Text

Insp Repts 50-272/93-15,50-311/93-15 & 50-354/93-11 on 930418-0605.One Noncited Violation Noted.Major Areas Inspected:Operations,Radiological Controls,Ep,Security,Maint & Surveillance Testing & Engineering/Technical Support
	ML18100A481
Person / Time
Site:	Salem, Hope Creek
Issue date:	07/12/1993
From:	Jason White; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML18100A480	List: IR 05000272/1993015; ML18100A479;
References
	50-272-93-15, 50-311-93-15, 50-354-93-11, NUDOCS 9307200052
	Download: ML18100A481 (40)
	v • d • e

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report Nos. 50-272/93-15 50-311/93-15 50-354/93-11 License Nos. DPR-70 DPR-75

- NPF-57 Licensee:

Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge,* New Jersey 08038 Facilities: -

Salem Nuclear Generating Station Hope Creek Nuclear Generating Station Dates:

April 18, 1993 - June 5, 1993 Inspectors:

T. P. Johnson, Senior Resident Inspector S. M. Pindale, Resident Inspector S. T. Barr, Resident Inspector H. K. Lathrop, Resipent Insp or J. G. Schop

, J esiden nsp tor T.H.B, e

~r Approved:

J. R Inspection Summary:

This inspection report documents inspections to assure public health and safety during day and backshift hours of station activities, including: operations, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering/technical support, and safety assessment/quality verification. The Executive Summary summarizes the inspection findings and conclusions.

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EXECUTIVE SUMMARY Salem Inspection Reports 50-272/93-15; 50-311/93-15

' Hope Creek Inspection Report 50-354/93-11 April 18, 1993 - June 5, 1993 OPERATIONS (Modules 60710, 71707, 71710, 93702)

Salem: The licensee effectively reloaded the Unit 2 reactor core. The inspector performed an engineered safety feature system walkdqwn and verified operability of the containment spray system and the containment fan cooling systems. The inspector closed an open item regarding the shutdown margin monitor. An unresolved item was opened as a result of the inspector's concern involving the inoperability of the Unit 2 steam-driven auxiliary feedwater pump. PSE&G implemented and properly performed the necessary fire protection compensatory measures when the operability of certain cable wrap materials was questioned by the NRC. Salem Operations appropriately performed all work and tests necessary to conclude the Unit 2 seventh refueling outage, however, four startup attempts, between May 26 and June 2, 1993, were aborted due to problems with the rod control system. The licensee restarted the unit again on June 4 without having an understanding of the cause of the previous rod control system problems. However, upon discussion with the NRC and Westinghouse (the vendor of the rod control system), the licensee shutdown the unit on the same day to effect resolution of the rod control system problems. On June 5, the NRC dispatched an Augmented Inspection Team (Report No. 50-272 and 311193-81) to investigate the rod control system problem Hope Creek: The licensee operated the Hope Creek unit safely. The licensee appropriately responded to a partial loss of off-site power which caused a rapid reactor power reduction and emergency diesel generator starts. A failed relay in the electrohydraulic control system resulted in a reactor scram on high pressure on May 16, 1993. The licensee's follow-up activities were thorough and effective. The inspector noted that reactor restart activities were well controlled. The inspector closed an open item regarding electrical power sources. The

licensee has adequately implemented operator guidance and training regarding potential vessel water level errors associated with rapid depressurization transients. The inspector verified that the high pressure coolant injection system was appropriately aligned for automatic initiation. The licensee appropriately addressed an issue they identified associated with overheating of microswitches used for indication on various pieces of safety related equipment. The licensee appropriately responded to a single control rod scram on June 2, 199 Common: The inspector closed an open item concerning the fire protection program. The licensee is appropriately addressing another failure of one of two Salem diesel fire pump ii

RADIOLOGICAL CONTROLS (Modules 71707, 93702)

Salem: Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requirement During routine Unit 2 containment tours, the inspector noted good radiological controls and professional conduct by radiation protection technician Hope Creek: Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requirements. During a tour of the drywell the inspector also noted good radiological controls. Improper entry by an individual into the radiological control area is a licensee identified rion-cited violatio Common: The licensee demonstrated a proactive and thorough approach when they identified and investigated a situation involving duplicate thermoluminesence dosimeter MAINTENANCE/SURVEILLANCE (Modules 61726, 62703, 72700)

Salem: The inspectors observed maintenance and surveillance-testing activities and concluded that they were appropriately performed. The inspector closed open items dealing with water-tight doors, surveillance testing, and measuring and test equipment. The inspector reviewed and observed the maintenance and testing of the 2B emergency diesel (EDG) generator, including its generator replacement and dedication testing, and determined the work was well performed and the EDG was properly returned to an operable status. The inspector reviewed the licensee's actions following an inadvertent safety injection signal on April 15, 1993, during surveillance testing, and concluded that the licensee's follow-up and corrective actions were adequat Hope Creek: The inspectors observed maintenance and surveillance testing activities and concluded that they were appropnately performed. The inspector closed an open item concerning a valve wiring erro EMERGENCY PREPAREDNESS (Modules 71707, 93702)

The inspectors did not have any significant finding SECURITY (Modules 71707, 93702)

The inspectors determined that the licensee appropriately implemented security program requirement * *

_ ENGINEERING/TECHNICAL SUPPORT (¥odules 71707, 71711).

Salem: The inspectors. identified concerns and an unresolved item regarding the failure of emergency diesel generator injector bolts, including operability determinations; root cause investigation adequacy and 10 CFR 21 applicability. The licensee appropriately responded to a contractor eleetrician personnel error which caused a loss of a vital bus during outage*

modification work. Long-term corrective actions concerning fuel rod* defects, caused by grid-to-rod fretting, is unresolved. The licensee appropriately responded to containment fan coil units' (CFCU) performance. Once identified and thoroughly documented~ the licensee appropriately responded to concerns regarding. CFCU configuration, installation and operability. The inspector closed open items concerning pressurizer power operated relief valves actuator diaphragm classification, switchgear transformer failures, emergency diesel generator troubleshooting activities, temporary modific_ations during emergency work, and a 10 CFR Part 21 issue relative to core cooling adequacy. The inspectors reviewed a personnel error event in which contractor electricians pulled cable through a wrong conduit.

and shorted a 480 volt motor control center. No personnel injuries occurred but some damage was sustained. The licensee performed adequate root cause and determined appropriate corrective actio Hope Creek: The inspectors noted that engineering personnel properly prioritized work activities. The inspector closed open items concerning the high pressure coolant injection system flow controller setpoints and tolerances, and instrumentation for the filtration, recirculation and ventilation system.*

SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 30702, 40500, 71707, 90712, 90713, 92701, 94702)

Salem: The inspector closed an open item concerning control room habitabilit Hope Creek: Significant Event Response Team activities were timely and effective for the partial loss of electrical power and reactor scram event Common: The inspector determined that the Station Operations Review Committee (SORC)

membership and qualification requirements were appropriate. Licensee Quality Assurance/Nuclear Safety Review groups demonstrated positive contributions to improve nuclear safety relative to open item tracking, process efficiency, and design enhancement procedures. The licensee's initial response to NRC Bulletin 93-02, concerning debris plugging of pump strainers, was determined to be appropriate. However, the bulletin remains open pending submittal and NRC review of the licensee's engineering analysi Upon a tour of the drywell to check for loose debris which could clog emergency core cooling system or residual heat removal suction strainers, the inspector noted th.at there was *

minimum potential for foreign material to clog system strainers. The deficiency identification and corrective action administrative procedures are unresolved pending completion of licensee identified corrective actions and procedure enhancement iv

TABLE OF CONTENTS EXECUTIVE SUMMARY...................................... ii TABLE OF CONTENTS *...................... :................ v SUMMARY OF OPERATIONS............................... 1 Salem Units 1 and 2.................................. 1 Hope Creek....................................... 1 OPERATIONS......................................... 1 Inspection Activities. *................................. 1 Inspection Findings and Significant Plant Events............... -.

2.2.1 Salem...................................... 1 2.2.2 Hope Creek..... *......... -..................... 5 2.2.3 Common.*.................. *.................

12 RADIOLOGICAL CONTROLS..............................

12 Inspection Activities.................................

12 * Inspection Findings.................................

3.2.1 Salem..................................... * 13 3.2.2 Hope Creek......................."..........

3.3.3 Common..................... *..... :.. *.....

13 MAINTENANCE/SURVEILLANCE TESTING............. ~......

14 Maintenance Inspection Activity.................... *....

14 Surveillance Testing Inspection Activity.....................

15 *

4. 3 Inspection Findings............ *.....................

.4.3.1 Salem................................ :....

4.3.2 * Hope Creek.................................

18 EMERGENCY PREPAREDNESS............................

18 Inspection Activity...... ~...........................

18 Inspection Findings............................. :...

18 SECURITY... *.......................................

19 Inspection Activity.. -....................,...........

19 Inspection Findings..................................

19 ENGINEERING/TECHNICAL SUPPORT.......................

7.1 Salem............................ *...............

19 Hope Creek........................................

v

. TABLE OF CONTENTS (CONTINUED) SAFETY ASSESSMENT/QUALITY VERIFICATION................

26 Salem

.........................................

26 Hope Creek....................... ;....... *........

27 Common........................................

27 LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOW-UP............................

9.1 LERs and Reports.................................. * 30 Open Items......................................

1 EXIT INTERVIEWS/MEETINGS.................. '..........

1 Resident Exit Meeting... *....................... ~....

1 Specialist Entrance and Exit Meetings......................

1 Management Meetings...............................

ATTACHMENT I........................................... 34 Vl

- *

DETAILS

- SU1\\1MARY OF OPERATIONS Salem Units 1 and 2 Salem Unit 1 operated at or near full power, except for load reductions due to condenser differential temperatures and periodic circulating water system cleaning to remove grass from screen Salem Unit 2 began the period defueled. The seventh refueling outage continued during the period. The licensee refueled the unit and initiated mode changes. The licensee made four attempts at reactor startup that were aborted due to rod control problems. Consequently, an Augmented Inspection Team was dispatched to the site to review and evaluate the occurrences on June 4, 1993. The Unit was in Mode 3 at the end of this perio.2 Hope Creek The Hope Creek unit began the period at full power. On May 13, 1993, a partial loss of off-site power caused the unit to reduce power to 40%. Subsequently, on May 16, 1993, the unit scrammed on high reactor pressure and the licensee commenced a forced outage and restarted the unit on May 19. The unit operated at power for the remainder of the perio.

OPERA TIO NS Inspection Activities The inspectors verified that Public Service Electric and Gas (PSE&G) operated the facilities in conformance with regulatory requirement The inspectors evaluated PSE&G's management control by* direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical Specification compliance, and review of facility records. The inspectors performed normal*

and back-shift inspections, including deep back-shift (70 hours8.101852e-4 days 0.0194 hours 1.157407e-4 weeks 2.6635e-5 months ) inspection.2 Inspection Findings and Significant Plant Events 2.2.1 Salem Unit 2 Core Reload During the period, May 1-3, 1993, the licensee reloaded the Unit 2 core. The inspectors monitored portions of the fuel movements from the control room and reviewed implementation of ~ppropriate procedure and Technical Specification requirements. In particular, the inspectors ensured that the following items were met: * * A senior reactor

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--

..

operator in charge of fuel movements was present continuously; adequate communication was established; and source range instrumentation was operable. The inspectors noted effective command and control of core reload activitie Firewatch Rounds Added to Compensate for Questioned Fire Barrier Materials During the week of May 17-21, 1993, a NRC Region I inspection team identified concerns with the qualification of the firewrap material (Kaowool, 3M FS-195 and 3M Interam E-50)

used to separate safety-related cables at Salem Units 1 and 2 (see NRC Inspection 50-272 ::ind 311/93-80). Pending the engineering resolution of the concerns, PSE&G considered the operability of these fire barriers indeterminate and instituted the required compensatory measures. The coml>ensatory measures included the identification of the areas where the questionable firewrap was used, and. the posting of a roving or stationary firewatch in those area The inspector reviewed the engineering drawings which document where the Kaowool and 3M firewrap materials are used at Salem and then reviewed the postings of Site Protection firewatch personnel to assure those areas were covered by the appropriate compensatory measure. The inspector toured the Salem auxiliary building in order. to observe the firewatch *

personnel perform their rounds and to interview those personnel to. verify their awaren.ess of firewatch responsibilities. The inspector concluded that the licensee had implemented the proper compensatory measures and they were adequately being carried ou Engineered Safety Feature (ESF) System Walkdown The inspector independently verified the operability of the containment spray system and the containment fan coil units (CFCUs). The inspector performed the walkdown to confirm that system lineups and procedures matched plant drawings and the as-built configuration, and to *

identify adverse equipment conditions which could degrade performance. The inspector performed the review in accordance with NRC Inspection Procedure 7171 The inspector reviewed the FSAR, Technical Specifications, 10 CFR 50 Appendix A, applicable information notices and generic letters, and industry codes and standards. The inspector examined the licensee's configuration baseline documentation (CBD), surveillance tests, operating procedures, and in-plant system lineups. The inspector verified that the containment spray system and CFCUs were designed, operated and maintained in accordance with the above directive The inspector discussed the material condition of the containment spray system and minor differences between the tagging request inquiry system (TRIS) and the in-plant configuration with the cognizant system engineer. The inspector observed good housekeeping practices in the areas inspecte Based on the above, the inspector concluded* that the containment spray system and CFCU s *

are operable and capable of performing their intended safety function Inoperable Auxiliary Feedwater Pump During Unit 2 Power Ascension During the 2R7 (Unit 2) refueling outage, PSE&G 'performed maintenance and re-built the turbine on the steam-driven No. 23 auxiliary feedwater (AFW) pump. Following the completion of this maintenance, *the licensee left the turbine un-coupled from the pump, in preparation for the overspeed trip test of the turbine which is done in Mode 3 (Hot Standby)

when adequate steam pressure is available. Unit 2 entered. Mode 3 at 4:20 a.m. on May 20, 1993. Later that day, while preparing for the overspeed test, operators noted a problem with the governor linkage on the No. 23 AFW pump, and the overspeed test was postponed pending the linkage repai On May 2i, while the repair work was underway, the inspector learned that a problem with the linkage existed and that the licensee had taken the unit to Mode 3 with the pump uncoupled from the turbine. The inspector* identified that, though the pump was known to be.

inoperable, Action Statement (AS) for Technical Specification (TS) 3.7.1.2, which requires all three AFW pumps to be operable in Modes 1, 2 and 3, had not been entered. In acknowledging the *inspector's concern, the licensee declared the pump inoperable and back-.

dated the entry time into the TSAS to the time at* which the problem with the linkage had *

been identified. The inspector also questioned the licensee as to how they considered the pump operable with it uncoupled from its turbine and their basis for taking the unit to Mode 3, which required the pump to be operabl The licensee responded by explaining that, since TS 3. 7.1.2 does not require a surveillance test to verify the operability of the No. 23 AFW pump until secondary steam supply pressure is greater than 750 psig, and that point in Mode 3 had not yet been reached, the No. 23 AFW pump was not required to be operable for entry into Mode 3 nor was a TSAS entry for that pump necessary prior to that point. The inspector understood the basis for the licensee's presumption and determined the safety significance of the No. 23 AFW pump unavailability below 750 psig at the low end of Mode 3, was low. The inspector also subsequently verificil that the licensee properly repaired, overspeed tested and coupled the pump after reaching 750 psig. Until PSE&G better clarifies the requirements of the applicable TSs and their interpretation of them, this item will remain unresolved (URI 50-272 and 311/93-15-01). Uriit 2 Mode Changes and Attempted Startups During the report period, the licensee completed all work which had been scheduled for the Unit 2 refueling outage. Core re-load was completed on May 4, 1993, and the plant reached Mode 5 (Cold Shutdown) on May 9, once the reactor vessel closure bolts were fully torque The licensee subsequently initiated a plant heat-up, and established Mode 4 (Hot Shutdown)

on May 19 and Mooe 3 (Hot Standby) on May 20. On May 25, 1993, upon completion of all necessary surveillance tests, the licensee initiated a reactor startup. However, the following chronology of events indicated recurring problems in the rod control system:

May 26 -

May 27 -

May 28 -

June 2 -

Control Bank "C".step counter failed to operate properly; A single control rod in Shutdown Bank "A" withdrew from, instead of inserting into, the reactor core upon an "insert" command signa Control Bank "C" - Group 1 rods dropped unexpectedly, and resulted in manual reactor trip; Plant computer did not properly track the movements of Control Bank

"B" and "D".

On June 4, 1993, the unit was successfully started. However, upon discussions with NRC and Westinghouse, the licensee concluded that the rod control system performance problems were not sufficiently resolved. Consequently, the licensee elected to shut down the uni The NRC dispatched an Augmented Inspection Team (A.IT) to the site ori June 5 in order to assess the licensee's performance, and investigate the cause of the rod control system failures and their generic implications. The AIT's evaluation of the events is discussed in NRC Inspection Report 50-272 and 311/93-81. Once shutdown 'on June 4, Unit 2 remained in Mode 3 through the end of the inspection perio *

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Open Item Follow-up (Closed) Unresolved Item (50-272 and 311/91-01-02); Shutdown Margin Monitor Availability. This instrumentation system was installed in 1985 to meet NRC Regulatory Guide 1.97 and 10 CPR 50.49 requirements. The inspector previously noted inoperable

. channels and an apparent licensee lack of concern for this condition. The licensee initiated an improved accountability system, including the daily manager's meeting and package. This has apparently improved awareness and tracking of out-of-service systems. The inspector verified that all channels of the shutdown margin monitor system for both units were operable. Further, the issue of Technical Specification for this system is being reviewed by NRR. Based on the above, the inspector closed !his ite (Closed) Violation (50-311/91-81-01); Failure to Follow Startup and Administrative Procedures. This violation, which occurred during a Unit 2 turbine startup on October 20, 1991, was one of several causal factors for the November 9, 1991 turbine failure even The licensee responded to the violation in a letter dated May 18, 1992. The licensee concluded root cause to be inadequate communications, personnel error, insufficient supervisory oversight and lack of attention to detail. Corrective actions included:

disciplinary actions for all of the operators involved, development of personal action plans, conduct of training sessions, management meetings, development of an information directive, procedure enhancements, and some additional action The inspectors reviewed the licensee's response and verified selective corrective action These actions were documented in NRC Inspection 50-272 and 311/92-04 and 92-12. Based on this, the inspector closed this ite.2.2 Hope Creek Overheating of Microswitches On April 30, 1993, an Instrumentation and.Control technician identified a microswitch which exhibited some damage due to overheating of an internal resistor. The switch and others like it are used to indicate component status, i.e., valve position (open/closed), damper position (open/closed), and pump status (start/stop). The licensee then inspected all panels in the plant which use this model of microswitch and identified five more degraded switches. The concern associated with the degraded microswitches was the uncertainty of whether the safety~related components associated with the switches would still function if a microswitch were to overheat and subsequently fail. That is, if position indication failed, would the pump/valve/damper still operat *

In accordance with 10 CFR 50.59 the licensee conducted a safety review of the proble The review concluded that no unresolved safety questions existed and that the Technical Specification did not need to be changed. These conclusions were based on engineering analysis which showed that the degraded microswitches would not impair the function of safety-related equipment. * The licensee confirmed that the function of the microswitch is to monitor circuit integrity, which is a non-safety-related function, and that any failure of a microswitch would not affect operability of its respective safety-related pump, valve or dampe The licensee's safety review also recommended replacing the switches with another type of switch which is better suited for the subject application. Plant management acted on this recommendation, is pursuing several options for purchasing new switches, and is working on a design change package for changing out the old switche The inspector reviewed this item, examined the microswitches, and discussed it with the licensee engineering, operations an,d management personnel. The inspector concluded that the licensee appropriately addressed and dispositioned this issue.

- -

6 Partial Loss of Off-site Power At 5:57 p.m. on May 13, 1993, with the Hope Creek unit at 100%, a fault occurred with the 13.8 KV switchyard bus Section 7. The "B" phase "pot-head" insulator failed, causing a loss of safety-related (AX501) and non-safety-related (AX502 and AX503) transformers. -

AX501 is the normal supply for the "A" and "C" 4.16 KV vital buses, and AX502/AX503 are the normal supplies for the 4.16 KV and 7.2 KV non-vital buses. In response to the fault, the "A" and "C" vital buses (as well as the other non-vital buses) fast-transferred to their backup supply: transformer BX501. When these buses transfe~ed, voltage on the BX501 m-feeder momentarily dipped below 92 % of rated voltage. (Such a dip is expected.)

Subsequently, with vital bus voltage below 70% rated (due to the fault) and backup supply voltage below 92 % rated, the loss of off-site power logic was satisfied. This logic simultaneously tripped the BX501 in-feeders to A" and "C" vital buses and started the "A" and "C 11 emergency diesel generators (EDGs). Thus, the "A" and "C" EDGS were powering their respective vital buses and the non-vital buses, which do not have loss of off-site protection, remained powered from BX50 An expected momentary loss of power during successful transfer to BX502/BX503 transformers for the non-vital buses resulted in the following lost equipment: "A" recirc pump, "A" and "C" reactor feed pumps (RFP), "A" and "C" circulating pumps, "A" primary condensate pump (PCP), "A" secondary condensate pump (SCP), "B" feedwater heater string, "A" and "B" reactor water cleanup pumps, "C" reactor auxiliaries cooling system (RACS) pump, "A" control rod drive (CRD) pump, offgas train,_ and the turbine auxilianes cooling system (T ACS). The vital bus equipment restarted after the EDGs powered the "A" and "C" buses. This equipment included the service water pumps, safety auxiliaries cooling system pumps, and several chiller With "A 11 reactor recirc pump tripped and a full runback initiated on recirc pump "B" (due to loss of the PCP and SCP), reactor power decreased to 48 %. The reactor operator recovered reactor level using "B" RFP. Reactor water level remained between 15 and 45 inche Normal level is 35 inches and the reactor scram setpoint is 12.5 inche Operators entered numerous abnormal operating procedures (AOPs) and single recirc loop operation. The recirc pump trip and runback resulted in entry into the potential power instability region (Region 1). Operators performed control rod insertions, 11A 11 recirc pump restart, and feedwater heater train restoration and they exited this instability region after 38 minutes. Control room operators monitored for, and did not observe any rea~tor power oscillations. Initially, the licensee believed that they were in Region I for one and one-half hours. However, a higher than expected reading on the "C" average power range monitor (APRM) resulted in the overall average APRM reading to be high. Operators eventually stabilized reactor power at about 51 % with 52% core flow. The licensee made an Emergency Notification System call due to an Engineered Safety Feature actuation (EDG auto starts) and notified the inspector at hom Licensee maintenance personnel performed troubleshooting activities on the A&C vital buses in-feed breakers from the BX501 transformer. The licensee racked out, inspected and successfully tested all infeed breakers. The licensee entered Technical Specification Action Statement (TSAS) 3.8.1.1.D for loss of both off-site power sources (AX501 and BX501).

Operators successfully tested all four EDGs as required by the TSAS. Subsequently, at 11:47 p.m. on May 13, operators transferred the A&C vital buses from their respective EDG supply to the BX501 transforme The licensee maintained 57% reactor power while in a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months TSAS with the AXSOl out of service. An emergency shipment of diesel fuel oil arrived on site about midnight, May 14. "

The licensee replaced the AX501 transformer "pot-head" and inspected other similar device Subsequently, electrical power was returned to normal at 11:00 p.m. on May 1 On May 13, the plant manager initiated a Significant Event Response Team (SERT) to investigate the event. The SERT's charter included reviewing the 13.8 KV insulator failure, the BX501 in-feed breaker response, plant and operator response; determining root cause(s);

and identifying any necessary corrective actfon The inspector responded to the site to review plant conditions and to assess licensee action The inspector reviewed AOP implementation, independently assessed plant conditions from the control room, and discussed the event with licensee operations and management personnel. The inspector examined the "pot-head" failure in the switchyard. In addition, the inspector witnessed EDG surveillance testing and vital bus switching evolutions. The inspector also toured the plant, including the EDG rooms' and the vital bus areas. On May 14, the inspector conducted a conference call with the licensee and NRC staff to clarify and understand the chronology and* issue The inspector reviewed the licensee's assessment of the vital bus/EDG interactions that occurred. Licensee engineering and Stations Operations Review Committee (SORC)

reaffirmed that the off-site and on-site electrical systems responded as designed. A cable fault ("B",pot-head) up-stream of AX501 transformer tripped the normal off-site power supply and also caused degraded voltage ( < 70 % ) on vital buses "A" and "C". When the backup off-site supply (BX501) attempted to supply the vital buses, supply voltage was momentarily degraded ( < 92 % ) because of the numerous loads transferring over from AX501. Thus, "A" and "C" EDGs started and loade The licensee confirmed the observed electrical sequence by reviewing design basis *

documentation and electrical schematics. The licensee documented this review in an engineering evaluation (H-l-NA-EEE-0813) dated May 17, 1993. The inspector also attended a SORC meeting which discussed this ite *

The inspector also reviewed the licensee's incidentand SORC reports. Vendor personnel and the licensee determined that equipment failure due to water intrusion was the root cause of the "pot-heag" failure. The inspector noted that the licensee -satisfactorily inspected other similar device The inspector concluded the licensee appropriately responded to this event, including initial operator response and AOP implementation, maintenance and troubleshooting activities, and root cause determination and corrective action recommendations. The inspector noted the SERT investigation and report to be thorough and well performe Reactor Scram The Hope Creek unit automatically scrammed from 60% power at 2: 14 a.m. on May 16, 1993, due to high reactor pressure (1037 psig setpoint). All rods inserted, reactor level was recovered by the reactor feed pumps, and the two low-low set safety relief valves opened and closed as designed. The maximum reactor pressure was 1047 psi The licensee entered emergency operating procedures (EOPs), made an ENS call, notified the inspector at home, and initiated a SERT. The licensee cooled the plant down to cold shutdown and began a forced outage. The licensee pursued a possible electrohydraulic control system (EHC) malfunction, as weekly turbine,-stop valve testing (OP-ST.AC-000-I(Q))

was in progress at the time of the scram. The turbine control and intercept valves closed unexpectedly causing a rapid steam demand decrease. This resulted in a reactor pressure increase and subsequent scram on high pressur The licensee initiated a post-scram procedure review per HC.OA-AP.zz..:101(Q). Further, SERT completed their review and issued a final report. Based on troubleshooting activities and contact with the vendor (General Electric), the licensee concluded that the most likely

. root cause to be failure of an EHC agastat relay (card D44) associated with the speed control circuit. This single failure caused the EHC system to sense a false turbine high speed signal and then react by closing the turbine control and intercept valves. The licensee replaced this relay and card, and two other cards whose failure could also explain the event. Additional sho~-term corrective actions included pre-startup EHC checks, turbine testing prior to startup and at 25% power, and special EHC system monitoring. Longer-term corrective actions included plans to evaluate the EHC preventive maintenance program and its design. While in a forced outage, the licensee repaired neutron monitoring instrumentation, performed NRC Bulletin: 93-02 inspections (See Section 8.3.C), and performed other maintenance and testing activitie The inspector reviewed the post scram review procedure AP-101, the SERT report, the incident report, and discussed the scram with licensee operations and management personne The inspector also reviewed the control room charts, alarm chronology, sequence of events recorder, EH~ system prints and the transient recorder trace The inspector concluded that the licensee appropriately responded to the scram, and performed detailed and thorough follow-up activities. The SORC, line management and SERT activities were effective in identifying the root cause and -initiating corrective action Reactor Startup The licensee restarted the Hope Creek reactor after completing post-trip activities on May 19, 1993. The licensee suc~ssfully performed turbine valve testing. The unit achieved full power on May 20, 199 The inspectors observed portions of the startup, including criticality, power ascension and testing. The inspectors noted that these activities were professionally accomplished in accordance with operating and test procedure _ High Pressure Coolant Injection (HPCI) System Walkdown The inspector independently verified the operability of the HPCI system by performing a walkdown of the accessible portions of the system. This walkdown confirmed that the system lineup and operating procedure matched the plant drawing and as-built configuratio Another purpose of the walkdown was to identify any adverse equipment cop.ditions which could effect the system's performance. Based on the walkdown, the inspector concluded that the HPCI system was operational and capable of performing its design functio Temporary Instruction (Tl) 2515/119: Water Level Instrumentation Errors During and After Depressurization Transients (GL 92-04) Background As discussed in NRC Information Notice (IN) No. 92-54, "Level Instrumentation Inaccuracies Caused by Rapid Depressurization" and Generic Letter (GL) No. 92-04,

"Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs

.

Pursuant to 10 CFR 50.54(t)," the staff is concerned that noncondensible g'!_ses may become dissolved in the reference leg of BWR water level instrumentation and lead to a false high level indication after a rapid depressurization event. The dissolved gases, which accumulate over time during normal operation, can rapidly come out of solution during depressurization and displace water from the reference leg. A reduced reference leg level will result in a false high vessel level indication. Accurate indication is important to safety because water level signals are used for actuating automatic safety systems and for guiding operator actions during and after an event. This potential problem affects the cold reference leg water level instruments used at Hope Cree *

On July 29, 1992, the NRC staff held a public meeting with the Regulatory Response Group (RRG) of the Boiling Water Reactor Owners Group (BWROG) to discuss the effect of inaccuracies in the reactor vessel level instrumentation system in BWRs. During the - *

-*

meeting, the BWROG and its consultant, General Electric Company (GE), presented the results of analyses assessing the safety implications of the postulated error in level indication Upon reviewing the information provided by the BWROG and the staffs assessment, the staff concluded that interim plant operation is a~ptable. The bases for the staffs conclusion are as follows: 1) the level instrumentation is expected to initiate safety systems prior to a significant depressurization of the reactor; 2) emergency procedures which are currently in place in conjunction with operator training are expected to result in adequate operator actions; and 3) an abrupt depressurization event resulting in a common mode, common magnitude level indication error is unlikel In response to staff concerns regarding adequate operator actions after a rapid depressurization event, the BWROG sent two letters to all BWR plant operations superintendents. The purpose of these letters, dated August 19 and October 16, 1992, was to sensitize operators to the potential problem, and to provide operator guidance to be used in conjunction with Emergency Operating Procedures (EOPs) to ensure adequate core coolin.

Objective The objective of this TI was to verify licensee implementation of operator guidance and training to ensure required operator actions concerning-reactor vessel water level following rapid depressurization transients, and also to ensure that this guidance and training is consistent with current plant EOP *

The inspector reviewed a Simulator Guide (SG), "Reactor Vessel Break Requiring Reactor Flooding," which is used to train Hope Creek operators on a rapid depressurization transient. As part of tliis particular SG, a small ;LOCA occurs, worsens, and becomes severe enough to result in a loss of vessel level indicatio Once level indication is lost, the crew is expected to implement EOP-206, "Reactor Flooding." The frequency of training on this scenario is such that each crew has practiced it three to four times over their two year training cycl *

In addition to the, above simulator _exercise, the Hope Creek training department provides operators training on level instrumentation errors. Lesson -Plan 203-00,

"Reference Leg Noncondensible Gases," has been taught to each crew, and will continue to be taught annually. The lesson discusses observations made at operating BWRs, probable causes for level indication errors during depressurization, resolution strategies which the BWROG developed, interim guidance which includes monitoring for the notching phenomenon seen on older BWRs, and a video tape discussing this issue.

The inspector interviewed the training staff and concluded that they were well aware of the level error issue and had read GL 92-04 and IN 92-54. *

The inspector reviewed the plant EOPs to determine if they provide clear information to the operators relative to identifying if reactor level is undetermined and emergency depressurization and vessel flooding is required. The definitions section of EOP-101,

"Reactor Pressure Vessel (RPV) Control," and EOP-206, "Reactor Flooding,"

indicates "undetermined" as a condition when all available indications (direct, indirect, individually or in combination) are insufficient to provide the current value or status of the identified parameter. All operators, as part of their training on the EOPs, are taught how to recognize and respond to this condition. In addition, if level is undetermined, the EOPs direct the operator to emergency depressurize and flood the vessel per EOP-206. The inspector concluded that the EOPs provide clear information and instructions to the operato The inspector reviewed operating procedures and annunciator response procedures to determine if they provide operators with guidance for i11:dividual water level instrument failures. Typically, these procedures provide information for power operations as well as shutdown conditions. Consequently, level errors of the kind described in GL 92-04 and IN 92-54 are not specifically addressed. However, since the EOPs do address such errors there appears to be appropriate procedure guidance to ensure adequate core cooling.

The inspector confirmed that the plant's Safety Parameter Display System (SPDS).

screen changes color to indicate to the operators that a water level instrument reading differs from the other level readings by a pre-determined amount. The SPDS value box changes to a white background with question mark symbols: ???. This indication means that the value is either unreliable or indeterminabl.

Conclusions Based on the actions which the licensee has taken and combined with existing guidance from EOPs, the inspector concluded that operator guidance and training has been provided for significant depressurization event Single Control Rod Scram On the afternoon of June 2, 1993, control rod 34-35 scrammed from position 48 to 0 Technicians were performing a channel calibration on intermediate range monitor (IRM).

Part of the calibration initiated an expected reactor protection system (RPS) channel "B" half-scram. Consequently, the "B" scram pilot solenoid valves for all control rods de-energize Since both the "A" and "B" scram pilot solenoid valves must de-energize in order for a rod to scram, the RPS "B" channel half-scram alone should not have caused any rods to inser However, unknown to the crew or the technician, the "A" scram pilot solenoid valve for rod 34-35 had a blown fuse and was therefore de-energized. Thus, with both "A" and "B" solenoids de-energized, rod 34-35 scramme **

The crew concurrently entered the annunciator response procedure for "Rod Drift" and stopped the surveillance. They also verified that the core was still within its thermal limits and reset the "B" channel half-scram. Operators identified the cause of the rod scram as a blown fuse to the "A" solenoid valve and replaced and tested the fuse. Subsequently,. per Reactor Engineering instructions, the crew reduced power to 96%, withdrew the rod to position 48, and returned to full powe The inspector reviewed this item with the Operations Engineer and concluded that the licensee responded appropriatel * * Open Item _Follow-up (Closed) Unresolved Item (50-354/93-02-01); Electrical Power Sources to the Vital 4 KV

. Buses. The licensee developed a Technical Specification Interpretation (TSI) for TS 3.8.1. l.A; addressing actions for out-of-service electrical power feeds to individual 4 KV vital buse The inspector reviewed this TSI and discussed it with operations management personne The inspector determined the TSI to be appropriate, and therefore closed this open ite.2.3 Common A~

Open Item Follow-up (Closed) Unresolved Item (50-272 and 311/92-07-01; 354/92-06-01); Artificial Island Fire Water Pumps and Fire Protection Program.* The licensee initiated a design change package (DCP) lEC-3217 to replace the Salem No. 1 diesel fire pump. The DCP was completed, and the new pump was tested and declared operable during April 1993. A second diesel was procured to replace the existing No. 2 pump in July 199 The inspector reviewed the DCP, walked down the system in the field, reviewed surveillance testing records, and reviewed fire pump status with licensee personnel. Based on this, the inspector closed this open item.* RADIOLOGICAL CONTROLS Inspection Activities The inspector verified on a periodic basis PSE&G's conformance with the radiological protection progra *

. *

. Inspection Findings 3.2.1 Salem Containment Tours During the inspection period, the inspectors toured the Unit 2 containment on several occasions. The inspectors reviewed radiological controls, including technician coverage, postings, radiation work permits, housekeeping, and cleanliness. Overall, the Unit 2 containment was well maintained. Radiation protection personnel were noted to be professional and very knowledgeabl.2.2 Hope Creek Open Item Follow-up (Closed) *Unresolved Item (59-354/93-06-01); Improper Personnel Entry Into the Radiological Controlled Area (RCA). A non-licensed equipment operator knowingly violated administrative procedures by entering the RCA without the appropriate dosimetry and documentation. The licensee completed their review of the event. Based on this review and previous performance problems, the licensee terminated this individual's employment. *The licensee did not identify any other similar violation by other personne The inspector reviewed the completed incident report and discussed the item with plant management. The inspector concluded that this was a licensee identified violation of plant procedures, and is not being cited because the licensee satisfied the criteria in Section VI of the Enforcement Policy. The licensee corrective actions included emplOyee termination, and review of the event with other station personnel. The inspector concluded that the licen~ee appropriately responded upon the identification of this occurrenc.3.3 Common Duplicate Thermoluminesence Dosimeters (TLDs)

The licensee informed the inspector of an issue concerning duplicate TLDs: On March 4, 1993, during routine radiation protection dosimetry TLD preparations, licensee personnel discovered duplicate identification numbers for 34 TLDs. The.licensee purchased these duplicate TLDs during the period 1983-84. The licensee initiated an incident report and began an investigation into this potential proble The licensee concluded that these duplicate TLDs were never used by site personnei for radiation dose documentation. The basis for this conclusion is as follows: (1) the duplicate TLDs appeared new and unused, (2) the PSE&G identification label was not on these TLDs, and (3) phone conversations with a former dosimetry supervisor confirmed that these

duplicate TLDs were never used and were placed in a storage area. Further, the licensee checked the entire population of the site 18,000 TLDs, and no additional duplicate TLDs were note The inspector reviewed the licensee's investigation, including the incident report and a letter dated April 5, 1993 (NRP-93-0235). The inspector also discussed this issue with licensee engineers and radiation protection personnel. The inspector concluded that the licensee initiated a proactive and thorough investigation, and no radiation protection safety issues were identifie.

MAINTENANCE/SURVEILLANCE TESTING Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to ascertain whether the licensee conducted these activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard The inspector observed portions of the following activities:

Unit Salem 1 and 2 Salem 1 Salem 2 Salem 2 Hope Creek Hope Creek Work Order(WO) or Design

. Change Package (DCP)

Description Various WOs WO 921209156 SC.MD-DC.AF-OOl(Q)

WO 930602080 WO 930429075 Various WOs No. 2 diesel drive fire pu~p 12B comp~nent cooling heat exchanger plate replacement Auxiliary feedwater pump mechanical overspeed trip*adjustment No. 23 auxiliary feedwater pump governor and trip linkage maintenance Motor driven fire pump Electrohydraulic system troubleshooting

.I The maintenance activities inspected were effective with respect to meeting the Safety objectives of the maintenance progra *

15 Surveillance Testing Inspection Activity The inspectors performed detailed technical procedure reviews, -witnessed in-progress surveillance testing, and reviewed completed surveillance packages. The inspectors *verified that the surveillance tests were performed in accordance with Technical Specifications, approved procedures, and NRC regulation The inspector reviewed the following surveillance tests with portions witnessed by the inspector:

Salem 2 Salem 2 Salem 2 Salem 2 Salem 2 Salem 2 Salem 2 Salem 2 Hope Creek Hope Creek Hope Creek Procedure N S2.0P-ST.DG-0002(Q)

S2.0P-ST.DG-0007(Q)

S2.0P-ST.DG-0013(Q)

S2.0P-PT.AF-0004 S2. OP-ST.SSP-0002 S2.0P-PT.AF-0004(Q)

S2. OP-ST. TRB-0002(Q).

S2.RE-RA.ZZ-0005(Q)

MlO-SHT-006 HC.OP-ST.KJ-0002(Q)

HC.OP-ST.KJ-0004(Q)

2B Emergency Diesel Generator 2B Emergency Diesel Generator 2B Emergency Diesel Generator 23 Auxiliary Feed Overspeed Trip Test Engineered Safety Feature - Manual Safety Injection Safeguards Equipment Cabinet Section - lA Vital Bus No. 23 Auxiliary Feedwater Pump Overspeed Trip Test Main Turbine Overspeed Solenoid

.Test Unit 2 Boron Endpoint Determination Motor driven fire pump annual flow test

. B Emergency Diesel Generator D Emergency Diesel Generator The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing progra *

16 Inspection Findings

. 4.3.1 Salem Unit 2 Safety Injection On April 15, 1993, the licensee reported an engineered safety feature actuation in accordance with 10 CFR 50. 72(b)(2)(ii). Specifically, during response time testing of the solid state protection system (SSPS) logic, an inadvertent safety injection (SI) signal occurred. No water was injected into the reactor coolant system as the reactor was defueled and the SI -

pumps were cleared and tagged out, and the reactor trip breakers were open. At the time, steam pressure transmitters were being replaced and steamline differential pressure blstables were trippe Technicians were performing response time testing of SSPS logic for SI train "B".

Technicians placed the SSPS train "A" input error inhibit switch to "inhibit," as required by procedure 2IC-18.4.004. When the switch was repositioned, the SI block was removed before the coincident input logic cleared, allowing the logic to initiate the SI signa Licensee testing showed that slow positioning of the switch caused a delay between removing the block and disabling the inputs, which would ordinarily prevent an SI signa *

The licensee has initiated actions to change the test procedure to require positioning the SSPS train mode selector switch to "test" prior to taking the affected train input error inhibit switch to "inhibit." A caution will also be added to the procedure and other similar SSPS procecJures will be revised accordingl The inspector reviewed the Licensee Event Report (93-06) and discussed it with the appropriate licensee personnel. The inspector concluded that the licensee's followup of this event and corrective actions were adequat Generator Replacement on the No. 2B Emergency Diesel Generator During the inspection of the emergency diesel generators (EDGs) during the sixth refueling outage (2R6) at Salem Unit 2, the licensee found that the amortisseur winding in the generator in the 2B EDG had been plastically deformed (an amortisseur winding dampens variations of the position or magnitude of the magnetic field linking the generator poles).

The licensee determined that, at some point iIJ. the unit's sixth operating cycle, the EDG must have not properly synchronized to its vital bus, thereby causing the rotor poles to deflect enough to cause the amortisseur winding deformation. PSE&G subsequently tested the 2B EDG to verify its operability prior to the conclusion of 2R6 and initiated a design change package (DCP) to replace the generator at the next outage.

During the Salem Unit 2 seventh refueling outage, PSE&G performed major overhauls on all three unit EDGs. Ineluded in the 2B EDG overhaul was the replacement of the generator in accordance with DCP 2EC-3214. The licensee had determined -the replacement of the generator to be economically more advantageous than repairing i The licensee pursued the replacement through the dedication of an available commercial grade generator made by Electric Machinery (EM), which was the supplier.of the six existing EDG generators. EM no longer has a 10 CFR 50, Appendix B, Quality Assurance program, and no other vendor was available to supply an identical spare generator, therefore the dedication of a commercial grade item (CGI) was necessary to replace the generator in accordance with the requirements of the EPRI standard and NRC guideline The inspector initially reviewed the licensee's findings froin 2R6 concerning the 2B EDG test results from that outage and the ensuing seventh operating cycle in order to verify that the amortisseur winding abnormality had not adversely affected the EDG's operability. The inspector subsequently reviewed DCP 2EC-3214 and the CGI Dedication Report for the new generator, monitored and observed portions of the 2B EDG overhaul and generator replacement work and testing, and discussed the modification results with the EDG system engineer and the DC~ project manager. The inspector concluded that the 2B EDG had been maintained operable during the Unit 2 seventh operating cycle, that DCP 2EC-3214, including the dedication testing, had been well performed, and that the 2B EDG was properly returned to an operable status prior to the conclusion of 2R Open Item Follow-up (Closed) Violation (50-272 and 311/91-16-02); Water Tight Doors Latching Devices Were Noted to be Difficult to Operate. The licensee responded to the violation ip a letter dated October 1, 1991. The licensee concluded that the cause of this problem was inadequate procedural guidance. Corrective actions included repairs to the several latching devices, issuing of a letter to all personnel emphasizing the importance of these doors and latching* *

devices, revision to the equipment operator round sheets to include door latch verification, door labelling, and inclusion of the door latches into the preventive maintenance progra *The inspector reviewed the violation response, verified corrective actions and examined a sample of doors and latches in the field. The inspector determined that doors were functional, and therefore closed the open ite (Closed) Unresolved Item (50-272/91-18-02); Unit 1 Containment High Range Radiation Monitor (1R44A) Surveillance Test. The licensee reviewed the out-of-specification voltage reading for procedure lIC-4.1.072 and concluded that the 1R44A monitor remained operabl The licensee also contacted the vendor, and revised the procedure for this voltage readin The licensee counselled the Information and Control supervisor for closing the surveillance test procedure and related work orde The inspector reviewed the licensee's assessment of this issue, including corrective actions and the revised surveillance test procedure. Based on this, the inspector closed the open ite (Closed) Violation (50-272 and 311/92-11-01); Failure to Follow Measuring and Test Equipment (M&TE) Procedures. The licensee responded to the violation in a letter dated August 28, 1992. The licensee initiated corrective actions, including procedure revisions, assurance that M&TE used was properly calibrated, discussions with the personnel involved, and training of site personne The inspector reviewed the_ licensee's response, verified selected corrective actions, and closed the open ite.3.2 Hope Creek _ Open Item Follow-up (Cfosed) Violation (50-354/92-13-01); Failure to Appropriately Address a Motor Operated Valve (MOY) Wiring Error. The licensee responded to the violation in a letter dated December 29, 1992. Licensee corrective actions included the following: (1) Independent review of the event by_ the on-site safety review group, (2) correction of.the MOV wiring errors, (3) discussion of the event with personnel involved, (4) meetings with groups effected to ensure communications of management expectation, (5) revision of the lifted lead and troubleshooting procedures, (6) modification of appropriate training programs, and (7)

modification of MOV post-maintenance testing program to include interlock check The inspector reviewed the licensee's response and verified selected corrective action Based on the above, the inspector closed the open ite.

EMERGENCY PREPAREDNESS Inspection Activity The inspector reviewed PSE&G's conformance with 10 CFR 50.47 regarding implementation of the emergency plan and procedures. In addition, the inspector reviewed licensee event notifications and reporting requirements per 10 CFR 50. 72 and 7.2 Inspection Findings There were no noteworthy finding.

SECURITY Inspection Activity The inspectors verified PSE&G conformance with the security program, including the adequacy of staffing, entry control, alarm stations, and physical boundarie.2 Inspection Findings The inspectors concluded that the licensee appropriately implemented security plan and program requirement.

ENGINEERING/TECHNICAL SUPPORT Salem Improper Emergency Diesel Generator (EDG) Fuel Injector Studs On March 15, 1993, the licensee noted a broken stud (one of the two fuel injector studs) on.

the No. 9.-Left cylinder (of 18 total) on the Unit 2 No. 2A EDG. The two studs per cylinder*.*

support the associated fuel tubing.* Subsequently, the licensee identified that the studs were

. of improper material. Design specifications require that each stud be made from A 193 Grade B7 chromium - molybdenum alloy steel, and be machined to a smaller diameter at the unthreaded (middle) portion of the stud. The licensee determined that the broken stud was made from a softer, re-sulfurized carbon steel with a very low carbon content, and was not properly machined down. Licensee personnel found and subsequently replaced* three additional improper (not broken) studs on the No. 2A ED '

'

The inspector interviewed the EDG system engineer and ascertained that similar_ EDG fuel injector stud material problems previously existed. *Specifically, several improper fuel injector studs were found (and subsequently replaced) on the Unit 1 No. lC EDG in June 1991. Also, a system engineer walkdown identified two improper studs on the No. 2B EDG ort January 16, 1993. The proper studs were -subsequently installed. Subsequent to the March 15, 1993 identification, the licensee inspected the studs on both Unit 1 and Unit 2 EDGs, and did not find any additional deficiencie The inspector noted that the system engineer completed a preliminary calculation, which determined that one stud made from the improper material would not affect EDG operabilit The inspector found, however, that the licensee did not make a formal EDG operability determination. In addition, on April 30, 1993, a sheared stud was found on the No. 2B EDG. In that case, the stud was the proper stud, however, it sheared apparently due to

'

improper stud alignment. On that occasion, however, the operators declared that EDG inoperable. Licensee practice regarding EDG operability determinations due to degraded/inoperable studs appeared inconsisten The licensee stated that the root cause for the improper studs appeared to be related to procurement of the replacement studs. The licensee procured the studs from a company (Canada Allied Diesels) other than the EDG manufacturer (Alco). However, a root cause determination for having incorrecfparts in stock, as well as installed in several EDGs, was in progress but not yet completed. In addition, it was not clear that a thorough and documented 10 CFR Part 21 evaluation was completed to determine whether more generic implications are eviden The inspector concluded that additional information is required to resolve this potential safety concern. Further information is required to ensure prior EDG operability (with the improper

stud material) and consistent application of operability determinations. Additionally, the root cause of this event has not yet been determined, and the licensee has not yet determined

whether 10 CFR Part 21 is applicable. Further, the potential safety significance of this event.

remains to be evaluated (i.e., the potential for.fuel leak and fire if all of the studs on any one fuel injector failed). This item will continue to be followed up by the inspector pending resolution of the above, and is an unresolved item (URI 50-272 and 311/93-15-02).

.

. B Vital Bus Fault On April 17, 1993 at 10:50 a.m., the feeder breaker from the 2B 4 KV vital bus to the 480/240 V AC motor control centers (MCCs) tripped. This occurred during design change package (DCP) 2EC-3189 installation. This DCP provided cabling between the 2A and 2C vital MCCs to be used only during outage periods, as a source of temporary powe Contractor electricians incorrectly accessed the 2B vital MCC through recently installed conduit on the elevation below the MC *

The metallic device used to access the conduit contacted the energized bus bars of the 480 V AC MCC, causing the MCC feeder breaker to trip on an instantaneous ground fault. The electricians did not receive any electrical shocks. The MCC sustained damage and the fault caused smoke alarms in the 84 foot level of the auxiliary building. The licensee's on-site fire protection group responded. No fire occurred and the fire protection personnel ventilated the area. The licensee initiated incident report 93-223 and fire incident report M93-107024 The licensee concluded that the root cause was personnel error due to lack of attention to detail. The cable was properly marked and the DCP work instructions provided sufficient detai *

The licensee inspected the damaged MCC, initiated non-conformance reports (DRs), replaced the damaged bus bars, and conducted tests to ensure operability. The electricians involved in the incident were counselled, including their foreman. The licensee discussed the event at the morning outage meeting and at the manager's meeting. Additional corrective actions included plans to access future conduits wi_th a nylon material device, plugging of unused conduits, safety meeting discussions and a review of similar industry event At the time of the event, the unit was defueled with practically no equipment in servic Therefore, the licensee concluded that the loss of 2B vital bus presented minimal safety significance for Salem Unit The inspector reviewed the related incident reports and DRs, and discussed the event with DCP installation engineers, fire protection personnel and plant management. The inspector examined cable pulling equipment, conduits and MCC damage. The inspector also monitored the repair activities. The inspector concluded that the licensee appropriately responded to this personnel error event, including root cause determination and corrective action Salem Unit 2 Fuel Rod Defects During the inspection period, PSE&G informed the inspectors that they had detected Salem Unit 2 fuel rod defects during the current 7th refueling outage. During the previous cycle, Salem Unit 2 operated with a higher than expected dose equivalent iodine (DEi) value of about 4.0 E-03 microcurie per gra Normal DEi _is approximately 1.0-2.0 E-03 microcurie per gram. The licensee expected to find one or two fuel rod defects. However, after completing core fuel assembly/rod inspections (ultrasonic test and visual), the licensee noted 13 fuel rod defects in 8 assemblies. All 13 rods had open defects, caused by fretting *

(wear) damag The affected fuel was Westinghouse Vantage SH, in its second cycle of core exposure. Most failures occurred on fuel rods located in the core periphery near the assembly grid area. The licensee believes the cause to be an apparent grid-to-rod fretting failure resulting from grid design changes combined with flow instabilities in this core baffle and periphery regio Other facilities noted similar failures during their current outage Westinghouse and the licensee are currently considering a 10 CFR 21 notificatio PSE&G reconstituted the Salem Unit 2 fuel by replacing the effected rods with stainless steel pins and reloaded the core in the vessel. Salem Unit 1 is currently operating at power with a similar value for DEi (5.0 E-03 microcurie per gram) and an expectation of one or two rod failures. The licensee intends to inspect Salem Unit 1 fuel during its upcoming* 11th refueling outage scheduled for October 1993. The licensee reviewed and approved a Westinghouse safety evaluation for both Salem units.

This evaluation concluded that no unreviewed safety question or unanalyzed condition exist Further, continued operation of Salem Unit 1 and restart of Salem Unit 2 is acceptabl Westinghouse also concluded that this fuel rod defect issue is not reportable under 10 CPR Part 2 The inspector reviewed the safety evaluation and discussed the issue with licensee nuclear

engineering and management personnel. The inspector also discussed this issue with NRC regional and headquarters specialists. A conference-call between NRC and PSE&G occurred on May 19, 1993, to further discuss this issue. The licensee stated that fuel integrity and'

reliability is addressed in administrative procedure NAP-71, "Fuel Integrity Program." This procedure establishes a goal of zero fuel defects, and provides actions for mitigating the consequences of fuel defects. Failed fuel action levels are also addressed, including power limitations at 10% of the Technical Specification limit of 1.0 microcurie per gram. Pending completion of the licensee's evaluation, assessment and reportability review, this item is unresolved (URI 50-272 and 311/93-15-03). The inspector concluded that this is not a startup issue for Salem Unit Containment Fan Coil Units (CFCU) Performance TeSting In response to Generic Letter (GL) 89-13, the licensee initiated plans to inspect and conduct performance testing of the ten CFCU s (five per unit).. The testing began in.1991, and has continued for two cycles. Recent performance testing of all Unit 1 and 2 CFCUs (January -

April 1993) has shown degradation of heat removal capability. Each CFCU has a minimum design of 81. million BTU /hr heat removal rat Once the CFCU failed its performance test, the licensee declared it inoperable and entered the appropriate Technical Specification (TS) action statement (TS 3.6.2.2). The licensee cleaned the unit and removed a small amount of grass debris. The unit was retested and passed all operability and surveillance test requirements. Subsequently, the* unit was restored to operatio Licensee evaluation into the heat capacity degradation concluded two possible causes: (1)

Frequency of the CFCU cleaning, and (2) modifications to the chlorination syste Regarding the frequency of CFCU cleaning, the licensee intends to modify their initial GL 89-13 commitment from once every other refueling to every refueling outage. Because of environmental issues and concerns, PSE&G modified the chlorination system in January 1989 per design change package (DCP) lSC-2006. This DCP added service water chlorination injection points at the pump suction and at the supply headers. Additionally, in June 1991,

the serviCe water pump suction chlorination injection point was secured to prevent chlorine discharge to the river through the strainer backwash system. Based on discussions with licensee personnel, PSE&G intends to restore the suction injection point with a new DC This is scheduled for Unit 2 during the current refueling outage and for Unit 1 during the fall 1993 refueling outage. Further, the licensee intends to clarify FSAR Section 9.2. 1.2 page 9.2-5 for the service water chlorination syste **

The inspector reviewed the associated documentation for this issue, including the FSAR, TSs, DCPs, incident reports, technical department memorandums, and test procedures. The inspector concluded that the licensee has appropriately addressed the CFCU performance issue Containment Fan Coil Unit (CFCU) Regulators In November 1992, a Salem contractor raised a concern dealing with CFCU flow control.

regulator configuration differences and seismic qualification. The in-plant tubing configuration on Salem Unit 1 was allegedly not in accordance with the system drawing and the CFCU setpOint flow control regulator was allegedly not as specified. Salem Unit 2 control panels were tubed in accordance with the drawing. The drawing showed that the Moore 91F60 air regulators should be used* for Unit 1 and 2 setpoint flow control, where Masoneilan 77-4 air regulators were found in the field for Unit 1. The purpose of the Moore air regulators is to provide setpoints to a service water flow controller through a solenoid valve. The solenoid valve is energized to select the low flow setpoint and de-energized (fail safe position) to select the high service water flow setpoint to the CFCU. Since the setpoints are based on Technical Specification minimum. flows, the regulators must be safety related and seismic I qualified. * The ~icensee determined (Incident Report 92-796) that the differences had no effect on CFCU operability as both regulators are identified in the FSAR as qualified devices (Seismic Class 1). On December 4, 1992, the licensee issued a work order to document the configuration difference issue On January 28, 1993, the licensee initiated a discrepancy evaluation form (DEF) questioning the safety-related function of the setpoint flow control regulators because_ the Masoneilan 77-4 regulators were listed in the Inventory Parts Catalog as a non safety-related purchase. The licensee dispositioned the DEF stating that a fault in the Masoneilan 77-4 regulators would not be detrimental to the operation of the CFCU. A fault would result in a loss of pneumatic signal to the service water flow control valve (SW223), which would open to its fail-safe position. On February 5,.1993, the licensee issued deficiency reports (DRs) with a 50.59 applicability review allowing the "Use-As-Is" condition of the panels and confirmed that the regulators are seismically (class 1) qualifie On February 9, 1993, the licensee identified additional technical information indicating that replaced ASCO s.olenoid valve; with a reduced maximum operating pressure (60 vice 115 psig), could cause the SW223 valve to fail closed (non fail-safe position). If the Masoneilan 77-4 regulator was non safety-related, this potential failure would be considered a common mode failure for all CFCU SW223 valves. Therefore, with the present ASCO solenoid valves installed, the Masoneilan regulators must be maintained as safety related. The licensee traced the qualification of the particular Masoneilan 77-4 air regulators* in use to the actual laboratory qualification test (Wyle Lab Report 43728-1). The licensee has taken steps to ensure only Seismic Class I regulators are used in these control panels and plans to retube the panel in accordance with design upon completion of a design change package (DCP).

The inspector reviewed the licensee's engineering qualification evaluation, FSAR, Wyle Lab

"Seismic Qualification Test Report," and all applicable incident reports, deficiency reports, discrepancy evaluation forms. On May 11, 1993, the inspector-met with members of the licensee's engineering and licen_sing organization to discuss the use and qualification of the Masoneilan regulators and the operability of the CFCU's. The inspector performed a walkdown of flow control regulator panels to independently verify system configuratio Based upon the above activities the inspector found the licensee's action appropriate in addressing the engineering and operability concerns once identifie '

. Open Item Follow-up (Closed) Unresolved Item (50-272 and 311/91-26-02; Determine Whether the Pressurizer Power Operated Relief Valve (PORV) Actuator Diaphragm Should be Considered as Safety-Related. The licensee now procures and maintains the PORV diaphragms as safety-related to ensure PORV operability in both the open and close direetions of valve trave In addition, the licensee implemented several actions to improve PORV operability and reliability. Some of these actions are documented in NRC Inspection 50-272 and 311/92-12, which resulted in moderate improvement in valve performance. The inspector verified that the licensee is pursuing.additional engineering and maintenance efforts, as well as operational monitoring activities, to further improve PORV operability/reliabilit Based on the above, the ins~tor closed this open ite *(Closed) Unresolved Item (50-272 and 311/92-09-02); Multiple Switchgear Dry-type Transformer Failures. The licensee initiated a review of the four non-safety related and one safety-related transformer failure that occurred during the period 1990-1992. These transformers are 4 KV to 460 V, and 4 KV to 230 V, and are located within the respective switchgear. *The licensee contracted an independent third party review of these failures. The licensee concurred in this independent review in a letter dated September 21, 1992 (Memo No.92-166). The review concluded that over time, airborne contamination reduced the high voltage coil strength, resulting in eventual transformer failure. Turbine building high ambient temperature and dust/dirt conditions accelerated this failure mechanism. (The first four failures occurred with non-safety-related transformers located in the turbine building.)

The licensee replaced the safety-related Unit 2 2C transformer in 1992, and the 2A/2B transformers in the current seventh refueling outage. This was done per design change packages (DCP) 2EC-3219. The Unit 2 non-safety-related transformers were also replace The licensee intends to replace the Unit 1 safety and non-safety related transformers during the upcoming eleventh refueling outag *

The inspector reviewed the report, the licensee's assessment of the report, the associated DCPs, and discussed the item with licensee engineers. The inspector concluded that the licensee has appropriately addressed this issue, and the inspector closed this open ite *

(Closed) Unresolved Item (50-272 and 311/92-13-02); Temporary Modifications (f-Mod)

and Emergency Work. The licensee addressed this issue by reviewing administrative procedure NAP-13, "Control of T-Mods." The licensee provided additional guidance for T-Mod initiation during emergencies, including approval authority and review procedure Based on this, the inspector closed this open ite (Closed) Unresolved Item (50-311/93-01-02); Completion of Review and Follow-up Activities for Emergency Diesel Generator (EDG) Overspeed Event During Troubleshooting..

The licensee completed an Incident Report and the Safety Review Group (SRG) completed an

independent review of the event, which provided recommendations to station management for corrective actions. The inspector reviewed the Incident and SRG reports. The inspector noted the SRG report to be thorough and very good in quality, including appropriate recommendations. In addition, the inspector found that station management accepted and assigned for implementation the SRG recommendations. Based upon a thorough event review by the SRG and the subsequent development of an acceptable corrective action plan, the inspector closed this open ite (Closed) Unresolved Item (50-272 and 311/93-02-01; and 93-26-P21); 10 CFR Part 21 Report Review~ Potential Inadequate Core Cooling. The licensee completed an evaluation to show that the minimum emergency core cooling system flows could be achieved, given a postulated single failure (valve RH26). The inspector reviewed the evaluation results and concluded that the evaluation provided a sufficient basis for the licensee's conclusion that immediate action was not required. The inspector therefore closed this open ite.2 Hope Creek Open Item Follow-up (Closed) Unresolved Items (50-354/92-03-01 and 02); High Pressure Coolant Injection (HPCI) Flow Controller Setpoint and Tolerances. The licensee addressed these issues as follows:

Revised surveillance procedure HC.OP-IS.BJ-OOOl(Q) to include a step to record the HPCI controller setpoint, and

Verified that the HPCI loop flow calibration was less than 112 %, which is equivalent to 15 gpm, and

Modified the HPCI periodic calibration program to check flow loop every 18 months, and

Concluded that the HPCI setpoint of 5600 gpm (less tolerances) is satisfactory to meet the small break loss of coolant analysis and assumption ***

The inspeetor reviewed these items, 'including documentation, procedures, analysis and licensee actions. Based on this review, the inspector closed these open item (Closed) Unresolved I~em (50-354/92-03-06); Instrumentation Described in the Updated Final Safety Analysis Report (FSAR) Not Installed in Plant. Seetions 1.8.1.52.2 and 7. 3.1.1. 9.4 of the FSAR reference filter pressure drop alarm and recorder instrumentation on the filtration, recirculation and ventilation system (FRVS) vent fans. During a physical walkdown of the FRVS in April 1992, no such instrumentation was found. The licensee determined that the subject instrumentation had not been installed and evaluated whether the

FRVS fans currently met their design bases. As documented in their 10 CFR 50.59 safety analysis, the purpose of these downstream filters is to remove any charcoal fines from the process air flow. The licensee concluded that adequate indication and annunciation was available in the control room to verify operability. Consequently, the licensee concluded that the instrumentation described in the FSAR was not required, and processed FSAR Change Notice (CN) 92-18 to remove it. This change was submitted to the NRC on. December 16, *

199.

The inspeetor reviewed the licensee's 10 CFR 50.59 analysis and conclusions, and determined that it adequately demonstrated that the FRVS could meet its design safety functions without the pressure drop and recorder instrumentation. The inspector also verified that CN 92-18 had been approved and issued (reference PSE&G Letter NLR-192586 dated December 16, 1992). This change will be incorporated in the 1993 annual revision to the FSAR. Therefore, the inspector closed this open ite.

SAFETY ASSESSMENT/QUALITY VERIFICATION Salem * Open Item Follow-up (Closed) Violation (50-272 and 311/92-07-02); Control Room Habitability Relative to the On-site Storage of Ammonia. The licensee responded to the violation in a letter dated August 27, 1992. The licensee concluded root cause to be inadequate evaluation, analysis, and documentation of potential control room habitability issues. Licensee corrective actions included reduction of the on-site storage ammonia concentration, evaluation that the control room would not be impacted, revision of administrative controls, training of operators relative to ammonia detection, revision of the UFSAR, and modification of the engineering process to include non-safety reviews during the design proces The inspeetor reviewed the violation response and verified selected corrective action Additional NRC reviews of this issue are documented in NRC Inspection 50-272 and 311/91-25, 91-32 and 92-07. Based on this, the inspector closed the open ite I

8.2 * Hope Creek Significant Event Response Team (SERT)

The Hope Creek plant manager initiated two SERTs during the period. One SERT reviewed a partial loss of off-site power (See Section 2.2.2.A) and the other SERT reviewed a reactor scram (See Section 2.2.2.B).

The inspector reviewed SERT activities, including SERT reports 93-01 and 02, and discussed each event with team members. The inspector concluded that each SERT effectively and thoroughly reviewed and assessed the events. Further, SERT's root cause and corrective action determinations were technically soun.3 Commo Station Operations Review Committee (SORC)

Based on questions from the licensee, the inspector reviewed the SORC meeting requirements. This included the Hope Creek and Salem Technical Specification (TS) 6. which pelineate SORC meeting frequency, scope, quorum and membership. The TSs designate station managers for the SORC position of Chairman and Vice-Chairmen. The licensee may designate an acting manager to fill the position of the SORC Chairman/Vice-Chairma The inspector reviewed this issue with licensee personnel, and with the NRR licensing.

project manager. The inspector concluded that an acting manager could also fill a SORC Chairman/Vice-Chairman position if: (1) The designation is in writing, and (2) The individual meets the NSI NlS.1-1971 (Salem) on the ANSI/ANS 3.1-1981 (Hope Creek)

qualification requirement Additionally, the inspector reviewed a Quality Assurance/Nuclear Safety Review (QA/NSR)

assessment of the Salem and Hope Creek SORCs, as described in report NSR 92-047. The report concluded that SORC functions*well and reviews appropriate safetyissues. *

Recommendations included improvements for open item tracking, enhancements for process efficiency, and for enhancements of the design change proces The inspector reviewed the report and discussed it with QA/NSR and plant management personnel. Overall, the inspector noted the study and report to be thorough, well performed, and directed towards nuclear safety. * Quality Assurance/Nuclear Safety Review (QA/NSR)

The inspector reviewed recent PSE&G QA/NSR activities that have resulted in contributions to improve nuclear safety of the Salem and Hope Creek facilities. This included a review of

..

specific QA/NSR activities and associated* documentation, and a discussion with specific QA/NSR personnel. The inspector noted that the QA/NSR groups (e.g., Salem QA, Hope Creek QA, Off site Safety Review, Salem Onsite Safety Review; Hope Creek Onsite Safety Review, QA Engineering and Procurement, and QA Programs and Audits) provided positive contributions relative to tracking open and unresolved items, enhancing the efficiency of processes, and improving design change procedure NRC Bulletin 93-02; Debris Plugging of Emergency Core Cooling Suction Strainers On May 11, 1993, the NRC issued NRC Bulletin 93-02, "Debris Plugging of Emergency Core Cooling Suction Strainers." The bulletin required licensee's to identify fibrous material sources in containment, ensure functional capability of the emergency core cooling system *

(ECCS), and take prompt action to remove such material or provide justification for continued use. The NRC required a written response to the bulletin within 30 days. On May 17, 1993, the licensee performed a drywell walkdown at the Hope Creek facility to inspect for temporary filter media and other temporary sources of fibrous material. The licenSee found no such material in the drywell and did not identify any additional actions required by the bulletin. The licensee concluded that no fibrous debris existed in the torus based on a detailed inspection performed during their last refueling outage and the limited amount of work performed since that time. On May 19, 1993, the inspector, accompanied by the licensee, performed a walkdown of the drywell. The inspector verified that no fibrous filter material existed in the drywell unit coolers and that no loose debris, trash, or

.

temporary equipment was present which could potentially end up in the suppression poo * The licensee concluded that the Salem units have equipment containing air filter fibrous*

material not designed to withstand a loss of coolant accident (LOCA), but that this material does not have the potential to restrict flow to the containment sump. The effected equipment included the containment fan coil units (CFCUs) and iodine removal units (IRUs), which contain permanently installed fibrous material roughing filter During normal plant operation, at least three of the five CFCUs are in service for coolin With the CFCUs in high speed, containment air is drawn through inlet dampers and roughing filters on both sides of each unit, through a cooling coil and then discharged into a common distribution header. During a (LOCA) emergency operation the roughing filter inlet dampers close, the CFCU s shift to slow speed, and containment air is drawn through high efficiency particulate (HEPA) filters, partition dampers, across the cooling coil and then discharged into the common distribution header. The roughing filters are in the air flow path during normal operation and are isolated by inlet dampers during accident flow. The filters are necessary during normal operations as they function to remove the larger dust and dirt particles suspended in the containment atmosphere. Removal of these particles prevents their build-up on the cooling coils, thus avoiding a reduction in heat transfer, and minimizing the inventory of potentially contaminated particles in the containment atmosphere. Removing the roughing filters would effect the cooling coil fouling factor assumed in accident analysis, and

potentially impact the safety-related function of the CFCUs, which are designed to remove heat from the containment atmosphere to ensure the containment pressure does not exceed design limits in the event of a LOC The licensee performed an engineering analysis to justify leaving the roughing filters permanently installed in the CFCUs. The licensee concluded that should the roughing filters degrade in a LOCA environment that the fibrous debris would be, for the most part, -

completely contained within the CFCUs. The licensee's analysis determined that the filters are isolated externally, held in place internally by a fine wire mesh screen and frame, and are further screened from the containment sump by the cooling coils, which coupled with the octopus ductwork block all but the smallest of particles from reaching the containment atmosphere. The licensee included jet impingement considerations for postulated high energy pipe breaks inside containment and concluded that no such source posed a *threat to roughing filter integrity. The licensee's accident analysis also assumed that only 50 percent of the free surface area of the fine inner screen of the containment sump is available to conservatively account for partial blockage.*

The licensee also considers the filters installed in the IRUs to be acceptable considering that they are completely isolated during a LOCA. Two iodine units and fans are installed to reduce the airborne radioactivity levels, facilitate access to the containment, and to minimize

.doses to personnel. Air is drawn through inlet dampers, through the roughing filter, HEPA filters, charcoal filters, and outlet dampers into the fan where it is discharged Into the containment atmosphere. In the event of a safety injection (SI) signal, any IRU fan in operation will be automatically stopped and the inlet and outlet dampers will be close On May 12, 1993, the licensee successfully completed a containment sump surveillance to inspect the sump for debris or blockage. In addition, the licensee's engineering, operations and licensing personnel performed a containment walkdown of Salem Unit 2 to identify loose debris or other potential sources of sump blockage. The licensee's walkdowns revealed no additional actions required as a result of the bulleti The inspector reviewed the licensee's preliminary response to address any relevant safety.

concerns prior to the restart of Hope Creek and Salem Unit 2. The inspector discussed the bul1etin with the licensee's engineering and licensing organizations. The inspector reviewe the containment building ventilation configuration baseline documentation, the CFCU Vendor Manual, and the required in-plant lineup and operating procedures. The inspector also performed a detailed walkdown of the containment, with particular emphasis on the CFCU s, IRU s, and the containment sump. The inspector observed good housekeeping practices and

found no additional concern~ affecting containment sump debris blockag On May 25, 1993, the licensee, NRC resident staff and NRR technical contacts participated in a conference call to discuss the bulletin and the licensee's intended action and respons The licensee presented their engineering analysis. to demonstrate that it was prudent to allow Salem Unit 2 to restart with roughing filters in containment. The licensee adequately

addressed NRR's questions concerning roughing filter purpose, filter degradation in a LOCA environment, and* potential fibrous debris transport to the containment sump. The bulletin remains open pending licensee's submittal of their detailed engineering analysis and final NRC review of that documentatio Deficiency and Discrepancy Corrective Actions During the follow-up investigation concerning containment fan coil.unit (CFCU) regulators (See Section 7.1. E), the licensee identified minor weaknesses in the incident report, engineering discrepancy control, deficiency report, and work control processes. The inspector found the processes properly implemented during the identification and resolution of the CFCU regulator issue. However, room for improvement exists in clearly defining the

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interactions between the processes and in potentially streamlining the processes. This item is unresolved (URI 50-272 and 311/93-15-04; 50-354/93-11-01) pending completion of licensee corrective actions and procedure enhancements, and subsequent NRC revie.

LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOW-UP LERs and Reports PSE&G submitted and reviewed for accuracy and evaluation adequacy the following special and periodic report *

Salem and Hope Creek Monthly Operating Reports for April 1993

. 1992 Salem Annual Operating Report

1992 Annual Environmental Operating Report

Salem Unit 2 Steam Generator Tube Plugging Report dated May 4, 1993 The inspe.ctor concluded that the licensee appropriately issued the above report Salem LERs Unit 1

LER 91-35, Revision 1, Supplement concerned a containment isolation due to lRlRA

. radiation monitor. The licensee updated the LER's cause and corrective actfons. The inspector reviewed and closed the LE *

LER 93-10 concerned less-than-design service water flow through the diesel generators' jacket water and lube oil coolers. This condition was discussed in NRC Inspection 50-272 and 311/93-08, Section 7. The inspeetor reviewed the LER, concluded that the report was adequate, and closed the LE Unit 2

LER 92-15, Revision 1 concerned an update to an event concerning containment control air header* isolation valves. The licensee modified the cause and related corrective actions. The inspector reviewed the LER, concluded that the licensee took appropriate actions, and closed the LE *

LER 93-06 concerned an inadvertent.safety injection signal (SI) during response time testing of solid state protection system logic. No water was injected into the reactor coolant system as the SI pumps were cleared and tagged for reactor refueling. See Section 4.3.1.A of this report. The inspector closed this LE Hope Creek

LER 93-01-01 is a revision to LER 93-01 (see NRC Inspection 50-354/93-06 for details) and corrected an error in the first submittal. Reference to an earlier LER, 86-09, was amended to read 89-06. The inspector noted the correction and had no.

further questions, and closed the LE *

LER 93-02 discussed required post-maintenance retest activities which the license failed to perform on several valves that had been repaired during the last outage. The retest activities, required to meet the in-service test requirements of Technical Specification 4.0.5, included recording valve stroke time. However, during a review of outage work orders, operations personnel discovered that stroke times had not been recorded. The inspector reviewed the LER, concluded that the licensee took appropriate actions, and closed the LE.2 Open Items The inspector reviewed the following previous inspection items during this inspection. These items are tabulated below for cross reference purpose &3 l 1/91-01-02 50-272&311/91-16-02 50-272/91-18-02 Report Section 2.2..3..3. Closed Closed Closed

I

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Site Report Section Status 50-272&311191-26-02 7. Closed 50-311191-81-01 2.2. Closed 50-272&311192-07-01 2.2. Closed 50-272&311192-07-02 8. Closed 50-272&311192-09-02 7. Closed 50-:272&311/92-11-01 4.3. Closed 50-272&311192-13-02 7. Closed 50-272&31 i/93-02-01; 93.:26-P21 7. Closed

. 50-311193-01-02 7. Closed Hope Creek 50-354/92-03-01 and 02 7. Closed 50-354/92-03-06 7. Closed 50-354/92-06-01.

2.2. Closed 50-354/92-13-01 4.3. Closed 50-354/93-02'-01 2.2. Closed 50-354/93-06-0.2. Closed 10. * EXIT INTERVIEWS/MEETINGS 1 Resident Exit Meeting The inspectors met with Mr. C. Vondra and Mr. R. Hovey and other PSE&G personnel periodically and at the end of the inspection report period to summarize the scope and findings of their inspection activitie Based on NRC Regfon I review and discussions with PSE&G; it was determined that this report does not contain information subject to 10 CFR 2 restriction *

1 SpecialiSt Entrance and Exit Meetings Date(s)

4/19-23/93 4/19-23/93 Subject *

Emergency Preparedness Engineering and Technical Support Inspection Report N &311193-13; 354/93-09 50-272&311/93-14; 50-354/93-10 Reporting Inspector Gordon*

Cheung

...,.

Date(s}

5/10-14/93 5/17-21/93 5124-28/93 5/24-28/93 6/1-4-93 Subject Rad con Effluents Fire Protection Erosion/Corrosion Requal Program Inspection Requal Program Inspection 1 Managem~nt Meetings

Inspection Report N /93-12 50-272&311/93-80 50-272&311/93-17; 50-354/93-15 50-272&3 l 1 /93-16 50-354/93-13 Integrated Schedule Program (ISP)

Reporting Inspector Jang Paolino Patniak Bissett Florek On May 12, 1993, a management meeting was held on site to discuss PSE&G's ISP implementation. The licensee discussed their program and responded to NRC question NRC Generic Fundamentals Examination On May 18, 1993, a management meeting was held in the Region I office to discuss the results of a recent NRC Generic Fundamentals Examination; The licensee discussed their exam and course analysis and their corrective actions to improve performanc General Management Meeting On April 19, 1993, senior PSE&G managers met with the NRC staff to explain the recent organizational changes, discuss the current economic factors associated with the operation of Salem and Hope Creek, and review current and past performance. Licensee and NRC attendees are identified in Attachment *-.

...

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ATTACHMENT I MANAGEMENT MEETING ATTENDEES APRIL 19, 1993 NRC REGION I PUBLIC SERVICE ELECTRIC AND GAS COMPANY S. E. Miltenberger, Vice President and Chief Nuclear Officer.

S. LaBruna, Vice President - Nuclear Engineering J. J. Hagan, Vice President - Nuclear Operations F. X. Thomson, Manager - Nuclear Licensing and Regulation W. L. Stewart, Nuclear Public Information Representative NUCLEAR REGULATORY COMMISSION T. T. Martin, Regional Administrator, Region I (RI)

W. F. Kane, Deputy Regional Administrator, RI.

J. T. Wiggins, Deputy Director, RI W. M. Hodges, Director, Division of Reactor Safety, RI

.

C. L. Miller, Director, Project Directorate 2, Office of Nuclear Regulation (NRR)

E. C. Wenzinger, Chief, Projects Branch 2, Division of Reactor Projects (DRP), RI J. R. White, Section Chief, Reactor Projects Section 2A, DRP, RI S. Dembek, Project Directorate 1-2, NRR.

OTHER D. Vann, New Jersey BNE.

J. Berr, Today's Sunbeam

v t e Inspection Report - Salem - 1993015
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1993 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 8(0) 9(0) 10(0) 11(0) 12(0) 14(0) 15(0) 16(0) 17(0) 18(0) 19(0) 20(0) 21(0) 22(0) 23(0) 24(0) 25(0) 26(0) 27(0) 28(0) 29(0) 30(0) 80(0) 81(0) 99(0) 27(0) Security Operator Exams Emergency Planning Other

IR 05000272/1993015

Text

REGION I

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