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Insp Repts 50-352/98-03 & 50-353/98-03 on 980317-0518. Violations Noted.Major Areas Inspected:Aspects of PECO Energy Operations,Engineering,Maint & Plant Support
	ML20249C193
Person / Time
Site:	Limerick
Issue date:	06/18/1998
From:	Anderson C; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20249C187	List: IR 05000352/1998003; ML20249C186; ML20249C190;
References
	50-352-98-03, 50-352-98-3, 50-353-98-03, 50-353-98-3, NUDOCS 9806260167
	Download: ML20249C193 (36)
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U.S. NUCLEAR REGULATORY COMMISSION l REGION I L

Docket No :

License No NPF-39 NPF-85 Report No Licensee: PECO Energy Correspondence Control Desk P.O. Box 195 Wayne, PA 19087-0195 Facilities: Limerick Generating Station, Units 1 and 2 ,

Location: Wayne, PA 19087-0195 Dates: March 17,1998 through May 18,1998 i

inspectors: A. Burritt, Senior Resident inspector F. Bonnett, Resident inspector S. Hansell, Resident inspector J. Noggle, Senior Radiation Specialist A. Lohmeier, Senior Reactor Engineer T. Burns, Reactor Engineer T. Fish, Operations Engineer Approved by: Clifford Anderson, Chief Projects Branch 4 Division of Reactor Projects

i 9806260167 18 POR ADOCK 0 52 G PM .

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EXECUTIVE SUMMARY Limerick Generating Station, Units 1 & 2 NRC Inspection Report 50-352/98-03,50-353/98-03 This integrated inspection included aspects of PECO Energy operations, engineering, maintenance, and plant support. The report covers a 9-week period of resident inspection, and region-based inspections in the inservice inspection and radiation protection area Operations

Management ensured that adequate oversight of refueling outage 1RF07 work was in place. The outage risk assessment model system effectively coafirmed and documented when higher risk evolutions occurred in the outage schedul Procedures were technically adequate and guidance was in place for maintaining decay heat removal available. (01.2)

Control room and refueling bridge operators appropriately conducted Unit 1 shutdown activities. The shift supervision remained aware of scheduled and emergent outage activities and effectively coordinated field activities, thereby reducing work conflicts. Outage management provided effective oversight to support the operations staff. Operations management's decision to provide shutdown training at the site-specific simulator enhanced the operators' response and ability to effectively control the unit safely during the shutdown and cooldow (01.3)

Operators failed to recognize, enter and log all the applicable limiting conditions for operation (LCO) related to the control room emergency fresh air supply (CREFAS) j system inoperable equipment and thus demonstrated a weakness in understanding l of the CREFAS technical specifications. Failure to make LCO entries in the control I room unified log is similar to problems noted in NRC inspection report 352,353/97-10 and is considered a violation of Arpendix B, Criterion XVI, " Corrective Action,"

due to the repetitive nature of the issue. (O2.1)

Several problems with the licensee not keeping the unified log current and excessive use of back dating of many of the log entries demonstrated weak log keeping practices and may have contributed to the missed control room emergency fresh air supply limiting conditions for operation. (O2.1)

The operations organization demonstrated a weakness in technical specification interpretation when the shift manager and operations manager both agreed that Technical Specification 3.0.3 did not have to be entered, when it should have been, when both control room emergency fresh air supply (CREFAS) systems were declared inoperable. It was inappropriate to base this decision on an expectation that an engineering evaluation would, in a short period of time, declare one of the CREFAS systems operable. (O2.1)

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Executive Summary (cont'd '

Maintenance o ~ _Overall,' maintenance activities performed during refueling outage 1R07.were conducted well and without incident. Supervisors were present in the field and field

teams were well briefed. Technicians had work packages at the jo'n -site and understood the effect of their activity on the unit. (M1.1)

~ Generally, surveillance testing was conducted well during refueling outage 1RF0 Large, complex tests were well supervised with management oversight and were conducted by an individual test coordinator. (M1.2)

e The Inservice inspection (ISI) was performed acceptably and included appropriate i . ASME program coverage, qualified personnel, approved procedures, proper

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implementation, adequate examination documentation, and PECO oversight. The inspections were sufficiently thorough to determine the integrity of the components'

inspected. L(M1.3)

Enaineerina e The licensee's activities to inspect, assess, and repair the A and B RHR pumps were very good. .The engineering team determined the root cause and identified appropriate corrective actions. (E1.1)

e The engineering work on the skimmer surge tank modification had been comprehensive and acceptable. The decision to forego detailed pre-fabrication measurements was reasonable, but better measurements prior to installation could have prevented most of the later fit up problems. (E2.1)

e The response to degraded scram and notching performance of control rod 18-15 was conservative. The evaluation and corrective actions implemented to address fuel channel bowing in a select population of fuel bundles were prompt and comprehensive. (E2.2)

.o . The planned testing, to identify additional control rod anomalies, for Limerick was adequate. However, the testing plan documented in the interim PECO disposition of channel bowing, provided inappropriate flexibility. Specifically, more subjective testing methods were allowed instead of requiring scram time testing for each suspect channel. :The engineering disposition did not establish sufficient bases for -

the alternate testing. In addition, no formal communication was provided to the operatorc, following the identification of a generic channel bowing concern. -(E2.2) l l Contract workers did not consistently perform the skimmer surge tank modification ' i activities appropriately, and on several occasions failed to perform adequate quality -

verification checks. PECO quality verification personnel identified these-deficiencies, which were adequately resolved. (E7.1)

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Executive Summary (cont'd i Plant Sucoort i

. . Generally ef fective RP Job coverage and radiological briefings to workers were provided during the Unit 1 seventh refuel outage. (R1.1)

Alarm setpoints on electronic dosimeters were not commensurate with radiological ;

conditions and accordingly, were not established to optimize exposure contro i

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During the Unit 1 seventh refueling outage, the drywell was effectively shie!ded resulting in relatively uniform and low dose rate conditions. The licensee was aggressive in reducing hot spots in plant piping, which resulted in improved j radiological conditions in various plant areas, including the suppression pool. (R1.2) 1 I

A very good level of air sampling was performed during the Unit 1 seventh refuel -

outage, with no indications of airborne radioactivity areas. i:ollow-up whole body counts for persons subject to personnel contamination did not identify any internal exposures. (R1.3)

The dai!y source response check of contamination instrumentation had been recorded in a misleading manner. (R2.1)

Interviews with some advanced radiation worker personnel to verify the degree of proficiency revealed a deficiency relative to knowledge of survey and contamination release criteria. Verification and oversight of activities conducted by advanced radiation workers was not well executed, consequently, the potential for inadequate performance existed. Notwithstanding, no actual performance deficiencies were noted during~this review. (R4.1) l

Other-utility radiation protection (RP) technicians brought in for the outage were not evaluated for their knowledge of RP fundamentals, which was previously found to be a weakness in the Limerick RP technician training program in 1997. In light of Limerick's experience in this area, waiving of the RP fundamentals examination for other-utility RP technicians was considered a poor practice. (R5.1)

A few radiological problems were identified shortly before and during the early Unit i 1 seventh refuel outage period and they were of minor safety consequence; however, they were not effectively resolved in a timely manner. (R7.1)

The control room operators appropriately declared an ALERT on April 17,1998,due to the potential presence of an unidentified toxic or flammable gas. The licensee controlled the non-radiological event well with no adverse effects on either unit.

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Although the source of the gaseous smell was not identified prior to termination of I

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. the event, PECO did identify the source when the smell recurred the following da (P1.1) .

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e TA8LE OF CONTENTS EXEC UTIVE S U M M ARY ~ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . il i TABLE O F CO NTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V Summary of Plant Status _ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1. O pe rat ion s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 u 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

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01.1 General Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

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01.2 , Refueling Outage (1 RO7) Preparations - Unit 1 .............. 2 01.3 ' Refueling Outage (1 R07) - Unit -1 . . . . . . . . . . . . . . . . . . . . . . . . 3 02.1 Control Room Emergency Fresh Air Supply (CREFAS) System Operability and Log Entries . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 08.1 :(Closed) VIO 50-352&353/97-10-02, Adequate measures not a: established to assure design requirements were maintained during hydraulic control unit (HCU) on-line maintenance ............ 8 08.2 (Closed) VIO 50 352&353/97-07-03,HPCI system inoperable due to clogged turbine exhaust drain line . . . . . . . . . . . . . . . . . . . . . . ~8 II . M aint e n a nc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

'M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 M1.1 Refueling Maintenance Activities - Unit 1 . . . . . . . . . . . . . . . . . . 8 M1.2 Refueling Surveillance Activities - Unit 1. . . . . . . . . . . . . . . . . . 10 M 1.3 Inservice Inspection (ISI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 111. Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 E1.1 Residual Heat Removal (RHR) Pump Repair . . . . . . . . . . . . . . . . 12 E2 . Engineering Support of Facilit'es and Equipment ................. 13 E Skimmer Surge Tank Modification - Unit 1 ................ 13 E2.2 Fuel Channel Bowing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 E7 . Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . . . . . . 16 E7.1 Quality Verification . . . ..............................16 I V. Pla nt Support . . . . . . . . . . . . . . . . '. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 8 R1 Radiological Protection and Chemistry ('iP'vC) Controls . . . . . . . . . . . . 18 R1.1 Outage Operational RP Performance . . . . . . . . . . . . . . . . . . . . . 18

R1.2 As Low As is Reasonably Achievable (ALARA) . . . . . . . . . . . . . 19 R1.3 Internal Exposure Performance . . . . . . . . . . . . . . . . . . . . . . . . 19 R2 Status of RP&C Facilities and Equipment ......................20

~ R2.1 Survey Equipment Source Checks . . . . . . . . . . . . . . . . . . . . . . 20 R4 Staff Knowledge and Performance in RP&C ....................2 R4.1 Advanced Radiation Worker (ARW) Program . . . . . . . . . . . . . . . 21 R5 Staff Training and Qualification in RP&C . . . . . . . . . . . . . . . . . . . . . . . 22

. R5.1 . Temporary Outage RP Technician Qualifications . . . . . . . . . . . . 22

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- Table of Contents (cont'd)

R Quality Assurance in Radiological Protection'and Chemistry Activities . . 23

R7.1. Radiological Performance Enhancement Program (PEP) . . . . . . . . 23 .

l R8- Miscellaneous RP&C issues . . . . . . . . . .. . . -. . . . . . . . . . . . . . . . . . . 24 '

l R8.1 (Closed) IFl 97-10-07, Resolution of Non-conservative Exposure l- Determinations Between TLD and Electronic Dosemeter . . . . . . . 24

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R8.2 - - (Closed) URI 97-10-08, Results Determination if Advanced Radiation Workers That Survey and Release Contaminated Areas Should be Qualified HP Technicians . . . . . . . . . . . . . . . . . . . . . .' 24

'P1 Conduct of Emergency Preparedness Activities . . . . . . . . . . . . . . . . . . 24 P1.1 ' ALERT Event Declared at Unit 1 .......................24

'P8 Miscellaneous EP lssues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 -

P8.1 (Closed) IFl 50-352,353/97-05-01, Licensee Failure to Integrate TSC Engineering Expertise ...........................25 V. M anagement Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . 2 6 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 ATTACHMENTS Attachment 1 -Inspection Procedures Used

- Partial List of Persons Contacted

- ltems Opened, Closed, and Discussed

- List of Acronyms Used vi

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Rooort Details Summary of Plant Status

. Unit.1 operated from 95% to 88.5% power in the end-of-cycle (EOC) coast down mode of operations during this inspection period. The seventh refueling outage (1RO7) began on

^ April 3,1998. Prior to the beginning of 1RO7, operators reduced power about 5% several times to maintain turbine back-pressure due to warm weather and cooling tower work activities. During the pcriod, the following power adjustments and events occurred:

e March 22 Operators reduced reactor power to 85% after load center 124B tripped causing a loss of the 18 drywell chiller resulting in increasing

! . recirculation pump motor winding and drywell temperature Operators further reduced reactor power to 50% after the chemistry manager reported to the operation staff that the sulf ate level (5.04 ppb) had exceeded an administrative Chemistry Action Level 1 (sulfates greater than 5.0 ppb). Chemistry technicians resolved and cleared the chemistry condition on March 2 e March 23 Operators stopped increasing reactor power at 69% power due to thermal limit and process computer restraints. Operators lowered power to 60% until reactor engineering resolved the issue and then raised reactor power to 90.5% on March 2 e April 3 Operators shutdown the unit to begin 1RO7. Reactor power had '

coast down to 88.5%

e April 5 Unit 1 entered OPCON 5 (Refueling) when maintenance technicians

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detensioned the reactor pressure vessel (RPV) head closure bolt The unit remained in OPCON 5 until May 6, when Unit 1 entered OPCON 4 (Cold Shutdown) after the RPV was reassemble e May 18 Operators placed the mode switch to Startup, antering OPCON 2, and mada the reactor critical at 8:41 Unit 2 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 folinwing plant evolution, e April 25 . Operators reduced reactor power to 75% to perform scram time testing on eight control rods that were potentially affected by channel bowing. All scram times and stroking characteristics were norma Reactor power was restored to .100% that same da p ..

~2 1. Operations

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l 01 Conduct of Operations'

01.1- General Comments (71707)

Using inspection Procedure 71707, the inspectors conducted t(squent reviews of ongoing plant operations. In' general, PECO Energy's conduct of eperations was professional and focused on safety principle q a

01.2 Ref6) lina Outaae (1R07) Preparations - Unit 1

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' . Lnsoection Scooe (60705) ,

The inspector performed a sample review of refueling procedures, administrative

. controls, and the outage risk assessment model (ORAM) for control of refueling outage'1RO7. The inspector also discussed monitoring shutdown margin (SDM)

throughout the outage with operators and reactor engineers,

~ Observations and Findinas i

The inspector determined that the portions of the following refueling and )

administrative procedures reviewed provided adequate guidance and met the j guidelines for procedures of this type. The' procedures reviewed included: ;

OSG 117 Guideline for Outage Planning and Risk Management

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OSG-118 Guideline for Pre-outage Schedule Reviewers ;

OSG-420 Outage Schedule Change Review ,

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GP-3 Normal Plant Shutdown -

GP- Shutdown Operations - Refueling, Core Alterations and Core Off-loading FH-105 Core Component Movement - Core Transfers ,

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RE-C-40 Core Component Transfer Authorization Sheet (CCTAS) Generation and Administration FM-C-4 Generation of CCTAS Using Shuffleworks ST-R-2 930 Refueling SDM Verification )

i PECO management implemented controls that qualitatively assessed the degree of shutdown risk present at any point in the outage. The ORAM system was a - ;

computerized tool used to assess the anticipated risk present when reactivity control, decay heat removal, spent fuel pool cooling, inventory control, power ;

l availability, and containment capability redundancies are affected. The outage schedule was developed by comparing outage activities, plant configurations, and :

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conditions during the shutdown where the plant was susceptible to an event, !

1 . Topical headings such as o1, MB, etc.; are used in accordance with the NRC standardized reactor inspection report

?f outline. Individual reports are not expected to address all outiirie topic 'I

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-indicating'the level of risk by color (green, yellow, orange, and red). The inspector noted that the level of risk for the outage never exceeded a yellow indication. .The

. . ORAM manager. demonstrated the computer's capability of redefining the shutdown -

risk anytime a change in the outage schedule occurred. The outage schedule was modified several times to improve the risk .For example, activities wer l rescheduled after identifying that the 1B RHR pump was degraded and to allow the .

early initiation of the alternate decay heat removal mod."icatio Control room operators were aware of the technical specification requirements for

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SDM and referred to the precedure for core component transfer authorization sheet, generation and administration (RE-C-40, Rev.4). The reactor engineering staff was also knowledgeable about the requirements for the minimum SDM and used conservative values for the computer program that generates the core component movement sequence. The reactor engineering staff established a conservative program to control reactivity during core alteration Conclusions Management ensured that adequate oversight of refueling outage 1RF07 work wa in place. The ORAM system effectively confirmed and documented when higher

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risk evolutions occurred in the outage schedule. Procedures were technically

, adequate and guidance was in place for maintaining decay heat removal availabl .3 Refuelino Outane (1RO7)- Unit 1 - Insoection Scone (71707)

The inspectors observed operator activities during t'he seventh refueling outage (1R07). Major activities included: fuel shuffle, control rod drive and blade replacement, disassembly and inspection of the No. 2 jet pump, initiation of the alternate decay heat removal (ADHR) modification, RPV hydro-test, and the containment integrated leak-rste test (ILRT). The inspector also observed operator training on the site specific simulator that involved shutdown exercise Observations and Findinas !

- The inspector observed operator training at the site-specific simulator for the operatin0 crew that would be performing the reactor shutdown. The training included f familiarization of procedure GP-3, Plant Shutdown, and other procedures .

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that would be performed during the evolution. Operators rehearsed specific plant operations,' dist'ussed operator actions for potential "what if" type scenarios, and ;

practiced responding to unplanned events. Operators subsequently conducted

. Tactivities well during the Unit 1 shutdow ^

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'The refueling platform operators and senior reactor operators with licenses limited to ,

,l . . fuel handling (LSRO) personnel were knowledgeable regarding their responsibilitie I g -

Three part communications and double verification of proper location for core

.f components were excellent.' The core component transfer authorization sheet f

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(CCTAS) was accurately maintained by the fuel handling director (LSRO), the .

spotter, and the control room. The control room staff was knowledgeable of fuel

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. move status and personnel monitored source range indication as required during fuel moves. No incidents occurred during fuel move activities, control rod blade exchanges, or local power range monitoring exchange Several challenges occurred early in the outage that delayed refueling bridge activities. Problems with "D" source range monitor operability delayed the start of

. fuel movements and core alteration activities had to be suspended several times to

- make repairs to the auxiliary hoist. Refuel floor personnel showed good attention-

. to-detail when a damaged hose was discovered on the refueling bridge and activities were stopped to make repairs. However, the inspector noted that the operator practice of placing yellow tape on the cable as an indication led to a pulley on the auxiliary hoist becoming jammed, causing fraying of the cable, necessitating its replacemen The shift supervision remained aware of scheduled and emergent outage activities and effectively coordinated field activities, thereby reducing work conflicts. Outage management provided effective oversight to support the operations staf The operations staff demonstrated good command and control and coordinated activities well during the RPV hydro-test and containment ILR Conclusions Control room and refueling bridge operators appropriately conducted shutdown activities. The shift supervision remained aware of scheduled and emergent cutage activities and effectively coordinated field activities, thereby' reducing work

. conflicts. Outage management provided effective eversight to support the operations staff. Operations management's decisic.n to provide shutdown training at the site-specific simulator enhanced the operators' response and ability to sfhetively control the unit safely during the shutdown and cooldow ' O2 Operational' Status of Facilities and Equipment O2.1 Control Room Emeroency Fresh Air Sunolv (CREFAS) System Operability and Loa Entries inspection Scone (71707)

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On April 4,1998, maintenance activities af facted operability of the 'A' and 'B'

CREFAS systems. The inspectors assessed whether operators made appropriate

. operability determinations and accordingly logged the associated technical specification (TS) entries in the control room unified log.

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5 Observations and Findinas The following events occurred on April 4,1998:

5:15 Shift management declared the D-13 emergency diesel generator (EDG) and its associated 4.16 KV electrical bus inoperable to support EDG work. Since the D-13 EDG provided emergency power to the 'A'

( CREFAS system, certain technical specification limiting condition for operations (LCOs) were applicable to the CREFAS syste :50 The 'B' CREFAS system failed to initiate in the chlorine isolation mode per procedure S78.8.A,"ManualInitiation of Control Room Radiation or Chlorine / Toxic Chemical isolation." 'A' CREFAS fan automatically started when the 'B' CREFAS fan failed to star :15 After the discovery of a failed agastat relay, the 'B' CREFAS system was declared inoperable and regulatory action 98-0-39 was entere The regulatory action for the 'B' CREFAS system was appropriately

! back dated in the log to 12:50 p.m. due to the failure of the 'D'

l chlorine channel to manually initiate the 'B' CREFAS fan at that tim :30 After the completion of an engineering evaluation, shift management i declared the 'A' CREFAS system operable and exited the TS LC :11 'B' CREFAS was returned to operable statu Several problem's were identified by the inspectors regarding entering the appropriate technical specification LCO. With the D-13 EDG inoperable, the operators failed to enter a 30 day Unit 2 LCO,3.7.2.a.1, at 5:15 a.m. on April 4, 1998. Unit 2 was in an operating mode that had additional requirements for CREFAS operabilit With the 'B' CREFAS system inoperable and the D-13 EDG still inoperable, the shift SRO failed to enter a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Unit 2 LCO,3.7.2.a.3, constituting a second instance where operators did not recognize they were in an LCO. This LCO should have been entered at 12:50 p.m. on April 4,1998. Since the D-13 EDG was returned to service at 12:04 PM on April 6,1998, before the 72 -hour and 30-day LCOs expired, the associated technical specifications were not violated, in addition, operaters did not enter TS 3.03 when both CREFAS systems were inoperable. In the period 7:15 p.m through 7:30 p.m., with both CREFAS systems known to inoperable, operators should have entered TS 3.0.3. The shift manager-(SM) stated he had not entered TS 3.0.3 because the engineer manager assured him the engineering evaluation of the 'A' CREFAS system would conclude that the system was actually operable even though it was considered administratively inoperable due to the ongoing D-13 EDG maintenance activities. The shift manager informed the operations manager of the CREFAS issue and he also agreed that it

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s was not necessary to~ enter TS 3.0.3. The inspector did not agree with the conclusion of the shift manager and operations manager that TS 3.0.3 did not have l .. to be entered. ..The inspector concluded that this was not a violation since a

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CREFAS system was restored to operable status prior to any action being required

. by TS 3. . The inspectors also identified several problems with the licensee not keeping the unified log current and excessive use of back dating of many of the log entries.

I Operators appropriately identified the 7 day CREFAS LCO for both Units. However, the operators logged this information in the control room unified log at

'approximately 5:30 p.m. The log time for the inoperable 'A' CREFAS system was

. back dated from 5:30 p.m. to 7:16 a.m., but was not highlighted as a " late entry."

The inspectors were not able to construct an accurate sequence of events related to

. the CREFAS system status on April 4th and 5th. For example, the unified control l ' room log showed the 'B' CREFAS system was inoperable at 12:50 p.m. However, l a performance enhancement progrem (PSP) review documented that the system was inoperable at 7:15 p.m. There was nc log entry at 7:15 p.m. to docunient the engineering evaluation. The following summarizes the actual log times and backdated log times for several of the events discussed abov CREFAS ACTION BACK DATED LOG TIME ACTUAL LOG TIME (Delta Hours to Back Date)

D-13 EDG/ BUS Inoperable . N/A 5:15 a.m.; 4/4

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'A' CREFAS Inoperable / '

7:16 a.m.; 4/4 5:30 p.m.; 4/4 (~ 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months )

Reg Act 98-0-37/

7 day LCO

D Chlorine isol Inoperable / 12:50 p.m.; 4/4 6:35 p.m.; 4/4 (~5 hours)

Reg Act 98-0-38/

7 day LCO

'B' CREFAS Inoperable / 12:50 p.m.; 4/4 5:24 a.m.; 4/5 (~ 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months )

Reg Act 98-0-39/

7 day LCO

'A' CREFAS Operable / 7:30 p.m.; 4/4 3:40 a.m.; 4/5 (~ 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months )

- Reg Action 98-0-37 closed

'B' CREFAS Operable / 8:11 p.m.; 4/4 5:25 a.m.; 4/5 (~ 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months )

Reg Action 98-0-39 closed

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D-13 EDG/ Bus Operable N/A 12:04 p.m.; 4/6

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Operations Manual sections OM-L-8.2, " Narrative Logs / Scope of Entry," requires {

in part, that items are to be entered into the unified !og pertaining to system )

operability or affecting the station. Also, OM-L-12.1, " Regulatory Action", step 4.4, requires a narrative log entry in the unified log for inoperable safety system Several control room unified log entries related to the CREFAS system, including TS LCOs, were missed or back dated. The missed TS LCO entries represented a weak understanding of the CREFAS technical specifications and many back dated unified log entries represent a weakness in the log keeping practice Even though the consequence associated with the missed CREFAS LCOs was minimal, the control room unified log discrepancies were similar to problems noted in NRC inspection report 352,353/97-10. The corrective actions that were impleniented ta addrass the previous TS LCO log entry problems did not prevent the repeat of similar problene, related to the CREFAS issues and is therefore considered a violation (VIO 50-357;353/98-03-01)of Appendix B, Criterion XVI, " Corrective Action."

The two PEPS written to document and evaluate the CREFAS issues, PEP 10008186 and 10008188,did not address the missed TS LCOs and the control room log late entrie:5. The PEP reviews were focused more on the equipment failure and hardware problems and did not address other potentially related problems, such as the repetitive nature of the TS operability determination c. Conclusion Operators failed to recognize, enter and log all the applicable limiting conditions for operation (LCO) related to the control room emergency fresh air supply (CREFAS)

system inoperable equipment a'nd thus demonstrated a weakness in understanding of the CREFAS technical specifications. Failure to make LCO entries in the control room unified log is similar to problems noted in NRC inspection report 352,353/97-10 and is considered a violation of Appendix B, Criterion XVI, " Corrective Action,"

due to the repetitive nature of the issu Several problems with the licensee not keeping the unified log current and excessive use of back dating of many of the log entries demonstrated weak log keeping practices and may have contributed to the missed CREFAS LCO The ope.ations organization demonstrated a weakness in technical specification interpretation when the shift manager and operations manager both agreed that Technical Specification 3.0.3 did not have to be entered, when it should have been, when both CREFAS systems were declared inoperable. It was inappropriate to base this decision on an expectation that an engineering evaluation would, in a short period of time, declare one of the CREFAS systems operabl _ _ _

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l 08 Miscellaneous Operations issues (90712)

08.1 (Closed) V'O 50-352&353/97-10-02.Adeauate measures not established to assure desian requirements were maintained durina hydraulic control unit (HCU) on-line maintenance This violation concerned inadequate maintenance practices. Following on-line repairs to the HCUs, LGS staff identified that electricians had improperly re-terminated electricalleads for the HCUs. PECO attributed the cause of the violation to: personnel error and inadequate technician training. For corrective '

actions, PECO staff reviewed this event and the need for greater sensitivity regarding electrical terminations in the first quarter training cycle for personnel in the Reactor Services Section (RSS) of the Nuclear Maintenance Department, and again prior to the current refuel outage at an all-hands meeting. Finally, this topic has been incorporated into the continued training cycle for RSS personnel. The inspector determined the response to the violation was adequate and that PECO staff had implemented the corrective actions. This item is close .2 (Closed) VIO 50-352&353/97-Q7-03 HPCI system inoperable due to cloaaed turbine exhaust drain ling This violation concerned deficient foreign material exclusion (FME) practices that led to a small piece of cloth clogging a drain line in the HPCI system, rendering the HPCI system inoperable. PECO staff attributed the cause of the violation to personnel error and inadequate implementation of the station's FME progra Corrective actions included adding FME training to all maintenance continuing training sessions, and clarification and reinforcement of management expectations'

for performance. The inspector determined these actions were acceptable and that maintenance continuing training sessions included discussions on FME. This item is closed, ll. Maintenance M1 Conduct of Maintenance M1.1 Refuelina Maintenance Activities - Unit 1 Scope (62707)

The inspectors observed selected maintenance activities to determine whether approved procedures were in use, details were adequate, technical specifications were satisfied, maintenance was perforrned by knowledgeable personnel, and post-maintenance testing was appropriately completed.

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The inspectors observed portions of the following work activities:

Unit 1 RPV Disassembly - April 6; i

Unit 1 18 Residual Heat Removal Pump Disassembly - April 14; j

Unit 1 1 A Residual Heat Removal Pump Disassembly - April 23; l

Unit 1 Replacement of all suppression pool suction strainers for all emergency core cooling pumps - Various days throughout outage;

Unit 1 Alternate Decay Heat Removalisolation Valve Installation,- April 28; i

Unit 1 1 A Recirculation Pump Agastat Relay Replacement - May 5;

Unit 1 High Pressure Coolant injection (HPCI) Turbine / Pump Shaft Alignment

- May 5;

Unit 1 Reactor Core Isolation Cooling (RCIC) Inboard Steam isolation Valve Protective Breaker Replacement and Testing - May 8; i

) Observations and Findinos Observed maintenance activities were conducted well using approved procedures, -

and were completed with satisfactory results. Communications between the various work and support groups were good, and supervisor oversight was appropriat Maintenance technicians removed the 1B RHR pump to repair and replace the damaged components due to the failure of the lower bearing support piece. The emergent work activity was planned and executed well by the maintenance staf Excellent support was demonstrated by outage planners, system engineers,' and Health Physics (HP) technicians. The 1 A pump was also removed and a new lower bearing support installed. The pump rebuild and replac'ement was completed on schedule. Operators complied with decay heat removal requirements tnroughout the pump repair activit The plant personnel response to the Unit 1 reactor core isolation cooling (RCIC)

inboard steam isolation valve protective breaker replacement and testing was goo The engineering, maintenance and operations breaker replacement activities were well coordinated and minimized the system out of service time. The good questioning attitude of the maintenance m6 nager highlighted the potential plant risk involved with the RCIC inboard steam motor isolation valve. Technician knowledge of an existing valve packing leak on the RCIC steam inboard isolation valve resulted ll in a cautious approach to the motor operated valve breaker work, Conclusion L : Overall, maintenance activities performed during refueling outage 1RO7 werc L conducted well and without incident. Supervisors were present in the field and field

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teams were well briefed. Technicians had work packages at the job-site and understood the effect of their activity on the unit.

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M1.2 Refuelina Surveillance Activities - Unit 1 -l a .- Scope (61726)

The inspectors observed selected surveillan::e tests to 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 were properly dispositione l The inspectors observed portions of the following surveillance activities:

Unit 1 - ST-6-073-320-1," Rod Worth Minimizer Operability Determination,"-

April 4; e Unit 1 - ST-1-092-114-1."D14 Diesel Generator 4 KV SFGD Loss of Power ll Logic System Functional (LSF)/SAA and Outage Testing,"- April 7; I o Unit 1 - M-055-003," HPCI Overspeed Trip Test,"- May 5; j e Unit 1 - ST-6-052-231-1,"1 ACore Spray Pump Full Flow Test," - May 6; 4 l

e Unit 1 - ST-2-052-101-1,"1 A Core Spray LSF Test," - May 6; l e Unit 1 -' ST-2-051-105-1,"Div 1 Residual Heat Removal LSF Test,"- May 6; ;

e Unit 1 - ST-2-001-804-1," Reactor Protection System and Nuclear Steam l Supply Shutoff System, Div IIA,"- May 7; )

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o Unit 1 - ST-6-051-202-1,"A Loop Cold Shutdown Valve Test," - May 7; :

e Unit 1 - ST-1-092-111-1,"D11 Diesel Generator 4 KV SFGD Loss of Power LSF/SAA and Outage Testing," May 8; Observations and Findinas Observed surveillance tests were conducted well using approved procedures, and were completed with satisfactory results. Communications between the various work and support groups were good, and supervisor oversight was appropriat The Unit 1 D-14 Diesel Generator 4 KV loss of coolant accident (LOCA)/ loss of power (LOP) test was performed satisfactorily with one test exception. The "B" control room chiller did not start and run as expected. The chiller breaker opened ,

shortly after closure resulting in a chiller trip. Troubleshooting efforts determined I that a relay adjustment was needed to ensure the chiller would start and remain in service. Engineering performed a detailed review and evaluation to ensure that the j

chiller operation met the LOCA/ LOP test acceptance criteria. After the adjustment, i

!' the chiller was re-tested satisfactoril A test coordinator conducted the more complex logic functional tests. Pre-test briefs were conducted and good coordination and communication with the operations staff in the control room was observed.1 These tests were generally L completed without inciden I pg r - - .

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An adverse circumstance occurred early in the outage when the control room staff did not ensure that the post-maintenance test was completed for a scram relay prior to beginning testing on the second relay. This was due to combining all of the relays into one work package and not clearly communicating that information to the control room staf Conclusign Generally, surveillance testing was conducted well during refueling outage 1RF0 Large, complex tests were well supervised with management oversight and were conducted by an individual test coordinato M1.3 Inservice Insnection (ISI) Insoection Scooe (73753)

The inspector reviewed plans and schedules for the current ISl interval (first outage, first period, second interval) to verify compliance with the requirements of ASME !

Section XI,1986 Edition, no addenda, and 10 CFR 50.55a(g). Specific areas 'l inspected included ASME Section Xl ISI program coverage, qualifications and certifications of the non destructive examination (NDE) personnel, ISI NDE procedures and results, and oversight of NDE contractors. In addition, the !

inspectors observed selected NDE activities, inciuding a remote visual test (VT) of a j broken lifting rod brace for the reactor steam dryer, rernote VT of core spray )

i bracket welds, a ultrasonic test (UT) of HPCI steam inlet pipe weld, and penetrant test (PT) of two RHR pipe weld (PECO has had NDE contractors perform ISI examinations and has provided an ' l oversight which involves review and approval of qualifications and procedures, and j monitoring and independent reexamination of selected tests.) ! Observations and Findinas The inspector found the ISI work activities to be performed acceptably. The ISI procedures being used were approved by the ISI contractor and PECO Energy and were in accordance with the ASME Code requirements. The work performed was found to be thorough and of sufficient extent to determine the integrity of the components inspected. The inspector reviewed the ultrasonic and liquid penetrant test procedures used by NDE personnel and found them to be adequate for the NDE tasks performed. The inspector found the inspection implementation consistent with the approved procedures. The personnel qualification records for six NDE j inspectors were examined and found to be in compliance with the ASME code

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requirements. The inspector evaluated oversight of contractor NDE activities by reviewing the NDE oversight reports and the summary logs, which documented I appropriate PECO involvement and control of the NDE contractor activitie !

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Examination data and documentation were reviewed and found to be in accordance with the ISI procedures and ASME Code requirernents. NDE personnel performing inspections had properly identified and recorded indications and, where applicable, had processed and re-examined those indications evaluated as non-relevant. The tracking of ISI examination results indicated that the ISI program was in compliance with the ASME Code,Section XI for the specified perio c. Conclugigng The inservice inspection (ISI) was performed acceptably and included appropriate ASME program coverage, qualified personnel, approved procedures, propa implementation, adequate examination documentation, and PECO ow ' sight. The inspections were sufficiently thorough to determine the integrity of the components inspected Ill. Engineering E1 Conduct of Engineering

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E1.1 Residual Heat Removal (RHR) Pumo Reoair a. Insoection Scoce NRC Inspection Report 98-02 documented a high differential pressure condition in a jet pump. LGS staff identified the cause as metal fragments from 1B RHR pum In response to this discovery, they ins'pected and subsequently made repairs to several RHR pumps. The inspector assessed activities associated with the failure of the RHR pump, b. Observations and Findinas While troubleshooting the cause of a high differential pressure condition in no. 2 jet pump, maintenance technicians discovered a metal fragment in the vessel annulu Engineers detennined the fragment was from the 1B RHR pump and consequently inspected the pump. Their inspection identified that the metal piece was from a lower bearing support that had broken away from the RHR pump casing. Pieces of these supports were found in the RPV lower head region and recovered. Several other pieces of debris, which had been previously assessed by non-conformance reports (NCRs), were also recovered. The inspector noted that the bottom head region was very clean, free from excessive sludge and foreign material.

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The engineering team determined the cause of the pump bearing failure was that its shaft key had worked loose because the setscrew that secured the key had gradually backed out over the life of the pump. When the key broke loose, a bearing component (sleeve bushing) dislodged, was swept into the pump flow stream, and caused collateral damage to the bearing support LGS personnel also performed boroscopic inspections of all remair;ing Unit 1 RHR and Core Spray pumps; no other failures were identifie For corrective action, PECO used additional set screws to secure the key when they rebuilt the 1B RHR pump. They also improved the design of the lower bearing supports. Technicians installed extra vibration monitoring equipment on the pump, and established new baseline data for all ECCS pumps (including the Unit 2 pumps).

The facility chose not to repair the C and D RHR pumps because the run times and vibration data for these components did not indicate repairs were warrante Conclusion The licensee's activities to inspect, assess, and repair the A and B RHR pumps were very good. The engineering team determined the root cause and identified appropriate corrective action E2 Engineering Support of Facilities and Equipment E2.1 Skimmer Syrgt Tank Modification - Unit 1 a., inspection Scong (37550)

The inspector reviewed the engineering work associated with a modification to the Unit 1 skimmer surge tanks. These changes are part of the alternate decay heat removal (ADHR) modification that provides for decay heat removal from the reactor pressure vessel (RPV) and spent fuel pool (SFP) during the common residual heat removal (RHR) shutdown cooling supply local leak rate test. The inspector reviewed Engineering Change Request (ECR) LG 98-00125-001 for MOD P781 - Skimmer 1 Surge Tank Unit 1, including commercial grade dedication plan ECR LG 98-00353, {

calculation LS-0190, and the 10 CFR 50.59 safety evaluation, Observations and Findinas l The inspector found the ECR to be comprehensive and to properly evaluate the l applicable design factors, including an acceptable safety evaluatio The inspector found that approval of the modification was based on fabrication and i l welding procedures in accordance with the original Code of record (AWWA D-100- l l 1983) and evaluations for protection from radiation. NDE of the new welds was l performed with liquid penetrant testing (PT) and visual inspection (VT), instead of radiographic testing (RT) used during original construction, because the necessity of

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establishing special radiation safety zones and other ALARA considerations. PECO I

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. determined that the PT and VT were justified' based on the significant configuration constraint and ALARA considerations.' The inspector found this NDE approach

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l PECO had conducted initial walkdowns prior to modification to assess the l

dimensional configuration of the skimmer surge tank area. While a general j confirmation of the as-built dimensions was observed,. thy measurement of tank l diameter roundness, and the precise position of the embedment plates was not 1

. performed due to radiological and confined space considerations, in hindsitPt based on installation and fit up problems, the absence of these measurements appaared to have resulted in difficulties in fitting the manufactured replacemen Conclusions The engineering work on the skimmer modification had been comprehensive and '

. acceptable. The decision to forego detailed pre-fabrication measurements was -

reasonable, but better measurements prior to installation could have prevented most of the later fit up problem E2.2 - Fuel Channel Bowina

Scope (37551) 'I Fuel channel bewing was recently identified at Limerick Unit 1 following inspections of a control cell that had degraded control rod performance. The inspectors evaluated the licensee's investigation and corrective actions for this issu Observations and Findinas During refueling, a fuel bundle located in control cell 18-15, exhibited fuel channel bowing and had visible scratching and abrasion on the two channel faces which faced the control blade during Cycle 7. The fuel bundle at core location 19-16 was a relatively high exposure GE11 fuel bundle (approximately 46.5 GWd/STU) during l three cycles of irradiation and did not have any unusual operating history and was within the lifetime burn up and fuel channel exposure limits. The fuel vendor determined that the most likely cause of the problem was the fuel channel fabrication process. Residual cold work caused by expansion sizing operations

- during f abrication ree.ulted in increased non-uniform irradiation growth-induced channel bow at elevated exposures. Although this fabrication process was changed in 1993, a significant population of channels, currently in-service, are susceptible to r : this type of channel bow for exposures >45 GWd/MTU (40.8 GWd/STU). The . vendor recommended a monitoring program to provide early indications of.

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~ channel / control blade interference when exposures are greater than those listed above.

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Limerick Unit-1 fuel was more likely to reveal this condition since the effect is more l

observable at higher exposures and Limerick Unit-1 represented the first application of achieving exposures to this level. The vendor indicated that 1400 similar fuel

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l channels in other boiling water reactors have successfully completed their planned lifetime with no indication of performance anomalies; however, the peak bundle average exposures were significantly less than exposures experienced at Limerick Unit 1 During the current outage at Limerick Unit-1, the licensee replaced the susceptible fuel channels on all fuel scheduled for re-use during the next operating cycle. The licensee also identified susceptible channels in service at Limerick Unit-2 and performed scram time performance testing with no anomalies identifie A PECO testing plan was developed to address continued monitoring of suspect channels for Limerick Unit-2 and both Peach Bottom plants until the channels can be

replaced. The documented PECO plan provides the flexibility to perform either -

scram time testing or control rod stroking of all control cells containing suspect fuel channels. The inspector determined that the control rod stroking tests are more subjective tests and thereby not as reliable for predicting control rod interference indicative of channel bowing. The inability to stroke a control rod continuously over the full travel, at power, for comparison of initial control rod speeds verses final speeds makes quantifying the results difficult. The inspector also found that no definitive acceptance criteria was established for the control rod stroke testing; however, the licensee noted that the channel bowing issue was initially identified during control rod strokin '

Notwithstanding the PECO plan, the Limerick staff plans to perform, at a minimum, scram time testing for all susceptible control cells in conjunction with the normally requir,ed technical specification scram time testing perform,ed every 120 days. If the acceptance criteria, a 25% increase in scram time,is exceeded one of two additional confirmatory tests will be performed. The first test is a control rod notch test to confirm that no rod drift alarm is received. The second test is a control rod stroke test to confirm that the insert and/or withdraw speeds are consistent throughout the rods travel. If either one of these two confirmatory tests are unsatisfactory, unacceptable channel bowing is assumed and the rod will be fully inserted. Although, the documented PECO plan was less conservative than the j

testing planned for Limerick, the licensee stated that the P5CO plan would be !

revised and made consistent with the BWROG guidance when finalized l l

The inspector found that no formal generic communication had been provided to the operators to alert them to the symptoms and problems associated with channel bowing. This information is particularly important so that during routine control rod movements - such as those required during power operation - the operators would be alert for indication of channel bowin l

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16 Conclusions cThe response to degraded scram and notching performance of control rod 18-15 was conservative. The evaluation and corrective actions implemented to address fuel channel bowing in a' select population of fuel bundles were prompt and comprehensiv ~ The planned testing, to identify additional control rod anomalies, for Limerick was-

- adequate. However, the testing plan documented in the interim PECO disposition of l channel bowing, provided inappropriate flexibility. Specifically, more subjective

' testing methods were allowed instead of requiring scram time testing for each suspect channel. The engineering disposition did not establish sufficient bases for the alternate testing. In addition, no formal communication was provided to the operators, following the identification of a generic channel bowing concern.

E7 Quality Assurance in Engineering Activities E Quality Verification - Insoection Scone (37550)

The inspector reviewed the fabrication and installation of the skimmer surge tank modification. The inspector reviewed various quality verification records and

~ disposition ' Observations and Findinas

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' Independent verification performed by the PECO Quality Verification group identified '

several deficiencies in the fabrication and installation phase. - These deficiencies included inappropriate worker verification (WV) and duplicate verification (DV) sign-off procedures for defective weld acceptance, absence of welder identification (ID),

and a surface cleanliness deficiency. Cold springing had been performed by the contractor in order to achieve proper fit-up. Approval of the procedure was made by the contractor with post-installation PECO engineering review. Also, PECO identified that there had been a failure by PECO to conduct training on contracted welder sign-off acceptance procedure The following are the PECO Quality Verification deficiency findings and resolutions:

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e - Weld 1 AT208-W13 on C0180118-20was unsatisfactory due to lack of fusion. Contractor WV and DV had signed off the weld as completed on the field weld check list (FWCL).

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Subsequent to the finding, the weld was repaired and accepted.-

.o: Weld inspection 1'AT208 W11 on C0180118-19was found incomplete although the contractor had signed off as complete on the FWC ,

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Subsequent to the finding, the weld was requalified, i.e., reinspected and accepte * Weld inspection on C0180118-19 had welder ids missing from welds W23, W25, W26, and W27, even though WV had signed for each of the weld Subaequent to the finding, the weld was requalifie * Fit-up inspection on weld W8 under C0180118-18, base metal and ~

completed weld 21 had been bent by cold springing without prior PECO engineering approva Contractor analysis of the cold sprung parts determined the effect to be minimal, since the operating stress levels were low. PECO evaluated and accepted this determinatio * The structural fillet welds under C0180118-18had been completed without paint removal, even though surface cleanliness and final weld had been signed off by WV and D PECO follow-up discovered that the extent of the weld was not within the painted area and that there had been no deficienc * Welder's ID was missing from weld 1 AT208 W9-R2, even though WV had signed off the FWCL, Subsequent to the finding, the weld was requalifie These examples indicate weaknesses in the worker verification program. PECO staff was evaluating corrective actions to prevent recurrence of these problems in {

future contract I c. Conclusions !

Contract workers did not consistently perform the skimmer surge tank modification activities appropriately, and on several occasions failed to perform adequate quality verification checks. PECO quality verification personnelidentified these deficiencies, which were adequately resolve i I

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IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Outaoe Operational RP Performance [qspection Scoce (83750)

The inspector toured all major work areas of Limerick Unit 1 during outage conditions and made observations of work in progress, interviewed radiation protection (RP) technicians and workers and reviewed applicable RP documentatio A comparison of radiation work permits (RWPs), with specified electronic dosimeter (ED) alarm setpoints, was made with surveys of the applicable plant area Observations and Findinas To support outage activities the licensee assigned approximately 120 RP technicians to provide round-the-clock coverage of outage activities at six satellite RP control points, and three RCA access points. Good RP coverage and surveillance of work activities was observed. During the inspection period, the electronic dosimeter and RWP log-on computer system was unavailable for several hours and the RP staff successfully initiated manual RWP and electronic dosimetry entry and exit transactions without mishap. Effective radiological briefings were provided to the workers and effective RP technician job coverage was observed in the field. In all cases observed, regulatory requirements were complied wit At the time of the outage, area specific RWPs specified electronic dosimeter setpoints between 3 times and 28 times higher than the' highest general field dose rate recorded on surveys for the areas covered by the RWPs. The integrated dose alarm setpoints represented stay times of between 1.25 and 19 hours2.199074e-4 days 0.00528 hours 3.141534e-5 weeks 7.2295e-6 months as calculated from the highest general field dose rate in the areas covered by the RWPs. While no actual unplanned personnel exposures were observed, the licensee's practice allows the potential for unplanned personnel exposures. The licensee acknowledged the finding and indicated that this issue would be reviewed to ensure that exposure control was adequately maintained. Notwithstanding, no violations of NAC requirements was observed in this area. Licensee actions will be reviewed in a future inspection. (IFl 50 352;50 353/98-03-02) l .QoncluidQD Generally effective radiation protection job coverage and radiological briefings to workers were provided during the Unit 1 seventh refuel outage. Alarm setpoints on electronic dosimeters were not commensurate with radiological conditions and ;

accordingly, were not established to optimize exposure contro l i

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R1.2 As Low As is Reasonably Achievable (ALARA) Insoection Scope (83750)

The inspector reviewed the results of the major dose reduction activities performed during the outage. In-field observations and independent surveys were performe Interviews with ALARA personnel were conducted and outage-related ALARA docurr ents were reviewe Observations and Findinas The Unit 1 seventh refueling outage was estimated to result in 185 person-re Sixty percent of the outage exposure was estimated for drywell work,12% from the suppression pool work,11 % from refueling activities, and 4% from reactor water cleanup system work. After the first 10 days of the scheduled 45 day outage,61 person-rem had been recorde The drywell recirculation system was very effectively shielded with temporary lead blankets (approximately 40,000 lbs.), that resulted in fairly uniform and relatively

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low general area dose rates of between 10-30 mrem /hr in most area Several hot spots were identified early in the outage that affected the suppression pool work and the drywell control point area. The radwaste group was very effective in coordinating system flushes and hydrolysing the applicable floor drain piping to remove these high radioactive sources in a timely fashion, Conclusions During the Unit 1 seventh refuel outage, the drywell was effectively shielded resulting in relatively uniform and low dose rate conditions. The licensee was aggressive in reducing hot spots in plant piping, which resulted in improved radiological conditions in various plant areas, including the suppression poo RI.3 Internal Exoosure Performance Inspect un Scope (83750)

The inspector reviewed the licensee's air sampling program and whole body count results during the early outage period to determine the effectiveness of the licensee's internal exposure control progra Observations and Findinas l . Approximately 100-125 air samples were taken each day during the outage with approximately 30 screened for gamma spectral analysis and detailed DAC evaluations. Relatively low air sample results were obtained. The inspector observed good air sampler placement in various work areas and a frequent use of breathing zone lapel air samplers. As of April 13,1998(11 days of the outage),

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there had been 60 personnel contaminations recorded. Several resulted in whole body counting, of which only two indicated any measurable activity. Neither of these whole body counts were above the procedural threshold for DAC-hour tracking (> 1 DAC-hour). Therefore, for the first 11 days of the Unit 1 outage, there were no internal exposures to personne Conclusion A very good level of air sampling was performed during the Unit 1 seventh refuel outage, with no indications of airborne radioactivity areas. Follow-up whole body counts for persons subject to personnel contamination did not identify any internal exposure R2 Status of RP&C Facilities and Equipment During this inspection, the inspector conducted numerous tours of the plant during outage conditions. RCA access functioned well through three control point During this outage, significant amount of remote monitoring video equipment was used successfully for work and area monitoring. All radiological postings and locked areas met regulatory requirement R2.1 Survev Eauioment Source Checks Insoection Scone (71750)

During inspecti on of PECO inservice inspection activities, the inspector noted an apparent discrepancy regarding the daily source response check specified by Procedure HP-CG-401, Rev'O for health physics radiation and contamination survey instrumentation. The inspector evaluated PECO practices in this regard, Findinas & Observations The inspector noted that the daily source response checks for two instruments (Eberline E-520 "Frisker" used for checking small tools and/or equipment when leaving the drywell) had already been recorded as performed on the current day (April 23,1998) and the next day (April 24,1998). Procedure HP-CG-401 specified that the source response check be performed daily and the satisfactory results of the test be recorded on the sticker affixed to each individualinstrument. If the instrument failed to meet the source check criteria, the instrument was to be removed from service. Health physics (HP) personnel in the area stated that it was PECO practice to perform the test and record the results on the test record one day prior to that shown on the record. This practice had apparently developed due to a need for certain computer entries to be made in order to accommodate the subsequent day's activities in radiological controlled areas (RCAs).

The inspector determined that this documentation practice was misleading and inaccurate, but there was no evidence that the daily source response check had been unacceptable. PECO department management agreed that the practice was

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misleading and had caused some confusion in the past. PECO indicated that corrective action would be taken such that the daily source check was accurately

,_ J documented..~The. inspector determined that this failure to accurately record the daily source check actual date constituted a violation of minor significance and was not subject to formal enforcement actio Conclusions The daily source response check 'of contamination instrumentation had been recorded in a misleading manner and PECO agreed to correct the problem and -

accurately document the daily chec R4 Staff Knowledge and Performance in RP&C R4.1 Advanced Radiation Worker (ARW) Proaram a.- JDARection Scone (83750)

During a previous inspection, 50-352; 50-353/97-10,the inspector reviewed '

contamination surveys performed by advanced radiation workers that resulted in non-RP personnel providing contamination sampling and deposting of contamination areas in the plant. The issue of whether ARWs were performing as RP technicians, but did not meet the training and qualification requirements was an unresolved item (50-352; 50-353/97-10-08).During this inspection, the inspector reviewed program

. elements of the ARW program that included: procedures, training, review of ARW .

surveys, and interviews with ARW ' ' Observations and Findinas A review of the 8-hour ARW initial training and 4-hour continuing training indicated that effective instruction in elemental radiation and contamination surveying techniques were given and reinforced on an annual basi The ARW program procedure (HP-C-111, Rev.3) states that the ARWs work supervisor is responsible for monitoring and ensuring acceptable ARW performance is maintained. The inspector interviewed 2 work supervisors during the inspectio The inspector determined that the work supervisors do not specifically review ARW activities of their workers, however, they do me, mr worker performanc Procedure HP-C-111 also states that HP supervision as well as work group supervision shall periodically monitor ARW performance. Since June of 1997 there had been 62 ARW monitoring cards generated by HP supervision. No discrepancies were noted on any of the cards. No ARW monitoring cards were generated by any work supervisors, j, All ARWs were qualified to provide contamination monitoring and release of tools'

from contaminated areas. However, interviews of 10 ARWs revealed that only 2

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. release criterion on a frisker (RM-14). The common explanations provided by the

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individuals was that they do not perform their ARW tasks often enough to maintain; proficienc Although' ARW surveys were reviewed by HP supervision, they did not necessarily'.

indicate ARW performance proficiency. The inspector noted that the ARW survey forms were an abbreviated survey checklist that did not provide an indication of the -

extent or quality of the surveys performed by the ARWs One of the ARWs ir,terviewod by the inspector, did not know the correct contamination release criteria. However, the inspector reviewed an HP approved ARW survey produced-by the same individual one day earlier, to support the release of tools from a contamination area. Notwithstanding, the inspection found no radiological condition i that was'not in accordance with licensee procedures or regulatory requirements.-

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Since no regulatory requirements pertains to this area, therefore, unresolved item 50-352; 50-353/97-10-081s close ~

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in response to these findings, RP management committed that no additional ARW l tasks would be approved until each of the ARW program elements were reviewed and appropriate changes were implemented to improve ARW proficiency. Actions to be taken to ensure ARW proficiency is an inspection followup item. (IFl 50-352; 50-353/98-03-03)- Conclusion Interviews with some advance radiation worker (ARW) personnel to verify the degree of proficiency revealed a deficiency relative to knowledge of survey and contamination release criteria. Verification and oversight of act3vities conducted by ARWs was not well executed, consequently, the potential for inedequate performance exists. Notwithstanding, no actual performance deficiencies were noted during this review, R5 Staff Training and Qualification in RP&C RS.1 Temocrarv Outaae RP Technician Qualifications a,. Insoection Scooe (837%4

.The inspector reviewed selected contractor and other-utility RP technician resumes and training qualification records with respect to ANSI 3.1 criteri Observations and Findinas Although all contractor and other-utility RP technicians met the regulatory required

< , - qualification and training requirements, a weakness was identified with respect to n .

this qualification of other-utility RP technicians. All contractor RP technicians were .

tested in RP fundamentals as well as site-specific procedures. The other-utility RP

> technicians were not tested in RP fundamentals, as this requirement'was wa:ve Licen'see procedures allow waiving of training requirements, in a previous

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inspection report, 50-353; 50-353/97-10,the licensee administered an RP fundamentals examination to the permanent Limerick RP technicians with poor results. Based on the licensee's own experience, the prt.ctice of waiving the RP fundamentals examination for other-utility RP technicians was considered a poor practice. The Training Manager stated that this issue will be reviewed and taken up as a generic issue for resolution with the Mid-Atlantic Nuclear Training Group. (IFl 50-352;50-353/98-03-04) Conclusions Other-utility radiation protection (RP) technicians brought in for the Unit 1 seventh refuel outage were not evaluated for their knowledge of RP fundamentals, which was previously found to be a weakness in the Limerick RP technician training program in 1997. In light of Limerick's experience in this area, waiving of the RP fundamentals examination for other-utility RP technicians was considered a poor practic R7 Quality Assurance in Radiological Protection and Chemistry Activities R7.1 Radiological Performance Enhancement Program (PEP) Inspection Scope (83750)

The inspector reviewed selected outage radiological problem identification and resolution issues as documented in the licensee's performance enhancement program (PEP). The review was made to assess the adequacy of the licensee's ability to i,dentify and resolve radiological issues during the outag Observations and Findinas A few PEPS were identified during the early days of the outage. Those reviewed were indicative of minor safety consequence. Although the issues were minor, exposure tracking computer failure and RCA entry errors, they were not always effectively resolved and were not always timely, Conclusions Few radiological problems were identified shortly before and during the early Unit 1 seventh refuel nutage period and they were of minor safety consequence; however, they were not effectively resolved in a timely manne :

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, R8.1 - (Closed) IFl 97-10-07. Resolution of Non-conservative Exoosure Determinations !

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8etween TLD and Electronic Dosemeter Second quarter 1997 exposure discrepancies betwcan TLD and electronic dos' metry j (ED) data resulted in several non-conservative dose assignments without definitive causes. The licensee reviewed this matter and could not adequately rese!n the specific dose discrepancies. Further review resulted in assignment of the higher dose value for each of the individuals. This issue is close !

R8.2 (Closed) URI 97-10-08. Results Determination if Advanced Radiation Workers That Survev and Release Contaminated Areas Should be Qualified HP Technicians The advanced radiation worker program resulted in non-RP personnel providing contamination sampling and deposting of contamination areas in the plant. The issue of adequacy of training and qualifications of ARWs for performing various RP functions was unreviewed. Some potential performance issues were discovered during this inspection and are documented in Section R4.1 of this repor P1 Conduct of Emergency Preparedness Activities P ALERT Event Declared at Unit 1 Insoection Scope (71750)

On April 17, at 11:54 a.m., the shift manager, acting as the Emergency Director IED), declared an ALERT after detection, by smell, of an unidentified gaseous odor initially believed to be acetylene or propane gas. Unit 1 was shutdown in day 14 of i*.s refueling outage and Unit 2 was operating at 100% power. The resident staff evaluated the response to the event from the main control room and the technical support center (TSC). Obser " tions and Findinas The control room staff utilized emergency response procedures well. The operators referenced Special Event (SE) procedures for fire and toxic gas after workers identified a gas smell at the north side of the main condenr.er bay and the common turbine elevation. The operation staff activated the fire b-igade and later the industrial risk management (IRM) team to search the turbine enclosure for the

- source of the gas. ' Further, shift management ordered all ignition sources to be extinguished arid the turbine enclosure evacuated. The ED entered emergency response procedure (ERP) 101, " Classification ~ of Emergencies," and correctly classified the event as an ALERT based on hazard to station operations. State, local and NRC notificatMns were completed within the required tim __ ___-_ . - _ - . . _ .

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PECO activated tho operational support center and the TSC within the required times and the ED effectively controlled the event in the TSC. The emergency offsite facility (EOF) was partially staffed as a precaution. Response teams extensively inspected the turbine enclosure, circulating pump house, and immediate areas outside of the turbine enclosure with hand-held gas detectors in an attempt to locate the source of the gas smell. The ED maintained communications with the control room, operational support facility, and EOF. Senior station management was available in the TSC to communicate with the NRC regional and headquarters incident response cente PECO was not able to identify the source of the gas smell, but verified that the turbine enclosure was habitable and confirmed that the gaseous odor had dissipated before terminating the event. The ED terminated the ALERT at 3:05 p.m. PECO management implemented a systematic site-recovery plan to return outage workers to work and restored acetylene rigs to service. PECO later was successful in identifying the source of the gaseous smell as gearbox lubricating oil used in a cutting tool being used for work in the main condenser water box area. The tool was used on-site for the first time on April 17. The tool's operator had opened the gearbox to perform maintenance exposing the atmosphere to the fumes caused by the overheating lubrication oilinside the gearbox. The fumes drifted throughout the turbine enclosure until the turbine enclosure was evacuated, at which time, the operator closed the gearbox and left the area. The following day (Saturday,

- April 18), PECO identified the source of tne smell when the tool's operator again opened the gearbox to perform maintenance. PECO determined that the smell was

never a threat to plant worker , Conclusions The control room operators appropriately declared an ALERT on April 17,1998,due to the potential presence of an unidentified toxic or flammable gas. The licensee i controlled the non-radiological event well with no adverse effects on either uni Although the source of the gaseous smell was not identified prior to termination of the event, PECO did identify the source when the smell recurred the following da P8 Miscellaneous EP issues P (Closed) IFl 50-352. 353/97-05 01. Licensee Failure to Intearate TSC Enaineerina Expertise

! The inspector identified during the 1997 NRC-graded, biennial, emergency l

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preparedness exercise an exercise weakness in the TSC. Specifically, the licensee did not integrate the expertise of the engineering staff when making crucial decisions and failed to effectively demonstrate the maintenance team coordinator's dutie During the ALERT event (Section P1.1), the inspector observed excellent participation by and effectsve use of the engineering staff by the ED. The engineering team was proactive in following the event. For example, the inspector f

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questioned the lead engineer if the gas detectors were qualified to monitor for acetylene gas. The engineer responded that the vendor technical manual was not clear, but that the team was in the process of contacting the vendor by telephone to obtain clarification.. The engineering response was timely and contributed to enabling the ED to de-escalate from the ALERT. The inspector also noted that the maintenance team coordinator effectively monitored the in-plant teams progres This item is close V. Management Meetings X1 Exit Meeting Summary The inspector presented the inspection results to members of plant management at the conclusion of the inspection on May 26,1998. The plant manager acknowledged the inspectors' findings. The inspectors asked whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie The inspector presented the inspection results of the inservice inspection to the Director of Engineering at the conclusion of the inspection at an exit meeting on April 10,199 PECO acknowledged the findings presented. No proprietary information was identified by PEC The inspector presented the inspection results of the radiological controls inspection to the radiation protection manager at the conclusion of the inspection at an exit meeting on April 14,1998. PECO acknowledged the findings presented. No proprietary information was identified by PEC l l 1 i !

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I ATTACHMENT 1 INSPECTION PROCEDURES USED IP 37550 Engineering inspection IP 37551 Onsite Engineerir,g IP 60705 Preparation for Refueling l lP 61726 Surveillance Observation IP 62707 Maintenance Observation IP 71707 Plant Operations IP 71750 Plant Support Activities IP 73753 in Service inspection IP 83750 Occupation Radiation Exposure IP 90712 in-office Review of Written Reports IP 90713 Review of Periodic and Special Reports IP 92904 Followup - Plant Support IP 93702 Prompt Onsite Response to Events at Operating Power Reactors PARTIAL LIST OF PERSONS CONTACTED Licensee S. Baker, Radiation Protection Training Instructor P. Berry, Radiation Protection Technical Suppcrt Manager D. DiCello, Radiation Protection Manager W. Harris, Radiological Engineering Manager R. Porrino, Maintenance Manager D. Hines, Radwaste Manager M. Kaminski, Licensing Engineer J. Stankiewicz, Training Manager J. Grimcs Engineering Director ITEMS OPENED, CLOSED, AND DISCUSSED Opened VIO 50-352:353/98-03-01 Operations Log Did Not Accurately Reflect Conditions in the Plant. (Section O2.1)

IFl 50-352:353/98-03-02 Outage Operational RP Performance. (Section R1.1)

IFl 50-352;353/98-03-03 Advanced Radiation Worker (ARW) Program. (Section R4.1)

IFl 50-352;353/98-03-04 Temporary Outage RP Technician Qualification (Section RS.1)

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- Attachment 1 2 Closed L

VIO 50-352;353/97-10-02 Adequate Measures Not Established to Assure Design Requirements Were Maintained During HCU On-line Maintenance. (Section 08.2)

VIO 50-352;353/97-07-03 HPCI System inoperable due to Clogged Turbine Exhaust Drain Line. (Section 08.3)

URI 50-352;353/97-10-08 Determination if Advanced Radiation Workers That Survey and Release Contaminated Areas Should be Qualified HP Technicians. (Section R8.2)

I - IFl 50-352;353/97-10-07 Resolution of Non-conservative Exposure Determinations Between TLD and Electronic Dosemeter Results. (Section R8.1)

!- IFl 50-352;353/97-05-01 Licensee Failure to Integrate TSC Engineering Expertis (Section P8.1)

Discussed VIO 50-352:353/97-10-01. Operations Log Did Not Accurately Reflect Conditions in L the Plant. (Section 08.1)

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Attachment 1 3 LIST OF ACRONYMS USED

lADHR . Alternate decay heat removal ALARA As Low As is Reasonably Achievable ARW Advanced Radiation Worker BWROG- Boiling Water Reactor Owners Group-CCTAS Core Component Transfer Authorization Sheet CFR .

Code of Federal Regulations CREFAS Control Room Engineering Fresh Air System DAC' Derived Air Concentration-DV Duplicate Verification ECC Emergency Core Cooling System ECR Engineering Change Request ED Emergency Director

'EDG Emergency Diesel Generator EOF Emergency Offsite Facility

.ERP Emergency Response Procedure FME Foreign Material Exclusion FWCL Field Weld Check List

< GWd/MTU Gigawatt day per Metric Ton GWd/STU Gigawatt day per Standard Ton HCU_ Hydraulic Control Unit HPCI High Pressure Coolant injection ID Identification IFl - Inspection Follow up item ILRT~ Integrated leak-rate test IR inspection Report IRM lndustrial Risk Management ISI in-service inspection .

LCO Limiting Condition For Operation LOCA- Loss of Coolant Accident LOP Loss of Power NCR Non Conformance Report NDE Nondestructive Examination NRC Nuclear Regulatory Commission ORAM Outage Risk Assessment Model PECO PECO Energy PEP Performance Enhancement Process PT Penetrant Test-RCA . Radiologically. Controlled Area RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal RP&C Radiological Protection and Chemistry r RP Radiation Protection RPV- Reactor Pressure Vessel RT . . Radiographic Testing RWP Radiation Work Permit -

SDM Shutdown Margin

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Attachment 1 4 1:

l:- SF Spent Fuel Pool l SRO Senior reactor operator . .TS Technical Specification

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- TSC Technical Support Center UFSAR Updated Final Safety Analysis Report URI ' Unresolved item UT Ultrasonic Test

- WV . Worker Verification VIO Violation VT : Visualt Test l ..

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v t e Inspection Report - Limerick - 1998003
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \|
1998 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 8(0) 9(0) Security Operator Exams Emergency Planning Other

IR 05000352/1998003

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