ML20211G770
| ML20211G770 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 10/31/1986 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| References | |
| NUREG-0896, NUREG-0896-S06, NUREG-896, NUREG-896-S6, NUDOCS 8611040160 | |
| Download: ML20211G770 (153) | |
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NUREG 0896 Supplement No. 6 Safety Evaluation Report related to the operation of Seabrook Station, Units 1 and 2 Docket Nos. 50-443 and 50-444 Public Service Company of- New Hampshire, et al.
U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation October 1986 s> % ,,
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w-NOTICE 1 Availability'of Reference' Materials Cited in NRC Publications
" .Most documents cited in NRC publications will be available from one of the following sources:
.1. , The NRC Public Document Room,' 1717 H Street, N.W.
- Washington, DC 20556
- 2. The Superintendent of Documents, U.S. Government Printing Office, Post Office Box 37082,
. Washington, DC 20013-7082
- ' 3. The National Technical information Service, Springfield, VA 22161 -
Although the listing that follows represents the majority of documents cited in NRC publications, it is not intended to be exhaustive.
Referenced documents available for inspection and copying for a fee from the NRC Public Docu.
j ment Room include NRC correspondence and internal NRC memoranda: NRC Office of Inspection ,
[
and Enforcement bulletins, circulars, information notices, inspection and -investigation notices; . .
O Licensee Event Reports: vendor reports and correspondence; Commission papers; and applicant and _
f ' licensee documents and correspondence.
The following documents in the NUREG series are available for purchase from the GPO Sales
- j. Program: formal NRC staff and contractor reports, NRC-sponsored conference proceedings, and -
4- NRC booklets and brochures. Also available are Regulatory Guides, NRC regulations in the Code of-L Federal Regulations, and Nuclear Regulatory Commission Issuances.' ,
T
- Docurunts available from the National Technical Information Service include NUREG series
- reports and technical reports prepared by other federal agencies and reports prepared by the Atomic
{i . Energy Commission, forerunner agency to the Nuclear Regulatory Commission.
Documents available from public and special technical libraries include all open literature items,- ,
such as books, journal and periodical articles, and transactions. Federal Register notices, federal and J state legislation, and congressional reports can usually be obtained from these libraries. i Documents such as theses, dissertations, foreign reports and translations, and non NRC conference l
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proceedings are available for purchase from the organization sponsoring the publication cited.
Single copies of NRC draft reports are available free, to the extent of supp9, upon written request
- to the Division of Technical information and Document Control, U.S. Nuclear Regulatory Com-mission, Washington, DC 20555.
Copies of industry codes and standards used in a substantive manner in the NRC regulatory process are maintained. at the NRC Library, 7920 Norfolk Avenue, Bethesda, Maryland, and are available
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i there for reference use by the public. Codes and standards are usually copyrighted and may be l-p purchased from the originating organization or, if they are American National Standards, from the L American National Standards Institute,1430 Broadway, New York, NY 10018.
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9 NUREG-0896 Supplement No. 6 Safety Evaluation Report related to the operation of Seabrook Station, Units 1 and 2 Docket Nos. 50-443 and 50-444 Public Service Company of New Hampshire, et al.
U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation October 1986
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ABSTRACT r
This report is Supplement No. 6 to the Safety Evaluation Report (NUREG-0896, i
March 1983) for the application filed by the Public Service Company of New Hampshire et al., for licenses to operate Seabrook Station, Units 1 and 2
' (Docket Nos. STN 50-443 and STN 50-444). It has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Commission and .
provides recent information on open items identified in the SER. The facility is located in Seabrook, New Hampshire. Subject to favorable resolution of the items discussed in this report, the staff concludes that the facility can be operated by the applicant without endangering the health and safety of the public.
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Seabrook SSER 6 iii
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i TABLE OF CONTENTS Page l ABSTRACT .............................................................. iii 1
INTRODUCTION'AND GENERAL DESCRIPTION OF PLANT .................... 1-1 1.1 Introduction ................................................ 1-1
- 1. 7 Outstanding Issues .......................................... 1-1 1.8 C o n f i rma to ry I s s u e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2
- 1. 9 License Condition Items ..................................... 1-2 2 SITE CHARACTERISTICS ............................................. 2-1 l
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- 2. 2 Nearby Industrial, Transportation and Military Facilities ... 2-1 3 DESIGN CRITERIA FOR STRUCTURES,' SYSTEMS,'AND COMPONENTS .......... 3-1 .
3.9 Mechanical Systems and Components ........................... 3-1.
3.9.2 Dynamic Testing and Analysis ........................ 3-1 3.9.2.1 Piping Preoperational Vibration and D Effects Testing......................ynamic
....... 3-1 3.9.6 Inservice Testing of Pumps and Valves ............... 3-1 3.10 Seismic and Dynamic Qualification of Safety-Related Mechanical and Electrical Equipment ......................... 3-2 3.10.2 Operability Qualification of Pumps and Valves........ 3-2 3.10.2.3 Co n f i rma to ry I s s ue s . . . . . . . . . . . . . . . . . . . . . . . . 3-2 3.11 Environmental Qualification of Electrical Equipment Important to Safety and Safety-Related Mechanical Equipment............ 3-2 4 REACTOR .......................... ............................... 4-1 4.4 Thermal-Hydraulic Design .................................... 4-1 4.4.5 Instrumentation ..................................... 4-1 4.4.5.3 Loose Parts Monitoring System............... 4-1 4.4.5.4 ICC Instrumentation......................... 4-1 Seabrook SSER 6 v
TABLE OF CONTENTS (Continued)
Pag 5-1 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS......................
5.4 Component and Subsystem Design................... ........... 5-1 1
5-1 5.4.7 Residual Heat Removal System.........................
6-1 6 ENGINEERED SAFETY FEATURES........................................
6-1 6.2 Containment Systems..........................................
Secondary Containment Systems........................ 6-1 6.2.3 6-1 6.2.6 Containment Leakage Testing Program..................
6.5 Engineered Safety Feature Atmosphere Cleanup Systems......... 6-3 4
Containment Spray System............................. 6-3 6.5.2 7-1 7 INST RUMENTATION AND CONTR0LS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7-1 7.3 Engineered Safety Features Systems...........................
Specific 7-1 7.3.2 Findings....................................
i 7.3.2.8 Level Measurement Errors As a Result of Environmental Temperature Effects on Level Instrument Reference Leys................... 7-1 7.3.2.16 Level and Pressure Measurement Errors As a Result of Environmental Temperature Effects on Sensors..................................
7-1 7-2 7.4 Systems Required for' Safe Shutdown...........................
7-2 7.4.2 Specific Findings....................................
7-2 7.4.2.1 Station Service Water System................
8-1 8 ELECTRIC POWER SYSTEMS ...........................................
8-1 8.1 Genera 1...................................................... 8-2 8.3 Onsite Power Systems ........................................
Onsite AC Power System Compliance With GDC 17 ....... 8-2 8.3.1 8.3.1.2 Compliance With the Guidelines of RG 1.9 8-2 (Revision 1)................................
8.3.1.4 Non-Safety Loads Powered From the Class 1E 8-3 AC Distribution System......................
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Seabrook SSER 6 vi i
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TABLE OF CONTENTS (Continued)
P, age 9 AUXILIARY SYSTEMS................................................. 9-1.
9.5 Other Auxiliary Systems...................................... 9-1 9.5.1 Fire Protection...................................... 9-1 9.5.1.4 General Plant Guidelines.................... 9-1
~9.5.1.8 Summary of Approved Deviations From Staff Fire Protection Guidelines.................. 9-2 9.5.1.9 Conclusions................................. 9-2 9.5.2 Communication System.................................. 9-3 9.5.2.1 Intraplant Systems.......................... 9-3
! 10 STEAM AND POWER CONVERSION SYSTEM ................................ 10-1 10.4 Other Features .............................................. 10-1 I
10.4.2 Main Condenser Evacuation System .................... 10-1 10.4.2.2 Evaluation Findings......................... 10-1 11 RADI0 ACTIVE WASTE MANAGEMENT...................................... 11-1 11.5 Process and Effluent Rdiological Monitoring and Sampling Program...................................................... 11-1 15 ACCIDENT ANALYSIS ................................................ 15-1
- 15.8 Anticipated Transients Without Scram ........................ 15-1 15.8.1 Generic Letter 83-28 ................................ 15-1 15.9 TMI Action Plan Requirements................................. 15-2 15.9.11 II.K.3.17, Report on Outages of ECCS................. 15-2 15.9.14 Plant-Specific Calculations to Show Compliance With 10 CR 50.46..................................... 15-2 18 HUMAN FACTORS ENGINEERING ........................................ 18-1 18.2 Safety Parameter Display System (TMI Action Plan Item I.D.2) ................................................. 18-1 Appendix 18A ELECTRICAL AND ELECTRONIC ISOLATION OF SAFETY PARAMETER DISPLAY SYSTEM....................... 18A-1 Seabrook SSER 6 vii
TABLE OF CONTENTS (Continued)
APPENDIX A CONTINUATION OF CHRON0 LOGY OF RADIOLOGICAL REVIEW APPENDIX B BIBLIOGRAPHY APPENDIX D ACRONYMS AND INITIALISMS i
i APPENDIX F NRC STAFF CONTRIBUTORS AND CONSULTANTS i APPENDIX H ERRATA TO THE SEABROOK STATION SAFETY EVALUATION REPORT AND ITS SUPPLEMENTS APPENDIX R DESIGN VERIFICATION AND DESIGN VALIDATION AUDIT OF THE SAFETY PARAMETER DISPLAY SYSTEM FOR PUBLIC SERVICE COMPANY OF NEW
- HAMPSHIRE SEABROOK STATION APPENDIX S SAFETY EVALUATION REPORT
- PUMP AND VALVE INSERVICE TESTING
' PROGRAM, SEABROOK STATION,-UNIT 1 APPENDIX T CONFORMANCE TO GENERIC LETTER 83-28, ITEM 2.1 (PART 1),
EQUIPMENT CLASSIFICATION (RTS COMPONENTS) i i
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I Seabrook SSER 6 vili i
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1 1 INTRODUCTION AND GENERAL DESCRIPTION OF PLANT j 1.1 Introduction On March 7, 1983, the Nuclear Regulatory Commission staff (NRC or staff) issued a Safety Evaluation Report (SER), NUREG-0896, on the application of Public Ser- ,
vice Company of New~ Hampshire (PSNH, hereinafter referred to as the applicant)
, for licenses to operate Seabrook Station, Units 1 and 2. In April 1983, the i
NRC issued the first supplement to the SER (SSER 1), in June 1983 the second supplement (SSER 2) was issued, in July 1985 the third supplement (SSER 3) was i
- issued, in May 1986 the fourth supplement (SSER 4) was issued, and in July 1986 the fifth supplement (SSER 5) was issued. This sixth supplement (SSER 6) pro-l vides information to update the status of the NRC review. ,
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! Each of the sections and appendices of this supplement is designated the same as the related portion of the SER. The contents of this document are supple-f i
mentary to the initial SER, SSER 1, SSER 2, SSER'3, SSER 4, and SSER 5, and not in lieu of those documents unless otherwise noted. Appendix A is a continua-
- tion of the chronology of this safety review. Appendix B lists reference mate-rials cited in this document.* Appendix D lists acronyms and initialisms used
- in this supplement. Appendix F gives the principal staff contributors. Appen-l dix H, Errata, corrects the SER and its supplements. Appendices R, S, and T
- consist of reports prepared for the NRC staff by two of its contractors.
- Lawrence Livermore National Laboratory audited the design of Seabrook's safety j parameter display system (Appendix R); and EG&G Idaho, Inc. evaluated the pump 4
and valve inservice testing program at Seabrook Unit 1 (Appendix S) as well as i the conformance of Seabrook 1 and 2 to NRC's Generic Letter 83-28, Item 2.1
- (Part 1) requiring applicants to confirm that all reactor trip system components
, are identified, classified, and treated as safety related (Appendix T).
Appendices C, E, G, I, J, K, L, M, N, 0, P, and Q have not been changed by
- this supplement.
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The NRC Project Manager for the Seabrook operating license (0L) review is
{ Mr. Victor Nerses. He may be reached by telephone at 301 492-8535 or by mail at the following address: i l Mr. Victor Nerses, Project Manager Office of Nuclear Reactor Regulation
- 4 U.S. Nuclear Regulatory Commission l Washington, DC 20555 l 1. 7 Outstanding Issues Section 1.7 of the SER and its supplements noted that certain outstanding
- issues in the staff's review had not been resolved by the time the report was I
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- Availability of all material cited is described on the inside front cover of i this report.
l j Seabrook SSER 6 1-1 4
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issued. This supplement closes two items. These items and the sections of this supplement that present results of the staff's evaluation are given below.
(6) Stress / dynamic qualification of equipment (3.10)
(20) Fire protection (9.5.1.9*)
1.8 Confirmatory Issues Section 1.8 of the SER and its supplements noted that there are some items that have been resolved essentially to the staff's satisfaction but for which cer-tain confirmatory information has not yet been provided by the applicant. This supplement closes five of the confirmatory items. These items and the sections of this supplement that present results of the staff's evaluation are given below.
(24) Non-safety loads povered from the Class 1E ac system (8.3.1.4)
(33) Sampling capability for vacuum pumps during startup (10.4.2)
(46) Electrical power syitems, general (8.1)
(47) Environmental qualification of equipment (3.11)
(48) Instrumentation and control for safe shutdown (7.4.2.1)
(53) Inservice testing of pumps and valves (3.9.6)
As of this supplement the remaining and additional confirmatory items are given below. The staff has decided that the confirmatory issues listed below may be resolved after core load.
(6) Loose parts monitoring system (4.4.5.3)
(45) Steam generator tube rupture (15.6.3)
(49) Cable tray supports (3.7 3)
(50) Turbine system iiiaintenance program (3.5.1.3)
(51) Inadequate core cooling, TMI. Action Plan Item II.F.2 (4.4.5.4)
(52) Postaccident monitoring (7.5.2.4)
(54) Tests, operational procedures, and support systems (5.4.7.5)
(55) Containment enclosure emergency cleanup system (6.2.3)
! (56) Intraplant systems (9.5.2.1) 1.9 License Condition Items i
In Section 1.9 of the SER, the staff noted several issues for which a license i condition may be desirable to ensure that staff requirements are met during plant operation if those requirements have not been met before the operating license is issued. The license condition may be in the form of a condition in l
the body of the operating license or a limiting condition for operation in the
. Technical Specifications appended to the license. As of this supplement the i remaining license conditions are (4) Inservice inspection program (5.2.4, 6.6.3)
(13) Emergency preparedness (13.3)
(16) Implementation and maintenance of the physical security plan (13.6)
(17) Training during low power testing, THI Action Plan Item I.G.1 (14) j (21) Safety parameter display system, TMI Action Plan Item I.D.2 (18.2) l
- Fire protection (9.5.1.9) becomes a license condition.
Seabrook SSER 6 1-2 l
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(22) Radiation data management system (7.5.2.2) !
(23) Fire protection (9.5.1.9)
(24) Systems outside containment containing radioactive material, TMI Action 1
P1an Item II!.D.1.1 (15.9.15) i i
l Seabrook SSER 6 1-3
2 SITE CHARACTERISTICS 2.2 Nearby Industrial, Transportation and Military Facilities In the SER, the staff indicated that should the air traffic at Pease Air Force Base (PAFB) increase substantially in the future, the annual crash probability could exceed acceptable levels. In view of this possibility, the staff indicated the applicant will determine periodically (every 3 years) the number and type of air operations for the PAFB.
'On July 28, 1986, in order to confirm that the applicant met its commitment, the staff reviewed the applicant's "Seabrook Completion Items List," dated July 22, 1986, and noted that this item is being tracked and that the applicant has visited the PAFB to discuss traffic patterns and plane types being used at PAFB. Therefore, the staff considers this item resolved.
Seabrook SSER 6 2-1
3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, AND COMPONENTS 3.9 Mechanical Systems and Components 3.9.2 0.inamic Testing and Analysis 3.9.2.1 Piping Preoperational Vibration and Dynamic Effects Testing As noted in the SER, the applicant committed to test piping vibration, thermal expansion, and dynamic effects during a preoperational testing program to en-sure that these are within acceptable limits. On July 28, 1986, in order to confirm that the applicant had met its commitment, the staff reviewed some pre-operational test procedures (1-PT(I)-3.1 and 1-PT(I)-3.2) and randomly audited the results of tests on some systems (normal letdown, charging, purification, shutdown, and cooling). The staff noted that no unusual vibrations were re-ported and that the measured values during the test indicated the numbers were significantly below the acceptable limits. Therefore, the staff considers this item resolved.
3.9.6 Inservice Testing of Pumps and Valves The applicant submitted an inservice testing (IST) program by letter dated December 31, 1985. This submittal was reviewed by the staff and was t!e sub-ject of a working meeting with the applicant on May 13 and 14, 1986. On the basis of staff comments made during the working meeting, the applicant submitted Revision 1 to its IST program by letter dated June 4, 1986. Revision 1 was amended by letter from J. DeVincentis to V. S. Noonan dated June 18, 1986, and letters from G. S. Thomas to V. S. Noonan dated June 23 and 25, 1986. Revi-sion 1 (June 4, 1986), as amended by letters dated June 18, 23, and 25, 1986, constitutes the Seabrook IST program that has been reviewed by the staff.
The applicant's IST program is required by 10 CFR 50.55a(g) to comply with the ASME Boiler and Pressure Vessel Code,Section XI, 1983 Edition through Summer 1983 Addenda. Pursuant to 10 CFR 50.SSa(g)(5), the applicant has requested relief from the ASME Code testing requirements for specific pumps and valves where the Code requirements are impractical within the limits of design, geome-try, and accessibility. Each of the applicant's requests for relief included an explanation and justification for the relief and a proposal for alternative test procedures.
The staff, with technical assistance from the Idaho National Laboratory (INEL),
has reviewed the applicant's IST program and relief requests. A status of this review was provided in SER Supplement 5 (SSER 5). A technical evaluation re-port (TER) prepared by INEL is included as Appendix 5 to this supplement. On the basis of this review, the staff concludes that the applicant's IST program meets the requirements of 10 CFR 50.55a(g) and is therefore acceptable. In addition, for each relief request the applicant's alternative IST procedure, basis for requesting relief, the staff evaluation of the request and staff con-clusion are fully discussed in Appendix S to this supplement. On the basis of Seabrook SSER 6 3-1
its review of the applicant's request for relief, the staff concludes that the requirements of 10 CFR 50.55a(6)(i)'are met and are, therefore, acceptable.
Granting the relief requested by the applicant will not endanger life or property or the common defense and is otherwise in the public interest giving due con-sideration to the burden on the applicant if the request were not granted.
3.10' Seismic and Dynamic Qualification of Safety-Related Mechanical and Electrical Equipment 3.10.2 Operability Qualification of Pumps and Valves 3.10.2.3 Confirmatory Issues Generic Confirmatory Issues (4) At the time of the audit, most construction tests had already been com-pleted except for the hot functional tests which were still in progress.
In these tests, the applicant was to confirm that all preservice tests that are required before fuel load have been completed.
Initially, the applicant committed to complete preservice tests before j fuel loading. Subsequently, in SSER 4, the staff noted that, in a letter dated April 8, 1986, the applicant had committed to complete the preser-vice testing before commercial operation. In a letter dated June 24, 1986, the applicant stated that preservice testing of a component as required by ASME Code,Section XI, will be complete before the component is required to be operable for the mode specified in the Technical Specifications (TS).
The staff found that although this represented a considerable improvement in the schedule for performing and completing the preservice testing, fur-l ther discussions would be needed before the staff would consider a modifi-cation of the requirement to complete all preservice tests before fuel
- loading, i
In subsequent discussions with the staff, the applicant noted that preser-vice testing as provided in ASME Code,Section III, is generally intended j to provide baseline data on benchmark values for the purpose of comparison, j Although this information is generally obtained from preservice Intesting, fact, there is no requirement in the ASME Code that stipulates this.
l IWP-3110 (1977 Edition) specifically states: " Reference values shall be determined...from the results of the first inservice test run during power operation." The applicant noted, that since the NRC has accepted this provision [10 CFR 50.55(a)(b)(2)] performing the test before the compon-ent is required to be operable for the mode specified.in the TS should be l acceptable. The staff agrees with this. Therefore, the applicant's com-l mitment to complete the preservice tests for a component before the oper-
' ability mode requirement specified for that component in the Technical
, Specifications is found acceptable.
3.11 Environmental Qualification of Electrical Equipment Important to Safety and Safety-Related Mechanical Equipment j
The staff found several deficiencies during its environmental qualification audit of the equipment qualification files at the Seabrook Station. Those Seabrook SSER 6 3-2
, deficiencies ~were discussed with the applicant at the time of the audit and were transmitted to the applicant by letter dated April 11, 1986. The appli-cant proposed acceptable corrective measuras in the form of additional informa-tion and file revisions to eliminate the deficiencies cited. By letter dated June 20, 1986, the applicant informed the staff that the revisions to the files have been completed and that all equipment within the scope of 10 CFR 50.49 has been qualified. The staff finds this acceptable and, therefore, considers confirmatory item 47 closed.
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Seabrook SSER 6 3-3
4 REACTOR 4.4 Thermal-Hydraulic Design 4.4.5 Instrumentation 4.4.5.3 Loose Parts Monitoring System In SER Supplement 4 (SSER 4), the staff stated that the applicant had provided information showing the loose parts monitoring system (LPMS) in compliance with Regulatory Guide (RG) 1.133. However, since the publication of SSER 4, the staff realized the applicant had taken an exception to RG 1.133 pertaining to the matter on what items should be provided in the Technical Specifications (TS).
Section C.5 of RG 1.133 indicates that ths TS should provide for several items related to the LPMS. These items relate to (1) location of the required sensors, (2) limiting condition for operation, and (3) surveillance requirements. However, in a letter dated May 20, 1986 (T. M. Novak, NRC, to R. J. Harrison, PSNH), as part of the Seabrook Station Technical Station Improvement Program, NRC approved removing Technical Specification 3/4.3.3.8, which contains these items, and placing the requirements of Section 3/4.3.3.8 on reporting and surveillance in the Final Safety Analysis Report. Therefore, since the reporting and surveillance requirements are listed in the FSAR, the staff finds this acceptable.
4.4.5.4 ICC Instrumentation In SSER 5, the staff required that the ICC instrumentation system shall be fully calibrated before 5% of rated power operation is exceeded. This is inconsistent with the draft Seabrook Station Technical Specifications (SSTS). The SSTS requires that the ICC instrumentation will be calibrated before entering mode 3.
Since the applicant has agreed to meet the SSTS requirements and this require-ment is a more restrictive requirement than 5% of rated power, the staff finds this acceptable, l
i Seabrook SSER 6 4-1
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5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.4 Component and Subsystem Design 5.4.7 Residual Heat Removal System In letters from John DeVincentis to Vincent S. Noonan dated July 18 and August 19, 1986, the applicant identified an unanticipated situation wherein insufficient head is developed at the inlet to the charging pumps when safety injection is' occurring in the recirculation mode and one of the two residual heat removal (RHR) pumps fails. At this point, the remaining RHR pump would have been pro-viding flow to both charging pumps (operating as safety injection pumps), to both safety ~ injection pumps, and directly to the four reactor coolant system (RCS) cold legs. Net positive suction head (NPSH) requirements for the charging pumps are not met under this condition.
'The applicant has proposed a solution whereby valve alignments are changed so that the above condition would result in injection into only two of the RCS cold legs. The applicant has stated that this would provide sufficient head at the charging pump inlets that NPSH requirements would be met.
The staff has reviewed the applicant's proposal as described in both letters and, in a conference call on October 9, 1986, with the applicant's staff, the applicant reviewed the changes to procedures necessitated by this change as well as the pump discharge pressures and flow rates, pump NPSH values and the effect of postulated failures of various components in the emergency core cooling system (ECCS) on the applicant's proposed solution.
The staff finds the applicant's proposal acceptable since the ECCS will provide acceptable flow assuming the worst single failure and the applicant's proposed procedures are adequate to ensure correct operator action.
This closes out this issue.
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i 6 ENGINEERED SAFETY FEATURES' 6.2 Containment Systems j 6.2.3 Secondary Containment Systems In discussions with the applicant on October 2, 1986, the applicant noted that confirmatory testing associated with the heating, ventilation, and air condi-l
' tioning (HVAC) system for the charging pump cubicles will be performed before entering Mode 4. This is the operating mode for which the Technical Specifica-tions require the system to be available. The applicant noted that the confir-matory testing was being done since exhaust fans had been added recently to the i HVAC system in order'to ensure the required negative pressure will be maintained l in the cubicles during a design-basis accident.
Since the' reactor will be in cold shutdown (Mode 5) and will not leave that mode until after the HVAC system tests are complete, the situation is identical to those modes of operation that would be permitted where the HVAC system is fully tested and operable and subsequently removed from service. Therefore, the staff finds that performing the confirmatory tests before entering Mode 4 is acceptable, 6.2.6 Containment Leakage Testing Program Type C Testing Program Supplement No. S to the SER (SSER 5) contains the staff's review and acceptance of the applicant's program for local leakage rate testing of containment isola-tion valves (Type C testing), as revised by the applicant's letter dated May 7, 1986. In part, SSER 5 discussed several containment penetrations, associated with the emergency core cooling system (ECCS), which will have a water seal maintained at a pressure greater than 1.10 P, for at least 30 days following the onset of a loss-of-coolant accident (LOCA). SSER 5 concluded that such penetrations were not required to be Type C tested, in accordance with Para-graph III.C.3 of Appendix J to 10 CFR 50. By letter dated July 25, 1986, the applicant proposed to exclude from Type C testing three additional ECCS penetra-tions, for the same reason as discussed above. These additional ECCS penetra-tions are X-11, X-12, and X-13, which serve the low-head safety-injection sys-tem, part of the residual heat removal (RHR) system. The staff's review of this proposal follows.
The low-head safety-injection (or RHR) portion of the ECCS operates in three distinct and successive modes following the occurrence of a design-basis 1.0CA.
Upon generation of a safety injection ("S") signal immediately following the accident, the RHR pumps (RH-P-8A and Ril-P-88) take suction from the refueling water storage tank (RWST) and discharge to all four reactor coolant system (RCS) cold legs. During this cold-leg injection phase, the RHR discharge header is common to both redundant pumps. When the RWST reaches the " low-low" level, the containment sumps' isolation valves open and the system is switched over l Seabrook SSER 6 6-1 l_
to the cold-leg recirculation mode. During this mode, the RHR pumps take suction from the containment sump and discharge to a suction header common to both centrifugal charging (CS) pumps and both high-head safety-injection (SI) pumps. The RHR pumps also discharge directly to the RCS cold legs. Previously, Seabrook's emergency operating procedures, in compliance with the FSAR, mandated closure of the valves (RH-V21, V22) on the discharge crosstie line between the two RHR trains during this switchover process. However, these procedures have been revised to leave these valves open and close one of the cold-leg / containment isolation valves (RH-V14, V1-26) during the switchover. These changes are reflected in revised FSAR pages included in the applicant's letter, dated July 25, 1986. Approximately 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> after the onset of the accident, the system is switched over to the hot-leg recirculation mode. During this mode, the RHR pumps continue taking suction from the containment sumps and discharge to two RCS hot legs via the common discharge header, as well as to the suction of the CS and SI pumps.
The applicant stated that, given the above system alignment and the fact that a sufficient recirculating water inventory will be available to the ECCS, a water seal will be maintained at containment penetrations X-11, X-12, and X-13, or against the corresponding isolation valves (RH-V14, V-26, V32, V70) outside containment when closed, for up to 30 days following the onset of a design-basis LOCA. This water seal will be maintained at a pressure in excess of 1.10 Pa regardless of any single active failure. This seal will preclude any isolation valve seat leakage of containment atmosphere via these penetrations.
In addition, the applicant stated that the design of all isolation valves for these penetrations for which stem / packing leakage is of concern (i.e., valves outside containment which may be closed at any time following an accident) is a gate valve design which allows for such leakage only from the high pressure side of the valve. Given that the water seal will always be at a pressure higher than containment pressure, containment atmosphere leakage from the valve stems and/or packing is precluded.
Considering the description of the system operation and valve design given above, the staff concurs with the applicant that these penetrations and associated containment isolation valves, if closed to perform their contain-ment isolation function, will be sealed with water from the containment sumps.
In accordance with paragraph III.C.3 of Appendix J to 10 CFR 50, because the containment isolation valves of theses penetrations will be maintained under a i
water seal for at least 30 days following the onset of an accident, they are not potential containment atmosphere leak paths, and therefore, do not require a Type C test with air or nitrogen. In addition, a water leakage rate test is not needed, since a continuous supply of sealing water is provided from the containment sumps.
The staff finds, on the basis of this evaluation, that the applicant's proposed revisions to to the Type C testing program, as described in its letter dated July 25, 1986, complies with the requirements of Appendix J to 10 CFR 50 and is, therefore, acceptable.
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Seabrook SSER 6 6-2 L
6.5 Engineered Safety Feature Atmospheric Cleanup System 6.5.2 Containment Spray System In the SER, it was noted that the applicant had agreed to a drawdown preopera-tional test to demonstrate the dynamic flow distribution in the system and the capability of the system to achieve the required pH levels designed into the system.
The completed tests were performed and the completed test procedures were re-viewed by Region I Staff to verify that adequate testing had been performed to satisfy regulatory guidance and FSAR requirements, and to verify that uniform criteria were applied for evaluation of e apleted test results in order to as-sure technical and administrative adequacy.
Region I staff reviewed the test results and verified the applicant's evaluation of test results by review of test changes, test exceptions, test deficiencies, "as-run" copy of test procedure, acceptance criteria, performance verification, recording conduct of test, quality control (QC) inspection records, restoration of system to normal after test, independent verification of critical steps or parameters, identification of personnel conducting and evaluating test data, and verification that the test results have been approved. The specific test pro-cedures reviewed by Region I were reported in Inspection Report 85-23.
During a site visit on July 28, 1986, the staff learned that when the drawdown test was performed the level difference between the spray additive tank and refueling water storage tank was five inches which corresponds to a variation of 1% and that this result showed that the proposed design pH levels can be met by the system. With the satisfactory completion of this test, this confirmatory issue is closed.
Seabrook SSER 6 6-3
7 INSTRUMENTATION AND CONTROLS 7.3 Engineered Safety Features Systems 7.3.2 Specific Findings 7.3.2.8 Level Measurement Errors As a Result of Environmental Temperature Effects on Level Instrument Reference Legs By letter dated September 19, 1986 (J. DeVincentis to V. S. Noonan), the appli-cant stated that the setpoint value of 17.1% for the steam generator water level l low-low trip (submitted by letter dated June 3, 1986, from J. DeVincentis to l V. S. Noonan) was in error and should have stated a trip value of 17.0%. This was correctly identified in a previous letter dated April 15, 1986 (J. DeVincentis to V. S. Noonan). The staff finds the 17.0%'setpoint for the steam generator water level low-low trip to be acceptable.
7.3.2.16 Level and Pressure Measurement Errors as a Result of Environmental Temperature Effects on Sensors By letter dated October 9, 1986 (George S. Thomas to Vincent S. Noonan), the l applicant stated there was a deficiency regarding calibration shifts in Veri-i trak Group A transmitters. These deficiencies resulted from variances in ex-pected ambient temperatures. It was reported that these ambient temperature compensation shifts could create a condition wherein the allowable value limit of the Seabrook Station Tcchnical Specifications cuuld be exceeded.
Westinghouse completed a testing phase for the Group A transmitters. As a re-sult, Westinghouse developed a new bounding error limit for temperature compen-
- sation. On the basis of this new temperature compensation, the applicant stated that new, more conservative, setpoints for steam generator low-low water level l (17.0% to 21.6%) and low pressurizer pressure safety injection (1850 psig to 1875 psig) will be implemented.
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' The staff has reviewed the information provided by the applicant and has con-cluded (1) the setpoint changes are in the conservative direction, (2) insuffi-cient information was provided by the applicant to verify the methodology util-ized to derive the setpoints, (3) the Group A transmitters with the new, more l conservative, setpoints are a temporary installation because Rosemount trans-mitters are scheduled to be installed to replace the present Group A transmit-ters on or about February 15, 1987 (the applicant has committed to make the nec-essary calculations to determine changes to the Seabrook Technical Specifica-tions), and (4) the safety systems associated with these setpoints are not re-quired to operate before initial criticality.
On this basis, the staff has concluded that the setpoints are acceptable for fuel load licensing. However, staff review and approval of the methodology used to derive the new setpoints is required before initial criticality.
l Seabrook SSER 6 7- 1~
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7.4 Systems Required for Safe Shutdown
'7.4.2 Specific Findings 7.4.2.1 Station Service Water System As stated in SSER 5, Section 7.4.2.1, " Station Service Water System," the appli-cant' committed to include in the procedure for cooling tower operation (during ',.
normal power operation) restrictions on the. operation of the diesel generators 4 when the Technical Specification basin temperature could be exceeded. The staff was to verify the implementation of this procedural restriction. The diesel 4 operation restriction as discussed above and in Section 7.4.2.1 of SSER 5, was verified and found acceptable by the staff. Therefore, confirmatory item 48 is resolved.
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i Seabrook SSER 6 7-2
8 ELECTRIC POWER SYSTEMS 8.1 General Diesel Generator Control Drawings In the Seabrook design, if the diesel generator (DG) control switch is in the local position, the DG will be unavailable for automatic start on a safety injection signal. The staff required that this condition be alarmed in the control room as one of the conditions that can render the DG incapable of re-sponding to an automatic emergency start signal. By letter dated November 27, 1985, the applicant committed to include this design feature. In Supplement No. 4 to the SER (SSER 4), the staff stated that it will verify the implementa-tion of this design feature at the Seabrook Station. By letter dated June 13, 1986, the applicant submitted revised FSAR Table 8.3-8, " Conditions That Can Render Diesel Generator Incapable of Responding to an Automatic Emergency Start Signal," to reflect the subject condition. On this basis, the staff finds this item resolved.
Control Circuitry of Recirculation Isolation Valve Redundant indication that meets the single-failure criterion was not provided for valve SI-V-93 in the Seabrook design. The staff required that another indication from a diverse device (e.g., stem-mounted switch) be provided to satisfy Branch Technical Position (BTP) PSB 18. By letter dated November 17, 1985, the applicant committed to install another indication from a stem-mounted switch as documented by the staff in SSER 4. By letters dated June 13 and August 21, 1986, the applicant informed the staff that an existing stem-mounted switch on valve SI-V-93 has been utilized to provide an independent alarm in lieu of valve position indication as previously committed. The is because installation of valve position indication requires drilling holes in the main control board and the applicant is reluctant to do it at this late stage.
Valve SI-V-93 is presently provided with the following indications / alarms:
(1) red / green valve' position indications utilizing the valve position limit switch (2) valve fully closed status monitor light utilizing the valve position limit switch (3) specific alarm in the video alarm system (VAS) indicating valve not fully open utilizing the stem-mounted position switch (4) alarm for both "SI Train A Inoperable" and "SI Train B Inoperable" any time SI-V-93 leaves the full open position utilizing the stem-mounted position switch The four indicating lights / alarms listed above are powered from redundant power supplies (items 1 and 2 from train B and items 3 and 4 from train A). On this Seabrook SSER-6 8-1
basis, the staff concludes that the multiplicity of indications and alarms for valve SI-V-93 satisfies the staff's concern with BTP-PSB 18 and is acceptable.
-8.3 Onsite Power Systems 8.3.1 Onsite AC Power System Compliance With GDC 17 8.3.1.2 Compliance With the Guidelines of RG 1.9 (Revision 1) 8.3.1.2.6 Capability of the Diesel Generator To Accept the Design Load The cooling tower pump load (800 hp) that, is normally connected at a 37-second time interval may be connected at the 52-second time interval or any time after 52 seconds in the Seabrook design. The staff was concerned that the diesel generator may not be able to handle such a heavy load at or after the 52-second time interval.
In SSER 4, the staff concluded that based on DG qualification test results, the Seabrook diesel generators are capable of starting a 1000-hp motor after being loaded to 4560 kW. This is more conservative than starting an 800-hp motor at the 52-second' time interval (3885 kW). However, the staff required that peri-odic testing using the.800-hp load at the 52-second time interval be included in the plant Technical Specifications (TS). Subsequently, the applicant has indicated that the above SSER 4 requirement is being satisfied by Seabrook TS 4.8.1.1.2.f(14). In this surveillance requirement, the cooling tower pump is started after the diesel generator is fully loaded (permanently connected loads and auto-connected accident loads). The staff has reviewed this information and conTludes that this surveillance testing is more conservative than starting the pump at the 52-second interval (3885 kW). Therefore, periodic testing to start the cooling tower pump at the 52-second time interval is not required.
8.3.1.2.8 Capability of Diesel Generator To Accept Design Load After Operation at Light or No Load In SSER 4, the staff concluded, that on the basis of DG qualification test results, the Seabrook diesel generators are capable of accepting design load after operation at no load for 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The staff required that the capability of the diesel generators to accept design load af ter operation at light load or no load be demonstrated during preoperational testing and be included in the plant Technical Specifications.
By letter dated September 25, 1986, the applicant submitted the results of the diesel generator preoperational test program. On the basis of the results of this test program, the staff concludes that the Seabrook diesel generators are capable of accepting design load after operation at no load for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This satisfies the staff's concern and is acceptable. With regard to periodic test-ing to demonstrate this capability, the applicant has stated that there is no need to include this requirement in the Technical Specifications because this capability has been demonstrated twice and there is no condition that could change this capability. The staff concludes that the Seabrook diesel generators have demonstrated the capability of accepting design load after no-load opera-tion during qualification and preoperational testing and the staff considers this to be adequate. Furthermore, the staff feels that to demonstrate this capability periodically is unnecessary and should not be required. This con-clusion is based on the fact that this requirement is not included in the Seabrook SSER 6 8-2
Standard Technical Specifications and the staff knows of no operating plant that has this requirement. Therefore, the staff finds this issue resolved.
8.3.1.4 Non-Safety Loads Powered From the Class 1E AC Distribution System In SSER 4, Section 8.3.1.4, the staff identified an open item requiring verifi-cation of the adequacy of certain preoperational tests. The staff. required confirmation that the diesel generator can start and run the startup feed pump while carrying the maximum train A load. The applicant, in its. letter of Octo-
~ber 9, 1986, confirmed that the testing was completed and that the results showed the voltage and frequency transient were within acceptable limits.
Therefore, the staff concludes that confirmatory issue 24 has been resolved.
Seabrook.SSER 6 8-3
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9 AUXILIARY SYSTEMS 9.b Other Auxiliary Systems-9.5.1 Fire Protection 9.5.1.4 General Plant Guidelines Ventilation During the course of discussions with the applicant concerning the applicant's charcoal filter adsorber temperature analysis (addressed in SER Supplement 5, SSER 5) the staff learned that the applicant had neither considered the poten-tial fire hazards associated with heating, ventilation, and air conditioning (HVAC) charcoal filter units nor determined the consequences of a charcoal.
filter unit. fire on safe shutdown. capabilities in accordance with Section'11.8 of Appendix R to 10 CFR 50 and Section A.2 of Appendix A to (BTP) Branch Tech-nical Position APCSB 9.5-1.
The staff met with the applicant on September 4, 1986, to discuss this issue, and by letter dated September 8, 1986 (V. S. Noonan to R. J. Harrison) trans-
, citted its position to the applicant. During the September 4, 1986, meeting, i
the applicant agreed to revise its fire hazards analysis with regard to the charcoal filters, outlined its proposed analysis methodology, and. stated that improved fire detection capabilities would be installed in the subject filter l units. By: letter dated September 17,.1986, the applicant committed to meet the ~ .
agreements reached with the staff during the September 4, 1986, meeting.
The applicant plans to develop individual charcoal fire models fo'r charcoal filters EAH-F-9,-69; FAH-F-41, 74; CAH-F-8; PAH-F-16; and CAP-F-40. The models will consider ignition of a specific area of a charcoal cell ~and the effect on adjacent cells. Propagation of the fire and heat transfer will be evaluated to determine the effect of the burning charcoal on structures and equipment required for safe. shutdown. Burning effects will be evaluated under both forced draft 4 and natural circulation conditions.
In the September 17, 1986, letter, the applicant committed to provide for staff review by October 10, 1986: (1).the charcoal filter fire analysis, (2) pen and
' ink markups of the reports entitled " Fire Protection Program-and Comparison to BTP.APCSB 9.5-1, Appendix A" and " Fire Protection of Safe Shutdown Capability (10 CFR 50, Appendix.R)," and-(3) a schedule of any plant modifications needed to support the analysis. In addition, the applicant stated that the afore-mentioned detection system and any other plant modifications will be operational "
bnfore exceeding 5% of rated power. The applicant also committed to formally update both the " Fire Protection Program and Comparison.to BTP APCSB 9'5-1, .
Appendix A" and " Fire Protection of Safe Shutdown Capability (10 CFR 50, Appendix R)" reports in November 1986.
As justification for.not having an operable fire detection system for the HVAC charcoal filter units by the time of licensing, the applicant proposes to Stabrook SSER 6- 9-1
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establish a fire watch patrol to inspect the charcoal filter units, as an in-terim compensatory measure, until the detection system is operable. The fire watches will be established in accordance with the Westinghouse Standard Techni-cal Specifications (NUREG.0452) for an inoperable detection system. This is, therefore, an acceptable compensatory measure.
In addition to the standard fire protection license condition, the staff will add the following license condition in the body of the Seabrook Station operat-ing license:
The appli. cant shall have the HVAC charcoal filter unit fire detec-tion systems and any other modifications dictated by the fire hazards analysis complete and operable before exceeding 5% of rated power, and shall update the reports entitled " Fire Protection Program and Comparison to BTP APCSB 9.5-1, Appendix A" and " Fire-Protection of Safe Shutdown Capability (10 CFR 50, Appendix R)" by November 30, 1986.
In Section 9.5.1.4 of SSER 5, the staff stated that the deviation request made by the applicant in a March 18, 1986, letter on the utilization of low-flow air bleed systems for engineered safety features (ESF) and non-ESF charcoal adsorbers, would require additional justification. This issue was considered an open item until such information was provided.
The current design of the ESF charcoal adsorbers includes a low-flow air bleed-system. Therefore, this design is appropriate for operation of the reactor.
For non-ESF charcoal adsorber units, the low-flow air bleed system would not be necessary for the removal of decay heat caused by the collection of radioactive iodine and its decay products, since these systems are not utilized to mitigate the consequences of an accident. Therefore, this item is considered closed.
9.5.1.8 Summary of Approved Deviations From Staff Fire Protection Guidelines All approved deviations from staff fire protection guidelines are identified in SSER 5.
9.5.1.9 Conclusions On the basis of its review, the staff concludes that, with the exception of the protection of the charcoal filter units, the applicant's fire protection program
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for Seabrook Station, with approved deviations, meets the staff fire protection guidelines of BTP CMEB 9.5-1 and satisfies General Design Criterion (GDC) 3 of Appendix A to 10 CFR 50.
The staff will condition the operating license to require that the applicant:
(1) implement and maintain in effect all provisions of the approved fire pro-tection program for the life of the plant, (2) submit the fire hazards analysis for the HVAC charcoal. filter units, (3) implement any plant modifications dic-tated by the analysis before exceeding 5% of rated power, and (4) revise the appropriate reports identified in Section 9.5.1.4 of this supplement by Novem-ber 30, 1986.
Seabrook SSER 6 9-2
9.5.2 Communication System 9.5.2.1 Intraplant Systems The Seabrook SER required that "during the preoperational tests, the applicant demonstrate that, with the antenna / repeaters not functioning, the operators can effectively communicate between each safety related area of the plant that may be required to be manned for a safe shutdown. If message relaying is required, the applicant will demonstrate that enough personnel will be on site to miti-gate the consequences of the accident and to safely shut down the plant." In a July 28, 1986 meeting with the staff, the applicant stated that the test had been performed and provided a copy of the signed-off test procedure used to demonstrate compliance with the SER requirement.
The staff has reviewed the procedure and finds that it is geared to demonstrat-ing effective communication, using only the radio system, between each diesel generator control panel and its associated plant remote shutdown panel.
Although the staff.does not believe the test completely satisfies the intent of the SER requirement, the resolution of staff concerns is-not a prerequisite for licensing. Performing additional confirmatory tests or providing adequate justification for not performing additional tests is acceptable prior to in-itial criticality, since no fission product buildup will have occurred in the reactor core, and safe-shutdown capability will not be an issue. Therefore, resolution of this matter may be safely deferred up to initial criticality.
Seabrook SSER 6 9-3
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10 STEAM AND POWER CONVERSION SYSTEM 10.4 Other Features
.10.4.2 Main Condenser Evacuation System
.10.4.2.2 Evaluation Findings It was noted in the SER that the main-condenser evacuation system (MCES) i contained no provisions for sampling discharges from the turbine vent during startup operations.
The applicant agreed to provide sampling capability for the MCES mechanical vacuum pumps during startup. During a site visit on July 28, 1986, the staff confirmed that procedures are in place for sampling capability; therefore, the staff considers this item resolved.
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Seabrook SSER 6 10-1 i
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11 RADI0 ACTIVE WASTE MANAGEMENT 11.5 Process and Effluent Radiological Monitoring and Sampling Program In Supplement No. 5 to the SER (SSER 5), the staff stated that turbine gland steam condenser exhaust samples would be. required by the Technical Specifica-tions. In SSER 5, the staff also said that certain tables that are in the Technical Specifications of other plants will be included in Part A of the Offsite Dose Calculation Manual (ODCM)~for Seabrook. This is acceptable because the Technical Specifications require compliance with the ODCM and prohibit changing Part A of the ODCM without prior approval by the NRC. The exhaust samplers (and all other effluent samplers) are specified in Part A of the ODCM. Therefore, the Technical Specifications do require these samplers, but the requirement is indirect.
Seabrook SSER 6 11-1
15 ACCIDENT ANALYSIS 15.8 Anticipated Transients Without Scram 15.8.1 ~ Generic Letter 83-28 Item 2.1 (Part 1) '
l In its evaluation of the applicant's response to NRC requirements stated in Generic Letter 83-28 for Item 2.1 (Part 1), the staff reviewed the following documents:
Letter from D. G. Eisenhut (NRC) to all licensees of operating reactors, applicants' for operating license, and holders of construction permits,
" Required Actions Based on Generic Implications of Salem ATWS Events (Generic Letter 83-28)," July 8, 1983 Letter from J. DeVincentis (PSNH) to G. W. Knighton (NRC), November 4, 1983 Letter from G. S. Thomas (PSNH) to G. W. Knighton (NRC), August 22, 1985 An EG&G report evaluated responses submitted in reply to the staff letter of July 8, 1983; the report on those responses to Item 2.1 (Part 1) is supplied in this supplement in Appendix T.
Item 2.1 (Part 1) requires the applicant to confirm that all reactor trip system (RTS) components are identified, classified, and treated as safety related as indicated in the following quotation from Generic Letter 83-28:
Licensees and applicants shall confirm that all components whose functioning is required to trip the reactor are iden-tified as safety-related on documents, procedures, and infor-mation handling systems used in the plant to control safety-
! related activities, including maintenance, work orders, and I
parts replacement.
The applicant responded to the requirements of Item 2.1 (Part 1) with submittals dated November 4, 1983, and August 22, 1985. In the first submittal, the appli-cant stated that the RTS components would be identified as safety related and that the identification would be incorporated into the administrative system to control safety-related activities. In the August 22, 1985, submittal, the applicant confirmed that the classification of safety-related RTS components had been completed and referenced in design, operating, and maintenance f documents. .
t On the basis of its review of these responses, the staff finds the applicant's statements confirm that a program exists for identifying, classifying, and I treating as safety related, components that are required for performance of the i
reactor trip function. This program meets the requirements of Item 2.1 (Part 1) of Generic Letter 83-28, and is therefore acceptable.
Seabrook SSER 6 15-1
Item 4.3 Generic Letter 85-09 specifies Technical Specification changes applicable to the reactor trip system instrumentation and surveillance. Generic Letter 85-09 concluded that Technical Specification changes should be proposed by licensees to explicitly require independent testing.of the undervoltage and shunt trip attachments of the reactor trip breakers during power operation, testing of by-pass breakers before use, and independent testing of the control room manual switch contacts and wiring during each refueling outage. These changes have now been incorporated in the Westinghouse Standard Technical Specifications.
The applicant has adopted the Westinghouse Standard Technical Specifications as a part of its license. Generic Letter 85-09 pertains to the following Technical Specifications in the Seabrook license.
- Table 3.3-1, Functional Unit 1 (Manual Reactor Trip), Functional Unit 19 (Reactor Trip Breakers), and Functional Unit 20 (Automatic Trip and Interlock Logic)
- Table 4.3-1, Functional Unit 1 (Manual Reactor Trip), Functional Unit 19 (Reactor Trip Breaker), Functional Unit 20 (Automatic Trip and Interlock Logic), and Functional Unit 21 (Reactor Trip Bypass Breaker)
The staff has reviewed the Seabrook Technical Specifications for the above func-tional units, including the action statements and table notations, and finds them consistent with those of Generic Letter 85-09. Therefore, they are acceptable.
The Seabrook Technical Specifications pertaining to Generic Letter 85-09 have been reviewed and found acceptable.
15.9 TMI Action Plan Requirements 15.9.11' II.K.3.17, Report on Outages of ECCS By letter dated June 23, 1986, the applicant referenced FSAR descriptions of its program to collect ECCS outage data for Seabrook, and identified that the data would be retained and reported through the Institute of Nuclear Power Operations (INPO) " Nuclear Plant Reliability Data System" (NPRDS) Program. The staff finds this prgram will satisfy the requirements of TMI Action Plan Item II.K.3.17, " Report on Outages of Emergency Core-Cooling Systems." Therefore, the staff finds this acceptable.
15.9.14 II.K.3.31 Plant-Specific Calculations to Show Compliance With 10 CFR 50.4f Item II.K.3.30 of NUREG-0737 outlines the Commission requirements for the indus-try to demonstrate that its small-break LOCA (SBLOCA) methods continue to comply with the requirements of Appendix K to 10 CFR 50. The technical issues to be addressed were listed in NUREG-0611 including comparison with semiscale experi-mental test results. In response to Item II.K.3.30, the Westinghouse Owners Group, of which the applicant for Seabrook is a participant, elected to reference the NOTRUMP code as the new licensing small-break LOCA model. The staff reviewed and approved NOTRUMP as the new licensing tool for calculating small-break LOCA response for Westinghouse plant designs. The staff further concluded that the Westinghouse Owners Group had met the requirements of Item II.K.3.30.
Seabrook SSER 6 15-2 l
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Referencing the new computer code did not imply deficiencies in the WFLASH code (which was previously utilized for small-break LOCA analysis) so that the code did not comply with Appendix K to 10 CFP 50. The decision to use NOTRUMP was based on the industry's. desire to perform licensing evaluations with a computer program specifically designed to calculate small-break LOCAs with greater phenom-enological accuracy than capable by WFLASH.
Item II.K.3.31 of NUREG-0737 required that each license holder or applicant sub-mit a new small-break analysis using the model approved under Item II.K.3.30.
NRC Generic Letter 83-25 provided clarification for the II.K.3.31 requirements by allowing license holders and applicants to comply on a generic basis by demon-4 strating that the WFLASH analyses are conservative when compared with analyses performed using NOTRUMP.
In response to this guidance, the Westinghouse owners submitted WCAP-11145 which contains generic comparisons to WFLASH analyses for various plant types. These include comparisons for 4-loop plants of the Seabrook design. If plant-specific analyses were performed for Seabrook using NOTRUMP, lower peak cladding tempera-tures should be expected in comparison with the generic NOTRUMP analysis (about 537 F lower than the 1,790 F PCT currently calculated with WFLASH SBLOCA EM).
Although the calculated peak. temperatures are significantly lower for the NOTRUMP analyses than for the WFLASH, the 4-inch break remains the limiting break size.
Staff review of WCAP-11145 has been completed; WCAP-11145 has been accepted as a licensing basis for SBLOCA analysis. The applicant has referenced WCAP-11145 (which consists of the results from calculations using approved methodology) in lieu of submitting a plant-specific analysis, and meets the criteria as stated in NRC Generic Letter 83-85. The staff, therefore, concludes that the Seabrook FSAR analyses of small-break LOCAs have been demonstrated to be conservative in comparison with the NOTRUMP Evaluation Model. This meets the requirements of Item II.K.3.31 and 10 CFR 50.46 for Seabrook.
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'Seabrook SSER 6 15-3
18 HUMAN FACTORS ENGINEERING 18.2 Safety Parameter Display System (TMI Action Plan Item I.D.2)
In SER Supplement 4, the staff described the safety parameter display system (SPDS) purpose and requirements and presented an initial status review of the Seabrook SPDS.
By letter dated January 6, 1986, the applicant submitted the SPDS design report for staff review. The applicant submitted additional information on the design by letter dated April 2, 1986. In addition to the staff review, the staff, assisted by consultants from Lawrence Livermore National Laboratory (LLNL),
conducted an onsite design verification and validation audit of the Seabrook SPDS on May 20-22, 1986. A detailed technical evaluation report (TER) of that audit prepared by LLNL, is reproduced in Appendix R of the supplement. The staff agrees with the technical positions and conclusions contained in the TER.
The following evaluation was prepared, based on the findings of the TER, to establish a basis for a license condition to ensure completion of items per-taining to the Seabrook SPDS.
SPDS Description The Seabrook SPDS is incorporated as a function within the main plant computer.
The displays are presented on cathode ray tubes (CRTs) that are an integral part of the control room. The designated primary SPDS CRT is located near the center of the control room at the shift technical advisor (STA) station. The SPDS displays may be selected and presented at any of six other CRTs in the main control board. Operator access is through the existing keyboards used for accessing all piant programs and displays.
The top-level SPDS display format consists of six color- and position-coded bars representing the summary status of the six critical safety functions (CSFs).
Each CSF status tree is displayed on the second-level format, which includes parameter values and a color- and shape-coded status circle for each tree branch.
The summary bar for the six functions appears in the lower left corner of each.
CSF status tree.
Variable Selection Section 4.1(f) of Supplement.1 to NUREG-0737 states:
The minimum information to be provided shall be sufficient to provide information to plant operators about:
(i) Reactivity control (ii) Reactor core cooling and heat removal from the primary system l
Seabrook SSER 6 18-1
(iii) Reactor coolant system integrity (iv) Radioactivity control (v) Containment conditions For review purposes, these five items have been designated as CSFs.
The applicant has defined the CSFs for Seabrook from a different perspective.
They are based on the maintenance of the following three physical barriers to radiation release:
(1) fuel matrix and fuel cladding (2) reactor coolant system (RCS) pressure boundary (3) containment The six CSFs that the applicant has defined to maintain these barriers are (1) subcriticality (2) core cooling (3) heat sink (4) RCS integrity (5) containment integrity (6) reactor coolant inventory Staff review of the parameters selected by the applicant to support these func-tions indicates that the six CSFs defined by the applicant do not fully cover the five CSFs specified in Supplement 1 to NUREG-0737. Specific findings of the staff review are:
(1) Residual heat removal (RHR) flow and hydrogen concentration are not included in the Seabrook CSF status trees and are not displayed on the SPDS.
(2) Radiation parameters are to be displayed but are not yet implemented.
(3) Containment isolation is not displayed on the SPDS but is accessible, to a limited extent, from the prime SPDS position (see section entitled
" Human Factors Program" below).
The staff finds all other variables selecteo acceptable in satisfying the above requirement of NUREG-0737, Supplement 1.
Display Data Validation The audit indicated that the data validation methodology includes only range checking, averaging, and auctioneering. Concern was raised that a parameter value could be within an acceptable range but significantly different from other measures of the same parameter, causing the average value to be incorrect and possibly misleading. A'more sophisticated data validation algorithm, to ensure display of more valid data, is being pursued by the applicant.
i Seabrook SSER 6 18-2
Human Factors Program The applicant's human factors program for the SPDS was not well described in the Seabrook SPDS description report. Information provided in the letter of April 2, 1986, described three basic ways in which human factors were involved in the SPDS development. ~First, the individual status trees (second-level formats) were developed as part of the Westinghouse Owners Group guidelines and had both human factors input into the display design and human factors review of the finished format. Second, Seabrook operators versed in human factors engineering, through participation in the detailed control room design review (DCRDR), developed the top-level display used in the SPDS. Finally, the SPDS display system was evaluated as part of the DCRDR program and no human engineering discrepancies were identified.
During the onsite audit, the staff conducted a human factors review of the Seabrook SPDS against the requirements of Supplement 1 to NUREG-0737. The writeup below addresses the degree of acceptability of the Seabrook SPDS with respect to these requirements.
Concise Display: With the exception of the containment isolation panel, which is a separate display and is to be improved, the SPDS CRT formats provide a concise display of plant conditions as required by NUREG-0737, Supplement 1.
Convenient Location: The locati_on of the prime SPDS CRT at the STA station near the center of the control room and the ability to call up the SPDS at other operator locations satisfy the NUREG-0737, Supplement No.1 requirement for. placing the SPDS in a convenient location. The containment isolation dis-play as it is currently configured and located does not meet this requirement of NUREG-0737, Supplement 1.
Continuous Display: The capability to call up display formats, other than the SPDS, on the STA's designated SPDS CRT does not satisfy the NUREG-0737, Supple-ment No. 1 requirement for the SPDS to be a continuous display. Either the CSF summary display must be added to all CRT formats accessible on the STA's CRT, or a dedicated CSF summary display needs to be added to the STA station.
Aid Operator in Rapidly and Reliably Determining Plant Status: Observation of an accident simulation indicated that the top-level CSF summary display appears to aid operators in rapidly determining plant status, but lower-level display formats do not seem to be as useful. The staff suggests a
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strong man-in-the-loop test program to identify drawbacks to the usefulness of the lower-level formats.
The system response time appears to be satisfactory, but the staff observations were made during a lightly loaded sequence.
System availability data indicate over 0.99 availability for the SPDS. The applicant needs to determine how the availability of the reactor vessel level instrumentation system (RVLIS) and the radiation data management system (RDMS) will be factored into the system availability calculation.
The subcriticality and core cooling status tree displays are not mode dependent.
- The displays will indicate that these CSFs are being challenged during normal power operations. This condition has the potential for misleading operators and needs improvement.
Seabrook SSER 6 18-3
Incorporate Accepted Human Factors Principles: The SPDS generally incorporates accepted human factors principles with the following exceptions:
(1) The heat sink format displays the flow data value in an unconventional location.
(2) The display callup. method is acceptable but awkward. The staff recommends a single operator action for callup of each of the second-level displays.
(3) The containment isolation display is located a significant distance from the primary SPOS location so that it is difficult to read the legends.
Unused cells appear to be randomly located so that pattern recognition is not a viable method of determining containment isolation. Furthermore, the display cells were design ~ed to use two light bulbs each, but heat pro-duced by two bulbs has caused the applicant to remove one bulb per cell.
This one-bulb condition reduces brightness and readability and eliminates the redundancy in indication provided by two bulbs.
Procedures and Training: Audit of the SPDS procedures and operator training program indicates that both satisfy the requirements of Supplement No.1 to NUREG-0737.
Electrical and Electronic Isolation
- The SPDS description report did not address isolation devices. Further infor-mation was provided by the letter of April 2, 1986. The following types of isolation devices are used at Seabrook:
(1) Westinghouse 7300 Series instrumentation (2) General. Atomics (GA) RM 80 isolators (3) Westinghouse isolators used in the RVLIS The Westinghouse 7300 Series isolators have been approved by the staff by means of Westinghouse Topical Report WCAP-8892A.
The GA RM 80 isolators, with the temporary fix of their fused output circuit, have been approved by the staff for use before the first refueling outage.
At that time, the isolators are to be replaced with isolators that do not have any fuses in their output circuit.
The Westinghouse RVLIS isolators, used to protect RVLIS from SPDS, have not yet been approved by the staff. In the meantime, the staff approves the use of r
' SPDS on an interim basis at reactor power levels less than 5% of rated power.
The likelihood of core damage at this_ low reactor power level is remote because the new fuel has not had a chance to build up significant radioactive decay products and, therefore, the amount of decay heat and the radiological source terms would both be low. In addition the reactor protection system-instrumenta-j tion, including pressurizer lev'el and pressure, would be available to provide an indication that the system is filled or-is voiding.
The Westinghouse test report covering qualification of the RVLIS isolators is due in September 1986. Since the circuitry in these isolator boards is identical
- See also Appendix 18A.
Seabrook SSER 6 18-4
_ - . - - _ _ - _ _ _ _ . - _ _ . - _ - - . _ = - --. .
to that used in an earlier approved Westinghouse product, Westinghouse believes the isolation capabilities to be sufficient. The staff concurs in the above and will confirm that the isolator capability is established before 5% of rated power is exceeded.
Conclusions J
On the basis of its documentation review and information gathered at the onsite audit, the staff concludes that the Seabrook SPDS does not fully meet the appli-cable requirements of Supplement 1 to NUREG-0737. The conclusion is based-on-the following:
(1) The SPDS display is not continuous.
(2) RHR flow and hydrogen concentration variables are considered by the staff to be part of the minimum information required to assess the CSFs and are not displayed on the SPDS.
(3) The containment isolation display is not satisfactorily readable from the prime SPDS location to be considered part of the SPDS.
-(4) The SPDS does not display sufficient radiation variables.
(5) Several human engineering discrepancies have been identified.
(6) Two CSF status trees are not mode dependent and 'have the potential for misleading the operator.
(7) Isolation devices between the RVLIS and the SPDS have not yet been approved.
(8) Data validation algorithms may not be sophisticated enough to ensure valid I data are displayed to the operator.
(9) The usefulness of the lower-level SPDS display formats to the operator is in question.
(10) RVLIS and RDMS availability has not yet been factored into overall SPDS 4
availability calculations.
(11) System response time appears to be satisfactory, but a system load test is needed to verify the worst condition.
Implementation of the SPDS is not required under NUREG-0737 before full power and is determined by a schedule that is negotiated with the staff. The appli-cant had proposed a June 30, 1986, implementation date for the Seabrook SPDS, and the staff found this acceptable. However, as noted in Supplement No. 4, a schedule for resolution of open items identified in the staff's review and on-site audit would be established as a license condition to be implemented by the applicant before restart following the first refueling outage.
The staff did not identify any serious safety questions concerning the Seabrook SPDS. However, the staff did determine that the isolators between RVLIS and SPDS have not yet been approved. Accordingly, the staff concludes that SPDS
- will be acceptable as an interim implementation up to 5% of rated reactor power.
Seabrook SSER 6 18-5
Following approval of the isolators, the interim SPDS may be used until the.
other open items identified above have been resolved, or up to the end of the first refueling outage. At a minimum, resolution of the open items will include:
(1) continuous display of the top-level critical safety function summary at the assigned SPDS control room location
~(2) addition of, or satisfactory justification for not adding, RHR flow and hydrogen concentration parameters to appropriate SPDS screens
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(3). addition of a containment isolation status screen on the SPDS, or improve-ment of the current containment isolation display to'be satisfactorily
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recognizable from the assigned SPDS location in the control room. The second option must also include a commitment by the applicant that the relative position and orientation of the containment isolation display with respect to the SPDS station be maintained or improved.
(4) addition of a radiation monitoring screen to display'at least steam genera-tor (or steamline) and stack radiation (5) improvement of the heat sink screen for consistency in labeling and the subcriticality and core cooling screens for mode dependency so as not to mislead operators (6) addition of approved isolation devices between the RVLIS and the SPDS, before 5% of rated reactor power is exceeded In addition, the applicant shall satisfactorily resolve the other open items identified above or demonstrate to the staff's satisfaction that the open items will not degrade the performance of the SPDS.
The staff proposes that the following license condition be imposed to ensure satisfactory resolution of the open issues:
Prior to exceeding 5% reactor power, the' applicant shall ha;.' installed qualified isolation devices, approved by the staff, between RVLIS and SPDS.
Before restart following the first refueling outage, the applicant shall have operational a safety parameter display system (SPDS) (as described in its submittals dated January 6, 1986, and April 2, 1986, and as modified as a result of the staff's audit findings) that is acceptable to the NRC.
Seabrook SSER 6 18-6
APPENDIX 18A ELECTRICAL AND ELECTRONIC ISOLATION OF SAFETY PARAMETER DISPLAY SYSTEM At the time Section 18 was written for this sixth supplement, the information provided in the material that follows was not yet available. Therefore, it is being added to the Seabrook SER at this time in this appendix.
Background
In order to satisfy the NRC requirements concerning the safety parameter display system (SPDS), Public Service Company of New Hampshire (PSNH) submitted a Safety Analysis Report by letter dated January 6, 1986 (J. DeVincentis, PSNH, to V. S.
Noonan, NRC). This report provided a description and a safety analysis of the SPDS at the Seabrook Station. However, the report did not address the require-ment that the SPDS must be isolated from equipment and sensors.that are used in safety systems to prevent electrical and electronic interference. On March 11, 1986, a request for additional information, which included specific questions on these isolators, was sent to the applicant (V. Nerses,-NRC, to R. J. Harrison, PSNH). The staff held several telephone conferences with the applicant, which resulted in submittals from the applicant (J. DeVincentis to V. S. Noonan) dated February 14, April 2, and August 28,-1986. These submittals documented the-various agreements and commitments reached in the telephone conferences.
The staff's evaluation addresses the qualification and documentation of the isolators as acceptable interface devices between Class 1E safety-related instru-mentation systems and the SPDS.
Discussion and Evaluation The SPDS developed at the Seabrook Station is an integral part of Seabrook's Emergency Response Procedures (ERPs) and Radiological Emergency Plan. The ERPs are based on the Westinghouse Owners Group Emergency Response Guidelines. The SPDS utilizes the main plant computer to accept information from plant instru-mentation ~and to display critical functions to the plant operator. All inputs to the plant computer that are used by the SPDS and which come from Class 1E instrumentation are isolated by Class 1E electrical isolation devices.
These isolation devices are:
(1) Westinghouse Series 7300 equipment supplied by Westinghouse (2) RM-80 microcomputer, supplied by GA Technologies, Inc, (3) RVLIS isolator model No. 2343D63G02 supplied by Westinghouse The Westinghouse Series 7300 isolators have been reviewed and approved by the staff via Westinghouse report WCAP-8892A. The GA RM-80 isolators have been conditionally approved by the staff as reported in a staff memorandum dated Seabrook SSER 6 18A-1
June 14, 1986 (C. E. Rossi to'V. Nerses). The GA RM-80_ isolators will be replaced with non-fuse-dependent isolators before startup after the first re-fueling outage.
The RVLIS isolation device ~uses an opto-coupler as the isolation barrier. Anal-ysis shows that the maximum credible fault (MCF) voltage and current that the isolator could be subjected to are 240 V ac and 140 V de, respectively, at a 20-ampere source. The pass / fail criteria established by the applicant state that the system must be in a normal operation mode and must provide normal in-formation within the execution cycle time of the microprocessor. The isolation devices are located in a mild environment; therefore, they are not covered by 10 CFR 50.49 conditions.
The reactor vessel level instrumentation system (RVLIS) isolators have been seismically qualified for the plant and have been subjected to several differ-ent types of noise testing without affecting the system output.
The MCF voltage and current were applied to the non-Class 1E output of the iso-lator in the transverse mode. .In accordance with the pass / fail criteria, there was no adverse effect on the Class IE input side of the isolator.
Conclusion On the basis of the staff's review and evaluation of the information supplied by the applicant with respect to the electrical isolation devices to be used with the SPDS, the staff has concluded that:
(1) The Westinghouse 7300 Series isolators are acceptable as previously ap-proved by the staff.
(2) The interim fix for the RM-80 system for isolating safety-related data channels from the SPDS is approved.
(3) Replacing the RM-80 devices with approved non-fused devices shall remain a confirmatory issue to be resolved during the first refueling outage.
(4) The RVLIS isolation devices are acceptable for isolating Class IE equipment from the SPDS.
The staff further concludes that this equipment meets the Commission's require-ments in NUREG-0737, Supplement No.1, and that the following propoud license condition (Memorandum dated June 14, 1986, from Rossi to Nerses) , as been satisfied:
Prior to exceeding 5% reactor power, the applicant shall have installed qualified isolation devices, approved by the staff, between RVLIS and SPDS.
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l Seabrook SSER 6 18A-2
APPENDIX A CONTINUATION OF CHRONOLOGY OF RADIOLOGICAL REVIEW July 22, 1986 Letter from applicant transmitting Supplement 3 to Amendment 57 to license application. Letter requests partial transfer of Construction Permits CPPR-135 and CPPR-136.
July 23, 1986 Letter to applicant.concerning approved security plan for Seabrook Station, Unit 1.
July 24, 1986 Letter from applicant concerning setpoint for Technical Specification 3.4.9.3.a, Overpressure Protection System.
July 24, 1986 Letter from applicant concerning Seabrook Technical Speci-fication 3.11.2.6, Explosive Gas Mixture-Cubicles.
July 25, 1986 Letter from applicant concerning 10 CFR 50, Appendix J, Type C leak rate testing.
' July 29, 1986 Letter from applicant concerning maximum expected waste generated by steam generator blowdown evaporators.
July 31, 1986' Letter from applicant concerning Preservice Inspection Pro-gram, Final Summary Report (SER Section 5.2.4.1).
July 31, 1986 Letter from applicant concerning TMI Action Plan Item II.K.3.31, Plant-Specific Calculations to Show Compli-ance With 10 CFR 50.46.
August 6, 1986 Representatives from NRC and PSNH meet in Bethesda, Md., to hear presentation by the applicant on the Seabrook Station Risk Management and Emergency Planning Study and Emergency Planning Sensitivity Study. (Summary issued September 8, 1986.)
August 19, 1986 Letter to applicant concerning Seabrook emergency and startup feedwater pumps.
August 19, 1986 Letter to applicant transmitting an Order extending the latest construction completion date for Seabrook Unit 1 to June 30, 1987.
August 19, 1986 Letter from applicant concerning emergency core cooling design.
August 20, 1986 Letter to applicant transmitting the draft Seabrook Station, Unit 1, license. Comments are requested by August 29, 1986.
Seabrook SSER 6 1 Appendix A
August 21, 1986 Letter from applicant concerning conformance of isolation valve SI-V-93 to Branch Technical Position PSB 18.
August 21, 1986 Letter from applicant concerning Final 10 CFR 50.55(e)
Report: Electrical Cable Tray Support Bolts (CDR 81-00-10).
August 22, 1986 Letter from applicant concerning anticipated transient without scram (ATWS), 10 CFR 50.62.
August 22, 1986 Letter from applicant concerning detailed control room de-sign review, control room environment.
August 26, 1986 Letter from applicant concerning preoperational flow-induced vibration testing of reactor internals, final report.
August 28, 1986 Letter from applicant requesting additional information concerning safety parameter display system for Seabrook Station.
September 2, 1986 Letter from applicant transmitting Supplement 4 to Amend-ment 57 to license application dated March 30, 1973, and request for partial transfer of Construction Permits CPPR-135 and CPPR-136. Letter clarifies applicant's letter of July 22, 1986, concerning the owner of shares transferred from five owners.
September 4, 1986 Representatives from PSNH-NHYD and NRC meet in Bethesda, 4
Md., at the Seabrook Project Office to discuss the charcoal filter units fire hazards analysis. (Summary issued September 17, 1986.)
September 8, 1986 Letter to applicant concerning fire protection.
September 8 & 9, Representatives from NRC, Brookhaven National Laboratory, 1986 and Public Serve Co. of New Hapshire (PSNH) meet at Seabrook Station to examine plant features important to Risk Management and Emergency Planning Study. (Summary issued September 11,'1986.)
September 10, 1986 Letter from applicant concerning Seabrook Station Offsite Dose Calculational Manual.
September 10, 1986 Letter from applicant concerning Revision to FSAR Figure 13.1-5.
September 10, 1986 Letter from applicant concerning conformance to Regulatory Guide 1.133.
September 11 - Representatives from NRC and PSNH will meet at different October 17, 1986 dates and times to resolve Seabrook licensing issues before issuing the operating license. Separate summaries and entries will be noted.
Seabrook SSER 6 2 Appendix A
- September 12, 1986 Letter to applicant transmitting Amendment No. 9 to CPPR-135 and CPPR-136 for Seabrook Station allowing change of ownership shares.
September 12, 1986 Letter from applicant transmitting additional comments on Seabrook Station Technical Specifications.
September 17, 1986 Letter from applicant concerning Seabrook HVAC charcoal filters.
September 18, 1986 Letter from applicant concerning emergency and startup feedwater pumps.
September 19, 1986 Letter from applicant concerning steam generator water level low-low trip setpoint.
t September 19, 1986 Letter from applicant transmitting Comments to Draft License for Seabrook Station, Unit 1.
September 23, 1986 Letter from applicant transmitting Amendment No. 60 to the March 30, 1973, application to construct and operate Seabrook Station, Units 1 and 2.
September 23, 1986 Representatives from NRC, Brookhaven National Laboratory, and PSNH meet in Bethesda, MD., to discuss status of Seabrook Risk Management and Emergency Planning Review.
(Summary to be issued.)
September 29, 1986 Letter from applicant transmitting Revision to Seabrook Station FSAR.
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j Seabrook SSER.6 3 Appendix A
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APPENDIX B BIBLIOGRAPHY U.S. Nuclear Regulatory Commission, Generic Letter 83-28, Letter from D. G.
Eisenhut to all licensees of operating reactors, applicants for operating. license, and holders of construction permits, " Required Actions Based on Generic Implica-tions of Salem ATWS Events," July 8, 1983.
-- , Generic Letter 83-85
-- , Generic Letter 85-09, " Technical Specifications for Generic Letter 83-28, Item 4.3," May 23, 1985.
-- , NUREG-0452, " Standard Technical Specifications fcr Westinghouse Pressur-ized Water Reactors," June 1978.
-- , NUREG-0611, " Generic Evaluation of Feedwater Transients an'd Small Break Loss-of-Coolant Accidents in Westinghouse-Designed Operating Plants,"
January 1980.
-- , NUREG-0737, " Clarification of TMI Action Plan Requirements," November 1980; Supplement 1, January 1983.
Westinghouse Corp., WCAP-8892A, " Westinghouse 7300 Series Process Control System Noise Tests," June 1977.
-- , WCAP-10054
-- , WCAP-10079 Seabrook SSER 6 1 Appendix B
APPENDIX D ACRONYMS AND INITIALISMS ASME American Society of Mechanical Engineers ATWS anticipated transients without scram BTP Branch Technical Position CFR Code of Federal Regulations CRT cathode ray tube CS centrifugal charging CSF critical safety function DCRDR detailed control room design review DG diesel generator ECCS emergency core cooling system ERP Emergency Response Procedure ESF engineered safety features FSAR Final Safety Analysis Report GA General Atomics HVAC heating, ventilation, and air conditioning INEL Idaho National Engineering Laboratory IST inservice testing program LLNL Lawrence Livermore National Laboratory i LOCA loos-of-coolant accident LPMS loose parts monitoring system MCES main condenser evacuation system MCF maximum credible fault NPSH net positive suction head ODCM Offsite Dose Calculation Manual OL operating license PAFB Pease Air Force Base PSNH Public Service Company of New Hampshire QC quality control Seabrook SSER 6 1 Appendix 0
.RCS ' reactor coolant system RG regulatory guide RHR residual heat removal RTS reactor trip system RVLIS reactor vessel level instrumentation system RWST refueling water storage tank SBLOCA small-break loss-of-coolant accident SER Safety Evaluation Report SI safety injection SPDS safety parameter display system SSER Supplement to Safety Evaluation Report SSTS Seabrook Station Technical Specifications STA shift technical advisor TER technical evaluation report TS Technical Specification VAS video alarm system l
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Seabrook SSER 6 2 Appendix 0 1
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l APPENDIX F NRC- STAFF CONTRIBUTORS AND CONSULTANTS The NRC staff members listed below were principal contributors to this report.
Name Title Review branch
- Goutam Bagchi Section Leader Engineering Om P. Chopra Senior Electrical Electrical, Instrumentation Engineer and Control Systems Richard J. Eckenrode Human Factors Engineer. Electrical, Instrumentation and Control Systems Robert J. Giardina Mechanical Engineer Plant Systems Richard Lobel Section Leader Reactor Systems Warren C. Lyon Senior Nuclear Engineer Reactor System Jerry L. Mauck Senior Electrical Electrical, Instrumentation Engineer and Control Systems
. Victor Nerses Senior Project Manager Project Directorate #5 Frank Orr Reactor S9 stems Engineer Facilities Operations J. Pulsipher Mechanical Engineer Engineering Norman D. Romney Mechanical Engineer Engineering Madelyn Rushbrook Licensing Assistant Project Directorate #5 Amarjit Singh Mechanical Engineer Plant Systems Harold Walker Materials Engineer Electrical, Instrumentation and Control Systems l
K. Steven West Mechanical Engineer Project Directorate #6 (PWR Lic. B)
- Division of~Pressurf7ed Water Reactor Licensing-A, Office of Nuclear Reactor Regulation (unless otherwise noced).
Seabrook SSER 6 1 Appendix F j
. _ , . = .. . - _ - .-. . . . . _ . . - - ...
The following contractor personnel contributed to this report.
James Cooper Lawrence Livermore National Laboratory R. Haroldsen EG&G Idaho, Inc.
Lawrence Livermore National Laboratory Gary L. Johnson
- . C. 8. Ransomd EG&G Idaho, Inc.
H. C. Rockhold EG&G Idaho, Inc.
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2 Appendix F Seabrook SSER 6
APPENDIX H ERRATA TO THE SEABROOK STATION SAFETY EVALUATION.
REPORT AND ITS SUPPLEMENTS SER Section 8.3.3.3.1, p. 8-19, 4th line from bottom of page Change " Technical Specifications" to "FSAR Section 16.3,. Technical Speci-fication Improvement Program."
SER Supplement 5 Section 3.10.2.3, p. 3-11, 10th line from bottom of page Change " Retesting before fuel load will verify seal integrity" to " Static test has been performed. Dynamic test to verify seal integrity will be
. performed prior to initial criticality. This is acceptable;-therefore, this issue is closed."
Section 11.3, page 11-1, line 16 Change " Technical Specifications" to " plant procedures".
Section 11.4.1, page 11-1, lines 3 and 4 Delete " filter sludges,".
Section 11.4.1, page 11-1, 2nd and 3rd lines from bottom of page
- Delete " Spent demineralizer resin xxx reduction and solidification."
Section 11.5.2, page 11-3, line 7 Change "by the Technical Specifications." to "in the ODCM."
i Seabrook SSER 6 1 Appendix H
APPENDIX R I
> DESIGN VERIFICATION AND DESIGN VALIDATION AUDIT OF THE SAFETY PARAMETER DISPLAY SYSTEM FOR PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE L SEABROOK STATION 4
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DESIGN VERIFICATION AND DESIGN VALIDATION AUDIT OF TIIE SAFETY PARAMETER DISPLAY SYSTEM FOR PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE -
SEABROOK STATION August I,1986 James Cooper Gary L. Johnson Lawrence Livermore National Laboratory for the United States Nuclear Regulatory Commission 1
Seabrook SSER 6 Appendix R
TABLE OF CONTENTS Page
- 1. Introduction ..................................................... ~1 d
- 2. Safety Parameter Display System Design Overview . . . . . . . . . . . . . . . . . . . . 2
- 3. . Assessment of the Verification and Validation Program . . . . . . . . . . . . . . . . 3
- 3.1 . System Requirem ents Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3.1.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3.1.2 Audi t Team Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 3.2. Design Verification Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 3.2.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 i
3.2.2 Audit Team Assessment ............................... 5 3.3 Vali da t i on Tes ts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 3.3.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 3.3.2 Audit Team Assessm ent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 3.4 Field Verification Tests ......................................
. 6 3.4.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 3.4.2 Audit Tea m Assessm ent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
- 4. Assessm ent o f SPD S Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 4.1 "De SPDS Should Provide _a Concise Display ..." . . . . . . . . . . . . . . . . . 7 4.1.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 4.1.2 Audit Team Assessment ............................... 8 4.2 "The SPDS Should ... Display ... Critical Plant Variables" . . . . . . . . . . 8 4.2.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 4.2.2 Audit Team Assessm ent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 4.3 "He SPDS Should ... Aid Them (Operators) In Rapidly and Reliably Determining the Safety Status of the Plant" ......... 11 4.3.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 4.3.2 Audit Tea m Assessm ent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
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. Seabrook SSER 6 fii Appendix.R I
TABLE OF CONTENTS (Cont.)
Page 4.4 "The Principle Purpose and Function of the SPDS is to I'4 Aid.........................................................
14 4.4.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14 4.4.2 Audit Tea m Assessm ent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.5 "(De) SPDS (Shall Be) Located Convenient to the Control Room Operators" . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 15 4.5.1 Audit Tea m Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15 4.5.2 Audit Team Assessment ...............................
4.6 "The SPDS Shall Continuously Display _ Information ... . . . . . . . . . . . . . 15 15
> 4.6.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15 4.6.2 Audit Team Assessment ...............................
4.7 "De SPDS Shall be Suitably Isolated ... . . . . . . . . . . . . . . . . . . . . . . . . . 16 16 4.7.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16 4.7.2 Audit Team Assessm ent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.8 " Procedures Which Describe the Timely and Correct 16 Safety Status Assessm ent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16 4.8.1 Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16 4.8.2 Audit Team Assessm ent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.9 "We SPDS Display Shall be Designed to Incorporate 16 Accepted Hum an Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audit Team Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -16 4.9.1 17 4.9.2 Audit Team Assessment ...............................
17
- 5. Summary........................................................
20
- 6. References......................................................
t 20 6.1 G eneral Re fe re nces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.2 Documentation Examined During the Audit . . . . . . . . . . . . . . . . . . . . . . 20
-iv-(
l Seabrook SSER 6 iv Appendix R
i DESIGN VERIFICATION AND DESIGN VALIDATION AUDIT OF THE SAFETY PARAMETER DISPLAY S STEM FOR PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SEABROOK STATION
- 1. INTRODUCTION On May 20 and 21,1986, an on-site audit of the Seabrook Station Safety Parameter Display System (SPDS) .was conducted by the NRC. 'Ihis NRC audit examined the Seabrook Verification and Validation program .and reviewed the operation of the SPDS.
'lhus, the audit specifically addressed the points of both a Design Verification Audit and a Design Validation Audit as described by Sec.18.2 of ~NUREG-0800. 2 The audit team was composed of one individual from the Nuclear Regulatory Commission Electrical Instrumentation and Control Systems Branch, an individual from the Lawrence Livermore National Laboratory, and an individual from EG&G acting as consultants to the NRC.-
The . audit was based upon the recommended criteria of NUREG-0800 See.18.2. In
[ accordance with that guidance, up to three separate audit meetings / site visits, as described below, may be arranged.
Design Verification Audit. The purpose of this audit meeting is to obtain additional information required to resolve any outstanding questions about the V&V program, to confirm that the V&V program is being correctly implemented, and to audit the results of the V&V activities to date. At this meeting, the applicant should provide a thorough
~
description of the SPDS design process. Emphasis should be placed on_how the applicant is assuring that the implemented SPDS will: provide appropriate parameters, be isolated from safety systems, provide reliable and valid data, and incorporate good human engineering practice.
Design Validation Audit. After review of all documentation, an audit may be conducted to review the as-built prototype or installed SPDS. The purpose of this audit is to assure that the results of the applicant / licensee's testing demonstrate that the SPDS meets the functional requirements of the design and to assure that the SPDS exhibits good human engineering practice.
Installation Audit. As necessary, a final audit may be conducted at the site to ascertain that the SPDS has been installed in accordance with the applicant / licensee's plan and is
- functioning properly. A specific concern is that the data displayed reflect the sensor signal which measures the variable displayed. 'Ihis audit will be coordinated with and may be conducted by the NRC Resident Inspector.
Based on the advanced state of the Seabrook SPDS design, the NRC staff carried out a.
combined Design Verification and Design Validation audit at the plant site.
During the course of this audit, the.NRC audit team discussed aspects of the Seabrook
- SPDS program with Public Service Company of New Hampshire (PSNH). Additionally, the Seabrook control room was visited to ascertain the location of SPDS displays in-JYB:860603:8/1/86 Seabrook SSER 6 1 Appendix R 4
I relation to plant control boards and a response to a simulated plant upset was witnessed at the unit simulator to observe how the SPDS is used by the plant operating staff.
- 2. SAFETY PARAMETER DISPLAY SYSTEM DESIGN OVERVIEW
' he Seabrook Station SPDS is a feature of the station's Main Plant Computer system (MPC). .The SPDS consists of seven MPC displays and one hardwired display that reflect i the status of the six Critical Safety Functions (CSF) defined by the Seabrook Emergency Operating procedures. Dese eight displays consist of:
o An overview display showing the status of all CSFs.
o 'Six logic tree displays, one for each of the CSFs defined by the EOPs. Each display shows the current value of the parameters used to assess the CSF.and the logic used to determine the status of the CSF.
o A hardwired display of containment isolation status.
PSNH has committed to add a Radiological Control CSF display that shows the current value of -the radiation monitoring parameters used to determine the status of the l Radiological Control CSF.
SPDS displays can be called up on any of seven MPC CRTs located around the control room. In addition, the ' MPC is used to generate alarm displays and is capable of displaying historical trends of any parameter input to the MPC or of any calculated value derived by the MPC.
He MPC receives inputs from plant instrumentation via nine Intelligent Remote Terminal Units (IRTU) that convert the input signals to digital format and transmit the data to two host computer units. Each IRTU contains redundant central processing units (CPUs). PSNH has organized MPC inputs such that redundant inputs are processed by different IRTUs.
The host computer consists of redundant CPUs. The hosts check each input value to 4 verify it is within the range of the measuring instrument and is within reasonableness limits established by 'PSNH. De host computer also performs SPDS calculations, logic, and develops SPDS displays in addition to other MPC and visual alarm system functions.
+
4 De MPC also receives input of SPDS parameters from the Inadequate Core Cooling Monitor (ICCM) and the Radiation Data Management System (RDMS). 'Unlike parameters input via IRTUs, parameters received from ICCM and RDMS have had range and -
- reasonableness checks by these systems; therefore, additional checking is not performed l by the host computer.
One Safety Parameter Display System Critical Safety Function Display that was not originally planned to be included in th'e Seabrook SPDS system is radiological control. In response to NRC's identification of the need for a Radiological Control CSF, the RDMS will be modified to input to the SPDS. This system uses redundant central processor units and a loop data bus data acquisition system to continuously monitor area and effluent radiation levels around the station. The system periodically collects data from JYB:860603:8/1/86 ,
Seabrook SSER 6 2 Appendix R
approximately 170 sensors, all with different addresses on the loop data busses. This information is presently displayed on a console in the control room. Linking this RDMS
, system by data bus to the Main Plant Computer will enable the display of current radiological data at any MPC work station, at the emergency response facility (ERF), the meteorological workstation (MET), and on the SPDS. Seabrook plans to link the MPCS to the RDMS by use of a vendor recommended interface.
- 3. ASSESSMENT OF THE VERIFICATION AND VALIDATION PROGRAM A Verification and - Validation (V&V) Program is concerned with the process of specification, design, fabrication, testing, and installation associated with an overall system's software, hardware, and operation. For the SPDS, verification is the review of the requirements to see that the right problem is being solved and a review of the design j to see that it meets the requirements. Validation is the performance of tests of the integrated system to see that it meets all requirements.
Verification and Validation activities are not a regulatory requirement for the SPDS.
Nevertheless, a V&V program performed by the applicant /lleensee during design, installation, and implementation of an SPDS will facilitate the NRC staff review of the system. The staff would then evaluate the program for the results of the design V&V
. program. On the basis of an effective V&V program, the staff would reduce the scope and detail of the technical audit of the design.
De purpose of the NRC Design Verification Audit was to obtain additionalinformation j required to resolve the outstanding questions about the PSNH V&V Program, to confirm that the V&V Program is being correctly implemented, and to audit the results of.the V&V activities to date. The criteria suggested in NUREG-0800, Sec.18.2, Appendix A were used as a basis for this audit. The recommendation of NSAC/39 u provided additional guidar 2e to the audit team.
t
! The remainder of this section presents the audit team's observations and assessments of
! the PSNII V&V Program for the following four items: System Requirements Review,
! Design Verification Review, Validation Tests, and Field Verification Tests. The observations and assessments were obtained through an examination of the available documentation.
, 3.1 SYSTEM REQUIREMENTS REVIEW i
Section 18.2 of NUREG-0800 recommends that the SPDS development process include a
- review of desired system capabilities to determine that the functional needs will be j satisfied. De principal goal of this activity is to independently determine if the requirements will result in a possible and usable solution to the entire problem. The requirements are reviewed for correctness, completeness, consistency, understandability,
} feasibility, testability, and traceability. The requirements review also provides the basis
]
for developing the system validation test plan.
4 3.1.1 Audit Team Observations 4
Since the Main Plant Computer design was completed before the development of requirements for a Safety Parameter Display System, PSNII could not conduct a formal review of planned MPC/SPDS capabilities against functional needs.
JYB:860603:8/1/86 j i
^
- Seabrook SSER 6 3 Appendix R
- . - - ~ - -, ,-.,-,,-n, ,,--,n - - , - - - -
i I
i An informal requirements review of the SPDS display contents and format was conducted during the development of SPDS software. 'Ihis review, however, did not include other attributes such as the requirements for data validation, continuous display, or us'er j interface. Section 4 of this report discusses a number of deficiencies noted by the audit j team. These deficiencies indicate that the SPDS development would have benefited from a thorough system requirements review to insure the system completely fulfilled the requirements of NUREG-0737, Supplement 1.
i j PSNH has implemented procedures to require a requirements versus planned capability design review for future modifications to the Main Plant Computer including the SPDS software.
4
- 3.1.2 Audit Team Assessment i Public Service of New Hampshire did not implement the recommendation of Sec.18.2 to l
NUREG-0800 to perform a verification that planned system capabilities will accomplish the functional needs for an SPDS. Given the advanced state of the system design, the
- audit team believes there would be little benefit in conducting a review of this type at this time.
The existence of formal design review requirements for future software modifications should help PSNH avoid similar problems as a result of future' modifications.
3.2 DESIGN VERIFICATION REVIEW Section 18.2 of NUREG-0800 recommends that the SPDS development process include a design verification review performed after the system is initially designed to verify that 4 the design will satisfy functional needs. This activity is intended to verify the hardware
.and software design against the system requirements. This review covers both the hardware and software specifications as well as the design. The specifications and the i designs are reviewed to ensure that the system requirements decomposition into hardware and software is complete and that there are no ambiguities or deficiencies.
. 3.2.1 Audit Team Observations b
As with the system requirements review, NRC recommendations regarding review of l
system design against functional needs were not available to support the development of j the Main Plant Computer system and Radiation Data Management System. Therefore, i the review process suggested by See 18.2 of NUREG-0800 was not fully implemented by PSNil. 'Ihe SPDS sof tware development process did, however, incorporate a review of l
software routines against a set of functional requirements for each SPDS display. Thesc display functional requirements were developed by the system engineer in conjunction with plant operations. The specific scope and findings of these reviews were not l
documented except for ultimate approval of the routines by the reviewer.
l f Testing of the SPDS software routines has also been conducted to verify that test
- combinations of data input to the MPC data base produce the expected parameter value, l
dDd proper validity flag. At the time of the audit, plant SPDS software development had not yet proceeded to the point where validation testing of the CSF status determination logic could be conducted.
JYIh860603:8/1/86 Seabrook SSER 6 4 Appendix R
n 3.2.2 Audit Team Assessment PSNH did not fully implement the recommendations of Sec.18.2 of NUREG-0800 regarding review of the system design versus system functional requirements. Although
. Verification and Validation reviews are not a requirement of Supplement I to NUREG-0737, the design problems identified by the NRC audit indicate that the Seabrook SPDS design would benefit from a thorough design verification review. The audit team, therefore, recommends that the process for correcting the identified system
- design problems should include a formal, complete, independent, and documented system
' design verification review to ensure that any systems shortcomings will be acceptably resolved.
3.3 VALIDATION TESTS Section 18.2 of NUREG-0800 recommends the SPDS development process include validation tests performed after the system is assembled to confirm that the integrated system satisfies the functional needs when combined with the plant control room and plant operators who have received the normal plant specific training in the use of the SPDS. he foundation for this activity lies in the information derived from the requirements review, the design review, and the hardware, software, and system tests performed by the system supplier. De system validation tests follow the system integration tests performed by the supplier to demonstrate that the hardware and software function acceptably.
3.3.1 Audit Team Observations
%e Seabrook SPDS was operable in the Seabrook control room simulator .when the simulator was used to conduct validation testing of the Westinghouse Owners Group (WOG) Emergency Response Guidelines (ERG) and Functional Response Guidelines (FRG). This testing included response to plant upsets both with and without the use of the SPDS. PSNH stated that the SPDS reduced the time required to respond to upset conditions. At the time of the audit, however, no documentation or other information was available to provide the details of how this conclusion was reached. Furthermore, there was no indication that any other measures of SPDS effectiveness were considered or observed.
3.3.2 Audit Team Assessment Sufficient information was.not available at the audit to allow a conclusion that the overall system validation testing conducted as part of the WOG ERG validation program satisfies the intent of Sec.18.2 of NUREG-0800 in this regard. The fact that operators did not choose to access lower level SPDS screens during the drill witnessed by the audit team would seem to indicate a need for further system validation testing. PSNH should reevaluate the adequacy of the previous validation testing to insure that the usefulness of the Seabrook SPDS was thoroughly established, if PSNH concludes that the previous efforts represented an adequate test, the basis for this conclusion ~should be described to NRC. This basis should include:
o Identification of the specific simulated plant upsets for which the SPDS effectiveness was evaluated.
JYB:860603:8/1/86 Seabrook SSER 6 5 Appendix R
- o Discussion of the applicability of the testing to the Seabrook plant SPDS given the differences between the simulator system and the plant system (e.g., the simulator does not provide redundant inputs to the SPDS; therefore, input of combinations of invalid data could not be simulated.)
o Description of any differences between the philosophy and training for using the SPDS during the procedure validation process and the Seabrook specific training and philosophy, o Identification of the specific data gathered to evaluate SPDS effectiveness and the data collection techniques.
o Description of the method and criteria used to evaluate the data.
o Discussion of the results of the validation testing.
3.4 FIELD VERIFICATION TESTS-Section 18.2 of NUREG-0800 recommends the SPDS development process include field verification tests performed after the system is installed to verify that the validated system was installed properly. As a minimum, field verification will consist of verifying that each input signal is properly connected and that the signal range is consistent with
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the design. Stated differently, it must be verified that the information displayed is directly correlated with the sensor data being input. It is expected that an independent review of the installation tests may fulfill a portion of the field verification test plan.
3.4.1 Audit Team Observations As part of Main Plant Computer system acceptance testing PSNH confirmed that each MPC input point was properly connected by verifying that the current value of each instrument input was accurately stored by the MPC. 'Ihis process will be repeated as
. part of each Instrument loop calibration by verifying that each calibration input is accurately displayed by the MPC. 'Ihe final SPDS software has not yet been installed in the plant so verification testing of this SPDS is not complete.
3.4.2 Audit Team Assessment PSNH has not yet completed all verification testing and has not developed an overall test plan that identifies the verification testing yet to be done. However, during the audit PSNH did exhibit an understanding of the purpose of field verification testing; therefore, if PSNH follows through on the validation testing process in a manner that is consistent with the testing to 'date, they are expected to satisfy the intent of See 18.2 to NUREG-0800 in this regard. The audit team suggests that this verification testing include an end-to-end system test of all portions of the MPC, RDMS, and ICCM that perform SPDS functions.
Once SPDS field verification testing is complete, PSNH should provide NRC with a description of the system attributes tested, the test methodology, and test results so that a final conclusion regarding the acceptability of the testing can be reached.
JYB:860603:8/l/86 Seabrook SSER 6 6 Appendix R
J
- 4. ASSESSMENT OF SPDS DESIGN
- De NRC audit team assessed the SPDS system with respect to the requirements of-Supplement I to NUREG-0737 using . the specific review criteria suggested by
- NUREG-0800, Sec.18.2, Appendix A. Dis portion of the audit addressed the points of a Design Validation Audit. De following provides a discussion of the Seabrook Station i SPDS design features relative to the provisions of Supplement I to NUREG-0737, and the
- ' corresponding audit team assessment in each area.
4.1 "THE SPDS SHOULD PROVIDE A CONCISE DISPLAY ..."
! 4.1.1 Audit Team Observations he Seabrook SPDS provides an overview of the status of all seven Critical Safety Functions. This overview display consists of a seven section horizontal bar. Each section corresponds to a CSF and is displayed in one of four colors that indicates the current degree of challenge to the safety function. De color coding scheme is:
Red - CSF under extreme challenge.
Orange - CSF under severe challenge.
Yellow - CSF off normal.
Green - CSF satisfied.
l I Each color is displayed in a different section of the CSF bar so that position coding of i
CSF status is available in addition to color coding. A condensed version of the overview display is incorporated into each of the other SPDS displays. His version presents only the color code to indicate CSF status.
Lower level displays provide the specific information used by the SPDS in determining i the status of each Critical Safety Function. With the exception of the Radiological Control CSF, this information is displayed in logic tree format. The current parameter
- value used at each decision point is displayed near the decision block that describes the
- logical decision made by the SPDS. Each logic path is color coded to show the degree of
- CSF challenge represented by that path. The terminus point flashes on the logic path i
that corresponds to the current status of the Critical Safety Function.
. Not all of the information needed to assess the Containment CSF is included on the CRT
- displays. De status of Containment Isolation is provided on a hardwired status light 1
display across the control room from the primary SPDS display. Most, but not all, status
) lights are illuminated by containment isolation and the lights are not arranged or labeled i such that an operator at the primary SPDS CRT can readily determine whether an unlit j status light corresponds to a failed containment isolation valve or to an unused light.
The Radioactivity Control CSF display consists of five horizontalintensity bars. Four of the bars are for steam generator radiation levels and one for radiation level at the containment vent. Each bar is titled on the display under the bar. The readout also shows the range of the detector channel that it displays. As the level of the channel goes JYB:860603:8/1/86 ,.
il 1
Seabrook SSER 6 7 Appendix R I
l
up, the bar fills in--progressing from left to right. When the channel is in alarm, as determined by the RDMS setting, the bar color turns red. It is cyan for normal values.
'Ihe alarm condition will be carried through to the overview display.
4.1.2 Audit Team Assessment With the exception of the' difficult to interpret containment isolation status display, the Seabrook SPDS meets the requirements of. Supplement I to NUREG-0737 regarding concise display of critical safety function status. 'Ihe Seabrook SPDS will totally satisfy this requirement if the containment isolation status display is modified such that an operator at the primary SPDS console can readily determine if all required containment isolation valves have closed. Two possible modifications that would accomplish this purpose would be to light the spare indicators on a containment isolation signal or to rearrange the indicators such that the ones that should be lit on containment isolation form an easily recognized pattern. PSNH should describe to NRC how the containment isolation status display will be corrected.
4.2 "THE SPDS SHOULD ... DISPLAY ... CRITICAL PLANT VARIABLES" 4.2.1 Audit Team Observations
'Ihe following plant parameters are inputs to the Seabrook SPDS Reactivity Control Critical Safety Function o Intermediate range reactor power; source range through 200 percent.
o Start-up rate.
Core Cooling Critical Safety Function o Core exit temperatures.
o Reactor coolant pump status, o Reactor vessel level indication.
o Wide range reactor cooling system (RCS) pressure (used with core exit temperature to calculate the displayed variable subcooling).
Heat Sink Critical Safety Function o Steam generator wide and narrow range water level.
o Emergency feed water flow.
o Steam generator pressure.
o Containment pressure (used in determining decision criteria for steam generator water level).
JYB:860603:8/1/86 8 Appendix R Seabrook SSER 6
Reactor Cooling System Integrity Critical Safety Function o RCS cold leg wide-range temperatures.
o RCS wide-range pressure.
Containment Critical Safety Function o Containment pressure.
o Containment recirculation sump level.
o Conteinment radiation level.
o Containment isolation valve status.
Reactor Coolant System Inventory Critical Safety Function o Pressurizer level.
PSNil has also committed to establish a Radiological Control CSF screen on the SPDS. It will provide steam generator radiation level and stack monitor radiation level.
The parameters selected for display and the groupings of parameters into CSFs are based upon the Critical Safety Functions monitored by the Westinghouse upgraded Emergency Operating Procedures. Two exceptions are containment isolation valve status indication and the Radiological Control CSF which are being added to the SPDS to resolve minor differences in philosophy behind the safety functions evaluated by EOPs and the CSF parameter selection for the SPDS.
The CSFs displayed by the Seabrook SPDS correspond in the following manner to the five safety functions identified by Supplement I to NUREG-0737 JYB:860603:8/1/86 Seabrook SSER 6 9 Appendix R
NUREG-0737, S1 Seabrook SPDS CSF CSF Reactivity Suberiticality Reactor core cooling and Core cooling (Except that the Seabrook heat removal from the IIcat sink SPDS has no parameter inputs primary system, which can be used to monitor the status of heat removal when post accident cool down has progressed to the point where cool down via steam generators is no longer desir-able.)
RCS integrity Integrity Inventory Radiation control Radiation control Containment Containment (Except that the challenge to the containment safety fune-tion posed by high hydrogen concentration is not monitor-ed by the SPDS.)
4.2.2 Audit Team Assessment With two exceptions, the parameters displayed by the Seabrook SPDS are sufficient to provide operators with information regarding the status of the five safety functions identified by Supplement I to NUREG-0737. We two exceptions are:
, o %e Seabrook SPDS has no inputs that allow the evaluation of the status of heat removal from the primary system after the post accident cool down has progressed to the point where the Residual lleat Removal (RIIR) system provides the primary heat removal path. RilR flow is one parameter that would provide the needed information.
o %e Seabrook SPDS does not account for high hydrogen concentration in containment as a challenge to containment integrity.
PSNil should submit a discussion to NRC of how these two items will be addressed by the SPDS. This discussion should also confirm PSNil's commitment to include containment isolation status and Radiological Control CSF in the SPDS and should document the content, format, data validation methodology, and CSF evaluation logic used in the Radiological Control CSF display.
i JYB:860603:8/1/86 10 Appendix R Seabrook SSER 6
4.3 "THE SPDS SHOULD ... AID THEM (OPERATORS) IN RAPIDLY AND' RELIABLY DETERMINING THE SAFETY STATUS OF THE PLANT" 4.3.1 Audit Team Obse:vations
, Most parameter values displayed by the SPDS and SPDS logic trees are updated every five seconds. De update rate is controlled by the MPC program scheduler in which SPDS programs are assigned a higher priority than most other MPC routines; therefore, the update interval should remain relatively independent of MPC workload. Two exceptions to the five-second update rate are the calculation of core heat-up and cool-down rate for the RCS integrity status tree and the information on the Radioactivity Control CSF.
display. De heat-up rate calculation is updated every thirty seconds. More frequent recalculation of this value is unnecessary because the status tree decision criterion is based upon change in temperature over the last sixty minutes rather than upon the instantaneous value of the heat-up or cool-down rate. He RDMS remote processors acquire data continuously and are polled every 30 seconds on' the bus by the RM-ll host.
' One line connects each of the RM-11 hosts to the plant computer. Every 30 seconds, the plant computer can request the current radiological data. In this manner, the screen data can be updated every 30 seconds for the current radiological conditions.
%e SPDS parameters input via the Intelligent Remote Terminal Units receive a gross validity check as part of the process for inserting instrument readings into the MPC data base. His gross check includes:
o Verification that the IRTU is scanning the instrument loop in question.
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o Operability verification of the communications link between the input processor and the host computer.
o IRTU operability verification, o Verification that the input parameter value is within the capability of the associated instrument loop.
o Verification that the parameter value is within a reasonable range as defined by PSNH engineering and operations.
%ese checks form the basis of an instrument validity status word that is associated with the reading in the MPC data base.
For Radioactivity Control CSF information, the RDMS performs data and operability checks at remote processors located with the radiation detector. The remote processor monitors data quality and operability status and encodes this information, along with the current radiation data, on the data bus to the RDMS host computers. The data are flagged questionable if t o Dere are inconsistent values more than 50 percent of the time (drop out in link).
o here is any operate failure.
JYB:860603:8/1/86 Seabrook SSER 6 11 Appendix R
o De integrated calculations are not accurate enough (95 percent confidence of value'within 6 percent of mean).
o Dere is less than 85 percent response to the automatic check source.
o An operate failure is reported for a loss of counts.
o' Sample flow is lost.
o A channel is out of service.
o A check source test failed.
o A filter is torn or clogged.
De data quality and operability status is passed up the bus to the RDMS display where the det9 display is color coded to indicate data validity. Els validity data will be transfe red, along with current radiation data, to the main plant computer and subseqmntly to the SPDS display system.
In cases where redundant measurements of plant parameters are input to the MPC, the SPDS synthesizes a single value of the parameter by either averaging all valid inputs or by selecting the highest or lowest reading from among the valid inputs. De use of high, low, or average was selected in each case to insure a conservative interpretation of the CSF status trees. If no valid inputs are available for a given parameter, the parameter value will be displayed with a question mark. If a lack of valid information prevents the evaluation of a tree under current plant conditions the affected status tree will not be evaluated, the status tree will not display an active evaluation path, and the overview display will display the status of the affected tree as black for unable to evaluate.
%e Seabrook SPDS does not currently make use of interchannel comparison of redundant instrumentation in the data validation scheme.
The audit team noted that two status trees appear to provide incorrect status information during power operation. De suberiticality status is indicated red (under-extreme challenge) whenever reactor power exceeds 5 percent. Since no plant mode information is used by this SPDS logic tree, the CSF will be continuously indicated to be under extreme challenge during normal power operation. A similar problem exists with the indication of core cooling CSF status because the RCS subcooling criteria used by the status tree may not always be met during power operation. Bis will cause the status of core cooling to be erroneously indicated as orange, under severe challenge.
Indication of SPDS and MPC operability is provided by a real-time clock located in the upper left-hand corner of the display. When the SPDS and MPC are operating, the clock updates every second; if the computer goes down, the clock reading will no longer increment.
PSNil has conducted a reliability analysis of the Main Plant Computer system which includes most SPDS functions. This analysis estimated system availability will exceed 0.99. %is analysis assumed component mean-time-to-repair would be on the order of 1/2 JYB:860603:8/1/86 Seabrook SSER 6 12 Appendix R
to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. During the audit, PSNH stated that this assumption is supported by their plans to maintain a complete set of MPC spare parts on site and to have qualified maintenance staff available on all shifts. PSNH has also been keeping system availability data since December 1985 The availability records show that MPC availability has significantly exceeded 0.99 over this period. Neither the availability analysis, nor the availability records address the effect upon SPDS availability of data processing systems, other than the MPC, that provide input data to the SPDS (i.e., Inadequate Core Cooling 4
Monitor and Radiological Data Monitoring System).
Data on the availability of.the Radiation Data Management System was not available at the time of the audit. De similarity of design to the Main Plant Computer system, with dual processors and dual or ring data busses, would lead one to expect high availability of the RDMS. It is not known how the numeric reliability of the data components of the RDMS compare with the comparable components of the MPC. The components of both systems are proven products of established manufacturers. The RDMS was originally designed to be a stand-alone plant radiation monitoring system required to supply data on critical plant levels during demanding plant conditions.
4.3.2 Audit Team Assessment The Seabrook SPDS does not completely satisfy the provisions of Sapplement I to NUREG-0737 regarding rapid and reliable display because the data validation techniques used are insufficient to provide a highly reliable synthesized value of SPDS parameters and because the SPDS displays incorrectly indicates that the reactivity control and core cooling CSFs are under challenge during normal power operation. The use of high or low values provided by redundant instrumentation may result in a conservative estimation of the status of Critical Safety Functions but it also ensures that the operator will be misled about safety function status in the event of large instrument errors or on-scale instrument failures. Use of average values without additional validation checks does not guarantee the operator will be consistently misled in the conservative direction. PSNH must implement data validation methodology that makes more effective use of redundant information available via the MPC. PSNH could also improve the usefulness of the existing validity screening of input data by tightening the reasonableness band applied to some parameters. For example, at the time of the audit, PSNH was using 0*F as the lower limit for reasonableness check of temperature inputs and 200 percent as the upper limit for the reasonableness check of reactor power. The audit team believes more meaningful bounds could be established in both cases,
%c precision to which plant variables are indicated on the SPDS displays and the update rates for the SPDS data base and displays are acceptable. PSNH system verification testing should confirm that the SPDS update rate is not seriously affected when a large number of nearly simultaneous processing demands are made on the MPC as may occur during the response to a severe accident.
The MPC system availability has been demonstrated to be sufficient to support the high SPDS availability goal set by Supplement I to NUREG-0737. PSNH has not, however, demonstrated high availability for the SPDS as a whole, since neither the availability analysis nor the availability history address the effect of the RDMS or the ICCM reliability upon overall SPDS availability. PSNH should include these items in their procedures for monitoring of SPDS availability.
JYD:860603:8/l/86 Seabrook SSER 6 13 Appendix R
. - _ ~ -
i PSNH should provide a discussion for NRC review of the actions planned to improve the data validation methodology and an assessment, based either on calculation or operating experience data, of the overall availability of the SPDS including the Inadequate Core Cooling Monitor and the Radiological Data Monitoring System inputs.
4.4 "THE PRINCIPLE PURPOSE AND FUNCTION OF THE SPDS IS TO AID THE CONTROL ROOM PERSONNEL DURING ABNORMAL AND EMERGENCY CONDITIONS IN DETERMINING THE SAFETY STATUS OF THE PLANT AND IN ASSESSING
, WHETHER ABNORMAL CONDITIONS WARRANT' CORRECTIVE ACTIONS BY
, CONTROL ROOM OPERATORS TO AVOID A DEGRADED CORE." <
4.4.1 Audit Team Observations l
%e Seabrook SPDS displays the current value of input SPDS variables and provides the l~ operator with a visual indication of the status of each Critical Safety Function. This status takes the form of an overview display that shows the status of all CSFs. A-3 detailed display for each CSF is 'also available. The detailed display shows the CSF status, the value of each variable used to determine CSF status, the logic to determine l
i CSF status, and references the procedure to be used to return the CSF to a normal condition.
{ !
De variables displayed, logic, logic set points, and logic display formats are based upon I l
I the Critical Safety Function evaluation process contained in the Seabrook Emergency i
Operating Procedures which were based upon the Emergency and Functional Response Guidelines developed for the Westinghouse Owners Group. Derefore, the basis for the i
i existing CSF displays is directly traceable to the System Funct'on and Task Analysis
! conducted during the development of the WOG guidelines, i De Seabrook Main Plant Computer is capable of displaying historical trends for any f
variable input to the MPC including all SPDS variables. However, since PSNH does not l consider the trending capability to be an SPDS feature, no prearranged trend displays have been established to simplify access to historical trend information. Since the j trending capability was not considered as part of the SPDS function, the audit team did not review the capabilities of the trending function.
lf The audit team observed a simulator drill conducted by PSNH to demonstrate the use of f the SPDS under plant upset conditions. The audit team noted that during the entire course of the drill, Critical Safety Function status was monitored by the Shif t Technical l
Advisor using hardwired instrumentation and hard copies of the CSF status trees. At no l time during the drill did any operator select for displLy an SPDS CSF status tree.
i i
4.4.2 Audit Team Assessment Although the Seabrook SPDS appears to display the information required to evaluate CSF
' status in an easily understood manner that should aid the operators In the determination j of plant safety status, the fact that no use was made of the logic tree displays during the drill indicates that the operators do not find the system to be a satisfactory aid.
herefore, the audit team cannot conclude that the Seabrook SPDS provides the required PSNH should investigate the basis of operator aid in the determination of safety status.
the operator's reluctance to use the lower level SPDS displays and report to NRC the l system changes made to make it useful from the operator's point of view.
JYB 860603:8/l/86 14 Appendix R Seabrook SSER 6
4.5 "(THE) SPDS (SHALL BE) LOCATED CONVENIENT TO TIIE CONTROL ROOM OPERATORS" 4.5.1 Audit Team Observa!*: ns ne SPDS displays can be accessed at any one of four locations in the control room. l o On any of four CRTs located near the center of the main control board, between primary system and secondary system controls and displays.
o On a CRT located among Service Water and Emergency Safety Feature controls and displays on the left side of the main control board.
o On a CRT located among the Component Cooling Water controls and displays on the right side of the main control board.
i o On a CRTlocated at the Shift Technical Advisor's desk.
The shift technical advisor has been designated as the primary user of the SPDS under upset conditions.
4.5.2 Audit Team Assessment PSNil has clearly satisfied the requirement of Supplement I to NUREG-0737 that the SPDS be located convenient to operators.
4.6 "Ti!E SPDS SilALL CONTINUOUSLY DISPLAY INFORMATION FROM WlilCil TIIE SAFETY STATUS OF Tile PLANT ... C AN BE ASSESSED ..."
4.6.1 Audit Team Observations ne Seabrook SPDS provides a summary overview display of the status of each Critical
- Safety Function. Els overview display consists of a full screen display of a seven segment bar, each segment of which corresponds to one CSF. Each bar segment contalrts a color and position code to represent the current status of the corresponding safety j function. When an Individual CSF status tree is selected for display, a reduced version of the overview is displayed in the lower left portion of the status tree display. Safety function status information is not incorporated into any of the MPC displays that are not designated as SPDS displays. Furthermore, PSNil has not implemented procedures to insure the SPDS is always displayed on at least one control room CRT.
4.6.2 Audit Team Assessment Under the current Seabrook procedures, all control room displays could be selected such that no SPDS display is provided in the control room. Derefore, PSNil has not satisfied the requirement of Supplement I to NUREG-0737 to continuously display safety status information. Two possible ways to resolve this deficiency would be to include the CSF status bar on all MPC displays, or to implement administrative procedures that require an SPDS display to be on at least'one control room CRT whenever the plant is above mW 5. PSNII should report to NRC on the ultimate resolution to this item.
JYB:860603:8/1/86 Seabrook SSER 6 15 Appendix R
4.7 "TH E SPDS SHALL BE SUITABLY ISOLATED FROM ELECTRICAL OR ELECTRONIC INTERFERENCE WITH EQUIPMENT AND SENSORS THAT ARE IN USE FOR SAFETY SYSTEMS" 4.7.1 Audit Team Obse vations PSNH uses three different models of isolators to electrically isolate the SPDS from safety related inputs. Type test data for two of these models has already been submitted to and reviewed by NRC. Type testing of the remaining model and the results will be submitted in the near future.
4.7.2 Audit Team Assessment We adequacy of electrical isolation devices used by the SPDS is being separately reviewed by NRC.
4.8 " PROCEDURES WHICH . DESCRIBE THE TIMELY AND CORRECT SAFETY STATUS ASSESSMENT WHEN THE SPDS IS AND IS NOT AVAILABLE WILL BE DEVELOPED BY THE LICENSEE IN PARALLEL WITH THE SPDS. FURTHERMORE, OPERATORS SHOULD BE TRAINED TO RESPOND TO ACCIDENT CONDITIONS BOTH WITH AND WITHOUT THE SPDS AVAILABLE."
~ 4.8.1 Audit Team Observations Operator training in the use of the SPDS is incorporated into training on the use of plant Emergency Operating Procedures. %is training is required for operator licensing and requalification. De Seabrook SPDS basically provides an automated means to continuously evaluate the Critical Safety Function Status Trees contained in the plant Emergency Operating Procedures. If the SPDS is unavailable, the operators will perform the same status tree evaluation manually using paper copies of the status trees and hardwired plant instrumentation located on the main control boards.
4.8.2 Audit Team Assessment PSNil has satisfied the requirements of Supplement 1 to NUREG-0737 in this regard.
4.9 "THE SPDS DISPLAY SHALL BE DESIGNED TO INCORPORATE ACCEPTED HUM AN FACTORS PRINCIPLES SO THAT THE DISPLAYED INFORMATION CAN BE READILY PERCEIVED AND COMPREHENDED BY SPDS USERS."
4.9.1 Audit Team Observations De basic format of the Critical Safety Function Status Trees was developed by Westinghouse using their human factors design criteria and input from utility representatives participating in the Westinghouse Owners Group. Except for use of control room color coding and nomenclature conventions, PSNH did not establish formal human factors criteria for use in the development of the Main Plant Computer or implementation of the SPDS on the MPC. However, a complete human factors review of the SPDS displays and operator interfaces was incorporated into Seabrook's Detailed Control Room Design Review and no human engineering discrepancies were noted.
JYB:860603:8/1/86 16 Appendix R Seabrook SSER 6
During the audit the audit team operated the SPDS to access and observe all displays.
De following human engineering discrepancies were noted:
o he Containment Isolation Status indication is not arranged such that an operator at the primary SPDS user's (STA) station can readily determine if all automatic containment isolation valves have closed.
o Access from the overview display to the first two CSF status trees is relatively awkward. De operator must traverse the cursor across a large
. portion of the CRT screen to address the desired tree then simultaneously push two keyboard buttons to display the tree. Access to subsequent displays is easier because after the second status tree is selected, the cursor remains in the area of the screen used to address status trees.
o On one tree, a parameter value is displayed in a location that is inconsistent with the standard format.
o Although the CSF status trees provide both a color and pattern coding of the CSF status, the overview display on the status trees only provides color coding.
4.9.2 Audit Team Assessment Seabrook's SPDS will satisfy the NUREG-0737, Supplement I requirement to incorporate human factors principles provided the above noted problem with the layout of the Containment Isolation Status display is corrected. De remaining human engineering deficiencies noted during the audit are not severe problems. Nevertheless, PSNII is encouraged to correct these discrepancies. PSNH should describe to NRC the corrective action taken in this area.
De noted difficulty in accessing the lower level SPDS displays should be evaluated as a potential source of the operators' reluctance to use the status tree displays.
S. SUMM ARY We Seabrook Station Safety Parameter Display System only partially fulfills the SPDS requirements of Supplement I to NUREG-0737. The system deficiencies that lead to this conclusion are:
o %e status of containment isolation valves is not displayed concisely so that an operator at the primary SPDS terminal can readily determine if containment isolation has been satisfactorily completed.
o %e SPDS does not allow assessment of heat sink status during post accident cool down after the steam generators are no longer the desired heat sink for the primary system.
o %e SPDS does not provide indication if hydrogen concentration in containment poses a challenge to the Containment Critical Safety Function.
JYD:860603:8/1/86 Seabrook SSER 6 17 Appendix R
o Indication of the status of the Radiological Control Critical Safety Function has not yet been implemented.
o %e data validation algorithms used do not take advantage of redundant information to provide the operator and SPDS logic with highly reliable values of SPDS parameters.
o During normal power operation, the SPDS provides an erroneous status indication for the suberiticality and core cooling CSFs.
o PSNH has not demonstrated that SPDS update and response times will not be unacceptably affected by the high Main Plant Computer loading conditions expected to occur during response to a severe plant upset.
o %e simulated response to a plant accident witnessed by the audit team indicated that the Seabrook operators do not find the Critical Safety Function Status Trees to be a significant aid, e Information from which the safety status of the plant can be assessed is not continuously displayed by the SPDS.
In addition to the above problems, the audit team noted a few items which would not by themselves inhibit acceptance of the SPDS. Nevertheless, PSNH should consider these items for correction.
o De limits selected for use in checking data reasonableness are in some cases well outside of the reasonable range of the variable, o %e first two Critical Safety Function Status Trees called up after display of the CSF overview are somewhat awkward to address, o On one status tree, one parameter is displayed in a location that is inconsistent with the convention used for all other parameter values.
o De Critical Safety Function overview provided on status tree displays does not incorporate redundant coding of safety function status as a backup to color coding.
PSNH should report to NRC on the actions taken to correct the problems listed above.
Although Verification and Validation of the SPDS design and implementation is not a regulatory requirement, the SPDS development process at Seabrook would have benefited significantly from a formal, rigorous V&V program. It is recommended that PSNH's process for correcting the NRC audit team's findings include a formal, complete, independent, and documented verification of SPDS capabilities against the requirements of Supplement I to NUREG-0737. %is will ensure that adequate corrective actions are implemented. The methodology and results of this review should be made available for NRC review.
-l8-JYB:860603:8/1/86 18 Appendix R Seabrook SSER 6
Although SPDS validation testing was incorporated into the verification and validation
'3 process for the Westinghouse Owners Group Emergency Response and Functional Response Guidelines, insufficient information was available during the audit to allow assessment of the suitability of this testing. De fact that the Seabrook operators did
> not choose to access any Critical Safety Function Status Trees during the simulator drill i witnessed by the audit team implies the existence of difficulties with the use of the system that were not detected by the original validation testing. It is recommended that PSNil review the adequacy of the original validation testing. PSNII should provide the details of this testing or any additional validation testing for NRC review. Specific information that should be included is discussed in Sec. 3.3.2 of this report.
Subsystem and field installation verification testing of the Seabrook SPDS has not been completed and PSNII has not documented the plans for the completion of this testing.
Therefore, a final conclusion regarding the suitability of this testing could not be reached. Testing conducted to date, however, indicates that PSNII understands the need for, and purpose of, verification testing. Consequently, if subsystem and field installation verification testing proceeds in a manner that is consistent with the testing to date, PSNII will comply with the intent of See.18.2 of NUREG-0800 and NSAC/39 in i this regard. The audit team recommends that a sensor-to-display test of all SPDS inputs be included in the field verification test program. PSNII should provide NRC with a discussion of the remaining system and field installation verification activities.
I JYB:860603:8/1/86 .
Seabrook SSER 6 19 Appendix R
._.,-,,.n - - . - - _ , . , _ - _._ ,--.- - - __-. . _ ,, _ - -. .._.___-.,__._,.---___.-..__....__n. ..
- 6. REFERENCES
, 6.1 GENERAL REFERENCES
- 1. U.S. Nuclear Regulatory Commission, NUREG-0737, " Clarification of TM1 Action Plan Requirements," November 1980, Supplement 1, December 1982.
- 2. U.S. Nuclear Regulatory Commission, NUREG-0800, " Standard Review Plan for Review of Safety Analysis Reports for Nuclear Power Plants," Sec.18.1, Control Room, Rev. O, September 1984 and Sec.18.2, Human Factors Review Guidelines for the Safety Parameter Display System (SPDS), Rev. O, November 1984.
- 3. Verification and Validation for Safety Parameter Display Systems, NSAC/39, Science Applications, Inc., December 1981.
- 4. U.S. Nuclear Regulatory Commission, NUREG-0700, " Guidelines for Control Room Design Reviews," September 1981.
- 5. U.S. Nuclear Regulatory Commission, Draft NUREG-0835, Human Factors Acceptance Criteria for the Safety Parameter Display System."
l 6. U.S. Nuclear Regulatory Commission, NUREG-0696, " Functional Criteria for Emergency Response Facilities," February 1981.
- 7. Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess Plant and
' Environs During and Following an Accident, Regulatory Guide 1.97, Rev.2, Nuclear Regulatory Commission, 0lfice of Standards Development, December 1980.
6.2 DOCUMENTATION EXAMINED DURING THE AUDIT
- 8. PX09-7, Rev.1, " Main Plant Computer System Hardware Configuration Manual,"
January 24,1986.
- 9. PX09-1, Rev.O, " Main Plant Computer System Functional Description,"
April'12,1984.
- 10. DWG M-510004, Rev. 48, " Computer input-Output Parts List," May 9,1986.
- 11. GT-I-42, Rev.11, " General Test Procedure, Station Computer," October 31,1984.
- 12. GT-1-07, Rev.I1, " General Test Procedure Indicating / Control Loops,"
December 19,1984.
t 13. GT-1-101, Rev. O, " Main Plant Computer System," May 12,1983.
j
- 14. " Computer Program Test, Inventory Critical Safety Function Status Tree," Rev. O, May 19,1986.
JYB:860603:8/1/86 I l Seabrook SSER 6 20 Appendix R l l
I
4
- 15. "SPDS Inventory Critical Safety Function Status Tree Subroutine," Rev.O, May 20,1986.
- 16. " Inventory Critical Safety Function Status Tree Program Description,"
Rev. O, May 19,1986.
- 17. "SPDS Functional Requirements for Seabrook Unit 1 Main Plant Computer Software Development, Inventory Status," no revision or date.
- 18. " Background Information for Westinghouse Owners Group Emergency' Response Guidelines; Critical Safety Function Status Tree FPO.6; Inventory," HP/LP-Rev.1, September 1,1983.
- 19. Main Plant Computer Program Subroutine,(Engineering Units Conversion).
- 20. Main Plant Computer Program Subroutine, (data checks against reasonableness limits).
- 21. "New Ilampshire Yankee Nuclear Production Computer Control Program Manual,"
Rev. O, December 24,1985,
- 22. Test procedure, "SPDS Graphics Test."
- 23. Scabrook Station General Test Procedure, TPI-62-F01, Rev.2, " Radiation Monitoring System and Adjacent-to-Line Radiation Monitors."
- 24. " Gulf General Atomic Model RM-80, E-Il5-870 Microprocessor Software Design Document."
- 26. "Seabrook Station Emergency Response Facility Functional Description."
l t
i JYB:860603:8/1/86 Seabrook SSER 6 21 Appendix R
\
l APPENDIX S SAFETY EVALUATION REPORT:
l PUMP AND VALVE INSERVICE ~ TESTING PROGRAM SEABROOK STATION, UNIT 1 l
l i
i l
i Seabrook SSER 6 Appendix S
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l l
SAFETY EVALUATION REPORT PUMP AND VALVE INSERVICE TESTING PROGRAM SEABROOK STATION UNIT 1 l
l C, 8. Ransom i H. C. Rockhold l
Published August 1986 l
EG&G Idaho, Inc.
Prepared for the U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Under 00E Contract No. 00E-AC07-761001570 l FIN No. A6811 l
t Seabrook SSER 6 l Appendix S
ABSTRACT This EG&G Idaho, Inc., report presents the results of our evaluation of the Seabrook Station Unit 1 Inservice Testing Program for pumps and valves whose function is safety related.
i i
i ij Appendix S Seabrook SSER 6
.t FOREWORD This report is supplied as part of the " Review of Pump and Valve Inservice Testing Programs for Operating License Plants being conducted for the U.S. Nuclear Regulatory Comission, Office of Nec; ear Reactor Regulation, Division of Engineering, by EG&G Idaho., Inc., NRR and I&E Support.
f The U.S. Nuclear Regulatory Comi',sion funded the work under the l- authorization 8&R 20-19-40-41-2, FIN No. A6811.
1 i
l J
f i
I Docket No. 50-443 Seabrook SSER 6 til Appendix S
CONTENTS 1
- 1. INTRODUCTION .....................................................
3 J. PUMP TESTING PROGRAM .............................................
3 2.1 All Pumps in the IST Program ...............................
3 2.1.1 Pump Bearing Temperature Measurements .............. 4 2.1.2 Pump Flow Instrumentation Accuracies ...............
7
- 3. VALVE TESTING PROGRAM ............................................
7 3.1 General Considerations .....................................
3.1.1 Full-Stroke Exercising of Check Valves ............. 7 3.1.2 Valves Identified for Cold Shutdown Exercising ..... 7 3.1.3 Conditions for Valve Testing During 8
Cold Shutdown ......................................
3.1.4 Category A 9alve Leak Test Requirements for 9
Containment Isolation Valves .......................
3.1.5 Application of Appendix J Testing to the 9 IST Program ........................................
9 3.1.6 Safety Related Valves ..............................
10 3.1.7 Active,' Valves ......................................
10 3.1.8 Rapid-Acting' Power Operated Valves .................
3.1.9 Valves Which Perform a Pressure Boundary 10 Isolation function ................................. 11 3.1.10 Pressurizer Power Operated Relief Valves ...........
13 3.2 General Relief Request .....................................
3.2.1 Solenoid Operated Valve Position Indicator 13 Verification .......................................
14 3.2.2 Rapid Acting Power Operated Va1ves'.................
3.2.3 Stroke Time Corrective Action for Power 15 Operated Valves ....................................
17 3.3 Emergency Feedwater System .................................
3.3.1 Category C Valves ...............'................... 17 l
1 18 3.4 Diesel Generator Air-Start System ..........................
18 3.4.1 Category B Valves ..................................
20 3.5 Diesel Generator Cooling Water System ......................
20 3.5.1 Category B Valves ..................................
iv Appendix S Seabrook SSER 6 I
1
3.6 Residual Heat Removal System ............................... 21 3.6.1 Category C Valves .................................. 21 3.7 Safety Injection System Accumulators ....................... 22 ,
3.7.1 Category A/C Valves ................................ 22 3.8 High Head Safety Injection System .......................... 26 3.8.1 Category A/C Valves ................................ 26 .
3.8.2- Category C Valves .................................. 29 3.9 Chemical and Volume Control System ......................... 32 3.9.1 Category A Valves .................................. 32 3.9.2 Category C Valves .................................. 33 3.10 Containment Spray System ................................... 35 3.10.1 Category C Valves .................................. 35 APPENDIX A--CODE REQUIREMENTS ......................................... 41
- 1. CODE REQUIREMENTS - VALVES ....,............................ 43
- 2. CODE REQUIREMENTS - PUMPS .................................. 43 APPENDIX B--VALVES TESTED DURING COLD SHUTDOWNS ....................... 45 APPENDIX C--P&ID LIST ................................................. 51 APPENDIX D--VALVES TESTED DURING COLD SHUTDOWNS - DETAILS ............. 55 j Seabrook SSER 6 v Appendix S
SAFETY EVALUATION REPORT !
PUMP AND VALVE INSERVICE TESTING PROGRAM SEABROOK STATION UNIT 1
- 1. INTRODUCTION Contained herein is a safety evaluation of the pump and valve inservice testing (IST) program submitted by Public Service of New Hampshire for its Seabrook Station Unit 1.
The working session with Public Service of New Hampshire representatives was conducted on May 13 and 14, 1986. The utility's IST program, Revision 1 dated June 4, 1986 as amended by a letter from J. DeVincentis to V. S. Noonan dated June 18, 1986 and by letters from G. S. Thomas to V. S. Noonan dated June 23, 1986 and June 25, 1986, was reviewed to verify compliance of proposed tests of pumps and valves whose function is safety related with the requirements of the ASME Boiler and Pressure Vessel Code (the Code)Section XI, 1983 Edition through Summer 1983 Addenda. In their IST program, Public Service of New Hampshire has requested relief from the ASME Code testing requirements for specific pumps and valves and these requests have been evaluated individually to determine whether they have significant risk implications and whether the tests, as required, are indeed impractical. Any I.ST program revisions subsequent to those noted above are not addressed in this SER. Required program changes, such as additional relief requests or the deletion of any components from the IST Program, should be submitted to the NRC under separate cover in crder to receive prompt attention, but should not be implemented prior to review and approval by the NRC.
The conclusions in this SER of the Seabrook Station Unit 1 pump and valve inservice testing program and the associated relief requests are those of the NRC staff. These findings apply only to component testing (i.e., pumps and valves),~and are not intended to provide the basis to change the utility's current technical specifications system test requirements.
Seabrook SSER 6 1 Appendix 5
A summary of pump and valve Section XI testing requirements is provided in Appendix A.
Category A, B, and C valves that meet the requirements of the ASME Code,Section XI, and are not exercised quarterly are addressed in Appendix B.
A listing of P& ids and Figures used for this review is contained in Appendix C.
The details of valve cold shutdown testing justifications are included in Appendix D.
Seabrook SSER 6 2 Appendix S 1
L
Y
- 2. PUMP TESTING PROGRAM The Seat *or+ Station Unit 1 IST program submitted by Public Service of
- New Hampshire was examined to varify that all pumps whose function is
- . safety related are included in the program and are subjected to the
! periodic tests required by the ASM'E Code,Section XI. The staff's review found that these pumps are tested in accordance with Section XI except for those pumps identified below for which specific relief from testing has been requested. Each Public Service of New Hampshire basis for requesting relief from the pump testing requirements and the staff's evaluation of that request is summarized below.
2.1 All Pumps in the IST Proaram 2.1.1- Pump Bearina Temperature Measurements 2.1.1.1 Relief Reauest. The utility has requested relief ~from the Section XI requirement of measuring pump bearing temperatures for all pumps in the Seabrook IST progr.am and has proposed to expand pump vibration t
testing from one reading to multiple readings in two orthogonal directions.
4 2.1.1.'l .1 Code Requirement--Refer to Appendix A.
2.1.1.1.2 Licensee's Basis for Reauestina Relief--The referenced Edition of the Code requires bearing temperature to be recorded annually.
It has been demonstrated by experience that bearing temperature rise occurs only minutes prior to bearing failure. Therefore, the detection of possible bearing failure by a yearly temperature measurement is. extremely unlikely. .It requires at least an hour of pump operation to achieve stable bearing temperatures. The small probability of detecting bearing failure by temperature measurement does not justify the additional pump operating
, time required to obtain the measurements. As an alternate, the pump vibration testing will be expanded from one to multiple reading in two crtho' gonal directions.
1 l
i Seabrook SSER 6 3 Appendix S
l 2.1.1.1.3 Evaluation--The-staff agrees with the utility's basis and, therefore, relief should be granted from the pump bearing temperature i measurement requirements of Section XI for all pumps in the IST program.
The yearly temperature measurements do not provide a viable means of
~
monitoring pump. mechanical condition. There are several. factors, such as.
working fluid and ambient temperatures, that can affect the pump bearing temperature which would make detection.of pump degradation difficult. The rapid rise in bearing temperature that signals an imminent bearing failure occurs just a short time before failure and would not likely be detected by a yearly measurement. Pump mechanical condition can be determined much more accurately by' measuring bearing vibration. The utility will expand the required pump bearing vibration measurements to give a better indication of pump mechanical Condition and will take these measurements
! quarterly to allow the detection of pump degradation. ,
2.'l .1.1. 4 Conclusion--The staff concludes that the utility's proposal to expand the pump bearing vibration measurements to multiple
- measurements in two orthogonal directions should provide a good indication of pump mechanical conditions and allow detection of pump degradation. The
~
relief thus granted will not endanger life or property or the common j defe'se n and security of the public, i
2.1.2 Pump Flow Instrumentation Accuracies 2.1.2.1 Relief Reauest. The utility has requested relief from the Section XI_ requirement for acceptable instrument accuracy for the
[ instruments used for. testing pump flow in the Seabrook Station IST program. The instruments used at Seabrook are well within the specified limits, however, the loop accuracies are sometimes above the specified limits.
2.1.2.1.1 Code Reautrement--The instrument accuracies shall be within the following limits. Station instruments meeting these-l requirements shall be acceptable.
Seabrook SSER 6 4 Appendix 5
Acceptable Instrument Accuracy Pressure '12% of full scale Differential pressure 12% of full scale Flow rate 12% of full scale Speed 12% of full scale Temperature 15% of full scale Vibration amplitude 5% of full scale 2.1.2.1.2 Licensee's Basis for Recuestino Relief--New Hampshire Yankee uses flow measuring instrumentation which meets the acceptable instrumentation accuracies defined in Table IWP-4110-1. However, the total flow element loop accuracy was calculated from the flow device to the computer readout providing hard copy log data. The loop accuracies do not meet the~ instrumentation accuracies of Table IWP-4110-1, but the instruments are well within the table limits for flow rate (see the table below f or flow instrument accuracies).
Pump Flow Measurement-Instrument Accuracies Instrument System Accuracy Loop Accuracy Containment Spray-System 0.5% 2.2%
Component Cooling Water System 0.5% 3.29%
Diesel Generator fuel Oil Transfer System 0.5% 2.2%
Emergency Feedwater System 0.5%~ 2.0%
Service Water System 0.5% 2.5%
0.5% 3.6%
Safety Injection System 1.0% 2.2%
Residual Heat Removal System 2.0% 3.0%
Spent Fuel Pool Cooling System 1.0% 2.0%
Seabrook SSER 6 5 Appendix S
2.1.2.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the Section XI requirements for pump flow measurement instrument accuracies. The installed flow instruments are within the accuracy limits of Section XI, but the. final ~
data obtained from the computer readout, with 'the inaccuracies associated with the other loop elements computed, in several caset falls outside the Code limits. The data provided by the utility indicates that the loop accuracies do not significantly exceed the Code limits and should be sufficiently repeatable from test to test to allow for an evaluation of the pump hydraulic condition and for the detection of pump degradation.
2.1.2.1.4 Conclusion--The staff concludes that the instrumentation utilized by the utility to measure pump flow should provide data that-is sufficiently accurate to allow them to access pump condition and detect pump degradation. The relief thus granted will not endanger life or property or the common defense and security of the public.
i l
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1 6 Appendix S ,
l Seabrook SSER 6 1 l
l
i
- 3. VALVE TESTING PROGRAM The Seabrook Station Unit 1 IST Program submitted by the Public
, Service of New Hampshire was examined to verify that valves whose function is safety related are included in the program and are subjected to the periodic tests required by the ASME Code,Section XI, and the NRC positions and guidelines. The staff's review found that, except where specific relief from testing has been requested, these valves are tested to the Code requirements and the NRC positions and guidelines summarized in Appendix A and Section 3.1 of this report. Each Public Service of New Hampshire basis for requesting relief from the valve testing requirements and the staff's evaluation of that request is summarized below and grouped according to system and valve category.
3.1 General Considerations 3.1.1 Full-Stroke Exercising of Check Valves The NRC's position was stated to the utility that check valves whose safety function is_to open are expected to be full-stroke exercised. Since the disk position is not always observable, the NRC staff position is that verification of the maximum flow rate through the check valve. identified in any of the plant's safety analyses would be an adequate demonstration of-the full-stroke requirement. Any flow rate less than this will be considered a partial-stroke exercising unless it can be shown that the check valve's disk position at the lower flow rate would permit maximum required flow through the valve. The NRC staff position is that this reduced flow rate method of demonstrating full-stroke capability is the only test that requires measurement of the differential pressure across the valve.
3.1.2 Valves Identified for Cold Shutdown Exercising The Code permits valves to be exercised during cold shutdowns when exercising is not practical during plant operation and these valves are Seabrook SSER 6 7 Appendix 5
specifically identified by the utility and are full-stroke exercised during cold shutdowns, therefore, the utility is meeting the requirements of the ASME Code. Since the utility is meeting the requirements of the ASME Code, it is not necessary to grant relief; however, during our review of the utility's IST program, we have verified that it is not practical to exercise these valves during power operation and that we agree with the utility's basis.
The NRC differentiates, for valve testin~g purposes, between the cold shutdown mode and the refueling mode. That is, for valves identified for testing during cold shutdowns, it is expected that the test will be performed both during cold shutdowns and each refueling outage. However, when relief is granted to perform tests on a refueling outage frequency, testing is expected only during each refueling outage. In addition, for extended refueling outages, tests being performed are expected to be maintained as closely as practical to the Code-specified frequencies.
3.1.3 Conditions for Valve Testing During Cold Shutdowns Cold shutdown testing of valves identified by the utility is acceptable when each of the following conditions are met:
- 1. The utility is to commence testing as soon as the cold shutdown condition is achieved, but no later than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> after shutdown and continue until complete or the plant is ready to return to power;
- 2. Completion of all valve testing is not a prerequisite to return to power; ,
- 3. Any testing not completed during one cold shutdown should be performed during any subsequent cold shutdowns starting from the last test performed at the previous cold shutdown;
- 4. For planned shutdowns, where ample time is available and testing all the valves identified for the cold shutdown test frequency in Seabrook SSER 6 8 Appendix S l
l
l the IST program will be accomplished, exceptions to the 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> may be taken.
3.1.4~ Category A Valve Leak Test Requirements for Containment Isolation Valves All containment isolation valves that are Appendix J Type C, leak tested should be included in the IST program as Category A or A/C valves.
The NRC has concluded that the applicable leak test procedures and requirements for containment isolaticn valves are determined by 10 CFR 50 Appendix J. Relief from Paragraphs IWV-3421 through IWV-3425 (1983 Edition through Summer 1983 Addenda) for containment isolation valves presents no safety problem since the intent of these paragraphs is met by Appendix'J requirements, however, the utiT1ty must comply with the Analysis of Leakage Rates and Corrective Action requirements of paragraphs IWV-3426 and IWV-3427. Based on the considerations discussed above, the NRC staff has concluded that the proposed alternate testing will give reasonable assurance of valve leak-tight integrity as required by the Code and that the relief thus granted will not endanger life or property or the common defense and security of the public.
3.1.5 Application of Appendix J Testino to the IST Program The Appendix J review of this plant is completely separate from the IST program' review. However, the determinations made by that review are directly applicable to the IST program. The utility has agreed that, should the Appendix J program be amended, they will amend their IST program accordingly.
3.1.6 Safety Related Valves This review was. limited to valves whose function is safety related.
Valves whose function is safety related are defined as those valves that are needed to mitigate the consequences of an accident and/or to shut down the reactor to the cold shutdown condition and to maintain the reactor in a cold shutdown condition. Valves in this category would typically include Seabrook SSER 6 9 Appendix S
certain ASME Code Class 1, 2, and 3 valves and could include some non-Code class valves. It should be noted that-the utility may have included valves whose function is not safety related in their IST program as a decision on their part to expand the scope of their program.
~
3.1.7 Active Valves The NRC staff position is that active valves are those for which changing position may be required to shut down a reactor to the cold shutdown condition or to mitigate the consequences of an accident.
Included are valves.which respond automatically to an accident signal, such as safety injection, and valves which may be optionally utilized but are subject to plant operator actions, such as service-water supply to the steam generators, and valves utilize'd to establish long term recirculation following a LOCA.
3.1.8 Rapid-Actina-Power Operated Valves The NRC staff has identified rapid-acting power operated valves as those which stroke in 2 seconds or less. Relief from the trending requirements of Section XI (Paragraph IWV-3417(a), 1983 Edition through Summer of 1983 Addenda) presents no safety concerns for these valves since variations in stroke time will be affected by slight variations in the response time of the personnel performing the tests. However, the staff does require that 'the utility assign a neximum limiting stroke . time of 2 seconds to these valves in order to obtain this Code relief.
3.1.9 Valves Which Perform a Pressure Boundary Isolation Function The following valves have been identified by the utility as pressure boundary isolation valves and have been categorized accordingly. These valves are individually leakrate tested in accordance with the NRC staff acceptance criteria for pressure boundary isolation valves and are included in the Seabrook Station Technical Specification Table 3.4-1. The valves are leakrate tested on the frequency identified in Technical Specification 4.4.6.2.2.
10 Appendix S Seabrook SSER 6
1 i
Valve Valve Size Function RC-V22 12" RHR Pump 8A Suction Isolation RC-V23 12" RHR Pump 8A Suction Isolation RC-V87 12" RHR Pump 88 Suction Isolation ,
RC-V88 12" RHR Pump 88 Suction Isolation '
RH-VIS 6" RHR to SI Loop 1 Cold Leg Injection RH-V29 6" RHR to SI Loop 3 Cold Leg Injection
.RH-V30 6" RHR to SI Loop 4 Cold Leg Injection RH-V31 6" RHR to SI Loop 2 Cold Leg Injection RH-V50 8" RHR to RCS Loop 4 Hot Leg Injection RH-V51 8" RHR to RCS Loop 1 Hot Leg Injection RH-VS2 6" SI to RCS Loop 1 Hot Leg Injection RH-V53 6" SI to RCS Loop 4 Hot Leg Injection SI-V5 10" SI to RCS Loop 1 Cold Leg Injection SI-V6 10" SI Tank 9A Discharge Isolation SI-V20 10" SI to RCS Loop 2 Cold' Leg Injection SI-V21 10" SI Tank 98 Discharge Isolation SI-V35 10" SI to RCS Loop 3 Cold Leg Injection SI-V36 10" SI Tank 9C Discharge Isolation SI-V50 10" SI to RCS Loop 4 Cold Leg Injection SI-V51 10" SI Tank 90 Discharge Isolation SI-V81 2" SI to RCS Loop 3 Hot Leg Injection SI-V82 6" SI to RCS Loop 3 Hot Leg Injection SI-V86 2" SI to RCS Loop 2 Hot Leg Injection SI-V87 6" SI to RCS Loop 2 Hot Leg Injection SI-V106 2" SI to RCS Loop 4 Hot leg Injection SI-V110 2" SI to RCS Loop 1 Hot Leg Injection SI-V118 2" SI to RCS Loop 1 Cold Leg Injection SI-V122 2" SI to RCS Loop 2 Cold Leg Injection
~
SI-V126 2" SI to RCS Loop 3 Cold Leg Injection SI-V130 2" SI to RCS Loop 4 Cold Leg Injection SI-V140 3" SI to RCS Cold Leg Injection SI-V144 1-1/2" SI to RCS Loop 1 Cold Leg Injection i
SI-V148 1-1/2" SI to RCS Loop 2 Cold Leg Injection SI-V152 1-1/2" SI to RCS Loop 3 Cold Leg Injection SI-V156 1-1/2" SI to RCS Loop 4 Cold Leg Injection 3.1.10 Pressurizer Power Operated Relief Valves The NRC has adopted the position that the pressurizer power operated relief valves (PORVs) should be included in the IST program as Category B l Seabrook SSER 6 11 Appendix S
valves and tested to the requirements of Section XI. However, since the PORVs have shown a high probability of sticking open and are not needed-for overpressure protection during power operation, the NRC has concluded that routine exercising during power operation is "not practical" and therefore not required by IWV-3412(a).
If the PORV's function during reactor startup and shutdown is to protect the reactor vessel and coolant system from low-temperature overpressurization conditions,~these valves should be exercised prior to initiation of system conditions for which vessel protection is needed and the following test schedule is required.
a
- 1. Full-stroke exercise should be performed at each cold shutdown or, as a minimum, once each refueling cycle.
- 2. Stroke timing should be performed at each cold shutdown or, as a.
minimum, once each refueling cycle.
- 3. Fail safe actuation testing should be performed at each cold shutdown.
- 4. The PORV block valves should be included in the IST program and tested quarterly to provide protection against a small break LOCA should a PORV fail open.
The utility has included the PORVs (RC-PCV456A and PCV4568) and the associated block valves (RC-V122 and V124) in the IST program as Category B valves and is testing them in accordance with the above NRC guidelines.
- a. The staff position described in Section 3.1.3 regarding_ cold shutdown testing is not applicable to the PORVs; however, in the case of frequent cold shutdowns, testing of the PORVs is not required more.often than each three months.
12 Appendix.S Seabrook SSER 6
3.2 General Relief Recuests 3.2.1 Solenoid Operated Valve Position Indicator Verification 3.2.1.1 Relief Request. The utility has requested relief from the Section XI requirement of observing solenoid operated valves to verify their remote position indication every two years and has proposed to verify the open and closed positions of the solenoid operated valves by monitoring system parameters such as flow, temperature and pressure.
3.2.1.1.1 Code Reauirement--Valves with remote position indicators shall be observed at least once every two years to verify that valve operation is accurately indicated.
3.2.1.1.2 Licensee's Basis for Requestina Relief--It is not practical to perform valve ~ position indication verification tests every two years as stated in Subsection IWV-3300. These valves will require disassembly of actuator components to verify operation. The accurate visual verification of valve operation is not possible due to the minimal stem travel and short stroke period. This visual observation would not contribute significantly to the assurance of safe and proper valve operation. Valve open and closed indications shall be verified by monitoring normal system parameters at least once every two years during exercise testing, (e.g.,-flow, temperature or pressure).
3.2.1.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the Section XI requirement to observe valve operation to verify remote position indication for all solenoid operated valves in the Seabrook IST. program. The utility has stated that due to the design of these solenoid operated valves, valve position cannot be determined by observation unless the valve is partially disassembled. Disassembling these solenoid operated valves solely to verify their position is not practical. The remote position indicators for these valves can be verified by observing system parameters such as temperature, pressure, and flow.
Seabrook SSER 6 13 Appendix S
3.2.1.1.4 Conclusion--The staff concludes that the utility's proposal to verify the remote position indicators of all solenoid operated valves by observing system temperatures, pressures, and flows as appropriate, should provide a reasonable assurance that the remote indicators provide the correct indication of valve position. The relief thus granted will not endanger life or property or the common defense and security of the public.
3.2.2 Rapid Acting Power Operated Valves 3.2.2.1 Relief Reauest. The utility has requested relief from the Section XI requirement of trending the stroke times of rapid acting power operated valves in the Seabrook IST program and proposed to set a limiting value of full-stroke time of 2 seconds for these valves and to take the corrective actions specified in IWV-3417(b) if the measured stroke time exceeds 2 seconds.
3.2.2.1.1 Code Reautrement--If an increase in stroke time of 25%
or more from the previous test for valves with full-stroke times greater than 10 seconds or 50% or more for valves with full-stroke times less than or equal to 10 seconds is observed, test frequency shall be increased to once each month until corrective action is taken, at which time the original test frequency shall be resumed.
3.2.2.1.2 Licensee's Basis for Requesting Relief--Rapid acting valves are defined as valves that stroke in 2 seconds or less. Relief from the trending requirements of Section XI (Paragraph IWV-3417(a), 1983 Edition through Summer of 1983 Addenda) presents no adverse safety concerns for these valves since variations in stroke times will be affected by slight variations in the response times of the personnel performing the tests.
3.2.2.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the Section XI requirement of trending the stroke times for all rapid acting power operated valves in 14 Appendix S Seabrook SSER 6
- 4. _ _ _ _
4_a 4 __. __: .,_,a_ 2 -
d_ a..-- -4d. 4 *. ~m4 _
l their -IST program.- As discussed in Section 3.1.8 the trending requirements i of IWV-3417(a) are not pra'ctical for valves that normally stroke in 2 seconds or less and granting relief from the Code requirements for these
_ valves presents no safety problems.
i 3.2.2.1.4 ' Conclusions The staff concludes that the utility's ,
proposal to not trend the stroke times for rapid acting valves but to
. assign a limiting value of full-stroke time of 2 seconds to these valves and take the corrective actions of IWV-3417(b) whenever the 2 second limit
'is exceeded, should provide a reasonable assurance that these valves are not degraded and will perform their safety related function. The relief thus granted will not endanger life or property or the common defense and
- security of the public.
t 4
3.2.3 Stroke Time Corrective Action for Power Operated Valves f
3.2.3.1 Relief Reauest. The utility has requested relief from the Section XI requirement to incresse the frequency of testing, if the measured valve stroke time is greater than the Code trending limits identifed in IWV-3417(a), for valves that cannot be exercised during power operations and proposed to. exercise these valves during each cold shutdown but not to exceed.once every 31 days.
i i
3.2.3.1.1 Code Reauirement--If, for power operated valves, an increase in stroke time of 25% or more from the previous test for valves
, with full-stroke times greater than 10 seconds or 50% or more for valves with full-stroke times' less than or equal to 10 seconds is observed, test frequency shall be increased to once each month until corrective action is taken, at which time the original test frequency shall be resumed.
3.2.3.1.2 Licensee's Basis for Reauestina Relief--It is "
impractical to increase the testing frequency for these valves. Strict adherence to this requirement for valves which cannot be exercised during Seabrook SSER 6 15 Appendix S
. _.-..._._ __ . . = . , _ __. _ ,_,_.. _ _ _
power operations would require-that the test frequency be increased to once each month until corrective action is taken. Exercising these valves would.
require a plant shutdown or operation under unusual conditions.
The subject valves shall be full-stroke exercised only during cold shutdowns on a frequency determined by the intervals between shutdowns as follows:
A. For intervals of one month (31 days) or longer, tests will be performed during each shutdown.
B. For intervals of less than one month (31 days), tests will not be performed unless one month (31' days) has passed since the last shutdown.
3.2.3.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the Section XI requirement to increase the test frequency to niunthly for valves whose stroke times exceed the trending. limits of IWV-3417(a) that cannot be exercised during power operations. When the utility has submitted a relief request or cold shutdown justification that provides a technical basis for not exercising a valve during power operations and the staff has evaluated and approved the basis, then it is not practical nor desirabi'e to require the valve to be tested monthly during power operations. The utility will test any power operated valves, that exceed the stroke time trending limits, during each cold shutdown, not to exceed once every 31 days, for D equent shutdowns.
3.2.3.1.4 Conclusion--The staff concludes that the utility's
{ proposed alternate corrective action of increasing the test frequency for j valves approved for the cold shutdown exercising frequency to each cold shutdown, not to exceed once every 31 days, if their stroke times exceed the limits of IWV-3417(a), should give reasonable assurance of valve operability and should provide as frequent as feasible testing of these valves. The relief thus granted will not endanger life or property or the common defense and security of the public.
I Seabrook SSER 6 16 Appendix S l
3.3 Emeroency Feedwater System 3.3.1 Category C Valves 3.3.1.1 pelief Request. The utility has requested relief from the exercising requirements of Section XI for FW-V64 and V70, the emergency feedwater pump discharge check valves, and proposed to full-stroke exercise these valves during cold shutdowns with the associate'd pump operability testing.
3.3.1.1.1 Code Requirement--Refer to Appendix A.
3.3.1.1.2 Licensee's Basis for Reauesting Relief--Full flow through these valves quarterly during power operations would unnecessarily introduce cold water into the steam generator causing thermal shock to the feed nozzles. These valves will be full-stroke exercise tested during cold shutdowns with the associated pump operability testing.
3.3.1.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves FW-V64 and V70. Exercising these valves with flow during power operations would result in the introduction of relatively cold water into the feedwater headers which would thermal shock the feed nozzles, the emergency feedwater to'feedwater tees, and the associated feedwater piping. Thernal shocking these components will cause cyclic thern21 stresses which could result in premature component failure.
The utility will full-stroke exercise these valves during each cold shutdown when feedwater and steam generator temperatures are lower, which will reduce the temperature difference between them and the emergency feedwater which would reduce the resulting thermal stresses to system components. The utility will exercise FW-V64 during plant cooldown to cold shutdown or heat-up from cold shutdown when there is sufficient steam to drive the turbine driven pump. The utility has stated that sufficient flow is established through this valve to verify a full-stroke exercise.
Seabrook SSER 6 17 Appendix S
3.3.1.1.4 Conclusion--The staff concludes that the utility's proposal to full-stroke exercise FW-V70 during cold shutdowns and FW-V64 during plant cooldown to cold shutdown or heat-up from cold shutdown should provide a reasonable assurance of valve operability. The relief thus granted will not endanger life or property or the common defense and .
security of the public.
3.4 Diesel Generator Air-Start System 3.4.1 Cateaory B Valves 3.4.1.1 Relief Request. The utility has requested relief from the stroke time measurement requirements of Section XI for DGA-FYAS1, DGA-FYAS2, DGB-FYAS1, and DGB-FTAS2, the emergency diesel generator air-start solenoid valves, and proposed to full-stroke exercise these valves at least quarterly during the monthly diesel generator testing and to determine valve degradation by measuring the time needed to start the diesel and establish rated freg6ency and voltage.
3.4.1.1.1 Code Reauirement--The stroke time of all power operated valves shall be measured to the nearest second, for stroke times 10 seconds or less, or 10% of the specified limiting stroke time for full-stroke times longer than 10. seconds whenever such a valve is full-stroke tested.
3.4.1.1.2 Licensee's Basis for Reauestino Relief--It is impractical to measure the limiting value of full-stroke time of these valves. These valves do not have remote position indication. Measuring the stroke time of these valves by observing stem travel would require disassembly of the operator. The safety function of these valves is to open to support the startup of its respective diesel to provide rated ,
frequency and voltage in less than ten seconds. Successful startup of each emergency diesel generator within the above specified conditions is dependent upon the proper operation and speed of these valves. Measuring start up time of each emergency diesel generator is an indirect method of Seabrook SSER 6 18 Appendix S
verifying the degradation of these valves and meets the intent of the Code. -Upon failure of the diesel generators to start as required, corrective action shall be taken to assure proper diesel startup conditions.
These valves shall be full-stroke tested on a quarterly basis using the emergency diesel generator start up times as an indirect indication of valve operability.
3.4.1.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the stroke time measurement requirements of Section XI for valves OGA-FYAS1, DGA-FYAS2, DGB-FYAS1, and OGB-FYAS2. The utility has demonstrated that the stroke times of these valves cannot be measured directly. The valves do not have position indicators and valve position cannot be determined locally without partially disassembling the valve, which is not practical. Valve degradation can be monitored indirectly by measuring the startup time of the diesel generators. The valves are individually tested with one of the two dies'el generator A valves peing used to start the diesel during one monthly diesel test and the other valve being used for the next test, which assures that each valve is tested at least quarterly. The same alternate testing schedule is used for the two diesel generator B valves. Any valve degr.adation should show up in the diesel generator start times, and if the degradation is substantial, the diesel will not meet the 10 second limit for being at rated frequency and voltage and corrective actions will be taken to repair or replace the valve.
3.4.1.1.4 Conclusion--The staff concludes that the utility's proposal to exercise each diesel generator air start valve at least quarterly and to indirectly monitor any valve degradation by measuring the diesel startup times for each individual valve, should provide a reasonable assurance of the ability of these valves to perform their safety related function. The relief thus granted will not endanger life or property or the common defense and security of the public.
l Seabrook SSER 6 19 Appendix 5 l
3.5 Diesel Generator Cooling Water System 3.5.1 Category B valves 3.5.1.1 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for DG-PV7Al, PV7A2, PV7Bl. PV782, TCV7Al, TCV7A2, TCV7B1, and TCV7B2, the emergency diesel generator, cooling water pressure and temperature control valves, and proposed to test their fail-safe function at least quarterly and to determine if there is any valve degradation by observing how these valves perform their control functions during the monthly diesel generator tests.
3.5.1.1.1 Code Requirement--Refer to Appendix A.
3.5.1.1.2 Licensee's Basis for Requestino Relief--Exercising these valves at any periodic frequency is impractical. These valves are not operated by hand switches. They respond to signals generated by pressure and temperature c'ontrotlers which cannot be manually bypassed.
The function of these valves is to modulate to control the pressure and temperature of the cooling water of each emergency diesel generator. Valve degradation is indicated by the inability of the cooling water system to provide proper flow and to maintain the proper operating temperature.
These valves are included in the inservice test program because of their fail-safe feature. These valves shall be verified on a quarterly basis that they fail to the maximum cooling position upon loss of actuator power.
3.5.1.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves DG-PV7Al, PV7A2, PV781, pV782, TCV7A1, TCV7A2, TCV781, and TCV7B2. These valves do not have controls that will allow stroking them f rom their fully closed to their fully open positions or from their fully open to their fully closed positions. During diesel generator
- operations these valves will modulate to control the diesel cooling water pressure and temperature and they cannot be forced from that mode unless actuator power is lost or removed, at which time they will go to their 20 Appendix S Seabrook SSER 6
fail-safe positions to provide maximum diesel cooling flow. These valves will be verified to-go to their fail-safe positions quarterly, but cannot be full-stroke exercised or have their full-stroke times measured.
Observing proper system temperature and pressure control is the only indication available of valve. degradation.
3.5.1.1.4 Conclusion--The staff concludes that the utility's proposal to exercise these diesel generator cooling water pressure and temperature control valves to their fail-safe position and observe proper cooling water pressure and temperature control quarterly during the diesel generator tests should provide a reasonable assurance of.the ability of these valves to perform their safety-related function. The relief thus granted will not endanger life or property or the common defense and security of the public.
3.6 Residual Heat Removal System 3.6.1 Cateaory C Valves 3.6.1.1 Relief Request. The utility has requested relief from the exercising requirements of Section XI for CBS-V55 and v56, check valves in RHR pump suction line from the refueling water storage tank (RWST), and proposed to full-stroke exercise these valves during refueling outages.
3.6.1.1.1 Code Reautrement--Refer to Appendix A.
3.6.1.1.2 Licensee's Basis for Reauestino Relief--It is impractical to full-stroke-exercise these valves on a quarterly basis
. because these valves are not in the pump test flow path. These valves cannot be exercised during cold shutdowns because there is no flow path back.to the RWST. Testing during cold shutdowns would require flow to be established into the RCS where there is no additional volume to add the additional inventory.
i l
Seabrook SSER 6 21 Appendix 5
3.6.1.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves CBS-V55 and V56. These' valves are not located in the RHR' pump test flow path'and can only be exercised with flow by taking a suction from the RWST and pumping into the RCS. These valves cannot be exercised quarterly because the RHR pumps do not develop sufficient head to pump into the RCS while it is at normal operating pressure. Exercising the valves during cold shutdowns would require changing from the cooldown recirculation flow path and taking a suction from the RWST and then pumping into the RCS. This cannot be done since it would add water inventory to the RCS and there is not a sufficient expansion volume in the RCS to allow for this testing. These valves will be full-stroke exercised during refueling outages.
> 3.6.1.1.4 Conclusion--The staff concludes that the utility's proposal to full-stroke exercise check valves CBS-V55 and V56 during refueling outages should provide a reasonable assurance of valve operability. The relief thus granted will not endanger life or property or the common defense and security of the public.
3.7 Safety In_1ection System Accumulators 3.7.1 Category A/C valves 3.7.1.1 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for SI-VS, V20, V35, and V50, the combined accumulator and RHR injection check valves, and proposed to partial-stroke exercise these valves during cold shutdowns and to partially disassemble, inspect, and verify full-stroke capability of one valve from the group each refueling outage on a staggered sampling basis.
3.7.1.1.1 Code Reauirement--Ref er to Appendix A.
Seabrook SSER 6 22 Appendix 5 1
3.7.1.1.2 Licensee's Basis for Requesting Relief--These valves cannot be full-stroke exercised quarterly during power operation because the safety injection accumulators have insufficient pressure to flow into
,the RCS. Additionally, valves SI-VS, SI-V20, SI-V35 and SI-V50 cannot be exercised quarterly during power operation because the RHR pumps have insufficient pressure to flow into the RCS, During cold shutdowns, there is not sufficient flow using the RHR pumps to full-stroke exercise these valves. These valves shall be partially stroked during cold shutdowns.
These valves shall be partially disassembled, inspected and manually exercised on a staggered sampling basis each refueling outage. At each disassembly, it shall be verified that the disassembled valve is capable of full stroking and that its internals are structurally sound (no loose or corroded parts). In the event that the disassembled valve's full-stroke capability is in question, all valves in this group shall be disassembled.
3.7.1.1.3 Evaluation.-The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves SI-VS, V20, V35, and V50. These valves cannot be exercised with flow quarterly during power operation because neither the RHR pumps nor the safety injection accumulators can establish flow into the RCS when it is at normal operating pressures. RHR flow is established through these valves during cold shutdowns, but this only results in a partial-stroke exercise of the valves because RHR flow is less than the design accident flow rate for the combined safety injection accumulator and RHR low head injection. Accumulator flow cannot be established into the RCS during cold shutdowns because the accumulator isolation valves are required to remain closed by plant technical specifications; this could also result in a low-temperature overpressurization of the RCS.
Discharging an accumulator during refueling outages could result in flow damage to reactor core internals. These valves will be disassembled, Seabrook SSER 6 23 Appendix S
inspected, and verified to full-stroke on a sampling basis during refueling outages.
The NRC staff has concluded tnat a valve sampling disassembly / inspection utilizing a manual full-stroke exercise of the valve disk is an acceptable method to verify a check valve's full-stroke capability. The sampling technique requires that each valve in the group be of the same design (manufacturer, size, model number and materials of construction) and have the same service conditions. Additionally, at each disassembly it must be verified that the disassembled valve is capable of full-stroking and that its internals are structurally sound (no loose or corroded parts).
A different valve of each group is required to be disassembled, inspected and manually full-stroke exercised at each refueling outage, until the entire group nas been tested. If it is found that the disassembled valve's full / stoke capability is in question, the remainder of the valves in that group must also be disassembled, inspected and manually full-stroke exercised during t'he same outage.
3.7.1.1.4 Conclusion--The staff concludes that the utility's proposal to partially disassemble, inspect, and verify full-stroke capability of one valve from this group each' refueling outage on a sampling basis, along with a partial-stroke exercise during cold shutdowns, should provide a reasonable assurance of the ability of these valves to perform their safety related function in the open position. These valves will be-leakrate tested in accordance with the technic 61 specifications requirements for pressure boundary isolation valves to verify their leak tight capability in the closed position. The relief thus granted will not endanger life or property or the common defense and security o. the public.
3.7.1.2 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for SI-V6, V21, V36, and V51, the safety injection accumulators discharge check valves, and has proposed to Seabrook SSER 6 24 Appendix S
partially disassemble, inspect, and verify the full-stroke capability of one of these valves each refueling outage on a staggered sampling basis.
3.7.1.2.1 Code Requirement--Refer to Appendix A.
3.7.1.2.2 Licensee's Basis for Requestina Relief--These valves cannot be full-stroke exercised quarterly during power operation because the safety injection accumulators have insufficient pressure to flow into the RCS.
During cold shutdowns these valves cannot be exercised because the accumulator isolation valves (SI-V3, SI-V17, SI-V32 and SI-V47) are required by the plant Technical Specifications Section 4.5.2 to be closed with power removed from the opeiators. SI flow from the accumulators could also risk low-temperature overpressurization of the RCS.
These valves shall be partially disassembled, inspected and manually exercised on a staggered sampling basis each refueling outage. At each disassembly, it shall be verified that the disassembled valve is capable of full stroking and that its internals are structurally sound (no loose or corroded parts). In the event that the disassembled valve's full stroke capability is in question, all valves in this group shall be. disassembled.
3.7.1.2.3 Evaluation--The staff agr'ees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves SI-V6, V21, V36, and V51. These valves cannot be exercised with flow quarterly during power operation because the safety injection accumulators operating pressures are less than normal operating RCS pressures which prevents flow from the accumulators into the RCS.
Accumulator flow cannot be established into the RCS during cold shutdowns because the accumulator isolation valves are required to remain closed by plant technical specifications. Accumulator flow into the RCS during cold shutdowns could result in a low-temperature overpressurization of the RCS.
Full-stroke exercising these valves with flow during refueling outages is not desirable since it would involve discharging an accumulator at normal Seabrook SSER 6 25 Appendix 5
. pressure into the RCS which could result in flow damage to the reactor internals. These valves will be disassembled, inspected, and manually exercised on a sampling basis during each refueling outage as explained in Section 3.7.1.1.3 of this report.
' 3. 7 .1. 2. 4 Conclusion--The staff concludes that the utility's proposal to partially disassemble, inspect, and manually exercise (to verify a full-stroke capability) one valve from this four valve group each refueling outage on a sampling basis should provide a reasonable assurance o.f the ability of these valves to perform their s-'ety-related function in the open position. These valves will be leakrate tested in accordance with the plant technical specifications requirements for pressure boundary isolation valves to verify their leak tight capability in the closed position. The relief thus granted will not endanger life or property or the common defense and security of the public.
3.8 High Head Safety Injection System 3.8.1 Category A/C Valves 3.8.1.1 Relief Request. The utility has requested relief from the exercising requirements of Section XI for RH-V50, V51, V52, and V53, the RHR to RCS hot leg injection line check valves, and proposed to full-stroke exercise these valves during refueling outages.
3.8.1.1.1 Code Reautrement--Refer to Appendix A.
~3.8.1.1.2 Licensee's Basis for Reauestino Relief--Exercising these valves per the frequency described in IWV-3520 is not practical.
Exercising these valves during plant operation would require initiating flow to the reactor coolant system using the residual heat removal pumps.
During plant operation, the reactor coolant system pressure will be greater than the residual heat removal pump discharge pressure. These valves cannot be exercised during cold shutdowns because establishing flow through Seabrook SSER 6 26 Appendix S
1 these valves could result in RHR cooling flow bypassing the reactor core.
These valves will be full-stroke exercised during refueling outages.
3.8.1.l.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves RH-V50, V51, V52, and V53. These valves cannot be exercised quarterly during power operations, because the only flow path through these valves is into the RCS and the RHR pumps do not produce a sufficient discharge head to overcome the normal operating RCS pressure.
Exercising these valves during cold shutdowns would necessitate switching the RHR flow to the hot leg injection path which would result in cooling flow bypassing the reactor core which could result in over-heating in the core. The utility will full-stroke ' exercise these valves with flow during each reactor refueling outage.
3.8.1.1.4 Conclusion--The staff concludes that the utility's proposal to ful.1-stroke exercise check valves RH-V50, VS1, V52, and V53 during refueling outages should provide a reasonable assurance of valve
. operability. The relief thus granted will not endanger life or property or the common defense and security of the public.
3.8.1.2 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for SI-V81, V82, V86, V87, V106, V110, Vil8, V122, V126, and V130, safety injection header check valves, and proposed to full-stroke exercise these valves during each refueling outage.
3.8.1.2.1 Code Requirement--Refer to Appendix A.
3.8.1.2.2 Licensee's Basis for Requestina Relief--Exercising these valves per the frequency described in'IWV-3520 is not practical.
Exercising these valves during plant operation would require initiating flow to the reactor coolant system using the safety injection pumps.
During plant operation, the reactor coolant pressure will be greater than the safety injection pump discharge pressure. These valves cannot be exercised during cold shutdowns because SI pump flow could possibly risk Seabrook SSER 6 27 Appendix S
low-temperature overpressurization of the RCS. These valves will be full-stroke exercised during refueling outages.
3.8.1.2.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves SI-V81, V82, V86, V87, V106, V110, V118, V122, V126, and V130. These valves are not in the safety injection pump test flow path, therefore, exercising them with flow would require injecting water into the RCS. Flow cannot be established into the RCS quarterly during power operation because the safety injecti.on pump discharge head is lower than the normal operating RCS pressures. During cold shutdowns, flow cannot be establis'hed through these valves into the RCS because the safety injection pump flow could result in a low-temperature overpressurization of
'the RCS. The utility will full-stroke exercise these valves with flow during each refueling outage.
3.8.1.2.4 Conclusion--The staff concludes that the utility's proposal to' full-stroke ex'ercis( valves SI-V81, V62, V86, V87, V106, V110, V118, V122, V126, and V130 during each ref ueling outage should provide a reasonable assurance of the operability of these check valves. The relief thus granted will not endanger life or property or the common defense and security of the public.
3.8.1.3 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for SI-V140, V144, V148, V152, V156, and V297, check valves in the injection flow path from the charging pumps, and proposed to full-stroke exercise these valves during each refueling outage. )
3.8.1.3.1 Code Reautrement--Refer to Appendix A.
l 3.8.1.3.2 Licensee's Basis for Requestina Relief--These valves are normally closed check valves. To exercise these check valves, charging flow from the charging pumps must be initiated. If charging flow was directed to the RCS in this manner, it could cause a loss of charging flow Seabrook SSER 6 28 Appendix 5 t
T i
)
i control during plant operation resulting in pressurizer level changes and possibly a plant trip. Charging flow through these valves during plant-operation would also result in the injection of relatively cold water into the RCS possibly resulting in the cold shocking of system components.
Charging flow through these valves during cold shutdown could cause low-temperature overpressurization of the RCS. These check valves will be full-stroke exercised open during refueling outages.
3.8.1.3.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves SI-V140, V144, V148, V152, V156, and V297. The only path to exercise these valves with flow results in pumping relatively cold water into the RCS. During power operation this injection of cold water could result in thermal s. hock to system components plus it could cause a loss of pressurizer level control which could lead to a plant trip. During cold shutdowns, flow cannot be established through these valves into the RCS because unrestricted charging pump flow could result in a low-temperature overpressurization of the RCS. The utility will full-stroke exercise these valves during each refueling outage.
3.8.1.3.4 Conclusion--The staff concludes that the utilit.y's proposal to full-stroke exercise valves SI-V140, V144, V148, V152, V156, and V297 during each refueling outage should provide a reasonable assurance of the ability-of these valves to perform their safety related function in the open position. Valves SI-V140, V144, V148, V152, and V156 are leakrate tested in accordance with the requirements in the plant technical specifications for valves that perform a pressure boundary isolation function to verify their safety related function in the closed position.
The relief thus granted will not endanger life or property or the common defense and security of-the public.
3.8.2 Cateaory C valves 3.8.2.1 Relief Request. The utility has requested relief from the exercising requirements of Section XI for CBS-V48 and VS2, check valves in l
Seabrook SSER 6 29 Appendix S l _ _ _ - - . - --. - -
the lines from the RWST to the suction of the safety injection pumps, and proposed to full-stroke exercise these valves during refueling outages.
3.8.2.1.1 Code Reauirement--Refer to Appendix A.
3.8.2.1.2 Licensee's Basis for Reauestina Relief--There is not sufficient flow to full-stroke exercise these valves during the quarterly SI pump tests because these tests are run on minimum flow recirculation.
These valves are partially-stroked on a quarterly basis. These valves cannot be full-stroke exercised during cold shutdowns due to possible low-temperature overpressurization concerns with the RCS. These valves will be full-stroke exercised during refueling outages.
i 3.8.2.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves CBS-V48 and V52. The only full-flow path for this system requires the injection of RWST water into the RCS. This flow path cannot be utilized during' power operation because the safety injection pumps cannot overcome RCS pressure. Also, pumping RWST water with its high concentration of boric acid into the RCS would result in power fluctuations and a possible plant shutdown. The only test flow path available for these valves is the minimum flow recirculation path which only allows a partial-stroke exercise of the valves. During cold shutdowns there are administrative controls that prevent pumping into the RCS in order to prevent a low-temperature overpressurization of the RCS. These valves will be partial-stroke exercised quarterly and will be full-stroke exercised during refueling outages.
i 3.8.2.1.4 Conclusion--The staff concludes that the utility's l
proposal to partial-stroke exercise CBS-V48 and V52 quarterly and to full-stroke exercise them during refueling outages should provide a l'
reasonable assurance of the operability of these check valves. The relief thus granted will not endanger life or property or the common defense and security of the public, i
I 1
Seabrook SSER 6 30 Appendix S
3.8.2.2 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for SI-V71 and V96, the safety injection pump discharge check valves, and proposed to full-stroke exercise
.these valves during each refueling outage.
3.8.P.2.1 Code Reautrement--Refer to Appendix A.
3.0.2.2.2 Licensee's Basis for Reauesting Relief--Full-stroke exercising these valves per the frequency described in IWV-3520 is not practical. Exercising these valves during plant operation would require initiating flow to the RCS using the SI pumps. During plant operation, the RCS pressure will be greater than the safety injection pump discharge pressure. These valves cannot be exercised during cold shutdowns because SI pump flow could possibly result in low-temperature overpressurization of the RCS. These valves shall be full-stroke exercised during refueling outages.
3.8.2.2.3 Evaluation <-The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves SI-V71 and V96. These valves are not in-the safety injection pump test flow path and exercising them with flow would require injecting water into the RCS. Flow cannot be established into the RCS quarterly during power operat. ion because the safety injection pump discharge head is lower than the normal operating RCS pressures. During cold shutdowns there are administrative controls that prevent safety injection flow into the RCS in order to preclude a low-temperature overpressurization of the RCS. The utility will full-stroke exercise these valves during each reactor refueling outage.
3.8.2.2.4 Conclusion--The staff concludes that the utility's proposal to full-stroke exercise valves SI-V71 and V96 during each refueling outage should provide a reasonable assurance of the operability of these check valves. The relief thus granted will not endanger life or property or the common defense and security of the public.
Seabrook SSER 6 31 Appendix 5 i
k 3.9 ' Chemical and Volume Control System 3.9.1 Category A Valves 3.9.1.1 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for CS-V167 and V168, the~ reactor coolant pump seal leakoff isolation valves, and proposed to full-stroke
. exercise these valves during cold shutdowns when the reactor coolant pumps are secured and during refueling outages.
3.9.1.1.1 Code Reautrement--Refer to Appendix A.
3.9.1.1.2 Licensee's Basis for Reauestino Relief--These. valves isolate leakoff flow from the.Eeactor coolant pump #1 seals. Isolating these valves during power operation and startup could cause damage to the reactor coolant pump seals. Full-stroke exercising of these valves will be J
performed during cold shutdowns when the reactor coolant pumps are secured.
1:
3.9.1.1.3 Ev.aluation--The staf f agrees with the utility's basis and, therefore, relief should be granted from_the exercising requirements
~
, of Section XI for valves CS-V167 and V168. The utility has shown that-exercising these valves would isolate the leakoff flow from the seals of the reactor coolant pumps. If one of these valves failed in the closed position-during testing it~would isolate leakoff from two of the reactor coolant pumps and could damage the pumps and result in a plant shutdown.
These valves cannot be exercised quarterly during power operation or during col.d shutdowns when the reactor coolant pumps remain in operation. The utility will full-stroke exercise:these valves during cold shutdowns when the reactor coolant pumps are secured and during refueling outages.
-3.9.1.1.4 Conclusion--The staff concludes that the utility's
- proposal to full-stroke exercise valves CS-V167 and V168 during cold shutdowns when the reactor coolant pumps are secured and during each
!. refueling outage should provide a reasonable assurance of the ability of j these valves to close to pa form their safety related function. The relief f Seabrook SSER 6 32 Appendix S I
thus granted will not endanger life or property or.the common defense and security of the public.
,3.9.2 Category C Valves 3.9.2.1 Relief Request. The utility has requested relief from the exercising requirements of Section XI for CBS-V58 and V60, check valves in the suction of the centrifugal charging pumps frcm the RWST, and proposed to full-stroke exercise these valves during each refueling outage.
3,9.2.1.1 Code Requirement--Refer to Appendix A.
3.9.2.1.2 Licensee's Basis for Requestino Relief--It is impractical to full-stroke exercise these valves quarterly. In order to full-stroke exercise these valves,-it is necessary to inject flow through the charging pumps to the high head safety injection flow path. If charging flow was directed,to the RCS in this manner, it could cause a loss of charging flow control duringslant operation resulting in pressurizer level changes and possibly a p.lant trip. Additionally, charging flow through these valves during plant operation would also result in the injection of relatively' cold water into the RCS possibly resulting in the cold shocking of system components. During cold shutdowns, the injection of charging flow could result in low-temperature overpressurization of the RCS. These valves.shall be full-stroke exercised during refueling outages.
3.9.2.1.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves CBS-V58 and V60. The only path to exercise these valves with flow would result in pumping water into the RCS. Pumping RWST water into the RCS quarterly during power operations would result in the '
injection of relatively cold water which could thermal shock system components and cause premature failure of the components. Also, charging i pump injection flow into the RCS would disrupt pressurizer level control which could lead to a plant trip. These valves cannot be exercised with flow during cold shutdowns because establishing charging pump injection Seabrook SSER 6 33 Appendix S
into the RCS could result in a low-temperature overpressurization of the RCS. The utility will full-stroke exercise these valves during each reactor refueling outage.
3.9.2.1.4 Conclusion--The staff concludes that the utility's proposal to full-stroke exercise valves CBS-V58 and V60 during each refueling outage should provide a reasonable assurance of the ability of these valves to perform their safety related function. The relief thus granted.will not endanger life or property or the common defense and security of the public.
3.9.2.2 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for CS-V200 and V209, the centrifugal charging pumps discharge check valves, and proposed to partial-stroke exercise these valves quarterly during the charging pump tests and to full-stroke exercise these valves during each refueling outage.
3.9.2.2.1 Code Requifement--Refer to Appendix A.
3.9.2.2.2 Licensee's Basis for Reauestina Relief--These valves can only be partially stroked during power operations. There is insufficient flow during charging operations to full-stroke exercise these valves. During the quarterly charging pump test, flow is directed through the seal water heat exchanger to the suction of the pumps. These valves cannot be exercised during cold shutdowns since injection flow from the charging pumps could result in low-temperature overpressurization of the RCS. These valves shall be full-stroke exercised during refueling outages.
3.9.2.2.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves CS-V200 and V209. The utility has shown that sufficient flow to full-stroke exercise these valves cannot be established during normal charging operations or during the quarterly charging pump tests. Therefore, these valves will be partial-stroke exercised quarterly but cannot be full-su oke exercised during power operations. During cold 34 Appendix S Seabrook SSER 6
shutdowns full injection flow cannot be established through these valves into the RCS because it could cause a low-temperature overpressurization of the RCS. The utility will full-stroke exercise these valves during refueling outages.
3.9.2.2.4 Conclusion--The staff concludes that the utility's proposal to partial-stroke exercise CS-V200 and V209 quarterly during power operations and to full-stroke exercise these valves during each refueling outage should provide a reasonable assurance of the ability of these valves to perform their safety related function. The relief thus granted will not endanger life or property or the common defense and security of the public.
3.10 Containment Spray System 3.10.1 Cateaory C Valves 3.10.1.1 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for CBS-V3 and V7, the containment spray pump suction check valves from the RWST, and proposed to partial-stroke exercise these valves quarterly when the containment ; pray pumps are operated in their recirculation test paths and to partially disassemble, inspect, and manually exercise these valves on a sampling basis during refueling outages.
3.10.1.1.1 Code Reautrement--Refer to Appendix A.
3.10.1.1.2 Licensee's~ Basis for Requestina Relief--These valves can only be partially stroked during quarterly pump testing. There is insufficient flow through these valves when the containment spray pump is operated in its RWST recirculation test path to full-stroke open these valves. The necessary flow required to full-stroke exercise these valves per the Code requirements would require the initiation of containment spray flow into the containment which is impractical. These valves shall be partially disassembled, inspected, and manually exercised on a staggered sampling basis each refueling outage. At each disassembly, it shall be Seabrook SSER 6 35 Appendix $
i l
I verified that the disassembled valve is capable of full troking and that its internals are structurally sound (no loose or corroded parts). In the event'that the disassembled valve's full-stroke capability is in question, both valves in this group shall be disassembled.
3.10.1.1.3 Evaluation--The staff agrees with the utility's basis and, therefore,. relief should be granted from the exercising requirements of Section XI for valves CBS-V3 and V7. The utility has shown that the only full-flow path for these valves requires spraying water inside primary containment which could cause damage to equipment and insulation in the containment. Spraying water in the containment building is not practical for valve testing during any plant operating mode. The. containment spray pumps are tested quarterly in a recirculation flow path which results in a partial-stroke exercise of these valves. The utility will partially disassemble, inspect, and manually exercise one of these valves during each refueling outage on a sampling basis as described in Section 3.7.1.1.3 of this report.
3.10.1.1.4 Conclusit>n--The staf f concludes that the utility's proposal to partial-stroke exercise valves CBS-V3 and V7 quarterly and to 4
partially disassemble, inspect, and manually exercise to demonstrate their capability to full-stroke each refueling outage on a sampling basis should provide a reasonable assurance of the ability of these valves to perform their safety related function. The relief thus granted will not endanger life or property or the common defense and security of the public.
3.10.1.2 Relief Reauest. The utility has requested relief from the exercising requirements of Section XI for CBS-V9, V15. V25, and V26, the l check valves in the RHR and containment spray pump suction lines from the containment sump, and proposed to partially disassemble, inspect, and manually exercise one valve from each group (CBS-V9 and V15 forming one group and CBS-V25 and V26 forming a second group) each refueling outage on a sampling basis.
l I Seabrook SSER 6 36 Appendix S l
3.10.1.2.1 Code Requirement--Refer to Appendix A.
3.10.1.2.2 Licensee's Basis for Requesting Relief--These valves cannot be exercised by system flow without pumping substantial amounts of low grade water from the containment sumps into the RCS, RWST, or containment spray headers using the containment spray and residual heat removal pumps. These valves will be partially disassembled, inspected and manually exercised on a staggered sampling basis (one valve in each group) each refueling outage. One group includes CBS-V9 and CBS-V15. The other group includes CBS-V25 and CBS-V26. At each disassembly, it shall be verified that the disassembled valve is capable of full stroking and that its internals are structurally sound (no loose or corroded parts). In the event that a valve's full-stroke capability is in question, both valves in the respective group shall be 6'isassembled.
3.10.1.2.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves CBS-V9< V15, V25, and V26. The utility has shown that to exercise these valves with flow would require placing a fairly substantial amount of water into the containment sump and then pumping from the sump with the RHR pumps and the containment spray pumps (not necessarily simultaneously). To obtain a full-stroke exercise of these valves would require pumping the low grade sump water either into the RCS, the RWST, or spraying containment. For chemistry control reasons, sump water should not be pumped into the RCS or RWST. Spraying containment could damage equipment and insulation. These valves will be partially disassembled, inspected, and manually exercised during refueling outages on a sampling basis as described in Section 3.7.1.1.3 of this report.
1 3.10.1.2.4 Conclusion--The staff concludes that the utility's proposal to partially disassemble, inspect, and manually exercise, to verify the full-stroke capability, valves CBS-V9, V15, V25, and V26, one i valve from each group each refueling outage on a sampling basis, should provide a reasonable assurance of the ability of these valves to perform Seabrook SSER 6 37 Appendix S
their safety related function. The relief thus granted will not endanger life or property'or the common defense and security of the public.
. -3.10.1.3 Relief'Reauest. The utility has requested relief from the exercising requirements of Section XI for CBS-V12 and V18, the containment spray header check valves, and proposed to partially disassemble, inspect, and manually exercise.one of these two valves during each refueling outage
.on a sampling basis.
3.10.1.3.1 Code Reautrement--Refer to Appendix A.
3.10.1.3.2 Licensee's Basis for Requestina Relief--These valves cannot be exercised without the initiation of containment spray flow into the containment building quarterly during power operation or during cold shutdowns. These valves shall be partially disassembled, inspected and manually exercised on a staggered sampling basis each refueling outage. At each disassembly, it shall be verified that the disassembled valve is capable of full stroking and that its-internals are structurally sound (no loose or corroded parts). In the event that the disassembled valve's
-full-stroke capability is in question, both valves in this group shall be disassembled.
3.10.1.3.3 Evaluation--The staff agrees with the utility's basis and, therefore, relief should be granted from the exercising requirements of Section XI for valves CBS-V12 and V18. The only flow path available to exercise these valves with flow is to the containment spray rings, therefore, exercising these valves would result in spray flow into the containment building which could damage equipment and insulation.
Estabitshing spray flow into containment for valve testing is not practical during any plant operating mode. The utility will partially disassemble, inspect, and manually exercise these valves during refueling outages on a sampling basis as described in Section 3.7.1.1.3 of this report.
3.10.1.3.4 Conclusion--The staff concludes that the utility's proposal to partially disassemble, inspect, and manually exercise, to Seabrook SSER 6 38 Appendix S
d
' verify a full-stroke capability, CBS-V12 or'V18 each refueling outage on a staggered sampling basis should provide a reasonable assurance of the ability of these valves to perform their safety related function. The relief thus granted will not endanger life or property or the common defense and security of the public.
l i-i a
4 s
1 f
I Appendix S Seabrook SSER 6 39 t
. .. -_ . , _ ._ . . . . _ _ _ . . . . . _ . _ _ . _ _ , . _ . . _ . - . _ . - - - , _ . _ _ _ , , , _ . _ . . _ _ _ - , _ _ . . - ~ . - -. _. --
APPENDIX A CODE REQUIREMENTS l
Seabrook SSER 6 41 Appendix S
APPENDIX A CODE REQUIREMENTS
- 1. CODE REQUIREMENTS--VALVES Subsection IWV-3411 of the 1983 Edition through the Summer of 1983 addenda of the Section XI ASME Code (which discusses full-stroke and partial-stroke exercising requirements) requires that Code Category A and B valves be exercised once every three months, with the exceptions as defined in IWV-3412(a), IWV-3415, and IWV-3416. IWV-3521 (which discusses full-stroke and partial-stroke exercising requirements) requires that Code Category C valves be exercised once every three months, with the exceptions as defined in IWV-3522. In the above exceptions, the Code permits the valves to be tested at cold sh6tdown where:
- 1. It is not practical to exercise the valves to the position required to fulfill their function or to the partial position during power operation.
- 2. It is not practical to observe the operation of the valves (with fail safe actuators) upon loss of actuator power.
Subsection IWV-3413 requires all Category A and 8 power-operated valves to be stroke-time tested to the nearest second or 10% of the maximum allowable owner-specified time. Additionally, all Category A valves are required to be individually leak-rate tested and trended on a frequeacy not to exceed two years in accordance with IWV-3420..
- 2. CODE REQUIREMENTS--PUMPS Section IWP-3400(a) of the 1983 Edition through the Summer of 1983 addenda of the ASME Code calls for an inservice test to be conducted on all safety-related pumps, nominally every three months during normal plant i
Seabrook SSER 6 43 Appendix 5
operation. Each inservice test shall include the measurement or observation and the recording of all quantities in Table IWP-3100-1, except bearing temperature, which shall be measured during at ic:st one inservice lest each year.
Seabrook SSER 6 44 Appendix S-
APPENDIX B VALVES TESTED DURING COLD SHUTDOWNS Seabrook SSER 6 45 Appendix S
APPENDIX 8 VALVES TESTED DURING COLD SHUTDOWNS The following are Category A, B, and C valves that meet the exercising requirements of the ASME Code,Section XI, and are not full-stroke exercised every three months during plant operation. These valves are specifically identified by the owner and are full-stroke exercised during cold shutdowns and refueling outages. The staff has reviewed all valves in this Appendix and agrees with the utility that testing these valves during power operation is not practical due to the valve type, location or system design. These valves should not be exercised during power operation.
These valves are listed below and grouped according to the system in which they are located.
Valve System Identification _ Function Main Steam System MS-V86 Main steam line isolation valve MS-V8B Main steam line isolation valve MS-V96 Main steam line isolation valve-MS-V32 Main steam line isolation valve MS-V94 Steam supply to emergency feedwater turbine check valve MS-V96 Steam supply to emergency feedwater turbine check valve Feedwater System FW-V30 Main feedwater isolation valve
~
FW-V39 Main feedwater isolation valve FW-V48 Main feedwater isolation valve FW-V57 Main feedwater isolation valve FW-V330 Main feedwater header check valve FW-V331 Main feedwater header check valve FW-V332 Main feedwater header check valve FW-V333 Main feedwater header check valve FW-V76 Emergency feed header check valve FW-V82 Emergency feed header check valve FW-V88 Emergency feed header check valve FW-V94 Emergency feed header check valve Containment Purge System CAP-V1 Purge containment isolation valve CAP-V2 Purge containment isolation valve CAP-V3 Purge containment isolation valve CAP-V4 Purge containment isolation valve Seabrook SSER 6 47 Appendix S
_ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ )
Valve System Identification __ Function Reactor Coolant System RC-V22 RHR suction from RCS hot leg RC-V23 RHR suction from RCS hot leg RC-V87 RHR-suction from RCS hot leg RC-V88 RHR suction from RCS hot leg Residual Heat Removal RH-V15 RHR to RCS cold leg check valve System RH-V29 RHR to RCS cold leg check valve RH-V30 RHR to RCS cold leg check valve RH-V31 RHR to RCS cold leg check valve RH-V14 RHR to RCS cold leg isolation valve RH-V26 RHR to RCS cold leg isolation valve RH-V32 RHR to RCS ht' leg isolation valve RH-V70 RHR to RCS hot leg isolation valve RH-V21 RHR cross-connect isolation valve RH-V22 RHR cross-connect isolation valve RH-V4' RHR pump discharge check valve RH-V40 RHR pump discharge check valve High Head Safety SI-V93 Minimum flow recirculation Injection System isolation valve CBS-V47 SI pump suction from RWST
' isolation CBS .V51 SI pump suction from RWST isolation SI-Vil4 SI to RCS cold legs isolation valve SI-V77 SI to RCS hot legs isolation valve SI-V102 SI to RCS hot legs isolation valve Chemical and Volume CS-V149 Letdown line isolation valve Control System CS-V150 Letdown line isolation valve CS-V142 Charging header isolation valve CS-V143 Charging header isolation valve CS-LCVil;D Charging pump suction from RWST isolation CS-LCVil2E Charging pump suction from RWST isolation CS-LCVil2B Charging pump suction from VCT isolation CS-LCV112C Charging pump suction from VCT isolation CS-V426 Charging pump suction from boric acid tanks CS-V427 Charging pump suction from boric acid tanks RMW-Vil9 Charging pump suction from boric acid blender Seabrook SSER 6 48 Appendix S
Valve System . identification Function Component Cooling Water CC-V57 Component cooling containment System isolation valve CC-V121 Component cooli.ng containment isolation valve i CC-V122 Component cooling containment '
isolation valve CC-V168 Component cooling containment isolation valve CC-V175 Component cooling containment isolation valve CC-V176 ' Component cooling containment isolation valve CC-V256 Component cooling containment isolation valve CC-V257 Component cooling containment isolation valve CC-TV2271-1 Component cooling temperature control valve CC-TV2271-2 Component cooling temperature control valve CC-TV2171-1 Component cooling temperature control valve CC-TV2171-2 Component cooling temperature control valve CC-V,341 Component cooling loop isolation valve CC-V426 Component cooling loop isolation valve CC-V427 Component cooling loop isolation valve CC-V447 Component cooling loop isolation valve CC-V448 Component cooling loop isolation valve Seabrook SSER 6 49 Appendix S I
APPENDIX C P&ID LIST Seabrook SSER 6 51 Appendix 5
I APPENDIX C P&ID LIST The P& ids listed below were used during the course of this review.
System P&ID Revision Main Steam 9763-F-202074 20 Emergency Feedwater System 9763-F-202076 9 feedwater System 9763-F-202079 17 Main Turbine and Steam. Piping 9763-F-202086 12 Auxiliary Boiler Steam and Condensate Return 9763-F-202100 14 i Diesel Generator fuel and Lube Oil 9763-F-202102 14 Diesel Generator Cooling Water 9763-F-202103 14 Leak Detection System 9763-F-500037 3 fuel Pool and Purge Exhaust System 9763-F-604131 11 Fire Protection System 9763-F-605146 9 Floor and Equipment Drain System 9763-F-804958 4 Sample System-Nuclear-Post Accident 9763-F-804978 4 Primary Component Cooling Water Loop "A" 9763-F-804981 8 Primary Component Cooling Water Loop "B" 9763-F-804982 9 Refueling Cavity Clean Up System 9763-F-804988 5 Reactor Ccolant System Reactor Vessel 9763-F-805002 12 Reactor Coolant System Loop Number 1 9763-F-805003 18 Reactor Coolant System Loop Number 4 9763-F-805006 17 Reactor Coolant System Pressur'izer 9763-F-805007 13 Residual Heat Removal System 9763-F-805008 15 Safety Injection System Accumulators 9763-F-805009 12 Safety Injection System High Head 9763-F-805010 17 Chemical and Volume Control System Purification 9763-F-805011 18 Chemical and Volume Control System Charging 9763-F-805012 19 Chemical and Volume Control System Boric Acid 9763-F-805014 15 Primary Component Cooling Water Loop "B" 9763-F-805016 14 Primary Component Cooling Water Loop "A" 9763-F-805018 13 Service Water System Nuclear 9763-F-805019 18 Gas-Service System Nitrogen Nuclear 9763-F-805020 10 Reactor Water Make Up 9763-F-805021 --
Combustible Gas Control System 9763-F-805022 9 Containment Spray System 9763-F-805023 12 Steam Generator 810wdown 9763-F-805024 12 Sample System Nuclear 9763-F-805025 11 Primary Component Cooling Water Loop "B" 9763-F-805028 13 Primary Component Cooling Water Loop "A" 9763-F-805029 12 Demineralized Water System Nuclear 9763-F-805030 13 Service Water System 9763-F-805033 10 Reactor Coolant Drain Tank Containment 9763-F-805040 12 Equipment Vent System Hydrogenated Vent Header 9763-F-805635 7 Compressed Air Headers 9763-F-202108 la Service Air System 9763-F-804989 6 Containment Floor and Equipment Drain System 9763-F-804994 8 Seabrook SSER 6 53 Appendix S
APPENDIX D VALVES TESTED DURING COLD SHUTDOWNS--DETAILS Seabrook SSER 6 55 Appendix S
APPENDIX 0 VALVES TESTED DURING COLD SHUTDOWNS--DETAILS The following are Category A, 8, and C valves that meet the exercising requirements of the ASME Code,Section XI, and are not full-stroke exercised every three months during plant operation. These valves are specifically identified by the owner and are full-stroke exercised during cold shutdowns and refueling outages. The staff has reviewed all valves in t'his Appendix and agrees with the utility that testing these valves during power operation is not practical due to the valve type, valve location or system design. These valves should not be exercised during power operation. These valves are listed below and grouped according to the system in which they are located.
- 1. MAIN STEAM SYSTEM 1.1 Category B Valves MS-V86, V88, V90, and V92, the main steam isolation valves, cannot be full-stroke exercised quarterly during power operations because fully closing these valves would isolate the steam supply from a steam generator which would require a plant shutdown. These valves will be partial-stroke exercised quarterly during power operations and full-stroke exercised during cold shutdowns and refueling outages.
1.2 Category C Valves MS-V94 and V96, check valves in the main steam supply lines to the emergency feedwater pump turbine, cannot be full-stroke exercised quarterly during power operation because the only full-flow path for the emergency feedwater pumps requires pumping relatively cold water into the main feed header and into the steam generators which would thermal shock the feedwater piping and nozzles, possibly resulting in its premature failure.
The steam flow to the turbine would not be sufficient to full-stroke exercise these check valves when the pump is tested quarterly in a Seabrook SSER 6 57 Appendix S
i l
1 recirculation flow path. These valves will be partial-stroke exercised quarterly during pump testing and will be full-stroke exercised during i plant cooldown to cold shutdown or heat-up from cold shutdown when there is sufficient steam available to supply the turbine and the temperature variation will not result in thermal shock to system components.
- 2. FEEDWATER SYSTEM 2.1 Category B Valves FW-V30, V39, V48, and V57, the main feedwater isolation valves, cannot be full-stroke exercised quarterly during power operations because closing any of these valves would stop feedwater flow to its associated steam generator which could result in a plant shutdown. These valves will be partial-stroke exercised quarterly during power operations and full-stroke exercised during cold shutdowns and refueling outages.
2.2 Cateaory C Valves FW-V330, V331, V332, and V333, the raain f eedwater header check valves, cannot be exercised quarterly during power operations because it would require securing feedwater flow to the steam generators which would result-in loss of steam generator level control which could cause a plant shutdown. These valves will be full-stroke exercised during cold shutdowns and rafueling outages. ,
' FW-V76, V82, V88, and V94, the check valves in the emergency feedwater lines to the main feedwater headers, cannot be exercised quarterly during power operations because to exercise these valves with flow would require pumping relatively cold emergency feedwater into the main feedwater header and the steam generator which could thermal shock these components and result in their premature failure. These valves will be full-stroke i exercised during cold shutdowns and refueling outages.
Seabrook SSER 6 58 Appendix S
- 3. CONTAINMENT PURGE SYSTEM 3.1 Cateaory A Valves CAP-V1, V2, V3, and V4, containment purge system supply and exhaust containment isolation valves, cannot be exercised quarterly during power operations'because these valves are locked closed containment isolation-valves that are required to remain closed during power operations by the plant Technical Specifications. These valves will be full-stroke exercised during cold shutdowns and refuell'ng outages.
- 4. REACTOR COOLANT SYSTEM 4.l'. Cateaory A Valves l RC-V22, V23, V87, and V88, the residual heat removal suction valves from.the reactor coolant system hot legs, cannot be exercised quarterly during power operations because these valves have system interlocks which prevent the valves from opening when RCS pressure is above 400 psig to prevent overpressurization of the RHR system piping. These valves will be full-stroke exercised during cold shutdowns and refueling outages.
4.2 Cateaory B Valves f Valve RC-PCV456A and PCV456B, the pressurizer PORVs, will be exercised during cold shutdowns. This exercising frequency is consistent with the NRC guidelines explained in Section 3.1.10 of this report.
- 5. RESIOUAL HEAT REMOVAL SYSTEM 5.1 Cateaory A/C Valves RH-V15, V29, V30, and V31, the check valves in the RHR to RCS cold leg injection lines, cannot be exercised quarterly during power operations because the only flow path through these valves requires pumping into the Seabrook SSER 6 59 Appendix S
l i
RCS and the RHR pumps discharge pressure is lower than normal operating RCS pressure. These valves will be full-stroke exercised during cold shutdowns and refueling outages.
5.2 Category B Valves RH-V14 and V26, the isolation valves in the RHR injection flow paths to the RCS cold legs, cannot be exercised quarterly during power operations b'e cause Seabrook Technical Specifications require that these valves remain open with power removed from their operators during power operations.
These valves will be exercised during cold snutdowns and refueling outages.
RH-V32, and V70, the RHR to RCS hot leg injection lines isolation valves, cannot be exercised quarterly during power operations because these valves are required to remain closed with power removed from their operators during power operations by the plant Technical Specifications.
These valves will be full-stroke exercised during cold shutdowns and refueling outages.
RH-V21 and V22, the isolation valves in the RHR headers cross connect line, cannot be exercised quarterly during power operations because if a LOCA occurred during testing accompanied by a failure of one of the emergency diesel generators, then this ECCS subsystem might not be able to supply cooling water to more than one unfaulted reactor coolant system cold leg. These valves will be full-stroke exercised during cold shutdowns and refueling outages.
5.3 Category C Valves RH-V4 and V40, the RHR pump discharge check valves, cannot be full-stroke exercised quarterly during power operations because the only full-flow path requires injection into the RCS and the RHR pumps cannot overcome normal operating RCS pressure. These valves will te partial-stroke exercised quarterly during the RHR pump tests which establish flow through the minimum flow recirculation lines. These valves will be full-stroke exercised during cold shutdowns and refueling outages.
Seabrook SSER 6 60 Appendix 5
- 6. HIGH HEAD SAFETY INJECTION SYSTEM 6.1 Category B Valves SI-V93, the isolation valve in the minimum recirculation flow path for the safety injection pumps cannot be exercised quarterly during power operations because if this valve failed closed during testing it could render an entire safety system inoperable. Both safety injection pumps could be damaged if they were started and ran at shutoff head with their minimum recirculation lines isolated. This valve will be full-stroke exercised during cold shutdowns and refueling outages.
CBS-V47, CBS-VS1, and SI-v114, the isolation valves for the safety injection pump suctions from the RWST and safety injection pump discharge to the RCS cold legs, cannot be exercised quarterly during power operations
! because these valves are required to be open with power removed from their operators during power operations by Seabrook Technical Specifications.
These valves will be full-stroke exercised during cold shutdowns and refueling outages.
SI-V77 and V102, the safety injection to the RCS hot legs isolation valves, cannot be exercised quarterly during power operations because during power operations these valves are required to remain closed with power removed from their operators by the plant Technical Specifications.
These valves will be full-stroke exercised during cold shutdowns and refueling outages.
- 7. CHEMICAL AND VOLUME CONTROL SYSTEM 7.1 Category A Valves CS-V149 and V150, the letdown line isolation valves, cannot be full-stroke exercised quarterly during power operations because closing these valves during power operations could cause a loss of pressurizer level control which could cause a plant trip. These valves will be full-stroke exercised during cold shutdowns and during refueling outages.
Seabrook SSER 6 61 Appendix S
7.2 Category B Valves CS-V142 and V143, the charging header to the regenerative heat
. exchanger isolation valves, cannot be exercised quarterly during power operations'because closing these valves during plant operations could result in the loss of pressurizer level control which could cause a plant trip. These valves will be full-stroke exercised during cold shutdowns and during refueling outages.
CS-LCVil2D and LCVll2E, the isolation valves in the charging pump suction lines from the RWST, cannot be exercised quarterly during power
~
operations because opening these valves would align the charging pump suction to the RWST which would result in an increase in the boric acid concentration of the water being pumped into the RCS; this would result in a negative reactivity addition to the reactor which could cause a plant shutdown. These valves will be exercised during cold shutdowns and refueling outages.
CS-LCVil2B and LCVll2C, the isolation valves in the line from the volume control tank to the charging pump suctions, cannot be exercised
( quarterly during power operations because closing these valves would isolate the charging pump suction which would result in a loss of charging flow with a resultant loss of pressurizer level control which could lead to a plant trip. The use of alternate pump suction sources could result in the injection of water with higher concentrations of boric acid into the l
RCS which could cause a plant shutdown. These valves will be full-stroke l exercised during cold shutdowns and refueling outages.
CS-V426, the isolation valve in the line from the boric acid tanks to
( the suction of the charging pumps, cannot be exercised quarterly during power operations because opening this valve could increase the boric acid concentration of the water being pumped into the RCS which would add negative reactivity to the reactor and could possibly result in a plant shutdown. This valve will be full-stroke exercised during cold shutdowns and refueling outages.
l l
Seabrook SSER 6 62 Appendix S
7.3 Category C Valves CS-V427 and RMW-V119, check valves in the lines from the boric acid tanks and blender to the suctions of the charging pumps, cannot be exercised quarterly during power operations because establishing flow through these valves would increase the boric acid concentration of the water being pumped into the RCS which would add negative reactivity to the reactor and could possibly result in a plant shutdown. These valves will be full-stroke exercised during cold shutdowns and refueling outages.
i
- 8. COMPONENT COOLING WATER SYSTEM 8.1 Catecory A Valves l
CC-V57, V121, V122, V168, V175, Vl?6, V256, and V257, containment isolation valves in the component cooling supply and return lines to equipment inside containment including the reactor coolant pump bearing oil coolers and motor air coolers, cannot be exercised quarterly during power operations because closing these valves would isolate cooling water to the cooled components which could lead to equipment damage and possibly result in a plant shutdown. These valves will be full-stroke exercised during cold shutdowns and refueling outages.
8.2 Category B Valves CC-TV2271-1. TV2271-2, TV2171-1, and TV2171-2, the component cooling water temperature control valves, cannot be full-stroke exercised quarterly during power operations because full-stroke exercising these valves requires isolating one train of component cooling which could isolate cooling water to vital ecmponents and result in equipinent damage. These valves will be full-stroke exercised during cold shutdowns and refueling l outages.
Seabrook SSER 6 63 Appendix S
CC-V341, V426, V427, V447, and V448, isolation valves in component cooling water flow loops, cannot be exercised quarterly during power operations because closing these valves would isolate cooling water to several heat-exchangers which could result in overheating of the cooled equipment and could cause that equipment to be damaged. These valves will be full-stroke exercised during cold shutdowns and refueling outages.
Seabrook SSER 6 64 Appendix S
APPENDIX T CONFORMANCE TO GENERIC LETTER 83-28, ITEM 2.1 (PART 1), EQUIPMENT CLASSIFICATION (RTS COMPONENTS)
I l
l l
i l
- ts Seabrook SSER 6 Appendix T l
EGG-NTA-7236 CONFORMANCE TO SENERIC LETTER 83-28 ITER 2.1 (PART 1) EQUIPMENT CLASSIFICATION (RTS COMPONENTS)
ROSINSON 2 SALER 1 AND 2 SAN ON0FRE 1 SEABROOK 1 AND 2 R. Haroldsen l'
Published May 1986 EG&G Idaho, Inc.
Idaho Falls, Idaho 83415 Prepared for the U.S. Nuclear Regulatory Commission Washington. 0.C. 20555 Under DOE Contract No. DE-AC07-76ID01570 FIN No. 06002 and D6002 Seabrook SSER 6 Appendix T
r' ABSTRACT This EG&G Idaho, Inc report provides a review of the submittals from selected operating and applicant Pressurized Water Reactor (PWR) plants for conformance to Generic Letter 83-28. Item 2.1 (Part 1). The following plants ~are included in this review.
Plant Name Docket Number TAC Number
~
Robinson 2 50-261 52875 Salem 1 50-272 52876 Sales 2 ,
50-311 52877 Saa Onofre 1 50-206 52878 Seabrook 1 50-443 OL seabrook 2 50 444 OL Seabrook SSER 6 fi Appendix T
FOREWORD This report is supplied as part of the program for evaluating licensee / applicant conformance to Generic Letter 83-28, " Required Actions Based on Generic Implications of Salem ATWS Events." This work is being conducted for the U.S. Nuclear Regulatory Comission. Office of Nuclear Reactor Regulation, Division of PWR Licensing-A, by the EG46 Idaho, Inc.
l The U.S. Nuclear Regulatory Commission funded this work under the i authorization 8&R 20-19-10-11-3 and 20-19-40-41-3, FIN Nos. D6001 and 06002.
I 1
l Seabrook SSER 6 iii Appendix T
CONTENTS ABSTRACT .............................................................. 11 FOREWORD .............................................................. 111
- 1. INTR 000CTION AND
SUMMARY
......................................... 1
- 2. PLANT RESPONSE EVALUATIONS ....................................... 3 2.1 Robinson 2 ................................................. 3 2.2 Conclusion ................................................. 3 2.3 ' Salem 1 and 2 .............................................. 4 2.4 Conclusion ................................................. 5 2.5 San Onofre 1 ............................................... 5 2.6 Conclusion ................................................. 6 2.7 Seabrook 1 and 2 ........................................... 6 2.8 Conclusions ................................................ 6
- 3. GENERIC REFERENCES ............................................... 8 Seabrook SSER 6 iv Appendix T
- 1. INTRODUCTION AND
SUMMARY
On f ebruary 25, 1983, both of the scram circuit breakers at Unit 1 of the Salem Nuclear Power Plant failed to open upon an automatic reactor trip signal from the reactor protection system. This incident was ter.minated manually by the operator about 30 seconds after the initiation of the automatic trip signal. The failure of the circuit. breakers was determined to be related to the sticking of the undervoltage trip attachment. Prior to the incident, on February 22, 1983, an automatic trip signal was generated at Unit 1 of the Salem Nuclear Power Plant based on steam generator low-low level during plant startup. In this case, the reactor was tripped manually by the operator almost coincidentally with the automatic trip.
Following these incidents, on February 28, 1983, the NRC Executive Director of Operations (E00), directed the staff to investigate and report on the generic implications of these occurrences at Unit 1 of the Salem Nuclear Power Plant. The results of the staff's inquiry into the generic l implications of the Salem Unit 1 incidents are reported la NUREG-1000, l " Generic Implications of the ATWS Events at the Salem Nuclear Power l Plant."1 As a result of this investigation, the Consnission (NRC) l requested (by Generic Letter 83-28, dated July 8, 1983) all licensees of operating reactors, applicants for an operating license, and holders of construction permits to respond to generic issues raised by the analyses of these two ATWS events.
This report is an evaluation of the responses submitted from a group of similar pressurized water reactors for Item 2.1 (Part 1) of Generic Letter 83-28.
The results of the reviews of several plant repponses are reported on in this document to enhance review efficiency. The specific plants reviewed in this report were selected based on the similarity of plant design and convenience of review. The actual documents which were reviewed Seabrook SSER 6 1 Appendix T
for each evaluation are listed at the end of each plant evaluation. The generic documents referenced in this report are listed at the end of the report.
Part 1 of Item 2.1 of Generic Letter 83-28 requires the licensee or applicant to confirm that all reactor trip system components are identified, classified, and treated as safety-related as indicated in the following statement:
Licensees and applicants shall confirm that all components whose functioning is required to trip the reactor are identified as safety-related on documents, procedures, and information handling systems used in the plant to control safety-related activities, including maintenance, work orders, and parts replacement.
Seabrook SSER 6 2 Appendix T
- 2. PLANT RESPONSE EVALUATIONS 2.1 Robinson 2, 50-261. TAC No. 52875 The licensee for Robinson 2-(Carolina Power and Light Co.) pr,,ovided a response to Item 2.1 (Part 1) in a submittal dated November 7,1983. The section of this submittal identified as response to Item 2.1 did not include sufficient information to evaluate compliance. This evaluation of the licensees response to Item 2.1 (Part 1) is based on information provided in the licensee's response to Item 2.2.1 in a subsequent section of the same submittal.
That section of the submittal states that a Q-list has been developed.
to identify safety-related structures, systems and components. It also .
states that the Q-list includes plant items required to make and hold the reactor sub-critical during the occurrence of frequent, infrequent and limiting plant process conditions. We take this to mean that the components required to trip the reactor have been designated safety-related. The submittal provides a description of the administrative procedures used to control safety-related activities.and states that maintenance, surveillance and procurement activities are controlled by the Q-list which determines those components which require additional controls.
2.2 Conclusions l
Based on the review of the licensee's submittal, we find that the components necessary to perform reactor trip are classified as safety-related and that activities relating to safety-related components are controlled by procedures which reflect the necessary requirements for handling safety-related components. We, therefore, find that the licensee's responses meet the requirements of Item 2.1 (Part 1) of Generic Letter 83-28 and are acceptable.
Seabrook SSER 6 3 Appendix T
Reference
- 1. Letter, A. 8. Cutter, Carolina Power and Light Co., to D. G. Eisenhut, NRC, November 7, 1983.
2.3 Salem 1 and 2. 50-272/311. TAC Nos. 52876/52877 The licensee for Salem 1 and 2 (Public Service Electric and Gas Co.)
provided relevant information for Item 2.1 (Part 1) in a series of submittals. Submittals dated March 8. March 14 and April 17, 1983 described the licensee's program for upgrading the equipment classification system at Salem 1. The staff had found that problems with the Master Equipment List (MEL) at Salem highlighted the need for reliable administrative controls over the development and use of components lists for determining the safety-classification of equipment. There had existed considerable confusion as to the states, use, and procedural requirements associated with the MEL. As a result some activities involving safety-related equipment were conducted which did not utilize controlled QA procedures.
The submittals described a program to review the MEL to determine the completeness, validate equipment classification and to reissue the MEL as a controlled document. The Q-list is the subset of the MEL which identifies activities, services, structures, components and systems to which the safety-related classification applies for work orders and station procurement documents. This upgrading program was projected for completion by May 1983. The April 7,1983 submittal stated that the MEL had been reviewed and reissued for several systems including the reactor protection system.
This work was said to be completed on March 24, 1983 and included upgrading of procurement, work orders and other procedures relating to classified equipment. The review was to be extended to all systems and completed by May 1983. While these earlier submittals referred only to the Salem 1 plant, later submittals dated April 8 and May 31, 1983 confirmed that the program for Salem 2 had also been similarly upgraded.
Seabrook SSER 6 4 Appendix T
2.4 Conclusion Based on the review of the licensee's submittals, we find that the components necessary to perform reactor trip are classified as safety-related and that activities relating to safety-related components are controlled by procedures which reflect the necessary requirements for handling safety-related components. We, therefore, find that the licensee's responses meet the requirements of Items 2.1 (Part 1) of Generic Letter 83-28 and are acceptable.
References
- 1. Letter, R. A. Uderitz, Public Service Electric and Gas Co., to R. A. Starostecki, NRC, March 8,1963.
- 2. Letter, R. A. Uderitz, Public Service Electric and Gas Co. to
- 0. G. Eisenhut, NRC, March 14, 1983.
- 3. Letter, R. A. Uderitz, Public Service Electric and Gas Co.. to D. G. Eisenhut, NRC, April 7, 1983.
- 4. Letter, R. A. Uderitz, Public Service Electric and Gas Co., to D. C. Eisenhut, NRC, April 8, 1983.
- 5. Letter, R. A. Uderitz, Public Service Electric and Gas Co.. to D. G. Eisenhut, NRC, May 31, 1983.
2.5 San Onofre Unit 1. 50-206. TAC No. 52872 The licensee for San Onofre Unit 1 (Southern California Edison Co.)
provided a response to Item 2.1 (Part 1) in a submittal dated November 28, 1983. The submittal states that all components whose functioning is required to trip the reactor are classified as safety-related on the Q-list. All documents, procedures and information handling systems used to control safety-related activities, including maintenance, work orders, and parts replacement, are based on the Q-list.
The Q-list is Seabrook SSER 6 5 Appendix T
l consulted during development of plant documents to determine the safety classification of each activity to be performed.
2.6 Conclusion Based on the review of the licensee's submittal, we find that the components necessary to perform teactor trip are classified as safety-related and that activities relating to safety-related components are controlled by procedures which reflect the necessary requirements for handling safety-related components. We, therefore, find that the licensee's response meets the requirements of Items 2.1 (Part 1) of Generic Letter 83-28 and is acceptable.
Reference
- 1. Letter, M. O. Medfc.rd, Southern California Edison Co., to D. M. Crutchfield, NRC, November 28', 1983.
2.7 Seabrook 1 and 2. 50-443/444 The applicant for Seabrook 1 and 2 (Public Service Co. of New Hampshire) provided responses to Item 2.1 (Part 1) in submittals dated November 4, 1983 and August 22, 1985. In the first submittal the applicant stated that the reactor trip system components would be identified as safety-related and that the identification would be incorporated into administrative system to control safety-related activities. This effort was to be completed 3 months prior to fuel load. In the August 22, 1985 submittal the applicant confirn,0) that the classification of safety-related reactor trip system components had been completed and refer,eoced in design, operating and maintenance documents.
2.8 Conclusions Based on the review of the applicant's submittals we find that the components necessary to perform reactor trip have been classified safety-related and that the component classification is appropriately Seabrook SSER 6 6 Appendix T
t referenced in plant documents and include the necessary requirements for handling safety-related components. We, therefore, find that the applicant's responses meet the requirements of Item 2.1 (Part 1) of Generic Letter 83-28 and are acceptable.
References
- 1. Letter, J. De Vincentis, Public Service Company of New Hampshire, to G. W. Knighton, NRC, November 4, 1983.
- 2. Letter, G. S. Thomas, Public Service Company of New Hampshire, to G. W. Knighton, NRC, August 22, 1985.
Seabrook SSER 6 7 Appendix T
- 3. GENERIC REFERENCES
- 1. Generic Implications of ATWS Events at the Salem Nuclear Power Plant, NUREG-1000, Volume 1 April 1983; Volume 2. July 1983.
- 2. NRC Letter, O. G. Eisenhut to all Licensees of Operating Reactors, Applicants for Operating License, and Holders of Construction Permits,
" Required Actions Based on Generic Implications of Salem ATWS Events (Generic Letter 83-28)," July 8, 1983.
4 Seabrook SSER 6 8 Appendix T
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BIBUOGRAPHIC DATA SHEET 3 TITLE AND SueTITLE
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4 HECIPiE NT $ ACCES$10N NUMBE R Safety Evaluatio Report related to the operation of /
Seabrook Station Units 1 and 2
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NTH YEAM ACTOBER 1986 6 AUTHOHise DATE REPORT ISSUED MONYM VEAR OCTOBER 1986 9 PROJECTrT ASE/ WORK UNIT NUMBER 3 PERf OHMING ORGANil ATION NaME AND MAILING AOL SS tractude I,a Coms Division of PWR Licensing-A Office of Nuclear Reactor Regu tion io ei~ NuYSEa
. U. S. Nuclear Regulatory Conuniss n Washington, D. C. 20555 11 $PONSORING ORG AN12ATION N AME AND MA'LsNG ADDRESS flacfwde / Codel I ?a TYPE OF REPORT Same as 8. above Technical I20 PERIOO COVERED fiaciasere de,esJ July 1986 - October 1986 13 $UPPLE MENTARY NOTE S -
Docket Nos. 50-443 and 50-444 14 ASS 1RACT (100 words or sesas Supplement No. 6 to the Safety Evaluation po related to operation of the Seabrook Station, Units 1 and 2 addresses items re ting o the issuance of a fuel loading and precriticality testing license for Unit f . 1.
The report relates to the application f ed by the Public Service Company of New Hampshire for licenses to operate e Seabrook 'tation, Units 1 and 2 located in Rockingham County, New Hampshire. '
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