IR 05000454/2002003

IR 05000454/2002-003(DRP) & IR 05000455/2002-003(DRP), Byron, Units 1 & 2 . Maintenance Risk Assessment, Emergent Work & Refueling & Outage Activities

ML021200344
Person / Time
Site:	Byron
Issue date:	04/26/2002
From:	Ann Marie Stone NRC/RGN-III/DRP/RPB3
To:	Skolds J Exelon Generation Co, Exelon Nuclear
References
IR-02-003
Download: ML021200344 (36)

Text

April 26, 2002

SUBJECT:

BYRON STATION, UNITS 1 AND 2 INSPECTION REPORT 50-454/02-003(DRP); 50-455/02-003(DRP)

Dear Mr. Skolds:

On March 31, 2002, the NRC completed an inspection at the Byron Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on April 3, 2002, with Mr. S. Kuczynski and other members of your staff.

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Two issues of very low risk significance (Green) were identified by inspectors. These issues involved a failure to assess the risk associated with a maintenance activity on the Unit 1 safety injection system and the failure to install the 1B steam generator manway covers in accordance with the maintenance procedure. These issues were determined to involve violations of NRC requirements. However, because of the very low safety significance of the issues and because they were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you contest 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 Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Byron Station.

In accordance with 10 CFR 2.790 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/NRC/ADAMS/index.html (the Public Electronic Reading Room). We will gladly discuss any questions you have concerning this inspection.

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 50-454/02-003(DRP);

50-455/02-003(DRP)

REGION III==

Docket Nos:

50-454; 50-455 License Nos:

NPF-37; NPF-66 Report No:

50-454/02-003(DRP); 50-455/02-003(DRP)

Licensee:

Exelon Generation Company, LLC Facility:

Byron Station, Units 1 and 2 Location:

4450 N. German Church Road Byron, IL 61010 Dates:

February 12, 2002, through March 31, 2002 Inspectors:

R. Skokowski, Senior Resident Inspector J. Adams, Acting Senior Resident Inspector B. Kemker, Senior Resident Inspector, D.C. Cook P. Snyder, Resident Inspector T. Tongue, Project Engineer R. Winter, Reactor Inspector R. Alexander, Radiation Specialist D. Jones, 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 05000454-02-003(DRP), IR 05000455-02-003(DRP), on 02/12/2001-03/31/2002; Exelon Generation Company, LLC; Byron Station, Units 1 & 2. Maintenance Risk Assessment and Emergent Work, Refueling and Outage Activities.

The baseline inspection was conducted by resident and region based inspectors, regional reactor engineers, and radiation specialists. The inspectors identified two Green findings associated with Non-Cited Violations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter 0609, Significance Determination Process (SDP). The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described at its Reactor Oversight Process website at http://www.nrc.gov/NRR/OVERSIGHT/index.html. Findings for which the SDP does not apply are indicated by No Color or by the severity level of the applicable violation.

A.

Inspector Identified Findings Cornerstone: Mitigating Systems

Green. The inspectors identified (self-revealing) that the licensee failed to perform a maintenance risk assessment prior to performing a maintenance activity on the common suction header for the Unit 1 SI pumps.

This finding was determined to be of very low safety significance because the failure did not result in the actual loss of the safety system function. A Non-Cited Violation of 10 CFR 50.65 (a)(4), for the failure to perform a risk assessment was identified.

(Section 1R13).

Cornerstone: Barrier Integrity

Green. The inspectors identified that the installation of the 1B steam generator hot and cold leg manway covers was not completed in accordance with applicable maintenance procedures. The failure to properly install the steam generator manway covers adversely affected the reactor coolant system integrity.

This finding was determined to be of very low safety significance, because the failure did not result in an increase in the likelihood of a significant loss of reactor coolant. A Non-Cited Violation of Technical Specification 5.4.1 a. for the failure to follow the maintenance procedure associated with steam generator manway closure installation was identified. (Section 1R20)

Report Details Summary of Plant Status Unit 1 was operated at or near full power until March 11, 2002 when the licensee conducted a reactor shutdown for refueling outage B1R11. Following the completion of the refueling outage, the unit was synchronized to the grid on March 30, 2002. As the inspection period ended, the unit was being returned to full power.

The licensee operated Unit 2 at or near full power for the duration of the inspection period.

1.

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

a.

Inspection Scope The inspectors verified the system alignment of the equipment listed below during maintenance activities affecting the availability of associated redundant equipment:

C 1B and 2B Essential Service Water System Trains.

This safety related system was selected because it was designed to mitigate the consequences of a potential accident and was identified as risk significant in the licensees risk analysis. The inspectors performed a walkdown of the accessible portions of the system and verified that the system lineup was in accordance with plant operating procedures and applicable system drawings. The inspectors also assessed the material condition of system equipment and verified that identified discrepancies were properly captured in the licensees corrective maintenance 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.

1R05 Fire Protection (71111.05)

a.

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

C Unit 1, Division 12 Miscellaneous Electrical Equipment and Battery Room (Zone 2.3.5.7);

Unit 2, Division 22 Miscellaneous Electrical Equipment and Battery Room (Zone 2.3.5.8);

• Unit 2, Turbine Building Grade Level (Zone 2.3.8.5); and

Unit 1 Containment Building.

These areas were selected for inspection because risk significant systems, structures and components were located in the areas. The inspectors reviewed applicable portions of the Byron Station Fire Protection Report and assessed the licensees control of transient combustibles and ignition sources, material condition, and operational status of fire barriers and fire protection equipment. 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.

1R08 Inservice Inspection Activities (71111.08)

a.

Inspection Scope The inspectors evaluated the implementation of the licensees inservice inspection (ISI)

program for monitoring degradation of the reactor coolant system boundary and the risk significant piping system boundaries. Specifically, the inspectors verified through observations that the in-process ultrasonic inspection of the 1A steam generator tubesheet to lower barrel weld (1RC-01-BA) was conducted in accordance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements. The inspectors also reviewed radiographic film of welds 1MS020AA-FW#1, FW#2, and FW#3, inservice inspection procedures and personnel certifications.

The inspectors reviewed the NIS-2 forms for Code repairs performed during the last Unit 2 outage and confirmed that ASME Code requirements were met. In addition, a sample of inservice inspection related problems documented in the licensees corrective action program, was also reviewed to assess conformance with 10 CFR Part 50 Appendix B, Criterion XVI, Corrective Action, requirements. In addition, the inspectors determined that operating experience was correctly assessed for applicability by the ISI group.

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 system:

C Unit 1 and 2 Leak Detection of Systems within Containment (Function RF-1).

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. The inspectors interviewed several members of the licensees engineering staff regarding the performance of the containment sump flow monitors associated with this maintenance rule function. 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 maintenance rule related issues documented in selected condition reports.

b.

Findings No findings of significance were identified.

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

a.

Inspection Scope The inspectors reviewed the licensees evaluation of plant risk for maintenance activities on the following equipment:

C 1B Essential Service Water Pump Discharge Valve Out-of-Service and Removal/Replacement; and C

2A Emergency Diesel Generator, Emergent Replacement of the Oil for Generator Bearing.

The inspectors selected these maintenance activities because they involved systems that were risk significant in the licensees risk analysis, or were considered significant as potential initiating events. During this inspection, the inspectors assessed the operability of redundant train equipment and verified that the licensees planning of the maintenance activities minimized the length of time that the plant was subject to increased risk. The inspectors interviewed operations, engineering, maintenance, and work control department personnel. For the essential service water maintenance, the inspectors also verified that the equipment determined to be protected equipment was properly posted and that the appropriate risk-related information was provided to plant staff during shift briefings and turnovers.

In addition, the inspectors reviewed the events associated with the September 27, 2001, maintenance activity that resulted in a leak on the common suction header for the safety injection (SI) pumps. Repair of the leak necessitated isolation of the common suction header, rendering both SI pumps inoperable, placing the plant in Technical Specification 3.0.3, and initiation of a plant shutdown. This event was evaluated under review of Licensee Event Report (LER) 50-454-2001-003-00: Entry into Technical Specification Limiting Condition for Operation 3.0.3 Due to a Leak on a Safety Injection Valve Weld

Caused by a Pre-existing Condition and Failing to Use Correct Work Scope Revision Process.

The documents listed at the end of this report were also used by the inspectors to evaluate this area.

b.

Findings

A finding of very low safety significance (Green) was self-revealed. Specifically, the licensee failed to perform a maintenance risk assessment prior to performing a maintenance activity on the common suction header for the Unit 1 SI pumps. The inspectors determined that this failure was a Non-Cited Violation of 10 CFR 50.65 (a)(4).

On September 27, 2001, the licensee initiated a design change to the Unit 1 SI pump common suction header to facilitate venting operation. In conjunction with this design change, the licensee also performed an additional maintenance activity to enhance the soc-o-let weld on the common header vent valve. While enhancing the soc-o-let weld on the common header vent valve, the existing weld began to leak. Upon identification of the leak, the licensee declared both trains of SI inoperable and commenced a plant shutdown in accordance with Technical Specification 3.0.3. The licensee removed both SI pumps from service, drained and repaired the applicable portion of the piping, and successfully tested the weld. The unit was at approximately 25% power when Technical Specification 3.0.3 was exited, and the operators returned the plant to full power.

The cause of the event as described in the LER was as a result of not using the formal process to evaluate the weld enhancement. In addition, the license determined that a risk assessment for the on-line maintenance was not completed as required by the stations Conduct of Maintenance Manual.

The inspectors determined that this issue had a credible impact on safety, specifically, on the operablity of the SI system. However, subsequent reviews by the licensee determined that the leak would not have prevented the SI pumps from performing the designed safety function. The inspectors evaluated this issue through the significance determination process (SDP) and determined that this issue was of very low safety significance (Green), because the failure did not result in the actual loss of the safety system function.

10 CFR 50.65 (a)(4), states, in part, that the licensee shall assess and manage the increase in risk that may result from proposed maintenance activities. Contrary to the above, the licensee failed to perform a maintenance risk assessment prior to performing a maintenance activity, specifically, enhancing a weld on a drain valve in the common suction header for the Unit 1 SI pumps. However, because of the very low safety significance of the item and because the licensee had included this item in the corrective action program (Condition Report B2001-76849) this violation is being treated as a Non-Cited Violation (50-454-02-03-01(DRP)).

1R14 Personnel Performance During Non-routine Plant Evolutions (71111.14)

a.

Inspection Scope The inspectors observed activities throughout the Unit 1 shutdown for refueling outage B1R11. In particular, the inspectors monitored status briefings, procedure usage, communications, and command and control. This non-routine plant evolution was selected for observation to evaluate the performance of the operators and qualified nuclear engineers. The documents listed at the end of this report were also used by the inspectors to evaluate this area.

b.

Findings During the plant shutdown on March 11, 2002, the licensee experienced difficulties with the startup feedwater pump, such that it was not available for use at the point specified in the Byron General Operating Procedure 100-4, Power Descension, Revision 24. Therefore, the operators used the motor driven feedwater pump to complete the shutdown. Although the use of the motor driven feedwater pump in leu of the startup feedwater pump was described in the power descension procedure, the licensee decided to make an exception to the procedure and trip the turbine generator at 180 Megawatts electric (MWe) instead of the specified 100 MWe. Upon tripping the turbine generator, the steam dump valves did not open as expected. As a result, the steam generator (SG) pressure increased and the SG atmospheric relief valves lifted to provided the necessary plant cooldown.

Subsequent review of the shutdown by the licensee determined that the operators failed to place the steam dumps in the pressure control mode prior to tripping the turbine generator as specified by the power descension procedure. It appears that during the operators evaluation for the procedure exception to trip the turbine generator at a higher power, they failed to adequately consider the impact on the steam dump valves. The use of exceptions to the general plant operating procedures was allowed by the Byron Administrative Procedure 1310-10, Procedure Use and Adherence, Byron Addendum, Revision 6, and it only required that exceptions were properly noted. The decision to trip the turbine at a higher power was noted as a procedure exception for the power descension procedure during the March 11, 2002-shutdown, however, the exception did not explicitly describe the actions associated with the steam dump valve control mode.

The licensee initiated Condition Report (CR) 00098784, to review the circumstances regarding this issue. Pending the completion of the licensee review of this issue, including the associated apparent cause analysis, and subsequent inspector review, this issue will be tracked as an Unresolved Item (50-454-02-003-02).

1R15 Operability Evaluations (71111.15)

a.

Inspection Scope

The inspectors reviewed the licensees justification for not correcting existing degraded and nonconforming conditions during refueling outage B1R11 to ensure consistency with the timeliness guidance contained in Generic Letter 91-18, Information to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions, Revision 1. 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.

1R16 Operator Workarounds (OWAs) (71111.16)

a.

Inspection Scope

The inspectors reviewed OWAs to identify any potential effect on the function of mitigating systems or the ability of operators to respond to an event and implement abnormal and emergency operating procedures. The inspectors interviewed selected engineering licensee personnel and evaluated the following OWA:

OWA 258, Boric Acid Controller Overshoot.

This OWA discussed the boric acid controller that was not getting consistent results from the existing counters. The operators workaround was to use batch additions rather than using the controller for boration control. The inspectors reviewed the licensee's proposed design change to replace existing counters with digital Predetermining Counters for the Boric Acid Batch and Make-up Water functions. 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.

1R17 Permanent Plant Modifications (71111.17)

a.

Inspection Scope The inspectors reviewed the permanent modification listed below:

EC 332356, "Letdown Booster Pump Installation Mod," Revision 0; and

Pressurizer Spray Line Low Temperature Alarm Set Point Change from 530 to 525 degrees Fahrenheit (oF) Due to Power Uprate Implementation Change to Tcold and to Support Operation of the Pressurizer Variable Heaters per OP Assessment 99-023.

The inspectors reviewed the Letdown Booster Pump Installation modification installed online during February, 2002 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 also verified that the modifications did not place the plant in an unsafe configuration. The inspectors considered the design adequacy of the

modifications by performing a review, or partial 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 evaluated the licensees post maintenance testing activities for maintenance conducted on the following equipment:

C Unit 1 Charge System Booster Pump; and

Unit 1 Safety Injection Relief Valve.

The inspectors reviewed the scope of the work performed and evaluated the adequacy of the specified post maintenance testing. The inspectors verified that the post maintenance testing was performed in accordance with approved procedures, the procedures stated acceptance criteria, and the acceptance criteria were met. The inspectors also evaluated the adequacy of work controls (including foreign material exclusion controls), reviewed post-maintenance test data, and conducted walkdowns to verify system restoration after the testing was completed. The documents listed at the end of this report were also used by the inspectors to evaluate this area.

In addition, the inspectors 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.

b.

Findings No findings of significance were identified.

1R20 Refueling and Outage Activities (71111.20)

Inspection Scope The inspectors evaluated the licensees conduct of B1R11 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 Technical Specifications (TS) and

approved procedures. Other major outage activities evaluated included the licensee's control of:

containment penetrations in accordance with the TS;

systems, structures, and components (SSCs) which could cause unexpected reactivity changes;

flow paths, configurations, and alternate means for reactor coolant system (RCS)

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

SSCs required for decay heat removal.

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 activities to verify that requirements of the TS and administrative procedure requirements were met prior to changing operational modes or plant configurations. Major restart 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.

b.

Findings The inspectors identified a finding of very low safety significance (Green). In particular, the installation of the 1B steam generator hot and cold leg manway covers was not completed in accordance with applicable maintenance procedures. The failure to

properly install the steam generator manway covers adversely affected the reactor coolant system integrity. The inspectors determined that this failure was a Non-Cited Violation of Technical Specification 5.4.1.

On March 26, 2002, during the inspectors' independent inspection of the Unit 1 containment, the inspectors identified a leak on the 1B steam generator (SG). This inspection was performed after the licensee completed their containment inspection in preparation for entering Mode 4 (Hot Shutdown). At this time, the reactor coolant pressure and temperature were at 350 psig and < 200oF respectively. Upon being informed of the leak, the licensee determined that the primary (reactor coolant) side hot leg manway cover was leaking at a rate of approximately one drop per second. During the subsequent extent of condition review, the licensee discovered that a small leak also existed on the cold leg manway of the same SG.

As a result of these leaks, the licensee cooled down and depressurized the plant to complete the repairs to the 1B SG manway covers. In addition, the licensee initiated reviews to determine the cause of the leaks and to determine if the other steam generators were impacted. The licensee inspected the other SGs and found no additional leaks. In addition, based on a review of the work performed on the SGs during the outage, the licensee determined that the crew that worked on the 1B SG did not work on any other SG. Based on these facts, the licensee preliminarily concluded that the other SGs were not affected.

The inspectors reviewed the licensees procedures completed for the installation of the 1B SG hot and cold leg manway covers and discussed the issue with various members of the licensees staff. The inspectors also reviewed the licensees root cause determination effort, which included a demonstration of a SG manway cover installation completed on a mocked-up SG. Based on these reviews the inspectors concluded that the licensee failed to adequate implement Procedure BMP-3300-21, Unit 1 Steam Generator Primary Manway Closure Removal; and Installation.

Two steps on the manway installation procedure were not properly completed while the installing the 1B SG manway covers. Step 4.14.14 item 10 specified that the threads of the studs, bell nuts and under the bell nuts be lubricated with a light coat of lubricant.

Based on the as-found condition of the bell nuts, there was no indication of lubricant at the bottom of the bell nuts. Without the proper lubrication, the bell nuts would prematurely appear to be tightened to the proper torque value. Step 4.14.27 for the measuring of the as-left stud elongation was to be completed after the tensioning device was depressurized. Based on an analysis and subsequent measurements, the licensee determined that these as-left elongation measurements were taken with the tensioning device still pressurized. Furthermore, all but one of the as-left recorded measurements obtained during the manway installation for both the hot and cold leg manways were outside the target values. Although these values were evaluated as acceptable, this evaluation was based on a past method for measuring elongation that tended to be less accurate.

The inspectors determined that the failure to properly lubricate the bell nuts and to properly measure manway stud elongation for the 1B SG as prescribed in the station procedure adversely affected the reactor coolant system integrity. The inspectors

evaluated this issue through the shutdown SDP and determined this issue was of very low safety significance (Green), because the incorrectly installed steam generator manway covers did not result in a significant loss of reactor coolant inventory.

Technical Specification 5.4.1, states, in part, that Written procedures shall be established, implemented, and maintained covering the following activities: The applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Paragraph 9.a. of this Regulatory Guide states, in part, that procedures for performing maintenance that can affect the performance of safety-related equipment shall be prepared and activities shall be performed in accordance with these procedures. The licensee established Procedure BMP-3300-21, Unit 1 Steam Generator Primary Manway Closure Removal; and Installation, Revision 4 as the implementing procedure for installing the SG manway covers. Contrary to the above, in March 2002, the technicians failed to adequately lubricate the bell nuts and failed to adequately measure the as-left stud elongation for the 1B Steam Generator hot and cold leg manway covers as required by steps 4.14.14 and 4.14.27 of Procedure BMP-3300-21. This is considered a violation of Technical Specification 5.4.1. However, because this violation was of very low risk significance, was non-repetitive, and was captured in the licensees corrective action program (CR 00100975), this violation is being treated as a Non-Cited Violation in accordance with Section V1.A.1 of the NRC Enforcement Policy (NCV 50-454-02-03-03 (DRP)).

1R22 Surveillance Testing (71111.22)

a.

Inspection Scope The inspectors observed and reviewed the performance of the following surveillance testing on risk-significant equipment:

C 1BOSR FW-SA1, Unit One Anticipated Transient Without SCRAM Mitigation System at Power Semiannual Surveillance Revision 3;

1BOSR 3.2.9.2, Unit 1 Train B Manual Safety Injection and Manual Phase A Initiation Surveillance, Revision 9 ;

1BOSR 8.1.9.2, "1B Diesel Generator Safe Shutdown Sequencer and Single Load Rejection Test," Revision 0;

1BOSR 6.3.6-1, "Unit One Primary Containment Type C Local Leakage Rate Tests of Containment Miniflow Purge Isolation Valves," Revision 4; and

1BOSR Z.5.b.1-1, Unit 1 Containment Loose Debris Inspection, Revision 2.

The inspectors selected these surveillance test activities because the system functions were identified as risk significant in the licensees risk assessment and the components were credited as operable in the licensees safety analysis to mitigate the consequences of a potential accident. Regarding the Unit 1 containment inspection, following the completion of the licensees inspection, the inspectors performed an independent visual inspection of the Unit 1 containment. The inspectors interviewed operations, maintenance, and engineering department personnel; reviewed the completed test documentation; and observed the performance of all or portions of these surveillance testing activities. The documents listed at the end of this report were also used by the inspectors to evaluate this area.

b.

Findings Except for the finding associated with the leaking 1B steam generator manway cover described in Section 1R20, no findings of significance were identified.

1R23 Temporary Plant Modifications (71111.23)

a.

Inspection Scope The inspectors reviewed the temporary modifications listed below to verify that the installation was consistent with design modification documents and that the modification did not adversely impact system operability or availability:

Operation of the Reactor Containment Fan Coolers without Containment Chillers; and

EC 335829, Installation of Temporary Pipe Supports for Main Steam Line 1MS01CC-32 3/4, Revision 0.

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.

2.

RADIATION SAFETY Cornerstone: Occupational Radiation Safety 2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Plant Walkdowns, Radiological Boundary Verification, and Radiation Work Permit (RWP)

Reviews a.

Inspection Scope The regional radiation protection inspector reviewed the stations implementation of physical and administrative controls over access to radiologically controlled areas (RCAs), including worker adherence to these controls, by reviewing station procedures, RWPs, electronic dosimetry alarm set points, and walking down radiologically significant areas (high radiation areas (HRAs), locked HRAs, and radiation areas) of the station.

Specifically, areas in the Unit 1 Containment, the Unit 1 Containment Access Facility, and the Auxiliary Building were observed to verify these areas were posted and controlled in accordance with 10 CFR Part 20, licensee procedures, and Technical Specifications.

b.

Findings No findings of significance were identified.

.2 Identification and Resolution of Problems a.

Inspection Scope The regional radiation protection inspector reviewed Nuclear Oversight field observations and licensee Condition Reports completed in conjunction with the B1R11 Refueling Outage which focused on access control to radiologically significant areas, radiation worker practices, and radiation protection (RP) technician practices. The inspector reviewed these documents to assess the licensees ability to identify repetitive problems, contributing causes, the extent of conditions, and implement corrective actions intended to 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/ALARA Planning a.

Inspection Scope The regional radiation protection inspector reviewed the stations procedures for radiological work/ALARA planning and scheduling, and evaluated the dose projection methodologies and practices implemented for the B1R11 Refueling Outage, to verify that sound technical bases for outage dose estimates existed. Specifically, the inspector reviewed six radiologically significant RWP/ALARA planning packages to verify that adequate person-hour estimates, job history files, lessons learned, and industry experiences were utilized in the ALARA planning process. As part of the reviews of the planning packages, the inspector reviewed Total Effective Dose Equivalent (TEDE)

ALARA evaluations developed for RWP Nos. 10000560, 10000562, and 10000563, to assess the licensees analysis for the potential use of respiratory protection equipment during those evolutions. The inspector also attended the mid-outage Station ALARA Committee Meeting and reviewed RP/Operations-coordinated dose rate reduction activities (e.g., pipe flushing, shield packages, timing of forced oxidation) to further assess inter-departmental coordination and ownership in the radiological work/ALARA planning and scheduling processes.

b.

Findings No findings of significance were identified.

.2 Job Site Inspections and ALARA Controls a.

Inspection Scope The regional radiation protection inspector observed work activities in the RCA that were performed in radiation areas, HRAs, and locked HRAs to evaluate the use of ALARA controls. Specifically, the inspector reviewed radiological surveys, attended pre-job

radiological briefings, and assessed job site ALARA controls, in part, for the following work activities:

Steam generator manway diaphragm removal (RWP No. 10000560);

Steam generator nozzle covers installation (RWP No. 10000562);

Steam generator eddy current testing (RWP No. 10000563);

Steam generator secondary-side sludge lancing (RWP No. 10000564);

Miscellaneous air operated valve work (RWP No. 10000573); and

Reactor head disassembly, including head lift (RWP No. 10000576).

Worker instruction requirements including protective clothing, engineering controls to minimize dose exposures, the use of predetermined low dose waiting areas, as well as the on-the-job supervision by the work crew leaders and RP technicians were observed to determine if the licensee had maintained the radiological exposure for these work activities ALARA. Enhanced job controls including RP technician use of electronic teledosimetry and remotely monitored cameras were also evaluated to assess the licensees ability to maintain real time doses ALARA in the field. Additionally, the inspector observed the implementation of dosimetry placement changes necessitated by significant dose rate gradients during steam generator nozzle cover installation jumps (per the requirements of RWP No. 10000562).

b.

Findings No findings of significance were identified.

.3 Radiation Worker Performance a.

Inspection Scope The regional radiation protection inspector observed radiation workers performing the activities described in Section 2OS2.2 and evaluated their awareness of radiological conditions, personal electronic dosimetry alarm set points, and their implementation of applicable radiological controls.

b.

Findings No findings of significance were identified.

.4 Verification of Dose Estimates, Dose Trending, and Dose Tracking Systems a.

Inspection Scope The regional radiation protection inspector reviewed the licensees total outage dose estimates, selected individual job dose estimates and the related dose trending for the B1R11 Refueling Outage. As of March 20, 2002, (day 9 of an estimated 14 day outage),

the licensee had recorded a collective dose of 62.634 person-rem compared to the total estimate of 116.149 person-rem for the outage. Work-in-Progress reviews for RWP Nos. 10000558, 10000560, and 10000573 were examined to evaluate the licensees ability to assess the effectiveness of the ALARA plans in a timely manner and institute

changes in the plan or its execution, if warranted. The licensees dose tracking system was also reviewed to determine if the level of dose tracking detail, dose report timeliness, and report distribution were sufficient to support the control of collective dose. Additionally, the inspector reviewed dose tracking records for all workers on selected steam generator-related RWPs, to assess the licensees effectiveness in maintaining individual exposures ALARA and minimizing significant dose variations across the workgroups.

b.

Findings No findings of significance were identified.

.5 Source Term Reduction and Control a.

Inspection Scope The regional radiation protection inspector reviewed the status of the stations source term reduction program focusing on those initiatives with the greatest potential to impact outage doses (i.e., hot spot tracking, pipe flushing, temporary and permanent shielding, and shutdown chemistry controls). The inspector also assessed the general trend of the stations total source term by reviewing historical and current containment baseline dose rates to evaluate the effectiveness of the stations source term reduction plan.

b.

Findings No findings of significance were identified.

.6 Identification and Resolution of Problems a.

Inspection Scope The regional radiation protection inspector reviewed Nuclear Oversight field observations and licensee CRs completed in conjunction with the B1R11 Refueling Outage which focused on ALARA planning and controls. The inspector additionally reviewed a focus area self-assessment for the ALARA program and [B1R11] outage readiness conducted by the RP Department. The inspector reviewed these documents to assess the licensees ability to identify repetitive problems, contributing causes, the extent of conditions, and develop corrective actions intended to achieve lasting results.

b.

Findings No findings of significance were identified.

4OA3 Event Followup

.1 (Closed) Licensee Event Report (LER) 50-454-2001-003-00: Entry into Technical Specification Limiting Condition for Operation 3.0.3 Due to a Leak on a Safety Injection Valve Weld Caused by a Pre-existing Condition and Failing to Use Correct Work Scope

Revision Process This event is discussed in Section 1R13 of this report. This LER is closed.

.2 (Closed) Licensee Event Report (LER) 50-454-2001-003-01: Entry into Technical Specification Limiting Condition for Operation 3.0.3 Due to a Leak on a Safety Injection Valve Weld Caused by a Pre-existing Condition and Failing to Use Correct Work Scope Revision Process, Supplement 1. The licensee submitted Supplement 1 to LER 50-454-2001-003 to provide additional corrective actions for the event. The inspectors determined that the information provided in Supplement 1 to LER 50-454-2001-003 did not raise any new issues or change the conclusions of the initial review which is documented in Section 1R13 of this report. This LER is closed.

40A5 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 NRC 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 NRC 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. The anticipated low likelihood of primary water stress corrosion cracking (PWSCC) degradation at the Bin 4 facilities indicates that enhanced examination beyond the present requirements is not currently necessary because enhanced examination is not likely to yield additional evidence of the propensity for PWSCC in vessel head penetration nozzles.

b.

Findings No findings of significance were identified.

4OA6 Meetings

.1 Interim Exits a.

The results of the occupational radiation safety access control and ALARA inspection were presented to Mr. Rich Lopriore and other members of licensee management at the conclusion of the inspection on March 20, 2002. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identified.

b.

The results of the Inservice Inspection was presented to Mr. Rich Lopriore and other members of licensee management at the conclusion of the inspection on March 22,

2002. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Resident Inspector Exit Meeting The inspectors presented the inspection results to Mr. S. Kuczynski and other members of licensee management at the conclusion of the inspection on April 3, 2002. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identified.

KEY POINTS OF CONTACT Licensee R. Lopriore, Site Vice President S. Kuczynski, Station Manager B. Adams, Engineering B. Altman, Maintenance Manager D. Goldsmith, Radiation Protection Director D. Combs, Site Security Manager G. Contrady, Engineering Programs Supervisor D. Drawbaugh, Byron NRC Coordinator D. Goldsmith, Radiation Protection Manager B. Grundmann, Regulatory Assurance Manager K. Hansing, Site Nuclear Oversight Manager D. Hoots, Operations Manager S. Kerr, Chemistry Manager W. Kolo, Work Management Director T. Roberts, Engineering Director B. Sambito, Byron Radiation Protection D. Spoerry, Training Manager S. Stimac, Shift Operations Superintendent D. Thompson, Radiation Protection Dose Assessment Health Physicist Nuclear Regulatory Commission A. Stone, Chief, Projects Branch 3, Division of Reactor Projects M. Parker, Senior Reactor Analyst

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-454-02-03-01 NCV Failure to Assess and Manage the Risk associated with the Safety Injection Common Header Welding Activity 50-454-02-03-02 URI Procedure Review to Trip the Turbine Generator at a Higher Power than Prescribed by the Procedure 50-454-02-03-03 NCV Failure to Follow the Procedure for the Installation of the 1B Steam Generator Manway Cover Closed 50-454-02-03-01 NCV Failure to Assess and Manage the Risk associated with the Safety Injection Common Header Welding Activity 50-454-02-03-03 NCV Failure to Follow the Procedure for the Installation of the 1B Steam Generator Manway Cover 50-454-2001-003- 00 LER Entry into Technical Specification Limiting Condition for Operation 3.0.3 Due to a Leak on a Safety Injection Valve Weld Caused by a Pre-existing Condition and Failing to Use Correct Work Scope Revision Process 50-454-2001-003- 01 LER Entry into Technical Specification Limiting Condition for Operation 3.0.3 Due to a Leak on a Safety Injection Valve Weld Caused by a Pre-existing Condition and Failing to Use Correct Work Scope Revision Process, Supplement 1 Discussed None

LIST OF ACRONYMS USED ALARA As-Low-As-Reasonably-Achievable ASME American Society of Mechanical Engineers B1R11 Unit 1's Eleventh Refueling Outage BAP Byron Administrative Procedure BGP Byron General Operating Procedure BISR Byron Instrument Maintenance Surveillance Requirement Procedure BOA Byron Abnormal Operating Procedure BOL Byron Limiting Condition for Operation Action Requirement Procedure BOP Byron Operating Procedure BOSR Byron Operating Surveillance Requirement Procedure BVSR Byron Technical Surveillance Requirement Procedure CFR Code of Federal Regulations CR Condition Report CV Control Room Ventilation DRP Division of Reactor Projects ECCS Emergency Core Cooling System GL Generic Letter HRA High Radiation Area ISI Inservice Inspection LCOAR Limiting Condition for Operation Action Requirement LER Licensee Event Report MWe Megawatts Electric NCV Non-Cited Violation NEI Nuclear Energy Institute NRC Nuclear Regulatory Commission NSP Nuclear Station Procedure OD Operability Determination ODCM Offsite Dose Calculation Manual OWA Operator Work-Around PWSCC Primary Water Stress Corrosion Cracking RCA Radiologically Controlled Area RCS Reactor Coolant System RP Radiation Protection RWP Radiation Work Permit SDP Significance Determination Process SG Steam Generator SI Safety Injection SSC Systems, Structures, and Components TEDE Total Effective Dose Equivalent TS Technical Specification UFSAR Updated Final Safety Analysis Report URI Unresolved Item VC Control Room Heating, Ventilation and Air Conditioning System WO Work Order WR Work Request

LIST OF DOCUMENTS REVIEWED 1R04 Equipment Alignment Byron Station Technical Specifications (TS)

Byron/Braidwood Stations Update Final Safety Analysis report (UFSAR)

BOP SX-E1B Unit 1 Essential Service Water Train B Electrical Lineup Revision 2 BOP SX-E2B Unit 2 Essential Service Water Train B Electrical Lineup Revision 1 BOP SX-M1B Unit 1 Essential Service Water Train B Valve Lineup Revision 6 BOP SX-M2B Unit 2 Essential Service Water Train B Valve Lineup Revision 6 Drawing M-42 Diagram of Essential Service Water - Unit 1 Drawing M-126 Diagram of Essential Service Water - Unit 2 1R05 Fire Protection Byron/Braidwood Stations Fire Protection Report Revision 19 Byron Station Pre-Fire Plans and Drawings BAP 1100-17T1 Byron Station Pre-Fire Plan Revision 0 BAP 1100-7 Fire Prevention for Transient Combustibles Revision 10 BAP 1100-7A1 Minor Transient Combustibles Revision 1 Byron/Braidwood Stations Fire Hazards Analysis, Sections2.3.3.17, 2.3.5.3 and 2.3.5.4 Amendment 18, December 1998 National Fire Protection Association Code, Chapter 72E, Automatic Fire Detectors, Section 4-3 1984

Byron/Braidwood Units 1 and 2 Fire Protection Program Documentation Package, Part 4, Book 1, Sargent &

Lundy/Consultant-Generated Documents and Correspondence, Evaluation of Fire Detection Systems.

Byron Drawing M-58, Sheet 5 Diagram of Fire Protection Portable Fire Extinguisher Location 1R08 Inservice Inspection EXE-PDI-UT-1 Ultrasonic Examination of Erritic Pipe Welds in Accordance with PDI-UT-1 March 11, 2002 EXE-ISI-11 Liquid Penetrant Examination March 4, 2002 EXE-ISI-170 Magnetic Particle Examination February 6, 2002 NDT-E-2 Multifrequency Eddy Current Data Acquisition of Steam Generator Tubing at Braidwood and Byron Nuclear Stations June 22, 2000 Byron Unit 1 B1R11, Steam Generator Eddy Current Inspection, Inspection Results March 2002 ER-AP-335-040 Evaluation of Eddy Current Data for Steam Generator Tubing July 3, 2001 ER-MW-335-1002 Steam Generator Eddy Current Data Analysis Guidelines for Braidwood and Byron Stations Unit 1 February 5, 2002 AR 00080066 Work Packages Documentation Errors (Welding)

October 19, 2001 AR 00080481 Uncontrolled Welding Filler Metal October 19, 2001 CR B2000-03233 Review of Contractor Visual Inspection Certifications October 17, 2000 Byron Letter:

2001-5029 Byron Station Unit 2 90-Day Inservice Inspection Report for Interval 2, Period 1, Outage 2 (B2R09)

July 19, 2001 NDT-A Radiographic Examination August 1, 1999

1R12 Maintenance Rule Implementation Technical Requirements Manual Maintenance Rule-Performance Criteria Leak Detection of Systems Inside Containment Criteria: RF1 CR 00092599 2RF008 Containment Floor Drains Flow High Annunciated January 28, 2002 CR 00096513 Elevated Run Times for U2 Containment Floor Drains Sump Pump February 24, 2002 CR 00097770 Problems With Reactor Coolant System Leakage Detection Systems March 4, 2002 WC-AA-110 Complex Troubleshooting March 18, 2002 CR 82449 Containment Floor Drain Sump (1RF008)

Flow Rate Increasing December 10, 2002 1R13 Maintenance Risk Assessments and Emergent Work Evaluation Byron Technical Specifications BAP 370-1 Station Lubrication Program Revision 07 BAP 370-2 Station Sampling Program Revision 06 1BOA PRI-7 Essential Service Water Malfunction Unit 1 Revision 7 Risk Assessment Week of March 04, 2002, Revision 1 MA-MW-716-230-1001 Used Oil Data Interpretation Guidelines Revision 0 WR 00037709 Diesel Generator Outboard Bearing Oil Sample Low Viscosity February 21, 2002 CR 00096192 2A Diesel Generator Bearing Oil Sample Low Viscosity February 21, 2002 Byron Station Shutdown Risk Manual B1R11 Drawing M-61 Sheet 1A Diagram of Safety Injection System Rev. AN WR# 97124197-01 Document #2, Isometric Drawing 1SI081 Rev. 0

CR- 00076849 Unplanned Limiting Condition for Operation Action Requirements (LCOAR) 1BOL 3.0.3 due to Both Trains of U-1 Safety Injection OOS for Repair of Weld Leak on 1SI081 Vent Valve September 27, 2001 LER 50-454-2001-003-00 Entry into Technical Specification Limiting Condition for Operation 3.0.3 Due to a Leak on a Safety Injection Valve Weld Caused by a Pre-existing Condition and Failing to Use Correct Work Scope Revision Process November 26, 2001 LER 50-454-2001-003- 01 Entry into Technical Specification Limiting Condition for Operation 3.0.3 Due to a Leak on a Safety Injection Valve Weld Caused by a Pre-existing Condition and Failing to Use Correct Work Scope Revision Process, Supplement 1 January 28, 2002 Prompt Investigation Report:

Unplanned LCOAR 1BOL 3.0.3 Due to Both Trains of U-1 Safety Injection Out-of-Service for Repair of Weld Leak on 1SI081 Vent Valve September 28, 2001 Root Cause Investigation Report Byron Unit 1 Entry into Technical Specification 3.0.3 due to Both Trains of SI Inoperable Caused by a Leak on 1SI081 Vent Valve Piping November 5, 2001 1R14 Personnel Performance During Non-routine Plant Evolutions Byron Station Technical Specifications Byron Braidwood Stations UFSAR Unit 2 Risk Configurations September 24-September 30, 2001 Shift Managers Logs March 11 & 12, 2002 0BOL PR1 Steam Generator Tube Leak Monitoring Equipment Revision 3 OP-AA-101-102 Roles and Responsibilities of On-Shift Personnel Revision 3 BAP 1310-10 Procedure Use and Adherence, Byron Addendum Revision 6 1BGP 100-2 Plant Startup Revision 27

1BGP 100-3 Power Ascension Revision 35 1BGP 100-4 Power Descension Revision 24 1BGP 100-5 Plant Shutdown and Cooldown Revision 35 BMP 3118-3 Reactor Vessel Upper Internals Removal Revision 14 BMP 3118-1 Reactor Vessel Closure Head Removal Revision 18 BOP FW-7 Startup of a Motor Driven Feedwater Pump Revision 13 CR 00098597 Procedure BOP RH-6 Does Not Meet Expectations March 6, 2002 CR 00098775 Unit 1 Steam Dump Operation Inappropriate Response March 12, 2002 CR 00098784 B1R11 Shutdown Events and Unexpected Occurrences March 12, 2002 Regulatory Guide 1.33 Quality Assurance Program Requirements February 1978 1R15 Operability Evaluations Byron Station TS Byron/Braidwood Stations UFSAR Byron Station Technical Requirement Manual NSP CC-3001 Operability Determination Process Revision 0 NSP LS-AA-105-1000 Operability Determination Guidance Manual Revision 0 NRC Generic Letter 91-18 Information to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions Revision 1 NRC Inspection Manual, Part 9900 Operable/Operability: Ensuring the Functional Capability of a System or Component October 8, 1997 LER 50-454-1997-017-01 Completion of Shutdown Initiated Due to Degraded Condition of Safety Injection System Found During Monthly Venting Surveillance November 7, 1997

Root Cause Report 454-230-97-CAQS00058 Trend 97-058, Maintenance Rule Reactor Coolant System (RC1 Function) Additional Scope (a)(1)

December 8, 1997 CR B2000-02391 Safety Injection Pump Discharge Pressure Increases After Accumulator Fill October 31, 2000 Problem Identification Form B1997-03509 Emergency Notification System Notification Due to Gas Found in Safety Injection System During Monthly Vent Surveillance November 9, 1997 1R16 Operator Work-Arounds OWA 258 Boric Acid Controller Overshoot DCP 331826 Replacement of Pre-determining Counters 2FY-0110B and 2FY-0111B Revision 0 B2001-02424 Unit 2 Primary Water Flow Controller Output Insufficient in Alternate Dilute Mode May 23, 2001 B2001-02461 Low Boration Flow Control Problem Continues to Produce Repeat Work Requests & Engineering Requests May 25, 2001 B2001-03081 Replacement Unit 2 Boric Acid flow Totalizer Failure July 13, 2001 IR 17 Permanent Plant Modifications Byron Technical Specifications Byron Final Safety Analysis Report, Applicable Portions Westinghouse Letter SEE-01-300 Byron/Braidwood Pressurizer Spray Line Low Temperature Alarm for Power Uprate Project 50.50 Screening Form Implementation of the Pressurizer Spray Line Low Temperature Alarm for Power Uprate Project 50.59 Review Cover Sheet Form Implementation of the Pressurizer Spray Line Low Temperature Alarm for Power Uprate Project

CC-AA-103 Design Change Approval Design Change Package No. EC 333674/SSC 01-061 Revision 0 EC 332356 Letdown Booster Pump Installation Mod Revision 0 CR B2001-02334 Corrective Actions; Restore Backup Heater Operation to Design Unit 1 and 2, Operability Determination 99-0233, Revision 2 1R19 Post Maintenance Testing Byron/Braidwood Stations UFSAR Byron Station TS Byron Station Technical Requirement Manual BIP 2000-TO HP Turb First Stage Press Transmitter Revision 1 CR 00095551 Spike Induced MW Swing of Unit 2 Resulting in 100.7% power February 17, 2002 WO 00409928 Investigate Spike on 2PT-MS002, Replace if Questionable February 21, 2002 BMP 3100-23 Inservice Testing Crosby Safety/Relief Valve Bench Testing Revision 13 SPP 01-029 Byron Unit One Charge System Booster Pump Operability Testing Revision 0 1R20 Refueling and Outage Activities Byron Station Technical Specifications Byron/Braidwood Stations UFSAR B1R11 Significant Issues List Shift Managers Logs March 16 & 17, 2002 Regulatory Guide 1.33 Quality Assurance Program Requirements February 1978 NRC Bulletin 2001-01 Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles August 3, 2001

RS-01-182 Exelon/AmerGen Response to NRC Bulletin 2001-01, Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles August 31, 2001 B1R11 Shutdown Safety Analysis for SSRB March 4, 2002 CP-1A Shutdown Safety analysis of Freeze for Replacement of 1AF017A CP-2A Shutdown Safety Analysis of Freeze for Replacement of 1AF017B CP-3A Shutdown Safety Analysis of Freeze for Replacement of 1CV8123 CP-4A Shutdown Safety Analysis of Freeze for Inspection of 1CV8378A/B CP-5A Shutdown Safety Analysis of Freeze for Replacement of 1SI8818D CP-6A Shutdown Safety Analysis Loss of DC Bus 111 from DC Bus 211 Crosstie CP-7A Shutdown Safety Analysis Loss of DC Bus 112 from 212 Crosstie CP-12A Shutdown Safety Analysis: Replacement of 1SX143B CP-13A Shutdown Safety Assessment for the Replacement of 1/2SX001A and 1A SX Pump Overhaul CP-14A Justification for Operating with a single Residual Heat Removal Train Available with the Upper Internals Installed following a Core Reload LS-AA-119 Overtime Controls Revision 0 LS-AA-125 Corrective Action Program Procedure Revision 2 CR 00099097 Unexplained Refuel Water Storage Tank Level Decrease Following Boron Dilution Protection System Actuation March 12, 2002 CR 00099463 Loose Terminal Screw in Main Control Board March 15, 2002 CR 00099519 Foreign Material Discovered in 1AF01PB-K After Removing PTO March 16, 2002

CR 00099532 Crack Found in 1A Main Condenser North Wall During Inspection March 14, 2002 CR 00099652 1 NRC questioned the use of Clear Skin Gloves in Foreign Material Exclusion Area Zone 1 March 17, 2002 CR 00099665 B1R11-Bus 143 Outage: Loss of Unit 2 Reactor Coolant Drain Tank Level Indication March 18, 2002 CR 00099670 Wasted Engineering Time and Resources During Bus 143 Outage March 18, 2002 CR 00099749 Internal Pipe Buildup in the Essential Service Water Inlet/Outlet to 1B Auxiliary Feedwater System March 13, 2002 CR 00099785 1RY8010B Exceeds 1% as found Lift Setpoint March 18, 2002 CR 00099832 1 Unplanned BOL-Entry 2PR28-Bus 143 Outage March 18, 2002 CR 00100059 Possibly Multiple Missed LCOAR Entries March 20, 2002 CR 00100065 Bus 143 Outage with Emergency Lighting Out-of-Service & No Temp Lighting March 19, 2002 CR 00100201 1 Operations Department Has Not Written Condition Reports as Expected March 20, 2002 CR 00100327 Summary of Bus 143 Outage Items during B1R11 March 21, 2002 CR 00100653 1CV8123 Seal Return Relief Valve Weeping March 23, 2002 CR 00100697 Some Main Steam Isolation Valve Solenoid Mounting Screws 1/8" Shorter than Design March 22, 2002 CR 00100795 Corrosion Identified on the Underside of the Reactor Vessel March 24, 2002 CR 00100975 1 1B Steam Gnerator Primary Manway Hotleg Leaking March 26, 2002 Generic Letter 88-17 Loss of Decay Heat Removal 10 CFR 50.54(f)

October 17, 1988 Generic Letter 88-17 Supplemental Information Commonwealth Edison provided status on the implementation of Generic Letter 88-17 July 8, 1991

List of Byron Station Corrective Maintenance Activities not Scheduled for B1R11 1BGP 100-1 Plant Heatup Revision 36 1BGP 100-1 Plant Heatup Revision 37 1BGP 100-4 T1 Power Dissension Flow Chart Revision 5 1BGP 100-5 Plant Shutdown and Cooldown Revision 35 1BGP 100-5 T1 Plant Shutdown and Cooldown Flow Chart Revision 16 1BGP 100-6 Refueling Outage Revision 26 1BGP-100-6 Refueling Outage Revision 27 BMP 3118-1 Reactor Vessel Closure Head Removal Revision 18 BMP 3118-3 Reactor Vessel Upper Internals Removal Revision 14 BMP 3118-5 Reactor Vessel Upper Internals Installation Revision 12 BMP 3118-7 Reactor Vessel Closure Head Installation Revision 18 BMP 3300-21 Unit 1 Steam Generator Primary Manway Closure Removal and Installation Revision 4 1BOP AP-104 Bus 143 Outage While in Mode 5, 6 or Defueled Revision 0 PORC 01-019 B1R11 Mode 4 Startup NSP (Process for Mode Change)

March 19, 2001 PORC 02-022 Reactor Vessel Staining Due to Reactor Cavity Boot Seal Leak March 25, 2002 PORC 02-022 B1R11 Material Condition Readiness Review March 25, 2002 OP-AA-101-102 Roles and Responsibilities of On-Shift Personnel Revision 3 OP-AA-108-108 Unit Restart Review Revision 0 ER-AA-330-001 Section XI Pressure Testing Revision 0 HU-AA-1211 Pre-Job, Heightened Level of Awareness, Infrequent Plant Activity and Post-Job Briefings Revision 0 Exelon Engineering Memo 1.02.1093 B1R11 Irradiated Fuel Inspection Summary Report March 29, 2002 GL 82-12 Nuclear Power Plant Staff Working Hours June 15, 1982

SY-AA-103-512 Continual Behavioral Observation Program Revision 3 SY-AA-102 Exelons Nuclear Fitness For Duty Program Revision 5 1R22 Surveillance Testing Byron Station Technical Specifications Byron/Braidwood Stations UFSAR Shift Managers Logs March 12 & 13, 2002 1BOSR FW-SA1 Unit 1 Anticipated Transient Without SCRAM Mitigation System at Power Semiannual Surveillance Revision 3 1BOSR Z.5.b.1-1 Unit 1 Containment Loose Debris Inspection Revision 2 WO 00355773 01 U-1 Anticipated Transient Without SCRAM Mitigation System at Power Semiannual Surveillance February 25, 2002 CR 00098912 Early Placement of Clear Order Delayed B1R11 SI Test March 13, 2002 CR 00098961 Problems Encountered with Performance of 1BOSR 3.2.9-2 March 13, 2002 CR 00100975 1 1B Steam Generator Primary Manway Hotleg Leaking March 26, 2002 1BOSR 3.2.9.2 Unit 1 Train B Manual Safety Injection and Manual Phase A Initiation Surveillance Revision 9 1BOSR 8.1.9.2 1B Diesel Generator Safe Shutdown Sequencer and Single Load Rejection Test Revision 0 AR 0995890995890B Control Room Heating, Ventilation and Air Conditioning System (VC) Chiller Unplanned LCOAR Entry March 18, 2002 AR 100051100051Missed Reading on 0B VC during Performance of 1BOSR 8.1.9.2 March 20, 2002 1BOSR 6.3.6-1 Unit One Primary Containment Type C Local Leakage Rate Tests of Containment Miniflow Purge Isolation Valves Revision 4

1BOSR 6.3.6-12 Primary Containment Type C Local Leakage Rate Tests and Inservice Inspection Tests of Component Cooling System Revision 4 1BOSR 8.1.17.2 1B Diesel Generator Sequencer Test - 18 Month Revision 0 1BOSR 8.1.11.2 1B Diesel Generator Safe Shutdown Sequencer Revision 0 1BOSR 3.2.9-2 Unit 1 Train B Manual Safety Injection Initiation and Manual Phase A Initiation Surveillance Revision 9 performed March 12 through 23, 2002 Clearance Order 0004617 Pen Elec E42 Channel 2 Nuclear Instrument 1-3353 RXB1+9 Outage Management and Services Predecessor View for Clearance Order 0004617 Regulatory Guide 1.33 Quality Assurance Program Requirements February 1978 NUREG 1020 Events Reporting Guidelines 10 CFR 50.72 and 73 Revision 2 OP-AA-101-201 Station Equipment Clearance and Tagging Revision 6 OP-AA-101-102 Roles and Responsibilities of On-Shift Personnel Revision 3 1R23 Temporary Plant Modifications Byron Station TS Byron/Braidwood Stations UFSAR CR 00096652 Inconsistencies in [containment] Chiller Operation Between Byron and Braidwood December 31, 2001 CR 00098118 U-1 Main Steam Supports Found Damaged in MS Tunnel March 06, 2002 CR 00100400 SD Sample Return per BOP SD-102 T-Mod Not Complete March 21, 2002 EC 335829 Installation of Temporary Pipe Supports for Main Steam Line 1MS01CC-32 3/4 Revision 0 BOP SD-102 Operation of the Steam Generator Blowdown Sample Return Subsystem Revision 2

Proposed Recommendation Operation of the Containment Ventilation System without Containment Chillers 2OS1 Access Control to Radiologically Significant Areas Facilitator Guide for Initial Radiation Worker Training: Protective Clothing Demo Revision 1 BRP 5000-7 Unescorted Access To and Conduct in Radiologically Posted Areas Revision 10 BRP 6020-3 Routine Plant Surveys Revision 17 CR 00098750 Radiation Protection Survey Weakness March 7, 2002 CR 00098901 Worker Dropped Digi and Lost Thermoluminescent Dosimeter March 15, 2002 CR 00099212 Rad Worker Not Furnished Dose Rate Instrument (Laundry Pickup)

March 14, 2002 CR 00099560 1 Radiation Protection Informational Posting Difficult to Read March 16, 2002 CR 00099598 1 Poor Radiation Worker Practices During B1R11 March 17, 2002 CR 00100149 1 MGPAC Does Not Lock Out Individuals on Dose Rate Alarm March 20, 2002 RWP 10000556 B1R11 - Tours and Insp - All RCAs (Aux, Cnmt IMB/OMB, Outside)

Revision 0 2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls Byron Station ALARA Unit 1 Containment Baseline Dose Rates March 16, 2002 Daily Station Dose by RWP Number Report (TE008) (for RWP Nos. 10000557 -

10000565) SR12 - Predecessor/Successor Analysis Report for RP Shielding and Flushing Activities March 18, 2002 ALARA Work in Progress Review RWP No. 10000558, Stage and Remove S/G Equipment in Aux. Building and U-1 Containment Including Decon Tent Activities March 16, 2002 ALARA Work in Progress Review RWP No. 10000560, Manway and Diaphragm Removal/Installation and Stud Hole Cleaning March 16, 2002

ALARA Work in Progress Review RWP No. 10000573, Misc. AOV Work March 18, 2002 BRP 5310-1 Hot Spot Tracking System Revision 8 CR 00076318 Source Term Reduction Program/Hot Spot Surveys Not Done September 25, 2001 CR 00097134 RP Focused Area Self-Assessment Outage Readiness and ALARA Issues February 8, 2002 CR00097258 Improvement for Radiation Protection Pre-Job Briefs February 26, 2002 CR 00098396 Laborer Dose Estimate 37 mr Over Initial Estimate for 3/7/02 March 7, 2002 CR 00098398 Aux Building Scaffold Exposure Estimate Exceeded, Venture March 4, 2002 CR 001000111 Weakness Identified in Source Term Reduction Program March 19, 2002 Focus Area Self-Assessment Report No. 2002-002 ALARA Program and Outage Readiness and Preparation February 7-8, 2002 HU-AA-1211 Pre-Job, Heightened Level of Awareness, Infrequent Plant Activity and Post-Job Briefs Revision 0 RWP/ALARA Plan No. 10000558 Stage and Remove Steam Generator Equipment in Aux. Building and Unit 1 Containment Including Decon Tent Activities Revision 1 RWP/ALARA Plan No. 10000560 Manway and Diaphragm Removal/Installation and Stud Hole Cleaning Revision 0 RWP/ALARA Plan No. 10000562 Install/Remove SG Nozzle Covers, Complete SG Bowl Closeout Revision 0 RWP/ALARA Plan No. 10000563 SG Eddy Current Testing, Tube Repairs, and Inspections Revision 2 RWP/ALARA Plan No. 10000564 Remove/Install Secondary Side Covers and Inspection Port Covers. Perform Sludge Lance Activities and Inspection(s). FOSAR (Foreign Object Search and Retrieval)

Revision 3 RWP/ALARA Plan No. 10000573 Miscellaneous Aor Operated Valve Work:

Including Operator and Process Diaphragm Work Revision 0

RWP/ALARA Plan No. 10000576 Reactor Head Disassembly/Re-assembly, Including Lift Prep, Cleaning Studs, Cono-Seal/RVLIS Removal and Installation Revision 0 Survey No. 01-3104 330' - 346' Els. Hot Spots January 25, 2001 Survey No. 01-3119 Hot Spot Survey 364 A.B.

January 25, 2001 Survey No. 01-3041 AB-364 Unit 1 Penetration Area (including Hot Spot Nos. 8 and 64)

January 9, 2001 Survey No. 01-3180 AB-364 Unit 1 Penetration Area (including Hot Spot Nos. 8 and 64)

February 7, 2001 TEDE Eval No. 02-06 Diaphragm Removal/Replacement (RWP No. 10000560)

March 5, 2002 TEDE Eval No. 02-08 Half Jumps into Steam Generator Bowl (RWP Nos. 10000562 and 10000563)

March 6, 2002 TEDE Eval No. 02-09 Work on Platforms, >300k but < 1000k contamination levels (RWP Nos. 10000560 and 10000563)

March 5, 2002 TEDE Eval No. 02-10 Work on the Platforms, >1000k contamination levels. Eddy Current Workers (RWP No. 10000563)

March 6, 2002 4OA3 Event Followup 50-454-2001-003-00 Entry into Technical Specification Limiting Condition for Operation 3.0.3 Due to a Leak on a Safety Injection Valve Weld Caused by a Pre-existing Condition and Failing to Use Correct Work Scope Revision Process November 26, 2001 50-454-2001-003- 01 Entry into Technical Specification Limiting Condition for Operation 3.0.3 Due to a Leak on a Safety Injection Valve Weld Caused by a Pre-existing Condition and Failing to Use Correct Work Scope Revision Process, Supplement 1 January 28, 2002 4OA5 Other RS-01-182 Exelon/AmerGen Response to NRC Bulletin 2001-01, Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles August 31, 2001

NRC Bulletin 2001-01 Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles, Responses for Byron Station, Units 1 and 2 and Braidwood Station, Units 1 and 2 November 14, 2001 CR 0009845 DG 14 Day Completion Time May No Longer Be Valid March 8, 2002 1 Condition Report written as a result of the inspection.