IR 05000352/1990027
| ML20029A002 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 01/23/1991 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20028H897 | List: |
| References | |
| 50-352-90-27, 50-353-90-27, NUDOCS 9102010030 | |
| Download: ML20029A002 (34) | |
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U.S. NUCLEAR REGULATORY COMMISSION I
REGION 'l
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Report Nos.
90-27 90 27
Docket Nos.
50 352 50-353 License Nos.
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NPF-85 Licensee:
Philadelphia Electric Company Correspondence Control Desk P.O. Box 195.
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Wayne, Pa - 19087-0195 Facility Name:
Limerick Generating Station, Units 1 and 2
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Inspection Period:
November 18 - December 31,1990 Inspectors:
T. J. Kenny, Senior Resident inspector
'L. L. Scholl, Resident Inspector -
M. G. Evans, Resident Inspector Approved by:
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d 3 l l-Lawrence T. Doerflein, Chief Date
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L Reactor Projects Section No. 2B Inspection Summary: This inspection report documents ioutine and reactive inspections during day and backshift hours of station activities including: plant operations; radiation protection; surveillance and maintenance; security; engineering and technical support; and safety assess-ment / qual?.y verification.
9102010030 violas PDR ADOCK 05000352 G
PDH
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TABLE OF CONTENTS i
EX EC UTIV E S U ht h1 A R Y......................................
il 1.0 PLANT OPERATIONS (71707, 71710)
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1.1 Operational Overview................................
I 1.2 Reportable Events..................................
1.3 Engineered Safety Feature (ESP) System Walkdown
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2.0 SURVEILLANCE /SPECIAL TEST OBSERVATIONS (61726)...
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-4 2.1 Inservice Testing......................
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3.0 M AINTENANCE OBSERVATIONS (62703)..,..
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-6 3.1 RH RS W Valve Replacement......... _............... =,..
4.0 ENGINEERING AND TECHNICAL SUPPORT (37700,37701)..........
4.1 Design Modifications
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5.0 SAFETY ASSESSMENT / QUALITY VERIFICATION.............
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5.1 Peri (xlic Procedure Reviews..............,,........
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6.0 REVIEW OF LICENSEE EVENT AND SPECIAL REPORTS (90712,92700)
6.1 Unit 1
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6.2 Unit 2
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7.0 M ANAGEMENT MEETINGS................
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7,1 Ex i t i n te rview....................................
7.2 Additional NRC Inspections this' Period.................,..
7.3 PECo's Early Retirement Program.......... -,............
NITACHMENT A Maintenance Documents Reviewed ATTACHMENT B Modification Documents Reviewed NITACHMENT C PECo Early Retirement Presentation i
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l EXECUTIVE SUMMARY
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Limerick Generating Station Report No. 90 27 & 90-27 Plant Operations A scram occurred on Unit I (while shut down) when an operator failed to adequately control reactor pressure during an operational liydrostatic test. Unit I resumed full power operation following the completion of the third refueling outage.
Surveillance and Maintenance i
Two reactor scrams occurred on Unit 1 (while shut down) during survei!!ance testing. One was l
the result of a loose cable connector and~the other due to a changing plant condition (establishing of main condenser vacuum) which was not compatible with the concurrent performance of the
- test. Additional weaknesses in the documentation of inservice testing results and problem resolut, ion were identified.
The failure of an RHRSW valve required Unit I to shut down until repair of the valve was
accomplished. The maintenance activities associated with this repair were well planned and j
executed.
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Fingineering and Technical Support
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Inspection of the plant modification program was performed and the program was found to be well implemented.
Safety Assessment and Ouality Verification A review of the status of periodic procedure reviews indicated that a previous backlog has been significantly reduced and a schedule is in place to complete the remaining procedures.
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DETAILS 1.0 PLANT OPERATIONS (71707, 71710)
The inspectors conducted routine entries into the protected areas of the plant, including the control room, reactor enclosure, fuel floor, and drywell (when access is 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 affirmed PECo's commitments and compliance with 10 CFR, Technical Specifications, License Conditions and Administrative Procedures. During this period,19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> of backshift inspections were conducted.
1.1 Operational Overview At the start of this report period, Unit I remained shutdown while the third refueling outage continued and Unit 2 was operating at full power. Unit status during the remainder of the report p riod was as follows:
Unit i December 6 Reactor mode switch placed in " start up" and criticality achieved follow-ing the completion of outage work activities.
December 9 Reactor shut dawn to comply with technical specification requirements while repairing the Residual Heat Removal Service Water (RHRSW) valve on the outiet of the B RHR heat exchanger.
December 14 Reactor critical following RHRSW valve repairs.
December 17 Main generator connected to the electrical grid marking the completion of the refueling outage activities.
December 22 Power increased to 100%.
December 28 Power was reduced to 85% for main turbine control valve testing and then returned to 100% upon completion of the testing. Full power operation continued for the remainder on the report period.
_Umt 2 November 28 Power was decreased to 90% for a control rod pa: tern adjustment and then returned to 100%.
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2 December 1 Power was decreased to 87% for repairs of an electrohydraulic control (EHC) system leak to the number four main turbine control valve (TCV)
and then returned to 100% following the repairs.
December 14 Power was decreased to 87% and then to 80%, due to an EHC leak at the -
number four TCV piping. Operation continued at 80% to reduce piping vibration while a resolution to the leak was being formulated.-
December 19 Power was decreased to 15% and the main turbine was taken off the line to permit isolating the EHC piping to the number four TCV, which had
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exhibited an increased leak rate. Operation continued at approximately 12% power, using the main turbine bypass valves, while the EHC piping to the number four TCV was replaced.
i December 21 EHC repairs were completed and the main turbine was returned to ser-vice. Power ascension commenced.
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December 24 Power was increased to 100% and full power operation continued for the
. mainder of the report period.
1.2 Reportable Events Umt 1 On November 18,1990, during the performance of an operational hydrostatic test of the reactor coolant system, a reactor scram signal was generated when reactor pressure increased to the high pressure scram setpoint. The reactor was in a cold shutdown condition with all control rods fully inserted at the time of the scram, thus no control rod motion occurred. Reactor pressure decreased to 825 psig when the scram occurred due to the discharge of water to the scram discharge volume.
Pressure is controlled during the hydrostatic test by the addition of water via the con:rol rod drive (CRD) system and discharging of water to the main condenser via the reactor water.
cleanup (RWCU) system. During the test the reactor operator noted that pressure was gradually increasing and had reached 1007 psig. He then adjusted the RWCU letdown rate in an effort to stabilize pressure. After the adjustment the operator's attention was diverted by other activities and thus he failed to observe that reactor pressure was continuing to increase and in fact increased to the scram setpoint of 1037 psig.
The cause of this event was operator error in that he failed to adequately monitor a changing plant condition which he was controlling from the main control room. The operator was counseled regarding his actions during the hydrostatic test. In addition, the occurrence will be included in licensed operator training to emphasize the need to properly verify the plant response following control manipulations.
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On November 18, 1990, while restoring the Technical Support Center (TSC) static inverters to service following maintenance, a temporary. loss of the Safety Parameter Display System (SPDS)
in the control room and the TSC occurred. The SPDS was lost for both Units 1 and 2 but was restored within one hour. The SPDS is a display system for plant parameters and is not used for plant operation. Unit I was shut down and Unit 2 was operating at 100% power at the time of the occurrence. The event had no significant impact on Unit 2 operations since other normal plant instrumentation was not affected. The momentary loss of power was due to the inadver-tent opening of a circuit breaker by an operator while placing the inverter in service. Procedural improvements are being reviewed as a method to prevent recurrence.
On November 20, 1990, a full reactor scram signal was generated when the channel "F" intermediate range monitor (IRM) spiked upscale concurrent with the performance of surveil-lance testing of IRM channel "C".
The Unit 1-reactor was in a cold shutdown condition with all rods fully inserted at the time of occurrence, thus no rod motion occurred. The cause of the i
spike on channel "F" was subsequently attributed to a loose undervessel cable connector. All other source range and intermediate range instrument connectors were inspected and found to be tight. The channel "F" connector was tightened and retested satisfactorily.
On December 2,1990, a full scram signal was generated during the performance of surveillance test ST-6-001-660-1,-" Main Turbine Stop Valve Reactor Protection System (RPS) and EOC-RPT Channel Functional Test." The scram occurred when vacuum was being established in the main condenser concurrent with the test performance. As the vacuum slowly increased through the reset point of the vacuum trip switches, it appeared.that the switches momentarily reset, arming the low condenser vacuum, turbine trip circuitry, and then went back to a low vacuum trip position. This resulted in a turbine trip signal being generated, and since the surveillance test simulates reactor power at greater than 30%, a scram signal resulted. All control rods were fully inserted at the time of the event thus no control rod motion occurred. The fluctuations of the vacuum switches has been experienced previously and is not a problem during normal operation. The surveillance tests are being modified to ensure they are not performed concur-rent with the establishment of main condenser vacuum.
The inspectors reviewed the three reactor scrams which occurred over a relatively short time frame for common causes which may be indicative of a potential programmatic problem. Based -
on this review the events appear to have been a result of independent causes and the corrective actions are adequate. The inspectors had no further concern regarding these events.
Umt 2 There were no reportable events on Unit 2 during this period except for the temporary loes of the SPDS system on November 18 discussed above, The above events were reported to the NRC via the Emergency Notification System (ENS) and the root cause analysis and corrective actions will be reviewed further upon iss"ance of the Licensee Event Reports as part of the routine inspection program.
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1.3 Engineered Safety Feature (ESP) System Walkdown The inspectors veriGed the operability of portions of the Unit 1 B Loop of the Residual Heat Removal (RHR) System and the D Loop of Low Pressure Coolant Injection (LPCI) by perform-ing.a walkdown of the system to confirm that system lineup procedures agree with plant drawings and the as-built configuration. These system walkdowns were also conducted to
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identify equipment conditions that might degrade system performance, to determine that instru-mentation is calibrated and functioning, and to verify that valves are properly positioned and locked as appropriate. The inspectors also utilized methods prescribed in a study prepared for the NRC by Brookhaven National Laboratory using the Limerick Probabilistic Risk Assessment (PRA), to enhance the inspection activity, The study, entitled PRA-Based System Inspection Plan, dated May 1986, provides inspection guidance by prioritizing plant safety systems with respect to their importance to risk. Abbreviated system checklists in Table 5-3, which identify.
components that are considered to have a high contribution to risk as determined in the PRA, were also used by the inspector.
The following procedures and drawings were utilized during the performance of the inspection:
Drawing M-51 Residual Heat Removal Piping and Instrumentation Drawing IS51.1 A (Col. 2)
Equipment Alignment for Automatic Operation of the RHR System in the LPCI Mode "B" Subsystem IS51.1. A (Col. 4)
Equipment Alignment for Automatic Operation of the RHR System in the LPCI Mode "D" Subsystem S51.1. A Set Up of RHR System for Automatic Operation in LPCI Mode The inspector found the system to be in good condition and properly aligned. No problems were noted.
2.0 SURVEILLANCE /SPECIAL TEST OBSERVATIONS (61726)
During this inspection period, the inspector reviewed in-progress surveillance testing as well as completed surveillance packages. The inspector verified that surveillances were performed in accordance with licensee approved procedures, plant technical specifications, and NRC Regulato-ry Requirements. The inspector also verified that instruments used were within calibration tolerances and that qualified technicians performed the surveillance tests.
Surveillance testing observed and/or reviewed included:
ST-6 001-660-1 Main Turbine Stop Valve RPS and EOC-RPT Channel Functional Test, performed December 3,1990.
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ST-6-052-232-1 B Loop Core Spray Pump, Valve and Flow Test, performed De-
cember 12 and 13,1990.
l ST-6-051-231-1 A Residual Heat Removal (RHR) System Pump, Valve and Flow Test, performed October 23,1990.
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i ST-6-051-232-1 B RHR Pump, Valve and Flow Test, performed August 24,1990 and December 18, 1990.
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ST-6-051-233-1 C RHR Pump, Valve and Flow Test, performed October 22, 1990.
ST-6-051-234-1 D RHR Pump, Valve and Flow Test, performed November 6 and 7, 1990.
No concerns or deficiencies.were identified except as noted in Section 2.1 below.
l 2.1 Inservice Testing (IST)
l The inspector reviewed tne test results of the recently performed pump, valve and flow tests for Unit 1 Core Spray Loop "B" and the Unit 1 RHR pumps. As discussed below, the inspector noted that in three of the tests, pump differential pressures and/or valve stroke times were found to be in either the alert or required action ranges.
In the case of the "D" Core Spray pump and the "D" RHR pump, partial retests had been conducted for which the results were within acceptable ranges. The causes of the initial failures included out-of calibration suction and discharge pressure gauges and an inaccurate flow reading.
During review of these pump differential pcessure tests, the inspector noted that a change had recently been made to the procedures to require recording of suppression pool level if the pump suction gauge was not reading within the required range specified in the procedure. If the gauge was not reading within this range, then it was assumed to be not operating properly. However, the pump tests were typically conducted using the inoperable gauge and later action taken to correct the results using suppression pool level, or the test was rerun following ca'ibration of the gauges. The inspector questioned the licensee regarding.the conduct of tests utilizing gauges which were known to be faulty, instead of attempting to recalibrate or repair the' gauges first.
PECo committed to review this issue to determine if a more appropriate method of testing was available.
The valve stroke times for valves HV-51-lF024A and HV-51-lF010B were found to be in the
alert range which requires an increased frequency to once per
- nth for the stroke time testing.
During discussions with a system engineer, the inspector was told that these valves had been modified during the outage and that their stroke times were lengthened. This test was conducted te collect the latest test data which would be used as baseline data for the procedure revision and future testing. Therefore, increased testing frequency was not required. The inspector noted
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that this information was not documented in the test record (the surveillance tests). In addition, the inspector noted during review of all of the surveillance tests, that there did not appear to be a standardized method of documenting corrective actions, including the need for increased test frequency to assure that the requirements of ASME Section XI Article IWP-6000, " Records of Inservice Tests," were sufficiently and uniformly met. The inspector discussed this concern with the licensee and PECo committed to review the method of documentation and take appropriate corrective action.
The inspectors have not noted any cases where increased testing frequency or operability issues were not properly addressed based on IST results. Nonetheless, the inspectors will review PECo action on the concerns noted above during followup to the licensee's ' response to previous IST violation 50-352/90-17-03.
3.0 MAINTENANCE OBSERVATIONS (62703)
The inspector reviewed safety related maintenance activities to verify that repairs were made in accordance with approved procedures and in compliance with NRC regulations and recognized codes and standards. The inspector also verified that the replacement parts and quality control utilized on the repairs were in compliance with the licensee's QA program. No problems or concerns were noted by the inspectors. Activities associated with repair of the Residual Heat Removal Service Water (RHRSW) valve HV-51-lF068B are discussed below.
3,1 RHRSW Valve Replacement On December 6,.1990 during conduct of surveillance test ST-2-012-407-1, " Radiation Monitor-ing - RHR Service Water Radiation Monitor; Division IV, Channel D Calibration / Functional Test" the "lB" Residual Heat Removal Service Water (RHRSW) Heat Exchanger Outlet Valve HV-51-lF068B was observed to not fully close. HV-51-IF068B is a normally closed, motor operated globe valve used for service water flowrate control and heat exchanger isolation upon high radiation detected downstream of the valve. With the valve not capable of closing, the "B" loop of RHRSW is considered inoperable for Unit 1. With one RHRSW subsystern inoperable, Technical Specification 3.7.1.a.3 requires the subsystem be returned to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the unit be in hot shutdown within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Following the required shutdown of Unit 1 on December 9,1990, activities to support and conduct the repair of the valve began.
To repair the valve (HV-51-lF0688) freeze seals were established downstream of the valve and upstream of valve HV-51-lF014B (Heat Exchanger Inlet Valve) to eliminate the necessity to drain the entire "B" RHRSW loop. Prior to application of the freeze seals, the "B" loop of RHRSW, common to both units, was declared inoperable, initiating a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Limiting Condi-tion for Operation (LCO) for Unit 2 due to the inoperable loop.
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Maintenance found that the valve (HV-51-lF068B) disc had separated from the stem. The threads on the valve skirt and disc were corroded by RHRSW to such a degree that the disc fell off of the stem, The licensee is investicating the cause of the corrosion.' The valve was refurbished utilizing a new skirt and keys and the disc from the HV-51-1F068A valve which had previously been replaced. In addition, a 360 degree stitch weld was utilized to prevent RHRSW
from seeping between the skirt and stem and further corroding their threads. _ Following replacement of the refurbished valve and removal of the freeze seal, the "B" loop of RHRSW was declared operable for Unit 2 and the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO was exited.
The inspector observed numerous activities in support of the valve repair utilizing the documents listed in Attachment A. The inspector attended a sub-PORC meeting on December.10,1990 during which procedure SP-106 and the 10 CFR 50.59 reviews required prior to conduct of the repair were reviewed and approved. On December 13, 1990, the inspector witnessed the installation of the refurbished valve and walked down portions of blocking permits 1-051-0123 and 1-051-0124 In addition, the inspector interviewed the health physics and Quality Control personnel assigned to monitor atmospheric conditions in the pipe tunnel while the freeze seal was in place. No unacceptable conditions were noted by the inspector. The inspector found the activities involving the various work groups to be well coordinated.
4.0 ENGINEERING AND TECHNICAL SUPPORT (37700,37701)
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. Design Modifications The inspectors continued to review modifications being installed during the Unit I third refuel-ing outage to verify conformity with NRC regulations and PECo commitments. The modifica-tions reviewed are listed below. The inspector's review includes:
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Verification that the new designs conform.with commitments made in the license amend-ment request for facility modifications which required prior commission review and
. approval; Verification that modifications that did not require prior commission approval were
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reviewed and approved by the appropriate organizations in accordance with Technical Specifications;
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- Observation of work in progress and/or examination of installa: ion records;
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Verification that new or revised procedures relating to the modification were completed and approved in accoA.nce with Technical Specification requirements, and that Techni-cal Specifications, if applicable, were updated;
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. Verification that operator training programs were revised in a reasonable time frame consistent with implementation of the modification;
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Verification of Quality Control / Quality Assurance involvement via reviews and work hold poiats by the PECo QC/QA Department;
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Observation and/or review of modification acceptance tests; and
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Verification that as built drawings were revised to reflect the modification and that control room drawings were revised before system startup.
4.1.1 Modification 801 " Addition of Test Connections for Functional Testing of Excess Flow Check Valves" This modification was installed in order to improve the method of testing excess flow check valves within the instrument portions of various systems such as Main Steam Isolation Valve (MSIV) Leakage Control, Nuclear Boiler Vessel Instrumentation, Reactor Recirculation and others. The piping portion of instrument sensing lnes for these systems, located inside contain-ment, penetrates the containment shell and is terminated outside the containment by an isolation valve followed by an excess flow check valve. The section from the excess flow check valve to the instrument is constructed of tubing. The former installation did not allow for functional testing of the excess flow check valve without the respective system being pressurized. This modification will allow functional testing without system pressurization. This design change has been installed, in stages, over the last three refueling outages on Unit 1, and was completed during this outage. During the first refueling outage eight excess flow check valves were completed, during the second 41, and during this outage the remaining 62 were completed. The inspector reviewed the following portions of the design change, which included a variety of welding and installation variations to the respective systems.
Excess Flow Valve System XV-40-101B MSIV Leakage Control System XV-4(bl01F MSIV Leaka' e Control System g
XV-40-10lK MSIV Leakage Control System-XV-40-10lP MSIV Leakage Control System XV-43-lF040A Reactor Coolant Recirculation Pump, Differential Pressure XV-43-lF040C Reactor Coolant Recirculation Pump, Differential Pressure XV-43-lF009A Reactor Coolant Recirculation Pump, Flow XV-43-lF010B Reactor Coolant Recirculation Pump, Flow-XV-43-lF010A Reactor Coolant Recirculation Pump, Flow XV-43-lF009B Reactor Coolant Recirculation Pump, Flow XV-42-lF059S Reactor Jet Pump Flow XV-42-lF059P Reactor Jet Pump Flow XV-42-lF059T Reactor Jet Pump Flow XV-42-lF059R Reactor Jet Pump Flow
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The documents listed in Attachment B were utilized in order to ascertain that the installed and tested portions of the added test piping met the requirements of the design change.
l During the review process the inspector noted (within the meeting minutes pertaining to the modification) that there was discussion about the dissimilar welding being performed. TN inspector consulted the specification for Piping Materials and Instrument Piping Standards for the Limerick Stations 8031-P-300 and noted that under the General Notes page 37.3 of 83 statement 6 states: Socket welding stainless steel to carbon or low alloy steel shall be permitted
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only where the design temperature is 212 degrees Fahrenheit (F) or less." Some of the dissimi-lar welds that were being reviewed were in piping connected to the main steam system and the inspector questioned the practice in light of the above statement. After discussion with the design control engineer it was identified that this practice is allowed under another specification 8031-M103 as stated below:
" Process connections and root valves should be located so that they are accessible for servicing and use at all times. Root valve stem and handle shall be installed clear of mainline insulation. For dead end instrument sensing lines with process line temperatures at or above 212 degrees F and dissimilar metal welds at the pipe to tube adaptor, a length of uninsulated line from the dissimilar weld to the process pipe shall be eight inches on steam lines and eight inches minimum for all other lines."
The inspector noted that the lines in which the dissimilar welding is being installed are normally dead ended lines and are 35 feet from the high temperature source with the last 18 inches being
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uninsulated. Tiie installed design exceeds the criteria stated above.
The inspector concluded that the r.ew.'y installed modification meets the intent of the installation specifications as well as the designated codes listed in the design change, and had no additional questions regarding this modification.
4.1.2 Modification 6101
" Main Steam Relief Valves Body Rcolacement"
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This modification replaced the bodies of the "E", "G" and "H" Main Steam Relief Valves I
(MSRV). The new valves utilize the existing pneumatic supply, solenoid and pilot assembly.
The new valve assembly is designed to reduce the amount of seat leakage experienced by the MSRVs and, as a result, keep the residual heat removal system from operating continually in the Suppression Pool Cooling Mode.
The inspector reviewed the documents listed in Attachment B and discussed details of the modification with applicable personnel. The inspector also reviewed the results of the surveil-lance tests used as the modification acceptance test. All aspects of the modification wtre well documented and no unacceptable conditions were identified.
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4.1.3 Modification 5994 " Installation of Manual Transfer Switch and Alternate Power Sunoly for RCIC Turbine Steam Suoply Valve HV-491F007": and Modification 5995 " Instal-lation of HPCI EmcIgency Shutdown Switch" During the previous inspection (50-352/90-25-and 50-353/90-24) the inspector reviewed modifications 5994 and 5995 and found them to be acceptable. However, modification accep-tance testing and procedure revisions were not complete at that time. During this period the inspector reviewed the documents listed in Attachment B including the results of all surveillance testing used as modification acceptance tests. The inspector discussed this testing and reviewed
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and discussed document revisions with the responsible PECo personnel. No discrepancies were noted. The inspector concluded that appropriate testing and document revisions were completed.
5.0 SAFETY ASSESSMENT /QUALrf Y VERIFICATION 5.1 Periodic Procedure Reviews The inspector reviewed the status of the periodic review of plant procedures. At the time of the inspection approximately one percent (77) of the plant procedure reviews.were overdue.
However, by the end of the report period less than 20 plant procedures remained to be reviewed and all were scheduled to be completed within approximately one week. The inspector had no further questions concerning procedure reviews.
6.0 REVIEW OF LICENSEE EVENT AND SPECIAL REPORTS (90712,92700)
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The following LERs or Special Peports were reviewed by the inspector and determined to have accurately described the events and to have been properly addressed for correuive or compensa-tory action:
I 6.1 Unit 1 LER l-90-24, Event Date: October 17, 1990, Report Date: November 27,1990 l
This report identified a condition where the Technical Specification (TS) actions had not been taken when the Reactor Core Isolation Cooling (RCIC) system was inoperable due to an unknown cable separation problem. The cable separation was corrected and extensive inspec-
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tions of additional IE electrical panels were initiated. The results of these inspections and additional actions taken by PECo will be provided in a supplement to this LER.
LER l-90 25, Event Date: November 10, 1990, Report Date: December 7,1990 This LER reported an event which resulted in an inadvertent Loss of Coolant Accident (LOCA)
signal being generated during a surveillance test. This occurrence was previously discussed in
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Section 1.2 of NRC Report 50-352/90-25. The planned procedural changes to the surveillance i
test appear to be the appropriate corrective actions to prevent recurrence. The inspector had no further questions regarding this event.
LER l-90-26, Event Date: November 18,-1990, Report Date: December 18,1990 This event was a reactor scram which occurred during hydrostatic testing ai. is discussed in Section 1.2 of this report. The.aspector had no f rther questions or concerns upon review of u
this LER.
LER l-90-27, Event Date: November 20,1990, Report Date: December 20,1990 This event was a reactor scram which occurred due to' a loose IRM cable connector and is discussed in Section 1.2 of this report. The inspector had no further questions or concerns upon review of this LER.
LER 90-1-28, Event Date: November 26,1990, Report Date: December 21,1990 This LER reports an occurrence which resulted in two IRM channels exceeding their TS surveillance time limit during the refueling outage activities. The missed surveillance was due to personnel error (inadequate communications) and a procedural deficiency associated with the
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surveillance tracking program. The surveillance interval was exceeded by 44 hours5.092593e-4 days <br />0.0122 hours <br />7.275132e-5 weeks <br />1.6742e-5 months <br /> and once tested the instruments performed satisfactorily. The tracking program will be modified prior to the start of the upcoming Unit 2 outage. The inspector had no further questions regarding this event.
LER l-90-29, Event Date: November 28,1990, Report Date: December 24,1990 A manual isolation of the main control room ventilation system was initiated due to a spurious high toxic gas alarm. The alarm was caused by the failure of the "B" toxic gas analyzer memory. The memory was restored by I&C personnel loading the required operating parame-(ers back into the system. The instrument then functioned properly and was declared operable.
The malfunction appears to be an isolated occurrence possibly caused by a power supply fluctua-tion. The inspector had no further concerns regarding this event, LER l-90-31, Event Date. December 3,1990, Report Date: December 20,1990 On December 2, st,rveillance test ST-7-022-371-1, Unit 1 Fire Door Daily Position Check, was l
missed when procedure ST-7-022-371-2, Unit 2 Fire Door Daily Position Check, was inadver-tently performed twice. The occurrence was due to inattention to detail on the part of tne fire -
watch and his supervisor. In addition to counseling the personnel involved all copies of the fire
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door STs were color coded by unit. The inspector had no further questions regarding this event.
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LER l-90-32, Event Date: December - 1990, Report Date: December 24,1990 A reactor building isolation occurred as a result of a blown fuse resulting from work in a control panel. In addition, an automatic initiation of the reactor enclosure recirculation and standby gas treatment systems occurred. The blown fuse also resulted in an isolation signal for the primary containment purge system valves. The impact of the event was minimal as the systems aligned to their accident mode lineup and functioned normally. A wire with a nick in its insulation is suspected as being the source of the short circuit. The wire was repaired, the fuse replaced and all systems were returned to their normal lineup. The inspector had no further questions concerning this event.
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Monthly Operating Report for October,1990, dated November 6,1990 6.2 Unit 2 LER 2-90-19, Event Date: November 1,1990, Report Date: December 3,1990
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This LER reports an event in which a half scram and various system isolations occurred during
the realignment of the static inverter power feeds. This event is also discussed in NRC Report J
50-353/90-25, Section 1.2. Revision 1 to the LER was issued on December 20,1990 to correct the fact that Dg radioactive material was released to the environment during the occurrence. The inspector had no further questions upon review of the revised LER, hionthly Operating Report for October,1990, dated November 6,1990 No additional ccncerns were identified upon review of the above listed reports.
7.0 MANAGEMENT MEETINGS 7.1 Exit Interview The NRC resident inspectors discussed the issues in this report with the licensee throughout the inspection period, and summarized the findi,gs at an exit meeting held with the Plant Manager, Mr. J. Doering on January 4,1991. No written inspection material was provided to licensee representatives during the inspection period.
7.2 Additional NRC Inspections this Period The following inspector exit interviews were attended during the report period:
[hm Sub,iect Reimri inspector i1/31/90 E.Q. Inspection 50-352/90-26 L. Cheung
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7.3 PECo's Early Retirement Program On November 20,1990, a management meeting was held in the NRC Region 1 Office !1 discuss PECo's early retirement program. At the meeting PECo described the program's options and pointed out that only about 6 percent of the total nuclear group had selected early retirement.
Senior line manager retirements were discussed including the timing involved and replacement status. The impact on maintenance / construction craft was also discussed and PECo indicated the program would assist in red Sing staff levels to previously planned targets with the end result being a more effective / capable maintenance workforce. PECo also discussed general company cost effectiveness initiatives, in summary, PECo pointed out that the early retirement program would help the company reach previously planned staffing levels; the program is being phased in with qualified replacements already identified (or in a few cases being actively sought) for senior line manager retirements;
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and the program is expected to increase staff effectiveness and improve company culture. At the conclusion of the presentation, no further questions or concerns were raised by the NRC.
Attachment C is a list of the meeting attendees and a copy of the slides used by PEco during the presentation.
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A'ITACHMENT A-I Maintenance Documents Reviewed i
i The following documents were reviewed during replacement of RHRSW valve HV-051-lF068B.
Maintenance Request Form (MRF)
i MRF 900699 Disassemble, Rework and Reassemble RHRSW valve HV-051-lF068B MRF 9007011 Perform Freeze Seal on RHRSW Piping Downstream of HV-051-lF068B valve MRF 9007012 Perform Freeze Seal on RHRSW Piping Upstream of HV-051-lF068B valve Blocking Permit No. 1-051-0123, Blocking Permits to support work on Blocking Permit No. 1-051-0124 valve HV-051-lF068B Special Procedure SP-106 RHRSW "lB" Heat Exchanger Outlet Valve
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(HV-51-lF0688) Repair," Revision 0, Sub-PORC ap-proved December 10,1990 10 CFR 50.59, Review for Temporary Installation of a Blind Flange for Valve HV-51-lF068B, Revision 0, Sub-PORC approved December 10, 1990 10 CFR 50.59, Review for Procedure for Determining the Effect of Temporary Breaching of Internal Barriers for Penetration Seal Work during Unit 1 Refueling Outage, Revision 6, Sub-PORC approved December 10, 1990
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ATTACHMENT B Modification Documents Reviewed The following is a list of documents reviewed for modifications installed during the last refuel-ing outage on Unit 1.
Modification 801
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Maintenance Request Form (MRF)
MRF 891-0141 for Excess Flow Check Valve XV-42-lF059F MRF 891-0142 for Excess Flow Check Valve XV-42-lF059R MRF 891-0143 for Excess Flow Check Valve XV-42-lF059S MRF 891-0144 for Excess Flow Check Valve XV-42-lF059T MRF 891-0147 for Excess Flow Check Valve XV-43-lF009A MRF 891-0148 for Excess Flow Check Valve XV-43-lF009b MRF 891-0152 for Excess Flow Check Valve XV-43-1F010A MRF 8910153 for Excess Flow Check Valve XV-43-lF010B MRF 891-0174 for Excess Flow Check Valve XV-43-lF040A MRF 891-0176 for Excess Flow Check Valve XV-43-lF040C MRF 891-0179 for Excess Flow Check Valve XV-40101B MRF 891-0180 for Excess Flow Check Valve XV-40-101F MRF 891-0181 for Excess Flow Check Valve XV-40-10lK MRF 891-0182 for Excess Flow Check Valve XV-40-10lP Design documentation pertaining to the above listed MRFs Modification meeting minutes Welding field check off lists Weld nller metal receipt forms Hydrostatic test reports QA verincation for fit up Material certification for piping, valves, weld filler metal and tubing Surveillance testing NDE inspections Modification 6101 Plant Modification 6101, Revision 00, PORC approved September 7,1990.
Installation Division, Modification Installation and Testing Memorandum, dated September 25, 1990 Maintenance Request Form (MRF) 90-04666, Pull and terminate cables.
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MRF 8984483, Replacement of MSRV (PSV-041-lF013E)
MRF 8984485, Replacement of MSRV (PSV-041-lF013G)
MRF 8984486, Replacement of MSRV (PSV-041-lF013H)
ST-4-041-210-1, " Main Steam Relief Valves Test" conducted November 29, 1990 ST-1-041-470-1, " Cyclic Test of Main Steam Safety Relief Valve Solenoid and Air Operator Assemblies" partial test conducted October 23,1990, hkxlifications 5994 and 5995
"HPCI Logic System Functional / Simulated Automatic Actuation," test
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conducted December 1,1990.
ST-1 -049-100- 1
"RCIC Logic System Functional / Simulated Automatic Actuation," test conducted November 30, 1990.
Unit 1, Locked Valve Log Primary Containment Isolation Valve (PCIV) List Annunciator Response Card (ARC) MCR-116 ARC-MRC-117 E-58, Slicet 1, Revision 22 E-58, Sheet 2, Revision 11 Check off List (COL) IS55.l A, " Equipment Alignment for Automatic Operation of HPCI" COL IS88.1. A, " Remote Shutdown Panel Controls Normal Line-up."
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ATTACHMENT C PECo Early Retirement Presentation November 20,1990 The following is a list of attendees and a copy of the slides used during a management meeting on November 20,1990, covering PECo's early retirement program:
ATTENDEES NAME POSITION NRC T. Martin
_ Regional Administrator W. Hodges Director, Division of Reactor Safety J. Wiggins Deputy Director, Division of Reactor Projects (DRP)
P. Swetland Acting Chief, Projects Branch No. 2, DRP L. Doerflein Chief, Reactor Projects Section No. 2B, DRP M. Evans Resident Inspector, Limerick Generating Station PFCo D. Smith Senior Vice President,' Nuclear K. Powers Manager, Nuclear Maintenance-Division E. Sproat Manager, Nuclear Business Unit G. Hunger Manager, Licensing Other S. Maingi Nuclear Engineer, Pennsylvania BRP D. Tauber Principal Engineer, PSE&G H. Abendroth Senior Engineer, Atlantic Electric R. Knieriem Delmarva Power
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Purpose of Meeting i
Provide Information on Early
Retirement Program Discuss Cost Effectiveness improvements
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Address Questions Raised Previously
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Agenda
introduction D.M. Smith II Early Retirement Program D.M. Smith 111 Impact on Maintenance and Training Forces K.P. Powers
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IV Cost Effectiveness improvements E.F. Sproat V
Managing Change D.M. Smith
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Early Retirement Program Options
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Retirement on August 1, September
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Retirement date to be scheduled based on operational needs, but no later than December 1,1992
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Continue Employment
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e Early Retirement Program Percent Number Limerick
28 Peach Bottom
35 NESD
115 Office of Sr. VP/
NQA
18 Total Nuclear Group 6%
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Senior Line Manager Retirements R.J. Lees Chairman NRB 4th O 1991 M.J. McCormick Plant Manager - Limerick Dec 31, 1990 J.F. Franz Plant Manager - Peach Bottom
'TBD L.B. Pyrih Manager - Nuclear Engineering TBD Division E.P. Fogarty Manager - -Project Division -
Peach Bottom 2nd O 1991 J.W. Spencer Superintendent Maintenance -
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Limerick Dec 31, 1990 W.F. Casey Superintendent Outages -
Limerick 3rd O 1991 P.J. Duca Manager Support Division -
Limerick Dec 31, 1990
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l MAINTENANCE /CONSTR_UCTION CRAFT ISSUE o
OVERALL COMPANY IMPACT / ISSUE o
o ENCOMPASSES CRAFT TRAINING o
CURRENT STAFF AFTER BILLETS AFTER STAFF RETIREMENTS REORG.
1020 871 850
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INTEGRATED SO_.UTlON I
l e GONYRACT MAJOR MODIFICATION WORK RESULT: o COMPANY CONSTRUCTION PERSONNEL AVAILABLE-FOR REDPLOYMENT o HEDUCE TRAINING REQUIREMENTS
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i e FOCUSING-NMD IN TWO AREAS
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o REACTOR SERVICING o TURBINE - GENERATOR RESULTi REDUCED PERSONNEL NEED l
l e FOSSIL / HYDRO AND T&D ORGANIZATION STUDIES RESULT: REDUCED PERSONNEL NEED-
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l e USE &-TRAINING OF SELECTED CONTRACTOR PERSONNEL IN MAINTENANCE AND TRAINING RESULT: FLEXIBILITY AND BACKUP i
l e INCREASED EFFECTIVENESS l
- SDA/ LEADERSHIP EXCHAN 3E
-.REf JCED EXCESSIVE LAYERS OF MGT.
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- 6 BROADER GRAFT TRADES
- TASK SPECIFIC TRAIN'NG
- ENGRS/ TECH AS SELECTED FOREMAN RESULT: LESS TOP HEAVY, MORE CAPABLE WORKFOPCE
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- TIMING OF RETIREMENTS (
- 3RD QTR 91 FOR MAsi4TENANCE SUPPORTS NUCLEAR OUTAGc7 PLANS e
. TIME FOR TRAMNG/ TRANSITION
. SELECTION OF TRAINING REPLACEMENTS
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SPAQED 1HROUGH 91 AND 92 SELECTED USE OF EXPERIENCED CONTRACTORS
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EXPECTED RESULTS
- A FULLY STAFFED, SLIGHTLY SMALLER, BUT MORE CAPABLE MAINTENANCE / TRAINING WORKFORCE
- SLIGHT INCREASE IN USE OF SELECTED CONTRACTORS DURING TRANSITION PERIOD
. EARLY RETIREMENTS TO EASE CHANGES
- PREVENTS LAYOFFS / DEMOTIONS
- NEWER CULTURE WITH A LONG FUTURE
- LESS RESISTANCE
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I PEco NUCLEAR GROUP
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APPROACI TO INCREASED COST EFFECTIVENESS O
BENCHMARK o
SET LONG TERM GsAL o
PLAN How To ACHIEVE GOAL STRATEGIC PUNNING
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LIMERICK AND PEACH BOTTOM VS.
1988-1990 AVERAGE OF SIX BWR PLANTS
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OSM COSTS PER MEGAWATT OF INSTALLED CAPACITY i
(EXCLUDING PECO'S LEASES AND WATER)
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YEAR
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- 1989-1990 I!OJSTRY DATA IS PELIMINARY
- INCLUDES ALL CLEAAED CHARGES TD STATION DESIGNATION
- FOR DATA VALUES SEE ATTACHED TABI.E
- INCLUDES FERCS 517 TrHJ 532 LESS 518 (FUELS)
- UNLESS NOTED. OE REFUEL DUTAGE PER STATION PER YEAR
- EXCLUDES NUCLEAR RELATED WRITE-DFFS Bl0GETED BY FEA
- IPOUSTRY AVERAGE UPDATED AMJALLY FBOM EUCS DATA
- EXCLUDES NON-STATION SPECIFIC NUCLEAR CHARGES
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- EXCLUDES LEASES AfD WATER f
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LIMERICK AND. PEACH BOTTOM /S.
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STRATEGIC INITIATIVES SUPPORTING INCREASED COST EFFECTIVENESS
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O HUMAN RESOURCES SUPERVISORY DEVELOPMENT ACADEMIES
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SUPERVISORY ASSESSMENT CENTERS
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MANAGEMENT INFORMATION SYSTEMS PLANT INFORMATION MANAGEMENT SYSTEM
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REFUELING OUTAGE LENGTH REDUCTION MAINTENANCE TECHNICIAN TRAINING PROGRAM
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l REACTOR VESSEL TEAM DEVELOPMENT
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BASE LEVEL OF EFFORT IDENTIFICATION
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Vonitoring Programs
- Weekly Executive Staff Meetings
- Monthly Station Review Meetings
- Monthly Key Indicator Reports
- Quarterly Key Indicator Reports
- NQA Audits and Reports
- NRB Reports
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