Text

Subsequent License Renewal Application - Aging Management Requests for Additional Information (RAI) Set 3 Response and Submittal of Superseded Response for One Set 2 RAI and One Supplement 1 Attachment
	ML22221A134
Person / Time
Site:	Saint Lucie
Issue date:	08/09/2022
From:	Maher W; Florida Power & Light Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	L-2022-115
	Download: ML22221A134 (69)
	v • d • e

August 09, 2022 L-2022-115 10 CFR 54.17 U.S. Nuclear Regulatory Commission Attn: Document Control Desk 11545 Rockville Pike One White Flint North Rockville, MD 20852-2746 St. Lucie Nuclear Plant Units 1 and 2 Dockets 50-335 and 50-389 Renewed Facility Operating Licenses DPR-67 and NPF-16 SUBSEQUENT LICENSE RENEWAL APPLICATION - AGING MANAGEMENT REQUESTS FOR ADDITIONAL INFORMATION (RAI) SET 3 RESPONSE AND SUBMITTAL OF SUPERSEDED RESPONSE FOR ONE SET 2 RAI AND ONE SUPPLEMENT 1 ATTACHMENT

References:

1. FPL Letter L-2021-192 dated October 12, 2021 - Subsequent License Renewal Application -

Revision 1 (ADAMS Accession No. ML21285A107)

2. FPL Letter L-2022-043 dated April 7, 2022 - Subsequent License Renewal Application Revision 1 - Supplement 1 (ADAMS Accession No. ML22097A202)

3. FPL Letter L-2022-044 dated April 13, 2022 - Subsequent License Renewal Application Revision 1 - Supplement 2 (ADAMS Accession No. ML22103A014)

4. FPL Letter L-2022-071 dated May 19, 2022 - Subsequent License Renewal Application Revision 1 - Supplement 3 (ADAMS Accession No. ML22139A083)

5. NRC Email and Attachment dated July 11, 2022, St. Lucie SLRA RAI Safety Set 3 Final (ADAMS Accession Nos. ML22193A086, ML22193A087)

6. FPL Letter L-2022-108 dated July 11, 2022 - Subsequent License Renewal Application -

Aging Management Requests for Additional Information (RAI) Set 2 Response Florida Power & Light Company (FPL), owner and licensee for St. Lucie Nuclear Plant (PSL) Units 1 and 2, has submitted a revised and supplemented subsequent license renewal application (SLRA) for the Facility Operating Licenses for PSL Units 1 and 2 (References 1-4). Based on the NRCs review of the SLRA, the NRC issued its Set 3 RAIs to FPL (Reference 5). Attachments 1-5 to this letter provide the response to those information requests. In addition, Attachment 6 to this letter provides a response to RAI B.2.3.34-2 that supersedes the previous Set 2, Attachment 14 response (Reference 6). Attachment 7 to this letter supersedes the previously submitted SLRA Revision 1, Supplement 1, Attachment 18 submittal (Reference 2).

Florida Power & Light Company 15430 Endeavor Drive, Jupiter, FL 33478

St. Lucie Nuclear Plant Units 1 and 2 Dockets 50-335 and 50-389 L-2022-115 l Page 2 of 3 For ease of reference, the index of attached information is provided on page 3 of this letter. Certain attachments include associated revisions to the SLRA (Enclosure 3 Attachment 1 of Reference 1, as supplemented by References 2 - 4) denoted by strikethrough (deletion) and/or bold red underline (insertion) text. Previous SLRA revisions are denoted by bold black text. SLRA table revisions are included as excerpts from each affected table.

Should you have any questions regarding this submittal, please contact me at (561) 304-6256 or William.Maher@fpl.com.

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

Executed on the 9th day of August 2022.

Sincerely, Digitally signed by William Maher DN: cn=William Maher, o=Nuclear, William Maher ou=Nuclear Licensing Projects, email=william.maher@fpl.com, c=US Date: 2022.08.09 12:13:09 -04'00' William D. Maher Licensing Director - Nuclear Licensing Projects Florida Power & Light Company Cc: Regional Administrator, USNRC, Region II Senior Resident Inspector, USNRC, St. Lucie Plant Chief, USNRC, Division of New and Renewed Licenses Senior Project Manager, USNRC, Division of New and Renewed Licenses Chief, Bureau of Radiation Control, Florida Department of Health

St. Lucie Nuclear Plant Units 1 and 2 Dockets 50-335 and 50-389 L-2022-115 l Page 3 of 3 Attachments Index Attachment RAI No. Subject No.

1 4.2-1 TLAA - Upper Shelf Energy 2 3.3.2.2.9-1 Aging Effects Associated with a Concrete Environment 3 3.4.2.2.8-1 Aging Effects for the Unit 2 Condensate Storage Tank 4 3.6.1.1-1 Aging Management Review for Fuse Holders 5 19.2.2.17-2 UFSAR Update for the Unit 1 Refueling Water Storage Tank AMP Inspection of Water-Control Structures Associated with Nuclear 6 B.2.3.34-2 Power Plants AMP - Hurricane Protection Sheet Piles 7 N/A Steam Generators: Clarified AMR Results and AMP Scope

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 4.2-1 L-2022-115 Attachment 1 Page 1 of 8 TLAA - Upper Shelf Energy RAI 4.2-1 Regulatory Basis:

10 CFR § 54.21(c) requires the applicant to evaluate time limited aging analyses (TLAA) and disposition them in accordance with (c)(1)(i), (c)(1)(ii), or (c)(1)(iii). 10 CFR § 54.21(d) requires that the FSAR supplement for the facility must contain a summary description of the programs and activities for managing the effects of aging and evaluation of the TLAA for the period of extended operation determined by 54.21(a) and 54.21(c).

Background:

SLRA Tables 4.2.2-1 and 4.2.3-1 provide the unirradiated RTNDT and upper-shelf energy (USE) values, respectively, for the Unit 1 RPV materials at 72 effective full power years (EFPY). The footnotes for SLRA Tables 4.2.2-1 and 4.2.3-1 indicate that Westinghouse report WCAP-18609-NP, Revision 2 (herein after referred to as WCAP-18609-NP), is the source document for these unirradiated values.

Table 3-1 of WCAP-18609-NP indicates the following for the Upper to Intermediate Shell Girth Weld Seam 8-203 (Heat Number 21935):

Footnote (g) - USE for Heat # 21935 is from Diablo Canyon 1 (WCAP-17315-NP, Intermediate to Lower Shell Weld Seam 9-442. Both materials were made with Heat

21935 and Linde 1092 flux).

Table 3-1 of WCAP-18609-NP indicates the following for the Upper Shell Axial Weld Seams 1-203 A, B, and C (Heat Number 21935/12008):

Footnote (h) - RTNDT(U) for Heat # 21935/12008, Linde 1092, Lot 3869 is from identical material at Diablo Canyon 2 (WCAP-17315-NP).

Footnote (i) - USE for Heat # 21935/12008, Linde 1092, Lot 3869 is from identical material at Diablo Canyon 2 (WCAP-17315-NP), specifically Intermediate Shell Axial Welds 2-201 A/B/C.

Issue:

The staff noted the following was not provided in Section 4.2 of the SLRA:

The applicant did not provide an adequate justification demonstrating that the unirradiated USE value from Diablo Canyon, Unit 1 (as referenced in footnote (g) of Table 3-1 of WCAP-18609-NP) is conservative, representative, or applicable for use as the unirradiated USE value for the upper to intermediate shell girth weld seam 8-203 at St. Lucie, Unit 1.

The applicant did not provide an adequate justification demonstrating that the

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 4.2-1 L-2022-115 Attachment 1 Page 2 of 8 unirradiated USE value from Diablo Canyon, Unit 2 (as referenced in footnote (i) of Table 3-1 of WCAP-18609-NP) is conservative, representative, or applicable for use as the unirradiated USE value for the upper shell axial weld seams 1-203 A, B, and C in St.

Lucie, Unit 1.

The applicant did not provide an adequate justification demonstrating that the unirradiated RTNDT value from Diablo Canyon, Unit 2 (as referenced in footnote (h) of Table 3-1 of WCAP-18609-NP) is conservative, representative, or applicable for use as the unirradiated RTNDT value for the upper shell axial weld seams 1-203 A, B, and C in St. Lucie, Unit 1.

The staff noted that inherent characteristics of manufacturing the RPV such as, but not limited to, welding processes, procedures and qualifications, post weld heat treatment activities, manufacturer/fabricator, and time of fabrication, have the potential to impact the unirradiated values for USE and RTNDT for RPV materials from plant to plant.

Additionally, the applicant did not describe how Diablo Canyon determined these initial values of USE and RTNDT, and whether this information supports the applicants determination that these initial values are conservative, appropriate, or applicable for use at St Lucie, Unit 1.

Request:

1. Describe and justify the process the applicant went through for assessing how Diablo Canyon obtained the above referenced values.

2. Taking into consideration the inherent characteristics that could affect the unirradiated USE and RTNDT values, as described above, justify how the methods, processes, or analysis used by Diablo Canyon to obtain or develop these values are conservative, representative, or applicable to use for St. Lucie, Unit 1 RPV materials.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 4.2-1 L-2022-115 Attachment 1 Page 3 of 8 PSL Response:

1. To justify the use of this data, the Heat, flux type, and lot numbers were compared as shown below in Table 1.

Table 1 Flux Type Heat # Plant Weld Seam (Lot)

Upper to Intermediate Shell Girth Linde 1092 St. Lucie 1 Weld Seam 8-203 (3889)

Intermediate to Lower Shell Weld Linde 1092 21935 Diablo Canyon 1 Seam 9-442 (3869)

Upper to Intermediate Shell Girth Linde 1092 Diablo Canyon 2 Weld Seam 8-201 (3889)

Upper Shell Axial Weld Seams Linde 1092 St. Lucie 1 1-203 A, B, & C (3869)

Intermediate Shell Axial Welds Linde 1092 Diablo Canyon 2 2- 201A/B/C (3869) 21935 / 12008 Upper Shell Axial Welds Linde 1092 Diablo Canyon 2 1-201A/B/C (3869)

Linde 1092 Diablo Canyon 2 Surveillance Weld (3869)

For the respective heat numbers, all the welds were constructed of very similar, if not identical, materials. The only exception is the Diablo Canyon Unit 1 Intermediate to Lower Shell Weld Seam 9-442 is made of Lot # 3869 versus the St. Lucie Unit 1 Upper to Intermediate Shell Girth Weld Seam 8-203 which used Lot # 3889. However, lot numbers are not typically considered relevant when considering the applicability of sister-plant data. The critical factors are heat number and flux type. In addition, for Diablo Canyon Unit 2, the Upper to Intermediate Shell Girth Weld Seam 8-201 uses a lot number identical to St. Lucie Unit 1 Upper to Intermediate Shell Girth Weld Seam 8-203 and has the same exact material properties as Diablo Canyon Unit 1 Intermediate to Lower Shell Weld Seam 9-442.

In addition, the vendor and timeframe of fabrication the welds were considered. As shown in Table 2, the vessels were fabricated by same vendor, in the same timeframe (late 1960s to early 1970s), and to similar Code requirements. In addition, the qualification welds had identical stress relief heat treatment (1150°F +/- 25°F) as required by the ASME code for the pressure vessel.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 4.2-1 L-2022-115 Attachment 1 Page 4 of 8 Table 2 ASME III Plant Fabricator Heat Treatment Inspection Date Code Edition 1965 thru late 1960's and St. Lucie 1 C-E 1150°F+/-25°F 40 Hours, furnace cooled to 600°F Winter 67 early 1970's Diablo 1965 thru late 1960's and C-E 1150°F+/-25°F 40 Hours, furnace cooled to 600°F Canyon 1 Summer 66 early 1970's Diablo late 1960's and C-E 1968 1150°F+/-25°F 40 Hours, furnace cooled to 600°F Canyon 2 early 1970's Therefore, it was determined that the initial/unirradiated RTNDT (RTNDT(u)) and USE values for Heat # 21935 and 21935/12008 from Diablo Canyon Units 1 and 2 are applicable to St. Lucie 1 because the welds are of the same heat number & flux type, were fabricated by same vendor, in the same timeframe, and to similar Code requirements.

This conclusion is in-line with previous industry conclusions, such as those used in response to Generic Letter 92-01, which resulted in the Reactor Vessel Integrity Database (RVID). As seen in the RVID, there are multiple instances of the use of sister plant data, including Heat # 21935 or # 21935/12008, to define the initial material properties. In addition, some vendors have provided databases of weld information such as References 1 and 2, which identifies the weld data by heat number, flux type, and lot number, not plant. Plants have used these databases to perform Reactor Vessel Integrity evaluation and to respond to industry issues such as Generic Letter 92-01.

2. To ensure these values are conservative, representative, and/or applicable to use for St.

Lucie Unit 1 RPV materials, the RVID and other resources were searched to identify plants with similar welds and the initial RTNDT and USE values were compared as shown in Table 3. In most cases, the values chosen for St. Lucie 1 were conservative. Most exceptions to this are because a generic value was used or the 10 CFR 50, Appendix G requirements for USE are met with an EMA. For the other exceptions, either the plants analysis of record has revised these initial values since the RVID was populated, or the RVID value is based on sister-plant data that has since been revised; therefore, the RVID value are not based on the latest information.

For Heat # 21935/12008, all initial RTNDT and USE are based on the surveillance program data for Diablo Canyon Unit 2. All the vessels were fabricated by same vendor (Combustion Engineering) in the same timeframe (late 1960s to early 1970s) and used similar Code requirements (ASME Winter 67 through ASME Summer 71) and heat treatments (1150°F+/-25°F 40 Hours maximum).

For Heat # 21935, all non-generic / non-EMA USE values are set to 109 ft-lb. This value is based on Charpy V-notch impact testing on the Shoreham Weld Seam 5-306, which was Type B4-Mod, Wire Heat # 21935, Flux Type Linde 1092, and Flux Lot 3869, as documented in Reference 3. This data was also included in Reference 4, which provides a conservative 95/95 lower tolerance limit generic value for welds with Linde 1092 (97 ft-lb). The Charpy data for Heat # 21935, Flux Type Linde 1092, and Flux Lot 3869 in

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 4.2-1 L-2022-115 Attachment 1 Page 5 of 8 Reference 2 were also reviewed. These results are all at 10°F and do not present the shear. However, they average to 60 ft-lb. It is expected that the USE would be experienced at a higher temperature, typically greater than 100°F. For example, the USE for Heat # 21935/12008 was reached at 150°F per Reference 5. Given the margin to the estimated USE temperature, 109 ft-lb is a reasonable USE.

Heats # 21935 and # 21935/12008 have been used fairly frequently in the welds of C-E fabricated vessels. These vessels were fabricated in the same timeframe (late 1960s to early 1970s) and to similar Code requirements. The material properties of these welds have been defined based on consistent data sets. Since St. Lucie Unit 1 was fabricated by same vendor, in the same timeframe, and to similar Code requirements, these data sets are also representative and applicable to the St. Lucie Unit 1 Heats # 21935 and #

21935/12008 reactor vessel welds.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 4.2-1 L-2022-115 Attachment 1 Page 6 of 8 Table 3 RVID Latest Values Flux Type Unirradiated Ht # Plant Weld Seam RTNDT(u) USE RTNDT(u) USE (Lot) Method Upper to Intermediate Linde 1092 St. Lucie 1 Shell Girth Weld --- --- --- -56 109 (3889)

Seam 8-203 Diablo Intermediate to Lower Linde 1092 Sister -56 109 -56 109 Canyon 1 Shell Weld Seam 9-442 (3869)

Upper to Intermediate Diablo Linde 1092 (1)

Shell Girth Weld --- --- --- -56 109 Canyon 2 (3889)

Seam 8-201 US to IS Linde 1092 (2)

McGuire 1 Circumferential (Circ.) --- --- --- -56 109 (3869) 21935 Weld 8-442 Calvert Lower Shell Axial Weld Linde 1092 Sister -56 109 -56 109 Cliffs 1 Seams 3-203A/C (3869)

Lower/Lower Int. Shell Cooper Linde 1092 EMA -50 --- --- ---

Circ Weld Seam 1-240 Lower Shell Axial Welds LaSalle 1 Linde 1092 EMA -50 --- --- ---

Seams 2-307A/C Lower Int./Lower Shell Pilgrim Linde 1092 Generic -50 75 --- ---

Circ. Weld 1-344 Point Nozzle Beltline to Int. Linde 1092 (3)

Generic -56 75 -56 109 Beach 2 Shell Circ. Weld (3869)

Upper Shell Axial Weld Linde 1092 ---

St. Lucie 1 --- --- -50 118 Seams 1-203 A, B, & C (3869)

Diablo Intermediate Shell Axial Linde 1092 Surveillance (4)

-50 124 -50 118 Canyon 2 Weld Seams 2- 201A/B/C. (3869) Weld 21935 / Diablo Upper Shell Axial Weld Linde 1092 (4)

--- --- --- -50 118 12008 Canyon 2 Seams 1-201A/B/C (3869)

Lower Shell Linde 1092 (2)

McGuire 1 Longitudinal Weld Seams Sister -50 103 -50 124 (3889) 3-442A, B, and C Lower Shell Longitudinal Linde 1092 (5)

Salem 2 Weld Seams 3-442 A, B, Sister -56 114 -56 114 (3889)

&C Notes:

1. Updated per Diablo Canyon Unit 2 UFSAR Table 5.2-21B.

2. McGuire 1 value defined is based on the RVID USE for Diablo Canyon Unit 2, which only used highest temperature Charpy data and is included in the McGuire LRA (Ref. 6). The applicability of Diablo Canyon 2 surveillance weld to McGuire 1 was evaluated in Reference 7. Included with the McGuire Units 1 and 2 Measurement Uncertainty Recapture (MUR) Power Uprate, evaluated in Reference 8 and approved in Reference 9.

3. Updated per Point Beach SLR Application (Ref. 10)

4. Diablo Canyon 2 values defined in Reference 11 & UFSAR, Table 5.2-21B.

5. Salem Unit 2 value defined in Reference 12 based on Diablo Canyon Unit 2 data provided in Reference

13. The Diablo Canyon Unit 2 data has since been revised; thus, the larger value could be justified.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 4.2-1 L-2022-115 Attachment 1 Page 7 of 8

References:

1. Certified Material Test Reports (CMTRs) CMTR-RV-RDM, Weld Material Documentation of the Eleven Reactor Pressure Vessels Fabricated by RDM for Westinghouse (ADAMS Accession No. ML20125E177)

2. CE Report LD-79-036, I&E Bulletin 78-12, Atypical Weld Material in Reactor Pressure Vessel Welds, June 8, 1979

3. R. E. Denton (BGE) to NRC Document Control Desk, Generic Letter 92-01 Reactor Vessel Structural Integrity Close-out Letter/Upper-Shelf Energy for Weld Seams 3-203-A, B, C (TAC No. M83446)," August 30, 1994 (ADAMS Accession No. ML20072P571)

4. Combustion Engineering (C-E) Owners Group Report CEN-622-A, Generic Upper Shelf Values for Linde 1092, 124 and 0091 Reactor Vessel Welds CEOG Task 839, December 1996 (ADAMS Accession No. ML20135E999}

5. Westinghouse Report WCAP-8783, Revision 0, Pacific Gas and Electric Diablo Canyon Unit No. 2 Reactor Vessel Radiation Surveillance Program, December 1976.

6. Duke Energy Corporation Application to Renew the Operating Licenses of McGuire Nuclear Station, Units 1 & 2 and Catawba Nuclear Station, Units 1 & 2 (ADAMS Accession No. ML011660145)

7. Westinghouse Report WCAP-13949, Revision 0, Analysis of Capsule V Specimens and Dosimeters and Analysis of Capsule Z Dosimeters from the Duke Power Company McGuire Unit 1 Reactor Vessel Radiation Surveillance Program, February 1994

8. Westinghouse Report WCAP-17455-NP, Revision 0, McGuire Units 1 and 2 Measurement Uncertainty Recapture (MUR) Power Uprate: Reactor Vessel Integrity and Neutron Fluence Evaluations, February 2012

9. NRC Safety Evaluation (SE) McGuire Nuclear Station. Units 1 and 2. Issuance of Amendments Regarding Measurement Uncertainty Recapture Power Uprate (TAC Nos.

ME8213 and ME8214), May 16, 2013 (ADAMS Accession No. ML13073A041)

10. NextEra Energy Point Beach Nuclear Plant Units 1 and 2 Subsequent License Renewal Application, November 2020 (ADAMS Accession No. ML20329A247)

11. Westinghouse Report WCAP-15423, Revision 0, Analysis of Capsule V from Pacific Gas and Electric Company Diablo Canyon Unit 2 Reactor Vessel Radiation Surveillance Program, September 2000 (ADAMS Accession No. ML010180432)

12. PSE&G Letter LR-N95198, Generic Letter 92-01, Rev. 1, Reactor Vessel Structural Integrity, Salem Generating Station Unit Nos. 1 & 2, November 20, 1995.

13. PG&E Letter from G.M. Rueger to NRC, Response to Generic Letter 92-01, Revision 1, Reactor Vessel Structural Integrity, June 30, 1992 (ADAMS Accession No. ML16341G610)

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 4.2-1 L-2022-115 Attachment 1 Page 8 of 8 Associated SLRA Revisions:

None.

Associated

Enclosures:

None.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 3.3.2.2.9-1 L-2022-115 Attachment 2 Page 1 of 7 Aging Effects Associated with a Concrete Environment RAI 3.3.2.2.9-1 Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 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 period of extended operation. One of the findings that the U.S.

Nuclear Regulatory Commission (NRC) 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 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.

Background:

As amended by letter dated April 7, 2022 (ML22097A202), the Subsequent License Renewal Application (SLRA) cites no aging effects requiring management for the following auxiliary system steel components exposed to an external environment of concrete: (a) piping and ducting in the ventilation system; and (b) the Unit 2 diesel oil storage tanks (DOSTs). These components cite Standard Review Plan for Subsequent License Renewal (SRP-SLR) item 3.3.1-112, which is associated with the further evaluation in SRP-SLR Section 3.3.2.2.9.

SRP-SLR Section 3.3.2.2.9 states the following:

If the following conditions are met, loss of material is not considered to be an applicable aging effect for steel [exposed to concrete]: (a) attributes of the concrete are consistent with American Concrete Institute (ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in NUREG-1557; (b) plant-specific OE [operating experience] indicates no degradation of the concrete that could lead to penetration of water to the metal surface; and (c) the piping is not potentially exposed to groundwater.

SLRA Section 3.3.2.2.9 states [a] review of OE for PSL indicates there are occurrences of concrete degradation, in some systems, that could lead to the penetration of water to the metal surface; therefore, a loss of material due to general, pitting, and crevice corrosion of steel piping and tanks exposed to concrete is an aging effect that requires management. In addition, SLRA Section 3.3.2.2.9 does not state whether attributes of the concrete for piping and ducting in the ventilation system are consistent with ACI 318 or ACI 349.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 3.3.2.2.9-1 L-2022-115 Attachment 2 Page 2 of 7 By letter dated April 7, 2022, the applicant stated the following:

unlike the Unit 1 DOSTs, the Unit 2 DOSTs 2A and 2B are excluded from the scope of the Outdoor and Large Atmospheric Metallic Storage Tanks AMP for SLR, since the Unit 2 DOSTs are indoors (within the Unit 2 DOST building) with a capacity of less than 100,000 gallons and no history of moisture at the inaccessible exterior bottom surface

[emphasis added by staff].

During its audit, the staff reviewed plant-specific operating experience where visual inspections of the external surfaces of the Unit 2 DOSTs revealed minor surface corrosion. In addition, during a walkdown of the 2A DOST, the staff noted that caulking at the interface of the tank bottom and concrete was damaged.

Issue:

For piping and ducting in the ventilation system, the staff seeks clarification with respect to how SRP-SLR Section 3.3.2.2.9 criteria are met, given that there have been occurrences of concrete degradation that could lead to the penetration of water to the metal surface. In addition, SLRA Section 3.3.2.2.9 does not address whether attributes of the concrete are consistent with ACI 318 or ACI 349 (associated with SRP-SLR Section 3.3.2.2.9 criterion (a)).

For the Unit 2 DOSTs, the staff seeks clarification with respect to citing no aging effects for the tank-to-concrete interface. The April 7, 2022, submittal states there is no history of moisture at the inaccessible exterior bottom surface. However, it is unclear to the staff how moisture can be readily identified at an inaccessible location. In addition, the staff notes there is plant-specific operating experience involving (a) minor corrosion on accessible external surfaces of these tanks; and (b) damaged caulking at the tank-to-concrete interface. Based on these observations, it is unclear to the staff why corrosion could also not occur at the tank-to-concrete interface.

Request:

Provide additional clarification with respect to citing no aging effects for the following auxiliary system steel components exposed to an external environment of concrete: (a) piping and ducting in the ventilation system; and (b) the Unit 2 DOSTs.

PSL Response:

SLRA Table 3.3.2-12 provides the summary of the aging management evaluation for the PSL Units 1 and 2 ventilation systems that are within the scope of SLR and require an aging management review. The table concludes that the component and material types of galvanized steel duct and carbon steel piping exposed to an external environment of concrete have no aging effects that require management for SLR. The basis for this conclusion is that for these components and environments PSL meets the following conditions specified in SRP-SLR Section 3.3.2.2.9 where loss of material is not considered to be an applicable aging effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute (ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in NUREG-1557; (b) plant-specific OE indicates no degradation of the concrete that could lead to penetration of water to the metal surface; and (c) the piping is not potentially exposed to

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 3.3.2.2.9-1 L-2022-115 Attachment 2 Page 3 of 7 groundwater. Compliance of the PSL ventilation system galvanized steel duct and carbon steel piping components with each condition is provided below.

(a) In accordance with SLRA Sections 3.5.2.2.1.7, 3.5.2.2.2.1, and 3.5.2.2.2.3, the reinforced concrete for Groups 1, 3, 4, 5, 6, 7, and 8 Class 1 structures at PSL is designed and constructed in accordance with the applicable portions of ACI 318-63 for Unit 1 and ACI 318-71 for Unit 2, therefore, the reinforced concrete for these PSL structures meets criterion (a) of SRP-SLR Section 3.3.2.2.9. Note that Group 2 and Group 9 structures are associated with BWR plants and are therefore not applicable to PSL.

(b) In addition to an external environment of concrete, the SLRA Table 3.3.2-12 entries for galvanized steel duct and carbon steel piping components also include an external environment of air - indoor uncontrolled indicating that these components are located indoors in Class 1 structures and not subjected to periodic wetting due to outdoor weather conditions. PSL Units 1 and 2 plant-specific OE indicates no degradation of indoor concrete that could lead to the penetration of water to the metal duct or piping surfaces.

(c) The subject PSL ventilation system galvanized steel duct and carbon steel piping components are located indoors in Class 1 structures and are therefore not exposed to groundwater.

The Unit 2 DOSTs are located in the diesel oil storage tank Class 1 structure which is described in Unit 2 UFSAR Section 3.8.4.1.8. This missile protection structure is a rectangular reinforced concrete structure supported on a three feet thick mat, with two foot thick walls and a two foot thick roof slab. An interior wall separates the two tanks. The floor inside the building is at elevation 19-0. The top of the 1-6 wide concrete ring wall supporting each DOST is at elevation 22-3 1/2, elevating each tank more than three feet above the floor level. The tank bottom is supported by compacted Class I sand fill within the ring wall and sloped one inch per ten feet away from the tank center towards the perimeter. The tank perimeter is anchored with non-shrink grout to maximize contact and load transfer between the tank bottom and the ring wall. This design precludes the potential for any water to penetrate the tank-to-concrete interface.

As indicated in SLRA Table 3.3.2-4, the Unit 2 DOSTs are exposed to an external environment of both concrete (the tank bottoms) and air - indoor uncontrolled (tank shells and roofs).

Therefore, the DOSTs are not exposed to weather events, including precipitation and wind.

Visual inspections of the accessible external surfaces of the Unit 2 DOSTs revealed minor surface corrosion. However, as indicated in the Operating Experience section of SLRA Section B.2.3.17, PSL has experienced some coating/paint delamination and some rusting/corrosion on tanks within the scope of SLR, but none that threatened the function of the tanks. As stated in SLRA Table 3.3.2-4, the aging effect of loss of material of the accessible carbon steel DOST shells and roof will continue to be adequately managed by the External Surfaces Monitoring of Mechanical Components during the SPEO.

The Unit 2 DOSTs have no history of tank leakage or other events that would expose the inaccessible exterior bottom surface to water. In addition, no other PSL Units 1 and 2 indoor metallic tanks that sit on concrete have a history of tank leakage or other events that would

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 3.3.2.2.9-1 L-2022-115 Attachment 2 Page 4 of 7 expose the inaccessible exterior tank bottom surface to water. Although a recent a walkdown of the 2A DOST noted damaged caulking at the tank-to-concrete interface, the caulking is not required to prevent water from penetrating the tank-to-concrete interface. There is reasonable assurance that penetration of water under the bottom of the DOSTs is unlikely based on the tank design and location as described above. Therefore, loss of material is not considered to be an applicable aging effect for the Unit 2 DOST steel bottoms.

Revision to SLRA Section 3.3.2.2.9 along with Tables 3.3-1 and 3.3.2-4 are provided below.

References:

None.

Associated SLRA Revisions:

SLRA Section 3.3.2.2.9, pages 3.3-24 and 3.3-25 are revised as follows:

3.3.2.2.9 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to Stress Corrosion Cracking Loss of material due to general (steel only), crevice, or pitting corrosion, and cracking due to SCC (SS only) can occur in steel and SS piping and piping components exposed to concrete. Concrete provides a high alkalinity environment that can mitigate the effects of loss of material for steel piping, thereby significantly reducing the corrosion rate. However, if water intrudes through the concrete, the pH can be reduced and ions that promote loss of material such as chlorides, which can penetrate the protective oxide layer created in the high alkalinity environment, can reach the surface of the metal.

Carbonation can reduce the pH within concrete. The rate of carbonation is reduced by using concrete with a low water-to-cement ratio and low permeability.

Concrete with low permeability also reduces the potential for the penetration of water. Adequate air entrainment improves the ability of the concrete to resist freezing and thawing cycles and therefore reduces the potential for cracking and intrusion of water. Cracking due to SCC, as well as pitting and crevice corrosion can occur due to halides present in the water that penetrates to the surface of the metal.

If the following conditions are met, loss of material is not considered to be an applicable aging effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute (ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in NUREG-1557; (b) plant-specific OE indicates no degradation of the concrete that could lead to penetration of water to the metal surface; and (c) the piping is not potentially exposed to groundwater. For SS components, loss of material and cracking due to SCC are not considered to be applicable aging effects as long as the piping is not potentially exposed to groundwater. Where these conditions are not met, loss of material due to general (steel only), crevice, or pitting corrosion, and cracking due to SCC (SS only) are identified as applicable aging effects.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 3.3.2.2.9-1 L-2022-115 Attachment 2 Page 5 of 7 GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks, describes an acceptable program to manage these aging effects.

The Auxiliary Systems includes both steel and SS piping and piping components and tanks exposed to concrete. A review of OE for PSL indicates there are occurrences of concrete degradation, in some outdoor systems, that could lead to the penetration of water to the metal surface; therefore, a loss of material due to general (steel only), pitting, and or crevice corrosion, and cracking due to SCC (SS only) of can occur in outdoor steel and SS piping and piping components tanks exposed to concrete is an aging effect that requires management.

It should be noted that sSome systems within the Auxiliary Systems have SS and steel components exposed to concrete but are located indoors and shielded from an outdoor environment. For indoor SS piping and piping components with an external environment of concrete, loss of material and cracking due to SCC are not considered to be applicable aging effects since these components are located inside Class 1 structures and are not exposed to groundwater. For indoor steel piping and piping components and Unit 2 DOSTs with an external environment of concrete, loss of material is not considered to be an applicable aging effect because the three conditions cited above are met as follows:

(a) In accordance with SLRA Sections 3.5.2.2.1.7, 3.5.2.2.2.1, and 3.5.2.2.2.3, the reinforced concrete for Groups 1, 3, 4, 5, 6, 7, and 8 Class 1 structures at PSL is designed and constructed in accordance with the applicable portions of ACI 318-63 for Unit 1 and ACI 318-71 for Unit 2.

Note that Group 2 and Group 9 structures are associated with BWR plants and are therefore not applicable to PSL.

(b) The subject steel piping and piping components and Unit 2 DOSTs with an external environment of concrete are located inside Class 1 structures and not subjected to weather events, including precipitation and wind. PSL Units 1 and 2 plant-specific OE indicates no degradation of indoor concrete that could lead to the penetration of water to the steel piping and piping component and Unit 2 DOST surfaces.

(c) The subject PSL steel piping and piping components and Unit 2 DOSTs are located inside Class 1 structure and therefore, not exposed to groundwater.

Consistent with the recommendation of GALL-SLR, the Buried and Underground Piping and Tanks (B.2.3.27) AMP is used to manage loss of material in (steel and SS) and cracking (SS only) in outdoor piping and piping components tanks exposed to concrete. This AMP provides for the management of aging effects. Any evidence of loss of material or cracking will be evaluated for acceptability.

Conditions will be documented in accordance with the 10 CFR Part 50, Appendix B Corrective Action Program. The Buried and Underground Piping and Tanks AMP is described in Section B.2.3.27.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 3.3.2.2.9-1 L-2022-115 Attachment 2 Page 6 of 7 SLRA Table 3.3-1, page 3.3-46 is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Discussion Number Effect/Mechanism Program (AMP)/TLAA Evaluation Recommended 3.3-1, 112 Steel piping, piping None None Yes (SRP-SLR Consistent with NUREG-2191.

components Section 3.3.2.2.9) There are no aging effects to be managed for exposed to concrete steel piping and piping components and the Unit 2 DOSTs exposed to concrete that are not subject to wetting.

Further evaluation is documented in Section 3.2.2.2.9.

SLRA Table 3.3.2-4, page 3.3-130 is revised as follows:

Table 3.3.2-4: Diesel Generators and Support Systems - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Function Requiring Program Item Item Management Tank (Unit 2 diesel Pressure Carbon steel Concrete (ext) None None VII.I.AP-198 3.3-1, 112 AC oil storage) boundary VII.J.AP-282

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 3.3.2.2.9-1 L-2022-115 Attachment 2 Page 7 of 7 Associated

Enclosures:

None.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.4.2.2.8-1 L-2022-115 Attachment 3 Page 1 of 5 Aging Effects for the Unit 2 Condensate Storage Tank RAI 3.4.2.2.8-1 Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 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 period of extended operation. One of the findings that the U.S.

Nuclear Regulatory Commission (NRC) 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 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.

Background:

The subsequent License Renewal Application (SLRA) cites no aging effects requiring management for the Unit 2 steel condensate storage tank (CST) exposed to an external environment of concrete. This component cites Standard SRP-SLR item 3.4.1-51, which is associated with the further evaluation in SRP-SLR Section 3.4.2.2.8.

SRP-SLR Section 3.4.2.2.8 states the following:

If the following conditions are met, loss of material is not considered to be an applicable aging effect for steel [exposed to concrete]: (a) attributes of the concrete are consistent with American Concrete Institute (ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in NUREG-1557; (b) plant-specific OE indicates no degradation of the concrete that could lead to penetration of water to the metal surface; and (c) the piping is not potentially exposed to groundwater.

SLRA Section 3.4.2.2.8 states the following in part:

[t]he carbon steel condensate storage tank bottoms sit on a concrete pad. There is no OE indicating degradation of the concrete that could lead to penetration of water to the metal surface, and the tanks are not exposed to groundwater.

[t]he Unit 2 CST and associated piping and components are located in a separate CST building, a structural missile barrier, which provides protection from weather. Therefore, loss of material of steel exposed to concrete for the Unit 2 CST is not an applicable aging effect but is an applicable aging effect for the Unit 1 CST.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.4.2.2.8-1 L-2022-115 Attachment 3 Page 2 of 5 Issue:

The staff seeks clarification with respect to citing no aging effects for the Unit 2 CST surfaces exposed to an external environment of concrete. Although the structural missile barrier can protect the Unit 2 CST from weather, it is unclear how this can prevent moisture accumulation at the tank-to-concrete interface.

Request:

Provide additional clarification with respect to citing no aging effects for the Unit 2 CST surfaces exposed to an external environment of concrete.

PSL Response:

The Unit 2 CST is located in the condensate storage tank building which is a Class 1 structure described in Unit 2 UFSAR Section 3.8.4.1.7. The building is a cylindrical reinforced concrete structure with a shallow dome roof. The thickness of the wall and of the roof is two feet. The structure is supported on a three foot thick reinforced concrete mat. The structure is designed to seismic Category I requirements. The floor inside the building is at elevation 19-6. The top of the 2-0 concrete ring wall supporting the Unit 2 CST is at elevation 20-0, elevating each tank 6 inches above the floor level. The tank bottom is supported by compacted Class I sand fill within the ring wall and sloped one inch per ten feet away from the tank center towards the perimeter. The tank perimeter is anchored with non-shrink grout to maximize contact and load transfer between the tank bottom and the ring wall. This design precludes the potential for any water to penetrate the tank-to-concrete interface.

SRP-SLR Section 3.4.2.2.8 states that if the following conditions are met, loss of material is not considered to be an applicable aging effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute (ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in NUREG-1557; (b) plant-specific OE indicates no degradation of the concrete that could lead to penetration of water to the metal surface; and (c) the piping is not potentially exposed to groundwater. Compliance of the PSL Unit 2 steel CST-to-concrete interface with each condition is provided below.

(a) In accordance with SLRA Sections 3.5.2.2.1.7, 3.5.2.2.2.1, and 3.5.2.2.2.3, the reinforced concrete for Groups 1, 3, 4, 5, 6, 7, and 8 Class 1 structures at PSL is designed and constructed in accordance with the applicable portions of ACI 318-63 for Unit 1 and ACI 318-71 for Unit 2, therefore, the reinforced concrete for these PSL structures meets criterion (a) of SRP-SLR Section 3.4.2.2.8. Note that Group 2 and Group 9 structures are associated with BWR plants and are therefore not applicable to PSL.

(b) As indicated in SLRA Table 3.4.2-3, the Unit 2 CST is exposed to an external environment of both concrete (the tank bottom) and air - indoor uncontrolled (tank shell and roof). Therefore, the CST is not exposed to weather events, including precipitation and wind. The Unit 2 CST has no history of tank leakage or other events that would expose the inaccessible exterior bottom surface to water. In addition, no other PSL Units 1 and 2 indoor metallic tanks that sit on concrete have a history of tank leakage or other events that would expose the inaccessible exterior tank bottom surface to water. Plant-

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.4.2.2.8-1 L-2022-115 Attachment 3 Page 3 of 5 specific OE also indicates no degradation of indoor concrete that could lead to the penetration of water to the steel surfaces has occurred. Therefore, there is reasonable assurance that penetration of water under the bottom of the Unit 2 CST is unlikely based on the tank design and location as described above.

(c) The Unit 2 CST is located indoors in a Class 1 structure elevated above grade and therefore is not exposed to groundwater.

Therefore, loss of material is not considered to be an applicable aging effect for Unit 2 CST steel-to-concrete interface.

Revision to SLRA Section 3.4.2.2.8 is provided below.

References:

None.

Associated SLRA Revisions:

SLRA Section 3.4.2.2.8, pages 3.4-12 and 3.4-13 are revised as follows:

3.4.2.2.8 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to Stress Corrosion Cracking Loss of material due to general (steel only), crevice, or pitting corrosion and cracking due to SCC (SS only) can occur in steel and SS piping and piping components exposed to concrete. Concrete provides a high alkalinity environment that can mitigate the effects of loss of material for steel piping, thereby significantly reducing the corrosion rate. However, if water intrudes through the concrete, the pH can be reduced and ions that promote loss of material such as chlorides, which can penetrate the protective oxide layer created in the high alkalinity environment, can reach the surface of the metal.

Carbonation can reduce the pH within concrete. The rate of carbonation is reduced by using concrete with a low water-to-cement ratio and low permeability.

Concrete with low permeability also reduces the potential for the penetration of water. Adequate air entrainment improves the ability of the concrete to resist freezing and thawing cycles and therefore reduces the potential for cracking and intrusion of water. Cracking due to SCC, as well as pitting and crevice corrosion can occur due to halides present in the water that penetrates to the surface of the metal.

If the following conditions are met, loss of material is not considered to be an applicable aging effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute (ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in NUREG-1557; (b) plant-specific OE indicates no degradation of the concrete that could lead to penetration of water to the metal surface; and (c) the piping is not potentially exposed to groundwater. For SS components loss of material and cracking due to SCC are not considered to be applicable aging effects as long as the piping is

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.4.2.2.8-1 L-2022-115 Attachment 3 Page 4 of 5 not potentially exposed to groundwater. Where these conditions are not met, loss of material due to general (steel only), crevice, or pitting corrosion, and cracking due to SCC (SS only) are identified as applicable aging effects.

GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks, describes an acceptable program to manage these aging effects.

The Unit 1 and 2 carbon steel condensate storage tank bottoms each sit on a concrete pad. There is no OE indicating degradation of the concrete that could lead to penetration of water to the metal surface, and the tanks are not exposed to groundwater. The Unit 1 CST and associated piping and components are protected on all sides by a concrete structural barrier. Since the top of the barrier provides minimal protection from weather, the Unit 1 CST and associated pipe and components are exposed to an outside environment. Site specific OE indicates there has been no degradation of the concrete that could lead to penetration of water to the metal surface, however it is conservatively assumed that water can penetrate under the external surface of the Unit 1 CSTtank. Therefore, loss of material of steel exposed to concrete is an applicable aging effect for the Unit 1 CST.

The Unit 2 CST is located in the condensate storage tank building which is a Class 1 structure described in Unit 2 UFSAR Section 3.8.4.1.7. The building is a cylindrical reinforced concrete structure with a shallow dome roof. The thickness of the wall and of the roof is two feet. The structure is supported on a three foot thick reinforced concrete mat. The structure is designed to seismic Category I requirementsand associated piping and components are located in a separate CST building, a structural missile barrier, which provides protection from weather.

However, for the indoor Unit 2 steel CST steel tank bottom exposed to an external environment of concrete, loss of material is not considered to be an applicable aging effect because the three conditions cited above are met as follows:

(a) In accordance with SLRA Sections 3.5.2.2.1.7, 3.5.2.2.2.1, and 3.5.2.2.2.3, the reinforced concrete for Groups 1, 3, 4, 5, 6, 7, and 8 Class 1 structures at PSL is designed and constructed in accordance with the applicable portions of ACI 318-63 for Unit 1 and ACI 318-71 for Unit 2, therefore, the reinforced concrete for these PSL structures meets criterion (a) of SRP-SLR Section 3.4.2.2.8. Note that Group 2 and Group 9 structures are associated with BWR plants and are therefore not applicable to PSL.

(b) As indicated in SLRA Table 3.4.2-3, the Unit 2 CST is exposed to an external environment of both concrete (the tank bottom) and air -

indoor uncontrolled (tank shell and roof). Therefore, the CST is not exposed to weather events, including precipitation and wind. Plant-specific OE indicates the Unit 2 CST has no history of moisture at the inaccessible exterior bottom surface. In addition, no other PSL Units 1 and 2 indoor metallic tank that sits on concrete has a history of moisture at the inaccessible exterior tank bottom surface. Plant-specific

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.4.2.2.8-1 L-2022-115 Attachment 3 Page 5 of 5 OE also indicates no degradation of indoor concrete that could lead to the penetration of water to the steel surfaces has occurred.

(c) The Unit 2 CST is located indoors in a Class 1 structure elevated above grade and therefore is not exposed to groundwater.

Therefore, loss of material of steel exposed to concrete for the Unit 2 CST is not an applicable aging effect but is an applicable aging effect for the Unit 1 CST.

The Outdoor and Large Atmospheric Metallic Storage Tanks (B.2.3.17) AMP is used to manage loss of material of the steel Unit 1 CST. Stainless steel piping exposed to soil or concrete are assumed to be subject to wetting and the Buried and Underground Piping and Tanks (B.2.3.27) AMP is used to manage loss of material and cracking. The Outdoor and Large Atmospheric Metallic Storage Tanks and Buried and Underground Piping and Tanks AMPs are described in Sections B.2.3.17 and B.2.3.27, respectively.

Associated

Enclosures:

None.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 1 of 11 Aging Management Review for Fuse Holders RAI 3.6.1.1-1 Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 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 period of extended operation. One of the findings that the U.S.

Nuclear Regulatory Commission (NRC) 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 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.

Background:

Subsequent License Renewal Application (SLRA), Supplement 1, Section 2.5.1.3, Elimination of Electrical and I&C Commodity Groups Not Applicable to St. Lucie, and Section 3.6.1.1, Electrical Commodity Groups Not Requiring Aging Management, addressed the aging management review (AMR) of new fuse holders (not part of active equipment) for aging effects consistent with the screening guidance in NUREG-2191 (GALL- SLR Report),Section XI.E5.

The applicant states:

This fuse box is located in a controlled (benign) environment, the fuses are not manipulated, and the fuses are not subject to electrical stress (high cycling or high heating). There are no relevant aging mechanisms or aging effects for these fuse holders, relative to the insulating material, the metallic clamps, or the fuse box itself (i.e.,

there are no stressors to cause corrosion or age-related degradation). These fuse holders are within the scope of SLR, but because they do not have relevant aging mechanisms and are not manipulated and are not subject to aging effects, they do not require aging management, consistent with the guidance of NUREG-2191,Section XI.E5.

The subject fuse holders are located in a junction box in a benign environment, are not exposed to environmental stressors (thermal or radiation or moisture), and do not experience electrical stress (high voltage or high cycling). The fuse holders therefore do not warrant aging management, and do not require an aging management program at PSL.

SLRA, Revision 1, Supplement 1, Table 3.6.2-1, Electrical and Instrumentation & Control Commodities - Summary of Aging Management Evaluation, and SLRA, Revision 1, Table 3.6 1, Summary of Aging Management Evaluation for Electrical and Instrumentation & Control Commodities, provided the aging management evaluations for the in-scope fuse holders in accordance with the aging effects/mechanisms listed in NUREG-2191, Chapter VI, Table A,

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 2 of 11 Equipment Not Subject to 10 CFR 50.49, Environmental Qualification Requirements, for AMP XI.E5.

Issue:

NUREG-2191, Chapter VI, Electrical Components, Table A, Equipment Not Subject to 10 CFR 50.49 Environmental Qualification Requirements, AMP XI.E5, identifies the following aging effects/mechanisms that can affect fuse holders (not part of active equipment):

The metallic clamps of fuse holders can be subject to increased electrical resistance of connection due to chemical contamination, corrosion, and oxidation or fatigue caused by ohmic heating, thermal cycling, electrical transients, frequent removal /manipulation or vibration.

The electrical insulation materials of fuse holders can be subject to reduced insulation resistance due to thermal/thermoxidative degradation of organics, radiolysis and photolysis (UV sensitive materials only) of organics, radiation-induced oxidation, and moisture intrusion.

NUREG-2192 Table 3.6-1, Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report, stated that no AMP is required for the fuse holders if the applicant can demonstrate that these fuse holders are not subject to the aging effects/mechanisms identified in the Table 3.6-1 and in NUREG-2191, Table A, AMP XI.E5.

The staff notes that the applicant did not demonstrate how they came to the conclusion that the fuse holders are not subject to the stressors that cause the aging effects/mechanisms provided in the NUREG-2191, Table A, AMP XI.E5, as recommended in NUREG-2192.

Request:

Provide a summary of the evaluation used to demonstrate how the applicant determined that the fuse holders electrical metallic clamps and insulation materials are not subject to the above-mentioned stressors (i.e., thermal, radiation, moisture, ohmic heating, thermal cycling, electrical transients, vibration, frequent removal/manipulation, chemical contaminants, thermal/

thermoxidative degradation of organics, radiolysis and photolysis of organics, etc.) as they relate to the above-mentioned aging effects/mechanisms listed in NUREG-2191, Table A, AMP XI.E5, found to be acceptable for adequately managing the effects of aging during the period of extended operation.

PSL Response:

The original screening of fuse holders in SLRA Section 2.5.1.3 was revised under FPL Letter L-2022-043 dated April 7, 2022 (ADAMS Accession No. ML22097A202) (Reference 1). This revision was provided to clearly identify those fuse holders at PSL that are within the scope of SLR and require an aging management review. A more detailed summary of the evaluation performed on the fuse holders in SLRA Section 2.5.1.3 revised under ML22097A202 is provided to demonstrate that these fuse holders are not subject to the aging effects/mechanisms identified in the Table 3.6-1 and in NUREG-2191, Table A, AMP XI.E5.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 3 of 11 The fuse holders within the scope of SLR and subject to an aging management review are used in 125 VDC control power applications in Unit 2 6.9 kV Switchgear Room 2A1 in the Turbine Building. Fuse holders in the 2A1 Unit 2 6.9 kV Switchgear Room are exposed to an air indoor-uncontrolled environment. Field cable termination panel B2536 is a large junction box that houses only fuses and wiring. Photographs of the panel and details regarding its location have been provided on the ePortal. Field cable termination panel B2536 is constructed of corrosion resistant type 316 stainless steel and is a NEMA 4X rated gasketed enclosure suitable for indoor or outdoor use. The gasketed design protects against liquid and solid ingress. There are four 60A fuses inside field cable termination panel B2536 that are within the scope of SLR.

Field cable termination panel B2536 along with the fuse holders inside the panel were installed in the 2020 timeframe.

A summary evaluation of fuse holder potential aging effects/mechanisms in an air indoor-uncontrolled environment is provided below:

SLRA Table Potential Aging Summary Evaluation 3.6-1 Item # Effect/Mechanism 016 Increased electrical Fuse holders are installed in a corrosion resistant type resistance of 316 stainless steel gasketed enclosure. Chemicals are connection due to not stored in the 2A1 Unit 2 6.9 kV Switchgear Room.

chemical The switchgear room in the Turbine Building is totally contamination, enclosed and equipped with a filtered air supply corrosion, and system. Supply fans in combination with high oxidation efficiency filters provide a saline and dust free environment for the switchgear (Reference 2).

Operation of the supply fans keep the room temperature below 104ºF during the design outside ambient air temperature of 93ºF (Reference 2). The actual switchgear room temperature is maintained below 100ºF. Only one supply fan is required to provide filtered supply air to the switchgear room and maintain a positive pressure (Reference 2). The moisture required to produce corrosion and oxidation is not present in this atmosphere since condensation does not form on the warm equipment surfaces in the switchgear room. The gasketed design of the enclosure also protects against the ingress of liquids and foreign contamination. Condensation would not form on surfaces internal to field cable termination panel B2536 because the panel internal temperature is slightly higher than the panel outside temperature.

Therefore, moisture as a result of humidity is not considered a significant stressor. Plant walkdown has verified that there are no potential sources of chemical contamination in the area, and the fuse holders are totally enclosed in a protective junction box, even if chemical contamination were possible. Therefore,

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 4 of 11 SLRA Table Potential Aging Summary Evaluation 3.6-1 Item # Effect/Mechanism chemical contamination is not considered an applicable aging mechanism. Plant walkdown verified that there are no sources of potential mechanical system leakage in proximity to the fuse holders in field cable termination panel B2536. Therefore, corrosion and oxidation are not considered applicable aging mechanisms. Plant walkdown also confirmed that these fuse holders appeared to be in like-new condition. Therefore, increased electrical resistance of connection due to chemical contamination, corrosion, and oxidation is not an aging effect requiring aging management.

017 Increased electrical The only fuse holders that could potentially be exposed resistance of to thermal cycling and ohmic heating are those that connection due to carry significant current in power supply applications.

fatigue from ohmic Engineering design shows the fuses are rated at 60A heating, thermal while the associated control wiring consists of #6 AWG cycling, electrical conductors with an ampacity of 55A. However, these transients circuits (and fuse holders) are purposely sized with margin to accommodate the inrush current of the 125 VDC breaker charging motor. These fuse holders are used in Main Feedwater Pump (MFWP) motor applications. The MFWP motors and associated switchgear breakers are cycled very infrequently, typically only once per fuel cycle. Under normal operation, these fuse holders experience a very low current draw. The steady state full load amperage (FLA) is on the order of only 4A (after charging).

Therefore, thermal cycling and ohmic heating are not considered significant aging mechanisms based on this design configuration. Regarding electrical transients, PSL electrical design ensures that stresses due to forces associated with electrical faults and transients are mitigated by the proper coordination and fast action of circuit protective devices at high currents.

Mechanical stress due to electrical faults is not considered a credible aging mechanism since such faults are infrequent and random in nature. Therefore, increased electrical resistance of connection due to fatigue from ohmic heating, thermal cycling, electrical transients is not an aging effect requiring aging management.

018 Increased electrical Based on research by plant personnel, the fuses within resistance of the scope of this evaluation are not routinely pulled or connection due to otherwise manipulated. Therefore, frequent

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 5 of 11 SLRA Table Potential Aging Summary Evaluation 3.6-1 Item # Effect/Mechanism fatigue caused by manipulation is not considered an applicable aging frequent fuse mechanism. Vibration is induced in fuse holders by the removal/manipulation operation of external equipment, such as compressors, or vibration fans, and pumps. Plant walkdown has verified the exact location and mounting of the fuse holders within the scope of this evaluation. This walkdown has verified that field cable termination panel B2536 is a stand-alone enclosure with no direct sources of vibration acting on it. The panel is mounted separately to its own Unistrut support structure which is anchored to the concrete floor. Vibration is not considered an applicable aging mechanism. Therefore, increased electrical resistance of connection due to fatigue caused by frequent fuse removal/manipulation or vibration is not an aging effect requiring aging management.

022 Reduced electrical The metallic clamp (or clip) portion of these fuse insulation resistance holders are constructed of high conductivity tin-plated due to thermal / copper. Tin-plated copper material is commonly used thermoxidative in various electrical applications because of its low cost degradation of and protection against oxidation and corrosion. As organics, radiolysis, shown in SLRA Table 3.6.2-1 under Table 1 item 3.6-1, and photolysis (UV 022 electrical insulation materials for fuse holders (not sensitive materials part of active equipment) include: bakelite; phenolic; only) of organics; melamine or ceramic; molded polycarbonate; other radiation-induced (Reference 1). Experience has shown these materials oxidation; moisture are used in this application because these materials intrusion are high strength, non-conductive, non-tracking, non-hygroscopic, and will not degrade at high temperatures or in the presence of pollution or UV light. The following addresses the environmental stressors of heat, radiation and moisture for the 2A1 Unit 2 6.9 kV Switchgear Room. Plant walkdown verified that there are no sources of potential mechanical system leakage in proximity to the fuse holders in field cable termination panel B2536. The switchgear room temperature is maintained below 100ºF and supply fans provide a positive pressure (Reference 2).

Therefore, moisture intrusion is not an applicable aging mechanism in this atmosphere because condensation does not form on the warm equipment surfaces in the switchgear room and the metallic clamp (or clip) portion of the fuse holder is constructed of corrosion resistance material. The 80-yr service-limiting dose in the Turbine Building is <2E+03 rads. This value is considered

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 6 of 11 SLRA Table Potential Aging Summary Evaluation 3.6-1 Item # Effect/Mechanism benign and is far below the service-limiting radiation thresholds for these insulation materials. For example, phenolic has an 80-yr radiation threshold of 2E+07 rads, while melamine has an 80-yr radiation threshold 5E+07 rads. Temperature in the Unit 2 6.9 kV Switchgear Room is kept below 100ºF. This value is far below the service-limiting temperature thresholds for these insulation materials. For example, phenolic has an 80-yr temperature threshold of 219.3ºF (104.1ºC), while melamine has an 80-yr temperature threshold of 202ºF (94.4ºC). Other materials such as ceramic are not age sensitive. Therefore, radiation and temperature are not considered significant aging mechanisms for these fuse holders (not part of active equipment).

Consistent with SLRA Table 3.6-1 Item Number 022, no XI.E5 AMP for Fuse Holders is required because the fuse holders in field cable termination panel B2536 are located in an environment that does not subject them to environmental aging mechanisms.

An additional review was performed to ensure there were no inconsistencies between SLRA, Revision 1, Table 3.6-1, Summary of Aging Management Evaluations for Electrical and Instrumentation & Control Commodities and SLRA, Revision 1, Supplement 1, Attachment 3, Table 3.6.2-1, Electrical and Instrumentation & Control Commodities - Summary of Aging Management Evaluation.

After review of SLRA, Revision 1, Table 3.6-1 (ADAMS Accession No. ML21285A110) some inconsistencies were identified. SLRA, Revision 1, Table 3.6-1 aligns with NUREG-2192 (SRP-SLR) Table 3.6-1, Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report, however some revisions are required in the discussion column for table item numbers 016, 017, 018, and 022. After review of SLRA, Revision 1, Supplement 1, Attachment 3, Table 3.6.2-1 (ADAMS Accession No. ML22097A202)

(Reference 1) some inconsistences were identified for the Table 1 column line item numbers 3.6-1, 022 and 3.6-1, 018. These line items have been revised to show an Air - indoor uncontrolled environment consistent with the environment for the PSL fuse holders (not part of active equipment) within the scope of this evaluation.

References:

1. FPL Letter L-2022-043 dated April 7, 2022 - Subsequent License Renewal Application Revision 1 - Supplement 1 (ADAMS Accession No. ML22097A202)

2. St. Lucie Unit 2 UFSAR Section 9.4.4, Turbine Building Ventilation System

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 7 of 11 Associated SLRA Revisions:

SLRA revisions are presented on the following pages.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 8 of 11 SLRA Table 3.6-1, page 3.6-17 is revised as follows:

Table 3.6-1: Summary of Aging Management Evaluations for Electrical and Instrumentation & Control Commodities Item Aging Effect/ Aging Management Further Evaluation Component Discussion Number Mechanism Programs (AMP)/TLAA Recommended 3.6-1, 016 Fuse holders (not part of active Increased electrical AMP XI.E5, Fuse Holders No Pursuant to the discussion in SLRA equipment): metallic clamps resistance of connection No AMP is required for those Section 2.5.1.33.6.1.1, the fuse composed of various metals due to chemical applicants who can holders within the scope of SLR are used for electrical connections contamination, demonstrate these fuse holders in an air-indoor uncontrolled exposed to air - indoor, corrosion, and oxidation are located in an environment environment and do not experience uncontrolled (in an air, indoor that does not subject them to the detailed environmental aging controlled environment, environmental aging effects.

increased resistance of mechanisms and effects due to connection due to chemical contamination, chemical contamination, corrosion, and oxidation.

corrosion and oxidation do not apply) 3.6-1, 017 Fuse holders (not part of active Increased electrical AMP XI.E5, Fuse Holders No Pursuant to the discussion in SLRA equipment): metallic clamps resistance of connection No AMP is required for those Section 2.5.1.33.6.1.1, the fuse composed of various metals due to fatigue from applicants who can holders within the scope of SLR are used for electrical connections ohmic heating, thermal demonstrate these fuse holders not subject to ohmic heating, exposed to air - indoor, cycling, electrical are not subject to fatigue due to thermal cycling, or electrical controlled, or uncontrolled transients ohmic heating, thermal cycling, transients.

electrical transients.

3.6-1, 018 Fuse holders (not part of active Increased electrical AMP XI.E5, Fuse Holders No Pursuant to the discussion in SLRA equipment): metallic clamps resistance of connection No AMP is required for those Section 2.5.1.33.6.1.1, the fuse composed of various metals due to fatigue caused by applicants who can holders within the scope of SLR are used for electrical connections frequent fuse demonstrate these fuse holders not subject to frequent manipulation exposed to air - indoor, removal/manipulation or are not subject to fatigue and will not experience fatigue controlled, or uncontrolled vibration caused by frequent fuse degradation (at the metallic clamp).

removal/manipulation or vibration.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 9 of 11 SLRA Table 3.6-1, page 3.6-18 is revised as follows:

Table 3.6-1: Summary of Aging Management Evaluations for Electrical and Instrumentation & Control Commodities Item Aging Effect/ Aging Management Further Evaluation Component Discussion Number Mechanism Programs (AMP)/TLAA Recommended 3.6-1, 019 Cable connections (metallic Increased electrical AMP XI.E6, Electrical Cable No Consistent with NUREG-2191. The parts) composed of various resistance of connection Connections Not Subject to Electrical Cable Connections Not metals used for electrical due to thermal cycling, 10 CFR 50.49 Environmental Subject to 10 CFR 50.49 contacts exposed to air - indoor ohmic heating, electrical Qualification Requirements Environmental Qualification controlled or uncontrolled, air - transients, vibration, Requirements AMP will manage the outdoor chemical contamination, effects of aging.

corrosion, and oxidation 3.6-1, 020 Electrical connector contacts for Increased electrical AMP XI.M10, Boric Acid No Consistent with NUREG-2191. The electrical connectors composed resistance of connection Corrosion Boric Acid Corrosion (B.2.3.4) AMP of various metals used for due to corrosion of will manage the effects of aging.

electrical contacts exposed to air connector contact with borated water leakage surfaces caused by intrusion of borated water 3.6-1, 021 Transmission conductors Loss of conductor None - for AAAC No NUREG-2191 aging effects are not composed of aluminum exposed strength due to corrosion applicable to PSL. See to air - outdoor Section 3.6.2.2.3 for further evaluation.

3.6-1, 022 Fuse holders (not part of active Reduced electrical AMP XI.E5, Fuse Holders No Pursuant to the discussion in SLRA equipment): insulation material insulation resistance due No AMP is required for those Section 2.5.1.33.6.1.1, the fuse composed of electrical insulation to thermal / applicants who can holders within the scope of SLR are material: bakelite; phenolic thermoxidative demonstrate these fuse holders located in an air-indoor melamine or ceramic; molded degradation of organics, are located in an environment uncontrolled environment and are polycarbonate, and other, radiolysis, and that does not subject them to not subject to the detailed exposed to air - indoor photolysis (UV sensitive environmental aging environmental aging effects.

controlled or uncontrolled materials only) of mechanisms organics; radiation-induced oxidation; moisture intrusion

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 10 of 11 Table 3.6.2-1, page 3.6-28 is revised as follows:

Table 3.6.2-1: Electrical and Instrumentation & Control Commodities - Summary of Aging Management Evaluation Structure and/or Component Material Environment Aging Effect Aging NUREG-2191 Table 1 Notes Component Intended Requiring Management Item Item Function Management Program (AMP) /

TLAA Fuse Holders (not part of Insulate Electrical insulation: Air - indoor None None VI.A.LP-24 3.6-1, 022 I active equipment) (electrical) controlled or Bakelite, Phenolic, uncontrolled Electrical Insulation Melamine, or Ceramic; Molded Polycarbonate, or other Organic Polymers Fuse Holders (not part of Electrical Various Metals used for Air - indoor None None VI.A.LP-23 3.6.1, 016 I active equipment) Continuity Electrical Connection uncontrolled Metallic Clamp Fuse Holders (not part of Electrical Various Metals used for Air - indoor None None VI.A.LP-31 3.6.1, 018 I active equipment) Continuity Electrical Connection uncontrolled Metallic Clamp Fuse Holders (not part of Electrical Various Metals used for Air-indoor None None VI.A.LP-7 3.6.1, 017 I active equipment) Continuity Electrical Connection uncontrolled Metallic Clamp General Notes A. Consistent with component, material, environment, aging effect, and AMP listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

E. Consistent with NUREG-2191 material, environment, and aging effect but a different AMP is credited or NUREG-2191 identifies a plant-specific AMP.

I. Aging effect in NUREG-2191 for this component, material and environment combination is not applicable.

Plant Specific Notes None.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. RAI 3.6.1.1-1 L-2022-115 Attachment 4 Page 11 of 11 Associated

Enclosures:

None

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 19.2.2.17-2 L-2022-115 Attachment 5 Page 1 of 6 UFSAR Update for the Unit 1 Refueling Water Storage Tank AMP RAI 19.2.2.17-2 Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 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 period of extended operation. One of the findings that the U.S.

Nuclear Regulatory Commission (NRC) 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 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.

Background:

10 CFR 54.21(d) requires each license renewal application to include a final safety analysis report (FSAR) supplement, containing a summary description of the programs and activities for managing the effects of aging. In its discussions about FSAR supplements, the Standard Review Plan for Subsequent License Renewal (NUREG-2192) notes that the description should be sufficiently comprehensive such that later changes to the program can be controlled by 10 CFR 50.59. NUREG-2192 also notes that the Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report (NUREG-2191), Table XI-01 provides examples of the type of information to be included. GALL-SLR Report Table XI-01, FSAR Supplement Summaries for GALL-SLR Report Chapter XI Aging Management Programs [AMP], provides a description of the Outdoor and Large Atmospheric Metallic Storage Tanks program (AMP XI.M29), stating that loss of material is managed by conducting periodic internal and external visual examinations.

Issue:

The Updated Final Safety Analysis Report (UFSAR) supplement for the Outdoor and Large Atmospheric Metallic Storage Tanks program appears to lack sufficient details for inspecting the Unit 1 Refueling Water Tank (U1 RWT). The staff questions whether the inspection frequency and technique will be based on the NRC approved ASME Section XI Inservice Inspection relief request.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 19.2.2.17-2 L-2022-115 Attachment 5 Page 2 of 6 Request:

Regarding SLRA Section 19.2.2.17, either: a) provide additional information that explains how the current description of the program and aging management activities in the UFSAR supplement meets the intent of 10 CFR 54.21(d) and NUREG-2192, which states that the description should be sufficiently comprehensive such that later changes to the program can be controlled by 10 CFR 50.59 or b) modify the UFSAR supplement to include information related to the U1 RWT and ASME Section XI Inservice Inspection relief request.

PSL Response:

The Unit 1 SLR UFSAR supplement and SLR commitment associated with the Outdoor and Large Atmospheric Metallic Storage Tanks aging management program (AMP) are revised to include the surveillance frequency and techniques associated with the U1 RWT internal inspections, including the surveillances associated with ASME Section XI Inservice Inspection relief requests. The exception and enhancements table in SLRA Appendix B are also updated accordingly.

References:

None.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 19.2.2.17-2 L-2022-115 Attachment 5 Page 3 of 6 Associated SLRA Revisions:

SLRA Appendix A1, Section 19.2.2.17, pages A1-23 and A1-24, as updated by SLRA Supplement 1 (Attachment 21) and the Set 1 (Set 1A) RAI 19.2.2.17-1 Response (Attachment 13), is revised as follows:

19.2.2.17 Outdoor and Large Atmospheric Metallic Storage Tanks The PSL Outdoor and Large Atmospheric Metallic Storage Tanks AMP is an existing AMP, previously part of the PSPM Program and Structures Monitoring Program.

This condition monitoring AMP manages aging effects associated with outdoor tanks sited on concrete and indoor large-volume tanks containing water designed with internal pressures approximating atmospheric pressure that are sited on concrete.

The Unit 1 and Common Unit tanks included within the scope of this AMP are as follows:

Unit 1 Refueling Water Tank (U1 RWT)

Treated Water Storage Tank (TWST)

Unit 1 Condensate Storage Tank (U1 CST)

Diesel Oil Storage Tank 1A (DOST 1A)

Diesel Oil Storage Tank 1B (DOST 1B)

This AMP includes preventive measures to mitigate corrosion by protecting the external surfaces of steel components per standard industry practice. Sealant or caulking is used for outdoor tanks at the tank bottom interface. This AMP manages loss of material and cracking by conducting one-time and periodic internal and external visual and surface examinations. The periodic inspections of the respective tank caulking or sealant are performed on an 18-month frequency.

Inspections of caulking or sealant are supplemented with physical manipulation.

Surface exams are conducted to detect cracking for the aluminum U1 RWT.

Thickness measurements of tank bottoms are conducted to detect degradation (e.g.,

loss of material on the inaccessible external surface). Inspections are conducted in accordance with ASME Code Section XI requirements as applicable or are conducted in accordance with plant-specific procedures that include inspection parameters such as lighting, distance, offset, and surface conditions.

Instead of volumetric examinations, visual inspections are used to inspect the U1 RWT floor, for cracking and loss of material as prescribed in an NRC-approved ASME Section XI Inservice Inspection relief request documented in FPL engineering evaluations and preventive maintenance activities. The preventive maintenance activities include a full hands-on drained tank interior inspection performed using the methods directed by the relief request at the frequency prescribed by the NRC approved relief request for each respective ASME Section XI ISI interval. The drained tank inspection will also inspect for galvanic corrosion cells between the stainless steel piping, and manway flanges and the aluminum tank. For a refueling outage where a hands-on inspection is not scheduled, a remote visual inspection of the RWT liner will be performed. As an option, the remote visual inspections may be performed with the unit on-line.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 19.2.2.17-2 L-2022-115 Attachment 5 Page 4 of 6 SLRA Appendix A1, Section 19.4, Table 19-3 commitment No. 20 (page A1-86), as updated by SLRA Supplement 1 (Attachment 7), is revised as follows:

No. Aging Management NUREG-2191 Commitment Implementation Schedule Program or Activity Section (Section)

Sample expansion inspections that happen in the next inspection interval are part of the preceding interval.

b) Perform baseline one-time interior visual inspections of the U1 RWT. Perform 10-year surface examination inspections of the aluminum U1 RWTs interior nonwetted surface and exterior surface for evidence of loss of material and cracking. The surface examinations will inspect 25 1-square-foot sections or 25 1-linear-foot sections of welds. If evidence of cracking is identified, then a surface examination is also performed to determine the extent of the cracking.

c) Perform 10-year LFET tank bottom thickness examinations of the TWST, DOST 1A, DOST 1B, and the U1 CST, with follow-on UT at discrete locations.

d) Perform visual inspections of the U1 RWT floor, in lieu of volumetric examinations, to inspect for cracking and loss of material as prescribed in an NRC-approved ASME Section XI Inservice Inspection relief request documented in FPL engineering evaluations and preventive maintenance activities. The preventive maintenance activities include a full hands-on drained tank interior inspection performed using the methods directed by the relief request at the frequency prescribed by the NRC approved relief request for each respective ASME Section XI ISI interval. The drained tank inspection will also inspect for galvanic corrosion cells between the stainless steel piping, and manway flanges and the aluminum tank. For a refueling outage where a hands-on inspection is not scheduled, a remote visual inspection of the RWT liner will be performed. As an option, the remote visual inspections may be performed with the unit on-line.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 19.2.2.17-2 L-2022-115 Attachment 5 Page 5 of 6 SLRA Appendix B, Section B.2.3.17, pages B-154 and B-155, as updated by SLRA Supplement 1 (Attachment 22), is revised as follows:

Exceptions to NUREG-2191 The PSL Outdoor and Large Atmospheric Metallic Storage Tanks AMP will take the following exception to the NUREG-2191 guidance:

The PSL Outdoor and Large Atmospheric Metallic Storage Tanks AMP will take an exception to performing volumetric examinations of the U1 RWT floor, since it is not feasible. The aluminum floor for the U1 RWT has through-wall holes and this metal floor was not credited for the original License Renewal. Instead the floor is lined with a fiberglass-reinforced vinyl ester epoxy material (Dudick Protecto-Line 800), which is credited for performing the pressure boundary function for SLR. Instead of volumetric examinations, visual inspections will be used to inspect for cracking and loss of material as prescribed in an approved NRC relief request documented in FPL engineering evaluations and preventive maintenance activities. The preventive maintenance activities include diver inspections performed at a refueling outage interval and a full hands-on drained tank interior inspection performed using the methods directed by the relief request at the frequency prescribed by the NRC approved relief request for each respective ASME Section XI ISI interval. The drained tank inspection will continue to inspect for galvanic corrosion cells between the SS piping, and manway flanges and the aluminum tank. For a refueling outage where a hands-on inspection is not scheduled, a remote visual inspection of the RWT liner will be performed. As an option, the remote visual inspections may be performed with the unit on-line.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Response to NRC RAI No. 19.2.2.17-2 L-2022-115 Attachment 5 Page 6 of 6 SLRA Appendix B, Section B.2.3.17 (enhancements table), page B-157, is revised as follows:

Element Affected Enhancement o Expand the inspection to include all tanks of with the same material-environment combination (for DOST degradation).

o For other sampling-based inspections (e.g., 20%, 25 locations) the smaller of five additional inspections or 20% of the inspection population is conducted. If subsequent inspections do not meet acceptance criteria, an extent of condition and extent of cause is conducted to determine the further extent of inspection. The additional inspections include inspections at all of the Units with the same material, environment, and aging effect combination.

Sample expansion inspections that happen in the next inspection interval are part of the preceding interval.

4. Detection of Aging Effects Perform baseline one-time interior visual inspections of the RWTs.

Perform 10-year surface examination inspections of the aluminum and SS RWTs interior nonwetted surface and exterior surface for evidence of loss of material and cracking. The surface examinations will inspect 25 1-square-foot sections or 25 1-linear-foot sections of welds. If evidence of cracking is identified, then a surface examination is also performed to determine the extent of the cracking.

4. Detection of Aging Effects Perform 10-year LFET tank bottom thickness examinations of the U2 RWT, U2 PWST, TWST, DOST 1A, DOST 1B, and the CSTs, with follow-on UT at discrete locations.

4. Detection of Aging Perform visual inspections of the U1 RWT floor, in lieu of Effects volumetric examinations, to inspect for cracking and loss of material as prescribed in an NRC-approved ASME Section XI Inservice Inspection relief request documented in FPL engineering evaluations and preventive maintenance activities. The preventive maintenance activities include a full hands-on drained tank interior inspection performed using the methods directed by the relief request at the frequency prescribed by the NRC approved relief request for each respective ASME Section XI ISI interval. The drained tank inspection will also inspect for galvanic corrosion cells between the stainless steel piping, and manway flanges and the aluminum tank. For a refueling outage where a hands-on inspection is not scheduled, a remote visual inspection of the RWT liner will be performed. As an option, the remote visual inspections may be performed with the unit on-line.

Associated

Enclosures:

None.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Revised Response to NRC RAI No. B.2.3.34-2 L-2022-115 Attachment 6 Page 1 of 6 Inspection of Water-Control Structures Associated with Nuclear Power Plants AMP -

Hurricane Protection Sheet Piles RAI B.2.3.34-2 Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 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 period of extended operation. One of the findings that the U.S.

Nuclear Regulatory Commission (NRC) 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 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.

Background:

Subsequent License Renewal Application (SLRA) Section B.2.3.34, Inspection of Water-Control Structures Associated with Nuclear Power Plants, states that the St. Lucie Nuclear Plant (PSL) Inspection of Water-Control Structures Associated with Nuclear Power Plants Aging Management Program (AMP), with enhancements, will be consistent without exception to the ten program elements of Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report AMP XI.S7, Inspection of Water-Control Structures Associated with Nuclear Power Plants.

SLRA Section 2.4.14 states that the ultimate heat sink dam evaluation boundary is at the exterior surface of the structure and adjacent hurricane protection sheet piles are also considered within the evaluation boundary. SLRA Table 2.4.14 and UFSAR 3.8.1.1.5 show that steel sheet piling (beneath dam) is subject to Aging Management Review (AMR).

For the scope of program program element, the GALL-SLR Report AMP states that the scope of the program includes structural steel, and structural bolting associated with water-control structures, steel or wood piles and sheeting required for the stability of embankments and channel slopes, and miscellaneous steel, such as sluice gates and trash racks.

Issue:

The staff is unclear where the hurricane protection sheet piles are located, or if they are the same item as the sheet piling beneath the dam, since there is no discussion of hurricane protection sheet piles provided in SLRA Section B.2.3.34. In addition, the staff was unable to identify AMR line items in the SLRA that addressed this commodity.

It is unclear whether the hurricane protection sheet piles discussed in SLRA Section 2.4.14 are within the scope of subsequent license renewal and subject to AMR.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Revised Response to NRC RAI No. B.2.3.34-2 L-2022-115 Attachment 6 Page 2 of 6 Request:

1. Provide the description of the hurricane protection sheet piles and their intended functions.

2. Clarify whether the hurricane protection sheet piles are within the scope of subsequent license renewal and subject to AMR.

3. If the hurricane protection sheet piles are within the scope of subsequent license renewal and subject to AMR, explain how aging management will be accomplished, provide associated AMR Table 2 items and update SLRA as necessary.

PSL Response:

This revised RAI response supersedes in its entirety the RAI response provided in 4 of FPL Letter L-2022-108 (Reference ML22192A078).

The numbered responses below correspond to the numbered requests above.

1. The hurricane protection sheet piles are steel sheet piles that are installed along the banks of Big Mud Creek on either side of the ultimate heat sink dam to protect against erosion of the banks during hurricanes. The sheet piles run mostly parallel to the road for a combined total of 598-6. The sheet piles are driven below ground to elevation 26.5 ft. The top elevation of the sheet piles varies between +11.00 ft and +16.00 ft.

The top of the sheet piles is visible at ground level.

2. As stated in SLRA Section 2.4.14 (Reference ML21285A110), the hurricane protection sheet piles are considered within the evaluation boundary. During initial license renewal, the hurricane protection sheet piles were evaluated and determined not to be within the scope of license renewal as they did not support an intended function. For subsequent license renewal, the hurricane sheet piles are conservatively considered to be within the scope of SLR and subject to AMR.

3. Aging of the hurricane protection sheet piles will be managed by the PSL Structures Monitoring AMP, consistent with SRP Table 1 Item 3.5-1, 079 and NUREG-2191 Item III.A3.TP-219 for steel components: piles exposed to soil, groundwater and with SRP Table 1 Item 3.5-1, 077 and NUREG-2191 Item III.A3.TP-302 for steel components: all structural steel exposed to air-outdoor. The implementing procedures for the PSL Structures Monitoring AMP currently includes the hurricane protection sheet piles; therefore, no additional enhancements are necessary.

References:

None.

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Revised Response to NRC RAI No. B.2.3.34-2 L-2022-115 Attachment 6 Page 3 of 6 Associated SLRA Revisions:

SLRA Table 2.4-14, page 2.4-30, is revised as follows:

Table 2.4-14 Ultimate Heat Sink Dam (Barrier Wall)

Components Subject to Aging Management Review Component Type Component Intended Function(s)

Checkered plate Structural support Grating Handrails Ladders Platforms Stairs Concrete: foundation Structural support Concrete: foundations, roof, slabs, walls Missile barrier Shelter, protection Structural support Miscellaneous steel (i.e., missile barriers, Shelter, protection hatch covers, etc.) Missile barrier Steel sheet piling (beneath dam) Shelter, protection Steel sheet piling (hurricane protection) Shelter, protection Structural bolting Structural support

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Revised Response to NRC RAI No. B.2.3.34-2 L-2022-115 Attachment 6 Page 4 of 6 SLRA Table 3.5-1 Item Number 3.5-1, 079, page 3.5-65, is revised as follows:

Table 3.5-1: Summary of Aging Management Evaluations for the Containments, Structures and Component Supports Item Aging Aging Management Further Evaluation Component Discussion Number Effect/Mechanism Program / TLAA Recommended 3.5-1, 079 Steel components: Loss of material due AMP XI.S6, "Structures No Consistent with NUREG-2191.

piles to corrosion Monitoring" The Structures Monitoring (B.2.3.33) AMP is credited with managing loss of material of steel piles for the Ultimate Heat Sink Dam (Barrier Wall), hurricane protection, and discharge nose wave protection (Yard Structures).

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Revised Response to NRC RAI No. B.2.3.34-2 L-2022-115 Attachment 6 Page 5 of 6 SLRA Table 3.5.2-14, page 3.5-128, is revised as follows:

Table 3.5.2-14: Ultimate Heat Sink Dam (Barrier Wall) - Summary of Aging Management Evaluation Aging Effect Intended Aging Management NUREG-2191 Table 1 Component Type Material Environment Requiring Notes Function Program Item Item Management Concrete: Missile barrier Concrete Raw water Cracking Inspection of Water- III.A6.T-34 3.5-1, A foundations, roof, Shelter, protection (reinforced) Control 096 slabs, walls Structural support Structures Associated (accessible) with Nuclear Power Plants (B.2.3.34)

Concrete: Missile barrier Concrete Raw water Increase in Inspection of Water- III.A6.TP-37 3.5-1, A foundations, roof, Shelter, protection (reinforced) porosity and Control 061 slabs, walls Structural support permeability Structures Associated (accessible) Loss of strength with Nuclear Power Plants (B.2.3.34)

Concrete: Missile barrier Concrete Raw water Cracking Inspection of Water- III.A6.TP-38 3.5-1, A foundations, roof, Shelter, protection (reinforced) Loss of bond Control 059 slabs, walls Structural support Loss of material Structures Associated (accessible) with Nuclear Power Plants (B.2.3.34)

Concrete: Missile barrier Concrete Water - flowing Loss of material Inspection of Water- III.A6.T-20 3.5-1, A foundations, roof, Shelter, protection (reinforced) Control 056 slabs, walls Structural support Structures Associated with Nuclear Power Plants (B.2.3.34)

Miscellaneous steel Missile barrier Steel Air - indoor Loss of material Structures Monitoring III.A8.TP-302 3.5-1, B (i.e., hatch covers, Shelter, protection uncontrolled (B.2.3.33) 077 missile barriers, etc.) Air - outdoor Steel sheet piling Shelter, protection Steel Groundwater/soil Loss of material Structures Monitoring III.A3.TP-219 3.5-1, B (beneath dam) (B.2.3.33) 079 Steel sheet piling Shelter, Steel Groundwater/soil Loss of material Structures III.A3.TP-219 3.5-1, B (hurricane protection Monitoring (B.2.3.33) 079 protection)

Steel sheet piling Shelter, Steel Air - outdoor Loss of material Structures III.A3.TP-302 3.5-1, B (hurricane protection Monitoring (B.2.3.33) 077 protection)

St. Lucie Units 1 and 2 Dockets 50-335 and 50-389 PSL Revised Response to NRC RAI No. B.2.3.34-2 L-2022-115 Attachment 6 Page 6 of 6 Associated

Enclosures:

None.

St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 PSL Revision to Supplement 1 Attachment 18 L-2022-115 Attachment 7 Page 1 of 23 Steam Generators: Clarified AMR Results and AMP Scope Affected SLRA Sections: Table 2.3.1-5, Table 3.1-1, Table 3.1.2-5, Table 19-3, (Appendix A1 and A2) Section 19.2.2.10, B.2.3.10, B.2.3.20 SLRA Page Numbers: 2.3-13, 3.1-23, 3.1-27, 3.1-38, 3.1-39, 3.1-89, 3.1-90, 3.1-97 through 3.1-99, 3.1-101, A1-18, A1-19, A1-71, A2-18, A2-19, A2-72, B-88 through B-91, B-92, B-93, B-174 Description of Change:

This revised SLRA supplemental response supersedes in its entirety the supplemental response provided in Attachment 18 of FPL Letter L-2022-043 (Reference ML22097A202). The revised SLRA supplemental response eliminates the reference to the PSL license amendment request to implement Revision 5 of NUREG-1432, Standard Technical Specifications-Combustion Engineering Plants (ML21265A285) in accordance with TSTF 577 Revision 1 (ML21098A188) and the associated exception to the Steam Generator AMP. The markup provided to SLRA Table 2.3.1-5 on page 2.3-13, SLRA Appendix A1 on page A1-71, SLRA Appendix A2 on page A2-72, SLRA Section B.2.3.10 on pages B-88 through B-91, B-92, and B-93 incorporates the markup from the PSL RAI Set 2 Responses (Reference ML22192A078).

The PSL SLRA Table 2.3.1-5 lists the intended functions of the tube bundle wrapper and wrapper supports as Structural support and Direct flow. In Table 3.1.2-5, the intended function of the tube bundle wrapper and wrapper supports only lists Structural support. Table 2.3.1-5 is accurate and as such SLRA Table 3.1.2-5 is modified to include the intended function of Direct flow in the line entry for the tube bundle wrapper and wrapper support.

PSL SLRA Appendices A1 and A2 Section 19.2.2.10 cite that the PSL Steam Generators AMP is modeled after NEI 97-06, Steam Generator Program Guidelines and the referenced EPRI Guidelines of NEI 97-06. These sections are edited to specify that the Steam Generators AMP is modeled after Revision 3 of NEI 97-06 consistent with SLRA general reference 1.6.32 on SLRA page 1-15.

Further evaluation item 3.1.2.2.11.1 evaluates the PSL steam generator divider plates with respect to PWSCC susceptibility and whether or not a plant-specific AMP is necessary. The Unit 1 RSG design includes a floating divider plate that has no crack initiation point. The Unit 2 RSG divider plate design utilizes highly resistant materials. Both Unit 1 and Unit 2 RSG divider plates are dispositioned as not requiring additional aging management from a plant-specific AMP. PSL SLRA Section B.2.3.20 summarizes this disposition and correctly cites that no plant-specific AMP is necessary but does not cite the associated justifications. Accordingly, SLRA Section B.2.3.20 is revised to cite the associated justifications provided in further evaluation item 3.1.2.2.11.1. In addition, plant specific note 1 to Table 3.1.2-5 is clarified to recognize that the nickel alloy divider plate is highly resistant but remains susceptible to PWSCC.

The Unit 1 stainless steel divider plate exposed to reactor coolant is susceptible to loss of material and cracking. The line items in Table 3.1.2-5 do not address the aging effect of loss of material in the Unit 1 divider plate. To recognize the aging effect and appropriate aging management program, an additional line item is added to Table 3.1.2-5 citing NUREG-2191 item IV.C2.RP-23 which credits the Water Chemistry program to manage loss of material.

St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 PSL Revision to Supplement 1 Attachment 18 L-2022-115 Attachment 7 Page 2 of 23 Further evaluation item 3.1.2.2.11.2 evaluates the PSL steam generator tube-to-tubesheet welds with respect to PWSCC and whether or not a plant-specific AMP is necessary. Both Unit 1 and Unit 2 steam generators are dispositioned to not require additional management from a plant-specific AMP but remain susceptible to PWSCC and require management by the Steam Generators and Water Chemistry AMPs. Accordingly, SLRA Table 2.3.1-5, Table 3.1-1, and Table 3.1.2-5 are modified to identify that the tube-to-tubesheet welds are in scope, susceptible to PWSCC and loss of material, and managed by the Steam Generators and Water Chemistry AMPs. In addition, discussions of the Steam Generators AMP in PSL SLRA Appendices A1 and A2 Section 19.2.2.10, and Appendix B Section B.2.3.10 are modified to identify that the tube-to-tubesheet welds are within the scope of the AMP.

The PSL steam generator component type feedwater feedring included in SLRA Table 2.3.1-5 does not fully address the feedwater feedring and its supports. The feedwater feedring includes intended functions of Structural integrity (attached) as well as Direct flow. The associated feedwater feedring supports have an intended function of Structural integrity (attached). In addition, the Unit 2 feedwater feedring is composed of stainless steel and the supports are carbon steel. To clarify this, the component type feedwater feedring supports is added in SLRA Tables 2.3.1-5, 3.1-1, and 3.1.2-5 and the appropriate intended functions and material types are identified for the feedwater feedring supports. The discussion in SLRA Table 3.1-1 for item 072 is revised to distinguish the group of components that are common to both units and those components that are only applicable to Unit 1. In addition, Appendix B Section B.2.3.10 is revised to discuss Unit 1 operating experience regarding feedwater feedring support inspections.

The PSL Steam Generators AMP remedies steam generator tubes which do not satisfy the performance criteria through tube plugging. The scope of the Steam Generators AMP is clarified in SLRA Sections Appendices A1 and A2 Section 19.2.2.10, and Appendix B Section B.2.3.10.

The PSL Steam Generators AMP inspections are performed in accordance with the Degradation Assessment for both the primary-side and secondary-side components. This is clarified in SLRA Section B.2.3.10.

The implementation schedule for the Steam Generators AMP includes a condition that it will be implemented no later than the last refueling outage prior to the SPEO. However, there are no enhancements or SLR-specific inspections required to be implemented prior to entry into the SPEO. To clarify the state of the AMP, this condition is removed from the implementation schedule in SLRA Table 19-3.

SLRA Tables 2.3.1-5, 3.1-1, and 3.1.2-5 include the component type Tube support plates and anti-vibration bars (Unit 2). While the tube support plates are unique to Unit 2, anti-vibration bars are an applicable component type for both Unit 1 and Unit 2. The component type of anti-vibration bars is inclusive of the design specific names of anti-vibration support components such as the flat fan bars used by the Unit 1 design and v-shaped support pads and bars used for the Unit 2 design. This is clarified in SLRA Tables 2.3.1-5, 3.1-1, and 3.1.2-5.

The PSL steam generators are susceptible to cumulative fatigue damage and cracking due to fatigue or cyclic loading. Table 3.1.2-5 includes NUREG-2191 line item IV.D1.R-221 to recognize the primary side steam generator components exposed to reactor coolant being managed for cumulative fatigue damage and cracking through the Section 4.3.1 TLAA, Metal Fatigue of Class 1 Components. In addition to the primary side components, the Section 4.3.1

St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 PSL Revision to Supplement 1 Attachment 18 L-2022-115 Attachment 7 Page 3 of 23 TLAA addresses the secondary side carbon steel components exposed to treated water and steam and bolting exposed to air. To recognize this, NUREG-2191 line items IV.D1.R-33 and IV.C2.R-18 are added to SLRA Table 3.1.2-5 to manage the carbon steel steam generator components exposed to treated water and steam and bolting exposed to air respectively. These changes are also captured in Table 3.1-1, Item number 3.1-1, 005.

PSL performs condition monitoring assessments to determine if tube integrity was met during the prior operating interval. PSL performs tube plugging and operational assessments to provide assurance that tube integrity will be maintained through the next inspection. SLRA Appendices A1 and A2 Section 19.2.2.10 are revised to discuss the performance of condition monitoring assessments consistent with the discussion in SLRA B.2.3.10.

SLRA Table 2.3.1-5 on page 2.3-13 is revised as follows including revisions incorporated in the previous PSL response to RAI B.2.3.10-4 (Reference ML22192A078):

Table 2.3.1-5 Steam Generator Components Subject to Aging Management Review Component Type Component Intended Function(s)

Anti-vibration bars 1 Structural support Blowdown nozzles Pressure boundary Bolting Mechanical closure Conical skirt Structural support Divider plates Flow distribution Feedwater feedring Structural integrity (attached)

Direct flow Feedwater feedring supports Structural integrity (attached)

Feedwater j-nozzle Structural integrity (attached)

Direct flow Feedwater nozzle Pressure boundary Moisture separators Structural integrity (attached)

Primary heads Pressure boundary Primary inlet and outlet nozzles Pressure boundary Primary instrument nozzles Pressure boundary Primary manway covers Pressure boundary Recirculation nozzles and end caps (Unit 2) Pressure boundary Secondary instrument nozzles Pressure boundary Secondary manway and handhole closure Pressure boundary covers Stay cylinders (Unit 1) Pressure boundary Steam generator components with fatigue Pressure boundary analysis Steam generator components: external Pressure boundary surfaces Mechanical closure Steam outlet nozzle (Unit 2) Pressure boundary Steam outlet nozzle venturis (Unit 2) Throttle Steam outlet nozzle with integral flow Pressure boundary orifices (Unit 1) Throttle

St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 PSL Revision to Supplement 1 Attachment 18 L-2022-115 Attachment 7 Page 4 of 23 Table 2.3.1-5 Steam Generator Components Subject to Aging Management Review Component Type Component Intended Function(s)

Tube bundle wrapper and wrapper supports Structural support Direct flow Tube-to-tubesheet welds Pressure boundary Tube plugs Pressure boundary Tube stabilizers (stakes) (Unit 2) Structural support Tube support lattice bars (Unit 1) Structural support Tube support plates and anti-vibration bars Structural support (Unit 2)

Tubesheets Pressure boundary Upper and lower shells, secondary head, Pressure boundary transition cone Upper vessel clevises and shear keys Structural support U-tubes Pressure boundary Heat transfer Note:

1. This component type includes the Unit 1 flat fan bars and the Unit 2 v-shaped support pads.

St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 PSL Revision to Supplement 1 Attachment 18 L-2022-115 Attachment 7 Page 5 of 23 SLRA Table 3.1-1 on page 3.1-23 is revised as follows:

Table 3.1-1: Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program / TLAA Recommended 3.1-1, 005 Steel, stainless steel, Cumulative fatigue TLAA, SRP-SLR Yes (SRP-SLR Consistent with NUREG-2191. Cumulative steel (with stainless steel damage: cracking Section 4.3 "Metal Section 3.1.2.2.1) fatigue damage of steel, stainless steel, or nickel alloy cladding) due to fatigue, cyclic Fatigue" and steel (with stainless steel cladding),

steam generator loading piping components and bolting is components, pressurizer addressed as a TLAA in Section 4.3.1.

relief tank components, Cumulative fatigue damage in the piping components, pressurizer surge line is addressed with a bolting plant specific AMP. Further evaluation is documented in Section 3.1.2.2.1.

SLRA Table 3.1-1 on pages 3.1-27 is revised as follows:

Table 3.1-1: Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program / TLAA Recommended 3.1-1, 025 Steel (with nickel alloy Cracking due to AMP XI.M2, "Water Yes (SRP-SLR Consistent with NUREG-2191. The Steam cladding) or nickel alloy primary water SCC Chemistry," and AMP Sections 3.1.2.2.11.1 Generators and Water Chemistry AMPs are steam generator primary XI.M19, and used to manage cracking due to primary side components: divider "Steam Generators." 3.1.2.2.11.2) water SCC in the tube-to-tubesheet welds plate and tube-to-tube In addition, a and the Unit 2 divider plates.

sheet welds exposed to plant- specific Further evaluation is documented in reactor coolant program is to be Section 3.1.2.2.11.

evaluated.

St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 PSL Revision to Supplement 1 Attachment 18 L-2022-115 Attachment 7 Page 6 of 23 SLRA Table 3.1-1 Item Number 3.1-1, 072 on page 3.1-38 and Item Number 3.1-1, 076 on page 3.1-39 are revised as follows:

Table 3.1-1: Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program / TLAA Recommended 3.1-1, 072 Steel steam generator Loss of material due AMP XI.M19, "Steam No Consistent with NUREG-2191. The Steam tube support plate, tube to general, pitting, Generators," and Generators and Water Chemistry AMPs are bundle wrapper, supports crevice corrosion, AMP XI.M2, "Water used to manage loss of material due to and mounting hardware erosion, ligament Chemistry" (corrosion general, pitting, and crevice corrosion, exposed to secondary cracking due to based aging effects erosion, and ligament cracking due to feedwater or steam corrosion and mechanisms only) corrosion in the steel steam generator tube bundle wrapper and supports, feedwater feedring supports, tubesheets, Unit 1 moisture separators, tubesheets, and Unit 1 feedwater feedring exposed to treated water or steam.

3.1-1, 076 Steel, chrome plated Loss of material due AMP XI.M19, No Consistent with NUREG-2191. The Steam steel, stainless steel, to wear, fretting "Steam Generators" Generators AMP is used to manage loss of nickel alloy steam material due to wear and fretting of the generator U-bend stainless steel anti-vibration bars, the supports including stainless steel Unit 1 tube support lattice anti-vibration bars bars, and the stainless steel Unit 2 tube exposed to secondary support plates and anti-vibration bars feedwater or steam exposed to treated water or steam.

St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 PSL Revision to Supplement 1 Attachment 18 L-2022-115 Attachment 7 Page 7 of 23 SLRA Table 3.1.2-5 on pages 3.1-89 and 3.1-90 is revised as follows Table 3.1.2-5: Steam Generators - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging NUREG-2191 Table 1 Notes Function Requiring Management Item Item Management Program Anti-vibration bars Structural Stainless Treated water Loss of material Steam Generators IV.D1.RP-225 3.1-1, 076 A support steel (ext) Steam (ext) (B.2.3.10)

Anti-vibration bars Structural Stainless Treated water Loss of material Steam Generators IV.D1.RP-226 3.1-1, 071 A support steel (ext) Steam (ext) (B.2.3.10)

Water Chemistry (B.2.3.2)

Anti-vibration bars Structural Stainless Treated water Cracking Steam Generators IV.D1.RP-384 3.1-1, 071 A support steel >140°F (ext) (B.2.3.10)

Steam (ext) Water Chemistry (B.2.3.2)

Blowdown nozzles Pressure Carbon steel Air - indoor Loss of material External Surfaces IV.C2.R-431 3.1-1, 124 A boundary uncontrolled (ext) Monitoring of Mechanical Components (B.2.3.23)

Blowdown nozzles Pressure Carbon steel Treated water Loss of material ASME Section XI IV.D1.RP-368 3.1-1, 012 C boundary (int) Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1) Water Chemistry (B.2.3.2)

Blowdown nozzles Pressure Carbon steel Treated water Wall thinning - Flow-Accelerated IV.D1.R-37 3.1-1, 061 C boundary (int) FAC Corrosion (B.2.3.8)

Bolting Mechanical Carbon steel Air - indoor Loss of material Bolting Integrity IV.D1.RP-166 3.1-1, 064 A closure uncontrolled (ext) (B.2.3.9)

Bolting Mechanical Carbon steel Air - indoor Loss of preload Bolting Integrity IV.D1.RP-46 3.1-1, 067 A closure uncontrolled (ext) (B.2.3.9)

Bolting Mechanical Carbon steel Air - indoor Cumulative TLAA - Section IV.C2.R-18 3.1-1, 005 A closure uncontrolled fatigue damage 4.3.1, Metal (ext) Cracking Fatigue of Class 1 Components

St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 PSL Revision to Supplement 1 Attachment 18 L-2022-115 Attachment 7 Page 8 of 23 Table 3.1.2-5: Steam Generators - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging NUREG-2191 Table 1 Notes Function Requiring Management Item Item Management Program Conical skirt Structural Carbon steel Air - indoor Loss of material External Surfaces IV.C2.R-431 3.1-1, 124 C support uncontrolled (ext) Monitoring of Mechanical Components (B.2.3.23)

Divider plates Flow Stainless steel Reactor coolant Cracking Water Chemistry IV.D1.RP-17 3.1-1, 086 A (Unit 1) distribution (ext) (B.2.3.2)

Divider plates Flow Stainless Reactor coolant Loss of material Water Chemistry IV.C2.RP-23 3.1-1, 088 C (Unit 1) distribution steel (ext) (B.2.3.2)

Divider plates Flow Nickel alloy Reactor coolant Cracking Steam Generators IV.D1.RP-367 3.1-1, 025 A, 1 (Unit 2) distribution (ext) (B.2.3.10)

Water Chemistry (B.2.3.2)

Divider plates Flow Nickel alloy Reactor coolant Loss of material Water Chemistry IV.C2.RP-23 3.1-1, 088 C (Unit 2) distribution (ext) (B.2.3.2)

Feedwater feedring Structural Carbon steel Treated water Loss of material Steam Generators IV.D1.RP-161 3.1-1, 072 C (Unit 1) integrity (ext) Steam (ext) (B.2.3.10)