ML16047A272

License Amendment Request: Revise Technical Specification 5.5.11 to Provide a Permanent Extension of the Integrated Leakage Rate (Type a) Test Frequency from Ten to Fifteen Years

ML16047A272
Person / Time
Site:	Monticello
Issue date:	02/10/2016
From:	Karenina Scott Northern States Power Co, Xcel Energy
To:	Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML16047A336	List: L-MT-16-001, 54005-CALC-001, Revision 2, Evaluation of Risk Significance of Permanent ILRT Extension ML16047A272
References
L-MT-16-001
Download: ML16047A272 (77)

Text

XcelEnergy 2807ceW CountycRoad~ 75 February 10, 2016 L-MT-1 6-001 10 CFR 50.90 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Monticello Nuclear Generating Plant Docket No. 50-263 Renewed Facility Operating License No. DPR-22 License Amendment Request: Revise Technical Specification 5.5.11 to Provide a Permanent Extension of the Integrated Leakage Rate (Type A) Test Frequency from Ten to Fifteen Years In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," the Northern States Power Company, a Minnesota corporation, d/b/a Xcel Energy (hereafter "NSPM"), requests a change to the Technical Specifications (TS) for the Monticello Nuclear Generating Plant (MNGP). The proposed change revises Specification 5.5.11 "Primary Containment Leakage Rate Testing Program", to increase the containment integrated leakage rate test (ILRT) program Type A test interval from 10 years to 15 years. The basis for the proposed change is in accordance with the guidance of Nuclear Energy Institute (NEI) Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 2-A, as endorsed by the U.S. Nuclear Regulatory Commission.

The proposed license amendment request (LAR) is risk-informed and follows the guidance provided by Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk-Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis", Revision 2.

Enclosure I contains a description and summary safety assessment of the proposed TS change as well as the technical bases for the changes. The enclosure also provides the No Significant Hazards Consideration evaluation in accordance with 10 CFR 50.92, "Issuance of Amendment," and the Environmental Assessment. These provide the bases for the conclusion that the amendment request involves no significant hazards consideration and meets the eligibility criterion for categorical exclusion as set forth in 10 CFR 51.22, "Criteria for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review," paragraph (c)(9).

Document Control Desk L-MT-16-001 Page 2 of 2 Attachment I to Enclosure 1 contains the marked-up TS page. Attachment 2 to provides the marked-up TS Bases pages for information. NSPM has performed a plant-specific evaluation to assess the risk impact of the proposed changes. A copy of the risk assessment is provided in Enclosure 2.

NSPM requests approval of the proposed LAR within one year after submittal to support an extension of the current MNGP ILRT interval, which requires performance of the ILRT during the upcoming refueling outage (RFO) in the Spring of 2017. Once approved, this amendment shall be implemented prior to startup from the 2017 RFO.

The MNGP Plant Operations Review Committee has reviewed this application. In accordance with 10 CFR 50.91, "Notice for public comment; State consultation,"

paragraph (b), NSPM is notifying the State of Minnesota by transmitting a copy of this application, with the enclosures, to the designated State Official.

Summary of Commitments This letter proposes no new commitments and does not revise any existing commitments.

If you have any questions or require additional information, please contact Mr. Richard Loeffier at (763) 295-1247.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on February ho, 2016.

Kent Scott /

for Peter A. Gardner Site Vice President - Monticello Nuclear Generating Plant Northern States Power Company - Minnesota :

Discussion and Evaluation of the Proposed Changes :

Marked-up Technical Specification Page : Marked-up Technical Specification Bases Page :

MNGP Evaluation of Risk Significance of Permanent ILRT Extension cc:

Administrator, Region Ill, US NRC Project Manager, Monticello Nuclear Generating Plant, US NRC Resident Inspector, Monticello Nuclear Generating Plant, US NRC State of Minnesota

L-MT-1 6-00 1 LICENSE AMENDMENT REQUEST: REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS Table of Contents ENCLOSURE 1 1.0

SUMMARY

DESCRIPTION............................................................. I

2.0 BACKGROUND

INFORMATION.......................................................

I 3.0 DETAILED DESCRIPTION............................................................. 2 3.1 Current Containment Leakage Rate Testing Program........................... 2 3.2 Proposed Technical Specification Change Description......................... 3

4.0 TECHNICAL EVALUATION

............................................................ 4 4.1 Description of the Primary Containment System................................. 4 4.1.1 Drywell.............................................................................. 5 4.1.2 Suppression Chamber.......................................................... 6 4.1.3 Piping Penetrations............................................................... 6 4.1.4 Electrical Penetrations.......................................................... 7 4.1.5 Plant Operational Considerations Relating to Containment Leakage........ 7 4.1.6 Containment Heat Removal and Emergency Core Cooling System Net Positive Suction Head Performance........................................... 8 4.2 Justification for the Proposed Technical Specification Change.............. 10 4.2.1 Chronology of Testing Requirements of 10 CER 50, Appendix J........... 10 4.2.2 Current MNGP Integrated Leakage Rate Testing Requirements........... 13 4.2.3 MNGP 10 CER 50, Appendix J, Option B Licensing History................ 14 4.2.4 MNGP Integrated Leakage Rate Testing History............................. 15 4.3 Plant Specific Confirmatory Analysis............................................. 17 4.3.1 Methodology...................................................................... 17 4.3.2 Technical Adequacy of the MNGP Probabilistic Risk Assessment......... 21 4.3.3 Summary of Plant-Specific Risk Assessment Results....................... 23 4.3.4 Previous Assessments........................................................ 24 4.4 Non-Risk Based Assessment...................................................... 24 4.4.1 Containment Inservice Inspection Plan (IWE Plan).......................... 25 Page 1 of 3

TABLE OF CONTENTS 4.4.2 Nuclear Coatings Program.................................................... 35 4.4.3 Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program...................................................... 38 4.4.4 Type B and Type C Local Leak Rate Testing Program Implementation Review.......................................................................... 39 4.4.5 Supplemental Inspection Requirements...................................... 40 4.5 Operating Experience................................

'.............................. 41 4.5.1 NRC Generic Letter 87-05, "Request for Additional Information -

Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells".............................................. 42 4.5.2 NRC Information Notice 1992-20, "Inadequate Local Leak Rate Testing"......................................................................... 44 4.5.3 Information Notice 2004-09,"Corrosion of Steel Containment and Containment Liner"............................................................. 45 4.5.4 Information Notice 2010-12, "Containment Liner Corrosion"............... 45 4.5.5 Information Notice 2011-1 5, "Steel Containment Degradation and Associated License Renewal Aging Management Issues".................. 46 4.5.6 Information Notice 20 14-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner".................................................... 47 4.5.7 Draft RIS 20YY-XX, "Containment Shell or Liner Moisture Barrier Inspection"..................................................................... 48 4.6 License Renewal Aging Management.........................................

... 49 4.6.1 Primary Containment In-Service Inspection Program....................... 49 4.6.2 Protective Coating Monitoring and Maintenance Program.................. 49 4.6.3 10 CFR 50, Appendix J Program............................................. 50 4.7 NRC Safety Evaluation Limitation and Conditions.............................

50 4.7.1 Limitations and Conditions Applicable to NEI 94-01, Revision 2-A........ 50 4.8 Conclusion........................................................................... 52 5.0

REGULATORY EVALUATION.......................................................

53 5.1 Applicable Regulatory Requirements............................................

53 5.2 Precedent............................................................................

57 5.3 No Significant Hazards Determination...........................................

57 Page 2 of 3

TABLE OF CONTENTS

6.0 ENVIRONMENTAL CONSIDERATION

............................................. 60

7.0 REFERENCES

......................................................................... 61 ATTACHMENT I ATTACHMENT 2 ENCLOSURE 2 Page 3 of 3

L-MT-1 6-00 1 Page 1 of 64 LICENSE AMENDMENT REQUEST: REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS 1.0

SUMMARY

DESCRIPTION Pursuant to 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," the Northern States Power Company, a Minnesota corporation, dlb/a Xcel Energy (hereafter "NSPM"), requests an amendment to the Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS) to revise Specification 5.5.11 "Primary Containment Leakage Rate Testing Program" to:

Increase the existing Type A containment integrated leakage rate test (ILRT) program Type A test 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 50, Appendix J",

Revision 2-A (Reference 1).

• Adopt the use of American National Standards Institute (ANSI) / American Nuclear Society (ANS) 56.8-2002, "Containment System Leakage Testing Requirements" (Reference 2)

The proposed change revises Specification 5.5.11 by replacing the reference to Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program" (Reference 3) and NEI 94-01, Revision 0, with a reference to NEI 94-01, Revision 2-A, as the document used to implement a performance-based leakage test program in accordance with "Option B - Performance-Based Requirements" of 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," (Reference 4).

NSPM has evaluated the additional considerations (e.g., extended Type C intervals) afforded by NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 3-A (Reference 5) and has chosen not to pursue adoption of NEI 94-01, Revision 3-A at this time.

2.0 BACKGROUND

INFORMATION The MNGP is a boiling water reactor (BWR) of the General Electric (GE) BWR/3 design, with a Mark I containment. The plant is located within the city limits of Monticello, Minnesota,. on the south bank of the Mississippi River approximately 30 miles northwest of Minneapolis/St. Paul, Minnesota. Commercial operation began on June 30, 1971.

The design of the plant predates both the 70 proposed draft General Design Criteria (GDC) issued for public comment by the Atomic Energy Commission (AEC) in July 1967 and the 1971 publication of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50.

L-MT-1 6-001 Page 2 of 64 A high level summary of licensing history pertinent to Type A testing follows. On April 3, 1996, 10 CFR 50, Appendix J, Option B,Section III.A was adopted for Type A testing at the MNGP. On March 31, 2003, a one-time, 5-year extension to the 10-year Type A test interval was approved. On December 7, 2006, a full-scope alternative source term license amendment was approved. In conjunction, the exemptions to Section III.A and Section III.B of 10 CFR 50, Appendix J, Option B, received allow the exclusion of main steam line (MSL) pathway leakage contributions from the overall integrated leakage rate for Type A tests and to the sum of the leakage rates for Type B and Type C tests. On December 9, 2013, an Extended Power Uprate (EPU) license amendment was received which increased the maximum licensed thermal power level by approximately 13 percent, from a previous level of 1,775 megawatts-thermal (MWt) to 2,004 MWt. As part of that amendment the Primary Containment accident pressure in the plant TS increased from 42.0 psig to 44.1 psig.

3.0 DETAILED DESCRIPTION 3.1 Current Containment Leakage Rate Testing Program MNGP Specification 5.5.11, "Primary Containment Leakage Rate Testing Program,"

currently states, in part:

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

1.

The Type A testing Frequency specified in NEI 94-01, Revision 0, Paragraph 9.2.3, as "at least once per 10 years based on acceptable performance history" is modified to be "at least once per 15 years based on acceptable performance history." This change applies only to the interval following the Type A test performed in March 1993.

2.

The main steam line pathway leakage contribution is excluded from the sum of the leakage rates from Type B and C tests specified in Section III.B of 10 CFR 50, Appendix J, Option B, Section 6.4.4 of ANSI/ANS 56.8-1994, and Section 10.2 of NEI 94-01, Rev. 0; and 2.(1) The main steam line pathway leakage contribution is excluded from the overall integrated leakage rate from Type A tests specified in Section IlI.A of 10 CFR 50, Appendix J, Option B, Section 3.2 of ANSI/ANS 56.8-1 994, and Section 8.0 and 9.0 of NEI 94-01, Rev. 0.

1.

Typographical numbering error corrected by this amendment.

L-MT-1 6-001 Enclosure I Page 3 of 64 3.2 Proposed Technical Specification Change Description The proposed TS change would allow an increase in the ILRT test interval from the current 10-year frequency to a maximum of 15 years, in accordance with NEI 94-01, Revision 2-A. The specific changes proposed to Specification 5.5.11 are:

Replace reference to RG 1.163, dated September 1995, with a reference to NEI 94-01, Revision 2-A.

Remove the reference to the one-time change extending the interval after the Type A test performed in March 1993 from at least once per 10 years to at least once per 15 years. That interval is complete. The Type A test was performed in April 2007.

Update the references to ANSI/ANS 56.8 from the 1994 version to the 2002 version of the standard.

Update the references to NEI 94-01 from Revision 0 to Revision 2-A.

The revised Specification 5.5.11 would then state:

a. A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 2-A, dated October 2008, as modified by the following exceptions:

1.

The main steam line pathway leakage contribution is excluded from the sum of the leakage rates from Type B and C tests specified in Section III.B of 10 CFR 50, Appendix J, Option B, Section 6.4.4 of ANSI/ANS 56.8-2002, and Section 10.2 of NEI 94-01, Revision 2-A; and

2.

The main steam line pathway leakage contribution is excluded from the overall integrated leakage rate from Type A tests specified in Section lII.A of 10 CFR 50, Appendix J, Option B, Section 3.2 of ANSI/ANS 56.8-2002, and Sections 8.0 and 9.0 of NEI 94-01, Revision 2-A.

A mark-up of proposed Specification 5.5.11 is provided in Attachment I to this enclosure. No TS Bases are associated with Section 5 of the TS which includes Section 5.5, "Programs and Manuals," subsection of the TS. However, the TS Bases for Specification 3.6.1.1, "Primary Containment," are also being revised to reflect the change in the ILRT test interval from 10 to 15 years and to provide the basis for the change in frequency via this license amendment request. The TS Bases for Specification 3.6.1.1 are provided in Attachment 2. The TS Bases will be updated in accordance with the Specification 5.5.9, "Technical Specification Bases Control Program." The TS Bases pages are provided for information only.

L-MT-1 6-001 Page 4 of 64 A plant-specific risk assessment entitled, "Monticello Nuclear Generating Station:

Evaluation of Risk Significance of Permanent ILRT Extension," performed by Jensen Hughes is provided as Enclosure 2. This assessment followed the guidelines of RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis", Revision 2 (Reference 6) and RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities", Revision 2 (Reference 7). The technical adequacy of the MNGP probabilistic risk assessment (PRA) is discussed in Appendix A of the assessment.

The risk assessment concluded that the increase in risk from changing the ILRT performance interval from 10 to 15 years is considered insignificant since it represents a very small change in the MNGP risk profile that is within the NRC established guidelines.

4.0 TECHNICAL EVALUATION

The following paragraphs provide a background discussion of the systems, components and parameters affected by the proposed changes. The discussion is provided for information and does not describe the changes being proposed.

4.1 Description of the Primary Containment System The MNGP is a BWR/3 with a Mark I pressure suppression type primary containment system( 2). The Primary Containment encloses the reactor vessel, the reactor coolant recirculation system loops, and other primary system piping. The Primary Containment consists of a Drywell, which encloses the reactor vessel and recirculation pumps, a pressure suppression chamber (torus or wetwell) that stores a large volume of water, a connecting vent system between the Drywell and the suppression (water) pool, isolation valves, vacuum breakers, ventilating and cooling systems, and other service equipment.

The function of the Primary Containment is to isolate and contain fission products released from the reactor primary system piping following a postulated design basis accident (DBA), i.e., a loss of coolant accident (LOCA), and confine the postulated release of radioactive material. It surrounds the reactor primary system piping and provides an essentially leak tight barrier against an uncontrolled release of radioactive material to the environment. The safety design basis for the Primary Containment is to

2.

Primary Containment consists of a steel pressure vessel enclosed in reinforced concrete, i.e., the Drywell, and a suppression chamber, a steel torus-shaped pressure vessel located below and encircling the Drywell, connected to it by vent pipes. The reinforced concrete is provided for shielding purposes and to provide additional resistance to deformation and buckling of the drywell over areas where the concrete backs up the steel shell. The design pressure is 56 psig coincident with a maximum temperature of 281 "F. The maximum external pressure is 2 psig above internal pressure.

L-MT-1 6-001 Page 5 of 64 withstand the pressures and temperatures(2 ) of the limiting DBA without exceeding the design leakage rate. The maximum allowable leakage rate (La) for the Primary Containment is 1.2 percent by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design basis LOCA maximum peak containment pressure (Pa) of 44.1 psig.

The drywell-to-wetwell vents are connected to a vent header contained within the airspace of the wetwell. Downcomer pipes project downwards from the vent header and terminate below the water surface of the suppression pool so that in the event of any pipe failure in the drywell, the released steam would pass directly to the water where it would be condensed. The vacuum relief system consists of eight vacuum breakers which equalize the pressure between the wetwell and the Drywell to prevent a backflow of water from the suppression pool into the vent system.

4.1.1 Drywell The drywell portion of the primary containment is a steel pressure vessel with a spherical lower portion and a cylindrical upper portion. It is enclosed in reinforced concrete for shielding purposes and to provide additional resistance to deformation and buckling of the drywell over areas where the concrete backs up the steel shell. Above the foundation transition zone, the drywell is separated from the reinforced concrete by a gap of approximately 2 inches for thermal expansion. Shielding over the top of the drywell is provided by a set of removable, reinforced concrete shield blocks.

In addition to the drywell head with its bolted manway and one double door personnel air lock, two hatches (one large equipment hatch and one control rod drive (CRD) hatch) are provided for access. The locking mechanism on each air lock door is designed so that a tight seal is maintained when the doors are subjected to either internal or external pressure. The air lock doors are mechanically interlocked to maintain primary containment integrity. The drywell airlock is tested by pressurizing the space between the inner and outer doors.

Individual drywell airlock door seal leakage tests cannot be performed. Since the inner door is designed to seat with containment pressure forcing the door closed, special bracing must be installed for each leakage test. The outer door must be opened to install and remove this bracing. The equipment hatch cover is bolted in place and sealed with a double tongue and groove seal. The CRD hatch is held in place by a yoke and clamp and is sealed with a double 0-Ring seal. The seals on the drywell access hatch covers are capable of being tested for leakage.

The top portion of the drywell vessel is removed during refueling operations.

The drywell head is held in place by bolts and is sealed with a double seal arrangement to provide primary containment integrity. The top head closure is made with a double tongue and groove seal that permits periodic checks for tightness without pressurizing the entire vessel.

L-MT-1 6-001 Page 6 of64 Eight large circular vent lines form a connection between the drywell and the pressure suppression chamber. Jet deflectors are provided in the drywell at the entrance of each vent line to prevent possible damage to the vent pipes from jet forces which might accompany a pipe break in the drywell. The vent lines are enclosed with sleeves and are provided with expansion joints to accommodate differential motion between the drywell and suppression chamber.

4.1.2 Suppression Chamber The suppression chamber is in the general form of a torus which is below and encircles the drywell. The suppression chamber is actually constructed of 16 mitered cylindrical shell segments. A reinforcing ring girder with two supporting columns and a saddle is provided at the miter joint of the adjoining shell segments.

The suppreSsion chamber is connected to the drywell by eight vent lines.

Within the suppression chamber, the vent lines are connected to a common vent header. Connected to the vent header are 48 pairs of downcomers which terminate below the water level of the suppression pool. The vent lines are shielded from jet impingement loads at each vent line - drywell penetration location by jet deflectors which span the openings of the vent lines. A bellows assembly connecting the suppression chamber to the vent line allows for differential movement between the drywell and the suppression chamber.

Eight vacuum breakers are provided to equalize the pressure between the suppression chamber and the drywell to prevent a backflow of water from the suppression pool into the vent header system. Each vacuum breaker is an 18 inch check valve with an air operator provided for testing purposes. There is one breaker located at each of the vent-to-vent header positions. The vacuum breakers are designed to be full open at 0.5 psid.

Access from the Reactor Building to the suppression chamber is provided through two manholes with double-gasketed, bolted covers, which are bolted closed when Primary Containment integrity is required. A test connection is provided between the double gaskets on each cover to allow leak rate testing of the Torus hatches.

4.1.3 Piping Penetrations Pipe penetrations are of two general types, i.e., those that must accommodate thermal movement (hot), and those that experience relatively little thermal movement (cold). The fluid piping penetrations for which movement provisions are made are the high temperature lines such~as the steam lines, the feedwater lines, and certain other reactor auxiliary and Cooling system lines. These penetrations have a guard pipe between the hot line and the penetration nozzle

L-MT-1 6-001 Page 7 of 64 in addition to a double-seal arrangement. This permits the penetration to be vented to the drywell should a rupture of the hot line occur within the penetration.

The guard pipes are designed to the same pressure and temperature as the fluid line and are attached to a penetration head fitting, a one-piece forging with integral flues or nozzles. The penetration sleeve is welded to the drywell and extends through the biological shield where it is welded to a bellows which in turn is welded to the guard pipe. The bellows accommodates the thermal expansion of the drywell. The MNGP has bellows with both single and two ply designs. A double bellows arrangement permits leak testing of the penetration seal. The lines are constrained to limit the movement of the line relative to the containment, yet permit pipe movement parallel to the penetration.

Small bore lines which connect to high-pressure systems, such as instrument lines and ORD hydraulic lines, do not have a double-seal penetration sleeve.

These lines are either bunched in groups of six lines and welded in a single pipe sleeve or shop welded in large groups directly to the drywell plate. The mechanical problems involved with this number of small penetrations in a relatively small area make it impractical to provide individual penetration sleeves.

The pipes are designed to deflect with the drywell shell.

All pipes that penetrate the primary containment are welded to a containment sleeve with the sleeve welded to the containment shell. There is no direct weldment of the pipe to the containment shell.

4.1.4 Electrical Penetrations Electrical penetration seals were designed to accommodate the electrical requirements of the plant. These are functionally grouped into low voltage power and control cable penetration assemblies, high voltage power cable penetration assemblies, and shielded cable penetration assemblies. All canister type electrical penetration seals have essentially the same basic configuration. The assemblies are sized to be inserted in penetration nozzles which are furnished as part of the containment structure.

4.1.5 Plant Operational Considerations Relating to Containment Leakage The MNGP is a BWR/3 with a Mark I containment. During power operation, the primary containment atmosphere is inerted with nitrogen to ensure that no external sources of oxygen are introduced into containment. The containment inerting system is used during the initial purging of the primary containment early in power operation and provides a supply of makeup nitrogen to maintain primary containment oxygen concentration within TS limits. As a result, the primary containment is maintained at a slightly positive pressure during power operation.

Primary containment pressure is monitored in the control room. In the event pressurization does not occur, a leakage path may be present. Plant operators are aware of the implications of lack of pressurization during power operation.

L-MT-1 6-001 Page 8 of64 Administrative controls and alarms have been established to monitor containment depressurization activities and evaluate trends (e.g., frequency, duration) for indication of changes to containment leakage.

4.1.6 Containment Heat Removal and Emergency Core Cooling System Net Positive Suction Head Performance On December 9, 2013, the NRC approved License Amendment No. 176 for the MNGP which increased the maximum licensed thermal power by approximately 13 percent, from the previous licensed thermal power of 1,775 MWt to 2,004 MWt (Reference 8). As part of EPU development the accidents and license basis events were re-evaluated. Net Positive Suction Head (NPSH) analyses were performed for the DBA-LOCA; and for the following four non-design basis events: Small Steam Line Break Accident (SBA), Appendix R Fire, Anticipated Transient Without Scram (ATWS), and Station Blackout (SBO).

For plants crediting containment accident pressure to maintain NPSH margin for emergency core cooling system (ECCS) pump performance, maintenance of containment integrity is required to meet the assumptions of the safety analyses.

Containment accident pressure (CAP)(3 ) was applied for the NPSH available (NPSHa) analysis for operation of the low-pressure Residual Heat Removal (RHR)( 4) and Core Spray (CS) pumps under EPU conditions in the MELLLA+ (5) domain. The current NRC staff guidance on use of CAP contained in to NRC SECY-1 1-00 14, "The Use of Containment Accident Pressure in Reactor Safety Analysis," (Reference 9) was applied in performance of the analyses. Section 2.6.5 of the NRC Safety Evaluation (SE) for the EPU entitled, "Containment Heat Removal," discusses in great detail how the criteria specified in the SECY regarding NPSH were satisfied.

NRC SECY 11-0014, Section 6.6.7, "Assurance of no Pre-existing Leak",

requires consideration of a loss of containment isolation that could compromise containment integrity, e.g., containment venting required by procedures or loss of containment isolation from a postulated 10 CFR 50 Appendix R fire. To apply the SECY's guidance it is required to determine the minimum containment leakage rate sufficient to lose the CAP needed for adequate NPSH margin. Second, a method to determine whether the actual containment leakage rate exceeds this leakage rate is required. For inerted containments, this method could consist of a periodic quantitative measurement of the nitrogen makeup performed at an appropriate frequency to ensure that no unusually large makeup of nitrogen o ccu rs.

3.

The previous DBA-LOCA licensing basis analysis also credited CAP in the determination of adequate NPSHa at the suction inlet of the RHR and CS pumps.

4.

The Low Pressure Coolant Injection (LPCI) mode for ECCS is provided by the RHR pumpls.

5.

MELLLA+ stands for Maximum Extended Load Line Limit Analysis - Plus, which is an operating domain on the power-flow map.

L-MT-1 6-001 Page 9 of 64 As stated in SE Section 2.6.5, for "on-line containment leakage monitoring, the licensee has proposed a procedure for detection of a large containment integrity failures where consideration of instrument uncertainty is not necessary." To provide assurance that a leak could be detected that could challenge containment integrity a methodology was developed and accepted consisting of (a) an on-line leakage test that determines the containment leakage rate during power operation, and (b) an on-line monitoring of the parameters on which the operator currently relies to determine abnormal containment leakage conditions.

Technical Requirements Manual (TRM) Specification 3.6.3.2, "Online Containment Leakage Check", was developed to perform an online (Mode 1) containment leakage test to determine the containment leakage rate during power operation. This leakage rate test is performed once-per-cycle, after an outage at the beginning of a new operating cycle when the plant is stabilized at full power. This online containment leakage rate test is a quantitative measurement of the nitrogen (N2) makeup while the N2 system is operated with a known vent release rate for eight hours. The test makes use of a computer point that calculates the N2 gas mass inside the inerted primary containment. This quantitative leak rate test provides a baseline that would identify any significant change in the containment leakage rate at any time during power operation. The test is repeated at any time during the cycle if inputs monitored during normal operation warrant another measurement.

The on-line containment leakage test has been performed twice since EPU approval as shown below. These results exhibit significant margin to the acceptance criteria of 5.0 scfm established for the on-line leakage test.

August 5, 2013 1.290 scfm July 15, 2015 1.376 scfm Additionally, there are several control room inputs used for normal monitoring that can indicate an increase in the containment leak rate between performance of the online containment leakage check TRM surveillance.

• A computer point that continually calculates N2 mass in containment and provides a computer alarm if the N2 mass is too low or too high.

A control room annunciator that alarms on drywell high or low pressure.

A flow indicator that measures N2 flow in the supply to the containment air system.

L-MT-1 6-001 Page 10 of 64 The NRC SE (Section 2.6.5) for EPU with respect to this subject stated:

The licensee justified the continuous monitoring to ensure CAP is available by stating that the drywell continuous air monitor detection capability is less than 5 scfm. The leakage rate that could challenge the NPSH margin for the ECCS and containment heat removal pumps is greater than 228 scfm which is well above the leakage that can be detected by the proposed procedure.

The NRC staff considers the licensee's method to detect loss of containment integrity during power operation acceptable because the proposed on-line test at the beginning of the cycle along with on-line monitoring of the above parameters will ensure the availability of CAP so that NPSH margin is available for the ECCS and containment heat removal pumps during design basis and non-design basis accidents.

To provide insight on the risk associated with reliance on containment accident pressure for proper low-pressure ECCS and containment heat removal pump performance during certain design basis and non-design basis accidents, a detailed sensitivity study was performed as part of the risk assessment. The study is similar to one discussed in Appendix F of the EPU risk assessment, included in the EPU license amendment request (LAR). RG 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis and defines very small changes in risk as resulting in increases of Core Damage Frequency (CDF) of less than 1.0E-06/year. Since the MNGP relies on containment accident pressure for ECCS NPSH during certain design basis accidents, extending the ILRT interval could impact CDF. The MNGP PRA model was used to estimate the potential change in CDF if containment accident pressure was unavailable due to a pre-existing containment leak. The containment accident pressure sensitivity study contained in Enclosure 2, Section 5.3.4 conservatively estimates that the potential increase in the overall CDF would be 9.83E-08, which is "very small" using the acceptance guidelines of RG 1.174.

4.2 Justification for the Proposed Technical Specification Change The following subsections provide a discussion of 10 CFR 50, Appendix J testing requirements, reviews the MNGP Primary Containment leakage licensing history and requirements, and reviews the MNGP ILRT test results.

4.2.1 Chronology:.of Testing Requirements of 10 CFR 50, Appendix J The testing requirements of 10 CFR 50, Appendix J, provide assurance that the leakage from the primary containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified within the TS. Also, 10 CFR 50, Appendix J also ensures that periodic surveillance of reactor containment penetrations and isolation valves is

L-MT-1 6-001 Page 11 of 64 performed so that proper maintenance and repairs are made during the service life of the containment and the systems and components penetrating primary containment. The limitation on containment leakage provides assurance that the containment would perform its design function following an accident up to and including the plant design basis accident.

10 CFR 50, Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the overall integrated leakage rate of the primary containment; 2) Type B tests, intended to detect leakage paths and measure leakage across pressure containing or leakage limiting boundaries (other than valves) for primary reactor containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Type B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing.

In 1995, 10 CFR 50, Appendix J, was amended to add another approach, Option B, entitled "Performance-Based Requirements", for performance of containment leakage testing. Option B requires the test intervals for Type A, Type B, and Type C testing to be determined using a performance-based approach. Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. Use of the term "performance-based" within 10 CFR 50, Appendix J refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B.

Also, in 1995, RG 1.163 was issued endorsing NEI 94-01, Revision 0, with certain modifications and additions. 10 CFR 50, Appendix J, Option B, in concert with the regulatory guide and the NEI guidance allows a licensee with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the ILRT test frequency from three tests in 10 years to one test in 10 years. This relaxation was based on an NRC risk assessment provided in N U REG-1 493, "Performance-Based Containment Leak-Test Program" (Reference 10) and Electric Power Research Institute (EPRI) topical report TR-1 04285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals (Reference 11) both of which showed that the increase in risk associated with extending the ILRT surveillance interval was very small.

In 2008, NEI 94-01, Revision 2-A, was issued. The NR.C indicated in the SE for NEI 94-01, Revision 2-A, that this report describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. Section 4.0 of the NRC SE for NEI 94-01, Revision 2-A, provides specific limitations and conditions for utilization of the report.

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

L-MT-1 6-001 Page 12 of 64 RG 1.163 (September 1995). It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification for increasing the duration of the interval included industry performance data, plant-specific performance data, and risk insights.

In Subsection 3.1.1.2, "Deferral of Tests Beyond The 15-Year Interval," of the NRC SE for the NEI 94-01, Revision 2-A. the NRC staff provided the following guidance concerning the use of test interval extensions (which was later augmented by additional guidance in Regulatory Issue Summary (RIS) 2008-27 (Reference 1 2)):(6)

..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 [topical report] NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRC staff that an unforeseen emergent condition exists.

In July 2012, NEI 94-01, Revision 3-A was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CER 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SEs dated June 25, 2008 (Reference 13) and June 8, 2012 (Reference 14) as an acceptable methodology for complying with the provisions of Option B to 10 CFR 50, Appendix J. The regulatory positions stated in RG 1.163 as modified by NRC SEs dated June 25, 2008 and June 8, 2012 are incorporated in this document. It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification of extending test intervals is based on the performance history and risk insights.

Extensions of Type B and Type C test intervals are allowed based upon completion of two consecutive periodic as-found tests where the results of each test are within a licensee's allowable administrative limits. Intervals may be increased from 30 months up to a maximum of 120 months for Type B tests (except for containment airlocks) and up to a maximum of 75 months for Type C tests. If a

6.

RIS 2008-27, "Staff Position on Extension of the Containment Type A Test Interval Beyond 15 Years Under Option B of Appendix J to 10 CFR Part 50."

L-MT-1 6-001 Page 13 of 64 licensee considers extended test intervals of greater than 60 months for Type B or Type C tested components, the review should include the additional considerations of as-found tests, schedule and review as described in NEI 94-01, Revision 3-A, Section 11.3.2.

MNGP has evaluated the extended Type C intervals afforded by NEI 94-01, Revision 3-A and has chosen not to adopt NEI 94-01, Revision 3-A at this time.

4.2.2 Current MNGP Integrated Leakage Rate Testing Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licensees to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements."

On April 3, 1996 the NRC approved License Amendment No. 95 for the MNGP (Reference 15) authorizing the implementation of Option B for Type A tests.

On February 4, 2003, the NRC approved License Amendment No. 132 for the MNGP (Reference 16) authorizing the implementation of Option B for Type B and Type C tests. Current Specification 5.5.11 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of 10 CFR 50, Appendix J, Option B.

RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01, Revision 0, rather than using the test intervals specified in ANSI/ANS 56.8-1994. NEI 94-01, Section 11.0 refers to Section 9, which states that 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. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0 La (where La iS the maximum allowable leakage rate at design pressure). The elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months.

Adoption of 10 CFR 50, Appendix J, Option B performance based containment leakage rate testing program altered the frequency of measuring primary containment leakage in the Type A, B and C tests but did not alter the basic method by which Appendix J leakage testing is performed. The test frequency is based on an evaluation of the leakage history to determine a frequency for leakage testing which provides assurance that leakage limits will not be exceeded.

L-MT-1 6-001 Page 14 of 64 The allowed frequency for Type A testing as documented in NEI 94-01, Revision 0, is based, in part, upon a generic evaluation documented in NUREG-1493. The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing types of containment types, including a containment design( 7 ) similar to the MNGP's containment structure. NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests from the original three tests per 10 years to one test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between performance of ILRTs is possible with a minimal impact on public risk.

4.2.3 MNGP 10 CFR 50, Appendix J, Option B Licensing History License Amendment No. 95 (April 3. 1996)

This amendment revised (1) the main steam line isolation valve (MSIV) leakage rate test acceptance criterion in the custom TS to be based upon the combined maximum flow path leakage for all four main steam lines of 46 standard-cubic-feet-per-hour (scfh) in lieu of the then current limit of 11.5 scfh per valve; (2) the operability test interval for the drywell spray header and nozzles from five to ten years; and (3) Specification 3/4.7.a.2, "Primary COntainment Integrity", to remove information specific to the primary containment leakage rate testing program and to adopt the requirements of 10 CFR 50, Appendix J, Option B, Section Ill.A, for Type A testing. Type B and C testing continued to be performed in accordance with 10 CFR 50, Appendix J, Option A.

License Amendment No. 132 (February 4, 2003)

Specification 3.7/4.7, "Containment Systems", in the custom TS was revised to permit use of 10 CFR 50, Appendix J, Option B, for Type B and Type C containment leak rate testing and added a new Specification 6.8.M, "Programs and Manuals - Primary Containment Leakage Rate Testing Program".

License Amendment No. 134 (March 31.,2003)

Surveillance Requirement 4.7.A.2.b, "Primary Containment Integrity", in the custom TS was revised to permit a one-time, five-year extension to the ten-year interval for performing a Type A containment ILRT (Reference 17). This allowed

7.

The Peach Bottom nuclear power plant is a BWR/3 plant with a Mark I containment design, the same as the MNGP.

L-MT-1 6-001 Enclosure I Page 15 of 64 the test to then be performed no later than 15 years from the date of the last ILRT, which had been performed in March 1993.

License Amendment No. 148 (December 7, 2006)

This amendment revised the MNGP licensing basis to incorporate a full-scope alternative source term (AST) methodology (Reference 18). Specification 5.5.11 was revised to exclude main steam line (MSL) pathway leakage contributions from the overall integrated leakage rate for Type A tests and to exclude MSL pathway leakage contributions from the sum of the leakage rates for Type B and Type C tests. Exemptions to Section lll.A and Section IlI.B of 10 CFR 50, Appendix J, Option B, were received in conjunction with approval of this license amendment (Reference 19). The MSL pathway includes the combined leakage through the eight MSIVs and through two primary containment isolation valves (PCIVs), which isolate the inboard MSIV drain lines, which is quantified by summing the leakage from Type C tests for these valves. This leakage is separate, and in addition to, the primary containment leakage limit of 1.2 percent per day, i.e., La, at a primary containment accident pressure.

License Amendment No. 176 (December 9, 2013)

The EPU license amendment increased the maximum licensed thermal power level by approximately 13 percent, from a previous level of 1,775 MWt to 2,004 MWt (Reference 8). The primary containment accident pressure specified in the TS increased from 42.0 psig to 44.1 psig.

License Amendment No. 187 (January 8, 2015)

This amendment removed a requirement for reduced pressure drywell airlock door seal testing, since this capability is not required and does not reflect the design of the airlock at MNGP. The acceptance criteria specified in Specification 5.5.11.d.2.b for testing between the airlock door seals were removed, and the drywell airlock door seals are tested solely by performance of an overall airlock leakage test as currently specified in Specification 5.5.11 l.d.2.a (Reference 20).

4.2.4 MNGP Integrated Leakage Rate Testing History As noted previously, Specification 5.5.11 currently requires that Type A, Type B, and Type C testing be performed in accordance with RG 1.163, which endorses the methodology for complying with Option B of 10 CFR 50, Appendix J. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing. The total Type A ILRT test history is provided in the following two tables. The first table provides the historical Type A test results from the time of initial licensing up to the May 1980 Type A test performance. In June 1984, the NRC approved the NSPM implementation of 10 CFR 50, Appendix J (Reference 21). The second table

L-MT-1 6-001 Page 16 of64 provides the last four performances of the Type A ILRT tests, after NRC approval of the 10 CFR 50, Appendix J Program for the MNGP.

Historical MNGP Type A ILRT Results Test ompltionDateLeakage Rate(4)

Test ompltionDate(weight-percent/day)

February 1968 0.0366 (Pre-Operationai)

July 1970 0.4370 May 1973 0.6406 May 1974(1) 0.2520 November 1975(2) 0.2456 November 1977 0.2488 March 1 980(3 May 1980 0.6324 (1) During the ILRT, leakage was observed from the vent port of the three-way solenoid valve that controls the air supply to the test operator for torus-to-drywell vacuum breaker "G". The leakage, at 41 psig, was found to be approximately 3.0 weight percent of the contained air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Following a torus entry, it was confirmed that the 3/8 inch air supply tubing for the test operator had been left uncapped when the "G" vacuum breaker had been removed for testing. It was not recognized that the air supply line and solenoid valve provided a leakage path.

(2) A defective Traversing Incore Probe ball valve on the number three line resulted in an initially measured leakage rate of approximately 1.5 weight-percent/day. The leaking valve was closed and the test satisfactorily completed.

(3) The March 1980 test was not accepted by the NRC and the test was successfully repeated in May 1980.

(4) All performances of the ILRT were performed at full test pressure, Pa, established as the licensing basis as of the date of performance.

The results of the last four Type A ILRTs for the MNGP are shown in the following table. The As-Found leakage for the four Type A test performances are well within the maximum allowable containment (As-Found) leakage rate specified in the TS of 1.2 weight-percent/day. Therefore, the requirement to demonstrate an acceptable performance history in order to place a plant on an extended interval in accordance with NEI 94-1, Revision 2-A, (i.e.,,successful completion of two consecutive periodic Type A tests) has been consecutively met over the last several ILRT test intervals. As a result, the MNGP is eligible to be

L-MT-1 6-001 Page 17 of 64 placed on an extended ILRT frequency (performance of a Type A test at least once per 15 years). The current ILRT interval frequency for the MNGP is once per 10 years.

MNGP Type A ILRT Results As-Found As-Left Test (weight-percent/da)

(weight-percent/day)

Completion Date~1 )

Leakage TS Acceptance Leakage TS Acceptance Rate Criteria Rate Criteria December 1984 0.7222,1.2 0.5484 0.9 October 1989 0.6183 1.2 0.5354 0.9 March 1993 0.8240 1.2 0.3943 0.9 April 2007 0.7323 1.2 0.6484 0.9 (1) All performances of the ILRT were performed at full test pressure, Pa, established as the licensing basis as of the date of performance.

4.3 Plant Specific Confirmatory Analysis 4.3.1 Methodology An evaluation has been performed to provide a risk assessment of permanently extending the currently allowed containment Type A ILRT from 10 to 15 years.

The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages for the MNGP. The risk assessment followed the guidelines from the following:

NEI 94-01 Revision 2-A,

• Methodology of EPRI TR-1 04285, NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" October 2001 (Reference 22),

NRC regulatory guidance on use of PRA as stated in RG 1.200 as applied to ILRT interval extensions,

• Risk insights in support of a request for a plant licensing basis change as "outlined in RG 1.174, Methodology applied by Calvert Cliffs to estimate likelihood and risk implications of corrosion-induced leakage of the steel liners going undetected during the extended test interval (from Reference 23),

Methodology applied in EPRI TR-1018243 (Reference 24), Revision 2-A of EPRI TR-1 009325 (Reference 25).

L-MT-1 6-001 Page 18 of 64 NEI 94-01, Revision 2-A includes a SE that supports using EPRI TR-1 009325, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals",

Revision 2-A for performing risk impact assessments in support of ILRT extensions. Appendix H, "Risk Impact Assessment Template," within this report illustrates the types of information that should be included in a plant-specific confirmation of risk impact associated with the extension of ILRT intervals. The methodology within this EPRI report builds on previous work performed in EPRI TR-1 04285 and NUREG-1493. This methodology was followed to determine the appropriate risk information for use in evaluating the impact of the proposed ILRT changes.

The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from containment leak rate testing. In that analysis, it was determined for a representative BWR plant (i.e., Peach Bottom), that increasing the containment leak rate from the nominal 0.5 percent per day to 5 percent per day leads to a barely perceptible increase in total population exposure, and increasing the leak rate to 50 percent per day increases the total population exposure by less than 1 percent. In fact, NUREG-1 493 states, "Reducing the frequency of Type A tests (ILRTs) from the current three per 10 years to one per 20 years was found to lead to imperceptible increase in risk." Therefore, it is desirable to show for the MNGP that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures to support a reduction in the test frequency for MNGP.

Since the publication of NUREG-1493, additional containment inspections are now performed at all nuclear power plants (ASME Code Section Xl Subsections IWE and IWL( 8)), and historical integrated and local leak rate testing performance has been good. Using newer methods and additional data, EPRI TR-1 009325 demonstrated that the conclusions of NUREG-1493 remain valid.

EPRI TR-1 009325, Revision 2, was determined acceptable for referencing by licensees proposing to amend their TS to extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the SE.

The following table addresses each of the four limitations and conditions for use of the EPRI topical report.

8.

ASME Section XI, Subsection IWE, "Requirements for Class MC and Metallic Liners of

'"Class CC Components of Light-Water Cooled Plants and Subsection IWL," and "Requirements for Class CC Concrete Components of Light-Water Cooled Plants,"

respectively.

L-MT-1 6-001 Page 19 of 64 EPRI Topical Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition (From Section 4.2 of SE)

MNGP Response 1.The licensee submits documentation MNGP PRA technical adequacy is addressed in indicating that the technical adequacy Section 4.3.2 of this LAR and Enclosure 2, of their PRA is consistent with the "Monticello Nuclear Generating Station:

requirements of RG 1.200 relevant to Evaluation of Risk Significance of Permanent the ILRT extension application.

ILRT Extension," Appendix A, "PRA Technical Adequacy."

2.a The licensee submits documentation RG 1.174 defines very small changes in risk indicating that the estimated risk as resulting in increases of CDF less than increase associated with permanently 1.0E-06/year and increases in LERF less than extending the ILRT surveillance 1.0E-07/year. Since the MNGP relies on interval to 15 years is small, and containment accident pressure for ECCS NPSH consistent with the clarification during certain design basis accidents, provided in Section 3.2.4.5 of this SE.

extending the ILRT interval may impact CDF.

The MNGP PRA model was used to estimate the potential change in CDF if CAP was unavailable due to a pre-existing containment leak. The CAP sensitivity study performed in, Section 5.3.4 conservatively estimates that the potential increase in the overall ODE would be 9.83E-08, which is "very small" using the acceptance guidelines of RG 1.174. The increase in LERF resulting from a change in the Type A ILRT test interval from three in 10 years to one in 15 years is estimated as 6.51 E-08/year using the EPRI guidance (this value increases negligibly if the risk impact of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is included).

As such, the estimated change in LERF is determined to be "very small" using the acceptance guidelines of RG 1.174.

L-MT-1 6-001 Page 20 of 64 EPRI Topical Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition (From Section 4.2 of SEI MNGP Resoonse f

I......

2.b 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.

The effect resulting from changing the Type A test frequency to once per 15 years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 0.064 person-rem/year.

EPRI TR-1 009325, Revision 2-A states that a very small population dose is defined as an increase of less than or equal to 1.0 person-rem per year, or less than or equal to 1 percent of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria. The increase in total integrated plant risk of 0.064 person-rem/year is much less than the 1.0 person-rem per criteria defined as a small increase in population dose. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible.

2.c in addition, a small increase in The increase in the CCFP from the three in

[Conditional Containment Failure 10 year interval to one in 15 year interval is Probability] CCFP should be defined 0.812 percent. EPRI TR-1 009325, Revision as a value marginallygreater than that 2-A states that increases in CCFP of less than accepted in previous one-time 15-year or equal to 1.5 percent is very small.

ILRT extension requests. This would require that the increase in CCFP be less than or equal to 1.5 percentage point.

3.

The methodology in EPRI Topical The representative containment leakage for Report No. 1009325, Revision 2, is Class 3b sequences used by MNGP is 100 La, acceptable except for the calculation of based on the recommendations in the latest the increase in expected population EPRI report and as recommended in the NRC dose (per year of reactor operation). In SE on this topic. It should be noted that this is order to make the methodology more conservative than the earlier previous acceptable, the average leak rate industry ILRT extension requests, which utilized accident case (accident case 3b) used 35 La for the Class 3b sequences.

by the licensees shall be 100 La instead of 35 La.

L-MT-1 6-001 Page 21 of 64 EPRI ToPical Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition (From Section 4.2 of SE)

MNGP Response

4.

A licensee amendment request LAR is Containment overpressure is required for required in instances where ECCS performance and was re-approved for containment over-pressure is relied use in License Amendment No. 176 for the upon for ECCS performance.

MNGP EPU on December 9, 2013. Subsection 4.1.6 of this enclosure summarizes the current licensing basis for application of containment accident pressure under EPU. This is discussed in Subsection 4.3.3 as part of the summary of plant-specific results via reference to a sensitivity study conducted as part of the risk-assessment (see Enclosure 2).

4.3.2 Technical Adequacy of the MNGP Probabilistic Risk Assessment a) Internal Events PRA Quality Statement for Permanent 15-Year ILRT Extension The MNGP internal events PRA model (Revision 3.2) was used to calculate the CDF and the LERE for the proposed permanent 15-year ILRT extension.

Any elements of the supporting requirements detailed in ASME/ANS RA-Sa-2009 that could be significantly affected by the application are required to meet Capability Category II requirements.

The internal events PRA provides an adequate base model for the development of the permanent 15-year ILRT extension. The MNGP PRA Peer Review was performed in April 2013 applying the NEI 05-04, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," process, the ASME PRA Standard (ASME/ANS RA-Sa-2009) and RG 1.200, Revision 2. The purpose of this review was to provide a method for establishing the technical adequacy of the PRA for the spectrum of potential risk-informed plant licensing applications for which the PRA may be used. The 2013 MNGP PRA Peer Review was a full-scope review of the Technical Elements of the internal events and internal flood, at-power PRA.

The ASME PRA Standard has 325 individual Supporting Requirements (SRs) for the Internal Events At-Power PRA (Part 2), and Internal Flood At-Power PRA (Part 3). The MNGP Peer Review included all of these SRs. Twelve of the SRs were judged to be not applicable. Of the remaining 313 ASME PRA Standard SRs, 93 percent are supportive of Capability Category II or greater.

L-MT-1 6-001 Enclosure I Page 22 of 64 to this LAR, Appendix A, Section A.3 presents an assessment of all ASME/ANS PRA Standard RA-Sa-2009 SRs that were assessed to be "Not Met" at Capability Category II in the 2013 MNGP PRA Peer Review or were assessed to be "Met" but had related Findings. Findings and Observations (F&Os) from the 2013 MNGP PRA Peer Review have been resolved. Therefore, the MNGP Internal Events PRA was judged to meet Capability Category II consistent with RG 1.200 guidance.

b) Fire PRA Quality Statement for Permanent 15-Year ILRT Extension The MNGP Fire Probabilistic Risk Assessment (FPRA) Peer Review was performed March 2-6, 2015, applying the NEI 07-12, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines," process, the ASME PRA Standard (ASME/ANS RA-Sa-2009) and RG 1.200, Revision 2. The purpose of this review was to establish the technical adequacy of the FPRA for the spectrum of potential risk-informed plant licensing applications for which the FPRA may be used. The 2015 MNGP FPRA Peer Review was a full-scope review of all of the Technical Elements of the MNGP at-power January 2015, Revision Ia, Fire PRA against all Technical Elements in Section 4 of the ASME/ANS Combined PRA Standard, including the referenced internal events SRs in Section 2.

The FPRA Peer Review team consisted of six team members, with extensive qualifications in all areas of FPRA as required by NEI 07-12 and one working observer. The team members experience averaged over 20 years in PRA or Fire Protection, with extensive experience in FPRA, the FPRA Section of the Standard, and NUREG/CR-6850, "EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities" (Reference 26).

The Fire PRA Section of the ASME PRA Standard has 182 individual SRs, and references 237 individual SRs in the internal events PRA section of the Standard; the MNGP Peer Review included all of the SRs and all applicable reference SRs. For the assessment of the reviewed ASME PRA Standard SRs, 102 unique Facts and Observations (F&Os) have been generated by the Peer Review team, 73 were peer review Findings, 28 were Suggestions, and one was considered a best practice. Enclosure 2 to this LAR, Appendix A, Section A.4, presents the Findings and their resolutions. There were no "Unreviewed Analysis Methods" identified during the review.

Therefore, the technical adequacy of the FPRA with respect to applying it to extend the IL-RT test frequency on a permanent basis to fifteen years has been determined to be acceptable.

L-MT-1 16-001 Page 23 of 64 4.3.3 Summary of Plant-Specific Risk Assessment Results The findings of the MNGP Risk Assessment contained in Enclosure 2 confirm the general findings of previous studies that the risk impact associated with extending the ILRT interval from three in ten years to one in fifteen years is very small. The MNGP plant-specific results for extending JLRT interval from the current ten years to fifteen years are summarized below:

Based on the results from Enclosure 2, Section 7.0, "Conclusions," and the sensitivity calculations presented in Enclosure 2, Section 5.3 "Sensitivities", the following conclusions regarding the assessment of the plant risk associated with permanently extending the Type A ILRT test frequency to fifteen years are as follows:

• RG 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of ODE of less than I1.0E-06/year. Since the MNGP relies on containment accident pressure (CAP) for EGOS NPSH during certain design basis accidents, extending the ILRT interval may impact ODE. The MNGP PRA model was used to estimate the potential change in CDF if CAP was unavailable due to a pre-existing containment leak. The CAP sensitivity study performed in, Section 5.3.4 conservatively estimates that the potential increase in the overall ODE would be 9.83E-08, which is very small using the acceptance guidelines of RG 1.174.

• RG 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of LERF of less than 1.0E-07/year. The increase in LERF resulting from a change in the Type A ILRT test interval from three in 10 years to one in 15 years is estimated as 6.51 E-08/year using the EPRI guidance (this value increases negligibly if the risk impact of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is included).

As such, the estimated change in LERF is determined to be very small using the acceptance guidelines of RG 1.174.

• The effect resulting from changing the Type A test frequency to once per 15 years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 0.064 person-rem/year.

EPRI TR-1 009325, Revision 2-A states that a very small population dose is defined as an increase of less than or equal to 1.0 person-rem per year, or less than or equal to 1 percent of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible.

L-MT-1 6-001 Enclosure I Page 24 of 64

• The increase in the conditional containment failure probability from three in a 10-year interval to one in a 15-year interval is 0.812 percent. EPRI TR-009325, Revision 2-A states that increases in CCFP of less than or equal to 1.5 percent is "very small". Therefore, this increase is judged to be "very small."

Therefore, increasing the ILRT interval from 10 years to 15 years is considered to be insignificant since it represents a "very small" change to the MNGP risk profile.

4.3.4 Previous Assessments The NRC in NUREG-1 493 has previously concluded that:

• Reducing the frequency of Type A tests (ILRTs) from three per 10 years to one per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.

• Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage-rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond one in 20 years has not been evaluated. Beyond testing the performance of containment penetrations, ILRTs also test the integrity of the containment structure.(9 )

The findings for MNGP confirm these general findings on a plant-specific basis considering the severe accidents evaluated, the containment failure modes, and the local population surrounding the MNGP.

Details of the MNGP risk assessment are contained in Enclosure 2 of this submittal.

4.4 Non-Risk Based Assessment Consistent with the defense-in-depth philosophy discussed in RG 1.174, the NSPM has assessed other non-risk based considerations relevant to the proposed amendment.

There are multiple inspections and testing programs at the MNGP that ensure the containment structure remains capable of meeting its design functions and that are designed to identify any degrading conditions that might affect that capability. These programs are discussed below.

9.

Type A tests serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing.

L-MT-1 6-001 Page 25 of 64 4.4.1 Containment lnservice Inspection Plan (IWE Plan)

On August 8, 1996, the NRC revised 10 CFR 50.55a, "Codes and Standards" to incorporate Subsections IWE and IWL( 1°) of Section XI of the ASME Code into the regulation by reference, as modified and supplemented by the provisions of 10 CFR 50.55a, for the inservice inspection, repair, and replacement of containment components.( 11 )

Subsection IWL (Concrete Containments) is NOT applicable to the MNGP.

Subsection IWE (Metal Containments) is applicable to the MNGP. The program addressing Subsection IWE is referred to as the Containment Inservice Inspection (CISI) Plan (IWE Plan). The First Interval, First Period IWE Plan examinations were performed during a five-year expedited implementation period and served as the "preservice examination" or baseline inspection. The second Subsection IWE inspection interval began September 9, 2009, and is scheduled to end September 8, 2018. The Second Interval IWE Plan is based on ASME Section XI, Subsection IWE, 2001 Edition with the 2003 Addenda as supplemented by the specific requirements set forth in 10 CFR 50.55a.

Other MNGP programs (listed below) interface with, and/or are used in conjunction with the IWE Plan to satisfy the requirements of Section Xl of the ASME Code and 10 CFR 50.55a.

• MNGP 10 CFR 50, Appendix J Primary Containment Leakage Rate Testing Program MNGP Inservice Inspection (ISI) Program MNGP ASME Section Xl Repair/Replacement (RIR) Program MNGP Nuclear Coatings Program The ASME XI Subsection IWE Examination Schedule for the First, Second, and as projected for the Third Interval is provided in the following table.

10.

ASME Section XI, Subsection IWE, "Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants and Subsection IWL," and "Requirements for Class CC Concrete Components of Light-Water Cooled Plants,"

respectively.

11.

Federal Register, Volume 61, No.154, Rules and Regulations page 41303, dated August 8, 1996 (effective September 9, 1996)." Specifically, Subsections IWE and IWL of the 1992 Edition of Section Xl of the ASME Code (with 1992 Addenda) were incorporated.

L-MT-1 6-001 Page 26 of 64 MNGP IWE Examination Schedule First Interval 1st Period(1) 9/9/1 998 through 9/8/2001 1R18 1998 1R19 2000 9/9/2001 through 9/8/2005 2nd Period 1 R20 2001 1R21 2003 1R22 2005 3rd Period(2 )

9/9/2005 through 9/8/2009 1R23 2007 1R24I 2009 Second Interval 1st Period( 3) 9/9/2009 through 9/8/2011 1R25 2011 9/9/2011 through 9/8/2015 2nd Period R621 1R26 2015 3rd Priod9/9/2015 through 9/8/2018 1 R28 2017 Third Interval 9/9/18 through 9/8/2021 lteod1 R29 2019 1R30 2021 9/9/202 1 through 9/8/2025 2nd Period1R123 1 R32 2025 3rd Priod9/9/2025 through 9/8/2028 1 R33 2027 (1) Period was extended earlier to April 2, 1998, as permitted in IWE-241 2(b) to allow the First Interval, 1st Period IWE examinations to coincide with the Cycle 18 RFO.

(2) As permitted by IWA-2430(d), the First Interval of the IWE Program was extended for one year. The interval extension was applicable through September 8, 2009.

(3) 1st Period of Second Interval was reduced by one year due to the one year used for the First Interval IWA-2430(d) extension.

L-MT-1 6-001 Page 27 of 64 Inaccessible Areas The MNGP was built prior to the implementation of the ASME Section XI examination accessibility requirements of IWA-1 500 and IWE-1 230 as recognized in 10 CFR 50.55a(g)(1). As a result, some containment components may not be fully accessible, or are inaccessible for examination.

As required by 10 CER 50.55a(b)(2)(ix)(A)(1), when conditions exist in Class MC accessible areas that could indicate the presence of, or result in degradation to Class MC inaccessible areas, the inaccessible areas must be evaluated for acceptability. No degraded or potentially degraded conditions have been identified or reported for inaccessible Class MC areas as a result of examinations for the CISI Plan.

NSPM has not needed to implement any new technologies to perform inspections of any inaccessible areas at the MNGP at this time. NSPM actively participates in various nuclear utility owners groups and on ASME Code committees to maintain cognizance of ongoing developments within the nuclear industry. Industry operating experience is also continuously reviewed to determine its applicability to the MNGP. Adjustments to inspection plans and adoption of new, commercially available technologies for examination of inaccessible areas of the containment would be explored and considered as part of these activities as they become available.

Class MC Component Examination Requirement Details The ASME Code Class MC boundaries subject to examination and testing are the containment structure and connecting penetrations, appurtenances and parts which form the Primary Containment leak-tight boundary. These are the:

• Drywell Shell

• Personnel Air Lock

• Drywell Head Assembly

• Equipment Access Hatch Drywell Vent System

• Control Rod Drive Hatch

• Drywell Head Access Hatch Bolted Connections

• Suppression Pool (Torus)

• Penetration Sleeves

• Suppression Pool Access Penetration Sleeves of Hatches Electrical Penetrations

• Moisture Barrier

• Class MC Component Supports(1)

(1) The Class MC Component Supports are examined under the ISI Program in accordance with ASME Section Xl, Subsection IWE.

L-MT-1 6-001 Enclosure I Page 28 of 64 Examinations include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, including pressure retaining bolting, wetted surfaces of submerged areas, the BWR vent system and the moisture barrier.

Examinations of Class MC components are performed using General Visual, Detailed Visual (VT-I), VT-I and VT-3 methods as applicable.

Containment Examination Containment VT-I and VT-3 examinations are performed by qualified and certified personnel using procedures written to the 2001 Edition with the 2003 Addenda of the Code and ASNT-CP-1 89, 1995 Edition. General Visual examination method requirements are found in IWE-2310, and as specified in 10 CFR 50.55a.

General Visual examination includes 100 percent of the accessible surface areas during each Inservice Inspection Period and requirements as modified by 10 CER 50.55a.

• General Visual (VT-3) examination of 100 percent of wetted surfaces of submerged areas is performed each interval.

• General Visual (VT-3) examination of 100 percent of BWR vent system accessible surface areas is performed each interval.

• General Visual examination to include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-to-metal interfaces which are not seal welded. Containment moisture barrier materials include caulking, flashing and other sealants used for this application. Also, 100 percent examination is required during each Inspection Period. Examination is performed to identify tears, cracks, or damage that permits moisture intrusion.

General Visual examination performed each period for El1.11 includes pressure retaining bolted connections. Once each interval, the pressure retaining bolted connections require examination using VT-3. Upon disassembly VT-3 examination is required.

L-MT-1 6-001 Enclosure I Page 29 of 64 2nd IWE Interval - Examination. Category E-A Component Area 1Examination Item Exam Period

_________________________________________________ Description Number Method Scheduled Examination Category E-A 1:

2 Drywell (DW), Torus, Vent Lines Accessible E1.11 GV X

X X

Bolting: VT-3 once each Interval Surface Areas VT-3 X

• VT3 if disassembled VT-3

• • VT-1 for flaws or VT-I degradation Torus, Downcomers Wetted E1.12 "GV (VT-3)

X Surfaces of Submerged Areas Vent Lines, Vent Header, BWR Vent El1.20 GV (VT-3)

X Downcomers System Accessible Surfaces Drywell Moisture E1.30 GV X

X X

Barrier Item Number As listed in ASME Code Section XI, Table IWE-2500-1, Category E-A Exam Method GV: General Visual GV (VT-3): VT-3 in lieu of General Visual for Items E1.12 and E1.20 (10 CFR 50.55a(b)(2)(ix)(G))

VT-3: in accordance with ASME Section XI, paragraph IWA-2200 (10 CFR 50.55a(b)(2)(ix)(F), (G), (H))

VT-I: in accordance with ASME Section Xl, paragraph IWA-2200 (10 CFR 50.55a(b)(2)(ix)(F), (G), (H))

Aucimented Inspections Containment surface areas that require successive, augmented examinations to monitor for changes of their condition are those evaluated as acceptable standards and were not corrected by repair/replacement or corrective measures.

Successive examinations have been performed, and many of the locations have shown no changes to the original condition, or components have had their

L-MT-1 6-001 Page 30 of 64 coatings repaired. Components that have not changed, or components where flaws or areas of degradation were corrected by repair/replacement or corrective measures do not require the successive augmented examinations of Table IWE-2500-1, Category E-C.

The ASME Code also has provisions to use ultrasonic thickness (UT) measurements on a gridded surface when an area requiring augmented examination is not accessible for visual examination. There are currently no components subject to this requirement.

Interval 2, Period 2 augmented examinations (Category E-C, Item 4.11), located on submerged areas of the torus shell and vent system downcomers, were completed in the 2013 RFO. During the 2013 inspections instances of change from the prior inspection were noted. Instances of additional degraded coatings, as well as rusting, pinpoint rusting, and bare substrate were reported. Interval 2, Period 3 examinations will occur during the 2017 RFO.

2nd IWE Interval - Examination Category E-C Component Area 1Examination Item Exam Period Description Number Method Scheduled Examination Category E-C1 2

3 Drywell, Vent System Visible Surface E4.11 DV (VT-I)

X Torus Vapor Phase / Vent Visible Surface E4.11I DV (VT-I)

X System Torus Below Waterline Visible Surface E4.11 DV (VT-I)

X X

X Torus, Vent System Visible Surface E4.11I DV (VT-I)

X X

X Downcomers Drywell, X-1 Bolting Visible Surface E4.1l DV (VT-I)

X N/A Surface Area E4.12 UTT Grid Minimum Wall Thickness Location Item Number As listed in ASME Code Section XI, Table IWE-250(0-1, Category E-C Exam Method DV (VT-I): VT-I performed in lieu of Detail Visual for Item E4.11I (10 CFR 50.55a(b)(2)(ix)(G))

VT-I" in accordance with ASME Section Xl, paragraph IWA-2200 (10 CFR 50.55a(b)(2)(ix)(F), (G), (H))

L-MT-1 6-001 Page 31 of 64 UTT: Ultrasonic Thickness Test in accordance with ASME Section V, T-544 Pressure Testinq Requirements If repair/replacement activities of ASME Section Xl, Subsection IWA-4000 become necessary on Class MC components, as authorized by the Fifth Interval 131 Plan Relief Request RR-007 (Reference 27), post repair/replacement pressure test requirements for components and parts of the pressure retaining boundary shall comply with the requirements of the 2007 Edition including the 2008 Addenda of ASME Section Xl, Subsection IWE-5000, as well as all applicable conditions in 10 CFR 50.55a for post-repair/replacement pressure testing of Class MC components.

Personnel performing post repair/replacement pressure testing required by IWE-5000, Appendix J leak rate tests, are qualified in accordance with the MNGP Primary Containment Leakage Rate Testing Program.

10 CFR 50.55a Requests There were no 10 CFR 50.55a requests required for the Second Interval, Containment ISI Plan (IWE Plan). However, 10 CFR 50.55a request RR-007 for the Fifth Interval ISI Plan authorizes use of the 2007 Edition of ASME Section Xl with the 2008 Addenda for repair/replacement activities on Class MC components, including the post repair/replacement pressure testing requirements of IWE-5000.

Significant Containment Inspection Related Historical Summary These inspections, repairs and modifications occurred prior to the official implementation of the MNGP IWE Plan, but provided a baseline containment condition. The following discussion illustrates some of the actions NSPM has taken to ensure that uninspectable areas of containment have retained their integrity and are not in a degraded state that would allow leakage through the containment boundary.

a) Plant Life Extension Proqram Testingq Prior to implementation of the IWE Plan, activities relating to plant life extension were undertaken. As part of this, Drywell shell ultrasonic wall thickness measurements were taken as part of the Plant Life Extension (PLEX) Program in 1986 and 1987. Concrete was removed at the concrete-to-shell interface at the 920'-6" elevation for UT measurements. The location corresponds to the exterior sand pocket region. The results of the Drywell shell thickness measurements ranged from 1.072 to 1.107 inch. The minimum design thickness for this Drywell shell area is 1.0 inch. Some minor interior corrosion was detected at the interface of the concrete floor and the

L-MT-1 6-001 Page 32 of 64 Drywell shell. The minor corrosion was cleaned and removed. No thinning of the exterior portion of the Drywell shell was detected.

b) Sand Pocket Examination Following the Oyster Creek Nuclear Station event (see Subsection 4.5.1 -

GL 87-05) the outlets for the sand pocket drains and the air gap drains were inspected at the MNGP. One sand pocket drain was found to be partially obstructed by deposits of calcium carbonate in the standpipe region of the drain line. The partial obstruction was attributed to be from the drying of the sand pocket during construction and not from leakage during operation. All other drain lines were unobstructed. Additional qualitative testing determined that the Drywell air gap drain lines from inlet to outlet were unobstructed using compressed air to establish a flow through each drain line. To ensure the drain line outlets are not obstructed, the plant procedure for filling the reactor well includes a prerequisite to inspect the sand pocket and the air gap drain outlets prior to flooding the refueling area.

MNGP operating history has shown no evidence of refueling seal leakage, and no water was observed in the air gap during construction. Plant engineering and maintenance personnel confirmed the absence of leakage at the Drywell air gap drains and the sand pocket drains. The ongoing IWE inspection and monitoring activities, and the plant features that monitor for leaks past the refueling bellows during refueling (i.e., local light indicator and Control Room panel alarm), adequately manage aging effects to ensure no loss of intended function.

c) 1996 RFO During this outage, the Drywell moisture barrier was repaired. In anticipation of implementing the new ASME Section XI IWE requirements, spot thickness UT readings were taken at approximately seven locations along the floor to wall interface (concrete to metal) of the interior circumference of the Drywell after defective areas of the moisture barrier were removed. In each area two readings were taken, one in the area of the corrosion and one right above it approximately 3 inches out of the corrosion zone (to provide a baseline as to the non-corroded metal thickness). Results showed that the most severe wall loss was only 0.057 inches. In several areas the difference between the reading taken on the corroded surface versus and the non-corroded surface varied only slightly and some did: not vary at all.

L-MT-1 6-001 Page 33 of 64 d) 1997 Maintenance (ECCS Suction Strainer Installation) Outag~e The ECCS suction strainer modification outage started on May 9, 1997, and was completed on July 31, 1997. Also, the drywell shell-to-basemat moisture barrier was replaced and pre-service IWE examinations were performed on the new barrier.

Current Containment ISI Performance In the period of time since the ASME Section Xl IWE Program for inservice inspection of the MNGP metal containment was implemented, there have been no substantial indications of degradation that would impact the structural integrity of Primary Containment.

Many of the "indications" noted during inspections early on were related to coatings issues that didn't impact the metal substrate, for example scrapes, flaking, peeling, chipping, discoloration, etc. However, there were other areas of reported surface corrosion and rusting, including a few instances where minor pitting was identified. When arc strikes have been identified, they were either removed and the area was examined, or they were determined to be superficial, examined, and left as-is.

Areas of degraded coatings with related corrosion-like indications, such as rust staining and surface rust have been reported in the high humidity or wetted areas on the internal surfaces of the suppression chamber (torus) and the portion of the vent system downcomers near or below the waterline. The downcomers have indications resulting from past welded modifications that still have degraded coatings with minor surface rust and adjacent rust staining as a result.

Indications are evaluated each outage, including minor pitting, and have been determined to be acceptable. No conditions indicative of degradation or potential degradation in inaccessible areas have been identified.

Numerous areas with degraded coatings have been recoated to eliminate the conditions that led to initial reporting under the IWE Program, including extensive coating repairs to the torus shell interior while drained in the 2007 RFO, and additional underwater coating repairs made during the 2013 REQ.

The most recent IWE examinations were performed during the 2013 REQ in accordance with the requirements of Table IWE-2500-1, Categories E-A and E-C for Period 2 of the 2nd IWE Interval. No new [WE indications were noted during REQ 26 as a result of coating inspections and General Visual inspections in the drywell, vent system (above the waterline) and torus (above the waterline);

however, there were some new or changed areas of coating degradation identified in the torus and vent system (downcomers) below the waterline with

L-MT-1 6-001 Page 34 of 64 nine areas of noted interest for IWE: rust with minor pitting was reported on seven components (e.g., shell plate) of the torus shell, a legacy arc strike and a random weld bead were identified during surface preparation for underwater coating repairs. A summary of the conditions identified are described below.

a) Drywell General Visual examination was performed of accessible interior Drywell for structural problems and for compliance with ASME Section Xl, Subsection IWE code requirements. No issues were identified. VT-3 examinations were performed on the disassembled bolted connections for the Drywell Equipment Hatch, the Control Rod Drive Hatch and the Drywell Head Manway. All connections were satisfactory.

The drywell basemat-to-shell moisture barrier was examined and is in good condition with no evidence of deterioration.

Corrosion on the Drywell, as in previous outages, was negligible.

b) Torus General Visual, VT-3, and VT-I exams were performed, as applicable, on the Torus interior above and below the waterline.

Areas on the torus shell components examined under Category E-C, Item E4.11I showed no changes from their previous examination, and, per IWE-2420(c), no longer require augmented examination.

For other areas examined for Category E-A, new indications on the torus shell were noted during this outage that will require re-inspection in the next IWE inspection period in accordance with IWE-2420(b). The examiners identified new or changed areas of bare metal, some with magnetite or light surface rust, and also new or changed amounts of degraded coatings with pinpoint rust. Bare metal areas of the torus had tightly adherent magnetite films or light surface rust.

These films are of negligible thickness (small fractions of a mil). Tightly adherent magnetite films limit the formation of additional corrosion product. Given that corrosion product thickness is a multiple of the corroded substance, only a negligible quantity of steel is lost in the formation of these films.

Areas of minor pitting were reported on seven torus shell components (e.g., shell plates). The deepest measured pit noted during the RFO 26 inspection on the underwater portion of the torus shell was substantially below the pit depth limit.

The shallow depth of pits and the presence of thin oxide films indicates that pitting and general corrosion in the low oxygen-pure water environment of the MNGP torus is proceeding at a very slow rate. Each of these noted areas were acceptable and were marked for coating repair.

L-MT-1 6-001 Enclosure I Page 35 of 64 During coating repair activities, workers identified a legacy arc strike and a random weld bead on the torus shell. Surface preparation was performed, the areas were re-examined with VT-I, and no remaining unacceptable conditions were found. Each of these noted areas were acceptable and were marked for coating repair.

c) Vent System Detailed Visual (VT-I) examination was performed on downcomers below the water line for Category E-C, Item E4.11I due to degraded coatings and substrate conditions identified during previous outages. The majority of previous indications on the downcomers had no change noted from the previous exam.

However, new or changed indications of degraded coatings, larger areas of rust, and new bare substrate were noted on some of the downcomers. Based on visual inspection of the downcomers, none of the indications were severe enough to require pit depth measurement. Corrosion in the vent system, as in previous outages, was negligible. The downcomers will continue to be examined, as required under Category E-C, Item E4.1 1.

4.4.2 Nuclear Coatings Program The MNGP Nuclear Coatings Program(1 2 ) assures that safety-related DBA qualified coating systems (Service Level 1) are properly selected, applied, monitored and maintained so the coatings can perform their intended function*

Degraded coatings are controlled and tracked to ensure that the ECCS performance will not be adversely affected by the coating debris following an accident. The Engineering organization reviews and evaluates the results of coating condition examinations performed by qualified examiners. This program addresses the concerns of NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling System [ECCS] and the Containment Spray System After a Loss-of-Coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment" (Reference 28).

NSPM does not credit the program for the prevention of corrosion of carbon steel components. Inspection procedures specify that the coated surfaces be inspected for rust, flaking, peeling, blistering, cracking, delamination, physical damage, and checking.

Service Le.vel 1 coatings are used in areas inside the reactor containment where the coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown.

12.

Under the aging management umbrella it is referred to as the Protective Coating Monitoring & Maintenance Program (USAR Subsection K2.1.27) applying to Service Level 1 components.

L-MT-1 6-001 Page 36 of 64 Inspections are performed each operating cycle for all accessible areas in the torus above the water line and for the drywell-coated surfaces to evaluate coatings degradation. The below the water line painted surfaces in the torus, including the areas near the ECCS suction strainers, are inspected at intervals not exceeding five years. A pre-inspection review of the previous two inspection reports is performed so that trends can be identified.

When areas of unacceptable coatings are identified that involve metal substrate degradation, or suspected degradation, then a VT-3 examination is performed in accordance with IWE criteria. Suspect areas may be evaluated for acceptability per ASME Section Xl, IWE-3122. Implementing procedures include provisions for analysis of suspected reasons for coating failure. If areas are acceptable, coating repairs may be performed or left as-is. Previously identified areas with coating degradation, whether repaired or un-repaired, are monitored for further degradation. If conditions would require base metal repairs, repairs would be performed in accordance with the ASME Section XI Repair/Replacement Program.

Sigqnificant Coatinq Related Historical Summary a) 1997 Maintenance Outage The torus was drained down and desludged. In 1997, new EGGS suction strainers were installed. The EGGS suction strainers and their support assemblies were designed to be structurally independent from the torus penetrations. Preservice Coating examinations were performed on the affected ring girder reinforcements used as supports for the new suction strainers. Coatings spot repair was performed in the torus.

b) 2003 RFO Sludge was removed from 100 percent of the underwater surface of the torus shell. The torus sludge appeared to consist mainly of fine particulate with no evidence of fibrous material. Sludge depths at the torus invert (bottom curved surface) ranged from 1-1/2 inch to 1/4 inch. Only insignificant amounts of foreign material were found on the suction strainers and there was no apparent damage to the strainers.

Coating and base metal deficiencies were found on-:less than 5 percent of the torus shell surface. Mechanical damage and flaking of the coating were evident. There was random and minimal pitting corrosion. The inspections verified that there was no deformation, cracking, corrosion, wear, dislocation or disconnection that would have affected either the containment structural integrity or leak tightness.

L-MT-1 6-001 Page 37 of 64 c) 2007 REQ Extensive under the water line Torus coating repairs were performed during REQ 23 (2007). General visual, VT-3 and UT examinations were performed on the internal surfaces of the Torus, external surfaces of the vent lines, vent header and downcomers during REQ 23 (2007). UT measurements confirmed no degradation of the pressure boundary. Small areas of bare metal most being very small nicks (less than 1/2-inch in diameter) on the torus shell with a only light rust film, without evidence of corrosion pitting were observed. VT-3 inspections of areas surfaced prepared for coating found no corrosion pitting and several minor arc strikes that when further inspected by magnetic particle examination were determined acceptable with no indications. No unacceptable loss of material due to pitting corrosion was identified. Results for subsequent outages did not identify any significant age-related degradation (including pitting corrosion). The observed areas of coatings degradation were nonstructural in nature. No conditions that could affect the structural integrity were observed.

Current Coatinqs Performance Minimal corrosion was noted during RFO27 (2015) inspections on the drywell, vent system, and torus vapor phase. Based on previous and RFO27 inspection results there is no evidence of systemic coating failure from aging or other systemic causes. Current and previous inspection results support an expectation of very small corrosion rates on primary containment pressure boundaries.

Small areas of coatings have suffered mechanical damage (e.g. from scaffolding installation). In some cases, this has led to exposed base metal. Some exposed base metal has superficial corrosion. Corrosion leads to further coating degradation. This coating degradation has occurred in small, localized areas.

Some small localized coating repairs in the vent system were done in the past with marginal base metal preparation. Over time evidence shows that a portion of these repairs fail. In order to reduce the probability of this type of failure in the future, procedures were revised to include more detailed instructions for surface preparation including preparation (feathering) of adjacent areas of intact coating.

Coating failures associated with previous marginal base metal preparation were noted during RFO27.

There are small areas at the plates at the highest elevations of the Drywell (interior) that are flaking. This area of the drywell is subject to high temperatures.

Higher temperatures in this area will lead to degradation of coating properties, resulting in flaking. The amount of flaking coating is small.

L-MT-1 6-001 Page 38 of 64 Coatings in the torus vapor phase are showing early signs of degradation (e.g.

pinpoint or spot rusting, magnetite staining). There is no indication of systemic failure.

The majority of degraded coating noted during RFO 26 (2013) was in the underwater portion of the torus. The coating in the underwater portion of the torus is in substantially the same as-left condition as in RFO 23 (2007). Limited underwater coating repairs were performed in 2013. The next underwater inspection of coatings is planned for RFO 28 (2017) and coincides with the ASME Section Xl IWE examinations required for the 3rd Period of the Second Interval.

The total amount of degraded coatings in the Primary Containment, as documented in the most recent inspection performed during RFO27 (2015),

was below the administrative limit (half the analytic limit-).

4.4.3 Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program The MNGP Type B and C testing program requires testing of electrical penetrations, airlocks, hatches, flanges, bellows and containment isolation valves in accordance with 10 CFR 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 thbeir service life. The Type 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 Specification 5.5.11, the allowable maximum pathway total Type B and Type C leakage is 0.6 La (or 60 percent of La) approximately 285 scfh, where La equals 475.1 scfh, excluding the Main Steam Pathway, Specification 5.5.11.a.2.

As discussed within NUREG-1493, Type B and C tests can identify the vast majority of potential containment leakage paths. Therefore, the Type B and Type C testing performed will continue to provide a high degree of assurance that containment integrity is maintained.

A review of the Type B and Type C test results for the MNGP from 2007 through 2015 has shown margin between the actual As-Found and As-Left outage summations and the regulatory requirements as described below:

The As-Found minimum pathway leak rate average for MNGP, shows an average of 19.26 percent of La with a high of 25.76 percent La.

• The As-Left maximum pathway leak rate average for MNGP, shows an average of 35.24 percent of La with a high of 45.06 percent La.

L-MT-1 6-001 Page 39 of 64 The following table provides the local leak rate test (LLRT) data trend summaries for the MNGP inclusive of the 2007 ILRT.

MNGP Type B and C LLRT Combined As-Found I As-Left Trend Summary 2007 2009 2011 2013 2015 FORslsRFO23 RFO24 RFO25 RFO26 RFO27 As-Found Minimum Pathway 75.27 110.29 67.35 70.66 122.40 Leakage (scfh)

Fraction of La (percent) 16.41 24.05 14.69 15.41 25.76 As-Left Maximum Pathway 150.63 206.64 137.90 135.23 184.03 Leakage (scfh)

Fraction of La (percent) 32.84 45.06 30.07 29.49 38.73 As-Left Minimum Pathway 50.43 82.17 54.63 54.80 93.67 Leakage (scfh)

Fraction ofLa (percent) 11.00 17.92 11.91 11.95 19.71 Statistics On Number of Components On Extended Intervals Components in Type B and Type C Test Program:

189 Components NOT eligible for extended intervals:

61 Components eligible for extended intervals:

128 Components that are eligible but not on extended intervals:

11 4.4.4 Type B and Type C Local Leak Rate Testing Program Implementation Review As indicated by the tables below, there were no components on extended LLRT intervals that exhibited unacceptable performance during the previous two refueling outages.

L-MT-1 6-001 Page 40 of 64 MNGP Type B and C LLRT Program Implementation Review 2013 Refuelinq Outacie (RFO26)

As-Admin Component Found Limit As-Left Cause of Corrective Scheduled (scfh)

(scfh)

(scfh)-

Failure Action Interval N one (1) 2015 Refueling Outage (RFO27)_________________

As-Admin Component Found Limit As-Left Cause of Corrective Scheduled scfh)

(scfh)

(scfh)

Failure Action Interval (1)Thee were no.dmnitrtie.imt.aiurs.ssoiaedwih

.omonnt.o.etede intervals identified in either the 2013 or 2015 RFOs.

4.4.5 Supplemental Inspection Requirements With the implementation of the proposed change, Specification 5.5.11 will be revised by replacing the reference to RG 1.163 with a reference to NEI 94-01, Revision 2-A. This will require that a general visual examination of accessible interior and exterior surfaces of the containment for structural problems that may affect either the containment structure leakage integrity of performance of the Type A test. This inspection must be conducted prior to each Type A test and during at least three (3) other outages before the next Type A test if the interval for the Type A test has been extended to 15 years in accordance with the following sections of NEI 94-01, Revision 2-A:

Section 9.2.1, "Pretest Inspection and Test Methodology" Section 9.2.3.2, "Supplemental Inspection Requirements" The following table displays the projected ILRT Type A test performances versus the General Visual examination requirements of accessible containment interior and exterior surfaces (in accordance with ASME Section Xl, Subsection IWE and 10 CFR 50, Appendix J) and the coating examinations of accessible Drywell and interior Torus surfaces - above the water line, and interior Torus surfaces - below the water line.

L-MT-1 6-001 Page 41 of 64 ILRT Versus General Visual (IWE and Appendix J) and Coatings Examination Accessible Surfaces Examination General Visual Calendar Year Type A Examination Coatings Examination (Refueling Test Containment Interior and Drywell and Interior Torus Outage)

(ILRT)

Exterior Surfaces -

Interior Torus Surfaces -

Drywell and Torus Surfaces -Beo (IWE, and Appendix J)

Above Water WtrLn Line 2008 2010 2012 2014 2016 2018 2020 Notes:

(1) The Monticello Operating License was renewed on September 8, 2010.

4.5 Operating Experience During the conduct of the various examinations and tests performed in support of the primary containment monitoring programs previously mentioned, issues that do not meet established criteria or that provide indication of degradation, are identified, placed into the site's corrective action program, and corrective actions are planned and performed. Also, a;summary of the MNGP responses to industry operating experience is provided. The following site specific and industry events have been evaluated for their impact on primary containment:

NRC Generic Letter 87-05, "Request for Additional Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells" (Reference 29)

L-MT-1 6-001 Page 42 of 64 NRC Information Notice 1992-20, "Inadequate Local Leak Rate Testing" (Reference 30)

NRC Information Notice 2004-09, "Corrosion of Steel Containment and Containment Liner" (Reference 31)

NRC Information Notice 2010-12, "Containment Liner Corrosion" (Reference 32)

• NRC Information Notice 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner' (Reference 33)

• Draft NRC Regulatory Issue Summary (RIS) 20YY-XX, "Containment Shell or Liner Moisture Barrier Inspection" (Reference 34)

Each of these operating experiences documents is discussed in detail in the following subsections, respectively.

4.5.1 NRC Generic Letter 87-05. "Request for Additional Information - Assessment of Licensee Measures to Mitigate and/or Identify Potential Degqradation of Mark I DrywelIs" Generic Letter (GL) 87-05 described Drywell shell degradation, which occurred at the Oyster Creek Nuclear Generating Station as a result of water intrusion into the air gap between the outer Drywell surface and the surrounding concrete, involving the subsequent wetting of the sand cushion at the bottom of the air gap.

The NRC requested utilities provide information regarding: (1) drainage of the sand cushion, (2) preventative maintenance and inspection activities to minimize any possible leakage from the refueling pool, (3) plans for ultrasonic thickness measurements for those drywell shells with open sand cushions, and (4) confirmation of specific information as listed in the generic letter.

The Oyster Creek Drywell was constructed leaving the air gap forming material in place. The refueling bellows design incorporated a mechanical joint which was subject to degradation and leakage when the reactor cavity was flooded and thus allowed water to leak into the air gap region. The sand cushion at Oyster Creek was constructed without a seal plate between the sand cushion and the air gap region. It was discovered that the sand pocket and air gap drain lines were not functional allowing leakage from a degraded refueling bellows mechanical joint to collect in the air gap and remain for a significant time period. After evaluation of the corrosion mechanisms, it was determined that moisture had reacted with chemicals in the sand cushion and gap forming material resulting in a corrosive environment which led to the degradation of the carbon steel shell.

L-MT-1 6-001 Page 43 of 64 Discussion:

In the construction method used at the MNGP to achieve the Drywell air gap, 2-inch thick sheets of Ethafoam, a slightly compressible material, were sprayed with silicone lubricant and attached to the drywell to provide a removable form.

Concrete was poured in 3-foot lifts against the Ethafoam. After the concrete was set, the Ethafoam was pulled out. Each lift was inspected to ensure that a 2-inch gap had been achieved. After this inspection, a strip of porous polyurethane foam was inserted to prevent objects being dropped into the air gap. This method provided positive assurance that the gap was achieved and that no foreign objects had inadvertently been left therein. Since the polyurethane strip is very soft, its compression does not induce any undue stresses on the containment vessel shell. Drains installed above the sand pockets at the 920.5 foot elevation in addition to that through the shield penetrations provides drainage. The material is porous so drainage is not inhibited and ventilation is not prevented.

NSPM performs an inspection for leakage from the refueling bellows each refueling outage. The sealing material between the refueling cavity and Drywell air gap is steel joined by watertight welds. Also, a flow switch is provided on the Drywell refueling bellows leakage drain line to detect leakage from the seal area.

There are several paths to remove leakage from refueling or spillage of water into the Drywell air gap. A channel with a 4-inch drain line beneath the refueling bellows prevents leakage from entering the air gap. At the air gap to sand pocket interface there is a galvanized steel plate sealed to the Drywell shell and surrounding concrete. Four 4-inch drain lines remove water which might collect on the plate from above. The sand pocket is provided with four 2-inch drain lines (that are filled with sand to prevent loss of sand from the sand pocket) while providing drainage.

As discussed in Subsection 4.4.1, Item b) (in response to Generic Letter 87-05) the outlets for the sand pocket drains and the air gap drains were inspected.

One sand pocket drain was found to be partially obstructed by deposits of calcium carbonate in the standpipe region of the drain line. The partial obstruction was presumed to be from the drying of the sand pocket during construction and not from leakage during operation. All other drain lines were unobstructed. An additional qualitative test was performed to determine that the Drywell air gap drain lines, from the inlets to the outlets, were unplugged using compressed air to establish a flow through each-.d rain line to verify that it was not obstructed. To ensure the drain line outlets are not obstructed, the plant procedure for filling the reactor well includes a prerequisite to inspect the sand pocket and air gap drain outlets prior to flooding the refueling area.

L-MT-1 6-001 Page 44 of 64 4.5.2 NRC Information Notice 1992-20. "Inadeqiuate Local Leak Rate Testincq'"

The information notice discussed problems with the Type B LLRTs of two-ply bellows and failure to properly identify how to test the components when the LLRT programs were established. LLRTs in some instances could not be relied upon to accurately measure the leakage rate that would occur under accident conditions since, during Type B testing, the two plies in the stainless steel bellows were in contact with each other, restricting the flow of the test medium to the crack locations. Any two-ply bellows of similar construction may be susceptible to this problem.i13 )

Discussion:

As part of the assessment the original equipment manufacturer (OEM), i.e.,

Pathway Bellows, and NRC technical contact for the information notice were contacted. The MNGP two-ply bellows were procured in accordance with the requirements of the design specification (ensure a specified flow rate through the bellows could be obtained). No OEM/vendor test records could be located, so a test was performed on a sample of the bellows to determine how much flow could be measured when testing these bellows by removing the test port plug at the far end of the bellows segment (and 180 degrees around the circumference).

Testing indicated that low leakage rates up to well in excess of the procedural limit could be detected. The test method was revised to have the testers open the test port plug at the opposite end of the bellows to verify that flow completely though a bellows segment could be detected each time tested. Since issuance of the information notice only one bellows had a LLRT leakage of greater than 0.5 scfh. The As-Found LLRT for the (X-1 6B) measured a little over 1 scfh in 1996 and was replaced with a modified bellows design with a "testable" volume in 1998.

The measures taken from NSPM's review of the information notice provided reasonable assurance that at low leakage rates up to well in excess of the procedural limit the method used is capable of detecting!/measuring two-ply bellows leakage. Any measured leakage in excess of the specified limit would be evaluated for further testing and appropriate corrective action.

13.

The information notice also discussed failures in Appendix J test development and program administration, e.g., failure to consider all possible leakage paths, failure to test properly, or inappropriately crediting water seals for lines that that have potential air leakage paths, such as flanges or vacuum breakers, or that depend on the minimum suppression pool water level to prevent leakage.

LUMT-1 6-00 1 Page 45 of 64 4.5.3 Information Notice 2004-09,"Corrosion of Steel Containment and Containment Liner" The information notice alerted the industry to occurrences of corrosion in freestanding metallic containments and in the liner plates of reinforced and pre-stressed concrete containments. Any corrosion (metal thinning) of the liner plate Or freestanding metallic containment could change the failure threshold of the containment under a challenging environmental or accident condition. Thinning changes the geometry of the containment shell or liner plate, which may reduce the design margin of safety against postulated accident and environmental loads.

Recent experience has shown that the integrity of the moisture barrier seal at the floor-to-liner or floor-to-containment junction is important in avoiding conditions favorable to corrosion and thinning of the containment liner plate material.

Inspections of containment at the floor level, as well as at higher elevations, have identified various degrees of corrosion and containment plate thinning.

Discussion:

In 1996 and 1997, the NSPM detected deterioration in the moisture barrier!

caulking between the Drywell shell and the concrete basemat. The defective moisture barrier was removed and the Drywell shell was found to have minor corrosion and was evaluated as acceptable, and the area was cleaned, recoated, and new a moisture barrier was installed.

NSPM has excavated a portion of the Drywell interior basemat concrete in the sand-pocket region to evaluate the exterior of the Drywell due to corrosion reported at other licensees due to leakage in the refueling bellows and blocked sand pocket drains. No indication of degradation was detected at the MNGP.

The sand pocket drains were verified to be operating properly. NSPM has procedures in place that verify no leakage through the refueling bellows by inspecting the sand pocket drains during each refueling outage.

Only minor coating degradation, minor surface rust and minor pitting has been reported in the Drywell, torus, and the vent system( 14 ). No further degradation has been detected at the moisture barrier interface between the Drywell shell and basemat.

4.5.4 Information Notice 2010-12, "Containment Liner Corrosion" This information notice alerted licensees to several events that had occurred where the steel liner of the containment building was corroded and degraded. At the Beaver Valley Power Station and the Brunswick Steam Electric Plant material

14.

In accordance with 10 CFR 50.55a and ASME Section Xl, Subsection IWE, a Metal Containment examination program is in place for the MNGP.

L-MT-1 6-001 Page 46 of 64 had been found in the concrete which trapped moisture against the liner plate and corroded the steel. In one case it was material intentionally placed in the building and in the other case it was foreign material which had inadvertently been left in the form when the wall was poured. The result in both cases was that the material trapped moisture against the steel liner plate leading to corrosion. In the third case, the Salem Nuclear Generating Station, an insulating material placed between the concrete floor and the steel liner plate absorbed moisture and led to corrosion of the liner plate.

Discussion:

Although the examples cited are for conditions specific to concrete containments with steel liners, corrosion concerns have been identified for designs similar to the MNGP Mark I steel Primary Containment. As discussed in-part, previously in Subsection 4.5.1 in response to GL 87-05, the industry has identified areas of corrosion concern primarily on the exterior in the sand-pocket regions and on the interior surface at the moisture-barrier interface with the basemat and steel containment vessel.

The sand pocket corrosion occurs when refueling bellows or cavity liners fail allowing flood-up water to enter the exterior/annulus region. This is accentuated if the sand-pocket drains are plugged. NSPM has performed extensive inspections at the MNGP in these areas, and no degradation was identified.

The interior corrosion at the moisture-barrier interface between the basemat and containment vessel occurs when the moisture barrier degrades, no longer provides a tight seal, allowing water intrusion behind the moisture barrier. In the mid-I1990's minor corrosion was identified at the MNGP moisture barrier which was replaced with a superior product and additional slope was added to ensure water is directed away from the metal shell. Procedural measures ensure leakage into the sand pocket region is not occurring during refueling flood up activities.

4.5.5 Information Notice 2011-1 5. "Steel Containment Deqradation and Associated License Renewal Agingq Management Issues" This information notice discusses age-related degradation of nuclear power plant steel containments that could impact aging management of the containment structures during the period of extended operation under a renewed operating license. Specifically with respect to the MNGP, it describes corrosion due to the presence of water in inaccessible areas and degradation of coatings and pitting corrosion of the torus steel shell or of the Drywell of BWR Mark I containments.

L-MT-1 6-001 Page 47 of 64 Discussion:

Aging management of the Primary Containment (shell) and the Torus (suppression chamber) are accomplished under the Containment Inservice Inspection Plan (CISI) and the Protective Coating Monitoring and Maintenance Program.

During the license renewal application phase the potential for water intrusion into inaccessible areas was reviewed. For the inaccessible exterior drywell shell the primary potential water source is Drywell refueling bellows leakage. As discussed previously in Subsection 4.5.1, under the response to GL 87-05, there are three drain paths for removing this leakage. When inspected in 1987 there was no indication of the presence of water.

The presence of water beneath the refueling bellows, resulting in water entering the drywell air gap, would be indicated by an increase in water to the Radioactive Waste System. The presence of water at the air gap to sand pocket interface would be detected since the drain lines below the torus are monitored during refueling activities by procedure. Flooding in the sand-pocket region would be indicated by water draining from the sand-pocket drain lines. No water has been observed at the drain lines or indications of water leakage during flood up for refueling.

The refueling bellows were inspected during the PLEX Project and were later inspected prior to entering the period of extended operation with no indication of bellows degradation due to cracking or loss of material due to corrosion.

4.5.6 Information Notice 2014-07. "Decqradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner" The containment basemat metallic shell and liner plate seam welds of PWRs are embedded in 3-to 4-feet thick concrete floor during construction and are typically covered by a leak-chase channel system that incorporates pressurizing test connections. This system allows for pressure testing of the seam welds for leak-tightness during construction and also in service, as required. A typical basemat shell or liner weld leak-chase channel system consists of steel channel sections that are fillet welded continuously over the entire bottom shell or liner seam welds and subdivided into zones, each zone with a test connection.

Each test connection consists of a small carbon or stainless steel tube (less than 1-inch diameter) that penetrates through the back of the channel and is seal-welded to the channel steel. The tube extends up through the concrete floor slab to a small steel access (junction) box embedded in the floor slab. The steel tube, which may be encased in a pipe, projects up through the bottom of the

L-MT-1 6-001 Page 48 of 64 access box with a threaded coupling connection welded to the top of the tube, allowing for pressurization of the leak-chase channel. After the initial tests, steel threaded plugs or caps are installed in the test tap to seal the leak-chase volume.

Gasketed cover plates or countersunk plugs are attached to the top of the access box flush with the containment floor. In some cases, the leak-chase channels with plugged test connections may extend vertically along the circumference of the cylindrical containment shell or liner to a certain height above the floor.

Discussion:

The construction of the MNGP metal containment is substantially different from a PWR metal containment. The MNGP Mark 1 containment does not have the leak-chase channel design that is reflected in the referenced PWR events.

Therefore, this operating experience is not directly applicable to the MNGP.

4.5.7 Draft RIS 20YY-XX(, "Containment Shell or Liner Moisture Barrier Inspection" The NRC staff identified several instances in a draft RIS in which containment shell or liner moisture barrier materials were not properly inspected in accordance with ASME Code Section XI, Table IWE-2500-1, Item El1.30. Note 4 (Note 3 in editions before 2013) for Item El1.30 under the "Parts Examined" column states that "Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-to-metal interfaces which are not seal-welded. Containment moisture barrier materials include caulking, flashing, and other sealants used for this application." Examples of inadequate inspections have included licensees not identifying sealant materials at metal-to-metal interfaces as moisture barriers because they do not specifically match Figure IWE-2500-l, and licensees not inspecting installed moisture barrier materials, as required by Item El1.30, because the material was not included in the original design or was not identified as a "moisture barrier" in design documents.

Discussion:

The MNGP moisture barrier (caulking) is located on the Drywell interior at the drywell shell-to-basemat interface and is examined in accordance with the requirements of ASME Section Xl, Table IWE-2500-1, Item E1.30.

L-MT-1 6-001 Page 49 of 64 4.6 License Renewal Aging Management The renewed operating license for MNGP was issued on November 8, 2006, after NRC review of the MNGP license renewal application was completed.

The following Programs which are part of the supporting basis for this LAR, are also Aging Management Programs for the MNGP:

• Primary Containment In-Service Inspection Program

• Protective Coating Monitoring and Maintenance Program 10 CFR 50, Appendix J 4.6.1 Primary Containment In-Service Inspection Program The MNGP Primary Containment In-Service Inspection Program requires visual examinations of the accessible surfaces (base metal and welds) of the Drywell, torus, vent lines, internal vent system, penetration assemblies and associated integral attachments. The program also requires examination of pressure retaining bolting and the drywell interior slab moisture barrier.

The program conforms to the applicable requirements of 10 CFR 50.55a and the 2001 Edition with 2003 Addenda of the ASME Boiler and Pressure Vessel Code, Subsection IWE.

• General visual examinations that assess overall structural condition are performed once during each period.

• Surface and/or volumetric examination augments visual examination as required to define the extent of observed conditions or to identify deterioration at inaccessible locations.

• Examinations are scheduled and performed as required to evaluate disassembled bolting and the condition of the normally submerged torus surface.

The program is updated periodically as required by 10 CER 50.55a.

4.6.2 Protective Coatingq Monitoringq and Maintenance Program The MNGP Protective Coating Monitoring and Maintenance Program applies to the Service Level I protective coatings inside containment to address the

• concerns of NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System after a Loss-of-Cooling Accident because of Construction and Protective Coating Deficiencies and

L-MT-1 6-001 Page 50 of 64 Foreign Material in Containment". The Protective Coating Monitoring and Maintenance Program prevents the degradation of coatings that could lead to the clogging of ECCS suppression pool suction strainers. The MNGP does not credit the Protective Coating Monitoring and Maintenance Program for the prevention of corrosion of carbon steel components.

As outlined in NSPM's response to GL 98-04, the Protective Coating Monitoring and Maintenance Program is a comparable program for monitoring and maintaining protective coatings inside the primary containment and subject to the requirements of ANSI N101.4-1972 as modified by RG 1.54, June 1973.

4.6.3.1.0 CFR 50, Appendix J Proqram The MNGP 10 CFR 50, Appendix J Program specifies pneumatic pressure test and visual examinations to verify the structural and leak tight integrity of the primary containment. An overall (Type A) pressure test assesses the capacity of the primary containment to retain design basis accident pressure. This test also measures total leakage through the containment pressure-retaining boundary.

Local (Type B and C) tests measure leakage through individual penetration isolation barriers. These barriers are maintained as required to keep overall and local leakage under TS and plant administrative limits.

Tests are performed at intervals determined by the risk and performance factors applicable to each tested item in accordance with governing regulations and standards. This risk and performance based approach to testing provides reasonable assurance that developing leakage is detected and corrected well before it reaches a magnitude that could compromise the containment function.

Visual examinations are performed prior to each Type A test. These examinations are also performed at least once during each containment in-service inspection period in which no Type A test is conducted. The examinations are performed to detect corrosion and other types of deterioration on the accessible surfaces of the containment.

4.7 NRC Safety Evaluation Limitation and Conditions 4.7.1 Limitations and Conditions Applicable to NEI 94-01. Revision 2-A The NRC staff found that the use of NEI 9o4-01, Revision 2, was acceptable for referencing by licensees proposing to revise their TSs to permanently extend the ILRT surveillance interval to 15 years, provided the following conditions were satisfied:

L-MT-1 6-001 Page 51 of 64 NEI 94-01, Revision 2-A, Limitations and Conditions Lim itation/Condition (From Section 4.0 of SE)

MNGP Response For calculating the Type A leakage rate, the licensee NSPM will utilize the should use the definition in the NEI 94-01, Revision 2, definition in NEI 94-01 in lieu of that in ANSI/ANS-56.8-2002. (Refer to SE Revision 2-A, Section 5.0.(15)

Section 3.1.1.1.)

The licensee submits a schedule of containment A projected schedule for inspections to be performed prior to and between containment inspections is Type A tests. (Refer to SE Section 3.1.1.3.)

provided in Subsection 4.4.5

______________________________________of this enclosure.

The licensee addresses the areas of the containment Refer to Subsections 4.4.1 structure potentially subjected to degradation.

and 4.4.5 of this enclosure.

(Refer to SE Section 3.1.3.)

The licensee addresses any tests and inspections There are no major performed following major modifications to the modifications planned for the containment structure, as applicable. (Refer to MNGP that would affect the SE Section 3.1.4.)

containment structure.

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

extending the ILRT interval beyond 15 years, the In accordance with the licensee must demonstrate to the NRC staff that it is guidance of Section 3.1.1.2, an unforeseen emergent condition. (Refer to SE of the SE for NEI 94-01, Section 3.1.1.2.)

Revision 2-A, as further amplified by the additional guidance provided in RIS 2008-27.(16)

NSPM will demonstrate to the NRC staff that an emergent unforeseen condition arose if an extension beyond the 15-year ILRT interval became necessary.( 17 )

15.

As part of the amendment implementation process the definition in NEI 94-01, Revision 2-A, will be adopted for calculating the Type A leakage rate.

16.

RIS 2008-27, "Staff Position on Extension of the Containment Type A Test Interval Beyond 15 Years Under Option B of Appendix J to 10 CFR Part 50.

17.

As part of the amendment implementation process the program document controlling Type A testing will be revised to reflect this limitation.

L-MT-1 6-001 Page 52 of 64 NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition (From Section 4.0 of SE)

MNGP Response For plants licensed under 10 CFR Part 52, Not applicable. The MNGP applications requesting a permanent extension of was not licensed under the ILRT surveillance interval to 15 years should be 10 CFR Part 52.

deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No.

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

4.8 Conclusion NEI 94-01, Revision 2-A, describes an NRC-accepted approach for implementing the performance-based requirements of 10 CER 50, Appendix J, Option B. It incorporated the regulatory positions stated in RG 1.163 and includes provisions for extending Type A intervals to 15 years. NEI 94-01, Revision 2-A delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies. NSPM is adopting the guidance of NEI 94-01, Revision 2-A, for MNGP, 10 CFR Part 50, Appendix J testing program plan.

The permanent extension of the containment ILRT interval from 10 to 15 years represents a minimal risk of increased leakage based on the previous ILRTs conducted at the MNGP. The risk is further diminished by the continued Type B and Type C testing performed in accordance with Option B of 10 CFR 50, Appendix J and the overlapping inspection activities performed as part of the following the MNGP inspection programs:

• Containment Inservice Inspection Plan (IWE Plan)

• Protective Coating Monitoring and Maintenance Program

• Containment inspections in accordance with the MNGP Appendix J Program This conclusion is supplemented by risk analysis studies, including the risk analysis for the MNGP provided in Enclosure 2. The risk assessment concluded that the risk incurred by increasing the ILRT interval to 15 years is insignificant because it represents a very small change to the MNGP risk profile.

L-MT-1 6-001 Page 53 of 64

5.0 REGULATORY EVALUATION

The proposed change has been evaluated to determine whether applicable regulations and requirements continue to be met. 10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of 10 CFR 50, Appendix J. The appendix specifies containment leakage testing requirements, including acceptance criteria, test methodology, frequency, and reporting requirements to ensure the leak-tight integrity of the primary containment and systems/components that penetrate containment.

Adoption of Option B performance-based containment leakage rate testing for Type A, Type B and Type C testing does not alter the basic method by which testing is performed; but does alter the frequency at which the Type A containment leakage tests are required to be performed. Test frequency is based on evaluation of the leakage history to determine a frequency for testing which provides assurance that leakage limits will not be exceeded. The proposed change to the ILRT (Type A) frequency does not directly result in an increase in containment leakage.

A risk-informed assessment was performed in accordance with the EPRI methodology using plant-specific risk insights and industry ILRT performance data. The NRC staff found that the methodology utilized (EPRI Report No. 1009325, Revision 2, and NEI 94-01, Revision 2), satisfied the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.174. Consistent with the previous industry results, the change in risk from extending the ILRT interval to 15 years for the MNGP was determined to be very small.

NRC staff review of NEI 94-01, Revision 2, determined that it provides an acceptable approach for implementing performance-based requirements of Option B to 10 CFR 50, Appendix J. The NEI document incorporates the regulatory positions in RG 1.163 and it provides provisions for extending the ILRT intervals to 15 years. The NRC staff found that the Type A test methodology (described in ANSI/ANS-56.8-2002) modified by the test frequencies recommended by the NEI guidance, serves to ensure continued leakage integrity of the containment structure. Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type B and Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths.

Any applicant may reference NEI 94-01, Revision 2-A, in a licensing action to satisfy the requirements of Option B to 10 CFR 50, Appendix J.

5.1 Applicable Regulatory Requirements 10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors."

10 CFR 50.36, "Technical specifications," provides the regulatory requirements

L-MT-1 6-001 Enclosure I Page 54 of 64 for the content required in the TS. The MNGP was designed largely before the publishing of the 70 General Design Criteria (GDC) for Nuclear Power Plant Construction Permits proposed by the Atomic Energy Commission (AEC) for public comment in July 1967, and constructed prior to the 1971 publication of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CER Part

50. As such, the MNGP was not licensed to the Appendix A, General Design Criteria (GDC).

The MNGP USAR, Section 1.2, lists the principal design criteria (PDCs) for the design, construction and operation of the plant. USAR Appendix E provides a plant comparative evaluation to the 70 proposed AEC design criteria. It was concluded that the plant conforms to the intent of the GDCs. The applicable GDCs and PDCs are discussed below.

• PDC 1.2.4 - Plant Containment

d. Provisions are made for preoperational pressure and leak rate testing of the primary containment system and for leak testing at periodic intervals.

Provision is also made for leak testing selected penetrations. Provision is also made for demonstrating the functional integrity of the secondary containment system.

Of the 70 Draft AEC General Design Criteria (AEC-GDC) the following are applicable:

• AEC-GDC Criterion 10 - Containment (CatecioryA)

Containment shall be provided. The containment structure shall be designed to sustain the initial effects of gross equipment failures, such as a large coolant boundary area, without loss of required integrity and, together with other engineered safety features as may be necessary to retain for as long as the situation requires the functional capability to protect the public.

• AEC-GDC Criterion 49 - Containment Design Basis (Category A)

The containment structure, including access openings and penetrations, and any necessary containment heat removal systems shall be designed so that the containment structure can accommodate without exceeding the design leakage rate the pressures and temperatures resulting from the largest credible energy release following a loss-of-coolant accident, including a considerable margin for effects from metal-water or other chemical reactions that could occur as a consequence of failure of emergency core cooling systems.

L-MT-1 6-001 Page 55 of 64

• AEC-GDC Criterion 54 - Containment Leakaqie Rate Testinq (Categqory A)

Containment shall be designed so that an integrated leakage rate testing can be conducted at design pressure after completion and installation of all penetrations and leakage rate measured over a sufficient period of time to verify its conformance with required performance.

• AEC-GDC Criterion 55 - Containment Periodic Leakage Rate Testinq (Categqory A)

The containment shall be designed so that integrated leakage rate testing can be done periodically at design pressure during plant lifetime.

• AEC-GDC Criterion 56 - Provisions for Testingq of Penetrations (Ca teglory A)

Provisions shall be made for testing penetrations which have resilient seals or expansion bellows to permit leak tightness to be demonstrated at design pressure at any time.

• AEC-GDC Criterion 57 - Provisions for Testing of Isolation Valves (Categqory A)

Capability shall be provided for testing functional operability of valves and associated apparatus essential to the containment function for establishing that no failure has occurred and for determining that valve leakage does not exceed acceptable limits.

While not part of the MNGP Licensing Basis, the applicable 10 CFR 50, Appendix A, General Design Criteria are:

• GDC 16 - Containment design Reactor containment and associated systems shall be provided to establish an essentially leak-tight barrier against the uncontrolled release of radioactivity to the environment and to assure that the containment design conditions important to safety are not exceeded for as long as postulated accident conditions require.

GDC 39 - Inspection of containment heat remov~al system The containment heat removal system shall be designed to permit appropriate periodic inspection of important components, such as the torus, sumps, spray nozzles, and piping to assure the integrity and capability of the system.

L-MT-1 6-001 Page 56 of 64

• GDC 40 - Testinq of containment heat removal system The containment heat removal system shall be designed to permit appropriate periodic pressure and functional testing to assure (1) the structural and leaktight integrity of its components, (2) the operability and performance of the active components of the system, and (3) the operability of the system as a whole, and under conditions as close to the design as practical the performance of the full operational sequence that brings the system into operation, including operation of applicable portions of the protection system, the transfer between normal and emergency power sources, and the operation of the associated cooling water system.

• GDC 50 - Containment desiqn basis The reactor containment structure, including access openings, penetrations, and the containment heat removal system shall be designed so that the containment structure and its internal compartments can accommodate, without exceeding the design leakage rate and with sufficient margin, the calculated pressure and temperature conditions resulting from any loss-of-coolant accident. This margin shall reflect consideration of (1) the effects of potential energy sources which have not been included in the determination of the peak conditions, such as energy in steam generators and as required by § 50.44 energy from metal-water and other chemical reactions that may result from degradation but not total failure of emergency core cooling functioning, (2) the limited experience and experimental data available for defining accident phenomena and containment responses, and (3) the conservatism of the calculational model and input parameters.

• GDC 52 - Capability for containment leakaqe rate testing The reactor containment and other equipment which may be subjected to containment test conditions shall be designed so that periodic integrated leakage rate testing can be conducted at containment design pressure.

• GDC 53 - Provisions for containment testing and inspection The reactor containment shall be designed to permit (1) appropriate periodic inspection of all important areas, such as penetrations, (2) an appropriate surveillance program, and (3) periodic testing at containment design pressure of the leaktightness of penetrations which have resilient seals and expansion bellows.

L-MT-1 6-001 Page 57 of 64

• GDC 54 - Piping systems penetratinqi containment Piping systems penetrating primary reactor containment shall be provided with leak detection, isolation, and containment capabilities having redundancy, reliability, and performance capabilities which reflect the importance to safety of isolating these piping systems. Such piping systems shall be designed with a capability to test periodically the operability of the isolation valves and associated apparatus and to determine if valve leakage is within acceptable limits.

5.2 Precedent This request is similar in nature to the following license amendments to permanently extend the Type A test frequency from 10 to 15 years as previously authorized by the NRC:

Nine Mile Point Nuclear Station, Unit No. 2, Amendment 134 (Reference 35)

Arkansas Nuclear One, Unit No. 2, Amendment 292 (Reference 36)

Palisades Nuclear Plant, Amendment 247 (Reference 37)

Virgil C. Summer Nuclear Station, Unit No. 1, Amendment 194 (Reference 38)

The following plants were identified where containment accident pressure is part of their licensing basis, and hence was applied in their NPSH analyses:

North Anna Power Station, Unit Nos. 1 and 2, Amendments 274 and 256, respectively (Reference 39)

• Surry Power Station, Unit Nos. 1 and 2, Amendments 282 and 282, respectively (Reference 40) 5.3 No Significant Hazards Determination In accordance with the requirements of 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," the Northern States Power Company - Minnesota (NSPM) requests an amendment to revise the Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS).

The proposed change revises Specification 5.5.11 "Primary Containment Leakage Rate Testing Program", to increase the containment integrated leakage rate test program Type A test interval from 10 years to 15 years. The basis for the proposed change is in accordance with the guidance of Nuclear Energy Institute (NEI) Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 2-A, as endorsed by the U.S. Nuclear Regulatory Commission.

L-MT-1 6-001 Page 58 of 64 NSPM's evaluation against each of the criteria in 10 CFR 50.92, "Issuance of amendment," follows.

1.

Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed amendment involves a permanent change to extend the Type A containment integrated leak rate test (ILRT) interval from 10 to 15 years. The proposed extension does not involve either a physical change to the plant or a change in the manner in which the plant is operated or maintained. The containment is designed to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment and the testing requirements invoked to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve the prevention or identification of any precursors of an accident.

The effect of changing the Type A test frequency to once every 15 years, measured as an increase to the total integrated plant risk (for accident sequences influenced by Type A testing), is less than or equal to the criteria established in in EPRI Report No. 1009325, Revision 2-A. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible. In addition, as documented in NUREG-1493, Type B and C tests have identified a very large percentage of containment leakage paths, and the percentage of containment leakage paths that are detected only by Type A testing is very small. The MNGP Type A test history supports this conclusion.

The integrity of the containment is subject to two types of failure mechanisms that can be categorized as: (1) activity based, and, (2) time based. Activity based failure mechanisms are defined as those which involve degradation due to system and/or component modifications or maintenance. Local leak rate test requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities. The design and construction requirements of the containment combined with the containment inspections performed in accordance with American Society of Mechanical Engineers (ASME) Section Xi, and TS requirements provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by a Type A test.

L-MT-1 6-001 Page 59 of 64 Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2.

Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No The proposed TS change involves a permanent extension of the Type A containment test interval from 10 to 15 years. The containment testing requirements which periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident. The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) nor does the proposed change alter the design, configuration, or the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.

3.

Does the proposed change involve a significant reduction in a margin of safety?

Response: No The proposed TS change involves a permanent extension of the Type A containment test interval from 10 to 15 years. The specific requirements and conditions of the Primary Containment Leak Rate Testing Program exist to ensure that the required degree of containment structural integrity and leak-tightness considered in the plant safety analysis is maintained.

The overall containment leak rate limit specified by TS is maintained.

The proposed change involves only an extension of the interval between Type A test performances for MNGP. Extension of the proposed surveillance interval is in accordance with the 15-year ILRT Interval determined acceptable by the NRC utilizing the guidance of NEI 94-01, Revision 2-A. Industry experience supports the conclusion that Type B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with ASME Section XI, and the TS serve to provide a high degree of assurance that the containment would not degrade ina manner that is detectable only by Type A testing. The combination of these factors ensures that the margin of safety in the plant safety analysis is

L-MT-1 6-001 Page 60 of 64 maintained. The design, operation, testing methods and acceptance criteria for Type A, B, and C containment leakage tests specified in applicable codes and standards continue to be met with the acceptance of this proposed change because these criteria are not affected by the proposed change to the Type A test interval.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, the NSPM has determined that operation of the facility in accordance with the proposed change does not involve a significant hazards consideration as defined in 10 CFR 50.92, "Issuance of amendment," paragraph (c), in that it does not: (1) involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) involve a significant reduction in a margin of safety.

6.0 ENVIRONMENTAL CONSIDERATION

10 CFR 51.22, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review," identifies certain licensing and regulatory actions which are eligible for categorical exclusion from the requirement to perform an environmental assessment. NSPM has determined that the proposed amendment meets the criteria for a categorical exclusion from an environmental review as set forth in 10 CFR 51.22, specifically, 10 CFR 51.22(c)(9). First, the proposed amendment changes a requirement with respect to installation or use of a facility or component located within the restricted area, as defined in 10 CFR 20, "Standards for Protection Against Radiation," or involves a change to an inspection or surveillance requirement. Second, the proposed amendment requires no environmental assessment since operation of the facility in accordance with the proposed amendment does not (i) involve a significant hazards consideration, or (ii) authorize a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) result in a significant increase in individual or cumulative occupational radiation exposure.

Therefore, NSPM concludes pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

L-MT-16-001 Page 61 of 64

7.0 REFERENCES

1.

Nuclear Energy Institute (NEI) Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J",

Revision 2-A, dated October 2008

2.

ANSI/ANS 56.8-2002, "Containment System Leakage Testing Requirements"

3.

NRC Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program", dated September 1995

4.

10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors"

5.

NEI Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 3-A, dated July 2012

6.

NRC Regulatory Guide 1.174, Revision 2, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis", dated May 2011

7.

NRC Regulatory Guide 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities", dated March 2009

8.

Letter from T. Beltz (NRC) to K. Fili (NSPM), "Monticello Nuclear Generating Plant - Issuance of Amendment No. 176 to Renewed Facility Operating License Regarding Extended Power Uprate", (TAC No. MD9990)", dated December 9, 2013.

9.

SECY-1 1-0014, "Use of Containment Accident Pressure in Analyzing Emergency Core Cooling System and Containment Heat Removal System Pump Performance in Postulated Accidents", dated January 31, 2011 (ADAMS Accession No. ML102II10167), Enclosure 1

10.

NUREG-1493, "Performance-Based Containment Leak-Test Program", dated September 1995

11.

Electric Power Research Institute (EP RI) Topical Report TR-1 04285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals", dated August 1994

L-MT-1 6-001 Page 62 of 64

12.

NRC Regulatory Issue Summary (RIS) 2008-27, "Staff Position on Extension of the Containment Type A Test Interval Beyond 15 Years Under Option B of Appendix J to 10 CFR Part 50", dated December 8, 2008

13.

Letter from M. Maxim (NRC) to C. Butler (NEI), "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2, 'Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J' and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, 'Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals' (TAC No. MC9663)", dated June 25, 2008

14.

Letter from S. Bahadur (NRC) to B. Bradley (NEI), "Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J (TAG No.

ME21 64)", dated June 8, 2012

15.

Letter from T. Kim (NRC) to R. Anderson (NSP), "Monticello Nuclear Generating Plant - Issuance of Amendment RE: Main Steam Isolation Valve and 10 CFR Part 50, Appendix J, Leak Test Requirement (TAC No. M93332)", dated April 3, 1996

16.

Letter from D. Hood (NRC) to J. Forbes (NMC), "Monticello Nuclear Generating Plant - Issuance of Amendment Re: License Amendment Request for Conversion to Option B for Containment Leak Rate Testing (TAC No. MB4975)",

dated February 4, 2003

17.

Letter from M. Padovan (NRC) to J. Forbes (NMC), "Monticello Nuclear Generating Plant - Issuance of Amendment Re: One-Time Extension of Containment Integrated Leak-Rate Test Interval (TAC No. MB4919)", dated March 31, 2003

18.

Letter from P. Tam (NRC) to J. Conway (NMC), "Monticello Nuclear Generating Plant - Issuance of Amendment Re: Full Scope Implementation of the Alternative Source Term Methodology (TAC No. MC8971)", dated December 7, 2006

19.

Letter from P. Tam (NRC) to J. Conway (NMC), "Monticello Nuclear Generating Plant - Issuance of Exemption to Certain 10 CFR Part 50, Appendix J, Requirements (TAC No. MD2395)", dated December 7, 2006

20.

Letter from T. Beltz (NRC) to K. Fili (NS PM), "Monticello Nuclear Generating Plant - Issuance of Amendment to Revise Technical Specification 5.5.11,

'Primary Containment Leakage Rate Testing program' (TAG NO. MF3161)",

dated January 8, 2015

L-MT-1 6-001 Page 63 of 64

21.

Letter from D. Eisenhut (NRC) to D. Musoif (NSP), discussing NRC review of a plan to achieve compliance with 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors", dated June 3, 1984

22.

Nuclear Energy Institute (NEI), "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals", October 2001

23.

Letter from C. Cruse (Constellation Nuclear) to NRC, "Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension", dated March 27, 2002

24.

EPRI Topical Report TR-1018243, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals", Revision 2-A of 1009325, dated October 2008

25.

EPRI Topical Report TR-1 009325, Revision 2-A, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals", dated August 2007

26.

NUREG/CR-6850, "EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities", dated September 2005

27.

Letter from I. Frankl (NRC) to S. Schimmel (NMC), "Monticello Nuclear Generating Plant (MNGP) - Approval of Relief Request RR-007 for the Fifth 10-Year Inservice Inspection Interval (TAC ME8157)", dated July 12, 2012

28.

N RC Generic Letter 1998-04, "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", dated July 14, 1998

29.

NRC Generic Letter 1987-05, "Request for Additional Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells (Generic Letter 87-05)", dated March 12, 1987

30.

NRC Information Notice 1992-20: "Inadequate Local Leak Rate Testing",

dated March 3, 1992

31.

NRC Information Notic*e 2004-09: "Corrosion of Steel Containment and Containment Liner", dated April 27, 2004

32.

NRC Information Notice 2010-12: "Containment Liner Corrosion", dated June 18, 2010

.\\,,

L-MT-1 6-001 Page 64 of 64

33.

NRC Information Notice 2014-07: "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner", dated May 5, 2014

34.

NRC Regulatory Issue Summary (RIS) 20YY-XX, "Containment Shell or Liner Moisture Barrier Inspection", [RIS is in draft and has not been formally issued.]

35.

Letter from R. Guzman (NRC) to S. Belcher (NMP), "Nine Mile Point Nuclear Station, Unit No. 2 - Issuance of Amendment RE: Extension of Primary Containment Integrated Leakage Rate Testing Interval (TAC No. ME1 650)",

dated March 30, 2010

36.

Letter from N. Kalyanam (NRC) to Vice President, Operations (Entergy),

"Arkansas Nuclear One, Unit No. 2 - Issuance of Amendment RE: Technical Specification Change to Extend Type A Test Frequency to 15 Years (TAC No.

ME4090)", dated April 7, 2011

37.

Letter from M. Chawala (NRC) to Vice President, Operations (Entergy),

"Palisades Nuclear Plant - Issuance of Amendment to Extend the Containment Type A Leak Rate Test Frequency to 15 Years (TAC No. ME5997)", dated April 23, 2012

38.

Letter from S. Williams (NRC) to T. D. Gatlin (VCSNS), "Virgil C. Summer Nuclear Station, Unit 1 - Issuance of Amendment Extending Integrated Leak Rate Test Interval (TAC No. MF1385)", dated February 5, 2014

39.

Letter from V. Sreenivas (NRC) to D. Heacock (VEPCO), "North Anna Power Station, Unit Nos. 1 and 2, Issuance of Amendments to Extend Type A Test Frequency to 15 Years (TAC Nos. MF4332 and MF4333)", dated June 16, 2015

40.

Letter from S. Williams (NRC) to 0. Heacock (VEPCO), "Surry Power Station, Units 1 and 2 - Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests (TAC Nos. MF2612 and MF261 3)", dated July 3, 2014

ATTACHMENT 1 MONTICELLO NUCLEAR GENERATING PLANT LICENSE AMENDMENT REQUEST REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS MARKED-UP TECHNICAL SPECIFICATION PAGE (1 page follows)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 5.5.11 Safety Function Determination Progqram (SFDP) (continued)

3.

A required system redundant to the support system(s) for the supported systems described in Specifications 5.5.10.b.1 and 5.5.10.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 Leakaqe Rate Testinq Progqram

a.

A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in R.gulato,,,; Gu,,,do.1.163, "Perormnce...

Bae otinetLa Te,,st..Progr....m...

dao pe...b..., 1..05, as modified by the following exceptions:

Paragr..ph 0.2.3, a... "at leat onco per 10...... based^, on...cceptabl, to* tlho* inter-_ml folqlowing;," the Ty*po." A test prfoe'od*'. in* MaIsrcl.h 1003.

NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J,"'

Revision 2-A, dated October 2008

[J 1.2 The main steam line pathway leakage contribution is excluded from the sum of the leakage rates from Type B and C tests specified in Section III.B of 10 CFR 50, Appendix J, Option B, Section 6.4.4 of

• eral iANSI/ANS 56.8--1-g4, and Section 10.2 of NEI 94-01,-Rv-; and Revision 2-A

2.

Temain steam line pathway leakage contribution is excluded from oealitegrated leakage rate from Type A tests specified in Sectie o 10 CFR 50, Appendix J, Option B, Section 3.2 of

~~ANSI/ANS 56. -09, and Section 8.0 and 9.0 of NEI 94-01, fav*

b.

The calculated peak containment internal pressure for the design basis loss of coolant accident, Pa, is 44.1 psig. The containment design pressure is 56 psig.

c.

The maximum allowable containment leakage rate, La, at Pa, shall be 1.2%

of containment air weight per day.

Monticello Motielo5.5-10 Amendment No. 116 118,1!75, 176,_

ATTACHMENT 2 MONTICELLO NUCLEAR GENERATING PLANT LICENSE AMENDMENT REQUEST REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS MARKED-UP TECHNICAL SPECIFICATION BASES PAGE (1 page follows)

Primary Containment B 3.6.1.1 BASES SURVEILLANCE REQUIREMENTS (continued) would be directed through the downcomers into the suppression pooi.

This SR measures drywell to suppression chamber differential pressure during a 25 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowable limits.

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and verifying that the bypass leakage is less than that equivalent to a one inch diameter orifice. The leakage test is performed every 24 months. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs. Two consecutive 24 month test failures, however, would indicate unexpected primary containment degradation; in this event, as the Note indicates, increasing the Frequency to once every 12 months is required until the situation is remedied as evidenced by passing two consecutive 12 month tests.

REFERENCES

1.

USAR, Section 5.2.

2.

USAR, Section 14.7.2.

3.

10 CFR 50, Appendix J, Option B.

4.

Amendment No. 176, "Monticello Nuclear Generating Plant -

Issuance of Amendment No. 176 to Renewed Facility Operating License Regarding Extended Power Uprate," (ADAMS Accession No. ML13316C459)

5.

Nuclear Energy Institute (NEI) Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 2-A, dated October 2008

6.

ANSI/ANS 56.8-2002, "Containment System Leakage Testing Requirements" Monticello Monticello

~B 3.6.1.1 Last Rvso o

Revision No.

ENCLOSURE 2 MONTICELLO NUCLEAR GENERATING PLANT LICENSE AMENDMENT REQUEST REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS MONTICELLO NUCLEAR GENERATING STATION EVALUATION OF RISK SIGNIFICANCE OF PERMANENT ILRT EXTENSION (145 pages follow)

QF0938 Rev 0 (FP-PE-PRA-06)

Page i of i SXceI EnergyI PRA Document Signature Sheet Document Information PRA Document No: PRA-CALC-15-O02 Revision: 2

Title:

Evaluation of Risk Significance of Permanent ILRT Extension Failty MT LI PI Applicable Unit: [] 1 [] 2 F

NOTE:

Pntadsign name insignature blocks, as required.

Review Information

[] Vendor Caic Vendor Doc No: 54005-CALC-01 Rev. 2 Vendor Name or Code: Jensen Hughes Prepared by:

Jensen Hughes (signatures on vendor

/(print)

Date:

(sign) calculation 2/8/2016 Reviewed by:

xJU*.. *_.*,

CL

/(printl Date:

(sign)

Dean R. Dudley 2/8/2016 Type of Review:

[] Technical Review

[] Suitability Review Revision History Rev.

Description Preparer Reviewer Date 0

Initial Issue Jensen Hughes TPW 1/11/2016 1

Containment Accident Pressure Update Jensen Hughes TPW 1/25/2016 2

PORC Comments Incorporated Jensen Hughes DRD 2/8/2016 Form retained in accordance with record retention schedule identified in FP-G-RM-01. Retain this form with the associated PRA calculation for the life of the plant.

QF0941 Rev I (FP-PE-PRA-06)

Page 1 of 2 4

Xcel Energy" PRA Suitability Review Checklist External Vendor Document Being Reviewed:

Title:

Evaluation of Risk Significance of Permanent ILRT Extension Number:

PRA-CALC-15-002 Rev:

2 Date:

2/8/2016 This design document was received from:

Organization Contract Number:

Name:

Jensen Hughes 59637 The purpose of the suitability~review is to ensure that a PRA calculation (or other PRA related document) provided by an External Vendor complies with the conditions of the purchase order and is appropriate for its intended use.

The suitability review does not serve as a technical review. Technical review of the document supplied by the External Vendor should be evident in the document.

The reviewer should use the criteria below as a guide to assess the overall quality, completeness and usefulness of the design document. The reviewer is not required to check calculations in detail.

REVIEW Reviewed NIA 1

Analysis inputs correspond to those that were transmitted to the External I[]

LI Vendor.

2 Assumptions are described and reasonable.

LII[

3 Applicable codes, standards and regulations are identified and met.

LI

[

4 Applicable structure(s), system(s), and component(s) are listed.

LI

[

5 Formulae and equations are documented. Unusual symbols are defined.

LI

[

6 Acceptance criteria are identified, adequate and satisfied.

LII[

7 Results are reasonable compared to inputs.

LI

[

8 Source documents are referenced.

[]

[

9 The document is appropriate for its intended use.

LI

[

10 The document complies with the terms of the Purchase Order.

[]

[

11 The impact to PRA applications (Maintenance Rule (a)(4), MSPI), other

[]

[

PRA documents, or other risk informed decisions has been identified and required changes tracked appropriately and listed in Table 1.

Reviewer Summary / Comments:

Review Completed by:

Dean R. Dudley Date:

2/8/2016 Form retained in accordance with record retention schedule identified in FP-G-RM-01. Retain this form with the associated PRA calculation for the life of the plant.

TABLE I Initiate an AR or POD item (as appropriate) to track open items and impacts, if any.

Item Tracking No.

umbr (A

orPRA IMPACT DESCRIPTION PCD, as appropriate I

None N/A 2

3 4

5 6

"7 8

9 10 11 12______________________________

13______________________________

14 15 Form retained in accordance with record retention schedule identified in FP-G-RM-01. Retain this form with the associated PRA calculation for the life of the plant.

XcelEnergy 2807ceW CountycRoad~ 75 February 10, 2016 L-MT-1 6-001 10 CFR 50.90 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Monticello Nuclear Generating Plant Docket No. 50-263 Renewed Facility Operating License No. DPR-22 License Amendment Request: Revise Technical Specification 5.5.11 to Provide a Permanent Extension of the Integrated Leakage Rate (Type A) Test Frequency from Ten to Fifteen Years In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," the Northern States Power Company, a Minnesota corporation, d/b/a Xcel Energy (hereafter "NSPM"), requests a change to the Technical Specifications (TS) for the Monticello Nuclear Generating Plant (MNGP). The proposed change revises Specification 5.5.11 "Primary Containment Leakage Rate Testing Program", to increase the containment integrated leakage rate test (ILRT) program Type A test interval from 10 years to 15 years. The basis for the proposed change is in accordance with the guidance of Nuclear Energy Institute (NEI) Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 2-A, as endorsed by the U.S. Nuclear Regulatory Commission.

The proposed license amendment request (LAR) is risk-informed and follows the guidance provided by Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk-Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis", Revision 2.

Enclosure I contains a description and summary safety assessment of the proposed TS change as well as the technical bases for the changes. The enclosure also provides the No Significant Hazards Consideration evaluation in accordance with 10 CFR 50.92, "Issuance of Amendment," and the Environmental Assessment. These provide the bases for the conclusion that the amendment request involves no significant hazards consideration and meets the eligibility criterion for categorical exclusion as set forth in 10 CFR 51.22, "Criteria for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review," paragraph (c)(9).

Document Control Desk L-MT-16-001 Page 2 of 2 Attachment I to Enclosure 1 contains the marked-up TS page. Attachment 2 to provides the marked-up TS Bases pages for information. NSPM has performed a plant-specific evaluation to assess the risk impact of the proposed changes. A copy of the risk assessment is provided in Enclosure 2.

NSPM requests approval of the proposed LAR within one year after submittal to support an extension of the current MNGP ILRT interval, which requires performance of the ILRT during the upcoming refueling outage (RFO) in the Spring of 2017. Once approved, this amendment shall be implemented prior to startup from the 2017 RFO.

The MNGP Plant Operations Review Committee has reviewed this application. In accordance with 10 CFR 50.91, "Notice for public comment; State consultation,"

paragraph (b), NSPM is notifying the State of Minnesota by transmitting a copy of this application, with the enclosures, to the designated State Official.

Summary of Commitments This letter proposes no new commitments and does not revise any existing commitments.

If you have any questions or require additional information, please contact Mr. Richard Loeffier at (763) 295-1247.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on February ho, 2016.

Kent Scott /

for Peter A. Gardner Site Vice President - Monticello Nuclear Generating Plant Northern States Power Company - Minnesota :

Discussion and Evaluation of the Proposed Changes :

Marked-up Technical Specification Page : Marked-up Technical Specification Bases Page :

MNGP Evaluation of Risk Significance of Permanent ILRT Extension cc:

Administrator, Region Ill, US NRC Project Manager, Monticello Nuclear Generating Plant, US NRC Resident Inspector, Monticello Nuclear Generating Plant, US NRC State of Minnesota

L-MT-1 6-00 1 LICENSE AMENDMENT REQUEST: REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS Table of Contents ENCLOSURE 1 1.0

SUMMARY

DESCRIPTION............................................................. I

2.0 BACKGROUND

INFORMATION.......................................................

I 3.0 DETAILED DESCRIPTION............................................................. 2 3.1 Current Containment Leakage Rate Testing Program........................... 2 3.2 Proposed Technical Specification Change Description......................... 3

4.0 TECHNICAL EVALUATION

............................................................ 4 4.1 Description of the Primary Containment System................................. 4 4.1.1 Drywell.............................................................................. 5 4.1.2 Suppression Chamber.......................................................... 6 4.1.3 Piping Penetrations............................................................... 6 4.1.4 Electrical Penetrations.......................................................... 7 4.1.5 Plant Operational Considerations Relating to Containment Leakage........ 7 4.1.6 Containment Heat Removal and Emergency Core Cooling System Net Positive Suction Head Performance........................................... 8 4.2 Justification for the Proposed Technical Specification Change.............. 10 4.2.1 Chronology of Testing Requirements of 10 CER 50, Appendix J........... 10 4.2.2 Current MNGP Integrated Leakage Rate Testing Requirements........... 13 4.2.3 MNGP 10 CER 50, Appendix J, Option B Licensing History................ 14 4.2.4 MNGP Integrated Leakage Rate Testing History............................. 15 4.3 Plant Specific Confirmatory Analysis............................................. 17 4.3.1 Methodology...................................................................... 17 4.3.2 Technical Adequacy of the MNGP Probabilistic Risk Assessment......... 21 4.3.3 Summary of Plant-Specific Risk Assessment Results....................... 23 4.3.4 Previous Assessments........................................................ 24 4.4 Non-Risk Based Assessment...................................................... 24 4.4.1 Containment Inservice Inspection Plan (IWE Plan).......................... 25 Page 1 of 3

TABLE OF CONTENTS 4.4.2 Nuclear Coatings Program.................................................... 35 4.4.3 Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program...................................................... 38 4.4.4 Type B and Type C Local Leak Rate Testing Program Implementation Review.......................................................................... 39 4.4.5 Supplemental Inspection Requirements...................................... 40 4.5 Operating Experience................................

'.............................. 41 4.5.1 NRC Generic Letter 87-05, "Request for Additional Information -

Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells".............................................. 42 4.5.2 NRC Information Notice 1992-20, "Inadequate Local Leak Rate Testing"......................................................................... 44 4.5.3 Information Notice 2004-09,"Corrosion of Steel Containment and Containment Liner"............................................................. 45 4.5.4 Information Notice 2010-12, "Containment Liner Corrosion"............... 45 4.5.5 Information Notice 2011-1 5, "Steel Containment Degradation and Associated License Renewal Aging Management Issues".................. 46 4.5.6 Information Notice 20 14-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner".................................................... 47 4.5.7 Draft RIS 20YY-XX, "Containment Shell or Liner Moisture Barrier Inspection"..................................................................... 48 4.6 License Renewal Aging Management.........................................

... 49 4.6.1 Primary Containment In-Service Inspection Program....................... 49 4.6.2 Protective Coating Monitoring and Maintenance Program.................. 49 4.6.3 10 CFR 50, Appendix J Program............................................. 50 4.7 NRC Safety Evaluation Limitation and Conditions.............................

50 4.7.1 Limitations and Conditions Applicable to NEI 94-01, Revision 2-A........ 50 4.8 Conclusion........................................................................... 52 5.0

REGULATORY EVALUATION.......................................................

53 5.1 Applicable Regulatory Requirements............................................

53 5.2 Precedent............................................................................

57 5.3 No Significant Hazards Determination...........................................

57 Page 2 of 3

TABLE OF CONTENTS

6.0 ENVIRONMENTAL CONSIDERATION

............................................. 60

7.0 REFERENCES

......................................................................... 61 ATTACHMENT I ATTACHMENT 2 ENCLOSURE 2 Page 3 of 3

L-MT-1 6-00 1 Page 1 of 64 LICENSE AMENDMENT REQUEST: REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS 1.0

SUMMARY

DESCRIPTION Pursuant to 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," the Northern States Power Company, a Minnesota corporation, dlb/a Xcel Energy (hereafter "NSPM"), requests an amendment to the Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS) to revise Specification 5.5.11 "Primary Containment Leakage Rate Testing Program" to:

Increase the existing Type A containment integrated leakage rate test (ILRT) program Type A test 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 50, Appendix J",

Revision 2-A (Reference 1).

• Adopt the use of American National Standards Institute (ANSI) / American Nuclear Society (ANS) 56.8-2002, "Containment System Leakage Testing Requirements" (Reference 2)

The proposed change revises Specification 5.5.11 by replacing the reference to Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program" (Reference 3) and NEI 94-01, Revision 0, with a reference to NEI 94-01, Revision 2-A, as the document used to implement a performance-based leakage test program in accordance with "Option B - Performance-Based Requirements" of 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," (Reference 4).

NSPM has evaluated the additional considerations (e.g., extended Type C intervals) afforded by NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 3-A (Reference 5) and has chosen not to pursue adoption of NEI 94-01, Revision 3-A at this time.

2.0 BACKGROUND

INFORMATION The MNGP is a boiling water reactor (BWR) of the General Electric (GE) BWR/3 design, with a Mark I containment. The plant is located within the city limits of Monticello, Minnesota,. on the south bank of the Mississippi River approximately 30 miles northwest of Minneapolis/St. Paul, Minnesota. Commercial operation began on June 30, 1971.

The design of the plant predates both the 70 proposed draft General Design Criteria (GDC) issued for public comment by the Atomic Energy Commission (AEC) in July 1967 and the 1971 publication of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50.

L-MT-1 6-001 Page 2 of 64 A high level summary of licensing history pertinent to Type A testing follows. On April 3, 1996, 10 CFR 50, Appendix J, Option B,Section III.A was adopted for Type A testing at the MNGP. On March 31, 2003, a one-time, 5-year extension to the 10-year Type A test interval was approved. On December 7, 2006, a full-scope alternative source term license amendment was approved. In conjunction, the exemptions to Section III.A and Section III.B of 10 CFR 50, Appendix J, Option B, received allow the exclusion of main steam line (MSL) pathway leakage contributions from the overall integrated leakage rate for Type A tests and to the sum of the leakage rates for Type B and Type C tests. On December 9, 2013, an Extended Power Uprate (EPU) license amendment was received which increased the maximum licensed thermal power level by approximately 13 percent, from a previous level of 1,775 megawatts-thermal (MWt) to 2,004 MWt. As part of that amendment the Primary Containment accident pressure in the plant TS increased from 42.0 psig to 44.1 psig.

3.0 DETAILED DESCRIPTION 3.1 Current Containment Leakage Rate Testing Program MNGP Specification 5.5.11, "Primary Containment Leakage Rate Testing Program,"

currently states, in part:

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

1.

The Type A testing Frequency specified in NEI 94-01, Revision 0, Paragraph 9.2.3, as "at least once per 10 years based on acceptable performance history" is modified to be "at least once per 15 years based on acceptable performance history." This change applies only to the interval following the Type A test performed in March 1993.

2.

The main steam line pathway leakage contribution is excluded from the sum of the leakage rates from Type B and C tests specified in Section III.B of 10 CFR 50, Appendix J, Option B, Section 6.4.4 of ANSI/ANS 56.8-1994, and Section 10.2 of NEI 94-01, Rev. 0; and 2.(1) The main steam line pathway leakage contribution is excluded from the overall integrated leakage rate from Type A tests specified in Section IlI.A of 10 CFR 50, Appendix J, Option B, Section 3.2 of ANSI/ANS 56.8-1 994, and Section 8.0 and 9.0 of NEI 94-01, Rev. 0.

1.

Typographical numbering error corrected by this amendment.

L-MT-1 6-001 Enclosure I Page 3 of 64 3.2 Proposed Technical Specification Change Description The proposed TS change would allow an increase in the ILRT test interval from the current 10-year frequency to a maximum of 15 years, in accordance with NEI 94-01, Revision 2-A. The specific changes proposed to Specification 5.5.11 are:

Replace reference to RG 1.163, dated September 1995, with a reference to NEI 94-01, Revision 2-A.

Remove the reference to the one-time change extending the interval after the Type A test performed in March 1993 from at least once per 10 years to at least once per 15 years. That interval is complete. The Type A test was performed in April 2007.

Update the references to ANSI/ANS 56.8 from the 1994 version to the 2002 version of the standard.

Update the references to NEI 94-01 from Revision 0 to Revision 2-A.

The revised Specification 5.5.11 would then state:

a. A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 2-A, dated October 2008, as modified by the following exceptions:

1.

The main steam line pathway leakage contribution is excluded from the sum of the leakage rates from Type B and C tests specified in Section III.B of 10 CFR 50, Appendix J, Option B, Section 6.4.4 of ANSI/ANS 56.8-2002, and Section 10.2 of NEI 94-01, Revision 2-A; and

2.

The main steam line pathway leakage contribution is excluded from the overall integrated leakage rate from Type A tests specified in Section lII.A of 10 CFR 50, Appendix J, Option B, Section 3.2 of ANSI/ANS 56.8-2002, and Sections 8.0 and 9.0 of NEI 94-01, Revision 2-A.

A mark-up of proposed Specification 5.5.11 is provided in Attachment I to this enclosure. No TS Bases are associated with Section 5 of the TS which includes Section 5.5, "Programs and Manuals," subsection of the TS. However, the TS Bases for Specification 3.6.1.1, "Primary Containment," are also being revised to reflect the change in the ILRT test interval from 10 to 15 years and to provide the basis for the change in frequency via this license amendment request. The TS Bases for Specification 3.6.1.1 are provided in Attachment 2. The TS Bases will be updated in accordance with the Specification 5.5.9, "Technical Specification Bases Control Program." The TS Bases pages are provided for information only.

L-MT-1 6-001 Page 4 of 64 A plant-specific risk assessment entitled, "Monticello Nuclear Generating Station:

Evaluation of Risk Significance of Permanent ILRT Extension," performed by Jensen Hughes is provided as Enclosure 2. This assessment followed the guidelines of RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis", Revision 2 (Reference 6) and RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities", Revision 2 (Reference 7). The technical adequacy of the MNGP probabilistic risk assessment (PRA) is discussed in Appendix A of the assessment.

The risk assessment concluded that the increase in risk from changing the ILRT performance interval from 10 to 15 years is considered insignificant since it represents a very small change in the MNGP risk profile that is within the NRC established guidelines.

4.0 TECHNICAL EVALUATION

The following paragraphs provide a background discussion of the systems, components and parameters affected by the proposed changes. The discussion is provided for information and does not describe the changes being proposed.

4.1 Description of the Primary Containment System The MNGP is a BWR/3 with a Mark I pressure suppression type primary containment system( 2). The Primary Containment encloses the reactor vessel, the reactor coolant recirculation system loops, and other primary system piping. The Primary Containment consists of a Drywell, which encloses the reactor vessel and recirculation pumps, a pressure suppression chamber (torus or wetwell) that stores a large volume of water, a connecting vent system between the Drywell and the suppression (water) pool, isolation valves, vacuum breakers, ventilating and cooling systems, and other service equipment.

The function of the Primary Containment is to isolate and contain fission products released from the reactor primary system piping following a postulated design basis accident (DBA), i.e., a loss of coolant accident (LOCA), and confine the postulated release of radioactive material. It surrounds the reactor primary system piping and provides an essentially leak tight barrier against an uncontrolled release of radioactive material to the environment. The safety design basis for the Primary Containment is to

2.

Primary Containment consists of a steel pressure vessel enclosed in reinforced concrete, i.e., the Drywell, and a suppression chamber, a steel torus-shaped pressure vessel located below and encircling the Drywell, connected to it by vent pipes. The reinforced concrete is provided for shielding purposes and to provide additional resistance to deformation and buckling of the drywell over areas where the concrete backs up the steel shell. The design pressure is 56 psig coincident with a maximum temperature of 281 "F. The maximum external pressure is 2 psig above internal pressure.

L-MT-1 6-001 Page 5 of 64 withstand the pressures and temperatures(2 ) of the limiting DBA without exceeding the design leakage rate. The maximum allowable leakage rate (La) for the Primary Containment is 1.2 percent by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design basis LOCA maximum peak containment pressure (Pa) of 44.1 psig.

The drywell-to-wetwell vents are connected to a vent header contained within the airspace of the wetwell. Downcomer pipes project downwards from the vent header and terminate below the water surface of the suppression pool so that in the event of any pipe failure in the drywell, the released steam would pass directly to the water where it would be condensed. The vacuum relief system consists of eight vacuum breakers which equalize the pressure between the wetwell and the Drywell to prevent a backflow of water from the suppression pool into the vent system.

4.1.1 Drywell The drywell portion of the primary containment is a steel pressure vessel with a spherical lower portion and a cylindrical upper portion. It is enclosed in reinforced concrete for shielding purposes and to provide additional resistance to deformation and buckling of the drywell over areas where the concrete backs up the steel shell. Above the foundation transition zone, the drywell is separated from the reinforced concrete by a gap of approximately 2 inches for thermal expansion. Shielding over the top of the drywell is provided by a set of removable, reinforced concrete shield blocks.

In addition to the drywell head with its bolted manway and one double door personnel air lock, two hatches (one large equipment hatch and one control rod drive (CRD) hatch) are provided for access. The locking mechanism on each air lock door is designed so that a tight seal is maintained when the doors are subjected to either internal or external pressure. The air lock doors are mechanically interlocked to maintain primary containment integrity. The drywell airlock is tested by pressurizing the space between the inner and outer doors.

Individual drywell airlock door seal leakage tests cannot be performed. Since the inner door is designed to seat with containment pressure forcing the door closed, special bracing must be installed for each leakage test. The outer door must be opened to install and remove this bracing. The equipment hatch cover is bolted in place and sealed with a double tongue and groove seal. The CRD hatch is held in place by a yoke and clamp and is sealed with a double 0-Ring seal. The seals on the drywell access hatch covers are capable of being tested for leakage.

The top portion of the drywell vessel is removed during refueling operations.

The drywell head is held in place by bolts and is sealed with a double seal arrangement to provide primary containment integrity. The top head closure is made with a double tongue and groove seal that permits periodic checks for tightness without pressurizing the entire vessel.

L-MT-1 6-001 Page 6 of64 Eight large circular vent lines form a connection between the drywell and the pressure suppression chamber. Jet deflectors are provided in the drywell at the entrance of each vent line to prevent possible damage to the vent pipes from jet forces which might accompany a pipe break in the drywell. The vent lines are enclosed with sleeves and are provided with expansion joints to accommodate differential motion between the drywell and suppression chamber.

4.1.2 Suppression Chamber The suppression chamber is in the general form of a torus which is below and encircles the drywell. The suppression chamber is actually constructed of 16 mitered cylindrical shell segments. A reinforcing ring girder with two supporting columns and a saddle is provided at the miter joint of the adjoining shell segments.

The suppreSsion chamber is connected to the drywell by eight vent lines.

Within the suppression chamber, the vent lines are connected to a common vent header. Connected to the vent header are 48 pairs of downcomers which terminate below the water level of the suppression pool. The vent lines are shielded from jet impingement loads at each vent line - drywell penetration location by jet deflectors which span the openings of the vent lines. A bellows assembly connecting the suppression chamber to the vent line allows for differential movement between the drywell and the suppression chamber.

Eight vacuum breakers are provided to equalize the pressure between the suppression chamber and the drywell to prevent a backflow of water from the suppression pool into the vent header system. Each vacuum breaker is an 18 inch check valve with an air operator provided for testing purposes. There is one breaker located at each of the vent-to-vent header positions. The vacuum breakers are designed to be full open at 0.5 psid.

Access from the Reactor Building to the suppression chamber is provided through two manholes with double-gasketed, bolted covers, which are bolted closed when Primary Containment integrity is required. A test connection is provided between the double gaskets on each cover to allow leak rate testing of the Torus hatches.

4.1.3 Piping Penetrations Pipe penetrations are of two general types, i.e., those that must accommodate thermal movement (hot), and those that experience relatively little thermal movement (cold). The fluid piping penetrations for which movement provisions are made are the high temperature lines such~as the steam lines, the feedwater lines, and certain other reactor auxiliary and Cooling system lines. These penetrations have a guard pipe between the hot line and the penetration nozzle

L-MT-1 6-001 Page 7 of 64 in addition to a double-seal arrangement. This permits the penetration to be vented to the drywell should a rupture of the hot line occur within the penetration.

The guard pipes are designed to the same pressure and temperature as the fluid line and are attached to a penetration head fitting, a one-piece forging with integral flues or nozzles. The penetration sleeve is welded to the drywell and extends through the biological shield where it is welded to a bellows which in turn is welded to the guard pipe. The bellows accommodates the thermal expansion of the drywell. The MNGP has bellows with both single and two ply designs. A double bellows arrangement permits leak testing of the penetration seal. The lines are constrained to limit the movement of the line relative to the containment, yet permit pipe movement parallel to the penetration.

Small bore lines which connect to high-pressure systems, such as instrument lines and ORD hydraulic lines, do not have a double-seal penetration sleeve.

These lines are either bunched in groups of six lines and welded in a single pipe sleeve or shop welded in large groups directly to the drywell plate. The mechanical problems involved with this number of small penetrations in a relatively small area make it impractical to provide individual penetration sleeves.

The pipes are designed to deflect with the drywell shell.

All pipes that penetrate the primary containment are welded to a containment sleeve with the sleeve welded to the containment shell. There is no direct weldment of the pipe to the containment shell.

4.1.4 Electrical Penetrations Electrical penetration seals were designed to accommodate the electrical requirements of the plant. These are functionally grouped into low voltage power and control cable penetration assemblies, high voltage power cable penetration assemblies, and shielded cable penetration assemblies. All canister type electrical penetration seals have essentially the same basic configuration. The assemblies are sized to be inserted in penetration nozzles which are furnished as part of the containment structure.

4.1.5 Plant Operational Considerations Relating to Containment Leakage The MNGP is a BWR/3 with a Mark I containment. During power operation, the primary containment atmosphere is inerted with nitrogen to ensure that no external sources of oxygen are introduced into containment. The containment inerting system is used during the initial purging of the primary containment early in power operation and provides a supply of makeup nitrogen to maintain primary containment oxygen concentration within TS limits. As a result, the primary containment is maintained at a slightly positive pressure during power operation.

Primary containment pressure is monitored in the control room. In the event pressurization does not occur, a leakage path may be present. Plant operators are aware of the implications of lack of pressurization during power operation.

L-MT-1 6-001 Page 8 of64 Administrative controls and alarms have been established to monitor containment depressurization activities and evaluate trends (e.g., frequency, duration) for indication of changes to containment leakage.

4.1.6 Containment Heat Removal and Emergency Core Cooling System Net Positive Suction Head Performance On December 9, 2013, the NRC approved License Amendment No. 176 for the MNGP which increased the maximum licensed thermal power by approximately 13 percent, from the previous licensed thermal power of 1,775 MWt to 2,004 MWt (Reference 8). As part of EPU development the accidents and license basis events were re-evaluated. Net Positive Suction Head (NPSH) analyses were performed for the DBA-LOCA; and for the following four non-design basis events: Small Steam Line Break Accident (SBA), Appendix R Fire, Anticipated Transient Without Scram (ATWS), and Station Blackout (SBO).

For plants crediting containment accident pressure to maintain NPSH margin for emergency core cooling system (ECCS) pump performance, maintenance of containment integrity is required to meet the assumptions of the safety analyses.

Containment accident pressure (CAP)(3 ) was applied for the NPSH available (NPSHa) analysis for operation of the low-pressure Residual Heat Removal (RHR)( 4) and Core Spray (CS) pumps under EPU conditions in the MELLLA+ (5) domain. The current NRC staff guidance on use of CAP contained in to NRC SECY-1 1-00 14, "The Use of Containment Accident Pressure in Reactor Safety Analysis," (Reference 9) was applied in performance of the analyses. Section 2.6.5 of the NRC Safety Evaluation (SE) for the EPU entitled, "Containment Heat Removal," discusses in great detail how the criteria specified in the SECY regarding NPSH were satisfied.

NRC SECY 11-0014, Section 6.6.7, "Assurance of no Pre-existing Leak",

requires consideration of a loss of containment isolation that could compromise containment integrity, e.g., containment venting required by procedures or loss of containment isolation from a postulated 10 CFR 50 Appendix R fire. To apply the SECY's guidance it is required to determine the minimum containment leakage rate sufficient to lose the CAP needed for adequate NPSH margin. Second, a method to determine whether the actual containment leakage rate exceeds this leakage rate is required. For inerted containments, this method could consist of a periodic quantitative measurement of the nitrogen makeup performed at an appropriate frequency to ensure that no unusually large makeup of nitrogen o ccu rs.

3.

The previous DBA-LOCA licensing basis analysis also credited CAP in the determination of adequate NPSHa at the suction inlet of the RHR and CS pumps.

4.

The Low Pressure Coolant Injection (LPCI) mode for ECCS is provided by the RHR pumpls.

5.

MELLLA+ stands for Maximum Extended Load Line Limit Analysis - Plus, which is an operating domain on the power-flow map.

L-MT-1 6-001 Page 9 of 64 As stated in SE Section 2.6.5, for "on-line containment leakage monitoring, the licensee has proposed a procedure for detection of a large containment integrity failures where consideration of instrument uncertainty is not necessary." To provide assurance that a leak could be detected that could challenge containment integrity a methodology was developed and accepted consisting of (a) an on-line leakage test that determines the containment leakage rate during power operation, and (b) an on-line monitoring of the parameters on which the operator currently relies to determine abnormal containment leakage conditions.

Technical Requirements Manual (TRM) Specification 3.6.3.2, "Online Containment Leakage Check", was developed to perform an online (Mode 1) containment leakage test to determine the containment leakage rate during power operation. This leakage rate test is performed once-per-cycle, after an outage at the beginning of a new operating cycle when the plant is stabilized at full power. This online containment leakage rate test is a quantitative measurement of the nitrogen (N2) makeup while the N2 system is operated with a known vent release rate for eight hours. The test makes use of a computer point that calculates the N2 gas mass inside the inerted primary containment. This quantitative leak rate test provides a baseline that would identify any significant change in the containment leakage rate at any time during power operation. The test is repeated at any time during the cycle if inputs monitored during normal operation warrant another measurement.

The on-line containment leakage test has been performed twice since EPU approval as shown below. These results exhibit significant margin to the acceptance criteria of 5.0 scfm established for the on-line leakage test.

August 5, 2013 1.290 scfm July 15, 2015 1.376 scfm Additionally, there are several control room inputs used for normal monitoring that can indicate an increase in the containment leak rate between performance of the online containment leakage check TRM surveillance.

• A computer point that continually calculates N2 mass in containment and provides a computer alarm if the N2 mass is too low or too high.

A control room annunciator that alarms on drywell high or low pressure.

A flow indicator that measures N2 flow in the supply to the containment air system.

L-MT-1 6-001 Page 10 of 64 The NRC SE (Section 2.6.5) for EPU with respect to this subject stated:

The licensee justified the continuous monitoring to ensure CAP is available by stating that the drywell continuous air monitor detection capability is less than 5 scfm. The leakage rate that could challenge the NPSH margin for the ECCS and containment heat removal pumps is greater than 228 scfm which is well above the leakage that can be detected by the proposed procedure.

The NRC staff considers the licensee's method to detect loss of containment integrity during power operation acceptable because the proposed on-line test at the beginning of the cycle along with on-line monitoring of the above parameters will ensure the availability of CAP so that NPSH margin is available for the ECCS and containment heat removal pumps during design basis and non-design basis accidents.

To provide insight on the risk associated with reliance on containment accident pressure for proper low-pressure ECCS and containment heat removal pump performance during certain design basis and non-design basis accidents, a detailed sensitivity study was performed as part of the risk assessment. The study is similar to one discussed in Appendix F of the EPU risk assessment, included in the EPU license amendment request (LAR). RG 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis and defines very small changes in risk as resulting in increases of Core Damage Frequency (CDF) of less than 1.0E-06/year. Since the MNGP relies on containment accident pressure for ECCS NPSH during certain design basis accidents, extending the ILRT interval could impact CDF. The MNGP PRA model was used to estimate the potential change in CDF if containment accident pressure was unavailable due to a pre-existing containment leak. The containment accident pressure sensitivity study contained in Enclosure 2, Section 5.3.4 conservatively estimates that the potential increase in the overall CDF would be 9.83E-08, which is "very small" using the acceptance guidelines of RG 1.174.

4.2 Justification for the Proposed Technical Specification Change The following subsections provide a discussion of 10 CFR 50, Appendix J testing requirements, reviews the MNGP Primary Containment leakage licensing history and requirements, and reviews the MNGP ILRT test results.

4.2.1 Chronology:.of Testing Requirements of 10 CFR 50, Appendix J The testing requirements of 10 CFR 50, Appendix J, provide assurance that the leakage from the primary containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified within the TS. Also, 10 CFR 50, Appendix J also ensures that periodic surveillance of reactor containment penetrations and isolation valves is

L-MT-1 6-001 Page 11 of 64 performed so that proper maintenance and repairs are made during the service life of the containment and the systems and components penetrating primary containment. The limitation on containment leakage provides assurance that the containment would perform its design function following an accident up to and including the plant design basis accident.

10 CFR 50, Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the overall integrated leakage rate of the primary containment; 2) Type B tests, intended to detect leakage paths and measure leakage across pressure containing or leakage limiting boundaries (other than valves) for primary reactor containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Type B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing.

In 1995, 10 CFR 50, Appendix J, was amended to add another approach, Option B, entitled "Performance-Based Requirements", for performance of containment leakage testing. Option B requires the test intervals for Type A, Type B, and Type C testing to be determined using a performance-based approach. Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. Use of the term "performance-based" within 10 CFR 50, Appendix J refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B.

Also, in 1995, RG 1.163 was issued endorsing NEI 94-01, Revision 0, with certain modifications and additions. 10 CFR 50, Appendix J, Option B, in concert with the regulatory guide and the NEI guidance allows a licensee with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the ILRT test frequency from three tests in 10 years to one test in 10 years. This relaxation was based on an NRC risk assessment provided in N U REG-1 493, "Performance-Based Containment Leak-Test Program" (Reference 10) and Electric Power Research Institute (EPRI) topical report TR-1 04285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals (Reference 11) both of which showed that the increase in risk associated with extending the ILRT surveillance interval was very small.

In 2008, NEI 94-01, Revision 2-A, was issued. The NR.C indicated in the SE for NEI 94-01, Revision 2-A, that this report describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. Section 4.0 of the NRC SE for NEI 94-01, Revision 2-A, provides specific limitations and conditions for utilization of the report.

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

L-MT-1 6-001 Page 12 of 64 RG 1.163 (September 1995). It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification for increasing the duration of the interval included industry performance data, plant-specific performance data, and risk insights.

In Subsection 3.1.1.2, "Deferral of Tests Beyond The 15-Year Interval," of the NRC SE for the NEI 94-01, Revision 2-A. the NRC staff provided the following guidance concerning the use of test interval extensions (which was later augmented by additional guidance in Regulatory Issue Summary (RIS) 2008-27 (Reference 1 2)):(6)

..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 [topical report] NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRC staff that an unforeseen emergent condition exists.

In July 2012, NEI 94-01, Revision 3-A was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CER 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SEs dated June 25, 2008 (Reference 13) and June 8, 2012 (Reference 14) as an acceptable methodology for complying with the provisions of Option B to 10 CFR 50, Appendix J. The regulatory positions stated in RG 1.163 as modified by NRC SEs dated June 25, 2008 and June 8, 2012 are incorporated in this document. It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification of extending test intervals is based on the performance history and risk insights.

Extensions of Type B and Type C test intervals are allowed based upon completion of two consecutive periodic as-found tests where the results of each test are within a licensee's allowable administrative limits. Intervals may be increased from 30 months up to a maximum of 120 months for Type B tests (except for containment airlocks) and up to a maximum of 75 months for Type C tests. If a

6.

RIS 2008-27, "Staff Position on Extension of the Containment Type A Test Interval Beyond 15 Years Under Option B of Appendix J to 10 CFR Part 50."

L-MT-1 6-001 Page 13 of 64 licensee considers extended test intervals of greater than 60 months for Type B or Type C tested components, the review should include the additional considerations of as-found tests, schedule and review as described in NEI 94-01, Revision 3-A, Section 11.3.2.

MNGP has evaluated the extended Type C intervals afforded by NEI 94-01, Revision 3-A and has chosen not to adopt NEI 94-01, Revision 3-A at this time.

4.2.2 Current MNGP Integrated Leakage Rate Testing Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licensees to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements."

On April 3, 1996 the NRC approved License Amendment No. 95 for the MNGP (Reference 15) authorizing the implementation of Option B for Type A tests.

On February 4, 2003, the NRC approved License Amendment No. 132 for the MNGP (Reference 16) authorizing the implementation of Option B for Type B and Type C tests. Current Specification 5.5.11 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of 10 CFR 50, Appendix J, Option B.

RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01, Revision 0, rather than using the test intervals specified in ANSI/ANS 56.8-1994. NEI 94-01, Section 11.0 refers to Section 9, which states that 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. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0 La (where La iS the maximum allowable leakage rate at design pressure). The elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months.

Adoption of 10 CFR 50, Appendix J, Option B performance based containment leakage rate testing program altered the frequency of measuring primary containment leakage in the Type A, B and C tests but did not alter the basic method by which Appendix J leakage testing is performed. The test frequency is based on an evaluation of the leakage history to determine a frequency for leakage testing which provides assurance that leakage limits will not be exceeded.

L-MT-1 6-001 Page 14 of 64 The allowed frequency for Type A testing as documented in NEI 94-01, Revision 0, is based, in part, upon a generic evaluation documented in NUREG-1493. The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing types of containment types, including a containment design( 7 ) similar to the MNGP's containment structure. NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests from the original three tests per 10 years to one test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between performance of ILRTs is possible with a minimal impact on public risk.

4.2.3 MNGP 10 CFR 50, Appendix J, Option B Licensing History License Amendment No. 95 (April 3. 1996)

This amendment revised (1) the main steam line isolation valve (MSIV) leakage rate test acceptance criterion in the custom TS to be based upon the combined maximum flow path leakage for all four main steam lines of 46 standard-cubic-feet-per-hour (scfh) in lieu of the then current limit of 11.5 scfh per valve; (2) the operability test interval for the drywell spray header and nozzles from five to ten years; and (3) Specification 3/4.7.a.2, "Primary COntainment Integrity", to remove information specific to the primary containment leakage rate testing program and to adopt the requirements of 10 CFR 50, Appendix J, Option B, Section Ill.A, for Type A testing. Type B and C testing continued to be performed in accordance with 10 CFR 50, Appendix J, Option A.

License Amendment No. 132 (February 4, 2003)

Specification 3.7/4.7, "Containment Systems", in the custom TS was revised to permit use of 10 CFR 50, Appendix J, Option B, for Type B and Type C containment leak rate testing and added a new Specification 6.8.M, "Programs and Manuals - Primary Containment Leakage Rate Testing Program".

License Amendment No. 134 (March 31.,2003)

Surveillance Requirement 4.7.A.2.b, "Primary Containment Integrity", in the custom TS was revised to permit a one-time, five-year extension to the ten-year interval for performing a Type A containment ILRT (Reference 17). This allowed

7.

The Peach Bottom nuclear power plant is a BWR/3 plant with a Mark I containment design, the same as the MNGP.

L-MT-1 6-001 Enclosure I Page 15 of 64 the test to then be performed no later than 15 years from the date of the last ILRT, which had been performed in March 1993.

License Amendment No. 148 (December 7, 2006)

This amendment revised the MNGP licensing basis to incorporate a full-scope alternative source term (AST) methodology (Reference 18). Specification 5.5.11 was revised to exclude main steam line (MSL) pathway leakage contributions from the overall integrated leakage rate for Type A tests and to exclude MSL pathway leakage contributions from the sum of the leakage rates for Type B and Type C tests. Exemptions to Section lll.A and Section IlI.B of 10 CFR 50, Appendix J, Option B, were received in conjunction with approval of this license amendment (Reference 19). The MSL pathway includes the combined leakage through the eight MSIVs and through two primary containment isolation valves (PCIVs), which isolate the inboard MSIV drain lines, which is quantified by summing the leakage from Type C tests for these valves. This leakage is separate, and in addition to, the primary containment leakage limit of 1.2 percent per day, i.e., La, at a primary containment accident pressure.

License Amendment No. 176 (December 9, 2013)

The EPU license amendment increased the maximum licensed thermal power level by approximately 13 percent, from a previous level of 1,775 MWt to 2,004 MWt (Reference 8). The primary containment accident pressure specified in the TS increased from 42.0 psig to 44.1 psig.

License Amendment No. 187 (January 8, 2015)

This amendment removed a requirement for reduced pressure drywell airlock door seal testing, since this capability is not required and does not reflect the design of the airlock at MNGP. The acceptance criteria specified in Specification 5.5.11.d.2.b for testing between the airlock door seals were removed, and the drywell airlock door seals are tested solely by performance of an overall airlock leakage test as currently specified in Specification 5.5.11 l.d.2.a (Reference 20).

4.2.4 MNGP Integrated Leakage Rate Testing History As noted previously, Specification 5.5.11 currently requires that Type A, Type B, and Type C testing be performed in accordance with RG 1.163, which endorses the methodology for complying with Option B of 10 CFR 50, Appendix J. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing. The total Type A ILRT test history is provided in the following two tables. The first table provides the historical Type A test results from the time of initial licensing up to the May 1980 Type A test performance. In June 1984, the NRC approved the NSPM implementation of 10 CFR 50, Appendix J (Reference 21). The second table

L-MT-1 6-001 Page 16 of64 provides the last four performances of the Type A ILRT tests, after NRC approval of the 10 CFR 50, Appendix J Program for the MNGP.

Historical MNGP Type A ILRT Results Test ompltionDateLeakage Rate(4)

Test ompltionDate(weight-percent/day)

February 1968 0.0366 (Pre-Operationai)

July 1970 0.4370 May 1973 0.6406 May 1974(1) 0.2520 November 1975(2) 0.2456 November 1977 0.2488 March 1 980(3 May 1980 0.6324 (1) During the ILRT, leakage was observed from the vent port of the three-way solenoid valve that controls the air supply to the test operator for torus-to-drywell vacuum breaker "G". The leakage, at 41 psig, was found to be approximately 3.0 weight percent of the contained air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Following a torus entry, it was confirmed that the 3/8 inch air supply tubing for the test operator had been left uncapped when the "G" vacuum breaker had been removed for testing. It was not recognized that the air supply line and solenoid valve provided a leakage path.

(2) A defective Traversing Incore Probe ball valve on the number three line resulted in an initially measured leakage rate of approximately 1.5 weight-percent/day. The leaking valve was closed and the test satisfactorily completed.

(3) The March 1980 test was not accepted by the NRC and the test was successfully repeated in May 1980.

(4) All performances of the ILRT were performed at full test pressure, Pa, established as the licensing basis as of the date of performance.

The results of the last four Type A ILRTs for the MNGP are shown in the following table. The As-Found leakage for the four Type A test performances are well within the maximum allowable containment (As-Found) leakage rate specified in the TS of 1.2 weight-percent/day. Therefore, the requirement to demonstrate an acceptable performance history in order to place a plant on an extended interval in accordance with NEI 94-1, Revision 2-A, (i.e.,,successful completion of two consecutive periodic Type A tests) has been consecutively met over the last several ILRT test intervals. As a result, the MNGP is eligible to be

L-MT-1 6-001 Page 17 of 64 placed on an extended ILRT frequency (performance of a Type A test at least once per 15 years). The current ILRT interval frequency for the MNGP is once per 10 years.

MNGP Type A ILRT Results As-Found As-Left Test (weight-percent/da)

(weight-percent/day)

Completion Date~1 )

Leakage TS Acceptance Leakage TS Acceptance Rate Criteria Rate Criteria December 1984 0.7222,1.2 0.5484 0.9 October 1989 0.6183 1.2 0.5354 0.9 March 1993 0.8240 1.2 0.3943 0.9 April 2007 0.7323 1.2 0.6484 0.9 (1) All performances of the ILRT were performed at full test pressure, Pa, established as the licensing basis as of the date of performance.

4.3 Plant Specific Confirmatory Analysis 4.3.1 Methodology An evaluation has been performed to provide a risk assessment of permanently extending the currently allowed containment Type A ILRT from 10 to 15 years.

The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages for the MNGP. The risk assessment followed the guidelines from the following:

NEI 94-01 Revision 2-A,

• Methodology of EPRI TR-1 04285, NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" October 2001 (Reference 22),

NRC regulatory guidance on use of PRA as stated in RG 1.200 as applied to ILRT interval extensions,

• Risk insights in support of a request for a plant licensing basis change as "outlined in RG 1.174, Methodology applied by Calvert Cliffs to estimate likelihood and risk implications of corrosion-induced leakage of the steel liners going undetected during the extended test interval (from Reference 23),

Methodology applied in EPRI TR-1018243 (Reference 24), Revision 2-A of EPRI TR-1 009325 (Reference 25).

L-MT-1 6-001 Page 18 of 64 NEI 94-01, Revision 2-A includes a SE that supports using EPRI TR-1 009325, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals",

Revision 2-A for performing risk impact assessments in support of ILRT extensions. Appendix H, "Risk Impact Assessment Template," within this report illustrates the types of information that should be included in a plant-specific confirmation of risk impact associated with the extension of ILRT intervals. The methodology within this EPRI report builds on previous work performed in EPRI TR-1 04285 and NUREG-1493. This methodology was followed to determine the appropriate risk information for use in evaluating the impact of the proposed ILRT changes.

The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from containment leak rate testing. In that analysis, it was determined for a representative BWR plant (i.e., Peach Bottom), that increasing the containment leak rate from the nominal 0.5 percent per day to 5 percent per day leads to a barely perceptible increase in total population exposure, and increasing the leak rate to 50 percent per day increases the total population exposure by less than 1 percent. In fact, NUREG-1 493 states, "Reducing the frequency of Type A tests (ILRTs) from the current three per 10 years to one per 20 years was found to lead to imperceptible increase in risk." Therefore, it is desirable to show for the MNGP that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures to support a reduction in the test frequency for MNGP.

Since the publication of NUREG-1493, additional containment inspections are now performed at all nuclear power plants (ASME Code Section Xl Subsections IWE and IWL( 8)), and historical integrated and local leak rate testing performance has been good. Using newer methods and additional data, EPRI TR-1 009325 demonstrated that the conclusions of NUREG-1493 remain valid.

EPRI TR-1 009325, Revision 2, was determined acceptable for referencing by licensees proposing to amend their TS to extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the SE.

The following table addresses each of the four limitations and conditions for use of the EPRI topical report.

8.

ASME Section XI, Subsection IWE, "Requirements for Class MC and Metallic Liners of

'"Class CC Components of Light-Water Cooled Plants and Subsection IWL," and "Requirements for Class CC Concrete Components of Light-Water Cooled Plants,"

respectively.

L-MT-1 6-001 Page 19 of 64 EPRI Topical Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition (From Section 4.2 of SE)

MNGP Response 1.The licensee submits documentation MNGP PRA technical adequacy is addressed in indicating that the technical adequacy Section 4.3.2 of this LAR and Enclosure 2, of their PRA is consistent with the "Monticello Nuclear Generating Station:

requirements of RG 1.200 relevant to Evaluation of Risk Significance of Permanent the ILRT extension application.

ILRT Extension," Appendix A, "PRA Technical Adequacy."

2.a The licensee submits documentation RG 1.174 defines very small changes in risk indicating that the estimated risk as resulting in increases of CDF less than increase associated with permanently 1.0E-06/year and increases in LERF less than extending the ILRT surveillance 1.0E-07/year. Since the MNGP relies on interval to 15 years is small, and containment accident pressure for ECCS NPSH consistent with the clarification during certain design basis accidents, provided in Section 3.2.4.5 of this SE.

extending the ILRT interval may impact CDF.

The MNGP PRA model was used to estimate the potential change in CDF if CAP was unavailable due to a pre-existing containment leak. The CAP sensitivity study performed in, Section 5.3.4 conservatively estimates that the potential increase in the overall ODE would be 9.83E-08, which is "very small" using the acceptance guidelines of RG 1.174. The increase in LERF resulting from a change in the Type A ILRT test interval from three in 10 years to one in 15 years is estimated as 6.51 E-08/year using the EPRI guidance (this value increases negligibly if the risk impact of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is included).

As such, the estimated change in LERF is determined to be "very small" using the acceptance guidelines of RG 1.174.

L-MT-1 6-001 Page 20 of 64 EPRI Topical Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition (From Section 4.2 of SEI MNGP Resoonse f

I......

2.b 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.

The effect resulting from changing the Type A test frequency to once per 15 years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 0.064 person-rem/year.

EPRI TR-1 009325, Revision 2-A states that a very small population dose is defined as an increase of less than or equal to 1.0 person-rem per year, or less than or equal to 1 percent of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria. The increase in total integrated plant risk of 0.064 person-rem/year is much less than the 1.0 person-rem per criteria defined as a small increase in population dose. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible.

2.c in addition, a small increase in The increase in the CCFP from the three in

[Conditional Containment Failure 10 year interval to one in 15 year interval is Probability] CCFP should be defined 0.812 percent. EPRI TR-1 009325, Revision as a value marginallygreater than that 2-A states that increases in CCFP of less than accepted in previous one-time 15-year or equal to 1.5 percent is very small.

ILRT extension requests. This would require that the increase in CCFP be less than or equal to 1.5 percentage point.

3.

The methodology in EPRI Topical The representative containment leakage for Report No. 1009325, Revision 2, is Class 3b sequences used by MNGP is 100 La, acceptable except for the calculation of based on the recommendations in the latest the increase in expected population EPRI report and as recommended in the NRC dose (per year of reactor operation). In SE on this topic. It should be noted that this is order to make the methodology more conservative than the earlier previous acceptable, the average leak rate industry ILRT extension requests, which utilized accident case (accident case 3b) used 35 La for the Class 3b sequences.

by the licensees shall be 100 La instead of 35 La.

L-MT-1 6-001 Page 21 of 64 EPRI ToPical Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition (From Section 4.2 of SE)

MNGP Response

4.

A licensee amendment request LAR is Containment overpressure is required for required in instances where ECCS performance and was re-approved for containment over-pressure is relied use in License Amendment No. 176 for the upon for ECCS performance.

MNGP EPU on December 9, 2013. Subsection 4.1.6 of this enclosure summarizes the current licensing basis for application of containment accident pressure under EPU. This is discussed in Subsection 4.3.3 as part of the summary of plant-specific results via reference to a sensitivity study conducted as part of the risk-assessment (see Enclosure 2).

4.3.2 Technical Adequacy of the MNGP Probabilistic Risk Assessment a) Internal Events PRA Quality Statement for Permanent 15-Year ILRT Extension The MNGP internal events PRA model (Revision 3.2) was used to calculate the CDF and the LERE for the proposed permanent 15-year ILRT extension.

Any elements of the supporting requirements detailed in ASME/ANS RA-Sa-2009 that could be significantly affected by the application are required to meet Capability Category II requirements.

The internal events PRA provides an adequate base model for the development of the permanent 15-year ILRT extension. The MNGP PRA Peer Review was performed in April 2013 applying the NEI 05-04, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," process, the ASME PRA Standard (ASME/ANS RA-Sa-2009) and RG 1.200, Revision 2. The purpose of this review was to provide a method for establishing the technical adequacy of the PRA for the spectrum of potential risk-informed plant licensing applications for which the PRA may be used. The 2013 MNGP PRA Peer Review was a full-scope review of the Technical Elements of the internal events and internal flood, at-power PRA.

The ASME PRA Standard has 325 individual Supporting Requirements (SRs) for the Internal Events At-Power PRA (Part 2), and Internal Flood At-Power PRA (Part 3). The MNGP Peer Review included all of these SRs. Twelve of the SRs were judged to be not applicable. Of the remaining 313 ASME PRA Standard SRs, 93 percent are supportive of Capability Category II or greater.

L-MT-1 6-001 Enclosure I Page 22 of 64 to this LAR, Appendix A, Section A.3 presents an assessment of all ASME/ANS PRA Standard RA-Sa-2009 SRs that were assessed to be "Not Met" at Capability Category II in the 2013 MNGP PRA Peer Review or were assessed to be "Met" but had related Findings. Findings and Observations (F&Os) from the 2013 MNGP PRA Peer Review have been resolved. Therefore, the MNGP Internal Events PRA was judged to meet Capability Category II consistent with RG 1.200 guidance.

b) Fire PRA Quality Statement for Permanent 15-Year ILRT Extension The MNGP Fire Probabilistic Risk Assessment (FPRA) Peer Review was performed March 2-6, 2015, applying the NEI 07-12, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines," process, the ASME PRA Standard (ASME/ANS RA-Sa-2009) and RG 1.200, Revision 2. The purpose of this review was to establish the technical adequacy of the FPRA for the spectrum of potential risk-informed plant licensing applications for which the FPRA may be used. The 2015 MNGP FPRA Peer Review was a full-scope review of all of the Technical Elements of the MNGP at-power January 2015, Revision Ia, Fire PRA against all Technical Elements in Section 4 of the ASME/ANS Combined PRA Standard, including the referenced internal events SRs in Section 2.

The FPRA Peer Review team consisted of six team members, with extensive qualifications in all areas of FPRA as required by NEI 07-12 and one working observer. The team members experience averaged over 20 years in PRA or Fire Protection, with extensive experience in FPRA, the FPRA Section of the Standard, and NUREG/CR-6850, "EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities" (Reference 26).

The Fire PRA Section of the ASME PRA Standard has 182 individual SRs, and references 237 individual SRs in the internal events PRA section of the Standard; the MNGP Peer Review included all of the SRs and all applicable reference SRs. For the assessment of the reviewed ASME PRA Standard SRs, 102 unique Facts and Observations (F&Os) have been generated by the Peer Review team, 73 were peer review Findings, 28 were Suggestions, and one was considered a best practice. Enclosure 2 to this LAR, Appendix A, Section A.4, presents the Findings and their resolutions. There were no "Unreviewed Analysis Methods" identified during the review.

Therefore, the technical adequacy of the FPRA with respect to applying it to extend the IL-RT test frequency on a permanent basis to fifteen years has been determined to be acceptable.

L-MT-1 16-001 Page 23 of 64 4.3.3 Summary of Plant-Specific Risk Assessment Results The findings of the MNGP Risk Assessment contained in Enclosure 2 confirm the general findings of previous studies that the risk impact associated with extending the ILRT interval from three in ten years to one in fifteen years is very small. The MNGP plant-specific results for extending JLRT interval from the current ten years to fifteen years are summarized below:

Based on the results from Enclosure 2, Section 7.0, "Conclusions," and the sensitivity calculations presented in Enclosure 2, Section 5.3 "Sensitivities", the following conclusions regarding the assessment of the plant risk associated with permanently extending the Type A ILRT test frequency to fifteen years are as follows:

• RG 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of ODE of less than I1.0E-06/year. Since the MNGP relies on containment accident pressure (CAP) for EGOS NPSH during certain design basis accidents, extending the ILRT interval may impact ODE. The MNGP PRA model was used to estimate the potential change in CDF if CAP was unavailable due to a pre-existing containment leak. The CAP sensitivity study performed in, Section 5.3.4 conservatively estimates that the potential increase in the overall ODE would be 9.83E-08, which is very small using the acceptance guidelines of RG 1.174.

• RG 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of LERF of less than 1.0E-07/year. The increase in LERF resulting from a change in the Type A ILRT test interval from three in 10 years to one in 15 years is estimated as 6.51 E-08/year using the EPRI guidance (this value increases negligibly if the risk impact of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is included).

As such, the estimated change in LERF is determined to be very small using the acceptance guidelines of RG 1.174.

• The effect resulting from changing the Type A test frequency to once per 15 years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 0.064 person-rem/year.

EPRI TR-1 009325, Revision 2-A states that a very small population dose is defined as an increase of less than or equal to 1.0 person-rem per year, or less than or equal to 1 percent of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible.

L-MT-1 6-001 Enclosure I Page 24 of 64

• The increase in the conditional containment failure probability from three in a 10-year interval to one in a 15-year interval is 0.812 percent. EPRI TR-009325, Revision 2-A states that increases in CCFP of less than or equal to 1.5 percent is "very small". Therefore, this increase is judged to be "very small."

Therefore, increasing the ILRT interval from 10 years to 15 years is considered to be insignificant since it represents a "very small" change to the MNGP risk profile.

4.3.4 Previous Assessments The NRC in NUREG-1 493 has previously concluded that:

• Reducing the frequency of Type A tests (ILRTs) from three per 10 years to one per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.

• Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage-rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond one in 20 years has not been evaluated. Beyond testing the performance of containment penetrations, ILRTs also test the integrity of the containment structure.(9 )

The findings for MNGP confirm these general findings on a plant-specific basis considering the severe accidents evaluated, the containment failure modes, and the local population surrounding the MNGP.

Details of the MNGP risk assessment are contained in Enclosure 2 of this submittal.

4.4 Non-Risk Based Assessment Consistent with the defense-in-depth philosophy discussed in RG 1.174, the NSPM has assessed other non-risk based considerations relevant to the proposed amendment.

There are multiple inspections and testing programs at the MNGP that ensure the containment structure remains capable of meeting its design functions and that are designed to identify any degrading conditions that might affect that capability. These programs are discussed below.

9.

Type A tests serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing.

L-MT-1 6-001 Page 25 of 64 4.4.1 Containment lnservice Inspection Plan (IWE Plan)

On August 8, 1996, the NRC revised 10 CFR 50.55a, "Codes and Standards" to incorporate Subsections IWE and IWL( 1°) of Section XI of the ASME Code into the regulation by reference, as modified and supplemented by the provisions of 10 CFR 50.55a, for the inservice inspection, repair, and replacement of containment components.( 11 )

Subsection IWL (Concrete Containments) is NOT applicable to the MNGP.

Subsection IWE (Metal Containments) is applicable to the MNGP. The program addressing Subsection IWE is referred to as the Containment Inservice Inspection (CISI) Plan (IWE Plan). The First Interval, First Period IWE Plan examinations were performed during a five-year expedited implementation period and served as the "preservice examination" or baseline inspection. The second Subsection IWE inspection interval began September 9, 2009, and is scheduled to end September 8, 2018. The Second Interval IWE Plan is based on ASME Section XI, Subsection IWE, 2001 Edition with the 2003 Addenda as supplemented by the specific requirements set forth in 10 CFR 50.55a.

Other MNGP programs (listed below) interface with, and/or are used in conjunction with the IWE Plan to satisfy the requirements of Section Xl of the ASME Code and 10 CFR 50.55a.

• MNGP 10 CFR 50, Appendix J Primary Containment Leakage Rate Testing Program MNGP Inservice Inspection (ISI) Program MNGP ASME Section Xl Repair/Replacement (RIR) Program MNGP Nuclear Coatings Program The ASME XI Subsection IWE Examination Schedule for the First, Second, and as projected for the Third Interval is provided in the following table.

10.

ASME Section XI, Subsection IWE, "Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants and Subsection IWL," and "Requirements for Class CC Concrete Components of Light-Water Cooled Plants,"

respectively.

11.

Federal Register, Volume 61, No.154, Rules and Regulations page 41303, dated August 8, 1996 (effective September 9, 1996)." Specifically, Subsections IWE and IWL of the 1992 Edition of Section Xl of the ASME Code (with 1992 Addenda) were incorporated.

L-MT-1 6-001 Page 26 of 64 MNGP IWE Examination Schedule First Interval 1st Period(1) 9/9/1 998 through 9/8/2001 1R18 1998 1R19 2000 9/9/2001 through 9/8/2005 2nd Period 1 R20 2001 1R21 2003 1R22 2005 3rd Period(2 )

9/9/2005 through 9/8/2009 1R23 2007 1R24I 2009 Second Interval 1st Period( 3) 9/9/2009 through 9/8/2011 1R25 2011 9/9/2011 through 9/8/2015 2nd Period R621 1R26 2015 3rd Priod9/9/2015 through 9/8/2018 1 R28 2017 Third Interval 9/9/18 through 9/8/2021 lteod1 R29 2019 1R30 2021 9/9/202 1 through 9/8/2025 2nd Period1R123 1 R32 2025 3rd Priod9/9/2025 through 9/8/2028 1 R33 2027 (1) Period was extended earlier to April 2, 1998, as permitted in IWE-241 2(b) to allow the First Interval, 1st Period IWE examinations to coincide with the Cycle 18 RFO.

(2) As permitted by IWA-2430(d), the First Interval of the IWE Program was extended for one year. The interval extension was applicable through September 8, 2009.

(3) 1st Period of Second Interval was reduced by one year due to the one year used for the First Interval IWA-2430(d) extension.

L-MT-1 6-001 Page 27 of 64 Inaccessible Areas The MNGP was built prior to the implementation of the ASME Section XI examination accessibility requirements of IWA-1 500 and IWE-1 230 as recognized in 10 CFR 50.55a(g)(1). As a result, some containment components may not be fully accessible, or are inaccessible for examination.

As required by 10 CER 50.55a(b)(2)(ix)(A)(1), when conditions exist in Class MC accessible areas that could indicate the presence of, or result in degradation to Class MC inaccessible areas, the inaccessible areas must be evaluated for acceptability. No degraded or potentially degraded conditions have been identified or reported for inaccessible Class MC areas as a result of examinations for the CISI Plan.

NSPM has not needed to implement any new technologies to perform inspections of any inaccessible areas at the MNGP at this time. NSPM actively participates in various nuclear utility owners groups and on ASME Code committees to maintain cognizance of ongoing developments within the nuclear industry. Industry operating experience is also continuously reviewed to determine its applicability to the MNGP. Adjustments to inspection plans and adoption of new, commercially available technologies for examination of inaccessible areas of the containment would be explored and considered as part of these activities as they become available.

Class MC Component Examination Requirement Details The ASME Code Class MC boundaries subject to examination and testing are the containment structure and connecting penetrations, appurtenances and parts which form the Primary Containment leak-tight boundary. These are the:

• Drywell Shell

• Personnel Air Lock

• Drywell Head Assembly

• Equipment Access Hatch Drywell Vent System

• Control Rod Drive Hatch

• Drywell Head Access Hatch Bolted Connections

• Suppression Pool (Torus)

• Penetration Sleeves

• Suppression Pool Access Penetration Sleeves of Hatches Electrical Penetrations

• Moisture Barrier

• Class MC Component Supports(1)

(1) The Class MC Component Supports are examined under the ISI Program in accordance with ASME Section Xl, Subsection IWE.

L-MT-1 6-001 Enclosure I Page 28 of 64 Examinations include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, including pressure retaining bolting, wetted surfaces of submerged areas, the BWR vent system and the moisture barrier.

Examinations of Class MC components are performed using General Visual, Detailed Visual (VT-I), VT-I and VT-3 methods as applicable.

Containment Examination Containment VT-I and VT-3 examinations are performed by qualified and certified personnel using procedures written to the 2001 Edition with the 2003 Addenda of the Code and ASNT-CP-1 89, 1995 Edition. General Visual examination method requirements are found in IWE-2310, and as specified in 10 CFR 50.55a.

General Visual examination includes 100 percent of the accessible surface areas during each Inservice Inspection Period and requirements as modified by 10 CER 50.55a.

• General Visual (VT-3) examination of 100 percent of wetted surfaces of submerged areas is performed each interval.

• General Visual (VT-3) examination of 100 percent of BWR vent system accessible surface areas is performed each interval.

• General Visual examination to include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-to-metal interfaces which are not seal welded. Containment moisture barrier materials include caulking, flashing and other sealants used for this application. Also, 100 percent examination is required during each Inspection Period. Examination is performed to identify tears, cracks, or damage that permits moisture intrusion.

General Visual examination performed each period for El1.11 includes pressure retaining bolted connections. Once each interval, the pressure retaining bolted connections require examination using VT-3. Upon disassembly VT-3 examination is required.

L-MT-1 6-001 Enclosure I Page 29 of 64 2nd IWE Interval - Examination. Category E-A Component Area 1Examination Item Exam Period

_________________________________________________ Description Number Method Scheduled Examination Category E-A 1:

2 Drywell (DW), Torus, Vent Lines Accessible E1.11 GV X

X X

Bolting: VT-3 once each Interval Surface Areas VT-3 X

• VT3 if disassembled VT-3

• • VT-1 for flaws or VT-I degradation Torus, Downcomers Wetted E1.12 "GV (VT-3)

X Surfaces of Submerged Areas Vent Lines, Vent Header, BWR Vent El1.20 GV (VT-3)

X Downcomers System Accessible Surfaces Drywell Moisture E1.30 GV X

X X

Barrier Item Number As listed in ASME Code Section XI, Table IWE-2500-1, Category E-A Exam Method GV: General Visual GV (VT-3): VT-3 in lieu of General Visual for Items E1.12 and E1.20 (10 CFR 50.55a(b)(2)(ix)(G))

VT-3: in accordance with ASME Section XI, paragraph IWA-2200 (10 CFR 50.55a(b)(2)(ix)(F), (G), (H))

VT-I: in accordance with ASME Section Xl, paragraph IWA-2200 (10 CFR 50.55a(b)(2)(ix)(F), (G), (H))

Aucimented Inspections Containment surface areas that require successive, augmented examinations to monitor for changes of their condition are those evaluated as acceptable standards and were not corrected by repair/replacement or corrective measures.

Successive examinations have been performed, and many of the locations have shown no changes to the original condition, or components have had their

L-MT-1 6-001 Page 30 of 64 coatings repaired. Components that have not changed, or components where flaws or areas of degradation were corrected by repair/replacement or corrective measures do not require the successive augmented examinations of Table IWE-2500-1, Category E-C.

The ASME Code also has provisions to use ultrasonic thickness (UT) measurements on a gridded surface when an area requiring augmented examination is not accessible for visual examination. There are currently no components subject to this requirement.

Interval 2, Period 2 augmented examinations (Category E-C, Item 4.11), located on submerged areas of the torus shell and vent system downcomers, were completed in the 2013 RFO. During the 2013 inspections instances of change from the prior inspection were noted. Instances of additional degraded coatings, as well as rusting, pinpoint rusting, and bare substrate were reported. Interval 2, Period 3 examinations will occur during the 2017 RFO.

2nd IWE Interval - Examination Category E-C Component Area 1Examination Item Exam Period Description Number Method Scheduled Examination Category E-C1 2

3 Drywell, Vent System Visible Surface E4.11 DV (VT-I)

X Torus Vapor Phase / Vent Visible Surface E4.11I DV (VT-I)

X System Torus Below Waterline Visible Surface E4.11 DV (VT-I)

X X

X Torus, Vent System Visible Surface E4.11I DV (VT-I)

X X

X Downcomers Drywell, X-1 Bolting Visible Surface E4.1l DV (VT-I)

X N/A Surface Area E4.12 UTT Grid Minimum Wall Thickness Location Item Number As listed in ASME Code Section XI, Table IWE-250(0-1, Category E-C Exam Method DV (VT-I): VT-I performed in lieu of Detail Visual for Item E4.11I (10 CFR 50.55a(b)(2)(ix)(G))

VT-I" in accordance with ASME Section Xl, paragraph IWA-2200 (10 CFR 50.55a(b)(2)(ix)(F), (G), (H))

L-MT-1 6-001 Page 31 of 64 UTT: Ultrasonic Thickness Test in accordance with ASME Section V, T-544 Pressure Testinq Requirements If repair/replacement activities of ASME Section Xl, Subsection IWA-4000 become necessary on Class MC components, as authorized by the Fifth Interval 131 Plan Relief Request RR-007 (Reference 27), post repair/replacement pressure test requirements for components and parts of the pressure retaining boundary shall comply with the requirements of the 2007 Edition including the 2008 Addenda of ASME Section Xl, Subsection IWE-5000, as well as all applicable conditions in 10 CFR 50.55a for post-repair/replacement pressure testing of Class MC components.

Personnel performing post repair/replacement pressure testing required by IWE-5000, Appendix J leak rate tests, are qualified in accordance with the MNGP Primary Containment Leakage Rate Testing Program.

10 CFR 50.55a Requests There were no 10 CFR 50.55a requests required for the Second Interval, Containment ISI Plan (IWE Plan). However, 10 CFR 50.55a request RR-007 for the Fifth Interval ISI Plan authorizes use of the 2007 Edition of ASME Section Xl with the 2008 Addenda for repair/replacement activities on Class MC components, including the post repair/replacement pressure testing requirements of IWE-5000.

Significant Containment Inspection Related Historical Summary These inspections, repairs and modifications occurred prior to the official implementation of the MNGP IWE Plan, but provided a baseline containment condition. The following discussion illustrates some of the actions NSPM has taken to ensure that uninspectable areas of containment have retained their integrity and are not in a degraded state that would allow leakage through the containment boundary.

a) Plant Life Extension Proqram Testingq Prior to implementation of the IWE Plan, activities relating to plant life extension were undertaken. As part of this, Drywell shell ultrasonic wall thickness measurements were taken as part of the Plant Life Extension (PLEX) Program in 1986 and 1987. Concrete was removed at the concrete-to-shell interface at the 920'-6" elevation for UT measurements. The location corresponds to the exterior sand pocket region. The results of the Drywell shell thickness measurements ranged from 1.072 to 1.107 inch. The minimum design thickness for this Drywell shell area is 1.0 inch. Some minor interior corrosion was detected at the interface of the concrete floor and the

L-MT-1 6-001 Page 32 of 64 Drywell shell. The minor corrosion was cleaned and removed. No thinning of the exterior portion of the Drywell shell was detected.

b) Sand Pocket Examination Following the Oyster Creek Nuclear Station event (see Subsection 4.5.1 -

GL 87-05) the outlets for the sand pocket drains and the air gap drains were inspected at the MNGP. One sand pocket drain was found to be partially obstructed by deposits of calcium carbonate in the standpipe region of the drain line. The partial obstruction was attributed to be from the drying of the sand pocket during construction and not from leakage during operation. All other drain lines were unobstructed. Additional qualitative testing determined that the Drywell air gap drain lines from inlet to outlet were unobstructed using compressed air to establish a flow through each drain line. To ensure the drain line outlets are not obstructed, the plant procedure for filling the reactor well includes a prerequisite to inspect the sand pocket and the air gap drain outlets prior to flooding the refueling area.

MNGP operating history has shown no evidence of refueling seal leakage, and no water was observed in the air gap during construction. Plant engineering and maintenance personnel confirmed the absence of leakage at the Drywell air gap drains and the sand pocket drains. The ongoing IWE inspection and monitoring activities, and the plant features that monitor for leaks past the refueling bellows during refueling (i.e., local light indicator and Control Room panel alarm), adequately manage aging effects to ensure no loss of intended function.

c) 1996 RFO During this outage, the Drywell moisture barrier was repaired. In anticipation of implementing the new ASME Section XI IWE requirements, spot thickness UT readings were taken at approximately seven locations along the floor to wall interface (concrete to metal) of the interior circumference of the Drywell after defective areas of the moisture barrier were removed. In each area two readings were taken, one in the area of the corrosion and one right above it approximately 3 inches out of the corrosion zone (to provide a baseline as to the non-corroded metal thickness). Results showed that the most severe wall loss was only 0.057 inches. In several areas the difference between the reading taken on the corroded surface versus and the non-corroded surface varied only slightly and some did: not vary at all.

L-MT-1 6-001 Page 33 of 64 d) 1997 Maintenance (ECCS Suction Strainer Installation) Outag~e The ECCS suction strainer modification outage started on May 9, 1997, and was completed on July 31, 1997. Also, the drywell shell-to-basemat moisture barrier was replaced and pre-service IWE examinations were performed on the new barrier.

Current Containment ISI Performance In the period of time since the ASME Section Xl IWE Program for inservice inspection of the MNGP metal containment was implemented, there have been no substantial indications of degradation that would impact the structural integrity of Primary Containment.

Many of the "indications" noted during inspections early on were related to coatings issues that didn't impact the metal substrate, for example scrapes, flaking, peeling, chipping, discoloration, etc. However, there were other areas of reported surface corrosion and rusting, including a few instances where minor pitting was identified. When arc strikes have been identified, they were either removed and the area was examined, or they were determined to be superficial, examined, and left as-is.

Areas of degraded coatings with related corrosion-like indications, such as rust staining and surface rust have been reported in the high humidity or wetted areas on the internal surfaces of the suppression chamber (torus) and the portion of the vent system downcomers near or below the waterline. The downcomers have indications resulting from past welded modifications that still have degraded coatings with minor surface rust and adjacent rust staining as a result.

Indications are evaluated each outage, including minor pitting, and have been determined to be acceptable. No conditions indicative of degradation or potential degradation in inaccessible areas have been identified.

Numerous areas with degraded coatings have been recoated to eliminate the conditions that led to initial reporting under the IWE Program, including extensive coating repairs to the torus shell interior while drained in the 2007 RFO, and additional underwater coating repairs made during the 2013 REQ.

The most recent IWE examinations were performed during the 2013 REQ in accordance with the requirements of Table IWE-2500-1, Categories E-A and E-C for Period 2 of the 2nd IWE Interval. No new [WE indications were noted during REQ 26 as a result of coating inspections and General Visual inspections in the drywell, vent system (above the waterline) and torus (above the waterline);

however, there were some new or changed areas of coating degradation identified in the torus and vent system (downcomers) below the waterline with

L-MT-1 6-001 Page 34 of 64 nine areas of noted interest for IWE: rust with minor pitting was reported on seven components (e.g., shell plate) of the torus shell, a legacy arc strike and a random weld bead were identified during surface preparation for underwater coating repairs. A summary of the conditions identified are described below.

a) Drywell General Visual examination was performed of accessible interior Drywell for structural problems and for compliance with ASME Section Xl, Subsection IWE code requirements. No issues were identified. VT-3 examinations were performed on the disassembled bolted connections for the Drywell Equipment Hatch, the Control Rod Drive Hatch and the Drywell Head Manway. All connections were satisfactory.

The drywell basemat-to-shell moisture barrier was examined and is in good condition with no evidence of deterioration.

Corrosion on the Drywell, as in previous outages, was negligible.

b) Torus General Visual, VT-3, and VT-I exams were performed, as applicable, on the Torus interior above and below the waterline.

Areas on the torus shell components examined under Category E-C, Item E4.11I showed no changes from their previous examination, and, per IWE-2420(c), no longer require augmented examination.

For other areas examined for Category E-A, new indications on the torus shell were noted during this outage that will require re-inspection in the next IWE inspection period in accordance with IWE-2420(b). The examiners identified new or changed areas of bare metal, some with magnetite or light surface rust, and also new or changed amounts of degraded coatings with pinpoint rust. Bare metal areas of the torus had tightly adherent magnetite films or light surface rust.

These films are of negligible thickness (small fractions of a mil). Tightly adherent magnetite films limit the formation of additional corrosion product. Given that corrosion product thickness is a multiple of the corroded substance, only a negligible quantity of steel is lost in the formation of these films.

Areas of minor pitting were reported on seven torus shell components (e.g., shell plates). The deepest measured pit noted during the RFO 26 inspection on the underwater portion of the torus shell was substantially below the pit depth limit.

The shallow depth of pits and the presence of thin oxide films indicates that pitting and general corrosion in the low oxygen-pure water environment of the MNGP torus is proceeding at a very slow rate. Each of these noted areas were acceptable and were marked for coating repair.

L-MT-1 6-001 Enclosure I Page 35 of 64 During coating repair activities, workers identified a legacy arc strike and a random weld bead on the torus shell. Surface preparation was performed, the areas were re-examined with VT-I, and no remaining unacceptable conditions were found. Each of these noted areas were acceptable and were marked for coating repair.

c) Vent System Detailed Visual (VT-I) examination was performed on downcomers below the water line for Category E-C, Item E4.11I due to degraded coatings and substrate conditions identified during previous outages. The majority of previous indications on the downcomers had no change noted from the previous exam.

However, new or changed indications of degraded coatings, larger areas of rust, and new bare substrate were noted on some of the downcomers. Based on visual inspection of the downcomers, none of the indications were severe enough to require pit depth measurement. Corrosion in the vent system, as in previous outages, was negligible. The downcomers will continue to be examined, as required under Category E-C, Item E4.1 1.

4.4.2 Nuclear Coatings Program The MNGP Nuclear Coatings Program(1 2 ) assures that safety-related DBA qualified coating systems (Service Level 1) are properly selected, applied, monitored and maintained so the coatings can perform their intended function*

Degraded coatings are controlled and tracked to ensure that the ECCS performance will not be adversely affected by the coating debris following an accident. The Engineering organization reviews and evaluates the results of coating condition examinations performed by qualified examiners. This program addresses the concerns of NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling System [ECCS] and the Containment Spray System After a Loss-of-Coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment" (Reference 28).

NSPM does not credit the program for the prevention of corrosion of carbon steel components. Inspection procedures specify that the coated surfaces be inspected for rust, flaking, peeling, blistering, cracking, delamination, physical damage, and checking.

Service Le.vel 1 coatings are used in areas inside the reactor containment where the coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown.

12.

Under the aging management umbrella it is referred to as the Protective Coating Monitoring & Maintenance Program (USAR Subsection K2.1.27) applying to Service Level 1 components.

L-MT-1 6-001 Page 36 of 64 Inspections are performed each operating cycle for all accessible areas in the torus above the water line and for the drywell-coated surfaces to evaluate coatings degradation. The below the water line painted surfaces in the torus, including the areas near the ECCS suction strainers, are inspected at intervals not exceeding five years. A pre-inspection review of the previous two inspection reports is performed so that trends can be identified.

When areas of unacceptable coatings are identified that involve metal substrate degradation, or suspected degradation, then a VT-3 examination is performed in accordance with IWE criteria. Suspect areas may be evaluated for acceptability per ASME Section Xl, IWE-3122. Implementing procedures include provisions for analysis of suspected reasons for coating failure. If areas are acceptable, coating repairs may be performed or left as-is. Previously identified areas with coating degradation, whether repaired or un-repaired, are monitored for further degradation. If conditions would require base metal repairs, repairs would be performed in accordance with the ASME Section XI Repair/Replacement Program.

Sigqnificant Coatinq Related Historical Summary a) 1997 Maintenance Outage The torus was drained down and desludged. In 1997, new EGGS suction strainers were installed. The EGGS suction strainers and their support assemblies were designed to be structurally independent from the torus penetrations. Preservice Coating examinations were performed on the affected ring girder reinforcements used as supports for the new suction strainers. Coatings spot repair was performed in the torus.

b) 2003 RFO Sludge was removed from 100 percent of the underwater surface of the torus shell. The torus sludge appeared to consist mainly of fine particulate with no evidence of fibrous material. Sludge depths at the torus invert (bottom curved surface) ranged from 1-1/2 inch to 1/4 inch. Only insignificant amounts of foreign material were found on the suction strainers and there was no apparent damage to the strainers.

Coating and base metal deficiencies were found on-:less than 5 percent of the torus shell surface. Mechanical damage and flaking of the coating were evident. There was random and minimal pitting corrosion. The inspections verified that there was no deformation, cracking, corrosion, wear, dislocation or disconnection that would have affected either the containment structural integrity or leak tightness.

L-MT-1 6-001 Page 37 of 64 c) 2007 REQ Extensive under the water line Torus coating repairs were performed during REQ 23 (2007). General visual, VT-3 and UT examinations were performed on the internal surfaces of the Torus, external surfaces of the vent lines, vent header and downcomers during REQ 23 (2007). UT measurements confirmed no degradation of the pressure boundary. Small areas of bare metal most being very small nicks (less than 1/2-inch in diameter) on the torus shell with a only light rust film, without evidence of corrosion pitting were observed. VT-3 inspections of areas surfaced prepared for coating found no corrosion pitting and several minor arc strikes that when further inspected by magnetic particle examination were determined acceptable with no indications. No unacceptable loss of material due to pitting corrosion was identified. Results for subsequent outages did not identify any significant age-related degradation (including pitting corrosion). The observed areas of coatings degradation were nonstructural in nature. No conditions that could affect the structural integrity were observed.

Current Coatinqs Performance Minimal corrosion was noted during RFO27 (2015) inspections on the drywell, vent system, and torus vapor phase. Based on previous and RFO27 inspection results there is no evidence of systemic coating failure from aging or other systemic causes. Current and previous inspection results support an expectation of very small corrosion rates on primary containment pressure boundaries.

Small areas of coatings have suffered mechanical damage (e.g. from scaffolding installation). In some cases, this has led to exposed base metal. Some exposed base metal has superficial corrosion. Corrosion leads to further coating degradation. This coating degradation has occurred in small, localized areas.

Some small localized coating repairs in the vent system were done in the past with marginal base metal preparation. Over time evidence shows that a portion of these repairs fail. In order to reduce the probability of this type of failure in the future, procedures were revised to include more detailed instructions for surface preparation including preparation (feathering) of adjacent areas of intact coating.

Coating failures associated with previous marginal base metal preparation were noted during RFO27.

There are small areas at the plates at the highest elevations of the Drywell (interior) that are flaking. This area of the drywell is subject to high temperatures.

Higher temperatures in this area will lead to degradation of coating properties, resulting in flaking. The amount of flaking coating is small.

L-MT-1 6-001 Page 38 of 64 Coatings in the torus vapor phase are showing early signs of degradation (e.g.

pinpoint or spot rusting, magnetite staining). There is no indication of systemic failure.

The majority of degraded coating noted during RFO 26 (2013) was in the underwater portion of the torus. The coating in the underwater portion of the torus is in substantially the same as-left condition as in RFO 23 (2007). Limited underwater coating repairs were performed in 2013. The next underwater inspection of coatings is planned for RFO 28 (2017) and coincides with the ASME Section Xl IWE examinations required for the 3rd Period of the Second Interval.

The total amount of degraded coatings in the Primary Containment, as documented in the most recent inspection performed during RFO27 (2015),

was below the administrative limit (half the analytic limit-).

4.4.3 Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program The MNGP Type B and C testing program requires testing of electrical penetrations, airlocks, hatches, flanges, bellows and containment isolation valves in accordance with 10 CFR 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 thbeir service life. The Type 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 Specification 5.5.11, the allowable maximum pathway total Type B and Type C leakage is 0.6 La (or 60 percent of La) approximately 285 scfh, where La equals 475.1 scfh, excluding the Main Steam Pathway, Specification 5.5.11.a.2.

As discussed within NUREG-1493, Type B and C tests can identify the vast majority of potential containment leakage paths. Therefore, the Type B and Type C testing performed will continue to provide a high degree of assurance that containment integrity is maintained.

A review of the Type B and Type C test results for the MNGP from 2007 through 2015 has shown margin between the actual As-Found and As-Left outage summations and the regulatory requirements as described below:

The As-Found minimum pathway leak rate average for MNGP, shows an average of 19.26 percent of La with a high of 25.76 percent La.

• The As-Left maximum pathway leak rate average for MNGP, shows an average of 35.24 percent of La with a high of 45.06 percent La.

L-MT-1 6-001 Page 39 of 64 The following table provides the local leak rate test (LLRT) data trend summaries for the MNGP inclusive of the 2007 ILRT.

MNGP Type B and C LLRT Combined As-Found I As-Left Trend Summary 2007 2009 2011 2013 2015 FORslsRFO23 RFO24 RFO25 RFO26 RFO27 As-Found Minimum Pathway 75.27 110.29 67.35 70.66 122.40 Leakage (scfh)

Fraction of La (percent) 16.41 24.05 14.69 15.41 25.76 As-Left Maximum Pathway 150.63 206.64 137.90 135.23 184.03 Leakage (scfh)

Fraction of La (percent) 32.84 45.06 30.07 29.49 38.73 As-Left Minimum Pathway 50.43 82.17 54.63 54.80 93.67 Leakage (scfh)

Fraction ofLa (percent) 11.00 17.92 11.91 11.95 19.71 Statistics On Number of Components On Extended Intervals Components in Type B and Type C Test Program:

189 Components NOT eligible for extended intervals:

61 Components eligible for extended intervals:

128 Components that are eligible but not on extended intervals:

11 4.4.4 Type B and Type C Local Leak Rate Testing Program Implementation Review As indicated by the tables below, there were no components on extended LLRT intervals that exhibited unacceptable performance during the previous two refueling outages.

L-MT-1 6-001 Page 40 of 64 MNGP Type B and C LLRT Program Implementation Review 2013 Refuelinq Outacie (RFO26)

As-Admin Component Found Limit As-Left Cause of Corrective Scheduled (scfh)

(scfh)

(scfh)-

Failure Action Interval N one (1) 2015 Refueling Outage (RFO27)_________________

As-Admin Component Found Limit As-Left Cause of Corrective Scheduled scfh)

(scfh)

(scfh)

Failure Action Interval (1)Thee were no.dmnitrtie.imt.aiurs.ssoiaedwih

.omonnt.o.etede intervals identified in either the 2013 or 2015 RFOs.

4.4.5 Supplemental Inspection Requirements With the implementation of the proposed change, Specification 5.5.11 will be revised by replacing the reference to RG 1.163 with a reference to NEI 94-01, Revision 2-A. This will require that a general visual examination of accessible interior and exterior surfaces of the containment for structural problems that may affect either the containment structure leakage integrity of performance of the Type A test. This inspection must be conducted prior to each Type A test and during at least three (3) other outages before the next Type A test if the interval for the Type A test has been extended to 15 years in accordance with the following sections of NEI 94-01, Revision 2-A:

Section 9.2.1, "Pretest Inspection and Test Methodology" Section 9.2.3.2, "Supplemental Inspection Requirements" The following table displays the projected ILRT Type A test performances versus the General Visual examination requirements of accessible containment interior and exterior surfaces (in accordance with ASME Section Xl, Subsection IWE and 10 CFR 50, Appendix J) and the coating examinations of accessible Drywell and interior Torus surfaces - above the water line, and interior Torus surfaces - below the water line.

L-MT-1 6-001 Page 41 of 64 ILRT Versus General Visual (IWE and Appendix J) and Coatings Examination Accessible Surfaces Examination General Visual Calendar Year Type A Examination Coatings Examination (Refueling Test Containment Interior and Drywell and Interior Torus Outage)

(ILRT)

Exterior Surfaces -

Interior Torus Surfaces -

Drywell and Torus Surfaces -Beo (IWE, and Appendix J)

Above Water WtrLn Line 2008 2010 2012 2014 2016 2018 2020 Notes:

(1) The Monticello Operating License was renewed on September 8, 2010.

4.5 Operating Experience During the conduct of the various examinations and tests performed in support of the primary containment monitoring programs previously mentioned, issues that do not meet established criteria or that provide indication of degradation, are identified, placed into the site's corrective action program, and corrective actions are planned and performed. Also, a;summary of the MNGP responses to industry operating experience is provided. The following site specific and industry events have been evaluated for their impact on primary containment:

NRC Generic Letter 87-05, "Request for Additional Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells" (Reference 29)

L-MT-1 6-001 Page 42 of 64 NRC Information Notice 1992-20, "Inadequate Local Leak Rate Testing" (Reference 30)

NRC Information Notice 2004-09, "Corrosion of Steel Containment and Containment Liner" (Reference 31)

NRC Information Notice 2010-12, "Containment Liner Corrosion" (Reference 32)

• NRC Information Notice 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner' (Reference 33)

• Draft NRC Regulatory Issue Summary (RIS) 20YY-XX, "Containment Shell or Liner Moisture Barrier Inspection" (Reference 34)

Each of these operating experiences documents is discussed in detail in the following subsections, respectively.

4.5.1 NRC Generic Letter 87-05. "Request for Additional Information - Assessment of Licensee Measures to Mitigate and/or Identify Potential Degqradation of Mark I DrywelIs" Generic Letter (GL) 87-05 described Drywell shell degradation, which occurred at the Oyster Creek Nuclear Generating Station as a result of water intrusion into the air gap between the outer Drywell surface and the surrounding concrete, involving the subsequent wetting of the sand cushion at the bottom of the air gap.

The NRC requested utilities provide information regarding: (1) drainage of the sand cushion, (2) preventative maintenance and inspection activities to minimize any possible leakage from the refueling pool, (3) plans for ultrasonic thickness measurements for those drywell shells with open sand cushions, and (4) confirmation of specific information as listed in the generic letter.

The Oyster Creek Drywell was constructed leaving the air gap forming material in place. The refueling bellows design incorporated a mechanical joint which was subject to degradation and leakage when the reactor cavity was flooded and thus allowed water to leak into the air gap region. The sand cushion at Oyster Creek was constructed without a seal plate between the sand cushion and the air gap region. It was discovered that the sand pocket and air gap drain lines were not functional allowing leakage from a degraded refueling bellows mechanical joint to collect in the air gap and remain for a significant time period. After evaluation of the corrosion mechanisms, it was determined that moisture had reacted with chemicals in the sand cushion and gap forming material resulting in a corrosive environment which led to the degradation of the carbon steel shell.

L-MT-1 6-001 Page 43 of 64 Discussion:

In the construction method used at the MNGP to achieve the Drywell air gap, 2-inch thick sheets of Ethafoam, a slightly compressible material, were sprayed with silicone lubricant and attached to the drywell to provide a removable form.

Concrete was poured in 3-foot lifts against the Ethafoam. After the concrete was set, the Ethafoam was pulled out. Each lift was inspected to ensure that a 2-inch gap had been achieved. After this inspection, a strip of porous polyurethane foam was inserted to prevent objects being dropped into the air gap. This method provided positive assurance that the gap was achieved and that no foreign objects had inadvertently been left therein. Since the polyurethane strip is very soft, its compression does not induce any undue stresses on the containment vessel shell. Drains installed above the sand pockets at the 920.5 foot elevation in addition to that through the shield penetrations provides drainage. The material is porous so drainage is not inhibited and ventilation is not prevented.

NSPM performs an inspection for leakage from the refueling bellows each refueling outage. The sealing material between the refueling cavity and Drywell air gap is steel joined by watertight welds. Also, a flow switch is provided on the Drywell refueling bellows leakage drain line to detect leakage from the seal area.

There are several paths to remove leakage from refueling or spillage of water into the Drywell air gap. A channel with a 4-inch drain line beneath the refueling bellows prevents leakage from entering the air gap. At the air gap to sand pocket interface there is a galvanized steel plate sealed to the Drywell shell and surrounding concrete. Four 4-inch drain lines remove water which might collect on the plate from above. The sand pocket is provided with four 2-inch drain lines (that are filled with sand to prevent loss of sand from the sand pocket) while providing drainage.

As discussed in Subsection 4.4.1, Item b) (in response to Generic Letter 87-05) the outlets for the sand pocket drains and the air gap drains were inspected.

One sand pocket drain was found to be partially obstructed by deposits of calcium carbonate in the standpipe region of the drain line. The partial obstruction was presumed to be from the drying of the sand pocket during construction and not from leakage during operation. All other drain lines were unobstructed. An additional qualitative test was performed to determine that the Drywell air gap drain lines, from the inlets to the outlets, were unplugged using compressed air to establish a flow through each-.d rain line to verify that it was not obstructed. To ensure the drain line outlets are not obstructed, the plant procedure for filling the reactor well includes a prerequisite to inspect the sand pocket and air gap drain outlets prior to flooding the refueling area.

L-MT-1 6-001 Page 44 of 64 4.5.2 NRC Information Notice 1992-20. "Inadeqiuate Local Leak Rate Testincq'"

The information notice discussed problems with the Type B LLRTs of two-ply bellows and failure to properly identify how to test the components when the LLRT programs were established. LLRTs in some instances could not be relied upon to accurately measure the leakage rate that would occur under accident conditions since, during Type B testing, the two plies in the stainless steel bellows were in contact with each other, restricting the flow of the test medium to the crack locations. Any two-ply bellows of similar construction may be susceptible to this problem.i13 )

Discussion:

As part of the assessment the original equipment manufacturer (OEM), i.e.,

Pathway Bellows, and NRC technical contact for the information notice were contacted. The MNGP two-ply bellows were procured in accordance with the requirements of the design specification (ensure a specified flow rate through the bellows could be obtained). No OEM/vendor test records could be located, so a test was performed on a sample of the bellows to determine how much flow could be measured when testing these bellows by removing the test port plug at the far end of the bellows segment (and 180 degrees around the circumference).

Testing indicated that low leakage rates up to well in excess of the procedural limit could be detected. The test method was revised to have the testers open the test port plug at the opposite end of the bellows to verify that flow completely though a bellows segment could be detected each time tested. Since issuance of the information notice only one bellows had a LLRT leakage of greater than 0.5 scfh. The As-Found LLRT for the (X-1 6B) measured a little over 1 scfh in 1996 and was replaced with a modified bellows design with a "testable" volume in 1998.

The measures taken from NSPM's review of the information notice provided reasonable assurance that at low leakage rates up to well in excess of the procedural limit the method used is capable of detecting!/measuring two-ply bellows leakage. Any measured leakage in excess of the specified limit would be evaluated for further testing and appropriate corrective action.

13.

The information notice also discussed failures in Appendix J test development and program administration, e.g., failure to consider all possible leakage paths, failure to test properly, or inappropriately crediting water seals for lines that that have potential air leakage paths, such as flanges or vacuum breakers, or that depend on the minimum suppression pool water level to prevent leakage.

LUMT-1 6-00 1 Page 45 of 64 4.5.3 Information Notice 2004-09,"Corrosion of Steel Containment and Containment Liner" The information notice alerted the industry to occurrences of corrosion in freestanding metallic containments and in the liner plates of reinforced and pre-stressed concrete containments. Any corrosion (metal thinning) of the liner plate Or freestanding metallic containment could change the failure threshold of the containment under a challenging environmental or accident condition. Thinning changes the geometry of the containment shell or liner plate, which may reduce the design margin of safety against postulated accident and environmental loads.

Recent experience has shown that the integrity of the moisture barrier seal at the floor-to-liner or floor-to-containment junction is important in avoiding conditions favorable to corrosion and thinning of the containment liner plate material.

Inspections of containment at the floor level, as well as at higher elevations, have identified various degrees of corrosion and containment plate thinning.

Discussion:

In 1996 and 1997, the NSPM detected deterioration in the moisture barrier!

caulking between the Drywell shell and the concrete basemat. The defective moisture barrier was removed and the Drywell shell was found to have minor corrosion and was evaluated as acceptable, and the area was cleaned, recoated, and new a moisture barrier was installed.

NSPM has excavated a portion of the Drywell interior basemat concrete in the sand-pocket region to evaluate the exterior of the Drywell due to corrosion reported at other licensees due to leakage in the refueling bellows and blocked sand pocket drains. No indication of degradation was detected at the MNGP.

The sand pocket drains were verified to be operating properly. NSPM has procedures in place that verify no leakage through the refueling bellows by inspecting the sand pocket drains during each refueling outage.

Only minor coating degradation, minor surface rust and minor pitting has been reported in the Drywell, torus, and the vent system( 14 ). No further degradation has been detected at the moisture barrier interface between the Drywell shell and basemat.

4.5.4 Information Notice 2010-12, "Containment Liner Corrosion" This information notice alerted licensees to several events that had occurred where the steel liner of the containment building was corroded and degraded. At the Beaver Valley Power Station and the Brunswick Steam Electric Plant material

14.

In accordance with 10 CFR 50.55a and ASME Section Xl, Subsection IWE, a Metal Containment examination program is in place for the MNGP.

L-MT-1 6-001 Page 46 of 64 had been found in the concrete which trapped moisture against the liner plate and corroded the steel. In one case it was material intentionally placed in the building and in the other case it was foreign material which had inadvertently been left in the form when the wall was poured. The result in both cases was that the material trapped moisture against the steel liner plate leading to corrosion. In the third case, the Salem Nuclear Generating Station, an insulating material placed between the concrete floor and the steel liner plate absorbed moisture and led to corrosion of the liner plate.

Discussion:

Although the examples cited are for conditions specific to concrete containments with steel liners, corrosion concerns have been identified for designs similar to the MNGP Mark I steel Primary Containment. As discussed in-part, previously in Subsection 4.5.1 in response to GL 87-05, the industry has identified areas of corrosion concern primarily on the exterior in the sand-pocket regions and on the interior surface at the moisture-barrier interface with the basemat and steel containment vessel.

The sand pocket corrosion occurs when refueling bellows or cavity liners fail allowing flood-up water to enter the exterior/annulus region. This is accentuated if the sand-pocket drains are plugged. NSPM has performed extensive inspections at the MNGP in these areas, and no degradation was identified.

The interior corrosion at the moisture-barrier interface between the basemat and containment vessel occurs when the moisture barrier degrades, no longer provides a tight seal, allowing water intrusion behind the moisture barrier. In the mid-I1990's minor corrosion was identified at the MNGP moisture barrier which was replaced with a superior product and additional slope was added to ensure water is directed away from the metal shell. Procedural measures ensure leakage into the sand pocket region is not occurring during refueling flood up activities.

4.5.5 Information Notice 2011-1 5. "Steel Containment Deqradation and Associated License Renewal Agingq Management Issues" This information notice discusses age-related degradation of nuclear power plant steel containments that could impact aging management of the containment structures during the period of extended operation under a renewed operating license. Specifically with respect to the MNGP, it describes corrosion due to the presence of water in inaccessible areas and degradation of coatings and pitting corrosion of the torus steel shell or of the Drywell of BWR Mark I containments.

L-MT-1 6-001 Page 47 of 64 Discussion:

Aging management of the Primary Containment (shell) and the Torus (suppression chamber) are accomplished under the Containment Inservice Inspection Plan (CISI) and the Protective Coating Monitoring and Maintenance Program.

During the license renewal application phase the potential for water intrusion into inaccessible areas was reviewed. For the inaccessible exterior drywell shell the primary potential water source is Drywell refueling bellows leakage. As discussed previously in Subsection 4.5.1, under the response to GL 87-05, there are three drain paths for removing this leakage. When inspected in 1987 there was no indication of the presence of water.

The presence of water beneath the refueling bellows, resulting in water entering the drywell air gap, would be indicated by an increase in water to the Radioactive Waste System. The presence of water at the air gap to sand pocket interface would be detected since the drain lines below the torus are monitored during refueling activities by procedure. Flooding in the sand-pocket region would be indicated by water draining from the sand-pocket drain lines. No water has been observed at the drain lines or indications of water leakage during flood up for refueling.

The refueling bellows were inspected during the PLEX Project and were later inspected prior to entering the period of extended operation with no indication of bellows degradation due to cracking or loss of material due to corrosion.

4.5.6 Information Notice 2014-07. "Decqradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner" The containment basemat metallic shell and liner plate seam welds of PWRs are embedded in 3-to 4-feet thick concrete floor during construction and are typically covered by a leak-chase channel system that incorporates pressurizing test connections. This system allows for pressure testing of the seam welds for leak-tightness during construction and also in service, as required. A typical basemat shell or liner weld leak-chase channel system consists of steel channel sections that are fillet welded continuously over the entire bottom shell or liner seam welds and subdivided into zones, each zone with a test connection.

Each test connection consists of a small carbon or stainless steel tube (less than 1-inch diameter) that penetrates through the back of the channel and is seal-welded to the channel steel. The tube extends up through the concrete floor slab to a small steel access (junction) box embedded in the floor slab. The steel tube, which may be encased in a pipe, projects up through the bottom of the

L-MT-1 6-001 Page 48 of 64 access box with a threaded coupling connection welded to the top of the tube, allowing for pressurization of the leak-chase channel. After the initial tests, steel threaded plugs or caps are installed in the test tap to seal the leak-chase volume.

Gasketed cover plates or countersunk plugs are attached to the top of the access box flush with the containment floor. In some cases, the leak-chase channels with plugged test connections may extend vertically along the circumference of the cylindrical containment shell or liner to a certain height above the floor.

Discussion:

The construction of the MNGP metal containment is substantially different from a PWR metal containment. The MNGP Mark 1 containment does not have the leak-chase channel design that is reflected in the referenced PWR events.

Therefore, this operating experience is not directly applicable to the MNGP.

4.5.7 Draft RIS 20YY-XX(, "Containment Shell or Liner Moisture Barrier Inspection" The NRC staff identified several instances in a draft RIS in which containment shell or liner moisture barrier materials were not properly inspected in accordance with ASME Code Section XI, Table IWE-2500-1, Item El1.30. Note 4 (Note 3 in editions before 2013) for Item El1.30 under the "Parts Examined" column states that "Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-to-metal interfaces which are not seal-welded. Containment moisture barrier materials include caulking, flashing, and other sealants used for this application." Examples of inadequate inspections have included licensees not identifying sealant materials at metal-to-metal interfaces as moisture barriers because they do not specifically match Figure IWE-2500-l, and licensees not inspecting installed moisture barrier materials, as required by Item El1.30, because the material was not included in the original design or was not identified as a "moisture barrier" in design documents.

Discussion:

The MNGP moisture barrier (caulking) is located on the Drywell interior at the drywell shell-to-basemat interface and is examined in accordance with the requirements of ASME Section Xl, Table IWE-2500-1, Item E1.30.

L-MT-1 6-001 Page 49 of 64 4.6 License Renewal Aging Management The renewed operating license for MNGP was issued on November 8, 2006, after NRC review of the MNGP license renewal application was completed.

The following Programs which are part of the supporting basis for this LAR, are also Aging Management Programs for the MNGP:

• Primary Containment In-Service Inspection Program

• Protective Coating Monitoring and Maintenance Program 10 CFR 50, Appendix J 4.6.1 Primary Containment In-Service Inspection Program The MNGP Primary Containment In-Service Inspection Program requires visual examinations of the accessible surfaces (base metal and welds) of the Drywell, torus, vent lines, internal vent system, penetration assemblies and associated integral attachments. The program also requires examination of pressure retaining bolting and the drywell interior slab moisture barrier.

The program conforms to the applicable requirements of 10 CFR 50.55a and the 2001 Edition with 2003 Addenda of the ASME Boiler and Pressure Vessel Code, Subsection IWE.

• General visual examinations that assess overall structural condition are performed once during each period.

• Surface and/or volumetric examination augments visual examination as required to define the extent of observed conditions or to identify deterioration at inaccessible locations.

• Examinations are scheduled and performed as required to evaluate disassembled bolting and the condition of the normally submerged torus surface.

The program is updated periodically as required by 10 CER 50.55a.

4.6.2 Protective Coatingq Monitoringq and Maintenance Program The MNGP Protective Coating Monitoring and Maintenance Program applies to the Service Level I protective coatings inside containment to address the

• concerns of NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System after a Loss-of-Cooling Accident because of Construction and Protective Coating Deficiencies and

L-MT-1 6-001 Page 50 of 64 Foreign Material in Containment". The Protective Coating Monitoring and Maintenance Program prevents the degradation of coatings that could lead to the clogging of ECCS suppression pool suction strainers. The MNGP does not credit the Protective Coating Monitoring and Maintenance Program for the prevention of corrosion of carbon steel components.

As outlined in NSPM's response to GL 98-04, the Protective Coating Monitoring and Maintenance Program is a comparable program for monitoring and maintaining protective coatings inside the primary containment and subject to the requirements of ANSI N101.4-1972 as modified by RG 1.54, June 1973.

4.6.3.1.0 CFR 50, Appendix J Proqram The MNGP 10 CFR 50, Appendix J Program specifies pneumatic pressure test and visual examinations to verify the structural and leak tight integrity of the primary containment. An overall (Type A) pressure test assesses the capacity of the primary containment to retain design basis accident pressure. This test also measures total leakage through the containment pressure-retaining boundary.

Local (Type B and C) tests measure leakage through individual penetration isolation barriers. These barriers are maintained as required to keep overall and local leakage under TS and plant administrative limits.

Tests are performed at intervals determined by the risk and performance factors applicable to each tested item in accordance with governing regulations and standards. This risk and performance based approach to testing provides reasonable assurance that developing leakage is detected and corrected well before it reaches a magnitude that could compromise the containment function.

Visual examinations are performed prior to each Type A test. These examinations are also performed at least once during each containment in-service inspection period in which no Type A test is conducted. The examinations are performed to detect corrosion and other types of deterioration on the accessible surfaces of the containment.

4.7 NRC Safety Evaluation Limitation and Conditions 4.7.1 Limitations and Conditions Applicable to NEI 94-01. Revision 2-A The NRC staff found that the use of NEI 9o4-01, Revision 2, was acceptable for referencing by licensees proposing to revise their TSs to permanently extend the ILRT surveillance interval to 15 years, provided the following conditions were satisfied:

L-MT-1 6-001 Page 51 of 64 NEI 94-01, Revision 2-A, Limitations and Conditions Lim itation/Condition (From Section 4.0 of SE)

MNGP Response For calculating the Type A leakage rate, the licensee NSPM will utilize the should use the definition in the NEI 94-01, Revision 2, definition in NEI 94-01 in lieu of that in ANSI/ANS-56.8-2002. (Refer to SE Revision 2-A, Section 5.0.(15)

Section 3.1.1.1.)

The licensee submits a schedule of containment A projected schedule for inspections to be performed prior to and between containment inspections is Type A tests. (Refer to SE Section 3.1.1.3.)

provided in Subsection 4.4.5

______________________________________of this enclosure.

The licensee addresses the areas of the containment Refer to Subsections 4.4.1 structure potentially subjected to degradation.

and 4.4.5 of this enclosure.

(Refer to SE Section 3.1.3.)

The licensee addresses any tests and inspections There are no major performed following major modifications to the modifications planned for the containment structure, as applicable. (Refer to MNGP that would affect the SE Section 3.1.4.)

containment structure.

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

extending the ILRT interval beyond 15 years, the In accordance with the licensee must demonstrate to the NRC staff that it is guidance of Section 3.1.1.2, an unforeseen emergent condition. (Refer to SE of the SE for NEI 94-01, Section 3.1.1.2.)

Revision 2-A, as further amplified by the additional guidance provided in RIS 2008-27.(16)

NSPM will demonstrate to the NRC staff that an emergent unforeseen condition arose if an extension beyond the 15-year ILRT interval became necessary.( 17 )

15.

As part of the amendment implementation process the definition in NEI 94-01, Revision 2-A, will be adopted for calculating the Type A leakage rate.

16.

RIS 2008-27, "Staff Position on Extension of the Containment Type A Test Interval Beyond 15 Years Under Option B of Appendix J to 10 CFR Part 50.

17.

As part of the amendment implementation process the program document controlling Type A testing will be revised to reflect this limitation.

L-MT-1 6-001 Page 52 of 64 NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition (From Section 4.0 of SE)

MNGP Response For plants licensed under 10 CFR Part 52, Not applicable. The MNGP applications requesting a permanent extension of was not licensed under the ILRT surveillance interval to 15 years should be 10 CFR Part 52.

deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No.

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

4.8 Conclusion NEI 94-01, Revision 2-A, describes an NRC-accepted approach for implementing the performance-based requirements of 10 CER 50, Appendix J, Option B. It incorporated the regulatory positions stated in RG 1.163 and includes provisions for extending Type A intervals to 15 years. NEI 94-01, Revision 2-A delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies. NSPM is adopting the guidance of NEI 94-01, Revision 2-A, for MNGP, 10 CFR Part 50, Appendix J testing program plan.

The permanent extension of the containment ILRT interval from 10 to 15 years represents a minimal risk of increased leakage based on the previous ILRTs conducted at the MNGP. The risk is further diminished by the continued Type B and Type C testing performed in accordance with Option B of 10 CFR 50, Appendix J and the overlapping inspection activities performed as part of the following the MNGP inspection programs:

• Containment Inservice Inspection Plan (IWE Plan)

• Protective Coating Monitoring and Maintenance Program

• Containment inspections in accordance with the MNGP Appendix J Program This conclusion is supplemented by risk analysis studies, including the risk analysis for the MNGP provided in Enclosure 2. The risk assessment concluded that the risk incurred by increasing the ILRT interval to 15 years is insignificant because it represents a very small change to the MNGP risk profile.

L-MT-1 6-001 Page 53 of 64

5.0 REGULATORY EVALUATION

The proposed change has been evaluated to determine whether applicable regulations and requirements continue to be met. 10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of 10 CFR 50, Appendix J. The appendix specifies containment leakage testing requirements, including acceptance criteria, test methodology, frequency, and reporting requirements to ensure the leak-tight integrity of the primary containment and systems/components that penetrate containment.

Adoption of Option B performance-based containment leakage rate testing for Type A, Type B and Type C testing does not alter the basic method by which testing is performed; but does alter the frequency at which the Type A containment leakage tests are required to be performed. Test frequency is based on evaluation of the leakage history to determine a frequency for testing which provides assurance that leakage limits will not be exceeded. The proposed change to the ILRT (Type A) frequency does not directly result in an increase in containment leakage.

A risk-informed assessment was performed in accordance with the EPRI methodology using plant-specific risk insights and industry ILRT performance data. The NRC staff found that the methodology utilized (EPRI Report No. 1009325, Revision 2, and NEI 94-01, Revision 2), satisfied the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.174. Consistent with the previous industry results, the change in risk from extending the ILRT interval to 15 years for the MNGP was determined to be very small.

NRC staff review of NEI 94-01, Revision 2, determined that it provides an acceptable approach for implementing performance-based requirements of Option B to 10 CFR 50, Appendix J. The NEI document incorporates the regulatory positions in RG 1.163 and it provides provisions for extending the ILRT intervals to 15 years. The NRC staff found that the Type A test methodology (described in ANSI/ANS-56.8-2002) modified by the test frequencies recommended by the NEI guidance, serves to ensure continued leakage integrity of the containment structure. Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type B and Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths.

Any applicant may reference NEI 94-01, Revision 2-A, in a licensing action to satisfy the requirements of Option B to 10 CFR 50, Appendix J.

5.1 Applicable Regulatory Requirements 10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors."

10 CFR 50.36, "Technical specifications," provides the regulatory requirements

L-MT-1 6-001 Enclosure I Page 54 of 64 for the content required in the TS. The MNGP was designed largely before the publishing of the 70 General Design Criteria (GDC) for Nuclear Power Plant Construction Permits proposed by the Atomic Energy Commission (AEC) for public comment in July 1967, and constructed prior to the 1971 publication of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CER Part

50. As such, the MNGP was not licensed to the Appendix A, General Design Criteria (GDC).

The MNGP USAR, Section 1.2, lists the principal design criteria (PDCs) for the design, construction and operation of the plant. USAR Appendix E provides a plant comparative evaluation to the 70 proposed AEC design criteria. It was concluded that the plant conforms to the intent of the GDCs. The applicable GDCs and PDCs are discussed below.

• PDC 1.2.4 - Plant Containment

d. Provisions are made for preoperational pressure and leak rate testing of the primary containment system and for leak testing at periodic intervals.

Provision is also made for leak testing selected penetrations. Provision is also made for demonstrating the functional integrity of the secondary containment system.

Of the 70 Draft AEC General Design Criteria (AEC-GDC) the following are applicable:

• AEC-GDC Criterion 10 - Containment (CatecioryA)

Containment shall be provided. The containment structure shall be designed to sustain the initial effects of gross equipment failures, such as a large coolant boundary area, without loss of required integrity and, together with other engineered safety features as may be necessary to retain for as long as the situation requires the functional capability to protect the public.

• AEC-GDC Criterion 49 - Containment Design Basis (Category A)

The containment structure, including access openings and penetrations, and any necessary containment heat removal systems shall be designed so that the containment structure can accommodate without exceeding the design leakage rate the pressures and temperatures resulting from the largest credible energy release following a loss-of-coolant accident, including a considerable margin for effects from metal-water or other chemical reactions that could occur as a consequence of failure of emergency core cooling systems.

L-MT-1 6-001 Page 55 of 64

• AEC-GDC Criterion 54 - Containment Leakaqie Rate Testinq (Categqory A)

Containment shall be designed so that an integrated leakage rate testing can be conducted at design pressure after completion and installation of all penetrations and leakage rate measured over a sufficient period of time to verify its conformance with required performance.

• AEC-GDC Criterion 55 - Containment Periodic Leakage Rate Testinq (Categqory A)

The containment shall be designed so that integrated leakage rate testing can be done periodically at design pressure during plant lifetime.

• AEC-GDC Criterion 56 - Provisions for Testingq of Penetrations (Ca teglory A)

Provisions shall be made for testing penetrations which have resilient seals or expansion bellows to permit leak tightness to be demonstrated at design pressure at any time.

• AEC-GDC Criterion 57 - Provisions for Testing of Isolation Valves (Categqory A)

Capability shall be provided for testing functional operability of valves and associated apparatus essential to the containment function for establishing that no failure has occurred and for determining that valve leakage does not exceed acceptable limits.

While not part of the MNGP Licensing Basis, the applicable 10 CFR 50, Appendix A, General Design Criteria are:

• GDC 16 - Containment design Reactor containment and associated systems shall be provided to establish an essentially leak-tight barrier against the uncontrolled release of radioactivity to the environment and to assure that the containment design conditions important to safety are not exceeded for as long as postulated accident conditions require.

GDC 39 - Inspection of containment heat remov~al system The containment heat removal system shall be designed to permit appropriate periodic inspection of important components, such as the torus, sumps, spray nozzles, and piping to assure the integrity and capability of the system.

L-MT-1 6-001 Page 56 of 64

• GDC 40 - Testinq of containment heat removal system The containment heat removal system shall be designed to permit appropriate periodic pressure and functional testing to assure (1) the structural and leaktight integrity of its components, (2) the operability and performance of the active components of the system, and (3) the operability of the system as a whole, and under conditions as close to the design as practical the performance of the full operational sequence that brings the system into operation, including operation of applicable portions of the protection system, the transfer between normal and emergency power sources, and the operation of the associated cooling water system.

• GDC 50 - Containment desiqn basis The reactor containment structure, including access openings, penetrations, and the containment heat removal system shall be designed so that the containment structure and its internal compartments can accommodate, without exceeding the design leakage rate and with sufficient margin, the calculated pressure and temperature conditions resulting from any loss-of-coolant accident. This margin shall reflect consideration of (1) the effects of potential energy sources which have not been included in the determination of the peak conditions, such as energy in steam generators and as required by § 50.44 energy from metal-water and other chemical reactions that may result from degradation but not total failure of emergency core cooling functioning, (2) the limited experience and experimental data available for defining accident phenomena and containment responses, and (3) the conservatism of the calculational model and input parameters.

• GDC 52 - Capability for containment leakaqe rate testing The reactor containment and other equipment which may be subjected to containment test conditions shall be designed so that periodic integrated leakage rate testing can be conducted at containment design pressure.

• GDC 53 - Provisions for containment testing and inspection The reactor containment shall be designed to permit (1) appropriate periodic inspection of all important areas, such as penetrations, (2) an appropriate surveillance program, and (3) periodic testing at containment design pressure of the leaktightness of penetrations which have resilient seals and expansion bellows.

L-MT-1 6-001 Page 57 of 64

• GDC 54 - Piping systems penetratinqi containment Piping systems penetrating primary reactor containment shall be provided with leak detection, isolation, and containment capabilities having redundancy, reliability, and performance capabilities which reflect the importance to safety of isolating these piping systems. Such piping systems shall be designed with a capability to test periodically the operability of the isolation valves and associated apparatus and to determine if valve leakage is within acceptable limits.

5.2 Precedent This request is similar in nature to the following license amendments to permanently extend the Type A test frequency from 10 to 15 years as previously authorized by the NRC:

Nine Mile Point Nuclear Station, Unit No. 2, Amendment 134 (Reference 35)

Arkansas Nuclear One, Unit No. 2, Amendment 292 (Reference 36)

Palisades Nuclear Plant, Amendment 247 (Reference 37)

Virgil C. Summer Nuclear Station, Unit No. 1, Amendment 194 (Reference 38)

The following plants were identified where containment accident pressure is part of their licensing basis, and hence was applied in their NPSH analyses:

North Anna Power Station, Unit Nos. 1 and 2, Amendments 274 and 256, respectively (Reference 39)

• Surry Power Station, Unit Nos. 1 and 2, Amendments 282 and 282, respectively (Reference 40) 5.3 No Significant Hazards Determination In accordance with the requirements of 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," the Northern States Power Company - Minnesota (NSPM) requests an amendment to revise the Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS).

The proposed change revises Specification 5.5.11 "Primary Containment Leakage Rate Testing Program", to increase the containment integrated leakage rate test program Type A test interval from 10 years to 15 years. The basis for the proposed change is in accordance with the guidance of Nuclear Energy Institute (NEI) Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 2-A, as endorsed by the U.S. Nuclear Regulatory Commission.

L-MT-1 6-001 Page 58 of 64 NSPM's evaluation against each of the criteria in 10 CFR 50.92, "Issuance of amendment," follows.

1.

Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed amendment involves a permanent change to extend the Type A containment integrated leak rate test (ILRT) interval from 10 to 15 years. The proposed extension does not involve either a physical change to the plant or a change in the manner in which the plant is operated or maintained. The containment is designed to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment and the testing requirements invoked to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve the prevention or identification of any precursors of an accident.

The effect of changing the Type A test frequency to once every 15 years, measured as an increase to the total integrated plant risk (for accident sequences influenced by Type A testing), is less than or equal to the criteria established in in EPRI Report No. 1009325, Revision 2-A. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible. In addition, as documented in NUREG-1493, Type B and C tests have identified a very large percentage of containment leakage paths, and the percentage of containment leakage paths that are detected only by Type A testing is very small. The MNGP Type A test history supports this conclusion.

The integrity of the containment is subject to two types of failure mechanisms that can be categorized as: (1) activity based, and, (2) time based. Activity based failure mechanisms are defined as those which involve degradation due to system and/or component modifications or maintenance. Local leak rate test requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities. The design and construction requirements of the containment combined with the containment inspections performed in accordance with American Society of Mechanical Engineers (ASME) Section Xi, and TS requirements provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by a Type A test.

L-MT-1 6-001 Page 59 of 64 Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2.

Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No The proposed TS change involves a permanent extension of the Type A containment test interval from 10 to 15 years. The containment testing requirements which periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident. The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) nor does the proposed change alter the design, configuration, or the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.

3.

Does the proposed change involve a significant reduction in a margin of safety?

Response: No The proposed TS change involves a permanent extension of the Type A containment test interval from 10 to 15 years. The specific requirements and conditions of the Primary Containment Leak Rate Testing Program exist to ensure that the required degree of containment structural integrity and leak-tightness considered in the plant safety analysis is maintained.

The overall containment leak rate limit specified by TS is maintained.

The proposed change involves only an extension of the interval between Type A test performances for MNGP. Extension of the proposed surveillance interval is in accordance with the 15-year ILRT Interval determined acceptable by the NRC utilizing the guidance of NEI 94-01, Revision 2-A. Industry experience supports the conclusion that Type B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with ASME Section XI, and the TS serve to provide a high degree of assurance that the containment would not degrade ina manner that is detectable only by Type A testing. The combination of these factors ensures that the margin of safety in the plant safety analysis is

L-MT-1 6-001 Page 60 of 64 maintained. The design, operation, testing methods and acceptance criteria for Type A, B, and C containment leakage tests specified in applicable codes and standards continue to be met with the acceptance of this proposed change because these criteria are not affected by the proposed change to the Type A test interval.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, the NSPM has determined that operation of the facility in accordance with the proposed change does not involve a significant hazards consideration as defined in 10 CFR 50.92, "Issuance of amendment," paragraph (c), in that it does not: (1) involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) involve a significant reduction in a margin of safety.

6.0 ENVIRONMENTAL CONSIDERATION

10 CFR 51.22, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review," identifies certain licensing and regulatory actions which are eligible for categorical exclusion from the requirement to perform an environmental assessment. NSPM has determined that the proposed amendment meets the criteria for a categorical exclusion from an environmental review as set forth in 10 CFR 51.22, specifically, 10 CFR 51.22(c)(9). First, the proposed amendment changes a requirement with respect to installation or use of a facility or component located within the restricted area, as defined in 10 CFR 20, "Standards for Protection Against Radiation," or involves a change to an inspection or surveillance requirement. Second, the proposed amendment requires no environmental assessment since operation of the facility in accordance with the proposed amendment does not (i) involve a significant hazards consideration, or (ii) authorize a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) result in a significant increase in individual or cumulative occupational radiation exposure.

Therefore, NSPM concludes pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

L-MT-16-001 Page 61 of 64

7.0 REFERENCES

1.

Nuclear Energy Institute (NEI) Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J",

Revision 2-A, dated October 2008

2.

ANSI/ANS 56.8-2002, "Containment System Leakage Testing Requirements"

3.

NRC Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program", dated September 1995

4.

10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors"

5.

NEI Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 3-A, dated July 2012

6.

NRC Regulatory Guide 1.174, Revision 2, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis", dated May 2011

7.

NRC Regulatory Guide 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities", dated March 2009

8.

Letter from T. Beltz (NRC) to K. Fili (NSPM), "Monticello Nuclear Generating Plant - Issuance of Amendment No. 176 to Renewed Facility Operating License Regarding Extended Power Uprate", (TAC No. MD9990)", dated December 9, 2013.

9.

SECY-1 1-0014, "Use of Containment Accident Pressure in Analyzing Emergency Core Cooling System and Containment Heat Removal System Pump Performance in Postulated Accidents", dated January 31, 2011 (ADAMS Accession No. ML102II10167), Enclosure 1

10.

NUREG-1493, "Performance-Based Containment Leak-Test Program", dated September 1995

11.

Electric Power Research Institute (EP RI) Topical Report TR-1 04285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals", dated August 1994

L-MT-1 6-001 Page 62 of 64

12.

NRC Regulatory Issue Summary (RIS) 2008-27, "Staff Position on Extension of the Containment Type A Test Interval Beyond 15 Years Under Option B of Appendix J to 10 CFR Part 50", dated December 8, 2008

13.

Letter from M. Maxim (NRC) to C. Butler (NEI), "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2, 'Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J' and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, 'Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals' (TAC No. MC9663)", dated June 25, 2008

14.

Letter from S. Bahadur (NRC) to B. Bradley (NEI), "Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J (TAG No.

ME21 64)", dated June 8, 2012

15.

Letter from T. Kim (NRC) to R. Anderson (NSP), "Monticello Nuclear Generating Plant - Issuance of Amendment RE: Main Steam Isolation Valve and 10 CFR Part 50, Appendix J, Leak Test Requirement (TAC No. M93332)", dated April 3, 1996

16.

Letter from D. Hood (NRC) to J. Forbes (NMC), "Monticello Nuclear Generating Plant - Issuance of Amendment Re: License Amendment Request for Conversion to Option B for Containment Leak Rate Testing (TAC No. MB4975)",

dated February 4, 2003

17.

Letter from M. Padovan (NRC) to J. Forbes (NMC), "Monticello Nuclear Generating Plant - Issuance of Amendment Re: One-Time Extension of Containment Integrated Leak-Rate Test Interval (TAC No. MB4919)", dated March 31, 2003

18.

Letter from P. Tam (NRC) to J. Conway (NMC), "Monticello Nuclear Generating Plant - Issuance of Amendment Re: Full Scope Implementation of the Alternative Source Term Methodology (TAC No. MC8971)", dated December 7, 2006

19.

Letter from P. Tam (NRC) to J. Conway (NMC), "Monticello Nuclear Generating Plant - Issuance of Exemption to Certain 10 CFR Part 50, Appendix J, Requirements (TAC No. MD2395)", dated December 7, 2006

20.

Letter from T. Beltz (NRC) to K. Fili (NS PM), "Monticello Nuclear Generating Plant - Issuance of Amendment to Revise Technical Specification 5.5.11,

'Primary Containment Leakage Rate Testing program' (TAG NO. MF3161)",

dated January 8, 2015

L-MT-1 6-001 Page 63 of 64

21.

Letter from D. Eisenhut (NRC) to D. Musoif (NSP), discussing NRC review of a plan to achieve compliance with 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors", dated June 3, 1984

22.

Nuclear Energy Institute (NEI), "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals", October 2001

23.

Letter from C. Cruse (Constellation Nuclear) to NRC, "Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension", dated March 27, 2002

24.

EPRI Topical Report TR-1018243, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals", Revision 2-A of 1009325, dated October 2008

25.

EPRI Topical Report TR-1 009325, Revision 2-A, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals", dated August 2007

26.

NUREG/CR-6850, "EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities", dated September 2005

27.

Letter from I. Frankl (NRC) to S. Schimmel (NMC), "Monticello Nuclear Generating Plant (MNGP) - Approval of Relief Request RR-007 for the Fifth 10-Year Inservice Inspection Interval (TAC ME8157)", dated July 12, 2012

28.

N RC Generic Letter 1998-04, "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", dated July 14, 1998

29.

NRC Generic Letter 1987-05, "Request for Additional Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells (Generic Letter 87-05)", dated March 12, 1987

30.

NRC Information Notice 1992-20: "Inadequate Local Leak Rate Testing",

dated March 3, 1992

31.

NRC Information Notic*e 2004-09: "Corrosion of Steel Containment and Containment Liner", dated April 27, 2004

32.

NRC Information Notice 2010-12: "Containment Liner Corrosion", dated June 18, 2010

.\\,,

L-MT-1 6-001 Page 64 of 64

33.

NRC Information Notice 2014-07: "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner", dated May 5, 2014

34.

NRC Regulatory Issue Summary (RIS) 20YY-XX, "Containment Shell or Liner Moisture Barrier Inspection", [RIS is in draft and has not been formally issued.]

35.

Letter from R. Guzman (NRC) to S. Belcher (NMP), "Nine Mile Point Nuclear Station, Unit No. 2 - Issuance of Amendment RE: Extension of Primary Containment Integrated Leakage Rate Testing Interval (TAC No. ME1 650)",

dated March 30, 2010

36.

Letter from N. Kalyanam (NRC) to Vice President, Operations (Entergy),

"Arkansas Nuclear One, Unit No. 2 - Issuance of Amendment RE: Technical Specification Change to Extend Type A Test Frequency to 15 Years (TAC No.

ME4090)", dated April 7, 2011

37.

Letter from M. Chawala (NRC) to Vice President, Operations (Entergy),

"Palisades Nuclear Plant - Issuance of Amendment to Extend the Containment Type A Leak Rate Test Frequency to 15 Years (TAC No. ME5997)", dated April 23, 2012

38.

Letter from S. Williams (NRC) to T. D. Gatlin (VCSNS), "Virgil C. Summer Nuclear Station, Unit 1 - Issuance of Amendment Extending Integrated Leak Rate Test Interval (TAC No. MF1385)", dated February 5, 2014

39.

Letter from V. Sreenivas (NRC) to D. Heacock (VEPCO), "North Anna Power Station, Unit Nos. 1 and 2, Issuance of Amendments to Extend Type A Test Frequency to 15 Years (TAC Nos. MF4332 and MF4333)", dated June 16, 2015

40.

Letter from S. Williams (NRC) to 0. Heacock (VEPCO), "Surry Power Station, Units 1 and 2 - Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests (TAC Nos. MF2612 and MF261 3)", dated July 3, 2014

ATTACHMENT 1 MONTICELLO NUCLEAR GENERATING PLANT LICENSE AMENDMENT REQUEST REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS MARKED-UP TECHNICAL SPECIFICATION PAGE (1 page follows)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 5.5.11 Safety Function Determination Progqram (SFDP) (continued)

3.

A required system redundant to the support system(s) for the supported systems described in Specifications 5.5.10.b.1 and 5.5.10.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 Leakaqe Rate Testinq Progqram

a.

A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in R.gulato,,,; Gu,,,do.1.163, "Perormnce...

Bae otinetLa Te,,st..Progr....m...

dao pe...b..., 1..05, as modified by the following exceptions:

Paragr..ph 0.2.3, a... "at leat onco per 10...... based^, on...cceptabl, to* tlho* inter-_ml folqlowing;," the Ty*po." A test prfoe'od*'. in* MaIsrcl.h 1003.

NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J,"'

Revision 2-A, dated October 2008

[J 1.2 The main steam line pathway leakage contribution is excluded from the sum of the leakage rates from Type B and C tests specified in Section III.B of 10 CFR 50, Appendix J, Option B, Section 6.4.4 of

• eral iANSI/ANS 56.8--1-g4, and Section 10.2 of NEI 94-01,-Rv-; and Revision 2-A

2.

Temain steam line pathway leakage contribution is excluded from oealitegrated leakage rate from Type A tests specified in Sectie o 10 CFR 50, Appendix J, Option B, Section 3.2 of

~~ANSI/ANS 56. -09, and Section 8.0 and 9.0 of NEI 94-01, fav*

b.

The calculated peak containment internal pressure for the design basis loss of coolant accident, Pa, is 44.1 psig. The containment design pressure is 56 psig.

c.

The maximum allowable containment leakage rate, La, at Pa, shall be 1.2%

of containment air weight per day.

Monticello Motielo5.5-10 Amendment No. 116 118,1!75, 176,_

ATTACHMENT 2 MONTICELLO NUCLEAR GENERATING PLANT LICENSE AMENDMENT REQUEST REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS MARKED-UP TECHNICAL SPECIFICATION BASES PAGE (1 page follows)

Primary Containment B 3.6.1.1 BASES SURVEILLANCE REQUIREMENTS (continued) would be directed through the downcomers into the suppression pooi.

This SR measures drywell to suppression chamber differential pressure during a 25 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowable limits.

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and verifying that the bypass leakage is less than that equivalent to a one inch diameter orifice. The leakage test is performed every 24 months. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs. Two consecutive 24 month test failures, however, would indicate unexpected primary containment degradation; in this event, as the Note indicates, increasing the Frequency to once every 12 months is required until the situation is remedied as evidenced by passing two consecutive 12 month tests.

REFERENCES

1.

USAR, Section 5.2.

2.

USAR, Section 14.7.2.

3.

10 CFR 50, Appendix J, Option B.

4.

Amendment No. 176, "Monticello Nuclear Generating Plant -

Issuance of Amendment No. 176 to Renewed Facility Operating License Regarding Extended Power Uprate," (ADAMS Accession No. ML13316C459)

5.

Nuclear Energy Institute (NEI) Topical Report NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J", Revision 2-A, dated October 2008

6.

ANSI/ANS 56.8-2002, "Containment System Leakage Testing Requirements" Monticello Monticello

~B 3.6.1.1 Last Rvso o

Revision No.

ENCLOSURE 2 MONTICELLO NUCLEAR GENERATING PLANT LICENSE AMENDMENT REQUEST REVISE TECHNICAL SPECIFICATION 5.5.11 TO PROVIDE A PERMANENT EXTENSION OF THE INTEGRATED LEAKAGE RATE (TYPE A) TEST FREQUENCY FROM TEN TO FIFTEEN YEARS MONTICELLO NUCLEAR GENERATING STATION EVALUATION OF RISK SIGNIFICANCE OF PERMANENT ILRT EXTENSION (145 pages follow)

QF0938 Rev 0 (FP-PE-PRA-06)

Page i of i SXceI EnergyI PRA Document Signature Sheet Document Information PRA Document No: PRA-CALC-15-O02 Revision: 2

Title:

Evaluation of Risk Significance of Permanent ILRT Extension Failty MT LI PI Applicable Unit: [] 1 [] 2 F

NOTE:

Pntadsign name insignature blocks, as required.

Review Information

[] Vendor Caic Vendor Doc No: 54005-CALC-01 Rev. 2 Vendor Name or Code: Jensen Hughes Prepared by:

Jensen Hughes (signatures on vendor

/(print)

Date:

(sign) calculation 2/8/2016 Reviewed by:

xJU*.. *_.*,

CL

/(printl Date:

(sign)

Dean R. Dudley 2/8/2016 Type of Review:

[] Technical Review

[] Suitability Review Revision History Rev.

Description Preparer Reviewer Date 0

Initial Issue Jensen Hughes TPW 1/11/2016 1

Containment Accident Pressure Update Jensen Hughes TPW 1/25/2016 2

PORC Comments Incorporated Jensen Hughes DRD 2/8/2016 Form retained in accordance with record retention schedule identified in FP-G-RM-01. Retain this form with the associated PRA calculation for the life of the plant.

QF0941 Rev I (FP-PE-PRA-06)

Page 1 of 2 4

Xcel Energy" PRA Suitability Review Checklist External Vendor Document Being Reviewed:

Title:

Evaluation of Risk Significance of Permanent ILRT Extension Number:

PRA-CALC-15-002 Rev:

2 Date:

2/8/2016 This design document was received from:

Organization Contract Number:

Name:

Jensen Hughes 59637 The purpose of the suitability~review is to ensure that a PRA calculation (or other PRA related document) provided by an External Vendor complies with the conditions of the purchase order and is appropriate for its intended use.

The suitability review does not serve as a technical review. Technical review of the document supplied by the External Vendor should be evident in the document.

The reviewer should use the criteria below as a guide to assess the overall quality, completeness and usefulness of the design document. The reviewer is not required to check calculations in detail.

REVIEW Reviewed NIA 1

Analysis inputs correspond to those that were transmitted to the External I[]

LI Vendor.

2 Assumptions are described and reasonable.

LII[

3 Applicable codes, standards and regulations are identified and met.

LI

[

4 Applicable structure(s), system(s), and component(s) are listed.

LI

[

5 Formulae and equations are documented. Unusual symbols are defined.

LI

[

6 Acceptance criteria are identified, adequate and satisfied.

LII[

7 Results are reasonable compared to inputs.

LI

[

8 Source documents are referenced.

[]

[

9 The document is appropriate for its intended use.

LI

[

10 The document complies with the terms of the Purchase Order.

[]

[

11 The impact to PRA applications (Maintenance Rule (a)(4), MSPI), other

[]

[

PRA documents, or other risk informed decisions has been identified and required changes tracked appropriately and listed in Table 1.

Reviewer Summary / Comments:

Review Completed by:

Dean R. Dudley Date:

2/8/2016 Form retained in accordance with record retention schedule identified in FP-G-RM-01. Retain this form with the associated PRA calculation for the life of the plant.

TABLE I Initiate an AR or POD item (as appropriate) to track open items and impacts, if any.

Item Tracking No.

umbr (A

orPRA IMPACT DESCRIPTION PCD, as appropriate I

None N/A 2

3 4

5 6

"7 8

9 10 11 12______________________________

13______________________________

14 15 Form retained in accordance with record retention schedule identified in FP-G-RM-01. Retain this form with the associated PRA calculation for the life of the plant.