ML20133F824
| ML20133F824 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 08/05/1985 |
| From: | NRC |
| To: | |
| References | |
| NUDOCS 8508080453 | |
| Download: ML20133F824 (242) | |
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bh ABSTRACT Supplement No. 2 to the Safety Evaluation Report on the application filed by Gulf States Utilities Company as applicant and for itself and Cajun Electric Power Cooperative, as owners, for a license to operate River Bend Station has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Commission. The facility is located in West Feliciana Parish, near St. Francisv111e, Louisiana. This suppleraent reports the status of certain items that had not been resolved at the time the Safety Evaluation Report was published.
1 l{t0' l$ DSb o r RIVER BENO SSER 2 iii 8500080453 850805 PDR ADOCK 05000458 E PDR
6 CONTENTS y Pagg ABSTRACT ................................................................. iii 1
, INTRODUCTION AND GENERAL DISCUSSION ................................ 1-1 1.1 Introduction ................................... 1-1 1.5 Outstanding Issues ........................................... 1-2
- 1.6 Con f i rma to ry I s s ue s . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... . . . . . . . . . . . . . 1-2 1.7 License Conditions ........................................... ............ 1-2 2
SITE CHARACTERISTICS ............................................... 2-1 2.'2 Nearby Industrial, Transportation, and Military Facilities.... 2-1 2.2.2 Nearby Facilities .................................... 2-1 2.3 Meteorology .................................................. 2-1 2.3.3 Onsite Meteorological Measurements Program ........... 2-1 2.4 Hydrologic Engineering........................................ 2-1 2.4.3 Probable Maximum Flood on Streams and Rivers.......... 2-1 2.4.11 Cooling Water Supp1y.................................. 2-1 2.5 Geology, Seismology, and Geotechnical Engineering ............ 2-2 2.5.5 Stability of Slopes .................................. 2-2 3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, EQUIPMENT, AND COMPONENTS . 3-1 3.6 Protection Against Dynamic Effects Associated With the Postulated Rupture of Piping ................................. 3-1 3.6.2 Determination of Rupture Location and Dynamic Effects Associated With the Postulated Rupture of Piping ..... 3-1 3.9 Mechanical Systems and Components ............................ 3-1 3.9.2 Dynamic Testing and Analysis of Systems, Components, and Equipment ........................................ 3-1 3.9.3 ASME Code Class 1, 2, and 3 Components, Component Supports, and Core Support Structures................. 3-1 3.9.6 Inservice Testing of Pumps and Valves ................ 3-3 3.10 Seismic and Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment .......................... 3-3 RIVER BEND SSER 2 v
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[, 3.10.1 Seismic and Dynamic Quali fication . . . . . . . . . . . . . . . . . . . 3-3
[1 3.10.2 Pump and Valve Operability .......................... 3-5 j-4 REACTOR ........................................................... 4-1 1
't 4.2 Fuel System Design .......................................... 4-1 4.2.3 Design Evaluation ................................... 4-1 l
1 4.4 Thermal and Hydraulic Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 4.4.4 The rmal-Hydraul ic S tabil i ty . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 6
ENGINEERING ....................................................... 6-1 I 6.2 Containment Systems ......................................... 6-1 6.2.1 Containment Functional Design ....................... 6-1 6.2.2 Containment Heat Removal System ..................... 6-10 6.2.3 Secondary Containment Functional Design ............. 6-10 6.2.4 Containment Isolation System ........................ 6-11 6.2.5 Combustible Gas Control in Containment .............. 6-13 6.2.6 Containment Leakage Testing ......................... 6-14
- 6. 3 . Eme rgency Core Cool ing Sys tem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-15 6.3.3 Performance Evaluation .............................. 6-15 .
7 INSTRUMENTATION AND CONTROLS ...................................... 7-1 7.2 Reactor Protection System ................................... 7-1 7.2.2 Specific Findings ................................... 7-1 7.3 Engineered Safety Features Systems .......................... 7-2 7.3.2 Speci fi c F i ndi ngs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-2 7.4 Systems Requi red for Safe Shutdown . . . . . . . . . . . . . . . . . . . . . . . . . . 7-3 7.4.2 Specific Findings ................................... 7-3 7.5 Information Systems Important to Safety ..................... 7-4 7.5.2 Specific Findings ................................... 7-4 7.6 Interlock Systems Important to Safety ....................... 7-5 7.6.2 Specific Findings ................................s... 7-5 ,
7.7 Control Systems ............................................. 7-6 RIVER BEND SSER 2 vi
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, Page 1 7.7.2 Specific Findings ................................... 7-6
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ELECTRIC POWER SYSTEMS ............................................ 8-1 q 8.3 Onsite Emergency Power Systems .............................. 8-1 8.3.1 AC Power Systens .................................... 8-1 8.3.2 DC Power Systems .................................... 8-1 8.4 Other Electrical Systems and Requirements for Safety ........ 8-1 8.4.5 Physical Identification and Independence of Redundant Safety-Related Electrical Systems ......... 8-1 8.4.6 Non-Safety Loads on Emergency Sources ............... 8-3 8.4.7 Flooding of Electrical Equipment .................... 8-5 8.4.9 Cable Derating for Spacin in Accordance With IPCEA ..............g............................ 8-5 9
AUXILIARY SYSTEMS ................................................. 9-1 9.1- Fuel Storage and Handling ................................... 9-1 E
9.1. 5 Overhead Heavy Load Handling System ................. 9-1 9.2 Water Systems ............................................... 9-1 9.2.2 Reactor Plant Component Cooling Water System (Reactor Auxiliary Cooling Water System) ............ 9-1 9.3 Process Auxiliaries ......................................... 9-2 9.3.2 Process Sampling System ............................. 9-2 9.4 Air Conditioning, Heating, Cooling, and Ventilation Systems ..................................................... 9-2 9.4.5 Engineered Safety Feature Ventilation Systems ....... 9-2 9.5 Othe r Auxi l i a ry Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-2 9.5.2 Communication Systems ............................... 9-2 9.5.3 Lighting Systems .................................... 9-3 9.5.4 Emergency Diesel Engine Fuel Oil Storage and Tran s fe r Sys tem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-4 9.5.5 Emergency Diesel Engine Cooling Water System ........ 9-6 9.5.6 Emergency Diesel Engine Starting System ............. 9-8 9.5.7 Emergency Diesel Engine Lubricating Oil System ...... 9-10 10 STEAM AND POWER CONVERSION SYSTEM ....................:............ 10-1 :
RIVER BEND SSER 2 vii
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CONTENTS (CONTINUED) 9 1 10.4 O the r Fea tu re s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-1 a
10.4.6 Condensate Filter Demineralizer System .............. 10-1
-1 h t 11 RADIOACTIVE WASTE MANAGEMENT ...................................... 11-1 I
11.2 Liquid Waste Management System .............................. 11-1 11.4 Solid Waste Management System ............................... 11-1 11.5 Process and Effluent Radiological Monitoring and Sampling Systems ............................................ 11-2 l
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11.5.4 Process Monitoring and Sampling ..................... 11-2 i
,; ; 12 RADIATION PROTECTION .............................................. 12-1 12.3 Radiation Protection Design Features ........................ 12-1 12.3.2 Shielding ........................................... 12-1 12.5 Operational Radiation Protection Program .................... 12-2 12.5.1 O rgan i z a ti o n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12- 2 13 CONDUCT OF OPERATIONS ............................................. 13-1 13.1 Organizational Structure .g- Qlim+ 13-1 4 ...................................
13.1.2 Corporate Organization .............................. 13-1 13.1.3 Nucl ear Admi ni s tration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-3 13.1.4 Station Organization ................................ 13-4 13.2 Training .................................................... 13-5 13.3 Emergency Preparedness ...................................... 13-6 13.3.1 Background .......................................... 13-6 13.3.2 Emergency Plan Evaluation ........................... 13-6 13.3.3 Conclusions ......................................... 13-14 13.4 Operational Review .......................................... 13-14 13.5 Station Administrative Procedures 13-15
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13.5.2 Operatin Maintenanceg rocedures P1EgEii![........ 13-15 s' 15 TRANSIENT AND ACCIDENT ANALYSIS ................................... 15-1 1 15.9 TMIs Action Plan Re9uirements ................................ 15-1
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15.9.4 II.K.3 - Final Recommendations of Bulletins a 4 4 TaskForce..................................g0rders ......... 15-1 :
- 35. 4. 3 J3csn. E. k. I .EG B oe rss rn Alsa wee,: r, 7 Nihr a h %U~3r c nde L.Of r) s na, J
. RIVER BEND'S'SER 2 Lors obFu/u"rviii Au d'^h ;
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'l 18 HUMAN FACTORS ENGINEERING ......................................... 18-1 18.1 Human Factors Engineering Team .............................. 18-1 18.2/18.3 System and Task Analysis ..................... 18-1 18.4 The Main Control Room ............................. ......... 18-2 18.4.1 Control Room Inventory .............................. 18-2 18.4.2 Control Room S u rvey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18-2 18.4.3 As s es sment o f HED s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18-2 18.4.4 Selection of Design Improvements . . . . . . . . . . . . . . . . . . . . 18-2 18.4.5 Verification of Design Improvements ................. 18-3 18.4.6 Coordination of DCRDR With Other Activities ......... 18-3 APPENDICES A
j CONTINUATION OF CHRONOLOGY OF NRC STAFF RADIOLOGICAL REVIEW OF RIVER BEND STATION I
pt (* v 7 8 BIBLIOGRAPHY D ACRONYMS AND INITIALISMS E PRINCIPAL STAFF CONTRIBUTORS AND CONSULTANTS G
ERRATA k R_I_VER BEND STATION SkFETY EV LUA ION _BEP_0RT' E H DEMONSTRATION OF CONTAINMENT PURGE AND VENT VALVE OPERABILITY I CONTROL OF HEAVY LOADS AT NUCLEAR POWER PLANTS, RIVER BEND STATION UNIT I T CPHASG- I) 3 Y
J TECHNICAL EVALUATION REPORT OF THE DETAILED CONTROL ROOM DESIGN REVIEW FOR GULF STATES UTILITIES COMPANY RIVER BEND STATION K REVIEW 0F HUMPHREY CONCERNS FIGURES 2.1 Location of G tunnel ............................................... 2-6 6.4 Loss-of-coolant accident chronology (design-basis accident)
(revised from SER) ................................................. 6-16 13.1 River Bend Nuclear Group management structure (revised from SER) ... 13-18 RIVER BEND SSER 2 ix
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- . i TABLES Page
- ! 1.3 Listing of outstanding issues ................................ 1-3 1.4 Li sti ng of confi rmatory i s sues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 1-5 l 1.5 Listing of license conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... ... 1-9 2.1 Water l evel s in Unit 2 excavation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-7 j 2.2 Minimum factors of safety for Unit 2 excavation slopes . . . . . . . . . . . . . 2-7 3.1 SQRT findings on seismic and dynamic qualification ................. 3-8 3.2 PVORT findings on operability qualification of pumps and valves .... 3-13 i
6.2 RiverBendLOCAanalysisresults(revisedfromSER)................6-1f7 X' 9.1 Conformance to NUREG/CR-0660 recommendations (revised from SER)..... 9-12 s
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1 INTRODUCTION AND GENERAL DESCRIPTION
- i 1.1 Introduction O
7j In May 1984, the Nuclear Regulatory Commission (NRC) staff issued its Safety
.? Evaluation Report (SER) (NUREG-0989) on the application filed by Gulf States 2.} Utilities Company (applicant or GSU), acting on behalf of itself and for Cajun
- Electric Power Cooperative (CEPCO), for a license to operate the River Bend L .' Station, Docket No. 50-458. In the SER, the staff identified items that were l not yet resolved with the applicant. Supplement No. 1 (SSER 1) was issued in
.i October 1984 to provide the staff evaluation of open items that have been re-solved, and to report on the status of all open items. Supplement No. 2 (SSER 2) i' is beingfissued to provide more recent information regarding resolution of other open and' confirmatory items and license conditions identified in the SER. In
' addition, SSER 2 has four reports appended to it: (1) the staff's "Demonstra-tion of Containment Purge and Vent Valve Operability," (2) EG&G's " Control of Heavy Loads at Nuclear Power Plants (River Bend Station Unit 1)," (3) Lawrence Livermore National Laboratory's " Technical Evaluation Report of the Detailed
' Control Room Design Review for Gulf States Utilities Company River Bend Station,"
and (4) the staff's " Review of Humphrey Concerns."
1 Each of the following sections and appendices is numbered the same as the corre-sponding SER section or, appendix that is being updated. Appendix A continues the chronology of the staff's actions related to the processing of the River i
Bend application. Letters between the applicant and the NRC staff are listed
'here in chronological order. Appendix B lists the references cited in this report.* Appendix D is a list of acronyms and initialisms used herein, and Appendix E is a list of the principal staff members and consultants who con-i
' tributed to this supplement. Appendix G contains the errata to the SER. Appen-dices H, I, and J contain, respectively, (1) the staff report on purge and vent valve operability, (2) the EG&G report on control or heavy loads, and (3) the 4
Lawrence Livermore report on the detailed control room design review, all three specific to River Bend. Appendix K contains the staff's review of concerns voiced by John Humphrey.
CohiesofthisSERsuppplementareavailableforinspectionattheNRCPublic Do'cument Room at 1717 H' Street, N.W., Washington, D.C., and at the Government
! Documents Department, Louisiana State University, Baton Rouge, Louisiana.
Copies are also available for purchase from the sources indicated on the inside front cover.
The NRC Project Manager assigned to the operating license application for River Bend is Stephen M. Stern. Mr. Stern may be contacted by telephoning him at (301)492-8349 or by writing to the following address:
s
- Availability of all material cited is described on the inside front cover of this report. :
l River Bend SSER 2 1-1
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'Jj Mr. Stephen M. Stern Division of Licensing U.S. Nuclear Regulatory Commission _
Washington, D.C. 20555 S 1. 5 Outstanding Issues
-[ In the SER the staff identified certain outstanding issues that had not been resolved with the applictat. The status of these issues is listed in an updated version of Table 1.3 whi :h follows. The sections of this supplement where these issues are discussed are indicated. If the staff review is completed for an issue, the item has the notation " Closed." As outstanding issues are resolved, they will be discussed in subsequent supplements to the SER.
Since the first SER supplement was issued, the staff has identified additional outstanding issues. Issues 19, 21, and 22 were identified by the staff during the review of the applicant's FSAR Amendments 16 through 19. For clarity in discussion and evaluation, issues 5 and 10 had issues subdivided from them.
These subdivisions do not represent new issues. Furthermore, in the course of s
review of the license application, the staff identified a new issue, Outstanding Issue 20, in the human factors discipline. The staff will complete its review of these items before the operating license is issued and will report resolution of each of these items in supplements to the SER.
1.6 Confirmatory Issues In its SER, the staff identified confirmatory items that required additional in-formation to confirm preliminary conclusions. Since the first SER supplement was issued, the staff has identified additional confirmatory items. Items 65, 70, and 71 were identified by the staff during the review of the applicant's FSAR Amendments 16 through 19. Items 66 through 69 are new human factors items.
Items 72 through 76 are confirmatory items identified during the staff analysis of Outstanding Issues 14, 15, and 16. Confirmatory Items 77 and 78 were identi-fied when the staff evaluated the solid waste management system and the contain-ment system, respectively. Confirmatory Item 79 was identified in a staff inspection. The status of these issues is listed in an updated version of Table 1.4 which follows and is discussed further in the sections of this sup-plement as indicated. If the staff review is completed for an issue, the item has the notation " Closed." However, if staff review has determined that the item .is resolved only for the initial license, the item has the notation
" Closed for initial license."
i 1. 7 License Conditions In Section 1.7 of the SER, the staff identified eleven license conditions.
These include several issues that must be resolved by the applicant before ex-ceeding 5% of rated power, and other longer term resolution issues that will be cited in the operating license issued, to ensure that NRC requirements are met during plant operation. Four license conditions have been resolved.
The current status of license conditions is in the updated version of Table 1.5.
River Bend SSER 2 1-2
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-j f Table 1.3 Listing of outstanding issues
. Issue Status I SER Section(s)
(1) Hydrostatic loading Closed (SSER 1)
(2) Moderate-energy line break Under review
.l (3) High-energy line break Under review (4) Inservice test program (including Closed (SSER 2) 3.9.6
- RCS pressure boundary valve leakage)
(5) Equipment qualification (a) Seismic, mechanical pump and Awaiting information valve operability (b) Environmental qualification Awaiting information of equipment P
(6) Preservice inspection program Awaiting information *
(7) Containment loads Closed (SSER 2) 6.2.1.8.3 (8) ECCS LOCA analysis (II.K.3.31) Closed (SSER 2) 15.9.4, 6.3.3
'(9) Bypassed and inoperable status Under review (10) Emergency diesel generators (a) Electrical loads Under review (b) Qualification of TDI diesel Under review generators (c) Auxiliary support systems Closed (SSER 2) 9.5.4.1, 9.5.5, 9.5.6, 9.5.6.2 4
(11) Submergence of electrical equipment Closed (SSER 2) 8.4.7 (12) Heavy-load handling system Closed (SSER 2) 9.1. 5 (13) Safe / alternate shutdown Awaiting information (14) Communications systems -Closed (SSER 2)* 9.5.2.1 (15) Lighting systems Closed (SSER 2)* 9.5.3 4
(16) HPCS diesel generator Closed (SSER 2)* 9.5.4.1, 9.5.5, 9.5.6, 9.5.6.2
- Became confirmatory item. -
River Bend SSER 2 1-3
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I Table 1.3 (Continued)
Issue Status SER Section(s)
(17) Fuel oil storage Closed (SSER 2) 9.5.4.2 (18) Emergency preparedness Closed (SSER 2) 13.3 (19) Separation of electric circuits Closed (SSER 2)* 8.4.5 i
(20) Human factors issues (a) Safety parameter display system Under review (b) Control room survey Under review (c) Resolution of HEDs Under review (21) Auxiliary systems ** '
(a) Standby service water system Awaiting information (b) Standby liquid control systems Under review (c) Low pressure interface leakage Under review (22) Starting voltage for Class IE Under review **
motors
- Became confirmatory item.
- New issue opened as a result of applicant's FSAR Amendments 16-20.
River Bend SSER 2 1-4
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j Table 1.4 Listing of confirmatory items
- Issue Status SER Section(s)
(1) West Creek sediment removal Closed (SSER 2) 2.4.3.3 (2) Ultimate heat sink Closed (SSER 1)
(3) Slope stability Closed (SSER 2) 2.5.5.1, 2.5.5.2 (4) Pipe failure modes and check Review continuing 3.6.2 valve stress analysis (SSER 2)
(5) Annulus pressurization Closed (SSER 2) 3.9.2.4 (6) Minimum wall thickness Closed (SSER 1)
(7) Thermal and anchor displacement Closed (SSER 2) 3.9.3.3 loads (8) Fuel rod mechanical fracturing Closed (SSER 2) 4.2.3.2 (9) Fuel assembly structural damage Closed (SSER 2) 4.2.3.3 (10) Post-irradiation surveillance Closed (SSER 1)
(11) LOCTVS/ CONTEMPT-LT 28 computer Closed (SSER 2) 6.2.1 codes (12) Reactor vessel cooldown rate Closed (SSER 2) 6.2.1.7 (13) SRV discharge testing Review continuing 6.2.1.8.3 (14) Mark III-related issues Closed (SSER 2) 6.2.1.9 (15) Containment repressurization Closed (SSER 2) 6.2.1 (16) Inleakage limit Closed (SSER 1)
(17) ECCS test return line design Closed (SSER 1)
(18) Containment purge valves Closed (SSER 2) 6.2.4 (19) Hydrogen control Closed for initial 6.2.5, 15.9.2 license (SSER 2)
(20) PVLCS leakage Closed (SSER 2) 6.2.6.3 (21) Electrical and instrumentation and Under review control diagrams (22) Routing of circuits and sensors Closed (SSER 2) 7.2.2.1 River Bend SSER 2 1-5
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,! Table 1.4 (Continued)
Issue Status SER Section(s) y (23) Instrumentation setpoints Under review (24) RPS power supply protection Under review l (25) RPS and ESF channel separation Under review (26) Isolation devices Under review (27) Reactor mode switch Closed (SSER 2) 7.2.2.
(28) ADS actuation Closed (SSER 2) 7.3.2.3 (29) ESF reset controls Under review (30) Initiation of ESF suppo'rt systems Under review (31) Instrumentation and control power Under review bus loss (32) RCIC system Under review (33) Standby liquid control system Closed (SSER 2) 7.4.2.3 (SCLC)
.(34) Postaccident monitoring Under review instrumentation (35) Temperature effects on level Closed (SSER 2) 7.5.2.5 measurements (36) High/ low pressure interlocks Under review (37) End of cycle recirculation Closed (SSER 2) 7.6.2.4 pump trip (38) NMS and RCIS isolation Under review (39) Rod pattern control system Under review
. microprocessors (40) ORMS Under review (41) High-energy line break control Under review j system failures (42) Multiple control system failures Under review 4
(43) Emergency Response Information Closed (SSER 2) 7.7.2.3 -
System (ERIS) '
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Table 1.4 (Continued)
Issue Status SER Section(s)
(44) LPCS/RHRA pump procedures Under review
- (45) EPA /RPS motor generator set Closed (SSER 2) 8.3.1, 8.4.6 interconnection (46) Second level undervoltage pro- Awaiting information tection relay setpoint (47) Verification of test results for Awaiting information station electric distribution system voltage (48) Safety cable identification Closed (SSER 2) 8.4.5 (49) Non-Class 1E loads powered Under review from Class 1E power supplies *
(50) Postaccident sampling system Closed (SSER 2) 10.4.6 (51) Diesel generators - mechanical Closed (SSER 2) 9.5.4.1, 9.5.5, issues 9.5.7 (52) TMI Item II.F.1, Attachment 2 Closed (SSER 2) 11.5.4 (53) Spent fuel transfer canal Closed (SSER 1)
(54) TMI Item II.B.2 Closed (SSER 2) 12.3.2 (55) Backup RPM designate Closed (SSER 2) 12.5.1 (56) Personnel rdsunds Closed (SSER 2) 13.1.4 (57) Licensed operator review Closed (SSER 2) 13.1.2.1 (58) Offsite fire department training Closed (SSER 2) 13.2.1 (59) Emergency planning Closed for initial 13.3 license (SSER 2)
(60) TMI Item I.C.1 Review continuing 13.5.2.2, (SSER 2) 13.5.2.3 (61) Initial test program revisions Under review (62) Proper ESF function (II.K.1.5) Closed (SSER 2) 15.9.3 (63) Safety system operability status Closed (SSER 2) 15.9.3 (II.K.1.10) . ,
" Title of item changed from " Lighting overcurrent device coordination" to generic name, "Non-Class 1E loeds powered from Class 1E power supplies."
River Bend SSER 2 1-7 l
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. Table 1.4 (Continued) t j Issue Status SER Section(s)
(64) QA organization Closed (SSER 1)
(65) Ultimate heat sink with delayed Review continuing
- 2.4.11
- fan start I (66) Participation of human factors Under review **
{ specialists in detailed control room design review (67) Task analysis documentation Under review **
(68) Control room modifications Under review **
(69) Containment venting procedures Awaiting information (70) Monitoring instruments for HPCS Under review
- 125-V ac system (71) Protection for lighting Awaiting information*
penetration circuits (72) Communication procedures Closed for initial 9.5.2.1 license (SSER 2)t (73) Lighting procedures Closed for initial 9.5.3 license (SSER 2)t (74) Pressure test HPCS air start Closed for initial 9.5.6.2 license (SSER 2)t (75) Design, install, test HPCS lube Closed for initial 9.5.7 oil system piping license (SSER 2)t (76) Turbocharger prelube (HPCS) Closed for initial 9.5.8 license (SSER 2)t (77) Process Control Program Interim approval 11.2, 11.4 until first refueling outage (SSER 2)tt (78) Subcompartment pressure analysis Closed (SSER 2)# 6.2.1.6 (79) Cable derating Closed (SSER 2)## 8.4.9
- New confirmatory issue opened as a result of applicant's FSAR Amendments 16-19.
- New human factors item.
! tNew confirmatory issue opened as a result of staff analysis of Outstanding l Issues 14-16.
. ttNew confirmatory issue opened as a result of staff evaluation of solid waste l management system.
'; #New confirmatory issue opened as a result of staff evaluation of containment system.
- New confirmatory issue identified in a staff inspection.
- River Bend SSER 2 1-8
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Table 1.5 Listing of license conditions Issue Status SER Section(s)
(1) Oil and gas exploration Resolved (SSER 2) 2.2.2 1
! (2) Turbine system maintenance program 3.5.1.3.3
~i (3) Fuel rod internal pressure Removed (SSER 1) 4.2.1.1 (4) Inadequate core cooling 4.4.7 (TMI Item II.F.2)
(5) ESF reset control Included in Confirm-atory Item 29 (SSER 1)
(6) Postaccident capability 10.4.6 (TMI Item II.B.3)
(7) Solid waste process control program Removed (SSER 2) 11.4.2 (8) Partial feedwater heating 15.1 (9) Inservice testing of pumps and 3.9.6 valves (10) Residual heat removal systein 6.2.1.9 in steam condensing mode (11) Operating staff experience 9.5 requirements l
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River Bend SSER 2 1-9 i
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. i 2 SITE CHARACTERISTICS i~
2.2' Nearby Industrial. Transportation, and Military Facilities
'i 2.2.2 Nearby Facilities In view of current oil and gas exploration in the region of the plant site, the applicant's letter of May 28, 1985, indicates its agreement to notify the Commission within 30 days of any plans for wells or pipelines within a 2-mile i radius of the River Bend Station, Unit 1, reactor centerline. The notification
' will address the potential safety of the wells or pipelines on the River Bend Station. Therefore, License Condition 1 is no longer required.
2.3 Meteoroloav 2.3.3 Onsite Meteorological Measurements Program The emergency plan, including the meteorological monitoring program, has been reviewed and evaluated by the staff. The meteorological portions of the plan are acceptable. The acceptability of the implementation of the program is evaluated in IE Inspection Report No. 458/85-05.
2.4 Hydrologic Engineerina 2.4.3 Probable Maximum Flood on Streams and Rivers 2.4.3.3 West Creek Flood Potential In the SER the appitcant was required to remove temporary road crossings and sediment from West Creek before beginning station operation. This work has been completed and is described in the May 13, 1985, letter from the applicant.
The applicant has also committed to an inspection and maintenance program for the Fabriform-lined section of West Creek (June 10, 1985, letter). The applicant will inspect the creek at least once a year. If sediment buildup exceeds 1 foot in depth the creek will be cleaned.
The staff now concludes that the applicant has met the requirements of the staff in regard to preventing flooding from West Creek.
2.4.11 Cooling Water Supply 2.4.11.2 Emergency Cooling Water Supply Since Supplement 1 of the SER was published, the applicant has made significant changes in the operation of the standby mechanical draft cooling tower. The
' cooling tower fans will no longer go on automatically in the event of an acci-dont requiring emergency cooling. Instead, the fans will be started manually, after a delay, to reduce the load on the diesel generators. The applicant has :
{ stated that following a design-basis accident, during the worst meteorological l
i River Bend SSER 2 2-1 i
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conditions (as specified in RG 1.27) a delg ed fan start of up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> will still maintain tower return temperatures below the design basis temperature of 95*F. The staff's contractor, Argonne National Laboratory (ANL), has completed an analysis which independently confirms the applicant's calculations. The staff concludes that the plant still meets RG 1.27 and GDC 44 even with the delayed fan start. However, the staff is still reviewing the heat input from the plant to determine the maximum water temperature with delayed fan start.
< 4 Staff confirmation of this temperature will be provided in a future SER Ji supplement.
2.5 Geoloav. Seismolony, and Geotechnical Encineerina 4
- j The staff has reviewed the applicant's submittals on (1) the stability of slopes caused by Unit 2 excavation and (2) the sliding stability of the service water 1
tunnel that leads to Unit 2. Although Unit 2 has now been canceled, the tunnel
' continues to retain and support foundation soils required for Unit 1 operation.
The staff has evaluated these submittals in accordance with the relevant cri-teria described in Appendix A to 10 C,FR 50, Appendix A to 10 CFR 100, Regula-tory Guide 1.70 (Rev. 3), and the Standard Review Plan (NUREG-0800), July 1981.
2.5.5 Stability of Slopes After canceling Unit 2, the applicant decided not to backfill the Unit 2 excavation pit that now exists adjacent to the Unit 1 structures. This pit is approximately 30 ft below Unit 1 plant grade (el 94 ft) and covers a horizontal 2
1 area of approximately 300 ft by 300 ft as shown in FSAR Figure 2.5-72a. Since the staff raised certain concerns .regarding the effect of precipitation and runoff ponding in ths pit (NUREG-0989), the applicant has evaluated the impact of this ponding on the safety of Unit 1 seismic Category I structures and has proposed to construct a berm around the Unit 2 excavation pit (letters, April 10, June 22, and August 9, 1984) to control the surface runoff. The hydrological aspects of this problem are evaluated in Section 2.4 of SSER 1.
The two geotechnical issues resulting from this open excavation include:
(1) stability of the Unit 2 excavation slopes, and (2) sliding stability of the service water tunnel.
2.5.5.1 Stability of Permanent Slopes 1 l
Stability of Unit 2 Excavation Slopes FSAR Figure 2.5-72a shows a plan view of the Unit 2 excavation and the adjoin-ing Unit 1 structures. The north, west, and south slopes of the excavation are cut slopes of in situ soil; the east slope which adjoins Unit I structures is formed by placement of compacted backfill materials. Both the cut and the fill slopes are at slopes of 2.4 horizontal to 1 vertical (2.4H:1V) configuration.
FSAR Figures 2.5-72b and 2.5-72c, respectively, show the typical cross-sections and foundation conditions of these slopes. The soil stratigraphy and design parameters shown in these figures are reasonable and consistent with the staff's evaluation presented in the SER. The app 1tcant's evaluation on stability for both the cut and fill slopes is presented in letters dated April 10 and June 22, 1984.
A letter dated June 22, 1984 presents the applicant's evaluation of the level I of water that would collect in the Unit 2 excavation for various design-basis River Bend SSER 2 2-2
1
. - . _ w. = -.-... - . .- ~ . . - . . _ ~ . . L .Au . !. ~ . . . . - .
events. These water levels are shown in Table 2.1 o'f this supplement and were
, conservatively considered in the completed slope stability studies.
Normal groundwater level at the site is at el 57.0 Tt. Because the level of the water collected in Unit 2 excavation is higher (see Table 2.1) than the
- groundwater level at the site, water seeps into the slope. For analysis pur-
' poses, the applicant assumed a horizontal groundwater level commensurate with the pond level rather than the actual phreatic surface. This is a conservative
, assumption because the upper phreatic surface normally will develop a gradient.
- The subsequent stability analysis of the Unit 2 excavation is thereby conserva-tive. Among the three design-basis conditions analyzed and listed in Table 2.1, the safe shutdown earthquake (SSE) with a 25 year storm was the most severe
, loading condition for slope stability as discussed below.
i In the stability analysis of the cut slope (FSAR Fig. 2.5-72b), the applicant has considered the effects of both the bers to be constructed and the live loads of traffic on adjacent roadways. The top of the berm elevation was based on the operating basis earthquake (OBE) + h probable maximum precipitation (PMP) condition because it resulted in a higher required berm elevation than the SSE with coincident 25 year storm. (See Table 2.1.) Two types of poten-tial slope failure modes were analyzed: (1) a massive sliding wedge failure that would connect the West Creek with Unit 2 excavation and (2) a shallow slip circle failure of the slope into the Unit 2 excavation.
Because of the in situ soil stratigraphy that consists of localized loose sand layers, a sliding-wedge method of stability analysis was performed for the first failure mode. The pseudostatic approach was used to consider the effects of.
the SSE. The sand with gravelly sand stratum (shown as type B soil in FSAR Fig. 2.5-72b) has occasional pockets of loose sand between el 40 and 59 ft (letter, June 22, 1984). Although this layer as a whole was considered to be nonliquefiable (NUREG-0989; letter, June 22, 1984), the impact of reduced ~ shear strength in these localized' inclusions of loose sand under SSE loading was con-sidered in the stability analysis by assigning lower shear strength for this cohesionless material. The angle of internal friction was varied between 10' and 35' in a parametric study (letter, June 22, 1984).
The Morgenstern-Price method of analysis was performed using computers and the minimum factor of safety against a deep-seated, wedge-type, sliding failure.is 1.30 for the lowest friction angle of 10' as shown in Table 2.2 of this supple-ment and FSAR Figure 2.5-72b.
The shallow slip circle failure of the cut slopes in sand and clayey sand (shown as type A soil in FSAR Fig. 2.5-72d) was investigated using the pseudo-static approach to consider the effects of SSE. The simplified Bishop method
, of analysis was performed and Table 2.2 shows the minimum factor of safety against a shallow slip circle failure. The analysis indicates that there may be local sloughing during an SSE but the slopes are stable during static condi-tion. The applicant has indicated that sloughing or localized surficial failure of the cut slope during the SSE will not affect the safety of Unit 1. There are no safety-related components at the bottom of the Unit 2 excavation. How-ever, if the berm were to fail during an SSE event, the applicant has committed to restore the berm to prevent surface runoff from entering into the excavation.
This restoration commitment for the berm is acceptable to the staff. By letter :
dated July 31, 1985, the applicant proposes to include restoration of Unit 2 River Bend SSER 2 2-3
- - - - ~ ~ ~-
I excavation slopes around the Unit 1 standby service water tower (SSWT); the staff finds this acceptable.
FSAR Figure 2.5-72c presents a typical cross-section of the backfill slope on the east side of the Unit 2 excavation. Both the OBE and SSE were considered in the pseudostatic analysis performed using computer-assisted simplified (slip circle) Bishop method. The minimum factors of safety against a shallow slip circle failure are shown in Table 2.2.
The results of the stability analyses presented show that both the in situ slope and the backfill slopes are generally safe against failure during the OBE and SSE. However, the factor of safety against a shallow or surficial failure
, of the slopes is marginal for the SSE condition. These results include the conservative assumption that the water in both the excavation pit and in the ground behind the slope are at the same level. Even if the slope fails, there is no safety related item in the Unit 2 excavation that would affect the safety of Unit 1. The applicant has committed to maintain the berm to fulfill its function of diverting surface runoff away from the Unit 2 excavation.
On the basis of a review of the stability analysis presented by the applicant, the staff concludes that the Unit 2 excavation slopes are not detrimental to the safety of Unit 1 structures and the stability of the slopes meets the safety requirements in accordance with 10 CFR 50, Appendix A. On the basis of the staff evaluation presented in this supplement, the confirmatory issue on the stability of Unit 2 excavation slopes (Confirmatory Item 3) is now resolved.
The applicant should, however, ensure that the proposed berm around the excava-tion and the slopes around Unit 1 standby service water tower are maintained to enable it to fulfill its safety function as committed to by the applicant in the letter dated June 22, 1984, 2.5.5.2 Stability of Temporary Slopes Stability of the Service Water Tunnel (G Tunnel)
Figure 2.1 of this supplement shows a plan and cross-section of the service water tunnel (G tunnel). This tunnel starts from the F tunnel at the west end of the Unit 1 fuel building, runs past the Unit 1 standby service water tower, and terminates near the Unit 2 fuel building. The G tunnel is a reinforced concrete box-type structure that was originally intended to be completely buried underground. However, it was decided to cancel Unit 2 and not to backfill the excavation pit above el 66 ft. Therefore, the G tunnel remains partly buried at its west end with the backfill on the north side of the tunnel 28 ft higher than that on the south side as seen in Figure 2.1. Unbalanced soil loading on the G tunnel results from the applicant's decision not to completely backfill around it. Thus, the applicant has performed a stability analysis of the G tunnel using the following assumptions:
(1) The driving forces for the sliding and overturning analyses include the dynamic soil and water pressures in addition to the earthquake-induced inertia forces of the structure.
(2) The resisting forces are: (a) the base friction, wall friction, and soil ,
pressures, where appropriate, in the case of sliding, and (b) the dead -
weight of the structure and soil pressures, where appropriate, in the case of overturning.
River Bend SSER 2 2-4 l
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(3) The internal angle of friction for the compacted cohesionless backfill (sand) is 36*.
(4) The coefficient of friction between soil and concrete poured on compacted fill is taken as 0.55 for sliding analysis.
(5) Since the backfill is placed to the same elevation on both sides of the G tunnel at the east end, at-rest earth pressures are assumed to act there.
Because of the difference in backfill elevations toward the west end of i
the tunnel, sufficient movement of the tunnel is assumed to occur to reduce the driving soil pressure from at rest condition to a state that approaches active earth pressure at the west end. In the stability analy-sis of the G tunnel, a lateral earth pressure coefficient of K, = 0.45 is used only for 100 ft at the east end of the tunnel and a coefficient of K, = 0.35 for the remaining length on the north side of the G tunnel. On the south side of the tunnel a coefficient of K = 0.45 is used throughout the length of the tunnel.
Some of the above assumptions are given in Revision 2 of the applicant's cal-culation G(c)-185. The staff is satisfied that the above design assumptions satisfactorily represent the existing conditions. The applicant's stability analysis results (shown in FSAR Table 2.5-16) indicate that the minimum factors of safety against sliding and overturning occur under SSE condition and the factors are 1.7 and 1.8, respectively. These results are acceptable to the staff.
On the basis of a review of the applicant's analysis of the stability of the service water tunnel (G tunnel) against sliding and overturning, the staff finds the margins of safety for the stability of the G tunnel to be adequate and acceptable. By letter dated July 31, 1985, the applicant agrees to revise the FSAR to incorporate the design assumptions that were furnished through detailed calculations. The staff finds this acceptable.
River Bend SSER 2 2-5
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Figure 2.1 Location of G tunnel (River Bend Station)
River Bend SSER 2 2-6
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L] Table 2.1 Water levels in Unit 2 excavation *
, Allowing for Assuming no seepage from Water level used seepage from ponding in in stability
.; Design-basis Unit 2 excava- Unit 2 excava- analysis of
- conditions tion, el in ft tion, el in ft slopes, el in ft i Static + PMP 78.1 68.3 80.0 OBE + % PMP 69.6 70.0 73.0 SSE + 25 yr 67.2 67.2 68.7 storm
- Letter from applicant, June 22, 1984.
- For the 25 year storm condition the resulting water level does not require a berm nor would significant seepage be anticipated.
Table 2.2 Minimum factors of safety for Unit 2 excavation slopes
- 1. North, west, and south slopes - cut slopes Deep-seated wedge sliding failure NA** NA** 1.30**
(west slope only)
Shallow slip circle failure 1.75 1.50 1.33**
- 2. East slope - fill slope Shallow slip circle failure 1.51 1.21 1.19 i
- Letter from applicant, June 22, 1984.
- Deep-seated sliding failure mode was considered only for SSE since that alone may produce partial liquefaction of the loose sands and cause such failure.
tThese factors of safety are obtained with friction angle of 35'.
Lower safety factors using the infinite slope method do result and would indicate that minor surficial sloughing can occur at the face of the slope.
l River Bend SSER 2 2-7 L- _
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t 3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, EQUIPMENT, AND COMPONENTS
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3.6 Protection Against Dynamic Effects Associated With the Postulated
'} Rupture of Piping a 3.6.2 Determination of Rupture Location and Dynamic Effects Associated With the Postulated Rupture of Piping In Section 3.6.2 of the River Bend SER (NUREG-0989, May 1984), the staff iden-tified a confirmatory issue regarding documenting in the FSAR the failure modes
! analysis for pipe breaks. In Amendments 15, 16, and 17 to Appendix 3C.2 of the FSAR, the applicant has provided the results of its failure mode analysis. Ap-pendix 3C.2 provides a discussion of the high-energy pipe breaks and summarizes the effects of pipe whip and jet impingment loadings on safety related struc-tures, systems, and components. The staff has reviewed the methodology used by 4
the applicant to postulate break locations. The applicant has postulated full break opening areas and no mechanistic approaches were used to reduce break areas. On the basis of the staff review of the failure modes and analyses, the staff finds that safety-related systems, structures, and components have been adequately protected from the dynamic effects associated with postulated high-energy pipe breaks. Thus, the staff concludes Confirmatory Item 4 regarding pipe failure modes has been acceptably resolved.
3.9 Mechanical Systems and Components 3.9.2 Dynamic Testing and Analysjs of Systems, Components, and Equipment 3.9.2.4 Dynamic System Analysis of Reactor Internals Under Faulted Conditions In Section 3.9.2.4 of the River Bend SER, the staff identified a confirmatory item (Confirmatory Item 5) regarding the documentation in the FSAR of the re-sults of LOCA and SSE analyses for the reactor internals and unbroken loops of the reactor coolant prassure boundary. In a letter dated January 31, 1985, the applicant provided the results of its analyses including the effects of annu-lus pressurization (AP). Subsequently, the analyses results were documented in FSAR Amendment 16. The staff review finds the results of the analyses satis-fies the staff acceptance criteria for the load combinations and stress limits of ASME Code Class 1, 2, and 3 components, component supports, and core-support structures. Thus, the staff concludes that the confirmatory issue regarding the documentation of the LOCA and SSE results for the reactor internals and unbroken loops of reactor coolant pressure boundary has been acceptably resolved and Confirmatory Item 5 is considered closed.
3.9.3 ASME Code Class 1, 2, and 3 Components, Component Supports, and Core Support Structures 3.9.3.3 Component Supports The staff iden'tified a confirmatory item (Confirmatory Item 7) in Section 3.9.3.3
- l of the River Bend SER regarding the' justification for the applicant's position River Bend SSER 2 3-1
classifying restraint of piping thermal expansion and relative building dis-placement stresses as secondary stresses for pipe supports. The applicant pro-vided its response in a letter dated December 21, 1984.
The staff's position with respect to pipe stresses in analyses is that piping thermal stress is treated as a secondary stress. Piping thermal stress is the stress that occurs from restraining the free-end deflection of piping that occurs when temperature increases or decreases. Piping thermal stress is char-acterized as a secondary stress whether the piping is analyzed by Article 3200 of Subsection NB of Section III of the Code of the American Society of Mechan-ical Engineers (ASME Code) or by the more simplified and generally used approach of Article NB/NC/NC 3600 of the ASME Code. However, within the limits of rein-forcement for Class 1, 2, or 3 vessel nozzles (nozzle piping transition), re-straint of free end displacement of the attached pipe is considered a primary stress by the Code and the staff concurs in this treatment.
For piping and the pipe-nozzle transition region of a component such as a vessel, the staff has accepted and usesSection III of the ASME Code to char-acterize the stress which results from the restraint of free end displacement of piping as primary for nozzles within the area of reinforcement, or as secondary for oiping.
Before Subsection NF was issued in 1973, the Code of the American Institute of Steel Construction (AISC Code) (Manual of Steel Construction) was used exclu-sively for support design with the exception of component standard supports.
Even now the AISC Code continues to be used for the design of either a portion, or the complete structural load path, of a piping and component support. The AISC Code does not characterize loads as primary or secondary. All loads in-cluding those caused by piping thermal expansion are evaluated. When Subsec-tion NF of the Code was first issued in 1973 and then in the 1974, 1977, and 1980 editions of the Code, the staff did not categorically accept the character-i.tation of restraint of piping thermal expansion as a secondary load for support design. Secondary loads, including restraint of free-end displacements from piping thermal expansion and seismic differential building movements, are accounted for in the normal and upset conditions, but were not required to be evaluated for the emergency and faulted conditions by ASME in the above-mentioned versions of Subsection NF, based on the assumption that their effect is usually small. Thermal stresses er other " secondary" effects are not explicitly dis-cussed in the AISC design' instructions. However, items meeting the AISC spect-fication must be designed so that stresses which result from all sources are at least within specified allowable values. Unless those loads are evaluated, or their effects are otherwise limited, such as by stipulating a maximum value for support strain, there is no assurance that the support will not fail because of gross plastic deformation or that the deformation will not affect the opera-bility of supported components. To disregard such effects simply because a standard allows the practice is not considered acceptable for a safety system.
Subsection NF in the 1973 edition of the AISC Code, and in all later editions, does not require the evaluation of stresses that result from the restraint of thermal expansion of the support itself. The staff has accepted this provision, requiring an evaluation only in those unusual cases where long-constrained support lengths subject to large temperature changes might collapse or otherwise ,
be a'preciably p stressed.
- l River Bend SSER 2 3-2 1
1
' For the River Bend facility, the applicant performed a comparison study using
' the at,0ve-described staff position to assess the effect of classifying constraint of thermal expansion and related seismic building displacement stresses as primary stresses on existing pipe support designs.
I The applicant selected 250 pipe supports from eight Category I piping systems.
' These eight piping systems were selected because of their high operating temper-atures and seismic building displacements. The pipe sizes varied between 2-inch nominal pipe size (NPS) and 24-inch NPS. The results of the study showed that redefining constraint of thermal expansion and seismic building displacement l stresses as primary stresses increased the pipe support stresses; the structural integrity of the designs was not compromised and physical modification of the designs was not required. The designs were evaluated to the allowable stresses I
of the 1974 ASME Code (including the Summer 1974 Addendum) which is the current River Bend licensing commitment.
On the basis of the results of the applicant's study, the staff concludes that the design methodology used for the River Bend component supports satisfies the staff position described above and, thus, the portion of the confirmatory item dealing with pipe thermal expansion and building displacement (Confirmatory Item 7) is considered closed.
3.9.6 Inservice Testing of Pumps and Valves The applicant had not submitted an inservice testing (IST) program for pumps and valves as of the issue of the SER. Thus, the SER stated that the resolu-tion of this issue would be addressed in an SER supplement. By a letter dated November 5, 1984, the applicant submitted an IST program. By letters dated May 16, 1985, and May 30, 1985, the applicant clarified the status of the pro-gram and amended the program, respectively.
The staff has not completed a detailed review of the River Bend IST program. A preliminary review was completed and it was found that it is impractical with-in the limitations of design, geometry, and accessibility for the applicant to meet certain of the ASME Code requirements. Imposition of those requirements at this time would, in the staff's view, result in hardships or unusual diffi-culties without a compensating increase in the level of quality or safety.
Therefore, pursuant to 10 CFR 50.55a(g)(6)(i), the relief that the applicant has requested from the pump and valve testing requirements of the 1980 edition of ASME Code Section XI through Winter 1981 addenda should be granted for a period of no longer than 2 years from the date of issue of the operating li-cense or until the detailed review has been completed, whichever comes first.
If the review results in additional testing requirements, the applicant will be required to comply with them.
3.10 Seismic and Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment 3.10.1 Seismic and Dynamic Qualification 3.10.1.1 Introduction As part of the review of the applicant's Final Safety Analysis Report (FSAR)
Sections 3.7.3A, 3.7.3B, 3.9.2A, 3.9.2B, 3.10A, and 3.108, an evaluation is made of the applicant's program for seismic and dynamic qualification of River Bend SSER 2 3-3 l
~ -. - - - - . . . ... . -.. .
t 1 safety-related electrical and mechanical equipment. The evaluation consists
,, of (1) a determination of the acceptability of the procedures used, standards followed, and the completeness of the program in general, and (2) an audit of selected equipment to develop a basis for the judgment of the completeness and l adequacy of the seismic and dynamic qualification program.
t Guidance for the evaluation is provided by the Standard Review Plan (SRP) Sec-tion 3.10, and its ancillary documents, Regulatory Guides (RGs) 1.61, 1.89, 1.92, and 1.100; NUREG-0484; and Institute of Electrical and Electronics Engineers (IEEE) Stds. 344-1975 and 323-1974. These documents define acceptable method-ologies for the seismic qualification of equipment. Conformance with these criteria is required to satisfy the applicable portions of General Design Criteria (GDC) 1, 2, 4, 14, and 30 (Appendix A to 10 CFR 50), Appendix B to
- 10 CFR 50, and Appendix A to 10 CFR 100. The program is evaluated by a Seismic i Qualification Review Team (SQRT) which consists of staff engineers and engi-neers from the Brookhaven National Laboratory (BNL, Long Island, New York).
3.10.1.2 Discussion The SQRT has reviewed the equipment seismic and dynamic qualification infor-mation contained in FSAR Sections 3.7.3A, 3.7.38, 3.9.2A, 3.9.28, 3.10A, and 3.108 and visited the plant site from October 29 through November 2, 1984. The purpose was to determine the extent to which the qualification of equipment, as installed at River Bend, meets the criteria described above. A representa-tive sample of safety-related electrical and mechanical equipment as well as instrumentation, included in both nuclear steam supply system (NSSS) and bal-ance of plant (80P) scopes, was selected for the audit. Table 3.1 identifies the equipment audited. The plant site visit consisted of field observation of the actual, final equipment configuration and its installation. This was followed by a review of the corresponding qualification document. The field installation of the equipment was inspected in order to verify and validate equipment modeling employed in the qualification program. During the audit the applicant presented details of the qualification and in-service inspection program.
3.10.1.3 Summary On the basis of the observation of the field installation, review of the quali-fication documents, and responses provided by the applicant to SQRT's questions during the audit, the applicant's seismic and dynamic qualification program, subject to generic findings discussed in Section 3.10.1.4, was found to be defined and implemented. The equipment-specific findings as a result of the SQRT audit are identified in Table 3.1 and the generic comments are listed in the following section. Upon satisfactory resolution of these specific findings and generic comments, the seismic and dynamic qualification o.' safety-related equipment at the River Bend Station, Unit 1, will meet the applicable portions of GDC 1, 2, 4,14, and 30 of Appendices A and B to 10 CFR 50 and Appendix A to 10 CFR 100.
I 3.10.1.4 Confirmatory Items l
l The satisfactory resolution of the specific findings identified in Table 3.1 ,
j and in the generic comments listed below, is required before the staff completes *
- its review of the applicant's seismic qualification program for equipment
l l River Bend SSER 2 3-4 i
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'. 1 Ll (1) Each equipment qualification document package contained summary statements
'1 and overall conclusions. The conclusion for each package was that the
- equipment was fully qualified. However, in many instances it was observed that evidence necessary to reach the state of complete qualification was unavailable. More recent documentation packages were incomplete and appeared to be put together without adequate checking after the selection
'li of equipment was transmitted to the applicant. Therefore, the applicant is to develop a more systematic program to perform the acceptance review
-j of all safety-related equipment.
(2) Where the qualification document package identifies a need for equipment
- ,i modification, the applicant is to develop a systematic program to include
' in the qualification package either a statement indicating implementation of the modification or justification for not implementing the modification.
(3) In many cases, the equipment qualification report identified parts with a limited life. Such equipment could be located in either a mild or a harsh environment. The applicant is to develop a systematic procedure for iden-tifying ifmited-life parts and to ensure their replacement at appropriate intervals during the acceptance review of equipment.
(4) Some pieces of equipment were incorrectly or improperly installed. The applicant is to develop a procedure to check proper mounting of all safety-related equipment consistent with the qualification mounting configuration.
(5) The enclosure panel for many pieces of equipment was partially removed or screws were loose, reportedly to facilitate preoperational testing. The applicant is to develop a procedure to ensure that such. equipment is re-turned to the qualified status.
(6) Upon completion of as-built piping analysis for all pipe-mounted safety-related equipment, the applicant must confirm that the g values used for qualification of this equipment was not lower than the g values obtained from the as-built piping analysis.
(7) The qualification of those pieces of equipment which were originally quali-fled to meet IEEE Std. 344-1971, should be identified and upgraded to meet the requirements of IEEE Std. 344-1975, as applicable.
(8) Upon completion of the on going qualification process, the applicant must confirm that all safety-related equipment has been qualified.
3.10.2 Pump and Valve Operability 3.10.2.1 Introduction .
To ensure that an applicant has developed and implemented a program regarding the operability qualification of safety-related pumps and valves, the staff performs a two-step audit. The first step is a review of FSAR Section 3.9.3.2 for the description of the applicant's pump and valve operability assurance program. The information provided in the FSAR, however, is general in nature I
- and not sufficient by itself to provide confidence in the adequacy of the licensee's overall program for pump and valve operability qualification. To f River Bend SSER 2 3-5
i 5
i provide this confidence, the Pump and Valve Operability Review Team (PVORT),
consisting of staff from Brookhaven National Laboratory (BNL) and the NRC, i
conducts an onsite audit of a small representative sample of safety-related pumps and valves and supporting documentation.
The criteria by which the audit is performed are described in SRP Section 3.10 entitled, " Seismic and Dynamic Qualification of Mechanical and Electrical Equipment." Conformance with SRP 3.10 is required in order to satisfy the applicable portions of General Design Criteria (GDC) 1, 2, 4,14, and 30 of Appendix A to 10 CFR 50 and Appendix B to 10 CFR 50.
$ 3.10.2.2 Discussion In performing the first step of the audit, the staff reviewed FSAR Sec-tion 3.9.3.2. The onsite audit, or second step, was performed by the PVORT during the week of October 29, 1984. The purpose of this two-step review process is to detern.ine the extent to which the applicant meets the criteria of SRP Section 3.10. A sample of three NSSS and seven BOP components was selected to be audited.
The onsite audit includes a plant inspection of the as-built configuration and installation of the equipment, a review of the normal, accident, and postacci-dent conditions under which the equipment and t,ystems must operate, the fluid dynamic loads, and a review of the qualification documentation (status reports, test reports, analysis specifications, surveillance programs, and long-term operability program (s), etc.). -
Table 3.2 of this supplement identifies the equipment audited and the findings that remained open as a result of the audit.
3.10.2.3 Summary On the basis of the observation of the field installation, review of the quali-fication documents, and responses provided by the applicant to PVORT's questions during the audit, the applicant's pump and valve operability qualification pro-gram, subject to generic findings discussed in Section 3.10.2.4 below, has been found to be defined and being implemented. The equipment-specific findings that resulted from the PVORT audit are identified in Table 3.2 and the generic com-ments are listed below. Upon satisfactory resolution of these specific and generic comments, the seismic and dynamic qualification of safety-related equip-ment at the River Bend Station, Unit 1, will meet the applicable portions of GDC 1, 2, 4, 14 and 30 (Appendix A to 10 CFR 50); Appendix B to 10 CFR 50; and Appendix A to 10 CFR 100.
.3.10.2.4 Generic The specific findings in Table 3.2 and the generic concerns listed below must be resolved before the staff completes its review of the applicant's pump and valve operability qualification program.
l
! (1) In many instances, evidence of complete qualification was unavailable.
More recent documentation packages were incomplete and appeared to have ,
been put together without checkiag. The PVORT long forms contained -
River Bend SSER 2 3-6 i L fL
._ __ . .._..__. _ _. _ . _ . Ji _ _ _ . . _ _ . . . _ . _ _ _ . . - . _ . . . . ._ _ __. i .
l i 1 P
numerous inconsistencies ranging from inconsistent serial numbers, capabil-ity, and qualification information on the actual equipment. The appitcant i
is to develop a more systematic program to perform the acceptance review of safety-related pumps and valves.
(2) During the acceptance review of equipment, a procedure should be developed to identify limited life parts and ensure their replacement at appropriate j intervals.
(3) Procedures should be established to return tested equipment to its quali-
! fied status.
l (4) Components were found to be incorrectly or improperly installed. Proce-dures should be established verifying equipment installation requirements and qualification.
(5) All pumps and valves important to safety must have their required preopera-tional tests completed before fuel load.
I (6) All pumps and valves important to safety must be qualified before fuel load.
(7) The applicant shall confirm that new loads resulting from loss-of-coolant accident (LOCA) or analysis of as-built conditions applicable to pumps and valves important to safety do not exceed those loads originally used to qualify the equipment.
f River Bend SSER 2 3-7
t I t.
i Table 3.1 SQRI findings on seismic and dynamic qualification i 3 !-
f < SQRT Appilcant Equipmen. naw '
I N ID No. ID No. and description Safety function Findings Resolution Status Remarts E NS$$-1 1CII-ACTD001 Hydraulic control unit: Translates scram signal The additional brace used Pending Open ,
3 AssenS1y consists of into hydraulic energy during qualification test !
" N, cylinder, water to insert the control of the equipment was alss- ,
m accumulator, and vari- rod drive and allow its ing from the installed unit. :
l
- o ous valves. return flow to discharge.
through the exhaust
[
u valve. !
l ,:
MS$5-2 H13-F680 Plant control console: Supports instrsments The dynamic siellarity Pending Open l-A U-shaped monitoring which are used to moni- between the tested specimen ).
benctboard. tor and control the and the River Bend console [^
safe operation and was not established. -
shutdown of tlw plant.
l The test mounting was not f-l documented in the test i report.
l For components quellfication.
the capability g values were not defined and demonstrated
{<
i s.: to envelop the RR$ over the d entire frequency range. j NSSS-3 C61-P001 Remote shutdown Provides redundant Th= insttilation condition Pending Open vertical board means for safe shutdown of being nemt to another ,
of the plant. cabinet and the wall was ;
not addressed in the ;
qualification. I' 1
MSSS-4 E12-C002A, C RHR pump and motor Assembly is required Qualified ,
to ptmp water in the , !
suppression pool during ;
pool cooling modes and LPCI vessel injection modes. l t
NSSS-S H13-P601 Reactor core cooling Contains instruments Dynamic siellarity between Pending Open ;
bench board: A moni- that are used for manual the tested specimen and the ;
l, toring panel. control for accident River Bend unit was not establistud.
mitigation of the emer-P"CY ** '**II"9 Test snunting was not i system. completely d9ctmented in -
the test report.
For component qualification, the capability g values were i not defined and demonstrated .
I to envelop the required re- [
[
sponse spectra over the J.
entire frequency ranga. [
l1 l I
,3
~
'4 - , ,,- <a
. f%m,, ..
s
'. . .-- . , . . ,, ; e _. ,
ta b;
, . Table 3.1 (Continued) !o3 2
- ' Applicant SQRT Equipment nama
' ID No. ID No. and description Safety function Findings Resolution Status Remarks ;{
to e ai g NSSS-5 Qualification of some devices t (Contd) below 5 Hz was missing. ii y w I m Controller and recorder units (~.
$ were sliding during tests. It .
could not be verified from
-I N
documentation presented wheth- f er River Bend panel contains l' these devices. ) i I
Site inspection revealed the 4 following: '
Ona unistrut was loose.
GE FRIS terminals were very flexible. ,
1 t
NS$5-6 H13-P670 Neutron / process Provides information The cabinet was installed rending Open !'
radiation monitoring about power levels and with 1/2"-diameter bolts al- g
( y system power distribution in though the specimen was ;!
, e the reactor, and is tested with 5/8"-diameter .-
l tied to a trip system bolts. .j (reactor protection j system). ,.
NSSS-7 H22-P041, 42 Main steam flow local Supports Class IE Transmitters were not Pending Open panel devices, avironmentally aged before
- I seismic testing. [
Transmitter output variation It detected during testing was t-apparently due to incomplete i Instruction provided by GE to !.
I ,' ,
testing engineers regarding calibration. '
R.
GSU/GE is to confirm that ,
River Bend Installation r engineers have received the complete instruction and the !
transmitters are properly j calibrated. ;
NSSS-8 B21-F028B Main steam isolation Isolates the steam- Adequary of the valve body Pending open ,.
valve line upon demand. was not demonstrated.
GSU is to confirm compilance !j with GE's recommendation '1 regarding'the followIrq a required for qualification: {
O
. . a_ .mi . m _ , . -_.__L._ _
l s s j, '
't .
W 4-i 2 Table 3.1 (Continued) , , . .,_ ;
O
-s SQRT Appilcant Equipment name '
a, ID No. ID No. and description Safety function Findings Resolution Status ' Remarks f
- !! y r.
Q- MS$$-8 Bracket modification for j m (Contd) limit switch. -I m
m Elimination of junction
! " box.
" The source of River Bend I l
-specific RRS was not presented during the audit. .
BOP-1 1CCP*MOV138 10" motor-operated is" required to isolate Qualified valve the containment and to intercept the water flow .
of the reactor plant )
component cooling water j system (RPCCW) to the nonregenerative heat w exchanger. .
e f.
$ BOP-2 1RCP"TCA03 Termination cabinets Are required at pene-trations to contain the Qualified- 'b- -
wiring used in instru- p.,
mentation monitoring and . ,j control of equipment used i t- j in various safety-related bt j functions. '
l j
- . i j"l BOP-3 IEHS*MCC Motor control center: Is required to provide Qualification of devices Pending Open apparently covered by ;
A two-bay rectangular Class IE power distri-cabitiet containing bution. Could reports R-STS-10,' 31 .
starters, circuit and analysis was not avall- !-
breakers, switches, able for review.
- terminal blocks.*etc. Test mounting.was not docu- ff mented.
It is not clear from test [
report whether the MCC was tested for 5 OBE and 1 SSE j.
for both the energized and 4 deene3 red conditions.
Supplemental evaluation report for HE 4-3 circuit
- breakers was not part of the qualification documen-tation package.
I l,
- 9 $
- c . ~L . -. . , _w. : L.
Table 3.1 (Continued) l
- .i-7 SQRT Appilcant Equipment name l' j ID No. ID No. and description Safety function Findings Resolution Status Remarks ,
y BOP-4 IE12*PC003 Centrifugal fill pump: A pump / motor Maintains the RHR system piping filled The site inspection revealed the following deficiencies:
Pending Open
- 3 I CL assembly, and ready for main m
m RHR pump startup. The shin stack was loose. b-i, m One nut in the seal housing t 2
was loose and another was '!'
N missing. i i.
The motor nameplate was f missing.
[*[
F BOP-5 1HVC*ACU1B Control building air Maintains the control Quellfled. '-
conditioning unit. building at design
. temperature and humidity.
BOP-6 1HVR*A0010A Air-operated damper: Operates only during Qualifted It is duct mounted LOCA when it bypasses and supported from the the air to the standby !
w ceiling. gas treatment building. 1 e !
U BOP-7 ILSV*C3A Leakage air system Provides pressurized Quallfled compressor: A single air to containment l rotary compressor with isolation valves to r-electric motor drive. prevent release of l fission products after . ,
LOCA.
l.
BOP-8 ISCM*XRC14 Transformer Furnithes power to Dynamic similarity between Pending Open various Class IE the tested specimen and,the ;c instruments as part of River Bend troosformer was the uninterrupted power not established. . . ,
supply system. Test mounting was not com-pletely documented in the !
test report. L Test anomalies were mentioned, '
but neither described nor justified in the test report.
Site inspection revealed the following:
There was no contact between the hase plate and concrete in most places.
$1de panels were loose.
Base plate was not addressed ;
in the qualification ;
documents presented. ;
I i.
t
_ _ . _ . n i
. ~
. ..a :. .._ , .. _ 1 .,...L... .. _: . . : ..;.._. . . _ - - . s.--
7 i'
i
. ,:c Table 3.1 (Continued) . ;
< f.
j u
SQRT ID No.
Appilcant ID No.
Equipment name and description Safety function Findings Itesolution Status Remarks p' i f ..~ -
j'
- g. 80P-9' IEJS*LDCIA Load centers Are required to furnish power distribution Only a summary of test Pending Open g report was available. The a '.
y to HVAC systems in the original Wyle Test Report
-{-
m control and diesel is needed for review and M generator building and doctamentation. !l m
- also to Class IE motor i control centers. -!
BOP-10 ISWP*P2B Standby service water Provides cooling water Torsional frequency of Pending Open pump: An electrically for safety-related assembly needs to be driven vertical turbine equipment when normal computed and compared to ,.
pump. service water is lost. motor's operational [L speed. '
Operability of pump under seismic load needs to be ensured.
'i Y !
N '4
<I
- i. 5
?
t k
l 5
l h
e' L
e m 01 '
E __________i _ _ . -__ _
7 , -
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h t
Y
= Table 3.2 PVORT findings on operability qualification of pumps and valves '
Plant I.D. L
- [ No. Description Safety function Findings / resolution Status Remarks F a
1 g E22-F015 20" motor oper- Opens in response Operability of the valve Open m ated gate valve to either a suppres- was established using (NSSS) sion pool high- analysis only. A test 1evel signal or a program is presently ['
low-condensate, being performed and a ' [j .
tank-level, con- similar analysis with a !f tainment isolation, similar valve which was I.
tested will be submitted as demonstration of oper- f.'l .
je ability and qualification. . i, 1
ISWP-P2A Standby service Provides cooling Clarify vibration accep- Open water pump (BOP) water for safety- tance criteria (displace- !
, related equipment ment velocity)? !
4 w
if normal senice Coupling runout value Open water is lost.
(driven member) is '
inconsistent with align- '
ment requirement. '
Pump weight incorrect on Open !
PVORT sheets.
Final qualification sub- Open ject to compliance with endurance testing recom-mended in IE Bulletin !
83-05.
B33-F060A 20" flow con- Maintains pressure Satisfactory. Closed trol valve boundary integrity.
(NSSS) '
e 4
5, b ;.-
a
= , .x... .:,. .
i l'
I 4
Eg Table 3.2 (Continued)
N o, Plant I.D. !
g No. Description Safety function Findings / resolution Status Remarks
- o. {
$ IE12-MOVF021 14" motor- Containment isola- Have stem leakoff Open g operated globe lation. requirements been met? ,
N) valve (B0P)
N&D No. 6189 motor !
starter housing welded to motor flange. Have possible effects of weld-ing on valve flange and valve shaft assembly ,
been considered? j Dates of issue on qual- f ified documents very ;
recent (i.e., ST-7003 u, " Operability Test Proce-J, dure" is dated 11/2/84
- which was the exit ,
meeting date). Com-pleteness and approval required.
1HVC-MOV1B 24" motor- Isolates main Actuator is serialized Open operated butter- control room during (260880); adapter plant fly valve (B0P) LOCA. is also serialized' i-(260953). PVORT form !;
picked up the adapter !
serial no. in place of !
the actuator no. !
Clarification required.
(-
1CCP-MOV138 10" motor- Outboard contain- Valve has serial no. 809 Open l" operated gate ment isolation (1980) on "N" stamp tag.
valve (BOP) valve. Manufacturer's nameplate ,.
c
, ; . .2.
.__ h. _ , i d...a ~ .as[
{,
!?
p
. h, m, Table 3.2 (Continued)
- Plant I.D. 5 No. Description Safety function. Findings / resolution Status Remarks
- v. ICCP-MOV138 serial no. is 1413-2.
x (Contd) PVORT form lists valve i'
" serial no.' as 809(1980). !
Inspection and test { <
record form lists serial I-no. as 1413. Clarifi- !
cation required. j 1 Stroke time require- Open ments vary from 30 sec l
- j (spec sheet) to 22 sec ;
(inspection and test '
record) to 20 sec -
(PVORT form). Clari-y fication required, w
ui Have stem leakoff Open requirements been [
{ provided?
i Have space heaters Open f)(
["
=
been removed? i.
f ".
Rev. 2 to MOV Check- Open out Procedure 1, i
' 1-G-EE-18, initiated i due to excessive torque ;.
values in Rev. 1. Com- '
i paring Revs. I and 2, the torque valves appear l to be the same. '
! B21-A0VF32A 20" check valve Containment iso- Satisfactory. Closed :
i (BOP) lation and reactor I coolant pressure boundary.
- i e
i i
i
= Table 3.2 (Continued) i 2
e -
Plant I.D. Safety EF No. Description function Findings / resolution Status Remarks E
vs E33-SOV14 2i' solenoid- Provides initial Valve installation Open ;
operated globe pressurization of contradicts note 18 '
" valve (B0P) main steam posi- of FSAR Fig. 6.7-1, i tive leak control qualification documen- i system. tation and manufacture i' recommendations.
If the working fluid Open (air) provides opening p. -
force, what is the minimum air pressure required to open the [l; ca valves? p
- d. Are the forces delivered Open by the spring capable of h-closing the valve against the loads of the working i' fluid? t I~
What assurance is there that the delivered air l; quality is in agreement .
with the manufacturer's f, requirements?
l List tests performed by Open GSU to date or to be performed in the future.
How to or will GSU track l' manufacturer's recom- i mendations regerding ,
maintainability of components subject to aging? '
. . . _ ._m. . . . .:m _ . z.1_._ _ .._ _
i i
I s
3 Table 3.2 (Continued)
$ f
)
g Plant I.D.
No. Description Safety function Findings / resolution Status Remarks ot 7
g E12-C002C RHR pump Supplies water to How is pump performance Open g (NSSS) the core in the (curves, vibration
)*
F
,, event of an levels, bearing temp., r accident. etc) established without i Suppression pool the use of manufacturer's data / acceptance criteria? ).
cooling.
Discharge pressure trans- Open mitter has a reject tag
, and as-built acceptance ,
tag. Clarify difference l and the reason for the !
,, reject tag and the action f
j, taken.
Serial no. on motor qual- Open ,
ification documentation }[
and long form disagree. !^
1 .
Clarify the differences Open !
between GE specification 21A3504, Rev. I and 21A35048V, Rev. 0 (e.g., [
removal of IEEE standards; t is this component built l
to IEEE, if not justify why. i Clarify how GSU will or has identified parts sensitive to aging mechanism and how they will be tracked.
i f
eq
. . ,y
. . : / ..
. .m... _ . . . . . . _. . .._._.a .
. .- . u .. . : - . . 1 l: .
i; e,
m Table 3.2 (Continued)
Z m I Plant I.D. Safety RF No. Description function Findings / resolution Status Remarks El ,
u, E12PC003 RHR subsystem Maintains RHR The specification Open M fill pump (BOP) system piping specifies demineralized
- filled and ready water on data sheet while for RHR pump the pump actually takes startup. suction from suppression l pool. What effect does !
this have on operability, I performance, life of wear rings, bearings, seals, impe11ers, etc.? t.
At reduced voltages what is the capability T of the pump / motor, and g does it meet the require- ,
ments of the system?
s l-t I
49
4%.
~
.a.. - - - . - -
- - - - . - - - - - - - - - .- L a
,y
}
'i 4 REACTOR 4.2 Fuel System Desian 4.2.3 Design Evaluation 4.2.3.2 Fuel Rod Failure Evaluation (8) Fuel Rod Mechanical Fracturing
~ The applicant has submitted for staff review a plant-specific analysis.(letter, November 30, 1984) using the approved methodology described in the General Elec-tric Co. (GE) report NEDE-21175-3. The staff finds these results to be accept-able and the issue of fuel rod mechanical fracturing (Confirmatory Item 8) is resolved. Since the mechanical fracturing analysis is usually done as a part of the seismic-and_LOCA loads analysis, further discussion can be found in Section 4.2.3.3(4).
4.2.3.3 Fuel Coolability Evaluation (4) Fuel Assembly Structural Damage From External Forces The staff approved (Thomas, October 20, 1983) the GE topical report NEDE-21175-3, which describes an analytical method for evaluating seismic-and-LOCA loads.
The staff has also reviewed the plant-specific va. lues of liftoff and accelera-tion (letter, November 30, 1984). The results show that the vertical liftoff is less than the allowable liftoff limit given in NEDE-21175-3, which is_ refer-enced by the applicant, and the acceleration is within the evaluation-basis limits, thereby assuring structural integrity and control rod insertability during seismic-and-LOCA events. Therefore, the staff concludes that the con-C $ -7 firmatory issue of seismic-and-LOCA loads, is satisfactorily resolved for River Bend.
}}o '
4.4 Thermal and Hydraulic Design 4.4.4 Thermal-Hydraulic Stability GE originally proposed a BWR stability design criterion for a decay ratio of less than 0.5. The applicant has calculated that the River Bend Unit 1 core design will exceed this value. In addition, more recent operating and test data from other BWRs have demonstrated the occurrence of limit cycle neutron flux oscillations at natural circulation and several percent above the rated rod line. The oscillations were observable on the average power range monitors (APRMs) and were suppressed with control rod insertion. It was predicted that limit cycle oscillations would occur at the operating conditions tested; however, the characteristics of the observed oscillations were different from those pre-viously observed in other stability tests. Namely, the test data taken showed that some low power range monitor (LPRM) detectors oscillated out of phase with the APRM signal and at an amplitude as great as six times the core average. GE F has prepared and released a service information letter, SIL-380, to alert the River Bend SSER 2 4-1
ie %+ a d **'
, . . . _ _ . _ _ _ _ _~ -, . . . - . . -- - - - - - - ~ - . . -- .- --
l I
.i BWR owners to these new data and to recommend actions to avoid and control
_ abnormal neutron flux oscillations.
The staff has reviewed the initial fuel loading of River Bend Unit 1 and finds it to be bounded by GE analyses presented in NEDE-24011. Therefore, this core e
meets the stability criteria set forth in GDC 10 and 12 and is acceptable on the condition that the Technical Specifications include appropriate limiting conditions for operation and surveillance requirements to address the concerns stated in SIL-380 and to avoid operation in regions of thermal-hydraulic in-stability. Also, in order to provide additional margin for stability, power operation in natural circulation is prohibited.
Since no analysis has been presented for minimum critical power ratio limits or stability characteristics for single-loop operation, the staff will require
- , Technical Specifications which prohibit single-loop operation. After supporting analyses are provided, single-loop operation may be approved upon submittal of appropriate Technical Specifications to avoid operation in regions of potential thermal-hydraulic instability.
Recent BWR fuel design changes that affect stability include decreasing the rod size and increasing the gap conductance because of prepressurization. As a consequence, the maximum decay ratio for most BWRs increases and becomes larger than 0.5, which is the original GE design criterion for BWR stability.
Therefore, GE now proposes a decay ratio of 1.0 for its criterion.
To further evaluate this criterion and other stability criteria, the staff is performing a generic study of the hydrodynamic stability characteristics of light water reactors under normal operation, anticipated transients, and accident conditions. The results of this study will be applied to the staff's
, review and acceptance of stability analyses and analytical methods now in use t
by the reactor vendors.
The stability analysis resulted in a maximum decay ratio of 0.98. Since the calculated maximum stability ratio is equal to that of some of the operating plants (for example, Peach Bottom Units 2 and 3 have a decay ratio of 0.98),
the staff concludes that the thermal-hydraulic stability result is acceptable for plant operation. However, to provide additional margin for stability, natural circulation under normal operation is prohibited by Section 3/4.4.1 of the Technical Specifications.
Because no analysis has been presented for minimum critical power ratio (MCPR) limits or stability characteristics for single-loop operation, the staff will require by Technical Specifications that single-loop operation not be permitted until supporting analyses are provided and approved. Normal operation with an inoperable loop is prohibited by 3/4.4.1 of the Technical Specifications.
River Bend SSER 2 4-2
y _n .
-. -.-.-.~ . -..-. . = = a w - -
l 1
1
~
-i 6 ENGINEERED SAFETY FEATURES
..l 6.2 Containment Systems 6.2.1 Containment Functional Design 6.2.1.3/6.2.1.4 Short-Term Pressure Response /Long-Term Response
't Repressurization Analysis 3
! In Section 6.2.3 of the SER, the staff stated that it will require the appli-
, cant to provide an analysis to show that repressurization of the containment due to all sources of inleakage such as the penetration valve leakage control system (PVLCS) and main steam positive leakage control system (MSPLCS) would not exceed 50% of the containment design pressure during the 30-day period following onset of a LOCA.
In its letter dated January 28, 1985, the applicant stated that the required analysis has been performed and it was determined that a constant 425 scfh in-leakage from both the PVLCS and the MSPLCS would meet the above criterion. How-ever, as a safety margin, the applicant has proposed to specify in the plant's Technical Specifications (TS) the allowable containment inleakage from both the OVLCS and MSPLCS to be 340 scfh, i.e., 80% of the acceptable inleakage.
On the basis of its assessment of the applicant's submittal, the staff finds that the TS inleakage will not repressurize the containmen,t to more than 50% of the containment design pressure in a 30-day period. It is, therefore, acceptable.
LOCTVS/ CONTEMPT Computer Codes In the SER, the staff indicated that it would analyze the containment pressure and temperature response using the CONTEMPT /LT-28 computer code to confirm the applicant's analyses. The staff has completed its analyses using the CONTEMPT-4 code and concludes that the peak calculated pressures and temperatures reported in the SER are in reasonable agreement with the values calculated using the CONTEMPT-4 computer code. This favorable comparison confirms the applicant's analyses. In addition, the applicant provided the results of the analyses per-formed to support the acceptability of the plant's Technical Specifications-allowable initial conditions. On the basis of its review of the applicant's results, the staff concludes that the peak pressure and temperature, in both the drywell and containment, will not exceed their respective design values and therefore, the proposed Technical Specification-allowable initial condi-tions are acceptable.
6.2.1.5 Reverse Pressurization See Section 6.2.1.8 of this SSER for compliance with NUREG-0978.
l River Bend SSER 2 6-1
4 j.
-1 l
a 1 6.2.1.6 Subcompartment Pressure Analysis In Section 6.2.1.6 of the SER, the staff stated that it would verify that the calculated differential pressure for the various subcompartments (reactor pres-sure vessel (RPV) shield wall annulus, drywell head region, and the reactor l water cleanup system rooms) will not exceed the design values.
The applicant's subcompartment nodal models of the different subcompartments consider all major flow restrictions. The staff has reviewed the applicant's models and the results of the analyses of the differential pressure. On the basis of a comparison of the results provided by using similar analytical models for similar subcompartment configurations, the staff finds the applicant's analyses of the differential pressures resulting from the design-basis acci-f dent to be conservative and, therefore, acceptable.
In addition to the subcompartment differential pressure analyses, the applicant has performed force calculations on the RPV and the RPV shield wall resulting from the asymmetric pressure loads calculated in the subcompartment analysis.
The staff has reviewed the applicant's method of determining forces from the differential pressure results and finds these methods and results acceptable.
6.2.1.7 Steam Bypass of the Suppression Pool In Section 6.2.1.7 of the SER, the staff indicated that it would report its findings on the acceptability of the proposed 200*F/ hour reactor vessel cool-down rate assumed in the a This rate was considered in demonstrating the plant's'pplicant's analyses.
suppression pool bypass capability of A/8 of 1.0 ft2, ,
The applicant informed the staff that the plant emergency operating procedures ;
will call for a 100 F/ hour reactor pressure cooldown rate, unless the contain-ment-to-annulus differential pressure exceeds 5 psid in less than 5 minutes. i Under these conditions, the operator will be instructed to proceed with a '
200 F/ hour controlled reactor vessel cooldown. However, in recent discussions with the staff, it was concluded that the plant's operating procedures do not reflect this procedure. To ensure that the plant's operating procedure con-forms to the assumptions used in the suppressien pool bypass design basis, the applicant provided the following information.
The River Bend Station Emergency Operating Procedures (EOPs) will direct the l operator to initiate the automatic depressurization system (ADS) whenever the i containment-to-annulus differential pressure reaches 5 psid. This action has been shown by analysis to provide acceptable containment pressures and, there-fore, is acceptable.
The NRC staff, however, expressed a concern regarding the use of ADS when the containment-to-annulus differential pressure reaches 5 psid, when shutdown via the normal controlled rate of 100 F/ hour might be possible.
The applicant agrees with the staff that ADS may not always be the preferred action. Therefore, the applicant stated that the E0P will be modified prior to startup after the first refueling outage to provide more definitive informa- !
tion to deal with the steam bypass concern.
The staff finds this acceptable. !
- l.
River Bend SSER 2 6-2
(
a_ -- m -.-
d l
6.2.1.8 Pool Dynamics 6.2.1.8.3 Hydrodynamic Load Assessment Section 6.2.1.8.3 of the SER identified the SRV-related pool dynamic loads as an outstanding issue.
The staff has completed its review of the SRV-related pool dynamic loads. The results of this evaluation are summarized below.
Safety / Relief Valve Dynamics Actuation of the safety / relief valves (SRVs) produces transient loac8ing on com-ponents and structures in the suppression pool region. Before actuation, the discharge piping of an SRV line contains atmospheric air and a column of water corresponding to the line's submergence. Following SRV actuation, pressure builds up inside the piping as steam compresses the air in the line.
The resulting high pressure air bubble that enters the pool oscillates in the pool as it goes through cycles of overexpansion and recompression. The bubble oscillations, resulting from SRV actuation and discharge, cause oscillating pressures throughout the pool, resulting in dynamic loads on the pool's bounda-ries and submerged structures.
Severe steam condensation vibration phenomena can potentially occur when high-
-pressure, high-temperature steam is continuously discharged at high mass velocity into the pool, if the pool is at elevated temperatures. These steam-quenching vibrations would result in loads on the pool's boundaries and sub-merged structures.
The River Bend design utilizes the GE X quencher device to mitigate pool tem-perature effects and dynamic forces. In NUREG-0802, " Safety / Relief Valve Quencher Loads: Evaluation for BWR Mark II and Mark III Containments," jfated October 1982, the staff set forth the X quencher generic load specifications and the staff's acceptance criteria. The applicant has performed its evalua-tion and assessment of the containment design based on these loads.
In Attachment A to FSAR Appendix 6A, the applicant provided a detailed compari-son of the River Bend design basis to the GESSAR II methodology. The staff has completed its review of the River Bend load specifications against the generic acceptance criteria and concludes that the SRV pool dynamic loads utilized by the applicant are in conformance with GESSAR II specifications and are, there-fore, acceptable.
LOCA-Related Hydrodynamic Load Assessment The Mark III pool dynamic loads were reviewed at the construction permit (CP) stage for the River Bend Station, Unit 1, and at the preliminary design approv-al (PDA) stage for GESSAR-238NI. The staff concluded at that time that the information available was sufficient to adequately define the pool dynamic loads for nuclear plants at the CP stage of licensing. Since the issuance of the GESSAR-238NI SER (NUREG-75/110, Dec. 1975), GE has conducted further tests ,
and analyses to confirm and refine the original load definitions. To keep the -
NRC and Mark III applicants apprised of the current status of these tests, GE River Bend SSER 2 6-3 I
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l l issued an Interim Containment Loads Report (22A4365) in April 1978 and several
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revisions to it before the GESSAR II application was provided to the staff in March 1980. The GESSAR II application is GE's final design approval (FDA) submittal for its standard " nuclear island" design and is to be referenced by the MARK III operating license (OL) applicants. Appendix 38 of the GESSAR II application provides the standard pool dynamic load definitions for Mark III
' containments, and is the basic document used for review by the staff and its consultants.
The applicant has included Appendix 38 of GESSAR II by reference in Appendix 6A b]1
'q of its FSAR submittal. Except as noted below, the applicant has adhered to all analytical techniques, assumptions, methodologies, and concepts contained in Appendix 3B of GESSAR II. Where plant-unique parameters differ from those of the GE standard plant, River Bend parameters are used.
The staff has completed its review of GE's pool dynamic load definitions and has arrived at a definitive set of hydrodynamic load definitions that can be used by all Mark III containment applicants for operating licenses. The results of this generic review are documented in NUREG-0978, " Mark III LOCA-Related Hydrodynamic Load Definition." They are applicable to River Bend.
Description of Phenomena Figure 6.4 of the SER shows the sequence of events occurring during a design-basis accident (DBA) and the potential loading conditions associated with these events. Following onset of a postulated LOCA, the drywell pressure increases because of blowdown of the reactor system. Pressurization of the drywell causes the water initially standing in the vent system to be accelerated into the pool and the vents are cleared of water. During this vent-clearing pro-cess, the water leaving the horizontal vents forms jets in the suppression pool and causes water jet impingement loads on the structures within the suppression pool and on the containment wall opposite the vents. During the vent-clearing transient, the drywell is subjected to a pressure differential and the weir wall experiences a vent-clearing reaction force.
i Immediately following vent clearing, an air and steam bubble forms at the exit of the vents. The bubble pressure initially is assumed equal to the current drywell pressure. This bubble theoretically transmits a pressure wave through the suppression pool water and results in loading on the suppression pool bound-artes and on equipment located in the suppression pool. As the airflow and steamflow from the drywell become established in the vent system, the initial vent exit bubble expands to equalize the suppression pool hydrostatic pressure.
Test results from GE's large-scale pressure suppression test facility (PSTF) show that the steam portion of the flow is condensed, but continued injection of drywell air and expansion of the air bubble results in a rise in the sur-face of the suppression pool. During the early stages of this process, the pool swells in a bulk mode (i.e., a slug of solid water is accelerated upward by the air). Structures close to the pool surface will experience loads as the rising pool surface impacts the lower surface of the structure. In addi-tion to these initial impact loads, these same structures will experience drag loads as water flows past them. Equipment in the suppression pool will also experience drag loads. ,.
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- l r' After the pool surface has risen approximately 15 feet above the initial pool surface, the thickness of the water ligament has decreased to 2 feet or less and the impact loads are significantly reduced. This phase is referred to as incipient breakthrough (i.e., the ligament begins to break up). To account for (
possible nonconservatisms in the test facility arrangement, the staff has deter- j mined that the breakthrough height should be set at 18 feet above the initial l pool surface.
Ligament thickness continues to decrease until co:nlete breakthrough is reached and the air bubble can vent to the containment free space. The breakthrough process results in formation of an air / water froth and, for load definition pur-poses, is defined to occur at a height of 19 feet above the initial pool surface.
The incipient breakthrough height and the height at which froth loads begin, have been set higher than the maximum prediction from test results to ensure conservatism. Continued injection of drywell air into the suppression pool re-sults in a period of froth pool swell. This froth swell impinges on structures it encounters, but the two phase nature of the fluid results in loads that are much less than the impact loads associated with bulk pool swell.
When the froth reaches the elevation of the floors on which the hydraulic con-trol units for the control rod drives are located (approximately 24 feet above pool level), the froth encounters a flow restriction, which results in approxi-mately 25% of the unrestricted flow area. The froth pool swell experiences a two phase pressure drop as it is forced to flow through the available open areas. This pressure differential represents a load on both the floor struc-tures and on the adjacent containment and drywell. The result is a discontin-uous pressure loading at this elevation. -
As drywell air flow through the horizontal vent system decreases, and the air /
water suppression pool mixture experiences gravity-induced phase separation, up-ward movement of pool water stops and the fallback process starts. During this process, floors and other flat structures experience downward loading and the containment wall theoretically can be subjected to a small pressure increase.
However, this pressure increase has not been observed experimentally.
The DBA pool-swell transient associated with drywell air venting to the pool i typically lasts 3 to 5 seconds. Following this, there is a long period of high steam flow through the vent system; available data indicate that this steam will be entirely condensed in the immediate vicinity of the vent exits. For the DBA reactor blowdcwn, steam condensation lasts for a period of approximately ,
1 minute. Potential structural loadings during the steam condensation phase of the accident have been observed, and are included in the containment loading specification.
As the reactor blowdown proceeds, the primary system becomes depleted of high-energy fluid inventory with a corresponding reduction of the steamflow rate to the vent system. This reduced steamflow rate leads to a reduction in the dry-well/ containment pressure differential which in turn results in sequential re-i covering of the horizontal vents. Suppression pool recovery of a particular .
vent row occurs when the vent stagnation differential pressure corresponds to the suppression pool hydrostatic pressure at that row of vents.
4
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- densing the reduced blowdown flow and the two lower rows will be totally re-covered. As the blowdown steamflow further decreases to very low values, the _
water in the top row of vents start to oscillate back and forth causing what has become known as vent chugging. This action results in dynamic loads on the top vents and on the weir wall opposite the upper row of vents. In addition, an oscillatory pressure loading condition can occur on the drywell and contain-ment walls. Since this phenomenon is steam mass-flux dependent (the chugging threshold appears to be in the range of 10 lb/sec/ft2), it is present for all break sizes. For smaller breaks, it is the only mode of condensation that the vent system will experience.
Shortly after a postulated pipe rupture, the emergency core cooling system (ECCS) pumps will automatically start up and pump condensate water and/or sup-pression pool water into the reactor pressure vessel. This water floods the reactor core and the water may start to cascade into the drywell from the break (the time at which this occurs depends upon break size and location). Because the drywell is full of steam at the time of vessel flooding, the sudden intro-duction of cool water could cause rapid steam condensation and drywell depres-surization. When the drywell pressure falls below the containment pressure, the suppression pool level will depress until the horizontal vents are uncov-ered and air from the containment enters the drywell. Eventually sufficient air will be returned through the vents to stabilize the drywell and containment pressures; however, during this drywell depressurization transient, there could be a period when a significant negative pressure acts on the drywell structure.
A conservative negative-load condition, therefore, was specified for the drywell design.
Small breaks, defined as breaks not large enough to automatically depressurize the reactor, do not result in bounding pool dynamic loads except for the chugging loads and thermal loading conditions on the drywell and . weir walls.
Thermal gradient load definitions are provided for in the design of the walls containing the suppression pool.
Pool Dynamic Load Assessment (1) Generic Load Definition The staff's review of the generic LOCA-related pool dynamic load definition was completed early in 1984. The results of this review and the staff's evaluation of the pool dynamic load definitions are documented in NUREG-0978, " Mark III LOCA-Related Hydrodynamic Load Definition," which was published in August 1984.
With only a few exceptions, the staff found the load definitions proposed by the General Electric Company in Appendix 3B of GESSAR II to be acceptable. A set of acceptance criter.ia was developed by the staff to cover those areas where the proposed loads were not satisfactory. These were included as Appendix C to NUREG-0987. A brief description of these acceptance criteria is provided below.
(a) Pool Swell Velocity Pool swell velocity controls impact and drag loads on the structures ,
between the initial pool surface elevation and the breakthrough elevation. -
GESSAR II proposes a value of 40 ft/sec at all elevations. The staff River Bend SSER 2 6-6
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requires use of an elevation-dependent value which varies linearly from 0 l
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4 (b) Pool Swell Loads on Structures-Attached to the Containment Walls '
OI D The GESSAR II specification corresponds to steady-state drag at a fixed
. velocity of 40 ft/sec. The staff's acceptance criteria require this to be j modified to reflect the change in pool swell velocity given in item above 9" and the inclusion of impact-type forces when the structure is not immersed prior to pool swell. A detailed procedure for evaluating the impact load j is provided in the acceptance criteria.
y
'e (c) Bulk Impact on Small Structures i
The GESSAR II methodology was found acceptable provided the structures in-volved satisfied certain limitations related to structural natural frequency, i size, and location above the pool. The acceptance criteria require that when any of these limitations are not satisfied, the load specification
}; be reviewed by the staff on a plant-unique basis. .
, (d) Froth Impact Loads The GESSAR II methodology was found to be unacceptable. An acceptable alternative was developed by the staff and its consultants and is de-scribed in detail in the acceptance criteria. The new method differs from the GESSAR II approach with respect to maximum froth impact pressure, temporal characteristics of the forcing functions, and region of application.
(e) Draa Loads The GESSAR II methods are found acceptable provided they are modified to account for the change in pool velocity given in item a above and provided they correctly account for the structure-wall interaction effect on drag loads.
(f) Loads on Submerged Structures The GESSAR II methods are acceptable except for computation of acceleration loads on noncylindrical structures and the evaluation of standard drag dur-
.ing the condensation oscillation (CO) phase of the LOCA. The staff requires that the Mark I acceptance criteria as set forth in NUREG-0661 be used to develop these loads.
(g) Impact Loads on Structures Above the Weir Annulus The GESSAR II methods were found to be acceptable except for radial struc-tures located within 1 foot of the top of the weir wall and all structures located between 0 and 0.25 foot above the weir wall. Detailed procedures for evaluation of the impact loads in these cases are provided in the acceptance criteria.
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(a) Applicability of the Generic Load Definition J The staff has examined the information supplied in the FSAR and has con-0 cluded that the generic load criteria described in NUREG-0978 are applic-0}- able to the River Bend Station. All major structures and components that
.j would experience LOCA-related pool dynamic loads are within the range of applicability of the staff-approved methodology in terms of geometry and relative location'in the containment and the suppression pool. The major features of the suppression pool geometry (main vent submergence and ver-
' tical spacing, pool radial width, and pool depth) differ slightly from the standard plant dimensions but these differences are not considered signi-i ficant in terms of their effect on pool dynamic loads. The use of the generic methodology by the applicant to develop the LOCA-related pool dyna-mic load definition is, therefore, acceptable to the staff.
(b) Plant-Unique Load Definition - Impact Loads on Certain Structures Between the Pool Surface and the Hydraulic Control Unit Floors
' The bulk impact load specification in the NRC's acceptance criteria (NUREG-0978) states that the GESSAR II methodology is acceptable, subject to the following limitations:
2 (i) Targets must have combinations of widths and natural frequences such that Figures 38.33-1, 2, 3, and 4 of GESSAR II indicate them to be in the "GESSAR conservative" region with respect to the V = 50 ft/sec pool velocity curve.
(ii) 'There are no structures smaller than 4 feet long.
, (iii)There are no structures closer than 6 feet above the pool.
In plant designs where some specific structures may not meet limitations i or 111, the pulse duration must be shortened with an appropriate adjustment to the 1
pressure amplitude. The load specifications for these structures will be re-viewed by the staff on a plant-unique basis. To aid the Mark III applicants i
.in this complex issue, the staff had its BNL consultants prepare load specifica-tions for structures that do not meet limitations 11 and iii that can, at the option of each Mark III applicant, be used to evaluate these structures.
The River Bend Station structures above the pool satisfy limitation 2.b.f. How-ever, limitations 2.b.ii and 2.b.iii are not satisfied for all structures. The FSAR has utilized a modified version of the Maise criteria (Maise, February 15, 1984) for the design of structures closer than 6 feet from the pool surface and/
or shorter than 4 feet in length. These modifications involve first decreasing
- the impact pressure amplitude by a factor (V/50)2, where V is the slug velocity at the structure elevation, and then increasing it by the factor 0.007/t where t is the impact pulse duration determine according to the requirements of Maise.
The Maise criteria do not allow a (V/50)2 reduction in peak pressure amplitude.
They do, however, permit a somewhat smaller increase in pressure for impulse ,
durations less than 7 msec; i.e. , the requisite increase is not 0.007/t but -
- 0.007 V/50t. It is not clear how the River Bend version of the Maise criteria l
River Bend SSER 2 6-8
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evolved, but the overall result is a load specification that utilizes a peak iJ impact pressure amplitude which is a factor V/50 less than that imposed in 1
Maise's report.
.i To address the staff's concern relative to this apparent nonconservatism, the a
applicant supplied additional information to demonstrate the adequacy of their approach in a letter sent to NRC dated June 3,1985. This information consisted j of a comparison between the River Bend design impact pressures on selected a structures with those predicted by an alternate method previously approved by j the staff. These comparisons demonstrated that the River Bend method yields
" loads that exceed those derived from the alternate method by margins of 1.25 and greater for radially oriented structures and 2.3 and greater for circumfer-ential targets.
i The applicant provided a detailed description of the alternate method in Attach-
'l ment 1 to the June 3, 1985, letter to the staff. The staff and its consultants have reviewed this methodology and find that it conforms in almost all respects to procedural steps previously approved by the NRC staff in NRC reports NUREG-0487 and NUREG-0661. However, two areas of nonconformance have been identified. These are the use of a triangular impulse to represent the impact load and determina-tion of hydrodynamic massHM , f r circumferentially oriented structures from 4
Figure 6-9 of GE Report NEDE-13426P. The methods approved by the staff require use of a versed sine representation for impulse shape and determination of M from Figure 6-8 of NEDE-13426P for all structures. H Both of the modifications used by the applicant imply a reduction in the derived load. This reduction is estimated to range between 10 and 25% because of the use of a triangular pulse (depending on structural natural frequency) and to be about 60% because of the use of the Figure 6-9 to determine M f r circumferen-H tially oriented structures. Application of the correct procedures would there-fore imply an increase of up to 25% in loads for radial targets and a doubling of the load for circumferential targets. Although these increases are substantial, they are still bounded by the margins demonstrated by the comparisons that were provided in the applicant's letter of June 3, 1985. Accordingly, the staff finds this plant-unique load specification acceptable.
Conclusion The staff has completed its review of the LOCA-related pool dynamic loads for the River Bend Station and finds the load definition used by the applicant con-servative and acceptable.
6.2.1.9 Mark III-Related Issues In a letter dated May 8,1982, John Humphrey, a former GE engineer, notified i Mississippi Power and Light Company (MP&L) of certain safety concerns regarding the Grand Gulf Mark III containment design. The staff met with MP&L, GE, and Mr. Humphrey to determine the character of these concerns and to establish an appropriate program for their resolution. A number of other Mark III plant applicants attended the meeting, including representatives of Gulf States
- Utilities (GSU) for River Bend. ,
1 i
j River Bend SSER 2 6-9
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1 The staff has reviewed the information supplied by the applicant for River Bend 4
in letters dated February 28, 1984, and January 23, 1985. These letters con-
. tain the applicant's responses to all the Humphrey concerns. The details of the staff's review of each of the 66 individual Humphrey concerns (covering 22
, major areas) are contained in Appendix K. The staff concludes that all but two major areas (covering 8 individual Humphrey concerns) and a small portion of a
, third area have been satisfactorily resolved for River Bend.
The two areas for which further information will be required before resolution can be reached are the SRV discharge line sleeve steam condensation load defini-
, tions and the RHR heat exchanger relief line load definitions. The third, and A minor, area is the effect of encroachments on submerged structure loads. Reso-1,
'I lution of this issue is expected to be uncomplicated. 7
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.j U , On the basis of the information received to date, regarding the SRV discharge
- Q <p - sleeve steam condensation loads, the staff finds that sufficient justification d has been provided for power operation up to 5% of rated power.
of The staff will require that the applicant not use the residual heat removal system in the steam condensing mode pending resolution of the staff's concerns in the second area, the RHR heat exchanger relief line load definitions. The
, loads from other discharge lines in the suppression pool are not expected to produce bounding load definitions and no restrictions on power operations are needed during the time it takes for the applicant to respond to the confirmatory questions raised by the staff for these lines.
The staff will assess the applicant's responses to its request for additional information, as identified in the report (Appendix K) on these three Humphrey areas, and will report its results in a future supplement to the SER. However, this issue is resolved because the license will be conditioned on the applicant not using the RHR in the steam-condensing mode.
6.2.2 Containment Heat Removal System See Section 6.2.1.8 of this supplement for discussion on compliance with NUREG-0978.
6.2.3 Secondary Containment Functional Design In Section 6.2.3 of the SER, the staff indicated that the secondary containment is comprised of the annulus building, the auxiliary building, and the fuel building and completely surrounds the primary containment. It is maintained at a negative pressure during normal plant operation.
Since then, the applicant has proposed to maintain the auxiliary building and fuel building at atmospheric pressure (0.0 psig) and the annulus (shield) building at 3.0 inches of vacuum water gauge (WG).
Assuming the onset of a LOCA along with loss of offsite power, the applicant has performed analyses to determine the length of time it takes to bring the secondary containment building (i.e., the annulus (shield) building, the auxiliary building, and the fuel building) to -0.25 inch WG. ,
River Bend SSER 2 6-10
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1 The annulus analysis, assuming the normal operating condition of -3.0 inches WG,
! inleakage of 2000 ft3/ min, and 38 seconds of delay for the standby gas treatment system (SGTS) to get up to speed, indicates that -0.25 inch WG is attained in 203 seconds. The results also indicate that for approximately 179 seconds the
- annulus pressure is greater than -0.25 inch WG.
The analysis of the auxiliary building, which is maintained at atmospheric conditions during normal plant operation, indicates that -0.25 inch WG will be attained in 111 seconds after onset of the LOCA. The analysis assumed the building inleakage to be 5000 ft3/ min and a delay of 38 seconds for SGTS startup.
The applicant analysis of the fuel building, which is normally maintained at atmospheric pressure, indicates that the -0.25 inch WG will be attained in 31 seconds. The analysis assumed an inleakage of 5000 ft3/ min and the fuel building charcoal filtration system delay of 18 seconds.
Before plant operation begins and at each refueling outage, the annulus build-ing, the auxiliary building, and the fuel building, will be tested to verify that the inleakage will not exceed the values used in the analyses (i.e., 2000 ft3/ min, 5000 fta/ min, and 5000 ft3/ min at pressures of -3.0 inches WG, -0.25 inch WG, and -0.25 inch WG, respectively).
Also, the applicant will perform a-test before plant operation and at each refueling outage to verify that the SGTS will draw down the annulus building and the auxiliary building to -0.25 inch WG in less than 173 and 81 seconds, respectively, and the fuel building charcoal filtration system will draw down the fuel building in less than 26 seconds.
On the basis of its review of the applicant's analyses and the proposed Tech-nical Specifications, the staff concludes that the secondary containment func-tional design is in compliance with the provision of BTP CSB 6-3 and is there-fore, acceptable.
6.2.4 Containment Isolation System 6.2.4.3 Containment Purge System Drywell Containment Purge Systems In Section 6.2.4.3 of the SER, the staff stated that the applicant should commit to the implementation of a nine point interim program for assessing the need for use of the purge system. This program would be carried out during the first fuel cycle.
In its letters dated November 8, 1984, and January 31, 1985, the applicant pro-vided its response and commitment to this nine point interim program.
The applicant stated that an analysis was performed to establish the number of hours per year that a containment purge system will have to be used to maintain the airborne activity below 25% of the maximum permissible concentration (MPC) s specified in 10 CFR 20 during normal operation. The applicant's analysis indi- ,
cattd that 7300 hours0.0845 days <br />2.028 hours <br />0.0121 weeks <br />0.00278 months <br /> per year are required to limit the airborne activity to -
23P.of the MPC. The applicant did not provide this analysis for staff review.
River Bend SSER 2 6-11 i l
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, j It should be noted, however, that the proposed 7300 hours0.0845 days <br />2.028 hours <br />0.0121 weeks <br />0.00278 months <br /> of usage is 80% of
,;e continuous usage or 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> per day. This does not represent a serious at-H '
tempt at limiting use of the purge system. In the absence of a revised esti-mate by the applicant, the staff has selected a 2000-hour /365-day limit. The l staff has discussed this Technical Specification limit with the applicant.
] The applicant also indicated that it will implement a data collection program
, during the first fuel cycle to collect and evaluate the operating experience
. with the containment purge systems at the River Bend Station. It should be noted that, as part of this effort, the applicant will be required to determine the minimum size purge valve that can be used to reduce the airborne activity in the containment to levels that are consistent with the provisions of
4
, The applicant stated that a containment access management program has been developed to minimize personnel access and residence time in,the containment.
With regard to the drywell purge system, the applicant stated that the use of the system will be limited to 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> / year (cumulative) in Operating Mode 3 for either drywell pressure control or for reducing drywell activity level.
This limit will be 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> / year (cumulative) for Operating Modes 1 and 2 for drywell pressure control, as stated in the staff's nine point program.
As part of the staff's nine point program for purge system use, the staff stated that whenever the drywell is being vented, the vent should discharge into the containment; moreover, the containment shall not be vented or purged, whenever the drywell is being vented or purged.
The applicant indicated that such a restriction, i.e. , requiring a drywell to
, containment purge, would significantly increase the radioactivity in the containment and would require additional containment purge time to maintain the containment activity-level below 25% of MPC.
To avoid the increase in the containment radioactivity level during drywell pressure control operations, the applicant proposed to operate the containment purge system in conjunction with the drywell purge system. To eliminate the staff's concern about the potential for containment bypass during these pres-sure control operations, the applicant stated that a qualified, dedicated opera-tor will administer the drywell purge system operation to ensure that the dry-well vent path bypassing the containment will not be open for more than 2 minutes /
venting operation. The plant's operating procedures will direct the dedicated operator to open one division of supply and exhaust drywell isolation valves (e.g., the inboard valves) and, without delay, to open the other division (e.g.,
the outboard valves) of supply and exhaust drywell isolation valves. Once the second division is indicated as fully open, the dedicated operator will, in less than 2 minutes, begin to close at least one division of the drywell isolation valves.
Since the applicant has not demonstrated the ability of the drywell purge iso- )
lation valve to close under the anticipated accident condition in the_dryw' ell, these valves will be required to be loded closed during OperatingdSLditioh'lg ))M .
1 through 3. Operability of the 36-inch containment purge valves is discussed in Appendix H. Limitations on the use of unqualified 24-inch drywell purge I valves-are discussed in Appendix H.
River Bend SSER 2 6-12
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'I The applicant indicated that it may elect to utilize the hydrogen mixing system Lj _
for drywell pr' essure control with no limitations on the total time for venting during the first fuel cycle.
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The concern regarding the use of the hydrogen mixing system for drywell pres-
' ~ sure control is the potential of it becoming a suppression pool bypass leakage path. The applicant stated that the suppression pool bypass area with the
- 6-inch hydrogen mixing system inlet valve open is 0.20 ft2 which is bounded by the allowable bypass leakage. Therefore, the staff finds the applicant's pro-posa) to use the hydrogen mixing system for drywell pressure control to be ac-cepte.ble. However, since the applicant has not demonstrated that these valves
' are capable of closing under accident conditions in the drywell, certain restric-
. tions should be applied. In Operating Modes 1 and 2, the total number of hours
,3 used should not exceed 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> /365 days and 'in Operating Mode 3 the number of f hours should be limited to 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> /365 days.
The applicant stated that, except for Items 1(c) and 3 of Branch Technical Posi-
- tion (BTP) CSB 6-4, the River Bend Station's drywell/ containment purge system i will comply with the requirements set forth in the BTP. With regard to Item 1(c),
the staff has determined that the use of the existing system is acceptable until it is determined, based on the nine point interim program to be implemented dur-
, ing the first fuel cycle, when purging is needed and what line size is needed to accomplish the function.
With regard to Item 3 of BTP CSB 6-4, recirculation of containment atmosphere will be accomplished through the external purge filter for the first fuel cycle and until the staff completes its evaluation of the report to be submitted at the end of the first refueling cycle.
Finally, the applicant has committed not to use two standby gas treatment system (SGTS) trains in the fast purge mode in Operating Modes 1 through 3 and that in
, those operating modes, only one SGTS may be used with the normal containment purging, provided that both SGTS subsystems are operable. The staff finds the applicant's commitment acceptable.
c 6.2.5 Combustible Gas Control in Containment In Section 6.2.5 of the SER, the staff stated that it will perform a confirma-i tory analysis to determine the acceptability of the hydrogen generation rate calculated by the applicant. On the basis of the results of its calculations, the staff concludes that the applicant's analyses are reasonably conservative i and are, therefore, acceptable. On the basis of its review of the combustible gas control system for compliance with all the acceptance criteria of SRP 6.2.5, the staff concludes that the applicant's design includes acceptable systems for i monitoring, controlling, and mixing the hydrogen and oxygen that may be gener-j ated in the containment following onset of a LOCA. Specifically, the combusti-ble gas control system satisfies the design and performance requirements of 1' 10 CFR 50.44 (except for those portions dealing with postulated degraded core ~
accidents, which is addressed in NUREG-0660 Item II.B.8, below); the provisions 1
of RG 1.7; and the requirements of GDC 41, 42, and 43. The system is, there-fore, acceptable.
^
River Bend SSER 2 6-13 1
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i 4 i NUREG-0660 Item II.B.7 - Analysis of Hydrocen Control and l Item II.B.8 - Rulemaking Proceedings on Degraded-Core Accidents As previously reported in the River Bend SER, the staff requested that the 1 applicant propose a program to improve the plant's hydrogen control capability.
. .i ' Specifically, this includes the hydrogen generated from a metal-water reaction involving up to 75% of the active cladding, which is well beyond the amount of hydrogen specified in 10 CFR 50.44(d),
i ;
In response to the NRC request, the applicant proposed a hydrogen igniter system for,the River Bend Station, similar to that installed in the Grand Gulf Nuclear Station. As reported in the SER, the applicant has indicated that justification a
of the adequacy of the igniter system will be the generic findings of the Hydro-
' gen Control Owners Group (HCOG), as supplemented by plant-specific design con-siderations. The NRC published an amendment to the hydrogen rule, 10 CFR 50.44, on January 25, 1985 (50 F_R 3498). This amendment, which affects the River Bend Station, became effective on February 25, 1985.
In accordance with the above-cited amendment to 10 CFR 50.44, the staff re-quires compliance with 10 CFR 50.44(c)(3)(iv)(A) before authorizing operations L
' above 5% of full power. A preliminary analysis of the proposed hydrogen igniter system will be needed which describes the system design and which addresses:
(1) the peak containment pressure resulting from the postulated hydrogen combustion (2) the peak pressure capability of the containment (3) the survivability of essential equipment For this preliminary analysis, the applicant may adopt by reference any prior analyses that may be applicable to the River Bend Station. However, all signi-ficant plant-unique features of the River Bend Station will have to be addressed in the applicant's submittal.
Also, consistent with 10 CFR 50.44, as amended, the staff finds that for opera-tions at or below 5% of full power, the hydrogen igniter system is not needed.
- 6.2.6 Containment Leakage Testing
, 6.2.6.3 Type C Test Penetration Valve Leakage Control System (PVLCS)
In Section 6.2.6.3 of the SER, the staff indicated that the applicant had pro-posed to air leak test the valves equipped with the PVLCS but exclude the measured leakage from the combined leak rate for the local Type B and C leak rate tests, i.e., 0.6 L,.
The PVLCS is composed of two independent redundant systems. The elimination of leakage is accomplished by creating a pressure barrier at the closed contain-
, ment isolation valve by injecting air into the space between the seats of the double-disc gate valves. However, since the system is manually operated and it :
takes about 30 minutes from the onset of a LOCA before the PVLCS becomes fully River Bend SSER 2 6-14 n- - . - - , -- n - - - - - - - - - - , , - - - ,~,.v, - - - - - - --- - - -,, - - - - - -r-., - - -, , . , - - - - - - . = - = - - - - ,w --y--, ww
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operational, the potential exists for containment effluent to leak through these valves during the initial 30-minute period.
O In FSAR Amendment 19, the applicant indicated that the penetrations served by the PVLCS are required to meet a leakage rate limit specified in Technical 1 Specification 3/4.6.1.2. The applicant further stated that this leakage limit is included in the offsite radiological dose assessment as a separate term.
On the basis of its review of Technical Specification 3/4.6.1, the staff con-cludes that the applicant's approach in resolving the staff concern regarding leakage from valves equipped with PVLCS is conservative and, therefore, acceptable.
6.3 Emergency Core Cooling System 6.3.3 Performance Evaluation
~6.3.3.3 Functional Design Plant-Specific LOCA Analysis In its SER (Sections 6.3.3.3 and 15.9.4), the staff reported the results of a lead plant LOCA analysis that was stated by the applicant to be representative of River Bend. The SER also noted that the applicant had committed to supply a plant-specific LOCA analysis for River Bend before fuel loading.
The applicant provided the LOCA analysis specific for River Bend in FSAR Amend-ment 15, dated November 1E84. The plant-specific LOCA analysis included a spectrum of large and small pipe breaks and indicated that the most limiting break is a design-basis break in a recirculttion suction pipe. As for the lead plant, an assumed failure of the low pressure coolant injection (LPCI) diesel generator, coincident with the break, resulted in the worst single failure condition. The plant-specific results demonstrate compliance with the require-ments of 10 CFR 50.46 as is shown in Table 6.2 (Revised).
From its review, the staff concludes that the plant-specific LOCA analyses for River Bend are acceptable. This issue, Outstanding Issue 8, is closed.
River Bend SSER 2 6-15
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, ;j Parameter analyses break Allowable Peak cladding temperature (PCT) 2144*F 2200*F
- J Maximum cladding oxidation 2.32% 17%
'j Maximum total hydrogen generation 0.16% 1%
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l 7 INSTRUMENTATION AND CONTROLS l
f 7.2 Reactor Protection System
- 7.2.2 Specific Findings 7.2.2.1 Circuits and Sensors Located in or Routed Through Structures Not Seismically Qualified v .
- i. Instruments used to monitor turbine control valve (TCV) fast closure, turbine stop valve (TSV) closure, main condenser vacuum, main steamline pressure, and l turbine first-stage pressure are located in the turbine building, a structure
! that is not seismically qualified. These instruments provide inputs to the reactor protection system (RPS), rod control and isolation system (RCIS), con-f
' tainment and reactor vessel isolation control system (CRVICS), and the reactor recirculation system (RRS). The specific instruments, identified in Sec-tion 7.2.2.1 of the River Bend SER, are classified as Class 1E, are seismically i
and environmentally qualified, and are treated as safety related in terms of identification, mounting, and separation.
i
' The staff has reviewed the isolation provided between those portions of instru-ment channels located in or routed through the turbine building and the down-stream safety-related circuits (logic and actuation circuits) to ensure that electrical faults occurring within the non-seismically qualified turbine build-ing will not propagate back to and damage downstream safety-related circuitry.
Isolation between faults, which could occur in aress not seismically qualified and the remainder of the protection system is provided in one of two ways. -For analog signals, isolation is provided using several stages of relay coil-to-contact isolation between the trip unit. outputs and protection system actuation logic. In addition, each cable is run .1 sensor to the protection system cabinet',n s. a separate For digital grounded signalsconduit from the (e.g., limit switch position), isolation is provided using a combination of fuses, circuit
, breakers, and coil-to-contact isolation. All of the subject instrument channels are designed to " fail safe" (i.e., protective action occurs) on loss of power.
In addition, for the TSV and TCV scram signals, diverse (backup) scram signals are provided.
Wiring for all instrument channels is routed in rigid metallic conduit. The wiring and instrument layout in the turbine building is designed to limit the effects of an event to as few channels as possible, so that the ability of the RPS, RCIS, CRVICS, and RCS to perform their safety functions is not degraded.
The applicant has stated that an analysis for the effects of a 480-V ac hot short on any RPS channel has been performed and confirms that no safety func-tions are lost as a result.
On the basis of its review, the staff concludes that sufficient isolation is provided to prevent damage to downstream safety-related circuits from electri-cal faults occurring in circuits located in areas that are not seismically qualified. This resolves Confirmatory Item 22, as listed in Table 1.4 of the :
SER and its supplements.
River Bend SSER 2 7-1 f
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r 7.2.2.7 Reactor Mode Switch
.l IE Information Notice 83-42, issued on June 23, 1983, provided information about mode switch malfunctions at several operating reactors. The specific
., failure mechanism was mode switch contact pcsitioning errors resulting from large design clearances and a tendency for the plastic can shaft used in the switch to twist (this shaft is actually composed of 22 individual interlocking sections). Subsequently, the General Electric Co. (GE) issued a Field Disposi-tion Instruction (FDI) to the applicant for installation of a new mode switch using a solid metal shaft. However, during functional testing of the upgraded mode switch at Susquehanna Unit 1, problems were encountered regarding proper mode switch operation that resulted in further modifications to the switch.
These modifications included cam identification markings, an improved torsion bar/ shaft, milled can surfaces, and external contacts fixed in place with epoxy.
Subsequently, the switch was tested successfully, and it was determined that the remodified mode switch would function properly for up to 1000 cycles.
The staff asked the applicant to confirm that the additional mode switch modifications found necessary as a result of functional testing performed on the Susquehanna mode switch have been made to the mode switch at River Bend, l and that the new mode switch has been installed and successfully tested. By
. letter dated February 15, 1985, the applicant stated that a new mode switch has been installed and functionally tested in accordance with the GE FDI.
During a telephone conversation on March 20, 1985, the applicant stated that '
the additional modifications found necessary from testing at Susquehanna, were made to the River Bend mode switch before the switch was shipped to the site.
On the basis of this information, the staff considers Confirmatory Item 27, as listed in- Table 1.4 of the SER, to be resolved. The NRC regional staff will be advised to follow this issue to ensure that the remodified mode switch has been successfully tested before unit startup.
7.3 Engineered Safety Features Systems 7.3.2 Specific Findings 7.3.2.3 ADS Actuation (TMI Action Plan Item II.K.3.18)
The automatic depressurization system (ADS) has been modified in accordance with TMI Action Plan Item II.K.3.18 to automatically initiate in the absence of a high drywell pressure initiation signal. The ADS functions as a backup to the high pressure core spray (HPCS) system by depressurizing the reactor
- vessel so that low pressure systems may inject water for core cooling. In the initial design, each ADS train was actuated upon coincident signals of reactor
. vessel low water level (two level 1 signals and one level 3 signal are required),
high drywell pressure (two signals required), a low pressure emergency core cooling system (ECCS) pump running (one of two pumps), and a 105-second time delay which allows ADS to be bypassed if the operator believes the actuation signal is erroneous or if vessel water level can be restored. However, for transient and accident events which do not produce high drywell pressure, and are further degraded by a loss of HPCS, manual actuation of the ADS would be required to ensure adequate core cooling.
In order to eliminate the need for manual ADS actuation to ensure adequate :
core cooling, the applicant has installed bypass timers which will automatically River Bend SSER 2 7-2 i
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bypass the drywell high pressure inputs required for ADS actuation if reactor vessel water level remains below the ADS initiation setpoint (level 1) for a sustained period (approximately 6 minutes). Thus ADS actuation will occur in the absence of a drywell high pressure signal after the 6-minute delay, and the additional 105-second delay, if a reactor vessel low-water-level condition
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still exists and a low pressure ECCS pump is running. Annunciation is provided Wi in the control room when the 105-second timers and the high drywell pressure il bypass timers are initiated. Annunciation is also provided when a reactor ves-sel low-water-level or drywell high pressure condition is detected.
Four-time delays have been added, one for each ADS drywell high pressure initia-j tion channel. There are two ADS actuation c bnnels (Division 1 and Division 2),
i either of which can perform the required ADS function. There are two bypass timers associated with each ADS division. The staff has required that the River Bend Technical Specifications contain provisions for periodic surveillance and calibration of the high drywell pressure bypass timers automatically reset when i vessel level increases above level 1. This is contained in Section 3/4.3.3.of
, the River Bend Technical Specifications.
Another modification made to the River Bend ADS consists of the addition of l two ADS inhibit switches (one per ADS division) that permit the operator to override the ADS automatic blowdown logic if necessary. These manual inhibit switches prevent automatic ADS actuation, but do not inhibit the safety / relief valve (SRV) pressure relief function, manual ADS actuation, or individual SRV control. The addition of the ADS manual inhibit switches will simplify the execution of those steps in the Emergency Procedures Guidelines (EPGs) related to mitigation of anticipated transient without scram (ATWS). The inhibit switches are two position (NORMAL and INHIBIT), maintained-contact, keylock switches. Placing a switch in the INHIBIT position, which defeats the ADS automatic actuation logic for the associated division, causes " ADS OR SRV INOPERATIVE" annunciation in the control room for that division and actuates an " ADS INHIBITED" status light on control room panel 1H13*P601.
The staff concludes that the River Bend ADS design conforms to the requirements of TMI Action Plan Item II.K.3.18 regarding ADS automatic actuation to ensure adequate core cooling, and therefore, is acceptable. This resolves Confirma-tory Item 28, as listed in Table 1.4 of the SER and its supplements.
7.4 Systems Required for Safe Shutdown 7.4.2 Specific Findings 7.4.2.3 Standby Liquid Control System The River Bend standby liquid control system (SLCS) design includes an interlock which prevents the boron storage tank suction valves (C41-F001A&B) from opening in response to a system level manual initiation signal if test tank suction valve C41-F031 is open. The interlock is provided to prevent dilution of the sodium pentaborate solution (from water in the test tank). During its initial !
review, the staff raised the concern that SLCS inoperable status indication l (annunciation) was not provided in the control room when valve C41-F031 is l open. Valve position indication lights are provided; however, the staff does
. not consider valve position status lights to be a positive indication of safety :1 system inoperability.
River Bend SSER 2 7-3
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- By letter dated February 5,1985, the applicant submitted an SLCS design change to provide an additional annunciator point on control room panel 1H13-P601 which indicates "SLCS INOP - F031 NOT FULLY CLOSED." This alarm function will be provided by a Division 2 limit switch mounted at valve C41-F031. The input to the annunciator is routed through an isolator assembly to isolate divisional
' circuits from the non safety-related annunciator system.
On the basis of its review, the staff concludes that adequate indication of
~ SLCS inoperability is provided in the control room when test tank suction valve C41-F031 is open. This resolves Confirmatory Item 33, as listed in Table 1.4 of the SER. The staff has verified during the Technical Specification review for River Bend that periodic testing of the interlock function is performed to ensure that the interlock has not failed in a manner that precludes the SLCS function. The applicant agreed to this periodic testing in accordance with Technical Specifications surveillance 4.1.5.D.1 in a letter dated July 26, 1985.
- 7. 5 Information Systems Important to Safety 7.5.2 Specific Findings 7.5.2.5 Temperature Effects on Level Measurements The staff was concerned that high drywell temperatures causing water density changes in reactor vessel water level instrument sensing lines could result in non-conservative false level indications in the control room (i.e., indicated level higher than actual level). Vessel level is determined by measuring the difference in head between a fixed reference column of water (connected to the reactor vessel steam space via a condensing chamber) and a variable column of water which changes with actual level in the vessel (i.e., differential pressure instruments are used). If the change in head due to density changes from dry-well heatup for both the reference and variable legs is not equal, a measure-ment error is introduced. The amount of error is dependent upon the difference in vertical drop between the reference and variable legs inside the drywell.
By letter dated November 21, 1984, the applicant provided information concerning the maximum vessel level indication errors based on the vertical drops of the level sensing lines inside the drywell, the calibration conditions (temperature and pressure) for the level instruments, and a maximum drywell temperature of 340*F. The data provided indicate that with the exception of the fuel zone range instruments, vessel water level indication errors are in the conservative direction (i.e., indicated level is lower than actual level). This included the narrow- and wide-range instruments; the wide-range instruments provide level indication from approximately 2 to 3 inches above the top of the active fuel (TAF) to approximately 50 inches below the centerline of the main steamlines.
The maximum error in level indication for the fuel zone range instruments is 11.02 inches in the non-conservative direction. The fuel zone range instruments monitor vessel level from the bottom of the fuel to 50 inches above TAF. There are no protection or control functions performed by the fuel zone range instru-ments. The applicant has stated that the River Bend Station em'rgency operating procedures will contain information which allows the operators 40 determine the maximum water level measurement errors given drywell heatup beyond normal ambient conditions.
5 River Bend SSER 2 7-4
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q On the basis of its review, the staff concludes that the difference in vertical i; drop between reactor vessel water level instrument sensing lines (reference and variable legs) inside the drywell will not result in false level indications beyond the capability of the control room operator (s). This resolves Confirma-tory Item 35, as listed in Table 1.4 of the SER.
M 7.6 Interlock Systems Important to Safety a
] 7.6.2 Specific Findings
'd 7.6.2.4 End-of-Cycle Recirculation Pump Trip s
['i Two redundant Class IE actuation logics [ engineered safety features (ESF)
[ ' Division 1 and ESF Division 2] are provided to initiate an end-of-cycle recir-culation pump trip (EOC-RPT) on either TSV closure or TCV fast closure. Either logic division will trip both recirculation pumps. In the original design, 4- 4 each logic was automatically bypassed when the reactor power level decreased c
below 30% of rated as sensed by a single-turbine first-stage pressure transmit-ter (C71-N052A and C71-N0528 for Divisions 1 and 2, respectively). This raised staff concerns that a transmitter or sensing-line failure could effectively
+
bypass the E0C-RPT function of a given division, and that such a failure might go undetected.
Since the initial review, two additional turbine first-stage pressure trans-mitters (C71-N052C and C71-N0520) have been provided, and the EOC-RPT automa-tic bypass logic has been changed to 2-out-of-2 logic for each division. The i bypass for a given division is automatically removed when either associated turbine first-stage pressure channel senses that pressure has increased above the setpoint (i.e., pressure has increased above that corresponding to 30%
reactor power). Thus, no single failure can cause automatic bypass of the EOC-RPT function for a given division, nor can any single failure prevent the bypass condition from being automatically removed when the conditions that permit the bypass are no longer satisfied. The turbine first-stage pressure instrument channels are powered from the reactor protection system (RPS) buses. Isolation between circuits powered from the RPS and ESF buses is provided using Potter-Brumfield MDR relays. These relays have been found acceptable as isolation devices as discussed in Section 7.2.2.6 of the River Bend SER.
Annuciation is provided on control room panel 1H13*P680 at a single annunciator point, " CONTROL VALVE FAST CLOSURE AND TURBINE STOP VALVE TRIP BYPASS," when any of the four turbine first-stage pressure instrument channels detect pressure less than the bypass setpoint. These same channels are also used to bypass the reactor scram function on TCV and TSV closure when reactor power is less than 30% of rated power. Two 2 position (NORMAL and INOP) maintained contact switches are provided (59A for Division 1 and S98 for Division 2) which allow the operator (s) to manually bypass the EOC RPT function. Placing either switch in the INOP position will bypass the associated division of EOC RPT logic, and will cause annunciation in the control rcce indicating the bypass condition, ~
"RECIRC PUMP TRIP SYS A (B) IN MANUAL BYPASS."
Transmitters C71-N052A, B, C, and D provide inputs to trip units C71-N652A, B, C, and D, respectively. These trip units are located at control room cabinets 1H13*P691, 2, 3, and 4 (RPS cabinets). The trip units contain panel meters L that display the value of the measured parameter which can be scaled in units River Bend SSER 2 7-5 t
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l of the process variable. The meters are not considered an integral part of the safety system channels, since they are not in series with the transmitter current loops. The meters monitor the normalized voltage at the output of the input buffer amplifiers (this voltage varies from 1 to 5 V for a corresponding 4- to 20 mA signal from the transmitter). The staff has determined that these
' meters are adequate for performing instrument channel checks to periodically verify that the output values of all four turbine first-stage pressure chan-nels are within an acceptable band. A deviation of one output value from the remaining three is indicative of a channel malfunction. The staff will verify 4
that the River Bend Technical Specifications contain provisions for channel checks of the turbine first-stage pressure instrument channels.
On the basis of its review, the staff concludes that adequate indication of an EOC-RPT bypass condition is provided in the control room consistent with the requirements of Section 4.13 (" Indication of Bypasses") of IEEE Std. 279-1971, and that sufficient means are provided to assess channel behavior during operation to verify that the turbine first-stage pressure intrument channels are functioning properly. This resolves Confirmatory Item 37, as listed in Table 1.4 of the SER and its supplements.
7.7 Control Systems 7.7.2 Specific Findings 7.7.2.3 Emergency Response and Information System (ERIS)
The ERIS is designed to collect, store, and process plant data from both safety-related and non-safety-related systems, and to provide visual (cathode-ray tube, CRT) displays of plant status information and printed records of tran-sient events. The ERIS will be used to monitor more than 1400 test points dur-ing startup transient testing, as identified by the ERIS input / output signal list for River Bend. More than 1000 of these will remain connected after startup The staff's preliminary review of the ERIS identified the following areas requiring additional information to complete the review:
isolation between the non-safety-related ERIS and safety-related input circuits failure of the ERIS data acquisition system (DAS) self-test circuits, and the effect on safety-related circuits the software development and qualification program applied to the ERIS, and the criteria, controls, quality assurance, and testing procedures applied during software development and production to independently verify that the software design conforms to the functional requirements susceptibility of the ERIS to noise / interference and line surges / spikes use of the ERIS to perform surveillance required by the plant Technical Specifications Subsequently, the applicant provided additional information concerning these ,
items and the IRIS design was reviewed during meetings held between the staff -
D and the vendor (GE).
River Bend SSER 2 7-6
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l 1' -The staff reviewed ERIS drawings and identified the safety-related and non-safety-related portions of the system. The isolation provided between safety-related and non-safety related circuits was reviewed and found to conform with 1 _ the guidelines of NUREG-0737, Supplement 1 (" Clarification of TMI Action Plan Requirements: Requirements for Emergency Response Capability"), issued by <
- a Generic Letter 82-33. Isolation is accomplished using fiber optic cable which varies in length from 2 feet to 5000 feet. Characteristics of fiber optic E
cable include nonsusceptibility to the coupling of crosstalk and electromagnetic
- 4 interference (EMI). Because optical fibers are totally dielectric, the elec-y trical energy resulting from a fault at the output /non-Class 1E end of the F 1
- ' cable will not propagate through the cable, and thus, will not degrade circuits at the input / Class 1E end.
' All inputs to the ERIS enter through remote input modules (RIMS). Two types of RIMS are used: GEDAC-4800 and GEDAC-5500. GEDAC-4800 modules are qualified as Class 1E devices to IEEE Stds. 323-1974 and 344-1975. The GEDAC-5500 4
modules are used in applications that are not Class 1E. The remainder of the
!- ERIS (downstream of the RIMS) is not Class 1E. Inputs to the ERIS from a given t'
division are routed to a cabinet (which houses the RIMS) located above the
- divisionally associated power generation control complex (PGCC) termination
', cabinet in the control room. Some RIMS are mounted locally. In these cases, I
the signals are transmitted to the control room via fiber optic cable. The
- RIMS, multiplexers (MUX), and data formatter module (DFM) are combined to form the DAS portion of the ERIS. Each DAS component executes a self-test routine which checks for valid hardware and software within the module as well as for valid external connections where possible. The applicant has stated that fail-ure of the DAS self-test circuitry has been analyzed and demonstrated not to impair safety-related signals. Alarms are provided in the ERIS/DRMS (digital radiation monitoring system) computer room upon DAS self-test detected failures.
The applicant has indicated that this room is continuously manned during normal operation.
The staff is currently reviewing the software methodology used and implementation of the methodology in the final ERIS design (i.e. , verification and validation, V&V) as part of the evaluation of the generic safety parameter display system 1
(SPDS) proposed for GESSAR II. GE has stated that the basis for the V&V program used in the design of the ERIS was NSAC-39 (Verification and Validation
! for Safety Parameter Display Systems). The staff has reviewed this program and found it to be in conformance with the guidelines of NUREG-0737, Supplement 1, j and therefore acceptable. A draft evaluation of the GESSAR II SPDS is provided i as the enclosure to a letter dated December 18, 1984 from C. Thomas, NRC, to G. Sherwood, GE. Those aspects of the V&V program for the GESSAR SPDS which are still under review will be addressed in the staff's final evaluation,
- scheduled'to be completed by May 1985.
The Class 1E portions of the ERIS are designed in accordance with IEEE Std. 472-1974 (" Guide for Surge Withstand Capability"). In addition, the ERIS Class 1E components were tested for susceptibility to electromagnetic interference (EMI), including radiofrequency interference (RFI) (e.g., walkie-talkies), in l accordance with GE qualification program standard procedures.
FSAR Section 7.7.1.7.2 indicates that the ERIS will be used to aid plant personnel in performing routine surveillance tests during commercial operation.
l River Bend SSER 2 7-7 1
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.I This raised staff concerns regarding the use of the ERIS for testing safety-related instrumentation. However, the coplicant has stated that the ERIS will not be used to satisfy any Technical Specification surveillance requirements for protection system instrument or logic channels. The ERIS will be used for scram time testing and integrated leak rate testing.
- On the basis of its review, the staff concludes that the ERIS satisfies the applicable criteria identified in Section 7.7 of the Standard Review Plan
.i' (NUREG-0800), and therefore, is acceptable. This resolves Confirmatory Item 43, as listed in Table 1.4 of the SER.
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I 8 ELECTRIC POWER SYSTEMS g,9. I
! 8.3 Onsite Emergency Power Systems i 56 I p 445e 8.3.1 AC Power Systems / Nf f8'a,W )
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In Section 8.3.1 of the River Bend SER, the staff Js ated that it,d shed to review a revised figure of the electrical protectibn assembly (EPA) reactor protection system (RPS) motor generator set interconnections in order to con-firm the adequacy of the installation of the EPAs and interconnections between the non-Class IE RPS motor generator sets and Class 1E alternate power supplies.
During its February 27-28, 1985, site visit, the staff viewed the installation of the EPAs between the RPS motor generator (MG) sets and the RPS buses, and between the RPS alternate power supplies and the RPS buses. From this and its previous review, the staff concludes that the Class IE EPAs are electrically and physically redundant and independent and are, therefore, acceptable. The isolation provided between the non-Class 1E RPS buses and the Class 1E alter-nate power supplies is discussed in Section 8.4.6 of this supplement.
8.3.2 DC Power Systems In SER Section 8.3.2, it was stated that a backup battery charger had the capa-bility of being connected to any of three safety or three non-safety de buses by way of a separate 125-V de switchgear that has connections to each bus. In FSAR Amendment 19 the applicant has subsequently deleted the connection of the Division III (HPCS) safety bus to the backup battery charger 125-V de switch-gear. This change does not impact the staff's previous evaluation because the staff had originally given no credit for the backup charger as a replacement for the normal safety battery chargers, because the backup charger is supplied from a non-safety ac bus.
8.4 Other Electrical Features and Requirements for Safety 8.4.5 Physical Identification and Independence of Redundant Safety-Related Electrical Systems The staff indicated in its May 1984 evaluation (River Bend SER, NUREG-0989) that Class 1E cables installed in cable trays dedicated to 4160-V or large 480-V power circuits, where spacing is maintained between cables installed in a single layer, are not color coded at 5-foot intervals. The staff stated it would con-firm the adequacy of this in a supplement to the SER.
Subsequently, in FSAR Amendment 16, the applicant stated that all cables except for the cables run entirely in conduit would be color coded by painting the cable jacket at intervals not exceeding 5 feet or by the use of cables with color-coded jackets. This is in conformance with Position C.10 of Regulatory Guide (RG) 1.75 and is, therefore, acceptable.
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-i i FSAR Amendment 16 also stated that cables with red- or blue-colored jackets may be used on unscheduled non-Class 1E circuits that run exclusively in conduit,
, only when the following mandatory conditions have been implemented:
'! (1) Neutral tags indicating non-Class 1E circuits are permanently attached at each end of the cable run and wherever the cable is exposed, and field quality control has verified 100% that this condition has been met. I', (2) No color-jacketed cable used for unscheduled non-Class 1E application is
' allowed to be terminated in or pass through an enclosure (pull box, junc-
~. tion box, cabinet) containing divisional Class 1E circuits. i 4 The staff finds that these exceptions to cable color coding, with the above- ' stated restrictions, will not decrease the effectiveness of the color coding
, system used at River Bend and are, therefore, acceptable.
1 In FSAR Amendment 16 and by letter dated January 28, 1985, the applicant stated its intent to justify the use of lesser cable separation at River Bend by per-forming tests using the reduced separation distances. The reduced separation distances are limited to circuits rated less than 4160 V. The original cable separation distances committed to by the applicant were the standard separation distances outlined in IEEE Std. 384-1974. In lieu of using the standard sep-i aration distances outlined in IEEE Std. 384-1974, the IEEE standard allows the i. separation distances to be established by analysis based upon tests of the pro-posed cable installations. The applicant's tests, as outlined in Wyle Test Report No. 47618-02 dated April 12, 1985, consisted of screening tests and configuration tests. The screening tests consisted of overcurrent tests on different size cables used at River Bend to determine which cable size, if subjected to a worst-case electri-cal fault, would have the most impact on adjacent cables. The worst-case elec-trical fault on a cable was taken to be the lesser of the locked rotor current , (6 times full load amperes) or the fault current level just below the longtime trip of the upstream protective device plus 10%. If the insulation should burn off the conductors during these tests, the bare conductors would be exposed and the temperatures would decrease. Under real circumstances the bare conductors would short circuit and the fault current level would increase. The test cur-rents were, therefore, increased to simulate the short circuit in this eventu-ality. Before energizing the cable with the worst-case electrical fault, warmup current was applied to the cable until the conductor temperature reached 90*C, which is the maximum normal operating temperature. Fault currents were applied to the cables until they open-circuited. The worst-case cable as established l by the screening tests was a Triplex 2 AWG copper cable. This size cable was used as the faulted cable in each of the configuration tests. 4 The configuration tests were run to demonstrate the acceptability of various cable separation configurations simulating those used at River Bend. The tests consisted of injecting a Triplex 2 AWG copper cable with a worst-case fault current as was done during the screening test and measuring temperatures and observing the effects on various target cables in the vicinity of the fault cable. The target cables were energized and carrying rated current which was i monitored during the course of the test. Following completion of each configur- , . ation test, an insulation resistance test and a high potential test were per- * ' formed on the target cables to determine the adequacy of their insulation. In i i River Bend SSER 2 8-2 I i
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' all cases the target cables successfully passed the insulation resistance and high potential tests.
The staff, however, was concerned that the temperatures recordeu on the target j cables during two of the configuration tests were extremely high. These were configuration 2, test 2 (688.9'F), and configuration 4, test 2 (786.6*F). The i configuration 2 test was conducted to demonstrate the adequacy of Siltemp 188 CH wrap as a barrier between two cables in free air with zero separation. Although the target cables in this test passed the insulation and high potential tests, the maximum temperature of 688.9'F recorded on the target cable was much greater than temperatures recorded during the other configuration tests with the one exception noted above. The subject test, however, was performed with three layers of the protective wrap while the applicant's updated separation criterion (Drawing 12210-EE-34ZE) calls for four layers of the protective wrap. An addi-tional test (configuration 2, test 1A) conducted with four layers of the protec-tive wrap resulted in a target cable temperature of 379.4*F, confirming the adequacy of four layers of the protective wrap. The configuration 4, test 2, in which a high temperature of 786.6*F was recorded, was conducted to demonstrate the adequacy of a configuration in which a hori-zontal aluminum conduit runs perpendicular to and in contact with a fault cable in a vertical tray. As above, the staff was concerned that the temperature (786.6*F) was well in excess of temperatures recorded during the other configur-ation tests. The high temperature, however, only existed briefly. Following ignition of the fault cable, the temperature on the target cable rose rapidly from 150*F to the peak of 786.6*F in 4 minutes, then immediately began falling to 370*F in the next 4 minutes. The ignition of the fault cable which started the dramatic rise in target cable temperature also did not occur until 17.3 minutes after fault current was applied to it. High impedance faults of the magnitude applied to the fault cable will not normally exist for that length of time. They generally degrade into low impedance faults which then quickly trip circuit breakers or burn clear. Re'gardless of the likelihood of the tested fault conditions, however, the test report states that following this test there was no visual evidence of damage to any target cable; and the target cable from the conduit which saw the high temperature was in good shape after exposure to flames all around the conduit. The target cable also easily passed the high potential and insulation resistance tests, and the applicant has taken addi-tional measures to ensure that in actual application the horizontal conduit will be separated a minimum of 1 inch from the vertical tray. The staff, there-fore, finds this configuration acceptable. ' On the basis of the tests conducted, the staff finds the proposed electrical separation at River Bend to be acceptable. The applicable separation distances are provided in the applicant's letter dated May 9, 1985. The applicant commit- ,
,ted to provide this information in a future FSAR amendment. The reduced separa-tion applies only to circuits less than 4160 V.
8.4.6 Non-Safety Loads on Emergency Sources In FSAR Amendment 16, the applicant identified (in Table 8.3-7) additional non-Class IE equipment supplied from Class 1E buses. These loads are unqualified heaters furnished with Class 1E motor-operated valves (MOVs), the RPS buses, and the main control room lighting system transformers. Each of these is dis-cussed below. hj l.7 River Bend SSER 2 8-3 1
g . . . . - - 1 e...,:i i U.:L:n!*.- ,.a. i s. . u - ., . MG. a t. - - aL L- - i f ' - a In Section 8.4.6 of the SER, the staff identified the main control room lighting as a non-Class IE load on a Class 1E power source. FSAR Amendment 16 to Table l 8.3-7 clarifies that the lighting transformer is not procured Class 1E although it is identical in design and construction to RBS Class 1E small dry-type trans-formers. The lighting transformer is connected to either of its alternate Class 1E sources of power via a series-connected circuit breaker and fuse located in the Class 1E motor control centers. During its site visit, the staff reviewed coordination curves which confirmed that the circuit breakers ] and fuses to the lighting transformer had adequate coordination with the up-stream feeded breakers which feed the Class 1E motor control centers. The staff finds these provisions acceptable and will ensure that the River Bend ! Technical Specifications contain a requirement for periodic testing of these j, overcurrent devices. ' Also during its site visit, the staff discussed with the applicant the isola-tion provided between the Class 1E RPS alternate power supplies and the non-Class 1E RPS buses. The alternate supply is taken from a regulating transformer which is powered from a Class 1E motor control center (MCC). Between the trans-former and the RPS bus are connected two in-series, redundant and independent EPAs. The applicant provided a short circuit analysis which indicated that the j available fault current to the RPS bus is insufficient to cause degradation or i tripping of the Class 1E MCC. There are also two circuit breakers in series, e one at the EC and one integral with the regulating transformer assembly, which are coordinated with the EC feeder breaker at the load center to preclude L tripping of the EC for faults on the RPS.' In addition, the EPAs would likely 1
' trip on low voltage for any fault large enough to degrade the Class 1E EC if a fault of that magnitude could exist. The staff considers these provisions suf-ficient to prevent a fault on the non-Class IE portions of the RPS from degrad-l ing the Class 1E EC.
FSAR Amendment 16 states that non-Class 1E heaters mounted in Class IE motor-operated valves and temporarily connected to Class 1E panelboards during the t.' construction phase are de-terminated'at the panelboards after equipment release and prior to operating above 5% of rated power. Because the unqualified heaters will have no connection to the Class 1E system during operation above 5% of rated power, the staff finds this acceptable. FSAR Amendment 19 has identified further additional non-Class 1E equipment con-nected to Class 1E power supplies. These are the polar crane in the reactor building, the monorails in the standby cooling towers, unqualified slide wire transducers used for valve position indication on selected residual heat removal (RHR) valves, and unqualified limit switches used for check valve position in-dication. The monorail circuits are tripped on a LOCA signal. This is in ac-cordance with RG 1.75 and is, therefore, acceptable. The circuit breaker for , the polar crane is locked in the open position during plant operation and is
- closed and energized only during periods of reactor maintenance. This is an acceptable variation of the RG 1.75 requirements. For the slide wire trans-
'- ducers and ifmit switches, the FSAR states that evaluation has demonstrated ~ that open, short, or ground circuits in these components will have no adverse effects on the Class 1E portion of the circuit. The applicant should provide this evaluation to the staff so that it can make an independent confirmation of this statement. The staff will report on this issue in a future supplement to ,<
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] The staff indicated in its initial report that it would evaluate the applicant's J
i analysis and proposed fixes relating to the flooding of electrical equipment as the result of a loss-of-coolant accident (LOCA) and report the results in a supplement to the SER. i In a letter dated February 15, 1985, the applicant provided a revision to 1 I Section 2.4 of the River Bend Equipment Qualification Document (EQD) which addressed the subject of submergence., It states that equipment located inside the containment is designed and qualified to perform its intended function while submerged. Equipment located inside the drywell that is subjected to submergence is not required to perform an active safety function, and the applicant's evaluation has demonstrated that subsequent failure of this equip-ment is without significant consequences. The staff was concerned that unqualified motor-operated valve control circuits located inside the drywell might cause spurious operation of the valve when subjected to submergence. During its site visit, the staff reviewed drawings provided by the applicant which indicate that control circuit contacts in the motor control centers isolate the contactor coil of the valve motors from their control circuits in the drywell so that no failure of the circuits in the
; drywell can cause spurious operation of the valve. For failures that would short these circuits, redundant overcurrent protection is provided as described
, in Section 8.4.2 of the River Bend SER. The staff finds these provisions acceptable.
8.4.9 Cable Derating for Spacing in Accordance With IPCEA Recommendations The applicant states in the FSAR that the normal current loading of all insu-lated conductors is limited to that continuous heating value which does not cause insulation deterioration from heating. The selection of conductor sizes is based on the Insulated Power Cables Engineers Association (IPCEA) publica-tion P-46-426. The applicant further states that cables are derated for group-ing and spacing in accordance with IPCEA recommendations. The staff raised a concern during its inspection that the spacing between power conductors in trays was maintained at one-fourth of a cable diameter only at the tie points and not necessarily between them, whereas the IPCEA derating factors used at River Bend are based on cables with maintained spacing of be-tween one-fourth to one cable diameter. Subsequently, in a letter dated December 5, 1984, the applicant referenced test-ing that was conducted which demonstrated that the temperature of the energized cable will not exceed the design rating of the cable with only intermittent touching. The staff has reviewed the results of this test and agrees, on the basis of these results, that the derating factors used at River Bend, which were IPCEA recommendations, are conservative.
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Furthermore, the design tempera-ture of the cable is not exceeded by allowing adjacent cables to occasionally touch or be separated from each other by less than one-fourth of a cable diam-eter between tie points. In a December 5, 1984, letter, the applicant empha-sized that the one-fourth of a cable diameter spacing is still an intended goal , at the time of installation, as it must be maintained at tie points both during ; and af ter installation. This issue (Confirmatory Item 79) is, therefore, { resolved. River Bend SSER 2 8-5 l.
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'9 AUXILIARY SYSTEMS l 9.1 Fuel Storage and Handling 9.1.5 Overhead Heavy Load Handling System As a result of Generic Task A-36, " Control of Heavy Loads Near Spent Fuel,"
NUREG-0612, " Control of Heavy Loads at Nuclear Power Plants," was developed.
' Following the issuance of NUREG-0612, a generic letter dated December 22, 1980, was sent to all operating plants, applicants for operating licenses, and holders i of construction permits requesting that responses be prepared to indicate the degree of compliance with the guidelines of NUREG-0612. A's indicated above, in accordance with the generic letter of December 22, 1980, the applicant was asked to review the provisions for the handling and control of heavy loads at the River Bend facility to determine the extent to which the guidelines of NUREG-0612 are satisfied and to commit to mutually agreeable changes and modifications that would be required in order to fully satisfy these guidelines. By submittals dated June 24, 1981; March 1, 1984; November 5, 1984; and January 8, 1985, the applicant provided the responses to this request.
The staff and its consultant, EG&G, of the Idaho National Engineering Laboratory (INEL), have reviewed the applicant's submittals for the River Bend Station. As a result of its review, EG&G has issued a technical evaluation report (TER). The staff has reviewed the TER and concurs with its findings that the guidelines in NUREG-0612, Section 5.1.1 have been satisfied. This TER is a part of this SER (Appendix I). The staff concludes that Phase I of NUREG-0612 for the River Bend Station is acceptable. The staff further concludes that with the comple-tion of Phase I and based on the above response and Phase II review to date, no further action is required concerning Phase II of NUREG-0612. Therefore, the staff concludes that the requirements of GDC 4 and 61 and the guidelines of Regulatory Guide 1.13, Positions C.3 and C.5, have been satisfied for the over-head heavy load handling systems at River Bend Station, Unit 1. 9.2 Water Systems 9.2.2 Reactor Plant Component Cooling Water System (Reactor Auxiliary Cooling Water System) In the SER, the staff stated that the safety-related portion of the reactor plant component cooling water (RPCCW) system is automatically isolated from the nonessential portion of the RPCCW in the event of an accident, such as a LOCA. In FSAR Amendment 15, the applicant deleted the reference to isolation
. during an accident. The automatic i w M ion is initiated by a low water pres-sure signal. An accident may result in a low water pressure in the RPCCW system and thereby result in isolation of the nonessential portion, but an accident, , such as a loss of offsite power, will not directly result in isolation. This change does not affect the staff's conclusions as discussed in the SER, t
River Bend SSER 2 9-1 m
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. d' l 9.3 ' Process Auxiliaries 9.3.2 Process Sampling System j Item II.B.3 - Post-Accident Sampling System This subject is discussed in Section 10.4.6 of this River Bend supplement. , , 9.4 Air Conditioning, Heating Cooling, and Ventilation Systems 9.4.5 Engineered Safety Feature Ventilation-Systems 9.4.5.1 Diesel Generator Building Ventilation System In the SER, the staff stated that each of the three diesel generators is ser-viced by two redundant exhaust fans. In FSAR Amendment 15, the applicant has eliminated one of the 100% exhaust fans in each diesel generator compartment. The failure of the single exhaust fan could result in the failure of the asso-ciated diesel generator. The failure of a diesel generator has previously been considered; thus the failure of a diesel generator owing to the failure of the exhaust fan does not represent any new accident scenario. Therefore the elimination of one 100% capacity exhaust fan per diesel generator is acceptable. This does not affect the staff's conclusions as discussed in the SER. 9.5 Other Auxiliary Systems 9.5.2 Communication Systems 9.5.2.1 Intraplant Systems In the SER, the staff noted that the intraplant communications were powered from non-Class 1E power sources and could not be connected to an onsite power source following a loss of offsite power (LOOP). The staff requested that the appli-i cant describe how it would maintain adequate communications between the control room and safety-related areas throughout the plant, assuming a design-basis seismic event and/or a LOOP in excess of 4 hours (intraplant communications have a 4-hour-rated, non-Class 1E battery backup). The applicant, in FSAR Amendment 13, stated that the plant design and accident analysis was such that the plant could be brought to safe cold shutdown from the control room, con-sidering any design-basis event, without the need to leave the control room or communicate with any location outside the control room. On this basis, the applicant concluded that Class IE communications and power supplies were not necessary. The staff has reviewed the applicant's response and the-River Bend accident analysis. On the basis of its review, the staff concurs with the applicant's assessment of shutdown capability from the control room. The staff concludes that the intraplant communications at River Bend conform to the standards, criteria, and design bases and can perform their design functions, ^ and is, therefore, acceptable. This finding is subject to confirmation that appropriate procedures covering shutdown from the control room only have been I developed and implemented, and that operating personnel have been trained in the use of these procedures. These procedures shall be in place before exceed-ing 5% power. : River Bend SSER 2 9-2 I
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1 ii =! ~l 9.5.3 Lighting Systems In the SER, the staff identified features of the control room emergency lighting system which were not acceptable. These included a design which would require
, an operator to restore emergency lighting during a design-basis event and/or ; LOOP by manually disconnecting a plug from a non-Class 1E receptacle and recon-a necting it to a Class IE receptacle, all within a short time from the event ini-tiation. Another system feature was that a significant portion of the emergency lighting was powered from a non-Class 1E power source. In addition to control room emergency lighting, the applicant had not provided information regarding 1 adequate lighting in safety-related areas outside the control room during and after a design-basis event and/or LOOP.
By FSAR Amendment 15 and by letter dated August 21, 1984, the applicant provided [ additional information on the design of the control room emergency lighting sys-tem. The system was redesigned so that the emergency lighting would always be connected to a Class 1E source, usually Division I, and that manual reconnec-tion for another Class 1E source would only be necessary in the event of failure of the original Class 1E source (i.e., reconnect to Division II in the event Division I fails). Since there will be adequate lighting from seismically mounted battery packs to perform this operation, and the potential of having to make a reconnection is low, the staff finds this acceptable. The applicant also provided additional information on the design, qualification, and instal-lation of transformers, distribution panels, cables, conduits, raceways, and system isolation devices associated with the control room emergency lighting system which demonstrates that these items are Class 1E or equivalent. On this basis, the applicant concludes that emergency lighting for the control room would be available during and/or after any design-basis event, including a seis-mic event. The staff concurs with the applicant's conclusions. The applicant also provided information which showed that the emergency lighting system would maintain illumination levels of 25 foot-candles in the control room. This also is acceptable. The applicant responded to the staff's concerns regarding emergency lighting in safety-related areas outside the control room. The applicant stated that the plant design and accident analysis was such that the plant could be brought to a safe cold shutdown from the control room, considering any design-basis event, without the need to leave the control room or occupy any safety-related areas. On this basis, the applicant concluded that lighting in safety-related areas that would be available following any design-basis event, including seismic, was not required. The staff has reviewed the applicant's response and.the River Bend accident analysis and concurs with the applicant's assessment of shutdown capability from the control room. The staff concludes that the lighting systems at River Bend conform to the standards, criteria, and design bases can perform their design functions, and is therefore acceptable. This finding is subject to confirmation that appro-priate procedures covering shutdown from the control room only have been devel-oped and implemented, and that operating personnel have been trained in the use of these procedures. These procedures shall be in place before exceeding 5% power. i River Bend SSER 2 9-3
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.i Dj 9.5.4 Emergency Diesel Engine Fuel Oil Storage and Transfer System i 9.5.4.1 Emergency Diesel Engine Auxiliary Support Systems ; In the SER, the staff concluded that the applicant had not provided sufficient 1
information to demonstrate that the training for operations, maintenance, and supervisory personnel on emergency diesel generators would be equivalent to vendor training. By letter dated August 21, 1984, the applicant stated that
" River Bend Station has implemented the staff's recommendation of providing l vendor training, or that equivalent to vendor training, for the operations and maintenance department personnel (including supervisors)." On the basis of the applicant's response, the staff concludes that the applicant's initial training .1 program is acceptable since it utilizes vendor training. The applicant also q stated that there would be a program for retraining, but did not specify if it would be vendor training or in-house training. By letter dated June 5, 1985, the applicant provided additional information on tne retraining program to be , implemented at River Bend. Site-specific training manuals for both types of diesel generators have been developed based on vendor materials and with assis-tance from vendor consultants. Retraining will be at intervals not exceeding 2 years. Therefore, the staff concludes that diesel generator training at River Bend is acceptable.
By letter dated March 5, 1984, the applicant provided a discussion of high-pressure core spray (HPCS) diesel generator testing. The applicant stated that no-load or light-load operation will be minimized and that the engine will be cleared in accordance with manufacturer's recommendations following extended periods of no-load operation. The preventive maintenance program for the HPCS diesel generator will go beyond normal routine adjustments, servicing, and re-pair of components. The program will encompass investigative testing of com-ponents that have a history of repeated malfunction and that have required con-stant attention and repair and have utilized industry operating experience to identify components that affect diesel generator reliability. Following main-tenance or extended outage of the diesel generator, a complete system lineup will be conducted to ensure that all electrical and mechanical systems are func-tional prior to a start attempt. Upon completion of the lineup, the diesel will be started and load tested before being returned to automatic standby service. The staff finds the applicant's discussion of HPCS diesel generator testing and maintenance acceptable. The applicant was asked to provide diesel generator design data which showed the diesel engines were capable of developing full-rated power under the most extreme conditions of temperature, humidity, and barometric pressure anticipated for the River Bend site. The staff stated that the design of the River Bend diesel generators, with regard to ambient conditions, would be acceptable on confirmation that the requested data had been provided. The applicant provided the information in FSAR Amendment 15, and the staff finds this acceptable. By FSAR Amendment 13, the applicant provided information regarding the mounting of instrumentation and controls for the standby diesel generators. The appli-cant stated that, except for sensors and other equipment which must be mounted directly on the engine, the standby diesel generator controls and instrumenta-tion are installed in freestanding, floor-mounted panels located in a vibration- , free floor area' The staff finds this acceptable. River Bend SSER 2 9-4
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I i In the SER, the staff concluded that there was not sufficient assurance of long-term diesel generator reliability. The staff described specific design changes, procedural modifications, and issues which required implementation and/or reso-lution in order to ensure long-term diesel generator reliability. The appli-
] cant's response to these staff concerns is described below.
(1) Dust and Dirt in the Diesel Generator Room
! The applicant provided a discussion of the dust protection for the diesel generator control panels, and of the ventilation system for the diesel I generator control rooms. This subject is addressed in Section 9.5.8 of ; this supplement. -
(2) Personnel Training The applicant provided additional information regarding initial and follow-up diesel generator training. This subject is addressed above in this section of the supplement. (3) Automatic Prelubrication The applicant provided additional information regarding the design and operation of lubrication oil system modifications on the HPCS diesel gen-erator. This subject is addressed in Section 9.5.7 of this supplement. (4) Diesel Generator Room Ventilation System Air Filtration The design of the diesel generator control panels and diesel generator control room ventilation systems provides adequate dust protection for the diesel generator control systems. This subject is addressed in Section 9.5.8 of this supplement. (5) Concrete Dust Control The applicant has committed to comply with the recomendations of NUREG/CR-0660. This subject is discussed in Section 9.5.8 of this supplement. (6) Vibration of Instruments The applicant provided data on the mounting of controls for the standby diesel generators. This subject is addressed above in this section of this supplement. On the basis of information provided by the applicant, the staff concludes that the diesel generators and their auxiliary systems are in conformance with the recommendations of NUREG/CR-0660 for enhancement of diesel generator reliability, and the related NRC guidelines and criteria. The revised Table 9.1 reflects this conformance. 9.5.4.2 Emergency Diesel Engine Fuel Oil Storage and Transfer System In the SER, the staff identified the concern that the fuel oil storage tanks r were not protected from internal corrosion. This lack of protection could River Bend SSER 2 9-5
I i i result in the formation of corrosion products which could affect diesel genera-i tor availability. By FSAR Amendments 11 and 13 and a letter dated August 21, 1984, the applicant addressed the staff's concerns as follows: (1) a fuel stabilizer, such as Apollo Chemical Corp. SDI-35 which inhibits oxidation of fuel oil and the formation of corrosive byproducts, will be added to stored and new fuel as recommended by the manufacturer, (2) the storage tanks will be checked for water and accumulated water removed on a 31-day basis, and (3) the stored fuel will be tested for the presence of particulate matter on a 31-day basis. The staff has reviewed the applicant's program and concludes that the potential for creating corrosion products is greatly reduced, the amount of corrosion products produced would be small in any case, and the presence of potentially harmful particulate would be discovered at an early stage. There-fore, the staff concludes that the absence of internal corrosion protection for the fuel oil storage tank is acceptable. In the River Bend SER, the staff assumed an event which requires refilling the fuel oil storage tanks during diesel generator operation. The applicant was asked to discuss how it would prevent stirring of sediment in the tanks as a consequence of the refilling operation. This sediment could foul diesel gener-ator fuel system components and cause potential loss of the diesel generator (s). In FSAR Amendment 13 and by letter dated August 21, 1984, the applicant stated that refilling of the storage tanks would be staggered by 24 hours so that only one tank at a time would be affected. In addition, procedures will be imple-mented to ensure that the day tank (for the associated diesel generator) is full before a storage tank is refilled. This will allow the diesel generator to operate for the longest period of time possible without requiring a transfer of fuel from the storage tank, thereby allowing time for sediment to settle. Finally, the minimum amount of fuel oil in the day tank is adequate to support continued diesel generator operation while fuel oil filters and/or strainers, which may have become clogged by sediment, are cleaned. The strainers have high differential pressure alarms. Therefore, the staff concludes that the applicant's method for controlling sediment in the fuel oil storage tanks is acceptable. The staff further concludes that the emergency diesel engine fuel oil storage and transfer system is acceptable. 9.5.5 Emergency Diesel Engine Cooling Water System In the SER, the staff requested that the applicant provide information on the heat removal capability of the standby diesel generator cooling water system. By FSAR Amendment 11, the applicant provided information which demonstrates that the cooling water system has adequate heat rejection capability for the maximum diesel generator load plus a margin to allow for system fouling. The staff finds the applicant's response acceptable. The River Bend FSAR did not contain sufficient information regarding the capa-bility of the standby diesel generators to operate at no-load, light-load con-ditions for an extended period of time. The applicant, by letters dated March 5, 1984, and July 24, 1985, provided additional information. The staff has reviewed the applicant's submittal and finds it acceptable. The design of the Division III (HPCS) diesel generator cooling water system is I' such that air is trapped at the high point of the closed-loop system when the River Bend SSER 2 9-6
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g_ _ . _ ~ . __ . .~ _ A r r ~ . _ _ _ . .a._. J _._ _ _ _ 4 n , diesel generator is in the standby mode. The staff asked the applicant to ' demonstrate that this air would not be detrimental to the operational reliabil-ity of the diesel generator cooling water system. In FSAR Amendments 13 and 15, the applicant provided information that demonstrated compliance with the manu- ' facturer's recommendation for corrosion inhibitors in the cooling water system. i~ The applicant also provided a copy of a letter from the manufacturer which stated that coating the exposed portions of the system with coolant / inhibitor on a monthly basis (by operating the diesel generator) is adequate to prevent corrosion of the exposed surfaces when the diesel generator is in standby. The : staff finds this acceptable. ' I~
' The FSAR did not contain sufficient information regarding diesel generator cool-i ing water system instrumentation and controls for the staff to evaluate their adequacy. In addition, the applicant did not address test and calibration of e
these controls. By FSAR Amendment 13 and letter dated August 21, 1984, the _ applicant provided this information. The staff has reviewed the additional ' data and concludes that the design of the diesel generator cooling water system instrumentation and controls, including test and calibration on an 18 month basis, is acceptable. i l' The applicant was asked to demonstrate that the cooling water systems for both the standby and HPCS diesel generators contained sufficient inventory to support 7 days of continuous diesel generator operation without a requirement to add coolant, assuming normal coolant leakage during operation. The applicant re-sponded to the staff's concern by stating that no makeup water needs were anti-cipated for 7 days of operation. However, the cooling water system coolant level can be monitored during operation, and provisions have been made for adding water, if necessary, to the standby and HPCS diesel generator cooling water systems during operation. The staff finds this acceptable. In the SER the staff asked the applicant to verify that the HPCS keep-warm sys-i tem will maintain the cooling water system temperature at a high enough point to enhance diesel engine starting reliability. The applicant, by letter dated July 24, 1985, provided additional information. The applicant stated that the keep-warm system is provided with an electric heater designed to maintain nor- ! mal engine jacket water and lubrication oil temperatures in a room temperature environment down to 40*F and lower. In addition, the room temperature will be , maintained above 40*F, and it would be alarmed and displayed in the control 4 room. Also a diesel generator trouble alarm is provided in the control room, with local alarm status to warn the operators of improper operation of several diesel engine functions, including a low engine lubrication oil temperature condition and a keep-warm system power failure. In addition, plant operating procedures will be provided to instruct operators to take immediate and appro-priate actions upon actuation of any alarm condition. The applicant stated
, that the above facts provide adequate assurance that the HPCS diesel generator will reliably start and operate under all anticipated conditions. The staff concurs with the applicant and finds the design of the keep-warm system for the HPCS diesel generator acceptable.
The staff concludes that the standby and HPCS diesel generator cooling water I systems is acceptable subject to confirmation that the applicant has identified the diesel engine interfaces. River Bend SSER 2 9-7
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; 9.5.6 Emergency Diesel Engine Starting System The FSAR had insufficient information on the design and operation of the diesel generator air start systems instrumentation and controls including frequency of test and calibration, thereby precluding a complete system evaluation. By FSAR Amendments 13 and 15 and a letter dated August 21, 1984, the applicant provided this information, and stated that test and calibration of the instrumentation and controls would be conducted on an 18-month basis. The staff finds this acceptable.
9.5.6.2 Standby Diesel Generators For the standby diesel generator air start system, there is an unloader line between the air receiver and the system air compressor which is not identified as Safety Class III. The staff's concern was that failure of this non-safety line would cause blowdown of the air receiver with attendant failure of the diesel generator to start on demand. By letter dated June 5, 1985, the appli-cant stated that the unloader line is seismic Category I, Safety Class III. This resolves the staff concern. The applicant, by letter dated June 27, 1985, provided additional information relative to the engine-mounted piping on the standby diesel generators. The auxiliary systems for the standby diesel generators are designed, engineered, manufactured, installed, and tested in accordance with ASME Code Section III, Class 3, requirements up to the connection point on the engine. The engine-mounted piping and components have been designed and installed in accordance with the standards of the Diesel Engine Manufacturers Association (DEMA). In addition, design reviews and quality revalidation inspections were performed on these engine mounted systems in conjunction with the Transamerica DeLaval Inc. (TDI) Diesel Generator Owners Group. The results are documented by the Owners Group in the Phase II Design Review and Quality Revalidation reports submitted December 24, 1984, and March 7, 1985. The acceptability of the standby diesel generator engine-mounted piping and components will be evaluated by the NRC TDI Project Group and will be reported in a future SER supplement. In the River Bend SER the applicant was requested to provide information on the program for monitoring the performance of the air dryers in the respected air starting systems of the standby diesel generators to ensure that starting air quality with respect to moisture is maintained. The applicant by letter dated March 5, 1985 provided additional information. The staff has reviewed the applicant's submittal and finds it acceptable. Section 9.5.6 in the River Bend FSAR contains reference to alarms in the com-pressed air starting systems to annunciate and indicate abnormal conditions. Also, FSAR Section 7.3 contains logic diagrams for the standby diesel genera-tors' air start systems instrumentation and controls on which the above-mentioned alarms are not included. The applicant was asked to clarify the inconsistency. The applicant by FSAR Amendments 11 and 13 and letters dated August 21, 1984, and July 24, 1985, provided information to clarify the inconsistency. The applicant had not provided FSAR drawings showing the locations of the standby diesel generator starting air instrumentation and control components. In FSAR Amendment 20, the applicant provided the information. 9 River Bend SSER 2 9-8
_L R -. - .- . - . A 22. - JLL : =- .= d l t i i d . ' 4 The air dryers for the HPCS diesel generator air start systems are of the re-i frigerant type _ and are designed to deliver dry air at a dewpoint of 35*F with
! a room ambient temperature of 40*F. Normally the room ambient temperature will be maintained at substantially higher levels than 40*F. The applicant has-established a minimum diesel generator room temperature of 40*F to ensure si ' satisfactory dryer operation and satisfactory operation of all other equipment in the diesel generator room which is subject to the same temperature environ- , ment limitation.
By letters dated August 21, 1984, and June 26, 1985, the applicant provided the basis for establishing the HPCS diesel generator room temperature at 40'F. As further assurance, the applicant has committed to include in the plant Technical Specifications surveillance of the HPCS diesel generator room temperature on a 24-hour cycle when the room temperature is 50'F or higher and on a 12-hour cycle when the room temperature is less than 50*F. The applicant has also stated that should the temperature begin to drop, it will take immediate remedial action before the temperature reaches 40'F to restore room temperature to normal. In the event the room temperature should fall below 40*F the applicant is required by operability Technical Specifications to declare the HPCS diesel generator ,. inoperable. The staff finds this acceptable. Some of the HPCS diesel generator engine-mounted piping and components are not designed to the Boiler and Pressure Vessel Code of the American Society of Mechanical Engineers (ASME Code) Section III, Class 3, requirements in accordance with applicable SRPs. The applicant, by letter dated August 21, 1984, provided information on the design and fabrication of the above piping and components. The applicant has indicated in followup discussion with the staff that, except for items which were not available as Class 3 or B31.1, all engine-mounted pip-ing and components are designed, installed, and tested to American National . Standards Institute (ANSI) Std. B31.1 requirements. In addition all engine-mounted piping and components have been analyzed to seismic Category I require-ments. The applicant concludes that piping and components, in accordance with the above criteria, are the equivalent of ASME Code Section III requirements in terms of system functional operability and inservice reliability. The staff concurs with the applicant and finds the engine-mounted piping and components for the HPCS diesel generator acceptable subject to confirmation of the above information. However, operation up to 5% power is justified since similar systems are in operation at other nuclear plants and have demonstrated high reliability. In addition the applicant was asked to provide a description or a logic dia-gram for the HPCS diesel generator air starting system instrumentation and con-trols. The applicant by letter dated August 21, 1984 provided logic diagrams. During the initial review, the staff could not conclude that the HPCS diesel > generator air-start system capacity was capable of delivering five consecutive starts without recharging. By letter dated August 21, 1984, the applicant pro-vided additional information on the design and capacity of this system. The applicant stated that the River Bend HPCS diesel generator air-start system was identical to the system installed at the Perry Nuclear Station. In addition, the applicant provided an extrapolation of data from actual air-start system tests at the Perry plant. On the basis of these data, the applicant concluded that the HPCS diesel generator air-start system has adequate capacity for more : than five consecutive 10-second starts without recharging, assuming the lowest River Bend SSER 2 9-9
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1 J r J normal operating pressure of 215 psig. The staff evaluated the data provided i
' by the applicant and concluded that the extrapolation is conservative, and that
-the capacity of the HPCS diesel generator air-start system is acceptable.
EI The applicant'had not addressed the staff's concern regarding the lack _of air
;i
-1 filters on the HPCS diesel generator air-start system air compressor intake ', openings. By letter dated June 5, 1985, the applicant provided this informa-tion. The HPCS diesel generator air start compressor intakes include filters 3 capable of removing particle size of 15-20 microns. This satisfies the staff's concern, and the staff concludes that the HPCS diesel generator air-start system is acceptable. 9.5.7 Emergency Diesel Engine Lubrication Oil System In the River Bend SER the staff asked the applicant to confirm details of the standby diesel generator turbocharger drip lubrication circuit on the appro-priate piping and instrumentation diagram (P&ID). The applicant, by letter dated March 5, 1985, provided this information on the appropriate P&ID. 6 At the time the SER was issued, the applicant had not provided sufficient in-formation regarding the HPCS diesel generator lubrication oil system to support
- a complete staff review. The applicant also had not provided information on the frequency of test and calibration of the lubrication oil systems (standby and HPCS) instrumentation and controls. The applicant, by FSAR Amendments 13, 15, and 21 and letters dated March 5, 1984, and August 21, 1984, provided the information. The staff has reviewed the submittals and finds acceptable the HPCS diesel generator lube oil system including instrumentation and controls, and test and calibrations on an 18-month basis for the HPCS and standby diesel generators.
In the FSAR, the applicant identified the HPCS diesel generator lubrication oil system piping and components as not being designed, fabricated, and installed in accordance with ASME Code Section III, Class 3, requirements. The staff p found this unacceptable. By letter dated August 21, 1984, the applicant stated that the above piping and components were designed in accordance with ANSI Std. B31.1 requirements (to the maximum extent practicable) and, in addition, had been pressure tested in accordance with the hydrostatic test parameters specified in ANSI B31.1. The applicant concluded that the design and testing of the HPCS diesel generator lubrication oil system piping and components to the above criteria would be the equivalent of ASME Code Section III, Class 3, with regard to functional operability and inservice reliability. The staff agrees with the applicant's conclusions and finds the design of the above HPCS diesel generator lubrication oil system piping and components acceptable sub-ject to confirmation that the hydrostatic testing had been performed per ANSI B31.1. However, operations up to 5% of rated power is justified since - similar systems are in operation at other nuclear plants and have demonstrated high reliability. In the SER, the staff asked the applicant to clarify the purpose and operation of relief valves installed in the standby diesel generators lubrication oil systems. As shown on the piping and instrumentation diagram (P&ID), the relief valves would have bypassed an important pressure differential (high) alarm. By , FSAR Amendment 13, the applicant redesigned the system to eliminate the staff's
- Concerns.
River Bend SSER 2 9-10
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Therefore, the staff concludes that!the standby and HPCS diesel generator lub-rication oil system is acceptable subject to confirmation of the following items: (1) the details of the standby diesel generator turbocharger drip lubrication 1 circuit have been included on the appropriate P&ID i (2) the HPCS 6 gpm pump provides adequate lubrication of the turbocharger (3) the turbocharger pre-lubrication circuit can function as shown on the P&ID (4) this information has been included in the FSAR The staff find that operation up to 5% of rated power is justified, since simi-lar systems are in operation at other nuclear plants and have demonstrated high reliability. By letter dated June 5, 1985, the applicant stated that procedures have been developed and implemented which will ensure cleaning of all controls panels, cabinets, and diesel generator start system electrical circuitry on a quarterly basis. Therefore, the staff concludes that the diesel generator (standby and HPCS) combustion air intake and exhaust systems are acceptable. River Bend SSER 2 9-11 n
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]- Table 9.1 Conformance to NUREG/CR-0660 recommendations (revised from SER).
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Recommendation Conformance Section
- 1. Moisture in air starting system Yes 9.5.6 (SER) 53 2. Dust and dirt in diesel generator Yes 9.5.4.1 (SSER 2)
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- 3. Turbocharger gear drive problem Yes 8.3 (SER)
- 4. Personnel training Yes 9.5.4.1 (SSER 2)
- 5. Automatic prelube Yes 9.5.7 (SSER 2)
- 6. Testing, test loading, and Yes 9.5.4.1 (SER) preventive maintenance
- 7. Improve the identification of root Yes 9.5.4.1 (SER) cause of failures
- 8. Diesel generator ventilation and Yes 9.5.8 (SSER 2) combustion air systems
- 9. Fuel storage and handling Yes 9.5.4.2 (SER)
- 10. High temperature insulation
- 9.5.4.1 (SER)
- 11. Engine cooling water Yes 9.5.5 (SER)
- 12. Concrete dust control Yes 9.5.4.1 (SSER 2)
- 13. -Vibration of instruments Yes 9.5.4.1 (SSER 2)
- Explicit conformance is considered unnecessary by the staff in view of'the equivalent provided by the design, margin, and qualification testing require-l ments that are normally applied to emergency standby diesel generators.
l l I l l River Bend SSER 2 9-12
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I i !, 10 STEAM AND POWER CONVERSION SYSTEM 10.4 Other Features i 10.4.6 Condensate Domineralizer System NUREG-0737 II.8.3 - Post-Accident Sampling Capability The staff has determined that the applicant met the criteria of Item II.8.3 of NUREG-0737. Criterion 2 which requires a procedure to estimate core damage remained as a confirmatory item to be completed prior to criticality. By let-ter dated May 13, 1985, the applicant provided additional information. The applicant provided procedure COP-1050 for estimating core damage during accident conditions based on the generic Westinghouse Owners Group Core Damar;e Assessment Methodology dated March 1984. Core damage estimates are based on utilizing postaccident sampling system meas-urements of fission product concentrations in primary coolant and in containment. Additional procedures are provided for estimating the extent of metal-water reaction based on measured hydrogen concentration in containment and for esti-mating the extent of core damage based on containment radiation monitors. Reactor vessel water-level and core exit thermocouple temperatures are used to establish if there has been adequate core cooling. This meets Criterion 2 and is, therefore, acceptable. Thus, the staff concludes that the applicant's postaccident sampling system meets all the requirements of Item II.B.3 of NUREG-0737 and is acceptable. Con-firmatory Item 50 is, therefore, resolved. 1 a River Bend SSER 2 10-1
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d 4 11 RADI0 ACTIVE WASTE MANAGEMENT q 11.2 Liquid Waste Manaaement System In the SER, the staff found the liquid waste management system acceptable. How-
'j ever, the applicant submitted a revision to this system in an FSAR amendment in af its letter dated April 17, 1985. This revision describes design features to o allow outside contractors to provide portable liquid waste self-contained dis- '1 .
posable filter and domineralizer services when necessary or for special appifca-j tions when the present liquid waste filter and domineralizer are not functional. In summary, the portable filter and domineralizer vessels will be located in a spare shielded cubicle in the radwaste building. Floor drains direct spills to
-< the radwaste building floor' drain collection tanks.
The staff has reviewed this modification and considers it acceptable with the following comment: l The applicant'should describe the method (s) for disposal of the self-contained filters and domineralizers. The present system transfers spent resins and filter media to the solid waste processing system for stabilization and the overall solid waste process is controlled by an approved process control program. The applicant should describe the methodology for disposing of and classifying these
" throw away" filter /demineralizer canisters. Also, the process control program referenced in Section 11.4 of this supplement should be revised to include the details for classifying and processing, as well as the administrative controls imposed for disposal of these items. It is mentioned only for empnasis that the disposal requirements of 10 CFR 61 and the Branch Technical Positions for solid waste disposal apply to these portable " throw away" filter /demineralizer canis-ters. This information should be submitted to the staff with a revised process control program (PCP) as discussed below in Section 11.4 of this supplement.
11.4 Solid Waste Manaaement System The SER in Section 11.4.2 identified as a licensing condition (License Condi-tion 7) that solid waste cannot be processed until after NRC approval is granted of the applicant's solid waste process control program (PCP). In its letter dated January 7, 1985, the applicant submitted the PCP for staff review. The staff has conducted a limited review of the applicant's PCP and concludes that the applicant can, on an interim basis, process solid waste. The interim ap-proval is granted based on the judgment that the applicant's PCP has included waste sampling and analysis controls that should ensure acceptable solid waste forms. However, because its review criteria for an acceptable PCP have recently been formulated, the staff has not yet reviewed the applicant's PCP against _ this new set of guidelines. The staff will send a copy of these guidelines titled, " Guidelines for Preparation of a Solid Was?.e Process Control Program," to the applicant under separate cover, for applicant review and use. A full review of the applicant's PCP wi'l be made after the applicant has had time to modify its PCP (if appropriate) And resubmit it to the staff for review. There- , fore, the applicant must revise its PCP and submit it for staff approval before operation after the first refueling outage. River Bend SSER 2 11-1 i
- - . - - - - - - - l . - -- - ~ = . - - - - .
Accordingly, an interim approval is granted of the applicant's PCP pending a future review and determination of any necessary changes. 11.5 Process and Effluent Radiological Monitoring and Sampling Systems 11.5.4 Process Monitoring and Sampling The SER requested as Confirmatory Item 52 information pertaining to the design method employed to minimize iodine and particulate plateout in air sample lines and also to provide information on the capability for the sample monitors to measure postaccident activity concentrations as specified in TMI Action Plan Item II.F.1, Attachment 2. The applicant, in its letter dated January 24, 1985, provided information in the FSAR describing the activity monitor ranges for the subject monitor. In addition, the applicant stated the sample lines are heat traced to prevent iodine vapor condensation on the tubing wall. Also, the lines are of stainless steel tubing, and flow straighteners are provided in process streams; although not explicitly conforming to the guidelines specified by ANSI Std. NB.1-1969 (" Guide to Sampling Airborne Radiciodine Materials in Nuclear Facilities"), they meet the intent. The staff considers the steps taken by the applicant to minimize iodine and particulate plateout in sample lines to be appropriate. Confirmatory Item 52 is closed. l l River Bend SSER 2 11-2
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, 12 RADIATION. PROTECTION 12.3 Radiation Protection Design Features 12.3.2 Shielding As required in TMI Action Plan Item II.B.2, " Design Review of Plant Shielding Which May Be Used in Postaccident Operations," the applicant has provided a radiation and shielding design review that identifies the location of vital areas and equipment in which personnel occupancy may be unduly limited or safety equipment may be unduly degraded by radiation during operations follow-ing an accident resulting in a degraded core.
The plant shielding design report was reviewed to evaluate the ability to have access to vital areas necessary to operate essential systems required after a LOCA with significant core damage. Vital areas that require continuous or frequent occupancy in order to control, monitor, and evaluate the accident were identified. In addition, the applicant identified potential maintenance activities that might become necessary during recovery and determined when after an accident such maintenance would be possible. For vital areas, the applicant has provided a person-rems, time, distance, and personnel occupancy study. The vital areas are the Operational Support Center, main plant exhaust duct effluent monitor grab sample area, postaccident sample station control panel and sample panel, health physics / chemistry laboratory, primary access point, main control room, and Technical Support Center. Calculations of source terms and estimated postaccident dose rates used for shielding design are based on RGs 1.4' and 1.7, and the guidelines of GDC 19. The applicant has provided " radiation" maps that show access routes to post-accident vital areas, to be used as an administrative guide in controlling access and reducing personnel exposure during the course of an accident. Systems containing high levels of radioactivity in a postaccident environment were identified but were found to be either irrelevant or negligible contribu-tors of radiation dose following an accident. The applicant's postaccident access and shielding study for River Bend Station shows that no personnel will be exposed to postaccident doses greater than GDC 19 dose rate guidelines of 5 rem whole body or its equivalent to any part of the body for the duration of the accident. On the basis of its review, the staff has concluded that the applicant hat per-i formed an acceptable radiation and shielding design review for vital ares access j in accordance with TMI Action Plan Item II.B.2 and, therefore, Confirmatory Item 54 is closed. River Bend SSER 2 12-1
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'i-12.5 Operational Radiation Protection Program
- 12.5.1 Organization l-The Backup Radiation Protection Manager meets the provisions of NUREG-0731
- j. Item II. A.2 and therefore is acceptable and Confirmatory Item 55 is closed.
. 1 i ?! '. I River Bend SSER 2 12-2
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APPENDIX I
; CONTROL OF HEAVY LOADS AT NUCLEAR POWER PLANTS RIVER BEND STATION - UNIT I (Phase I) 4 m
i River Bend SSER 2 Appendix I
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il CONTROL OF HEAVY LOADS AT NUCLEAR POWER PLANTS RIVER BEND STATION - UNIT 1 (Phase I) Docket No. [50-458] Author C. R. Shaber . Principal Technical Investigator T. H. Stickley Published January 1985 EG&G Idaho, Inc. Idaho Falls, Idaho 83415 Prepared for the U.S. Nuclear Regulatory Commission Under DOE Contract No. DE-AC07-76IDO 1570 FIN No. A6457 4 i i: River Bend SSER 2 Appendix I
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ABSTRACT
-1 l The Nuclear Regulatory Comission (NRC) has requested that all nuclear
'l-plants, either operating or under construction, submit a response of
- l. compliancy with NUREG-0612, " Control of Heavy Loads at Nuclear Power Plants." EG&G Idaho, Inc., has contracted with the NRC to evaluate the responses of those plants presently under construction. This report l
contains EG&G's evaluation and recommendations for River Bend Station (R8S) Unit 1.
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- i EXECUTIVE
SUMMARY
i Gulf States Utilities has presented information and made commitments F to show that River Bend Station Unit 1 is consistent with the intent of NUREG 0612 Article 5.1.1. t 4 i i i 4 9 s i: River Bend SSER 2 iii Appendix I
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I s j i 1 e CONTENTS ABSTRACT ............................................................. 11 EXECUTIVE
SUMMARY
.................................................... iii
- 1. INTRODUCTION .................................................... I 1.1 Purpose of Review ......................................... 1 1.2 Generic Background ........................................ I 1.3 Pl ant-Speci fic Background . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . 3
- 2. EVALUATION AND RECOMMENDATIONS .................................. 4 2.1 O v e rv i ew . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 2.2 Heavy Load Overhead Handli ng Systems . . . .. .. . . . . . . . . . . . . . . . 4 2.3 General Guidelines ........................................ 5 2.4 Interim Protection Measures ............................... 21
< 3. CON C LU D I NG
SUMMARY
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 3.1 Applicable Load-Handling Systems .......................... 22 3.2 Guideline Recommendations ................................. 22 3.3 Interim Protection ........................................ 25 3.4 Summary ................................................... 25
- 4. REFERENCES ...................................................... 26 TABLES 2.1 Nonexempt Heavy Load-Handling Systems ........................... 6 2.2 Monorails, Hoists and Cranes Excluded from Further Consideration ................................................... 7 3.1 NUREG-0612 Compliance Matrix .................................... 23 River Bend SSER 2 iv Appendix I
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~ Control of Heavy Loads at Nuclear power plants l River Bend Station Unit 1
- 1 (Phase I) 9
- 1. INTRODUCTION .
1.1 Purpose of Review This technical evaluation report documents the EG&G Idaho, Inc., review of general load-handling policy and procedures at RBS Unit 1. This evaluation was performed with the objective of assessing conformanca to,the general load-handling guidelines of NUREG-0612,
- " Control of Heavy Loads at Nuclear Power Plants" [1], Section 5.1.1.
1.2 Generic Background 4 Generic Technical Activity Task A-36 was established by the U.S. Nuclear Regulatory Commission (NRC) staff to systematically examine staff licensing criteria and the adequacy of measures in effect at operating nuclear power plants to assure the safe handling of heavy loads and to recommend necessary changes to these measures. This activity was initiated by a letter issued by the NRC staff on May 17, 1978 [2], to all power reactor applicants, requesting information concerning the control cf heavy loads near spent fuel. The results of Task A-36 were reported in NUREG-0612 " Control of Heavy Loads at Nuclear Power Plants." The staff's conclusion from this evaluation was that existing measures to control the handling of heavy loads at operating plants, although providing protection from certain potential problems, do not adequately cover the major causes of load-handling accidents and should be upgraded. i
.0 River Bend SSER 2 1 Appendix I
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1 a ; Gj J 'j In order to upgrade measures for the control of heavy loads, the staff ! developed a series of guidelines designed to achieve a two phase
! objective using an accepted approach or protection philosophy. The
,d first portion of the objective, achieved through a set of general guidelines identified in NUREG-0612, Article 5.1.1, is to ensure that " I all load-handling systems at nuclear power plants are designed and '
. operated such that their probability of failure is uniformly small and ] appropriate for the critical tasks in which they are employed. The j second portion of the staff's objective, achieved through guidelines identified in NUREG-0612, Articles 5.1.2 through 5.1.5, is to ensure that, for load-handling systems in areas whom their failure might result in significant consequences, either (a) features are provided, in addition to those required for all load-handling systems, to ensure that the potential for a load drop is extremely small (e.g., a single-failure proof crane) or (b) conservative evaluations of load-handling accidents indicate that the potential: consequences of any load drop are acceptably small. Acceptability of accident consequences is quantified in NUREG-0612 into four accident analysis evaluation criteria.
The approach used to develop the staff guidelines for minimizing the potential for a load drop was based on defense in depth and is summarized as follows: o Provide sufficient operator training, handling system design, load-handling instructions, and equipment inspection to assure reliable operation of the handling system o Define safe load travel paths through procedures and operator training so that, to the extent practical, heavy loads are not carried ever or near irradiated fuel or safe _ shutdown equipment o Provide mechanical stops or electrical interlocks to prevent movement of heavy loads over irradiated fuel or in proximity to equipment associated with redundant shutdown paths. River Bend SSER 2 2 Appendix I
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4 i Staff guidelines resulting from the foregoing are tabulated in Section 5 of NUREG-0612. 1.3 Plant-Specific Background 4 On December 22, 1980, the NRC issued a letter [3] to Gulf States Utilities Co. (ESU), the applicant for RBS Unit 1 requesting that the applicant review provisions for handling and control of heavy loads at i RBS Unit 1, evaluate these provisions with respect to the guidelines of NUREG-0612, and provide certain additional information to be used for an independent determination of conformance to these guidelines. On June 24, 1981 and March 1, 1984 GSU provided responses [4] and [5] to this request. Additional data were provided in transmittals of November 5, 1984 [10] and January 8, 1985 [11]. I i River Bend SSER 2 3 Appendix I
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- 2. EVALUATION AND RECOMMENDATIONS 2.1 Overview E
/
The following sections summarize GSU's review of heavy load handling at RBS Unit 1 accompanied by EG&G's evaluation, conclusions, and ',. recommendations to the applicant for bringing the facilities more
"; completely into compliance with the intent of NUREG-0612. GSU's review addresses only Unit 1. The applicant has indicated the weight of a heavy load for this facility (as defined in NUREG-0612, Article 1.2) as 1200 pounds.
2.2 Heavy Load Overhead Handling Systems This section reviews the applicant's list of overhead handling systems which are subject to the criteria of NUREG-0612 and a review of the justification for excluding overhead handling systems from the above mentioned list. 2.2.1 Scope
" Report the results of your review of plant arrangements to identify all overhead handling systems frem which a load drop may result in damage to any system required for plant shutdown or decay heat removal (taking no credit for any interlocks, technical specifications, operating procedures, or detailed structural analysis) and justify the exclusion of any overhead handling system from your list by verifying that there is sufficient physical separation from any load-impact point and any safety-related component to permit a determination by inspection that no heavy load drop can result in damage to any system or component required for plant shutdown or decay heat removal."
A. Summary of Applicant's Statements The applicant's review of overhead handling systems identified the cranes and hoists shown in Table 2.1 as those which handle heavy loads in the vicinity of irradiated fuel or safe shutdown equipment. - River Bend SSER 2 Appendix I 4 i l
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- - - - - - - ~ - - - - -
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The applicant has also identified seventeen other cranes that have been excluded from satisfying the criteria of the , general guidelines of NUREG-0612. (Table 2.2) B. EG&G Evaluation Each hoist system numbered in Table 2.1 has one or more paragraphs in the submittal to elaborate on it. The hoist list was given in the March 1, 1984 submittal and subsequent submittals have not indicated or justified changes. Each.of the hoist systems listed in Table 2.2 are discussed to verify their exclusion. C. EG&G Conclusions and Recommendations Based on the information provided EG&G concludes that the applicant has included all applicable hoists and cranes in their list of handling systems which must comply with the requirements of the general guidelines of NUREG-0612. 2.3 General Guidelines This section addresses the extent to which the applicable handling systems comply with the general guidelines of NUREG-06,12, Article 5.1.1. EG&G's conclusions and recommendations are provided in sunnaries for each guideline. River Bend SSER 2 5 Appendix I
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TABLE 2.1. OVERHEAD HANDLING SYSTEMS SUBJECT TO NUREG 0612 CRITERIA--RIVER BEND STATION UNIT 1 Capacity No. Handling System (Tons) Location
- 1. Reactor Building Polar Crane / Aux Hoist 100/5 Reactor Building
- 2. Drywell MSIV and Relief Valve Monorail 3 Reactor Building
- 3. Fuel Building Bridge Crane 15 Fuel Building
- 4. Spent Fuel Cask Trolley / Aux Hoist 125/15 Fuel Building
- 5. MSIV Monorails 8/5 Auxiliary Building
- 6. MSIV and Feedwater Isolation 3 Auxiliary Building Valve Monorails s 7. Feedwater Valve Hofsts 3 Auxiliary Building
- 8. RHR A Pump Monorail 8 Auxiliary Building
- 9. RHR 8 & C Pump Monorail 8 Auxiliary Building
- 10. Auxiliary Building Tunnel Plug 6 ' Auxiliary Building II. Hoist Area Monorails 5 Control Building
- 12. Floor Plug Monorail 5 Control Building
- 13. Control Building Equipment 5 Control Building Handling Area Monorail 1
l River Bend SSER 2 6 Appendix I
_ . - - - - . . - . - - - - . . - -- . -- -a-~- -- - -- = I i e TABLE 2.2. MONORAILS, HOISTS AND CRANES EXCLUDED FROM FURTHER CONSIDERATION RIVER BEND STATION UNIT 1 Capacity
, No. Handling System (Tons) location
- 1. HPCS Pump Monorail 12/6 Auxiliary Buf1 ding 108'
- 2. Control Rod Drive Maintenance 0.5 Auxiliary Building 108'
- 3. RCIC Pump Monorail 3 Auxiliary Building 85'
- 4. LPCS Pump Monorail 8 Auxiliary Butiding 10S'
- 5. Hoist Area Monorail 8 Auxiliary Building 164'
- 6. Elevator Machi'ne Room Hofst 3.5 Auxiliary Building 199'
- 7. Jib Crane and Channel Handling 0.5/0.1 Reactor Building 186' Boom
- 8. Recire Pump Motor /In-Care 30/6 Reactor Building 114' Detector Cask Monorail
- 9. Steam Tunnel Floor Plug 3 Reactor Building 145' Monorails (Reactor Butiding and Annulus)
- 10. Fuel Transfer Tube Floor Plug 3 Reactor Buf1 ding 156' Monorail
- 11. Drywell Access Monorail 8 Reactor Building 110'
- 12. Containment Access Monorail 12 Reactor Building 116'
- 13. Crated Guide Tube Monorail 2.5 Reactor Building 114'
- 14. Fuel Transfer Tube Floor Plug 8 Fuel Building 143'
- 15. Jib Crane and Channel Handling 0.5/D.2 Fuel Building 113' Boom (future)
- 16. Diesel Generator Unit Monorails 2 Diesel Gen. Bldg. 125'
- 17. Standby Service Water Cooling 3 SSW Cooling Tower I 161' Tower I Monoratis ~
River Bend SSER 2 7 Appendix I
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'i The NRC has established seven general guidelines which must be met in order to provide the defense-in-depth approach for the handling of heavy loads. These guidelines consist of the following criteria from Section 5.1.1 of NUREG-0612:
o Guideline 1--Safe Load Paths o Guideline 2--Load-Handling Procedures o Guideline 3--Crane Operator Training o Guideline 4--Special Lifting Devices o Guideline 5--Lifting Devices (not specially designed) o- Guideline 6--Cranes (Inspection, Testing, and Maintenance) o Guideline 7--Crane Design. . These seven guideliiles should be satisfied for all overhead handling systems and programs in order to handle heavy loads in the vicinity of the reactor vessel, near spent fuel in the spent-fuel pool, or in other areas where a load drop may damage safe shutdown systems. The succeeding paragraphs address the guidelines individually. 2.3.1 Safe Load Paths [ Guideline 1, NUREG-0612, Article 5.1.1(1)1
" Safe load paths should be defined for the movement of heavy loads to minimize the potential for heavy loads, if dropped, to impact irradiated fuel in the reactor vessel and in the spent-fuel pool, or to impact safe shutdown equipment. The path should follow, to the extent practical, structural floor members, beams, etc., such that if the load is dropped, the structure is more likely to withstand the impact. These load paths should be _
defined in procedures, shown on equipment layout drawings, and clearly marked on the floor in the area where the load is to be ? , c' River Bend SSER 2 8 Appendix I _-- .I
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i i a 13 CONDUCT OF OPERATIONS 13.1 Organizational Structure of Applicant 13.1.2 Corporate Organization Because the staff is concerned about the possible lack of hot operating experi-ence among the operators on shift at newly licensed reactor power plants, it has evaluated the operating experience on shift proposed by the applicant. 13.1.2.1 Operating Experience on Shift Dialogue with the industry was begun late in 1983 to find a way of ensuring that each operating shift at a newly licensed plant had at least one senior operator with previous hot operating experience. On February 24, 1984, an Industry Working Group representing utilities with nuclear power plants under construction or ready for operation presented a proposal to the staff on the amount of previous operating experience considered to be the minimum desirable on each shift and how that experience could be obtained. On June 14, 1984, the staff accepted the industry proposal with certain clarifications. Information regarding the staff action was forwarded to the industry as Generic Letter 84-16, dated June 27, 1984. The objective is that, at the time of initial criticality, each operating shift will have at least one senior operator with a minimum of 6 months of hot operating experience on a similar type plant, in-cluding startup/ shutdown experience and at least 6 weeks' experience operating above 20% power. However, for plants in the late stages of licensing with insufficient time to meet the objective, the temporary use of experienced shift advisors is acceptable. The minimum experience level for shift advisors is 4 years of power plant experience (including 2 years of nuclear power plant experience) and 1 year of hot operating experience as a Senior Reactor Oper-ator, if found suitably qualified) on a large commercial nuclear power plant of the same type as the plant at which they will work. All shift advisors are to be trained on the systems, procedures, and Technical Specifications of the plant for which they are to provide advice and they are to be certified to the NRC as being qualified to act as shift advisors. The applicant's latest submittals on operating experience are dated March 7, April 11, and May 28, 1985; a meeting between the applicant and the staff was held on May 14, 1985, and additional information was provided. The applicant has four licensed senior operators with enough BWR operating experience to satisfy the requirements of Generic Letter 84-16. The applicant has also iden-tified three other individuals with BWR operating experience who could be used as shift advisors until additional senior operators who do meet the requirements of the generic letter can be licensed. The staff has reviewed the applicant's submittals and its findings are discussed below. In addition, since the applicant does not now have senior reactor operators on each shift who meet the minimum guidelines for hot operating experience, the sta'ff will condition the operating license to require shift advisors until such time as the requisite experience has been obtained. River Bend SSER 2 13-1 5 k u
I l 13.1.2.2 Shift Advisor Program By letters dated March 7 April 11, and May 28, 1985, the applicant has sub-mitted information regarding the shift advisor program at River Bend. The staff has reviewed this information for conformance to Generic Letter 84-16. The review has covered four main areas: shift advisor experience, the shift advisor training program, the procedure used to define shift advisor duties and responsibilities, and other matters pertaining to the use of shift advisors. (1) Shift Advisor Experience Two prospective shift advisors amply meet the requirements of Generic Letter 84-16 and may participate in the River Bend shift advisor program. All have well over 4 years of power plant experience (including well over 2 years of nuclear plant experience), and all have had well over 1 year as a senior oper-ator at a large operating BWR. A third prospective shift advisor would also meet the requirements of Generic Letter 84-16, except that he has only 11 months (rather than at least 12 months) of on-shift SRO experience at a large operating BWR. However, this individual also has a bachelor's degree in nuclear engineering and has 14. months of on-shift Shift Technical Advisor (STA) experience at a large operating BWR, which more than compensates for the 1-month shortfall in on-shift SRO time. The staff considers the third prospective shift advisor to be qualified to participate in the River Bend shift advisor program. (2) Shift Advisor Training Program The shift advisor training program is patterned after the systems training course described in FSAR Section 13.2.1.1.2, the simulator course described in FSAR Section 13.2.1.1.3, and the general employee training described in FSAR Section 13.2.1.2.3. In addition, the simulator segment will include training in station procedures; the applicant should ensure that the Technical Specifi-cations are also covered. The staff finds the applicant's shift advisor train-ing program acceptable, assuming that it includes, or will include, familiariza-tion with the River Bend Technical Specifications. (3) Shift Advisor Procedure The duties and responsibilities of the shift advisor are described in River Bend procedure TP-85-02. This procedure establishes experience / training cri-teria, log-keeping and shift-turnover requirements, and other detailed duties and responsibilities of the shift advisor position. The main responsibility of the shift advisor will be to evaluate plant conditions and provide advice to the Shift Supervisor during startup testing, low power testing, and power ascension. Step 6.1 of of procedure TP-85-02 (draft Rev. 0) states, in part, that shift advisor candidates shall have a minimum of "six months on shift" as a licensed SRO or R0 at an operating plant of the same type (i.e. , BWR). In order for this procedural requirement to agree with Generic Letter 84-16, it should read "one year on shift." River Bend SSER 2 13-2
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The staff has reviewed draft Revision 0 of TP-95-02 and, with the exception of the one change described above, finds it acceptable. By letter dated May 18, 1 1985, the applicant proposed a candidate whose experience was deemed acceptable j by the staff. Therefore, this issue is closed.
'1, 1J (4) Additional Shift Advisor Issues Plant management will review the performance of each shift advisor as part of the monthly appraisal of overall shift performance. This is acceptable to the staff.
All members of operating shift crews will be responsible for familiarizing them-4 selves with the shift advisor procedure. This is acceptable to the staff. The prospective advisors have passed a River Bend health screening examination. This is acceptable to the staff. 13.1.3 Nuclear Administration Gulf States Utilities (the applicant) has made several organizational changes. Some of these changes are not significant because they are essentially title changes. .Some other changes are, however, significant. Revised Figure 13.1 shows the organization of the nuclear project. Of signif-icance, the Senior Vice President - River Bend Nuclear Group, reports directly
~
to the Chairman of the Board. Thus, the senior corporate officer with exclusive nuclear responsibility is highly placed within the organization. Four positions report to the Senior Vice President - River Bend Nuclear Group. These are: Vice President - Safety and Environment Vice President - River Bend Nuclear Group Manager - Quality Assurance Manager - Project Control The Manager - Project Control position is related to construction and will not be considered further in this evaluation except to note that he now reports one management level higher than before. The Manager - Quality Assurance remains in the same reporting position as before, but his title has been upgraded. The Vice President - Safety and Environment is a new position. The incumbent is responsible for environmental services, serves as Chairman of the Nuclear Review Board (i.e., the offsite committee), and is the individual to whom the Independ-ent Safety Engineering Group (ISEG) reports. The organizational change involv-ing ISEG meets the intent and requirements of TMI Action Plan Item I.B.1.2, in that this group reports to a corporate official who is not in the management chain for power production. The Vice President - River Bend Nuclear Group is responsible for both line (plant operation) and direct support functions. There are four positions ' reporting to this Vice President. These are: Plant Manager Manager - Engineering, Nuclear Fuels, and Licensing , Manager - Projects Planning and Coordination - Manage,r - Administration River Bend SSER 2 13-3 ! I b
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1 4 1 The Manager - Administration is responsible for four functions: training, emer-gency planning, security, and support services. The title has been changed from Vice President (SER Figure 13.1) to Manager (SSER 2 Figure 13.1) and the environmental services function has been transferred to the Vice President - Environmental Services. It is noted that the somewhat unusual organization i arrangement whereby security is not administrative 1y under the Plant Manager is i retained. This was found to be acceptable before. The applicant now proposes to delete from the responsibilities of the onsite Facility Review Committee R (FRC) responsibility for reviewing the security plan and implementing proce-
- dures. This proposed change coupled with the unusual organization removes all t-i review of security plans and procedures from those organizations charged with
' safe plant operation. This is only acceptable if the Plant Manager's concur- ' rence is required on the physical security plan, its implementing procedures, and all changes thereto before their implementation. For similar reasons, the Plant Manager's concurrence shall be required on the emergency and fire protec-tion plans, implementing procedures, and changes thereto, before implementation.
The Manager - Projects Planning and Coordination, a new position under the Vice President - River Bend Nuclear Group, is assigned the responsibility for the outage management system and for continuing interface with the architect-engineer and nuclear steam system supplier. The staff concludes that the organization changes proposed by the applicant are acceptable provided that there is a specific requirements that the Plant Manager will concur in the security, emergency and fire protection plans, im-plementing procedures and changes thereto before implementation. Section 6.5.1.2 of the Technical Specifications provides for the Plant Manager or his principal assistant to approve these plants prior to implementation; this resolves the staff concern. 13.1.4 Station Organization The organization under the Plant Manager has been changed so that there are now' four positions that report to the Plant Manager. These are: Assistant Plant Manager - Operations Assistant Plant Manager - Technical Services Assistant Plant Manager - Maintenance and Materials Supervisor - Radiological Programs The position of Superintendent - Startup and Test also reports to the Plant Manager, but only until the plant reaches commercial operation. The revised organization provides direct access to the Plant Manager for the individual responsible for radiological health and safety. It should be noted, however, that the radwaste and chemistry functions are retained under the direction of the Assistant Plant Manager - Operations. The Assistant Plant Manager - Maintenance and Material is responsible for the mechanical, electrical, and instrument and control craft groups, as well as for purchasing and materials. This is a new position, but the functions and re-sponsibilities grouped under it are logically determined. The shift organization indicates a minimum of 14 personnel. Included in this I total are 2 radiation protection technicians, 1 chemistry technician, and 1 River Bend SSER 2 13-4
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nuclear test technician. There are also 5 nonlicensed operators, one of whom
,, is a radwaste operator. The applicant has proposed to have 5 licensed oper-
.' ators (2 Senior Reactor Operators, SR0s, and 3 Reactor Operators, R0s) on shift but not to have a Shift Technical Advisor (STA), provided that one of the SR0s has had sufficient additional training to qualify as an STA. This is acceptable.
- 'The applicant has also committed to have a separate STA on shift if neither of m
the 2 SR0s has had sufficient additional training to act as STA. In this latter instance, it is proposed that one of the 3 RO positions would not have to be filled. This would keep minimum shift manning at 14, with 2 SR0s, 3 Ros, and 1 STA. Since this alternate proposal appears to satisfy TMI Action Plan Item I.A.1.1, it is considered an acceptable alternative. 7 The rdsunds of key personnel have been reviewed. On the basis of this review, it is concluded that key members of the operating staff meet the requirements of Regulatory Guide (RG) 1.8 (ANSI /ANS Std. 3.1-1978). This _ satisfactorily resolves Confirmatory Item 56 of the River Bend SER. On the basis of this supplemental review, the staff has determined that changes to applicant organization and personnel qualifications meet regulatory guidance. 13.2 Training The applicant has added a section (13.2.1.3.1) to the FSAR which describes the training for STAS. The applicant states that this training meets the intent of TMI Action Plan Item I.A.1.1 for STA training. Although the times allocated to various aspects of the training vary slightly from the periods delineated in the TMI Action. Plan (NUREG-0737 Appendix C), the applicant's program appears to cover all aspects of the required training for STAS. The applicant also de-scribes an STA retraining program and links this to a requalification training program for those SR0s who are cross-trained as STAS. The applicant has described the requalification training program. This de-scription commits to the items delineated in 10 CFR 55 (Appendix A) and in the H. R. Denton letter of March 28, 1980. The commitment to requalification training thus meets the regulatory requirement of 10 CFR 50.54 and NUREG-0737 Items I.A.2.1 and II.B.4. On the basis of the review of the supplemental applicant submittal, the staff concludes that the applicant's training commitments remain acceptable. Offsite Fire Department Training In the SER, the staff stated that training for the fire protection staff and for offsite fire departments was not firm and was therefore subject to confirma-tory review. FSAR Amendment.13 delineated how the fire prevention. staff would be trained. The applicant's letter of October 22, 1984, committed to specific, annual training of offsite fire departments (including basic radiation protec-tion), the use of personal dosimetry, plant familiarization (including fire protection systems and hazards), and fire-fighting procedures (including entry and exit from the plant). The October 22, 1984, letter also stated that these commitments would be included in an FSAR amendment. These changes and commit-ments that the applicant has made are acceptable. This resolves SER Confirma- ,
, tory Item 58. ~
River Bend SSER 2 13-5
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_i . _ _ mi zc . . . . . . _ . _ . - i 1 13.3 Emergency Preparedness 13.3.1 Background The SER provided the results of the staff's review and evaluation of the River Bend Station Radiological Emergency Plan (Plan), including FSAR Amendment 11 and supplemental information and commitments in letters dated October 8,1983, and February 16, 1984. In SER Section 13.3.3, the staff concluded that the Plan will provide an adequate planning basis for an acceptable state of onsite emer-gency preparedness when those items requiring resolution and those items com-mitted to by the applicant are satisfactorily completed. After the SER was issued, the applicant continued to upgrade its emergency plan-ning program and submitted FSAR Amendments 13, 15, and 16 (June 1984, November 1984, and February 1985, respectively). On August 14, 1984, and February 5, 1985, the applicant responded to the items identified by the staff in the SER, and, in addition, furnished information that the staff had requested. The staff has completed its review and evaluation of emergency preparedness as described in the FSAR through Amendment 16 and the applicant's responses of August 14, 1984, and February 5, 1985. The results of this evaluation are given in Section 13.3.2 below under the same format used in the SER. Section 13.3.3 provides the staff's conclusions. An onsite appraisal of the applicant's implementation of its emergency prepared-ness program was conducted between December 3 and 14,1984. The appraisal was conducted in seven general areas: administration, organization, facilities and equipment, training, procedures, coordination with offsite support groups, and drills, exercises, and walkthroughs. Appraisal results are documented in NRC's Office of Inspection and Enforcement (IE) Inspection Report No. 50-458/84-35, dated March 28, 1985. NRC Region IV will conduct followup appraisal (s) to en-sure that all identified deficiencies are corrected. A full participation exercise of the River Bend Station Emergency Plan was con-ducted at the River Bend site on January 16, 1985. The exercise tested the capabilities of the applicant's onsite and offsite emergency support organiza-tions to respond to a simulated accident scenario resulting in a major radio-active release. The exercise was integrated with a test of the emergency plans of the State of Louisiana and the parishes of West Feliciana, East Feliciana, Pointe Coupee, East Baton Rouge, and West Baton Rouge. NRC's findings, which are documented in IE Inspection Report No. 50-458/85-03, dated March 29, 1985, show that the applicant demonstrated an adequate state of onsite emergency preparedness. , 13.3.2 Emergency Plan Evaluation 13.3.2.1 Assignment of Responsibility (Organizational Cortrol) (1) Letters of Agreement By letter dated August 14, 1984, the applicant provided an agreement letter with Our Lady of the Lake Regional Medical Center, dated April 9, 1984. The letter describes: (1) the capabilities of the medical center for treating contaminated patients from River Bend Station on a 24-hr/ day basis, (2) training to be pro-vided by the applicant for medical center personnel, and (3) a list of medical River Bend SSER 2 13-6 !
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_._.._a: I and emergency equipment. Medical support is discussed further in Sec-tion 13.3.2.12 of this supplement. With regard to the letter of agreement with Illinois Central Gulf Railroad (ICGR), in its response of August 14, 1984, the applicant explained that suffi-cient track was purchased so that ICGR is abandoning the track that traverses the site in a northwest-southeast direction. Thus, the applicant has direct control over access to the site via the railroad and no longer requires an agreement letter with ICGR to provide this control. In its February 5, 1985, response, the applicant provided letters of agreement with Stone and Webster Engineering and General Electric Company (GE's letter, , ,. amended December 11, 1984, confirms the agreement pending formal contract agreement). - The applicant has obtained a letter of agreement with the State of Mississippi dated May 24, 1985. The applicant advised the staff that this letter would be appended to the Plan in the next FSAR amendment. The staff finds the above portions of the applicant's Plan adequate. 13.3.2.2 Onsite Emergency Organization t (1) Secondary Assignment of Shift Supervisor Information on the Shift Technical Advisor (STA) function provided by the appli-cant on October 28, 1983, has been incorporated into the Plan. The Plan speci-fies that the STA function is a collaterally shared responsibility of the Shift Supervisor and the control operations foreman (C0F) as shown in Table 13.3-5 and Figure 13.3-7 of the Plan. The Shift Supervisor and the C0F are both Senior Reactor Operators who will be trained in accordance with the April 30, 1980, INPO (Institute of Nuclear Power Operations) guidance document provided under NUREG-0737, Item I. A.1.1, "Shif t Technical Advisor." The Shift Supervisor will be primarily responsible for emergency direction and control. The C0F will be primarily responsible for technical support in plant system engineering, repair, and corrective actions. The Shift Supervisor or the C0F, and hence a qualified STA, will be in the control room at all times. In addition, in Section 13.2.1 of the SER, the staff concluded that the training for licensed plant staff per-sonnel meets regulatory requirements. Furthermore, the shift staffing shown in Table 13.3-5 of the Plan conforms to Table B-1 of NUREG-0654 (Table 2 of Supple-ment 1 to NUREG-0737). The staff finds this portion of the applicant's Plan adequate. (2) Availability Requirement of Recovery Manager and Other Personnel , By letter dated August 14, 1984, the applicant provided the results of its study of residential patterns to determine response capability as suggested in Table 8-1 : of NUREG-0654. On the basis of these results and FSAR Amendment 15, the staff ! finds that the applicant's Plan meets the guidance criteria of Table B-1 under normal weather and traffic conditions. Under severe weather or heavy traffic conditions, the applicant specifies that the 30-minute responders could be avail-able in 45 minutes. To implement the 60-minute augmentation criteria during , these conditions, all but six individuals would be available in 60 minutes. Of River Bend SSER 2 13-7 l
_ _ . _ _ _ . . _ _ ~1.2.'a .a .C - - . - u. . ----il w-
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[ l j these six individuals, five would be available in 75 minutes and one, an alter-nate radiation protection technician, would require about 90 minutes to be avail-
,. able at the site. The Plan indicates that the entire emergency organization, ~d including a primary person and two alternates for each key position, could be 7i available within 60 minutes during fair weather and light traffic. The staff finds this portion of the applicant's Plan adequate.
(3) Primary and Alternate Spokespersons i
' FSAR Amendment 15 (Table 13.3-5 and Section 13.3.6.2.1).identif'ies the Senior Vice President External Affairs (Gulf States Utilities (GSU) Public Spokesperson) as the primary spokesperson and the Administrator of Louisiana Communications as the alternate spokesperson. The staff finds this portion of the applicant's Plan adequate.
13.3.2.3 Emergency Response Support and Resources (1) Dispatch of a utility Representative FSAR Amendment 15 provides for the dispatch of a technical representative.to each of the five parish EOCs during a Site Area or General Emergency in order to ensure continuity and coordinetion among the utility, State, and affected parishes. The staff finds this portion of the applicant's Plan adequate. (2) Review of Proposed Change To Replace the Mutual Assistance Plan The Mutual Assistance Plan between Gulf States Utilities Company, Arkansas Power and Light Company, Louisiana Power and Light Company, Mississippi Power and Light Company, and Middle South Services, Inc., contained in Appendix B to the Plan is to be replaced by the " Nuclear Power Plant Emergency Response Voluntary Assistance Agreement," which is advocated by INPO. An appropriate Plan change will be made. Also, copies of the INPO Emergency Resources Manual will be available in'the Technical Support Cer.ter and Emergency Operations Facility. The staff finds this proposed change to the applicant's Plan adequate. 13.3.2.4 Emergency Classification System (1) Emergency Action Levels Following discussions with the applicant in May 1984, Table 13.3-1 of the Plan was revised by FSAR Amendments 13 and 15. The staff completed its review of Table 13.3-1, Amendment 15, dated November 1984, and on February 22, 1985, requested that the applicant provide additional information and clarification on certain EAls that were previously discussed with the applicant. On March 29, 1985, the applicant provided the additional information and clarification that were requested and committed to make a further minor revision to the EAL scheme in a future FSAR amendment. The staff finds this portion of the applicant's Plan adequate. 13.3.2.5 Notification Methods and Procedures (1) Emergency Implementing Procedures On October 3,1984, the applicant submitted its approved EIPs for the staff's review. The review of EIPs was conducted during the onsite appraisal of the River Bend SSER 2 13-8 i
- ... . _ . .-.,a.-.a- . - - --- - - - - - - - - - - - - - - - -
4 L, applicant's implementation of its emergency preparedness program on Decem-ber 3-14,1984 (see IE Inspection Report No. 50-458/84-35). The staff finds
, this portion of the applicant's Plan adequate.
(2) Notifying Augmentation Personnel i Notification of the applicant's emergency organization augmentation personnel located in Beaumont, Texas, is addressed in Section 13.3.2.13 of this supplement. This confirmatory item is considered closed. (3) Alert and Notification System A general description of the final system configuration, siren control s'ignals, and system communications has been provided and included in FSAR Amendment 15. On February 5,1985, the applicant provided information on alert monitoring radios to be placed in special facilities as a secondary means of notification within the 10-mile emergency planning zone (EPZ). This information will be included in a future amendment to the FSAR. On April 19, 1985, the applicant submitted an " Operational Siren Certification Report." The report includes a complete system description; installation infor-mation; means for alerting special facilities, unpopulated areas, and the trans-1ent population; a design report summary, and a schedule for completing the sys-tem and testing it. The applicant informed the staff that all sirens are now installed and that the operability of the entire system was tested on May 29, 1985. The results of this test will be furnished to NRC Region IV. The applicant plans to submit a full report on the total. alert and notification system (ANS) in accordance with the FEMA 43 procedure in the near future. NRC Region IV has identified the installation and operability testing of the ANS as an item to be completed before fuel load. Accordingly, Region IV will pro-vide confirmation in an inspection report that the ANS has been installed and operability tested. On the basis of its review of the Plan and the applicant's submittal of April 19, 1985, the staff finds this portion of the applicant's Plan adequate. This item is closed. (4) Notifying the Public FSAR Amendment 15 provided additional information on the administrative capabil-ity of local authorities to promptly alert the public. A dedicated telephone system permits plant personnel to notify the five parishes and State agencies simultaneously and within 15 minutes, on a 24-hr/ day basis, of any emergency classification and recommended protective actions for the public. On reaching a decision to implement a protective response, each Parish Police Jury President, through the Civil Defense Director, will first ensure that an Emergency Broad-cast System message coordinated with other parishes is ready to be broadcast. Control consoles in each of the five parish Emergency Operation Centers (EOCs) allow activation of sirens and alert monitoring radios in each respective parish. Each of the five parishes has an emergency plan compatible with the State of Louisiana emergency plan which will be exercised periodically. Training will , be provided on the offsite plans. The EAL configuration in Table 13.3-1 of the
- Plan provides the utility interface with State and local officials for offsite River Bend SSER 2 13-9 l
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]' ;_ response under the four emergency classifications. On an annual basis, State N
and local authorities will review their interface with the applicant with regard to offsite response necessary (under the four emergency classes as shown in the f EAL scheme in Table 13.3-1) for the protective action decisionmaking process. T S The protective action decisionmaking process (onsite and offsite) utilizes plant status, core / containment conditions, offsite monitoring results, EPA protective action guides, protective action sections (subareas of the 10-mile EPZ), EAL
; table, and evacuation time estimates in the Plan. The staff finds this portion il of the applicant's Plan adequate.
13.3.2.6 Communications (1) Testina the Health Physics Network and the Emergency Notification System Section 13.3.7.3.2.3 of the Plan has been revised to include testing of the health physics and emergency notification systems between the control room, TSC, EOF, NRC Headquarters, and NRC Region IV on a monthly basis. The staff finds this portion of the applicant's Plan adequate.
, 13.3.2.7 Public Information i, (1) Emergency Information Brochure
^ 3 The staff has received a copy of the final public emergency information brochure. The brochure contains the information specified in the guidance criteria of NUREG-0654. FEMA will provide an evaluation of the brochure in the process of
- its review of offsite plans. The staff finds this portion of the applicant's Plan adequate.
13.3.2.8 Emergency Facilities and Equipment (1) Interim Facilities 1 By letter dated February.16, 1984, the applicant committed to submit a new appendix to FSAR Section 13.3 that describes the capabilities of the interim facilities. In lieu of submitting a new appendix to the Plan, the applicant I changed Section 13.3.6 identifying those automated, diagnostic functions in the TSC and EOF which may not be fully functional until February 1986. Table 13.3-16 to the Plan specifies the primary and backup (secondary) systems for the emer-gency response information system (SPDS), digital radiation monitoring system - automated dose assessment system (MIDAS), and the meteorological information system. The applicant specifies that the secondary systems are provided so that the ERFs can effectively support an emergency. The ERFs were reviewed during the onsite appraisal in December 1984, and were utilized during the full participation emergency preparedness exercise on January 16, 1985. The staff finds this portion of the applicant's Plan adequate and also finds that, on an interim basis, the ERFs are capable of supporting an emergency response effort in the event of an emergency at River Bend. Therefore, this outstanding issue is closed for the SER. However, as indicted in the SER, the staff will conduct a post-implementation appraisal of the ERFs in accordance with Supplement 1 to NUREG-0737 on a schedule to be developed between the applicant and the staff. River Bend SSER 2 13-10
. d.,_
. ._ ____ - _ ;._ _ _ m _. - _ . _ . _ _ . _ _ __ _ _ _ _
j j 1
]
pl (2) Meteoroloutcal Monitorina Program
.)
H The staff has reviewed the meteorological monitoring program presented in Sec-tions 13.3.5.2 and 13.3.6.3 and Table 13.3-8 of the Plan and has conducted an onsite appraisal of its implementation. The staff's evaluation of the adequacy
'! of the applicant's emergency response meteorological monitoring program, as pre-sented in the Plan, and the implementation of the program is provided in IE Inspection Report No. 458/85-05. The staff considers this item closed.
(3) Lists of Medical and Radiological Equipment and Supplies Appendix E to the Plan has been revised and now provides a list of medical and radiological equipment and supplies to be stored and used at West Feliciana Parish Hospital and Our Lady of the Lake Regional Medical Center. The staff finds this portion of the applicant's Plan adequate. 13.3.2.9 Accident Assessment (1) Dose Assessment Methodology Three methods for assessing the potential and actual consequences of a release of airborne radioactivity are described in the Plan. These consist of a com-puterized dose assessment method, which is the primary method, and two backup hand calculational dose assessment methods. The computerized system, termed the Online Dose Assessment System (ODAS), re-ceives effluent monitor data from the radiation data processing subsystem, meteorological information from the onsite meteorological tower, and isotopic composition data from multichannel analyzer input. These data are used for accident assessment and dose projection calculations using a model which con-forms to the Class A model described in Appendix 2'of NUREG-0654, Revisi6n 1. The model uses a blend of equations from RGs 1.111 (Revision 1) and 1.145 (Re-vision 1). The ODAS can compute and plot contour lines of equal disperion or dose on a site map based on the last 10-minute average of meteorological data recorded. Several alternative approaches are available to input release rates, isotopic data, and meteorological data. An alternative manual calculation procedure is provided, via EIP-2-024, using a programmed electronic calculator with a printer. If both computer and cal-culator are not available, a third, totally manual method is provided in EIP-2-024 to calculate doses. The last method uses information from EPA's Manual of Protective Action Guides to convert concentrations of radionuclide to dose rate. The applicant has described methods by which the doses to the relevant target organs of individuals in the vicinity of the site can be estimated. The Plan also includes a manual procedure to assess the possible impact of a poten-tial release to the liquid pathway (i.e., the Mississippi River). The appli-cant's dose assessment methods provide an adequate planning basis for emergency preparedness purposes. Accident conditions of radiation levels in containment will be indicated by high range containment area monitors. Radioactive material available for release from the containment can be estimated using the readout from these monitors in , , conjunction with the graphs in Figures 13.3-25 and 13.3-26 of the Plan, relating ' 1 River Bend SSER 2 13-11
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area monitor reading in containment versus time for the following accident situa-tion radioactive releases: 100% gap activity, 100% coolant activity, and 1, 10, and 100% fuel inventory. Information from the high-range containment monitors is included in offsite dose assessment and is also incorporated in the EAL scheme for classifying Site Area and. General Emergencies. The staff finds this portion of the applicant's Plan adequate. (2) Procedures for Radiological Sampling and Monitoring On October 3, 1984, the applicant submitted approved EIPs to the staff. EIP 013 and EIP-2-014 provide instructions to the monitoring teams for inplant, onsite, and offsite radiological monitoring, respectively. These EIPs will be reviewed during the health physics preoperational inspection program. The staff finds this portion of the applicant's Plan adequate. (3) Detection and Measurement of Radioactivity in Liquid Effluents Section 13.3.3.2.2 of the Plan has been revised and now provides a general description of the applicant's methods for handling potential releases via the cooling tower blowdown and liquid radwaste effluent lines. These lines have radiation monitors that detect the radiation level in the blowdown to the Mississippi River and will alarm in the contrcl room for any level above pre-established setpoints. EIP-2-024, "Offsite Dose Calculation-Manual Method," provides a method for projecting doses resulting from liquid releases. The EIPs will be reviewed during the health physics preoperational inspection program. The staff finds this portion of the applicant's Plan adequate. 13.3.2.10 Protective Response (1) Manual Method of Accountability Section 13.3.4.2.2.8 of the Plan has been revised to include a description of a manual badge exchange system that will be used to perform accountability in the event the security access control system is inoperative. The staff finds this portion of the applicant's Plan adequate. (2) Classification of Emergencies and Protective Action Recommendations The applicant has incorporated the guidance of Appendix 1 of NUREG-0654 into Table 13.3-1 (EAL scheme) of the Plan and EIP-2-007, " Protective Action Recom-mendation Guidelines." The staff finds this portion of the applicant's Plan adequate. (3) 30-Minute Accountability for All Persons On Site Section 13.3.5.4.1.1.3.4 of the Plan has been revised to specify accountability of all onsite individuals within 30 minutes of the declaration of a Site Area or General Emergency. In addition, should the Emergency Director determine that a protected area evacuation is required for other classes of emergency, the accountability will be accomplished within 30 minutes of the evacuation order. The staff finds this portion of the applicant's Plan adequate. River Bend SSER 2 13-12 , i
13.3.2.11 Radiological Exposure Control (1) Exposure Limits for Medical Personnel In correspondence dated February 5, 1985, the applicant specified that exposure limits for ambulance drivers are in accordance with the Louisiana Radiation Regulations, and by FSAR Amendment 16 revised the Plan accordingly. The staff finds this portion of the applicant's Plan adequate. 13.3.2.12 Medical and Public Health Support (1) Emergency Medical Assistance Plans
)
By letter dated August 14, 1984, the applicant submitted the emergency medical assistance plan (EMAP) and the Decontamination and Treatment of the Radioactivity Contaminated Patient Manual of West Feliciana Parish Hospital and Our Lady of the Lake Regional Medical Center. The submittal contains a description of the hospitals' capabilities and agreement letters between Our Lady of the Lake Regional Medical Center, Jackson Rescue Unit, West Feliciana Parish Hospital, and Radiation Management Corporation (RMC) and the applicant. The submittal also includes agreement letters between RMC and the Hospital of the University of Pennsylvania and Northwestern Memorial Hospital. By FSAR Amendment 15, the applicant incorporated the EMAP into the Plan by reference. Appendix C to the Plan lists the EMAP as a supporting emergency plan. Controlled copies of the supporting emergency pisns are maintained in the TSC and EOF. The staff finds this portion of the applicant's Plan adequate. (2) Letters of Agreement FSAR Amendment 13 provided letters of agreement with the Jackson Rescue Unit and West Feliciana Parish Hospital. The staff finds this portion of the applicant's Plan adequate. j 13.3.2.13 Recovery and Reentry Planning and Postaccide.nt Operations (1) Coordination of Emeroency Plans By letter dated August 14, 1984, the applicant furnished additional information on the relationship between the River Bend Nuclear Group (RBNG) and GSU's head-quarters. The applicant specifies that GSU headquarters does not provide support as previously detailed in FSAR Section 13.3.4.3.1 and Figure 13.3-11. The Plan has been revised to show that the RBNG is organized to support einergencies and provide long-range support during the recovery phase. Interface may be required between the Recovery Manager (Senior Vice President - RBNG), and GSU's Chief Executive Officer for authorization of funds above the Recovery Manager's authorized level. However, according to the Plan, GSU's Approvals and Author-ization Procedures are in place to support this interface. The GSU Treasurer and Controller will manage funds required by RBNG during the emergency and recovery phases. In addition, the Licensing Support Coordinator (Beaumont, Texas) previously referenced in FSAR Table 13.3-5 is within the RBNG but is no
, longer a member of che emergency organization. Tne Joint Information Center (JIC) is operated by the JIC Director. The primary spokesperson within the emergency organization is the Vice President - External Affairs located in -
River Bend SSER 2 13-13 I _____a
_ . ._. .. n ___ _ . . _ _ _ . . . _ _ . . . - _ . _ _ ._ _ 4 i 2 Beaumont, Texas. However, the Administrator of Louisiana Communications (JIC
- Director) is located in Baton Rouge and will serve as the alternate spokesperson j until he is relieved by the primary spokesperson. Primary and backup communica-tions exist between River Bend and the GSU corporate office. EIP 2-006 provides for notification of the JIC Director by a pager system at the Notification of Unusual Event level.
a An Emergency Communications Staff Activation and Functions Procedure (EIP-2-023) describes the functions of the GSU primary spokesperson and his alternate when interfacing with RBNG, local, and State public information personnel and the media. To ensure that the necessary coordination and interface exists among i RBNG and local and State plans and procedures, the Recovery Manager will manage I appropriate emergency implementing procedures with offsite authorities. The staff finds this portion of the applicant's Plan adequate. 13.3.2.16 Responsibility for the Planning Effort: Development, Periodic Review, and Distribution of Emergency Plans (1) Cross-Referencing the Plan and Emergency Implementing Procedures Revised Table F-2 of Appendix F to the Pla includes a cross-reference between the EIPs and the section of the Plan that is implemented by each EIP. The staff finds this portion of the applicant's Plan adequate. 13.3.3 Conclusions On the basis of the staff's review of the applicant's Plan, the staff concludes that the state of onsite emergency preparedness provides reasonable assurance that adequate protective measures can and will be taken in the event of a radio-logical emergency during operation up to 5% of rated power. The staff!s conclusions with regard to offsite emergency plans and preparedness will be provided in a future supplement to the SER in support of full power ope {ations. 13.4 Operational Review The organizational changes made by the applicant have resulted in changes in the onsite Facility Review Committee. The new composition of the FRC is as follows: Assistant Plant Manager - Technical Services, Chairman Assistant Plant Manager - Maintenance and Materials Assistant Plant Manager - Operations, Radwaste, and Chemistry l - General Operations Supervisor l Reactor Engineering Supervisor [ Supervisor - Radiological Programs There are also two nonvoting members on the onsite review committee: the t Director, Operations QA and the Plant Services Supervisor, who acts as Secretary. River Bend SSER 2 13-14 _ _ _ _ _ _ _ _ _ _ _ 1
~ 6 9 d' The committee composition appears to provide expertise or access to expertise in all required areas. The quorum is established as the Chairman (or desig-nated alternate) and four members, of whom no more than two are alternates.
', The review responsibilities for procedures are proposed to be that the FRC reviews all general administrative procedures. All other procedures are re-viewed by the department responsible for their preparation (a peer review sys-4 i tem). Additionally, cross-discipline reviews are done as required. Proce-dures are approved by either the Plant Manager or by one of his direct assis- . tants, e.g., Assistant Plant Managers. This review plan concentrates the efforts of the FRC on the broader procedures which establish programmatic con-trols and allows detailed technical review by technical groups.
The makeup of the offsite committee, the Nuclear Review Board (NRB), has also changed. NRB composition is: Vice President - Safety and Environment, Chairman Vice President - River Bend Nuclear Group, Vice Chairman and Member a Executive Vice President - External Affairs, Member Manager - Design Engineering, Technical Services Department, Member Hanager - Engineering, Nuclear Fuels and Licensing, Member River Bend Station Plant Manager, Member Assistant Plant Manager - Operations, Radwaste and Chemistry, Member Manager - Quality Assurance, Member Manager - Administration, Member Director - Nuclear Plant Engineering, Member Director - Nuclear Fuels Design and Safety. Analysis, Member Director - Nuclear Licensing, Member This composition appears to contain or to have readily available expertise in all required areas. The quorum is the Chairman or the Vice Chairman and six members including no more than two alternates. This means that a majority of the NRB will be present in order to conduct a meeting. Also, individuals with line responsibility for power production are a minority on this committee. The ISEG has been changed organizationally so that the ISEG reports to the Vice President - Safety and Environment. This appears to meet the requirements and intent of TMI Action Plan Item I.B.1.2. The staff finds that the changes in review and audit meet SRP Section 13.4 and are acceptable. 13.5 Station Administrative Procedures 13.5.2 Operating, Maintenance, and Other Procedures - 13.5.2.2 Operating and Maintenance Procedures Program In SER Section 13.5.2.2, the staff described the review and approval of the applicant's operating and maintenance procedures program through FSAR Amendment 11. A letter from W. J. Cahill, Jr. , to H. R. Denton, dated Feb-ruary 20, 1985, transmitted FSAR Amendment 16, which included changes made by ,. the applicant to FSAR Section 13.5, " Procedures." The staff reviewed these River Bend SSER 2 13-15 H
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I[.t t [i changes and determined that the applicant's operating and maintenance procedures program continues to meet the relevant requirements of 10 CFR 50.34, and remains consistent with RG 1.33, ANSI Std. N18.7-1976/ANS Std. 3.2, and NUREG-0800, Standard Review Plan, Section 13.5.2, " Operating and Maintenance Procedures." 13.5.2.3 Reanalysis of Transients and Accidents; Development of Emergency
. Operating Procedures
'j SER Section 13.5.2.3 described the review of the River Bend Station (RBS) Pro-
; cedures Generation Package (PGP) and identified one item (indicated as Confirma-tory Item 60 in the SER) that had to be completed before the applicant's pro-gram for developing procedures could be approved. This item was the identifica-tion and justification of safety-significant differences between the RBS plant- , specific. technical guidelines and the NRC-approved BWR Owners Group guidelines. ; These differences and justifications were provided to the staff in a letter from J. E. Booker to H. R. Denton, dated January 15, 1985. Supplemental information was provided to the staff on February 11, 1985.
The staff used the plant-specific procedures to evaluate the justification for each deviation from the generic technical guidelines. Telephone discussions with the applicant were held on March 1 and 7, 1985, for clarification of several items. The procedures submitted by the applicant have several plant-specific setpoints, operator action levels, and procedure references which are to be determined. The staff will confirm that the information required to complete each procedure is incorporated into the procedure before fuel loan through the routine pre-licensing inspection program. Justifications for several deviations included commitments by the applicant to change plant procedures, in most cases,. based on improvements identified during the plant's procedure verification and validation effort. These changes were identified in deviations discussed on pages 7, 10, 16, 17, 19, 20, 27, 35, 39, and 52 of Attachment 1 to the January 15, 1985, letter. These changes must be completed before fuel load. In addition, the apolicant committed to change or i clarify the deviations on pages 18, 34, and 50 of Attachment 1 to the January 15, 1985, letter. The staff will confirm the acceptability of these revised devia-tions in an SER supplement. The staff identified three errors associated with the deviations reviewed. i First, although the justification on page 1 of Attachment 1 stated that generic Emergency Procedures Guidelines (EPG) Cautions 1-8 were addressed in training l and not in the procedures, two cautions which the operators would be expected ; to have difficulty remembering (6 and 8) are, in fact, included in the proce- l
. dures. The staff found this acceptabl.e. Second, the staff found an inconsis- i tency in the value used for the "maxiium subcritical banked withdrawal position." l The applicant stated that it had also found the inconsistency and that-it had been corrected. The staff found this acceptable. Third, the staff identified an apparent typographical error in the justification for E0P-0002, step 3.4.4 (page 33 of the attachment) referencing 2 psig instead of 12 psig. On the basis of these changes, the staff found the material acceptable.
Finally, the RBS Emergency Operating Procedures direct the plant operators to vent the primary containment when containment pressure exceeds the " primary River Bend SSER 2 13-16 )
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' containment pressure limit" as defined by a curve of primary containment water level versus suppression chamber pressure. The RBS limit proposed is based on 4
an ultimate capacity of 56 psia which is in excess of the design pressure by a factor of about three. The NRC staff's Safety Evaluation Report on Revision 2 of the generic Emergency Procedure Guidelines (issued February 1983) has ap-
' proved the use of twice design pressure as an interim limit provided containment integrity can be demonstrated. The staff is aware of a proposed revision to the
' generic EPGs which will result in a redefinition of the venting criteria. In this regard, it is the staff's intent to continue the review of the proposed
" venting criteria (both generically and for each plant) which place emphasis on the following areas:
(1) purge valve operability at the proposed venting pressure (2) consideration of depressurization rate during venting to limit suppression pool flashing (3) ' safety / relief valve actuation at high containment pressures (4) structural analyses and tests (5) limitation of offsite release rates by selective use of vent paths The staff must complete its review of this item before operation above 5% of rated power. I River Bend SSER 2 13-17
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4 Figure 13.1 River Bend Nuclear Group management structure (revised from SER) River Bend SSER 2 13-18
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a j s T k Chairman
, of the Board .
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Senior Vice President - RBNG Vice President Safety and Environment _ , B . Manager Quality Assurance Manager A Project Control L-Vice ' President - RBNG C Manager - Engineering. Plant Nuclear Fuels, Licensinj Manager f Manager D Manager - Projects Planning & Coordination Administration , 3 , 4 R:;IC!:^ * ) - Figure 13.1 4 River Bend Nuclear Group $ C%Y L.- pnagement f tructure (revi5ed Op SEg} NOTES: A See Figure 13.1-3 7 pgAR B .See Figure 17.2-1 ' C See Figure 13.1-6 D S'ee Figure 13.1-2 E See Figure 13.1-4 _ e e e .
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?- .= _ _ _ _ u . u -- i j i J l 15 TRANSIENT AND ACCIDENT ANALYSIS. 15.9 TMI Action Plan Requirements J
' 15.9.3 Item II.K.1 - IE Bulletins on Measures To Mitigate Small-Break LOCAs and Loss-of-Feedwater Accidents Item II.K.1.5 - Assurance of Proper Engineered Safety Features Functioning Confirmatory Item 62 required NRC Region IV to verify that procedures satisfied the requirements of IE Bulletin 79-08, Item 6. The staff of Region IV has determined by inspection that the applicant has issued appropriate procedures to meet the aforestated item. This will be documented in NRC Inspection Report 50-458/85-49.
This completes regional action on Confirmatory Item 62 and the item is resolved. 15.9.4 Item II.K.3 - Final Recommendations of Bulletins and Orders Task Force Item II.K.3.31 - Plant-Specific Calculations To Show Compliance With 10 CFR 50.46 Plant-Specific LOCA Analysis The staff's SER (Sections 6.3.3.3 and 15.9.4) reported the results of a lead plant loss-of-coolant accident (LOCA) analysis that was stated by the applicant to be representative of River Bend. The SER also noted that the applicant had committed to supply a plant-specific LOCA analysis for River Bend before fuel loading. The applicant provided the LOCA analysis specific for River Bend in FSAR Amendment 15, dated November 1984. The plant-specific LOCA analysis included a spectrum of large and small pipe breaks and indicated that the most limiting break is a design-basis break in a recirculation suction pipe. As for the lead plant, an assumed failure of the low pressure coolant injection (LPCI) diesel generator, coincident with the break, resulted in the worst single failure con-dition. The plant-specific results demonstrate compliance with the requirements of 10 CFR 50.46. (See revised Table 6.2.)
~ From it review, the staff concludes that the plant-specific LOCA analyses for River Bend are acceptable. This issue is, therefore, closed.
River Bend SSER 2 15-1
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i 18 HUMAN FACTORS ENGINEERING The staff evaluation of the organization, process, and results of the River Bend detailed control room design review (DCRDR) contains the following elements, consistent with Section 18.1 and its Appendix A to Section 18.1 of the Standard Review Plan (NUREG-0800): (1) an evaluation of the DCRDR Program Plan submitted by the applicant (2) an onsite in progress audit of the DCRDR conducted July 24-27, 1984 (3) an evaluation of the applicant's DCRDR Summary Report (4) a preimplementation audit meeting with the applicant's DCRDR team leader and human factors contractor, January 23, 1985 (5) review of a letter dated January 23, 1985, providing supplemental informa-tion to clarify the applicant's DCRDR Summary Report The staff was assisted in items 1-3 above by consultants from Lawrence Livermore National Laboratory (LLNL). Appended to this SER supplement is the Technical Evaluation Report (TER) prepared by LLNL (Appendix J). Except as noted, the staff concurs with the evaluation, conclusions, and recommendations contained in the LLNL report. The following summarizes the staff's evaluation findings regarding the required elements of the River Bend DCRDR. 18.1 Human Factors Engineering Team 1 The applicant has established and utilized a qualified multidisciplinary team to conduct the detailed control room design review (DCRDR). The concern raised (see Appendix J) that the applicant's Summary Report indicates a significant reductius in the participation of human factors specialists during the final implementation and verification of control room design changes has been accept-ably addressed by the applicant in a letter dated January 23, 1985. The con-tinued application of appropriate human factors expertise through the completion of DCRDR activities should be confirmed by the applicant in his scheduled supplement to the DCRDR Summary Report. 18.2/18.3 System and Task Analysis The methodology described in the applicant's Summary Report and discussed in depth at the DCRDR in progress audit provides an acceptable means to fulfill the function and task analysis requirements of the DCRDR. The information provided in the Summary Report, however, is insufficient to allow the staff or its consultants to determine if discrete operator tasks, decisions and actions associated with each task, and information and control requirements for success-ful task performance have been identified and analyzed to an acceptable level I of detail. The staff met with the applicant's DCRDR team leader and human , ! factors consultants on January 23, 1985, to determine if these processes have
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been adequately performed and documented. The staff audited the DCRDR task River Bend SSER 2 18-1
analysis documentation for selected emergency scenarios. The sample audited revealed that the applicant has identified the discrete tasks, decisions, and actions operators need to undertake in order to carry out emergency actions. Review of the documented information and control capability requirements for task performance, however, indicates that the applicant applied a broader definition of " requirements" than the staff had anticipated. As a result, the information and control requirements include more than the minimum requirements for completing the task. Because of this, the subsequent comparison of informa-tion and control requirements with the controls and displays in the existing control room appears, as currently documented, to indicate more discrepancies than the applicant has reported. On the basis of the explanation of the verification of availability and suitability of displays and controls which was provided at the audit meeting, the staff believes that the process employed was adequate and identified human engineering discrepancies (HEDs) correctly. In order to confirm this, the applicant should provide written documentation for at least one emergency sequence which unequivocally demonstrates how it was determined.that the inventoried displays and controls provided the necessary information and control capability. This information may be provided in the scheduled supplement to the DCRDR Summary Report. 18.4 The Main Control Room 18.4.1 Control Room Inventory Although the control room inventory compiled by the applicant does not conform precisely to that recommended by the staff, the approach used is satisfactory. The documentation required to confirm the acceptability of the task analysis (see preceding paragraph) will also serve to confirm that the control room inventory function has been met. 18.4.2 Control Room Survey With the exception of items which have not been completed because of the con-struction status of the plant, the control room survey conducted as part of the DCRDR meets the requirements of Supplement 1 to NUREG-0737. Control room survey items which must be completed before fuel load include: lighting; heating, ventilation, and air conditioning (HVAC); noise levels; communications; and the availability of procedures and adequate protective clothing. The applicant has committed to evaluate these items and report the results to NRC in a supplement to the DCRDR Summary Report before fuel load. This is acceptable to the staff if the supplement also provides resolutions and an acceptable implementation schedule for any HEDs identified and assessed as significant. 18.4.3 Assessment of HEDs The method applied by the applicant to assess the significance of HEDs satisfies the requirements of Supplement 1 to NUREG-0737. 18.4.4 Selection of Design Improvements The applicant's approach to selecting design improvements which will correct significant HEDs is potentially acceptable for meeting the DCRDR requirements. , However, on the basis of a review of the priority 1 and 2 discrepancy records
- River Bend SSER 2 18-2
I I j in Section 7 of the applicant's Summary Report, the appropriateness of the pro-posed resolution of numerous HEDs is uncertain and/or unacceptable to the staff. The HEDs for which further information and/or additional action is needed are specified in Appendices A and B of the technical evaluation report (TER) that i appears in this supplement as Appendix J. These HEDs fall into several cate-l gories which will require the applicant to take different degrees of action in order to resolve the HEDs to NRC's satisfaction. Many HEDs in question will require only a firmer commitment to implement a specific resolution consistent with good human engineering practices. In its letter of January 23, 1985, the applicant provided a generic commitment to develop and apply appropriate conven-tions and to implement certain displays associated with the safety parameter display system (SPDS) before fuel load. This commitment should be made specific to the HEDs identified in the appendices to the TER. Other HEDs with which the staff has concern will require either additional, more detailed justification for the proposed resolution or modification to the proposed resolution. For those HEDs which the TER recommends implementing before fuel load rather than before exceeding 5% power, the applicant should either modify its implementation schedule accordingly or provide justification for delaying implementation. Of particular concern to the staff is the possibility that, as now scheduled, some modifications may interfere with initial reactor startup operations. The applicant should include the resolutions to the referenced HEDs in its scheduled supplement to the DCRDR Summary Report. 18.4.5 Verification of Design Improvements The staff gengrally agrees with the recommendations in the appended TER (Appen-dix J) regarding verification that design improvements provide the necessary corrections and do not introduce new HEDs. The staff only requires, however, that the applicant confirm that modifications to the control room have been or, in the case of modifications not yet implemented, will be verified to ensure that the desired correction has been obtained without introducing new HEDs. 18.4.6 Coordination of DCRDR With Other Activities Although the appended TER (Appendix J) notes some deficiencies in the documen-tation of the coordination and integration of the DCRDR with other Supplement 1 to NUREG-0737 activities, the staff does not require additional documentation at this time. The staff may, however, require additional information about the integration of the River Bend SPDS into the control room during its review and audit of the SPDS. Conclusions The staff concludes that, with the exception of the issues identified below, the applicant meets the relevant requirements of Supplement 1 to NUREG-0737 for conducting a detailed control room design review. The applicant should provide for staff review information that will: (1) Confirm the continued participation of human factors specialists in remaining DCRDR activities (Confirmatory Item 66). (2) Document the adequacy of the DCRDR task analysis (Confirmatory Item 67). I River Bend SSER 2 18-3
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t (3) Confirm that the remaining control room survey items have been completed and provide acceptable resolutions and implementation schedules for any significant HEDs identified (Outstanding Issue 20b). (4) Respond to the specific concerns regarding resolution of the HEDs identified in Appendices A and B to the technical evaluation report appended to this supplement (Appendix J) (Outstanding Issue 20c). 3 (5) Confirm that all control room modifications resulting from the DCRDR have
."[ been verified to ensure they provide the expected correction and do not q ~1 introduce new HEDs (Confirmatory Item 68). 'l
- This information should be included in the supplement to the applicant's Summary Report to be provided before fuel load.
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.y APPENDIX A CONTINUATION OF CHRONOLOGY OF NRC STAFF RADIOLOGICAL .
REVIEW OF RIVER BEND STATION I. ! October 1, 1984 Letter from applicant forwarding interim response to Sec-tion 1.2 of Generic Letter 83-28, " Required Actions Based on Generic Implications of Salem ATWS Events."
,N October 1, 1984 Letter from applicant forwarding comments on Draft Environ-mental Statement, NUREG-1073.
October 5, 1984 Letter from applicant confirming qualification status of Category I safety-related equipment seismic qualification program. October 5, 1984 Summary of July 27, 1984 audit exit meeting with applicant ~ i at site regarding detailed control room design review. , October 8, 1984 Letter from applicant forwarding " Gulf States Utility Co. 4 Position Regarding Safety / Relief Valve Discharge Testing at River Bend Station," in response to staff's November 14, 1983 letter. Information completes SER Confirmatory Item 13. October 9, 1984 Summary issued on August 7-9, 1984 meetings in San Jose, CA, with applicant and staff to resolve SER Section 7 con-firmatory issues. Octcber 11, 1984 Letter from applicant forwarding additional information addressing SER Confirmatory Item 12 regarding results of computer runs to model containment pressure following loss-of-coolant accident steam bypass event. Revised FSAR page is also enclosed. t October 11, 1984 Letter from applicant forwarding response to SER Confirma-tory Item 16 regarding secondary containment pressure fol-lowing loss-of-coolant accident. Analysis includes revised time delays for diesel start and fan speedup. Revised FSAR pages ,and figures reflecting analysis are enclosed. October 11, 1984 Letter to applicant forwarding results of in progress audit of detailed control room design review on July 24-27, 1984. - 1
- October 15, 1984 Letter from applicant advising that final submittal regard-l ing containment issues are delayed pending documentation of final 1/10-scale test conclusions.
j 4 River Bend SSER 2 1 Appendix A
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i ' ' ' October 15, 1984 Letter from applicant forwarding response to Generic Letter 84-11 regarding inspection of BWR stainless steel piping, per August 31, 1984 letter. Contract with services organi-
- zation to perform intergranular stress corrosion cracking
' i examination of reactor coolant system is arranged. l October 16, 1984 Letter from applicant forwarding revised program plan for u , evaluating and testing Division I and II standby diesel i generators and data on inspections and testing performed to date. October 16, 1984 Letter from applicant forwarding Revision 3 to physical security plan and response to staff comments. l October 16, 1984 Letter from applicant forwarding Revision 1 to safeguards contingency plan and explanation of major changes. October 17, 1984 Summary issued on August 7-9, 1984 meetings with applicant, a General Electric Co. , and Stone and Webster in San Jose, CA 3 regarding resolution of SER confirmatory issues on instru-mentation and controls. i October 17, 1984 Letter to applicant requesting additional information re-garding shear reinforcement design, per integrated design inspection. Summary of calculations regarding redefinition of temperature gradient and resulting thermal loads and explanation of how critical sections are determined is requested. October 19, 1984 Letter from applicant forwarding updated seismic Category I safety-related equipment master list for both balance-of-plant and nuclear steam supply system. E October 19, 1984 Letter from applicant forwarding balance-of plant and nuclear steam supply system qualification master list of electrical equipment located in harsh' environment and 4 4 system component evaluation worksheets for each component. October 22, 1984 Letter from applicant submitting Amendment 14 to the FSAR which provides complete set of newly formatted piping and { instrumentation diagrams as redrawn to latest design
- documents.
October 22, 1984 Letter from applicant forwarding description of offsite fire department training program, addressing SER Confirma-tory Item 58. Revised FSAR pages, including fire brigade training program are also enclosed. _ October 22, 1984 Letter from appitcant forwarding information in support of Seismic Qualification Review Team and Pump and Valve Qualification Review Team audits, per staff's December 21, 1982 request. , l River Bend SSER 2 2 Appendix A i ev -r--.-,.,,--,-.----.-%. --------_m-, ,.y. , , ~ . -,r-e-y, ,-e-<--w.,_ ..--e,m,,,--c- -wm.,-.w.-r,.--.i, ,-w.,.-..,-,..,--_
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-I ,! October 31, 1984 1
Letter from applicant forwarding summary report, " Detailed
;- Control Room Design Review, Methodology and Approach, Human
'l Engineering Discrepancy Results," per Generic Letter 82-33,
; " Supplement 1 to NUREG-0737 - Requirements for Emergency 4 Response Capability."
1
' November 1, 1984
. Letter from Duke Power Co. forwarding applicant's March 4, j 1980 letter in support of statements in June 1984 report,
" Supplement to Emergency Diesel Generator Auxiliary Module Control Wiring and Termination Qualification Review." ..
November 2, 1984
- Letter to applicant forwarding September 27, 1984 trans-mittal of FEMA report regarding adequacy of offsite planning.
November 5, 1984 Letter from applicant forwarding response to SER Open Item 4, " Inservice Test Program" and Open Item 6, " Pre-service Inspection Program." November 5, 1984 Letter from applicant forwarding response to staff's Decem-ber 22, 1980 request for information in Sections 2.2, 2.3, and 2.4 regarding planned controls for handling heavy loads. SER Outstanding Item 12 is satisfied. November 8, 1984 Letter to applicant forwarding request for additional infor-mation regarding initial test program and SER (NUREG-0989) Confirmatory Item 61, for review of FSAR Chapter 14 through Amendment 13. November 8,1984 Letter to applicant forwarding SER Supplement 1 (NUREG-0989). November 8, 1984 Letter to applicant informing it of staff's intent to con-duct Caseload Forecast Panel site visit on December 4-6, 1984. November 8, 1984 Letter from appitcant forwarding revised response to staff's January 23, 1984 position regarding drywell/ containment purge system, "LOCA and Seismic Analysis" and revised text of FSAR. Enclosures respond to SER Confirmatory Item 18. November 9, 1984 Letter from applicant forwarding revised FSAR Section 8.3.1.4.2 regarding Class 1E electrical equipment arrangement. November 9, 1984 Letter to applicant forwarding staff's request for addi-tional information regarding NEDE-24988-P, " Analysis of Generic BWR Safety / Relief Valve Operability Test Results'" , to complete review of NUREG-0737 Item II.D.1. __ November 15, 1984 Letter from applicant submitting Amendment 15 to the FSAR responding to SER Open Items 3, 8, 10, 16, and 17, and Con-firmatory Items 1, 3, 7, 12, 16, 20, 51, and 54. , River Bend SSER 2 3 Appendix A
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k i November 16, 1984 Letter from applicant forwarding response to Items 1 through 4 of October 17, 1984 request for additional infor-1 mation regarding shear reinforcement design of reactor shield building. November 21, 1984 Letter from applicant forwarding revision to FSAR Sec-tion 3.8.2.7.1.1 regarding initial structure acceptance test of containment vessel. November 21, 1984 Letter from applicant providing additional information to finalize SER Confirmatory Item 35, Table 1.3 regarding operator information of maximum expected errors for water a ' level measurements in event of drywell heatup normal ambient conditions. November 21, 1984 Letter from applicant forwarding " Control System Failures Evaluation Report" and " Common Sensor Failure Evaluation Report" in response to staff's request for additional information. November 23, 1984 Summary issued on October 30, 1984 meeting with applicant in Bethesda, MO, regarding modifications to supporting sys-tem for high pressure core spray diesel generation at facility. November 27, 1984 Summary issued on November 19, 1984 meeting with applicant regarding schedule for plant, program for developing draft Technical Specifications, and quality concern program. November 29, 1984 Letter from applicant forwarding proposed revisions to FSAR Sections 1.8, 8.3.1, and 14.2, establishing qualified load for each diesel generator, providing positions on Regulatory Guides 1.9 and 1.108, and addressing high pres-sure core spray independence. November 30, 1984 Letter from applicant forwarding viewgraphs for caseload forecast presentation to staff on December 5-6, 1984, in response to November 8, 1984 request. November 30, 1984 Letter from applicant forwarding response to staff's request for additional information providing final closeout of SER Table 1.4 Confirmatory Items 8 and 9 regarding fuel assembly peak acceleration. November 30, 1984 Letter from applicant forwarding Supplement 9 to environ-mental report - operating license stage.
~
November 30, 1984 Letter from applicant submitting additional information regarding surveillance of engineered safety features unit coolers, in response to staff's request per SER Confirma-tory Item 30. November 30, 1984 Letter from applicant forwarding revised certificate of pollution control facilities and description of pollution control equipment per September 19, 1984 request. River Bend SSER 2 4 Appendix A
i
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, j- November 30, 1984 Letter from applicant forwarding 412 oversize drawings ' '(i providing final closeout of SER Confirmatory Items 21, 29, 32, 36, 37, and 38, and partial closeout of Items 24 and
- d. 43, per staff's request.
w December 3, 1984 Letter from applicant forwarding response to staff's re-
.) quest for additional information regarding SER Confirma-j tory Item 43, Table 1.4 on emergency response and informa-
; tion systems, t
') December 3,1984 Letter from applicant forwarding response finalizing SER Confirmatory Item 39 Table 1.4 on safety / relief valve j relief function.
December 3, 1984 Letter from applicant agreeing with staff that loss of redundancy of automatically initiated engineered safety features should be indicated to operator. Support system indication will be provided to close Item 9 of Table 1.3 of SER, per enclosed revisions to FSAR. December 6, 1984 Letter from appifcant providing additional information re-garding participation with Hydrogen Control Owners Group to generically address use of CLASIX-3 computer code in determining environmental conditions for equipment surviv-ability evaluation, per staff's request. December 6, 1984 Summary issued on November 1 and 2, 1984 site visit with applicant regarding development of Technical Specifications. December 10, 1984 ' Letter from applicant forwarding Draft Environmental State-
, ment (NUREG-1073) Table 4.1 regarding onsite area land use, per staff's request.
December 12, 1984 Letter to applicant informing it of issuance of enclosed
- i pollution control facilities certification, per September 19, 1984 request.
December 13, 1984 Letter to applicant responding to August 13, 1984 letter regarding operating experience on shift. Updated informa-tion is required for shift supervisors and control operat-ing foreman to ensure hot participation experience listed. December 14, 1984 Letter from applicant forwarding information requested by Caseload Forecast Panel regarding December 5 and 6, 1984 site visits and enclosing five oversize drawings. Sup-porting information is enclosed. December 14, 1984 Letter from applicant forwarding summarization of systems ~ i ' component evaluation worksheets submitted on October 19, 1984 to assist staff review of balance-of plant and nuclear steam supply system electrical equipment located in a harsh environment. i River Bend SSER 2 5 Appendix A j 4 - . _ . . _ _ - ..._m ., , , ,_ , - , , _ _ . . _ , . _ , _ _ . , - _ . . . , , - , _ , , . _ , , , . _ , , _ _ . _ - , , , , , , , _ _ . _ . _ _ _ , _ _ . , __ - , , . _ - ,-
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,)N F. X December 17, 1984 Letter from applicant forwarding for review dynamic analy-sis results for Atwood & Morrill feedwater isolation check 9
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valves. Information addresses SER Confirmatory Item 4
;; identified in Section 3.6.2 by staff. .] December 18, 1984 Summary issued on November 20, 1984 meeting with applicant and Stone and Webster in Bethesda, MD, regarding alternate j_ t and safe shutdown criteria for fire in control room.
4
/ December 18, 1984 Summary issued on meeting with applicant and Stone and 'I Webster regarding applicant's November 9, 1984 proposal to 1
1 modify FSAR commitments concerning Regulatory Guide 1.75. December 20, 1984 Letter from applicant informing the staff that comprehen-sive final submittal or status report regarding containment issues revised by Humphreys will be provided by January 11, 1985. December 21, 1984 Letter from applicant submitting information regarding estimate of permanent local operating staff for facility, a'
-December 21, 1984 Letter from applicant forwarding description of results of comparison study demonstrating that structural integrity
~
is not compromised under existing support design, in re-sponse to September 27, 1984 request. Response to SER Confirmatory Item 7 is complete. December 21, 1984 Letter from applicant responding to staff's request for additional information regarding adequate voltage to re-actor protection system scram pilot valve solenoids. Re-sponse closes out Confirmatory Item 24 of SER Table 1.4. December 21, 1984 Letter from applicant forwarding response to SER Open Item 13 regarding safe alternate shutdown. December 21, 1984 Letter from applicant forwarding revised program plan for evaluating and testing Transamerica Delaval, Inc. Division I and II standby diesel generators and data on inspections 1 and testing performed to date, l i December 26, 1984 Summary issued on November 20, 1984 meeting with applicant ' in Bethesda, MD, regarding alternate and safe shutdown criteria, per SER Outstanding Issue 9. ! i December 27, 1984 ' Generic Letter 84-24 issued to all licensees of operating reactors and applicants for operating license regarding certification of compliance to 10 CFR 50.49, " Environmental . Qualification of Electric Equipment Important to Safety of
, Nuclear Power Plants."
December 28, 1984 Letter from applicant forwarding response to SER Confirma-
< tory Items 54 and 55 regarding TMI Item II.B.2, " Plant ,
Shielding," and backup radiation protection manager desig-
- nate, respectively.
River Bend SSER 2 6 Appendix A
w._.. a- -. - d. Li q4 a. E1 January 2, 1985 Letter from applicant forwarding response to SER Confirma-i tory Item 50, Section 10.4.6. SER Section 9.3.2 should be 'd revised to reflect November 8, 1983 submittal regarding c{-1 postaccident sampling system. Enclosure provides addi-
. u- tional clarification of NUREG-0737 Item II.B.3.
Nj ' January 7, 1985 Letter to applicant forwarding marked-up BWR-6 Standard .,t , Technical Specifications, based on July 27, 1984 submittal.
- '
- Draft provides bases for late January 1985 site visit and meeting to discuss areas of June 1984 submittal not incorpo-rated in draft.
January 7, 1985 Letter from applicant forwarding " Process Control Program"
-i and "Offsite Dose Calculation Manual" for review.
January 9,1985 Generic Letter 85-01 issued to all power reactor ifcensees and all applicants for power reactor licenses regarding Fire Protection Policy Steering Committee report. 3 January 14, 1985 Letter from applicant forwarding draft status of construc- '! tion completion and testing items to be completed after F
! fuel load. Areas include normal cooling water, solid, rad-waste system, fuel building sampling system, elevators, and safe / alternate shutdown (SER Issue 3).
4 January 15, 1985 Letter from applicant forwarding additional information regarding ten concerns of Advisory Committee on Reactor Safeguards, including high pressure core spray pump and - design criteria, per July 12, 1984 meeting. 2 January 15, 1985 Letter from applicant forwarding emergency procedure guide-line deviation justification forms per SER Section 13.5.2.3, Confirmatory Item 60. Evaluation is under way to ensure that emergency operating procedures are consistent with , FSAR design basis.
- January 21, 1985 Letter from applicant forwarding revision to position on
, fuel storage areas. Fire patrol will monitor activities i
and promptly respond to events should portion of fire protection equipment remain incomplete for fuel storage Zone.
- January 21, 1985 Letter from applicant forwarding revised page to Novem-i ber 5, 1984 response to SER Open Items 4 and 6 regarding inservice testing program and preservice inspection pro-
, gram, respectively.
i , January 22, 1985 Letter from applicant forwarding revision to FSAR Section 3.8.2.7.1.1, superseding applicant's November 21, 1984 j t letter regarding initial structural acceptance test of containment vessel. i >
- January 23, 1985 Letter from applicant forwarding information regarding simulator control room comparison study, for review and
- development of SER Section 18.
River Bend SSER 2 7 Appendix A i
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1 January 23, 1985 Letter from applicant forwarding " Action Plan To Address
%q;.
Additional Containment Issues" as final response to staff-letters of June 23 and July 23, 1982. SER Confirmatory Item 14 regarding Mark III-related issues is also addressed. Information from 1/10th-scale testing program is included regarding Concerns 1.1-1.7. l January 24, 1985 Letter from applicant forwarding response to SER Confirma-N tory Item 52 regarding TMI Action Plan Item II.F.1. January 24, 1985 Letter from applicant forwarding revision to FSAR Chap-ters 13.1, 13.2, 13.4, and 13.5 regarding organizational changes. Rdsunds in FSAR Appendix 13A will be revised and updated by January 31, 1985. January 25, 1985 Letter to applicant forwarding request for additional infor-nation or clarification of pool dynamic loads in order to continue review of SER Open Item 7 regarding containment loads. ~ January 28, 1985 Letter from applicant forwarding information on SER Open Item 11 regarding submergence of electrical equipment. Equipment that could be submerged during design-basis loss-of-coolant accidents was identified in October 19, 1984 environmental qualification master list. January 28, 1985 Generic Letter 85-03 issued to all BWR licensees and applicants regarding clarification of equivalent control capacity for standby liquid control system. January 28, 1985 Letter from applicant forwarding revision to FSAR discus-sion of physical independence of electric system. Revi-sion will be included in future FSAR amendment and super-sedes November 9, 1984 submittal. Proposed criteria changes are conservative and are in compliance with Regu-latory Guide 1.75. January 28, 1985 Letter from applicant responding to SER Confirmatory Item 15 on containment repressurization. January 29, 1985 Generic Letter 85-04 issued to all power reactor 1icensees and applicants for operating licenses regarding operator licensing examinations. January 29, 1985 Letter to applicant requesting additional information re-garding Transamerica Delaval, Inc. diesel generators to continue review of application for operating license. _, 1 January 30, 1985 Letter to applicant forwarding Seismic Qualification Re- l view Team audit report regarding seismic and dynamic qualifications of safety-related equipment. January 30, 1985 Letter to applicant forwarding first draft of Technical Specifications. River Bend SSER 2 8 Appendix A
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- l hk-January 31, 1985 Letter from applicant forwarding final response to SER Confirmatory Item 18 regarding containment purge valves.
Response addresses Staff Position 6 on operation of dry-well purge system. I !' J"""a'# 31* 1985 Letter from applicant forwarding response to SER Open + Item 2 regarding moderate energy line crack. ij January 31, 1985 Letter from applicant forwarding change to FSAR Sec-H- tion test. 6.2.6.5.1 regarding upcoming drywell bypass leakage !! Change provides maximum allowable leakage rates and i_ revised is reduced minimum per listed duration bases. for tests. Minimum test duration January 31, 1985= Letter from applicant- forwarding response to SER Confirma-tory Item 20, " Penetration Valve Leakage Control System." l' 4, FSAR pages and tables are revised to justify exclusion of penetration valve leakage control system leakage from sum- ! nation of' local leak rate tests.
- January 31, 1985 a Letter from applicant forwarding response to SER Confirma-2
- tory Item 5 " Effects of Annulus Pressurization."
January 31, 1985 Letter from appifcant forwarding partial response to SER Outstanding Issue 3, " Analysis of High Energy Line Break l- in Secondary Containment for Equipment Qualification," providing details of subcompartmental analyses. February 1, 19P5. Letter from appifcant forwarding response to staff's 4 request of November 5,.1984 for additional information on initial test program. Response also addresses SER Con- .I. firmatory Item 61 regarding program revisions and Generic Letter 83-24. February 1, 1985 Letter from applicant forwarding response to SER Confirma-tory Item 19 on hydrogen control and 13 oversize drawings. Revised responses to request for additional information on hydrogen ignition system and FSAR Question 480.40 are also enclosed. t February 4, 1985 Letter to applicant forwarding notice of availability of Final Environmental Statement (NUREG-1073) for facility.
- t. February 5, 1985 Letter from appifcant forwarding revision to FSAR Sec-tion 6.2.6.5.1 on drywell bypass leakage test. Revision supersedes changes contained in January 31, 1985 letter.
i February 5, 1985 Letter from applicant providing revised response to SER ~ ' Confirmatory Item 30 of Table 1.4. Surveillance of engi- ' neered safety features unit coolers will be added to operations daily log. Operator will verify unit cooler { operating by ascertaining air flow through cooler. , 1 1 1
; River Bend SSER 2 9 Appendix A t
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-1 February 5, 1985 Letter from appifcant responding to request for additional information on Confirmatory Item 33 of Table 1.4 of SER, concerning standby liquid control system. Applicant will install additional annunciator (Valve C41-F031 not fully closed) for standby liquid control system test tank suc-tion valve.
February 5, 1985 Letter from applicant forwarding information requested by staff for review and input to SER Section 13.1 on emergency plan and procedures. I February 6, 1985 Letter from applicant forwarding Revision 4 to physical security plan and explanation of changes. 1 February 6, 1985 Letter to applicant forwarding draft supplement to SER in-1- put regarding seismic and dynamic qualification of seismic Category I mechanical and electrical equipment and pump and valve operability assurance program. ' Input incorporates results of October 29, 1984 site audit. February 6, 1985 Summary issued on November 28, 1984 meeting with applicant, Stone and Webster, and Wackenhut Advanced Technology Corp. ~i in Silver Spring, MD, regarding security information con- , cerning hardware installation. February 6, 1985 Letter from applicant forwarding revisions to FSAR estab-lishing qualified load for diesel generators, per Regula-tory Guides 1.9'and 1.103, and addressing high pressure core spray independence. February 8, 1985 Letter to applicant reviewing applicant's December 21, 1984 submittal regarding SER (NUREG-0989) Outstanding Issue 13 concerning safe / alternate shutdown. Facility is not in conformance with Positions C.5.b and C.5.c of SRP Section 9.5.1. February 8, 1985 Letter from applicant forwarding partial response to SER Outstanding Issue 3 regarding reactor water cleanup, con-tro1* rod drive, and main steam drain system. Final re-sponse to Confirmatory Issue 4 regarding FSAR Appendix 3C, Section 3C.2.10 is also enclosed. February 8, 1985 Summary issued on January 10, 1985 meeting with applicant in Bethesda, MD, regarding Technical Specifications. February 11, 1985 Letter to applicant forwarding request for additional information regarding Transamerica Delaval, Inc. emergency diesel generators, including information regarding defini- ~ tion of entire mass elastic system. February 11, 1985 Summary issued on January 11, 1985 meeting with applicant and Stone and Webster in Bethesda, MD, regarding small-break loss-of-coolant accident assumptions used in develop- ! ing pressure / temperature vs time history curves, cooldown rate, and mass and energy release rates. River Bend SSER 2 10 Appendix A l l l
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I - g i February 13, 1985
; Letter from applicant forwarding response to SER Confirma-4 tory Item 56, " Personnel Rdsunds."
February 15, 1985 Letter from applicant forwarding Revision 0 to "High Energy Line Break Evaluation Report (Effect on Nonsafety-Related Control Components)" in response to Request for Additional Information 421.004 and SER Confirmatory Item 41. February 15, 1985 Letter from applicant forwarding revision to FSAR Sec-tion 6.2.6.5.1 regarding drywell bypass leakage test.
> Revision supersedes changes contained in February 5, 1985 letter.
February 15, 1985 Letter from appitcant forwarding 20 oversize drawings re-quested by staff on automatic depressurization system. Draw-ings will close out SER Confirmatory Item 28, Table 1.4. February 15, 1985' Letter from applicant forwarding marked-up revision to initial startup test phase of FSAR Section 14.2, " Initial Test Program." Justification and summary explanation of revisions are also enclosed. February 15, 1985 Letter from applicant forwarding Revision 1 to environ-mental qualification document to assist staff reviewer in developing SER Section 3.11 and in addressing SER Open Item 5. Justification for interim operation for Class 1E electrical components in harsh environment is also enclosed. February 18, 1985 Letter from Transamerica Delaval, Inc. forwarding addi-tional information to the staff regarding torsional dynamic analysis of River Bend crankshaft, in response to verbal request. February 20, 1985 Letter from applicant forwarding Amendment 16 to FSAR. Amendment incorporates responses to SER outstanding and confirmatory items and provides other revisions caused by changes in design, construction startup, or operations. February 22, 1985 Letter from applicant requesting that response due date be extended to March 29, 1985 for Generic Letter 84-24
" Certification of Compliance to 10 CFR 50.49, Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants."
, February 22, 1985 Letter to applicant forwarding review of emergency classi-fication scheme contained in Section 13.3.3 of radiologi-cal emergency plan. Requests additional information on emergency action levels listed in Table 13.3-1, per _ NUREG-0654, within 30 days. February 25, 1985 Letter to applicant responding to October 16, 1984 letter transmitting Revision 3 to physical security plan and , Revision 1 to safeguards contingency plan. Information
- on upgrading or plan changes necessary to satisfy regula-tory requirements is enclosed.
River Bend SSER 2 11 Appendix A
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1, - j 1 'I j February 27, 1985 Letter to applicant forwarding request for additional j 4 information on TMI Action Plan Item II.K.3.28, "Qualifi-cation of Accumulators on Automatic Depressurization j System Valves." Response is requested within 45 days of ] letter date. February 28, 1985 Letter to applicant forwarding draft of " Review and Evalu-ation of TDI Diesel Engine Reliability and Operability - River Bend Station Unit 1," technical evaluation report. Report was discussed with contractors during February 18, 1985 site visit. March 1, 1985 Letter from applicant forwarding final response to Sec-tion 1.2 of Generic Letter 83-28, " Required Actions Based on Generic Implications of Salem ATWS Events." Response includes nuclear steam supply system and balance-of plant post-data recall variables for plant. March 1, 1985 Letter from applicant forwarding marked-up FSAR Sec-tion 13.2.2.3 revising licensed operator requalification
; training program, in response to staff request.
March 1, 1985 Letter from applicant responding to January 25, 1985 ques-tions and comments regarding pool dynamic loads for facil-ity. Revisions to FSAR supporting responses will be in-ciuded in future amendment to FSAR to close out SER Out-standing Issue 7.
~
March 5, 1985 Letter from applicant submitting revised response to Item 9 of SER Table 1.3, changing information provided in appli-cant's December 3, 1984 letter. Revised FSAR Table 1.5-12 on indication of bypass /inoperability due to auxiliary / support system is enclosed. March 5, 1985 Letter from applicant forwarding revised FSAR Section 9A.2.1 responding to concerns identified in staff's letter of February 8,1985. Section 9A.2 provides fire hazards analysis, including safe shutdown analysis. Submittal completes response to SER Outstanding Issue 13. March 7, 1985 Letter from applicant informing staff of review of shift staffing in light of operating experience on shift, in response to staff's December 13, 1984 letter to applicant. Current training and examination plans continue toward fully qualified six-shift rotati,on. March 12, 1985 Letter from applicant forwarding Revision 2 to construc-tion quality assurance (QA) program as submitted to staff -- on March 18, 1985. Program is current as of April 1, 1984. March 12, 1985 Letter from applicant forwarding justifications for interim operation of Class 1E electrical components located in harsh environments for which qualification is incomplete. i l River Bend SSER 2 12 Appendix A
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- q March 15,11985 Letter from applicant forwarding Revision 1 to " Environ-
;j mental Qualification Document," which addresses February 15, 1985 environmental qualification portion of SER Outstanding
~
=i. Item 5.
.p
]O March 15, 1985 Letter from applicant forwarding revised response to SER Open Item 2 regarding moderate energy line crack.
j March 15, 1985 Letter to appifcant forwarding second draft of Technical ,.j. Specifications for review. 9 March 15, 1985 Letter from applicant forwarding revisions to FSAR which C' reflect change in calculations for ultimate heat sink maximum temperature due to revisions in plant equipment
] operation.
- u. March 18, 1985 Letter from applicant forwarding proprietary Revision 4 of " Security Training and Qualification Plan," and supple-mental package to Revision 4 of " Physical Security Plan."
, March 18, 1985 Letter to applicant forwarding request for additional
- information on procedures generation package. Questions address technical guidelines portion of required proce-s ,
dures generation package and refer to January 15 and February 11, 1985 submittals. March 19, 1985 Letter to applicant forwarding request for additional , information on response to Generic Letter 83-28, Items 2.1, 2.2.1, 2.2.2, and 4.5.3.
; March 19, 1985 Letter to appifcant forwarding request for additional 4
information on alternate shutdown to complete review of operating license application. March 20, 1985 Letter from applicant forwarding final response to Sec-tions 3.1 and 3.2 of Generic Letter 83-28 " Required Actions Based on Generic Implications of Salem ATWS Events," regarding postmaintenance testing. March 25, 1985 Letter from applicant forwarding minor revisions to FSAR Section 6.2.6 on containment leak rate testing of electri-cal penetrations. Penetration design now incorporates double 0 rings to be Type B tested by pressurizing between seals. March 25, 1985 Letter from applicant informing staff that all procedures required to govern control of heavy loads lifted by reactor _ building's polar crane listed in Table 4 of March 1,1984 submittal will be completed before fuel load except for Load 5, "Portaole, Refueling Shield." March 25, 1985 Letter from applicant forwarding revised pages to January 31, , 1985 response to SER Dutstanding Issue 3, providing addi-
- tional details of subcompartment analyses of high energy line breaks necessary for independent verification analysis.
River 8end SSER 2 13 Appendix A
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1, I March 25, 1985
! Letter from appifcant forwarding proposed changes to I staff's second draft of Technical Specifications. Brief description of proposed change and justification for change and marked-up pages from second draft are enclosed. ! March 26, 1985 i Summary issued on March 20, 1985 meeting with applicant regarding activities authorized by CPPR-145, including
" fuel load checklist, construction schedule, preoperational test completion and status, and system turnover. March 26, 1985 _' Summary issued on March 8, 1985 meeting with appitcant and Stone and Webster regarding formal second draft of Tech-
- nical Specifications.
March 26, 1985 Letter from applicant forwarding Revision 13 to FSAR with additions regarding organization and training of optional shift technical advisor and review and audit section. March 28, 1985 Letter from applican* 'orwarding response to request for additional informatio.) egarding calibration, testing, and access / changing of setpufnts on digital radiation monitor-ing system. Submittal proviaes partial response to SER Confirmatory Item 40. March 28, 1985 Letter from applicant forwarding January 22, 1985 revision to FSAR Section 3.8.2.7 on initial structural acceptance test of containment vessel. March 29, 1985 Letter from applicant submitting Amendment 17 to FSAR for River Bend Station, in response to open and confirmatory items in SER (NUREG-0989) and requests for additional information. March 29, 1985 Letter from applicant forwarding partial response to Generic Letter 84-24, " Certification of Compliance to 10 CFR 50.49, Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants." Environmental qualification program satisfies requirements of 10 CFR 50.49. March 29, 1985 Letter from applicant forwarding justification for current emergency action levels listed in Table 13.3-1 of emer-gency plan, including one revision to Site Area Emergency Initiating Condition 7, per staff's February 22, 1985 request. April 1, 1985 Letter to applicant forwarding request for additional in-formation on open items associated with prior request for - information on initial plant test program, FSAR Amendments 14-16, and applicant's February 1, 1985 letter. April 1,1985 Letter to applicant discussing review of March 25, 1985 proposed changes to Technical Specifications. Proposed : changes refer to numerous FSAR amendments which have not been submitted to staff. River Bend SSER 2 14 Appendix A
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q= ; April 2, 1985 Letter from applicant forwarding response to request for ! additional information regarding optical isolator and MDR 4 auxiliary relay tests. Submittal provides final response h to SER Confirmatory Item 26. o i ~ -l April 4, 1985 Letter from applicant forwarding proprietary supplement 'y to Revision 4 to physical security plan. 1 April 8, 1985 Letter from applicant forwarding markedup FSAR Fig-l ure 13.1-5, representing shift complement and providing option to use separate shift technical advisor if no shift senior reactor operator is qualified. r April 9, 1985 Letter from appitcant forwarding information regarding TMI Action Plan Item II.K.3.28, " Verify Qualification of Accumulators on Automatic Depressurization System Valves," per staff's February 27, 1985 letter. April 9, 1985 Summary issued on March 14, 1985 meeting with applicant and Stone and Webster in Bethesda, MD, regarding electri-cal verification testing. April 9, 1985 Letter to applicant forwarding request for additional in-formation regarding diesel generator loading, per review
, of FSAR Amendment 16. NRC Project Manager should be noti-fled regarding response schedule.
April 12, 1985 Letter from applicant submitting Amendment 18 to the FSAR,
, responding to open and confirmatory SER (NUREG-0989) items.
April 12, 1985 Summary issued on April 4, 1985 meeting with applicant in Bethesda, MD, regarding review of Technical Specifications. Staff milestones for Technical Specification development and review are enclosed. April 12, 1985 Letter to applicant forwarding request for additional in-formation regarding shift advisor program, per utility's March 6 and August 13, 1984 submittals. Information re-garding training experience of each shift advisor requested. April 15, 1985 Letter to applicant requesting additional information regarding qualification program for safety-related mechan-feal equipment, including engineering drawings for listed items, per Section 3.11 of SER (NUREG-0989). April 16, 1985 Generic Letter 85-06 issued to all PWR licensees and all , applicants for operating licenses regarding quality assu-rance guidance for anticipated transient without scram j equipment not safety related. { ( April 17, 1985 Letter from applicant forwarding response to NRC's March 18, , 1985 request for additional information regarding emer-
- gency procedures generation package. Response to SER Con-firmatory Item 60 is complete.
- River Bend SSER 2 15 Appendix A I
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3 April 17,1985 i Letter from applicant forwarding revision to liquid rad-waste systems. I Clarification and information on contracted systems and revised FSAR text to be included in future y FSAR amendment enciesed. a April 19, 1985 Letter from applicant forwarding Revision 13 to automatic 9 T depressurization systems logic drawings, per TMI
~j Issue II.K.3.18. Final response to SER Confirmatory Item 28 is provided.
o
'l April 19, 1985 i
Letter from applicant forwarding information regarding ' > prompt notification system in response to July 20, 1981 request. System consists of 92 sirens. Eighty sirens in-stalled and tested to be functional as of March 28, 1985. Additional 12 strens will be installed and functionally tested. April 22, 1985 Letter from applicant forwarding additional information requested in response to Item 8 regarding Transamerica Delaval Inc. diesel generators at facility. Information revises April 11, 1985 response and completely addresses all items in request. April 22, 1985 Letter from applicant forwarding revised response to Items 8 and 16 of December 29, 1983 request for additional
'information regarding Transamerica Delaval Inc. diesel gen-
, erators. All items are addressed completely.
April 26, 1985 Letter from applicant forwarding qualification packages for safety-related mechanical equipment, per staff's April 15, 1985 letter. Complete qualification information provided for three items of equipment. April 30, 1985 Letter to applicant requesting additional information re-garding fire protection as part of revitw of application for operating license. April 30, 1985 Letter to applicant forwarding request for additional information regarding feedwater check valves as part of review of application for operating license. Open issue resolution is required before fuel load. April 30, 1985 ' Letter to applicant forwarding request for additional information regarding initial test program. Questions refer to justifications for items in FSAR Figure 14.2-5 regarding startup test program. May 1, 1985 Letter from applicant requesting approval to invoke ASME - Code Case N-413 for fillet and partial penetration welds for supports, including attachment welds to supporting structures. May 2, 1985 Generic Letter 85-07 issued to all operating reactor licen- : sees regarding implementation of integrated schedules for plant modifications. River Bend SSER 2 16 Appendix A
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- l May 2, 1985 l Letter to applicant forwarding final draft Technical Speci-iO fications for review. Certification requested that draft fy{ - reflects plant FSAR, NRC's SER, and as-built configuration of plant.
May 3, 1985 { Letter to applicant forwarding listing of unresolved, out- l l standing and confirmatory items for utility's low power license, per May 1, 1985 telephone conversation. [ May 3, 1985 Letter to applicant forwarding staff's request for addi-tional information regarding occupational exposure and pro-tective measures associated with long-term automatic de-1 pressurization system's pneumatic supply makeup connection. 1
' May 3, 1985 Letter from applicant forwarding utility total inspection report and TDI Ownert, Group modification report for TOI standby diesel generators,-for review.
May 6, 1985 Letter from applicant responding to May 2, 1985 request to review proposed final draft Technical Specifications.
-! Editorial and technical changes are enclosed. Conditional j certification given subject to resolution of identified items and NRC's review comments.
May 6, 1985 Summary issued of March 26, 1985 management review meeting in Bethesda, ating license. MD, regarding utility's application for oper-May 7, 1985 Letter to applicant forwarding request for additional information regarding equipment qualification, contained I in enclosed Brookhaven National Laboratory's letter of
, April 25, 1985. Meeting scheduled for May 10, 1985 to review responses. Equipment qualification program must be resolved before fuel load.
May 8, 1985 Letter to applicant requesting additional information per L s review of application for operating license. Information l is needed regarding operability of 24-inch drywell purge and vent valves and 6-inch hydrogen mixing valves. i- May 9, 1985 Letter from applicant forwarding proprietary report, " Test Report on Electrical Separation Verification Testing...." and FSAR revision. Hazards for electrical raceways are listed. May 10, 1985 Letter from applicant forwarding Amendment 19 to FSAR for
' River Bend Station. Amendment provides response to various-open and confirmatory items of SER (NUREG-0989). -
May 10, 1985 t Letter from applicant forwarding proprietary reports, "RM-80
' Microprocessor Performance Specifications" and "RM-23 Hardware...," and 19 oversize drawings, in response to re-quest for additional information. Closes out SER Confirm-
~
atory Item 40. River Bend SSER 2 17 Appendix A
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i i l May 10, 1985 i Summary issued of April 11, 1985 meeting with utility and i Stone & Webster in Bethesda, MD, to review issues asso-ciated with containment as result of Technical Specifica-tion review. May 10, 1985 Letter to applicant forwarding request for additional in-formation regarding TMI Action Item 1.C.1 concerning emer-
! gency operating procedures, per review of application for operating license.
May 10, 1985 Letter from applicant forwarding listed peuprietary docu-ments, in response to NRC request for additional informa-tion. . Submittal provides partial closecut of Confirmatory Item 40 of Table 1.4 of SER. May 10, 1985 Letter from applicant forwarding supplemental information l for high energy line break evaluation report, addressing reduction in feedwater temperature event. Information completes utility's response to SER (NUREG-0989) Confirma-tory Item 41. May 13, 1985 Letter from applicant forwarding Revision 2 to Procsdure COP-1050, " Post-Accident Estimation of Fuel Core Damage," completing utility's. response to Criterion 2 of SER Confir-matory Item 50 regarding NUREG-0737, Item II.B.3. May 13, 1985 Letter from applicant forwarding revised environmental i qualification justification for interim operation pre-viously submitted on February 15, 1985. Revision provides new completion date of November 30, 1985 for SRN 228214-2,
" Motor-Operated Valves With Limitorque Type SMC Operators."
May 13, 1985 Letter from applicant responding to May 3, 1985 letter re-garding occupational exposure and protective measures asso-ciated with long-term automatic depressurization system's pneumatic supply makeup connection. No connections were made in post-LOCA environment and no personnel exposure was noted. May 13, 1985 Letter from applicant forwarding ar. visions to FSAR which supplement December 3, 1984 report regarding IE Bulle-tin 79-27, " Loss of Non-Class 1E Instrumentation and Con-i trol Power System During Operation." Enclosure completes L , response to Confirmatory Item 31 of Table 1.4 of SER i
,} (NUREG-0989).
May 13, 1985 Letter from applicant forwarding FSAR revisions which sup- _ plement previous response to SER (NUREG-0989) Confirmatory Issue 1. Revisions indicate intent to maintain crossing I of West Creek upstream of lined portion and to verify that temporary construction crossing has been removed. River Bend SSER 2 18 Appendix A
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1 l May 13, 1985 Letter from applicant forwarding supplemental information regarding TMI Action Item II.K.3.28, " Verify Qualification of Accumulators on Automatic Depressurization System Valves." Information will be included in a future FSAR amendment. i May 14, 1985 Letter from applicant responding to concerns identified in staff's April 9, 1985 letter. Standby water service sys-tems valves will be tested in accordance with Section XI of ASME Boiler and Pressure Vessel Code.
; May 14, 1985 Letter from applicant forwarding "DCRDR Summary Report J Supplement," per April 12, 1985 request for additional ! information.
i May 15, 1985 Letter from applicant forwarding draft Revision 3 to
" River Bend Station, Unit 1 Preservice Inspection Plan,"
including Volume 4 set of weld maps to provide cross-reference to appendix of plan. May 15, 1985 Letter from applicant responding to staff's August 30, 1984 request for additional information regarding safety parameter display system (SPDS). SPDS hardware is installed. SPDS is scheduled to be fully functional by February 1986. May 15, 1985 Letter from applicant requesting exemption from air lock testing requirements, per 10 CFR 50, Appendix J. Exemp-tion in public interest does not endanger life or property and is authorized by law. May 15, 1985 Letter from applicant forwarding response to November 9, 1984 request for additional information regarding TMI Action Plan Item II.D.1 concerning performance testing of BWR relief and safety valves. Justification is provided regarding applicability of BWR Owners Group test results to facility design. May 15, 1985 Letter from applicant forwarding response to NRC request for additional information to clarify utility's April 17, 1985, submittal regarding facility emergency operating procedure deviations from BWR Owners Group emergency pro-cedure guidelines, completing Confirmatory Item 60. May 15, 1985 Letter from applicant forwarding additional information requested in staff's April 30, 1985 letter to applicant regarding revisions to FSAR subsections. Revised FSAR _ pages supporting revisions are enclosed. Revisions will be included in a future FSAR amendment. River Bend SSER 2 19 Appendix A
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,' May 15, 1985 Letter from applicant supplementing March 29, 1985 letter with enclosed information, addressing Seismic Qualification q Review Team (SQRT) and pump and valve operability review team (PVORT) specific comments on SSER, discussed during
] May 10, 1985 meeting with staff. Proposed program is to be .] provided by May 24, 1985.
i May 15, 1985 Letter from applicant forwarding updated seismic and pump l and valve qualification program master list and status of qualification for seismic Category I equipment required by fuel load. May 16, 1985 Letter from applicant responding to NRC concerns and SER l Outstanding Issue 4 regarding status of inservice test
-i program submitted on November 5, 1984 and supplemented on d January 21, 1985. Inspection of piping welds is submitted 3 as preservice inspection program.
May 17, 1985 Letter from applicant forwarding revisions to FSAR Sec-tion 9A.2, providing additional clarification regarding safe shutdown method logy to be used in specific fire areas and supplementing previous responses to SER Out-standing Issue 13. May 17, 1985 Letter from applicant forwarding supplemental response to NRC's position regarding facility drywell/ containment purge systems identified in SER (NUREG-0989) Section 6.2.4.3 as Confirmatory Issue 18. Utility will minimize use of con-tainment purge systems. May 17, 1985 Letter from applicant forwarding revised program plan for Transamerica Delaval Inc. standby diesel generators. Post-test inspection will be completed during May 1985. May 17, 1985 Summary issued of May 10, 1985 meeting with utility in Bethesda, MD, to resolve remaining open items and issues from staff's Seismic Qualification Review Team (SQRT)/ Pressure Vessel Operations Review Team (PVORT) sudit. May 17, 1985 Summary issued of May 10, 1985 meeting with utility, Brookhaven National Laboratory, and Stone & Webster in Bethesda, MD, regarding resolution of remaining open items and issues resulting from NRC SQRT/PVORT audit. May 20, 1985 Letter from applicant forwarding additional information regarding Generic Letter 83-28 concerning Salem antici-pated transient without scram events, per March 19, 1985 request. -- l May 20, 1985 Letter from applicant advising that utility will monitor temperature of ultimate heat sink basin per Surveillance Requirement 4.7.1.2.b submitted on May 6, 1985. Tempera-ture monitoring system will be installed before startup : following first refueling outage. River Bend SSER 2 20 Aopendix A
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j i May 20, 1985 Letter from applicant forwarding initial response to l staff's April 30, 1985 Request for Additional Information
~i, 210.110. Information regarding original calculation for
' performance of feedwater check valves is enclosed. Confirm-atory analysis will be submitted before exceeding 5% full power.
May 20, 1985 Letter from applicant forwarding schedule for submittal of information for open/ confirmatory items awaiting informa-tion in response to staff's Hay 3, 1985 request for addi-tional information. May 22, 1985 Letter from applicant forwarding changes to FSAR identi-i fled during utility review of Technical Specifications. Changes ensure consistency between Technical Specifications and FSAR. May 23, 1985 Generic Letter 85-08 issued to all holders of construction permits and operating licenses regarding 10 CFR 20.408 termination reports and formats. May 24, 1985 Letter from applicant submitting procedures, per May 10, 1985 request, for sample review of seismic qualification documentation to show successful implementation of seismic Category I equipment before proceeding above 5% power. May 28, 1985 Letter from applicant advising that notification will be submitted within 30 days of plans for any new oil or gas wells or pipelines within 2-mile radius of reactor center-line, per NUREG-0989, Section 2.2.2. May 28, 1985 Letter from applicant advising that utility will provide inspection and maintenance of manmade portion of facility during operation, per NUREG-0989. Commitment will be included in a future amendment to FSAR Section 2.4.3.5.2. May 28, 1985 Letter from applicant supplementing April 11, 1985 letter regarding shift advisors. May 30, 1985 Letter from applicant forwarding Revisien 1 to " Pump and Valve Inservice Testing Plan, River Bend Station, First 10-Year Inspection Interval" as supplement to November 5, 1984 submittal. Plan contains editorial revisions and ; Relief Request 11 for Appendix C, " Valves." ' June 3, 1985 Letter from applicant forwarding supplemental information l regarding clarification to Section 6A.10 on methodology ' used to calculate bulk suppression pool swell impact loads ~l for structures less than 6 feet above suppression pool to J close out SER Outstanding Issue 7. ' River Bend SSER 2 21 Appendix A 1 1
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I June 4, 1985 Letter from applicant forwarding scope of preliminary analysis for hydrogen control supporting installation of { hydrogen igniter system. Analysis provides satisfactory i basis for NRC determination to support interim full power i operation until final analysis completed. j June 4, 1985 Letter to applicant forwarding draft operating license for facility, for information and comment. Since NRC is '; still reviewing numerous outstanding SER issues, condi-tions on license are not definite at present. June 5, 1985 t Letter from applicant forwarding responses to staff's re-1 quest for additional information regarding Open Item 16 to Table 1.3 of SER concerning diesel generator (DG) training and high pressure core spray DG temperature. Enclosed changes to FSAR text will be incorporated in a future
', amendment.
June 5, 1985 Letter from applicant forwarding revised FSAR proprietary Figures 4.3-3, 4.3-4, 4.3-9, 4.3-10, 4.3-11, and 4.3-12, regarding selection of General Electric Co.'s control cell core fuel design. Nonproprietary FSAR Figure 15.0-4 is also enclosed. June 7, 1985 Letter to applicant forwarding request for additional in-formation regarding emergency, operating procedures (Con-firmatory Item 60) per operating license review. , June 10, 1985 Letter from applicant forwarding updated Revision 1 to
" Nuclear Plant Engineering Preservice Inspection / Pump and Valve Testing Plan." Update reflects May 31, and June 5, 1985 discussions on relief requests requiring clarification and/or changes.
June 10, 1985 Letter from applicant providing list of justifications for interim operation being withdrawn because of completed status of environmental qualification, as update to March 12, 1985 submittal. June 10, 1985 Letter to applicant forwarding request for additional in-formation regarding offsite dose calculation manual, per operating license review. June 13, 1985 Letter from applicant discussing current projection of status of plant completion at fuel load, per utility's January 14, 1985 draf t listing of items that" would not be completed and March 26, 1985 meeting with NRC. Completion of corrective actions on 10 CFR 50.55(e) is addressed to - Region IV. June 13, 1985 Letter to applicant requesting information for review of May 15, 1985 submittals regarding seismic equipment quali-fication and pump and valve operability. : River Bend SSER 2 22 Appendix A i
4 'l . .i June 13, 1985 Letter to applicant requesting additional information i i regarding Part 21 reports issued by Transamerica Delaval Inc. since April 1984 regarding problems with emergency diesel generators. Information is to be used in prepara-i tion of SER to close out Transamerica Delaval Inc. engine reliability issues. June 19, 1985 Letter from applicant providing clarifying statement on May 22, 1985 FSAR changes regarding five fuel bundle type design (control cell core loading). Results presented in GESSAR II are applicable to control cell core loading used in facility. June 20, 1985 Letter from applicant responding to request for additional information, supplementing utility's April 2, 1985 letter regarding discussions on MOR relays and optical isolation devices. Letter provides final response to Confirmatory Item 26 of Table 1.4 of SER. l
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River Bend SSER 2 23 Appendix A i
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, l , 1 J -1 APPENDIX D ACRONYMS AND INITIALISMS ACRS Advisory Committee on Reactor Safeguards ADS automatic depressurization system AISC American Institute of Steel Construction ANS American Nuclear Society ANSI American National Standards Institute AP annulus pressurization APRM average power range monitor ASME American Society of Mechanical Engineers ATWS anticipated transients without scram BNL Brookhaven National Laboratory BOP balance of plant BTP Branch Technical Position CAT Construction Appraisal Team CEPCO Cajun Electric Power Cooperative CFR Code of Federal Regulations C0 condensation oscillation CP construction permit CRT cathode-ray tube CRVICS containment and reactor vessel isolation control system DAS data acquisition system DBA design-basis accident DCRDR detailed control room design review DEMA Diesel Engine Manufacturers Association DFM data formatter module DRMS digital radiation monitoring system ECCS emergency core cooling system EMI electromagnetic interference EOC-RPT end-of-cycle recirculation pump trip EPA electrical protection assembly EPG Emergency Procedures Guidelines EQD Equipment Qualification Document ERIS emergency response and information system ESF engineered safety features FDA final design approval 1
FDI Field Disposition Instruction FSAR Final Safety Analysis Report GDC General Design Criteri(on)(a) GE- General Electric Co. GSU Gulf States Utilities Co. River Bend SSER 2 1 Appendix D
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i HCOG Hydrogen Control Owners Group HCU hydraulic control unit HED human engineering discrepancy HPCS high pressure core spray j HVAC heating, ventilation, and air conditioning i
, IE Office of Inspection and Enforcement IEEE Institute of Electrical and Electronics Engineers INEL Idaho National Engineering Laboratories IPCEA Insulated Power Cables Engineers Association ISEG Independent Safety and Engineering Group
.- l IST inservice testing LLNL Lawrence Livermore National Laboratory LOCA loss-of-coolant accident LOOP loss of offsite power LPCI low pressure coolant injection LPCS low pressure core spray LPRM low power range monitor MCC motor control center MCPR minimum critical power ratio MG motor gen'erator MOV motor-operated valve MPC maximum permissible concentration MSPLCS main steamline penetration leakage control system NEMA National Electrical Manufacturers Association NMS neutron monitoring system NPS nominal pipe size NRB Nuclear Review Board NRC U.S. Nuclear Regulatory Commission NSSS nuclear steam supply system OBE operating basis earthquake ODAS Online Dose Assessment System OL operating license PASS postaccident sampling system PCP process control program PDA preliminary design approval PGCC power generation control complex PGP Procedures Generation Package P&ID piping and instrumentation diagram PSTF pressure suppression test facility PVLCS penetration valve leakage control system
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PVORT pump and valve operability review team QA quality assurance l RBNG River Bend Nuclear Group 1 RBS River Bend Station ,1 1 River Bend SSER 2 2 Appendix D
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I. l RCIC . reactor core isolation cooling j RCIS rod control and isolation system i RCS reactor coolant system i RFI radiofrequency interference RG regulatory guide RHR residual heat removal
- RIM remote input module RO reactor operator
, RPS reactor protection system RPT recirculation pump trip RPV reactor pressure vessel RRS reactor recirculation system SER Safety Evaluation Report SGTS standby gas treatment system SLCS standby liquid control system SPDS safety parameter display system SQRT Seismic Qualification Review Team SRO Senior Reactor Operator SRP Standard Review Plan SRV safety / relief valve SSE safe shutdown earthquake SSER Supplement to Safety Evaluation Report SSWT standby service water tower STA Shift Technical Advisor TAF top of the active fuel TCV turbine control valve TDI Transamerica DeLaval Inc.
TER technical evaluation report TMI Three Mile Island Nuclear Station TS Technical Specification (s) TSV turbine stop valve V&V verification and validation l l I l l l I t i r l l River Bend SSER 2 3 Appendix D i 1 l I
s - __-.._mo__.-~ --iu - -- - 1 ] -! l I l- l l .d APPENDIX E 'I PRINCIPAL STAFF CONTRIBUTORS AND CONSULTANTS I ,j NRC STAFF MEMBERS i Name Title Review Branch / Region Goutam Bagchi Section Leader Equipment Qualification James Bongarra Gr- y ;C M u a nn:yPshhologist Procedures and System Review [ Walter Brooks Reactor Physicist Core Performance Farouk Eltawila Senior Containment Containment Systems Systems Engineer Robert Fell Nuclear Engineer Meteorology and Effluent Treatment Martin Hum Senior Materials Engineer Materials Engineering John Jaudon Section Chief Region IV Richard Kendall Reactor Engineer Instrumentation and Control Systems William Kennedy Safety Engineer Procedures and System Review Robert Kirkwood Principal Mechanical Mechanical Engineering Engineer James Lazevnick Electrical Engineer Power Systems John Minns Health Physicist Radiological Assessment Al Notafrancesco Containment Systems Containment Systems Engineer Donald Perrotti Emergency Procedures Emergency Preparedness Specialist John Ridgely Mechanical Engineer Auxiliary Systems Owen Rothberg Structural Engineer Structural and Geotechnical Engineering ,- Michael Shopman Management System Licensee Qualification Engineer River Bend SSER 2 1 Appendix E
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i -. Name Title Review Branch i j Robert Skelton Plant Protection Analyst
- Power Reactor Safeguards Licensing David Terao Mechanical Engineer Mechanical Engineering e\
George Thomas Nuclear Engineer Reactor Systems Ed Tomlinson Mechanical Engineer Power Systems Al Ungaro Section Leader Power Systems Rex Wescott Hydraulic Engineer Environmental and Hydraulic Engineering V 7 Robert Wright -
- Paul Wu Chemical Engineer Chemical Engineering Shih-Liang Wu Reactor Fuels Engineer Core Performance 4
River Bend SSER 2 2 Appendix E i k I _ __ _ _ _ L
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1 1 APPENDIX G 1
.: ERRATA t
I .$ $i River Bend Station SER ll .. ' j Pm -Line/ Item Change -h 2-37 8 Change "0.06" to "0.05" m ? , 3-44 -10 Change " audible" to "auditable" L 6-19 22 Change "0.5" to "1.0" 6-21 24 Change "200*" to "2000"
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,i : 6-23
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19 Change " local and control room readout" to
" security area readouts" i.< 6-31 29 & 32 Change "14" to "12" ll 6-48 29 & 42 Change "2" to "4" 7-33 37- Change "II.K.3.13" to "II.K.1.22" 7-50 21 Change "30%" to "40%"
8-9 43 Add " incoming" between "The" and " circuit" 43 Change "to" to "from" 44 Add "to Panel 1E22*S001" between " charger" and "is" i' 8-13 38 Change "FSAR Figure 8.3-13a" to "the applicant's letter of December 30, 1983" 9-24 2 Change "of" to "above" 3 Delete "to 100*F" 4 Change "between 75* and 85*F" to "above 75*F" l 9-44 5 Delete "and hydropneumatic tank"
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9-47 17 Change " Floor drains" to " Curbs" 10-8 9 Change "25%" to "10%" t i River Bend SSER 2 1 Appendix G l r L
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! 10 39 Delete " filter"
- 40 Delete " filter" and " cleanup" 42 Delete " filter" 45 Add " quality" between " condensate" and "during"
.i 45 Change " filters" to " deep-bed demineralizers" Q .
45 Change " polish" to " treat"
', 13-6 16 Change "12" to "7" l 13-12 42 Move entire line, from "FSAR" through "its" to a position between lines 38 and 39 13-27 2 Add " safety-related" between "all" and " activities" i
River Bend Station SER, Supplement 1 4-2 14 Change "1984" to "1983" App. G, 1 18 Change "20000" to "2000" App. G, 1 20 Change "9-30" to "9-36" r River Bend SSER 2 2 Appendix G
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APPENDIX H DEMONSTRATION OF CONTAINMENT PURGE AND VENT VALVE OPERABILITY River Bend SSER 2 Appendix H N
a . . ~.' '; .' ...-- _ a.... i l RIVER BEND STATION - UNIT 1 1 s DOCKET NO. 50-458 l 1 DEMONSTRATION OF CONTAINMENT PURGE AND VENT VALVE OPERABILITY 1.0 Requirement Demonstration of operability of the containment purge and vent valves, par-ticularly the ability of these valves to close during a design-basis accident, is necessary to ensure containment isolation. This demonstration of operabil-
' ity is required by Branch Technical Position (BTP) CSB 6-4 and SRP Section 3.10 for containment purge and vent valves which are not sealed closed during oper-ating conditions 1, 2, 3, and 4.
2.0 Description of Purge and Vent Valves The applicant has submitted operability demonstration information only for the 36-inch containment purge and vent valves listed below. Operability demonstra-tion information was not received for the other valves considered part of the purge and vent system at River Bend Station Unit 1. Valve size Valve number (inches) Use Location 1HVR A0V123 36 Containment purge supply Inside containment 1HVR A0V128 36 Containment purge exhaust Inside containment 1HVR A0V165 36 Containment purge supply Outside containment
, 1HVR A0V166 36 Containment purge exhaust Outside containment The 36-inch containment purge and vent valves are butterfly-type valves manu-factured by Posi-Seal International Inc. (PSI) furnished with MATRYX 45122-SR80 air open-spring close actuators for valves A0V 165 and 166, and MATRYX 33122-SR80 air open-spring close actuators for valves A0V 123 and 128.
The applicant, based on the LOCA/ seismic analysis performed by PSI, intends to limit the valve openings-to 65* (90 = full open) and is changing the bolting material on valve number 1HVR A0V123 to SA 354 GR BD. 3.0 Demonstration of Operability 3.1 The review of the purge and vent valve operability demonstration for the 36-inch purge and vent valves at River Bend Station Unit 1 is based on the following submittals from the applicant: . Reference A November 8, 1984, letter, from J. E. Booker (GSU) to H. R. Denton (NRC). Included with the letter were the following:
- 1. Attachment 1 containing responses by GSU to earlier NRC staff positions.
- 2. Attachment 2 containing proposed FSAR revisions. ,
River Bend SSER 2 1 Appendix H
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- 3. Attachment 3, supplemental technical justification contain-ing an estimate of required torque for closure of PSI actuators.
- 4. Attachment 4, LOCA and seismic analysis l-
- 5. Appendix A, piping system schematics.
l 6. Appendix B, determination of flow conditions.
- 7. Appendix C, determination of closing times.
- 8. Appendix D, comparison of actual to calculated closing times.
- 9. Appendix E, seismic and LOCA stress analysis.
- 10. Enclosure 3, derivation of hydrodynamic torque curves.
Reference B Telephone conversations on December 18 and 26, 1984, between GSU and Brookhaven National Laboratory (BNL). 3.2 The applicant has not provided operability demonstration information for the 24-inch drywell purge and vent valves or the 6-inch valves in the hydrogen mixing system. 3.3 Reference A-10 describes model testing performed by PSI on valve sizes from 1 -inch through 14-inch for both preferred and nonpreferred fluid flow to obtain hydrodynamic torque factors that are used in calculating dynamic torques for all sizes and classes of trunnion valves. On the basis of the flow testing per-formed at PSI, the following general observations concerning hydrodynamic torque of trunnion valves can be made: (1) For preferred flow, the hydrodynamic torque will always act to close the valve. (2) For non preferred flow, the hydrodynamic torque will, through 70* to 80* of valve rotation (the exact location varies with valve class), act to close the valve. At angles less than 70*, the Hydrodynamic Torque will act to open the valve. (3) Except for the 90* valve opening where the hydrodynamic torque factors are of equal magnitude for both preferred and non preferred flow, but of oppo-site sign, the non preferred hydrodynamic torque factors are considerably less in magnitude than those for preferred flow. In Reference A-4 aerodynamic torque equations are derived for steam and water using the data from the hydrodynamic model testing program. Peak containment pressure during the postulated LOCA of 9 psig is assumed across the 36-inch valves for conservatism since the larger the pressure drop, the larger the aerodynamic torques acting on the valve. Actually, with valve closure
, within 3 seconds, the maximum differential pressure will be less than 3 psig based on the LOCA containment pressure response curves. Single valve closure is assumed for conservatism since simultaneous valve closure would reduce the flow and aerodynamic torque.
3.4 The stress analysis for valve critical parts is shown in Reference A-9 entitled, " Seismic and LOCA Stress Analysis." On the basis of the results of the analysis, PSI recommends that the amount of valve opening for all the sub- , ject valves be restricted to 65*. This can be accomplished by bolting a stop -- to the internals of the MATRYX piston cartridge which would limit the stroke of the actuator. River Bend SSER 2 2 Appendix H
_ - . . - .._ 2 a _ . m. . . A To ensure that the valve bolts are not overstressed during a combined LOCA and seismic event, it is recommended that the bolt material for valve A0V123 be changed to SA 354 GR BD. The staff concludes that if the amount of valve opening is restricted to a maxi-mum of 65* and the change in bolt material is made as discussed above, the subject valves will operate properly within the required time during a combined LOCA and seismic event. 3.5 Reference A-7 entitled, " Determination of Closing Times," presents a tabu-lation of available spring torques and dynamic torques at increments of valve closure angle for steam and air from the 65* blocked angle to closure. While the flow torque exceeds the spring torque at the larger angles above 50*, clo-sure is ensured for both the preferred and non preferred orientation since the flow torque below 65* in both cases tends to close the valve. 3.6 The seismic qualification analyses and test data are referenced in the November 8,1984, letter as being contained in the following reports: (1) Posi-Seal Seismic Report (SWEC File No. 4228.241-092-004) (2) Posi-Seal Static Operability Qualification Report No. 108375T-001 (SWEC File No. 4228.241-092-011) 4.0 Evaluation 4.1 PSI's approach to dynamic torque predictions for the 36-inch purge and vent valves A0V123, 128, 165, and 166 is based on torque factors derived from hydrodynamic model tests coupled with torque equations (Reference A-4) that determine the aerodynamic torques under LOCA conditions. Table 1, taken from Reference A-4, summarizes the maximum torques resulting from a LOCA for the 36-inch valves for closure from 90* and 65*. The torque predictions developed by PSI are acceptable for the 65* opening angle limitation considering the conservative assumptions used in the PSI approach. l single valve closure redundant valve in line remains open l - peak containment pressure of 9 psig technical specification closure time of 3 seconds, with calculated LOCA , closing times under 0.5 second. From the containment pressure response i curves the differential pressure at 3 seconds after LOCA indication is under 3 psig PSI has also doubled the calculated torque to account for a 79* elbow upstream of A0V123. 4.2 The maximum allowable torque for the MATRYX 33122-SR80 actuator of l 66,800 in.-lbs compared to the maximum dynamic valve torque developed during a LOCA for the 65* limitation is 47,920 in.-lbs demonstrating that the structural capability of the actuator is not exceeded. Similarly, the MATRYX 45122-SR80 i actuator with a maximum allowable torque of 174,000 in.-lbs working against a 5 maximum dynamic torque of 54,360 in.-lbs provides an adequate structural .; margin. l River Bend SSER 2 3 Appendix H
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". Table 1 Maximum torques resulting from a LOCA and closing time rw A0V165
, Tag No. A0V123 A0V128 A0V166 s
M Valve size 36 inches 36 inches 36 inches
, MATRYX actuator model 33122-SR80 33122-SR80 45122-SR80 1
2 I Maximum torque resulting from a LOCA (in.-lbs)
- Valve opened to 90* 74,830 104,160 119,600
- Valve opened to 65* 47,920 19,600 54,360
( Actuator maximum allowable i torque (in.-lbs) 66,800 66,800 174,000
; Closing Times (sec.)*
- No flow 0.60 0.60 0.70
- Valve opened to 90* Will not close Will not close 0.34
- Valve opened to 65* 0.24 0.30 0.38
' 1. - Required closing time 3 3 3
- Calculated values. As shown in Appendix E (Ref. A-9), the actual closing times for the valves with a MATRYX 45122-SR80 actuator were slightly greater than that calculated.
With the 65* angle limitation for the 36-inch valves, the dynamic torques under LOCA conditic.s act to close the valve thereby assuring closure. 4.3 PSI's stress analysis results for the 36-inch valve critical parts are shown in Table 2 taken from Reference A-4. These demonstrate that for a 65* opening angle limitation, the stress allowables are not exceeded provided that the SA 354 GR BD bolt material is used as a replacement for the existing bolt material being used on valve number A0V123. 4.4 Seismic qualification of the 36-inch purge and vent valves at River Bend Nuclear Station Unit 1 is addressed in the qualification reports referenced in Section 3.6. 4.5 Operability demonstration for the 24-inch drywell purge and vent valves and the 6-inch hydrogen mixing valves has not been submitted by GSU, therefore, i the staff cannot evaluate the ability of these valves to close against the buildup of containment pressure in the event of a DBA/LOCA. 5.0 Summary r.- _ L. The staff has completed its review of the information submitted to date concern-ing operability of the 36-inch valves used in the containment purge and vent
- ' system at River Bend Nuclear Station Unit 1. The staff finds that the informa-tion submitted has demonstrated the ability of these valves to close against the containment pressure of up to 9 psi in the event of a DBA/LOCA, provided that t mechanical stops are installed to limit the valve opening to 65* (90* = full
River Bend SSER 2 4 Appendix H
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1 j Table 2 LOCA and seismic stresses
'i-
" Valve. Actuator bolt Bracket bolt Bracket opening j Valve No. (*) Calc. Allow Calc. Allow Calc. Allow A0V123 65 38650 45000* 30356 37500 5740 20550 A0V128 65 32617 37500 34767 37500 4297 20550 A0V165, 166 90 17505 37500 40764 37500 7918 20550 A0V165, 166 65 13738 37500 34693 37500 6428 20550
, Valve neck Valve neck Disc pin Calc. Allow Calc. Allow Calc. Allow A0V123 65 1706 26350 12719 54300 11906 32580 A0V128 65 1632 26250 5838 54300 4870 32580 A0V165, 166 90 2806 26250 30250 54300 37147 32580 A0V165, 166 65 2289 26250 14292 54300 16883 32580 l- *This allowable is based on a bolt material of SA 354 GR BD which is a different bolt material than that provided for A0V123.
Note: The allowable stresses are based on 1.5 times the allowables given in Section III of the ASME Boiler and Pressure Vessel Code. open) and the A0V123 valve bolts are replaced using the SA 354 GR BD material proposed in the submittal. Sections 4.1, 4.2, 4.3, and 4.4 of this evaluation are the basis for this conclusion. The applicant has indicated in Reference B that the operability demonstration in-formation will not be provided at the present time for the 24-inch drywell purge and vent valves or the 6-inch hydrogen mixing valves. Therefore, the 24-inch drywell valves are to be sealed closed as defined in SRP Section 6.2.4.II.6.f during modes other than cold shutdown er refueling. Furthermore, these valves are to be verified closed at least once every 31 days. Resvrictions on opera-tion of the 6-inch valves are discussed in SER Section 6.2.4. 4 i. t i River Bend SSER 2 5 Appendix H
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. +3 handled. Deviations from defined load paths should require written alternative procedures approved by the plant safety review committee."
A. Summary of Applicant's Statements With regard to the thirteen handling systems identified in Table 2.1 above, there are many different load handling situations encountered. Defining safe load paths in the manner described in NUREG 0612, Section 5.f.1(1), is neither t required nor prudent for every situation. To do so would unnecessarily restrict plant operations and maintenance activities. To address this problem, the possible load handling situations that could be encountered have been identified. Each load handling situation has been assigned a " safety class" designation, roughly in order of safety
~
significance. Safe load path and load handling procedural requirements have been defined for each safety class. There are 4 safety classes with class No. 3 subdivided into 3A and 38. Supplementing the safety class designations the loacs of pr'incipal concern, that are assigned to safety class 1, 2, or 38, are summarized. The summaries on these designators generally call for procedural testrictions and precautions for the operator to limit carrying height of the loads and ; travel time over areas of risk. Five heavy loads handled by the Polar Crane have very direct travel paths to their storage locations; accordingly detailed travel paths are not required. These loads and their class are: o RPV Head Class 1 and 3B o Steam Dryer Class 1, 2, and 3B o Shroud Head / Steam Separator Class 1 and 3B o Dry well Head Class 1 and 3B i o Portable Refueling Shield Class 2 and 3B ' River Bend SSER 2 9 Appendix I
x.. . : . .- .
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i In addition to the procedure including steps that minimize load l height of travel, eleven of the Polar Crane heavy loads are
. guided by match marks permanently affixed to the crane ratis, l 4 .; trolley, and end trucks to assure proper alignment of the crane u
during the lifts. Use of the match marks will assure that the most direct and unobstructed path is taken to and from the I storage location. i The one remaining heavy load handled by the Polar Crane j involves a refueling sequence which introduces barriers to the
,;i risk of a dropped load that can damage the reactor, fuel storage, or safe shutdown capability.
Procedures must be followed for all of the loads handled by the other hoisting systems listed in Table 2.1, in addition, consistency with the intent of Guideline 1 is shown by one or more of the following: (1) Fuel Bridge Crane, Mechanical Stops (2) Spent Fuel Cask Trolley, Mechanical Stops and structural analysis (3) Auxiliary Building Tunnel Plug Monorail, a structural analysis and load carring height restrictions (4) MSIV and feedwater Isolation Valve Monorail (4 loads) controlled use restricted to operating modes 4 and 5. (5) The remaining hoist systems are monorails whose load drop areas have been evaluated and structural analyses made to tiemenstrate compliance with NUREG 0612. To assure that load handling operations remain in safe load paths enforcement procedures call for each heavy lift to be f supervised by a designated individual who will be responsible
~
River Bend SSER 2 10 Appendix I [ t I
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j for enforcing the procedural requirement. Any deviation from these requirements will require the prior approval of the Operations Supervisor. B. EG&G Evaluation 5 f The GSU safety class designators may be an aid in helping them , meet the guidelines of NUREG 0612 Article 5.1. The several submittals now indicate 18 loads where safe load path i} designation / restrictions are necessary, and 29 additional loads to consider. The data summary indicates: 16 loads controlled by crane match marks and/or mechanical stops, an approach consistent with the NRC " Synopsis of Issues;" I load controlled by refueling sequence; 4 through restriction to operating modes 4 and 5; and the remaining 26 loads involve monorail fixed paths on which system evaluation and structural analysis demonstrated ' safety or restrictions required for NUREG 0612. C. EG&G Conclusions and Recommendations The actions reported by GSU indicate consistency with the intent of Guideline 1. 2.3.2 Load-Handling Procedures [ Guideline 2, NUREG-0612 Article 5.1.1(2)]
" Procedures should be developed to cover load-handling operations for heavy loads that are or could be handled over or in proximity to irradiated fuel or safe shutdown equipment. At a minimum, procedures should cover handling of those loads listed in Table 3-1 of NUREG-0612. These procedures should include: identification of required equipment; inspections and acceptance criteria required before movement of load; the steps and proper sequence to be followed in handling the load; defining the safe path; and other -~
special precautions." River Bend SSER 2 11 Appendix I l h
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-i j A. Summary of Applicant's Statements -1 For each of the heavy loads listed, where compliance with NUREG 0612 is required, the safe load path / procedural requirements corresponding to the RBS assigned safety class will be added to the appropriate plant procedures. When more than one safety class assignment was made for a particular load, the safe load path / procedural requirements of all safety class assignments will be included in the procedures.
Measures will be included in a number of plant procedures utilized in performing heavy lifts. Each such heavy lift will be supervised by a designated individual who will be responsible for enforcing the procedural requirements. Any deviation from these requirements will require the prior approval of the Operations Supervisor. The " Load Handling Procedures" for systems of concern will contain the requirements of NUREG 0612 Section 5.1.1(2). B. EG&G Evaluation The information submitted provides a commitment to develop procedures and that they will contain the requirements'of NUREG D612 Article 5.1.1(2).
. C. EG&G Conclusions and Recommendations The commitment of Gulf States Utilities to develop procedures which incorporate all of the requirements specified in NUREG.0612 Section 5.1.1(2) is consistent with the intent of Guideline 2. ~
4 River Bend 55ER 2 12 Appendix I
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1 2.3.3 Crane Operator Training fGuideline 3, NUREG-0612,
'j-Ar,ticle 5.1.1(3)]
4 4
" Crane operators should be trained, qualifted, and conduct themselves in accordance with Chapter 2-3 of ANSI B30.2-1976,
' Overhead and Gantry Cranes' [6]."
j A. Summary of Applicant's Statements
.-j '! A procedure for the qualification and training of overhead crane operators will be developed which meets the provisions of ANSI B30.2-1976, Chapter 2-3. This procedure will include training, examination, experience, and physical requirements for crane operators as well as precau~tions' and instructions to assure proper conduct of crane operation. In addition, required crane operator training will include, among other things, instruction in crane operator conduct,'such as proper hand signals, testing of controls, limit devices, attaching the !
load, and moving the load. No exceptions to the : guidance in ANSI B30.2-1976, Chapter 2-3 are taken. With regard to the monorail /hof st systems identified, the provisions of ANSI B30.2-1976 are not directly applicable. Appropriate requirements, however, will be included in plant procedures regarding the control and use of hoists. These procedures require that hoist operators be trained in hoist operation and certified as hoist operators by the Mechanical Maintenance. Supervisor, e B. EG&G Evaluation Development and application of the procedure RBS states they will follow, without exception, is an adequate commitment to show consistency with Guideline 3. -. 1 River Bend SSER 2 13 Appendix I 1 I
- . , - - - - - . . = . - . .-:.--- : -- - - - - -- h j \
C. EG&G Conclusions and Recommendations The commitment for operator training, qualification, and
, conduct is consi. stent with Guideline 3.
l 2.3.4 Special Lifting Devices IGuideline 4. NUREG-0612 l Article 5.1.1(4))
"Special lifting devices should satisfy the guidelines of ANSI N14.6-1978, ' Standard for Special Lifting Devices for Shipping Containers Wei Materials' [7]ghing .
10,000 This Pounds standard (4500 should kg) or apply to More for Nuclear all special lifting devices which carry heavy loads in areas as defined above. For operating. plants, certain inspections and load tests may be accepted in lieu of certain material requirements in the standard. In addition, th'e stress design factor stated in Section 3.2.1.1 of ANSI N14.6 should be based on the combined maximum static and dynamic loads that could be imparted on the handling device based on characteristics of the crane which will be used. This is in lieu of the guideline in Section 3.2.1.1 of ANSI N14.6 which bases the stress design factor on only the weight (static load) or the load and of the intervening components of the special handling devic ~e." A. Summary of Applicant's' Statements ' The two special lifting devices are: 1) Head Strongback Carousel, 2) Dryer / Separator Strongback. A description of each of these devices and plant function or operations in which , these devices are used is presented. The two special lifting devices were evaluated against ANSI N14.6-1978, with special emphasis on Sections 3.2 and 5 of that standard. The devices were designed and fabricated prior to the application of this standard to special lifting devices, therefore there are a number of sections that are not appropriate to apply in retrosoect. These relate to Designer's - and Fabricator's responsibilities in Sections 3.1, 3. 3, 4.1, 4.2 and 4.3. Information on drawings and letters indicate that 6 River Bend SSER 2 14 Appendix I
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4 e /l sound engineering practices were placed on the fabricator and inspectors by the designer. The devices were designed and supplied in accordance with Project Quality Assurance-program as appropriate for Category 1 structures. The devices will be used only in controlled environments; procedures will permit their use for the loads intended only, or special test loads. Certain specific design considerations not pertinent to load htndling reliability were not addressed. RBS takes specific exception to considering the heavy loads handled by the two strongbacks as critical loads, at this time. Any load drop scenarios are believed premature and are not required untti the final report to NRC, so ANSI N14.6 Section 6 is not applied. Stress design and fracture toughness considerations have been evaluated and are consistent with ANSI N14.6 Section 3.2 requirements. Inspection, test, and maintenance meets the ANSI N14.6 Section 5 requirements with four exceptions. o The inspection interval, due to long periods between usage will be prior to use by qualified personnel and thorough NDE examination each ! 5 years. o Load testing was initially at 125% so follow-up,
, after any incident subjecting load bearing components to excess stresses, will use
~
dimensional examination and NDE. If defects or
- deformation are detected, a 125% load test consistent with initial proof test will be made and followed with NOE.
F River Bend SSER 2 15 Appendix I
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~l o, Proof load testing was at 125% and the devices a
service is dedicated to one or two specific loads,
.j so subsequent proof load testing will be at 125%
l ' followed by NDE. 5 j o The NDE and dimensional examinations are at intervals longer than recomended by Section 5.3.1(2) of ANSI N14.6, but will be performed at 5 year intervals which is believed to jj be adequate due to the limited dedicated service.
,r J
B. EG&G Evaluation All discussions are relative to the Head Strongback Carousel and the Dryer / Separator Strongback, the only two special
, lifting devices for RBS.
Information presented on these two special devices provide insight into the RBS position relative to their status and the guideline requirements. The specific exception taken to co'nsidering loads handled by the special strengbacks as
" Critical Loads" is not at issue in Phase I evaluations.
One basic concept of NUREG D612 is to identify and control risk of heavy load drops, especially if the drop adversely affects "a safety related system required for unit safety . . . " The first part of the ANSI N14.6 definition of Critical Load emphasizes the same key components as NUREG 0612. The ANSI N14.6 Section 6 requirements relate primarily to the guidelines that must be answered for the Phase II evaluation. The considerations discussed on: stress design; fracture toughness; and the exceptions concerning inspection intervals, incident load testing, proof load testing, and i NDE dimensional examinations am considered within the scope : )_ River Bend SSER 2 16 Appendix I
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1 ) .! P; and meeting the intent of NUREG 0612 Guideline 4 or the interpretations given in the " Synopsis of Issues Associated [' e with NUREG 0612." t C. EG&G Conclusions and Recommendations n } The two special lifting devices for RBS are consistent with I the intent of requirements for Guideline 4. 2.3.5 Liftino Devices (Not Specially Designed) [ Guideline 5, NUREG-0612. Article 5.1.1(5)1
" Lifting devices that are not specially designed should be installed and used in accordance with the guidelines of ! ,- l ANSI B30.9-1971, ' Slings' [8]. However, in selecting the proper sling, the load used should be the sum of the static and maximum l
dynamic load. The rating identified on the sling should be in l terms of the ' static load' which produces the maximum static and I dynamic load. Where this restricts slings to use on only certain l cranes, the slings should be clearly marked as to the cranes with l which they may be used." l A. Summary of Applicant's Statements itith respect to lifting devices not specially designed (i.e., slings), the criteria of ANSI B0.9 apply. Therefore, to assure that slings are appropriately used and , unintained, load handling procedures are being developed ' which will require: a) The use of ANSI B30.9 and NUREG 0612 Section 5.1.1 (5) criteria for sling selection and rigging techniques; River Bend SSER 2 17 Appendix I
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'f b) A preventive maintenance procedure specifying annual inspection of slings; j c) A visual inspection of slings for damage prior to making a lift;
, d) A preventive maintenance procedure which includes tagging requirements to identify sling rating, application, last examination, and expiration date of examination;
.e) Sling selection, use, and marking which will be based on rated loads, which include the sum of both maximum static and dynamic loads.
B. EG&G Evaluation The commitment on procedure development for use of non-special lifting devices is consistent with NUREG 0612 Guideline 5. The interpretation r,f 2.3.5 A sub d) above concerning tagging for application, is considered to include marking a sling dedicated to service on a certain crane load, if slings are so dedicated. C. EG&G Conclusions and Recommendations The commitment for Lifting Devices, not Specially Designed is consistent with NUREG 0612 Guideline 5. i River Bend SSER 2 18 Appendix I
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I-a j ' 2.3.6 Cranes (Inspection, Testing, and Maintenance) [ Guideline 6, NUREG-0612 Article 5.1.1(6)1 "The crane should be inspected, test'ed, and maintained in d accordance with Chapter 2-2 of ANSI B30.2-1976, ' Overhead and 1 Gantry Cranes,' with the exception that tests and inspections
- y. should be performed prior to use where it is not practical to ;
j meet the frequencies of ANSI B30.2 for periodic inspection and i test, or where frequency of crane use is less than the specified
-inspection and test frequency (e.g., the polar crane inside a PWR containment may only be used every 12 to 18 months during refueling operations, and is generally not accessible during power operation. ANSI B30.2, however, calls for certain inspections to be performed daily or monthly. For such cranes having limited usage, the inspections, test, and maintenance should he, performed prior to their use).
A. Summary of Applicant's Statements 1 Procedures for inspection, testing, and maintenance of the ' three overhead cranes (Reactor Building Polar Crane, Fuel Building Eridge crane, Spent Fuel Cask Trolley) will be l pmpared following the guidelines of ANSI B30.2-1976, ; Chapter 2'2. With the implementation of these procedures, the criteria of ANSI B30.2-1976 Chapter 2-2, are satisfied. No exceptions to the standard are taken. 1 ANSI B30.2-1976, Chapter 2-2 is not directly applicable to the inspection, testing, and maintenance of the monorail / hoist systems. The activities for these monorail / hoist systems are, however, covered extensively by ! plant procedures which have been prepared following the guidelines of ANSI B30.16-1973, Section 16-2.2 and ANSI B30.11-1980, Chapter 11-2. I
-l River Bend SSER 2 19 Appendix I
,. - . . -..-.:.=. . - . . - - . .
i
' I, B. EG&G Evaluation-Procedure preparation and follow-up usage commitment RBS < . makes constitutes consistency with NUREG 0612 Guideline 6. ', C. EG&G Conclusions and Recommendations a
The commitments are consistent with the NUREG 0612 Guideline 6. 2.3.7 Crane Design fGuideline 7, NUREG-0612, Article 5.1.1(7Ti "The crane'should be designed to meet the applicable criteria and guidelines of Chapter 2-1 of ANSI B30.2-1976, ' Overhead and Gantry Cranes,' and of CMAA-70, ' Specifications for Electric Overhead Traveling Cranes' [9]. An alternative to a specification in ANSI B30.2 or CMAA-70 may be accepted in lieu of specific compliance if the intent of the specification is satisfied." , A. Summary of Applicant's Statements The overhead cranes listed in response to Item 1 are the Reactor Building Polar Crane, the Spent Fuel Cask Trolley and the Fuel Building Bridge Crane. The SWEC design specifications for these cranes were compared to the 1975 revision of CMAA-70 and to the additional safety requirements of ANSI B30.2-1976, Section 2-1. Based on these comparisons, we find that the Reactor Building Polar Crane, Spent Fuel Cask Trolley and the Fuel Building Bridge ' Crane comply with the guidelines of CMAA-70-1975 and i ANSI B30.2-1976. l
..l 1
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River Bend SSER 2 20 Appendix I
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With regard to the monorail lifting systems, the guidelines of CMAA-70 and ANSI B30.2-1976 are not directly applicable. However,-the design of these monorail systems does meet the applicable industry standards as described below.
~
The monoratis used at River Bend Station were either q designed by SWEC or procured under a special specification. The appropriate industry standards applicable to these 1 systems are ANSI B30.16, " Overhead Hofst--1973" and ANSI B30.ll, " Monorail Systems and Underhung Cranes." In
, all cases, the monorails at River Bend Station comply with the appropriate sections of these two ANSI standards B. EG&G Evaluation There is acceptable information to confirm consistency with Guideline 7, or its intent. ,
C. EG&G Conclusions and Recommendations Information presented shows that RBS Unit 1 is consistent with the intent of Guideline 7. 2.4 Interim Protection Measures The NRC staff has established (NUREG-0612, Article 5.3) for' interim protection guides to operating plants. Since 1 RBS Unit 1 is not operational these guidelines do not apply. l 1
~
i l l River Bend SSER 2 21 Appendix I
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- 3. CONCLUDING
SUMMARY
l 3.1 Applicable Load-Handling Systems The list of cranes and hoists supplied by the applicant as being subject to the provisions of NUREG-0612 is apparently complete (see Section2.2.1). However, additional evaluation on 8 cranes is needed. This may result in exemption for some of these cranes. 3.2 Guideline Recommendations Compliance with the seven NRC guidelines for heavy load handling (Section 2.3) are partially satisfied at RBS Unit 1. This conclusion is represented in tabular form as Table 3.1. Specific recommendations to aid in compliance with the intent of these guidelines are provided as follows: Guideline Recommendation
- 1. Section 2.3.1 The actions of GSU indicate Safe Load Paths RBS is consistent with the intent of Guideline 1.
- 2. Section 2.3.2 The commitment to develcp Load Handling Procedures procedures incorporating all the requirements of NUREG 0612 Section 5.1.1(2) is consistent with Guideline 2.
- 3. Section 2.3.3 The commitment for operator -
Crane Operator Training training, qualification and conduct is consistent with Guideline 3. g River Bend SSER 2 22 Appendix I
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( p TABLE 3.1. RIVER BEND STATION UNIT 1, NUREC 0612 SECTION 5.1.1 COMPLIANCE MATRIX ~
, ?,
Lifting Crane
< Handling System Load Sara Load Crane Special Devices inspection
[' Rating Loads Hand 1lng Ope ra to r Lifting Not
@ h Identification fTons) Paths Procedures Trainino Test Crane Devices Special Deslan Hafntenance Dealen -
g
- 3 1 Reactor 81dg. Polar Crane / Aux. 100/5 C C C I C C C Hoist CL m 2 Drywell MSIV and Roller Valve 3 C C C
, y Monorail C C 'C
;o 3 Fuel Bldg. Bridge Crane 15 C C C C C C is Spent fuel Cask Trolley / Aux. 125/15 C C C Holst C C C 'i l
5 MSIV Monorails 8/5 C C C C C C I' 6 MSIV Foodwater Isolation Valve 3 C C C C C C I Monora ii s ! l' 7 Feedwater Valve Holsts 3 C C C C C C !>- 8 RHR A Pump Monorail 8 C C C C 1 C C !. 9 RHR 8 & C Pump Honorail 8 C C C C C C l y 10 Aux. Bldg Tunnel Plug Monora i l 6 C C C C C C i 11 Holst Area Honoralls S C C C C C C j 12 l'Ioor Plug Honorail 5 C C C 13 Cont. sidg. Eqpt. Handling Area 5 C C C C C C C { Honora il C C [ C = Appilcant action complies with NUREC 0612 Culdeline. I NC = Applicant action does not comply with NUREC 0612 Culdeline. R = Appilcant has proposed revision / modifications designed to comply with NUREG 0612 Culdelines. j 1 = Insufficient information provided by the appilcant. , 3' l' y i I a
$ 23 '
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-! Guideline Recommendation
- 4. Section 2.3.4 The two special lifting l Special Lifting Devices devices for RBS are a
consistent with the intent of requirements for Guideline 4
- 5. Section 2.3.5 The commitments on l Lifting Devices, Guideline 5 are I
Not , Specially Designed consistent with requirements.
- 6. Section 2.3.6 The commitments are Cranes Inspection consistent with NUREG D612 Testing and Maintenance Section 5.1.1(6) Guidelines.
- 7. Section 2.3.7 RBS Unit 1 is consistent with Guideline 7.
Crane Design t River Bend SSER 2 Appendix I 24 see I
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u i i t! 3.3 Interim Protection l These requirements do not apply to plants under construction. ~
, 3.4 Summary GSU has shown that RBS is. consistent with the intent of NUREG 0612
, Article 5.1.1 requirements.
i River Bend SSER 2 25 Appendix I
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;l 4. REFERENCES a '
I ,i ' ;j
- 1. NUREG-0612, Control of Heavy Loads,at Nuclear Power Plants, NRC.
- 2. V. Stello, Jr. (NRC), Letter to all applicants.
Subject:
Request for Additional Information on Control of Heavy Loads Near Spent Fuel, NRC, 17 May 1978.
- 3. USNRC, Letter to Gulf States Utilities Co.
Subject:
NRC Request for Additional Information on Control of Heavy Loads Near Spent Fuel, NRC, 22 December 1980.
- 4. E. L. Draper, Jr., Gulf States Utilities Co. , to Darrell G. Eisenhut, NRC.
Subject:
RBG-10,612 File No. G9.11 Control of Heavy Loads, June 24, 1981.
- 5. J. E. Brooker, Gulf States Utilities Co., to Harold R. Denton, NRC.
Subject:
River Bend Station-Unit 1 Docket No. 50-458 March 1,1984.
- 6. ANSI B30.2-1976, " Overhead and Gantry Cranes."
- 7. ANSI N14.6-1978, " Standard for Lifting Devices for Shipping Containers Weighing 10,000 Pounds (4500 kg) or more for Nuclear Materials."
- 8. ANSI B30.9-1971, " Slings".
- 9. CMAA-70, " Specifications for Electric Overhead Traveling Cranes."
- 10. J. E. Booker, Gulf States Utilities Co. , to Harold R. Denton, NRC.
Subject:
River Bend Station--Unit 1 Docket No. 50-458, November 5, 1984.
- 11. Amarjit Sing, NRC, to T. H. Stickley,
Subject:
Summary River Bend Station Heavy Loads Evaluation, January 8,1985. River Bend SSER 2 26 Appendix I 1
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APPENDIX J TECHNICAL EVALUATION REPORT OF THE DETAILED CONTROL ROOM DESIGN REVIEW FOR GULF STATES UTILITIES COMPANY RIVER BEND STATION i a L i River Bend SSER 2 Appendix J
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.j .i TECHNICAL EVALUATION REPORT 'l 0F THE il DETAILED CONTROL ROOM DESIGN REVIEW FOR -i i GULF STATES UTILITIES COMPANY RIVER BEND STATION 9
January 29, 1985 4 Jack W. Savage L. Rolf Peterson I Lawrence Livermore National Laboratory for the United States Nuclear Regulatory Commission l
- )
River Bend SSER 2 Appendix J
J, E '! CONTENTS t ] ' t Page 1. Background............................................................. 1 2. Discussion............................................................. 3 2.1. DC R DR R e v i ew Te a m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2. Fu nct i on and Ta s k An a ly se s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 2.3. Comparison of Control and Displa Control Room Inventory..........y Requirements with a
.................,............... 7 2.4 Control Room Survey.............................................. 8 2.5. Assessment of HEDs.............................................. 10.
2.6. Sel ect i on of Desi gn Imp rovement s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 2.7. Verification that Design Improvements Provide the Necessar Corrections and Do Not Introduce New HEDS.................y...... 12 2.8. Coordination of the DCRDR with Other Programs...................13 3. Conclusions........................................................... 15 4. References............................................................ 16 Appendix A................................................................ 17 Appendix B................................................................ 20 1 . I River Bend SSER 2 i Appendix J
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,) 1 ', \: .l. TECHNICAL EVALUATION REPORT OF THE DETAILED CONTROL ROOM DESIGN REVIEW FOR GULF STATES UTILITIES COMPANY RIVER BEND STATION .' 1. BACKGROUND Licensees and applicants for operating licenses shall conduct a Detailed Control Room Design Review (DCRDR). of nuclear power plant control room operators to prevent accidents
. with accidents if they occur by improving the information provided to them" (NUREG-0660. Item I.D.).
or licensee to conduct a DCRDR on a schedule negotiated with th Regulatory Commission (NRC). 1
' ,; NUREG-0700 licensees with guidelines for its conduct.
describes four phases of the DCRDR and provides applicants and A The phases are:
- 1. Planning 1
- 2. Review
- 3. Assessment and implementation
- 4. Reporting The NRC staff's evaluation activities are briefly identified in the subsections that follow. The criteria to be applied during this evaluation l process are presented in detail in Sections 2 through 5 of Appendix A to Standard Review Plan (SRP), Section 18.1 of NUREG-0800.
i A program plan is to be submitted within two months of the start of the DCRDR. describe how the following elements of the DCRDR will be a 1. Establishment of a qualified multidisciplinary review team. 2. Function and task analyses to identify control room operator tasks
; and operations. information and control requirements during emergency 3.
A comparison of display and control requirements with a control room inventory. 4 A factorscontrolprinciples. room survey to identify deviations from accepted human - i I - 4 ' River Bend SSER 2 1 Appendix J _ _ ._. . _ _ _ _ . , , . _ . _ . . _ . . _ , _ . _ _ . , , _ . . _ , , , , , . _ - _. _ . _ ._ , _ , . . _ -_ - - ~ . _ _ _ . . . _ . . - _ - , . - -
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Assessment of human engineering discrepancies (HEDs) to determine which HEDs are significant and should be corrected.
- 6. Selection of design improvements.
- j. 7.
; Verification that selected design improvements will provide the necessary correction, and will not introduce new HEDs.
8.
,; Coordination programs such as ofSPDS control room improvements with changes from other
- 1 i
and upgraded emergency, operating procedures. operator training, RG 1.9
-.i A Summary Report is to be submitted at the end of the DCRDR.
shall: As a minimum, it
] 1. Out i t..t proposed control room changes.
1 2. Outline proposed schedules for implementation. 3. be left uncorrected or partially corrected. Provide summary The NRC will evaluate the organization, process, and results of the DCRDR. Evaluation will include review of required documentation (program plan and summary briefings, discussions, report) andand mayon-site also include audits. reviews of additional documentation, In-progress audits may be conducted Summary after submission of the program plan, but before submission of the Report. 0737. Additional guidance for the evaluation is provided by NU evaluation report (SER) or SER supplement.Results of the NRC ev Significant HEDs should be corrected. with an enhancement program should be done promptly. Improvements which c f I
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L River Bend SSER 2 2 Appendix J
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- 2. DISCUSSION The River Bend Station, operated by Gulf States Utilities Company (GSU), is now under construction. As required by Supplement 1 to NUREG-0737, a complete
' Detailed Control Room Design Review (DCRDR) is required before a license can be issued.
GSU submitted a DCRDR program plan for River Bend Station (RBS) to the NRC on
. January 31, 1984. The GSU DCRDR program plan for RBS was reviewed by the NRC staff to compare the applicant's response to the requirements of Supplement 1 to NUREG-0737 and the guidance of NUREG-0700 and draft NUREG-0801 (now incorporated into NUREG-0800, Appendix A to SRP Section 18.1). NRC staff comments on the RBS Program Plan were issued April 25, 1984 This review of the RBS Program Plan included general comments on addressing control room modifications and additions made or planned as a result of post-TMI actions and possible integration of lessons learned from Salem ATWS events. In addition to the general comments above, the staff provided specific comments on the DCRDR elements identified in Supplement 1 to NUREG-0737.
A NRC human factors engineering in-progress audit of the RBS DCRDR was performed July 27, 1984 at the plant site in St. Francisville, Louisiana, on July 24 through The audit was carried out by a team of NRC personnel from the Human Factors Engineering Branch (HFEB) and consultants from Lawrence Livermore National Laboratory, Livermore, California. NRC staff comments on the results of the NRC in-progress audit of the RBS DCRDR were issued October 4, 1984. GSU submitted their RBS DCRDR Sumary Report to the NRC on October 31, 1984 This technical evaluation report (TER) provides comments on the content of the Summary Report and the current status of the RBS DCRDR with respect to fulfillment of the DCRDR requirements of Supplement I to NUREG-0737. Deficiencies in the RBS DCRDR are noted, and recommendations for actions to resolve these deficiencies are included. 2.1. DCRDR REVIEW TEAM Supplement I to NUREG-0737 requires the establishment of a qualified multidisciplinary review team. Guidelines for review team selection are found in NUREG-0700 and NUREG-0800, Appendix A to SRP Section 18.1. NUREG-0700 guidelines state that support of the applicant's management is needed to provide to the DCRDR team all of the information, equipment, and categories of manpower needed to conduct a control room design review. The RBS program plan stated that the review team would be a multidisciplinary team with the wide range of skills necessary to perform the DCRDR. The information gathered by the NRC audit team during the RBS in-progress audit supported that statement. Before the in-progress audit, there was a question - as to extent of participation in the day-to-day review activities by.the team members and supporting personnel. The audit provided evidence that an . appropriate level of expertise was being provided in the necessary technical areas. : River Bend SSER 2 3 Appendix J
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- and stafffing for the RBS DCRDR.The RBS DCRDR Summary Repor The Review Team Leader provided technical and administrative project. direction for the project and had responsibility for the ultimate responsibility for the RBS DCRDR.The Review Team Leader
, General Physics Corporation was the Human Factors Consultant to GPU for RBS DCRDR.
Review Team Leader in conducting each phase of the ,RBS D l s team members and supporting personnel.The RBS DCRDR Summa
] members were provided in appendices to the Summary Report. Resumes of Based on the NRC review team observations during the DCRDR in-progre and our review of the RBS DCRDR Summary Report, we conclude'that GSU management made a clear commitment to support the DCRDR process and that t review team members had suitable expertise for the job.
review team to conduct the DCRDR has been met by the However, there are indications that GSU plans to significantly reduce the participation of human factors specialists durin j the verification of implemented HED resolutions.g the resolution of HEDs and We recossnend that GSU provide assurance to NRC of the continued participation of human factors verification of control room design changes that are ma 2.2. FUNCTION AND TASK ANALYSES i and task analyses (SFTA) to identify control room opera identify control room operator information and control needs during emerg operations.
- Supplement 1 to NUREG-0737 recommends the use of function and operating procedures technical guidelines and plant-sp operating procedures to define these needs.
NUREG-0700 guidelines are:The steps for top-down systems function and ta 1 1.
- 2. Identification of systems and subsystems
- 3. Identification of operating events for analysis 4
Function identification Operator task identification and analysis Operator information and control needs should be determined independently . the existing control room design. The analysis should include the appropriate functions of plant safety-related systems and the emergency operating River Bend SSER 2 4 A pendix J
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, i procedures (EOPs) that must be used to ensure that the plant can be efficiently and reliably operated by available personnel during emergency conditions.
j GSU has used the Boiling Water Reactor Owners Group (BWROG) emergency procedure guidelines (EPGs) as the basis for the DCRDR task analysis and to
, 1 develop River Bend specific E0Ps.
meeting between the NRC and the BWROG.These EPGs were the topic of a May 4, 1984 concluded that: Based on that meeting, the NRC staff 1. i . . . it appears that Revision 3 of the EPG provides a functional analysis that identifies, on a high level, generic information and
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control needs. However, these EPGs do not explicit 1; identify the i plant-specific information and control needs, which are necessary for preparing emergency operating procedures and determining the adequacy of existing instrumentation and controls... 2. i Because detailed plant-specific information and control needs cannot be extracted directly from the EPGs, plant-specific analysis is required. 3. 4 Each licensee and applicant must describe the process used to identify plant-specific parameters and other plant-specific 1 information and control capability needs and must describe how the characteristics of needed instruments and controls will be determined. ,; These processes may be described in either the i Procedure Generation Packages or the DCRDR Program Plan with - appropriate cross-referencing. 4
- For each instrume'nt and control used to implement the E0Ps, there i should be an auditable record that defines the necessary characteristics of the instrument or control and the bases for that determination.
The necessary characteristics should be derived from analysis of the information and control needs identified in NRC-approved EPGs and from analysis of plant-specific information. ) The major concern identified by the NRC staff in reviewing the RBS Program Plan was that the methodology used to conduct the task analysis may not result in appropriate identification of operator information and control needs. i Specifically, it was not clear to the staff if the analyses would ascertain, independently from the existing displays and controls, the characteristics of the information required by operators to perform discrete emergency tasks. analysis. a major emphasis of the in-progress audit was on the GSU task Therefore, ^ i Based on a detailed discussion with GSU personnel and their contractors, audit j of task analysis documentation to date, and review of drafts of proposed DCRDR
- Program Plan revisions provided by GSU, it appeared that an approach to .
l performing the analysis which would be sufficient to meet the requirements of i Supplement 1 to NUREG-0737 was being pursued. This conclusion was contingent i River Bend SSER 2 5 Appendix J i
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- upon the successful indicated completion of the following analysis steps that GSU it was pursuing:
1. Plant systems and subsystems with which control room operators must
. interface during emergency operations have been identifted.
2. t Description prepared. of the functions of each of the above systens have been 3. A set of scenarios has been developed which, with the residual tasks defined below, incorporate all of the ope,rator actions necessary to implement Revision 3 of BWROG EPGs. 4 Residual tasks; i.e., operation actions identified in the EPGs that are not incorporated in the emergency scenarios, have been identified and analyzed to determine information and control requirements. 5. All operator actions encompassed by 3 and 4 above have been analyzed
. to identify discrete tasks operators must perform.
6. Operator decisions and actions associated with each task have been defined. - 7. Information and control requirements for successful task performance have been identified for each task. These include, but are not limited to, identification of parameters which need to be monitored and identification of relevant information and control capability characteristics such as ranges, setpoints, need for trending, need for continuous or discrete control, etc. i GSU identified the RBS plant systems and subsystems that the operators must use during emergency operations in the RBS DCRDR Summary Report. The functions Report. of these systens were described in Appendix E of the Sunnary The set of scenarios based upon the BWROG EPGs and the RBS plant-specific E0Ps that were selected for task analysis are listed in the Summary Report the withReport. Sunnary narrative descriptions of each scenario provided in Appendix F of from plant-specific E0Ps that were not included in the selected assure requirementsthat awas complete made. determination of operator information and control GSU states that Task Analysis Worksheets were developed that indicate the operational steps required in each scenario. specific RBS E0Ps and corresponding generic BWROG ERGS were identified ordersheets. work of performance and entered in the " Procedure Number" column of the
" Decision and/or Action Requirements " and "Information and C Requirements" were filled in during the function and task analysis. Relevant i
characteristics for parameter readings and control selection were provided b a 1 i River Bend SSER 2 \ 6 Appendix J i
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Lj a 4 i r Y 1! 4 - a subject matter expert. Supporting documentation of primary sources of
! ~ information and control requirements for each task were identified and recorded on a separate form. GSU states in the R8S Sumary Report that these lj portions of the task analyses were completed using independent sources of data ,
JJ other than the., instruments and controls present in the control rode.
. The RBS Summary Report described the methodology used for the RBS function and task analyses and provided blank copies of the task analyses forms. The methodology in the RBS Sumary Report describes a technique that would j
acceptably to NUREG-0737. fulfill the function and task analysis requirement of Supplement 1 provided in the RBS Summary Report.No supporting data or examples from, th y.j Without this more specific information ! we were unable to determine whether the RBS function and task analyses were, j actually performed to a level of detail sufficient to determine operator information and control needs for each operating task. Therefore, we could not determine that the function and task analysis requirement of Supplement 1 to NUREG-0737 has been fully satisfied. We recomend that GSU provide more detailed task analysis i ormation to the NRC to confirm that the R8S task analyses satisfy the requirement of Supplement 1 to NUREG-0737.
'2.3.
i INVENTORY COMPARISON OF CONTROL AND DISPLAY REQUIREMENTS WITH A C 4
- Supplement 1 to NUREG-0737 requires the applicant to make a control room 4 - inventory and to compare the operator display and control requirements determined missing from and controls the task analyses with the control room inventory to determine displays.
Guidance in NUREG-0700 also calls for a review of the human factors operator information and control requirements. suitability of instruments and controls used to satisfy GSU states in the RBS Sumary Report that the inventory function was accomplished as part of the task analysis and related verification and validation efforts. GSU states that the specific displays, controls, or other interfaces available to: 1) initiate, maintain, or remove a system from : service; 2) confirm that an appropriate system response has or has not
! occurred, i.e., feedback; or 3) make a decision regarding plant or system status for each procedural step were identified and documented in the "Means" and "I & C Identification" columns of the Task Analysis Worksheet. Detailed
{ information about the characteristics of the identified instruments and controls were recorded on a separate Equipment Characteristics form. The j identification of actual instruments and controls occurred during walkthroughs of the tasks performed by the control room operators. The comparison of the control room instruments and controls with the information and control requirements derived from function and task analyses 2 was'also made during the walkthroughs. During this comparison, the 3 availability and. suitability of control room instruments and controls was _i j evaluated and recorded on the Task Analysis forms. Discrepancies were
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4 River Bend SSER 2 7 Appendix J 4 _.~___...~-r--,._ .
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l ]I 1 documented as HEDs on Equipment Suitability HEDs forms and noted in the i " Comments / Candidate" HEDs column of the Task Analysis Worksheet. HED data were later recorded on HED forms and entered into a computerized database.
- . 1 GSU states that all task analysis data was entered into the River Bend DCRDR d
j computerized database. - l The GSU approach does not conform to the NRC recommended approach of developing a complete control room inventory with detailed descriptions of the ,l ' characteristics of all instruments and controls installed in the control room. However, the GSU approach should provide the data needed to evaluate '* the suitability of instruments and controls needed to perform the RBS plant-specific E0Ps and to identify missing displays and controls. Performance of the comparison of information and control requirements with the
- ' characteristics of installed instruments and controls as described in the RBS Summary Report would fulfill the requirement of Supplement 1 to NUREG-0737.
The RBS Summary Report did not provide supporting data or eaamples of the control room equipment inventory and task analysis requirements comparison. Without this information we were unable to determine that suitable and comparable levels of detail about instrument and control characteristics were used to make the comparison with the information and control needs identified i from the task analyses.' Thus, we could not determine that the RBS comparison of task analysis requirements and control room equipment characteristics fully satisfies the requirement of Supplement I to NUREG-0737. i We recommend that GSU provide information to the NRC to confirm that the RBS comparison of the characteristics of control room instruments and controls ' with the task analysis derived operator information and control needs was performed to an adequate level of detail for each operator task. Based upon preliminary observations during the NRC in-progress audit, we believe that GSU , can provide working documentation to show that the RBS DCRDR has satisfied the requirement of Supplement 1 to NUREG-0737 for comparison of control and j display requirements with a control room inventory. 2.4. CONTROL ROOM SURVEY Supplement 1 to NUREG-0737 requires that a control room survey be conducted to identify deviations from accepted human factors principles. NUREG-0700 provides guidelines and criteria for conducting a control room survey. The objective of the control room survey is to identify, for assessment and [ possible correction, characteristics of displays, controls, equipment, panel i layout, annunciators and alarms, control room layout, and control room ambient j conditions that do not conform to good human engineering practices. i GSU/ General Physics performed a complete control room survey (CRS) in February 1984. The 1981 BWROG CRS Checklist and the 1983 Supplemental CRS Checklist t were used for this survey. The NRC audit team endorsed the GSU decision to do the control room survey over again, rather than use the survey that was done - by the BWROG in San Jose in 1981. By doing a complete new survey, a more up-to-date and integrated evaluation of control room interfaces was obtained. i r , River Bend SSER 2 8 Appendix J
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?]h The NRC audit team reviewed Panels 680 and 870 by comparing the CRS checklists
; filled out by the R8S reviewers with the corresponding HED sheets. A HED 4
sheet was product (EP) found equal toon or file greater for than all checklist
- 6. item deviations with an evaluation include the BWROG checklist category item identification number and
- location.
t i During the in-progress audit, the NRC audit team was told by the RBS review than 4 would be considered HEDs. team that all deviations from the guideline t The audit team was further told that, based l on BWROG guidelines, action and would be dropped. checklist items with EP=0 to 3 required no corrective It was the NRC audit team's position that all checklist deviations with a judged compliance factor of 2 and 3 and a
- potential for error of I should also be listed as HEDs and evaluated.
During post-audit telephone discussions between the NRC and RBS, it was agr; j
- thJt all checklist deviations with a compliance factor greater than I would be f i evaluated as HEDs regardless of their potential for error rating. The RBS
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Summary Report confirmed that all checklist items with a compliance factor . phase of the RBS DCRDR. greater than I were designated as HEDs' and addressed i The NRC audit team compared the BWROG checklists that were filled out by the i GSU/ General Physics CRS working groups with the actual control panels. ! Control room panels 601, 680, 870, and remote shutdown panels for Division 1 and Division 2 were audited. It was found that the 8WROG checklists were applied objectively and consistently by the two RBS working groups that performed the survey of the control panels. l l The NRC audit team compared the BWROG checklists that were filled out by the GSU/ General Physics CRS working groups with the actual control panels. Control room panels 601, 680, 870, and remote shutdown panels for Divi:; ion 1 and Division 2 were audited. It was found that the BWROG checklist were applied objectively and consistently by the two R8S working groups that i- performed the survey of the control panels. i
- The NRC audit team agreed with most findings of observed deviations from guidelines that were written up as HEDs. There was minor disagreement with a few conform GSU/GP findings that control layouts and control / display relationships to guidelines.
- The NRC audit team noted that some HEDs were duplicated on different panels and that some HEDs were designated by GSU to be panel generic and control room generic HEDs.
The NRC audit team noted that i duplicated and generic HEDs should be consistently reviewed, assessed, and resolved throughout the control room. The duplicated and generic and controls. at RBS include labels, annunciators, and glare on instruments discrepancies i Remaining disagreements on these items are discussed further in this report in Section 2.5 Assessment of HEDs; in Section 2.6, Selection of _. Design2Improvements; Priority HEDs. and in- Appendices A and 8, Comments on Priority' 1 and l River Bend SSER 2 9 Appendix J i
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__ . _ - - - . t a .c . = L .--- a - - w - - i , ! -! L 'D i}; GSU has made a commitment to complete open control room survey items that have + not been completed due to the construction status of the plant. Control room -
- ;j survey items that are still open include lighting; heating, ventilation, and air conditioning; communications; noise levels; availability of pr.ocedures in the control room and remote shutdown panels; availability of protective clothing; and emergency preparedness.
GSU states that these items will be ! evaluated prior to loading fuel and the results will be submitted to the NRC 'g, as a supplement to the RBS Summary Report. 1 1 We conclude that the RBS control room survey has been executed with reasonable {ii diligence and adequately documented. With the completion of the open iterns 1
; above and the addition of HEDs defined by any deviation from the guidelines,
. the RBS CRS is expected to meet the requirement of NUREG-0737 Supplement I to i 4 , conduct factors pr.inciples.a control room survey which identifies deviations from accepted human 2.5. ASSESSMENT OF HEDS j !
! Supplement 1 to NUREG-0737 requires that HEDs be assessed to determine which HEDs are significant and should be corrected. NUREG-0700 and NUREG-0800, Appendix A to SRP Section 18.1, contain guidelines for the assessment process. . Our review of the Priority 1 and Priority 2 safety related HEDs included in ! the Summary Report confirmed that GSU has analyzed, prioritized, and t reconnended plant / operatormeans for correcting those HEDs which will impact safety or performance. !. efforts. Human factors personnel assisted GSU in these i Nonsafety in detail. However, the GSU methodology related Priority 3 and Priority A HEDs were not reviewed included their analysis assessment j and resolution.
- The GSU methodology included an analysis of potential cumulative and '
interactive effects of Priority 4 HEDs and the formal HED assessment and t resolution methodology described appears to be thorough and conplete. It directs review team members in both independent and collective assessment actions. {- 3
- HEDs were assessed on the basis of potential for operating crew error and i
potential impact on safety. Information from the operating experience review I t was used to help assess whether an HED resulted in an operating error or
- provided the potential for operator error. HEDs that might affect operator performance were subjected to a series of 20 statements or questions which i
aided the reviewers in their assessment and judgment of the HEDs. HEDs were also assessed by subjecting them to a list of five statements or questions i that addressed their impact on plant safety. The HEDs were prioritized for selection of corrective actions by categorizing them into levels of significance as determined by safety status and error potential. We conclude that the applicant's HED assessment method, as described and i reported, meets the intent of the guidelines of NUREG-0700 and NUREG-0800, l c River Bend SSER 2 10 Appendix J i
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t l t Appendix A to SRP Section 18.1, and meets the requirement of Supplement I to NUREG-0737 to assess HEDs to determine which HEDs are significant and should be corrected.
. 2.6. SELECTION OF DESIGN IMPROVEMENTS Supplement 1 to NUREG-0737 requires the selection of control room design improvements that will correct the significant HEDs. It also states that improvements that can he accomplished with an enhancement program should be done promptly.
The applicant's Summary Report describes a methodology whereby the DCRDR review team considered, for each documented HED, individual recommendations for HED resolution provided by the human factors consultant, General Physics (GP). GP reviewed issues concerning improvement effectiveness and assurance that no new HEDs would result from the improvements. DCRDR engineering representatives supplemented by inputs for operations and other appropriate sources acted to perform feasibility and scope reviews and to consider alternate corrective actions. Proposed corrective actions were reviewed in a series of multiple iterations by all DCRDR team members until a consensus was reached. The mutually agreeable results and cost estimates were then submitted to GSU management for review and approval. For those HEDs of all priorities for which a decision not to correct, or only partially correct. was made, GSU developed justifications to disallow corrective action. These justifications are included in the individual HED discrepancy record recommendations described in Part 7 of the Sumary Report. The GSU HED corrective action implementation schedule is described in Part 2 of the Summary Report and is stated for each HED on the HED discrepancy record in Part 7 of the Summary Report. Our detailed review of the Part 7 HED discrepancy records was limited to Priority 1 and Priority 2 HEDS on control room panels 601, 614, 680, 808, 845, 863, 870, and 877, and labeling aspects of C61-P001. The results of our review are described in Appendix A and Appendix B of this report. Our detailed review developed several areas of concern that we recommend be reviewed and given further consideration by GSU. These areas of concern should be settled to the satisfaction of, and on a schedule acceptable to the NRC. We conclude that the applicant's methodology appears to be potentially capable of meeting the requirement of Supplement 1 to NUREG-0737 to select design improvements that will correct HEDs. The satisfaction of this requirement presently rests on the resolution of the concerns detailed in Appendices A and B. i River Bend SSER 2 11 Appendix J
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1 2.7. VERIFICATION THAT DESIGN IMPROVEMENTS PROVIDE THE NECESSARY CORRECTIONS AND DO NOT INTRODUCE NEW HEDS f 1 Supplement 1 to NUREG-0737 requires that selected design improvements be it verified to provide the necessary corrections and will not introduce new HEDs. l The GSU Sunenary Report states that the modified main control room i ~f instrumentation and controls design was evaluated to assure that the selected 1 design improvements, both individually and collectively, adequately correct their respective discrepancies and do not create other safety problems. The j verification was accomplished by performing the following: 3 1 e
' Comparison of the modified main control room design with the control room human factors design conventions document.
e Comparison of the modified main control room desig$ with the instrumentation and controls requirements identified during the control room survey and task analysis. o Comparison of .the modified main control room design with approved project design criteria (e.g., electrical separation criteria). From observations and discussions during the NRC in-progress audit at R85, it was understood that GSU's verification efforts are intermingled with the HED. assessment, corrective action selection, and procedure walkthrough phases of the DCRDR. It was also understood that some verifications would be performed on the simulator which differs in some respects from the CR panels. The Summary
' ' Report includes a comprehensive explanation for the differences and how they were accommodated so as to assure the quality and completeness of the verifications.
GSU has stated that a human factors maintenance plan will be implemented on an ongoing basis to verify the operational effectiveness of implemented improvements and to handle future design changes and alterations. This maintenance plan, as described in the RBS Summary Report, applies mainly to future control room modifications. RBS design v'erification activities and human factors maintenance plan contain the elements of a thorough and comprehensive GSU verification process. But, we have concerns about the following items. e We recomend a hands-on walk /talkthrough verification / validation af ter control room design changes are installed to demonstrate that operators can use the implemented HED CR corrections to effectively _. execute the E0P tasks. This verification effort is not described in the Summary Report. Neither is a definite commitment made' to verify implemented control room design changes in the future. River Bend SSER 2 12 Appendix J l
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1 'i I i e ij We recommend that the simulator be made and kept as an exact l duplicateand training, of the control room procedure fidelity. to enhance verification / validation, 1
' Report whether the control room / simulator differences study re andberecommendations will continued as an ongoing wereeffort usedin and/or the future. executed on a one-time i GSU should provide a more comprehensive description of the verification
, process and firm commitment to verify the effectiveness of HED corrective
- actions after they are implemented in order to demonstrate that the j', requirement in Supplement 1 to NUREG-0737 to verify that selected design j, improvements HEDs is met. will provide the necessary corrections and do not introduce new 2.8.
- i. COORDINATION OF THE DCRDR WITH OTHER PROGRAMS
- Supplement I to NUREG-0737 requires that control room improvements be
- coordinated with changes from other initiatives such as SPDS, operator i
training, RG 1.97 instrumentation, and upgraded E0Ps. i During the NRC in-progress audit at RSS, the MtC audit team observed that the , coordination and integration of the DCRDR with the other NUREG-0737
- Supplement I activities stemed largely from the fact that the DCRDR team leader also functioned as coordinator of all Supplement I tasks.
j ( j DCRDR activity descriptions in the RBS Summary Report cite the coordination i between the development of E0Ps and the DCRDR task analysis. ! RBS plant-specific E0Ps were used for systems function and task identifica-GSU stat and for validation of the E0P content. tion, for verification of control. roo The DCRDR and E0P verification / validation activities were accomplished by walkthrough and talkthroughs of a comprehensive set of emergency scenarios at the R8S control room simulator. Both HEDs and E0P discrepancies were noted during the walkthroughs and talkthroughs. GSU has stated that operator requirements, during conditions of emergency of the SPDS.that were identified during the DCRDR, are being used in development operation , GSU also states DCRDR input is being used in developing the i format of SPDS displays and that the SPDS displays will be reviewed under the GSU Human Factors Maintenance Plan. No comitment for a complete human factors review of SPDS operating characteristics is provided. The RBS Sumary Report notes coordination of the evaluation of RG 1.97
- variables and monitoring requirements with DCRDR determination of the
! availability and adequacy of control room equipment. Discrepancies were input into the DCRDR as HEDs. 4 4 The RBS Summary Report states that training personnel were involved as _ i scenario observers during E0P walkthroughs and talkthroughs and in ' P, verification of the availability and adequacy of control room equipment. y 1 l 0 j l River Bend SSER 2 13 Appendix J i.
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The coordination efforts described mainly involve interactions of personnel
; assigned to various jobs and comparisons of requirements among the control room prograns of Supplenent 1 to NUREG-0737. That occurred early in the DCRDR.
Assurance of a uniformly high level of good human factors
- practices in the control room during implementation of control room design changes from all improvement programs is only addressed in general terms in the GPU Human Factors Naintenance Program.
5
, The RBS Summary Report description of the coordinat, ton of the DCRDR with othe prograss is deficient in the following areas:
e No specific description of activities or commitment to provide a comprehensive human factors review of control room design changes for RG 1.97 instrumentation and the SPDS installation has been e No program to coordinate installation of control 'rown design changes with revisions of procedures and operator training is provided. The early coordination of DCRDR activities with EDP development and evaluation. RG 1.97 accident monitoring instrumentation requirements evaluation, and SPDS parameter selection and display format development partially to NUREG-0737. fulfills the control room coordination requirement of Supplement 1 We recommend that GSU provide further commitment or confirmation to the NRC that the RBS DCRDR will have a positive program to coordinate the DCRDR with other control room improvement prograss during implementation and final verification of control room modifications. We believe this additional coordination is needed to fully satisfy the DCRDR coordination requirement of Supplement 1 to NUREG-0737. l l 8 River Bend SSER 2 14 Appendix J l _ - . . _ _ . . _ _ . _ _ . . - _ -_-..__,__..-___.______.m_ _ _ _ , _ , _ _ _ _ _ _ _ _ _ . _ . . _ . _ . . _ . . . . . . , _ , . , . _ _ .
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3. CONCLUSIONS i Based upon our review of the RBS DCRDR Program Plan, the NRC audit team observations during the NRC in-progress audit at RBS, and our review of the i RBS DCRDR Sumary Report, we believe that GSU is conducting a RBS -DCRDR
; will meet the requirements of Supplement I to NUREG-0737 ,i After ourDCRDR.
in the RBS review of the RBS Sumary Report we note the following shortcom 1. We could not determine that the level of ' detail of the task analysis was adequate to determine operator information and control needs for all operator tasks during emergency operations. 2. We could not determine that information and control needs det from task analyses were adequately compared with the characteristics of control and instruments room instruments controls are provided and controls in the to determine that s.ita control room. 3. Disagreements with the GSU selections of design improvements ud the GSU schedules' for implementation of design improvements for Friority 1 and 2 Safety Related HEDs are provided in Appendices A and B of this technical evaluation report. Improvements thatlcan be accomplished by enhancements should be done promptly. HEDs. Firm GSU comitments to take corrective action are needed for consistent manner is needed. Clearer comitment to resolve repeated and generi - correct HEDs are needed in some instances.Better justification for GSU decisions not 1 e i f River Dend SSER 2 ;15 Appendix J i
I
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i i j ~i 4 REFERENCES
^
1. 1 NUREG-0660, "NRC Action Plan Developed as a Result of the THI-2
.! Accident," May 1980; Revision 1, August 1980.
j 2. i NUREG-0737, " Clarification of TMI Action Plan Requirements," November l 1980; Supplement 1, December 1962 (Generic Letter No. 82-33). l 3. Ii NUREG-0700, " Guidelines for Control Room Design Review," September 1981. ! i,
- 4. '
. NUREG-0800, " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Section 18.1, Ap 4 Criteria for Detailed Cor. trol Room Design Reviews,"pendix A " Evaluation September 1984 5.
Letter from J. E. Booker, GSU, to H. R. Denton, submittin Station 1984. Detailed Control Room Design Review Program Plan,g the River January 31, Bend 6 Letter from A. Schwencer, NRC, to W. Cahill, Jr., transmitting staff April 25,1984coments on River Bend Station Control Room Design Review Program Plan, 7. Memorandum for Voss A. Moore, from S. H. Weiss, " Meeting Summary - Task with BWR Owner's Group Emergency Procedure Guidelines Design Review Committees," May 1984. s 8. Lett5rfromS.H.WeisstoA.SchwencerTransmittingstaffcommentson the Results of In-Progress Audit of River Bend Detailed Control Room Design Review, October 4,1984 9. Letter from J. E. Booker, GSU, to H. R. Denton, submitting the River Bend Station Detailed Design Review Summary Report, October 31, 1984. a River Bend SSER 2 16 Appendix J
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i i l I APPENDIX A RIYER BEND - ANALYSIS OF THE , RESOLUTION OF PRIORITY 1 HEDS I In Part 7 of the RBS Sunnary Report,113 HEDs were classified as Priority 1 in the Summary Report discrepancy record. The descriptions, recommendations, and implementation schedules of 51 were found to be acceptable as reported. The remaining 62 HEDs were analyzed and classified into 7 categories that we believe require further resolution or justification by GSU. These Pr.iority 1 HEDs requiring further action are described in the following pages:
- 1. _GSU No Further Action Required HEDs. We disagree with the GSU classification of these HEDs and Delieve that these HEDs require further consideration by the applicant for the reasons given. ,
1 HED 417 This HED proposes that operator training can compensate for l inconsistent left-to-right and top-to-bottom ordering of components. We question that training is an adequate corrective ' action for poor panel layout. HED 437 This HED proposes that operator training can compensate for switch j' handles that do not move consistently in accordance with operator expectations. We recommend that a more complete rationale be supplied to justify why GSU believes that training can compensate for nonuniform and inconsistent hardware characteristics.
- 2. Generic and Specific Lighting HEDs. These are HEDs for which Stone and Webster is evaluating control room lighting as a result of the DCRDR.
I These HEDs prior deficiencies shouldtoinclude a definite commitment to correct all lighting fuel load. HEDs 196, 194, 198, 197, 193 i 3. Open or Unresolved HEDs. These are HEDs for which the recommendations / actions do not describe an acceptable resolution / implementation of the problem. HED 432 The investigation should be completed, conventions should be established, and specific recommendations made and implemented prior l to fuel load. r al River Bend SSER 2 17 Appendix J
i: _ __ _ . . _ _ _ . - _ i 4 '
]
J HED 16 The recommendations do not include a definite commitment to assure
, adequate lighting levels.
HED 32
] .
The recommendations to use the results of the investigation "as appropriate" should be made more specific. Also, the resolution should justify the use of training / procedures in place of additional hardware. HED 285 There should be a definite comitment to implement the design change prior to fuei load.
.i HED 541 The Justification for "no action" should include an . explanation which addresses whether and how it was established that operators will not have problems with meters which are not easily read. Implementation
.. ! should be scheduled prior to fuel load.
; HED 292 The recomendations should include a definite comitment to implement" the design change selected for corrective action prior to fuel load.
- 4. Generic and Specific HEDs Involving Labels and Location Aids (e.g.,
mimics, color coding, demarcation, etc.). These HEDs should state an unambiguous commitment to implement labels and location aids enhancement corrective actions prior to fuel load. Generic corrective actions should be uniformly and consistently implemented throughout the control room. The operators should not be subjected to changes in labels and locations aids enhancements during the period of initial reactor start-up operations. HEDs 847, 833, 5, 316, 7, 8, 466, 25, 77, 421, 830, 804, 747, 225, 236, 80, 269, 29, 284, 427, 116, 428, 81, 298, 13, 322, 812, 820, 23, 795, 22, 287, 540, 498, 454, 410, 503, 457
- 5. Operating Zone and Setpoint Markings. We agree with generic use of meter zone bounding and setpoint markings to show normal / abnormal state and operational limits and warnings. The recommended markings are enhancements that should be implemented prior to fuel load instead of prior to exceeding 5 percent power.
HEDs 422, 30, 355
- 6. Use of SPDS Displays. Some HED resolutions involve the use of SPDS displays as justification for no corrective action. The use of the SPDS _
as described in the recommendations / actions appears to be acceptable providing the SPDS is operational prior to exceeding 5 percent power. i Comitment that the SPDS displays will be available at that time is needed. River Bend SSER 2 18 Appendix J
1 , i
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,i 1 HEDs 775, 546, 547, 551, 554, 555 ) 7. Miscellaneous HEDs. l HED 399 ' }, ; This HED, which reconsnends the design of a control r00m foreman's desk for ERIS displays, should also commit to its implementation.
- HED 576 The recommendation made to resolve the discrepancy does not state specifically how it will be certain that operators will respond as described.
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1 River Bend SSER 2 19 Appendix J b
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j . i l. > APPENDIX B
- RIVER BEND - ANALYSIS OF THE RESOLUTION OF PRIORITY 2 HEDS
' In Part 7 of the RBS Summary Report the Summary Report discrepancy recor,d.128 HEDs were classified as Priority 2 in s implementation schedules of 55 were found to be acceptable as reported The remaining 73 HEDs were analyzed and classified into 6 categories, which we i believe require pages. in the following further resolution and justification by GSU, and are described 1. .' GSU No Further Action Required HEDs. We disagree with the GSU classification of these HEDs and believe that these HEDs require further consideration by the applicant for the reasons given. / HED 114 The text action" of this HED does not describe the rationale for the "no decision. given. We request that a more complete explanation be HED 268 The meter and control heights exceed good human factors practice. We "no action" decision be given. request that a more complete justification HED 299 We suggest possible that the blank meter be removed from the board to avoid confusion. HED 228 The of thetext of this HED shoeld be rewritten to address the description discrepancy. HED 827 The text of this HED should include reference to task analysis information requirements which support the recommendations. HED 18 Displayfactors human subdivisions practice.in multiples of three are normally not good conclusion that no action is needed.This HED should be rewritten to support the River Bend SSER 2 20 Appendix J ..
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l
'd HED 435
- } We question whether training is an acceptable corrective action for ]
i poor human factors practice concerning the inconsistent use of unlighted indicating lights. i 3 HED 660 f l This HED does not include enough description to support the
.j conclusion that corrective action is not needed to correct the "not
)
i
; durable" and inadequate size switch handles. ;) l HED 661 1
The recommendations of this HED do not address the discrepancy of visual obstruction by hand or arm when the switch is operated. j! HED 290 j- The no action HED is justified by stating that operator action will be the same whether temperature is high or low. Th'e' text of this HED should include information to answer the following questions. e Are there other instances in addition to the example described which should be addressed and/or acknowledged? , e Does the instrumentation needed and its location follow good human factors practice? e Do the operator response actions needed follow good human 1 , factors principles? HED 543 The recomendations in this HED do not address the discrepancy. . The following three HEDs are GSU no further action HEDs involving annunciators with which we disagree with the choice of no further action needed for the reasons given. HED 288 This HED should explain the rationale for not taking corrective < action to improve annunciator grouping. l HED 59 This HED should explain the rationale for not relocating the penetration annunciators. HED 451 Recommendations will be satisfactory if the features described are committed to be available and functioning prior to exceeding S percent power.
- 2. Generic Lighting. These HEDs involve survey and evaluation of conditions and implementation of corrective actions. These HEDs state that final
.P River Bend SSER 2 21 Appendix J i<
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light readings will be taken after design changes are implemented, but do "l not comment to implement corrective lighting actions. ; a HEDs 195, 202 j 3. Open or Unresolved HEDs. This HED should include a comitment to correct 4 all deficiencies prior to fuel load. t I j HED 552 I 4 Generic and Specific HEDs Involving Labels and Location Aids (e.g., mimics, color, coding, demarcation, etc.). These HEDs should state an ^ unambiguous commitment to implement label and location aid corrective
-) actions prior to fuel load. Generic corrective actions should be Lo uniformly and consistently implemented throughout the control room. The operators should not be subjected to changes in labels and location aids enhancements during the period of initial reactor start-up operations.
HEDs 82, 238, 76, 113, 128, 239, 72, 109, 110, 203, 313, 129, 73, 111, 294, 74, 112, 315, 104, 317, 224, 509, 11, 297, 574, 79, 320, 826, 15, 227, 86, 270, 665, 423, 46, 474, 14, 83, 210, 226, 792, 303, 769, 302, 440
- 5. Generic and Specific HEDs Involving Annunciators (e.g., tiles, legends, grouping, etc.). These HEDs shoulc state an unambiguous commitment to implement corrective actions prior to fuel load. Generic corrective actions should be uniformly and consistently implemented throughout the control room.
HEDs 304, 444, 98, 328, 289, 329, 282
- 6. Miscellaneous HEDs.
HED 237 The recomendations do not clearly state the specific light colors to be installed on each control. The implementation should be completed prior to fuel load. HED 223 The recommendations should include the rationale for why training is considered to be a satisfactory corrective action instead of rearrangement of switches. HED 319 It is not possible to draw a conclusion about the acceptability of the recommendations because the human factors dimensions / distances are not included to support the recommendation. - HED 439 The corrective action should be impler.:ented prior to fuel load. c River Bend SSER 2 22 Appendix J
APPENDIX X REVIEW OF HUMPHREY CONCERNS River Bend SSER 2 Appendix K
REVIEW OF HUMPHREY CONCERNS In a letter dated May 8, 1982, John Humphrey, a former GE engineer, notified Mississippi Power and Light Company (MP&L) of certain safety concerns regarding the Grand Gulf Mark III containment design. The staff met with MP&L, General Electric Company (GE), and Humphrey to determine the character of these concerns and to establish an appr,opriate program for their resolution. A number of other Mark III plant applicants attended the meeting, including representatives of Gulf States Utilities for the River Bend Station. The staff has reviewed the information supplied by the applicant for the River Bend Station in letters dated February 28, 1984, and January 23, 1985. These letters contain the applicant's responses to all of Humphrey's concerns. Addi-tional sources of relevant documents reviewed by the staff are listed at the end of this report and after the evaluations of selected Humphrey concerns. There are 66 individual Humphrey concerns covering 22 major areas (referred to as Action Plans by the Mark III Containment Owners Group). Table 1 shows the relationship between the individual Humphrey concerns and the Action Plans along with the staff's review status for each of the Humphrey concerns. The body of this report contains a description, evaluation, and staff conclu-sion for each Humphrey concern. The Humphrey concerns that were judged to be not applicable to the River Bend Station, as identified in Table 1, are grouped together at the end of this report. HUMPHREY CONCERNS 1.1, 1.2, 1.4, AND 1.5 1.1 Presence of local encroachments, such as TIP platform, the drywell person-nel airlock, and the equipment and floor drain sumps, may increase the pool swell velocity by as much as 20%. 1.2 Local encroachments in the pcol may cause the bubble breakthrough height to be higher than expected. 1.4 Piping impact loads may be revised as a result of the higher pool swell velocity. 1.5 Impact loads on HCU floor may be imparted and the HCU modules may fail, which could prevent successful scram if the bubble breakthrough height is raised appreciably by local encroachments. Evaluation The applicant's initial response to these concerns was based on a numerical simu-lation of the encroached pool swell process using a General Electric proprietary version of the SOLA-V0P code for fluid flows, the SOLAV. This was basically a River Bend SSER 2 1 Appendix K
7
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t 4-Table 1 Humphrey Concerns Humphrey Mark III CIOG Review Humphrey Mark III CIOG Review Concern Action Plan Status Concern Action Plan Status 1.1 1 Resolved 7.1 13 Resolved
- 1. 2 1 Resolved 7. 2 24 Resolved 1.3 2 Open 7.3 40 Resolved
- 1. 4 2 Resolved 1.5 3 Resolved 8.1 25 Resolved
- 1. 6 4 Resolved 8.2 26 Resolved 1.7 47 Resolved 8.3 26 Resolved 8.4 27 Resolved 2.1 5 Open 2.2 5 Open 9.1 11 Resolved
- 2. 3 5 Open 9. 2 19 Resolved 9.3 28 Resolved 4 3.1 6 Open
- 3. 2 7 Resolved 10.1 23 Resolved 3.3 6 Open 10.2 30 Resolved
- 3. 4 8 Open 3.5. 8 N/A 11.0 31 Resolved 3.6 9 Open
- 3. 7 6 Open 12.0 41 N/A 4.1 10 Resolved 13.0 -
42 N/A i 4.2 11 Resolved 4.3 12 Resolved 14.0 32 N/A 4.4 13 Resolved 4.5 14 - Resolved 15.0 43 N/A ' ~ 4.6 15 Resolved 4.7 16 Resolved 16.0 33 Resolved 4.8 17 N/A , 4.9 18 N/A 17.0 46 N/A 4.10 16 Resolved 18.1 44 Resolved 5.1' 19 Resolved 18.2 44 Resolved 5.2 50 Resolved 5.3 18 N/A 19.1 34 N/A 5.4 20 Resolved 19.2 35 Resolved
- 5. 5 - 21 Resolved 5.6 19 Resolved 20.0 36 Resolved 5.7 48 N/A 5.8 22 Resolved 21.0 49 N/A 6.1 45 Resolved 22.0 37 Resolved 6.2 38 N/A 6.3 23 Resolved ,
6.4- 39 Resolved ,l 6.5 23 Resolved *: l River Bend SSER 2 2 Appendix K
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1 two-dimensional code, and a number of judgments had to be made in deciding how the effect of the actual, three-dimensional bubbles was to be simulated in the two-dimensional model in order to best represent the pool swell process. In addition, some judgment was required in simulating the effect of breakthrough in the unencroached parts of the pool on the pressure in the bubble (s) under the encroached region. The NRC staff did not find the results of these compu-tations sufficient because the results for pool swell velocity, and particularly for pool rise height, were close to values which would be of concern, and, as stated, the computations were based on several modeling judgments whose accu-racy could not be assessed. The applicant's second response was based on a 1/10-scale experimental test program to determine the effect of encroachments on local pool swell, using the scaling methodology (Moody's) which had previously been employed to define Mark I and Mark II pool swell. These simulations were performed under the direction of the Containment Issues Owners Group (CIOG). The River Bend Station (RBS) traversing in-core probe (TIP) platform, which is the only significant encroach-ment in the RBS suppression pool, is very close in geometry to the type C en-croachment tested in the 1/10-scale simulations. (The type C encroachment ex- ~ tended radially to the middle of the pool, and circumferential1y over a distance of 2 cells, a cell being the circumferential distance between two adjacent vent rows.) The small-scale tests showed that for the type C encroachment, the dis-turbance in the pool swell was benign: the encroachment caused a 3- to 4-foot-wide water ligament to be propelled upward along the containment wall opposite the encroachment. However, this ligament broke up, became frothlike and decel-erated as it ascended toward the hydraulic control unit (HCU) floor and virtually came to a stop by the time the froth reached the HCU floor level. The peak ligament velocity was below the accepted design value. The staff judged that the existing acceptance criteria for pool swell loads would bound the loads with a type C encroachment. Conclusion The staff considers issues 1.1, 1.2, 1.4, and 1.5 closed for the River Bend Station because the 1/10-scale simulations showed the RBS pool swell near the TIP platform (the only significant encroachment) to be bounded by existing specifications. HUMPHREY CONCERN 1.3 Additional submerged structure loads may be applied to submerged structures near local encroachments. Evaluation The loads addressed under this item fall into three categories: (1) loads on the drywell wall, (2) loads on the containment wall, and (3) loads on submerged pipes and beams. The first of these, loads on the drywell wall, was specified to be equal to the peak drywell pressure. Even with encroachments, this limit will not be affected. The staff is in agreement with this rationale. ; River Bend SSER 2 3 Appendix K
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The containment wall pressure was found to increase by 15% because of the lar-gest encroachment. The value for this increase was obtained by comparing two-dimensional SOLAV01 calculations for encroached and clean pools. The encroached configuration for these computer runs Cbrresponded to the Grand Gulf Nuclear Station (GGNS) encroachment rather than the RBS. (The RBS encroachment protrudes
- i. out 11' 4" vs. 10' 8" for the GGNS).
~,
+ The staff feels that the RBS encroachment will not cause the containment wall pressure to increase above the current design value of 10 psid. The original
' 10 psid specification is based on full-scale measurements as shown in Fig-ute 38-55 of GESSAR II, where containment pressure differential during bubble formation is plotted against the peak drywell pressure. The 10 psid corresponds to a peak drywell pressure of 36.5 psia in a GESSAR plant. The peak drywell pressure in the RBS is 33.8 psi, which would give a containment pressure differ-ential of approximately 8.5 psid. Thus, the 15% pressure increase from the
! encroachment is compensated by a 15% reduction because of a lower drywell peak pressure. The fact that the SOLAV01 run was made for an encroachment 8 inches shorter than the one in RBS is judged to be balanced by the fact that the cal-culations assume the encroachment extending 360* around the pool, whereas the ' RBS encroachment covers only two vents. With regard to submerged structures, such as beams and pipes, two classes are considered; structures initially above the pool surface and submerged struc-tures. For structures initially sbove the pool surface, the current 60/115 psi impact followed by drag is bounding. The staff is in agreement with that statement. Furthermore, the encroachments were found to lead to lower pool rise velocities in their vicinity (as seen' in motion pictures of scale model tests). Thus, higher loads induced by the encroachments on these structures are not anticipated. For structures that are submerged before pool rise, the RBS response claims that the bubble loads "are bounded by the loss-of-coolant accident (LOCA) vent clearing loads specified as the design basis for River Bend Nuclear Station in GESSAR II." The staff finds this response unacceptable. The only load that is mentioned in GESSAR II during vent clearing is the LOCA water jet load. Fur-thermore, in response to NRC Question 38.1 (see page 380.3.2.1-83 in GESSAR II), it is stated that water jet loads are not specified because they are less than LOCA air bubble loads. If the water jet loads are to be cited as bounding, the staff requires that they be specified so that an assessment can be made. Conclusion The staff considers this an open issue. The utility response with regard to
- wall pressures and loads on structures initially above the pool is acceptable.
The response with regard to loads on submerged structures is unacceptable. HUMPHREY CONCERN 1.6 i Local encroachments on the steam tunnel may cause the pool swell froth to move horizontally and apply lateral loads to the gratings around the HCU floor. River Bend SSER 2 4 Appendix K
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Evaluation The utility has performed a potential flow analysis of the flow field through the HCU floor. This analysis assumed steady flow, i.e. , the liquid droplets had velocities equal to air and all of the froth was allowed to pass through the openings in the HCU floor. The resulting lateral pressures were found to be 0.85 psid on the beams and 0.24 psid on the gratings. The additional stres-ses resulting from these lateral forces were found to be small fractions of the total stresses. The staff concurs with the utility claim that the potential flow analysis is conservative. In fact, independent calculations conducted by the NRC indicate that more than 90% of the froth will continue in the vertical direction, impact on the HCU floor, and lose all its velocity. As the froth begins to fall back toward the pool, the horizontal component of the flowing air will accelerate the froth to some extent, but steady-state conditions are not expected to be attained. Considering that the additional stresses are modest even with a con-servative flow analysis, the staff does not feel that additional effort needs to be expended on this issue. Conclusion The staff concurs with the applicant's evaluation and considers this issue closed. HUMPHREY CONCERN 1.7 GE suggests that at least 1500 square feet of open area should be maintained in the HCU floor. In order to avoid excessive pressure differentials, at least 1500 square feet of open area should be maintained at each containment elevation. Evaluation In the RBS, the requirement for 1500 square feet of open area is satisfied everywhere except at the refueling floor which is at the 186-foot elevation. Here the opening is 689 square feet. The utility has conducted an analysis (using three volume nodes) which indicates that the resulting maximum pressure l differential on this floor is 0.478 psid and the increase in the drywell pres- I sure is 1.49%. l l The staff agrees with the utility that the effect of the smaller than 1500-square-foot openings at the 186-foot level is very small. Since this elevation is 72 feet above the HCU floor and no froth will reach this level, the flow resistance provided by the 689 square fo;t opening to air is very much smaller than the resistance provided by the larger HCU floor opening to the two phase froth. Conclusion The staff considers this issue closed. River Bend SSER 2 5 Appendix K
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l 1 i : HUMPHREY CONCERN 2.1 The annular regions between the safety / relief valve lines and the drywell wall ' penetration sleeves may produce condensation oscillation (CO) frequencies near the drywell and containment wall structural resonance frequencies. t Evaluation The concern exists that additional and unaccounted for suppression pool boundary loads may be produced by steam condensation at the exit of the sleeve annulus. For CO loads the applicant has addressed this concern using the generic approach described in Ref. 2.1.1. This methodology derives sleeve annulus C0 loads from the main vent loads using the scaling laws originally proposed by GE (Ref. 2.1.2). This approach has three weaknesses. First, the analytical basis for the C0 scaling laws was never fully accepted by the NRC staff and its consultants. Acceptance of the main vent C0 load specification was the result of substantial margins that were available to account for uncertainties in scaling of the peak-to peak pressure amplitude (PPA) and C0 frequencies as well as a demonstration that other pool boundary loads (from pool swell and chugging) were generally greater, even allowing for considerable error in scaling predictions (Ref. 2.1.3). Second, these scaling laws were previously applied to vents of similar geometry (circular cross-section) and orientation in the pool (horizontal). Their appli-cability for the sleeve annulus may not be appropriate. Finally, the approach does not account for possible resonance between sleeve annulus C0 frequency and sleeve acoustic frequency as suggested by Humphrey in Reference 2.1.4. This might lead to pressure loads in excess of those developed via the scaling laws. With the exception of this potential resonance effect, the staff judges that the added CO loads proposed by the applicant are acceptable. Because of the relative size of the steam / water interface at the sleeve annulus, the staff would expect that any nonresonant loads that may occur will be second order compared to main vent loads. The judgment applies to both C0 and chugging loads. The added sleeve CO loads proposed by the applicant are substantial. For example, the PPA proposed is about 20% of that used in the main vent load defi-nition. They are also applied uniformly in the circumferential direction which represents a sizable conservatism. This is because there are roughly twice as many main vents as drywell penetration sleeves. These modifications are clearly more than second order. Thus, provided it can be demonstrated that resonant amplification does not occur, the staff concludes that the C0 loads which are specified are adequate. Insofar as the chugging loads are concerned, the staff has not received a description of these, even though this information exists (Ref. 2.1.5) and has been assessed by the Mark III Containment Issues Review Panel (Ref. 2.1.6). The findings of this panel were that the proposed loads were only about 6% of main vent chugging and are easily bounded by design. The staff is satisfied that this is the case. Note that resonance effects are not expected to play any role in or influence the chugging phenomenon associated with the sleeve annulus. , River Bend SSER 2 6 Appendix K
. . . . - - - -. .- .- ~ .. .-
~! Conclusion The staff considers this issue to be closed for chugging loads and for non-resonant CO loads. The issue is still considered open, however, relative to the potential for resonant amplification of the sleeve annulus CO loads. References 2.1.1 MP&L letter No. AECM 82/574) dated December 3, 1982 from L. F. Dale (MP&L) to H. R. Denton (NRC). 2.1.2 General Electric Co., 22A7007, " General Electric Standard Safety Analysis Report" (GESSAR-II), Appendix 3B through Amendment 1, February 25, 1982. 2.1.3 " Mark III LOCA-Related Hydrodynamic Load Definition," NUREG-0978, August 1984. 2.1.4 Humphrey Engineering, Inc., letter dated June 17, 1982 from J. M. ' Humphrey (HEI) to A. Schwencer (NRC). 2.1.5 Enercon letter No. RWE-0G-060 dated May 25, 1983 from R. W. Evans (Enercon) to B. R. Patel (CREARE R & D). 2.1.6 Mark III Containment Issues Review Panel, " Assessment of Humphrey Concerns," CREARE R & D, Inc., Technical Memorandum TM-928, July 1984. HUMPHREY CONCERNS 2.2 AND 2.3 2.2 The potential condensation oscillation and chugging loads produced through the annual area between the safety / relief valve discharge line (SRVDL) and sleeve may apply unaccounted for loads to the SRVDL. Since the SRVDL is unsupported from the quencher to the inside of the drywell wall, this may result in failure of the line. i 2.3 The potential condensation oscillation and chugging loads produced through the annular area between the SRVDL and sleeve may apply unaccounted for loads to the penetration sleeve. The loads may also be at or near the natural frequency of the sleeve. Evaluation The concern is that the steam condensation process (C0 + chugging) at the sleeve annulus exit will give rise to loads on the SRVDL and SRVDL sleeve analogous to the lateral loads experienced by Mark I and Mark II downcomers during postulated LOCA blowdowns and that these structures have not been designed to accommodate them. The applicant states in its submittal (Ref. 2.2.1) that a lateral load of 22 kips is appropriate for this purpose. It is claimed that this load is developed "by scaling the Mark II downcomer lateral load data to the outside diameter of the SRVDL sleeve." It is further asserted that both of these struc-tures are capable of sustaining this load. No further details are provided. River Bend SSER 2 7 Appendix K
For example, the source of the Mark II data base is not cited; also, the pro-cedure used to scale these data is not described; it is not indicated if the load is applied dynamically or statically. Some of these details can be inferred from information supplied in References 2.2.2 and 2.2.3. Staff review of this information leads to the belief that what has been done is to scale down the dynamic lateral load definition for Mark II downcomers that was approved by the staff in 1981 (Ref. 2.2.4). Here again, the applicability of these results for the present concern is somewhat question-able because of substantial geometric differences (straight down vs. inclined pipes, annular vs. circular cross-section). The staff also does not find acceptable the region of application of the load proposed by the applicant. This is because it is not consistent with the scaling procedure used to derive the load magnitude. Finally, the absence of a lateral load specification dur-ing the C0 phase needs justification in view of the use of such a load in Mark I containments. Conclusion The staff considers these issues open. The applicant needs to supply more de-tailed information on the development of this load for staff evaluation. References 2.2.1 Attachment 2 to GSU letter dated January 23, 1985 from J. E. Bocker (GSU) to H. R. Denton (NRC). 2.2.2 Mark III Containment Issues Review Fanel, " Assessment of Humphrey Concerns," CREARE R & D, Inc., Technical Memorandum TM-928, July 1984. 2.2.3 Attachment 1 to CEI letter dated January 5, 1984 from M. R. Edelman (CEI) to B. J. Youngblood (NRC). 2.2.4 " Mark III Containment Program Load Evaluation and Acceptance Criteria," NUREG-0808, August 1981. HUMPHREY CONCERNS 3.1, 3.3, AND 3.7 3.1 The design of the STRIDE did not consider vent clearing, condensation os-cillation, and chugging loads which might be produced by the actuation of the RHR heat exchanger relief valves. 3.3 Discharge from the RHR relief valves may produce bubble discharge or other submerged structure loads on equipment in the suppression pool. 3.7 The concerns related to the RHR heat exchanger relief valve discharge lines should also be addressed for all other relief lines that exhaust into the pool. Evaluation The concern is that, besides the main safety / relief valves (MSRVs), there are a , number of other valves that discharge fluids into the suppression pool. As a -
; River Bend SSER 2 8 Appendix K
result they produce loads analogous to those associated with MSRV discharges and/or LOCA blowdowns through downcomers. These loads have not been accounted for in plant design. The applicant has supplied a plant-unique response for the vent clearing water jet loads and for air bubble loads. Using a combination of analyses and GESSAR guidelines, estimates of these loads were obtained. The applicant states that they are negligible or bounded by design MSRV and LOCA loads. No details of these analyses and procedures are provided. For C0 and chugging loads on the pool boundaries, the applicant utilizes the ge-neric methods employed by all the Mark III utilities. No detailed description of the methodology is supplied by the applicant, but the general features can be discerned from the information supplied in References 3.1.1 and 3.1.2. Generally speaking, the method derives from a conservative application of the Mark II CO and chugging methodologies. The specific application is to the Grand Gulf Nuclear Station (GGNS) RHR heat exchanger relief valve discharge line. Source terms are developed from selected chugs and C0 pressure signatures from the Mark II data base. These are used to generate pressure loads on the GGNS pool boundaries. They are shown to be bounded by design SRV loads. The conservatism in this load specification stems primarily from the use of the selected source strength directly without any reduction to account for the dif-ference in pipe diameter between the RHR heat exchanger relief valve discharge line (10 inches in the GGNS) and that from which the data base derives (24 inches in the test facility). Since the River Bend Station is equipped with an even smaller diameter pipe, the conservatism would be even greater in this case. The adequacy of the C0 load also needs to be judged in the context of the poten-tial for unstable steam condensation; i.e., elevated pool temperatures. The staff's evaluation of this aspect is presented under Humphrey Concern 3.6. The staff does note, however, that according to the applicant, the RBS RHR heat exchanger relief valve discharge lines are equipped with tees. If this is the case, the potential (or unstable steam condensation could be expected to be reduced. Loads that result from other steamline discharges are considered to be bounded by the RHR related loads. In general, this is not unexpected because of lower flow rates and/or smaller discharge line diameter. One exception that may be of concern is the reactor core isolation cooling (RCIC) turbine exhaust dis-charge pipe. In this case, the combination of flow rates and pipe diameter are comparable. Although this line is equipped with a load mitigator (sparger), insufficient justification for ignoring the loads that result from discharges through this line has been provided. Finally, no information has been supplied by the applicant relative to the lat-eral loads experienced by any of the discharge lines. The staff judges that this is probably the most critical omission in terms of design evaluation. Conclusion The issues raised by this set of concerns are considered unresolved. Tl)e com- , plete absence of a lateral load specification for the discharge lines and an
- River Bend SSER 2 9 Appendix K
- --^
_ . . . _ . _ _ _ _ _ _ _ .. . n z_: . . _ __ 4 assessment of their capability to sustain such loads is the most serious of these open issues. However, additional clarification would be appropriate in all of the areas discussed above. The staff will require the applicant to address the staff's concerns outlined above. References 3.1.1 Meeting handouts from NRC/ Mark III/GE meeting of May 19, 20, 1983. 3.1.2 Mark III Containment Issues Review Panel, " Assessment of Humphrey Concerns," CREARE R & D, Inc., Technical Memorandum TM-928, July 1984. HUMPHREY CONCERN 3.2 The STRIDE design provided only 9 inches of submergence above the RHR heat ex-changer relief valve discharge lines at low suppression pool levels. Evaluation Because of the relatively small submergence involved, the concern is that steam condensation may not be complete leading to steam bypass and failure of the pressure suppression system. The applicant has addressed this concern using the generic approach common to all plants. The approach cites the full-scale data from the Humboldt Bay tests where it is shown that, over a wide range of steam flux rate, condensation was complete (i.e., no steam bypass and containment pressurization), even with a clearance of 2 feet between the vertical vent pipe exit and the pool surface. The applicability of this data base to the RBS is somewhat questionable since, by virtue of the tees that have been installed, the steam discharge will be horizontal rather than vertical. It is stated, however, that the minimum sub-mergence of the discharge lines will be about 4 feet. With this submergence and the level of subcooling that would be expected during steam discharges through these lines (see discussion of Concern 3.6), the potential for steam bypass is, in the staff's opinion, nonexistent. Conclusion The staff considers this issue satisfactorily resolved for the RBS based on the large minimum submergence that exists in this plant. HUMPHREY CONCERN 3.4 The RHR heat exchanger relief ~ valve discharge lines are provided with vacuum breakers to prevent negative pressure in the lines when discharging steam is condensed in the pool. If the valves experience repeated actuation, the vacuum breaker sizing may not be adequate to prevent drawing slugs of water back through the discharge piping. These slugs of water may apply impact loads to the relief valve or be discharged back into the pool at the next relief valve actuation and apply impact loads to submerged structures. River Bend SSER 2 10 Appendix K
r __ _ . _ m , _ _ _ _a _ _ . .._ . __ 1 I i
'! I f Evaluation The real issue is that the various steam discharge lines may not have been equipped with properly sized vacuum breakers. This is a credible concern in
- view of the historical development of the same issue for the MSRVs. Because the potential for subsequent actuations was not fully-appreciated in the early stages, the MSRV discharge lines were originally equipped with undersized vacuum breakers. When very high reflood elevations were encountered during tests with subsequent actuation, it became evident that this was so and much larger vacuum breakers were installed (from 1-inch to as much as 10-inch diameter, or 2- to 6-inch diameter).
The applicant states that a reflood analysis was performed to determine worst- i case pipe conditions at the onset of a second actuation. The analysis was done using an existing GE model (Ref. 3.4.1). Details of the assumptions used in l this analysis are not provided. For example, in Ref. 3.4.2, it is stated that credit is taken in this analysis for the so-called bleed flow which keeps the pipe pressurized. One would not know this to be so from the information supplied to the staff. Conclusion This concern has not been resolved. The information that has been supplied does not permit the staff to conclude that a conservative estimate of the potential loads has been obtained. The staff will require the applicant to address the staff concerns outlined above. References 3.4.1 Wheeler, A. J. , Dougherty, D. A. , " Analytical Model for Computing Water Rise in Safety Relief Valve Discharge Line Following Valve Closure," GE Document No. NEDE-23898-P, October 1978. 3.4.2 Mark III Containment Issues Review Panel, " Assessment of Humphrey Con-cerns," CREARE R & D, Inc., Technical Memorandum TM-928, July 1984. 3.4.3 Attachment 1 to CEI letter dated January 5, 1984 from M. R. Edelman (CEI) to B. J. Youngblood (NRC). 3.4.4 Personal communication, CEI/NRC meeting May 2, 1984. HUMPHREY CONCERN 3.6 If the RHR heat exchanger relief valves discharge steam to the upper levels of the suppression pool following a design-basis accident, they will significantly aggravate suppression pool temperature stratification. Evaluation Continuous steaming for an extended period under normal conditions could not only result in excessive containment pressurization via vertical thermal stra-tification but could introduce the potential for unstable steam condensation :. leading to excessive dynamic loading on the pool boundaries. River Bend SSER 2 11 Appendix K
._. _ . . . . ..i A na. _ . _____ . _ _ _ . _ . _ . _
The applicant has addressed this concern via the generic approach which was provided in the MP&L response (Ref. 3.6.1). A demonstrably conservative model of thermal deposition, stratification, and pool mixing was developed and ap-plied using MP&L plant parameters. On the basis of this model, it was shown in Ref. 3.6.2 that even after steaming at the very high flow rate assumed in the analysis, the difference between the average pool surface temperature (131*F) and bulk temperature (107*F) was only about 24F*. The corresponding temperatures and temperature difference for the RBS can be expected to be substantially less. This reduction is because the maximum flow rates through the RBS RHR heat exchanger relief valve discharge line are less than half that of the GGNS and because of the installation of the tees at the end of the discharge pipes (the analysis assumes a straight-down pipe). The staff notes also that the peak temperatures reported are just barely approach-ing levels that might imply unstable steam condensation loads; e.g., about 130*F for a straight-down pipe. Since discharge of steam through a tee is known to improve steam-condensing capability, the staff concludes that this scenario could safely proceed for as much as 20 minutes without the need for any mitigating action. The staff is also satisfied that sufficient time is available to institute a number of actions which would effectively mitigate any adverse effects of this postulated failure. Although the Humphrey concern suggests that these discharges will occur following a design-basis accident (DBA), the analysis referenced by the applicant is based on non-DBA bulk pool temperatures. This assumption implies that operation of the RHR system in the steam-condensing mode will not be allowed following a DBA, or that operation will not be allowed until the peak local and bulk sup-pression pool temperatures have been reduced below the values used in the referenced analysis. For the staff to find this implied assumption acceptable, and therefore the analysis acceptable, the applicant will be required to in-corporate the appropriate procedures and restrictions on operation of the RHR system in the steam-condensing mode into the emergency operating procedures. Conclusion The issue raised by this concern is considered to be satisfactorily resolved for the RBS if the applicant incorporates into the plant emergency operating pro-cedures (E0Ps) the restrictions on operation of the RHR system in the steam-condensing mode detailed above. The basic issue relative to use of the steam-condensing mode, however, is under review. Therefore, this addition to the E0P is contingent on satisfactory resolution of the use of the RHR system in the steam-condensing mode. References 3.6.1 MP&L letter No. AECM-82/574 dated December 3, 1983, from L. F. Dale (MP&L) to H. R. Denton (NRC). 3.6.2 Meeting handout " Response to Question 9.2," NRC/ Mark III/GE Meeting, May 19, 20, 1983. River Bend SSER 2 12 Appendix K
o 4... . . . , S . .. .,.1.. - . - ,- .4 - .a d- m . k -- .e .- _ _ - 3. j* HUMPHREY CONCERN 4.1 The present containment response analyses for drywell break accidents assume that the ECC systems transfer a significant quantity of water from the suppres-sion pool to the lower regions of the drywell through the break. This results
' in a pool in the drywell which is essentially isolated from the suppression pool at a temperature of approximately 135*F. The containment response analysis as-sumes that the drywell pool is thoroughly mixed with the suppression pool. If the inventory in the drywell is assumed to be isolated and the remainder of the
, heat is discharged to the suppression pool, an increase in bulk pool temperature of 10F* may occur.
Evaluation The applicant has performed an analysis using licensing assumptions to calculate what the drywell pool temperature would be if no mixing were to occur with the suppression pool. The initial formation of the drywell pool results from the condensation of steam in the drywell on the drywell heat sinks and emergency core cooling system (ECCS) water spillage and the unflashed portion of the reac-tor vessel blowdown. The temperature of this mixture is calculated to be 231 F, which will result in lower bulk suppression pool temperatures if the drywell pool remains isolated. The FSAR analysis assumes that the drywell pool mixes with the suppression pool and a peak suppression pool temperature of 167.5*F is reached at 4.78 hours after the postulated DBA. Humphrey's concern about the drywell pool being formed at 135 F and the resulting effect on the bulk suppres-sion pool temperature is not valid for RBS. To provide additional evidence that isolation of the drywell pool will not lead to above-design suppression pool temperatures, the applicant has evaluated a different scenario than that postulated by Humphrey that results in the lowest drywell pool temperature. To minimize the drywell pool temperature, the applicant assumed no water storage on the drywell floor until drywell depressurization and subsequent weir wall overflow occurred. Before this time, all unflashed blowdown and heat conden-sate were added directly to the suppression pool. This assumption results in a suppression pool temperature of 155.7 F at the time of drywell depressurization. This represents the minimum temperature of the water that could be isolated on the drywell floor. The increase in the peak suppression pool temperature assum-ing an isolated drywell pool at a temperature of 155.7*F, is 13.5F , or from 167.5*F to 181 F. This increase, based on a set of highly unlikely and conser-vative assumptions, does not result in bulk suppression pool temperatures higher than the design temperature of 185 F. Conclusion - The applicant has shown that the drywell pool temperature, when isolated early as postulated by Humphrey, is higher than the peak suppression pool temperature and therefore will result in lower supppression pool temperatures. Minimizing i the drywell pool temperature on the basis of a different scenario than postu-lated by Humphrey will not result in higher than design suppression pool tem-peratures. Therefore, the staff considers this issue satisfactorily resolved. , River Bend SSER 2 13 Appendix K )
)
___.- -. . . , _ .__ __ . _ . _ ._ ~ ( . =. --.- 2.- ~ w w ..x .. . ~ . - -- . .=-:=~---- i g. 1 ; i! HUMPHREY CONCERNS 4.2 AND 9.1 3 4.2 The existence of the drywell pool is predicated on continuous operation 1 e of the ECCS. The current emergency procedure guidelines require the opera-tors to throttle ECCS operation to maintain vessel level below level 8. Consequently, the drywell pool may never be formed. 9.1 The current FSAR analysis is based on continuous injection of relatively i cool ECCS water into the drywell through a broken pipe following a design basis accident. The EPGs direct the operator to throttle ECCS operation to maintain reactor vessel level at about level 8. Thus, instead of re-leasing relatively cool ECCS water, the break will be releasing saturated steam, which might produce higher containment pressurizations than currently i anticipated. Therefore, the drywell air which would have been drawn back into the drywell will remain in the containment, and higher pressures will j result in both the containment and the drywell. + Evaluation i The applicant has provided a calculation of the containment response assuming no drywell pool is formed and continuous addition of saturated steam to the dry-well. The assumption of no drywell pool being formed is highly conservative since some water would accumulate from heat sink condensate. The limiting break was determined to be a 0.01-square-foot MSLB and the assump-
. tion of continuous steaming results in no air being returned to the drywell from l
' drywell depressurization. The effect of assuming no drywell pool resulted in a peak suppression pool temperature of 178*F, which is below the design value of 185'F. The effect of considering no air return to the drywell and conservatively ' assuming the containment atmosphere temperature is equal to the design suppres-sion pool temperature (185'F) results in a peak containment pressure of 7.3 psig, well below the design value of 15 psig. The effects of steam bypass of the dry- . well because of the long-term pressurization of the drywell is discussed under Humphrey Concern 5.1. ,. The staff has evaluated the assumptions and methodologies used by the applicant and finds them to be acceptable, f Conclusion The assumption of no formation of the drywell pool and no air return to the drywell does not result in higher than design results for the RBS. The staff ' considers this issue satisfactorily resolved for the RBS. .., HUMPHREY CONCERN 4.3 E All Mark III ana.yses presently assume a perfectly mixed uniform suppression pool. These analyses assume that the temperature of the suction to the RHR heat exchangers is the same as the bulk pool temperature. In actuality, the
' temperature in the lower part of the pool where the suction is located will be as much as 71F* s cooler than the bulk pool temperature. Thus, the heat transfer
- -through the RHR heat exchanger will be less than expected. ,
i , River Bend SSER 2 14 Appendix K
~.ap
_ . - 1 1.-_._ . _ L _ _ _ _i . . _ . . - - - - a- _ _ - - - - . - - . - - - Evaluation To complete the statement of this concern, the following should be added: "and containment pressure and temperature greater than expected." Humphrey's basis for expecting a temperature difference of up to 7 F* is un-clear. The staff agrees that in the event of a postulated LOCA, the reality will be a thermally stratified pool. However, to decide what is the difference between bulk and RHR suction temperature requires an estimate of the degree of vertical stratification that will occur, together with knowledge of RHR suction elevation. The first of these requirements was established to the staff's satisfaction during its evaluation of the GESSAR II containment loads (Ref. 4.3.1). After a lengthy and detailed review process by the various interested parties (Ref. 4.3.2), the worst-case vertical temperature profile proposed by the General Electric Company for design (Fig. 3BI-3 of Ref. 4.3.3) was judged ac-ceptable. The basis for this judgment is given in Ref. 4.3.1. It implies that the profile is applicable only for a standard top vent submergence (s7.5 feet). In responding to Humphrey Concerns 4.7 and 4.10 (below), the applicant indi-cates that the_RBS RHR suction is located at an elevation 3' 4-3/4" above the basemat. Comparison with the temperature profile referred to above implies a temperature difference (bulk-to-RHR suction) of about 10F*. This exceeds the value cited by Humphrey. On the other handy.for the GGNS with RHR suction elevation of 10' 6", a conservative temperature difference of about 6F* pre-vails; i.ei, RHR suction temperature is greater than bulk temperature. The applicant has indicated that RBS containment response analysis assumes RHR suction temperature to be 5F* less than the bulk pool temperature. This reduces the nonconservatism to only 5F*. The staff also notes (Ref. 4.3.4) that the RBS main vent vertical spacing is greater than standard, bringing the bottom vent in closer proximity to the basemat (2k feet vs. 4 feet for the standard plant). The staff would expect this to lead to a flatter vertical temperature profile; i.e., higher temperatures at lower elevations. Also, the staff is satisfied that RHR operation will be very effective in reducing vertical strati-fication. This is based on the results observed during in plant SRV tests in which RHR operation was involved (Refs. 4.3.5 and 4.3.6). In fact, during the Kuosheng tests (Ref. 4.3.6), it was found that RHR operation induces a favorable radial temperature stratification. That is, higher temperature fluid is direc-ted by the swirling motion toward the containment walls where the RHR suction strainers are typically located. For these reasons, as well as the margins that have been demonstrated to exist in heat exchanger performance Ref. 4.3.7), the staff concludes that the RBS analysis does conservatively estimate the con-tainment response despite the existence of vertical temperature stratification induced by LOCA blowdowns. Conclusion The staff considers this issue satisfactorily resolved for the RBS. River Bend SSER 2 15 Appendix K d'
. :__ _..I,.-
_l. l j References 4.3.1 " Mark III Containment Program Load Evaluation and Acceptance Criteria," NUREG-0808, August 1981. 4.3.2 Transcript of the ACRS Subcommittee on Fluid Hydraulic Dynamic Effects Meeting of September 24, 25, 1981.
; 4.3.3 General Electric Co., 22A707, " General Electric Standard Safety Anal- '4 ysis Report," (GESSAR-II), Appendix 3B through Amendment 1, February 25, 1982.
4.3.4 Gulf States Utilities Co., " River Bend Station Final Safety Assessment
];l Report - Appendix 6A," November 1984.
4.3.5 Patterson, B. J., " Mark I Containment Program, Monticello T-Quenchers Thermal Mixing Test - Final Report," General Electric Co. Report NEDE-24542-P, April 1979. 4.3.6 NUTECH International " Final Test Report - Safety Relief Valve Dis-charge Test - Kuosheng Nuclear Power Station," Report ZTP-06-310, Rev. O, August 1982. 4.3.7 MP&L letter No. AECM-82/353 dated August 19, 1982, from L. F. Dale (MP&L) to H. R. Denton (NRC). HUMPHREY CONCERNS 4.4 AND 7.1 4.4 The long-term analysis of containment pressure / temperature response assumes that the wetwell airspace is in thermal equilibrium with the suppression pool water at all times. The calculated bulk pool temperature is used to determine the airspace temperature. If pool thermal stratification were considered, the surface temperature, which is in direct contact with the airspace, would be higher. Therefore, the airspace temperature (and pres-sure) would be higher. 7.1 The containment is assumed to be in thermal equilibrium with a perfectly mixed, uniform temperature suppression pool. As noted under Topic 4, the surface temperature of the pool will be higher than the bulk pool tempera-ture. This may produce higher-than-expected containment temperatures and pressures. Evaluation The RBS analysis assumes that the surface temperature of the suppression pool is 5F greater than the bulk pool temperature. The actual amount of thermal stratification expected at RBS with the RHR system in operation will be less than this temperature difference. Additional assurance that this concern does not represent a significant safety hazard is the large pressure margin in the containment pressure. The design pressure is 15 psig; the maximum calculated pressure is 7.3 psig (from Humphrey Concerns 4.2 and 9.1). River Bend SSER 2 16 Appendix K n -
, _ - ~
, - . . . - - - . . -~ - . . . .
'i
'1-
-4 Conclusion
, The staff considers this issue satisfactorily resolved for the RBS.
, HUMPHREY CONCERN 4.5
'A number of factors may aggravate suppression pool thermal stratification. The
.J chugging produced through the first row of horizontal. vents will not produce any
' mixing from the suppression pool layers below the vent row. An upper pool dump
^ may contribute to additional suppression pool temperature stratification. The large volume of water from the upper pool further submerges RHR heat exchanger effluent discharge which will decrease mixing of the hotter, upper regions of
- the pool. Finally, operation of the containment spray eliminates the heat ex-changer effluent discharge jet which contributes to mixing.
Evaluation The applicant has indicated that the RBS design does not incorporate an upper pool dump or containment sprays. In the absence of these design features, this
- concern reduces to that expressed in Humphrey Concerns 4.3 and 4.4.
Conclusion , The staff considers this issue satisfactorily resolved for the'RBS based on the discussion provided for Humphrey Concerns 4.3 and 4.4. HUMPHREY CONCERN 4.6 The initial suppression pool temperature is assumed to be 95*F; the maximum expected service water temperature is 90*F for all GGNS accident analyses as noted in FSAR Table 6.2-50. If the service water temperature is consistently higher than expected, as occurred at Kuosheng, the RHR system may be required to operate nearly continuously in order to maintain suppression pool tempera-ture at or below the maximum permissible value. Evaluation The RBS FSAR analysis uses an initial suppression pool temperature of 100*F and a service water temperature of 95*F. The worst-case maximum standby service water temperature is 90*F for RBS, as described in FSAR Section 9. , During the normal plant operation (excluding test conditions), the only possible mechanism for raising the pool temperature is leakage through the main steam safety / relief valves. A simplified suppression pool heatup analysis assuming 20-lb/hr steam leakage from each of the 16 main steam safety / relief valves was performed by the applicant. The results of the analysis show that it takes 4.4 days to raise the pool temperature from 100*F to 105*F and 2.25 hours for
- the RHR system (with 95*F service water temperature) to cool the pool back down to 100*F.
The staff has reviewed the initial conditions, assumptions, and analysis tech-niques utilized by the applicant with regard to this issue, and concludes that ,' the RHR system is capable of maintaining the suppression pool temperatures -
; River Bend SSER 2 17 Appendix K l
below its Technical Specification value with only intermittent usage even under the most severe normal operating conditions. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERNS 4.7 AND 4.10 4.7 All analyses completed for the Mark III are generic in nature and do not consider plant-specific interactions of the RHR suppression pool suction and discharge. 4.10 Justify that the current arrangement of the discharge and suction points of the pool cooling system maximizes pool mixing. Evaluation The concern is that if the RHR system's geometric arrangement for the suction and return lines is not properly designed, the capability of the system to in-duce bulk mixing and remove thermal energy will be degraded. The applicant has addressed these concerns via the generic approach developed for the Mark III Containment Issues Group (Ref. 4.7.1). The key element of this study was the Perry one-tenth-scale tests (Ref. 4.7.2). In these tests, a number of concerns were addressed systematically. These included short cir-cuiting, development of bulk pool motion, ability to eliminate thermal strati-fication and the presence of isolated recirculation zones. The staff and its consultants have reviewed this information in detail and have concluded that the Perry one-tenth-scale tests correctly simulate design condi-tions in Mark III plants, including a sufficient range of parameters to encompass the RBS plant-unique features, and are therefore applicable. Since the findings from these tests show that good mixing can be achieved, as well as the absence of short circuiting, the staff concludes that the RBS RHR system can be expected to perform in a manner consistent with design assumptions. Conclusion The staff considers the issues raised by these concerns to be satisfactorily resolved for the RBS. References 4.7.1 Quadrex Corp., "A Survey of Tests and Analyses on the Effectiveness of the RHR system in the Pool Cooling Mode," Report No. QUAD-1-82-245, Rev. A, November 1982. 4.7.2 Gilbert Associates, Inc. , "Model Study of Perry Nuclear Power Plant Suppression Pool - Final Report," November 1977. River Bend SSER 2 18 Appendix K
_ _ _ . . _ . . ._._ _ . _ -._ _ - . . - . - . . _ _ _ ~ _ . HUMPHREY CONCERN 5.1 The worst case of drywell-to-containment bypass leakage has been established as a small-break accident. An intermediate-break accident will actually pro-duce the most significant drywell-to-containment leakage before initiation of containment sprays. Evaluation The staff requires each Mark III applicant, including the River Bend applicant, to consider the entire spectrum of break sizes in its analysis of the drywell steam bypass issue. The resulting worst case for the River Bend containment design was a 0.1-square-foot MSLB, which is in the small-break-size range. The staff is satisfied that the entire range of break sizes has been considered by the applicant in evaluating the consequences of drywell steam bypass. In addition, the lack of containmtnt sprays makes this Humphrey issue less relevant for River Bend than for other Mark III plants. Conclusion i The staff considers this issue closed for the River Bend Station. Further details of the staff's evaluation of this topic are contained in Section 6.2.1.7 of the SER. HUMPHREY CONCERN 5.2 Under Technical Specification limits, bypass leakage corresponding to A//E = 0.1 square foot constitutes acceptable operating conditions. Smaller-than-IBA-sized breaks can maintain break f. low into the drywell for long time periods, however, because the reactor vessel would be depressurized over a 6-hour period. Given, for example, an SBA with A//R = 0.1, projected 15 psig is 2 hours. In the latter 4 hours of the depressurization, the containment would presumably experience ever-increasing overpressurization. Evaluation The active heat removal systems at RBS (containment air coolers) are designed to remove the heat addition to the containment from drywell steam bypass leak-ages corresponding to A//E = 1.1 square feet, ten times higher than the Tech-nical Specification value. Both the short-term and long-term effects of dry-well steam bypass were evaluated by the applicant and reviewed by the staff, and found acceptable. In addition, the operator is instructed to initiate rapid reactor vessel depressurization and eliminate the driving pressure for steam bypass if the containmsnt pressure increases beyond acceptable limits. Conclusion The staff considers this issue satisfactorily resolved for the RBS. Further details of the staff's evaluation of this topic are contained in Section 6.2.1.7 of the SER. River Bend SSER 2 19 Appendix K
,. + ,
_- . _.__ - .. -._.-_.._-a-._ _ . _ _ _ _ - . . _ . _ _ - . _ . .. . ~ C
'i HUMPHREY CONCERN 5.4 ,,
Direct leakage fros' the drywell to the containment may dissipate hydrogen out-side the region where the hydrogen recombiners take suction. The anticipated
. leakage exceeds the capacity of the drywell purge compressors. This could lead to pocketing of hydrogen exceeding the concentration limit of 4% by volume.
. Evaluation The River Bend design does not rely on drywell purge compressors to pressurize the drywell and force any hydrogen generated in the core into the containment.
Instead, two mixing system. trains allow air to flow into the drywell from the containment through lines located just above the suppression pool, thus equaliz-ing any pressure difference between the drywell and containment. The drywell air is exhausted into the containment through two other penetrations located at
'. the top of tne'drywell by means of two recirculation fans. Since the mixing systems will be initiated before the drywell hydrogen concentration reaches 4%
by volume, there will be no possibility of hydrogen pockets forming in the con-gp tainment from drywell bypass leak paths exceeding 4% by volume. Conclusion The' staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN,5.5 Equipment may be ' exposed to local conditions which exceed the environmental qualification envelope as a result of direct drywell-to-containment bypass leakage. . J Evaltation Following a LOCA or MSLB, the drywell temperature can reach temperatures in ex-excess of 300*F. The concern is that this superheated air / steam gas could pass through drywell bypass leakage paths and impinge on safety-related equipment located in the containment near the drywell wall. The applicant has provided a list of the safety related equipment within 10 feet of the drywell electrical
'/l penetrations, which are the bypass paths assumed to exist for this analysis.
The applicant has determined that those equipment items not qualified for the drywell temperature profile are located at least 3 feet from the drywell pene-trations and on or below the elevation of the drywell penetrations. This mini-4 i' mum spacing will be more than sufficient, according to the applicant, to diffuse
- any drywell air passing through the 5-inch-diameter electrical penetrations filled with cable in the 5-foot-thick drywell wall.
The staff agrees that there will be a considerable amount of cooling of the dry-
- well air as it passes through the postulated drywell leakage paths because of the
~ thickness of the wall and the relatively small leakage areas that could conceiv-ably occur. The drywell concrete wall, including the drywell wall penetrations, is designed to be a leaktight barrier under all accident conditions and to direct
. the steam produced by a LOCA or MSLB into the suppression pool. Thus, the staff does not believe it credible to postulate large cracks in the drywell wall or 4
River Bend SSER 2 20 Appendix K i
-- ,,,, .- , -,--c. -~~-,-
y ._
, ___ . . ___ ._.s.* - .- a- _ - - '
-a -- -
a around penetrations that could lead to significant amounts of drywell air to enter the containment at the superheated temperatures postulated by Humphrey. The information s o mitted by the applicant, relative to the location and quali-fication criteria for safety related equipment located near the drywell electri-cal penetrations, provides additional assurance that there will be no adverse { i effects on the safety of the plant because of the local high temperature effects from steam bypass postulated by Humphrey. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERNS 5.6 AND 9.2 l 5.6 The test pressure of 3 psig specified for the periodic operational drywell leakage rate tests does not reflect additional presse-ization in the dry-well which will result from upper pool dump. This pressure also does not reflect additional drywell pressurization resulting from throttling of the ECCS to maintain vessel level which is required by the current EPGs. 9.2 The continuous steaming produced by throttling the ECCS flow will cause increased direct leakage from the drywell to the containment. This could result in increased containment pressures. Evaluation These concerns are only partially applicable to RBS because there is no upper pool in the RBS containment. Humphrey's concern regarding the additional drywell pressurization resulting from the continuous steaming from throttling the ECCS has been included implicitly in the FSAR analysis. The FSAR analysis, as evaluated by the staff in Section 6.2.1.7, of the SER, assumes continuous steam flow through the postulated drywell leakage path in the long-term drywell bypass analysis. Conclusion On the basis of the discussion provided above, the staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 5.8 The possibility of high temperatures in the drywell without reaching the 2 psig I high pressure scram level because of bypass leakage through the drywell wall should be addressed. Evaluation The concern is that bypass leakage from the drywell during a transient that adds heat to the drywell (e.g. , a small MSLB) will reduce the drywell atmospheric mass, thus allowi.,g high temperatures to exist without actuating the automatic reactor scram signels. The net result could be higher than design temperatures River Bend SSER 2 21 Appendix K
7
- - - a a- . . w w ~ ~ - - - . . - '--l -~ua -- -- .. a --
1
' inside the drywell before actions are performed to mitigate the accident conse-quences.
The applicant has considered a spectrum of break sizes and assumptions in its analysis of this issue. The MSLB sizes analyzed ranged from 0.0008 square foot to 0.1 square foot and the assumptions included an A/# = 1.5 square feet pure or homogenous flow through the bypass path, and 8% or 100% revaporization of steam condensate from the drywell heat sinks. The worst case was a 0.1 square-foot MSLB with pure steam flow and 100% revaporization. This break size re-suited in a 2 psig scram signal generated at 3.7 seconds into the accident and the maximum calculated temperature of 251*F occurred at 1940 seconds into the accident. The 0.0008-square-foot break size assuming homogenous flow and 8% revaporization resulted in a 2 psig scram signal at about 10 minutes into the accident and a peak temperature of 221*F at about 30 minutes into the accident. I Conclusion The staff is satisifed that higher than design temperatures will not occur for any credible size bypass leakge path (the A/# = 1.15 square foot value used by the applicant is a factor of 10 greater than the Technical Specification value). Therefore, the staff considers this issue satisfactorily resolved for i the RBS. HUMPHREY CONCERN 6.1 GE had recommended that the drywell purge compressors and the hydrogen recom-biners be activated if the reactor vessel water level should drop to within 1 foot of the top of active fuel. This requirement was not incorporated in the emergency procedure guidelines. - Evaluation ' The current emergency operating procedures for design-basis accidents, as ap-proved by the staff, requires the control room operators to initiate the dry-well mixer system when the drywell hydrogen concentration reaches 3% by volume. The concern raised by Humphrey has an involved history that is fully explained in the Mark III Containment Issue Review Panel's report. Basically, this recom-mendation originated during informal discussions held between GE and the NRC staff in 1981 on how to ensure timely initiation of the drywell purge compres- , sors. At that time, the staff had expressed concerns relative to the hydrogen monitoring system's ability to measure the hydrogen concentration when the dry- 4 well atmosphere consisted of all steam (see Humphrey Concern 6.4 below). The I recommendation outlined in this Humphrey concern was a proposed "fix" to the problem. However, none of the Mark III plants utilize hydrogen monitoring sys-tems that have the limitation of the GE hydrogen monitors. Therefore, this recommendation to initiate the drywell compressors based on the reactor vessel water level is no longer relevant to the design-basis-accident hydrogen control issue. Conclusion The staff considers thi:, issue satisfactorily resolved for the RBS. River Bend SSER 2 22 Appendix K
- 7. . - . a - .- - . ~ u.- n.. - -
,Eh j - i j 4 j q HUMPHREY CONCERNS 6.3 AND 6.5 g-4 6.3 The recombiners may produce " hot spots" near the recombiner exhausts that might exceed the environmental qualification envelope or the containment fp, design temperature. 6.5 Discuss the possibility of local temperatures owing to recombiner operation
' being higher than the temperature qualification profiles for equipment in the region around and above the recombiners. State what instructions, if any, are available to the operator to actuate containment sprays to keep
- this temperature below design values.
Evaluation The applicant has reviewed the equipment arrangements at the River Bend Station and states that no safety-related equipment is located in the vicinity of the recombiners. In addition, the temperature of the recombiner exhaust will be-50F* higher than the ambient temperature, which should be around 90*F by the time the hydrogen recombiners would be needed (13 days after a design-basis accident). The applicant has also calculated the bulk temperature rise inside the contain-ment from recombiner operation, considering the mitigating effects of the con-tainment air coolers and heat sinks. The temperature rise due to the operation of both recombiners is less than 3F*. It should be noted that the Mark III Containment Issue Review Panel (Ref. 2) considers the bulk temperature increase an open issue for River Bend, Grand Gulf, and Perry because of informal information transmitted to Panel members after it was too late to be formally reviewed. This informal information revised the earlier calculations of the bulk temperature increase (2F* to 3F*) up to 20* to 30*F. The staff has discussed this panel concern with the applicant and is satisfied that the 3F" bulk temperature rise contained in Ref. 1 is correct. The main reason for the low temperature rise for the River Bend case is the continuous operation of the containment air coolers. The other plants have spray systems, which are not operated continuously. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 6.4
~
For the containment air monitoring system furnished by GE, the analyzers are not capable of measuring hydrogen concentration at volumetric steam concentrations above 60L Effective measurement is precluded by condensation of steam i in the equipment. Evaluation The RBS hydrogen analyzers are not supplied by GE and condensation of steam in I the monitoring lines is precluded by heat tracing. Therefore, the concern River Bend SSER 2 23 Appendix K
t raised by Humphrey is satisfied by the River Bend hydrogen analyzer system design. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 7.2 The computer code used by GE to calculate environmental qualification parameters considers heat transfer from the suppression pool surface to the containment atmosphere. This is not in accordance with the existing licensing basis for Mark III environmental qualification. Additionally, the bulk suppression pool temperature was used in the analysis instead of the suppression pool surface temperate.*e. Evaluation The GE containment response computer code, SHEX, was only used to identify the margins in the results of using the staff's environmental qualification profile methodology contained in NUREG-0588. All Mark III plants, including River Bend, have used the NUREG-0588 qualification parameters in the development of plant-unique environmental qualification curves, which the staff finds acceptable. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 7.3 The analysis assumes that the containment air space is in thermal equilibrium with the suppression pool. In the short term, this is nonconservative for the Mark III containment design due to adiabatic compression effects and finite time required for heat and mass to be transferred between the pool and containment volumes. Evaluation The applicant has stated that the adiabatic compression effects were accounted for in the RBS containment response analysis. In addition, the adiabatic compression effect (calculated to be about 0.5 psi by MP&L for Grand Gulf) occurs early in the DBA transient when the pressures is considerably lower than the long-term pressures which control the containment pressure design.
. Conclusion The staff considers this issue satisfactorily resolved for the RBS.
HUMPHREY CONCERN 8.1 This issue is based on consideration that some Technical Specifications allow operation at parameter values that differ from the values used in assumptions , River Bend SSER 2 24 Appendix K
=
\
- _ . _ .__e__
.i for FSAR transient analyses. Normally, analyses are done assuming a nominal containment pressure equal to ambient (0 psig) and a temperature near maximum ; operating temperature (90*F) and do not limit the drywell pressure equal to ' the containment pressure. The Technical Specifications permit operation under conditions such as a positive containment pressure (1.5 psig) and temperatures less than maximum (60 F or 70 F), and drywell pressure can be negative with re-spect to the containment (-0.5 psid). All of these differences would result in transient responses different from the FSAR descriptions. Evaluation The basic question raised by Mr. Humphrey here is, have all the worst-case combinations of initial conditions been considered in the FSAR analysis. The staff has considered the effect; of initial conditions on the end results of various accidents for many years and has developed criteria for evaluating the initial conditions selected by nuclear power plant applicants. Basically, the staff's approach to this concern can be summarized as follows: (1) Numerous analyses using computer codes developed to predict the plant response to various accident scenarios have shown which initial con-dition variations have a strong effect on the end results. (2) If the initial conditions have a significant impact on the end results, then the staff requires that the most limiting value be used in the ana-lysis. An example of this is the use of zero relative humidity in sub-compartment analysis. (3) If the initial conditions do not have much of an impact on the end results, the staff requests that the applicant use generally conservative values or expected values for the initial conditions. An example of this would be the effect of initial drywell temperatures on the peak calculated drywell temperatures. (4) The margins that exist between the peak calculated values and the design values are intended, in part, to account for the uncertainties in the as-sumptions and analytical techniques utilized in the response analysis, including toe uncertainties inherent in the initial conditions. In direct response to Humphrey's concern, the applicant has performed a compu-ter analysis of the drywell and containment pressure / temperature response to different values of initial drywell pressures and containment temperatures. This analysis, which is presented in Ref. 1, confirms the staff's opinion on the small impact that varying these initial conditions will have.on the end result. Increasing the drywell initial pressure by 2 psi results in only a 0.6 psi increase in the peak drywell pressure and a 0.3 psi increase in the peak containment pressure. Similar results were obtained by varying the ini-tial containment temperature by 20F . Conclusion The staff considers this issue satisfactorily resolved for the RBS. River Bend SSER 2 25 Appendix K
~
.- w . _. :_
HUMPHREY CONCERNS 8.2 AND 8.3 The draft GGNS Technical Specifications permit operation of the plant with con-tainment pressure ranging between 0 and -2 psig. Initiation of containment spray at a pressure of -2 psig may reduce the containment pressure by an addi-tional 2 psig, which could lead to buckling and failures in the containment liner plate. If the containment is maintained at -2 psig, the top row of vents could admit blowdown to the suppression pool during an SBA without a LOCA signal being developed. Evaluation The proposed RBS Technical Specifications limit the containment pressure range to between -0.3 psig and +0.3 psig. Although the RBS containment does not uti-lize sprays, the applicant has evaluated the consequences of inadvertent air cooler operation on the containment negative design pressure. This evaluation is addressed in Section 6.2.1.5 of the SER and also under Humphrey Concern 8.4 below. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 8.4 Describe all of the possible methods, both before and after an accident, of creating a condition of low air mass inside the containment. Discuss the effects on the containment design external pressure of actuating the contain-ment sprays. Evaluation Although the RBS does not utilize containment sprays, the effect of inadvertent containment air cooler operation on the containment external design pressure has been evaluated. This evaluation is contained in Section 6.2.1.5 of the SER, with the exception of the effect of assuming purge operations concurrent with the negative pressure scenarios. The effect of purge operations on the contain-ment external pressure evaluation is discussed below. The applicant has identified the scenario of a reactor water cleanup (RWCU) line break inside the containment with the purge exhaust operating and no purge supply as the bounding case for the external design containment pressure issue. For this case, operator action is required to isolate the drywell exhaust with-in 100 seconds after the RWCU line break to keep this final containment pres-sure within the design pressure of -0.6 psig. To prevent the reduction of con-tainment air mass via the purge exhaust line, the applicant has committed to modify the purge system operation logic to prevent inadvertent closure of the purge supply line with exhaust continuing. The staff also notes that the high radiation isolation signal to the purge supply and exhaust valves should close these valves within 100 seconds following an RWCU line break. ; River Bend SSER 2 26 Appendix K ; I
~ ~ ^
- a. ; - -. . -, -. .- w. - %: .- :. - - .
2 4 On the basis of the proposed design change to prevent purge exhaust operation without purge supply operation, and the isolation valve closure on a high radia-
-tion condition inside the containment, the staff considers this issue resolved.
Conclusion On the basis of the evaluation contained above and the staff's general evalua-tion of this issue in Section 6.2.1.5 of the SER, the staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 9.3 It appears that some confusion exists as to whether SBAs and stuck-open SRV accidents are treated as transients or design-basis accidents. Clarify how they are treated, and indicate whether the initial conditions were set at nominal or licensing values. Evaluation The applicant has stated that small-break accidents (SBAs) and stuck-open SRV accidents are treated as design-basis accidents. The initial conditions used in the analysis of these accidents are the same conservative licensing values used for the double ended rupture of a recirculation pipe. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 10.1 The suppression pool may overflow from the weir wall when the upper pool is dumped into the suppression pool. Alternatively, negative pressure between the drywell and the containment that occurs as a result of normal operation or sudden containment pressurization could produce a similar overflow. Any cold water spilling into the drywell and striking hot equipment may produce thermal failures. Evaluation This concern is only partially applicable to the RBS containment design since there is no upper pool at this facility. The applicant has analyzed the consequences of a sudden containment pressurization (e.g., an RWCU line break) on the weir wall overflow issue. The results of the analysis show that the peak differential pressure between the containment and drywell, assuming nominal initial conditions, will not cause overflow of the weir wall. The operator can relieve the differential pressure by opening the inlet valves of the drywell mixing system. The applicant has also provided a fatigue analysis performed by GE that shows no damage to the extent of a LOCA inside the drywell occurring even if drywell flooding is postulated. The staff has reviewed the containment pressurization analysis performed by the
-applicant and concludes that the assumptions and methodology used are reasonable.
River Bend SSER 2 27 Appendix K
,. . _ _ _J. __. . _.m _ -_.__.u. " %.i- _ _ . _ _ _ .__
s_. _,_ 2 1 4
- The fatigue ana7ysis performed by GE, while not reviewed in detail by the staff, provides additional assurance that this Humphrey concern will not cause opera-8 tional difficulties at the RBS.
Conclusion <I The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 10.2 Describe the interface requirement (A42) that specifies that no flooding of the drywell shall occur. Describe your intended methods to follow t5is interface. Evaluation It is the staff's understanding (shared by the industry) that this Humphrey con-cern refers to the ability of Mark III containments to avoid drywell flooding if the upper pool should be inadvertently dumped into the suppression pool. Since the RBS does not have an upper pool, this concern is not applicable to this plant. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 11.0 Mark III load definitions are based upon the levels in the suppression pool and the drywell weir annulus being the same. The GGNS Technical Specifications permit elevation differences between these pools. This may affect load defini-tion for vent clearing. Evaluation The applicant has evaluated the effect of having a higher initial pressure in the containment than in the drywell on the load definitions for vent clearing. For pressure differentials in the other direction, the staff agrees that the vent clearing loads will be less severe than normal because the vents will clear sooner. The applicant's analysis assumed that the initial differential pressure was equal to the Technical Specification value of 0.3 psid; this results in the weir annulus water being almost 8 inches higher than normal. The effect of this elevated water surface is to delay the vent clearing process by approxi-mately 0.04 second and increase the peak drywell pressure by 0.74 psi. The peak drywell pressure calculated by the applicant was less than 20 psid. The changes in the drywell pressure change the driving conditions for submerged structure bubble loads and pool swell loads. However, not only is the change in peak drywell pressure small, it also remains less than the 21.8 psid value The usedbyGEtoderivethegenericLOCA-relatedhydrodynamicloadcriteriabges staff concludes, therefore, that this concern will not result in any cha , to the design loading criteria used at RBS. River Bend SSER 2 28 Appendix K
- b
_ _ _ _. _ .x u . . _ _ _ - ._ _ __. _. _ l 1 I Conclusion 3 The staff considers this issue satisfactorily resolved for the RBS.
- HUMPHREY CONCERN 16.0 Some of the suppression pool temperature sensors are located (by GE recommenda-tion) 3 inches to 12 inches below the pool surface to provide early warning of high pool temperature. However, if the suppression pool is drawn down below the level of the temperature sensors, the operator could be misled by erroneous readings, and the required safety action could be delayed.
Evaluation The applicant has committed to include in the RBS emergency procedures to either require the operator to verify level in the suppression pool before reading suppression pool temperature or to specify which suppression pool temperature instruments can be used following an accident. The staff believes either of these approaches will prevent erroneous readings on the part of the operator, and therefore, are acceptable. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 18.1 Failures of reflective insulation in the drywell may lead to blockage of the gratings above the weir annulus. This may increase the pressure required in the drywell to clear the first row of drywell. vents and perturb the existing load definitions. Evaluation The gratings in the RBS drywell are located 3.75 feet above the top of the weir wall. This clearance provides a vent area of 707 square feet. The weir annu-lus flow area is 515.5 square feet. Therefore, even if the grating area was somehow entirely covered with insulation debris, the steam / air flow from the drywell to the suppression pool following a postulated LOCA would not be sig-nificantly affected, since the flow area between the gratings and the top of the weir wall is greater than the weir annulus flow area. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 18.2 1 Insulation debris may be transported through the vents in the drywell wall into the suppression pool. This debris could then cause blockage of the suction strainers. River Bend SSER 2 29 Appendix K , i i: i
. I
- a. .s.a. = - -. - - . . . - - . -
Evaluation The staff has performed a. detailed evaluation of the potential for debris blockage of the ECCS suction strainers and the resulting effects. This evalua-tion is presented in Section 6.2.2 and Appendix C of the RBS SER. The conclu-sfon reached l'y the staff in Appendix C is that there is reasonable assurance that RBS can be operated before the ultimate resolution of Unresolved Safety Issue (USI) Task 43 without endangering the health and safety of the public. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 19.2 The effect of local encroachments on chugging loads needs to be addressed. Evaluation The applicant's response to this concern is the generic one which was originally provided by MP&L for the GGNS via Ref. 19.2.1. In this submittal, physical arguments and analytical procedures are used to estimate the pressure field that would be generated on the suppression pool boundaries if the worst-case chug from the Mark III data base were to occur at vents located below the GGNS TIP platform. The results are compared with design on an ARS basis and shown to be bounded except for local loads in the frequency range 12 to 30 Hz. For these conditions an exceedance of design amounting to 60% occurs on the basemat. The applicant argues that this exceedance is not important because this is a local load affecting only the basemat liner and that because of the hydrostatic head to which the ifner is subjected, it will not experience a " negative pres-sure in the frequency range of exceedance." Also, "since the liner is backed by concrete everywhere, no natural modes in this range are excitable." Without passing judgment on the merits of these arguments, the staff notes the following: the loads developed for GGNS are conservative for the RBS; as indi-cated in their respective responses to Humphrey Concern 1.0, the.GGNS has the largest encroachment and the RBS the smallest: the use of an acoustic model in the analysis represents a significant conservatism; dissipative mechanisms not accounted for in such an analysis result in pressure attenuation which is much greater than predicted; this has been borne out convincingly by experimental re-sults: application of the worst-case chug to all vents below the encroachment also represents a very significant conservatism; in a recent submittal by CEI to address the staff concern relative to the combined effect of upper pool dump and encroachment on local chugging loads (Ref.19.2.2), it was shown that by postulating a maximum strength chug at the central vent and average strength chug at adjacent vents, the design loads were capable of bounding the combined offect. In summary, the margins inherent in the design load for chugging are very large. They can more than accommodate any increment in loading caused by off-design effects such as encroachment. ; River Bend SSER 2 , 30 Appendix K
. i
% , ___. 2_m . _ . _ . -_ _ _ . _ ._. 1 _ 7 . [ Conclusion The staff is satisfied that the issues related to this concern have been satis-
, factorily addressed by the applicant and are therefore considered closed.
References
; 19.2.1 MP&L letter No. AECM-82/574 dated December 3,1983, from L. F. Dale (MP&L) to H. R. Denton (NRC).
19.2.2 CEI letter dated July 11, 1984, from M. R. Edelman (CEI) to B. J. Youngblood (NRC). HUMPHREY CONCERN 20.0 During the latter stages of a LOCA, ECCS overflow from the primary system can cause drywell depressurization and vent backflow. The GESSAR defines vent back-flow, vertical impingement, and drag loads to be applied to drywell structures, piping, and equipment, but no horizontal loading is specified. Evaluation The reverse weir annulus flow will be directed vertically into the drywell. The only horizontal flow possible would be defection of the rising water off structures above the weir wall or from the gravity-induced lateral velocity
. gradients in the vertically rising water. Deflection of the vertically rising water would result in a spray type of impact load, which is not expected to result in any significant loads. The lateral movement of the rising water because of gravity is expected to be slight and noi create any significant horizontal loads.
The staff does not consider it credible that the slight horizontal loads would be bounding loads on structures inside the drywell because of all the other load constraints on these structures, such as earthquake, reactor vessel blow-down, and dead loads. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERN 22.0 The EPGs currently in existence have been prepared with the intent of coping with degraded core accidents. They may contain requirements conflicting with design-bases accident conditions. Someone needs to carefully review the EPGs to assure that they do not conflict with the expected course of the design-basis accident. Evaluation The emergency procedure guidelines (EPGs) have been prepared with the intent of coping with all types of accidents, including design-basis accidents and ,, degraded-core accidents.
- River Bend SSER 2 31 Appendix K l
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i The process of developing the EPGs includes input from experienced personnel from all utilities that own boiling-water reactor (BWR) plants and representa- ' tives from GE. The NRC has reviewed, and is continuing to review, the proposed EPGs to assure to the maximum extent possible, that no conflicts exist between i the EPGs and the licensing-basis accident analysis. l The staff is satisfied with the steps that have been taken in the development of the EPGs and also in the ongoing review process to assure consistency in the EPGs. Conclusion The staff considers this issue satisfactorily resolved for the RBS. HUMPHREY CONCERNS NOT APPLICABLE TO RIVER BEND Humphrey initially raised his concerns based en his knowledge of the GESSAR design and certain aspects of the Grand Gulf design. Because of differences in plant designs, some of the Humphrey concerns are not applicable, directly or in-directly, to the RBS. Those Humphrey concerns that are indirectly applicable, or partially refer to design features not contained in the RBS design, are addressed in the previous ser+. ion. The following Humphrey concerns'do not need to be addressed for the RBS .or the reasons specified below. I. # HUMPHREY CONCERNS RELATED TO THE CONTAINMENT SPRAY SYSTEM The River Bend Station utilizes containment air coolers rather than a con-tainment spray system. Therefore, the following concerns are not applicable: 4.8 Operation of the RHR system in the containment spray mode will de-crease the heat transfer coefficient through the RHR heat exchangers due to decreased system flow. The FSAR analysis assumes a constant heat transfer rate from the suppression pool, even with operation of the containment spray. 4.9 The effect on the long-term containment response and the operability of the spray system due to cycling the containment spray on and off to maximize pool cooling needs to be addressed. Also, provide and justify the criteria used by the operator for switching from the containment spray model to pool cooling mode, and back again. 5.3 Leakage from the drywell to containment will increase the temperature and pressure in the containtrent. The operators will have to use the containment spray in order to maintain containment temperature and pressure control. Given the decreased effectiveness of the RHR sys-tem in accomplishing this objective in the containment spray mode, the bypass leakage may increase the cyclical duty of the containment sprays. 6.2 GE has recommended that an interlock be provided to require contain-ment spray prior to starting the recombiners because of the large , quantities of heat input to the containment. Incorrect implementa- ~ tion of this interlock could result in the inability to operate the recombiners without containment spray. River Bend SSER 2 32 Appendix K , [ . k
_ _ _ _ . _. ~ . - . _ _ _ _ _ ._m._ 13.0 The "Bd loop of the containment sprays includes a 90-second timer to prevent simultaneous initiation of the redundant containment sprays. Because of instrument drift in the sensing instrumentation and the 1,
. timers, GE estimates that there is a 1-in-8 chance that the sprays will actuate simultaneously. Simultaneous actuation could produce negative pressure transients in the containment and aggravate tempera-ture stratification in the suppression pool.
14.0 A failure in the check valve in the LPCI line to the reactor vessel q" could result in direct leakage from the pressure vessel to the con-
' tainment atmosphere. This leakage might occur as the LPCI motor-operated isolation valves in closing and the motor-operated isola-a tion valve in the containment spray line is opening. This could a
[ produce unanticipated increases in the containment pressure. II. HUMPHREY CONCERNS RELATED TO THE UPPER CONTAINMENT POOL The River Bend plant does not have an upper containment pool. Therefore, the following concerns are not applicable: 4 3.5 The RHR relief valves must be capable of correctly functioning follow-ing an upper pool dump, which may increase the suppression pool level as much as 5 feet, creating higher back pressures on the relief valves. 5.7 After upper pool dump, the level of the pool will be 6 feet higher, and drywell-to-containment differential pressure will be greater than 3 psid. The drywell hydrogen purge compressor head is nominally 6 psid. The concern is that after an upper pool dump, the purge com-pressor head may not be sufficient to depress the weir annulus enough to clear the upper vents. In such a case, hydrogen mixing would not be achieved. 12.0 The upper pool dumps into the suppression pool automatically follow-ing a LOCA signal with a 30-minute delay timer. If the signal that starts the timer disappears on the solid-state logic plants, the timer resets to zero, preventing upper pool dump. 17.0 The EPGs contain a curve that specifies limitations on suppression pool level and reactor pressure vessel pressure. The curve pres-ently does not adequately account for upper pool dump. At present, the operator would be required to initiate automatic-depressuriza-tion when the only action required is the opening of one additional SRV. 19.1 The chugging loads were originally defined on the basis of 7.5 feet 4 of over the drywell to suppression pool vents. Following an upper pool dump, the submergence will actually be 12 feet, which may affect chugging loads.
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III. HUMPHREY CONCERNS RELATED TO THE CONTAINMENT VACUUM BREAKERS l
, The River Bend plant does not utilize containment vacuum breakers. There- j fore, the following concerns are not applicable: '
River Bend SSER 2 33 Appendix K J
_ _- -_ . _ - - ~ 1 --- - - - --- i __ 1 - i 1 d 15.0 The STRIDE plants had vacuum breakers between the containment and
?( the secondary containment. With sufficiently high flows through the vacuum breakers to containment, vacuum could be created in the secon-dary containment.
21.0 Regulatory Guide 1.7 requires a backup purge hydrogen removal capa-bility. This backup purge for Mark III is via the drywell purge line, which discharges to the shield annulus, which in turn is exhausted through the standby gas treatment system. The contain-ment air is blown into the drywell via the drywell purge compressor
' to provide a positive purge. The compressors draw from the contain-ment; however, without hydrogen-lean air makeup to the containment, '". no reduction in containment hydrogen concentration occurs. It is necessary to ensure that the shield annulus volume contains a hydrogen-lean mixture of air to be admitted to the containment via containment vacuum breakers.
REFERENCES The staff reviewed the following documents in the preparing of this report.
- 1. L. A. England (Gulf States Utilities Company), letter to H. Denton (NRC),
containing the final Containment Issues Review Panel Report, July 27, 1984.
- 2. J. E. Booker (Gulf States Utilities Company), letter to A. Schwencer (NRC), River Bend response to Humphrey Issues, April 29, 1983.
- 3. -- , River Bend Station Final Response to Humphrey Issue, January 23, 1985.
Additional documents reviewed for specific Humphrey concerns are listed at the end of the staff's evaluation of the subject Humphrey concerns. ABBREVIATIONS ARS BWR boiling-water reactor CEI Cleveland Electric Illuminating Co. CIOG Containment Issues Owners Group C0 condensation oscillation DBA desi,gn-basis accident ECC emergency core cooling ECCS emergency core cooling system _ E0P emergency operating procedure EPG emergency procedure guidelines FSAR Final Safety Analysis Report , River Bend SSER 2 34 Appendix K
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.i l GE General Electric Company.
, GGNS Grand Gulf Nuclear Station )
j _ HCU hydraulic control unit IBA 7 - LOCA loss-of-coolant accident LPCI low pressure coolant injection 1 i MP&L Mississippi Power and Light Company
. MSRV- main safety / relief valve ; PPA peak-to peak pressure amplitude RBS River Bend Station RCIC reactor core isolation cooling RHR residual heat removal RWCU reactor water cleanup SBA small-break accidents SRV safety / relief valve SRVOL safety / relief valve discharge line TIP traversing in-core probe USI Unresolved Safety Issue-River Bend SSER 2 35 Appendix K I}}