ML19253D708

Summary of August 13, 2019, Category 2 Public Meeting Related to the Safety Review of the Surry Power Station, Units 1 and 2, Subsequent License Renewal Application

ML19253D708
Person / Time
Site:	Surry
Issue date:	09/24/2019
From:	Angela Wu NRC/NRR/DMLR/MRPB
To:	Eric Oesterle NRC/NRR/DMLR/MRPB
Wu A, NRR-DMLR 415-2995
Shared Package
ML19262F338	List: ML19253D708
References
Download: ML19253D708 (12)

Text

September 24, 2019 MEMORANDUM TO: Eric R. Oesterle, Chief License Renewal Projects Branch Division of Materials and License Renewal Office of Nuclear Reactor Regulation FROM: Angela Wu, Project Manager /RA/

License Renewal Projects Branch Division of Materials and License Renewal Office of Nuclear Reactor Regulation

SUMMARY

OF AUGUST 13, 2019, CATEGORY 2 PUBLIC MEETING RELATED TO THE SAFETY REVIEW OF THE SURRY POWER STATION, UNITS 1 AND 2, SUBSEQUENT LICENSE RENEWAL APPLICATION 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), April 2, 2019 (ADAMS Accession No. ML19095A666),

June 10, 2019 (ADAMS Accession No. ML19168A028), June 27, 2019 (ADAMS Accession No.

ML19183A440), July 17, 2019 (ADAMS Accession No. ML19204A357) and September 3, (ADAMS Accession No. ML19253B330). 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, Units 1 and 2 (SPS). 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.

By letter dated August 5, 2019 (ADAMS Accession No. ML19217A358) the U.S. Nuclear Regulatory Commission (NRC) issued second round requests for additional information (RAIs),

Set 3, to Dominion regarding the SPS subsequent license renewal application (SLRA). On August 13, 2019, the NRC staff held a public meeting to discuss technical matters of the second round RAIs of Set 3, and draft RAIs of Set 4. Subsequently, on August 14, 2019 (ADAMS Accession No. ML19231A153), the U.S. Nuclear Regulatory Commission (NRC) issued requests for additional information (RAIs), Set 4, to Dominion regarding the SPS subsequent license renewal application (SLRA). The public meeting agenda is available at ADAMS Accession No. ML19212A660.

CONTACT: Angela Wu, NRR/DMLR/MRPB 301-415-2995

E. Oesterle As a Category 2 meeting, the public was invited to participate in the meeting by discussing regulatory issues with the NRC staff at designed points identified on the agenda.

Enclosures:

1. Summary of Discussions

2. Original Draft Set 4 Second Round RAIs

3. List of Meeting Attendees

Meeting Package ML19262F338 Meeting Notice/Agenda ML19212A660 Meeting Summary: ML19253D708 *via e-mail OFFICE PM:MRPB:DMLR LA:MRPB:DMLR BC:MRPB:DMLR PM:MRPB:DMLR NAME AWu YEdmonds EOesterle AWu DATE 9/19/19 9/19/19 9/23/19 9/24/19

Surry Power Station (SPS) Units 1 and 2: Public Meeting Summary of Discussions August 13, 2019 During the Category 2 public meeting on August 13, 2019, technical discussion was held on a total of eight draft second round requests for additional information (RAIs).

For each draft second round RAI, there were three possible outcomes from the technical discussion: a) issue RAI, b) modify and issue RAI, or c) delete RAI. The original draft second round RAIs discussed during the public meeting are in Enclosure 2. The table below depicts the outcome of each of the technical discussions held for the draft second round RAIs.

Second Round RAIs RAI Outcome Set 3 RAI B2.1.28-7a, Internal Coatings Issued August 5, 2019 (Component Cooling Heat Exchangers)

Set 3 RAI B2.1.21-1, Selective Leaching Issued August 5, 2019 Set 3 B2.1.27-1a (Request 1) and B2.1.27-2a Issued August 5, 2019 (Request 2), Buried Components (Cementitious Piping Aging Management)

Draft Set 4 RAI B2.1.28-5a, Internal Coatings Issue RAI.

(Security Diesel Fuel Oil Tank Coatings)

Draft Set 4 RAI B2.1.34-1a, Structures Issue RAI.

Monitoring (Wood Pole Aging Management)

Draft Set 4 RAI B2.1.8-1a, Flow Accelerated Issue RAI.

Corrosion Draft Set 4 RAI B2.1.8-3a, Flow Accelerated Modify and issue RAI Corrosion Draft RAI B2.1.8-3a:

After technical discussions, Draft RAI B2.1.8-3a, regarding Surry Subsequent License Renewal Application (SLRA) Section B2.1.8.3, Flow Accelerated Corrosion, the request of the RAI was modified to provide additional clarification. Specifically, the text italicized was incorporated:

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 (CLB) 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 CLB. 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.

Enclosure 1

RAI B2.1.8-3a

Background:

As supplemented by letter dated April 2, 2019, SLRA Table 3.3.2-6 Bearing Cooling, was modified to address the potential for erosion in valve bodies constructed of several different materials. The supplement also states that cavitation in this system could be caused by valve throttling. Additionally, condition report CR1031398, BC Valve - Indication of Cavitation, describes cavitation in a Unit 1 bearing cooling valve and notes that the valve was previously replaced in 2013 due to a pin hole leak in the valve body. This CR also notes that the current non-destructive examination strategy doesnt evaluate the valve body for wall thinning. The staff notes that condition report CR1026621, 2-BC-505 Has a Through-Wall Leak, describes a through-wall leak for the corresponding Unit 2 valve; however, the cause of the leak was not included in the summary documentation.

The applicants erosion susceptibility evaluation (ESE) (ETE-CME-2018-1002, Revision 1, Transmittal of True North Consulting Technical Report BP-2017-0045-TR-01, Erosion Susceptibility Evaluation - Surry, September 2018) designated the bearing cooling system as not being susceptible to cavitation because the cavitation index is greater than 2.5. The ESE states that the bearing cooling system is a closed-loop system which does not have large enough pressure drops for cavitation to occur. The staff notes that comments for other systems in the ESE identify the potential for cavitation and flashing downstream of throttle valves and orifices. The ESE indicates that the criteria for the cavitation index greater than 2.5 is a rule of thumb and cites a reference to a valve manufacturer publication. The associated implementing procedure, ER-AA-FAC-105, Erosion Control Program, Section 3.1.1 states that the ESE is to be periodically updated based on relevant operating experience.

The response to RAI B2.1.8-3 dated July 17, 2019 (ADAMS Accession No. ML19204A357),

states that the input for the erosion susceptibility evaluation included a review of plant operating experience to determine locations with a history of erosion failure, and that the bearing cooling system was determined to not be susceptible based on the absence of erosion failures.

Issue:

In its initial request the NRC staff requested information regarding whether other systems (i.e. in addition to the bearing cooling system) determined to not be susceptible to erosive mechanisms could be affected in a similar manner as the bearing cooling system (i.e. change of operating conditions lead to higher erosion susceptibility). In its response to RAI B2.1.8-3 the applicant stated that plant information has not indicated other systems that may have higher erosion susceptibility than was stated in the ESEs.

Although the response to RAI B2.1.8-3 states that the bearing cooling system was determined to not be susceptible based on the absence of erosion failures, the two CRs referenced above (CR1031398 and CR1026621) describe erosive failures (i.e. cavitation) in the bearing cooling system.

The staff noted the residual heat removal and chemical and volume control (CVCS) systems are identified in the current ESE as not susceptible to cavitation although NRC Information Notices 89-01 and 98-45 describe these systems as potentially susceptible. Additionally, EPRI 3002005530, which is referenced by the applicants Erosion Control Program, states that the CVCS system is potentially susceptible to erosion. These are some examples of instances

where the exclusion criteria as noted in the applicants ESE may not apply and where the staff may need additional explanation for why these criteria are applied. These examples are used to demonstrate that systems not frequently in service may be susceptible to erosion, and plant operations (IN 98-45 cites an incorrectly adjusted blowdown setting of a pressure relief valve) can impact susceptibility to erosion. Additionally, EPRI Report TR-112657, Revised Risk-Informed Inservice Inspection Evaluation Procedure, Revision B-A, December 1999, discusses a lower threshold for erosion susceptibility than the 2% cited in the applicants ESE.

Request:

1. Provide a description of what plant information was reviewed and how it was determined that no other systems may have higher erosion susceptibility than was initially stated in the ESEs.

2. Also, justify use of the exclusion criteria for susceptibility to cavitation related to pressure drops as well as the service time exclusion criterion given the discussion in the Issue section above.

3. Additionally, describe how the initial ESE included and performed a review of site-specific operating experience as part of the susceptible evaluation, given that the bearing cooling system had experienced erosion prior to the ESE being issued.

With this modification, RAI B2.1.8-3a was issued to Dominion Energy.

Surry Power Station (SPS) Units 1 and 2: Public Meeting Original Draft Set 4 Second Round Requests for Additional Information (RAIs)

August 13, 2019 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 15: Internal Coatings, TRP 30: Fuel Oil Chemistry RAI B2.1.28-5a

Background:

As amended by letter dated April 2, 2019, SLRA Section B2.1.28, Enhancement No. 1 provides a list of components, including tanks, which will be inspected as part of the program. This list did not include the security diesel fuel oil tank, which is within the scope of the Fuel Oil Chemistry program.

As amended by letter dated April 2, 2019, SLRA Section B2.1.18, Fuel Oil Chemistry, Exception No. 1 states the following regarding the security diesel fuel oil tank: [t]he wall of the interior tank is provided with a solvent-based rust preventive film (not considered a coating).

The scope of program program element of GALL-SLR Report XI.M42, Internal Coatings/Linings For In-Scope Piping, Piping Components, Heat Exchangers, and Tanks, recommends that internally coated tanks exposed to fuel oil, where loss of coating or lining integrity could prevent satisfactory accomplishment of any of the components or downstream components current licensing basis intended functions, are included within the scope of the program.

The response to RAI B2.1.28-5 dated June 27, 2019 (ADAMS Accession No. ML19183A440),

states the following:

As required by the Fuel Oil Chemistry program (B2.1.18), the security diesel generator fuel oil tank is sampled quarterly and the samples are analyzed for particulates consistent with ASTM D6217-98, Standard Test Method for Particulate Contamination in Middle Distillate Fuels by Laboratory Filtration. Since the security diesel generator fuel oil tank was originally installed in 2011, quarterly test results noted below demonstrate fuel oil particulate levels have remained below the 10 mg/L acceptance limit over the installed life of the tank.

Enclosure 2

Issue:

1. The response to RAI B2.1.28-5 did not provide any information regarding the specific type of film used on the internal surfaces of the security diesel fuel oil tank, or information regarding potential age-related failure modes outside of particulate generation (e.g., failure into sheets). The staff notes that all coatings (e.g., epoxy) are either water-based or solvent-based.

2. An adequate basis was not provided for why particulate testing would be an effective indicator of film degradation. It is unclear how a coating, or film, which could potentially degrade into large sheets (i.e., as opposed to small particles) would be detected through particulate testing. Additionally, it isnt clear where the fuel oil filter is located.

Request:

1. State the specific type of film used on the internal surfaces of the security diesel fuel oil tank (e.g., product data sheet), and potential age-related failure modes that might impact the intended function of the security diesel fuel oil tank, or downstream components.

2. State the basis for why any potential age-related failure modes (e.g., accumulated particulate in the bottom of the tank) would not lead to flow blockage in the fuel oil filter or injectors sufficient to impact the intended function of the diesel.

TRP 17: Flow-Accelerated Corrosion RAI B2.1.8-1a

Background:

In SLRA, Section B2.1.8, Flow-Accelerated Corrosion, the applicant claimed consistency with the GALL-SLR Report AMP XI.M17, Flow-Accelerated Corrosion. SLRA Section B2.1.8 states that the erosion activity implements the recommendation of EPRI 3002005530, Recommendations for an Effective Program Against Erosive Attack. The parameters monitored or inspected, detection of aging effects, and monitoring and trending program elements for GALL-SLR Report AMP XI.M17 discuss recommendations to monitor, detect, and trend degradation due to erosion mechanisms (e.g., cavitation, flashing, etc.).

During the In-Office audit, the staff reviewed the program basis document ETE-SLR-2018-1311, Surry Subsequent License Renewal Project - Aging Management Program Evaluation Report

- Flow-Accelerated Corrosion, Revision 1, to evaluate whether the applicant is consistent with the GALL-SLR Report AMP XI.M17 recommendations for the flow-accelerated corrosion (FAC) program. In the document, the applicant stated that the FAC erosion module in CHECWORKS will be used to assist in the development of the inspection plan for the Erosion Control program.

Issue:

In its response to RAI B2.1.8-1, dated July 17, 2019 (ADAMS Accession No. ML19204A357),

the applicant stated that EPRI 3002005530 is referenced in its Erosion Control Program implementing procedure, and provides the basis used in the erosion module for component inspection, inspection techniques, determination of wear rate and service life, and determination

of component replacement. However, the applicants RAI response does not appear to discuss specifically how the erosion module in CHECWORKS is used to plan inspections, determine wear rate, etc.

Additionally, the erosion module in CHECWORKS appears to have different predictive capabilities for different erosion mechanisms. It is unclear to the staff how the outputs from this software are used in the applicants erosion program.

Request:

Provide a justification for how the FAC erosion module in the CHECWORKS software is used to model erosion, how the results will be used in planning erosion inspections, and how this meets the recommendations of the GALL-SLR with respect to monitoring effects of wall thinning due to erosive mechanisms, its use in planning inspections for erosive degradation, as well as for monitoring and trending potential degradation due to erosive mechanisms. Additionally, given that the FAC erosion module in CHECWORKS has different capabilities for different erosion mechanisms, the justification should include a discussion that describes what outputs from the erosion module are used in the applicants program and how the results from the erosion module are validated by applicant inspections.

RAI B2.1.8-3a

Background:

As supplemented by letter dated April 2, 2019, SLRA Table 3.3.2-6 Bearing Cooling, was modified to address the potential for erosion in valve bodies constructed of several different materials. The supplement also states that cavitation in this system could be caused by valve throttling. Additionally, condition report CR1031398, BC Valve - Indication of Cavitation, describes cavitation in a Unit 1 bearing cooling valve and notes that the valve was previously replaced in 2013 due to a pin hole leak in the valve body. This CR also notes that the current non-destructive examination strategy doesnt evaluate the valve body for wall thinning. The staff notes that condition report CR1026621, 2-BC-505 Has a Through-Wall Leak, describes a through-wall leak for the corresponding Unit 2 valve; however, the cause of the leak was not included in the summary documentation.

The applicants erosion susceptibility evaluation (ESE) (ETE-CME-2018-1002, Revision 1, Transmittal of True North Consulting Technical Report BP-2017-0045-TR-01, Erosion Susceptibility Evaluation - Surry, September 2018) designated the bearing cooling system as not being susceptible to cavitation because the cavitation index is greater than 2.5. The ESE states that the bearing cooling system is a closed-loop system which does not have large enough pressure drops for cavitation to occur. The staff notes that comments for other systems in the ESE identify the potential for cavitation and flashing downstream of throttle valves and orifices. The ESE indicates that the criteria for the cavitation index greater than 2.5 is a rule of thumb and cites a reference to a valve manufacturer publication. The associated implementing procedure, ER-AA-FAC-105, Erosion Control Program, Section 3.1.1 states that the ESE is to be periodically updated based on relevant operating experience.

The response to RAI B2.1.8-3 dated July 17, 2019 (ADAMS Accession No. ML19204A357),

states that the input for the erosion susceptibility evaluation included a review of plant operating experience to determine locations with a history of erosion failure, and that the bearing cooling system was determined to not be susceptible based on the absence of erosion failures.

Issue:

In its initial request the NRC staff requested information regarding whether other systems (i.e. in addition to the bearing cooling system) determined to not be susceptible to erosive mechanisms could be affected in a similar manner as the bearing cooling system (i.e., change of operating conditions lead to higher erosion susceptibility). In its response to RAI B2.1.8-3 the applicant stated that plant information has not indicated other systems that may have higher erosion susceptibility than was stated in the ESEs.

Although the response to RAI B2.1.8-3 states that the bearing cooling system was determined to not be susceptible based on the absence of erosion failures, the two CRs referenced above (CR1031398 and CR1026621) describe erosive failures (i.e. cavitation) in the bearing cooling system.

Request:

1. Provide a description of what plant information was reviewed and how it was determined that no other systems may have higher erosion susceptibility than was initially stated in the ESEs.

2. Additionally, describe how the initial ESE included and performed a review of site-specific operating experience as part of the susceptible evaluation, given that the bearing cooling system had experienced erosion TRP 46: Structures Monitoring RAI B2.1.34-1a

Background:

Dominion addressed the age-related degradation of loss of material and change in material properties for wooden power poles by including a plant-specific enhancement to the detection of aging effects program element of the Structures Monitoring Program (SLRA Section B2.1.34). This enhancement specifies that wooden power poles will be inspected on a 10-year frequency. However, the staff needed additional information to evaluate the adequacy of the proposed 10-year inspection frequency for wooden poles which resulted in the issuance of RAI B2.1.34-1.

In its response to RAI B2.1.34-1, dated July 17, 2019 (ADAMS Accession No. ML19204A357),

Dominion stated that the 10-year inspection period was appropriate for the chromate copper arsenate (CCA) treated southern pine poles at Surry by considering the fifty-year durability evaluation from the USDA Forest Products Laboratory. Dominion also stated that there are 14 CCA wooden poles installed at Surry that were manufactured in 1981 or later.

SRP-SLR Section A.1.2.3.4 recommends that the discussion for the detection of aging effects program element should provide, in part, justification, including codes and standards referenced, to demonstrate that the technique and frequency are adequate to detect the aging effects before a loss of intended function.

Issue:

Dominions response to RAI B2.1.34-1 does not provide adequate justification for the proposed 10-year inspection frequency of wooden poles, because the service life of at least some of the poles would exceed 50 years prior to entering the subsequent period of extended operation and no previous inspections would have been performed. The staff notes that the durability study referenced by Dominion for the CCA-treated southern pine poles specifically establishes the basis for the fifty-year durability of treated wood products; however, it does not establish inspection frequency criteria for use with treated wood poles after the fifty years of service.

Furthermore, the response did not clearly provide the criteria, based on the expected decay at the sites location (deterioration zone), to establish the 10-year inspection frequency, and when the initial inspection that would establish the baseline condition will be performed at the site.

Treated poles are expected to eventually lose resistance to decay (e.g., after the treatment service life) and their vulnerability and inspection criteria should be proportioned to the level of decay that is expected at the sites location (deterioration zone) to ensure that the aging effects can be detected before a loss of intended function.

Request:

Provide justification that would demonstrate, pursuant to 10 CFR 54.21(a)(3), that the proposed inspection frequency for wooden poles will be adequate to detect the associated aging effects before a loss of intended function considering the sites location. Also, clarify when the initial baseline inspection will occur, the type of inspection that will be performed to assess the poles current condition, and its role, if any, in determining subsequent inspection frequency.

Surry Power Station (SPS) Units 1 and 2: Public Meeting List of Meeting Attendees August 13, 2019 Name Affiliation Paul Aitken Virginia Electric and Power Company (Dominion Energy Virginia)

Eric Blocher Dominion Energy Virginia Tony Banks Dominion Energy Virginia Rick Eagan Dominion Energy Virginia Mark Pellegrino Dominion Energy Virginia Pratt Cherry Dominion Energy Virginia James Johnson Dominion Energy Virginia James Zaborowski Dominion Energy Virginia Bryan McCarter Dominion Energy Virginia Ryan Doremus Dominion Energy Virginia Vendor-True North Emmanuel Sayoc NRC Alexander Chereskin NRC Brian Allik NRC Steve Bloom NRC Bill Rogers NRC Juan Lopez NRC James Gavula NRC Brian Wittick NRC Brian Allik NRC Tony Gardner NRC Enclosure 3