ML050320004

License Amendment 187, Primary Containment Leakage Rate Testing Program

ML050320004
Person / Time
Site:	Hatch
Issue date:	02/01/2005
From:	Gratton C NRC/NRR/DLPM/LPD2
To:	Sumner H Southern Nuclear Operating Co
Gratton C, NRR/DLPM, 415-1055
Shared Package
ML050320005	List: ML050320004 ML050330157
References
TAC MC2761
Download: ML050320004 (12)

Text

February 1, 2005 Mr. H. L. Sumner, Jr.

Vice President - Nuclear Hatch Project Southern Nuclear Operating Company, Inc.

P.O. Box 1295 Birmingham, AL 35201-1295

SUBJECT:

EDWIN I. HATCH NUCLEAR PLANT, UNIT 2 RE: ISSUANCE OF AMENDMENT REVISING THE TECHNICAL SPECIFICATIONS FOR THE PRIMARY CONTAINMENT LEAKAGE RATE TESTING PROGRAM (TAC NO. MC2761)

Dear Mr. Sumner:

The Nuclear Regulatory Commission has issued the enclosed Amendment No. 187 to Renewed Facility Operating License NPF-5 for the Edwin I. Hatch Nuclear Plant, Unit 2. The amendment consists of changes to the Technical Specifications (TS) in response to your application dated April 26, 2004, as supplemented by letters dated August 17 and September 7, 2004.

The amendment revises the TSs for the primary leakage rate testing program.

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

Sincerely,

/RA/

Christopher Gratton, Sr. Project Manager, Section 1 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-366

Enclosures:

1. Amendment No. 187 to NPF-5

2. Safety Evaluation cc w/encls: See next page

February 1, 2005 Mr. H. L. Sumner, Jr.

Vice President - Nuclear Hatch Project Southern Nuclear Operating Company, Inc.

P.O. Box 1295 Birmingham, AL 35201-1295

SUBJECT:

EDWIN I. HATCH NUCLEAR PLANT, UNIT 2 RE: ISSUANCE OF AMENDMENT REVISING THE TECHNICAL SPECIFICATIONS FOR THE PRIMARY CONTAINMENT LEAKAGE RATE TESTING PROGRAM (TAC NO. MC2761)

Dear Mr. Sumner:

The Nuclear Regulatory Commission has issued the enclosed Amendment No. 187 to Renewed Facility Operating License NPF-5 for the Edwin I. Hatch Nuclear Plant, Unit 2. The amendment consists of changes to the Technical Specifications (TS) in response to your application dated April 26, 2004, as supplemented by letters dated August 17 and September 7, 2004.

The amendment revises the TSs for the primary leakage rate testing program.

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

Sincerely,

/RA/

Christopher Gratton, Sr. Project Manager, Section 1 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-366

Enclosures:

1. Amendment No. 187 to NPF-5

2. Safety Evaluation cc w/encls: See next page DISTRIBUTION: See next page Package Number: ML050320005 Amendment Number: ML050320004 Tech Spec Number: ML050330157 *No Major changes to SE OFFICE PDII-1/PM PDII-1/LA DE/EMEB-C DSSA/SPSB-C DIPM/IROB-A OGC PDII-1/SC NAME CGratton CHawes CMH KManoly RDennig* TBoyce DFruchter JNakoski DATE See SE dated 1/12/05 01/19/05 1/12/05 11/23/04 1/19/05 1/28/05 1/31/05 OFFICIAL RECORD COPY

FOR DISTRIBUTION EDWIN I. HATCH NUCLEAR PLANT, UNIT 2 RE: ISSUANCE OF AMENDMENT REVISING THE TECHNICAL SPECIFICATION FOR THE PRIMARY CONTAINMENT LEAKAGE RATE TESTING PROGRAM (TAC NO. MC2761)

Date: February 1, 2005 DISTRIBUTION:

PUBLIC PDII-1 R/F EHackett JNakoski CHawes OGC ACRS/ACNW GHill (4)

TBoyce RidsRgn2MailCenter DLPMDPR HAshar JPulsipher RPalla TMintz

SOUTHERN NUCLEAR OPERATING COMPANY, INC.

GEORGIA POWER COMPANY OGLETHORPE POWER CORPORATION MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA CITY OF DALTON, GEORGIA DOCKET NO. 50-366 EDWIN I. HATCH NUCLEAR PLANT, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 187 Renewed License No. NPF-5

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

A. The application for amendment to the Edwin I. Hatch Nuclear Plant, Unit 2 (the facility) Renewed Facility Operating License No. NPF-5 filed by Southern Nuclear Operating Company, Inc. (the licensee), acting for itself, Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and City of Dalton, Georgia (the owners), dated April 26, 2004, as supplemented by letters dated August 17 and September 7, 2004, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is hereby amended by page changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-5 is hereby amended to read as follows:

(2) Technical Specifications The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 187 are hereby incorporated in the license.

Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

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

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

John A. Nakoski, Chief, Section 1 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation

Attachment:

Technical Specification Changes Date of Issuance: February 1, 2005

ATTACHMENT TO LICENSE AMENDMENT NO. 187 RENEWED FACILITY OPERATING LICENSE NO. NPF-5 DOCKET NO. 50-366 Replace the following page of the Appendix A Technical Specifications with the attached revised page. The revised page is identified by an amendment number and contains marginal lines indicating the areas of change.

Remove Insert 5.0-16 5.0-16

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 187 TO RENEWED FACILITY OPERATING LICENSE NPF-5 SOUTHERN NUCLEAR OPERATING COMPANY, INC., ET AL.

EDWIN I. HATCH NUCLEAR PLANT, UNIT 2 DOCKET NO. 50-366

1.0 INTRODUCTION

By application dated April 26, 2004, and supplemented by a letters dated August 17 and September 7, 2004, Southern Nuclear Operating Company (SNC, the licensee) requested a technical specification (TS) change for the Edwin I. Hatch Nuclear Plant (Hatch), Unit 2.

Specifically, the change would allow a one-time change in their Appendix J, Type A test (containment integrated leakage rate test (ILRT)) interval from the required 10 years to a test interval of 15 years. The TS revision is based on the risk-informed approach developed using Regulatory Guide (RG) 1.174, ?An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis.

This evaluation addresses the acceptability of the licensees proposal from risk perspective, as well as the ability of the licensees inservice inspection (ISI) program to ensure the leak tight integrity of the containment, if the ILRT test interval is extended as proposed by the licensee.

2.0 REGULATORY EVALUATION

Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix J, Option B requires that a Type A test be conducted at a periodic interval based on historical performance of the overall containment system. Hatch, Unit 2 TS 5.5.12, Primary Containment Leakage Rate Testing Program, requires that leakage rate testing be performed as required by 10 CFR Part 50, Appendix J, Option B, as modified by approved exemptions, and in accordance with the guidelines contained in RG 1.163, Performance-Based Containment Leak-Test Program, dated September 1995. RG 1.163, Section C, ?Regulatory Position states, ?licensees intending to comply with the Option B of Appendix J in the amendment should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01, rather than using test intervals specified in ANSI/ANS-56.8-1994. Nuclear Energy Institute (NEI) 94-01, Section 11 states that Type A testing shall be performed at a frequency of at least once every 10 years. The licensees proposed TS change is an extension of the currently specified 10-year interval for ILRT to a 15-year interval on a one-time basis. There are no changes to any Code or regulatory requirement or acceptance criteria.

A Type A test is an overall (integrated) leakage rate test of the containment structure.

NEI 94-01 specifies an initial test interval of 48 months, but allows an extended interval of 10 years, based upon two consecutive successful tests. There is also a provision for extending the test interval an additional 15 months in certain circumstances. The most recent two Type A

tests at Hatch, Unit 2 have been successful, so the current interval requirement is 10 years.

The licensee is requesting a change to TS 5.5.12 which would add an exception from the guidelines of RG 1.163 and NEI 94-01, Revision 0, regarding the Type A test interval.

Specifically, the exception states that the first Type A test performed after the November 2, 1995, Type A test shall be performed no later than November 2010.

The local leakage rate tests (Type B and Type C tests), including their schedules, are not affected by this request.

3.0 EVALUATION The Nuclear Regulatory Commission (NRC) staff provides the following evaluations addressing the acceptability of the licensees request to extend the frequency of the Type A test from 10 years to 15 years.

3.1 RISK EVALUATION The licensee has performed a risk impact assessment of extending the Type A test interval to 15 years. The risk assessment was provided in the April 26, 2004, application for the license amendment. Additional analysis and information was provided by the licensee in a letter dated September 7, 2004. In performing the risk assessment, the licensee considered the guidelines of NEI 94-01, which is the methodology used in Electric Power Research Institute (EPRI)

Research Project Report TR-104285 and RG 1.174.

The basis for the current 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision 0. This basis was established in 1995 during the development of the performance-based Option B of Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493 Performance-Based Containment Leak Test Program, provided the technical basis to revise leakage rate testing requirements which are contained in Option B of Appendix J. This basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals. To supplement this basis, industry undertook a similar study. The results of that study are documented in EPRI Research Project Report TR-104285.

The EPRI study used an analytical approach similar to that presented in NUREG-1493 for evaluating the incremental risk associated with increasing the interval for Type A tests. The Appendix J, Option A requirements that were in effect for Hatch, Unit 2 early in the plants life required a Type A test frequency of three tests in 10 years. The EPRI study estimated that relaxing the Type A test frequency from three tests in 10 years to one test in 10 years would increase the average detection time of a detectable leak from 18 to 60 months. Since Type A tests only detect about 3 percent of leaks (the rest are identified during local leak rate tests based on industry leakage rate data gathered from 1987 to 1993), this results in a 10 percent increase in the overall probability of leakage. The risk contribution of pre-existing leakage for the pressurized water reactor and boiling water reactor (BWR) representative plants in the EPRI study confirmed the NUREG-1493 conclusion. These conclusions demonstrated that a reduction in the frequency of Type A tests, from three tests in 10 years to one test in 20 years, leads to an imperceptible increase in risk. The increase in risk is on the order of 0.2 percent and a fraction of one person-rem per year in increased public does.

Building upon the methodology of the EPRI study, the licensee assessed the change in the predicted person-rem per year frequency. The licensee quantified the risk from sequences that have the potential to result in large releases if a pre-existing leak were present. Prior to the completion of Option B rule-making in 1995, NRC staff had issued a RG 1.174 on the use of probabilistic risk assessment (PRA) in evaluating risk-informed changes to a plants licensing basis. The licensee has proposed using RG 1.174 guidance to assess the acceptability of extending the Type A test interval beyond that established during the Option B rule-making.

RG 1.174 defines a very small change in the risk-acceptance guidelines as increases in core damage frequency (CDF) which are less than 10-6 per year and increases in large early release frequency (LERF) which are less than 10-7 per year. Since the Type A test does not impact CDF, the relevant criterion is the change in LERF. The licensee has estimated the change in LERF for the proposed change and the cumulative change from the original frequency of three tests in a 10-year interval. RG 1.174 also discusses defense-in-depth and encourages the use of risk analysis techniques to help ensure and show that key principles, such as the defense-in-depth philosophy are met. The licensee demonstrates that the defense-in-depth philosophy is met by estimating the change in the conditional containment failure probability for the proposed change.

The analyses that the licensee provided for risk is discussed below. The following comparison of risk from a change in test frequency of three tests in 10 years to one test in 15 years is considered to be bounding for Hatch, Unit 2 compared to the proposed change. The following conclusions can be drawn from the analysis associated with extending the Type A test frequency:

1. Given the change from a three in 10-year test frequency to a one in 15-year test frequency, the increase in the total integrated plant risk is estimated to be about 0.03 person-rem per year. This increase is comparable to that estimated in NUREG-1493, where it was concluded that a reduction in the frequency of test from three in 10 years to one in 20 years leads to an imperceptible increase in risk. Therefore, the increase in the total integrated plant risk for the proposed change is considered small and supportive of the proposed change.

2. The increase in LERF resulting from a change in the Type A test frequency from the original three tests in 10 years to one test in 15 years is estimated to be 1.1 x10-7 per year based on the internal events PRA. However, there is some likelihood that the flaws in the containment estimated as part of the Class 3b frequency would be detected as part of the IWE/IWL visual examination of the containment surfaces (as identified in American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section XI, Subsections IWE/IWL). Visual inspections are expected to be effective in detecting large flaws in the visible regions of containment, and this would reduce the impact of the extended test interval on LERF. The licensees risk analysis considered the potential impact of age-related corrosion/degradation in inaccessible areas of the containment shell on the proposed change. The increase in LERF associated with corrosion events is estimated to be less than 1 x10-8 per year.

When the calculated increase in LERF is in the range of 10-7 per year to 10-6 per year, applications are considered if the total LERF is less than 10-5 per year. The licensee estimated that the total LERF for internal and external events is approximately 3 x 10-6

per year. This is based on judgements concerning the potential contribution to LERF from fire and seismic events. The NRC staff concludes that increasing the Type A interval to 15 years results in only a small change in LERF and is consistent with the acceptance guidelines of RG 1.174.

3. RG 1.174 also encourages the use of risk analysis techniques to help ensure and show that the proposed change is consistent with the defense-in-depth philosophy.

Consistency with the defense-in-depth philosophy is maintained if a reasonable balance is preserved between prevention of core damage, prevention of containment failure, and consequence mitigation. The licensee estimates the change in the conditional containment failure probability to be an increase of less than one percentage point for the cumulative change of going from a test frequency of three in 10 years to one in 15 years. The NRC staff finds that the defense-in-depth philosophy is maintained based on the small magnitude of the change in the conditional containment failure probability for the proposed amendment.

3.1.1 RISK

SUMMARY

Based on the facts presented in the previous section, the NRC staff finds that the increase in predicted risk due to the proposed change is within the acceptance guidelines while maintaining the defense-in-depth philosophy of RG 1.174 and, therefore, is acceptable.

3.2 TECHNICAL EVALUATION

Hatch, Unit 2 utilizes a General Electric BWR Mark I primary containment consisting of a drywell, a wetwell, vents connecting the drywell and the wetwell, primary containment access penetrations, and other process piping and electrical penetrations. The leak tight integrity of the penetrations and isolation valves are verified through Type B and Type C local leak rate tests (LLRTs) as required by 10 CFR Part 50, Appendix J, and the overall leak-tight integrity of the primary containment is verified through an ILRT. These tests are performed to verify the essentially leak-tight characteristics of the containment at the design basis accident pressure.

The last ILRT for Hatch, Unit 2 was performed in November 1995. With the extension of the ILRT time interval, the next overall verification will be performed no later than November 2010.

Because the leak rate testing requirements (ILRT and LLRTs) of Option B of 10 CFR Part 50, Appendix J, and the containment ISI requirements mandated by 10 CFR 50.55a complement each other in ensuring the leak-tightness and structural integrity of the containment, the NRC staff, from its review of Type A test interval extension applications at other plants, has identified the following five general areas of potential weaknesses. For licensees seeking to extend the period of performance for ILRTs, the NRC staff typically requests each licensee to address these general areas in relation to the ISI of the containment and potential areas of weaknesses in the containment:

(1) Include a description of the ISI methods that provide assurance that in the absence of a containment ILRT for 10 to 15 years, the containment structural and leak-tight integrity will be maintained.

(2) IWE-1240 requires licensees to identify the containment surface areas requiring augmented examinations. Provide the locations of the steel containment (or concrete containment liner) surfaces that have been identified as requiring augmented examination and a summary of the findings of the examinations performed.

(3) For the examination of penetration seals and gaskets, and examination and testing of bolted connections associated with the primary containment pressure boundary (Examination Categories E-D and E-G), licensees have requested relief from the requirements of the code. As an alternative, licensees have proposed to examine the above items during the leak-rate testing of the primary containment. However, Option B of Appendix J for Type B and Type C testing (as per NEI 94-01 and RG 1.163), and ILRT extension requests for Type A testing provide flexibility in the scheduling of these inspections. As appropriate, provide the schedule for examination and testing of seals, gaskets, and bolted connections that provide assurance regarding the integrity of the containment pressure boundary.

(4) Stainless steel bellows have been found to be susceptible to trans-granular stress corrosion cracking, and the leakage through these bellows are not readily detectable by Type B testing (see Information Notice 92-20). If applicable, provide information regarding inspection and testing of the bellows, and how their performance has been factored into the risk assessment of containment leaking to support the proposed TS change.

(5) Inspections of some reinforced concrete and steel containment structures have identified degradation on the uninspectable (embedded) side of the drywell steel shell and steel liner of the primary containment. These degradations cannot be found by visual (i.e., VT-1 or VT-3) examinations unless they are through the thickness of the shell or liner, or 100 percent of the uninspectable surfaces are periodically examined by ultrasonic testing.

Provide information addressing how potential leakage under high pressure during core damage accidents is factored into the risk assessment related to the extension of the ILRT.

In anticipation of the typical concerns identified by the NRC staff, the licensee provided responses to each issue as provided in Enclosure 1 of its submittal. The NRC staff conducted a review of the licensees response to these typical concerns. An overview of the licensees responses to the concerns stated above and the NRC staffs findings associated with each of these concerns are provided below:

(1) The current containment ISI 10-year interval began in Fall of 1998. The licensee is using the 1992 Edition and the 1992 Addenda of Subsections IWE of Section XI of the ASME Code, with certain approved relief from some ASME Code requirements, for conducting the ISI of the Hatch, Unit 2 containment. The licensee indicated that the accessible areas of the containment pressure boundary will be periodically monitored for signs of degradations.

In describing the results of prior inspections the licensee in each case states: ?No significant pressure boundary degradation was identified. The licensee was requested to provide a description of the criteria used to identify ?significant pressure boundary degradation. In response, the licensee provided the following criteria:

Plant Hatch procedure 42SV-L23-001-0S ?Protective Coating Surveillance Inspection, 42SV-T23-003-0S, ?Drywell Surfaces Visual Inspection, and 42SV-SUV-047-0S, ?Venting Assembly and Suppression Chamber Surfaces Visual Inspection all contain acceptance criteria consistent with ASME Section XI Subsection IWE.

Degradation that is not detrimental, such as general surface corrosion or light surface pitting that is of no concern to the integrity of the pressure retaining

boundary should not be considered as reportable; however, evidence of OR actual existence of the following (or similar) conditions shall be reported and brought to the attention of the CIPRE for evaluation.

Miscellaneous damage, deformation, or degradation (any condition that could potentially be detrimental to the component integrity) such as cracks, tears, broken welds, etc.

The inspector may use the following guidelines in determining reportability of the following conditions having depth: (1) 40 mils: Drywell Shell (interior and exterior), (2) 50 mils: Torus Shell Vapor Space (interior and exterior), and (3) 60 mils: Torus Shell Wetted Surfaces (interior and exterior):

• Excessive corrosion/pitting (generally represented by dark discoloration (red/brown), spalling from swelling, rust ejection, deep pits, and/or other severe manifestations),

• Deep gouges or dents (excluding fabrication or installation marks),

• Excessive wear (generally represented by shiny wastage).

The NRC staff considers the criteria developed by the licensee acceptable, as they provide reasonable assurance that significant defects or degradation that could challenge the structural and leaktight integrity of the primary containment components will be detected.

(2) The licensee stated the following regarding the areas subject to augmented inspection:

Inspection of the seal at the steel liner plate and concrete floor interface inside the drywell at 114' elevation was performed during the Spring 2000 Unit 2 Outage.

Results of the inspection revealed three areas where the mastic seal had either been damaged or was disbonded from the steel liner. One of the areas was approximately two feet in length and the other two were approximately 10 inches (each) in length.

CR2000002021 was generated and repairs were initiated in accordance with MWO20000662. The mastic material in these three areas was removed and a protective coating was applied to the containment shell, however, because of very wet conditions created by other work in the area, successful repair of the seal was questionable.

On 3/29/00, certified personnel visually examined all three areas and scanned all accessible surfaces of all three areas with an ultrasonic thickness meter to determine the minimum shell thickness. The minimum ultrasonic thickness measurement was recorded for each area.

Area #1 - Minimum Thickness = 1.500 Area #2 - Minimum Thickness = 1.475 Area #3 - Minimum Thickness = 1.615 The mastic seal was reinspected during the Unit 2 Fall 2001 Refueling Outage.

CR2001009111 was generated to document the inspection results. MWO20103141 was implemented during the Spring 2003 Refueling Outage to remove and replace the mastic seal.

Further, the licensee provided the following summary of the state of degradation, and a rationale to justify the method of monitoring the degradation of drywell and the torus:

SNC has been monitoring both coated and un-coated steel surfaces in the drywell and torus for several years and has noted very low corrosion rates during an operating cycle. This is primarily because of the high nitrogen, low oxygen content that is present in the drywell and torus when the plant is operating. SNC has been measuring and monitoring the corrosion rates in the immersion areas of the torus since 1993, and has documented that it is less than 3 mils. per year (average) during plant operation.

The liner plate in the repair areas was coated prior to installing the mastic seal, but even if some of the coating has failed and water collects in these areas (creating an immersion environment) and remains until next outage, metal loss due to corrosion should be less than 5 mils. Bare substrate in immersion should be the worst case condition.

Based on its review of the licensees response to this concern, and the rationale for monitoring the degradation, the NRC staff found that the licensees program provides reasonable assurance that containment surfaces requiring augmented inspections will be identified and that corrective actions will be taken when necessary to ensure their structural integrity.

(3) In response to the NRC staffs concern related to penetration seals and gaskets, and examination and testing of bolted connections associated with the primary containment pressure boundary, the licensee cited Relief Requests (RR)-MC-1, RR-MC-6, and RR-MC-8.

For penetrations (other than equipment hatch and air-locks, which are Type B tested after each opening) with seals, gaskets, and pressure-retaining bolting, reliance has been placed on the frequency of Type A and Type B testing to detect their degradation. As the performance based Type B test interval for these penetrations could be as high as 10 years, and with the request to extend the Type A test interval to 15 years, the NRC staff requested the licensee to provide information to demonstrate that the integrity of the seals, gaskets, and bolting associated with the mechanical and electrical penetrations, and drywell head will be maintained. The licensee provided the following response:

The justification for extension of most Type B test intervals to 10 years in conjunction with extension of the Type A test interval has already been reviewed by the staff as documented in RG 1.163. The incremental increase in risk associated with extending the Type A test interval to 15 years while maintaining the Type B test interval at 10 years is documented in our submittal.

Electrical penetrations at Plant Hatch do not have pressure retaining bolting and conductor penetrations are sealed by cast epoxy. The penetrations are nitrogen pressurized during normal operation and pressures are periodically monitored.

Furthermore, at least one electrical penetration of each type is Type B tested each operating cycle.

The drywell head is removed each operating cycle. The bolting and seal are examined in accordance with RR-MC-1 and RR-MC-6. Type B leakage testing is performed every operating cycle.

The highlighted mechanical penetrations in the attached table [to SNC letter dated August 17, 2004, page E1-5] are the only mechanical penetrations which may not be Type B tested every operating cycle and examined in accordance with RR-MC-1 and RR-MC-6. Outage and maintenance activities generally require disassembling most mechanical penetrations which would result in a Type B leakage test upon reassembly. As a minimum they will be disassembled, inspected, and tested at least once every 10 years in accordance with RR-MC-8.

The NRC staff review of the table in SNC letter dated August 17, 2004, found that the important mechanical penetrations will be Type B tested once every operating cycle. Some internal penetrations (to drywell and torus), such as the reactor pressure vessel stabilizer access hatches, electrical spares, and drain valves will be Type B tested once every 10 years. The NRC staff determined that the licensees process of Type B testing these penetrations provides reasonable assurance that the integrity of seals, gaskets, and the associated bolts during the extended ILRT interval will be maintained.

(4) In Enclosure 1 of its submittal, while addressing the potential degradation of vent line bellows, the licensee states: ?Experience indicates that conventional examination techniques are not adequate to identify defects in the bellows, and presently Appendix J testing is the only practical test method currently being performed. On this subject, the staff questioned: ?If the bellows are not designed for detection of bellows degradation by Appendix J, Type B testing, the licensee is requested to justify why the Type A test should not be performed as required by the existing Technical Specification. The licensee provided the following response:

In response to IN92-20 (Ref. 5.9), Plant Hatch installed temporary plates on some selected bellows penetrations (a labor and outage schedule intensive activity) and performed a simulated Type A leakage test. These leakage tests indicated that the Type B leakage test is a representative test. The licensees answer (in SNC's original submittal) indicates that Appendix J Type B testing is considered adequate to detect bellows degradation, but alternatives to conventional examination techniques (visual, dye penetrant, radiography, etc.) continue to be evaluated.

The NRC staff finds the licensees efforts to detect degradation of vent line bellows by means of Type B leak rate testing is acceptable. The NRC staff notes that the licensee is pursuing better ways to detect the bellows degradation.

(5) In response to the concern related to the effects of degradations in uninspectable areas of the steel shell that could not be identified by visual examinations the licensee stated:

The attached ?Risk Assessment for Edwin I. Hatch Nuclear Power Station Regarding ILRT (Type A) Extension Request provides a sensitivity evaluation considering potential corrosion impacts within the framework of the ILRT interval extension risk assessment. The analysis confirms that the ILRT interval extension has a minimal impact on plant risk. Additionally, a series of parametric sensitivity studies regarding the potential age-related corrosion effects on the steel liner also indicate that even with very conservative assumptions, the conclusions from the original analysis would not change. That is, the ILRT interval extension is judged to have a minimal impact on plant risk and is therefore acceptable.

The attached analysis also clarifies the delta LERF for the original License Bases

?three tests in 10 years and the proposed ?one test in 15 years. The analysis also provides a discussion on the effects ILRT interval extension would have on the total LERF (internal and external events) for Hatch. The conclusion shows that the total LERF for Hatch is well below the RG 1.174 acceptance criteria for total LERF of 1.0E-05.

Additionally, the drywell containment at HNP [Hatch] has a two inch air gap between the steel shell and concrete shield wall. The design includes drain lines (4), at the basemat elevation, which route any leakage into the air gap away from the drywell shell. SNC performed examination of the drain lines using a video probe to confirm that the drains were open and functional (unlike the drain lines at another plant which resulted in water accumulation). SNC performs visual examinations of the drains lines each outage when the refueling cavity is flooded to look for evidence of moisture or leakage. These examinations are performed to ensure there is no leakage from the refueling cavity bellows that would support corrosion.

The licensee describes the following process during operation of the reactor that provides additional confidence in the ability of the licensee to identify gross leakage from the 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 prior to power operation and provides a supply of makeup nitrogen to maintain primary containment oxygen concentration within Technical Specification limits. As a result, the primary containment is maintained at a slightly positive pressure during power operation. Primary containment pressure is continuously recorded and verified by TS surveillance on a frequency of every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from the Main Control Room. Although this feature, that is inherent to the HNP BWR containment design, does not challenge the structural and leak tight integrity of the containment system at post-accident pressure, the fact that the containment is continuously pressurized by the containment inerting system, and is periodically monitored, provides assurance that gross containment leakage that may develop during power operation will be detected.

The NRC staff finds that this continuous monitoring at a slight positive pressure will ensure that areas of containment degradation will be detected before they could result in large leakage areas.

With the precautionary measures taken to prevent any degradation in the uninspectable areas of the drywell, ability to detect significant degradation due to slightly higher pressure level in the drywell, and considering that the risk analysis includes a large leakage (up to 35 times La , where La is the acceptable leak rate), the NRC staff finds the licensee is appropriately addressing the potential degradation of the uninspectable areas of the drywell.

3.2.1 Technical Evaluation Summary Based on the licensees procedures related to the potential degradation of the pressure retaining primary containment components, the NRC staff finds that granting the requested ILRT extension will not adversely affect the leak tight integrity of the primary containment. It should be noted that Subarticle IWE-5000 of the ASME Code,Section XI requires leak rate testing following a major repair, modification, or replacement of containment components. An ILRT might be required to confirm that these activities are adequate and that further degradation does not exist in other areas of the containment. The licensee is required to report serious degradation of the containment pressure boundary pursuant to 10 CFR 50.72 or 10 CFR 50.73.

3.3 Evaluation Summary On the basis of its review of the information provided by the licensee in its April 26, 2004, TS amendment request and its August 17, 2004, response to the NRC staffs questions, the NRC staff finds that (1) the structural integrity of the containment vessel will be verified through the periodic ISIs conducted as required by Subsection IWE of the ASME Code,Section XI, and (2) the integrity of the penetrations and containment isolation valves will be periodically verified through Type B and Type C tests as required by 10 CFR Part 50, Appendix J. In addition, the system pressure tests for containment pressure boundary (i.e., Appendix J tests, as applicable) are required to be performed following repair and replacement activities, if any, in accordance with Article IWE-5000 of the ASME Code,Section XI. Further, as stated in Section 3.1, the NRC staff finds that the increase in predicted risk due to the proposed change is within the acceptance guidelines while maintaining the defense-in-depth philosophy of RG 1.174.

Therefore, granting a one-time extension of performing the ILRT as proposed by the licensee in Section 5.5.12 of the proposed TS revision request is acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Georgia State official was notified of the proposed issuance of the amendments. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts and no significant change in the types of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (69 FR 46591). Accordingly, the amendments meet the eligibility criteria for categorical

exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

6.0 CONCLUSION

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

Principal Contributors: H. Ashar, DE J. Pulsipher, DSSA R. Palla, DSSA Date: February 1, 2005

Edwin I. Hatch Nuclear Plant, Units 1 & 2 cc:

Laurence Bergen Chairman Oglethorpe Power Corporation Appling County Commissioners 2100 E. Exchange Place County Courthouse P.O. Box 1349 Baxley, GA 31513 Tucker, GA 30085-1349 Mr. Jeffrey T. Gasser Mr. R.D. Baker Executive Vice President Manager - Licensing Southern Nuclear Operating Company, Inc.

Southern Nuclear Operating Company, Inc. P.O. Box 1295 P.O. Box 1295 Birmingham, AL 35201-1295 Birmingham, AL 35201-1295 Mr. G. R. Frederick, General Manager Resident Inspector Edwin I. Hatch Nuclear Plant Plant Hatch Southern Nuclear Operating Company, Inc.

11030 Hatch Parkway N. U.S. Highway 1 North Baxley, GA 31531 P.O. Box 2010 Baxley, GA 31515 Harold Reheis, Director Department of Natural Resources Mr. K. Rosanski 205 Butler Street, SE., Suite 1252 Resident Manager Atlanta, GA 30334 Oglethorpe Power Corporation Edwin I. Hatch Nuclear Plant Steven M. Jackson P.O. Box 2010 Senior Engineer - Power Supply Baxley, GA 31515 Municipal Electric Authority of Georgia 1470 Riveredge Parkway, NW Atlanta, GA 30328-4684 Mr. Reece McAlister Executive Secretary Georgia Public Service Commission 244 Washington St., SW Atlanta, GA 30334 Arthur H. Domby, Esq.

Troutman Sanders Nations Bank Plaza 600 Peachtree St, NE, Suite 5200 Atlanta, GA 30308-2216