IR 05000454/2002006

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IR 05000454-02-006 and 05000455-02-006 DRP, on 07/01 - 09/30/2002, Byron Station, Units 1 & 2. Non-Cited Violations Noted
ML023010673
Person / Time
Site: Byron  Constellation icon.png
Issue date: 10/25/2002
From: Ann Marie Stone
NRC/RGN-III/DRP/RPB3
To: Skolds J
Exelon Generation Co
References
IR-02-006
Download: ML023010673 (57)
v • d • e


Text

ber 25, 2002

SUBJECT:

BYRON STATION, UNITS 1 AND 2 USNRC INTEGRATED INSPECTION REPORT 50-454/02-06; 50-455/02-06

Dear Mr. Skolds:

On September 30, 2002, the U.S. Nuclear Regulatory Commission (USNRC) completed an integrated inspection at your Byron Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on October 4, 2002, with Mr. R. Lopriore and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and to 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.

Three findings of very low safety significance (Green) were identified in the report. Two of the three findings were determined to involve violations of USNRC requirements. However, because of the very low significance of these two findings, and because they were entered into your corrective action program, the USNRC is treating the issues as a Non-Cited Violation in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

If you contest the subject or severity of the Non-Cited Violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U. S. Nuclear Regulatory Commission - Region III, 801 Warrenville Road, Lisle, IL 60532-4351; the Director, Office of Enforcement, U. S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector office at the Byron facility.

During this past year, in response to the terrorist attacks on September 11, 2001, the USNRC issued an Order and several threat advisories to commercial power reactors to strengthen licensees capabilities and readiness to respond to a potential attack. The USNRC established a deadline of September 1, 2002 for licensees to complete modifications and process upgrades required by the Order. In order to confirm compliance with this Order, the USNRC issued Temporary Instruction 2515/148 and over the next year, the USNRC will inspect each licensee in accordance with this Temporary Instruction. The USNRC continues to monitor overall security controls and may issue additional temporary instructions or require additional inspections should conditions warrant. In accordance with 10 CFR 2.790 of the USNRCs Rules of Practice, a copy of this letter and its enclosure will be made available electronically for public inspection in the USNRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the USNRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Ann Marie Stone, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-454; 50-455 License Nos. NPF-37; NPF-66

Enclosure:

Inspection Report 50-454/02-06; 50-455/02-06

REGION III==

Docket Nos: 50-454; 50-455 License Nos: NPF-37; NPF-66 Report Nos: 50-454/02-06; 50-455/02-06 Licensee: Exelon Generation Company, LLC Facility: Byron Station, Units 1 and 2 Location: 4450 N. German Church Road Byron, IL 61010 Dates: July 1 through September 30, 2002 Inspectors: R. Skokowski, Senior Resident Inspector P. Snyder, Resident Inspector C. Brown, Clinton Resident Inspector R. Jickling, Emergency Preparedness Inspector D. Jones, Reactor Inspector G. ODwyer, Reactor Inspector S. Orth, Senior Radiation Specialist S. Ray, Braidwood Senior Resident Inspector S. Sheldon, Reactor Inspector T. Tongue, Project Engineer R. Walton, Reactor Inspector R. Winter, Reactor Inspector C. Thompson, Illinois Department of Nuclear Safety Approved by: Ann Marie Stone, Chief Branch 3 Division of Reactor Projects

SUMMARY OF FINDINGS IR 05000454-02-06, 05000455-02-06; Exelon Generation Company, LLC; on 07/01-09/30/02, Byron Station; Units 1 & 2. Heat Sink Performance, Operability Evaluations, and Refueling and Other Outage Activities.

This report covers a 3-month period of baseline resident inspection and announced baseline inspections on radiation protection, emergency preparedness and inservice testing, which included completion on Temporary Instruction 2515/145, Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles. The inspection was conducted by Region III inspectors and the resident inspectors. Three Green findings, two of which were associated with Non-Cited Violations (NCVs) were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be green or be assigned a severity level after USNRC 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.

A. Inspection Findings Cornerstone: Initiating Events Green. A finding of very low safety significance was identified through a self-revealing event. Specifically, the licensee failed to assess and manage the increase in risk associated switchyard maintenance activities that commenced prior to restoring reactor coolant system (RCS) inventory to greater than 5 percent pressurizer level as required by the licensees preestablished contingency plan. This was identified when the outage manager contacted the switchyard coordinator to inform him that the prerequisite regarding RCS inventory was about to be met, at which time the outage manager was informed that work already commenced. The primary cause of this finding was related to the cross-cutting area of Human Performance. Although administrative controls were in place to prevent switchyard work the RCS was at reduced inventory, the controls were not implemented.

The finding was more than minor because it increased the likelihood of those events that upset plant stability and challenge a critical safety function, specifically electric power control, during shutdown operations. The finding was of very low safety significance because both emergency diesel generators were subsequently determined to be available; therefore, providing sufficient redundancy such that the licensees ability to cope with a loss of offsite power was not degraded during the switchyard activities. This was determined to be a Non-Cited Violation of 10 CFR 50.65 (a)(4). (Section 1R20)

Cornerstone: Mitigating Systems Green. The inspectors identified a finding of very low safety significance regarding inadequate acceptance criteria for the licensees Generic Letter 89-13 heat exchanger inspections. The inspectors identified this issue during observations and review of the licensees inspection of an auxiliary feedwater system heat exchanger.

The finding was more than minor because it adversely affected the licensees ability to ensure that safety-related heat exchangers would be available, reliable, and capable of responding to initiating events to prevent undesirable consequences. The finding was very low safety significance because the as-found and as-left conditions of the heat exchangers did not reveal any actual concerns with the operability of the heat exchangers. This was determined to be a Non-Cited Violation of 10 CFR 50 Appendix B, Criteria V. (Section 1R07)

Cornerstone: Barrier Integrity Green. A finding of very low safety significance was identified through a self-revealing event when an operator failed to recognize inappropriate indication of a pressurizer liquid sample line isolation valve and failed to communicate this appropriately to the unit supervisor. The primary cause of this finding was related to the cross-cutting area of Human Performance.

This finding was more than minor because it involved misinterpretation of an erroneous valve position indication and the human performance attribute of the Barrier Integrity cornerstone. The finding was very low safety significance because it did not represent a degradation of a radiological barrier and it did not result in an open pathway in the physical integrity of the reactor containment. No violation of USNRC requirements occurred. (Section 1R15)

B. Licensee Identified Violations No violations of significance were identified.

Report Details Summary of Plant Status Unit 1 operated at or near full power throughout the inspection period except on August 15, 2002, when power was reduced to about 91 percent for load following, on September 2, 2002, when power was reduced to about 77 percent for turbine throttle valve/governor valve testing, and on September 23, 2002, when power was reduced to about 83 percent for load following.

Unit 2 operated at or near full power until the unit was shut down for a refueling outage on September 16, 2002. Unit 2 remained shut down for the remainder of the inspection period.

1. REACTOR SAFETY Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity 1R04 Equipment Alignment (71111.04)

a. Inspection Scope The inspectors performed partial walkdowns of accessible portions of trains of risk-significant mitigating systems equipment during times when the trains were of increased importance due to the redundant trains or other related equipment being unavailable.

The inspectors utilized the valve and electric breaker checklists listed at the end of this report and applicable system drawings to verify that the components were properly positioned and that support systems were lined up as needed. The inspectors also examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors used the information in the appropriate sections of the Updated Final Safety Analysis Report (UFSAR) to determine the functional requirements of the systems.

The inspectors verified the alignment of the following trains:

The inspectors reviewed selected condition reports (CRs) concerning improper equipment alignments to determine if the licensee had properly identified and resolved these issues. The inspectors reviewed the extent of condition, corrective actions taken and corrective action timeliness. The review period was from March 2001 through the present.

b. Findings No findings of significance were identified.

1R05 Fire Protection (71111.05)

.1 Walkdowns a. Inspection Scope The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of fire fighting equipment; the control of transient combustibles and ignition sources; and on the condition and operating status of installed fire barriers. The inspectors reviewed applicable portions of the Byron Station Fire Protection Report and selected fire areas for inspection based on their overall contribution to internal fire risk, as documented in the Individual Plant Examination of External Events Report. The inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and that fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The documents listed at the end of this report were also used by the inspectors to evaluate this area.

The inspectors examined the plant areas listed below to observe conditions related to fire protection:

  • Auxiliary Building Elevation 426' - 0" Zone 11.6 - 0 South Zone 11.6 - 0 North Zone 11.6 - 0 West Zone 11.6-1 - Unit 1 Electrical Penetration Area Zone 11.6-2 - Unit 2 Electrical Penetration Area Zone 11.6E-0 - Decontamination Pad and Storage Zone 12.1-0 - Fuel Handling Building Zone 14.4-0; C Turbine Building Unit 1 426 elevation - (Zones 8.5-1);
  • Unit 2 Containment Building (Zone1.2-2, 1.3-2);
  • Unit 2 Diesel Generator Cable Tunnel (Zone 3.1-2);
  • Division 21 Electrical Switchgear room (Zone 5.2-2);
  • Division 22 Electrical Switchgear Room (Zone 5.1-2); and
  • Division 12 Electrical Switchgear Room (Zone 5.1-1).

b. Findings No findings of significance were identified.

.2 Drill Observation a. Inspection Scope The inspectors assessed fire brigade performance and the drill evaluators critique during a fire brigade drill conducted in the electrical maintenance shop tool and equipment storage area on July 27, 2002. The drill simulated a trash fire in the electrical maintenance shop. The inspectors focused on command and control of the fire brigade activities; fire fighting and communication practices; material condition and use of fire fighting equipment; and implementation of pre-fire plan strategies. The inspectors evaluated the fire brigade performance using the licensees established fire drill performance procedure criteria. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program. The documents listed at the end of this report were also used by the inspectors to evaluate this area.

b. Findings No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope On September 19, 2002, the inspectors observed the licensees inspection of the following safety-related heat exchanger:

This heat exchanger was selected for our review because the AFW pump was ranked high in the plant specific risk assessment and was directly connected to the safety-related essential service water system.

During the inspection the inspectors discussed the results and heat exchanger performance with the system engineer and performed an independent inspection of the heat exchanger. Subsequently, the inspectors reviewed the completed work package for the 2B AFW pump lube oil cooler and other 2B AFW system coolers that used essential service water as the cooling medium. Additionally, the inspectors reviewed the Generic Letter 89-13, Service Water System Problems Affecting Safety-Related equipment, and licensees procedures governing Generic Letter 89-13 heat exchanger inspections. The inspectors also discussed the adequacy of the licensees acceptance criteria associated with these heat exchanger inspections with the appropriate engineering supervisor and manager, and the Regulatory Assurance Manager. The documents listed at the end of this report were also used by the inspectors to evaluate this area.

In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also

reviewed the licensees corrective actions for the issues documented in selected condition reports.

b. Findings The inspectors identified that the licensees acceptance criteria for the Generic Letter 89-13 heat exchanger inspections was inadequate to ensure that the inspections were satisfactorily accomplished. This issue was considered to be of very low safety significance (Green) and was dispositioned as a Non-Cited Violation (NCV) of 10 CFR 50 Appendix B, Criteria V Instructions Procedures and Drawings.

Description On September 19, 2002, during the licensees inspection of the 2B AFW pump lube oil cooler heat exchanger, the inspectors reviewed the associated work order (WO)

99275648 and noted that there was not an explicit acceptance criteria provided. The system engineer performing the inspection was questioned regarding the acceptance criteria, and acknowledged that there was not explicit acceptance criteria; however, he also stated that the current conditions were to be compared to past observations.

Subsequently, the inspector reviewed the licensees Procedure ER-AA-340-1002, Service Water Heat Exchanger and Component Inspection Guide, Revision 0, and discussed the licensees heat exchanger inspection program with the applicable engineering program supervisor and manager, and the Regulatory Assurance Manager.

As a result of these discussions and procedure reviews, the inspectors ascertained that the procedure required that a written assessment comparing the as-found conditions of the heat exchangers to the pre-inspection expectation. However, no written assessment was made for any of the five 2B AFW system exchangers inspection work packages reviewed by the inspectors (WOs 99215024, 99275593, 99275594, 99275648, 99275649).

The inspectors reviewed the heat exchanger inspection data sheets for the five 2B AFW heat exchangers and noted little or no degradation. However, the inspectors noted that for three of the five heat exchangers the as-found conditions were worse than the past inspection results with no explanation provided regarding the increased degradation.

The inspectors discussed the results with the members of the licensees engineering staff and USNRC Region III specialist inspectors and concluded that in all cases there was no impact on the operability. This was based on the fact that in all cases less than 10 percent of the tubes were found plugged and that the licensee cleaned all the heat exchangers before returning them to service. The inspectors also concluded the acceptance criteria as provided in Procedure ER-AA-340-1002 was inadequate for determining whether heat exchanger performance would remain satisfactory until the next inspection.

Analysis The inspectors determined that the failure to have an adequate acceptance criteria for the Generic 89-13 heat exchanger inspections was a deficiency warranting a significance evaluation in accordance with USNRC Inspection Manual Chapter (IMC)

0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening,

issued on April 29, 2002. The inspectors determined that the finding was more than minor because it involved the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors determined that the finding could be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Significance Determination Process, because the finding was associated with the availability and reliability of a train in a mitigating system. However, since the heat exchanger inspection results did not reveal any actual concerns with the operability of the heat exchangers, the inspectors answered no to all the SDP Phase 1 screening questions regarding mitigating systems.

Therefore, this finding was considered to be of very low safety significance (Green).

Enforcement 10 CFR 50 Appendix B, Criteria V, Instructions, Procedure, and Drawings, required, in part, that Instructions, procedures or drawings include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, on or before September 19, 2002, the licensee Procedure ER-AA-340-1002, Service Water Heat Exchanger and Component Inspection Guide, failed to include to an appropriate acceptance criteria for determining whether heat exchanger performance would remain satisfactory until the next inspection. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the USNRC Enforcement Policy (NCV 50-454/455/02-06-01). The licensee entered this violation into its corrective action program as CR 00125982.

1R08 Inservice Inspection Activities (71111.08)

a. Inspection Scope The inspectors conducted a review of the licensees inservice inspection program for monitoring degradation of the reactor coolant system boundary and the risk significant piping system boundaries. Specifically, the inspectors conducted a record review of the following examinations:

WELD # SYSTEM Nondestructive Testing TYPE 2CV05CB-6" Chemical and Volume Control Ultrasonic Testing 2RC35AA-6" Reactor Coolant Ultrasonic Testing 2RH02AA-8" Residual Heat Removal Ultrasonic Testing 2RY02AA-8" Reactor Coolant Ultrasonic Testing 2MS01AA-30-1/4" Main Steam Magnetic Particle Testing These examinations were evaluated for compliance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements. The inspectors also reviewed inservice inspection procedures, equipment certifications,

personnel certifications, and NIS-2 forms for Code repairs performed during the Unit 1 outage (B1R11) to confirm that ASME Code requirements were met.

A sample of inservice inspection related problems documented in the licensees corrective action program was also reviewed to assess conformance with 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requirements. In addition, the inspectors determined that operating experience was correctly assessed for applicability by the inservice inspection group.

b. Findings No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

a. Inspection Scope On August 6, 2002, the inspectors observed an operating crew during an out-of-the-box requalification examination on the simulator using Scenario BY-46, Respond to an Anticipated Transient Without Scram and Miscellaneous Malfunctions, The inspectors evaluated crew performance in the areas of:

  • clarity and formality of communications;
  • ability to take timely actions in the safe direction;
  • prioritization, interpretation and verification of alarms;
  • procedure use;
  • control board manipulations;
  • supervisors command and control;
  • management oversight; and
  • group dynamics.

Crew performance in these areas was compared to licensee management expectations and guidelines as presented in the following documents:

  • OP-AA-101-111, Rules and Responsibilities of On-Shift Personnel, Revision 0;

The inspectors verified that the crew completed the critical tasks listed in the above simulator guide. The inspectors also compared simulator configurations with actual control board configurations. For any weaknesses identified, the inspectors observed the licensee evaluators to verify that they also noted the issues and discussed them in the critique at the end of the session.

In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also

reviewed the licensees corrective actions for the issues documented in selected condition reports listed at the end of this report.

b. Findings No findings of significance were identified.

1R12 Maintenance Rule Implementation (71111.12)

a. Inspection Scope The inspectors evaluated the licensees implementation of the maintenance rule, 10 CFR 50.65, as it pertained to identified performance problems with the following equipment and systems:

C Component Cooling Water System (July 1 - 12, 2002), and

During this inspection, the inspectors evaluated the licensees monitoring and trending of performance data, verified that performance criteria were established commensurate with safety, and verified that equipment failures were appropriately evaluated in accordance with the maintenance rule. These aspects were evaluated using the maintenance rule scoping and report documents listed at the end of this report. For each system, structure, and component (SSC) reviewed, the inspectors also reviewed the significant WOs and CRs listed at the end of this report to verify that failures were properly identified, classified, and corrected, and that unavailable time had been properly calculated. The inspectors also interviewed system engineers, operations department personnel and the stations maintenance rule coordinator.

In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for the issues documented in selected condition reports.

b. Findings No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

a. Inspection Scope The inspectors reviewed the licensees management of plant risk during emergent maintenance activities or during activities where more than one significant system or train was unavailable. The inspectors chose activities based on their potential to increase the probability of an initiating event or impact the operation of safety-significant equipment. The inspectors verified that evaluation, planning, control, and performance of the work was done in a manner to reduce the risk and the work duration was

minimized where practical. The inspectors also verified that contingency plans were in place where appropriate.

The inspectors reviewed configuration risk assessment records, observed operator turnover, observed plan-of-the-day meetings, and reviewed the documents listed at the end of this report to verify that the equipment configurations had been properly listed, that protected equipment had been identified and was being controlled where appropriate, and that significant aspects of plant risk were being communicated to the necessary personnel. The inspectors verified that the licensee controlled emergent work in accordance with Nuclear Station Procedure WC-AA-101, On-Line Work Control Process, Revision 6.

The inspectors reviewed the following activities:

  • Essential Service Water Tower 0B Suction Valve (0SX138B) Actuator Replacement (July 10, 2002).

In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for the issues documented in selected condition reports listed at the end of this report.

b. Findings No findings of significance were identified with the item reviewed under this inspection procedure. However, a finding related to the inadequate assessment and management of maintenance risk assessment was described below in Section 1R20, Refueling and Outage Activities.

1R14 Personnel Performance Related to Non-routine Plant Evolutions and Events (71111.14)

a. Inspection Scope On September 16, 2002, the inspectors observed control room operators shut down Unit 2 for refueling outage B2R10. The inspectors evaluated crew performance in the areas of:

  • clarity and formality of communications;
  • ability to take timely actions in the safe direction;
  • prioritization, interpretation and verification of alarms;
  • procedure use;
  • control board manipulations;
  • supervisors command and control;
  • management oversight; and
  • group dynamics.

Crew performance in these areas was compared to licensee management expectations and guidelines as presented in the following documents:

  • OP-AA-101-111, Rules and Responsibilities of On-Shift Personnel, Revision 0;

b. Findings No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope The inspectors evaluated plant conditions, selected CRs and operability determinations (ODs) for risk-significant components and systems in which operability issues were questioned. These conditions were evaluated to determine whether the operability of components was justified.

The inspectors reviewed the following operability evaluations:

C OD 02-012, 1A Reactor Containment Fan Cooler Elevated Vibration Levels (August 22, 2002); and

  • OD 02-009, Leakage of SI8819 Check Valves Pressurizing Safety Injection Pump Discharge Lines (September 17, 2002).

The inspectors compared the operability and design criteria in the appropriate section of the Technical Specification (TS) and UFSAR to the licensees evaluations to verify that the components or systems were operable. The inspectors determined whether compensatory measures, if needed, were taken; and determined whether the evaluations were consistent with the requirements of licensees Procedure LS-AA-105, Operability Determination Process, Revision 0. The inspectors also discussed the details of the evaluations with the shift managers and appropriate members of the licensees engineering staff.

In addition, the inspectors also reviewed selected issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. In particular, the inspectors focused on the licensees evaluation of CR 107967, regarding a potentially inoperable pressurizer liquid sample line isolation valve.

b. Findings A finding of very low safety significance (Green) was self-revealed related to a licensed operators failure to communicate the status of a failed shut indication for containment isolation valve 1PS9355A (Unit 1 pressurizer liquid sample isolation valve). This finding was not considered a violation of regulatory requirements.

Description On May 13, 2002, at about 7:00 a.m. the valve (1PS9355A) was shut remotely from the control room and the closed indicating light failed to illuminate. The operator changed the indicating light bulb but did not get the closed light again. He informed the Unit Supervisor (US) who replaced the indicating light a second time, had the operator cycle the valve twice, and the light illuminated as expected. During one of the initial attempts to shut the valve, the operator moved the control switch from the open position, to the shut position then to the automatic position. The open light went out then on again. It was later determined that the valve opened because the micro-switch for the closed indication was not made up. This reopening was not communicated to the US. No other communications such as a log entry were made at that time. About 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> later, the operator returned for the shift and questioned the stroke time of the valve because it seemed slow during the earlier cycling. The valve timing was tested satisfactorily; however, the closed light failed to light again as it had earlier. At this point, the valve was declared inoperable, an appropriate log entry was made, a condition report was generated, and the Technical Specification Limiting Condition for Operation Action Requirement (LCOAR) was entered. A prompt investigation revealed that the valve was operable and capable of performing its isolation function as required. The failure of the closed indication light was the result of an intermittent failure of the closed micro-switch on the valve which also caused the valve to reopen when the control switch was placed in the automatic position during one of the initial cycles.

The root cause investigation also revealed human performance problems in that the communications between the operator and the US were poor and their actions to change the light bulbs were inadequate to correct the basic problem. In addition, when the first failures occurred, no log entries were made, no condition report was written, the appropriate LCOAR was not recognized and entered, and a work request was not generated. These were created on the following shift when the valve was timed and the closed light failed to illuminate as it should have.

Analysis The inspectors determined that the failure to properly communicate the indications of a failed containment isolation valve, was an operator performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on April 29, 2002. The inspectors determined that the finding was more than minor because it involved misinterpretation of an erroneous valve position indication and human performance attributes of the Barrier Integrity cornerstone. The inspectors determined that the error by the operator also affected the cross-cutting area of Human Performance because despite having the valve behave in an unexpected manner, e.g., returned to the open

position when the control switch was placed in the automatic position, the operator failed to show a questioning attitude, inform the supervisor, and generate appropriate documentation in a timely manner.

The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, because the finding was associated with a potentially degraded containment isolation valve and its ability to isolate if called upon as discussed above. For the Phase 1 screening, the inspectors answered no to all three questions in the Containment Barrier column because it did not represent a degradation of a radiological barrier, it did not represent a degraded barrier function, and it did not result in an open pathway in the physical integrity of the reactor containment. Therefore, the finding was of very low safety significance (Green)

(FIN 50-454/02-06-02).

Enforcement The inspectors determined that the valve did shut and that only a micro-switch failed giving an erroneous indication. The valve remained operable; therefore, no violation of regulatory requirements occurred. The licensee entered the event into its corrective action system as CR 00107967 Sample Valve 1PS9355A Does Not Indicate Closed.

1R17 Permanent Plant Modifications (71111.17)

a. Inspection Scope The inspectors evaluated the following permanent plant modifications:

The inspectors reviewed the 2B EDG Governor modification installed during the September 2002, Unit 2 refueling outage to verify that the design basis, licensing basis, and performance capability of risk significant systems were not degraded by the installation of the modification. The inspectors considered the design adequacy of the modifications by performing a review, of the modifications impact on plant electrical requirements, material requirements and replacement components, response time, control signals, equipment protection, operation, failure modes, and other related process requirements.

The documents listed at the end of the report were used in the assessment of this area.

b. Findings No findings of significance were identified.

1R19 Post Maintenance Testing (71111.19)

a. Inspection Scope The inspectors reviewed the post maintenance testing activities associated with maintenance or modification of mitigating, barrier integrity, and support systems that were identified as risk significant in the licensees risk analysis. The inspectors reviewed these activities to verify that the post maintenance testing was performed adequately, demonstrated that the maintenance was successful, and that operability was restored.

During this inspection activity, the inspectors interviewed maintenance and engineering department personnel and reviewed the completed post maintenance testing documentation. The inspectors used the appropriate sections of the TS and UFSAR, as well as the documents listed at the end of this report, to evaluate this area.

Testing subsequent to the following activities was observed and evaluated:

C 0SX138B Essential Service Water Valve Actuator Replacement (July 10, 2002);

  • Unit 1 Digital Electrical Hydraulic Control System Repairs following the Failure of the Display and Transfer to Manual ( August 1, 2002);

C 0A Control Room Make Up System Charcoal Adsorber Bank ( August 19, 2002);

  • 2B Charging Pump Maintenance (September 24, 2002); and

b. Findings No findings of significance were identified.

1R20 Refueling and Outage Activities (71111.20)

a. Inspection Scope The inspectors evaluated the licensees conduct of B2R10 refueling outage activities to assess the licensees control of plant configuration and management of shutdown risk.

The inspectors reviewed configuration management to verify that the licensee maintained defense-in-depth commensurate with the shutdown risk plan; reviewed major outage work activities to ensure that correct system lineups were maintained for key mitigating systems; and observed refueling activities to verify that fuel handling operations were performed in accordance with the TS and approved procedures. Other major outage activities evaluated included the licensee's control of:

  • containment penetrations in accordance with the TS;
  • SSCs which could cause unexpected reactivity changes;

inventory addition and control of SSCs which could cause a loss of inventory;

  • RCS pressure, level, and temperature instrumentation;
  • spent fuel pool cooling during and after core offload;
  • switchyard activities and the configuration of electrical power systems in accordance with the TS and shutdown risk plan; and

The inspectors observed portions of the plant cooldown, including the transition to shutdown cooling, to verify that the licensee controlled the plant cooldown in accordance with the TS. In addition, the inspectors evaluated portions of the restart preparation activities to verify that requirements of the TS and administrative procedure requirements were met prior to changing operational modes or plant configurations.

Major restart preparation inspection activities performed included:

  • verification that RCS boundary leakage requirements were met prior to entry into mode 4 (cold shutdown) and subsequent operational mode changes;
  • verification that containment integrity was established prior to entry into mode 4;
  • inspection of the containment building to assess material condition and search for loose debris, which if present could be transported to the containment recirculation sumps and cause restriction of flow to the emergency core cooling system (ECCS) pump suctions during loss-of-coolant accident conditions; and
  • verification that the material condition of the containment building ECCS recirculation sumps met the requirements of the TS and was consistent with the design basis.

The inspectors interviewed operations, engineering, work control, radiological protection, and maintenance department personnel and reviewed selected procedures and documents.

In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for refueling outage issues documented in selected condition reports.

The documents listed at the end of the report were used in the assessment of this area.

Outage activities were still in progress at the end of this inspection period. Additional findings, if any, will be documented at the close of the inspection in a subsequent inspection report.

b. Findings A finding of very low safety significance (Green) was self-revealed. With Unit 2 in Mode 5 (Cold Shutdown), the licensee failed to assess and manage the increase in risk associated maintenance activities as required by 10 CFR 50.65(a)(4). Specifically, contrary to the preestablished contingency plan, the licensee commenced switchyard maintenance activities prior to restoring RCS inventory to greater than 5 percent pressurizer level. This issue was considered to be of very low safety significance and was dispositioned as a Non-Cited Violation.

Description On the morning of September 27, 2002, the licensee inappropriately commenced switchyard maintenance activities while the RCS was at reduced inventory, and the 2B EDG was out-of-service for testing following maintenance. Although the switchyard work was scheduled for completion on the morning of September 27, the licensee also had administrative controls in place requiring sufficient RCS inventory be established prior to starting the switchyard work. Specifically, the licensees shutdown risk contingency plan B2R10 CP-10, for conditions with reduced inventory in the RCS, required administrative control to be in place controlling switchyard activities until RCS inventory was greater than 5 percent pressurizer level. After approximately three hours, the licensee discovered that switchyard work commenced while they were still at reduced inventory.

This occurred when the outage manager contacted the switchyard coordinator to inform him that the prerequisite regarding RCS inventory was about to be met, at which time the outage manager was informed that work already commenced. Upon discovery, the licensee stopped the work in the switchyard and initiated a prompted investigation of the event.

The licensees original outage risk evaluation for reduced inventory conditions with the 2B EDG unavailable reflected a yellow risk configuration (i.e., acceptable but reduced level of defense). Furthermore, the outage risk analysis recognized the significance of controlling switchyard maintenance activities by establishing the administrative controls.

By completing the switchyard maintenance activities with reduced inventory while the 2B EDG was out of service, the licensee inadvertently entered a higher orange risk configuration (i.e., minimum acceptable level of defense). The licensees plant shutdown safety and risk management procedure, OU-AA-103, Shutdown Safety Management Program, required the implementation of additional risk management actions to protect available equipment and to maintain an adequate level of defense which were not taken for the unplanned entry into the orange risk configuration.

Subsequently, the licensee determined that the 2B EDG was available, from a shutdown risk perspective, while the switchyard work was in progress. This was based on the following

  • all testing of the 2B EDG was completed satisfactorily indicating that it was available from the time the associated maintenance was completed, and
  • all maintenance was completed on the 2B EDG prior to commencing the switchyard work.

Therefore, the actual shutdown risk remained yellow during the entire time switchyard maintenance was being performed.

Analysis The inspectors determined that the failure to assess and manage the risk associated with switchyard maintenance while the Unit 2 RCS was at reduced inventory and the 2B EDG was believed to be unavailable was a deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on April 29, 2002. The inspectors determined

that the finding was more than minor because it involved the configuration control and human performance attributes of the Initiating Events cornerstone. This finding affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge a critical safety function, specifically electric power control, during shutdown operations. The inspectors determined that the error by the switchyard coordinator also affected the cross-cutting area of Human Performance because despite having the administrative controls in place to prevent the working in the switchyard while the RCS was at reduced inventory, the controls were not implemented.

The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, because the finding was associated with a potential increase in the likelihood of an initiating event. The inspectors utilized the guidance in IMC 0609, Appendix G, Shutdown Operations Significance Determination Process. Specifically, the checklist for Pressurized Water Reactor Cold Shutdown and Refueling Operation - Reactor Coolant System Closed and No Inventory in Pressurizer, Time to boiling less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> since this best matches the plant conditions at the time of the event. This guidance specified that control over switchyard and transformer yard activities is required for the plant conditions that existed. However, since both EDGs were subsequently determined to be available, the inspectors discussed the issue with a USNRC Region III Senior Risk Analyst. Based on this discussion, the inspectors concluded that having both EDGs available provided sufficient redundancy such that the licensees ability to cope with a loss of offsite power was not degraded during the switchyard activities. Therefore, based on the guidance in IMC 0609 Appendix G, this issue was determined to be of very low safety significance (Green).

Enforcement 10 CFR 50.65(a)(4) requires, in part, that before performing maintenance activities (including but not limited to surveillances, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to the above, on September 27, 2002, the licensee failed to assess and manage the risk associated with maintenance activities affecting the switchyard while the reactor system was at reduced inventory and the 2B EDG was believed to be unavailable. This resulted in the inadvertent entry into a higher shutdown risk configuration, for which the licensee had not implemented additional risk management actions to protect available equipment to maintain an adequate level of defense. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the USNRC Enforcement Policy (NCV 50-455/02-06-03). The licensee entered this violation into its corrective action program as CR 00124902.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope The inspectors witnessed selected surveillance testing and/or reviewed test data to verify that the equipment tested using the surveillance procedures met the TS, the Technical Requirements Manual, the UFSAR, and licensee procedural requirements,

and demonstrated that the equipment was capable of performing its intended safety functions. The activities were selected based on their importance in verifying mitigating systems capability and barrier integrity. The inspectors used the documents listed at the end of this report to verify that the testing met the frequency requirements; that the tests were conducted in accordance with the procedures, including establishing the proper plant conditions and prerequisites; that the test acceptance criteria were met; and that the results of the tests were properly reviewed and recorded. In addition, the inspectors interviewed operations, maintenance and engineering department personnel regarding the tests and test results.

The inspectors evaluated the following surveillance tests:

  • Unit 1 Operability Surveillance Requirements for 1B Diesel Generator (July 10);
  • Unit 1 Train B Solid State Protection System Bi-Monthly Surveillance (July 15, 2002);

C Unit 0 A Essential Service Water Makeup Pump Monthly Operability Test (August 21, 2002);

C Unit 2 Engineered Safety Feature Actuation System Instrumentation Slave Relay Surveillance Tests (R-632A)(R-610) (August 22, 2002);

C Unit 2 Passive Indication Test of 2SX004, 2SX010, 2SX011, 2SX033, 2SX034 and 2SX136 (August 22, 2002); and

  • Unit 2 Train B Manual Safety Injection Initiation and Manual Phase A Initiation (September, 17, 2002),

and

  • Unit 2 Local Leak Rate Test of 2VQ005 (September 23, 2002).

In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for the issues documented in selected condition reports.

b. Findings No findings of significance were identified.

1R23 Temporary Plant Modifications (71111.23)

a. Inspection Scope The inspectors reviewed and evaluated the following temporary plant modification on risk-significant equipment:

  • EC# 333751, Install A3 Cable to the A4 Preamplifier at the 2NR-13, Revision 0 (July 2002)

The inspectors reviewed these temporary plant modifications to verify that the instructions were consistent with applicable design modification documents and that the modifications did not adversely impact system operability or availability. The inspectors interviewed operations, engineering and maintenance personnel as appropriate and reviewed the design modification documents and the 10 CFR 50.59 evaluations against the applicable portions of the UFSAR. The documents listed at the end of this report were also used by the inspectors to evaluate this area.

The inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified temporary modification problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for temporary modification related issues documented in selected condition reports. The condition reports are specified in the List of Documents Reviewed.

b. Findings No findings of significance were identified Cornerstone: Emergency Preparedness 1EP2 Alert and Notification System (ANS) Testing (71114.02)

a. Inspection Scope The inspectors discussed with Emergency Preparedness (EP) staff the design, equipment, and periodic testing of the public ANS for the Byron reactor facility emergency planning zone to verify that the system was properly tested and maintained.

The inspectors also reviewed procedures and records for a six-month period ending June 2002, related to ANS testing, annual preventive maintenance, and non-scheduled maintenance. The inspectors reviewed the licensees criteria for determining whether each model of siren installed in the emergency planning zone would perform as expected if fully activated. Records used to document and trend component failures for each model of installed siren were also reviewed to ensure that corrective actions were taken for test failures or system anomalies.

b. Findings No findings of significance were identified.

1EP3 Emergency Response Organization (ERO) Augmentation Testing (71114.03)

a. Inspection Scope The inspectors reviewed the licensees ERO augmentation testing to verify that the licensee maintained and tested its ability to staff the ERO during an emergency in a timely manner. Specifically, the inspectors reviewed semi-annual, off-hours staff augmentation drill procedures, related June 19 and 25, 2001, December 13, 2001, and March 29, 2002, drill records, primary and backup provisions for off-hours notification of the Byron reactor facility emergency responders, and the current ERO rosters for Byron.

The inspectors reviewed and discussed the facility EP staffs provisions for maintaining ERO call out lists.

b. Findings No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies (71114.05)

a. Inspection Scope The inspectors reviewed the Nuclear Oversight staffs 2001 - 2002 audits and field observations to ensure that these audits complied with the requirements of 10 CFR 50.54(t) and that the licensee adequately identified and corrected deficiencies.

The inspectors also reviewed the EP staffs self-assessments and critiques to evaluate the EP staffs efforts to identify and correct weaknesses and deficiencies. Additionally, the inspectors reviewed a sample of EP items, condition reports, and action requests related to the facilitys EP program to determine whether corrective actions were acceptably completed.

b. Findings No findings of significance were identified.

1EP6 Drill Evaluation (71114.06)

a. Inspection Scope On August 21, 2002, the inspectors reviewed an after-hours EP exercise to assess the licensees exercise performance and identify weaknesses in the risk significant areas of emergency classification, notification and protective action development. The inspectors used the criteria listed in the guidance documents at the end of this report to identify weaknesses. The inspectors compared the inspector-identified weaknesses to the licensee-identified weaknesses to determine whether the licensee properly identified

failures. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program. The inspectors observed the exercise from the following facilities:

  • Control Room Simulator,
  • Operations Support Center.

a. Findings No findings of significance were identified.

2. RADIATION SAFETY Cornerstone: Occupational Radiation Safety (OS)

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Plant Walkdowns and Radiological Boundary Verifications a. Inspection Scope The inspectors performed walkdowns of the radiologically controlled area (RCA) to verify the adequacy of radiological boundaries and postings. Specifically, the inspectors performed confirmatory radiation measurements in the Unit 2 Containment Building to verify that radiologically significant work areas (high radiation areas (HRAs), radiation areas, and airborne radioactivity areas) were properly posted and controlled in accordance with 10 CFR 20 and the licensees procedures. During this review, the inspectors evaluated the licensees dose assessments for any actual internal exposures greater than 50 millirem committed effective dose equivalent. The inspectors also reviewed the licensees controls for the storage of irradiated materials (non-fuel) in the spent fuel pool to ensure that appropriate measures were in place to prevent the inadvertent removal of those materials, which could result in significant exposures to personnel.

b. Findings No findings of significance were identified.

.2 High Risk Significant, High Dose Rate High Radiation Area (HRA) and Very High Radiation Area (VHRA) Controls a. Inspection Scope The inspectors reviewed the licensees controls for access to risk significant HRAs and VHRAs to ensure that the licensees controls were consistent with the requirements contained in 10 CFR 20 and contained within its Technical Specifications. Specifically, the inspectors discussed the controls with members of the radiation protection staff and reviewed applicable procedures. The inspectors also performed walkdowns of the Unit 2

Containment Building to ensure adequate posting and locking of entrances to high dose rate (>25 rem in one hour at 30 centimeters) HRAs and VHRAs.

b. Findings No findings of significance were identified.

.3 Problem Identification and Resolution a. Inspection Scope The inspectors reviewed condition reports completed during the previous four months which identified issues in radiation worker and radiation protection technician performance. The inspectors reviewed these documents to assess the licensees ability to identify repetitive problems, contributing causes, the extent of conditions, and corrective actions which will achieve lasting results.

b. Findings No findings of significance were identified.

2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls (71121.02)

.1 Radiological Work Planning a. Inspection Scope The inspectors reviewed the licensees radiological planning for the following Unit 2 outage work activities:

  • Reactor Cavity Decontamination,
  • Reactor Head Removal and Installation, and
  • Entry into Reactor Vessel Bottom Incore Area.

The inspectors evaluated the licensees exposure estimates and exposure mitigation techniques to verify that the licensee had established procedures and engineering and work controls, based on sound ALARA principles, to achieve occupational exposures that were ALARA. The inspectors also compared the accumulated exposures for work activities to the licensees planning and evaluated the reasons for any inconsistencies between intended and actual work activity doses.

b. Findings No findings of significance were identified.

.2 Radiation Dose Estimates and Exposure Tracking Systems a. Inspection Scope The inspectors reviewed the licensees Unit 2 outage dose goals and dose trending.

The inspectors evaluated the licensees method for adjusting dose estimates to verify that the licensee implemented sound radiation protection principles and properly identified work control problems. The inspectors also attended site ALARA committee meetings that discussed and approved dose adjustments for steam generator work activities.

b. Findings No findings of significance were identified.

.3 Job Site Inspections and ALARA Controls a. Inspection Scope The inspectors observed work activities in the RCA that were performed in radiation areas or HRAs to evaluate the use of ALARA controls. Specifically, the inspectors assessed the implementation of radiation work permits, engineering and ALARA controls, and radiological surveys and observed pre-job radiological briefings (as available) and radiation protection technician performance for the following Unit 2 work activities:

  • Reactor Cavity Decontamination, and
  • Entry into Reactor Vessel Bottom Incore Area.

The inspectors also observed radiation worker performance to verify that the training and skill levels demonstrated by the workers was sufficient with respect to the radiological hazards present and the work involved. During the observation of work activities, the inspectors evaluated workers use of low dose waiting areas and the level of on-the-job supervision provided by the licensee to ensure that ALARA requirements were met.

b. Findings No findings of significance were identified.

.4 Source Term Reduction a. Inspection Scope The inspectors reviewed the status of the licensees source term reduction program. In particular, the inspectors evaluated the licensees implementation of improvements to the hot spot tracking and reduction program and the status of the licensees revised source term reduction procedure implementation. The inspectors also performed surveys within the RCA to verify the accuracy of the licensees records/surveys and to

identify any other significant, unidentified sources of radiation exposure.

b. Findings No findings of significance were identified.

.5 Declared Pregnant Workers a. Inspection Scope The inspectors reviewed the controls implemented by the licensee for an individual who voluntarily declared her pregnancy within the last 18 months (December 2001).

Specifically, the inspectors reviewed the licensees adherence to the requirements contained in 10 CFR 20.1208 and its procedures and reviewed the licensees evaluation of the dose to the individuals embryo/fetus.

b. Findings No findings of significance were identified.

.6 Problem Identification and Resolution a. Inspection Scope The inspectors reviewed self-assessments, audits, and condition reports completed during the previous four months which focused on ALARA planning and controls and the radiological source term reduction program. The inspectors reviewed these documents to assess the licensees ability to identify repetitive problems, contributing causes, the extent of conditions, and corrective actions which will achieve lasting results.

b. Findings No findings of significance were identified.

3. SAFEGUARDS Cornerstone: Physical Protection 3PP3 Response to Contingency Events (71130.03)

a. Inspection Scope The Office of Homeland Security (OHS) developed a Homeland Security Advisory System (HSAS) to disseminate information regarding the risk of terrorist attacks. The HSAS implements five color-coded threat conditions with a description of corresponding actions at each level. USNRC Regulatory Information Summary (RIS) 2002-12a, dated August 19, 2002, NRC Threat Advisory and Protective Measures System, discusses the HSAS and provides additional information on protective measures to licensees.

On September 10, 2002, the USNRC issued a Safeguards Advisory to reactor licensees to implement the protective measures described in RIS 2002-12a in response to the Federal government declaration of threat level orange. Subsequently, on September 24, 2002, the OHS downgraded the national security threat condition to yellow and a corresponding reduction in the risk of a terrorist threat.

The inspectors interviewed licensee personnel and security staff, observed the conduct of security operations, and assessed licensee implementation of the threat level orange protective measures. Inspection results were communicated to the region and headquarters security staff for further evaluation.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITIES 4OA1 Performance Indicator Verification (71151)

Cornerstone: Mitigating Systems, Barrier Integrity, and Emergency Preparedness

.1 Reactor Coolant System Activity Performance Indicators a. Inspection Scope The inspectors verified that the licensee had accurately reported the RCS activity performance indicator. Specifically, the inspectors reviewed the licensees sample analyses results for maximum dose equivalent iodine-131 (September 2001 through June 2002), performed independent calculations of dose equivalent iodine-131, and reviewed applicable chemistry procedures. The inspectors also observed a chemistry technician obtain and analyze an RCS sample.

b. Findings No findings of significance were identified.

.2 Reactor Coolant System Leakage Performance Indicators a. Inspection Scope The resident inspectors verified that the licensee had accurately reported the reactor coolant system leakage performance indicator. The inspectors reviewed the data for the period of July 2001 through June 2002 found in the shift manager logs, calculations performed by procedure, and records of reactor coolant system water inventory balance surveillances from the process computer. The information was compared to the criteria of NEI 99-02 Regulatory Assessment Performance Indicator Guidelines, Revision 2, of November 19, 2001, and compared to the information provided to the USNRC in quarterly submittals.

.3 Safety System Functional Failures Performance Indicators a. Inspection Scope The inspectors verified that the licensee had accurately reported the safety system functional failures performance indicator. The inspectors reviewed selected conditions reported in Licensee Event Reports, CRs and control room logs from July 1, 2001 to June 30, 2002, and reviewed that the licensee had appropriately reported those conditions that prevented, or could have prevented, the fulfillment of a safety function.

The condition reports are specified in the List of Documents Reviewed.

b. Findings No findings of significance were identified.

.4 Safety System Unavailability Performance Indicators a. Inspection Scope The inspectors verified that the licensee had accurately reported the safety system unavailability performance indicators for the following systems:

C Safety System Unavailability - High Pressure Safety Injection, and C Safety System Unavailability - Residual Heat Removal.

The inspectors reviewed condition reports, Performance Indicator Data Elements, operating logs, maintenance history and surveillance test history for unavailability information for these systems from July 1, 2001 to June 30, 2002. The condition reports are specified in the List of Documents Reviewed. The inspectors also reviewed the licensees calculation of critical hours for both units and evaluated applicable safety system equipment unavailability against the performance indicator definition.

b. Findings No findings of significance were identified.

.5 Emergency Preparedness Performance Indicators a. Inspection Scope The inspectors verified that the licensee had accurately reported these indicators: ANS Reliability, ERO Drill Participation, and Drill and Exercise Performance (DEP), for the EP cornerstone. Specifically, the inspectors reviewed the licensees Performance Indicator records, data reported to the NRC, and condition reports for the period October 2001 through March 2002, to identify any occurrences that were not identified by the licensee.

Records of relevant Control Room Simulator training sessions, periodic ANS tests, and excerpts of drill and exercise scenarios and evaluations were also reviewed.

b. Findings

No findings of significance were identified 4OA4 Cross-Cutting Findings

.1 A finding described in Section 1R15 of this report had, as its primary cause, a human performance deficiency, in that, a licensed operator, failed to properly communicate, show a questioning attitude, and failed to identify an indication of a failed containment isolation valve.

.2 A finding described in Section 1R20 of this report had, as its primary cause, a human performance deficiency, in that despite having the administrative controls in place to prevent the working in the switchyard while the RCS was at reduced inventory, the controls were not implemented.

4OA5 Other

.1 Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles (Temporary Instruction 2515/145)

a. Inspection Scope The inspectors performed a review of the licensees activities in response to USNRC Bulletin 2001-01, Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles, to verify compliance with applicable regulatory requirements. In accordance with the guidance of USNRC Bulletin 2001-01, the Byron Plant was characterized as belonging to the sub-population of plants (Bin 4) that were considered to have a low susceptibility to primary stress corrosion cracking based upon a susceptibility ranking of more than 30 effective full power years of operation from that of the Oconee Nuclear Station, Unit 3 condition. Although, the low likelihood of primary water stress corrosion cracking at Bin 4 facilities indicates that examination is not necessary, Byron responded to USNRC Bulletin 2001-01 by performing a direct visual examination of the reactor vessel head. The inspectors interviewed inspection personnel, reviewed procedures and inspection reports, including video tape documentation, to assess the licensees efforts in conducting an effective visual examination of the reactor vessel head.

b. Evaluation of Inspection Requirements 1. Were the licensees examinations performed by qualified and knowledgeable personnel?

Yes, the inspectors determined that the examinations were performed by personnel certified as Level II or Level III VT-2 in accordance with procedure SPP 2-1-0, Certification of VT-Examiners for ASME Section XI. In addition, the licensee provided the individuals with training specific to the guidelines described in the Electric Power Research Institute (EPRI) 1006296, Visual Examination for Leakage of PWR [Pressurized Water Reactor] Reactor Head Penetrations.

2. Were the licensees examinations performed in accordance with approved and

adequate procedures?

The inspectors verified that the examinations were conducted in accordance with an approved plant procedure, CEDI-B2R10-RV Head Exam, Visual Inspection Of Byron Unit 2 Reactor Vessel Head. The inspectors determined that the procedure was appropriate for the examinations.

3. Were the licensees examinations adequately able to identify, disposition, and resolve deficiencies?

Yes, through a review of the examination records, including video tape documentation, and condition report, the inspectors determined that the licensees examinations were adequate to identify, disposition, and resolve deficiencies.

4. Were the licensees examinations capable of identifying the primary stress corrosion cracking phenomenon described in the Bulletin?

The inspectors determined through interviews with inspection personnel, reviews of procedures, including video tape documentation of the examinations, that the licensees efforts were capable of identifying the results of the phenomenon described in the Bulletin.

5. What was the condition of the reactor vessel head (debris, insulation, dirt, boron from other sources, physical layout, viewing obstructions)?

The Byron Station reactor head has three-inch mirror insulation installed with overlapping joints in an interwoven pattern. The insulation is installed in a flat field across the top of the reactor head and is stepped down as it approaches the outer perimeter of the reactor head. The minimum vertical clearance between the vessel head penetrations and the insulation is approximately 1.5-inches at the apex of the head, with clearance increasing towards the periphery of the head and service structure. The inspectors also determined through discussions with the inspection personnel and viewing of the videotape of the inspection that the as-found pressure vessel head condition was relatively clean, with no viewing obstructions to the exam. The inspection personnel fully examined the 79 pressure vessel head penetrations (53 control rod drive nozzles, 18 spare control rod drive nozzles, five in-core thermocouple nozzles, two reactor vessel level indication system nozzles all equally sized (approximately four inches diameter), plus the one-inch head vent. The center to center distance between most penetrations is approximately 12".

The inspection personnel identified boron residue at the bottom and along the length of nozzles numbers 14, 37, and 61 between the insulation and the reactor head (AR#00124013, B2R10 Reactor Head Examination Indications, September 22, 2002). The residue was not due to an active leak, and was cleaned from the reactor head and nozzles.

6. Could small boron deposits, as described in the bulletin, be identified and

characterized?

The inspectors verified, through interviews with inspection personnel and review of the video tape and photographic record of the examination, that small boron deposits, as described in the Bulletin, could be identified given the cleanliness and accessibility of the pressure vessel head penetrations.

7. What materiel deficiencies (associated with the concerns identified in the bulletin)

were identified that required repair?

None.

8. What, if any, significant items that could impede effective examinations and/or ALARA issues were encountered?

The inspectors verified that there were no impediments to the examinations.

Radiation dose received as a part of the examinations was 2.329 person-rem.

3. Findings No findings of significance were identified.

4OA6 Meetings

.1 Exit Meeting The inspectors presented the inspection results to Mr. Rich Lopriore and other members of licensee management at the conclusion of the inspection on October 4, 2002. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Interim Exit Meetings Interim exits were conducted for:

Lopriore on September 27, 2002.

  • Radiation Protection inspection with Mr. R. Lopriore on September 27, 2002

.

KEY POINTS OF CONTACT Licensee C. Crane, Exelon Senior Vice President R. Lopriore, Site Vice President S. Kuczynski, Plant Manager B. Altman, Maintenance Manager C. Brown, Emergency Preparedness Coordinator D. Combs, Site Security Manager D. Goldsmith, Radiation Protection Director B. Grundmann, Regulatory Assurance Manager D. Hoots, Operations Manager W. Kolo, Work Management Director S. McCain, Exelon Corporate Emergency Preparedness Manager T. Roberts, Engineering Director Nuclear Regulatory Commission C. Khan, Senior Materials Engineer, NRR/DE/EMCB P. Lougheed, Senior Reactor Inspector S. Burgess, Senior Reactor Analyst K. Karwoski, Senior Level Advisor for Steam Generators and Material Inspection E. Murphy, Senior Materials Engineer A. Stone, Chief, Projects Branch 3, Division of Reactor Projects LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-454/455/02-06-01 NCV Adequate Acceptance Criteria for Generic Letter 89-13 Heat Exchanger Inspections 50-454/02-06-02 FIN Operator Failed to Communicate Abnormal Indications While Attempting to Shut a Primary Sample System Containment Isolation Valve 50-455/02-06-03 NCV Failure to Manage Shutdown Risk associated with Switchyard Activities during Reduced RCS inventory Closed 50-454/455/02-06-01 NCV Adequate Acceptance Criteria for Generic Letter 89-13 Heat Exchanger Inspections 50-455/02-06-02 FIN Operator Failed to Communicate Abnormal Indications While Attempting to Shut a Primary Sample System Containment Isolation Valve

50-455/02-06-03 NCV Failure to Manage Shutdown Risk associated with Switchyard Activities during Reduced RCS inventory Discussed None

LIST OF ACRONYMS USED AFW Auxiliary Feedwater ALARA As-Low-As-Reasonably-Achievable ANS Alert and Notification System ASME American Society of Mechanical Engineers BAP Byron Administrative Procedure BFP Byron Fuel Handling Procedure BGP Byron General Operating Procedure BOP Byron Operating Procedure BOSR Byron Operating Surveillance Requirement Procedure BVP Byron Technical Procedure BVSR Byron Technical Surveillance Requirement Procedure CFR Code of Federal Regulations CR Condition Report DEP Drill and Exercise Performance ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EP Emergency Preparedness EPRI Electric Power Research Institute ERO Emergency Response Organization HRA High Radiation Area HRSS Highly Radioactive Sampling System HSAS Homeland Security Advisory System IMC Inspection Manual Chapter ISI In-service Inspection LCOAR Limiting Condition for Operation Action Requirement NCV Non-Cited Violation NSP Nuclear Station Procedure OD Operability Determination OHS Office of Homeland Security PORC Plant Operations Review Committee PRA Probabilistic Risk Assessment PWR Pressurized Water Reactor RCA Radiologically Controlled Area RCS Reactor Coolant System RP Radiation Protection RWP Radiation Work Permit RIS Regulatory Information Summary SDP Significance Determination Process SSC System Structure or Component SX Essential Service Water TS Technical Specification UFSAR Updated Final Safety Analysis Report US Unit Supervisor USNRC United States Nuclear Regulatory Commission VHRA Very High Radiation Area WO Work Order WR Work Request

LIST OF DOCUMENTS REVIEWED 1R04 Equipment Alignment Byron Station Technical Specifications Byron/Braidwood Stations Updated Final Safety Analysis Report (UFSAR)

Action Tracking Operations Plant Status and Configuration July 5, 2002 Report 106267 Control events Condition Report (CR) Inadequate Corrective Actions Specified in March 22, 2001 B2001-01250 Previous CR CR B2001-01292 2B Diesel Generator Starting air System March 26, 2001 Valve Found Out of Position CR B2001-02055 AB Monitor Tanks Cross-tied May 2, 2001 CR B2001-03058 Mispositioned Valve Found at Unit 1 Boric July 11, 2001 Acid Skid CR B2001-01250 Inadequate Corrective Actions Specified in March 22, 2001 Previous CR CR 00075173 2AF005D Controller at Unit 2 Remote September 13, 2001 Shutdown Panel Found Out of Position CR 00094472 Fuel Assembly Misplaced in New Fuel February 8, 2002 Storage Vault CR 00100716 Loss of Start Capability of 2A Feedwater March 24, 2002 Pump CR 00106267 Adverse Trend in Ops Plant Status and May 6, 2002 Configuration Control Events CR 00107725 Trouble Opening 2A Feedwater Pump May 11, 2002 Suction Valve CR 00110083 Wrong Unit Error - Instrument Maintenance May 30, 2002 Department Fire Protection Surveillance Byron System Auxiliary Feedwater System Train A Valve Revision 3 Operating Procedure Lineup (BOP) AF-M1A BOP CS-E2 Containment Spray System Unit 2 Electrical Revision 3 Lineup BOP SX-M1A Unit 1, Train B, Essential Service Water Revision 3 Valve Lineup

BOP SX-M2A Unit 2, Train B, Essential Service Water Revision 3 Valve Lineup BOP SX E1A Unit 1, Train B, Essential Service Water Revision 2 Electrical Lineup BOP SX E2A Unit 2, Train B, Essential Service Water Revision 1 Electrical Lineup BOP SX E3 Unit 0 Essential Service Water System Revision 7 Valve Lineup Drawing M-37 Diagram of Auxiliary Feedwater System Revision AV 1R05 Fire Protection Byron/Braidwood Stations Fire Protection Revision 19 Report Fire Protection Program 9.5.1 Byron Fire Protection Report, Section Amendment 13 2.3.8.8, Unit 1 Mezzanine Floor (Turbine Building)

Byron Station Pre-Fire Plans and Drawings Emergency Response Training Fire Brigade January 1999 Program Fire Protection Report Safe Shutdown Equipment and Cables Listed By Fire Zone, Table 2.4-4 Byron Letter 84-1020 Seismic Supports for Fire Extinguisher August 13, 1984 Brackets Letter - Sargent & Fire Rating of Structural Steel Beams with August 12, 1988 Lundy Engineers Partially Unprotected Areas SAIC Report No. Table 2 - Fire Compartment Ignition Revision 0 4563-400-02 Frequency Table - Byron Byron Administrative Fire Prevention for Transient Combustibles Revision 10 Procedure (BAP)

1100-7 BAP 1100-7A1 Minor Transient Combustibles Revision 1

Byron General Plant Barrier Impairment (PBI) Program Revision 17 Operating Procedure (BGP) 1100-3 CR 00111670 Security Contingency Lockers not Fire June 12, 2002 Rated CR 00117241 Observations from Critique of 7/27/02 Fire July 27, 2002 Drill CR 00117445 Potential Fireproofing Issue in Unit 2 Diesel July 18, 2002 Generator Cable Tunnel Nuclear Station Fire Drill Scenario No. 8 Revision 3 Procedure (NSP)

OP-AA-201-003 NSP OP-AA-201-003 Fire Drill Performance Revision 5 Unit 0 Byron Fire Rated Assemblies Visual Inspection Revision 2 Technical Surveillance Requirement Procedure (BVSR)

10.g.8-1 Work Order (WO) Fire Extinguisher Annual Maintenance and August 30, 2002 99275518 Inspections 2 Byron Maintenance Portable Fire Extinguisher Annual Revision 3 Surveillance Inspection/Maintenance Requirement Procedure FP-4 1R07 Heat Sink Performance (71111.07)

NSP Service Water Heat Exchanger and Revision 0 ER-AA-340-1002 Component Inspection Guide NSP Generic Letter 89-13 Program Revision 0 ER-AA-340-1001 Implementation Instructional Guide NSP ER-AA-340 Generic Letter 89-13 Program Revision 0 Implementation Procedure Byron Technical Service Water Fouling Monitoring Program Revision 5 Procedure (BVP)

800-30 BVP 800-30 Service Water Fouling Monitoring Program Revision 6

Generic Letter 89-13 Service Water System Problems Affecting Supplement 1 Safety-Related Equipment April 4, 1990 Focus Area Self Heat Sink Performance May 1, 2001 Assessment WO 99215024 2VA08S - Heat Exchanger (HX) Inspection September 19, 2002 per Generic Letter 89-13 WO 99275593 2SX02K - HX Inspection per Generic Letter September 19, 2002 89-13 WO 99275594 2SX01K - HX Inspection per Generic Letter September 19, 2002 89-13 WO 99275648 2AF01AB - HX Inspection per Generic Letter September 19, 2002 89-13 WO 99275649 2AF02AB - HX Inspection per Generic Letter September 19, 2002 89-13 CR B2001-02520 Inadequate Acceptance Criteria for Generic May 31, 2001 Letter 89-13 Heat Exchanger Inspections CR 00081816 Lube Oil Cooler Degradation November 5, 2001 CR 00084018 2B Diesel Generator Jacket Water Heat November 26, 2001 Exchanger Reversing Head Corrosion CR 00084059 2B Diesel Generator Jacket Water Channel November 27, 2001 Heads CR 00084260 Degraded Ceramalloy Coating on 2B Diesel November 28, 2001 Generator Jacket Water Cooler, 2DG01KB-X2 CR 00094031 Eddy Current of 1A VP Chiller Not Identified February 04, 2002 for Performance CR 00110460 NRC Response to Unresolved Item May 31, 2002 50-454/455-01-03-01 CR 0123498 2B Auxiliary Feedwater Pump Cubicle September 19, 2002 Cooler Channel Head Degradation CR 00124919 1 Issues Identified during USNRC Review of September 26, 2002 89-13 HX Inspections CR 00125982 1 NSP-ER-AA-340-1002 Does Not Have Clear October 4, 2002 Acceptance Criteria 1R08 Inservice Inspection (71111.07)

ISI Program Plan, Second Ten-Year February 15, 2002 Inspection EXE-PDI-UT-2 Ultrasonic Examination of Austenitic Piping March 11, 2002 Welds in Accordance with PDI-UT-2 EXE-ISI-70 Magnetic Particle Examination February 6, 2002 CR 00100467 Quality Verification Certification Document March 22, 2002 Enhancements Related to Record Organization and Storage CR 00121158 Nondestructive Examination Procedure August 30, 2002 Deficiencies CR 00124722 Foreign Material Exclusion (FME) Found in September 25, 2002 Secondary Side of Steam Generators During B2R10 Byron Letter Byron Station Unit 1 90-Day Inservice June 27, 2002 2002-0065 Inspection Report For Interval 2, Period 2, Outage 2 (B1R11)

NRC Letter Approval of Relief Request 12R-40 for February 5, 2002 Application of Risk-Informed Inservice Inspection Program as an alternative to the ASME Boiler and Pressure Vessel Code Section XI Requirements for Class 1 and Class 2 Piping Welds for Byron Station, Units 1 and 2 1R11 Licensed Operator Requalification (71111.11)

CR 00117514 Exam Material Found in Unsecured Location July 19, 2002 Dated July 19, 2002 Apparent Cause Uncontrolled Licensed Operator August 20, 2002 Evaluation Requalification Training Exam Material Left in the Scantron Machine Area Memorandum Exam Administrator Limitations July 31, 2002 SCORECARDS Examination Activated Observation August 8, 2002, August 16, 2002 and 2 on August 9, 2002 NSP TQ-AA-201 Examination Security and Administration Revision 1 NSP Exam Proctor Checklist Revision 0 TQ-AA-201-0101

Memo #98-005 Examination Security Policy Revision 8 Policy 98-005 Exam Security Checklist Attachment C NSP OP-AA-101-111 Rules and Responsibilities of On-Shift Revision 0 Personnel NSP OP-AA-103-102 Watchstanding Practices Revision 0 NSP OP-AA-103-103 Operation of Plant Equipment Revision 0 NSP OP-AA-103-104 Reactivity Management Control Revision 0 NSP OP-AA-104-101 Communications Revision 0 Simulator Scenario Respond to an Anticipated Transient BY-46 Without Scram and Miscellaneous Malfunctions 1R12 Maintenance Rule Implementation Technical Requirements Manual Technical Specifications Maintenance Rule Component Cooling Water System Performance Criteria CC1 Maintenance Rule Ultimate Heat Sink Temperature Control Performance Criteria SX2 Maintenance Rule Ultimate Heat Sink Level Control Performance Criteria SX3 CR B2001-01299 0B Essential Service Water (SX) Tower Fan March 27, 2001

- Unexpected Alarm and Oscillating Amps CR B2001-02592 SX Fan Gearbox Oil Sample Contains High June 6, 2001 Iron Particulate CR B2001-02986 0G Low Speed SX Fan Failure To Start July 7, 2001 CR B2001-03207 0C SX Natural Draft Cooling Tower Fan Trip July 22, 2001 CR B2001-03321 1SX147B Functional Failure July 27, 2001 CR 00078039 SX Low Speed Fan 0G Failure to Start October 7, 2001 (Breaker Tripped Open)

CR 00089902 Auxiliary Feedwater and SX Make-up January 10, 2002 Engines Governor Dump Soleniod-operated Valve - Results of Byron Root cause Report CR 00091481 2CC9473B Did Not Go Full Closed During January 19, 2002 Attempt to Close CR 00103523 Found What Appears To Be 2 Loose Lower April 15, 2002 Set Screws Associated With The Shaft Seal On The 0A SX Make-up Pump (0SX02PA)

CR 00103876 Evaluation of SX Cooling Tower OF Fan April 15, 2002 Motor Noise and Vibration Data CR 00104086 0B SX Make-up Pump Auto Start During April 16, 2002 2SX150B Valve Stroke CR 00104925 0B SX Fan Bolting Torque Values Found April 22, 2002 Lower Than Specified CR 00105174 Newly Rebuilt SX Fan Motor Improperly April 24, 2002 Rebuilt By Vendor CR 00109216 2B Component Cooling Water Pump Failed May 23, 2002 to Start From 2PM06J Control Switch CR 00110752 Indicated Slow Start of 0B SX Make-up June 5, 2002 Pump From Main Control Room CR 00111838 Void Discovered in SX Cooling Tower June 13, 2002 Concrete During Repairs CR 00112798 Pin Hole Leak In 1360 Tank fill Line June 21, 2002 1R13 Maintenance Risk Assessments And Emergent Work Control Byron Operating On-Line Risk/Protected Equipment Revision 2 Department Policy 400-47 NSP WC-AA-103 On-Line Maintenance Revision 4 CR 0078130 Incorrect Probabilistic Risk Assessment October 8, 2001 (PRA) Risk Information Used in Work Week Analysis CR 00100141 B1R11 Work Slippage Resulting in Unit 2 March 19, 2002 On-Line Risk Incorrect

CR 00101822 PRA System Structure and Component April 1, 2002 Shutdown Crosstie Assumptions Need Maintenance Rule Expert Panel Review CR 00102971 On-Line Risk Not Properly Evaluated April 9, 2002 CR 00103721 2B Diesel Generator Limiting Condition for April 14, 2002 Operation Action Requirement (LCOAR)

Time Not Minimized CR 00103205 Unit 2 Online Risk Not Properly Evaluated April 9, 2002 During B1R11 CR 00104787 Potentially Incomplete Risk Assessment of April 22, 2002 Emergent Condition CR 00108581 Online Risk Not Evaluated for 1B Main May 17, 2002 Steam Dump Work Extension CR 00109282 Unit 2 Online Risk Evaluations May 23, 2002 CR 00109418 0C VA Exhaust Fan Out-of-Service, Not May 22, 2002 Evaluated For Risk CR 00109678 Fire Pump Cooling Water Availability for May 28, 2002 Diesel Generator Outage CR 00114997 Emergent Online Risk Evaluation Not July 10, 2002 Performed for Unit 1 Station Air Compressor Trip CR 00115266 PRA Credit For Motor-Operated Valves/Air- July 11, 2002 Operated Valves Closing to Isolate an Inter-system Loss-of-Coolant Accident CR 00118822 Unnecessary Auxiliary Feedwater August 9, 2002 Unavailability Due to Lack of Bundling NSP MA-MW-1001 Maintenance Risk Assessment Revision 0 NSP LS-AA-125-1006 Corrective Action Program Process September 2002 Expectations NSP WC-AA-103 On-Line Maintenance Revision 4 NSP WC-AA-104 Review and Screening for Production Risk Revision 4 NSP Human Performance Review Process for Revision 1 WC-AA-104-1001 High-Risk Maintenance Procedures or Work Packages NSP ER-AA-600 Risk Management Revision 2

Regulatory Guide Assessing and Managing Risk Before May 2000 1.182 Maintenance Activities at Nuclear Power Plants 1R14 Personnel Performance During Non-routine Plant Evolutions CR 00120887 Potential Unanalyzed Condition Re: Steam August 28, 2002 Line Break Analysis 2BGP 100-4 Power Descension Revision 17 2BGP 100-5 Plant Shutdown and Cooldown Revision 30 NSP OP-AA-101-111 Rules and Responsibilities of On-Shift Revision 0 Personnel NSP OP-AA-103-102 Watchstanding Practices Revision 0 NSP OP-AA-103-103 Operation of Plant Equipment Revision 0 NSP OP-AA-103-104 Reactivity Management Control Revision 0 NSP OP-AA-104-101 Communications Revision 0 1R15 Operability Evaluations Technical Specifications UFSAR Shift Manager Log May 13, 2002 Byron Inservice Pressurizer Liquid To Highly Radioactive Testing Bases Sampling System (HRSS) SCP PS29J Document Inside Containment Byron Inservice Pressurizer Liquid To HRSS SCP PS29J Testing Bases Outside Containment Document Byron Inservice Reactor Coolant To HRSS SCP PS29J Testing Bases Inside Containment Isolation Document Operability Leakage of SI8819 Check Valves Revision 0 Determination (OD) Pressurizing Safety Injection Pump 02-009 Discharge Lines

OD 02-012, 1A Reactor Containment Fan Cooler July 17, 2002 Elevated Vibration Levels CR 00107104 Elevated (acceptable) Closed Stroke Time June 6, 2002 for 2PS9355B CR 00107967 Sample Valve 1PS9355A Does Not Indicate May 13, 2002 Closed CR 00109300 Poor Coordination Between Troubleshooting May 23, 2002 and Post Maintenance Testing CR 00110332 Containment Isolation Valve Failing Closed June 2, 2002 CR 00110778 Leakage of SI8819 Check Valves Revision 0 Pressurizing Safety Injection Pump Discharge Lines CR 00111294 Installed Relief Valves 2PS9556A/B Failed June 10, 2002 Testing CR 00111360 Unit 2 Reactor Coolant Sample Not June 10, 2002 Collected CR 00112328 Air-Operated Valves May Not Fail to Safe June 18, 2002 Position on Loss of Instrument Air Due to Regulator CR 00120436 Unexpected Steam Generator Chemistry August 22, 2002 Excursion CR 00122493 1 Remote Shutdown Panel Elevated Room September 11, 2002 Temperature Questions Byron Station Root 1BOL 6.3 Not Entered When 1PS9355A July 1, 2002 Cause Report Exhibited Closed Indication Problems Work Order Selection AOVA 9355A (Unit 1) June 7, 2002 Prompt Work Order Selection AOVA 9355B (Unit 1) June 7, 2002 Prompt Work Order Selection AOVA 9356A (Unit 1) June 7, 2002 Prompt Work Order Selection AOVA 9356B (Unit 1) June 7, 2002 Prompt Work Order Selection AOVA 9355A (Unit 2) June 7, 2002 Prompt

Work Order Selection AOVA 9355B (Unit 2) June 7, 2002 Prompt 1R17 Permanent Plant Modifications Technical Specifications Upgraded Final Safety Analysis Report Modification Approval Emergency Diesel Generator Governor October 17, 1997 Letter DCP# 9400204 Upgrade BAP 1310-8T1 Special Procedures/Tests/Experiments Revision 7 Request Form Procedure NEP-04-03 10CFR50.59 Safety Evaluations Revision 0 Nuclear Station Work Validation of Previously Performed Safety Revision 0 Procedure -A-04 Evaluations and Screenings Work Package No. DCN # BYR0006909E Rev. 10/17/1997 Revision 0 96113647-03 1R19 Post Maintenance Testing Byron/Braidwood Stations UFSAR Byron Station TS BAP 1310-8TI Special Procedures/Tasks/Experiments Revision 7 Requests Form BOP CV-3 Filling and Venting the Chemical and Revision 13 Volume Control System BOP EH-11 Digital Electrical Hydraulic Control (DEHC) Revision 1 Operations BOP DG-1 Diesel Generator Alignment to Standby Revision 9 Condition BOP DG-11 Diesel Generator Startup Revision 17 BOP DG-12 Diesel Generator Shutdown Revision 16 BOP RH-3 Fill and Vent of the Residual Heat Removal Revision 19 System BOP RH-6 Operation of the Residual Heat Removal Revision 25 System in Shutdown Cooling

BOP RH-11 Securing the Residual Heat Removal Revision 16 System From Shutdown Cooling Unit 2 Byron Unit 2B Diesel Generator Sequence Test, 18 Revision 1 Operating Month Surveillance Requirement Procedure (BOSR)

8.1.11-2 Work Request (WR) Diesel Generator Room 2B Vent Fan 2V July 18, 2002 00058257 D01CB Breaker WR 0059652 Complex Troubleshooting - Prior to Event: July 31, 202 Steady State- 100 percent Power-DEHC in Auto Mode WO 000467042-01 Control Power Lost Upon Securing Fan July 18, 2002 2AP1ZE-J WO 00470840 DEHC Control Panel August 3, 2002 CR 00115243 Loss of Control Power to 2VD01CB Causes July 18, 2002 LCOAR Entry CR 00117597 Failure of Unit 1 DEHC Control Display July 31, 2002 CR 00119741 0BVSR 7.10.2-2 0A VC Make-up System August 19, 2002 Operability Test Failure Special Plant R/O; 2B Diesel Generator Governor Revision 0 Procedure-02-005 Upgrade Setup and Construction Test WO 00412257 Task Instructions WO 00444666 1AF01PB 1B Auxiliary Feedwater Pump August 13, 2002 ASME Surveillance (2 VC Trains Required Operable)

WO 99285127 Replace Drain Line August 13, 2002 WO 9928512701 Replace 1B SX Pump Strainer Drain Line, Completed and valve 2WE010B August 12, 2002 WO 9921105901 Replace 1B Diesel-Driven Auxiliary August 13, 2002 Feedwater Pump 1B Battery Charger Control Card WO 00403354 1B Auxiliary Feedwater Pump Diesel August 13, 2002 Tachometer Reading Higher Than Actual WR 00444169 Diesel Driven Auxiliary Feedwater Pump August 15, 2002, Quarterly Surveillance Revision 7

WR 99002670801 0A Control Room Make-up System Charcoal December 14, 2000 Absorber Bank Operability Test WO 389028 0SX138B Remains Full Open With 1B and December 12, 2001 2B SX Pumps 0BVSR 7.10.2-2 0B Control Room Make-up System Charcoal Revision 2 Absorber Bank Operability Test Performed on July 10, 2002 0BVSR 7.10.2-2 0A Control Room Make-up System Charcoal Revision 2 Absorber Bank Operability Test Performed on August 19, 2002 0BVSR 7.10.2-2 0A Control Room Make-up System Charcoal Revision 2 Absorber Bank Operability Test Performed on August 20, 2002 2BVSR 5.5.8.SX.1-2 Test of the 2B Essential Service Water Revision 3 Pump and Discharge Check Valve 1R20 Refueling and Outage Activities B2R10 Issues Open Items B2R10 Scope Changes Technical Specifications Updated Final Safety Analysis Report List of Work Removed From B2R10 Between Scope Freeze and Outage Start B2R10 Issues Completed Byron Station U-2 - Open Operability Revision Determination Status September 24, 2002 B2R1- Shutdown Safety Analysis September 5, 2002 Switchyard Work Checklist September 27 -

September 30, 2002 Shift Manager Log September 27, 2002 Plant Operations B2R10 Shutdown Safety Plan September 5, 2002 Review Committee (PORC) Package

NUREG-1022 Event Reporting Guidelines, 10 CFR 50.72 Revision 2 and 50.73 BAP 370-3 Administrative Control During Refueling Revision 31 Byron Fuel Handling Fuel Movement in Spent Fuel Pool Revision 12 Procedure (BFP)

FH-4 BFP FH-5 Fuel Movement in Containment Revision 12 BFP FH-12 Operation of the Spent Fuel Pool Bridge Revision 11 Crane BFP FH-14 Operation of Refueling Machine Revision 15 2BGP 100-1T2 Mode 5 to 4 Checklist Revision 12 2BGP 100-1T3 Mode 4 to 3 Checklist Revision 14 2BGPP 100-1T5 Containment Integrity Checklist Revision 10 Byron Maintenance Reactor Vessel Upper Internals Removal Revision 14 Procedure 3118-3 2BOSR z.5.b.1-1 Unit 2 Containment Loose Debris Inspection Revision 2 2BOSR 4.3.1-1 Unit 2 Reactor Coolant System Revision 4 Pressure/Temperature Limit Surveillance Regulatory Guide Quality Assurance Program Requirements Revision 2 1.33 (Operation)

Byron Work Control Online Management of Risk Sensitive Work June 12, 2001 Policy Memo 200.09 Westinghouse Head O Ring Leakage Revision 2 Technical Bulletin NSD-TB-87-02 NSP MA-AA-716-008 Foreign Material Exclusion Program Revision 0 NSP OU-AA-103 Shutdown Safety Management Program Revision 1 NSP OU-AP-104 Shutdown Safety Management Program Revision 5 Byron/Braidwood Annex CR 00102684 B1R11 Outage Concerns March 11, 2002 CR 00119358 Common Cause Results for CR 102684 - August 14, 2002 B1R11 Ops Issues CR 00117625 Removal of 2FW009C from B2R10 July 31, 2002

CR 00124395 1 NRC Inspector Discussion & Question of September 24, 2002 FME Practices CR 00124722 FME Found in Secondary Side of Steam September 25, 2002 Generators During B2R10 CR 00124999 1 NRC B2R10 Close Out Walk Down of September 29, 2002 Containment CR 00123496 Eagle Timer Relay T6A in 2PA13J Failed to September 18, 2002 Operate CR 00124088 Shutdown risk comments B2R10 to date September 23, 2002 CR 00124902 Prompt Investigation: Unit 2 Shutdown Risk September 27, 2002 Challenged by Switchyard Activities CR 00125833 1 Possible Reportable Issues Related to Mode October 3, 2002 Specific CRs Contingency Plan Reactor Coolant System Inventory at the September 18, 2002 B2R10 CP-10 Flange DCR 338169 50.59 Review January 11, 2001 NSP MA-AA-716-008 Foreign Material Exclusion Program Revision 0 Procedure NF-AA-100 Reload Control Procedure Revision 0 NSP OP-AA-108-108 Unit restart Review Revision 0 PORC #02-048 B2R10 Mode 4 Startup NSP (Process for September 26, 2002 Mode Change) OP-AA-108-108 WR 66533 Dried Boron on Valve Stem of PS9350B September 27, 2002 WR 66514 Penetrations for Instruments 2PT-PC005, September 27, 2002 2PT-935, 2PT-936 Contain Wood Piece in Containment WR 66523 Box 2VQ12JC Missing a Clip and Screw September 27, 2002 Assembly on Top WR 66535 2JB540R Missing Screw in Lower Left September 27, 2002 Corner WR 66510 Incore Cabinets Have Screws that are September 27, 2002 Loose WR 66531 Dried Boron Found on 2RC5434B and September 27, 2002 Below Grating WR 66542 2CC50AC Pipe Has Surface Rust Needs September 27, 2002 Painting

WO 00430377 2CV8378A Disassembly Inspection September 21, 2002 WO 00430396 2CV8378B Disassembly Inspection September 21, 2002 Clearance Order 9205 DC 111 to DC 211 cross tie September 17, 2002 1R22 Surveillance Testing Technical Specifications Updated Final Safety Analysis Report CR 00119240 Missed Technical Specification Surveillance August 13, 2002 2CS010B CR 00123283 Procedure Improvements for 2BOSR September 17, 2002 6.3.8-1 CR 00123286 Post Job Critique if 2BOSR 3.2.9-1/2 September 19, 2002 Surveillance CR 00123339 P4 Feedwater Isolation Received During September 19, 2002 2BOSR 3.2.9-1 CR 00123652 Typographical Error on Procedure Data September 19, 2002 sheet in 2BVSR 5.5.8.SI CR 00123656 Erroneous Expected Value in Procedure September 19, 2002 2BVSR 5.5.8.SI.2-1 CR 00123865 Surveillance Results Appear to Indicate High September 20, 2002 CV Pump Flow 1BOSR 0.5-2.CS.1-1 Unit 1 Train A Containment Spray System Revision 2 Valve Stroke Test 1BOSR 8.1.2-2 Unit 1 1B Diesel Generator Operability Revision 11 Surveillance Test 2BOSR 6.3.6-1 Unit 2 Primary Containment Type C Local Revision 4 Leakage Rate Tests of Containment Miniflow Purge Isolation Valves (VQ)

2BOSR 3.2.9-2 Train B Manual Safety Injection Initiation Revision 11 and Manual Phase A Initiation Surveillance 1BOSR 3.1.5-2 Train B Solid State Protection System Bi- Revision 12 Monthly Surveillance 2BVSR 5.5.8.SX.1-2 Test of the 2B Essential Service Water Revision 3 Pump and Discharge Check Valve

WO 00435618 Stroke Test 1CS001A, 1CS009A, 1CS019A, July 1, 2002

& BT 1CS020A WO 00435122 ASME Surveillance Requirements For SX June 19, 2002 Pump WO 00491092 Summation of Type B and C Local Leak September 28, 2002 Rate Tests for Acceptance CR WO 99276897-01 2BOSR 3.2.9-2 Train B Manual Safety September 17, 2002 Injection and Phase A Initiation 1R23 Temporary Plant Modifications NOA-BY-02-1Q Nuclear Oversight Continuous Assessment April 29, 2002 Report, Byron Nuclear Power Station CR B2001-03217 Unauthorized Temporary Modification July 23, 2001 Installed to Provide Cooling to the Miscellaneous Electrical Equipment Room CR B2001-03374 Unauthorized Temporary Modification August 2, 2001 CR 00078478 Unauthorized Temporary Modification October 10, 2001 Installed at Air Dampers CR 00080266 Unauthorized Temporary Modification October 24, 2001 Installed on Door 0DSSD171 CR 00080828 Inspector Comments October 29, 2001 CR 00084217 0WM2038 Denim Water Supply Valve Has November 28, 2001 Too Much Hanging On It CR 00092124 Inappropriate Authorization of an Installed January 24, 2002 Temporary Change CR 00093890 Unapproved Temporary Modification February 4, 2002 Installed at 0VS03C Plenum Doors CR 00096463 1DO22M Filter Cartridges February 23, 2002 CR 00100750 Unauthorized Alteration of Plant Equipment, March 24, 2002 0VS03C (Repeat)

CR 00104152 Adverse Trend in Unauthorized Temporary April 16, 2002 Modifications CR 00117281 Unauthorized Cable Attached to SX Cooling July 25, 2002 Fan Motor

CR 00117919 Potential Temporary Modification Without August 1, 2002 Proper Paper Engineering Change # Provide Temporary Setpoint Band Change Revision 0 336844 for Underfrequency Relay 0SSL-SY077 to Main Control Room Annunciator 0-35-F5 Engineering Change Install A3 Cable to the A4 Preamplifier at the Revision 0

  1. 333751 2NR-13 (Post Accident Neutron Monitoring System)

NSP CC-AA-112 Temporary Configuration Changes Revision 5 NSP Temporary Configuration Change Packages Revision 0 CC-MW-112-1001 1EP2 Alert and Notification System (ANS) Testing Byron Off-site Siren Test Plan Revision 3 Byron Monthly Siren Availability Reports 2001-2002 Siren Daily Operability Data Sheets 2001-2002 Exelon Semi-Annual Siren Report July 1-December 31, 2001 1EP3 Emergency Response Organization (ERO) Augmentation Testing June 19, 2001 Off-Shift Augmentation Drill June 25, 2001 Re-Demonstration Off-Shift Augmentation June 25, 2001 Drill December 13, 2001, Augmentation Drill December 14, 2001 Report May 29, 2002, Augmentation Drill Report May 30, 2002 ERO Duty Roster July 12, 2002 Section N.2 Exelon Nuclear Radiological Emergency Revision 11 Plan TE-001 Respiratory Qualifications Report July 25, 2002

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies Training Records for Licensed Operator Requalification Training and Dec Makers Byron Station Emergency Preparedness July 19, 2002 (EP) Program Assessment Report NSP EP-AA-122 Exercises and Drills Revision 1 NSP EP-AA-122-1001 Drill Development, Conduct, and Evaluation Revision 0 NSP EP-AA-122-1002 Drill Development, Conduct and Evaluation Revision 0 NSP LS-AA-125 Corrective Action Program Procedure Revision 3 Memorandum 2001 Exercise Findings and Observation December 26, 2001 Report NOA-BY-01-4Q Nuclear Oversight Continuous Assessment January 30, 2002 Report Byron Station October-December 2001 0076173/32 Nuclear Oversight Field Observation Report: January 03, 2002 Offsite Interface CR B200100279 Potential USNRC Performance Indicator January 19, 2001 Data Discrepancy CR B200100302 EP Focus Area Self-Assessment January 22, 2001 Recommendations for Improvement CR B200102409 Generating Station Emergency Plan May 22, 2001 Environs Radio Problems With Emergency Off-site Facility CR B200103397 Table Top Drill Issues Lead to Missed August 3, 2001 Performance Indicator Opportunity.

CR 00074467 Emergency Action List HA5 Needs September 6, 2001 Clarification CR 00082588 Areas for Correction From October 31, 2001 November 12, 2001 Pre-Exercise CR 00084351 Siren Monthly Reporting Data November 29, 2001 CR 00086929 Byron Marginally Successful Augmented December 14, 2001 Drill December 13, 2001

CR 00087866 Areas for Correction From November 28, December 21, 2001 2001 Exercise CR 00089792 Severe Accident Management Guidelines January 10, 2002 CR 00102426 Re-submittal of ANS (Siren) Reliability April 4, 2002 Performance Indicator Data CR 00102878 Communication Drill Failures April 8, 2002 April 8, 2002 CR 00104314 EP Performance Indicator for Drill and April 16, 2002 Exercise Performance (DEP) Less Than 95 percent CR 00106461 EP Performance Indicator for DEP Remains May 2, 2002 Less Than 95 percent CR 00106490 Declining Trend for Corp ERO Participation May 2, 2002 Affects Site Performance Indicator CR 00116318 EP Training Records Not in TAS July 19, 2002 1EP6 Drill Evaluation NEI 99-02 Regulatory Assessment Performance Revision 2 Indicator Guideline Byron Station 2002 Integrated Drill Scenario August 21, 2002 and Associated Information Byron 2002 Integrated Preliminary Report August 23, 2002 Drill 20S1 Access Control to Radiologically Significant Areas AR 00099598 Poor Radiation Worker Practices During March 15, 2002 B1R11 AR 00123412 Radiation Worker Practices September 17, 2002 AR 001247071 Cavity Decontamination Air Sampling September 25, 2002 BAP 1450-3 Access to Reactor Incore Sump Area Revision 9 BFP-FH-37 Control of Non-Fuel Items in the Spent Fuel Revision 3 Pool BRP 6020-2 Radiological Air Sampling Program Revision 16

RHS-19.1 Radiological Controls for Handling Items and Revision 0 Hanging Activated Parts in the Spent Fuel Pool RP-AA-460 Controls for High and Very High Radiation Revision 2 Areas 2OS2 As-Low-As-Reasonably-Achievable (ALARA) Planning and Control AR 00100011 Weakness Identified in Source Term March 15, 2002 Reduction Program AR 00109992 Deficiencies While [FASA] Performing Focus May 30, 2002 Area Self Assessment on Source Term Reduction AR 00110773 ALARA Dose Reduction Suggestion June 6, 2002 AR 00111054 Additional Dose Taken Due to Unit 2 June 7, 2002 AR 00112143 Ineffective Radiation Protection Corrective June 13, 2002 Actions AR 00113057 Wrong Equipment on Steam Generator June 24, 2002 Platform Caused Delays and Dose AR 00119505 Radiation Protection ALARA Outage February 8, 2002 Readiness FASA AR 00120688 Implement Hot Spot Program in Accordance August 27, 2002 with RP-AA-550-1001 AR 00121456 Work on 2CV01DA Exceeded Dose September 3, 2002 Estimate AR 00123803 Steam Generator Dose Rates September 20, 2002 AR 00124584 Reactor Services Equipment Not Removed September 25, 2002 for Cavity Decontamination AR 00124728 Steam Generator Exposure Exceeds Goal September 20, 2002 AR 001247311 NRC Observations During B2R10 Inspection September 26, 2002 FASA 2002-006 Focus Area Self Assessment Report, May 21 - 23, 2002 Radiation Protection, Byron Station FASA 2002-006 Focus Area Self Assessment Report, August 6 - 7, 2002 Radiation Protection, Byron Station RP-AA-270 Prenatal Radiation Exposure Revision 2

RP-AA-401 Operational ALARA Planning and Controls Revision 2 RP-AA-401, ALARA Plan (for Radiation Work Permit Revision 2 Attachment 2 (RP) 10001452))

RP-AA-401, ALARA Plan (for RWP 10001466) Revision 2 Attachment 2 RP-AA-401, ALARA Plan (for RWP 10001479) Revision 2 Attachment 2 RP-AA-401, ALARA Plan (for RWP 10001489) Revision 2 Attachment 2 RP-AA-401, Work in Progress Review (Completed for Revision 2 Attachment 7 radiation work permits nos. 10001439, 10001447, 10001452, 10001475, and 10001489)

RP-AA-403 Administration of the RWP Program Revision 1 RP-AA-550-1001 Hot Spot and Radiation Source Component Revision 0 Tracking RP-MW-403-1001 RWP Processing Revision 0 RWP 10001452 Secondary Side Inspections and Sludge Revision 0 Lance RWP 10001466 Remove and Install Reactor Head and Revision 1 Upper Internals RWP 10001479 Reactor Vessel Bottom Incore Area Revision 3 RWP 10001489 Reactor Cavity Decontamination Revision 0 4OA1 Performance Indicator Verification Byron Monthly Siren Availability Reports October 2001-March 2002 Siren Daily Operability Data Sheets October 2001-March 2002 Exelon Semi-Annual Siren Report July 1-December 31, 2001 Supporting Documentation and Records for DEP October 2001-March 2002 BCP 300-23 Reactor Coolant or Pressurizer Liquid Revision 24 and/or Grab Sample

BCP 300-37 Degassing Reactor Coolant System Revision 5 CC #008 NRC Performance Indicator Notebook, Drills, Exercise and Actual Event Performance Shift Managers Logs Selected Portions from July 2001 through June 2002 2002 Byron Simulator/Technical Support July 8, 2002 Center EP Performance Indicator Data -

Cycle 2002-4 1BOSR 4.13.1-1 Reactor Coolant System Water Inventory Revision 3 Balance Surveillance Process Computer Data Sheets for the Period of July 2001 through June 2002 CR 1242761 Step 11 of BCP 300-37 Was Not Performed September 24, 2001 CR B2001-03130 Work in Progress Delays Out-of-Service, July 17, 2001 Incurs 4 Minutes of LCOAR Time For 2A Safety Injection Pump CR B2001-03273 Critique of 2A Safety Injection Pump Work July 19, 2001 Window and Delays Experienced CR B2001-03253 OE12506-Core Alterations Performed With July 25, 2001 Boration Flow Path Inoperable CR B2001-03406 Emergency Core Cooling System (ECCS) August 6, 2001 Unavailability Reporting Discrepancies CR 00083620 ECCS Pipe Venting Modification May Not November 21, 2001 Perform Its Intended Function CR 00083719 ECCS Vent Excessive Gas November 22, 2001 CR 00097301 Unexpected LCOAR Entry on ECCS February 28, 2002 Systems CR 00099599 1CV459 As-Found Test Results Outside March 15, 2002 Allow Accept Criteria CR 00099656 ECCS Full Flow Lessons Learned For March 16, 2002 B1R11 CR 00100059 Possibly Multiple Missed LCOAR Entries March 20, 2002 CR 00100658 Unit 2 Refueling Water Storage Tank Level March 22, 2002 Indicator of ~1 percent With Unit 1 Cavity Pump Down

CR 00102581 1B CV Pump Casing Leak April 5, 2002 CR 00110778 Unit 1 Safety Injection Pump Discharge June 5, 2002 Pressure at Safety Injection Accumulator Pressure CR 001167871 Revised DEP Performance Indicator Data July 24, 2002 Not Updated in Business Ops Spreadsheet LS-AA-2090 Monthly Performance Indicator Data Completed Elements for Reactor Coolant System September 2001 Specific Activity through July 2002 NSP LS-AA-2100 Monthly Performance Indicator Data Revision Elements for Reactor Coolant System June 25, 2001 Leakage, Data for July 2001 through June 2002 NSP LS-AA-2110 Monthly Performance Indicator Data Elements for ERO Participation October 2001-March 2002 NSP LS-AA-2120 Monthly Performance Indicator Data Elements for DEP October 2001-March 2002 NEI 99-02 Regulatory assessment Performance Revision 2 Indicator Guideline November 19, 2001 NSP RS-AA-122-113 Performance Indicator - Reactor Coolant Revision 2 System Leakage RS-AA-122-112 Performance Indicator - Reactor Coolant Completed System Specific Activity August 6, 2001 4OA5 Other CR 00124013 B2R10 Reactor Head Examination September 22, 2002 NSP RS-01-182 Indications Exelon/AmerGen Response to August 31, 2001 USNRC Bulletin 2001-01, Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles NRC Bulletin 2001-01 Circumferential Cracking of Reactor November 14, 2001 Pressure Vessel Head Penetration Nozzles Responses for Byron Station, Units 1 and 2 and Braidwood Station Units 1 and 2

1-Condition report issued as a result of the inspection 58

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