IR 05000454/2006005: Difference between revisions

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{{Adams|number = ML070430564}}
{{Adams
| number = ML070430564
| issue date = 02/12/2007
| title = IR 05000454-06-005, 05000455-06-005; 10/01/2006-12/31/2006; Byron Station, Units 1 and 2; Identification and Resolution of Problems
| author name = Skokowski R A
| author affiliation = NRC/RGN-III/DRP/RPB3
| addressee name = Crane C M
| addressee affiliation = Exelon Generation Co, LLC
| docket = 05000454, 05000455
| license number = NPF-037, NPF-066
| contact person =
| document report number = IR-06-005
| document type = Inspection Report, Letter
| page count = 51
}}


{{IR-Nav| site = 05000454 | year = 2006 | report number = 005 }}
{{IR-Nav| site = 05000454 | year = 2006 | report number = 005 }}
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===B.Licensee Identified Violations===
===B.Licensee Identified Violations===
None Enclosure3
 
None  
 
3


=REPORT DETAILS=
=REPORT DETAILS=
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====a. Inspection Scope====
====a. Inspection Scope====
From September 11, 2006 through September 14, 2006, the inspectors reviewed theBACC 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 toevaluate 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 followingcorrective action documents to ensure that ASME Code wall thickness requirements were maintained:*IR 477473, component 1SI059A; Containment Recirc Sump to ContainmentSpray/Residual Heat Removal Test Connection Isolation Valve; and*IR 306134; component 1 RC8029C; Unit 1Loop C Reactor Coolant BypassVent Valve.The inspectors also reviewed a number of boric acid leak corrective actions todetermine 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.
From September 11, 2006 through September 14, 2006, the inspectors reviewed theBACC 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 toevaluate 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 followingcorrective action documents to ensure that ASME Code wall thickness requirements were maintained:*IR 477473, component 1SI059A; Containment Recirc Sump to ContainmentSpray/Residual Heat Removal Test Connection Isolation Valve; and*IR 306134; component 1 RC8029C; Unit 1Loop C Reactor Coolant BypassVent Valve.The inspectors also reviewed a number of boric acid leak corrective actions todetermine 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.
10


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors observed the administration of a requalification operating test to assessthe licensee's 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,
The inspectors observed the administration of a requalification operating test to assessthe licensee's 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 thisreport.
"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 thisreport.


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors assessed the methods and effectiveness of the licensee's processesfor 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 licensee's quality assurance oversight activities, including licensee training department self-assessment reports. The inspectors evaluated the licensee's 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 ©
The inspectors assessed the methods and effectiveness of the licensee's processesfor 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 licensee's quality assurance oversight activities, including licensee training department self-assessment reports. The inspectors evaluated the licensee's 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 licensee's SAT program.The documents reviewed during this inspection are listed in the Attachment to thisreport.
"Requalification program requirements" and the licensee's SAT program.The documents reviewed during this inspection are listed in the Attachment to thisreport.


====b. Findings====
====b. Findings====
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The inspectors assessed the adequacy and effectiveness of the remedial trainingconducted since the previous biennial requalification examinations and the trainingfrom the current examination cycle to ensure that they addressed weaknesses in licensed operator or crew performance identified during training and plant operations.
The inspectors assessed the adequacy and effectiveness of the remedial trainingconducted since the previous biennial requalification examinations and the trainingfrom 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 trainingplans. This evaluation was performed in accordance with 10 CFR 55.59 ©
The inspectors reviewed remedial training procedures and individual remedial trainingplans. This evaluation was performed in accordance with 10 CFR 55.59 © "Requalification program requirements" and with respect to the licensee's SAT program.The documents reviewed during this inspection are listed in the Attachment to thisreport.
"Requalification program requirements" and with respect to the licensee's SAT program.The documents reviewed during this inspection are listed in the Attachment to thisreport.


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors reviewed the facility and individual operator licensees' conformancewith 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 and individual operator licensees' conformancewith 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 compliancewith 10 CFR 55.53 (I).The documents reviewed during this inspection are listed in the Attachment to thisreport.
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 compliancewith 10 CFR 55.53 (I).The documents reviewed during this inspection are listed in the Attachment to thisreport.
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors reviewed the pass/fail results of the individual biennial writtenexaminations, 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 thisreport.
The inspectors reviewed the pass/fail results of the individual biennial writtenexaminations, 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 thisreport.


====b. Findings====
====b. Findings====
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The inspectors completed three inspection samples by evaluating the licensee'simplementation 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
The inspectors completed three inspection samples by evaluating the licensee'simplementation 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 ifthey had been properly addressed in the licensee's corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.
*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 ifthey had been properly addressed in the licensee's corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.
16


====b. Findings====
====b. Findings====
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The inspectors evaluated plant conditions, selected condition reports, engineeringevaluations, 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 evaluated plant conditions, selected condition reports, engineeringevaluations, 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.


17The inspectors completed two inspection samples by reviewing the following evaluationsand 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 sectionsof the TS including the TS Basis, the Technical Requirements Manual (TRM) and the UFSAR to the licensee's 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 licensee's engineering staff.The inspectors also reviewed selected issues documented in IRs, to determine if theyhad been properly addressed in the licensee's corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.
17The 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 sectionsof the TS including the TS Basis, the Technical Requirements Manual (TRM) and the UFSAR to the licensee's 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 licensee's engineering staff.The inspectors also reviewed selected issues documented in IRs, to determine if theyhad been properly addressed in the licensee's corrective action program. The documents reviewed during this inspection are listed in the Attachment to this report.


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors completed a screening review of Revision 17 of the Byron Station Annexof the Exelon Standardized Emergency Plan to determine whether changes identified in this Annex revision may have reduced the effectiveness of the licensee's 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 thisinspection are listed in the Attachment to this report.
The inspectors completed a screening review of Revision 17 of the Byron Station Annexof the Exelon Standardized Emergency Plan to determine whether changes identified in this Annex revision may have reduced the effectiveness of the licensee's 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 thisinspection are listed in the Attachment to this report.
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====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors examined the licensee's physical and programmatic controls for highlyactivated or contaminated materials (non-fuel) stored within spent fuel and other storage pools. This review represented one sample.
The inspectors examined the licensee's physical and programmatic controls for highlyactivated or contaminated materials (non-fuel) stored within spent fuel and other storage pools. This review represented one sample.
22


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors performed a review of the licensee's 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 licensee's mechanisms for identifying and correcting trends.The review was accomplished by grouping IRs into broad categories during the dailyscreenings. 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.
The inspectors performed a review of the licensee's 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 licensee's mechanisms for identifying and correcting trends.The review was accomplished by grouping IRs into broad categories during the dailyscreenings. 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.
25


====b. Findings and Observations====
====b. Findings and Observations====
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=====Analysis:=====
=====Analysis:=====
The inspectors determined that the failure to have setpoint controlof the safety-related constant level oilers was a performance deficiency warranting a significance evaluation in accordance with Inspection Manual Chapter (IMC) 0612,
The inspectors determined that the failure to have setpoint controlof 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,"
"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, usingIMC 0609, "Significance Determination Process," dated November 22, 2005, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power 26Situations," dated November 22, 2005. As stated the failure to have setpoint control ofthe 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 thatthis 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
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, usingIMC 0609, "Significance Determination Process," dated November 22, 2005, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power 26Situations," dated November 22, 2005. As stated the failure to have setpoint control ofthe 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 thatthis 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:=====
=====Enforcement:=====
The inspectors concluded that no violation regulatoryrequirements 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 IRswith 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 andevaluated 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 beenalready 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 routinesurveillance. The operators did a prompt controlled shutdown of the DG when the right bank air intake manifold temperature started swinging and reached 162F. This exceeded the procedural limit of 160F. A note in the surveillanceprocedure (BOP DG-11T2) stated that the DG was to be tripped if the procedural limit of 160F was exceeded. IR 438719 was written addressing the cause of 27the high temperature and performed an operability assessment. This IR didnot 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 160F was for normal mode only and was not a limitrequired 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 similarcondition. 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 containmentradiation monitor 2PR11J the inspectors noted a procedural adherence issue.
The inspectors concluded that no violation regulatoryrequirements 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 IRswith 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 andevaluated 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 beenalready 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 routinesurveillance. The operators did a prompt controlled shutdown of the DG when the right bank air intake manifold temperature started swinging and reached
 
162F. This exceeded the procedural limit of 160F. A note in the surveillanceprocedure (BOP DG-11T2) stated that the DG was to be tripped if the procedural limit of 160F was exceeded. IR 438719 was written addressing the cause of 27the high temperature and performed an operability assessment. This IR didnot 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 160F was for normal mode only and was not a limitrequired 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 similarcondition. 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 containmentradiation 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 toreplace 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 instrument's ability to perform its intended safety function.The licensee had already recognized the need to focus on site wide procedureadherence 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.
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 toreplace 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 instrument's ability to perform its intended safety function.The licensee had already recognized the need to focus on site wide procedureadherence 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.


284OA3Event Follow-up (71153).1(Closed) LER 454-2006-003-00:  Inadvertent Exceeding of TS Action RequirementCompletion Time for Containment Spray Additive System Due to Not Recognizing an Inoperable ConditionOn August 11, 2006, the licensee identified a pressure boundary weld leak in anASME 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.4OA5Other ActivitiesMitigating Systems Performance Index Verification (Temporary Instruction 2515/169)
284OA3Event Follow-up (71153).1(Closed) LER 454-2006-003-00:  Inadvertent Exceeding of TS Action RequirementCompletion Time for Containment Spray Additive System Due to Not Recognizing an Inoperable ConditionOn August 11, 2006, the licensee identified a pressure boundary weld leak in anASME 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.4OA5Other ActivitiesMitigating Systems Performance Index Verification (Temporary Instruction 2515/169)


====a. Inspection Scope====
====a. Inspection Scope====
The Mitigating System Performance Index (MSPI) was developed to replace the SafetySystem 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 licensee's basis document and evaluated theimplementation of the MSPI against the guidance provided in NEI 99-02,
The Mitigating System Performance Index (MSPI) was developed to replace the SafetySystem 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 licensee's basis document and evaluated theimplementation 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.
"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.


29  b.Evaluation of Inspections Requirements1.For the sample selected, did the licensee accurately document the baselineplanned unavailability hours for the MSPI systems?The inspectors identified that the licensee had prepared two sets of baselinedata 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.
29  b.Evaluation of Inspections Requirements1.For the sample selected, did the licensee accurately document the baselineplanned unavailability hours for the MSPI systems?The inspectors identified that the licensee had prepared two sets of baselinedata 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.
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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 revisingthe 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.2.For the sample selected, did the licensee accurately document the actualunavailability hours for the MSPI systems?The inspectors identified numerous instances in several MSPI systems that theunavailability 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.3.For the sample selected, did the licensee accurately document the actualunreliability information for each MSPI monitored component?The inspectors identified several instances where failure information for theemergency diesel generator was not being documented appropriately. These discrepancies were related to the capability of the opposite unit's 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 systemtrains 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 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 revisingthe 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.2.For the sample selected, did the licensee accurately document the actualunavailability hours for the MSPI systems?The inspectors identified numerous instances in several MSPI systems that theunavailability 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.3.For the sample selected, did the licensee accurately document the actualunreliability information for each MSPI monitored component?The inspectors identified several instances where failure information for theemergency diesel generator was not being documented appropriately. These discrepancies were related to the capability of the opposite unit's 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 systemtrains 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.


30The inspectors identified several past failures that affected the test mode (ormanual 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 onlybe 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 licensee's determination for the followingreasons:  1)  The function monitored for the emergency AC power system is the ability ofthe 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 dieselgenerators 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 availableto 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 resultedin a change to the indicated index color?  Describe the actual condition andcorrective actions taken by the licensee, including the date when the revisedPI information was submitted to the NRC.The inspectors did not identify significant errors in the reported data, whichresulted 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 31expected from this review. The inspectors will perform verification of the changeas part of the ongoing performance indicator verification process of the ROP.5.Did the inspector identify significant discrepancies in the basis document whichresulted in (1) a change to the system boundary; (2) an addition of a monitoredcomponent; or (3) a change in the reported index color?  Describe the actualcondition and corrective actions taken by the licensee, including, the date ofwhen the bases document was revised.The inspectors did not identify significant discrepancies in the basis documentwhich 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.
30The inspectors identified several past failures that affected the test mode (ormanual 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 onlybe 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 licensee's determination for the followingreasons:  1)  The function monitored for the emergency AC power system is the ability ofthe 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 dieselgenerators 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 availableto 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 resultedin a change to the indicated index color?  Describe the actual condition andcorrective actions taken by the licensee, including the date when the revisedPI information was submitted to the NRC.The inspectors did not identify significant errors in the reported data, whichresulted 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 31expected from this review. The inspectors will perform verification of the changeas part of the ongoing performance indicator verification process of the ROP.5.Did the inspector identify significant discrepancies in the basis document whichresulted in
: (1) a change to the system boundary;
: (2) an addition of a monitoredcomponent; or
: (3) a change in the reported index color?  Describe the actualcondition and corrective actions taken by the licensee, including, the date ofwhen the bases document was revised.The inspectors did not identify significant discrepancies in the basis documentwhich 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.
In addition, a FAQ is being submitted to clarify the treatment of test failures for the opposite unit diesel generators to provide power.
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==KEY POINTS OF CONTACT==
==KEY POINTS OF CONTACT==
Licensee
Licensee
: [[contact::D. Hoots]], Site Vice President
: [[contact::D. Hoots]], Site Vice President
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2
2
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
OpenedNoneOpened and  
Opened NoneOpened and  
===Closed===
===Closed===
: 05000454/2006005-01
: 05000454/2006005-01
: [[Closes finding::05000455/FIN-2006005-01]]FINFailure to have setpoint control of the constant leveloilers on safety-related pumpsClosed
: [[Closes finding::05000455/FIN-2006005-01]]FINFailure to have setpoint control of the constant leveloilers on safety-related pumps
: [[Closes LER::05000454/LER-2006-003]]-00LERInadvertent Exceeding of TS Action RequirementCompletion Time for Containment Spray Additive System
 
: Due to Not Recognizing an Inoperable ConditionDiscussedNone
===Closed===
: 13
: 05000454/2006005-01
: [[Closes finding::05000455/FIN-2006005-01]]FINFailure to have setpoint control of the constant leveloilers on safety-related pumps
 
===Discussed===
None
 
3
==LIST OF DOCUMENTS REVIEWED==
==LIST OF DOCUMENTS REVIEWED==
The following is a list of documents reviewed during the inspection.
The following is a list of documents reviewed during the inspection.
: Inclusion on this list doesnot imply that the NRC inspectors reviewed the documents in their entirety but rather that selected sections of portions of the documents were evaluated as part of the overall inspection effort.
: Inclusion on this list doesnot imply that the NRC inspectors reviewed the documents in their entirety but rather that selected sections of portions of the documents were evaluated as part of the overall inspection effort.
: Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report.1R01Adverse Weather Protection0BOSR
: Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report.
: 1R01Adverse Weather Protection0BOSR
: XFT-A1; Freezing Temperature Equipment Protection SH and Department SupportRequirements, Revision 9
: XFT-A1; Freezing Temperature Equipment Protection SH and Department SupportRequirements, Revision 9
: 0BOSR
: 0BOSR
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: IR 567089; River Screen House Temperature Alarm Comes in Early, December 08, 2006
: IR 567089; River Screen House Temperature Alarm Comes in Early, December 08, 2006
: IR 567427; Potential for Freezing Pipes, December 10, 2006Corrective Action Documents as a Result of NRC InspectionIR
: IR 567427; Potential for Freezing Pipes, December 10, 2006Corrective Action Documents as a Result of NRC InspectionIR
: 560928; Loose Debris Around SX Tower During Fan Replacement Project, November 21,2006 (NRC Identified)1R04Equipment AlignmentBOP RH E2A; Residual Heat Removal System, Unit 2 Electrical Lineup, Revision 3BOP
: 560928; Loose Debris Around SX Tower During Fan Replacement Project, November 21,2006 (NRC Identified)
: RH-M2A; Train "A" Residual Heat Removal System Valve Lineup, Revision 61R05Fire ProtectionIR
: 1R04Equipment AlignmentBOP RH E2A; Residual Heat Removal System, Unit 2 Electrical Lineup, Revision 3BOP
: RH-M2A; Train "A" Residual Heat Removal System Valve Lineup, Revision 6
: 1R05Fire ProtectionIR
: 543978; Print Not Updated to Reflect a Change in Fire Seal Status, October 14, 2006IR
: 543978; Print Not Updated to Reflect a Change in Fire Seal Status, October 14, 2006IR
: 559556; Lessons Learned From Offsite Fire Drill, November 17, 2006
: 559556; Lessons Learned From Offsite Fire Drill, November 17, 2006
: Pre Fire Plan; "Auxiliary Building Elevation 383'-0" - Zone 11.4A-2" Fire Safety Analysis Report; Section 2.3.11.31, "Unit 2 Auxiliary Feedwater Diesel - Driven Pump Room," Fire Zone 11.4A-1
: Pre Fire Plan; "Auxiliary Building Elevation 383'-0" - Zone 11.4A-2" Fire Safety Analysis Report; Section 2.3.11.31, "Unit 2 Auxiliary Feedwater Diesel - Driven Pump Room," Fire Zone 11.4A-1
: Fire Safety Analysis Report; Section 2.3.11.32, "Unit 2 Auxiliary feedwater Diesel-Driven Pump Room," Fire Zone 11.4A-2   
: Fire Safety Analysis Report; Section 2.3.11.32, "Unit 2 Auxiliary feedwater Diesel-Driven Pump Room," Fire Zone 11.4A-2   
: 146E-Q-4Q30VA61; "Diesel Driven Auxiliary Feedwater Pump & Day Tank Room CO2 FireProtection System Fire Damper Control Catalog ID#23764; "Linkage, thermal, Electro, 165 DEG. F. Melting Point Fire Safety Analysis Report; Section 2.3.11.12, "Auxiliary Building General Area Level 364 feet inches, " Fire Zone 11.3-0  
: 46E-Q-4Q30VA61; "Diesel Driven Auxiliary Feedwater Pump & Day Tank Room CO2 FireProtection System Fire Damper Control Catalog ID#23764; "Linkage, thermal, Electro, 165 DEG. F. Melting Point Fire Safety Analysis Report; Section 2.3.11.12, "Auxiliary Building General Area Level 364 feet inches, " Fire Zone 11.3-0  
: Pre Fire Plan; "Auxiliary Building Elevation 364' - 0 Basement Floor Zone 11.3-0 West, North, and South Fire Drill Scenario No. 37; Stores Warehouse w/Offsite Assistance, November 10, 2006
: Pre Fire Plan; "Auxiliary Building Elevation 364' - 0 Basement Floor Zone 11.3-0 West, North, and South Fire Drill Scenario No. 37; Stores Warehouse w/Offsite Assistance, November 10, 2006
: Pre Fire Plan; Unit 2 Lower Cable Spreading Room, Zone 3.2A-2
: Pre Fire Plan; Unit 2 Lower Cable Spreading Room, Zone 3.2A-2
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: IR 546853; Pre-Fire Plan/Fire Protection Plan/Plant Discrepancy, October 20, 2006
: IR 546853; Pre-Fire Plan/Fire Protection Plan/Plant Discrepancy, October 20, 2006
(NRC Identified)
(NRC Identified)
: IR 574929; Issues with Fire Pre-Plans, December 22, 2006 (NRC Identified)1R06Flood Protection MeasuresUFSAR Section 3.4, Water Level (Flood) Design; Revision 10, December 2006IR
: IR 574929; Issues with Fire Pre-Plans, December 22, 2006 (NRC Identified)
: 1R06Flood Protection MeasuresUFSAR Section 3.4, Water Level (Flood) Design; Revision 10, December 2006IR
: 557177; Revise 0BMSR
: 557177; Revise 0BMSR
: DD-1 To Update Acceptance Criteria, November 13, 2006
: DD-1 To Update Acceptance Criteria, November 13, 2006
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: DD-1 Add to Model Work Orders, November 13, 2006
: DD-1 Add to Model Work Orders, November 13, 2006
: IR 563669; 2A SX Sump Pump Discharge Valve 2WF040A is Leaking, November 30, 2006  
: IR 563669; 2A SX Sump Pump Discharge Valve 2WF040A is Leaking, November 30, 2006  
: 15Corrective Action Documents as a Result of NRC InspectionIR
: 5Corrective Action Documents as a Result of NRC InspectionIR
: 559022; Uncapped SX Drain line Above Unit 2 CC Pump Motors, November 16, 2006(NRC Identified)1R07Heat Sink PerformanceWO
: 559022; Uncapped SX Drain line Above Unit 2 CC Pump Motors, November 16, 2006(NRC Identified)
: 1R07Heat Sink PerformanceWO
: 948789 01; 1SX01AA - Heat Exchanger Inspection per Generic Letter 89-13,November 21, 2006
: 948789 01; 1SX01AA - Heat Exchanger Inspection per Generic Letter 89-13,November 21, 2006
: BVP 800-30; Service Water System (Essential Service Water) Fouling Monitoring Program, Revision 91R08Inservice Inspection ActivitiesNDE ProceduresEXE-PDI-UT-1; Ultrasonic Examination of Ferritic Pipe Welds in Accordance with
: BVP 800-30; Service Water System (Essential Service Water) Fouling Monitoring Program, Revision 9
: 1R08Inservice Inspection ActivitiesNDE ProceduresEXE-PDI-UT-1; Ultrasonic Examination of Ferritic Pipe Welds in Accordance with
: PDI-UT-1;Revision 5
: PDI-UT-1;Revision 5
: EXE-PDI-UT-2; Ultrasonic Examination of Austenitic Pipe Welds in Accordance with PDI-UT-2;
: EXE-PDI-UT-2; Ultrasonic Examination of Austenitic Pipe Welds in Accordance with PDI-UT-2;
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: USN-60sw; October 6, 2005Corrective Action DocumentsIR
: USN-60sw; October 6, 2005Corrective Action DocumentsIR
: 296825; Work Order Scope Change not Reviewed Through RRR Process:
: 296825; Work Order Scope Change not Reviewed Through RRR Process:
: February 2,2005  
: February 2, 2005  
: 16IR
: 6IR
: 504160; Deficiencies Identified During ISI Programs FASA; June 27, 2006IR
: 504160; Deficiencies Identified During ISI Programs FASA; June 27, 2006IR
: 307161; Incorrect Size (Class-D) Snubber "1SD21033S"; March 2, 2005
: 307161; Incorrect Size (Class-D) Snubber "1SD21033S"; March 2, 2005
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: 2006
: 2006
: B1R13 Control Rod Drive Mechanism Volumetric Examinations; Discussions of Significance ofSurface Scratches Found on reactor Vessel Upper Head Penetrations; June 23, 2005Welding DocumentsWO00706874-01; U-1 Pressurizer 1RY01S Auxiliary Spray Header Check Valve;August 23, 2004Corrective Action Documents as a Result of NRC InspectionIR00379827; Overly Conservative Use of Recordable Indication per IWF; September 29, 2006(NRC Identified)
: B1R13 Control Rod Drive Mechanism Volumetric Examinations; Discussions of Significance ofSurface Scratches Found on reactor Vessel Upper Head Penetrations; June 23, 2005Welding DocumentsWO00706874-01; U-1 Pressurizer 1RY01S Auxiliary Spray Header Check Valve;August 23, 2004Corrective Action Documents as a Result of NRC InspectionIR00379827; Overly Conservative Use of Recordable Indication per IWF; September 29, 2006(NRC Identified)
: IR 531366; Numerous Housekeeping Concerns in Unit 1 Refueling Water Storage Tank Tunnel, September 14, 2006 (NRC Identified)1R11Licensed Operator Requalification ProgramByron ROP Plant Issue Matrix from June 1, 2004 to October 11, 2006; October 11, 2006Byron Station, Units 1 and 2 NRC Integrated Inspection Reports; dated various from November 6, 2004 through August 3, 2006
: IR 531366; Numerous Housekeeping Concerns in Unit 1 Refueling Water Storage Tank Tunnel, September 14, 2006 (NRC Identified)
: 1R11Licensed Operator Requalification ProgramByron ROP Plant Issue Matrix from June 1, 2004 to October 11, 2006; October 11, 2006Byron Station, Units 1 and 2 NRC Integrated Inspection Reports; dated various from November 6, 2004 through August 3, 2006
: LER 454-2005-004-00; TS Required Action Not Satisfied Due to Ambiguous Implementing Procedure; May 24, 2005
: LER 454-2005-004-00; TS Required Action Not Satisfied Due to Ambiguous Implementing Procedure; May 24, 2005
: Seven Licensed Operators' Medical Records; dated various
: Seven Licensed Operators' Medical Records; dated various
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dated various Completed
dated various Completed
: TQ-AA-210-5101; Training Observation Form; dated various  
: TQ-AA-210-5101; Training Observation Form; dated various  
: 17Completed
: 7Completed
: TQ-AA-210-5103; Trainee Reaction - Multiple Topic; dated variousCompleted
: TQ-AA-210-5103; Trainee Reaction - Multiple Topic; dated variousCompleted
: TQ-AA-210-5106; LORT Evaluation Summary; dated various from June 27, 2004
: TQ-AA-210-5106; LORT Evaluation Summary; dated various from June 27, 2004
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: Open
: Open
: SWR 9150; CV System Flow Oscillation; July 24, 2006  
: SWR 9150; CV System Flow Oscillation; July 24, 2006  
: 18Open
: 8Open
: SWR 9360; LTOP Lift Setpoint Changes Due to PTLR Revision; September 25, 2006List of Closed Simulator Work Requests for Last 12 Months; October 27, 2006
: SWR 9360; LTOP Lift Setpoint Changes Due to PTLR Revision; September 25, 2006List of Closed Simulator Work Requests for Last 12 Months; October 27, 2006
: Closed
: Closed
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: IR 558180; Low Quality Package, Training Improvement Opportunity, November 3, 2006
: IR 558180; Low Quality Package, Training Improvement Opportunity, November 3, 2006
(NRC Identified)
(NRC Identified)
: IR was Initiated Based on NRC Observations During Inspection (NRC Identified)1R12Maintenance Effectiveness (A)(1) Action Plan for VV1, July 13, 2005Material Condition Improvement Plan; MSIV/Safety Valve Enclosure Ventilation Modification, August 03, 2005
: IR was Initiated Based on NRC Observations During Inspection (NRC Identified)
: 1R12Maintenance Effectiveness
(A)(1) Action Plan for VV1, July 13, 2005Material Condition Improvement Plan; MSIV/Safety Valve Enclosure Ventilation Modification, August 03, 2005
: IR 264685; Found 1VV01CD Running With No Discharge or Recirculation Path, October 18,
: IR 264685; Found 1VV01CD Running With No Discharge or Recirculation Path, October 18,
: 2004
: 2004
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: Apparent Cause Report; 1A DG Slowed to Idle Speed Due to Relay Failure, December 13, 2006
: Apparent Cause Report; 1A DG Slowed to Idle Speed Due to Relay Failure, December 13, 2006
: BYR-28090; Failure Analysis (1) Killovac Relay PD10AC57, November 22, 2006  
: BYR-28090; Failure Analysis (1) Killovac Relay PD10AC57, November 22, 2006  
: 191R13Maintenance Risk Assessment and Emergent Work Control Unit 2 Risk Configurations, Week of October 02, 2006, Revision 1Protected Equipment Log, October 5, 2006
: 1R13Maintenance Risk Assessment and Emergent Work Control Unit 2 Risk Configurations, Week of October 02, 2006, Revision 1Protected Equipment Log, October 5, 2006
: IR 541127; Disabling TS Equipment to Prevent Valid Auto Start, October 6, 2006
: IR 541127; Disabling TS Equipment to Prevent Valid Auto Start, October 6, 2006
: WC-AA-101; Attachment 7 to Protected Equipment Process and Methodology, Revision 13
: WC-AA-101; Attachment 7 to Protected Equipment Process and Methodology, Revision 13
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: Protected Equipment Log, November 06, 2006
: Protected Equipment Log, November 06, 2006
: Policy No. 400-47; Byron Operating Department Policy Statement, Revision 9Corrective Action Documents as a Result of NRC InspectionIR
: Policy No. 400-47; Byron Operating Department Policy Statement, Revision 9Corrective Action Documents as a Result of NRC InspectionIR
: 559537; Weaknesses in Byron's Protected Equipment Program, November 17, 2006(NRC Identified)1R14Personnel Performance During Non-Routine EvolutionsOctober 23, 2006 Byron Station Emergency Preparedness & Security Integrated Drill EvaluationReport, November 26, 20061R15Operability EvaluationsIR
: 559537; Weaknesses in Byron's Protected Equipment Program, November 17, 2006(NRC Identified)
: 1R14Personnel Performance During Non-Routine EvolutionsOctober 23, 2006 Byron Station Emergency Preparedness & Security Integrated Drill EvaluationReport, November 26, 2006
: 1R15Operability EvaluationsIR
: 262818; Debris Discovered in 2B SX Pump Lube Oil Reservoir, October 12, 2004IR
: 262818; Debris Discovered in 2B SX Pump Lube Oil Reservoir, October 12, 2004IR
: 543978; Print Not Updated to Reflect a Change in Fire Seal Status, October 14, 2006
: 543978; Print Not Updated to Reflect a Change in Fire Seal Status, October 14, 2006
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: IR 546853; Pre-Fire Plan/Fire Protection Plan/Plant Discrepancy, October 20, 2006
: IR 546853; Pre-Fire Plan/Fire Protection Plan/Plant Discrepancy, October 20, 2006
(NRC Identified)  
(NRC Identified)  
: 1101R19Post Maintenance TestingWO
: 1R19Post Maintenance TestingWO
: 736551-01; MM - Upgrade Seal Cooling Water Supply Piping, November 30, 2006WO
: 736551-01; MM - Upgrade Seal Cooling Water Supply Piping, November 30, 2006WO
: 736551-03; OPS PMT - Visual, December 11, 2006
: 736551-03; OPS PMT - Visual, December 11, 2006
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: 6E-1-4030FP04; Fire Detection Control Cabinet
: 6E-1-4030FP04; Fire Detection Control Cabinet
: IR 569062; 1VV01CC Failed PMT for
: IR 569062; 1VV01CC Failed PMT for
: WO 876174, December 13, 20061R20Refueling and Outage ActivitiesEngineering Change
: WO 876174, December 13, 2006
: 1R20Refueling and Outage ActivitiesEngineering Change
: 363000; Evaluation for Foreign Material Left in Unit 1 ContainmentIR
: 363000; Evaluation for Foreign Material Left in Unit 1 ContainmentIR
: 541200; Low Sensitivity to Foreign Material in Containment, October 2, 2006
: 541200; Low Sensitivity to Foreign Material in Containment, October 2, 2006
Line 722: Line 755:
: B1R14 Shutdown Risk Profile, October 1 - 13, 2006
: B1R14 Shutdown Risk Profile, October 1 - 13, 2006
: B1R14 Outage News, October 1 - 15, 2006  
: B1R14 Outage News, October 1 - 15, 2006  
: 111Corrective Action Documents As A Result of NRC InspectionIR
: 11Corrective Action Documents As A Result of NRC InspectionIR
: 544108; NRC Question During Unit 1 Containment Walkdown in Mode 3, October 14, 2006(NRC Identified)
: 544108; NRC Question During Unit 1 Containment Walkdown in Mode 3, October 14, 2006(NRC Identified)
: IR 544092; Issues During Unit 1 Containment Walkdown in Mode 3, Many a Repeat of Previously Identified Cleanliness Issues on the Polar Crane, October 14, 2006 (NRC Identified)1R22Surveillance TestingWO
: IR 544092; Issues During Unit 1 Containment Walkdown in Mode 3, Many a Repeat of Previously Identified Cleanliness Issues on the Polar Crane, October 14, 2006 (NRC Identified)
: 935255 01; Unit 0 Deep Well Pump Make-up Flow Verification, December 27, 20061BOSR 0.5-2.AF.1-1, Stroke Time Testing for Valves 1AF013 A through D1R23Temporary Plant ModificationsEngineering Change
: 1R22Surveillance TestingWO
: 935255 01; Unit 0 Deep Well Pump Make-up Flow Verification, December 27, 20061BOSR 0.5-2.AF.1-1, Stroke Time Testing for Valves 1AF013 A through D
: 1R23Temporary Plant ModificationsEngineering Change
: 363128; Provide RCS Loop 1B Hot Leg Indication to RemoteEngineering Change
: 363128; Provide RCS Loop 1B Hot Leg Indication to RemoteEngineering Change
: 363442; Install Jumper at A1-A2 of Relay 43FSX in Panel 1PL07J to Defeat Slow Start Capability of the 1A Diesel Generator, Revision 0
: 363442; Install Jumper at A1-A2 of Relay 43FSX in Panel 1PL07J to Defeat Slow Start Capability of the 1A Diesel Generator, Revision 0
Line 733: Line 768:
: IR 556907; Question Whether the 1A DG is Operable, November 12, 2006Corrective Action Documents As A Result of NRC InspectionIR
: IR 556907; Question Whether the 1A DG is Operable, November 12, 2006Corrective Action Documents As A Result of NRC InspectionIR
: 554339; 50.59 Screening Requires Revision, November 6, 2006 (NRC Identified)
: 554339; 50.59 Screening Requires Revision, November 6, 2006 (NRC Identified)
: 2OS1Access Control to Radiologically Significant AreasRP-AA-460; Controls for High and Very High Radiation Areas; Revision 11RP-AA-460-1001; Additional High Radiation Exposure Control; Revision 1
 
==2OS1 Access Control to Radiologically Significant AreasRP-AA-460; Controls for High and Very High Radiation Areas; Revision 11RP-AA-460-1001; Additional High Radiation Exposure Control; Revision 1==
: RP-AA-19; High Radiation Area Program Description; Revision 1
: RP-AA-19; High Radiation Area Program Description; Revision 1
: RP-AA-376; Radiological Postings, Labeling and Markings; Revision 1
: RP-AA-376; Radiological Postings, Labeling and Markings; Revision 1
: RP-BY-500-1003; Radiological Controls for Handling Items and Hanging Activated Parts in the Spent Fuel Pool; Revision 11EP4Emergency Action Level and Emergency Plan ChangesByron Station Annex of the Exelon Standardized Emergency Plan; Revision 17
: RP-BY-500-1003; Radiological Controls for Handling Items and Hanging Activated Parts in the Spent Fuel Pool; Revision 1
 
==1EP4 Emergency Action Level and Emergency Plan ChangesByron Station Annex of the Exelon Standardized Emergency Plan; Revision 17==
: 1EP6Drill EvaluationNuclear Accident Reporting System (ARs) Form, October 23, 2006EP-AA-112-F-01; Command and Control Turnover Briefing Form, Revision B
: 1EP6Drill EvaluationNuclear Accident Reporting System (ARs) Form, October 23, 2006EP-AA-112-F-01; Command and Control Turnover Briefing Form, Revision B
: Byron EP/Security Integrated PI Drill, October 23, 2006
: Byron EP/Security Integrated PI Drill, October 23, 2006
: LS-AA-1150; Reactor Plant Event Notification Worksheet, Revision 0  
: LS-AA-1150; Reactor Plant Event Notification Worksheet, Revision 0  
: 11240A2Identification and Resolution of ProblemsIR
: 240A2Identification and Resolution of ProblemsIR
: 350579; 1B DG Air Manifold Temperature Swinging, July 06, 2005IR
: 350579; 1B DG Air Manifold Temperature Swinging, July 06, 2005IR
: 374363; SOS to Perform Aggregate Assessment of Operator Work Arounds, November 30,
: 374363; SOS to Perform Aggregate Assessment of Operator Work Arounds, November 30,
Line 768: Line 806:
: IR 569751; Evaluate 1B AF Pump Gearbox Oil PP for Operator Challenge, December 15, 2006
: IR 569751; Evaluate 1B AF Pump Gearbox Oil PP for Operator Challenge, December 15, 2006
(NRC Identified) 4OA3Event Follow-upLER 454/2006-003; Inadvertent Exceeding of TS Action Requirement Completion Time forContainment Spray Additive System Due to Not Recognizing an Inoperable Condition, September 01, 2006  
(NRC Identified) 4OA3Event Follow-upLER 454/2006-003; Inadvertent Exceeding of TS Action Requirement Completion Time forContainment Spray Additive System Due to Not Recognizing an Inoperable Condition, September 01, 2006  
: 1134OA5Other Activities BB
: 134OA5Other Activities
: BB
: PRA-017.27B; Byron Reactor Oversight Program MSPI Basis Document; Revision 2;BISR 3.4.2-200; Surveillance Calibration of Auxiliary Feedwater to Steam Generators A, B, C
: PRA-017.27B; Byron Reactor Oversight Program MSPI Basis Document; Revision 2;BISR 3.4.2-200; Surveillance Calibration of Auxiliary Feedwater to Steam Generators A, B, C
and D Flow Control Loops, Revision  
and D Flow Control Loops, Revision  
Line 806: Line 845:
: 449971; 1B DG Missed Opportunities, February 04, 2006 (NRC Identified)IR
: 449971; 1B DG Missed Opportunities, February 04, 2006 (NRC Identified)IR
: 564938; Delta in MSPI Data Reporting Period, December 04, 2006 (NRC Identified)  
: 564938; Delta in MSPI Data Reporting Period, December 04, 2006 (NRC Identified)  
: 114IR
: 14IR
: 572142; MSPI Baseline Unavailability Period Incorrect, December 21, 2006 (NRC Identified)IR
: 572142; MSPI Baseline Unavailability Period Incorrect, December 21, 2006 (NRC Identified)IR
: 572244; MSPI Baseline Unavailability Data Discrepancies HPI & RHR, December 21, 2006
: 572244; MSPI Baseline Unavailability Data Discrepancies HPI & RHR, December 21, 2006
Line 819: Line 858:
: IR 579340; Display Anomaly in Outdated Maintenance Rule Database, January 16, 2007
: IR 579340; Display Anomaly in Outdated Maintenance Rule Database, January 16, 2007
(NRC Identified)  
(NRC Identified)  
: 115
: 15
==LIST OF ACRONYMS==
==LIST OF ACRONYMS==
: [[USEDAC]] [[Alternating Current]]
USEDACAlternating CurrentADAMSAgencywide Documents Access and Management System
: [[ADAMSA]] [[gencywide Documents Access and Management System]]
: [[AFWA]] [[uxiliary Feedwater]]
: [[AF]] [[]]
: [[ALARAA]] [[Low As Reasonably Dose Equivalent]]
: [[WA]] [[uxiliary Feedwater]]
ANSAlert and Notification System
: [[ALAR]] [[]]
ANSIAmerican National Standard Institute/American Nuclear Society
: [[AA]] [[s Low As Reasonably Dose Equivalent]]
ASMEAmerican Society of Mechanical Engineers
: [[AN]] [[]]
BACCBoric Acid Corrosion Control
: [[SA]] [[lert and Notification System]]
CAPCorrective Action Program
: [[ANS]] [[]]
CFRCode of Federal Regulations
: [[IA]] [[merican National Standard Institute/American Nuclear Society]]
DGDiesel Generator
: [[ASM]] [[]]
: [[EA]] [[merican Society of Mechanical Engineers]]
: [[BAC]] [[]]
: [[CB]] [[oric Acid Corrosion Control]]
: [[CA]] [[]]
: [[PC]] [[orrective Action Program]]
: [[CF]] [[]]
RCode of Federal Regulations
: [[DGD]] [[iesel Generator]]
: [[DRPD]] [[ivision of Reactor Projects; Region]]
: [[DRPD]] [[ivision of Reactor Projects; Region]]
: [[RIII]] [[]]
: [[RIII]] [[]]
: [[IEM]] [[]]
IEMAIllinois Emergency Management Agency
: [[AI]] [[llinois Emergency Management Agency]]
IMCInspection Manual Chapter
: [[IM]] [[]]
CInspection Manual Chapter
IPInspection Procedure
IPInspection Procedure
: [[IRI]] [[ssue Report]]
IRIssue Report
: [[IS]] [[]]
ISIInservice Inspection
: [[II]] [[nservice Inspection]]
JPMJob Performance Measure
: [[JP]] [[]]
LERLicensee Event Report
: [[MJ]] [[ob Performance Measure]]
LOOPLoss Of Offsite Power
: [[LE]] [[]]
LORTLicensed Operator Requalification Training
: [[RL]] [[icensee Event Report]]
MSPIMitigating System Performance Index
: [[LOO]] [[]]
NCVNon-Cited Violation
: [[PL]] [[oss Of Offsite Power]]
NDENondestructive Examination
: [[LOR]] [[]]
NRCUnited States Nuclear Regulatory Commission
: [[TL]] [[icensed Operator Requalification Training]]
PARSPublic Availability Records
: [[MSP]] [[]]
PIPerformance Indicator
: [[IM]] [[itigating System Performance Index]]
RCARadiologically Controlled Area
: [[NC]] [[]]
RCSReactor Coolant System
: [[VN]] [[on-Cited Violation]]
: [[ND]] [[]]
: [[EN]] [[ondestructive Examination]]
: [[NR]] [[]]
: [[CU]] [[nited States Nuclear Regulatory Commission]]
: [[PAR]] [[]]
SPublic Availability Records
: [[PIP]] [[erformance Indicator]]
: [[RC]] [[]]
: [[AR]] [[adiologically Controlled Area]]
: [[RC]] [[]]
SReactor Coolant System
RIResident Inspector
RIResident Inspector
: [[ROR]] [[eactor Operator]]
ROReactor Operator
: [[SA]] [[]]
SATSystems Approach to Training
: [[TS]] [[ystems Approach to Training]]
SDPSignificance Determination Process
: [[SD]] [[]]
SROSenior Reactor Operator
: [[PS]] [[ignificance Determination Process]]
SSCStructures, Systems, & Components
: [[SR]] [[]]
SWRSimulator Work Request
: [[OS]] [[enior Reactor Operator]]
: [[SS]] [[]]
: [[CS]] [[tructures, Systems, & Components]]
: [[SW]] [[]]
RSimulator Work Request
SXEssential Service Water
SXEssential Service Water
: [[TRT]] [[raining Request]]
TRTraining Request
: [[TR]] [[]]
TRMTechnical Requirement Manual
MTechnical Requirement Manual
TSTechnical Specifications
: [[TST]] [[echnical Specifications]]
UFSARUpdated Final Safety Analysis Report
: [[UFSA]] [[]]
RUpdated Final Safety Analysis Report
WOWork Order
WOWork Order
: [[WRW]] [[ork Request]]
: [[WRW]] [[ork Request]]
}}
}}

Revision as of 21:50, 24 October 2018

IR 05000454-06-005, 05000455-06-005; 10/01/2006-12/31/2006; Byron Station, Units 1 and 2; Identification and Resolution of Problems
ML070430564
Person / Time
Site: Byron  Constellation icon.png
Issue date: 02/12/2007
From: Skokowski R A
NRC/RGN-III/DRP/RPB3
To: Crane C M
Exelon Generation Co
References
IR-06-005
Download: ML070430564 (51)
v • d • e


Text

February 12, 2007

Mr. Christopher M. CranePresident and Chief Nuclear Officer Exelon Nuclear Exelon Generation Company, LLC 4300 Winfield Road Warrenville, IL 60555

SUBJECT: BYRON STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTIONREPORT 05000454/2006005 AND 05000455/2006005

Dear Mr. Crane:

On December 31, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed anintegrated 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 andcompliance with the Commission's 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 NRC's "Rules of Practice," a copy of this letter andits enclosure will be made available electronically for public inspection in the NRC PublicDocument Room or from the Publicly Available Records (PARS) component of NRC's C. Crane-2-document system (ADAMS). ADAMS is accessible from the NRC Web site athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/Richard A. Skokowski, ChiefBranch 3 Division of Reactor ProjectsDocket Nos. 50-454, 50-455License Nos. NPF-37, NPF-66

Enclosure:

Inspection Report 05000454/2006005 and 05000455/2006005

w/Attachment:

Supplemental Informationcc w/encl:Site Vice President - Byron StationPlant 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 baselineinspections 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. NRC's 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 associatedwith 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 thedegradation 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 licensee's 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).

B.Licensee Identified Violations

None

3

REPORT DETAILS

Summary of Plant StatusUnit 1 operated at or near full power throughout the inspection period with the followingexception:*On October 23, 2006, the unit returned to full power from a refueling outage that startedon 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 followingexceptions:.*On October 21, 2006, the unit reduced power to 85 percent to perform turbine throttleand governor valve surveillances. The unit returned to full power on October 22,

REACTOR SAFETY

Cornerstone:

Initiating Events, Mitigating Systems, Barrier Integrity andEmergency Preparedness1R01Adverse Weather Protection (71111.01)

a. Inspection Scope

The inspectors reviewed the licensee's seasonal preparations for operation duringthe 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 apredicted 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 4susceptible to cold weather conditions and discussed weather-related issues during theOperations 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 (71111.04).1Partial Walkdowns

a. Inspection Scope

The inspectors performed one partial walkdown sample of accessible portions of trainsof 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 BRHR Pump was Out of Service.The inspectors also reviewed selected issues documented in IRs, to determine if theyhad been properly addressed in the licensee's 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.

51R05Fire Protection (71111.05).1Quarterly 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 designatedlocations 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 listedbelow 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 hadbeen properly addressed in the licensee's corrective action program. The inspectors also verified that minor issues identified during the inspection were entered into the licensee's 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.

6.2Drill Observation

a. Inspection Scope

The inspectors assessed the fire brigade performance and the drill evaluator's critiqueduring 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 fightingand 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 brigade's performance using the licensee's established fire drill performance procedure criteria. The inspectors also reviewed the qualification and training of the fire brigade and therequired 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 (71111.06).1External Flooding Review

a. Inspection Scope

The inspectors reviewed Byron's flood analysis and design basis documents to identifydesign 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 duringthis inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

7.2Internal 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 Pumpsincluding the covers over the Essential Service Water Pumps.This review represented one inspection sample. Documents reviewed during thisinspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07A)

a. Inspection Scope

The inspectors completed one annual testing and performance review inspectionsample by observing and evaluating the licensee's 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 theyhad been properly addressed in the licensee's 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 (71111.08)

.1 Piping systems Inservice Inspection Activities

a. Inspection Scope

From September 11, 2006 through September 15, 2006, the inspectors conducted areview of the implementation of the licensee's 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 licensee's 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.

8The inspectors observed two types of nondestructive examination (NDE) activities,specifically Ultrasonic Examination and Visual Examination, to evaluate compliancewith 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 pipeto 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 thelicensee for continued service.The inspectors reviewed a pressure boundary weld for a Class 1 system which wascompleted 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 bythe 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 pressureboundary 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.

9.2Pressurized 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..3Boric Acid Corrosion Control (BACC) ISI

a. Inspection Scope

From September 11, 2006 through September 14, 2006, the inspectors reviewed theBACC 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 toevaluate 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 followingcorrective action documents to ensure that ASME Code wall thickness requirements were maintained:*IR 477473, component 1SI059A; Containment Recirc Sump to ContainmentSpray/Residual Heat Removal Test Connection Isolation Valve; and*IR 306134; component 1 RC8029C; Unit 1Loop C Reactor Coolant BypassVent Valve.The inspectors also reviewed a number of boric acid leak corrective actions todetermine 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..4Steam Generator Tube ISI Steam generator inspections were not scheduled to be performed this outage. Therefore, no inspection sample was credited..5Identification and Resolution of ProblemsThe inspectors performed a review of ISI-related problems that were identified by thelicensee 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 issuesrelated 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 (71111.11).1Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors completed one inspection sample by observing and evaluating theresponse 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;
  • Supervisor's command and control;
  • Management oversight; and
  • Group dynamics.

11The inspectors verified that the crew completed the critical tasks listed in the abovesimulator guide. The inspectors also compared simulator configurations with actual control board configurations. For any weaknesses identified, the inspectors observed the licensee's 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 licensee's corrective action program.The documents reviewed during this inspection are listed in the Attachment to thisreport.

b. Findings

No findings of significance were identified..2Facility Operating History

a. Inspection Scope

The inspectors reviewed the plant's operating history from October 2004 throughOctober 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 station's 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 thisreport.

b. Findings

No findings of significance were identified..3Licensee Requalification Examinations

a. Inspection Scope

The inspectors performed a biennial inspection of the licensee's LORT test/examinationprogram for compliance with the station's 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 12reviewed the methodology for developing the examinations, including the LORTprogram 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 thisreport.

b. Findings

No findings of significance were identified..4Licensee Administration of Requalification Examinations

a. Inspection Scope

The inspectors observed the administration of a requalification operating test to assessthe licensee's 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 thisreport.

b. Findings

No findings of significance were identified..5Examination Security

a. Inspection Scope

The inspectors observed and reviewed the licensee's overall licensed operatorrequalification 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 licensee's 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.

13The documents reviewed during this inspection are listed in the Attachment to thisreport.

b. Findings

No findings of significance were identified..6Licensee Training Feedback System

a. Inspection Scope

The inspectors assessed the methods and effectiveness of the licensee's processesfor 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 licensee's quality assurance oversight activities, including licensee training department self-assessment reports. The inspectors evaluated the licensee's 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 licensee's SAT program.The documents reviewed during this inspection are listed in the Attachment to thisreport.

b. Findings

No findings of significance were identified..7Licensee Remedial Training Program

a. Inspection Scope

The inspectors assessed the adequacy and effectiveness of the remedial trainingconducted since the previous biennial requalification examinations and the trainingfrom 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 trainingplans. This evaluation was performed in accordance with 10 CFR 55.59 © "Requalification program requirements" and with respect to the licensee's SAT program.The documents reviewed during this inspection are listed in the Attachment to thisreport.

b. Findings

No findings of significance were identified.

14.8Conformance With Operator License Conditions

a. Inspection Scope

The inspectors reviewed the facility and individual operator licensees' conformancewith 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 compliancewith 10 CFR 55.53 (I).The documents reviewed during this inspection are listed in the Attachment to thisreport.

b. Findings

No findings of significance were identified..9Conformance With Simulator Requirements Specified in 10 CFR 55.46

a. Inspection Scope

The inspectors assessed the adequacy of the licensee's 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 licensee's simulator staff about the configuration control process and completed the IP 71111.11, Appendix C, checklist to evaluate whether or not the licensee's 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 thisreport.

b. Findings

No findings of significance were identified.

15.10Annual Operating Test Results and Biennial Written Examination Results

a. Inspection Scope

The inspectors reviewed the pass/fail results of the individual biennial writtenexaminations, 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 thisreport.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors completed three inspection samples by evaluating the licensee'simplementation 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 ifthey had been properly addressed in the licensee's 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 (71111.13)

a. Inspection Scope

The inspectors reviewed the licensee's management of plant risk during emergentmaintenance 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, andIndividual 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 EssentialService Water Basin Level was lowered for Repair;*Unit 2 Train B Residual Heat Removal Pump Work Window while DC Bus 212was cross-tied to DC Bus 112; and*Unit 1 DC Bus 112 Battery Charger was out of service while System AuxiliaryTransformer 142-2 was in a Work Window.The documents reviewed during this inspection are listed in the Attachment to thisreport.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors evaluated plant conditions, selected condition reports, engineeringevaluations, 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.

17The 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 sectionsof the TS including the TS Basis, the Technical Requirements Manual (TRM) and the UFSAR to the licensee's 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 licensee's engineering staff.The inspectors also reviewed selected issues documented in IRs, to determine if theyhad been properly addressed in the licensee's 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 (71111.19)

a. Inspection Scope

The inspectors reviewed the post maintenance testing activities associated withmaintenance or modification of mitigating, barrier integrity, and support systems that were identified as risk significant in the licensee's 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 thepost maintenance testing subsequent to the following maintenance activities:*Actuator Replacement of the Unit 1 Train B Diesel Generator (DG) roomventilation Damper, 1VD10YA;*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; 18*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 IR's to determine ifthey had been properly addressed in the licensee's 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 (71111.20)

a. Inspection Scope

The inspectors observed the licensee's performance during Refueling Outage B1R14beginning 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 licensee's conduct of refueling outage activities to assessthe licensee's 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 unexpectedreactivity changes;*flow paths, configurations, and alternate means for reactor coolant systeminventory 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 inaccordance 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 tocriticality 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 19could assess the material condition of equipment inside containment before containmentclosure. 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 verifythat 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 searchfor 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 licensee's approach to initial criticality, initial criticality, corereload 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 thisreport.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors witnessed selected surveillance tests and/or reviewed test data todetermine 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. Thefollowing surveillance tests were selected:*1BOSR 0.5-2.AF.1-1, "Stroke Time Testing for Auxilary Feedwater SystemValves 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 reportto 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 licensee's requirements, and that the test equipment used during 20the test were calibrated within the specified periodicity. In addition, the inspectorsinterviewed operations, maintenance, and engineering department personnel regarding the tests and test results. The documents reviewed during this inspection are listed in the Attachment to thisreport.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications (71111.23)

a. Inspection Scope

The inspectors completed two inspection samples by evaluating the following temporaryplant 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 EmergencyDiesel Generator.The inspectors reviewed this temporary plant modification to determine that theinstructions 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 thisreport.

b. Findings

No findings of significance were identified.1EP4Emergency Action Level and Emergency Plan Changes (71114.04)

a. Inspection Scope

The inspectors completed a screening review of Revision 17 of the Byron Station Annexof the Exelon Standardized Emergency Plan to determine whether changes identified in this Annex revision may have reduced the effectiveness of the licensee's 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 thisinspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

Main article: IP 71114.06

a. Inspection Scope

On October 23, 2006, the inspectors complete one inspection sample by observingan emergency preparedness drill. The inspectors assessed the licensee's drill performance and looked for weaknesses in the risk significance areas of emergency classification, notification and protective action development. The inspectors observed the licensee's performance from the simulator control room. The inspectors compared issues noted during their observations to those identified during the licensee's critique.

Additionally, the inspectors verified that items identified during the licensee's critique were appropriately entered into their corrective action program.The documents reviewed during this inspection are listed in the Attachment to thisreport.

b. Findings

No findings of significance were identified.2.RADIATION SAFETYCornerstone: Occupational Radiation Safety2OS1Access Control to Radiologically Significant Areas (IP 71121.01).1Inspection Planninga.Inspection ScopeThe inspectors reviewed the licensee Performance Indicator for the OccupationalExposure Cornerstone for followup. This review represented one sample.

b. Findings

No findings of significance were identified..2Plant Walk Downs and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors examined the licensee's physical and programmatic controls for highlyactivated 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..3Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed the licensee's self-assessments, audits, Licensee EventReports, 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 licensee's self-assessment activities were also identifyingand 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 Indicatorevents 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..4Job-In-Progress Reviews

a. Inspection Scope

The inspectors reviewed the adequacy of radiological controls, radiation protectionjob 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 topersonnel 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.

23.5 High Risk Significant, High Dose Rate, High Radiation Area and Very High RadiationArea Controls

a. Inspection Scope

The inspectors discussed high dose rate-high radiation area and very high radiationarea 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 reducethe effectiveness and level of worker protection. This review represented one sample.The inspectors discussed with first-line radiation protection supervisors, or equivalentpositions 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 accessiblehigh dose rate-high radiation areas and very high radiation areas. This review represented one sample.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES4OA2Identification and Resolution of Problems (71152).1Review 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 licensee's 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 licensee's ability to identify operator workarounds as wellas 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 24records review was conducted which included the adverse condition monitoringprogram, 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 ObservationsThe licensee's corporate procedure for classifying operator workarounds created thecategory 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..3Semiannual Review to Identify Trends

a. Inspection Scope

The inspectors performed a review of the licensee's 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 licensee's mechanisms for identifying and correcting trends.The review was accomplished by grouping IRs into broad categories during the dailyscreenings. 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 identifiedwhen 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 fivesafety-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 controlof 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, usingIMC 0609, "Significance Determination Process," dated November 22, 2005, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power 26Situations," dated November 22, 2005. As stated the failure to have setpoint control ofthe 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 thatthis 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 regulatoryrequirements 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 IRswith 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 andevaluated 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 beenalready 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 routinesurveillance. The operators did a prompt controlled shutdown of the DG when the right bank air intake manifold temperature started swinging and reached

162F. This exceeded the procedural limit of 160F. A note in the surveillanceprocedure (BOP DG-11T2) stated that the DG was to be tripped if the procedural limit of 160F was exceeded. IR 438719 was written addressing the cause of 27the high temperature and performed an operability assessment. This IR didnot 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 160F was for normal mode only and was not a limitrequired 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 similarcondition. 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 containmentradiation 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 toreplace 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 instrument's ability to perform its intended safety function.The licensee had already recognized the need to focus on site wide procedureadherence 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.

284OA3Event Follow-up (71153).1(Closed) LER 454-2006-003-00: Inadvertent Exceeding of TS Action RequirementCompletion Time for Containment Spray Additive System Due to Not Recognizing an Inoperable ConditionOn August 11, 2006, the licensee identified a pressure boundary weld leak in anASME 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.4OA5Other ActivitiesMitigating Systems Performance Index Verification (Temporary Instruction 2515/169)

a. Inspection Scope

The Mitigating System Performance Index (MSPI) was developed to replace the SafetySystem 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 licensee's basis document and evaluated theimplementation 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.

29 b.Evaluation of Inspections Requirements1.For the sample selected, did the licensee accurately document the baselineplanned unavailability hours for the MSPI systems?The inspectors identified that the licensee had prepared two sets of baselinedata 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 revisingthe 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.2.For the sample selected, did the licensee accurately document the actualunavailability hours for the MSPI systems?The inspectors identified numerous instances in several MSPI systems that theunavailability 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.3.For the sample selected, did the licensee accurately document the actualunreliability information for each MSPI monitored component?The inspectors identified several instances where failure information for theemergency diesel generator was not being documented appropriately. These discrepancies were related to the capability of the opposite unit's 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 systemtrains 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.

30The inspectors identified several past failures that affected the test mode (ormanual 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 onlybe 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 licensee's determination for the followingreasons: 1) The function monitored for the emergency AC power system is the ability ofthe 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 dieselgenerators 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 availableto 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 resultedin a change to the indicated index color? Describe the actual condition andcorrective actions taken by the licensee, including the date when the revisedPI information was submitted to the NRC.The inspectors did not identify significant errors in the reported data, whichresulted 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 31expected from this review. The inspectors will perform verification of the changeas part of the ongoing performance indicator verification process of the ROP.5.Did the inspector identify significant discrepancies in the basis document whichresulted in

(1) a change to the system boundary;
(2) an addition of a monitoredcomponent; or
(3) a change in the reported index color? Describe the actualcondition and corrective actions taken by the licensee, including, the date ofwhen the bases document was revised.The inspectors did not identify significant discrepancies in the basis documentwhich 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.4OA6Meetings.1On January 16, 2007, the resident inspectors presented the inspection results toMr. 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..2Interim Exit MeetingsInterim exits were conducted for:

  • Inservice Inspection Activities Inspection with Mr. D. Hoots and other membersof 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 radiologicallysignificant 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 onNovember 3, 2006.

32*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, EmergencyPreparedness 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 TrainingNuclear Regulatory Commission
R. Skokowski, Chief, Branch 3, Division of Reactor Projects

2

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened NoneOpened and

Closed

05000454/2006005-01
05000455/FIN-2006005-01FINFailure to have setpoint control of the constant leveloilers on safety-related pumps

Closed

05000454/2006005-01
05000455/FIN-2006005-01FINFailure to have setpoint control of the constant leveloilers on safety-related pumps

Discussed

None

3

LIST OF DOCUMENTS REVIEWED

The following is a list of documents reviewed during the inspection.

Inclusion on this list doesnot imply that the NRC inspectors reviewed the documents in their entirety but rather that selected sections of portions of the documents were evaluated as part of the overall inspection effort.
Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report.
1R01Adverse Weather Protection0BOSR
XFT-A1; Freezing Temperature Equipment Protection SH and Department SupportRequirements, Revision 9
0BOSR
XFT-A2; Freezing Temperature Equipment Protection Auxiliary Steam Boilers, Revision 1
0BOSR
XFT-A3; Winter Readiness Surveillance Discrepancies, November 19, 2006
0BOSR
XFT-A5; Freezing Temperature Equipment Protection Non-Protected Area Buildings Ventilation Systems, Revision 2
Byron Station Test Report; Condensate Storage Tank Temperature Indicating Switch 1TIS-CD053, Revision 1
IR 561806; PWST Heater Vent Caps Are Not Per Design, November 20, 2006
IR 561812; Unexplained Unit 2 CST Level Pertibations, November 25, 2006
IR 562347; Unit 2 CST Heaters Need Draining, November 27, 2006
IR 562348; Unit 0A PWST Heaters Need Draining and New Vent Caps, November 27, 2006
IR 562351; Unit 0B PWST Heaters Need Draining and New Vent Caps, November 27, 2006
IR 564343; Unit 1 CST Heaters Need Draining, November 27, 2006
IR 567089; River Screen House Temperature Alarm Comes in Early, December 08, 2006
IR 567427; Potential for Freezing Pipes, December 10, 2006Corrective Action Documents as a Result of NRC InspectionIR
560928; Loose Debris Around SX Tower During Fan Replacement Project, November 21,2006 (NRC Identified)
1R04Equipment AlignmentBOP RH E2A; Residual Heat Removal System, Unit 2 Electrical Lineup, Revision 3BOP
RH-M2A; Train "A" Residual Heat Removal System Valve Lineup, Revision 6
1R05Fire ProtectionIR
543978; Print Not Updated to Reflect a Change in Fire Seal Status, October 14, 2006IR
559556; Lessons Learned From Offsite Fire Drill, November 17, 2006
Pre Fire Plan; "Auxiliary Building Elevation 383'-0" - Zone 11.4A-2" Fire Safety Analysis Report; Section 2.3.11.31, "Unit 2 Auxiliary Feedwater Diesel - Driven Pump Room," Fire Zone 11.4A-1
Fire Safety Analysis Report; Section 2.3.11.32, "Unit 2 Auxiliary feedwater Diesel-Driven Pump Room," Fire Zone 11.4A-2
46E-Q-4Q30VA61; "Diesel Driven Auxiliary Feedwater Pump & Day Tank Room CO2 FireProtection System Fire Damper Control Catalog ID#23764; "Linkage, thermal, Electro, 165 DEG. F. Melting Point Fire Safety Analysis Report; Section 2.3.11.12, "Auxiliary Building General Area Level 364 feet inches, " Fire Zone 11.3-0
Pre Fire Plan; "Auxiliary Building Elevation 364' - 0 Basement Floor Zone 11.3-0 West, North, and South Fire Drill Scenario No. 37; Stores Warehouse w/Offsite Assistance, November 10, 2006
Pre Fire Plan; Unit 2 Lower Cable Spreading Room, Zone 3.2A-2
Pre Fire Plan; Unit 2 Lower Cable Spreading Room, Zone 3.2B-2
Pre Fire Plan; Unit 2 Lower Cable Spreading Room, Zone 3.2D-2
Pre Fire Plan; Unit 1 Lower Cable Spreading Room, Zone 3.2A-1
Pre Fire Plan; Unit 2 Turbine Building Elevation 426; Zone 8.5-2 Northwest Pre Fire Plan; Unit 2 Turbine Building Elevation 426; Zone 8.5-2 Northeast Pre Fire Plan; Unit 2 Turbine Building Elevation 426; Zone 8.5-2 Southwest Pre Fire Plan; Unit 2 Turbine Building Elevation 426; Zone 8.5-2 Southeast Fire Protection Report Appendix 5.2; Cable Systems Criteria, December 1990
IEEE 634-1978; IEEE Standard Cable Penetration Fire Stop Qualification Test Transco Test Report No.
TR-159; Fire and Hose Stream Tests of
TCO-001 Cement Used in Electrical Conduit Penetrations, November 15, 1984
Fire Test 6510-001; Fire and Hose Stream Test of Nine Penetration Seal Systems, August 1986
ASTM E119; Standard Test Methods for Fire Tests of Building Construction and Materials Drawing
FPS-724-BY; Fire Barrier Penetration Seal Surveillance; Revision A
Drawing
FPS-740-BY; Fire Barrier Penetration Seal Surveillance; Revision A
Drawing 6E-0-3905, Revision U, Fire Detection Grade Floor at El. 401'-0" Byron Drawing 6E-0-3906, Revision P, Fire Detection Mezzanine Floor at El. 426'-0" Byron Drawing 6E-2-3331, Revision BR, Electrical Installation Auxiliary Building Plan El. 401'-0", Columns L-QCorrective Action Documents as a Result of NRC InspectionIR
540438; NRC Question Concerning Fire Barrier on 383' Elevation, October 5, 2006(NRC Identified)
IR 545892; NRC Issue Identified for 0LL077E;October 18, 2006 (NRC Identified)
IR 546853; Pre-Fire Plan/Fire Protection Plan/Plant Discrepancy, October 20, 2006

(NRC Identified)

IR 574929; Issues with Fire Pre-Plans, December 22, 2006 (NRC Identified)
1R06Flood Protection MeasuresUFSAR Section 3.4, Water Level (Flood) Design; Revision 10, December 2006IR
557177; Revise 0BMSR
DD-1 To Update Acceptance Criteria, November 13, 2006
IR 557186; 0BMSR
DD-1 Add to Model Work Orders, November 13, 2006
IR 563669; 2A SX Sump Pump Discharge Valve 2WF040A is Leaking, November 30, 2006
5Corrective Action Documents as a Result of NRC InspectionIR
559022; Uncapped SX Drain line Above Unit 2 CC Pump Motors, November 16, 2006(NRC Identified)
1R07Heat Sink PerformanceWO
948789 01; 1SX01AA - Heat Exchanger Inspection per Generic Letter 89-13,November 21, 2006
BVP 800-30; Service Water System (Essential Service Water) Fouling Monitoring Program, Revision 9
1R08Inservice Inspection ActivitiesNDE ProceduresEXE-PDI-UT-1; Ultrasonic Examination of Ferritic Pipe Welds in Accordance with
PDI-UT-1;Revision 5
EXE-PDI-UT-2; Ultrasonic Examination of Austenitic Pipe Welds in Accordance with PDI-UT-2;
Revision 5
ER-AA-335-016;
VT-3 Visual Examination of Component Supports, Attachments and Interiors of Reactor Vessels; Revision 3
PDI Piping and Bolting Program; Krautkramer Model
USN-58Lsw and
USN-60sw; October 6,
2005
TQ-AA-122; Qualification and Certification of Nondestructive (NDE) Personnel; Revision 2Head ExamER-AP-331; Boric Acid Corrosion Control (BACC) Program; Revision 2ER-AP-331-1003; RCS Leakage Monitoring and Action Plan; Revision 0
ER-AP-331-1004; Boric Acid Corrosion Control (BACC) Training and Qualification; Revision 1NDE Exam DocumentsWO
00816082-66; OBS #14-194, 195, 196:
ISI Examination Summary; UT Weld InspectionReport; November 11, 2006
WO 00731033;
VT-3 Examination Report for Snubbers 1MS08007-S1 and 1CC24013S;
September 14, 2006
WO 00831572; Determine Unit 1 EDY (NRC Order
EA-03-009); August 21, 2006
WO 00650401; Unit 1 ASME Section XI Pressure Test (Class 1) - Post Refuel; March 17, 2005
ISO
MS-15; Large Bore Isometric Main Steam (MS) System; Revision 9
ISO
CC-40;
SYS-Component Cooling Sta-Byron Unit-1; Revision E
Equipment Equivalence; Krautkramer Model
USN-58Lsw and
USN-60sw; October 6, 2005Corrective Action DocumentsIR
296825; Work Order Scope Change not Reviewed Through RRR Process:
February 2, 2005
6IR
504160; Deficiencies Identified During ISI Programs FASA; June 27, 2006IR
307161; Incorrect Size (Class-D) Snubber "1SD21033S"; March 2, 2005
IR 453027;
ER-AA-335-030 Rev. 2 Comments; February 12, 2006
IR 372536;
VT-2 PMT Discrepancy; September 12, 2005
IR 453301; U-1 SFP HX Outlet Isolation Valve; February 13, 2006
IR 453320; U-1 RCP Seal Inj. Header Vent Valve; February 13, 2006
IR 455325; U-1 Pressurizer Liquid Sample Vent Conn Isolation Valve; February 17, 2006
IR 462938; 1A CV EENT Chg PP; March 7, 2006
RS-06-117; Clarification of Relaxation Request for First Revised Order (EA-03-009); August 28,
2006
B1R13 Control Rod Drive Mechanism Volumetric Examinations; Discussions of Significance ofSurface Scratches Found on reactor Vessel Upper Head Penetrations; June 23, 2005Welding DocumentsWO00706874-01; U-1 Pressurizer 1RY01S Auxiliary Spray Header Check Valve;August 23, 2004Corrective Action Documents as a Result of NRC InspectionIR00379827; Overly Conservative Use of Recordable Indication per IWF; September 29, 2006(NRC Identified)
IR 531366; Numerous Housekeeping Concerns in Unit 1 Refueling Water Storage Tank Tunnel, September 14, 2006 (NRC Identified)
1R11Licensed Operator Requalification ProgramByron ROP Plant Issue Matrix from June 1, 2004 to October 11, 2006; October 11, 2006Byron Station, Units 1 and 2 NRC Integrated Inspection Reports; dated various from November 6, 2004 through August 3, 2006
LER 454-2005-004-00; TS Required Action Not Satisfied Due to Ambiguous Implementing Procedure; May 24, 2005
Seven Licensed Operators' Medical Records; dated various
FASA
AT 370526; Focused Area Self-Assessment Report; Byron Licensed Operator Requalification Training; May 8, 2006 through May 12, 2006
FASA
AT 390926; Focused Area Self-Assessment Report; Operations Training Program Comprehensive Self-Assessment; May 17, 2006
IR 494164; UFSAR Time-Critical Task Evaluation Results - Loss of All AC; May 26, 2006
IR 502730; Licensed Operator Time Critical Task Evaluation -SGTR, June 22, 2006
IR 507358; UFSAR Time-Critical Task Evaluation Results - Cold Leg Recirc; July 7, 2006
Completed
TQ-AA-210-4101; Remedial Training Notification and Action on Failure; various from September 10, 2004 through October 13, 2006
Licensed Operator Requalification Long Range Training Plan; 2005 through 2006
Completed
TQ-AA-106-0102; Licensed Operator Requal Training Classroom Attendance Sheet; dated various Completed
TQ-AA-106-0103; Licensed Operator Requal Training (Simulator Attendance);

dated various Completed

TQ-AA-210-5101; Training Observation Form; dated various
7Completed
TQ-AA-210-5103; Trainee Reaction - Multiple Topic; dated variousCompleted
TQ-AA-210-5106; LORT Evaluation Summary; dated various from June 27, 2004

through July 16, 2006

Completed
TQ-AA-106-113; Simulator Demonstration Examination Individual Competency Form; dated various Completed
TQ-AA-106-114; Simulator Demonstration Examination Crew Competency Form;

dated various Completed

TQ-AA-106-116; Licensed Operator Requal Training JPM Evaluation Summary;

dated various Completed

OP-AA-105-102; Attachment 1; Active License Tracking Log; dated various Completed
OP-AA-105-102; Attachment 2; Reactivation of License Log; dated various
2004 Byron Station Licensed Requalification Exam Report
2005 Byron Station Licensed Requalification Exam Report
TQ-AA-106; Licensed Operator Requal Training Program; Revision 8
TQ-AA-106-0302; Licensed Operator Training Simulator Training Scenario Development Job Aid; Revision 0
TQ-AA-106-0303; Licensed Operator Training Job Performance Measure Development Job Aid; Revision 2
TQ-AA-106-0304; Licensed Operator Training Exam Development Job Aid; Revision 7
TQ-AA-106-0307; Licensed Operator Requal Training Cycle Simulator Evaluation Job Aid;Revision 1
TQ-AA-201; Examination Security and Administration; Revision 8
TQ-AA-204; Training Management System; Revision 0
TQ-AA-301; Simulator Configuration Management; Revision 6
TQ-AA-301-0301; Simulator SWR Prioritization Maintenance, Modification, and Enhancements;
Revision 2
TQ-AA-302; Simulator Testing and Documentation; Revision 6
TQ-AA-303; Controlling Simulator Core Update and Thermal-Hydraulic Model Updates;
Revision 4
TQ-BY-302-0101; Byron Plant-Referenced Simulator Certification Plan; Revision 0
Byron Simulator and Plant Differences; Training Load BY0604.00
ANSI/ANS-3.5-1985; Nuclear Power Plant Simulators for Use in Operator Training; October 25,
1985
Regulatory Guide 1.149; Nuclear Power Plant Simulation Facilities for Use in Operator License Examinations; Revision 1; April 1987
Simulator Malfunction Tests; dated various Simulator Transient Tests; dated various Simulator Steady State Tests; dated various Simulator Core Performance Tests; dated various Simulator Review Board Meeting Minutes; dated various from January 6, 2005 through October 19, 2006
Simulator Testing Review Board Meeting Minutes; dated various from June 24, 2005 through June 24, 2006
List of Open Simulator Work Requests; October 27, 2006
Open
SWR 7701; DEHC Upgrade - TV/GV Test Response; April 7, 2005
Open
SWR 8869; 1SA033 IA Supply Appears to be from Aux Bldg vs. Containment; April 18,
2006
Open
SWR 9150; CV System Flow Oscillation; July 24, 2006
8Open
SWR 9360; LTOP Lift Setpoint Changes Due to PTLR Revision; September 25, 2006List of Closed Simulator Work Requests for Last 12 Months; October 27, 2006
Closed
SWR 6302; 1SA033 and 1IA066 Improper Response to
MF-RP04; June 7, 2004
Closed
SWR 7511; Add Malfunction for Loss of MPT Cooling; February 16, 2005
Closed
SWR 7915; Compare Data from 2B FW Pump trip to Simulator for STRB; June 3, 2005
Closed
SWR 7985; Spike in Steam Flows and Temperatures Dropping Quicker in Some Transient Tests; June 29, 2005
Closed
SWR 8021; Determine if Tavg Effects during Test
TR-6 Are Acceptable; July 14, 2005
List of Open Training Requests; November 1, 2006
List of Closed Training Work Requests for Last 12 Months; October 31, 2006
Training Performance Indicators - Simulator Manager Input; October 13, 2004 through May 24,
2006
Closed
TR 04-718; Trainee Reaction
TQ-AA-210-5103 for LORT Cycle 04-5; October 14, 2004
Closed
TR 04-728; Trainee Reaction
TQ-AA-210-5103; June 3, 2005
Closed
TR 04-723; Trainee Reaction
TQ-AA-210-5103 for LORT Cycle 04-5; September 17,
2004
Closed
TR 04-718; Trainee Reaction
TQ-AA-210-5103 04-7 Crew C; April 28, 2005
Closed
TR 05-463; Student Provided Feedback; January 11, 2006
LORT Cycle Curriculum Review Committee Meeting Minutes; dated various from October 13,
2004 through May 24, 2006
Requalification Examinations (Operating); dated various 2006
Requalification Examinations (Written); dated various 2006Corrective Action Documents as a Result of NRC InspectionIR
551556; Training:
Simulator Work Request Issue; October 31, 2006 (NRC Identified)IR
558176; Segregation of Students, Training Improvement Opportunity, November 3, 2006

(NRC Identified)

IR 558180; Low Quality Package, Training Improvement Opportunity, November 3, 2006

(NRC Identified)

IR was Initiated Based on NRC Observations During Inspection (NRC Identified)
1R12Maintenance Effectiveness

(A)(1) Action Plan for VV1, July 13, 2005Material Condition Improvement Plan; MSIV/Safety Valve Enclosure Ventilation Modification, August 03, 2005

IR 264685; Found 1VV01CD Running With No Discharge or Recirculation Path, October 18,
2004
IR 318059; Temperature Controller (Thermostat) Has Failed, March 28, 2005
IR 318063; Temperature Controller (Thermostat) Failed for 1D MSIV Room, March 28, 2005
IR 344768; 2A MSIV Vent Fan Discharge Damper is Closed, June 16, 2005
IR 553349; 1A DG Cooldown Cycle Failure Causes Delay in SAT Outage, November 04, 2006
IR 556907; Question Whether the 1A DG is Operable, November 12, 2006
Apparent Cause Report; 1A DG Slowed to Idle Speed Due to Relay Failure, December 13, 2006
BYR-28090; Failure Analysis (1) Killovac Relay PD10AC57, November 22, 2006
1R13Maintenance Risk Assessment and Emergent Work Control Unit 2 Risk Configurations, Week of October 02, 2006, Revision 1Protected Equipment Log, October 5, 2006
IR 541127; Disabling TS Equipment to Prevent Valid Auto Start, October 6, 2006
WC-AA-101; Attachment 7 to Protected Equipment Process and Methodology, Revision 13
Unit 1 Risk Configurations, Week of November 06, 2006, Revision 2
Unit 1 Risk Configurations, Week of November 06, 2006, Revision 3
Unit 2 Risk Configurations, Week of November 06, 2006, Revision 2
Protected Equipment Log, November 06, 2006
Policy No. 400-47; Byron Operating Department Policy Statement, Revision 9Corrective Action Documents as a Result of NRC InspectionIR
559537; Weaknesses in Byron's Protected Equipment Program, November 17, 2006(NRC Identified)
1R14Personnel Performance During Non-Routine EvolutionsOctober 23, 2006 Byron Station Emergency Preparedness & Security Integrated Drill EvaluationReport, November 26, 2006
1R15Operability EvaluationsIR
262818; Debris Discovered in 2B SX Pump Lube Oil Reservoir, October 12, 2004IR
543978; Print Not Updated to Reflect a Change in Fire Seal Status, October 14, 2006
IR 559556; Lessons Learned From Offsite Fire Drill, November 17, 2006
IR 563447; 2SX01PB Found FME Thrust Bearing Disassembly, November 30, 2006
1A SX Pump Trend; November 27, 2006 - December 27, 2006
1B SX Pump Trend; November 12, 2006 - December 12, 2006
2A SX Pump Trend; November 12, 2006 - December 12, 2006
2B SX Pump Trend; November 27, 2006 - December 27, 2006
EC 378409; Evaluate Damaged Outboard Thrust Bearing Housing Damage During Pump Repair Work, Revision 0
ER-AA-2006; Lost Parts Evaluations, Revision 3
MA-AA-716-008; Attachment 10 - Loss of Integrity Notification and Recovery Plan, Revision 2Corrective Action Documents as a Result of NRC InspectionIR
540438; NRC Question Concerning Fire Barrier on 383 Elevation, October 5, 2006(NRC Identified)
545892; NRC Issue Identified for 0LL077E;October 18, 2006 (NRC Identified)
IR 546853; Pre-Fire Plan/Fire Protection Plan/Plant Discrepancy, October 20, 2006

(NRC Identified)

1R19Post Maintenance TestingWO
736551-01; MM - Upgrade Seal Cooling Water Supply Piping, November 30, 2006WO
736551-03; OPS PMT - Visual, December 11, 2006
WO 736551-10; OPS PMV - Verify Flood Seal Reinstalled, December 11, 2006
WO 736551-11; OPS PMV - Verify Blind Flange Reinstalled, December 11, 2006
WO 821150-01; IM Perform Calibration of 2FIS-0611
WO 826580; stroke 1SI8811A with following valves aligned
WO 826589; Replace AR Relay - Containment Sump ISO Valve Relay SI8811
WO 832925-01; MM - Repair Outboard Bearing Oil Leak/Replace Oil Pump, December 01, 2006
WO 832925-02; Remove/Reinstall Thermocouple From 0B Bearing Housing, November 30,
2006
WO 832925-03; OP - PMT; No Oil Leakage and Pump Temperatures Are Normal, December 13, 2006
WO 876174 09; OPS - PMT MOD Test Perform BOP
VV-1 & Remove Temperature Vent, December 13, 2006
WO 945382 01; Stroke Time Test for 2RH611, November 5, 2006
WO 945714 02; OP Post Maintenance Test, Verify Proper RH Pump Motor Oil Level
WO 947256 01; 2RH01PB Group A First Requirements for Residual Heat Removal Pump, November 7, 2006
WO 947256 02; Instrument Maintenance Support 2BVSR 5.5.8.RH.5-2A 2B RH ASME Pump Run, November 7, 2007
WO 965021; "MCR Fire Panel Fie Zones 1D-47/48 & 1S-36
WO 966203; Troubleshoot Recirculating Dampers 1VD10YA & B
IR 544073; VD System Temperature Controller Not Controlling 1A DG Room
IR 569039; LO DP Alarm 1VV01CC, December 13, 2006
MA-BY-EM-1-FP001-B-BY04; "Test Report Package Suppression Zone 1S-36, Detection Zone
1D-47/48 Fire Zone 3.3D, System Number 1EE4," dated 04/07/06
MA-BY-EM-1-FP001; "Upper Cable Spreading Room Halon System Actuation Surveillance," Revision 9
BAR 0-37-A4; Unit 1 Area Fire
6E-1-4030FP04; Fire Detection Control Cabinet
IR 569062; 1VV01CC Failed PMT for
WO 876174, December 13, 2006
1R20Refueling and Outage ActivitiesEngineering Change
363000; Evaluation for Foreign Material Left in Unit 1 ContainmentIR
541200; Low Sensitivity to Foreign Material in Containment, October 2, 2006
IR 544308; Not Getting the Message on Containment FME, October 15, 2006
Evaluation of Boric Acid Leakage; Unit 1 In-Core Support/Reactor Vessel Outside Surfaces, Revision 3
B1R14 Shutdown Risk Profile, October 1 - 13, 2006
B1R14 Outage News, October 1 - 15, 2006
11Corrective Action Documents As A Result of NRC InspectionIR
544108; NRC Question During Unit 1 Containment Walkdown in Mode 3, October 14, 2006(NRC Identified)
IR 544092; Issues During Unit 1 Containment Walkdown in Mode 3, Many a Repeat of Previously Identified Cleanliness Issues on the Polar Crane, October 14, 2006 (NRC Identified)
1R22Surveillance TestingWO
935255 01; Unit 0 Deep Well Pump Make-up Flow Verification, December 27, 20061BOSR 0.5-2.AF.1-1, Stroke Time Testing for Valves 1AF013 A through D
1R23Temporary Plant ModificationsEngineering Change
363128; Provide RCS Loop 1B Hot Leg Indication to RemoteEngineering Change
363442; Install Jumper at A1-A2 of Relay 43FSX in Panel 1PL07J to Defeat Slow Start Capability of the 1A Diesel Generator, Revision 0
Shutdown Panel Via Use of Spare Narrow Range RTDS, Revision 0
IR 556827; 1A DG Shifted to Slow After Being in Fast, 12 Hour Shutdown Clock, November 12,
2006
IR 556907; Question Whether the 1A DG is Operable, November 12, 2006Corrective Action Documents As A Result of NRC InspectionIR
554339; 50.59 Screening Requires Revision, November 6, 2006 (NRC Identified)

2OS1 Access Control to Radiologically Significant AreasRP-AA-460; Controls for High and Very High Radiation Areas; Revision 11RP-AA-460-1001; Additional High Radiation Exposure Control; Revision 1

RP-AA-19; High Radiation Area Program Description; Revision 1
RP-AA-376; Radiological Postings, Labeling and Markings; Revision 1
RP-BY-500-1003; Radiological Controls for Handling Items and Hanging Activated Parts in the Spent Fuel Pool; Revision 1

1EP4 Emergency Action Level and Emergency Plan ChangesByron Station Annex of the Exelon Standardized Emergency Plan; Revision 17

1EP6Drill EvaluationNuclear Accident Reporting System (ARs) Form, October 23, 2006EP-AA-112-F-01; Command and Control Turnover Briefing Form, Revision B
Byron EP/Security Integrated PI Drill, October 23, 2006
LS-AA-1150; Reactor Plant Event Notification Worksheet, Revision 0
240A2Identification and Resolution of ProblemsIR
350579; 1B DG Air Manifold Temperature Swinging, July 06, 2005IR
374363; SOS to Perform Aggregate Assessment of Operator Work Arounds, November 30,
2006
IR 438719; Temperature Swings During 1B DG Run, January 04, 2006
IR 544667; Work Inside Missile Barrier During Mode Change, October 15, 2006
IR 567449; Procedure Change Needed for Units 1 & 2 BOSR
DG-2/3, December 08, 2006
WO 901581, OWA Coordinator to Review Degraded Equipment List, Temporary Modification Log, Out of Service Log, etc , June 10, 2006
WO 929912, OWA Coordinator to Review Degraded Equipment List, Temporary Modification Log, Out of Service Log, etc , September 4, 2006
OP-AA-102-103, "Operator Work-Around Program," Revision 1
Standing Order 06-059, 1/2 BOA Elec-3 Procedure Weakness in Resetting DG Overspeed Trip, dated November 13, 2006
Standing Order 06-060, Recent Observations of Operating Responsible Areas Identified 2
Deficiencies-housekeeping and log keeping, dated November 12, 2006
Listing of all 2006 IRs by Significance level Listing of all 2006 Apparent Cause Evaluations Listing of all 2006 Common Cause Assessments Listing of all 2006 Quick Human Performance Investigations Listing of all 2006 IRs Coded Level 3 and Above that were Human Performance or Technical Human Performance Common Cause Analysis
551404-12; Engineering Corrective Action Program Quarterly Trending Identified Human Error Prevention Issues, December 14, 2006
Engineering Change
352661; Non-Safety Related Pump Trico Oiler Relocation
MA-AA-734-400; Constant Level Oiler and Sight-Glass Maintenance, Revision 0
BAP 370-1; Station Lubrication Program, Revision 9Corrective Action Documents as a Result of NRC InspectionIR
441546; Question Regarding Necessity to BOP
DG-11T2 Procedure Revision, January 04,2006 (NRC Identified)
IR 559496; Oiler Piping Needs to Reflect OEM Drawing, November 17, 2006 (NRC Identified)
IR 559601; Discrepancies with Oiler Piping Installation, November 17, 2006 (NRC Identified)
IR 559604; Discrepancies with Oiler Piping and Oiler Bowl Size, November 17, 2006

(NRC Identified)

IR 569751; Evaluate 1B AF Pump Gearbox Oil PP for Operator Challenge, December 15, 2006

(NRC Identified) 4OA3Event Follow-upLER 454/2006-003; Inadvertent Exceeding of TS Action Requirement Completion Time forContainment Spray Additive System Due to Not Recognizing an Inoperable Condition, September 01, 2006

134OA5Other Activities
BB
PRA-017.27B; Byron Reactor Oversight Program MSPI Basis Document; Revision 2;BISR 3.4.2-200; Surveillance Calibration of Auxiliary Feedwater to Steam Generators A, B, C

and D Flow Control Loops, Revision

1BOSR 5.2.2-1; Unit 1 ECCS Venting and Valve Alignment Monthly Surveillance, Revision 23
1BOSR 0.5-2.AF.1-2; 1AF013E/F/G/H Stroke Test on Unit 1, Revision 4
1BOSR 0.5-2.CV.1-1; Chemical and Volume Control System "A" Train Miniflow Valve Stroke Test on Unit 1, Revision 6
1BOSR 0.5-2.RH.3-3; 1RH610 Position Indication Test for Unit 1, Revision 5
1BOSR 3.2.3-1; Unit 1 Undervoltage Simulated Start of 1A Auxiliary Feedwater Pump Monthly Surveillance, Revision 2
2BOSR 5.2.2-1; Unit 2 ECCS Venting and Valve Alignment Monthly Surveillance, Revision 17
2BOSR 0.5-2.RH.2-2; Unit 2 train B Residual Heat Removal System Valve Stroke and Position Indication Test, Revision 7
2BOSR 0.5-2.SI.2-2.2; 2SI18802B, 2SI8809B, 2SI8811B and 2SI8923B Stroke Test and Position Indication Test, Revision 7
2BOSR 0.5-3.CC.1-3.1; 2CC9412A Stroke Test for Unit 2
2BOSR 3.2.8-620A; Unit 2 ESFAS Instrumentation Slave Relay Surveillance (Train A Auxiliary Feedwater Actuation - Relay K633, K62-0), Revision 0
1BVSR 5.5.8.CC.5-2c; Unit 1 Comprehensive Inservice Testing (IST) Surveillance Requirements for Component Cooling Pump 1CC01PB, Revision 0
2BVSR 5.5.8.RH.5-1a; Unit 2 Group A Inservice Testing (IST) Requirements for Residual Heat Removal Pump 2RH01PA, Revision 0
BOP
RH-5; RH System Startup for Recirculation, Revision 22
BOP
SI-9; Lowering SI Accumulator Pressure, Revision 9
IR 552111; MSPI AF Margin Recovery Actions; November 1, 2006
Selected Operator Logs; January 1, 2002 thru June 30, 2006
MSPI Derivation Report for Unavailability Index; Cooling Water System; November, 2006
MSPI Derivation Report for Unavailability Index; Residual Heat Removal System; November,
2006
MSPI Derivation Report for Unavailability Index; High Pressure Injestion System; November,
2006
MSPI Derivation Report for Unavailability Index; Emergency AC Power System; November,
2006
MSPI Derivation Report for Unavailability Index; Heat Removal System; November, 2006
Maintenance Rule Unavailability Reports, January 2005 to June 2006
IR 540456; MSPI Reporting for SX Needs Peer Group Clarification, October 05, 2006
IR 541902; NOS Identified MSPI Basis Document Problems, October 09, 2006
IR 579330; Byron Risk Management MSPI NER Review Results, January 16, 2007
IR 328721; 86 Lockout Relay for
ACB 2412 Melted During OAD Relay Tests, April 26, 2005
IR 328839; Lockout Relay Failure Causes Equipment Availability Concern, April 26, 2005Corrective Action Documents As A Result of NRC InspectionIR
449971; 1B DG Missed Opportunities, February 04, 2006 (NRC Identified)IR
564938; Delta in MSPI Data Reporting Period, December 04, 2006 (NRC Identified)
14IR
572142; MSPI Baseline Unavailability Period Incorrect, December 21, 2006 (NRC Identified)IR
572244; MSPI Baseline Unavailability Data Discrepancies HPI & RHR, December 21, 2006

(NRC Identified)

IR 572295; MSPI Data Question for Diesel Generator Reporting, December 21, 2006

(NRC Identified)

IR 572303; MSPI Data Question for Diesel Generator Reporting, December 21, 2006

(NRC Identified)

IR 572582; Documentation of NRC Questions on
MSPI-SX System, December 22, 2006

(NRC Identified)

IR 579340; Display Anomaly in Outdated Maintenance Rule Database, January 16, 2007

(NRC Identified)

15

LIST OF ACRONYMS

USEDACAlternating CurrentADAMSAgencywide Documents Access and Management System

AFWA uxiliary Feedwater
ALARAA Low As Reasonably Dose Equivalent

ANSAlert and Notification System

ANSIAmerican National Standard Institute/American Nuclear Society

ASMEAmerican Society of Mechanical Engineers

BACCBoric Acid Corrosion Control

CAPCorrective Action Program

CFRCode of Federal Regulations

DGDiesel Generator

DRPD ivision of Reactor Projects; Region
RIII [[]]

IEMAIllinois Emergency Management Agency

IMCInspection Manual Chapter

IPInspection Procedure

IRIssue Report

ISIInservice Inspection

JPMJob Performance Measure

LERLicensee Event Report

LOOPLoss Of Offsite Power

LORTLicensed Operator Requalification Training

MSPIMitigating System Performance Index

NCVNon-Cited Violation

NDENondestructive Examination

NRCUnited States Nuclear Regulatory Commission

PARSPublic Availability Records

PIPerformance Indicator

RCARadiologically Controlled Area

RCSReactor Coolant System

RIResident Inspector

ROReactor Operator

SATSystems Approach to Training

SDPSignificance Determination Process

SROSenior Reactor Operator

SSCStructures, Systems, & Components

SWRSimulator Work Request

SXEssential Service Water

TRTraining Request

TRMTechnical Requirement Manual

TSTechnical Specifications

UFSARUpdated Final Safety Analysis Report

WOWork Order

WRW ork Request
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