ML20039E647
| ML20039E647 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 01/05/1982 |
| From: | Eccleston K Office of Nuclear Reactor Regulation |
| To: | Ippolito T Office of Nuclear Reactor Regulation |
| References | |
| TAC-48771, NUDOCS 8201110125 | |
| Download: ML20039E647 (53) | |
Text
{{#Wiki_filter:- L _3 91 + q, JAN 5 - 1982 g RECENED J4N5 194{ Docket No. 50-293 MEMORANDUM FOR: Thomas A. Ippolito Chief Operating Reactors Branch #2 g Division of Licensing y i FROM: Kenneth T. Eccleston, Project Manager Operating Reactors Branch #2 Division of Licensing j
SUBJECT:
Meeting Summary - 9:00 AM, December 18, 1981 Meeting with Boston Edison Company (BECo) A meeting was held at 9:00 AM _on December 18, 1981 with representatives of the Boston Edison Company concerning: 1 Torus gouges identified during the current refueling outage 2 Safety relief valve (SRV) test results, and 3 High drywell temperature operation. 1. Torus' Gouges Six gouges were identified on November 10, 1981 in a localized area of torus bay #11 after sandblasting of the torus inner shell to prepare the surface for painting. These gouges ranged from approximately 1/4" to 9/16" in depth. Torus shell thickness is approximately 5/8". The licensee has attributed the probable cause of these gouges to carbon arc gouging. The licensee stated that the most likely period of occurrence of these gouges was during the 1980 refueling outage. Repairs to the torus will be performed in accordance with the requirements of the ASME code and will be followed by non-destructive testing and an Appendix J Type A leak rate test. The licensee will conduct a detailed examination of the torus after work completion and will also develop a surveillance procedure for torus inspection after any work is done in 4 containment. Analyses are being perfonned to determine the possible failure modes (if any) of the torus as a result of torus pressurization (post LOCA) and the existing i torus degradation arising from the gouges. Prior to restart, the licensee expects to provide the results of these analyses. If these analyses indicate a break or leak would be expected to occur, the licensee will evaluate the potential offsite dose consequences and the possible effect on equipment from flooding. omce) 8201110125 820105 (URNA%E) PDR ADOCK 05000293 - - - - ~ ~. ~ ~ ~ ~. - - - - - - - ~ ~ - - - --~~~~~- ......m..o PR .p,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, e om> , unc ronu ais co-co> nncu eno OFFICIAL RECORD COPY usom --mea
M' s 2-1 2. High Drywell Temperature Operation Flashing in the reference leg of the Yarway level instrumentation resulted in oscillation of the indicated levels provided by this instrumentation. This occurred during the at shutdown for the current refueling. These oscillations were apparently caused by operation with drywell temperatures in excess of 220 F. r Operation with drywell temperatures in excess of containment atmosphere system design was recognized shortly after startup in 1972. After consulta-tion with General Electric (GE), it was detemined that operation with drywell temperatures slightly in excess of normal would not present a problem. However, operation with drywell temperatures in excess of 200 F was not considered in this evaluation. The licensee cited numerous contributors to the high drywell temperatures experienced. Among the cited causes were dirty coils on the fan cooler units, damaged ventilation ducting, a degraded salt service water (SSW) system (arising primarily from mussel. intrusion problem), and leaking Target Rock Safety Relief Valves. BEco was asked to provide documentation (i.e., a safety evaluation) which provided a basis for continued operation since operation comenced. In addition, BECo was asked to provide additional information concerning the significance of deviations in level indication, particularly since GE-SIL 299 was issued. This documentation is to include a detemination as to the validity of ECCS analyses and the basis for detemining that Pilgrim I operated safely from the beginning of Cycle 5 until the end of Cycle 5. The licensee is also to propose Technical Specifications providing drywell temperature limits. This infomation is to be provided for our review and approval before resumption of operation. The licensee described the actions planned to prevent recurrence of high drywell temperatures. 3. _SRV Testing In November 1981, "as-received" testing by Wyle Laboratories of safety relief valves (SRVs) employed at Pilgrim I revealed gross erosion of the pilot discs in three of the four valves tested. Actuation pressures in these three valves were found to be higher than the 1095 + 11 PSIG j l setpoint required by trie Technical Specifications. The fourth valve exhibited " incipient" erosion / cutting. These valves are Tuo-Stage Target Rock SRVs. Although the overpressure protection function of these valves was affected in the non-conservative direction, the Automatic Depressurization System (ADS) function and the capability to manually actuate these' valves were + unaffected according1to the licensee. i e - omce> sunnus>
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'f i e s 1 ,J i ' f k I Boston Edison advised that Cycle 5 was the on1 operating cycle for { h which the Two Stage (as opposed to Three Stagef Target Rock SRVs were L used at Pilgrim. Two inadvertant openings of the modified SRVs occurred during Cycle 5 operation. These have been attributed, at least in part[, to high nitrogen pressure. The licensee further stated that body-base leakage was judged to be not significant, and that the bulk of the observed i' leakage occurred through the pilot assembly. into the valve ta11 pipe. / l BECo is continuing to investigate the composition and possible' origin of foreign material which was found plated.out on valve intervals. The licensee is'also taking the following actions: j t a refurbishing the four SRVs of interest b investigating the suitability of increasing the sinner margin c limiting nitrogen supply pressure d increasing / surveillance of the ta11 pipe temperatum. tie (n Target Rock has been asked to verify that proper materials of i i ~, construction were,used in the valves. /e i Finally, Bostoo Edison has asked General Electric to 1) deten[ine.if proper overpressure protection was provided during Cycle 5, 2) verify the validity of a 200 lb/hr flow rate without a setpoint change, 3) make recommendations - regarding a sismer margin increase and 4) verify that materials of the valve + poppet are suitable. ' / i Boston Edison was asked to provide information regarding the overpressure protection provided throughout Cycle 5 and to verify the suitability of the SRVs for use in subsequent cycles. The licensee was asked to prop 3se Tech Specs limiting valve Icak rates and/or ta11 pipe temperatures to suitably. low 1 L values. This infonnation is to be provided for our review and approval i befom resumption of operation. r - pmsents the agenda for the meeting. Enclosure 2 is the list of ~ meeting attendees. Enclosures 3 through 6 are copies of the material presented by the licensee' at the meeting. ORIGINAL SIGH 7D BY j Kenneth T. Eccleston, Project isanager L Operating Reactors Branch #2 Division of Licensing
Enclosures:
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a o Meetina Summary Distribution Docket File fiRC PDR Local PDR ORB #2 Reading J. Olshinski J. Heltemes B. Grimes T. Ippolito Project Manager OELD IE (3) S. Norris ACRS (.10) NRC Participants NSIC TERA B. D. Liaw cc: Licensee with short cc list Regional Administrator
.e 't I Mr. A. Victor Morisi Boston Edison Company cc: Mr. Richard D. Machon Pilgrim Station Manager Boston Edison Company RFD #1, Rocky Hill Road . Plymouth, Massachusetts 02360 Henry Herrmann, Esquire Massachusetts Wildlife Federation 151 Tremont Street-Boston, Massachusetts 02111 Plymouth Public Library North Street Plymouth, Massachusetts 02360 Resident Inspector c/o U. S. NRC P. 0. Box B67 Plymouth, Massachusetts 02360 Ms. JoAnn Shatwell Office of the Attorney General Environmental Protection Division 1 Ashburton Place 19th Floor Boston, Massachusetts 02108 O
PILGRIM MEETING "'I " I DECEMBER 18, 1981 INTRODUCTION o TORUS SHELL G0UGES
- IDENTIFICATION AND PROBABLE CAUSE oPROJECTED FAILURE MODE eINSPECTION, REPAIR AND TESTING PROGRAM aCORRECTIVE ACTIONS TO PREVENT RECURRENCE o ELEVATED DRYWELL TEMPERATURE l
a EVALUATION OF THE EVENT a HISTORICAL PERSPECTIVE a CAUSAL CONTRIBUTOR o CORRECTIVE ACTIONS TO PREVENT RECURRENCE aEVALUATION OF DETRIMENTAL EFFECTS = C0llTAINMENT STRUCTURE
- CONTAINMENT EQUIPMENT
- DEFICIENCY RESOLUTION
- JUSTIFICATION FOR CONTINUED OPERATION o TARGET ROCK SAFETY / RELIEF VALVES oEVALUATION OF THE EVEllT aHISTORICAL PERSPECTIVE
- CAUSAL CONTRIBUTORS
o BOSTON EDISON CO. PILGRIM STATION DECEMBER 18, 1981 MEETING AGENDA I. INTRODUCTION JIM KEYES REASON FOR MEETING ATTENDEES II. TORUS SHELL GOUGES GEORGE MILERIS III. ELEVATED DRYWELL TEMPERATURE JIM SEERY DICK SWANSON IV. TARGET ROCK SAFETY / RELIEF VALVES KEN ROBERTS . ROCKY DELOACH
t AM Meeting w/ Boston Edison Company 12/18/81 Tom Ippolito NRC/NRR/DL/ Chief, ORB #2 Jim Gleason Wyle Laboratories Jack Robertson Wyle Laboratories Harold Gregg NRC/RES/DET/MSEB Frank Cherny NRC/MEB/NRR George Moy Teledyne Eng'g. Serv. Richard Berks Teledyne Engineering Services David E. Smith NRC/MTEB/DE/NRR Walter Rekito NRC/I&E/RI Harold Eichenholz NRC/I&E/RI (Resident Inspector-Pilgrim) Wayne Hodges NRC/RSB Ken Eccleston NRC/NRR/ Pilgrim I Project Manager Al Baker General Electric Jim Klapproth General Electric Jim Gosnell Boston Edison - NED James Ashkar Boston Edison - Engineering James A. Seery Boston Edison - Onsite Safety & Performance William H. Deacon Boston Edison - Home Office Paul D. Smith Boston Edison - CTE Ken Roberts Boston Edison - CTE Jim Keyes Boston Edison Pete Kahler Boston Edison Ed Kearney Boston Edison John Pawlak Boston Edison Richard N. Swanson Boston Edison - NED Earl J. Brown NRC/AEOD Rockie J. DeLoach Boston Edison - NED Paul Shemanski NRC/NRR/EQB Vincent Thomas NRC/I&E/ REB C. J. DeBevec NRC/I&E/ REB Richard J. Kiessel NRC/I&E/ REB Khalid SMaukat NRC/NRR/DE/SEB Alexander W. Dromerick NRC/I&E/ REB J. E. Rosenthal NRC/NRR/ICSB E. V. Imbro NRC/AE0D Doug Pickett NRC/NRR/DL/0RAB Cy Cheng Gouge Discussion Only NRC/NRR/DL/0RAB Keith Wichman Gouge Discussion Only NRC/NRR/DL/0RAB R. D. Machon Boston Edison R. M. Butler Boston Edison Jim Van Vliet NRC/NRR/DL/0RB#2 Stu Rubin NRC/AE0P
t (kUC61"/D-1) TORUS SHELL GOUGES PROBLEM DEEP LOCALIZED GOUGES FOUND IN TORUS SHELL CAUSE PROBABLE CAUSE WAS CARBON ARC GOUGING FAILURE MODE EXPECTED FAILURE IS SHELL LEAK REPAIR VELD REPAIR PER ASME SECTION XI, CODE CASE-236 AND OWNERS SPECIFICATION FOR TORUS STRUCTURAL MODIFICATIONS NDE LIQUID PENETRANT, MAGNETIC PARTICLE AND PJJ)IOGRAPHY TESTING PER 10 CFR 50, APPENDIX J PREVENTION DETAILED VISUAL EXAMINATION BEFORE RESUMPTION OF POWER OPERATION
s (FUC61/D-2) PROBLEM DISCUSSION SIX LOCALIZED GOUGES IN BAY #11 0F THE PILGRIM-1 TORUS SHELL WERE FOUND ON 11-10-81 DURING SANDBLASTING PRIOR TO RECOATING OF THE TORUS SUBMERGED PORTION. GOUGE SIZE RANGED FROM 1/4" TO 9/16" DEEP AND 1" TO 1 3/4" DIAMETER. REFER TO FIGURE 1. FOR DETAILS. PREVIOUS INSPECTIONS OF THE TORUS SHELL ON 10-6 !.ND 10-10-81 TO EVALUATE THE COATING CONDITION AND PERFORM A CORROSIOM SL2VEY FAILED ' TO LOCATE THE GOUGES. APPARENTLY THE GOUCES WERE NOT VISIBLE BECAUSE THEY WERE NEAR THE BOTTOM OF THE SHELL AND THERE WAS SOME SEDIMENT AND WATER AT THE BOTTOM DURING THE INSPECTION.
l-FIGURE 1 i 60" l B AY:= 11 = 0 ,2 '250 36'** 25 i= 2 [ p ,200 6 4 2so j' 4.,, y. //4g// o BOTTOM 6 GROUP'A' WELD / i ' 'F i C g t./////s, /'[ 3 24 " 5 1 l7 " a g G 1 g,T HK(N OMINAL) ' TORUS OUTER A ) gg(({ g BOTTOM C 4 n SLIGHT IMPRESSION p WELD i sr 2 c. f A i l 15" p GROUP 1~ i3 - s,~ TORUS GOUGES 18" 2 ~ O PILGRIM I P'f- _, 2 _. 470 4 DEPTH f 470 su ,c. .600 DEPTH a.'. 1
(NUC61/D-3) CAUSE OF GOUGES THE FOLLOWING WERE CONSIDERED AS POSSIBLE CAUSES: CORROSION EROSION CARBON ARC GOUGING MECHANICAL DAMAGE ARC STRIKES CARBON ARC GOUGING DURING CONSTRUCTION / MODIFICATION IS THE PROBABLE CAUSE DUE TO THE DEPTH OF THE GOUGES, SMOOTH CONTOURED SIDES AND RIPPLES IN THE CAVITIES WHICH INDICATE FLOW OF MOLTEN METAL. THE DAMAGED AREA IS LOCATED BELOW AN ACCESS MANWAY AND SOME SRV PIPING WAS CUT UP DURING THE LAST OUTAGE. IT WOULD HAVE BEEN CONVENIENT TO LAY THE PIPING ON THE NEARBY RING GIRDNER DURING THE CUTTING. FIGURE 2 SHOWS THE TORUS CONFIGURATION. HARDNESS TESTS AND/OR CHEMICAL ETCH ARE PLANNED TO CONFIRM IF HEAT INPUT TO THE SHELL OCCURRED. THE OUTSIDE OF THE SHELL WILL ALSO BE EXAMINED FOR PAINT AND/OR METAL DISCOLORATION FROM HEATING. PLANT RECORDS ARE BEING SEARCHED TO DETERMINE WHEN THE DAMAGE MAY HAVE OCCURRED. THE MOST LIKELY PERIOD IS THE 1980 REFUELING OUTAGE. b m*- e am
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Q FAILURE MODE DISCUSSION PRELIMINARY ANALYSIS INDICATES THAT THE MODE OF FAILURE COULO BE A LEAK BEFORE BREAK WHICH MAY LEAD TO A DUCTILE MODE OF FAILURE. THE G0UGES ARE FOUR BAYS FROM THE !!EAREST T-QUENCHER AND EFFECTS OF T-QUENCHER LOADS ARE !!0T SIGNIFICANT. TORUS MAXIMUM PEAK PRESSURE IS 32 PSI STATIC AT ADS ACTUA-TION PER THE MK I CONTAINMENT PULD. MAXIMUM EXPECTED LEAK RATE FROM THE TORUS SHELL ASSUMING A 1-INCH DIAMETER HOLE AT THE DEEPEST GOUGE IS APPCOXIt'- Y 132 GPM WITH A PSID OF 38 PSI (32 PSI STATIC AND 6 PSI LIQUID). A MORE DETAILED ANALYSIS WILL BE DONE TO VERIFY THE ABOVE CONCLUSIONS. 12/17/81 .o .__O_. J
(NUC61'/D-5) REPAIR OF GOUGES REPAIRS TO THE DAMAGED AREAS WILL BE MADE USING THE BUTTERBEAD/ TEMPERBEAD TECHNIQUE PER THE REQUIREMENTS OF THE DOCUMENTS LISTED BELOW: ~ ASME CODE SECTION XI ASME CODE CASE N-236 OWNERS SPECIFICATION, 05-2255-7, PILGRIM 1 STRUCTURAL MOD-IFICATIONS TO MARK I CONTAINMENT TORUS SUPPORT SYSTEM GENERAL REQUIREMENTS FOR THE TORUS SHELL REPAIR ARE OUTLINED IN TELEDYNE LETTER 5310-44,1) 11-25-81. A DRAFT OF THE REPAIR PROGRAM HAS BEEN PREPARED BY THE TELEDYNE AND PILGRIM STATION MAINTENANCE AND QC ARE WORKING TO PREPARE A DETAILED SHELL REPAIR PROCEDURE, WELD PROCEDURE SPECIFICATION, AND ELECTRODE CORE & STORAGE PROCEDURE. THE PLANS ARE FOR A BECO. WELDER TO DO THE REPAIRS AFTER WELD PROCEDURE AND WELDER QUALIFICNfION. 1) ATTACHMENT 1.
(NUC61/D-6) NON DESTRUCTIVE EXAMINATION (NDE) THE REPAIR AREA IS TO BE EXAMINED BY LIQUID PENETRANT OR MAGNETIC PARTICLE METHODS PRIOR TO WELD REPAIR AND FINAL EXAMINATION BY RADIOGRAPHY AND MAGNETIC PARTICLE. REFER TO ATTACHMENT 1) FOR ADDITIONAL DETAILS. FINAL EXAMINATION SHALL BE DONE 72 HOURS AFTER THE WELD IS AT AMBIENT. TESTING REQUIREMENT PERFORM TYPE A TEST IN ACCORDANCE WITH 10 CFR 50, APPENDIX J - PRIMARY REACTOR CONTAINMENT LEANAGE TESTING FOR WATER - COOLED POWER REACTORS.
i (NUC61/D-7) l PREVENTIVE MEASURES AFTER PRESENT TORUS MODIFICATIONS ARE COMPLETED AND PRIOR TO POWER OPERATION A DETAILED VISUAL INSPECTION WILL BE CONDUCTED TO CHECK THE TORUS SHELL FOR ANY DEFECTS AND TO DETERMINE COATING AREAS THAT NEED TOUCH UP. ACCEPTANCE CRITERIA FOR DEFECTS WILL BE PER THE OWNER SPECIFICA-TION, AND ANY UNACCEPTABLE DEFECTS WILL BE REPAIRED. A TORUS SURVEILLANCE PROCEDURE WILL BE PREPARED TO INSPECT THE TORUS SHELL WHENEVER ANY WORK WITH THE POTENTIAL TO CAUSE SHELL DAMAGE IS DONE IN OR AROUND THE TORUS. INSl'ECTIONS OF THE TORUS COATING WILL BE CONTINUED. I
WTELEDYNE ENGINEERING SERVICES 13a SECOND AVENUE w ALTHAM. MASSACHUSETTS C2254 k ATTACHMENT 1 mi snaasa rwxvo,massex08 November 25, 1981 5310-44 Mr. George Mileris fiuclear Engineering Department Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199
Subject:
Repairs of Torus Shell Gouge
Dear George:
Teledyne Engineering Services (TES) has reviewed the sketches showing' the gouges on the torus shell. Based on the information supplied to date, TES has assumed that the indications were due to are gouges. These should be repaired in accordance with Code Case 11-236 and Paragraph 5.1.2 of Owner's Specifica-j tion 2255-7. The following actions should be initiated: I. Develop a Repair Program in accordance with IWA-4130 of Sec-r' tion XI. The Repair' Program is subject to review by the enforcement and regulatory authorities having jurisdiction at the plant site. The services of an Authorized Inspection Agency must be used when making the welded repairs. II. Develop a procedure for the removal of defects, including preparations for welding. The Repair Program is subject to-review by the enforcement and regulatory authorities having jurisdiction at the plant site. The services of an Authorized Inspection Agency must be usd when making the welded repairs. 2 Since it is believed that a thermal process was the cause of the cavities, a minimum of 1/16 inch material shall be removed from the cavity to be repaired. by a mechanical removal pro-cess. The cavity shall be ground smooth and clean with bevel sides and edges rounded to provide suitable accessibility for weld-ing. After final grinding, the affected surf aces, including sur-faces of cavities prepared for welding, shall be examined by .h the magnetic particle or liquid penetrant method to ensure that the defect is completely removed. ENGINEERS AND */ETALLU.7 GISTS
~ W TELEDYNE ENGINEERING SERVICES Mr.. George Mileris November 25, 1981 (- Page 2 A The Owner or his Agent shall be notified of any indications detected as a result of the excavation that are not associated ' with the defect being removed. Approval of the Owner or his Agent is required prior to the start of any repairs. III. Develop a Weld Procedure Specification in accordance with Sec-tions IX, III, XI, and Code Case N-236. The weld metal shall be deposited by the manual shielded metal arc process using low hydrogen-type electrodes. The maximum bead width shall be four times the electrode core diameter. IV. Develop an Electrode Case and Storage Procedure which meets the requirements of Paragraph 2.0 of Code Case N-236 and Sec-tion XI, Paragraph IWB-4321. V. The Welding Procedure Qualification shall meet the require-ments of Section XI, Paragraph IWB-4322.1 (a) through (h), as well as Section IX and the additional requirements of Sec-tion III, Subsection NE. The test assembly thickness shall be one inch. The test assembly length shall be 30 inches long and 15 inches wide. The depth of the cavity in the test assembly shall be 5/8 inch. The cavity length shall be 18 inches. f VI. The welders shall be qualified in accordance with Section IX A and the additional requirements of Section III, Subsection NE. The welder shall also demonstrate the ability to deposit sound weld metal in the position required, using the same parameters and simulated physical obstructions as are involved in the repair. The procedure and welder performance test may be combined if so desired. VII. The additional requirements contained in Appendix B of the Owner's Specification shall be met, along with the require-ments contained in Paragraph 5.0 of the Owner's Specification. I VIII. Nondestructive Examination: The completed weld repair shall meet the examination require-ments set forth in NE-4130 and the acceptance criteria given in NE-5000. In addition the requirements of IWB-4324 and i-Appendix B of Owner's Specification 2255-7 apply. The methods of examination shall be radiography and magnetic particle. This examination shall occur a minimum of 72 hours af ter the weld is at ambient. IX. Testing These repairs by welding to the existing shell of the Class MC 1 vessel shall be subjected to a Type A test in accordance with (
.. o W TELEDYNE ENGNEERING SERVICES Mr. George Mileris tiovember 25, 1981 Page 3 k. the provisions of Title 10, Part 50, of the Code of' Federal Regulations, Appendix J. The preservice examination in accor-dance with Paragraph 1.0 of Code Case ti-236 may be performed, either prior to or following the test. This is not a problem since BECO is planning an ILRT prior to start-up. If you have any further questions, please contact the writer. Sincerely, TELEDYtlE EtiGIriEERItiG SERVICES James A. Flaherty L/ Manager, Engineering Design and Testing JAF:jej cc: L. J. Diluna (TES) ti. S. Celia (TES) ( E. F. Kearney (BECO) D. Mills (BECO) '(._ ?
OPERATIONAL ASPECTS OF HIGH DRWELL TDf? EVENT I. OVERVIEW OF DRWELL ATMOS. COOLING SYSTDI II. SUBS!ARY OF PNPS OPERATING HISTORY AND DRWELL TDiPERATURES III. CONDITIONS WHICH CONTRIBUTED TO HICH DRWELL TDiPERATURE EVENT IV. CORRECTIVE ACTIONS TO PREVENT RECURRENCE
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CYCLE AND REFUELING OUTAGE HIS'iDsY COMMERICIAL OPERATION 12/72 CYCLE 1 12/72-12/29/73 REFUEL 1 12/29/73-7/26/74 CYCLE 2 7/26/74-1/27/76 REFUEL 2 1/27/76-6/1/76 CYCLE 3 6/1/76-8/6/77 REFUEL 3 8/6/77-11/17/77 CYCLE 4 11/17/77-1/5/80 REFUEL 4 1/5/80-5/19/80 CYCLE 5 5/19/80-9/26/81 REFUEL 5 9/26/81-PRESENT e
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BASIS FOR CONIINUED OPERATION AT EOC-5 1. PNPS WAS OPERATING IN COMPLIANCF WITH TECHNICAL SPECIFICATIONS. 1 2. PROGRAM WAS IN PLACE TO CORRECT THE DRYWELL TEMPERATURE PROBLEMS DURING REFUEL #5 (SEPT. 1981). 3. ENGINEERING EVALUATIONS WERE ONGOING AND POTENTIAL CABLE DEGRADATION WAS IDENTIFIED AS ONLY SAFETY CONCERN AND INSPECTION WAS PLANNED DURING REFUEL #5. 4. FOLLOWING EVALUATION OF GE-SIL 299 ADJUSTMENTS WERE MADE TO RPV LEVEL INSTRUMENTS TO COMPENSATE FOR HIGH DRYWELL TDiP. 5. PROBLD1 WAS OF A LONG-TERM NATURE AND THERE WAS NO HISTORY AT PNPS OF OPERATING PROBLEMS RESULTING FROM ELE'.'ATED DRYWELL TEMPERATURES. d q yep---, ,.m,.--,- -.y-~g -..g., e._,._,, m -s +-ms. -,,,w, ,,g,nm.. .-a---,<- <nny .w. -,n. e
l 1 CONDITIONS WHICH CONTRIBUTED TO HIGH DRYWELL EVENT CONDITIONS TIME EFFECT RDIOVAL OF PERSONNEL 1974 OUTAGE ALLOWED DIRECTED FLOW ACCESS DOORS TO LOWER DRYWELL LEVELS & DECREASED FLOW TO UPPER LEVELS DIRTY COILS ON FAN 1976,1977 CONTINUALLY DECREASING COOLER UNITS 61980OUTAK,/'EFFICIENCYOFUNITS x-f{y.w*n, s^e s/> * ' p' 'f M D.21 AGED VENTILATION 1977,1980 CONTINUING IMBALANCING DUCTING OUTAGES
- OF DRYWELL COOLING SYS
.uJr. ' b, ~ k,m ///,/ af,,T.:' I DAMAGED AND MISSING 1977 & 1980 INCREASED HEAT LOAD INSULATION ROUGHING FILTERS NOT CYCLE 5 FURTHER DECREASE OF AIR REMOVED FLOW OVER COOLERS OPERATION WITH LEAKING CYCLE 5 I'sCREASED HEAT LOAD TARGET ROCKS DEGRADED SSW SYSTE'4 CYCLE 5 DECRADED HEAT SINK mi
CORRECTIVE ACTIONS TO PREVENT RECURRENCE A. ACTIONS PLANNED, SCHEDULED AND FUNDED PRIOR TO CO)DIENCDIENT OF S1 OUTAGE: REPLACEALLCOOLERSINDRYWELL[M8f d.! '- M/'if#
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/t- ,.." *T - av' 2. REPAIR / REPLACE EXISTING DUCTWORK 3. CONDUCT DETAILED INSULATION SURVEY / REPAIR 4. PERFORM DRYUELL FAN EFFICIENCY TESTS AND VENTILATION SYSTDI BALANCING 5. MECHANICALLY CLEAN SALT SERVICE UATER SYSTEM PIPING 6. MODIFY RBCCW HEAT EXCHANGER BAFFLE PLATES 7. INSTALL CONTINUOUS CHLORINATION SYSTEMS (1 YEAR EPA APPROVED TEST FOR MUSSEL CONTROL) 8. REFURBISH DRYUELL TDiPERATURE INSTRUMENTATION 9. INSTALL ADDITIONAL INSTRUMENTATION TO MONITOR PERFORMANCE ON: A. DRYWELL COOLERS B. RBCCW HEAT EXCHANGER 10. PERFORM CABLE INSPECTION 11. START-UP MONITORING PROGRAM / f f -/ / U O ' #' f \\ ,.Q 4, f *' ' l i
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l m,., s <~ R - W ,~ CORRECTIVE ACTIONS TO PREVENT RECURRENCE (CONT.) . B. ACTIO'?S PLANNED AS A; RESULT OF SUBSEQUENT DETAILED ANALYSIS: 1. SELECTED CABLE REPLACEMENT / ANALYSIS e i. 2. COMPONENT ANALYSIS 3. INSTALLATION OF+AUCESS_ DOORS / C. ADDITIONAL ACTIONS TO PREVENT RECURRENCE. s N -1. UPGRADE OF TRAINING'AND ^ PRO.CEDURES (DRWELL INSPECTION AND CLOSURE PROCEDURE) l' h d~ 2. IMPLEMENTATION OF-DKWELL TDiFERATURE SUPNEILLANCE TEST. ~ k -Q d
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-40 -20 0 +20 +40 +60 +80 TEMPERATURE CORRECTION ( F) WYLE LABORATORIES Huntsyme FaCHity
e WRElBECO ACTION PLAN FOR ASSESSMENT OF DRYWELt EVENT DETHIMENTAL EFFECT O DAMAGE DRVWELL U DRYWEtt. E ASSESSMENT ENylRONMENTS D EQUIPMEN T E MEillODOLOGY N 2 D = } Records g liigh Temp. Environ.
- 19 01B List i
identity Equip. Drywell identify Damege
- PNPSI file Inden U
Potential Celteria identily Temp. in Drywell Wethdown
- Maint. Req.
g Data Sources Q Classify U . Man T Rating of Equip. I O ir g De16ne f ernp. g f f f E = Man i Rating of I For Drywell Zones U Non-Melat Time Histories M Salety Rel. Non. Safety Safety & Non Safely g Elect. Eqpt. Elect. Eqpt. Mech Eqpt. D + Oual. Life Parameters D E
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U 0 D y U D u D Devel. Damage g Identity Locat. Identify g Assess. Method. O in DrywelllZone g 1 O + Non Metal g j U
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t Correlate Equipt.
- Oual. Limits
- Function of Non Metal U
& Temp. Environ. R D l u n E D o Pre liigh Temp. l Event Normal l U Y Assess. Potential Darnage l H==U AQ nglMalat. i --=== { History j 1r g 7 __J_____ Determine Eqpt. Define Post High Temp 7 l Event Normal D E Status Acceptance Criteria Aging & DOE _j g 1r i Develop Action
- Ol',e 4
Plan & JCOlPer item J s l
i m E I COMPONENTS RE0UIRING REWORK-AS t. L A RESULT OF DRYWELL EVENT -c I e 1 e NAMCO LIMIT SWITCHES' - < -? 5 '. 3 i s,ff,-.. - e s e 0KONITE CABLE ABOVE 41 FOOT ELEVATION +: x e DRYWELL COOLING. SYSTEM i j 1 Y a 1 ? i A L ~ i, s 1 I NRC 12/81 \\ a I y--., .<,,-~ y -..,m,-.v,w-,w,-,,..,,,-.,,,,..,,,---,, c-e,.~, .,.m,., . -. - ~,, ,m. m.,---- ,3-,-,m,-,,v-w.vm-,~,..v.w,, .y ,v.- .. - ~, - .7y ys.
COMPONENTS RE0VIRING FURTHER' TESTS / INSPECTION e LIMITORQUE OPERATORS e TARGET ROCK SOLENOID VALVES e PENETRATIONS-e JUNCTION BOXES /IERMINAL BLOCKS e MOISTURE ELEMENTS e MOTOR OPERATORS e AIR OPERATORS-e KERITE CABLE (FUTURE IEST REQ'D) - l l 1 l NRC 12/81 l l-
t .i COMPONENTS NOT SIGNIFICANTLY AFFECTED 9 l BY DRYWELL EVENT-I e ASCO SOLENOID VALVES e AVC0 SOLENOID VALVES' l e - TEC MONITORING SYSTEM [r.:. ;;./:h. ' e CABLE TERMINATIONS e SWITCHBOARD-WIRE i e RAYCHEM SPLICES e SNUBBERS e TEMPERATURE ELEMENTS i e FLOW SWITCHES NRC 12/81 1 r .--.e.-,-w--r.~ 3vr-.-
2 STAGE TARGET ROCK REP. ORT 6 SECTIONS. 1 HISTORY & BASIC POSITION 2 MAJOR PROBLEMS ENCOUNTERED 3 PROEABLE CAusE 4 ACTION TO J.C,0. PRIOR To STARTUP 5 FURTHER ACTIONS THAT WE FEEL ARE REQUIRED' 6 Discussion
s I. TWO-STAGE " TARGET ROCK" SAFETY RELIEF VALVES A. Historv and Basic position The two-stage "Targe: Rock" safety relief valves were installed during the 1980 ref,ueling outage. The justification for installing the valves was that they could exper-ience pilot leakage without the inadvertant opening trait exliibited by the three-stage design. The =anufacturer's purchase specification in-ferred that the valves could exhibit leakage up to 1,000 lbc/hr, and at that point torus te=perature would beco=e a proble=. In the following description of three and tuo-stage safety relief valve differences, please note that in the three-stage design the =anufacturer identified a failure =echanis= that would render the valves inoperable and in-stalled equip =ent to warn the operator of that condition. The two-stage analysis does not offer " protection" against the failure =echan-is= identified on our two-stage valves and which we believe to be gen-eric to all two-stage " Target Rock" safety relief valves; and require that operative restrictions be i=ple=ented to ensure that they re=ain operable. 3. Description of Operation of the Two and Three-Stage Valves The operation of both the initial design (three-stage) and the new design (two-stage) will be briefly described. This vill be followed with a closer view of the design differences and how they affect the identified proble=s. On Figure 1, the stea: inlet to the three-stage valves is at (1) and-the discharge is at (2). Volu=es (1) and (3) are a: reac c: pressure. Reactor pressure is also ec==unicated in the pilot (6) through port (5) and to the bellows interior (7). When reactor pressure reaches the pilot setpoint, the expanding bellows lif:s the pilot and stea: flows into the second stage (8). Sufficient stea= pressure causes the second s: age piston to =ove and open the second stage disc at (9). This allows depressurization of the =ain piston cha=ber volu=e (3) as the stea= flows ou: through path (1) - (11) to the discharge piping. The differential pressure across the =ain piston (4) over-co=es =ain disc closure force and the =ain piston (4) = oves to open the =ain valve (13) to allow the stea= to flow fro: the inlet (1) to the outlet (2). Figure 2, shows the topworks for the new two-stage valve. The =ain stage is functionally unchanged. Reactor pressure is co==unicated through port (5) :o the pilo: (6). When the reactor pressure reaches the pilot se: point, the pilot lifts and the stabilizer dise (7) seats. The stabilizer holds the pilot disc open as long as the stabill:er is against its own seat. The open pilot valve for s part of the path that releases the scea: in volu=e (3) through ports (8) and (9). The pressure in (3) drops quickly and differen:ial pres-sure across the =ain piston (4) opens the =ain stage valve just as ( in the earlier design. i
Ths principal differsness.batwstn the initial and now dsaigns, cnd 1how they relate to i= proved perfor=ance, are described below: 1. The pilot valve is connected directly to the =ain piston cha=ber (3) in the new design-eli=inating the second-stage of the-initial design. The pilot valve has been =ade~1arge enough to perfor= the functions of both the pilot and the second stage of the ini-tial-design. If there is leakage past the pilot it comes from. the inlet pressure port (5) and through leakage passages around the.=ain piston that =aintain the pressure in chamber (3); leak-age goes to the valve discharge line through port (9). Tests have shown that even with leakage at 200 lb/hr there is no appre-ciable effect on'setpoint perfor=ance, and leakage will not cause the valve to open and blow down the reactor. Calculations show that the pilot leakage could reach 1000 lbs/hr without pilot lift or main stage operation. (In the initial design a calculated pilot leakage of 15 lb/hr is enough to pressurize the second stage cha=ber and stroke it, causing the =ain valve to open). 2. In the initial design an expanding bellows (14) surrounds the pilot and is subjected to steam pressure (internally). If the bellows develops a leak, the pressure that develops in the-external space increases the effective setpoint of the valve. Since this is a potential safety proble= the design includes a pressure switch (15) to warn the plant operator of a bellows leak. The new design has a direct-acting pilot with no pressure sensing bellows and no need for a pressure switch. This change resolves three proble=s that have occurred. a. Bellows Leak b. Switch Failures c. Shor: Circuits In Switch k' iring 3. In the initial design, the air actuator (16) is a separate bolt-on asse=bly. In the new design, the air actuator.is an integral part of the bonne: (10). Each uses a diaphrag= of the sa=e =at-erial, but the new air operator has i= proved diaphrag= sealing characteristics. This change eli=inates the need for grease or or gaskets to affect an adequate seal. Tests and operational experience have shown that the initial design resulted in dela=- ination failures of the diaphrag=. Tests under the sa=e environ- = ental conditions showed that the new diaphrag: did not dela=in-ate.
II. MAJOR PRO 3LDiS IDENTIFIED DURING THE NOVEM3ER 1981 TESTING OF THE SAFCTY RELIEF VALVES A. Gross Erosion and Steam Cutting Valves 1048,1049, and 1054 exhibited gross erosion of the pilot discs. ( This resulted in an actuation pressure beyond the 1095 + 11 psig set-point required by the Technical Specifications. Valve 1046 was installed in October 1980, and axhibited incipient erosion / cutting. The operational differences between the valves:will be discussed in the probable cause section of this report. This is the ::ajor proble: encountered and the one that we are concerned with in this report. NOTE: Refer to Figures 3, 4, 5 and 7 3. Sodv to 3ase Leakage All valves exhibited "3cdy to Base" leakage. This proble: had.been addressed by the =anufacturer and all were nodified to enlarge the seating surface area, thus eliminating the problem. C. Foreirn Material The presence of a black foreign =aterial plating out on the valve in-ternals. 4
O e III. PR03d3?.E CA$SES A. Factors Considered - High Nitrogen Pressure Initially this was considsted as the =ajor catalyst to erosion because the three valves (A, 3, and C), that leaked within two to threa =onths of startup, had been subjected to the higher nitrogen systa= pressure with acco=panying inadvertant overpressuri:ations (10/81), and that - the "D" valve (1046) had not been subjected to higher nitrogen-syste= pressures and had not leaked. Futher investigation indicated that although the "D" valve had.not leaked for eight =enths, it did begin to leak and it had in fact ex- ~ perienced the same nitrogen overpressure transient that th _jh", "3", 3 and "C" valves had experienced. To reinforce this position, a pressure test of the solenoid valves was conducted (12/81), f and results indicate - that the solenoid valves will not leak at pressures below 140 psig af ter twelve to fif teen =enths of in contain=ent service. NOTE: Refer to Figure 6 Thus, we conclude that although.pneu=atic overpressurization will cause a reduction in si==er-=argin and thus enhance the probability of stea= cutting, it was not the pri=e factor. 3. Higher Reactor Pressure The facility was operate. during the tycle at a reactor full power pressure as high as 1047-psig, (highest reading fro = co=puter point 3013). The lowest lift pressure (recorded during the pre-installation Wyle testing), of any of the five valves installed this cycle was 1092 psig and the average was 1098 psig. s The lowest si==er =argin was: 1092 - 1047 + 45 psig The average si==er cargin was: 1098 - 1047 + 51 psig A survey of other BWR 3 and 4's (with two-stage valves), indicate that they run with an average si==er =argin of 60 psig for SWR 3's, and-80-85 psig for BWR 4's. It is interesting to note that the SWR 4 has experienced pilot leakage and the BWR 3 has not. It is our position that although the infor=ation is nct totally con-clusive, we feel that the si==er =argin is a pri=e factor in the fail-u?e of the valves, as this is a direct catalyst to pilot erosion.
8-s C. Unknown Foreign Material Plating-Out on Valve Internals This factor remains an unknown, U.S. Testing Laboratories-has been. contracted to attempt to identify the material. The results of the E avamination_and testing it expected at the end of December 1981. This may_beceme the prime factor in the valve failures; but, that is'doubtfull, as other steam co=ponents did not exhibit any unusual 4 failures. i D. Material and/or Configuration Defect in the Design of the Pilot Dise i We believe that this factor should be thoroughly investigated as-the -utility-industry has had stellite / stellite faced components'that " throttle" saturated steam for years without suffering.the degree of_ degradation that occurred in these valves. E. Conclusions I Boston Edison Company cannot, at this time, point at one specific cause for the failures and therefore,.must justify continued opera-tion with the valves refurbished'to their original' condition by ad-dressing each of the factors and either correcting the problem or provide a monitored parameter value, that below which safety rilief valves operability can be assured. A IV. ACTIONS TO JUSTITY CONTINUED OPERATION WITH REFUR3ISHED SAFETY RELIEF VALVES (TO BE COMPLETED PRIOR TO' START-UP) _A. Ensure that Pneumatic Pressure Cannot Reach 140 psig-s 1. Method 3 a. Installation and operation with a relief valve of sufficient size and with a low enough setpoint.to preveni over pressuri-zation of the solenoid valves, b. Also install and operate 'an annuciator-in the control room j to-alert the operator'of a highe'r than. normal pneumatic pressure ( 130 psig). I 3. Ooerate the Reactor at a Lower Full Power Pressure to Increase-Si=ner Margin l a. Change operating procedures to operate the EPR to =aintain_ t j-reactor pressure at a full power maxi =um of 1030 psig, as indicated by the highest _instru=ent. i b. Increase of setpoint. r 1 1 1 1 4 g
a O e j C. Prevent the Pilot Degradation from proceeding to the Point Where Safety t Relief Valve Operability Mav Be in Question 1. Method a. ~ Boston Edison Ccmpany shall monitor safety relief valve tail-pipe temperatures daily and shall take corrective action up to and including plant shutdown when tail-pipe temperatures exceed values to be deternined prior to start-up from.this outage. b. We have made some basic correlations between tail-pipe temp-erature and pilot leak rate.. We are in the process of.vali-dating the correlation, and the assu=ption that there will not be a setpoint change with a pilot leak rate of 200 lbs/hr. Once these factors have been validated, Boston Edison Cc=pany-will incorporate the tine factors and provide specific. action levels with alowable durations at these levels. i / - 1 4 ,.,.e -n,- n., m. sy p..e.-.- ,.~s-.,,- eg, e- ,,e-y ,ep---- ..--,,e ..e. w,. - ----, ,,,se.e-w-, n
s V. FURThER ACTIONS RECUIRED A. Identifv Foreign Material - Evaluate and Report 1. The responsibility t3 identify the foreign naterial, evaluate, and report on the findings should be that of Boston Edison Conpany. 2. The identification of the foreign nacerial, evaluation, and reporting is currently in progress by Boston Edison Co=pany. 3. This infor=ation should be available by January 1,1982. 3. Evaluate Consecuences of Higher Lift Pressures on Safety Analvsis 1. It is felt tha: the responsibility '?cr evaluating the conse-quences of higher lift pressures on safety analysis should be Boston Edison Conpany's. 2. Currently this evaluation is in progress - G.E. Contract. 3. The conpletion date for this evaluation is January 1, 1982. 4. The possibility of increasing the setpoint of the valves to provide additional sL= er =argin yet maintain the integrity of the safety analysis will be investigated. j l
7 SRV DAIA- -PLANT ID "A" CARTRIDGE SR #1054 ? BASE SR #133 SOV SR #26 AVG SET PRESS'1102 PSIG LOW SGT PRESS 1095 PSIG j AS FOUND LIFT PRESS: 1210 PSIG (+104) i LEAKAGE 880 L3M/HR INSERVICE DATE: 5/13/80 PLANT ID "3" CART SR'#1048 BASE SR #8 SOV SR #1 AVG SET: 1095 PSIG LOW SGT: 1093 PSIG AS FOUND: 1136 PSIG (+30) LEAKAGE EST: > > 500 LBM/HR INSERVICE: 5/13/80 PLANT ID."C" CART SR #1049 BASE SR #117 l SOV SR #125~ AVG SET: 1097 PSIG LOW SGT: 1095 PSIG i AS FOUND: 1230 PSIG (+124) LEAKAGE EST: >500 L3M/HR INSERVICE: 5/13/80 PLANT ID "D" CART SR #1046 3ASE SR #10 SOV SR #133 AVG SET: 1101 PSIG l LOW SGT: 1091 PSIG I AS FOUND: 1136, 1113 TO 1094
- TEST PROBLEM
- LEAKAGE 8.5 L3M/ER
- INSERVICI:
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1 RELIEF VALVE SOLENOID LEAK TEST 11-3 ,.e p / 1.0 - gr i i A SOLENOID VALVE [ 9-SERIAL tt26 I l l I l 8 B SOLENOID VALVE I f [ 8 .7 - SERIAL tri I l e C SOLENOID VALVE l f l SERIAL tt125 of s c Al y B .5 - ] 3: 4 0 .4 - 8 l j [;8, D SOLENOID VALVE l l su { SERIAL tt191 y oo 3- < m. x l i5 2-e a .1 - l l ] e I l \\ SATISFACTORY LEAK RATE FOR f BOTH AIR OPERATOR AND ROLENOID ASSEMBLY COMBINED IS 0.1 SCFH l j '06 - l AT (70-110 PSIG) 1 l .04 -. NOTE: THIS TEST WAS CONDUCTED f a ON SOLENOID VALVE ONLY. t .I 02 ' hW /j O r i i i i i i i i i i i i i i i i i ^ 100 120 125 130 135 140 145 150 155 160 165 170 175 180 185 190 195 200 INLET PRESSURE 'PSIG" ] FIGURE 6 F
e <.. SRV DATA PLANT ID "A" CARTRIDGE 3R #1054 BASE SR #133 SOV SR #26 AVG SET PRESS 1102 PSIG LOW SGT PRESS 1095 PSIG AS FOUND LIFT PRESS: 1210 PSIG (+104) LEAKAGE 8S0 LBM/HR INSERVICE DATE: 5/13/80 PLANT ID "B" CART SR #1048
- BASE SR #8 SOV SR #1 AVG SET:
1095 PSIG LOW SGT: 1093 PSIG AS FOUND: 1136 PSIG (+30) LEAKAGE EST: > > 500 LBM/HR ~ INSERVICE: 5/13/80 PLANT ID "C" CART SR #1049 BASE SR #117 SOV SR #125 AVG SET: 1097 PSIG LOW SGT: 1095 PSIG AS FOUND: 1230 PSIG (+124) LEAKAGE EST: > 500 LBM/HR / INSERVICE: 5/13/80 PLANT ID "D" CART SR #1046 BASE SR #10 SOV SR #133 AVG SET: 1101 PSIG LOW SGT: 1091 PSIG AS FOUND: 1136, 1113 TO 1094
- TEST PROBLEM
- LEAKAGE 8.5 LBM/HR
- INSERVICE:
12/2/81 FIGURE 7
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