ML17291A209

Issuance of Amendment Technical Specification Change for Permanent Extension to Type a and Type C Containment Leak Rate Test Frequencies (CAC No. MF8462; EPID L-2016-JLD-0011)

ML17291A209
Person / Time
Site:	Hope Creek
Issue date:	11/08/2017
From:	Lisa Regner Plant Licensing Branch 1
To:	Sena P Public Service Enterprise Group
Regner L, NRR/DORL/LPL4, 415-1906
References
CAC MF8462, EPID L-2016-JLD-0011
Download: ML17291A209 (29)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 November 8, 2017 Mr. Peter P. Sena, Ill President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038

SUBJECT:

HOPE CREEK GENERATING STATION - ISSUANCE OF AMENDMENT RE: TECHNICAL SPECIFICATION CHANGE FOR PERMANENT EXTENSION TO TYPE A AND TYPE C CONTAINMENT LEAK RATE TEST FREQUENCIES (CAC NO. MF8462; EPID L-2016-JLD-0011)

Dear Mr. Sena:

The U.S. Nuclear Regulatory Commission (Commission) has issued the enclosed Amendment No. 207 to Renewed Facility Operating License No. NPF-57 for the Hope Creek Generating Station (Hope Creek). This amendment consists of changes to the Technical Specifications in response to your application dated October 7, 2016, as supplemented by letters dated March 27, 2017, and July 13, 2017.

The amendment modifies Hope Creek Technical Specification 6.8.4.f, "Primary Containment Leakage Rate Testing Program," by deleting the exemption in item a. that allowed a one-time extension (by letter dated April 16, 2003) and requiring compliance with Nuclear Energy Institute (NEI) 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," instead of Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program." This change will allow Hope Creek to extend the Type A reactor containment test interval required by Title 10 of the Code of Federal Regulations Part 50, Appendix J, from one test in 10 years to one test in 15 years, and extends the Type C test interval up to 75 months, with a permissible extension period of 9 months (total of 84 months) for non-routine emergency conditions.

P. Sena A copy of our related safety evaluation is also enclosed. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Lisa M. Regner, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-354

Enclosures:

1. Amendment No. 207 to Renewed License No. NPF-57

2. Safety Evaluation cc w/

Enclosures:

Distribution via Listserv

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 PSEG NUCLEAR LLC DOCKET NO. 50-354 HOPE CREEK GENERATING STATION AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 207 Renewed License No. NPF-57

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

A. The application for amendment filed by PSEG Nuclear LLC dated October 7, 2016, as supplemented by letters dated March 27, 2017, and July 13, 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 set forth in 10 CFR Chapter I; 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 2.C.(2) of Facility Operating License No. NPF-57 is hereby amended to read as follows:

Enclosure 1

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 207, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated into the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. The license amendment is effective as of its date of issuance and shall be implemented within 60 days.

FOR THE NUCLEAR REGULATORY COMMISSION J9~h~

Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed License and Technical Specifications Date of Issuance: November 8, 2O1 7

ATTACHMENT TO LICENSE AMENDMENT NO. 207 HOPE CREEK GENERATING STATION RENEWED FACILITY OPERATING LICENSE NO. NPF-57 DOCKET NO. 50-354 Replace the following page of the Renewed Facility Operating License with the attached revised page. The revised page is identified by amendment number and contains a marginal line indicating the area of change.

Remove 3

Replace the following page of the Appendix A Technical Specifications with the attached revised page. The revised page is identified by amendment number and contains a marginal line indicating the area of change.

Remove Insert 6-16b 6-16b

reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended; (4) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility. Mechanical disassembly of the GE14i isotope test assemblies containing Cobalt-60 is not considered separation.

(7) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Part 30, to intentionally produce, possess, receive, transfer, and use Cobalt-60.

C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level PSEG Nuclear LLC is authorized to operate the facility at reactor core power levels not in excess of 3840 megawatts thermal (100 percent rated power) in accordance with the conditions specified herein.

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 207, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Renewed License No. NPF-57 Amendment No. 207

ADMINISTRATIVE CONTROLS 6.8.4.f Primary Containment Leakage Rate Testing Program A program shall be established, implemented, and maintained to comply with the leakage rate testing of the containment as required by 10CFR50.54(o) and 10CFR50, 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.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 50.6 psig.

The maximum allowable primary containment leakage rate, La, at Pa, shall be 0.5% of primary containment air weight per day.

Leakage Rate Acceptance Criteria are:

a. Primary containment leakage rate acceptance criterion is less than or equal to 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are less than or equal to 0.6 La for Type B and Type C tests and less than or equal to 0.75 La for Type A tests;

b. Air lock testing acceptance criteria are:

1) Overall air lock leakage rate is less than or equal to 0.05 La when tested at greater than or equal to Pa,

2) Door seal leakage rate less than or equal to 5 scf per hour when the gap between the door seals is pressurized to greater than or equal to 10.0 psig.

The provisions of Specification 4.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program.

The provisions of Specification 4.0.3 are applicable to the Primary Containment Leakage Rate Testing Program.

6.8.4.g Radioactive Effluent Controls Program A program shall be provided conforming with 10 CFR 50.36a for the control of radioactive effluents and for maintaining the doses to MEMBER(S) OF THE PUBLIC from radioactive effluents as low as reasonably achievable. The program (1) shall be contained in the ODCM, (2) shall be implemented by operating procedures, and (3) shall include remedial actions to be taken whenever the program limits are exceeded. The program shall include the following elements:

HOPE CREEK 6-16b Amendment No. 207

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 207 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-57 PSEG NUCLEAR LLC HOPE CREEK GENERATING STATION DOCKET NO. 50-354

1.0 INTRODUCTION

By letter dated October 7, 2016 (Agencywide Documents Access and Management (ADAMS)

Accession No. ML16281A139, as supplemented by letters dated March 27, 2017, and July 13, 2017 (ADAMS Accession Nos. ML17086A096 and ML17194A460, respectively), PSEG Nuclear LLC (PSEG, or the licensee) requested changes to the Hope Creek Generating Station (Hope Creek or HCGS) Technical Specifications (TSs).

The supplements dated March 27, 2017, and July 13, 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 the Commission) staff's original proposed no significant hazards determination as published in the Federal Register on December 20, 2016 (81 FR 92869).

The license amendment would revise Technical Specification (TS) 6.8.4.f, "Primary Containment Leakage Rate Testing Program," to adopt Nuclear Energy Institute (NEI) 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J" (ADAMS Accession No. ML12221A202), and the conditions and limitations specified in NEI 94-01, Revision 2-A, as the guidance document for implementation of performance-based Option B of Title 10 of the Code of Federal Regulations ( 10 CFR)

Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." This change would allow the maximum interval for the Type A integrated leakage rate test (ILRT) to extend from once in 10 years to once in 15 years and the maximum Type C containment isolation valve local leak rate test (LLRT) interval to be extended from once in 60 months to once in 75 months, with a permissible extension period of 9 months (total of 84 months) for non-routine emergency conditions, based on acceptable performance history as defined in NEI 94-01, Revision 3-A.

Enclosure 2

2.0 REGULATORY EVALUATION

2.1 System Description Hope Creek has a General Electric boiling water reactor within a Mark I water pool pressure suppression design containment. The primary containment consists of a carbon steel pressure vessel with a drywell composed of a domed removable head on top of a cylindrical upper section and spherical lower section attached by large vent lines to a torus shaped suppression chamber below which is roughly halfway filled with water. The drywell houses the reactor vessel, the recirculating loops, main steam lines, and other branch connections of the reactor coolant system. This arrangement limits primary containment pressurization from a design-basis loss-of-coolant accident (LOCA) by channeling the steam and heated drywell atmosphere into the suppression pool where condensation and cooling of the containment atmosphere occur during the initial blowdown. The steel containment is an American Society of Mechanical Engineers (ASME) Boiler & Pressure Vessel Code (ASME Code), Class MC vessel.

The licensee further stated that the drywell is enclosed by the concrete drywell shield wall. An air gap of nominally 2 inches separates the drywell vessel from the concrete drywell shield wall.

The air gap permits displacement of the vessel, but the size of the gap is limited to allow transfer of postulated jet impingement forces into the drywell shield wall without rupturing the vessel. The primary containment provides the "leaktight" barrier against the potential uncontrolled release of fission products during a design-basis LOCA. TS 6.8.4.f identifies the primary containment allowable leakage rate (La) as 0.5 weight percent of the contained free air volume per day at the calculated maximum design-basis LOCA pressure (Pa) of 50.6 psig.

2.2 Regulations and Guidance Section 50.54(0) of 10 CFR requires primary reactor containments for water cooled power reactors be subject to the requirements set forth in Appendix J to 10 CFR Part 50. Appendix J includes two options: "Option A- Prescriptive Requirements," and "Option B -

Performance-Based Requirements," either of which may be chosen by a licensee for meeting the requirements. By letter dated September 18, 1997 (ADAMS Accession No. ML011770097),

the NRC issued an amendment allowing Hope Creek to adopt 10 CFR Part 50, Appendix J, Option B, for Type A ILRTs, and Type Band Type C LLRTs.

The testing requirements in 10 CFR Part 50, 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.

Appendix J, Option B, to 10 CFR Part 50, specifies performance-based requirements and criteria for preoperational and subsequent leakage rate testing. These requirements are met by performing:

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 containment isolation valve leakage rates.

After the preoperational tests, these tests are required to be conducted at periodic intervals based on the historical performance of the overall containment system (for Type A tests), and

based on the safety significance and historical performance of each penetration boundary and isolation valve (for Type Band Type C tests) to ensure integrity of the overall containment system as a barrier to fission product release.

The leakage rate test results must not exceed the allowable leakage rate (La) with margin, as specified in the TSs. Option B of 10 CFR Part 50 also requires that a general visual inspection of the accessible interior and exterior surfaces of the containment system for structural deterioration, which may affect the containment leaktight integrity, must be conducted prior to each Type A test and at a periodic interval between tests.

Section V.B.3 of 10 CFR Part 50, Appendix J, Option B, requires that the regulatory guide or other implementation document used by a licensee to develop a performance-based leakage testing program must be included, by general reference, in the plant TSs. Furthermore, the submittal for TS revisions must contain justification, including supporting analyses, if the licensee chooses to deviate from methods approved by the Commission and endorsed in a regulatory guide.

NEI 94-01, Revisions 2 and 3, were reviewed by the NRC staff and approved for use. The final safety evaluation (SE) for Revision 2, issued by letter dated June 25, 2008 (ADAMS Accession No. ML081140105), documents the NRC's evaluation and acceptance of Revision 2, subject to six specific limitations and conditions listed in Section 4.1 of the NEI 94-01, Revision 2, SE. The final SE for Revision 3, issued by letter dated June 8, 2012 (ADAMS Accession No. ML121030286), includes two specific limitations and conditions listed in Section 4.0 of that SE for the Type C tests. NEI 94-01, Revisions 2-A and 3-A, include the limitations and conditions in the corresponding SEs.

Section 50.36, "Technical specifications," of 10 CFR states that the TSs include items in five specific categories. These categories include: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting Conditions for operation; (3) surveillance requirements; (4) design features; and (5) administrative controls.

NUREG-1433, Revision 4.0, "Standard Technical Specifications - General Electric Plants (BWR/4)," incorporated the Standard Technical Specification Task Force (TSTF) Traveler TSTF-52, Revision 3, "Implement 10 CFR 50, Appendix J, Option B," which provided guidance for specific changes to TSs for implementation of 10 CFR Part 50, Appendix J, Option B.

To justify the current TSs change request, the licensee provided historical plant-specific containment leakage testing program results, containment inservice inspection (CISI) program results, and a supporting plant-specific risk assessment, consistent with the guidance in NEI 94-01, Revisions 2-A and 3-A.

3.0 TECHNICAL EVALUATION

3.1 Background By amendment dated September 18, 1997, the NRC authorized PSEG to adopt 10 CFR Part 50, Appendix J, Option B. By amendment dated April 16, 2003 (ADAMS Accession No. ML030660099), the NRC authorized PSEG a one-time 5-year extension of the Type A test.

3.2 Licensee's Proposed Changes Hope Creek TS 6.8.4.f currently states, in part:

A program shall be established, implemented, and maintained to comply with the leakage rate testing of the 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 Regulatory Guide 1.163, "Performance Based Containment Leak Test Program", dated September 1995, as modified by the following exception:

a. NEI 94-01-1995, Section 9.2.3: The First Type A test performed after April 12, 1994 shall be performed no later than April 12, 2009.

With the proposed changes, this part of Hope Creek TS 6.8.4.f would state:

A program shall be established, implemented, and maintained to comply with the leakage rate testing of the containment as required by 10CFR50.54(o) and 10CFR50, 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, Hope Creek will implement NEI 94-01, Revision 3-A, with its associated limitations and conditions, and the limitations and conditions of Section 4.1 of the NEI 94-01, Revision 2-A, SE. NEI 94-01, Revision 3-A, provides that extension of the Type A test 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 that are the likely pathways for a majority of potential primary containment leakage.

Additionally, the licensee must have a robust containment visual inspection program where deterioration of the primary containment boundary away from penetrations can be detected and remediated before leakage develops. 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 (i.e., Hope Creek performance history) and meeting other specified limitations and conditions.

The existing Hope Creek TS 6.8.4.f exception to NEI 94-01 regarding a specific date for the next Type A test is no longer needed and may be removed, as that date has passed, and the test was completed.

The reference to Regulatory Guide (RG) 1.163 is to be replaced with a reference to NEI 94-01, Revision 3-A, and the conditions and limitations of NEI 94-01, Revision 2-A. This is allowed by the provision in 10 CFR Part 50, Appendix J, Option B, Section V.B.3, regarding the TSs referencing the NRC staff-approved guidance document for program implementation.

3.3 Deterministic Considerations: Structural and Leaktight Integrity of the Containment 3.3.1 Historical Type A Test Results In its submittal dated October 7, 2016, the licensee stated that TS 6.8.4.f requires Types A, B, and C testing in accordance with RG 1.163 "Performance-Based Containment Leak-Test Program," which endorses the methodology for complying with 10 CFR Part 50, Appendix J, Option B. Since the adoption of Option B, the performance leakage rates were calculated in accordance with NEI 94-01, Section 9.1.1, for Type A testing. Hope Creek TS 6.8.4.f identifies the primary containment allowable leakage rate (La) as 0.5 weight percent of the contained free air volume per day at the calculated maximum design-basis LOCA pressure (Pa) of 50.6 pounds per square inch gauge (psig). The past periodic Type A ILRT results for Hope Creek were presented in Table 3.4.4-1, "HCGS Type A Test History," of the licensee's submittal. This table is provided below.

Table 1 Type A- Integrated Leakage Rate Testing History As-Found Test Result As-Left Test Result Acceptance Criteria Test Date

(%weight per day) (% weight per day) (% weight per day)

January 2, 1986 ( 1) 0.193 0.375 November 9, 1989 0.189 0.153 0.375 April 12, 1994 0.252 0.237 0.375 April 28, 2009 (2) 0.373 0.373 0.375 (1) The January 1986 test was a pre-operational test, therefore no "As-Found" results were required.

(2) The April 2009 Type A Test was performed at the post EPU [extended power update] Pa of 50.6 psig.

The NEI 94-01, Revisions 2-A and 3-A, requirement for allowing the extended ILRT interval is that the past two consecutive tests meet the performance criterion of leakage La or less. The Hope Creek TS 6.8.4.f performance criterion is:

La= 0.5 percent weight of containment free air volume per day(% weight per day)

The acceptance criterion for reactor restart is:

0.75 La= 0.75 (0.5) = 0.375 % weight per day The 1994 and 2009 ILRT results both show leakage less than La, and thus, meet the NEI 94-01 requirement for interval extension.

Based on the above, the NRC staff concludes that the last two consecutive Type A ILRT results were less than the design-basis leak rate, La; therefore, the guidelines in NEI 94-01, Revisions 2-A and 3-A, regarding acceptable performance history have been met. The NRC staff concludes that the results of the Type A ILRTs provide reasonable assurance that containment overall leakage will be maintained below the design-basis leak rate, consistent with the requirements in TS 6.8.4.f and the requirements of 10 CFR Part 50, Appendix J, Option B.

3.3.2 Historical Type B and Type C Leak Rate Results In its submittal dated October 7, 2016, the licensee presented the historical results of the Type Band Type C test combined, as-found minimum pathway leakage totals in Table 3.6.3-1, "HCGS Types B and C LLRT Combined As-Found/As-Left Trend Summary." This table is summarized in Table 2 below.

Table 2 HCGS Types Band C LLRT Combined As-Found/As-Left Trend Summary Refuel Outage and As-Found Minimum Pathway Percent of TS 6.8.4.f Combined Year of Tests Leakage Rate in standard cubic Type Band Type C Total Criterion, centimeters per minute (seem) 0.6 La, which equates to 79,800 seem R15, 2009 21,628 27 R16,2010 30,226 38 R17, 2012 45,217 57 R18,2013 26,348 34 R19,2015 34,795 43 The Hope Creek TS 6.8.4.f criterion for combined Type B and Type C test total is 0.6 La. As detailed in NEI 94-01, this criterion is the evaluated minimum pathway for as-found values and maximum pathway for as-left values. The as-found minimum pathway total provides an assessment of the leakage testing and corrective action program's effectiveness for ensuring penetration leakage potential is kept acceptable throughout each operating cycle such that margin to La is maintained to accommodate some increase in non-penetration leakage potential between ILRTs. The as-left maximum pathway total criterion is a permissive for restoring primary containment operability and ensures margin is available to accommodate increases in leakage potential between outages where leakage testing is performed.

The NRC staff reviewed the last five refueling outage combined Type B and Type C testing totals and determined that the results show substantial margin to the applicable performance criterion suggesting that both the ILRT and LLRT performance criteria are unlikely to be exceeded if the Hope Creek ILRT maximum interval is authorized to be extended to 15 years and the Type C testing maximum interval is authorized to be extended to 75 months.

Based on the above, the NRC staff concludes that the Type B and Type C tests were less than the design-basis leak rate; therefore, the guidelines in NEI 94-01, Revisions 2-A and 3-A, regarding acceptable performance history have been met. Thus, the NRC staff concludes that the results of the Type B and Type C tests provide reasonable assurance that as-found minimum pathway totals will be maintained below the design-basis leak rate consistent with the requirements in Hope Creek TS 6.8.4.f and 10 CFR Part 50, Appendix J, Option B.

3.3.3 Containment lnservice Inspection Program In its October 7, 2016, submittal, the licensee stated that the inservice inspection (ISi) program plan provides the requirements for the examination and testing of ISi Class 1, 2, and 3, and MC pressure retaining components, supports, and containment structures. The ISi program plan

includes the CISI as a program within the ISi program. The licensee specified that the third ISi interval {the second CISI interval, a sub-part of the third ISi interval) is effective from December 13, 2007, through December 12, 2017. The common ASME Section XI Code of Record for the third ISi interval (the second CISI interval) is the 2001 Edition through the 2003 Addenda.

The third ISi interval (the second CISI interval) is divided into three inspection periods as determined by calendar years within the intervals. Table 3.6.2-1 of the licensee's October 7, 2016, submittal identifies the period start and end dates for the third ISi interval (the second CISI interval). In accordance with paragraph IWA-2430(d)(3) of the ASME Code, the inspection periods specified in these tables may be decreased or extended by as much as 1 year to enable the inspection to coincide with the Hope Creek refueling outages. However, in Section 3.1.1.2, "Deferral of Tests Beyond the 15-Year Interval," of the NRC safety evaluation report (SER) for NEI 94-01, Revision 2A, it states that the "required surveillance intervals for recommended Type A testing given in this section may be extended by up to 9 months to accommodate unforeseen emergent conditions but should not be used for routine scheduling and planning purposes." The NRC staff notes that extensions of the performance-based Type A test interval beyond the required 15 years should be infrequent and used only for compelling reasons.

Therefore, if a licensee wants to use the provisions of Section 9.1 in NEI 94-01, Revision 2, the licensee must demonstrate to the NRC staff that an unforeseen emergent condition exists.

3.3.4 Deterministic Review Summary Based on the preceding regulatory and technical evaluations, the NRC staff finds that the licensee has submitted its CISI schedule and has adequately implemented its primary containment leakage rate testing program consisting of ILRT and LLRT. The results of the recent ILRT and LLRT combined totals demonstrate acceptable performance and support a conclusion that the structural and leaktight integrity of the primary containment vessel is adequately managed and will continue to be periodically monitored and managed by the ILRTs and LLRTs.

3.4 NRC Staff Evaluation of the Conditions and Limitations 3.4.1 NRC Conditions in NEI 94-01, Revision 2-A In the NRC SE dated June 25, 2008, the staff concluded that licensees may reference the guidance in NEI 94-01, Revision 2-A, when requesting to modify their 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 was extended to 15 years.

In Table 3.6.8.1-1 of the licensee's October 7, 2016, submittal, PSEG described its response to the six conditions specified in the NRC SE for NEI 94-01, Revision 2-A. The NRC staff has evaluated PSEG's responses to determine whether the licensee adequately addressed these conditions. The text in parentheses following each condition below shows where the condition is discussed in the NRC staff's SE for NEI 94-01, Revision 2-A.

NRC Condition 1:

For calculating the Type A leakage rate, the licensee should use the definition in the NEI 94-01, Revision 2, in lieu of that in ANSI/ANS- 56.8-2002. (NRC SE, Section 3.1.1.1)

The licensee stated in the LAR that Hope Creek will utilize the definition in NEI 94-01, Revision 3-A, Section 5.0. This definition has remained unchanged from Revision 2 to Revision 3-A of NEI 94-01 and is the one identified as acceptable. Therefore, the licensee has addressed and satisfied NRC Condition 1.

NRC Condition 2:

The licensee submits a schedule of containment inspections to be performed prior to and between Type A tests. (NRC SE, Section 3.1.1.3)

As discussed in Section 3.3.3 of this SE, the licensee has submitted a schedule of containment inspections to be performed prior to and between Type A tests for the second CISI interval. In addition, Table 3.6.2-1 of the licensee's October 7, 2017, submittal includes postulated dates for the third CISI interval. Therefore, the licensee has addressed and satisfied NRC Condition 2.

NRC Condition 3:

The licensee addresses the areas of the containment structure potentially subjected to degradation. (NRC SE, Section 3.1.3)

This condition relates to the areas identified in NRC staff SE, Section 3.1.3, for NEI 94-01, Revision 2, that need to be specifically addressed during the ASME Code, Section XI, Subsections IWE and IWL program inspections, including a number of containment pressure-retaining components and a number of the accessible and inaccessible areas of the containment structure. The licensee described the applicable requirements in LAR Section 3.6.2, specifically, in Table 3.6.2-2, "Code of Federal Regulations 10 CFR 50.55a Requirements," and the LAR Table 3.6.2-3, "lnservice Inspection Requirements," by providing a summary of the Hope Creek ASME Section XI nonexempt CISI components and the program requirements, scope, and implementation for Hope Creek. Based on the information in the aforementioned sections of the LAR, the staff concludes that the licensee has addressed and satisfied NRC Condition 3.

NRC Condition 4:

The licensee addresses any tests and inspections performed following major modifications to the containment structure, as applicable. (NRC SE, Section 3.1.4)

In LAR Section 3.2, "Modifications to Primary Containment," the licensee indicated that there are no major modifications planned to the containment structure. Modifications to comply with NRC severe accident capable hardened vent Order EA-13-109, "Order Modifying Licenses with Regard to Reliable Hardened Containment Vents Capable of Operation Under Severe Accident Conditions (Effective Immediately)," dated June 6, 2013 (ADAMS Accession No. ML13143A321 ), issued as the result of the Fukushima Dai-ichi event, do not impact the penetrations and performance of LLRT and do not present a potential need for an integrated containment test. Therefore, the licensee has addressed and satisfied NRC Condition 4.

NRC Condition 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 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 SE, Section 3.1.1.2)

Hope Creek's response to Condition 5 in Table 3.6.8.1-1 of the LAR states:

HCGS will follow the requirements of NEI 94-01 Revision 3-A, Section 9.1. This requirement has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.

In accordance with the requirements of NEI 94-01, Revision 2-A, SER Section 3.1.1.2, HCGS will also demonstrate to the NRC staff that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.

The licensee's response indicates acknowledgement and acceptance of the NRC staff's position that extensions of the Type A test interval beyond the upper-bound performance based limit of 15 years should be infrequent and that any request for an extension should demonstrate to the NRC staff that an unforeseen emergent condition exists. Therefore, the licensee addressed and satisfied NRC Condition 5.

NRC Condition 6:

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 Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, including the use of past ILRT data.

This condition is not applicable to Hope Creek. The licensee was not licensed under 10 CFR Part 52.

3.4.2 NRC Conditions In NEI 94-01, Revision 3-A In the NRC SE for NEI 94-01, the staff concluded that the guidance in NEI 94-01, Revision 3-A, is acceptable for reference by licensees proposing to amend their TSs regarding containment leakage rate testing, subject to two conditions.

NRC Condition 1:

NEI 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 9 months (84 months total). The NRC 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 B and 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 are 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.,

boing water reactor 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.

NRC Condition 2:

When scheduling a valve LLRT interval beyond 60 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 combined totals and must be included in the

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

The licensee stated in the LAR that the Hope Creek post-outage reports will include the margin between the Type B and Type C minimum pathway leak rate summation value adjusted for leakage understatement and the acceptance criterion. Should the Type B and Type C combined totals exceed an administrative limit of 0.5 La but be less than the TSs 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 Hope Creek will apply the 9-month grace period only to eligible Type C tested components and only for non-routine emergent conditions.

The licensee acknowledged these two conditions 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 by administrative limits and understatement contribution adjustments. Therefore, the licensee addressed and satisfied NRC Conditions 1 and 2 of NEI 94-01, Revision 3-A.

3.4.3 Limitations and Conditions Summary The 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's SE incorporated in NEI 94-01, Revision 2-A. Therefore, the staff finds that the proposed changes to Hope Creek TS 6.8.4.f regarding the primary containment leakage rate testing program are acceptable.

3.5 Risk Review 3.5.1 Background Section 9.2.3.1, "General Requirements for ILRT Interval Extensions beyond Ten Years," of NEI 94-01, Revision 2-A, states that plant-specific confirmatory analyses are required when extending the Type A ILRT interval beyond 10 years. Section 9.2.3.4, "Plant-Specific Confirmatory Analyses," of NEI 94-01 states that the assessment should be performed using the approach and methodology described in Electric Power Research Institute (EPRI) Technical Report (TR) 1009325, Revision 2-A, 1 "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals." The analysis is to be performed by the licensee and retained in the plant documentation and records as part of the basis for extending the ILRT interval.

In its SER dated June 25, 2008, the NRC staff concluded that the methodology in EPRI TR-1009325, Revision 2, was acceptable for use by licensees proposing to amend their TSs to permanently extend the ILRT interval to 15 years, provided certain conditions are satisfied.

These conditions, set forth in Section 4.2 of the SER for EPRI TR-1009325, Revision 2, stipulate that:

1. The licensee submit documentation indicating that the technical adequacy of its probabilistic risk assessment (PRA) is consistent with the requirements of RG 1.200, "An 1 It should be noted that EPRI TR-1009325, Revision 2-A, is also identified as EPRI TR-1018243. This report is publicly available and can be found at www.epri.com by typing "1018243" in the search field box.

Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," relevant to the ILRT interval extension application.

2. The licensee submits documentation indicating that the estimated risk increase associated with permanently extending the ILRT interval to 15 years is small and consistent with the clarification provided in Section 3.2.4.6 of the SER2 for EPRI TR-1009325, Revision 2.

3. The methodology in EPRI TR-1009325, Revision 2, is acceptable, provided the average leak rate for the preexisting containment large leak accident case (i.e., accident case 3b) used by licensees is assigned a value of 100 times the maximum allowable leakage rate (La) instead of 35 La.

4. An LAR is required in instances where containment over-pressure is relied upon for emergency core cooling system (ECCS) performance.

3.5.2 Plant-Specific Risk Evaluation The licensee performed and submitted a risk impact assessment for permanently extending the Type A containment ILRT interval from 10 years to 15 years for Hope Creek. The risk analysis was provided in Attachment 3 of the October 7, 2016, LAR. Additional information was provided by the licensee in letters dated March 27, 2017, and July 13, 2017.

In Section 1.1 of Attachment 3 of the LAR, the licensee stated that its plant-specific risk assessments to support the ILRT interval extension request follow the guidance from:

• NEI 94-01, Revision 3-A;

• The methodology described in EPRI TR-1018243 {which is the same as EPRI TR-1009325, Revision 2-A);

• The methodology used in EPRI TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," dated August 1994; and

• The methodology used for Calvert Cliffs Nuclear Plant (CCNP) (ADAMS Accession No. ML020920100) to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval.

The licensee addressed each of the four conditions for the use of EPRI TR-1009325, Revision 2, which are listed in Section 4.2 of the NRC SER on that report (ADAMS Accession No. ML081140105). A summary of how each condition has been met is provided in the sections below.

3.5.3 Technical Adequacy of the Probabilistic Risk Assessment The first condition stipulates that the licensee submit documentation indicating that the technical adequacy of its PRA models supporting the ILRT interval extension application is consistent with the requirements of RG 1.200, which are relevant to the subject application.

In Section 3.2.4.1 of the SER to EPRI TR-1009325, Revision 2, the NRC staff stated that Capability Category (CC) I of the American Society of Mechanical Engineers (ASME) PRA 2 The SER 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.

standard shall be applied as the standard for assessing PRA quality for ILRT interval extension applications, as approximate values of core damage frequency (CDF) and large early release frequency (LERF), and their distributions among release categories are sufficient to support the evaluation of changes to ILRT frequencies.

In Regulatory Issue Summary 2007-06, "Regulatory Guide 1.200 Implementation" (ADAMS Accession No. ML070650428), the NRC staff clarified that it will use Revision 2 of RG 1.200 (ADAMS Accession No. ML090410014) to assess the technical adequacy of the PRA used to support risk-informed applications received after March 2010. However, on occasion, the peer review of the PRA models used to support ILRT interval extension applications will have been performed using Revision 1 of RG 1.200 (ADAMS Accession No. ML070240001 ). In such circumstances, Revision 2 of NEI 05-04, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard" (ADAMS Accession No. ML083430462),

provides guidance on performing a self-assessment for gaps between the PRA standard endorsed in Revisions 1 and 2 of RG 1.200. The staff's regulatory position on the use of self-assessments following Revision 2 of NEI 05-04, documented in Appendix C of Revision 2 of RG 1.200, clarifies the staff's expectations for such self-assessments and states, in part, that:

... if the results of the self-assessment are used to demonstrate the technical adequacy of a PRA for an application, differences between the current version of the Standard as endorsed in Appendix A and the earlier version of the ASME PRA Standard (i.e., RA-Sb-2005) be identified and addressed.

Furthermore, in Regulatory Position 4.2 of RG 1.200, Revision 2, the NRC staff stated that it expects licensees to submit a discussion of the resolution of peer review findings that are applicable to the parts of the PRA required for the application.

3.5.3.1 Internal Events In Appendix A of Attachment 3 of the LAR, the licensee stated that the submitted risk analyses use the most recent full-power internal events (FPIE) PRA model for Hope Creek (referred to as the HC111A version) and the subsequent containment response resulting in various fission product release categories. The licensee described the process used for controlling the PRA model and for ensuring that the model reflects the as-built and as-operated plant. Hope Creek has a process for continued PRA maintenance and updates, including procedures for regularly scheduled PRA model updates and for tracking issues identified as potentially affecting the PRA 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 into the FPIE PRA model that would affect this application. As a result, the FPIE PRA model sufficiently represents the as-built and as-operated plant for this application.

The PRA technical adequacy for Hope Creek is discussed in Section A.2 of Appendix A of of the LAR. The licensee stated in the LAR and clarified in its request for additional information (RAI) response that an independent full-scope peer review of the internal events and internal flooding PRA model was performed in 2008 against the requirements set forth in the 2005 version of the ASME PRA standard and the qualifications provided in the staff's endorsement of that standard in RG 1.200, Revision 1. The peer review was performed against the CC II Supporting Requirements. Following PRA model revisions arising from the peer review, the licensee performed a self-assessment of the Hope Creek FPIE PRA model in 2011 to determine if there were any gaps present between the Hope Creek FPIE PRA model and the CC II Supporting Requirements in the 2009 version of the ASME/American Nuclear Society

(ANS) PRA standard and qualifications provided in the staff's endorsement of that standard in RG 1.200, Revision 2.

By letter dated March 27, 2017, the licensee provided an overview of all the changes to the internal events PRA model that occurred after the full-scope peer review and stated that none of the changes constitute PRA model upgrades that would require focused-scope peer reviews.

The staff notes that one of the changes made to the model subsequent to the full-scope peer review was "[m]igration" to the EPRI human reliability analysis (HRA) calculator. The use of the HRA calculator can potentially qualify as a PRA model upgrade. The licensee stated, however, that the use of the HRA calculator was a modeling enhancement and that a new methodology was not used. The NRC staff is not able to unequivocally determine whether the use of the HRA calculator constitutes a PRA upgrade. However, since the licensee asserted that it did not use a new HRA methodology and sufficient margin exists between the reported risk metrics for the application and the acceptance guidelines (discussed in SE Section 3.2.2), the NRC staff is able to determine that uncertainties in the implementation of the EPRI HRA calculator will not impact the conclusions of this SE. Accordingly, the staff concludes that the licensee's response to RAl-3b is acceptable for this application. It should be noted that the acceptability in the context of this application does not eliminate the possibility of NRC review of the use of the EPRI HRA calculator for other risk-informed LARs from the licensee where acceptability requirements can be different.

In Table A-1 of Appendix A of Attachment 3 of the LAR, the licensee provided a list of the facts and observations (F&Os) from the full-scope peer review and the corresponding resolutions. In addition, Table A-2 of Appendix A of Attachment 3 of the LAR documented the results of the "gap assessment" against CC II Supporting Requirements in the 2009 version of the ASME/ANS PRA standard performed as part of the 2011 self-assessment. The self-assessment identified and addressed the differences between the 2009 and 2005 versions of the ASME/ANS PRA standard. The NRC staff reviewed the F&Os and the gaps reported by the licensee to determine whether the licensee's resolutions appropriately addressed the corresponding F&Os such that the resulting quality of the FPIE PRA model was sufficient to support the risk assessment for this application. The NRC staff requested additional information regarding the resolution of several F&Os; these are discussed below. The NRC staff's review of the other F&Os determined that they were either appropriately dispositioned or did not have an impact on the risk assessment for this application.

F&O LE-G1-01 stated that the Level 2 analysis notebook was very detailed but not "written in a manner conducive to demonstrating the requirements of the standard were met" and that it "limited the ability of the Peer-Review team to perform an adequate review." The F&O statements appeared to imply that the peer review team, due to the limitations cited in the F&O, did not review or only partially reviewed the Level 2 analysis against the LERF analysis supporting requirements of the 2005 ASME PRA standard. Since LERF is a key metric in the risk assessment supporting this application, the NRC staff requested further justification as to why a focused-scope peer review of the Level 2 PRA model is not required. By letter dated March 27, 2017, the licensee stated that the peer review team reviewed the Level 2 model against all LERF analysis supporting requirements, F&O LE-G1-01 was the only finding for the LERF analysis technical element, and all other LERF analysis supporting requirements were shown in the peer review report as "SR [supporting requirement] Met" with at least a CC II. The licensee's response provided sufficient evidence to demonstrate that the resolution of the F&O as a documentation issue was appropriate. Therefore, the NRC staff determines the response to be acceptable for this application.

F&O QU-E4-01 identified that the evaluation of uncertainties did not identify or address plant-specific sources of uncertainty. In the F&O resolution, the licensee stated that this issue has not yet been resolved because there was no published guidance on the treatment of uncertainties at the time the resolution was documented. Since the guidance on the treatment of uncertainties in PRA has been issued, and the 2009 PRA standard (ASME/ANS RA-Sa-2009) endorsed by RG 1.200, Revision 2, requires evaluation of sources of model uncertainty, the NRC staff requested additional information on the licensee's uncertainty evaluation. By letter dated March 27, 2017, the licensee stated that the uncertainty evaluation mentioned in the F&O has been performed as part of the 2011 PRA model update and that the results of the uncertainty evaluation, the sources of model uncertainty, and the resulting impact on the model are included in the PRA model documentation. The licensee stated that the uncertainty evaluation is consistent with the staff guidance in NUREG-1855, Volume 1, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making, Main Report" (ADAMS Accession No. ML090970525), and the complementary industry guidance issued by EPRI. Because the licensee confirmed that it performed an uncertainty evaluation, the NRC staff concludes that the licensee's response is acceptable for this application.

F&O SY-B14-01 found that failure of common piping that affects more than one system has not been modeled as required by the supporting requirement. Further, the licensee did not provide a supporting example wherein the failure of common piping between the high pressure core injection (HPCl)/feedwater (FW)/core spray (CS) and reactor core isolation cooling (RCIC)/FW systems was modeled. By letter dated March 27, 2017, the licensee stated that it performed a review of the modeling of common piping between HPCl/FW/CS and RCIC/FW systems and justified the PRA modeling for this common piping. The licensee further stated that a review of system notebooks and relevant piping diagrams was performed, and no other instances of common piping that could fail multiple systems were identified. The NRC staff determines the licensee's response to be acceptable for this application since it demonstrated that common piping failures have been considered and modeled to support the current application.

F&O AS-B2-01 identified that the operation of the automatic depressurization system under conditions of a stuck open relief valve with failure of the high pressure makeup appeared to be modeled as always successful. Since the licensee's resolution to this F&O stated that this is a documentation issue only, the NRC staff requested more information on the PRA model impacts. By letter dated March 27, 2017, the licensee stated that it performed a review of the plant-specific thermal hydraulic calculations, event trees, and fault trees and found that the FPIE PRA model used for this application was consistent with the success criteria determined by the plant-specific thermal hydraulic-calculations; therefore, no model changes were required. The NRC staff concludes that the licensee's response provides sufficient justification to address the staff's concern and, therefore, is acceptable for this application.

F&O SC-A6-01 questioned the basis for crediting the diesel-driven firewater pump as a low pressure source of makeup to the reactor vessel after depressurization, stating that the pump flow curve had not been rigorously analyzed. In the resolution to this F&O, the licensee performed a detailed deterministic calculation of the fire pump flow curve and identified that additional equipment, such as a "fire pumper truck" was required to boost pressure for the success of the diesel-driven firewater pump. The NRC staff requested additional information about the modeling of human actions associated with the use of the firewater pump. By letter dated March 27, 2017, the licensee stated that the credit for the diesel-driven firewater pump and the fire pumper truck was removed from the FPIE PRA model during the 2011 model update, and a new alternate injection source was credited. The licensee also stated that the corresponding human failure event was fully developed and documented, and it provided

examples of sources of information that were used in developing the human failure event. The licensee's response clarifies the alternate injection method credited in the model and confirms that the corresponding human failure events have been incorporated. Therefore, the staff finds the response to be acceptable for this application.

In summary, the licensee evaluated its internal events PRA model against the currently implemented version of RG 1.200, Revision 2, and the currently endorsed ASME PRA standard (i.e., ASME/ANS RA-Sa-2009), evaluated the findings developed during the peer review of its internal events PRA for their applicability to the ILRT frequency extension, addressed the findings, or evaluated the impact. The staff reviewed the internal events peer review findings and determines that the dispositioned findings have been adequately addressed for this application. Therefore, the NRC staff concludes that the Hope Creek FPIE PRA model is of sufficient technical adequacy to support the current application.

3. 5. 3. 2 External Events In Section 3.2.4.2 of the SER for NEI 94-01, Revision 2, and EPRI TR-1009325, Revision 2, the NRC staff stated that:

Although 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 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 evaluated the impact of external events in Section 5. 7 of Attachment 4 of the LAR.

The licensee's assessment included a quantitative estimate of the contribution of internal fires 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 was negligible for this application.

To assess the fire risk, the licensee used the current version of the Hope Creek fire PRA (FPRA). The licensee stated that the FPRA had a peer review in 2010 against the 2009 version of the ASME/ANS PRA standard and RG 1.200, Revision 2. The licensee stated that the FPRA was updated in 2014 to address the peer review F&Os. Table A-4 of Appendix A of of the LAR provided the list of F&Os from the 201 O peer review of the FPRA and the corresponding resolutions. The NRC staff noted that some of the modeling choices made

during the resulting FPRA model modifications appeared to be non-conservative. In order to gain additional assurance that the updated FPRA would provide a reasonable order of magnitude estimate for use in the risk assessment for this application, the NRC staff requested additional information on the justification for the FPRA not under-predicting the fire risk, citing certain F&Os as examples of potential non-conservatisms. By letter dated March 27, 2017, the licensee provided the results of a sensitivity study to quantify the uncertainties in fire ignition frequencies and joint human error probabilities by increasing the error factor by 10. The results of the sensitivity demonstrated that the impact of the increased uncertainty on the fire CDF, and consequently the risk quantification for this application, is small. It should be noted that the licensee also provided several qualitative arguments on uncertainty quantification. The staff is unable to verify those arguments due to lack of supporting analysis and, therefore, did not consider them in its decision on the sufficiency of the response.

By letter dated March 27, 2017, the licensee also addressed other potential non-conservatisms identified by the NRC staff including:

• completeness of the sources of uncertainty,

• lack of quantification of the risk associated with multi-compartment fires,

• treatment of the failure probability for alternate shutdown, and

• fraction of cable length assumed to participate in cable tray fires.

In addition, the licensee reviewed the FPRA peer review F&Os and identified other possible non-conservatisms such as:

• unavailability of cable data for operator instrumentation,

• screened out ignition sources for certain plant areas,

• use of an inappropriate transient heat release rate, and

• lack of a review of plant-specific detection and suppression availability for multi-compartment analysis and main control room scenarios.

For each of these potential non-conservatisms, the licensee provided justification for why it would not result in under-prediction of the fire risk by the FPRA. The justifications included:

• the need to meet only CC I of the 2009 ASME/ANS PRA standard for the relevant supporting requirement and the requirements therein,

• modifications to the updated FPRA such as logic inclusion and use of NRC recommended values, and

• a comparative explanation for the cable length weighting factor being conservative.

Based on the review of the licensee's response for each potential non-conservatism cited above, the NRC staff concludes that non-conservatisms in the Hope Creek FPRA are not expected to result in significant under-prediction of the fire risk metrics used for the risk assessment to support this application. In addition, the fire risk metrics provide sufficient margin to the acceptance criteria for ILRT frequency extension. Therefore, the NRC staff determines that the current FPRA order of magnitude estimate for the contribution of the internal fire risk is acceptable for this application.

To estimate the risk contribution from seismic events, the licensee used the seismic core damage frequency (SCDF) calculations performed for Hope Creek as part of Generic Issue (Gl)-199, "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and

Eastern United States on Existing Plants: Safety/Risk Assessment" (ADAMS Accession No. ML100270639). The licensee used the maximum value of the SCDF calculated for Hope Creek as part of the Gl-199 issue. The NRC staff noted that, based on the seismic hazard reevaluation performed in response to Recommendation 2.1 of the near-term task force, by letter dated March 28, 2014 (ADAMS Accession No. ML14087A436), the licensee concluded, and the staff confirmed, by letter dated February 29, 2016 (ADAMS Accession No. ML16049A609), that a seismic risk reevaluation is not merited. Therefore, the Gl-199 analysis represents the most recent available estimate of the seismic risk for Hope Creek. The NRC staff concludes that the use of the maximum value from the Gl-199 analysis for Hope Creek to provide an order of magnitude estimate of the seismic risk contribution is acceptable for this application.

The licensee stated that the risk from other external hazards, including high winds and tornadoes, external floods, transportation accidents, and nearby facility accidents is negligible, based on the Hope Creek individual plant examination for external events analysis. By letter dated March 27, 2017, the licensee assessed the applicability of these individual plant examination for external events conclusions for the current plant. The licensee stated that the initiating event resulting from loss of service water caused by buildup of detritus, such as mud and grass on the traveling screens, is a plant-specific special initiator and is included in the Hope Creek PRA model used for this application. The licensee also performed a review of the current plant conditions and any updated hazards and concluded that the risk from these external hazards remains negligible. The staff concludes that the licensee's assessment of risk from high winds and tornadoes, transportation accidents, and nearby facility accidents is acceptable for this application.

Regarding external flooding, based on the external flooding hazard reevaluation performed by the licensee in response to Recommendation 2.1 of the near-term task force (ADAMS Accession Package Accession No. ML14071A505 and Accession No. ML16266A281), the licensee stated that the current design basis is bounding for all external flooding events except for the local intense precipitation (LIP) event. This external flooding hazard reevaluation concluded that several external flooding mechanisms, including substantial storm surges, are plausible for the site and may lead to flooding in excess of the plant grade such that water could impinge upon plant structures. Therefore, the staff found that the licensee's justification of negligible risk impact of external flooding, which was based on conformance with the current design basis, was insufficient because it did not account for:

1. The possible failure of flood barriers due to degraded or missing seals and other factors demonstrated by operational experience (NRC Information Notice 2015-01, "Degraded Ability to Mitigate Flooding Events" (ADAMS Accession No. ML14279A268)),

2. The frequency of occurrence of external floods, and

3. The failure estimates for procedures and operator actions required to be performed as part of flood mitigation efforts.

Therefore, the staff requested the licensee to provide an assessment of the impact of external flooding risk on this application.

By letter dated July 13, 2017, the licensee provided a qualitative explanation to support the assessment of negligible impact of external flooding risk on this application. The licensee stated that the reevaluated external flooding hazard demonstrated that flooding above plant grade can occur only for the LIP, storm surge, and probable maximum flood in conjunction with a storm surge. The licensee also stated, citing the reevaluated external flooding hazard and related

RAls, that LIP and storm surge events that can challenge the plant's design-basis flood protection features have an annual exceedance frequency of 1.0 x 10-5 per year or lower.

According to the licensee, the rainfall rate used for the LIP event that can challenge the plant's design basis is estimated to have an annual frequency of 1.0 x 10-5 to 1.0 x 10-9 per year.

The licensee stated that Hope Creek's design-basis flood protection features were established to cope with a hurricane storm surge, do not include any temporary features, and the watertight doors are the only active flood protection features. The balance of the flood protection features are passive and continually maintain their full hydraulic capability. In support of the reliability of the flood protection features, the licensee stated that the walkdowns performed in response to Recommendation 2.3 of the near-term task force (letters dated November 26, 2012, and November 18, 2013 (ADAMS Accession Nos. ML12334A452 and ML13266A297, respectively),

provided confirmation that flood protection features are in place, are in good condition, and will perform as credited in the CLB. The licensee also stated that it has implemented condition monitoring of flood control features such as concrete walls and slabs, water-control structure elements, penetration seals, etc. The licensee further stated it has procedures in place providing specific instructions regarding the inspection of Hope Creek's penetration seals, as well as the inspection and maintenance of the watertight doors.

The licensee cited a severe weather guidance document and an abnormal operating procedure to support the reliability of operator actions in the event of external flooding. The licensee provided a list of external flooding events that would result in entry into the cited abnormal operating procedure, which would, in turn, instruct operators to increase monitoring of river levels and perform closure of water-tight doors onsite. The licensee stated that the operators can monitor river level conditions from the control room and that the actions to close water-tight doors are within the capability of the minimum shift complement to complete. The licensee also stated that the trigger events that result in entry into the abnormal operating procedure provide sufficient time for the operators to complete required actions prior to water levels on site approaching the level where flooding could impact system operations.

The staff concludes that the licensee's response provides sufficient qualitative basis to support the negligible impact of external flooding risk on this application and is, therefore, acceptable for this application. The licensee also included a "rough" quantitative estimate of the risk from external flooding that the licensee considered to be bounding; however, since it lacked adequate justification and clarity, the NRC staff did not consider the quantitative estimate during its review.

In summary, the staff concludes that the licensee's methodology and evaluation of the impact of external hazards on the risk assessment for the ILRT frequency extension is acceptable for the application.

Based on the review of the internal events PRA model and the treatment of external events in the context of this application as documented in the preceding discussion, the staff concludes that the first condition in Section 4.2 of the NRC SER for the use of EPRI TR-1009325, Revision 2, is met for this application.

3.5.4 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, Revision 2, "An Approach for Using

Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," and the clarification provided in Section 3.2.4.6 of the NRC SER 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-roentgen equivalent man (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 head for ECCS injection, both CDF and LERF will be considered in the ILRT evaluation and compared with the risk acceptance guidelines in RG 1.174 2. In Section 3.3 and Table 3.5.1-1 of Attachment 1 of the LAR, the licensee stated that containment over-pressure is not relied upon for ECCS performance for Hope Creek. Therefore, the risk metrics of interest for the Hope Creek ILRT interval extension application are changes (delta) in LERF, population dose, and CCFP.

The licensee reported the results of the plant-specific risk assessment in Section 3.5.3 of the LAR. Details of the risk assessment for Hope Creek are provided in Attachment 3 of the LAR.

The reported risk impacts are risk impact from baseline, which estimates the impact of a change in test frequency from three tests in 10 years (the test frequency under 10 CFR Part 50, Appendix J, Option A) to one test in 15 years. The following conclusions can be drawn based on the licensee's analysis associated with extending the ILRT frequency:

1. The reported increase in LERF for a change in the ILRT interval from three tests in 1O years to one test in 15 years is 2.68 x 10-7 per year. These numbers include both contributions from both internal and external events (internal fires and seismic hazards) and the impact from steel liner corrosion. This change in risk is considered to be "small" (i.e., between 1 x 10-6 per year and 1 x 10-7 per year) per acceptance guidelines in RG 1.174. According to RG 1.174, for "small" changes in risk, an assessment of baseline LERF is required to show that the total LERF is less than 1 x 10-5 per year. The licensee estimated total base LERF, including the contribution from external events and o-the extended ILRT interval, is determined to be 4.82 x 1 6 per year (this value was corrected by letter dated March 27, 2017, which corrected the value originally provided in the LAR). The total base LERF value is less than the corresponding threshold of 1.0x10-5 per year in RG 1.174.

2. Given a change in the Type A ILRT frequency from three in 10 years to one in 15 years, the reported increase in the total population dose for Hope Creek from internal and external events is 3.53 x 10-2 person-rem per year, or 0.1 percent of the total population dose as reported in Table 5.7-6 of Attachment 3 of the LAR. The licensee used a multiplier approach to calculate the dose increase from external events using the internal events based dose increase value. The multiplier approach and value are the same as those used for determining the increase in LERF from external events based on the internal events value. The reported increase in the total population dose for Hope Creek is less than the value associated with a small increase in population dose.

3. The licensee reported the increase in CCFP for Hope Creek from internal and external events from a test interval of three tests in 10 years to one test in 15 years as 0.93 percent. This value is less than the acceptance guidelines in Section 3.2.4.6 of the NRC SER for NEI 94-01, Revision 2, and is, therefore, acceptable.

It should be noted that the licensee also provided risk assessment results based on expert elicitation of the probability for large and small preexisting leaks in the containment in Section 6.2 of Attachment 3 of the LAR. Section 3.2.4.5 of the SER for NEI 94-01, Revision 2, and EPRI TR-1009325, Revision 2, state that the NRC staff does not accept the expert elicitation as presented; therefore, the NRC staff did not consider this risk assessment.

Based on the review of the risk assessment results as documented in the preceding discussion, the NRC staff concludes that the increase in LERF for Hope Creek for the proposed ILRT frequency extension is small and consistent with the acceptance guidelines of RG 1.17 4. The increase in the total integrated plant risk and the small 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. Therefore, the NRC staff concludes that the second condition is met for this application.

3.5.5 Leak Rate for the Large Preexisting 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 preexisting containment large leak rate accident case (i.e., accident case 3b) used by the licensees shall be 100 La instead of 35 La.

As noted by the licensee in Table 3.5.1-1 of Attachment 1 of the LAR, the methodology in EPRI TR-1009325, Revision 2-A, incorporates the use of 100 La as the average leak rate for the preexisting containment large leak rate accident case. The same value has been used by the licensee in Section 5 of Attachment 3 of the LAR for the risk evaluation for this application.

Accordingly, the staff concludes that the third condition in Section 4.2 of the NRC SER for the use of EPRI TR-1009325, Revision 2, is met for this application.

3.5.6 Applicability if Containment Over-Pressure is Credited for ECCS Performance The licensee stated in Section 3.3 and Table 3.5.1-1 of Attachment 1 of the LAR that containment over-pressure is not relied upon for ECCS performance for Hope Creek.

Therefore, the staff concludes that the fourth condition in Section 4.2 of the NRC SER for the use of EPRI TR-1009325, Revision 2, is not applicable to the review of the this application.

3.5. 7 PRA Conclusion Based on the evaluations in SE Section 3.5, the NRC staff concludes that the increase in projected risk due to the proposed change is within the acceptance guidelines, while maintaining the defense-in-depth philosophy of RG 1.174, and is, therefore, acceptable.

3.6 Deletion of Exception The existing Hope Creek TS 6.8.4.f exception to NEI 94-01 requires the first Type A test performed after April 12, 1994, to be performed no later than April 12, 2009. The date has passed and the test was completed on April 28, 2009. Therefore, the NRC staff finds it acceptable to remove this exception from TS 6.8.4.f.

3.7 Technical Conclusion Based on the review and assessment described above, the NRC staff concludes that the proposed changes to TS 6.8.4.f are acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the New Jersey State Official was notified of the proposed issuance of the amendment on October 17, 2017. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves 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 Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding (December 20, 2016; 81 FR 92869). Accordingly, the amendment meets 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 amendment.

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 amendment will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors: Jerome Bettle Dan Hoang Shilp Vasavada Date: November 8, 2017

P. Sena

SUBJECT:

HOPE CREEK GENERATING STATION - ISSUANCE OF AMENDMENT RE: TECHNICAL SPECIFICATION CHANGE FOR PERMANENT EXTENSION TO TYPE A AND TYPE C CONTAINMENT LEAK RATE TEST FREQUENCIES (CAC NO. MF8462; EPID L-2016-JLD-0011) DATED NOVEMBER 8, 2017 DISTRIBUTION:

PUBLIC RidsACRS_MailCTR Resource RidsNrrDssStsb Resource RidsNrrDorlLpl1 Resource RidsRgn 1MailCenter Resource RidsNrrSbpb Resource RidsNrrStsb Resource RidsNrrDraApla Resource RidsNrrPMHopeCreek Resource RidsNrrLALRonewicz Resource JBettle, NRR RidsNrrDeEeob Resource SVasavada, NRR DHoang, NRR ADAMS A ccess1on No.: ML17291A209 *b1y memo **b1y e-ma1*1 OFFICE DORL/LPL 1/PM DORL/LPL 1/LA DE/EEOB/BC* DRA/APLA/BC*

NAME LRegner LRonewicz JQuichocho SRosenberg DATE 10/18/2017 10/19/2017 03/06/2017 09/06/2017 OFFICE DSS/SBPB/BC* DSS/STSB/BC(A)** OGC** DORL/LPL 1/BC NAME RDennig JWhitman JGillespie JDanna DATE 05/24/2017 10/18/2017 10/30/2017 11/06/2017 OFFICE DORL/LPL 1/PM NAME LReQner DATE 11/08/2017 OFFICIAL RECORD COPY