IR 05000352/1993007
| ML20036A902 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 05/06/1993 |
| From: | Anderson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20036A896 | List: |
| References | |
| 50-352-93-07, 50-352-93-7, 50-353-93-07, 50-353-93-7, NUDOCS 9305170171 | |
| Download: ML20036A902 (25) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
i Repon Nos.
93-07
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93-07
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Docket Nos.
50-352 50-353
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License Nos.
NPF-39 i
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Licensee:
Philadelphia Electric Company Correspondence Control Desk l
P.O. Box 195 t
Wayne, Pa 19087-0195
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Facility Name:
Limerick Generating Station, Units 1 and 2
Inspection Period:
March 14 - April 17,1993
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Inspectors:
T. J. Kenny, Senior Resident Inspector N. S. Perry, Senior Resident Inspector T. A. Easlick, Resident Inspector
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Approved by:
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Clifford ). bder[4n, Chief Date
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Reactor Projects Section No. 2B i
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i 9305170171 930507 PDR ADOCK 05000352
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t EXECUTIVE SUMMARY
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Limerick Generating Station l
Report No. 93-07 & 93-07 l
Plant Operations t
i Operator response to 2 ESF actuations,1 reactor scram, I main turbine runback, and 1 recirculation pump runback was good. Investigations of the events were thorough, and
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corrective actions were appropriate. A concern regarding reactor level instrumentation spiking, which resulted in an abnormal system configuration for HPCI, following a main
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turbine trip, remains unresolved (50-353/93-07-01) pending PECo's final analysis and i
resolution of the issue. Plant personnel were well-prepared for severe weather experienced
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in March. A concern regarding the licensee's rescinding an LER related to an ESF actuation j
is unresolved (50-353/93-07-02) (Section 1).
Maintenance l
Emergency service water piping replacement and check valve inspection on the emergency
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diesel generators was well-controlled and performed. Adequate corrective actions were taken
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for the diesel prelube pump start failures, following initial identification of keys removed
from " local / remote" switches, located on the diesel control panel. (Section 2)
Engineering and Technical Support
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Installation of two modifications, replacement of Bailey 730 series recorders and installation
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of a cross tie between RHR and fire protection systems, was in accordance with applicable
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codes and standards. (Section 3)
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Radiological Protection j
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Actions taken in response to higher than normal radioactive noble gases experienced in the l
_ plant, due to the prior reactor fuel failure experienced on Unit 2, have been quick and
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comprehensive. (Section 4)
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I Safety Assessment and Ouality Verification
PECo's reorganization at Limerick was initiated and discussed with NRC management. The new format for the morning management meeting, including planned presentations by the
various departments, was observed as a positive initiative. (Section 5)
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TABLE OF CONTENTS EXECUTIVE SUMMARY i
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1.0 PLANT OPERATIONS.................................... I 1.1 Operational Overview................................. I 1.2 Reportable Events................................... I 1.3 Main Turbine Runback................................ 6 1.4 Recirculation Pump Runback........................
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1.5 120 VAC Voltage Verification
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1.6 Severe Weather Actions
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1.7 Power Decrease for Brush Replacement...................... 9
2.0 MAINTENANCE OBSERVATIONS
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2.1 Emergency Diesel Generator Maintenance.................... 9 2.2 Emergency Diesel Generator Prelube Pump Start Failures
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3.0 ENGINEERING AND TECHNICAL SUPPORT
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i 3.1 Review of Modification 6156-2 Replacement of Bailey 730 Series
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Recorders.......................................
3.2 Review of Modification 6147-2, Installation of a Cross Tie Between the RHR and Fire Protection Systems I1
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4.0 RADIOLOGICAL PROTECTION
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5.0 SAFETY ASSESSMENT / QUALITY VERIFICATION................
5.1 PECo's Reorganization...............................
5.2 Changes to Morning Meeting Agenda......................
6.0 REVIEW OF LICENSEE EVENT REPORTS (LERs), ROUTINE AND SPECIAL REPORTS
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6.1 Licensee Event Reports (LERs)..........................
l 6.2 Routine Reports..................................
7.0 FOLLOWUP OF PREVIOUS INSPECTION FINDINGS..............
i 8.0 M AN AGEMENT MEETINGS.............................. -17
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8.1 Exit Interviews....................................
8.2 Enforcement Conference..............................
l 8.3 Reorganization Meeting
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DETAILS
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1.0 PLANT OPERATIONS (71707)'
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The inspectors conducted routine entries into the protected areas of the plant, including the control room, reactor enclosure, fuel floor, and drywell (when access was possible). During
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the inspections, discussions were held with operators, health physics (HP) and
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instrumentation and controls (I&C) technicians. mechanics, security personnel, supenrisors and plant management. The inspections evaluated the licensee's compliance with 10 CFR, technical specifications, license conditions and administrative procedures.
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1.1 Operational Overview i
Unit 1 operated at full power throughout the inspection period, except for mmor power
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t reductions during surveillance testing. On the last day of the report period Unit 1 power was
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reduced to approximately 35% to secure the 1 A and IB recirculation pump motor generator
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sets, one at a time, for generator brush replacements. This evolution was completed and the unit was returned to full power without incident (Section 1.7).
Unit 2 returned to power following the refueling outage at the beginning of the report period.
Unit startup began on the weekend of March 13,1993, during a severe snow storm (Section 1.6). The storm turned out to be a positive event since most of the plant staff were j
stranded on site and available for the Unit 2 startup. The unit remained at full power until
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March 26,1993, when the reactor scrammed, due to a problem with the electrohydraulic control (EHC) system (Section 1.2). The unit was subsequently returned to power on March
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28, and remained at full power except for a recirculation pump runback on April 7,1993
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(Section 1.4).
f 1.2 Reportable Events
Unit 1
Inadvertent ESF Actuation
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On April 5,1993, while the unit was at 100% power, an inadvertent division 1 (A channel).
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refuel floor high radiation signal was generated causing a partial group VI C isolation, an
.i engineered safety feature (ESF) actuation. While performing a surveillance test on the
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division 3 (C channel) refuel floor high radiation channel, the I&C technician performed the
required manipulations on the division 1, vice the division 3, channel. The generated signal i
caused three H/0 sample valves to close; no other isolations occurred, because only a-
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division I signal was generated. The isolation was reset and all systems were returned to a normal status within 16 minutes.
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'The NRC Inspection Procedures used as guidance are listed parenthetically throughout this report.
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During performance of the surveillance, the technician, performing the work in the field, was training another technician. The crew was to perform both the A and C channel tests that
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day; normally the A channel test is performed first. The field technician believed that the A channel test would be performed first, and started to explain the procedure to the technician
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in training. The technician in the control room called the field technician and indicated that i
the C channel would be tested first, due to a required breaker manipulation. The field technician understood that the C channel would be tested first; however, he inadvertently manipulated the A channel switch first, as he originally intended.
Plant management determitted that the cause of the event was personnel error. This was compounded by inadequate communications and self checking. Corrective actions included counseling of the technician regarding the importance of self-checking and good communications. Additicnally, supervision was asked to provide instructions or guidelines on proper and acceptable methods for performing technician training in the field.
The inspectors reviewed the event and discussed the causes and corrective actions with plant
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personnel. The event had only minor safety significance since there was little effect on plant systems and plant operations. The corrective actions were assessed as adequate by the inspectors to preclude recurrence. The inspectors had no further concerns.
Unit 2
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Inadvertent ESF Actuation On April 8,1993, with the unit operating at 100% power, a licensed operator inserted a manual reactor enclosure HVAC isolation, by procedure, as part of a clearance for a maintenance activity. The result of the manual isolation was a primary containment instrument gas isolation, an ESF actuation. The isolation was immediately reset, and the systems affected were appropriately realigned. Although the reactor enclosure HVAC isolation was intentional, the original intent of the clearance was to avoid the primary containment instrument gas isolation. Performance of a different section of the procedure for isolation of the reactor enclosure HVAC would have prevented the primary containment instrument gas isolation. Although the operator performing the operation was aware of the resultant plant response, management present in the control room at that time were not aware, nor did they expect,the instrument gas isolation. As a result of this, control room
personnel reported this ESF actuation to the NRC as a four hour reportable event, in that it was an unplarmed ESF actuation. After further review, plant management concluded that the actuation was preplanned, and was therefore not reportable to the NRC, since the control
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room operator knew of the actuation prior to initiation. At the conclusion of the inspection period, plant management planned to rescind the four hour notification, and not initiate an LER. The inspectors questioned the appropriateness of rescinding the LER. This item will remain open pending the licensee and NRC review of the basis for rescinding the LER (50-353/93-07-02).
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3 The inspectors reviewed the event, the results of the plant investigation, and had discussions with plant management. The inspectors were concerned that not all personnel in the control room were aware that the actuation was about to occur. For preplanned evolutions it is normally expected that all personnel in the control room will be aware of the expected plant
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response to any actions taken by operations personnel, especially if an ESF is going to be challenged. This will provide for alternate methods to be discussed, and the possibility for the ESF challenge to be avoided. For the event on April 8, an alternate method existed, which would have avoided the ESF actuation. Plant management indicated agreement that unnecessary ESF challenges should be avoided, and that this event will be reviewed further for possible programmatic improvements.
The inspectors concluded that overall response to the event was good. The isolation was immediately reset, and the appropriate systems were properly realigned. Safety significance in this instance was low since at least one operator in the control room was aware of the
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actuation prior to its initiation, and subsequent actions had little effect on overall plant operations. The inspectors had no further concerns.
I Scram from 100% Power On March 26,1993, during the performance of a main turbine stop valve (MSV) and l
combined intermediate valve (CIV) exercise test, a reactor scram occurred as a result of an
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inadvertent closure of the Unit 2 MSVs. The unit was operating at 100% power at the time of the event. The unit scram was immediately followed by a turbine trip resulting from the
closure of the MSVs, as well as the intermediate stop valves (ISVs). Both the 2A and 2B reactor recirculation pumps received trip signals from the redundant reactivity control system
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(RRCS) on reactor pressure high, which was expected following the closure of all MSVs. At j
the onset of the event Unit 2 operators implemented trip procedures, (T)-101, Reactor Pressure Vessel (RPV) Control and T-99, Post Scram Restoration, and conducted a
controlled orderly shutdown. General plant procedure (GP)-3, Normal Plant Shutdown, was
performed to continue with the normal shutdown activities. Good coordination by the
operators limited the cooldown rate during the shutdown to a maximum of 49*F per hour l
(the technical specification maximum cooldown rate is 100"F per hour.) This coordination was noteworthy since minimal decay heat was present in the reactor core, following the
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unit's return to power on March 13, 1993, after the refueling outage.
i The high pressure coolant injection (HPCI) system, and the reactor core isolation cooling (RCIC) systems received spurious initiation signals due to momentary spiking of reactor
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vessel level instrumentation to bdow the initiation setpoint of -38 inches. The level spiking I
was a direct result of the closure of the MSVs from full power. Although both HPCI and
RCIC systems received initiation signals, the spurious signals did not exist long enough to cause either system to fully initiate and automatically inject into the reactor _ vessel. This level signal spiking or " ringing" was a previously identified phenomena at Limerick and other BWR plants. The reactor water level signal oscillations experienced during this trip l
were expected based on previous testing on both Unit I and 2. Redundant level indications l
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HPCI and/or RCIC, these systems could be secured based on correct redundant level indication. The duration of the " ringing" during this event was less than one second.
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and CIV Valve Exercise Test, was being performed. The purpose of the test is to
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demonstrate operability of the MSVs and CIVs. The test demonstrates that both the normal and fast acting closure devices operate properly. Just prior to the reactor scram the Unit 2 reactor operator performed the first part of step 6.5.3.4 of the ST, which requires him to (
release ISV-IV No. 6 test pushbutton and then verify ISV-6 opens. The operator had previously cycled the (4) MSVs and the other (5) ISVs as part of this test. Approximately
twenty seconds later all (4) MSVs closed, initiating a reactor scram. The scram was
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followed by a main turbine trip in response to the MSV closures and the additional closure of
all the main turbine ISVs.
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PECo's investigation concluded that the MSVs and the ISVs, which are supplied emergency trip system (ETS) control oil from the electrohydraulic control (EHC) system, experienced a i
collapse in control oil pressure as a result of air or nitrogen entrapment in the ETS fluid.
l The ETS fluid controls the disk dump valves on the control packs of the MSVs and ISVs.
PECo concluded that the air or nitrogen may have gotten into the fluid system by two j
possible methods: 1) normal air in-leakage due to an extended EHC system shutdown, and
2) from one of six system nitrogen accumulators, which was found depressured following the
turbine trip. The inspectors' discussions with various plant personnel indicated that the C
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accumulator (found depressurized) had been reworked during the recent Unit 2 refueling outage for similar depressurization problems. In addition, during the Unit 2 outage, isolation valves on the control packs of four ISVs (ISVs I,3,4, & 6) were found defective and were
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replaced with the new valve design type recommended in General Electric (GE) Turbine
Information Letter (TIL) 894, " Servo Valve Isolation Package." Industry experience following the issuance of GE TIL 894 has shown that the recommended replacement valve
tends to trap air that may become entrained in the EHC system. These new replacement isolation valves are currently installed in the Unit 2 system only.
Plant management concluded that air or nitrogen remained trapped in the newly installed isolation valve on the ISV No. 6, following the main turbine startup. During the surveillance testing on March 26,1993, the ETS system pressure collapsed with the stroking ofISV
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No. 6. This pressure perturbation was severe enough to actuate the disk dump valves on the MSVs and the ISVs, and cause the reactor scram. Prior to unit startup on March 28,1993, the C EHC accumulator was isolated and orifices were installed in the fast acting solenoid ports on ISV Nos.1, 3,4 and 6, as recommended by GE to mitigate the effects of air entrapment. Stroking of the main turbine valves during the subsequent turbine startup indicated no further EHC/ETS system perturbations.
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As previously stated, the HPCI and RCIC systems received a spurious initiation signal;
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however, due to the short duration of the signal only the HPCI system started. The HPCI turbine cycled (increased speed, then ran back in speed) five times on overspeed before the operator took manual control of the system. While the HPCI turbine cycled five times during this event it was within the first minute of the scram and turbine trip. The injection salve did not open during this event because the inidation signal was not present long enough. It should be noted that the actual reactor water level never dropped below +12 inches during the scram. The inspectors concluded that the operator's response to the HPCI initiation was timely, considering all the activities involved with the scram and turbine trip recovery.
With the HPCI system in the standby mode and the turbine at rest, the flow controller senses no flow and, thus, produces a maximum output signal calling for rated speed. Upon HPCI system initiation, a ramp generator function is initiated by the mechanical movement of the
turbine stop valve. The flow controller output ca'Is for maximum turbine rated speed,
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limited by the ramp generator, until such time the pump flow is established and reaches the setpoint of the flow controller. From this condition, the flow controller will regulate HPCI turbine speea to maintain the desired system flowrate. Since the injection valve did not open during this event, the flow signal was not present and the flow controller output continued to call for maximum turbine rated speed. When turbine speed reached 4150 rpm (125% of -
rated speed) the overspeed governor ran the turbine back to 3000 rpm. This protcctive function automatically resets and the turbine begins to accelerate to maximum rated speed.
This system response will continue until the operators take manual control of the system.
The reactor level instrumentation spiking folic > wing a main turbine trip, which resulted in the abnormal system configuration for HPCI, continues to be reviewed and evaluated by PECo.
This issue will remain unresolved pending the final analysis and resolution of the issue. (50-353/93-07-01)
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A review of the " Sequence of Events log" and the Process Monitoring System (PMS) plots identified three additional anomalies. First division 2 RRCS actuated on the sensed high reactor pressure while division 1 RRCS (re6undant reactivity control system) failed to actuate. PECo's investigation identified that the channel 1 B pressure instrument never saw
> 1093 psig reactor pressure due to a faulty Rosemount pressure transmitter. The
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transmitter was replaced prior to the unit's return to power. The pressure signal output of the transmitter indicated both an electronics problem and some leaking fill oil characteristic
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indications. PECo plans to send the transraitter back to Rosemount for the failure analysis.
Although the results of Rosemount's analysis are pending, plant personnel were trending and tracked the instrument's response as specified on their response to NRC Bulletin No. 90-01, and had noted some minor deterioration with the instrument's response over the previous few calibrations. The noted deterioration was below the established action level. The second anomaly was the fact that the A reactor feed pump mini-flow valve could not be controlled from the control room during the plant shutdown. This problem was traced to the local mini-flow controller and a signal processor was replaced, which corrected the problem. The
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final anomaly, which was identified by the control room operators was that the control rod
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drive (CRD) flow controller did not respond correctly with one or two CRD pumps in service per T-240, Maximizing CRD Flow After Shutdown During Emergency Conditions.
The controller output would drift when in " manual" and would oscillate in the " automatic" mode of operation. The flow controller was subsequently replaced following troubleshooting activities. The inspectors plan to review the results of Rosemount's failure analysis.
In general, the inspectors found PECo's investigation following the event to be thorough with
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many noted problems immediately resolved. The inspectors will continue to review PECo's efforts to resolve the reactor water level " ringing" issue.
The NRC received reports of the above events via the Emergency Notification System (ENS). The inspectors determined that the licensee's initial response and corrective actions were appropriate. The root cause analysis and the need for additional /long-term corrective
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action will be reviewed upon issuance of the Licensee Event Reports as part of the routine l
mspection program.
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1.3 Main Turbine Runback On March 17,1993, during the startup from the refueling outage, Unit 2 experienced a
turbine runback and subsequent trip due to a loss of stator coolant to the main generator
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bushing. This turbine trip function, which had been defeated in the past, was reactivated
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during the outage. The plant was at approximately 25% power, so no reactor scram was received or expected. Investigation by plant personnel identified two causes that contributed
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to the event. First, the turbine trip function was reactivated during the refueling outage and i
a low flow condition existed due to a mispositioned valve on the return line from the bushing; the valve was not throttled to allow proper pressure buildup in the return line.
Second, the trip occurred when the generator amperage went above the no coolant flow limit setpoint of 7469 amps. Corrective actions included disabling the loss of stator coolant
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turbine trip function, and throttling the valve on the return line from the bushing. Additional long term corrective actions are being evaluated.
The inspectors reviewed the event, and discussed its causes and the corrective actions taken i
with the system manager, and concluded that the actions taken were appropriate. Although l
the system is not safety-related, it has the potential for causing an unnecessary plant l
transient. Actions taken were adequate to ensure that an unnecessary plant transient does not
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1.4 Recirculation Pump Runback
On April 7,1993, Unit 2 experienced a reactor recirculation pump runback, initiated due to a spurious low level signal spike ofless than +12.5 inches on narrow range (NR) channel A.
This channel was the selected level input to the feedwater level control system at the time of the event. Both the 2A and 2B recirculation pumps ranback to 28% speed. The NR channel
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A signal also provided an input to the master level controller, initiating a level setpoint setdown, which ran back the reactor feed pumps to prevent overfeeding the reactor vessel.
The reactor operator took manual control of the reactor feed pumps and restored level to normal (+35 inches) from a low level of +19 inches. The operators immediately initiated operational transient procedure (OT)-100, Reactor Iew level, and GP-5, Power Operations, i
and performed the applicable steps. The chief operator inserted control rods and power was
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stabilized at 40%. The control rods were inserted to preclude power oscillations caused by
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thermal-hydraulic instability in the reactor core. Good response by the operating crew returned the plant to a safe stable condition as soon as possible.
An investigation of the signal spike was initiated by the system manager and I&C personnel.
With the exception of the initiating signal spike, all other system response was normal including, the recirculation pumps receiving a 62% speed runback initiation signal due to the individual feedwater flow signals going less than 20% with reactor level less than +27.5 inches. The actual cause of the spike could not be identified, although, operations personnel
noticed that at the time of the event the channel A NR/ upset range level recorder indication
" straight lined" (recorder output did not change), and remained that way until the recorder power was cycled on and off. This level recorder was one of the new digital recorders replaced during the recent Unit 2 refueling outage (Section 3.1). PECo contacted the manufacturer of the recorders to inquire about any known problems that could feed back from the recorder and cause an indicated level spike. The manufacturer did not know of any
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problems like that, but suggested replacement of an analog-to-digital card to correct the
" straight line" problem with the recorder.
As a corrective action, NR channel B was selected as the controlling level signal to the feedwater level control system. As a followup to the event the system power supplies were verified to be functioning correctly and common equipment to the power supplies were checked for similar transients; none were found. The analog-to-digital card was replaced, and along with the recorder traces from the event, were sent to the manufacturer for analysis. A recorder was set up to monitor the output of NR channel A and no other spikes were seen through the end of the inspection period. The system manager indicated that he will recommend to plant management that the level control be returned back to channel A.
The inspectors concluded that PECo properly reviewed and evaluated this event and initiated appropriate corrective actions. The inspectors will continue to review followup actions conceming this event.
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1.5 120 VAC Voltage Verification i
During a review of surveillances, on March 23,1993, plant personnel identified an apparent missed technical specification required surveillance. Technical Specifications 4.8.3.1 and 4.8.3.2 require that power distribution system divisions shall be determined energized at least once per 7 days. A 120 VAC distribution panel was not checked for voltage during performance of the surveillance on March 17,1993, due to a clearance on the panel, for i
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maintenance on dampers, which are powered by the panel. When the panel was restored, on March 19,1993, the appropriate surveillance test procedure step was not performed to verify l
voltage on the panel. After further investigation, plant management concluded that the
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surveillance test requirement was pmperly met during post-maintenance testing of the dampers, which is allowed by the surveillance test procedure as a means of verifying voltage j
on the panel.
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The inspectors reviewed the technical specification requirements, the post-maintenance test records, and concluded that the surveillance requirement was properly met. Additionally, the
inspectors verified that the surveillance was performed within the time allowed by technical
specifications. The surveillance had been last performed on March 10, so the surveillance was completed within the allowed time limit.
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1.6 Severe Weather Actions
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PECo took several positive actions in anticipation of seve-re weather expected and received on March 13,1993. The plant manager held a meeting Friday morning, March 12, 1993, j
which was attended by the inspectors, with plant management, to develop plans and
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I contingencies.
All groups evaluated staffing needs for the weekend and developed plans to keep necessary i
people on-site if weather conditions warranted. Food was brought in and sleeping arrangements were made, including the purchase of air mattresses for any of the staff who
were required to stay over Saturday night. Operations personnel reviewed special event j
procedure, (SE)-9, High Winds, and SE-14, Heavy Snowfall. The outside plant areas and l
the substat'ons were searched for loose material and debris that could go airborne with high
winds. Snow renoval arrangements for the site were ensured.
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In addition, on March 12, 1993, the chief security coordinator with the security shift
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coordinator and guard force operations lieutenant held a meeting to preplan snowstorm
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security contingencies. Issues discussed at the meeting included: asking for the security force to volunteer to come in early on the shifts and stayover; asking for volunteers to work their days off; and arrangements were made with security force members for transportation l
of other security force members on the way into the plant. Also, extra vehicles were j
borrowed from maintenance and facilities to use as needed. The gas tanks were topped off, and food and other supplies were purchased for the security force.
The inspectors concluded that plant personnel were well-prepared for the storm and ample manpower was available for continued operation of Unit I and the startup of Unit 2.
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1.7 Power Decrease for Brush Replacement During this inspection period, plant personnel were monitoring the wear on the Unit 1 A recirculation pump motor-generator (M-G) set generator brushes. On April 17, plant power
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was reduced to hpproximately 35% for a planned brush replacement, due to excessive wear noted on the 1 A M-G set brushes. The brushes for both M-G sets were replaced.
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The inspectors reviewed the operator logs of the planned evolution and discussed the activities with control room personnel. The inspectors concluded that the overall control of the power decrease and associated activities was good and coincided well with the plan for the activities.
2.0 MAINTENANCE OBSERVATIONS (62703)
The inspector reviewed the following safety-related maintenance activities to verify that repairs were made in accordance with approved procedures and in compliance with NRC regulations and recognized codes and standards. The inspector also verified that the
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replacement parts and quality control used on the repairs were in compliance with PECo's Quality Assurance (QA) program.
2.1 Emergency Diesel Generator Maintenance
r During this inspection period, the inspectors observed portions of maintenance activities on the emergency diesel generators (EDG). On April 6 & 7, the D13 EDG was removed from service for emergency service water piping replacement. The piping was found somewhat corroded, though less than originally suspected, so replacement was appropriate before the piping wall thickness became a concern. A short section of piping was replaced before the EDG was returned to service; no significant difficulties were experienced during the work.
On April 12-14, the D21 EDG was removed from service for various planned maintenance.
Among the activities, was an inspection of the check valves between the compressors and the air start receivers.
For both of the maintenance activities, the inspectors observed portions of the work and
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discussed the activities with maintenance personnel. The inspectors observed that the workers used and adhered to approved procedures, and that they were knowledgeable of the ongoing activities. Supervision was also noted present and involved in the work activities.
The inspectors found the two maintenance activities to be well-controlled and performed.
2.2 Emergency Diesel Generator Prelube Pump Start Failures l
On April 14,1993, during post-maintenance testing of the D21 EDG, operators observed that j
the prelube pump failed to start when a manual test start signal was initiated. When a test start signal is initiated for the EDG, the prelube pump starts first, followed three minutes
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.10 later by the diesel engine start. The test start circuit for the EDG and the associated start of,
the prelube pump are not required for EDG operability since the EDG is required to start immediately from a cold condition during an emergency. The prelube pump failed to start twice and started on the third attempt. Initial investigation could not identify the cause for the failure of the prelube pump; though it was suspected that the " local / remote" key-operated -
switch may have been the cause, by being slightly misaligned. Prior to the successful start
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on the third attempt the switch was cycled.
During surveillance testing for the Dll EDG, on April 15, 1993, its prelube pump failed to start. Plant personnel suspected that the " local / remote" switch was at fault, so they cycled that first. Subsequently, the prelube pump and EDG started successfully. Investigation revealed that recently operators had removed the keys from the switches to be consistent in the control of these keys, since some switches had the keys installed, and some had the keys removed. In the " remote" position, the normal operating position, the key should not be able to be removed. Apparently, to remove the keys, the operators had to move the switch slightly. Though this had no affect on the operability of the EDGs, since they would have started during an emergency condition, it did have an effect on the prelube pump. As corrective action, operators replaced all of the keys in the switches, with a tag as an operator i
aid, indicating that the keys need to remain in the switches. Additional investigation was ongoing at the end of the inspection period to verify that the switches were the cause of the
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prelube pump start failures.
The inspectors reviewed the EDG operability with operations personnel to ensure that the EDGs were operable with the prelube pump circuitry inoperable, and concluded that the EDGs were operable as indicated. Additionally, the inspectors verified that the keys should
be in the switches, by verifying that the keys cannot normally be removed from the switches with the switch in the " remote" position. The corrective actions taken were found to be adequate.
3.0 ENGINEERING AND TECIINICAL SUPPORT (37700)
3.1 Review of Modification 6156-2 Replacement of Bailey 730 Series Recorders The entire line of Bailey 730 recorders, for both units, are being replaced by a similar recorder, Westronic Series 2100. Bailey 730 recorders are no longer manufactured, nor are l
spare parts available to implement repairs for recorder failures. A total of 56 recorders are being replaced, 26 for Unit 1, 24 for Unit 2 and 6 common plant applications.
The inspectors reviewed and witnessed the installation of a select number of the recorders in Unit 2 during the past outage, then reviewed the final package to ascertain if the recorders meet all of the standards that were in place with the Bailey 730 series. Six of the newly installed are safety-related. (Fuel zone reactor level LR-42-1/2R615, steam jet air ejector off
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11 gas discharge radiation RR-26-1/2R601, RHR heat exchanger radiation RR-12-0R615 A&B
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and RR-12-0R616 A&B, source range monitor XRX-M1-1/2R602 A&B, and intermediate range monitor XRX-M1-1/2R603, A, B, C and D.) The inspector determined the following:
A 10 CFR 50.59 review determined that no unreviewed safety questions exist as a
result of the new recorders.
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Post Accident Monitoring, Regulatory Guide 1.97 was satisfied.
- Guidelines for IEEE standard 1023 and NU' REG 0700 for human factors were
considered.
The original power supplies were used to powc4 the new recorders.
- The recorders were seismically maunted where required.
- New procedures are in piace far calibration and the "as-left" conditions are on file for
future calibrations.
Operators and technicians havc attended training on the use and calibration of the new.
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Certificates of conformance were on record for the new recorders. The review of the
instruments by the QA department was performed in accordance with established procedures.
The remaining recorders for Unit 1 are scheduled to be installed at a latei date. The inspectors concluded that the installation of the new recorders was performed in compliance with established codes and standards as delineated above.
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3.2 Review of Modification 6147-2, Installation of a Cross Tie Between the RHR and Fire Protection Systems This modification installs a cross connection between the residual heat removal (RHR) and the fire protection systems to provide an alternate source of water to the drywell spray mode of RHR system operation. This cross connection would be used in the event of a " severe, beyond design basis" accident in which all low pressure emergency core cooling systems (ECCS) fail. At such a time, the cross connection will be made via a 6 inch fire hose and ability to spray the drywell will be maintained. This modification comes about as a result of a commitment made to the Limerick Ecology Action (LEA) group during the licensing of Unit 2. The modification will also be an alternate source of water that can be injected through the low pressure coolant injection (LPCI) line.
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i The inspectors reviewed the initial Project Plan and the 10 CFR 50.59 safety evaluation for -
this modification. The inspectors verified that the modification was reviewed and approved by the on-site review organization and that it was in accordance with established QA program controls. Various portions of the installation were witnessed by the inspectors during the
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Unit 2 refueling outage. Some problems were experienced during the welding of the
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connection on the RHR header. The modification called for the use of a " weld-o-let" for this connection that was completed and radiographed on February 2,1993. The radiograph indicated porosity problems and the weld was rejected. Subsequent rewelds and radiography-
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inspections were completed satisfactorily.
Following the completion of the installation the inspector reviewed the final modification package. Tne documentation was well organized, complete and in accordance with approved
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procedures. As a close out of the modification process the inspectors reviewed the following areas:
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All applicable piping and instrumentation diagrams (P& ids) and isometric drawings
have been updated.
SE-10, LOCA and T-225, Startup and Shutdown of Suppression Pool and Drywell
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Spray Operation, were both revised to include operation of the RHR to fire water cross-connection.
Shift night orders documented when the modification was in effect and a shift training
bulletin was initiated as a read and sign for all oncoming crews.
Licensed operator and non-licensed operator (NLO) read and reviews were developed
as a part of continuing operator training. NLO task review training was developed as
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a part of cycle 2 training that will take the NLOs into the plant and review the revised T-225 procedure.
The new valves added per this modification were properly labeled including the use of
purple tags indicating the valves are a part of an emergency contingency procedure (T-225).
The 6 inch fire hose is in place and stored adjacent to the pipe connections.
- This modification was well-planned and implemented in accordance with applicable codes and standards. The inspectors had no further questions regarding this modification.
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4.0 RADIOLOGICAL PROTECTION (71707)
During the report period, the inspectors examined work in progress in both units including
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HP procedures and controls, ALARA implementation, dosimetry and badging, protecdve clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys,
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radiation protection instrument use, and handling of potentially contaminated equipment and materials.
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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
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observed as meeting the applicable requirements. The activities observed by the inspectors
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were acceptable.
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After the startup of Unit 2, in March 1993, the levels of radioactive noble gases in the
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buildings were higher than normal, due to some minor leaks in plant system piping combined
with the higher than normal radioactivity in plant systems caused by the reactor fuel failure
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experienced prior to the last plant snutdown. Minor leaks in plant system piping are not l
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unusual, but the radioactivity in the systems is higher than would normally occur. Plant personnel immediately recognized the higher than normal levels of radioactive noble gases, due to the increase in the number of alarms experienced by personnel using the personnel
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contamination monitors (PCM), on the Unit 2 side of the turbine building. Plant
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management has concluded, based on flux tilt testing, that the levels of radioactive noble gases are due to the prior reactor fuel failure and that Unit 2 has not experienced any new fuel failures.
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Corrective actions taken thus far have been quick and comprehensive. All detected leaks have been repaired if possible, and those not readily repairable have been identified and
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marked. Some of these areas have had enclosures erected around them with exhaust fans to i
remove the noble gases from these areas. Work planning for work which breaches Unit 2 systems, which see reactor coolant, will consider alpha contamination for respiratory
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protection, especially those activities that require welding, burning or grinding. The plant
work force has been made aware of the situation through articles in the Possum Hollow Press, Plant FYIs, and group meetings. The information put out through these means is
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intended to educate personnel about the problem, and to let them know their responsibilities
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concerning exiting areas of the plant when they alarm the PCM. Higher than normal levels of radioactive noble gases are expected to continue for at least the next few years.
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The inspectors reviewed the acdons taken so far, and concluded that they have been
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responsive and comprehensive. Awareness of the situation has increased, and plant
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personnel are appropriately dealing with any inconveniences and delays caused by alarming the PCMs.
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5.0 SAFETY ASSESSMENT / QUALITY VERIFICATION (71707)
5.1 PECo's Reorganization On March 30,1993, members of PECo's corporate and plant staff met with NRC Region I
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management and staff. The purpose of the meeting was to provide an opportunity for PECo to present their new management teams at the Limerick and Peach Bottom plants, and the Nuclear Headquarters at Chesterbrook. The meeting was held in the NRC Region I Office, King of Prussia, Pennsylvania.
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During the meeting PECo's Senior Vice President-Nuclear stated that the initial selections by the Nuclear Group Senior Management had been completed, pursuant to the Nuclear Effectiveness and Efficiency Design Study (NEEDS) recommendations. This completed the staffing of the new organization through the management and Professional Supervisory i
Managerial (PSM) ranks. PSM employees will be transitioned to their new posts over the next several months with implementation of the new organization scheduled to be completed by September 30,1993. At the time of the meeting no planned lay-offs of non-professional employees were anticipated.
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After the initial opening remarks by PECo's Senior Vice President, each member of PECo's staffintroduced themselves to the NRC staff. Each spoke briefly about their background and
'i their new position in the PECo organization. The handouts from the meeting are included in this report as Attachment A.
5.2 Changes to Morning Meeting Agenda During the week of April 12, 1993, the plant manager instituted a formal agenda for the i
daily 8:30 a.m., management meeting. The agenda and format of the meeting were pattemed after an initiative begun at Peach Bottom. It includes the mandatory attendance of department heads, or their representatives, the use of name plates on the conference table,
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and a pre-selected list of special topics for each day. The special topics or presentations are presented by each department on a given day, Monday through Friday. They are meant to be brief but informative and cover any current or emerging issues at the site.
The inspectors attend these meetings and found that there has been a good exchange of informatien between the managers. The inspectors did note that the initial meetings tended to be a little lengthy (approximately an hour), but as the agenda and format became more familiar to the staff the meetings became more efficient. This new meeting format will provide an opportunity for team building for site management. The inspectors will continue to attend these meetings and review the efforts of the plant management st ff.
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i 6.0 REVIEW OF LICENSEE EVENT REPORTS (LERs), ROUTINE AND
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SPECIAL REPORTS (90712,90713)
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6.1 Licensee Event Reports (LERs)
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LER 2-93-003. Event Date: February 13. 1993. Report Date: March 11.1993 Engineered Safety Feature Actuations resulting from a Spurious Division 2 less of Coolant
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Accident Signal due to personnel error.
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This event was reviewed and documented in Combined Inspection Report Nos. 50-352/93-03
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and 50-353/93-03, Section 1.2, Reportable Events.
LER 2-93-004. Event Date: March 3.1993. Report Date: March 30.1993 Inadvertent Emergency Diesel Generator start as a result of personnel error from misunderstood verbal communications during performance of a procedure.
See Section 7.0 of this report, since this LER provided information that closed NRC unresolved item 50-353/93-03-01 concerning this event.
The inspectors found that the LERs listed above met the requirements of 10 CFR 50.73 and
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had no funher questions regarding these events.
6.2 Routine Reports Routine reports submitted by PECo were reviewed to verify the reported information. The following reports were reviewed and satisfied the requirements for which they were reported:
Monthly Operating Reports for February 1993, dated March 10,1993 and March 1993, dated April 13, 1993 7.0 FOLLOWUP OF PREVIOUS INSPECTION FINDINGS (92701,92702)
(Closed) Violations (50-352 and 50-353/91-81-02; 91-81-03). The violations involved the failure to take measures to assure that conditions adverse to quality are promptly identified and corrected, with two examples: 1) Procedure PMQ-020-010, Section 7.21.7, requires acceptance criteria for the emergency diesel engine fuel injector timing not to exceed (+/-)
1/2 degrees between control side and opposite control side. The data was recorded but not identified as being beyond the acceptance criteria and no corrective action was taken; and 2)
Procedure PMQ-020-010, Section 7.13.8, requires acceptance criteria for crankcase strain measurements of.0015 inches maximum. The data recorded (.0025 inches) was outside the acceptance criteria and no corrective action was take.
Nonconformance report L91192 was initiated with a conclusion that, according to the manufacturer of the engine, the "as-left" setting was within the acceptance range for an interim period of performance. On February 24,1992, during the overhaul of the diesel, the correct settings were incorporated. The procedure was revised to reflect the manufacturer's recommendations of a tolerance setting of (+/-) I degree.
Nonconformance report L91191 was initiated with a conclusion that the analysis of the.0025-inches, which was the recorded reading, was within the acceptance criteria recommended by the engine manufacturer. The procedure has been corrected to reflect this.
Additionally, Quality Assurance procedure NQA-4-S11, " Management Oversight of the i
Quality Control Program," was developed to define the methodology and responsibilities to be used in the performance of management oversight of the QC program. NQA-4-56,
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" Maintenance Planning and Review," was revised to emphasize the need for attention to detail. The QA/QC department personnel have been trained on the new procedures.
Training was also conducted with maintenance and I&C personnel for attention to detail
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adherence during the performance of work activities.
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(Closed) Unresolved Item (50-353/93-03-01). Concerning the Division 2 EDG, D22, automatically starting in response to the sensed low bus voltage.
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On March 3,1993 the D22 EDG automatically staned during performance of the Diesel Generator 4KV Safeguard Loss of Power Logic System Functional Test and Outage Testing 18 Month Surveillance Test. An unresolved item was initiated because at the time of the
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report (50-353/93-03) PECo had not completed their investigation of the event. The initial investigation indicated that steps in the surveillance test were not followed correctly. The issue of why procedural steps were performed out of sequence remained unresolved pending completion of the review of the actual event.
PECo has since completed their investigation and issued Licensee Event Report (LER) 2-93-j 004, on March 30,1993. The cause of this event was personnel error during performance of an ST procedure in that verbal communications were misunderstood by the test director. The misunderstood verbal communications and the belief that the 101/D22 feeder breaker had been tripped led the test director to conclude that certain procedure steps had been performed when, in fact, they had not yet been completed. The performance of a procedure step out of sequence caused the D22 EDG to start prematurely.
l As a result of this error the test director was counseled regarding this event and on the importance of proper communication techniques during work activities. A PECo voice mail message was issued to all technical section supervision on March 3,1993, to provide immediate notification of the event and its cause, and to reinforce plant management's expectations for proper communication during work activities. This event was communicated
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to all technical section personnel by memorandum on March 17,1993, to reinforce management's expectation regarding procedure use and proper communication techniques.
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l The inspectors had no further questions regarding this event and the unresolved item is closed.
8.0 MANAGEMENT MEETINGS L
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8.1 Exit Interviews
The inspectors discussed the issues in this report with PECo representatives throughout the l
inspection period, and summarized the findings at an exit meeting with the acting Plant Manager, Mr. R. Boyce, on April 19, 1993. No written inspection material was provided to licensee representatives during the inspection period.
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8.2 Enforcement Conference On March 16, 1993, an enforcement conference was held at the NRC Region I Office to
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discuss the apparent violations associated with the Radiation Protection Program. The results of this conference were sent to PECo in a separate correspondence dated April 9,1993, which included the Enforcement Conference Report and the results of a supplemental inspection conducted on March 17, 1993.
8.3 Reorganization Meeting On March 30,1993, PECo's management staff met with NRC staffin the NRC Region I Office, to discuss recent changes in the PECo management organization (Section 5.1).
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ATTACHMENT A PHILADELPHIA ELECTRIC COMPANY NUCLEAR GROUP
.t Senior Vice President
- Nuclear Vice President Vice President Vice President Nuc r Quality Nu ar Peach Bottom Limerick Station Support.
Review Board Assurance orgng2 j
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LIMERICK GENERATING STATION I'
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STATION SUPPORT ORGANIZATION
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Vice President Station Support Director, Joint Owners Affairs Director
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NUCLEAR QUALITY ASSURANCE i:
Director Nuclear Quality Assurance
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