IR 05000454/2006005
| ML070430564 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 02/12/2007 |
| From: | Richard Skokowski NRC/RGN-III/DRP/RPB3 |
| To: | Crane C Exelon Generation Co |
| References | |
| IR-06-005 | |
| Download: ML070430564 (51) | |
Text
ary 12, 2007
SUBJECT:
BYRON STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000454/2006005 AND 05000455/2006005
Dear Mr. Crane:
On December 31, 2006, 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 January 16, 2007, with Mr. Dave Hoots 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.
This report documents one NRC-identified finding of very low safety significance (Green).
This finding did not involve a violation of NRC requirements.
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/
Richard A. Skokowski, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-454, 50-455 License Nos. NPF-37, NPF-66 Enclosure: Inspection Report 05000454/2006005 and 05000455/2006005 w/Attachment: Supplemental Information cc w/encl: Site Vice President - Byron Station Plant Manager - Byron Station Regulatory Assurance Manager - Byron Station Chief Operating Officer Senior Vice President - Nuclear Services Vice President - Mid-West Operations Support Vice President - Licensing and Regulatory Affairs Director Licensing Manager Licensing - Braidwood and Byron Senior Counsel, Nuclear Document Control Desk - Licensing Assistant Attorney General Illinois Emergency Management Agency State Liaison Officer, State of Illinois State Liaison Officer, State of Wisconsin Chairman, Illinois Commerce Commission B. Quigley, Byron Station
SUMMARY OF FINDINGS
IR 05000454/2006005, 05000455/2006005;10/01/2006-12/31/2006; 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 Emergency Preparedness, Licensed Operator Requalification Training and Temporary Instruction 2515/169, Mitigating Systems Performance Index Verification. These inspections were conducted by regional inspectors and the resident inspectors. Two Green findings were described in this report, one of which was a non-cited violation (NCV) under the traditional enforcement process. The NCV was originally provided to the licensee in a separate letter, dated December 5, 2006. The emergency preparedness portion of this inspection is being tracked using Inspection Report 05000454/2006012, 05000455/2006012. The significance of most findings is indicated by their color (Green, White, yellow, Red) using Inspection Manual Chapter 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. 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 finding of very low safety significance associated with the failure to maintain control of the setpoints for constant level oilers. This condition increased the challenges to the proper functioning of the lubricating oil and thus to the bearings to the safety-related pumps.
This finding was considered more than minor because of the potential for the degradation of oil/bearings to safety-related components which would increase their unavailability and unreliability. This finding was of very low safety significance because no bearings had been damaged due to the high or low oil levels despite operating in this condition for many years and the oil had only been moderately impacted. The licensees corrective actions included assessing the setpoints of other safety related and non-safety related pumps, verifying no pumps had been damaged, and revising the work order template to include the reference to the corporate procedure for the setting of constant level oilers. No violation of NRC requirements occurred.
(Section 4OA2.3).
Licensee Identified Violations
None
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at or near full power throughout the inspection period with the following exception:
- On October 23, 2006, the unit returned to full power from a refueling outage that started on September 10, 2006.
- On October 25, 2006, the unit reduced power to 95 percent to swap feedwater pumps.
The unit returned to full power on October 26, 2006.
Unit 2 operated at or near full power throughout the inspection period with the following exceptions:.
- On October 21, 2006, the unit reduced power to 85 percent to perform turbine throttle and governor valve surveillances. The unit returned to full power on October 22,
REACTOR SAFETY
Cornerstone: Initiating Events, Mitigating Systems, Barrier Integrity and
1R01 Adverse Weather Protection
a. Inspection Scope
The inspectors reviewed the licensees seasonal preparations for operation during the winter months. This was primarily accomplished by verifying that the licensee had completed the requirements for winter readiness as documented in Exelon Nuclear Administrative Procedure WC-AA-107, Seasonal Readiness, Revision 2. The inspectors also reviewed the Updated Final Safety Analysis (UFSAR), Technical Specifications (TS) and other design-bases documents to identify those components that were susceptible to degradation from low temperatures during the winter months.
The inspectors verified that the licensee had addressed these components in preparation for winter operation. In addition, the inspectors selected the following risk-significant support systems/areas for specific review:
- Essential Service Water Cooling Tower;
- Unit 1 and Unit 2 Condensate Storage Tanks; and
- River Screenhouse.
The inspectors also verified that the licensee had taken the appropriate actions for a predicted winter storm, including the potential for icing and severe cold temperatures.
Specifically, the inspectors verified that the licensee had reviewed the impact of the weather against planned work activities, performed walkdowns of areas particularly susceptible to cold weather conditions and discussed weather-related issues during the Operations Shift Turnover briefings and station Plan-of-the-Day meetings.
The inspectors also reviewed selected issue reports (IRs), interviewed plant personnel, and performed plant walkdowns. Documents reviewed as part of this inspection are listed in the Attachment to this report. This review constituted one sample for the onset of a site specific weather-related condition and three annual system review samples.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
.1 Partial Walkdowns
a. Inspection Scope
The inspectors performed one partial walkdown sample 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 determine 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 determine 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:
- Unit 2 Train A Residual Heat Removal System while the Unit 2 Train B RHR Pump was Out of Service.
The inspectors also reviewed selected issues documented in IRs, to determine if they had been properly addressed in the licensees corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R05 Fire Protection
.1 Quarterly Walkdowns
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.
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 inspectors completed eight inspection samples by examining the plant areas listed below to observe conditions related to fire protection:
- Unit 1 Auxiliary Building Elevation 364' General Area (Zone 11.3-0);
- Unit 2 Train B Auxiliary Feedwater Pump Room (Zone 11.4A-1);
- Main Control Room (Zone 2.1-0);
- Unit 2 Lower Cable Spreading Room (Zone 3.2A-2);
- Unit 1 Division 12 ESF Switchgear Room (Zone 5.1-1);
- Unit 2 Train B Diesel Generator Room (Zone 9.1-2);
- Unit 1 Lower Cable Spreading Room (Zone 3.2A-1); and
- Unit 2 Turbine Building 426' General Area (Zone 8.5-2).
The inspectors reviewed selected issues documented in IRs, to determine if they had been properly addressed in the licensees corrective action program. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.2 Drill Observation
a. Inspection Scope
The inspectors assessed the fire brigade performance and the drill evaluators critique during a fire brigade drill conducted on November 15, 2006. The drill simulated a fire in the Stores warehouse with participation from several offsite local fire departments.
The inspectors focused on command control of the fire brigade activities; fire fighting and communication practices; material condition and use of fire fighting equipment; and implementation of pre-fire plan strategies. The inspector also observed the communication, command and control and coordination between the onsite fire brigade and the offsite team of responders. The inspectors evaluated the fire brigades performance using the licensees established fire drill performance procedure criteria.
The inspectors also reviewed the qualification and training of the fire brigade and the required Appendix R fire fighting equipment. This inspection sample was started in our last report period and was completed in this report.
Documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures
.1 External Flooding Review
a. Inspection Scope
The inspectors reviewed Byrons flood analysis and design basis documents to identify design features important to external flood protection, and reviewed the external flood protection measures in place to prevent or mitigate effects of the probable maximum flood and the probable maximum precipitation. This review included a general area walkdown of the outdoor plant area and perimeter to assess the condition and readiness of the plant drainage system components to perform their function during a probable maximum flood or probable maximum precipitation scenario.
This review represented one annual inspection sample. Documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.2 Internal Flooding Review
a. Inspection Scope
The inspectors evaluated the internal flooding controls for the following area:
- Auxiliary Building Elevation 364 around the Component Cooling Water Pumps including the covers over the Essential Service Water Pumps.
This review represented one inspection sample. 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
a. Inspection Scope
The inspectors completed one annual testing and performance review inspection sample by observing and evaluating the licensees inspection of the following safety-related heat exchanger:
- Unit 1 Train A Essential Service Water Pump Oil Cooler Inspection.
The inspectors also reviewed selected issues documented in IRs, to determine if they had been properly addressed in the licensees corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R08 Inservice Inspection Activities
.1 Piping systems Inservice Inspection Activities
a. Inspection Scope
From September 11, 2006 through September 15, 2006, the inspectors conducted a review of the implementation of the licensees Risk-Informed (RI) ISI program for monitoring degradation of the reactor coolant system boundary and the risk significant piping system boundaries. The inspectors selected the licensees RI-ISI program components and American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI required examinations and Code components in order of risk priority as identified in Section 71111.08-03 of the NRC Inspection Procedure, based upon the ISI activities available for review during the on-site inspection period.
The inspectors observed two types of nondestructive examination (NDE) activities, specifically Ultrasonic Examination and Visual Examination, to evaluate compliance with the ASME Code Section XI and Section V requirements and to verify that indications and defects (if present) were dispositioned in accordance with the ASME Code Section XI requirements. The following NDE activities were observed:
- Ultrasonic Examination of safety injection line welds 1SI01B-24-C03, 1SI01B-24-C04, 1SI01B-24-C05;
- Ultrasonic Examination of feedwater line weld 1FW87CA-6-C07A, a pipe to elbow weld; and
- Visual Examination of main steam pipe support snubber 1MS08007S1 and component cooling system pipe support snubber 1CC24013S.
There were no examinations with recordable indications that had been accepted by the licensee for continued service.
The inspectors reviewed a pressure boundary weld for a Class 1 system which was completed since the beginning of the previous refueling outage to determine if the welding acceptance and preservice examinations (e.g. visual, dye penetrant, and weld procedure qualification tensile tests) were performed in accordance with ASME Code Sections III, V, IX, and XI requirements. Specifically, the inspectors reviewed a weld associated with the following work activity;
- Repair (welding) of ISI Class 1 aux spray header check valve 1CV8377.
The inspectors performed a review of ISI-related problems that were identified by the licensee and entered into the corrective action program, conducted interviews with licensee staff and reviewed licensee corrective action records to determine if:
- the licensee had described the scope of the ISI-related problems;
- the licensee had established an appropriate threshold for identifying issues;
- the licensee had evaluated industry generic issues related to ISI and pressure boundary integrity; and
- the licensee implemented appropriate corrective actions.
The inspectors performed these reviews to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.
The reviews as discussed above counted as one inspection sample.
b. Findings
No findings of significance were identified.
.2 Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities
a. Inspection Scope
Unit 1 is in the low susceptibility ranking category. No control rod drive mechanism NDE examinations were reviewed to be performed this outage. Therefore, no inspection sample was credited.
b. Findings
No findings of significance were identified.
.3 Boric Acid Corrosion Control (BACC) ISI
a. Inspection Scope
From September 11, 2006 through September 14, 2006, the inspectors reviewed the BACC inspection activities conducted pursuant to licensee commitments made in response to NRC Generic Letter 88-05 Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary.
The inspectors conducted a direct observation of BACC visual examination activities to evaluate compliance with licensee BACC program requirements and 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. Specifically, on September 11, 2006, following the Unit 1 shutdown, the inspectors reviewed a sample of BACC visual examination activities through direct observation. This walkdown was begun with the Unit in Mode 3 at full operating pressure and temperature. The inspectors observed the visual inspections to determine if locations where boric acid leaks can cause degradation of safety significant components were emphasized.
The inspectors also reviewed the visual examination procedures and examination records for the BACC examination to determine if degraded or non-conforming conditions were properly identified in the licensee's corrective action system.
The inspectors reviewed the engineering evaluations performed for the following corrective action documents to ensure that ASME Code wall thickness requirements were maintained:
- IR 477473, component 1SI059A; Containment Recirc Sump to Containment Spray/Residual Heat Removal Test Connection Isolation Valve; and
- IR 306134; component 1 RC8029C; Unit 1Loop C Reactor Coolant Bypass Vent Valve.
The inspectors also reviewed a number of boric acid leak corrective actions to determine if they were consistent with the requirements of the ASME code and 10 CFR Part 50, Appendix B, Criterion XVI. The documents reviewed during this inspection are listed in the Attachment to this report. These reviews counted as one inspection sample.
b. Findings
No findings of significance were identified.
.4 Steam Generator Tube ISI
Steam generator inspections were not scheduled to be performed this outage.
Therefore, no inspection sample was credited.
.5 Identification and Resolution of Problems
The inspectors performed a review of ISI-related problems that were identified by the licensee and entered into the corrective action program, conducted interviews with licensee staff and reviewed licensee corrective action records to determine if;
- the licensee had described the scope of the ISI-related problems;
- the licensee had established an appropriate threshold for identifying issues;
- the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity; and
- the licensee implemented appropriate corrective actions.
The inspectors performed these reviews to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
.1 Resident Inspector Quarterly Review
a. Inspection Scope
The inspectors completed one inspection sample by observing and evaluating the response to a steam generator tube rupture with a loss of pressurizer control. 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.
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 licensees evaluators to determine whether they also noted the issues and discussed them in the critique at the end of the session. The inspectors verified that minor issues were placed into the licensees corrective action program.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.2 Facility Operating History
a. Inspection Scope
The inspectors reviewed the plants operating history from October 2004 through October 2006 to identify operating experience that was expected to be addressed by the Licensed Operator Requalification Training (LORT) program. It was verified that the identified operating experience had been addressed by the facility licensee in accordance with the stations approved Systems Approach to Training (SAT) program to satisfy the requirements of 10 CFR 55.59 ©, Requalification program requirements.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.3 Licensee Requalification Examinations
a. Inspection Scope
The inspectors performed a biennial inspection of the licensees LORT test/examination program for compliance with the stations SAT program which would satisfy the requirements of 10 CFR 55.59 © (4), Evaluation. The reviewed operating examination material consisted of six operating tests, each containing two dynamic simulator scenarios and six job performance measures (JPMs). The written examinations reviewed consisted of four written examinations, each including a Part A, Plant and Control Systems and Part B, Administrative Controls / Procedure Limits. Each part of the exam contained 15 questions. The inspectors reviewed the annual requalification operating test and biennial written examination material to evaluate general quality, construction, and difficulty level. The inspectors assessed the level of examination material duplication from week-to-week during the current year operating test. The examiners assessed the amount of written examination material duplication from week-to-week for the written examination administered in 2006. The inspectors reviewed the methodology for developing the examinations, including the LORT program 2-year sample plan, probabilistic risk assessment insights, previously identified operator performance deficiencies, and plant modifications.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.4 Licensee Administration of Requalification Examinations
a. Inspection Scope
The inspectors observed the administration of a requalification operating test to assess the licensees effectiveness in conducting the test to ensure compliance with 10 CRF 55.59 © (4), Evaluation. The inspectors evaluated the performance of two crews in parallel with the facility evaluators during four dynamic simulator scenarios and evaluated various licensed crew members concurrently with facility evaluators during the administration of several JPMs. The inspectors assessed the facility evaluators ability to determine adequate crew and individual performance using objective, measurable standards. The inspectors observed the training staff personnel administer the operating test, including conducting pre-examination briefings, evaluations of operator performance, and individual and crew evaluations upon completion of the operating test. The inspectors evaluated the ability of the simulator to support the examinations. A specific evaluation of simulator performance was conducted and documented under Section 1R11.8, Conformance With Simulator Requirements Specified in 10 CFR 55.46, of this report.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.5 Examination Security
a. Inspection Scope
The inspectors observed and reviewed the licensees overall licensed operator requalification examination security program related to examination physical security (e.g., access restrictions and simulator considerations) and integrity (e.g., predictability and bias) to verify compliance with 10 CFR 55.49, Integrity of examinations and tests.
The inspectors also reviewed the facility licensees examination security procedure, any corrective actions related to past or present examination security problems at the facility, and the implementation of security and integrity measures (e.g., security agreements, sampling criteria, bank use, and test item repetition) throughout the examination process.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.6 Licensee Training Feedback System
a. Inspection Scope
The inspectors assessed the methods and effectiveness of the licensees processes for revising and maintaining its LORT Program up to date, including the use of feedback from plant events and industry experience information. The inspectors reviewed the licensees quality assurance oversight activities, including licensee training department self-assessment reports. The inspectors evaluated the licensees ability to assess the effectiveness of its LORT program and their ability to implement appropriate corrective actions. This evaluation was performed to verify compliance with 10 CFR 55.59 © Requalification program requirements and the licensees SAT program.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.7 Licensee Remedial Training Program
a. Inspection Scope
The inspectors assessed the adequacy and effectiveness of the remedial training conducted since the previous biennial requalification examinations and the training from the current examination cycle to ensure that they addressed weaknesses in licensed operator or crew performance identified during training and plant operations.
The inspectors reviewed remedial training procedures and individual remedial training plans. This evaluation was performed in accordance with 10 CFR 55.59 © Requalification program requirements and with respect to the licensees SAT program.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.8 Conformance With Operator License Conditions
a. Inspection Scope
The inspectors reviewed the facility and individual operator licensees' conformance with the requirements of 10 CFR Part 55. The inspectors reviewed the facility licensee's program for maintaining active operator licenses and to assess compliance with 10 CFR 55.53
- (e) and (f). The inspectors reviewed the procedural guidance and the process for tracking on-shift hours for licensed operators and which control room positions were granted watch-standing credit for maintaining active operator licenses.
The inspectors reviewed the facility licensee's LORT program to assess compliance with the requalification program requirements as described by 10 CFR 55.59 c.
Additionally, medical records for seven licensed operators were reviewed for compliance with 10 CFR 55.53 (I).
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.9 Conformance With Simulator Requirements Specified in 10 CFR 55.46
a. Inspection Scope
The inspectors assessed the adequacy of the licensees simulation facility (simulator)for use in operator licensing examinations and for satisfying experience requirements as prescribed in 10 CFR 55.46, Simulation Facilities. The inspectors also reviewed a sample of simulator performance test records (i.e., transient tests, malfunction tests, steady state tests, and core performance tests), simulator discrepancies, and the process for ensuring continued assurance of simulator fidelity in accordance with 10 CFR 55.46. The inspectors reviewed and evaluated the discrepancy process to ensure that simulator fidelity was maintained. Open simulator discrepancies were reviewed for importance relative to the impact on 10 CFR 55.45 and 55.59 operator actions as well as on nuclear and thermal hydraulic operating characteristics. The inspectors conducted interviews with members of the licensees simulator staff about the configuration control process and completed the IP 71111.11, Appendix C, checklist to evaluate whether or not the licensees plant-referenced simulator was operating adequately as required by 10 CFR 55.46 © and (d).
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
.10 Annual Operating Test Results and Biennial Written Examination Results
a. Inspection Scope
The inspectors reviewed the pass/fail results of the individual biennial written examinations, and the annual operating tests (required to be given annually per 10 CFR 55.59(a)(2)) administered by the licensee during calender year 2006. The overall written examination and operating test results were compared with the significance determination process in accordance with NRC Manual Chapter 0609, Appendix I, Operator Requalification Human Performance Significance Determination Process.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors completed three 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 structures, systems, and/or components:
- Testing of control switches used for shutdown outside of control room;
- Main Steam Safety Valve Enclosure Ventilation Damper Failures; and
- Unit 1 Train A Emergency Diesel Generator Relay Failures.
The inspectors evaluated the licensee's appropriate handling of structures, systems, and components (SSC) condition problems in terms of appropriate work practices and characterizing reliability issues. Equipment problems were screened for review using a problem oriented approach. Work practices related to the reliability of equipment maintenance were observed during the inspection period. Items chosen were risk significant, and the extent of condition was reviewed as applicable. Work practices were reviewed for contribution to potential degraded conditions of the affected SSCs. Related work activities were observed and corrective actions were discussed with licensee personnel. The licensee's handling of the issues being reviewed was evaluated under the requirements of the maintenance rule.
The inspectors also reviewed selected issues documented in IRs, to determine if they had been properly addressed in the licensees corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
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 other related documents to determine 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 completed three inspection samples by reviewing the following activities:
- Unit 2 Train B Essential Service Water Pump Work Window while the Essential Service Water Basin Level was lowered for Repair;
- Unit 2 Train B Residual Heat Removal Pump Work Window while DC Bus 212 was cross-tied to DC Bus 112; and
- Unit 1 DC Bus 112 Battery Charger was out of service while System Auxiliary Transformer 142-2 was in a Work Window.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
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 two inspection samples by reviewing the following evaluations and issues:
- Constant Level Oilers on Safety-Related Pumps Found without Setpoint Control; and
- Unit 2 Essential Service Water Damaged Outboard Thrust Bearing Housing.
The inspectors compared the operability and design criteria in the appropriate sections of the TS including the TS Basis, the Technical Requirements Manual (TRM) and the UFSAR to the licensees evaluations to determine 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 licensee procedures. The inspectors also discussed the details of the evaluations with the shift managers and appropriate members of the licensees engineering staff.
The inspectors also reviewed selected issues documented in IRs, to determine if they had been properly addressed in the licensees corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R19 Post Maintenance Testing
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 determine 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, and other related documents to evaluate this area.
The inspectors completed seven inspection samples by observing and evaluating the post maintenance testing subsequent to the following maintenance activities:
- Replacement of Dual Zone Board for Fire Detection System Zone 1D-47/1D-48
& 1S-36;
- Unit 1 Train A Containment Recirculation Sump Outlet Isolation Valve (1SI8811A) Relay Replacement;
- Unit 2 Train A Residual Heat Removal Pump Work Window;
- Unit 1 Train A Essential Service Water Pump Oil Cooler Inspection;
- Unit 2 Train B Essential Service Water Pump Work Window; and
- Unit 1 Loop C Main Steam Safety Valve Enclosure Damper Modification.
The inspectors also reviewed selected issues documented in IRs to determine if they had been properly addressed in the licensees corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R20 Refueling and Outage Activities
a. Inspection Scope
The inspectors observed the licensees performance during Refueling Outage B1R14 beginning September 10, 2006. The licensee returned the unit to full power on October 23, 2006. One inspection sample was completed for this report.
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 Reasonably Achievable] briefings. Other major outage activities evaluated during this inspection period included evaluating the licensee's control of:
- containment penetrations in accordance with the TS;
- structures, systems or components (SSCs) which could cause unexpected reactivity changes;
- flow paths, configurations, and alternate means for reactor coolant system inventory addition;
- SSCs which could cause a loss of inventory;
- reactor coolant system 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 startup, including the approach to criticality and power ascension, to verify that the licensee controlled the plant startup in accordance with the TS and established procedures. In addition, the inspectors completed numerous visual inspections inside the Unit 1 containment. This included a tour of the Unit 1 containment at Mode 4 before plant startup so that the inspectors could assess the material condition of equipment inside containment before containment closure. During the visual inspections the inspectors focused on the material condition of the equipment and housekeeping.
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 inspection activities performed included:
- 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 pump suctions during loss-of-coolant accident conditions.
- inspection of the licensees approach to initial criticality, initial criticality, core reload physics testing, and turbine generator rolling and tie in to the off-site grid.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors witnessed selected surveillance tests and/or reviewed test data to determine that the equipment tested using the surveillance procedures met the TS, TRM, UFSAR and licensee procedural requirements. The inspectors also reviewed applicable design documents including plant drawings, to verify 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 ensuring mitigating systems capability and barrier integrity.
These activities represented one routine and one Inservice Testing sample. The following surveillance tests were selected:
- 1BOSR 0.5-2.AF.1-1, Stroke Time Testing for Auxilary Feedwater System Valves 1AF013 A through D, Revision 3 (Inservice Testing sample); and
- 0BVSR 2.7.A.3, Unit 0 Deep Well Pump Make-up Flow Verification, Revision 3.
Additionally the inspectors used the documents listed in the attachment to this report to determine that the testing met the frequency requirements; that the tests were conducted in accordance with procedures, that the test acceptance criteria were met; and that the results of the tests were properly reviewed and recorded. The inspectors verified that the individuals performing the tests were qualified to perform the test in accordance with the licensees requirements, and that the test equipment used during the test were calibrated within the specified periodicity. In addition, the inspectors interviewed operations, maintenance, and engineering department personnel regarding the tests and test results.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications
a. Inspection Scope
The inspectors completed two inspection samples by evaluating the following temporary plant modifications on risk significant equipment:
- Unit 1 B Loop Wide Range T-hot Temperature Indication; and
- Jumper to Defeat Slow Start Capability of the Unit 1 Train A Emergency Diesel Generator.
The inspectors reviewed this temporary plant modification to determine that the instructions were consistent with applicable design modification documents and that the modification did not adversely impact system operability or availability. The inspectors verified that the licensee controlled temporary modifications in accordance with Nuclear Station Procedure NSP CC-AA-112, Temporary Configuration Changes, Revision 11.
The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1EP4 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
The inspectors completed a screening review of Revision 17 of the Byron Station Annex of the Exelon Standardized Emergency Plan to determine whether changes identified in this Annex revision may have reduced the effectiveness of the licensees emergency planning. The screening review of Revision 17 does not constitute approval of the changes and, as such, the changes are subject to future NRC inspection to ensure that the emergency plan continues to meet NRC regulations.
These activities completed one inspection sample. The documents reviewed during this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1EP6 Drill Evaluation
a. Inspection Scope
On October 23, 2006, the inspectors complete one inspection sample by observing an emergency preparedness drill. The inspectors assessed the licensees drill performance and looked for weaknesses in the risk significance areas of emergency classification, notification and protective action development. The inspectors observed the licensees performance from the simulator control room. The inspectors compared issues noted during their observations to those identified during the licensees critique.
Additionally, the inspectors verified that items identified during the licensees critique were appropriately entered into their corrective action 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
2OS1 Access Control to Radiologically Significant Areas (IP 71121.01)
.1 Inspection Planning
a. Inspection Scope
The inspectors reviewed the licensee Performance Indicator for the Occupational Exposure Cornerstone for followup. This review represented one sample.
b. Findings
No findings of significance were identified.
.2 Plant Walk Downs and Radiation Work Permit Reviews
a. Inspection Scope
The inspectors examined the licensees physical and programmatic controls for highly activated or contaminated materials (non-fuel) stored within spent fuel and other storage pools. This review represented one sample.
b. Findings
No findings of significance were identified.
.3 Problem Identification and Resolution
a. Inspection Scope
The inspectors reviewed the licensees self-assessments, audits, Licensee Event Reports, and Special Reports related to the access control program since the last inspection. The inspectors assessed whether identified problems were entered into the corrective action program for resolution. This review represented one sample.
The inspectors assessed if the licensees self-assessment activities were also identifying and addressing repetitive deficiencies or significant individual deficiencies in problem identification and resolution. This review represented one sample.
The inspectors reviewed licensee documentation packages for all Performance Indicator events occurring since the last inspection. The inspectors reviewed any of these Performance Indicator events that involved dose rates >25 R/hr at 30 centimeters or
>500 R/hr at 1 meter and assessed what barriers had failed and if there were any barriers left to prevent personnel access. The inspectors reviewed unintended exposures >100 mem total effective dose equivalent (or >5 rem shallow dose equivalent or >1.5 rem lens dose equivalent) to assess if there were any overexposures or substantial potential for overexposure. This review represented one sample.
b. Findings
No findings of significance were identified.
.4 Job-In-Progress Reviews
a. Inspection Scope
The inspectors reviewed the adequacy of radiological controls, radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls during job performance observations. This review represented one sample.
The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel for high radiation work areas with significant dose rate gradients (factor of 5 or more). This review represented one sample.
b. Findings
No findings of significance were identified.
.5 High Risk Significant, High Dose Rate, High Radiation Area and Very High Radiation
Area Controls
a. Inspection Scope
The inspectors discussed high dose rate-high radiation area and very high radiation area controls and procedures with the Radiation Protection Manager. The discussion focused on any procedural changes since the last inspection. The inspectors reviewed changes to licensee procedures and assessed that changes did not substantially reduce the effectiveness and level of worker protection. This review represented one sample.
The inspectors discussed with first-line radiation protection supervisors, or equivalent positions having backshift radiation protection oversight authority, the controls in place for special areas that have the potential to become very high radiation area during certain plant operations. The inspectors reviewed how the required communications between the radiation protection group and other involved groups would occur beforehand in order to allow corresponding timely actions to properly post and control the radiation hazards. This review represented one sample.
The inspectors verified adequate posting and locking of all entrances to all accessible high dose rate-high radiation areas and very high radiation areas. This review represented one sample.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA2 Identification and Resolution of Problems
.1 Review of Items Entered into the Corrective Action Program:
As required by Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed screening of all items entered into the licensees corrective action program. This was accomplished by reviewing the description of each new Issue Report and attending selected daily management review committee meetings. Documents reviewed are listed in the Attachment to this report.
.2 Annual Sample - Operator Workarounds
a. Inspection Scope
The inspectors reviewed the licensees ability to identify operator workarounds as well as the timeliness by which they were addressed. The inspectors conducted walkdowns of the plant in order to assess for any deficiencies in the plant that may prevent an operator from performing their job in a timely and safe manner. In addition, a thorough records review was conducted which included the adverse condition monitoring program, the temporary configuration change log, the degraded equipment list, the approved operator aid list, and a historical review of issue reports for potential operator workarounds. Documents reviewed as part of this inspection are listed in Attachment to this report. This review represented one sample.
b. Assessment and Observations The licensees corporate procedure for classifying operator workarounds created the category of operator challenges which was differentiated from an operator workaround based on the challenge being an obstacle to normal plant operation while the workaround was described as an obstacle to emergency or safe plant operation (TS/safety-related equipment). There were two items classified as operator challenges and one identified operator workaround. The inspectors noted that the use of a separate category for operator challenges was an acceptable management tool.
However, it may have created a vulnerability allowing the licensee to rationalize not always addressing operational issues in a timely manner. Interviews with operators determined that they liked the two tier system as they felt it allowed for a lower threshold of items to be added to the operators challenges list and they had not observed a decline in the timeliness of addressing operational issues.
c. Findings
No findings of significance were identified.
.3 Semiannual Review to Identify Trends
a. Inspection Scope
The inspectors performed a review of the licensees Corrective Action Program (CAP)and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment and corrective maintenance issues with additional insights from the daily inspector CAP item screening discussed in Section 4OA2.1. The review also included issues documented outside of the normal CAP including focus area self-assessments, corrective maintenance backlog reports, common cause analysis reports, component status reports, and maintenance rule assessments. The inspectors review nominally considered the 6-month period of July 2006 through December 2006, although examples expanded beyond those dates when the scope of the trend warranted. The inspectors compared and contrasted their results with the results contained in the licensees mechanisms for identifying and correcting trends.
The review was accomplished by grouping IRs into broad categories during the daily screenings. These groups included, but were not limited to, items involving the same issue, same equipment/components, or the same program. This activity completed one sample.
b. Findings and Observations
Finding
Introduction:
A finding of very low safety significance (Green) was identified when the inspectors identified the licensee failed to maintain setpoint control of the constant level oilers. This condition increased the challenges to the proper functioning of the lubricating oil and thus to the bearings of the safety-related pumps. This finding was of very low safety significance because no bearings had been damaged due to the high or low oil levels despite operating in this condition for many years and the oil had only been moderately impacted.
Finding
Description:
The inspectors observed that the constant level oilers on the five safety-related component cooling water pumps (CCW) were all set at different heights with respect to their associated bearings. The vendor recommended that the bearings should not be submerged more than one-half the diameter of the bearing. Since the bearing diameter was small (less than one half inch) and the largest variation between setpoints was 3/8" there was a possibility that the setpoints were not correct. Low oil level can result in an insufficient amount of oil to the bearing. High oil levels can cause air to be pushed into the oil resulting in frothing, and thinning of the oil, which can cause inadequate heat removal and bearing damage. The licensee wrote IRs 555893 and 555201 to address this concern. The licensee also stated that, although they were in the process of reducing oil leaks and had determined that some constant level oilers had been installed on the wrong side of the pumps, they had not noticed the setpoint variation.
Licensee personnel determined that there was a corporate procedure, MA-AA-734-400, for setting the level of the constant level oilers but had also determined that they had not incorporated the procedure into maintenance work packages. The licensee performed a review and determined that, while there was a potential to damage the pump bearings due to either high or low oil levels, no history bearing damage that could be attributed to improper oil levels.
The licensee implemented corrective actions to assess the setpoint including:
- incorporating MA-AA-734-400 into work packages;
- training operators how to recognize the setpoint of the oilers;
- assessing the setpoints of other safety-related pumps; and
- incorporating the setpoint assessment into the leak reduction efforts.
Finding
Analysis:
The inspectors determined that the failure to have setpoint control of the safety-related constant level oilers was a performance deficiency warranting a significance evaluation in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued September 30, 2005. This finding was considered more than minor because of the potential for degradation of oil/bearings to safety-related components that would increase their unavailability and unreliability.
The inspectors performed a phase 1 significance determination of this issue, using IMC 0609, Significance Determination Process, dated November 22, 2005, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, dated November 22, 2005. As stated the failure to have setpoint control of the constant level oilers was a performance deficiency that could affect the core decay heat removal system and was considered more than minor. This met the mitigating systems cornerstone screening criteria as discussed in IMC 0609 Appendix A.
In accordance with IMC 0609, Appendix A, Attachment 1, the inspectors determined that this finding should be screened as Green. Specifically because the finding did not result in a Loss of Operability, did not result in a loss of system safety function, did not result in an actual loss of safety function of a single Train for greater than its TS Allowed Outage Time, did not represent an actual loss of safety function of one or more non-TS trains of equipment designated as risk-significant, and was not related to a seismic, flooding or severe weather initiating events. Therefore, the inspectors concluded that this finding was of very low safety significance (Green) (FIN 05000454/2006005-01; 05000455/2006005-01)
Finding
Enforcement:
The inspectors concluded that no violation regulatory requirements had occurred as there was no procedure requirement in the maintenance work packages to check/adjust the constant level oiler setpoints, no significant oil degradation had occurred, and no bearings had been damaged due to the lack of setpoint control.
Observations: The inspectors determined that licensee employees were writing IRs with a low threshold, that employees at all levels of the organization were writing IRs, and that IRs were written for all issues of significance. Collectively, this provided one indication of a safety conscious work environment.
The licensee identified a number of trends. Each trend was documented in an IR and evaluated to determine if a common cause evaluation was necessary. The licensee-identified trends were identified by a combination of the work groups involved with the issues, department or station corrective action program coordinators, department managers, and the nuclear oversight group. This indicated that multiple groups were looking for and identifying meaningful trends.
The inspectors did not identify any new trends or potential trends that had not been already identified by the licensee. The inspectors identified a trend in the area of procedural adherence but noted that the licensee had already identified this trend and initiated corrective actions. The inspectors did note several examples of IRs written which did not identify the procedural adherence aspects of the issues. In all cases the procedural adherence aspect was of minor safety significance in accordance with the guidance provided in IMC 0612. Examples included:
- On January 4, 2006, the Unit 1 Train B (1B) DG was being operated for a routine surveillance. The operators did a prompt controlled shutdown of the DG when the right bank air intake manifold temperature started swinging and reached 162EF. This exceeded the procedural limit of 160EF. A note in the surveillance procedure (BOP DG-11T2) stated that the DG was to be tripped if the procedural limit of 160EF was exceeded. IR 438719 was written addressing the cause of the high temperature and performed an operability assessment. This IR did not address the operators performance of an immediate shutdown of the DG instead of tripping the DG as required by procedure.
As the procedural limit of 160EF was for normal mode only and was not a limit required to be followed when the DG was started in the emergency mode and as the operability assessment determined the DG would have been able to meet design requirements at the increased temperature this failure to follow procedure was a minor violation in accordance with the guidance provided in IMC 0612.
During the followup to this issue the inspectors noted other IRs on a similar condition. For example, IR 350579 noted a problem with the 1B DG intake manifold temperature swinging in July 2005 and problems were noted with the air intake manifold temperature swinging in September 2000 on the 1A DG.
- During the review of IR 571193, regarding a design problem with containment radiation monitor 2PR11J the inspectors noted a procedural adherence issue.
The IR addressed a problem achieving the procedurally required high flow rate during a calibration check of flow control switch 2FS-PR135. During the calibration the instrument mechanics (IM) were required to get the air flow through the flow switch up to 3.1 scfm [standard cubic feet per minute]. The IMs were unable to reach the required flow rate without loosening the particulate channel filter plug. This method of reaching the required flow rate was not called out in the calibration procedure (BISR 4.15.4-200). Moreover, the calibration procedure assumed the filter was partially plugged if the flow rate was not reached and directed the IMs to replace the filter. This issue has existed since the equipment was originally installed and the IMs routinely loosened the particulate channel filter plug instead of replacing the filter.
The IR written to address this concern recognized and corrected the need to replace the filters, however, it did not address the concern regarding the IMs failure to follow the procedure by loosening the filter plug to obtain the specified flow rate. This failure to follow procedure was a minor violation in accordance with the guidance provided in IMC 0612 because the calibration verified that upon a high flow condition the associated control valve would to return the flow rate to the required value. The design issues which prevented the flow from reaching the required high value did not affect the instruments ability to perform its intended safety function.
The licensee had already recognized the need to focus on site wide procedure adherence before the inspectors had identified the apparent trend. Procedure adherence had been entered into the Human Performance Excellence Plan along with all of the individual IRs associated with procedural adherence. The licensee generated IR 577579 to formally document the site wide improvement initiative.
4OA3 Event Follow-up
.1 (Closed) LER 454-2006-003-00: Inadvertent Exceeding of TS Action Requirement
Completion Time for Containment Spray Additive System Due to Not Recognizing an Inoperable Condition On August 11, 2006, the licensee identified a pressure boundary weld leak in an ASME Class II pipe of the spray additive system. However, it was not until September 11, 2006, that the licensee recognized that the leak rendered the spray additive system inoperable. Therefore, the licensee failed to repair the leak within 7 days as required by TS 3.6.7. Subsequently, the licensee declared the system inoperable and repaired the leak. Other corrective actions included the development of a new component leak template to convey operability information to shift management and a training improvement plan for operability determination on issue reports. The violation is of very low safety significance because the system does not affect core damage frequency and has no impact on Large Early Release Frequency. This licensee-identified finding involved a violation of TS 3.6.7. The enforcement aspects of the violation were discussed in NRC Inspection Report 05000454/2006003. This LER is closed.
4OA5 Other Activities
Mitigating Systems Performance Index Verification (Temporary Instruction 2515/169)
a. Inspection Scope
The Mitigating System Performance Index (MSPI) was developed to replace the Safety System Unavailability (SSU) indicators previously in use in the Reactor Oversight Process (ROP). The MSPI monitors the unavailability and the unreliability of the same four safety systems that comprise the SSU and it also monitors the cooling water support systems for those four safety systems. The index measures the performance of risk significant functions of these safety systems and was based on plant specific probability risk assessment (PRA) model. The purpose of this Temporary Instruction was to validate the unavailability and unreliability input data and to verify accuracy of the first reporting results for the 2006 2nd quarter.
The inspectors reviewed the licensees basis document and evaluated the implementation of the MSPI against the guidance provided in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 4. The inspectors reviewed selected surveillances that do not render the safety system train unavailable due to short duration of the surveillance or due to credit for operator recovery activities, as defined by NEI 99-02. The inspectors also performed independent verification of selected unavailability and unreliability data using operating logs, maintenance rule record, and condition reports to confirm that the actual data reported was accurate.
b. Evaluation of Inspections Requirements
For the sample selected, did the licensee accurately document the baseline planned unavailability hours for the MSPI systems?
The inspectors identified that the licensee had prepared two sets of baseline data in their basis document. One set of data consisted of the unavailability data from July 2002 to June 2005 and another set of data consisted of the unavailability data from January 2002 to December 2004. However, the data set from July 2002 to June 2005 was used to calculate the reported MSPI.
The inspectors determined that this was not in accordance with the NEI 99-02 guidance, which specified using data from January 2002 to December 2004.
At the close of the inspection period the licensee was in the process of revising the basis document and recalculating the MSPI using the unavailability data set from January 2002 to December 2004. This re-evaluation was not expected to cause the MSPI to change indicated index color and the change was expected to be incorporated in the 4th quarter 2006 performance indicators.
For the sample selected, did the licensee accurately document the actual unavailability hours for the MSPI systems?
The inspectors identified numerous instances in several MSPI systems that the unavailability hours were not accurately determined. However, the magnitude of the data discrepancies was small and did not significantly affect the calculated MSPI. For example, on a few occasions, the licensee failed to included short duration periods of planned unavailability for maintenance. As part of the corrective actions, the licensee was performing a comprehensive data review to ensure the unavailability hours were accurately reflected in the index. It was expected that the review would be completed and incorporated any changes into the 4th quarter 2006 performance indicators.
For the sample selected, did the licensee accurately document the actual unreliability information for each MSPI monitored component?
The inspectors identified several instances where failure information for the emergency diesel generator was not being documented appropriately. These discrepancies were related to the capability of the opposite units diesel generators to support a loss of offsite power (LOOP) in the monitored unit. The Byron PRA assumed the availability of opposite unit diesel generators for certain accident scenarios and that is reflected in the MSPI basis document.
According to the NEI guidance, the number of emergency AC power system trains for a unit is equal to the number of class 1E emergency generators that are available to power safe-shutdown loads in the event of a loss of offsite power for that unit. Since all the diesel generators at Byron Station can supply all units, the number of train is equal to the number of diesel generators. Therefore, for the Byron Station, four trains of diesel generators were being monitored.
The inspectors identified several past failures that affected the test mode (or manual mode) of operation of the diesel generators. These failures either prevented the diesel generator from starting in the manual mode or tripped the diesel generator during test. The licensee determined that these failures were spurious operation of a trip that would be bypassed in a loss of offsite power event and therefore the diesel generators were not considered to have failed.
The licensee also stated that the opposite unit diesel generators would only be required to function during a dual unit loss of offsite power event. In that situation, the opposite unit diesel generators would auto-start in the emergency mode instead of the manual mode.
The inspectors disagreed with the licensees determination for the following reasons:
1) The function monitored for the emergency AC power system is the ability of the emergency generators to provide AC power to the class 1E buses following a loss of offsite power event on that unit. Four trains of diesel generators are providing this risk significant MSPI function per the NEI guidance. Under a LOOP event, the two diesel generators associated with the LOOP unit will be auto-started in emergency mode. However, the opposite unit diesel generators have to be started in test mode (manual) to provide AC power to the LOOP unit.
2) Per the NEI guidance, no credit is given for the achievement of a monitored function by an unmonitored system in determining unavailability or unreliability of the monitored systems. Therefore, the licensee could not take credit for the opposite unit buses to provide AC power. The licensee must be able to manually start the opposite unit diesels to provide power to the LOOP unit.
3) According to the Byron MSPI basis document, the opposite unit diesel generators were risk significant and the Maintenance Rule functions of providing test mode capability and local start and control capability were within the scope of MSPI.
4) The Byron PRA assumed the opposite unit diesel generators were available to supply power to the monitored unit under certain scenarios.
This issue is being addressed through the Performance Indicator FAQ
[frequently asked question] process.
4. Did the inspector identify significant errors in the reported data, which resulted
in a change to the indicated index color? Describe the actual condition and corrective actions taken by the licensee, including the date when the revised PI information was submitted to the NRC.
The inspectors did not identify significant errors in the reported data, which resulted in a change to the indicated index color. As described in Question 1, 3 and 4, the licensee was reviewing the data accuracy for MSPI and was expected to have this completed in January 2007. No change in indicated index color was expected from this review. The inspectors will perform verification of the change as part of the ongoing performance indicator verification process of the ROP.
Did the inspector identify significant discrepancies in the basis document which resulted in
- (1) a change to the system boundary;
- (2) an addition of a monitored component; or
- (3) a change in the reported index color? Describe the actual condition and corrective actions taken by the licensee, including, the date of when the bases document was revised.
The inspectors did not identify significant discrepancies in the basis document which resulted in either a change to the system boundary, an addition of a monitored component or a change in the reported index color. The inspectors did identify an implementation error in the treatment of an installed spare component. This error resulted in additional unavailability hours in the baseline data and current data. That implementation error was corrected in the basis document during the inspection period. Currently, reported data was undergoing a comprehensive review by the licensee but the discrepancy was not expected to cause any change in index color, system boundaries or monitored components.
In addition, a FAQ is being submitted to clarify the treatment of test failures for the opposite unit diesel generators to provide power.
c. Findings
No findings of significance were identified.
4OA6 Meetings
.1 On January 16, 2007, the resident inspectors presented the inspection results to
Mr. D. Hoots and his staff, who acknowledged the findings. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
.2 Interim Exit Meetings
Interim exits were conducted for:
- Inservice Inspection Activities Inspection with Mr. D. Hoots and other members of licensee management on September 15, 2006. The inspectors returned proprietary information reviewed during the inspection and the licensee confirmed that none of the potential report input discussed was considered proprietary.
- Occupational radiation safety program for access control to radiologically significant areas and As-Low-As-Is-Reasonably-Achievable Planning And Controls (ALARA) programs inspections with Mr. D. Hoots on September 15, 2006.
- Biennial Operator Requalification Program Inspection with Mr. D. Hoots on November 3, 2006.
- Biennial Operator Requalification Program Inspection with Mr. S. Gackstetter, Operations Training Supervisor, and Mr. R. Williams, Training Instructor, on November 28, 2006, via telephone.
- Emergency Preparedness inspection with Mr. D. Drawbaugh, Emergency Preparedness Manager, on December 27, 2006.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- D. Hoots, Site Vice President
- M. Snow, Plant Manager
- B. Adams, Work Control Director
- B. Barton, Radiation Engineering Superintendent
- Z. Cox, Chemistry
- L. Doyle, Programs Coordinator
- D. Drawbaugh, Emergency Preparedness Manager
- S. Fruin, Operations
- S. Gackstetter, Operations Training Supervisor
- A. Giancatarino, Engineering Director
- C. Gregory, RP Instrumentation Coordinator
- B. Grundmann, Regulatory Assurance Manager
- E. Hernandez, Maintenance
- T. Hulbert, NRC Coordinator
- W. Kouba, NOS Manager
- J. Langan, Regulatory Assurance
- R. McBride, ISI Engineer
- D. Palmer, Radiation Protection Manager
- M. Prospero, Operations Manager
- P. Reister, Work Control
- C. Settles, IEMA, Springfield
- J. Smith, Acting Engineering Programs Manager
- S. Stimac, Acting Training Manager
- S. Swanson, Maintenance Director
- D. Palmer, Radiation Protection Manager,
- M. Prospero, Operations Manager
- C. Thompson, IEMA, Byron Station
- D. Thompson, Technical Support Superintendent
- R. Williams, LORT Instructor Training
Nuclear Regulatory Commission
- R. Skokowski, Chief, Branch 3, Division of Reactor Projects
Attachment 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
None
Opened and Closed
- 05000454/2006005-01 FIN Failure to have setpoint control of the constant level
- 05000455/2006005-01 oilers on safety-related pumps
Closed
- 05000454/2006-003-00 LER Inadvertent Exceeding of TS Action Requirement Completion Time for Containment Spray Additive System Due to Not Recognizing an Inoperable Condition
Discussed
None Attachment 1