IR 05000352/1997008

Insp Repts 50-352/97-08 & 50-353/97-08 on 970916-1117.No Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20203F242
Person / Time
Site:	Limerick
Issue date:	12/08/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20203F229	List: IR 05000352/1997008 ML20203F225
References
50-352-97-08, 50-352-97-8, 50-353-97-08, 50-353-97-8, NUDOCS 9712170318
Download: ML20203F242 (48)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Dockat No '

50 353 License No NPF 39 NPF-85 Report No Licensee: PECO Energy Facilities: Limerick Generating Station, Units 1 and 2 Location: Wayne, PA 19087 0195 Dates: September 16,1997 through November 17,1997 Inspectors: A. Burritt, Senior Resident inspector N. Perry, Senior Resident inspector F. Bonnett, Resident inspector P. Swetland, Project Engineer W. Higgins, Reactor Engineer G. Smith, Security inspector T. Fish, Operations Engineer F. Rinaldi, Project Manager Approved by: Clifford Anderson, Chief Projects Branch 4 Division of Reactor Projects 9712170310 971200 PDR ADOCK 05000352 0 PDR

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' b TABLE OF CONTENTS Summary of Plent Status ...........................................1 1. O p e r a t i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 01 Condu ct of O perations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 01.1 G e ner al Comme nt s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 01.2 Control Rod Scram Failure - Unit 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 02 Operational Status of Facilities and Equipment .........................E O2.1 Engineered Safety Feature Walkdown - High Pressure Coolant Injection . . 5 03 Opt ations Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 03.1 Clearance and Tagging Fuses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 05 Operator Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 05.1 Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . 7 08 Miscellansous Oaerations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 08.1 IN PO Re port Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 ll , M a int e n a nc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . ................. 9 M1.1 General Comments on Maintenance Activities . . . . . . . . . . . . . . . . . . . . 9 M1.2 General Comments on Surveillance Activities . . . . . . . . . . . . . . . . . . . . 9 M1.3 Reactor Core Isolat!on Cooling (RCIC) Governor Issues - Unit 1. . 10 M1.4 Hydraulic Control Unit On line Maintenance Unit 2. . . . . . . . . . . . . . . 11 M1.5 Division 1 Safeguards Battery Charger Failure - Unit 2 . . . . . . . . . . . . . 12 ill . E ng in e e ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . '3

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E1 Conduct of Erigine ering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 E1.1 Residual Hect Removal Service Water (RHRSW) Radiation Monitor .... 13 E1.2 Scram Solenoid Pilot Valve Preventative Maintenance , . . . . . . . . . . . . 14 E2 Engineering Support of Faci) hies and Equipment ......................18 E CFR 50.59 Saf ety Evaluation Program . . . . . . . . . . . . . . . . . . . . . . 18 E8 Miscellaneous Engineer:ag Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 E8.1 (Closed) LER 197 007.lsolation of the Reactor Water Clean-up System, an Engineered Safety Feature, Resulting from Lifting of a Filter Demineralizer Pressure Safety Valve Caused 8y Setpoint Drif t ................. 19 IV . Pl a nt Su p p or t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0 li

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"1 Conduct of Emergency Preparedness Activities . . . . . . . . . . . . . . . . . . . . . . . 20 P l .1 Response to Emergency Diesel Generator Failure . . . . . . . . . . . . . . . . . 20 S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . . . . . . 21 S2 Status of Securit, Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . 22 S2.1 Prutected Area Detection Aids .............................22 S2.2 Alarm Stations and Communications . . . . . . . . . . . . . . . . . . . . . . . . . 23 S2.3 Testing, Maintenance and Compensatory Measures . . . . . . . . . . . . . . . 23 S3 Security cnd Safeguards Procedures and Documentation . . . . . . . . . . . . . . . . 24 S3.1 Implementation of Site Access Authorization Procedures . . . . . . . . . . . 24 S5 Security and Safeguards Staf f Training and Qualification . . . . . . . . . . . . . . . . 25

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SS Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 S8 Miscellaneous Security and Safety Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 S8.1 G e n e r al . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 6 S8.2 Vehicle Barrier System (VBS) ...............,,.............27 S8.3 Bomb Blast Analysis . . ..................................27 S8.4 Procedural Controls . . . . . . . . . . ..........................28 S8.5 Security Force Strike Contingency Plans . . . . . . . . . . . . . . . . . . . . . . . 28 F3 Fire Protection Procedures and Documentation . . . . . . . . . . , , . . . . . . . . . . . 28 F Fire Protection Damper Surveillance . . . . . . . . . . . . . . . . . . . . . . . . . . 29 F8 Miscellaneous Plant Support issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 F (Closed) LER 197-006. Revision 1, Previous Condition Prohibited by Tech Specs in that a Fire Protection System Deluge Valve may not have Functioned per Design Since Issuance of the Unit 1 Operating License . 31 r (Closed) LER 197-008, Failure to Perform Annual Maintenance Inspections of Onsite Portable Fire Extinguishers .........................31 F (Closed) URI 50-352,353/96-07-02, Missed Fire Protection Surveillance

...................................................31 V. M anage m e nt Me eting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 2 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . .......................32

> X2 Review of Ui 3 AR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 g INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 LIST O F AC RO NYM S U S ED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 36 iii i

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EXECUTIVE SUMMARY Limerick Generating Station, Units 1 & 2 NRC Inspection Report 50 352/97 08,50-353/97 08 This integrated inspection included aspects of PECO Energy operatiore, engineering, maintenance, and plant support. The report covers an 9 week period of resident inspection and region based inspection in the training and security area Opfdstions

• Operator response was excellent for an unexpected control rod drif t observed during rear tor protection system (RPS) testing at Unit 2. A leaking scram solenoid pilot valve (SSPV) was identified and ultimately a control rod f ailed to scra Subsequent control rod testing found several other degraded leaking SSPV diaphragms that cuased sicw rod travel but no other f ailures to scram occurred.

However, PECO Energy did not perform a prompt and comprehr.nsive assessment of generic and common modo concerns, and did not initially verify whether an unanalyzed condition existed. A number of conference calls occurred between licenser, staff and NRC management resulting in further testing and analysis. The vendor materials analysis performed in response to NRC concerns, identified a batch of in service diaphragms that were beyond their service life. Subuquent licensee actions addressing BUNA N dianbragms were conservative (Section 01.2).

• The licensee is adequately maintaining the Unit 1 high pressure coolant injection (HPCI) system in an operable condition. However, an inadequate catch funnel under a leaky steam valve and a large puddle on the floor of the HPCI pump room may be early indications of watchstander complacency and the further need for management to more frequently assess long standing leaks. The licensee exhibited a minor weakness with respect to system configuration control as indicated by the finding of an incorrect pipe label for the Unit 2 HPCI System (Section O2.1).

• The clearance and tagging program,in the area of fuse controlis very goo Performance in this area continues to improve as indicated by the decline of tagging errors. Clearance appliers are adequately trained and qualified (Section O3.1).

• The Limerick training staff ensured licensed operators satisfied the conditions of their licenna. Where appropriate, the training staff had revised the toqualification program to incorporate lesson plans and test items that addressed plant modifications and industry events. The staff tested the operators oc challenging exams that addressed appropriate areas of knowledge and skills. Performance on the exam by one observed operating crew was good and PECO staff ensured that exam administration was effective and uncompromised. The trcining evaluators critically assessnd crew and individual operator performance. The inspector concluded that the f acility had a good licensed operator requalification program (Section 05.1).

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• The Unit 1 reactor core injection cooling (RCIC) system was inopuable due to the :

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inability to control turbine speed below approximately 2800 rpm. After much {

troubleshooting and repair activity, the cause was determined to be improper .

governor valve stem runout due to an inadequate maintenance procedure. The  !

f ailure to establish and maintain an adequate maintenance procedure was treated as l a non cited violation. Overall, the follow up actions to ensure that the RCIC system :

was operable were very good (Section M1.3).

• The Nuclear Maintenance Division had established good control and oversight of on-line hydraulic control unit work activities. Technicians and operators completed the l activity without error or challenge to safe plant operations (Section M9.4).  ;

e Operators, techniclans, and engineers responded well to the failure of the Division 1 safeguards 125 vde battery charger (2BCA1). The operators controlled the load on j i the battery while technicians restored the charger to an operable conditio '

Engineers appropriately determined that a maintenance preventable functional failure had not occurred (Section M1.5). l Enaineerina f

, * From 1985 through 1997, changes were made to the A RHRSW radiation monitor l and its associated drawings and P&lDs. Each time a change was made the reviews

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were inadequate to ensure that the configuration and all of the associated drawings ,

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and P&lDs were consistent and as specified in the Updated Final Safety Analysis Report (UFSAR). This resulted in the monitor, at times, being incorrectly cont.Jured such that emergency service water was not properly monitored. This licensee '

identified and corrected violation was not cited. (Section E.1.1).

* The licensee did not revise their program for SSPV replacement and/or increased ,

frequency of inspection, and did not establish a sufficient bases for maintaining the ,

program as is in-spite of the continuing industry experience with age related l failures, in geneml, poor documentation was available regaiding scram solenoid 4 pilot valve preveatuive maintenance bases, and internal responses to industry information which discussed degradation of SSPVs. The preventive maintenance process was not consistently used to control the SSPV replacement intervals

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(Section E1.2).

• The inspector concluded that the licensee had adequately implemented the requirements of 10 CFR 50.59. Safety issues were adequately resolved and there were no significant deviations, deficiencies, or violations of NRC requirements '

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• 1he licensee has an effeulve security program. Management support for the security program was evident. The alarm station operators are knowledgeable about their duties and responsibilities and are not engaged in activities that would interfere witn their response functions. Security training is being performed in accordance "th the NRC approved training and qualification olan. Protected drea detection equipment satisfies the NRC approved Physical Security Plan (the Plan)

commitments and security equipment testing is performed as required in the Pla Maintenance of security equipment is performed in a timely manner as evidenced by minimal compensatory posting asso(lated with security equipment repairs. Based on observations and discussions with security officers, the inspector dehrmined they possess the requisite knowledge to carry out their assigned duties 6..J that the training program was effective. A review of the vehicle barrier system determined that the system was installed and was being maintained in accordance with applicable regulatory guidance and requirements. At the time of the inspection the security contractor was in labor negotiations with the security force labor unio The inspector reviewed the licensee's security force strike coretingency plans. The inspector determined that all appropriate actions had been taken to mitigate the consequences of a potential strike (Section S1).

• NRC review of the site access authorization process implementation for personnel who were denied access in 19951996 found that, generally, the process was well implemented. Some process weaknesses were corrected by the licensee. A minor violation regarding adequate notification of access denial was corrected during the inspection and was not cited (Soction S3.1).

• On October 9,1997, an Alert emergency condition was delcared when a fire occurred in an emergency diesel generator. Activities reviewed in the Technical Support Center during the Alert declaration were performed well, with conservative decisions made and thorough verifications of emergency bus operability prior to termination of the Alert. Additionally, the post event critique was comprehensive, covering all aspects of the response, including strengths and deficiencies. Actions taken and planned to address the 20 minute time delay between the Alert declaration and emergency response organization notification appear to be acceptable for resolving the issue (Section P1.1).

• The access and radiological controls implemented for fire damper inspections were adequate. When necessary a scaffold was used to support the safe work practices and the radiation work permit controls were implemented as required. in cases where the advanced radiation worker program was used to support fire damper inspections, the records generally reflect that sufficient surveys were performe However, the completed surveillance was improperly documented in that the performers did not annotate the reasons for not performing a functional test consistent with the procedural requirements. This istue was a concern because the same error was made by more than one person and then repeated in a subsequent surveillance two years later. Further, the licensee did riot initiate a performance enhancement program evaluation af ter the issue was brought to their attention until vi

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- e prompted by the inspector. Management attention is warranted to ensure a more se..ous procedural compliance problem does not exist. The documentation discrepancy was not cited due to its minor significance. (Section F3.1)

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Report Details Summary of Plant Status .

. - Unit 1 began this inspection period operating at 100%. The unit remained at full power throughout the inspection period with exceptions for testing, rod pattern adjustments, and the following plant event ;

e September 16 Operators reduced power to 76% upon finding control rod 50-27 uncoupled. The control rod was fully inserted and disabled af ter attempts to recouple the control rod apparently faile Operators restored power to 100% the same da * October 17 Operators reduced power to 70% for hydraelic control unit (HCU) maintenance following scram time testing. Several control rods f ailed to scram within the required tiri.e and were ,

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repaired. Operators returned the unit to 100% power on t October 1 Unit 2 began this inspection parlod operating at 100%. The unit remained at full power throughout the inspection period with exceptions for testing, red pattern adjustments, and the following plant events, e September 25 Operators reduced power to 83% af ter control rod 34 03 failed to scram during testing. The HCU was repaired and the unit returned to 100% power on September 2 * October 2 Operators reduced power to 56% during scram time testin Two control rods (34 27,54 27) were declared inoperable, fully inserted, and disabled due to slow scram time Operators returned the unit to 100% power, with the tw.'

control rods inserted, on October * November 8 Operators reduced power to 60% to perform on-line

. maintenance on 52 HCUs. Maintenance activities were completed and the unit returned to full power on November 1 . _ - . .- . . . - -- - . . - . .-. .

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1. Operatigna 01 Conduct of Operations'

01.1 General Comments (71707)

Using in:pection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations, in general, PECO Energy's conduct of operations was professional and focused on safoty principle .2 Control Rod Scram Failure - Unit 2 Snom_(21707)

On September 25, during the repair to a leaking scram solenoid pilot valve (SSPV)

at Unit 2, control rod 34-03 f ailed to scram using the local test switches at the hydraulic control unit 'HCU). Operators dsclared the control rod 34-03 was declared inoperable and entered the applicable technical specification (TS) limiting condition for operaticn (LCO). The inspector reviewed the interim corrective actions and discussed the f ailure with the engineering staf Observations and Firdinas During reactor protection system (RPS) functional testing, control rod 34 03 drifted when the RPS "B" SSPV was de-energized. The control rod, originally at position 48, drif ted less than one notch for a duration of 6 seconds and then settled back to position 48. Shift supervision stopped the RPS testing and initiatted an inspection of the asrociated HCU which revealed a significant air leak on one of the "A" SSPV solenoid end cap During implementation of repairs, control rod 34-03 f ailed to scram using the test toggle switchen. Operators fully inserted the control rod with no anomalies note The scram inlet and outlet valves functioned normally when air to the HCU was isolated and vented in preparation for maintenance. Technicians replaced the SSPV assembly for control rod 34-03 and subsequent scram time testing was satisfactory. An evaluation of the failed SSPV revealed that all 4 BUNA N diaphragms had hardened with some cracking noted. The inspector determined that a single rod f ailing to scram was accounted for in the shutdown margin specification. Additionally, the diverse backup scram feature would have likely caused rod 34-03 to scram, but not necessarily within the time required by technical specifications 1 Topical headings such as 01, MB, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline tople i

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To address generic implications of the f ailure, scram time testing was performed on 18 additional control rods (30% of the 60 rods) with BUNA-N diaphragms in service for 4.5 years. The sample selected included 7 SSPVs that were also found to be leaking. Of the additional control rods tested, two control rods were found to be slow (marginally exceeding the average time specification to position 45). S;nce the >

average scram time for each control rod was w' thin the TS lirait the licensee planned to replace the associated SSPVs at a later opportunity. Based on the repairs and satisfactory retest of control rod 34 03, and since no other rods f ailed to scram in the sample population, the licensee concluded that no further short term action was required. The licensee also implemented weekly monitoring for SSPV external air leakag The inspector questioned the bases for not performing scram time testing on the remaining population of similar SSPVs (approximately 42 control rods), and for not evaluating the generic implications for Unit 1. Management stated that they had addressed all TS requirements and generic implications via a 30% sample of timilar diaphragms inclWing all leaking SSPVs identified. Further, management was looking at the f ailed SSPV to determine if the f ailure was consistent with industry experience, was evaluating industry information concerning leaking SSPVs and control rod failures to scram, and would compare the trend of control rod 34 03 to other rod trend The inspector determined that the f ailure mechanism remained unclear, since no cause and effect relationship could be established. Although, the licensee postulated the control rod f ailure to scram related to diaphragm hardening and the air leak, no previous surveillance test.ng had predicted the failure and no anomalous evidence suggested a different reason for the failur Following several conference calls with NRC staff, tha licensee expanded the interim corrective actions to include scram time testing of all Unit 2 control rods containing BUNA N SSPVs and a sample of the control rods containing BUNA-N on Unit The in-service time for the Unit 1 BUNA N SSPVs was less than 4 years. The licensee had the vendor perform a failure analysis, and a material analysis to determine the service life of the diaphragm for control rod 34 0 The GE failure aaalysis concluded that control rod 34-03 f ailed to scram as a result of cracks in the diaphragm which prevented the establishment of the differential pressures necessary to actuate the valve. This evaluation also concluded that the external leaks in the SSPV did not contribute to the f ailure, but were indicative of diaphragm hardening. The material analysis found that the batch of diaphragms from which the f ailed diaphragm was a part, had a service life of 4.25 years. Other diaphragm material tested was found to have an end of life at 4.85 years. The analysis also found evidence of contaminants that could result in accelerated diaphragm aging. The inspector determined that following the f ailure of control rod 34 03 to scram, three other control rods had diaphragms beyond the 4.25 year predicted end of lift . Also, three additional control rods on Unit 2 and seven at Unit 1 had diaphragms from this batch, but were scheduled for replacement prior to exceeding the 4.25 year life of the diaphragms.

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The inspector determined that the licensee did not initially test all control rods with similar SSPV diaphragms nor established a sufficient bases for not testing the associated control rods. Although the licensee ultimately tested the BUNA N population of concern, following a series of conference calls with NRC staff, the interim actions were not consistent with the events of diaphragm failures occurring in less than 4 years in service, within the industry and the f act that licensee had not implemented the vendor recommended periodic sampling inspections of diaphragms to continually verify in service conditions (Section E1.2). in addition, a control rod failure to scram occurred during the Unit 2 startup in March 1997, an evalustion found no conclusive root cause and provided the first evidence of detrimental contamination on the diaphragms, not previously seen at Limerick. The inspector categorized the two slow rods, identified during the initial testing sample, as test failures since the slow scram times may have been indicative that the diaphragms were degraded and may have been approaching f ailure. The inspector determined that 3 of 19 test failures was a significant failure, since there was no analysis for the f ailure of multiple control rods to scram via normal metho Consequently, the failure of multiple control rods to scram via normal methods would have resulted in an unanalyzed condition. However, subsequent testing of all effected control rod confirmed no unanalyzed condition existe Throughout the remainder of the inspection period the licensee took conservative action by replacing several slow or leaking SSPVs, and by inserting a control rod for a suspect batch of BUNA N diaphragms until the SSPV could be replaced. By the end of the inspection period, the licensee had replaced all Unit 2 SSPVs containing BUNA N diaphragms. The licensee also plans to replace all Unit 1 SSPVs containing BUNA N diaphragms no later than the end of January 1998. This replacement schedule will ensure all BUNA N SSPVs including the suspect batch are replaced prior to the end of life, c. Conclusion Operator response was excellent for an unexpected control rod drift observed during reactor protection system (RPS) testing at Unit 2. A leaking scrarn solenoid pilot valve (SSPV) was identified and ultimately a control rod failed to scra Subsequent control rod testing fc,und several other degraded / leaking SSPV diaphragms that caused slow rod travel but no other f ailures to scram occurre However, PECO Energy did not perform a prompt and comprehensive assessment of generic and common modo concerns, and did not !nitially verify whether an unanalyzed condition existed. A number of confarence calls occurred between licensee staff and NRC management result;ng in further testing and analysis. The vender materials analysis performed in response to NRC concerns, identified a batch of in-service diaphragms that were beyond their service life. Subsequent licensee actions addressing BUNA-N diaphragms were conservative (Section 01.2).

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5 02 Operational Status of Facilities and Equipment O2.1 Enaineered Safety Feature Walkdown - Hiah Pressure Coolant inlection Insoection Scone (71707)

On October 16 and 17, tho inspector performed a detailed walkdown of a representative sample of the accessible portions of the Unit 1 high pressure coolant injection (HPCl) system. The objective of the walkdown was to verify that the system lineup and as built condition matches plant procedures and drawings and to identify equipment conditions that could degradn system performance. Additionally, the condition of all equipment and the general surroundings was observed. A similar, but less rigorous walkdown of the Unit 2 HPCI system was performed on November Observations and Findinas The inspector found all valve positions to be correct for a normal, ready for-automauc operation lineup as indicated on the applicable P&lD's and the equipment lineup check-off list. The inspector surveyed all steam and water piping between the primary contair. ment penetrations and the HPCI turbine / pump skid excluding a small portion of the skid mounted steam drain piping and most of the skid mounted lobe oil and control oil system piping. The inspector observed that all Unit 1 valve and pipe labels were present, legible, and correct. However, the inspe': tor identified on Unit 2 that the last section of the main HPCI pump discharge piping before the tee with the Core Spray (CS) System was incorrectly labeled as CS piping. The inspector observed two adverse housekoeping conditions at Unit 1:

• Steam leakage through the stem packing of the steam isolation bypass valve (HV 1F100) was causing significant condensation that wetted lagging. Also, the radiological waste catch funnel was insufficient in size to catch and contain all condensate dripping from the lagging. An equipment trouble tag attached to the valve indicated that the leak had been present since February 3,199 * A large puddle (approximately 3 X 6 feet) on the floor of the HPCI pump room evidently from a leaking cooling water drain valve for tho HPCI toom cooler cooling coil. The puddle was discovered with a small towelin the middle of it potentially indicating an ettempt to clean up the leakag However, dried mineral deposits severalinches from the entire periphery of the puddle indicated that the puddle had been stagnant for a long period of time such that significant evaporation occurred, Both of these adverse conditions had been long standing and escaped appropriate operator attention and/or corrective action until discovered and reported by the inspecto . _ _ _ _ . - _ _ _ _ . _ _ . _ _ _ . _ _ _ .. _ _ . . _ _ _ _ _

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The inspector related these findings to the licensee and they were immediately addressed. The licensee reassessed the steam isolation bypass valve steam leak and determined that the leak rate did not pose an immediate operability concer The catch funnel under the leak was enlarged to adequately catch the condensatio The puddle on the HPCl room floor was cleaned up and the cooling water drain  !

valve flushed and shut tightly to prevent further leakage. The incorrect pipe label on the Unit 2 HPCI pump discharge line was replaced.

, Conclusions The licensee is adequately maintaining the Unit 1 HPCI system in an operable

condition. However, an inadequate catch funnel under a leaky steam valve and a large puddle on the floor of the HPCI pump room may be early indications of watchstander complacency and the further need for management to more frequently ,

assess long standing leaks. The licensee exhibited a minor weakness with respect j to system configuration control as indicated by the finding of an incorrect pipe label

. for the Unit 2 HPCI syste Operations Procedures and Documentation 03.1 Clearance and Taaaina - Fuses , insoection Scope The inspector reviewed the program for the control of fuses during work activitie The inspector reviewed the guidance in the Clearance and Tagging Manusl; Operation Manual Section OM-L 7.6, Fuse Control; and OM-C-10.4, Unavailable Equipment / Equipment Fielease. Further, the mspector reviewed the Operations Department Self Assessment in the area of clearance and tagging of fuses and associated Performance Enhancement Program (PEP) evaluations regarding tagging errors and the corrective actions implemented. The inspector discussed clearance and tagging of fuses with several representatives in the Operations Departmen , Observations and Findinas Specific guidance for the clearance and clearance restoration processes exists in the '

Clearance and Tagging Manual, Section 7.7, Fuse Control Standards, and in the other references stated above. Positive fuse identification including, panel number, terminal board number, fuse number as well as any further physical description is .

required to be listed on the clearance paperwork. Further, all clearance points must be annotated on the clearance sheets and the clearance applier must have the clearance in hand and sign for all tags applied. The inspector observed several clearance applications in the field and noted that the clearance was in-hand, that the applier was knowledgeable and cognizant of his tas The current fuse clearance and tagging process evolved out of several tagging errors that had occurred in 1994, in 1994, three significant fuse tagging errors were made within an eight month period that involved: a Unit 2 recirculation pump

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trip; a Unit 1 inadvertent emergency safety feature (ESF) actuation; and an incorrect fuse removeJ on the D-21 emergency diesel generator while applying a master clearance. The root causes identified for these events included, poor labeling, lack of supervisory oversight, and incorrectly written clearance. A common csuse ir, cach of the above events was poor attention to detail by the operator. Following the third event, the NRC issued a Notice of Violation to the licensee (50 353/94 2101).

The inspector noted an overall improving performance trend in clearanua and tagging, including fuse control. A review of PEP data and Operations Self-Assessment data identified an overall decline in fuse tagging errors. This is, in part,

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due to the Event Free Operations (EFO) program that Operations Management established in late 1995, to assess and promote event free behaviors and attribute This year through October, a total of only 12 tagging error have occurred, of which zero were due to fuse error All clearance appliers receive initial ' raining and are required to complete a clearance and tagging cualification manual. On-going training occurs throughout the year and is performed by the clearance office. Review of significant tagging events occurs during requalifice. tion training at the training center. The inspector determined that operator training was adequat Conclusion The clearance and tagging orogram,in the area of fuse controlis very goo Performance in this area continues to improve as indicated by the decline of tagging errors. Clearance appliers are adequately trained and qualifie Operator Training and Qualification 05.1 Mcensed Ooerator Reaualificalion Fronram Insoection Senge (71001)

From November 3 7, the inspector evaluated the Limerick licensed operator requalification training program, Qhservations and Findinog Reaualification examinations: The inspector reviewed ten simulator scenarios and noted the training staff incorporated system changes, procedure changes, and industry events into simulator examinations, when applicable. For example, the staff revised a scenario to include a malfunction that mimicked problems operators had encountered when a reactor feed pump motor governor unit malfunctioned following a reactor scram that occurred earlier this year. The inspector also determined that the operating tests adequately sampled appropriate knowledge and peiformance abilities for reactor and senior reactor opere+ or _ . - _ . __

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8 Examination administration oractices: The inspector observed the training staff evaluate one operating crew (eight operators) on four scenarios. The evaluators, which included the senior manager of operations, satisf actorily assessed crew and individual operator perfor nance. All operators passed the exam, which was consistent with the inspector's assessment of performance, in the area of exam integrity, the inspector did not detect any indications of exam compromis Feedbagk system: The inspector reviewed a representative sample of licensed operator comments and noted the training staff effectively implemented feedback where appropriate. For example, the inspector noted a comment in which an operator questionod the clarity of an exam question. The feedback system tracked this comment, the staff determined the comment was valid, and subsequently revised the questio Operator license conditions: The inspector reviewed records for the reactivation of operator licenses from January 1996 through November 1997 and noted that operators satisf actorily reactivated their licenses. Also, based on a review of eight operator medical records (roughly 10% of all operator licenses), the inspector determined operators were receiving the biennial physical exam Caps _lusionti The Limerick training staff ensured licensed operators satisfied the conditions of their licenses. Where appropriate the training staff had revised the requalification program to incorporate lesson plans and test items that addressed plant modifications and industry events. The staff tested the operators on challenging exams that addressed appropriate areas of knowledge and skills. Pe formance on the exam by one observed operating crew was good and PECO staff ensured that exam administration was effective and uncompromised. The training evaluators critically assessed crew and individual operator performance. The inspector concluded that the f acility had a good licensed operator requalification progra Miscellaneous Operations issues (90712)

08.1 INPO Report Reviqw During this inspection period, the inspector reviewed the INPO Interim Report dated July 7,1997: the evaluation team inspected at Limerick Generating Station from May 12 through 24,1997. The findings in the report, both positive and negative, were consistent with recent findings of the Nuclear Regulatory Commissio _- - -

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II. Maintenance M1 Conduct of Maintenance M 1.1 General Comments on Maintenance Activities (62707)

The inspectors observed selected maintenance activities to determine whether approved procedures were in use, dettJls were adequate, technical specifications were satisfied, maintenance was performed by knowledgeable personnel, and post-maintenance testing was appropriately complete The inspectors observed portions of the following work activities:

• Unit 1 HCU maintenance replacement of SSPVs, October 18;

• Unit 2 HCU maintenance - replacement of SSPVs, November 81 Observed maintenance activities were conducted well using approved procedures, and were completed with satisf actory results. Communications between the various work and support groups were good, and supervisor oversight was goo M1.2 General Coriments on SyJvellance Activities (61726)

The inspectors observed selected surveillar'ce tests m determine whether approved procedures were in use, details were adequate, test instrumentation was properly calibrated and used, technical specifications were satisfied, testing was performed by knowledgeable personnel, and test results satisfied acceptance criteria or wure properly dispositione The inspectors observed portions of the following surveillance activities:

• Unit 1 HPCI Quarterly Surveillance Test, September 24;

• Unit 2 D21 Weekly Surveillance Test, September 25;

• Main Control Room SCBA Test, Septembcr 26;

• Unit 2-HPCI Quarterly Surveillance Test, September 29;

• Unit 2-D21 Post Overhaul Special Testing, October 29; and e Unit 2-D2124 Hour Endurance Test and Hot Restart, October 3 Observed surveillance tests were conducted well using approved procedures, and were completed with satisf actory results. Communications between the various work and support groups were good, and supervisor oversight was goo _- _ _._ _ _ _ _ _ __ _ _ _ __ .__ _ _._ ___ _ _ _ _. _ ___

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On September 10,- during a quarterly surveillance test, plant personnel observed that the Unit i RCIC turbine would not operate at less than 2800 rpm. The inspector observed the response to the event, and discussed the root causes and corrective actions to restore the system to a fully operable statu ; Qbgtystions and Findinas ,

On September 10, at the conclusion of the quarterly RCIC surveillance test,

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operators attempted to manually reduce turbine speed to approximately 2500 rpm prior to tripping the turbine. However, operators were unable to reduce the turbine ,

speed below 2800 rpm. Subsequently, the inspector observed engineering  :

personnel manually stroking the governor valve to verify there was no binding; no binding was observed. After consulting with an industry expert and concluding that ,

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there was not an electrical problem, personnel restarted the pump; turbine speed '

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could not be reduced below approximately 2700 rpm. However, light agitat;on of 1

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the valve's servo piston resulted in the ability to reduce speed to below 2400 rpm; therefore, maintenance personnel replaced the valve's servo. During the post-maintenance test, turbine speed could not be reduced below 2800 rpm, and on

subsequent runs, after other adjustments, speed control was not improved. The ,

governor valve was disassembled and indications were found on the stem; the stem

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was repicced. The pump was rerun and turbine speed could not be reduced below

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2800 rpm. Engineering personnel concluded at this point that the problem could be

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electrical, so a loop check of the control system was performed. A damaged wire was discovered in the EGR, which was sent out for failure analysis, and the EGR

was replaced. Additionally, the speed sensor was found worn, so it was replace The pump was run for EGM/EGR tuning, and afterwards, turbine speed could not be reduced below 2800 rpm. The governor valve was disassembled again, and it was

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discovered that the stem to plug runout (alignment) was unacceptable. The stem runout was properly set, and the subsequent pump runs were satisf actory in that speed control was proper at all speeds. Following these succesaful runs, the RCIC system was declared operable; the system had been inoperable for approximately 10 days of the 14 days allowed by technical specification During the troubleshooting and repair activities, the inspector observed various

. activities, and attended meetings where action plans were discussed and develope Very good management attention was observed, and engineering support and coordination with an industry expert were excellent. The inspector was concerned 1 about the length of time the system was inoperable and unavailable, but it appeared that personnel were actively pursuing the most probable root causes at all time Through discussions with engineering personnel, the inspector determined that the maintenance procedure for performing the RCIC governor valve maintenance was inadequate; the step for measuring the valve stem runout was identified as incorrect. Corrective actions included correctir.. the procedure step and properly adjusting the governor valve runout. Inspection of the Unit 2 RCIC system for L

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similar conditions was planned af ter the next scheduled run. The inspector reviewed all of the procedure's prior revisions and noted that the step had not been changed. It appears that although the procedure has always been incorrect. either the step was properly performed in the past, possibly due to vendor oversight, or the valve runout aid not need adjusting. Additionally, engineering personnel indicated that if the condition had not been identified and corrected, it could have deteriorated to a condition where speed control at higher speeds would have been a proble Technimi Specification 6.8.1 requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 197 Appendix A of Regulatory Guide 1.33 specifies procedures for maintenance that can affect the performance of safety related systems. The PECO Energy procedure for RCIC turbine govemor valve maintenance was not properly established, in that it provided incorrect guidance for measuring valve stem runout. This non repetitive, licensee identified and corrected violation is being treated as a Non Cited Violation, consistent with Section Vll.B 1 of the NRC Enforcement Policy. (NCV 50 352/97-08-01) Conclusions The Unit 1 RCIC system wcs inoperable due to the inability to control turbine speed below approximately 2800 rpm. Af ter much trcubleshooting and repair activity, the cause was determined to be improper governor valve stem runout due to an inadequate maintenance procedure. The f ailure to establish and maintain an adequate maintenance procedure was treated as a non-cited violation. Overall, the follow up actions to ensure that the RCIC system was operable were very goo M 1.4 Hydraulic Control Unit On line Maintenance - Unit 2 [Dipection Scone (62707)

PECO Energy's Nuclear Maintenance Division (NMD) performed an on-line maintenance outage on selected Unit 2 HCUs beginning on November 8. The maintenance focused on replacing the scram pilot valves. Maintenance technicians used maintenance procedure M 047-027, Preventive Maintenance for HCUs, throughout the activities. NMD technicians rebuilt 52 HCUs over a three day period, completing the activity on November 11. The inspector observed the activities performed at the HCU _ _ - _ _ - _

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12 Observations and Findinas Work Activities were planned, coordinated, and executed well between the Operations and NMD Departrr.ents, and the reactor engineering staff. Operato.s and reactor engineers pe-formed a large number of control rod manipulations wi'.hout error. Further, NMD personnel performed clearance and tagging responsibilitier, maintenance activities, and HCU restoration without error. Following HCU restoration, operators performed scram time testing to verify the control rod's operability. No discrepancies were identified, Concluid The Nuclear Maintenance Division had established good control and oversight of the work activities. Technicians and operators completed the activity without error or challenge to safe plant operation M1.5 Division 1 Safeauards Batterv Chamerf ailure - Unit 2 Insocction Scong (62707)

The Division 1 safeguards 125 vde battery charger (2BCA1) f ailed on October 1 The control room staff declared the battery inoperable and entered an eight-hour TS LCO. The inspector reviewed the cause of the f ailure and corrective actions taken to restore the charger to service. Further, the inspector evaluated the operability determinatian and reviewed the f ailure to determine if the f ailure was a maintenance preventable functional f ailur Observations and Findinos The operator responding to the battery charger trouble alarm that annunciated in the main control room, found the de output breaker in the tripped position. The battery (2A1) was supplying the de safeguard loads while the battery charger was disconnected from the de bus. The operator secured the battery charger and the control room staf f minimized unnecessary loads carried by the battery to reduce the output current from the battery I&C technicians troubleshooting the battery charger found that one of the eight filter capacitors had f ailed. The capacitor was leaking and extremely hot. The other seven capacitors were verified to be intact and within their normal parameters. The technician replaced the f aulty capacitor, checked fuses and other components, and returned the charger to service without further incident. The f ailed capacitor was sent to the corporate laboratory for f ailure analysis and was determined to be the cause for the de output breaker of the charger 2BCA1 to trip ope The engineering staff concluded that a functional f ailure had occurred. Battery charger 29CA1 and battery 2A1 are considered a train. Loss of either component would constitute a functional f ailure for the train, regardless of the condition of either component. Since the battery charger's output breaker tripped, the charger

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could no longer perform its function to supply de to the Division 1 safeguard load However, the engineers determined that no maintenance preventable functional f ailure occurred. No indication existed that the capacitor had been installed incorrectly when it was replaced during 2R03 in 1995, or was subjected to improp*r maintenance practices, Conclusions Operators, technicians, and engineers responded well to the f ailure of the Division 1 safeguards 125 vJc battery charger (2BCA1). The operators controlled the load on the battery while technicians restored the charger to an operable conditio Engineers appropriately determined that a maintenance preventable functional f ailure had not occurro Ill. Engineering E1 Conduct of Engineering E 1.1 Residual Heat Removal Service WateL[RHRSW) Radiation Monitor Insoection Sesoe (37551)

On October 15, licensee personnelidentified that the A RHRSW radiation monitor was incorrectly configured, in that, its supply line was, upstream of the emergency service water (ESW) return. The inspectors walked down the system, reviewed the associated P&lDs, discussed the configuration problem with engineering and health physics personnel, and reviewed the corrective actions taken, Observations and Findinas During, a walkdown of the RHRSW radiation monitoring system, site contracted personnelidentified a discrepancy in the configuration of the A RHRSW radiation monitor sample line, in that it was located upstream of the ESW return line. The Lirnerick Updated Final Safety Analysis Report (UFSAR) states that the common RHRSW radiation monitors sample both RHRSW and ESW. The A RHRSW radiation monitor was declared inopcrable and chemistry personnel were directed to sample the system downstream of the ESW discharge to the RHRSW once every 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to meet Offsite Dose Calculation Manual (ODCM) actions. The configuration of the piping was changed so that the supply and return lines were swapped prior to the end of the inspection period; this resulted in the supply line sampling both RHRSW and ESW as specified in the UFSAR. Additional corrective actions taken included verifying that the B RHRSW radiation monitor was properly configure Investigation by plant engineering personnel determined the following:

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• In 1985, management recognized that the A RHRSW radiation monitor configuration was not in agreement with the UFSAR description, sin e the sample tap was upstream of the LSW line; the condition was correcte * In 1989, the A RHRSW radiation monitor sample lines were upgraded and replaced with stainless steel piping. The sample line was incorrectly installed upstream of the ESW line, since the construction drawings incorrectly referenced original sample location i

• In 1990, the isometrics were revised to reverse the sample inlet and outlet i valves, and reverse the flow arrows to reflect the changes made in 1985; the plant configuration remained in erro * In 1995, during a system walkdown, a contractor identified a discrepancy between the cetual plant configuration and the P&lD; the P&lD was change At this point buth the plant configuration and P&lD were incorrect, but  !

consistent with each othe Engineering personnel concluded that each time the system and drawings were changed the reviews were inadequate, since they did not ensure that the system configuration and all of the drawings were as required. Based on a review of system history, and spray pond sampling, management concluded that no unmonitored releases occurred during the periods of time the configuration of the A RHRSW radiation monitor was incorrect. This non repetitive, licensee identified and corrected violetion, for inadequate engineering reviews resulting in an inadequate  ;

configuration, is being treated as a Non-Cited Violation, consistent with Section Vl!.B.1 of the NRC Enforcement Policy. (NCV 50 352,353/97 08 02)

i Conclusigna From 1985 through 1997, changes were made to the A RHRSW radiation monitor and its associated drawings and P&lDs. Each time a change was made the reviews were inadequate to ensure that the configuration and all of the associated drawings and P&lDs were consistent and as specified in the UFSAR. This resu;ted in the monitor, at times, being incorrectly configured such that ESW was not properly monitored. This iicensee identified and corrected violation was not cite E1.2 Scram Solenoid Pilot Valve Preventative Maintenanca fggns As a result of the f ailure discussed in Section O2.1 of this report, the inspector performed a review of the preventive maintenance program for control rod drive scram solenoid pilot valves (SSPV). Specifically, the inspector assessed the replacement frequency SSPV diaphragms. The inspector reviewed licensee documentation and discussed the issue with the license i

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b. Qhiervations Lid Find!nas Based on discuss. ions with the licensee, the inspector determined that prior to 1993, the preventative rnaintenance replacement 'requency for SS9V diaphragms was every six refueling outages (approximately a 9 year interval). However, the practice at that time was to replace one third of the SSPVs ev3ry outage on a rotating bases. THs pre:ticed resulted in an approximate replacement frequency of years as a result of the eighteen month cycle length at that time. By the eno of 1993, the replacement frequency had been revised to a 6 year periodicity, based on a reliability crntered maintenance (RCM) analysis. The licensee stated that the analysis considerad SSPV performance data (industry and Limerick specific) along with vendor recommendations including a July 1989 response from the vendor concerning Unh 2 SSPV diaphragms service life (which recommended 3 to 4 years cf in service s.fo based on specific operating parameters).

The inspector determined that although the vendor recommended a replacement interval of 3 to 4 years of in-service life, the licensee established a 6 year interval based on perfntmance data from SSPVs replaced at a 4.5 year interval. In addition, the licensee could not provide or re-create the performance data that was used as input for the SSPV replacement interval determination. Subsequent to establishing the 6 year interval, the licensee established an on-line program for SSPV replacements that allowed the ability to leave the SSPVs in service longer since the maintenance was no longer constrained to refueling outage period In October 1993, General Electric (GE) recommended a four year service life for the valves, with extension possible on a plant specific basis after examination of diaphragms discussed in Service information Letter (SIL) 575 "CRD Slow Start of Motion." The licensee stated that this recommendation was not implemented due to the lack of cinificant scram time degradation data and because the threshold for replacement of SSPVs was set well below the criteria established in TS Specifically, for any rods that showed marginal degradation in scram times, the SSPVs were replaced. The SSPVs diaphragms inspected after routine replacement generally showed no evidence of significant degradatio The engineering staff had several opportunities to evaluate and addrecs degraiation of SSPV diaphragm * On May 2,1994, GE issued Rapid Information Communication Service info mation Letter (RICSIL) 069, " Scram Solenaid Pilot Valve Diaphragm Degradation." The RICSIL discussed events at two plants involving a control rod f ailure to scram during scram time testing, and multiple control rods f ailing to meet the scram time specification. In both cases the problems involved degraded SSPV diaphragms which had been in service for less than four years for the rod that f ailed to scram and less than three years for the rods with slow scram time * On May 11,1994, revision 1 to RICSIL 069 provided further information and recommended interim corrective actions foi SSPVs rebuilt af ter early 198 ________

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The RICSIL discussed a material analysis that showed a more rapid degradation of the diaphragms when compared to previous experience, most probably a result of changes in the BUNA-N material. The recommended dClions included: identifying SSPVs that were refurbished or replaced two or more years earlier using diaphragms with essembly of 1989 or af ter; for SSPVs identified in the first recommendation, removing diaphragms from a sample (minimum of three recommended) of the SSPVs and examining for cigns of cracking or excess hardening; and if the evaluation indicated near end-of life conditions, replacement of the diaphragms. Although the licensee stated that both revisions of RICSIL 069 were reviewed, no documented evidence of the review or recommended acOns existe * In July 1994, GE issued a 10CFR Part 21 notification due to further occurrences of slowing and a failure of one rod to scram at another facilit The Part 21 safety basis of allowing the valves to remain in-service was delineated based on a review of a significant number of slow tod insertions following a scram and two f ailures of rods to insert following a scram. No further corrective actions or preventative measures over those established in RICSIL 069, revision 1 were identified. Utilities were requested to review the RICSIL and implement the interim recommendations. The licensee's internal response referenced the response to RICSIL 069, revision 1 (winich could not be found), but also discussed the BUNA-N population of concern at Limerick, which was one of the recommended actions, in addition, the licensee disassembled and visually inspected one SSPV and found no abnormalities. The diaphragms were also sent to GE who confirmed that there was no evidence of premature degradation. However,in retrospect the diaphragm provided was not the post 1988 material of concern. The licensec's documentation also discussed that a review of historical scram times did not reveal any adverse trends and that in some cases the observed scram times improve * On October 4,1994, the NRC issued Information Notice 94 71, which provided more detaikd information for the f ailures addressed in RICSIL 06 This correspondence provided the licensee another opportunity to evaluate and address degradation of SSPV diaphragms. However, the licensee's internal documentation again referred to the responso to revision 1 of the RICSIL In addition, the licensee's response also discussed that two SSPVs with approximately 6 years of service life were inspected and showed no signs of degradation. However, again in retrospect the licensee was not certain if these diaphragms were post 1988 vintag * On October 12,1994, GE issued RICSIL 069, revision 2, which identified an additional plant that had a control rod fail to scram. This revision of the RICSit also specified, as an additional interim recommendatien, unless inspections indicate otherwise, plan to replace diaphragms af ter 3 years of service. The licensee's internal documentation again stated that the response to revision 1 of the RICSIL was still applicabl _ . _ _ _ . . _ . _ _ _ . - . .. -

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The inspector found that the licensee did not trend the scram time data. Instead the licensee uses a threshold value to declare a scram time as slow and then implements prcmpt corrective maintenance. The licensee had determined that data scatter was inhibiting the ability to trend SSPV performanc The inspector determined that, in 1994, the licensee did not revise the SSPV replacement frequency nor establish a sufficient bases for maintaining the 6 year intervalin-spite of the continuing industry experience indicating a more rapid aging than previously experienced, evidence of different causes and increased uncertainty in predicting SSPV service life. Instead the licensee relied on past performance of primarily pre 1989 SSPVs without the capability to accurately trend scram times and thus the ability to predict failures. Further, the replacement interval became longer as a result of the ability to do on-line replacement GE SILs 584 and 585, issued in January 1995, further explained the phenomenon relation to the BUNA N diaphragms of the SSPV's. The valves showing more rapid degradation were manuf actured 1989 ar d later, and the degradation was linked to a combination of the formulation process and possible contaminants. Sll 584 recommends actions consistent with RICSIL 069 but also added a recommendation to repeat the sampling inspections, on post 1938 diaphragms with greater than 2 years in service, at approximately a six month interval. However, the licenses did not implement this new recornmendation nor did they establish a bases for not performing the periodic inspections. SIL 585 recommended good maintenance practices relating to valve rebuilds and checking air systems for contaminants. The recommended maximum operating life of four years assuming a clean air system and contaminant free maintenance and installatien practices. The licensees internal response again referred to the previously discussed RCM analysis that determined six years to be the appropriate diaphragm replacement frequenc The inspector determined following the issuance of SIL 584, the licensee did not implement routine SSPV sampling inspections as recommended nor did they establish a bases for not performing the recommended inspections. These periodic inspections were not only to establish the SSPV service life; but also to routinely confirm the predictior.. Had the routine inspections been performed, they may have identified the ba*ch of DUNA N with a significantly shorter life discussed in Section 01.2 of this repor During Unit 1 scram tiniing performed on February 21,1995, signs of performance degra lation were identified. Subsequently, following corrective maintenance in May 1995, a samplo of tiie diaphragmc were sent to GE for analysis. Two sets of diaphragms,in service for 4 years and 7 months, were evaluated at near end of-life conditions. GE recommended replacement by August 1995. The licensee replaced the identified batch in July of 1995. Subsequent batches on both units were targeted to be replaced so as not to exceed a 4.5 year in service lifetime. This replacement frequency was based on providing a margin to the 5 year service life determined by GE, for the batch analyzed and the indication by GE that the diaphragms at Limerick are maintained in good operating conditio . . - . . . .

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The inspector d6termined that the licensee was informally implementing the replacement periodicity instead of using the preventative maintenance process described in A C-028 " Preventative Maintenance Program," to implement the necessary change to the diaphragm replacement interval. In addition, following acknowledgment of the issue, the licensee did not initiate a PEP evaluation. As of the end of the period when asked if a PEP was warranted, the licensee stated that the issue was still being evaluated, in general the documentation available related to scram solenoid pilot valve preventative maintenance and internal responses to industry information which discussed degradation of SSPVs was poor. Specifically, there were no records available to establish the initial bases for or subsequent changes to the SSPV preventative maintenance frequency. For example, the licensee could not provide a comprehensive analysis to support the reliability centered maintenance conclusions concerning the SSPV replacement interval, in addition, the licensee did not create or maintain complete documentation of the assessments performed to address the applicability of the industry experience to Limerick. For example, there was no evidence that the licensee reviewed RICSiL 06 Conclusion The licensee did not revise their program for SSPV replacement and/or increased frequency of inspection, and did not establish a sufficient bases for maintaining the program as is in spite of the continuing industry experience with age-related f ailures. In general, poor documentation was available regarding scram solenoid pilot valve preventive maintenance bases, and internal responses to industry information which discussed degradation of "SPVs. The preventive maintenance process was not consistently used to control the SSPV replacement intervals (Section E1.2).

E2 Engineering Support of Facilities and Equipment E QFR 50.59 Safety Evaluation Proaram Scope An evaluation of the licensee's program to implement of the requirements of 10 CFR 50.59 was performed. The inspection addressed the principle areas: (1) Procedures and Controls; (2) Training and Qualifications, and (3) Implementation, which involves the performance of Determinations, Safety Evaluations of Unreviewed Safety Questions (USQ). The inspector reviewed relevant procedures and controls, training records, and other administrative controls, listed in Encloture 1. Enclosure 2 provides a list of PECO Energy Company personnel that the inspector interviewed during this inspectio .

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19 Observations and FindiD M The review of the documents included the screening of 133 safety evaluations implemented 9t the Lims, rick Generating Station between July 1,1995 and June 30, 1997. The Inspector selected fourteen reports for review. These reports included:

three Modifications (MOD), one Non-Conformance Report (NCR), eight Engineering Change Requests (ECR), one Procedure evaluation, and one Commitment revie Enclosure 3 provides a list and brief description of these fourteen package The inspector found that the licensee formal procedures were complete and provided adequate details. Also these procedures were found to be consistent with NRC 10 CFR 50.5 The inspector determined that the required training is provided to the preparers, peer-reviewers, PORC members and alternates, station qualified Procedure Changes reviewers and approving superintendents. Further, the inspector noted some aspects of the licensee's efforts toward self assessment with regard to 10 CFR 50.59 safety evaluations. These self assessment efforts include a yearly self assessment by engineering, periodic self assessments by QA, and re evaluation through the licensee's PE Conclusions The inspector concluded that the licensee had adequately implemented the requirements of 10 CFR 5'?.59. Safety issues were adequately resolved and there were no significant deviations, deficiencies, or violations of NRC requirement E8 Miscellaneous Engineering issues E (Closed) LER 1-97-007.lsolation of the Reactor Water Clean-un System an Ennineered Safety Feature. Resultina from Lif tina of a Filter Demineralizer Pressure Satetv Valve Caused Bv Sotooint Drift This event was discussed in NRC Integrated inspection Report 50-352/97-07,50-353/97-07, and resulted in an Inspection Follow-up Item. The inspector noted that for this particular event, the setpoint of the pressure safety valve had drifted fairly significantly. Also, the valves have been in service for approximately 10 years, and have not been in the preventive maintenance program, and therefore have not had their lif t setpoints checked periodically. The LER met the requirements of 10 CFR 50.73,6nd no additional issues were identifie _ _ _ _ _ _ - - _ _ __ _ _-

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IV. Plant Support P1 Conduct of Emergency Preparedness Activities P 1.1 Runonse to Emeroency Diesel Generator Failure Inspection Scooe (93702)

The inspector evaluated the response of the Emergency Response Organization (ERO) and the activation of the emergency f acilities during a plant that took place on October 9, at 11:02 p.m., to verify if the response was in accordance with the Emergency Plan, Emergency Response Procedures (ERP) and met NRC regulatory requirements. The inspector responded to the Technical Support Center during part of the Alert and reviewed the activities prior to Alert term! nation. Additionally, the inspector attended the post event critique, Qblervations and Findiring A crankcase explosion and fire occurred in the exhaust stack and exhaust manifold at the number one cylinder in the Unit 2 D21 emergency diesel generator (EDG) at 11:02 p.m. Though the fire was c (tinguished by 11:04 p.m., the shif t manager declared an Alert emergency classification at 11:10 p.m. In accordance with ERP-1015," Classification of Emergencies." The State, County and Federal officials were notified by 11:21 and the ERO was notified by 11:30 p.m. via personal electronic pagers. Pe sonnel activated the Technical Support Center, Operations Support Center and minimally staffed the Emergency Operations Facility for standby in case the event was to escalate to a Site Area Emergency. The Alert was terminated at 3:05 a.m. on October 10, following the verification and determination that the event was limited to the f ailure of the D21 EDG, The D21 f ailure, its root cause and corrective actions taken will be reviewed in a separate NRC Inspection Report 50 353/97 0 Under the " Fire * Category described in ERP 1015,if there is a " potential" threat of losing an Engineering Safety System (Class IE power supply buses) personnel are to declare an Alert. The inspector reviewed the emergency action level tables and determined the Alert declaration was made in accordance with the procedure The inspector reviewed the " Emergency Notification Log" sheets and verified that notifications to the of fsite agencies were timely and met NRC 10 CFR Part 50, Appendix E, requirements. The " Emet fency Response logs" were properly maintr.ined and checklists contained in the ERPs were followed and filled ou However, the ERO response pager notifications were not initiated until approximately 20 minutes af ter the Alert declaration. The inspector discussed this matter with PECO Energy emergency preparedness management because of the length of time between the declaration and notification to the ERO responders which resulted in activation of the Technical Support Center nearly one and one half hours af ter the Alert declaration. They stated that their current notification process is to personally make individual telephone calls to notify the State, County and

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Federal agencies first, followed by the activation of the ERO pagers. The inspector discussed the importance of notifying the emergency responders simultaneously with making offsite notifications for timely activation of the f acilities and mitigating the event. Management stated that the 20 minute delay was unacceptable and in f act identified this as an issue in the post event critique. Management indicated that they have been taking steps to upgrade the notification system process for it's Limerick and Peach Bottom sites in order to correct this proble PECO Energy is considering a system in which preliminary results indicated that notification to their ERO responders would be within minutes af ter an emergency declaration of an Alert and above. Conversations with all of the involved offsite agencies for Limerick and Peach Bottom were f avorable to the new process change, barring negative test results of the system. The inspector verified that PECO Energy plans to perform several tests of the process at the Peach Bottom sito to verify proper operation of the system before activation. Pending final approval by the States of Maryland and Pennsylvania officials and the surrounding counties, the goal is to complete this initiative before the end of 1997, Conclusions On October 9,1997, an Alert emergency condition was declared when a fire occurred in an emergency diesel generator. Activities reviewed in the Technical Support Center during the Alert declaration were performed well, with conservative decisions made and thorough verifications of emergency bus operability prior to termination of the Alert. Additionally, the post event critique was comprehensive, covering all aspects of the response, including strengths and deficiencies. Actions taken and planned to address the 20-minute time delay between the Alert declaration and emergency response organization notification appear to be acceptable for resolving the issue (Section P1.1).

S1 Conduct of Security and Safeguards Activities Insoection Scone The inspector reviewed the security program during the period of October 20 24,1997. Areas inspected included: management support; protected area (PA) detection equipment; alarm stations and communication; testing, maintenance and compensatory measures; training and qualification, and the vehicle barrier system. The purpose of this inspection was to determine whether the licensee's security program, as implemented, met the licensee's commitments and NRC regulatory requirement _ _ _ _ ____ ___

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i Observations and Findinos Management support was evident by support for upgrades to the protected area intrusion detection system, assessment system, and firearm Alarm station operators were knowledgeable of their duties and responsibilities and security training was being performed in accordance with the NRC approved training and qualification (TSO) pla The PA detection equipment satisfied the NRC approved physical security plan (the Plan) commitments and security equipment testing was being performed as required by the Plan Maintenance of security equipment was being performed in a timely manner as evidenced by minimal compensatory posting associated with non-functioning security equipment, Conclusions The inspector determined that the licensee was conducting its security and safeguards activities in a manner that protected public health and safet S2 Status of Security Facilities and Equipment S2.1 Protected Area Detection Aids Inspection Scope The inspector conducted a physicalinspection of the PA intrusion detection systems (IDSs) to verify that the systems were functional, effective, and met the licensee's Plan commitments, Observations and Findinas On October 22,1997, the inspector determined by observation and selected testing that the IDSs were functional and effective, and were installed and maintained as described in the Plan, Qpnclusion The PA IDSs met the licensee's Plan commitment . _ _ _ - __ -

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S2.2 Alarm Stations and Communicalips Insnection Scooe Determine whether the Central Alarm Station (CAS) and Secondary Alarm Station (SAS) are: 1) equipped with appropriatt, alarm, surveillance and communication capability, 2) continuously manned by operators, and that 3) the systems are

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g independent and diverse so that no single act can remove the capability of detecting G a threat and calling for assistance, or otherwise resnonding to the threat, as required by NRC regulations, Observations and Findinas 7 Observations of CAS and SAS operations verified that the alarm stations weie oo' sipped with the appropriate alarm. Ourveillance and communications capabilities, interviews with CAS and SAS operators found them knowledgeable of their duties and responsibilities. The inspector also verified through observations and

- interviews that the CAS and SAS operators were not required to engage in activities that would interfere with their assessment and response functions, and that the licensee hs4 exercised communications methodr with the local law enforcement agencies as committed to in the Plan, Concluslun The alarm stations and commu.iications mu the licensee's Plan commitments and NRC requirement S2.3 Testina. Maintenance and Comocrsatorv Measures Insoection Senqa Determine whether programs were implemented that will ensure the reliability of security-related nquipment, including proper installation, testing and maintenance to replaco defective or marginally effective equipment. Additionally, determine that when security-related equipment failed, th compensatory nicasures put in p' ace were comparable to the effectiveness of tho security system that existed prior to the failu Observations and Findinas Review of testing and maintenance re.,ords for security-related equipment confirmed that the records were on file, rind tua: 'he licensee was testing and maintaining systems and equipment as committed to in the Plan. A priority status was assigned to each work request and repairs were being completed in a timely manner for all work necessitating compansatory measure .._

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I 24 Conclusions Security equipment repairs were timely. The use of compensatory measures was found to be appropriate and minima S3 Security and Safegu1rds Procedures and Documentation S3.1 Implementatiopf Site Access Authorization Procedureji Scope Several PECO employees have been terminated for cause, recently, and some were subsequently reinstated. NRC inspected PFCO's implementation of the site access authorization procedures required by 10 CFR 73.56 to verify that these activities were adequately performed, Observations and Findinas 10 CFR 73.56," Personnel Access Authorization Requirements for Nuclear Power Plants," and the sito Security Plan require that procedures be established to control the imp lcmentation of the site access authorization process. For Limerick and Peach Bottom, these procedures include SEC C-5, " Granting, Suspending, and Terminating Unescorted Access to Nuclear Generating Stations," and SEC-C-2,

" Unescorted Access Authorization Appeals Procedure." The inspector reviewd the evolution of these procedures and their ir..plementation for selected PECO Eney,y employees who wc;e removed for cause during calendar years 1995 and 199 Based on NRC review of all revisions to these procedurt.s and selected security access records, the inspectors determined that the security access process regarding suspension, termination and denial of Limerick s.to access was generally wellimplemented. In particular, control of site access authorization for non-PECO employees was very good. Some process weaknesses were identified during NRC review of the procedure / process evo;ution. Early revisions of the procedure SEC-C-5 lacked guidance regarding the expected timeliness and the record keeping for personnel notification of denial of their access authorization, in at least one for cause denial , these weaknesses led to a procrastinated appeal process. Revisions 2 and 3 to SEC C-5 implementad enhancements to rectify these weaknesses. The inspectors also found that the accerts authorization process lacked timeliness criteria for processing suspension / termination / denial decisions into access control system However,in all of the cases reviewed, these actions were implemented on the date of the applicable decisio !

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2S During NRC review of access denial records for individuals te moved for cause during 19951996,severalinconsistencies were noted. One access denial record was not properly dated and had no verification of receipt by the individual. Several fitness for-duty cases relied on 10 CFR 26 notifications rather than the accer denial process. Further review of these discrepancies led the licensee to at lead, one case where notification of access denial ard the individual's rights to appeal could not be verified. The licensee promptly made these notifications in accordance with the recently enhanced access denial procedure The f ailure to make adequato notifhation cf an individual access denial, including the rea.;on for the denial and the right to appeal the decision was a violat;on of procedure SEC C-2, Revision 2, Section 7.1.2. The violation had minor significance and is being treated as a non-cited violation, consistent with Section IV of the enforcement policy. (NCV Sn-352/97-08-03). Conclusion NRC review of the site access authorization process implementation for personnel who were denied access in 19951996found that, generally, the process was well implemented. Some process weaknesses were corrected by the liceaseo. A minor violatiois regarding adequate notification of access denial was corrected during the inspection and was not cite S5 Security and Safeguards Staff Training and Qualification Insoection Sqqp_q Determine whether members of the secucity organization weie trained and qualified to perform each assigned security-related job task or duty in accordance with the T&Q pla Observations and Findinas On October 23,1997, the inspector met with the security training , taff and discussed the training program and its effectiveness and reviewed the training records for contingency force security officers. Additional.y, he inspector interviewed a number of supervisors and officers to determire if they possessed the requisite knowledge and ability to carry out their assigned t'utiet Conclusio lhe inspector determined that train'ng had been conducted in accordance with the T&Q plan Based cn the supervisors' and officers' responses to the inspector's questions, the training provided by the security tra ning staff was cons:dered offectiv _ - _ _ _ _ _ _ _ _ __

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S6 Security Organization and Administration Insoection Scope Conduct a review of the level of mariagement support for the licensee's physical security progra Observations and Findinos The inspector reviewed various program enhancements made since the last program inspection, which was conducted in January 1997, and discussed them with security management. These enhancements included upgrades to the perimeter intrusion detection and assessment systems, and transition to new weapon Conclusion Management support for the physical security program was determined to be goo S8 Miscellaneous Security and Safety issues S8,1 General On August 1,1994, the Commission amended 10 CFR Part 73, " Physical Protection of Plants and Materia's," to modify the design basis threat for radiological sabotage to include the use of a land vehicle by adversaries for transporting personnel and their hand-carried equipment to the proximity of vital areas and to include the use of a land vehicle bomb. The amendments require reactor licensees to install vehicle control measures, including vehicle barrier systems (VBSs), to protect against the malevolent use of a land vehicle. Regulatory Guide 5.68 and NUREG/CR 6190 were issued in Atiqust 1994 to provide guidance e.cceptable to the NRC by which the licensees could meet the requirements of the amended regulation An April 15,1996, letter from the licensee to the NRC forwarded issue 2, Revision 6, to its physical security plan. The letter stated, in part, that vehicle control measures meet the criteria of 10 CFR 73.55(c)(7),(8) and (9) and Regulatory Guide 5.68 dated August 1994. An NRC February 27,1997, letter advised the licensee that the changes submitted had been reviewed and were determined to be consistent with the orovisions of 10 CFR 50.54(p) and were acceptable for inclusion in the NRC-approved security pla This inspection, conducted in accordance with NRC Inspection Manual Temporary Instruction 2515/132," Malevolent Use of Vehicles at Nuclear Power Plants," dated January 18,1996, assessed the implementation of the licensee's vehicle control measures, including vehicle barrier systems, to determine if they were commensurate with regulatory requirements ar.d the licensee's physical security pla l

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S8.2 Vehicle Barrier System (VBS) Insoection Scop _g The inspector reviewed documentation that described the VBS and physically inspected the as-built VBS to varify it was consistent with the licensee's summary description submitted to the NRC and was in accordance with the provisions of NUREG/CR 619 Observations and Findinas The inspector's walkdown of the VBS and review of the VBS summa ~ description disclosed that the as-built VBS was consistent with the summary description and met the specifications in NUREG/CR-4190. During the physicalinspection of the VBS, the inspector noted that the VBS in one area was only marginally acceptabl After discussion between the licensee and the inspector, it was determined that the effectiveness rf vehicle barriers could be significantly enhanced through a simple modification. The modification was completed at this location prior to the conclusion of the inspectin Conclusion The inspector determined that there were no discrepancies in the as-built VBS or the VBS summary descriptio S8.3 Bomb Blast Analysig Insoection Scope The inspector reviewed the licensee's documentation of the bomb blara analysis and verified actual standoff distances provided by the a: ilt VB Obse,vations and Findinag The inspector's review of the licensee's documentation of the bomb blast analysis determined that it was consistent with the summary description submitted to the NRC. The inspector aise verified that the actual standoff distances provided by their as-built VBS were consistent with the minimum standoff distances calculated using NUREG/CR-6190. The standoff distances were verified by actual field measurements and review of scaled drawings, Conclusion No discrepancies were ..ated in the documentation of bomb blast analysis or actual standoff distances provided by the as-built VE I l

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S8.4 Procedural Cor11rglg Inscection Seqpa The inspector reviewed applicable procedures to ensure that they had been revised to include the VBS, Observations and Findinas The inspector reviewed the licensse's procedures for VBS access control measures, surveillance and compensatory measures. The procedures containad effective controls to provide passage through the VBS, provide adequate surveillance and inspection of the VBS, and provide adequate compensation for any degradation of the VB Conclusim The inspector's review of @,e procedures applicable to the VBS disclosed no discrepancie S8.5 Escurity Force Strike Continaency Plans Insoection Scone Evaluate the licensee's strike contingency plans to verify that treiined personnel are available to support staffing levels consistent with staffing requirements and that plans are in place to instae security operations continue in a safe and orderly manner in the event of a strike, Observations and Findinas The inspector reviewed the licensee's contingency plan to be implemented in the event of a strike, and reviewed training and qualificatic' records for contirigency force personnel that were available to replace striking officers in the event of a strike, Conclusicn The licensee had taken appropriate action to insure that an adequate number of trained and qualified personnel were available to meet regulatory required staffing levels and continue security operations in a safe and orderly manner in the event of a strik F3 Fire Protection Procedures and Documentation

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F3.1 Fire Protection Damoer Surveillance Scoce (71750)

The inspector reviewed the license * 's work practicos applied to performing fire damper inspections. Specifically, the inspector reviewed Fire Damper Inspection ST-7-022 921-2, performed under Unit 2 work order R0504356,to assess the inspection and supporting activities (such as erection of scaffolds and radiological surveys).

b. Observations and Findinas The inspector selected a sample of the dampers to walk down to determine the type of physical access requiremy.nts, as well as, surveys necessary to perform the damper inspections. The inspector found that for the rataple selected most dampers were easily accessible both physically and radic#call In a number of cases the visualinspectior, could be performed through open diffuser gratings, alleviating the need to open vent:lation ducting access plates, in other cases smallladders were necessary to access the damper or on top of other structures for damper access. The inspector determined that, for the dampers observed, work could be performed off of ladders safely with one exceptio Damper 503-037 was approximately 30 feet in the overhead with no easy acces The inspector verified that a scaffold haa been erected to perform this damper inspectio For the damper inspections selected, most of the radiological surveys necessary were completed using the Advanced Radiological Woiker (ARW) program as noted in the work order. The ARW program allows the personnel performing the work to perform their own surveys. A number of ARW surveys were found that were perfor.ned by personnel performing the fire damper inspections. Although these surveys were consistent with the areas and dates that the work was performed, the records did not indicate which surveys correlated to the damper inspections perf.,rmed. Based on discussion with health physics personnel, the inspector also determined that ARW surveys were not always recorded, particularly when the expected conditions of low radiation fields and no contamination were confirme To access the vicinity of fire darper 503-047, a locked high radiological area entry was necessary, in this instance, the inspector venfied the appropriate radiation work permit controls were implemente A review of the compteted surveillance data sheets against the procedure revealed that the records, related to visual verses functional inspections, were incomplet Specifically, procedure ST-7-022-921-2," Fire Damper Inspection," requires that each damper be visually and functionally tested; however, for functional tests that could not be performed, the reason should be indicated in the remarks column. The inspector found that only 10 percent of the dampers had been functionally tested; however, no reasons were specified for not performing the tests for the remainder of the dampers. The inspector reviewed the Technical Specification and Technical

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Requirements Manual requirements for these tests and found that only the visual inspection portion was required. However, discussion with the licensee also identified that the functional test was a result of a commitment made i: response to NRC inspection 50-352/85 16:50-352/85-04. However, the commitment was to establish a program to functionally test 10 percent of the dampers every eighteen months. The inspector also noted that the Unit 1 version of the fire damper inspection procedure was less restrictive and consistent with the commitment. The

!!censee stated that the Unit 2 procedure was incorrect and believed that the personnel performing the Unit 2 damper inspection did not note the discrepancy between the two similar procedures when implementing the inspections and tests at Unit In rosponse to the procedural non-compliance issue, the licensee reinforced procedure adherence expectations with the individuals involved and plans to initiate a procedure revision prior to the next performance of the surveillance. The inspector noted that the licensee did not initiate a PEP evaluation after the issue was brought to their attention. The inspcctor also noted that ST-7-022 921-2had been performed in 1997, the procedural non-compliance was repeated and again not identified by the personnel implementing the surveillance. The inspector subsequently asked if the procedural non-compliance met the PEP threshold and the licensee stated that it did and initiated the PE The inspector determined the completed surveillance met the un('3rlying requiremont, currently in the Technical Requirements Manual as well as the commitment to perform functional tests of 10 percent of the damper Consequently, this f ailure constitutes a violation of minor significance and is being treated as a Non-Cited Violation (NCV 50 353/07 08-04) consistent with section IV of the NRC Enforcement Polic Conclusion The access and radiological controls implemented for fire damper inspections were adequate. When necessary a scaffold was used to support the safe work practices and the radiation work permit controls were implemented as required in cases where the advanced radiation worker program was used to support fire damper inspections, the records generally reflect that sufficient surveys were performe However, the completed surveillance was improperly documented in that the performers did not annotate the. re9 sons fc~ not performing a functional test consistent with the procedural requirements. This issue was a concern because the same error was made by more than one person and then repeated in a subsequent surveillance two years later. Further, the licensee did not initiate a PEP evaluation af ter the issue was brought to their attention until prompted by the inspecto Management attention is warranted to ensure a more serious procedural compliance problem does not exist. The documentation discrepancy was not cited due to its minor significanc l

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F8 Miscellaneous Plant Support issues (90712)

F (Closed) LER 1-97-006, Revision 1 Previous Condition Prohibited by Tech Specs in itLat a Fire Protection System Deluae Valve may not have Functioned oer Desian Since issuance of the Unit 1 Operatina License This event was discussed in NRC Ir.tegrated inspection Report 50-352/97-07,50-353/97-07, and resulted in a non-cited violation. This revision provided information concerning additional actions taken, including completion of replacement of the valve. The LER met the requirements of 10 CFR 50.73, and no additionalissues were identifie F8.2 (Closed) LER 197-008, Failure to Perform Annual Maintenance Insoections of pnsite Portable Fire Extinauishegg This LER documents an instance where the provisions of the Fire Protection Program were not maintained as described in the UFSAR in violation of the Facility Operating License Condition 2.C.(3) for both Limerick units. Sp?cifically, the annual maintenance inspection of fire extinguishers had not been performed since initial licensing for both Limerick units. However, the monthly inspections were performed, and the 5 year hydrostatic testing was performed. The condition was discovered on September 15,1997, and tN inspections were completed and any probler.is were corrected by September 20,3 of the 450 fire extinguishers inspected were found to be out of compliance. Safety consequences for this event were low, since only 3 extinguishers were affected, and the remaining fire extinguishers in the areas were more than capable of extinguishing a small fir Additionally, the affected areas were protected by automatic fire suppression systems. The cause of the omission was determined to be personnel error, in that wrong assumptions were made concerning the accountability for conducting the annualinspections. Administrative controls for performing the annual inspections are being developed as corrective actions, and a generic review, concerning the inspection requirements associated with other Fire Protection Program fire equipment, is being performed to ensure that all requirements are being satisfie This nowepetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Polic (NCV 50-352,353/97-08-05)

F8.3 LQlosed) URI 50-352. 353/96-07-02. Missed Fire Protection Surveillance This unresolved item concerned instances, where an individual failed to perform fire protection surveillances as required by TSs and the inaccuracy of the documentation associated with these curveillances. A violation was previously issued for failure to maintain certain surveillance records complete and accurate in all material respects as required by 10 CFR 50.9. The failure to perform the required fire protection surveillances was also addressed in the disposition of this issue. Corrective actions included conducting a comprehensive investigation into the events, anu performing a broad based look at several of the work groups for other problems; none were identified. Additionally, PECO management spoke directly with employees and t_ _ _ - - _ _ . - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

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groups of employees concerning management expectations of truthfulness and integrity; a memorandum was also issued to all PECO employees from the Senior Vice President regarding these issues. Actual safety consequences for the missed surveillances were low, since the equipment in question passed subsequent surveillance tests. Additionally, the inspector noted that the LER for this event was later than the 30 days required by 10 CFR 50.73. Although a similar violation wes issueri in NRC Integrated Inspection Report 50 352/97-06,50-353/97-06,the root causes wera different, and the corrective actions for the first would not be expected to prevent the second violation. This non-repetitive, licensee-identified and corrected violations is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Pclicy. (NCV 50-352,353/97 08-06)

F8.4 IQ.losed) eel 50-352,353/97-06-02, Failure to Maintain Fire Safe Shutdown Eauioment This open item concerned an instance where PECO Energy personnelidentified that certain equipment, required to be pre-staged to help bring the plant to a cold shutdown condition in the event of a fire, was not in placc for Unit 2 since 198 '

This resulted in a violation (EA 97-340), issued on September 29,1997, by separate correspoadence. No response was required, since the corrective actions taken and planned to correct the violation and prevent recurrence, and the date when full compliance was achieved was already adequately addressed on the docktt. Based on this, the open item is close V. Manegement Meetings X1 Exit Meeting Summary

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The inspector presented the inspection results to members of plant management at the conclusion of the inspection on November 25,1997. The plant manager acknowledged the inspectors' findings. The inspectors asked whet ker any materials examined during the inspection should be considered proprietary. No proprietary information was identifie The security inspector met with the licensee representatives at the conclusion of the inspection on October 24,1997. At that time, the purpose and scope of the inspection were reviewed, and the preliminary findings were presented. The licensee acknowledged the preliminary inspection finding A specialinspection of the October 9, D21 EDG event was conducted by a Regional-Based inspector. Details of this review will be provided in NRC Report 50-353/97-0 X2 Review of UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, pro *:sdures and/or parameters to the UFSAR description. While performing the inspections l

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discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters. Since the UFSAR does not specifically include security program requirements, the inspector compared licensee activities to the NRC-approved physical security plan, which is the applicable document. While performing the inspection discussed in this report, the inspector reviewed Chapter 3 of the Plan titled, "Protacted Area Perimeter." Based on discussions with security supervision, procedural reviews, and direct observations, the inspector detormined that barriers were installed and maintained as described in the Plan and applicable precedure _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

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I 34 INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 38701: Procurement Program IP 61726: Survwillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Activities IP 84750 Radioactive Wasta Treatment, and Effluent and Environmental Monitoring IP 90712: In-office Review of Written Reports IP S0713: Review of Periodic and Special Reports IP 92904: Followup Plant Support IP 93702: Prompt Onsite Response tc, Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED Opened NCV 50 352/97-08-01 Improper RCIC maintenance procedure. (Section M1.3)

NCV 50 252,353/97 08-02 Inadequate system drawings changes and review (Section E1 1)

NCV 50-352/97-08-03 Failure to n .xc adequate notification of an individual access denial. (Section S3.1)

NCV 50-353/97-08-04 Failure to adequately perform a technical specification functional tests. (Section F3.1)

NCV 50 352,353/97-08-05 Annual maintenance inspection of fire extinguishers had not been performed since initlallicensing for both Limerick units. (Sectica F8.2)

NCV 50 352,353/97-08-06 LER !ssued late. (Section FJ.3)

Closed NCV 50-352/97-08 01 Improper RCIC maintenance procedure. (Section M1.3)

NCV 50-252,353/97-08-02 Inadequate system drawings changes and review (Section E1.1)

NCV 50-352/97-08 03 Failure to make adequate notification of an individual access denial. (Section S3.1)

NC i 50-353/97-08-04 Fa. lure to adequately perform a technical specification functional tests. (Section F3.1)

NCV 50-352,353/97-08-05 Annual maintenance inspection of fire extinguishe.s had not been performed since initial licensing for both unit (Section F8.2)

NCV 50 352,353/97-08-06 LER issued late. (Section F8,3)

eel 50-352,353/97-06-02 Failure to Maintain Fire Safe Shutdowri Equipmen (Section F8.4)

URI 50-352,353/96-07-02 Missed Fire Protection Surveillance. (Section F8.3)

LER 1-97-006, Revisio:' 1 Previous Condition Prohibited by Tech Specs in that a Fire Protection System Deluge Valve may not have i

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Functioned per Design Since issuance of the Unit 1 Operating License. (Section F8.1)

LER 197-007 Isolation of the Reactor Water Clean up System, an Engineered Safety Feature, Resulting from Lifting of a Filter Demineralizer Pressure Safety Valve Caused By Setpoint Drift. (Section E8.1)

LER 197-008 Failure to Perform Annual Maintenance inspections of Onsite Portable Fire Extinguishers. (Section F8.2)

Discussed None t-

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LIST OF ACPONYMS USED AFSS Automatic Fire Suppression System AR Action Request BOP Balance of Plant CAS Central Alarm Station CEI Centerior Energy CI:R Code of Federal Regulations CREFAS Control Room Engineering Fresh Air System CS Core Spray EDG Emergency Diecel Generator ERO Emergency Response Organization ERP Emergency Response Procedure ELU Emergency Lighting Unit ESF Engineered Safety Feature E5W Emergency Service Water EWR Engineering Work Request FIT Focused Improvement Team FME Foreign Material Exclusio .

FP Fire Protection FSWS Fira Suppression Water System GL Generic Letter HEPA High Efficiency Particulate HPCI High Pressure Coolant injection IFl Inspection Follow-ep Item IR inspection Report IRM Industrial Risk Management LCO Limiting Condition For Operation LER Licensee Event Report LGS Limerick Generating Station NCV Non-Cited Violation NDE Nondustructive E<a nination NED Nuclear Engineering Department NMD Nuclear Maintenance Division NQA Nuc' ear Quality Assurance NRB Nuclear Review Board NRC Nuclear Regulatory Commission NUPIC Nuclear Procurement issues Committee ODCM Offsite Dose Calculation Manual PAB Protected Area Boundary PBAPS Peach Bottom Atomic Power Station PECO PECO Energy PEP Performance Enhancement Process PO Purchase Order PORC Plant Operations Review Committee PSA Probabilistic Safety Assessment QA Quality Assurance OC Ouality Control I

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! 37 QV Quality Verbication RCIC Reactor Core Isolation Cooling RCM Reliability Centered Maintenance RCO Request for Change Order RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water RMS Radiation Monitoring System RP&C Radiological Protection and Chemistry RP Radiation Protection RT Routine Test RWCU Reactor Water Clean-up SCBA Self Contained Breathing Apparatus SLC Standby Liquid Control ST Surveillance Test TRM Technical Requirements Manual TS Technical Specification TSC Technical Support Center UFSAR Updated Final Safety Analysis Report URI Unresolved item VIO Violation

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Enclosure 1 PROCEDURES. TRAINING PROGRAMS, FORMS AND DIRECTIONS FOR 10 CFR 50.59

. REVIEW AT LIMERICK GENERATING STATION IIEM TITLE EFFECTIVE DATE CNP 0010, Re .59 Review Training 05/09/96 LR-C-13, Re CFR 50.59 Reviews 08/29/97 AG-CG-4, Re PORC Review & Approval of Documents 05/13/97  ;

A-C-4, Re Plant Operation Review Committee 01/31/96 A-C-4.2, Re Station Qualified & Quality Reviewer 01/31/96 Program

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A C-901, Re Control of Non Conformances 02/18/97

. MOD-C 3, Re Modifications & Minor Physical Change 07/14/97 Process MOD-C-7, Re Temporary Plant Alterations 09/04/97 MOD C-8, Re Setpoints Changes 07/30/97

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MOD--9, Re Design Control and Processing of 05/13/97 Engineering Changes Requests LR CG.13, Re Seven Questions - 10CFR 50.59 Reviews 08/29/97 t

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Enclosure 2 PECO ENERGY COMPANY PERSONNEL INTERV!EWED DURING 10CFR50.59 REVIEW Becki Dothanczyk, Licensing Analyst, PECO t

s Glen Stewart, Licensing Engineer, PECO Timothy Moore, Manager Experience Assessment, PECO Dan Fiorello, Engineer, PECO

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Enclosure 3 LISTING & DESCRIPTION OF FOURTEEN REPORTS REVIEWED DURING 50.59 INSPECTION Modification ECR 95-00164: Rerating of the reactor enclosure cranes's Maximum Critical Load retir'g from 110 to 125 ton . Non Conformance Report 96-00845: Evaluation of circumferential flaw /creck indicatior.s in certain welds on the Unit 1 corn shroud identified during 1R06 refueling outag . Temporary Plant Alteration ECR 96-00745: Evaluation of temporary use of non-class 1E source as temporary power feed for the 1 A Fuel Pool Cooling pum . Procedure MAT P00167-1: Applicable to the post modification testing of a portion of the ESW and RHRSW crossti . UFSAR Change ECR 95-02894: Evaluation of deferral of Unit 1 low pressure main turbine rotor inspections beyond the 6-year interva . UFSAR Change ECR 96-01833: Evaluotion of the use of nuclear fuel channels from initial core at the Shoreham nuclear facilit . Commitment Revision T03588: Evaluation of change in the testing frequer.cy of the undervoltage relay (6 week to 6-month). Modification P00140: Upgrades to Units 1 and 2 Main Steam Isolation Valves (MSIV's). Modification P00674: Replacement of existing 2A-P202 RHR pump motor with a newly purchas'.d motor supplied by G . Temporary Plant Alteration ECR 96-03716: Justifies the operability of the Drywell Air Cooler Condensate Drain Flow Monitoring System when air cooler drain flow transmitter FT 87 220 Dis removed from servic . UFSAR Change ECR 96-01283: Revision to include the results of HOLTEC thermal-hydraulic analysis for the spent fuel pool which evaluated a reduction in the I-core decay time from 125 to 40 hr . UFSAR Change ECR 96-02909: Revise to agtee with the actual testing method used for the ADS SRV valve exercisin . UFSAR Change ECR 96-04524: Revise secticns to be consistent with QAPD change regarding commitment to Regulatory Guide 1.5 _ _ . -._

e . TS Change ECR 97-01-067: Revise TS Bases for diesel fuel oil system.

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