ML15034A353

Response to Request for Additional Information Proposed License Amendment Request Permanent Fifteen-Year Type a Test Interval

ML15034A353
Person / Time
Site:	North Anna
Issue date:	01/28/2015
From:	Mark D. Sartain Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
14-595
Download: ML15034A353 (40)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 January 28, 2015 U. S. Nuclear Regulatory Commission Serial No.: 14-595 Attention: Document Control Desk NLOS/ETS: RO Washington, DC 20555-0001 Docket Nos.: 50-338/339 License Nos.: NPF-4/7 VIRGINIA ELECTRIC AND POWER COMPANY NORTH ANNA POWER STATION UNITS 1 AND 2 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION PROPOSED LICENSE AMENDMENT REQUEST PERMANENT FIFTEEN-YEAR TYPE A TEST INTERVAL In a letter dated June 30, 2014 (Serial No.14-272), Virginia Electric and Power Company (Dominion) requested license amendments in the form of changes to the Technical Specifications, for facility Operating License Numbers NPF-4 and NPF-7 for North Anna Power Station Units 1 and 2, respectively. The proposed amendments revise North Anna Power Station Units 1 and 2 Technical Specification (TS) 5.5.15, "Containment Leakage Rate Testing Program," by replacing the reference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, as the implementation document used to develop the North Anna performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J. On November 28, 2014, the NRC requested additional information associated with the proposed license amendment request.

Attached is the response to the request for additional information (RAI) and revised marked-up and proposed (typed) Technical Specification pages, which address the NRC request to include the Conditions and Limitations for NEI 94-01, Revision 2A.

In a telephone conference call January 12, 2015 with the NRC staff, the NRC Project Manager concurred with Dominion providing the response to the RAI by January 31, 2015 to permit providing the final leakage results for the North Anna Unit 2 Type A test.

The proposed revision to the amendment request does not affect the significant hazards consideration determination submitted with the original license amendment request nor result in any significant increase in the amount of effluents that may be released offsite or any significant increase in individual or cumulative occupational radiation exposure.

The next Unit 1 ILRT is currently due no later than October 2017. Based on the current outage schedule for Unit 1, the current ten-year frequency would require the next Unit 1 ILRT to be performed during the fall 2016 refueling outage. Due to lead time required to procure the services and equipment to perform a Type A test, Dominion requests approval of the proposed change by December 31, 2015.

Serial No.14-595 Docket Nos. 50-338/339 Page 2 of 3 Should you have any questions or require additional information, please contact Mr.Jay Leberstien at (540) 894-2574.

Respectfully, Mark Sartain Vice President - Nuclear Engineering Commitment contained in this letter: None Attachments:

1. Response to Request for Additional Information

2. Revised Marked-up Technical Specifications Page

3. Revised Proposed Technical Specifications Page HikiL.Wll .

I NO'TARY PIlJIC p Commonwealth of4Virginia t 4 Reg.o# 140 5 2 COMMONWEALTH OF VIRGINIA ) My Commission Expires May 31, 208 -

COUNTY OF HENRICO The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Mr. Mark D. Sartain, who is Vice President - Nuclear Engineering, of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that company, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this a4 6 day of 2015.

My Commission Expires: 0

• Notary Public

Serial No.14-595 Docket Nos. 50-338/339 Page 3 of 3 cc: U.S. Nuclear Regulatory Commission - Region II Marquis One Tower 245 Peachtree Center Avenue, NE Suite 1200 Atlanta, GA 30303-1257 State Health Commissioner Virginia Department of Health James Madison Building - 7 th floor 109 Governor Street Suite 730 Richmond, VA 23219 Mr. J. E. Reasor, Jr.

Old Dominion Electric Cooperative Innsbrook Corporate Center 4201 Dominion Blvd.

Suite 300 Glen Allen, Virginia 23060 Dr. V. Sreenivas NRC Project Manager North Anna U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9A 11555 Rockville Pike Rockville, MD 20852-2738 NRC Senior Resident Inspector North Anna Power Station

Docket Serial No.14-595 Nos. 50-338/339 Attachment I

Response

to Request for Additional Information Virginia Electric and Power North (Dominion) Company Anna Station Units I and 2

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 1 of 32 REQUEST FOR ADDITIONAL INFORMATION TECHNICAL SPECIFICATION CHANGE PROPOSING PERMANENT FIFTEEN-YEAR TYPE A TEST INTERVAL DOCKET NUMBERS 50-338 AND 50-339 Backgqround By letter dated June 30, 2014 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML14183B318), Virginia Electric and Power Company (Dominion) requested an amendment to Operating License Numbers NPF-4 and NPF-7 in the form of changes to the Technical Specifications (TSs) for North Anna Power Station Units 1 and 2, respectively. The license amendment request (LAR) proposes a change to TS 5.5.15, "Containment Leakage Rate Testing Program," by replacing the reference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, as the implementation document used to develop the North Anna performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J. In order to complete its safety evaluation the NRC staff has the following comments and requests the following additional information.

In order to meet the due dates, please respond to these RAIs by January 16, 2015.

In a telephone conference call January 12, 2015 with the NRC staff, the NRC Project Manager concurred with Dominion providing the response to the RAI by January 31, 2015 to permit providing the final leakage results for the North Anna Unit 2 Type A test.

Mechanical and Civil Engineering Branch (EMCB):

NRC EMCB RAI-1 It is stated in Section 4.4.1 "IWE Examinations"of the LAR that the Interval 2, Period 2 of the NAPS Unit 2 Containment IWE in-service inspection is scheduled to be completed by October 2014. Please discuss the highlight of findings from this recent IWE inspection and any corrective actions taken to dispositionthe findings.

Dominion Response The IWE Examination performed during the 2014 NAPS Unit 2 refueling outage was completed satisfactorily. The original examination scope was expanded to include a new Examination Category, E-A Containment Surfaces, Item No. E1.30 - Moisture Barriers, in response to the NRC Information Notice 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner". Two deficiencies were noted and Condition Reports CR558777 and CR558783 were submitted to document these discrepancies. A missing test port panel plug (CR558777) used to test the bottom liner welds during initial construction was replaced in accordance with work order 59102772082. The

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 2 of 32 replacement was completed after the scheduled Appendix J, Type A Test in order to confirm liner integrity. Work order 59102773080 was used to clean and inspect another test port panel plug which had unidentified deposits (CR558783). Follow up general visual IWE examinations were completed satisfactorily for these two items.

NRC EMCB RAI-2 It is stated in the LAR and the current NAPS TS that the next Unit 2 integratedleak rate test (ILRT), Type A test, is currentlydue no laterthan October 9, 2014.

Please provide the following:

a. The results of as-found and as-left leak rate for the NAPS Unit 2 ILRT performed in October 2014 and a comparison with the correspondingleak rate acceptancelimit.

b. The results of visual inspection of containment concrete exterior surface areas, completed prior to the NAPS Unit 2 ILRT performed in October 2014.

Dominion Response

a. Below are the results of the 2014 NAPS Unit 2 Integrated Leak Rate Test (ILRT).

The maximum allowable containment leakage rate is 0.1% of containment air weight per day. The NAPS Unit 2 ILRT results are less than 40% of the Technical Specification limit.

Unit 2 2014 Containment Integrated Leak Rate Test As Found As Left Performance (ILRT) Results Calculated Leak Rate 0.0242 %wt/day 0.0242 %wt/day 0.0242 %wt/day Upper Confidence Limit 0.0291 %wt/day 0.0291 %wt/day 0.0291 %wt/day Leakage Savings 0 %wt/day 0 %wt/day 0 %wt/day Non-vented Penalities 0.0001 %wt/day 0 %wt/day 0 %wt/day Total Results 0.0292 %wt/day 0.0291 %wt/day 0.0291 %wt/day

b. The NAPS Unit 2 concrete examination was completed satisfactorily. Two small concrete spalls were identified adjacent to instrumentation penetration 2-PE-EP-2F1.

The minor spalls were evaluated and accepted in accordance with Dominion and industry standards (ACI 349.3R-14).

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 3 of 32 NRC EMCB RAI-3 Please provide a summary of any degradationidentified during inspections of the NAPS Unit I and Unit 2 containment liner at the interface of containment floor slab and the containment wall liner, including moisture barrier (if any). Please describe the degradation condition, corrective actions, and additional monitoring program implemented to manage the identified condition.

Dominion Response North Anna Units 1 and 2 do not have moisture barriers located at the interface. The NAPS Unit 1 IWE general visual examinations have not identified any degradation at the floor slab and containment liner interface.

The initial NAPS Unit 2 IWE general visual examinations performed in 1999 identified some areas of minor surface corrosion at the interface. Four of these areas were evaluated and documented in Engineering Transmittal (ET)-MAT-99-0003, Containment Liner and Coating Evaluation North Anna Power Station, Unit 2 and ET-CEE-99-0007, Evaluation of Reduced Containment Liner Thickness North Anna Power Station, Unit 2.

The apparent cause was due to water spraying during containment decontamination efforts during outages.

The four inaccessible areas were excavated and volumetric examinations were performed. The subsequent evaluation determined the corrosion was minimal and minor loss of liner thickness (.035 in.) was evident. Repairs, other than recoating, were not required, but augmented examinations, in accordance with Category E-C (Item E4.12), were performed satisfactorily for the next three periods. This information is documented in the Dominion letter dated April 3, 2008 (See RAI-5).

NRC EMCB RAI-4 It is stated in Section 4.0 of the LAR that although not a specific line item in the North Anna IWE program,accessible leak chase channel plugs and caps are inspected during the general visual examination completed in accordance with IWE program.

Relative to the NRC Information Notice 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner," discuss the NAPS Units I and 2 operating experience, inspection results and any corrective actions taken.

Dominion Response In response to NRC Information Notice 2014-07, a new Examination Category, E-A Containment Surfaces, Item No. E1.30 - Moisture Barriers, has been incorporated into

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 4 of 32 the North Anna Containment Inservice Inspection IWE Plan and individual Unit Implementation Schedules. For NAPS Unit 2, the additional general visual examination was completed satisfactorily. Two deficiencies were noted and Condition Reports CR558777 and CR558783 were submitted to document these discrepancies. A missing test port panel plug (CR558777) used to test the bottom liner welds during initial construction was replaced in accordance with work order 59102772082. The replacement was completed after the scheduled Appendix J, Type A Test in order to confirm liner integrity. Work order 59102773080 was used to clean and inspect another test port panel plug which had unidentified deposits (CR558783). Follow up general visual IWE examinations were completed satisfactory for these two items. The NAPS Unit 1 examination is scheduled for the upcoming 2015 refueling outage. However, most of these components (outside the In-core Instrumentation area) received a general visual inspection during the forced NAPS Unit 1 cold shutdown in December 2014. No deficiencies were noted.

NRC EMCB RAI-5 Please provide information relative to findings (if any) and actions taken where existence of or potential for degraded conditions in inaccessible areas of the NAPS Units I and 2 containment structure and steel liner were evaluated based on conditions found in accessible areas as required by IOCFR 50.55a(b)(2)(ix)(A) and I OCFR 50.55a(b)(2) (viii) (E).

Please note that in response to the NRC staff request for additionalinformation, in support of the one-time extension of the NAPS Unit 2 ILRT until 2014, Dominion, in its letter dated April 3, 2008, has alreadyprovided information relative to discovery of a blister in the NAPS Unit 2 containment liner plate protective coating that prompted an examination of the liner plate which revealed the presence of a through-thickness hole. Therefore, information relative to this finding does not need to be resubmitted.

Dominion Response The NAPS Unit 1 and 2 containment structures are in good material condition. No significant defects or concerns were observed during the last scheduled IWL examinations. NAPS Unit 1 IWL examinations were performed in July 2011 and the inspection findings are documented in Engineering Technical Evaluation (ETE)-NA-2011-0051. The inspection findings can be summarized as follows:

Five areas were identified exhibiting efflorescence or staining. These areas were sounded with a hammer and sound concrete was found with no cracking or voids. The stains appeared to be originating from abandoned inserts and tie bars and not from primary reinforcement. These areas were evaluated as inconsequential requiring no further actions.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 5 of 32 One area was identified with cracks measuring up to 0.05" in width on the top of the barrel to the equipment hatch. These are shallow cracks that are relatively short in length with no evidence of rust staining that would be indicative of degradation of the reinforcement. This area was evaluated as inconsequential and requiring no further actions.

Nineteen areas were identified as needing repair. These areas were characterized as popouts, small spalls, small holes, rock pockets or embedded steel wire. However, these areas are considered non-structural as they do not extend beyond the face of primary reinforcement (4"). As such, the completed repairs did not rise to the level of Code Repairs but were considered Cosmetic Repairs.

One area extended beyond the concrete cover and had exposed primary reinforcement.

This area required an approved Repair/Replacement plan prior to making the ASME Section Xl, Subsection IWL code repair.

Based on these inspection findings, the Unit 1 Containment structure was found to be in good material condition. No significant defects or concerns were observed on the exterior concrete and for the most part, observed defects were due to original construction flaws. Taken together or individually, the defects identified do not represent a structural concern. The Containment structure continues to retain its ability to perform as designed under all load cases including the design basis earthquake and postulated strike from a tornado generated missile. Required repairs were completed in accordance with the work management process.

The NAPS Unit 2 IWL examinations were performed in July 2011 and the inspection findings are documented in ETE-NA-2011-0052. The inspection findings can be summarized as follows:

Five areas are considered minor defects (efflorescence or staining, spall and small hole) and have been evaluated as inconsequential requiring no further actions.

The remaining twenty (20) items required only cosmetic repairs as all of the excavations were considered non-structural as they do not extend beyond the face of primary reinforcement (4").

Based on these inspection findings, no Code repairs were required and the Unit 2 Containment structure was found to be in good material condition. No significant defects or concerns were observed on the exterior concrete and observed defects were due to original construction flaws. Taken together or individually, the defects identified do not represent a significant structural concern. The Containment structure continues to retain its ability to perform as designed under all load cases including the design basis earthquake and postulated strike from a tornado generated missile. Required repairs were completed in accordance with the work management process.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 6 of 32 During the NAPS Unit 1 2009 refueling outage, general corrosion was discovered on exposed Recirculation Spray Sump test plug end caps. Additional examinations revealed several degraded grout hole test plates and plugs, pump suction well test connections, and liner test plugs in the Recirculation Spray Sump, Containment Sump, and the In-core Instrument areas. Similar examination results were found in the next NAPS Unit 2 refueling outage (2010). Repairs were conducted in accordance with Design Changes NA-09-0123 (Unit 1) and NA-09-0133 (Unit 2). To prevent further degradation of the Containment floor liner, the exposed carbon steel components of the test connections were removed from boric acid exposure. The repair approach eliminated carbon steel surfaces from Containment sumps that are exposed to boric acid, confirmed past and ensures future Containment Liner pressure retaining integrity, repaired any degraded sump pressure test connections and eliminated the potential for corrosion of the Containment liner either from direct exposure to boric acid originating from sump contents or from indirect exposure from moisture migration from adjacent grouting.

The discovery of the blister documented in Dominion letter dated April 3, 2008 led to additional examinations of the liner and basement floor interface. Four inaccessible areas were excavated, based on evidence of rust, and volumetric examinations were performed. The subsequent evaluation determined the corrosion was minimal and minor loss of liner thickness (0.035 in.) was evident. Repairs, other than recoating were not required, but augmented examinations, in accordance with Category E-C (Item E4.12), were performed satisfactory for the next three inservice inspection periods.

NRC EMCB RAI-6 Section 4.0 of the LAR, Dominion response to limitation/condition3 of NRC staff safety evaluation (SE) for NEI 94-01, Revision 2, dated June 25, 2008, states that there are no primary containment surface areas that require augmented examinations in accordance with American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (Code) Section Xl, IWE-1240. Section 4.4.1 of the LAR states that for North Anna Unit 2, Interval 2, Period 1, one area of the liner was observed to have exhibited some blistering and although no liner degradation was observed during the inspection prior to recoating, this area was considered as Category E-C (Item E4. 11) to be reexamined during the next Unit 2 refueling outage. Please provide further information regardingthe above condition and clarify whether there are any NAPS Unit 2 primary containment surface areas that require augmented examinations in accordance with ASME Code Section XI, IWE-1240.

Dominion Response As stated, one area had a relevant condition, and six additional areas were observed with blisters, and documented in CR373134. These items were cleaned, prepped,

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 7 of 32 quality inspected, repairs made to the coating, and conservatively added to the NAPS Unit 2 IWE/IWL Implementation Schedule as a Category E-C (Item 4.11) to be re-inspected. During the last NAPS Unit 2 refueling outage the required IWE detailed visual, examinations were completed satisfactory. No other augmented examinations are required.

NRC EMCB RAI-7 Please provide the following information:

a. Percent of the total number of Type B tested components that are on 120-month extended performance-basedtest interval.

b. Percent of the total number of Type C tested components that are on 60-month extended performance-basedtest interval.

Dominion Response

a. Type B tested Components NAPS Unit 1: With the exception of one, all electrical penetrations are on the extended test interval (>99%).

NAPS Unit 2: All electrical penetrations are on the extended test interval (100%).

The air locks and the fuel transfer tube are tested every refueling outage.

b. Type C Tested Components NAPS Unit 1: 92 % of all Type C valves are on the extended test interval.

NAPS Unit 2: 92 % of all Type C valves are on the extended test interval.

Although 92% of Type C valves perform well enough to be on an extended test interval, only approximately 40% are tested at that frequency. Because of scheduled maintenance and testing methods, Type C penetrations are routinely tested more frequently than the 60-month interval.

b Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 8 of 32 PRA Licensing Branch (APLA):

NRC PRA RAI-1 In the safety evaluation report for Electric Power Research Institute (EPRI) Technical Report (TR) 1009325, Revision 2, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals," the Nuclear Regulatory Commission (NRC) staff, in part, stated that for licensee requests for a permanent extension of the integrated leak rate testing (ILRT) surveillance interval to 15 years "[clapability category I of ASME RA-Sa-2003 shall be applied as the standard,since approximate values of CDF and LERF and their distribution among release categories are sufficient for use in the EPRI methodology."

Section 4.6.2 of Attachment I to the license amendment request (LAR) states that the 2013 ProbabilisticRisk Assessment (PRA) full scope peer review found that 92 percent of the supporting requirements (SRs) were met with Capability Category I/Il or greater.

Table B. I of Attachment 5 to the LAR provides the list of findings from the 2013 peer review and provides an assessment of the impact on the ILRT extension application.

a. Provide a list of all SRs from Table B. I of Attachment 5 to the LAR which did not meet Capability Category I requirements of the PRA Standard endorsed by Revision 2 of Regulatory Guide (RG) 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities." Explain why not meeting Capability Category I has no impact on the ILRT extension application.

b. Fact and observation (F&O) LE-GI-01 in Table B. I of Attachment 5 to the LAR appears to indicate that the peer review team had difficulty in completely reviewing the Level 2/LERF analysis. The finding states: "There is no adequate roadmap that facilitates peer review of the Level 2/LERF documentation." The finding further states that "[t]here are several dated self-assessment documents. For LE, about one-third of the SRs do not have any discussion of how the SR is met and where the documentation can be found. Moreover, because of the conversion of the Volume numbers (e.g. LE.2 to LE. 1), there is additional confusion added for LE. Many of the referenced sections in the self-assessment (e.g., Section 5.4.1 of LE. 1 (old LE.2)) appear to no longer exist. Finally, unlike the other technical elements that have completely revised the analysis, the Level 2 relies significantly on historicaldocuments including the 20 year old IPE, SM-1243 and SM-1464."

If the LAR provides the summary of the peer review finding LE-GI-01, please provide the complete peer review feedback for F&O LE-GI-01.

c. For F&Os LE-GI-01, IE-C3-01, AS-B6-01, AS-Cl-01, DA-D8-01, DA-D8-02, and SY-CI-01 the impact assessment provided in the LAR states that there is no impact on risk because "this is primarily a documentation enhancement." Explain

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 9 of 32 how it was determined that these gaps are limited only to documentation and have no impact on the risk results, or alternatively explain why not meeting Capability Category I will have no impact on the ILRT extension application.

Dominion Response

a. Each Fact and Observation (F&O) and the associated SR from Table B.1 of Attachment 5 to the LAR which did not meet Capability Category I requirements of the PRA Standard is listed below. The impact on the application is also included for each F&O explaining why not meeting Capability Category I has no impact on the ILRT extension application. This impact on the application discussed below is same justification provided in Table B.1 of Attachment 5 to the LAR with the exception of the F&Os specifically addressed by Part C of this RAI.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 10 of 32 F&O Issue Unmet Impact on Application SR IE-A6-01 Discussion: Common cause and routine system alignments IE-A6 (From LAR) are generally appropriately considered for complicated safety Common cause initiating system initiating event fault trees. However, for other events are expected to have systems (notably, electrical systems) there is no discussion relatively low frequencies, and or evidence of a review for initiators due to common cause of their impact on the CDF and electrical systems nor due to routine system alignments. LERF are bounded by an order GARD NF-AA-PRA-101-204C identifies that transformers, of magnitude increase. The battery chargers, and inverters are candidates for common sensitivity study in Enclosure 1 cause. These common cause failures are modeled in the of the LAR demonstrates that core damage mitigation fault trees. However, these common an order of magnitude increase cause failures are not considered as initiating events, in CDF or LERF does not particularly for RSST 4KV transformers, vital inverters, and impact acceptability of the 125VDC battery chargers. Also, for example, unavailability results for this application.

of a backup battery charger may drive a plant shutdown given loss of the normally operating charger.

In addition, could not find a discussion of why common cause blockage of service water travelling screens was not considered.

Basis for Significance: IE-A6 CAT II requires a systematic evaluation of initiating events, including events resulting from multiple failures resulting from common cause or from routine system alignments. Notebook IE.1 says that due to the independency of busses, the loss of more than one bus at a time is assessed as negligible frequency, however this statement does not consider common cause. No evidence of a systematic evaluation is evident.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 11 of 32 F&O Issue Unmet Impact on Application SR IE-C3-01 Discussion: Many recovery actions are credited in SSIE IE-C3 See response in RAI-1 Part C.

fault trees. No discussion or analysis was found to justify these credits.

Basis for Significance: SR IE-C3 requires justification for credited recoveries in initiating events. These recoveries are also used in the post-initiating event mitigation tree.

AS-B6-01 Discussion: No discussion could be identified in the AS AS-B6 See response in RAI-1 Part C.

calculation and supporting information with respect to plant configurations and maintenance practices creating dependencies among various system alignments.

Basis for Significance: System alignments could have an impact on the risk profile if unique plant configurations or maintenance practices are used.

AS-Cl-01 Discussion: Accident sequence analysis is a key element of AS-Cl See response in RAI-1 Part C.

PRA to integrate many other elements of PRA, but accident sequence notebook needs to improve for further application and update. For instance operator actions are generally described without specific governing procedures and basic event name modeled in HRA. Observations in AS-C2 provide more specific examples. Observations in AS-Cl-02 and AS-C2-01 and 02 provide more specific examples.

Basis for Significance: This would facilitate emergent risk informed applications using documents with better traceability.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 12 of 32 F&O Issue Unmet Impact on Application SR SY-C1-01 Discussion: The dependency matrix appears to address SY-C1 See response in RAI-1 Part C.

dependency for front-line systems and mechanical support systems, but appears incomplete for electrical support systems. For example, no dependency is listed for 125VDC panel 2-BY-B-2-11 or MCC 2-EP-MCC-2A1-2. In some instances the support system gate is provided, in other instances only the system name is provided.

Basis for Significance: This issue made it difficult to assess the completeness of the dependency analysis and made it difficult to assess the completeness of the identification of the systems needed to provide or support the safety functions contained in the accident sequence analysis.

HR-G6-01 Discussion: HR-G6 requires a check of the consistency of HR-G6 (From LAR) the post-initiator HEP quantifications. The instructions are to A comparison between HFEs review the HFEs and their final HEPs relative to each other to and their final HEPs for a check their reasonableness given the scenario context, plant reasonableness check was history, procedures, operational practices, and experience, performed prior to release of HR.2 states that an operator survey, which collects operator the NAPS-R07 model.

response times, was performed to meet this requirement. However, the documentation of However, the surveys do not really check the consistency of the review requires the HEP quantifications. enhancement. There is little to no impact on CDF or LERF as Basis for Significance: Confirm that quantifications are this is primarily a reasonable. documentation enhancement.

As a result, this gap has no impact on the application.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 13 of 32 F&O Issue Unmet Impact on Application SR HR-13-01 Discussion: NAPS HR.1, HR.2, HR.3 section 2.3 and HR.4 HR-13 (From LAR) section 5 addresses assumptions and uncertainties. Only There is little to no impact on source of model uncertainty listed is lack of ERO credit which CDF or LERF as this is in reality can be accounted for using the recoveries available primarily a documentation in the HRA calculator. NUREG/CR-1278 lists sources of enhancement. As a result, this uncertainty which could be referenced. gap has no impact on the application.

Basis for Significance: Need better documentation of sources of uncertainty.

DA-B2-01 Discussion: This SR instructs that outliers not be included in DA-B2 (From LAR) the definition of a data group. Looking at the NAPS Data Any change in CDF or LERF calculation outliers with zero demands were included in resulting from addressing this groups with frequently tested components. F&O is expected to be small and bounded by an order of Basis for Significance: These data events could impact risk magnitude increase. The results. sensitivity study in Enclosure 1 of the LAR demonstrates that an order of magnitude increase in CDF or LERF does not impact acceptability of the results for this application.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 14 of 32 F&O Issue Unmet Impact on Application SR DA-C14-01 Discussion: Coincident maintenance events for intersystem DA-C14 (From LAR) events have not been looked at. Need to evaluate historical Coincident maintenance may maintenance schedules to detect patterns of typical result in an increase in CDF maintenance combinations and then add these identified and LERF, but the impact is coincident maintenance events to the model. expected to be bounded by an order of magnitude. The Basis for Significance: These events could have an impact sensitivity study in Enclosure 1 on the annual risk results. Some plants have experienced a of the LAR demonstrates that significant impact to their results form including such events an order of magnitude increase in the model. in CDF or LERF does not impact acceptability of the results for this application.

DA-D8-01 Discussion: No discussion of evaluation of the impact of DA-D8 See response in RAI-1 Part C.

plant modifications on the data could be found in any of the below:

-GARD on Data (2061, 2063)

-Data Calculation and Supporting Analyses

- SY.3 System Notebooks Therefore this SR is considered to be Not Met Basis for Significance: This item could change the results from the PRA.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 15 of 32 F&O Issue Unmet Impact on Application SR DA-D8-02 Discussion: No discussion of evaluation of the impact of See response in RAI-1 Part C.

plant modifications could be found in any of the below:

-GARD on Data (2061, 2063)

-Data Calculation and Supporting Analyses

- System Notebooks Basis for Significance: Data could be impacted by a plant mod and effect risk results.

IFPP-B3-01 Discussion: No discussion is given in the various internal IFPP-B3 (From LAR) flooding notebooks with regard to the plant partitioning There is little to no impact on process or conclusions as what sources of uncertainty may CDF or LERF as this is be present or may have been introduced as part of the primarily a documentation partitioning task. Assumptions are given in Section 2.3 of the enhancement. As a result, this IF.1B notebook related to flood area definitions, though no gap has no impact on the discussion of their potential impacts to the analysis are given, application.

Sources of uncertainty related to the flooding initiating events pipe mode are included in Section 6.0 of the IF.2 notebook and repeated in Section 2.0 of the QU.4 notebook (with no other internal flooding related uncertainties added in this QU.4 notebook) while Section 5.0 of the IF.3 notebook indicates that sensitivities related to internal flooding are contained in the QU notebooks, though only sensitivity cases related to HEP and CCF values were noted which contained the overall internal flooding events in the sensitivity case model quantifications.

Basis for Significance: The SR was deemed 'not met' thus a finding level is appropriate.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 16 of 32 F&O Issue Unmet Impact on Application SR IFSO-A5-01 Discussion: The capacities of various sources are limited by IFSO-A5 (From LAR) an assumption that all flood isolations could be performed A sensitivity was performed to within 60 minutes. No basis is given for this assumption, and assess the impact of flood the potential of all scenarios using a purely assumptive basis scenarios that screened out for such inherent screening of potential impacts should also IFSN-A10 based on the 60 minute model non-isolated scenarios for the same pipe break timeframe, and the CDF impact source. Also, the treatment is inconsistent with an IF HFE of those scenarios was that is evaluated past 60 minutes. insignificant. As a result, this gap has no impact on the This F&O applies to the following SRs: IFSO-B1, IFQU-A6, IFSN-A14 application.

IFQU-A5, IFSN-A9, IFSN-A15, IFSN-A16, IFSN-A1O, IFSN-A14, and IFSN-B2.

Basis for Significance: This assumption could have IFSN-A16 significant impact to internal floods risk. REC-FLD-IRR has available time of 84 minutes, yet still analyzed for failure probability.

IFSO-B3-01 Discussion: There is no uncertainty analysis related to flood IFSO-B3 (From LAR) sources. There is little to no impact on CDF or LERF as this is Basis for Significance: Missing uncertainty analysis. SR primarily a documentation unmet. enhancement. As a result, this gap has no impact on the application.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Paae 17 of 32 F&O Issue Unmet Impact on Application SR IFSN-A5-01 Discussion: The critical height of all PRA-related SSCs is IFSN-A5 (From LAR) not given in an easy to identify single location such as the There is little to no impact on table listing of PRA-related SSCs within the various internal CDF or LERF as this is flood areas. In addition, the critical height is not always primarily a documentation defined in the other sections of the internal flooding enhancement. As a result, this notebooks such as walkdowns or area scenario discussions, gap has no impact on the only for the end-state important SSCs. application.

Basis for Significance: SR requires spatial location of SSCs which was not consistently done.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Paqe 18 of 32 F&O Issue Unmet Impact on Application SR IFQU-A6-01 Discussion: While the flooding-specific HFEs are developed IFQU-A6 (From LAR) with detailed assessments, several of the noted items in the There is little to no impact on SR were not accounted for. CDF or LERF as this is Items noted from review of SR IFQU-A6: primarily a documentation (b) The impact of the flooding on cues that the control room enhancement. As a result, this uses for a non-flooding HFEs is not discussed in the gap has no impact on the supporting spreadsheet of the internal flooding HRA application.

notebook for internal events HFEs used in the flooding analysis.

(a) The impact of the flooding on additional workload and stress in the control room uses for a non-flooding HFEs is not discussed in the supporting spreadsheet of the internal flooding HRA notebook for internal events HFEs used in the flooding analysis. In addition, the stress levels for the flooding-specific events were evaluated at low stress levels, which is inconsistent with the intent of the SR.

In addition, there appears to be inconsistent timings for the HEPs defined between the HRA calculator inputs and the NOTEBK-PRA-NAPS-IF.2 for time to perform the action (which is usually 1 minute less than the time to damage) being noted in the NOTEBK-PRA-NAPS-IF.2 notebook and the time to damage being used in the HRA calculator. This slight difference is not expected to cause significant changes, but should be reviewed for consistency and updated as needed.

Basis for Significance: The SR was deemed 'not met' thus the level of finding is appropriate.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Paae 19 of 32 F&O Issue Unmet Impact on Application I SR I QU-B5-01 Discussion: Section 3.2 of fleet wide PRA procedure NF- QU-B5 (From LAR)

AA-PRA-28 describes a method to break the circular logic There is uncertainty associated appropriately and Table 3 in SY.2 attachment lists circular with the scope and impact logic break gates, but further review of the logic indicates the associated with this modeling circular logic is not handled properly. issue. However, it is expected than the CDF and LERF impact A Gate 2-EP-CB-12A-LC "NO ELECTRIC POWER 125 V DC resulting from correcting the BUS 2-1 (U2 ESGR) (CIRC LOGIC BREAK)" is modeled circular logic break modeling under EDG 2H. The 125V DC power supply with circular would be bounded by an order logic break is supplied power only from battery under LOOP of magnitude increase. The condition which is required the EDG. However the battery sensitivity study in Enclosure 1 power is ANDed with battery charger failures as below: of the LAR demonstrates that 2-EP-CB-12A-PS-LC AND 2-BY-BC-2-I-FAIL 2-BY-BC-2C-l- an order of magnitude increase FAIL 2-BY-B-2-1 in CDF or LERF does not impact acceptability of the Basis for Significance: Improper breaking of circular logics results for this application.

would result in improper accident sequence evaluation.

Serial No.14-595 Docket Nos. 50-338/339 9 Attachment 1 Paqe 20 of 32 F&O Issue Unmet Impact on Application

____ SR LE-GI-01 Discussion: There is no adequate roadmap that facilitates LE-G1 See response in RAI-1 Part C.

peer review of the Level 2/LERF documentation. This is exacerbated by the significant reliance on historical documents going back to the original IPE report.

Basis for Significance: There are several dated self-assessment documents. For LE, about one-third of the SRs do not have any discussion of how the SR is met and where the documentation can be found. Moreover, because of the conversion of the Volume numbers (e.g. LE.2 to LE.1), there is additional confusion added for LE. Many of the referenced sections in the self-assessment (e.g., Section 5.4.1 of LE.1 (old LE.2)) appear to no longer exist. Finally, unlike the other technical elements that have completely revised the analysis, the Level 2 relies significantly on historical documents including the 20 year old IPE, SM-1243 and SM-1464.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 21 of 32

b. The LAR did not summarize the peer review finding LE-G1-01. The peer review feedback for F&O LE-G1-01 is provided below in addition to other instances in which the F&O is mentioned in the peer review report.

High Level Requirement (HLR) Summary for LERF Analysis (LE)

HLR Index HLR Summary of Assessed Number Capability for PRA HLR-LE-G The documentation of LERF Documentation of LERF analysis analysis shall be consistent with is consistent with the applicable the applicable supporting supporting requirements. All SRs requirements. are met except LE-G1. One Finding, F&O LE-G1-01, is assessed based on the difficulty of tracing the documents for ease of peer review. Additionally, a suggestion is provided regarding documentation of the capacity assessment for electrical penetration assemblies and other containment seals.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 22 of 32 Supporti g Requirements Summary for LERF Analysis Index No.

LE-G Capability Category I Capability Category II Capability Category III LE-GI DOCUMENT the LERF analysis in a manner that facilitates PRA applications, upgrades, and peer review.

F&O Assessment: Not Met LE-G1-01 Basis: Reviewed LE.1, LE.2, and LE.3. The LERF analysis is in a manner that facilitates PRA applications and upgrades. However, the documentation does not facilitate peer review and a Finding F&O is assessed.

LE-G5 IDENTIFY limitations in the LERF analysis that would impact applications.

F&O Assessment: Met LE-G1-01 Basis: Reviewed LE.1, LE.2, LE.3, and Volume QU.4 Model, Assumptions and UncertaintiesAnalysis, NOTEBK-PRA-NAPS-QU.4 Revision 0. Table 2-1 of QU.4, items 15 through 22, provide discussion of impact on applications. However, these discussions should be documented in the LE notebooks as well, or at least referenced from the LE notebooks. Hence, a link is made to a previous F&O because of the difficulty in finding such discussion during the peer review.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 23 of 32 Facts and Observations No. F&O # Level Other Issue Affected SRs 64 LE-G1-01 Finding LE-G5 Discussion: There is no adequate roadmap that facilitates peer review of the Level 2/LERF documentation. This is exacerbated by the significant reliance on historical documents going back to the original IPE report.

Basis for Significance: There are several dated self-assessment documents. For LE, about one-third of the SRs do not have any discussion of how the SR is met and where the documentation can be found. Moreover, because of the conversion of the Volume numbers (e.g., LE.2 to LE.1), there is additional confusion added for LE. Many of the referenced sections in the self-assessment (e.g., Section 5.4.1 of LE.1 (old LE.2)) appear to no longer exist. Finally, unlike the other technical elements that have completely revised the analysis, the Level 2 relies significantly on historical documents including the 20 year old IPE, SM-1243 and SM-1464.

Possible Resolution: In the LE.1 notebook, provide an SR-by-SR table of how each SR is addressed and where the documentation can be found.

c. Each of the F&Os is listed below with an explanation of why these issues were assessed as primarily documentation enhancements. Since these issues are related to documentation and do not impact the model results, they do not impact the ILRT extension application.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 24 of 32 F&O Issue Unmet Impact on Application SR IE-C3-01 Discussion: Many recovery actions are credited in IE-C3 A review of the recovery actions SSIE fault trees. No discussion or analysis was found credited in the SSIE fault trees to justify these credits, indicated that the credit taken for these actions is appropriate for Basis for Significance: SR IE-C3 requires justification support system initiating events for credited recoveries in initiating events. These based on the assumption, cues, and recoveries are also used in the post-initiating event procedures. However, justification for mitigation tree. crediting these actions is not documented and needs to be added to the model documentation. As a result, this is primarily a documentation enhancement, and there is no impact on the acceptability of the results for this application.

AS-B6-01 Discussion: No discussion could be identified in the AS-B6 A review of the plant configurations AS calculation and supporting information with respect and maintenance practices has to plant configurations and maintenance practices indicated that redundant equipment is creating dependencies among various system rotated regularly to evenly wear alignments. equipment and maximize reliability, and electrical loads are balanced Basis for Significance: System alignments could have across both trains of power. No plant an impact on the risk profile if unique plant configurations or maintenance configurations or maintenance practices are used. practices were identified that would create a dependency among system alignments that would impact the model results. As a result, this is primarily a documentation enhancement, and there is no impact on the acceptability of the results for this application.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 25 of 32 F&O Issue Unmet Impact on Application SR AS-Cl-01 Discussion: Accident sequence analysis is a key AS-Cl This F&O was assigned based on the element of PRA to integrate many other elements of traceability of information within the PRA, but accident sequence notebook needs to model documentation. However, the improve for further application and update. For instance peer review and subsequent review operator actions are generally described without of this issue by the SME did not specific governing procedures and basic event name identify any related technical errors.

modeled in HRA. Observations in AS-C2 provide more Of the referenced observations, AS-specific examples. Observations in AS-Cl-02 and AS- C1-02 and AS-C2-02 are C2-01 and 02 provide more specific examples. Suggestions, and AS-C2-01 is Met for Capability Category I. As a result, Basis for Significance: This would facilitate emergent this is primarily a documentation risk informed applications using documents with better enhancement, and there is no impact traceability. on the acceptability of the results for this application.

SY-Cl-01 Discussion: The dependency matrix appears to SY-C1 This F&O was assigned based on address dependency for front-line systems and completeness of the dependency mechanical support systems, but appears incomplete matrix with respect to electrical for electrical support systems. For example, no support systems. Although the dependency is listed for 125VDC panel 2-BY-B-2-11 or dependency matrix needs to be MCC 2-EP-MCC-2A1-2. In some instances the support enhanced to include electrical support system gate is provided, in other instances only the systems, these dependencies are system name is provided. captured in the PRA model and no technical errors have been identified.

Basis for Significance: This issue made it difficult to As a result, this is primarily a assess the completeness of the dependency analysis documentation enhancement, and and made it difficult to assess the completeness of the there is no impact on the acceptability identification of the systems needed to provide or of the results for this application.

support the safety functions contained in the accident sequence analysis.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Paae 26 of 32 F&O Issue Unmet Impact on Application I SR DA-D8- Discussion: No discussion of evaluation of the impact DA-D8 This F&O was assigned based on the 01 of plant modifications on the data could be found in any lack of guidance for including the of the below: impact of plant modifications on the data. Although the model update

-GARD on Data (2061, 2063) guidance needs to be updated to

-Data Calculation and Supporting Analyses provide these specific instructions,

- SY.3 System Notebooks plant modifications are reviewed as a part of the periodic model update Therefore this SR is considered to be Not Met process, and their impacts on the data are taken into consideration.

Basis for Significance: This item could change the This is supported by the calculations results from the PRA. in the data analysis documentation.

DA-D8- Discussion: No discussion of evaluation of the impact As a result, this is primarily a 02 of plant modifications could be found in any of the documentation enhancement, and below: there is no impact on the acceptability

-GARD on Data (2061, 2063) of the results for this application.

-Data Calculation and Supporting Analyses

- System Notebooks Basis for Significance: Data could be impacted by a plant mod and effect risk results.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 27 of 32 F&O Issue Unmet Impact on Application SR LE-G1-01 Discussion: There is no adequate roadmap that LE-G1 This F&O was assigned primarily due facilitates peer review of the Level 2/LERF to the lack of an adequate roadmap documentation. This is exacerbated by the significant to facilitate the peer review by reliance on historical documents going back to the providing discussion of how each SR original IPE report. was met and the location of supporting documentation. In Basis for Significance: There are several dated self- addition, changes in the LE document assessment documents. For LE, about one-third of the structure have not been reflected in SRs do not have any discussion of how the SR is met the self-assessment document and where the documentation can be found. Moreover, references. Although these because of the conversion of the Volume numbers (e.g. documentation issues need to be LE.2 to LE.1), there is additional confusion added for addressed, no technical errors were LE. Many of the referenced sections in the self- identified that would impact the model assessment (e.g., Section 5.4.1 of LE.1 (old LE.2)) results, and all other LE SRs were appear to no longer exist. Finally, unlike the other considered met. Reliance on the IPE technical elements that have completely revised the and other historical documents is analysis, the Level 2 relies significantly on historical acceptable since the information documents including the 20 year old IPE, SM-1243 and contained in these documents is still SM-1464. relevant. As a result, this is primarily a documentation enhancement, and there is no impact on the acceptability of the results for this application.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 28 of 32 NRC PRA RAI-2 Section 4.4 of the LAR uses the Calvert Cliffs Nuclear Power Plant methodology in evaluating the impact of liner corrosion on the extension of ILRT testing intervals. This assessment was based on two observed corrosion events at North Anna Power Station, Unit 2 and Brunswick Steam Electric Plant, Unit 2. Additionally, the LAR references a data search performed by Peach Bottom Atomic Power Station in 2010, reviewing more recent liner corrosion events. If there have been additionalinstances of liner corrosion that could be relevant to this assessment, provide an updated list of observed corrosion events relevant to North Anna containment, and an evaluation of the impact on risk results when all relevant corrosion events are included in the risk assessment.

Dominion Response Two corrosion events occurring over a 5.5-year period starting in September 1996 were used to estimate the liner flaw probability in the Calvert Cliffs analysis. Peach Bottom Atomic Power Station documented a data search in 2010 which identified two liner corrosion events with through-wall holes occurring since the original data period.

Dominion performed a data search to determine if more recent instances of liner corrosion with through-wall holes have occurred that could be relevant to this assessment, and two were identified. In October 2010, an area 4" by 32" was found to be significantly degraded, including through-wall damage, in the Turkey Point 3 containment liner. In October 2013, a 0.40" by 0.28" through-wall hole was identified in the Beaver Valley 1 containment liner. The liner flaw probability with six events occurring over an 18-year period based on the inclusion of all relevant corrosion events is adequately represented by the two events occurring in the 5.5-year period of the Calvert Cliffs analysis. As a result, the inclusion of all relevant corrosion events has no impact on the steel liner corrosion analysis and the results of the risk assessment.

NRC PRA RAI-3 Section 4.2.6 of EPRI TR-1009325, Revision 2-A states that "[pilants that rely on containment overpressure for net positive suction head (NPSH) for emergency core cooling system (ECCS) injection for certain accident sequences may experience an increase in CDF", therefore requiring a risk assessment. The fourth condition in the safety evaluation report for EPRI TR-1009325, Revision 2 states that "[a] LAR is required in instances where containment over-pressure is relied upon for ECCS performance." Section 5.8 of Attachment 4 to the LAR states that the design basis calculations credit containment overpressure to satisfy net positive suction head (NPSH) requirements for recirculation spray (RS) and low head safety injection (LHSI) pumps during loss of coolant accidents. The MAAP analyses discussed in Attachment 4 of the LAR are intended to demonstrate that adequate NPSH is available assuming an increasedcontainment leak rate.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 29 of 32

a. The MAAP calculations performed in the LAR analyzed the following break size LOCAs: 1 inch, 2 inch, 4 inch, 6 inch and 31 inch. Describe the basis for the selection of the break sizes analyzed and discuss how they compare to the design basis calculations crediting containment overpressure.

b. Discuss any key assumptions in the MAAP analysis that may be non-conservative and impacting the loss of NPSH assessment.

c. Attachment A, "MAAP Analyses," included in Attachment 4 of the LAR states that the presented MAAP results "did not include any loss of NPSH. This is well demonstrated by Figures D- I through D-5." Explain how these figures indicate that the available NPSH is sufficient for operation of the RS and LHSI pumps.

Dominion Response

a. The break sizes were selected to cover the wide range of LOCAs including Small, Medium and Large Break LOCAs and demonstrate that there is always sufficient NPSH to the pumps regardless of the break size/LOCA type. Unlike PRA, the design basis analysis only models Large Break LOCA with double-ended rupture of hot leg (corresponds to 31" break MAAP case) for NPSH calculation by providing justification that it is the bounding scenario.

b. No non-conservative assumptions were made.

c. Investigation of the summary output files for all cases identified no indication of loss of NPSH for any pumps, nor did it show any signs of core uncovery and damage. The sump water level plots were provided to demonstrate the availability and stability of the water level in the sump with the underlying conclusion that no core uncovery happens.

Containment and Ventilation Branch (SCVB):

NRC SCVB RAI-1 Referring to Attachment I of letter dated June 30, 2014, Section 2.0, "Proposed Change", states:

North Anna TS 5.5.15 currently states: "A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, modified by the following exception:

NEI-94-01-1995, Section 9.2.3: The first Unit 2 Type A test performed after the October 9, 1999 Type A test shall be performed no later than October 9, 2014."

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 30 of 32 The licensee proposes to revise TS 5.5.15 as follows:

"Aprogram shall establish the leakage rate testing of the containment as requiredby 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 2012."

The proposed TS 5.5.15 language refers to Revision 3-A of NEI 94-01 which does not contain the limitations and conditions for the extension of the Type A testing that are requiredin NEI 94-01 Revision 2-A. The current NRC staff position is as follows:

• Licensees that plan to extend Type A test interval up to 15 years and do not plan to extend Type C test intervals beyond 60 months should reference NEI 94-01, Revision 2-A.

• Licensees that plan to extend Type A test interval up to 15 years and/or acquire the option to plan to extend Type C test intervals beyond 60 months up to 75 months should reference NEI 94-01, Revision 3-A as well as the limitations and conditions requiredin the NRC staff Safety Evaluation Report for NEI 94-01 Revision 2-A.

OR

" Licensee that does not prefer to reference NEI 94-01 Revision 2-A in TS 5.5.15 shall include the following requirements in the TS 5.5.15:

1. For calculating the Type A leakage rate, the licensee should use the definition in the NEI TR 94-01, Revision 2, in lieu of that in ANSI/ANS-56.8-2002. (Refer to Section 3.1.1.1 of NRC Safety Evaluation Report for NEI 94-01 Revision 2)

2. The licensee submits a schedule of containment inspections to be performed prior to and between Type A tests. (Refer to Section 3.1.1.1 of NRC Safety Evaluation Report for NEI 94-01 Revision 2)

3. The licensee addresses the areas of the containment structure, potentially subjected to degradation. (Refer to Section 3.1.1.1 of NRC Safety Evaluation Report for NEI 94-01 Revision 2)

4. The licensee addresses any tests and inspections performed following major modifications to the containment structure, as applicable. (Refer to Section 3.1.4 of NRC Safety Evaluation Report for NEI 94-01 Revision 2)

5. The normal Type A test interval should be less than 15 years. If a licensee has to utilize the provision of Section 9.1 of NEI TR 94-01, Revision 2, related to

Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 31 of 32 extending the ILRT interval beyond 15 years, the licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition. (Refer to Section 3.1.1.2 of NRC Safety Evaluation Report for NEI 94-01 Revision 2)

Explain and/or revise the license language to reflect the above for further review.

Dominion Response Section 5.5.15 will be revised to include a discussion of the Limitations and Conditions contained in Section 4.1 of NEI TR 94-01, Revision 2 of the NRC Safety Evaluation Report in NEI 94-01 Revision 2A, dated October 2008. The revised TS page is attached in Attachment 2 to this letter.

NRC SCVB RAI-2 Refer to Attachment 1, Section 2.0, page 2 of 20, in the second from last line the words "currently states" appears to be an editorial error. Please provide further clarification/explanation.

Dominion Response The "currently states" in the paragraph above is a typographical error. The paragraph below corrects the typographical error and includes the condition and limitations from NEI 94-01 Revision 2A.

TS 5.5.15, "Containment Leakage Rate Testing Program,": "A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 2012 and Section 4.1, "Limitations and Conditions for NEI TR 94-01, Revision 2" of the NRC Safety Evaluation Report in NEI 94-01 Revision 2A, dated October 2008.

4 Serial No.14-595 Docket Nos. 50-338/339 Attachment 1 Page 32 of 32 References

[1] Industry Guideline for Implementing Performance-BasedOption of 10 CFR Part 50, Appendix J, NEI 94-01 Revision 2-A, October 2008.

[2] Nuclear Energy Institute, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, NEI 94-01 Revision 3-A, July 2012.

[3] Letter from U.S. Nuclear Regulatory Commission to Biff Bradley (Director, Nuclear Energy Institute), REQUEST REVISION TO TOPICAL REPORT NEI 94-01, REVISION 3-A, "lndustry Guideline for Implementing Performance-Based Option of 10 CFR PART 50, Appendix J", Accession Number ML13192A394, August 20, 2013.

[4] Letter from Dominion to U.S. Nuclear Regulatory Commission, Virginia Electric Power Company North Anna Power Station Units 1 and 2 Proposed License Amendment Request Permanent Fifteen-Year Type A Test Interval, June 30, 2014.

Serial No.14-595 Docket Nos. 50-338/339 Attachment 2 Revised Marked-up Technical Specification Page Virginia Electric and Power Company (Dominion)

North Anna Station Units I and 2

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Safety Function Determination Program (SFDP) (continued) analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

5.5.15 Containment Leakage Rate Testing Program

a. A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Program," dated Septerbr19 as mno di-ýc -1

b. The calculated peak containment iternal p ssure for the design 9401 ENE 3A"nust Reiso design pressure is 45 Guidel.inpsig. .o Impleme fPeF ntn 111orý Mance-asd Option of efeme l0CRP*5,apperhndi J,"dtoued uy21 ndScin41 Lmttos

c. The maximum allowable containme tleakage rate, La, at Pa shall CodThen b.n TR9-1,Rvsontainmenth calulte peak NRC SaeyEaution deposign NEI 9d

__NEI 94-01, Revision 2-A,"datd Octobry Guidlin fo mlmnigPefrac-North Anna Units 1 and 2 5.5-15 Amendments 269ýý

Serial No.14-595 Docket Nos. 50-338/339 Attachment 3 Revised Proposed Technical Specification Page Virginia Electric and Power Company (Dominion)

North Anna Station Units 1 and 2

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Safety Function Determination Program (SFDP) (continued) analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

5.5.15 Containment Leakage Rate Testing Program

a. A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 2012 and Section 4.1 "Limitations and Conditions for NEI TR 94-01, Revision 2" of the NRC Safety Evaluation Report in NEI 94-01, Revision 2A, dated October 2008.

b. The calculated peak containment internal pressure for the design basis loss of coolant accident, Pas is 42.7 psig. The containment design pressure is 45 psig.

c. The maximum allowable containment leakage rate, La, at Pas shall be 0.1% of containment air weight per day.

(continued)

North Anna Units I and 2 5.5-15 Amendments