IR 05000272/1998012

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Insp Repts 50-272/98-12 & 50-311/98-12 on 981206-990116. Violations Noted.Major Areas Inspected:Operations, Engineering,Maint & Plant Support
ML18106B068
Person / Time
Site: Salem  PSEG icon.png
Issue date: 02/12/1999
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18106B066 List:
References
50-272-98-12, 50-311-98-12, NUDOCS 9902190289
Download: ML18106B068 (24)
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Docket Nos:

License Nos:

Report N Licensee:

Facility:

Location:

Dates:

Inspectors:

Approved by:

U.S. NUCLEAR REGULATORY COMMISSION 50-272, 50-311 DPR-70, DPR-75

REGION I

50-272/98-12, 50-311/98-12 Public Service Electric and Gas Company Saleni Nuclear Generating Station, Units 1 & 2 P.O. Box 236 Hancocks Bridge, New Jersey 08038 December 6, 1998 - January 16, 1999 S. A. Morris, Senior Resident Inspector F. J. Laughlin, Resident Inspector H. K. Nieh, Resident Inspector Glenn W. Meyer, Chief, Projects Branch 3 Division of Reactor Projects 9902190289 990212 PDR ADOCK 05000272 G

PDR

EXECUTIVE SUMMARY Salem Nuclear Generating Station NRG Inspection Report 50-272/98-12, 50-311/98-12 Tl")is inspection included aspects of PSE&G operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspectio Operations Inadequate procedures, ineffective oversight of plant evolutions, and deficient operator knowledge resulted in a 1300 gal discharge from the reactor coolant system to the containment sump during a plant startup evolution. The operations superintendent appropriately classified the event in accordance with emergency plan guidance, but the event declaration was not timely. PSE&G's corrective actions were comprehensive and long term corrective actions were reasonable. A quality assurance department assessment of emergency plan implementation during the event was adequate. (Section 01.2)

With the exception of the reactor coolant system leak event, plant startup activities following the Unit 2 forced outage were generally conducted in a well controlled manner with an appropriate level of management oversight. Emergency core cooling system components inside containment were properly aligned to support power operation. (Section 01.3)

The Unit 1 service water system configuration was consistent with the Updated Final Safety Analysis Report and was properly aligned for plant conditions. System material condition and housekeeping were acceptable. The associated system manager was closely monitoring system performance. A general manager directive corrected the poor maintenance practice of not working service water pump trains around the clock dur'ing on-line maintenance. (Section 02.1)

The existing number of operator workarounds at both units was reasonable and was being appropriately managed. Nonetheless, the inspectors identified two additional deficiencies needing continued operational action; one was repaired and the other was added to the workaround listing. (Section 07.1)

In November 1997, PSE&G personnel failed to properly translate service water (SW) system design change information into plant procedures. As a result, plant operators improperly isolated the SW overpressure protection path for a containment fan coil unit during July 1998 maintenance activities. PSE&G's corrective actions for this self-identified issue were adequat (Section 08.1)

Maintenance Salem operations and maintenance staff were frequently challenged with emergent corrective maintenance issues, which adversely impacted the effectiveness of the established work week schedules. However, all of these emergent issues were adequately resolved using PSE&G's ii

work management process and without undue plant risk. The Salem staff properly assessed each of these emergent equipment concerns to ensure that maintenance rule performance information was accurately captured. (Section M1.2)

Effective management oversight of the backlog resulted in a substantial reduction in the volume of outstanding work activities though the backlog of corrective maintenance activities remained large. PSE&G's prioritization scheme for scheduling the backlogged work was reasonable. The quality assurance department's continued focus in this area was appropriate and helped to ensure that line management maintained corrective maintenance backlog reduction as a station priority. (Section M2.1)

PSE&G's corrective actions for multiple component deficiencies identified following a failed surveillance test of the 13 auxiliary feedwater (AFW) pump were reasonable. Troubleshooting and maintenance activities were appropriate and well-controlled, and maint~nance rule implementation was good. Operator inattention to detail during post-maintenance testing resulted in the mispositioning of the AFW pump local/remote switch, which damaged pump trip circuitry and caused expanded on-line work scope. (Section M2.2)

Continued weaknesses in work coordination between the operations and maintenance departments and individual attention to detail were evident during three testing activitie PSE&G management appropriately responded to each of the specific examples using their corrective action process. (Section M4.1)

PSE&G exhibited prompt and thorough action on an emergent concern involving a degraded 28 VDC vital battery cell. SORC reviewed an associated operability determination which yielded an effective battery corrective action plan. (Section M7.1)

Engineering.

PSE&G engineers developed and implemented a condenser offgas radiation monitor design change which improved the reliability of the system. The design modification process was properly employed, and 1 O CFR 50.59 requirements were effectively addressed. The discovery of a non-conservative assumption in the monitor alarm setpoint calculation was an example of a good self-assessment finding. (Section E2.1)

Though PSE&G personnel successfully completed a technical specification surveillance of the control room emergency air conditioning system (CREACS) within the specified test interval, several delays were encountered which negatively impacted other scheduled work week activities. Also, the inspectors had identified a weakness in the test plan that further delayed the evolution. The design basis for CREACS had not been clearly established in the Salem licensing basis documentation but was being corrected. (Section E3.1)

Plant Support PSE&G properly implemented the observed security equipment maintenance activities with minimal impact to the on-duty security force personnel. Protected area barriers and personnel access control were properly maintained. (Section S2.1)

iii

  • TABLE OF CONTENTS EXECUTIVE SUMMARY....................................................... ii TABLE OF CONTENTS........................................................ iv I. Operations................................................................. 2

Conduct of Operations............................................. 2 0 General Comments......................................... 2 0 Unit 2 Reactor Coolant System Leak Resulting in Unusual Event Declaration................................................ 2 0 Restart from Unit 2 Forced Outage............................ 5

Operational Status of Facilities and Equipment......................... 5 0 Unit 1 Service Water System Walkdown......................... 5

Quality Assurance in Operations..................................... 7 0 Resolution of Plant Deficiencies............................... 7

Miscellaneous Operations Issue...................................... 8 0 (Closed) LER 50-272/98-012-00..... :.. :...................... 8 0 (Closed) LER 50-311/98-016-00............................... 8 II. Maintenance.................... * *.. *......................................... 9 M 1 Conduct of Maintenance........................................... 9 M1.1 General Comments......................................... 9 M 1.2 Emergent Corrective Maintenance............................ 10 M2 Maintenance and Material Condition of Facilities and Equipment.......... 11 M2;1 Corrective Maintenance Backlog Review....................... 11 M Auxiliary Feedwater Pump Failed Surveillance Test............ 12 M4 Maintenance Staff Knowledge and Performance....................... 14 M Work Coordination and Implementation........................ 14 M7 Quality Assurance in Maintenance Activities........................... 15 M7.1 2B 28 VDC Vital Battery Cell Degradation...... *................ 15 Ill. Engineering.............................................................. 16

E2 Engineering Support of Facilities and Equipment....................... 16 E R15 Radiation Monitor Modification........................... 16 E3 Engineering Procedures and Documentation... :...................... 17 E Control Room Emergency Air Conditioning System Testing........ 17 IV. Pl.ant Support.............. *.............................................. 18 S2 Status of Security Facilities and Equipment........................... 18 S Security Equipment Modifications............................. 18 F8 Miscellaneous Fire Protection Issues................................ 19 F (Closed) LER 50-311/98-014-00.............................. 19 V. Management Meetings..................................................... 19 X1 Exit Meeting Summary............................................ 19 iv

Report Details Summary of Plant Status Unit 1 began the period at 100% power and remained at or near that power level until the end of the report perio Unit 2 began the period in cold shutdown to replace the 21 reactor coolant pump shaft seals. A reactor startup was conducted on December 11, 1998, the unit was synchronized* to the grid on December 12, and it returned to 100% power on December 13. The unit remained at or near full power until the end of the report perio I. Operations

Conduct of Operations 0 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations.. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the *

sections belo.2 Unit 2 Reactor*Coolant System Leak Resulting in Unusual Event Declaration Inspection Scope (93702. 92901)

The inspectors promptly responde*d to a reactor coolant system (RCS) leak event at Unit 2 that resulted in the declaration of an Unusual Event (UE) in accordance with the Salem event classification guide (ECG). Follow up reviews included discussions with plant operators and management, and a review of a quality assurance (QA) department assessment of the even Observations and Findings At 5:01 p.m. on December 8, 1998, with Unit 2 in hot shutdown, control room operators noted a rapidly lowering RCS pressurizer (PZR) level concurrent with a report of steam in the containment building. Over the next five minutes, PZR ievel lowered from approximately 26 to 14 percent, resulting in an automatic RCS normal letdown isolation at 17% PZR level. PZR level stabilized at 14% shortly after the letdown isolation. At the time of the event, a control room reactor operator (RO) was in the process of transferring RCS cooling from th~ RCS shutdown cooling made of the residual heat removal (RHR)

system to the steam dump system in preparation for plant startu Initially PSE&G personnel believed the*source of the leak to be from the normal RCS letdown line. However, they later determined that it was the result of an inadvertent opening of the RHR system common RCS suction relief valve (2RH3), which discharges

  • directly to the containment sump. PSE&G estimated that approximately 1300 gallons of
  • RCS inventory was discharged. No adverse radiological conditions were detected in the area following the event, and no personnel contamination resulted. All systems and equipment operated as designed. This event did not have any offsite consequence The inspectors concluded that there was inadequate supervision in the control room during the RHR transfer evolution, which ultimately resulted in the event. Further, the licensed operators' knowledge of the 2RH3 relief valve setpoint was deficient. The RO a~d the control room supervisor (CRS) both thought that the 2RH3 relief valve setpoint was 425 psig, but it was actually 375 psig. As such, the RO believed that he could safely increase RCS pressure to 375 psig. At the time of the event, there was one licensed RO at the control panels. PSE&G determined that the RO was engaged in controlling at least three separate evolutions simultaneously, including the transfer of RHR from shutdown cooling to the normal system standby lineup and raising RCS pressur PSE&G also determined that the RO was not adequately briefed for the shutdown cooling transfer evolution in that he could not recall being assigned a specific RCS pressure band to maintai Two other factors contributed to this event. First, the operations. procedure that governed the operational mode change from cold shutdown to hot standby, 82.0P-IO.ZZ-0002, permitted an RCS pressure increase up to the RHR relief valve setpoin Secondly, the RCS high pressure alarm with RHR in service was inappropriately set at 400 psig, providing no warning to operators of the approach to the relief valve setpoin PSE&G determined that the relief valve setpoint had been reduced from 450 to 375 psig in 1985 as a result of a design change, but that operating procedures and the high pressure alarm setpoint had not been adequately revised to account for the chang Additionally, PSE&G personnel missed an opportunity to correct this situation when the procedure was revised in 1997. The inspectors concluded that PSE&G's failure to provide adequate procedures for operation of the RHR system when proceeding from cold shutdown to hot standby was a violation of TS 6.8.1. (VIO 50-311/98-12-01)

The inspectors also reviewed the Salem ECG to determine the appropriateness and timeliness of the event classification. The OS declared a UE at 5:38 p.m. He exited the UE at 8:37 p.m. following restoration of the RHR system shutdown cooling lineup. At 9:33 p.m., based on further review of plant parameters at the time of the event, the OS determined that conditions during the event actually warranted an Alert classification, and made an "after-the-fact" 10 CFR 50. 72 non-emergency one-hour report to the NR The inspectors concluded that the UE declaration for this event and the "after-the-fact" alert *notification were reasonable.. The OS' decision to classify the event as a UE was based on emergency action level (EAL) 2.1.1.b, "Reactor Coolant System Unidentified Leakage Greater Than 10 gpm." The OS also reviewed EAL 3.2.2.a for an Alert, since the ECG directs a review of the fission product barrier table in Section 3 before event classification. EAL 3.2.2.a requires that an Alert be declared if "one centrifugal charging pump cannot maintain PZR level greater than 17% (as a result of RCS leakage)." The inspectors noted that the plant actually reached that threshold at about 5:05 However, plant conditions had stabilized within about seven minutes of event initiation

  • *

and operators had exited abnormal operating procedure S2.0P-AB.LOCA-0001 (Q) for a shutdown loss of a coolant accident (LOCA) by the time the OS consulted the ECG. As such, the ECG Alert criteria were no longer met, and the OS declared a UE. In fact, the inspectors judged that by the time the OS made the event classification, the ECG criteria for a UE were also not met, but the classification was nonetheless reasonable since a UE is also defined as "events in progress or that have occurred which indicate a potential degradation of the level of safety of the plant."

With regard to classification timeliness, the inspectors concluded that the OS did not consult the ECG in accordance with established guidelines.Section IV.A of the ECG states that the assessment of an emergency condition should be completed within about 15 minutes of event recognition. The Emergency Plan, Section 4.1, specifies the OS as the emergency coordinator (EC) during an emergency event while the CRS takes operational control of the unit. The event was first recognized at 5:01, but the OS did not consult the ECG until 5:25, largely because he was closely involved with direct oversight of plant operations without adequate consideration of his emergency plan duties. The UE declaration was not issued until 5:38 p.m. The OS did not assume the EC duties in a timely manner which was also a violation of TS 6.8.1. (VIC 50-311/98-12-01)

PSE&G initiated a "level one" action request to investigate and determine root causes for this event. Additionally, the Station Operations Review Committee (SORG) reviewed the event on December 10, 1998, and formulated immediate corrective actions to be completed prior to reactor startup. These actions included a brief of all crews covering key topics such as the roles and responsibilities of watchstanders, use of operating experience in briefings, procedural usage, and a review of temporary modifications for potential impact on plant operations. The inspectors attended both the SORG meeting and the crew briefing given to each operating crew before the startup recommenced, and concluded that the SORG was of sufficient scope and the briefings of sufficient detail to enable a safe plant startu The inspectors also reviewed PSE&G's QA department assessment report of the operating crew during the event which was performed at the request of SORG to assess the effectiveness of emergency plan implementation. This report concluded that Salem operations personnel appropriately classified the event as a UE, and made the proper after-the-fact Alert classification. QA also concluded that the UE classification (similar to NRG findings) and NRG notification should have been more timel The inspectors concluded that the QA assessment, though generally adequate, did not effectively address the issues concerning the primary duty of the OS during an emergency situation is to assume the EC position and the fact that the OS could have recognized much sooner that the Alert EAL had been exceede Conclusions

  • Inadequate procedures, ineffective oversight of plant evolutions, and deficient operator knowledge resulted in a 1300 gal discharge from the reactor coolant system to the containment sump during a plant startup evolution. The operations superintendent

appropriately classified the event in accordance with emergency plan guidance, but the.

event declaration was not timely. PSE&G's immediate corrective actions were comprehensive and long term corrective actions were reasonable. A quality assurance department assessment of emergency plan implementation during the event was adequat.3 Restart from Unit 2 Forced Outage Inspection Scope (71707)

The inspectors observed restart activities following the Unit 2.shutdown in December 1998 to repair a degraded reactor coolant pump seal. The inspectors also toured the containment building to verify proper emergency core cooling system (EGGS) alignment and general cleanlines Observations and Findings PSE&G personnel performed startup activities in a well-controlled manner, with one noted exception involving a substantial loss of reactor coolant (see section 01.2).

Station management and quality assurance personnel provided additional oversigh The inspectors verified the proper alignment of accessible EGGS components to support power operations inside the containment building. Additionally, the inspectors found the material condition and housekeeping of the Unit 2 containment building to be adequat Conclusions Plant startup activities following the Unit 2 forced outage were generally conducted in a well-controlled manner with an appropriate level of management oversight. Emergency core cooling system components inside containment were properly aligned to support power operatio Operational Status of Facilities and Equipment 0 Unit 1 Service Water System Walkdown Inspection Scope (71707)

The inspectors selected this system for a comprehensive walkdown due to its relative risk importance and the factthat the system is in a(1) status for maintenance rule considerations. The inspectors conducted a walkdown of accessible portions of the Unit-1 service water system. The inspectors also reviewed the Updated Final Safety Analysis Report (UFSAR), technical specifications (TS), piping and instrument diagrams; and selected procedures to verify that the system was being operated and maintained as designed.

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  • * *

Observations and Findings The service water system configuration was consistent with the UFSAR description and was properly aligned for existing plant conditions. The inspectors reviewed procedure S1.OP-SO.SW-0005(0), "Service Water System Operation," and determined that the procedure was consistent with TS and was adequate.for controlling system operatio The system material condition and housekeeping were acceptable. System components were operable and properly labeled. All observed valves were found in the proper position, locked open valves had acceptable lockwires in place, and remote position indicators were indicating properly. The inspectors viewed the interior of two service water pump 4KV motor supply breakers and found them to be clean, in good material condition, and with no noticeable evidence of arcin The engineering department service water system manager was actively involved in performance monitoring. He stated that he walked down the system on a monthly basis and performed weekly partial walkdowns. He maintained a component monitoring matrix to monitor the completion of TS surveillances and preventive maintenance of system components. He also produced a quarterly system health report in accordance with system engineering procedures to keep management appraised of system status, with emphasis on maintenance rule considerations. The inspectors reviewed the 1998 third quarter report and found it to be thorough and informative.

The system manager stated that he had questioned the maintenance practice of not working service water pump trains around the clock during on-line maintenance, since it resulted in the unnecessary accumulation of train unavailability time. The Salem general manager subsequently directed that all service water maintenance shall be worked continuously until all work is complete. The inspectors also concluded that this was a poor maintenance practice since the service water system was in maintenance rule a(1)

status and that the change was appropriate. *

Conclusions The Unit 1 service water system configuration was consistent with the Updated Final Safety Analysis Report and properly aligned for plant conditions. System material condition and housekeeping were acceptable. The system manager was closely monitoring system performance. A general manager directive corrected the poor maintenance practice of not working service water pump trains around the clock during on-line maintenance.

07 Quality Assurance in Operations 0 Resolution of Plant Deficiencies Inspection Scope (71707. 40500)

The inspectors reviewed PSE&G's operator deficiency program. Within scope of the program, operator workarounds (OWA), operator burdens, and degraded control room indicators are tracked and managed. The inspectors focused their review on the OWAs being tracked. As defined in PSE&G's operator deficiency program, an OWA is a deficiency that adversely affects plant operations and necessitates operators to take compensatory measures, which may degrade the operators' ability to respond to plant event * Observations and Findings At the end of the inspection period PSE&G personnel were tracking a total of 25 OWAs (12 at Unit 1, 11 at Unit 2, and 2 common); 21 of the 25 OWAs were scheduled for repair. Most of OWAs affected non-safety-related systems such as heating water, waste processing, circulating water, and condensate. Some of the OWAs affected safety-related systems, such as the service water and the chilled water systems, but did not pose any equipment operability issue The inspectors noted a weakness in the identification and classification of OWA During routine plant observations, the inspectors observed several deficiencies requiring additional operator actions. These included the more frequent equipment operator tours of the turbine driven auxiliary feed pump (TDAFP) enclosures (at both units) to verify proper ventilation damper alignment, and the frequent automatic source check failures of the control room ventilation intake radiation monitors, the latter of which required control room operator manual actions and a short duration entries into a technical specification action statement. Neither of these deficiencies were being tracked as OWAs, and operators had not raised these deficiencies to operations department personnel responsible for the operator deficiency program. PSE&G personnel reviewed the noted examples for applicability to the operator deficiency program and determined that the TDAFP enclosure additional tours represented an OWA. PSE&G personnel repaired the radiation monitor automatic source check deficiency by the end of the inspection period.

. Conclusions The existing number of operator workarounds at both units was reasonable and was being appropriately managed. Nonetheless, the inspectors identified two additional deficiencies needing continued operational action; one was repaired and the other was added to the workaround listing.

  • 08 Miscellaneous Operations Issue 0 (Closed) LER 50-272/98-012-00: Isolation of a SW Overpressure Protection Line Inspection Scope (92700. 92901}

The inspectors performed an onsite review of the nature, the root cause, and the corrective actions of the event described in the subject licensee event report (LER). Observations and Findings On July 15, 1998, during a maintenance activity for the No. 13 containment fan coil unit (CFCU), PSE&G personnel identified that the closed boundary valves isolated the service water (SW) header overpressure protection path. Plant operators vented and drained the affected SW header once the condition was identified eliminating the need for overpressure protection. PSE&G personnel determined that this configuration existed for approximately ten hours. No safety consequences resulted from this event since no overpressure condition occurre PSE&G personnel attributed the apparent cause of the event to inadequate procedure guidance resulting from insufficient attention to detail during a 1997 system design change that added a SW overpressure relief path to each CFCU. Specific~lly, operations department personnel failed to incorporate the unique configuration of the 13 CFCU SW overpressure protection piping into the affected SW and CFCU operating procedures during November 1997 procedure changes. The inspectors verified that PSE&G personnel revised the appropriate procedures to include the necessary caution for isolating 13 CFCU. This failure to translate system design information into plant procedures constitutes a violation of minor significance and is not subject to formal enforcement actio Conclusions In November 1997, PSE&G personnel failed to properly translate service water (SW)

system design change information into plant procedures. As a result, plant operators improperly isolated the SW overpressure protection path for a containment fan coil unit during July 1998 maintenance activities. PSE&G's corrective actions for this self-identified issue were adequat.2 (Closed) LER 50-311/98-016-00: ECCS leakage outside design basis value a:

Inspection Scope (92700)

The inspectors conducted an on-site review of the subject licensee event report (LER)

and verified selected corrective action *

  • Observations and Findings This LER documented a condition outside the Salem Unit 2 design basis identified by PSE&G staff on December 19, 1998. Specifically, operators discovered an approximately 0.5 gallons/niinute (114,000 cc/hour) leak into the residual heat removal (RHR) pump room sump. This leak exceeded the design basis maximum allowable leak rate from systems outside containment that are connected to the reactor coolant system (3800 cc/hour limit). Upon discovery, operators properly completed a 10 CFR 50.72 non-emergency event notification to the NRC operations center. PSE&G staff promptly determined the leakage path to be from the refueling water storage tank through a partially open RHR pump casing drain valve (via the RHR system). The valve was shut and the leak rate was returned to a value within design basis requirements. PSE&G personnel were unable to determine how the manual casing drain valve became unseated, but postulated that the valve may have been inadvertently disturbed during a quarterly inservice test of the associated RHR pump conducted the previous da The inspectors verified that no adverse consequences resulted from this event, and that PSE&G staff initiated an action request required by their corrective action program to document this occurrence. The inspectors also verified that PSE&G implemented and maintained a program for monitoring primary coolant leak sources outside containment in accordance with technical specification 6.8.4.a.

Conclusions Plant operators promptly corrected, reported and documented the self-identified discovery of RHR system leakage in excess of design basis requirements due to an open pump casing drain valv II. Maintenance M1 Conduct of Maintenance (50001, 62707, 61726, 92902, & 40500)

M1.1 General Comments Inspection Scope (61726. 62707)

The inspectors observed all or portions of the following maintenance and surveillance activitie * WO 990227028

  • WO 990114046
  • WO 981214090 Inspect 11SW102 1A vital bus undervoltage functional test Pressurizer pressure channel IV functional test 13 auxiliary feed water (AFW) pump speed oscillations 13 AFW pump room pressure relief panels repairs
  • SC.MD-ST:125-0003
  • SC.OP-PM.DG-0003

. * S1.OP-ST.DG-0002

  • S1.IC-FT.RCP-0048
  • WO 981019246
  • WO 991130018
  • S2.0P-ST.SW-0010
  • S2.RA-ST.CAV-0001
  • S2.0P-ST.DG-0003
  • S2.0P-ST.CVC-0003
  • S2.0P-ST.DG-0002

125 VDC battery surveillance test Emergency diesel generator (EDG) air start motors 1 B EDG surveillance test 13 steam flow channel I functional test 21 service water strainer repairs 22 charging pump lube oil cooler clean and inspect Service water valve inservice testing Control area ventilation system surveillance test 2C EDG surveillance test 21 charging pump surveillance test 28 EDG surveillance test The inspectors observed that PSE&G personnel performed the maintenance and surveillance activities within station 'requirements. Minor deficiencies noted by the inspectors were promptly corrected by PSE&G. Maintenance activities associated with the 21 reactor coolant pump seal replacement were well planned and supervised. The inspectors also reviewed tagouts associated with maintenance activities on the Unit 2 component cooling water and chilled water systems, and a Unit 1 containment fan cooler

  • unit; and found them to be properly implemented in accordance with station procedure M Emergent Corrective Maintenance Inspection Scope (62707)

Throughout the report period, the inspectors noted that there were frequent, unplanned corrective maintenance activities needed to address emergent plant equipment test and operational failures. The inspectors reviewed PSE&G's response to these issues, including the impact they had on preplanned and scheduled work activities. Initial

screening for maintenance rule impact was also assesse Observations and Findings Salem experienced several equipment failures during the period, which challenged the ability of the Salem staff to implement the preplanned on-line work schedule. The following is a partial list of the unplanned corrective maintenance:

  • 13 *auxiliary feed water (AFW) pump test failure
  • 13 containment fan coil unit (CFCU) service water valve test failure
  • 15 CFCU piping leak
  • 11 auxiliary building ventilation fan motor run failure
  • 2R 11, 2R 15, 2R41 radiation monitoring system faults
  • 22 component cooling heat exchanger service water inlet valve. test failure
  • The inspectors conducted varying degrees of follow up for each of the listed issues, noting that in no instance was an equipment failure a direct result of inadequate human performance. In each case, the Salei:n staff appropriately deferred previously scheduled on-line maintenance when needed to minimize plant risk. Further, operators promptly initiated corrective action requests and properly coded each of the emergent issues for maintenance rule system performance monitoring purposes. All system retests and technical specification operability requirements were satisfied prior to the expiration of any applicable allowed outage time Post-work week critiques conducted by work management staff adequately captured the various concerns in an attempt to assess their impact. The inspector's review of Salem work management performance indicators showed that work week schedule stability (number of activities completed versus number of activities originally scheduled)

averaged below 60% over the course of the report period, substantially below PSE&G goal Conclusions Salem operations and maintenance staff were frequently challenged with emergent corrective maintenance issues, which adversely impacted the effectiveness of the established work week schedules. However, all of these emergent issues Were adequately resolved using PSE&G's work management process and without undue plant risk impact. The Salem staff properly assessed each of these emergent equipment concerns to ensure that maintenance rule performance information was accurately capture M2 Maintenance and Material Condition of Facilities and Equipment M Corrective Maintenance Backlog Review Inspection Scope (62707) The inspectors assessed PSE&G's progress with regard to reducing the high number of backlogged work activities. The inspectors reviewed several PSE&G work planning documents and conducted interviews with members of the maintenance, planning, and quality assurance (QA) department Observations and Findings

. At the end of the report period, PSE&G management was tracking approximately 6,000 total work orders in the Salem non-outage maintenance backlog, down substantially from mid-1998 when the backlog was over 10,000 items. The inspectors attributed this reduction to increased management focus in this area, which included the implementation of a comprehensive action plan and the use of detailed performance indicators. The most significant reductions were realized by improvements in administrative processes, specifically in "closing out" completed work order documents to archive files. QA department auditors also maintained a focus on the backlog and

  • continued to provide objective assessments of station performance in this are PSE&G's method for prioritizing and scheduling the backlogged work was reasonabl The inspectors verified that nearly all of the outage corrective maintenance coded for outage periods was in fact scheduled for the next unit outage. The non-outage maintenance backlog was being reduced at a rate of nearly 100 work orders per week, by factoring the items into the appropriate on-line maintenance work weeks. The recently established work management center effectively screened and prioritized incoming work requests. The inspectors noted that the number of items categorized as

"minor maintenance" had actually increased in recent months. These activities were not included in the on-line work schedule, but rather were left to individual maintenance supervisors to work at their discretion. Hqwever, since the overall backlog had decreased, the inspectors judged that PSE&G management had appropriately focused greater effort on the reduction of the more significant work activities, thereby minimizing the potential safety impact of the backlog.

...,, :* Conclusions Effective management oversight of the backlog resulted in a substantial reduction in the volume of outstanding work activities, though the backlog of corrective maintenance activities remained large. PSE&G's prioritization scheme for scheduling the backlogged work was reasonable. The quality assurance department's continued focus in this area was appropriate and helped to ensure that line management maintained corrective maintenance backlog reduction as a station priorit M Auxiliary Feedwater Pump Failed Surveillance Test. Inspection Scope (62707. 37551. 61726)

The inspectors followed up on a failed surveillance test of the 13 (turbine-driven)'

auxiliary feedwater (AFW) pump due to governor speed oscillations. The inspectors also observed maintenance activities resulting from additional component failures identified during troubleshooting activitie Observations and Findings On January 7, 1999, the 13 AFW pump experienced speed oscillations when the pump was started for a routin~ surveillance run. The operators appropriately declared the pump inoperable and remained in technical specification 3. 7.1.2 which had been entered for the run. PSE&G engineers believed that the cause of the oscillations was air entrainment in the governor oil system, but when the pump was run to vent the governor, the vent plugs appeared to be plugged. PSE&G management subsequently decided to replace the turbine governor and return it to the vendor for evaluatio Following a successful post-maintenance test (PMT) of the new governor, operators attempted to trip the AFW pump. However, the turbine trip valve (MS52) failed to close in spite of attempts to shut it from both the control room and the local control panel. The turbine steam supply valve (MS 132) did close and stopped the pump. The operator who

  • attempted to trip the pump locally inadvertently failed to change the local/remote switch to the local position. This oversight caused the MS52 trip relay to remain energized and increased the current through the solid state protection system (SSPS) pump trip circuitry. The trip relay and trip circuitry overheated, which eventually open-circuited due to a failed resistor. Maintenance technicians subsequently replaced the MS52 trip relay and all of the damaged resistors in the SSPS cabinet. Also, the MS52 valve was lubricated. The inspectors verified that the PMTs of the MS52, the trip relay, and SSPS circuitry were all satisfactory. The cause of the initial MS52 failure was still under investigation at the end of the report perio The inspectors noted that operators appropriately allowed the pump to cool to ambient temperature after all of the AFW work was completed to minimize the effect of pre-conditioning. The ensuing surveillance test was also completed satisfactorily. 66 of the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> permitted by the TS action statement were needed to restore the 13 AFW pump to an operable conditio The turbine speed oscillations and failure of the MS52 trip valve were similar to indications observed during the October 1998 surveillance test. A key difference was that the turbine oil was changed prior to the October run which was not the case for the January test. PSE&G initiated corrective action requests to evaluate both failures. The inspectors observed good management involvement and engineering support for the troubleshooting efforts, the governor replacement, and the SSPS repairs. Maintenance technicians followed procedures and performed appropriate PMTs. Immediate corrective actions for both issues were good. PSE&G management also directed that the 13 AFW pump be run weekly for a month to prove its operability and reliability. The inspectors verified that PSE&G's maintenance rule accounting for these failures was appropriat The inspectors walked down the two motor-driven AFW pump trains and other risk-significant systems during the 13 AFW pump outage. No system operability concerns were noted. They also observed the surveillance test of the 23 AFW pump, and reviewed data for the first weekly run of the 13 AFW pump, which were satisfactor Conclusions PSE&G's corrective actions for multiple component deficiencies identified following a failed surveillance test of the 13 auxiliary feedwater (AFW) pump were reasonabl Troubleshooting and maintenance activities were appropriate and well-controlled, and maintenance rule implementation was good. Operator inattention to detail during post maintenance testing resulted in the mispositioning of the AFW pump local/remote switch, which damaged pump trip circuitry and caused expanded on-line work scope. *
  • M4 Maintenance Staff Knowledge and Performance M Work Coordination and Implementation Inspection Scope (61726. 62707)

The inspectors reviewed and assessed the impact of multiple work coordination.and test implementation errors that were identified during the report perio Observations and Findings The inspectors noted a continued weakness with regard to work coordination between departments and individual attention to detail. None of the three examples of performance problems identified during the report period resulted in an adverse safety or operational consequence. However, recently issued NRC inspection reports and LERs have documented similar examples of not following written guidance for safety-related work activities, including work on an auxiliary feed water flow transmitter and a service water acc~mulator pressure instrumen On December 18, 1998, PSE&G operators identified that testing of a reactor trip bypass breaker was not properly controlled, resulting in field activities being performed without the knowledge of control room personnel. Additionally, the trip breaker was manipulated while tagout documentation still indicated that the breaker was "danger-tagged" in the open position. On January 7, 1999, NRC inspectors identified a weakness in routine service water valve inservice testing. In this instance, maintenance technicians were directed to isolate, vent, and later restore a service water system pressure transmitter in accordance with an operations department procedure, without explicit guidance to perform an independent verification of valve positions. On January 8, 1999, a self-revealing event involving a missed procedure step during 4 KV vital bus undervoltage testing caused several unexpected alarms and indications in the Unit 1 control roo This latter failure to properly implement a technical specification required procedure constituted a violation of minor significance and is not subject to formal enforcement actio The inspectors reviewed PSE&G's responses to each of these issues and judged them to be sufficiently thorough given the relatively minor consequence associated with each of the individual concerns. In each case PSE&G personnel initiated action requests in accordance with the corrective action program. Station management appropriately elevated the concerns to ensure that thorough root cause assessments were completed and corrective actions identified and implemente Conclusions Continued weaknesses in work coordination between the operations and maintenance departments and individual attention to detail were evident during three testing activitie PSE&G management appropriately responded to each of the specific examples using the corrective action proces *

M7 Quality Assurance in Maintenance Activities M7.1 2B 28 VDC Vital Battery Cell Degradation Inspection Scope (37551. 62707)

The inspectors reviewed PSE&G's response to a degraded 2B 28 VDC battery cel Observations and Findings On December 29, 1998, during a quarterly battery surveillance test performed to satisfy technical specification (TS) 4.8.2.5.2.b, technicians determined that cell 5 of the 2B 28 VDC battery indicated an individual cell voltage. (ICV) of 2.128 VDC, slightly below the TS requirement of 2.13 VDC. * Because the allowed outage time for the inoperable battery was only two hours, the inspectors verified that operators promptly entered the associated TS action statement and initiated a corrective action request. A re-check of cell 5 several minutes later indicated that the ICV had risen to 2.148 VDC, an acceptable reading. Nonetheless, operators initiated an equalizing charge and after 45 minutes measured the ICV at 2.21 VDC. The inspectors reviewed past battery cell ICV data which did not indicate a negative trend in cell 5 performanc In spite of meeting the TS operability requirements within the allowed time, PSE&G operators drafted an operability determination which was subsequently reviewed by the station operations review committee (SORC). The inspectors attended the SORC, noting that this collective review of the issue was extremely thorough and added value.to planned future actions. Specifically, the SORC approved a detailed action plan for the 2B 28 VDC battery which included increased frequency ICV checks torten days, an administrative low limit for ICV acceptability, and a review of existing battery preventive maintenance procedures. The potential for generic concerns was raised and debate PSE&G engineers contacted the battery vendor in an effort to gain additional insights into the observed battery performance. The battery remained operable for the remainder of the report period, with no other issues or concerns identified. The inspectors noted that the entire 2B battery is scheduled for replacement during the spring 1999 refueling outag Conclusions PSE&G exhibited prompt, thorough action on an emergent concern involving a degraded 28 VDC vital battery cell. SORC reviewed an associated operability determination which yielded an effective battery corrective action plan.

  • Ill. Engineering E2 Engineering Support of Facilities and Equipment E R15 Radiation Monitor Modification (Closed) Salem Unit 1 Special Report dated August 31. 1998 Inspection Scope (37551)

The inspectors reviewed the adequacy of an October 1998 modification to the 1R15 (condenser offgas) radiation monitor. This monitor is required to be operable during plant operation in accordance with technical specification 3.3.3.1 to provide an indication of primary to secondary leakage. In August 1998, PSE&G experienced repeat failures of this instrument and committed in a special report to the NRC that a design change was needed to improve its reliability. The physical change involved the replacement of the instrument's Geiger-Mueller tube and amplification circuitry with a different design. The inspectors interviewed the cognizant Salem system engineer, reviewed the design change documentation, and observed the installation in the fiel Observations and Findings The 10 CFR 50.59 safety evaluation screening performed in support of the 1R15

  • modification was of good quality and provided sufficient detail to justify the design change without the neec:t for a safety evaluation. This change was incorporated using PSE&G's minor modification process governed by procedure NC.NA-AP.ZZ-0017 (Q).

The inspectors noted that PSE&G engineers accurately employed the guidance in this procedure when planning and implementing the 1R15 modification.. Only minor deficiencies were noted, including inconsistencies in the detector procurement documentatio Field installation of the modification was good, and accurately reflected the design change drawings. The post-installation calibration test data was satisfactory. Based on discussions with the system engineer and a review of maintenance rule performance monitoring information, the inspectors noted that the 1R15 off gas radiation monitor had performed reliably since the change, though the radiation monitoring system remained in category a(1) status at the end of the report perio In the August 1998 special report, PSE&G described an additional concern regarding the alarm setpoint associated with the 1R15. Specifically, during a self-assessment engineering personnel determined that some of the assumptions used in the calculation that established the alarm setpoint were not longer valid, and also that the sensitivity of the monitor changed with the number of condenser air removal pumps that were runnin These deficiencies rendered the alarm setpoint less conservative than desired, but within the margin of TS 3.3.3.1 acceptability. PSE&G committed to revise both the noted calculation and to the air removal pump operating procedure to account for these issues.

The inspectors verified that both of these actions were either in progress or complete * * Conclusions PSE&G engineers developed and implemented a condenser offgas radiation monitor design change which improved the reliability of the system. The design modification process was properly employed, and 1 O CFR 50.59 requirements were effectively addressed. The discovery of a non-conservative assumption in the monitor alarm setpoint calculation was an example of a good self-assessment findin E3 Engineering Procedures and Documentation E Control Room Emergency Air Conditioning System Testing Inspection Scope (37551, 61726)

The inspectors reviewed the current design and licensing basis for the control room emergency air conditioning system (CREACS) in preparation for a technical specification required surveillance test of the system. Additionally, the inspectors assessed the test plan and the surveillance procedure, and observed portions of the test. Several discussions were held with engineering and licensing department personnel while performing this evaluatio Observations and Findings Based on a detailed review of the Salem UFSAR, technical specifications (TS) and their bases, and license amendment safety evaluation reports, the inspectors discovered that the design basis for the CREACS was not clearly established. PSE&G management agreed with this assessment. After several discussions with engineering and licensing personnel, and NRC technical reviewers, the inspectors were able to determine the

  • criteria upon which appropriate surveillance testing should be conducted.. PSE&G staff initiated a corrective action request to address the complexity associated with the CREACS design basis documentatio PSE&G developed a test coordination and contingency plan to guide the evolution, largely because the consequences of a CREACS surveillance failure would require both Salem units to shut down to comply with the associated TS action statement. The inspectors reviewed the plan and questioned the contingency actions established if the test were to fail. Specifically, the plan would have permitted continued plant operation in a degraded CREACS condition that had not been sufficiently tested to justify continued CREACS operability. As a result, engineering personnel revised the plan to test the contingency ventilation system configuration before running the TS acceptance tes The inspectors determined that PSE&G test procedure S2.RA-ST.CAV-0001(Q) was adequately established to implement the requirements of TS requirement 4. 7.6.1.d, though several "last minute" changes had to be incorporated to resolve the test. plan weaknesses described above. The inspectors verified that the procedure required the system to be tested in the worst case configuration, consistent with design basis calculation assumption *

In spite of employing their "infrequently performed test or evolution" process defined by procedure NC.NA-AP.ZZ-0005(0), which assigned a special test manager and engineer to guide the activities, PSE&G staff experienced numerous delays in their attempts to execute the test. These delays had a notable impact on other planned work week activities and routine operations department tasks. An action request was initiated to identify all of the specific concerns associated with the delays in executing the CREACS surveillanc The inspectors observed portions of the surveillance test conduct and did not identify any deficiencies. The test results were satisfactor Conclusions Though PSE&G personnel successfully completed a technical specification surveillance of the control room emergency air conditioning system (CREACS) within the specified test interval, several delays were encountered which negatively impacted other scheduled work week activities. Also, the inspectors had identified a weakness in the test plan that further delayed the evolution. The design basis for CREACS not been clearly established in the Salem licensing basis documentation but was being correcte IV. Plant Support S2 Status of Security Facilities and Equipment S Security Equipment Modifications Inspection Scope (71750)

The inspectors observed maintenance and security force activities during installation of security equipment modifications to verify that the integrity of the protected area barriers was maintained, and that access to vital equipment areas was properly controlled. The inspectors also observed activities in the facility alarm station Observations and Findings The inspectors noted that security department personnel appropriately maintained the integrity of the protected area barriers and controlled personnel access to vital areas duririg the maintenance activities. Compensatory security measures, when required,*

were properly implemented, and the maintenance activities did not adversely interfere with security force personnel in the facility alarm stations.

I * Conclusions PSE&G properly implemented the observed security equipment maintenance activities with minimal impact to the on-duty security force personnel. Protected area barriers and personnel access cpntrol were properly maintaine FB Miscellaneous Fire Protection Issues F (Closed) LER 50-311/98-014-00: fire barrier material for heating ventilation and air conditioning CHVAC) ducts does not meet required level of fire resistanc Inspection Scope (90712)

The inspectors conducted an in-office review of the subject licensee event report (LER). Observations and Findings This LER documented the test results of the FS-195 fire barrier material used at the Salem facilities. During a laboratoi-Y test and subsequent analysis, PSE&G determined that the FS-195 material failed to meet its design one-hour rating for certain electrical raceway fire barrier configurations. As a compensatory action PSE&G management initiated additional fire watch tours of plant areas containing the FS-195 material. Further corrective actions involve the completion of a three-phase project to resolve all of the fire barrier issues. PSE&G personnel described the scope of this project in their November 6, 1997 letter in response to Notice of Violation 50-272 & 311/97-257-02014; in two subsequent letters dated June 6, 1997 and May 19, 1997, respectively; and at a meeting on September 23, 1998 at the.NRG office in RockVille, Maryland. This LER is close However, the NRC will maintain the noted enforcement item open pending additional inspection of PSE&G's corrective action Conclusions Immediate corrective actions were prompt and appropriate following the discovery that FS-195 fire barrier material could not meet its design criteri V. Management Meetings X1 Exit Meeting Summary On January 27, 1999, the inspectors presented their findings and conclusions to members of PSE&G management. PSE&G management acknowledged the findings presented, ahd did not contest the inspectors conclusions. Additionally, they stated that none of the information reviewed by the inspectors was considered proprietar *

IP 37551:

IP 40500:

IP 61726:

IP 62707:

IP 71707:

IP 71750:

IP 90712:

IP 92700:

IP 92901:

IP 92902:

IP 92903:

IP 92904:

IP 93702:

Opened

INSPECTION PROCEDURES USED Onsite Engineering Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Surveillance Observations Maintenance Observations Plant Operations Plant Support Activities lnoffice Review of Written Reports of Nonroutine Events at Power Reactor Facilities Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities Plant Operations Followup Maintenance Followup Engineering Followup Plant Support Followup

  • Event Followup ITEMS OPENED AND CLOSED 50-311/98-12-01 VIO Failure to follow procedures. (Section 01.2)

Closed 50-272/98-012-00 50-311/98-014-00 50-311/98-016-00 LER Potential to exceed the rating of piping due to isolation of an overpressure protection line. (Section 08. 1)

LER Fire barrier material for heating ventilation and air conditioning ducts does not meet required level of fire resistance. (Section F8.1)

LER ECCS leakage outside design basis value. (Section 08.2)

Salem Unit 1 Special Report dated August 31, 1*999 1R15 radiation monitor modification. (Section E2.1)

AFW CFCU CREA CS EAL EC ECCS ECG HVAC ICV LER NRC OWA PD PMT PSE&G PZR QA RCS RHR RO SORC SSPS SW TDAFP TS UE UFSAR

LIST OF ACRONYMS USED Auxiliary Feedwater Containment Fan Coil Unit Control Room Emergency Air Conditioning System Emergency Action Level Emergency Coordinator Emergency Core Cooling System Event Classification Guide Heating Ventilation and Air Conditioning Individual Cell Voltage Licensee Event Report Nuclear Regulatory Commission Operator Workarounds Public Document Room Post-Maintenance Test Public Service Electric and Gas Pressurizer Quality Assurance Reactor Coolant System Residual Heat Removal Reactor Operator Station Operations Review Committee Solid State Protection System Service Water Turbine Driven Auxiliary Feed. Pump Technical Specification Unusual Event Updated Final Safety Analysis Report

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