ML20134C650

Informs That Due to Pending EAs at Both Plants Scope of 950530 Eppr Has Been Reduced.Meeting Will Be Limited to 1 H

ML20134C650
Person / Time
Site:	Salem, Hope Creek
Issue date:	05/04/1995
From:	Marschall C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	Barber G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
Shared Package
ML20134C519	List: ML20134C503 ML20134C579 ML20134C588 ML20134C595 ML20134C609 ML20134C616 ML20134C641 ML20134C644 ML20134C650 ML20134C653 ML20134C658 ML20134C704 ML20134C773 ML20134C800 ML20134C814 ML20134C829 ML20134C839 ML20134C853
References
FOIA-96-351 NUDOCS 9702030230
Download: ML20134C650 (86)

Text

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i fron: G. Scott Barber (GSS) /

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To: com [. [ "?g /  !

Date: Thuredey, May 4,1995 8:55 am -

Subject:

Selen EPPR Scope Redaction Because of pending enforcement actions at both Setem and NC, 4 TTM's planned visit, the NC SALP, and other activities, the scope of the Mey 30 Setem EPPR has been redaced. TTM has agreed to limit the meeting itself to one hour. So, our discussion will have to be focused only on the " key" issues.

Per discussion with John and Dick Cooper, the following need to y be included in the EPPRI 1

' 1) PSA @ te to include recent inspections only. The full update of the PSR with the inspection findings and plant event attachments should proceed in the backgromd on a "not to interfere" bests with the planned elements ilsted below.

i 2) Senior Management Briefing paper I 3) Preliminary or finst findings from the Eselgroth 40500 team '

inspection currently mderway.

) 4) Proposed MIP that reflects our Insights from above i

i From my perspective, I believe there are three " key" (seues that

' need to be highlighted. First, Manan modJte confleuretion

, control. Many, if not ett of, the Ms 10 problems appear to stem from a lack of configuretton control with the Hagen radJtes. The j licensee also admits to many other problems in their recent ettegation response on this same s4 ject. Second, control and issuance of certe and stanolles from the warehouse and selv system appears to be at the root of a number of plant problems, such as, the recent problems with sW, pre planning for the turbine outage to fix the control volve limiter, and the instettetton of the wrong PORV Internels. Some of these problems seem to stem from the fact that the same part mmber (follo) is used (vice a mlque mmber) for the same part from many different suppliers or vendors. Third, and last, root cause anstysis l performed by system engineering continues to be week. See my 1 recent inspection (95 02) with Larry Schott and Ram shotle. I believe that we should consider these when planning future initiative inspections.

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l j SALEM OPERATIONS l 9 Strengths e OPERATOR RESPONSE TO PLANT PROBLEMS AND TRANSIENTS WAS GOOD.

e OPERATIONS OVERSIGHT OF PLANT ACTIVITIES IMPROVED FROM PREVIOUS ASSESSMENTS.

O Weaknesses

• OPERATOR DID NOT CONSISTENTLY COMMUNICATE NOR DOCUMENT PLANT PROBLEMS OR DEFICIENCIES. AS A RESULT, SUPPORT FROM PLANT MAINTENANCE, AND PLANT i ENGINEERING WAS VARIABLE, AND STRONGLY DEPENDENT ON THE QUALITY OF INFORMATION COMMUNICATED AND DOCUMENT;.D BY OPERATIONS. THESE DELAYS ,

WERE OFTEN EXPLAINED BECAUSE OF THE MYRIAD OF PROBLEMS THAT ARISE EACH l DAY. l

• OPERATORS CONTINUED TO HAVE DIFFICULTLY APPLYING TECHNICAL SPECIFICATIONS. SOME OPERABILITY DETERMINATIONS WERE MARGINALLY BETTER, WITH A GREAT DEGREE OF VARIABILITY IN QUALITY. OPERABILITY DETERMINATIONS THAT WERE WELL DOCUMENTED AND REFLECTED CONSULTATION WITH ENGINEERING WERE GENERALLY OF SUPERIOR QUALITY, WHILE UNDOCUMENTED DETERMINATIONS THAT WERE INTERNAL TO OPERATIONS CONTINUED TO BE OF GENERALLY POOR QUALITY.

PROPOSED RATING: 3 PROPOSED INITIATIVE INSPECTIONS 93802 OPERAVIONAL SAFETY TEAM INSPECTION (NOV. OR DEC 1995)

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l SALEM MAINTENANCE l 9 Strengths e THE CONDUCT OF THE LICENSEE'S BASIC MAINTENANCE PROGRAMS CONTINUED TO BE GOOD. ADMINISTRATIVE CONTROLS FOR THESE PROGRAMS WERE ADEQUATE WHEN SUFFICIENT TIME FOR PRE-PLANNING EXISTED. THE LICENSEE'S ON-LINE MAINTENANCE PROGRAM HAS PROVIDED SOME MAINTENANCE PLANNING INSIGHTS, WHILE ITS OVERALL IMPLEMENTATION HAS BEEN MIXED, BUT STILL EVOLVING.

• HIGH " PROFILE " MAINTENANCE WORK CONTINUES TO RECEIVE A GREAT DEAL OF MANAGEMENT ATTENTION. THIS ATTENTION OFTEN RESULTS IN BETTER OVERALL PERFORMANCE ON THE J08.

O Weaknesses

• MAINTENANCE WAS OCCASSIONALLY CONDUCTED WITHOUT HAVING A PROCEDURE PRESENT.

• THE MAINTENANCE ORGANIZATION WAS CONSISTENTLY WEAK IN INVOLVING ENGINEERING WITH REPETITIVE EQUIPMENT FAILURES. AS A RESULT, ROOT CAUSE IDENTIFICATION AND CORRECTIVE ACTION FOR BOTH BALANCE OF PLANT (BOP),

AND SAFETY RELATED (SR) HARDWARE PROBLEMS CONTINUES TO BE WEAK.

MAINTENANCE CONTINUED TO PURSUE AN UNSUCCESSFUL " BROKE-FIX" APPROACH FOR REPETITIVE FAILURES OF BOTH BOP, AND, TO LESSER EXTENT, SR EQUIPMENT.

INADEQUATE PREVENTATIVE MAINTENANCE ON KEY BOP EQUIPMENT CONTINUES TO CAUSE A MYRIAD OF PLANT PROBLEMS.

PROPOSED RATING: 3 PROPOSED INITIATIVE. INSPECTIONS 4 .g . - 3. p +

l 62700 MAINTENANCE PRACTICES (COOR&IMA.TE utru we rusprerrnu SCHEDUEED-f0R~J"LY 10

• 17) iq z &e 4 s'-y u lc < WkI 93802 OPERATIONAL SAFETY TEAM INSPECTION (NOV. OR DEC 1995)

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SALEM ENGINEERING O Strengths e CORPORATE ENGINEERING SUPPORT OF PLANT ACTIVITIES WAS A CONTINUED STRENGTH.

• ENGINEERING HAS IMPROVED ITS SUPPORT 0F DAY-TO-DAY OPERATIONS O Weaknesses e ENGINEERING HAS NOT AGGRESSIVELY ADDRESSED HAGAN MODULE CONFIGURATION CONTROL PROBLEMS. LICENSEE SCHEDULES REFLECT ONLY MINIMAL PROGRESS TO RESOLVE THE ISSUE. (100 UPGRADES PER REFUEL OUTAGE WITH 800 MORE MODULES PER UNIT TO UPGRADE)

• SYSTEM ENGINEERING DID NOT ALWAYS AGGRESSIVELY PURSUE DIFFICULT ISSUES.

THEY WILLINGLY ACCEPTED THE FIRST PLAUSIBLE CAUSE AS THE ROOT CAUSE FOR PLANT PROBLEMS. PERFORMANCE IN THIS AREA CONTINUES TO BE SUSPECT 1 ESPECIALLY SINCE ROOT CAUSE ANALYSIS PERFORMED BY SYSTEM ENGINEERING CONTINUED TO BE WEAK. MANAGEMENT ALSO FAILS TO EMPHASIS THE IMPORTANCE OF RIGOROUS ROOT CAUSE ANALYSIS FOR RECURRING PROBLEMS. INCIDENT REPORTS RARELY CONTAINED WELL DOCUMENTED ROOT CAUSE ANALYSIS. AS A l

RESULT, CORRECTIVE ACTIONS FOR MANY PLANT PROBLEMS CONTINUED TO BE INEFFECTIVE.

e SYSTEMIC PROBLEMS WITH THE ISSUANCE OF PARTS AND SUPPLIES CONTINUES TO CAUSE INSTALLATION ERRORS AND OTHER PROBLEMS.

PROPOSED RATING: 3 PROPOSED INITIATIVE INSPECTIONS I 62704 & 38702 HAGAN MODULE CONFIGUARAION CONTROL AND 4

PARTS / MATERIALS CONTROLS (JUNE g C 93802 OPERATIONAL SAFETY TEAM INSPECTION (NOV. OR DEC 1995) /

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SALEM PLANT SUPPORT l

I. Radiation Control

, O Strengths

e SALEM'S RADIATION PROTECTION COVERAGE DURING BOTH OPERATIONAL AND OUTAGE PLANT ACTIVITIES WAS STRONG. GOOD COORDINATION WITH OTHER DEPARTMENTS WAS NOTED.

e MANAGEMENT OVERSIGHT OF RADIATION CONTROL WAS EFFECTIVE. SALEM HAD 4 STRONG RADIATION CONTROL PROGRAM AND EFFECTIVE ALARA PROGRAM.

O Weaknesses i

e ONLY MINOR EVENTS OCCURRED IN AN OTHERWISE STRONG RADIATION CONTROL PROGPAM.

II. Emeroency PreDaredness (EP)

O O Strengths & Weaknesses

• EP PROGRAM AND EXERCISE PERFORMANCE WAS GOOD.

U I. Security i

1 O Strengths I l

• SALEM'S BASIC SECURITY AND SAFEGUARDS PROGRAM WAS SOUND. l O Weaknesses

• ASSESSMENT AID PERFORMANCE IS DEGRADING. NRC INTERVENTION HAS BEEN NECESSARY TO ENSURE THAT ADEQUATE UPGRADING WAS PLANNED. y@g )

fjQ IV. Fire Protection (FP) and HousekeeDinQ Q O Strengths & Weaknesses

• EXCEPT FOR CERTAIN APPENDIX "R" CONCERNS AND SOME SCAFFOLDING PROBL 5, THE LICENSEE IMPLEMENTED A GOOD HOUSEKEEPING AND FP PROGRAM.

e OIL LEAKAGE OBSERVED FROM RCPs, A 10 CFR APPENDIX "R" FIRE HAZA , WAS' NOTINITIALLYADDRESSEDINATIMELYMANNERBYLICENSEEMANANGEpNT. .

SCAFFOLDING PROBLEMS CONTINUED.

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PROPOSED RATING: 1 ts it cel)edad 7 PROPOSED INITIATIVE INSPECTIONS NONE (EMPHASIZE ASSESSMENT AID PERFORMANCE DURING CORE SECURITY INSPECTIONS) jg / W

a SALEM SAFETY ASSESSMENT AND QUALITY VERIFICATlOq4 AM DM nAewbt p I[v,4 6f1 O Strengths

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• THE NUCLEAR SAFETY REVIEW GROUP HAS BEEN EFFECTIVE AT IDENTIFYING AND DOCU NTING PAST AND PRESENT SAFETY PROBLEMS.

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• SALEM MANAGEMENT CONTINUED TO HAVE EXTRAORDINARY DIFFICULTY DISCHARGING THEIR SAFETY RESPONSIBILITIES DUE TO THE ARRIVAL RATE OF NEW PROBLEMS, THE BACKLOG OF PROBLEMS THAT WERE NEVER ADEQUATELY ADDRESSED, AND THEIR OWN INABILITY TO DEVELOP A QUESTIONING ATTITUDE THAT SUFFICIENTLY CHALLENGED CONTINUED WEAK. STAFF PERFORMANCE.

PROPOSED INITIATIVE INSPECTIONS FRE"IEW LICEN3EE FROGRE33 Gh int NBU IMPACT PLAN I

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SALEM OPERATIONS O Strengths

• OPERATOR RESPONSE TO PLANT PROBLEMS AND TRANSIENTS WAS G000.

e OPERATIONS OVERSIGHT OF PLANT ACTIVITIES INPROVE0 FROM PREVIOUS A$$ES$NENTS.

6 Neaknesses e OPERATOR DID NOT CONSISTENTLY COMUNICATE NOR DOCUMENT PLANT PROB AS A RESULT, SUPPORT FROM PLANT MAINTENANCE, AND PLANT DEFICIENCIES.

ENGINEERING WAS VARIABLE, AND STRONGLY DEPENDENT ON THE QUALITY OF THESE DELAYS INFORMATION COMUNICATED AND DOCUNENTED BY OPERATIONS.

WERE OFTEN EXPLAINED BECAUSE OF THE MYRIAD OF PROBLEMS THAT ARISE DAY.

e OPERATORS CONTINUED To HAVE DIFFICULTLY APPLYING TECHNICAL SPECIFICATIONS. SOME OPERA 8ILITY DETERMINATIONS WERE MARGINALLY BETTER, WITH A GREAT DEGREE OF VARIABILITY IN QUALITY. OPERABILITY DETERMINATIONS THAT WERE WELL DOCUMENTED AND REFLECTED CONSULTA ENGINEER!NC WERE SENERALLY OF SUPERIOR QUALITY, WHILE UND0CUMENTED DETERMINATIONS THAT WERE INTERNAL TO OPERATIONS CONTINUED TO BE O GENERALLY P00R QUALITY.

PROPOSED INITIATIVE INSPECTIONS 93802 OPERATIONAL SAFETY TEAM INSPECTION (NOV. OR DEC 1995);

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i SALEM MAINTENANCE O Strengths I

• THE C0050CT OF TNE LICENSEE'S BASIC NAINTENANCE PROGRAMS CONTINUED T l G000. ADMINISTRATIVE CONTROLS FCR THESE PROGRANS WERE ADEQUATE WHEN SUFFICIENT TIME FOR PRE-PLANNING EXISTED. THE LICENSEE'S ON-LINE MAINTENANCE PROGRAM HAS PROVIDED SOME MAINTENANCE PLANNING INSIGNTS, WHILE ITS OVERALL IMPLEMENTATION HAS BEEN MIXED, BUT STILL EVOLVING.

• HIGN " PROFILE " NAINTENANCE WORK CONTINUES TO RECEIVE A GREAT DEAL OF MANAGEMENT ATTENT!0N. THIS ATTENTION 0FTEN RESULTS IN BETTER OVERALL PERFORMANCE ON TNE J08.

9 Weaknesses

• NAINTENANCE WAS OCCASSIONALLY CONDUCTED WITHOUT HAVING A PROCEDURE PRESENT.

• THE MAINTENANCE ORGANIZATION WAS CONS!$TENTLY WEAK IN INVOLVING ENGINEERING WITH REPETITIVE EQUIPMENT FAILURES. AS A RESULT, ROOT CAUSE IDENTIFICATION AND CORRECTIVE ACTION FOR BOTH BALANCE OF PLANT (80P),

AND SAFETY RELATED (SR) HARDWARE PROBLENS CONTINUES TO BE WEAK.  ;

MAINTENANCE CONTINUED TO PURSUE AN UNSUCCESSFUL ' BROKE-FIX" APPROACH REPETITIVE FAILURES OF BOTH B0P, AND, TO LESSER EXTENT, SR EQUIPNENT.

INADEQUATE PREVENTATIVE MAINTENANCE ON KEY 80P EQUIPMENT  ;

CONTINUES T CAUSE A NYRIAD 0F PLANT PROSLEMS, PROPOSED INITIATIVE INSPECTIONS i

62700 . MAINTENANCE PRACTICES (COORDINATE WITH HC INSPECTION t '

SCHEDULED FOR JULY 10 & 17) l 93802 OPERATIONAL SAFETY TEAM INSPECTION (NOV. OR DEC 1995) l

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d SALEM ENGINEERING O Strengths e CORPORATE ENGINEERING SUPPORT OF PLANT ACTIVITIES WAS A CONTINUED STRENGTH.

e ENGINEERING HAS IMPROVED ITS SUPPORT OF DAY-TO-DAY OPERATIONS 1

8 Weaknesses

• ENGINEERING HAS NOT AGGRESSIVELY ADDRESSED HAGAN MODULE CONFIGURATION J

CONTROL PROBLEMS. LICENSEE SCHEDULES REFLECT ONLY MINIMAL PROGRESS TO

, RESOLVE THE ISSUE. (100 UPGRADES PER REFUEL OUTAGE WITH 800 MORE MODULES PER UNIT TO UPGRADE)

• SYSTEM ENGINEERING DID NOT ALWAYS AGGRESSIVELY PURSUE DIFFICULT ISSUE THEY NILLINGLY ACCEPTED THE FIRST PLAUSIBLE CAUSE AS THE ROOT CAUSE F PLANT PROBLEMS, PERFORNANCE IN THIS AREA CONTINUES 70 8E SUSPECT ESPECIALLY SINCE ROOT CAUSE ANALYSIS PERFORMED BY SYSTEM ENGINEERING CONTINUED TO BE WEAK, NANAGEMENT ALSO FAILS TO EMPHASIS THE IMPORTANCE

" INCIDENT 0F RIG 0ROUS ROOT CAUSE ANALYSIS FOR RECURRING PROBLEMS.

REPORTS RARELY CONTAINED WELL DOCUMENTED ROOT CAUSE ANALYSIS. AS A RESULT, CORRECTIVE ACTIONS FOR MANY PLANT PROBLEMS CONTINUED TO BE INEFFECTIVE.

e SYSTEMIC PR08 LENS WITH THE ISSUANCE OF PARTS AND SUPPLIES CONTINUES TO CAUSE INSTALLATION ERRORS AND OTHER PROBLEMS.

PROPOSED INITIATIVE INSPECTIONS 62704 1 38702 HAGAN MODULE CONFIGUARAION CONTROL AND PARTS /NATERIALS CONTROLS (JUNE 26) l l

93802 OPERATIONAL SAFETY TEAM INSPECTION (NOV. OR DEC 1995) l l,

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I SALEM PLANT SUPPORT i  !

I andiation control O Strengths '

5

• SALEM'S RADIATION PROTECTION C0VERAGE DURING BOTH OPERATIONA

• PLANT ACTIVITIES WAS STRONG. G000 C0 ORDINATION WITH OTHER DEP

WAS NOTED. l SALEM HAD e MANAGEMENT OVERSIEW 0F RADIATION CONTROL WAS EFFECTIVE.

STRONG RADIATION CONTROL PROGRAM AND EFFECTIVE ALARA PROGRAM.

e Weaknesses l J

e ONLY MIN 0R EVENTS OCCURRED IN AN OTHERWISE STRONG RADIATION PROGRAN.

I II. rmaraancy Pranaredness (EPl

0 9 Strengths & Weaknesses 4 e EP PROGRAM AND EXERCISE PERFORMANCE WAS GOOD.

i

) III. Security i

i O Strengths 4

e SALEM'S BASIC SECURITY AW SAFEGUARDS PROGRAM WAS SOUNO.

9 Weaknesses i

e ASSESSMENT AID PERFORMANCE IS DEGRADING. NRC INTERVENTION HAS NECESSARY TO ENSURE THAT ADEQUATE UPGRADING WAS PLANNED.

IV. Fire prataction (FP) and Housakaanina O e Strengths & Weaknesses , 1

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• EXCEPT FOR CERTAIN APPENDIX "R" CONCERNS AND SOME SCAFFOLDING PROBLEMS, i

THE LICENSEE IMPLEMENTED A G000 HOUSEKEEPING AND FP PROGRAM, FIRE HAZARD, WAS e OIL LEAKAGE OBSERVED FROM RCPs, A 10 CFR APPENDIX "R" l NOT INITIALLY ADDRESSED IN A TIMELY MANNER BY LICENSEE i MANANGEMENT. l SCAFFOLDING PROBLEMS CONTINUED. )

1 PROPOSED INITIATIVE INSPECTIONS NONE (EMPHASIZE ASSESSMENT AID PERFORMANCE DURING CORE SECURITY J i INSPECTIONS) l Nix i N01938 '3*B'N S'O TE PT 56/8T/SO sm

SALEN SAFETY ASSESSMENT AND QUALITY VERIFICATION O Weaknesses e SALEN NANAGEMENT CONTINUED TO HAVE EXTRAORDINARY DIFFICULTY DISC THE!R SAFETY RESPONS!8!LITIES DUE TO THE ARRIVAL RATE OF NEW PR08 LENS, THE SACKLOG 0F PROBLENS THAT WERE NEVER ADEQUATELY ADDRESSED, AND THEIR OWN INABILITY TO DEVELOP A QUESTIONING ATTITUDE THAT SUFFICIENTLY CHALLENGED C0KIINUED WEAK STAFF PERFORMANCE.

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• * * * * ,d REGION I I PLANT STATUS REPORT I

FACILITY: Setem Nucteer Generating Station mite 1 and 2

3. aAcacnouwp II. PLANT FERFORMANCE DATA III. ANALYSIS /ASSESSMDfT IV. INSFEcTION rsioGRAM STATUS

v. ATTAcHMarts Last updates merch 22, 1995 Update Approvat Section Chief CHANES 51NCE THE t.AST UPDATE ARE DEMARCATED IN THE BORDER g, .. ..... y & N - . - .i..... .t.... . .i w.

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ATTACNMENT A CONTENTS

1. BACEGAOUND

1. Licensee Pereuters

2. NRC organization

3. Licensee Orgenlastion ,

4 Operator Licensing II. PLANT PERFORMANCE DATA

1. Current Operating Status (lost 6 months)

2. Recent significant operating Events and Identified Safety Concerns (of test 12 months)

3. Esceleted Enforcement Activittee (of last 2 years)

4. IPE Insights Ill. ANALYSIS /ASSESSIENT

1. Previous SALP Ratings and Overvlow

2. Licensee Response to Previous SALP Furwtlonel Aree Weaknesses /Recent Licensee Performance Trends (in the last yeer)

3. Licensee Performance Strengths and Weaknesses

4. NRC Team Inspections Within the Last foer

5. Planned Team Inspections IV. INSPECTION PROGRAM STATUS

1. Status of Inspections (see attached MIPs Report #2) -

2. Proposed Changes to MIP

3. $1pnificant Allegations and Investigations 4 Open Item Status

5. Outstanding Licensing Issues

6. Local / State /Externet Issues V. ATTACleENTS (NOTE: To be determined based on intended audience)

1. Af0D Performance Indicators /LER Suunsry 0 )

2. Allegations Status D

3. Most recent $ ALP Report O 4 MIPS Report Nos. 2 & 22 0 ,

5. Principal staff Resumes (NRC and Licensee) O

6. Planned vs. Completed Inspection Hours O l

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• I. BACKGROUND 1 1. LICENSEE PARAM TERS Utility: P elle service Electric & Gee Company (PSE&G)

Company Location: Mancocke Bridge, NJ (18 miles Southeast of Wilmington, DE)

County Salem UNIT 1 UNIT 2 Docket ilos 50 272 50 311 CP Issued september 25, 1968 september 25, 1968 operating License Issued: April 6, 1977 Itey 19, 1981 August 2, 1980 Inittel criticality: December 11, 1976 3

Elec. Ener.1st Gener: December 19, 1976 Itey 29, 1981 i Commercial Operetton June 30, 1977 October 13, 1981 Reactor Type PWR 4 Loop same Contelrusent Typer Large dry same j Power Levels 3411 MWt Some Architect / Engineer PSE&G/UESC Some NS$$ Vendor Westinghouse same Constructor PSE&C/UE&C same Turbine sgtfor Westinghouse Westinghouse (GE q

4 Generator) j Condenser Cooling Method: Once through same

! Condenser Cooling Water: Delevers River same

2. IIRC ORGAllI2ATION d

NRC Regir- t Adelnistrator Thames T. flertin (Tet: 610-337 5000)

(Region I, King of Prussia, PA)

Olvision of Reactor Projecto: Richard Cooper, Jr., Divlefon Ofrector gRegion I) (Tels 8 610-337-5229) -

Wayne Lenning, Deputy Director (Tels 8 610-337 5126)

John R. W lte, Sectlen Chlef (Tels 8 610 337-5114) i i senior Resident inspector Charlee S. leerscheLL (Tels 8-609-935 3850)

Reeldent inspector: Joseph G. Schoppy, Jr. (Telt 8-609-935-3850)

Resident Inspector Todd N. Fish (Tels 8 609-935-3850)

Project Engineer G. Scott Barber (Tels 8 610-337 5232) l Project Manager Leonard Olshan, NRR (Tel 8 301-504 1419) 1 l

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, 3. LICENSEE ORGANIZAfl0N Meneaement Personnel:

E. Jesse Forland Chefreen etwJ Chief Executive officer Leon R. Etioson Chief Nuctor Officer and Preefdent Nucteer Businese Unit j

Stanley Letrme Vice Proeident, Nucteer Engineeririg '

Joseph Negen Vice Proeident Operatione d John Summere General Manager

• Setem Operations Jeffrey Benjamin -General Meneger, eustity Aeourance &

Nucteer Safety Review Charles Mezerunnier Director, Operatione Services Chuck Johnson Director, Numan Resources & Administration Francie M. Thomson -Licensing Manager Lee catelfano Operations Manager 4

Michael P. Morroni Manager, Maintenance-controlo 4 Michael Metcalf Meneger, Maintenance-Mechanteel Jerome A. Genetti Technicet Meneger Eric Kataman -Redletion Protection / Chemistry Manager Dennie Te@er Salem QA Manager Terry Collmer Manager, Setem Station Planning

. Arthur Orticelle Manager, Nuclear Trefning 1 Workshifts l' 5 operatione ehlf te, 2 working 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> ehlf ts/ day,1 relief crew,1 crew in training,1 crew off.

l Shift Comntement TE minim a M 3 M0 4 20 I

& Ro 5 RO i 1 STA 1 STA (dual role SRO) )

j Non Licensed Operatore 5 7 or 8 f Maintonence Electrician /I&C 1 2 Chemistry / Red. Prot. 1 2 Fire Brigade 5 6 (ofte fire brigade shared with Hope Creek) i t

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. 4. OPERATOR LICENSIWG l e. Licensed enactor anarators (Licensen cover oath unitait e Total mmber of active stos 28 l e Total mater of active Ros 26 e Total number of certified instructors: 13 e one elmulator (modeled after Unit 2) located at the training feellity in Salem, NJ, and i

used for Unit 1 and Unit 2 operator trefning and mac seministered licensing exams. PSE&G completed a major modeling upgrade package in the summer of 1993.

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• II. PLANT PERFORMANCE DATA

1. CURRENT CPERATING STATUS (for period 1/29/95 to 3/11/95)

Unit 1 besen the period operating et 1001 power. On February 3, the Licensee initiated a

' mit shutdom to comply with plant Technical Specifications. During leptementation of a i

DCP to correct a problem with a solid state protection eyeten ($sPS) power feed, a j

rededent power ogply tripped. The licensee wee moble to fully restore SSPs to operability within the technical specification limiting condition for operation acti m statement allowed outese time. On February 4, the licensee entered Mode 5 (Cold shutdown) to addrese $$Ps concerne. On February 15, operators entered Mode 4 (Not shutdown). The q

ticensee maintained the unit in Mode 4 iAfte resolving problems encountered with main steen atmospheric relief volves (MS 10s). On February 27, operators commenced a reactor eterty.

On Merch 2, operatore increased power to 48%. On March 3, operatore reduced power to 28K to make a bloshield entry to adjust RCP oil levels. On March 8, operators increased power to 1005 and maintained the mit there for the remainder of the period.

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I Unit 2 began the period in Mode 3 (Hot $tenchy). On February 1, operators commenced and completed a reactor startup. On February 3, operators commenced e Technical Specification j required shutdown from 15 power, following removat of WRC Enforcement Discretion due to potential common mode failure Of SSPS power supplies. The (feensee placed the unit in Mode j 5, completed trosleshooting and repelrs to sses, and commenced a plant startw. On February 11, operators took the reactor criticet and comunenced a power increase. On February 19, the licensee inittsted a shutdown from 475 power to remove the no. 21 Reactor i Coolant Ptap from service in response to low seat water Leekoff flow. The (feensee entered

- Mode 5, replaced the no. 1 seat on no. 21 RCP, and commenced a plant start w. On March 8, i

operatore achieved reactor criticality and commenced power escalation. The mit coupleted s the period at 905 power. .

2. RECENT SIGNIFICANT OPERATING EVENTS Als IDENTIFIED SAFETY CONCERNS i

e. Blanffleant Events falnen Anell 1990 i

e on February 3, 1995, e unit 1 main steem atmospheric relief (13Ms10) velve would not open in roeponse to maniputetton of centrote. On February 10, 1995, 22Ms10 would not respond in automatic to steen pressure above the pressure setpoint. These problems were the latest in j e tone history of events with M810 (and Nogen mochJte) performance probleme (including April l

7, 1994 event). The licensee did not initiate a thorough root cause until prompted by the reeldents and Regional management. A thorough root cause, perfonsed by a multi disciplinary i

a team, concluded that contributing factors included inadecpaste maintenance, vendor i

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refurbishment, design, control of parts, and operator m derstanding of design contributed to the performance problems. (It 95 02, not yet issued.)

e During tote January 1995, seles sought eNd wee granted e Notice of Enforceennt Discretion to address design deficiencies with the Solid State Protection System. Electrical coupersonts (e.g. Limit switches and pressure sensors) associated with main steem, turbine controls, and feedwater were susceptible to rendering all or most of SSPS inoperable based  !

on a ainete high energy line break. Vnen mexpected power supply trips occurred during the i modifications, Region I withdrew enforcement discretion. l i

e on January 11, 1995, with Salem Unit 2 in Mode 4, the no. 23 RCP seat water return valve {

for the no. 1 seal closed, foolating seat flow. The licensee determined that the pressure  !

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diaphragm of the ASCO solenoid velve failed because of its extensive time-in service (about  ;

20 years) coupled with the continuous air pressure applied at the diaphragm (about 80

'i psig). Plant staff planned to establish a periodic replacement sche ele for the J diaphrops. Westinghouse recosmonded that PSE&G inspect the no. 1 seal. For safety considerations (evoiding redwed inventory) Setem management, af ter consulting with Westinghouse and other licensees, elected to perform the maintenance by lowering the RCP I onto the "backseet" formed by resting the radial bearing on the thernet barrier heat exchanger. Selen meintonence coupleted the maintenance activity safely. Although they found no seal demose the licensee reptoced the no. 1 seal package.

e in January 1995, the inspectors learned that unit 2 operated the entire previous cycle 1

(5/o3 to 10/94) with a closed drain velve in a connon drain line for the Pressuriser Safety a Velve loop seats. The velve should have been opened, but the licensee had not done an edsquete post-modification linew or adequate post modification testing. The 10 settons of ,

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water in the loop seats would create thrust loading on the safety velve discharge piping 4

with the potential to deform the pipe, restricting flow. As a result, the loop seats could render the safety vetwee incapable of protecting the RCS from overpressurization. This issue is a candidate for escateted enforcement. (IR 95 02, not yet issued.)

e In December 1994 and January 1995, during startg from the refueling outage, Salem Unit 2 pressuriser code safetles teeked poet the seats se (apparently) to dead weight and theneet loading on the discherpe piping. As a reeutt, Sales spent the period from December 25, 1994 to January 10, 1995, determining the cause of the leakage. Sales replaced the code

! safeties, adjusted the piping, and, as of January 31, 1995, had successfully reached normat l

operating pressure with no code safety seet leakage. (IR 94 35) i e Stuck trash reke af fecting unit 1; occurred several times, em November 15, 1994, the new i

reke stuck on the old trash rocks in front of the 138 CW ptmp intake, forcing a power re & ction to 850 MWe. On December 7, 1994, the new reke again stuck on the old trash rocks in front of the 13e CW ptap intake, forcing a power reduction to 850 Mwe. On January 3, 1995, the new reke stuck in front of 12g CW pump. On January 9, 1995, the old reke stuck in front of the newly replaced rocks in front of 138 CW ptmp intoke. PSE&G replaced the

rocks in front of 13a CW ptmp, and ptens to replace the rocks in front of 128 and 11A by i the end of February. Att other rocks have been replaced at least once. (IR 94 31) 4 e Unit 1 operators commenced a forced shutdown on January 6, 1995, due to inoperable 1A safeguards Equipment Controls (SEC). The power styply felted. Although the Alternate Test Insertion (ATI) circuit had been turned on (see below) and had pro &ced portudic alorse, the techs and operators did not pursue the alarms ( & e to previous experience) and i apparently took a power reduction that could have been evolded. The licensee contracted an

- EMI specialist in mid-February to investigate the frequent ATI test faults. Engineering, steported by the EMI speciellet, determined that EMI tevels in the SEC cabinet, although high enough to cause ATI alarms, do not ispect the ability of the SEC to perform its

designed safety f mction. Engineering is actively pursuing the EMI specialist's recommendations to improve the lasunity of the ATI to EMI and to prevent future spurious ATI storms. (IR 94 31) e Grass intrusion into mit 1 Circ Water on December 11, 1994. Operators took 13g out of service to clean the water box.13A tripped on high d/p. Operators re&ced power at 5% per minute. The 125 and 12A emergency tripped. Operators re &ced power to 51% while restoring the 12A and 12e CW ptmps to service. (IR 94 31)

• Unit 1 operators initiated an mplanned shutdown on December 9,1994, for inoperable safeguards Equipment Control cabinets. The three SEC cabinets for each unit control ee pencing of safety rotated loads onto the 4kV vitet busses. A stuck test switch (not famediately identified) caused a fault indication in the test circuit. Technicians took the test switch panel from the le SEC to aid in trothle shooting 1A, and inadvertently caused a stuck switch in is SEC. Operations and maintenance staff concluded that a commen mode f ailure might exist, declared the SECS inoperable, and started the shutdown. The stuck switch in 1A SEC exleted from the previous surveillance on November 23, but operators did 4

not detect the f ault since they had taken the Automatic Test insertion circuit out of service he to ' nuisance

• eterms. (It 94 31) l Salem PSA Page 6 i

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• e On Noveeer 28,1994, rw. 2 station Power Teensformer lost power as a result of e .

modification in the unit 2 control room actuating ground fault protective relaying. The  !

worker performing the mod intrtduced a ground f ault on the relay, in conjunction with an existing promd elsewhere on the unpromded system (by design).

• Also on November 28, 1994, the no. 5 substetton in the 13 kV ringhus toet power, cousing the TSC to tone power. The cause wee insulatore arcing over. The TSC dieset started, but i the TSC ventitetten felled to etect se e result of a blown fuse. Fest transfere occurred l auccessfully en both mite.

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l . e greakdown of Insutetton on 4kV supply cable to the unit i vitet buses (Novestier 21, 1994);

caused ty liquefied pulling cogound dripping down onto the cable end between the dust boot and the heat shrink, providing a towered resistance from the terminet tus to the grom d i strap, e on November 18, 1994, the 4T60 disconnect opened cousing the no. 4 station power transform to de energlae, interrupting one source of offsite power to each unit. Loads fast l treneferred at unit 1. but 3 of 5 running cire water puups lost power, re w iring operators to re&ce power. Unit 2 lost spent fust pool cooling for 17 minutes since the other source of power wee out h e to the outage work. No apparent increase in SFP tag. No apparent cause for the disconnect opening. Power was restored five days later using no.2 SPT.

e on September 29,19%, seten unit 2 operators inittsted a eerset reactor trip from 29E I power following the inadvertent closing of two main steem footation velves (Nstve). The I Licensee was returning the mit to rated power following maintenance on one of the charging  !

pussis. The operators were et the point In the power ascension proceere for closing main i steen Line draine. Af ter acknowledging the order to close the main stosa drains, the i operator mistakenly closed two mstys. Operators inttleted a menuet trip. (see IR 50-311/94 24) j I

• On August 24, Unit 1 operators reduced power to 15 to repair the condensate system suction '

header. The header sustelnad damage to e oggiport pedestel and several sapension joints i

when operators isolated No. 12 condensate pimp to replace its mechanical seat. Pressure from back leakage through the closed pump discharge typees volve generated sufflcient force to shift the suction header. The Licensee repelred damaged components and modified the condensete procedure to change the sequence of volve mentpulations operators follow den isolating a condensate pump. (see IR 50 272/M-19) e on July 14, 1994, setem Unit 1 operators initleted e.nonust reactor trip from 1005 power I following a complete toss of circulators. A lightning strike caused the Unit 1 circulator supply breakers to open on undervoltage. Operators responded correctly in tripping the reactor as condenser vacuum decreased rapidly. (see IR 50 272/9414) e on July 2,19M, the licensee identified an misolable flange teak from an mused instrument ifne en the No. 22 reactor coolant pump (RCP). At the time of the discovery, the licensee wee attempting to repelr the flange. The licensee cooled down and O z ined the plant (taking the plant from Mode 3 to Mode 5). The Licensee established a freeze seel on the Leeking line and reptoced the existing flange and piping with a blank fienge. (see IR 50-311/M 14) e on J m e 29, 1994, solem Unit 2 experienced a reactor trip from approximately 65 reactor power h e to low steam generator water level. Prior to the trip, while increasing power to 14%, e foesheter oscillation caused a hfgh water level condition in one steen generator.

The high steen generator water level Inittsted a fee & ster f oolation. The levet oscillettore occurred when the alnim6ss flow velve cycled operi and closed. The licensee changed procedures to leprove operator control of the alniana. flow volve. The Licensee also changed the poln in the velve controls. The operator reduced power to within the capacity of auulliery 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 J m e 10, 19 M , d ite operettne et 975 power, the salem Unit 1 reactor automatically tripped following a main generator trip. The licensee concluded that a potential .

transformer failed, cousing the main generator output breakers to open, leading to the reactor trip. The licensee sent the potential transformer to en outside facility to determine the co me of the component felture. (see IR 50-272/94 13) e on April 7,1994, the Unit 1 operating crew rapidly reduced power in response to severe river sress intrusion et the circulating water intake structure. Salem Unit i tripped from 251 pow 3r & ring maneuvers to shut the plant down. sesowent to the reactor trip, the plant experienced a series of safety injections which resulted in loss of the pressurizer steen bubble and normat p* essure control. In addition to the reactor trip and safety injections, certeln volves that are required to operate, felled to close. On April 8, the Nec dispatched en Aussented Inspection Tesa to the site to review the causes and safety leptications of the euttiple failures in safety related systems & ring the event and possible operator errors. (see AIT toport 50 272/94 30 and 50-311/9440)

b. Assessment unenticipated owlpment deficiencles continue to dominste performance of the solen mits.

In February, both mits shutdown to correct design inadewacles with the solid State Protection system. Problems with main steen atmospheric relief velve controls deleyed mit 1 starte mtil February 27. Although operators resterted unit 2 on February 11, low seal toekoff flow from the no. 21 Reactor Coolant Puup seel rewired a shutdown on February 19.

Salem PSA pape 3 i

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. As of January 31, Sales Unit 1 had continuously operated for more then 150 days, etthough Unit 1 operators had to reduce power six times in six weeks due to equipment problems from '

Novesdaer 6,1994 to Deceeer 17, 1994. On the other hand, the Salem mits have experienced only one reactor trip in the six months beginning August 1,1994, as cogered with five trips in the period f rom February 1,1994 to August 1,1994. Operatore have bege to take significantly increased ownership for plant performance and safety. Their involvement in insuring nucteer and personnet safety daring the inspection of the no. 23 goector Cootent

Pump seat illustrates their loadorehlp in identifying and preventing pitfalls In plant activities. Maintenance management identified that lack of s wervisory oversight of job briefings had resulted in ineffective worker preparation for maintenance activities. Steps have been tehen to leprove the job briefines. System engineering sigiport for deity operations and maintenance activities continues to re wire significant ( g rovement. White

' some I g rovement has been noted in design engineering sigiport for deity activities, plant and design engineering senior management involvement wee fregently recpired to force casamication between the organitettons. Plant support organizations continued to demonstrate excellence in their activities.

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Overall, the tsaber of chattenges to moventful Salem operations continued at a high rate in comparison to other plants, such es, Nope Creek. Senior PSE&G management hee loplamented j

3 e number of changes intended to address the need for change, including replacing the Chief Nucteer Officer, the Seton General Menacer, the quellty assurance and nucteer safety review 7

, manager, the station quality assurance mensper, the mechanicet maintenance manager, the planning manager and the plant technical support manager. Senior PSEFG management met with Region I senior management on March 12, to present a proposed Setem .sorgenfration. The new organization would add a mit 1 director and a mit 2 director reporting directly to the Salem generet mensper. The new orgenf ration would etso add (for each mit): a unit j operations manager, mit senf or nucteer shif t agervisor, unit maintenance manager, unit l'

planning manager, and mit outage planning mensper. Salem management has taken steps to increase the esphesis on accomtebility from the Vice President of operations down through all levels of management to the workers. Leon Elleson initiated a team of consultants and nucteer incksstry senior managers to determine why PSE&G actions to leprove Sales

, performance have been ineffective. In addition, Mr. Elleson has initleted a process to bring about e ' step change

• in Selen performance. This process is intended to hold managers

' accountable for achieving reeutte, as opposed to past equheels on generating activity.

4 Although some examples of leproved performance have occurred, especletty in the areas of operettens and usintenance, it cannot yet be determined whether PSE&G actions ultl result

in testing enenges.

c. Performance indlentar Data l

FOR AEE) 70 (PDATE 4

Units 1 and Unit 2

d. ancantiv fdantiffed fachntent tafety and mananmelat chaltaname fof tant 12 months) i i e The Salem unit 2 refueling outage, schedJted for TT days, extended to 110 days as a result of equipment probless, including pressurfter code safety vetves leaking post the seat.

e goth Setem mits shutdown in early February 1995 dae to inadecpaste design of the Solid State Protection System. A single steen line failure in the turbine building could have

rendered both trains of $$PS inoperable with the result that operators would have been rewired to manuelty initiate Safety Injection.

e goth Salen mits suffered performance feltures in the controts for the mein steam safety atmospheric relief vetves. These controts have a long history of inadecpate control and maintenance. In the most recent problems, the Licensee again discovered mexpected e components in the control circuits, demonstrating ineffactive corrective action for the level IV vietetton efter the April 7, 1994, event, e A rsaber of allegations with potentlet safety algnificance have been substantleted, j includingt

o inade@ste PCAV design, with the result that rededent capability to limit RCS

pressure under low tagerature conditions had not been assured (an USO with the

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potentist for escateted enforcement);

o instellation of non-e limit switches in safety related applications, two of the eight (for both mits) head vent volves, with the result that repeat problems with

safety rotated part controls rejse programentic questions about the Sales ability to control safety rotated maintenance (currently being reviewed for escateted enforcement); and o incorrect Technical Specification definition of controlled teekage, with the result Setem PSA Page 9

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!* that safety injection flow supplied to the core, in the event of a RCP seet supply

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tine failure during en accident, could have (and at times would have) been less e

then assumed in the accident analysis (no vlotetton was issued, since satem was always in compliance with the Technical specifiestion requirements).

The Senior Resident Inspector has personally seen evidence that the alleger made the

! concerns known to the licensee and that the licensee did not respond in a timely, conservative fashion. Although some of the allegations from the same source were uns @stentiated, several more have yet to be addressed.

e The licensee discovered on October 15, 1994, 2 days into the unit 2 refueling outage, that a velve in the pressurlaer code safety velve loop seel drain Line had been closed throughout the operating cycle from July 1993 until October 1994. The lamediate safety laplication is that the licensee could not assure, based on any onelysis estating as of Merch 15, 1995, that the water hasumer from the impact of the water in the loop seal on the velve discherpe line would not deform the discharge pipe and restrict flow to less then that regaired by design. The licensee is currently performing an analysis to demonstrate that the velves could have performed their intended f metton, however, engineering stated that enelysis ullt not be able to show that the thrust loads will be within code ellowable timits.

e service Water (SW) Leeks: The licensee is completing a seven year pipe replacement project that will reptoce most (about 19,000 lineer feet are safety related) of the safety related SW piping with 65 moty steintess steel. This project will probably continue through 1997.

Currently, approximately 90% of the safety rotated portion of the project has been  ;

completed, including the majority of the gW piping in contaltenent, diesel boys, SW intake '

structure, and auxiliary building. gesed on NaC inspection, SW pipe replacement project is ,

progressing satirfactority se scheduled.

e Unit 2 Sustained Operation of Greater Than 1005 Powers daring the recent outage, the licensee confinmed eroeien of the feedwater flow nogales resulting in incorrect entine colorimetric data. Upon discovery, ticensee famediately reduced power for both units, and began adjusting instrument setpoints to insure conservettve operation. The Licensee concluded that 102.55 was the exact power level and operating at that power level did not i invetidote any of the UfsAR Chapter MV conclusions.

e Work Control Problems: During the Unit 2 refusting outage, the licensee and the NaC Identified additionet emanples of failure to follow established procedsres relative to the control of maintenance work activittee. These examples were simiter to those previously l Identified daring the Unit 1 outage, November - December 1993. i i

e In september, PSEM named Leon Elleson se the new Chlef Nucteer Officer (replacing Steven Mittenberger), and Proeident of a newly structured nucteer business mit. Elleson's appointment was effective October 1, 1994. Ne reporte directly to PSEM Chairman Fortand.

The nucteer businese mit will encompass att operationet and stoport activities for both seten units and Nope Creek. Since October senior management has etso appointed a new salem general annager and a new quality assurance end nucteer safety review manager; they have replaced the station quality assurance manager, the mechanical meintenance manager, and the 1 planning manager. As discussed above senior PSEM management met with Region I senior l management on March 12, to present a preposed Setem reorgenf ration. The new orpentration would add a mit i director and a unit 2 director reporting directly to the Sales general manager. The new organization would also add (for each unit): a mit operations manager, unit senior nuclear shif t supervisor, unit maintenance annager, mit planning manager, and '

mit outage planning manager. Sales management has taken steps to increase the emphasis on l acco mtability from the Vice President of operations down through ett levels of management i to the workers. Leon Elfsson initiated a team of consultants and nucteer Industry senior managers to determine why PSEM actions to (sprove solen performance have been ineffective.

In addition, Mr. Etteson has inittsted a process to bring about e ' step change' In solen l performance. This process is intended to hold managers accountable for achieving results, as opposed to poet saphesle on generating activity.

e Gross Intrusion et Circulating Water Intet Structures The Lleensee documented this plant vulnerability for years, yet the condition continues to provide m nocessary plant ,

challenges. An AIT was dispatched to the site on April 8, 1994, to investigate the plant i transient that resulted from severe grote fatrusion on ,

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• April 7. The A!T concluded that the vulnerability of the design was previously recognized and modifications to improve the system had not yet been implemented.

e Unaddressed Equipment Problems: The staf f documented numerous cases of known equipment deficiencies factoring significantly into Selon events. The AIT of April 1994 found that management allowed epipment problems to exist that made operations difficult for plant operators.

I e In an effort to leprove management accomtability and performance, in July 1994 PsEAG ,

terminated approximately 55 non-bergelning unit maahers of the Nucteer givlelen for (

4 inadequate performance. Eleven of the terminated employees were assigned to Seten.

J e operators continue to face many chattences posed by egipment failures. Recent examples include the control air system, the emergency diesel ponerator alr start system, and the main feeduster puup hydraulic control systems.

3. ESCALATED ENf0RCEE sf ACTIVITIES e The NRC issued e Levet !!! Vlotation on March 8,1994, documented in NRC Inspection Report 50 272 and 311/93 23; 50-354/93-25. The vlotetton was based on multiple exemples of PSE&G's f ailure to follow procedures and their fatture to property control safety-related activities.

• The NRC issued four Level !!! 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 auring the April 7, 1994 event.

• On February 8, 1995, PSE&G met with NRC et Region I in King of Prussia to discuss the findings of the office of Investigation relative to assertions of violations involving 10 CFR 50.5 "Dettberate Misconduct," and 10 CFR 50.7 "Esployos Protection."

e on March 17, 1995, an enforcement penet will review three vlotations for potential escalated enforcement. The vlotations involves o failure to control meterials used in safety rotated applications (non-e timit j switches instatted in two reactor head vent volves);

o failure to control a modification to insure that it was correctly implemented a

(Instelling the loop drains for the pressurizer code safety without insuring that the drain vetwee were properly stigned, or insuring that post modification testing verified that the drain performed its intended f mction); and o a repeat felture to comply with the Technlcel Speelfleetion action statement requirement for en inoperable PORV.

4. IPE IN51GNTS e Sales adseitted its IPE to the NRC in July 1993; the document le still under NRC review.

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III. ANALYSIS / ASSESSMENT

1. PREVIOUS SALP RATINGS AND OVERVIEW

a. Previous RALP tatinna Ftmettonal Area Jtna 19. 1993 November 5. 1994 Operations 2 3 Melntenance/ 2 3 surveillance Re&on 1 N/A Emergency Preparednese 1, Declining N/A Security 1 N/A SA/ov 2 N/A Engineering & Ts 2 2 Plant Support N/A 1 current ca n .t period: November 5,1994 to March 9,1996.

b. SALP Overvlaw (derfvad frem the a - ev naranraoh of each SALP nection h OPERAfl0NS On January 12, 1995, the SALP board met to discuse PSE W s performance at Selen dJring the period from Jtme 19, 1993 to November 5,1994. The board concluded that operatore generelty responded appropriately with good command and control to the many plant tripe and operational transiente that occurred over the SALP period. Likewlee, they demonstrated good proffclency In making emergency doctorations for events for which such declaratione should have been considered. However, performance over the assessment perlod demonstrated significant weaknesses in several areas. Operators did not practice ownership of the plant and did not egeresolvely entist other plant departments to resolve longstanding equipment probleme dich frecpantly challenged them in normal and teset plant conditions.

A lack of an appropriate questioning attitude by operators resulted in anomalous Indicatione, or conditions belns unnoticed or not tmderstood and not being acted upon. A teck of guldence for and training of operators on operability decisions resulted in some decisione being nonconservative or having week technical bases. Examples of nonconservative approaches to entering and exiting LCOs ,

occurros over the period. Some difficuttles were experienced managing and controtting outage activities. Poor self assessment within the Operatione department rotpled with ineffective independent assessment of Operatford by the Gustity Assurance and Nucteer Safety Revlow organfration contributed to the continuation of performance problems throughout moet of the period.  ;

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• MAINTENANCE /9URVEILLANCE The board concluded that performance weaknesses were evident in meintenance programo and activities, such as procedurst meerence and adequacy, the feecheck process, specification of post maintenance  !

testing requiremente, and control of work activities by numerous onelte groupe. Management has fsproved its safety focus in prioritising and schedJLine maintenance activities. However, management oversight of corrective action program activities has been weak me evidenced by the high recurrent egalpment failure rates. Inconsistencies in troubleshooting activities and root cause anstysis ,

contributed to the deley in correcting recurring problems. Meterial conditfon of the plant continues to improve, but there remain severet areas that need improvement. Although the in service testing program was adequate, management did not effectively resolve self essessment findings. Programs for ,

in service inspection, erosion / corrosion and steen generator leeksee monitoring were adegJetely laplemented.  !

ENGINEERING i The soard concluded that Engineering performance was incorstatent, with substantial verf ation in quality. The quality of the discipline deslen work was good, with significant engineering management

• focus shown in severet modification activities. However, engineering work priorities did not always reflect plant needs. In several significant prograsmatic areas in which the Engineering orpenfastion had an important role, performance was, on belance very good, significant problems, nonetheless were noted associated with root cause essessments and with ogJfpment problem resolution. The fact that there enleted engineering capability, that when focused by station management and brought to bear on leportant issues, demonstrated the ability to achieve very good performance, suggested that a s8gnificant espect of the problem was escociated with the effective engagement of available engineering expertise In activities leportant to safe plant operatione, such as in root cause assessment and equipment problem resolution.

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) PLANT SUPPORT The goerd concluded that plant support fimettone contributed effectively to safe plant perfonsance. ,

! Performance in the radiation protection eroe continued to be e significant licensee strength. Well tralned techniciens and staff coupled with effective management resulted in aggressive ALARA program leptementation with significant dose savings reellaed. Excellent performance in the radiological

) envirorumental monitoring and effluent control programs was egeln noted. There was continued good I

performance in the emergency properosess ares. Security program performance continued to be a strength. Fire protection program (splementation was substantially leproved. l i

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2. LICENSEE RESPONSE TO PREVIOUS SALP FUNCTIONAL AREA WJ4NESSES/RECENT LICENSEE PERFORMANCE TREles (in the test year) l 8 OPERATIONS l t

The Licensee response to the SALP did not provide detailed information on plans to address performance inadewacles. The response ponerstly agreed with the NRC's assessment of Sales performance, in eMition, the response stated an intention to correct Selen performance problems. Since the response i letter wee issued, senior PSEM management hee initiated an effort to determine the cause of the  !

ineffectiveness of previous corrective actlant. In seltion, PSEM management proposed reorganf rations of several organizations (discussed in more detall below), and loplementation of a ' step change' process intended to produce results, rather than activity without results.

4 The proposed re-orgenlaation would quickly bring the mitization concept to fruition for Sales l Operations. Two plant directors (one for each unit) would report to the Salem Generet Manager. In turn, two operations managers (one for each unit) would report to the directors, and each operations i manager woutd have responsIbllity for a unit operations depertaant, Inc1udIne a Senior NucIeer Shift S w ervisor and the ehlft complement necessary to sg port operation of that unit. It is fsportant to

! note that, as of March 15, the Licensee had not reached a finst conclusion to leptement the propose orgenlaation.

In response to the April 7 ovent, operations management provided leprowed ouldance to operotors for command and control and conservettve operation of the plant.

In response to WRC concerne, Operations management developed a flow chart for operability determinettone. Inspectors have occasionally noted weak or incorrect interpretation of Technical Specifications.

The inspectors have also noted that the Operations Manager has convinced the department staff that change is necessary, and fostered an increasing sense of ownership and team work.

e MAINTENANCE AND SURVEILLANCE Secondary /goP ewfpeont deflciencies pose significant challenges to plant operations, e.g. menway fallure, condensate header danese, COPU filter replacement, CW travelling screens, FW feed control at low power tevole.

In order to leprove overalt performance and response to emergent issues, PSEM reorganized the

Melntenance Department. Changes included replacing the single Melntenance Manager role with three new positions

1) Mechanicet Maintenance Manager, 2) Controls Maintenance Meneger, and 3) Planning Manager. PSE M began to mittae these departments. The proposed (as of March 15) reorganization would further unitize maintenance planning management structures. As of March 15, mit 1 and unit 2 had separate outage planning managers. The proposed reorgenlaation would provide seperate (non-outage) planning managers and maintenance managers for each mit, reporting to the unit directors for their respective mits. The a

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• mit maintenance annagers would oversee mechanical, electricet and l&C maintenance for their respective mits (recombining the disciplines under one maintenance manager for each mit).

To address the existence of Long standlns equipment problems, plant management required operators to l develop a list of workarom de to be addressed by maintenance personnel in accordance with assigned i I

priority.

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• ENGINEERING AND TECHNICAL SUPPORT j Sales and corporate engineering have not consistently consemicated well with operations, nor has

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i operations caemmicated well with engineering. System engineering has not effectively prioritized i

their workload, nor have they effectively monitored agalpment reliability, as demonstrated by the  !

"workeromer' IIst generated in response to this NaC Identified concern. The system engineers did not I receive training on operability or Generic Letter 91 18 mtfl September 1994.

An NRC observation related to the Selen rod control Issue was that the inittel troubleshooting efforts locked clear leadership and delegetlen of responsibilities. This resulted in the efforts narrowly focusing on the most recent system entfmetion without adequate attention to the repetitive nature of 4

the feltures and the need to deteralne and correct the root cause. The fatture of PSE&G to determine I the root cause of the failures resulted in n eerous aborted start @ ettempts. The team did observe significant leprovements in the control of trosteshooting and root cause determinetton daring the inspection. A management oversight team was initleted to review ett !&C troubleshooting activities in en of fort to redace events caused by trosleshooting.

l In late February 1995, PSE&G announced a reorganization of the Nuclear Engineering department (corporate engineering). PSE&G management redirected resources no longer regJfred to s g port the Salem revitalization project (since it would be substantially complete in 1995) to better support $ stem and  ;

.' Nope Creek operation. The effects of this reorgenlzetion have not yet been demonstrated.

4 In addition, Selen management rotated the Technical Sgport manager to the euellty Assurance and Nucteer Safety Review department to provided leproved oversight of euclity Assurance and corrective  ;

action programs. Selen management had not named a permanent replacement Technical Sg port manager as of March 15. I e PLANT SUPPORT The NRC noted that PSE&G continued to perform at a noteworthy levet in the eres of radiological protection through the end of 1994, especlotly during the recent unit 2 refueling outage.

The Licensee's annual portf et.perticipation emergency preparodiess exercise was condacted on Jee 23, 1993. On-site response to the sleuteted emergency was very good. An exercise strength wee Emergency Response Manecer command and control. No eneacise weeknesses were identified. Significant erees for potentiel leprovement were maintenance team tracking from the operational Support Center and public address system operability in the Technicet Sgport Center.

The PSE&G security program continues to be effectively directed towards public health and safety.

However, certeln essessment elds have deteriorated to the point there maintenance was no longer effective.

e SAFETY ASSESSMENT /ouALITY VERIFICATION In July 1993, the lfconsee formed a Comprehensive Performance Assessment team (CPAT) editch conducted a special assessment of safety issues and recent plant events using en integrated MORT investigatory enelysis. The CPAT developed comprehensive root causes for these events, and the licensee has formed task teams charged with developing corrective actions. PSE&G has held periodic meetings with the NRC to discuss CPAT findings, and the NRC continues to monitor licensee progress in this eree.

3. LICENSEE PERFORMANCE STRENGTNS AW MAKNESSES

• Setam performance continues te be inconsietent.

e Capacity f actor has been low due to refueling outages et both mits and manerous forced outages and power redactions resulting from problems with SPPS, MS-10s, pressurizer code safety velves, rod control, and to s g port PORV replacement as well as equipeont modifications following the April 7 event. Gross fouling of circulators and rueerous plant trips contribute to the low cepecity factor as wett.

Strengths:

e The licensee continues to increase resources for a meterfel condition leprovement program. The NRC hee observed noticeable taprovement in the meterial condition of the plant, indicating that the Salem PSR Page 15 l

l 4

licensee has been earnest in the laptementation of improvements.

e Radiation protection program (splementation continues to be very strong.

• When problems or conditions are self-identified and self detected, event response and root cause 2 determinetton are through and comprehensive, particularly when the matter is the st&Joct of NRC attention. In other cases, the licensee's performance le considered weaker, as identified below.

e PSE&G has responded to idontifIed performance and management weeknesses reietive to approech to 3

4 problem resolution by initiating the following actiones

) e PSE&G senior management hee reptoced the machenical maintenance manager, the planning manager, GA manager with personnel from within the PSE&G orgentsatten, and hee filled the General 14enager l poeltion and the Guellty Assurance and Nuclear Safety Review poeltf on with new personnet from i

]

outelde the company. In additten, PSE&G management proposed reorganizations of several organlaaticme and laptementation of a ' step change' process intended to hold managere accountable a for pre &cIns results.

e Verifying the effectiveness of numerous e gervloors and managers and changing the incts6ent when i

deemed appropriate; e Pursuing mititetton of the operations orgenf astion; meintenance and planning organizations are

, mi t t aed.

'

• Implementing the esteting performance essessment tools to leprove accomtability from the highest levels of menagement down to rank and file workers; I

e Forming dedicated teams to implement the corrective actions developed in response to the CPAT

,: findings. I 4 i Weeknessess l j

solen performance continues to be week ins l l

e ploming

• Control of unintenance; j e System Engineering and Techalcal Sg port e The ability to do root cause determinetton; j e Corrective action effectiveness & e to inadequate root cause essessment; I

e inadopete approach to problem resolution (i.e., generet tendency to fix problems or conditions based on the most probable cause without assessment or understanding of all poselble causal factors.) Examples include, but are not limited to maintenance and modifications to the atmospheric relief valves, problems with main feedwater reputating valve controls and fee & ster pape, maintenance of the Safeguards Equipusent Control systems, and inittet response to cracked diesel liner issues, failure to identify elevated reactor power in 1992, and falture to recognize generic laplication of rod control problems.

4. Nec TEAM INSPECTIONS WITNIN THE LAST YEAR Area /Date F!ndinen i

1 Augmented Inspectler. Team (AIT) An AIT was formed to review causes l April 15 16, 1994 and safety implicatione associated with a series

, of malfmettons emperienced & ring a plant 4 trenelent and s h equent trip.

Custenlaed Inspection Program Team The team concluded that increased August 15 16, 1994 Inspection is warranted in the areas of anointenance and d

control systems. Also empressed concern about Licensee i failure to proectively correct e pipment deficiencies before they lead to plant events.

SWSOPI Report on licensee's esseeement not '

September 5 23, 1996 yet issued.

leonttorirg of Licensee's setf Assessment Selse PSR Page 16 l

4

9 i

• IV. INSPECTION PROGRAM STATUS

1. STAH4 OF INSPECTIONS The inspection program status le reflected in etteched MIPS report e2. The data le current se of the date of the MIP. The MIP Indicates that inspection program to on-track with the planned resource attotment, no significant shift In inspection activities is warranted.

2. PROPOSED CHANGES TO MIP J

e Unit 1 I

j A. DRSS -

S. DRS -

C. DRP e Unit 2 A. DRSS -

8. DR$ -

C. DRP -

3. SIGNIFICANT ALLEGATIONS Am INVESTIGATIONS Three Selen ellegations are related to or resulted from o December 3,1992 ettercation between two SRG ,

engineers and the former General Manager (QM), Operations Manager (OM), and, to a lesser extent, the Manager oustity Assurance & Nucteer Safety Revlow (QA&NSR). 01 e 4stantleted heresament and j Intimidstlen (N&l) in thle case. Enforcement conferences were concheted with the licensee and the i effected managers on February 8 5 23, 1995. Some of these managers engaged in willful eleconchet (pre-decisional). Enforcement action is pending.

l Since the licensee's effort to terminate several esployees for poor performance on July 18, 1994, the Region hos received additional euttifaceted attegettone from two terminated employees that are currently mder review. One of these pertelned to 23 separate management, operations, and engineering concerns. These were presented to NRC personnel in a fece to face meetirg on August 8,1994. One

• concern pertelning to the low pressure over protection system (POPS) was s entantiated. Inadequate design compromised the redundant capability of the PORVs to limit RCS pressure mder low toeperature conditions. An enforcement panel agreed to proceed with additionet action after 01 completed its review of potential ulltful misconchet and herseement and intimidation issues. An additional multifaceted ellegetton involved both technical fasues and potential M&I lasues. This allegation concerns ela technical issues relsed regarding the environenntel quellfication of equipment.

~

Currently, the E0 f asues are being reviewed by DRS and the 4

5 1

6 Salem PSR Page 17

._ _ . . . _ . . .- _ . _.. m- . . _- . _ _ _ _ _ _ _ _ _ . _ .. = _

1 l

• wrongdoing issues are being reviewed by 01. This allegation also involved a terminated enployee. The )

j NRC received this allegation from senior PSE&G management.

Additional ellesettons with potential safety significance have been sthstantiated. Non safety related l limit switches were Installed in two of eight reactor vessel heed vent velves (safety related I e application), and an incorrect Technicet Speelfleetion definition of controlled leakage, with the result that Safety injection flow supptled to the core, in the event of a RCP seal supply line failure during an accident, could have (and at times would have) been less than assumed in the accident snelvels (no violation was issued, since Salem wee always in compliance with the Technical Specification rewirements).

Cottoctively, these ellegations lepticate the previous station management's ability to personally resolve and address safety issues. Regarding the December 1992 altercation, this incident and the two 1

related ellegations appear to be chse to management's confrontational attitude with QA&NSR personnel. j i Since these managers have been replaced, thle concern appears to have dissipeted. The E0 ellegetlen and its 01 cogenent, and the 8/96 allegation appear to stem from a tendency of PSE&G to manage try meno. They are not effectively using their root cause programs. Management's failure to identify and  !

i resolve root causes was a direct contributor to these two allegations. Based on the SALP (50 272/93-

99) and a recent engineering inspection (50 272/95-01), this appears to be a continuing concern.

4. OPEN ITEM STATUS

$ BACKLOG /No. GREATER THAN 2 YRS i (Unit 1 and 2 - Common) g 7h 8

' NOTE: The large number of open items le due to the issuance of an Appendix R/ Fire Protection Team Inspection Report in October 1993 and an EDSFI Team Inspection Report in November 1993.

5. cuTSTANDING LICENSING ISSUES i e GL 89 10 (MOV) technical differences between NRC/PSE&G. (Nepe Creek also)

e EDG amendment meeting held May 11, 1992 to resolve issues.

o TS amendment to resolve AFW/contairseent spray issue (see Section II.2.a).

• Increase in survelltance test intervals and ACT for reactor trfp and ESFAS.

e Install new digital feechseter control system.

e Evaluation of Control Rocus Deelen Deficiencies that were not corrected.

• Sulletin 88 08 (Thermal Stress in Piping Systems Connected to the RCS) - licensee is revising their response.

6. LOCAL / STATE / EXTERNAL ISSLES

s. NJ DEPE/BNE I

e Now providing igut/cossents on all PSE&G licensing change reposts.

e Nigh interest in reeldent Inspection accoopeniment.

e Continuing interest in Sales coollrg tower issues e en Salem's renewable verlance for the use .

the Delswere River es a heet sink came w for renewet in 1984, New Jersey envirorumentellsts appealed j to the state to not renew the vertence. In 1990, NJ DEPE issued a adraft order" requiring PSE&G to buttd two cootIng towers to sgport the Salem units' operation. PSE&G responded to the state's order with a 56 volume comment, and the issue is currently taider review try NJ DEPE. Recent NJ DEPE decision not to re@lre cooling towers.

• State inspectors generally accespany all Alf efforts.

b. Other (Recent Medle Interest) e Large interest in recent Alf (April 26, 1994) exit meeting and subseeaant enforcement conference (July 28, 1994). Several local televleton and newsprint representatives attended. Also, the conference was attended by representatives of Senator Blden's staff.

j i

Salem PSg Pese 18

SALEM EXECUTIVE SLsetARY LICENSEE PERFORMANCE STRENGTMS AND WEAKNESSES Salem performance continues to be inconalstent.

1 e Capacity factor has been low dJe to refusting outages et both units and numerous forced outages and power reductions resulting from problems with SPPS, MS-10s, pressurfter code safety valves, rod control, and to sg port PORV replacement es well as e@lpment modifications following the April 7 event. Grass fouling of circulators and numerous plant trips contribute to the low capacity factor as well.

1 Strergths:

e The licensee continues to increase resources for a meterial condition improvement program. The NRC l

has observed noticeable leprovement in the meterial condition of the plant, indicating that the d licensee has been earnest in the isplementation of leprovements.

- I e Radiation protection program laptementation continues to be very strong.

T

• When problems or conditions are self identified and self detected, event response and root cause determinetton are through and comprehensive, particularly when the metter is the adject of NRC 2

attention. In other cases, the licensee's performance is considered weeker, as identified below. .

1 e PSE&G has responded to identified performance and management weaknesses relative to approach to l problem resolution by initiating the following actions:

o PSE&G senior management has replaced the mechanical maintenance manager, the planning manager, the technical so port manager, and the Salem QA manager'with personnel from within the r$E&G orgenlaation; and hos filled the General Manager position and the Quality Assurance and Nuclear Safety Review position with new personnet from outside the company.

e Verifying the effectiveness of numerous swervisors and managers and changing the incudient when deemed appropriate.

e Pursuing mititetton of the operations organization; maintenance and plaming organizations are 1 mitized. Additionet changes have been proposed to further unitiae operations, plaming, and maintenance managers below the proposed plant directors. i

, e Implementing the enleting performance assessment tools to (grove accomtability from the highest levels of management down to rank and file workers.

e Forming dedicated teams to laplement the corrective actions developed in response to the CPAT l findings.

e Initiating a team of consultants and senior managers from other utilities to determine the cause of the ineffectiveness of PSE&G corrective actions for Salem to date.

$ e Developing a ' step change' process intended to hold managers accountable for achieving measured performance isprovementa.

Weeknesses:

Selen performance has been week in:

e Planning.

Salem m necessarily rendered an entire train of Service Water inoperable for a valve repefr that didn't need i s be done, and didn't get completed. Sales planned maintenance on an EDG to tros le shoot a non safety portion of the test controls, without determining if parts were evallable; this extended the time in the LCO.

\

e Control of maintenance.

Level III violation in the Unit 2 outage for lack of procedure eserence and lack of tagging control. Mechanics changed the olt in the wrong component in the AFW pump, and mintentionally

" adjusted" the overspeed trip test device. The Selen Unit 2 PORVs were replaced with the "wronga internata (not the parts intended). The correct internets were esse @ently installed daring the recent Unit 2 outage.

e Engineering and Technical Sgport.

System engineering has poorly trended equipment reliability (for example, the Diesel air start system, the control air system). Engir. sering (corporate and system) has not casemanicated well with operations (for the most part, the operators don't know who they are). System engineering has not been involved in operability deciolons, and was not trained on operability (Generic Letter 91 18)

4 l

. 2 totll I made a big issue out' of it.

j e secognitlon of the need to do root cause determinetton.

e corrective action effectiveness due to inedequate root cause essessment.

e inadequate approach to problem resolution (i.e., general tendency to fin problems or conditions based on the most probable cause without essessment or understanding of all possible causal factors.

a Examples include, but are not limited to the licensee's initlet response to cracked diesel liner

+ leeues, failure to identify elevated reactor power in 1992, and f alture to recognize generic l laptication of rod control problems.)

GENERAL OgSERVATIONS: i l

j orpenlaation may not have sufficient level of knowledge relative to managing change based on observations by 1

DAP and DR$ inspectors.

I i Until recently, the salen organization never engaged in attegting to benchmark itself rotative to other I utilities, including Hope creek.

1 1 New emphasis on accountability, ownership of problems.

j The July 1994 termination of 50 60 personnet appears to have been well received (by those who were not terminated). Generally positive comments from remaining staff acknowledging that there were several week performers that felled to contribute to overall gelity or safety.

l While J. Megan has been pushing for more swervisory field time, increased first line s wervisory presence I le not very apparent. However, there is a noticeable increase in the presence of middle management level )

personnet. i There are several examples recurring problems In pop (service air, and fee & ster) and some safety related l systems (EDG air start) have the potentist to effect nuclear plant performance.

It is not clear, that the maintenance orpentzetion and system engineering organizations understand and

, appreciate the need to change. Unable to agree on meaningfut leprovement strategy teless leposed from the j top down. Passive attitude seems to exist relative to chenho. Taken g with day to day crisis management.

still tend to focus on most inmediate proximate causes associated with an event.

White management is driving change, noticeable improvement in plant performance and personnet attitude and enthusteam for determining and laptementing improvement strategies and plans is not yet apparent.

4 W

s s

1 4

e salem Forformance Data gov d -r 6. 1994 to Nav 16. 1995 1,

d i

1

-- __ _ . ... -. - - - - . - _ - - - --. ~. . - ~ - - - - . _ - - . .~ - -

i, f 1. Operations i

9 Strengthe 1 e OPERATOR RESPONSE TO PLANT PROBLENS Als TRANSIENTS WAS G0(B.

- On January 6, operatione maintelnad good control and commanicated well edille responding to i power reshaction to 251 due to SEC power etspty felture. (In M 35) 1 l

- Operatore acted conservatively and aggressfwely in response to e press intruolon into thit 1 CMS reeutting in power reshaction. (It M 31) e OPERATIONS (WWER$1GNT OF PLANT ACTIVITIES IIFROWED FRON PREVISAS ASSESSIENTS.

J - The inspector reviewed Setem's leptementation of TS Survelllence 4.6.1.5 and determined

that everagirg the ten temperatures represented a more conservative indication of W containment temperature then re yfred. However, Setem initleted en Incident Report, 4

changed the survoittance to re wire overaging five temperatures, and inittsted a review to asesse the need to charge TS 4.6.1.5 in non-conservative usy. (It 95-02) l

- Operators actively participated in ensuring that activities with the potentfet for i effectire plant operation occurred safely and without incident. Operators also contributed to effective performance of the PZR code oefety volve work and facilitated a thereich pre-Jab briefing, and contributed to the quality of operability deterufnettone threigh interaction with engineering. (IR M 35) j - Increened sperator ettentien une noted to identifylre sesficient conditione and initiatins

action to effect resolutten. (IR 94 31)

• 4 l - Operator safety and effectively removed a stuck fust assembly toeding guide. Its remowel reeutted directly from the thoroughness of ticarmee preperation and oversight. (It M-31)

e Weakne

• OPERAft DID NOT CCNSISTENTLY CGetallCATE IIOR D00sENT PLANT PROBLENS OR DEFICIENCIES. AS A RESULT, 1

SUPPORT Fatsi PLANT HAINTENANCE, AIS PLANT ElIGINEER!hG WAS VARIABLE, AIB STRONGLY DEPfleENT ON TNE

' euALITY OF INFORMATION ColgtNIICATED AIS DOCLSENTED BY OPERATIONS. THESE DELAYS W RE OFTEN EXPLAINED BECAugE OF THE NYRIAD OF PROBLENS TNAT ARISE EACN DAY.

- The inspector noted that epipment deffcfencies continued to provide delly chatterges to control reas operatore. Previous NRC Inspection reporte identified degraded conditions, l

4 work aretada and distractions to operators. The inspector noted that Unit 1 control roon j sperators endured 13 survelttence teste, 8 technical specification entries, 5 abnonnet overhead enmmelatore, and 14 emergent opfpment deffelencies sharing one 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> perind in i early Aprit. (IR 95 07) j I

j

- Contrary 9 en internet cammitment, the training program for refustfre operators did not revleu prevleue fuel handling problems esperienced at sharfrg the Nope Creek outase.

Operatione identif fed a weeknese in the tracking and implementation of thfe training, took short term actions te provide additionet focused trainire, and inittsted a reviou of refustire training practices for tong-tors (sprovement.g(d }

- Nousvor, en tuo accesIene inspectors idontiffad minor fue1 handling opfpuent defIcfoneles

, knam by epipment operatore, but not conveyed to management. ( % }

o CPERATORS CONTINUED T0 IIAVE DIFFICULTLY APPLYIIIG TECNNICAL SPECIFICATIONS. SCIE OPERAgILITY j DETERIllNATIONS WRE MARCIllALLY BETTER, WITil A GREAT DEGREE OF VARIABILITY IN GUALITY. OPERASILITY

? DETERMillATIONS TilAT WRE WLL 000sENTED Ale REFLECTED CONSULTATION WITil EIIGINEERIIIG WRE GENERALLY

OF SUPERIOR euALITY, WNILE UN0008ENTED DETERNINATIONS TNAT WRE INTERIIAL TO OPERATIONS CONTINUED TO J

BE OF WNERALLY POOR ERAALITY.

7 - Between January 20, 1994 and October 18, 19M , and with the tailt in nodes 1, 2, 3, or 4, the RWST re ylred unter volume une not met at verlous times. In all instances, the licenses felled to doctore the RWST inoperable or take the action re stred by TS 3.5.5 Action. (IR 95 07)

- For a tus day perled, in April 1995, the ifcensee blocked actuation of both 2R1A and 2R15 en high redletten in the contret room air canditioning ventitetion intake duct rendering a

i 1 A

- . _ . . . . . - . . . . _ - - . . _ ~ - - - - - - . _ - - - - - . - .-

I 1

the footettone despers Incapable of leolatire en high redletten, and felled to take the actions reesired by Technical Specification 3.0.3. (IR 95 07)

- The beste for Technicet specificetten 3.8.1 states that the seten survelltance reestrements for demonstratire operability of the EDGs are bened en the reccomendetiens of RG 1.9, and RG 1.108. RG 1.108 (rev.1, August 19TT) reyf res nonconcurrent operetten of EDGE daring norunt plant aparation. Centrary to this restrement, et toest tuo EDG output breakere were concurrently closed on IIey 5,1995. (la 95-07)

- Operatore noted entry into the TS Action statement for en inoperable PORV. Neuover id not close the PORY block wtwo, se repired, within ene . g { p Q, they

- vhe inspectore prevleusly identified e almilar failure to seere to 78 involving tmit 2.

(IR 95 02, LER 95 02: Unit 1) (EEI 50-272;311/95-02-01).

- Operators manuelly blocked the Nigh IIsin steen Line Fleu 31 Actuation Lesic et T > 565 *F.

This conditlen provided no SI protection for e les line break daunstream of the lesivs. (It ,

M-35, LER 9616: Unit 2)

- Poor planning of relief volve and heating steen maintenance, and failure to pro g tly restore the margin to Boric Acid storage Tank (BAST) level, contributed to entry into e is LCO relative to the decreened BAST Levels oveliable for reactivity control. (It 96-31)

- Durire last several yeere, aperators determined that there were four separate instances of not meeting is rewiremonte for control room eres sRO marming rewirements. (LER 96 16:

Unit 1)

- The is rewired mininas Rust wettes uns potentially not met et verlous times. (LER 96-15: Unit 1) .

- Four planned is 3.0.3 entries occurred et unit 1 and three et unit 2 to steport correction I of Ansles Red Positten Indication (ARPI) system drift effective rede. (LER 95-03:seth 4 Units) l

- unit 2 operatore manuelty initiated ESF actuation to effect a les footetten signet in order to increase RCs T ,above 561'F. (LER 95-01:Lmit 2) 2*

s

a

2. Maintenance e Strengthe e THE ComuCT OF THE LIM NSEE'S BASIC MAINTENANCE PROGRAMS CONTINUED TO BE 00CB. ADMINISTRATIVE CONTROLS FOR THESE PRomANS ERE ADEeUATE WNEN WFFICIENT TIE FOR PRE PLANN! SIC EXISTED. THE LIMNSEE'S OM-LINE MAINTENANCE P900 RAM NAS PROVIDED SEBE MAINTENAME PLANNIIIG INSIGHTS, WILE ITS

OVERALL IIFLEMNTATION NAS SEEN MINED, BUT STILL EVOLVIIIG.

- Two meintenance activities did not adequately consider the risk associated with the concurrent performance of work on maltiple pieces of safety-related equipment. In the first case, Unit 1 opeestors coerenced a turbine driven MW pup surveillance prior to S returning No.12 RNR pup to service, and, in the second case, operators authorized /

sencR> testing issuedletely adjacent to No. 21 SW pup while No. 23 Su pup tagged out for g.g maintenance. (It 95 02) g

• Thecurrentprocessforschedulingandessessingtheriskofon-linemaintenance[tobev (N- '

good. PSE&G had plans in place to addrese shortcomings in the areas of procedJealization and format operator trefning. (It 94 35) Qf 4

4 - Monocement oversight, quellty escurence activittee, and self assessment activities of the ISI, EC, and SG tube plugging proerens were good. (!R M -29) e ging upg0 FILE

• MAINTENANCE WORK EXNITIIRJES 70 REmlVE A GREAT DEAL OF MANAGEMNT ATTENTION. THIS ATTENTION OFTEN RESULTS IN SETTER OVERALL PERFORMANCE 011 THE JtN.

- Setos maintenance staff made numerous changes to the procedsre to provide careful instructions for lowering the No. 21 RCP and to ensure an effective beckseat to limit RCS 4 leakage daring the seal replacement work. Several significant procedare improvements resulted from the management review. men workers implemented the procedare, the work proceeded esfely and without event. (IR M 35)

- Operations, maintenance, planning, and RP demonstrated good coordinetton, thorough attention to detall, and excellent redletion work practices in completing the No. 21 RCP j maintenance activities. (It 94 35)

- Salem's response and corrective measures to a water hammer that occurred daring e i Contelnment Spray Testing were prompt and appropriately developed. (IR 94 31) e MAINTENANCE WAS OCCAS$10NALLY COSUCTED WITNWT NAVIIIG A Penrsnuar PRESENT.

On April 26, 1995, plant staff performed hot spot flushing dich effected the RWST and ke)h

! safety injection without a procedare to control the activity, en May 4, 1995, plant staff' performed work on the no. 23 service water pump without a procedare or a work pec on April 18, 1995, a security guard corrected a malfmettonlns security door without a procedare or a work package. (It 95-07) 4

- In May 19M, e system ergineer inttf ated a work ressest to inspect the 2A128 VDC bettery charger ground detection circuit (GDC) wirfre. Ne inittsted the repasst following e system

• usik-down of the 28 Y bettery chargers that revealed Unit 1 chargers were configured differently than Lmit 2 chargers. However, the work order to condact the charger internet inspection did not occur mtil late April 1995. (IR 95-07)

J 4 e TME MAINTENANG ORGANIZATION WAS CONSISTENTLY WAK IN INVOLVillG ENGINEERIIIG WITN REPETITIVE EQUIPMENT FAILURES. AS A RESULT, ROOT CAusE IDENTIFICATION Als CORRECTIVE ACTION FOR 90TN BALANE OF PLANT (BOP), "~ SAFETY RELATED (SE) NARDWARE PROBLEMS CONTINUES TO BE EAK. MAINTENANCE CONTINUED TO PUS ~ 91 UNSUCCESSFUL "SROKE FIM" APPRGACM FOR REPETITIVE FAILURES OF BOTN BOP, A4D, TO LESSER EXTEN) A EQUIPMENT. INADEGUATE PREVENTATIVE MAINTENANCE ON EY 80P EQUIPMENT CONTINUES

• TO CAUSE A MYRIA 0 OF PLANT PROBLEMS.

l - While Setem eagerly pursued the low east water return flow problem d en flow dropped below y

1.0 spa, the degraded conditten omf eted since leey 1993. (IR 95-02)

- The Air Solenoid Velve for No. 23 RW Seel Water Retum Velve failed dare its extensive i

3 I

l ties-in-serv!ce coupled with the continuous air pressure appLlod to the diaphragm. (It 94-35)

- Test Sultches for the 1A Safeguards Essipsont cabinet were moved and eventuotty stuck in ptoce durftg the November 23 surveltlance. This caused the SEC cabinant to become Inoperable dich neceseltated a forced shutdown. Operators felled to detect the problem daring the Noveder 23 surveltlance, since the ATI circuit had been turned off chas to

• nulsence" status. (IR M 31, LER 9418: Unit 1)

- The brw% of ineutetten in a 4kV sely cable wee caused by Lispaefied pulling compomd dripping down onto the cable end. (IR 94-31) l 4

I 1

l 1

I 1

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. . _ _ ..._ _. ._ _ _. _. ._._. _ _ . _ ___ ~ _ __ ___ _ _ . _ _ - _

4

3. Engineering 9 Strengths e CORPORATE ENGINEERING SLA' PORT OF PLANT ACTIVITIES WAS A CONTIIRED STRENGTN.

- Recording the ssPS wulnerabtLity, The corporate engineering staff shound timely and appropriate resserch of the design beels by detemining the actual desipi status een the

' wulnerabiLity was presented by another utiL1ty. PsEAG mennessant acted promptty on the inforumtion presented by the engineere. IIanagement involvement and direction uns evident.

- Troubtenhooting uns planned, controtted, and documented. The anstyeis et failures uns 4

accurets, detailed, decimented, and technicetty sound, system enelneers provided accurate anstysle of the ssPs vulnerability. (It 95 G3)

- In 1988, the NRC foeund Generic Letter 88-05 pertelning to Reactor Need Leekase Detection Systes, dich uns in response to severet incidente d ere leaking reactor coolant caused significant corrosion problems. The central leeue of GL 88-05 (i.e., detection of boric j

ecid corroelen) has been estisfactority addressed through precocharet ordiencemente, plant wetkdouns by systam ensinserins personnet, and addltionet checks for borie acid accumuletten daring post outeos and at power containment inspections. (It 95-02) e ENGINEERING MAS INPROWED ITS SLPPORT OF DAY TO-DAY OPERATIONS j

- Reactor engineerine's provided high spaelity soport to operstlens een spandrent power tilt enceeded TS Limits. This ogport and thorough oneinserig evolustion were fowul to be timely and very detailed. Reactor engineerig's technical emportlee, and conservative i

eg port of operations contributed to safe plant performance. (IR 95-02) l

- The inspectors decimented recurring problems with Unit 1 SEC degraded peuer owpties and frespannt ATI test faults and opurious alarms in previous ire (96 31 & M 35). teille SEC test faults perslet et a frespannt periodicity, engineering uns fomd to be actively eneesed in monitoring and diaennelne system perfonmence. (la 95-02) l

- Inspectors identified of t Leeksee located circumferentially about the No. 23 and No. 24 RCP l

platforms. The Licensee actions to spanntify the amowit of oil teskaos were votid for

' determining the inventary lost sharing the test ported. The licensee's planned actions to i

redace ott teakage, closely monitor motor performance and ett teskage, and further evoluete motor structures for possible modification were appropriate. (la M 35) 1

- A system engineer noted that mechanical steam pipig penetration eres went panels were locked closed sich uns not law plant draulnes. The inspector observed the mobstructed vent penets and the increased security measures. Operations took prompt action to address TDAFW piap operability concorre. (IR M 35) i

- System engineerig identified a dooreded condition in the No.11 common distribution header for the No. 1 SW boy. The inspector noted system engineerine's thorough su piping inspection and prompt communication of concerns. The inspector observed operations' timely problem resolution and good safety perspective concerning SW operablLity. (It M-35) t

- The inspector noted a concerted effort by system engineering, planning, and operations to address control ele deficiencles. (IR M-35)

- Selen entended their outage to determine the cause of the teekage through the Unit 2 PZR j Code Safeties. Sales replaced the code safeties, adjusted the pipine, and successfully reached norant operatig pressure with no code safety seet ladman. (IR M-35) i j - The sWS operational performance inspection (SWs0PI) self assessesnt concluded that etl .

' elements of TI 2515/118, Rev.1, were setlefactority accomplished. (IR M 22) d 8 Weeknesses

• e gNGINEERING MAS NOT AGGRES$lVELY ADDRESSED NAGAN NGIULE CONFIIRAATION CONTROL PROBLENS. LICENSEE SCHEDULES REFLECT ONLY NINIleAL PROGRESS 70 RESOLVE THE Issue. (100 UPGRADES PER REFUEL QUTAGE WITN j 800 NORE IEEIlULES PER UNIT TO LPGRADE)

• Prebtems with IIS Atmospheric Rollef Vetwest 4

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+ The Licensee une inittetty stou to assemble the resources to evoluste the cause of the us10 volve  :

centret problems. They eventually ammtad a matti disciplinary team to examine the recent problems.

j nelntenance, design, eral refurblehment inedspecies caused the inittel 13mS10 felture.

• The tess's efforts occurred only after e Long history of problems ulth ps10 centroller l

deficiencies, that had ogspeeedly been corrected and resotwed prevleuely. (It 95-02) l 4

- The Licensee could not identify the root cause failure of a 15 volt peuer eseply ulthin the SsPs uhtch reeutted in a forced shutdaan althN Ts allaund outese tism. (IR 95-02, LER 95-4 01: Unit 13 e SYSTM ENGilEERING DID NOT ALWAYS AemESSIVELY MRM DIFFICULT ISEES. THEY WILLINGLY ACCEPTB TNE FIRST PLAtlSIBLE CAugE AS TNE ROOT CAueE FM PLANT PeWLEMB. PERFOWIANCE IN TNIS AREA CONTIMES 70 i BE suePECT ESPECIALLY SINCE SOUT CAUSE ANALYSIS PERFtWED BY SYSTEN ENGINEERING CXINTI8 RED TO BE WAK. meurNT ALSO FAILS TO EIPNASIS THE Ipp0RTANE OF Rie0RERJS ROOT CAUSE ANALYSIS FOR REQJRRilIG PROBLEMS. INCIDENT REPORTS RARELY 00NTAINED IELL 00m2ENTED ROOT CAUSE ANALYSIS. AS A RESULT, CORRECTIVE ACTIONS FOR MANY PLANT PROBLENS CONTIIRED TO BE INEFFECTIVE.

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- setem system continued to have problems identifying the root cause of worious problems.

? For the two esemples listed, the system engineering staff did not promptly identify, correct, notify appropriate levels of menessment, or Insure action to preclude recurrence

• 1 for the following conditions:

! An oil sample Laboratory report, dated August 4,19N, recommanded resampling and chanslew the oil en the no. 21 high head safety injection Isop bened upon a ten-fold incrosse in user M centration. An oil analyels, dated November 28,19M, identified high user

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j perWLe concentratten in the no. 22 high head eefety injection pump speed increamer ef t.

tm learch 20, 1995, the reopensible system engineer lesund E pipment Helfa ction i

Identificetten system (Ents) tage en the above cesponente identifying the degraded 1

conditlene. A lab report, dated October 6, 1996, recommended resa gting the no. 23 AFW turbine Lee ett due to a trace sammt of unter feed and a marked incrosse in user concentration particles. On nerch 27, 1995, the system ergineer lesund an EIIIS tag f

addressing this degraded conditlen. The lampacter noted that the engineer had Little er no documentation en the above prebtems other than the inittet tab reports and felled to l

j identify, or to ottempt to identify, the root cause of the user particles, se adopete

- corrective action ums not taken.

i Licensee Event Report (LER) 95 05 (dentified seven instances adiere the vendor identified j out of tolerance pressuriser code safety volves (PSVs) 6etpoints. The report stated that, between ney 8,1990 and January 14, 1995, the vender identified that the Psve did not aset the 11 tolerance restred by Technicet specificetten 4.0.5 reptrement for seten unit 1.

J The LER further stated that the four instances between Newester 14, 1996 and January 14, l 1995 each Identified that tuo of the instetted three PSVs did not meet the TS 4.0.5

. tolerance re yframent. In each case, the vender notified the appropriate system argineer j by telephone, and followed the telephone report ulth a written report. In ELL cases, solem pereennel informed by the vendor felled to initlete an Incident Report. As e result, PSE&G

' did not initlete timely root cause er reportablLity evolustions. (IR 95 07)

- Engineering centinued to demonstrate weaknesses in problem receptitlen and resolutf an by not perfernire and docusanting eefety swelustians in tus esperste instances. The licensee

felled to provide the beste for determinits that e degraded 1A 125vDC bettery cett no. 35 i

post seet did not constitute en unrevleund safety euestien (use), and the Licensee failed t to provide the beste for deteretning that une of a service Water intake eres exhaust fan motor in place of the re yfred no. 22 RNR room cooling motor did not constitute an Use.

(IR 95-07) i

- From the and of outage 2RT to the etert of 2RS, PSE84 had operated tmit 2 et peuer with an j m enetyred configuration sesociated with the P2R safety wolves since the Loop easte are t filled with unter. (IR 95 02) [EEI 50-272;311/95 02 023

- Engineering staff appeared to recognize the japortance of determining the root cause of epigment failures and other problems. Neuever, the p ollty of problem resolutions une wertable. In some cases, the root causes of problems more not identified and in other esamples mampacted system reopenses more not futty mdereteod and resolved prior to returning epipment to service. Atee, system oneinsering esqiport of operablLity

• determinations use inconsletent, and Indicated an week mderstanding a system's safety and doelen bases. (It 95 01) j 6-l i

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- Engineering failed to esgresolvely pursue SEC test faults generated prior to the January 6 stars. A more thorough root cause approach any have evolded the SEC reesired plant power redaction of January 6. NRC inspectors have continued to observe recurring ATI test feutts on both the 81A" and "1g* SEC since the January 6 forced power redaction. (It M-35)

- The orgineering staff worked to resolve nonconservetfees in the POPS setpoint calculations for appronlastely two years. In the process, PSEAG rolled on an exemption from the reestrements of 10 CFR 50.60 withwt NRC approvel, falted to report a condition outside their plants' design-bases, and revised the POPS design-basis transient without performing e safety evetustlen pursuant to 10 CFR 50.59. Several agonrent violations of NRC

! reestrements identified darltg this inspection are being considered for enforcement action.

4 The Licensee's calculattens for the revised POPS design-bests transient beve been referred l

to NRR for review and pending their evolustion, this espect of the leeue wlLL t,e ,

mresolved. (IR M-32) (EEI 53-311;272/96 321, 2, 3 & 41 l

- A grees intrusion into thit i resulted in a power redaction and provided a mild challenge to service water operation. CW probleme (press intrvolon, inoperable circulating water '

pumps, and stuck trash rekes) continue to lepose chattenges to the operators. Although the prese intrumlen into the SW intake structure did not signifIcently effect system operation, the potentist effect of grose on the SWS continues as a chelteres to norant plant operation. (It M 31)

- The Licensee failed to take timely and comprehensive corrective action for Westinghouse identified doelen vulnerablLity ese to inadassate margin for the PZR overpressure protection (POPS) daring Low temperature conditions. Unit 1 determined that several reellstic assumption could place the mit outside the design /ticonsing basis for POPS enstysfo should a SI signet occur. (LER M -17: Unlt 1) o STSTEMIC P90 GLENS WITN TNE ISSUANCE OF PARTS Am SUPPLIES CONTINLES TO CAUSE INSTALLATION ERRORS Am OtNER PRWLENS.

- Parts controls were insufficient to ensure that the proper reactor heed vent meterlet, parts, and components were installed. Felture to take adequate corrective actions rotative to the identification of non-spellffed timit switches on the safety related reactor head ,

vent vetwee was en apperent vlotetton of TS. (It 95 02) [EEI 50 272;311/95 02-03]

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4. Plant support I t. mediatten cantent

' # Strengths e SALEN'S RADIATION PROTECTION COWERAM DLRING BOTN OPERATIONAL Am EXITAGE PIANT ACTIVITIES W48

' STRONG. Gots C00mlNATION WITN OTNER DEPARTIENTS W48 NOTED.

- White perforslag many significant plant maintenance activities within RCA. The RP, maintenance, and ergineering staff contirmand to effectively control and Limit worker espesure to redletion. (IR M 35) 1

- The RP staff monitored, centrotted, and annaged persomet exposure to be ALARA. Plant radiological conditions were maintained appropriately. Radiation and contamination areas were observed to be posted and controtted. (It 96 31) 1.

- Throughout the eutage, RP staff worked effectively with plant operations, engineering, and maintenance persomet to esaure that jobs were adespantely ptarmed, monitored, and controtted. (IR M 31)

! - The licensee provided effective NP coverage and provided very good ALARA controls daring the Setem Unit 2 outage. (IR 96 30) i

- The redf ological occurrence reports for 19% were few in nwher and generally of low safety

< significance. No safety concerns or vlotations of respJirements were observed. (IR 96 30) e -NT OWER$1GNT OF RADIATION EXNITROL WAS EFFECTIVE. SALEN NAD STRONG RADIATION EXNITROL PROGRAN f Am EFFECTIVE ALARA PROGRAM. ,

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! - RP management maintained overalsht of performance indiceters and kept eenfor stetten

managers advloed of status of radiological conditions. (IR 96 31)

- Two ALARA initletivos that were noteworthy included the field testing of a prototype j

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$ robotic are for steem generator platform og port activittee and the leptementation of an Eddy Current (EC) cable cleaner to enhance contaminetton controts during EC inspection l

4 octivities. (IR 96 30) a

- The ALARA tracking program was effective, but could be f eroved if exposures were also

! tracked with respect to work completion as is tracked charing outage status meetings. (IR l l 96 30)  ;

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- The ALARA shletdlng efforts were extensive, but were generetty based on dose rate redJction and not on an area's collective dose beels. (la 96 30) i - The use of remote MP work stations has resulted in a rechaced MP presence in the work eroe and, in some Instances, a workforce that was not etweye observed maximizing the ALARA ,

' potentlet in the work eroes. (IR 96 30) l

- Within the eroes irripected, Excellent leptementation of redienctive Liquid and gaseous effluent centrol programs performed by the Chemistry Department was observed. The licensee i has an acceptable program for callbrating redletion monitors. (la 94-28)

- Setem's Solid Redweste Processing and Radioactive Noteriet Transportetlen Program were of 1 pood cp mLity. (IR 96 20) 9 Weeknesses e ONLT MINOR EVENTS OCORRED IN AN OTHERWISE STRONG RADIAT10N CONTROL PROGRAM.

- Operators felled to collect grab samples of the Weste Gas Decay Tank (WmT) on Lmit 2 as respJired try TS. Ne violation was cited since the licensee took leadiate corrective action j to estabileh the semple flogeth and sampled the WST for oxygen, and initleted long-ters

corrective actions that re emphaelsed management's espectations regarding review of off-normal reports. (IR 95 02, LER 96 15

Unit 2)

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i - The Licensee fourut a contaminated wrench used outside RCA. (It 94 35)

II. Emeraency Frenereshone (EP) 99 Strengths & Weaknesses e EP PROGRAM Am EMERCISE PERFORENE MS 0013.

- The licensee doctored an unuount Event (UE) for both units due to a low water level in the Delamere River. The licensee's primary concern uns the continued eporebility of the SWB dJe to SW pnmp NPSN re wirements. The licensee's actlens and notifications more prompt and appropriate. (la 95-02)

- . The inspector revisued PsEM's conformance with 10 CFR 50.47 regarding laptementation of the energency plan and precedares. In additlen, the inspector revleued Licensee event notifications and reportfre respairements per 10 CFR 50.72 and 73. (IR M-35)

- The ensite response to the accident scenarie dartre EP esercise was good. There were no EP esercise strengths or weeknesses, but three areas for potentist leprovement were noted. No safety cancerns or vlotettens of. regulatory regairements were observed. (IR 96-Z3) 111. t=~*fty G Strengths e SALEN'S RASIC SEORITT Am SAFERMEDS PROGRAN ES StM S.

- The inspectors verified PSE&G's confoneance with the security program, including the adecpancy of staf fing, entry control, etere stations, and physical botaderlos. Inspectors observed good performance by Security Departoont personnet in their condact of routine activittee. (la 96 35)

- Inspectors observed good performance by security Department personnet in their conduct of routine activities. Security personnet maintelnad positive control of sa twe to the plant and controlled erees, though cheltenged by increased raabers of personr* esite to stoport outage activittee. (It 96 31)

- PSE&G had in place effective programs for feptementation of your safeguards program. No safety concerns or vlotettons of regulatory respJirements were observed. (IR 96 34)

- No safety frW-les or vlotettons of regulatory regaframents were identified. (IR 94-25) 9 Weeknesses e ASSESSIENT AID PERFORENCE IS DEGRADING. NRC INTERVENTION IIAS BEEN NEESSART TO ENSURE TNAT ADERAATE LPMADING 6148 PLANNED.

- Assessment old esing is a continuing potentist problem. A6erence to the licensee's schedule for Legrading essessment sids 18 leportant to assuring continued overall Wey of the essessment flmction. Package searches remains open pending further evaluetion of the adecpancy of package searches daring periods of high traffic.

IV. Fire Protection (FP1 and Mounakeenine 9 Strengthe e EXCEPT FM CERTAlle APPEleIX *R* ConCERIls Ale StBE SCAFFOLDIIIG PtogLEIIS, THE LICENSEE IMPLEIENTED A GOgg ureascrFEPIIIG AIS FP PROMAN.

• The inspector revleued PSE&G's FP program leptementation f.e.w nucteer department edelnistrative procedares fo6md no discrepancies. (IR 94 35)

- The Inspector revleued PSE&G's housekeeping conditlens and cleanliness controts i.e.w.

nucteer department edelnistrative procedures and found no discrepencies.

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I 9 Weaknesses e OIL LEAKAE OBSERVED Fatst RCPs, A 10 CFR APPEWlX "R" FIRE M2ARD, WAS NOT INITIALLY ADDRESSED IN A TIIELY MmMER Bf LICENSEE MMANGEMNT. SCAFFOLDING PROBLENS CONTINUED.

- On April 26, scaffolding instetted in the vicinity' of the no.12 aistillery feechseter samp (AFP) and the roam coster for the Setem mit 1 meter drlwen AFPs did not have the reyfred clearance, crees bracing, restreints, or vertence approvet, and, en May 1, scaffolding i

eremd the Setem Unit 2 centelrument fan coeter mit service unter pipfre uns not removed in

e tiesty omnner following completion of the work en January 25, 1995. (la 95-07)

- The inspector noted saamples of Setem's failure to adspotely control scaffolding in oefety-related erees. The inspector abeerved minor deficiencies recording ads p ote clearances, preper restreints, vertence inspections, and timely removet. The inspector noted the operating shifts' timely response in addressing the deficiencies. The inspector did not observe any discrepancies that directly lupacted or threatened nucteer safety presently. (la 95-02)

- The Inspectors feed that an olt collection system had been generetty designed and

fnetelled to collect eit from reacter coolant pumps en imit 2 as described in 10 CFR Part 50, Appendix R, Section III.O. Neuever, a concern uns identified recordire the lack of a collection device for a certeln plugs and flerges en the RCPs. A PSE&G evolustion did not consider these Locations to be credible teekage sites. Inittetty, licensee annagement did not paavlde timely resolution. A project team uns planned to revleu the (sous en a long 4 ters bes's. (IR 96 33) j

v. SELF-ASSESSENT Am ERLITY WERIFicATIM l

e SALEN MANAGEIENT CONTIIRJED TO MVE EXTRANDINART DIFFIOJLTY DISCMAGIIIS THEIR SAFETY RESPONSIBILITIES OW TO TNE ARRIVAL RATE OF NEW PROBLENS, THE BAOCLOG OF PROBLENS TNAT WRE NEVER j ADEeuATELY ADDRESSED, Am TilEIR ClRI INALILITY TO DEVELOP A SWSTIONIIIG ATTITWE TMT SUFFICIENTLY j 6

CNALLENGED CONTINUED LEAK STAFF PERFORMNCE.

- Senior manneement estabilehes espectations for performance et Selen. During the inspectlen i

! period, Setem eenler management placed censiderable emphasis on leprevfre perforumnce in i the areas of plannfre, owent free sporetien, maintenance and surwelltence, and en ounerehlp i and acco mtability. The Selen Statf an Operating Revleu Cammittee (80RC) and the senior j amnegers, houewer, did not systematically and rigorously esamine the potential eefety a

lapset of degraded canditions and planned activities brought to the SORC and the annagers' meetirg. Senter menessment identified inademaste plannire, but did not censletantly l

identify the nature of the Insdepacies or provide a clear picture of the Santitles

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necessary for adespante planning. In addltlan, SORC did not adogantely reviou 10 CFR 50.59 i

safety evolustions er reportable events. The members of 80RC did not have a fmdumental mderstanding of 10 CFR 50.59 er NSAC 125, nor did they understand the purpose for revleutre reportable events.

1 The inspectors concluded that Setem eenfor mannesment had not established standards or espectattens for nucteer safety perfonmence for itself or for SORC. As a result, the l senior mensomment team could not monitor its e m eefety performance. The Inspectors eteo concluded that the incenststent spaelity of plaresing, LEte, and 10 CFR 50.59 applicability I revleus and safety swelustions reeutted from Lack of clearly defined standards for j performance. (IR 95 07)

- P1EAG generally operated the Selen mits esfety. However, the continued annifestation of recurrire espalpment problems and ineffective corrective action indicate that PSE&G has not

! yet achieved any significant laprovement in overalt perforumnce. The Licensee's failure to 4

implement measures (procockares, directions, or draulnes) to esaure proper confleurotion folloulre the oefety retlef volve loop seel endification charing 2RT demonstrates weakness j in work controls. (It 95 02) >

j - The roepense to the recurrire problems with the main steam atmospheric relief valves (NS-10s) demonstrated recurrence of previously documented week inittet root cause

investigation. As has else been the case in the post, in response to NRC gaestions and management recopiltion of the lepect of the NS 10 problems, the Licensee canaiselened a d

inalti disciplinary team to perfore a comprehenstwo engineering Investigation of the cause 3

ef contlemand NS10 reliablLity problems. laille such effort is considered a pooltive step in d ettemptire to resolve thle tone-standfre leeue, the Licensee supposed that this item uns 4 . 1o.

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i previously resolved as a result of tro steohootine and ensincerine efforts following the April 7, 1996 trip. (IR 95-02)

- Sales currently has l' open ettesettons. Eloht of the open ellegations have either DOL or of cases open en them, see have both. Three of these ettesettons are related to or reeutted from a Deca d or 3, 1992 ottercation between two SRG enginsors and the previous j Generet manneer (en), operations noneser (0M), and, to a lesser extent, the noneser-eustity Assurance & uucteer Sofety Reviou (GAkst). O! substantiated heressment and intimidation 4

(NSI) in thle case. Another alenificant etteestion uns generated by a terminated empteyse

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and pertelnad to 23 separate menessment, operstlans, and engineerite concerns. These were i presented to NRC pereennel in a face to face meeting an August 8, 1996. the additlenal etteestion involved both technicet (Ee) leaues and potentist NAI feeums. Currently, the Ee

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issues are beine revleued by DRS and the uransdelag leeums are belne reviewed by 01. This 1

atteestion else involved are tereinsted engineer. The NRC received this attesation from senior PsEAG menessment.

j asserdine ellesettons, Setem has had a rusher of attegotions that tapticate the previous statlan mannessent's ablLity to pereenelly resolve and addrene oefety leaues. Recording the December 1992 ettercation, enforcement action uns taken soninst the licensee (SL II, 80K CP) with letters of reprimand meelnet the individuals. This incident and the two related attesettons appear to be das to menaeament's confrentational attitude with GAkst pereennel. Since these manneers have been replaced, this concerti appears to have dioelpeted. The Ee atteestion and its 01 camponent, and the S/96 elleestion appear to sten 4

from o tendency of PsE&G to menese by mome. They are not effectively using their root cause progress. Kanessment's failure to identify and remotve root causes une e direct j eentributor to these two alteestions. This is a continuftg concern. (aa==mt of attesettons) a

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INSPECTION R8 PORTS INC'LUMD IN THE SAEAM KPPR (11/6/94 - 5/20/95)

'Inspectlen Report We ~ .-Inspectfen totes : ~Bnspector i M 21 9/12 9/16 & Demsey / Coleccino 10/19 - 10/21 M 22 9/08 - 10/14 Drysdale / noy / Melur 94 23 10/24 - 10/26 Leuchtin & othere 94 24 9/18 11/05 Marschett 8 others M 25 9/12 - 9/16 Lieroth / Dette Rette

% 26 10/17 - 11/01 Prividy 4 others 94 27 9/26 10/07 cetwert / moy 9m 10/17 - 10/21 Peluso i

N-29 11/07 11/18 Boardstee 94 30 10/24 - 11/02 Nosele 94 31 11/06 - 12/17 marschett 8 othere M-32 12/05 12/19 & McDerimett 3/14 15/95 M 33 11/30 - 12/02 & Norrisen / Morris 12/07 - 12/09 &

12/12 - 12/16 94 34 12/12 - 12/15 Llmroth / smith 94 35 12/18 - 1/28/95 Norschell & others 95 01 1/12 1/20 Schott & others 95 02 1/29 3/22 Merechett 8 others 95 03 2/04 - 2/17 calvert / Trapp rate As\sALIN8P.TBL 1

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LICENSEE EVENT REJ' ORTS (LERs) INCLUMD IN THE SALEM EPPR 1 (11/6/94 - 5/20/95) i j tuntt 1) i l LES Ilo. Event Dete i Title-M 15 10/18/M RWst volume tevet tese than rossired

) M 16 11/16/M Non-complfence with control room 380 manning requirement i

. M 17 11/17/M Inadopete eersin for PZR overpressure protectfon daring low 1

temperature conditfone H

$ M 18 12/09/M Desfon beste concern das to inoperability of 1A SEC cabinet and

ede-mt TS 3.0.3 entry due to (noserability cf 1A and 18 SEco i

I 95 01 2/01/95 TS 3.0.3 entry; Both treino of the $$PS belns inoperable J 95 02 2/24/95 Felture to restore automatic control of P2R Potv IPR 2 or close j essociated block valve 1PRT ulthin 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> i

4 95 03 2/28/95 Four planned is 3.0.3 entries to sagsport correction of Analog Red poeltlen Indication system drif t effectins rode 2SA1, 2SA4 and 2sA2 J

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LER us. Event pote Title l

i' M 12 Catorfmetric calculottens not perforised within the specified 10/13/96

survelttence intervet on both Unite 4

M-13 10/23/M Core alteretton and fust movement without contelnment building

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i closure darins refuellns outese 2R8 M 14 11/18/M ESF octuottons blackout sienet toeding of 25 and 2C 4kV vitet buses j 94 15 12/20/M The Weste Gas Nolde system was not samsted IAW Ts l M 16 12/26/96 urplanned is 3.0.3 entry due to inoperability of Nigh steen Flow / Low T Si above M5'F reactor coolant temperature and felture to take action regired due to inoperability of 24 Loop Rx coolant reefstance 4

temperature device 95 01 2/12/95 seenuelty Initiated Esf actuation to effect a les fooletion signsL in

order to incrosse RCS T . above M1*F f 95 02 3/11/95 Three planned is 3.0.3 entries to support Analog Rod Poeftfon

! IndicetIon eyetem delft offeetIns rode 2884 and 1M l

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REGION I l PLANT STATUS REPORT FACILITY: Salem Nuclear Generating Station Units I and 2 I

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l I. BACKGROUND I II. PLANT PERFDRMANCE DATA III. ANALYSIS / ASSESSMENT IV. INSPECTION PROGRAM STATUS j V. ATTACIIMERTS l 1

Last Update: March 22,1994 Update Approval:

Branch Chief Update Approval:

Section Chief CIIANGES SINCE TIIE LAST UPDATE ARE DEMARCATED IN TIIE BORDER The a e ic. not disseminate or discuss its contents outside NRC. nat t '

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• ATTACIIMENT A CONTENTS I. BACKGROUND

1. Licensee Parameters

2. NRC Organization

3. Licensee Organization

4. Operator Licensing II. PLANT PERFORMANCE DATA l 1. Current Operating Status (last 6 months) l 2. Recent Significant Operating Events and Identified l Safety Concerns (of last 12 months) l 3. Escalated Enforcement Activities (oflast 2 years) l 4. IPE Insights III. ANALYSIS / ASSESSMENT l 1. Previous SALP Ratings and Overview l 2. Licensee Response to Previous SALP Functional Area Weaknesses /Recent l Licensee Performance Trends (in the last year) l 3. Licensee Performance Strengths and Weaknesses l 4. NRC Team Inspections Within the Last Year 1 5. Planned Team Inspections IV. INSPECTION PROGRAM STATUS l 1. Status of Inspections (see attached MIPS Report #2) l 2. Proposed Changes to MIP l 3. Significant Allegations and Investigations l 4. Open Item Status 1 5. Outstanding Licensing Issues l 6. Local / State /ExternalIssues V. A'ITACHMENTS (NOTE: To be deterinined based on intended audience)

1. AEOD Performance Indicators /LER Summary O

2. Allegations Status O

3. Most recent SALP Report O

4. MIPS Report Nos. 2 & 22 0

5. Principal Staff Resumes (NRC and Licensee) O

6. Planned vs. Completed Inspection Hours O Salem PSR Page I

I. BACKGROUND

1. LICENSEE PARAMETERS Utility: Public Service Electric & Gas Company (PSE&G)

Company location: Hancocks Bridge, NJ (18 miles Southeast of Wilmington, DE)

County: Salem UNIT 1 UNIT 2 Docket No: 50-272 50-311 CP Issued: September 25,1968 September 25,1968 Operating License Issued: April 6,1977 May 19,1981 Initial Criticality: December 11, 1976 August 2,1980 Elec. Ener.1st Gener: December 19, 1976 May 29,1981 Commercial Operation: June 30,1977 October 13, 1981 Reactor Type: PWR 4-Imop Same Containment Type: Large dry Same Power 12 vel: 3411 MWt Same Architect / Engineer: PSE&G/UE&C Same NSSS Vendor: Westinghouse Same Constructor: PSE&G/UE&C Same Turbine Supplier: Westinghouse Westinghouse (GE Generator)

Condenser Cooling Method: Once-through Same Condenser Cooling Water: Delaware River Same

2. NRC ORGANIZATION NRC Regional Administrator: Thomas T. Martin (Tel: 610-337-5000)

(Region I, King of Prussia, PA)

Division of Reactor Projects: Richard Cooper, Jr., Division Directer (Region I) (Tel: 8-610-337.5229)

Wayne Lanning, Deputy Director (Tel: 8-610-337-5126)

Edward C. Wenzinger, Branch Chief (Tel: 8-610-337-5225)

John R. White, Section Chief (Tel: 8-610-337-5114)

Salem PSR .

Page 2

, NRC ORGANIZATION Continued:

Senior Resident inspector: Charles S. Marschall (Tel: 8-609-935-3850)

Resident inspector: Stephen T. Barr (Tel: 8-609-935-3850)

Resident Inspector: Joseph G. Schoppy, Jr. (Tel: 8-609-935-3850)

Resident Inspector: Todd H. Fish (Tel: 8-609-935-3850)

Project Engineer: Robert J. Summers (Tel: 8-610-337-5189)

Project Manager: James C. Stone, NRR (Tel: 8-301-504-1419)

3. LICENSEE ORGANIZATION Management Personnel:

E. James Ferland -Chairman and Chief Executive Officer 12wrence R. Codey -President and Chief Operating Officer Robert J. Dougherty -Senior Vice President, Electric Steven E. Miltenberger -Vice President and Chief Nuclear Officer Stanley LaBruna -Vice President, Nuclear Engineering Joseph Hagan -Vice President Operations and General Manager Salem Operations ,

Richard N. Swanson -General Manager, Quality Assurance and Nuclear l I

Safety Review Lynn K. Miller -General Manager, Nuclear Operations Support Francis X. Thomson -Licensing Manager Lee Catalfomo -Operations Manager l Michael P. Morroni -Manager, Maintenance-Controls Arthur Orticelle -Manager, Maintenance-Mechanical John W. Morrison -Technical Manager Terry L. Cellmer -Radiation Protection / Chemistry Manager Richard T. Griffith, Sr. -Station QA Manager G. Charles Munzenmaier -Manager, Salem Station Planning Peter Moeller -Manager, Site Protection Greg Mecchi -Manager, Nuclear Training Christopher Connor -General Manager, Nuclear Support and Services Workshifts 5 operations shifts,2 working 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts / day, I relief crew, I crew in training, I crew off.

Shift Comolement: TS minimum Actual 3 SRO 4 SRO 4 RO 5 RO 1STA 1 STA (dual role SRO)

Non-licensed Operators 5 7 or 8 Salem PSR Page 3

Maintenance Electrician /I&C 1 2 Chemistry / Rad. Prot. 1 2 Fire Brigade 5 6 (site fire brigade shared with Hope Creek)

4. OPERATOR LICENSING l a. Licensed Reactor Operators (Licenses Cover Both Unitsk l

l

• Total number of active SROs: 29 l

• Total number of active ROs: 26 l

• Total number of certified instructors: 13 l

l

• In June 1993, NRC performed TI 117, " Licensed Operator Requalification l Program Evaluation"; results were satisfactory.

l l

• One simulator (modeled after Unit 2) located at the training facility in Salem, l NJ, and used for Unit 1 and Unit 2 operator training and NRC administered ,

l licensing exams. PSE&G completed a major modeling upgrade package in the l summer of 1993. I l

I l b. Other Licensed Ooerator Trainine / Performance / Staffine Concerns:

l l

l

• Shift Supervisors began working 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts during refuel outages l conducted in the spring and summer of 1992, formally implementing that l schedule in November 1992. The remainder of the shift complement j l maintained 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shifts until April 1992, when, upon a union vote, they also )

l adopted the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shirts for a 1 year trial basis. The reactor operators and l l equipment operators will be voting again in April 1993 as whether to l permanently stay on 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts.

l i

1 1

1 \

Salem PSR Page 4

II. PLANT PERFORMANCE DATA

1. CURRENT OPERATING STATUS (for period 10/1/93 to 3/1/94)

PSE&G shut down Unit i en October 1,1993, to commence a 72 day refueling and maintenance outage. Prior to the shutdown, the unit had been on line since July 15,1993, and operating at or near full power. Plant management extended the outage completion date (originally scheduled for December 17) because of emergency diesel generator (EDG) operability concerns. On December 2,1993, a cracked cylinder liner in a Unit 2 EDG raised generic operability concerns for Unit 1 No. IB EDG because of the similar liners installed in No. IB. Operators restarted the unit on January 24; it automatically tripped from 100% power, on January 27 in response to a low <

water level condition in No.14 steam generator. Operators restarted the unit on January 31, and operated the unit at power until it automatically tripped, from 100% power, in response to a loss of control power to the main turbine control system. PSE&G rewarted the unit February 13, synchronized to the grid February 20, and has operated the unit at or near power through the end of the month. ,

PSE&G operated Unit 2 at or near full power throughout the fall, until December 3,1993, when operators shut down the unit due to failure of a cylinder liner in the 2C EDG. After completion of repairs to the EDG, operators restarted the unit on January 3,1994, and operated at full power until January 19, when the reactor engineering staff discovered that PSE&G had apparently operated Unit 2 in excess of 3411 megawatts (thermal). Since then, and through February, operators have maintained Unit 2 at 95% power.

2. RECENT SIGNIFICANT OPERATING EVENTS AND IDENTIFIED SAFETY CONCERNS I

a. Sienificant Events (oflast 12 months) l

• Unit I automatically tripped on February 10,1994, from 99% power, in l response to a loss of 15 VDC power to the main turbine control system. The l plant stabilized at normal operating pressure and temperature. PSE&G l determined that the 15 VDC power supplies had tripped when their protective l relays sensul an over-voltage condition. (See IR 50-272/94-01)

I l l

• Unit 1 automatically tripped on January 27,1994, from 10% power, in '

l response to a low water level condition in No.14 steam generator. The cause l of the trip was a level error controller in the control circuit for No.14 steam l generator feedwater regulating valve, which caused generator water level l control to malfunction in the tuto position. This malfunction generated the l low water level condition and subsequent reactor trip. (See IR 50-272/94-01)

Salem PSR Page 5

l

• Operators shut down Unit 2 on December 3,1993, from 100% power, due to j failure of a cylinder liner in 2C emergency diesel generator (EDG). PSE&G l conservatively determined they had a basis for concern about the particular l liner's reliability and consequently declared Unit 1 EDG IB inoperable as

. l well, since the IB diesel had similar liners installed. (See IR 50-311/93-27) l l

• On November 2,1993, operators declared an Unusual Event (UE) in response l to a fire in a 230 volt lighting transformer in the Unit 2 turbine building. The l fire brigade responded to the scene and extinguished the fire. The station was  ;

~

, l in the UE for approximately one hour. A loose electrical connection caused l the fire. No personnel were injured and no safety-related equipment was l affected. (See IR 50-311/93-23) l

< l

• On October 13,1993, operators declared an UE in response to a fire in the

, l Unit i No.12 service water piping penetration bay. The shift supervisor l notified PSE&G Fire Department, which responded to the scene and l extinguished the fire. The station was in the UE for about 50 minutes. The l fire was caused by sparks from a grinding activity, which ignited insulation l from service water piping. Three contractor employees were treated for

, l smoke inhalation; no equipment sustained damage. (See IR 50-272/93-21) l 4

l

• On August 24,1993, operators initiated a Technical Specification-required shutdown of Unit 1 in response to a degraded voltage on a cell in the IC 125 l

l '

l volt battery. The need to shut down was relieved when the NRC exercised l enforcement discretion in response to the licensee's request and associated i l justification. (See IR 50-272/93-20) l

,. 1 i

l

• On July 11,1993, while the repairs to a faulty Unit I feedwater isolation j protection relay were being performed, the main feedwater regulating valve for l the No.14 steam generator inadvertently went closed at 8:38 p.m., resulting i l in the water level in that steam generator dropping to a level sufficient to l cause an automatic reactor trip. The licensee determined that the technician l l who was repairing the SSPS relay lifted an improper lead and caused the l l isolation of the No.14 steam generator. The licensee additionally determined 1 l the root cause of the technician's error was inadequate detail and direction in l the SSPS troubleshooting plan. Subsequent to the cause determination of the l trip, PSE&G repaired the SSPS and commenced a reactor startup on July 15, l 1993. The unit was returned to service on July 16,1993. (See IR 50-l 272/93-19) i I

l

• On July 10,1993, toxic gas release (ammonia) in the Unit I turbine building l caused by a loop seal failure on the ammonia hydroxide storage tank due to l l overpressure. This apparently resulted from excessive ambient temperature )

l conditions. The licensee will change the concentration of the ammonia l hydroxide in the tank to increase the boiling point of the solution to prevent j

~

l recurrence. (See IR 50-272/93-19) l l

• On June 8,1993, Unit I automatically tripped following massive intrusion of Salem PSR Page 6

.~ l sea-grass into the circulating water system suction. Four of five operating

l. circulating water pumps tripped, causing a loss of main condenser vacuum, l turbine trip, and subsequent reactor trip. (See IR 50-272/93-19)  :

l I

l e On May 28,1993, Unit 2 was manually tripped by the operators per abnormal  !

l operating procedures when control bank "C", group I control rods (four rods [

l total) fell into the core during reactor start up operations. At the time the i l operators were diluting the RCS to criticality for post-refueling startup. A l i

l card failure was attributed to a degraded solder trace in the rod control system, l which led to the event. (See IR 50-311/93-81)  ;

i I

l e On March 16,1993, Unit 2 automatically tripped from 100% power due to a >

l low-low level condition on the No. 24 steam generator. A failed pressure l l control switch in the condensate polishing system led to a low suction pressure j l condition for the No. 22 steam generator feed pump and subsequent feed pump t trip, which caused the steam generator low level reactor trip. (See IR 50-  ;

l 311/93-08)  ;

l I

b. Performance Indicator Data Units 1 and Unit 2:

o Performance indicators generally show good performance. Capacity factor ,

numbers were low for 1993 due to back-to-back outages of Unit I and Unit 2 i and shutdowns for potentially generic safety issues such as rod control and  !

diesel generator cylinder liners. No other significant trends are evident in the statistical analysis.

1 I

l c. Recently Identified Technical Safety and Managerial Challennes l i

l (oflast 12 months)

I l

• Four resident inspectors are permanently assigned to Artificial Island (Salem l and Hope Creek).

I l e The NRC Resident Office continues to monitor and evaluate the licensee's l

l efforts to improve plant material condition, repair and replace service water l piping, upgrade the RMS system, complete actions relative to Appendix R )

l requirements, issues associated with fire watches and security guards,  !

l personnel error reduction efforts, and procedure quality and compliance l improvement efforts. i l

J e Reviews were conducted and are planned for erosion / corrosion program.  ;

I l e Service Water (SW) 12aks: Numerous SW through wall leaks continue to j l occur due to erosion and microbiologic induced corrosion attack of carbon ,

steel piping. The licensee has a seven year pipe replacement project that will I l

l replace 95% (about 19,000 linear feet are safety related) of the safety related ,

l Salem PSR Page 7 l

1 i

• l SW piping with 6% moly stainless steel. This project will continue through ,

1 1995 (two more refueling outages per unit). Currently, approximately 90% of ,

j -l the safety related portion of the project has been completed, including the t

l majority of the SW piping in containment. Based on NRC inspection, SW  !

i pipe replacement project is progressing satisfactorily as scheduled. {

! l

. l

• Radiation Monitoring System (RMS) Problems: RMS problems have resulted l: l in numerous ESF actuations and reportable events. Short term corrective

l actions were completed on both Unit 2 and Unit I during the 1992 refueling

] l outages. These changes include electronic upgrades and a new uninterruptible l

! l I power supply. Longer term actions (1993-4) include a complete system  ;

j  ! upgrade. Based on NRC inspection, the upgraded RMS operation to date has j l been satisfactory.

i I l j l

• Failure of Overhead Annunciators: On December 13,1992, a Unit 2 operator >

i l

discovered that the overhead annunciators had not been updating alarms for l

I about i 1/2 hours. This was the result of a member of the operating shift -

-l entering a keystroke combination into a remote control workstation that, when  !

. I input through the wrong system port, prevented the system from updating  :

l alarms. An AIT was dispatched to the site and concluded: (1) the root cause l

I j l was a failure to follow procedure for proper operation of the overhead i l annunciator system; (2) the design of the OHA system permitted the operator '

j l to inadvertently emulate the password-protected software without warning.

I

l

• Rod Control System: On May 27,1993 Unit 2 operators experienced several i l problems with the rod control system. The most significant event was that i l during an attempt to insert Shutdown Bank "A", one control rod actually 3

l withdrew 15 steps'of travel. An AIT was dispatched to the site and j l concluded: (1) the root cause was an introduction of static charges into the ,

l solid state electronic components which caused system damage; (2) damage

! l. was also caused by voltage spikes originating from "back EMF" in the I system's electro-mechanical step counters (the suppression diode installed to l mitigate this previously-known phenomenon was disabled due to a failed pin ,

connector on the affected circuit card).  !

i l I

l At 5:12 p.m. on July 18,1993, Salem Unit 2 Control Bank D (8 control rods) l l began stepping inward at a rate of 72 steps per minute, but only moved a few j l steps before being detected by operators. At the time, Unit 2 was at 100%

• i l power with the control rods in automatic. The operator, finding no apparent

, l cause for the rod insertion, positioned the rods in manual control, which l I stopped the rod movement. The operators performed all actions per their '

l l l abnormal rod movement procedure (AB-ROD-0003) and were still unable to

] l positively identify the cause. The licensee installed monitoring instrumentation g l on the inputs to the automatic rod control signal summator and at 11:40 p.m.

8 l on July 18, returned rod control to automatic. l l l l At i1:24 a.m. on July 21,1993, the. licensee again experienced the same l phenomenon on Unit 2. As in the previous occurrence, the operator quickly 1 4 Salem PSR Page 8 1

4

, - - - - . - *~- , . - - - - _ _ _ _ _ _ . _ _ _ _ _ _ _ - _

l evaluated the situation and appropriately placed the rods in manual control. In l both cases the rods only moved inward a few steps (2 and 4 steps

] respectively). Current traces on the signal summator input revealed no change l from the nuclear instrument (NI) or turbine impulse pressure, but some spiking l from the average temperature (Tave) and reference temperature (T ref) input.

l Together these four signals are the input signals to the automatic rod control l system. On July 21, the licensee placed additional monitoring instrumentation l on the output of the signal summator, output of the " rod in output" signal l comparator, and individually on all four Tave channels.

l l On July 22,1993, during I&C troubleshooting, the licensee was able to I identify a fault in the signal summator, which erroneously produced a high rod I inward demand output for a relatively small temperature error input.

l l e Switchyard Modifications: During the recent outage on Unit 1, PSE&G l implemented an extensive design change package involving modifications to l the Salem switchyard. These modifications increased voltage recovery on vital l and group buses during bus transfers, provided load growth capacity, removed l the Salem circulating water system pump motor feeds from the Hope Creek l switchyard, improved voltages in both Salem plants, provided margin for short l circuit capability, and improved plant reliability. Major components added l included two 500/13.8 kv transformers, four 13.8/4.16 kv transformers, four l 13.8 kv breakers, and 4.16 kv switchgear for the circulating water system bus.

I l

• Unit 2 Sustained Operation of Greater Than 100% Power: Suspected root -

l cause is erosion of the feedwater flow nozzles resulting in i- wect online I calorimetric data. Upon discovery, licensee immediately r.J wd power for l both units, and began adjusting instrument setpoints to insure conservative l operation. Licensee is pursuing determination of the exact power level and the l effects on the UFSAR Chapter XV analyses. They expect resolution by mid-l April 1994.

l l

• Emergency Diesel Generator Cylinder Liner: This caused Salem 2 to shut l down as a result of a cracked liner, and delayed Salem 1 to delay startup from I the refueling outage. The licensee could not find a clear root cause. The l suspected root cause was dimensional tolerance problems with liners l distributed by Canadian Allied Diesels. PSE&G determined that only two l liners have ever failed, including the Salem liner, in a population of tens of l thousands of liners in use world wide (including locomotives and ships).

3. ESCALATED ENFORCEMENT ACTIVITIES

• The NRC issued a Level III Violation on March 8,1994, documented in NRC Inspection Report 50-272 and 311/93-23; 50-354/93-25. The violation was based on multiple examples of PSE&G's failure to follow procedures and their failure to properly control safety-related activities.

Salem PSR Page 9

l

. 4. IPE INSIGIITS 1

l

• The Salem IPE was submitted to the NRC in July 1993, and is still under l NRC review.

l l

1 l

l l

l Salem PSR Page 10

III. ANALYSIS / ASSESSMENT

, 1. PREVIOUS SALP RATINGS AND OVERVIEW

a. Previous SALP Ratings l

l Functional Area December 28.1991 June 19.1993 l

l Operations 2 2 l

l Maintenance /

l Surveillance 2 2 l

l Radeon 2, Imp 1 l Emergency Preparedness 1 1, Declining l Security 1 1 I

l SA/QV 2 2 l

l Engineering & TS 2 2 l

l l

l Current assessment period: June 20,1993 to December 10,1994.

b. SALP Overview (derived from the summary caragraoh of each SALP sectionh OPERATIONS On July 29,1993, the SALP board met to discuss PSE&G's performance at Salem during the period from December 29,1991 to June 19, 1993. The board concluded that the licensee had operated the Salem units safely and that operator response to operational events was excellent. The overall performance in the Operations area was good.

However, weaknesses were noted in the decisions to restart Unit 2 following the rod control system problems, in the failure to follow procedures resulting in the loss of Unit 2 annunciators, and in the inadequate oversight of the fire protection program.

4 Salem PSR Page 11

. MAINTENANCE / SURVEILLANCE The board concluded that the Salem maintenance and surveillance programs contributed i to the safe operation of the two units during the assessment period. In general, a  !

declining number of personnel errors in both maintenance and surveillance indicated i improving performance. However, the number of transients induced by con'ponent i i

failures and the significant problems with the rod control system raise quest'ons regarding the overall effectiveness of the maintenance and engineering support functirms.

1 RADIOLOGICAL CONTROLS 1

PSE&G continued to implement effective radiological controls and ALARA programs during this period. The SALP board noted improvements in this functional area  ;

including strong management support and oversight. Quality Assurance audits in this area were of very good quality.

EMERGENCY PREPAREDNESS l The SALP board determined that PSE&G maintained a generally strong and effective  ;

emergency preparedness (EP) program. However, the board was concerned with an I apparent decline in the ability of the licensee to make correct initial Protective Action Recommendations during training, drills and annual exercises. This concern resulted in j the board's assessment of a declining trend for this area. The board also concluded that i i

PSE&G continued to maintain an effective and performance-oriented security program during this period. Overall, licensee perfonnance in both EP and security remained j excellent. i 4

l ENGINEERING AND TECHNICAL SUPPORT l Engineering and technical support organizations provided good support for refueling and

maintenance outages, and strong performance in addressing day-to-day problems. The

! SALP board noted that training programs for engineering personnel were excellent but that weaknesses were observed in the licensee's non-conformance, erosion / corrosion, and i fire protection programs. Although the root cause training program was viewed as a i strength, the board noted that the threshold for initiating actual root cause investigation l was not clear or consistent.

PSE&G management continued to provide generally effective management support.

l Significant Event Response Team (SERT) reviews of major events have been effective.

However, the board noted that in several instances, PSE&G failed to initiate adequate root cause evaluation or assessment of abnormal conditions. NRC interaction with PSE&G management was needed in a number of cases in order for full evaluation and

corrective action to be taken in a timely manner. Once initiated, comprehensive

assessment, root cause analysis and effective corrective actions were implemented.

Outage planning and training programs in all areas were considered strengths.

Saleen PSR Page 12

1

2. LICENSEE RESPONSE TO PREVIOUS SALP FUNCTIONAL AREA WEAKNESSES / RECENT LICENSEE PERFORMANCE TRENDS (in the last year) l l l

• OPERATIONS I

l PSE&G continues to safely operate the units. Operator plant knowledge and response to l events remains strong, however, operator response has been less than thorough regarding l indications of stuck-open RHR check valves, indications of a possible leaking RHR l pressure isolation valve, and a case of indeterminate hotwell level.

I I Recent management changes included the naming of a new Operations Manager in l September 1993, and two new Operations Engineers in January 1994. The licensee

, l intends to pursue full unitization of the Salem operating crew shifts.

l I

l

• MAINTENANCE AND SURVEILLANCE l

l Although maintenance and surveillance activities remain generally good, as exhibited by l strong Maintenance Department performance in response to the December 1993 EDG l cracked cylinder liner issue, the recent Unit I refueling outage was marked by multiple l examples of poor work control practices and multiple examples of failure to follow l procedures.

I l In order to improve overall per'iormance and response to emergent issues, PSE&G has l reorganized the Maintenance Department. Recent changes include replacing the single l Maintenance Manager role widi three new positions: 1) Mechanical Maintenance

l Manager, 2) Controls Maintenance Manager, and 3) Planning Manager. PSE&G is also l pursuing unitization in these departments.

l

l l

• ENGINEERING AND TECHNICAL SUPPORT I

l l Both Salem system engineering and PSE&G nuclear engineering have continued to l provide good engineering support for plant operations.

l l An NRC observation related to the Salem rod control issue was that the initial l troubleshooting efforts lacked clear leadership and delegation of responsibilities. This

] resulted in the efforts narrowly focusing on the most recent system malfunction without l adequate attention to the repetitive nature of the failures and the need to determine and l correct the root cause. The failure of PSE&G to determine the root cause of the failures l resulted in numerous aborted startup attempts. The team did observe significant l improvements in the control of troubleshooting and root cause determination during the l inspection.

I Salem PER Page 13

l e PLANT SUPPORT I

l The NRC noted that PSE&G continued to perform at a noteworthy level in the area of l radiological protection through the end of 1993, especially during the recent Unit 1 l refueling outage.

I l The licensee's annual partial-participation emergency preparedness exerc.c was l' conducted on June 23,1993. On-site response to the simulated emergency vs very l good. An exercise strength was Emergency Response Manager command and control.

l No exercise weaknesses were identified. Significant areas for potential improvement l were maintenance team tracking from the Operational Support Center and public address l system operability in the Technical Support Center.

l

• l The PSE&G security program continues to be effectively directed towards public health l and safety. A strike by the security force was narrowly averted when a new labor I agreement was reached in November 1993.

I I

l e SAFETY ASSESSMENT / QUALITY VERIFICATION I

l In July 1993, the licensee formed a Comprehensive Performance Assessment team j l (CPAT) which conducted a special assessment of safety issues and recent plant events l using an integrated MORT investigatory analysis. The CPAT developed comprehensive l root causes for these events, and the licensee has formed task teams charged with l developing corrective actions. PSE&G has held periodic meetings with the NRC to l discuss CPAT findings, and the NRC continues to monitor licensee progress in this area.

l l In February 1994, PSE&G Vice President of Nuclear Operation (VP-NO) assumed the l collateral role of General Manager of Salem Operations. The licensee also initiated other l management changes under the VP-NO and intends to pursue unitization of the Salem l units. PSE&G has implemented these changes in order to achieve sustained improvement l in the area of Salem performance.

I i 3. LICENSEE PERFORMANCE STRENGTHS AND WEAKNESSES

• Salem performance continues to be inconsistent.

e Capacity factor has been low due to refueling outages at both units and forced outages i due to rod control problems, and diesel liner concerns.

Strengths:

The NRC has documented progress or good performance in:

i e Material condition e Procedure quality Salem PSR Page 14

. o Radiation protection program o Event response and root cause determination when the need to respond or evaluate has been identined Weaknesses:

Salem performance has been weak in:

o Control of maintenance e Recognition of the need to due root cause determination, e Inspectors have observed a production oriented mindset e Examples include imlial response to the cracked diesel liner, failure to identify elevated reactor power in 1992, failure to recognize generic implication of rod control problems e Management performance (tolerance of above conditions).

e Licensee Response Actions For Identified Concerns:

o PSE&G has responded to identified performance and management problems by:

e Replacing the Salem General Manager, on an interim basis (approximately one year) with the Vice President, Nuclear Operations.;

e Rotating the majority of managers reporting directly to the Salem General Manager, o Pursuing unitization of the maintenance, operations, and planning organizations, e Implementing the existing performance assessment tools to improve accountability from the highest levels of management down to rank and file workers, o Forming dedicated teams to implement the corrective actions developed in response j to the CPAT findings.

! e The licensee continues to increase resources for a material condition improvement program. The NRC has observed noticeable improvement in the material condition of the plant, indicating that the licensee has been earnest in the implementation of

improvements.

i

• The Procedure Upgrade Project (PUP) was closed out in September 1993. A large l- majority of procedures were reviewed and upgraded, and procedure maintenance has

! been made the responsibility of the Technical Department.

t l e A meeting was held on July 9,1992, to discuss concerns associated with the Fire Salem PSR Page 15 i

1

l

• Protection Program and the status of Appendix R open issues. In a letter dated September 15, 1992, the licensee stated that they had completed Appendix R modifications and the penetration seal project. Further, the fire damper project is  !

scheduled for completion in 1995. An Appendix R inspection was conducted in May  :

and July 1993. NRC identified concerns with the licensee's qualification testing of 3M fire wrap material.  !

• A management meeting was held on July 16,1993, to discuss a new comprehensive self assessment of licensee activities associated with a number of recent performance issues at the site. The licensee intends to review a number of recent events utilizing a MORT-type investigation process to discover possible root causes that may have been missed previously. This effort is expected to be completed by December 1993.

4. NRC TEAM INSPECTIONS WITIIIN THE LAST YEAR Area /Date Findings EDSFI Assessment Licensee-contracted EDSFI has been August 16 - completed. The NRC assessment of the September 3,1993 licensee EDSFI identified a number of minor concerns; but, concluded overall that the licensee's assessment was good.

Augmented Inspection Team (AIT) An AIT was formed to review and June 5 - July 2,1993 evaluate the circumstances surrounding a problem with the Unit 2 rod control system. The components within the control circuitry that led to rod withdrawal when operators were demanding rod insertion.

Appendix R Inspection Identified concerns with Kaowool and 3-M May 17-21,1993 fire wrap material. Also weaknesses in safe shutdown outside the control room and lighting. Re-evaluation to occur during July 1993.

5. PLANNED TEAM INSPECTIONS SWSOPI Date and scope to be determined.

DET/OSTI/IPAT77 (Does this team exist yet?)

Salem PSR Page 16

e IV. INSPECTION PROGRAM STATUS I. STATUS OF INSPECTIONS l

l The inspection program status is reflected in attached MIPS report #2. The data is l current as of the date of the MIP. The MIP indicates that inspection program is on-l track with the planned resource allotment; no significant shift in inspection activities is l warranted.

2. PROPOSED CHANGES TO MIP e Unit ! ,

i A. DRSS -

B. DRS -

1 C. DRP ll (1)

)

e Unit 2 1 A. DRSS - j B. DRS -

C. DRP-

3. SIGNIFICANT ALLEGATIONS AND INVESTIGATIONS e There are eight open significant allegations at Salem. (two are common with Hope Creek)

Three allegations are related to harassment and intimidation of licensee personnel, up to and including allegations of promotion denial due to "whistleblowing." One of the allegations asserts that the Offsite Safety Review Group is not performing its function in accordance with technical specifications. OI is actively reviewing these cases.

Salem PSR Page 17

A fourth allegation asserted that the main security access center at the Salem / Hope Creek site was not manned as required by the NRC approved security plan. DRSS is scheduled to conduct a routine security inspection in March 1994 and will review this matter.

The fifth allegation concerns an operator wrongdoing issue. During and subsequent to the Overhead Annunciator (OHA) AIT in early 1993, neither of the two operators in the control room at the time of the incident admitted to any manipulation of the OHA system, even though clearly operator involvement was a contributor to the event. DRP is reviewing the licensee's investigation and followup into this matter and will determine this issue's resolution on the basis of that review.

The sixth allegation involves a technical question that suggests that HVAC ductwork integrity may not be assured under dynamic loading of new fast-acting curtain fire dampers. DRP is reviewing test procedures and results while DRS is scheduled to review the matter during the next routine fire protection inspection. >

i The seventh allegation regards evidence that the Rod Control problems experienced by the plant (and followed up by the AIT) occurred during stanup testing at the Zion nuclear station, even though Westinghouse representatives denied that the problem had ever .

t occurred before. OI has opened an investigation into this case and is currently reviewing the matter.  ;

The final allegation concerns 6 technical issues raised regarding the environmental qualification of equipment. Upon agreement of the alleger, this matter will be referred to the licensee for resolution. Otherwise, DRS will followup it up.

4. OPEN ITEM STATUS BACKLOG /No. GREATER THAN 2 YRS (Unit I and 2 - Common) 57/6 NOTE: The large number of open items is due to the issuance of an Appendix R/ Fire Protection Team inspection Report in October 1993 and an EDSFI Team Inspection Report in November 1993.

5. OUTSTANDING LICENSING ISSUES e GL 89-10 (MOV) - technical differences between NRC/PSE&G. (Hope Creek also) e EDG amendment - meeting held May 11,1992 to resolve issues.

e TS amendment to resolve AFW/ containment spray issue (see Section II.2.a).

e Increase in surveillance test intervals and AOT for reactor trip and ESFAS.

Salem PSR Page 18

O a

e Install new digital feedwater control system.

e Evaluation of Control Room Design Deficiencies that were not corrected.

e Bulletin 88-08 (Thermal Stress in Piping Systems Connected to the RCS) - licensee is revising their response, ,

I l 6. LOCAUSTATE/ EXTERNAL ISSUES l

l a. NJ DEPE/BNE l

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• Now providing input / comments on all PSE&G licensing change requests.

4 l

• 12tter regarding Salem RMS (see Section II.2.a).

l e Provided comments on recent SALP report.

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• High interest in resident inspection accompaniment.

l e Continuing interest in Salem cooling tower issue: When Salem's renewable variance l for the use of the Delaware River as a heat sink came up for renewal in 1984, New i

l Jersey environmentalists appealed to the state to not renew the variance. In 1990, NJ l DEPE issued a " draft order" requiring PSE&G to build two cooling towers to support l the Salem units' operation. PSE&G responded to the state's order with a 56-volume J

l comment, and the issue is currently under review by NJ DEPE. Recent NJ DEPE l decision not to require cooling towers.

l

• State inspector accompanied AITs that reviewed Salem 2 loss of OHA system and l RCS.

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• Recent letter (6/29/93) concerning digital feedwater modifications to be performed the l next two refueling outages.

l l b. Other (Media Interest) l l

• Minimal interest in SALP Management Meeting.

i l e 1.arge interest in AIT (Unit 2 TG failure) exit meeting.

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• Smaller interest in two AITs (Unit 2 less of Alarms and rod control problems) exit

l meeting.

Salem PSR Page 19

6Em4 w, w e f43R-14-1995 10:25 DPP NARRATIVE

SUMMARY

INPUT FOR PLANTS DISCUSSED AT THE LAST SM I. HISTORY Briefly describe when and why the plant was first discussed by senior REGION L managers. If on the Watch List, when did this occur? Briefly p/ (,d describe the previous plant performance. Refer to narrative summary prepared for previous SMM; condense where possible.

II. CHANGES SINCE LAST SMM Briefly describe the changes in the licensee corrective action initiatives, plans l REGION */ J PROJECTS kJ/ - and programs including management and organization, newBriefly describe and progress toward goals.

p addressing the licensee's problems since the last SMM.

]

REGION /NRR/

Highlight significant inspection findings since the last SMM in 1 AEOD as chronological order (i.e., NRR Special Team Inspection, AEODAlso, include i cpplicable Diagnostic Evaluation, SSOMI, SSFI, OSTI, AIT, etc.).results of  ;

Sunnarize, in narrative form, the most recent NoteSALP and briefly REGION v' lW highlight major events and/or problems.

any applicable trends on emerging concerns.

Briefly describe any new hardware issues or items warranting increased PROJECTSU* / th REGION NRC attention.

III. FUTURE ACTIVITY REGION y/ Summarize planned or anticipated conferences, and management meetings.

major Include inspections, current outage enforcement ,

J D' schedules with major plant modifications and program upgrades.

Summarize significant ongoing, planned or anticipated licensing l PROJECTS initiatives (i.e.. TS upgrades and changes for plant modifications).

l REGION /

PROJECTS L'y' considered at the SMM.tIdentify any other licensee initia

• In case of multiple assignment, the organization with lead responsibility appears first.

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Attachment 1

A Q-j DATA $UMMARY f}

y

[

I. OPERATIONAL PERFORMANCE A. Scram Summary Unit 1 7/14/94 - Operators manually tripped the reactor from 100% power in response to decreasing condenser vacuum caused by a lightning-induced loss of all circulating water (CW) pumps. The licensee determined that a design inadequacy (there was no time delay in the undervoltage (UV) pickup circuitry of the CW pump switchgear) resulted in unnecessary UV relay actuation following a lightning-induced voltage drop.

6/10/94 - Automatic reactor trip from 97% power following a main generator trip. The licensee determined that a transformer failed, causing the main generator output breakers to open resulting in a turbine trip and subsequent reactor trip. l i

Unit 2 l

• 9/29/94 - Operators manually tripped the reactor following an l operator inadvertently closing two main steam isolation valves while at 30% power.

6/29/94 - Automatic reactor trip on low-low steam generator water level during power. escalation. The licensee determined that

' feedwater recirculation valve cycling at low feedwater flow rates caused rapid changes in feedwater header pressure and steam generator feedwater flow. Subsequent investigation determined that improper gain settings caused unstable feedwater controller operation.

Sianificant Operator Errors B.

On September 29, 1994, while increasing power on Unit 2, operators manually tripped the reactor from 30% power. A licensed operator, intending to close main steam line drain valves, inadvertently

closed two main steam isolation valves (MSIVs). Operators manually tripped the reactor in anticipation of the automatic trip.

C. Procedures The licensee continues to experience problems with adherence to procedures and work practices. For example, the failure of a contractor electrician to adhere to stated work practices resulted in the individual cutting into the wrong 4160 Vac cable. The fact that the cable was de-energized at the time was fortuitous, since it was tagged out to support other work. Other examples of failure to adhere to stated work practices have recently been identified during I

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4 the Unit 2 outage, which commenced in October 1994, and appear to be similar in nature to events and causes that were the basis for previous escalated enforcement on March 9, 1994.

!!. CONTROL ROOM STAFFING A. Number of Licensed Operators

/qWA F.d EQ , LSEQ i3/lo TOTAL 9

33 27 0 60 14 ti  %

B. Number and Lenath of Shifts Five, 12-hour shifts C. Role of STA 4

There are at least two STAS per shift and they train with assigned operating shift crews. All STAS are required to have at least bachelor's degrees and hold senior reactor operator (SRO) licenses.

In normal operating conditions, one STA qualified individual is t typically assigned to the work control center, and the other l individual is assigned as an extra SRO to one of the control rooms i or performs as one of the two Nuclear Shift Supervisors. In an accident condition, the role of the STA is to assure that the proper I actions are taken relative to emergency response procedures, activities are initiated to mitigate core damage, and accident conditions are properly assessed and analyzed.

D. Recualification Procram Evaluation ,

l During May 1994, the NRC conducted a requalification program j evaluation. The program was determined to be effective ar.d operator 4 performance was considered satisfactory. However, a technical adequacy and procedure compliance issue was raised by the inspectors when, during the conduct of a simulator scenario, the operating crew

> closed all steam generator MSIVs without E0P specific direction. No other significant program deficiencies were identified.

i

!!!. PLANT-SPECIFIC INFORMATION i '

A. Plant-Specific Information Plant Salem Nuclear Generating Station, Units 1 and 2 Owner Public Service Electric and Gas

, Company Reactor Supplier / Type Westinghouse / Pressurized Water Capacity 1106 Mwe AE/ Constructor PSE&G/ United Engineers and ,

Constructors l Commercial Operation Unit 1: 6/30/77; Unit 2: 10/13/81 l

I I

i B. Uniaue Desian Information Containment: Large, Dry with steel liner Emeraency Core Ccciina Systems: Four accumulators, two high head and two intermediate head safety injection pumps. Two motor driven and one steam driven auxiliary feedwater pumps ,

AC Power: Three 500 kV lines feed a ring bus that connects to both l units. Three ALCO emergency diesel generators / unit provide '

emergency' power. One 40 MWe gas turbine is capable of being l connected to the ring bus DC Power: Each unit has three 125 Vdc batteries with two battery chargers / battery and two 28 Vdc batteries with one battery charger / battery Main Circulatina Water: The main condenser is cooled by circulating water from the Delaware river. The flow rates are about one million .

gallons per minute for each Salem unit IV. SIGNIFICANT MPAs OR PLANT-UNIQUE ISSUES Bulletin 88-08, Thermal Stresses in Piping Connected to Reactor Coolant i System (open). PSE&G has not installed temperature monitoring on the '

susceptible piping that was identified. For the charging piping,  !

alternate charging piping, and auxiliary piping, PSE&G has used analysis to show that the piping can withstand the maximum number of thermal cycles projected to occur from the time of licensing until at least five years in  !

the future. The methodology, developed by Westinghouse for EPRI, is  !

currently being reviewed by the staff. j

! For the safety injection system piping, PSE&G is developing a program that

! will be able,to detect small amounts of leakage. This program will also i

be reviewed by the staff.

i l V. STATUS OF THE PHYSICAL PLANT

} A. Problems Attributed to Acine I SERVICE WATER: Due to extensive corrosion and erosion of the carbon i steel service water piping, the licensee initiated a project to a

completely replace all service water piping (including the piping in i containment) with 6% moly-stainless steel in 1989. Currently, about j 95% of the service water system has been replaced. Completion of the service water upgrade project is expected by the end of 1995.

RADIATION MONITORING SYSTEM (RMS): RMS age and design has caused recurring system failures that have resulted in occasional ESF actuations or reportable events. Licensee budget constraints have

prevented complete replacement of the system. However, the licensee has initiated short-term correctivo actions to make the system less vulnerable to certain failure modes. Improvements have been noted.

However, frequent RMS system failures and the associated

- - _ _ - - . - - - - - - - - - _ - - _ - _ _ _ . _ _ . - _ - - - - - - - - - -- --o , - . . . ---+m rv '" - r

'. e l1 l'e j compensatory measures and corrective actions still require significant resources and attention from the operations and maintenance departments.

B. Other Hardware Issues j The licensee continues to experience recurring degraded system

< performance or conditions which require operational maneuvering to

support unplanned maintenance activities. These conditions occur i i frequently and are often caused by material or design inadequacies. i

Recent examples include:

CONTROL OIL POWER UNITS (COPU): Recurring filter differential pressure problems have required the licensee to frequently reduce l power to support COPU filter replacement. The cause of frequent

! filter loading is not yet fully understood by the licensee.

4 CONTROL AIR SYSTEM DEGRADATION: Recurring leaks and degradation of 1 the control air system are of sufficient magnitude that removing one

! air dryer from service for maintenance often has the potential to e adversely affect the performance of the entire air system.

i Compensatory measures are usually required to ensure satisfactory system operation.

i EMERGEACY DIESEL GENERATOR (EDG) STARTING AIR CHECK VALVES:

{

Moisture in the EDG air start system frequently cau es pipe i j corrosion. The licensee believes the build-up of corrosion prodccts is the cause of frequent check valve degradation associated with the i air receiver tanks in the air start system. Consequently, operators i frequently replace check valves, which requires that the affected  !

EDG be declared inoperable while maintenance is in progress. j

FEEDWATER SYSTEM CONTROLS: In November the licensee discovered an

! amplifier in the feedwater control circuitry, that was supposed to '

be set for a 1:1 gain, was actually set for an 8:1 gain. The condition is believed to have existed since initial startup.

' The

amplifier affects low flow operations (power ascension, up to about ,

15%), an operating regime in which the licensee has historically

experienced significant difficulty in controlling feed flow to the

! steam generators.

Recent hardware issues: l i

On November 18, 1994, a main electrical disconnect in the 500 kV  ;

c switchyard opened unexpectedly and for unknown reasons. The event I

caused the isolation of the No. 4 Station Power Transformer (SPT-4),

which affected the Unit I vital buses, and caused the loss of a train of three Circulating Water pumps.

i On November 22,1994, SPT-13 isolated due to degraded performance of l i

the transformer caused by current " tracking" on the outside of the j insulation due to an improperly installed boot seal and associated i potting compound which directly contacted the conductor. j 4

4 i

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On November 28, 1994, SPT-2 isolated for reasons unknown. The isolation affected the Unit I vital buses and resulted in loss of a train of three Circulating Water pumps. Since another Circulating Water pump was already out of service for maintenance, the operators had to initiate a rapid . power reduction to compensate for the reduced condenser efficiency and vacuum.

On November 28, 1994, the loss of a portion of the 13 kV ring bus i was caused by a fuse failure, and for unknown reasons, resulted in a loss of power to the Technical Support Center (TSC) and constituted a loss of accident assessment capability until power j could be restored.

VI. PRA A. PRA Insiehts I l

The Salen Generating Station Units 1 and 2 are Westinghouse 4 loop  !

PWRs with large dry containments. Station blackout had been identified in the Individual Plant Examination (IPE) to be a significant contributor to total Conditional Core Damage Frequency.

Each Unit is powered by three offsite power lines, and each Unit has three diesel generators. In addition, a gas turbine is located on site and is capable of providing emergency power to both units. In the event of a loss of offsite power, the required on-site emergency AC power is supplied by either 2 of 3 diesel generators, or by the gas turbine supplying power to the 13 kV system. The station blackout commitments have been implemented. These were to add a diesel-driven air compressor and battery room heaters, and to develop an EDG reliability program. The battery capacity meets the 4-hour coping period station blackout criteria.

A sensitivity study performed in the IPE found that the total core damage frequency (CDF) was increased by failure of the PORVs to open. During design basis transients, the PORVs are used to prevent challenges to the pressurizer safety valves and provide RCS overpressure protection. On 4/7/94, the PORVs performed successfully during a transient at Unit 1. Following this event, the Unit 1 PORV internals were replaced due to cracking noted in the valve stem related to IGSCC or hydrogen assisted cracking. The sensitivity study also found that the total CDF was sensitive to the probability of operator action failures under accident conditions.

l A factor of 10 increase in estimating operator action failure resulted in a seven-fold increase in the CDF. l l

l In 1994, the number of scrams while critical increased at Unit 1, but did not increase for Unit 2. Unit I experienced 4 scrams, while Unit 2 experienced I scram. This implies that the initiator

" Transient with PCS Available" frequency may be greater for Unit I

! than Unit 2.

l 4

j-  :

4 l

B. PRA Profile In response to Generic Letter 88-20, the lice-see submitted the i Sales Unit I and 2 IPE dated July 30, 1993. The licensee plans to

! submit the IPEEE in May,1995. The total CDF was estimated at 4.5E-5/yr for Unit I and 4.8E-5/yr for Unit 2. The Internal Flooding CDF for each Unit was 1.6E-5/yr. The SER for the IPE is expected to be completed in the Fall of 1995. Below the overall CDF is broken down by initiating event.

Internal Initiating SGS I  % of SGS 2  %(

3 Event CDF/yr CDF CDF/yr CDF SB0 2.1E-5 47.9 1.7E-5 34.5

. Transient with PCS Available 5.3E-6 12.9 1.1E-5 3.6

LOOP (EDGs available) 4.3E-6 9.8 2.9E-6 6.1 Intermediate LOCA 3.1E-6 7.0 4.1E-6 8.5

) 4.8 Small LOCA 2.5E-6 5.7 2.3E-6

- Main Feedwater Line Break 1.4E-6 3.1 1.4E-6 2.9 4 ATWS . 1.4E-6 3.1 1.3E-6 2.7 Large LOCA 1.2E-6 2.7 1.0E-6 2.2 i Loss of SWS 1.2E-6 2.7 1.1E-6 2.3

Very Small LOCA 6.2E-7 1.4 1.4E-6 2.9

ISLOCA 5.6E-7 1.3 5.6E-7 1.2 Transient with PCS Unavail. 5.4E-7 1.2 3.1E-6 6.5 0.8 i Loss of DC Bus 3.7E-7 0.8 3.8E-7 SGTR 3.2E-7 0.7 1.9E-7 0.4 i Reactor Vessel Rupture 3.0E-7 0.7 3.0E-7 0.6  !

Main Steam Line Break 3.5E-8 <0.1 3.5E-8 4.1 t l On August 8, 1994, Unit 1 experienced condensate suction header i On August 31, 1994, Unit 2 experienced turbine building i

j damage.

flooding when a weld broke on the No. 23 waterbox. The IPE internal flooding study performed for Unit I concluded that turbine building flooding was not a contributor to the CDF. The following internal flooding profile is given in the IPE for Unit 1:

! Initiator h l y

l Nonisolable flood on the AB 84-foot elevation 4.2E-6 4

Rupture of piping in the relay room 7.3E-6 l Rupture of FP piping in the 64-foot switchgear room 2.5E-6 2

Rupture of DM piping in the 64-foot switchgear room 8.4E-7 Isolable flood on the AB 84-foot elevation 5.1E-7

.l l

The IPE identifies the dominant core damage sequence for Unit I to

) be a loss of offsite power followed by station blackout and loss of j AFW with recovery of power within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. For Unit 2, the dominant i sequence was a transient with power conversion systems available, and a loss of cooling to RCP seals.

I

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C. Core Damaae Precursor Events 4

On the basis of the precursors identified by ORNL for 1992 and 1993 (NUREG/CR-4674, vols.17 through 20), the staff did not identify any precursor events for the site that have a conditional core damage probability of IE-5 per year or greater. j The following event was classified as a "Significant Event" by the Events Assessment Panel. On April 7,1994, the Unit I reactor j tripped from 25% power. The operators had reduced power due to the grass-induced loss of some CW pumps such that the RCS T-avg was too low. In order to increase the temperature, the operators pulled control rods. Subsequently, the reactor tripped on a Power Low Range /High Flux signal. The resultant transient caused the plant to go water-solid L High Head Safety Injection flow, and to rupture the PRT ble disc. The risk significant aspects of the event are primarily sne result of human errors of commission.

VII. ENFORCEMENT HISTORY 10/93 NOV WITHOUT A SEVERITY LEVEL - LOG FALSIFICATIONS - The action concerned the falsification of required fire watch records by a licensee contractor. The violation, which was i identified' by the licensee's contractor, involved 19 of 35 fire waten personnel falsifying logs to indicate that fire watch patrols were performed, when, in fact, the individuals had not entered the areas indicated on the logs. In accordance with the Commission's direction, an NOV with no severity level designation was issued.

3/94 CIVIL PENALTY - The action consisted of eight violations of failure to follow procedures related to the control of maintenance activities. While none of the violations were significant from a nuclear safety perspective, some demonstrated the potential to cause physical harm to

' individuals and collectively demonstrated weaknesses in the maintenance and control of work activities. ($50,000) 3 10/94 CIVIL PENALTY - The action was based on four violations ,

e identified by the NRC as a result of an AIT and later followup inspections of plant events on April 7,1994, including an automatic reactor trip and two automatic actuations of the Three of the violations were

Safety Injection system.

considered to be continuing violations, involving the failure 4 to identify and correct conditions adverse to quality including inadequate procedures and known equipment deficiencies. Both senior reactor operators failed to exercise command and control during the events. Each of the four violations was characterized as a Severity Level III violation. Enforcement Discretion was exercised by the staff

' to increase the proposed civil penalty to emphasize the need for the licensee to pror.ptly identify conditions adverse to i

. i quality and to implement effective corrective actions.

($500,000) >

PENDING Based on an Office of Investigation Report dated September 30, 1994, the staff is considering enforcement action involving apparent hara;sment and intimidation of two staff engineers by licensee's management.

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! steam generator water level initiated a feedwater isolation. The level j oscillations occurred when the minimum flow valve cycled open and closed. '

l The licensee changed procedures to improve operator control of the minimum flow valve. The licensee also changed the gain in the valve controls. '

j The operator reduced power to within the capacity of auxiliary feedwater; however, before water level could be stabilized in all generators, the No.

23 steam generator reached its low level setpoint causing the reactor trip. (See IR 50-311/94-14) e On June 10, 1994, while operating at 97% power, the Sales Unit I reactor automatically tripped following a main generator trip. The licensee concluded that a potential transformer failed, causing the main gener. tor output breakers to open, leading to the reactor to trip. The licensee sent the potential transformer to an outside facility to determine the cause of the component failure. (See IR 50-272/94-13) e On April 7,1994, the Unit 1 operating crew rapidly reduced power in  !

response to severe river grass intrusion at the circulating water intake i structure. Salem Unit 1 tripped from 25% power during maneuvers to shut the plant down. Subsequent to the reactor trip, the plant experienced a series of safety injections which resulted in loss of the pressurizer steam bubble and normal pressure control. In addition to the reactor trip l and safety injections, certain valves that are required to operate, failed l to close. On April 8, the NRC dispatched an Augmented Inspection Team to  !

the site to review the causes and safety implications of the multiple  !

failures in safsty-related systems during the event and possible operator i errors. (See AIT Report 50-272/94-80 and 50-311/94-80)

2. ASSESSMENT Unanticipated equipment deficiencies continue to dominate performance of the Salem units. Although Sales unit I has continuously operated for more than 150 days, unit 1 operators had to reduce power six times in six weeks due to equipment problems from 11-6-94 to 12-17-94. On the other hand, the Salem units have experienced only one reactor trip in the six months beginning 8-1-94, as compared with five trips in the period from 2-1-94 to 8-1-94. Operators have begun to take significantly increased ownership for plant performance and safety.

Tt.eir involvement in insuring nuclear and personnel safety during the inspection of the no. 23 Reactor Coolant Pump seal illustrates their leadership in identifying and preventing pitfalls in plant activities. Maintenance management identified that lack of supervisory oversight of job briefings had resulted in ineffective worker preparation for maintenance activities. Steps have been taken to improve the job briefings. System engineering support for daily operations and maintenance activities continues to require significant improvement, while some improvement has been noted in design engineering support for daily activities.

Plant support organizations cont'aued to demonstrate excellence in their activities.

Overall, the number of challenges to uneventful Salem operations, although decreased over the last six months, continued at a high rate in comparison to other plants such as Hope Creek. Senior PSE&G management has implemented a number of changes intended to address the need for change, including replacing the Chief Nuclear Officer, the Sales General Manager, the mechanical maintenance manager, u

1 and the planning manager. Sales management has taken steps to incniase the emphasis on accountability from the Vice President of Operations down through all levels of management to the workers. Although some examples of improved performance have occurred, especially in the areas of operations and mairitenance, it cannot yet be determined whether PSE&G actions will result in lasting :hanges.

i I

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s i

s t SALEM e

I. BASIS FOR CONCERN For several years the NRC has noted stagnate, and sometimes declining, performance relative to the licensee's (Public Service Electric and Gas-PSE&G) initiative and ability to successfully perform comprehensive and through root cause analysis of abnormal conditions or situations affecting the operation of the facility, or recognize trends that are indicative of programmatic weaknesses. Consequently, corrective actions have not always been effective, as evidenced by recurrent deficiencies of a similar nature or continuing performance weaknesses. The apparent exception to this general observation av matters that involved or required NRC attention, such as situations in which an Augmer. N Icsp etion Team was dispatched or other conditions that resulted in increased NRC attentbn. 4(.ordingly, when NRC is involved or demonstrates interest in a matter, the licensee generally responds with a comprehensive and thorough root cause assessment that forms the basis of a corrective action agenda. However, in an increasing number of other situations, the licensee's efforts appear to be directed to rapidly identifying a seemingly reasonabic cause, followed by the implementation of corrective actions which usually fail to successfully resolve the condition or situation. Consequently, recurrent deficiencies, problems, or weaknesses are continually identified.

Though NRC inspection, enforcement, and assessment activities have identified the same basic or similar weaknesses, to which the licensee has generally acknowledged and responded to with corrective action plans, PSE&G has never actually demonstrated significant performance improvement at Salem. In reviewing previous NRC activities (SALPs and inspections) since 1988, we have noted that the licensee's performance and our subsequent assessments have not significantly changed. The licensee continues to experience recurrent operational, design and maintenance-related problems with no indication that previously applied corrective measures have been effective in resolving or causing reduction in the frequency or severity of apparent problems.

The Summary of Significant Issues and Events at Salem. 1988-1994 Attachment 1 provides highlights of select events and NRC activities at Salem since 1988. While the events themselves appear generally unrelated, there is a remarkable similarity in the theme and causes for a majority of the items and problems observed in this period. Of particular note is the findings of an Maintenance Team inspection (April 1990) and an Integrated Performance Assessment Team (May 1990) relative to the identification of weaknesses involving management oversight and control, insufficient supervisory presence in the field, ineffective corrective action implementation, and inadequate maintenance pecen el control, insufficient oversight of contractors, inadequate root cause analysis and determination for some events, and procedural adherence.

Many of these same themes are recognized in subsequent events, including, but not limited to:

(1) the catastrophic failure of the Salem Unit 2 Main Turbine, November 1991 (AIT involved);

(2) the licensee's identification that at least half of the contract fire watches had falsified records or otherwise improperly conducted firewatch activities in the 1991-1992 time period (Special Enforcement Action; (3) the failure of the Salem Unit 2 Overhead Annunciator System to properly function due to the licensee's failure to understand system design and function, and improper operator action (AIT involved); (4) the control rod control system malfunction during 0

y four start-up attempts of Salem Unit 2 following an outage due to the licensee's failure to l

. understand system design, failure to properly assess root cause, and poor control of troubleshooting efforts (AIT involved); and (5) the Salem Unit I trip and subsequent plant  !

stabilization problems that occurred on April 7,1994, as a result of suspected command and  !

control deficiencies involving operating personnel. (AIT involved).

A management meeting 'was held with the licensee in July 1993 to discuss the licensee's difficulty in resolving problems and implementing effective corrective actions, in light of the  !

three AITs conducted since 1991. In response, the licensee implemented an action plan. to perform a comprehensive assessment of their performance (CPAT), using several events l (including the AIT activities and recent plant trip events) as indicators of programmatic '

deficiencies. The CPAT effort was generally completed in January 1994, and identified causes having the same themes as previously identified by the NRC, and emphasized defects in the management and leadership of the Salem organization. Several problems were identified relative l to management skills and practices, work process control and worker performance, and problem i solving and follow-up. A management team has been assigned to determine, establish, and  ;

implement corrective measures. The corrective action effort is still in progress.  ;

Notwithstanding the CPAT effort, the licensee continued to experience several problems during the Salem Unit I refueling outage, which resulted in extending the outage from December 1993 l to February 1994. During the outage l NRC and the licensee identified several weaknesses and j violation of the established maintenance process and control program which had the potential to compromise worker safety. As' a result, the examples were the basis for an escalated i enforcement action and proposed $50,000 civil penalty issued February 10, 1994.

The licensee subsequently acknowledged the violations and submitted the penalty on April 8, 1994. In their response, the licensee identified the cause of these violations as less than adequate  ;

supervisory methods (i.e., insufficient management and oversight), less than adequate verbal  ;

communications, and less than adequate work practices (i.e., failure to follow procedures and  !

failure self-check in accordance with established work practices), i.e., the same general causes l that have been continually noted by the NRC. While the licensee's stated corrective actions appear address the causal factors, given past performance, there is no assurance that~ the same i or similar events will not recur. 1 II. CURRENT STATUS )

i As a result of the CPAT effort and in recognition of continuing difficulties in effectively l i resolving problems, achieving performance expectations, the licensee has initiated efforts to l l restructure and unitize certain Salem organizational elements in an effort to accelerate j

improvement in Salem Station performance. Accordingly, on February 9,1994, Steve  !

i Miltenberger, Chief Nuclear Officer-PSE&G, announced, effective immediately, that Cal (

Vondra, General Manapr-Salem Operations was being removed from Nuclear Department  ;

- activities and being reassigned to PSE&G's Fossil Department. Joseph Hagan, Vice President- l Nuclear Operations was designated to function as the General Manager-Salem Operations, and l as a Change Agent responsible for initiatives relative to performance improvement. Unitization l of certain functional areas such as Operations, Maintenance, and Station Planning and l l

2 l l

1 4 I l

> l

_ _ . ._ .. __.- , a

t Scheduling, and Outage Planning and Scheduling is being planned in an effort to assure [

] ,- ' increased attention and oversight. j i

The licensee also initiated re-evaluation of current managers and supervisors to assure that the individuals were capable of performing to management's expectations, and to replace or reassign the individuals, as necessary. The NRC has noted that actions have already been taken to  ;

l

reassign or otherwise replace several of the incumbents. Other changes to the overall l j organization are expected as the licensee pursues other improvement plan objectives, including  !

'(but not limited to) enhancement of personnel performance appraisal review, personnel  ;

l accountability initiatives relative to supervisory, employee, contractor, and plant performance, i requirements for increased field time for supervisors, training improvements, improved problem  !

] solving methods, leadership ability enhancement of supervisory personnel, and improved human l l performance assessments of events.

. a l Evaluation of Salem's most recent SALP cycle (December 29,1991 to June 19,1993) resulted  ;

j in ratings of Category 1 in Radiological Controls and Security, Category 1-declining in l Emergency _ Preparedness, and Category 2 in Operations, Maintenance / Surveillance,  !

. Engineering / Technical Support, and Safety Assessment / Quality Verification. There vere  !

frequent operational challenges, including nine separate plants trip among the units. The board  !

{ '

j concluded that the plant were operated safely and the operator response of operational events was

! excellent. Weaknesses were noted in the licensee's decision-making relative to restart on Unit-2

]

in light of continuing problems with the rod control system, procedural adherence which resulted in loss of Unit-2 Overhead Annunciators, and management oversight of fire protection activities .

which resulted in the improper performance of firewatch activities by contractors. The Board also noted that in several instances, the licensee failed to initiate adequate root cause evaluation or assessment of abnormal conditions; and that NRC interaction with the licensee management I was needed in several cases in order for full evaluation and sufficient corrective action to be accomplished. j

[ The current SALP cycle ends on December 10, 1994. In view of the continuing performance

!' deficiencies, including the findings of the most recent AIT (dispatched to review and assess the i licensee performance. relative to the April 7,1994, Salem Unit-1 trip and consequent plant l stabilization problems), overall performance appears to continue to decline in the areas of Plant

Operations, Maintenance and Surveillance, and Engineering and Technical Support. Plant

! Support activities appear to be stable. Licensee management is fully cognizant of the problems and have readily acknowledged performance deficiencies in several meetings with the NRC staff.

The licensee appears sincere and is actively engaged in efforts to improve overall performance.

i III. FUTURE ACTIVITY i {This section is currently under development}  !

Attachment 1 l

Summarv of Sinnificant Issues and Events at Salem. 1988-1994 i.

P

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Synopsis: This is a summary of issues and events at Salem which, when viewed in the

,y aggregate, indicate a continuing problem in the licensee's management and ,

oversight and control, and corrective action effectiveness. The following themes ~!

appear to be present:  ;

l. o I Lack of aggressive management oversight of plant activities o Lack of aggressiveness to assure adequate corrective action implementation.

o Inadequate root cause analysis of events o Slow identification and evaluation of degraded plant conditions o Lack of procedural compliance ,

The general response of the licensee relative to these matters is often expressed as:

o Their programs are on improving trends; o They are committed to excellence and plant betterment;  ;

o They have improved the quality of their procedures;  !

o They are dedicated to better training of their employees; and o They have taken effective action to improve management oversight.

OUTAGE TEAM INSPECTION (October 1988) l 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 identified program problem areas but their effectiveness was minimal due to a lack of management follaw-up to assure corrective action implementation. (IR 88-80)

Licensee responded to the report in a March 1988 letter by indicating that strong and effective action was being taken to resolve the identified weaknesses by:

- reiterating their commitment to excellence in Engineering and Plant Betterment;

- improving the design change control process;

-improving personnel training;

- improving the content and substance of weekly meetings;

- initiating Offsite Safety Review evaluations of management effectiveness.

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MAINTENANCE TEAM INSPECTION (Aoril 1990) '

l Several problems were noted regarding adherence to procedural requirements and the  !

- effectiveness of controlling contractor personnel. The identification, evaluation, and correction l of deficient conditions were also areas noted to need increased management attention. The report identified several examples of personnel performance errors, particularly in the area of mechanical maintenance. Inadequate root cause analysis was also noted. Quality verification

< activities were 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 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 procedures during the performance of work activities." (IR 90-200) 4 INTEGRATED PERFORMANCE ASSESSMENT TEAM INSPECTION (May 1990)

The Team noted a management tolerance of degraded plant conditions and 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. The report also noted that several safety tagging errors were not documented by the licensee's incident reports. (IR  :

90-81)

1 l CATASTROPHIC FAILURE OF THE MAIN TURBINE (November 1993 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 l attention to detail. (AIT IR 91-81) l FIRE WATCH FALSIFICATION (1991-1992)

Following an 4cident on July 1,1992 when a contractor (PTI) supervisor noticed that a PTI employee willfully failed to properly complete the required fire patrol, a comprehensive 1 investigation was initiated by the licensee. The licensee subsequently discovered that over half of the contracted firewatch personnel had improperly performed firewatch patrols and had l falsified associated documentation. Previously, the licensee was made aware of a similar issue l through an allegation referred to their attention by the NRC, However, their investigation efforts were not sufficient to substantiate the assertion. The licensee's most recent review of firewatch performance deficiencies noted the root causes to be willful misconduct by contractor employees aggravated by a lack of sufficient management oversight. (IR 92-09)

FAILURE OF OVERHEAD ANNUNCIATORS (December 1992)

ATTACHMENT 1 5 l

1 Unit 2 Operators discovered that the overhead annunciators (OHA) had not been updating alarms

, for about 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> as a result of an operator entering a' keystroke combination into a remote control work station that locked up the system. Root cause was determined to be a failure of personnel to follow procedures relative to use of the computer v-rk station affecting the monitoring and control of the OHA system operation. Further, the jesign of the OHA system l was not sufficient to alert operators to a critical switch that was mispositioned and prevented  ;

normal operation. (AIT IR 92-81)

ROD CONTROL SYSTEM FAILURFR (May 1993) l Unit 2 operators experienced several problems with the rod control system; the most significant l being that a rod actually withdrew 15 steps during an attempt to insert Shutdown Bank A. Root j causes were primarily determined to be equipment and design related, however some component failures were attributed to poor work practices during system troubleshooting and testing.

Additionally, the initial management oversight and control of troubleshooting were not sufficient i to assure understanding of the failure causes and establishment of proper corrective measures. l Notwithstanding, the licensee conducted several startup attempts without a concerted effort to  !

determine the root cause of the problems. It was not until NRC directly intervened with an AIT that the licensee initiated a thorough and comprehensive analysis of the abnormal performance

, of the rod centrol system. (AIT IR 93-81)

MANAGEMENT MEETING Uuly 1993)

A management meeting was held with the licensee in July 1993 to discuss the licensee's difficulty in resolving problems and implementing effective corrective actions, in light of the three AITs conducted since 1991. In response, the licensee implemented an action plan to

perform a comprehensive assessment of their performance (CPAT), using several recent events (including the three AIT activities and nine reactor trip occurrences) as indicators of programmatic deficiencies. The purpose of the CPAT efforts was to discover common causal factors that could be associated with the licensee's continuing performance problems, and to establish and implement a corrective action plan to prevent recurrence.

DUTAGE 1R11 WORK CONTROL PROBLEMS (October 1993 - February 1994)

During the conduct of Unit I refueling outage, the licensee and the NRC identified numerous 1 examples of failure to follow established procedures relative to the control of maintenance work I 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 the instances (when considered individually) significantly affected plant safety, several of the items had the potential to affect individual worker safety. (IR 93-23)

I ATTACHMENT 1 6 l

k'NFORCEMENT CONFERENCE (February 1994) l Ie

During the enforcement conference held February 1994, the licensee maintained that

;

4 i - the self identification of events process works;

! - procedures are in place to ensure safe practices; j - management presence in the field has increased;

- there is enhanced review of events at weekly meetings; .

3

- safety stand-downs / training were conducted to reaffirm management expectations;  !

- the contractor work force would be reduced in an effort to better maintain oversight;  !

j - the scope of future outages would be limited; and, ,

- personnel accountability for actions will be reinforced.

1 Following the conference, the NRC issued a Notice of Violation and Imposition of Civil Penalty

($50,000). _ On April 8,1994, the licensee acknowledged the violations and paid the civil l penalty. The licensee identified the causes of the violations to be related to inadequate

supervisory methods, insufficient supervisory oversight, inadequate communications of .

l expectations, and failure to follow procedures and established work practices.

e i I OUTAGE 1R11 ISSUES (October 1993 - February 1994)  !'

The licensee experienced several difficulties during the outage relative to hardware j modifications. Examples includer p o A auxiliary feedwater (AFW) pump governor, which was previously operating normally l

l and not due for any maintenance, was replaced during the outage due to an error in work i planning. After several unsuccessfully attemps to effect normal operation of the AFW

, pump, and after another replacement of the governor, the licensee determined that the

! replacement parts were different in design than the part that was originally removed.

i Successful operation was accomplished only after the licensee was able to retrieve the i original governor and remount it on the AFW pump. This event may indicate that the i licensee's procurement control program may be defective.

i a e During the outage the licensee aodified the turbine speed control system by changing the

configuration of the oil pressure control system on the Main Feedwater (MFW) pumps a in anticipation of the installation of a digital feedwater control system during a later 4

outage. Subsequent testing during start-up revealed significant flow oscillations were 1

occurring in the MFW pumps as a result of the modification. After analyzing the cause, j

the licensee determined that the difficulties were associated with the test configuration and the manner the system test was conducted. Notwithstanding, the licensee restored the MFW pumps to the original configuration in order to continue start-up activities.

i e On December 3,1993, during a post-maintenance test on Unit 2, "C" Emergency Diesel Generator (2C EDG) (Note: This is an ALCO diesel; and there are three EDGs per Unit), coolant was noted to be leaking from one of the cylinder liners. Subsequent d licensee investigation revealed that the liner was actually cracked and broken in three

] pieces. During the investigation the licensee determined that the liner was not the ATTACHMENT 1 7 i

[ l l

l l

original equipment and that the 10 or the 18 liners in the 2C EDG were replaced during  ;

e a 1992 outage with parts manufactured by Canadian Allied Diesel (CAD), under license  ;

by ALCO, in an effort to expedite reassembly of the engine to support plant start-up.

(Note: The original ALCO liners were still being refurbished and were not available for immediate use.) The licensee subsequently shutdown the unit as required by Technical Specifications due to an inoperable diesel. The licensee also determined that all of the cylinder liners in the IB EDG were supplied by CAD due to a similar liner refurbishment effort in 1991. Consequently, that engine was also declared inoperable, which further delayed Unit I restart activities. The licensee conducted a through root cause investigation and determined that there were slight differences in the material and dimensions of the CAD liners, that they did not know previously, that could result in early failure of the part. As a result, the licensee initiated extensive testing and verification, and took action to replace all CAD liners with ALCO manufactured parts.

The licensee's investigation revealed the most probable mechanism that could lead to failure of CAD supplied liners. Consequently, the licensee took actions to improve the quality of its commercial grade dedication process and maintenance procedure. In review, the licensee also discovered that there was no technical or safety basis to refurbish, or otherwise replace any of their diesel liners without cause; and that their rationale that refurbishment or replacement of the liners would result in increased reliability of the engines was unfounded and not demonstrated by industry or vendor experience.

ADDITIONAL SALEM UNIT 1 PROBLEMS SUBSEOUENT TO RESTART ON FEBRUARY 4.1994 After resolving the issues that impacted startup, Salem Unit I was finally, successfully restarted on February 4,1994. However, the following events were subsequently experienced:

• On February 10,1994, after being at power for only 3 days, the unit tripped from 100%.

The plant experienced a coincident loss of both 15 VDC control power supply to the electronic controller associated with the main turbine Electro-Hydraulic Control (EHC) system. Unexpected actuation of the over-voltage protection feature " crowbar", (for reasons still not fully understood but suspected to be associated with vibration caused by maintenance activities in an adjacent equipment cabinet), led to the loss of both redundant power sources. The loss of power caused closure of turbine stop and control valves, leading to turbine trip and resultant reactor trip. All plant systems and emergency safety features operated normally on plant shutdown.

• On February 11, 1994, the licensee discovered that the mode switches for both air compressors on the IB EDG air start system were in the "off" position. Consequently, for some period of time, the air compressors were not replenishing the air receiver tanks for the EDG. Upon discovery, the licensee restored the switches to the proper position and replenished the air supply before it decayed below the pressure necessary to assure EDG start. TK-licensee determined that a maintenance worker failed to restore the switches to th: Wal podon during the performance of a surveillance activity.

ATTACHMENT 1 8

e o On February 13, 1994, I & C technicians were inserting wires in a pressure transducer e associated with the atmospheric steam dump system. Though the technicians believed that they had taken actions to de-energize the cables, they failed to fully understand the circuit completely and recognize that another supply also fed the cables that they were working with. Consequently, the cables shorted to ground and caused the steam dumps to actuate. As a result, an excessive cooldown rate was experienced but manually controlled by reactor operators prior to exceeding technical specification limits.

i However, reactor power was increased from 2% to 5.6% by the event, which constituted an unplanned reactor Mode change from Mode 2 to Mode 1.

MANAGEMENT MEETING. February 24.1994 On February 24, 1994, NRC held a Management Meeting with PSE&G to discuss their intentions, plans and schedules relative to program improvement. The licensee discussed the final results of their CPAT and provided a comprehensive improvement plan and schedule for NRC review and assessment.

The CPAT findings revealed serious deficiencies weaknesses in (1) management skill and practices (including first line supervisory personnel), (2) work processes and controls (including training and communication of expectations to workers), and (3) problem solving and follow-up of planned corrective actions (including root cause assessment, and tracking and trending operating experience feedback. The task for the establishment, implementation, and maintenance of corrective measures has been assigned to a management team. Activities are still in progress.

SAMM UNIT 1 TRIP. Anril 7.1994 On April 7,1994, Salem Unit I tripped from 25% power on a power low range /high flux signal and a safety injection initiation on low-low Tavg coincident with high steam flow. Operators were in the process of reducing power and had declined to below 10% (which enabled the 25 %

low power trip setpoint) to accommodate the loss of some circulating water pumps due to grass intrusion at the intake structure. In order to restore a lower than normal Tavg, the operators withdrew some control rods, which resulted in a power increase to the 25% low power trip setpoint, resulting in an inadvertent trip. The trip was further complicated when at least two main steam isolation valves and two feed water isolation valves failed to close as expected, and the two turbine-driven feed pumps failed to trip. The subsequent cooldown of the RCS caused pressurizer level and pressure to drop. Consequently, another safety injection on low pressurizer pressure was initiated. The plant went solid on high head safety injection pumps. The PORVs opened and relieved pressure to the pressurizer relief tank (PRT). Subsequently, the blowout disk on the PRT released to prevent overpressurization of the tank. The licensee declared an UE and subsequently upgraded the classification to an ALERT during the course of the event.

Several other automatic valves failed to isolate in response to the SI signal. All the affected valves and pumps had to be manually closed or tripped. Pressurizer heaters were turned on to restored pressurizer pressure control. Following, the plant was stabilized and brought to Mode 4, and then Mode 5, without further incident. An AIT was dispatched on April 8,1994, to investigate the cause of the conditions and situations that led to this event.

ATTACHMENT 1 9