ML20134C653
| ML20134C653 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 02/04/1994 |
| From: | Wenzinger E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | Lanning W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| Shared Package | |
| ML20134C519 | List: |
| References | |
| FOIA-96-351 NUDOCS 9702030234 | |
| Download: ML20134C653 (45) | |
Text
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From:
Eduard C. Wenzinser (ECW)/ ' j To:
WL W,
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Date:
Friday, February 4, 1994 3:44 pm Subjects EVENTS 8 SALEM THE ATTACHED WRITEUP IS A FIRST DRAFT SUISSRY OF RECENT [88 941 PROBLEMS AT SALEM. IT SHOWS RECURRENT THEMES. W ARE FINE TUNING
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I IT, BUT I THOUGHT YOU SNOULD READ IT NOW, ANYWAY.
IT MAKES INTERESTING READING.
ALSO INTERESTING ARE THE RESULTS OF THEIR SELF ASSESSMENT TEAM EFFORTS THAT CONCLt2ED THAT THE MAIN CONCER$ IS " MANAGEMENT".
MILTONSERGER, IN A DISCUSSION WITH JOHN, CHARLIE AND I ON WEDNESDAY, [2/2/943 CALLED IT "A PEOPLE PROBLEM" AND A
" LEADER $ NIP" PROBLEM. I THINK NE WAS RIGHT.
INCIDENTLY, MILTONSERGER 18 PLANNING A " DROP IN", PROSASLY MENT WEEK TO TELL US A80VT NEAR TERM NANAGEMENT CHANGES. NE WILL MAY TELL US THAT THEY ARE SPLITTING SALEM 1 AND SALEM 2 INTO TWO MANAGEMENT TEAMS.
SRANCH 2 MANAGEMENT AND STAFF 15 CONCERNED THAT THE NEXT SALEM EVENT COULD SE SIGGER TNAN $ NUTTING DOWN SOTN UNITS DUE TO GRASS AND ICE, OR 4+ FAILED STARTUPS. THE SCONER W 00 A " DIAGNOSTIC" OR SIMILAR INSPECTION [ CALL IT WHAT YOU WANT), THE SETTER.
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CSM, JGS, STS, TMF Files Ps\\ EVENTS. SAL 4
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9702030234 970116 PDR FOIA 0'NEILL96-351 PDR:
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6 MEMORANDUM FOR:
Ed Wenzinger, Chief l
Projects Branch 2 THROUGH:
John White, Chief Projects Section 2A I
FROM:
Scott Mo'rris, Reactor Engineer l
Projects Section 2A
SUBJECT:
COMMON ROOT CAUSES OF RECENT SIGNIFICANT EVENTS AT SALEM GENERATING STATION l
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Enclosed as Attachment 1 is a summary of recent significant events at Salem which, when viewed in the aggregate, indicate a continuing problem in the licensee's management i
organization.
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l Upon a review of this document, several recurring themes are present:
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o lack of aggressive management oversight of plant activities Lack of aggressiveness to assure adequate corrective action implementation.
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Inadequate root cause analysis of events
.o Slow identification and evaluation of degraded plant conditions j
o lack of procedural compliance i
When pressed for explanation or resolution, the response on the part of the licensee is often is the same. For example:
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Rey believe that their programs are on improving trends o
Dey are committed to excellence and plant betterment o
They have improved the quality of their procedures i
o They are dedicated to better training of their employees o
They have taken steps to improve management oversight 1
In light of the continuing events at the facility, the effectiveness of these stated enhancements j
is in question.
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SUMMARY
OF RECENT SIGNIFICANT EVENTS AT SALEM OUTAGE TEAM INSPECTION (October 1988)
Multiple examples of lack of direct management control or effective action with regard to the design change / modification / installation process. 50.59 reviews exhibited a lack of attention to detail. QA audits were identifying program problem areas but their effectiveness was minimal due to a lack of management aggressiveness to assure corrective action implementation. (IR 88-80)
Licensee responded to report in March 1988 letter, stating:
- taking strong and effective action to resolve
- committed to excellence in Engineering and Plant Betterment
- improved design change control process
- improved training of personnel
- enhanced weekly meetings
- initiated Offsite Safety Review group evaluation MAINTENANCE TEAM INSPECTION (Anril 1990)
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Several problems were noted regarding adherence to procedural requirements and to the effectiveness of controlling contractor personnel. The identification, evaluation, and correction of deficient conditions were also areas noted to need increased management attention. Report identified several examples of personnel performance errors, particularly in the area of mechanical maintenance. Inadequate root cause analysis was noted. Quality verification i
activities identified as being weak. The probability that adverse generic plant material conditions could exist for long periods of time before the licensee is able to discover and correct the j
problems was noted. A quote from the reports stated "Although the instances discussed above are not individually significant with regard to safety, the team concluded that the number of examples identified indicated a general failure by licensee and contractor personnel to follow
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procedures during the performance of work activities." (IR 90-200) j INTEGRATED PERFORMANCE ASSESSMENT TEAM INSPECTION (May 1990)
Team noted a management tolerance of degraded plant conditions. Also identified a need for improved safety perspective. Weaknesses in management oversight of plant activities, including a lack of field presence were documented, as well as significant weaknesses regarding adequate review and timely implementation of corrective actions. Weaknesses were also observed in procedure quality, procedure implementation, and Incident Report initiation. Misuse and lack of management control of the temporary modification process was noted. Several safety tagging errors were not documented in incident reports. (IR 90-81)
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CATASTROPHIC FAILURE OF THE MAIN TURBINE (Nove=her 1991) f The Unit 2 main turbine catastrophically failed due to an overspeed condition caused by mechanical binding of turbine control solenoid valves. Root causes were determined to be personnel error, lack of procedural compliance, insufficient supervisory oversight, and lack of attention to detail. (AIT IR 91-81)
I FIRE WATCH FAIliIFICATION (1991-1992)
Following an incident on July 1,1992 when a PTI supervisor noticed that a PTI employee failed i
to properly complete the required fire patrol, an investigation was launched that subsequently determined that this willful conduct was being perpetrated by 19 out of 35 employees.
j Licensee's initial investigation into the matter was considered inadequate, but the follow up effort was praised. Root causes werew determined to be willful misconduct by contractor employees aggravated by a lack of sufficient management oversight. (IR 92-09) 4 FAILURE OF OVERHEAD ANNUNCIATORS (D:--- " cr 1992)
Unit 2 Operators discovered that the overhead annunciators had not been updating alarms for about 1 1/2 hours as a result of an operator entering a keystroke combination into a remote l
control workstation that locked up the system. Root cause was deterrrdned to be a failure of q
personnel to follow procedures for proper OHA system operation. Further, the design of the OHA system did not alert operators to a critical switch that was mispositioned. (AIT IR 92-81) l ROD CONTROL SYSTEM FAILURES (May 1993)
Unit 2 operators experienced several problems with the rod control system; the most significant being that a rod actually withdrew 15 steps during an attempt to insert Shutdown Bank A. Root 2
l causes were primarily determined to be equipment design related, however some component l
failures were attributed to poor work practices during system troubleshooting and testing. Also, troubleshooting efforts once the problems arose lacked clear leadership and delegation of responsibilities. Concerns also arose due to the fact that the licensee conducted several startup attempts without a concerted effort to determine the root cause of the problems, indicating a lack of safety consciousness on the part of management (5th startup stopped with NRC intervention).
(AIT IR 93-81)
A management meeting was held in July 1993 to discuss events of the past several years that led to AIT's and other significant occurrences. The licensee initiated a comprehensive self assessment team (CPAT) to investigate these recent performance issues in order to detect common causal factors and prevent their recurrence.
ATTACHMENT 1 i
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OUTAGE 1R11 WORK CONTROL PROBIIMS (October - Decamher 19911 During the conduct of Unit I refueling outage, the licensee and the NRC identified numerous examples of failure to follow established procedures relative to the control of maintenance work activities. Of particular note was the failure on the part of the licensee to effectively assess these occurrences, determine root cause, and establish appropriate corrective measures to prevent recurrence. Though none of these instances (when considered individually) significantly affected plant safety, in the aggregate there is a. concern that the potential exists for more serious consequences. (IR 93-23)
During the enforcement conference held February 1994, the licensee maintained that:
- their self-identification of events process works
- procedures are in place to ensure safe practices
- management presence in the field has increased
- there is enhanced review of events at weekly meetings
- safety stand downs / training were conducted to reaffirm policy
- they are decreasing the contractor force to better maintain oversight
- they will limit the scope of future outages
- personnel accountability for actions will be reinforced OUTAGE 1R11 ISSUES (Octahar 1993 - Ja-ary 1994)
The licensee experienced several difficulties during the outage relative to hardware modifications. Examples include:
(1) Unit 1 Auxiliary Feed Water (AFW) pump A governor (which was operating normally) was replaced twice with identical but different spares that were ultimately determined to be of a different configuration than the original.
The original governor was eventually reinstalled on the pump.
Procurement of the spares should have identified the difference in configuration, indicating a lack of attention to detail or inadequate procurement procedures.
(2) Unit 1 Main Feed Water pump Configuration of the turbine speed control system was changed to incorporate a dual pressure control oil configuration to support future installation of a digital feed water control system. When subsequent testing revealed that flow oscillations were occurring as a result of the changes, the pump was restored to its original configuration. In addition, though the modification had been successfully installed on Unit 2, the licensee reduced power on this operating unit to effect repairs on its modified feed pump turbine speed control system before the problems with the Unit 1 installation were fully understood.
(3) Emergency Diesel Generator (EDG) cylinder liners ATTACHMENT 1
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Licensee performed vendor recommended 10-year overhauls of the engines, even though the run time on the machines was far below that assumed for a 10 year overhaul 4
recommendation. During the maintenance, cracking was identified in non-OEM liners which the licensee had procured from an alternate vendor and self-certified as "Q."
However, it was later determmed that the liners had dimensional differences from the original equipment and probably resulted in the observed cracking. This discovery led l
to an approximately 3 week extension to the Unit 1 outage and caused a forced 3 week 1
shutdown of Unit 2 because of the suspect operability of the EDG's in Unit 2 that j
underwent liner replacement. Further, upon identification of this problem, the licensee's immediate response was to attempt repairs to the affected diesels before determining what j
the actual root cause of the liner cracking was. As a result, the exact cause of the cracking may not have been fully evaluated.
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ATTACHMENT 1 4
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TECHNICAL ISSUE
SUMMARY
l No: RI-94-01 Date: 2/8/94 4
CONTROL ROOM VENTILATION SINGLE FAILURE VULNERABILITY j
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j PROBLEM: In July 1993, the New York Power Authority (NYPA) identified a potential design l
deficiency at FitzPatrick while reviewing industry operating experience data concerning control room ventilation systems. NYPA identified that FitzPatrick's control room ventilation system contained locked open bypass dampers around the inboard supply and exhaust dampers that were not shown in l
l the system prints. In September 1993 after a series of inspections, tests and evaluations, engineering confirmed that if a single failure of either the intake or exhaust isolation valve were to occur, unfiltered air would leak into the control room.
EVALUATION: The bypass dampers did not appear in controlled system drawings and were not included in system operating procedures; however, these bypass dampers were shown in a drawing in 4
the FSAR. The bypass dampers appear to have been locked open since initialinstallation. NYPA also determined that their NUREG 0737 submittal for control room habitability (Item III.D.3.4) did not identify these bypass dampers on the ventilation figures or account for them in the leakage rate analysis.
Further review of this issue by engineering also identified additional potential single failure concerns i
in October 1993. Specifically, some control and power cables for safety-related ventilation system fans, i
dampers and valves were identified as non-safety-related and were routed in common, non-safety-related electrical raceways.
j LICENSEE /NRC ACTION: 'Ihe control room ventilation system was placed in the isolate mode of j
operation, which shuts the supply and exhaust isolation valves and dampers, and provides make-up air
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through the emergency supply filter trains and fans. In order to resolve the immediate cable separation concern, NYPA opened appropriate supply breakers and disconnected appropriate cables. NYPA also l
initiated an action plan to complete further evaluations, reviews and corrective actions. NYPA
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performed a safety evaluation to allow the plant to operate with the control room ventilation system in its modified state. The plant is currently at 100% power and the resident inspectors are continuing to 5
follow this issue.
i CONTACT: Richard Urban (610) 337-5271; William Cook (315) 342-4907 i
IR 50-333/93-14 & 24; LER 93-19; EN 26106; NRCIN 86-76; INPO OE 2465
REFERENCES:
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ORIGINAL SIGNED BY:
Donald R. Haverkamp Technical Assistant Division of Reactor Projects
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T. Martin, RA W. Kane, DRA V. McCree, EDO
-J. Calvo, NRR F. Gillespie, NRR B. Grimes, NRR R. Capra, NRR B. McCabe, NRR A. Chaffee, NRR R. Baer, RES K. Raglin, AEOD E. Merschoff, RII E. Greenman, RIII A. Beach, RIV K. Perkins, RV J. Wiggins, DRS W. Hehl, DRSS J. Durr, DRS J. Joyner, DRSS P. Eapen, DRS W. Ruland, DRS K. Abraham, PAO D. Screnci, PAO DRP staff 1
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l Salem performance Safety Review Group (SRG, the ISEG equivalent) determined to be ineffective.
o World Series issue; off-shift SRO candidate patched ball games into his work area o
through the control room telephones. The SRO candidate has been termin*i.
l Two ROs have also been disciplined for listening to the game on the handset.
j Other ROs were involved in transferring the call through the control room. In i
my opinion (SRI), this is indicative of poor work ethic among the operators.
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Response to Salem Unit 1 Airborne Particulate Radiation Monitor actuations were
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ineffective. Initially, licensee root cause determination was superficial, j
Three Unusual Events in the first month of the Salem Unit I refueling outage.
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Contammated worker Fire in Primary Auxiliary Building Fire in electrical lighting panel o
Inadequate EDG surveillances at both Salem units.
Monthly TS surveillance uses both air start systems, all four motors for i
each EDG.
Licensee has not, since original acceptance tests, demonstrated capability of redundant air start systems to start the diesels, as stated as stated in the f
FSAR.
l Licensee has occasionally valved out an air start system and considered
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that the related EDG remained operable Multiple examples, during current Unit 1 outage, of procedure use for o
documentation, as opposed to control, of safety related activities.
Work on a Service Water supply valve to a Containment Fan Cooling Unit (23SW58) was performed using an uncontrolled vendor technical manual.
Work on SFP cooling MOVs to replace jumpers.
Removal and replacement of no.12 Service Water header.
i Component Cooling Water to Service Water pipe replacement.
Removal of spare ccms fmm Auxiliary Feedwater Bailey Controller i
without procedural control, work order, or other documentation.
Multiple examples, during current Unit 1 outage, of failure to follow procedures.
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4 Failure to following tagging procedure resulted in electrical contractors cutting an energized 125 VDC cable.
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Three additional examples of failure to follow the tagging procedure.
Service Water valve 23SW58 was removed from the RCA without entry in the required HP log.
Production-oriented approach to resolving EDG cylinder liner issue.
o Initially, licensee intended to replace 3R cylinder sleeve, declare the EDG operable, and exit LCO. On 12-2-93, the licensee asked the Region to be prepared for a NOED discussion to support this approach. The licensee 4
evidently did not intend to determine the cause of the cylinder failure prior j
to considering the problem resolved.
The licensee abandoned this approach when they found what they believed (then) to be indications of crack in the EDG block.
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a cs SALEM EVENTS 2/9 13/94 2/10/94 [1258 hrs]- UNIT 1 100% POWER REACTOR TRIP - EHC POWER SUPPLIES CONCIDENT LOSS OF LAMOOA TYPE POWER SUPPUES RESULTED W LOSS OF EHC AND MSULTANT FUU POWER REACTOR TNP. CERT WAS WITIATED TO FNO ROOT CAUSE. PROXIMATE CAUSE WAS ACTUATION OF OUTPUT CIRCUff *CROWSAR* FEATURE. THE FAILURE
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OCCURRED CONCIDENT WITH CLOSMG THE CASMET DOOR AFTER CHANOMO THE AIR FS.TER N THE DOOR. EXERCISNG NTEfMAL CAKES PERTURBED THE PS VOLTA 00 BUT NOT ENOUGH TO ACTUATE THE CROWSAR CIRCU:T. ALL NTEMAL VOLTAGES WERE NOfWAL.
l 0 WIRE CNMPS WERE LOOSE: THEY WERE REPAfMD. CROWSAR SETTMOS (TNP ON H00H VOLTAOEl WERE SL10HTLY LOW; THEY WERE RESET. ACTUATION OF THE CROWSAR CIRCulT COULD NOT BE DUPLICATED.
WESTNGHOUSE HAS RECOMMENDED REPLACNG NTEMAL WINNG SECAUSE OF EXCESS VOLTAGE DROP N THE WIRNG.18AWG WAS REPLACED W/14AWG. NOMINAL BUS VOLTAGE WCREASED IV, AS A RESULT OF THE LARGER WIRE.
THERE ARE 2 POWER SUPPLIES 'A' & '8'. DOTH POWER SUPPLIES HAD VOLTAGE ADJUST POTS THAT DID NOT OPERATE SMOOTHLY. THEY 2
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EXERCISED BOTH. THE 'A' SUPPLY CONTNUED TO HAVE PROKEMS. THE 'O' SUPPLY SEEME0 OK AFTER THE POT WAS EXERCISED. THEY REPLACED THE 'A' POWER SUPPLY, THE ROOT CAUSE OF THE CROWSAR ACTUATION 4 NOT UNOERSTOOD BY THE LICENSEE. RES10ENTS ARE FOLLOWING UP POTENTIAL FOR OTHER APPUCATIONS OF SAME POWER SUPPUES TO FAL.
2/11/94 (0800) - UNIT 1 1B EDG AIR START (COMPRESSORI TURNED OFF I
UCENSEE WVESTIGATNG CAUSE OF MANUAL CONTROLLER FOR SOTH [TWOI REDUNDANT COMPRESSORS BENG W OFF POSITION N THE UNIT 1 D/G AIR START SYSTEM. MAY HAVE BEEN NADVERTENTLY 1771 LEFT OFF AFTER KOW DOWN OF AIR RECEIVER. (MAYSE NOT SY PROCEDURE.1 SOTH A/C'S WERE RESTARTED AND AIR PRESOUfE RECOVEMD SATISFACTONLY.
THERE ARE 2 A/C'S THAT FEED 2 PARALLEL AIR RECEfVERS. THE RECEIVERS WERE SOTH FOUND AT 100 psi. NOlm4 ALLY THE AIR PRESSURE 15 220 to 250pel THE ALAfW [ COMMON D/G TROUSLE N C/R1 IS SET AT 160 psi. SEVERAL START ATTEMPTS CAN BE MADE AT 150pel RESIDENTS BELIEVE, FROM DISCUSSIONS WITH OPERATORS. THAT SOME TECHNICIANS MANUALLY TURN OFF THE COMPRESSOR WHEN CHECKNG COMPRESSOR OIL WITH A DIP STICK. SO THEY DON'T GET SPRAYED WITH OL, IF THE AIR COMPRESSOR STARTS AUTOMATICALLY, OR MAY TUfM OFF THE AIR COMPRESSOR IF THEY *EOW-DOWN' ONE OF THE AIR RECEIVERS. THEY UCENSEE HAS y
1 QUESTIONED 30 OF 70 PEOPLE WHO M10HT HAVE OCCAS40N TO TUfM OFF THE COMPRESSORS. NO ONE HAS ADMff7ED DOING ITt THERE WAS A SIMLAR EVENT ON 2/0/84 WHEN gg AIR COMPRESSOR WAS FOUND OFF AT UNIT 2. [2A D/G1 4
AIR RECEfVER FOUND AT 100 pol. NOfMAL IS 250 poi. LOW PRESOUfE SET PONT 18150psL THE SECOND AIR RECEIVER AND COMPRESSOR WERE UNAFFECTED. THE DIESEL WAS OPERAaLE THROUGHOUT.
i ON 2/18/84 LICENSEE (MILTONSERGER) TOLD US THAT THEY DISCOVERED THAT THE PMSSURE SWITCH FOR T
s THIS PMSOUfE SWTTCH IS USED TO ACTUATE AN ALAfW ON LOW i
0 IN H AIR D/G TROUSL
'rW W THE CONTROL ROOM.
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MILTONSERGER NFOfMED US THAT THEY Aff RAISMG THE t.t3 POINT OF LOW PRESSURE N THE AIR RECEIVER TANKS. CLOSER TO THE NOMMAL VALUE OF 220 2Sopei OPERATNG PRESSURE.
4 2/13/94 - UNIT 1 UNCONTROLLED COOL DOWN AT 2% POWER LICENSEE NVESTIGATNG CAUSE OF STEAM DUMP VALVES (TO CONDENSER) OPENWG. OPERATOR ACTIONS APPEARED APPROPNATE.
IINCLUDED OPERATORS DNVWG W CONTROL RODS. PLACMG DUMPS N MANUAL. AND FOLLOWING THEIR PROCEDUREl. APPARENTLY I &
C TECHNICIANS ACTIONS CAUSED THE VALVES TO ACTUATE.
i RCS GOT TO 63Sf. T/8 REOUIRES 841't WITHW 15 MMUTES. T/S WAS MET SY OPERATOR MANU,M. ACTIONS.
REACTOR POWER NCREASED FROM 2% TO S.0%. MODE 1 IS DEFNED AS ASOVE 6%. THEREFORE, THE CHANGE TO 5.0% WAS A MODE CHANGE FROM 2 TO 1. IT WAS UNPLANNEDI i
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4 PROXIMATE CAUSE WAS la C TECH NSERTNG WlRES NTO PRES 8URE TRANSDUCER. THE WIRES WERE ENERGlZED. THE ENERGlZED W1REIS) SHORTED TO GROUND. THE SHORT CAUSED THE STEAM DUMP 8 TO ACTUATE. THE TECHNICIAN WAS REPLACNG THE TRAN8DUCER. UNKNOWN TO THE TECHNICIAN AT THE TIME WA8 THAT THE TRANSDUCER WAS CONNECTED TO A SUMMATOR THAT HAD ANOTHER PRES 8URE TRANSDUCER CONNECTED. THE TECHNICIAN HAD REMOVED THE POWER FROM THE TRANSOUCER HE WAS REPLACNG, BUT NOT THE OTHER TRANSDUCER CONNECTED TO THE SUMMATOR. ELECTRBCITY FROM THE TRANSDUCER THAT WAS STILL ENERGlZED FED THROUGH THE SUMMATOR TO THE LEADS BENO FE0 TO THE REPLACEMENT TRANSDUCER. THIS '8NEAK CIRCUIT
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SUB8EQUENTLY RECOGNI2ED. THEY WILL NOW TAPE LEADS DENG DISCONNECTED FOR EQUIPMENT REPLACEMENT, J
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t Licensee performed vendor recommended 10-year overhauls of the engines, even though the run time on the machines was far below that assumed for a 10 year overhaul recommendation. During the maintenance, cracking was identified in non-OEM liners which the licensee had procured from an altemate vendor and self certified as "Q."
However, it was later determmed that the liners had dimensional differences from the original equipment and probably resulted in the observed cracking. This discovery led to an approximately 3 week extension to the Unit 1 outage and caused a forced 3 week shutdown of Unit 2 because of the suspect operability of the EDG's in Unit 2 that underwent liner replacement. Further, upon identification of this problem, the licensee's immediate response was to attempt repairs to the affected diesels before determining what the actual root cause of the liner cracking was. As a result, the exact cause of the cracking may not have been fully evaluated.
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REGION I PLANT STATUS REPORT 4
FACILITY: Sales Nuclear Generating Station Units 1 and 2 i
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marvemam II.
PLANT PERFmam* DATA III.
Am4 LYSIS /ASSEssENT IV.
IllSPECTION Pe0 MAN STATUE v.
ATTAosumis Last Update: March 15, 1995 update w t:
Section Chief CNMIES SIIN:E TE LAST LPDATE ARE DEMARCATED IN TE BORDER
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0 ATTAugENT A CONTENTS 1.
BAMMMS 1.
Licensee Parameters 2.
NRC Organization 3.
Llwensee organtastion 4.
Operator Licensing II.
PLANT PERHSMREE DATA
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Current Operating Status (last 6 senths) 2.
Recent significant operating Events and Identif f ed Safety concerns (of last 12 months) 3.
Escalated Enforcement Activities (of test 2 years) 4.
IPE Insights III.
ANALYSIS /A85ESSENT 1.
Previous SALP Ratings and overview 2.
Licensee Response to Previous SALP Functional Aree Weaknesses /Recent Licensee Performance Trends (in the test year) 3.
Licensee Performance Strengths and Weaknesses 4
NRC Team Inspections Within the Last Year 5.
Planned Team Inspections IV.
IEWECTI M PROMAN STATUS 1.
Status of Inspections (see attached MIPS Report #2) 2.
Proposed Changes to MIP j
3.
Significant Allegations and Investigattens j
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Open Item Status 5.
Outstanding Licensing Issues 6.
Local / State /Externet Issues l
V.
ATTAugENTS (NOTE: To be determined based en intended anaHence) 4 l
1.
AEOD Performance Indicators /LER Summary O 2.
Altogettone Status O 3.
Most recent SALP Report O 4.
MIPS Report Nos. 2 1 22 0 5.
Principel Staff Resumes (NAC and Licensee) O 6.
Plamed vs. Completed Inspection Hours O l
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i Salem PSR Page 1
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I. BACKGROUND
- 1. LitElleEE PARAfETERS Utility:
P 4 tic Service Etoctric & Ces company (PSE&G)
Ccapeny Locations Mancocks Bridge, NJ (18 mitee Southeast of Wilmington, DE)
Comty:
Selen UNIT 1 UNIT 2 Docket No 50 272 50-311 CP leeued:
September 25, 1968 Septenber 25, 1968 Operating License Issued:
April 6,1977 May 19,1981 Inittet criticality:
December 11, 1976 August 2, 1980 Elec. Ener. 1st Gener:
December 19, 1976 May 29,1981 Commerclet Operetton June 30,1977 October 13, 1981 Reactor Type PW 4 Loop Some Containment Types Large dry Same Power Level:
3411 padt some Architect / Engineers PSELC/UESC some NS$$ Vendor Westinshouse Some Constructor:
PSE&G/UESC Sanc Turbine S w llers Westinghouse Westinghouse (GE Generator) y Condenser Cooling Method Once through some Condenser Cooling Water Detswere River same
- 2. IRC (RCANIZATimi NaC Regional Adminletrator:
Thames T. Martin (Tel: (10 337-5000)
(Region I, King of Prusef e, PA)
Divfelon of Reactor Projects:
Alchard Cooper, Jr., Divleton Director (Region I) (Tels 8-610 337 5229)
Wayne Lemning, Deputy birector (Tels 8 610 337 5126)
John R. Wite, Section Chief (Tels 8-610 337 5114)
Senior Reeldent Inspector Charles S. Marschall (Tels 8-609-935 3850)
Roaldent Inspector:
Joseph G. Schoppy, Jr. (Tels 8 609-935 3850)
Reefdent Inspector Todd N. Flah (Tets 8 609 935 3850)
Project Engineer:
G. Scott serber (Tels 8-610-337-5232) l Project Meneger:
Leonard Olehen, NRR (Tels 8 3015041419) i i
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i Salem PSR Page 2
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- 3. LIENSEE ORGANIZATION Meneaement Personnet E. James forland Chelrmen and Chief Executive officer Leon R. Elleson Chief Nuclear Officer and President Nuclear Business Unit Stanley Letrune
-Vice President, Nuclear Engineering Joseph Mssen Vice President OperetIone John Summers
- General Manager Salem Operations Jeffrey Benjamin General Manager, Quality Assurance &
9 Nuclear Safety Review Charles Muruenseler Director, Operatione Servicoe -
Chuck Johnson
-Director, Numan Resources & Administration Francis X. Thomson Licensing Manceer Lee Catelfomo Operations Manager
. Michael P. Morrent
-Manager, Maintenance Controle Michael Metcalf Manager, Maintenance-Mechanical Jerome A. Benelli Technical Meneger -
Eric Katamen Radiation Protection / Chemistry Manager - -
Dennie Tauber
$alen QA Manager -
Terry Cellner Manager, solem Stetton Planning ~
Arthur Orticelle
-Manager, Nucteer Training d
Workohlfts 5 operations ehlfts, 2 working 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shif ts/dey, i relief crew, 1 crew in training, 1 crew of f.
c ShIff Comptemant TS aInImun ag,1]al 3 SR0 4 SRO 4 to 5 to 1 STA 1 STA (dal role SRO)
Non-licensed Operators 5
7 or 8 Maintenance Electrician /IEC 1
2 Chemistry / Red.
Prot.
1 2
d Fire erigade 5
6 (site fire brigada shared with Hope Creek) l 4
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Sales PSR Page 3
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- 4. OPERATM LIENSING
- a. Licensed peactor Goerators flicensee Cover Both Unitsit 1
e Total number of active saos:
28
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l Total na ber of active aos:
26 i
e Total ramber of certified instructors:
13 e
one sinalator (modeled af ter Unit 2) located at the training feellity in salem, j
NJ, and used for Unit 1 and Unit 2 operator training and NaC administered ticonsing esame.
P$E&G completed a mejor modelins L@0rade package in the sunner i
of 1993.
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Salem PSR Page 4
II. PLANT PERFORMANCE DATA
- 1. nasemi OsERATINS STATUS (for period 1/29/95 to 3/11/95)
Unit i began the period operating at 100% power.
On February 3, the licensee initlated a mit shutdown to cogly with plant Technical Specifications.
During implementation of a DCP to correct a problem with a solid state protection system (SSPS) power food, a rededent power sigply tripped.
The licensee wee unable to fully restore SSPS to operability within the technical speelfication limiting condition for operation action statement allowed outage time.
On February 4, the licensee entered Mode 5 (Cold shutdown) to addrese SSPS concerns.
On February 15, operatore entered Mode 4 (Not shutdown).
The licensee meintained the mit in Mode 4 white resolving problems encountered with main steen atmospheric relief volves (MS 10s).
On February 27, operators caunenced a reactor starty.
On March 2, operators increased power to 48%.
On March 3, operators reeced power to 28% to make a bloehield entry to adjust RCP oil levels. On March 8, operators increased power to 100% and maintained the mit there for the remainder of the period.
Unit 2 began the period in Mode 3 (Not S t ar+v).
On February 1, operators commenced and cogleted a reactor startw. Ot february 3, operators commenced e Technicet Specification required shutdown from 1% power, following removal of NRC knforcement Olscretion due to potential conson made failure of $$PS power staplies.
The licensee placed the unit in Mode 5, completed troubleshooting and repelrs to SSPS, and commenced a plant start @.
On february 11, operators took the reactor critical and commenced a power increase.
On February 19, the 'llconsee initleted a shutdown from 47% power to remove the no. 21 Reactor Cootent Ptap from service in response to tow seal water leekoff flow.
The licensee entered Mode 5, replaced the no. 1 seal on no. 21 RCP, and commenced a plant startup.
On March 8, q
operators achieved reactor criticality and commenced power escalation.
The unit completed the period et 901 poser.
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2.
RECENT SIMIFICANT WERAiluG EVENTS Am IDENTIFIS SAFETY marrama 1
s.
Blanificant Events falnce Acril 1990 e
on February 3, 1995, a mit 1 main steem atmospheric relief (13nS10) velve would not open in response to manipulation of controle. On February 10, 1995, 22MS10 would not respond in automatic to steen pressure above the pressure setpoint. The 13MS10 valve These were the totest in a long history of events with MS10 (and Nogen module) performance problems (including April 7, 1994). The licensee did not initiate a thorough root cause until prompted by the residents and Regional management. A thorough root cause, performed by a multi disciplinary
- team, concluded that contributing factors included inodoquete maintenance, vendor refurbishment, design, control of parts, and operator understanding of design contributed to the perforamnce problems. (It 95 02, not yet issued.)
During late January 1995, Sales sought and was granted a Notice of Enforcement Discretion to address design deficiencies with the Solid State Protection System.
Electrical components (e.g. Limit switches and pressure sensors) associated with j
main steem, turbine controls, and fee &eter were susceptible to rendering all or most of SSPS Inoperable based on a single high energy line breek. When unexpected 4
power staply tripe occurred during the modificettors, Region I withdrew enforcement discretion, e
on January 11, 1995, with Sales Unit 2 in Mode 4, the no. 23 RCP seat water return valve for the no. 1 seat closed, isolating seat flow.
The licensee determined that the pressure diaphragm of the ASCO solenoid velve f alted because of its extensive time in service (about 20 years) cowled with the continuous air pressure applied at the diaphrope (about 80 pelg).
Plant staf f planned to establish a periodic replacement schedule for the diaphropus.
Westinghouse recommended that PSE&G inspect the no. 1 seal.
For safety consideratione (evoiding re&ced inventory) Sales management, af ter coneutting with Westinghouse and other licensees, elected to perform the maintenance by L;wering the RCP onto the "beckseet" forried by resting the redist bearing on the thermal barrier heat exchanger.
Sales maintenance completed the maintenance activity safety.
Although they fomo no seal damage the licensee reptoced the no. I seat package, e
In January 1995, the inspectors learned.het Unit 2 operated the entire previous cycle (5/93 to 10/94) with a closed drain velve in a common draln line for the Preseuriser Safety Velve loop seats. The volve should have been opened, but the a
licensee had not done en adegante post modification (Inew or odegante post-modification testing. The 10 settons of water in the loop seats would create thrust loading on the safety vetve discherpe piping with the potential to deform Salem PSR Page 5 l
the pipe, restricting flow. As a result, the loop seats could render the safety valves incopeble of protecting the RC5 from overpressurlastion.
This issue is a candidate for escalated enforcement. (It 95 02, not yet issued.)
e in December 1994 and January 1995, during startup from the refueling outage, Salem Unit 2 pressurf ter code safetles teeked post the seats chae (apparently) to deed weight and thermal loading on the discharge piping. As a result, Salem spent the period from December 25, 1994 to January 10, 1995, determining the cause of the 4
Leakage. Salem replaced the code safeties, adjusted the piping, and, as of January 31, 1995, had successfully reached normal operating pressure with no code safety seet teakage. (IR 94 35) s e
Stuck trash reke af fecting unit 1; occurred several times. On November 15, 1994, the new rake stuck or. the old trash rocks in front of the 135 CW pimp intake, forcing a power rechaction to 850 MWe. On December 7, 1994, the new rake speln stuck on the old trash rocks in front of the 138 CW pump intake, forcing a power reduction to 850 Mwe. On January 3,1995, the new reke stuck in front of 128 CW ptmp.
On January 9, 1995, the old reke stuck In front of the newly reptoced rocks in front of 1M CW ptmp intake. PSE&G replaced the rocks in front of 138 CW ptmp, and plans to replace the rocks in front of 125 and 11A by the end of February. All other rocks have been replaced at least once. (IR 94 31) e Unit 1 operators commenced a forced shutdown on January 6, 1995, due to inoperable 1A Safeguards Equipment Controls (SEC). The power s@ ply failed. Although the Alternate Test Insertion (ATI) circuit had been turned on (see below) and had produced periodic storms, the techs and operators did not pursue the stares (due to previous experience) and apparently took a power reduction that could have been avoided. PSE&G obtelned the services of an " expert
- In power s@ ply noise problems i
to try to address the suttiple ATI storms; PSE&G expects to see the expert the week of February 6, 1995. (IR 94 31) e cross intrusion into unit 1 Cire Water on December 11, 1994 Operators took 138 out of service to clean the water box. 13A tripped on high d/p. Operators rechced j
power et 5% per minute. The 12e and 12A emergency tripped. Operators rechced power to 51% while restoring the 12A and 125 CW pumps to service. (IR 94 31) e Unit 1 operators initleted en urplanned shutdown on December 9, 1994, for inoperable Sefeguards EcpJipment Control cabinets. The three SEC cabinets for each mit control secpaencing of safety rotated toads onto the 4kV vital busses. A stuck test sultch (not lamedletely identified) caused a fault indication in the test I
circult. Technicians took the test switch panel from the 18 SEC to afd in troste-shooting 1A, and inadvertently caused a stuck switch in 1B SEC. Operations and usintenance staf f concluded that a common mode f ailure might exist, declared the SECS (noperable, and started tia shutdown.
The stuck switch in 1A SEC existed from the previous surveiltence un November 23, but operators did not detect the fault since they had taken the Autcastic Test Insertion circuit out of service due to ' nuisance
- storms. (IR 94 31) e On November 28,1994, no. 2 Station Power Transformer lost power as a result of a modification in the unit 2 control room actuating promd fault protective relaying. The worker performing the mod introduced a ground fault on the reley, in conjunction with an existing grced elsedere on the merounded system (by i
design),
e Also on November 28, 1994, the no. 5 s4 station in the 13 kV ringbus lost power, cousing the TSC to lose power.
The cause was insulators arcing over. The TSC dieset started, but the TSC ventilation failed to start as a result of a blown fuse.
Fast transfers occurred successfully on both mits.
e Brookdown of insulation on 4kV s@ ply cable to the mit 1 vital buses (November 21, 1994); caused by iIquefled pulling compound dripping down onto the cabte end between the cbst boot and the heat shrink, providing a lowered resistance f rom the terminal lug to the ground strap, e
On November 18, 1994, the 4760 disconnect opened causing the no. 4 station power transform to de energite, Interrwting one source of offsite power to each unit.
Loads fast transferred at Unit 1, but 3 of 5 rmning circ water ptmps lost power, requiring operators to reduce power. Unit 2 lost spent fuel pool cooling for 17 minutes since the other source of power wee out due to the outage work.
No apparent increase in SFP tosp.
No apperont cause for the disconnect opening.
l Power was restored five days later using no.2 SPT.
e on September 29, 1994, Sales Unit 2 operators initiated a menuel reactor trip from 298 power fothwing the inadvertent closing of two main steam isolation valves (MSive).
The licensee was returning the unit to rated power following maintenance Salem PSR Page 6
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on one of the charging PLaupe.
The operators were et the point in the power esconsion procedure for closing mein steam line drains.
After acknowledging the i
order to close the main steam drelne, the operator mistakenly closed two M51Vs.
operators inittsted a menuet trip.
(see IR 50 311/M 24) d t
e on August 24, Unit 1 operators reduced power to it to repelr the condensate system suctlen header. The header sustained damage to a support pedestat and several expension jefnts when operators footsted No.12 condensate pay to replace its mechanical seel. Pressure from back bekage through the closed pump discherse bypese volve generated sufficient force to ehlft the auction header.
The licensee repelred damaged components and modified the corudensato procedure to change the 5
sequence of volve mentpulations operators follow when f ootating a condensate pmp.
l (see IR 50 272/9419) e on July 14, 19M, solem Unit 1 operators initleted a manuel reactor trip from 1005 power following a complete loss of circulators.
A lightning strike caused the
{
Unit 1 circulator ogply breakers to open on mdervoltage.
Operators responded j
correctly in tripping the reactor es condenser vacuum decreased rapidly.
(See IR l
50 272/M 14) i e
on July 2,1994, the licensee identified an unisolable flenge Leek from an mused instrument line on the No. 22 reactor cootent pap (RCP).
At the time of the i
discovery, the (fconsee was attempting to repelr the flange.
The licensee cooled j
doom and depressurized the plant (taking the plant from Mode 3 to Mode 5).
The licensee estabtlehed a freeze seal en the toeking line and replaced the salsting flenge and piping with a blank flenge.
(See IR 50 311/94-14)
I e
on Jme 29, 1994, satan unit 2 emperiences, a reactor trip fras approximately 65 reactor power 6e to low steam generator water level. Prlor to the trip, whfte 7
fncrossing power to 141, a fec ester oscilletten caused a high water tevel condition in one steen generator.
The high steam generator water Level inttleted a fee 6eter isolation.
The level oscillations occurred when the minisass flew j
valve cycled open and closed.
The licensee changed procedJres to laprove operator control of the minlaus flow velve. The licensee else changed the gain In the j
velve controls. The operator reduced power to within the capacity of sumfilary feedwater; however, before water level could be stabilized in ett generators, the no. 23 steen generator reached its low level setpoint causing the reactor trip.
(see IR 50-311/M 14) e On June 10,19M, while operating et 975 power, the Setem Unit 1 reactor i
automaticatty trlpped following a mein ponerator trip. The licensee concluded that a potentiel transfonsor felled, cousing the main generator output brookers to i
open, leading to the reacter trip. The Licensee sent the potential transformer to an outside facility to determine the cause of the component failure.
(see IR 50-272/M 13) i j
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on April 7,1994, the Unit 1 operating crew rapidly reduced power in response to e
severe river grass intrusion et the circulating water intake structure.
Sales 4
Unit 1 tripped fron 251 power durIng anneuvers to shut the plent down.
Subsequent
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to the reactor trip, the plant experienced a series of safety injections which resulted in toes of the pressuriser steam bihble and normat pressure control.
In i
additten to the reactor trip and safety injections, certain valves that are required to operate, failed to close. On April 8, the NRC dispatched en Augmented i
Inspection Team to the site to review the causes and safety leptications of the sultiple failures in safety related systems sharing the event and poselble operator 3
errors.
(see Alf Report 50-272/M-80 and 50 311/M 80) j b.
Assessment s
1 Unenticipated ogJipment deficiencies continue to dominate performance of the setem J
mits. In February both mits shutdown to correct design inadequecies with the Solid State Protection System.
Problems with main steen atmospheric relief volve I
controle deleyed unit 1 start @ etil February 27. Although operators restarted unit 2 on February 11, low seal leekoff flow f rom the no. 21 Reactor cootent Pup seal recpJired a shutdown en February 19.
As of January 31, setem Unit 1 had continuously operated for more than 150 days, etthough unit 1 operators had to redJce power six times in six weeks due to egalpment problems from November 6,
1994 to December 17, 1994. On the other hand, the salen mits have esperienced only one reactor trip in the sin months beginning August 1, 1994, as coupered with five trips in the perled from February 1,1994 to Aeguet 1, 1994. Operators have bege to take algnificantly increased ownerehlp for plant perform nce and safety.
Their involvement in Insuring nucteer and personnel safety during the inspection i
of the no. 23 Reactor Cootent Pw p seel illustrates their toederehlp in i
identifying and preventing pitfalls in plant activities. Melntenance management identified that lack of swervisory oversight of job briefines had resulted in i
Sales PSR Page 7 j
(neffective worker preparation for maintenance activities. Steps have been taken i
to leprove the job briefings. System engineering s@ port for delly operations and maintenance activltles continues to require significant leprovement. White some improvement has been noted in design engineering support for dail) activities, plant and design engineering senior management involvement was frecpently required I
to force casummicetion between the organizations. Plant s@ port organizations continued to demonstrate excellence in their activities.
j overett, the ntaber of cheltenges to moventful sales operatione continued at a l
high rate in comparison to other plants such as Hope Creek. Senior PSE&G l
management has leptemented a ramber of changes intended to address the need for change, including replacing the Chief Nuclear Officer, the Salem General Manager, j
- the spellty assurance and nucteer safety review mensper, the station quality essurance manager, the mechanical maintenance manager, the planning manager and I
the plant technical stoport manager. Senior PSE&G management met with Region I senior annagement on March 12, to present a proposed sales reorganization. The new organtration would add a mit i director and a mit 2 diretor reporting directly to the Setem general manager. The new organization would etso add (for each mit):
a unit operatione manager, unit senior nucteer shift supervisor, unit maintenance manager, unit planning manager, and unit outage planning manager, setem management has taken steps to increase the emphasis on accountability from the Vice President of operations down through all levels of management to the workers. Leon Eliason initiated a team of consultants and nuclear industry senior managers to determine why PSE&G actions to improve Sales performance have been inef fective. In addition, 1
Mr. Elleson has initiated a process to bring about a
- step change
- In sales performace. This process is intended to hold managers accountable for achieving results, as opposed to past emphasis on generating activity, i*tthough some i
omanples of leproved performance have occurred, especially in the eres of operations and maintenance, it cannot yet be determined whether PSGd actions will result in lasting changes.
c.
Performance ladicator Data FM AEmi 70 trDATE 1
units 1 and unit 2 i
)
d.
Recently Identlffed Technical Safety and Manaaerlat Challennes (of test 12 months) e The $ stem mit 2 refueling outage, scheduled for TT days, extended to 110 days as a result of ocpipment problems, including pressuriser code safety volves teeking past the seat.
e toth SeIam mits shutdown in early Fobruary 1995 che to inadecpete desien of the Solid State Protection System. A single steen line f ailure in the turbine building could have rendered both trains of $$PS inoperable with the result that operators would have been required to manuelty initiate safety injection.
e Both Salem mits suffered performance failures in the controls for the main steam d
safety atmospheric relief volves. These controls have a tone history of inadequate control and maintenance.
In the most recent problems, the licensee again discovered unexpected components in the control circuits, demonstrating ineffective corrective action for the tevel IV vlotetton af ter the April 7,1994, event.
j e
A asuber of attegations with potentfel safety significance have been stbstantIated, IncludIngs o
inadecpste PORV desf on, with the result that re& ndant capability to limit RCS pressure under low tenperature conditions had not been assured (an USQ with the potential for escalated enforcement);
o instattation of non-4 timit switches in safety-related applications, two of the eight (for both mits) head vent valves, with the result that repeat problems with safety related part controls raise programentic questions about the sales ability to control safety related maintenance (currently being reviewed for escalated enforcement); and a
o incorrect Technical specification definition of controlled teskoge, with the result that safety Injection flow steplied to the core, in the event of a RCP seat ogpty line fatture & ring en accident, could have (and at times would have) been less then esstseed in the accident analysis (no vlotetton was issued, since Salon was always in compliance with the Technical Specification requiremente).
Salem PSR Page 8
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1 The Senior Resident inspector has personnely seen evidence that the atteger made s.
j the concerne known to the licensee and that the Licensee did not respond in a i
timely, conservative fashion.
Although some of the attegations from the same source were estdistentiated, severet more have yet to be addressed.
J e
The Licensee discovered on October 15, 1994, 2 days into the unit 2 refueling outage, that a velve in the pressurlser code safety valve loop seet drain line had been closed throughout the operating cycle from July 1993 until October 1994 The Isandlete safety laplication is that the licensee could not assure, based on any onetysis enleting as of March 15, 1995, that the water hasseer from the tapect of the water in the loop seat on the volve discharge Line would not deform the i
discharge pipe and restrict flow to less then that respaired by design.
The i
licensee is currently performing on analysis to demonstrate that the vetves could I
have perfoeiend their intended f metten, however, engineering stated that anstysis i
will not be able to show that the thrust loads will be ulthln code ellowebte Limite.
e Servlce Water (SW) Leeks: The Licensee is completing a seven year pipe reptocement project that will reptoce most (about 19,000 Lineer feet are safety rotated) of the safety rotated SW piping with 65 moty stelnless steel.
This project will probably continue through 1997. Currently, approntmetely 905 of the safety rotated portion of the project has been completed, including the majority 4
of the SW piping in contaleveent, diesel boys, SW Intake structure, and auxiliary building.
gesed on NRC Inspection, SW pipe replacement project is progressing settsfactority as scheduled.
4 b
e Unit 2 Sustelnad Operetton of Greater Then 1005 Powers daring the recent outage, l
the licensee confirmed erosion of the feedwater flow nozzles resulting in incorrect online coloriastric date. Upon discovery, licensee lunediately redaced j
power for both units, and began adjusting Instrument setpoints to insure i
conservative operation.
The Licensee concluded that 102.5E was the exact power Levet and operating at that power level did not Invetidote any of the UFSAR Chapter XV conclusions.
e Work Control Problems:
During the Unit 2 refueling outage, the licensee and the j
l NRC Identified additional enssples of failure to follow established procesares rotative to the control of maintenance work activities.
These examples were y
l slalter to those previously identified diaring the Unit 1 outage, Noventier Decastier 1993.
q e
In September, PSE&G named Leon Eliasen as the new Chief Nucteer officer (replacing j
Steven Mittenberger), and President of a newly structured nucteer business unit.
Elleson's appointment was effective October 1, 1994.
Ne reports directly to PSE&G j
Chairman Forland.
The nucteer business unit will encompass att operationet and i
steport activities for both Selon units and Hope Creek. Since October senior J
management has etso appointed a new Setem general manager and a new quality i
sesurance and nucteer safety review manager; they have replaced the station spaelity assurance manager, the mechanicet maintenance manager, and the planning a
l manager.
As discussed above senior PSE4G management met with Region I senior 1
menessment on March 12, to present a proposed sales reorganization. The new 1
orgenlaation would add a mit 1 director and a unit 2 diretor reporting directly t
to the Seten general manager. The new orsentastion would also add (for each unit):
l l
a mit operations manager, mit senior nucteer shift supervisor, mit maintenance manager, mit planning manager, and unit outage planning manager. Salen management has taken steps to increase the esphesis on accountability from the Vice President of Operations down through ett levels of management to the workers. Leon Elleson inittsted a team of consultants and nucteer Industry senior managers to determine idiy PSE&G actions to leprove Salem performance have been ineffective. In addition, i
Mr. Elleson has inttleted a process to bring about e
- step change" in Selon perfornece. This process is intended to held managers accomtable for achieving
+
results, se opposed to post enphesis on generstlns activity.
i e
Cross Intruston at Circulating Water Inlet structures The licensee documented thle plant vulnerability for years, yet the condition continues to provide unnecessary plant chattenses.
An AIT was dispatched to the site on AprlL 8,1994, n
to investigate the plant transfont that resulted from severe grees intrusion on April 7.
The AIT concluded that the vulnerability of the design was previously recognized and modifications to leprove the system had not yet been implemented.
Unaddressed Espalpment Problems:
The staff documented numerous cases of known j
equipment deficiencies factoring significantly into Selos events.
The AIT of April 1994 fomd that management el Lowed equipment problems to exist that made
)
operations difficult for plant operators.
i e
In en effort to leprove menessment accomtsbility and performance, in July 1994 i
Salem PSR Page 9 1
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1 PSE&G terminated approximately 55 non bargaining unit members of the Nuclear DIvieion for inedequete performance.
Eteven of the termineted emptoyses were assigned to sales.
e operators continue to f ace many cheltenges posed by egipment failures.
Recent exemples include the control air system, the emergency diesel generator air start system, and the mein feedwater pump hydraulic control systems.
- 3. ESCALATS ENF - af ACTIVITIES i
e The NRC losued a Level III Violation on Merch 8, 1994, documented in NRC a ort 50 272 and 311/93 23; 50 354/93 25.
The violation was nosed on Inspection m
multiple emanples of PSE&G's failure to follow procedures and their f alture to properly control safety related activities.
e The NRC tasued four Level Ill and two Level IV violations and imposed a Civil Penalty of $500,000 on october 5, 1994 The violations were documented in NRC Letter EA 94112 and were based on the licensee's performance prior to and charinJ the April 7,1994 event.
e On February 8, 1995, PSE&G met with NRC et Region I in King of Prussie to discJos the findings of the Office of Investigation relative to assertions of violattens Involving 10 CFR 50.5 "Dettberate Misconduct," and 10 CFR 50.7 "Esployee Protection."
e on March 17, 1995, en enforcement penet will review three violations for potential escalated enforcement.
The violations involves o
failure to control meterials used in safety related applications (non-e limit switches instatted in two reactor head vent valves);
o failure to control a modification to insure that it was correctly laplemented (Instelling the loop drains for the pressurizer code safety
+
without insuring that the drain volves were properly aligned, or insuring that post modification testing verified that the drain perforned its 4
intended faction); and l
0 e repeat failure to comply with the Technical specification action statement requirement for an inoperable PORV.
- 4. IPE INSIGNTS i
f e
salen s h itted its IPE to the N;;C in July 1993; the document is still under NRC review.
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4 Salem PSR Page 10
III. ANALYSIS / ASSESSMENT
- 1. PREVIOUS SALP RATINGS AfD WERVIEW I
- a. Prevfous SALP Rattnas Functional Area June 19, 1993 povember
- 5. 1994 operations 2
3 Melntenance/
2 3
surveillance Radeon -
1 N/A Emergency Preparosess 1, Declining N/A security 1
N/A SA/QV 2
N/A 1
Engineertre & Ts 2
2 Plant $@ port N/A 1
Current assessment period: Newsmber 5,1994 to search 9,1996.
b.
SALP overvf ew (derived f rom the stannery carnaraoh of each $ ALP sectionn j
1 OPERATIONS on January 12, 1995, the SALP board met to discuss PSE&G's performance et sales charing the period from June 19, 1993 to Noventer 5, 1994 The board concluded that operators generstly responded appropriately with good command and control to the many plant trips and operational translents that 0 :urred over the SALP period. Likewise, they demonstrated good profielency l
In making emergency cieclarations for events for which such declarations should have been considered.
However, performance over the essessment period demonstrated significant weaknesses in severet erees. Operatore did not practice ownership of the plant and did not aggressively enlist other plant deportments to resolve longstanding eSJipment problems which fregaently challenged them in normat and @ set plant conditions.
A tack of an appropriate cpestioning attitude by operators resulted in anomalous indications, or conditions being mnoticed or not mderstood and not being acted won.
A tack ef guldence for and training of operators on operability decisions resulted in some decisions being nonconservative or having week technical bases.
Examples of nonconservettve approaches to entering and exiting LCos occurred over the period.
Some difficuttles were experienced managing and controlling outage j
activities.
Poor self essessment within the Operations department coupled with ineffective J
independent assessment of Operations by the Quality Assurance and Nucteer safety Review organization contributed to the continuation of performance problems throughout most of the period.
MAINTENANCE /9URVEILLANCE The board concluded that performance weaknesses were evident in maintenance programs and activities, such as procedural acgierence and adequacy, the feeseck process, specification of i
post maintenance testing regJirements, and control of work activities by ntmerous onsite 3
groups. Management has leproved its safety focus in prioriti Ing and schechating maintenance activitles.
However, management oversight of corrective action program activities has been week as evidenced by the high recurrent equipment failure rates.
Inconsistencies in troubleshooting activities and root cause analysis contributed to the delay in correcting recurring problems.
Meterial condition of the plant continues to inprove, but there remain severet areas that need isprovement.
Although the in-service testing program was adequate, management did not effectively resolve self essessment findings.
Programs for in-service inspection, erosion / corrosion and steam generator teskoge monitoring were adequately laptemented.
ENGINEERING The Board conc 1Laied that Engineering performance was inconsistent, with sestantial verlation l
In gastity.
The quellty of the discipline design work was good, with significant engineering management focus shown in several modification activities.
However, engineering work priorities did not etweys reflect plant needs.
In severet significant programmatic areas in which the Engineering orgentration had an important role, perfonnance was, on betence very Salem PSR Page 11 i
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good.
Significant problems, nonetheless were noted associated with root cause assessments and with equipment problem resclution.
The f act that there existed engineering capability, that when focused by statlon management and brought to bear on important issues, demonstrated the ability to schleve very good performance, suggested that a significant aspect of the problem was associated with the effective engagement of evellable engineering expertise in activities leportant to safe plant operations, such as in root cause essessment and ecpipment problem resolution.
PUWT sWPPORT The Board concluded that plant sipport functions contributed effectively to safe plant performance.
Performance in the redletion protection area continued to be a significant licensee strength.
Well trained technicians and staff coupled with effective management resulted in egeresolve ALARA progree leptementation with elsnificant dose savings realized.
Excellent perfoneance in the radiological envirorseental monitoring and effluent control programs was egeln noted.
There was continued good performance in the emergency preparochess area.
Security propres performance continued to be a strength.
Fire protection program leptementation was substantially leproved.
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2.
LIENSEE RESPONSE TO PREVI(US SALP FUNCTIONAL AREA KAKNESSES/RECENT LIENSEE PENORMANE TRE SS (In the test year)
- OPERATIONS The licensee response to the SALP did not provide detailed Information on plans to address perfonnance inademocles.
The response generally agreed with the NRC's essessment of Salem performance.
In addltion, the response stated an intention to correct Sales performance problems.
$1nce the response letter wee issued, senior PSE&G management has initiated en effort to determine the cause of the ineffectiveness of previous cor*ective actions.
In addition, PSE&G management proposed reorgenlaations of several organlastions (discussed in j
more detsfl below), and implementation of a
- step change" process intended to produce results, rather than activity without results.
The proposed re-organization would wickly bring the unitization concept to fruition for Salem Operations.
Two plent directors (one for each unit) would report to the Salem General Manager.
In turn, two operations managers (one for each unit) would report to the directors, and each operations manager would have responsibility for a unit operations department, j
including a Senior Nucteer Shift Supervisor and the shif t comptement necessary to steport operation of that mi t. If IS Ir0RTANT TO NDTE THAT, as of March 15, the licensee had not reached a finst conclusion to implement the propose orgentzetion.
In response to the April 7 event, Operations management provided laproved guidance to operators for connend and control and conservative operation of the plant.
In response to NRC concerne, Operations management developed a flow chart for operability determinettons.
Inspectors have occasionally noted week or incorrect interpretation of Technical Specifications.
The inspectors have etso noted that the Operations Manager has convincad the department staff that change is necessary, and fostered an increasing sense of ownership and tems work.
- MAINTENANCE AND SURVEILLANCE Secondary /goP equipment deficiencies pose significer.t chattenges to plant operations, e.g.
1 manwey felture, condensate header demose, CDPU filter replacement, CW travelling screens, N feed control at low power levels.
In order to feprove overall performance and response to amergent Issues, PSE&G reorganized the Maintenance Department.
Changes included replacing the sinste Melntenance Meneger role 4
with three new positionet
- 1) Mechanical Maintenance Manager, 2) Controls Nefntenance Meneger, and 3) Pterviing Meneger.
PSE&G began to unf ttre these departments.
The proposed (se of March 15) reorganlaation would further unitize maintenance planning management structures.
As of March 15, unit 1 and unit 2 had seperate outage planning managers.
The proposed reorganization would provide separate (non outage) planning managers and maintenance managers for each unit, reporting to the unit directors for their respective units.
The unit maintenance managers would oversee mechanical, electrical and !&C maintenance for their respective units (recombining the disciplines mder one maintenance manager for each urif t).
I To address the existence of long standing equipment problems, plant management re@ fred I
operators to develop a list of workarounds to be addressed by maintenance personnel in l
accordance with assigned priority.
I e ENGINEERING AND TECHNICAL SUPPORT Salem and corporate engineering have not consistently cosumicated well with operations, nor has operations comenmicated well with engineering.
System engineering has not effectively prioritfred their workload, nor have they effectively monitored owipment reliability, as demonstrated by the *workaround" list generated in response to this NRC fdentified concern.
The system engineers did not receive training on operability or Generic Letter 91 18 mtil September 1994 An NRC observation rotated to the Sales rod control issue was that the initial trosteshooting efforts tecked clear tendership and delegation of responsibilities.
This resulted in the efforts narrowly focusing on the most recent system malfmetion without ade@ ste attention to the repetitive nature of the feltures and the need to determine and correct the root cause.
The failure of PSE&G to determine the root cause of the failures resulted in tsamerous aborted start y attempts.
The team did observe slenfficant leprovements in the control of trosteshooting and root cause determination diaring the inspection.
A management oversight team was initiated to review all I&C trosteshooting activities in en effort to radice events caused by trostoehooting.
Salem PSR Page 13
I In tote February 1995, PSE&G announced a reorgenfration of the Nucteer Engineering department j
(corporate engineering).
PSE&G management redirected resources no longer required to support the Seton revitellretion project (since It would be substantt ally complete in 1995) to i
better sgport selen and Hope Creek operation.
The ef fects of this reorganization have not yet been demonstrated.
In addition, Salem management rotated the Technical Support manager to the Gustity Assurance and Nuclear $sfety Review department to provided leproved oversight of Quality Assurance and corrective action programs.
Selen management had not named e pennenent replacement Technical i
sg port manager as of March 15.
e PLANT SUPPORT The NRC noted that PSE&G contlnued to perform at a noteworthy levet in the area of redlological protection through the si.4 of 1994, especially during the recent Urit 2 refuellrg outage.
e SAFETY ASSESSMENT /ouALITY VERIFICAfl0W
]
In July 1993, the licensee formed a Comprehensive Performance Assessment team (CPAT) which condhacted a special assessment of safety issues and recent plant events using an integrated f
MORT Investigatory enelysis.
The CPAT devotoped comprehensive root causes f or these events, and the licensee has formed task teams charged with developing corrective actions.
PSE&G has held periodic meettnes with the NRC to discuse CPAT findings, and the NRC continues to monitor licensee progress in this area.
3.
LIMIINE PERHENIANE STRENGTNS AID lEAEIESgES
- Setem perforumco centlemsos to be inconsistent.
e Capacity factor has been low due to refueling outages et both units and rusmorous forced outages and power rechJctione resulting from problems with SPPs, Ms-10s, pressuriser code safety velves, rod control, and to sgport PORV replacement as well as espalpment modifications following the April 7 event.
Gross fouling of circulators and rasserous plant trips contribute to the tw capacity factor es well.
Strerythos e The licensee continues to increase resources for a meterial condition leprovement program.
The NRC has observed noticeable {sprovement in the materlet condition of the plant,
]
Indicating that the licensee hee been earnest in the laplementation of {sprovements.
i i
e Radletion protection program laptementation continues to be very strong.
e idhen problems or conditions are self identified and self detected, event response and root cause determinetton are through and comprehenelve, porticularly asen the matter is the s@ ject of NRC attention.
In other cases, the licensee 8s perfonnance is considered weaker, as identified below.
l l
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Salem PSR Page 14
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- PSE&G has responded to identified performance and management weaknesses rotative to approach to problem resolution by initiating the following actions:
l
- PSE&G senior management has reptoced the mechanicet meintenance manager, the planning manager, QA manager with personnel from within the PSE&G organization, and has filled the General Manager position and the Quality Assurance and Nucteer safety Review position with new personnel from outside the company.
In addition, PSE&G management proposed reorgenl etions of severet orgentzstions and implementation of a
- step change" process intended to hold managers accountable for producing results.
- Verifying the effectiveness of rumorous supervisors and managers and changing the incumbent when deemed appropriate; j
e Pursuing mitization of the operations orgenlaatton; maintenance and planning
~
organisations are mitized.
e Implementing the existing performance essessment tools to feprove accountability from the highest levels of management doim to rank and file workers; e Forming dedicated teams to implement the corrective actions developed in response to the CPAT findings.
Weaknessen:
Salam performance continues to be weak ins e Planning
- Control of maintenance;
- system Engineering and Technicet Support
- The ability to do root cause determinetton;
- Corroctive oction effoctivenese due to inodopota root cause essessment; 4
e inadequate approach to problem resolution (i.e.,
general tendency to fix problems or conditions based are the most probable cause without sesessment or understanding of all possible causet factors.)
Examples Include, but are not limited to: maintenance and modifications to the atmospheric relief volves, problems with main feeddater regulating velve controls and feedwater pumps, maintenance of the safeguards Equipment Control systems, and inittet response to cracked diesel liner issues, failure to identify elevated reactor power in 1992, and felture to recognize generic implication of rod control problems.
t-Salem PSR Page 15
- 4. IEC TEAN INSPECTIONS WITNIN TIE LAST YEAR Aree/Date fIndines Augmented Inspection Team (Alf)
An Ali was formed to review causes and safety April 8 26, 1994 laplicatione associated with a series of malfunctione experienced during a plant i
transient and shequent trip.
The team concluded that increased NRC Customl ed Inspection Program Team inspection is warranted In the areas of August 15 16, 1994 maintenance and control systems.
Also expressed concern about Licensee failure to proactively correct ocpalpment deficiencies before they teed to plant events.
SWSOPI Report on Licensee's esseeement not yet September 5 23, 1994 lasued.
Monitoring of Licensee's Self Assessment 1
a 4
4 1
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1 Salem PSR Page 16
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i IV. INSPECTION PROGRAM STATUS
- 1. STATUS OF INSPECTIGIS The inspection program statue is reflected in attached MIPS report s2. The date is current as of the date of the MIP.
The MIP Indicates that inspection program is on-track with the P erywd resource ellotment; no significant shift in inspection activities is warranted.
t 4
- 2. Petr0MB CRANES TO MIP o
Unit 1 j
A.
DRSS -
8.
DRS -
)
C.
DRP e
Unit 2 j
A.
DRS$ -
B.
DRS a C.
DRP -
- 3. SIMIFICANT ALLEgATimIS Am IINESTIGATimIS Three ellegettons are rotated to heressment and intimidation of (fconsee personnel, up to and including ettegettons of promotfon denist das to "idilstleblowing."
One of the ellegations esserts that the Offsite Safety Review Gro g is not performing its faction in accordance with technical specifications.
01 is actively reviewing these cases, i
An attegation involves a technical question that suggests that MVAC chactwork integrity may not be esaured mder dynamic loading of new f ast acting curtain fire deepers.
DRP is reviewing test procedares and results while DRS le schechsted to review the setter charing the next routine fire protection inspection.
An attegation regards evidence that the R W Control problems experienced by the plant (and followed @ by the Jme 5,1993 AIT) occurred charing starty testing at the Zion nucteer I
station, even though Westinghouse representatives denied that the problem had ever occurred I
before. 01 has opened en investigetfon into this case and is currently reviewing the matter.
An allegetton concerne 6 technical issues raised regarding the environmental quellfication of 4
f equipment.
Upon agreement of the elleger, this matter is currently mder review.
$1nce the licensee's effort to terminate several employees for poor performance on July 18, j
1994, the Region has received several other allte ; ions from terminated employees that are currently under review.
- 4. (FEN ITDI STATUS BACKLOG /No. GREATER THAN 2 YR$
(Unit 1 and 2 Common) 62/T NOTE: The large ramber of open Itene is due to the issuance of an Appendix R/ Fire Protection Team Inspection Report in October 1993 and en EDSFI Teen Inspection Report in November 1993.
+
5.
DUTSTAm LNG LICENStats ISgUES e GL 8910 (MOV) technical differences between NRC/PSE&G.
(Nope Creek etso) weting held May 11, 1992 to resolve issues.
e EDG emendeont e TS emendeont to resolve AFW/contelnment spray issue (see Section II.2.e).
o Increase in survelliance test Intervals and ACT for reactor trip and ESFAS.
o InsteLL new digltet feedwater control system.
1 Salem PSR Page 17 s
4 e Evaluation of Control Room Design Deficiencies that were not corrected.
llconsee is
- Bulletin 88 08 (Thermal Stress in Piping Systems Connected to the RCS) revising their response.
6.
LOCAL / STATE /EXTERIIAL ISplES e.
NJ DEPE/gnE
- Now providing input /comuments on all PSE&G licensing change requests.
- Migh Interest in reeldent inspection accompaniment.
- Continuing interest in Sales cooling tower issuer When Salem's renewable variance for the use of the Delswere River as a heet sink came to for renewal in 1984, New Jersey envirorumentallsts appealed to the state to not renew the verlance.
in 1990, NJ DEPE
{ sound a
- draft order" requiring PSE5G to build two cooling towers to styport the Selon units' operation.
PSE&G responded to the state's order with a 56 volues comment, and the issue is currently under review by NJ DEPE.
Recent NJ DEPE dociolon not to require cooling towers.
- State inspectors generally accompany all AIT ef forts, b.
Other (Recent Medle Interest)
- Large interest in recent Alt (April 2i, 1994) exit meeting and stesequent enforcement conference (July 28, 1994).
Several local television and newsprint representatives attended.
Also, the conference was attended by representatives of Senator Blden8s staff.
4 k
Q 4
t Salem PSR Page 18
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SALEN EXEQlTIVE SLegIARY i
i LICENSEE PERFWIANE STREIIETIIS Als uraamarggs Sales perforumnos casetirases to be Incanaistent.
- Capacity factor has been low skse to refueling outages et both mits and rumerous forced outages and power redactions resulting from problems with SPPs, MS-10s, pressurtzer code e
safety volves, red control, arel to sgport PORV replacement as well as egJlpsesnt i.
modifications following the April 7 event.
Gross fouling of circuletors and numerous plant trips contribute to the low cepecity factor as well.
Strereths:
e The lfconsee continues to increase resources for a meteriel condition leprovement program.
)
The INtc hee observed noticeable !sprovement in the materlot condition of the plant, I
indicating that the licensee has been earnest in the laptementation of leprovements.
e e Radletion protection program toplamentation continues to be very strong.
9 i
- When problems or conditions are self identified and self detected, event response and root l
cause determinetton are through and comprehenstve, particularly een the matter is the i
s@ ject of haC ettention.
In other cases, the licensee's performance is considered i
weaker, as idontIfIed beiow.
]
e PSE&G has responded to identified performance and management weeknesses rotative to
)
approach to problem. resolution by initiating the followlns actions:
o P8ESG senior management has replaced the mechanical maintenance manager, the planning mensper, the technical opport manager, and the Salem GA manager with personnel from within the PSE&G orgenlaation; and has ff Llod the General Manager position and the Gustity I
I Assurance and Nucteer Safety Review poeltlen with new personnel from outside the company.
e Verifying the effectiveness of rumorous supervisers and managers and changing the Inciatient when deemed appropriate.
- Pureufne mitiration of the operations organisetton; maintenance and planning orsenlaations are mitised. Additlenet changes have been proposed to further mitize operations, ptenning, and maintenance managers below the proposed plant directors.
e Implementing the existing perforiaance essessment tools to leprove accomtsbility from the highest levels of management down to rank and file workers.
I e Forming dedicated teams to leptement the corrective actions developed in response to the CPAT findings.
e Initleting a team of consultants and senior managers from other utilities to determine the cause of the inef fectiveness of P$t&G corrective actions for salen to date.
e Developing a ' step change' process intended to hold managers accountable for achieving measured performance leprovements.
Weakneesse:
Setem performance has been week inn e Planning.
Sales mnocessarily rendered en entire train of service Water inoperable for a valve repelr that dicWt need to be done, and dicWt get completed.
Salem planne" %.ntenance on an EDG to troele shoot a non safety portion of the test controle, without W eining if parts were ovellable; this entended the time in the LCO.
e Control of maintenance.
Lovet III violation in the Unit 2 outage for lack of procedare accierence and lack of tagging control. Mechantes changed the of t In the wrong component in the AFW pump, and mintentlenetty "adjustocP' the overspeed trip test device. The solem Unit 2 PORVs were reptoced with the " wrong" internels (not the parts intended).
The correct internets were essegauntly Instetted sharing the recent Unit 2 outage.
e Engineering and Technical Soport.
System engineering has poorly trended agafpment rettability (for example, the ofeset air stort system, the controt air system).
Engineering (corporcte and system) has not commmicated well with operations (for the most part, the operators don't know do they are).
System engineering has not been involved in operability decisions, and was not trained en operabflity (Generic Letter 91 18) mtil I made a ble issue out of it.
l
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2 e Recognition of the need to do root cause determinetton.
- Corrective action effectiveness due to inadogaste root cause essessment.
- Inadessete approach to problem resolution (i.e.,
general tendoney to ffa problems or conditions based on the most probable cause without assessment or understanding of all possible causet factore.
Examples include, but are not limited to the licensee's initlet response to crocked diesel Liner issues, failure to identify elevated reactor power in 1992, and f ailure to recognize generic faplication of rod control problems.)
GENERAL OBSERVAfl0NS:
Organitetton may not have sufficient level of knowledge relative to meneging change based on observations by DRP and DRS inspectore.
Until recently, the Selen orpenitation never engaged in ettempting to benchmark itself relative to other utilities, including Hope Creek.
New emphosts on accountability, ownership of proklems.
The July 1994 terminetton of 50-60 personnel appears to have been well received (by those who were not terminated).
Generally positive consments from remaining staff acknowledging that there were several week performere that felled to contribute to overall quality or safety.
While J. Hagen has been pushing for more swervisory field time, increased first line opervisory presence is not very apparent. However, there is a noticeable increase in the presence of middle management level personnel.
There are several exemples recurring problems in pop (service air, and feedwater) and some safety-related systems (EDG elr start) have the potential to effect nuclear plant performance.
It is not steer, that the maintenance orpentration and system engineering orpenfrations mderstand and appreciate the need to change.
Unable to agree on meaningful improvement strategy miese luposed from the top down. Possive attitude seems to exist relative to change.
Taken w with ster to day crf ele management.
Still tend to focus on most famedlete proximate causes eseociated with an event.
While management le driving change, noticeable leprovement in plant performance and personnel attitude and enthueless for determining and laptementing laprovement strategies and plans Is not yet apperent.
I j
s I
)
i
BAtJDr bat h 6/20/93 - 22/5/94 PlJurf 80PPORT (fire protection, rad pro, security, emergency preparedness)
FIRE PROTRCTIOE ETREEQTEDs Fire department response to a March 9 simulated fire was well executed.
(IR 94-06)
In February PSEGG completed fire damper modifications that resulted in safe, high quality improvements to the fire protection system. (IR 94-01)
Licensee res, mse to a November 2 fire in a turbine building lightning
~
transformer was appropriate.
(IR 93-23)
The fire department responded very well to a pipe insulation fire on October 13 in No. 12 service water piping penetration bay.
(IR 93-21) 1 i
RADIATIOE PROTECTIOE BTREEQTEDs i
The inspector determined that the licensee responded promptly and appropriately in response to elevated radiation readings in containment.
(2R11A in Warning -30,000 eps.)
The licensee took appropriate steps to identify the source of the leak.
(IR 50-272/94-19) 2 The NRC team noted that management safety focus was appropriate and that management and supervisors were involved in plant support activities. NRC Filot Team sales Assessment (7/11/94 - 8/25/94) f Bealth physics organisation appears to have implemented prosctive and l
ef fective problem identification and resolution programs, as shown by a lack of recurring problems. NRC Filot Team salem Assessment (7/11/94 -
8/25/94)
In reviewing the Salem radiological protection program for 1993, the inspector noted that PSEGG manages and controle personnel exposure and contamination very well and maintains an aggressive as-low-as-reasonably-achievable policy for their staff.
4 Salem chemistry and Radiological Protection Department personnel consistently demonstrated good performance in implementing chemistry and radiation protection programs.
VEAKEEBBE8s The licensee discovered the Unit 2 liquid radwaste affluent line (2R18) radiation monitor in the blocked position while a liquid release was in progress.
The inspector determined that the release was less than
1 J
allowable and provided no additional risk to public health and safety.
j Mon-cited violation.
(IR 50-272/94-14)
On one occasion, the Radiation Protection Department failed to document the free release of a potentially contaminated valve from the RCA as required by procedure. (This was included as one of eight examples of the 4
licensee's failure to follow procedures in the conduct of work activities.
(Violation 93-23-01)
(IR 50-272/93-23)
BBCUKETTr amtm anMECT PREPARROKESS ETRENGTERs Plant support of emergency preparedness, fire protection, security, and health physics continue to perform strongly. (NRC Performance Assessment of sales)
]
Management and communications withis the various plant support organisations were acted to be effective.
(NRC Performance Assessment of sales) i Problem identification was proactive and effective, and programs and procedures were good.
(NRC Performance Assessment of salem) 4 security, in spite of some incidents, has aggressively pursued identified issues.
(NRC Performance Assessnest of sales)
{
Team review of the emergency preparedness facilities was favorable. (NRC j
Performance Assessment of sales)
Response to Appendia R fire protection issues was also acceptanle.
(NRC Performance Assessment of sales)
]
Operator use of emergency procedures was good.
(IR 94-80/80)
Declaration of the NOUR was timely and in accordance with sales Emergency Action Levels.
(IR 94-80/80) t The emergency coordinator prudently decided to declare an Alert to obtain f
i technical assistance when BOPS did not provide clear guidance for recovery l
from solid RCs conditions.
(IR 94-80/80)
TBD (IR 94-24/24) i None with respect to security or RF (IR 94-19/19)
Inspectors observed good performance by security personnel la performing i
routine activities, such as control of access to the plant and implementation of the security plan.
(IR 94-14/14) j The plaats were very clean, well painted sad lighted, with the exception of two of the four sales service water bays, and the sales turnine i
i
~. _.. -..
building basement. The licensee planned to address these areas as part of the salem revitalisation project.
(IR 94-14/14)
No plant support observations (IR 94-13/13)
No EP or security observations.
(IR 94-11/11)
I,1censee methodology for testing emergency battery powered lighting was acceptable and, with one exception, the emergency lighting functioned adequately.
(IR 94-06/04)
The PSEGO implemented the access authorisation continual behavioral observation program well to assure that personnel with unescorted access l
to Salem (and Hope Creek) maintain proper reliability and trustworthiness.
(IR 94-01/01)
No EP or security observations (IR 93-27/27)
Despite initially weak inter-departmental communication, the licensee took comprehensive action to insure readiness for a possible security union labor action.
(IR 93-23/23) on November 2,1993, operators appropriately declared an Unusual Event in response to a fire lasting 14 minutes.
(IR 93-23/23)
On october 26, 1993, operators appropriately declared an Unusual Event when a potentially contaminated worker was transported to the salen Hospital.(IR 93-23/23) j During a practice Emergency Preparedness drill, the EP staff appropriately 1
identified areas for improvement. The drill provided good practice for I
the emergency response participants and the EP staff.
(IR 93-21/21)
Operator appropriately declared an Unusual Event on October 13, 1993, in anticipation of state interest in a short duration fire in the service i
water penetration area.
(IR 93-21/21)
Inspectors noted good coordination between PSE&G Engineering and Site Protection during installation of a new sales no. 2 fire pump. Testing of 1
i the pump was satisfactorily performed.
(IR 93-20/20) i l
During the annual emergency plan exercise at Salem, the licensee properly declared and responded to an actual Unusual Event which resulted from an ammonia leak.
(IR 93-19/19)
When the fire pumps were declared inoperable, PSEGG properly implemented l
the necessary compensatory measures until a salem fire pump could be returned from service.
Compensatory measures included verifying the availability of the Hope Creek fire water supply by tagging open the cross connect between Salem and Hope Creek.
(IR 93-19/19) usaarassss:
Initial motification to the NRC did not convey information that i
1 3
complications were associated with the event. This was the subject of aa l
NOV for the April 7, 1994 ovest, and was cited as a Severity Level IV violation.
(IR 94-80/80) 4 0
.Ii l
4 4
4 1
l 1
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1 i
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4 4
4 1
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4 4
F 9
n
4 SALEM SALP BULLETS TRIPS
'l e
On July 11, 1993, while shutting down Unit 1 to comply with a Technical specification Action statement for an inoperable solid state protection relay, the main feedwater regulating valve for the No. 14 steam generator inadvertently closed as a result of personnel error. This closure resulted in water level dropping low enough to cause a reactor trip.
3 e
On January 27, 1994, the Unit i reactor automatically tripped from 10%
power in response to a low water level in No. 14 steam generator. The licensee determined that the cause of the trip was a level error controller in the control circuit for No. 14 steam generator feedwater j
regulating valve.
8 On February 10, 1994, Unit 1 automatically tripped from 994 power in response to a main turbine trip. The licensee determined that a voltage spike tripped protective relays in the 15 VDC power supplies to the main j!
turbine electrohydraulic system.
On April 7, 1994, the Unit i reactor tripped from 256 power as a result 1
of loss of circulating water to the main condenser. Region I initiated 4
an AIT because of the complexity of the events, the uncertainty of the e
root causes of some of the conditions and equipment probisme that had been encountered during the events, and possible generic implications.
. ~..
i
[AIT Report No. 50-272/94-80) i On June 10, 1994, while operating at 974 power, Unit 1 reactor automatically tripped following a asia generator trip. The licensee determined that a potential transformer failed, causing the mais 4
generator output breakers to opes resulting is a turbine trip and 4
subsequent reactor trip.
1 On June 29, 1994, Unit 2 reactor automatically tripped, during power escalation, due to a low-low steam generator water level. The licensee 1
l determined that feedwater recirculation valve cycling at low feedwater 4
flow rates caused rapid changes in feedwater header pressure and steam s
generator feedwater flow.
i 8
on July 14, 1994, Unit 1 operators manually tripped the reactor from 100% power in response to decreasing condenser vacuum caused by the loss
^
of all circulating water (CN) pumps. The licensee determined that a 1
design inadequacy, lack of a time delay in the madervoltage (UV) pickup j
i
[
circuitry of the cw pump switchgear, resulted is unnecessary UV relay 4
actuation f 11 wing11ghtning-induced voltage drop.
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- ll SENT BY:
10-18-84 : 8:23AM :
PSE&G LIC & REG-
- 2/ 3 J
t ATTACHMENT 1 NLR-194473 l
i SALP BOARD MEMBER VISIT SALEM STATION - OCTOBER 21, 1994 1
~
DIVISION OF RADIATION SAFETY & SAFEGUARDS (DRSS)
NRC REGION I SCHEDULE OF ACTIVTTTES (IST DRAFT)
)
7:30 -> 8:00 Arrive on-alte 8:00 -> 9:30 Meeting with NRC Site Personnel (NRC Trailer) 9:30 -> 11:30 Tour Salem Station (w/ PSE&G Mgrs) 11:30 -> 12:00 Lunch 12:00 -> 3:45 Personnel Interviews (See attached) 3:45 -> 4:15 NRC - Senior Management Exit /De-brief Salem GM Conference Room 1
d
3ENT BY:
10-18-94 : 8:23AM :
PSE&G LIC & REre
- 8 3/ 3 f
ATTACHMENT 2 NLR-I94473 SALP BOARD MEMBER VISIT i
1 1
SALEM STATION OCTOBER 21,1994 l
3 INTERVIEW SCHEDULE APPROX.
NAME tIOB TITLE PHONE TIME SLOT e
FUNCTIONAL AREA EMERGENCY FREPAREDNESS Tom DiGuiseppi Nuc. EP Mgr.
X-1517 12:00 - 12:45 Engineer TBD Health Physics Terry Cellmer Rad Pro / Chem. Mgr.
X-2830 12:45 - 1:30 Engineer TBD Security Dan Renwick Nuc. Security Mgr.
X-2244 1:30 - 2:15 Engineer TBD Fire Protection Paul Eldreth Nuc. Safety & P.P. Mgr.
X-2828 2:15 - 3:00 Engineer TBD RP/Chen Services John Trejo Mgr.- RadPro/ Chem. Sves X-2446 3:00 -3:45 Engineer TBD
i e
- Ken UNITED STATES
., e g
NUCLEAR HEGULATORY COMMISSION j'
g REGION l 1
To j
475 ALLENDALE ROAD A
KING OF PRUSSIA, PENNSYLVANIA 19406-1415
%,g *
,4'
.s,*
October 13, 1994 John Stolz, Director, Project Directorate I-2, NRR MEMORANDUM FOR:
Richard W. Cooper, II, Director, DRP Charles W. Hehl, Deputy Director, DRSS James T. Wiggins, Ditector, DRS John R. White, Chief, RPS 2A, DRP FROM:
SALEM GENERATING STATION SALP BOARD MEETING
SUBJECT:
2 17, 1994 at 9:30 a.m., in The Salem SALP Board will meet Thursday, NovemberBoard members should ensure the DRP Conference Room.
of their staff will be present to support the meeting.
The SALP Board meeting will be conducted in accordance with Management t
Directive 8.6 and the supplement to the Region I Instruction 1440.1, Revision 4.
The following is the proposed SALP Board Meeting agenda:
a JR!E DISCUSSION ITEM LfB 8
9:30 - 9:45 a.m.
Introduction and Overview Dick Cooper 9:45 - 10:15 a.m.
Review of SALP Supporting Data Dick Cooper 10:15 - 11:00 a.m.
Operations Functional Area Dick Cooper 11:00 - 11:45 a.m.
Maintenance Functional Area John Stolz 11:45 a.m. - 12:45 a.m. Lunch Break 12:45 - 1:30 p.m.
Engineering Functional Area Jim Wiggins 1:30 - 2:15 p.m.
Plant Support Functional Area Bill Hehl 2:15 - 3:00 p.m.
Summary of Discussion for Dick Cooper SALP Cover Letter 3:00 - 3:15 p.m.
Overall Comments on the Salem All SALP and Closing Remarks Thank you for your continued support and cooperation in this effort.
Docket No. 50-272; 50-311 8 SALP Chairman j
9702030237 970116 '
/
O'NEILL96-351 PDR I
l l
[AIT Report No. 50-272/94-80]
i On June 10, 1994, while operating at 974 power, Unit i reactor automatically tripped following a main generator trip. The licensee determined that a potential transformer failed, causing the main generator output breakers to open resulting in a turbine trip and subsequent reactor trip.
s J
On June 29, 1994, Unit 2 reactor automatically tripped, during power
{
escalation, due to a low-low steam generator water level. The licensee determined that feedwater recirculation valve cycling at low feedwater i
flow rates caused rapid changes in feedwater header pressure and steam generator feedwater flow.
)
l On July 14, 1994, Unit 1 operators manually tripped the reactor from j
i 1004 power la response to decreasing condenser vacuum caused by the loss of all circulating water (CW) pumps. The licensee determined that a design inadequacy, lack of a time delay in the undervoltage (UV) pickup circuitry of the CW pump switchgear, resulted in unnecessary UV relay 4
actuation following 11ghtning-induced voltage drop.
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10-18-94 : 8:23AM.
PSE&G[iC& REG IlSENTBY:
- 8 2/ 3 ATTACHMENT 1 utg.Ig4473 RPJa. BOARD MEMBER VISIT SALEM STATION - OCTOBER 21, 1994 i
DIVISION C1' RADIATION SAFETY & SAFEGUARDS (DRSS)
NRC REGION I SCHEDULE OF ACTIVITTES (IST DRAFT) 7:30 -> 8:00 Arrive on-site 8:00 -> 9:30 Meeting with NRC Site Personnel 4
(NRC Trailer) 9:30 -> 11:30 Tour Salem Station (w/ PSE&G Mgra) 11:30 -> 12:00 Lunch 12:00 -> 3:45
?crsonnel Interviews (See attached) 3:45 -> 4:15 l
NRC - Senior Management Exit /De-brief Salem GM Conference Room 4
3Ca By:
10-18-84 : 8:23AM :
PSE&G LIC & REG-28 3/ 3 f
ATTACHMENT 2 NLR-I94473 SALP BOARD MEMBER VISIT SALEM STATION OCTOBER 21,1994 l
INTERVIEW SCHEDULE l
I APPROX.
HbHE JOB TITLE El[QHE TIME SLOT FUNCTIONAL AREA EMERGENCY PREPAREDNESS Tom DiGuiseppi Nuc. EP Mgr.
X-1517 12:00 - 12:45 Engineer TBD Health Physics Terry Cellmer Rad Pro / Chem. Mgr.
X-2830 12:45 - 1:30 Engineer TBD Security Dan Renwick Nuc. Security Mgr.
X-2244 1:30 - 2:15 l
Engineer TBD I
Fire Protectio.
Paul Eldreth Nuc. Safety K. P.P. Mgr.
X-2828 2:15 - 3:00 Engineer TBD
)
RP/ Chem Services John Trejo Mgr.- RadPro/ Chem. Sves X-2446 3:00 - 3:45 Engineer TBD i
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