ML17311A162

Issuance of Amendments Regarding Permanent Extension of Type a and Type C Leak Rate Test Frequencies

ML17311A162
Person / Time
Site:	Quad Cities
Issue date:	12/01/2017
From:	Kimberly Green Plant Licensing Branch III
To:	Bryan Hanson Exelon Generation Co, Exelon Nuclear
GreenK, NRR/DORL/LPL3, 415-1627
References
CAC MF9675, CAC MF9676, EPID L-2017-LLA-0220, RS-17-051
Download: ML17311A162 (30)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 December 1, 2017 Mr. Bryan C. Hanson Senior Vice President Exelon Generation Company, LLC President and Chief Nuclear Officer (CNO)

Exelon Nuclear 4300 Winfield Road Warrenville, IL 60555

SUBJECT:

QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2- ISSUANCE OF AMENDMENTS REGARDING PERMANENT EXTENSION OF TYPE A AND TYPE C LEAK RATE TEST FREQUENCIES (CAC. NOS. MF9675 AND MF9676; EPID L-2017-LLA-0220) (RS-17-051)

Dear Mr. Hanson:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 269 to Renewed Facility Operating License No. DPR-29 and Amendment No. 264 to Renewed Facility Operating License No. DPR-30 for Quad Cities Nuclear Power Station, Units 1 and 2. The amendments consist of changes to the technical specifications (TSs) in response to your application dated April 27, 2017, as supplemented by letters dated July 27 and September 28, 2017.

The amendments revise TS 5.5.12, "Primary Containment Leakage Rate Testing Program," to allow for the permanent extension of the Type A integrated leak rate testing and Type C leak rate testing frequencies by replacing the reference to Regulatory Guide 1.163 with a reference to Nuclear Energy Institute 94-01, Revisions 2-A and 3-A. In addition, the amendments delete a Type A test extension that expired in 2009 for Unit 1, and 2008 for Unit 2, from TS 5.5.12.a.

A copy of the Safety Evaluation is also enclosed. The Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely, K ~ r o j e c t Manager Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-254 and 50-265

Enclosures:

1. Amendment No. 269 to DPR-29

2. Amendment No. 264 to DPR-30

3. Safety Evaluation cc w/encls: Distribution via Listserv

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 EXELON GENERATION COMPANY, LLC AND MIDAMERICAN ENERGY COMPANY DOCKET NO. 50-254 QUAD CITIES NUCLEAR POWER STATION, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 269 Renewed License No. DPR-29

1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by the Exelon Generation Company, LLC (the licensee) dated April 27, 2017, as supplemented by letters dated July 27 and September 28, 2017, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 3.B of Renewed Facility Operating License No. DPR-29 is hereby amended to read as follows:

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 269, are hereby incorporated into this renewed operating Enclosure 1

license. The licensee shall operate the facility in accordance with the Technical Specifications.

3. This license amendment is effective as of the date of its issuance and shall be implemented within 30 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION C) J 9 ,./---

David J. Wrona, Chief Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Renewed Facility Operating License Date of Issuance: December 1, 2017

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 EXELON GENERATION COMPANY, LLC AND MIDAMERICAN ENERGY COMPANY DOCKET NO. 50-265 QUAD CITIES NUCLEAR POWER STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 264 Renewed License No. DPR-30

1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by the Exelon Generation Company, LLC (the licensee) dated April 27, 2017, as supplemented by letters dated July 27 and September 28, 2017, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 3.B of Renewed Facility Operating License No. DPR-30 is hereby amended to read as follows:

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 264, are hereby incorporated into this renewed operating Enclosure 2

license. The licensee shall operate the facility in accordance with the Technical Specifications.

3. This license amendment is effective as of the date of its issuance and shall be implemented within 30 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION OJ9M------

David J. Wrona, Chief Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Renewed Facility Operating License Date of Issuance: December 1, 2017

ATTACHMENT TO LICENSE AMENDMENT NOS. 269 AND 264 QUAD CITIES NUCLEAR POWER STATION, UNITS 1 and 2 RENEWED FACILITY OPERATING LICENSE NOS. DPR-29 AND DPR-30 DOCKET NOS. 50-254 AND 50-265 Replace the following pages of the Renewed Facility Operating License and Appendix A Technical Specifications with the attached pages. The revised pages are identified by amendment number and contain marginal lines indicating the area of change.

Remove Insert License DRP-29 License DPR-29 Page 4 Page 4 License DPR-30 License DPR-30 Page 4 Page 4 TSs TSs Page 5.5-11 Page 5.5-11 Page 5.5-12 Page 5.5-12

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 269, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

C. The licensee shall maintain the commitments made in response to the March 14, 1983, NUREG-0737 Order, subject to the following provision:

The licensee may make changes to commitments made in response to the March 14, 1983, NUREG-0737 Order without prior approval of the Commission as long as the change would be permitted without NRG approval, pursuant to the requirements of 10 CFR 50.59. Consistent with this regulation, if the change results in an Un reviewed Safety Question, a license amendment shall be submitted to the NRG staff for review and approval prior to implementation of the change.

D. Equalizer Valve Restriction Three of the four valves in the equalizer piping between the recirculation loops shall be closed at all times during reactor operation with one bypass valve open to allow for thermal expansion of water.

E. The licensee shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822), and the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined sets of plans 1, which contain Safeguards Information protected under 10 CFR 73.21, is entitled: "Quad Cities Nuclear Power Station Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, Revision 2," submitted by letter dated May 17, 2006.

Exelon Generation Company shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p).

The Exelon Generation Company CSP was approved by License Amendment No. 249 as modified by License Amendment No. 259.

F. The licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report for the facility and as approved in the Safety Evaluation Reports dated July 27, 1979 with supplements dated November 5, 1980, and 1 The Training and Qualification Plan and Safeguards Contingency Plan are Appendices to the Security Plan.

Renewed License No. DPR-29 Amendment No. 269

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 264, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

C. The licensee shall maintain the commitments made in response to the March 14, 1983, NUREG-0737 Order, subject to the following provision:

The licensee may make changes to commitments made in response to the March 14, 1983, NUREG-0737 Order without prior approval of the Commission as long as the change would be permitted without NRG approval, pursuant to the requirements of 10 CFR 50.59. Consistent with this regulation, if the change results in an Unreviewed Safety Question, a license amendment shall be submitted to the NRC staff for review and approval prior to implementation of the change.

D. Equalizer Valve Restriction Three of the four valves in the equalizer piping between the recirculation loops shall be closed at all times during reactor operation with one bypass valve open to allow for thermal expansion of water.

E. The licensee shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822), and the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined sets of plans 1, which contain Safeguards Information protected under 10 CFR 73.21, is entitled: "Quad Cities Nuclear Power Station Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, Revision 2," submitted by letter dated May 17, 2006.

Exelon Generation Company shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p).

The Exelon Generation Company CSP was approved by License Amendment No. 244 and modified by License Amendment No. 254.

F. The licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report for the facility and as approved in the Safety Evaluation Reports dated July 27, 1979 with supplements dated 1

The Training and Qualification Plan and Safeguards Contingency Plan are Appendices to the Security Plan.

Renewed License No. DPR-30 Amendment No. 264

Programs and Manuals 5.5 5.5 Programs and Manuals

5. 5 .11 Safety Function Determination Program (SFDP) (continued)

b. A loss of safety function exists when, assuming no concurrent single failure, and assuming no concurrent loss of offsite power or loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

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

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

3. A required system redundant to support system(s) for the supported systems described in b.l and b.2 above is also inoperable.

c. 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. 12 Primary Containment Leakage Rate Testing Program

a. This program shall establish the leakage testing of the primary containment as required by 10 CFR 50.54(ol 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, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.

(continued)

Quad Cities 1 and 2 5.5-11 Amendment No. 269/264

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Primary Containment Leakage Rate Testing Program (continued)

b. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 43.9 psig.

c. The maximum allowable primary containment leakage rate, La, at Pa, is 3% of primary containment air weight per day.

d. Leakage rate acceptance criteria are:

1. Primary containment overall leakage rate acceptance criterion is~ 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are~ 0.60 La for the combined Type Band Type C tests, and~ 0.75 La for Type A tests.

2. Air lock testing acceptance criteria is the overall air lock leakage rate is~ 0.05 La when tested at~ Pa.

e. The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program.

5.5.13 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Ventilation (CREV) System, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (OBA) conditions without personnel receiving radiation exposure in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident. The program shall include the following elements:

a. The definition of the CRE and the CRE boundary.

b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive (continued)

Quad Cities 1 and 2 5.5-12 Amendment No. 269/264

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 269 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-29 AND AMENDMENT NO. 264 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-30 EXELON GENERATION COMPANY, LLC AND MIDAMERICAN ENERGY COMPANY QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 DOCKET NOS. 50-254 AND 50-265

1.0 INTRODUCTION

By application dated April 27, 2017 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17121A449), as supplemented by letters dated July 27 and September 28, 2017 (ADAMS Accession Nos. ML17208A849 and ML17271A099, respectively),

Exelon Generation Company, LLC (EGC or the licensee) submitted a license amendment request (LAR) for Quad Cities Nuclear Power Station, Units 1 and 2 (QCNPS). The LAR proposes changes to Technical Specification (TS) 5.5.12, "Primary Containment Leakage Rate Testing Program," for the permanent extension of the Type A integrated leak rate test (ILRT) interval from 10 years to 15 years, in accordance with Nuclear Energy Institute (NEI) 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR [Title 1O of the Code of Federal Regulations] Part 50, Appendix J" (ADAMS Accession No. ML12221A202), and the limitations and conditions specified in NEI 94-01, Revision 2-A (ADAMS Accession No. ML100620847). The LAR also proposes to extend the containment isolation valves (CIVs) leakage rate testing (i.e., Type C tests) frequency from the 60 months, currently permitted, to 75 months by replacing the TS 5.5.12.a reference to Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program" (ADAMS Accession No. ML003740058), with a reference to NEI 94-01, Revision 3-A.

In addition, the LAR proposes the deletion of a Type A test extension that expired in 2009 for Unit 1, and 2008 for Unit 2 from TS 5.5.12.a.

Enclosure 3

The supplemental letters dated July 27 and September 28, 2017, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC or Commission) staff's original proposed no significant hazards consideration determination as published in the Federal Register (FR) on June 19, 2017 (82 FR 27888).

2.0 REGULATORY EVALUATION

The LAR requested a change to the Renewed Facility Operating Licenses for QCNPS, in accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit."

The regulations in 10 CFR 50.36(c)(5), "Administrative controls," require, in part, the inclusion of administrative controls in TSs that are necessary to assure operation of the facility in a safe manner. This LAR requests a change to "Administrative Controls" section of the QCNPS TSs.

Paragraph (o) of 10 CFR 50.54, "Conditions of licenses," requires that primary reactor containments for water-cooled power reactors be subject to the requirements in 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." Appendix J contains two options: Option A- Prescriptive Requirements and Option B - Performance-Based Requirements, either of which can be used to meet Appendix J requirements. The testing requirements in Appendix J ensure that: (a) leakage through containments or systems and components penetrating containments does not exceed allowable leakage rates specified in the TSs, and (b) integrity of the containment structure is maintained during the service life of the containment. QCNPS, Units 1 and 2, adopted 10 CFR 50, Appendix J, Option B for Type A (ILRT), and Type Band Type C (LLRT) by license amendments 169 and 165, dated January 11, 1996 (ADAMS Accession No. ML021160123).

Section V.B.3 of 10 CFR 50, Appendix J, Option B, requires the licensee to develop a performance-based leakage-testing program using the RG or other implementation document and referencing it in the plant TSs .. The submittal for TS revisions must also contain justification, including supporting analyses, if the licensee deviates from methods approved by the NRC and endorsed in RG 1.163, "Performance-Based Containment Leak-Test Program."

Option B specifies performance-based requirements and criteria for preoperational and subsequent leakage rate testing. These requirements are met by:

1. Type A tests to measure the containment system overall integrated leakage rate,

2. Type B pneumatic tests to detect and measure local leakage rates across pressure retaining leakage-limiting boundaries such as penetrations, and

3. Type C pneumatic tests to measure CIV leakage rates.

After the containment system has been completed and is ready for operation, Type A tests are conducted at periodic intervals based on the historical performance of the overall containment system to measure the overall integrated leakage rate. The leakage rate test results must not exceed the maximum allowable leakage (La) at design-basis loss-of-coolant accident (DBLOCA) pressure (Pa) with margin, as specified in the TSs. Option B also requires that a general visual inspection for structural deterioration of the accessible interior and exterior surfaces of the containment system, which may affect the containment leaktight integrity, be conducted prior to

each Type A test and at a periodic interval between tests based on the performance of the containment system.

Type B and Type C tests are performed based on the safety significance and historical performance of each boundary and isolation valve to ensure integrity of the overall containment system as a barrier to fission product release.

Section 50.55a, "Codes and standards," of 10 CFR contains the containment inservice inspection (ISi) requirements, which, in conjunction with the requirements of 10 CFR Part 50, Appendix J, ensure the continued leaktight and structural integrity of the containment during its service life.

Section 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," paragraph (a)(1 ), states, in part, that the licensee:

... shall monitor the performance or condition of structures, systems, or components, against licensee-established goals, in a manner sufficient to provide reasonable assurance that these structures, systems, and components, ... are capable of fulfilling their intended functions. These goals shall be established commensurate with safety and, where practical, take into account industry-wide operating experience.

NEI 94-01, Revision O (ADAMS Accession No. ML11327A025), provides methods for complying with the provisions of 10 CFR Part 50, Appendix J, Option B, and includes provisions that address the extension of the performance-based Type A test interval for up to 1O years, based upon two consecutive successful tests.

The final safety evaluation (SE) for NEI Topical Report (TR) 94-01, Revision 2, "Industry Guideline For Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals," dated June 25, 2008 (ADAMS Accession No. ML081140105), states that NEI 94-01, Revision 2, describes an acceptable approach for implementing the optional performance-based requirements of 10 CFR Part 50, Appendix J, Option B. The NRC staff concluded that NEI 94-01, Revision 2, is acceptable for referencing by licensees proposing to amend their containment leakage rate testing TSs, subject to the specific limitations and conditions listed in Section 4.1 of the SE.

NEI 94-01, Revision 2-A, incorporates the regulatory positions stated in RG 1.163, and includes provisions for extending Type A test intervals up to 15 years.

EPRI Report No. 1009325, Revision 2 1, provides a generic assessment of the risks associated with a permanent extension of the ILRT surveillance interval to 15 years, and a risk-informed methodology/template to be used to confirm the risk impact of the ILRT extension on a plant-specific basis. Probabilistic risk assessment (PRA) methods are used, in combination with ILRT performance data and other considerations, to justify the extension of the ILRT surveillance interval. This is consistent with guidance provided in RGs 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the 1 EPRI Report 1018243 is also identified as EPRI Report 1009325, Revision 2-A. This report is publicly available and can be found at www.epri.com by typing "1018243" in the search box.

Licensing Basis," and 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications," to support changes to surveillance test intervals. In the SE dated June 25, 2008, the NRC staff concluded that the methodology in EPRI Report No. 1009325, Revision 2, is acceptable for referencing by licensees proposing to amend their TSs to permanently extend the ILRT surveillance interval to 15 years provided four conditions are satisfied.

NEI 94-01, Revision 3-A, July 2012, provides guidance for extending Type C local leak rate test (LLRT) intervals beyond 60 months. The NRC published an SE with limitations and conditions for NEI 94-01, Revision 3, by letter dated June 8, 2012 (ADAMS Accession No. ML121030286).

In the SE, the NRC concluded that NEI 94-01, Revision 3, describes an acceptable approach for implementing the optional performance-based requirements of Appendix J, and is acceptable for reference by licensees proposing to amend their containment leakage rate testing TSs, subject to two conditions. The SE was incorporated into Revision 3 and subsequently issued as NEI 94-01, Revision 3-A, on July 31, 2012.

3.0 TECHNICAL EVALUATION

3.1 Licensee's Proposed Changes QCNPS TS 5.5.12 currently states, in part:

This program shall establish the leakage testing of the primary containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemption. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Testing Program," dated September 1995, as modified by the following exceptions:

1. NEI 94 1995, Section 9.2.3: The first Unit 1 Type A test performed after the July 23, 1994, Type A test shall be performed no later than July 22, 2009.

2. NEI 94 1995, Section 9.2.3: The first Unit 2 Type A test performed after the May 17, 1993, Type A test shall be performed no later than May 16, 2008.

With the proposed changes, QCNPS, TS 5.5.12, would state, in part:

This program shall establish the leakage testing of the primary containment as required by 10 CFR 50.54(0) 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, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.

With this change, the licensee will implement the guidance of NEI 94-01, Revision 3-A, and the limitations and conditions of NEI 94-01, Revision 2-A rather than those of NEI 94-01, Revision 0, that were endorsed by RG 1.163, Revision 0. This is allowed by the provision in 10 CFR 50, Appendix J, Option B,Section V.B.3, regarding the TS referencing the NRC staff approved guidance document for program implementation. NEI 94-01, Revision 3-A provides that extension of the Type A test (ILRT) interval to 15 years be based on two consecutive successful

Type A tests (performance history) and other requirements stated in Section 9.2.3 of NEI 94-01.

The basis for acceptability of extending the Type A test interval also includes implementation of robust Type B and Type C testing of the penetration barriers where most containment leakage has historically been shown to occur and are expected to continue to be the pathways for a majority of potential primary containment leakage; and of a robust containment visual inspection program where deterioration of the primary containment boundary away from penetrations can be detected and remediated before any actual significant leakage potential were to develop.

NEI 94-01, Revision 3-A also provides that Type C test intervals may be extended to 75 months based on two consecutive successful tests (performance history) and meeting other specified conditions.

The existing QCNPS TS 5.5.12 exceptions to NEI 94-01 regarding specific dates, by which the then next Type A tests were required, were included in the TS with implementation of one-time ILRT interval extensions approved in Amendments 220 and 214, issued on March 8, 2004 (ADAMS Accession No. ML040280368). These exceptions are no longer needed because those dates have passed with the tests having been completed. Therefore, the licensee has proposed their deletion.

3.2 Description of the Primary Containment QCNPS, Units 1 and 2, are General Electric boiling-water reactors (BWRs) with Mark I water pool pressure suppression design primary containments. These primary containments consist of a carbon steel pressure vessel with a drywell volume composed of a domed removable head on top of a cylindrical upper section and spherical lower section and a wetwell volume in the shape of a torus that is roughly half-way filled with water. The drywell is mostly above and centered over the wetwell and these volumes are connected by large vent pipes. The drywell houses the reactor vessel, the recirculation loops, main steam lines, and other branch connections of the reactor coolant system. The drywell is surrounded by a reinforced concrete shield structure and is separated from it on the sides by a small gap to accommodate relative displacements. This arrangement limits primary containment pressurization from a DBLOCA by channeling steam and heated drywell atmosphere into the suppression pool where condensation and cooling of the containment atmosphere occurs during initial blowdown. The suppression pool also serves as a water source for emergency core cooling and containment spray injection recirculation flow.

The primary containment provides the "leak tight" barrier against the potential uncontrolled release of fission products during a DBLOCA. Technical Specification 5.5.12 identifies the primary containment La as 3 percent of the containment air weight per day at the calculated Pa of 43.9 pounds per square inch gauge.

3.3 Type A Integrated Leak Rate Test History In LAR Table 3.3-1, QCNPS, Units 1 and 2, Type A ILRT Test History, the licensee presented the historical results of the Unit 1 and 2 tests as summarized below.

Unit/ Test Date Leakage Rate Leakage Rate Performance Criterion (Primary Containment Atmosphere (Primary Containment Atmosphere Percent WeiQht per Day) WeiQht Percent per Dav) 1 / December 1992 0.6926 1.0 1 / July 1994 0.6168 1.0 1 / May, 2009 1.1419 3.0

2 I Ma 1993 0.7359 1.0 2 I March 2008 0.5992 3.0 The ILRT performance criterion (La) was changed from 1.0 weight percent per day to 3.0 weight percent per day with implementation of a new design basis radiological analysis (10 CFR 50.67, "Accident Source Term") approved in license amendments 233 and 229 on September 11, 2006 (ADAMS Accession No. ML062070290).

The NEI 94-01, Revision 3-A, requirement for allowing the extended test interval is that the past two tests meet the performance criterion by showing a leakage of La or less. The 1994 and 2009 Unit 1, and 1993 and 2008 Unit 2 ILRT results showed the performance criterion had been met, so the extended interval would be allowed. Considering variables such as changes in test pressure and testing methodology, past testing results generally showed ample margin and no discernable adverse trend or pattern and thus suggest that an ILRT interval of 15 years would not result in exceeding the performance criterion for either unit. Therefore, the NRC staff concludes that a permanent extension to the test frequency of 15 years in accordance with NEI 94-01, Revision 3-A, and the limitations and conditions set of NEI 94-01, Revision 2-A, is acceptable.

3.4 Historical Type Band Type C Test Results Combined Totals In LAR Tables 3.5-9 and 3.5-10, the licensee presented the historical results of the Types Band C test combined as-found minimum pathway leakage totals for QCNPS, Units 1 and 2, as summarized below:

QCNPS, Unit 1 Refuel Outage/ Year As-Found Minimum Pathway Fraction of TS 5.5.12 Combined Leakage Rate Type B and C Performance Criterion (standard cubic feet per hour) (scfh) with Margin (0.6 La)

R19 / 2007 134.057 0.1627 R20 / 2009 229.078 0.2781 R21 / 2011 184.265 0.2237 R22 / 2013 544.56 0.6610 R23 / 2015 283.592 0.3443 QCNPS, Unit 2 Refuel Outage/ Year As-Found Minimum Pathway Fraction of TS 5.5.12 Combined Leakage Rate Type B and C Performance Criterion (standard cubic feet per hour) (scfh) with Marqin (0.6 La)

R19 / 2008 106.137 0.1288 R20 / 2010 189.452 0.2300 R21 / 2012 200.995 0.2440 R22 / 2014 470.624 0.5713 R23 / 2016 315.866 0.3834 The TS 5.5.12 specified margin for the combined Types Band C test total, summed from the as-found minimum pathway leakage values, is 0.6 La. The licensee stated in LAR Section 3.5.4 that 0.6 La is 823.79 standard cubic feet per hour (scfh). The combined Types Band C test totals tabulated above show sufficient additional margin to suggest that the performance criteria are unlikely to be exceeded by allowing the QCNPS, Units 1 and 2, ILRT maximum interval to be extended to 15 years or the Type C test intervals to be extended to 75 months.

NRC Staff Evaluation

Based on the review of the data contained in LAR Tables 3.5-9 and 3.5-10, the NRC staff concludes that the aggregate results of the as-found trend summaries for the Types B and C tests from 2007 to 2015 (Unit 1) and 2008 to 2016 (Unit 2) generally demonstrate a history of successful tests. Furthermore, the tables show that there have been no as-found failures that resulted in exceeding the TS 5.5.12 acceptance criterion of 0.6 La.

3.5 Inspection and Testing Programs The LAR provides evaluations of other non-risk considerations related to the proposed amendment. This includes the inspection and testing programs that ensure the containment structure remains capable of meeting the design functions and identification of degraded conditions which may affect the containment capability.

3.5.1 Safety-Related Coatings Inspection Program In Section 3.5.1 of the LAR, the licensee describes its safety-related coatings inspection program. The program is conducted in accordance with RG 1.54, "Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants,"

Revision 0. The program ensures that qualified coatings are used inside primary containment and that coatings are inspected and properly maintained. In LAR Table 3.5-1, the licensee summarizes the results from the coating inspections performed in Units 1 and 2 for the past 3 refueling outages. The table shows that 100 percent of submerged torus surfaces were inspected during each outage. Coating deficiencies were identified during each inspection; however, no areas were found with metal loss greater than the plant-specific 60 mil threshold.

The NRC staff reviewed the information provided in the LAR and finds that the licensee is properly implementing its safety-related coatings inspection program. The licensee is inspecting the coatings inside primary containment during each outage, including 100 percent of the submerged coatings in the suppression chamber. Deficiencies are identified and properly repaired, and during the past three inspections, no locations have been identified with metal loss greater than the 60 mil threshold.

3.5.2 Containment ISi Program Option B of Appendix J to 10 CFR Part 50 requires a general visual inspection of the containment prior to each Type A test and at a periodic interval between tests. NEI 94-01, Revision 3-A, recommends that these inspections be performed in conjunction with the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),

Section XI, Subsection IWE, required examinations. Section 3.5.2 of the LAR indicates that QCNPS will use the required ASME Code examinations to meet the Appendix J requirement regarding visual inspections.

In Section 3.5.2 of the LAR, the licensee described its containment inservice inspection (GISI) program. Visual inspections are conducted of the steel primary containment in accordance with ASME Code,Section XI, Subsection IWE. QCNPS does not have concrete containment (CC) components that meet the criteria of ASME Code Section, Subsection IWL; therefore, no concrete inspections in accordance with Subsection IWL are included in the GISI program.

In LAR Table 3.5-3, the licensee summarizes the results of the IWE general inspections performed over the last three outages. The table notes that both units have identified recordable indications on the moisture barrier in the past and that the moisture barrier was repaired and passed reinspection. The information in the table explains why the moisture barrier is acceptable after repair; however, there is no discussion of the metal containment behind or below the moisture barrier. If the moisture barrier was degraded, a possible path for moisture to reach inaccessible portions of the liner may have existed. Paragraph 50.55a(b)(2)(ix)(A) of 10 CFR imposes a condition on the use of ASME Code,Section XI, Subsection IWE which requires licensees to evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in degradation to, such inaccessible areas. The LAR contains no discussion of whether or not this evaluation was conducted or the results of the evaluation. To gain additional information on this topic, the NRC staff issued request for additional information (RAI) 7.

In its response dated July 27, 2017, the licensee stated that the degraded moisture barrier was removed and the containment areas behind the moisture barrier were inspected. No degradation was identified on the containment and the moisture barriers were replaced. The NRC staff reviewed the licensee's response and finds it acceptable because the licensee noted that the containment behind the moisture barrier was inspected and found to be acceptable prior to the replacement of the moisture barrier. The lack of degradation, along with the repaired moisture barrier, provides reasonable assurance that the inaccessible portions of the containment are acceptable.

In Section 3.6 of the LAR, the licensee discusses relevant industry operating experience and its evaluation on the possible impact on QCNPS containment. The NRC staff reviewed the information in the LAR and, in general, found that generic industry operating experience was properly identified and evaluated. However, additional information was required on the drywell liner and sand pocket inspections, as discussed below.

In Section 3.6.5 of the LAR, the licensee discusses its response to NRC Generic Letter (GL) 87-05, "Request for Additional Information -Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells." The GL describes degradation that could occur in the drywell air gap (small gap between the drywell and the supporting concrete) or the sand cushion region ("sand pocket") at the bottom of the air gap. In response to this GL, the licensee conducted a review of the potential for drywell corrosion in the sand pocket region.

This review included Dresden, Units 2 and 3, because of the similarities of the containment designs. The licensee concluded that based on site-specific operating experience, Dresden, Unit 3, was the limiting case for potential drywell corrosion and that Dresden, Unit 3, was acceptable. The licensee also concluded that additional surveillance procedures needed to be implemented to ensure moisture was properly draining from the sand cushion region. Additional discussion of this issue, along with a detailed discussion of the NRC staff's review, can be found in Section 3.5.2.2.1 of the "Safety Evaluation Report Related to the License Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power Station, Units 1 and 2" (ADAMS Accession No. ML043060581 ).

In LAR Table 3.6.5-1, the licensee summarizes the results of the sand pocket inspections from the past two refueling outages for each unit. LAR Table 3.6.5-1 Note (2), related to QCNPS, Unit 1, states that there is leakage but that the leakage is not from the drains and appears to be groundwater leakage with no structural impact. Note (4), related to QCNPS, Unit 2, also indicates issues with groundwater leakage. From the notes, it appears the leakage is an ongoing issue. It was not clear to the NRC staff how the licensee determined that the leakage is

groundwater and that the leakage is not impacting the structural integrity or leak-tightness of the containment. To gain additional information on this topic, the NRC staff issued RAI 8.

In its response dated July 27, 2017, the licensee stated that the term groundwater was inappropriately used in the initial corrective action documents. Based on chemistry samples of the leakage, the likely source of the water is refueling outage pool water leaking past various seals. The response also noted that procedures exist to verify the drains are open and to check for leakage after cavity flood up during refueling outages; however, the response did not explain how the licensee determined that the current leakage is not impacting the containment surface.

To gain additional information on this topic, the NRC staff issued follow-up RAI 8-A requesting the licensee explain how it determined the leakage was not impacting the structural integrity of the containment.

In its response dated September 28, 2017, the licensee explained that the notes refer to leakage from the sand pocket drains as well as from the drywell pedestal wall. The leakage from the sand pocket area is contained within the drain lines and has only been detected on Unit 2. Chemical analysis of the leakage determined that the likely source of the water is fuel pool water. The response further explained that the drywell pedestal wall leakage has been observed in both units but is sporadic, not active, and of insufficient volume to chemically analyze. The leakage could be groundwater; however, due to the normal level of the water table, there is not sufficient hydraulic head to force groundwater to inaccessible areas of the containment.

The NRC staff reviewed the licensee's response and finds it acceptable because the response clearly explains where the leakage is located and why it is not impacting the structural adequacy of the containment. The sand pocket drain leakage is contained within the sand pocket drain system and the licensee has verified that enough of the drain lines are open at each unit to allow adequate drainage from the sand pocket region. The sand pocket drain system provides reasonable assurance that the leakage in the sand pocket region is not impacting containment.

The pedestal wall leakage is sporadic and minimal, and based on the groundwater head, unlikely to contact inaccessible areas of the containment. Therefore, it is reasonable to assume that the pedestal wall leakage is not impacting the inaccessible portions of the containment based on the low hydraulic head of the groundwater and the minimal amount of leakage.

Based on its review, the NRC staff finds the licensee's response acceptable and finds that the identified leakage is not impacting the structural adequacy of the containment.

Based on its review of the licensee's GISI program, as summarized in the LAR, and the additional information provided as discussed above, the NRC staff finds that the licensee is properly implementing the ASME Code,Section XI, Subsection IWE, program.

3.

5.3 NRC Staff Conclusion

Regarding Containment Inspection Programs Based on the evaluation above, the NRC staff finds that the licensee has adequately implemented its GISI program to periodically examine, monitor, and manage age-related and environmental degradation of the containment structures. The results of past containment visual inspections demonstrate acceptable performance of the containment and demonstrate that the structural integrity of the containment structure is adequate. Thus, the NRC staff finds that there is reasonable assurance that the containment structural integrity will continue to be maintained, without undue risk to public health and safety, if the Type A test interval is extended to 15 years and the Type C test intervals are extended up to 75 months. Therefore, the NRC

staff finds it acceptable to extend the intervals, as proposed by the licensee, in accordance with NEI 94-01, Revision 3-A.

3.6 NEI 94-01, Revision 2-A, Conditions In the NRC SE dated June 25, 2008, the staff concluded that the guidance in NEI 94-01, Revision 2, is acceptable for reference by licensees proposing to amend their TSs in regard to containment leakage rate testing, subject to six conditions. The requirements of NEI 94-01 stayed essentially the same from the original version through Revision 2 except that the regulatory positions of RG 1.163 were incorporated and the maximum ILRT interval extended to 15 years. The LAR Table 3.9.1 described the licensee's response to the six conditions identified in the SE dated June 25, 2008, and the NRC staff evaluated these responses to determine whether the licensee adequately addressed these conditions.

Condition 1 Condition 1 specifies that for calculating the Type A leakage rate, the licensee should use the definition in NEI 94-01, Revision 2, in lieu of that in American National Standards Institute (ANSl)/American Nuclear Society (ANS)-56.8-2002.

NRC Staff's Evaluation of Licensee's Response to Condition 1 In LAR Table 3.9-1, "NEI 94-01 Revision 2-A Limitations and Conditions," the licensee stated:

QCNPS will utilize the definition in NEI 94-01 Revision 3-A, Section 5.0. This definition has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.

This definition is the one identified as acceptable and, therefore, the licensee has addressed and satisfied NRC Condition 1.

Condition 2 Condition 2 stipulates that the licensee submit a schedule of containment inspections to be performed prior to and between Type A tests.

NRC Staff's Evaluation of Licensee's Response to Condition 2 In LAR Table 3.9-1, "NEI 94-01 Revision 2-A Limitations and Conditions," the licensee referenced Tables 3.5-4 and 3.5-5 for QCNPS, Units 1 and 2, which show the schedules for the second (current) and third (future) CISI intervals by period for implementation of ASME Code,Section XI, Subsections IWE, "Requirements for Class MC [metal containment] and Metallic Liners of Class CC Components of Light-Water Cooled Plants." Therefore, the licensee has addressed and satisfied NRC Condition 2.

Condition 3 Condition 3 stipulates that the licensee address the areas of the containment structure potentially subjected to degradation.

NRC Staff's Evaluation of Licensee's Response to Condition 3 In LAR Section 3.5, "Non-Risk Based Assessment," and Section 3.6, "Operating Experience,"

the licensee described its experience regarding degradation found in past inspections and how inaccessible areas would be assessed for degradation potential. Therefore, the licensee has addressed and satisfied NRC Condition 3.

Condition 4 Condition 4 specifies that the licensee address any tests and inspections performed following major modifications to the containment structure, as applicable.

NRC Staff's Evaluation of Licensee's Response to Condition 4 In the LAR, the licensee indicated that the only modification affecting the primary containment boundaries was the planned installation of hardened containment vents per NRC Order EA-13-109 with inclusion of new outboard containment isolation valves. Associated integrity and leak rate testing is to be accomplished with local tests as part of the post modification testing during the unit outages involved. The licensee has addressed and satisfied NRC Condition 4.

Condition 5 Condition 5 specifies that 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 94-01, Revision 2, related to extending the ILRT interval beyond 15 years, the licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition.

NRC Staff's Evaluation of Licensee's Response to Condition 5 In the LAR, the licensee indicated acknowledgement and acceptance of this NRC staff position. Therefore, the licensee addressed and satisfied NRC Condition 5.

Condition 6 Condition 6 specifies that for plants licensed under 10 CFR Part 52, applications requesting a permanent extension of the ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, including the use of past containment ILRT data.

NRC Staff's Evaluation of Licensee's Response to Condition 6 In the LAR, the licensee stated that Condition 6 is not applicable to QCNPS because it was not licensed under 10 CFR Part 52.

Conclusion Related to the Six Conditions Listed in NEI 94-01, Revision 2-A The NRC staff evaluated each of the six conditions listed above and determined that the licensee adequately satisfied or addressed all of the limitations and conditions identified in NEI 94-01, Revision 2-A, Section 4.1, of the NRC SE. Therefore, the NRC staff finds it

acceptable for the licensee to adopt the "conditions and limitations" of NEI 94-01, Revision 2-A, SE Section 4.1, as part of the implementation documents listed in QCNPS TS 5.5.12.

3.7 NEI 94-01, Revision 3-A, "Conditions" The NRC published an SE with Limitations and Conditions for NEI 94-01, Revision 3, by letter dated June 8, 2012. In the SE, the NRC concluded that NEI 94-01, Revision 3, describes an acceptable approach for implementing the optional performance-based requirements of Appendix J, as modified by the limitations and conditions summarized in Section 4.0 of the SE, and is acceptable for reference by licensees proposing to amend their containment leakage rate testing TSs, subject to two conditions. The SE was incorporated into Revision 3 and subsequently issued as NEI 94-01, Revision 3-A, on July 31, 2012.

Topical Report Condition 1 The June 8, 2012, NEI 94-01, Revision 3, SE, Section 4.0, Condition 1, stipulates that:

NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type Band Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The staff is also allowing the non-routine emergent extension out to 84-months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g. BWR MSIVs

[main steam isolation valves]), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months.

Condition 1 identifies three issues that are required to be addressed:

(1) The allowance of an extended interval for Type C LLRTs of 75 months requires that a licensee's post-outage report include the margin between the Type Band Type C leakage rate summation and its regulatory limit; (2) A corrective action plan is to be developed to restore the margin to an acceptable level; and (3) Use of the allowed 9-month extension for eligible Type C valves is only allowed for non-routine emergent conditions, but not for valves categorically restricted and other excepted valves.

NRC Staff's Evaluation of Licensee's Response to Condition 1 The licensee indicated in the LAR that the QCNPS post-outage Appendix J testing summary reports will include the margin between the Type B and Type C minimum pathway leak rate summation value adjusted for understatement and the acceptance criterion. Should the Types B and C combined totals exceed an administrative limit of 0.5 La but be less than the TS

acceptance value (performance criterion) of 0.6 La, then an analysis will be performed and a corrective action plan prepared to restore and maintain the leakage summation margin to less than the administrative limit. The LAR also stated that QCNPS will apply the 9 month grace period only to eligible Type C tested components and only for nonroutine emergent conditions.

The NRC staff has evaluated the licensee's response to Condition 1 and finds that the licensee has adequately addressed the three issues identified in Condition 1.

Topical Report Condition 2 The June 8, 2012, NEI 94-01, Revision 3, SE, Section 4.0, Condition 1, stipulates that:

The basis for acceptability of extending the I LRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time. The containment leakage condition monitoring regime involves a portion of the penetrations being tested each refueling outage, nearly all LLRT's being performed during plant outages. For the purposes of assessing and monitoring or trending overall containment leakage potential, the as-found minimum pathway leakage rates for the just tested penetrations are summed with the as-left minimum pathway leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves which, in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable. Routine and appropriate maintenance may extend this increasing leakage potential. Allowing for longer intervals between LLRTs means that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total used to assess the current containment leakage potential. This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations. Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for. Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI 94-01, Revision 3, Section 12.1.

When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Type B & C total, and must be included in a licensee's post-outage report.

The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

Condition 2 identifies two issues that are required to be addressed:

(1) Extending the Type C LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative, provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI 94-01, Revision 3, Section 12.1; and (2) When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the Primary Containment Leakage Rate Testing Program trending or monitoring must include an estimate of the amount of understatement in the Type B and Type C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

NRC Staff's Evaluation of Licensee's Response to Condition 2 The licensee acknowledges these two issues and the likelihood that longer test intervals would increase the understatement of actual leakage potential given the method by which the totals are calculated, and will assign additional margin for monitoring acceptability of results via administrative limits and understatement contribution adjustments. Additionally, the licensee will prepare a post-outage report presenting results of the previous cycle's Type B and Type C tests, and Type A, Type B, and Type C tests, if performed during that outage.

The NRC staff has evaluated the licensee's response to Condition 2 and finds that the licensee has adequately addressed the two issues identified in Condition 2.

Conclusion Related to the Conditions Listed in NEI 94-01, Revision 3-A The NRC staff has evaluated the two conditions listed above and has determined that the licensee adequately satisfied the conditions identified in NEI 94-01, Revision 3, Section 4.0, of the NRC SE. Therefore, the NRC staff finds it acceptable for QCNPS to adopt NEI 94-01, Revision 3-A, as part of the implementation documents listed in TS 5.5.12.

3.8 Deletion of the First Type A Test Requirements The licensee requested deletion of the requirements to perform Type A tests for QCNPS, Units 1 and 2, no later than July 22, 2009, and May 16, 2008, respectively, from TS 5.5.12.a.

The NRC staff has reviewed the proposed changes and considers these changes to be editorial in nature since the Type A tests for both units have already been performed. The requirement for these specific Type A tests is obsolete. Therefore, the NRC staff finds that the proposed change is acceptable.

3.9 Probabilistic Risk Assessment of the Proposed Extension of the ILRT Test Intervals The licensee performed a risk impact assessment for extending the Type A containment ILRT interval from 1O years to 15 years. The risk analyses for QCNPS was provided in Attachment 3 of the LAR dated April 27, 2017. Additional information was provided by the licensee in its letters dated July 27 and September 28, 2017, in response to NRC RAls.

In Section 3.4.1 of Attachment 1 to the LAR, the licensee stated that the plant-specific risk assessment for QCNPS follows the guidance in:

• NEI 94-01, Revision 3-A,

• EPRI TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," dated August 1994,

• RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Revision 2, May 2011 (ADAMS Accession No. ML100910006),

• EPRI 1009325, Revision 2-A (also known as EPRI 1018243),

• Calvert Cliffs Nuclear Plant liner corrosion analysis described in a letter to the NRC dated March 27, 2002 (ADAMS Accession No. ML020920100).

As discussed in Section 3.1 above, the NRC staff concluded in Section 4.2 of its June 25, 2008, SE that the methodology in EPRI Report No. 1009325, Revision 2, is acceptable for referencing by licensees proposing to amend their TSs to permanently extend the ILRT surveillance interval to 15 years provided 4 conditions are satisfied.

The licensee addressed each of the four conditions for the use of EPRI TR-1009325, Revision 2-A. A summary of each condition, how it has been met, and the NRC staff's evaluation is provided in the sections below.

3.9.1 Technical Adequacy of the PRA The first condition stipulates that the licensee submits documentation indicating that the technical adequacy of its PRA is consistent with the requirements of RG 1.200 relevant to the ILRT extension application.

In Regulatory Issue Summary 2007-06, "Regulatory Guide 1.200 Implementation," the NRC clarified that for all risk-informed applications received after December 2007, the NRC staff will use Revision 1 of RG 1.200 (ADAMS Accession No. ML070240001) to assess technical adequacy of the PRA used to support risk-informed applications. Revision 2 of RG 1.200 will be used for all risk-informed application received after March 2010. In Section 3.2.4.1 of the SE to EPRI TR-1009325, Revision 2, and the NRC staff stated, in part, that:

[l]icensee requests for a permanent extension of the ILRT surveillance interval to 15 years pursuant to NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, will be treated by NRC staff as risk-informed license amendment requests. Consistent with information provided to industry in Regulatory Issue Summary 2007-06, "Regulatory Guide 1.200 Implementation," the NRC staff will expect the licensee's supporting Level 1/LERF PRA to address the technical adequacy requirements of RG 1.200, Revision 1 ... Any identified deficiencies in addressing this standard shall be assessed further in order to determine any impacts on any proposed decreases to surveillance frequencies. If further revisions to RG 1.200 are issued which endorse additional standards, the NRC staff will evaluate any application referencing NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, to examine if it meets the PRA quality guidance per the RG 1.200 implementation schedule identified by the NRC staff.

In the same section of the SE, the NRC staff stated that Capability Category I, of ASME PAA standard shall be applied as the standard for assessing PAA quality for ILRT extension applications, as approximate values of core damage frequency (CDF) and large early release frequency (LEAF) and their distribution among release categories are sufficient to support the evaluation of changes to ILRT frequencies.

As discussed in Section 4.2 of Attachment 3 to the LAA, the QCNPS risk assessment performed to support the ILRT application uses the current Unit 1 Level 1 and Level 2 internal events and internal flooding PAA model of record. In response to RAI 2, the licensee explained that there are no significant differences relevant to internal events modelling between Unit 1 and Unit 2, except for some differences in power supplies for shared equipment. The licensee stated, however, that the CDF and LEAF results are the same for Unit 1 and Unit 2. In Section A.2 of Attachment 3 to the LAA, the licensee describes the process used for controlling the model and for ensuring that the model reflects the as-built and as-operated plant. The licensee has a process for continued PAA maintenance and update, including procedures for regularly scheduled and interim PAA model updates and for tracking issues identified as potentially affecting the PAA model. The licensee performed a review of the plant modifications and changes and concluded that there are no plant changes that have not yet been incorporated in those PAA models that would affect the application.

As described in Appendix A to Attachment 3 of the LAA, the QCNPS internal events PAA underwent a peer review in February 2017 and the internal flooding model underwent a peer review in May 2010. Both peer reviews were performed against ASME/ANS PAA standard RA-Sa-2009, as clarified by RG 1.200, Revision 2. The 2010 internal flooding peer review resulted in three findings. The licensee stated that these findings have been resolved, and provided documentation of their resolution in Table A-1 of Attachment 3 to the LAA. The 2017 internal events peer review resulted in 31 findings. Table A-2 of Attachment 3 to the LAA provided the internal events Facts and Observations (F&Os), which have not been resolved by the licensee, but were dispositioned for the application. To assess the impact on the application, the licensee either performed sensitivity studies and showed minimal impact, provided justification that the current model is conservative, or justification that the F&O has no impact on the application. The NRC staff reviewed each F&O and associated dispositions and determined that they have no impact on the ILRT application results. The NRC staff asked for further clarification of the following F&Os:

• F&O 1-9, related to supporting requirement (SR) HR-I 1, HR-D2, and HR-D5, identified seven pre-initiator human failure events potentially lacking documentation or detailed human reliability analysis (HRA). In response to RAI 1a, the licensee stated that these seven pre-initiators are based on or grouped with other similar actions for which there are detailed HRA calculations. The licensee further stated that for three of these initiators, the values implemented in the PAA model were incorrect, being lower than the value resulting from the detailed calculations. For each of these errors the licensee stated that the impact on CDF and LEAF is minimal (0.1 percent or less). Because the licensee confirmed that detailed HRA calculations were performed for the pre-initiators identified in the F&O and explained that the identified numerical errors have minimal impact on the risk estimates, the NRC staff finds the licensee's disposition of this F&O acceptable for the application.

• F&O 1-18, related to SR LE-C 10, found that significant accident sequences were not reviewed to support equipment operation or operator actions during accident progression to reduce LEAF. The licensee stated that it performed a review of the top ten sequences, which constitute 90 percent of LEAF, but did not include a full disposition of these

sequences. In response to RAI 1b, the licensee stated that addressing F&O 1-18 would reduce LERF. Because the resolution of this F&O would result in a reduction in LERF, and therefore, addressing this F&O would likely result in a reduction in the risk metrics for the application, the NRC staff finds that this F&O does not adversely impact the conclusions of this application, and is, therefore, acceptable.

• F&O 2-10 found that SR QU-B3 was not met because the truncation limit in the LERF quantification did not show that the model results converged. In disposition to this F&O, the licensee cited a sensitivity study performed on truncation levels, showing that the LERF results would converge to a higher value than the LERF value used in the LAR. In response to RAI 3c, the licensee stated that a converged LERF value would be 2.10E-7/year, as opposed to the value of 1.97E-6/year included in the LAR. The licensee included this updated LERF value in a new risk estimate for the application, provided in response to RAI 6, which is further discussed in Section 3.9.2 of this SE.

• F&O 3-2, related to SR IE-A6, IE-01, and IE-02, identified deficiencies regarding consideration of common cause failures (CCF) or maintenance activities for special initiators, which include support system failures. The peer review stated that potential common cause and alignment are generally addressed in the fault tree supporting the initiating events, but the effects of maintenance were not. In response to RAI 1d, the licensee provided an overview of the support system initiators and how they were considered in the PRA. The licensee stated that instrument air and circulating water systems initiators are represented by point estimates, updated to reflect the plant specific operation experience. For the other risk-significant special initiators fault trees, service water, and turbine building closed cooling water (TBCCW), the licensee showed how maintenance terms and CCF are reflected in the PRA model. The licensee further stated that the CCF for the TBCCW running and standby pumps and the component cooling water heat exchangers is not captured in the model. The licensee provided the results of a sensitivity study showing minimal impact on CDF and LERF if these missing CCF failures were modeled in the PRA. Because the licensee confirmed that common cause failures and maintenance activities are modeled for the special initiators, and for the two missing CCF instances the licensee performed sensitivity studies and concluded that they have minimal impact on CDF and LERF, the NRC staff finds that the licensee's disposition of this F&O acceptable for the application.

• F&O 3-9, related to SR DA-C3 and IE-C2, found that the PRA data analysis spanned only four years of plant-specific experience and it did not justify exclusion of plant events that occurred prior to January 2010. In disposition to this F&O, the licensee discussed the impact on the application for two of the initiators, general transients and loss of offsite power, but did not appear to address all other initiating events or equipment failure probabilities and unavailabilities. In response to RAI 1e, the licensee explained that only the two types of initiators mentioned in the LAR occurred since 2005. Further, with regard to operational experience for equipment failures and unavailabilities, the licensee provided justification on how the older operational experience is reflected in the PRA though the industry generic data. Because the licensee reviewed the plant operational experience and explained how it is captured in the PRA, the NRC staff finds the licensee's disposition of this F&O acceptable for the application.

In Section 3.2.4.2 of the SE for NEI 94-01, Revision 2, and EPRI TR-1009325, Revision 2, the NRC staff states that:

[a]lthough the emphasis of the quantitative evaluation is on the risk impact from internal events, the guidance in EPRI Report No. 1009325, Revision 2, Section 4.2.7, "External Events," states that: "Where possible, the analysis should include a quantitative assessment of the contribution of external events (e.g., fire and seismic) in the risk impact assessment for extended ILRT intervals." This section also states that: "If the external event analysis is not of sufficient quality or detail to directly apply the methodology provided in this document [(i.e., EPRI Report No. 1009325, Revision 2)], the quality or detail will be increased or a suitable estimate of the risk impact from the external events should be performed." This assessment can be taken from existing, previously submitted and approved analyses or other alternate method of assessing an order of magnitude estimate for contribution of the external event to the impact of the changed interval."

Therefore, the NRC staff's review of the contribution of external events for this application is framed by the context that an order of magnitude estimate for the corresponding risk contribution is sufficient. The licensee performed an analysis of the impact of external events in Section 5.7 of Attachment 3 of the LAR and updated it in response to RAI 6. For the evaluation of the acceptance criteria discussed in Section 3.9.2 of this SE, the licensee's analysis reflected the contribution from internal fire and seismic events. The change in LERF due to the ILRT frequency extension was estimated by scaling the internal events change in LERF by a multiplication factor, which was derived based on the CDF contribution from each hazard.

As further discussed below, the licensee assessed that the contribution from other external hazards, such as high winds and external flooding, to be negligible for this application.

The licensee stated that a fire PRA model meeting the PRA standard is under development for QCNPS. Therefore, the licensee used the fire CDF estimated in the individual plant examination for external events (IPEEE) using the EPRI Fire-Induced Vulnerability Evaluation methodology. The licensee provided a fire CDF estimate of 6.6E-05/year based on estimated Unit 1 CDF, which was used in the LAR to estimate the risk from both units. In RAI 3.b, the NRC staff asked the licensee to justify the applicability of Unit 1 CDF to Unit 2. In response to RAI 2 and 3.b, the licensee explained the unit differences and confirmed that the Unit 2 fire CDF is higher than Unit 1. Therefore, the licensee provided an updated estimate from external events in response to RAI 3b and RAI 6. In order to calculate the Class 3b frequency for fire events, the licensee used a reduced frequency of 1.56E-5/year by eliminating 95 percent of the fire-induced loss of decay heat removal scenarios, based on an assumption that these scenarios would have the general emergency declared "early," such that the releases would be considered non-LERF. The NRC staff notes that some of the non-LERF scenarios could become LERF if the containment had an undetected leak; therefore, in RAI 3c, the NRC staff asked the licensee to justify this assumption. In response to RAI 3c, the licensee justified that loss of decay heat removal sequences are slow evolving and based on timing, any associated releases will not be LERF. Therefore, the NRC staff finds the licensee's assessment of fire risk acceptable for the application.

To estimate the seismic risk, the licensee used a bounding seismic CDF value based on the NRC staff's Generic Issue (GI) 199 study (ADAMS Accession No. ML100270756), which contains the postulated CDF using the updated 2008 U.S. Geological Survey seismic hazard curves. The weakest link model for QCNPS resulted in a seismic CDF of 2.7E-05/year. This is the highest CDF estimate presented in the NRC staff's GI 199 study for QCNPS. The NRC staff noted that based on the seismic hazard reevaluation performed in response to Recommendation 2.1 of the Near-Term Task Force, the staff concluded that a seismic risk re-

evaluation is not merited (ADAMS Accession No. ML15194A015). Therefore, the Gl-199 analysis represents the most recent available estimate of the seismic risk for QCNPS. Based on these considerations, the NRC staff finds that the licensee's use of this seismic CDF provides a sufficient estimate to support the evaluation of the acceptance criteria discussed in Section 3.9.2 of this SE.

As stated in Section 5.7.3 of Attachment 3 of the LAR, the licensee evaluated other external events, including high winds, tornadoes, external floods, transportation and nearby facility accidents, based on the QCNPS IPEEE analysis. The licensee concluded that these events are considered negligible in estimation of the external events impact on the ILRT extension risk assessment. In response to HAI 4, the licensee assessed the applicability of these conclusions to the current as-built and as-operated plant, and any changes in the plant or its environs since the IPEEE analysis was performed and concluded that the risk from these hazards remains negligible.

In summary, the licensee has evaluated its internal events PRA against the currently endorsed ASME PRA standard (i.e., ASME/ANS RA-Sa-2009) and the currently implemented version of RG 1.200 (i.e., Revision 2); resolved or dispositioned the findings developed during the peer review of its internal events PRA for applicability to the ILRT interval extension; and, included a quantitative assessment of the contribution of external events. The NRC staff reviewed the internal events peer review findings and concludes that the findings have been adequately dispositioned for this application. Furthermore, the NRC staff concludes that the impact from external events is appropriately considered by an order of magnitude estimate. Based on the above, the NRC staff concludes that the PRA used by the licensee is of sufficient technical adequacy to support the evaluation of changes to ILRT frequency. Accordingly, the first condition is met.

3.9.2 Estimated Risk Increase The second condition stipulates that the licensee submit documentation indicating that the estimated risk increase associated with permanently extending the ILRT interval to 15 years is small and consistent with the guidance in RG 1.174 and the clarification provided in Section 3.2.4.6 of the NRC SE for NEI 94-01, Revision 2-A. Specifically, a small increase in population dose should be defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or 1 percent of the total population dose, whichever is less restrictive. In addition, a small increase in conditional containment failure probability (CCFP) should be defined as a value marginally greater than that accepted in previous one-time 15-year ILRT extension requests. This would require that the increase in CCFP be less than or equal to 1.5 percentage points. Additionally, for plants that rely on containment over-pressure for net positive suction (NPSH) for emergency core cooling system (ECCS) injection, both CDF and LERF will be considered in the ILRT evaluation and compared with the risk acceptance guidelines in RG 1.174. As discussed further in Section 3.9.4 of this SE, QCNPS credits containment over-pressure. Thus, for this application, the associated risk metrics include CDF, LERF, population dose, and CCFP.

The licensee reported the results of the plant-specific risk assessment in Section 3.4.3 of to the LAR. Details of the risk assessment for QCNPS is provided in of the LAR, and were further revised in response to RAI 5 and RAI 6. The reported risk impacts are risk impact from baseline, which estimates the impact of a change in test frequency from 3 tests in 10 years (the test frequency under 10 CFR 50 Appendix J,

Option A) to 1 test in 15 years for both units. The following conclusions can be drawn based on the licensee's analysis associated with extending the Type A ILRT frequency:

1. The increase in CDF due to loss of containment overpressure for a change in test frequency from 3 tests in 10 years to 1 test in 15 years reported by the licensee is 2.4E-8/year for both units. This change in CDF is considered to be "very small" (i.e., below 1E-6/year) per the acceptance guidelines in RG 1.174.

2. The reported increase in LERF for internal events is 3.0E-08/year for both units. The increase in LERF for combined internal and external events is 8.?E-07/year. The risk contribution from external events includes the effects of internal fires and seismic, as discussed in Section 3.9.1 of this SE, and the contribution from loss of containment overpressure, as discussed in Section 3.9.4. This change in risk is considered to be "small" (i.e., between 1E-06/year and 1E-07/year) per the acceptance guidelines in RG 1.174. An assessment of total baseline LERF is required to show that the total LERF is less than 1E-05/year. The licensee estimated the total LERF for internal and external events as 4.9E-06/year. The total LERF, given the increase in ILRT interval, is below the acceptance guideline of 1E-05/year in RG 1.174 for a "small" change.

3. The increase in population dose risk from changing Type A ILRT frequency from 3 in 10 years to 1 in 15 years is reported as 2.9 x 1OE-01 person-rem/year or 0.31 percent. The reported increase in total population dose is below the values provided in EPRI TR-1009325, Revision 2-A, and defined in Section 3.2.4.62 of the NRC SE for NEI 94-01, Revision 2. Thus, this increase in the total population dose for the proposed change is considered small and supportive of the proposed change.

4. The increase in CCFP due to change in test frequency from 3 in 10 years to 1 in 15 years is 1.03 percent for QCNPS. This value is below the acceptance guideline of 1.5 percentage points for a small increase in CCFP in Section 3.2.4.6 of the NRC SE for NEI 94-01, Revision 2.

Based on the risk assessment results, the NRC staff concludes that, for QCNPS, the increase in CDF and LERF are small and consistent with the acceptance guidelines of RG 1.17 4, and the increase in the total population dose and the magnitude of the change in the CCFP for the proposed change are small and supportive of the proposed change. The defense-in-depth philosophy is maintained as the independence of barriers will not be degraded as a result of the requested change, and the use of quantitative risk metrics collectively ensures that the balance between prevention of core damage, prevention of containment failure, and consequence mitigation is preserved. Accordingly, the second condition is met.

3.9.3 Leak Rate for the Large Pre-Existing Containment Leak Rate Case The third condition stipulates that in order to make the methodology in EPRI TR-1009325, Revision 2, acceptable, the average leak rate for the pre-existing containment large leak rate accident case (i.e., accident case 3b) used by the licensees shall be 100 La instead of 35 La.

2 The SE for EPRI TR-1009325, Revision 2, indicates that the clarification regarding small increases in risk is provided in Section 3.2.4.5; however, the clarification is actually provided in Section 3.2.4.6.

containment large leak rate accident case, and this value has been used in the QCNPS plant-specific risk assessments. Accordingly, the third condition is met.

3.9.4 Applicability if Containment Over-Pressure is Credited for ECCS Performance The fourth condition stipulates that in instances where containment over-pressure is relied upon for ECCS performance, a LAR is required to be submitted. In Section 3.4.1 of Attachment 1 to the LAR, the licensee stated that QCNPS relies upon containment over-pressure for ECCS performance. In Section 5.8 of Attachment 3 to the LAR, the licensee provided an estimate of change in CDF of 7.2E-08/year, but did not sufficiently describe how this estimate was obtained; therefore, in RAI 5, the NRC staff asked the licensee to describe and justify the PRA modeling and methodology used, and explain how all the initiating events and accident sequences were considered in the risk estimate, consistent with the guidance in Section 5.2.4 of EPRI TR-1009325, Revision 2-A, which includes the following examples of accident scenarios to be considered:

• Loss-of-coolant accident (LOCA) scenarios where the initial containment pressurization helps to satisfy the NPSH requirements for early injection in BWR or PWR [pressurized-water reactor] sump recirculation

• Total loss of containment heat removal scenarios where gradual containment pressurization helps to satisfy the NPSH requirements for long term use of an injection system from a source inside of containment.

In response to RAI 5, the licensee explained that to estimate the change in CDF, the containment isolation failure logic was increased by the Class 3b frequency at 15 years and that a basic event modeling the failure of ECCS if the containment is de-pressurized was applied to a wide range of accident sequences. The licensee stated that a total loss of containment heat removal scenario, coupled with a containment isolation failure, including a pre-existing leak, fails long term use of injection systems from a source inside of containment. In follow-up RAI 5-A, the NRC staff asked the licensee to provide justification for why the loss of containment overpressure impacting NPSH for the ECCS injection is not a concern in any accident scenario with containment decay heat removal available. In its response to follow-up RAI 5-A, the licensee explained that based on thermal-hydraulic calculations performed for QCNPS using the Modular Accident Analysis Program (MAAP), sufficient NSPH remains when containment heat removal is available. The licensee presented the results of MAAP calculations, where it postulated a large LOCA and applied a containment leakage of 200 La. The results showed that the peak suppression pool temperature was 174 °F [degree Fahrenheit], well below the temperature of 212 °F, which can challenge NSPH requirements. The NRC staff finds the licensee's justification acceptable to conclude that loss of NSPH is not a concern when containment heat removal is available.

The licensee explained that operator actions were credited for aligning the residual heat removal (RHR) low pressure coolant injection (LPCI) pumps and core spray (CS) pumps to the clean condensate storage tank (CCST), given the potential for loss of NPSH associated with the suppression pool, and for operators to refill the CCST to support long term injection. The licensee stated that procedures exist and operators have received training to support both of these actions. The CCST alignment operator action was only applied to those sequences prior to containment failure, because the potential for adverse atmosphere in the reactor building after containment failure would preclude this operator action. A screening value of 0.1 was assigned to both human error probabilities. The licensee further explained that the PRA model

did not credit long term use of reactor core isolation cooling system with loss of suppression pool cooling, which could further reduce the impact of loss of NSPH to CS and LPCI.

In the response to RAI 5, the licensee described the PRA modeling for scenarios "post containment failure" and for scenarios with "successful pool venting," and provided logic diagrams. Based on the NRC staff's understanding, the containment would already be failed due to the postulated pre-existing containment leak and NSPH would already have been lost for the RHR and CS pumps, thus, it appeared that the licensee's PRA modeling could underestimate the risk. Therefore, in follow-up RAI 5-A, the NRC staff asked for further explanation of these scenarios and assurance that they do not result in an underestimate of risk.

In response to follow-up RAI 5-A, the licensee stated that the loss of NPSH fails CS and RHR (from the suppression pool) for reactor pressure vessel (RPV) injection early in the event tree sequences, and this failure is maintained throughout the accident sequences, such as in consideration of RPV injection later in a given sequence. The licensee concluded that the PRA model already considers the containment to be failed (via the pre-existing leakage) and the CS and RHR LPCI to be failed, and therefore there is no contribution to delta CDF or delta LERF from the model logic portions for post containment failure or successful pool venting.

The licensee estimated change in CDF was 2.4E-8/year. This CDF was assumed by the licensee to directly result in change in LERF due to loss of containment overpressure, which was included in the total change in LERF provided in response in RAI 6 and further discussed in in Section 3.9.2 of this SE. Because the licensee included an estimate of change in CDF, the fourth condition is met.

3. 1O Technical Conclusion Based on the preceding regulatory and technical evaluations, the NRC staff finds that the licensee has adequately implemented its existing primary containment leakage rate testing program consisting of ILRT and LLRT. The results of the recent ILRTs and of the LLRTs (Types Band C tests) combined totals demonstrate acceptable performance and support a conclusion that the structural and leak-tight integrity of the primary containment is adequately managed and will continue to be periodically monitored and managed effectively with the proposed changes.

The NRC staff finds that the licensee has addressed the NRC conditions to demonstrate acceptability of adopting NEI 94-01, Revision 3-A, and the limitations and conditions identified in the staff SE incorporated in NEI 94-01, Revision 2-A. Therefore, the NRC staff finds that the proposed changes to QCNPS TS 5.5. 12 regarding the primary containment leakage rate testing program are acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Illinois State official was notified of the proposed issuance of the amendment on October 20, 2017. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change the requirements with respect to installation or use of a facility's components located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The

significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (82 FR 27888, dated June 19, 2017). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

6.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors: J. Bettle, NRR B. Lehman, NRR M. Biro, NRR Dateofissuance: December 1, 2017

ML17311A162 *via e-mail OFFICE NRR/D0RL/LPL3/PM NRR/DORL/LPL3/LA N RR/DSS/SBPB/BC*

NAME KGreen SRohrer RDennig DATE 11/09/2017 11/8/2017 09/13/17 OFFICE NRR/DE/ESEB/BC* NRR/DSS/STSB/BC NRR/DRA/APLA/BC*

NAME BWittick VCusumano SRosenberg DATE 10/16/17 11/14/2014 10/26/17 OFFICE OGC NRR/D0RL/LPL3/BC NRR/DORL/LPL3/PM NAME CKanatas DWrona KGreen DATE 11/29/2017 12/1/2017 12/1/2017