IR 05000454/2004004

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IR 05000454-04-004; IR 05000455-04-004, on 04/01/2004-06/30/2004; Byron Station, Units 1 and 2; Identification and Resolution of Problems
ML042050022
Person / Time
Site: Byron  
Issue date: 07/20/2004
From: Ann Marie Stone
Division Reactor Projects III
To: Crane C
Exelon Generation Co, Exelon Nuclear
References
IR-04-004
Download: ML042050022 (57)
v • d • e


Text

July 20, 2004

SUBJECT:

BYRON STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000454/2004004; 05000455/2004004

Dear Mr. Crane:

On June 30, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Byron Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on July 1, 2004, with Mr. S. Kuczynski 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.

Based on the results of this inspection, one inspector-identified finding of very low safety significance (Green) is identified in the report. This finding was determined to involve a violation of NRC requirements. However, because this violation was of very low significance and because the issue was entered into your corrective action program, the NRC is treating this finding 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 a 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, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U. S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector office at the Byron facility. In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be made 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/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 05000454/2004004; 05000455/2004004 w/Attachment: Supplemental Information

REGION III==

Docket Nos:

50-454; 50-455 License Nos:

NPF-37; NPF-66 Report Nos:

05000454/2004004; 05000455/2004004 Licensee:

Exelon Generation Company, LLC Facility:

Byron Station, Units 1 and 2 Location:

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

April 1, 2004, through June 30, 2004 Inspectors:

R. Skokowski, Senior Resident Inspector P. Snyder, Resident Inspector R. Alexander, Radiation Specialist D. Jones, Reactor Engineer P. Higgins, Reactor Engineer L. Kozak, Senior Reactor Engineer D. Schrum, Reactor Engineer T. Tongue, Project Engineer R. Winter, Reactor Engineer C. Thompson, Illinois Emergency Management Agency, Resident Inspector Observers:

T. Bilik, Reactor Engineer C. Acosta, Reactor Engineer Approved by:

Ann Marie Stone, Chief Branch 3 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000454/2004004; 05000455/2004004; on 04/01/2004-06/30/2004; Byron Station,

Units 1 and 2; Identification and Resolution of Problems.

This report covers a 3-month period of baseline resident inspection and announced baseline inspections on maintenance effectiveness-periodic evaluation, inservice inspection program, and radiation protection. In addition, inspections were conducted using Temporary Instructions (TI) 2515/152 (Unit 2 only) and 2515/156. The inspections were conducted by Region III inspectors, and the resident inspectors. One Green finding, which was a violation of NRC requirements, was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG 1649, Reactor Oversight Process, Revision 3, dated July 2000.

A.

Inspector-Identified and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Non-Cited Violation of 10 CFR 50 Appendix B,

Criterion XVI, Corrective Actions, having very low safety significance for failing to identify several instances of improperly installed scaffolding, which was considered a condition adverse to quality. These improperly installed scaffolds were identified by the inspectors during plant tours on March 16, March 19, March 28, April 6, and April 7 of 2004. In each case, after being brought to their attention, the licensee took actions to correct the improperly installed scaffolding. The cross-cutting area of Human Performance was affected because the licensee personnel failed to install scaffolding in accordance with the licensees procedure. The cross-cutting area of Problem Identification and Resolution was affected because the deficiencies were not identified during the scaffolding inspections nor were these deficiencies identified by other members of the licensees staff. Moreover, even after the inspectors initial identification of improperly installed scaffolding, the licensees extent of condition review was inadequate as evidenced by the additional deficiencies later identified by the inspectors.

The issue was more than minor because the licensee failed to perform engineering evaluations on scaffold that potentially impacted safety-related systems. The issue was similar to more than minor example 4.a of Appendix E of IMC 0612. The inspectors determined that the finding could not be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process. Therefore, this finding was reviewed by the Regional Branch Chief in accordance with IMC 0612, Section 05.04c, and determined to be of very low safety significance (Green) because in no case was the improperly installed scaffolding determine to adversely impact the operability of safety-related equipment. The issue was a Non-Cited Violation of Criterion XVI of 10 CFR 50 Appendix B. (Section 4OA2)

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 May 2, 2004, when power was reduced about thirteen percent for a turbine throttle valve and governor valve surveillance test as well as a swap of main feedwater pumps.

Unit 2 began the quarter shutdown for a refueling outage. On April 9, 2004, restart activities began with the unit reaching full power on April 12, 2004. Unit 2 then operated at or near full power for the remainder of the inspection quarter except for two short power reductions: on May 16, 2004, power was reduced about five percent for a main feedwater pump swap, and on June 20, 2004, power was reduced about fourteen percent for load following and a turbine throttle valve and governor valve surveillance test.

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Main article: IP 71111.01

a. Inspection Scope

The inspectors completed two inspection samples. The first sample reviewed the licensees response to severe thunderstorms and high winds warnings on May 12, 2004.

The inspectors evaluated licensee performance by comparing actual performance to the licensee management expectations and guidelines as presented in Byron Abnormal Operating Procedures:

  • 0BOA ENV-1, Adverse Weather Conditions, Revision 101;
  • 1BOA ENV-1, Adverse Weather Conditions, Revision 3; and
  • 2BOA ENV-1, Adverse Weather Conditions, Revision 3.

The second sample reviewed the licensees preparations for potential high temperature conditions during the summer season. Specifically, the inspectors performed the following:

  • reviewed the Updated Safety Analysis Report (UFSAR), Technical Specifications (TS) and other plant documents to identify areas potentially challenged by summer temperatures;
  • reviewed applicable licensee procedures and surveillance tests appropriate for monitoring plant conditions during summer weather;
  • verified through interviews and record review, that Nuclear Shift Operators were familiar with plant systems potentially affected by high temperatures and that necessary procedural and/or contingency plans were in place; and

During the week of May 10-14, 2004, the inspectors performed a walkdown of the plant perimeter and switchyard. The purpose of the walkdown was to assess the adequacy of the protection of plant equipment and the plants offsite power supply from possible airborne missile hazards caused by high winds. To complete this assessment, the inspectors utilized the guidance provided by the licensees Procedure MA-AA-716-026, Station Housekeeping and Material Condition Program, Revision 1.

The inspectors also reviewed selected issues documented in Condition Reports (CR), to determine if they had been properly addressed in the licensees corrective actions program. The documents reviewed during this inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

Main article: IP 71111.04

.1 Partial Walkdowns

a. Inspection Scope

The inspectors performed three 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 lineups 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 UFSAR and TS to determine the functional requirements of the systems.

The inspectors verified the alignment of the following trains:

  • Unit 2 train B component cooling water train while train A component cooling water train was out of service for maintenance;
  • Unit 2 train B essential service water pump during planned work on the train A pump; and

The inspectors utilized the following references during the completion of their review:

  • Control Room Drawing; Diagram of Essential Service Water M-42, Revision AG;
  • BOP SX-E2B; Essential Service Water Unit 2 Train B Electrical Lineup, Revision 1;
  • BOP SX-M2B; Unit 2 Train B Essential Service Water System Valve Lineup Revision 6.

The documents reviewed during this inspection were listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.2 Complete Walkdown

a. Inspection Scope

During the inspection, the inspectors finished one complete system alignment inspection of the accessible portions of the Unit 2 auxiliary feedwater system. This system was selected because it was considered both safety-related, and risk significant in the licensees probabilistic risk assessment and the B train was classified as (a)(1) under the Maintenance Rule. The inspection consisted of the following activities:

  • a review of plant procedures (including selected abnormal and emergency procedures), drawings, and the UFSAR to identify proper system alignment;
  • a review of outstanding work requests on the system;
  • a review of the system health information; and
  • a walkdown of the system to verify proper alignment, component accessibility, availability, and current condition.

The inspectors also reviewed selected issues documented in CRs, to determine if they had been properly addressed in the licensees corrective actions program. The documents reviewed during this inspection were listed in the Attachment to this report.

Findings No findings of significance were identified.

1R05 Fire Protection

Main article: IP 71111.05

a. Inspection Scope

The inspectors conducted fire protection walkdowns that 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. In addition, during these inspections, the inspectors used the following reference documents:

  • OP-MW-201-007; Fire Protection System Impairment Control, Revision 0; and

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 Byron Station Pre-Fire Plans applicable for each area inspected were used by the inspectors to determine approximate locations of firefighting equipment. The documents listed in the Attachment to this report were also used by the inspectors to evaluate this inspection area.

The inspectors completed nine inspection samples by examining the plant areas listed below to observe conditions related to fire protection:

  • 2A EDG room (Fire Zone 9.2-2);
  • Auxiliary building elevation 426' (Fire Zone 11.6-0);
  • Unit 2 EDG cable tunnel (Fire Zone 3.2-1);
  • Division 11 engineered safety feature (ESF) switch gear room (Fire Zone 5.2-1);
  • Auxiliary building elevation 364 Unit 1 containment piping penetration area (Fire Zone 11.3-1);
  • Main control room (Fire Zone 2.1-0);
  • Auxiliary building elevation 346 (Fire Zone 11.2-0); and
  • Division 11 miscellaneous electrical equipment room (Fire Zone 5.6-1).

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

Main article: IP 71111.06

a. Inspection Scope

During the weeks of April 26, and May 10, 2004, the inspectors evaluated the licensees controls for mitigating internal and external flooding by completing a semi-annual and a annual sample. The specific areas evaluated for the semi-annual internal flooding sample included the auxiliary building elevations 330', 346', 364', and 383'. During the evaluation, inspectors performed the following:

  • Reviewed the licensees design basis documents including UFSAR, Safety Evaluation Report, and applicable calculations, to identify the design basis for flood protection and to identify those areas susceptible to external or internal flooding;
  • Reviewed selected abnormal operating procedures for identifying and mitigating flooding events;
  • Plant configuration that may impact external flooding controls;
  • Inspected areas for control of materials that could potentially clog drains, and
  • Inspected the watertight doors and flood seals.

The inspectors also reviewed selected issues documented in CRs, to determine if they had been properly addressed in the licensees corrective actions program. The documents reviewed during this inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

==1R07 Heat Sink Performance (71111.HS)

a. Inspection Scope

==

The inspectors completed one biennial testing and performance review inspection sample by observing and evaluating the licensees inspection of the following safety-related heat exchangers:

  • Unit 2 train B auxiliary feedwater pump gear oil cooler; These heat exchangers were selected for review because essential service water was ranked high in the plant specific risk assessment and the heat exchangers were a support system directly connected to the safety-related auxiliary feedwater 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 exchangers. The inspectors observed the internals of the coolers and the associated data in the respective work packages for any abnormalities and compared the as-found conditions to the acceptance criteria. The inspectors used Licensees Procedure ER-AA-340-1002, Service Water Heat Exchanger and Component Inspection Guide, Revision 1, as a reference document for this inspection. Additionally, the documents listed in the Attachment to this report were also used by the inspectors to evaluate this area.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

Main article: IP 71111.08

a. Inspection Scope

The inspectors conducted a review of the implementation of the licensees inservice inspection program for monitoring degradation of the Unit 2 reactor coolant system boundary and the risk significant piping system boundaries.

Specifically, the inspectors conducted an onsite record review of the following eight nondestructive examination activities to evaluate compliance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements and to verify that indications and defects were dispositioned in accordance with the ASME Code: (This review counted as two samples.)

  • Ultrasonic Examination of Weld No. 2FW87CB-6"-C01;
  • Ultrasonic Examination of Weld No. 2FW87CB-6"-C02;
  • .

Ultrasonic Examination of Weld No. 2FW87CB-6"-C03;

  • .

Ultrasonic Examination of Weld No. 2FW87CB-6"-C05;

  • Ultrasonic Examination of Weld No. 2FW87CB-6"-C06;
  • Ultrasonic Examination of Weld No. 2FW87CB-6"-C07;

The inspectors also reviewed the following examination from the previous outage with recordable indications that have been accepted by the licensee for continued service to verify that the licensees acceptance for continued service was in accordance with the ASME Code: (This review counted as one sample.)

  • Ultrasonic examination of a feedwater system 1FW03DD-16"-C01 weld (indications found to be I.D. geometry).

The inspectors reviewed the following pressure boundary welds for Class 1 or 2 systems which were completed since the beginning of the previous refueling outage, to verify that the welding acceptance (e.g., radiography) and pre-service examinations were performed in accordance with ASME Code requirements: (This review counted as one sample)

  • Radiographic examination of a pressurizer system pipe to pipe weld 1RY32A-3", Weld 1; and
  • Radiographic examination of a pressurizer system pipe to valve weld 1RY32A-3",

Weld 2.

The inspectors reviewed one ASME Section XI Code replacement to verify that the replacement met ASME Code requirements. (This review counted as one sample.)

  • Work Order Package 00419282-09, replacement of pressurizer system check valve (1RY8046) and pipe (1RY32A-3").

The inspectors reviewed a sample of inservice inspection related problems documented in the licensees corrective action program to assess conformance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. In addition, the inspectors verified that the licensee correctly assessed operating experience for applicability to the Inservice Inspection group.

The inspectors also confirmed that the steam generator tube eddy current testing (ECT)scope and expansion criteria met TS requirements, Electric Power Research Institute (EPRI) Guidelines, and commitments made to the NRC; confirmed that all areas of potential degradation (based on site-specific experience and industry experience) were inspected, especially areas which are known to represent potential ECT challenges (e.g., top-of-tube sheet, tube support plates, U-bends); confirmed that the ECT probes and equipment were qualified for the expected types of tube degradation; assessed the site specific qualification of one or more techniques (e.g., equipment, data quality/noise issues, degradation mode); and assessed corrective actions for loose parts or foreign material discovered on the secondary side of the steam generator. The inspectors reviewed the following two samples of eddy current data because questions arose regarding eddy current data analyses: (This review counted as one inspection sample.)

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

Main article: IP 71111.11

a. Inspection Scope

On April 29, 2004, the inspectors completed one inspection sample by observing and evaluating an operating crew during an out-of-the-box requalification examination on the simulator using Scenario Number 04-02-OOB, Revision 0. The inspectors evaluated crew performance in the areas of:

  • clarity and formality of communications;
  • ability to take timely actions;
  • 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, Roles and Responsibilities of On-Shift Personnel, Revision 0,
  • TQ-AA-106-0113; Simulator Demonstration Examination Individual Competency Evaluation Form, Revision 1.

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 utilized the following references during the completion of their review:

  • Unit 1 Abnormal Operating Procedure 1BOA-SEC-1, Secondary Pump Trip, Revision 104;
  • Unit 1 Emergency Operating Procedure 1BEP-0, Reactor Trip or Safety Injection, Revision 106; and

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

.1 Periodic Evaluation

a. Inspection Scope

The inspectors examined the periodic evaluation report covering the period January 2002 through June 2003. To evaluate the effectiveness of (a)(1) and (a)(2) activities, the inspectors examined a number of (a)(1) action plans, functional failures, and CRs.

The inspectors reviewed these same documents to verify that the threshold for identification of problems was at an appropriate level and the associated corrective actions were appropriate. Also, the maintenance rule program documents were reviewed. The inspectors focused the inspection on the following four systems (samples):

  • Safety Injection;
  • Auxiliary Power (specifically 4160 Vac); and

The inspectors verified that the periodic evaluation was completed within the time restraints defined in 10 CFR 50.65 (once per refueling cycle, not to exceed two years).

The inspectors also determined that the licensee reviewed its goals, monitored Structures, Systems, and Components (SSCs) performance, reviewed industry operating experience, and made appropriate adjustments to the maintenance rule program as a result of the above activities.

The inspectors verified that the licensee balanced reliability and unavailability of SSCs including safety significant systems during the previous refueling cycle.

The inspectors verified that (a)(1) goals were established and corrective actions were appropriate to address the causes for SSCs being in (a)(1) category, including the use of industry operating experience, and that (a)(1) activities and related goals were adjusted as needed.

The inspectors verified that the licensee had established (a)(2) performance criteria, examined any SSCs that failed to meet their performance criteria, and reviewed any SSCs that have suffered repeated maintenance preventable functional failures including a verification that failed SSCs were considered for (a)(1). The inspectors also attended a Maintenance Rule Expert Panel meeting to evaluate the panels decision-making process for changes to maintenance rule scoping, performance criteria, and (a)(2)evaluations.

In addition, the inspectors reviewed maintenance rule self-assessments that addressed the maintenance rule program implementation.

b. Findings

No findings of significance were identified.

.2 Routine Inspections

a. Inspection Scope

The inspectors completed two inspection samples by evaluating the licensees implementation of the maintenance rule, 10 CFR 50.65, as it pertained to identified performance problems associated with the following systems:

  • SX5 - essential service water train and unit cross-tie isolation capability; and
  • Unit 2 train B emergency diesel generator During this inspection, the inspectors evaluated the licensees monitoring and trending of performance data for the past 2 years, 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. The inspectors also verified the basis for classification as (a)(1) or (a)(2) and the criteria for change of classification. For the system reviewed, the inspectors also reviewed the significant work orders and condition reports listed in the Attachment to this report to verify that failures were properly identified, classified, and corrected, and that unavailable time had been properly calculated.

In addition, the inspectors utilized the following references during the completion of their review:

  • NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2, and
  • ER-AA-310; Implementation of the Maintenance Rule, Revision 2.

Additionally, the documents reviewed during this inspection were listed in the to this report.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 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 the evaluation, planning, control, and performance of the work were 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, UFSAR, TS, and Individual Plant Examination. The inspectors also observed operator turnovers, observed plan-of-the-day meetings, and reviewed the documents listed in the to 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 work activities in accordance with the following:

  • Nuclear Station Procedure (NSP) WC-AA-101, On-Line Work Control Process, Revision 8,
  • NSP ER-AA-310, Implementation of the Maintenance Rule, Revision 3,
  • Byron Operating Department Policy 400-47, May 13, 2004, Revision 4, and.

The inspectors completed five inspection samples by reviewing the following activities:

  • planned unavailability of the Unit 2 train A essential service water pump concurrent with the unavailability of the Unit 1 general area containment radiation monitor;
  • planned unavailability of the Unit 1 and Unit 2 train B essential service water pumps;
  • planned unavailability of the Unit 2 train B residual heat removal pump concurrent with the 2C steam power operated relief valve and train C auxiliary building supply fan;

b. Findings

No findings of significance were identified.

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

Main article: IP 71111.14

a. Inspection Scope

The inspectors completed one inspection sample by observing and evaluating control room operators during the following non-routine evolutions:

  • startup following Byron Station Unit 2 Outage Eleven (B2R11) on April 9, 2004.

The inspectors evaluated crew performance in the areas of:

  • clarity and formality of communications,
  • 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, Roles and Responsibilities of On-Shift Personnel, Revision 0,
  • OP-AA-300, Reactivity Management Controls, Revision 000, and

In addition, the inspectors utilized the following references during the completion of their review:

  • 2BGP 100-2; Plant Startup, Revision 30;
  • 2BGP 100-2T1; Plant Startup Flow Chart, Revision 13;
  • 2BGP 100-3T1; Power Ascension Flow Chart, Revision 17; and
  • 2BVSR XPT-3; Unit 2 Reload Tests Following Refueling, Revision 5.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

Main article: IP 71111.15

a. Inspection Scope

The inspectors evaluated plant conditions, selected condition reports, engineering evaluations and operability determinations 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 completed seven inspection samples by reviewing the following evaluations and issues:

  • CR 213691, 2SX136 breaker failed post maintenance testing;
  • CR 214994, 2B diesel generator engine lube oil temperature off-normal alarm;
  • CR 219025, Part 21 issued on installed 2B diesel generator governor digital reference unit; and
  • the licensees justification for not correcting existing degrading and nonconforming conditions during B2R11.

The inspectors compared the operability and design criteria in the appropriate section of the TS including the TS Basis, the technical requirements manual (TRM) 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 1. The inspectors also discussed the details of the evaluations with the shift managers and appropriate members of the licensees engineering staff.

The inspectors utilized the following references during the completion of their review:

  • NRC Inspection Manual Part 9900: Technical Guidance; Operable/Operability:

Ensuring the Functional Capability of a System or Component;

  • NRC Inspection Manual Part 9900: Technical Guidance; Resolution of Degraded and Nonconforming Conditions; October 8, 1997; and
  • NRC Generic Letter No 91-18: Information to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions, Revision 1.

The documents reviewed during this inspection were listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications (Annual)

Main article: IP 71111.17

a. Inspection Scope

The inspectors completed one inspection sample by reviewing the following permanent plant modifications:

The inspectors reviewed the sump level instrumentation modification installed during B2R11 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 modification 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 inspectors utilized the following references during the completion of their review:

  • Technical Specifications; and

The documents listed in the Attachment to this report were used in the assessment of this area.

b. Findings

No findings of significance were identified.

1R19 Post Maintenance Testing

Main article: IP 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, TRM, and UFSAR, as well as the documents listed in the Attachment to this report, to evaluate this area. The inspectors verified that the licensee controlled post maintenance testing in accordance with the following:

  • Byron Administrative Procedure (BAP) 1600-11; Work Request Post Maintenance Testing Guidance; Revision 12, and

The inspectors completed five inspection samples by observing and evaluating the post maintenance testing subsequent to the following activities:

  • Unit 1 and 2 train B essential service water pump suction valves following replacement on April 1, 2004;
  • Unit 2 cold leg injection Valve SI8900A following emergent work on April 2, 2004;
  • Unit 2 train A essential service water pump following planned work on May 27, 2004; and
  • Unit 1 train B component cooling water pump following plan maintenance on June 9, 2004.

During the review of the testing of the essential service water pump suction valves, the inspectors utilized the following reference documents:

  • BOP SX-7; filling and venting the essential service water system, Revision 10-Interim;
  • Braidwood CR 00026418; A2000-01641 unplanned entry into essential service LCOAR, April 5, 2000; and
  • Braidwood Licensee Event Report (LER) 2000-001-00; 2A essential service water pump inoperable for more than the TS allowed outage time resulting from inadequate testing criteria due to a design deficiency and inadequate methodology for the return to service.

b. Findings

No findings of significance were identified.

1R20 Refueling & Outage Activities

Main article: IP 71111.20

a. Inspection Scope

The inspectors observed the licensees performance during B2R11 beginning March 22, 2004, and concluding on April 9, 2004. The inspection activities described below completes the inspection sample started in the last inspection period.

The inspectors evaluated the licensees conduct of 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, TRM, UFSAR and approved procedures. The inspectors interviewed operations, engineering, work control, radiological protection, and maintenance department personnel during their inspection activities. The inspectors also attended outage-related status and pre-job briefings as well as Radiation Protection ALARA (As Low As Reasonable Achievable) briefings. Other major-outage activities evaluated included the licensees control of:

  • SSCs which could cause unexpected reactivity changes;
  • flow paths, configurations, and alternate means for RCS inventory addition;
  • 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

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 core reload was completed in accordance with the core loading plan for Byron Unit 2 Cycle 12;
  • 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 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 also observed portions of the plant heatup and reactor startup, to verify that the licensee controlled the plant cooldown in accordance with the TS and approved procedures.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

Main article: IP 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 TRM, the UFSAR, and licensee procedural requirements. The inspectors also verified that the surveillance tests 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 completed six inspection samples by observing and evaluating the following surveillance tests:

  • Unit 1 train A engineered safety features actuation system (ESFAS)instrumentation slave relay surveillance for automatic safety injection (K611);
  • Unit 2 ECCS system flow balance test.

During this inspection, the inspectors used the following references:

  • Commonwealth Edison Drawing 6E-1-4030 CS06 Schematic Diagram Containment Spray Eductor 1A Spray Additive Valves 1CS019A&B Revision M,
  • Commonwealth Edison Drawing 6E-1-4030 CS06 Byron - Unit 1 Schematic Diagram Diesel Generator 1B Feed to 4.16KV ESF Switchgear Bus 142 ACB
  1. 1423 Revision W,
  • Sargent & Lundy Drawing 6E-2-4031 CS508 Loop Schematic Diagram Containment Spray Eductor 1B Additive Flow Control System Revision L,

Additionally the inspectors used the documents listed in the Attachment to 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.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

Main article: IP 71111.23

a. Inspection Scope

The inspectors completed two inspection samples by evaluating the following temporary plant modification on risk-significant equipment:

The inspectors reviewed these temporary plant modifications to verify that the instructions were consistent with applicable design modification documents and that the modification did not adversely impact system operability or availability. The inspectors used the following documents as references when completing the review: UFSAR, TS including the basis, and the TRM. The inspectors verified that the licensee controlled temporary modifications in accordance with Procedure NSP CC-AA-112, Temporary Configuration Changes, Revision 7.

In addition, the inspectors utilized the following references during the completion of their review:

  • NRC Administrative Letter 98-10: Dispositioning of TSs That Are Insufficient To Assure Plant Safety.

The inspectors also reviewed selected issues documented in CRs, to determine if they had been properly addressed in the licensees corrective actions program. The documents reviewed during this inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety (OS)

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors reviewed licensee controls and surveys for selected radiation areas, high radiation areas and airborne radioactivity areas, as available, in the following four radiologically significant work areas within the plant and reviewed work packages which included associated licensee controls and surveys for these areas to determine if radiological controls (including postings and barricades) were acceptable:

  • Unit 2 Containment;
  • Unit 2 Containment Access Facility;
  • Auxiliary Building (in particular, the Penetration Area); and
  • Radwaste Building.

The inspectors reviewed the radiation work permits (RWP) and work packages used to control work in these four areas and other high radiation work areas to identify the work control instructions and control barriers that had been specified. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. Workers were interviewed to assess their knowledge of the actions required when their electronic dosimeters noticeably malfunctioned or alarmed.

The inspectors walked down and surveyed (using an NRC survey meter) these four areas to verify that the prescribed RWPs, procedures, and engineering controls were in place, that licensee surveys and postings were complete and accurate, and that air samplers (if necessary) were properly located.

These reviews represented three inspection samples.

b. Findings

No findings of significance were identified.

.2 Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed eleven corrective action reports related to access controls written leading up to and during the most recent B2R11 refueling outage, including reports on high radiation area radiological incidents, as available. Staff members were interviewed and corrective action documents were reviewed to verify that follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:

1. Initial problem identification, characterization, and tracking;

2. Disposition of operability/reportability issues;

3. Evaluation of safety significance/risk and priority for resolution;

4. Identification of repetitive problems;

5. Identification of contributing causes;

6. Identification and implementation of effective corrective actions;

7. Resolution of Non-Cited Violations tracked in the corrective action system; and

8. Implementation/consideration of risk significant operational experience feedback.

These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

.3 Job-In-Progress Reviews

a. Inspection Scope

The inspectors observed the following four activities that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers:

  • Steam Generator Secondary Side/Pre-Heater Inspections and FOSAR (Foreign Object Search and Removal) [RWP No. 10003224];
  • Scaffold Staging, Building and Removal [RWP No. 10003261]; and
  • Unit 2 train B chemical and volume control system (CV) Letdown Heat Exchanger Head Gasket Replacement [RWP No. 10003497].

The inspectors reviewed radiological job requirements for these four activities, including RWP and work procedure requirements, and attended ALARA pre-job briefings.

Job performance was observed with respect to these requirements to verify that radiological conditions in the work areas were adequately communicated to workers through pre-job briefings and postings. The inspectors also verified the adequacy of radiological controls (including required radiation, contamination, and airborne surveys);radiation protection job coverage (including audio/visual surveillance for remote job coverage); and contamination controls.

Radiological work in high radiation work areas having significant dose rate gradients was reviewed to evaluate the application of dosimetry to effectively monitor exposure to personnel and to verify that licensee controls were adequate. In particular, the steam generator eddy current activities involved evolutions where the dose rate gradients were severe which increased the necessity of providing multiple or repositioned dosimetry and/or enhanced job controls.

These reviews represented three inspection samples.

b. Findings

No findings of significance were identified.

.4 Radiation Worker Performance

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation worker performance with respect to stated radiation protection work requirements and evaluated whether workers were aware of the significant radiological conditions in their workplace, the RWP controls and limits in place, and that their performance accounted for the level of radiological hazards present.

These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

.5 Radiation Protection Technician Proficiency

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation protection technician performance with respect to radiation protection work requirements and evaluated whether they were aware of the radiological conditions in their workplace, the RWP controls and limits in place, and if their oversight of radiological activities was consistent with their training and qualifications with respect to the radiological hazards and work activities.

These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

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

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the B2R11 refueling outage work scheduled during the inspection period and associated work activity exposure estimates for the following three work activities which were likely to result in the highest personnel collective exposures:

  • Steam Generator Secondary Side/Pre-Heater Inspections and FOSAR (Foreign Object Search and Removal) [RWP No. 10003224]; and
  • Scaffold Staging, Building and Removal [RWP No. 10003261].

Additionally, the inspectors reviewed licensee procedures associated with maintaining occupational exposures ALARA and processes used to estimate and track work activity specific exposures.

These reviews represented two inspection samples.

b. Findings

No findings of significance were identified.

.2 Radiological Work Planning

a. Inspection Scope

The inspectors evaluated the licensees list of work activities for the B2R11 refueling outage ranked by estimated exposure that were in progress, and reviewed the following five work activities of highest exposure significance or radiological challenge:

[RWP No. 10003222];

  • Scaffold Staging, Building and Removal; and
  • 2B CV Letdown Heat Exchanger Head Gasket Replacement

[RWP No. 10003497].

For these five activities, the inspectors reviewed the ALARA evaluations, exposure estimates, and exposure mitigation requirements in order to verify that the licensee had established procedures, and engineering and work controls that were based on sound radiation protection principles in order to achieve occupational exposures that were ALARA. This also involved determining if the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.

The interfaces between radiation protection, operations, maintenance, planning, scheduling and engineering groups were evaluated by the inspectors to identify interface problems or missing program elements. The inspectors evaluated if work activity planning included consideration of the benefits of dose rate reduction activities such as shielding provided by water filled components/piping, job scheduling, and shielding and scaffolding installation/removal activities. Finally, the inspectors evaluated the integration radiological job planning activities (pre-job ALARA reviews) into work procedure and RWP documents.

These reviews represented five inspection samples.

b. Findings

No findings of significance were identified.

.3 Verification of Dose Estimates and Exposure Tracking Systems

a. Inspection Scope

The inspectors reviewed the licensees process for adjusting exposure estimates or re-planning work, when unexpected changes in scope, emergent work or higher than anticipated radiation levels were encountered. This review included a determination if adjustments to estimated exposures (intended dose) were based on sound radiation protection and ALARA principles, rather than adjustments to account for failures to adequately control the work. The frequency of these adjustments was reviewed to evaluate the adequacy of the original ALARA planning process. In particular, the inspectors reviewed and discussed with the RP staff the Work-In-Progress reviews conducted for the 2B CV letdown heat exchanger activities, steam generator nozzle dam installation/removal activities, and contingent/emergent work RWPs.

These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

.4 Job Site Inspections and ALARA Control

a. Inspection Scope

The inspectors observed three of the activities identified in Section 2OS1.3 that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers.

The licensees use of ALARA controls for these work activities was evaluated using the following:

(1) The licensees use of engineering controls to achieve dose reductions was evaluated to verify that procedures and controls were consistent with the licensees ALARA reviews, that sufficient shielding of radiation sources was provided for and that the dose expended to install/remove the shielding did not exceed the dose reduction benefits afforded by the shielding.
(2) Job sites were observed to determine if workers were utilizing the low dose waiting areas and were effective in maintaining their doses ALARA by moving to the low dose waiting area when subjected to temporary work delays.

These reviews represented two inspection samples.

b. Findings

No findings of significance were identified.

.5 Radiation Worker Performance

a. Inspection Scope

Radiation worker and RP technician performance was observed during work activities performed in radiological areas that presented the greatest radiological risk to workers.

The inspectors evaluated whether workers demonstrated the ALARA philosophy in practice by being familiar with the work activity scope and tools to be used, by utilizing ALARA low dose waiting areas, and that work activity controls were being complied with.

Also, radiation worker performance was observed to determine whether individual training/skill level was sufficient with respect to the radiological hazards and the work involved.

These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Occupational Radiation Safety

4OA1 Performance Indicator Verification

Main article: IP 71151

.1 Reactor Safety Strategic Area

a. Inspection Scope

The inspectors sampled the licensees submitted materials for performance indicators (PIs) and periods listed below. The inspectors used PI definitions and guidance contained in Revision 2 of Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline to verify the accuracy of the PI data. The following four PIs for Unit 1 and Unit 2 (8 samples) were reviewed:

  • unplanned scrams per 7000 critical hours (April 2003 to March 2004);
  • unplanned power changes per 7000 critical hours (April 2003 to March 2004);
  • scrams with loss of normal heat removal (April 2003 to March 2004); and

The inspectors reviewed selected applicable condition reports and data from logs, licensee event reports, and work orders from April 2003 through March 2004 for each PI area specified above. The inspectors independently reperformed calculations where applicable. The inspectors compared that information with the performance indicator definitions in the guideline to ensure that the licensee reported the data accurately.

For the reactor coolant system specific activity PI, the inspectors reviewed the licensees Chemistry Department records and selected isotopic analyses to verify that the greatest Dose Equivalent Iodine value obtained during those months corresponded with the value reported to the NRC. The inspectors also reviewed selected DEI calculations to verify that appropriate conversion factors were used in the assessment as required by TSs. Additionally, on June 24, 2004, the inspectors observed adherence with licensee procedures for the collection and analysis of reactor coolant system samples.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

Main article: IP 71152

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees corrective action system at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Minor issues entered into the licensees corrective action system as a result of inspectors observations are generally denoted in the list of documents reviewed at the back of the report.

b. Findings

No findings of significance were identified.

.2 Annual Sample

Control of Scaffolding

Introduction:

During this inspection period the inspectors identified several issues associated with the improper installation of scaffolding. The inspectors communicated their observations to the licensee and number of condition reports were generated.

Based on the number of issues identified, the inspectors selected the review scaffolding control as an annual sample of the licensees problem and identification and resolution program.

a.

Effectiveness of Problem Identification

(1) Inspection Scope During the course of plant tours, prior to, during and after the Unit 2 refueling outage (B2R11), the inspectors focused on verifying that installed scaffolding was completed in accordance with the licensees procedures. This also allowed the inspectors to assess the licensees effectiveness to identify conditions adverse to quality. In addition to inspections of installed scaffolding, the inspectors reviewed scaffolding related procedures and discussed the scaffolding installation process and requirements with the licensees engineering, maintenance and operations staff. Also, the inspectors reviewed related condition reports to ensure that the issues were accurately documented, reviewed in a timely manner, and the extent of condition was appropriately considered.

During the course of this review the inspectors utilized the following licensees procedures as references:

  • LS-AA-125 Corrective Action Program Procedure, Revision 8;
  • NES-MS-04.1, Seismic Prequalified Scaffolds, Revision 4.

Additional documents reviewed as part of this inspection were listed in Attachment A of this report.

(2) Findings
Introduction:

The inspectors identified a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective actions having very low safety significance (Green) for failing to identify several instances of improperly installed scaffolding, which was considered a condition adverse to quality. These improperly installed scaffolds were identified by the inspectors during plant tours.

Description:

On March 16, 2004, during a walkdown of the Unit 2 penetration area to assess if pre-outage activities, such as equipment staging and scaffolding construction were not adversely impacting safety-related equipment, the inspectors noted that scaffold B4300 was in contact with a portion of the safety-related charging system piping. In addition, the inspectors noted other scaffolding in the penetration that looked very close to other safety-related equipment. The inspectors informed the shift manager of the concerns. Based on a subsequent discussion with the licensee structural engineer and a review of the licensee procedures, the inspectors ascertained that the seismic requirement for rigid scaffolds was a minimum 1/4 inch gap between the scaffold and safety-related equipment. Based on the clearance gap requirements, the scaffolding in contact with the charging system piping was not in accordance with the installation procedure and the licensee initiated CR 208999 and corrected the condition.

Later on March 16, the licensee completed walkdowns of scaffolding and identified five additional scaffolds that did not meet the seismic requirements. For three of the five scaffolds, the licensees maintenance staff was able to correct the deficiencies, for the remaining two, engineering evaluations were completed to address the deficiencies. All five of the issues were documented in CR 208902.

During another walkdown by the inspectors on March 19, the inspectors identified seismic clearance concerns with scaffold 4656, located in the 2B auxiliary feedwater pump room. This scaffold was in the process of being constructed, and was inappropriately attached to safety-related support steel of the diesel-driven auxiliary feedwater pump. At the time, the 2B auxiliary feedwater pump was considered operable. After discussion with the inspectors, the structural engineer had the scaffolding removed and documented the issue in CR 209638. In addition, the inspectors expressed concern to the licensee management regarding the quality of their extent of condition review and corrective actions for the issues identified on March 16.

On March 28, the inspectors toured the operating unit (Unit 1) penetration area and identified three additional examples of scaffolds not meeting the specified seismic requirements. The inspectors discussed the concerns with the shift manager and showed the scaffolds in question to one of the on-watch operations department field supervisors. The concerns were acknowledged and documented in CR 211387. Later the licensee determined that one of these scaffolds had been inadvertently left in place since the Unit 1 outage in the fall of 2003. The licensee generated another CR (211824) to document the issue.

On March 30, the licensee generated a condition report (211906) documenting a potential negative trend regarding the scaffold program. As a result of this CR, the licensee initiated common cause analysis to be performed after the outage to capture all scaffolded related events and issues and to provide lessons learned prior to the next outage. The common cause analysis is scheduled to be completed in July 2004, and therefore the inspectors have not reviewed the results of the analysis.

On April 6, 2004, the inspectors found another scaffold (B4589) in the Unit 2 penetration area contacting safety-related piping, and on April 7, the inspectors questioned the seismic qualification of several permanent scaffolds within the Unit 2 containment. The licensee removed the scaffolding in the penetration area and documented the concern in CR 213703. Regarding the questions regarding the permanent scaffolding in the Unit 2 containment, the licensees engineering staff provided supporting information to justify the adequacy of the installation. For one case, the licensee also adjusted the scaffolding to ensure adequate clearance between the scaffolding the safety-related equipment.

On April 7, 2004, based on the number of scaffolding-related issues noted by the inspectors, the licensee initiated CR 213802, which focused on the ineffectiveness of the licensees actions to identify and prevent additional scaffolding issues.

Analysis The inspectors determined that failing to identify that scaffolding was not installed in accordance with the licensees procedure was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspections Reports, Appendix B, Issue Disposition Screening, issued on June 20, 2003. The inspectors determine that the finding was more than minor because it was similar to the more than minor examples of Section 4 of Appendix E of IMC 0612.

The inspectors determined that this deficiency affected the cross-cutting areas of Human Performance and Problem Identification and Resolution. Human Performance was affected because the licensee did not install or construct the scaffolding in accordance with the licensees procedure. Problem Identification and Resolution was affected because the deficiencies were not identified during the scaffolding inspections nor were these deficiencies identified by other members of the licensees staff.

Moreover, even after the inspectors initial identification of some cases of improperly installed scaffolding, the licensees extent of condition review was inadequate as evidenced by the additional deficiencies identified by the inspectors.

The inspectors determined that the finding could not be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Significance Determination Process. Therefore, this finding was reviewed by the Regional Branch Chief in accordance with IMC 0612, Section 05.04c, and determined to be of very low safety significance (Green) because in no case was the improperly installed scaffolding determine to adversely impact the operability of safety-related equipment. The finding was assigned to the mitigating system cornerstone for both units.

Enforcement Criterion XVI of 10 CFR 50 Appendix B states, in part, that measures shall be established to assure that conditions adverse to quality, such as nonconformances are promptly identified. Contrary to the above, in March and April 2004, on at least four occasions, the licensee failed to identify situations of scaffolding not constructed in accordance with the seismic clearance requirements specified in Procedure NES-MS-04.1, Seismic Prequalified Scaffolds, Revision 4. This violation was captured in the licensees corrective action program as CR 213802. This violation was characterized as having very low risk significance (i.e., Green) and is being treated as a Non-Cited Violation, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000454/2004004-01; 05000455/2004004-01).

.3 Semi-Annual Trending Review

a. Inspection Scope

The inspectors completed a semi-annual review for potential or identified trends. The purpose of this review was to determine if any potential or identified trends might indicate a more significant safety issue. The inspectors limited their focus to equipment issues that were documented in the following licensee programs or reports:

  • Component Health Indicator Program;
  • Rework Program;
  • Engineering Department Quarterly Corrective Action Program Trend Report; and
  • Maintenance Department Quarterly Corrective Action Program Trend Report.

The inspectors reviewed the above information for the past two years, and discussed these programs and reports with the applicable members of the licensees staff. The inspectors verified that any trends identified by these programs and reports were appropriate entered and classified in the licensees corrective action program.

In addition, the inspectors considered aspects of their day-to-day inspection activities to determine whether trends were overlooked by the licensee.

During the course of the inspection, the inspectors utilized the following licensees procedures as references:

  • LS-AA-125 Corrective Action Program Procedure, Revision 8;

Additional documents reviewed as part of this inspection were listed in Attachment A of this report.

b.

Issues No findings of significance were identified. The inspectors review of the programs and reports found the identified trends appropriately captures and classified in the licensees corrective action program. Also, based on a review of the data contained in these program, the inspectors did not identify any additional trends.

However, during the review of day-to-day inspections insights, specifically, during the inspection sample described in Section 4OA2.2 of this report, the inspectors identified a failure of the licensee to identify a trend regarding improperly installed scaffolding, such that the scaffolding was in contact with safety-related equipment. In addition, during a walkdown of the Unit 2 auxiliary building penetration area, the inspectors identified several valves with indications of dried boric acid corrosion. The boric acid was primarily due to inactive valve packing leaks. The inspectors specifically identified boric acid corrosion on following valves 2SI8802B, 2SI046, 2CV052D, 2CV8355D, 2CV8355A, but noted that several other valves with indications of boric acid corrosion. The concerns with specific valves identified by the inspectors were documented by the licensee in CR 213703.

As a result of the inspectors concerns regarding the boric acid corrosion, the licensee completed a thorough walkdown of the valves in the penetration areas for both units, and identified several additional valves with indications of boric acid corrosion. Although no actual valve degradation was identified as a result of the boric acid corrosion, the licensees Boric Acid Corrosion Control Program Owner initiated another CR (213843)noting the need to incorporate periodic walkdowns of the areas containing equipment vulnerable to boric acid corrosion, including the penetration areas and containment when accessible, and additional tracking of the indications of boric acid corrosion identified. From a regulatory perspective, because there was no actual degradation of equipment identified, the condition was not considered a condition adverse to quality and therefore, no violation of regulatory requirements occurred.

4OA3 Event Follow-up

Main article: IP 71153

.1 Response to June 28, 2004 Earthquake

a. Inspection Scope

On June 28, 2004, an earthquake was experienced in the portions of Illinois. According to the National Earthquake Center, at 1:10 A.M. local time on the morning of June 28, 2004, an earthquake with a magnitude of 4.5 occurred with the epicenter approximately eight miles northwest of Ottawa, Illinois. Although the magnitude and location of the earthquake was such that the seismic instrumentation did not indicate a problem, the operators entered the applicable abnormal operating procedures because some ground shaking was felt. The inspectors reviewed the operators actions in accordance with the following procedures:

  • BAR 0-38-E5, Accelerograph Accel High, Revision 7.

The inspectors also reviewed the applicable portions of the UFSAR related to seismic aspects of the Byron Station.

In addition, the inspectors verified that the licensee properly evaluated the significance of the earthquake in accordance with their emergency action levels as specified in the Exelon Nuclear Radiological Emergency Plan Annex for the Byron Station, Revision 15.

The inspectors verified that there were no indications of reactor coolant system leakage, and completed visual inspections of selected safety-related system to verify no impact to system integrity or other structural damage. The systems inspected included the emergency diesel generators, spent fuel pool and associated equipment, portions of the component cooling water system, essential service water system, and auxiliary feedwater system. The inspectors also completed visual inspections of the Unit 1 and Unit 2 auxiliary building to containment building pipe penetration area, the Unit 1 trains A and D main steam safety valve room and steam tunnel, and outside structures and tanks, included the containment buildings, the essential service water cooling towers, the refueling water storage tanks, the condensate storage tanks, the primary water storage tanks and the fuel oil storage tanks.

b. Findings

No findings of significance were identified.

.2 (Closed) LER 05000454/2003003-01; 05000455/2003003-01:

Licensed Maximum Power Level Exceeded Due to Inaccuracies in Feedwater Ultrasonic Flow Measurements Caused by Signal Noise Contamination, Supplement 1. The original LER, which was reviewed in NRC IR 05000454/2003007; 05000455/2003007, described that Byron Unit 1 and Unit 2 exceeded their licensed maximum power level since the implementation of the ultrasonic flow measurement system (UFMS) in May 2000. The UFMS was installed to provide more accurate measure of feedwater flow, which in turn was used in the reactor power calorimetric calculation. Upon installation of UFMS, the licensee noted unexpected differences in the stations megawatt output when compared to the megawatts recovered when the licensee installed the UFMS at similar stations.

The licensees attempts to understand the differences were inconclusive. However, based on their evaluation the licensee verified that the UFMS was correctly installed and operating at the Byron Station. Consequently, the licensee decided to utilize the UFMS in calculated reactor power, allowing for greater megawatt output. The licensee continued to investigate the difference in megawatt output between the stations. In August 2003, the licensee installed another ultrasonic flow measuring instrument on the common feedwater header. The flow indications from this instrument were compared to the sum of the UFMS indications installed on the four feedwater branch lines. Based on this comparison the licensee determined that Byron Units 1 and 2 were operating in excesses of the licensed maximum power. As a result, the licensee reduced power on both units and utilized the original feedwater flow instruments (venturi) for determining reactor power.

The licensee submitted Supplement 1 to LER 2003003 to provide results of subsequent analysis of feedwater flow measurements. Specifically in February 2004, the licensee performed a feedwater flow measurement utilizing a radioactive tracer. The results of this test indicated that there was a non-conservative bias on the UFMS installed on the Unit 1 and Unit 2 common feedwater headers. This test also validated the accuracy of the installed venturi flow measurement system. Based on the tracer test results, the licensee determined that the worst case power level experienced since the installation of the UFMS was 102.62 percent for Unit 1 and 101.88 percent for Unit 2. Additionally, the results of the tracer test indicated that the originally determined cause of the problem that signal noise adversely impacted the ability of the UFMS to accurately calculated feedwater flow was fully developed and that the UFMS vendor was doing additional investigation to determine the cause.

The inspectors reviewed the licensees LER and considered it closed. However, the regulatory aspects of this issue, including the determination of actual worst case power levels will be determined upon completion of the NRCs review of the associated Unresolved Item 50-454/03-02-03.

4OA4 Cross-Cutting Aspects of Findings

  • A finding identified Section 4OA2 of this report affected the cross cutting area of human performance, in that, the licensee failed to install or construct the scaffolding in accordance with the licensees procedure.
  • A finding identified Section 4OA2 of this report affected the cross cutting area of problem identification and resolution, in that, the deficiencies were not identified during the scaffolding inspections nor were these deficiencies identified by other members of the licensees staff. Moreover, even after the inspectors initial identification of some cases of improperly installed scaffolding, the licensees extent of condition review was inadequate as evidenced by the additional deficiencies identified by the inspectors.

4OA5 Other Activities

.1 Reactor Pressure Vessel (RPV) Lower Head Penetration (LHP) Nozzles (NRC

Bulletin 2003-02) (Temporary Instruction (TI) 2515/152, Revision 1)

a. Inspection Scope

The inspectors conducted a review of the licensees activities in response to Bulletin 2003-02, which was issued on August 21, 2003. To support the evaluation of the licensees activities implemented in accordance with Bulletin 2003-02, TI 2515/152, Reactor Pressure Vessel Lower Head Penetration Nozzles (NRC Bulletin 2003-02),was issued September 5, 2003, and revised November 5, 2003.

Summary The licensee did not identify any signs of leakage from the RPV LHP nozzles or degradation of the RPV lower head.

b.

Evaluation of Inspection Requirements In accordance with requirements of TI 2515/152, Revision 1, the inspectors evaluated and answered the following questions:

For each of the examination methods used during the outage, was the examination:

1. Performed by qualified and knowledgeable personnel? (Briefly describe the

personnel training/qualification process used by the licensee for this activity.)

Yes. The inspectors verified that the remote visual examination of the LHP nozzles was performed by qualified and certified ASME Level II and Level III VT-2 examiners. Additionally, the licensees inspection staff were trained on Electric Power Research Institute (EPRI) Report TR 1000975, Boric Acid Corrosion Evaluation.

2. Performed in accordance with demonstrated procedures?

Yes. The remote visual examination of the vessel bottom head and the penetration nozzles was performed in accordance with procedure ER-AP-335-1012, Revision 0, Visual Examination of PWR Reactor Vessel Head Penetrations. The inspectors reviewed the videotape of the licensees demonstration of visual resolution and noted that it was consistent with the procedure requirements.

3. Able to identify, disposition, and resolve deficiencies?

Yes. The inspectors verified that the licensee was able to identify, disposition, and resolve deficiencies.

4. Capable of identifying pressure boundary leakage as described in the bulletin

and/or RPV lower head corrosion?

Yes. The inspectors verified that the remote visual examinations of the bottom mounted instrumentation nozzles were conducted in accordance with ER-AP-335-1012, Revision 0, Visual Examination of PWR Reactor Vessel Head Penetrations. The camera resolution was such that pressure boundary leakage as described in the bulletin and/or RPV lower head corrosion could be identified and characterized.

5. Could small boric acid deposits, as described in the Bulletin 2003-02, be

identified and characterized, if present by the visual examination method used?

Yes. Through review of in-process and videotape documentation, the inspectors verified that small boric acid deposits, as described in the Bulletin 2003-02, could be identified and characterized. However, the licensee did not identify any leakage from the J-groove welds of the LHP nozzles during the remote bare metal visual examination of the reactor vessel bottom head.

6. How was the visual inspection conducted (e.g., with video camera or direct visual

by the examination personnel)?

The licensee performed a remote visual examination of the vessel bottom head and the lower head penetration nozzles using a video camera. The inspection was performed in accordance with procedure ER-AP-335-1012, Revision 0, Visual Examination of PWR Reactor Vessel Head Penetrations. Each lower head penetration nozzle was examined for 360 degrees (in 90 degree quadrants)and the entire examination was recorded on a videotape.

7. How complete was the coverage (e.g., 360 degrees around the circumference of

all the nozzles)?

Each lower head penetration nozzle was examined for 360 degrees (in 90 degree quadrants).

8. What was the physical condition of the RPV lower head (e.g., debris, insulation,

dirt, boric acid deposits from other sources, physical layout, viewing obstructions)? Did it appear that there are any boric acid deposits at the interface between the vessel and the penetrations?

The bottom head has vertical insulation panels that cover the sides of the vessel.

Horizontal insulation panels are mounted to the vertical insulation panels. A minimum clearance of approximately eight inches existed between the bottom radius of the vessel and the horizontal insulation panels. Access to the space between the horizontal insulation panels and the bottom of the vessel is provided through twelve removable, horizontal, peripheral panels.

A remotely powered and controlled crawler with camera and lighting was placed on top of the horizontal panel insulation allowing access for a bare metal visual examination. Each of the lower head penetration nozzles was examined for 360 degrees (in 90 degree quadrants) and the entire examination was recorded on a videotape.

The bottom head had rust colored stains attributed to be from previous cavity seal leakage. No buildup of deposits were noted on the J-groove welds and adjacent areas. There was no indication of leakage from the J-groove welds, which would have easily penetrated the stained surface.

9. What material deficiencies (i.e., cracks, corrosion, etc.) were identified that

required repair?

None. The bare metal remote visual inspections did not identify any materiel deficiencies associated with the LHP nozzles.

10.

What, if any, impediments to effective examinations, for each of the applied nondestructive examination methods, were identified (e.g., insulation, instrumentation nozzle distortion)?

None. There were no impediments to the remote visual examinations. Access to the LHP nozzles was provided through one of the twelve bottom head peripheral removable insulation panels. A minimum clearance of approximately eight inches existed between the bottom radius of the vessel and the horizontal insulation panels. Each of the lower head penetration nozzles was examined for 360 degrees (in 90 degree quadrants) and the entire examination was recorded on a videotape.

11.

Did the licensee perform appropriate follow-on examinations for indications of boric acid leaks from pressure-retaining components above the RPV lower head?

There were rust colored stained areas attributed to be from previous cavity seal leakage. No buildup of deposits were noted.

12.

Did the licensee take any chemical samples of the deposits? What type of chemical analysis was performed (e.g., Fourier Transform Infrared (FTIR), what constituents were looked for (e.g., boron, lithium, specific isotopes), and what were the licensees criteria for determining any boric acid deposits were not from RCS leakage (e.g., Li-7, ratio of specific isotopes, etc.)?

No. There were no deposits from which to take samples, only rust colored stains.

13.

Is the licensee planning to do any cleaning of the head?

No. There were no deposits; only stains.

14.

What are the licensees conclusions regarding the origin of any deposits present and what is the licensees rationale for the conclusions?

No deposits were identified.

c. Findings

No findings of significance were identified.

.2 TI 2515/156, Offsite Power System Operational Readiness

a. Scope

The inspectors performed an operational readiness review of the offsite power (OPS)systems in response to TI 2515/156, Offsite Power System Operational Readiness.

Specifically, the inspectors gathered and reviewed licensee data supporting the following requirements:

  • Appendix A to 10 CFR Part 50, General Design Criterion (GDC) 17, Electrical Power Systems, to minimize the likelihood of losing offsite power on loss of the generating unit;
  • Appendix B to 10 CFR Part 50, Criterion III, Design Control, to confirm the design interface between the nuclear power plant (NPP) and the regional transmission operator (RTO);
  • Criterion XVI, Corrective Actions, to confirm the licensees assessment of the industry operating experience from the August 14, 2003 grid event;
  • licensee TSs for determining operability of the OPS; and
  • the licensees assumptions used in the station blackout analysis performed per 10 CFR 50.63, Loss of All Alternating Current Power, to determine an acceptable coping time.

The inspectors also reviewed the licensees requirements for assessing risk when performing work on the OPS or the emergency onsite power systems per 10 CFR 50.65(a)(4).

b. Observations and Findings

No findings of significance were identified. Based on the inspection, no immediate operability issues were identified. In accordance with TI 2515/156 reporting requirements, the inspectors provided the required data to the headquarters staff for further analysis. Therefore, this TI is closed for both units.

4OA6 Meetings

.1 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 July 1, 2004. The inspectors did review and dispose of two proprietary documents. The inspectors asked the licensee whether any other materials examined during the inspection should be considered proprietary. No other proprietary information was identified.

.2 Interim Exit Meeting

An interim exit meeting was conducted for:

  • Maintenance Effectiveness Periodic Evaluation with Mr. S. Kuczynski on April 30, 2004.
  • Inservice Inspection and Temporary Instruction TI 2515/152 with Mr. S. Kuczynski on March 31, 2004.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Kuczynski, Site Vice President
D. Hoots, Plant Manager
B. Adams, Engineering Director
D. Combs, Site Security Manager
B. Dean, Maintenance Rule Coordinator
D. Goldsmith, Radiation Protection Director
W. Grundmann, Regulatory Assurance Manager
K. Hansing, Nuclear Oversight
Y. In, PRA Engineer
S. Kerr, Chemistry Manager
S. Koernschild, Inservice Inspection
R. Kolo, Training Manager
R. McBride, Inservice Inspection
D. Palmer, Radiation Protection - ALARA
J. Smith, Byron Engineering
M. Snow, Work Management Director
S. Stimac, Operations Manager
B. Youman, Maintenance Manager

Nuclear Regulatory Commission

A. Stone, Chief, Projects Branch 3, Division of Reactor Projects
G. Dick, Project Manager, Office of Nuclear Reactor Regulation

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000454/2004004-01 NCV Failure to Identify Several Situations of Scaffolds Not
05000455/2004004-01 Meeting the Seismic Clearance Specifications (Section 4OA2.2)

Closed

05000454/2003003-01 LER Licensed Maximum Power Level Exceeded Due to
05000455/2003003-01 Inaccuracies in Feedwater Ultrasonic Flow Measurements Caused by Signal Noise Contamination (Section 4OA3.2)

Discussed

50-454/03-02-03 URI Evaluation for Unit 1 Potentially Exceeding Licensed Thermal Power Limits (Sections 4OA3.2)

LIST OF DOCUMENTS REVIEWED

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