ML19217A358

SLRA RAI Transmittal Email Set 3 with Attachments- 2-August 5, 2019

ML19217A358
Person / Time
Site:	Surry
Issue date:	08/02/2019
From:	Sayoc E NRC/NRR/DMLR/MRPB
To:	Stoddard D Dominion Energy Co
Sayoc E, NRR-DMLR 415-4084
References
CAC 000951, EPID L-2018-RNW-0023
Download: ML19217A358 (16)

Text

From: Sayoc, Emmanuel To: "Daniel.g.stoddard@dominionenergy.com" Cc: Wu, Angela; Oesterle, Eric; "Paul Aitken"; Eric A Blocher; Tony Banks

Subject:

FINAL REQUESTS FOR ADDITIONAL INFORMATION FOR THE SAFETY REVIEW OF THE SURRY POWER STATION, UNITS 1 AND 2 SUBSEQUENT LICENSE RENEWAL APPLICATION (L-2018-RNW-0023/000951) - SET 3 Date: Friday, August 02, 2019 9:47:57 AM Attachments: Attachment 1 - Surry SLRA Final RAI Summary Index - Set 3.pdf Attachment 2 - Surry SLRA Final RAIs Package Set 3.pdf Importance: High Docket No. 50-280 and 50-281

Dear Mr. Stoddard,

By letter dated October 15, 2018 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML18291A842), as supplemented by letters dated January 29, 2019 (ADAMS Accession No. ML19042A137), and April 2, 2019 (ADAMS Accession No. ML19095A666), Virginia Electric and Power Company (Dominion Energy Virginia or Dominion) submitted to the U.S. Nuclear Regulatory Commission (NRC or staff) an application to renew the Renewed Facility Operating License Nos. DPR-32 and DPR-37 for the Surry Power Station, Unit Nos. 1 and 2. Dominion submitted the application pursuant to Title 10 of the Code of Federal Regulations Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants, for subsequent license renewal.

From July 15, 2019 through July 30, 2019, the U.S Nuclear Regulatory Commission (NRC) staff sent Dominion the draft Requests for Additional Information (RAIs) for various technical review packages (TRP). Dominion subsequently informed the NRC staff that clarification calls were needed to discuss the information requested. Between July 15, 2019 through August 1, 2019, clarification calls were completed for all the draft RAIs unless Dominion declined having a call. The specific dates of the draft RAI transmittals and the RAIs clarification calls are summarized in Attachment 1. The final RAIs resulting from these calls are enclosed in Attachment 2.

Paul Aitken of your staff agreed to provide a response to these RAIs within 30 days of the date of this email. The NRC staff will be placing a copy of this email and attachments in the NRCs ADAMS.

Sincerely, Emmanuel Sayoc, Project Manager License Renewal Projects Branch (MRPB)

Division of Materials and License Renewal Office of Nuclear Reactor Regulation Docket No. 50-280 and 50-281 Attachments:

As stated OFFICE PM:MRPB:DMLR BC: MRPB:DMLR PM: MRPB:DMLR

NAME ESayoc EOesterle ESayoc DATE 08/1/2019 08/2/2019 08/2/2019 OFFICIAL RECORD COPY

Surry SLRA RAI Set 3 Index Date - Draft RAI Date - Clarification Call Sent To Clarification Attendees - Clarification Call Item No RAI Set TRP RAI Number Issue Applicant Call Applicant Attendees - NRC Issue Date Eric Blocher, Tony Banks, Pratt Cherry, Buried and Underground Piping and Candee Lovett, Angela Wu, 1 3 14 B.2.1.27-1a Tanks 7/19/2019 7/22/2019 Robert T Steve Bloom 8/1/2019 Eric Blocher, Tony Banks, Pratt Cherry, Candee Lovett, Robert T Buried and Underground Piping and Scarborough Angela Wu, 2 3 14 B.2.1.27-2a Tanks 7/19/2019 7/22/2019 Steve Bloom 8/1/2019 Eric Blocher, Tony Banks, Pratt Cherry, Candee Lovett, Internal Coatings/Linings for In-Scope Robert T Piping, Piping Components, Heat Scarborough Angela Wu, 3 3 15 B.2.1.28-6a Exchangers, and Tanks 7/15/2019 7/22/2019 Steve Bloom 8/1/2019 Eric Blocher, Tony Banks, Pratt Cherry, Candee Lovett, Internal Coatings/Linings for In-Scope Robert T Piping, Piping Components, Heat Scarborough Angela Wu, 4 3 15 B.2.1.28-7a Exchangers, and Tanks 7/15/2019 7/22/2019 Steve Bloom 8/1/2019 Paul Aitken, Eric Blocher, Craig Heah, John Thomas, Mark Pellegrino, Tony Banks, Angela Wu Ron Burner Tony Gardner 5 3 33 B.2.1.21-1 Selective Leaching 7/23/2019 7/25/2019 Steve Jones 8/1/2019 Paul Aitken, Angela Wu, Neutron Fluence Monitoring Aging Eric Blocher David Dijamco, 6 3 61 B.3.2-1-a Management Program 7/30/2019 8/1/2019 Emmanuel Sayoc 8/1/2019

SURRY POWER STATION, UNITS 1 AND 2 Subsequent License Renewal Application (SLRA)

Request for Additional Information (Set 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.

TRP 14: Buried and Underground Piping and Tanks RAI B2.1.27-1a

Background:

1. SLRA Section B2.1.27, Buried and Underground Piping and Tanks, states that the Buried and Underground Piping and Tanks program is an existing program that, following enhancement, will be consistent with NUREG-2191,Section XI.M41, Buried and Underground Piping and Tanks.

The responses to RAIs B2.1.27-1 and B2.1.27-2 dated June 27, 2019 (ADAMS Package Accession No. ML19183A440), state the following:

Buried cementitious piping within the scope of subsequent license renewal (SLR) is precast reinforced concrete pipe installed with specifications that are consistent with American Water Works Association (AWWA) C302, Reinforced Concrete Pressure Pipe, Noncylinder Type.

Buried cementitious piping does not have an external coating and will not be cathodically protected.

GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks, recommends external coatings and cathodic protection for buried cementitious piping.

During its review of Concrete Pressure Pipe - Manual of Water Supply Practices, the staff noted that external corrosion protection is recommended for buried reinforced concrete piping when the following conditions are present.

Where pipe is to be buried in soils with resistivity readings below 1,500 ohm-cm and the water soluble chloride contents exceeds 400 ppm at those same locations, one of the following protective measures should be used: (a) moisture barrier should be used to protect the exterior surfaces; (b) silica fume in an amount equal to 8 to 10 percent of the cement weight or a corrosion inhibitor

should be included in the exterior mortar or concrete; or (c) cathodic protection should be installed if monitoring of the pipeline detects the onset of corrosion.

For installations of mortar-coated pipe in soils with more than 5,000 ppm water-soluble sulfates, a barrier material should be considered.

In clay soils, supplemental precautions against acid attack generally are not needed.

In granular soils, when the soil pH immediately after sample excavation is greater than 5, supplemental precautions against acid attack of the mortar coating generally are not needed.

SLRA Section B2.1.34, Structures Monitoring, states that groundwater samples are obtained at intervals not to exceed 5 years. The water chemistry is evaluated and limits are established for chlorides, sulfates, and pH.

2. The response to RAI B2.1.27-1 dated June 27, 2019 (ADAMS Package Accession No. ML19183A440), states the following:

Forty-four of 48 soil samples tested in 2012 were found to be mildly corrosive or noncorrosive (the corrosive samples were not applicable to buried components within the scope of license renewal).

The soil type and soil conditions from the analyzed soil samples at Surry in 2018 are mildly corrosive (lowest corrosive ranking) using the Electric Power Research Institute (EPRI) index and non-corrosive using the AWWA index.

In 2004, a two-inch auxiliary feedwater (AFW) line piping leak was identified due to poorly installed coating. As a corrective action, the Unit 1 and Unit 2 AFW recirculation system piping is no longer buried and was rerouted through the safeguards building basement.

Pipe-to-soil potential measurements were not addressed during the 2018 soil survey.

SLRA Section B2.1.27 states the following:

Soil sampling and testing is performed during each excavation and a station-wide soil survey is also performed once in each 10-year period to confirm that the soil environment of components within the scope of license renewal is not corrosive for the installed material types. Soil sampling and testing is consistent with EPRI Report 3002005294, Soil Sampling and Testing Methods to Evaluate the Corrosivity of the Environment for Buried Piping and Tanks at Nuclear Power Plants.

SLRA Section B2.1.27 documents that in May 2017, during the as-found coating inspection on Unit 2 buried carbon steel condensate makeup piping, coating was missing on approximately 270 degrees of the pipe circumference from the center of the excavated area into the soil on the east side.

GALL-SLR Report AMP XI.M41 recommends cathodic protection for buried steel piping.

In addition, the preventive actions program element of GALL-SLR Report AMP XI.M41 states the following:

Failure to provide cathodic protection in accordance with Table XI.M41-1 may be acceptable if justified in the SLRA. The justification addresses soil sample locations, soil sample results, the methodology and results of how the overall soil

corrosivity was determined, pipe to soil potential measurements and other relevant parameters.

If cathodic protection is not provided for any reason, the applicant reviews the most recent 10 years of plant-specific operating experience (OE) to determine if degraded conditions that would not have met the acceptance criteria of this AMP have occurred. This search includes components that are not in-scope for license renewal if, when compared to in-scope piping, they are similar materials and coating systems and are buried in a similar soil environment. The results of this expanded plant-specific OE search are included in the SLRA.

During the audit, the staff noted plant-specific OE indicating instances of leaks, coating degradation, and minor external degradation of buried steel piping.

Licensee Event Report (LER) 281-2004-01, Surry Power Station Regarding Switchyard Device Failure Results in a Reactor Trip, (ADAMS Accession No. ML043280416) states the following:

On May 22, 2004, following refill of the Emergency Condensate Storage Tank, an unisolable leak in a buried Unit 2 AFW recirculation line was discovered. The AFW system was declared inoperable. Further evaluations determined that the AFW system was capable of performing its intended function. The cause of the AFW piping leak was external galvanic corrosion of the buried carbon steel piping due to the failed corrosion protection.

Issue:

1. An adequate basis was not provided for why external corrosion protection (i.e., cathodic protection or external coatings) are not necessary for buried cementitious piping. Based on its review of Concrete Pressure Pipe - Manual of Water Supply Practices, the staff noted that various soil parameters determine if external corrosion protection is recommended for buried cementitious piping (i.e., soil resistivity, pH, chlorides, and sulfates).

Although samples of groundwater are obtained for the Structures Monitoring program:

(a) they are not necessarily obtained in the vicinity of the in-scope buried cementitious piping; (b) groundwater samples might not be representative of soil parameters in close proximity to the in-scope buried cementitious piping; (c) groundwater parameter acceptance criteria is different than that recommended in the Concrete Pressure Pipe -

Manual of Water Supply Practices; and (d) soil resistivity readings are not obtained.

Absent a technical justification for why external corrosion protection is not necessary, the staff seeks clarification for why additional inspections, beyond those recommended in GALL-SLR Report Table XI.M41-2, Inspection of Buried and Underground Piping and Tanks, are not appropriate if exceptions are taken to the preventive actions program element of GALL-SLR Report AMP XI.M41.

2. An adequate basis was not provided for why cathodic protection is not necessary for the balance of buried steel piping. Specifically, the staff notes the following:

The staff seeks clarification for why the four corrosive samples tested in 2012 are not applicable to buried components within the scope of SLR. For example, are

local conditions at the sample point unique enough that they would never be representative of conditions in the vicinity of in-scope buried piping?

The staff notes the following regarding the use of EPRI Report 3002005294 in each 10-year period to confirm that the soil environment of components within the scope of license renewal is not corrosive for the installed material types.

i. EPRI Report 3002005294 provides two tables that provide guidance related to determining soil corrosivity. The response to RAI B2.1.27-4 did not state which one of these tables is used to determine soil corrosivity. If EPRI Report 3002005294, Table 9-4 will be utilized (i.e., using column three for gray cast iron, column four for steel, and column seven for stainless steel), the SLRA did not state how non-corrosive soil determination was concluded because based on EPRI Report 3002005294, soil can only be classified as mildly corrosive, moderately corrosive, appreciably corrosive, or severely corrosive (i.e., there is no classification designated as non-corrosive).

ii. Neither SLRA Section B2.1.27 nor the RAI responses state the number of soil corrosivity samples, location of samples, and timing of samples (e.g.,

during maximum rainfall periods) in each 10-year period to confirm that the soil environment of components within the scope of license renewal is not corrosive for the installed material types.

iii. There are no corrective actions for adverse soil sampling results. Soil being classified as corrosive vs. non-corrosive (if using AWWA C105, Polyethylene Encasement for Ductile-Iron Pipe Systems, Table A.1, Soil-Test Evaluation, as recommended in GALL-SLR Report AMP XI.M41); or mildly corrosive, moderately corrosive, appreciably corrosive, or severely corrosive (if using EPRI Report 3002005294) does not appear to impact the Buried and Underground Piping and Tanks program (e.g., increased inspections, installation of cathodic protection).

The staff has concluded that even mildly corrosive soil could result in a loss of pressure boundary function in the absence of cathodic protection if there are localized areas where coatings were not installed properly or were missing.

The technical basis for not providing cathodic protection does not address pipe-to-soil potential measurements and other relevant parameters (e.g., external corrosion rate measurements). The response to RAI B2.1.27-1 only addresses soil corrosivity testing, which provides a general classification of corrosion susceptibility but cannot be used to accurately predict corrosion rates.

GALL-SLR Report AMP XI.M41 recommends that soil corrosivity testing can be used to guide inspection quantities (i.e., moving between Preventive Action Categories E to F), but not as a sole technical basis for why cathodic protection is not necessary. Although a new enhancement has been added to the program to measure pipe-to-soil potentials prior to the subsequent period of extended operation there are no proposed: (a) acceptance criteria for the testing, and (b)

no proposed actions (e.g., increased inspections, installation of cathodic protection) if the results are not acceptable.

Based on its review of plant-specific OE, including the buried steel piping leak associated with LER 281-2004-01, the staff seeks clarification regarding how the intended function(s) of buried steel piping will be maintained through 80 years of operation without cathodic protection.

i. The staff notes that the corrective action to address LER 281-2004-01 does not address all buried steel piping within the scope of SLR.

ii. The staff notes that an explanation was not provided regarding why failed or missing coatings would also not be occurring in other locations that have not yet been self-revealing.

iii. The staff notes that the design life of typical buried piping coatings is less than 80 years. An explanation was not provided regarding why coatings can be relied upon through 80 years of operation without cathodic protection.

Request:

1. State the basis for why buried cementitious piping within the scope of SLR is not provided with external coatings or cathodic protection.

2. State the basis for why the balance of buried steel piping and tanks within the scope of SLR are not provided with cathodic protection, including at a minimum the basis of: (a) acceptance criteria for subsequent soil testing; and (b) corrective actions including increased excavated buried pipe inspections as a result of not installing cathodic protection in light of plant-specific operating experience associated with coatings.

RAI B2.1.27-2a

Background:

1. The response to RAI B2.1.27-2 dated June 27, 2019 (ADAMS Package Accession No. ML19183A440), states that each uncoated stainless steel segment will be coated consistent with Table 1 of NACE SP0169-2007, Standard Recommended Practice, Cathodic Protection of Prestressed Concrete Cylinder Pipelines.

GALL-SLR Report AMP XI.M41 recommends that buried stainless steel piping is coated in accordance with Table 1 of NACE SP0169-2007, Control of External Corrosion on Underground or Submerged Metallic Piping Systems.

2. The response to RAI B2.1.27-2 dated June 27, 2019 ADAMS Package Accession No. ML19183A440), states the following:

The eight concrete circulating water lines without external coating comprise the total of approximately 1000 feet of buried cementitious piping within the scope of SLR. The Open Cycle Cooling Water Systems program will periodically inspect for evidence of concrete aging in accessible internal surfaces of the concrete circulating water lines. The Open Cycle Cooling Water Systems program will require that evaluation of inspection results includes consideration of the

acceptability of inaccessible buried surfaces when conditions exist in accessible surfaces that could indicate the presence of, or result in, degradation to inaccessible buried surfaces. One hundred percent of the accessible circulating water line internal surfaces will be inspected in a ten year period. The Buried and Underground Piping and Tanks program will opportunistically inspect buried concrete circulating water lines when scheduled maintenance work permits access.

Ground water monitoring has shown historically the external environment of these circulating water lines to be non-aggressive. The internal environment is considered to be slightly more aggressive since the brackish water is drawn from the James River.

GALL-SLR Report AMP XI.M41 recommends periodic inspections for buried cementitious piping.

Issue:

1. The staff seeks confirmation on whether uncoated stainless steel segments will be coated consistent with Table 1 of NACE SP0169-2007. The title referenced in the response to RAI B2.1.27-2 references a standard related to concrete cylinder pipelines.

2. The staff notes that various GALL-SLR Report AMPs (e.g., AMP XI.M36, External Surfaces Monitoring of Mechanical Components) state that for situations where the similarity of the internal and external environments are such that the external surface condition is representative of the internal surface condition, inspections of either the internal or external surfaces of the component may be credited for managing the effects of aging for the other surface. The staff seeks clarification regarding why the internal environment of brackish water and the external soil environment are representative of one another. As documented in RAI B2.1.27-1a, it is not clear that the plant-specific groundwater sampling requirements will yield results representative of the aggressiveness of the soil conditions in the vicinity of the buried cementitious piping.

Request:

1. Provide clarification on whether uncoated stainless steel segment will be coated consistent with Table 1 of NACE SP0169-2007.

2. State the basis for why the environments of brackish water and soil are representative of one another, specifically as it relates to degradation of external surfaces of the cementitious piping. Alternatively, state the basis for why opportunistic inspections, in lieu of periodic inspections, are appropriate for buried cementitious piping.

RAI B2.1.27-4a: The staff has integrated concerns related to the response to RAI B2.1.27-4 into RAI B2.1.27-1a above.

References.

1. AWWA C105, Polyethylene Encasement for Ductile-Iron Pipe Systems. Denver, Colorado: American Water Works Association. 2010.

2. AWWA C302, Reinforced Concrete Pressure Pipe, Noncylinder Type. Denver, Colorado: American Water Works Association. 2011.

3. Concrete Pressure Pipe - Manual of Water Supply Practices, M9 (3rd Edition). American Water Works Association (AWWA), 2008

4. EPRI Report 3002005294, Soil Sampling and Testing Methods to Evaluate the Corrosivity of the Environment for Buried Piping and Tanks at Nuclear Power Plants.

Palo Alto, California: Electric Power Research Institute. November 06, 2015.

TRP 15: Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks RAI B2.1.28-6a

Background:

SLRA Section B2.1.28, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks, states that the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program will be consistent with GALL-SLR Report AMP XI.M42 with exception (not related to this RAI).

As amended by letter dated April 2, 2019, SLRA Section B2.1.28, Enhancement No. 7 states

[p]rocedures will be revised to require a pre-inspection review of the previous "two" condition assessment reports, when available, be performed, to review the results of inspections and any subsequent repair activities.

In addition to the statement above, GALL-SLR Report AMP XI.M42 states the following:

A coatings specialist prepares the post-inspection report to include: a list and location of all areas evidencing deterioration, a prioritization of the repair areas into areas that must be repaired before returning the system to service and areas where repair can be postponed to the next refueling outage, and where possible, photographic documentation indexed to inspection locations.

The response to RAI B2.1.28-6 dated June 27, 2019 ADAMS Package Accession No. ML19183A440), states that Enhancement No. 7 does not include recommendations for a post inspection report because the program procedures require preparation of a Coating Report Summary that includes the following information: (a) list and location of all areas evidencing deterioration; (b) prioritization of the repair areas that must be repaired before returning the system to service; (c) areas where repair can be postponed to the next refueling outage; and (d) where possible, photographic documentation indexed to inspection locations.

Issue:

The response to RAI B2.1.28-6 does not address the qualifications of the individual preparing the post-inspection report. The staff seeks clarification for why Enhancement No. 7 does not include the GALL-SLR Report AMP XI.M42 recommendation regarding preparation of a post-inspection report by a coatings specialist.

Request:

State the basis for why Enhancement No. 7 does not include the GALL-SLR Report AMP XI.M42 recommendation regarding preparation of a post-inspection report by a coatings specialist.

RAI B2.1.28-7a

Background:

As amended by letter dated April 2, 2019, the operating experience (OE) summary section of SLRA Section B2.1.28 states [t]he component cooling heat exchanger channel heads are epoxy-coated carbon steel exposed to raw water (service water). Inspections are performed yearly, which allows early detection of degradation of coatings and underlying metal. The OE summary also states that an inspection of the 1B component cooling water heat exchanger inlet and outlet endbells in 2016 revealed 25 areas requiring coating repair and 3 locations requiring weld repair.

GALL-SLR Report Table XI.M42-1 recommends that internal coatings/lining for piping, piping components, heat exchangers, and tanks are inspected every 4 or 6 years based on the inspection category.

The response to RAI B2.1.28-6 dated June 27, 2019 ADAMS Package Accession No. ML19183A440), states the following:

There is no current licensing basis requirement for annual inspection of the components cooling water heat exchangers but the technical basis for inspection on an annual frequency is to monitor flow blockage due to biological growth as a preventive measure, not degradation of the coatings. Flow blockage of the component cooling water heat exchangers is managed by the Open-Cycle Cooling Water System program (B2.1.11).

The service water flow is reduced in colder months because the incoming water is much colder. The reduced service water flow velocities allow mud and sediments, which would tend to remain in suspension during periods of higher flow, to come out of suspension and contribute to fouling the tubes. Eventually, the tubes are fouled so much that full flowing the heat exchangers during testing does not improve conditions. Under the preventive maintenance program, scraping and cleaning the heat exchanger tubes is performed once per year in the winter months.

Issue:

The response to RAI B2.1.28-7 does not address the component cooling water heat exchanger channel heads which are inspected on an annual basis to allow early detection of degraded coatings and underlying metal. The response to RAI B2.1.28-7 only addresses flow blockage of the component cooling water heat exchangers.

GALL-SLR AMP XI.M42 recommends a 4-year inspection interval for coatings that that do not meet Inspection Category A. However, the extent of degradation identified in the plant-specific

operating experience calls into question whether consistency with Table XI.M42-1, Inspection Intervals for Internal Coatings/Linings for Tanks, Piping, Piping Components, and Heat Exchangers, can provide reasonable assurance that the intended function of the component cooling water heat exchangers will be met.

Request:

State the basis for why the annual inspections of the component cooling heat exchanger channel heads to detect degradation of coatings and underlying metal is not reflected in the current licensing basis for the SPEO or provide a basis for a plant-specific inspection interval for these heat exchangers.

TRP 33: Selective Leaching RAI B2.1.21-1

Background:

SLRA Section B2.1.21, Selective Leaching, states the following:

The Selective Leaching program is a new program that, when implemented, will be consistent with NUREG-2191,Section XI.M33, Selective Leaching.

External surfaces of buried components that are coated consistent with the Buried and Underground Piping and Tanks program (B2.1.27) are excluded from the sample population.

GALL-SLR Report AMP XI.M33, Selective Leaching, states the external surfaces of buried components may be excluded for the scope of the program is they are externally-coated in accordance with Table XI.M41-1, Preventive Actions for Buried and Underground Piping and Tanks, of GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks, and where direct visual examinations of buried piping in the scope of license renewal have not revealed any coating damage.

The response to RAI B2.1.27-1 dated June 27, 2019 (ADAMS Accession No. ML19183A440),

states [i]n 2004, a two-inch auxiliary feedwater (AFW) line piping leak was identified due to poorly installed coating.

SLRA Section B2.1.27 documents that in May 2017, during the as-found coating inspection on Unit 2 buried carbon steel condensate makeup piping, coating was missing on approximately 270 degrees of the pipe circumference from the center of the excavated area into the soil on the east side.

Issue:

An adequate basis was not provided for why the external surfaces of buried components are excluded from the Selective Leaching program. Plant-specific operating experience (OE) has identified instances of failed or missing coatings of buried components.

Request:

State the basis for why the external surfaces of buried components susceptible to selective leaching are excluded from the scope of the Selective Leaching program.

TRP 61: Neutron Fluence Monitoring Aging Management Program RAI B3.2-1-a

Background:

SLRA Section B3.2 describes Dominions Neutron Fluence Monitoring Aging Management Program (AMP). In this AMP, Dominion stated that the program does not include neutron fluence monitoring activities for reactor internal (RVI) components. In RAI B3.2-1, the staff asked for clarification whether Surry-specific neutron fluence values for the RVI components have been projected to 80 years of licensed operation. By letter dated June 27, 2019 (ADAMS Accession No. ML19183A386) Dominions response to RAI B3.2-1 cited report WCAP-18353-NP, Revision 0, Reactor Internals Fluence Evaluation for a Westinghouse 3-Loop Plant with Two Units - Subsequent License Renewal, October 2018 for the Surry-specific neutron fluence projections of the RVI components to 80 years of licensed operation. Dominion uploaded WCAP-18353-NP in Dominions SLRA document portal.

Issue:

The staff has reviewed the neutron fluence projection basis for RVI components in WCAP-18353-NP, Revision 0, to determine whether the AMP described in SLRA Section B3.2 should include neutron fluence monitoring activities for RVI components. The staff will rely on the information in WCAP-18353-NP to make its determination, and as such WCAP-18353-NP will need to be submitted as an official NRC agency record. Accordingly, WCAP-18353-NP will need to be submitted into the dockets for the Surry units.

Request:

The staff requests that WCAP-18353-NP, Revision 0, Reactor Internals Fluence Evaluation for a Westinghouse 3-Loop Plant with Two Units - Subsequent License Renewal, October 2018

be submitted into the dockets for Surry, Units 1 and 2 (i.e., Docket No. 50-280 for Unit 1 and Docket No. 50-281 for Unit 2).

From: Sayoc, Emmanuel To: Daniel.g.stoddard@dominionenergy.com Cc: Wu, Angela; Oesterle, Eric; Paul Aitken; Eric A Blocher; Tony Banks

Subject:

REVISED REQUESTS FOR ADDITIONAL INFORMATION B3.2-1-a FOR THE SAFETY REVIEW OF THE SURRY POWER STATION, UNITS 1 AND 2 SUBSEQUENT LICENSE RENEWAL APPLICATION (L-2018-RNW-0023/000951)

- SET 3 Date: Monday, August 05, 2019 2:07:00 PM Attachments: TRP 061 Surry SLRA - Revised 2nd Round RAI for B3.2 Neutron Fluence Monitoring AMP.pdf Docket No. 50-280 and 50-281

Dear Mr. Stoddard,

On August 2, 2019, the NRC staff sent the 3rd set of Requests for Additional Information (RAI) for the Surry Power Station, Unit Nos. 1 and 2 Subsequent License Renewal Application. The NRC staff has made some modifications to one of the RAI to more clearly document the staffs request. The attached RAI B3.2-1-a on Neutron Fluence Monitoring Aging Management Program is hereby transmitted and supersedes the previously sent version. All other RAI stand as originally transmitted and the response due date is reset to within 30 days of the date of this email (August 5, 2019).

The NRC staff will be placing a copy of this email and attachments in the NRCs Agencywide Documents Access and Management System. If you have any questions please let me know.

Sincerely, Emmanuel Sayoc, Project Manager License Renewal Projects Branch (MRPB)

Division of Materials and License Renewal Office of Nuclear Reactor Regulation Docket No. 50-280 and 50-281 Attachments:

As stated OFFICE PM:MRPB:DMLR BC: MRPB:DMLR EOesterle (ESayoc NAME ESayoc For)

DATE 08/5/2019 08/5/2019

TRP 61 - Second Request for Additional Information for SLRA B3.2 Neutron Fluence Monitoring AMP - David Dijamco RAI B3.2-1-a 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. Additionally, 10 CFR 54.21(d) states, [t]he [U]FSAR supplement for the facility must contain a summary description of the programs and activities for managing the effects of aging To complete its review, enable making a finding under 10 CFR 54.29(a), and ensure that the UFSAR contains an adequate summary of programs for managing the effects of aging, the staff requires additional information regarding the matters described below.

Background

SLRA Section B3.2 describes Dominions Neutron Fluence Monitoring Aging Management Program (AMP). In this AMP, Dominion stated that the program does not include neutron fluence monitoring activities for reactor internal (RVI) components. In RAI B3.2-1, the staff asked for clarification whether Surry-specific neutron fluence values for the RVI components have been projected to 80 years of licensed operation. By letter dated June 27, 2019 (ADAMS Accession No. ML19183A386) Dominions response to RAI B3.2-1 cited report WCAP-18353-NP, Revision 0, Reactor Internals Fluence Evaluation for a Westinghouse 3-Loop Plant with Two Units - Subsequent License Renewal, October 2018 for the Surry-specific neutron fluence projections of the RVI components to 80 years of licensed operation. Dominion has included WCAP-18353-NP, Revision 0, in Dominions SLRA document portal. The SLRA portal also includes another referenced WCAP report for assessing neutron fluences in RVI components, which is WCAP-18205-NP, Revision 0.

Issue In its response to RAI B3.2-1, Surry stated that WCAP-18353-NP contained the information requested by the staff. The staff reviewed this and other WCAP documents and believes that the needed information is in WCAP18205-NP. The staffs observation appears to be inconsistent with the RAI response.

Irrespective of the appropriate document, the staff will need to rely upon the information in the document to reach its regulatory conclusion. As such, NRC processes require that the document be docketed.

Request Please identify the necessary document and submit to the NRC on the docket.