IR 05000373/2002004

IR 05000373-02-004, IR 05000374-02-004, on 4/1/02-6/30/02; Exelon; LaSalle County Station, Units 1 & 2; Heat Sink Performance; Post-Maintenance Testing; Non-Routine Evolutions; Radioactive Material Control Program

ML022040725
Person / Time
Site:	LaSalle
Issue date:	07/12/2002
From:	Burgess B NRC/RGN-III/DRP/RPB2
To:	Skolds J Exelon Generation Co
References
IR-02-004
Download: ML022040725 (42)

Text

uly 12, 2002

SUBJECT:

LASALLE COUNTY STATION NRC INSPECTION REPORT 50-373/02-04(DRP);50-374/02-04(DRP)

Dear Mr. Skolds:

On June 30, 2002, the NRC completed an inspection at your LaSalle County Station. The enclosed report presents the results of that inspection. The results of this inspection were discussed on June 28, 2002, with Mr. G. Barnes and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. Specifically, this inspection focused on reactor safety.

Based on the results of this inspection, the inspectors identified three issues of very low safety significance (Green) that were determined to involve violations of NRC requirements. However, because of their very low safety significance and because these issues were entered into your corrective action program, the NRC is treating these issues as a Non-Cited Violations in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you deny these Non-Cited Violations, you should provide a response with a basis for your denial, within 30 days of the date of this inspection report, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at LaSalle County Station. In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/NRC/ADAMS/index.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Bruce L. Burgess, Chief Branch 2 Division of Reactor Projects Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18

Enclosure:

Inspection Report 50-373/02-04(DRP);

50-374/02-04(DRP)

REGION III==

Docket Nos: 50-373, 50-374 License Nos: NPF-11, NPF-18 Report Nos: 50-373/02-04(DRP); 50-374/02-04(DRP)

Licensee: Exelon Generation Company Facility: LaSalle County Station, Units 1 and 2 Location: 2601 N. 21st Road Marseilles, IL 61341 Dates: April 1 through June 30, 2002 Inspectors: E. Duncan, Senior Resident Inspector G. Wilson, Resident Inspector D. Kimble, Resident Inspector - Monticello P. Lougheed, Division of Reactor Safety W. Slawinski, Radiation Protection Specialist G. Wright, Division of Reactor Projects J. Yesinowski, Illinois Department of Nuclear Safety Approved by: Bruce L. Burgess, Chief Branch 2 Division of Reactor Projects

SUMMARY OF FINDINGS IR 05000373/02-04(DRP), IR 05000374/02-04(DRP), on 4/1/02-6/30/02; Exelon; LaSalle County Station, Units 1 & 2; Heat Sink Performance; Post-Maintenance Testing; Non-Routine Evolutions; Radioactive Material Control Program.

This report covers a 13-week routine resident inspection. The inspection was conducted by the LaSalle resident inspectors, the Monticello resident inspector, and two regional specialist inspectors. Three Green findings were identified which were the subject of Non-Cited Violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, Red)

using Inspection Manual Chapter (IMC) 0609 Significance Determination Process (SDP).

Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity Inspector Identified Findings

• Green. Debris collected on the drywell floor clogged the drywell floor drain sump due to an inadequate sump screen design. This rendered the leakage detection system incapable of identifying increases in unidentified leakage as required by the Technical Specifications.

The issue was of very low safety significance since other means remained available to detect an increase in unidentified leakage. A Non-Cited Violation of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for the failure to properly review for suitability the drywell floor drain sump screen. (Section 40A3)

• Green. Licensee personnel failed to properly perform a governor adjustment procedure associated with the 1A Emergency Diesel Generator (EDG) which unexpectedly rendered the EDG inoperable.

The issue was of very low safety significance since the 1A EDG was restored to service within the Technical Specification Allowed Outage Time. A Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified. (Section 1R19)

Cornerstone: Public Radiation Safety

• Green. A Non-Cited Violation of Technical Specification 5.4.1 was identified for the failure to conduct an adequate radiological survey and identify a discrete radioactive particle on an individual that alarmed a portal monitor. The failure caused a discrete radioactive particle to be released from the site undetected.

The finding was determined to be of very low safety significance since the public dose impact from the discrete radioactive particle was not more than 0.005 rem total effective dose equivalent and there were not more than five radioactive material event occurrences during the inspection period. (Section 2PS3)

Licensee-Identified Violations Violations of very low safety significance, which were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

Report Details Summary of Plant Status: Unit 1 operated at full power until May 17, 2002, when the unit was shutdown for a planned maintenance outage. The outage was completed and Unit 1 was restarted and synchronized to the grid on May 26, 2002. Following power ascension activities, Unit 1 operated at full power for the remainder of the inspection period, except for power reductions to perform maintenance, pre-planned surveillance testing activities, and rod pattern adjustments. Unit 2 operated at full power until April 9, 2002, when the unit was shut down for a planned maintenance outage. The outage was completed and Unit 2 was restarted and synchronized to the grid on April 24, 2002. Following power ascension activities, Unit 2 operated at full power for the remainder of the inspection period, except for power reductions to perform maintenance, pre-planned surveillance testing activities, and rod pattern adjustments.

1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity 1R01 Adverse Weather Protection (71111.01)

a. Inspection Scope The inspectors verified that the design features and licensee procedures protecting systems from the effects of hot weather and high winds were adequate. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), LaSalle Abnormal Operating Procedures (LOA) TORN-001, High Winds/Tornado, Revision 2, and LOA-DIKE-001, Lake Dike Damage/Failure, Revision 2, and other related documentation to verify that the plant was adequately protected from the effects of hot weather and high winds. The inspectors reviewed and verified that prescribed operator actions were appropriate to maintain readiness of essential systems to the maximum extent practicable.

The inspectors reviewed the LaSalle Summer 2002 Readiness Plan and verified that the plan assessed potential items that could affect unit operation during the summer. The inspectors verified that scheduled critical maintenance associated with the switchyard was completed and that non-critical maintenance which was not completed was accurately identified.

The inspectors reviewed LaSalle Operating Surveillance (LOS) ZZ-A2, Preparation for Summer Operations, completed May 14, 2002, and independently verified that dampers associated with the Emergency Diesel Generator Ventilation, and Essential Switchgear Room Ventilation systems were properly positioned for hot weather conditions.

b. Findings No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

a. Inspection Scope During Unit 2 maintenance outage L2P01, the inspectors performed a walkdown of accessible portions of the 2A and 2B Residual Heat Removal (RHR) systems and the Unit 2 C and D Safety Relief Valves (SRVs) and flowpaths to verify system availability for primary and alternate decay heat removal. This verification was conducted to ensure that sufficient alternate decay heat removal paths were present during maintenance activities to replace the remaining Unit 2 SRVs which had the potential to compromise the availability of the C and D SRVs.

The inspectors also performed a walkdown of the accessible portions of the 1A RHR system on May 6, 2002, to verify system availability during scheduled maintenance on the 1B and 1C RHR systems.

On May 7, 2002, the inspectors performed a walkdown of the 1B Emergency Diesel Generator (EDG) and the Unit 0 EDG to verify system availability during scheduled maintenance on the 1A EDG.

A walkdown of the Unit 1 Division 2 Core Standby Cooling System (CSCS) was performed by the inspectors on May 13, 2002, to verify system availability during scheduled maintenance on the Unit 1 Division 1 CSCS.

The inspectors reviewed documentation to determine correct system lineup. These documents included plant procedures, such as mechanical and electrical checklists, as well as plant drawings. The inspectors identified any discrepancies between the existing equipment lineup and the correct lineup.

b. Findings No findings of significance were identified.

1R05 Fire Protection (71111.05)

a. Inspection Scope The inspectors walked down the following risk significant areas to identify any fire protection degradations:

• Fire Zone 2J: Unit 1 Primary Containment

• Fire Zone 3J: Unit 2 Primary Containment

• Fire Zone 3K: Unit 2 Outboard Main Steam Isolation Valve Room

• Fire Zone 5B10: Unit 2 Motor-Driven Reactor Feedwater Pump Room

• Fire Zone 5B7: Unit 1 Hydrogen Seal Oil Units

• Fire Zone 5B8: Unit 2 Hydrogen Seal Oil Units

• Fire Zone 5B9: Unit 1 Motor-Driven Reactor Feedwater Pump Room

Emphasis was placed on control of transient combustibles and ignition sources; the material condition, operational lineup, and operational effectiveness of the fire protection systems, equipment, and features; and the material condition and operational status of fire barriers used to prevent fire damage or fire propagation.

In particular, the inspectors verified that all observed transient combustibles were being controlled in accordance with the licensees administrative control procedures. In addition, the inspectors observed the physical condition of fire suppression devices, such as overhead sprinklers, and verified that any observed deficiencies did not impact the operational effectiveness of the system. The physical condition of portable fire fighting equipment, such as portable fire extinguishers, was also observed. The inspectors verified that extinguishers were located appropriately and that access to the extinguishers was unobstructed. Fire hoses were verified to be installed at their designated locations and the physical condition of the hoses was verified to be satisfactory and access unobstructed. The physical condition of passive fire protection features such as fire doors, ventilation system fire dampers, fire barriers, fire zone penetration seals, and fire retardant structural steel coatings was inspected and verified to be properly installed and in good physical condition.

b. Findings No findings of significance were identified.

1R06 Flood Protection Measures (71111.06)

a. Inspection Scope The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and related flood analysis documentation to identify the design internal flood levels for areas which contained safety-related equipment. The inspectors also reviewed the licensees internal flooding update to its risk analysis to identify the most risk significant flooding scenarios.

Based on the insights gained from the above reviews, the inspectors selected the Core Standby Cooling System (CSCS) pump rooms, the turbine building condenser pit, the 120-inch de-icing lines, and the Reactor Core Isolation Cooling (RCIC)/Containment Spray (CS)/RHR A sump for additional review. The reviews were conducted to independently verify that the licensees flooding mitigation plans and equipment were consistent with design requirements and risk analysis assumptions. Specifically, the inspectors reviewed the maintenance history for the sump pumps, check valves, and level switches for RHR A pump room sump 1RE07 and CSCS sump 1DT02. The inspectors observed penetrations and the condition of penetration sleeve seals below the flood line in the Unit 1 CSCS rooms. In addition, the inspectors observed the general condition of watertight doors including seals, and door position limit switches for the Unit 1 and Unit 2 CSCS rooms and entry into the Unit 2 condenser pit area. Further, the inspector interviewed engineering, operations, and training personnel regarding their knowledge of the most recent Probabilistic Risk Assessment (PRA) insights on internal flooding. The inspectors also reviewed the licensees assessment of cable pull boxes

susceptible to external flooding, including discussions with engineering staff regarding the licensees ongoing evaluation of NRC Information Notice 2002-012, Submerged Safety-Related Electrical Cables.

The inspectors also reviewed Work Orders 99253390 and 990023863, which implemented LaSalle Technical Surveillance (LTS) 1000-29, Watertight Door and Penetration Inspection, on January 25, 2002 and November 13, 2000 for Unit 1 and Unit 2 respectively. The inspectors independently verified that the watertight doors and selected penetrations reviewed in the surveillance were intact. In particular, the inspectors observed the sealing of equipment below the floodline, such as electrical conduits, the presence of holes or unsealed penetrations in floors and walls between flood areas, the adequacy of watertight doors between flood areas, and determined whether sources of potential internal flooding that had not been previously analyzed existed.

The inspectors also reviewed LaSalle Abnormal Operating Procedure (LOA) FLD-001, Flooding, Revision 4, dated July 14, 2001, and verified that actions prescribed in the procedure could reasonably be used to achieve the desired actions. The inspectors verified that problems related to flooding, including past flooding events, were included in the licensees corrective action program and were properly identified and prioritized for resolution.

b. Findings No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

Biennial Review of Heat Sink Performance a. Inspection Scope The inspector reviewed documents associated with the Unit 1 and Unit 2 RHR and High Pressure Core Spray (HPCS) system room coolers. These coolers were selected based on their high Risk Achievement Worth (RAW) in the licensees probabilistic safety analysis. The inspector reviewed completed surveillance tests and associated calculations, and performed independent calculations to verify that these tests ensured adequate heat transfer capability. The inspector reviewed the documentation to confirm that the test or inspection methodology was consistent with Electrical Power Research Institute (EPRI) standard NP-7552, Heat Exchanger Performance Monitoring Guidelines. The inspector also reviewed documentation to verify that acceptance criteria were consistent with the design basis values contained in the UFSAR and Technical Specifications. The inspector reviewed documentation to verify that testing instruments were within calibration and discussed the use of these instruments with the system engineer to verify that the instruments were used correctly. The inspector reviewed documentation to verify that the licensee took appropriate actions to verify the physical integrity of the heat exchangers. The inspector also reviewed documentation to verify that the licensee had appropriate controls in place to ensure availability of the ultimate heat sink under adverse conditions.

The inspector reviewed corrective action documents concerning heat exchanger and heat sink performance issues to verify that the licensee had an appropriate threshold for identifying issues. The inspectors also evaluated the effectiveness of these corrective actions, including the engineering justification for operability, when applicable.

b. Findings No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

a. Inspection Scope On May 6, 2002, the inspectors observed licensed operator re-qualification training scenario ESG43, "High Pressure Core Spray (HPCS) Water Leg Pump Trip /A Control Rod Drive (CRD) Pump Trip With B CRD Pump Reduced Capacity/Anticipated Transient Without Scram (ATWS)."

The inspectors verified crew performance in terms of clarity and formality of communication; the ability to take timely and safe actions; the prioritizing, interpreting, and verifying of alarms; the correct use and implementation of procedures, including alarm response procedures; timely control board operation and manipulation, including high-risk operator actions; the oversight and direction by the shift manager, including the ability to identify and implement appropriate Technical Specification actions such as reporting and emergency plan actions and notifications; and group dynamics.

b. Findings No findings of significance were identified.

1R13 Maintenance Risk Assessment and Emergent Work Evaluation (71111.13)

a. Inspection Scope The inspectors reviewed the licensees evaluation of plant risk, scheduling, configuration control, and performance of maintenance associated with planned and emergent work activities and verified that scheduled and emergent work activities were adequately managed. In particular, the inspectors reviewed the licensees program for conducting maintenance risk safety assessments and verified that the licensees planning, risk management tools, and the assessment and management of online risk was adequate.

The inspectors also verified that licensee actions to address increased online risk during these periods, such as establishing compensatory actions, minimizing the duration of the activity, obtaining appropriate management approval, and informing appropriate plant staff, were accomplished when online risk was increased due to maintenance on risk-significant structures, systems, and components (SSCs). The following specific activities were reviewed:

• The inspectors reviewed the maintenance risk assessment for work planned during the week of March 31, 2002.

• The inspectors reviewed the maintenance risk assessment for work planned during the week of May 5, 2002.

• The inspectors reviewed the maintenance risk assessment for work planned during the week of May 12, 2002.

• The inspectors reviewed the maintenance risk assessment for work planned during the week of May 19, 2002.

• The inspectors reviewed the maintenance risk assessment for work planned during the week of June 2, 2002.

b. Findings No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

.1 Routine Operability Evaluation Review a. Inspection Scope The inspectors reviewed selected Operability Evaluations (OEs) and Engineering Changes (ECs) of degraded and non-conforming conditions affecting mitigating systems and barrier integrity to ensure that operability was properly justified and the component or system remained available, such that no unrecognized increase in risk had occurred.

The following evaluations were reviewed:

• OE02-08: Unit 1 Drywell Floor Drain

• OE 97052: 2C RHR Injection Line

• OE 02-010: Unit 2 Hydraulic Actuator 2TZ-VD003C For EDG Ventilation Damper 2VD03YA Only Strokes 3.0 Inches Instead of 3.5 Inches

• OE 02-09 Reactor Core Isolation Cooling (RCIC) System Data Collection

• EC 336192: Unit 2 Division 1, 125 Volt Direct Current Battery Cell #21 Charge

• EC 337298 Unit 1A Reactor Recirculation Flow Control Valve b. Findings No findings of significance were identified.

.2 (Closed) Unresolved Item 50-373/0203-02(DRP); 50-374/0203-02(DRP): OE 02-06, Unit 1 and Unit 2 Secondary Containment Leakage.

As discussed in NRC Inspection Report 50-373/02-03(DRP); 50-374/02-03(DRP), during the performance of LaSalle Technical Surveillance (LTS) 300-3, Secondary Containment

Leak Rate Test, pressure in the secondary containment was identified as abnormally low. This occurred with the reactor building ventilation (VR) and Standby Gas Treatment (VG) systems of both units shutdown and with the turbine building ventilation (VT)

systems of both units operating. Due to the unexpected condition, the test was aborted and the issue was evaluated under OE 02-06, Unit 1 and Unit 2 Secondary Containment Leakage, to determine whether the operability of the secondary containment was adversely impacted. The evaluation concluded that based upon historical testing data and walkdowns, the Standby Gas Treatment (VG) system and secondary containment would perform all of their design functions.

Licensee personnel subsequently identified degraded VT system supply ductwork which resulted in a large negative turbine building differential pressure. Although this aided the ability of the VG system to draw down the secondary containment with respect to the atmosphere, this condition threatened the capability of the VG system to draw down the secondary containment to a pressure less than the turbine building pressure. This was important to ensure that air flow was always into the secondary containment for processing.

The inspectors reviewed OE 02-06 which documented that the functions of the Standby Gas Treatment system discussed in the Standard Review Plan (SRP) included the ability to maintain the secondary containment vacuum greater than or equal to -0.25 inches water gauge with respect to atmosphere and maintain the pressure in the secondary containment less than the pressure external to the secondary containment (i.e. negative with respect to adjacent structures such as the turbine building). Unresolved Item 50-373/0203-04(DRP); 50-374/0203-04(DRP)) was opened pending a determination of whether the secondary containment testing acceptance criteria, which did not include a verification of negative pressure with respect to the turbine building, was adequate.

During this inspection period, the inspectors determined that the licensee was only required to meet the surveillance acceptance criteria specified in the Technical Specifications and was therefore not required to verify that the pressure in the secondary containment was negative with respect to the turbine building. As a result, the inspectors concluded that the secondary containment testing acceptance criteria was adequate.

The VT system was subsequently repaired. The licensee was considering administrative controls, such as monitoring turbine building pressure, to prevent recurrence of the issue.

1R16 Operator Workarounds (71111.16)

a. Inspection Scope The inspectors reviewed Operator Workaround (OWA) 338/339 (Unit 1/Unit 2) regarding feedwater heater trips during reactor recirculation pump downshifts to identify any potential adverse impact on the function of mitigating systems or the ability to implement an abnormal or emergency operating procedure.

b. Findings No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19)

a. Inspection Scope The inspectors reviewed and observed the following post-maintenance testing activities involving risk significant equipment:

• WO 99237316-01 Unit 2 Safety Relief Valve Testing Per LTS-500-19

• WO 99263772-01 Inspect 1HS-VY003

• WO 99180664-01 Unit 1 A EDG Woodward Governor Adjustments

• WO 00414392-01 Unit 0 EDG Breaker Inspection

• WO 00387494-01 Unit 0 EDG Governor Inspection

• WO 00449604-01 Unit 2B EDG Potentiometer Replacements

• WO 00450211-03 2E51-F080 Failed to Reopen During Routine Cycling During post-maintenance testing observations, the inspectors verified that the test was adequate for the scope of the maintenance work which had been performed, and that the testing acceptance criteria was clear and demonstrated operational readiness consistent with the design and licensing basis documents. The inspectors also verified that the impact of the testing had been properly characterized during the pre-job briefing; the test was performed as written and all testing prerequisites were satisfied; and that the test data was complete, appropriately verified, and met the requirements of the testing procedure. Following the completion of the test, the inspectors verified that the test equipment was removed, and that the equipment was returned to a condition in which it could perform its safety function.

b. Findings Introduction Work Order (WO) 99180664: 1A EDG Woodward Governor Adjustments One Green finding and an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified due to the failure to properly perform LaSalle Electrical Procedure (LEP) DG-105, Maintenance and Adjustment of Woodward U 8 Governor Shutdown Solenoids, which rendered the EDG inoperable.

Description On May 8, 2002, the inspectors observed the performance of LEP-DG-105 on the 1A EDG to evaluate the adequacy of post maintenance testing following the cleaning and adjustment of the governor shutdown solenoid. The licensee did not perform the post maintenance testing activity in accordance with the approved written procedure. Step 14 of Attachment A to the procedure was not performed which energizes the shutdown solenoid prior to performing final solenoid adjustments. The failure to perform the step in accordance with the procedure resulted in an unexpected start of the 1A EDG since the associated shutdown circuitry was never energized. The 1A EDG restarted when the oil pressure switches were reset allowing the air start motor pistons to re-engage. The

licensee conducted a root cause investigation of the event. The event increased the scheduled unavailability of the 1A EDG.

Analysis The inspectors reviewed this issue against the guidance contained in Appendix B, Issue Dispositioning Screening, of Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports. In particular, the inspectors compared this finding to the findings identified in Section 4, Insignificant Procedure Errors, to Appendix E, Examples of Minor Issues, of IMC 0612 to determine whether the finding was minor. The inspectors determined that finding had greater safety significance than similar issues described in IMC 0612, Appendix E, Sections 4.a, 4.b, and 4.f. This safety significance was attributed to the fact that the procedural error resulted in a loss of availability of the 1A EDG.

The failure to properly follow LEP-DG-105, Maintenance and Adjustment of Woodward U 8 Governor Shutdown Solenoids, was a human performance error that resulted in additional unavailability of the 1A EDG, warranting further review in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP).

The inspectors conducted this review utilizing the SDP Phase 1 Screening Worksheet For IE [Initiating Events], MS [Mitigating Systems], and B [Barrier Integrity]

Cornerstones. The inspectors determined that although the unavailability of the 1A EDG was affected, because the loss of the 1A EDG did not exceed the Technical Specification Allowed Outage Time (AOT) and no weather-related impact existed, that the finding was screened as Green.

Enforcement 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions. The failure to properly perform LEP-DG-105 was an example where the requirements of 10 CFR 50, Appendix B, Criterion V, were not met and was a violation. However, because of its low safety significance and because it was entered into the corrective action program, the NRC is treating this issue as a Non-Cited Violation (NCV 50-373/0204-02(DRP); 50-374/0204-02(DRP)), in accordance with Section VI.A.1 of the NRCs Enforcement Policy. This issue was entered into the licensees corrective action program as CR 017346.

1R20 Refueling and Outage Activities (71111.20)

LaSalle Unit 1 and Unit 2 Maintenance Outage Observations a. Inspection Scope On April 9, 2002, Unit 2 was shut down for planned maintenance outage L2P01. The outage was completed and Unit 2 was restarted and synchronized to the grid on April 24, 2002. On May 17, 2002, Unit 1 was shut down for planned maintenance outage L1P03.

The outage was completed and Unit 1 was restarted and synchronized to the grid on May 26, 2002. The inspectors evaluated L2P01 and L1P03 outage activities to ensure that

the licensee considered risk in developing the outage schedule; adhered to administrative risk reduction methodologies developed to control plant configuration; developed mitigation strategies for losses of key safety functions; and adhered to the operating license and Technical Specification requirements that ensured defense-in-depth. The following specific outage-related activities were accomplished:

• Outage Plan Review The inspectors reviewed the licensees outage control plan and verified that the licensee had appropriately considered risk, industry experience, and previous site-specific problems. The inspectors also confirmed that contingency plans for losses of key safety functions had been established.

• Monitoring of Shutdown Activities The inspectors observed portions of the Unit 2 shutdown for Maintenance Outage L2P01 and the Unit 1 shutdown for L1P03 and verified that the plant was operated in accordance with regulatory requirements and plant procedures. In particular, the inspectors verified that cooldown restrictions were followed.

• Licensee Control of Outage Activities The inspectors verified that the licensee appropriately managed the configuration of equipment during the outage to ensure that a defense-in-depth commensurate with the outage risk plan for key safety functions and applicable Technical Specifications was maintained. The inspectors also verified that outage activities were appropriately managed. In particular, out-of-service activities were reviewed to ensure that tags were properly hung to support the out-of-service. Reactor coolant system instrumentation was verified to be configured to provide adequate indication of reactor vessel pressure, temperature, and level. In addition, the inspectors routinely observed decay heat removal system parameters and verified that decay heat removal systems were functioning properly. The inspectors verified that flow paths, configurations, and alternative means for inventory addition and decay heat removal were consistent with the outage risk plan. The inspectors verified that the licensee maintained secondary containment in accordance with Technical Specifications.

• Monitoring of Heatup and Startup Activities The inspectors verified that Technical Specifications, license conditions, and other prerequisites, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant configurations. The inspectors conducted a walkdown of containment prior to restart and verified that debris had not been left which could adversely impact the Emergency Core Cooling System (ECCS)

suction strainers.

• Identification and Resolution of Problems

The inspectors verified that the licensee identified problems related to outage activities at an appropriate threshold and entered them into the corrective action program.

b. Findings No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope The inspectors observed surveillance testing on risk-significant equipment and verified that the SSCs selected were capable of performing their intended safety function and that the surveillance tests satisfied the requirements contained in Technical Specifications, the UFSAR, and licensee procedures. During surveillance testing observations, the inspectors verified that the test was adequate to demonstrate operational readiness consistent with design and licensing basis documents, and that the testing acceptance criteria was clear. The inspectors also verified that the impact of the testing had been properly characterized during the pre-job briefing; the test was performed as written and all testing prerequisites were satisfied; the test data was complete, appropriately verified, and met the requirements of the testing procedure; and that the test equipment range and accuracy was consistent with the application, and the calibration was current. Following the completion of the test, the inspectors verified that the test equipment was removed, and that the equipment was returned to a condition in which it could perform its safety function.

The following surveillance testing activities were observed:

• LOS-RH-Q3, Attachment 2B, 2B RHR (LPCI) and RHR Service Water Valve Inservice Test for Cold Shutdown or Refuel Condition.

• LTS-1100-14, Unit 2 Scram Insertion Times.

• LOS-RH-Q1, RHR and RHR Service Water Pump and Valve Inservice Test for Modes 1, 2, 3, 4, and 5" on May 14, 2002.

• LaSalle Instrument Surveillance (LIS) NB-104A, Unit 1 Reactor Vessel Low Water Level 1 ECCS [Emergency Core Cooling System] Division 1 Initiation and Level 2 RCIC [Reactor Core Isolation Cooling] Initiation Instrument Channels A & C Calibration on May 16, 2002.

• LTS-300-3, Secondary Containment Leakage Test, on May 3, 2002.

• LTS-200-228, 2A DG Flow Balance Test, on June 19, 2002.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications (71111.23)

a. Inspection Scope Temporary Modification 336420 - Seal Weld on 2E12-F009 The inspectors reviewed Temporary Modification 336420 which installed a seal weld on shutdown cooling isolation valve 2E12-F009 to address a body-to-bonnet leak. The inspectors reviewed the associated 10 CFR 50.59 safety evaluation against the system design basis documentation, including the UFSAR and verified that the temporary modification had no adverse impact on safety. The inspectors also conducted a walkdown of the temporary modification and compared the installed configuration against the configuration prescribed in the design drawings. A review of Non-Destructive Testing (NDT) examination results was also accomplished.

Temporary Modification 337326 - Repair to 2E22-S001 Heat Exchanger Partition Plate The inspectors reviewed Temporary Modification 337326 which installed a temporary patch over an erosion hole in the 2B EDG cooler partition plate. The inspectors reviewed the associated 10 CFR 50.59 safety evaluation against the system design basis documentation, including the UFSAR and verified that the temporary modification had no adverse impact on safety. The inspectors also verified that the repair was accomplished in accordance with American Society of Mechanical Engineers (ASME) Code requirements and that heat exchanger flow had not been adversely impacted.

b. Findings No findings of significance were identified.

2. RADIATION SAFETY Cornerstone: Public Radiation Safety 2PS3 Radiological Environmental Monitoring and Radioactive Material Control Programs (71122.03)

.1 Reviews of Radiological Environmental Monitoring Reports and Data a. Inspection Scope The inspector reviewed the Annual Radiological Environmental Operating Reports for calendar years 2000 and 2001, and the results of monthly radiological environmental monitoring analyses for the first quarter of 2002. The inspector also reviewed the land use census, changes made to the Offsite Dose Calculation Manual (ODCM), and the results of the inter-laboratory comparison program for 2000 and 2001, that were related to the radiological environmental monitoring program. These reviews were conducted to

verify that the radiological environmental monitoring program (REMP) was implemented as required by Technical Specifications and the ODCM, and to verify that any changes did not affect the licensees ability to monitor the impacts of radioactive effluents on the environment. Additionally, the inspector evaluated the present locations of the environmental monitoring stations and the types of samples collected from each location to determine if they were consistent with the ODCM and NRC guidance in Regulatory Guides 1.21, 4.8 and an associated NRC Branch Technical Position.

b. Findings No findings of significance were identified.

.2 Walkdowns of the Radiological Environmental Monitoring Stations and Meteorological Tower a. Inspection Scope The inspector walked down four of the nine environmental air sample monitoring stations to determine whether they were located as described in the ODCM, to assess equipment material condition and operability, and to verify that monitoring station orientation, vegetation growth control, and equipment configuration allowed for the collection of representative samples. The meteorological tower was also walked down to verify that the tower was sited adequately and that instrumentation was available and installed consistent with Regulatory Guide 1.23. Meteorological data readouts and recording instruments located at the tower and as provided by the plant process computer were verified to be operable and were compared to determine if there were any line loss differences.

b. Findings No findings of significance were identified.

.3 Reviews of Radiological Environmental Monitoring Equipment Maintenance and Testing a. Inspection Scope The inspector selectively reviewed the most recent environmental air sample pump calibration records, the REMP contractors pump calibration procedures and meteorological tower equipment calibration records for calendar year 2001 and the first quarter of 2002, to verify that the testing program for this equipment was implemented consistent with Technical Specifications and procedural requirements. The most recent calibration records for both the rotameter currently used by the REMP technician to field check air sample pumps and the rotameter standard used to calibrate the field rotameter, were reviewed to verify that instrument certifications met industry standards and had traceability to the National Institute of Standards and Technology. The inspector discussed air sample pump maintenance practices with the contractor REMP technician to assess the adequacy of the preventive maintenance program for this equipment and to

evaluate the technicians knowledge of the program and procedures.

b. Findings No findings of significance were identified.

.4 Reviews of REMP Sample Collection and Analyses a. Inspection Scope The inspector accompanied the contractor REMP technician and observed the individual collect an Illinois River surface water sample and change-out air particulate filters at four environmental air sampling stations. The observations were made to determine whether samples were collected in accordance with the contractors sampling procedure and to determine if appropriate practices were used to ensure sample integrity. Additionally, the inspector observed the technician complete pump flow and pump vacuum field checks to verify that they were accomplished adequately, consistent with the vendors procedures.

The inspector assessed the analytical detection capabilities of the contract laboratory used by the licensee to analyze its environmental sample, and discussed with radiation protection management its plans to revise the ODCM relative to the laboratory inter-comparison program. The assessment was conducted to determine if the radiological environmental sample analysis and inter-laboratory comparison programs were implemented consistent with the ODCM and industry standards, and to verify that the vendor was capable of performing adequate radiological measurements.

b. Findings No findings of significance were identified.

.5 Unrestricted Release of Material From Radiologically Controlled Areas (RCAs)

a. Inspection Scope The inspector evaluated the licensees procedures and practices for the unrestricted release of material from RCAs and for the survey of personnel leaving the RCA and the site. Specifically, the inspectors reviewed the licensees personnel survey and unconditional release program to verify that: (1) radiation monitoring instrumentation used to perform surveys for unrestricted release were appropriate; (2) instrument sensitivities were consistent with NRC guidance contained in Inspection and Enforcement Circular 81-07 and Health Physics Positions in NUREG/CR-5569 for both surface contaminated material and material in volumetric form; (3) criteria for survey and unconditional release conformed to NRC requirements; and (4) licensee procedures were technically sound and provided appropriate guidance for survey techniques. The inspector reviewed the licensees most recent 10 CFR Part 61 analyses and the licensees assessment of the plants radionuclide mix to determine if the potential impact of difficult to detect contaminants (such as those that decay by electron capture) was adequately captured in the unrestricted release program.

Additionally, the inspector reviewed the circumstances associated with the inadvertent

release of a worker from the site on February 18, 2002, with a discrete radioactive particle clung to the workers coat. Specifically, the inspector reviewed the licensees root cause investigation of the incident, station procedures associated with external dose assessment and with assessment of radiologically contaminated personnel, and the incident was discussed with radiation protection staff involved in its follow-up. The inspector also independently calculated the deep dose equivalent which the worker received from the particle to verify the accuracy of the licensees dose assessment.

b. Findings Introduction A Green finding and an associated Non-Cited Violation (NCV) of Technical Specification 5.4.1 were identified for the failure to conduct adequate radiological surveys of a contaminated individual in accordance with station procedures, resulting in the inadvertent release of a discrete radioactive particle from the site.

Description On February 18, 2002, an electrical maintenance department (EMD) worker wearing an overcoat that was contaminated with a 120,000 disintegration per minute (54 nanocurie) discrete radioactive particle, alarmed the main access facility (MAF) portal radiation monitor as the individual attempted to leave the LaSalle Station. (Station portal monitors employ plastic scintillation detectors that are primarily sensitive to gamma radiation, and are set to alarm at an integrated activity level of 50 nanocuries). The individual contacted the radiation protection (RP) department as required by station procedure and reported the alarm to a radiation protection technician (RPT). The technician used a small article monitor and surveyed the personnel effects that the worker carried in a bag. The monitor did not alarm and the bag was cleared. The two individuals then proceeded back to the MAF portal monitors where the EMD worker and subsequently his overcoat were separately passed through the portal monitor. Although the monitor again alarmed as the worker wore his coat thru the monitor, the coat itself did not cause an alarm as it was hand-held by the RPT and moved past the monitor detectors. The worker then cleared the monitor without wearing the coat and was allowed to leave the site along with his coat and other personal belongings. Since the coat had never been in the RCA according to the worker and the coat did not cause the monitor to alarm when it was separately passed through the monitor by the RPT, the technician assumed the prior monitor alarms were false and no contamination was present on the coat. The coat was not surveyed by the RPT using an appropriate instrument such as a Geiger-Mueller (GM) survey meter, as required by station procedure.

On February 21, 2002, the EMD worker returned to the site wearing the overcoat for the first time since February 18, and immediately proceeded to the MAF portal monitors because the alarms received three days earlier concerned the individual. The monitor again alarmed as the worker passed through it wearing the coat and the problem was reported to the RP department. Radiation protection staff performed a thorough survey of the coat using a portable GM survey meter and identified the discrete radioactive particle located on the lower outside back of the coat. The particle was removed and

determined to be comprised primarily of cobalt-60.

Follow-up surveys of those areas where the EMD worker had either worn or stored the coat at the plant between February 18 and February 21, identified no contamination.

Similarly, no contamination was identified in the EMD workers home or vehicle. The licensees investigation was unable to determine the origin of the particle or how it got onto the workers coat. The licensee concluded that had a portable GM survey instrument been used to survey the worker and his coat during the initial response to the portal monitor alarm, the particle would have been identified on February 18 and not released off-site.

To assess the total effective dose equivalent (TEDE) received by the individual, the licensee interviewed the individual and determined that the coat had previously been worn to the station and successfully cleared the portal monitors on February 14, and was not brought to the station on February 15, 16 or 17. Consequently, the licensee assumed that the particle was picked-up by the coat on February 18. Based on conservative assumptions of the thicknesses and densities of the coat and the other clothing worn by the worker under the coat (consistent with NUREG/CR-5873) and the amount of time the coat was worn between February 18 and February 21, the licensee calculated an estimated deep dose equivalent to the worker from the particle of approximately 0.5 mrem.

Analysis This issue represented a performance deficiency associated with the Public Radiation Safety Cornerstone that affected the cornerstone objective because a discrete radioactive particle was inadvertently released into the public domain. Specifically, the survey performed on February 18 was not completed consistent with the licensees procedure for the assessment of radiologically contaminated personnel and resulted in an occurrence in the licensees radioactive material control program. Since the procedure, had it been followed, adequately covered this condition, this occurrence could have been prevented. Consequently, the issue represents a finding that is more than minor. Although the discrete radioactive particle produced a TEDE as defined in 10 CFR Part 20, the dose did not exceed one mrem. Therefore, consistent with the Pubic Radiation Safety Significance Determination Process (SDP) for Radioactive Material Control, this finding is not analyzed using the SDP. However, since the finding is greater than minor but not greater than Green, it is dispositioned as a Green Non-SDP Finding of very low safety significance consistent with Manual Chapter 0612.

Enforcement Technical Specification 5.4.1 requires, in part, that procedures be established, implemented and maintained that cover the activities recommended in Regulatory Guide 1.33, Revision 2, Appendix A, which includes procedures for radiation surveys and contamination controls. Procedure RP-AA-350, Assessment of Radiologically Contaminated Personnel, requires in Section 5.3 that RPT surveys of individuals that alarm a contamination monitor include surveys of all areas that caused the alarm using a GM or other approved instrument. The failure to survey the EMD workers coat and other clothing using a hand-held GM survey instrument on February 18, 2002, was a

violation of Technical Specification 5.4.1. However, since the licensee documented this issue in its corrective action program (Condition Report and Root Cause Investigation Action Tracking Item No. 96125) and because the violation is of very low safety significance, the violation is being treated as a Non-Cited Violation (NCV 50-373/0204-03; 50-374/0204-03).

.6 Identification and Resolution of Problems a. Inspection Scope The inspector reviewed recent Nuclear Oversight field observations and an audit performed in 2001, and condition reports (CRs) generated in 2001 through April 2002 relative to the REMP and radioactive material control programs. In addition, the inspector reviewed the results of REMP program self-assessments completed in April 2001 and April 2002, including the corrective actions taken for the 2001 self-assessment. These reviews were conducted to determine if the licensee adequately identified individual problems and trends, evaluated contributing causes and extent of condition, and developed corrective actions to prevent recurrence. The inspector also discussed with the radiation protection manager plans to strengthen the radioactive material control program during outages through an enhanced greeter initiative, and plans to improve REMP Coordinator transition and change management should future staffing changes occur.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITIES 4OA1 Performance Indicator Verification Cornerstones: Initiating Events and Barrier Integrity

.1 Unplanned Scrams Per 7,000 Critical Hours and Scrams With a Loss of Normal Heat Removal Performance Indicator (PI) Review a. Inspection Scope The inspectors reviewed Licensee Event Reports (LERs) and operator log entries for Unit 1 and Unit 2 to determine the number of scrams that occurred during the previous four quarters and compared that number to the number in the performance indicator.

The inspectors also reviewed licensee Monthly Operating Reports and operator logs to verify the accuracy of the number of critical hours reported. The inspectors also reviewed the licensees basis for crediting normal heat removal capability for each of the reported reactor scrams. The inspection was performed utilizing the performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Indicator Guideline, Revision 2 dated November 2001.

b. Findings

No findings of significance were identified.

.2 Reactor Coolant System Specific Activity Performance Indicator a. Inspection Scope The inspector reviewed the dose equivalent iodine calculation procedure, the reactor coolant system (RCS) specific activity performance indicator procedure and interviewed members of the licensees chemistry staff involved in the determination and verification of RCS specific activity. The inspector also reviewed the licensees Unit 1 and Unit 2 chemistry sample analysis results for maximum dose equivalent iodine for the twelve month period beginning May 2001. These reviews were performed to verify that the licensee adequately determined dose equivalent iodine values, and to verify adherence to station procedures and to the guidance contained in Nuclear Energy Institute (NEI) 99-02 relative to assessing and reporting the RCS specific activity performance indicator.

Additionally, the inspector observed a chemistry technician collect an RCS sample to verify that the sample was collected properly and discussed with chemistry staff the method used to calculate dose equivalent iodine to verify its adequacy.

b. Findings No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

a. Inspection Scope The inspectors reviewed corrective actions associated with the following Problem Identification Forms (PIFs) and Condition Reports (CRs) to verify the effectiveness of the licensees corrective actions:

• PIF L2000-4349 Configuration Control Issues

• PIF L2000-03778 Fire Seals

• CR 88165 0 EDG Tripped on Low Lube Oil Pressure Attributes considered during the review of licensee actions included the following:

• Complete and accurate identification of the problem in a timely manner commensurate with its significance and ease of discovery.

• Evaluations and disposition of performance issues associated with maintenance effectiveness.

• Evaluation and disposition of reportability issues.

• Consideration of extent of condition, generic implications, common cause, and previous occurrences.

• Classification and prioritization of the resolution of the problem commensurate

with its safety significance.

• Identification of root cause and contributing causes of the problem.

• Identification of corrective actions which are appropriately focused to correct the problem.

• Completion of corrective actions in a timely manner commensurate with the safety significance of the issue.

b. Findings No findings of significance were identified.

4OA3 Event Follow-up (71153)

Cornerstones: Initiating Events and Mitigating Systems

.1 (Closed) Licensee Event Report (LER) 50-374/02-01: Transient Increases in Unit 2 Unidentified Leakage Due to Clogged Drywell Floor Drain Sump Screen a. Inspection Scope The inspectors evaluated Licensee Event Report (LER) 50-374/02-01: Transient Increases in Unit 2 Unidentified Leakage Due to Clogged Drywell Floor Drain Sump Screen.

b. Findings Introduction A finding of very low significance (Green) and an associated NCV of 10 CFR 50, Appendix B, Criterion III, Design Control related to a modification performed on the drywell floor drain screen were identified by the inspectors.

Description On March 16, 2002, the Unit 2 unidentified leakage in the drywell reached 3.0 gallons per minute (gpm) which exceeded the previous days calculation by more than 2.0 gpm, thereby exceeding Technical Specification 3.4.5.d limits for increased unidentified leakage within a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. The increase was transient and returned to normal values. Troubleshooting identified that debris collected on the drywell floor from previous maintenance activities had clogged the drywell floor drain screen due to inadequate design and restricted water flow through the floor drain to the drywell floor sump. The licensee redesigned and installed a new floor drain screen cover and initiated a periodic maintenance activity to perform a thorough cleaning of the drywell after each refueling outage to prevent recurrence. The inspectors determined that although the drywell floor drain sump flow monitoring system was inoperable, other multiple independent means for

detecting drywell leakage were still available and working as designed. Since there were other redundant systems available for leak detection, this Technical Specification 3.4.5.d violation was determined to be of very low safety significance.

Analysis The inspectors reviewed this issue against the guidance contained in Appendix B, Issue Dispositioning Screening, of Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports. In particular, the inspectors compared this finding to the findings identified in Appendix E, Examples of Minor Issues, of IMC 0612 to determine whether the finding was minor. Following that review, the inspectors concluded that the guidance in Appendix E was not applicable or useful for the specific finding since no examples were provided which involved equipment that was inadvertently rendered inoperable as a direct result of an inadequate design change. As a result, the inspectors compared this performance deficiency to the minor questions contained in Section C, Minor Questions, to Appendix B of IMC 0612. The inspectors concluded that the issue was more than minor since the finding, if left uncorrected, could become a more significant safety concern. This conclusion was based on the fact that a small reactor coolant system leak would not be detected by the drywell floor drain sump monitoring system because the sump screen was degraded and clogged. Without adequate detection, a small initial leak could become larger and therefore become a more significant concern prior to its detection by other means.

As a result, the inspectors reviewed this issue in accordance with Inspection Manual Chapter (IMC) 0609 Significance Determination Process (SDP). The inspectors conducted this review utilizing the SDP Phase 1 Screening Worksheet For IE [Initiating Events], MS [Mitigating Systems] and B [Barrier Integrity] Cornerstones. The inspectors determined that none of the above cornerstones were directly impacted by this finding, therefore, the issue screened out as Green.

Enforcement 10 CFR 50, Appendix B, Criterion III, Design Control, requires that measures shall be established for the selection and review for suitability of application of materials, parts, and equipment that are essential to the safety-related functions of structures, systems, and components. The failure to properly review the suitability of the application of the existing drywell floor drain screen cover adversely impacted the response of the drywell floor drain monitoring system. As a result, fine debris collected in the screen and resulted in a significant flow restriction, rendering the drywell floor drain sump monitoring system incapable of detecting small leaks, an essential function of this safety related system. The failure to properly review for suitability the drywell floor drain sump screen was an example where the requirements of 10 CFR 50, Appendix B, Criterion III, were not met and was a violation. However, because of its low safety significance and because it was entered into the corrective action program (CR 99520), the NRC is treating this issue as a Non-Cited Violation (NCV 50-373/0204-01(DRP);

50-374/0204-01(DRP)), in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

4OA6 Meetings

Exit Meeting Summary The inspectors presented the routine resident inspection results to Mr. G. Barnes and other members of licensee management on June 28, 2002. The results of a biennial heat sink inspection were presented to Mr. G. Barnes and other members of licensee management at the conclusion of that inspection on April 5, 2002. The results of a Radiological Environmental Monitoring Program (REMP) inspection were presented to Mr. G. Barnes and other members of licensee management at the conclusion of that inspection on May 3, 2002. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee Identified Violations The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as Non-Cited Violations (NCVs).

10 CFR 50, Appendix B, Criterion XI, Test Control, requires that all testing required to demonstrate that SSCs will perform satisfactorily in service is identified and performed in accordance with written test procedures. On May 22, 2002, licensee personnel identified that Safety Relief Valve (SRV) pressure drop testing conducted in accordance with LTS-500-18 failed to ensure that all required SRV pilot valve seals were tested. This issue was entered into the licensees corrective action program as Condition Report (CR) 00104591. Because no actual impact on the operability of the SRVs was identified, this violation is not more than of very low safety significance, and is being treated as a Non-Cited Violation (50-373/0204-04(DRP); 50-374/0204-04(DRP)).

10 CFR 55.53(f)(2), Conditions of License, requires that for requalification of senior reactor operators (SROs) limited to fuel handling activities, that one shift of activities under the direction of a qualified SRO must have been completed. On May 7, 2002, licensee personnel identified that SROs limited to fuel handling activities had performed those activities prior to observation of those activities for one shift by a qualified SRO. This item was entered into the licensees corrective action program as CR 00106992. Because no actual fuel handling errors occurred, this violation was not more than of very low safety significance, and is being treated as a Non-Cited Violation (50-373/0204-05(DRP); 50-374/0204-05(DRP)).

KEY POINTS OF CONTACT Exelon D. Czufin, Site Engineering Manager D. Enright, Operations Manager F. Gogliotti, Design Engineering Supervisor G. Barnes, Site Vice President J. Henry, System Engineering Manager W. Riffer, Regulatory Assurance Manager M. Schiavoni, Station Manager C. Wilson, Station Security Manager ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-373/0204-01;50-374/0204-01 NCV Inadequate Drywell Sump Screen Design 50-373/0204-02;50-374/0204-02 NCV 1A EDG Governor Adjustment Error 50-373/0204-03;50-374/0204-03 NCV Inadequate Radiological Survey 50-373/0204-04;50-374/0204-04 NCV Inadequate SRV Testing 50-373/0204-05;50-374/0204-05 NCV Inadequate Requalification of Fuel Handling SROs Closed 50-373/0204-01;50-374/0204-01 NCV Inadequate Drywell Sump Screen Design 50-373/0204-02;50-374/0204-02 NCV 1A EDG Governor Adjustment Error 50-373/0204-03;50-374/0204-03 NCV Inadequate Radiological Survey 50-373/0204-04;50-374/0204-04 NCV Inadequate SRV Testing 50-373/0204-05;50-374/0204-05 NCV Inadequate Requalification of Fuel Handling SROs 50-373/0203-02;50-374/0203-02 URI Secondary Containment Leakage Measurement Discussed None

LIST OF ACRONYMS USED ACE Apparent Cause Evaluation ADAMS Agency Document and Management System AOT Allowed Outage Time ASME American Society of Mechanical Engineers ATWS Anticipated Transient Without Scram B Barrier Integrity CR Condition Report CRD Control Rod Drive CS Containment Spray CSCS Core Standby Cooing System DRP Division of Reactor Projects EC Engineering Change ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EMD Electrical Maintenance Department EPRI Electrical Power Research Institute ER Engineering Request GM Geiger-Mueller gpm gallons-per-minute HPCS High Pressure Core Spray IE Initiating Events IMC Inspection Manual Chapter LCP LaSalle Chemical Procedure LEP LaSalle Electrical Procedure LER Licensee Event Report LIS LaSalle Instrument Surveillance LOA LaSalle Abnormal Operating Procedure LOS LaSalle Operating Surveillance LPCI Low Pressure Coolant Injection LTP LaSalle Technical Procedure LTS LaSalle Technical Surveillance MAF Main Access Facility MS Mitigating Systems NCV Non-Cited Violation NDT Non-Destructive Testing NEI Nuclear Energy Institute ODCM Offsite Dose Calculation Manual OE Operability Evaluation OWA Operator Work Around PARS Publicly Available Records PI Performance Indicator PIF Problem Identification Form PRA Probabilistic Risk Analysis RAW Risk Achievement Worth RCA Radiologically Controlled Area RCIC Reactor Core Isolation Cooling RCS Reactor Coolant System

REMP Radiological Environmental Monitoring Program RHR Residual Heat Removal RP Radiation Protection RPT Radiation Protection Technician SDP Significance Determination Process SEAG Site Engineering Administrative Group SRO Senior Reactor Operator SRP Standard Review Plan SRV Safety Relief Valve SSC Structure, System, or Component TEDE Total Effective Dose Equivalent UFSAR Updated Final Safety Analysis Report WO Work Order WR Work Request VG Standby Gas Treatment VR Reactor Building Ventilation VT Turbine Building Ventilation VY Core Standby Cooling System Equipment Cooling Water System

LIST OF DOCUMENTS REVIEWED Adverse Weather Protection LOS-ZZ-A2 Preparation For Winter/Summer Readiness Revision 22 LOS-ZZ-A2 Preparation For Winter/Summer Readiness May 2002 LOA-DIKE-001 Lake Dike Damage/Failure Revision 2 LOA-TORN-001 High Winds/Tornado Revision 2 UFSAR Section 9.2.6.1.2 - Power Generation Design Bases Revision 14 RegGuide 1.27 Ultimate Heat Sink For Nuclear Power Plants January 1976 LaSalle Station Summer Readiness Duty Team Guide - 2002 EC 334017 Revise Maximum Cooling Water Inlet Temperature Revision 0 From the UHS to 102F For CSCS and WS [Service Water], CW [Circulating Water] From 97.5F to 100F 50.59 Evaluation Revise Maximum Cooling Water Inlet Temperature Revision 0 L-02-0182 From the UHS to 102F For CSCS and WS [Service Water], CW [Circulating Water] From 97.5F to 100F Calc 97-200 VY Cooler Thermal Performance Model - 1(2)VY01A Revision A00 and 1(2)VY02A Calc 97-195 Thermal Model of Comed/LaSalle Station Unit 0, 1, Revision A00 and 2 Diesel Generator Jacket Water Coolers WO 00340260 1TIC-VX007 Alarming Before Setpoint in LOR WO 00331190 2TIC-VX007 Alarming Early - 95 Degrees Equipment Alignment LMP-MS-08 Safety Relief Valve Removal/Replacement Revision 7 LOP-RH-17 Alternate Shutdown Cooling Revision 17 EC 113199 Replace SRVs Per Procedure LMP-MS-08 LOP-RH-1AM U1 A Residual Heat Removal System Revision 0 Mechanical Checklist LOP-RH-02E U1 A Residual Heat Removal System Revision 18 Electrical Checklist

LOP-DG-03M Unit 0 Diesel Generator Mechanical Revision 7 Checklist LOP-DG-03E Unit 0 Diesel Generator Electrical Checklist Revision 7 LOP-DG-2M U1 HPCS Diesel Generator Mechanical Revision 8 Checklist LOP-DG-2E U1 1B Diesel Generator Electrical Checklist Revision 9 LOP-RHWS-1BM Unit 1B RHR Service Water Mechanical Revision 1 Checklist LOP-RH-01E Unit 1 RHR Service Water Electrical Revision 8 Checklist LOP-DG-06M Unit 1A Diesel Generator Cooling System Revision 11 Mechanical Checklist LOP-DG-06E Unit 1A Diesel Generator Cooling System Revision 5 Electrical Checklist Fire Protection Updated Final Safety Analysis Report Appendix H Revision 13 (UFSAR)

Technical Requirements Manual - Fire Rated Assemblies Revision 0 Section 3.7.o Operability Determination OE02-005 Unsealed Openings (Core Holes) in Revision 0 Floor Slab Apparent Cause Evaluation 95253 Bus Duct Seal Deficiencies Final Safety Analysis Report (FSAR) Response to NRC Questions October 1979 NRC Inspection Manual - Chapter Significance Determination Process Appendix F 0609 LTS-1000-31 Inspection of Bus Duct Seals on Revision 7 Unit 1 and Unit 2 Drawing NP-8-E-SE-01 Bus Duct Penetration Tech-Sil Inc.

Drawing 1E-1-3639 Non-Segregated Bus Duct - Auxiliary Revision G Building Sections Drawing 1E-1-3641/3644 Non-Segregated Bus Duct - Auxiliary Revision 2 Building Elevation 731

Drawing S-572 Auxiliary Building Floor Framing Plan

- El. 731 South Area Drawing S-1072 Auxiliary Building Floor Framing Plan

- El. 731 North Area Condition Report 095253 Potential Bus Duct Fire Seal Deficiencies Discovered By NRC Risk Significance Determination Bus Duct Seal Deficiencies at April 5, 2002 LaSalle EC 335434 Evaluate Bus Duct Breeches Between Division 1&2 Switchgear Rooms Flood Protection Measures LTS-1000-29 Watertight Door and Penetration Completed Inspection - Unit 1 January 12, 2002 LTS-1000-29 Watertight Door and Penetration Completed Inspection - Unit 2 November 13, 2000 LTS-1000-3 Groundwater Level Surveillance Revision 8 LaSalle Focused Area Flood Protection Measures Completed March 3, Self-Assessment 2001 LOP-PF-01 Closure of Watertight Doors Revision 4 LOA-FLD-001 Flooding Revision 4 LTS-1000-29 Watertight Door and Penetration Revision 8 Inspection CR 00082752 Storm Drain Configuration Control Issues CR 00104408 NRC Observation Notes During Inspection of Unit 1 Core Spray Cooling System (CSCS) Room A/R No. 41953 Focus Area Self Assessment Plan March 12, 2001 Drawing M-7 General Arrangement Main Floor Plan April 24, 2001 Drawing M-9 General Arrangement Ground Floor Plan May 2, 2001 Drawing M-11 General Arrangement Basement Floor March 5, 2001 Plan

Drawing M-87 P&ID Core Standby Cooling System - January 4, 2001 System Equipment Cooling Water System Drawing M-91 P&ID RB Equipment Drains January 12, 2002 Drawing M-104 P&ID RB Floor Drains February 8, 1999 Drawing M-105 P&ID Diesel Bldg. Floor Drains January 5, 2001 Drawing M-106 P&ID Diesel/Aux/Turbine & Service Bldg May 13, 1999 Floor Drains Drawing M-112 P&ID Waste Water Treatment System January 5, 1999 Drawing M-151 P&ID Diesel/Aux/Turbine Bldg Floor Drains September 24, 2001 Drawing M-1203 Reactor-Aux Bldg-Diesel Gen. RM. Sleeve Loc. Pl. El. 673-4" & 663-0" and 694-6"&

687-0" L02-LTS-1000-29 Watertight Door & Penetration Inspection August 9, 2000 L01-LTS-1000-29 Watertight Door & Penetration Inspection September 25, 2001 LOA-FLD-001 Flooding Rev. 4 July 14, 2001 LOS-ZZ-Q2 Sump Pump Inspection March 15, 2001 LTS-1000-3 Groundwater Level Surveillance June 22, 1999 LOP-PF-01 Closure of Water Tight Doors October 23, 2001 LOS-ZZ-A4 Sump Inspection March 21, 1994 LGA-002 Secondary Containment Control (Emergency Procedure)

2PM10J A-5-02 Service Water Low Pressure Annunciator Response LOA-WS-201 Loss of Service Water CR-AR-84907 Condition Report on 2RE08PA failure May 18, 2001 during Functional PMT WOP 99253390 01 Work Order Package for implementation of January 25, 2002 LTS-1000-29 Rev. 8 for Unit 1 LaSalle Internal Flooding Risk Insights Gained from 2001 PRA.

Heat Sink Performance Calculation L-002457 LaSalle County Station Ultimate Heat Revision 3 Sink Analysis Calculation 97-199 VY Cooler Thermal Performance Revision B Model - 1(2)VY03A Calculation 97-200 VY Cooler Thermal Performance Revision A Model - 1(2)VY01A and 1(2)VY02A Calculation L-001077 Residual Heat Removal Pumps B & C Revision 2 Cubicle Cooler Ventilation System Calculation L-001078 Residual Heat Removal Pump A Revision 2 Cubicle Cooler Ventilation System Calculation L-001221 High Pressure Core Spray Pump Revision 2 Cubicle Cooler Ventilation System Calculation L-001584 Volume of the Ultimate Heat Sink Revision 1 CR 98176 2B Residual Heat Removal Heat March 5, 2002 Exchanger Test (L2R08) Results Are Indeterminate CR 98305 VY Cooler Air Flow Testing Procedure March 5, 2002 Deficiencies CR 101568 VY Cooler Coils and Screens Dirty March 14, 2002 CR 102283 VY Cooler Calculation Computer April 04, 2002 Output Contains Program Flags Drawing 28SW404543 Core Standby Cooling System July 21, 1976 Equipment Area Cooling Coils (1VY01A, 1VY02A, 2VY01A, 2VY02A)

Drawing 28SW404553 Safety Related Heat Recovery Coils - July 21, 1976 Core Standby Cooling System Equipment Area Cooling Coils (1VY03A, 2VY03A)

ER 9804483 Evaluate Division 1 Operation with September 24, 1998 Various Components Out of Service Procedure CY-AA-120-400 Closed Cooling Water Chemistry Revision 2 Procedure LCP-110-1 Chemical Analysis and Corrective Revision 33 Action Schedule

Procedure LCP-830-21 Circulating/ Service Water Corrosion Revision 5 Monitoring Program Procedure LCP-830-23 Monitoring and Adjusting Chemical Revision 1 Feed System Equipment Procedure LTP-100-5 Service Water Component Inspection Revision 4 Guideline Procedure LTS-200-12 Northwest and Northeast Cubicle Revision 7 Cooler 1(2)VY01A and 1(2)VY04A Flowrate Test Procedure LTS-200-13 1(2)VY02A, Southwest Cubicle Cooler Revision 5 Flowrate Test, Division III Procedure LTS-200-14 1(2)VY03A, Southeast Cubicle Cooler Revision 4 Flowrate Test Procedure LTS-200-19 Emergency Core Cooling Systems Revision 7 Cubicle Area Cooler Air Flowrate Test Procedure LTS-200-27 0 Diesel Generator Cooling Water Revision 6 System Flow Test Specification J-2582 Design Specification for Heat March 25, 1975 Exchanger Coils and Cabinets -

LaSalle County Station - Unit 1 SEAG 97-000577 Evaluation of Potential Water Hammer December 4, 1997 Events Within the Core Standby Cooling System Equipment Cooling Water System SEAG 00-000243 Evaluation of Measured Air Flowrate June 01, 2000 Which Is Less than Acceptance Criteria in LTS-200-19 for Room Cooler 1VY04A Surveillance LTP-100-5 Water to Air, Air Side Heat Exchanger September 1, 1992 Inspection Report, 1VY-02C Surveillance LTP-100-5 Water to Air, Air Side Heat Exchanger September 8, 1992 Inspection Report, 1VY-03C Surveillance LTS-200-13 Southwest Corner Room Area Cooler June 3, 1998 Water Flowrate Test 1VY02A Surveillance LTS-200-19 Water to Air, Air Side Heat Exchanger December 18, 1991 Inspection Report, 2VY-03A

Trend Reports Air Flow Trends - 1VY01A, 1VY02A, March 29, 2002 1VY03A, 2VY01A, 2VY02A, 2VY03A Trend Reports Differential Pressure Trends - 1VY01A, March 29, 2002 1VY02A, 1VY03A, 2VY01A, 2VY02A, 2VY03A WO 99059404 01 Air Side Flowrate Test 2VY03A May 24, 2001 WO 99059406 01 Air Side Flowrate Test 2VY02A June 6, 2001 WO 99164043 01 Heat Exchanger Water Flowrate Test August 9, 2001 1VY03A WO 99210556 01 Heat Exchanger Water Flowrate Test March 5, 2002 2VY02A WO 99220041 01 Southwest Corner Room Cooler Air March 13, 2002 Side Flowrate Test 1VY02A WO 99221980 01 Air Side Flowrate Test 1VY03A March 14, 2002 WO 00371879 01 LOS-DG-Q3 Unit 2 High Pressure December 14, 2001 Core Spray Diesel Generator Cooling Water Pump WO 00377105 01 LOS-DG-Q1 0 Diesel Generator December 28, 2001 Cooling Water Pump WO 00390649 01 LOS-DG-Q3 Unit 2 High Pressure February 8, 2002 Core Spray Diesel Generator Cooling Water Pump WO 00393941 01 LOS-DG-Q1 0 Diesel Generator February 18, 2002 Cooling Water Pump WR 950036092 01 Air Side Flowrate Test 2VY03A February 19, 1999 WR 950054677 01 Unit 2 Northwest Cubicle Area Cooler February 11, 1999 Air Side Flowrate Test 2VY01A WR 950105880 01 Southeast Area Cooler Water Flowrate January 06, 1999 Test 2VY03A WR 960064305 01 Air Side Flowrate Test 2VY02A January 11, 1999 WR 970091697 01 Unit 1 Northwest Cubicle Area Cooler June 22, 1998 Air Side Flowrate Test 1VY01A WR 980058487 01 Southwest Corner Room Area Cooler October 20, 2000 Water Flowrate Test 1VY02A

WR 980060965 01 Heat Exchanger Water Flowrate Test September 30, 1999 1VY03A WR 980063945 01 Air Side Flowrate Test 1VY03A April10, 2000 WR 980066356 01 Unit 1 Northwest Cubicle Area Cooler April 21, 2000 Air Side Flowrate Test 1VY01A WR 980080278 01 Unit 2 Northwest Cubicle Area Cooler January 31, 1999 Water Side Flowrate Test 2VY01A WR 980135489 01 Unit 1 Northwest Cubicle Area Cooler October 5, 1999 Water Side Flowrate Test 1VY01A WR 990018659 01 Core Standby Cooling System Pond May 18, 1999 Sediment Deposition Check WR 990052824 01 Core Standby Cooling System Pond January 22, 2001 Sediment Deposition Check WR 990059400 01 Unit 2 Northwest Cubicle Area Cooler April 20, 2001 Air Side Flowrate Test 2VY01A WR 990059401 01 Heat Exchanger Water Flowrate Test March 10, 2000 2VY02A WR 990059402 01 Unit 2 Northwest Cubicle Area Cooler April 23, 2001 Water Side Flowrate Test 2VY01A WR 990059405 01 Southeast Area Cooler Water Flowrate January 05, 2001 Test 2VY03A WR 990098661 01 Southwest Corner Room Cooler Air April 4, 2000 Side Flowrate Test 1VY02A WR 990166167 01 Unit 1 Northwest Cubicle Area Cooler April 23, 2001 Water Side Flowrate Test 1VY01A Operator Licensing Requalification Licensed Operator Requalification Revision 0 Scenario Guide ESG 43 LGA - 010 Failure to SCRAM Revision 3 LGA - 001 RPV Control Revision 3 EP-AA-111 Emergency Classification and Revision 3 Protective Action Recommendations

Maintenance Risk Assessment and Emergent Work Evaluation LaSalle 7-Day Look-Ahead Schedule Various Operability Evaluations EC 336192 Battery Equalize Charge at 2.5 VDC Per Cell SEAG 02-00081 Application of 2.5 Volts Per Cell Charging March 28, 2002 Criteria VETIP J-0150 LEP-DC-01 Individual Equalizing Cell Charge for Station Revision 7 Batteries CR 00101955 Formal Documentation Not Obtained For Change to LEP-DC-01 LEP-DC-01 Unit 2 Division 1, 125 VDC Battery Cell #21 March 26, 2002 Data WO 0421426 Unit 2 Division 1, 125 VDC, Battery Cell #21 March 26, 2002 Charge S&L Specification Atmospheric Cleanup Filter Units For The J-2583 LaSalle County Station Units 1 & 2 OE02-08 Unit 1 Drywell Floor Drain Revision 0 WO 990213169 1RF08M - Inspect Screen January 19, 2002 WO 990012582 1RF08M - Inspect Screen November 11, 1999 WO 990209213 2RF08M - Inspect Screen November 21, 2000 OE97052 2C RHR Injection Line March 28, 1997 CR 00109991 Damper Actuator 2TZ-VD003C Does Not May 30, 2002 Achieve Full Stroke OE02-09 Unit 1 RCIC Data Collection June 7, 2002 EC 000337298 Operation of 1A RR FCV on LVDT May 25, 2002 Operator Workarounds OWA338/339 Feedwater Heater Trips During Reactor Recirculation Pump March 6, 2002 Downshift

LOP-RR-08 Changing Reactor Recirculation Pump Speed From Fast to Revision 27 Slow Speed LGP-2-1 Normal Unit Shutdown Revision 61 ATM 36429 Root Cause Evaluation of the Feedwater Temperature November 28, Transient During Unit 1 RR Pump Downshift 2000 Post-Maintenance Testing LTS-500-19 Unit 2 Main Steam Safety Relief Valve Operability Revision 5 WO 99237316 Unit 2 Main Steam Safety Relief Valve Testing WO 99180664 Unit 1A EDG Woodward Governor Adjustments April 26, 2002 CR 107346 Step 14 of LEP-DG-105 Not Performed May 8, 2002 WO 00414392 0 EDG Inspect Breaker April 18, 2002 WO 00387494 0 EDG Governor Inspection April 17, 2002 LOS-DG-M1 0 Diesel Generator Operability Test Revision 46 WO 00449604 2B Diesel Generator Potentiometer Replacements May 30, 2002 WO 00450211-03 2E51-F080 Valve Did Not Reopen During Cycling June 3, 2002 LEP-EQ-114 Westinghouse 250 VDC MCC Equipment Parts Revision 8 Replacement For EQ Requirements or Repair CR 00110348 2E51-F080 Failed To Open June 3, 2002 VETIP J-0157 Instruction Manual for Motor-Operated November 1984 Potentiometer (Return-To-Center)

Refueling and Outage Activities OU-LA-104 Shutdown Safety Management Program Revision 2 LTP-1500-2 Alternate Decay Heat Removal Lineup Revision 2 Capabilities L2P01 Shutdown Safety Revision 0 Management Program EC 336113 SRVs As Alternate Decay Heat Removal April 1, 2002 Crane Technical Paper Flow of Fluids Through Valves, Fittings 1988

1. 410 and Pipes LOP-RH-14 Alternate Shutdown Cooling Revision 17

Kenny Manta Industrial Evaluation of Level 1 Coating - LaSalle April 18, 2002 Services Letter Station LST01 Kenny Manta Industrial Evaluation of the LaSalle Station Unit 2 February 5, 1999 Services Letter Drywell Floor Coating Kenny Manta Industrial Evaluation of Level 1 Coatings at LaSalle November 14, 2000 Services Letter Station (L2R08)

L2P01 Drywell Cleanup Project Plan LOP-DW-01 Drywell Closeout Revision 33 LOP-DW-01 Drywell Closeout - Documentation April 23, 2002 LGP-1-S1 Startup Checklist Revision 51 LGP-1-1 Reactor Startup EC 336572 Upgrade Drywell Floor Drain 2RF08M Revision 0 Screen EC 336572 Upgrade Drywell Floor Drain 2RF08M Revision 1 Screen L1P03 Shutdown Safety Revision 0 Management Program AR 00088182 Failure of Division 3 Temperature December 27, 2001 Controller to Maintain Temperature CR 00106992 Limited SROs Do Not Properly Maintain May 7, 2002 Active Status Surveillance Testing LOS-RH-Q3 Att. 2B RHR (LPCI) and RHRSW Valve Inservice Test For Revision 35 Cold Shutdown or Refuel Condition LTS-1100-4 Scram Insertion Times Revision 20 LTS-1100-4 Scram Insertion Times April 24, 2002 LTS-300-3 Secondary Containment Leak Rate Test Revision 16 LTS-300-3 Secondary Containment Leak Rate Test May 3, 2002 LOS-RH-Q1 RHR and RHR Service Water Pump and Valve Revision 49 Inservice Test for Modes 1, 2, 3, 4, and 5 LIS-NB-104A Unit 1 Reactor Vessel Low Water Level 1 ECCS Revision 11 Division 1 Initiation and Level 2 RCIC Initiation Instrument Channels A & C Calibration

CR 00108062 Maintenance Work Around - EDG Reverse Power April 8, 2002 K32X Relay ACE 102854 Unit 1A Emergency Diesel Generator Lockout Due to April 9, 2002 Bumped Relay LTS-200-228 2A DG Flow Balance Test Revision 3 Temporary Plant Modifications EC 336420 Temporary Repair of the 2E12-F009 Valve to Eliminate Revision 0 Pressure Seal Gasket Leakage (Seal Welding of Bonnet)

WO00430503-03 Install Temporary Repair of the 2E12-F009 Isolation Valve April 12, 2002 50.59 L02-0156 Temporary Repair of the 2E12-F009 Valve to Eliminate April 13, Pressure Seal Gasket Leakage 2002 EC 336699 Evaluation of the 2E12-F009 Seal Weld Leak VT Report 2E12-F009 Inboard Shutdown Cooling Valve April 21, E02-163 2002 EC 337326 Temporary repair to 2E22-S001 Heat Exchanger Plate May 28, 2002 WO00448732 Installation of TMOD EC 337326 May 29, 2002 Performance Indicator Verification Monthly Performance Indicator Packages for January 2001-March Unplanned SCRAMS 2002 Monthly Performance Indicator Packages for January 2001-March SCRAMS with a loss of Normal Heat Sink 2002 Monthly Operating Reports January 2001-March 2002 Identification and Resolution of Problems PIF L2000-4349 Configuration Control Issues August 30, 2001 PIF/CR L2000- High Differential Pressure Alarm May 9, 2000 03023

PIF/CR L2000- Extent of Condition - HVAC Filter Discrepancies November 26, 2000 06843 Root Cause Installation of HVAC Pre-Filters Different Than Revision 1 AD-AA-106 Described in UFSAR LS-AA-125-1004 Effectiveness Review for HVAC Pre-Filters April 18, 2002 Different Than Described in UFSAR CR 110032 2B EDG KVAR Output was Abnormal May 31, 2002 L2001-05813 Failed R3 Potentiometer October 10, 2001 CR 88165 0 EDG Trip On Low Lube Oil Pressure December 26, 2001 Event Followup WR 990209213-01 2RF08M - Inspect Drywell Floor Drain Screen November 21, 2000 WR 990012582-01 1RF08M - Inspect Drywell Floor Drain Screen November 11, 1999 WO 990213169 1RF08M - Inspect Drywell Floor Drain Screen January 19, 2002 L2P01 Drywell Cleanup Project Plan CHRON 307434 LaSalle ComEd SEC Calculation R-M-1044 April 11, 1995 Calc. R-M-1044 Debris Screen Equivalent Area to Drain Pipe April 12, 1995 LER 50-374/02-01 Transient Increases in Unit 2 Unidentified Leakage Due to Clogged Drywell Floor Drain Sump Screen Cross-Cutting Issues CR 00108062 Maintenance Work Around - DG Reverse Power K32X April 8, 2002 Relay Dwg. M-137 Reactor Building Equipment Drain System Sheet 4 40