IR 05000352/1992029
| ML20128C459 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 01/27/1993 |
| From: | Anderson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20128C456 | List: |
| References | |
| 50-352-92-29, 50-353-92-29, NUDOCS 9302040027 | |
| Download: ML20128C459 (77) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
- Report Nos.
92-29
! '-29 Docket Nos.
50-352 50-353 License Nos.
NPF-39 NPF-85 Licensee:
Philadelphia Electric Company Correspondence Control Desk P.O. Box 195 ~
Wayne, Pa 19087-0195 Facility Name:
Limerick Generating Station, Units 1 and 2 Inspection Period:
November 15,1992 - January 2,1993 Inspectors:
T. J. Kenny, Senior Resident inspector T. A. Easlick, Resident inspecto'
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Approved by:
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//h 7/C73 -
Date
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Clffford*J. Anderson,/Chf
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Reactor Projects Section N{o.1B 9302040027 930127-PDR ADOCK 05000352-G PDRj
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EXECUTIVE SUMMARY Limerick Generating Station Report No. 92-29 & 92 29 Plant Operations Unit 1 operated at or near 100 percent throughout this inspection period. - Unit 2 operated in a coast down mode (86-73 percent power) due to fuel burnup, with the exception of a reactor trip early in the inspection period. During the Unit 2 trip, good command and control was.
evident on the part of the shift crew throughout the event (Section 1.2). During this period PEco identified a fuel leak on Unit 2. PECo is continuously monitoring the offgas activity and other parameters to ensure technical specification requirements are not exceeded.
Surveillance and Maintenance Following the Unit 2 reactor trip, investigations and analysis of the event identined two-deficiencies: control rod 10-19 had a slower than normal scram insertion time and the 'A'
outboard Main Steam Isolation Valve (MSIV) failed to remain in the closed position. Both of these deficiencies required extensive investigation and root cause analysis by maintenance personnel to identify the problems and determine corrective actions. This work was.
completed and presented to the Plant Operation Review Committee (PORC) prior to returning Unit 2 to operation. The.MSIV failure and PECo's analysis of the improperly installed spring in the associated solenoid valve resulted in a non-cited violation in accordance with the Enforcement Policy,Section VII.B.2. (See Section 3.2 and 3.4 for additional details.) Failure of a 2A RHR motor lead resulted from the incorrect installation.
of connector lugs. As a result, PECo embarked on a systematic approach to performing -
thermographic checks of the motor leads on each of the remaining seven RHR pump motors.
A similar problem was identiDed on the 2B RHR pump motor, which required repairs to the L
motor leads. (Section 3.3)
Radiological Protection During this period, two managemer. meetings were conducted to discuss radiological control L
program enhancements and the status of leaking fuel identified on Unit 2. During the first meeting, PECo discussed the efforts underway to enhance their program relative to concerns and weaknesses identined following the NRC review of the July 1992 unplanned exposure of i
a worker. The second meeting provided an opportunity for PECo to provide a status of the fuel leak monitoring program at Unit 2. PECo informed the NRC that.there was at least'one and potentially two fuel pins with cladding failures. However, there have not been any signincant changes in the radiological environment encountered by workers. (Section 9.4 and 9.5)
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Safety Assessment and Ouality Verincation Section 5.0 discusses the increased outage time for the Residual Heat Removal (RHR)
System at Limerick Units I and 2. PECo calculations indicated that the overall effect of the RHR system unavailability was low relative to the Probabilistic Risk Assessment (PRA)
estimates of core damage frequency. Hewever, additional inspection will be performed to review the signincant amount of LCO maintenance activities observed by the inspectors at Limerick, ii
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TABLE OF CONTENTS EXECUTIVE SUMMARY i
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1.0 PLANT OPERATIONS (71707)...............................
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1.1 Operational Overview................................. 1 1.2 Reportable Events................................... I 1,3 Flant Operating Review Committee (PORC) Meetings............, 4
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1.4 ESF System Walkdown (71710)
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2.0 SURVEILLANCE /SPECIAL TEST OBSERVATIONS (61726)
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3.0 MAIN 1ENANCE OBSERVATIONS (62703)
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3.1 Control Rod 10-19 Slower than Expected Rod Insertion Time'........
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3.2 Rod Position Indication System Inoperable...............,.... 8
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3.3 Residual Heat Removal (RHR) Outages..............,...
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3.4 Main Steam isolation Valve Malfunction.....................
I1 4.0 RADIOLOGICAL PROTECTION (71707).......................
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SAFETY ASSESSMENT / QUALITY VERIFICATION................
6.0 REVIEW OF LICENSEE EVENT REPORTS (LERs), ROUTINE AND -
SPECIAL REPORTS (90712,92700)
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6.1 Licensee Event Reports (LERs)..........................
6.2 Routine and Special Reports............................
6.2.1 M onthly Report...............................
6.2.2 Special Report Dated December 18,1992 Emergency Diesel i
Generator (EDG) Test Failure......................
6.2.3 Special Report for the Inoperability of a Seismic Monitoring System Instrument for More Than 30 Days.............. - 19 7.0 COOLING TOWER FOAM PROBLEM FOLLOWUP................
8.0 FOLLOWUP OF PREVIOUS INSPECTION FINDINGS (92702).........
9.0 M AN AGEM ENT M EETINGS........................
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9.1 Exit Interviews.................................
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Additional NRC Inspections this Period.....................
9.3 Enforcement Con ference................................22 9.4 Radiological Controls Program Enhancements.................
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Status of Leaking Fuel............................... 23 9.6 Senior Vice President Briefing
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9.7 Management Meeting Regarding Maintenance Procedural Compliance
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DETAILS 1.0 PLANT OPERATIONS (71707)'
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 the inspections, discussions were held with operators, health physics (HP) and instrument and control (I&C) technicians, mechanics, security personnel, supervisors and plant management.
The inspections were conducted in accordance with NRC Inspection Procedure 71707 and evaluated the licensee's compliance with 10 CFR, Technical Specifications, License Conditions and Administrative Procedures.
1,1 Operational Overview At the start of this report period Unit I was operating at full power and continued to operate at full power for the remainder of the inspection period except for minor power reductions during surveillance testing.
Unit 2 was operating at 85.7 percent power in a coast down due to fuel burn up at the beginning of the period. Except for the reactor trip described below the unit continued la coast down. At the end of this report period the unit was at 73 percent reactor power. Also during this period PECo identified a fuelleak. The radiological activities as a result of the fuel leak have not exceeded any technical specification requirements. PECo is continuously monitoring the offgas activity and other parameters to ensure the limits are satisfied. PECo management asked for a meeting in Region I to inform regional management of the leak and their plans for the upcoming outage scheduled for January 22,1993. Section 9.5_ contains more information on the fuelleak.
j 1.2 Reportable Events Unit i Loss of Emergency _ Assessment Eouloment t
On December i1,1992, at 7:50 a.m., the following emergency assessment equipment was lost:
The meteorological tower data (needed to perform offsite dose calculations)
l approximately 50 percent of the sirens in the Public Prompt Notifications Systems-
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'The NRC Inspection Procedures used as guidance are listed parenthetically throughout this report.
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The cause of both of these failures was attributed to severe weather conditions causing the loss of electrical power. After the restoration of electrical power the meteorological tower and the sirens were returned to service.
Partial ESF Actuation On December 11,1992, at 11:03 a.m., PECo determined that an Automatic Depression System (ADS) Instrument Gas Pressure Control and Isolation Valve PCIV (HV-059151 A)
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may have had a spurious Nuclear Steam Supply Shutoff System (NSSSS) isolation signal.
The valve was discovered closed during system turnover by the Unit 1 Reactor Operator at 7:05 a.m. Prompt troubleshooting was performed by an I&C Technician. The effort concluded that'a pressure switch was believed to be out of calibration.
The pressure switch was recalebrated and functionally checked using procedure ST-2-059-602-1. The as found readings were at the lower end of the acceptable range. After the pressure switch settings were reset, valve HV 059 i51 A was declared operable based on the satisfactory testing of PDS-059-106A switch I and 2 and successful completion of the procedure.
Unit 2 Unit Trip From 77 Percent Power On December 4,1992, during the performance of a main turbine stop valve functional test, signals were generated which tripped the 2A and 2B reactor recirculation pumps. The unit was operating at 77 percent power at the time of the event. The reactor operator immediately placed the reactor mode switch in the " shutdown" position initiating a full reactor scram, in accordance with the Operational Transient Procedure, OT-112,.
Recirculation Pump Trip. The unit was placed in the cold shutdown condition with'all systems functioning as expected, expect for the following two deficiencies: control rod 1.0-19
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l had a slower than normal rod insertion time; and during the plant cool down the operators -
were unable to close and keep closed the "A" outboard Main Steam Isolation, Valve (MSIV)
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in accordance with procedure GP-3, Normal Plant Shutdown. These two issues' are discussed L
in detail in Section 3.0 of this report. The 2A reactor recirculation pump was restarted l
within one hour of the event in accordance with GP-3, Normal Plant Shutdown,.without L
problems, and the 2B recirculation pump remained secured to facilitate motor generator brush replacement.
L The inspector was in the control room within five minutes of the scram and observed the unit L
shutdown. At the onset of the event the Unit 2 operators implemented Emergency Operating -
Procedures, T-101, RPV control and T-99, Post Scram Restoration, and conducted a controlled orderly shutdown Good command and control was evident on the part of shift management throughout the event, including the removal of all unnecessary personnel from
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the Unit 2 control area on two occasions. The crew was also concerned about temperature
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3 stratification within the vessel, as a result of the loss of forced circulation, and ensured that the reactor. cochnt temperatures were strictly monitored for the restart of the recirculation pump. Technical Specification temperature limits were met prior to placing the 2A recirculation purnp in service. The remainder of the shutdown was conducted per GP-3 with no abnormalities noted. The reactor operator's immediate response to the dual recirculation pump trip is noteworthy, since OT-ll2 was recently revised (November 12,1992) to require-a manual scram if both recirculation pumps trip and the reactor is operating in natural circulation. Prior to this revision, the procedure allowed the plant to operate in nr.tural circulation, directing the operators to insert control rods as neccssary to avoid power oscillations caused by thermal-hydraulic instability in the core. The direction to manually scram the plant was adopted as a conservative measure, while awaiting additional guidance from the BWR Owners Group concerning power oscillations.
At the time of the event, ST-6-001-660-2, the Main Turbine Stop Valve Reactor Protection System (RPS) and End-of-Cycle Recirculation Pump Trip (EOC-RPT) Channel Functional Test was being performed. The purpose of the test is to prove the ability of the main turbine stop valve limit switches to provide the proper input to the RPS and EOC-RPT systems, and is designed to test both the 'A' and 'B' trip systems in the course of the functional test. This test requires coordination and communications between the reactor operator in the control room, an operator in the auxiliary equipment room, and an operator at the RPT breakers located in the reactor building. Prior to initiating the signal which tripped the recirculation pumps, the operators were performing a part of the functional test that involved testing the
'B' system trip logic of the EOC-RPT system (each recirculation pumps has an 'A' and 'B'
EOC-RPT breaker, with a loss of either breaker resulting in a pump trip). However, as noted by the control room operators and on the Sequence of Event Computer printout, the 2A and 2B recirculation pumps tripped five seconds apart as a result of an 'A' logic EOC-RPT signal. The 'A' EOC-RPT breaker tripped on each of the recirculation pumps. This was inconsistent with what was believed to be the current status of the testing, namely the
'B' logic EOC-RM' trip system.
PECo's review of the event included: 1) a comparison between the completed portions of the functional test and the Sequence Event Computer to verify that the test was completed correctly up to the point that it was signed off; 2) a walkdown of the functional test including a review of the alarms that resulted from each of the procedure steps, the time sequence of the events, and the electrical prints verses each procedure step; 3) a walkdown of the location of the operators during the test and their actions; 4) interviews with all the individuals involved in the test; and 5) review of the performance of the functional test in its entirety.
The results of this review indicated that the test was correctly completed by the operators up to the point that the procedure was signed off (Step 6.6.31). The review /walkdown of the test demonstrated that there were no deficiencies identified in the procedure, and that the operators were in the correct locations for the performance of the test. The functional test was successfully performed a second time with no problem, either with the equipment or the procedure itself.
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While the ext.ct cause of the trip signals cannot be determined, the most probable cause of the event was improper operator action. It is believed that the trip signal to the 'A' EOC-RIYr breakers was generated as a result of the operator in the auxiliary equipment room placing a digital volt mder across an open contract in the trip logic for each of the recirculation pumps, which provided a current path through the meter, simulating a closed condition on the contact. Continuity tests on these contacts are performed as part of the functional test only after the control power fuses are removed from the RPT breakers. PECo theorized that the operator in the auxiliary equipment room may have proceeded forward with the test prematurely, or that he may have been in the wrong logic cabinet (the test involves operations in both the 20C609 and the 20C611. panels, which are located side by side in the auxiliary equipment room). During the interview with the operator stationed in the auxiliary equipment room, he was asked about the proposed scenario, however, he could not confirm nor deny his presence in the wrong instrument cabinet during the test. A sequence of events for this shutdown is provided as Attachment A.
The NRC received reports of the above events via the Emergency Notification System (ENS). The inspectors determined that PECo's initial response and corrective actions were
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appropriate. The root cause analysis and the need for additional /long-term corrective action will be reviewed upon issuance of the Licensee Event Reports as part of the routine l_
inspection program.
l 1.3 Plant Operating Review Committee (PORC) Meetings The inspectors attended two "Op. Con. Change PORC Meetings" Op. Con. (Mode) is the operation condition of the reactor. For every Op. Con. change the PORC meets to insure l-that all prerequisites are satisfied prior to the change, or the entry into the next mode (e.g.,
L from mode 3 to mode 2).
The inspectors noted that a quorum was present at the meetings, the meetings were conducted in a professional manner. The inspectors also noted that unanswered questioe or l
areas for more information wem put on a follow-up list for future PORC meetings. One.
L example was the discussion of Main Steam Isolation Valves (MSIVs). Main Steam Isolation Valve HV 041-2F028A (2A outboard valve) had failed to stay closed after being closed from
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the control room after the December 4 plant trip. The PORC decided, with the inforrr.ation on MSIVs presented at the meeting, that the unit was ready for restart, however more information was needed to completely answer some remaining questions. A subsequent meeting did close the questions, however, there were substantial changes to the original input. The PORC chairman insured that the latest information on MSIVs was true and -
accurate and closed the open issues.
The inspector noted that the PORC chairman was concerned about information being in error at the previous meetings. He thoroughly questioned the parties making the presentation on the new information to insure himself that the current information was complete.
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As a result of the latest information, the PORC chairman' ordered that additional inspections
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1.4
- ESF System Walkdown (71710)-
I The inspectors verified the operability of Diesel Generator (DG) 2_2 by performing.a..
walkdown of the system. The inspector confirmed that the system lineup was in accordance.
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with the plant piping and instrumentation drawing (P&lD). The applicable updated fmal'
safety _ analysis (UFSAR) drawing for the DG was used.' Attention _was paid to equipment; and housekeeping conditions that may degrade system performance and to component support-structures. The housekeeping was found to be adequate and appropriate levels of cleanliness were found. Except as designated below, the system lineup and component identificationi tags corresponded to the P&lD and UFSAR drawings.
The items of concern, and PECo's corrective actions are:
Some check valves were not labeled in the Air Starting System - The check valve
configuration for the other seven DGs was examined. AdditicL1 check valves were also found untabeled. Maintenance geideline M-26 and Administration Procedure A-61, the procedures for labeling components, were used by PECo to apply new labels.
The exhaust silencer drain cover was open - The cover was returned to its closed-
position which is the correct position for the cover.
The Jacket Water Expansion Tank valve label numbers and valves were not delineated
on the P&ID, the valve numbers were incorrect and some valves were not shown on
the UFSAR drawing. ' Historically root valves and instrumentation and controls (I&C)
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are not shown on the P&lD. PECo is committed to, within the next three months, a
p update P&ID M-93 to include root valves and correct the errors.' A nonconformance
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j report was issued to correct the UFSAR drawing.
2.0 SURVEILLANCE /SPECIAL TEST OBSERVATIONS (61726) -
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' During this inspection period, the inspector reviewed an in-progress surveillance test and -
completed surveillance package. The inspector verified that surveillance was done according to PECo approved procedures and plant Technical Specification requirements. The inspector also verified that the instruments used were within calibration tolerance and that qualifiedc
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technicians did the surveillance.
The following surveillance test was observed and reviewed:
Work Order (WO) #R0477774, IC-ll-00340, Routine Calibration on FSL-077-205G
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The calibration on FSle077 205G, which is part of the start / trip logic for drywell unit cooler
fan 2GlV212, was performed to satisfy preventive maintenance requirements. The instrument calibration procedure used was IC-ll-00340.
The inspector verified that the intent of the procedure was met, however, a concern resulted while observing the calibration. Confusing word usage was found in the procedure. The note preceding step 5.1.7 contains the term, " flow calibration sheet," while step 5.1.10 contains the term, " flow calibration curve " When the inspector asked to see the curve, the foreman said that there wasn't a curve in terms of a graphical representation, but that the " calibration table" (which consists of columns of data) was the curve. Therefore, there are three terms that are used to denote the same item.
The inspector concluded that the calibration satisfied the requirements, The technician had stated that he had performed this calibration several times in the past. However, the use of three different terms to describe the same thing could be confusing to a novice. The methodology used to conclude that " flow calibration sheet," "How calibration curve," and
" calibration table," were the same item, could, when applied to the implementation of other procedures, lead to erroneous conclusions, which could result in incorrect actions, After discussions with PECo, the inspector was informed that the procedure will be temporarily modified and will be corrected at a later date in accordance with PECo's Administrative Procedure.
Based on discussions with the foreman and the technician while observing the calibration, the inspector concluded that the intent of the procedure was met. Aside from some minor
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concerns that the licensee will correct, an appropriate level of knowledge and equipment usage was observed. There was good communications between the control room and the instrument technician.
3.0 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 verined that the replacement parts and quality control utilized on the repairs were in compliance with PECo's Quality Assurance (QA) program.
The following maintenance activities were also observed:
Work Order (WO) #R0045146; Perform Visual Inspection and Tests per PMQ-500-063 -
(Preventative Maintenance Procedure for Operational Analysis of Motors P-20, P-206 P-506, P-548 for Maintenance Recommendation)
The inspector observed the work done on the residual heat removal pump motor drive. Prior to proceeding with the WO, the technician reviewed the procedure and explained the step. _
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s During the completion of the WO, the technician discovered that one of the screws could not be screwed in. This was promptly reported and the defective screw was replaced. The technician correctly assumed the responsibility for reporting the situation and stopping the work until the defective part was replaced. The maintenance and quality verification personnel demonstrated knowledge of their responsibilities and procedural requirements.
Appropriate acceptance criteria such as performer signoff and verifier signoff was observed.
The inspector observed work associated with WO #C0134048 conducted on the 2A control rod drive (CRD) pump turbine enclosure cooling water drain valve. The inspector observed-the valve technician examining the surface of the valve seat for deposits of foreign material and completing a check that verified full seating contact for the new bonnet assembly.'-
Installation of a new gasket and bonnet assembly was observed.
The inspector verified that tagouts were obtained prior to initiating the work and that radiological controls were properly implemented. Health Physics (HP) personnel did a swipe of the work area and no adverse levels of radioactivity were found.
The valve technician and HP personnel were found to demonstrate an appropriate level of knowledge and professionalism in completing their tasks.
3.1 Control Rod 10-19 Slower than Expected Rod Insertion Time During the review of the December 4,1992 Unit 2 shutdown, PECo determined that control-rod 10-19 had slower than expected rod insertion time, exceeding the maximum allowable scram time per Technical Specifications. The scram time recorded was 7.14 seconds with the maximum allowable time being 7.0. All other rod scram times recorded were less than 3.0 seconds. Additionally, the scram time data for 1019 showed that the rod did not start to move until approximately 4.5 seconds after the scram signal was generated. Once it began motion, rod speed was in line with the other rods. This 4.5 second time delay led PECo to believe the control rod scrammed as a result of backup scram valves depressurizing the L control rod drive (CRD) air header instead of via the individual control rod inlet and outlet scram valves, which would normally scram the control rod.
Under normal conditions the inlet and outlet scram valves, associated with each of the control rod hydraulic control units (HCUs) are closed by control air pressure applied to their respective diaphragm actuators by two scram pilot solenoid valves. During a reactor scram, the scram pilot solenoid valves are de-energized venting control air pressure off the inlet and outlet scram valve diaphra;;ms, which open by internal spring pressure allowing the control-rod to rapidly insert into the reactor core. In addition, the CRD Instrument Air System has a series set of two solenoid operated valves. These two valves are called backup scram valves and supply all the instrument air to the HCUs Upon a reactor scram, both backup scram valves energize to vent the instrument air from the air supply header as a backup ! the individual scram pilot solenoid valves on each HC,
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PECo's investigation determined that the 'A' scram pilot solenoid valve on control rod 10-19 had not actuated, in response to the scram signal, to vent the control air pressure off the inlet and outlet scram valves. (Both the 'A' and 'B' scram pilot solenoid valves must operate in order for the control air to be vented under a full scram condition.) Subsequently, it was also determined that the rod did insert as a result of the backup scram valves venting the instrument air from the CRD air supply header. The air manifold containing the two scram pilot solenoid valves was removed from the HCU and disassembled for inspection. During this inspection the maintenance personnel found that the solenoid base sub assembly appeared to be in working order, but debris was found inside the valve body. The debris consisted primarily of shreds of tenon tape. A 1/2 inch piece of teflon tape and a 1/4 inch piece of teDon tape were found on the valve body side af one of the valve's diaphragms (there are-two per pilot valve) crossing the scaling surface of the diaphragm-to-valve body. The tenon tape had migrated from the connections between the solenoid manifold and the air line pipe.
PECo believes this debris affected proper operation of the solenoid valve's diaphragm preventing valve actuauon. The onsite General Electric (GE) representative, who was consulted on this issue, stated that any tape c debris on the diaphragm would not allow the diaphragm to seat properly and would result in bypass air flow through the solencid keeping the scram inlet and outlet valve diaphragms pressurized. This in turn would not allow the scram inlet and outlet valves to open, since control air would not be properly vented.
All HCU's are supplied from the manufacturer with teflon tape used to seal the air line pipe connections (tenon tape is not used at Limerick). Therefore, PECo determined that all scram pilot valves could be susceptible to this problem. However, it i-believed that this is an isolated case. Maintenance personnel sponsible for rebuilding the : cram pilot valves inspected the debris found in the failed valve and stated that amount of debris hasn't been seen before. During each refuel outage approximately 60 solenoid valves are rebuilt, so there is a reasonable amount of maintenance history associated with these valves. It was noted that a large amount of teDon tape was used by the manufacturer to seal the air line fittings to this valve, which may account for the unusual amount of teflon tape that migrated into the valve. In addition, a review of Limerick data revealed no other scram pilot valve failures have been identined to date and there have not been any indications of degraded scram times during rod testing.
On December 8,1992, this issue was discussed at a meeting of the Plant Operation Review Committee (PORC), at which time the findings and corrective actions were presented.
PECo, along with the GE representative, concluded that the failure of the control rod 10-19 scram pilot valve was not a generic problem at Limerick for the reasons stated above.
3.2 Rod Position Indication System Inoperable On December 28,1992, at 2:46 p.m., with the unit operating at 100 percent power, the Unit I control room operator received a " Rod Position Indication System (RPIS) Inoperable" alarm. The operator observed that the four rod display, as well as the plant process l
computer, no longer provided position indication for any of the control rods. The limiting
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condition for operation (LCO) for Technical Specification 3.1.3.7, Control Rod Position Indicator, was immediately entered. The LCO requires that in Operation Condition 1 or 2, with one or more control rod position indication inoperable, within one hour, determine the position of the control rod by using an alternate method. Otherwise, be in at least Hot -
Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, it should be noted that with a loss of the RPIS the Reactor Manual Control System does not permit rod motion in any direction. Under these conditions the only rod motion available would be by a reactor scram.
In accordance with the alarm response procedure, which indicated that the most probably cause of the alarm was an inoperable power supply, trouble shooting and repair of the RPIS power supplies were initiated. Concurrent with those activities, plant personnel commenced the alternate method for determining control rod position, which consisted of taking resistance reading, at the RPIS panel, across the reed switches for each of the control rods.
This method took approximately one and one half hours to complete. All control rod positions were verified on the moming of December 29,1992, at 1:30 a.m., and compared.
to the last known control rod positions. PECo decided that this alternate method for control
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rod position verification would be repeated during the next 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> cycle, if the RPIS could not be restored within that time. This was a conservative decision since Technical Specification 4.1.3.7 requires that the RPIS be determined operable by verifying at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> that the position of each control rod is indicated.
PECo maintenance personnel worked areund the clock performing extensive troubleshooting activities to identify and correct the cause of the loss of RPIS. PECo determined that the cause was due to two of the three RPIS power supplies being faulty. One power supply overheated as a result of a failed cooling fan, and the other power supply failed as a result of an electronics problem. On December 29,1992 at 1:00 p.m., both power supplies were replaced, the RPIS was restored, and the system declared operable. As part of the post maintenance testing, PECo went beyond what would have been expected to verify RPIS operability and thoroughly evaluated the RPIS system. Six control rods, one from each of-the RPIS control files, were moved one notch and returned to their original position. After each of the rod movements (both insert and withdrawal) a control rod position scan was run on the process computer and the four rod display was checked to verify proper RPIS responses. The inspector had no further question or concerns with the RPIS power supply replacement activities. The activitics' observed by the inspector were acceptable, t
L 3.3 Residual Heat Removal (RIIR) Outnges On November 1,1992, the "A" phase of the 2A RHR motor failed because of the incorrect installation of an oversized connector lug. Procedures indicate that extra wire should have L
been used in the crimping of this type of lug, however, the extra wire was not added.
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During the pre-operational testing on Unit 2 (1988) all the lugs were changed on all of the RHR pump motors by the installation contractor. The reason for relugging the motors was because of broken and frayed connections on the existing lugs that were identified by the installation contractor.
Because of the 2A RHR "A" phase failure PECO wanted to check all of the existing connections of all RHR motors in both units, to see if there were similar connections that-needed to be changed. A process called thermography was selected as a good method for
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performing this check. The process utilizes a device that reads and records infrared light (heat) that is transmitted from an object and compares temperatures of that object to the surrounding area. By looking at the lug / wire connections of an RHR pump that is running, thermography can determine if one of the lugs is running " hot," (elevated temperatures).
This is an indication of a loose connection.
PECo embarked on a systematic approach for performing the thermographic checks on each -
of the remaining seven RHR r' imp motors. At the same time concerns were raised by the NRC concerning the remova; of these safety related systems while the unit was at power. A-study was performed by PECo regarding the safety impact on the operating unit, regarding the removal of RHR systems for repairs and preventative maintenance. (Section 5.0 delineates the results of this study.)
The inspector followed these RHR system removals for the lug / wire examinations, they are documented below:
11/01/92 2A RHR Motor failed at 5:30 a.m. The line (A phase) to ground failure was caused by an incorrect lug size (#1/0 lug, #2 leads) and inadequate crimping causing excessive ohmic heating which led to lead degradation and ultimate failure. The motor lead was repaired and tested and the other two phases were also corrected.
11/04/92 2A RHR System was declared operable at 10:15 a.m.
I1/05/92 1B RHR Mo.or lead / lug visual and thermographic inspections were satisfactorily completed by PECo engineers.
11/16/92 2B RHR Motor lead / lug visual and thermographic inspections were performed.
This inspection was unsatisfactory because the inspection revealed signs of heat degradation in the "A" and "C" phases. Thermographic inspection confirmed excessively high temperatures on both of the phases. This motor had been lugged in the same way as 2A RHR with #1/0 lug with #2 leads and no filler material used.- Work order #C0134043 was initiated to rework the leads. (See 11/20/92)
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11/18/92 2C and 2D RHR motor lead / lug vhual and thermographic inspections were satisfactory. This motor also it ' #1/0 lugs without filler material. An Action Request (AR) was written to rework the motor leads.
I1/20/92 2B RHR Motor ! cad / lug rework. General Electric Co. spliced in approximately I foot of new leads and replaced all of the lugs, using filler material.
11/24/92 ID RHR Motor lead / lug visual and thermographic inspections were satisfactory.
I1/05/92 1C RHR Motor lead / lug visual and thermographic inspections were satisfactory.
12/04/92 l A RHR Motor lead / lug visual and thermographic inspections were satisfactory.
The reason for the oversized lugs was to accommodate the connection studs in the connection box of the motor. This is an accepted practice, provided additional filler wire is added in order to create a tight crimp of the lug to the wire. In 1988 the contractor changed the lugs without using the extra filler wire in the Unit 2 ins.allations. Additional information concerning the RHR motor connection lugs is as follows:
Construction personnel installed the lugs using construction procedures prior to the
startup of Unit 2.
All lug work is now done by station electricians using a procedure designed to install
the lugs correctly.
The symptom and the problem have been corrected by station electricians for all RHR
motors except 2C and 2D However, these two motors passed the thermography testing and ARs have been written to correct the lugs.- The RHR motor 2C is scheduled for August 1993 and 2D is ' scheduled for September 1993. PECo engineers
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stated that until then thermography will be performed on a three month basis to insure the connections are still tight. They are also looking into the possibility of changing the lugs during the upcoming outage beginning January 22,1993.
3.4 Main Steam Isolation Valve Malfunction During the wactor trip of Unit 2 on December 4,1992, HV-041-2F028A (2A Outboard Main Steam _ Isolation Valve (MSIV)) was slow closed using the test pushbutton in accordance with procedures, however, when the handswitch was placed in the closed position the valve drifted open. Subsequent investigt. tion revealed that the valve would not have isolated on a containment isolation signal. All other MSIV's reacted normally and closed.
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The manifold assembly containing two AC solenoid valves and one DC solenoid valve was
- replaced and the one that was removed was tested and disassembled to determine the root-cause of the problem. The cause of failure was attributed to the incorrect assembly of the DC solenoid valve plunger and spring assembly. The spring in the plunger assembly _is tapered and must be installed so that the large outside diameter of the spring is oriented such that it will seat on the stem when the stem is screwed into the manifold, if the spring is installed in the opposite orientation, the plunger may bind while attempting to stoke the valve resulting in failure of the valve to operate properly. Subsequent testing, after the PORC meeting on December 8,1992, has shown that failure rates of the spring assembly with the spring improperly oriented are higher at elevated temperatures (in excess of 122*F) as compared to ambient temperatures.
A PORC meeting was held on December 8,1992 to discuss this issue prior to the restart of Unit 2. It was decided during the meeting that it was acceptable to restart Unit 2 based upon ratisfactory inspection of the remaining outboard valve DC solenoids on Unit 2 and based:
upon preliminary evidence that the inboard valve manifolds and the outboard "A" valve -
manifold were replaced with new manifolds that had been assembled by the manufacturer (Automatic Valve). Since these manifolds had been assembled by the manufacturer who was aware of the need to orient the spring in a specinc manner, it was determined that no further action was required on these manifolds. Further investigation revealed that the ~ Unit 2-inboard valve manifolds _wcre not replaced _with new manifolds, assembled by the manufacturer, as initially believed by PORC on December 8,1992. -It was determined that the manifolds were actually rebuilt on site and assembled correctly.
PORC also discussed the generic implications of this event on Unit I which was operating at 100 percent power at the time. Discussions with'the foreman whose team had done the work on the MSIV's during IR04 indicated that the inboard manifolds were rebuilt just prior to the-outage and that the personnel involved in the rebuilds had been appropriately trained on the spring orientation. The outboard valves had the AC and DC solenoid valves replaced during the outage and work was performed in accordance with an approved procedure which specifically made reference to the spring taper and orientation. This information was reviewed to make a preliminary determination that Unit I could continue to operate safely.
A PORC commitment was issued to review the records to substantiate the discussions'which took place to provide added assurance that continued Unit 1 operation was acceptable.
Since the initial PORC meeting, subsequent PORC meetings, attended by the inspector, have substantiated some information. However, due to pECo's reexamination of records the following is the final status of the MSIV manifolds:
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Unit i Outboards MSIV's:
All valves HV-041-lF028A,B,C and D had the AC and DC solenoid replaced during the last refueling outage by a qualified maintenance mechanic "A".
All paperwork was signed off on Apnl.'0,1992. The training lesson plan discussed the spring -
orientation and procedure PMQ-600-037 emphasized the spring tape E
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Unit 1 Inboard MSIV's:
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HV-041-lF022A has a new manifold installed that was assembled by the manufacturer who was aware of the spring orientation.
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HV-041-lF022B,C, and D were all rebu it in the July / August 1989 time frame. - This 3 i
was one of the differences that was origint'ly presented in the Decemt,er 8,1992 PORC meeting. These were rebuilt by a diil-rent mechanic _"B" prior to training being available that specifically addressed the s,' ring orientation. _ However,
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interviews with him indicated that the assembly n.ethod used would have reasonably :
precluded improper orientation of the spring.
Subsequent review of paperwork and interviews with personnel involved with the rework of the Unit 2 MSIV's led to the fol owing conclusions:
1.
HV-041-2F022A (Inboard MSIV) has a rebuilt manifold installed that was rebuilt by a qualified mechanic "C" on January 18, 1991.
2.
HV-041-2F022B (Inboard MSIV) has a rebuilt manifold installed that was rebuilt by mechanics "D" and "C" on January 15, 1991.
3.
HV-041-2F022C (Inboard MSIV) has a rebuilt manifold installed that was rebuild by.
mechanics "D" and "C" on January 15, 1991.
4.
HV-041-2F0220 (Inboard MSIV) has a rebuilt manifold installed that was rebuilt by l
l mechanic "B" on October 26, 1989.
There is not a concern with the Unit 2 inboard valves. The three craftsmen, "B",_"C" and.
"D", involved with the rebuild were interviewed and their assembly method would have =
reasonably prevented improper oticatation of the spring.
l The status of the Unit 2 Outboard MSIVs as discussed in the previous PORC meetings was
.as follows:
1.
HV-041-2F028A - the currently installed manifold was assembled by the y
manufacturer.
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HV-041-2F0288,C and D - DC springs inspected and verified to be installed properly. The AC springs were not inspected because they were not believed to be
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susceptible to this failure mode based on LER 2-89-023 which was issued by Peach
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Bottom. The information about the AC solenoids was called into question by GE L
- SIL-505 (located after the PORC Meeting of December 8,1992) which states:
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"There also is a tapered spring in the AC solenoid valve. Failure caused by improper installation of the tapered spring in the AC solenoid valve is less likely to occur that in a DC solenoid valve because of stronger force developed in the AC solenoid. Nevertheless the potential for failure exists for all AC MSIV solenoid valves if the tapered springs are installed improperly."
Based on this information a PORC commitment was made to inspect the Unit 2 B C, and D Outboard MSIV AC solenoid plunger springs. All six AC solenoid springs were found to have the proper orientation.
Personnel involved in the rebuilds of the Unit 2 Outboard valves were interviewed. Work packages for the "A" outboard valve could not be located. interviews with the job leader, foreman and craftsman indicated that Mechanics "B", "C" and "D" who replaced solenoids on Unit 1 outboard valves were not involved in the Unit 2 outboard replacement work. The individuals involved in the Unit 2 outboard solenoid replacements could not be traced to work on any valves other than the Unit 2 outboard valves, which were subsequently inspected for proper spring alignment (both AC and DC).
In addition, four manifolds that were previously rebuilt and were in the hot shop or storeroom were inspected. All twelve solenoid plunger springs were found to have the proper arientation. All four manifolds were rebuilt by Mechanics "C" and "D".
The other seven spare manifolds were never rebuilt.
Significantly hampering the investigation of the history of the MSIV manifolds was the condition of the parts history paperwork. Research of the storeroom paperwork verified the aforementioned information. A Corrective Action Request (CAR) has been issued to investigate the documentation and storage of documents.
Due to a management meeting on December 22,1992, in Region I, where this event and incidents of procedural noncompliance were discussed. the inspector concluded that PECo's discussion at the meeting, addressed the procedural noncompliance, and outlined the corrective actions to prevent recurrence. The licensee-identified violation (incorrect spring installation) is not being cited because the criteria specified in Section Vli. B.2 of the Enforcement Policy were satisfied. The inspectors intend to follow PECo's corrective actions and followup with additional inspection in the maintenance area.
4.0 RADIOL.OGICAL PROTECTION (71707)
During the report period, the inspector examined work in progress in both units including health physics procedures and controls, ALARA implementation, dosimetry and badging, protective clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and materials.
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The inspector 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 were acceptable.
5.0 SAFETY ASSESSMENT / QUALITY VERIFICATION The NRC is concerned with the removal of safety systems for maintenance purposes while l
the unit is at power, purposely entering LCOs (Limiting Condition for Operation). LCOs are definitive requirements written into Technical Specifications and were originally intended to direct the operator that, in the event a portion of a safety system or component becomes incapacitated during operation, a finite time is permitted for the return of that component or system to an operable condition prior to mandatory additional action being taken. The NRC does not want to discourage licensees from doing preventive maintenance (PM) at power if-there is a net safety gain resulting from the improved reliability of equipment.- However, it
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does want to ensure that LCOs are not being entered purposely without prior planning and an expectation ofimproved safety.
The inspector discussed voluntary entry into LCOs as it applied to the Residual Heat Removal (RHR) system at Limerick with PECo management. PECo provided the inspector with a list of RHR system outages and the reason for those outages for a three month period from September 1992 through December 1992. During that period, various loops (A-D) of the RHR system were declared inoperable on 14 occasions on Unit I and on 9 occasions on Unit 2. A review of the reasons for these outages identified two major contributors. The first contributor was the need for Emergency Service Water (ESW) component cleaning, including unit coolers, motor coolers and lubrication oil coolers, which was conducted on several occasions and resulted in RHR system outages. A problem was identified with ESW -
components concerning micro-biological influenced corrosion (MIC) and magnesium -
deposits, which reduce the heat transfer capability of the heat exchanger, necessitating the need for inspection and cleaning of these components. This problem _ was also identified at-the Susquehanna Steam and Electric Station (SSES) and resulted in a loss of an RHR pump, due to a motor cooler failure. The second contributor to the RHR outages at Limerick was the failure of the 2A RHR pump motor leads and the subsequent inspection of the other RHR pumps for any similar problems using thermography. The pump motor leads issue is discussed further in Section 3.3 of this report.
While the maintenance associated with the ESW component cleaning was performed during planned " system outage windows,". the RHR motor leads inspections were done in addition to the planned outage windows due to the safety significance of the problem. The decision not to wait for an outage window was based on the likelihood of fmding similar problems in the other seven RHR pumps. The problem was identified on the 2B RHR pump motor, which required repairs be made to those lead..
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The inspector noted that PECo has established and implemented procedure AG-43,-
" Guideline for the Perforrnance of System Outages," which addresses the issue of system outages as they relate to probabilistic risk assessment-(PRA). This procedure provides guidance for decision making and planning for the execution of system outages based on the Limerick PRA insights. The inspector reviewed the document and found that it addressed, in detail, how to remove, repair, test and return a system following maintenance. The process
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includes management input. The procedure also mandates the removal of only one system at a time per plant, and only if all other safety systems are operable. There is a. time limit imposed for system removal. The time limit is 75 percent of that permitted by applicable technical specifications action statements. The procedure further states that " Technical Specification LCOs associated with PRA Systems should not be entered for the purpose of performing elective activities that result in little or no gain in system reliability." In addition, AG-43 requires that, for systems important to PRA safety (listed in an attachment to AG-43), PRA unavailability time should be tracked by the plant Performance Monitoring Group. This data should then be sent to the NESD Reliability and Risk Assessment Branch =
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for the calculation and trending of the yearly core damage frequency (CDF).
The inspector further discussed what effect the current three months of RHR system unavailability would have on the yearly CDF. PECo was asked to perform the yearly calculations for CDF, which was completed using the following assumptions:
unavailabilities for RHR system outages includes other assumed system outages due to
maintenance; and unavailabilities due to RHR were calculated as if the three months of RHR outages
were performed in each of the four quarters of the year. (This is a conservative estimate since outages in this quarter exceeded those in previous quarters.)
The results of these calculations indicated that the RHR outage impact has the following contribution to the PRA:
Core damage frequency per year = 3.8 x 10*/ year
(assuming plant system unavailability throughout the year)
Unit I core damage frequency w/RHR unavailability = 4.65 x 10*/ year
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(22 percent increase)
Unit 2 core damage frequency w/RHR unavailability = 3.9 x 10*/ year
(Approximately no change)
Major contributions on the Unit I was the corrosion monitor installation which took 51/2 days of shutdown and suppression pool cooling availability.
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- The inspector noted that the overall effect of the RIJR system unavailability on the CDFJ appears to be low. However, the inspector noted that a significant amount of LCO
- preventive maintenance on a' number of systems has' occurred at Limerick. Further
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inspection of LCO maintenance will be conducted. '(Unresolved Item 50-352/92-29.-01)-
6.0 REVIEW OF LICENSEE EVENT REPORTS (LERs), ROUflNE AN'D SPECIAL REPORTS (90712,92700)
6.1 Licensee Event Reports (LERs)
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Llig 2-92-011. Event Date: October 27.1992. Reoort Date: November 20.1992 Failure to comply with Technical Sptcification frS) Section 3.7.7 in that 'a one hour fire-watch insnection was not oerformed.
This LER reported that the established firewatch inspection for an area containing an inoperable fire barrier (i.e., Thermolag barrier) was not performed within one hour, as -
required by the action statement of TS 3.7,7, " Fire Rated Assemblies.." The area was -
eventually inspected within I hour and 35 minutes of the last completed inspection. The cause of this event was cognitive personnel error in that the contractor employed firewatch failed to inspect the area containing the inoperable barrier as described on the firewatch -
round sheet. The firewatch involved in this event is no longer employed by the contractor. -
All remaining firewatch personnel were counseled on the importance for attention to detail and on the need to perform a self check of their work. - The round sheets have also been-modified to assist the firewatch in the self check process.
LER 2-92-0.[2. Event Date: December 4._1992. Report Date: December 30.1992 Manual Reactor Scram due to Recirculation Pumn trins resulting from an indeterminate -
cause.
This event is discussed in detail in Section 1.2 of this report.
6.2 Rostine and Special Reports -
q Routine and special reports are submitted by PECo to inform the NRC of routine operating conditions and other noteworthy occurrences that are reportable due to' requirements in 10 CFR 20, technical specifications and other regulatory documents. The inspector reviews.
these reports for information and confirms the accuracy of the reports. The followingE..
reports were reviewed and unless otherwise delineated below, satisfied the requirements for which they were reported.
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.6.4.i Monthly Repod Monthly Operating Report for November 1992, dated December 14, 1992 6.2.2 Special Repod Dated December 18, i992 Emergency Diesel Generator (EDG)
Test Failure This special report was submitted pursuam to the requirements of Technical Specifications (TS) Section 6.9.2 at required by plant TS Surveillance Requirement 4.8.1.1.3 which requires reporting of diesel generator failures.
On November 25,1992, D21 EDG failed its monthly surveillance test when the EDG's c"$ut began erratically increasing and decreasing because the control logic had converted to the isochronous mode of operation instead of the droop mode while connected to the offsite electrical power grid. Steady load could not be maintained, therefore, the EDG was
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shutdown and declared inoperable.
Troubleshooting of the problem determined that the cause was the result of the test start circuit being de-er.ergized causing the EDG to revert to the isochronous mode of operation.
A wire enclosed within the mechanical governor had rubbed against the rotating portion of the mechanical governor, rubbing the insulation off the wire. Contact of the bare wire with the mechanical governor, along with a previously existing Unit 2, Division 1 battery ground (present during testing and troubleshooting of the D21 EDG), caused an intermittent battery ground in the governor circuit. This ground produced electrical currents sufficient to sporadically energize the 5B relay on initial EDG starting. Energization'of the 5B relay resulted in the de-energization of the start circuit.
The damaged wire insulation was repaired and the wire was shortened such that it no longer contacted the mechanical governor. The cause of the previously existing ground has-not been determined. The investigation is continuing utilizing Routine Test (RT) procedure RT-1-095-900-0, Location of Battery Grounds.
The D21 EDG failure was classified as a nonvalid failure using the guidance of Regulatory Guide 1.108, Rev.1 August 1977, Section C.2.e.(2). The relay contacts that caused the problem are bypassed in the emergency operating mode so that the D21 EDG would have fulfilled its safety function in the event of an accident. Because this event was classified as a nonvalid failure, the ST procedure frequency is not required to be changed.
The mechanical governors for the remaining three Unit 2 and all four Unit i EGDs were inspected and verified to not have the same condition.
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6.2.3 Special Report for the Inoperability of a Selsmic Monitoring System Iristrmnent for More Than 30 Days This special report was submitted purcuant_to the requirements of Technical Specifications (TS) Section 6.9.2 as required by plant TS 3.3.7.2, Seismic Monitoring Instrumentation, which requires that with one or more of the required Scis'mic. Monitoring System (SMS)-
instruments inoperable for more than 30 days, a report must be submitted within 10 days.
On September 9,1992, with both units at 100 percent power, channel 1 (longitudinal axis of h
three orthogonal axes) of accelerograph sensor XE-VA-105 to recorder XR-VAi105 failed the functional loop check test criteria and was declared inoperable.
i Troubleshooting indicated that the problem existed with the accelerograph sensor XE-VA-105, which is located inside the Unit 1 Primary Containment on a reactor piping support -
(i.e., Main Steam Line D clevation 313'). _ On September 21,1992, a vendor for the accelerograph sensor recommended that further troubleshooting of the accelerograph sensor; inside the containment would be necessary to identify the root cause of the problem. On l
September 22,1992, a maintenance work action request was initiated to repair the-accelerograph sensor during the next Unit 1 outage of sufficient duration which allows accessibility to the Unit I containment. 'On October 9,1992,.the accelerograph sensor had been inoperable for more than 30 days requiring the submittal'of a special report.
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No seismic events have occurred to date since the sensor was declared inoperable, and the balance of the 26 SMS sensors remain available to sense, alarm, record and analyze seismic
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data. Plans for corrective actions to prevent recurrence will be determined after'
troubleshooting and any corrective maintenance are performed.
The resident inspector had no further concerns or questions regarding the above listed
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7.0 COOLING TOWER FOAM PROHLEM FOLLOWUP Several concerns about the foam that is emitted from the cooling basin portion of the cooling towers, at Limerick, prompted PECo to analyze the foam for toxicity or harmful affects on.
humans or materials in which it may come in contact.
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The analysis shows that thorough mixing of the chemicals added to the water from the Schuylkill River is accomplished by the method of addition. Chemicals are diluted in a four inch chemical addition line and further diluted by a 100,000 gallon per minute (gpm) flow system through the main condensers prior to entering the 7 million gallon cooling tower-basin. The chemicals added are PECo-4 (a custom blend of zinc sulfate and a dispersant pollimer) and PECo-5 (a custom blend of phosphate, HEDP (calcium carbonate scalc _..
inhibitor), TTA.(corrosion inhibitor)) for corrosion inhibiting, and acid for pH control of the
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water. The river water is generally 6-9 pli depending on the time of year. The tower water is maintained at a pit of 8.0-8.5 for normal operation by the addition of acid. The acid is mixed in a sin'llar manner to that stated above.
Chemical analysis was performed to eciuate potential biological hazards for health concerns.
The results where that the cooling tower does concentrate certain bacteriological harards found in the Susquehanna River and that prolonged exposure to this concentrated water could have harmful effects. The effects studied were compared to workers that work in sanitary waste water trratment facilities where conditions are similar. The results of the study showed that only slightly clevated incidents of minor gastrointestinal Rinews occurred in the treatment facility workers. Duration of espcsures to cooling water over spray and foam at Limerick should not approach exposures of typical waste-water treatment piant workers and, therefore, people exposed to the foam should not be infected as a result.
Discussions with the PECo medical department indicated that people who have gotten foam or spray in their eyes experienced a burning effect. All of the cases were referred to an ophthalmologist. The medical department does not know of any damage to the eyes as a result of getting foam or spray in them.
The resident inspector has had foam on his car. The foam is harder to remove than ordinary road dirt, however, it was removed with no damye to the paint.
Since March of 1992, PECo has been adding an an:llohmir g agent called Foam-Trol, which consists mostly of mineral oil, to reduce the foan 7g from the cooling towers.
8.0 FOLLOWUP OF PREYlOUS INSPECTION FINDINGS (92702)
(Closed) Unresolved item (50-352/91-15-01). liydrogen llecombhier blower motor not lubricated in accordance with vendor manual recommendations.
During a review of the vendor manual, the inspator noted that the recommended lubrication frequency for hydrogen recombhier blower motor was once every five years. A review of the preventative maintenance (PM) procedures and discussions wi h the PECo maintenance t
personnel indicated that this recommendation was no; being implemented, and in fact, the PM program did not provide for periodic lubrication of the blower motor. A PECo review associated with the environmental qualification program had indicated that no periodic lubrication was necessary based on the expected service life of the lubricant. The vendor recommendation was to be reevaluated and incorporated into the PM program.
PECo's evaluation concluded that the frequency for lubrication of the Hydrogen llecombiner blower motor should be changed from once every 5 years to once every 15 years based on the following information:
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the actual run times on the blower motors is 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> per cycle;
recent grease samples taken from the l A blower motor were analyred and found to be
satisfactory (It was estimated that the grease analyzed was in service for at least 8 years with no signs of degradation. The grease samples were compared with a
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sample of a new grease and chemical testing indicated that old grease had the same characteristles as the new grease); and the Nuclear Engineering Division (NED) Equipment Qualification group has thermally
aged and radiated this grease ar:d determined that it has a qualification life of 40 years.
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PECo concluded that while this information would indicate that greasing is not required on any hydrogen recon biner blower motors, good maintenance practice dictates that periodic greasing should be done to minimite the cost associated with the repair of motors. The inspector had no further questions on this issue. This item is closed.
(Closed) Unresolved item (Nos. 50 352/90-02-01 and 50-353/91401) pertaining to unsupported dsta used in the calculation of high range radiation monitor accuracy.
These ummolved items were last updated in combined inspection report nos. 50-352/92-12 and 50-353/9212 dated August 3,1992. At that time the inspector reviewed PECo'_s calculation results and other documentation supporting their conclusion that the Radiation Monitoring System (RMS) was acceptable with the postulated worst case degradation.
PECo had indicated this information would be made available to plant operators. However, at that time there was an operator aid posted in the main control room which gave the operator a correction factor to apply to the readings based on primary containment temperature, it was not certain if this operator aid was correct bel on the latest
l calculations. This issue was discussed with station personnel who agreed to review the
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question and take actions to ensure the correct information is conveyed to the operators.
These items reniained open pending assurance that the plant operations personnel have adequate guidance.
I PECo has since reviewed the need for operator aid in light of the latest calculations and o
concluded that the operator aid (#26-29) was no longer required and should be cancelled.
Since containment radiation levels are used in declaring emergency classifications (under
" Damage to Fuel"), the operator aid cancellation was reviewed by the Site Emergency Preparedness (EP) organization. They supported the removal of the operator aid based on o
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the following conclusions:
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The overall system accuracy satisfies Regulatory Guide 1.97 Revision 2 accuracy requirements and the system'will perform its intended function under extreme accident
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temperature conditions.
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The containment radiation levels specined in ERP 101 under the " Damage to Fuel'
Emergency Action level (EAL) set are intended as relative quantification and are confirmatory in nature. The Loss of Coolant Accident (1,0CA) accident sequences which result in a "Iksendary degradation /LOCA" EAL set classification would require an ALERT declaration prior to the containment radiation levels reaching 100 R/hr.
The inspector had no further questions on these issues. These items are closed, p
9.0 MANAGEMFNr MEETINGS 9.1 Exit Intertlews The NRC Resident inspectors discussed the issues in this re[mrt with PECo representatives throughout the inspection period, and summarized the findings at an exit meeting with the Plant Manager, Mr. J. Doering, on January 5,1993. No written inspection material was provided to licensee representatives during the inspection period.
9.2 Additional NRC Inspections this Period The Resident inspector also attended the following exit interviews during the report period:
Dalc laspec10I rcd 0Il Siddect November 23 25 Jeff laughlin 50 352/92 28 Implementa-50-353/92 28 tion of the
' Emergency Plan November 30 -
Joe Carrasco 50-352/92-30 Engineering December 4 50-353/92 30 and Technical Sup;mrt 9.3 Enforcement Conference l
On October 22,1992, an enforcement conference was held at the Region i Of0cc to discuss an apparent violation associated with discrimination against a security employee because he'
engaged in protected activities, in violation of Section 210 of the Energy Reorganization Act.
At the enforcement conference PECo was given the opportunity to discuss the facts of the case, the czuses and safety significance of the violation, and to present their proposed l
corrective actions. PECo's enforcement conference agenda and presentation are included in l
this report as Attachment B. NRC action in this regard is the subject of separate l
corresimndence.
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9.4 Radiological Controls Program Enhancements On December 3,1992, members of PECo's plant management met with NRC Region I management and staff at the Limerick Generating Station to discuss radiological controls program enhancements. Topics discussed were:
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program philosophy
organizational development issues
near term corrective actions e
PECo discussed the efforts underway to enhance the radiological controls program relative to concerns and weaknesses identified following the NRC review of a July 1992 unplanned exposure of a worker (Reference NRC Combined Inspection Report No. 50 352/92-26; 50-353/92 26). NRC management acknowledged PECo efforts to enhance the radiological controls organitation and its self-assessment process.
During the meeting, PECo also discussed the equipment qualification (EQ) resolution plan
'
schedule developed to resolve potential EQ concerns rah' during the aforementioned inspection. NRC management acknowledged PECo's efforts to resolve this matter.
9.5 Sintus of Iraking Fuel On December 18,1992, members of PEco's corporate and plant staff and plant management met with NRC Region 1 management and vaff. The purpose of the meeting was to provide an opportunity for PECo to provide a status of the fuel leak monitoring program at Unit 2.
The meeting was held in the NRC Region i Office King of Prussia, PA. PECo discussed the following matters:
project teams established to monitor the fuel including use of outside expertise
fuel leak monitoring techniques and methods
plans to suppress leaking pins
>
radiological impact and actions taken
training and communication of issues with workers
pre and post outage strategies to respond to potential radiological concerns
...
-.
.
.
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.= -.
-
_ _ _ _ _ _ _ _ _ _ _
_ __
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.
PECo concluded that there was at least one and potentially two fuel pins with cladding
'
failures. Ilowever, there has not been any signincant changes in the radiological'
>
cnvironment entered by workers. Effluent releases from the station continue to be well below allowable limits.
,
,
NRC Region I personnel acknowledged that PECo was properly responding to the leaking pins and that PECo's efforts relative to this matter were well managed.
.;
PECo's handouts provided at the meeting are attached. (Attachment C)
9,6 Senior Vlee President Briefing
On December 18,1992, Mr. Dickinson S. Smith, Senior Vice President, Nuclear, PECo,-
briefed the Regional Administrator of Region I, Mr. Thomas T. Martin and interested staff =
'
members, on the Nuclear Effectiveness and Ef0ciency Design Study (NEEDS) recently completed and soon to be implemented by PECo.
Attachment "F" contains execrpts from a News Release, by PECo, that describes the program and what PECo hopes to accomplish by instituting the changes.
The NRC will monitor PECo's progress over this program, that is expected to take place over the next three years.
9.7 Management Meeting Regarding Maintenance Procedural Compilance i
On December 22,1992, PECO management personnel attended a meeting held at King of
-
Prussia to discuss procedural non-compliance within the Maintenance Departmenti The meeting was requested by NRC letter dated December 7 -.1992.' The letter described the'-
a need to discuss a violation issued for PECo's failure to correct procedural non-compliance within the Maintenance Department. (A list of attendees is attached in Attachment D.)
'
i
'
PECo personnel discussed the procedural non-compliance issues in accordance with the -
attached agenda (Attachment E).
o n
!
.
.
<
L Mr. David R. Helwig, Vice President of Limerick Generating Station; in_his opening l.
remarks stated, "There are four primary focus areas at Limerick of which thn' maintenance
'
'
areas is one." He went on to say that the station needs to increase its quality and quantity of-
_
work'in order to correct some of the problems. -(The other three areas are outages,
- radiological control. and operations management reassignment.)
,;
During Mr. Robert W.' Boyce's presentation,' he highlighted problems identified in the 1991
,
time frame that have been corrected, and that these problems were within support agencies to.
~
L
.the station rather than the maintenance work force within the~ station. The correctioris in
-
I
. these areas were the result of the support agencies and the station coming together and
.
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changing their methods of operation. However, these corrections did not reach into the station maintenance area. Mr. Iloyce went on to describe the background of, interventions to, and current insights into procedural non-compliance. Mr. Boyce summarized the pECo position and described a continuing program of root cause analysis and self assessment mechanisms to further correct procedural problems. The station maintenance department will
'
be scheduling monthly meetings to formalize and document lessons learned regarding maintenance activities.
,
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A'lTACllMENT A SEQUENCE OF EVENTS FOR UNIT 2 TRIP FROM 77 PERCENT IUWER lhttiliber 4.1992 Time Event 0930 Commence ST 6-001-660-2, Main Turbine Stop Valve RPS and EOC-RPT
-
Channel Functional Test.
1001 Loss of 2A and 2B Reactor Recirculation Pumps (5 seconds apart).
-
Reactor operator places reactor mode switch to " Shutdown," initiating a full
-
reactor scram.
Enter T-101, RPV Control and OT-112, Recirculation Pump Trip procedures.
-
Mala turbine tripped, B and C Reactor Feed Pump secured.
1002
-
GP-ll, Reactor Protection System Scram Reset, completed scram reset, reactor 1009
-
level 30 inches, reactor pressure 945 pounds.
1016 C condensate pump secured.
-
Recirculation Pump Motor Generator (MG) sets reset.
1032
-
2B Control Rod Drive (CRD) pump secured.
1033
-
Main generator protection relays reset.
1038
-
Main turbine steam seals on auxiliary steam.
1040
-
1054 2B CRD pump started.
-
!
2A reactor recirculation pump started, reactor pressure 895 pounds.
l 1057
-
Main steam to Steam Jet Air Ejectors (SJAE) secured.
1110
-
Restored electrical distribution ring bus, closed breakers 235 and 335.
1118
-
Main turbine placed on its turning gear.
1153
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1935 A reactor feed pump secured.
-
_ _ _
_- _ _ - _ _ _ _ _ _ _ _ - _ _
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_ ____ ___ _ _
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-__ __ _______._ _ _ _ ______
.
>~
lkstmber 5.1992
nm:
nytni
)
2B reactor recirculation pump started.
1056
-
Commenced depressurization at 25'F per hour to cold shutdown.
J 1200
-
liigh Pressure Coolant Injection (11PCI) isolated at 100 pounds reactor pressure.
2152
-
December 5.1992 r
20 Residual }{ cat Removal (RilR) pump placed in service in the shutdown cooling 0425
-
mode.
Operational condition 4, cold shutdown (less than 200*F).
0850
-
.
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PilILADELPilIA ELECTRIC COMPANY e
LIMERICK GENERATING STATION Affoc,kme.
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,
SUPPORT DIVISION NUCLEAR SECURITY SECTION A
,
AGENDA
[H{C. ENFORCfMENT CONFEMNCE - Off0BER 19, 199%
$1UEGT Opening Remarks D. llolwig Vice President Limerick Generating Station Discussion of Apparont Violation Ccuses R. C. Gill Review by Philadelphia Electric Company Director, Nuclear Security Limerick Generating Station Management Dr. Potor Kolson Standard and Associatos R. C. Gill Other Facts Director, Nuclear Socurity Limerick Generating Station Correctivo Actions Taken (PECo)
R. C. Gill Director, Nuclear Security.
Limerick Generating Station
,
Corrective Actions (PTI)
R. C. Gill Director, Nuclear Security Limerick Generating Station
!
!
l
!
Summary / Closing Remarks D. Holwig b
Vice President Limerick Generating Station-i
l. _. _, _ _ _ _ - _. _. _ _ _..~.._.___ _,_. _ -__ _ - _._-_._ _. _. _ __
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Allegatiun. P xedural January 1,1992
'
I lion Comphan^e
- Approrirnately i
i 2300 hours0.0266 days <br />0.639 hours <br />0.0038 weeks <br />8.7515e-4 months <br />
i um swiew ct the January 2, 19921 Janusty t.19u-Approxirnately I I
t v * 'd 0700 hours0.0081 days <br />0.194 hours <br />0.00116 weeks <br />2.6635e-4 months <br /> I
I
,
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,__,____-_-------
I______
_...
I i 10CFR Part 26 Fitness For Duty Incident i i
1
.
I
2nd Shift Sgt.
January 2,19921
approaches Sito Cpt.
- - Approximately 1
!
'
'
Cpt, advises Shift Sgt.
1600 hours0.0185 days <br />0.444 hours <br />0.00265 weeks <br />6.088e-4 months <br />
',
',
need facts i
i Previous behavioral
[.cpt revim saments January 3,1992 '
. Captain provides
_ _. Approxituately,
.---
issues Considered l
tocommenda'jon to Director 0900 A.M.
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. Access Suspended -
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i SATUllDAY/.
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january 4, S,1992 sunoay i
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1. Psycho, eval. MMPI January 0; 1992 i Dr. Peter Kolson - - - - -
t *esults of MMPl/ interview -. A.M.
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obta.med-
.
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. Access Revoked '
I I
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+
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O!!icer terminated
'
anuary 7,199.9. I
.
por PT! Work
'
Itulos/ Bargaining
- -- A,M,
J Unit Acroornent I
i_._________________
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OTHER FACTS
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Timing of the two (2) separato events
-
>
>
NRC Regulations Involved
~
r Requirements for Physical protection of 10CFR 73.55
-
licensod activities in Nucioar - Power-reactors against Radiological sabotage.
-
-
Employoo Protection-50.7
-
r Fitness For Duty Part 26
-
,
Unescorted Access not Revoked until Part 26.27 concern surfaced -
+
i i
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Approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the 10CFR73.55 incident.
Unoscorted Access suspended on January 3, 1992.
-
,
Eligible to retako psychological test January 7, 1993.
'
-
-- -
Protection Technology (Incorporated) has appealed the Administrativo Law L
Judge's recommendation..
. ;
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fe a'm**
. _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _.. _ - _ _ _ _ _ -
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_PECo Corrective ActioJLq
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Ennuro open communications between Work Force, Contractor and Licenseo Management.
Formal employco concerns meetings
Informal one-on-ono discussions with employees
Monthly Safety Meetings (Reinforce the desire for open
communications)
Management attendance at Security Force pre-shift briefings
(Guardmount)
Menagement by Walking Around (MBWA)
e Reiterating Managemont's Open Door Policy
,
Publicizing our complaint / concern llotlino in the daily Plan of tho'
e Day correspondence Management discussions with now hires in February 1992 e
(PTI/ LGS Security)
Unit 1 Refueling Outage employco presentation meetings e
.
.
Weekly / Daily staff meetings
July Security Forco Member meeting with R. C.
Gill e
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Plco correctAvo Actions-
!
>
An indopondent review of the Security Organization by SAIC during the:
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week of April 27 - May 1, 1992, resulted in very pcJitive remarks.
i
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General Employeo Training-(GET)
>
e The PECo "lfuclear Group Management Philosophy for Assuranco.of Quality"
-
,
i s posted in all N.aclear Group employee and contractor work locations.
(e.g.,
Poach 130ttom Atomic Power Station (PBAPS), LGS, Nuclear Group
}{cadqua rters ).
A Quality Concerns llotlino" was established inJ0ctober, 1988, and
"
-
advertised to all Nuclear Group employees and contractors by means of a
,
poster, e
i
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NQA Administrative Procedure NOA-30, effective -December 26, 1988,.
-
addressocs,- :in - part, how an individual's quality concerns should be.-
reported, and dcfines alternatives-available to: an individual who -
believes-thatC his/her previously reportod = concerns are - not receiving proper attention'.-
-
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PT1 Corrective A_ctions
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Bi-Monthly Sergeant's mootings.
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PTI Corporate meetings conducted.
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Unit 1 Refueling Outage employeo presentation meetings.
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Security Forco Members advised of-January ~1992 termination issues.
.
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Employee concerns / suggestions are solicited during supervisory post :
-
visits.
-...
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F DOL Legal Standard is complex (le - dual motivo)
[
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ALJ Recommended Decision has boon appealed.
- Finding doos not imply inappropriato action
e
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Guard was expressing a legitimato concern
-
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Behavior was basis for action, not concern
Security concerns routinely raised by others e
t
Action taken was appropriate under 10CFR26
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. Appropriato actions have been taken to ensure there was no chi.', ling
-
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offact.
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CURRENTLEU_EL STATUS
~i e
PEER REVIEW MEETING 12/9/92
> PECo: FUEL MANAGEMENT, LICENSING, AND
"
LGS REACTOR ENGINEERS, OUTAGE PLANNING, CHEMISTRY, HEALTH PHYSICS, REACTOR SERVICES AND-l PUBLIC RELATIONS p
i
> EXTERNAL EXPERTISE:
G.E.
G. POTTS (MGR FUEL PERFORMANCE)
'
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S. LEVY - H. KLEPFER (VP CORE & FUEL DIV!SION)
> REVIEWED HISTORY OF FAILURE AND DISCUSSED-RADIOLOGICAL CONCERNS, METHODS OF DEALING WITH-
.
'
FAILURE, FUTURE IMPACTS AND GENERAL CONCERNS.
> RESULTS:
,
POTENTIAL 2nd FAILURE
,
CONTROL POWER CHANGES DURING S/U & S/D
e FULL CORE FLUX TILT BEING PERFORMED (STARTED 12/16)
TO SEARCH FOR 2nd LEAK
__
_
> LATEST ~RESULTS <
L e
SENIOR MANAGEMENT INVOLVED L
L-e CURRENT PLANS L
n'
> SUPPRESS 2nd LEAKER lF FOUND L
> REDUCE TRAMP BY REPLACING U/2 INITIAL CORE FUEL-WITH U/1' DISCHARGED FUEL
> PERFORM SIPPING ON ALL RETURNING FUEL (BOTH U/1 &
-U/2)
,
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Limerick Unit 2 Cycle 2
!
Fuel Per"ormarice History
!
2/20/92 offgas distribution changed from 100% recoil
!
8/31/92 - 9/4/92 offgas increased to 7200 uCi/sec
i 9/5/92 Reactor power reduced to 80% (2000 - 3000 uCi/sec)
!
9/6/92 and 9/12/92 flux tilt testing performed I
9/14/92 rod 38-07 inserted as part of power ascension
!
Offgas activity between.3000 - 4000 uCi/sec,100% recoil l
-
i-J;
9/29/92 offgas activity began increasing trend
'
,
h 10/21/92 rod 42-07 inserted to suppress local power
i around failure t
11/22/92 rod 38-11; inserted to suppress local power
,
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around failure
,
i
12/17/92 offgas activity at 47200uCi/sec, power at 76%
!
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UNIT 2 OFFGAS Sum of Six :ay grab sample
Thousands (microcuries/sec)
IDE as microcuries/ gram
0.07 axscam
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.
OFFGAS
' Dose Equiv Iodine 12/08/92 -mp
,
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Fuel Leak Effect Monitoring Philosophy i
t
- Monitoring requirements by system and area of the unit Reactor Water
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Condensate
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. Define radiological controls for an area during the
outage I,
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i Fuel Leak Effect Monitoring Weekly Contamination Survey
,
- Locations y
- RWCU Sample Sink
- 1
- HPCI Room (Contamination)
!-
!
- H\\LSA area
,
,
!
. Survey Requirements j
- Gamma scan g
- Proportional count j
- Alpha Survey l
- Hot Particle Survey l
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12/18/92 l
L
. _ _]
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-
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,
-
!
Fuel Leak Effect Monitoring Reactor Water Cleanup System i
1. Loose Surface alpha contamination has been identified
,
2. Long lived alpha airborne contamination has been
.
identified during the pump rebuild. (These samples j
have been sent offsite for further analysis)
j
,
3.
Beta \\ Gamma smearable levels have been higher l
and more restrictive than the alpha contamination a
'
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4. No hot particles have been identified l
i
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i
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12/18/92
.
. _ - --
-_
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I Fuel Leak Effect Monitoring j
Reactor Water Cleanup System 1. During recent pump rebuild jobs, positive air purifying
air respirators used l
2. Increased surveillance for alpha and Hot particles inside and outside of the RWCU pump rooms l
!
3.
RWP resurvey frequency increased for the pump and heat
-
exchanger rooms l
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f 12/18/92.
I
- - - -
-
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Fuel; Leak Effect Monitoring-i
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RHR\\ Shutdown Cooling System
1. During;the recent-reactor scram, the shutdown cooling mode of the RHR system was utilized.
,
.
2.
Increased surveillance was conducted
3.
Results of these. surveys L
+ - No loose-surface-alpha contamination p
No long lived alpha airborne contamination
.
,
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12/18/92
.
.
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- - - - - - - - - -
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.
Fuel Leak Effect Monitoring l
Main Steam (EHC leak)
!
l i
1. Monitored for alpha contamination at various locations in j
"
the condenser area during this time:
l-
OBMSlV room n
I
Moisture Sep area j
Stop and control valve l
h
)
2. No alpha contamination was found l
l l
3.
Several of these samples sent offsite for analysis l
t
!
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'12/18/92-
,
,
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- - - - - - - - - - - - - -
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i Fuel Leak Effect Monitoring
!
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condensate System
.
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1.
Demin hold pump rooms
,
2.
Alpha surveys have been performed l(_
No Loose Surface Alpha Contamination l
e
!
3. Two samples were sent off site l
!
I N
ll l
1 f
l 12/18/92
-,
- - -
- - - - - - - -
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.
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. Fuel Leak Effect Monitoring
-
Chemistry Data Review
[
1. Trended on a daily and weekly basis Help determine the anticipated conditions
>
[
I I
2. Trending the following data:
!
Offgas levels
,
-
Gross beta and gamma coolant levels
-
Coolant lodine dose equivalent
!
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Fission Products in the coolant water
,
i i
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12/18/92
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F.uel LeakiEffect Monitoring Isotopic. Data
,
1.
A new Part 61. analysis has been sent offsite
,
2. LWilijuse isotopic data to help establish the Beta \\ Gamma to e
alpha ratios expected 'during the. outage 3. TheLsamples sent offsite will help determine the actual isotopic mix.
.
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12/18/92
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,r. z Fuel LeakEEff6ct: Monitoring
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- Shutdown Strategy
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1. JCommunication.to Mant staff and workers pre outage'of:the Lexpectsd plant. conditions.
.
-2.- l lodine Levels:at-Shutdown
-
~ Monitor.-IDELduring. shutdown
-*
.
- LRWCU full flowiat. shutdown
-'
IDE limit 1forLremoval-of RPV head
Increased used:-of LHEPA units:with Charcoal
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Fuel Leak Effect Monitoring Shutdown Strategy 1.
Perform a soft shutdown to minimize lodine spike:
Slow cooldown
Slow depressurization
"
2.
During the reactor scram on 12/4/92, this should minimize the iodine spike at shutdown
3.
Reduce the possibility of airborne radioactivity s, hen l-vacuum is broken during shutdown j
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Fuel Leak Effect Monitoring Shutdown ' Strategy 1.
Comprehensive Hot particle, alpha, and beta analysis in key areas.of the plant Main Steam (Valves and Components)
~
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Undervessel
Refuel Floor \\ Reactor Cavity
Turbine
LP condenser Hotwell
t Filter Demins (RWCU and Condensate)
i 2.
Frequent communications of radiological conditions to plant workers during the outage 12/18/92
--
_
--
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.
.
.
.
Institute Fuel Leak Monitoring Program j
.
a. Increased alpha and pure beta surveillance
~
(RWCU rooms, sample sinks, HPCI, HLSA)
b. Increased air samples at known steam leaks (isotopic scans)
._
c. Detailed. surveys during breaches (isotopics, alpha & beta).
j d. Increased hot particle surveys (RWCU, sample sinks, HPCI)
e. offgas trend.& IDE ' trend reviewed daily.
f. Increased noble -gas monitoring & trending.
d g. Data above' is trended & reviewed.
h. Increased: RWP resurvey frequency of Unit 2 highrad areas.
12/18/92
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DetailedLOffsite Isotopic ' Analysis
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- of Key Inplant: Samples e
a. :RWCU-room, pump smears
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b. RWCU room l air samples c. HPClhroom. smears
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d. HPCI ; room' air. samples
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f. Reactoricociant.-
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Develop Experience Base from other Plants in U'.S. with Similar F uel Leak Profile
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Perry
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Pilgrim Contact INPO for' other industry contacts 112/18/92
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Develop Effective Communication-Strategy :for Plant Workers
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t p're-outage. training-
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all-hands / safety meetings
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inter-departmental team building
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- 12/18/92.
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_ CUMULATIVE ORGAN DOSE DUE TO IODINE /
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PARTICULATE RELEASE & CUMULATIVE AIR DOSE
'
DUE TO NOBLE GAS RELEASES Ofisite doses due to the release of Noble gases, lodines and Particulates from the North Stack, Unit 1 & 2 South Stacks, and the Hot Maintenance Shop are calculated to comply with ODCM Centrol 13.3.3 Surveillance Requirement 3.3.3.1 and ODCM Control 13.3.4 Surveillance requirement i 3.3.'4.1.
Radiochemical analysis of iodine cartridges (weekly), particulate filters (weekly) and noble gas grab samples (morithly) taken from thess release points are used to calculate the dose to members of the public. The values reported below represent the offsite -
cose at the t.GS site boundary. This data will be updated on a monthly frequency.
ORGAN DOSE DUE TO IODINE /PART GASEOUS mR DA is 61-TER Ath4M Ub6T.1.5 mW
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During the month of November 1992, increased air dose was due to activities associated with Unit 2 Reactor Water Cleanup Filter Domineralizer transfers to Backwash Receiving Tank and
=""viHa= associated with Unit 2 fuel leaks.
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Shutdown Strategy
.4
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1.
. Ensure. gaseous releases to the environment are below-r tech spec limits.
. 2..
Reduce io' dine levels in coolant 'to minimize. the
- possibility of airborne iodine ~ when RPV head is removed. -
'
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3.
~ Reduce possibilityfof-airborne-radioactivity in
,
turbine' building when; vacuum is 1 broken.
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4.
Reduce the radioactivity. levelsfin RHR system piping
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l as l expeditiously as possible after shutdown.. cooling.
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Post Outage I
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Define 3rd cycle strategy prior to end of 2RO2
-
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-recommendations.:to be developed by Fuel Leak ~ Task _ Force.
,
- 2.
- Increased. emphasis on steam leak identification and repair.
.
3..
Anticipated and unanticipated shutdown. procedures revisedEto factor in -increased offgas ' levels.
,
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Incorporate lessons learned during the outage to improve
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Ensure control points have analytical capabilities and logistical support for supplies and e.quipment.
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Ensure chem. lab is-adequately manned to. support
,
-extensive analytical requests.
.
l 3.
Conduct hot particle. surveys of key areas -
set up known/ anticipated hot particle: areas.
4.
Ensure frequent and; effective communications of radiological conditions..to plant. workers prior-to and during job evaluations (pre-job briefing guideline).
L 5.
Optimize' Lthe use'. of. engineering. controls to' minimize l
respirator -use.
.
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A1TACIIMENT D
- MAINTENANCE PROCEDURAL COMPLIANCE-
"
- MANAGEMENT MEETING OF 12/22/92 A'ITENDANCE LIST U. S. NUCL. EAR REGULATORY COMMISSION Clifford J. Anderson, Chief, Reactor Projects Section, DRP Walter H. Baunack, Senior Reactor Engineer, DRS Norm J. Blumberg, Chief, Performance Programs Section, DRS Theodore A. Easlick, Resident Inspector,'DRP Thomas J. Kenny, Senior Re'sident Inspector, DRP Deirdre W. Spaulding, General Engineer-Intern, DRP Edward C. Wenzinger, Chief, Projects Branch No. 2, DRP PHILADELPHIA ELECTRIC COMPANY Robert W. Boyce, Maintenance Superintendent
'
Thomas J. Carr, Maintenance Job Leader
>
Timothy J. Christmann, Public Relations John Doering,- Jr., Plant Manager..
Matthew S. Dunleavy, Maintenance Job Leader David R. Helwig, Vice President William J. Jones, Media Relations-Rodney M. Krich, Licensing Branch Head Walter G. MacFarland, Nuclear _ Maintenance Manager Gil J. Madsen, Regulatory Engineer Ralph R. Ritter, Jr., Maintenance Planner Mark A. Tornetts., Maintenance Mechanical Technician
"
Lloyd M. Yates, Maintenance Supervisor OTHER Stan P. Mangi, Nuclear Engineer, PA, Department of Environmental Resources-
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Bureau of Radiation Protection
- Jose Monaghan, Member of the PublL o
P. J. Reilly, Times Herald
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Violations.Since April,1991
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- 4/91 & 8/91
. Specific to Fuel Floor Accountability
. Limited. Scope-(NMD, Fuel. Floor)
-
Unique Complex Process With Changing Conditions
initial Corrective Actions - Narrow Focus to Enforce-Existing Process,
e Final Corrective? Actions - Total Redesign of the; Process World Class Results 'at PBAPS.and LGS 9/91 Sp.ecific to Special Welding Conditions
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Improved _ Process-
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Enhanced Training
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Manufacturers Settings
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1/92 - 14B Valve, Procedure Not Followed
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,c 7/921-Feed Water, Local Leak Rate Test, Procedure not Well Human Factored
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- 9/92i PaulLMonroe/ Actuator, Unfamiliarity with Procedure
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Vio ations Provice Limited nsig1t and Perspective
- 1991 Events Provide no Insight into 1992 Events
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Internal Processes Detailed and Comprehensive Corrective Actiori Request (CARS)
Deviations i
Immediate. Corrective Action Taken (ICATs)
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Reportability Evaluation / Event Investigation Fo.rm (RE-EIF)
Part of Intended: Continuous improvement / Self Assessment:
3rocess
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199" Insig1ts
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Procedures Often Used as Guidelines (Safety versus Balance Of. Plant Equipment)
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- Few Worker Initiated Procedure Changes
- Management Exp'ectation of Workers Needed Greater Clarity;
-
F Developing Self Assessment Program an.d Event Investigation Program
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Corrective ' Actions Needed Broadening L
- Trends.Not Fully Developed
. Focus on Spe:cifics P
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Interventions
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Sto o. Work
- Maintenance Suaerintendent initiated
- Significant Tr.aumatic. Event
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.
- Su aervisory Conc uoted
- Exaectations Defined
- Procedure Use C arified
,
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For:Your:Information (FYl) - Station
-
Maintenance Training Bulletin (MTB) - Maintenance
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Increased Oversight - Management - NQA
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Scenario BasediTraining1(Quarterly Continuing Training)
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Procedure Changes Are Routine
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Technical Adherence improved
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Administrative Process
- Work Order Management (PIMS) Flexibility Not Fully Managed
- Expectations Clarified
- Management Ownership
'
&
Work Order / Procedure Coordination
- Perceived to be Driven by External Expectations
- Adverso Trend. Reversed Approx Mid-Year
- Action Plans Developed (Focus on Maintenance)
>
QV Interface
- Subset of \\Nork Order / Procedure Coordination and Complexity
- Joint Problem Solving
- lJ R C - 5
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Current insig1ts-
~
Corr:inuec Transfer of Responsibilities (Need To. Control)
>
- Increased Management Attention
- Increased Technical involvement
- Improved Control of Qualifications / Task Assignments
,
Improved Ownership and Accountability
- Seriousness Well Understood l
- Pride in Success Thus Far
- Violation is Painful Reminder to Workers NRC-9
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Summary
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Coni:inuec
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Situation Well Understood
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No Quick Fixes
&
Corrective Actions Underway Address Identified issues
&
Seeking increased Learning Opportunities
>
Procedures and Process Upgrades Ongoing
&
Monthly Maintenance Management Meeting
- Increased Awareness
- Review of Trends-
- Monitor Corrective Action Effectiveness
- Review Events
- Ownership Accountability by First Line
- Supervisory Team Process NRC-11
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e Attachment F
"The Board of Directors has approved a voluntary early retirement program and voluntary separation package for employees of the Company's Nuclear Group.
The benefits are being made available in connection with the implementation of recommendations resulting from the soon to Se completed Nuclear Effectiveness and Efficiency Design Study (NEEDS).
The voluntary early retirement plan will be open to Nuclear Group employees who as of March 31,1993, are 50 or more years of age and have five or more years of credited service.- Approximately 165 Nuclear Group employees are expected to be eligible for this program which provides substantially improved retirement benefits.
Employees will have their age and service increased by five years for pension calculation purposes only and will have any early retirement discount climinated, in addition, other Company benefits for retirees will be provided in accordance with existing policy, The election period for the voluntary retirement program will be from December 10, 1992, through January 25, 1993.
The NEEDS study was undertaken to identify opportunities to improve the Company's nuclear program by increasing efficier.cies to improve or maintain the current level of quality and safety while reducing costs. A group of employees and line management from the Nuclear Group worked with a consultant for almost a year. Their preliminary recommendation was completed and announced in the Nuclear Group in October.
Following the completion of the retirement election and revocation periods, all of the positions in the new organization in salary level GB and above of the Professional, Supervisory and Managerial Salary Plan (PSM) will be filled. A number of positicns are expected to be changed substantially or eliminated as a result _of the study. The criteria for selecting employees to fill the positions will include performance, skill mix, future potential, Affirmative Action /EEO, incumbency, and location.
After filing the higher level positions, the remaining unassigned GB and above-employees, as well as all other PSM employees in the Group will be considered for the other PSM positions in the new organization.
Upon completion of this phase, those employees not assigned who have 10 or more years of service will be eligible to elect to receive the voluntary separation package or-to be considered for other positions under the Supervisory and Professional Employee Lack of Work Policy.
-1-
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e-Other unassigned PSM employees not covered by the Policy will be reassigned to open positions in the Company to the maximum extent possible or, as a last resort, involuntarily separated. - An employee involuntarily separated will receive two weeks'
pay for each year of service, with a minimum of 12 weeks, as well as Company provided benefits for up to one year in accordance with the provisions of the Policy.
.he specific details of the new organization were considered and examined throughout December. It is expected that During January the Company will communicate additional details on the implementation of the NEEDS study, insluding the new organization structure, the planned timing for any reassignments and the overall impact on the Nuclear Group.
It is anticipated that no CTAC employee will be involuntarily separated as a result of the implementation of the new organization. However, reassignment to availabic positions in the Company may be necessary in some instaus."
-2-