IR 05000272/1999001
| ML20205J317 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 04/01/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18106B153 | List: |
| References | |
| 50-272-99-01, 50-272-99-1, 50-311-99-01, 50-311-99-1, NUDOCS 9904090303 | |
| Download: ML20205J317 (26) | |
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! U. S. NUCLEAR REGULATORY COMMISSION l l
REGION 1 ;
Docket Nos: 50-272, 50-311 License Nos: DPR-70, DPR-75 l
Report N /99-01, 50-311/99-01 Licensee: Public Service Electric and Gas Company i
Facility: Salem Nuclear Generabng Station, Units 1 & 2 Location: P.O. Box 236 Hancocks Bridge, New Jersey 08038 Dates: January 17,1999 - March 7,1999 Inspectors: S. A. Morris, Senior Resident inspector F. J. Laughlin, Resident inspector H. K. Nieh, Resident inspector L. M. Harrison, Reactor Engineer i
Approved by: Glenn W. Meyer, Chief, Projects Branch 3 Division of Reactor Projects i
l 1 ~9904090303 990401 *
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.1 g EXECUTIVE SUMMARY Salem Nuclear Generating Station NRC Inspection Report 50-272/99-01, 50-311/99-01 l This inspection included aspects of operations, maintenance, engineering, and plant suppor The report covers a seven-week period of resident ins'.sctio Operations
Observed operator performance was generally good, however aggressive pursuit of the source -
of increased reactor coolant system leakage was not evident until prompted by station management. Maintained of a selected alternate shutdown equipment cabinet was adequate, and preparations for cold weather were appropriate. (Section 01.1)
A personnel error resulted in a Unit 1 main turbine trip and subsequent automatic reactor trip .
when an equipment operator inadvertently unseated an isolation valve in the lubricating oil system. The plant operated as designed in response to the event, and control room operators completed post-trip response actions in a timely, appropriate manner. Control room operators had been unaware of the potential for a plant transient due to inadequate communications from field operators regarding their plan to manipulate the noted valve. Post-trip review and root cause assessment efforts were comprehensive, self-critical, and timely. Planned corrective actions and the root cause determination were reasonable. (Section Oi.2)
Chemistry technicians and control room operators exhibited a good questioning attitude in response to indications of a possible fuel failure, and operators appropriately determined that no emergency event declaration was warrarned. Subsequent evaluations ruled out any fuel failur PSE&G personnel performed appropriate maintenance activities and surveillance tests during the short duration forced outage. Station operators effectively prepared for and safely conducted plant start up activities in the control room. (Section 01.3)
Control room operators promptly and appropriately responded to an unplanned loss of overhead annunciators (OHAs) at Unit 2, which included a timely, accurate Unusual Event declaratio (Section 01.4)
The quality assurance department continued to provide comprehensive independent ,
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assessmena of station operations. The Nuclear Review Board remained a strong, self-critical safety assessment panel. (Section 07.1)
Corrective actions for a December 1998 event involving an inadvertent discharge of reactor coolant to the containment building were reasonable and timely. (Section 08.1)
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Maintenance An unplanned loss of overhead annunciators (OHA) at Unit 2 was the direct result of human error, due in large part to inattention to detail and weak OHA maintenance procedure guidanc The root cause assessment and corrective actions were thorough. (Section M1.2)
Operators performed well and equipment operated as designed during an AFW system surveillance test performed in support of the Unit i restart. (Section M1.3)
PSE&G successfully completed on-line work activities affecting plant safety systems before the expiration of TS allowed outage times. Technicians were knowledgeable, and post maintenance testing was appropriate. The associated on-line maintenance plans were detailed. However, in
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both cases the equipment outage durations exceeded planned unavailability times, in part due to pre-planning deficiencies and inter-departmental work coordination problems. Post-work {
week critiques were self-critical and identified several issues, but these issues had been J previously identified and not resolved. (Section M1.4)
PSE&G effectively planned and executed an emergent corrective maintenance activity to replace a 28VDC battery cell found degraded during a technical specification surveillance tes Operators appropriately responded to the event, including commencing a shutdown and making a 10 CFR 50.72 non-emergency event notification. The return to full power operations was well controlled and coordinated. (Section M2.1)
Enaineerina PSE&G appropriately implemented the maintenance rule with respect to the Unit 2 ventilation system chiller units, which has led to improvements in overall system reliability. The cognizant system manager performed effective system performance monitoring, which included a quarterly system health report. (Section E2.1)
Though several design changes have been implemented which have improved the overall reliability of the service water (SW) system, PSE&G did not address individual SW component deficiencies in a manner commensurate with the system's relative risk significance, maintenance rule status, or performance history. Entry conditions for the SW-cooled component biofouling abnormal operating procedure were vague, arid a heat exchanger biofouling tracking log was not maintained up to date. A recent Salem general manager directive to work SW maintenance activities on a continuous basis was not adhered to in all cases. Quality assurance personnel identified numerous housekeeping deficiencies in the SW intake structure. (Section E2.2)
Selected minor modification packages were of good quality, though numerous modification packages remained in the document update backlog. PSE&G established a reasonable goal for completing all outstanding document changes. Several minor discrepancies noted by the inspectors were promptly corrected. (Section E8.1)
PSE&G's electrical raceway fire barrier project was progressing as scheduled. (Section E8.2)
Plant Suooort PSE&G exhibited excellent radiological control practices during a 12 reactor coolant pump maintenance activity inside the biological shield. (Section R1.2)
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TABL3 OF CONTENTS
EXEC UTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . il TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv i
1. Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 O1 Conduct of 0perations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 O1.1 General Com ments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 1 01.2 Unit 1 Reactor Trip . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 01.3 Unit 1 Forced Outage and Restart Activities . . . . . . . . . . . . . . . . . . . . . 5 O1.4 Loss of Unit 2 Overhead Annunciators . . . . . . . . . . . . . . . . . . . . . . . . 6 07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 07.1 Review of CA Audits and Nuclear Review Board Activities . . . . . . . . . 7 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 08.1 (Closed) LER 50-311/98-015-00 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 08.2 Institute of Nuclear Power Operations (INPO) Assessment Review . . 8 I I . M a inten ance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 M1.1 General Com ments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 M1.2 Loss of Unit 2 Overhead Annunciators . . . . . . . . . . . . . . . . . . . . . . . . . 9 M1.3 Auxiliary Feedwater System Surveillance Test . . . . . . . . . . . . . . . . 10 M1.4 On-line Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . . . . 12 M2.1 Emeroent Corrective Maintenance for 2B 28VDCEattery . . . . . . . . . . 12 M3 Maintenance Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . 13 M3.1 Surveillance Test Procedure Review . . . . . . . . . . . . . . . . . . . . . . . . . 13 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 M8.1 (Closed) LER 50-272/96-013-01 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 M8.2 (Closed) LER 50-272/98-015-01 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 111. E ngineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . 15 E2.1 Maintenance Ruie implementation for Safety-Related Chiliers . . . . . 15 E2.2 Service Water System Performance . . . . . . . . . . . . . . . . . . . . . . . . . . 16 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 E Review of Minor Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 E8.2 - Electrical Raceway Fire Barrier Project . . . . . . . . . . . . . . . . . . . . . . . . 19 IV. Pla nt S upport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0 R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . . . . . 20 R1.2 Emergent Maintenance in High Radiation Area . . . . . . . . . . . . . . . . 20 V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 X2 Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 X3 M iscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
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l Report Details Summary of Plant Status r
Unit 1 began the period at 100% power. On February 27,1999, control room operators reduced power to 25% in order to perform corrective maintenance on the 12 reactor coolant pum During the subsequent retum to power ca February 28, the reactor automatically tripped due to a main turbine trip caused by equipment operator error. The unit was restarted on March 3, 1999, cnd returned to full power operation the following day. The unit remained at full power until the end of the report perio Unit 2 began the period at 100% power. On February 17,1999, control room operators commenced a power reduction in accordance with a technical specification action statement requirement associated with a degraded 28VDC battery. Load was reduced to nearly 75%
before the battery was repaired. Operators subsequent l/ retumed the unit to full power, where it remained for the balance of the perio . Operati 9 nt 01 Conduct of Operations O1.1 General Comments (71707) Jngpetion Scope (71707)
l l The inspectors conducted frequent observations of ongoing plant operations, including l control room walkdowns, log mviews, and shift tumovers. The inspectors also conducted numerous plant tours to observe equipment operation and nuclear operators working in the fiel Observations and Findinos l
In general, the conduct of operations was professional and safety-conscious. Nuclear equipment opersbra were knowledgeabb of plant systems and performed thorough tours. On Februai917,1999, the inspectors observed portions of a controlled plant shutdown required by Unit 2 technical specifications (TS) due to an emsrgent equipment is, sue on the 2B 28VDC battery (see section M2.1). PSE&G personnel completed .
corrective measures prior to ti,e expiration of the time period allowed by the TS action
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statement, and subsequently retumed the unit to full power operation that same da The ob&rved plant evolutions were well coordinated by control room operator During the inspection period, the Unit 2 reactor coolant system unidentified leakage rate increased from approximately 0.10 gallons per minute (GPM) to greater than 0.25 GPM This leakage could be from sources either inside or outside the containment building. TS
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l l 6.8.4.a requires that PSE&G implement a program to minimize reactor coolant leak I
sources outside containment. Although the leakage rate was well below the maximum allowed value of 1.0 GPM, operations were not aggressive in determining the source of
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the increased leakage until prompted by senior PSE&G managemen The inspectors inventoried the contents of a Unit 1 attemate shutdown equipmmt cabinet (required by em9tgency operating procedures (EOPs)), and noted that it was adequately maintained. Some minor deficiencies were noted; however the deficiencies
, were aliesdy entered into the corrective action system. The inspectors reviewed PSE&G's preparations, for cold weather and determined that appropriate measures were implemented in accordance with station procedures. Noted deficiencies had been documented in the corrective action progra Conclusions Observed operator performance was generally good, however aggressive pursuit of the source of increased reactor coolant system leakage was not evident until prompted by station management. Maintenance of a selected attemate shutdown equipment cabinet was adequate, and preparations for cold weather were appropriat .2 Unit 1 Reactor Trio Inspection Scope (71707. 62707. 93702)
At 1:38 a.m. on February 28,1999, the Salem Unit 1 reactor automatically tripped from 60% power due to a main turbine trip. Power was at a reduced level because of a planned load reduction to 25% the previous day to repair the 12 reactor coolant pump (see section R1.2). The turbine tripped on main lubricating oillow bearing pressure immediately after an inadvertent draining of oil. The inspectors responded to the site to assess the nature of the event and to assess performance in stabilizing plant conditions and identifying the event causa(s,. Observations and Findinas Based on reviews of control room logs, event recorder printouts, and interviews with d.ation operators and management, the inspectors determined that Unit 1 operators implemented timely, appropriate actions following the reactor trip. For example, a manual reactor trip signal (an initial action under the EOP) was inserted just four seconds after the automatic signal was received. With cae exception, the plant operated as de tied in response to the transient. The exception involved the 11 r,uxiliary feedw Aer pump discharge valve, which failed to open automatically due to a faulty pressure transmitter Operators immediately recognized this condition and s.ppropriately bypassed the fadty pressure eignalin accordance with established procedures. The plant was subsequently stabilized in Mode 3 while attempting to determine the cause of the initiating main turbine trip. Operators completed a 10 CFR 50.72 non-emergency event notification lo the NRC operations center within the raquired four hours.
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i Station management promptly arrived on site following the event and quickly attributed the cause of the turbine trip to a personnel error. Specifically, PSE&G determined that a momentary low main turbine lubricating oil pressure signal was created when an equipment operator and supervisor (a licensed senior reactor operator) inadvertently unseated an oil system tagging boundary valve (1TL45). Maintenance technicians were working on a vented and drained lubricating oil cooler as part of a related corrective maintenance activity. Interviews determined that the operators actually intended to increase the valve seating force in an effort to minimize suspected leakage past the valve seat, which was impacting the ongoing maintenance effort. However, the individuais mis-operated the valve (a Shutte & Koerting six-way valve) because of a shared knowledge deficiency with regard to the unusual manner in which it function PSE&G's follow-up root cause investigation determined that no one at the station fully understood the manner in which this unique valve functioned, including the operations training staf Poct-trip assessment and root cause determination efforts were comprehensive, self-critical, and timely. The inspectors reviewed the written assessment, attended the station operations review committee ISORC) meeting that evaluated the report and the proposed corrective actions, and P sd the corre tive actions to be reasonable. These actions included operator trainine ITL45 valve operation, main turbine lubricating oil system procedure enhancemerr ., and renewed emphasis on communicating planned field activities to control room personnel prior to changing the status of component This last action was created because control room operators were unaware that the 1TL45 valve was to be manipulated, in spite of the linpact a mis-operation would have on continued plant operation. Lastly, PSE&G management accepted part of the fault for the reactor trip since they allowed power to be raised above 50% before the main turbine lubricating oil cooler was restored. By design, a main turbine trip below 50% would not have caused an automatic reactor tri c. Conclusi_qng A personnel error resulted in a Unit 1 main turbine trip and subsequent automatic reactor trip when an equipment operator inadvertently unseated an isolatio 1 valve in the lubricating oil syste n. The plant operated as designed in response to the event, and control room operators completed post-trip response actions in a timely, appropriate manner. Control room operators had been unaware of the potentiai far a plant transient due to inadequate communications from field operators regarding their plan to manipulate the noted valve. Post-trip review and root cause assessment efforts were comprehensive, self-critical, and timely. Planned corrective actions and the root cause determination were reasonable.
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O1.3 Unit 1 Forced Outaae and Restart Activities Inspection Scope (71/07. 61726)
During the Unit 1 forced outage from March 1 through 4,1999, the inspectors monitored surveillance testing activities and observed control room operators conducting the -
reactor start up, Observations and Findinos PSE&G chemistry technicians and control room bperators exhibited a good questioning attitude in response to indications of a possible tuel failure. Specifically, shortly after the Unit i reactor trip, chemistry personnel obtained a sample of the primary coolant and noted that the dose equivalent iodine (DEI) levels were substantially higher than previously observed. Additionul sampling per; nned at an increased frequency validated the initial result and monitored the trend. Engineers later demonstrated that the elevated del, though unusual, were explainable and did not represent a fuel failure, based on the reactor power history of a long period of full power followed by a brief power reductio Later, operators observed that the 1R31 reactor coolant system letdown radiation ,
monitor also detected increased levels of coolant activity. Timely follow up by radiation I protection department staif to this indication determined that the 1R31 detector was in an i area adjacent to a radioiogical " hot spot * created by a crud burst following the reactor !
trip. When the 1R31 subsequently reached the " warning" level, operators appropriately 1 reviewed the Salem emerDency classification guide (ECG) to determine whether an Unusual Event declaration per section 1.1.1.c was needed. The inspectors independently reviewed the ECG, and concluded that the operators appropriately 1 deemed that no emergency event classification was warrante ,
PSE&G personnel conducted appropriate maintenance activities and surveillance tests !
during the short duration forced outage. All required technical specification (TS) testing was completed prior to changing from Modes 3 to 2 and from 2 to 1. Additionally, the ;
inspectors noted that PSE&G ,made reasonable efforts to complete some of the TS i surveillance tests that were included in an earlier surveillance test deferral reques ;
PSE&G had submitted a request to the NRC on January 15,1999, seeking a one-time !
test interval extension for several surveillances in order to preclude the need for a mid- ,
cycle shutdown simply to conduct testing. One of these ac+ivities was completed during j
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the outage.
e Operators effectively prepared for and safely conducted reactor and plant startup l activities in the control room. The operating crews had conducted reactor start up training in the Salem control room simulator just prior to commencing the actual evolution at the station. The inspectors observed excellent self- and peer-checking practices, especially with regard to reactivity manipulations. Good three-point communications and supervisory oversight were evident, and management provided full-time reactor engineering support during the startur Nities. Quality assurance (nA) department
- staff maintained independent oversir f, d control room opsrations th.. og? cut the restart
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- effort. The Salem Unit 1 main generator was synchronized to the offsite electrical grid on l
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March 4,1999,96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after the unit automatically tripped.
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Chemistry technicians and ccntrol room operators exhibited a good questioning attitude in response to indications of a possible fuel failure, and operators appropriata'y determined that no emergency event declaration was warranted. Subsequent evaluations ruled out any fuel failure. PSE&G personnel performed appropriate maintenance activMies and surveillance tests during the short duration forced outer e Statica operators effectively prepared for and safely conducted plant start up activities in the control room.
l O1.4 Loss of Unit 2 Overherud Annunciators Insoection Scope (71707. 62707. 93702)
On February 2,1999, Salem Unit 2 operators declared an Unusual Event in accordance with PSE&G emergency classification guide (ECG) section 8.2.1, following an unanticipated loss of control room overhead annunciators (OHAs). The plant was
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operating at 100% power at the time of the event. Upon notification the inspectors
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promp+ly responded to the Unit 2 control room to assess the nature of the event and to evaluate PSE&G's performance in resolving the condition. The maintenance aspects of this event are discussed in Section M I Observations and Findinos Control room operators promptly and appropriately responded to the loss of OHA at Unit l 2, which included a timely and accurate Unusual Event declaration. At 11:00 a.m. on !
February 2,1999, operators entered abnormal procedure S2.OP-AB. ANN-0001(Q) in l response to a console alarm in the control room which indicated an OHA system faul I Prescribed immediate and subsequent compen natory actions were implemented in a timely manner. These actions included the addition of a third licensed reactor operator in the control room, suspension of all ongoing plant activities, increased monitoring of 1 attemate alarms and indications, and conCnuous in-plant observations of safety systems l and equipment. The operations superintendent promptly reviewed and classified the ;
event in accordance with the ECG within 15 minutes of recognizing the occurrenc Operators exited the Unusual Event at 3:40 p.m., following complete restoration of the OHA syr, te Conclusions Control room operators promptly and appropriately responded to an unplanned loss of l overhead annunciators (OHAs) at Unit 2, which included a timely, accurate Unusual Event declaratio :
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07 Quality Assurance in Operations 07.1 Review of QA Audits and Nuclear Review Board Activities Inspection Scooe (71707)
The inspectors reviewed several QA department audits to assess the scope and depth of the reviews and to understand the nature of their findings. The inspectors also attended a February 3 - 4,1999 meeting of the Nuclear Review Board (NRB) and reviewed the
- associated meeting minute Observations and Findinos The QA department continued to provide comprehensive independent assessments of station operations. For example, on February 17,1E 9, QA completed an audit of equipment status control in which several issues were identified, including the discovery
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of a large number of abandoned station equipment / systems which were being controlled solely with blocking tags. Several other issues were raised regarding the overall effectiveness of the station tagging program. The auditors appropriately i:ntiated corrective action requests (ARs). QA personnel initiated several other ARs, including one that documented numerous housekeeping deficiencies in the service water intake j structure. (See section E2.2).
The NRB remained a strong, self-critical safety assessment panel. The inspectors attended a recent meeting of the board and observed that the members provided good insights to line management and sufficiently challenged the manner in which station activities were being performed. The inspectors also reviewed the minutes of the recent meeting, which accurately reflected the board's proceedings and listed the various action items developed for future resolutio Conclusions l
The quality assurance departme,nt continued to provide comprehensive independent assessmeats of station operations. The Nuclear Review Board remained a strong, self-critical ec'ety assessment pane Miscellaneous Operations issues O8.1 ~ { Closed) LER 50-311/98-015-00: Inadvertent Discharoe Throuah RHR Relief Valve (Closed) VIO 50-311/98-12-01: Failure to Follow Procedures Inspection Scope (92700. 92901)
The inspectors performed an onsite review of the co7ective actions for the event documented in the subject voluntary licensee event report (LER). The event involved the inadvertent discharge of reactor coolant through the residLAl heat removal (RHR) system
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relief valve and was documented in NRC Inspection Report 50-272/98-12, Section O1.2, and resulted in the subject Notice of Violation. The inspectors reviewed PSE&G's root cause evaluation for this event and discussed corrective actions with station managemen Observations and Findinos PSE&G completed a thorough root cause evaluation for this event which resulted in numerous corrective actions. The inspectors reviewed several of these actions and verified that they were either completed or scheduled in the corrective action program, including actions to correct the inaccurate procedures and the inappropriate RHR system alarm setpoint while in chutdown cooling mode. The inspectors dotermined that one of tne issues identified following the event was not adequately addressed by the planned corrective actions. Specifically, the inspec'. ors noted that the issue involving the lack of timely implementation of the emergency classification guide lacked explicit corrective measures. The inspectors discussed this concem with training and emergency preparedness personnel, who subsequently added a corrective action to specifically address the timeliness issue. The inspectors determined that this was sufficient to address the concem. The immediate corrective actions for this event were comprehensive, ea documented in the noted NRC inspection repor Conclusions Corrective actions for a December 1998 event involving an inadvertent discharge of reactor coolant to the containment building were reasonable and timel .2 Institute of Nuclear Power Operations (INPO) Assessment Review The inspectors reviewed the most recent INPO assessment of Salem performance, which was conducted in November 1998, and was documented in a report dated l December 31,1998. No safety issues were identified as a result of this revie !
11. Maintenance
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.M1 Conduct of Maintenance (50001,62707,61726,92902, & 40500)
M1.1 General Commen The inspectors observed all or portions of the following maintenance and surveillance activitie Unit 1
. S1.OP-ST.CVC-000412 charging pump surveillance test
. WO 990211218 Inspect 15 service water strainer
. WO 990201257 Repair control rod 1D4 indication
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. WO 980907018 Calibrate 1B EDG lube oil cooler controls
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WO.981001200 Repair 24SW56 Unit 2
. S2.OP-ST.DG-000228 emergency diesel generator surveillance test
. . WO 961014004 Replace 2SV1415/1416 on 2B EDG
. WO 990120131 Repair 2WL17 l
. WO 980524016 23MS10 air actuator testing .
. WO 981201024 Calibrate 22 Si pump discharge pressure transmitter
. -WO 961206292 Repair 21SW77 I
. WO 981108074 Repack 25 service water pump
. WO 990208052 Lubricate Unit 2 service water strainers The inspectors observed that PSE&G personnel performed the maintenance and surveillance activities in accordance with station requirements. Minor deficiencies were promptly corrected. The inspectors also observed two " confidence" runs of the 13 auxiliary feedwater (AFW) pump, and noted proper supervisory and technical personnel oversight, and good procedural implementation during AFW system operatio M1.2 Loss of Unit 2 Overhead Annunciators j Insoection Scope (71707. 62707. 93702)
On February 2,1999, a Salem Unit 2 Unusual Event resulted following an unanticipated loss of control room overhead annunciators (OHAs). The plant was operating at 100%
power at the time of the event and e preventive maintenance activity on the OHA system had been in progress Following the event the inspectors interviewed system engineering and management personnel to understand the causes and corrective actions for the occurrence. The operational aspects of this event are discussed in Section 0 Observations and Findinos The inspectors noted that this event was the direct result of human error, mainly due to
- individual inattention-to-detail and weak OHA maintenance procedure guidance. The OHA system is comprised of two independent and redundant computer processors (sequence of event recorders (SER) A and B), only one of which is normally in servic At the time of the occurrence, a PSE&G system engineer was attempting to restore SER B to service following a planned preventive maintenance activity. During the restoration
- process, the engineer inadvertently induced an SER initialization command to the in service processor (SER A), which effectively inhibitM its function. Upon recognition of his mistake, the individual promptly reported the error to control room operator The inspectors reviewed PSE&G's root cause assessment for this incident and noted that it was very thorough. The inspectors also interviewed some of the individuals directly involved in the loss of OHA event, reviewed the procedure which governed the
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OHA maintenance activity, and independently reached the same conclusions identified in OSE&G's causal determination. The inspectors noted that the procedure, SC.YE-TI.ZZ-0019(Z), " Overhead Annunciator RCW Computer Usage," contained sufficient guidance to complete the maintenance task successfully, but relied heavily on individual knowledge of the OHA system to ensure that it could be implemented consistently without error. - The engineer involved with the February 2 incident had successfully performed this maintenance task in the past but in this case simply missed a critical step in the procedure which would have prevented the even '
Corrective actions both proposed and implemented focused both on the circumstances specific to the OHA event as well as other potential concems with similar equipment and procedures. For exEmple, the noted maintenance procedure was placed on administrative hold until it could be thoroughly reviewed and rewritten to provide more specific and user-friendly guidance. PSE&G also placed other computer hardware / software related maintenance procedures on hold for a similar evaluatio Plant management planned to emphasize the use of human error-reduction techniques with all staff, but in particular with engineering department personnel because they do not frequently conduct work activities which have the potential to adversely impact plant equipmen I Conclusions An unplanned loss of overheau annunciators (OHA) at Unit 2 was the direct result of human error, due in large part to inattention to detail and weak OHA maintenance procedure guidance. The root cause assessment and corrective actions were thoroug M1.3 Auxiliary Feedwater System Surveillance Test Insoection ScoD*, (61726)
On March 3,1999, in preparation for the Unit i restart, the inspectors observed surveillance testing of the 12 and 13 AFW pumps required by technical specification (TS) 4.7.1. ) Observations and Findinas The inspectors found that all equipment performed properly and that the acceptance criteria presented in Salem operating procedure S1.OP-ST.AF-0004(Q), Revision 11,
" Auxiliary Feedwater"were met. Specifically, the 12 and 13 AFW pumps started automatically on a simulated actuation signal, and the steam generater blowdown and sample system isolation valves isolated automatically. Operators appropriately performed independent verifications and the survaillance test was completed successfully. The inspectors verified that AFW system valves were properly aligned in the Unit 1 auxiliary building. No problems were identifie , ,
11 Qonclusion Operators performed well and equipment operated as designed during an AFW system surveillance test performed in support of the Unit 1 restar M1.4 On-line Maintenance Inspection Scope (62707)
The inspectors observed planned maintenance activities on risk significant system Field inspections included direct observations of mainte.ance technicians and verification of appropriate work orders, procedures, and equipment tagouts. For the
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j selected system outages, PSE&G prepared detailed on-line maintenance plans '
documenting responsible personnel, contingencies, risk assessments, and activity
. timeliness. The inspectors reviewed thase plans to assess their quality and to evaluate adherence to the plans. Additionally, the inspectors reviewed selected post-work week critiques prepared by planning department personnel.' The critiques documented PSE&G's self-assessment of the effectiveness of their maintenance and planning effort Observations and Findinas !
The inspectors observed scheduled work activities associated with the 24 containment fan cooler unit (CFCU) and the 1B emergency diesel generator (EDG), and determined that PSE&G properly performed the activities in accordance with station guideline Maintenance technicians were thoroughly prepared and knowledgeable of the tasks performed. All required documentation was present at the work sites, and prescribed !
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_ post-maintenance tests were appropriate. The it.apectors ider,tified one minor deficiency associated with the restoration of an EDG temperature instrument. Maintenance personnel immediately corrected the discrepancy. The inspectors verifed that station operators entered the appropriate technical specification action statements (TSAS) and prepared adequate tagouts. The inspectors also conducted field walkdowns of ,
redundant systems to verify that they were maintained in an operable conditio l l
In both of the on-line equipment outages reviewed, the actual maintenance duration i exceeded the scheduled outage time in spite of reasonably welFprepared plans. For j example, completing the 24 CFCU maintenance activities exceeded the scheduled outage duratior by 34 hours3.935185e-4 days <br />0.00944 hours <br />5.621693e-5 weeks <br />1.2937e-5 months <br />, in part due to emergent corrective maintenance activities !
necessitated by a degraded 28 VDC vital battery (see Section M2.1). Additionally, !
equipment tagouts took several hours longer than expected to implement. For he 1B ;
EDG, maintenance activities exceeded the planned duration by five hours. Delays l resulted from unanticipated tagging evolutions, and the need to re-perform the outage ;
risk assessment due to a change in assumed plant conditions. For both outages, the
, time to complete post-maintenance testing activities was underestimated by approximately four hour ,
The inspectors concluded that sorne of the work delays resulted from good attention to
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this good questioning attitude, these delays indicated inefficiencies in the work planning process since the discrepancies could have been identified during the weeks precedir g the work. The inspectors also noted several other instances of work planning
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deficiencies. For example, PSE&G personnel conducted a leak rate surveillance test of a containment isolation valve (WL17) without developing adequate contingency plans in the event of a test failure. As a result, whon the leak rate test did in fact fail, the required spare parts were not available to effect prompt repairs. This resulted in delays in other scheduled activities, additional burdens on station maintenance personnel, and an extended period in a TSAS, accumulating equipment unavailability time. PSE&G management later prompted the initiation of a corrective action request to address the issue of poor contingency plannin PSE&G conducted comprehensive and self-critical post-work week critiques that reflected a strong focus on self-assessment. The inspectors reviewed several critique documents and observed that, while the critiques were appropriately focused on enumerating the problems experienced during the on-line work, the same basic problems had been identified in previous weeks. For examp'e, the critiques routinely listed spare parts unavailability, lack of qualified technicians, and work coordination problems as reasons why scheduled work was not completed in the time allotted. The I
inspectors noted that PSE&G initiated corrective action requests to resolve several of the individual issues involved, but because these issues had been previously identified without being resolved, the inspectors were uncertain that effective long term corrective action wow resul Conclusions PSE&G successfully completed on-line work activities affecting plant safety systems before the expiration of TS allowed outage times. Technicians were knowledgeable, and post maintenance testing was approprit.te. The associated on-line maintenance plans were detailed. However, in both cases the equipment outage durations exceeded planned unavailability times, in part due to pre-planning deficiencies and inter-departmental work coordination problems. Post-work week critiques were self-critical and identified several issues, but these issues had been previously identified and not resolve M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Emeroent Corrective Maintenance for 2B 28VDC Battery Insoection Scooe (61726. 62707. 71707)
During a quarterly surveillance test on February 16,1999, maintenance technicians determined that the 28 28VDC battery cell 9 failed to meet technical specification (TS) 3.8.2.5 requirements foi v.dividual cell voltage. The inspectors reviewed PSE&G's response to this emergent issue which placed the Unit 2 facility in two hour TS shutdown ac'.lon staten;en I i
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I Observations and Findinos At 11:00 p.m. on February 16, after being notified of the battery cell test failure, control room operators promptly entered the associated TS action statement. Operators raised the overall3attery voltage using the charger to the maximum allowed level, but this effort 4 failed to recover the degraded cell. Mair tenance and planning personnel promptly developed an action plan to replace the cell with a spare from the on-site warehous Because the cell replacement was not completed within the two hour TS allowed outage l time, requiring a plant shutdown to be completed within six hours, operators appropriately made a non-emergency notification to the NRC operations center in accordance with 10 CFR 50.72. At 2:02 a.m. on February 17,1999, operators commenced a controlled shutdown of Salem Unit Maintenance, engineering, and operations personnel exhibited good coordination in the unexpected cell replacement activity. The battery was restored to an operable condition at 3:51 a.m., and operators terminated the Unit 2 load reduction at approximately 80%
power. The inspectors observed portions of the return to full power and noted that these activities were also well controlled and coordinated. The inspectors also verified that the narrative log entries and the non-emergency event notification accurately described the circumstances of the event. Operators properly initiated a corrective action request in accordance with PSE&G guidanc Conclusiong PSE&G effectively planned and oxecuted an emergent corrective maintenance activity to replace a 28VDC battery cell found degraded during a technical specification surveillance test. Operators appropriately responded to tha event, including commencing a shutdown and making a 10 CFR 50.72 non4mergency event notificatio i The retum to full power operations was well controlled and coordinate !
l M3 Maintenance Procedures and Documentation M3.1 Surveillance Test Procedure Review 3 Insoection Scope (61726) l i
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The inspectors reviewed the adequacy of selected TS surveillance test procedures. The inspectors verified that the pr6cedures met TS requirements and that previous test results were within established acceptance criteri Observations and Findinos >
The inspectors selected TS functional test procedures associated with the Unit 2 emergency core cooling automatic switchover and containment pressure protection l channels (S2.lC-FT.RCP-0072/73/74/75 and S2.lC-FT.RCPC M/67/68/69, respectively). The test metnodology employed in the proceda a satisfied the channel i
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functional test requirements of TS, which states that a simulated signal be injected as l
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close as practicable to the primary sensor to verify alarm and/or trip functions. The inspectors reviewed the history of previous test performancas end found that PSE&G personnel performed the tests within the required intervals. A review of previously completed procedures revealed that the test results were within the required acceptance criteria, e,nd that PSE&G personnel appropriately reviewed the test result Conclusions Surveillance test procedures associated with the Unit 2 emergency core cooling automatic switchover and containment pressure protection channels satisfied technical specification requiremns. PSE&G personnel performed the noted tests within the required intervals and appropriately reviewed the result M8 Miscellaneous Maintenance issues M8.1 (Closed) LER 50-272/96-013-01: Scalina Error of Overtemperature Delta Temoerature Inspection Scope (92700)
The inspectors conducted an on-site review of the subject licensee event report (LER)
and verified selected corrective actions. This LER is a supplement to one which was I
reviewed and closed in NRC Inspection Report 50-272/98-08, Section M8.1, as a non-cited violation (NCV). The original LER documented a self-identified issue that overtemperature celta temperature (OTDT) instruments were improperly scaled, ,
rendering them inoperable over a small portion of their operating range. It also stated that the cause of the occurrence was under investigation and would be reported in a
supplemental report , I Observations and Findinas PSE&G completed their root cause investigation which revealed a problem with the methodology used to set the lead / lag module time constants in the OTDT instrument Spacifically, the time constant calibration method was not in strict compliance with technical specifications (TS) b that the station maintenance procedure allowed a * 0%
tolerance about the nominal value as acceptance criteria. The TS specified only a single
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value for the time constants (i.e. no tolerance). PSE&G determined that this could result j in time constant values which were set non-conservatively relative to the plant accident j analysi !
During their root cause assessment PSE&G obtr'ned an evaluation from Westinghouse l which stated that setting the time constants in accordance with the calibration procedure j
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nominal values would not impact the safety analysis due to the conservatism included in the instrument gain settings. The inspectors reviewed the Westinghouse report and agreed that the OTDT instruments were calibrated in such a way as to not compromise safety. The inspectors further verifiexf that PSE&G planned to submit a license change request to provide for a nominal time constant value with an appropriate toleranc )
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i 15 Conclusions PSE&G completed reasonable actions to identify and correct deficiencies associated I with the overtemperature delta temperature instrument scaling error M8.2 (Closed) LER 50-272/98-015-01: Imoroper installation of Test Eauioment to the Reactor Protection System The inspectors conducted an in-office review of the subject LER supplement, which documented the completion of PSE&G's evaluation of the event previously described in the original LER and in NRC Inspection Report 50-272 & 311/98-11, section M8.1. No new issues were identified. PSE&G's investigation of the root causes and potential consequences for the subject event was adequat . Enaineerins E2 Engineering Support of Facilities and Equipment E Maintenance Rule Imolementation for Safetv-Related Chillers Inspection Scope (62707. 37551)
The inspectors interviewed system engineering personnel and reviewed applicable documentation to assess the adequacy of maintenance rule implementation for the Unit 2 ventilation chilled water system, which was in "a(1)" (goal monitoring) statu Obsarvat:ons and Findinas The 23 chiller unit exceeded its unavailability (400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br />) and reliability (2 preventable system functional failures) goals during the fourth quarter of 1997, mainly due to the poor performance of the service water temperature control valve (23SW102). PSE&G's corrective actions were effective, and included the installation of improved controllers on al! SW102 valve actuators to improve the valve's sensitivity to the rate of water temperaturo change. Additiona'ly, PSE&G increased the valve seat inspection frequency since the seats were wearing out prematurely due to silt deposition. A long term corrective actior: to evaluate changing the valve seats to a more durable material was also planne The 21 chiller unit exceeded its unavailability goal of 400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br /> during the fourth quarter of 1998, again largely due to 21SW102 valve actuator failures and the replacement of a degraded refrigerant compressor. The system manager recognized that this chiller would eventually exceed its unavailability goal for the operating cycle simply by completing routina proventive maintenance, and pro-actively initiated a corrective action request to doctaneni the issue.
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The inspectors concluded that PSE&G had implemented reasonable corrective actions which improved overall Unit 2 chiller performance. Unit 1 chillers performed well since operating experience leamed from the Unit 2 chillers was applied early in the operating cycle. The system manager close!y monitored system performance and adequately documented the chiller system status in a quarterly system health repor Conclusions PGE&G appropriately implemented the maintenance rule with respect to the Unit 2 ventilation system chiller units, which has led to improvements in overall system reliability. The cognizant system manager performed effective system performance monitoring, which included a quarterly system health repor E2.2 Service Water System Performance Inspection Scooe (37551. 62707)
The service water (SW) system is a risk-significant system that has had a recent history of unreliable performance during periods of high river grass concentration. River grass concentis.tions have historically been at their peak in the late winter /early spring month The inspectors conducted frequent tours of the SW intal's structure, interviewed station personnel, and reviewed procedures and other documentation to assess the effectiveness of PSE&G's actions to minimize biological fouling (biofouling) of safety-related heat exchangers. The SW system was a category a(1) system in accordance with PSE&G's maintenance rule program, and is fourth on the " Top Issues List" maintained by the Salem engineering departmen Observations and Findinos PSE&G made several design changes to the SW system over the past few years which have immved the reliability of the system, including piping upgmdes, discharge strainer filter eleinent modifications, and pump replacements. In spite of the overall SW system performance improvements, several individual issues have continued to challenge station personnel and equipmen Throughout this report period, the inspectors observed that PSE&G did not address SW system deficiencies in a manner comnansurate with its relative risk-significance, maintenance rule status, performance history, or assigned importance as an engineering department top issue. For example, corrective action program (CAP) implementation with respect to SW issues was weak. The inspectors noted that the significance level and resolution methods for SW-related corrective action requests (ARs) were inconsistent. Various significance levels were assigned to nearly identical issues, and in at least one case no AR was initiated at all. Similarly, some ARs were closed via corrective maintenance work orders with no cause determination, while mome were no In one case a SW-related AR was initiated as a business process enhancement (vice a condition adven. 'o quality), potentially indicating a lack of appreciation on the part of
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the AR initiator, approver, and the CAP reviewer as to the importance of SW system relisbility at Sale The inspectors also noted that the entry conditions for the component biofouling abnormal procedure (SC.OP-AB.ZZ-0003 (AB)) were vague. This procedure specified compensatory measures to be implemented during periods of abnormally high river grass levels. This procedure did not include an entry condition for repetitive SW strainer failures, even though these everit, have providesd early indication of grass biofoulin Several strainer failures were experienced during the early part of the report period and the operating crew did not enter the AB on any of those occasions. Subsequently, on February 15,1999, PSE&G engineers identified that both SW-cooled heat exchangers on the 11 charging pump failed flow tests due to biofouling. Based in part on this discovery, control room operators entered the component biofouling AB which mandated increased SW-cooled component performance monitorin The inspectors noted that a recent general manager directive that all SW system maintenance be performe'l "around the clock" was a positive initiative to clinimize unavailability time, but in practice some service water work did not meet this expectatio For example, on February 22,1999, the 25 SW pump discharge strainer blowdown valve failed, rendering the SW subsystem inoperable. The subsystem was not restored to an operable condition until March 4,1999, ten days later. Several delays were encountered in executing this corrective maintenance activity, in part due to maintenance personnel not working the job on a continuous basis. Lack of spare parts also contributed to the delay. Within hours of restoring this subsystem on March 4, two other Unit 2 SW strainers experienced heavy grass loading and subsequent failure The inspectors noted other evidence of insufficient management attention with respect to improving SW system reliability and availability. These include:
e The control room log used to trend safety-related heat exchanger biofouling was not kept up to date. This deficiency was corrected after the inspectors identified i e Quality assurance department personnel identified a condition adverse to quality involving numerous housekeeping deficiancies in the SW intake structure.
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- The 26 SW pump was tagged out of service on three separate occasions over a two day period to add additional pump shaft packing material, e A planned design change to improve the grass removal capability of the SW traveling screens was not impiemented prior to the present heavy grass season (January through May), and was planned to be completed on Unit 2 after the April outage. Modification of the Unit 1 screens began in Marc e The non-safety related SW trai ake at Unit 1 has been out of service since August 1997, 1eeded work on tnis component has been rescheduled several time a , . . .
18 Conclusions Though several design changes have been implemented which have improved the overall reliability of the service water (SW) system, PSE&G did not address individual SW component deficiencies in a manner commensurate with the system's relative risk significance, maintenance rule status, or performance history. Entry conditions for the SW-cooled component biofouling abnormal operating procedure were vague, and a heat exchanger biofouling tracking log was not maintained up to date. A recent Salem general manager directive to work SW maintenance activities on a continuous basis was not adhered to in all cases. Quality assurance persanel identified numerous housekeeping deficiencies in the SW intake structur E8 Miscellaneous Engineering issues E8.1 Review of Minor Modifications Ingegction Scope (37551. 37700)
The inspectors reviewed several minor modification packages (MMPs) to verify that the modifications were processed in accordance with established guidelines, including 10 CFR 50.59. Specifically, the inspectors verified that the modifications received the appropriate level of technical evaluation and approval, and that the appropriate changes to plant documents were completed. The inspectors also performed a field walkdown of selected modifications. PSE&G procedure NC.NA-AP.ZZ-0017 (NAP-17), " Minor Modification Process,"was used as a reference.
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The inspectors selected MMPs based on the relative risk importance of the affected !
systems. The following packages were reviewed:
. S97-015 Rescale RHR heat exchanger CCW flow transmitter
. S97-040 Replace CCW pump low discharge pressure relays
- S97-042 Replace spring pack on 2RH1 motor actuator
. S97-164 Rewire 11CC16 motor actuator
. S97-174 Relocate ECCS relief valve discharge lines to floor drains Observations and Findinas PSE&G personnel appropriately applied the NAP-17 process to the selected MMPs, in that complex engineering input was not needed. Each MMP contained adequate levels of technical evaluation, including 10 CFR 50.59 applicability reviews. Each MMP addressed the appropriate plant drawings, procedures, and documents affected by the I modification. The inspectors identified some uJar discrepancies, though none adversely impacted equipment operability. A fie;J walkdown of MMP S97-040 showed i
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that the modification was installod as designed and modifie Two of the +ive MMPs affected plant documents that remained to be updated, though the inspectors concluded that none of these documents were essential to safe plant
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operation. The inspectors noted that numerous MMPs, some of which dated back to 1996, still awaited completion. All of the outstanding MMPs needed only an administrative review or updating of non-essential documents. PSE&G personnel established a goal to have all outstanding MMPs comp!eted by June 1999. The ,
inspectors verified that drawings and procedures used during operations and I maintenance activities were appropriately revised to reflect MMP implementatio The inspectors also noted that the minor modification tracking log contained inaccuracies conceming the status of several MMPs. These discrepancies were corrected by PSE&G personne Conclue'ons Selected minor modification packages were of good quality, though numerous modification packages remained in the document update back!og. PSE&G established a reasonable goal for completing all outstanding document changes. Several minor discrepancies noted by the inspectors were promptly correcte E8.2 Electrical Raceway Fire Barrier Proiect [qsoection Scope (37551)
The inspectors held discussions with Salem design engineering personnel regarding the ;
objectives, scope and current status of the ongoing electrical raceway fire barrier project ;
(ERFBP). )
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PSE&G personnel last discussed the ongoing ERFBP with the NRC staff on September !
23,1998 in Rockville, Maryland. The ERFBP consists of three phases, the first of which is a complete re-evaluation of the Salam safe shutdown analysis. The subsequent phases involve the development of any needed design changes and their installation At the end of the report period, the inspectors verified that the ERFBP was on schedule I with the firs! phase sIready completed at Unit Conclusions PSE&G's electrical raceway fire barrier project was progressing as scheduled.
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- 0 IV. Plant Support R1- Radiological Protection and Chemistry (RP&C) Controls i
- R1.2 Emeroent Maintenance in Hiah Radiation Area
, Inspection Scoos (71750)
i The inspectors observed maintenance activities on 12 reactor coolant pump (RCP)
which is inside the biological shield in the Unit 1 containment building, including plar.ning, the addition of oil to the lower motor bearing oil sump, and a check of the low level alarm switch. Control room operators had received a 12 RCP motor low oil sump level alarm earlier in the month. The work was performed on February 27,1999 with the reactor at
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approximately 25% of rated powe .. Observations and Findi.oga PSE&G maintenance and radiation protection (RP) department personnel performed a thorough pre-job brief, which included a comprehensive discussion of the expected
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radiological conditions in the vicinity of the 12 RCP, contingency plans, a detailed review of the specific maintenance activities, and industrial safety. The RP department established a dose gcal of 1 REM for the evolution based on the expected gamma radiation levels. No neutron dose wcs expecte The inspectors entered the biological shield area and directly observed the maintenance and RP technicians performing and monitoring the work, and noted excellent radiological practices throughovt the evolution. Appropriate anti-contamination clothing was wo ]
Thorough area sinveys and briefings were completed just prior to commencing work The RP technician directly rnonitoring the evolution frequently checked the dosimetry
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readings on the workers to ensure that dose goals were not exceeded. Maintenance work practices were deliberate and effective, whirh permitted the job to be completed in dess than 20 minutes. A quick check was made for the source of the oilleak. Upon work completion, the total exposure for all personnel involved was about 75% of the 1 I
REM goa Conclusions i PSE&G exhibited excellent radiological control practices during a 12 reactor coolant pump maintenance activity inside the biological shield during power operatio V, Management Meetings I X1: Exit Meeting Summary On March 12,1999, the inspectors presented their findings and conclusions to members of PSE&G management led by Dave Garchow. PSE&G management acknowledged the findings
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presented and did not contest any of the inspector's conclusiono Additionally, they stated that none of the information reviewed by the inspectors was cons ! proprietar X2 Management Meeting Summary On February 2,1999, NRC Region I management held a teleconference with members of PSE&G management to discuss the initial results of PSE&G's investigatioriinto the loss of overhead annunciators at Salem 2. This incident, which was declared an Unusual Event in accordance with PSE&G's emergency classification guide, is described in detail in sections 0 and M1.2 of thiu .epor X3 Miscellaneous On February 26,1999, Mr. D. Garchow of PSE&G assumed the duties of General Manage,r -
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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 90712: Inoffice Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Plant Operations Followup IP 92902: Maintenance Followup IP 92903: Engineering Followup IP 92904: Plant Support Followup IP 93702: Event Followup ITEMS OPENED, CLOSED, AND DISCUSSED Closed 50-311/98-12-01 VIO Failure to follow procedures. (Section 08.1)
50-272/96-013-01 LER Scaling error of overtemperature delta temperature resulted in inoperable protection channels. (Section M8.1)
50-311/98-015-00 LER Inadvertent discharge through RHR relief valve during startup. (Section O8.1)
50-272/98-015-01- LER Improper installation of test equipment to the reactor protection system. (Section M8.2)
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LIST OF ACRONYMS USED l
AFW Auxiliary Feedwater I AR Action Request l CAP Corrective Action Program CFCU Containment Fan Cooler Unit ECG Emergency Classification Guide EDG Emergency Diesel Generator ERFBP Electrical Raceway Fire Barrier Project DEI Dose Equivalent lodine l GPM Gallons Per Minute ,
LER Licensee Event Report l
MMPs Minor Modification Packages l NCV Non-Cited Violation NRB Nuclear Review Board )
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NRC Nuclear Regulatory Commission OHA Overhead Annunciators OTDT Overtemperature Delta Temperature PDR Public Document Room PSE&G Public Service Electric and Gas QA Quality Assurance RCP Reactor Coolant Pump RHR Residual Heat Removal RP Radiation Protection SER Sequence of Event Recorders SW Service Water l TS Technical Specification TSAS Technical Specification Action Statement
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