ML18137A271

Issuance of Amendments Regarding Permanent Extension of Type a and Type C Leak Rate Test Frequencies (Cac. Nos. MF9687 and MF9688; EPID L-2017-LLA-0228) (RS-17-060)

ML18137A271
Person / Time
Site:	Dresden
Issue date:	06/29/2018
From:	Haskell R Plant Licensing Branch III
To:	Bryan Hanson Exelon Generation Co, Exelon Nuclear
Haskell R NRR/DORL/LPL3, 415-1129
References
CAC MF9687, CAC MF9688, EPID L-2017-LLA-0228, RS-17-060
Download: ML18137A271 (62)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 June 29, 2018 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:

DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3-ISSUANCE OF AMENDMENTS REGARDING PERMANENT EXTENSION OF TYPE A AND TYPE C LEAK RATE TEST FREQUENCIES (CAC NOS. MF9687 AND MF9688; EPID L-2017-LLA-0228) (RS-17-060)

Dear Mr. Hanson:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 257 to Renewed Facility Operating License No. DPR-19 and Amendment No. 250 to Renewed Facility Operating License No. DPR-25 for Dresden Nuclear Power Station (DNPS), Units 2 and 3, respectively. The amendments consist of changes to the technical specifications (TSs) in response to your license amendment request (LAR) dated May 3, 2017, as supplemented by letter dated February 14, 2018.

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 the Type C leak rate testing frequencies by replacing the reference to Regulatory Guide 1.163 with a reference to Nuclear Energy Institute (NEI) Topical Report NEI 94-01, Revisions 2-A and 3-A.

Additionally, the amendments make an administrative change to the DNPS TSs to delete two previously satisfied exceptions of TS 5.5.12a that have expired.

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

~--ussell S.

, Project Manager Docket Nos. 50-237 and 50-249

Enclosures:

1. Amendment No. 257 to DPR-19

2. Amendment No. 250 to DPR-25

3. Safety Evaluation cc w/encls: Listserv Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 EXELON GENERATION COMPANY, LLC DOCKET NO. 50-237 DRESDEN NUCLEAR POWER STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 257 Renewed License No. DPR-19

1.

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

A.

The application for amendment by Exelon Generation Company, LLC (the licensee) dated May 3, 2017, as supplemented by letter dated February 14, 2018, 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 1 O 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 Renewed Facility Operating License No. DPR-19 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 257, are hereby incorporated into this renewed operating 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 issuance.

Attachment:

Changes to the Technical FOR THE NUCLEAR REGULATORY COMMISSION 0~

~. 5G A/'

u c_rt _

David J. Wrona, hief Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Specifications and Renewed Facility Operating License Date of Issuance:

June 2 9, 2 O 1 8

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 EXELON GENERATION COMPANY, LLC DOCKET NO. 50-249 DRESDEN NUCLEAR POWER STATION, UNIT 3 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 250 Renewed License No. DPR-25

1.

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

A.

The application for amendment by Exelon Generation Company, LLC (the licensee) dated May 3, 2017, as supplemented by letter dated February 14, 2018, 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 3.8. of Renewed Facility Operating License No. DPR-25 is hereby amended to read as follows:

B.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 250, are hereby incorporated into this renewed operating 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 issuance.

Attachment:

Changes to the Technical FOR THE NUCLEAR REGULATORY COMMISSION UJ 9 0)_

David J. Wrona, Chief Plant Licensing Branch 111 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Specifications and Renewed Facility Operating License Date of Issuance: June 29, 2018

ATTACHMENT TO LICENSE AMENDMENT NOS. 257 AND 250 DRESDEN NUCLEAR POWER STATION, UNITS 2 and 3 RENEWED FACILITY OPERATING LICENSE NOS. DPR-19 AND DPR-25 DOCKET NOS. 50-237 AND 50-249 Replace the following pages of the Renewed Facility Operating Licenses and the Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert Page 3 (DPR-19)

Page 3 (DPR-19)

Page 4 (DPR-25)

Page 4 (DPR-25)

TSs TSs Page 5.5-11 Page 5.5-11 Page 5.5-12 Page 5.5-12 (2)

Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Part 70, to receive, possess and use at any time special nuclear materials as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Updated Final Safety Analysis Report, as supplemented and amended; (3)

Exelon Generation Company, 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; (4)

Exelon Generation Company, 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 (5)

Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct special nuclear materials as may be produced by the operation of the facility.

C.

This renewed operating 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; 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 The licensee is authorized to operate the facility at steady state reactor core power levels not in excess of 2957 megawatts thermal (100 percent rated power) in accordance with the conditions specified herein.

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 257, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

(3)

Operation in the coastdown mode is permitted to 40% power.

Renewed License No. DPR-19 Amendment No. 257

f.

Surveillance Requirement 4.9.A.10 - Diesel Storage Tank Cleaning (Unit 3 and Unit 2/3 only)

Each of the above Surveillance Requirements shall be successfully demonstrated prior to entering into MODE 2 on the first plant startup following the fourteenth refueling outage (D3R 14 ).

3.

This renewed operating license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations: 10 CFR Part 20, Section 30.34 of 10 CFR Part 30, Section 40.41 of 10 CFR Part 40, Sections 50.54 and 50.59 of 10 CFR Part 50, and Section 70.32 of 10 CFR Part 70; 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:

A.

Maximum Power Level B.

C.

The licensee is authorized to operate the facility at steady state power levels not in excess of 2957 megawatts (thermal), except that the licensee shall not operate the facility at power levels in excess of five (5) megawatts (thermal), until satisfactory completion of modifications and final testing of the station output transformer, the auto-depressurization interlock, and the feedwater system, as described in the licensee's telegrams; dated February 26, 1971, have been verified in writing by the Commission.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 250, are hereby incorporated into this renewed operating license.

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

Reports The licensee shall make certain reports in accordance with the requirements of the Technical Specifications.

D.

Records The licensee shall keep facility operating records in accordance with the requirements of the Technical Specifications.

E.

Restrictions Operation in the coastdown mode is permitted to 40% power.

Renewed License No. DPR-25 Amendment No. 250

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 5.5.12 Safety Function Determination Program CSFDP)

(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.

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(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.

(continued)

Dresden 2 and 3 5.5-11 Amendment No. 257nso

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 5.5.13 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.

Battery Monitoring and Maintenance Program This Program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450-1995, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications," including the following:

a.

Actions to restore battery cells with float voltage

< 2.13 V, and

b.

Actions to equalize and test battery cells that had been discovered with electrolyte level below the minimum established design limit.

(continued)

Dresden 2 and 3 5.5-12 Amendment No. 257/250

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RE: LICENSE AMENDMENT REQUEST TO EXTEND THE CONTAINMENT TYPE A AND TYPE C LEAK RA TE TEST FREQUENCIES AT DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3 DOCKET NOS. 50-237 AND 50-249

1.0 INTRODUCTION

By application dated May 3, 2017 (Reference 1 ), Exelon Generation Company, LLC (EGC, the licensee), requested that the U.S. Nuclear Regulatory Commission (NRC, the Commission) approve an amendment for the Dresden Nuclear Power Station (DNPS), Unit 2, Renewed Facility Operating License (RFOL) (DPR-19), and the DNPS, Unit 3, RFOL (DPR-25), in the form of changes to the technical specifications (TSs). This request was supplemented by letter dated February 14, 2018 (Reference 2). The license amendment request (LAR) proposes changes to 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) Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR [Title 10 of the Code of Federal Regulations] Part 50, Appendix J" (Reference 3), Revision 3-A, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A (Reference 4). 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 5.5.12a reference to Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program" (Reference 5), with a reference to NEI 94-01, Revision 3-A. Additionally, the LAR proposes an administrative change to the DNPS TSs to delete previously satisfied exceptions 1 and 2 of TS 5.5.12a that expired in 1996 and 2009, respectively.

The supplemental letter dated February 14, 2018, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staff's original proposed no significant hazards consideration determination as published in the Federal Register (FR) on August 1, 2017 (82 FR 35838).

2.0

2.1 REGULATORY EVALUATION

Description of DNPS Containment DNPS, Units 2 and 3, were built with the General Electric Mark I primary containment system that is designed to condense the steam released during a postulated loss-of-coolant accident (LOCA), to limit the release of fission products associated with such an accident, and to serve as a source of water for the emergency core cooling system (ECCS). The primary containment system consists of a drywell; a pressure suppression chamber which is partially filled with water; a vent system connecting the drywell and the suppression chamber water pool; isolation valves; heating, ventilating, and cooling systems; and other service equipment.

The drywell is a steel pressure vessel which houses the reactor vessel, the reactor coolant recirculation system, and other branch connections of the reactor primary system. It has a spherical lower section, approximately 66 feet (ft.) in diameter, a cylindrical upper section, approximately 37 ft. in diameter, and a hemispherical tophead.

The drywell shell is enclosed in reinforced concrete to provide radiological shielding and additional resistance to deformation. A portion of the lower spherical drywell section is embedded in concrete. Beneath the drywell is concrete fill from the spring line down. At the foundation level, a sand pocket was formed to soften the transition between the foundation and the containment vessel. Above the foundation transition zone, the drywell is separated from the reinforced concrete by a gap of approximately 2 inches to accommodate thermal expansion. The embedment in combination with the upper lateral restraints attached to the cylindrical section forms the drywell support system.

The pressure suppression chamber is an approximately toroidal steel pressure vessel encircling the base of drywell. Due to its shape, the suppression chamber is commonly called the torus. It is approximately 109 ft. in diameter, constructed from 16 mitered cylindrical shell segments 30 ft. in diameter, joined together to shape a torus, encircling and located below the drywell. It contains approximately 116,300 cubic feet of water and has a free air volume above the water line. The vertical support system provides a load transfer mechanism which acts to reduce local suppression chamber shell stresses and to more evenly distribute reaction loads to the reactor building basemat.

The vent system from the drywell terminates below the suppression chamber water level. The drywell and suppression chamber are interconnected by the vent system.

Eight main vents connect the drywell to a vent ring header, which is located within the suppression chamber air space. A bellows assembly is located at the junction where each main vent penetrates the suppression chamber shell to permit differential movement of the suppression chamber and drywell/vent system. Projecting downward from the vent ring header are downcomer pipes, arranged in 48 pairs around the vent header circumference, terminating below the surface of the suppression chamber water volume.

The safety design basis for the primary containment is to withstand the pressures and temperatures of the limiting design basis accident (OBA) without exceeding the design leakage rate. Primary containment is designed for a maximum internal pressure of 62 pounds per square inch gauge (psig), with a maximum temperature of 281 degrees Fahrenheit (°F). The maximum allowable leakage rate for primary containment is s 1.0 La, (leakage absolute) where La is defined as three percent of primary containment air weight per day at the design basis LOCA maximum peak containment pressure Pa (pressure absolute) of 43.9 psig.

2.2 Licensee Proposed Changes A Type A test is an overall ILRT of the containment structure. NEI 94-01, Revision 0, specifies an initial test interval of 48 months, but allows an extended interval of 1 O years, based upon two consecutive successful tests. There is also a provision for extending the test interval an additional 15 months, but this provision "should be used only in cases where refueling schedules have been changed to accommodate other factors." Amendment No. 210 to Facility Operating License No. DPR-19 for DNPS, Unit 2, allowed a one-time extension of the ILRT interval to 15 years and Amendment No. 202 to Facility Operating License No. DPR-25 for DNPS, Unit 3, allowed a one-time extension of the ILRT interval to 15 years (Reference 6).

However, subsequent to these one-time extensions, both long-term ILRT test interval requirements in DNPS TS 5.5.12 remained at 10 years.

For DNPS, Unit 2, the licensee proposes to extend the interval for the containment ILRT to 15 years. The most recent DNPS, Unit 2, ILRT was completed during refueling outage (RFO) 21 (D2R21) in November 2009. The results of DNPS, Unit 2, Type A tests of February 1996 and November 2009 are reflected in Table 3.3.4-2 of the LAR, "DNPS ILRT Test Results Verification of Current Extended ILRT Interval." It can be seen in Table 3.3.4-2 and its associated "Note 1" that both DNPS, Unit 2, Type A tests were performed consistent with the definition of Pa. Both Type A tests were successful in that the "Adjusted As Left Leak Rate" test results were less than 1.0 La as specified by the limiting value of DNPS TS 5.5.12. Both Pa and La are defined respectively in DNPS TS 5.5.12b and c of the "Primary Containment Leakage Rate Testing Program." Accordingly, the next DNPS, Unit 2, ILRT is due during the fall of 2019 (D2R26). Using the proposed interval of 15 years, the next DNPS, Unit 2, ILRT would need to be completed before the end of November 2024.

For DNPS, Unit 3, the licensee proposes to extend the interval for the containment ILRT to 15 years. The most recent DNPS, Unit 3, ILRT was completed during RFO 20 (D3R20) in November 2008. The results of the DNPS, Unit 3, Type A tests of July 1994 and November 2008 are reflected in Table 3.3.4-2 of the LAR, "DNPS ILRT Test Results Verification of Current Extended ILRT Interval." It can be seen in Table 3.3.4-2 and its associated "Note 1" that both DNPS, Unit 3, Type A tests were performed consistent with the definition of Pa. Both Type A tests were successful in that the "Adjusted As Left Leak Rate" test results were less than 1.0 La as specified by the limiting value of DNPS TS 5.5.12. Both Pa and La are defined respectively in DNPS TS 5.5.12b and c of the "Primary Containment Leakage Rate Testing Program."

Accordingly, the next DNPS, Unit 3, ILRT is due during the fall of 2018 (D3R25). Using the proposed interval of 15 years, the next DNPS, Unit 3, ILRT would need to be completed before the end of November 2023.

The current DNPS TS 5.5.12, "Primary Containment Leakage Rate Testing Program" states, in part:

a. This program shall establish the leakage testing of the primary containment as required by 10 CFR 50.54 (o) and 10 CFR [Part] 50, Appendix J, Option B, as modified by approved exemption. This program shall be in accordance with the guidelines contained in [RG] 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 2 Type A test performed after the February 28, 1996, Type A test shall be performed no later than February 27, 2011.

2. NEI 94 1995, Section 9.2.3: The first Unit 3 Type A test performed after the July 14, 1994, Type A test shall be performed no later than July 13, 2009.

The proposed amendments would replace the reference to RG 1.163 with NEI Topical Report NEI 94-01, Revision 2-A, and Revision 3-A, and would state, in part:

a. This program shall establish the leakage testing of the primary containment as required by 10 CFR 50.54(0) and 10 CFR [Part] 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 [Part] 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 proposed amendments would also delete exceptions 1 and 2.

NEI 94-01, Revision 2-A, describes an approach for implementing the optional performance-based requirements of Option B of 10 CFR Part 50, Appendix J. It incorporates the regulatory positions stated in RG 1.163 (September 1995), and includes provisions for extending Type A test intervals to up to 15 years. In the NRC safety evaluation (SE) dated June 25, 2008 (Reference 7), the NRC staff concluded that NEI 94-01, Revision 2, describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR Part 50, Appendix J, and is acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the specific Limitations and Conditions listed in Section 4.1 of the SE.

As noted above in proposed TS 5.5.12a, the licensee requests an administrative change be made to TS 5.5.12a by deleting the two exceptions regarding the performance of the next DNPS Type A tests to be performed no later than February 27, 2011, for DNPS, Unit 2, and July 13, 2009, for DNPS, Unit 3.

In the LAR, the licensee states:

[t]his change will have no impact as these dates have already occurred and these Type A tests have already been performed.

In the LAR, the licensee also states:

[t]his Type A test information had been previously approved in Amendments Nos. 210 and 202 for DNPS, Units 2 and 3, respectively, and is no longer applicable since the test dates occur in the past.

2.3 Regulatory Requirements The LAR requested a change to the RFOLs for DNPS, in accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit."

Regulation 10 CFR 50.36(c)(5), "Administrative controls," requires, 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 the "Administrative Controls" section of the DNPS TSs.

Regulation 10 CFR Part 50.54( o) requires that the primary reactor containments for water-cooled power reactors shall be subject to the requirements set forth in Appendix J to 10 CFR Part 50, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors."

Appendix J includes two options, "Option A - Prescriptive Requirements," and "Option B -

Performance-Based Requirements," either of which may be chosen for meeting the requirements of Appendix J. The testing requirements in Appendix J ensure that: (a) leakage through the containments or systems and components penetrating the containments does not exceed allowable leakage rates specified in the TS, and (b) the integrity of the containment structure is maintained during its service life. At DNPS, the licensee has implemented Option B to meet the requirements of Appendix J.

Section V.B.3 of 10 CFR Part 50, Appendix J, Option B, requires that the RG 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 TS. Furthermore, a 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 an RG.

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

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.

Regulation 1 O CFR 50.55a, "Codes and standards," contains the containment in-service inspection (CISI) program requirements that, in conjunction with the requirements of 10 CFR Part 50, Appendix J, ensure the continued leak-tightness and structural integrity of the containment during its service life.

Regulation 10 CFR 50.65 (a), "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," 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, as defined in paragraph (b) of this section, are capable of fulfilling their intended functions. These goals shall be established commensurate with safety and, where practical, take into account industrywide operating experience.

2.4 Regulatory Guidance Guidance for extending Type C Local Leak Rate Test (LLRT) surveillance intervals beyond 60 months is provided in NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," July 2012 (Reference 3).

Guidance for extending Type A ILRT surveillance intervals beyond 10 years is provided in NEI 94-01, Revision 2-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," October 2008 (Reference 4).

3.0 TECHNICAL EVALUATION

The NRC staff reviewed the DNPS LAR (including supplemental information) from the perspective of deterministic considerations with regard to containment leak-tight integrity. The staff's review and analysis of these changes is discussed in the following subsections.

3. 1 Staff Evaluation of Licensee's Proposed Changes In the LAR, the licensee proposed to revise DNPS TS 5.5.12 by replacing the reference to RG 1.163 with a reference to NEI 94-01, Revision 3-A, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, as the documents used at DNPS to implement the performance-based leakage testing program in accordance with Option B of 10 CFR Part 50, Appendix J. By invoking these two NEI 94-01 TRs as the reference documents for TS 5.5.12, the NRC staff notes that the licensee will be:

adopting the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, "Containment System Leakage Testing Requirements" (Reference 8); and adopting a more conservative grace interval of 9 months, for Type A, Type B, and Type C leakage tests in accordance with NEI 94-01, Revision 3-A (Reference 3).

With respect to the proposed deletions of the existing TS 5.5.12a exceptions 1 and 2, the NRC staff has determined that the deletions are appropriate. Table 3.3.4-2 of Attachment 1 to the LAR lists the first DNPS, Unit 2, Type A test after the February 1996 ILRT as being completed in November 2009. Similarly, Table 3.3.4-2 lists the first DNPS, Unit 3, Type A test after the July 1994 ILRT as being completed in November 2008. Accordingly, the staff approves the licensee's proposed deletion of both exceptions "1" and "2" associated with DNPS TS 5.5.12a because the exceptions are no longer applicable.

The NRC staff determined that the LAR was consistent with the adoption of the guidance contained in both NEI 94-01, Revision 2-A, and NEI 94-01, Revision 3-A. The licensee justified the proposed changes by demonstrating adequate performance of the DNPS containments based on: (a) the historical plant-specific containment leakage testing program results; (b) the containment inservice inspection (GISI) program results; and (c) a DNPS plant-specific risk assessment.

3.1.1 DNPS, Unit 2, Type A Integrated Leak Rate Test History Per DNPS TS 5.5.12c, the Unit 2 primary containment was designed for a maximum allowable leakage rate, La, of 3.0 percent of primary containment air weight per day at the design basis LOCA maximum peak containment pressure, Pa. TS 5.5.12b states that Pa is 43.9 psig.

Since 1986, a total of five ILRTs have been performed on the DNPS, Unit 2, primary containment. All five ILRTs had satisfactory leakage rate results. These five ILRT test results were documented in Tables 3.3.4-1 and 3.3.4-2 of Attachment 1 to the LAR. The NRC staff created the following table to summarize the DNPS, Unit 2, ILRT test results:

rn DNPS U "t2 T ::>e YI A ILRT Ht IS Ory Test Date Test Upper95%

Level Correction As Left Min ILRT Leakage Acceptance Test Method I Pressure Confidence (wt%/day)

Pathway Rate Criteria(6l, La Data Analysis (psig)

Level Penalty for (wt%/day)

(wt%/day)

Technique (wt% /day)

Isolated Pathways (wt.%/davl Dec. 1986 (7)

(7)

(7)

(7)

(7) 0.6366 (8) 1.6 Dec. 1990 (7)

(7)

(7)

(7)

(7) 0.7428 (8) 1.6 May 1993 (7)

(7)

(7)

(7) 0.8184 (8)

(7) 1.6 Feb. 1996 50.59 0.33798(9) 0.00860(9) 0.09540(9) 0.44198 (9X10l Absolute psig 1.6 Method(3l /

(1X9)

BN-TOP-1, Rev 1 (4l Nov. 2009 45.8237 0.595874 (9)

Conservatively 0.1379(9) 0.7338 (9X10l 3.0 Mass Point<5l psig Ignored (2X9)

(9)

TABLE 3.1.1-1 Table Notes: c,1 Pa is 48 psig; C21 Pa is 43.9 psig; C3> absolute method analysis per Section 5.5.2 of ANSl-56.8-1994 (Reference 9); <41 BN-TOP-1 Revision 1, 1972 (Reference 1 O); (5l mass point analysis per Section 5.5.3 of ANSl-56.8-1994; (5lper TS 5.5.12c; (7l data not provided as part of the LAR; (a) data source LAR Table 3.3.4-1; (9l data source LAR Table 3.3.4-2; (ml ILRT Leakage Rate =

Upper 95 percent Confidence Level + As Left Min Pathway for Isolated Pathways + Level Correction.

NEI 94-01, Revision 3-A, Section 9.2.3, "Extended Test Intervals," states, in part:

In the event where previous Type A tests were performed at reduced pressure (as described in 10 CFR [Part] 50, Appendix J, Option A), at least one of the two consecutive periodic Type A tests shall be performed at peak accident pressure (Pa).

NEI 94-01, Revision 3-A, Section 9.1.2, "Test Interval," states, in part:

The elapsed time between the first and the last tests in a series of consecutive passing tests used to determine performance shall be at least 24 months.

The NRC staff confirmed that the Pa guidance of Section 9.2.3 has been satisfied as the last two DNPS, Unit 2, historical ILRTs (February 1996 and November 2009) were performed at or above Pa (see Table 3.1.1-1 above). Both Type A tests were performed at a pressure higher than the peak calculated design basis internal accident pressure for the DBLOCA Pa, which per TS 5.5.12b for Unit 2 is equal to 43.9 psig. On December 21, 2001, the NRC staff issued Amendment No. 191 associated with the Unit 2 EPU where Pa was lowered from 48 psig to its current TS value of 43.9 psig. On September 11, 2006, the NRC staff issued Amendment No.

221 associated with the Unit 2 adoption of the alternate source term (AST) methodology where La increased from 1.6 percent to 3.0 percent by weight of the primary containment atmosphere air mass per day. Therefore, the staff concludes that the above guidance of both NEI 94-01, Revision 3-A, Sections 9.1.2 and 9.2.3, has been satisfied.

Similarly, with respect to DNPS, Unit 2, Appendix J, Option B, current license basis DNPS TS 5.5.12 references document RG 1.163. Regulatory Position C of RG 1.1.63, in turn, states that NEI 94-01, Revision O "provides methods acceptable to the NRC staff for complying with the provisions of Option B in Appendix J to 10 CFR Part 50.... " Section 9.2.3, "Extended Test Intervals," of NEI 94-01, Revision 0, states, in part:

In reviewing past performance history, Type A test results may have been calculated and reported using computational techniques other than the Mass Point method from ANSI/ANS 56.8-1994 (e.g., Total Time or Point-to-Point).

Reported test results from these previously acceptable Type A tests can be used to establish the performance history. Additionally, a licensee may recalculate past Type A UCL [Upper Confidence Limit] (using the same test intervals as reported) in accordance with ANSI/ANS 56.8-1994 Mass Point methodology and its adjoining Termination criteria in order to determine acceptable performance history.

NEI 94-01, Revision 3-A, reads nearly identically, except that the test standard invoked is ANSI/ANS-56.8-2002.

The NRC staff notes that Section 9.2.3 does not mandate that a licensee recalculate past Type A test results to demonstrate conformance with the definition of "performance leakage rate" contained in NEI 94-01, Revision 3-A. The staff also notes that the DNPS, Unit 2, ILRT results since December 1986 demonstrated ample margin (i.e.,~ 48 percent) between each ILRT value and La. Accordingly, the staff did not request that the licensee reconstitute the Unit 2, Type A test results from earlier than the ILRT of February 1996.

The DNPS TS 5.5.12d.1, regarding leakage rate acceptance criteria, establishes the maximum limit for the DNPS, Unit 2, "As-Left" leakage rate for unit startup following completion of Type A testing at s 0. 75 La, which equals 2.25 percent by weight of the containment atmosphere air mass per day.

The DNPS, Unit 2, containment was designed for a leakage rate, La, not to exceed 3.0 percent by weight of the containment atmosphere air mass per day at the calculated peak pressure, Pa.

As displayed in Table 3.1.1-1, there has been adequate margin to the "As found" performance limit as described in TS 5.5.12c of La for all historical ILRTs spanning a period of time greater than 30 years.

3.1.1.1 Conclusion As stated above, the past five DNPS, Unit 2, ILRT results dating back to 1986 have confirmed that the primary containment leakage rates are acceptable with respect to the design criterion leakage of primary containment air weight (La) per day at the DBLOCA (Pa). The NRC staff concludes that, since the last two Type A tests for DNPS, Unit 2, had ILRT test results of less than 1.0 La, a test frequency of 15 years, in accordance with NEI 94-01, Revision 3-A, and the Limitations and Conditions of NEI 94-01, Revision 2-A, is acceptable for Unit 2. Furthermore, the NRC staff has determined that, based on the last two DNPS, Unit 2, ILRT test results, the requirements of Sections 9.1.2 and 9.2.3 of NEI 94-01, Revision 3-A, have been satisfied.

3.1.2 DNPS, Unit 3, Type A Integrated Leak Rate Test History Per TS 5.5.12c, the DNPS, Unit 3, containment was designed for a maximum allowable primary containment leakage rate, La, of 3.0 percent of primary containment air weight per day at the calculated peak pressure, Pa. TS 5.5.12b states that Pa is 43.9 psig.

Since July 1986, a total of six ILRTs have been performed on the DNPS, Unit 3, containment.

These six Unit 3 ILRTs all had satisfactory leakage rate results. The six ILRT test results were documented in Tables 3.3.4-1 and 3.3.4-2 of Attachment 1 to the LAR. The NRC staff created the following table to summarize the DNPS, Unit 3, ILRT test results:

ni DNPS U *t 3 T ype A ILRT H" t IS Ory Test Date Test Upper95%

Level As Left Min ILRT Leakage Acceptance Test Method /

Pressure Confidence Correction Pathway Rate Criteria'6l, L.

Data Analysis (psig)

Level (wt%/day)

Penalty for (wt%/day)

(wt%/day)

Technique (wt% /day)

Isolated Pathways (Wt.%/dav)

July 1986 (7)

(7)

(7)

(7) 0.6567 (5)

(7) 1.6 Mar. 1988 (7)

(7)

(7)

(7) 0.4800 (0)

(7) 1.6 Feb. 1990 (7)

(7)

(7)

(7) 1.0075 (0)

(7) 1.6 Mar. 1992 (7)

(7)

(7)

(7) 0.5546 (0)

(7) 1.6 July 1994 49.793 0.5740 (9) 0.0087(9 )

0.0722 (9) 0.6549 <9X10>

Absolute psig 1.6 Method<3> /

(1X9)

BN-TOP-1, Rev 1 <4>

Nov. 2008 45.64 0.81627 (9) 0.0061(9) 0.202 (9) 1.041 (9X10) 3.0 Mass Point<5l psig (2X9)

TABLE 3.1.2-1 Table Notes: <1l Pa is 48 psig; (2) P. is 43.9 psig; <3) absolute method analysis per Section 5.5.2 of ANSl-56.8-1994; <4l BN-TOP-1 Revision 1, 1972; <5) mass point analysis per Section 5.5.3 of ANSl-56.8-1994; (5) per TS 5.5.12c; <7) data not provided as part of the LAR; (0) data source LAR Table 3.3.4-1; <9) data source LAR Table 3.3.4-2; <10l ILRT Leakage Rate= Upper 95 percent Confidence Level + As Left Min Pathway for Isolated Pathways + Level Correction.

With respect to Sections 9.1.2 and 9.2.3 of NEI 94-01, Revision 3-A, the licensee's DNPS, Unit 3, data, as exhibited in Table 3.1.2-1, satisfies the NEI 94-04, Revision 3-A, guidance. The last two DNPS, Unit 3, Type A, tests were performed in July 1994 and in November 2008. Both Type A tests were performed at a pressure higher than the peak calculated design basis internal accident pressure for the DBLOCA, Pa, which per TS 5.5.12b for Unit 3 is equal to 43.9 psig.

On December 21, 2001, the NRC staff issued Amendment No. 185 associated with the DNPS, Unit 3, extended power uprate (EPU) where Pa was lowered from 48 psig to its current TS value of 43.9 psig. On September 11, 2006, the NRC staff issued Amendment No. 212 associated with the DNPS, Unit 3, AST methodology where La increased from 1.6 percent to 3.0 percent by weight of the containment atmosphere air mass per day.

The Appendix J, Option B, current license basis DNPS TS 5.5.12 references document RG 1.163. Regulatory Position C of RG 1.1.63, in turn, states that NEI 94-01, Revision 0, "provides methods acceptable to the NRC staff for complying with the provisions of Option B in Appendix J to 10 CFR Part 50.... " Section 9.2.3, "Extended Test Intervals," of NEI 94-01, Revision 0, reads, in part:

In reviewing past performance history, Type A test results may have been calculated and reported using computational techniques other than the Mass Point method from ANSI/ANS 56.8-1994 (e.g., Total Time or Point-to-Point).

Reported test results from these previously acceptable Type A tests can be used to establish the performance history. Additionally, a licensee may recalculate past Type A UCL (using the same test intervals as reported) in accordance with ANSI/ANS 56.8-1994 Mass Point methodology and its adjoining Termination criteria in order to determine acceptable performance history.

NEI 94-01, Revision 3-A, reads nearly identically except that the test standard invoked is ANSI/ANS-56.8-2002 The NRC staff notes that Section 9.2.3 does not mandate that a licensee recalculate past Type A test results to demonstrate conformance with the definition of "performance leakage rate" contained in NEI 94-01, Revision 3-A. The staff also notes that the DNPS, Unit 3, ILRT results since 1986 demonstrated ample margin (i.e.,~ 37 percent) between each ILRT value and La. Accordingly, the staff did not request that the licensee reconstitute the Unit 3, Type A test results from earlier than the ILRT of July 1994.

The DNPS TS 5.5.12d.1, regarding leakage rate acceptance criteria, establishes the maximum limit for the DNPS, Unit 3, "As-Left" Leakage Rate for unit startup following completion of Type A testing at s 0. 75 La, which equals 2.25 percent by weight of the containment atmosphere air mass per day.

The DNPS, Unit 3, primary containment was designed for a leakage rate La not to exceed 3.0 percent by weight of the containment atmosphere air mass per day at the calculated peak pressure, Pa. As displayed in Table 3.1.2-1, there has been adequate margin to the "As found" performance limit as described in TS 5.5.12c of La for all historical ILRTs spanning a period of time greater than 30 years.

3.1.2.1 Conclusion As stated above, the past six DNPS, Unit 3, ILRT results dating back to 1986 have confirmed that the primary containment leakage rates are acceptable with respect to the design criterion leakage of containment air weight (La) per day at the DBLOCA pressure (Pa). The NRC staff concludes that, since the last two Type A tests for DNPS, Unit 3, had ILRT test results of less than 1.0 La, a test frequency of 15 years in accordance with NEI 94-01, Revision 3-A, and the Limitations and Conditions of NEI 94-01, Revision 2-A, are acceptable. Furthermore, the NRC staff has determined, based on the last two DNPS, Unit 3, ILRT test results, that the requirements of Sections 9.1.2 and 9.2.3 of NEI 94-01, Revision 3-A, have been satisfied.

3.1.3 DNPS, Unit 2, Types Band C, Leak Rate Test History DNPS TS 5.5.12d states, in part:

Leakage Rate acceptance criteria are:

1. Primary containment overall leakage rate acceptance criterion is s 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are s 0.6 La for the combined Type B and Type C tests.

The NRC staff reviewed the local leak rate summaries contained in Table 3.5.4-1 of Attachment 1 to the LAR. Note 1 of the table indicates that La equals 1350.84 standard cubic feet per hour (scfh) and 0.6La equals 810.507 scfh.

With the use of this numeric La value and the data contained in Table 3.5.4-1, the NRC staff confirmed the accuracy of the "Fraction of La" values contained in the table and concluded that:

The Unit 2 "As-Found" minimum pathway leakage rates for four of the last five RFOs 1 since 2007 have an average of 52. 7% of La with a high of 92.8% La.

The Unit 2 "As-Left" maximum pathway leakage rates for the last five RFOs since 2007 have an average of 22.5% of La with a high of 25.5% La.

In Section 3.5.5 of the LAR, the licensee states, in part:

The percentage of the total number of DNPS, Appendix J, Type B tested components that are on extended performance-based test intervals [i.e., 120 months] is approximately 67% for Unit 2...

Also in Section 3.5.5, the licensee states, in part:

The percentage of the total number of DNPS Appendix J Type C tested components that are on extended performance-based test intervals [i.e., 60 months] is approximately 55% for Unit 2...

1 The "As-Found" minimum pathway leakage rate during refueling outage 02R23 in 2013 was indeterminate due to excessive feedwater valve leakage as documented in Licensee Event Report (LER) 13-005-00 (ADAMS Accession No. ML14037A208).

The licensee stated that there are a total of 93 Type C tests (i.e., multiple or single valve tests) required for DNPS, Unit 2 (Reference 2). From this total, 57 Type C tests are eligible for a 60-month extended performance-based interval. The licensee states that approximately 87 percent of DNPS, Unit 2, Type C tests are on an extended test frequency. Table 3.5.5-1 of the LAR, "DNPS, Unit 2 Type Band C LLRT Program Implementation Review," indicates there have been no LLRT failures of Type B and Type C components on extended test intervals during the two most recent Unit 2 RFOs of 2013 and 2015, D2R23 and D2R24, respectively. However, in contrast to Table 3.5.5-1 of the LAR, the NRC staff observed that Table 3.5.4-1, "DNPS, Unit 2 Types Band C LLRT Combined As-Found/As-Left Trend Summary," for the aggregate LLRT values of the row labeled "AF Min Path (scfh)" displays a significant increase in the LLRT values recorded for RFOs D2R22, D2R23, and D2R24 above the values recorded for D2R20 and D2R21. To resolve these disparate tell tales of Appendix J, Option B, program health, the NRC staff requested the licensee to provide additional information, stating, in part, that:

The NRC staff notes that for [RFO] D2R22 in 2011 and that for [RFO] D2R24 in 2015, the as found minimum pathway that "Fraction of La" values were recorded at 0.928 and 0. 701, respectively. In both instances, there is neither an explicit indication in the LAR that this represented a failure to meet the surveillance performance criterion nor that past operability of the primary containment had been evaluated given the As-found Type B and C total exceeding 0.6 La. Both occurrences represent a prima facie entrance into the margin reserved for ensuring the overall primary containment performance criterion of La had not been challenged given that the combined Type B and C leakage did not necessarily account for all containment leakage potential.

The licensee provided a response to the NRC staff that detailed the repairs performed on the CIVs with "AF Min Path" Type C test leakage rate values which contributed the most to the "AF Min Path (scfh)" values contained in Table 3.5.4-1, during D2R22, D2R23, and D2R24 (Reference 2). From the staff's review of the additional information presented, it is apparent that the largest contributor to the excessive min-pathway leakages in all three RFOs was the Loop A and Loop B feedwater check valves. The licensee acknowledged that in the year 2000, a root cause evaluation report attributed a common mode of failure for these check valves. The common mode of failure consisted of the failure of seat ring-to-body sealing interface. Following implementation of four specific check valve enhancements, as prescribed by the root cause determination, failures due to "seat ring-to-body sealing failure mode" had decreased. However, as noted by the licensee, "The failures in the past 10 years have been due to disc-to-seat ring sealing failures and have not significantly decreased."

To resolve historical operational problems associated with the DNPS, Unit 2, feedwater check valves, the licensee's current course of corrective actions include:

1) Develop valve maintenance and testing best practices with the desired outcome of developing common maintenance and testing practices and internals modifications to optimize check valve performance. Consider possible uniqueness of Unit 2 Feed Water Header Outboard Isolation Check Valve, 2-220-628, which has higher failure rates than other valves.

2) Implement valve maintenance best practices.

3) Implement valve testing best practices.

Corrective actions that have been implemented on DNPS, Unit 2, include:

'B' Feedwater Loop: Feedwater modification and best practice implementation was completed during D2R24 in November 2015. The post-modification as-found min-path leakage for the Unit 2, B Feedwater Loop during D2R25 in November 2017 was 0.84 scfh - satisfactory results.

'A' Feedwater Loop: Feedwater modification and best practice implementation was completed during D2R25 in November 2017. The post-modification leakage for the Unit 2, A Feedwater Loop will be determined during D2R26 in November 2019.

In summary, the licensee provided a comprehensive response about the cause of significant LLRT failures and explained the corrective actions performed to prevent repetitive and/or common cause failures.

From the review of the information contained in: (1) Section 3.5.4 of the LAR, "Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program," (2)

Section 3.5.5 of the LAR, "Type B and Type C [LLRT] Testing Program Implementation Review," and (3) information provided in the licensee's supplemental responses to the LAR, the NRC staff concluded that the licensee has been compliant with the guidance of:

RG 1.163, "Regulatory Position" C.2; NEI 94-01, Revision 0, Section 10.2.1, "Type B Test Intervals"; and NEI 94-01, Revision 0, Section 10.2.3, "Type C Test Interval."

Based on this review, the NRC staff concluded that, with the exception of the DNPS, Unit 2, Type C, feedwater check valve test failures experienced during D2R22, D2R23, and D2R24, the aggregate results of the "As-Found Minimum Pathway" for Unit 2, Type B and C tests from 2007 through 2015 demonstrates a history of adequate maintenance.

3.1.3.1 Conclusion Based on the information evaluated above and in particular the licensee's supplemental information to the LAR (Reference 2), the NRC staff concludes that the percentage of Type B and Type C components on extended frequencies represents adequate adherence to the requirements of Appendix J, Option B. This conclusion supports allowing an extended test interval of up to 75 months for the DNPS, Unit 2, Type C tested CIVs in accordance with the guidance of NEI 94-01, Revision 3-A.

3.1.4 DNPS, Unit 3, Types B and C Leak Rate Test History DNPS TS 5.5.12d states, in part:

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 ~ 0.6 La for the combined Type B and Type C tests...

The NRC staff reviewed the local leak rate summaries contained in Table 3.5.4-2 of Attachment 1 to the LAR. Note 1 of the table indicates that La equals 1350.84 scfh and 0.6 La equals 810.507 scfh. With the use of this numeric La value and the data contained in Table 3.5.4-2, the NRC staff confirmed the accuracy of the "Fraction of La" values contained in the Table and concluded that:

The Unit 3 "As-Found" minimum pathway leakage rates for the last six RFOs since 2006 have an average of 16.3% of La with a high of 22.2% La.

The Unit 3 "As-Left" maximum pathway leakage rates for the last six RFOs since 2006 have an average of 24.2% of La with a high of 30.4% La.

In Section 3.5.5 of the LAR, the licensee states, in part:

The percentage of the total number of DNPS, Appendix J, Type B tested components that are on extended performance-based test intervals [i.e., 120 months] is approximately 67%... for... Unit 3.

Also in Section 3.5.5, the licensee states, in part:

The percentage of the total number of DNPS Appendix J Type C tested components that are on extended performance-based test intervals [i.e., 60 months] is approximately 55%... for... Unit 3.

The licensee stated that there are a total of 93 Type C tests (i.e., multiple or single valve tests) required for DNPS, Unit 3 (Reference 2). From this total, 57 Type C tests are eligible for a 60-month extended performance-based interval. The licensee states that approximately 87 percent (i.e., 50) of DNPS, Unit 3, Type C tests are on an extended test frequency. Table 3.5.5-2 of to the LAR indicates that there were two LLRT failures of Type B and Type C components on extended test intervals. Both failures occurred during the Unit 3 2014 RFO (D3R23).2 The failures were remediated as follows:

1) Reactor Water Cleanup valve CIV 3-1201-2 was disassembled, repaired, satisfied "as left" test requirements, and returned to a 30-month scheduled test interval during RFO D3R23.

2) Instrument Air valve CIV 3-4799-531 failure was evaluated with the corrective action deferred until D3R24 and returned to a 30-month scheduled test interval. During D3R24, this valve was replaced and satisfied "as left" test requirements.

As noted above for DNPS, Unit 2, the licensee provided a response to an NRC staff RAI that detailed its approach to resolve historical operational problems associated with the DNPS, Unit 3, feedwater check valves. The licensee's current course of corrective actions include:

( 1) Develop valve maintenance and testing best practices with the desired outcome of developing common maintenance and testing practices and internals modifications to optimize check valve performance. Consider possible uniqueness of Unit 3 Feed Water Header Inboard Isolation Check Valve, 3-220-58A, which has a higher failure rate than other valves.

(2) Implement valve maintenance best practices.

(3) Implement valve testing best practices.

2 There were no Unit 3 Type 8 and C LLRT failures identified during the 2016 RFO (D3R24).

Corrective actions that have been implemented on Unit 3 include:

'B' Feedwater Loop: Feedwater modification and best practice implementation was completed during D3R23 in November 2014. The post-modification, as-found minimum pathway (min-path) leakage for the Unit 3, B feedwater loop during Refuel Outage D3R24 in November 2016 was 2.77 scfh - satisfactory results.

'A' Feedwater Loop: Feedwater outboard valve modification and best practice implementation was completed during D3R24 in November 2016. The post-modification as found min-path leakage for the Unit 3, A feedwater outboard valve will be determined during D3R25 in November 2018.

'A' Feedwater Loop: Feedwater inboard valve modification and best practice implementation will be completed during D3R25 in November 2018.

From the review of the information contained in (1) Section 3.5.4 of the LAR, "Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program," (2)

Section 3.5.5 of the LAR, "Type B and Type C [LLRT] Program Implementation Review," and (3) information provided in the licensee's supplemental responses to the LAR, the NRC staff concluded that the licensee has been compliant with the guidance of:

RG 1.163, "Regulatory Position" C.2; NEI 94-01, Revision 0, Section 10.2.1, "Type B Test Intervals"; and NEI 94-01, Revision 0, Section 10.2.3, "Type C Test Interval."

3.1.4.1 Conclusion Based on this review, the NRC staff concluded that the aggregate results of the "As-Found Minimum Pathway" for the DNPS, Unit 3, Type B and C tests from 2006 through 2016 demonstrates a history of adequate maintenance since the aggregate "AF Min Path" test results at the end of each operating cycle were all well below (i.e.,> 63 percent margin) the Type Band Type C test TS Leakage Rate acceptance criteria of s 0.60 La contained in TS 5.5.12d.1.

3.1.5 Final Staff Evaluation of the DNPS Type Band Type C Test Program Following the NRC staff evaluation of all of the licensee-sourced material, the staff has determined that: (1) the licensee adequately addressed its proposed changes in the LAR and supplemental information provided in the letter dated February 14, 2018; (2) the licensee has been compliant with the guidance of RG 1.163 and Sections 10.2.1 and 10.2.3 of NEI 94-01, Revision O; (3) the cumulative Type B and C test results were below the acceptance limit of TS 5.5.12d.1; and (4) the licensee's corrective action program appropriately addresses poor performing valves and penetrations.

On the bases of the above evaluation, the NRC staff has determined that the percentage of Type B and Type C components on extended frequencies represents adequate adherence to the requirements of Appendix J, Option B. This determination supports allowing an extended test interval of up to 75 months for the DNPS, Type C tested CIVs in accordance with the guidance of NEI 94-01, Revision 3-A. Therefore, the staff concludes that the licensee is effectively implementing the Type B and Type C leakage rate test program at DNPS, as required by Option B of 10 CFR Part 50, Appendix J.

3.2 CISI Program In the LAR, the licensee stated that the inservice inspection (ISi) program plan details the requirements for the examination and testing of ISi Class 1, 2, 3, and MC (Metal Containment) pressure retaining components, supports, and containment structures at DNPS. The ISi program plan also includes CISI.

The licensee stated in the LAR that:

DNPS has no ISi Class Concrete Containment (CC) components that meet the criteria of Sub article IWL-1100; therefore, no requirements to perform examinations in accordance with Subsection IWL are incorporated into this Containment ISi Plan. The basis for exclusion of Class CC components from examination in accordance with ASME Section XI, Subsection IWL, is provided in DG97-001424 ["Applicability of IWL Concrete Examination Requirements for Dresden and Quad Cities (Basis for exclusion of concrete (Class CC components) from examination per ASME Section XI, Subsection IWL)," dated October 23, 1997]

3.2.1 ISi Program for Containment Metal Liner - IWE In the LAR, the licensee stated that DNPS, Units 2 and 3, are currently in the fifth 10-year ISi interval, which commenced on January 20, 2013, and ends on January 19, 2023. Currently, DNPS, Units 2 and 3, are in the second CISI interval, which started September 9, 2008, and ends on September 8, 2018. The license also stated that the ASME Code,Section XI, Code of Record, for the fifth ISi interval is the 2007 Edition through the 2008 Addenda, and the ASME Code,Section XI, Code of Record, for the second CISI interval is the 2001 Edition through the 2003 Addenda. The licensee stated that the fifth ISi interval and the second CISI interval are divided into three inspection periods as determined by calendar years within the intervals. The matrices below identify the period start and end dates for the second CISI interval as defined by the ISi program plan and for the third CISI interval as approximated by the licensee.

s econ dCISI I nterva 1/P

. d/0 eno utage Unit2 Period Period Unit 3 Outage or Start Date Start Date Outage or Outage Projected to to Projected Outage Number Scheduled End Date End Date Scheduled Number Date Date 1st 1st 10/2008 D3R20 D2R21 10/2009 9/9/08 to 9/9/08 to 9/8/11 9/8/11 10/2010 D3R21 D2R22 10/2011 2nd 2nd 10/2012 D3R22 9/9/11 to 9/9/11 to D2R23 10/2013 9/8/15 9/8/2015 10/2014 D3R23 D2R24 10/2015 3rd 3rd 9/9/15 to 9/9/2015 to 10/2016 D3R24 D2R25 10/2017 9/8/18 9/8/18 Th" d CISI I Ir nterva 1/P

. d/0 eno utage*

Unit2 Period Period Unit 3 Outage or Start Date Start Date Outage or Outage Projected to to Projected Outage Number Scheduled End Date End Date Scheduled Number Date Date 1st 1st D2R26 10/2019 9/9/18 to 9/9/18 to 10/2018 D3R25 9/8/21 D2R27 10/2021 2nd 9/8/21 10/2020 D3R26 D2R28 10/2023 9/9/21 to 2nd 10/2022 D3R27 9/8/25 9/9/21 to D2R29 10/2025 3rd 9/8/25 10/2024 D3R28 3rd D2R30 10/2027 9/9/25 to 9/9/25 to D3R29 9/8/28 9/8/28 10/2026 Identifies the successive periods start and end dates for the third CISI interval, which is approximate since the third CISI interval inspection program has not been developed at this time.

In accordance with IWA-2430(c)(1 ), the inspection periods specified in these tables may be decreased or extended by as much as 1 year to enable inspection to coincide with the RFOs and IWA-2420(d) allows an inspection interval to be extended when a unit is out of service continuously for 6 months or more. The extension may be taken for a period of time not to exceed the duration of the outage.

3.2.2 Safety-Related Coatings Inspection Program In the LAR, the licensee stated that at DNPS it has committed to follow RG 1.54, "Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants," Revision O (Reference 11 ). RG 1.54 provides the Regulatory Position for compliance with 1 O CFR Part 50, Appendix B, and invokes several ANSI standards. Standards pertinent to coatings are: ANSI N101.2, "Protective Coatings (Paints) for Light Water Nuclear Reactor Containment Facilities," ANSI N101.4, "Quality Assurance for Protective Coatings Applied to Nuclear Facilities," and ANSI N5.12, "Protective Coatings for the Nuclear Industry." The licensee also stated that at DNPS it implements a safety-related coatings program that ensures that the limiting DBA qualified coating systems are used inside primary containment. The licensee further stated that:

The program assures that safety-related DBA qualified coatings (i.e., Service Level 1) are selected, procured, applied, and inspected in a manner that conforms to the applicable 10 CFR [Part] 50, Appendix B criteria. Unqualified coatings are controlled and tracked to ensure that [ECCSs) will not be adversely affected by coating debris following an accident. The program objective is to conform to licensee commitments made in response to [Generic Letter] GL 98-04

["Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System after a Loss-of-Coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment"]. The Safety-Related Coatings Program also receives the support of the formal Maintenance Rule (10 CFR 50.65) condition-monitoring program.

Engineering reviews and evaluates the results of coating condition examinations performed by qualified examiners.

The NRC staff reviewed the coating inspection results and determined the condition of that the safety-related coatings program in the DNPS drywell and torus are in adequate condition.

There are multiple areas with coatings damaged by mechanical means, however, the surrounding substrate is in an acceptable condition with no coatings peeling or delaminating from the point of damage. The primary cause of the degraded drywell coating is attributed to age-related degradation. Paint flakes have been found during the inspections for the last several outages and have been determined to be occurring during normal operating cycles, rather than being caused by abnormal conditions. Based on the staff's evaluation of the licensee's furnished information for this LAR, the NRC staff finds that the licensee has adequate in-service inspection programs in place to monitor and manage age-related degradation of the DNPS, Unit 2 and 3 containment structures.

3.2.3 Type B and Type C LLRT Program In the LAR, the licensee stated that the DNPS, Types B and C testing program requires testing of electrical penetrations, airlocks, hatches, flanges, and CIVs, in accordance with 10 CFR Part 50, Appendix J, Option B, and the methods described in RG 1.163. The test program results are used to demonstrate that appropriate maintenance and repairs are made on these components throughout their service life. The licensee stated that the Types B and C testing program provides a means to protect the health and safety of plant personnel and the public by maintaining leakage from these components below appropriate limits. In accordance with DNPS TS 5.5.12, the Types B and C allowable maximum pathway total leakage is 0.6 La (Note:

for DNPS, 0.6 La is defined as 810.507 scfh and La is defined as 1350.84 scfh). The licensee further stated that a review of the DNPS, Type B and Type C test results from 2007 through 2015 for Unit 2 and from 2006 through 2014 for Unit 3 "has shown an exceptional amount of margin between the actual As-Found (AF) and As-Left (AL) outage summations and the regulatory requirements."

The two tables below provide LLRT data trend summaries for DNPS, Unit 2, since 2007 (i.e.,

the last ILRT was performed in 2009) and for Unit 3 since 2006 (i.e., the last ILRT was performed in 2008).

DNPS, Unit 2, Types B and C, LLRT C

b.

d A F d/ A L ft T d S om ine s-oun s-e ren ummarv Refueling Outage R20 R21 R22 R23 R24 (Year)

(2007)

(2009)2 (2011)

(2013)

(2015)

AF Min Path 394.909 251.651 1253.92 Undetermined3 946.685 (scfh)

Fraction of La 1 0.292 0.186 0.928 0.701 AL Max Path 344.048 341.338 245.724 299.878 291.229 (scfh)

Fraction of La 0.225 0.253 0.182 0.222 0.216 AL Min Path 177.218 134.354 117.139 109.442 118.691 (scfh)

Fraction of La 0.131 0.099 0.087 0.081 0.088 1 0.6La = 810.507 scfh and La= 1350.84 scfh; 2 D2R21 in 2009 was also an ILRT outage; 3 AF was undetermined due to excessive feedwater valve leakage as documented in Licensee Event Report (LER) 13-005-00 (ADAMS Accession No. ML14037A208)

DNPS U *t 3 T m

, ypes B d C LLRT C

b.

d A F d/A L ft T d S an om me s-oun s-e ren ummary Refueling R19 R20 R21 R22 R23 R24 Outage (2006)

(2008)2 (2010)

(2012)

(2014)

(2016)

(Year)

AF Min Path 95.78 191.709 293.903 283.894 299.356 157.421 (scfh)

Fraction of La 1 0.071 0.142 0.218 0.210 0.222 0.117 AL Max Path 230.5 410.876 337.358 318.434 361.035 304.5 (scfh)

Fraction of La 0.171 0.304 0.250 0.236 0.267 0.225 AL Min Path 79.61 187.546 179.735 97.236 109.515 131.4

{scfh)

Fraction of La 0.059 0.139 0.133 0.072 0.081 0.097 1 0.6L. = 810.507 scfh and L. = 1350.84 scfh; 2 D3R20 in 2008 was also an ILRT outage 3.2.4 Conclusion 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 ILRTs and LLRT combined totals demonstrate acceptable performance. The NRC staff determined that the licensee's containment inspection programs support extension of the ILRT frequency as requested in the LAR. The NRC staff finds that there is reasonable assurance that the structural and leak-tight integrity of the DNPS primary containment will continue to be monitored and maintained with the performance-based Type A test interval extended up to one test in 15 years, without undue risk to public health and safety. Therefore, the NRC staff concludes that the licensee's containment inspection programs support the proposed license amendment to change TS 5.5.12, to extend integrated leakage rate test frequency to 15 years for Type A on a permanent basis, and the licensee's adoption of NEI 94-01, Revision 3-A, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, as the documents used at DNPS to implement the performance-based leakage testing program in accordance with Option B of 10 CFR Part 50, Appendix J, as the implementation document, as requested in the LAR.

3.3 NEI 94-01, Revision 2, Limitations and Conditions As required by 10 CFR 50.54(0), both DNPS primary containments are subject to the requirements set forth in 10 CFR Part 50, Appendix J. Option B of Appendix J provides that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach. Currently, the DNPS 10 CFR Part 50, Appendix J, Primary Containment Leakage Rate Testing Program invokes RG 1.163 as the plan implementation document. The LAR proposes to revise the DNPS Primary Containment Leakage Rate Testing Program by replacing this implementation document with the guidance contained in NEI 94-01, Revision 3-A, and the Limitations and Conditions of NEI 94-01, Revision 2-A.

By letter dated June 25, 2008 (Reference 7), the NRC provided an SE with Limitations and Conditions for NEI 94-01, Revision 2. In the SE, the NRC staff concluded that NEI 94-01, Revision 2, describes an acceptable approach for implementing the optional performance-based requirements of 1 O CFR Part 50, Appendix J, and is acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the Limitations and Conditions noted in Section 4.0 of the SE. Specifically, Section 4.1 of the SE establishes Limitations and Conditions pertaining to deterministic requirements and Section 4.2 of the SE establishes Limitations and Conditions pertaining to the plant's Probabilistic Risk Assessment (PRA) analysis. More explicitly, the SE included provisions for extending the ILRT Type A interval to a maximum of 15 years, subject to the six Limitations and Conditions provided in the SE. The NRC noted in the SE that NEI 94-01, Revision 2, incorporates the regulatory positions stated in RG 1.163. The accepted version of NEI 94-01, Revision 2, was subsequently issued as Revision 2-A. The NEI issued Revision 2-A, to NEI 94-01 on November 19, 2008. With Revision 2-A, the TR was revised to incorporate the June 25, 2008 NRC SER.

The NRC staff evaluated Section 3.8.1 of the LAR, "Limitations and Conditions Applicable to NEI 94-01, Revision 2-A", which contains Table 3.8.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," which indicates that the licensee intends to satisfy the Limitations and Conditions of NEI 94-01, Revision 2, Section 4.1. Accordingly, as previously noted, the licensee intends to adopt the testing methodology of ANSI/ANS 56.8-2002 (Reference 8) in place of the methodology of ANSI/ANS 56.8-1994 (Reference 9). The leakage rate testing requirements of 10 CFR Part 50, Appendix J, Option B (Type A, Type B, and Type C Tests) and the GISI requirements mandated by 1 O CFR 50.55a, together, ensure the continued leak-tight and structural integrity of both DNPS primary containments during their service lives.

Type B testing ensures that the leakage rate of individual containment penetration components are acceptable. Type C testing ensures that individual CIVs are essentially leak tight. In addition, aggregate Type B and Type C leakage rates support the leak tightness of both primary containments by minimizing potential leakage paths.

In the LAR, the licensee proposes that DNPS invoke NEI 94-01, Revision 3-A, along with the Limitations and Conditions of NEI 94-01, Revision 2-A, as the reference documents for the DNPS "Primary Containment Leakage Rate Testing Program" in TS 5.5.12. Therefore, the licensee is also applying to extend the frequencies of the Type C performance-based test intervals beyond 60 months.

The NRC staff has found that the use of NEI 94-01, Revision 2-A, is acceptable for referencing by licensees proposing to amend their TS to permanently extend the ILRT surveillance interval to 15 years, provided the following six conditions are satisfied.

3.3.1 Condition 1 The first Limitation/Condition of Attachment 1 to the LAR, page 64, is derived from Sections 3.1.1.1 and 4.1 (i.e., Enclosure, page 19) of the NRC SE dated June 25, 2008, and stipulates that for calculating the Type A leakage rate, the licensee should use the definition in the NEI TR 94-01, Revision 2, in lieu of that in ANSI/ANS-56.8-2002.

Licensee Response In Table 3.8.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," the licensee stated:

DNPS 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.

Staff Evaluation Section 3.2.9, "Type A test performance criterion," of ANSI/ANS-56.8-2002, defines the "performance leakage rate" and reads, in part:

The performance criterion for a Type A test is met if the performance leakage rate is less than La. The performance leakage rate is equal to the sum of the measured Type A test UCL and the total AL MNPLR [minimum pathway leakage rate] of all Type B or Type C pathways isolated during performance of the Type A test.

NRC staff SE Section 3.1.1.1, Enclosure, page 6, for NEI 94-01, Revision 2, reads, in part:

Section 5.0 of NEI TR 94-01, Revision 2, uses a definition of "performance leakage rate" for Type A tests that is different from that of ANSI/ANS-56.8-2002....

The definition contained in NEI TR 94-01, Revision 2, is more inclusive because it considers excessive leakage in the performance determination. In defining the minimum pathway leakage rate, NEI TR 94-01, Revision 2, includes the leakage rate for all Type B and Type C pathways that were in service, isolated, or not lined up in their test position prior to the performance of the Type A test. Additionally, the NEI TR 94-01, Revision 2, definition of performance leakage rate requires consideration of the leakage pathways that were isolated during performance of the test because of excessive leakage in the performance determination. The NRC staff finds this modification of the definition of "performance leakage rate" used for Type A tests to be acceptable.

Section 5.0, "Definitions," of NEI 94-01, Revision 2-A, reads, in part:

The performance leakage rate is calculated as the sum of the Type A upper confidence limit (UCL) and as-left minimum pathway leakage rate (MNPLR) leakage rate for all Type Band Type C pathways that were in service, isolated, or not lined up in their test position (i.e., drained and vented to containment atmosphere) prior to performing the Type A test. In addition, leakage pathways that were isolated during performance of the test because of excessive leakage must be factored into the performance determination. The performance criterion for Type A tests is a performance leak rate of less than 1.0la.

The NRC staff reviewed the definitions of "performance leakage rate" contained in NEI 94-01, Revision 2, Revision 2-A, and Revision 3-A, and determined that these definitions are identical.

Therefore, the staff concludes that the licensee will use the definition found in Section 5.0 of NEI 94-01, Revision 2 (Reference 12), for calculating the Type A leakage rate in the DNPS, "Primary Containment Leakage Rate Testing Program." Based on this evaluation, the NRC staff concludes that the licensee has adequately addressed Condition 1.

3.3.2 Condition 2 The second Limitation/Condition of Attachment 1 to the LAR, page 64, is derived from Sections 3.1.1.3 and 4.1 (i.e. Enclosure, page 19) of the NRC SE dated June 25, 2008 and stipulates that the licensee submit a schedule of containment inspections to be performed prior to and between Type A tests.

Licensee Response In Table 3.8.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," the licensee stated:

Reference Section 3.5.2 (Tables 3.5.2-3 and 3.5.2-4) of this LAR submittal.

Staff Evaluation NRC staff SE Section 3.1.1.3, Enclosure, page 7, for NEI 94-01, Revision 2, reads, in part:

NEI TR 94-01, Revision 2, Section 9.2.3.2, states that: "To provide continuing supplemental means of identifying potential containment degradation, a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity must be conducted prior to each Type A test and during at least three other outages before the next Type A test if the interval for the Type A test has been extended to 15 years." NEI TR 94-01, Revision 2, recommends that these inspections be performed in conjunction or coordinated with the examinations required by ASME Code,Section XI, Subsections IWE and IWL. The NRC staff finds that these visual examination provisions, which are consistent with the provisions of regulatory position C.3 of RG 1.163, are acceptable considering the longer 15 year interval. Regulatory Position C.3 of RG 1.163 recommends that such examination be performed at least two more times in the period of 10 years.

The NRC staff agrees that as the Type A test interval is changed to 15 years, the schedule of visual inspections should also be revised. Section 9.2.3.2 in NEI TR 94-01, Revision 2, addresses the supplemental inspection requirements that are acceptable to the NRC staff.

Page 10 of NEI 94-01, Revision 3-A, Section 9.2.1, "Pretest Inspection and Test Methodology,"

reads, in part:

Prior to initiating a Type A test, a visual examination shall be conducted of accessible interior and exterior surfaces of the containment system for structural problems that may affect either the containment structure leakage integrity or the performance of the Type A test. This inspection should be a general visual inspection of accessible interior and exterior surfaces of the primary containment and components. It is recommended that these inspections be performed in conjunction or coordinated with the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE/IWL required examinations.

Page 12 of NEI 94-01, Revision 3-A, Section 9.2.3.2, "Supplemental Inspection Requirements,"

reads:

To provide continuing supplemental means of identifying potential containment degradation, a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity must be conducted prior to each Type A test and during at least three other outages before the next Type A test if the interval for the Type A test has been extended to 15 years. It is recommended that these inspections be performed in conjunction or coordinated with the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE/IWL required examinations.

DNPS has no ISi Class Concrete Containment (CC) components that meet the criteria of Sub article IWL-1100; therefore, no requirements to perform examinations in accordance with Subsection IWL are incorporated into the DNPS CISI plan.

The Second Interval CISI program plan was developed in accordance with the requirements of 10 CFR 50.55a and the 2001 Edition through the 2003 Addenda of ASME Code,Section XI, subject to the limitations and modifications contained within Paragraph (b) of the regulation.

These limitations and modifications are detailed in Table 3.5.2-1 of the LAR, "Code of Federal Regulations 10 CFR 50.55a Requirements (Applicable to Containment Inspection Program)."

Overall, the Second Interval CISI program plan addresses Subsections IWE, Mandatory Appendices of ASME Code,Section XI, approved IWE Code Cases, approved alternatives through relief requests and SE's, and utilizes Inspection Program B as described in ASME Code,Section XI, IWE-2412. Both DNPS, Units 2 and 3, are in the Second CISI Interval, which started September 9, 2008, and is effective through September 8, 2018. CISI inspections have been completed for the first and second periods, while the third period inspections are currently ongoing.

As displayed Table 3.3.4-2 of the LAR, the last Unit 2 Type A test was performed during November 2009 and the last Unit 3 Type A test was performed during November 2008.

Accordingly, with the proposed extension of both Type A test intervals, the next Unit 2 Type A test would be due during November 2024 and the next Unit 3 Type A test would be due during November 2023.

Table 3.5.2-3 and Table 3.5.2-4 of the LAR identify the start and end dates for the first, second, and third periods of the second and third CISI intervals as defined by the Inspection ISi program plan. Review of Table 3.5.2-3 indicates that the last Unit 2 Type A test was performed in RFO D2R21 during the first period of the second interval. Review of Table 3.5.2-4 indicates that granting a test interval extension to 15 years will allow the occurrence of the next Unit 2 Type A test during November 2024. This test is projected to occur during the second period of the third CISI interval between September 9, 2021 and September 8, 2025. Consistent with ASME Code,Section XI, Table 3.5.2-5 of the LAR indicates 100% visual inspection of the relevant "Items" for both categories "E-A" Containment Surfaces and "E-C" Containment Surfaces Requiring Augmented Examination" for each period of each interval. Since there will be three entire CISI program periods without a completed Type A test between November 2009 and the next required ILRT of November 2024, the staff confirms that the requirements of NRC staff SE Section 3.1.1.3 for NEI 94-01, Revision 2, as reflected in NEI 94-01, Revision 3-A, Section 9.2.3.2, can be satisfied for Unit 2.

Similarly for Unit 3, Table 3.5.2-3 and Table 3.5.2-4 of the LAR identify the start and end dates for the first, second, and third periods of the second and third CISI intervals as defined by the Inspection ISi program plan. Review of Table 3.5.2-3 indicates that the last Unit 3 Type A test was performed in RFO D3R20 during the first period of the second interval. Review of Table 3.5.2-4 indicates that granting a test interval extension to 15 years will allow the occurrence of the next Unit 3 Type A test during November 2023. This test is projected to occur during the second period of the third CISI interval between September 9, 2021 and September 8, 2025.

Consistent with ASME Code,Section XI, Table 3.5.2-5 of the LAR indicates 100% visual inspection of the relevant "Items" for both categories "E-A" Containment Surfaces" and "E-C" Containment Surfaces Requiring Augmented Examination" for each period of each interval.

Since there will be three entire CISI program periods without a completed Type A test between November 2008 and the next required ILRT of November 2023, the staff confirms that the requirements of NRC staff SE Section 3.1.1.3 for NEI 94-01, Revision 2, as reflected in NEI 94-01, Revision 3-A, Section 9.2.3.2, can be satisfied for Unit 3.

Based on the foregoing discussion, the NRC staff concludes that the licensee intends to comply with the guidance contained in NEI 94-01, Revision 3-A, Sections 9.2.1 and 9.2.3.2 and intends to satisfy the provisions contained in NRC staff SE Section 3.1.1.3. Accordingly, the staff concludes that the licensee has adequately addressed Condition 2.

3.3.3 Condition 3 The third Limitation/Condition of Attachment 1 to the LAR, page 64, is derived from Sections 3.1.3 and 4.1 (i.e., Enclosure, page 19) of the NRC SE dated June 25, 2008, and stipulates that the licensee address the areas of the containment structure potentially subjected to degradation.

Licensee Response In Table 3.8.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," the licensee stated:

Reference Section 3.5.2 (Tables 3.5.2-3, 3.5.2-4, and 3.5.2-7) of this LAR submittal.

Staff Evaluation The staff reviewed the information contained in Section 3.5.2 of the LAR, "Containment lnservice Inspection (CISI) Program."

NRC staff SE, Section 3.1.3, Enclosure, page 9, for NEI 94-01, Revision 2, reads, in part:

In approving for Type A tests the one-time extension from 10 years to 15 years, the NRC staff has identified areas that need to be specifically addressed during the IWE and IWL inspections including a number of containment pressure-retaining boundary components (e.g., seals and gaskets of mechanical and electrical penetrations, bolting, penetration bellows) and a number of the accessible and inaccessible areas of the containment structures (e.g., moisture barriers, steel shells, and liners backed by concrete, inaccessible areas of ice-condenser containments that are potentially subject to corrosion).

General visual examinations of the accessible surfaces of containment are performed to assess the general condition of the containment surfaces. DNPS has no ISi Class Concrete Containment (CC) components that meet the criteria of Sub article IWL-1100; therefore, no requirements to perform examinations in accordance with Subsection IWL are incorporated into this CISI plan. The DNPS CISI plan includes ASME Code,Section XI, ISi Class MC Pressure retaining components, and their integral attachments that meet the criteria of Sub article IWA-1300. This CISI plan also includes information related to augmented examination areas, component accessibility, and examination review.

The scope of the augmented examinations for the DNPS primary containments are defined by ASME Code,Section XI, subsection IWE-1240, "Surface Areas Requiring Augmented Examination."

The NRC staff notes that the basic premise of IWE-1240 is: (a) containment surfaces that are subject to accelerated corrosion with no or minimal corrosion allowance or areas where the absence or repeated loss of protective coatings has resulted in substantial corrosion and pitting, and (b) containment surfaces subjected to excessive wear from abrasion or erosion that causes a loss of protective coatings, deformation, or material loss.

In Section 3.5.2.3 of the LAR, the licensee stated, in part, that:

The CISI components overall were evaluated for potential candidates to be included programmatically in the Augmented Inspection Program.... The evaluation resulted in one component (i.e., area) being recommended on a programmatic basis, as candidates for the Augmented Program within Examination Category E-C, and therefore appear on Table IWE-2500-1. This augmented inspection area is the Drywell Shell at the Sand Pocket Location.

In the First and Second CISI Intervals, portions of the DNPS, Unit 3 Drywell Shell located at the sand pocket were identified as augmented surface areas requiring examination in accordance with Paragraph IWE-1240. These surface areas were categorized in accordance with Table IWE-2500-1, Examination Category E-C, Item No. E4.12, requiring volumetric examination of 100% of the minimum wall thickness locations identified.

The licensee stated in Section 3.5.2.4 of the LAR that "DNPS, Unit 2 credits the inspections performed on Unit 3 to establish the most conservative bounding case for continued inspection.

This inspection is a part of the ASME Code,Section XI, Subsection IWE Program, Commitment 8.1.26 at DNPS."

Table 3.5.2-5 of the LAR identifies each specific containment examination by an IWE Item No.

A summary of inspected DNPS, Units 2 and 3, augmented containment components, Category E-C, is provided in Table 3.5.2-5. These components are identified in the table as Item No.

E4.11 and Item No. E4.12.

The programmatic requirements for Class MC application for inaccessible areas as specified in 10 CFR 50.55a(b )(2)(ix)(A) are:

(1) the licensee must 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.

(2) for each inaccessible area identified for evaluation, the licensee must provide the following in the ISi Summary Report as required by IWA-6000:

i.

A description of the type and estimated extent of degradation, and the conditions that led to the degradation; ii.

An evaluation of each area, and the result of the evaluation; and iii.

A description of necessary corrective actions.

ASME Code,Section XI, defines "Accessible Surface Areas" in accordance with IWE-1231, which reads, in part:

(a) As a minimum, the following portions of Class MC Containment vessels, parts and appurtenances, and Class CC metallic shell and penetration liners shall remain accessible for either direct or remote visual examination, from at least one side of the vessel, for the life of the plant:

( 1) openings and penetrations; (2) structural discontinuities; (3) 80% of the pressure-retaining boundary (excluding attachments, structural reinforcement, and areas made inaccessible during construction); and (4) surface areas identified in IWE-1240 In Section 3.5.2.6 of the LAR, the licensee indicated that an evaluation had been performed that satisfies the requirements of 10 CFR 50.55a(b )(2)(ix)(A). The evaluation resulted in the identification of no inaccessible areas. The licensee stated, in part:

DNPS has not needed to implement any new technologies to perform inspections of any inaccessible areas at this time. However, EGC actively participates in various nuclear utility owner's groups and ASME Code committees to maintain cognizance of ongoing developments within the nuclear industry. Industry operating experience is also reviewed to determine it's applicably to DNPS.

For the bellows assemblies, as noted in Section 3.1, the licensee stated:

The drywell and suppression chamber are interconnected by a vent system. Eight main vents connect the drywell to a vent ring header, which is located within the suppression chamber air space. A bellows assembly is located at the junction where each main vent penetrates the suppression chamber shell to permit differential movement of the suppression chamber and drywell/vent system.

Table 3.5.2-5 of the LAR identifies for both DNPS units a VT-3 visual examination of the vent system bellows with Item No. E1.20, "Containment Vessel Pressure Retaining Boundary-BWR Vent System Accessible Surface Areas."

In Section 3.6.1 of LAR, the licensee stated:

At DNPS, LLRT testing of the two-ply stainless steel bellows is performed by a proceduralized series of test techniques, which are; (1) air is first used as the test media to determine leak tightness, (2) followed by helium as a test media if leakage exceeds a predetermined test value, (3) then welding in temporary test fixtures and testing as a Type B component to determine leakage, and (4) then finally, by the replacement of a failed bellow."

For containment bolted connections, Table 3.5.2-5 of the LAR identifies for both DNPS units a VT-3 visual examination of the containment surface bolted connections with Item No. E1.11.

Table 3.5.2-1 of the LAR discussing 10 CFR 50.55a(b)(2)(ix)(H) was clarified with the words "As an alternative to performing VT-3 examinations of containment bolted connections that are disassembled during the scheduled performance of Item E1.11, VT-3 examinations of containment bolted connections may be conducted whenever containment bolted connections are disassembled for any reason." The NRC staff notes that this alternative method of the licensee satisfying code requirements was evident in Table 3.5.2-2 of the LAR where specific inspection results of the bolting for the Control Rod Drive Hatch, Torus Hatches, Drywell Equipment Hatch, Drywell support ring, and Drywell head were recorded in the respective work orders for five of the last six RFOs performed at DNPS.

For electrical penetrations, Section 3.1.2 of the LAR states, in part:

Electrical penetrations were designed to accommodate the electrical requirements of the plant. Penetrations are functionally grouped into low voltage power and control cable penetration assemblies, high voltage power cable penetration assemblies, and shielded cable penetration assemblies.

An assembly is sized to be inserted in the 12-inch Schedule 80 penetration nozzles, which are furnished as part of the containment structure.

Section 3.5.4 of the LAR indicates that the DNPS Type B test program currently requires inspection and testing of electrical penetrations in accordance with 10 CFR Part 50, Appendix J, Option B and RG 1.163. The results of the test program are used to demonstrate that proper maintenance and repairs are made on these components throughout their service life.

For moisture barriers, Table 3.5.2-5 of the LAR identifies for both DNPS units a General Visual examination of the containment moisture barriers with Item No. E1.30. In section 3.6.4 of the LAR, the licensee indicated that DNPS, Units 2 and 3, moisture barrier inspections are performed each inspection period per Item E1.30. Moreover, it was stated that:

This moisture barrier inspection is performed as a part of the CISI program.

There are four inspections locations performed, they are: (1) Drywell Basement Moisture Barrier, (2) X-100 Equipment Hatch Moisture Barrier, (3) X-101 Personnel Hatch Floor Moisture Barrier, and (4) X-101 Personnel Hatch Penetration Moisture Barrier. The inspection results for these four inspection locations, for the last two inspection periods, have resulted in no reportable indications.

Section 3. 7 of the LAR credits the ASME Code,Section XI, Subsection IWE (Supplement Appendix A.1.26) program which consists of periodic visual examination for signs of degradation.

The program covers steel containment shells and their integral attachments including but not limited to seals, gaskets, and moisture barriers. The program includes assessment of damage and corrective actions.

In summary, the NRC staff determined that, based on the information contained in Section 3.5.2 of the LAR, the licensee has established its intent to satisfy the issues of SE Section 3.1.3.

Therefore, the staff concludes that the licensee has adequately addressed Condition 3.

3.3.4 Condition 4 The fourth Limitation/Condition of Attachment 1 to the LAR, page 64, is derived from Sections 3.1.4 and 4.1 (i.e., Enclosure, page 19) of the NRC SE dated June 25, 2008, and stipulates that the licensee address any tests and inspections performed following major modifications to the containment structure, as applicable.

Licensee Response In Table 3.8.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," the licensee stated:

There are no major modifications planned to the containment structure.

Modification is underway to comply with NRC Order EA-13-109, to install a hardened containment vent system. Does not directly modify containment.

Modification has been completed that installed new AOV 2(3)-4724 in series with check valve 2(3)-4799-531. These valves are in a parallel flow path to AOV 2(3)-4722 (Both located outside the drywell) and in series with check valve 2(3)-4799-530 (located inside the drywell). Does not directly modify containment. 3 Refer to Section 3.1. 7 of this LAR submittal for additional details Staff Evaluation NRC staff SE Section 3.1.4, Enclosure, page 9, for NEI 94-01, Revision 2, reads, in part:

Section 9.2.4 of NEI TR 94-01, Revision 2, states that: "Repairs and modifications that affect the containment leakage integrity require LLRT or short duration structural tests as appropriate to provide assurance of containment integrity following the modification or repair. This testing shall be performed prior to returning the containment to operation." Article IWE-5000 of the ASME Code,Section XI, Subsection IWE (up to the 2001 Edition and the 2003 Addenda),

would require a Type A test after major repair or modifications to the containment. In general, the NRC staff considers the cutting of a large hole in the containment for replacement of steam generators or reactor vessel heads, replacement of large penetrations, as major repair or modifications to the containment structure.

This Condition is intended to verify that any major modification or maintenance repair of the primary containment since the last ILRT has been appropriately accompanied by either a structural integrity test (SIT) or ILRT and that any plans for such major modification also include appropriate pressure testing. The last Type A test for the Unit 2 and Unit 3 primary containments was performed during November 2009 and 2008, respectively. Section 3.1. 7 of the LAR provides additional installation and test details about the two containment modifications described in the licensee's response to Condition 4. With respect to the modification associated with the installation of a hardened containment vent system (HCVS), the licensee stated, in part:

Primary containment is also not impacted since the tie-in for the HCVS will be to the vent line outboard of an existing primary containment isolation valve.

The modification installs a new valve second in-line valve as an outboard CIV in the existing vent line. The new valve, once installed, will be tested and become a part of the 1 O CFR [Part] 50, Appendix J, Type C Local Leak Rate Test (LLRT) Program.

3 Refer to Section 3.1. 7 of the LAR for additional details.

With respect to the completed modification associated with elimination of a "Single Point Vulnerability" (i.e., Engineering Change (EC) No. 351639 / 351640), the licensee stated, in part:

Primary containment was not impacted since the tie-in for the new AOV 2(3)-4724 was outboard of the drywell and downstream of the existing outboard primary containment isolation valve AOV 2(3)-4722. All post modification testing was addressed by the performance of LLRTs.

The NRC staff has determined that following the completion of both modifications, neither will require a Type A test to re-establish containment operability at the conclusion of implementation. The licensee indicated that there are no major modifications planned for the primary containment that could affect its leak-tightness thereby subsequently requiring either a structural integrity test or ILRT. Following the evaluation of the licensee's furnished information, the NRC staff concludes that the licensee has adequately addressed the issues of SE Section 3.1.4 and Condition 4.

3.3.5 Condition 5 The fifth Limitation/Condition of Attachment 1 to the LAR, page 65, is derived from Sections 3.1.1.2 and 4.1 (i.e., Enclosure, page 19) of the NRC SE dated June 25, 2008 and stipulates 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.

Licensee Response In Table 3.8.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," the licensee stated:

DNPS 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 94-01 Revision 2-A, SER Section 3.1.1.2, DNPS will also demonstrate to the NRC that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.

Staff Evaluation NRC staff SE Section 3.1.1.2, Enclosure, page 6, for NEI 94-01, Revision 2, reads:

As noted above, Section 9.2.3, NEI TR 94-01, Revision 2, states, "Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history."

However, Section 9.1 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 believes 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 TR NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRC staff that an unforeseen emergent condition exists.

The licensee stated in its response that "DNPS will follow the requirements of NEI 94-01, Revision 3-A, Section 9.1." The staff notes that NEI 94-01, Revision 3-A, Section 9.1, "Introduction," contains the relevant passage from the NRC staff SE for NEI 94-01, Revision 2, and states in part:

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 has determined that the licensee has demonstrated its understanding that any extension of the Type A test interval beyond the upper-bound performance-based limit of 15 years should be infrequent and that any requested permission (i.e., for such an extension) will demonstrate to the NRC staff that an unforeseen emergent condition exists. Based on the staff's review of the above information, the staff concludes that the licensee has adequately addressed Condition 5.

3.3.6 Condition 6 The sixth Limitation/Condition of Attachment 1 to the LAR, page 65, is derived from Section 4.1 (i.e., Enclosure, pages 19 and 20) of the NRC SE dated June 25, 2008, and stipulates 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 Electric Power Research Institute (EPRI) Report No.

1009325, Revision 2, including the use of past containment ILRT data.

Licensee Response In Table 3.8.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," the licensee stated:

Not applicable. DNPS was not licensed under 10 CFR Part 52.

Staff Evaluation The NRC staff finds that DNPS is an operating reactor currently licensed under the requirements of 10 CFR Part 50. Therefore, the NRC staff agrees that Condition 6 does not apply to DNPS.

3.3. 7 Conclusion Based on the above evaluation of each Condition, the NRC staff has determined that the licensee has adequately addressed the six Conditions identified in Section 4.1 of the NRC SE for NEI 94-01, Revision 2-A. Therefore, the staff finds it acceptable for DNPS to adopt the Limitations and Conditions of NEI 94-01, Revision 2-A, as part of the implementation documents in DNPS TS 5.5.12, "Primary Containment Leakage Rate Testing Program" for DNPS, Unit 2, and Unit 3.

3.4 NEI 94-01, Revision 3, Limitations and Conditions As required by 10 CFR 50.54(0), the DNPS primary containments are subject to the requirements set forth in 10 CFR Part 50, Appendix J. Option B of Appendix J provides that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach. Currently, DNPS TS 5.5.12, "Primary Containment Leakage Rate Testing Program,"

is implemented in accordance with the guidelines contained in RG 1.163, as modified by two exceptions to NEI 94-01, Revision 0. The licensee's LAR with its supplement proposes to revise the DNPS TS 5.5.12 by replacing Option B implementation document RG 1.163 with NEI 94-01, Revision 3-A, along with the Limitations and Conditions of NEI 94-01, Revision 2-A, to govern the test frequencies and the grace periods for Type A, Type B, and Type C tests.

By letter dated June 8, 2012 (Reference 13), the NRC provided an SE, with Limitations and Conditions, for NEI 94-01, Revision 3. In the SE, the NRC concluded that NEI 94-01, Revision 3, describes an acceptable approach for implementing the optional performance-based requirements of 10 CFR Part 50, Appendix J, and is acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the Limitations and Conditions identified in SE Section 4.0 and summarized in SE Section 5.0. The accepted version of NEI 94-01, Revision 3, was subsequently issued as Revision 3-A. The NEI issued Revision 3-A, to NEI 94-01 on July 31, 2012. With Revision 3-A, the report was revised to incorporate the June 8, 2012, NRC SER The licensee indicated in the LAR that it will meet the Limitations and Conditions of NEI 94-01, Revision 3-A, Section 4.0. Accordingly, the licensee will be adopting in part the testing criteria ANSI/ANS 56.8-2002 as part of its licensing basis. As stated in Section 2.0, "Purpose and Scope," of NEI 94-01, Revision 3-A, where technical guidance overlaps between NEI 94-01, Revision 3-A, and ANSI/ANS 56.8-2002, the guidance of NEI 94-01, Revision 3-A, takes precedence.

In the LAR, the licensee proposes to invoke NEI 94-01, Revision 3-A, as the implementation document for DNPS TS 5.5.12, "Primary Containment Leakage Rate Testing Program," to govern its Type B and Type C LLRT programs.

The NRC staff has found that NEI TR 94-01, Revision 3, is an acceptable reference for use in licensee TSs to extend the Option B to 10 CFR Part 50, Appendix J, Type B test and Type C test intervals beyond 60 months, provided the following two Conditions are satisfied.

3.4.1 Condition 1 Section 4.0 of Enclosure, page 10 of 13, Condition 1 of the NRC letter dated June 8, 2012, states 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 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 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),

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 presents three (3) separate issues to be addressed:

Issue (1 ), the allowance of an extended interval for Type C LLRTs of 75 months carries 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.

Licensee Response The licensee response to Condition 1, Issue (1) is reflected in Section 3.8.2 of the LAR. In particular, Attachment 1 to the LAR, page 66, reads, in part:

The post-outage report shall include the margin between the Type B and Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La.

Issue (2), a corrective action plan shall be developed to restore the margin to an acceptable level.

Licensee Response The licensee response to Condition 1, Issue (2) is reflected in Section 3.8.2 of the LAR. In particular, Attachment 1 to the LAR, page 66, reads, in part:

When the potential leakage understatement adjusted Types B and C MNPLR total is greater than the DNPS, Units 2 and 3, leakage summation limit of 0.5 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the DNPS leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues so as to maintain an acceptable level of margin.

Issue (3), use of the allowed 9-month extension for eligible Type C valves is only authorized for non-routine emergent conditions with exceptions as detailed in NEI 94-01, Revision 3-A, Section 10.1.

Licensee Response The licensee response to Condition 1, Issue (3) is reflected in Section 3.6.2 of the LAR. In particular, Attachment 1 to the LAR, page 66, reads, in part:

DNPS, Units 2 and 3 will apply the nine-month allowable interval extension period only to eligible Type C components and only for non-routine emergent conditions. Such occurrences will be documented in the record of tests.

Staff Evaluation The NRC staff has reviewed NEI 94-01, Revision 3, against the licensee responses for Issues (1 ), (2), and (3) of Condition 1. Based on this review, the staff concludes that the licensee acknowledges all of the requirements of Condition 1 and that the licensee has established its intent for DNPS to comply with these requirements. Therefore, the staff finds that the licensee has adequately addressed Condition 1.

3.4.2 Condition 2 Section 4.0 of Attachment 1, pages 10 and 11 of 13, Condition 2 of the NRC letter dated June 8, 2012, states that:

The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust containment inspection program and the local leakage rate testing of penetrations. Most of the 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 [RFO], nearly all LLRTs 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 [RFOs].

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 predictat>le. 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 Types B [and] C total leakage, 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 presents two separate issues 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.

Licensee Response The licensee response to Condition 2, Issue (1) is reflected in Section 3.8.2 of the LAR. In particular, Attachment 1 to the LAR, pages 67 and 68, reads, in part:

The change in going from a 60-month extended test interval for Type C tested components to a 75-month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25% in the LLRT periodicity. As such, DNPS, Units 2 and 3 will conservatively apply a potential leakage understatement adjustment factor of 1.25 to the actual As-Left leak rate, which will increase the As-Left leakage total for each Type C component currently on greater than a 60-month test interval up to the 75-month extended test interval.

This will result in a combined conservative Type C total for all 75-month LLRTs being carried forward and will be included whenever the total leakage summation is required to be updated (either while on-line or following an outage).

When the potential leakage understatement adjusted leak rate total for those Type C components being tested on greater than a 60-month test interval up to the 75-month extended test interval is summed with the non-adjusted total of those Type C components being tested at less than or equal to a 60-month test interval, and the total of the Type B tested components, results in the MNPLR being greater than the DNPS leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the DNPS leakage limit. The corrective action plan should focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues....

(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 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.

Licensee Response The licensee response to Condition 2, Issue (2) is reflected in Section 3.8.2 of the LAR. In particular, Attachment 1 to the LAR, page 68, reads, in part:

If the potential leakage understatement adjusted leak rate MNPLR is less than the DNPS leakage summation limit of 0.50 La, then the acceptability of the greater than 60-month test interval up to the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.

In addition to Condition 1, Issues 1 and 2, which deal with the MNPLR Types B and C summation margin, NEI 94-01, Revision 3-A, also has a margin-related requirement as contained in Section 12.1, "Report Requirements."

A post-outage report shall be prepared presenting results of the previous cycle's Type Band Type C tests, and Type A, Type Band Type C tests, if performed during that outage. The technical contents of the report are generally described in ANSI/ANS-56.8-2002 and shall be available on-site for NRC review. The report shall show that the applicable performance criteria are met, and serve as a record that continuing performance is acceptable. The report shall also include the combined Type Band Type C leakage summation, and the margin between the Type B and Type C leakage rate summation and its regulatory limit. Adverse trends in the Type Band Type C leakage rate summation shall be identified in the report and a corrective action plan developed to restore the margin to an acceptable level.

At DNPS, in the event an adverse trend in the aforementioned potential leakage understatement adjusted Types Band C summation is identified, then an analysis and determination of a corrective action plan shall be prepared to restore the trend and associated margin to an acceptable level. The corrective action plan shall focus on those components which have contributed the most to the adverse trend in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.

At DNPS, an adverse trend is defined as three (3) consecutive increases in the final pre-mode change Types B and C MNPLR leakage summation values, as adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La.

Staff Evaluation The staff has reviewed NEI 94-01, Revision 3, against the licensee responses for Issues (1) and (2) of Condition 2. Based on this review, the staff concludes that the licensee acknowledges all of the requirements of Condition 2 and that the licensee has established its intent for DNPS to comply with these requirements. Therefore, the staff finds that the licensee has adequately addressed Condition 2.

Summary Based on the above evaluation of each Condition, the staff determined that the licensee has adequately addressed the two Conditions in Section 4.0 of the NRC SE for NEI 94-01, Revision

3. Therefore, the staff finds it acceptable for the licensee to adopt NEI 94-01, Revision 3-A, as the implementation document in DNPS TS 5.5.12, "Primary Containment Leakage Rate Testing Program," for both Unit 2 and Unit 3. Furthermore, the staff's evaluation of the licensee's proposed extension of ILRT and LLRT test intervals includes the following.

The NRC staff reviewed the Type A, Type B, and Type C leakage test results related to the licensee's proposal to extend 10 CFR Part 50, Appendix J test intervals. The ILRT results provided in the LAR indicate that the previous two consecutive Type A tests for both DNPS, Unit 2 and Unit 3 were successful with primary containment performance leakage rates less than the maximum allowable (i.e., 1.0 La at Pa) contained in the leakage rate acceptance criteria of TS 5.5.12c. Therefore, the staff finds that the performance history of both DNPS Units Type A tests supports extending the current ILRT interval on a permanent basis to 15 years as provided by NEI 94-01, Revision 3-A, and the Limitations and Conditions of NEI 94-01, Revision 2-A.

For DNPS, Unit 2, the NRC staff reviewed the "As-Left Pathway" local leak rates contained in the LAR and notes that the results of the "As-Left Maximum Pathway" for all the recent (i.e.,

since RFO D2R20 in 2007) Type Band C tests are significantly (i.e.,> 57%) less than the Type Band Type C test TS limit of s 0.60 La contained in TS 5.5.12d.1. The staff reviewed the LAR and notes that no components on extended intervals failed "As-Found" LLRT Program "Administrative Limits" during the two most recent RFOs of 2013 (D2R23) and 2015 (D2R24).

The information contained in the LAR was adequately supplemented by the licensee in response to an NRC RAI, with details about failures of "Administrative Limits" and subsequent corrective actions for LLRTs associated with the Unit 2 Type C tests since the RFO of 2011 (D2R22). Additionally, the licensee's RAI response provided the status of the "Implementation of Corrective Actions and Improvements to Leak Rate Test Program" pertaining to A and B Feedwater Loop Outboard and Inboard Check Valves. Based on the licensee's responses, the staff concludes that the licensee has taken adequate corrective action for failed Unit 2 LLRTs.

For DNPS, Unit 3, the NRC staff reviewed the "As-Left Pathway" local leak rates contained in the LAR and notes that the results of the "As-Left Maximum Pathway" for all the recent (i.e.,

since RFO D3R19 in 2006) Type Band C tests are significantly (i.e.,> 49%) less than the Type B and Type C test TS limit of s 0.60 La contained in TS 5.5.12d.1. The staff reviewed the LAR and notes that during the RFO of 2014 (D3R23) two components on extended intervals failed "As-Found" LLRT Program "Administrative Limits" and that during the RFO of 2016 (D3R24) no components on extended intervals failed "As-Found" LLRT Program "Administrative Limits."

The information contained in the LAR was adequately supplemented by the licensee in response to an NRC RAI, with status details of the "Implementation of Corrective Actions and Improvements to Leak Rate Test Program" pertaining to A and B Feedwater Loop Outboard and Inboard Check Valves. Based on the information contained in the LAR and the licensee's responses to the RAls, the staff concludes that the licensee has taken adequate corrective action for failed Unit 3 LLRTs.

Accordingly, the NRC staff finds that the licensee is effectively implementing the DNPS, Unit 2 and Unit 3 Type B and Type C leakage rate test programs, as required by 10 CFR Part 50, Appendix J, Option B, and that the performance history of Type B tests and Type C tests supports extending the current Type C test interval to 75 months as provided by NEI 94-01, Revision 3-A, for DNPS, Unit 2 and Unit 3.

3.4.3 Conclusion With the LAR and associated supplement (References 1 and 2) the licensee proposed to extend the DNPS, Unit 2 and Unit 3 current performance-based Type A test interval to no longer than 15 years by adopting NEI 94-01, Revision 3-A, and the Limitations and Conditions of NEI 94-01, Revision 2-A, as the implementation documents in TS 5.5.12. This change would allow DNPS Unit 2 to conduct the next Type A test no later than November 2024, in lieu of the current requirement of no later than plant restart from RFO D2R26 (i.e., fall 2019). Similarly, this change would allow DNPS Unit 3 to conduct the next Type A test no later than November 2023, in lieu of the current requirement of no later than plant restart from RFO D3R25 (i.e., fall 2018).

Consistent with the guidance in NEI 94 01, Revision 3-A, and the Limitations and Conditions of NEI 94-01, Revision 2-A, the licensee justified the proposed change by demonstrating adequate performance of the DNPS, Unit 2 and Unit 3 primary containments based on: (a) plant-specific containment leakage testing program results; (b) CISI results; and (c) a plant-specific risk assessment.

Based on the NRC staff's review of the LAR and RAI responses and the regulatory and technical evaluations above, the staff concludes that there is reasonable assurance that the licensee has addressed the NRC Conditions to demonstrate acceptability of adopting NEI 94-01, Revision 3-A, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, as the 10 CFR Part 50, Appendix J, Option B implementation documents for both DNPS, Unit 2 and Unit 3.

The NRC staff finds that the licensee adequately implemented its Primary Containment Leakage Rate Testing Program (i.e., Type A, B, and C leakage tests), for the DNPS, Unit 2 and Unit 3 primary containments. The results of past ILRTs and recent LLRTs demonstrate acceptable performance of the DNPS primary containments and demonstrate that the structural and leak-tight integrity of the containment structures are being adequately maintained. Additionally, the licensee adequately implemented its ASME Section XI, Subsection IWE and IWL program. The staff also finds that the structural and leak-tight integrity of the DNPS primary containments will continue to be monitored and maintained if DNPS adopts NEI 94-01, Revision 3-A, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, as the 10 CFR Part 50, Appendix J, Option B implementation documents for both Unit 2 and Unit 3. Accordingly, the staff determined that there is reasonable assurance that the structural and leak-tight integrity for the DNPS, Unit 2 and Unit 3 primary containments will continue to be maintained, without undue risk to public health and safety, if the current Type A test intervals are extended to 15 years and if the current Type C test intervals for qualifying CIVs are extended to 75 months.

3.5 Plant-Specific Confirmatory Analysis The LAR proposes to include a reference to NEI 94-01, Revisions 2-A and 3-A, in TS 5.5.12.

Therefore, incorporation of the proposed amendment would make the guidance in NEI 94-01 a TS requirement for DNPS. Section 9.2.3.1, "General Requirements for ILRT Interval Extensions beyond 10 years," of NEI 94-01, Revisions 2-A and 3-A, states that plant-specific confirmatory analyses are recommended 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 the EPRI TR-1009325, Revision 2-A, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals" (also known as EPRI TR-1018243). 4 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 the SE dated June 25, 2008, the NRC staff found the methodology in NEI 94-01, Revision 2, and EPRI TR-1009325, Revision 2,5 to be acceptable for referencing by licensees proposing to 4 ADAMS Accession No. ML072970206.

5 ADAMS Accession No. ML072970208.

amend their TSs to permanently extend the ILRT interval to 15 years, provided that certain Conditions are satisfied. These Conditions, set forth in Section 4.2 of the SE for EPRI TR-1009325, Revision 2, provide that:

3.6

1. The licensee submitted documentation indicating that the technical adequacy of its probabilistic risk assessment (PRA) is consistent with the requirements of RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," 6 relevant to the ILRT extension application.

2. The licensee submitted documentation indicating that the estimated risk increase associated with permanently extending the ILRT surveillance interval to 15 years is small, consistent with the clarification provided in Section 3.2.4.5 of the SE for EPRI TR-1009325, Revision 2. 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.

3. The methodology in EPRI TR-1009325, Revision 2, is acceptable, except for the calculation of the increase in expected population dose (per year of reactor operation).

In order to make the methodology acceptable, the average leak rate for the pre-existing containment large leak rate accident case (accident case 3b) used by the licensee shall be 100 La instead of 35 La.

4. An LAR is required in instances where containment overpressure is relied upon for ECCS performance.

PRA of the Proposed Extension of the ILRT Test Intervals The licensee performed a risk impact assessment for extending the Type A containment ILRT frequency. For the risk assessment, the risk was evaluated considering the changes from the base case of performing three tests in 10 years to the proposed case of performing one test in 15 years on a permanent basis. The risk assessment was provided in Attachment 3 to the LAR.

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

1. NEI 94-01, Revision 3-A;

2. EPRI TR-1009325, Revision 2;

3. RG 1.17 4, Revision 2, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" (ADAMS Accession No. ML100910006); and 6 ADAMS Accession No. ML090410014.

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

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 was met, and the NRC staff's evaluation is provided in the sections below.

3.6.1 Technical Adequacy of the PRA The first Condition provides that the licensee submit documentation indicating that the technical adequacy of its PRA is consistent with RG 1.200, Revision 2 (Reference 14), relevant to the ILRT extension application.

3.6.1.1 Internal Events Consistent with the information provided in Regulatory Issue Summary (RIS) 2007-06, "Regulatory Guide 1.200 Implementation," the NRC staff uses Revision 2 of RG 1.200 to assess the technical adequacy of the PRA used to support risk-informed applications. In Section 3.2.4.1 of the SE for NEI 94-01, Revision 2, and EPRI TR-1009325, Revision 2, the NRC staff states that Capability Category (CC) I of the ASME Code PRA standard shall be applied as the standard for assessing quality for ILRT extension applications, since approximate values of core damage frequency (CDF) and large early release frequency (LERF) and their distribution among release categories are sufficient for use in the EPRI methodology.

As discussed in Section 3.4.2.5 of Attachment 1 and Section A.2 of Attachment 3 to the LAR, the DNPS risk assessment performed to support the ILRT application uses the current DNPS, Unit 2, internal events PRA (IEPRA) model of record, which was completed in December 2013 and referred to as the 2013A PRA model, which includes consideration of internal flooding (IF).

In its supplemental letter (Reference 2), the licensee corrected a reference to utilizing a 2014 version of the PRA model included as part of Table 5.1-2 of Attachment 3 to the LAR. The correct version should have stated the use of a 2013A PRA model. In Section A.2 of to the LAR, the licensee describes the process used for controlling the PRA model and for ensuring that the model accurately reflects the as-built, as-operated plant. The licensee's PRA maintenance and update process includes procedures for regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA model, and for controlling the model and associated computer files. The licensee performed a review of plant modifications and changes that could impact the PRA model and concluded that there are no plant changes that have not yet been incorporated in the PRA models that could affect the ILRT extension application.

A full scope, independent peer review of the IEPRA model, excluding the IF portion of the model, was performed in November 2016. The peer review was performed using NEI 05-04, Revision 2 (Reference 15), as clarified by RG 1.200, Revision 2. The Facts and Observations (F&Os) from this peer review are provided in Table A-2 of Attachment 3 to the LAR. An independent focused-scope peer review of the IF PRA model was performed in March 2009.

The licensee clarified that references in the LAR to a focused-scope peer review of the IF PRA model in 2010 were incorrect and should have referred to the 2009 peer review (Reference 2).

The LAR states that the 2009 peer review was performed using NEI 05-04, Revision 2, as clarified by RG 1.200, Revision 1. The F&Os from this peer review are provided in Table A-1 of the LAR.

In Reference 2, regarding a gap assessment of the IF PRA model to RG 1.200, the licensee provided an assessment of the gaps between RG 1.200 Revisions 1 and 2. This assessment included: identification and evaluation of changes made to the ASME/ANS PRA standard between 2005 (ASME/ANS RA-Sb-2005, Addendum B to ASME/ANS RA-S-2002) and 2009 (ASME/ANS RA-Sa-2009), evaluation of NRC staff clarifications and qualifications in Tables A-1 and A-2 of RG 1.200, Revision 2, as they apply to the IF PRA, and evaluation of NRC staff clarifications and qualifications in Table A-3 of RG 1.200, Revision 2. The licensee's gap assessment did not identify any deficiencies with the IF PRA.

The PRA standard provides supporting requirements (SRs) for the PRA against CCs I, II, or Ill.

The peer reviews resulted in identification of F&Os against the PRA standard supporting requirements that did not meet CC I or higher, or that were met and had related findings. In Tables A-1 and A-2 of the LAR, the licensee provided these peer review F&Os, its disposition to each of them, and an assessment of the impact of each disposition on the ILRT application.

The NRC staff reviewed the licensee's disposition to each F&O. Regarding F&O 2-12, the licensee explained (Reference 2) that under certain conditions, continued availability of water injection into the containment and/or reactor pressure vessel (RPV) following containment failure was modeled with minimal credit (0.9 failure probability). The licensee performed a sensitivity analysis using the ILRT PRA model by removing this credit (setting failure probability to 1.0), which resulted in no change to CDF or LERF at a truncation limit of 1 E-11/year. Based on the results of the licensee's sensitivity analysis, the NRC staff concludes that the licensee's PRA credit for continued availability of water injection following containment failure has a negligible impact on the ILRT application.

Regarding SRs, the licensee clarified its LAR assessment that five SRs were not applicable to the DNPS PRA, as determined by a peer review team. The licensee provided justification for the assessment of each SR (Reference 2). Specifically, the licensee explained that two of the SRs (LE-D5 and LE-D6) are specific to pressurized-water reactors (PWRs) and are, therefore, not applicable to DNPS, which is a boiling water reactor (BWR), and that three of the SRs (AS-B4, QU-B10, and SY-A9) are specific to PRA model structures and techniques (i.e., split fractions, modules, subtrees, and super components) that are not utilized in the DNPS PRA.

Considering that the five SRs are either not applicable to BWRs or are not applicable to model structures and techniques used in the DNPS PRA, the NRC staff concludes that these SRs are not applicable to the PRA technical adequacy assessment for this ILRT LAR.

As discussed above, the ILRT application uses the DNPS, Unit 2, IEPRA model which includes consideration of IF for assessing DNPS, Unit 3 leakage rate testing interval extensions. The NRC staff requested in an RAI for the licensee to: (a) discuss the impact of significant differences in flooding risk between Units 2 and 3 and (b) explain how dual unit risk is adequately addressed by just the Unit 2 PRA. In response to part (a), the licensee explains that there is a separate PRA model of record (includes both IE (internal events) and IF) for both DNPS, Unit 2 and Unit 3, that the IF analysis covered both units but identified no substantive differences between the two units, and that the impact of flood sources in one unit on the opposite unit is included in the respective PRAs (Reference 2). The quantitative results for these PRAs show that the total (IE and IF) CDF and LERF for both units is the same to three decimal places, and that the total contribution to CDF from IF for both units is the same at 5.1 percent. In response to part (b ), the licensee explained that both the Units 2 and 3 PRA models of record include the impact of IE and IF initiators/flood sources from the opposite unit, and that the multi-unit SRs for both IE and IF were assessed by the respective peer review and self-assessment to be "Met." The licensee also demonstrated that the differences between the plant configurations of the two units are well understood and documented, that these configuration differences are reflected in the respective PRA models of record, and that these differences are not significant and so result in very similar risk profiles. The NRC staff also observes that Finding 5-16 for the IEPRA and Finding IF-C4a for the IFPRA identify deficiencies in the treatment of cross-unit impacts, but the licensee's resolution to both findings was found acceptable by the NRC staff for the ILRT application (i.e., they were either resolved with model changes or determined to be negligible for the ILRT application). Based on the licensee's responses and the licensee's dispositions to the applicable peer review findings, the NRC staff finds that the differences in the DNPS, Units 2 and 3, plant configurations have been appropriately considered. Therefore, the staff has determined that the use of the Unit 2 ILRT PRA model is acceptable for assessing Unit 3 leakage rate testing interval extensions.

The NRC staff reviewed the IE and IF PRA F&Os, and the associated dispositions by the licensee, and found that they are adequate for the ILRT application. The NRC staff also reviewed the results of the licensee's RG 1.200, Revision 2, gap assessment of the IF PRA and found that the IF PRA is adequate for the ILRT application.

3.6.1.2 External Events 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:

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.

Fire Events In Section 5.7.1 of Attachment 3 to the LAR, the licensee stated that there is no fire PRA model for DNPS available for use in risk-informed applications. For fire risk, the licensee used the results of the fire analysis performed for the individual plant examination of external events (IPEEE) analysis. The licensee's approach was to scale the internal events CDF/LERF by a multiplication factor based on the DNPS, Unit 3, fire CDF, which is greater than the DNPS, Unit 2, fire CDF. The licensee's risk assessment, including application of this multiplication factor, is discussed below in section 3.6.2.

Seismic Events In Section 5.7.2 of Attachment 3 to the LAR, the licensee stated that there is no seismic PRA model for DNPS available for use in risk-informed applications. For seismic risk, the licensee used the most conservative seismic CDF from the Generic Issue (GI) 199, "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants" (ADAMS Accession No. ML100270582), study in the risk assessment of the extended ILRT interval. The licensee's approach was to scale the internal events CDF/LERF by a multiplication factor based on this seismic CDF. The licensee's risk assessment, including application of this multiplication factor, is discussed below in section 3.6.2.

Miscellaneous Events In Section 5.7 of Attachment 3 to the LAR, the licensee reviewed the IPEEE analysis and conclusions for high winds, tornadoes, external floods, transportation accidents, and nearby facility accidents to consider changes to the plant configuration and surrounding environment since the IPEEE. The licensee concluded that these external events are very low risk contributors and do not impact the results of the ILRT extension interval risk analysis.

3.6.1.3 Conclusion The NRC staff concludes that the IE PRA, including the IF PRA model used by the licensee, is of sufficient technical adequacy to support the evaluation of changes to ILRT frequencies as it supports CC I of the PRA standard, as clarified by RG 1.200. In addition, the assessments of external events risk are sufficient for application to the ILRT extension evaluation as they support an order of magnitude estimate consistent with EPRI guidance. Accordingly, the first Condition of the staffs SE for EPRI TR-1009325, Revision 2, is met.

3.6.2 Estimated Risk Increase The second Condition of the NRC staffs SE for EPRI TR-1009325, Revision 2, provides 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 1.17 4 (Reference 16), and the clarification provided in Section 3.2.4.5 of the NRC SE report for NEI 94-01, Revision 2, and EPRI TR-1009325, Revision 2. 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 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 percent. Additionally, for plants that rely on containment over-pressure (i.e., containment accident pressure (CAP)) for net positive suction head (NPSH) 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. As discussed further in Section 3.6.4 below, DNPS credits CAP.

Thus, the associated risk metrics include CDF, LERF, population dose, and CCFP.

In Section 3.4.3 of Attachment 1 to the LAR, the licensee reported the results of the plant-specific risk assessment. Details of the risk assessment are provided in Attachment 3 to the LAR. The reported risk impacts are for a change in the Type A containment ILRT 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, and accounts for the risk from undetected containment leaks due to steel liner corrosion. The following conclusions can be drawn based on the licensee's risk analysis for the extended Type A ILRT interval:

1. In the LAR, the licensee reported an increase in internal events/IF CDF due to loss of CAP for a change in test frequency from three tests in 1 O years to one test in 15 years by increasing the containment isolation failure probability in the PRA. As discussed in section 3.6.4 below, the licensee revised this analysis in response to an RAI by the NRC staff and reported an increase in IE and IF CDF of 4.0E-08/year (Reference 2). The licensee's revised analysis failed to specifically account for the risk from external (fire and seismic) events. However, the licensee's revised analysis of the increase in LERF due to loss of CAP, provided in a response to an RAI by the staff and discussed in item 2 below, did account for the risk from external events (Reference 2). In this revised analysis, the licensee determined the increase in LERF for both internal and external events due to a loss of CAP to be 5.0E-07/year. Since the licensee assumes in the revised analysis that the increase in LERF is equivalent to the increase in CDF for loss of CAP scenarios, the staff determined that the increase in CDF can be assumed to also be 5.0E-07/year. This change in CDF is considered to be "very small" (i.e., below 1 E-06/yr) per the acceptance guidelines in RG 1.17 4.

2. The licensee reported that the increase in LERF for a change in test frequency from three tests in 10 years to one test in 15 years for internal events which includes IF is 3.3E-08/year for each unit. To account for the risk from external (fire and seismic) events, the licensee used a multiplier based on the ratio of bounding estimates of fire and seismic CDF to internal/IF events CDF. However, the licensee's analysis failed to account for the additional increase in LERF due to loss of CAP. In an RAI, the NRC staff requested the licensee to provide the total increase in LERF from the ILRT application, including the contribution to the LERF increase due to loss of CAP. The licensee's response included an estimated increase in LERF due to loss of CAP to be the same as the increase in the CDF due to loss of CAP (see section below titled, "Applicability if Containment Overpressure is Credited for ECCS Performance"}, which the licensee described as conservative because thermal-hydraulics analyses show that the loss of NPSH sequences, or failure of the core spray (CS) and low pressure coolant injection (LPCI) pumps, do not result in large early releases (Reference 2). After applying the multiplier to account for the increase in LERF due to loss of CAP for external events, the increase in LERF for combined internal and external events is 9.1 E-07/year for each unit. This change in risk is considered to be "small" (i.e., between 1 E-07 /year and 1 E-06/year) per the acceptance guidelines in RG 1.17 4. An assessment of total baseline LERF is required to show that the total LERF is less than 1 E-05/year, an estimate for which is provided in the LAR. During its evaluation, the NRC staff observed that the total LERF was close to the 1.0E-05/year criterion and in an RAI requested that the licensee provide information regarding the assumptions and uncertainties in the LERF estimate. The licensee's response provided a qualitative evaluation of the uncertainties and assumptions used in the determination of the contribution to LERF from: (1) fire events, (2) loss of CAP scenarios, (3) seismic events, (4) steel liner corrosion analysis, and (5) loss of decay heat removal scenarios (Reference 2). In each case, except for loss of CAP scenarios, the licensee provided justification to conclude that its treatment in the LAR is conservative, including (1) plant modifications and improved fire procedures that have reduced fire risk since the IPEEE, (2) use of a bounding seismic CDF from the NRC's Gl-199 program,7 (3) continuous monitoring in the DNPS control room of oxygen (02) levels in containment in accordance with DNPS technical specifications and required actions when technical specification criteria are exceeded, and (4) the results of DNPS-specific thermal-hydraulic analyses that show 7 Refer to ADAMS Accession No. ML100270756 dated August 31, 2010.

that treatment of loss of decay heat removal scenarios does not result in large early release. Based on the use of conservative fire and seismic CDFs in developing the multiplier to account for external events, and the use of a DNPS PRA model that has been peer reviewed with F&Os appropriately dispositioned, the NRC staff finds that the licensee's LERF analysis is adequate for the ILRT extension application. For loss of CAP scenarios, which is discussed extensively in the previous paragraph and in section 3.6.4 below, the licensee added the calculated increase in LERF to the total plant LERF.

The licensee described this contribution to LERF as conservative because thermal-hydraulics analyses show that the loss of NPSH sequences do not result in large early releases. Also, in the response an RAI, the licensee changed two LERF sequences in the PRA model used for the ILRT extension application from large/early release to medium/early release, with the basis for the change being DNPS-specific thermal-hydraulics analyses that show that there is sufficient time, with margin, after core damage and prior to a large fission product release, to evacuate the population (Reference 2). The licensee estimated the total LERF for internal and external events, using a multiplier (as discussed above), as 7.1 E-06/year for each unit. The total LERF, which includes the increase due to the ILRT interval extension, is below the acceptance guideline of 1 E-05/year in RG 1.17 4 for a "small" change.

3. The licensee reported that the increase in the total population dose for a change in the Type A ILRT frequency from three in 10 years to once in 15 years for internal/IF events is 4.3E-2 person-rem/year for each unit. To account for the risk of external events (fire and seismic), the licensee used a multiplier, as described above. However, the licensee's analysis failed to account for the additional population dose due to loss of CAP. In the licensee's response to an RAI, the licensee estimated the population dose contribution due to loss of CAP for internal and external events to be 4.9E-01 person-rem/year (Reference 2). The licensee stated in its response that the increase in total population dose for combined internal and external events, including loss of CAP, is 1.03 person-rem/year. This represents 0.52 percent of the total population dose; described by the license to be conservative due to thermal-hydraulics analyses which show that the loss of NPSH sequences (including failure of the CS and LPCI pumps) does not result in large early releases which contribute approximately 50 percent of these results.

The NRC staff observed that a 36-hour release time was assumed for consequence category L2-10 (intact containment), which is used to calculate the population dose rate for the ILRT application, and in an RAI requested the licensee to justify that continued releases after 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> do not impact the conclusions of the LAR. The licensee's response provided graphs showing the cumulative release fractions from start of release for cesium (as cesium hydroxide or CsOH), iodine (as cesium iodide or Csl), and noble gases fission products for release category L2-10, and explains that cesium and iodine are the dominant contributors to early population dose and noble gases are the dominant contributors to long term population dose (Reference 2). These graphs show that: (1) releases of Csl after 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> are minimal, (2) releases of CsOH continue after 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, but at a substantially reduced rate from the initial release rate, and (3) releases of noble gases continue after 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> at essentially the same rate as the initial release rate (i.e., the release rate is linear over time). The licensee also provides a sensitivity analysis that shows that increasing the noble gas release fraction by 100 percent ( essentially doubling the release time) will result in about a one percent increase in the population dose. However, the NRC staff evaluated a concern that the population dose is likely dominated by the continuing release of CsOH after 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, not the continuing release of noble gases, and whether the fission product release rates could potentially increase after 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> (e.g., due to a loss of water injection capability).

While the licensee's response did not specifically address the potential for fission product release rates to increase after 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, a sensitivity analysis was provided that showed that if drywell spray were credited rather than RPV core spray, both CsOH and Csl releases would decrease by over an order of magnitude relative to those assumed in the ILRT application. Based on the low release rate of CsOH and Csl after 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, and the significant conservatism in the population dose analysis from not crediting drywell spray, the NRC staff concludes that using a 36-hour release time does not impact the conclusions of the LAR that the population dose acceptance criteria are met.

The reported increase in total population dose is the same as or below the values provided in EPRI TR-1009325, Revision 2-A, and defined in Section 3.2.4.6 of the NRC SER for NEI 94-01, Revision 2, (i.e., 1.0 person-rem/year or 1 percent, whichever is most restrictive). While the licensee's reported population dose is slightly higher than the 1.0 person-rem/year criterion, conservatisms in the licensee's analysis (i.e., thermal-hydraulics analyses that show that the loss of NPSH sequences do not result in large early releases and not crediting drywell sprays) provide reasonable assurance that the population dose criterion is not exceeded with the ILRT application. Therefore, the NRC staff has concluded that the increase in the total integrated plant risk for the proposed change is considered small and supportive of the proposed change.

4. The licensee's revised analysis provided in an RAI response reported that the increase in CCFP for a change in test frequency from three in 10 years to once in 15 years is 1.03 percent (Reference 2). This value is below the acceptance guideline of 1.5 percent in Section 3.2.4.6 of the NRC SER for NEI 94-01, Revision 2, and is therefore, acceptable.

3.6.2.1 Sensitivity Analysis of Containment Steel Liner Corrosion The EPRI TR-1009325, Revision 2-A, recommends a sensitivity analysis to assess the impact of assumptions regarding corrosion-induced leakage of steel containments/liners be completed.

The methodology calls for a separate plant-specific assessment of the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended ILRT interval. The licensee's reported risk impacts discussed above for a change in the Type A containment ILRT 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, accounts for the risk from undetected containment leaks due to steel liner corrosion.

The licensee's analysis used the Calvert Cliffs Nuclear Power Plant methodology8 to estimate the risk significance of age-related containment steel liner corrosion large leaks. The method provides an estimate of the likelihood of non-detected containment leakage due to corrosion.

This method for assessing ILRT frequency represents a reliability model in which the containment is "as good as found" and not "as good as new" because there is a likelihood that the ILRT may not detect a containment flaw. Thus, undetected flaws could continue to grow until detected and corrected.

8 ADAMS Accession No. ML020920100 dated March 27, 2002.

In Table 6.1-1 of Attachment 3 to the LAR, the licensee also provided the results of a sensitivity analysis that varied the assumptions used in the steel liner corrosion analysis. Parameters varied included: (1) increasing and decreasing the failure rate doubling time of the steel liner, (2) increasing and decreasing the likelihood of breach in containment given steel liner flaw for both the containment wall and the basemat, and (3) increasing and decreasing the visual inspection detection failure likelihood for both the containment wall and the basemat. The licensee reported that the increase in LERF for a change in test frequency from three tests in 10 years to one test in 15 years for internal/IF events ranged from 2.9E-08/year to 1.54E-07/year for each unit. The licensee's analysis failed to account for the risk from external (fire and seismic) events. To account for the risk from external events in the analysis results reported above, the licensee used a multiplier based on the ratio of bounding estimates of fire and seismic CDF to internal/IF events CDF. The NRC staff used this same multiplier approach and calculated the increase in LERF for combined internal and external events to range from 3. 7E-07 /year to 1.9E-06/year for each unit. Based on this analysis, only the sensitivity case that assumed upper bound values for all of the varied parameters exceeded the acceptance guideline of 1 E-06/year in RG 1.17 4 for a "small" change. Due to the bounding nature of this sensitivity case, the NRC staff does not expect the guideline to be exceeded from the steel liner corrosion contributor.

3.6.2.2 Conclusion Based on the estimated risk results for the risk metrics, the NRC staff concludes that the increase in CDF, and the increase in LERF satisfies the acceptance guidelines of RG 1.174, 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. Accordingly, the second Condition of the NRC staffs SE for EPRI TR-1009325, Revision 2, is met.

3.6.3 Leak Rate for the Large Pre-Existing Containment Leak Rate Case The third Condition of the NRC staffs SE for EPRI TR-1009325, Revision 2, states that the methodology in EPRI TR-1009325, Revision 2, is acceptable, except for the calculation of the increase in expected population dose (per year of reactor operation). 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 licensee shall be 100 La instead of 35 La.

Table 4.1-1 of Attachment 3 to the LAR, defines the containment failure classifications used for the containment Type A ILRT. The containment failure classification of interest for the extended ILRT is Class 3, which is described as independent (or random) isolation failures that include those accidents in which the pre-existing isolation failure to seal (i.e., provide a leak tight containment) is not dependent on the sequence in progress. Class 3 sequences include core damage sequences in which containment integrity is impaired due to random isolation failures of plant components other than those associated with Type B or Type C test components; for example, liner breach or bellows leakage, if applicable. Pre-existing containment leaks that are classified as a large early release are designated as Class 3b in the LAR and are evaluated for the risk analysis.

3.6.3.1 Conclusion As noted in Table 3.4.1-1 of Attachment 1 and Section 5.2 of Attachment 3 to the LAR, the DNPS plant-specific risk analysis used 100 La as the average leak rate for the pre-existing containment large leakage rate accident case (Class 3b) in accordance with EPRI TR-1009325, Revision 2-A, to calculate the increase in population dose for the large leak rate accident case.

Therefore, the NRC staff concludes that the third Condition of the NRC staff's SE for EPRI TR-1009325, Revision 2, is met.

3.6.4 Applicability if Containment Overpressure is Credited for ECCS Performance The fourth Condition of the NRC staff's SE for EPRI TR-1009325, Revision 2, provides that an LAR is required in instances where containment overpressure is relied upon for ECCS performance. The NRC staff has discontinued the use of the term "containment overpressure" since the industry uses several definitions of containment overpressure, and the term has been confused with exceeding the design pressure of the containment. The inclusion of some or all of the pressure developed in the containment during an accident, in calculating the NPSH, is referred to as CAP. The containment design pressure is never exceeded while crediting CAP.

The guidance in EPRI TR-1009325, Revision 2, Section 4.2.6, is that the PRA model should be adjusted to account for CAP to evaluate the impacts on CDF. The combined impacts on CDF and LERF are considered and compared with the risk acceptance guidelines of RG 1.17 4. The guidance identifies two examples of sequences where CAP may be considered:

LOCA scenarios where the initial containment pressurization helps to satisfy the NPSH requirements for early injection in BWRs or in PWR sump recirculation, and 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 (i.e., BWR suppression pool).

In Section 5.8 of Attachment 3 to the LAR, the licensee states that there is some dependency on NPSH at DNPS and that the DNPS PRA model does include scenarios where CDF could be impacted due to an increase in the likelihood for a loss of containment accident pressure resulting from a pre-existing leak from containment and loss of heat removal systems. The LAR also provided an assessment of the increase in internal/IF events CDF due to loss of CAP for a change in test frequency from three tests in 10 years to one test in 15 years.

The NRC staff observed that the increased CDF from crediting CAP was estimated by increasing the containment isolation failure probability in the PRA and in an RAI requested that the licensee provide a detailed justification for this approach. The licensee's response provided a revised assessment of the increase in CDF from crediting CAP using the baseline DNPS PRA model and a detailed description of the associated modeling assumptions, including a listing and description of all accident sequences in the PRA that include failure of CS and LPCI pumps taking suction from inside the containment that are modeled in the PRA as relying on NPSH (Reference 2). These sequences include loss of coolant accidents where the initial containment pressurization helps to satisfy the NPSH requirements for early injection.

However, the licensee explained that the DNPS PRA model does not credit CS or LPCI injection with a loss of containment heat removal and a pre-existing leak (i.e., there is no credit for gradual containment pressurization). The results of thermal-hydraulics sensitivity analyses showed that relying on NPSH is appropriate for pre-existing leak scenarios (up to 200 La) when either suppression pool cooling (SPC) or shutdown cooling (SDC) is available (i.e., a pre-existing leak is not sufficient to fail the CS or LPCI pumps), and that there is over 50 °F margin between the peak suppression pool temperature and the boiling temperature of water. The licensee's response provides a summary of key assumptions and inputs in to these sensitivity analyses, including assuming a pre-existing leak of 200 La (two times the definition of a large leak in the ILRT application), and concludes that the analyses are conservative. Based on the results of these sensitivity analyses, in the revised assessment of the increase in CDF from crediting CAP, the licensee failed CS and LPCI in the baseline PRA model for NPSH-credited scenarios in which SPC or SOC is not available. The DNPS PRA model includes an "AND" gate that is "true" when basic events for SPC, SOC, and pre-existing containment failure (or pre-existing leak) are "true." When the "AND" gate is true, CS and LPCI injection are failed. In the licensee's revised analysis, the probability of a pre-existing containment failure was set to zero, which resulted in the increase in baseline CDF from the loss of NPSH to be 1.2E-08/year.

However, because the DNPS PRA used a large pre-existing leak probability of 2. 7E-03 rather than 2.3E-03 specified in EPRI TR-1009325, Revision 2, the increase in baseline CDF was reduced to 1.0E-08/year by multiplying 1.2E-08/year by the ratio of the two probabilities. The increase in IE and IF CDF for the ILRT application (i.e., changing the ILRT frequency from three tests in 10 years to one test in 15 years) is then estimated to be 4.0 E-08/year (5 x baseline CDF contribution - baseline CDF contribution). The NRC staff finds the licensee's PRA modeling of the loss of NPSH to be reasonable and conservative for the reasons cited by the licensee and, therefore, concludes that the licensee's estimated increase in IE and IF CDF from crediting CAP is acceptable for the ILRT application.

3.6.4.1 Conclusion In accordance with EPRI TR-1009325, Revision 2-A, the LAR and responses to NRC staff RAls adequately provided an assessment of the increase in CDF due to the loss of CAP. Therefore, the NRC staff concludes that the fourth Condition of the NRC staffs SE for EPRI TR-1009325, Revision 2, is met.

3.7 Staffs Overall 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 B and 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 DNPS TS 5.5.12 regarding the primary containment leakage rate testing program are acceptable.

The staff concludes that it is acceptable for the licensee to:

(i) revise TS 5.5.12, "Primary Containment Leakage Rate Testing Program," to adopt NEI 94-01, Revision 3-A, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, as the 10 CFR Part 50, Appendix J, Option B implementation documents; (ii) delete the existing two historical exceptions associated with TS 5.5.12a; (iii) extend on a permanent basis the Type A test interval up to 15 years; and (iv) extend the Type C test intervals for qualifying CIVs up to 75 months.

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 June 22, 2018. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change requirements with respect to the installation or use of facility components located within the restricted area as defined in 1 O 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 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 published in the Federal Register on August 1, 2017(82 FR 35838). 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.

7.0 REFERENCES

1. Exelon Generation Company, LLC (EGC), dated May 3, 2017, from Patrick R. Simpson, Manager - Licensing, to USNRC re: Request for License Amendment to Revise Technical Specifications Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies (ADAMS Accession No. ML17123A104).

2. Exelon Generation Company, LLC (EGC), dated February 14, 2018, from Patrick R.

Simpson, Manager - Licensing, to USNRC re: Response to NRC Request for Additional Information (RAI) for Request for License Amendment to Revise Technical Specification 5.5.12, "Primary Containment Leakage Rate Testing Program" (ADAMS Accession No. ML18045A508).

3. Nuclear Energy Institute Topical Report NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 2012 (ADAMS Accession No. ML12221A202).

4. Nuclear Energy Institute Topical Report NEI 94-01, Revision 2-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated October 2008 (ADAMS Accession No. ML100620847).

5. NRC Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program," September 1995 (ADAMS Accession No. ML003740058).

6. Letter from M. Banerjee (NRC) to C. M. Crane, President and Chief Nuclear Officer (EGC), re: Issuance of Amendments - Dresden Nuclear Power Station, Units 2 and 3, One-Time Extension of Containment Type A Leakage Rate Test Interval {TAC Nos.

MC1796 and MC1797), dated October 13, 2004 (ADAMS Accession No. ML042520432).

7. NRC Final Safety Evaluation Report, "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report 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 Test Intervals," US Nuclear Regulatory Commission, Washington, DC, June 25, 2008 (ADAMS Accession No. ML081140105).

8. ANSI/ANS-56.8-2002, Reaffirmed August 9, 2011, "Containment System Leakage Testing Requirements."

9. ANSI/ANS-56.8-1994, Approved August 4, 1994, "Containment System Leakage Testing Requirements" (ADAMS Accession No. ML11327A024).

10. Bechtel Corporation Procedure BN-TOP-1, Revision 1, "Testing Criteria for Integrated Leakage Rate Testing of Primary Containment Structures," dated November 1, 1972.

11. NRC Regulatory Guide 1.54, "Quality Assurance Requirements for Protective Coatings Applied to Water Cooled Nuclear Power Plants," Revision 0, U.S. Nuclear Regulatory Commission, Washington, DC, June 1973. (ADAMS Accession No. ML003740187).

12. Nuclear Energy Institute 94-01, Revision 2, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J" and Electric Power Research Institute Report No. 1009325, Revision 2, August 2007, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals" (ADAMS Accession No. ML072970206).

13. Letter from S. Bahadur (NRC) to B. Bradley (NEI), dated June 8, 2012, "Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J (TAC No. ME2164)" (ADAMS Accession No. ML121030286).

14. RG 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," dated March 2009 (ADAMS Accession No. ML090410014).

15. NEI 05-04, Revision 2, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard" (ADAMS Accession No. ML083430462).

16. RG 1.17 4, Revision 2, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," dated May 2011 (ADAMS Accession No. ML100910006).

Principal Contributors:

D. Nold, NRR J. Bettle, NRR D. Hoang, NRR J. Evans, NRR Date of issuance: June 29, 2018

ML18137A271

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