L-96-018, Rev 1 to INEL-96/0188, TER on Third 10-Yr Interval Inservice Insp Program Plan:Gpc,Ei Hatch Nuclear Plant Units 1 & 2
| ML20141L924 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 12/31/1996 |
| From: | Mary Anderson, Feige E, Hall K IDAHO NATIONAL ENGINEERING & ENVIRONMENTAL LABORATORY |
| To: | NRC |
| Shared Package | |
| ML20141A134 | List: |
| References | |
| CON-FIN-J-2229 INEL-96-0188, INEL-96-0188-R01, INEL-96-188, INEL-96-188-R1, NUDOCS 9706030171 | |
| Download: ML20141L924 (59) | |
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INEL-96/0188, Revision 1 l
December 1996 l
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Idaho National i
Engineering
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l Laboratory Technical Evaluation Report on the l
Third 10-year Interval inservice Inspection Program Plan:
Georgia Power Company, Edwin 1. Hatch Nuclear Plant, l
Units 1 & 2, Docket Numbers 50-321 and 50-366 4
l M. T. Anderson l
E. J. Feige l
K. W. Hall A. M. Porter i
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L O C K N E E D M A R T I Nl (g[g bhongs A ex*3
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l INEL-96/0188, Revision 1 I
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Technical Evaluation Report on the Third 10-year Interval Inservice Inspection Program Plan:
Georgia Power Company, Edwin I. Hatch Nuclear Power Plant, Units 1 and 2 Docket Numbers 50-321 and 50-366 l
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M. T. Anderson E. J. Feige K. W. Hall A. M. Porter l
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Published December 1996 l
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Idaho National Engineering Laboratory Materials Physics Department Lockheed Martin Idaho Technologies Company l
i Prepared for the Division of Engineering Office of Nuclear Reactor Regulation j
U.S. Nuclear Regulatory Commission Washington, D.C. 20555 i
Under doe Idaho Operations Office I
Contract DE AC07-941D13223 JCN J2229 (Task Order TWA-A11)
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f ABSTRACT l
This report presents the results of the evaluation of the Edwin 1. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0, submitted October 17, 1995, including the 1
requests for relief from the American Society of Mechanical Engineers (ASME) l Boiler and Pressure Vessel Code,Section XI, requirements that the licensee has determined to be impractical.
The Edwin I.. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, j
Revision 0, is evaluated in Section 2 of this report.
The inservice inspection (IFI) program plan is evaluated for (a) compliance with tha appropriate edition / addenda of Section XI, (b) acceptability of the l
examination sample, (c) correctness of the application of system or component l
examination exclusion criteria, and (d) compliance with ISI-related l
commitments identified during previous Nuclear Regulatory Commission (NRC) reviews.
The requests for relief are evaluated in Section 3 of this report.
As a result of this review, a Request for Additional Information (RAI) was prepared describing the information and/or clarification required from the licensee in order to complete the review.
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1 This work was funded under:
U.S. Nuclear Regulatory Commission JCN J2229, Task Order TWA-All Technical Assistance in Support of the NRC Inservice Inspection Program ii
SUMMARY
The licensee, Georgia Power Company, has prepared the Edwin I. #atch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0, to meet the requirements of the ASME Boiler and Pressure Vessel Code,Section XI, 1989 Edition.
The third 10-year interval began January 1, 1996.
The information in the Edwin I. #atch Nuc.' ear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0, submitted October 17, 1995, and the responses to the Nuclear Regulatory Commission's Request for Additional Information (RAI), received in the licensee's submittals dated January 26, 1996, and November 18, 1996, were reviewed.
Included in the review were the requests for relief from the ASME Code Section XI requirements that the licensee has determined to be impractical.
By letter dated June 4, 1996, the licensee submitted two additional requests for relief associated with the update of the pressure testing program.
In the review of the Edwin I. Natch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0, the licensee's responses to the Nuclear Regulatory Commission's RAI, and the recommendations for granting relief from the ISI examinations that cannot be performed to the extent required by Section XI of the ASME Code, no deviations from regulatory requirements or commitments were identified in the Edwin I. Natch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plass, Revision 0.
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3.2 Class 2 Components........................
15 3.2.1 Pressure Vessels.......................
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3.2.1.1 Request for Relief RR-5, Examination Category C-A, Item Cl.20, Class 2 Pressure Vessel Circumferential Head Welds........................
15 3.2.2 Piping (No relief requests) 3.2.3 Pumps (No relief requests) l 3.2.4 Valves (No relief requests) l l
3.2.5 General (No relief requests) 3.3 Class 3 Components (No relief requests) 3.4 Pressure Tests 17 1
l 3.4.1 Class 1 System Pressure Tests (No relief requests) 3.4.2 Class 2 System Pressure Tests 17 l
3.4.2.1 Request for Relief RR 15,Section XI, j
Table IWC-2500-1, Examination Category C-H, Items i
C7.40 and C7.60, Hydrostatic Testing of the High Pressure Coolant Injection (HPCI Pum Associated Lines........).. p Turbine and i
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17 3.4.3 Class 3 System Pressure Tests 21 3.4.3.1 Request for Relief RR-16, Examination Category D-A, Item Dl.10, Functional and Hydrostatic Pressure Testing for the Main Steam Relief Valve Discharge Lines 21 l
3.4.4 General 23 3.4.4.1 Request for Relief RR-2, 10-Year Hydrostatic Test Requirements for Code Class 1, 2, and 3 Systems 23 3.4.4.2 Request for Relief RR-9, Alternative Pressure Test for Welded Repairs or Replacements in Class 1, 2, and 3 Systems 27 3.5 General 30 j
3.5.1 Ultrasonic Examination Techniques (No relief requests) l 3.5.2 Exempted Components (No relief requests)
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3.5.3 Other 30 l
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SUMMARY
4 The licensee, Georgia Power Company, has prepared the Edwin I. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0, to meet the requirements of the ASME Boiler and Pressure Vessel Code,Section XI, 1989 Edition.
The third 10-year interval began January 1, 1996.
The information in the Edwin I. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0, submitted October 17, 1995, and the responses to the Nuclear Regulatory Commission's Request for Additional Information-(RAI), received in the licensee's submittals dated January 26, 1996, and November 18, 1996, were reviewed.
Included in the review were the requests for relief from the ASME Code Section XI requirements that the licensee has determined to be impractical.
By letter dated June 4, 1996, the licensee submitted two additional requests for relief associated with the update of the pressure testing program.
In the review of the Edwin I. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-l ear Interval Inservice Inspection Program Plan, Revision 0, the licensee's responses to the Nuclear Regulatory Commission's RAI, and the recommendations for 5, ranting relief from the ISI examinations that cannot be performed to the extent required by Section XI of the ASME Code, no deviations from regulatory requirements or commitments were identified in the Edwin I. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plas,, Revision 0.
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CONTENTS ABSTRACT ii
SUMMARY
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INTRODUCTION I
2.
EVALUATION OF INSERVICE INSPECTION PROGRAM PLAN...........
4 2.1 Documents Evaluated........................
4 2.2 Compliance with Code Requirements 4
2.2.1 Compliance with Applicable Code Editions...........
4 2.2.2 Acceptability of the Examination Sample 5
2.2.3 Exemption Criteria......................
6 2.2.4 Augmented Examination Commitments 6
2.3 Conclusions 7
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EVALUATION OF RELIEF REQUESTS....................
8 3.1 Class 1 Components........................
8 3.1.1 Reactor Pressure Vessel 8
3.1.1.1 Request for Relief RR-1, Examination Category B-G-1, Item B6.10, Reactor Vessel Closure Head Nuts.......
8 3.1.1.2 Request for Relief RR-3, Examination Category B-D, Items B3.90 and B3.100, Reactor Pressure Vessel Nozzle-to-Shell and Nozzle Inner Radius Examinations...
10 3.1.2 Pressurizer (Not applicable) 3.1.3 Heat Exchangers and Steam Generators (No relief requests) 3.1.4 Piping Pressure Boundary...................
12 3.1.4.1 Request for Relief RR-6, Examination Category B-F, Item B5.20, Examination of Reactor Pressure Vessel Nozzle-to-Safe-End Butt '.d-lds 12 3.1.5 Pump Pressure Boundary (No relief requests) 3.1.6 Valve Pressure Boundary (No relief requests) 3.1.7 General (No relief requests) iv
a 3.2 Class 2 Components........................
15 3.2.1 Pressure Vessels.......................
15 3.2.1.1 Request for Relief RR-5, Examination Category C-A, Item C1.20, Class 2 Pressure Vessel Circumferential Head Welds........................
15 3.2.2 Piping (No relief requests) 3.2.3 Pumps (No relief requests) 3.2.4 Valves (No relief requests) 3.2.5 General (No relief requests) 3.3 Class 3 Components (No relief requests) 3.4 Pressure Tests 17 3.4.1 Class 1 System Pressure Tests (No relief requests) 3.4.2 Class 2 System Pressure Tests 17 3.4.2.1 Request for Relief RR-15,Section XI, Table IWC-2500-1, Examination Category C-H, Items C7.40 and C7.60, Hydrostatic Testing of the High Pressure Coolant Injection (HPCI Pum Associated Lines........).. p Turbine and 17 3.4.3 Class 3 System Pressure Tests 21 3.4.3.1 Request for Relief RR-16, Examination Category D-A, Item DI.10, Functional and Hydrostatic Pressure Testing for the Main Steam Relief Valve Discharge Lines 21 3.4.4 General 23 3.4.4.1 Request for Relief RR-2, 10-Year Hydrostatic Test Requirements for Code Class 1, 2, and 3 Systems 23 3.4.4.2 Request for Relief RR-9, Alternative Pressure Test for Welded Repairs or Replacements in Class 1, 2, and 3 Systems 27 3.5 General 30 3.5.1 Vltrasonic Examination Techniques (No relief requests) 3.5.2 Exempted Components (No relief requests) 3.5.3 Other 30 v
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3.5.3.1 Request for Relief RR-4, ASME Code Class 1, 2, and 3 Integrally Welded Attachments 30 3.5.3.2 Request for Relief RR-7, Examination Category B-J.
Item B9.12 and Examination Category C-F-2, Item C5.52 and C5.82, Examination of Class 1 and 2 Longitudinal Piping Welds 33 3.5.3.3 Request for Relief RR-8, IWA-2413, Upgrade of the ISI Program 35 3.5.3.4 Request for Relief RR-10, Weld Reference System for Class 1 and Class 2 Piping, Vessels, and Components 36 3.5.3.5 Request for Relief RR-12, IWA-5250(a)(2), Corrective Action Resulting from Leakage at Bolted Connections, IWB-2430 and IWC-2430, Additional Examinations......
38 3.5.3.6 Request for Relief RR-13, Table IWC-2500-1, Examination Category C-H, Items C7.10, C7.30, C7.50, and C7.70, Pressure-Retaining Components.........
41 3.5.3.7 Request for Relief RR-14, Request to Implement Alternatives to Code Recording and Reporting Requirements Contained in Code Case N-532 45 4.
CONCLUSION 48 5.
REFERENCES 50 i
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TECHNICAL EVALUATION REPORT ON THE THIRD 10-YEAR INTERVAL INSERVICE INSPECTION PROGRAM PLAN GEORGIA POWER CONPANY EDWIN I. HATCH NUCLEAR POWER PLANT UNITS 1 AND 2 DOCKET NUMBERS 50-321 AND 50-366 1.
INTRODUCTION Throughout the service life of a water-cooled nuclear power facility, 10 CFR 50.55a(g)(4) (Reference 1) requires that components (including supports) that are classified as American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Class 1, Class 2, and Class 3 meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components (Reference 2), to the extent practical within the limitations of design, geometry, and materials of construction of the components. This section of the regulations also requires that inservice examinations of components and system pressure tests conducted I
during successive 120-month inspection intervals shall comply with the requirements in the latest edition and addenda of the Code incorporated by reference in 10 CFR 50.55a(b) on the date 12 months prior to the start of the 120-month inspection interval, subject to the limitations and modifications listed therein. The components (including supports) may meet requirements set forth in subsequent editions and addenda of this Code that are incorporated by reference in 10 CFR 50.55a(b) subject to the limitations and modifications listed therein and subject to Nuclear Regulatory Commission (NRC) approval.
The licensee, Georgia Power Company, has prepared the Edwin I. Hatch Nuclear l
Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0 (Reference 3), to meet the requirements of the 1989 I
Edition of the Code.
The third 10-year interval began January 1,1996.
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i As required by 10 CFR 50.55a(g)(5), if the licensee determines that certain Code examination requirements are impractical and requests relief from them, the licensee shall submit information and justification to the NRC to support that determination.
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Pursuant to 10 CFR 50.55a(g)(6), the NRC will evaluate the licensee's l
determination that Code requirements are impractical to implement.
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The NRC may grant relief and may impose alternative requirements that are determined to be authorized by law, will not endanger life, property, or the common defense and security, and are otherwise in the public interest, giving due consideration to the burden upon the licensee that could result if the requirements were imposed on the facility.
Alternatively, pursuant to 10 CFR 50.55a(a)(3), the NRC will evaluate the licensee's determination that either (i) the proposed alternatives provide an acceptable level of quality and safety, or (ii) Code compliance would result in hardship or unusual difficulty without a compensating increase in safety Proposed alternatives may be used when authorized by the NRC.
The information in the Edwin I. Hatch Nuclear Power Plant, Units 1 and 2.
Third 10-Year Interval inservice Inspection Program Plan, Revision 0, submitted October 17, 1995, was reviewed, including the requests for relief from the ASME Code Section XI requirements that the licensee has determined to be impractical.
The review of the Inservice Inspection (ISI) Progra.. Plan was performed using the Standard Review Plans of NUREG-0800 (Reference 4),
Section 5.2.4, " Reactor Coolant Boundary Inservice Inspection and Testing "
and Section 6.6, " Inservice Inspection of Class 2 and 3 Components."
In transmittals dated November 16, 1995 (Reference 5) and October 23, 1996 (Reference 6), the NRC requested additional information that was required to complete the review of the ISI Program Plan.
Georgia Power Company provided the requested information in letters dated January 26, 1996 (Reference 7), and November 18, 1996 (Reference 8).
In these responses, the licensee provided clarification on the program, submitted one additional request for relief, and revised one request for relief.
In a conference call dated February 8, 1996, the NRC requested clarification on exemption of Code class piping in containment penetrations (Reference 9).
By letter dated April 5, 1996, the licensee responded to the inquiry and submitted two additional requests for relief (Reference 10).
By letter dated June 4, 1996, the licensee submitted two additional requests for relief, the result of an update to the pressure testing program (Reference 11).
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The Edwin I. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval l
Inservice Inspection Program Plan, Revision 0, is evaluated in Section 2 of this report. The ISI Program Plan is evaluated for (a) compliance with the appropriate edition / addenda of Section XI, (b) acceptability of examination sample, (c) correctness of the application of system or component examination exclusion criteria, and (d) compliance with ISI-related commitments identified during the NRC's previous reviews.
The requests for relief are evaluated in Section 3 of this report.
Unless otherwise stated, references to the Code refer to the ASME Code,Section XI, 1989 Edition.
Specific inservice test (IST) programs for pumps and valves are being evaluated in other reports.
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2.
EVALUATION OF INSERVICE INSPECTION PROGRAN PLAN This evaluation consists of a review of the applicable program documents to j
determine whether or not they are in compliance with the Code requirements and any previous license conditions pertinent to ISI activities. This section i
describes the submittals reviewed and the results of the review.
2.1 Documents Evaluated Review has been completed on the following information from the licensee:
(a) Edwin I. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0, submitted October 17, 1995 (Reference 3).
(b) Response to Request for Additional Information, Third 10-Year Interval Inservice Inspection Program, submitted January 26, 1996 (Reference 7).
(c) Response to Request for Additional Information, Third 10-Year Interval Inservice Inspection Program, submitted April 5,1996 (Reference 10).
(d) Additional Requests for Relief, Third 10-Year Interval Inservice Inspection Program, submitted June 4, 1996 (Reference 11).
(e) Response to Request for Additional Information, Third 10-Year Interval Inservice Inspection Program, submitted November 18, 1996 (Reference 8).
2.2 Comoliance with Code Reoufrements 2.2.1 Compliance with Apolicable Code Editions The ISI Program shall be based on the Code editions defined in 10 CFR 50.55a(g)(4) and 10 CFR 50.55a(b).
Based on the starting date of January 1, 1996, for Edwin I. Hatch Nuclear Plant, Units 1 and 2, the Code applicable to the third interval ISI program is the 1989 Edition.
As stated in Section 1 of this report, the licensee has prepared the Edwin I. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0, to meet the requirements of the 1989 Edition.
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In accordance with 10 CFR 50.55a(c)(3), 10 CFR 50.55a(d)(2), and 10=CFR 50.55a(e)(2), ASME Code Cases may be applied to systems and components as alternatives to Code requirements.
ASME Code Cases that have been found suitable for use by the NRC are listed in the current i
revision of Regulatory Guide 1.147, inservice Inspection Code Case j
Acceptability, with conditions for use, as applicable.
These Code cases must.be implemented in.their entirety and the licensee may adopt them by providing written notification to the NRC.
Published Code cases awaiting approval and subsequent listing in Regulatory Guide 1.147 may l
be adopted only if the licensee requests, and the NRC authorizes, their i'
use on a case-by-case basis.
l The licensee has requested to implement the alternatives to Code requirements. contained in the following Code cases.
These requests are i
evaluated in Requests for Relief RR-2, RR-4, RR-7, RR-9, RR-13 and RR-14, respectively.
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. Code Case N-416-1 Alternative Pressure Test Requirement for Welded 1
Repairs or Installation of Replacement Items by Welding, Class 1, 2, and 3 t
l Code Case N-498-1 Alternative Rules for 10-Year Systems Hydrostatic Testing for Class 1, 2, and 3 Systems Code Case N-509 Alternative Rules for the Selection and Examination of Class 1, 2, and 3 Integrally Welded Attachments Code Case N-522 Pressure Testing of Containment Penetration Piping Code Case N-524 Alternative Examination Requirements for i
Longitudinal Welds-in Class 1 and 2 Piping Code Case N-532 Alternative Requirements to Repair and Replacement Documentation Requirements and Inservice Summary
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Report Preparation and Submission as Required by IWA-4000 and IWA-6000 2.2.2 Acceptability of the Examination Samole i
Inservice volumetric, surface, and visual examinations shall be performed on ASME Code Class 1, 2, and 3 components and their supports using sampling schedules described in Section XI of the ASME Code and 10 CFR 50.55a(b).
The sample size and weld selection have been 5
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implemented in accordance with the Code and 10 CFR 50.55a(b) and appear to be correct.
2.2.3 Exemotion Criteria The criteria used to exempt components from examination shall be consistent with Paragraphs IWB-1220, IWC-1220, IWC-1230, IWD-1220, and 10 CFR 50.55a(b).
The exemption criteria have been appliec by the licensee in accordance with the Code, as discussed in the ISI Program Plan, and appear to be correct.
2.2.4 Auomented Examination Commitments In addition to the requirements specified in Section XI of the ASME Code, the licensee has committed to perform the augh. anted examinations listed below.
Georgia Power Company is not committed to Regulatory Guide 1.150, Ultrasonic Testing of Reactor Vessel Welds During Preservice and Inservice Examinations (Reference 12).
However, portions of Regulatory Guide 1.150, are used for guidance. Augmented reactor pressure vessel examinations required by the Code of Federal Regulations, Part 10, 50.55a(g)(6)(ii)(A), will be evaluated in a separate report.
(a) Augmented inspections on the Unit 2, main steam, feedwater, high pressure coolant injection (HPCI) steam, reactor core isolation cooling (RCIC) steam, and reactor water cleanup (RWC) fluid systems outside primary containment will be performed in accordance with Branch Technical Position MEB 3-1, High Energy Fluid Systems, Protection Against Postulated Piping Failures in Fluid Systems Outside Containment. As documented in a December 1972, NRC letter from A. Giambusso concerning High Energy Pipe Breaks Outside Containment, augmented examinations are not required for Unit 1; (b) Examination of welds susceptible to intergranular stress corrosion cracking (IGSCC) as specified by NUREG-0313 (Reference 13);
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(c) Examination of the feedwater nozzle as specified by NUREG-0619 (Reference 14) as modified by Generic Letter 81-11; (d) Examination of Scram System Piping in accordance with NUREG-0803; (e) Examination of stainless steel pipe welds in accordance with Generic Letter 88-01, NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel Piping (Reference 15);
(f) Examination of core shrouds in accordance with Generic Letter 94-03; (g) Examination of High and Low Pressure Core Spray Spargers in accordance with IEB 80-13 and NUREG CR-4523; and l
(h) Volumetric examination of a. /.5% sample of a portion of thin-wall, nonexempt piping within the Residual Heat Removal, Core Spray, and High Pressure Coolant Injection systems.
2.3 Conclusions Based on the review of the documents listed above, no deviations from
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regulatory requirements or commitments have been identified in the Edwin I. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval Inservice Inspection Program Plan, Revision 0.
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EVALUATION OF RELIEF REQUESTS
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The requests for relief from the Code requirements that the licensee has 1
determined to be impractical for the third 10-year inspection interval are l
evaluated in the following sections.
3.1 Class 1 Comconents 3.1.1 Reactor Pressure Vessel l
3.1.1.1 Reauest for Relief RR-1. Examination Cateoorv 8-G-1.
Item B6.10. Reactor Vessel Closure Head Nuts Code Reauirement:
Section XI, Table IWB-2500-1, Examination Category B-G-1, Item B6.10 requires a 100% surface examination l
of all reactor vessel closure head nuts.
Licensee's Code Relief Reauest: The licensee requested relief l
from performing the Code-required surface examination of the l
reactor vessel closure head nuts as specified in Table IWB-2500-1.
l Licensee's Basis for Reauestina Relief (as stated):
l "The closure head nut configuration does not allow for an adequate Magnetic Particle examination.
The MT method requires j
two directional coverage to detect the surface flaws.
The configuration permits examination in one direction and limits i
the coverage in the other direction.
The Liquid Penetrant l
method is not practical, due to the lubricant applied to the inside surface.
The lubricant is difficult to completely remove in order to get a proper exam.
"ISI optimization did a survey on bolting.
Results did not reveal any service induced cracking.
No cracks have been detected at Plant Hatch, Units 1 & 2.
No flaws have been l
detected at Plant Farley or Vogtle. This survey was part of i
the technical basis for changing the surface requirement to a VT-1.
"Later editions of the ASME code changed the examination requirement to a VT-1.
Since the change (visual examination) j was issued by ASME, the alternative examination should be l
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technically acceptable for determining flaws.
The proposed alternative visual examination, VT-1 will provide reasonable assurance that unallowable inservice flaws have not developed in the subject components or that they will be detected and repaired prior to return of the reactor vessel to service.
If relevant indications are detected, alternate surface / volumetric techniques will be performed as necessary.
Thus an acceptable level of quality and safety will have been achieved and public health and safety will not be endangered by allowing the proposed alternative examination in lieu of the Code requirement.
By implementing the alternative examinations, cost savings, personnel radiation dose, and outage time can be realized by Georgia Power Company at Plant Hatch.
Time spent performing the examinations will be minimized, while ALARA principles will be adhered to by reducing contact with contaminated components."
i licensee's ProDosed Alternative Examination (as stated):
" Georgia Power Company proposes that, in lieu of the 1989 Edition, Code-required surface examination, the subject RPV Closure Head Nuts will receive a Visual Exam, VT-1 in accordance with the ASME,Section XI, 1989 Addenda."
Evalaation:
The licensee has requested relief from performing the Code-required surface examination of the reactor pressure vessel closure head nuts.
As an alternative, the licensee proposes to perform a VT-1 visual examination.
All Items in Examination Category B-G-1 except the reactor pressure vessel closure head nuts and the closure studs (when removed) require VT-1 visual examinations and volumetric examination (as applicable).
Typical conditions that would require corrective action prior to putting closure head nuts back into service would include corrosion, deformed or sheared threads, deformation, and degradation mechanisms (i.e., boric acid attack).
The Code i
requires a surface examination for closure head nuts.
Surface j
examination procedures are typically qualified for the detection of linear flaws (cracks) and have acceptance criteria specifying only rejectable linear flaw lengths.
Acceptance criteria are not provided in the 1989 Edition of the Code, Item B6.10, as they were in the course of preparation when the Code was published. Without clearly defined acceptance criteria, l
conditions that require corrective measures may not be adequately addressed. The 1989 Addenda of Section XI addresses these problems by changing the requirement for the subject reactor pressure vessel closure head nuts from surface to VT-1 visual examination and providing appropriate acceptance criteria.
Article IWB-3000, Acceptance Standards, IWB-3517.1, Visual Examination, VT-1, describes conditions that require corrective action prior to continued service for bolting and associated nuts.
One of these requirements is to compare crack-like flaws to the flaw standards of IWB-3515 for acceptance.
Because the VT-1 visual examination acceptance criteria include evaluation of crack-like indications and other conditions requiring corrective action, such as deformed or sheared threads, localized corrosion, deformation of part, and other degradation mechanisms, it can be concluded that the VT-1 visual examination provides a more comprehensive assessment of the condition of the closure head nut. As a result, the INEL staff q
believes that VT-1 visual examination provides an acceptable level of quality and safety.
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Conclusion:==
Based on the comprehensive assessment that the VT-1 visual examination provides, and considering that later editions of the Code require only a VT-1 visual examination on reactor pressure vessel closure head nuts, it is concluded that an acceptable level of quality and safety will be provided by the proposed alternative.
Therefore, it is recommended that the proposed alternative, VT-1 visual examination, be authorized pursuant to 10 CFR 50.55a(a)(3)(i).
3.1.1.2 Reauest for Relief RR-3. Examination Cateaory B-D. Items 83.90 and B3.100. Reactor Pressure Vessel Nozzle-to-Shell Welds and Nozzle Inner Radius Sections Code Reouirement:
Section XI, Table IWB-2500-1, Examination Category B-D, Items B3.90 and B3.100 require a 100% volumetric 10
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examination of all reactor vessel nozzle-to-shell welds and nozzle inside radius sections as defined by Figure IWB-2500-7(a) through (d) as applicable.
Licensee's Code Relief Reaues.t:
The licensee requested relief l
from performing the Code-required volumetric examinations for the following reactor vessel nozzles.
2" NPS Bottom Head Drain Vessel-to-Nozzle Welds N15 and 2N15, and 2" NPS Bottom Head Drain Vessel Inside Radius Sections N15 and 2N15 Licensee's Basis for Reauestina Relief (as stated):
l "There is no known technique that can be used on the inside of the vessel to examine the nozzle. Access is not available to examine from the outside of the vessel.
During the Leakage Test / Hydrostatic Test, GPC will ensure there is no leakage coming from the area of the subject nozzles.
The VT-2 visual examination should provide reasonable assurance that unallowable inservice flaws have not developed in the subject welds or that they will be detected and repaired prior to return of the reactor vessel to service."
Licensee's Proposed Alternative Examination (as stated):
" Georgia Power Company proposes that, in lieu of the Code-required volumetric examination, the subject nozzle welds will receive a visual (VT-2) examination during the Leakage Test / Hydrostatic Test."
Evaluation:
The Code requires that the subject nozzle-to-shell welds and inner radius sections be volumetrically examined.
Based on a review of the information provided, it has been determined that the Code-required volumetric examination of the bottom head drain vessel-to-nozzle welds and inner radius sections are impractical because of inaccessibility.
These examination items are within the area of the control rod drive housings, in the center of the bottom head.
To provide access for a volumetric examination, design modifications would be required.
Imposition of this requirement would cause a considerable burden on the licensee.
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As an alternative to the Code-required volumetric examinations, the licensee proposes to perform VT-2 visual examinations of the subject areas in conjunction with the system leakage and hydrostatic tests. Considering the impracticality of performing a volumetric examination on the subject areas, the INEL staff believes that the proposed alternative VT-2 visual examination during pressure tests will provide reasonable assurance of operational readiness.
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Conclusion:==
For the subject reactor vessel bottom head drain vessel-to-nozzle welds and nozzle inside radius sections, performing the Code-required volumetric examination is impractical.
The INEL staff believes that the licensee's proposed VT-2 visual examination will provide reasonable assurance of operational readiness. Therefore, it is recommended that relief be granted pursuant to 10 CFR 50.55a(g)(6)(i).
3.1.2 Pressurizer (Not applicable) j 3.1.3 Heat Exchanaers and Steam Generators (No relief requests) 3.1.4 Pipina Pressure Boundary 3.1.4.1 Reauest for Relief RR-6. Examination Cateaory B-F. Item B5.20.
Examination of Reactor Pressure Vessel Nozzle-to-Safe-End Butt Welds i
Code Reauirement:
Section XI, Table IW8-2500-1, Examination Category B-F, Item B5.20 requires a 100% surface examination of Class 1 safe-end welds in piping less than 4-inch nominal pipe size as defined in Figure IWB-2500-8.
Licensee's Code Relief Reouest:
The licensee requested relief from performing 100% of the Code-required surface examination on the following Class 1 safe-end welds.
i 12
2.5" Core D.P. & Liquid Control Nozzle-to-Safe-End Welds N10 and 2N10; 3" Bottom Head Drain Nozzle-to-Safe-End Welds NIS and 2N15; and 2.5" RPV Instrumentation Nozzle-to-Safe-end Welds N16A, 2N16A, N16B and 2N16B.
Licensee's Basis for Reauestina Relief (as stated):
"These instrument nozzles (N10, N16A/B, 2N10, 2N16A/B) have very limited access due to the design of the concrete shield.
Each nozzle has small doors that can be opened allowing 12 to 18 inches of access. However, due to the distance the RPV wall is recessed from the outside of the shield wall (e.g.
insulation thickness, air gap, and shield thickness), the welds cannot be physically reached with enough room to perform the surface examination.
j "The N15 and 2N15 welds are the Bottom Head Drain Nozzles.
l These welds are located in the center of the Bottom Head and are not accessible due to the Control Rod Drive Housings (see attached drawings)'.
"VT-2 examination in conjunction with the Class 1 system leakage / hydrostatic test each refueling outage will provide adequate assurance that any flaw (s) that might have propagated through the subject welds are identified and repaired prior to returning the plant to power operation.
"In addition, other RPV Instrument Nozzles which have adequate access (N11A/B, N12A/B, 2N11A/B, 2N12A/B) will receive a Code required surface examination and a supplemental volumetric examination. Therefore, a 50% sample will receive in excess of Code Required surface exams.
"The visual examination of the subject nozzles as well as the Code surface exam and supplemental volumetric examination of similar nozzles with the same Code category, will provide reasonable assurance that unallowable inservice flaws have not developed in the subject welds or that they will be detected and repaired prior to return of the reactor vessel to service.
Thus an acceptable level of quality and safety will have been achieved and public health and safety will not be endangered by allowing the proposed alternative examination in lieu of Code requirement."
i
'Not included with this evaluation.
13
l Licensee's Proposed Alternative Examination (as stated):
" Georgia Power Company proposes that, in lieu of the Code-required surface examination, the following reactor vessel nozzle-to-safe-end butt welds will receive a VT-2 examination:
N10, N15, N16A/B, 2N10, 2N15, 2N16A/B."
"In addition, other RPV Instrument Nozzles which have adequate access (N11A/B, N12A/B, 2N11A/B, 2N12A/B) will receive a Code required surface examination and a supplemental volumetric examination.
Therefore, a 50% sample will receive in excess of Code Required surface exams."
Evaluation:
The licensee has requested relief from performing the Code-required surface examinations of the subject safe-end welds.
Based on a review of the sketches provided, it has been determined that the Code-required surface examinations of the subject areas are impractical due to inaccessibility.
The NIS nozzle safe-ends are located within the control rod drive housing assembly in the center of the bottom head, and the N10 i
and N16 nozzle safe-ends are located out of reach inside the bioshield.
To provide access for a surface examination, design 1
modifications would be required.
Imposition of this
~
requirement would cause a considerable burden on the licensee.
The licensee proposes to perform VT-2 visual examinations of the subject examination areas.
In addition, the licensee will 1
perform a volumetric examination in conjunction with the Code-required surface examination on the N11 and N12 nozzle safe-ends.
These nozzles / safe-ends are similar in design to the N10, N15, and N16 safe-ends.
Based on the licensee's proposed alternative, it is reasonable to conclude that generic degradation, if present, will be detected. As a result, reasonable assurance of operational readiness will be provided.
l
==
Conclusion:==
The licensee proposes to perform VT-2 visual examinations of the subject examination areas and ultrasonic examinations on a sample of similar examination areas.
Based on the licensee's proposed alternative, it is reasonable to conclude that significant degradation, if present, will be l
14 l
l detected, thereby providing reasonabic assurance of operational readiness.
Therefore, it is recommended that relief be granted pursuant to 10 CFR 50.55a(g)(6)(i).
i 3.1.5 Pumo Pressure Boundary (No relief requests) l 3.1.6 Valve Pressure Boundary (No relief requests) i 3.1.7 General (No relief requests) j 3.2 Class 2 Comoonents 3.2.1 Pressure Vessels 3.2.1.1 Reouest for Relief RR-5. Examination Cateaory C-A. Item C1.20.
Class 2 Residual Heat Removal Heat Exchanaer Circumferential Head Welds Code Reauirement: Table IWC-2500-1, Examination Category C-A, Item C1.20, requires a 100% volumetric examination of circumferential head welds in Class 2 pressure vessels, as defined in Figure IWC-2500-1.
Licensee's Code Relief Reauest: The licensee requested relief from 100% volumetric examination of the following Residual Heat Removal Heat Exchanger Shell Head-to-Upper Shell Ring Welds:
1 Ell-2HX-A-1, IE11-2HX-B-1, 2HX-A-1, and 2HX-B-1.
Licensee's Basis for Reauestina Relief (as stated):
"The subject welds cannot be completely ultrasonically examined due to permanent welded brackets located at 0, 90, 180, and 270 degrees (see attached Figure)2 These brackets are l
located in the examination area and prohibit full coverage from l
either side of the weld.
Estimated coverage based on previous examination data is 72% of the required volume.
2Not included with this evaluation.
15
"The proposed supplemental surface examination and the Code required volumetric examination (to the extent practical considering the physical limitations) will provide reasonable assurance that unallowable inservice flaws have not developed in the subject welds or that they will be detected and repaired prior to return of the reactor vessel to service.
Thus an acceptable level of quality and safety will have been achieved and public health and safety will not be endangered by allowing the limited examinations and the proposed alternative examinations in lieu of the full Code requirement."
Licensee's Procosed Alternative Examination (as stated):
" Georgia Power Company proposes to supplement the volumetric examination of Head to Shell Welds with a surface examination, to the extent practical."
Evaluation:
The Code requires a 100% volumetric examination of pressure vessel head circumferential welds.
Based on the information provided, it has been determined that scanning limitations due to welded brackets located at 0, 90, 180, and 270 degrees preclude 100% volumetric examinations.
To perform the volumetric examinations to the extent required by the Code, design modifications would be necessary, causing a considerable burden on the licensee.
The licensee proposes to perform the volumetric examinations to the extent practical, which is estimated to be approximately 72% volumetric coverage.
In addition, the licensee proposes to perform a supplemental surface examination of areas not receiving volumetric coverage.
Based on the volumetric coverage that can be obtained, in combination with the proposed i
surface examination of those areas not being volumetrically examined, it can be concluded that significant degradation, if present, will be detected. As a result, reasonable assurance of structural integrity will be provided.
==
Conclusion:==
Volumetric examination of the subject areas to the extent required by the Code is impractical due to interference from integral attachments.
Based on the percent of vclumetric coverage that can be obtained, in combination with the 16
supplemental surface examination for areas that do not receive the required volumetric coverage, it can be concluded that significant degradation, if present, will be detected.
As a result, reasonable assurance of structural integrity will be provided. Therefore, it is recommended that relief be granted pursuant to 10 CFR 50.55a(g)(6)(i).
3.2.2 Pioina (No relief requests) 3.2.3 Pumos (No relief requests) 3.2.4 Valves (No relief requests) 3.2.5 General (No relief requests) 3.3 Class 3 Components (No relief requests) 3.4 Pressure Tests 3.4.1 Class 1 System Pressure Tests (No relief requests) 3.4.2 Class 2 System Pressure Tests 3.4.2.1 Request for Relief RR-15.Section XI. Table IWC-2500-1.
Examination Cateaory C-H. Items C7.40 and C7.60. Hydrostatic Testina of the Hiah Pressure Coolant In.iection (HPCI) Pumo Turbine and Associated lines Code Reauirement:
Section XI, Table IWC-2500-1, Examination Category C-H, Items C7.40 and C7.60, require a VT-2 visual examination during hydrostatic tests of Class 2 systems performed in accordance with IWC-5222 near the end of the interval.
IWA-5213 states that for system hydrostatic tests, a l
4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time is required after attaining the test pressure and temperature conditions for insulated systems, and a 10 l
minute hold time for noninsulated systems or components.
17
a 8
In addition, the licensee requested relief from the hydrostatic 9
pressure test requirements for Code Class 1, 2, and 3 systems.
Specifically, the licensee requested to use Code Case N-498-1, Alternative Rules for 10-Year System Hydrostatic Testing for Class 1, 2, and 3 Systems,Section XI, Division 1.
This request is addressed in Relief Request RR-2.
For Class 2 system hydrostatic tests, Code Case N-498-1 states:
" Prior to performing the VT-2 visual examination, the system shall be pressurized to nominal operating pressure for a minimum of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for insulated systems and 10 minutes for noninsulated systems.
The system shall be maintained at nominal operating pressure during performance of the VT-2 visual examination".
Licensee's Code Relief Reouest:
The licensee requests relief from the 4-hour hold time prior to performing the VT-2 visual examinations associated with hydrostatic tests of the Class 2 High Pressure Coolant Injection (HPCI) Pump Turbine steam supply / exhaust lines, and associated drains and vent lines extending from the turbine to the suppression pool.
Ljcensee's Basis for Reouestino Relief (as stated):
"Pumo Discharae Pioina - A test pump is required to pressurize the pump discharge piping and apply a 4-hour hold time prior to the leakage inspection.
One of the boundary components for this test is HPCI pump discharge check valve F005 since the pump suction piping is designed for low pressure. _ The capacity of a standard high pressure test pump (>1000 psig) is relatively small (<3 gpm), thus complicating pressurization of large bore piping and components (14 inches especially when attempting to utilize a check valve as a pre)ssure boundary.
Therefore, pressurizing the pump discharge piping to normal system operating pressure (approximately 1050 psig) utilizing a test pump will likely require a significant time duration and may not be possible due to the leakage characteristics of the discharge check valve.
" Turbine Exhaust Pioina - The turbine exhaust piping is designed to exhaust spent steam from HPCI turbine to the suppression pool for condensing.
This piping is not designed to support the weight associated with filling the pipe with water as required in performing a hydrostatic pressure test.
Performing a tt:st using water as the test fluid requires the installation cN temporary piping supports which requires the 18
L
\\.
l following: declaring the system inoperable; performing an l
engineering analysis to determine support requirements and seismic considerations; fabricating, installing, and removing the temporary supports; and planning and scheduling to minimize the impact on other plant activities and system unavailability.
This test also requires that the turbine be completely drained l
prior to placing the system back in service, in order to prevent component damage from water intrusion.
"All HPCI System pioing - Performance of a leakage inspection after 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of system operation is impractical due to the design basis temperature constraints on the suppression pool and the Limiting Conditions of Operation imposed by Technical l
Specifications.
The suppression pool temperature must be constantly monitored during HPCI System operation to ensure design basis accident conditions (suppression pool water temperature) are not_ exceeded.
HPCI System operation and the discharge of spent steam to the suppression pool significantly increase water temperature.
Historical data indicate a maximum allowable operation time of approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, even with operation of the Residual Heat Removal System in the suppression pool cooling mode.
" Requiring a 4-hour hold time prior to performing the leakage examination (VT-2) results in an undue hardship without a commensurate increase in quality and safety of the affected 1
components.
Performing a system function test and a VT-2 inspection, in accordance with IWA-5211 period, in addition to Operations person (b), each inspection nel performing routine visual examinations in conjunction with quarterly inservice testing of the HPCI pump, ensures the pressure boundary integrity of the subject piping and components is maintained and/or any leakage is identified and corrective actions are implemented."
Licensee's Proposed Alternative Examination (as stated):
"GPC will perform visual examinations (VT-2) of the pump discharge, turbine exhaust, and turbine exhaust drain piping and components, in conjunction with a system function test (IWA-5211(b)), once each inspection period."
j Evaluation:
Both the Code and Code Case N-498-1 specify pressure tests that include a 4-hour hold time prior to l
performing the VT-2 visual examination during the hydrostatic j
test of insulated systems.
The licensee has stated that j
compliance with the pressure test and 4-hour hold time will result in a burden and could compromise plant safety.
Based on l
the review of the information provided, the INEL staff believes 19 l
1
that, under the circumstances presented, the pressure test and 4-hour hold time for the subject system would require the operation of other safety-related systems, creating an operational safety concern.
This is because the required 4-hour hold time, during system operation, would cause the Suppression Pool water temperature to rise above that allowed by Technical Specifications.
Even with the use of the Residual Heat Removal System, the maximum allowable operation time is stated to be approximately one hour.
Under these test conditions, should an actual plant emergency occur, the additional actions required to bring the plant to a safe shutdown condition could be compromised.
The licensee proposed to perfor.n a VT-2 visual examination in conjunction with the System Functional test once each period.
The INEL staff believes that performing the VT-2 visual examination in conjunction with the system functional test (at pressure for approximately one hour) will ensure the detection of leakage in insulated systems.
f
==
Conclusion:==
For the subject system, requiring the licensee to I
comply with the 4-hour hold time would result in a considerable burden.
The licensee stated that periodic tests at operating pressure are performed each period.
During these tests, the l
operating pressure is maintained for approximately one hour for performance of the functional test.
Performing the VT-2 visual examination with the system at normal operating pressure for one hour, should ensure that leakage will be detected, j
providing reasonable assurance of operational readiness.
Therefore, it is recommended that the licensee's proposed alternative be authorized pursuant to 10 CFR 50.55a(a)(3)(ii).
i i
20
1 3.4.3 Class 3 System Pressure Tests 1
3.4.3.1 Reauest for Relief RR-16. Examination Cateaory 0-A. Item D1.10.
Functional and Hydrostatic Pressure Testina for the Main Steam Relief Valve Discharae Lines (Revised by letter dated November
- 18. 1996)
Code Reauirement:
Section XI, Table IWD-2500-1, Examination Category D-A, Item D1.10 requires a System Pressure Test and/or a System Hydrostatic Test be performed.
IWD-5223(f) states that for safety or relief valve piping that discharges into the containment pressure suppression pool, a pneumatic test (at a pressure of 90% of the pipe submergence head of water) that demonstrates leakage integrity shall be performed in lieu of a system hydrostatic test.
Licensee's Code Relief Reauest:
The licensee requested relief from performing a pneumatic pressure test on SRV B21-F013, main steam relief valve discharge piping.
Licensee's Basis for Reauestina Relief (as stated):
"The SRV discharge piping is 10 inches in diameter, has a design pressure rating of 448 psig for Unit 1 and 500 psig for Unit 2, and has a submergence head of approximately 10 feet.
The resultant pneumatic pressure test would be performed at approximately 4 psig.
Performing a pressure test at less than 1/100 of the design pressure serves no useful purpose associated with pressure boundary or structural integrity of the SRV discharge piping.
"The inspection associated with a pneumatic test usually consists of solution film testing of the test boundary, or some other inspection / test methods (e.g., sonic gun) which must be demonstrated to the satisfaction of the ANII.
The majority of l
the discharge piping is not accessible because of the lack of L
permanent scaffolding in the drywell and portions of the piping l
are located in the drywell to suppression pool vent headers.
Much of the piping in the drywell is in high radiation areas due to it proximity to reactor recirculation piping and pumps.
Therefore, only a limited portion of the piping is accessible for solution film testing, or for any other method of inspection, without significant increases in manpower, radiation exposure, and budget.
21 l
l
" Based on the above discussion, performing a pneumatic pressure test of the SRV discharge piping in accordance with the 1989 ASME Code Section XI is impractical and will not result in a compensating increase in the level of quality and safety.
" Pressure testing the SRV discharge piping does not result in a significant safety benefit for normal operation or shutdown of the plant.
The ASME Code Section XI Committee agree with the position stated herein.
The requirement to perform the pressure testing was deleted in the 1995 Code Edition.
1 Paragraph IWD-5240 was added in the 1995 Edition exempting SRV discharge piping, as well as all open-ended discharge piping, from examination requirements."
Licensee's Proposed Alternative Examination (as stated):
"The accessible portions of the SRV discharge piping will be 4
visually examined (VT-3) at least once each 40-month inspection i
j period to provide reasonable assurance of structural integrity i
of the piping. The associated piping supports are examined in accordance with the ASME Section XI requirements."
a 4
Evaluation:
For safety or relief valve piping that discharges into the containment pressure suppression pool, the Code requires a pneumatic test (at 90% of the pressure of the pipe submergence head of water) that demonstrates leakage integrity to be performed in lieu of a system hydrostatic test.
Submergence head pressure for the subject piping is approximately 4 psig. The INEL staff believes that performing a pressure test at 4 psig when the piping operates at pressures 1448 psig, is not a meaningful test of the operational readiness.
In addition, to perform the pneumatic pressure test, assembly and disassembly of scaffolding in radiation areas would be required. As a result, it is concluded that the Code-required pressure test is an undue burden.
It is noted that later editions of the Code (1992 Addenda) have exempted open-ended portions of discharge lines beyond the last shutoff and open-ended safety or relief valve discharge lines, including safety or relief valve piping that discharges in the containment pressure suppression pool from hydrostatic tests.
22
Considering the licensee's request for relief from Code requirements, and the subsequent removal of this requirement later editions of the Code, the INEL staff believes that requiring the licensee to perform a pneumatic test on the subject lines results in a burden without a compensating increase in quality and safety.
As an alternative to the Code requirements, the licensee proposes to perform a VT-3 visual examination for verification of discharge piping integrity once each 40-month inspection period.
The INEL staff believes that this verification of the integrity of the discharge flow path will provide reasonable assurance of operational readiness.
==
Conclusion:==
Requiring the licensee to perform a pneumatic test on the SRV discharge piping to the suppression pool at a test pressure of only 4 psig results in a burden without a compensating increase in quality and safety.
Based on the licensee's proposal to perform a VT-3 visual examination once each 40-month inspection period, verification of discharge piping integrity will be ensured, providing reasonable assurance of operational readiness of the subject piping.
Therefore, it is recommended that the licensee's proposed alternative be authorized pursuant to 10 CFR 50.55a(a)(3)(ii).
3.4.4 _ General 3.4.4.1 Reouest for Relief RR-2. 10-Year Hydrostatic Test Reouirements for Code Class 1, 2. and 3 Systems Code Reouirement:
The requirements for system hydrostatic testing are contained in Table IWB-2500-1, Category B-E, Items B4.11, B4.12, and B4.13, and Category B-P, Items B15.11, B15.51, B15.61, and 815.71 (for Class I systems); Table IWC-2500-1, Category C-H, Items C7.20, C7.40, C7.60, and C7.80 (for Class 2); and Table IWD-2500-1, Categories D-A, D-8, and 23
D-C, Items 01.10, D2.10, and D3.10 (for Class 3).
The Code requires system hydrostatic testing once per 10-year interval at or near the end of the interval.
Licensee's Code Relief Reauest: The licensee requested relief from ASME Section XI hydrostatic test requirements for Code Class 1, 2, and 3 systems.
Licensee's Basis for Reauestina Relief (as stated):
"ASME Section XI Code Case N-498-1 was issued on May 11, 1994.
This Code Case has been approved by the NRC staff for use at Plant Hatch and other, plants, but has not been formally endorsed by inclusion in NRC Regulatory Guide 1.147.
It was.
previously approved for Plant Hatch for the 2nd Interval by SER dated 7/5/95.
"The proposed alternative testing requirements have been evaluated by the ASME Code Committee and the NRC and have been deemed acceptable for determining the pressure boundary integrity of the affected components.
Implementation of pressure testing in accordance with the subject Code Case will ensure an acceptable level of quality and safety,.ioes not decrease the margin of public health and safety a d is 'thus authorized pursuant to 10 CFR 50.55a(a)(3)(1).
fy implementing the alternative examinations, cost savings, personnel radiation dose, and outage time can be realized by Georgia Power Company at Plant Hatch."
Licensee's Proposed Alternative Examination (as stated):
" Georgia Power Company will comply with the pressure testing requirements of ASME Section XI Code Case N-498-1 for the listed Code item numbers."
Evaluation: The' Code requires a system hydrostatic test to be performed once per interval in accordance with IWA-5000 for Class 1, 2, and 3 pressure-retaining systems.
In lieu of the Code, the licensee proposes to implement the alternatives to Code requirements' contained in Code Case N-498-1, Alternative Rules for 10-Year System Hydrostatic Testing for Class 1, 2, and 3 Systems, dated May 11, 1994.
24
The system hydrostatic test stipulated in Section XI is not a test of the structural integrity of the system but rather an enhanced leakage test (Reference 16). Hydrostatic testing only subjects the piping components to a small increase in pressure over the design pressure; therefore, piping dead weight, thermal expansion, and seismic loads present far greater challenges to the structural integrity of the system.
Consequently, the Section XI hydrostatic pressure test is primarily regarded as a means to enhance leak detection duri the examination of components under pressure, rather than as method to determine the structural integrity of the components a
In addition, the industry experience indicates that leaks are not being discovered as a result of hydrostatic test pressures causing a preexisting flaw to propagate through the wall-in most cases leaks are being found when the system is at normal operating pressure.
In lieu of 10-year hydrostatic pressure testing at or near the end of the 10-year interval, Code Case N-498-1 requires a VT-2 visual examination at nominal operating pressure and temperature in conjunction with a system leakage test performed in accordance with paragraph IWA-5000 of the 1992 Edition of Section XI.
The requiremeni.s of Code Case N-498-1 for Class 1 and 2 systems are the same as those of Code Case N-498, Alternative Rules for 10-Year System Hydrostatic Testing for Class 1 and 2 Systems, which was previously approved for general use on Class 1 and 2 systems in Regulatory Guide 1 147 Rev. 9.
For Class 3 systems, N-498-1 specifies requirements identical to those for Class 2 components.
Class 3 systems do not normally receive the amount and/ w type of nondestructive examinations that Class 1 and 2 systems receive.
While Class 1 and 2 system failures are relatively uncommon, Class 3 leaks occur more frequently and are caused by different failure mechanisms. Based on a review of Class 3 25 i
-~
~
system failures requiring repair during the last 5 years, the most common causes of failures are erosion-corrosion (EC),
microbiological 1y-induced corrosion (MIC), and general In general, licensees have implemented programs for corrosion.
the prevention, detection, and evaluation of EC and MIC; therefore, Class 3 systems receive inspections commensurate with their functions and expected failure mechanisms.
System hydrostatic testing entails considerable time, radiation The safety assurance provided by dose, and dollar resources.
the enhanced leakage detection gained from a slight increase in system pressure during a hydrostatic test may be offset or negated by the necessity to gag or remove Code safety and/or relief valves (placing the system, and thus the plant, in an off-normal state), erect temporary supports in steam lines, and expend resources to set up testing with special equipment and Therefore, performance of system hydrostatic testing gages.
represents a considerable burden. Giving consideration to the minimal amount of increased assurance provided by the increased pressure associated with a hydrostatic test versus the pressure for the system leakt.ge test, and the hardship associated with performing the hydrostatic test, the INEL staff finds that compliance with the Section XI hydrostatic testing requirements results in hardship and/or unusual difficulty without a compensating increase in the level of quality and safety.
==
Conclusion:==
Compliance with the Code's hydrostatic testing requirements results in hardship and/or unusual difficulty without a compensating increase in the level of quality and Performing the hydrostatic pressure test in accordance safety.
with Code Case N-498-1 will provide reasonable assurance of Therefore, it is recommended that the operational readiness.
licensee's proposed alternative, to implement the pressure test rules of Code Case N-498-1 for Code Class 1, 2, and 3, be Documented in Licensee Event Reports and the Nuclear Plant Reliability Data System databases.
26
+
I authorized for Hatch Nuclear Plant, Units I and 2, pursuant to l
This alternative should be authorized for the current interval or until such time as the Code Case is published in a future revision of Regulatory Guide 1.147.
At that time, if the licensee intends to continue to implement this code case, the licensee is to follow all provisions in Code Case N-498-1, with limitations issued in Regulatory Guide 1.147, if any.
3.4.4.2 Reouest for Relief RR-9. Alternative Pressure Test for Welded Repairs or Replacements in Class 1. 2 and 3 Systems Code Reouirement: Section XI, IWA-4400(a) requires that a system hydrostatic test be performed in accordance with IWA-5000 after repairs by welding in a pressure-retaining boundary.
Licensee's Code Relief Reouest:
The licensee requested relief from the ASME Section XI, Class 1, 2, and 3 repair / replacement pressure tests at elevated hydrostatic test pressures.
Licensee's Basis for Reouestino Relief (as stated):
"ASME Section XI Code Case N-416-1 was issued on February 15, 1994.
This Code Case has been approved by the NRC staff for use at Plant Hatch and other plants, but has not been formally endorsed by inclusion in NRC Regulatory Guide 1.147.
It was previously approved for Plant Hatch by SER dated 6/15/95.
"The proposed alternative testing requirements have been evaluated by the ASME Code Committee and the NRC and have been deemed acceptable for determining the pressure boundary integrity of the affected components.
Implementation of pressure testing in accordance with the subject Code Case will ensure an acceptable level of quality and safety, does not decrease safety and is thus authorized pursuant to 10 CFR 50.55a(a)(3)(i).
By implementing the alternative examinations, reduction in costs, personnel radiation dose, and outage time can be realized by Georgia Power Company at Plant Hatch."
l 27
Licensee's proposed Alternative Examination (as stated):
" Georgia Power Company will comply with the pressure testing requirements of ASME Section XI Code Case N-416-1 for welded repairs or installation of replacement items by welding.
In addition to the alternative rules of Code Case N-416-1, GPC proposes to augment the alternative tests by performing an additional surface examination on the root pass layer of butt and souet welds on the pressure retaining boundary of Class 3 components."
Evaluation:
Section XI of the Code requires a system hydrostatic test to be performed in accordance with IWA-5000 after repairs by welding on the pressure-retaining boundary.
The licensee proposes to implement the alternative to hydrostatic pressure tests contained in Code Case N-416-1 for Code Class 1, 2, and 3 repairs / replacements.
In addition, for Class 3 repair / replacement welds or welded areas the licensee will supplement the pressure test with an additional surface examination on the root pass layer.
Hardships are generally encountered with the performance of hydrostatic testing in accordance with the Code. Hydrostatic pressure testing frequently requires a significant effort to set up and perform due to the need to use special equipment, such as temporary attachment of test pumps and gages, and the need for unique valve lineups.
Code Case N-416-1 specifies that nondestructive examination (NDE) of the welds be performed in accordance with the applicable subsection of the 1992 Edition of Section III. This Code Case also allows a VT-2 visual examination to be performed at nominal operating pressure and temperature in conjunction with a system leakage test, in accordance with paragraph IWA-5000 of the 1992 Edition of Section XI. Comparison of the system pressure test requirements of the 1992 Edition of Section XI to those of the 1989 Edition of Section XI, the latest Code edition referenced in 10 CFR 50.55a, shows that:
- 1) The test frequencies and pressure conditions are unchanged; 1
I 28
2)
The hold times either remained the same or increased;
- 3) The terminology associated with the system pressure test requirements for all three Code classes has been clarified and streamlined; and
- 4) The NDE requirements for welded repairs remain the same.
Hydrostatic testing only subjects the piping components to a small increase in pressure over the design pressure and, therefore, does not present a significant challenge to pressure boundary integrity. Accordingly, hydrostatic pressure testing is primarily regarded as a means to enhance leak detection during the examination of components under pressure, rather than as a measure of the structural integrity of the components.
Following welding, the Code requires volumetric examination (depending on wall thickness) of repairs or replacements in Code Class 1 and 2 piping components, but only requires a surface examination of the final weld pass in Code Class 3 piping.
There are no ongoing NDE requirements for Code Class 3 components except for VT-2 visual examination for leaks in conjunction with the 10-year hydrostatic tests and the periodic pressure tests.
Considering the NDE performed on Code Class I and 2 systems, and considering that the hydrostatic pressure tests rarely result in pressure boundary leaks that would not occur duririg system leakage tests, the INEL staff believes that the increased assurance of the integrity of Class 1 and 2 welds that could be achieved is not commensurate with the burden of performing hydrostatic testing.
It is also believed that the added assurance provided by a hydrostatic test of Class 3 welds is not commensurate with the burden of hydrostatic testing when
- 1) a surface examination is performed on the root pass layer of i
29
i r
butt and socket welds, and 2) a system pressure test is i
performed.
==
Conclusion:==
Compliance with Code hydrostatic testing requirements for welded repairs or replacements of Code Class 1, 2, and 3 components would result in a hardship without a compensating increase in the level of quality and safety.
Therefore, pursuant to 10 CFR 50.55a(a)(3)(ii), it is recommended that the proposed alternative use of Code Case N-416-1, augmented by performing an additional surface examination on the root pass layer of butt and socket welds for Class 3 welds, be autScrized.
Use of Code Case N-416-1, with the licensee's proposed augmented examination noted above, should be authorized for the current interval or until such time as the Code Case is published in a future revision of Regulatory Guide 1.147.
At that time, if the licensee intends to continue to implement this code case, the licensee should follow all provisions in Code Case N-416-1, with limitations issued in Regulatory Guide 1.147, if any.
3.5 General 3.5.1 Vltrasonic Examination Techniaues (No relief requests) 3.5.2 Exemoted Components. (No relief requests) 3.5.3 Other 3.5.3.1 Reauest for Relief RR-4. ASME Code Class 1. 2. and 3 Intearally Welded Attachments Code Reauirement: ASME Section XI, Examination Category B-K-1, Items 810.10 and B10.20 require a volumetric or surface examination of integrally-welded attachments as defined by Figures IWB-2500-13, -14, or -15, as applicable.
Examination Category C-C, Items C3.10, and C3.20 require surface examination as defined by Figure IWC-2500-5.
Examination 30
l.
Category D-A, D-8, and D-C, Items D1.20 through DI.60, D2.20 through D2.60, and D3.20 through D3.60 require VT-3 visual examination as defined by Figure IWD-2500-1.
1 Licensee's Code Relief Reauest:
The licensee requested relief from the Code requirements associated with the selection and examination of integrally-welded attachments.
The licensee proposes to implement Code Case N-509, " Alternate Rules for the Selection and Examination of Class 1, 2, and 3 Integrally Welded Attachments,Section XI, Division 1".
Licensee's Basis for Reauestina Relief (as stated):
" Code Case N-509 provides an alternative sampling which will retain an acceptable level of quality and safety for Class 1, 2, and 3 Integrally Welded Attachments.
Since approval was granted by ASME, the alternative requirements should be technically acceptable for determining flaws.
By implementing the alternative examinations, cost savings, personnel radiation dose, and outage time can be realized by Georgia Power Company at Plant Hatch."
Li_gensee's Proposed Alternative Examination (as stated):
" Georgia Power Company proposes that, in lieu of the Code-required volumetric, surface, or visual examination on those Integrally Welded Attachments required by Table IWB-2500-1, IWC-2500-1, or IWD-2500-1 in the 1989 Edition, a surface examination be performed on those Integrally Welded Attachments as noted in the Code Case, Table 2500-1, Examination Category B-K, Integral Attachments for Class 1 Vessels, Piping, Pumps, and Valves; Examination Category C-C, Integral Attachments for Class 2 Vessels, Piping, Pumps, and Valves; and a visual examination for Examination Category D-A, Integral Attachments for Class 3 Vessels, Piping, Pumps, and Valves.
GPC will ensure that the sample will be a minimum of 10% of the IWB/IWC/IWD items."
Evaluation:
In lieu of Code requirements for selection and examination of integral attachment welds, the licensee proposes to apply alternatives contained in Code Case N-509, Alternative Rules for the Selection and Examination of Class 1, 2, and 3 Integrally Welded Attachments.
In addition, the licensee will ensure that at least a 10% sample of all nonexempt integral 31 l
attachment welds in Class 1, 2, and 3 systems will be examined.
Considering that many of the Code examination requirements are based on sampling to assure that service-related degradation is not occurring, it is logical to extend the sampling process to welded integral attachments.
Based on the licensee's proposed sample of a minimum of 10% of all integral attachment welds in Code ~ Class 1, 2, a'nd 3 systems, the INEL staff believes that degradation, if occurring, will be detected.
Therefore, the use of the alternatives contained in Code Case N-509, with a minimum 10% selection of all integrally-welded attachments in each Code Class, will provide an acceptable level of quality and safety.
==
Conclusion:==
The licensee has proposed to examine integral attachments in accordance with Code Case N-509, with a minimum 10% selection of all nonexempt Code Class 1, 2, and 3 integrally-welded attachments.
The INEL staff believes that the licensee's proposed alternative will provide an acceptable level of quality and safety. Therefore, it is recommended that the licensee's proposed alternative be authorized pursuant to 10 CFR 50.55a(a)(3)(i). Use of alternatives contained in Code Case N-509, with the mimimum 10% selection proposed by the licensee, should be authorized for the current interval or until such time as the Code Case is published in a future revision of Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement this code case, the licensee should follow all provisions in Code Case N-509, with limitations issued in Regulatory Guide 1.147, if any.
l 32
~
3.5.3.2 Reauest for Relief RR-7. Examination Cateaory B-J. Item B9.12 and Examination Cateoories C-F-1 and C-F-2. Items C5.12. C5.22 C5,42. C5.52. C5.62 and C5.82. Examination of Class 1 and 2 Lonoitudinal Pipino Welds l
Code Reauirement:
Section XI, Table IWB-2500-1, Examination Category 8-J, Item B9.12 requires surface and volumetric examinations of longitudinal piping welds in Class 1 piping 4-inch nominal pipe size and larger to be performed in conjunction with the circumferential welds selected for examination, as defined in Figure IWB-2500-8.
The length of longitudinal weld required to be examined is at least one pipe diameter, but not more than 12 inches, from the circumferential l
weld intersection point.
I Examination Categories C-F-1 and C-F-2, Items C5.12, C5.22, C5.52, and C5.62 require volumetric and surface examinations of longitudinal piping welds in Class 2 piping to be performed in cenjunction with circumferential welds selected for examination, as defined in Figure IWC-2500-7. At least 2.5t of longitudinal weld is required to be examined.
For Items C5.42 and C5.82, a surface examination is required for longitudinal piping welds intersecting circumferential welds selected for examination, as defined in Figure IWC-2500-7. At least 2.5t of longitudinal weld is required to be examined.
Licensee's Code Relief Reouest:
The licensee requested relief from performing the volumetric and/or surface examination for the length of longitudinal piping welds required to be examined in accordance with Tables IWB-2500 and IWC-2500.
I Licensee's Basis for Reouestino Relief (as stated):
" Code Case N-524 (approved August 9,1993) of the ASME Boiler and Pressure Vessel Code addresses the alternative requirements for surface and volumetric examination requirements of longitudinal piping welds.
By implementing the provisions of this Code Case, personnel radiation exposure, outage 33
examination time, and costs can be significantly reduced at Plant Hatch.
"The proposed alternative testing requirements have been evaluated by the ASME Code Committee and have been deemed acceptable for determining the pressure boundary integrity of the affected components.
The proposed alternative requirements, in accordance with Code Case, will provide reasonable assurance that unallowable inservice flaws have not developed in the subject welds or that they will be detected and repaired prior to return of the reactor vessel to service.
Thus an acceptable level of quality and safety will have been achieved and public health and safety will not be endangered by allowing the proposed alternative examination in lieu of the Code requirements."
Licensee's Proposed Alternative Examination (as stated):
" Georgia Power Company will comply with the requirements of ASME Section XI, Code Case N-524 as follows: (a) When only a surface examination is required, examination of longitudinal piping welds is not required beyond those portions of the welds within the examination boundaries of the intersecting circumferential welds.
(b) When both surface and volumetric examinations are required, examination of longitudinal piping welds are not required beyond those portions of the welds within the examination boundaries of intersecting circumferential welds provided that the following requirements are met.
(1) Where longitudinal welds are specified and locations are known, examination requirements shall be met for both transverse and parallel flaw; at the intersection of welds and for that length of longitudinal weld within the circumferential weld examination volume; (2) Where longitudinal welds are specified but locations are unknown, or the existence of longitudinal welds is uncertain, the examination requirements shall be met for both transverse and parallel flaws within the entire examination volume of intersecting circumferential welds."
Evaluation: The licensee has proposed to implement the alternatives contained in Code Case N-524 for examination of Class 1 and 2 piping longitudinal welds. The licensee proposes to examina the potentially critical portions of the longitudinal welds (the portion that intersects the circumferEntial weld) in conjunction with examination of the circumferential welds.
34
When implementing the alternatives contained in Code Case N-524, longitudinal welds need not be examined beyond the examination zone of the associated circumferential weld.
When the longitudinal weld can be identified, only that portion of the longitudinal weld intersecting the circumferential weld.is required to be examined for flaws parallel and transverse to the wald.
Where the longitudinal weld cannot be identified, 100% of the circumferential weld shall be examined for flaws parallel and transverse to the weld to ensure that the longitudinal /circumferential weld intersection is examined.
l Code Case N-524, when implemented in its entirety, leads to examination of the most critical area of the longitudinal weld,
{
and thus provides an acceptable level of quality and safety.
(It should be noted that when implementing alternatives l
contained in Code Case N-524, requirements for examination of longitudinal welds contained in Table IWB-2500 are superseded.)
i-
==
Conclusion:==
An acceptable level of quality and safety is provided by the licensee's proposed alternative, use of Code Case N-524 for examination of Class 1 and 2 piping longitudinal I
Therefore, pursuant to 10 CFR 50.55a(a)(3)(i), it is recommended that the use of Code Case N-524 be authorized.
Use of Code Case N-524 should be authorized for the current interval or until such time as the Code Case is published in a future revision of Regulatory Guide 1.147.
At that time, if the licensee intends to continue to implement this Code Case, the licensee is to follow all provisions in Code Case N-524 with limitations issued in Regulatory Guide 1.147, if any.
3.5.3.3 fleauest for Relief RR-8. IWA-2413. Unarade of the ISI Proaram Code Reauirement:
ASME Section XI, Paragraph IWA-2413 requires that the licensee upgrade its inservice inspection program to i
the Edition and Addenda adopted by. the regulatory authority 12 months prior to the start of an inspection interval.
The licensee requested permission to maintain the same interval l
start dates for Units 1 and 2 for the third 10-year interval.
l 35 l
The actual third interval start date for Unit 2 is September 1999.
However, the licensee was granted permission (Safety Evaluation Report dated September 29,1986) to change the start date of the Second 10-Year Inspection Interval for Hatch 2 to i
January 1,1986, to establish concurrent interval start dates for Hatch, Units 1 and 2.
I The current Code edition approved for use in 10 CFR 50.55a is the 1989 Edition of ASME Section XI.
Because Hatch, Units 1 and 2, third 10-year interval starting dates have been established as January 1,1996, and the 1989 Edition of the Code was approved 12 months prior to the start of the third 10-year interval, the Code of record is the 1989 Edition of ASME Section XI.
The licensee's ISI program has been developed to comply with the requirements of 1989 Edition of the ASME Code.
Therefore, it has been determined that relief is not required.
3.5.3.4 Reauest for Relief RR-10. Weld Reference System for Class 1 and Class 2 Pinina. Vessels. and Components Code Reauirement: Section XI, Paragraph IWA-2600, Weld Reference System, requires that a reference system be 5
established for all welds and areas subject to surface or volumetric examination. The system shall permit identification of each weld, location of each weld center line, and designation at regular intervals along the 1:ngth of the weld.
Licensee's Code Relief Reauest: The licensee requested relief i
from establishing a weld reference system for all welds of Class 1 and Class 2 piping, vessels, and components.
Licensee's Basis for Reauestino Relief (as stated):
t
" Physical and radiological limitations prevent the actual marking of the majority of the RPV welds, nozzle welds, and piping welds. Many of these limitations actually prohibit l
36
[
o complete examination of the welds. Many of the welds which could be accessed are covered by insulation.
"Each weld is referenced to permanently located fixtures in the immediate area of the subject weld.
These references include such items as nozzles, plant azimuth, and floor identification, welded attachments, and concrete embedments.
Each weld is described in the examination plan and on the examination reports in such a manner as to make it unique.
"For each weld that is examined, the starting point is identified and the direction of travel is noted on the examination report in order that any indications can be accurately located.
The configuration of the welds permits the i
inspectors to locate the weld edgas which are used to locate the weld centerline."
Licensee's Proposed Alternative Examination (as stated):
"Each weld subject to inservice examination will receive the Code-required reference markings and identification, as inservice examinations are being performed."
1 Evaluation:
The Code requires that the licensee establish a reference system for all welds subject to surface or volumetric examination. However, for an operating plant, establishing a weld reference system for all welds and areas subject to surface or volumetric examination is a major effort and, in some cases, is prohibitive due to inaccessibility and/or high radiation levels.
To establish a comprehensive weld reference system for all welds and areas subject to surface and volumetric examinations in accordance with the requirements, many man-hours and man-rem of radiation exposure would be required to perform such tasks as locating the welds, removing insulation, marking the welds, and reinstalling insulation, regardless of whether or not the weld is scheduled for examination.
l Considering the large number of areas suoject to the weld reference identification requirements, the limited number of areas selected for examination, and other methods for locating and identifying examination areas (i.e. isometrics and component drawings, etc.), the INEL staff believes that 37 l
requiring the licensee to establish a weld reference system for areas not being examined will result in a burden.
j
't The licensee has proposed to establish a permanent reference, j
as required by the Code, for each examination area as it is l
3 examined. -The burden associated with establishing a reference l
will not exist for these examination areas since access will have been provided to perform the examinations.
Therefore, the INEL staff believes that imposing the requirement to establish i
a comprehensive reference system, even where an examination is
[
not being performed, will result in a burden without a i
compensating increase in quality and safety.
i
==
Conclusion:==
Marking all welds and areas subject to surface or l
volumetric examination, as required by the Code, in the absence
[
of a required examination, results in a burden without a compensating increase in quality and safety. Theref' ore, it is
[
recommended that the licensee's proposed alternative, to establish a permanent reference the first time each weld is examined during subsequent. inservice examinations, be authorized pursuant to 10 CFR 50.55a(a)(3)(ii).
3.5.3.5 Reauest for Relief RR-12. IWA-5250falf2). Corrective Action j
Ogsultina from Leak'aae at Bolted Connections f
1 Code Reauirement:
IWA-5250(a)(2) requires that the set.rce of leakages detected during a system pressure test shall be located and evaluated by the Owner for corrective action. When i
the leakage is at a bolted connection, the bolting shall be removed, VT-3 visually examined for corrosion, and evaluated in j
accordance with IWA-3100.
Licensee's Code Relief Reauest: The licensee requested relief l
from the ASME Section XI requirements for removal of bolting at leaking connections for VT-3 visual examination.
t 38 i
l Licansee's Basis for Reauestino Relief (as stated):
" Hatch Nuclear Plant is a Boiling Water Reactor (BWR) and the t
j reactor coolant system and associated systems do not experience the corrosive environment from boric acid residues as would a Pressurized Water Reactor (PWR).
When leakage is detected, the 1
integrity of the bolted connections can typically be adequately assessed without the prescriptive requirement for removal of the bolting.
Removal of bolting may not represent the prudent course of action.
For example, an adequate approach would be to verify bolt tightnes; and tightening bolts as needed.
Tightening a loose bolt employs good and sound engineering judgement, and potentially reduces radiation exposure.
Tnis represents a more reasonable approach as opposed to immediately removing all bolting without evaluating the situation as required by the 1989 ASME Section XI Code, or removing the bolt nearest the leakage source as required by the 1990 Addenda and i
later editions of ASME Section XI.
By allowing an evaluation i
l of the bolting and associated mechanical connection, and determining the need for corrective measure, the leakage may be 1
corrected without undue burden and the Code intent would be satisfied.
)
l
" Bas'd on the above example and other similar scenarios, e
Georgia Power Company (GPC) believes it is appropriate to perform an evaluation.
The evaluation may conclude that removal of the bolting is unnecessary.
i
" Hatch Nuclear Plant is a Boiling Water Reactor (BWR) and the reactor coolant system and associated systems do not experience the corrosive environment from boric acid residues as would a Pressurized Water Reactor (PWR).
Therefore, there is no reason to suspect degradation of bolting caused solely by leaking system chemistry.
" Satisfying the Code requirement for removing bolting may l
require significant planning and scheduling due to existing Technical Specification requirements, operational concerns, and personal safety.
In cases of unisolatable or non-redundant piping, the requirement to remove the bolting in order to conduct a visual examination and evaluation, may necessitate l
shutdawn of the plant.
Shutdown of the plant for the sole purpose of satisfyng this visual examination requirement constitutes an undue hardship without a commensurate benefit to safety."
Licensee's Prooosed Alternative Examination (as stated):
" Based on these considerations, GPC will perform an evaluation to determine the appropriate course of action.
The evaluation will censider the potential for bolting degradation as well as the cause of the leakage.
The evaluation will determine whether bolt tightening or removal of bolting is needed.
GPC 39
will assure that the bolting and component material in the area of leakage is evaluated to assure joint integrity.
"Should the bolting need to be removed, GPC proposes to remove the bolt nearest the leakage source, as required by the 1990 ASME Section XI Addenda and later editions, perform a VT-3 examination, and evaluate the bolt in accordance with IWA-3100.
If the bolt has evidence of degradation, additional bolts in the connection shall be removed, VT-3 examined, and evaluated in accordance with IWA-3100.
" Evaluations shall be documented in writing, reviewed by the appropriate plant management, and maintained in the plant records. The results of these findings will be made available to the regulatory and enforcement authority having jurisdiction at the plant site.
Inspections or repairs and replacements necessitated by these evaluations will be documented on Forms NIS-1. "0wners Report for Inservice Inspections" and/or Forms NIS-2, "0wners Report for Repair or Replacement", as applicable."
Evaluation:
In accordance with the 1989 Edition of the Code, when leakage occurs at bolted connections, all bolting is to be removed for VT-3 visual examination.
In lieu of removal of all bolting to perform a VT-3 visual examination, the licensee has proposed to perform an evaluation of the bolted connection.
The evaluation will consider the potential for bolting degradation as well as the cause of the leakage.
If the evaluation indicates the need for a more detailed analysis, the bolt closest to the source of leakage sill be removed, VT-3 examined, and evaluated in accordance with IWA-3100(a).
The licensee's alternative to bolting removal when leakage occurs is based on sound engineering judgment. As a result, it is believed that the licensee's proposed alternative to the Code-required removal of bolting at a joint when leakage occurs will provide an acceptable level of quality and safety.
==
Conclusion:==
Based on the licensee's proposed alternative, to perform an evaluation of the bolting when leakage occurs at a bolted connection, it is reasonable to conclude that the degradation of bolting, if present, will be detected, providing an acceptable level of quality and safety.
Therefore, it is 1
40
1 recommended that the proposed alternative be authorized pursuant to 10 CFR 50.55a(a)(3)(1).
3.5.3.6 Reauest for Relief RR-13. Table IWC-2500-1. Examination Cateaory C-H. Items C7.10. C7.30. C7.50. and C7.70. Pressure-Retainino Components Code Reouirement:
Section XI, Table IWC-2500-1, Examination Category C-H, Items C7.10, C7.30, C7.50, and C7.70 require a VT-2 visual examination during System Functional and System Inservice Pressure Tests.
Licensee's Code Relief Reauest: Relief is requested from performing the Code-required VT-2 visual examination during System Functional and System Inservice Pressure Tests for the portions of the subject containment penetration pipe classified as Code Class 2.
The attaching segments of line, inside and outside of containment, are nonclass.
The portions for which relief is requested are listed below.
Unit 1 Unit 2
(
l Penetration Function Penetration Function X-18 Radwaste X-3 H0 2 2 X-19 Radwaste X-18 Radwaste X-21 Service Air X-19 Radwaste X-22 Drywell Pneumatic X-21 Service Air X-23 RBCCW X-22 Drywell Pneumatic X-24 RBCCW X-23 RBCCW X-25 Purge & Inerting X-24 RBCCW X-26 H 0, Sample X-25 Purge & Inerting 2
X-27a fission Product X-26 Purge & Inerting Monitoring 3
j i
X-27C Reactor X-28 H 0 Sample 22 l
Protection l
X-270 Reactor 32A,C Drywell Pressure l
j Protection X-27E Purge & Inerting X-34C ILRT X-27F Drywell Pneumatic X-34D ILRT X-28 Recirculation X-35A-E Neutron l
Sample Monitoring X-28F H,0, Sample X-44 Nitrogen Inerting l l
41 i
Unit 1 Unit 2 Penetration Function Penetration Function X-31 H0 Sample X-46 Demineralized 2 2 Water i
X-31F Pump Seal Purge X 47 Chilled Water X-33C Fission Product X-40 Chilled Water Monitoring X-34E H 0, Sample X-51C Drywell Pneumatic 3
"X-44 Service Water X-51D Drywell Pressure X-45C Drywell Pressure X-54A,C Drywell Pressure X-45D Drywell Pressure X-55 Radwaste X-35A-D Tip Drive X-60A H,0, X-35E TIP N Purge X-60B Fission Product 2
Monitoring X-40C-F Drywell Pneumatic X-62 Fission Product Monitoring X-45E Purge & Inerting X-63 Drywell Pneumatic X-45F ILRT X-64 H 0, Sample 2
X-46 Demineralized X-67 Purge & Inerting Water X-59A Pump Seal Purge X-69 Drywell to Torus X-205 Purge & Inerting X-80 Purge & Inertin3_
X-206A,B Purge & Inerting X-81 Nitrogen Inerting X-206C,0 Purge & Inerting X-205 Purge & Inerting X-Purge & Inerting X-206A Torus Water Level 209A,B,C,0 X-216A,B,C, Purge & Inerting X-206C Torus Water Level D
X-217 H,0, X-206H,F Instrument Lines X-218A Torus Drainage &
X-209A-D Instrument Lines Purification X-220 H 0, Sample X-217A,B H,0, Sample 2
X-223A(A-F)
Vacuum Breakers X-218A Torus Drainage X-223B(A-F)
Vacuum Breakers X-220 Purge & Inerting
~
X-225A-H,J-M Purge & Inerting X-230 Nitrogen Inerting X-231 Purge & Inerting X-233 Torus to Drywell P
X-234A Torus Drainage X-235A Purge & Inerting X-235B Purge & Inerting 42
Licensee's Basis for Reouestino Relief (as stated):
"ASME Code Section XI, Code Case N-522, allows Appendix J testing of the subject penetrations as an alternative to the Code-required Category C-H Pressure tests.
Since Code Case N-522 will not be included in Revision 12 to Regulatory Guide 1.147, relief from performing the Category C-H pressure tests is necessary."
Licensee's Proposed Alternative Examination (as stated):
" Georgia Power Company (GPC) will comply with the Appendix J testing requirements established for Plant Hatch Unit I and Unit 2."
i In the licensee's November 18, 1996, submittal, the licensee stated:
"The existing Plant Hatch leakage rate testing procedures perform Appendix J testing of the applicable penetrations at the calculated peak accident pressure and the acceptance criteria provide for detection and location of any unacceptable through-wall leakage in containment isolation valves (CIVs) and pipe segments between the CIVs."
Evaluation:
The licensee proposes to implement the alternatives contained in Code Case N-522, Pressure Testing of l
Containment Penetration P/ ping, in lieu of the Code-required I
pressure tests for portions of the subject lines that are Class 2 at the containment penetration.
These segments of lines are safety-related only because they function as part of the containment pressure boundary and are relied on for containment integrity.
Therefore, it is logical to test the penetration piping portion of the associated systems to the containment test criteria found in 10 CFR 50.55a, Appendix J.
Appendix J pressure tests are local leak rate and integrated leak rate tests that verify the leak-tight integrity of the primary reactor containment and of systems and components that penetrate containment.
In addition, Appendix J test frequencies provide assurance that the containment pressure i
boundary is being maintained at an acceptable level while i
monitoring for deterioration of seals, valves, and piping.
I I
43 E
]
The Class 2 containment isolation valves (CIVs) and connecting i
pipe segments must withstand the peak calculated containment internal pressure related to the maximum design containment The INEL finds that the pressure-retaining integrity pressure.
of the CIVs and connecting piping and their associated safety functions may be verified with an Appendix J, Type C test if it is conducted at the peak calculated containment pressure.
The seal between the connecting pipe segment and containment may be verified using an Appendix J, Type B test.
Therefore, when the connecting pipe segment is subjected to either a Type B or C test, its safety function is verified by the Appendix J test.
Section XI, IWC-5210(b) requires that where air or gas is used as a testing medium, the test procedure shall include methods for detection and location of through-wall leakage in components of the system tested.
If the licensee's test procedure uses air as a testing medium, the procedure should meet the above requirement for the CIVs and pipe segments between the CIVs.
The INEL staff has reviewed the licensee's basis and alternatives.
Considering that existing licensee Appendix J test procedures require that these leak tests be performed Ot the peak calculated containment design pressure and contain acceptance criteria for detection and location of through-wal' leakages in the pipe segments that are being tested, the INEL staff believes that an acceptable level of quality and safety is provided.
==
Conclusion:==
The licensee proposes to implement the alternative to Code requirements contained in Code Case N-522, Containment Penetration Piping, in lieu of performing the Code-required hydrostatic pressure tests of the subject penetrations.
The licensee's Appendix J pressure test procedures require that leak tests be performed at the peak calculated containment design pressure and contain acceptance criteria that provides for detection and location of through-wall leakages in the pipe 44
segments that are being tested.
Based on the licensee's proposed alternative to Code-required hydrostatic pressure tests of the subject penetration piping, in combination with existing test procedures, it is concluded that an acceptable l
level of quality and safety is provided.
Therefore, it is recommended that the licensee's proposed alternative to the Code-required pressure tests be authorized pursuant to 10 CFR 50.55a(a)(3)(i).
The use of alternatives contained in Code Case N-522 should be authorized for the current interval or until such time as the Code Case is published in a future revision of Regulatory Guide 1.147.
At that time, if the licensee intends to continue to implement this Code Case, the licensee is to follow all the provisions in Code Case N-522 with limitations issued in Regulatory Guide 1.147, if any.
3.5.3.7 Recuest for Relief RR-14. Imolementation of Alternatives to Code Recordino and Reportino Recuirements Contained in Code Case N-532 Code Reouirement:
Paragraph IWA-6220 requires that the licensee prepare reports using NIS-1, Owner's Report for Inservice Inspections, and NIS-2, Owner's Report for Repair or Replacements; IWA-6230 requires that these reports be filed with the enforcement and regulatory authorities having jurisdiction at the plant site within 90 days of the completion of the inservice inspection conducted during each refueling outage.
Licensee's Code Relief Recuest:
The licensee requested relief from Code-required repair and replacement and inservice summary report documentation and submission requirements.
l Licensee's Basis for Recuestino Relief (as stated):
"ASME Code Case N-532, " Alternate Requirements to Repair and Replacement Documentation Requirements and Inservice Inspection Summary Report Preparation and Submission as Required by IWA-4000 and IWA-6000," provides an alternative to the 1989 ASME Code Section XI repair and replacement documentation and 45
Georgia Power Company (GPC) regulatory reporting requirements.
reviewed Code Case N-532 and determined its implementation will substantially reduce the administrative burden required by IWA-6000.
Since Code Case N-532 will not be included in Revision 12 of Regulatory Guide 1.147, relief from the requirements of IWA-6000 is necessary."
Licensee's proposed Alternative Examination "GPC will comply with the requiremer:ts of Code Case N-532, with the following clarification regarding reporting of corrective Code Case N-532, paragraph 2.0(c), requires an measures.
abstract for repairs, replacements, and corrective measures required due to an item containing a flaw or relevant condition exceeding the acceptance criteria of ASME Code Section XI.
According to Section XI, the term " corrective measures" has two applications. One application involves repair and replacement activities on pressure-retaining components (e.g., metal removal and welding). The other application involves maintenance-type activities, such as tightening of bolting, replacing gaskets / packing, cleaning surface corrosion products, and adjusting component supports.
For Code Case N-532 reporting, GPC considers " corrective measures" to involve only repair and replacement activities."
fyaluation: The use of Form NIS-1, Owner's Report for Inservice Inspections, and Form NIS-2, Owner's Report for Repairs or Replacements, and submittal of the 90-day Summary Report are Code requirements. Alternatives contained in Code Case N-532 allow the licensee to submit these records in an abstract format on Form NIS-2A, Repair / Replacement Certification Record, and Form 0AR-1, Owner's Activity Report, following the completion of an inspection period.
The requirements associated with documentation of inservice examinations and repairs / replacements and the subsequent submittal of Forms NIS-1 and NIS-2 within 90 days following a refueling outage are adminWrative only.
It is noted that repair and replacement documentation reviews and approvals by the Authorized Nuclear Inspector continue to be required by this Code Case and that the licensee is required to establish a Repair / Replacement Plan in accordance with IWA-6340 of the 1992 Edition of Section XI.
46
4.
4 The licensee has implemented Inspection Program B of the Code.
Under this program, examination schedules are satisfied on a "per period" basis.
Considering the milestones associated with Inspection Program B, submittal of the results of examinations and an abstract of repairs / replacements on a periodic basis is a reasonable alternative.
In addition, the INEL staff believes that the forms contained in Code Case N-532, which provide a summary of the status of repairs / replacements and a more detailed status of examinations by period and interval, are an improvement over report forms currently required by the Code.
i For example, 0AR-1 includes the status of examinations credited for the period and percent credited to date for the interval, i
by Examination Category.
This type of information provides the regulatory authorities a more comprehensive report on the status of the inservice inspection program.
==
Conclusion:==
Considering that the Code recording and reporting j
criteria are only administrative requirements, the INEL staff i
t believes that use of the alternatives to Code requirements contained in Code Case N-532 will continue to provide an acceptable level of quality and safety for Edwin I. Hatch Nuclear Plant, Units 1 and 2.
Therefore, it is recommended i
that the licensee's proposed alternative be authorized pursuant i
The use of alternatives contained in Code Case N-532 should be authorized for the current interval or until such time as the Code Case is published in a future revision of Regulatory Guide 1.147.
At that time, if the licensee intends to continue to implement the alternatives 4
of this Code Case, the licensee is to follow all provisions in Code Case N-532 with limitations issued in Regulatory Guide 1.147, if any.
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4.
CONCLUSION Pursuant to 10 CFR 50.55a(g)(6)(1), it has been determined that certain inservice examinations cannot be performed to the extent required by Section XI of the ASME Code.
For Requests for Relief RR-03, RR-05, and RR-06, the licensee has demonstrated that specific Section XI requirements are impractical; it is therefore recommended that relief be granted.
The granting of relief will not endanger life, property, or the common defense and security and is otherwise in the public interest, giving due consideration to the burden upon the licensee that could result if the requirements were imposed on the facility.
Pursuant to 10 CFR 50.55a(a)(3), it is concluded that for Requests for Relief RR-01, RR-02, RR-04, RR-07, RR-09, RR-10, RR-12, RR-13, RR-14, RR-15, and RR-16, the licensee's proposed alternatives will (i) provide an acceptable level of quality and safety, or (ii) Code compliance will result in hardship or unusual difficulty without a compensating increase in safety.
In these cases, it is recommended that the proposed alternative be authorized.
Request for Relief RR-11 will be evaluated by the Mechanical Engineering Branch.
For Request for Relief RR-08, it has been determined that relief is not required.
This technical evaluation has not identified any practical method by which the licensee can meet all the specific inservice inspection requirements of Section XI ot the ASME Code for the existing Hatch Nuclear Plant, Units 1 and 2.
Compliance with all the exact Section XI required inspections would necessitate redesign of a significant number of plant systems, procurement of replacement components, installation of the new components, and performance of baseline examinations for these components.
Even after the redesign efforts, complete compliance with the Section XI examination requirements probably could not be achieved.
Therefore, it is concluded that the public interest is not served by imposing certain provisions of Section XI of the ASME Code that have been determined to be impractical.
48
4 The licensee should continue to monitor the development of new or impro examination techniques.
As improvements in these areas are achieved, the licensee shoulo incorporate these techniques into the ISI program plan examination requirements.
Based on the review of the Edwin I. Hatch Nuclear Power Plant, Units 1 and 2 Third 10-Year Interval inservice Inspection Program Plan, Revision 0, the licensee's responses to the Nuclear Regulatory Commission's requests for additional information, and the recommendations for granting relief from the ISI examinations that cannot be performed to the extent required by Section XI of the ASME Code, no deviations from regulatory requirements or commitments were identified.
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5.
REFERENCES 1.
Code of Federal Regulations, Title 10, Part 50.
American Society of Mechanical Engineers Boiler and Pressure Vessel Code, f
2.
Section XI, Division 1:
1989 Edition Edwin I. Hatch Nuclear Power Plant, Units 1 and 2, Third 10-Year Interval 3.
Inservice Inspection Program Plan, Revision 0, submitted October 17, 1995.
NUREG-0800, Standard Review Plan for the Review of Safety Analysis 4.
Reports for Nuclear Power Plants, Section 5.2.4, " Reactor Coolant Boundary Inservice Inspection and Testing," and Section 6.6, " Inservice Inspection of Class 2 and 3 Components," July 1981.
Request for Additional Information on the Third 10-Year Interval ISI 5.
Program Plan, transmitted to the licensee on November 16, 1995.
Request for Additional Information on the Third 10-Year Interval ISI 6.
Program Plan requests for relief, transmitted to the licensee by letter dated October 23, 1996.
Letter, dated January 26, 1996, from J. T. Beckham, Jr. (GPC) to Document Control Desk, containing the response to the NRC's request for additional 7.
information.
Letter, dated November 18, 1996, from J. T. Beckham, Jr. (GPC) to 8.
Document Control Desk, containing the response to the NRC's request for additional information on October 23, 1996.
Conference call on February 8,1996, between the licensee and NRC, 9.
requesting additional information.
- 10. Letter, dated April 5, 1996, from J. T. Beckham, Jr. (GPC) to Document Control Desk, containing the response to the NRC's request for additional information on February 8, 1996.
- 11. Letter, dated June 4, 1996, from J. T. Beckham, Jr. (GPC) to Document Control Desk, containing additional requests for relief.
- 12. NRC Regulatory Guide 1.150, Ultrasonic Testing of Reactor Vessel Welds During Preservice and Inservice Examinations, Revision 1, February 1983.
- 13. NUREG-0313/Rev. 2, Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping, January 1988.
- 14. NUREG-0619/Rev. 1, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, July 1980.
- 15. NRC letter datad February 4, 1992, NRC Position on Intergranular Stress l
Corrosion Cracking (IGSCC) In BWR Austenitic Stainless Steel Piping (Generic letter 88-01, Supplement 1).
50
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- 16. S. H. Bush and R. R. Maccary, " Development of In-Service Inspection Safety Philosophy for U.S. A. fluclear Power Plants," ASME,1971.
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INEL-96/0188 Revision 1 2 miecMunterie Evaluation Report on the Third 10-Year ica Interval Inservice Inspection Program P1an:
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Edwin I. Hatch, Units 1 and 2 December; 1996 Docket Numbers 50-321 and 50-366 4 nNeacaA m enta JCN-J2229 (TWA-All)
$ AUTHQRIS) 6 OFRU@T Technical M. T. Anderson, E. J. Feige, K. W. Hall t PE Rico Cov E n e o...c..
om, a PE R,o,RMigRc Apiz A rioN - N AM E AND AD Q R E SS es, Nec s,v,,o, one,4.oa car,ce or nee.oa. v s sucmar m,uuror, ce==,ss,owo m,,,,i, aoores:
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,s conirruier. e,...o, Lockheed Martin Idaho Technologies Company P.O. Box 1625 Idaho Falls, ID 83415-2209
- e. go,NSoRgORG ANIZATION - N AM E AND A00 R ESS or eac. tree "se* es eco e' et coarrurer o ov,oe **c o,vmea. 0"ve or defea u s. m cm,, a,,,,,,ory co.,n,..a Civil Engineering and Geosciences Branch Office of Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, D.C.
20555
- 10. SUPPLEMENTARY NOTES
- 11. ABSTR ACT a00 moros or om, This report presents the results of the evaluation of the Edwin I. Hatch, Units 1 and 2, Third 10-Year Interval Inservice Inspection (ISI) Program Plan, Revision 0, submitted October 17, 1995, including the requests for relief from the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI requirements that the Licensee has determined to be impractical.
The Edwin I.
Hatch, Units 1 and 2, Third 10-Year Interval Inservice Inspection (ISI) Program Plan, is evaluated in Section 2 of this report.
The ISI Program Plan is evaluated for (a) compliance with the appropriate edition / addenda of Section XI, (b) acceptability of examination sample, (c) correctness of the application of system or component examination exclusion criteria, and (d) compliance with ISI-related commitments identified during previous Nuclear Regulatory Commission (NRC) reviews. The requests for relief are evaluated in Section 3 of this report.
- 12. KE Y WOR DS/DESC R ;P10R S tt,st.oros er oareses raev aest aussr ae.v,raem,n,ocarsae rne reoorr,
- 12. A y AgA$%t I y 5Y A f (Mt % I Unlimited l
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a ra e.,e, Unclassified a ra,,,recorr, Unclassified
- 16. NUMBER OF PAGES 16 PRICE
(
NICFORM3.16,7491 i
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