IR 05000352/1993014
| ML20046B090 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 07/20/1993 |
| From: | Anderson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20046B080 | List: |
| References | |
| 50-352-93-14, 50-353-93-14, NUDOCS 9308030084 | |
| Download: ML20046B090 (16) | |
Text
4 U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
93-14 93-14 Docket Nos.
50-352 50-353 License Nos.
NPF-39 NPF-85 Licensee:
Philadelphia Electric Company Correspondence Control Desk P.O. Box 195 Wayne, Pa 19087-0195 Facility Name:
Limerick Generating Station, Units 1 and 2 Inspection Period:
May 25 through July 6,1993 Inspectors:
N. S. Perry, Senior Resident Inspector T. A. Easlick, Resident Inspector Approved by:
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Clifford I. Anderson, Chief Date Reactor Projects Section No. 2B
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9308030084 930723 PDR-ADDCK 05000352 G
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EXECUTIVE SUMMARY Limerick Generating Station Report No. 93-14 & 93-14
Operations Two late NRC notifications resulted in a non-cited violation. Corrective actions taken and planned were adequate to address the identified deficiencies (Section 1.2). A walkdown of
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the Unit 2 standby liquid control system identified no conditions that might degrade overall system performance (Section 1.4). Review of PECo's short term compensatory actions,
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requested in NRC Bulletin 93-03, Resolution of Issues Related to Reactor Vessel Instrumentation in BWRs, showed adequate implementation, with a comprehensive review
conducted by the independent safety engineering group (Section 1.5).
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Maintenance Corrective maintenance on an emergency diesel generator jacket water expansion joint was in -
accordance with procedures, and codes and standards (Section 2.1). A configuration change for wiring on a drywell chilled water valve was not properly documented, resulting in a cited
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violation of PECo administrative procedures (50-352/93-14-01) (Section 2.2). Plant personnel performed a thorough review of this event with a root cause analysis and adequate corrective actions.
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Plant Support Plant emergency preparedness personnel identified the TSC UPS as inoperable for nearly one year with no corrective actions taken (Section 3.2). This resulted in a cited violation for
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failing to follow and maintain in effect the emergency plan as required by 10 CFR 50.54(q)
(50-352, 50-353/93-14-02).
Miscellaneous A missed surveillance, for a primary containment isolation valve, required by technical
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specifications, was properly documented in an LER, and resulted in_a non-cited violation (Section 4.1). Another LER adequately documented a failure to implement a technical specification action statement for an inoperable emergency diesel generator, resulting in a j
non-cited violation (Section 5.0).
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TABLE OF CONTENTS
EXECUTIVE SUMMARY i
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1.0 OPERATIONS I
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1.1 Operational Overview................................. I 1.2 Event Reports
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1.3 Reactor Enclosure and Radwaste Enclosure HVAC............... 2
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l.4 Engineered Safety Feature System Walkdown - Standby Liquid Control..
1.5 NRC Bulletin 93-03 Resolution ofIssues Related to Reactor Vessel
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Water Ixvel Instrumentation in 'BWRs
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2.0 MAINTENANCE
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2.1 Corrective Maintenance for EDG Jacket Water Expansion Joint....... 4
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2.2 Improper Wiring for a Drywell Chilled Water Valve.............. 5 3.0 PLANT S U PPORT....................................... 6 3.1 Radiological Protection................................ 6 3.2 Emergency Preparedness............................... 7 3.3 Security............
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4.0 REVIEW OF LICENSEE EVENT AND ROUTINE REPORTS...........
4.1 Licensee Event Reports (LERs).........
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4.2 Routine Reports
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i 5.0 FOLLOWUP OF PREVIOUS INSPECTION FINDINGS..............
6.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION............
6.1 Nuclear Review Board Meeting..........................
7.0 M AN AG EMENT MEETINGS...............................
7.1 Exit Interviews....................................
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7.2 Additional NRC Inspections this Period.....................
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P DETAILS 1.0 OPERATIONS (71707)'
The inspectors observed that plant equipment was operated and maintained safely and in conformance with license and regulatory requirements. Control room staffing met all requirements. Operators were found to be alert, attentive and responded properly to annunciators and plant conditions. Operators adhered to approved procedures and understood
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the reasons for lighted annunciators. The inspectors reviewed control room log books for
trends and activities, observed control room instrumentation for abnormalities, and verified
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compliance with technical specifications. Accessible areas of the plant were toured; plant conditions, activities in progress, and heusekeeping conditions were observed. Additionally, selected valves and breakers were verified to be aligned correctly. Deep backshift inspection
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was conducted on June 5,15,17 and July 5,1993.
1.1 Operational Overview Unit 1 operated at full power throughout the inspection period, except for minor power reductions during surveillance testing and a power reduction to approximately 80% on June 20,1993, for condensate pump motor maintenance and alignment. The work was completed and the unit was returned to full power.
Unit 2 operated at full power throughout the inspection period, except for minor power reductions during surveillance testing and two power reductions on June 26 and June 29. On
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both occasions, power was reduced to approximately 80% for condensate pump motor maintenance and alignment. In each case, the unit was returned to full power after completion of the work.
1.2 Event Reports On June 28, and 30,1993, late Four-Hour Reports were made to the NRC pursuant to 10 CFR 50.72. The first concerned a manual start of the reactor enclosure recirculation system and the standby gas treatment system, an ESF actuation, on June 27. These systems were started to maintain reactor enclosure differential pressure, after the normal exhaust fan tripped and could not be restarted, and a redundant fan was out of service for maintenance work. The ESF would have automatically initiated after 50 minutes with the low differential condition. The report was made late due to confusion concerning whether the actuation was pre-planned or not. Section 5.0 of this inspection report addresses the issue of pre _-planned ESF actuations.
'The NRC Inspection Procedures used as guidance are listed parenthetically throughout this repor,
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2 The second late report concerned a spurious actuation of a primary containment isolation valve in the traversing in-core probe (TIP) system, on June 17. Initially, operators only brd
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indication that the valve had inadvertently closed or.was inoperative, since only continuity is
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indicated in the main control room. The spurious actuation of the valve was not confirmed,
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by visual verification, until June 22, due to high radiation dose levels in the TIP room following TIP runs on June 17. The report was made late because it was not recognized as
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an ESF actuation until June 30.
10 CFR 50.72 requires notification of the NRC within four hours for any event or condition
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that results in a manual or automatic actuation of any ESF, with certain exceptions, such as being part of a pre-planned sequence during testing or reactor operation. Plant personnel conducted an investigation of the two events, and identified the need for some corrective
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actions. Feedback to personnel who make reportability determinations has been less than adequate in the past, and revisions to and training for changes to the Reportability Reference E
Manual have been less than adequate. Planned corrective actions include: 1) feedback has been given to the appropriate personnel concerning recent events highlighting the
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reportability determinations; 2) a feedback mechanism will be developed for the reportability process; and 3) an easy and timely mechanism will be provided to update the reference manual, and better communication of the changes to it will be included.
The inspectors reviewed the events and the corrective actions, and concluded that the corrective actions taken and planned are adequate to address the identified deficiencies. This violation involving the failure to make the required four-hour reports, meets the criteria for enforcement discretion of Section VII of the NRC's Enforcement Policy and will not be cited.
1.3 Reactor Enclosure and Radwaste Enclosure IIVAC During this inspection period, the inspectors performed a detailed walkdown of the reactor enclosure and radwaste enclosure HVAC systems; this equipment is not safety-related. In particular the inspectors observed area housekeeping and the general condition of the equipment. Although a small portion of each system showed evidence of minor corrosion, in general the condition of the equipment appeared good. The inspectors concluded that overall the condition of the equipment and general area housekeeping were good. No conditions-
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were identified that might degrade overall system performance.
1.4 Engineered Safety Feature System Walkdown - Standby Licinid Control
'An engineered safety feature system walkdown was performed on the accessible portions of the Unit 2 standby liquid _ control (SLC) system components to verify operability. The inspectors verified that the system lineup procedure matched the piping and instrument drawing, and the actual system configuration. Drawing 8031-M-48, sheet 2, Standby Liquid-Control (Unit 2), Rev. 7, and procedure 2S48.1. A, Equipment Alignment to Place Standby Liquid Control System in Normal " Standby" Condition, Rev. 4, were used for the lineup
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verification. Procedures ST-3-048-320-2, SLC Operability Verification and Valve Test, Rev.
5, ST-6-107-590-2, Daily Surveillance Log /Opcons 1, 2, 3, Rev. 26, ST-6-048-230-2, SLC Pump, Valve, and Flow Test, Rev. 2 and ST-6-048-450-2, SLC Lineup Verification, Rev.1, were used to verify that the appropriate technical specification requirements were being met.
The inspectors concluded that the Unit 2 SLC system was properly aligned for operability as required, and no equipment conditions existed that might degrade overall system performance. Minor discrepancies were noted on the drawing, in that several valves were shown to be required locked closed. The valves are not required to be locked; operations management indicated that they are aware of this and will have the drawing corrected.
Several handwheel nuts were found very loose and the air hose used to supply sparging air to the SLC tank was found connected, not in accordance with the system drawing. Once notified of these discrepancies, operations management ensured all handwheel nuts were tightened and the air hose was removed. Additionally, an entry was placed in the Shift Night Orders to remind the operators that the hose should be removed since a non-Q system should not be permanently aligned to a Q rated system. This deficiency is considered to be an example of a weakness in licensee configuration control. In all cases the identified
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I discrepancies were of low safety significance and the inspectors had no further concerns.
1.5 NRC Bulletin 93-03 Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs On May 28,1993, the NLC issued Bulletin 93-03 requesting that three short term compensatory actions be implemented (within 15 days of the date of the bulletin) to ensure that potential level errors caused by reference leg degassing will not result in improper system response during transients and accident scenarios initiated from reduced pressure conditions (Mode 3). The first requested action (1.(a)(1)) was to establish enhanced monitoring of all reactor pressure vessel (RPV) level instruments to provide early detection of level anomalies associated with degassing from the reference legs. In response to this request PECo provided requirements for increased monitoring of the narrow range level indication channels below 450 psig reactor pressure. General Procedure (GP)-3, Normal Plant Shutdown, was revised to add an appendix describing vessel level monitoring actions using the process computer. It describes what to look for and how to respond to level notching. This activity will commence at 450 psig and will be terminated when level is raised to place shutdown cooling in service. In order to ensure accurate level indication during shutdown cooling operations, instrumentation and controls (I&C) technicians will backfill the shutdown / upset range level reference leg at 150 psig. Additionally, the shutdown cooling system procedure (S51.8.B) has been temporarily changed (TC'd) to raise level to the shutdown / upset range prior to flushing the system.
The second requested action (1.(a)(2)) was to deaelop enhanced procedures or additional restrictions and controls for valve alignments and maintenance that have a potential to drain the RPV during Mode 3. In response, GP-3 was revised to direct that shift managem-ent begin reviewing in-progress and planned work when a unit is being shutdown to identify activities that could drain the vessel. The Shift Manager's review occurs shortly after
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entering Mode 3. Such activities would then be evaluated and carefully controlled to prevent
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an inventory loss during depressurization. Additionally, the shutdown cooling procedure was TC'd to include a caution about reference leg degassing and its potential effect on automatic isolations.
The third requested action (1.(a)(3)) was to alert operators to potentially confusing or misleading level indication that may occur during accidents or transients initiating from Mode 3. For example, a drain-down event could lead to automatic initiation of high-pressure
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emergency core cooling systems (ECCS) without automatic system isolation or low-pressure ECCS actuation. PECo's response was to provide two shift training bulletins and a briefing to each shift. Also, additional cautions, warnings, and notes, which state that reference leg
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degassing may delay automatic isolations due to inaccurate indications, and that prompt manual action must be taken if inventory loss occurs, were placed in appropriate procedures.
The inspectors observed two of the six shift briefings that were given to supplement the
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training bulletins. The briefm' gs were very informative and provided the necessary background to tie earlier training given on this issue, to the latest NRC concern highlighted
in NRC Bulletin 93-03. The operators were also given an opportunity to ask questions, which they did. At the conclusion of the brief, the instructor provided history plots for level indication during the Washington Public Power Supply System Unit 2 (WNP-2) event of January 21,1993, to familiarize the operators with level notching that is expected with reference leg degassing.
la summary, PECo has adequately implemented the three short term compensatory actions with the 15 days requested in NRC Bulletin 93-03. PECo is currently conducting the augmented operator training on loss of vessel inventory scenarios during Mode 3, to be completed by July 30,1993, as requested by NRC Bulletin 93-03 (1.(b)). PECo's Independent Safety Engineering Group (ISEG) also performed a review of the short term compensatory actions corapleted by the plant staff. The review was comprehensive and in agreement with the inspectors' conclusions regarding the plant's implementation of the bulletin. The ISEG also reviewed compensatory actions that were discussed but not implemented, since they believe that an assessment of the rationale for not implementing i
l these actions is of equal value to the assessment of actions that were implemented. In this case, ISEG concluded, as did the inspectors, that it was appropriate that these actions were
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considered and that the decision to not implement the actions was based on sufficient i
discussion and technical justification. The inspectors will continue to review PECo's response to this bulletin.
2.0 MAINTENANCE (62703)
2.1 Corrective Maintenance for EDG Jacket Water Expansion Joint i
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The inspectors reviewed maintenance activities and Work Order (WO) C0144716 pertaining to the repair of an Emergency Diesel Generator (D-24) jacket water expansion joint for the turbo charger cooling water line, to verify that repairs were made according to approved
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The inspectors verified that the replacement parts and quality control used on the repairs were in compliance with PECo's Quality Assurance (QA) program. The inspetors found that the work was performed in compliance with acceptable codes and standards and that the work package contained the necessary documentation to conduct a thorough review. The inspectors concluded that the repairs to the expansion joint were according to acceptable procedures.
2.2 Improper Wiring for a Drywell Chilled Water Valve Following the completion of routine maintenance on 480 volt circuit breaker D114-R-C-13, for drywell chilled water (DWCW) supply valve HV-87-120A, operations personnel performed post maintenance testing (PMT) to ensure valve operability. While performing ST-6-087-200-1, Drywell Chilled Water Valve Test Quarterly, on April 13,1993, DWCW valve HV-87-120A did not stroke open as required when the control room handswitch was placed in the RE. CLG. WATER position. An investigation was immediately initiated by the system manager, and maintenance and operations personnel. This investigation determined that during the maintenance work, the overload relay and heaters for the B phase were replaced. During this replacement, the physical configuration of two thermal overload relay wires was reversed, which prevented the valve f:om operating.
The system manager informed the operations shift manager of the results of the troubleshooting activities and described the wiring configuration and the potential repair.
The system manager told the shift manager that he was going to reverse the wires to fix the problem. The Shift Manager perceived that the wires causing the problem at the breaker side of the thermal overload would be restored to their original configuration. He also assumed that this activity would be documented as part of the original maintenance work order. On the contrary, the system manager's repair of the problem entailed swapping the leads on the motor side of the thermal overload relay to correct the problem. Two wires on the motor side of the breaker were subsequently swapped and the post maintenance test was satisfactorily performed.
The change in the configuration of the load side wires was not documented by the system manager and this condition was not known by management until it was identified by maintenance supervision during a followup investigation of the event. The failure to document this change in the wiring configuration for circuit breaker Dil4-R-C-13 is a violation of PECo administrative procedures required by Technical Specification, Section 6.8.1. (50-352/93-14-01). Another example of a configuration control deficiency involving an air hose on the SLC tank was discussed in Section 14 of this report.
The inspectors reviewed the event investigation report for this event and the corrective actions, both completed and planned. These corrective actions included: 1) issuing a Maintenance Training Bulletin to all technicians on site outlining this event and specifically reaffirming expectations associated.with independent verification; 2) initiating an equipment trouble tag (ETT) and a WO to have D114-R-C-13 wired properly; 3) issuing a For-Your-
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Information (FYI) to all station personnel reaffirming expectations of troubleshooting, proper utilization of procedures, and appropriate documentation during troubleshooting activities; 4)
I training of all maintenance technicians regarding self-checking per Administrative Guideline l
(AG)-03, Self Checking; and 5) developing a maintenance specific observation card for
. reviewing maintenance activities. Additionally, an investigation has been initiated concerning
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generic issues revolving around the independent verification process. A senior management group will review all aspects of the verification process.
j Based on PECo's thorough review of this event, root cause analysis, and adequate corrective actions, the inspectors concluded that a response to this violation is not required. The inspectors had no further questions concerning the event. The inspecors did, however, have a concern with respect to the increased number of wiring discrepancies documented in this report (Section 5.0), as well as recent previous inspection reports. Maintenance supervision was contacted concerning this issue and the inspectors were informed that a meeting between maintenance and site engineering was already scheduled to discuss the recent wiring problems. The inspectors attended the meeting, the purpose of which was to determine if there was a generic wiring problem at Limerick. The plant staff identified five wiring discrepancies between January and May 1993, involving the drywell chilled water system and
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the emergency diesel generator 4KV safeguards bus breakers. Each event was reviewed to identify the root cause, causal factors, process cont ol, and responsible organization. There was no obvious connection between the events, and the plant staff, as well as the inspectors,
concluded that no generic wiring problem existed. The inspectors will continue to review the issue of miswiring and note any future tends.
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3.0 PLANT SUPPORT i
3.1 Radiological Protection
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During the inspection period, the inspectors examined work in progress in both units I
including health physics (HP) procedures and controls, ALARA implementation, dosimetry and badging, protective clothing use, adherence to radiation work permit (RWP)
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requirements, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and materials.
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A sampling of high radiation area doors was conducted. All doors were verified to be
. locked as required. Compliance with RWP requirements was reviewed during plant tours.
RWP line entries were reviewed to verify that personnel provided the required information
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and people working in RWP areas were observed to be meeting the applicable requirements.-
The activities observed by the inspectors were acceptable.
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3.2 Emergency Preparedness On May 18,1993, plant emergency preparedness personnel identified the failure to perform the quarterly surveillance testing on the Technical Support Center (TSC) uninterruptible i
power supply (UPS) battery since July 10,1992, and that the battery had failed the three
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prior performances of the surveillance. The battery is required to supply power to the TSC communication system for 15 minutes following a total station blackout. Plant personnel reperformed the surveillance test to determine the current condition of the battery. The testing was completed on May 31, with 14 of 192 cells failing due to low voltage, and approximately 50% of the cells failing due to low specific gravity. An event investigation was conducted and an action plan was drawn up.
The event investigation results indicated that corrective actions have been less than adequate, since there were numerous surveillance failures of this battery in the past and priorities were
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not clearly established ensuring resolution of the problems. Additionally, an action request (A/R), initiated in November 1991, was not followed up on, and personnel with responsibility for the system put a low priority on the system. Corrective actions include: 1)
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establishing a management tracking mechanism for missed or failed surveillance and routine tests; 2) determining if similar out-of-surveillance issues exist, and if open action requests
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prevent performance of these surveillances; 3) reestablishing the TSC UPS configuration-
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consistent with approved procedures and guidelines; and 4) transferring responsibilities for j
the TSC UPS to the emergency preparedness section, and evaluating the transfer of other system responsibilities to the emergency preparedness section.
10 CFR 50.54(q) requires that a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in 50.47(b) and the requirements in Appendix E of this part. 10 CFR 50.4'/(b)(8) requires that adequate emergency facilities and equipment to support the emergency response are provided
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and maintained. Section 7.2.2 of the Limerick Generating Station Emergency Plan states that -
the first backup for the TSC offsite power supplies is a 15 minute UPS, to maintain the
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communication system during a total station blackout. Section 8.4 of the Emergency Plan
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states, in part, that any deficiencies identified during pc 'ormance of surveillances are corrected to ensure operational readiness of emergency equipment.
On July 12, 1992, following a surveillance test failure, the TSC UPS battery was declared inoperable, and no actions were taken to correct the deficiencies until May 18, 1993.
Additionally, following an unsatisfactory performance of the surveillance test in November 1991, an A/R was generated to' investigate the feasibility of performing single cell charging, to correct deficiencies identified through surveillance test failures. No corrective actions were processed in response to the A/R. Failure to have the TSC UPS operable, and failure to take corrective action is a violation of 10 CFR 50.54(q). (50-352, 353/93-14-02).
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L 3.3 Security Selected aspects of plant physical security were reviewed during regular and backshift hours, to verify that controls were in accordance with the security plan and approved procedures.
This review included the following security measures: guard staffing, vital and protected area barrier integrity, and implementation of access controls including authorization, badging, escorting, and searches.
On June 5,1993, plant management held a plant open house for Limerick employees'
families. Employees badged for access to Limerick Generating Station were allowed to escort family members or friends through various areas in the facility. Approximately 1800 i
people toured through the main control room, the turbine deck, and the refuel floor. The inspectors monitored portions of the tours during the day, and concluded that the event was
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handled very well. Good up front planning was evidenced by the smooth control of personnel throughout the tour route. In particular, the inspectors noted good coordination of personnel entering the protected area and the main control room.
4.0 REVIEW OF LICENSEE EVENT AND ROUTINE REPORTS (90712,90713)
4.1 Licensee Event Reports (LERs)
I LER l-93-006, Engineered Safety Feature Actuation Resulting from a Reactor Water Cleanup (RWCU) System Isolation due to High 'A' RWCU Pump Room Temperature,
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Event Date: May 6,1993, Report Date: June 7,1993.
This LER documents an instance where normal reactor enclosure HVAC was removed from service for maintenance, and due to a faulty fan motor breaker, operators were unable to return the system to service prior to reaching the reactor water cleanup (RWCU) system high temperature isolation setpoint; this is an engineered safety feature actuation. Investigation by plant personnel revealed that the temperature probe was improperly located, resulting in an inaccurately high ambient room temperature representation. The probe was installed too
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close to the RWCU system pump suction piping. Corrective actions include relocating the temperature probe.
The inspectors concluded that all systems operated as d: signed, and that operations personnel were aware of the impending event prior to its occurrence. The inspectors had no further questions.
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LER l-93-007, This LER reports a condition prohibited by Tech. Spec. (TS) in that a Primary Containment Isolation Valve was inoperable and the required TS ACTION was not taken due to personnel error, Event Date: May 16,1993, Report Date: June 21,1993.
This LER reports the failure to perform a routine surveillance test, required by technical specifications, within the allotted time period. In this case, a primary containment isolatior
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valve could not be tested as scheduled, due to maintenance being performed on the system.
The maintenance work order correctly included instructions for testing the valve after completion of the maintenance activity, but failed to provide a reason for testing the valve.
The surveillance was incorrectly cancelled from the work order, due to personnel error.
Personnel incorrectly concluded that since the maintenance activity was not on the valve in question, that the surveillance was not required. Corrective actions included immediately completing the required surveillance successfully, reviewing both units for additional discrepancies, with none found, and requiring a basis for performance of a surveillance test on action requests, work orders, or clearances.
The inspectors reviewed the event and concluded that corrective actions taken were appropriate. Safety significance for this event is minimal since the valve subsequently passed
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the surveillance test. This event could not reasonably be expected to have been prevented by
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the corrective action for a previous event. This violation, involving the failure to meet a technical specification surveillance requirement, meets the criteria for enforcement discretion of Section VII of the NRC's Enforcement Policy and will not be cited.
LER 2-93-002, Revision 00, Improperly Connected Wires in Circuit Breakers caused an Emergency Diesel Generator to be inoperable and a violation of Technical Specifications to occur, Event Date: January 19, 1993, Discovery Date: January 24,1993, Report Date:
February 18,1993.
This event is reviewed and documented in Section 5.0, Followup of Previous Inspection Findings, of this report.
LER 2-93-002, Revision 01, Improperly Connected Wires in Circuit Breakers caused an Emergency Diesel Generator to be inoperable and a violation of Technical Specifications to occur, Event Date: January 19, 1993, Discovery Date: January 24,1993, Report Date:
May 20,1993.
This event is reviewed and documented in Section 5.0, Followup of Previous Inspection Findings, of this report.
I The inspectors found that the LERs listed above met the requirements of 10 CFR 50.73 and had no further questions regarding these events.
4.2 Routine Reports Routine reports submitted by PECo were reviewed to verify the reported information. The '
following report was reviewed and satisfied the requirements for which it was reported.
Station Monthly Operating Report for May 1993, dated June 11, 1993
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5.0 FOLLOWUP OF PREVIOUS LNSPECTION FINDINGS (92702)
(Closed) Unresolved Item (50-353/93-02-01). This unresolved item concerned the failure of
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the D-24 Emergency Diesel Generator (EDG) to pass Surveillance Test (ST) procedure, ST-i 1-09-114-2, D-24 Diesel Generator 4KV SFGD Loss of Power LSF/SAA and Outage i
Testing.
On January 24,1993, the D-24 EDG failed to pass ST-1-092-114-2 because certain shunt trip coils failed to function when a simulated loss of coolant accident (LOCA) signal was initiated. The reason for the shunt trip coils failing to operate was traced to a loose wire and a wire that was not connected in circuit breakers D244-R-E-15 and D244-D-G-28 respectively. The wires were restored and the test was successfully completed. An investigation into the cause of the faulty wiring in the breakers was initiated by PECo. The wire in the D244-E-15 circuit breaker was believed to have come loose at the plug connector
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during repairs made to enhance electrical separation between electrical divisions. The activity that lifted the wire in the D244-D-G-28 circuit breaker had not been identified and remained unresolved pending completion of the review of the event.
On February 18,1993, PECo issued the first of two licensee event reports (LER) concerning
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this event (LER 2-93-002, Revision 00). The LER stated that circuit breaker D244-R-E-15
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had been installed with a loose wire since January 19, 1993, and that this event resulted in a condition prohibited by Technical Specifications (TS) Section 3.8.1.1, A.C. Sources -
Operating, because the associated TS ACTION statements were not implemented within the required time period. The cause for failing to implement the TS action statements within the required time was that the D-24 EDG was unknowing inoperable due to faulty wiring in the
circuit breakers.
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The LER also stated that the activity that lifted the wire in the D244-D-G-28 circuit breaker has not been identified after reviewing all historical maintenance, troubleshooting, and modification work activities since the last successful completion of this test. The
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investigation into the cause of the lifted wire on circuit breaker D244-D-G-28 was continuing.
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On May.20,1993, PECo issued the second LER concerning this event (2-93-002, Revision 01). This revision provided the results of the investigation into the lifted wire in circuit breaker D244-D-G-28 and voluntarily reported another failure of a load to deenergize from the safeguard bus. During the performance of ST-1-092-112-2, D-22 Imss of Power Testing,.
on March 4,1993, a shunt trip load, off motor control center D244-R-C, did not load shed when a simulated LOCA signal to the D-22 safeguard bus was initiated. At that time, D-22
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was declared inoperable and the appropriate TS. Actions were taken. Troubleshooting on March 5,1993, identified that wires had been improperly connected causing the D224-R-C-03 circuit breaker, which supplies the lighting panel transfer, to fail to shunt trip.
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PECo completed the investigation of both the January 24, and the March 4,1993 events. Nt activity could be identified that lifted the wire in the D244-D-G-28 circuit breaker or caused the improperly connected wires in breaker D244-R-C-03. All work activities were reviewed since the last successful completion of procedure ST-1-092-114-2 on April 19,1991, and ST-
1-092-112-2, on May 6,1991, to identify any activity involving circuit breakers D244-D-G-i 28 and D224-R-C-03.
The investigations failed to identify any activity with the potential for lifting a wire in circuit breaker D244-D-G-28 or removing and improperly reconnecting wires in circuit breaker
D224-R-C-03. A meeting was held with representatives from all organizations that perform
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activities on circuit breakers to review the results of the investigation and determine if any other areas warranted investigation. The representatives at the meeting concluded that all possible causes to lifting a wire in circuit breaker D244-D-G-28 or improperly connected wires in circuit breaker D224-R-C-03 had been investigated.
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The corrective actions for this event included procedural and training changes to emphasize to workers that perform activities on circuit breakers, the importance of proper removal and.
installation of motor control center circuit breakers. Additionally, procedures S93.0.A,480 VAC Safeguard MCC Compartment Removal, and S93.0.C.,480 VAC Safeguard MCC Compartment Installation, were revised to alert workers of the potential for wires becoming loose during removal and restoration of plug connections on circuit breakers. PECo also
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performed an inspection on all Unit 1 EDG motor control center terminal blocks to identify any lifted or taped leads; none were found. With the completion of D-22 EDG testing, all Unit 1 and 2 EDGs have demonstrated operability by verifying deenergization ofits associated 4KV safeguard bus and load shedding during a simulated loss of offsite power and LOCA.
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The inspectors reviewed the events and corrective actions taken, and concluded that the corrective actions were adequate. The safety significance of the event is minimal since D-22 and D-24 would have been capable of performing their design function had an accident
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occurred in which the onsite emergency AC power system was called upon. PECo
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er incering personnel concluded toat failure to trip the loads associated with the affected shunt trips would not have caused D-22 or D-24 to become overloaded. Additionally, the FSAR requires that only two EDGs be operable to support an actual LOCA. This violation
involving failure to implement the TS ACTION statements within the required time period, meets the criteria for enforcement discretion of Section VII of the NRC's Enforcement Policy and will not be cited.
The inspectors had no further questions regarding these events and the unresolved item is
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closed, (Closed) Unresolved Item (50-352/93-09-02). This unresolved item, concerning the improper wiring of a drywell chilled water valve, is closed. The issue resulted in the issuance of a Severity Level IV violation (Section 2.2).
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(Closed) Unresolved Item (50-352/91-15-02). This issue remained unresolved pending NRC review of PECo's review of the adequacy and implementation of the equipment trouble tag I
(ETT) program. The NRC was concerned because the EIT system was not being adequately implemented, and the backlog of corrective maintenance requests was increasing.
The inspectors met with maintenance management to discuss implementation of the E'IT
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system and program enhancements made, and took a sample of ETTs obtained through plant tours to determine if they were adequately controlled. A check of the E'IT numbers showed that 2 of the tags should have been removed, since the work had been completed.
Maintenance management indicated that failure to remove the ETT after completion of the work activity has been a weakness, in that the tag has not been removed in all cases. This was due to failure to hold a specific individual accountable for removing the tag in all cases.
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Corrective actions include: 1) instructing the maintenance foremen to send back the tag with the completed work packages to the maintenance planners for accountability; 2) asking operators, who hang most of the ETTs, to provide more specific information regarding the location of the tag; 3) instructing the work control unit coordinators that if they reject an E'IT, they are responsible for removal of the tag; and 4) asking management conducting required housekeeping tours to perform a validity check of existing ETTs.
Additionally, the inspectors reviewed the corrective maintenance backlog, and observed that
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since mid-1992 the backlog has been decreasing, with the most significant decrease occurring late in 1992. The inspectors concluded that actions taken have been effective in controlling the E'IT system and had no further questions.
(Closed) Unresolved Item (50-353/93-07-02). This unresolved item concerned an event where a licensed operator performed an operation resulting in an ESF actuation, without operations management aware of the event prior to its initiation. The inspectors were
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concerned that the guidance to the operators, concerning when an ESF actuation is a pre-planned evolution, was weak.
F In response, operations management issued a shift training document, in May, and a revision i
to the Reportable Events guidance, in June, regarding expectations for considering an
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evolution / activity as pre-planned. The additional guidance provides specific criteria / expectations regarding what constitutes a pre-planned evolution, including ensuring
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that operations shift management is cognizant of the activity and the possible consequences or expected responses prior to the start of physical work. Additionally, the evolution / activity
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needs to be controlled by the appropriate work group, and appropriate plant conditions need -
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to be monitored during the evolution / activity.
The inspectors reviewed the guidance provided to the operators and concluded that it
adequately addressed the inspectors' concern. Additionally, the inspectors noted one other instance involving confusion regarding when an activity is pre-planned, which occurred prior
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to issuance of the guidance in June. This event resulted in a late four-hour report to the NRC, and is reviewed in section 1.2 of this inspection report. The inspectors had no further questions.
6.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION
6.1 Nuclear Review Board Meeting i
On July 1,1993, the Nuclear Review Board (NRB) met at Limerick Generating Station, and the inspectors attended portions of the meeting. The inspectors found the meeting to be well-
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attended, with detailed presentations, and active participation from the board members. The inspectors concluded that the NRB successfully fulfilled its technical specification function of providing an independent review and audit of designated activities.
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i 7.0 MANAGEMENT MEETINGS
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l 7.1 Exit Interviews
i The inspectors discussed the issues in this report with PECo representatives throughout tha inspection period, and summarized the findings at an exit meeting with the Plant Manager,
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Mr. R. Boyce, on July 6,1993. PECo personnel did not express any disagreement with the inspection findings. No written inspection material was provided to licensee representatives
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during the inspection period.
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f 7.2 Additional NRC Inspections this Period i
Two Region-based inspections were conducted during this inspection period. Inspection l
results were discussed with senior plant management at the conclusion of the inspections.
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Date Subiect Insnection No.
Lead Inspector 6/24 - 6/27/93 Emergency 50-352/93-11 J. Laughlin
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Preparedness 50-353/93-11
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6/28 - 7/2/93 Engir.eering 50-352/93-15 J. Carrasco 50-353/93-15
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