L-MT-23-037, Subsequent License Renewal Application Response to Request for Additional Information Set 3

Subsequent License Renewal Application Response to Request for Additional Information Set 3

ML23265A158
Person / Time
Site:	Monticello
Issue date:	09/22/2023
From:	Hafen S Northern States Power Company, Minnesota, Xcel Energy Inc
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
L-MT-23-037
Download: ML23265A158 (1)

Text

(l Xcel Energy* 2807 West County Road 75 Monticello, MN 55362 September 22, 2023 L-MT-23-037 10 CFR 54.17 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Monticello Nuclear Generating Plant Docket No. 50-263 Renewed Facility Operating License No. DPR-22 Subsequent License Renewal Application Response to Request for Additional Information Set 3

References:

1) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant Docket No. 50-263, Renewal License Number DPR-22 Application for Subsequent Renewal Operating License dated January 9, 2023, ML23009A353

2) Email from the NRC to Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy, Monticello SLRA - Request for Additional Information - Set 1 dated July 19, 2023, ML23200A350 and ML23200A351

3) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant - Subsequent License Renewal Application Response to Request for Additional Information Set 1 dated August 15, 2023, ML23227A175

4) Email from the NRC to Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy, Monticello SLRA - Request for Additional Information - Set 2 dated August 7, 2023, ML23219A107 and ML23219A108

5) Letter from Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy to Document Control Desk, Monticello Nuclear Generating Plant Subsequent License Renewal Application Response to Request for Additional Information Set 2 and Supplement 6 dated September 05, 2023, ML23248A474

6) Email from the NRC to Northern States Power Company, a Minnesota corporation (NSPM), d/b/a Xcel Energy, Monticello SLRA - Request for Additional Information - Set 3 dated August 25, 2023, ML23237A483

Docum ent Co ntro l Des k L-MT 037 Page 2 Northern States Power Company, a Minnesota corporation, doing business as Xcel Energy hereafter "NSPM", is submitting responses to requests for additional information (RAls) to the Subsequent License Renewal Application, listed in Reference 1.

RAI Set 1 and Set 2 were issued by the NRC in References 2 and 4, respectively. Responses were provided in References 3 and 5, respectively. Additional RAls were issued by the NRC as Set 3 on August 25, 2023 (Reference 6). The responses to RAI Set 3 are provided in the Enclosures. Any RAI responses that require revisions to the SLRA are marked up in accordance with the paragraph below that discusses changes to the SLRA.

In the enclosures, changes are described along with the affected section(s) and page number(s) of the docketed SLRA (Reference 1) where the changes are to apply. For clarity, revisions to the SLRA are provided with deleted text by strikethrough and inserted text by bold red underline . Changes incorporated from previous RAls and supplements are provided by bold, black font and noted in the enclosure .

Summary of Commitments This letter makes no new commitments. Revisions to existing commitments are explained in the enclosures. Commitments 19 and 30 include revisions.

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

z.:i. , 2023.

S awn Site Vic resident, Monticello Nuclear Generating Plant Northern States Power Company - Minnesota cc: Administrator, Region 111, USNRC Project Manager, Monticello, USNRC Resident Inspector, Monticello, USNRC Minnesota Department of Commerce

Document Control Desk L-MT-23-037 Page 3 Enclosures Index Enclosure Subject No.

01 RAI B.2.3.27-3 02 RAI B.2.3.16-1 03 RAI B.2.3.16-2 04 RAI B.2.3.16-3 05 RAI B.2.3.17-1 1

RAI B.2.3.27-3

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 1 of 10 RAI B.2.3.27-3 Regulatory Basis:

10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (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:

DRAFT NRC Regulatory Issue Summary (RIS) 2014-06, Consideration of Current Operating Issues and Licensing Actions in License Renewal, Revision 1, (ML22024A172; issuance of final version pending) notes that the NRC staff needs to receive information about recent and late-breaking operating experience to have sufficient technical bases to evaluate the adequacy of an applicants aging management activities.

As discussed in NRC Inspection Report 05000263/2023001 (ML23124A108), the source of a recent radioactive leak into groundwater was determined to be from a below grade portion of the control rod drive piping that runs between the reactor building and the turbine building. By design, there is a gap between these buildings to eliminate seismic interactions, and the leak occurred in that gap. The inspection report notes that the leaking carbon steel piping was replaced with stainless steel, and the pipe penetration was modified to allow periodic inspections. The report also identifies a performance deficiency for the licensees failure to include the below grade portion of the control rod drive piping within the scope of the sites existing Underground Piping and Tank Integrity program.

SLRA Supplement 4 (ML23199A154), Enclosure 6b adds aging management review items to the Buried and Underground Piping and Tanks program and states that the supplement addresses the control rod drive piping between the reactor and turbine buildings that is potentially subject to wetting from groundwater due to its elevation. The staff notes that changes to the SLRA included the addition of underground environment to the associated system table with aging management review items for managing loss of material and cracking of the new stainless steel piping exposed to an underground environment. These new items use the Buried and Underground Piping and Tanks program to manage the associated aging effects. The supplement also added steel piping items located in a vault to the off-gas system that were inadvertently omitted from the SLRA.

SLRA Section B.2.3.27, Buried and Underground Piping and Tanks, includes a discussion in the plant-specific operating experience about an increasing trend of chloride concentrations in groundwater samples between 2011 and 2015. The SLRA states that the increase in chloride concentration was likely due to salt treatment during the winter months.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 2 of 10 Monticello Updated Safety Analysis Report (USAR), Section 12.2.2.1.1, Structure Description, Revision 36 (ML23006A146) states that a 1-inch seismic gap separates the reactor and turbine buildings and notes that the 1-inch separation is filled with pre-molded filler up to the 951-foot elevation.

GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks, recommends external visual inspections of underground steel and stainless steel piping in each 10-year inspection interval. It also recommends inspections for cracking, using a method that has been determined to be capable of detecting cracking. In addition, while the AMP does not recommend coatings for underground stainless steel piping (coatings are recommended for underground steel piping), it does recommend coatings for stainless steel piping in chloride containing environments.

NUREG-2192, Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants, states [i]f an applicant does take credit for a program in the GALL-SLR Report, it is incumbent on the applicant to ensure that the conditions and operating experience (OE) at the plant is bounded by the conditions and OE for which the GALL-SLR Report program was evaluated.

Issue:

1. Due to the timing of the recent discovery of leaking underground Control Rod Drive (CRD) piping, operating experience documentation was not available to the staff during its audit of the Buried and Underground Piping and Tanks program. Although SLRA Supplement 4 added aging management review items resulting from consequent modifications, it did not include any discussion or specific operating experience information concerning the degradation of the CRD piping (e.g., internal or external corrosion, depth and area of wall loss, results of any causal determinations).

2. GALL-SLR Report AMP XI.M41 recommends external visual inspections of underground piping, where underground components are described as being contained within a tunnel or vault. Given the potentially limited access to the underground CRD piping (e.g.,

small gap between the reactor and turbine buildings with pre-molded filler material), it is unclear how the inspections will be performed.

3. Given the inadvertent omission of underground CRD and off-gas system piping from the SLRA, if it unclear whether additional actions have been taken and, if so, whether they have been completed to identify any other in-scope underground piping that was inadvertently omitted from the SLRA.

4. Based on groundwater samples containing elevated levels of chlorides, it is unclear whether in-scope underground steel and stainless steel piping are externally coated in accordance with the preventive actions program element of GALL-SLR Report AMP XI.M41.

Request:

1. Provide operating experience information regarding the degraded CRD piping (e.g.,

internal or external corrosion, depth and area of wall loss (if applicable), causal determinations) as needed to ensure that the conditions and operating experience at the plant are bounded by the Buried and Underground Piping and Tanks program.

2. Provide additional information with respect to how inspections of underground CRD piping will be conducted given the potentially limited access (e.g., small gap between the reactor and turbine buildings, presence of filler material).

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 3 of 10

3. Provide information regarding actions that have been or will be taken to identify any other in scope underground piping that may have been inadvertently omitted from the SLRA.

4. Provide clarification with respect to whether in-scope underground steel and stainless steel piping are externally coated in accordance with the preventive actions program element of GALL-SLR Report AMP XI.M41. If the subject components are not externally coated, state the basis for why external coatings are not provided.

Response to RAI B.2.3.27-3:

1. Control Rod Drive (CRD) Piping Degradation Operating Experience and Causal Analysis:

a. The degraded CRD piping, as discussed above, was located at penetration FZ-1833, which contained two carbon steel 3-inch pipes, the CRD suction piping and CRD piping leading to a relief valve. FZ-1833 is at approximately 910 in elevation. Normal ground water level is approximately at the 906 elevation but does occasionally reach the 911 elevation for a few weeks each year. The CRD piping is below grade but not in contact with soil. The corroded section of pipe was not directly observable from inside the building due to the close proximity of the exterior surface of the buildings walls and because the penetration was grouted on both ends. The grout covered approximately 12 inches on each side of the piping.

b. The visual examinations of the removed piping sections showed that both of the CRD pipes experienced severe corrosion of the external surfaces in the regions exposed to the ground water present between the buildings.

A through-wall pinhole leak occurred as a result of the severe external surface corrosion on the CRD suction pipe. No indications of coating being applied on the piping external surface was observed.

The failure of CRD piping was from general corrosion of the pipe external surface from contact with ground water.

Visual inspection of the internal surfaces of the CRD piping revealed no significant corrosion within the pipes.

Both CRD pipes in FZ-1833 were replaced with uncoated stainless steel piping.

c. To ensure that the conditions and operating experience from this event are maintained during future operations at the plant, the CRD piping is added as having an underground environment to the SLRA and will be managed by the Buried and Underground Piping and Tanks AMP. The SLRA changes due to this operating experience are documented in L-MT-23-031 Enclosure 06b (Reference 1).

2. MNGP replaced the below grade portion of the carbon-steel CRD suction piping and relief valve piping with stainless steel piping. Penetration FZ-1833 has been modified to allow for periodic inspections to check for degradation. A removable 1/4 stainless steel plate anchored to the wall with stainless steel concrete anchors on the Reactor Building inside wall provides access into the penetration. The Reactor Building wall opening is packed with removable Kaowool. The piping is grouted for about 1 foot into the Turbine Building wall. The piping in

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 4 of 10 the Turbine Building is also packed with removable Kaowool. The piping in the vicinity of the 1 seismic gap is uncovered and opened to the underground environment. The design gaps to the stainless steel plate openings are sealed with room temperature vulcanized (RTV) sealant. The entire lengths of stainless steel piping are not coated, which is acceptable as indicated in Table XI.M41-1 of the GALL-SLR. The 8 inch diameter penetration contains both a 3 inch CRD suction piping and 3 inch relief valve pipe, which provides access for inspection. The two pipes are arranged horizontally within the penetration.

3. Actions have been taken to identify other in scope underground piping that may have been inadvertently omitted from the SLRA. The evaluation performed by MNGP as a result of the piping leak includes relevant findings for the extent of condition. The extent of condition looked for similar instances where pipes went between buildings similar to FZ-1833. There are 35 penetrations identified where pipe went between the Reactor Building and Turbine Building. However, only eight of the locations were below grade (931), and therefore have the potential to be exposed to what would be considered an underground environment. Of those below grade penetrations , the penetration associated with the Drywell Equipment Drain Sump Piping to Condenser Drip Tank was the next closest to the ground water level, elevation 914.45. The piping in that penetration was replaced with uncoated stainless steel piping as a precautionary measure.

A sample of the other below grade pipes were inspected using a borescope to check for leaks, wetness, corrosion, and to determine if the pipe was painted or not. Some pipes showed no indication of corrosion. All pipes where corrosion was identified had the extent of the corrosion evaluated. The evaluations determined that the corrosion is not indicative of impending failure over the next cycle or two years, during which time further inspections and evaluation or replacement will be performed. Based on these findings, the Drywell Equipment Drain Sump Piping to Condenser Drip Tank will conservatively be added to the SLRA as managed by the Buried and Underground Piping and Tanks AMP because of its potential to be exposed to moisture from elevated ground water levels. All other piping that run through the 1 seismic gap between the Reactor Building and Turbine Building are managed by the External Surfaces Monitoring of Mechanical Components AMP based on the environment and observed condition of the external surfaces of the sampled piping.

During the extent of condition evaluation, it was also identified that the Off-Gas System had piping that would be considered as having an underground environment. This environment only occurs in one tunnel located at MNGP. Piping and piping components within this tunnel were evaluated to ensure that all components in-scope of SLR were identified. The piping and piping components associated with the underground environment in the Off-Gas System were added to the SLRA to be managed by the Buried and Underground Piping and Tanks AMP as documented in L-MT-23-031 Enclosure 06b (Reference 1).

4. External Coatings:

a. The in-scope underground steel piping in the Off-Gas System is not externally coated in accordance with the preventive actions program element of GALL-SLR Report AMP XI.M41, Table XI.M41-1. This is an exception to the Buried and Underground Piping and Tanks AMP and has been added as shown in this RAI response.

b. The newly installed CRD and Drywell Equipment Drain Sump Piping to Condenser Drip Tank piping that is classified as being in an underground environment is constructed of a

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 5 of 10 stainless steel material that has no requirement for external coatings as shown in Table XI.M41-1 of GALL-SLR.

c. Piping between the Reactor and Turbine Buildings other than the CRD and Drywell Equipment Drain Sump Piping to Condenser Drip Tank piping is not classified as underground based on the definition in Table IX.D of the GALL-SLR (i.e., are not contained in a tunnel or vault where access for inspection is limited and/or are not below grade). The external surfaces of these pipes were evaluated during the extent of condition as adequately managed using the External Surfaces Monitoring of Mechanical Components AMP.

i. GALL-SLR, Element 4 for the External Surfaces Monitoring of Mechanical Components AMP states, Surfaces that are not readily visible during plant operations and refueling outages are inspected when they are made accessible and at such intervals that would ensure the components intended functions are maintained. The expectations of this element are being met with the maintenance notifications to perform periodic inspections described above as part of the evaluation of this issue.

ii. GALL-SLR, Element 2 for the External Surfaces Monitoring of Mechanical Components AMP states that, Depending on material, components may be coated to mitigate corrosion by protecting the external surface of the component from environmental exposure. External coatings are an optional guidance for this AMP in the GALL-SLR and so it is acceptable to not have the piping coated. Because the pipes between these buildings (other than the CRD pipes that are addressed separately above) are not in a soil environment or at an elevation that subjects them to ground-water, the optional guidance from the GALL-SLR to have the piping coated is considered unnecessary.

The SLRA revision included in this RAI response includes changes made in Enclosure 06b, 06c, and 12 of Reference 1 and Enclosures 06a and 06b of Reference 2 (shown in bold black font).

References:

1. L-MT-23-031, Monticello Nuclear Generating Plant, Docket No. 50-263, Renewed Facility Operating License No. DPR-22, Subsequent License Renewal Application Supplement 4 and Responses to Request for Confirmation of Information - Set 1, ML23199A154.

2. L-MT-23-025, Monticello Nuclear Generating Plant, Docket No. 50-263, Renewed Facility Operating License No. DPR-22, Subsequent License Renewal Application Supplement 2, ML23199A154.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 6 of 10 Associated SLRA Revisions:

SLRA Section 3.3.2.1.13 on page 3.3-15 is revised as follows:

Environments The RAD System components are exposed to the following environments:

Air - Dry Air - Indoor Uncontrolled Closed-Cycle Cooling Water Concrete Condensation Treated Water Underground Waste Water Waste Water >140 F Aging Effects Requiring Management The following aging effects associated with the RAD System require management:

Cracking Cumulative Fatigue Damage Flow Blockage Long-Term Loss of Material Loss of Coating or Lining Integrity Loss of Material Loss of Preload Aging Management Programs The following AMPs manage the aging effects for the RAD System components:

Bolting Integrity (B.2.3.10)

Buried and Underground Piping and Tanks (B.2.3.27)

Closed Treated Water Systems (B.2.3.12)

Compressed Air Monitoring (B.2.3.14)

External Surfaces Monitoring of Mechanical Components (B.2.3.23)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.3.24)

Internal Coatings/linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks (B.2.3.28)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 7 of 10 SLRA Section 3.3.2.2.3 on page 3.3-23 is revised as follows:

Plant-specific OE associated with insulated stainless steel components in the auxiliary systems has been evaluated to determine if prolonged exposure to a condensation environment has resulted in cracking due to SCC. Cracking has not been identified as an aging effect at MNGP for insulated stainless steel components for this environment indicating that moisture intrusion into the insulation and leaching of contaminants present in the insulation onto component surfaces, or onto other components below the insulated component, resulting in SCC has not occurred.

Plant-specific OE associated with underground piping that is occasionally wetted in the CRD and RAD systems indicates that corrosion of the carbon steel piping is an aging mechanism that requires management. The carbon steel piping was replaced with stainless steel piping to better mitigate future corrosion. Consistent with the recommendation of GALL-SLR, the Buried and Underground Piping and Tanks AMP will confirm that cracking is not occurring in stainless steel components exposed to an underground environment. Deficiencies will be documented in accordance with the sites 10 CFR Part 50, Appendix B, Section XVI, CAP. The Buried and Underground Piping and Tanks AMP is described in Section B.2.3.27.

SLRA Section 3.3.2.2.4 on page 3.3-25 is revised as follows:

Plant-specific OE associated with insulated stainless steel components in the auxiliary systems has been evaluated to determine if prolonged exposure to a condensation environment has resulted in loss of material due to pitting and crevice corrosion. Loss of material has not been identified as an aging effect at MNGP for insulated stainless steel components for this environment indicating that moisture intrusion into the insulation and leaching of contaminants present in the insulation onto component surfaces, or onto other components below the insulated component, resulting in loss of material has not occurred.

Plant-specific OE associated with underground piping that is occasionally wetted in the CRD and RAD systems indicates that corrosion of the carbon steel piping is an aging mechanism that requires management. The carbon steel piping was replaced with stainless steel piping to better mitigate future corrosion. Consistent with the recommendation of GALL-SLR, the Buried and Underground Piping and Tanks AMP will confirm that loss of material is not occurring in stainless steel components exposed to an underground environment. Deficiencies will be documented in accordance with the sites 10 CFR Part 50, Appendix B, Section XVI, CAP. The Buried and Underground Piping and Tanks AMP is described in Section B.2.3.27.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 8 of 10 SRLA Table 3.3.2-13 on page 3.3-252 is revised as follows:

Table 3.3.213: Radwaste Solid and Liquid - Summary of Aging Management Evaluation Aging Effect Aging Component Intended Material Environment Requiring Management NUREG2191 Item Table 1 Item Notes Type Function Management Program Piping, Piping Leakage Stainless Underground Cracking Buried and VII.I.A-714b 3.3.1-146 B Components Boundary Steel (External) Underground Piping and Tanks (B.2.3.27)

Piping, Piping Leakage Stainless Underground Loss of Buried and VII.I.A-775b 3.3.1-246 B Components Boundary Steel (External) Material Underground Piping and Tanks (B.2.3.27)

SLRA Table A-3, Commitment 30 on page A-84 is revised as follows:

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

No later than 6 months prior 30 Buried and XI.M41 t) Ensure that new and replacement underground components shall to the SPEO, or no later than Underground Piping meet the requirements of Table 1 of NACE SP0169-2007 or the last refueling outage prior and Tanks Section 3.4 of NACE RP0285-2002 for coatings to the SPEO (A.2.2.27)

Implement the AMP and start 10-year interval inspections no earlier than 10 years prior to the SPEO.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 9 of 10 Section B.2.3.27 on page B-199 is being revised as follows:

NUREG-2191 Consistency The MNGP Buried and Underground Piping and Tanks AMP, with enhancements, will be consistent with one two exceptions, to the 10 elements of NUREG-2191,Section XI.M41, Buried and Underground Piping and Tank.

Exceptions to NUREG2191 New and replacement backfill is to be consistent with SP0169-2007 Section 5.2.3 or NACE RP0285-2002. The maximum allowable backfill size per ASTM D448-08 (size number 67) is one inch.

Existing backfill for buried components at MNGP was installed per site design specifications. The general requirement for earthwork material is that materials containing brush, roots, peat, sod, or other organic, perishable or deleterious matter, snow, ice, or frozen soil is not used for backfilling. Structural backfill is well graded, sound, dense and durable material. No more than 10 percent by weight shall pass the No.

200 sieve. The maximum size of structural backfill is two inches in confined areas where hand tamping is required and four inches in other areas. This is an exception to what is required by SP0169-2007 Section 5.2.3 or NACE RP0285-2002.

This exception is acceptable because operating experience demonstrates that surveys/tests are capable of detecting and identifying degraded conditions in backfill.

These degraded conditions are entered into the CAP and then addressed. If the backfill does not meet acceptance criteria, the degraded condition is evaluated or repaired.

MNGP has been exposed to severe winter conditions for many years, and has, to date, shown no signs of significant freeze-thaw damage. An enhancement has been added to ensure compliance with NACE SP01692007 Section 5.2.3 or NACE RP02852002 Section 3.6 for new and replacement backfill.

New and replacement coatings for underground components are to be consistent with Table 1 of SP0169-2007 or Section 3.4 of NACE RP0285-2002.

Existing coatings for underground components at MNGP were installed per site design specifications. Site design specifications did not require coatings on underground components. This is an exception to what is required by Table 1 of SP0169-2007 or Section 3.4 of NACE RP0285-2002.

This exception is acceptable because operating experience demonstrates that the lack of moisture intrusion does not lead to accelerated degradation of the uncoated underground components at MNGP. An enhancement has been added to ensure compliance with Table 1 of NACE SP01692007 or Section 3.4 of NACE RP02852002 for new and replacement underground piping.

Enhancements The MNGP Buried and Underground Piping and Tanks AMP will be enhanced as follows, for alignment with NUREG-2191. The enhancements are to be implemented no later than 6 months prior to entering the SPEO.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 1 Page 10 of 10 Element Affected Enhancement

2. Preventive Actions Update MNGP BUPT AMP procedures as appropriate:

State that new and replacement backfill shall meet the requirements of NACE SP0169-2007 Section 5.2.3 or NACE RP0285-2002 Section 3.6.

Refurbish the Cathodic Protection System at least 5 years prior to the SPEO and perform effectiveness reviews in accordance with Table XI.M41-2 in NUREG-2191,Section XI.M41. The cathodic protection system for buried piping shall also include a limiting critical potential of -1,200 mV to prevent overprotection.

State that new and replacement underground components shall meet the requirements of Table 1 of NACE SP0169-2007 or Section 3.4 of NACE RP0285-2002 for coatings.

2 RAI B.2.3.16-1

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 2 Page 1 of 4 RAI B.2.3.16-1 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 in the requests for additional information.

Background:

The implementation schedule for the Fire Water System program in Table XI-01 of NUREG-2191, Volume 2, Generic Aging Lessons Learned for Subsequent License Renewal (GALLSLR) Report (Agencywide Documents Access and Management System (ADAMS)

Accession No. ML17187A204), states, Program is implemented and inspections or tests begin 5 years before the subsequent period of extended operation [SPEO]. Inspections or tests that are to be completed prior to the subsequent period of extended operation are completed 6 months prior to the subsequent period of extended operation or no later than the last refueling outage prior to the subsequent period of extended operation.

The Implementation Schedule for the Fire Water System (No. 19) in Table A-3, List of SLR Commitments and Implementation Schedule, in Appendix A of the Subsequent License Renewal Application (SLRA) states the following:

No later than 6 months prior to the SPEO, or no later than the last refueling outage prior to the SPEO Implement the AMP [aging management program] and start the pre SPEO inspections and tests no earlier than 5 years prior to the SPEO.

Section B.2.3.16, Fire Water System, in SLRA Appendix B states, The enhancements are to be implemented no later than 6 months prior to entering the SPEO. This AMP is to be implemented and its pre-SPEO inspections and tests begin no earlier than 5 years prior to the SPEO. The pre-SPEO inspections and tests are to be completed no later than six months prior to entering the SPEO or no later than the last refueling outage prior to the SPEO.

During the audit of the Fire Water System AMP, the applicant stated that the program enhancements will be implemented no later than 6 months prior to the SPEO or no later than the last refueling outage prior to the SPEO, and that pre-SPEO inspections and tests will begin no earlier than 5 years prior to the SPEO and will be completed no later than 6 months prior to the SPEO or no later than the last refueling outage prior to the SPEO.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 2 Page 2 of 4 Issue:

The SLRA does not appear to clearly reflect the intended implementation schedule. Also, the Fire Water System AMP implementation schedule in Table A-3 in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B appear to be inconsistent. Table A-3 in SLRA Appendix A doesnt state that the pre-SPEO inspections and tests are to be completed no later than 6 months prior to the SPEO or no later than the last refueling outage. Section B.2.3.16 in SLRA Appendix B does not include or no later than the last refueling outage to the SPEO for the implementation of the enhancements.

In addition, it is unclear whether the program will be implemented no later than 6 months prior to the SPEO or no later than the last refueling outage prior to the SPEO, or 5 years prior to the SPEO consistent with the implementation schedule in the GALL-SLR Report. Implementing the program 6 months prior to the SPEO or no later than the last refueling outage prior to the SPEO is not consistent with the implementation schedule in the GALL-SLR Report, which states that the program is implemented 5 years before the SPEO. In addition, beginning inspections before implementing the program is not consistent with the implementation schedule in the GALL-SLR Report, which states the program be implemented and inspections or tests begin 5 years before the SPEO. It is unclear to the NRC staff how inspections and tests will be adequately managed (i.e., performance, acceptance criteria, corrective actions, etc.) as part of the Fire Water System program without the inspection and test requirements being incorporated into the Fire Water System program documentation.

Request:

Please discuss the differences in the implementation schedule for the Fire Water System program stated in Table A-3 in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B. In addition, discuss the basis for the implementation schedule, including how inspections and tests would be adequately managed prior to the Fire Water System program being implemented.

Alternatively, revise the implementation schedule for the Fire Water System AMP in Table A-3 in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B to be consistent and to be consistent with the implementation schedule in the GALL-SLR Report.

Response to RAI B.2.3.16-1:

NUREG-2191 (GALL-SLR), Table XI-01 (FSAR Supplement Summaries for GALL-SLR Report Chapter XI AMPs), for AMP XI.M27 states in part that, Inspections or tests that are to be completed prior to the subsequent period of extended operation [SPEO] are completed 6 months prior to the subsequent period of extended operation or no later than the last refueling outage prior to the subsequent period of extended operation. SLRA Table A-3 (List of SLR Commitments and Implementation Schedule), Commitment 19 states in part that the implementation schedule is, No later than 6 months prior to the SPEO, or no later than the last refueling outage prior to the SPEO. SLRA Section B.2.3.16 Enhancements Subsection states, The pre-SPEO inspections and tests are to be completed no later than six months prior to entering the SPEO or no later than the last refueling outage prior to the SPEO. These three sentences were intended to have the same meaning, and do not have any practical difference in interpretation.

GALL-SLR for AMP XI.M27 also states, Program is implemented and inspections or tests begin 5 years before the subsequent period of extended operation. SLRA Table A-3, Commitment 19

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 2 Page 3 of 4 also states, Implement the AMP and start the pre-SPEO inspections and tests no earlier than 5 years prior to the SPEO. In the SLRA, Section B.2.3.16, Subsection Enhancements, states This AMP is to be implemented and its pre-SPEO inspections and tests begin no earlier than 5 years prior to the SPEO.

Although the wording of these portions of the implementation schedule commitments are similar, it is recognized that there could be a difference in the interpretation of the schedule commitment in the GALL-SLR from the interpretation intended in the sections of the SLRA. The difference is that the SLRA commits to only performing the tests and inspections that are identified in Chapter XI.M27 of the GALL-SLR as required to be performed prior to entering the SPEO and to begin implementing the program no earlier than 5 years prior to entering the SPEO. Whereas the schedule in Table XI.01 of the GALL-SLR could be interpreted as requiring the GALL-SLR AMP XI.M27 to be implemented in its entirety at 5 years prior to the SPEO, and all tests and inspections associated with the AMP (regardless of whether they are identified as pre-SPEO or not) are to begin at that point of 5 years prior to entering the SPEO. This interpretation would be inconsistent with the guidance contained in Chapter XI.M27 of the GALL-SLR. Specifically, Element 4 of AMP XI.M27 explicitly identifies the tests and inspections that are required to be performed prior to entering the SPEO and which ones are only required to be performed upon entering the SPEO at the frequency specified for the test or inspection. This Element states that, The inspections and tests ... occur at the intervals specified in NFPA 25, or as modified in Table XI.M27-1. The Element does not indicate that the test and inspections associated with NFPA 25 are required to be performed prior to entering the SPEO. The wording in Table XI.01 is also considerably different from the implementation schedule that was part of the guidance in LR-ISG-2012-02, where the last change to the implementation schedule for the XI.M27 program from GALL was made and from which the GALL-SLR program and implementation schedule are based (any changes and their bases that should be identified in NUREG-2221).

Because of this inconsistency between two parts of the GALL-SLR (the guidance in Element 4 of XI.M27 and the schedule in Table XI.01), MNGP reviewed other SLRAs in the industry that have been approved by the NRC to determine what the correct interpretation should be. It was found that this inconsistency exists in the SLRA safety evaluation reports (SERs) to date as well.

The NRC-approved implementation schedule for Turkey Point (PTN) (Reference 1) and Surry (Reference 2) match the schedule shown in Table XI.01, but the NRC-approved implementation schedule for Peach Bottom (Reference 3) matches the interpretation that is indicated by MNGP in the SLRA (Reference 4). However, the PTN SER (Reference 1) in Section 3.0.3.2.18, UFSAR Supplement Subsection, indicates that, The staff also noted that the applicant committed to implement the enhancements to the program no later than 6 months prior to the subsequent period of extended operation. This sentence implies that the acceptance criterion for implementing enhancements (such as the additional tests and inspections of NFPA 25) is completed no later than 6 months prior to the SPEO. NUREG-2221 was also reviewed to attempt to resolve the discrepancy between the two parts of the GALL-SLR and also with the difference in wording from LR-ISG-2012-02. The review of NUREG-2221 (specifically pages 2-316 through 2-323 and page 3-6) did not identify a change or technical basis for the change to the schedule for implementation or identify such a change within Element 4 of XI.M27 and Table XI.M27-1.

The NRC staff appears to have recognized this issue when developing the draft revision to the GALL-SLR (Reference 5). On page XI-351, the guidance has been revised to state, The program is implemented and inspections or tests begin within the 5-year period before the subsequent period of extended operation. This change is interpreted as having the same

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 2 Page 4 of 4 intended meaning with no practical difference to the implementation schedule identified for the Fire Water Systems AMP in the MNGP SLRA (Reference 4).

For clarity, the MNGP implementation schedule for the Fire Water Systems AMP for SLR is to implement the program (as described in the SLRA and as amended by all applicable supplements, RAI responses, and RCI responses) no earlier than 5 years prior to the SPEO and no later than 6 months prior to the SPEO. The inspections or tests associated with the Fire Water Systems AMP for SLR that are required to be completed prior to the SPEO will be performed no earlier than 5 years prior to the SPEO and either no later than 6 months prior to the SPEO, or no later than the last refueling outage prior to the SPEO. Any test or inspection that is performed prior to the SPEO and that is intended to be credited to meet commitments or enhancements for the AMP XI.M27 for SLR will be performed commensurate with the requirements and guidance described in the SLRA and as amended by all applicable supplements, RAI responses, and RCI responses for all elements of the AMP.

References:

1. Florida Power & Light Company, Docket Nos. 50-250 and 50-251, Safety Evaluation Report Related to the Subsequent License Renewal of Turkey Point Generating, Units 3 and 4, Office of Nuclear Reactor Regulation, December 2019, ML19191A057

2. Virginia Electric and Power Company, Docket Nos. 50-280 and 50-281, Safety Evaluation Report Related to the Subsequent License Renewal of Surry Power Station, Units 1 and 2, Office of Nuclear Reactor Regulation, March 2020, ML20052F523

3. Exelon Generation Company, LLC, Docket Nos. 50-277 and 50-278, Safety Evaluation Report Related to the Subsequent License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3, Office of Nuclear Reactor Regulation, February 2020, ML20044D902

4. L-MT-23-001, Monticello Nuclear Generating Plant, Docket 50-263, Renewed Facility Operating License No. DPR-22, Monticello Nuclear Generating Plant Unit 1 Subsequent License Renewal Application, January 09, 2023, ML23009A354

5. NUREG-2191, Volume 2, Draft Revision 1, Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report, Draft Report for Comment, July 2023, ML23180A188 Associated SLRA Revisions:

No SLRA changes have been identified as a result of this response.

3 RAI B.2.3.16-2

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 3 Page 1 of 3 RAI B.2.3.16-2 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 in the requests for additional information.

Background:

The second table in the Enhancements subsection in Section B.2.3.16 in SLRA Appendix B provides additional detail on the required enhancements based on Table XI.M27-1, Fire Water System Inspection and Testing Recommendations, in the Fire Water System AMP (XI.M27) in Volume 2 of NUREG-2191. However, the associated enhancement to the Detection of Aging Effects program element in Table A-3, List of SLR Commitments and Implementation Schedule, in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B do not refer to the table for additional detail on the required enhancements.

In addition, it is unclear why some enhancements are identified as an enhancement to a particular program element in Table A-3 in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B while other required enhancements are identified in the table that provides additional detail on the required enhancements based on Table XI.M27-1 in GALL-SLR Report AMP XI.M27 in Section B.2.3.16 in SLRA Appendix B. For example, the GALL-SLR Report AMP XI.M27, states that portions of water-based fire protection system components that have been wetted but are normally dry are subject to augmented testing and inspection beyond Table XI.M27-1. The augmented tests and inspections include:

In each 5-year interval, beginning 5 years prior to the subsequent period of extended operation, either conduct a flow test or flush sufficient to detect potential flow blockage, or conduct a visual inspection of 100 percent of the internal surface of piping segments that cannot be drained or piping segments that allow water to collect.

In each 5-year interval of the subsequent period of extended operation, 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect is subject to volumetric wall thickness inspections. Measurement points are obtained to the extent that each potential degraded condition can be identified (e.g.,

general corrosion, MIC). The 20 percent of piping that is inspected in each 5-year interval is in different locations than previously inspected piping.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 3 Page 2 of 3 If the results of a 100-percent internal visual inspection are acceptable, and the segment is not subsequently wetted, no further augmented tests or inspections are necessary.

Table A-3 in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B include 2) and 3) above but do not include 1) above. However, the table in Section B.2.3.16 of SLRA Appendix B that provides additional detail on the required enhancements based on GALL-SLR Report AMP XI.M27, Table XI.M27-1, includes 1), 2), and 3) above.

Issue:

Because the table in Section B.2.3.16 of SLRA Appendix B that provides additional detail on the required enhancements based on Table XI.M27-1 in GALL-SLR Report AMP XI.M27 is not referenced in the associated enhancement to the Detection of Aging Effects program element in Table A-3 in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B, it may be hard to verify implementation of all of the required enhancements.

Request:

Please discuss why some enhancements are identified as an enhancement to a particular program element in Table A-3 in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B while other required enhancements are identified in the table that provides additional detail on the required enhancements based on Table XI.M27-1 in GALL-SLR Report AMP XI.M27 in Section B.2.3.16 in SLRA Appendix B. Alternatively, revise the associated enhancement to the Detection of Aging Effects program element in Table A-3 in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B to clearly reference the table that provides additional detail on the required enhancements.

Response to RAI B.2.3.16-2:

SLRA Table A-3 and the associated enhancements to the Detection of Aging Effects program elements in SLRA Section B.2.3.16 do not have the same level of detail provided in the additional detail on enhancements based on NUREG-2191, Table XI.M27-1. A pointer has been added to Table A-3 Commitment 19 to provide a cross-reference between the associated required enhancements in SLRA Section B.2.3.16 based on NUREG-2191, Table XI.M27-1.

References:

None

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 3 Page 3 of 3 Associated SLRA Revisions:

SLRA Table A-3, Commitment 19 on page A-65 is revised as follows:

No. Aging Management NUREG-2191 Commitment Implementation Schedule Program or Section Activity (Section) 19 Fire Water System XI.M27 The Fire Water System AMP is an existing program that will be enhanced as No later than 6 months prior (A.2.2.16) stated in SLRA Section B.2.3.16, and in accordance with associated to the SPEO, or no later than additional details provided in NUREG-2191, Table XI.M27-1, which are the last refueling outage prior based on NFPA 25, 2011 Edition, as well as to: to the SPEO a) Clarify that when visual inspections are used to detect loss of Implement the AMP and start material, the inspection technique must be capable of detecting the preSPEO inspections surface irregularities that could indicate an unexpected level of and tests no earlier than 5 degradation due to corrosion and corrosion product years prior to the SPEO.

deposition. Where such irregularities are detected, followup volumetric wall thickness examinations are performed.

b) Perform volumetric wall thickness inspections on the portions of the waterbased fire protection system components that are periodically subjected to flow but are normally dry as follows: In each 5year 4

RAI B.2.3.16-3

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 4 Page 1 of 3 RAI B.2.3.16-3 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 in the requests for additional information.

Background:

SLRA Supplement 2 dated June 26, 2023 (ML23177A218), revised Section A.2.2.16 in SLRA Appendix A and Section B.2.3.16 in SLRA Appendix B to address Footnote 7 to Table XI.M27-1 in GALL-SLR Report AMP XI.M27 associated with sprinkler testing. Specifically, the SLRA sections were revised to indicate that the wet pipe sprinklers are not exposed to harsh environments.

Issue:

SLRA Supplement 2 did not revise the table that provides additional detail on the required enhancements based on Table XI.M27-1 in GALL-SLR Report AMP XI.M27 in Section B.2.3.16 in SLRA Appendix B. This table includes a required enhancement related to Section 5.3.1.1.2 of NFPA Standard 25 concerning sprinklers subject to harsh environments.

Request:

Please discuss whether an enhancement related to Section 5.3.1.1.2 of NFPA Standard 25 is needed given that the SLRA was revised in Supplement 2 to indicate that wet pipe sprinklers are not exposed to harsh environments.

Response to RAI B.2.3.16-3:

Based on the changes made in Enclosure 23b of Reference 1 and for consistency with other NFPA 25 related guidance that is not applicable to MNGP, the table in SLRA Section B.2.3.16 that provides additional detail on the required enhancement based on NUREG-2191 Table XI.M27-1, is revised to indicate that NFPA 25 Section 5.3.1.1.2 is not applicable.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 4 Page 2 of 3

References:

1. L-MT-23-025, Monticello Nuclear Generating Plant, Docket No. 50-263, Renewed Facility Operating License No. DPR-22, Subsequent License Renewal Application Supplement 2, ML23177A218.

Associated SLRA Revisions:

SLRA Section B.2.3.16, Required Enhancements paragraph 5.3.1.1.2* on page B-123 is revised as follows:

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 4 Page 3 of 3 NFPA 25 Description Required Enhancements Section 5.3.1.1.1: Where sprinklers have been in service for 50 years, they shall be replaced or representative samples from one or more sample areas shall be tested.

5.3.1.1.1.1: Test procedures shall be repeated at 10-year intervals.

5.3.1.1.1.2: [Not applicable since MNGP does not utilize sprinklers manufactured prior to 1920.]

5.3.1.1.1.3*: Sprinklers manufactured using fast-response elements that have been in service for 20 years shall be replaced, or representative samples shall be tested and then retested at 10-year intervals.

5.3.1.1.1.4*: Representative samples of solder-type sprinklers with a temperature classification of extra high [325°F (163°C)] or greater that are exposed to semi-continuous to continuous maximum allowable ambient temperature conditions shall be tested at 5-year intervals.

5.3.1.1.1.5: Where sprinklers have been in service for 75 years, they shall be replaced or representative samples from one or more sample areas shall be submitted to a recognized testing laboratory acceptable to the authority having jurisdiction for field service testing and repeated at 5-year intervals.

5.3.1.1.1.6*: Dry sprinklers that have been in service for 10 years shall be replaced or representative samples shall be tested and then retested at 10-year intervals.

5.3.1.1.2*: Where sprinklers are subjected to harsh environments, including corrosive atmospheres and corrosive water supplies, on a 5-year basis, either sprinklers shall be replaced, or representative sprinkler samples shall be tested.

[Not applicable since the MNGP wet pipe sprinkler systems are not exposed to any harsh or corrosive environments as defined in NFPA 25 Section 5.3.1.1.2 and Section A.5.3.1.1.2 of Annex A of NFPA 25. The wet pipe sprinklers are exposed only to an external environment of plant indoor air and internal environments of raw water and condensation.]

5.3.1.1.3: Where historical data indicate, longer intervals between testing shall be permitted.

5 RAI B.2.3.17-1

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 1 of 15 RAI B.2.3.17-1 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 regarding the matters described in the requests for additional information.

Background:

Subsequent License Renewal Application (SLRA) (Agencywide Documents Access and Management System (ADAMS) Accession No. ML23009A354) Section 3.3.2.2.9 addresses loss of material and cracking of stainless-steel components exposed to concrete. The discussion notes that the stainless-steel standby liquid control tank is the only component where this issue applies and states that past operating experience identified cracking of the tank bottom. The discussion also notes that the issue has been corrected and that the One-Time Inspection program will be used to confirm that the tank bottom has not experienced further cracking.

SLRA Table 3.3.2-17 includes a corresponding discussion for item 3.3.1-230 that cites generic Note E and plant-specific note 3, stating that, although the GALL-SLR Report recommends XI.M29, Outdoor and Large Atmospheric Metallic Storage Tanks program for this item, the One-Time Inspection program will be used instead. The plant-specific note also states that the tanks bottom plate has been replaced, and an epoxy coating was applied to the concrete tank pedestal to prevent future cracking due to chloride exposure from the concrete. The associated discussion in NUREG-2192, Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR) (ML17188A158) Section 3.3.2.2.9 notes that for stainless-steel components, stress corrosion cracking is not considered to be an applicable aging effect as long as the components are not potentially exposed to groundwater.

For cracking of stainless-steel tanks exposed to concrete, GALL-SLR Report Table XI.M29-1, Tank Inspection Recommendations prescribes volumetric inspections during each 10-year period, starting 10 years prior to the subsequent period of extended operation. In addition, as it relates to the use of a coating to prevent exposure of the stainless-steel tank to chlorides from the concrete, Table XI.M29-1 refers to SRP-SLR Section 3.3.2.2.3, Cracking Due to Stress Corrosion Cracking in Stainless Steel Alloys. The associated discussion in SRP-SLR Section 3.3.3.2.3 addresses the use of a barrier coating to isolate components from an aggressive environment by stating, the reviewer verifies that the barrier coating is impermeable to the applicable environment and verifies that loss of coating integrity is being managed for the associated components with a program equivalent to the GALL-SLR Report AMP XI.M42, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 2 of 15 With respect to the proposal for using the One-Time Inspection program, the GALL-SLR Report (XI.M32) states that the program cannot be used for components subjected to known age related degradation mechanisms based on a review of plant-specific operating experience for the prior operating period. In those cases, periodic inspections are proposed. In addition, the One-Time Inspection program notes that the inspected components need to attain sufficient age such that the aging effects with long incubation periods can be identified by the inspection.

The apparent cause evaluation, performed as part of the associated corrective action document (AR 01223696), states that the insulation and the grout are possible sources of the chlorides that caused the stress corrosion cracking of the stainless-steel standby liquid control tank. It also states that chlorides were present on the aluminum lagging on the tank and in the grout on which the tank rests. In addition, it states that water spillage would transport chlorides from the lagging, tank insulation, or grout to the surface of the stainless-steel tank. The extent of condition evaluation for AR 01223696 notes that high chloride concentrations can be due to the combined effects of moisture wicking under the bottom of the tank from spillage or condensation and repeated wet/dry conditions.

Issue:

Based on previous plant-specific operating experience, sufficient bases have not been provided to demonstrate that the One-Time Inspection program can be substituted for the periodic inspections prescribed by the Outdoor and Large Atmospheric Metallic Storage Tanks program.

Although the source of chlorides from the concrete or grout has been addressed, it is not clear whether there are other sources of chlorides (e.g., tank insulation) that could lead to future stress corrosion cracking of the stainless-steel tank base.

In addition, the use of a barrier coating to isolate a component from an aggressive environment includes aspects that do not appear to be addressed in the SLRA. As discussed in the background, the impermeability of the coating to the applicable environment and the associated aging management activities to address loss of coating integrity are to be addressed. The staff notes that Monticellos new (currently proposed) Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program is consistent with the GALL-SLR Report XI.M42, as modified by SLR-ISG-2021-02-Mechanical. The proposed program addresses internal coatings exposed only to water environments and does not include coatings exposed to air or condensation. The associated aging management review items in the SLRA only address internal coatings on carbon steel or gray cast iron components and do not include concrete with an external coating.

Although the guidance in SRP-SLR Section 3.3.2.2.9 states that stress corrosion cracking of stainless-steel components is not an applicable aging effect, as long as the components are not potentially exposed to groundwater, the operating experience at Monticello indicates otherwise.

The application included a discussion about the standby liquid control tank when addressing this item even though the associated stainless-steel to concrete interface would not be considered exposed to groundwater. Based on the plant-specific operating experience, stress corrosion cracking of stainless steel exposed to concrete may be an applicable aging effect in locations where the interface is exposed to operational leakage.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 3 of 15 Request:

For the aging management of the stainless-steel standby liquid control tank proposed in SLRA Table 3.3.1-17, item 3.3.1-230, provide information to justify the substitution of the One-Time Inspection program for the Outdoor and Large Atmospheric Metallic Storage Tanks program.

Specifically address whether all of the potential sources of the chlorides attributed to the cause of the observed stress corrosion cracking have been eliminated through the use of an epoxy coating on the tanks concrete pad. Include information about statements in corrective action documents that note water spillage can transport chlorides from the lagging and tank insulation to the surface of the stainless-steel tanks. Provided that the source of the chlorides has been eliminated, also include information concerning the proposed timing of the one-time inspection, given that the tank bottom has been replaced sometime in the past.

In addition, provide information about how the loss of coating integrity for the previously applied epoxy coating on the concrete pedestal of the standby liquid control tank will be managed during the subsequent period of extended operation. Include any changes to the currently proposed Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program along with appropriate aging management review items. Specifically address whether loss of coating integrity needs to be considered for the inaccessible portions of the coating underneath the tank.

Regarding SLRA Section 3.3.2.2.9, provide information to confirm that the extent of condition reviews conducted for the standby liquid control tank provide reasonable assurance that stress corrosion cracking is not an applicable aging effect for other stainless steel components exposed to concrete with similar operational leakage.

Response to RAI B.2.3.17-1:

The Outdoor and Large Atmospheric Metallic Storage Tanks (OLAMST) AMP is not suitable for the Standby Liquid Control (SLC) Tank because the SLC Tank is (a) not an outdoor tank, (b) not an indoor tank with a capacity greater than 100,000 gallons, and (c) not an indoor tank that sits on concrete (it now sits on epoxy, though the AMR table entries will indicate the environment as concrete to conservatively capture the aging effects for the tank bottom). As such, it is not exposed to the harsh environments that drive many of the aging effects and subsequent management activities identified in the OLAMST AMP. Tank Inspection Recommendations presented in GALL-SLR Table XI.M29-1 identify degradation of inside surfaces for stainless steel tanks in an air, and condensation environment as:

1) visual for loss of material each refueling outage interval or one-time inspection, see SRP-SLR Sections 3.2.2.2.2, 3.3.2.2.4, or 3.4.2.2.3., and

2) surface for cracking each 10-year period starting 10 years before the subsequent period of extended operation, or one-time inspection, see SRP-SLR Sections 3.2.2.2.4, 3.3.2.2.3, or 3.4.2.2.2.

In place of the programs suggested for use in SRP-SLR Sections 3.3.2.2.3 and 3.3.2.2.4, MNGP intends to manage the cracking and loss of material aging effects on the external portions of the stainless steel SLC Tank using the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (ISI) AMP. The ASME Section XI Standby Liquid Control Suction Piping System Leakage Test is performed every two years. The inspection will be part of the ISI AMP for MNGP, and will provide reasonable assurance that any aging effects for the

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 4 of 15 SLC tank are managed before there is a potential loss of its pressure boundary intended function. This change will be incorporated into the SLRA as indicated in this RAI response.

Use of the One-Time Inspection (OTI) AMP is appropriate for the internal surfaces of the SLC Tank based on the guidance in SRP-SLR Sections 3.3.2.2.3 and 3.3.2.2.4. This is because the cracking and loss of material identified by the plant-specific operating experience (OE) was determined to be a result of exposure to chlorides leached out of the tanks insulation or concrete pedestal due to moisture on the external surface of the tank only, and because the internal surfaces of the SLC Tank have neither exposure to this source of chlorides nor OE indicating that cracking on these surfaces is a problem. Because the internal OTI will look for indications of aging effects on both the tank bottom that was replaced in 2011 and on the sides of the tank that were not replaced but were still exposed to chlorides from the water spillage, it is proposed that the OTI be performed in the period that occurs between 5 years prior to entering the SPEO and 6 months prior to entering the SPEO as described in the guidance from GALL-SLR Table XI.M29-1, note 2. For this OTI, an ultrasonic test or similar method for performing a volumetric inspection of the tank material will be used to detect aging effects on both the internal and external sides of the tank as described in the guidance from GALL-SLR Table XI.M29-1, note 3. This will provide reasonable assurance that any aging effects that occur to the tank sides or bottom would be detected prior to a loss of intended function. This information is added to the further evaluation in Section 3.3.2.2.9 of the SLRA.

Coating integrity will not be managed during the SPEO. The epoxy coating is an additional defense in depth but will not be credited for prevention of cracking or loss of material to the bottom of the SLC Tank. Instead, MNGP will manage the cracking and loss of material aging effects using a combination of the ISI and OTI AMPs as detailed in the discussion above.

MNGP Engineering evaluated the Extent of Condition for transgranular stress corrosion cracking in stainless steel tanks, piping, and vessels in contact with grout or concrete in the SLC Tank Condition Report. The latest SRLA document was also reviewed for any susceptible components. No additional stainless steel components were determined to be in contact with concrete. A review of plant OE for the key words insulation and steel was performed. No additional instances indicating that wetted insulation resulted in degradation to insulated piping, piping components, tanks, or valve bodies constructed of stainless steel. OE for condensation between the tank and insulation of the carbon steel condensate storage tank was reviewed as well for extent of condition and applicability to this issue. Based on this review, it has been confirmed that the extent of condition reviews conducted for the SLC Tank provides reasonable assurance that stress corrosion cracking is not an applicable aging effect for other stainless steel components exposed to concrete with similar operational leakage.

Black bold font information in revisions being made to SLRA Sections 3.3.2.2.3 and 3.3.2.2.4 represents changes made in Attachment 1, Enclosure 06b of Supplement 4 (Reference 1).

References:

1. L-MT-23-031, Monticello Nuclear Generating Plant, Docket No. 50-263, Renewed Facility Operating License No. DPR-22, Subsequent License Renewal Application Supplement 4 and Responses to Request for Confirmation of Information - Set 1, ML23199A154.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 5 of 15 Associated SLRA Revisions:

SLRA Section 3.3.2.1.17 on page 3.3-19 and 3.3-20 is revised as follows:

Aging Management Programs The following AMPs manage the aging effects for the SLC System components:

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1)

Bolting Integrity (B.2.3.10)

Compressed Air Monitoring (B.2.3.14)

External Surfaces Monitoring of Mechanical Components (B.2.3.23)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.3.24)

Internal Coatings/Linings for InScope Piping, Piping Components, Heat Exchangers, and Tanks (B.2.3.28)

OneTime Inspection (B.2.3.20)

Water Chemistry (B.2.3.2)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 6 of 15 SLRA Section 3.3.2.2.3 on page 3.3-23 is revised as follows:

Ambient air at MNGP is not subject to a marine atmosphere. MNGP is located in the vicinity of a major road that is routinely salted for snow and ice. A review of the over 69,000 ARs created during the 01/01/2010 to 07/29/2021 period was performed to determine if the proximity to the salted road has resulted in any plant-specific OE for cracking of the susceptible materials to chlorides in an air environment. The results of this review show that the ambient air environments do not contain sufficient halides (e.g., chlorides) in the presence of moisture to result in SCC. As such, stainless steel components exposed to air or condensation in the auxiliary systems are not susceptible to cracking due to SCC.

Plant-specific OE associated with insulated stainless steel components in the auxiliary systems has been evaluated to determine if prolonged exposure to a condensation environment has resulted in cracking due to SCC. Cracking has not been identified as an aging effect at MNGP for insulated stainless steel components for this environment indicating that moisture intrusion into the insulation and leaching of contaminants present in the insulation onto component surfaces, or onto other components below the insulated component, resulting in SCC has not occurred.

Plant-specific OE associated with underground piping that is occasionally wetted in the CRD system indicates that corrosion of the carbon steel piping is an aging mechanism that requires management. The carbon steel piping was replaced with stainless steel piping to better mitigate future corrosion.

Consistent with the recommendation of GALL-SLR, the Buried and Underground Piping and Tanks AMP will confirm that cracking is not occurring in stainless steel components exposed to an underground environment.

Deficiencies will be documented in accordance with the sites 10 CFR Part 50, Appendix B, Section XVI, CAP. The Buried and Underground Piping and Tanks AMP is described in Section B.2.3.27.

Consistent with the recommendation of GALL-SLR, the One-Time Inspection AMP will confirm that cracking is not occurring in stainless steel components exposed to air indoor uncontrolled, air outdoor, and condensation, and, insulated stainless steel components exposed to condensation. Deficiencies will be documented in accordance with the sites 10 CFR Part 50, Appendix B, Section XVI, CAP. The One-Time Inspection AMP is described in Section B.2.3.20.

The SLC tank has the potential for cracking of its stainless steel. The One-Time Inspection (B.2.3.20) and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1) AMPs will be used to manage the cracking aging effect. An internal OTI will look for indications of aging effects on both the tank bottom and on the sides of the tank. For this OTI, an ultrasonic test or similar method for performing a volumetric inspection of the tank material will be used to detect aging effects on both the internal and external sides of the tank as described in the guidance from GALL-SLR Table XI.M29-1, note 3. This will provide reasonable assurance that any aging effects that occur to the tank sides or bottom would be detected prior to a loss of intended function.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 7 of 15 SLRA Section 3.3.2.2.4 on page 3.3-25 is revised as follows:

Ambient air at MNGP is not subject to a marine atmosphere. MNGP is located in the vicinity of a major road that is routinely salted for snow and ice. A review of the over 69,000 ARs created during the 01/01/2010 to 07/29/2021 period was performed to determine if the proximity to the salted road has resulted in any plant-specific OE for cracking of the susceptible materials to chlorides in an air environment. The results of this review show that the ambient air environments do not contain sufficient halides (e.g., chlorides) in the presence of moisture to result in loss of material. As such, stainless steel components exposed to air or condensation in the auxiliary systems are not susceptible to loss of material.

Plant-specific OE associated with insulated stainless steel components in the auxiliary systems has been evaluated to determine if prolonged exposure to a condensation environment has resulted in loss of material due to pitting and crevice corrosion.

Loss of material has not been identified as an aging effect at MNGP for insulated stainless steel components for this environment indicating that moisture intrusion into the insulation and leaching of contaminants present in the insulation onto component surfaces, or onto other components below the insulated component, resulting in loss of material has not occurred.

Plant-specific OE associated with underground piping that is occasionally wetted in the CRD system indicates that corrosion of the carbon steel piping is an aging mechanism that requires management. The carbon steel piping was replaced with stainless steel piping to better mitigate future corrosion.

Consistent with the recommendation of GALL-SLR, the Buried and Underground Piping and Tanks AMP will confirm that loss of material is not occurring in stainless steel components exposed to an underground environment. Deficiencies will be documented in accordance with the sites 10 CFR Part 50, Appendix B, Section XVI, CAP. The Buried and Underground Piping and Tanks AMP is described in Section B.2.3.27.

Consistent with the recommendation of GALL-SLR, the One-Time Inspection AMP will confirm that loss of material is not occurring in stainless steel components exposed to air indoor uncontrolled, air outdoor, and condensation, and insulated stainless steel components exposed to condensation. Deficiencies will be documented in accordance with the sites 10 CFR Part 50, Appendix B, Section XVI, CAP. The One-Time Inspection AMP is described in Section B.2.3.20.

The SLC tank has the potential for loss of material of its stainless steel. The One-Time Inspection (B.2.3.20) and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1) AMPs will be used to manage the loss of material aging effect. An internal OTI will look for indications of aging effects on both the tank bottom and on the sides of the tank. For this OTI, an ultrasonic test or similar method for performing a volumetric inspection of the tank material will be used to detect aging effects on both the internal and external sides of the tank as described in the guidance from GALL-SLR Table XI.M29-1, note 3. This will provide reasonable assurance that any aging effects that occur

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 8 of 15 to the tank sides or bottom would be detected prior to a loss of intended function.

SLRA Section 3.3.2.2.9 on page 3.3-29 is revised as follows:

The stainless steel SLC tank is the only stainless steel component that is considered to be exposed to concrete (no credit is taken for the epoxy material between the tank bottom and the concrete pedestal) that is susceptible to cracking. Other steel or stainless steel components exposed to concrete is not subject to wetting, so loss of material and cracking are not applicable aging effects. OE has shown cracking of the stainless steel SLC tank bottoms. However, this issue has been corrected and tThe One-Time Inspection (B.2.3.20) and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1) AMPs will be used to confirm that the tank bottoms has not experienced further cracking. An internal OTI will look for indications of aging effects on both the tank bottom and on the sides of the tank. For this OTI, an ultrasonic test or similar method for performing a volumetric inspection of the tank material will be used to detect aging effects on both the internal and external sides of the tank as described in the guidance from GALL-SLR Table XI.M29-1, note 3. This will provide reasonable assurance that any aging effects that occur to the tank sides or bottom would be detected prior to a loss of intended function.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 Enclosure 05 Page 9 of 15 SRLA Table 3.2-1, Item 3.2.1-129 on page 3.2-45 is revised as follows:

Table 3.2-1: Summary of Aging Management Evaluations for the Engineered Safety Features Item Aging Effect / Aging Management Further Evaluation Component Discussion Number Mechanism Program (AMP)/TLAA Recommended 3.2.1129 Stainless steel Loss of AMP XI.M29, "Outdoor No Not applicable.Consistent with tanks exposed material due to and Large Atmospheric NUREG-2191.

to soil, concrete pitting, crevice Metallic Storage Tanks" corrosion, MIC There are no tanks within the scope of (soil only) the Outdoor and Large Atmospheric Metallic Storage Tanks (B.2.3.17) AMP in the ESF systems.

This item is used for the stainless steel SLC tank. The One-Time Inspection (B.2.3.20) and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1) AMPs are used to manage loss of material of the stainless steel SLC tank bottom exposed to concrete.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 Enclosure 05 Page 10 of 15 SRLA Table 3.3-1, Item 3.3.1-004 on page 3.3-33 is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Aging Effect / Aging Management Further Evaluation Component Discussion Number Mechanism Program (AMP)/TLAA Recommended 3.3.1004 Stainless steel Cracking due AMP XI.M32, "One- Yes (SRP-SLR Consistent with NUREG-2191.

piping, piping to SCC Time Inspection," AMP Section 3.3.2.2.3) components, XI.M36, External This line item is also applied to heat tanks exposed Surfaces Monitoring of exchanger components. The One-Time to air, Mechanical Inspection (B.2.3.20) AMP is used to condensation Components, AMP manage cracking of stainless steel XI.M38, Inspection of piping, piping components, and heat Internal Surfaces in exchanger components exposed to air Miscellaneous Piping indoor uncontrolled, air outdoor, and and Ducting condensation.

Components, or AMP XI.M42, Internal This item is used for the stainless Coatings/Linings for In- steel SLC tank. The ASME Section Scope Piping, Piping XI Inservice Inspection, Subsections Components, Heat IWB, IWC, and IWD (B.2.3.1) AMP is Exchangers, and used to manage cracking of the Tanks external stainless steel SLC tank surfaces exposed to air indoor uncontrolled.

Further evaluation is documented in Section 3.3.2.2.3.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 Enclosure 05 Page 11 of 15 SRLA Table 3.3-1, Item 3.3.1-222 on page 3.3-77 is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Aging Effect Aging Management Further Evaluation Component Discussion Number / Mechanism Program (AMP)/TLAA Recommended 3.3.1222 Stainless steel, Loss of AMP XI.M32, "One- Yes (SRP-SLR Consistent with NUREG-2191.

nickel alloy tanks material due Time Inspection," AMP Section 3.3.2.2.4) exposed to air, to pitting, XI.M36, External The One-Time Inspection (B.2.3.20) condensation crevice Surfaces Monitoring of AMP is used to manage loss of material (internal/external) corrosion Mechanical of stainless steel piping, piping Components, AMP components, and tanks exposed to air XI.M38, Inspection of indoor uncontrolled or condensation.

Internal Surfaces in Miscellaneous Piping This item is used for the stainless and Ducting steel SLC tank. The ASME Section Components, or AMP XI Inservice Inspection, Subsections XI.M42, Internal IWB, IWC, and IWD (B.2.3.1) AMP is Coatings/Linings for In- used to manage loss of material of Scope Piping, Piping the external stainless steel SLC tank Components, Heat surfaces exposed to air indoor Exchangers, and uncontrolled.

Tanks Further evaluation is documented in Section 3.3.2.2.4.

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 Enclosure 05 Page 12 of 15 SRLA Table 3.3-1, Item 3.3.1-230 on page 3.3-79 is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Aging Effect / Aging Management Further Evaluation Component Discussion Number Mechanism Program (AMP)/TLAA Recommended 3.3.1230 Stainless steel Cracking due AMP XI.M29, "Outdoor No This item is used for the stainless steel tanks (within the to SCC and Large Atmospheric SLC tank. The One-Time Inspection scope of AMP Metallic Storage Tanks" (B.2.3.20) and the ASME Section XI XI.M29, Inservice Inspection, Subsections "Outdoor and IWB, IWC, and IWD (B.2.3.1) AMPs Large are is used to manage cracking of the Atmospheric stainless steel SLC tank bottom Metallic Storage exposed to concrete.

Tanks")

exposed to soil, concrete

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 13 of 15 SRLA Table 3.3.2-17 on page 3.3-304 is revised as follows:

Table 3.3.217: Standby Liquid Control - Summary of Aging Management Evaluation Aging Effect Aging Component Intended Material Environment Requiring Management NUREG2191 Item Table 1 Item Notes Type Function Management Program Tanks Pressure Stainless Air Indoor Cracking One-Time VII.E4.AP-209a 3.3.1.-004 C E, 5 (Standby Boundary Steel Uncontrolled Inspection Liquid (External) (B.2.3.20)

Control ASME Tank) Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1)

Tanks Pressure Stainless Air Indoor Loss of One-Time VII.I.A-751b 3.3.1-222 E, 5 A (Standby Boundary Steel Uncontrolled Material Inspection Liquid (External) (B.2.3.20)

Control ASME Tank) Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 14 of 15 Table 3.3.217: Standby Liquid Control - Summary of Aging Management Evaluation Aging Effect Aging Component Intended Material Environment Requiring Management NUREG2191 Item Table 1 Item Notes Type Function Management Program Tanks Pressure Stainless Concrete Cracking ASME VII.E5.A-759 3.3.1-230 E, 3 (Standby Boundary Steel (External) Section XI Liquid Inservice Control Inspection, Tank) Subsections IWB, IWC, and IWD (B.2.3.1)

Tanks Pressure Stainless Concrete Cracking One-Time VII.E5.A-759 3.3.1-230 E, 3 (Standby Boundary Steel (External) Inspection Liquid (B.2.3.20)

Control Tank)

Tanks Pressure Stainless Concrete Loss of ASME V.D2.E-472 3.2.1-129 E, 3 (Standby Boundary Steel (External) Material Section XI Liquid Inservice Control Inspection, Tank) Subsections IWB, IWC, and IWD (B.2.3.1)

Tanks Pressure Stainless Concrete Loss of One-Time V.D2.E-472 3.2.1-129 E, 3 (Standby Boundary Steel (External) Material Inspection Liquid (B.2.3.20)

Control Tank)

Monticello Nuclear Generating Plant Docket 50-263 L-MT-23-037 5 Page 15 of 15 SRLA Table 3.3.2-17 on page 3.3-308 is revised as follows:

3. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1) and One-Time Inspection (B.2.3.20) AMPs are is being substituted for the Outdoor and Large Atmospheric Metallic Storage Tanks (B.2.3.17) AMP to verify that the aging effects of cracking and loss of material on the stainless steel base plate of the SLC tank (T200) has been mitigated. The base plate has experienced cracking, has been replaced, and an epoxy coating applied to the concrete tank pedestal to prevent future cracking as a result of chloride exposure from the concrete. Further evaluation is provided in section 3.3.2.2.9.

4. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.3.24) program is being substituted for the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks (B.2.3.28) program to manage the loss of material in the base metal of carbon steel (with internal coating) accumulators exposed to treated water.

5. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.3.1) AMP is being substituted for the One-Time Inspection (B.2.3.20) AMP to manage the cracking and loss of material aging effects associated with this the stainless steel SLC Tank in an air - indoor uncontrolled environment.