ML20134K351
| ML20134K351 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 03/22/1995 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20134J860 | List: |
| References | |
| FOIA-96-351 NUDOCS 9702130257 | |
| Download: ML20134K351 (28) | |
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,1 REGION I PLANT STATUS REPORT 1
FACILITY: Salen Nuclear Generating Station Units 1 and 2 I.
mAcammum II.
PLANT PERN DATA III.
ANALTSIS/ASKSWENT IV.
INSPECTION PROIRAM STATUS V.
ATTACMENTS Last Update: March 22, 1995 d
Update Apprwets Section Chief CMMcES SINCE THE LAST UPDATE ARE DDIARCATED IN THE SONDER o -' a a-'a" - a a "
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9702130257 970207
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I ATTACHMENT A CONTENTS I.
BACKGROUND 1.
Licensee Parameters 2.
NRC Organization l
3.
Licensee Organization i
4.
Operator Licensing II.
PLANT PERFORMANCE DATA 1.
Current Operating Status (last 6 months) 2.
Recent Significant Operating Events and Identified i
Safety Concerns (of last 12 months) i 3.
Escalated Enforcement Activities (of last 2 years) 4.
IPE Insights III.
ANALYSIS / ASSESSMENT 1.
Previous SALP Ratings and Overview 2.
Licensee Response to Previous SALP Functional Area Weaknesses /Recent Licensee Performance Trends I'
(in the last year) 3.
Licensee Performance Strengths and Weaknesses 4.
NRC Team Inspections Within the Last Year 5.
Planned Team Inspections IV.
INSPECTION PROGRAM STATUS 1.
Status of Inspections (see attached MIPS Report #2) 2.
Proposed Changes to MIP
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3.
Significant Allegations and Investigations 4.
Open Item Status 5.
Outstanding Licensing Issues 6.
Local / State / External Issues V.
ATTACHMENTS (NOTE: To be determined based on intended audience) 1.
AE00 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 l
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- 1. BACKGROUND
- 1. LICENSEE PARAMETERS Utility:
Public Service Electric & Gas Company l
(PSE&G) l Company Location:
Hancocks Bridge, NJ (18 miles Southeast of Wilmington, DE) l l
County:
Salem j
t UNIT 1 UNIT 2 i
Docket No:
50-272 50-311 CP Issued:
September 25, 1968 September 25, 1968 Operating Licensissued:
April 6, 1977 May 19, 1981 Initial Criticality:
December 11, 1976 August 2, 1980 Elec. Ener. Ist Gener:
December 19, 1976 May 29, 1981 Commercial Operation:
June 30, 1977 October 13, 1981 Reactor Type:
PWR 4-Loop Same Containment Type:
Large dry Same Power Level:
3411 MWt Same Architect / Engineer:
PSE&G/UE&C Same NSSS Vendar:
Westinghouse Same t
Constructor:
PSE&G/UE&C Same
.l Turbine Supplier:
Westinghouse Westinghouse (GE
.l 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 Director (Region I) (Tel: 8-610-337-5229)
Wayne Lanning, Deputy Director
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(Tel: 8-610-337-5126)
John R. White, Section Chief (Tel: 8-610-337-5114) i Senior Resident Inspector:
Charles S. Marschall (Tel: 8-609-935-3850)
Resident Inspector:
Joseph G. Schoppy, Jr. (Tel: 0-609-935-3850)
Resident Inspector:
Todd H. Fish (Tel: 8-609-935-3850) i Project Engineer:
G. Scott Barber (Tel: 8-610-337-5232) l Project Manager:
Leonard 01shan, NRR (Tel: 8-301-504-1419)
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- 3. LICENSEE ORGANIZATION Manaaement Personnel:
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E. James Ferland
-Chairman and Chief Executive Officer Leon R. Eliason
-Chief Nuclear Officer and President Nuclear Business Unit Stanley LaBruna
-Vice President, Nuclear Engineering l
Joseph Hagan
-Vice President Operations John Summers
-General Manager - Salem Operations i
Jeffrey Benjamin
-General Manager, Quality Assurance &
Nuclear Safety Review Charles Munzenmaier
-Director, Operations Services Chuck Johnson
-Director, Human Resources & Administration Francis X. Thomson
-Licensing Manager Lee Catalfomo
-Operations Manager Michael P. Morroni
-Manager, Maintenance-Controls Michael Metcalf
-Manager, Maintenance-Mechanical Jerome A. Rana 111
-Technical Manager Eric Katzman
-Radiation Protection / Chemistry Manager i
Dennis Tauber
-Salem QA Manager Terry Ce11mer
-Manager, Salem Station Planning Arthur Orticelle
-Manager, Nuclear Training
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.j Workshifts
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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, 1 crew off.
Shift Comolement:
TS minimum Actual 3 SRO 4 SRO 4 RO 5 R0 1 STA 1 STA (dual role SRO)
Non-licensed Operators 5
7 or 8 Maintenance Electrician /Inc 1
2 Chemistry / Rad. Frot.
I 2
Fire Brigade 5
6 (site firr; brigade shared with Hope Creek)
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- 4. OPERATOR LICENSING I
- a. Licensed Reactor Operators (Licenses Cover Both Units):
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e Total number of active SR0s:
28 l
e Total number of active R0s:
26 l
e Total number of certified instructors:
13 l
e One simulator (modeled after Unit 2) located at the training facility in Salem, NJ, and used for Unit 1 and Unit 2 operator training and NRC administered licensing exams. PSE&G completed a 4
major modeling upgrade package in the summer of 1993.
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Salem PSR Page 4
f II. PLANT PERFORMANCE DATA
- 1. CURRENT OPERATING STATUS (for period 1/29/95 to 3/11/95)
Unit I began the period operating at 100% power. On February 3, the licensee initiated a unit shutdown to comply with plant j
i Technical Specifications. During implementation of a DCP to I
correct a problem with a solid state protection system (SSPS) power feed, a redundant power supply tripped. The licensee was unable to fully restore SSPS to operability within the technical
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specification limiting condition for operation action statement allowed outage time. On February 4, the licensee entered Mode 5 (Cold Shutdown) to address SSPS concerns. On February 15, operators entered Mode 4 (Hot Shutdown). The licensee maintained the unit in Mode 4 while resolving problems encountered with main steam atmospheric relief valves (MS-10s). On February 27, l
operators commenced a reactor startup. On March 2, operators increased power to 48%. On March 3, operators reduced power to l
28% to make a bioshield entry to adjust RCP oil levels. On March 8, operators increased power to 100% and maintained the unit there i
for the remainder of the period.
Unit 2 began the period in Mode 3 (Hot Standby). On February 1, operators commenced and completed a reactor startup. On February 3, operators commenced a Technical Specification required shutdown from 1% power, following renoval of NRC Enforcement Discretion due to potential common mode failure of SSPS power supplies. The licensee placed the unit in Mode 5, completed troubleshooting and repairs to SSPS, and commenced a plant startup. On February 11, operators took the reactor critical and commenced a power increase. On February 19, the licensee initiated a shutdown from
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47% power to remove the no. 21 Reactor Coolant Pump from service in response to low seal water leakoff flow. The licensee entered Mode 5, replaced the no. I seal on no. 21 RCP, and commenced a plant startup. On March 8, operators achieved reactor criticality and commenced power escalation. The unit completed the period at 90% power.
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RECENT SIGNIFICANT OPERATING EVENTS AND IDENTIFIED SAFETY CONCERNS a.
Sionificant Events (since April 1994) e On February 3, 1995, a unit 1 main steam atmospheric relief (13MS10) valve would not open in response to manipulation of controls. On February 10,1995, 22MS10 would not respond in automatic to steam pressure above the pressure setpoint. These problems were the latest in a long history of events with MS10 (and Hagan module) performance problems (including April 7,1994 event). Th iicensee did not initiate a thorough root cause until l
prompted,, the residents and Regional management. A thorough root cause, performed by a multi-disciplinary team, concluded that l
contributing factors included inadequate maintenance, vendor Salem PSR Page 5
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refurbishment, design, control of parts, and operator understanding of design contributed to the performance problems.
(IR 95-02, not yet issued.)
During late January 1995, Salem sought and was granted a Notice of e
Enforcement Discretion to address design deficiencies with the Solid State Protection System. Electrical components (e.g. limit i
switches and pressure sensors) associated with main steam, turbine controls, and feedwater were susceptible to rendering all or most of SSPS inoperable based on a single high energy line break. When unexpected power supply trips occurred during the modifications, 1
Region I withdrew enforcement discretion, j
e On January 11, 1995, with Salem Unit 2 in Mode 4, the no. 23 RCP i
seal water return valve for the no. I seal closed, isolating seal flow. The licensee determined that the pressure diaphragm of the ASCO solenoid valve failed because of its extensive time-in-service (about 20 years) coupled with the continuous air pressure applied at the diaphragm (about 80 psig). Plant staff planned to establish a periodic replacement schedule for the diaphrages.
Westinghouse recommended that PSE&G inspect the r.o. I seal. For safety considerations (avoiding reduced inventory) Salem management, after consulting with Westinghouse and other i
licensees, elected to perform the maintenance by lowering the RCP onto the " backseat" formed by resting the radial bearing on the thermal barrier heat exchanger. Salem maintenance completed the maintenance activity safely. Although they found no seal damage the licensee replaced the no. I seal package.
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In January 1995, the inspectors learned that Unit 2 operated the entire previous cycle (5/93 to 10/94) with a closed drain valve in
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a common drain line for the Pressurizer Safety Valve loop seals.
The valve should have been opened, but the licensee had not done an adequate post-modification lineup or adequate post-modification testing.' The 10 gallons of water in the loop seals would create thrust loading on the safety valve discharge piping with the potential to deform the pipe, restricting flow. As a result, the loop seals could render the safety valves incapable of protecting the RCS from overpressurization. This issue is a candidate for escalated enforcement. (IR 95-02, not yet issued.)
e In December 1994 and January 1995, during startup from the J
refueling outage, Sales Unit 2 pressurizer code safeties leaked past the seats due (apparently) to dead weight and thermal loading on the discharge piping. As a result, Salem spent the period from December 25, 1994 to January 10, 1995, determining the cause of the leakage. Salem replaced the code safeties, adjusted the piping, and, as of January 31, 1995, had successfully reached normal operating pressure with no code safety seat leakage. (IR 94-35) e Stuck trash rake affecting Unit 1; occurred several times. On November 15, 1994, the new rake stuck on the old trash racks in front of the 13B CW pump intake, forcing a power reduction to 850 MWe, On December 7, 1994, the new rake again stuck on the old trash racks in front of the 13B CW pump intake, forcing a power Salem PSR Page 6
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reduction to 850 Mwe. On January 3, 1995, the new rake stuck in front of 12B CW pump. On January 9, 1995, the old rake stuck in
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front of the newly replaced racks in front of 138 CW pump intake.
PSE&G replaced the racks in front of 13B CW pump, and plans to l
replace the racks in front of 12B and 11A by the end of February.
All other racks have been replaced at least once. (IR.94-31) i Unit 1 operators commenced a forced shutdown on January 6, 1995, e
due tc inoperable 1A Safeguards Equipment Controls (SEC). The l
power supply failed. Although the Alternate Test Insertion (ATI) l circuit had been turned on (see below) and had produced periodic l
alarms, the techs and operators did not pursue the alarms (due to e
previous experience) and apparently took a power reduction that could have been avoided. The licensee contracted an EMI l
specialist in mid-February to investigate the frequent ATI test i
faults. Engineering, supported by the EMI specialist, determined that EMI levels in the' SEC cabinet, although high enough to cause ATI alarms, do not impact the ability of the SEC to perform its 1
designed safety function. Engineering is actively pursuing the j
l EMI specialist's recommendations to improve the immunity of the i
ATI to EMI and to prevent future spurious ATI alarms. (IR 94-31) e Grass intrusion into unit 1 Circ Water on December 11, 1994.
Operators took 13B out of service to clean the water box. 13A i
j tripped on high d/p. Operators reduced power at 5% per minute. The 12B and 12A emergency tripped. Operators reduced power to 51%
l while restoring the 12A and 12B CW pumps to service. (IR 94-31) i a'
Unit 1 operators initiated an unplanned shutdown on December 9, l
e 1994, for inoperable Safeguards Equipment Control cabinets. The i
three SEC cabinets for each unit control sequencing.of safety j
related loads onto the 4kV vital busses. A stuck test switch (not t t j
immediately identified) caused a fault indication in the test circuit. Technicians took the test switch panel from the IB SEC to i
- aid in trouble-shooting 1A, and inadvertently caused a stuck j
switch in IB SEC. Operations and maintenance staff concluded that a common mode failure might exist, declared the SECS inoperable, i
and started the shutdown. The stuck switch in IA SEC existed from j
the previous surveillance on November 23, but operators did not a
detect the fault since they had taken the Automatic Test Insertion circuit out of service due to " nuisance" alarms. (IR 94-31) i t
e On November 28, 1994, no. 2 Station Power Transformer lost power l
as a result of a modification in the unit 2 control room actuating i
ground fault protective relaying. The worker performing the mod introduced a ground fault on the relay, in conjunction with an i
existing ground elsewhere on the ungrounded system (by design).
Also on November 28, 1994, the no. 5 substation in the 13 kV ringbus lost power, causing the TSC to lose power. The cause was j '.
insulators arcing over. The TSC diesel started, but the TSC l
ventilation failed to start as a result of a blown fuse. Fast i
transfers occurred successfully on both units.
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I Breakdown of insulation on 4kV supply cable to the unit I vital
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. buses (November 21,1994); caused by liquefied pulling compound dripping down onto the cable end between the dust boot and the heat shrink,-providing a lowered resistance from the terminal lug
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to the ground strap.
e On November 18, 1994, the 4T60 disconnect opened causing the no. 4 l
station power transform to de-energize, interrupting one source of offsite power to each unit. Loads fast transferred at Unit 1, but l
3 of 5 running circ water pumps lost power, requiring operators to red 1ce power. Unit 2 lost spent fuel pool cooling for 17 minutes l
since the other source of power was out due to the outage work.
1 No apparent increase in SFP temp. No apparent cause for the disconnect opening. Power was restored five days later using no.2 SPT.
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e On September 29, 1994, Salem Unit 2 operators initiated a manual reactor trip from 29% power following the inadvertent closing of two main steam isolation valves (MSIVs). The licensee was returning the unit to rated power following maintenance on one of 4
the charging p m s.
The operators were at the point in the power ascension procedure for closing main steam line drains. After acknowledging tLe order to close the main steam drains, the i
operator mistakenly closed two MSIVs. Operators initiated a r.anual trip.
(See IR 50-311/94-24) j D
On August 24, Unit 1 operators reduced power to 1% to repair the e
i condensate system suction header. The header sustained damage to a support pedestal and several expansion joints when operators 1solated.No.12 condensate pump to replace its mechanical seal.
l Pressure from back leakage through the closed pump discharge bypass valve generated sufficient force to shift the suction t,
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header. The licensee repaired damaged components and modified the.
condensate procedure to change the sequence of valve manipulations 1
operators follow when isolating a condensate pump.
(See IR 50-272/94-19) 4 l
e On July 14, 1994, Salem Unit 1 o erators initiated a manual
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i reactor trip from 100% power f 31 owing a complete loss of i
circulators. A lightning stru.e caused the Unit I circulator I
supply breakers to open on undervoltage. Operators responded correctly in tripping the reactor as condenser vacuum decreased i
rapidly.
(See IR 50-272/94-14) 1 On July 2,1994, the licensee identified an unisolable flange leak i
from an unused instrument line on the No. 22 reactor coolant pump (RCP). At the time of the discovery, the licensee was attempting to repair the flange. The licensee cooled down and depressurized the plant (taking the plant from Mode 3 to Mode 5). The licensee established a freeze seal. on the leaking line and replaced the i
existing flange and piping with a blank flange.
(See IR 50-
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311/94-14) 1 j
e On June 29, 1994, Salem Unit 2 experienced a reactor trip from j
approximately 6% reactor power due to low steam generator water level. Prior to the trip, while increasing power to 14%, a s
Page 8 Salem PSR 3
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l feedwater oscillation caused a high water level condition in one steam generator. The high steam generator water level initiated a t
feedwater isolation. The level oscillations occurred when the minimum flow valve cycled open and closed. The licensee changed procedures to improve operator control of the minimum flow valve.
The licensee also changed the gain in the valve controls. The l
operator reduced power to within the capacity of auxiliary l
feedwater; however, before water level could be stabilized in all generators, the no. 23 steam generator reached its low level 2
setpoint causing the reactor trip.
(See IR 50-311/94-14) e On June 10, 1994, while operating at 97% power, the Salem Unit I l
reactor autonatically tripped following a main generator trip.
The licensee concluded i. hat a potential transformer failed, i
causing the main generator output breakers to open, leading to the reactor 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) l e
On April 7, 1994, the Unit 1 operating crew rapidly reduced power l
in response to severe river grass intrusion at the circulating i
water intake structure. Salem Unit I tripped from 25% power j
during maneuvers to shut the plant down. Subsequent to the i
reactor trip, the plant experienced a series of safety injections which resulted in loss of the pressurizer steam bubble and normal pressur's control. In addition to the reactor trip and safety injections, certain valves that are required to operate, failed to close. On April 8, the NRC dispatched an Augmented Inspection Team to the site to review the causes and safety implications of l
the nultiple failures in safety-related systems during the event J
ar.d possible operator errors.
(See AIT Report 50-272/94-80 and 50-311/94-80) i b.
Assessment Unanticipated equipment deficiencies continue to dominate i
performance of the Salem units. In February, both units shutdown to correct design inadequacies with the Solid State Protection j
System. Problems with main steam atmospheric relief valve l
controls delayed unit I startup until February 27. Although operators restarted Unit 2 on February 11, low seal leakoff flow from the no. 21 Reactor Coolant Pump seal required a shutdown on l
February 19. As of January 31, Salem Unit I had continuously j
operated for more than 150 days, although Unit 1 operators had to reduce power six times in six weeks due to equipment problems from November 6, 1994 to December 17, 1994. On the other hand, the Salem units have experienced only one reactor trip in the six months beginning August 1, 1994, as compared with five trips in the period from February 1, 1994 to August 1, 1994. Operators have i
begun to take significantly increased ownership for plant performance and safety. Their involvement in insuring nuclear and i
personnel safety during the inspection of the no. 23 Reactor i
l Coolant Pump seal illustrates their leadership in identifying and j
preventing pitfalls in plant activities. Maintenance management l
identified that lack of supervisory oversight of job briefings had
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resulted in ineffective worker preparation for maintenance i
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t activities. Steps have been taken to improve the job briefings.
System engineering support for daily operations and maintenance activities continues to requirt significant improvement. While some improvement has been noted in design engineering support for daily activities, plant and design engineering senior management involvement was frequently required to force communication between the organizations. Plant support organizations continued to
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demonstrate excellence in their activities.
Overall, the number of challenges to uneventful Salem operations l
continued at a high rate in comparison to other plants, such as, l
Hope Creek. Senior PSE&G management has implemented a number of l
changes intended to address the need for change, including replacing the Chief Nuclear Officer, the Salen General Manager, the quality assurance and nuclear safety review manager, the r
station quality assurance manager, the mechanical maintenance t
l manager, the planning manager and the plant technical support j
manager. Senior PSE&G management met with Region I senior management on March 12, to present a proposed Salem l
reorganization. The new organization would add a unit I director l
and a unit 2 director reporting directly to the Salem general manager. The new organization would also add (for each unit): a i
l unit operations manager, unit senior nuclear shift supervisor, unit maintenance manager, unit planning manager, and unit outage planning manager. Sales management has taken steps to increase the emphasis on accountability from the Vice Precident of Operations down through all levels of management to the workers. Leon Eliason initiated a team of consultants and nuclear industry senior managers to determine why PSE&G actions to improve Sales performance have been ineffective. In addition, Mr. Eliason has t
l initiated a process to bring about a " step change" in Sales performance. This process is intended to hold managers accountable for achieving results, as opposed to past emphasis on generating r
activity. Although some examples of improved performance have occurred, especially in the areas of operations and maintenance, it cannot yet be determined whether PSE&G actions will result in lasting changes.
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Performance Indicator Data l
FOR AE00 TO UPDATE Units 1 and Unit 2:
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Recentiv Identified Technical Safety and Manaaerial Challenoes (of last 12 months)
The Salem unit 2 refueling outage, scheduled for 77 days, extended e
to 110 days as a result of equipment problems, including pressurizer code safety valves leaking past the seat.
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Both Salem units shutdown in early February 1995 due to inadequate design of the Solid State Protection System. A single steam line failure in the turbine building could have rendered boto trains of SSPS inoperable with the result that operators would have been required to manually initiate Safety Injection.
i Salem PSR Page 10 i
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Both Salem units suffered performance failures in the controls for the main steam safety atmospheric relief valves. These controle have a long history of inadequate control and maintenance.
In the most recent problems, the licensee again discovered unexpected i
components in the control circuits, demonstrating ineffective j
corrective action for the level IV violation after the April 7, i
1 1994, event.
A number of allegations with potential safety significance have e
been substantiated, including-inadequate PORY design, with the result that redundant o
capability to limit RCS pressure under low temperature I
conditions had not been assured (an USQ with the potential for escalated enforcement);
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o installation of non-Q limit switches in safety-related applications, two of the eight (for both units) head vent valves, with the result that repeat problems with safety related part controls raise programmatic questions about the Salem ability to control safety related maintenance (currently being reviewed for escalated enforcement); and incorrect Technical Specification definition of controlled f
o leakage, with the result that Safety Injection flow supplied to the core, in the event of a RCP seal supply line fr' lure during an accident, could have (and at times would ha/e) been less than assumed in the accident analysis (no violation was issued, since Salem was always in compliance with the Technical Specification 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 unsubstantiated, 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 valve in the pressurizer code safety valve loop seal drain line had been closed throughout the operating cycle from July 1993 until October 1994. The immediate safety implication is that the licensee could not assure, based on any analysis existing as of March 15, 1995, that the water hammer from the impact of the water in the loop seal on the valve discharge line would not deform the discharge pipe and restrict flow to less than that required by design. The licensee is currently performing an analysis to demonstrate that the valves could have performed their intended function, however, engineering stated that analysis will not be able to show that the thrust loads will be within code allowable limits.
e Service Wate;- (SW) Leaks: The licensee is completing a seven year pipe replacement project that will replace most (about 19,000 linear feet are safety related) of the safety related SW piping with 62 moly stainless steel. This project will probably continue through 1997. Currently, approximately 90% of the safety related Page 11 Salem PSR
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l portion of the project has been completed, including the majority l
of the SW piping in containment, diesel bays, SW intake structure, t
and auxiliary building. Based on NRC inspection, SW pipe replacement project is progressing satisfactorily as scheduled.
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Unit 2 Sustained Operation of Greater Than 100% Power: during the recent outage, the licensee confimed erosion of the feedwater l
flow nozzles resulting in incorrect online calorimetric data.
l Upon discovery, licensee immediately reduced power for both units, f
and began adjusting instrument setpoints to insure conservative operation. The licensee concluded that 102.5% was the exact power I
level and operating at that power level did not invalidate any of i
the UFSAR Chapter XV conclusions.
e Work Control Problems: During the Unit 2 refueling outage, the l
licensee and the NRC identified additional examples of failure to follow established procedures relative to the control of i
maintenance work activities. These examples were similar to those previously identified during the Unit 1 outage, November -
i December 1993.
In September, PSE&G named Leon Eliason as the new Chief Nuclear e
Officer (replacing Steven Miltenberger), and President of a newly structured nuclear business unit. Eliason's appointment was effective October 1, 1994. He reports directly to PSE&G Chairman s
Ferland. The nuclear business unit will encompass all operational and support activities for both Salem units and Hope Creek. Since October senior management has also appointed a new Salem general i
I manager and a new quality assurance and nuclear safety review manager; they have replaced the station quality assurance manager, l
the mechanical maintenance manager, and the planning manager. As discussed above senior PSE&G management met with Region I senior management on March 12, to present a proposed Sales rl reorganization. The new organization would add a unit I director i;
and a unit 2 director reporting directly to the Salem general manager. The new organization would also add (for each unit):
a unit operations manager, unit senior nuclear shift supervisor, unit maintenance manager, unit planning manager, and unit outage planning manager. Salem management has taken steps to increase the emphasis on accountability from the Vice President of Operations down through all levels of management to the workers. Leon Eliason initiated a team of consultants and nuclear-industry senior J
managers to determine why PSE&G actions to improve Salem performance have been ineffective. In addition, Mr. Eliason has initiated a process to bring about a " step changs" in Salem performance. This process is intended to hold managers accountable for achieving results, as opposed to past emphasis on generating activity.
e Grass Intrusion at Circulating Water Inlet Structure: The licensee documented this plant vulnerability for years, yet the condition continues to provide unnecessary plant challenges. An AIT was dispatched to the site on April 8, 1994, to investigate the plant transient that resulted from severe grass intrusion on Page 12 1
Salem PSR
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April 7.
The AIT concluded that the vulnerability of the design i
was previously recognized and modifications to improve the system had not yet been implemented.
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UnadJressed Equipment Problems: The staff documented numerous cases of known equipment deficiencies factoring significantly into Sales events. The AIT of April 1994 found that management allowed equipment problems to exist that made operations difficult for plant operators.
In an effort to improve management accountability and performance, o
in July 1994 PSE&G terminated approximately 55 non-bargaining unit members of the Nuclear Division for inadequate performance.
Eleven of the terminated employees were assigned to Sales.
Operators continue to face many challenges posed by equipment e
failures. Recent examples include the control air system, the emergency diesel generator air start system, and the main feedwater pump hydraulic control systems.
- 3. ESCALATED ENFORCEMENT ACTIVITIES The NRC issued a Level III Violation on March 8, 1994, documented e
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.
The NRC issued four Level III and two Level IV violations and e
imposed a Civil Penalty of $500,000 on October 5, 1994. The violations were documented in NRC Letter EA 94-112 and were based on the_ licensee's performance prior to and during the April 7, 1994 event.
On February 8, 1995, PSE&G met with NRC at Region I in King of e
Prussia to discuss the findings of the Office of Investigation relative to assertions of violations involving 10 CFR 50.5
" Deliberate Misconduct," and 10 CFR 50.7 " Employee Protection."
e On March 17, 1995, an enforcement panel will review three violations for potential escalated enforcement. The violations involve:
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failure to control materials used in safety related applications (non-Q limit switches installed in two reactor head vent valves);
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failure to control a modification to insure that it was correctly implemented (installing the loop drains for the i
pressurizer code safety without insuring that the drain j
valves were properly aligned, or insuring that post modification testing verified that the drain performed its j
intended function); and a repeat failure to comply with the Technical Specification o
action statement requirement for an inoperable PORV.
i Salem PSR Page 13
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- 4. IPE INSIGHTS I
Sales submitted its IPE to the NRC in July 1993; the document is e
still under NRC review.
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2 Page 14 Salem PSR 1
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Ill. ANALYSIS / ASSESSMENT
- 1. PREVIOUS SALP RATINGS AND OVERVIEW
- a. Previous SALP Ratinos Functional Area June 19. 1993 November 5. 1994 Operations 2
3 Maintenance /
2 3
Surveillance Radcon 1
N/A Emergency Preparedness 1, Declining N/A Security 1
N/A SA/QV 2
N/A Engineering & TS 2
2 Plant Support N/A 1
Current assessment period: November 5, 1994 to March 9, 1996.
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SALP Overview (derived from the s -nary paraaraoh of each SALP
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igetion):
OPERATIONS On January 12, 1995, the SALP board met to discuss PSE&G's performance at Salem during the period from June 19, 1993 to November 5, 1994. The board concluded that operators generally responded appropriately with good command and control to the many plant trips and operational transients that occurred over the SALP period. Likewise, they demonstrated good proficiency in making emergency declarations for events for which such declarations should have been considered. However, performance over the assessment period demonstrated significant weaknesses in several areas.
Operators did not practice ownership of the plant and did not aggressively enlist other plant departments to resolve longstanding equipment problems which frequently challenged them in normal and upset plant conditions. A lack of an appropriate questioning attitude by operators resulted in anomalous indications, or conditions being unnoticed or not understood and a
not being acted upon. A lack of guidance for and training of operators on operability decisions resulted in some decisions being nonconservative or having weak technical bases. Examples of nonconservative approaches to entering and exiting LCOs occurred over the period. Some difficulties were experienced managing ar.d controlling outage activities. Poor self assessment within the Operations department coupled with ineffective independent assessment of Operations by the Quality Assurance and Nuclear Safety Review organization contributed to the continuation of performance l
prnblems throughout most of the period.
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f MAINTENANCE / SURVEILLANCE The board concluded that performance weaknesses were evident in maintenance programs and activities, such as procedural adherence and adequacy, the feedback process, specification of post-maintenance testing j
requirements, and control of work activities by numerous onsite groups.
Management has improved its safety focus in prioritizing and scheduling i
maintenance activities. However, management oversight of corrective l
action program activities has been weak as evidenced by the high recurrent I
equipment failure rates. Inconsistencies in troubleshooting activities and root cause analysis contributed to the delay in correcting recurring problems. Material condition of the plant continues to improve, but there remain several areas that need improvement. Although the in-service testing program was adequate, management did not effectively resolve self assessment findings. Programs for in-service inspection, erosion / corrosion and steam generator leakage monitoring were adequately implemented.
a ENGINEERING l
l The Board concluded that Engineering performance was inconsistent, with substantial variation in quality. The quality of the discipline design work was good, with significant engineering management focus shown in several modification activities. However, engineering work priorities did not always reflect plant needs. In several significant programmatic areas in which the Engineering organization had an important role, performance was, on balance very good. Significant problems, nonetheless were noted associated with root cause assessments and with equipment problem resolution. The fact that there existed engineering capability, that when focused by station management and brought to bear on important issues, demonstrated the ability to achieve very good performance, suggested that a significant aspect of the problem was associated with the effective i
engagement of available engineering expertise in activities important to i
safe plant operations, such as in root cause assessment and equipment problem resolution.
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PLANT SUPPORT The Board concluded that plant support functions contributed effectively to safe plant performance. Performance in the radiation protection area continued to be a significant licensee strength. Well trained technicians and staff coupled with effective management resulted in aggressive ALARA program implementation with significant dose savings realized. Excellent performance in the radiological environmental monitoring and effluent control programs was again noted. There was continued good performance in l
the emergency preparedness area. Security program performance continued to be a strength. Fire protection program implementation was substantially improved.
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e 2.
LICENSEE RESPONSE TO PREVIOUS SALP FUNCTIONAL AREA WEAKNESSES /RECENT LICENSEE PERFORMANCE TREES (in the last year) e OPERATIONS The licensee response to the SALP did not provide detailed information on I
plans to address performance inadequacies. The response generally agreed with the NRC's assessment of Sales performance. In addition, the response stated an intent bn to correct Sales performance problems. Since the response letter was issued, senior PSE&G management has initiated an
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effort to determine the cause of the ineffectiveness of previous I
corrective actions.
In addition, PSE&G management proposed reorganizations of several organizations (discussed in more detail below),
and implementation of a " step change" process intended to produce results, rather than activity without results.
The proposed re-organization would quickly bring the unitization concept l
to fruition for Salen Operations. Two plant directors (one for each unit) would report to the Salem General Manager. In turn, two operations managers (one for each unit) would report to the directors, and each operations manager would have responsibility for a unit operations department, including a Senior Nuclear Shift Supervisor and the shift l
complement necessary to support operation of that unit. It is important to note that, as of March 15, the licensee had not reached a final l
l conclusion to implement the propose organization.
In response to the April 7 event, Operations management provided improved guidance to operators for command and control and conservative operation l
of the plant.
In response to NRC concerns, Operations management developed a flow chart for operability determinations.
Inspectors have occasionally noted weak or incorrect interpretation of Technical Specifications.
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The inspectors have also noted that the Operations Manager has convinced the department staff that change is necessary, and fostered an increasing I
sense of ownership and tsam work.
l e MAINTENANCE AND SURVEILLANCE l
Secondary / BOP equipment deficiencies pose significant challenges to plant operations, e.g. manway failure, condensate header damage, COPU filter l
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replacement, CW travelling screens, FW feed control at low power levels.
In order to improve overall performance and response to emergent issues, PSE&G reorganized the Maintenance Department. Changes included replacing the single Maintenance Manager role with three new positions:
1)
Mechanical Maintenance Manager, 2) Controls Maintenance Manager, and 3)
Planning Manager. PSE&G began to unitize these departments. The proposed (as of March 15) reorganization would further unitize maintenance planning management structures. As of March 15, unit I and unit 2 had separate i
outage planning managers. The~ proposed reorganization would provide I
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separate (non-outage) planning managers and maintenance managers for each unit, reporting to the unit directors for their respective units. The i
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l, unit maintenance managers would oversee mechanical, electrical and I&C maintenance for their respective units (recombining the disciplines under one maintenance manager for each unit).
To address the existence of lang standing equipment problems, plant management required operators to develop a list of workarounds to be addressed by maintenance personnel in accordance with assigned priority.
e ENGINEERING AND TECHNICAL 10PPORT Salem and corporate engineering have not consistently communicated well with operations, nor has operations communicated well with engineering.
System engineering has not effectively prioritized their workload, nor have they effectively monitored equipment reliability, as demonstrated by e
the "workaround" list generated in response to this NRC identified concern. The system engineers did not receive training on operability or Generic Letter 91-18 until September 1994.
An NRC observation related to the Salem rod control issue was that the initial troubleshooting efforts lacked clear leadership aPf delegation of responsibilities. This resulted in the efforts narrowly focusing on the most recent system malfunction without adequate attention to the repetitive nature of the failures and the need to determine and correct the root cause. The failure of PSE&G to determine the root cause of the failures resulted in numerous aborted startup attempts. The team did observe significant improvements in the control of troubleshooting and root cause determination during the inspection. A management oversight team was initiated to review all I&C troubleshooting activities in an effort to reduce events caused by troubleshooting.
In late February 1995, PSE&G announced a reorganization of the Nuclear Engineering department (corporate engineering). PSE&G management redirected resources no longer required.to support the Salem revitalization project (since it would be substantially complete in 1995) to better support Sales and Hope Creek operation. The effects of this reorganization have not yet been demonstrated.
In addition, Sales management rotated the Technical Support manager to the Quality Assurance and Nuclear Safety Review department to provided improved oversight of Quality Assurance and corrective action programs.
Sales management had not named a permanent replacement Technical Support 1
manager as of March 15.
e PLANT SUPPORT The NRC noted that PSE&G continued to perform at a noteworthy level in the area of radiological protection through the end of 1994, especially during the recent Unit 2 refueling outage.
The licensee's annual partial-participation emergency preparedness exercise was conducted on June 23, 1993. On-site response to the 1
simulated emergency was very good. An exercise strength was Emergency i
Response Manager command and control. No exercise weaknesses were identified. Significant areas for potential improvement were maintenance
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l team tracking from the Operational Support Center and public address system operability in the Technical Support Center.
The PSE&G security program continues to be effectively directed toward3 public health and safety. However, certain assessment aids have
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deteriorated to the point where maintenance was no longer effective.
SAFETY ASSESSMENT / QUALITY VERIFICATION e
l In July 1993, the licensee formed a Comprehensive Performance Assessment l
team (CPAT) which conducted a special assessment of safety issues and I
The recent plant events using an integrated MORT investigatory analysis.
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 area.
3.
LICENSEE PERFORMANCE STRENGTHS AND WEAKP5SSES
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Sales performance continues to be inconsistent.
Capacity factor has been low due to refue1 % outages at both units and i
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numerous forced outages and power reduc +.ioin resulting from problems with SPPS, MS-los, pressurizer code af>ty valves, rod control, and to support PORV replacement as well as icipment modifications following the April 7 event. Grass fouling of c.culators and numerous plant trips contribute to the low capacity factor as well.
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Strengths:
e The licensee continues to increase resources for a material condition improvement program. The NRC has observed noticeable improvement in the I
material condition of the plant, indicating that the licensee has been earnest in the implementation of improvements.
Radiation protection program implementation cont..)ues to be very strong.
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l e When problems or conditions are self-identified and self-detected, event response and root cause determination are through and comprehensive, In other particularly when the matter is the subject of NRC attention.
cases, the licensee's performance is considered weaker, as identified i
J below.
e PSE&G has responded to identified performance and management weaknesses relative to approach to problem resolution by initiating the following actions:
PSE&G senior management has replaced the mechanical maintenance manager, l
e the planning manager, QA manager with personnel from within the PSE&G l) organization, and has filled the General Manager position and the 1
Quality Assurance and Nuclear Safety Review position with new personnel from outside the comp:ny. In addition, PSE&G management proposed reorganizations of several organizations and implementation of a " step change" process intended to hold managers accountable for producing results.
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e Verifying the effectiveness of numerous supervisors and managers and changing the incumbent when deemed appropriate; i
e Pursuing unitization of the operations organization; maintenance and planning organizations are unitized.
e Implementing the existing performance assessment tools to improve accountability frem the highest levels of management down to rank and file workers-e Forming dedicated teams to implement the corrective actions developed in response to the CPAT findings.
Weaknesses:
Salem performance continues to be weak in:
- Planning e Control of maintenance; e System Engineering and Technical Support e The ability to do root cause determination; e Corrective action effectiveness due to inadequate root cause assessment; Inadequate approach to problem resolution (i.e., general tende w to fix e
problems or conditions based on the most probable cause withour, assessment or understanding of all possible causal factors.) Examples include, but are not limited to: maintenance and modifications to the atmospheric relief valves, problems with main feedwater regulating valve controls and feedwater pumps, maintenance of the Safeguards Equipment Control systems, and initial response to cracked diesel liner issues, failv,e to identify elevated reactor power in 1992, and failure to recognize generic implication of rod control problems.
- 4. NRC TEAN INSPECTIONS WITHIN THE LAST YEAR 1
Area /Date Findinas I
Augmented Inspection Team (AIT)
An AIT was formed to review causes and safety implications associated April 15-16,1994 with a series of malfunctions experienced during a plant transient i
and subsequent trip.
Customized Inspection Program Team The team concluded that increased August 15-16, 1994 inspection is warranted in the areas of maintenance and control systems.
Also expressed concern about licensee failure to proactively correct equipment deficiencies before they laad to plant events.
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e, SWSOPI-Report on licensee's assessment not September 5-23, 1994 yet issued.
Monitoring of Licensee's 3
Self-Assessment 1
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l IV. INSPECTION PROGRAM STATUS I
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- 1. STATUS OF INSPECTIONS j
l The inspection program status is reflected in attached MIPS report #2.
The data is current as of the date of the MIP. The MIP indicates that inspection program is on-track with the planned resource allotment; no significant shift in inspection activities is warranted.
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- 2. PROPOSED CHANGES T0 MIP e Unit 1 A'
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e Unit 2
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- 3. $1GNIFICANT ALLEGATIONS A m INVESTIGATIONS i
Three Salem allegations are related to or resulted from a December 3,1992 altercation between two SRG engineers and the former General Manager (GM),
Operations Manager (OM), and, to a lesser extent, the Manager-Quality Assurance & Nuclear Safety Review (QA&NSR).
OI substantiated harassment and intimidation (H&I) in this case. Enforcement conferences were conducted with the licensee and the affected managers on February 8 & 23, 1995. Some of these managers engaged in willful misconduct (pre-decisional). Enforcement action is pending.
Since the licensee's effort to terminate several employees for poor performance on July 18, 1994, the Region has received additional multifaceted allegations from two terminated employees that are currently 3
under review. One of these pertained to 23 separate management, operations, and engineering concerns. These were presented to NRC personnel in a face to face meeting on August 8, 1994. One concern pertaining to the low pressure over protection system (POPS) was substantiated.
Inadequate design compromised the redundant capability of the PORVs to limit RCS pressure under low temperature conditions. An enforcement panel agreed to proceed with additional action after 01 completed its review of potential willful misconduct and harassment and intimidation issues. An additional multifaceted allegation involved both technical issues and potential H&I issues. This allegation concerns six technical issues raised regarding the environmental oualification rf equipment. Currently, the EQ issues are being review 3d by DRS and the Salem PSR Page 22
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wrongdoing issues are being reviewed by 01. This allegation also involved i
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a terminated employee. The NRC received this allegation from senior PSE&G management.
i Additional allegations with potential safety significance have been substantiated. Non safety related limit switches were installed in two of eight reactor vessel head vent valves (safety-related application), and an
'i incorrect Technical Specification definition of controlled leakage, with the result that Safety Injection flow supplied to the core, in the event l
of a RCP seal supply line failure during an accident, could have (and at times would have) been less than assumed in the accident analysis (no l
violation was issued, since Salem was always in compliance with the j
Technical Specification requirements).
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Collectively, these allegations implicate the previous station management's ability to personally resolve and address safety issues.
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Regarding the December 1992 altercation, this incident and the two related allegations appear to be due to management's confrontational attitude with QA&NSR personnel. Since these managers have been replaced, this concern I
appears to have dissipated. The EQ allegation and its 01 component, and the 8/94 allegation appear to stem from a tendency cf PSE&G to manage by i
memo. They are not effectively using their root cause programs.
Management's failure to identify and 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 i
continuing concern.
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- 4. OPEN ITEN STATUS i
BACKLOG /No. GREATER THAN 2 YRS l
(Unit I and 2 - Common) 62/7 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.
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OUTSTAWING LICENSING ISSUES e GL 89-10 (MOV) - technical differences between NRC/PSE&G.
(Hope Creek also) e EDG amendment - meeting held May ll, 1992 to resolve issues.
2 e TS amendment to resolve AFW/ containment spray issue (see Section II.2.a).
e Increase in surveillance test intervals and A0T for reactor trip and ESFAS.
- Install new digital feedwater control system.
e Evaluation of Control Room Design Deficiencies that were not corrected.
l-e Bulletin 88-08 (Thermal Stress in Piping Systems Connected to the RCS) -
licensee is revising their response.
Salem PSR Page 23
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LOCAL / STATE / EXTERNAL ISSUES a.
NJ DEPE/BNE e Now providing input / comments on all PSE&G licensing change requests.
e High interest in resident inspection accompaniment.
e Continuing interest in Salem cooling tower issue: When Salem's renewable variance for the use of the Delaware River as a heat sink came up for renewal in 1984, New Jersey en41ronmentalists appealed to the state to not renew the variance.
In 1990, NJ DEPE issued a " draft order" requiring PSE&G to build two cooling towers to support the Salem l
inits' operation. PSE&G responded to the state's order with a 56-volume emnt, and the issue is currently under review by NJ DEPE. Recent NJ DEPE decision not to require cooling towers.
e State inspectors generally accompany all AIT efforts.
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Other (Recent Media Interest) e Large interest in recent AIT (April 26,1994) exit meeting and subsequent enforcement conference (July 28,1994). Several local television and newsprint representatives attended. Also, the conference was attended by representatives of Senator Biden's staff.
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I SALEM EXECUTIVE SUMARY i
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LICENSEE PERFORMANCE STRENGTHS A.@ WEAKNESSES j
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Sales performance continues to be inconsistent.
i e Capacity factor has been low due to refueling outages at both units and j
numerous forced outages and power reductions resulting from problems with SPPS, MS-10s, pressurizer code safety valves, rod control, and to i
a support PORV replacement as well as equipment modifications following the April 7 event. Grass fouling of circulators and numerous plant trips contribute to the low capacity factor as well.
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Strengths:
i 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 m ast in the implementation of improvements.
I o Radiation protection program implementation continues to be very strong.
e When problems or conditions are self-identified and self-detected, event response and root cause determination are through and comprehensive, particularly when the matter is the subject of NRC attention.
In other cases, the licensee's performance is considered weaker, as identified below.
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e PSE&G has responded to identified performance and management weaknesses relative to approach to problem resolution by initiating the following j
actions:
4 e PSE&G senior management has replaced the mechanical maintenance manager, the planning manager, the technical support manager, and the Salem QA manager with personnel from within the PSE&G organization; and has j
filled the General Manager position and the Quality Assurance and Nuclear Safety Review position with new personnel from outside the company.
l e Verifying the effectiveness of numerous supervisors and managers and changing the incumbent when deemed appropriate.
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i Pursuing unitization of the operations organization; maintenance and e
4 planning organizations are unitized. Additional changes have been proposed to further unitize operations, planning, and maintenance managers below the proposed plant directors.
l e Implementing the existing performance assessment tools to improve accountability from the highest levels of management down to rank and 1
file workers.
e Forming dedicated teams to implement the corrective actions developed in response to the CPAT findings.
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- Initiating a team of consultants and senior managers from other i
utilities to detemine the cause of the ineffectiveness of PSE&G j
corrective actions for Sales to date.
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2 e Developing a " step change" process intended to hold managers accountable for achieving measured performance improvements.
Weaknesses:
Sales performance has been weak in:
e Planning.
Sales unnecessa.-11y rendered an entire train of Service Water inoperable for a valve repair that didn't need to be done, and didn't get completed.
l Sales planned maintenance on an EDG to trouble shoot a non-safety portion I
of the test controls, without determining if parts were available; this
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extended the time in the LCO.
e Control of maintenance.
Level III violation in the Unit 2 outage for lack of procedure adherence and lack of tagging control. Mechanics changed the oil in the wrong componer.t in the AFW pump, and unintentionally " adjusted" the overspeed i
trip test device. The Salem Unit 2 PORVs were replaced with the " wrong" l
internals (not the parts intended). The correct internals were l
subsequently installed during the recent Unit 2 outage.
l e Engineering and Technical Support.
System engineering has poorly trended equipment reliability (for example, the Diesel air start system, the control air system).
t Engineering (corporate and system) has not communicated well with operations (for the most part, the operators don't know who they are).
System engineering has not been involved in operability decisions, and r
i was not trained on operability (Generic Letter 91-18) until I made a big issue out of it.
- Recognition of the need to do root cause determination.
l e Corrective action effectiveness due to inadequate root cause assessment.
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l Inadequate approach to problem resolution (i.e., general tendency to fix e
problems or conditions based on the most probable cause without assessment or understanding of all possible causal factors.
Examples include, but are not limited to the licensee's initial response to cracked diesel liner issues, failure to identify elevated reactor power in 1992, and failure to recognize generic implication of rod control problems.)
l GENERAL OBSERVATIONS:
Organization may not have sufficient level of knowledge relative to managing change based on observations by DRP and DRS inspectors.
Until recently, the Salem organization never engaged in attempting to benchmark itself relative to other utilities, including Hope Creek.
l New emphasis on accountability, ownership of problems.
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The July 1994 termination of 50-60 personnel appears to have been well received (by those who were not terminated). Generally positive comments from remaining staff acknowledging that there were several weak performers that failed to contribute to overall quality or safety.
i While J. Hagan has been pushing for more supervisory field time, increased first line supervisory presence is not very apparent. However, there is a i
i noticeable increase in the presence of middle management level personnel.
There are several examples recurring problems in B0P (service air, and feedwater) and some safety-related systems (EDG air start) have the potential to affect nuclear plant performance.
It is not clear, that the maintenance organization and system engineering organizations understand and appreciate the need to change. Unable to agree on meaningful improvement strategy unless imposed from the top down. Passive attitude seems to exist relative to change. Taken up with day-to day crisis maragement. Still tend to focus on most immediate proximate causes associated with an event.
While management is driving change, noticeable improvement in plant performance and personnel attitude and enthusiasm for determining and implenenting improvement strategies and plans is not yet apparent.
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