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Insp Repts 50-352/93-09 & 50-353/93-09 on 930418-0524. Enforcement Discretion Exercised.Major Areas Inspected:Plant Operations,Maint & Surveillance Observations,Engineering & Technical Support,Emergency Preparedness & Security
	ML20045A515
Person / Time
Site:	Limerick
Issue date:	06/04/1993
From:	Anderson C; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20045A512	List: IR 05000352/1993009; ML20045A511;
References
	50-352-93-09, 50-352-93-9, 50-353-93-09, 50-353-93-9, NUDOCS 9306110020
	Download: ML20045A515 (48)
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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report Nos.

93-09-l

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93-09 l

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50-352

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50-353 License Nos.

NPF-39 NPF-85 Licensee:

Philadelphia Electric Company Correspondence Control Desk l

d P.O. Box 195 Wayne, Pa 19087-0195

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Facility Name:

Limerick Generating Station, Units 1 and 2 l

Inspection Period:

April 18 through May 24,1993 Inspectors:

N. S. Perry, Senior Resident Inspector T. A. Easlick, Resident Inspector

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Approved by:

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Clifford J.'Anderd6n, Chief Date Reactor Projects Section No. 2B f

9306110020 930607 PDR ADOCK 05000352 O

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r EXECUTIVE SUMMARY Limerick Generating Station

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Report No. 93-09 & 93-09 Plant Operations Operator actions were successful in reducing the severity of a reactor level transient that resulted from a feedwater master controller malfunction. A concern regarding plant

personnel finding several valves mispositioned during performance of an ESW lineup verification, remains unresolved pending the completion of the investigation and corrective actions (50-352/93-09-01) (Section 1.3). PECo has fully implemented the BWROG guidance concerning the effects of noncondensible gases in the instrument reference legs and has ensured that operations personnel are knowledgeable and capable of executing this guidance (Section 1.5).

Maintenance and Surveillance i

As a result of at least two EDG component failures attributed to piston pin bushings at the Peach Bottom Station, plant management displayed good initiative by incorporating piston bushing examinations into periodic engine inspections. A significant weakness was observed in the maintenance practices used during the replacement of an overload relay for a drywell'

chilled water valve. A concern regarding the method by which a wiring problem was

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corrected for this valve, remains unresolved pending completion of PECo's final investigation (50-352/93-09-02) (Section 2.3). An investigation following the failure of a drywell chiller to trip when the control room handswitch was taken to stop, identified a trip coil that was disabled due to a lifted and taped wire. This issue remains unresolved pending the completion of PECo's investigation (50-353/93-09-03) (Section 2.4). A concern regarding the operability of a core spray system valve remains unresolved (50-353/93-09-04) (Section 3.2) pending PECo's final analysis and resolution of the issue. A limit switch problem could have prevented the valve from closing under response time testing conditions.

Eneineerine and Technical Support

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A violation of technical specifications concerning a tightness check of vital battery connections was identified by plant staff. Overall response to the issue was appropriate, and actions taken to verify battery operability were conservative and carefully planned and executed. This is a non-cited violation (Section 4.1). A violation involving the failure to have operable toxic gas monitors since initial installation, as required by technical

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specifications, also meets the criteria for enforcement discretion and will not be cited l

(Section 9.1).

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TABLE OF CONTENTS EXECUTIVE SUMMARY i

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1.0 PLANT OPERATIONS

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1.1 Operational Overview................................. I 1.2 Feedwater Master Controller Malfunction I

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1.3 Emergency Service Water Lineup......................... 2 1.4 Engineered Safety Feature System Walkdown - Standby Liquid Control.

1.5 Level Instrumentation Errors During Depressurization (TI 2515/119)....

1.6 Operations 12 Hour Shift Schedule......................... 6 2.0 MAINTENANCE OBSERVATIONS............................ 6 2.1 Residual Heat Removal System Maintenance....................

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2.2 Diesel Generator D-11 Maintenance........................ 7 2.3 Improper Wiring of a Drywell Chilled Water Valve

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2.4 2B Drywell Chiller Trip Failure.......................... 8 2.5 Fuel Pool Cooling System Maintenance...................... 9 3.0 SURVEILLANCE OBSERVATIONS

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3.1 Emergency Diesel Generator Surveillances...................

3.2 Core Spray System Response Time Test I1

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4.0 ENGINEERING AND TECHNICAL SUPPORT...................

4.1 Vital Battery Surveillance Missed

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4.2 Spray Pond Piping Draining............................

5.0 RADIOLOGICAL PROTECTION

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6.0 EMERGENCY PREPAREDNESS

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7.0 SECURITY

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8.0 SAFLTY ASSESSMENT / QUALITY VERIFICATION................

9.0 REVIEW OF LICENSEE EVENT AND ROUTINE REPORTS.........

9.1 Licensee Event Reports (LERs)..........................

9.2 Routine Reports

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10.0 M A NA G EM ENT M EETI NG S...............................

10.1 Exit Intervi ews....................................

10.2 Additional NRC Inspections this Period.....................

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DETAILS r

1.0 PLANT OPERATIONS (71707,71710,92701)'

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 compliance with technical specifications. Accessible areas of the plant were toured; plant conditions, activities in progress, and housekeeping conditions were observed. Additionally, selected valves and breakers were verified to be aligned correctly. Deep backshift inspection was conducted on April 18 and May 22.

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 at the end of the reporting period. On May 22,1993, power was reduced to approximately 75% to clean a main condenser water box and realign the condensate pumps. This evolution was completed and

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the unit was returned to full power.

Unit 2 began the inspection period at full power until April 19, 1993, when the unit

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experienced a level transient that resulted in a reduction in power to 71% (Section 1.2). The unit was returned to full power, until a planned power reduction to 62% on May 1,1993, to realign the 2C condensate pump. The unit was retumed to full power the following day.

i The unit remained at full power until May 16, 1993, when an electrohydraulic control (EHC)

oil leak was identified on the Number 2 Main Turbine Control valve. The unit was reduced to 20% power and the main turbine was taken offline for repairs. The unit was subsequently returned to power on May 17, 1993, and remained at full power for the remainder of the inspection period.

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i 1.2 Feedwater Master Controller Malfunction

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On April 19, 1993, with Unit 2 operating at 100% rated power and the three reactor feed pump (RFP) turbines controlled by the master controller, the unit experienced a level

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transient that resulted in a trip of the C RFP and a recirculation pr.up runback to 62% speed.

This event was caused by the master feedwater level controller's output spiking downward

several times over a four second time period. The RFPs responded to the spikes by decreasing flow to the reactor vessel. Reactor water level had reduced from 36 inches to 30 i

inches when the master feedwater level controller spiking stopped. The feedwater level control system (FWLCS) responded to the decreasing reactor water level by increasing RFP

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'The NRC Inspection Procedures used as guidance are listed parenthetically throughout this report.

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flow to the vessel. By the time the first alarms were received the operators observed that feedwater flows on the B and C pumps were upscale and the A was increasing. The increased feedwater flow caused a reduction in the suction pressure to the RFPs and the C RFP tripped on low suction pressure. The C RFP tripped first due to its low suction pressure trip time delay being the shortest, which allowed suction pressure to the remaining pumps to increase enough to prevent the A and B pumps from tripping.

Following the trip of the C RFP, reactor level decreased and caused a recirculaiion runback

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to 62% speed. This occurred, as designed, due to y,ater level below 27.5 inches and feedflow through any one RFP less than 20%; in this case the C RFP was tripped. With the decreasing feedwater temperature and the reduced core flow, the average power range monitors (APRM) alarmed and the operator inserted the first four control rods of reactor engineering procedure (RE)-201 to obtain a larger scram margin with a final reactor power of 71%.

PECo's followup investigation of the event indicated that the master level controller had malfunctioned as stated above; however, no cause for this malfunction could be identified and the problem could not be repeated. The possibility of a common mode failure between this transient and an earlier feedwater transient on April 7,1993, involving the A narrow range (NR) (NRC Combined Inspection Report Nos. 50-352/93-07 and 50-353/93-07), is being reviewed. A feedwater level control power supply provides +24 VDC to the A NR water level channel and the four circuit cards associated with the master feedwater level controller. A failure or degradation of this power supply could initiate the same type of

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transient. A recorder was installed on. April 22,1993, to continuously monitor the power supply output for abnormalities. As of the end of this reporting period no disturbances had been observed. The plant staff has investigated all possible failures that could have initiated the feedwater transients and all equipment has been confirmed to be operating as designed.

At the end of the inspection period, the A NR level channel was selected as the controlling channel for feedwater level control.

In response to these recent transients, management placed an item in the Shift Night Orders to inform all shifts that a feedwater transient had occurred. Although normal operator training is sufficient, as evidenced by the successful operator actions taken to reduce the severity of the transient, each operations shift has received additional feedwater transient training on the simulator. This training provided operators with the different types of feedwater transients and operator responses that can mitigate the consequences of these types of events. The system manager was present at a training class to ensure all appropriate transients were being demonstrated.

1.3 Emergency Service Water Lineup During performance of the emergency service water (ESW) lineup verification, on May 10,1993, plant personnel found several valves mispositioned. Four valves, that should have been in a throttled position, were found full open. Additionally, these and several other i

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valves were found without the required restraints installed. Restraints were required for

these valves to ensure that vibrations do not cause the valves to become repositioned. The

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valves were correctly repositioned with restraints as required. Engineering personnel determined, using computer flow modeling, that the ESW system was operable at all times, since the flow required to all components was adequately met.

Preliminary investigation by plant personnel determined that these valves were last manipulated on May 6,1993, for a routine flushing operation, for which the valves are fully opened. Prior to opening the valves for flushing, plant personnel found all of the valves in the required positions, but after the flushing operation may have inadvertently failed to return

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the valves to a throttled position. After the flushing operation was completed, all of the valves manipulated were independently verified to be in the required positions. This independent verification apparently failed to identify the mispositioned valves.

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The inspectors questioned operations personnel concerning independent verification of throttled valves. Operations personnel indicated that no documented policy exists describing tL_. method for independently verifying throttled valves. It appears, through discussions with several operators, that no consistent method was used. Operations management immediately described the required method for verifying throttled valves in the Shift Night Orders to operations personnel, and will incorporate the requirements for independent verification of throttled valves into the Operations Manual.

Plant personnel were continuing their investigation at the end of the inspection period, and other corrective actions are being evaluated. This issue will remain unresolved pending NRC review of the completed investigation and corrective actions (50-352/93-09-01).

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1.4 Engineered Safety Feature System Walkdown - Standby Liquid Control

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An engineered safety feature system walkdown was performed on the accessible portions of the Unit I standby liquid control (SLC) system components, to verify operability. The inspectors verified that the system lineup procedure matched the piping and instrument

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drawing, and the actual system configuration. Drawing 8031-M-48, sheet 1, Standby Liquid Control (Unit 1), Rev. 25, and procedure IS48.1.A, Equipment Alignment to Place Standby Liquid Control System in Normal " Standby" Condition, Rev.12, were used for the lineup

verification. Procedures ST-3-048-320-1, SLC Operability Verification and Valve Test, Rev.

9, ST-6-107-590-1, Daily Surveillance Log /Opcons 1,2,3, Rev. 60, ST-6-048-230-1, SLC Pump, Valve, and Flow Test, Rev. 2 and ST-6-048-450-1, SLC Lineup Verification, Rev. 3,

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were used to verify that the appropriate technical specification requirements were being met.

The inspectors concluded that the Unit 1 SLC system was properly aligned for operability as i

required, and no equipment conditions existed that might degrade overall performance.

Minor discrepancies were noted on the drawing, in that several valves were shown to be

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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. The inspectors had l

no further concerns.

1.5 Level Instrumentation Errors During Depressurization (TI 2515/119)

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As discussed in NRC Information Notice (IN) No. 92-54, Level Instrumentation Inaccuracies Caused by Rapid Depressurization, and Generic Letter (GL) No. 92-04, Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs pursuant to 10 CFR 50.54(f), the NRC is concerned that noncondensible gases may become dissolved in the reference legs of BWR water level instrumentation. The dissolved gases, which accumulate j

over time during normal operation, can come out of solution rapidly during depressurization

and displace water from the reference leg. A reduced reference leg level will result in a j

false high vessel level indication. The inspectors reviewed PECo's implementation of operator guidance and training to ensure required operator actions concerning water level following rapid depressurization transients is commensurate with the guidance. Additionally,-

the inspectors ensured that this guidance and training is consistent with current plant Emergency Operating Procedures (EOPs).

At Limerick four cold reference legs are used for reactor water level indication and provide

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input to various plant systems for automatic systems response. These systems include:

Emergency Core Cooling Systems (ECCS); Reactor Protection System (RPS); Redundant Reactivity Control System (RRCS); Main Turbine, Reactor Feed Pump, HPCI and RCIC turbine trip signals; and Primary Containment Isolation System (PCIS). In addition, the cold

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leg level instruments' indications are used to make EOP decisions and for taking manual actions where level is the determining parameter.

PECo developed a licensed operator requalification lesson plant (LP) to familiarize the licensed operators and shift technical advisors (STA)s with the effects of dissolved

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noncondensible gases on vessel level indication. The LP, Reactor Level Indication System, provided an in-depth review of the phenomenon of noncondensible gases in the reference leg and its effect on indhated level. The LP also reviewed the basic operation of the level transmitters covering both the electrical and mechanical arrangement of the transmitters. The LP was made part of a four hour training period dedicated to this issue during cycle 1 requalification training, given in January 1993. At the conclusion of the inspection, training management has not permanently incorporated this LP into the requalification training program since they are waiting for the final results of the BWR Owners Group (BWROG)

investigation and recommendations concerning this issue. The LP will be reviewed by the licensee on an annual basis to determine the need for incorporation into the requalification training. The LP is also being tracked as a commitment to PECo's response to Generic letter 92-04 concerning this issue.

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The simulator currently in use at the I.imerick Training Center is a 1980 vintage simulator.

As such, it is unable to adequately model the effect of noncondensible gases coming out of solution in the reference legs of level instrumentation. PECo is currently initiating a simulator model upgrade program, with completion expected in April 1994. The ability to model this event accurately will be provided by this upgrade. The simulator instructor will be able to simulate a leak in the level reference leg, which will emulate noncondensible~ gases coming out of solution. To compensate for this lack of simulator training, instrumentation and controls (l&C) personnel constructed a mock-up of a wide range level instrument, including reference and variable legs, a Rosemount transmitter, and a level indicator The mock-up was set up in the I&C laboratory and compressed air was introduced into the reference leg to simulate the event. Operators were able to observe the phenomenon and the corresponding indicated level effects. This mock-up was utilized during cycle 1 training in conjunction with the LP review. The operators were also shown a 30 minute tutorial video made by a vender at the direction of the BWROG, as part of the cycle training. The inspectors reviewed the video and found it to be very informative.

The inspectors had the opportunity to observe a shift crew, currently in requalification training, on the simulator. Since the simulator is unable to adequately model the effects of noncondensible gases in the reference legs, the inspectors requested that the crew perform a rapid depressurization scenario with level instrument failures to determine if the EOPs provide clear guidance to the operators when reactor water level is unknown. The rapid depressurization was a rupture of the A recirculation loop suction piping and the failure mode for the reactor water level instrumentation was reference leg flashing due to elevated containment temperatures following the loss of coolant accident (LOCA). The operators immediately recognized the reference leg flashing event following the LOCA and implemented Trip Procedures (T)-ll2, Emergency Blowdown, and T-ll6, RPV Flooding, in response to water level being undetermined. The overall crew response to this scenario was excellent and the inspectors had no further questions. The inspectors noted that the plant safety parameter display system (SPDS) computer screen did change color (purple) to indicate that the level parameter was no longer valid during the scenario. The SPDS computer also has an RPV Level Validation Page that lists all the level instruments and gives the current status of the indication.

In addition to the cycle training, operations management initiated a read and sign Shift Training Bulletin on the issue concerning noncondensible gases and an entry was made in the Shift Night Orders, which provide operators with the guidance on how to determine RPV water level following a rapid depressurization. The inspectors discussed these items, along with the cycle requalification training that was provided in January 1993, with the licensed

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operators including 10 senior reactor operators and 8 reactor operators. All individuals were

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management expectations in the event ofinaccurate level indications. The operators were also knowledgeable of the EOPs and the direction provided in the event that water level cannot be determined, t

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In summary, PECo has fully implemented the BWROG guidance concerning the effects of noncondensible gases in the instrument reference legs and has ensured that operations personnel are knowledgeable and capable of executing this guidance. PECo is an active participant in the BWROG activities regarding this issue and will monitor the progress of the BWROG on this issue and continue to review possible hardware modifications.

1.6 Operations 12 Hour Shift Schedult In March 1993, the operations shift personnel and station management decided to revise the operations shift schedule from an 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months daily work schedule. The schedule

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was implemented on April 20,1993. There are 6 shifts in two rotating schedules from 6:30 a.m. to 6:30 p.m. on days, and 6:30 p.m. to 6:30 a.m. on nights. Both schedules have each shift operator scheduled to work 240 hours0.00278 days 0.0667 hours 3.968254e-4 weeks 9.132e-5 months in a 6 week period and the schedule is repeated every 6 weeks. Prior to implementing the schedule a 10 CFR 50.59 evaluation, keview for Operations Twelve Hour Shifts, was initiated and reviewed by the Plant Operations Review Committee (PORC). The PORC concluded that implementation of the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months shift schedule does not involve an unresolved safety question and a change to the technical specification was not required at this time.

The inspectors discussed the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months shifts and the effects on the plant operating staff with plant management. Operations management has established performance indicators to monitor the change in the shift rotation. These indicators include, use of overtime, violations

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of administrative procedure (A)-40, Working Hour Restriction, number of Licensee Event Report (LERs) and number of reportability evolution / event investigation forms (RE/EIFs)

generated. In addition, each shift has a designated supervisor to accept any feedback from his shift on problems related to the new shifts duration. Every 2 months a meeting will be held to discuss and evaluate 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months shift issues.

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Currently a work coordination issue is being addressed related to equalization of work to relieve the amount of scheduled work on Tuesday, Wednesday and Thursday night shifts. A review of operations overtime for the last 3 weeks has indicated a reduction in overtime of approximately 2.5% compared to originally budgeted overtime for the same period. The inspectors will continue to review the performance indicators, and considers operations management involvement in the program to be comprehensive.

2.0 MAINTENANCE OBSERVATIONS (62703)

2.1 Residual IIcal Removal System Maintenance The inspectors reviewed selected residual heat removal (RHR) system maintenance activities

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to verify that the activities were conducted in accordance with approved procedures and in compliance with NRC regulations and recognized codes and standards. The inspectors also

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verified that the replacement parts and quality control utilized were in compliance with PECo's Quality Assurance (QA) program.

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The following RHR system maintenance activities were reviewed:

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2D RHR motor lead repair, WO CO141419, observed May 4,1993.

For this maintenance activity, the inspectors observed good quality control and technical

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monitoring by appropriate plant personnel. Worker knowledge of the activity was good, and written instructions were being followed.

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1B RHR pump seal cooler cleaning, WO 487005, observed May 5,1993.

For this activity, the inspectors found the workers very knowledgeable of the activity, its frequency, and its history.

The inspectors had no further comments on the RHR system maintenance activities.

2.2 Diesel Generator D-11 Maintenance At the end of this reporting period the D-11 emergency diesel generator (EDG) was:

undergoing a five year overhaul. As a result of at least two EDG component failures attributed to piston pin bushings at the Peach Bottom Station, Limerick has incorporated piston bushing examinations into its periodic engine inspections. The piston pin bushing, piston pin, insert bushings and insert, form the pivot and connection assembly between the piston and connecting rod on the EDG.

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On May 20,1993, four of the twelve piston bushings inspected were found with less then desirable internal clearance. When the clearance is lost between the piston pin bushing and the insert bushing, the bushings can overheat and expand axially along the piston pin and eventually push the piston skirt outward against the cylinder wall. In this case, Nos. 3,9,11 and 12 upper piston pin bushings were found to have unacceptable internal clearance as

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indicated by excessive wear in several locations. In addition, the No. 9 upper piston insert bushings showed slight protrusion outward from the insert.. All four piston pin bushings were replaced with new bushings. The No. 9 insert and insert bushings were replaced with a new insert and bushings.

PECo is currently investigating the cause of the problem with the piston pin bushings, involving both Coltec Industries (EDG Vender) and PECo Metallurgy Laboratory. The most probable cause, suggested by Coltec, is faulty bushing material. The faulty bushings and the l

No. 9 insert will be forwarded to the Metallurgy Laboratory for analysis. Other possible causes suggested by PECo include 5-6 fast starts on the engine each year, and the fact that the D-11 was synchronized to the grid 180 out of phase in June of 1987. It should be noted that the D-12 EDG recently completed its 5 year overhaul and no piston pin bushing problems were identified.

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The inspectors will continue to follow PECo's investigation of the failure mechanism for these bushings. Incorporating this examination into the PECo EDG inspection program was an excellent initiative and will contribute to the safe, reliable operation of the diesels.

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2.3 Improper Wiring of 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.

Earlier that day, operations personnel applied a clearance on Dil4-R-C-13 to have maintenance perform cleaning, examination and calibration of the breaker. While testing the overload relay, it was determined that the B phase of the relay did not operate properly.

Consequently, per the procedure, the overload relay and heaters were replaced. The breaker was subsequently tested satisfactorily on the bench and returned to operations to restore the clearance. The operators restored the clearance and the post maintenance testing was attempted. Following the failed test, it was determined that the physical configuration of the thermal relay wires was reversed. In order to correct the problem, two wires on the load side of the breaker were swapped and the post maintenance test was satisfactorily performed.

The inspectors were concerned with this event since the relay replacement was performed using a procedure that required a worker and an independent verification be performed during both the determination and the retermination of the overload relay. This indicates a significant weakness in the maintenance practices used during this job. The safety significance of this event was reduced by the fact that the post maintenance test program identified the deficiency prior to the valve being returned to operable status. However, the J

inspectors are concerned with the method by which the problem with the wiring was corrected. It was not evident at the close of the inspection period that when the two wires on j

the load side of the breaker were swapped, there was a procedure controlling the evolution.

This issue will remain unresolved pending completion and NRC review of PECo's final j

investigation (50-352/93-09-02).

i 2.4 2B Drywell Chiller Trip Failure

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On May 21,1993, during the break-in runs on the 2A Drywell Chiller, the 2B Drywell

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Chiller failed to trip. Both chillers were running together during the 2A break-in runs.

Additional load was needed for the 2A chiller, so the 2B chiller was to be shutdown.

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The control room handswitch for the 2B chiller was taken to STOP. The discharge valve was observed by the operators to have closed, but the compressor indication remained red which indicated the chiller was still running. An operator was immediately dispatched to the 4 KV breaker to trip the breaker. The breaker was manually tripped. The time the compressor was running after the handswitch was taken to STOP was estimated at about 5 minutes.

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The system manager was contacted to determine the cause of the failure to trip. The breaker was tested by maintenance personnel and the chiller logic was tested by the system manager with no problems identified. The auxiliary logic in the breaker cubicle was inspected by the system manager and STA. The chiller trip relay which energizes the trip coil in the breaker cubicle was found disabled. The M2 wire was found lifted from the 105-11708 relay (E-464). The wire was lifted and taped, with the relay screw missing. This deficiency is still under investigation by PECo and the issue will remain unresolved pending NRC review of the completed investigation (50-353/93-09-03).

2.5 Fuel Pool Cooling System Maintenance The inspectors reviewed a Nuclear Maintenance Division (NMD) work order (WO) package (C0132879) for work that was performed on the Unit I fuel pool cooling system, during the Unit 2 refueling outage in February 1993. An action request (AR) was initiated to address fuel pool weir leakage. During fuel pool cooling system shutdown, the skimmer surge tank level had been increasing at approximately one foot per hour. This input to the tank was suspected to be from weir leakage. Subsequently a WO was written to tighten and/or replace the weir gaskets.

While reviewing the WO package with an NMD supervisor the inspectors noted that there were three activities covered by this WO, but that activity 03 was not in the current package.

The NMD supervisor suggested that we go to a nearby Plant Information Management

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System (PIMS) terminal and print out that portion of the WO dealing with activity 03. The PIMS indicated that activity 03 had been deleted and was done as part of activity 01. The inspectors questioned what activity 03 was and how it was incorporated into activity 01.

The NMD supervisor was able to address the inspectors' concerns by speaking with Quality Control personnel involved in the work activity. Apparently there were two welding procedures for the fabrication of weir plates in this package. The original procedure had a weld information data (WID) sheet which required, " welds to be final visual by job leader,"

which was appropriate for a non-Q system or component. The second procedure was a field weld checkoff list (FWCL) which required a Quality Verification (QV), " clean check and final visual," essociated with a Q-system or component. The craft workers welded the plates and signed the WID sheet for final visual inspection, then seeing the FWCL called QV to inspect the work. The QV inspector told the craft workers that the job was performed unsatisfactorily since the clean check requirement had not been performed p'ior to welding.

The QV inspector placed a hold on the job. Since the work instructions were contradictory

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an investigation was initiated. The original WID sheet was approved by QV and no Quality Control Verincation Plan (QCVP) was needed. Another activity was created (activity 03) for the FWCL and a QCVP was created. However, since this was a non-Q component, the newly created activity was not needed. This issue was resolved by deleting the FWCL activity and using the original WID sheet requirements for inspection. The inspectors verined that the weir plates were not on the facility Q-list. The inspector had no further questions concerning this issue. In addition, the inspectors found the rest of the WO package complete and in accordance with approved plant procedures.

3.0 SURVEILLANCE OBSERVATIONS (61726)

3.1 Emergency Diesel Generator Surveillances During this inspection period, the inspectors reviewed in-progress EDG surveillance testing and completed surveillance packages. The inspectors veri 5ed that the surveillances were completed according to PECo approved procedures and plant technical specification requirements. The inspectors also veriGed that the instruments used were within calibration tolerance and that qualiBed technicians performed the surveillances.

The following EDG surveillances were reviewed:

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RT-6-092-322-1, D-12 Diesel Generator Overspeed Trip Test, Revision 0, observed April 17,1993.

For this surveillance activity, the inspectors observed the pre-briefing in the main control room, and the performance of the surveillance at the EDG. The pre-briefing was comprehensive and good management oversight was noted at the EDG.

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ST-6-092-312-2, D-22 Diesel Generator Slow Start Operability Test Run, Revision i

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14, observed May 18,1993.

For this surveillance activity, the inspectors observed performance from the main control i

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room. Operators perfc,rming the surveillance were found to be very knowledgeable of the activity and the surveillance requirements.

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Various testing after the 5 year overhaul of D-11 diesel generator.

Portions of the testing to return the EDG to an operable status were observed by the inspectors from the main control room and at the EDG. Operators in the control room and at the EDG monitoring its performance were found very knowledgeable of the ongoing testing.

The inspectors identified no deficiencies for the EDG surveillance activitie. -

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3.2 Core Spray System Response Time Test During the performance of ST-1-052-801-2, Loop A Core Spray System Response Time Test, on January 20,1993, the core spray loop A full flow test valve, HV52-2F015A, failed to fully close as required. The purpose of this test was to measure the response time for the core spray system from automatic initiation to starting the core spray pump and developing rated pressure and flow. The full flow test valve is a normally closed valve that receives a close signal during a core spray system initiation. During time response testing, when the core spray pump starts, the valve is manually opened (with the use of logic jumpers) and

,

then the breaker for the valve is opened when the valve is in the fully open position. This will prevent the automatic closure of the valve on the loss of coolant accident (LOCA)

signal. Once the system is in service the full flow test valve is manually throttled to achieve-3175 gpm as required by the test. Upon completion of the test the circuit breaker for the full flow test valve is closed and the valve returns to the full closed position.

During the test performed on January 20,1993 the full flow test valve did not go closed as

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expected when power was restored to the valve. PECo's investigation revealed that when the valve was manually throttled closed to achieve 3175 gpm the closed limit switch was made up due to a misalignment of the limit switch. When power was restored to the valve, the valve logic indicated the valve was already in the closed position, when in fact it was still throttled open. The valve was subsequently closed by taking the control room handswitch to the closed position.

At that time, the operability of the valve was reviewed, since it is a primary containment isolation valve required to close on an initiation signal to the core spray system in 23 seconds. Plant management determined that the valve would close under normal conditions

'

(the response time testing placed the valve in an abnormal condition, manually throttled) and it was declared operable with an administrative information tag placed on the valve

'

handswitch. The limit switches were scheduled to be realigned during the first planned maintenance window. On February 11, 1993, a logic system functional test was performed and the full flow test valve operated properly in response to a LOCA signal, going fully closed from an open position.

,

On April 13, 1993, the full flow test valve was declared inoperable for maintenance work.

At that time, the operations shift manager raised a question about the operability of the valve since the limit switch problem was first identified on January 20,1993. The shift manager was concerned that the valve would not close under all conditions, including the abnormal condition during response time testing, and therefore, should have been inoperable since January 1993. This issue is currently being reviewed by PECo and that review has been expanded to include other valves that might be susceptible to this problem. In addition, the effects on the valve logic of a loss of offsite power (LOOP) concurrent with a LOCA signal i

are being reviewed. The valve is currently deenergized to meet the technical specification action statement for an inoperable primary containment isolation valve. This issue will remain unresolved pending completion of NRC review of PECo's results (50-353/93-09-04).

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4.0 ENGINEERING AND TECIINICAL SUPPORT (71707)

4.1 Vital Battery Surveillance Missed On April 23,1993, during a review of surveillance procedures, plant personnel determined that Technical Specification Surveillance Requirement 4.8.2.1.c.2, concerning a tightness

'

check of battery cell-to-cell and terminal connections at least once per 18 months, had not been met since 1989, for both units. Technical Specification Surveillance Requirement 4.0.3 was entered, allowing 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to complete the surveillance. All 2400 &cted battery cell-to-cell and terminal connections were verified tight within the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period. During performance of the tightness verification, the batteries were declared inoperable, and the

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associated action statement was entered, for batteries with connections found not meeting the acceptance criteria for tightness.

Plant personnel began performing the surveillance requirement by verifying that the connections were torqued to the manufacturer's recommended value for initial installation.

For both units, this process was successful for the division I and II batteries; however, problems were encountered for the division 111 and IV batteries for both units. The division III and IV battery posts are smaller than the division I an II battery posts (3/4 inch versus 1 inch). When the connections for the division III and IV batteries were retorqued, personnel noticed some resulting deformation of the posts. The surveillance was stopped, to ensure that no damage would result from the torquing, and the manufacturer was contacted. The manufacturer indicated that the connections should only be torqued during installation and that subsequent checks should be for snugness only. Additionally, the manufacturer indicated that the slight deformation observed is acceptable. Plant personnel continued the surveillance verifying the connections were hand tight, as recommended by the manufacturer.

Plant management determined that the surveillance requirement was improperly deleted from

'

the appropriate surveillance procedures in 1988. The deletion was intended to prevent damage to the batteries due to repeated torquing of the connections. It was thought that an acceptable cell-to-cell connection resistance value along with an acceptabic visual examination would effectively satisfy the tightness requirement. In addition to immediately performing the surveillance requirement, the appropriate procedures will be revised to include a tightness verification of cell-to-cell and terminal connections, prior to their next performance. Plant management concluded that the cell-to-cell and terminal connections were sufficiently tight such that the batteries would have performed their design function

'

throughout the period of the missed technical specification surveillance requirement, and that loose connections would have been detected through observation or resistance readings taken during performance of the surveillance.

.

The inspectors and NRC Region I management discussed the event and the actions taken, and concluded that the overall response to the issue was appropriate. Actions taken to verify battery operability were conservative and carefully planned and executed. This event could

,

not reasonably be expected to have been prevented by the corrective action for a previous i

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event. The inspectors observed the deformation of the division III and IV battery posts and concluded that it was not extensive and should not affect battery performance. This violation involving the failure to meet a technical specification surveillance requirement and not taking the associated actions within the required time, meets the criteria for enforcement discretion of Section VII of the NRC's Enforcement Policy and will not be cited.

4.2 Spray Pond Piping Draining During shift turnover, on April 19, 1993, an operator recognized that the offgoing shift had failed to drain spray pond piping as required following running of the residual heat removal service water and emergency service water pumps. Technical SpeciGcation Surveillance Requirement 4.7.1.3.c requires verification that all piping above the frost line is drained i

within I hour after being used. Operators immediately initiated spray pond piping draining, which was completed prior to exceeding the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months technical specification action statement.

Plant event investigation determined that the root causes for this were that the operators were very busy and inadvertently missed the requirement, and that the controlling procedure was weak in that the use of cautions could have been better. Corrective actions include

..

evaluating the procedure and implementing improvements as necessary, and reiterating

!

management expectations to the operators concerning draining the spray pond piping.

The inspectors reviewed the event and questioned the reason for requiring draining of the piping within such a short period of time, when conditions do not exist which would potentially cause freezing to occur. Prior to the end of the inspection period, plant management indicated that a technical specification change request was being reviewed which would modify the surveillance requirement to be valid only during conditions when freezing would be a potential concern. In this instance, there was no safety signincance to this event since outside air temperatures were high enough to prevent freezing. The inspectors had no

,

further concerns.

5.0 RADIOLOGICAL PROTECTION (71707)

During the inspection period, the inspectors examined work in progress in both units including health physics (HP) procedures and controls, ALARA implementation, dosimetry and badging, protective clothing use, adherence to radiation wot permit (RWP)

requirements, radiation surveys, radiation protection instnm.ent use, and handling of potentially contaminated equipment and materials.

.

The inspectors observed individuals frisking in accordance with HP procedures. A sampling of high radiation area doors was 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 and people working in RWP areas were observed as meeting the applicable requirements. The activities observed by the inspectors l

were acceptable.

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6.0 EMERGENCY PREPAREDNESS (71707)

On April 21,1993, plant personnel conducted a practice emergency drill. This drill was intended as a pmetice for the annual emergency exercise. The inspectors observed portions

,

!

of the drill, attended the post-drill critique in the technical suppon center, and concluded that the drill adequately met the goal of providing plant personnel with training for the annual exercise and potential plant events. In particular, the inspectors noted that the critique was comprehensive with good cornments and recommendations from the players and observers.

The inspectors identified no deficiencies.

7.0 SECURITY (71707)

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 impicmentation of access controls including authorization, badging, escorting, and searches. No inadequacies were identified.

8.0 SAFETY ASSESSMENT / QUALITY VERIFICATION (40500)

8.1 Plant Oparations Review Committee

.

During this inspection petiod the inspectors attended PORC meetings where the vital battery connection tightness issu were discussed. The meetings were found to be well attended, with good participation by various managers. Reviews conducted were comprehensive and thorough. The inspectors identified no deficiencies.

8.2 Performance Assessment Meeting On May 17,1993, PECo management presented results of their self assessment for the

'

period since March 1992. Functional area managers described strong performance areas,

,

performance improvements, and improvement initiatives. The meeting was informational in

'

nature and open to observation by the public. The handout from the meeting is attached to this report.

9.0 REVIEW OF LICENSEE EVENT AND ROUTINE REPORTS (90712,90713)

9.1 Licensee Event Reports (LERs)

t LER l-87-028, Failure to Perform Hourly Firewatch Required by Technical Specifications, Revision 1, Event Date: June 10,1987, Report Date: May 7,1993.

!

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This LER revision was made to add the corrective action of including responsibility for hourly firewatch patrols with the security organization. No deficiencies were identified.

LER l-93-003, A condition prohibited by Technical Specifications in that the Toxic Gas

Detection System was inoperable for the detection of ammonia since initial installation, Event Date: October 26,1984, Report Date: March 30,1993.

This LER documents the identification of a condition whereby the toxic gas analyzers would not respond to the presence of ammonia in adequate time to allow 120 seconds for operators to don self contained breathing apparatus prior to reaching the incapacitation level, as specified in the Limerick Generating Station Updated Final Safety Analysis Report. On

March 3,1993, the A and B toxic gas analyzers were declared inoperable based on an investigation initiated in February 1993, which concluded that the analyzers' capabilities had

{

been misinterpreted. It was incorrectly thought that the response time, when monitoring for

I 5 gases simultaneously, was 40 seconds; the 40 second response time is only valid when monitoring for a single gas. Recalculations of the response time indicated that the actual time period was too long by approximately 53 seconds. In order to meet the newly calculated response time criteria, the flush time for the sample chamber was reduced to 10 seconds. The 10 second flush time was determined to be adequate for the station environment, and was addressed in the disposition of NCR 93-00119.

The inspectors reviewed the event and the corrective actions taken, and through discussions with plant personnel concluded that the toxic gas analyzers were correctly declared inoperable since original installation, and that corrective actions taken were adequate. Safety significance for this event is minimal since operators are trained on the detection of various odors, such as ammonia, and would have had reasonable time to detect ammonia and don the self contained breathing apparatus, prior to reaching the incapacitation concentration. This event could not reasonably be expected to have been prevented by the corrective action for a previous event. This violation involving the failure to have operable toxic gas monitors since initial installation, as required by technical specifications, meets the criteria for enforcement

,

discretion of Section VII of the NPC's Enforcement Policy and will not be cited.

I LER l-93-004, Primary Containment and Reactor Vessel Isolation Control System Actuation Resulting From Personnel Error during performance of Surveillance Test Procedure, Event Date: April 5,1993, Report Date: May 5,1993.

This event was reviewed and documented in Combined Inspection Report Nos. 50-352/93-03 and 50-353/93-03, Section 1.2, Reportable Events.

LER l-93-005, Missed Technical Specifications Surveillance Requirement due to Personnel Error during Procedure Revision, Event Date: April 23,1993, Report Date: May 21,1993.

This event is reviewed in Section 4.1, Vital Battery Surveillance Missed, of this report.

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LER 2-93-005, Reactor SCRAM and PCRVICS actuation resulting from a closure of the Main Turbine Stop Valves due to air entrained in the Main Turbine Electro Hydraulic Control system, Event Date: April 26,1993, Report Date: April 22,1993.

This event was reviewed and documented in Combined Inspection Report Nos. 50-352/93-03 and 50-353/93-03, Section 1.2, Reportable Events.

'

The inspectors found that the LERs listed above met the requirements of 10 CFR 50.73 and had no further questions regarding these events.

9.2 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 April 1993, dated May 10,1993

10.0 MANAGEMENT MEETINGS 10.1 Exit Interviews The inspectors discussed the issues in this report with PECo representatives throughout the inspection period, and summarized the findings at an exit meeting with the Plant Manager, Mr. J. Doering, on May 24,1993. The licensee personnel did not e-xpress any disagreement with the inspection findings. No written inspection material was provided to licensee

,

representatives during the inspection period.

10.2 Additional NRC Inspections this Period Two Region-based inspections were conducted during this inspection period. Inspection '

results were discussed with senior plant management at the conclusion of the inspections.

Date Subject Inspection No.

Lead Inspector April 26-30,1993 Safeguards 50-352/93-10 Art Della Ratta 50-353/93-10 May 10-14,1993 Radioactive 50-352/93-12 Laurie Peluso Effluents 50-353/93-12

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PERFORMANCE ASSESSMENT RESULTS AGENDA 1. Overview D. R. Helwig 2. Plant Operations L. A. Hopkins 3. Radiological Controls G. W. Murphy

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4. Maintenance / Surveillance D. B. Fetters 5. Emergency Preparedness R. C. Brown 6. Security and Safeguards R. C. Gill

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7. Engineering / Technical J. A. Muntz Support.

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D. R. Helwig-Quality Verification

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MAINTENANCE / SURVEILLANCE

CONTINUED STRONG PERFORMANCE

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SECURITY AND SAFEGUARDS CONTINUED STRONG PERFORMANCE e Implementation of 10CFR 73.56

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I SECURITY AND SAFEGUARDS PERFORMANCE IMPROVEMENTS

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e Environment for Raising Safety-and i

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ENGINEERING / TECHNICAL SUPPORT IMPROVEMENT INITIATIVES

' VOTES' Program (GNL 89-10)

NEEDS

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Cost Effectiveness of Engineering Support

Procedure Partnership

Nonconformance Reports (NCR's)

l l^

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.

_

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.

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SAFETY ASSESSMENT / QUALITY VERIFICATION CONTINUED STRONG PERFORMANCE q

e Strong Safety Focus e Effective Assessment Process

,

i e Effective External Operating Experience Assessment Program

.

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OEAP REVIEWS AND ACTIONS CURRENT VERSUS PREVIOUS SALP PERIOD NUMBER OF REVIEWS / ACTIONS 300 300 250

-"

-

"-

250 REVIEWS

200

--

"-,200 ACTIONS 150

--

~-

150 100

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'

-

"-

100

-"

"-

"

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02-t

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12

16

MONTHS IN THE SALP PERIOD

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.

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+ PREVIOUS SALP ACTION PREVIOUS SALP REVIEW

^

CURRENT SALP ACTION

+ CURRENT SALP REVIEW

' 05/17/93

,

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-

_

.

..

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....,

,

,

-

.

,

SAFETY ASSESSMENT /O.UALITY VERIFICATION PERFORMANCE IMPROVEMENTS

More Aggressive Management involvement and Oversight

'

Event Investigation Process

-

s

Increased Focus on Offsite Station Support Organization

.

'

.

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.~

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. -...

.....

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d-SAFETY ASSESSMENT /O.UALITY VERIFICATION IMPROVEMENT INITIATIVES

Improved Corrective Action Processes e improved Ownership of Training Programs

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Close Monitoring of NEEDS Implementation s

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v t e Inspection Report - Limerick - 1993009
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \| 25 \| 26 \|
1993 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 20(0) 7(0) 8(0) 9(0) 10(0) 11(0) 12(0) 13(0) 14(0) 15(0) 16(0) 17(0) 18(0) 19(0) 20(0) 22(0) 23(0) 24(0) 25(0) 26(0) 27(0) 28(0) 29(0) 31(0) 12(0) Security Operator Exams Emergency Planning Other

IR 05000352/1993009

Text

REGION I

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