IR 05000237/2006007: Difference between revisions

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{{Adams|number = ML062150068}}
{{Adams
| number = ML062150068
| issue date = 07/31/2006
| title = IR 05000237-06-007; 05000249-06-007 on 04/01/2006 - 06/30/2006; Exelon Generation Co., LLC; Dresden Nuclear Power Station, Units 2 and 3; Fire Protection, Maintenance Effectiveness, Maintenance Risk Assessments and Emergent Work Control, Pe
| author name = Ring M A
| author affiliation = NRC/RGN-III/DRP/RPB1
| addressee name = Crane C M
| addressee affiliation = Exelon Generation Co, LLC, Exelon Nuclear
| docket = 05000237, 05000249
| license number = DPR-019, DPR-025
| contact person =
| document report number = IR-06-007
| document type = Inspection Report, Letter
| page count = 47
}}


{{IR-Nav| site = 05000237 | year = 2006 | report number = 007 }}
{{IR-Nav| site = 05000237 | year = 2006 | report number = 007 }}
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Mr. Christopher M. CranePresident and Chief Nuclear Officer Exelon Nuclear Exelon Generation Company, LLC 4300 Winfield Road Warrenville, IL 60555
Mr. Christopher M. CranePresident and Chief Nuclear Officer Exelon Nuclear Exelon Generation Company, LLC 4300 Winfield Road Warrenville, IL 60555


SUBJECT: DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3NRC INTEGRATED INSPECTION REPORT 05000237/2006007;05000249/2006007
SUBJECT: DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3NRC INTEGRATED INSPECTION REPORT 05000237/2006007; 05000249/2006007


==Dear Mr. Crane:==
==Dear Mr. Crane:==
On June 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspectionat your Dresden Nuclear Power Station, Units 2 and 3. The enclosed integrated inspectionreport documents the inspection findings, which were discussed on July 18, 2006, with Mr. D. Wozniak 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.
On June 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspectionat your Dresden Nuclear Power Station, Units 2 and 3. The enclosed integrated inspectionreport documents the inspection findings, which were discussed on July 18, 2006, with Mr. D. Wozniak 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. Based on the results of this inspection, four NRC-identified and two self-revealed findings ofvery low safety significance, five of which involved violations of NRC requirements wereidentified. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these violations as non-citedviolations (NCVs) consistent with Section VI.A.1. of the NRC Enforcement Policy. If you contest these NCVs, you should provide a response within 30 days of the date of thisinspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Dresden Nuclear Power Station.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. Based on the results of this inspection, four NRC-identified and two self-revealed findings ofvery low safety significance, five of which involved violations of NRC requirements wereidentified. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these violations as non-citedviolations (NCVs) consistent with Section VI.A.1. of the NRC Enforcement Policy. If you contest these NCVs, you should provide a response within 30 days of the date of thisinspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001;
 
and the NRC Resident Inspector at the Dresden Nuclear Power Station.


C. Crane-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of thisletter and its enclosure will be available electronically for public inspection in the NRCPublic Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
C. Crane-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of thisletter and its enclosure will be available electronically for public inspection in the NRCPublic Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
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=SUMMARY OF FINDINGS=
=SUMMARY OF FINDINGS=
IR 05000237/2006007; 05000249/2006007; 04/01/2006 - 06/30/2006; Exelon GenerationCompany, Dresden Nuclear Power Station, Units 2 and 3; fire protection, maintenanceeffectiveness, maintenance risk assessments and emergent work control, personnel performance related to non-routine evolutions and events, and operability evaluations.This report covers a 3-month period of baseline resident inspection and an announced baselineinspection in Licensed Operator Requalification Program. The inspection was conducted by Region III inspectors and the resident inspectors. Six Green findings, involving five non-citedviolations, were identified. The significance of most findings is indicated by their color (Green,
IR 05000237/2006007; 05000249/2006007; 04/01/2006 - 06/30/2006; Exelon GenerationCompany, Dresden Nuclear Power Station, Units 2 and 3; fire protection, maintenanceeffectiveness, maintenance risk assessments and emergent work control, personnel performance related to non-routine evolutions and events, and operability evaluations.This report covers a 3-month period of baseline resident inspection and an announced baselineinspection in Licensed Operator Requalification Program. The inspection was conducted by Region III inspectors and the resident inspectors. Six Green findings, involving five non-citedviolations, were identified. 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. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors is described in NUREG-1649, "ReactorOversight Process," Revision 3, dated July 2000.A.NRC-Identified and Self-Revealing Findings
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. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors is described in NUREG-1649, "ReactorOversight Process," Revision 3, dated July 2000.A.
 
===NRC-Identified and Self-Revealing Findings===


===Cornerstone: Mitigating Systems===
===Cornerstone: Mitigating Systems===
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On May 15, 2006, a finding involving a non-cited violation of 10 CFR 50,Appendix B, Criterion XVI, was identified by the inspectors. The licensee failed to identify a condition adverse to quality where the Unit 2 350 psig reactor low pressure emergency core cooling system (ECCS) permissive pressure switch was found outsidethe Technical Specification (TS) allowable tolerance range repeatedly. The licensee's actions lacked prioritization in determining the cause of the out-of-tolerance of the 2-0263-52B permissive pressure switch. Also, the licensee failed to assign timely corrective actions to evaluate the cause of the switch's repeated TS surveillance testfailures.
On May 15, 2006, a finding involving a non-cited violation of 10 CFR 50,Appendix B, Criterion XVI, was identified by the inspectors. The licensee failed to identify a condition adverse to quality where the Unit 2 350 psig reactor low pressure emergency core cooling system (ECCS) permissive pressure switch was found outsidethe Technical Specification (TS) allowable tolerance range repeatedly. The licensee's actions lacked prioritization in determining the cause of the out-of-tolerance of the 2-0263-52B permissive pressure switch. Also, the licensee failed to assign timely corrective actions to evaluate the cause of the switch's repeated TS surveillance testfailures.


Enclosure3The finding was greater than minor because it impacted the equipment performanceattribute of the Mitigating System cornerstone objective to ensure availability, reliability,and capability of systems that respond to initiating events. As corrective action, thelicensee created action items to address the repeat failures of the 2-0263-52B switch to meet its TS requirements. The licensee wrote Issue Report (IR) 495327, "Trending IR for 2-0263-52B exceeds TS 6 of 9 Surveillances," to identify why this adverse trend wasnot entered into the corrective action system. As immediate corrective action, thelicensee reduced the surveillance frequency to adequately monitor the switch'sperformance. The licensee also required all system managers and first line supervisorsto review the station procedure for the instrument performance trending program, and implemented a manufacturer's recommendation to use smaller step changes in applied pressure to improve set point accuracy. The finding was of very low safety significance because the other permissive switch 2-0263-52A was always operable. Therefore, the switch's safety function and ability to permit reactor low pressure ECCS injection weremaintained. The primary cause of this finding was related to the cross-cutting issue of problem identification and resolution (corrective action).  (Section 1R12)*Green. A finding was self-revealed when an instrument maintenance technician shorteda power lead while performing modification work that resulted in the Unit 2 high pressure coolant injection system becoming inoperable for 2 hours and 14 minutes onApril 6, 2006. No violation of NRC requirements was identified.This finding was more than minor because it involved the attribute of equipmentperformance of the Mitigating Systems objective of ensuring the capability of systemsthat respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because the high pressure coolant injection system was inoperable for a short time period and could have been manually controlled in the event of an accident. The individual was counseled for a lack of attention to detail and the entire instrument maintenance department was made aware of this error. This finding affected the cross-cutting issue of human performance (personnel).  (Section 1R14)*Green. On May 5, 2006, the inspectors identified a finding involving a non-citedviolation of 10 CFR 50.62 associated with a licensee-identified material condition, and having very low safety significance. The licensee identified that the inputs to a design analysis (DRE01-0066, "Dresden Unit 2 & 3 Standby Liquid Control System Discharge Piping Pressure Drop," Revision 1) were non-conservative. Some of the valves installed in the plant were not the same type of valves assumed to be installed in the design analysis. This ultimately resulted in a change in a design calculation that demonstrated that standby liquid control system relief valves could lift upon system initiation during ananticipated transient without scram (ATWS) event.The finding was more than minor because it affected the design control attribute of theMitigating Systems objective of ensuring the capability of systems that respond toinitiating events to prevent undesirable consequences. The finding was of very low safety significance because the standby liquid control system could be recovered duringan ATWS event. Cycling of the relief valves would not prevent most of the borated solution from being injected into the reactor pressure vessel, and the licensee was able to demonstrate that the reactor remained within the acceptance criteria of their originalATWS analysis even if no boron solution was injected into the reactor pressure vessel Enclosure4while the relief valves lifted. The licensee planned to use a more enriched form of boronso that one pump could be used to meet the 10 CFR 50.62 requirements. This enrichedboron would replace the current boron in the storage tanks in the next refueling outages. This issue was a non-cited violation of 10 CFR 50.62.  (Section 1R15)
3The finding was greater than minor because it impacted the equipment performanceattribute of the Mitigating System cornerstone objective to ensure availability, reliability,and capability of systems that respond to initiating events. As corrective action, thelicensee created action items to address the repeat failures of the 2-0263-52B switch to meet its TS requirements. The licensee wrote Issue Report (IR) 495327, "Trending IR for 2-0263-52B exceeds TS 6 of 9 Surveillances," to identify why this adverse trend wasnot entered into the corrective action system. As immediate corrective action, thelicensee reduced the surveillance frequency to adequately monitor the switch'sperformance. The licensee also required all system managers and first line supervisorsto review the station procedure for the instrument performance trending program, and implemented a manufacturer's recommendation to use smaller step changes in applied pressure to improve set point accuracy. The finding was of very low safety significance because the other permissive switch 2-0263-52A was always operable. Therefore, the switch's safety function and ability to permit reactor low pressure ECCS injection weremaintained. The primary cause of this finding was related to the cross-cutting issue of problem identification and resolution (corrective action).  (Section 1R12)*Green. A finding was self-revealed when an instrument maintenance technician shorteda power lead while performing modification work that resulted in the Unit 2 high pressure coolant injecti on system becoming inoperable for 2 hours and 14 minutes onApril 6, 2006. No violation of NRC requirements was identified.This finding was more than minor because it involved the attribute of equipmentperformance of the Mitigating Systems objective of ensuring the capability of systemsthat respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because the high pressure coolant injection system was inoperable for a short time period and could have been manually controlled in the event of an accident. The individual was counseled for a lack of attention to detail and the entire instrument maintenance department was made aware of this error. This finding affected the cross-cutting issue of human performance (personnel).  (Section 1R14)*Green. On May 5, 2006, the inspectors identified a finding involving a non-citedviolation of 10 CFR 50.62 associated with a licensee-identified material condition, and having very low safety significance. The licensee identified that the inputs to a design analysis (DRE01-0066, "Dresden Unit 2 & 3 Standby Liquid Control System Discharge Piping Pressure Drop," Revision 1) were non-conservative. Some of the valves installed in the plant were not the same type of valves assumed to be installed in the design analysis. This ultimately resulted in a change in a design calculation that demonstrated that standby liquid control system relief valves could lif t upon system initiation during ananticipated transient without scram (ATWS) event.The finding was more than minor because it affected the design control attribute of theMitigating Systems objective of ensuring the capability of systems that res pond toinitiating events to prevent undesirable consequences. The finding was of very low safety significance because the standby liquid control system could be recovered duringan ATWS event. Cycling of the relief valves would not prevent most of the borated solution from being injected into the reactor pressure vessel, and the licensee was able to demonstrate that the reactor remained within the acceptance criteria of their originalATWS analysis even if no boron solution was injected into the reactor pressure vessel 4while the relief valves lifted. The licensee planned to use a more enriched form of boronso that one pump could be used to meet the 10 CFR 50.62 requirements. This enrichedboron would replace the current boron in the storage tanks in the next refueling outages. This issue was a non-cited violation of 10 CFR 50.62.  (Section 1R15)


===Cornerstone: Barrier Integrity===
===Cornerstone: Barrier Integrity===
: '''Green.'''
: '''Green.'''
On May 15, 2006, the inspectors identified a non-cited violation 10 CFR 50.65(a) (4), having very low safety significance associated with inadequate management of risk. While working on the Unit 2 1601-20B reactor building to torus vacuum breaker relief valve, the Unit 2 risk status was designated as "yellow" and would have gone to "red" if the 2-1601-20A valve was also taken out-of-service. The 2-1601-20A vacuum relief valve was not clearly indicated as a protected pathway as required by station workcontrol procedures and station personnel were not notified of the 2-1601-20B "yellow" risk status through any of the normal administrative methods.This finding was more than minor because this issue, if left uncorrected, could havebecome a more significant safety concern. Had the availability of the 2-1601-20A valvebeen affected, plant risk would have been elevated to a "red" condition. The plant risk model did not show that this equipment was required to have a protected pathway onthe redundant equipment. In addition, during the extent of condition review, the licenseeidentified that six additional pieces of plant equipment should have indicated therequirement for protected pathways, but did not. The licensee corrected both theseconditions. The inspectors evaluated this finding using IMC 0609, "Significance Determination Process," and concluded the issue was of very low safety significance (Green) because no actual degradation of the barriers occurred. This finding affected the cross-cutting issue of human performance (resources).  (Section 1R13)*Green. On April 5, 2006, a performance deficiency involving a non-cited violation ofTS 5.4.1 was self revealed when an auxiliary nuclear station operator (Aux NSO) and aunit supervisor (US) were performing Dresden Operating Procedure (DOP) 0500-03,
On May 15, 2006, the inspectors identified a non-cited violation 10 CFR 50.65(a) (4), having very low safety significance associated with inadequate management of risk. While working on the Unit 2 1601-20B reactor building to torus vacuum breaker relief valve, the Unit 2 risk status was designated as "yellow" and would have gone to "red" if the 2-1601-20A valve was also taken out-of-service. The 2-1601-20A vacuum relief valve was not clearly indicated as a protected pathway as required by station workcontrol procedures and station personnel were not notified of the 2-1601-20B "yellow" risk status through any of the normal administrative methods.This finding was more than minor because this issue, if left uncorrected, could havebecome a more significant safety concern. Had the availability of the 2-1601-20A valvebeen affected, plant risk would have been elevated to a "red" condition. The plant risk model did not show that this equipment was required to have a protected pathway onthe redundant equipment. In addition, during the extent of condition review, the licenseeidentified that six additional pieces of plant equipment should have indicated therequirement for protected pathways, but did not. The licensee corrected both theseconditions. The inspectors evaluated this finding using IMC 0609, "Significance Determination Process," and concluded the issue was of very low safety significance (Green) because no actual degradation of the barriers occurred. This finding affected the cross-cutting issue of human performance (resources).  (Section 1R13)*Green. On April 5, 2006, a performance deficiency involving a non-cited violation ofTS 5.4.1 was self revealed when an auxiliary nuclear station operator (Aux NSO) and aunit supervisor (US) were performing Dresden Operating Procedure (DOP) 0500-03,
"Reactor Protection System Power Supply Operation," Revision 27. The Aux NSO and US did not verify that the area radiation monitor's (ARM) power supply voltage was normal and did not reset all trips on the ARM modules prior to removing an installed jumper which bypassed the trips. This required entry into TS 3.6.4.1 Limiting Condition of Operation, Action A for reactor building low differential pressure. Both operators had been provided with marked up copies of the procedure, and briefed on jumper placement and removal and on the use of concurrent verification prior to the event.The finding was greater than minor because it impacted the structures, systems, andcomponents attribute of the Barrier Integrity cornerstone objective. The finding was of very low safety significance because it impacted the reactor building differential pressure for a time period of less than 1 hour. As an immediate corrective action, the two individuals were temporarily removed from licensed shift duties. The operations department was tasked to develop a dynamic learning activity for place-keeping and jumper manipulation for all operations personnel, and to create an internal operating experience document to communicate lessons learned. This finding affected the cross-cutting area of human performance (personnel).  (Section 1R14)
"Reactor Protection System Power Supply Operation," Revision 27. The Aux NSO and US did not verify that the area radiation monitor's (ARM) power supply voltage was normal and did not reset all trips on the ARM modules prior to removing an installed jumper which bypassed the trips. This required entry into TS 3.6.4.1 Limiting Condition of Operation, Action A for reactor building low differential pressure. Both operators had been provided with marked up copies of the procedure, and briefed on jumper placement and removal and on the use of concurrent verification prior to the event.The finding was greater than minor because it impacted the structures, systems, andcomponents attribute of the Barrier Integrity cornerstone objective. The finding was of very low safety significance because it impacted the reactor building differential pressure for a time period of less than 1 hour. As an immediate corrective action, the two individuals were temporarily removed from licensed shift duties. The operations department was tasked to develop a dynamic learning activity for place-keeping and jumper manipulation for all operations personnel, and to create an internal operating experience document to communicate lessons learned. This finding affected the cross-cutting area of human performance (personnel).  (Section 1R14)
Enclosure5
 
5


===B.Licensee-Identified Violations===
===B.Licensee-Identified Violations===
No findings of significance were identified.
No findings of significance were identified.


Enclosure6
6


=REPORT DETAILS=
=REPORT DETAILS=
Summary of Plant StatusUnit 2 began the inspection period at 912 MWe (95 percent thermal power and 100 percent ofrated electrical capacity).*On May 27, 2006, power was reduced to 15 percent to perform a walkdown of the drywell toidentify the source of a leak, to perform turbine valve testing, and to make a control rod pattern adjustment. The unit was returned to full power the next day.*On June 8, 2006, power was reduced to 71 percent to replace the 2A feedwater regulatingvalve solenoid due to erratic operation. The unit was returned to full power the same day.Unit 3 began the inspection period at 912 MWe (95 percent thermal power and 100 percent ofrated electrical capacity). *On June 4, 2006, power was reduced to 57 percent to perform turbine valve testing, controlrod drive scram time testing, and to make a control rod pattern adjustment. The unit was returned to full power on the same day.1.REACTOR SAFETYCornerstones:  Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather (71111.01)a. Inspection ScopeThe inspectors assessed the licensee's readiness for warm weather conditions during thetime period of May 2006 and conducted inspections on the following equipment and systems:*Unit 3 containment cooling service water vault;*Unit 2 reactor building ventilation; and
Summary of Plant StatusUnit 2 began the inspection period at 912 MWe (95 percent thermal power and 100 percent ofrated electrical capacity).*On May 27, 2006, power was reduced to 15 percent to perform a walkdown of the drywell toidentify the source of a leak, to perform turbine valve testing, and to make a control rod pattern adjustment. The unit was returned to full power the next day.*On June 8, 2006, power was reduced to 71 percent to replace the 2A feedwater regulatingvalve solenoid due to erratic operation. The unit was returned to full power the same day.Unit 3 began the inspection period at 912 MWe (95 percent thermal power and 100 percent ofrated electrical capacity). *On June 4, 2006, power was reduced to 57 percent to perform turbine valve testing, controlrod drive scram time testing, and to make a control rod pattern adjustment. The unit was returned to full power on the same day.1.REACTOR SAFETYCornerstones:  Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather (71111.01)a. Inspection ScopeThe inspectors assessed the licensee's readiness for warm weather conditions during thetime period of May 2006 and conducted inspections on the following equipment and systems:*Unit 3 containment cooling service water vault;*Unit 2 reactor building ventilation; and
*Unit 2 and 3 auxiliary electric equipment room heating, ventilation and air conditioningThe inspectors selected the above inspection samples to ensure the equipment couldperform design functions during summer conditions. The inspectors reviewed the Updated Final Safety Analysis Report, the licensee's seasonal readiness procedure, previously initiated issue reports, and walked down equipment and systems to verify proper alignmentin accordance with the licensee procedures to remove plant equipment and systems usedfor cold weather operations from service at the end of cold weather season. This represented one inspection sample.
*Unit 2 and 3 auxiliary electric equipment room heating, ventilation and air conditioningThe inspectors selected the above inspection samples to ensure the equipment couldperform design functions during summer conditions. The inspectors reviewed the Updated Final Safety Analysis Report, the licensee's seasonal readiness procedure, previously initiated issue reports, and walked down equipm ent and systems to verify proper alignmentin accordance with the licensee procedures to remove plant equipment and systems usedfor cold weather operations from service at the end of cold weather season. This represented one inspection sample.


====b. Findings====
====b. Findings====
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=====Description:=====
=====Description:=====
On May 1, 2006, while performing a fire protection walkdown of the Unit 2EDG room, the inspectors identified a through-wall gap in the west corner of the diesel fuel oil day tank room. Light from the Unit 2 RFP room could be seen through the wall. The inspectors determined that a through-wall gap existed in a fire barrier wall and reported this condition to the licensee. The gap was promptly evaluated and was judged to be about 1/32 inch wide and about 5 feet long. The inspectors were informed that this fire barrier separated the Unit 2 diesel fuel oil day tank room, Fire Zone 9.0.A, from the Unit 2 RFProom, Fire Zone 8.2.5.A. Upon confirmation of the inspectors' concern, the licenseedeclared the carbon dioxide (CO2) system for the Unit 2 EDG day tank room inoperable. The fuel oil day tank west wall was also considered to be inoperable as a 3-hour fire barrier. The licensee immediately implemented the appropriate technical requirement manuallimiting condition for operation actions by establishing an hourly fire watch, and entered the deficiency into the corrective action program as issue report IR 485432. The licensee's engineering evaluation stated that this gap is speculated to have formed when the wall waspoured during original construction when a seal did not form between the concrete and the steel beam. Licensee personnel completed a permanent repair of the fire barrier wall gap per work order WO 917879.The gap had not been identified by the licensee because the existing surveillancerequirement was not properly performed. Station procedure DFPS 4175-02, "Operating FireStop/Break Surveillance," Revision 12, Section I.1.d, stated, in part, "besides the listedpenetrations, the entire surface of the fire rated assembly shall be inspected for open penetrations or breaks of any kind."  This surveillance was last completed for the Unit 2emergency diesel fuel oil tank room wall on January 11, 2005. The inspectors interviewed the individual that performed the inspection, and the individual acknowledged that the entiresurface of the barrier had not been inspected.Analysis:  The inoperable fire barrier wall represented a licensee performance deficiencybecause the gap in the 3-hour fire barrier wall would be expected to have been identified and corrected by the licensee using Fire Protection Surveillance (DFPS) Procedure 4175-2,"Operating Fire Stop/Break Surveillance," Revision 12. The affect of the identifieddeficiency was that since original construction a communication path existed between the 9two fire zones. The requirement to have fire barriers was to ensure that a postulated firewould not propagate to more than one fire area, thus jeopardizing the availability of safeshutdown equipment. Using Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," dated September 30, 2005, the finding was greater than minorbecause it affected the protection against external factors attribute of the Mitigating Systems cornerstone objective. The inspectors evaluated the finding using IMC 0609, Appendix F, "Fire ProtectionSignificance Determination Process (SDP)," dated February 28, 2005, Attachment 2, Table A2.1, and concluded that the finding affected the defense-in-depth element of firebarrier degradation in the fire confinement category. Based on the gap being about 1/32 inch wide and 5 feet long through a 3-hour barrier wall, the degradation level was categorized as low "Green."  Factors which contributed to this classification included the following:  a credible firescenario could not be developed that would have affected the safe shutdown of Unit 2 because both zones were in the same fire area. The Unit 2 EDG oil day tank room had a negligible amount of combustibles. The fuel oil was excluded from the combustible loading because it was located within an National Fire Protection Association qualified tank and which is assumed not to rupture. The inspectors considered in their evaluation the lack of electrical cables in the area of the gap, the fact that the Unit 2 fuel oil day tank room isprotected by both an automatic CO2 suppression and an automatic wet pipe sprinklersystem, the relatively small transient combustible loading in the area of the gap from theUnit 2 RFP side, and the fact that the Unit 2 RFP area is protected by an automatic wet pipesprinkler system.The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (personnel) because the licensee failed to accomplish activities in accordance with prescribed instructions in a station procedure. Specifically, a surveillance test wasperformed on this wall in January 2005 and the gap was not found because the entire surface of the wall was not inspected in accordance with station procedure DFPS 4175-02.Enforcement:  Operating License Condition No DPR-19, Section E, requires that thelicensee shall implement and maintain in effect all provisions of the approved Fire Protection Program, as described in the Updated Final Safety Analysis Report (UFSAR).The UFSAR, Section 9.5.1, "Fire Protection System," states, in part, that the design basesand system descriptions are described in the Dresden Fire Protection Report (DFPR),Volume 1, "Updated Fire Hazards
On May 1, 2006, while performing a fire protection walkdown of the Unit 2EDG room, the inspectors identified a through-wall gap in the west corner of the diesel fuel oil day tank room. Light from the Unit 2 RFP room could be seen through the wall. The inspectors determined that a through-wall gap existed in a fire barrier wall and reported this condition to the licensee. The gap was promptly evaluated and was judged to be about 1/32 inch wide and about 5 feet long. The inspectors were informed that this fire barrier separated the Unit 2 diesel fuel oil day tank room, Fire Zone 9.0.A, from the Unit 2 RFProom, Fire Zone 8.2.5.A. Upon confirmation of the inspectors' concern, the licenseedeclared the carbon dioxide (CO 2) system for the Unit 2 EDG day tank room inoperable. The fuel oil day tank west wall was also considered to be inoperable as a 3-hour fire barrier. The licensee immediately implemented the appropriate technical requirement manuallimiting condition for operation actions by establishing an hourly fire watch, and entered the deficiency into the corrective action program as issue report IR 485432. The licensee's engineering evaluation stated that this gap is speculated to have formed when the wall waspoured during original construction when a seal did not form between the concrete and the steel beam. Licensee personnel completed a permanent repair of the fire barrier wall gap per work order WO 917879.The gap had not been identified by the licensee because the existing surveillancerequirement was not properly performed. Station procedure DFPS 4175-02, "Operating FireStop/Break Surveillance," Revision 12, Section I.1.d, stated, in part, "besides the listedpenetrations, the entire surface of the fire rated assembly shall be inspected for open penetrations or breaks of any kind."  This surveillance was last completed for the Unit 2emergency diesel fuel oil tank room wall on January 11, 2005. The inspectors interviewed the individual that performed the inspection, and the individual acknowledged that the entiresurface of the barrier had not been inspected.Analysis:  The inoperable fire barrier wall represented a licensee performance deficiencybecause the gap in the 3-hour fire barrier wall would be expected to have been identified and corrected by the licensee using Fire Protection Surveillance (DFPS) Procedure 4175-2,"Operating Fire Stop/Break Surveillance," Revision 12. The affect of the identifieddeficiency was that since original construction a communication path existed between the 9two fire zones. The requirement to have fire barriers was to ensure that a postulated firewould not propagate to more than one fire area, thus jeopardizing the availability of safeshutdown equipment. Using Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," dated September 30, 2005, the finding was greater than minorbecause it affected the protection against external factors attribute of the Mitigating Systems cornerstone objective. The inspectors evaluated the finding using IMC 0609, Appendix F, "Fire ProtectionSignificance Determination Process (SDP)," dated February 28, 2005, Attachment 2, Table A2.1, and concluded that the finding affected the defense-in-depth element of firebarrier degradation in the fire confinement category. Based on the gap being about 1/32 inch wide and 5 feet long through a 3-hour barrier wall, the degradation level was categorized as low "Green."  Factors which contributed to this classification included the following:  a credible firescenario could not be developed that would have affected the safe shutdown of Unit 2 because both zones were in the same fire area. The Unit 2 EDG oil day tank room had a negligible amount of combustibles. The fuel oil was excluded from the combustible loading because it was located within an National Fire Protection Association qualified tank and which is assumed not to rupture. The inspectors considered in their evaluation the lack of electrical cables in the area of the gap, the fact that the Unit 2 fuel oil day tank room isprotected by both an automatic CO 2 suppression and an automatic wet pipe sprinklersystem, the relatively small transient combustible loading in the area of the gap from theUnit 2 RFP side, and the fact that the Unit 2 RFP area is protected by an automatic wet pipesprinkler system.The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (personnel) because the licensee failed to accomplish activities in accordance with prescribed instructions in a station procedure. Specifically, a surveillance test wasperformed on this wall in January 2005 and the gap was not found because the entire surface of the wall was not inspected in accordance with station procedure DFPS 4175-02.Enforcement:  Operating License Condition No DPR-19, Section E, requires that thelicensee shall implement and maintain in effect all provisions of the approved Fire Protection Program, as described in the Updated Final Safety Analysis Report (UFSAR).The UFSAR, Section 9.5.1, "Fire Protection System," states, in part, that the design bases and system descriptions are described in the Dresden Fire Protection Report (DFPR),Volume 1, "Updated Fire Hazards


=====Analysis.=====
=====Analysis.=====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors reviewed the plant's operating history from April 2004 through April 2006 toidentify operating experience that was expected to be addressed by the Licensed OperatorRequalification Training (LORT) program. It was then verified that the identified operatingexperience had been addressed by the facility licensee in accordance with the station'sapproved Systems Approach to Training (SAT) program to satisfy the requirements of 10 CFR 55.59 (c), "Requalification program requirements."
The inspectors reviewed the plant's operating history from April 2004 through April 2006 toidentify operating experience that was expected to be addressed by the Licensed OperatorRequalification Training (LORT) program. It was then verified that the identified operatingexperience had been addressed by the facility licensee in accordance with the station'sapproved Systems Approach to Training (SAT) program to satisfy the requirements of 10 CFR 55.59 (c), "Requalification program requirements."
12


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors reviewed the facility and individual operator licensees' conformance with therequirements of 10 CFR Part 55. The inspectors reviewed the facility licensee's program formaintaining 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 facilitylicensee's LORT program to assess compliance with the requalification program requirements as described by 10 CFR 55.59 (c). Additionally, medical records for ten licensed operators were reviewed for compliance with 10 CFR 55.53 (I).
The inspectors reviewed the facility and individual operator licensees' conformance with therequirements of 10 CFR Part 55. The inspectors reviewed the facility licensee's program formaintaining 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 facilitylicensee's LORT program to assess compliance with the requalification program requirements as described by 10 CFR 55.59 (c). Additionally, medical records for ten licensed operators were reviewed for compliance with 10 CFR 55.53 (I).


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors assessed the adequacy of the licensee's simulation facility (simulator) foruse in operator licensing examinations and for satisfying experience requirements as prescribed in 10 CFR 55.46, "Simulation Facilities."  The inspectors also reviewed a sampleof 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 theIP 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 (c) and (d).
The inspectors assessed the adequacy of the licensee's simulation facility (simulator) foruse in operator licensing examinations and for satisfying experience requirements as prescribed in 10 CFR 55.46, "Simulation Facilities."  The inspectors also reviewed a sampleof 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 theIP 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
: (c) and (d).


====b. Findings====
====b. Findings====
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=====Enforcement:=====
=====Enforcement:=====
Title 10 CFR, Part 50, Appendix B, Criterion XVI, "Corrective Actions,"requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to the above, the licensee failed to identify an adverse trend for the repeated out oftolerance condition associated with the 2-0263-52B pressure switch, a condition adverse to quality. During this period when the switch was repeatedly out of tolerance, the calibration interval of the switch was not changed to assure the switch's operating setpoint values stayed within the TS allowable tolerance range. After the inspectors questioned the lack of identification of a condition adverse to qualityand the untimely corrective actions, the licensee created an action item to review the cause of the event and create corrective actions. The licensee wrote Issue Report (IR) 495327,
Title 10 CFR, Part 50, Appendix B, Criterion XVI, "Corrective Actions,"requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to the above, the licensee failed to identify an adverse trend for the repeated out oftolerance condition associated with the 2-0263-52B pressure switch, a condition adverse to quality. During this period when the switch was repeatedly out of tolerance, the calibration interval of the switch was not changed to assure the switch's operating setpoint values stayed within the TS allowable tolerance range. After the inspectors questioned the lack of identification of a condition adverse to qualityand the untimely corrective actions, the licensee created an action item to review the cause of the event and create corrective actions. The licensee wrote Issue Report (IR) 495327, "Trending IR for 2-0263-52B exceeds TS 6 of 9 Surveillances."  The purpose of this IR wasto identify why this adverse trend was not entered into the corrective action system. Asimmediate corrective action, the licensee reduced the surveillance frequency to adequatelymonitor the switch's performance. Also the licensee required all system managers and firstline supervisors to review the station procedure for the instrument performance trending program to ensure applicability and implementation, and initiated a training request forinstrument maintenance technicians to include a manufacturer's recommendation to use smaller step changes in applied pressure to improve set point accuracy. Because of the very low safety significance and because the issue is in the licensee's corrective action program IR 495327, it is being treated as a non-cited violation, consistent withSection VI.A.1 of the NRC Enforcement Policy.  (NCV05000237/2006007-02)181R13Maintenance Risk Assessments and Emergent Work Control (71111.13).1Routine Inspections
"Trending IR for 2-0263-52B exceeds TS 6 of 9 Surveillances."  The purpose of this IR wasto identify why this adverse trend was not entered into the corrective action system. Asimmediate corrective action, the licensee reduced the surveillance frequency to adequatelymonitor the switch's performance. Also the licensee required all system managers and firstline supervisors to review the station procedure for the instrument performance trending program to ensure applicability and implementation, and initiated a training request forinstrument maintenance technicians to include a manufacturer's recommendation to use smaller step changes in applied pressure to improve set point accuracy. Because of the very low safety significance and because the issue is in the licensee's corrective action program IR 495327, it is being treated as a non-cited violation, consistent withSection VI.A.1 of the NRC Enforcement Policy.  (NCV05000237/2006007-02)181R13Maintenance Risk Assessments and Emergent Work Control (71111.13).1Routine Inspections


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors evaluated the implementation of the licensee's maintenance risk programwith respect to the effectiveness of the risk assessments performed before maintenance activities were conducted on structures, systems, and components and verified that thelicensee managed the risk in accordance with 10 CFR 50.65, "Maintenance Rule."  The inspectors evaluated whether the licensee had taken the necessary steps to plan and control emergent work activities. The inspectors also verified that equipment necessary to complete planned contingency actions was staged and available. The inspectors completed evaluations of maintenance activities on the:*Unit 3 Division 1 low pressure coolant injection and containment cooling service waterpumps out-of-service for planned maintenance;*Unit 2 standby liquid control out-of-service for accumulator replacement, squib valve,and oil change;*Unit 3 high pressure coolant injection system out-of-service for planned maintenance;*Unit 2 reactor protection system bus swap to reserve power; and
The inspectors evaluated the implementation of the licensee's maintenance risk programwith respect to the effectiveness of the risk assessments performed before maintenance activities were conducted on structures, systems, and components and verified that thelicensee managed the risk in accordance with 10 CFR 50.65, "Maintenance Rule."  The inspectors evaluated whether the licensee had taken the necessary steps to plan and control emergent work activities. The inspectors also verified that equipment necessary to complete planned contingency actions was staged and available. The inspectors completed evaluations of maintenance activities on the:*Unit 3 Division 1 low pressure coolant injection and containment cooling service waterpumps out-of-service for planned maintenance;*Unit 2 standby liquid control out-of-service for accumulator replacement, squib valve,and oil change;*Unit 3 high pressure coolant injecti on system out-of-service for planned maintenance;*Unit 2 reactor protection system bus swap to reserve power; and
*Unit 2 and 3 containment isolation associated with the high pressure coolant injectionsystem pipe replacement.This represented five inspection samples.
*Unit 2 and 3 containment isolation associated with the high pressure coolant injectionsystem pipe replacement.This represented five inspection samples.


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19Description:  On May 15, 2006, the inspectors toured the Unit 2 torus catwalk area asrepair work was being performed on the Unit 2 1601-20B reactor building to torus vacuum relief valve. Unit 2 was on-line at full power. The vacuum breakers relieve pressure to the torus to prevent exceeding the external torus pressure. The inspectors noticed that there were no protected pathway signs posted on or near the remainingvacuum breaker 2-1601-20A. Unit 2 was in a "yellow" risk condition from 11:06 a.m. to 12:22 p.m. on May 15, 2006, due to the unavailability of the 2-1601-20B valve and wouldhave gone to red risk if the 2-1601-20A valve had been made unavailable. There was no mention in the POD meeting on May 15, 2006, of Unit 2 being in a"yellow" risk condition for the Unit 2 1601-20B valve work or that the 2-1601-20A valve was a protected pathway. Additionally, neither was the risk condition documented in the plant status sheet for the day or in the schedule review sheet for the day as being "yellow,"nor was 2-1601-20A listed as a protected pathway. The inspectors reviewed procedure, MA-AA-743-310, "Diagnostic Testing And Evaluation Of Air Operated Valves," Revision 4, and WO 99213710-01, and discovered that the pre-job briefing checklist designated protected pathways and equipment as not applicable (NA).The inspectors reviewed procedure, WC-AA-101, "On-Line Work Control Process,"Revision 12. In Attachment 3, this procedure ranked the four configuration risk conditions:
19Description:  On May 15, 2006, the inspectors toured the Unit 2 torus catwalk area asrepair work was being performed on the Unit 2 1601-20B reactor building to torus vacuum relief valve. Unit 2 was on-line at full power. The vacuum breakers relieve pressure to the torus to prevent exceeding the external torus pressure. The inspectors noticed that there were no protected pathway signs posted on or near the remainingvacuum breaker 2-1601-20A. Unit 2 was in a "yellow" risk condition from 11:06 a.m. to 12:22 p.m. on May 15, 2006, due to the unavailability of the 2-1601-20B valve and wouldhave gone to red risk if the 2-1601-20A valve had been made unavailable. There was no mention in the POD meeting on May 15, 2006, of Unit 2 being in a"yellow" risk condition for the Unit 2 1601-20B valve work or that the 2-1601-20A valve was a protected pathway. Additionally, neither was the risk condition documented in the plant status sheet for the day or in the schedule review sheet for the day as being "yellow,"nor was 2-1601-20A listed as a protected pathway. The inspectors reviewed procedure, MA-AA-743-310, "Diagnostic Testing And Evaluation Of Air Operated Valves," Revision 4, and WO 99213710-01, and discovered that the pre-job briefing checklist designated protected pathways and equipment as not applicable (NA).The inspectors reviewed procedure, WC-AA-101, "On-Line Work Control Process,"Revision 12. In Attachment 3, this procedure ranked the four configuration risk conditions:
green, yellow, orange, and red. Green is the least configuration risk and red is the worst or discussed as an unacceptable risk condition. Green is optimal defense in depth or no appreciable increase in initiating event frequency or decrease in mitigation capability. Yellow is nominal defense in depth. Orange is marginal defense in depth or significant increase in initiating event frequency or decrease in mitigation capability. Red isunacceptable defense in depth or unacceptable increase in initiating event frequency or decrease in mitigation capability.The inspectors discussed their concern with a lack of a protected pathway for the2-1601-20A valve with the licensee on May 15, 2006. The licensee documented the issuein IR 490307 the same day. The licensee concluded that the vacuum breaker valves were not, but should have been, on the Paragon Model "remain-in-service list" for protected pathway per ER-AA-600-1042, "On- Line Risk Management," Revision 4.Based on the inspectors' finding, the licensee performed an extent of condition by reviewingthe Paragon Model component list to identify any other components that should be on theprotected pathway remain-in-service list. The review looked for items that could cause the configuration risk to change from "yellow" to "orange" or "red" if the protected pathway component was also taken out-of-service. The licensee performed a thorough review and found six other Unit 2 components that could cause the on-line risk to go from "yellow" to
green, yellow, orange, and red. Green is the least configuration risk and red is the worst or discussed as an unacceptable risk condition. Green is optimal defense in depth or no appreciable increase in initiating event frequency or decrease in mitigation capability. Yellow is nominal defense in depth. Orange is marginal defense in depth or significant increase in initiating event frequency or decrease in mitigation capability. Red isunacceptable defense in depth or unacceptable increase in initiating event frequency or decrease in mitigation capability.The inspectors discussed their concern with a lack of a protected pathway for the2-1601-20A valve with the licensee on May 15, 2006. The licensee documented the issuein IR 490307 the same day. The licensee concluded that the vacuum breaker valves were not, but should have been, on the Paragon Model "remain-in-service list" for protected pathway per ER-AA-600-1042, "On- Line Risk Management," Revision 4.Based on the inspectors' finding, the licensee performed an extent of condition by reviewingthe Paragon Model component list to identify any other components that should be on theprotected pathway remain-in-service list. The review looked for items that could cause the configuration risk to change from "yellow" to "orange" or "red" if the protected pathway component was also taken out-of-service. The licensee performed a thorough review and found six other Unit 2 components that could cause the on-line risk to go from "yellow" to "orange" or "red" due to components being taken out-of-service for surveillance testing orfor components that are normally repaired or replaced during an outage but may be repaired or replaced while on-line. Four components were identified for the risk configuration heat removal function and included containment cooling service water discharge valves 2A and 2B and torus cooling trains 2A and 2B. Two other components were identified for the reactivity control function and included ATWS RPT Trip Logic A and Trip Logic B. These components were documented in IR 490307. The same components for Unit 3 were also not on the remain-in-service list and should have been to prevent the risk from becoming "orange" or "red" if the protected pathway component was taken out-of-service.
"orange" or "red" due to components being taken out-of-service for surveillance testing orfor components that are normally repaired or replaced during an outage but may be repaired or replaced while on-line. Four components were identified for the risk configuration heat removal function and included containment cooling service water discharge valves 2A and 2B and torus cooling trains 2A and 2B. Two other components were identified for the reactivity control function and included ATWS RPT Trip Logic A and Trip Logic B. These components were documented in IR 490307. The same components for Unit 3 were also not on the remain-in-service list and should have been to prevent the risk from becoming "orange" or "red" if the protected pathway component was taken out-of-service.


20Analysis:  The inspectors concluded that the failure to identify and protect redundant riskimportant equipment was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," Appendix B, "
20Analysis:  The inspectors concluded that the failure to identify and protect redundant riskimportant equipment was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," Appendix B, "
Issue Screening," issued on September 30, 2005. Failure to notify plant personnel of risk conditions that are "yellow" and that could change to "red" or "orange" if the redundant component is taken out-of-service could become a more significant safety concern if left uncorrected. This deficiency in the protected pathway program could affect the availability and capability of components and systems that respond to initiating events. Failure to beaware of all the components and systems that could cause an elevated "orange" or "red"risk condition increases the probability that the mitigating systems or components will betaken out-of-service and that they would not be able to respond as designed to an initiating event or accident condition.The inspectors completed a Phase 1 "Significance Determination Process," of IMC 0609Appendix A, Attachment 1, dated November 22, 2005. The inspectors determined that thisfinding impacted the Barrier Integrity cornerstone column. The inspectors answered "No" to all three questions under the Barrier Integrity column on page A1-9 because no actual barrier failure occurred. Therefore, the issue screened out as having very low significance (Green).The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (resources) because the procedure did not list this component as requiring a protected pathway. Specifically, sufficient guidance did not exist in the Paragon Modelremain-in-service list for a protected pathway per ER-AA-600-1042, "On-Line Risk Management," Revision 4.Enforcement:  Title 10 CFR 50.65 (a) (4) states, "before performing maintenance activities(including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The scope of the assessment may be limited to structures, systems, and components that a risk-informed evaluation process hasshown to be significant to public health and safety.Licensee procedure WC-AA-101, On-Line Work Control Process, Revision 12,Attachment 7, required that, "in even the cases of short equipment duration unavailability, aheightened level of sensitivity to the protected equipment must be maintained and it is the responsibility of every department to ensure that personnel working in the plant areinformed as to what components are protected."  The procedure also stated in Section 4.1.4that actions shall be taken to protect redundant structures, systems, or components if lossof the redundant component would cause entry into a "red" or "orange" risk configuration.Contrary to the above, from 11:06 a.m. to 12:22 p.m. on May 15, 2006, the licensee didnot assess and manage the increase in risk, in that, Unit 2 was in a "yellow" risk condition due to the unavailability of the 2-1601-20B valve and would have gone to "red"risk if the 2-1601-20A valve had been made unavailable. The licensee took no actions to protect redundant structures, systems, or components. The 2-1601-20A valve was notmarked as a protected pathway. In addition, the licensee did not alert all departments to theprotected pathways through normal methods such as the POD meeting on May 15, 2006, orthe plant status sheet for the day or in the schedule review sheet for the day.
Issue Screening," issued on September 30, 2005. Failure to notify plant personnel of risk conditions that are "yellow" and that could change to "red" or "orange" if the redundant component is taken out-of-service could become a more significant safety concern if left uncorrected. This deficiency in the protected pathway program could affect the availability and capability of com ponents and systems that respond to initiating events. Failure to beaware of all the components and systems that could cause an elevated "orange" or "red"risk condition increases the probability that the mitigating systems or components will betaken out-of-service and that they would not be able to respond as designed to an initiating event or accident condition.The inspectors completed a Phase 1 "Significance Determination Process," of IMC 0609Appendix A, Attachment 1, dated November 22, 2005. The inspectors determined that thisfinding impacted the Barrier Integrity cornerstone column. The inspectors answered "No" to all three questions under the Barrier Integrity column on page A1-9 because no actual barrier failure occurred. Therefore, the issue screened out as having very low significance (Green).The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (resources) because the procedure did not list this component as requiring a protected pathway. Specifically, sufficient guidance did not exist in the Paragon Modelremain-in-service list for a protected pathway per ER-AA-600-1042, "On-Line Risk Management," Revision 4.Enforcement:  Title 10 CFR 50.65 (a)
: (4) states, "before performing maintenance activities(including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The scope of the assessment may be limited to structures, systems, and components that a risk-informed evaluation process hasshown to be significant to public health and safety.Licensee procedure WC-AA-101, On-Line Work Control Process, Revision 12,Attachment 7, required that, "in even the cases of short equipment duration unavailability, aheightened level of sensitivity to the protected equipment must be maintained and it is the responsibility of every department to ensure that personnel working in the plant areinformed as to what components are protected."  The procedure also stated in Section 4.1.4that actions shall be taken to protect redundant structures, systems, or components if lossof the redundant component would cause entry into a "red" or "orange" risk configuration.Contrary to the above, from 11:06 a.m. to 12:22 p.m. on May 15, 2006, the licensee didnot assess and manage the increase in risk, in that, Unit 2 was in a "yellow" risk condition due to the unavailability of the 2-1601-20B valve and would have gone to "red"risk if the 2-1601-20A valve had been made unavailable. The licensee took no actions to protect redundant structures, systems, or components. The 2-1601-20A valve was notmarked as a protected pathway. In addition, the licensee did not alert all departments to theprotected pathways through normal methods such as the POD meeting on May 15, 2006, orthe plant status sheet for the day or in the schedule review sheet for the day.


21Furthermore, the licensee identified that the reason this happened was thatprocedure ER-AA-600-1042, "On-Line Risk Management," Revision 4, did not specify that the 2-1601-20A and 2-1601-20B valves were components that needed protectedpathways on the redundant components. Additional licensee review identified six othercomponents for each unit that should have been listed in the Paragon Model remain-in-service list while their redundant component was being repaired or replaced on-line. The licensee has since added the omitted eight components for each unit to their remain-in-service list in ER-AA-600-1042 for protected pathway components that can change risk to
21Furthermore, the licensee identified that the reason this happened was thatprocedure ER-AA-600-1042, "On-Line Risk Management," Revision 4, did not specify that the 2-1601-20A and 2-1601-20B valves were components that needed protectedpathways on the redundant components. Additional licensee review identified six othercomponents for each unit that should have been listed in the Paragon Model remain-in-service list while their redundant component was being repaired or replaced on-line. The licensee has since added the omitted eight components for each unit to their remain-in-service list in ER-AA-600-1042 for protected pathway components that can change risk to "orange" or "red" if removed from service. Because this violation was of very low safety significance and it was entered into the licensee's corrective action program as IR 490307, this violation is being treated as a non-cited violation, consistent with Section VI.A of theNRC Enforcement Policy.  (NCV 05000237/2006007-03)1R14Personnel Performance Related to Non-routine Evolutions and Events (71111.14).1Failure to Perform Procedure Steps in the Proper Sequence by Operations CausedEmergency Safety Feature Systems Actuation
"orange" or "red" if removed from service. Because this violation was of very low safety significance and it was entered into the licensee's corrective action program as IR 490307, this violation is being treated as a non-cited violation, consistent with Section VI.A of theNRC Enforcement Policy.  (NCV 05000237/2006007-03)1R14Personnel Performance Related to Non-routine Evolutions and Events (71111.14).1Failure to Perform Procedure Steps in the Proper Sequence by Operations CausedEmergency Safety Feature Systems Actuation


====a. Inspection Scope====
====a. Inspection Scope====
On April 5, 2006, during the swap of the 3A reactor protection system (RPS) bus to reservepower to support repair of the 3B RPS motor generator (MG) set, the Unit 2/3 standby gas treatment auto started and a Unit 3 reactor building ventilation isolation occurred. Thelicensee determined that the cause of this issue was a human performance error for the failure to perform steps in the proper sequence. All systems were restored in accordancewith plant procedures and there was no equipment that was damaged or any personnel thatwere injured. The licensee entered this issue into their corrective action program as IR 475365.This represented one inspection sample.b.FindingIntroduction:  A Green finding involving a non-cited violation of TS 5.4.1 was self revealedwhen an auxiliary nuclear station operator (Aux NSO) and a unit supervisor (US) wereperforming Dresden Operating Procedure (DOP) 0500-03, "Reactor Protection System Power Supply Operation," Revision 27. The Aux NSO and the US did not verify that thearea radiation monitor's (ARM) power supply voltage was normal and did not reset all trips on the ARM modules prior to removing a jumper that was installed. This required entry into TS 3.6.4.1 Limiting Condition of Operation, Action A for reactor building low differentialpressure (D/P).Description:  On April 5, 2006, operations department staff were placing the 3A reactorprotection system (RPS) bus to reserve power from the normal power source to supportrepair of the 3B RPS motor generator (MG) set using DOP 0500-03. The operators reset a half scram that was expected during this activity and then they proceeded with removing a jumper that was installed, in accordance with the procedure, to allow the transfer. Following the removal of the jumper, the Unit 3 reactor building ventilation tripped and the Unit 2/3 standby gas treatment train auto started. Neither the Aux NSO nor the US verified that theARM power supply was indicating normal and that the 3A reactor building ventilation and 22reactor building fuel pool channel 'A' ARMs were reset prior to jumper removal as requiredby attachment A of DOP 0500-03. Procedure HU-AA-101,"Human Performance Tools and Verification Practices," Revision 3, required the individuals to agree that the system wasready for the action prior to performing the action. The US failed to verify that the systemwas reset or to check the proceeding steps had been completed prior to going into the next step. Both operators had been provided with marked up copies of the procedure, and briefed on jumper placement and removal and on the use of concurrent verification prior to the event.Analysis:  The inspectors determined that the failure to implement procedure instructions forperforming the swap of the RPS buses to support a planned maintenance activity, that impacted safety-related equipment, was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordancewith Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports,"
On April 5, 2006, during the swap of the 3A reactor protection system (RPS) bus to reservepower to support repair of the 3B RPS motor generator (MG) set, the Unit 2/3 standby gas treatment auto started and a Unit 3 reactor building ventilation isolation occurred. Thelicensee determined that the cause of this issue was a human performance error for the failure to perform steps in the proper sequence. All systems were restored in accordancewith plant procedures and there was no equipment that was damaged or any personnel thatwere injured. The licensee entered this issue into their corrective action program as IR 475365.This represented one inspection sample.b.FindingIntroduction:  A Green finding involving a non-cited violation of TS 5.4.1 was self revealedwhen an auxiliary nuclear station operator (Aux NSO) and a unit supervisor (US) wereperforming Dresden Operating Procedure (DOP) 0500-03, "Reactor Protection System Power Supply Operation," Revision 27. The Aux NSO and the US did not verify that thearea radiation monitor's (ARM) power supply voltage was normal and did not reset all trips on the ARM modules prior to removing a jumper that was installed. This required entry into TS 3.6.4.1 Limiting Condition of Operation, Action A for reactor building low differentialpressure (D/P).Description:  On April 5, 2006, operations department staff were placing the 3A reactorprotection system (RPS) bus to reserve power from the normal power source to supportrepair of the 3B RPS motor generator (MG) set using DOP 0500-03. The operators reset a half scram that was expected during this activity and then they proceeded with removing a jumper that was installed, in accordance with the procedure, to allow the transfer. Following the removal of the jumper, the Unit 3 reactor building ventilation tripped and the Unit 2/3 standby gas treatment train auto started. Neither the Aux NSO nor the US verified that theARM power supply was indicating normal and that the 3A reactor building ventilation and 22reactor building fuel pool channel 'A' ARMs were reset prior to jumper removal as requiredby attachment A of DOP 0500-03. Procedure HU-AA-101,"Human Performance Tools and Verification Practices," Revision 3, required the individuals to agree that the system wasready for the action prior to performing the action. The US failed to verify that t he syst emwas reset or to check the proceeding steps had been completed prior to going into the next step. Both operators had been provided with marked up copies of the procedure, and briefed on jumper placement and removal and on the use of concurrent verification prior to the event.Analysis:  The inspectors determined that the failure to implement procedure instructions forperforming the swap of the RPS buses to support a planned maintenance activity, that impacted safety-related equipment, was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordancewith Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports,"
Appendix B, "Issue Screening," issued on September 30, 2005, because it impacted thestructures, systems, and components attribute of the Barrier Integrity cornerstone(containment) objective. This deficiency challenged a safety system and could haveaffected the availability and capability of components and systems that respond to initiatingevents.The inspectors completed a Phase 1 significance determination of this issue usingIMC 0609, "Significance Determination Process," Appendix A, Attachment 1, dated  November 22, 2005, and determined that this finding impacted the Barrier Integritycornerstone column. The inspectors answered "Yes" to question #1 under the Barrier Integrity column on page A1-9. Therefore, the issue screened out as having very low significance (Green).The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (personnel) because the Aux NSO and the US failed to utilize humanperformance error prevention techniques required to safely implement the station procedure.Enforcement:  Technical Specification 5.4.1 required, in part, that written procedures shallbe established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978, paragraph 1.jrequired administrative procedures for the bypassing of safety functions and jumper control. Station procedure DOP 0500-03, Attachment A, "Bypassing and Restoration of SecondaryContainment Isolations and SBGT Initiations When De-Energizing 'A' RPS Bus,"
Appendix B, "Issue Screening," issued on September 30, 2005, because it impacted thestructures, systems, and components attribute of the Barrier Integrity cornerstone(containment) objective. This deficiency challenged a safety system and could haveaffected the availability and capability of com ponents and systems that respond to initiatingevents.The inspectors completed a Phase 1 significance determination of this issue usingIMC 0609, "Significance Determination Process," Appendix A, Attachment 1, dated  November 22, 2005, and determined that this finding impacted the Barrier Integritycornerstone column. The inspectors answered "Yes" to question #1 under the Barrier Integrity column on page A1-9. Therefore, the issue screened out as having very low significance (Green).The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (personnel) because the Aux NSO and the US failed to utilize humanperformance error prevention techniques required to safely implement the station procedure.Enforcement:  Technical Specification 5.4.1 required, in part, that written procedures shallbe established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978, paragraph 1.jrequired administrative procedures for the bypassing of safety functions and jumper control. Station procedure DOP 0500-03, Attachment A, "Bypassing and Restoration of SecondaryContainment Isolations and SBGT Initiations When De-Energizing 'A' RPS Bus,"
Revision 27, Removing Jumpers Step 1, stated, "Prior to jumper removal verify ARM power supply 2(3)-1705-7A at 902(3)-10 is indicating normal voltage compared to other power supply;" and Step 2, "Reset ALL trips on the 902-(3)-10 ARM Modules AND verify annunciators are reset.Contrary to the above, on April 5, 2006, neither the NSO nor the US, verified that theARM power supply 2(3)-1705-7A at 902(3)-10 was indicating normal voltage compared to the other power supply or reset all trips on the 902-(3)-10 ARM Modules or verified that the annunciators reset prior to removing jumpers identified in procedure DOP 0500-03, Revision 27.
Revision 27, Removing Jumpers Step 1, stated, "Prior to jumper removal verify ARM power supply 2(3)-1705-7A at 902(3)-10 is indicating normal voltage compared to other power supply;" and Step 2, "Reset ALL trips on the 902-(3)-10 ARM Modules AND verify annunciators are reset.Contrary to the above, on April 5, 2006, neither the NSO nor the US, verified that theARM power supply 2(3)-1705-7A at 902(3)-10 was indicating normal voltage compared to the other power supply or reset all trips on the 902-(3)-10 ARM Modules or verified that the annunciators reset prior to removing jumpers identified in procedure DOP 0500-03, Revision 27.


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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors reviewed operability evaluations (OE) to ensure that operability was properlyjustified and the component or system remained available, such that any non-conformanceconditions were in compliance with Generic Letter 91-18, "Information to Licensees 25Regarding Two NRC Inspection Manual Sections on Resolution of Degraded andNonconforming Conditions and on Operability."  The review included issues involving theoperability of:*Engineering Change/Evaluation #359519, MR-90 Technical Evaluation to supportshoring for trenching of underground piping and tank 2/3 B condensate storage tank;*Engineering Change/Evaluation #342944, Unit 3 containment cooling service watersystem water hammer loss of keep-fill analysis; and*Document # 0006216498, dated July 7, 2000, "Dresden Unit 2 High Pressure CoolantInjection Room Cooler Operability."This represented three inspection samples.
The inspectors reviewed operability evaluations (OE) to ensure that operability was properlyjustified and the component or system remained available, such that any non-conformanceconditions were in compliance with Generic Letter 91-18, "Information to Licensees 25Regarding Two NRC Inspection Manual Sections on Resolution of Degraded andNonconforming Conditions and on Operability."  The review included issues involving theoperability of:*Engineering Change/Evaluation #359519, MR-90 Technical Evaluation to supportshoring for trenching of underground piping and tank 2/3 B condensate storage tank;*Engineering Change/Evaluation #342944, Unit 3 containment cooling service watersystem water hammer loss of keep-f ill analysis; and*Document # 0006216498, dated July 7, 2000, "Dresden Unit 2 High Pressure CoolantInjection Room Cooler Operability."This represented three inspection samples.


====b. Findings====
====b. Findings====
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=====Introduction:=====
=====Introduction:=====
The inspectors identified a finding involving a violation of 10 CFR 50.62,having very low safety significance (Green) associated with a licensee-identified material condition. The licensee identified that the inputs to a design analysis (DRE01-0066,"Dresden Unit 2 & 3 Standby Liquid Control System Discharge Piping Pressure Drop,"
The inspectors identified a finding involving a violation of 10 CFR 50.62,having very low safety significance (Green) associated with a licensee-identified material condition. The licensee identified that the inputs to a design analysis (DRE01-0066,"Dresden Unit 2 & 3 Standby Liquid Control System Discharge Piping Pressure Drop,"
Revision 1) were non-conservative. Some of the valves actually installed in the plant were not the same type of valves assumed to be installed in the design analysis. This ultimately resulted in a change in a design calculation that demonstrated that standby liquid controlsystem relief valves could lift upon system initiation during an anticipated transient withoutscram (ATWS) event.Description:  On May 5, 2006, during a system walkdown the licensee identified that valves2/3-1101-2A & 2B, 2/3-1101-23, and 2/3 1101-1 are globe valves rather than gate valvesand valves 2/3-1101-43A & 43B, 2/3-1101-15 & 16 are lift check valves rather than swing check valves as shown in calculation DRE01-0066, Revision 1.The impact of having some of the valves actually installed in the plant that were not thesame type of valves assumed to be installed in the ATWS Analysis was that it resulted in a 26higher pressure drop between the pump discharge and the reactor than calculated in DRE01-0066, Revision 1. This higher pressure drop meant that pump discharge pressure had to be higher to get flow to the reactor and the SBLC system relief valves could liftduring an ATWS event. The lifting of the relief valves would cause SBLC system flow to be recirculated to the system storage tank rather than injected into the reactor vessel. Due tothe inability to provide continuous SBLC system design flow into the reactor vessel asrequired by 10 CFR 50.62.c.(4), the licensee would fail to comply with 10 CFR 50.62.c.(4) if the relief valve lifted.A licensee contractor revised calculation DRE01-0066 using the installed valve types. The results indicated that based on a two pump flow of 88 gallons per minute, the calculated system pressure loss increased to 215 psig for Unit 2 (as compared to 141 psig)and 362 psig for Unit 3 (as compared to 232 psi). Based on these results the licensee concluded that the SBLC relief valves would lift, during two pump flow, under the condition when SBLC was required to inject into the vessel.The licensee performed Engineering Change (EC) 360883 to document the justificationfor operability basis stated in IR 488251, "Non-Conservative Inputs Used In SBLCPressure Drop Calculation."  Because the revision to calculation DRE01-0066 had not been completed at the time EC 360883 was performed, the licensee assumed higher values of pressure drop in EC 360883 than what was eventually determined to be accurate in DRE01-0066, Revision 2. The licensee assumed a 300 psig drop for Unit 2 and a 390 psig drop for Unit 3 when performing EC 360883. The licensee analyzed for a failed open pressure regulator along with a failure of the alternate rod insertion system. This was assumed to be the most limiting transient. The licensee concluded that vessel peak pressure and temperature, and also peak cladding temperature would not be impacted by the increase in SBLC pressure drop since they occur before the SBLC system would be initiated. In addition, the licensee assumed the event duration was short enough that fuelclad oxidation was not an issue. The licensee did conclude that delayed SBLC systeminjection would have an impact on the maximum suppression pool temperature and pressure. The licensee concluded that with the assumed higher calculated pressure drops (300 psig and 390 psig), suppression pool temperature could be maintained at an acceptable level, but only by taking credit for the reactor cooling provided by the isolation condenser.The licensee took several conservativisms in EC 360883. For example, all the reactor reliefvalves were assumed to open at their set point plus three percent and both SBLC systemrelief valves were assumed to open at their set point minus 3 percent. In addition, the licensee assumed that both SBLC system relief valves would open instead of the morelikely scenario that only one would open. If one SBLC relief valve remained closed more flow would be available to the reactor.Compliance with the 10 CFR 50.62The inspectors used the above information to determine that the potential to lift the SBLCrelief valve resulted in the licensee being outside of the design basis and in noncompliance with 10 CFR 50.62 because the system would be unable to meet the required injection flowrate and boron concentration during the time the relief valves were lifting.
Revision 1) were non-conservative. Some of the valves actually installed in the plant were not the same type of valves assumed to be installed in the design analysis. This ultimately resulted in a change in a design calculation that demonstrated that standby liquid controlsystem relief valves could lift upon system initiation during an anticipated transient withoutscram (ATWS) event.Description:  On May 5, 2006, during a system walkdown the licensee identified that valves2/3-1101-2A & 2B, 2/3-1101-23, and 2/3 1101-1 are globe valves rather than gate valvesand valves 2/3-1101-43A & 43B, 2/3-1101-15 & 16 are lift check valves rather than swing check valves as shown in calculation DRE01-0066, Revision 1.The impact of having some of the valves actually installed in the plant that were not thesame type of valves assumed to be installed in the ATWS Analysis was that it resulted in a 26higher pressure drop between the pump discharge and the reactor than calculated in DRE01-0066, Revision 1. This higher pressure drop meant that pump discharge pressure had to be higher to get flow to the reactor and the SBLC system relief valves could liftduring an ATWS event. The lifting of the relief valves would cause SBLC system flow to be recirculated to the system storage tank rather than injected into the reactor vessel. Due tothe inability to provide continuous SBLC system design flow into the reactor vessel asrequired by 10 CFR 50.62.c.(4), the licensee would fail to comply with 10 CFR 50.62.c.(4) if the relief valve lifted.A licensee contractor revised calculation DRE01-0066 using the installed valve types. The results indicated that based on a two pump flow of 88 gallons per minute, the calculated system pressure loss increased to 215 psig for Unit 2 (as compared to 141 psig)and 362 psig for Unit 3 (as compared to 232 psi). Based on these results the licensee concluded that the SBLC relief valves would lift, during two pump flow, under the condition when SBLC was required to inject into the vessel.The licensee performed Engineering Change (EC) 360883 to document the justificationfor operability basis stated in IR 488251, "Non-Conservative Inputs Used In SBLCPressure Drop Calculation."  Because the revision to calculation DRE01-0066 had not been completed at the time EC 360883 was performed, the licensee assumed higher values of pressure drop in EC 360883 than what was eventually determined to be accurate in DRE01-0066, Revision 2. The licensee assumed a 300 psig drop for Unit 2 and a 390 psig drop for Unit 3 when performing EC 360883. The licensee analyzed for a failed open pressure regulator along with a failure of the alternate rod insertion system. This was assumed to be the most limiting transient. The licensee concluded that vessel peak pressure and temperature, and also peak cladding temperature would not be impacted by the increase in SBLC pressure drop since they occur before the SBLC system would be initiated. In addition, the licensee assumed the event duration was short enough that fuelclad oxidation was not an issue. The licensee did conclude that del ayed SBLC systeminjection would have an impact on the maximum suppression pool temperature and pressure. The licensee concluded that with the assumed higher calculated pressure drops (300 psig and 390 psig), suppression pool temperature could be maintained at an acceptable level, but only by taking credit for the reactor cooling provided by the isolation condenser.The licensee took several conservativisms in EC 360883. For example, all the reactor reliefvalves were assumed to open at their set point plus three per cent and both SBLC systemrelief valves were assumed to open at their set point minus 3 percent. In addition, the licensee assumed that both SBLC system relief valves would open instead of the morelikely scenario that only one would open. If one SBLC relief valve remained closed more flow would be available to the reactor.Compliance with the 10 CFR 50.62The inspectors used the above information to determine that the potential to lift the SBLCrelief valve resulted in the licensee being outside of the design basis and in noncompliance with 10 CFR 50.62 because the system would be unable to meet the required injection flowrate and boron concentration during the time the relief valves were lifting.


27To achieve compliance with 10 CFR 50.62, the licensee planned to increase SBLC boronenrichment from greater than or equal to 30 atom percent boron-10 to greater than or equalto 45 atom percent boron-10. This would allow the licensee to provide the acceptable amount of boron per 10 CFR 50.62 while using only one pump. In addition, licensee's calculation DRE01-0066, Revision 2, demonstrated that the use of one SBLC pump wouldnot result in lifting a SBLC relief valve. The licensee planned to fill the SBLC tank with theenriched boron on each unit during the next refueling outages. Review of TS OperabilityTechnical Specification Surveillance Requirement 3.1.7.7 required the licensee todemonstrate that each SBLC pump was capable of pumping at a rate of at least 40 gpm with a discharge pressure of greater than or equal to 1275 psig. The inspectors reviewed additional information on the relief valves and determined that due to differences in systemhead losses during one and two pump system operation, the licensee could inject flow intothe reactor with one pump at the rate specified in TS Surveillance Requirement 3.1.7.7without lifting the relief valves. Based upon the continued ability to satisfy TS SurveillanceRequirement 3.1.7.7, the licensee determined that the SBLC system remained operableeven though the licensee was unable to continuously inject 86 gpm of sodium pentaborate solution as required to meet 10 CFR 50.62. In addition, the TS Basis stated that with onesubsystem inoperable the requirements of 10 CFR 50.62 cannot be met, however, theremaining subsystem is still capable of shutting down the unit.The Office of Nuclear Reactor Regulation also determined in Task InterfaceAgreement 2001-12, for a similar issue at the Susquehanna plant, that although thelicensee was not in compliance with 10 CFR 50.62, the standby liquid control systemremained operable as required by TS 3.1.7. This determination was based upon information contained in NUREG-1433, "Standard Technical Specifications GeneralElectric Plants," which states that TS 3.1.7 does not require meeting the requirements of10 CFR 50.62 to meet the associated TS Limiting Condition for Operation. Based upon thisinformation, the inspectors concluded that no violation of TSs occurred.Analysis:  The inspectors determined that the failure to comply with 10 CFR 50.62 was aperformance deficiency warranting a significance determination. The inspectors concluded that the finding was greater than minor in accordance with IMC 062, "Power Reactor Inspection Reports," Appendix B, "Issue Disposition Screening," issued on September 30, 2005. This finding involved the attribute of design control and could haveaffected the Mitigating Systems objective of ensuring the capability of systems that respondto initiating events to prevent undesirable consequences.The inspectors completed a significance determination of this issue using IMC 0609,Significance Determination Process," dated November 22, 2005. The finding was associated with the Mitigating Systems cornerstone. Specifically, it impacted the reactivity control degraded attribute found on page A1-7 of Appendix A. The inspectors performed a Phase I screening of the finding. The inspectors answered "Yes" to question 1, under the Mitigating System cornerstone on page A1-9, "is the finding a design or qualification deficiency confirmed not to result in loss of operability per Part 9900, Technical Guidance,Operability Determination Process for Operability and Functional Assessment," andtherefore the issue screened as very low significance (Green). The SBLC system could berecovered during an ATWS event. Cycling of the relief valves would not prevent most of the 28borated solution from being injected into the reactor pressure vessel, and the licensee wasable to demonstrate that the reactor remained within the acceptance criteria of their originalATWS analyses even if no boron solution was injected into the reactor pressure vessel while the relief valves lifted.Enforcement:  Part 50.62 of Title 10 CFR requires, in part, that each boiling water reactormust have a SBLC system with the capability of injecting into the reactor pressure vessel aborated water solution at such a flow rate that the resulting reactivity control was at least equivalent to that resulting from the injection of 86 gpm of 13 weight percent sodium pentaborate decahydrate (boron) solution. Contrary to the above, the licensee has failed to have, since 1984, a SBLC system with thecapability of injecting into the reactor pressure vessel a borated water solution at such aflow rate that the resulting reactivity control was at least equivalent to that resulting from the injection of 86 gpm of 13 weight percent sodium pentaborate decahydrate (boron) solution. This condition was considered a performance deficiency. To achieve compliance with 10 CFR 50.62, the licensee planned to increase SBLC boronenrichment from greater than or equal to 30 atom percent boron-10 to greater than or equalto 45 atom percent boron-10. This would allow the licensee to provide the acceptable amount of boron per 10 CFR 50.62 while using only one pump. In addition, licensee's calculation DRE01-0066, Revision 2, demonstrated that the use of one SBLC pump wouldnot result in lifting a SBLC relief valve. The licensee planned to install the enriched boron on each unit during the next refueling outages. The inspectors questioned why the boron enrichment could not be accomplished during a forced outage. The licensee wrote IR 507856 to address this question. The answer was not obtained by the end of the inspection period.Because this violation was of very low safety significance and it was entered into thelicensee's corrective action program as IR 488251, this violation is being treated as a non-cited violation (NCV), consistent with Section VI.A of the NRC Enforcement Policy.(NCV 05000237/2006-007-05; 05000249/2006-007-05).
27To achieve compliance with 10 CFR 50.62, the licensee planned to increase SBLC boronenrichment from greater than or equal to 30 atom percent boron-10 to greater than or equalto 45 atom percent boron-10. This would allow the licensee to provide the acceptable amount of boron per 10 CFR 50.62 while using only one pump. In addition, licensee's calculation DRE01-0066, Revision 2, demonstrated that the use of one SBLC pump wouldnot result in lifting a SBLC relief valve. The licensee planned to fill the SBLC tank with theenriched boron on each unit during the next refueling outages. Review of TS OperabilityTechnical Specification Surveillance Requirement 3.1.7.7 required the licensee todemonstrate that each SBLC pump was capable of pumping at a rate of at least 40 gpm with a discharge pressure of greater than or equal to 1275 psig. The inspectors reviewed additional information on the relief valves and determined that due to differences in systemhead losses during one and two pump system operation, the licensee could inject flow intothe reactor with one pump at the rate specified in TS Surveillance Requirement 3.1.7.7without lifting the relief valves. Based upon the continued ability to satisfy TS SurveillanceRequirement 3.1.7.7, the licensee determined that the SBLC system remained operableeven though the licensee was unable to continuously inject 86 gpm of sodium pentaborate solution as required to meet 10 CFR 50.62. In addition, the TS Basis stated that with onesubsystem inoperable the requirements of 10 CFR 50.62 cannot be met, however, theremaining subsystem is still capable of shutting down the unit.The Office of Nuclear Reactor Regulation also determined in Task InterfaceAgreement 2001-12, for a similar issue at the Susquehanna plant, that although thelicensee was not in compliance with 10 CFR 50.62, the standby liquid control systemremained operable as required by TS 3.1.7. This determination was based upon information contained in NUREG-1433, "Standard Technical Specifications GeneralElectric Plants," which states that TS 3.1.7 does not require meeting the requirements of10 CFR 50.62 to meet the associated TS Limiting Condition for Operation. Based upon thisinformation, the inspectors concluded that no violation of TSs occurred.Analysis:  The inspectors determined that the failure to comply with 10 CFR 50.62 was aperformance deficiency warranting a significance determination. The inspectors concluded that the finding was greater than minor in accordance with IMC 062, "Power Reactor Inspection Reports," Appendix B, "Issue Disposition Screening," issued on September 30, 2005. This finding involved the attribute of design control and could haveaffected the Mitigating Systems objective of ensuring the capability of systems that res pondto initiating events to prevent undesirable consequences.The inspectors completed a significance determination of this issue using IMC 0609,Significance Determination Process," dated November 22, 2005. The finding was associated with the Mitigating Systems cornerstone. Specifically, it impacted the reactivity control degraded attribute found on page A1-7 of Appendix A. The inspectors performed a Phase I screening of the finding. The inspectors answered "Yes" to question 1, under the Mitigating System cornerstone on page A1-9, "is the finding a design or qualification deficiency confirmed not to result in loss of operability per Part 9900, Technical Guidance,Operability Determination Process for Operability and Functional Assessment," andtherefore the issue screened as very low significance (Green). The SBLC system could berecovered during an ATWS event. Cycling of the relief valves would not prevent most of the 28borated solution from being injected into the reactor pressure vessel, and the licensee wasable to demonstrate that the reactor remained within the acceptance criteria of their originalATWS analyses even if no boron solution was injected into the reactor pressure vessel while the relief valves lifted.Enforcement:  Part 50.62 of Title 10 CFR requires, in part, that each boiling water reactormust have a SBLC system with the capability of injecting into the reactor pressure vessel aborated water solution at such a flow rate that the resulting reactivity control was at least equivalent to that resulting from the injection of 86 gpm of 13 weight percent sodium pentaborate decahydrate (boron) solution. Contrary to the above, the licensee has failed to have, since 1984, a SBLC system with thecapability of injecting into the reactor pressure vessel a borated water solution at such aflow rate that the resulting reactivity control was at least equivalent to that resulting from the injection of 86 gpm of 13 weight percent sodium pentaborate decahydrate (boron) solution. This condition was considered a performance deficiency. To achieve compliance with 10 CFR 50.62, the licensee planned to increase SBLC boronenrichment from greater than or equal to 30 atom percent boron-10 to greater than or equalto 45 atom percent boron-10. This would allow the licensee to provide the acceptable amount of boron per 10 CFR 50.62 while using only one pump. In addition, licensee's calculation DRE01-0066, Revision 2, demonstrated that the use of one SBLC pump wouldnot result in lifting a SBLC relief valve. The licensee planned to install the enriched boron on each unit during the next refueling outages. The inspectors questioned why the boron enrichment could not be accomplished during a forced outage. The licensee wrote IR 507856 to address this question. The answer was not obtained by the end of the inspection period.Because this violation was of very low safety significance and it was entered into thelicensee's corrective action program as IR 488251, this violation is being treated as a non-cited violation (NCV), consistent with Section VI.A of the NRC Enforcement Policy.(NCV 05000237/2006-007-05; 05000249/2006-007-05)
{{a|1R19}}
 
==1R19 Post Maintenance Testing (71111.19)==
===.1 R19Post Maintenance Testing===
{{IP sample|IP=IP 71111.19}}


====a. Inspection Scope====
====a. Inspection Scope====
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors observed station personnel during a licensee-only-participation emergencypreparedness training exercise on May 31, 2006. The inspectors evaluated the effectiveness of drill participants and the adequacy of the licensee's critique in identifyingweaknesses and failures. The drill scenario involved the reactor protection system failure toinitiate an automatic scram and initiation of the alternate rod insertion system.This represented one inspection sample.
The inspectors observed station personnel during a licensee-only-participation emergencypreparedness training exercise on May 31, 2006. The inspectors evaluated the effectiveness of drill participants and the adequacy of the licensee's critique in identifyingweaknesses and failures. The dr ill scenario involved the reactor protection system failure toinitiate an automatic scram and initiation of the alternate rod insertion system.This represented one inspection sample.


====b. Findings====
====b. Findings====
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====b. Findings====
====b. Findings====
No findings of significance were identified4OA2Identification and Resolution of Problems (71152).1Routine Quarterly ReviewReview of Licensee's Response to the Unit 2 "A" Electrohydraulic Control System (EHC)Pressure Regulator IssueOn March 24, 2005, Unit 2 received two unexpected control room alarms due to anEHC system malfunction. Several seconds later, Unit 2 experienced a steam transientwhich caused a Group 1 isolation and scram. The licensee initiated IR 316625 and initiated a prompt investigation to ensure the details regarding this event were appropriately captured and corrected. a.Effectiveness of Problem Identification (1)Inspection ScopeThe inspectors reviewed the information provided in IR 316625 and the associated rootcause report to verify that the licensee's identification of the problems was complete, accurate, and timely, and that the consideration of extent of condition review, generic implications, and common cause was adequate.
No findings of significance were identified4OA2Identification and Resolution of Problems (71152).1Routine Quarterly ReviewReview of Licensee's Response to the Unit 2 "A" Electrohydraulic Control System (EHC)Pressure Regulator IssueOn March 24, 2005, Unit 2 received two unexpected control room alarms due to anEHC system malfunction. Several seconds later, Unit 2 experienced a steam transientwhich caused a Group 1 isolation and scram. The licensee initiated IR 316625 and initiated a prompt investigation to ensure the details regarding this event were appropriately captured and corrected. a.Effectiveness of Problem Identification (1)Inspection ScopeThe inspectors reviewed the information provided in IR 316625 and the associated rootcause report to verify that the licensee's identification of the problems was complete, accurate, and timely, and that the consideration of extent of condition review, generic implications, and common cause was adequate.


(2)IssuesThere were no issues in the area of Effectiveness of Problem Identification.
(2)IssuesThere were no issues in the area of Effectiveness of Problem Identification.
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TAC Nos. MB7297 through MB7300.The inspectors were concerned that anchor bolts for HELB pipe whip restraints at theDresden and Quad Cities stations were designed with a minimum SF of 2.0, which was less than the SF of 4.0 they expected.  (Reference Quad Cities Inspection FollowupItem 05000254/96011-06; 05000265/96011-06). Subsequently, the licensee performed additional analysis, and determined that there are five CEAs at Quad Cities, and one CEA at Dresden that have a designed factor of safety between 2.5 and 3.8. These CEAs areused in pipe whip restraints (HERs) provided for high energy line break mitigation. CEAs used to satisfy seismic design requirements must have a SF of 4.0 or greater. CEAs used for other applications, such as HERs, are typically designed with a SF of 4.0.
TAC Nos. MB7297 through MB7300.The inspectors were concerned that anchor bolts for HELB pipe whip restraints at theDresden and Quad Cities stations were designed with a minimum SF of 2.0, which was less than the SF of 4.0 they expected.  (Reference Quad Cities Inspection FollowupItem 05000254/96011-06; 05000265/96011-06). Subsequently, the licensee performed additional analysis, and determined that there are five CEAs at Quad Cities, and one CEA at Dresden that have a designed factor of safety between 2.5 and 3.8. These CEAs areused in pipe whip restraints (HERs) provided for high energy line break mitigation. CEAs used to satisfy seismic design requirements must have a SF of 4.0 or greater. CEAs used for other applications, such as HERs, are typically designed with a SF of 4.0.


34An Internal NRC Memorandum (R. Capra to J. Grobe) dated, July 23, 1997, respondedto an NRC Region III Request for Technical Assistance (Task Interface Agreement(TIA) 96-0325) (G. Grant to J. Roe) dated, September 20, 1996, and provided the NRCOffice of Nuclear Reactor Regulation (NRR) evaluation of the issue. Additional discussions and correspondence between the licensee and NRC staff occurredwith respect to this issue. Additional onsite inspection of this issue occurred as indicated in NRC Integrated Inspection Report 05000254/03-02; 05000265/03-02. Docketed correspondence between the NRC and the licensee included the following:Letter from NRC to L. Pearce (ComEd) dated December 16, 1997;Letter from J. Heffley (ComEd) to NRC dated January 9, 1998; Exelon Response to Verbal Request for Additional Information (K. Jury (Exelon) to NRCDocument Control Desk) dated September 11, 2002;NRC Request for Additional Information, M. Banerjee (NRC) to C. Crane (Exelon) dated,August 10, 2004; andExelon Response to Request for Additional Information (P. Simpson to NRC DocumentControl Desk) dated, September 30, 2004.There is no specific regulatory requirement or commitment regarding the SF for theseCEAs. Therefore, the staff did not identify any non-compliance with a specific regulatory requirement. However, in order to ensure that adequate protection exists given the smaller SFs, the staff requested the licensee to provide a bounding type of analysis to discuss the safety impact of these CEAS failing to perform their safety function upon a postulated failureof the pipe (a beyond design basis analysis).The licensee provided the requested analysis in the letter dated, September 30, 2004,(available in the NRC agencywide document access and management system (ADAMS)under accession number ML042820219). The staff reviewed this analysis and performed a walkdown of the plant areas where some of the protected equipment is located. Thefollowing provides a summary of the licensee's response and the staff's observation during the walkdown regarding the safety impact of postulated failures of the subject CEAs (for Dresden) to restrain the high energy line in the unlikely event of a total circumferential break:Dresden HER PWHP-3This anchor is located on the high pressure coolant injection (HPCI) steam line in the torusarea. During a postulated HPCI steam line circumferential break, if this anchor fails, the whipping pipe could damage certain safety related motor operators for valves in the low pressure coolant injection (LPCI) system (not crediting several structural elements in between the pipe and the valve operators). These valves are in the return line to the torus for one of the redundant torus cooling/spray loops, and hence damage to these valves could cause the loss of one of the two loops of the suppression pool cooling system. Thehigh HPCI steam flow out the ruptured pipe will isolate the system, thus terminating the 35flow. The operators will use symptom based emergency operating procedures (EOPs) toshutdown the reactor from the control room. The suppression pool cooling system is notrequired to mitigate the accident, as the isolation condenser system will be available toremove decay heat before normal shutdown cooling could be initiated. Additionally, the main condenser should also be available if the high steam flow does not isolate the main steam lines. ConclusionBased on a review of the information that was provided, the staff agrees that there isreasonable assurance that the plant can be safely shutdown in the event of acircumferential pipe break, and subsequent failure of its related CEA(s) as described above. Therefore, adequate protection exists for a postulated beyond design basis event when the subject CEAs with a SF of less than 4.0 are assumed to fail after a high energy line break. Hence, no further regulatory action is warranted relative to this issue.
34An Internal NRC Memorandum (R. Capra to J. Grobe) dated, July 23, 1997, respondedto an NRC Region III Request for Technical Assistance (Task Interface Agreement(TIA) 96-0325) (G. Grant to J. Roe) dated, September 20, 1996, and provided the NRCOffice of Nuclear Reactor Regulation (NRR) evaluation of the issue. Additional discussions and correspondence between the licensee and NRC staff occurredwith respect to this issue. Additional onsite inspection of this issue occurred as indicated in NRC Integrated Inspection Report 05000254/03-02; 05000265/03-02. Docketed correspondence between the NRC and the licensee included the following:Letter from NRC to L. Pearce (ComEd) dated December 16, 1997;Letter from J. Heffley (ComEd) to NRC dated January 9, 1998; Exelon Response to Verbal Request for Additional Information (K. Jury (Exelon) to NRCDocument Control Desk) dated September 11, 2002; NRC Request for Additional Information, M. Banerjee (NRC) to C. Crane (Exelon) dated,August 10, 2004; andExelon Response to Request for Additional Information (P. Simpson to NRC DocumentControl Desk) dated, September 30, 2004.There is no specific regulatory requirement or commitment regarding the SF for theseCEAs. Therefore, the staff did not identify any non-compliance with a specific regulatory requirement. However, in order to ensure that adequate protection exists given the smaller SFs, the staff requested the licensee to provide a bounding type of analysis to discuss the safety impact of these CEAS failing to perform their safety function upon a postulated failureof the pipe (a beyond design basis analysis).The licensee provided the requested analysis in the letter dated, September 30, 2004,(available in the NRC agencywide document access and management system (ADAMS)under accession number ML042820219). The staff reviewed this analysis and performed a walkdown of the plant areas where some of the protected equipment is located. Thefollowing provides a summary of the licensee's response and the staff's observation during the walkdown regarding the safety impact of postulated failures of the subject CEAs (for Dresden) to restrain the high energy line in the unlikely event of a total circumferential break:Dresden HER PWHP-3This anchor is located on the high pressure coolant injection (HPCI) steam line in the torusarea. During a postulated HPCI steam line circumferential break, if this anchor fails, the whipping pipe could damage certain safety related motor operators for valves in the low pressure coolant injection (LPCI) system (not crediting several structural elements in between the pipe and the valve operators). These valves are in the return line to the torus for one of the redundant torus cooling/spray loops, and hence damage to these valves could cause the loss of one of the two loops of the suppression pool cooling system. Thehigh HPCI steam flow out the ruptured pipe will isolate the system, thus terminating the 35flow. The operators will use symptom based emergency operating procedures (EOPs) toshutdown the reactor from the control room. The suppression pool cooli ng system is notrequired to mitigate the accident, as the isolation condenser system will be available toremove decay heat before normal shutdown cooling could be initiated. Additionally, the main condenser should also be available if the high steam flow does not isolate the main steam lines. ConclusionBased on a review of the information that was provided, the staff agrees that there isreasonable assurance that the plant can be safely shutdown in the event of acircumferential pipe break, and subsequent failure of its related CEA(s) as described above. Therefore, adequate protection exists for a postulated beyond design basis event when the subject CEAs with a SF of less than 4.0 are assumed to fail after a high energy line break. Hence, no further regulatory action is warranted relative to this issue.


The TAC Nos. MB7297 through MB7300 are closed. This unresolved item is also closed.4OA6Meetings.1Exit MeetingThe inspectors presented the inspection results to the Plant Manager, Mr. D. Wozniak, andother members of licensee management on July 18, 2006. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was discussed..2Interim Exit MeetingsInterim exit meetings were conducted for:
The TAC Nos. MB7297 through MB7300 are closed. This unresolved item is also closed.4OA6Meetings.1Exit MeetingThe inspectors presented the inspection results to the Plant Manager, Mr. D. Wozniak, andother members of licensee management on July 18, 2006. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was discussed..2Interim Exit MeetingsInterim exit meetings were conducted for:
Line 349: Line 367:
: [[contact::M. Otten]], Corporate Training
: [[contact::M. Otten]], Corporate Training
: [[contact::B. Rybak]], Acting Regulatory Assurance Manager
: [[contact::B. Rybak]], Acting Regulatory Assurance Manager
: [[contact::C. Symonds]], Training Director
: [[contact::C. Symonds]], Training DirectorNRC pers onnel
===NRC personnel===
: [[contact::M. Ring]], Chief, Division of Reactor Projects, Branch 1IEMA personnel
: [[contact::M. Ring]], Chief, Division of Reactor Projects, Branch 1IEMA personnel
: [[contact::R. Schulz]], Illinois Emergency Management Agency
: [[contact::R. Schulz]], Illinois Emergency Management Agency
Line 356: Line 373:
2
2
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
Opened05000237/2006007-01NCVFailure to Identify an Inoperable 3-hour Fire Barrier Wall in theUnit 2 EDG Day Tank Room05000237/2006007-02NCVUnit 2 350 psig Reactor Low Pressure Emergency CoreCooling System Permissive Switch Out-of-tolerance During
 
===Opened===
05000237/2006007-01NCVFailure to Identify an Inoperable 3-hour Fire Barrier Wall in theUnit 2 EDG Day Tank Room05000237/2006007-02NCVUnit 2 350 psig Reactor Low Pressure Emergency CoreCooling System Permissive Switch Out-of-tolerance During
Surveillance Testing05000237/2006007-03NCVFailure to Post Protective Pathway Signs During Unavailabilityof Torus to Reactor Building Vacuum Breaker05000249/2006007-04NCVFailure to Perform Procedure Steps in the Proper Sequenceby Operations Caused Emergency Safety Feature Systems
Surveillance Testing05000237/2006007-03NCVFailure to Post Protective Pathway Signs During Unavailabilityof Torus to Reactor Building Vacuum Breaker05000249/2006007-04NCVFailure to Perform Procedure Steps in the Proper Sequenceby Operations Caused Emergency Safety Feature Systems
Actuation05000237/2006007-05FINUnit 2 High Pressure Coolant Injection (HPCI) SystemDeclared Inoperable05000237/2006007-06NCVStandby Liquid Control Valves Installed In The Plant05000249/2006007-06Different than those Assumed in a Design CalculationClosed05000237/2006007-01NCVFailure to Identify an Inoperable 3-hour Fire Barrier Wall in theUnit 2 EDG Day Tank Room05000237/2006007-02NCVUnit 2 350 psig Reactor Low Pressure Emergency CoreCooling System Permissive Switch Out-of-Tolerance During
Actuation05000237/2006007-05FINUnit 2 High Pressure Coolant Injection (HPCI) SystemDeclared Inoperable05000237/2006007-06NCVStandby Liquid Control Valves Installed In The Plant05000249/2006007-06Different than those Assumed in a Design CalculationClosed05000237/2006007-01NCVFailure to Identify an Inoperable 3-hour Fire Barrier Wall in theUnit 2 EDG Day Tank Room05000237/2006007-02NCVUnit 2 350 psig Reactor Low Pressure Emergency CoreCooling System Permissive Switch Out-of-Tolerance During
Surveillance Testing05000237/2006007-03NCVFailure to Post Protective Pathway Signs During Unavailabilityof Torus to Reactor Building Vacuum Breaker05000249/2006007-04NCVFailure to Perform Procedure Steps in the Proper Sequenceby Operations Caused Emergency Safety Feature Systems
Surveillance Testing05000237/2006007-03NCVFailure to Post Protective Pathway Signs During Unavailabilityof Torus to Reactor Building Vacuum Breaker05000249/2006007-04NCVFailure to Perform Procedure Steps in the Proper Sequenceby Operations Caused Emergency Safety Feature Systems
Actuation05000237/2006007-05FINUnit 2 High Pressure Coolant Injection (HPCI) SystemDeclared Inoperable05000237/2006007-06NCVStandby Liquid Control Valves Installed In The Plant05000249/2006007-06Different than those Assumed in a Design Calculation
Actuation05000237/2006007-05FINUnit 2 High Pressure Coolant Injection (HPCI) SystemDeclared Inoperable05000237/2006007-06NCVStandby Liquid Control Valves Installed In The Plant05000249/2006007-06Different than those Assumed in a Design Calculation  
Attachment305000237/97019-04URIConcrete Expansion Anchor Safety Factor for05000249/97019-04High Energy Line Break (HELB) Whip Restraints237/2006-002-00LERU2 Low Pressure Coolant Injection System DeclaredInoperableDiscussedNone
 
Attachment4
305000237/97019-04URIConcrete Expansion Anchor Safety Factor for05000249/97019-04High Energy Line Break (HELB) Whip Restraints237/2006-002-00LERU2 Low Pressure Coolant Injection System DeclaredInoperableDiscussedNone  
 
4
==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.
Line 389: Line 410:
-DOS 1500-20; Unit 2(3) CCSW Pump Vault Penetration Surveillance Testing-DOS 1500-21; Unit 2(3) CCSW Pump Vault Watertight Door Leak Test1R11Licensed Operator Requalification-Dresden Station, Units 2 and 3 NRC Integrated Inspection Reports; dated various fromJuly 28, 2004, through May 8, 2006
-DOS 1500-20; Unit 2(3) CCSW Pump Vault Penetration Surveillance Testing-DOS 1500-21; Unit 2(3) CCSW Pump Vault Watertight Door Leak Test1R11Licensed Operator Requalification-Dresden Station, Units 2 and 3 NRC Integrated Inspection Reports; dated various fromJuly 28, 2004, through May 8, 2006
-TQ-AA-106; Licensed Operator Requal Training Program; Revision 7
-TQ-AA-106; Licensed Operator Requal Training Program; Revision 7
-TQ-AA-210-5101; Training Observation Forms; dated various Attachment5-TQ-AA-301; Simulator Configuration Management; Revision 6-TQ-AA-301-0301; Simulator SWR Prioritization, Maintenance, Modification, and Enhancements; Revision 2
-TQ-AA-210-5101; Training Observation Forms; dated various  
: 5-TQ-AA-301; Simulator Configuration Management; Revision 6-TQ-AA-301-0301; Simulator SWR Prioritization, Maintenance, Modification, and Enhancements; Revision 2
-Curriculum Review Committee Meeting Minutes; dated various August 2004 through January 2006
-Curriculum Review Committee Meeting Minutes; dated various August 2004 through January 2006
-Training Advisory Committee Meeting Minutes; dated various June 2004 through February 2006
-Training Advisory Committee Meeting Minutes; dated various June 2004 through February 2006
Line 423: Line 445:
-IR
-IR
: 00491450; NRC Identified Procedure Issue; dated May 18, 2006-IR
: 00491450; NRC Identified Procedure Issue; dated May 18, 2006-IR
: 00491455; NRC Identified - Simulator Testing Enhancements; dated May 18, 2006-Issue Reports Initiated Based on NRC Observations1R12Maintenance Effectiveness -IR
: 00491455; NRC Identified - Simulator Testing Enhancements; dated May 18, 2006-Issue Reports Initiated Based on NRC Observations1R12Maintenance Effectiveness
-IR
: 00473392; LPCI Maint Rule Function Z15-4 Availability Criteria Not Met; 3/31/06-First Quarter 2006 LPCI Maintenance Rule Evaluation dated April 4, 2006, covering criteriaZ15-4, Z15-5 and Z15-6.
: 00473392; LPCI Maint Rule Function Z15-4 Availability Criteria Not Met; 3/31/06-First Quarter 2006 LPCI Maintenance Rule Evaluation dated April 4, 2006, covering criteriaZ15-4, Z15-5 and Z15-6.
-IR
-IR
Line 431: Line 454:
-IR
-IR
: 00368361; EQ Switches Not Torqued During 34Y Replacement; 8/30/05  
: 00368361; EQ Switches Not Torqued During 34Y Replacement; 8/30/05  
: Attachment61R13Maintenance Risk Assessments and Emergent Work Control-DOP 0500-03, Revision 29, Reactor Protection System Power Supply Operation1R14Personnel Performance Related to Non-routine Evolutions and Events-IR
: 61R13Maintenance Risk Assessments and Emergent Work Control-DOP 0500-03, Revision 29, Reactor Protection System Power Supply Operation1R14Personnel Performance Related to Non-routine Evolutions and Events-IR
: 00475365; Rx Bldg Vent System Tripped and 2/3B SBGT Train Auto Started; April 5, 2006-Apparent Cause Evaluation 4753651R15Operability Evaluations -RSA-D-92-06, HPCI Room Thermal Response with Loss of HPCI Room Cooler, datedNovember 13, 1992
: 00475365; Rx Bldg Vent System Tripped and 2/3B SBGT Train Auto Started; April 5, 2006-Apparent Cause Evaluation 4753651R15Operability Evaluations
-CHRON #200889, Dresden Station Units 2 and 3, EQ Applicability Determination andEvaluation of Components Located in EQ Zones 4, 5 and 6 EQ Evaluation Transmittal12-93-0084OA2Identification and Resolution of Problems -IR
-RSA-D-92-06, HPCI Room Thermal Response with Loss of HPCI Room Cooler, datedNovember 13, 1992
-CHRON #200889, Dresden Station Units 2 and 3, EQ Applicability Determination andEvaluation of Components Located in EQ Zones 4, 5 and 6 EQ Evaluation Transmittal12-93-0084OA2Identification and Resolution of Problems
-IR
: 00316625; U2 Reactor, Group 1 Isolation and Scram; March 24, 2005 -IR
: 00316625; U2 Reactor, Group 1 Isolation and Scram; March 24, 2005 -IR
: 00317029; NOS ID'D EHC Scram Troubleshooting Discrepancies; March 25, 2005-IR
: 00317029; NOS ID'D EHC Scram Troubleshooting Discrepancies; March 25, 2005-IR
Line 450: Line 475:
-IR
-IR
: 00439891; ERO pager test of 2/9/06 had 4 on-duty persons not respond; February 28, 2006  
: 00439891; ERO pager test of 2/9/06 had 4 on-duty persons not respond; February 28, 2006  
: Attachment7
: 7
==LIST OF ACRONYMS==
==LIST OF ACRONYMS==
: [[USEDAD]] [[]]
USEDADAMSAgencywide Documents Access and Management SystemARMArea Radiation Monitor
AMSAgencywide Documents Access and Management SystemARMArea Radiation Monitor
Aux NSOAuxiliary Nuclear Station Operator
Aux
CEAConcrete Expansion Anchor
: [[NS]] [[]]
CFRCode of Federal Regulations
: [[OA]] [[uxiliary Nuclear Station Operator]]
CRCondition Report
: [[CE]] [[]]
DFPPDresden Fire Protection Reports
: [[AC]] [[oncrete Expansion Anchor]]
DISDresden Instrument SurveillanceDOPDresden operating Procedure
: [[CF]] [[]]
DOSDresden Operating Surveillance DRPDivision of Reactor Projects
RCode of Federal Regulations
DRSDivision of Reactor Safety
: [[CRC]] [[ondition Report]]
EDGEmergency Diesel Generator
: [[DFP]] [[]]
EHCElectro Hydraulic Control
: [[PD]] [[resden Fire Protection Reports]]
EPEmergency Preparedness
: [[DISD]] [[resden Instrument Surveillance]]
EPRIElectrical Power Research Institute
: [[DOPD]] [[resden operating Procedure]]
EOPEmergency Operating Procedures
: [[DOSD]] [[resden Operating Surveillance]]
: [[DRPD]] [[ivision of Reactor Projects]]
: [[DR]] [[]]
: [[SD]] [[ivision of Reactor Safety]]
: [[ED]] [[]]
: [[GE]] [[mergency Diesel Generator]]
: [[EH]] [[]]
CElectro Hydraulic Control
: [[EPE]] [[mergency Preparedness]]
: [[EPR]] [[]]
: [[IE]] [[lectrical Power Research Institute]]
: [[EO]] [[]]
PEmergency Operating Procedures
gpmgallons per minute
gpmgallons per minute
: [[HEL]] [[]]
HELBHigh Energy Line Break
: [[BH]] [[igh Energy Line Break]]
HERHELB Pipe Whip Restraints
: [[HERHE]] [[]]
HPCIHigh Pressure Coolant Injection
: [[LB]] [[Pipe Whip Restraints]]
HVACHeating, Ventilating and Air-Conditioning
: [[HPC]] [[]]
IEMAIllinois Emergency Management Agency
: [[IH]] [[igh Pressure Coolant Injection]]
IFIInspection Followup Item
: [[HVA]] [[]]
IMCInspection Manual Chapter
: [[CH]] [[eating, Ventilating and Air-Conditioning]]
IRInspection / Issue Report
: [[IEM]] [[]]
ISTInservice Test
: [[AI]] [[llinois Emergency Management Agency]]
JPMJob Performance Measure
: [[IF]] [[]]
LORTLicense Operator Requalification Training
: [[II]] [[nspection Followup Item]]
LPCILow Pressure Coolant Injection
: [[IM]] [[]]
CInspection Manual Chapter
: [[IRI]] [[nspection / Issue Report]]
: [[IS]] [[]]
: [[TI]] [[nservice Test]]
: [[JP]] [[]]
: [[MJ]] [[ob Performance Measure]]
: [[LOR]] [[]]
: [[TL]] [[icense Operator Requalification Training]]
: [[LPC]] [[]]
ILow Pressure Coolant Injection
MCCmotor control center
MCCmotor control center
: [[MG]] [[motor generator]]
MGmotor generator
: [[MO]] [[]]
MOVMotor Operated Valve
VMotor Operated Valve
MWemegawatts electrical
: [[MW]] [[emegawatts electrical]]
NCVNon-Cited Violation
: [[NC]] [[]]
NFPANational Fire Protection Association
: [[VN]] [[on-Cited Violation]]
NOSNuclear Oversight
: [[NFP]] [[]]
NUREGNuclear Regulatory GuideNRCNuclear Regulatory Commission
: [[AN]] [[ational Fire Protection Association]]
NRROffice of Nuclear Reactor Regulation
: [[NO]] [[]]
PARSPublicly Available Records
: [[SN]] [[uclear Oversight]]
PIPerformance Indicator
: [[NUREGN]] [[uclear Regulatory Guide]]
PODMPlan of the Day Meeting
: [[NRCN]] [[uclear Regulatory Commission]]
RCICReactor Core Isolation Cooling
: [[NR]] [[]]
RFPReactor Feed Pump
: [[RO]] [[ffice of Nuclear Reactor Regulation]]
RHRResidual Heat Removal
: [[PAR]] [[]]
RPSReactor Protection System
SPublicly Available Records
SATSystems Approach to Training  
: [[PIP]] [[erformance Indicator]]
 
: [[POD]] [[]]
8SBLCStandby Liquid ControlSDPSignificance Determination Process
: [[MP]] [[lan of the Day Meeting]]
SFSafety Factor
: [[RCI]] [[]]
SROSenior Reactor Operator
: [[CR]] [[eactor Core Isolation Cooling]]
SWService Water
: [[RF]] [[]]
TIATask Interface Agreement
: [[PR]] [[eactor Feed Pump]]
TSTechnical Specification
: [[RH]] [[]]
UFSARUpdated Final Safety Analysis Report
: [[RR]] [[esidual Heat Removal]]
: [[RP]] [[]]
: [[SR]] [[eactor Protection System]]
: [[SA]] [[]]
TSystems Approach to Training
Attachment8SBLCStandby Liquid ControlSDPSignificance Determination Process
: [[SFS]] [[afety Factor]]
: [[SR]] [[]]
OSenior Reactor Operator
: [[SWS]] [[ervice Water]]
: [[TI]] [[]]
ATask Interface Agreement
: [[TST]] [[echnical Specification]]
: [[UFSA]] [[]]
RUpdated Final Safety Analysis Report
USUnit Supervisor
USUnit Supervisor
: [[WOW]] [[ork Order]]
: [[WOW]] [[ork Order]]
}}
}}

Revision as of 18:55, 26 October 2018

IR 05000237-06-007; 05000249-06-007 on 04/01/2006 - 06/30/2006; Exelon Generation Co., LLC; Dresden Nuclear Power Station, Units 2 and 3; Fire Protection, Maintenance Effectiveness, Maintenance Risk Assessments and Emergent Work Control, Pe
ML062150068
Person / Time
Site: Dresden  Constellation icon.png
Issue date: 07/31/2006
From: Ring M A
NRC/RGN-III/DRP/RPB1
To: Crane C M
Exelon Generation Co, Exelon Nuclear
References
IR-06-007
Download: ML062150068 (47)
v • d • e


Text

July 31, 2006

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

SUBJECT: DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3NRC INTEGRATED INSPECTION REPORT 05000237/2006007; 05000249/2006007

Dear Mr. Crane:

On June 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspectionat your Dresden Nuclear Power Station, Units 2 and 3. The enclosed integrated inspectionreport documents the inspection findings, which were discussed on July 18, 2006, with Mr. D. Wozniak 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. Based on the results of this inspection, four NRC-identified and two self-revealed findings ofvery low safety significance, five of which involved violations of NRC requirements wereidentified. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these violations as non-citedviolations (NCVs) consistent with Section VI.A.1. of the NRC Enforcement Policy. If you contest these NCVs, you should provide a response within 30 days of the date of thisinspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001;

and the NRC Resident Inspector at the Dresden Nuclear Power Station.

C. Crane-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of thisletter and its enclosure will be available electronically for public inspection in the NRCPublic Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/Mark A. Ring, ChiefBranch 1 Division of Reactor ProjectsDocket Nos. 50-237; 50-249License Nos. DPR-19; DPR-25

Enclosure:

Inspection Report 05000237/2006007; 05000249/2006007

w/Attachment:

Supplemental Informationcc w/encl:Site Vice President - Dresden Nuclear Power StationDresden Nuclear Power Station Plant Manager Regulatory Assurance Manager - Dresden Chief Operating Officer Senior Vice President - Nuclear Services Senior Vice President - Mid-West Regional Operating Group Vice President - Mid-West Operations Support Vice President - Licensing and Regulatory Affairs Director Licensing - Mid-West Regional Operating Group Manager Licensing - Dresden and Quad Cities Senior Counsel, Nuclear, Mid-West Regional Operating Group Document Control Desk - Licensing Assistant Attorney General Illinois Emergency Management Agency State Liaison Officer Chairman, Illinois Commerce Commission

SUMMARY OF FINDINGS

IR 05000237/2006007; 05000249/2006007; 04/01/2006 - 06/30/2006; Exelon GenerationCompany, Dresden Nuclear Power Station, Units 2 and 3; fire protection, maintenanceeffectiveness, maintenance risk assessments and emergent work control, personnel performance related to non-routine evolutions and events, and operability evaluations.This report covers a 3-month period of baseline resident inspection and an announced baselineinspection in Licensed Operator Requalification Program. The inspection was conducted by Region III inspectors and the resident inspectors. Six Green findings, involving five non-citedviolations, were identified. 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. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors is described in NUREG-1649, "ReactorOversight Process," Revision 3, dated July 2000.A.

NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green.

On May 1, 2006, the inspectors identified a non-cited violation of Unit 2Operating License Condition E, Fire Protection Program, for failure to identify and correct a degraded fire barrier wall. The inspectors identified a wall gap in the Unit 2 emergency diesel generator day tank room. The gap was in a 3-hour fire rated wall, separating the Unit 2 diesel fuel oil day tank room from the Unit 2 reactor feed pump room. As corrective action, the licensee established a firewatch, entered the issue into the corrective action program, and repaired the gap in the wall. The finding was greater than minor because it affected the protection against externalfactors attribute of the Mitigating Systems cornerstone objective. However, the finding was of very low safety significance due to no credible fire scenarios developing that would have affected the safe shutdown of Unit 2, and due to the relatively negligible combustible loading in the area of the gap. The inspectors also concluded that this finding affected the cross-cutting issue of human performance (personnel).

(Section 1R05)

Green.

On May 15, 2006, a finding involving a non-cited violation of 10 CFR 50,Appendix B, Criterion XVI, was identified by the inspectors. The licensee failed to identify a condition adverse to quality where the Unit 2 350 psig reactor low pressure emergency core cooling system (ECCS) permissive pressure switch was found outsidethe Technical Specification (TS) allowable tolerance range repeatedly. The licensee's actions lacked prioritization in determining the cause of the out-of-tolerance of the 2-0263-52B permissive pressure switch. Also, the licensee failed to assign timely corrective actions to evaluate the cause of the switch's repeated TS surveillance testfailures.

3The finding was greater than minor because it impacted the equipment performanceattribute of the Mitigating System cornerstone objective to ensure availability, reliability,and capability of systems that respond to initiating events. As corrective action, thelicensee created action items to address the repeat failures of the 2-0263-52B switch to meet its TS requirements. The licensee wrote Issue Report (IR) 495327, "Trending IR for 2-0263-52B exceeds TS 6 of 9 Surveillances," to identify why this adverse trend wasnot entered into the corrective action system. As immediate corrective action, thelicensee reduced the surveillance frequency to adequately monitor the switch'sperformance. The licensee also required all system managers and first line supervisorsto review the station procedure for the instrument performance trending program, and implemented a manufacturer's recommendation to use smaller step changes in applied pressure to improve set point accuracy. The finding was of very low safety significance because the other permissive switch 2-0263-52A was always operable. Therefore, the switch's safety function and ability to permit reactor low pressure ECCS injection weremaintained. The primary cause of this finding was related to the cross-cutting issue of problem identification and resolution (corrective action). (Section 1R12)*Green. A finding was self-revealed when an instrument maintenance technician shorteda power lead while performing modification work that resulted in the Unit 2 high pressure coolant injecti on system becoming inoperable for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 14 minutes onApril 6, 2006. No violation of NRC requirements was identified.This finding was more than minor because it involved the attribute of equipmentperformance of the Mitigating Systems objective of ensuring the capability of systemsthat respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because the high pressure coolant injection system was inoperable for a short time period and could have been manually controlled in the event of an accident. The individual was counseled for a lack of attention to detail and the entire instrument maintenance department was made aware of this error. This finding affected the cross-cutting issue of human performance (personnel). (Section 1R14)*Green. On May 5, 2006, the inspectors identified a finding involving a non-citedviolation of 10 CFR 50.62 associated with a licensee-identified material condition, and having very low safety significance. The licensee identified that the inputs to a design analysis (DRE01-0066, "Dresden Unit 2 & 3 Standby Liquid Control System Discharge Piping Pressure Drop," Revision 1) were non-conservative. Some of the valves installed in the plant were not the same type of valves assumed to be installed in the design analysis. This ultimately resulted in a change in a design calculation that demonstrated that standby liquid control system relief valves could lif t upon system initiation during ananticipated transient without scram (ATWS) event.The finding was more than minor because it affected the design control attribute of theMitigating Systems objective of ensuring the capability of systems that res pond toinitiating events to prevent undesirable consequences. The finding was of very low safety significance because the standby liquid control system could be recovered duringan ATWS event. Cycling of the relief valves would not prevent most of the borated solution from being injected into the reactor pressure vessel, and the licensee was able to demonstrate that the reactor remained within the acceptance criteria of their originalATWS analysis even if no boron solution was injected into the reactor pressure vessel 4while the relief valves lifted. The licensee planned to use a more enriched form of boronso that one pump could be used to meet the 10 CFR 50.62 requirements. This enrichedboron would replace the current boron in the storage tanks in the next refueling outages. This issue was a non-cited violation of 10 CFR 50.62. (Section 1R15)

Cornerstone: Barrier Integrity

Green.

On May 15, 2006, the inspectors identified a non-cited violation 10 CFR 50.65(a) (4), having very low safety significance associated with inadequate management of risk. While working on the Unit 2 1601-20B reactor building to torus vacuum breaker relief valve, the Unit 2 risk status was designated as "yellow" and would have gone to "red" if the 2-1601-20A valve was also taken out-of-service. The 2-1601-20A vacuum relief valve was not clearly indicated as a protected pathway as required by station workcontrol procedures and station personnel were not notified of the 2-1601-20B "yellow" risk status through any of the normal administrative methods.This finding was more than minor because this issue, if left uncorrected, could havebecome a more significant safety concern. Had the availability of the 2-1601-20A valvebeen affected, plant risk would have been elevated to a "red" condition. The plant risk model did not show that this equipment was required to have a protected pathway onthe redundant equipment. In addition, during the extent of condition review, the licenseeidentified that six additional pieces of plant equipment should have indicated therequirement for protected pathways, but did not. The licensee corrected both theseconditions. The inspectors evaluated this finding using IMC 0609, "Significance Determination Process," and concluded the issue was of very low safety significance (Green) because no actual degradation of the barriers occurred. This finding affected the cross-cutting issue of human performance (resources). (Section 1R13)*Green. On April 5, 2006, a performance deficiency involving a non-cited violation ofTS 5.4.1 was self revealed when an auxiliary nuclear station operator (Aux NSO) and aunit supervisor (US) were performing Dresden Operating Procedure (DOP) 0500-03,

"Reactor Protection System Power Supply Operation," Revision 27. The Aux NSO and US did not verify that the area radiation monitor's (ARM) power supply voltage was normal and did not reset all trips on the ARM modules prior to removing an installed jumper which bypassed the trips. This required entry into TS 3.6.4.1 Limiting Condition of Operation, Action A for reactor building low differential pressure. Both operators had been provided with marked up copies of the procedure, and briefed on jumper placement and removal and on the use of concurrent verification prior to the event.The finding was greater than minor because it impacted the structures, systems, andcomponents attribute of the Barrier Integrity cornerstone objective. The finding was of very low safety significance because it impacted the reactor building differential pressure for a time period of less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. As an immediate corrective action, the two individuals were temporarily removed from licensed shift duties. The operations department was tasked to develop a dynamic learning activity for place-keeping and jumper manipulation for all operations personnel, and to create an internal operating experience document to communicate lessons learned. This finding affected the cross-cutting area of human performance (personnel). (Section 1R14)

5

B.Licensee-Identified Violations

No findings of significance were identified.

6

REPORT DETAILS

Summary of Plant StatusUnit 2 began the inspection period at 912 MWe (95 percent thermal power and 100 percent ofrated electrical capacity).*On May 27, 2006, power was reduced to 15 percent to perform a walkdown of the drywell toidentify the source of a leak, to perform turbine valve testing, and to make a control rod pattern adjustment. The unit was returned to full power the next day.*On June 8, 2006, power was reduced to 71 percent to replace the 2A feedwater regulatingvalve solenoid due to erratic operation. The unit was returned to full power the same day.Unit 3 began the inspection period at 912 MWe (95 percent thermal power and 100 percent ofrated electrical capacity). *On June 4, 2006, power was reduced to 57 percent to perform turbine valve testing, controlrod drive scram time testing, and to make a control rod pattern adjustment. The unit was returned to full power on the same day.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather (71111.01)a. Inspection ScopeThe inspectors assessed the licensee's readiness for warm weather conditions during thetime period of May 2006 and conducted inspections on the following equipment and systems:*Unit 3 containment cooling service water vault;*Unit 2 reactor building ventilation; and

  • Unit 2 and 3 auxiliary electric equipment room heating, ventilation and air conditioningThe inspectors selected the above inspection samples to ensure the equipment couldperform design functions during summer conditions. The inspectors reviewed the Updated Final Safety Analysis Report, the licensee's seasonal readiness procedure, previously initiated issue reports, and walked down equipm ent and systems to verify proper alignmentin accordance with the licensee procedures to remove plant equipment and systems usedfor cold weather operations from service at the end of cold weather season. This represented one inspection sample.

b. Findings

No findings of significance were identified.

71R04Equipment Alignment (71111.04Q)

a. Inspection Scope

The inspectors selected a redundant or backup system to an out-of-service or degradedtrain to determine that the system met the design of the Updated Final Safety AnalysisReport. Piping and instrumentation diagrams were used to determine correct system lineupand critical portions of the system configuration were verified. Instrumentation, valveconfigurations, and appropriate meter indications were also observed. The inspectors observed various support system parameters to determine the operational status ofsystems. Control room switch positions for the systems were observed. Other conditions,such as adequacy of housekeeping, the absence of ignition sources, and proper labeling were also evaluated.The inspectors performed partial equipment alignment walkdowns of the:

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05Q and A).1Routine Inspection

a. Inspection Scope

The inspectors toured plant areas important to safety to assess the material condition,operating lineup, and operational effectiveness of the fire protection system and features toensure compliance with the station's Fire Hazard Analysis Report. The review included control of transient combustibles and ignition sources, fire suppression systems, manual firefighting equipment and capability, passive fire protection features, including fire doors, andcompensatory measures. The following areas were walked down: *Unit 2 computer room and auxiliary electrical room, elevation 517' Fire Zone 6.2;*Unit 2 low pressure coolant injection east corner room, elevation 476' Fire Zone 11.2.2;

  • Unit 2 low pressure coolant injection west corner room, elevation 476'-6" FireZone 11.2.1;*Unit 2 station blackout diesel room, Fire Zone not applicable;
  • Unit 2 reactor feed pump, elevation 517' Fire Zone 8.2.5A; and 8*Unit 3 battery rooms, elevation 538' Fire Zone 6.1 and charger room, elevation 551' FireZone 7.0.B.This represented nine inspection samples.

b. Findings

Failure to Identify an Inoperable 3-hour Fire Barrier Wall in the Unit 2 Emergency DieselGenerator (EDG) Day Tank RoomIntroduction: The inspectors identified a non-cited violation (NCV) of Unit 2 OperatingLicense Condition E, having very low safety significance (Green). The NCV was related to the licensee's failure to identify and correct a degraded 3-hour fire barrier wall in the Unit 2 EDG day tank room. This fire barrier separated the Unit 2 diesel fuel oil day tank room from the Unit 2 reactor feed pump (RFP) room.

Description:

On May 1, 2006, while performing a fire protection walkdown of the Unit 2EDG room, the inspectors identified a through-wall gap in the west corner of the diesel fuel oil day tank room. Light from the Unit 2 RFP room could be seen through the wall. The inspectors determined that a through-wall gap existed in a fire barrier wall and reported this condition to the licensee. The gap was promptly evaluated and was judged to be about 1/32 inch wide and about 5 feet long. The inspectors were informed that this fire barrier separated the Unit 2 diesel fuel oil day tank room, Fire Zone 9.0.A, from the Unit 2 RFProom, Fire Zone 8.2.5.A. Upon confirmation of the inspectors' concern, the licenseedeclared the carbon dioxide (CO 2) system for the Unit 2 EDG day tank room inoperable. The fuel oil day tank west wall was also considered to be inoperable as a 3-hour fire barrier. The licensee immediately implemented the appropriate technical requirement manuallimiting condition for operation actions by establishing an hourly fire watch, and entered the deficiency into the corrective action program as issue report IR 485432. The licensee's engineering evaluation stated that this gap is speculated to have formed when the wall waspoured during original construction when a seal did not form between the concrete and the steel beam. Licensee personnel completed a permanent repair of the fire barrier wall gap per work order WO 917879.The gap had not been identified by the licensee because the existing surveillancerequirement was not properly performed. Station procedure DFPS 4175-02, "Operating FireStop/Break Surveillance," Revision 12,Section I.1.d, stated, in part, "besides the listedpenetrations, the entire surface of the fire rated assembly shall be inspected for open penetrations or breaks of any kind." This surveillance was last completed for the Unit 2emergency diesel fuel oil tank room wall on January 11, 2005. The inspectors interviewed the individual that performed the inspection, and the individual acknowledged that the entiresurface of the barrier had not been inspected.Analysis: The inoperable fire barrier wall represented a licensee performance deficiencybecause the gap in the 3-hour fire barrier wall would be expected to have been identified and corrected by the licensee using Fire Protection Surveillance (DFPS) Procedure 4175-2,"Operating Fire Stop/Break Surveillance," Revision 12. The affect of the identifieddeficiency was that since original construction a communication path existed between the 9two fire zones. The requirement to have fire barriers was to ensure that a postulated firewould not propagate to more than one fire area, thus jeopardizing the availability of safeshutdown equipment. Using Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," dated September 30, 2005, the finding was greater than minorbecause it affected the protection against external factors attribute of the Mitigating Systems cornerstone objective. The inspectors evaluated the finding using IMC 0609, Appendix F, "Fire ProtectionSignificance Determination Process (SDP)," dated February 28, 2005, Attachment 2, Table A2.1, and concluded that the finding affected the defense-in-depth element of firebarrier degradation in the fire confinement category. Based on the gap being about 1/32 inch wide and 5 feet long through a 3-hour barrier wall, the degradation level was categorized as low "Green." Factors which contributed to this classification included the following: a credible firescenario could not be developed that would have affected the safe shutdown of Unit 2 because both zones were in the same fire area. The Unit 2 EDG oil day tank room had a negligible amount of combustibles. The fuel oil was excluded from the combustible loading because it was located within an National Fire Protection Association qualified tank and which is assumed not to rupture. The inspectors considered in their evaluation the lack of electrical cables in the area of the gap, the fact that the Unit 2 fuel oil day tank room isprotected by both an automatic CO 2 suppression and an automatic wet pipe sprinklersystem, the relatively small transient combustible loading in the area of the gap from theUnit 2 RFP side, and the fact that the Unit 2 RFP area is protected by an automatic wet pipesprinkler system.The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (personnel) because the licensee failed to accomplish activities in accordance with prescribed instructions in a station procedure. Specifically, a surveillance test wasperformed on this wall in January 2005 and the gap was not found because the entire surface of the wall was not inspected in accordance with station procedure DFPS 4175-02.Enforcement: Operating License Condition No DPR-19, Section E, requires that thelicensee shall implement and maintain in effect all provisions of the approved Fire Protection Program, as described in the Updated Final Safety Analysis Report (UFSAR).The UFSAR, Section 9.5.1, "Fire Protection System," states, in part, that the design bases and system descriptions are described in the Dresden Fire Protection Report (DFPR),Volume 1, "Updated Fire Hazards

Analysis.

" The DFPR, Section 2.3.1.2, "Barriers," states, in part, that walls enclosing separate fireareas utilize fire resistive construction. All penetrations in a fire resistive barrier areprotected so that they have an equivalent fire resistance rating or are evaluated to ensuretheir adequacy to withstand the hazards associated with the areas. Drawing F-10-1, Revision F, located in the DFPR, Volume 1, "Updated Fire HazardsAnalysis," describes the west wall of the Unit 2 EDG day tank room as a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> fire barrier.

10The UFSAR Section 13.5.3.3, "Fire Protection Surveillance" (DFPS), also states, in part,that fire protection surveillances provide for verification of operability or performancecharacteristics of systems/equipment. Fire protection surveillance procedure DFPS 4175-02, "Operating Fire Stop/BreakSurveillance," Revision 12,Section I.1.d, stated, in part, "besides the listed penetrations, theentire surface of the fire rated assembly shall be inspected for open penetrations or breaks of any kind." This surveillance was last completed in January 2005.Contrary to the above, on May 1, 2006, the inspectors identified a breach in the wallsections that make up the 3-hour fire barrier in the Unit 2 EDG day tank room. This breach did not have an equivalent fire resistance rating and was not evaluated to ensure the adequacy to withstand the hazards associated with the area. The wall gap represented adegradation of a defense-in-depth fire protection element and compromised the 3-hour fire barrier separation requirements. However, because the finding is of very low safety significance and has been entered into the licensee's corrective action program, IR 485432, this violation is being treated as an NCV, consistent with Section VI.A of the NRCEnforcement Policy. (NCV 05000237/2006007-01).2Fire Drill (Annual)

a. Inspection Scope

On June 13, 2006, the inspectors observed the licensee's fire brigade participate in anunannounced fire drill. The drill scenario consisted of a fire in the Unit 1 craft building. Upon hearing the fire alarm, the inspectors observed the fire brigade members don their protective equipment to ensure that the brigade members were appropriately protected fromthe fire. The inspectors also observed the actions performed by and communications provided by the fire brigade leader to ensure that the leader demonstrated adequatecommand and control responsibilities, performed a proper size-up of the fire, selected theproper fire attack strategies, recognized the need for offsite assistance, and communicated with the control room. Lastly, the inspectors observed the fire brigade members during the fire attack to evaluate the appropriateness of their actions. This represented one inspection sample.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (71111.06)1.Internal Flooding

a. Inspection Scope

The inspectors performed a review of the following:

11The inspections focused on verifying that flooding mitigation plans and equipment weremaintained as required and that the plans were consistent with design requirements. The inspection activities included, but were not limited to, visually inspecting the containment cooling service water pump vault watertight door seals, other penetration seals for pipes, and cables and the floor drains within the room. In addition, the inspectors reviewed the results of flooding related equipment surveillance tests to ensure that acceptance criteriawere met, and reviewed the flooding and surveillance procedures for technical adequacy. This represented one inspection sample.b.FindingsNo findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11Q)

a. Inspection Scope

The inspectors observed an evaluation of a Senior Reactor Operator (SRO) onMay 26, 2006, during the annual requalification exam. The SRO performed job performance measures (JPMs). The JPMs consisted of the isolation of the 250 VDC turbine building MCC 2 due to the MCC being damaged, and lining up reactor head cooling for alternate water injection. The inspectors verified that the SRO was able to complete the tasks in accordance with applicable plant procedures and that the success criteria asestablished in the job performance measures were satisfied. The inspectors observed the licensee's evaluators to ensure that no inappropriate cues were provided by the evaluators while assessing the operators' performance. This represented one inspection sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11B).1Facility Operating History

a. Inspection Scope

The inspectors reviewed the plant's operating history from April 2004 through April 2006 toidentify operating experience that was expected to be addressed by the Licensed OperatorRequalification Training (LORT) program. It was then verified that the identified operatingexperience had been addressed by the facility licensee in accordance with the station'sapproved Systems Approach to Training (SAT) program to satisfy the requirements of 10 CFR 55.59 (c), "Requalification program requirements."

b. Findings

No findings of significance were identified..2Licensee 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 (c)(4), "Evaluation." The operating examination materialreviewed consisted of three operating tests, each containing two dynamic simulator scenarios and six JPMs. The written examinations reviewed consisted of six written examinations, each containing 37 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 May/June 2005. The inspectors reviewed the methodology for developing the examinations, including the LORT program 2-yearsample plan, probabilistic risk assessment insights, previously identified operatorperformance deficiencies, and plant modifications.

b. Findings

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

a. Inspection Scope

The inspectors observed the administration of a requalification operating test to assess thelicensee's effectiveness in conducting the test to ensure compliance with 10 CFR 55.59 (c)(4), "Evaluation." The inspectors evaluated the performance of two crews in parallel with the facility evaluators during four dynamic simulator scenarios and evaluated variouslicensed 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 simulatorperformance was conducted and documented under Section 1R11.8, "Conformance With Simulator Requirements Specified in 10 CFR 55.46," of this report.

b. Findings

No findings of significance were identified.

13.4Examination 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, anycorrective 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.

Two specific corrective action reports, IR 334912 and IR 487168, were reviewed.

b. Findings

No findings of significance were identified..5Licensee 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 theeffectiveness of its LORT program and their ability to implement appropriate correctiveactions. This evaluation was performed to verify compliance with 10 CFR 55.59 (c),

"Requalification program requirements," and the licensee's SAT program.

b. Findings

No findings of significance were identified..6Licensee 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 training from the current examination cycle to ensure that they addressed weaknesses in licensed operatoror crew performance identified during training and plant operations. The inspectors reviewed remedial training procedures and individual remedial training plans. This evaluation was performed in accordance with 10 CFR 55.59 (c), "Requalification program requirements," and with respect to the licensee's SAT program.

b. Findings

No findings of significance were identified.

14.7Conformance With Operator License Conditions

a. Inspection Scope

The inspectors reviewed the facility and individual operator licensees' conformance with therequirements of 10 CFR Part 55. The inspectors reviewed the facility licensee's program formaintaining 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 facilitylicensee's LORT program to assess compliance with the requalification program requirements as described by 10 CFR 55.59 (c). Additionally, medical records for ten licensed operators were reviewed for compliance with 10 CFR 55.53 (I).

b. Findings

No findings of significance were identified..8Conformance With Simulator Requirements Specified in 10 CFR 55.46

a. Inspection Scope

The inspectors assessed the adequacy of the licensee's simulation facility (simulator) foruse in operator licensing examinations and for satisfying experience requirements as prescribed in 10 CFR 55.46, "Simulation Facilities." The inspectors also reviewed a sampleof 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 theIP 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

(c) and (d).

b. Findings

No findings of significance were identified..9Annual Operating Test Results and Biennial Written Examination Results

a. Inspection Scope

The inspectors reviewed the pass/fail results of the individual biennial written testsadministered by the licensee during calender year 2005. The inspectors also reviewed the results for the operating and simulator tests (required to be given annually per 10 CFR 55.59 (a)(2)) administered by the licensee during calender years 2005 and 2006.

The overall written examination and operating test results were compared with the significance determination process in accordance with NRC Manual Chapter 0609, 15Appendix I, "Operator Requalification Human Performance Significance DeterminationProcess."

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12Q)

a. Inspection Scope

The inspectors assessed the implementation of the licensee's maintenance rule programto evaluate maintenance effectiveness for the selected systems in accordance with10 CFR 50.65, Maintenance Rule. The following systems were selected based on beingdesignated as risk significant under the Maintenance Rule, being in the increased monitoring (Maintenance Rule Category a(1)) group, or due to an inspector's identified issue or problem that potentially impacted system work practices, reliability, or common cause failures:*Unit 2/3 emergency diesel generator ventilation;*Unit 2 low pressure coolant injection system;

  • Unit 2 standby liquid control system; and*Unit 3 standby liquid control system.The inspectors verified the licensee's categorization of specific issues, including evaluationof the performance criteria, appropriate work practices, identification of common cause errors, extent of condition, and trending of key parameters. Additionally, the inspectors reviewed the licensee's implementation of the Maintenance Rule requirements, including areview of scoping, goal-setting, performance monitoring, short-term and long-term corrective actions, functional failure determinations associated with the condition and issue reports reviewed, and current equipment performance status.This represented five inspection samples.

b. Findings

Unit 2 350 psig Reactor Low Pressure Emergency Core Cooling System Permissive SwitchOut-of-tolerance During Surveillance TestingIntroduction: A finding involving a non-cited violation of 10 CFR 50, Appendix B,Criterion XVI, was identified by the inspectors. The finding was associated with the licensee failure to identify an adverse trend in the performance of the 350 psig reactor low pressure emergency core cooling system (ECCS) permissive switch 2-0263-52B. The licensee failedto determine the cause of the repeated out-of-tolerance surveillance test results of the2-0263-52B switch in 2005 and 2006, until prompted by the inspectors.

Description:

During the performance of the Unit 2 quarterly Technical Specification (TS)surveillance test, DIS 1500-01, Revision 21, "Reactor Low Pressure 350 psig ECCS Permissive," on April 19, 2006, the licensee completed the calibration and functionally 16tested the performance of the Unit 2 ECCS low pressure permissive switches. Each unithas two low reactor ECCS permissive pressure switches designed to permit the initiation of the ECCS subsystems during an analyzed transient between a reactor pressure of 322.1and 355.3 psig. The result of the quarterly surveillance testing in April 2006 indicated thatthe 2-0263-52B ECCS permissive switch was out of TS allowable tolerance range at the low end. The licensee re-calibrated the pressure switch to within required TS tolerance and initiated IR 480479. The licensee's corrective action program review of this IR determined that the issue was not reportable.The inspectors reviewed previous surveillance test results and identified that betweenJanuary 2004 and April 2006 the Unit 2 350 psig permissive switch was found outside the TS allowable tolerance range several times. Specifically, in May 2004 during the quarterly surveillance test, the licensee identified that switch 2-0263-52B was out of the TS allowable tolerance range and that the indicator on the switch was found indicating about 45 psig with zero pressure applied. The switch was declared inoperable. The switch was immediately replaced under WO 98083028. The failure analysis report stated that there was evidence of internal mechanical problems, in that, the drive arm had slipped on the torque tube which could have accounted for the offset of the indicator at zero pressure and erratic setpoint adjustment. In July 2005, the 2-0263-52B switch exhibited similar problems, in that it was foundexceeding the TS required allowable tolerance range, and the indication pointer was reading 20 psig with zero input pressure. At that time, the licensee re-calibrated the switchback to within the TS allowable range tolerance, entered this deficiency into the corrective action program as IR 354804, but did not replace the switch. The licensee's preliminary review of IR 354804 concluded that the switch may have been out-of-tolerance from an event instead of normal drift, and therefore initiated a work request to replace the 2-0263-52B switch, and to perform a failure analysis. The switch failed its subsequent quarterly surveillance test again in October 2005, in that it was found to be outside the TSallowable tolerance range. However, 2-0263-52B was not replaced until it was once again found outside the TS allowable tolerance range in January 2006. The offsite failure analysis report, performed after the switch was replaced in January 2006, indicated an internal mechanical failure mode similar to the May 2004 event. The inspectors questioned the licensee's staff about the justification for not replacing asafety related pressure switch following the July 2005 surveillance test failure. The licenseedid not have a documented justification. The inspectors concluded that the surveillance testresults of the past 2 years indicated an adverse trend in the performance of the ECCS permissive switch 2-0263-52B. The inspectors noted that the licensee failed to identify and correct the repeated out of tolerance condition. As a result of the inspectors concerns, the licensee issued IR 495327 to determine the cause and corrective actions to address the programmatic issues that allowed the Unit 2 350 psig permissive switch to repeatedly fail to meet TS requirements without the issuance of an IR to identify the adverse trend. Thelicensee then determined that this issue was reportable based on historical review of dataand planned to initiate a Licensee Event Report.

Analysis:

The inspectors determined that the failure to identify a condition adverse toquality and have adequate corrective actions associated with repetitive failures of a safety related instrument was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was more than minor in accordance with IMC 0612, 17"Power Reactor Inspection Reports," Appendix B, "Issue Screening," issued onSeptember 30, 2005, because it impacted the equipment performance attribute of theMitigating System cornerstone objective to ensure availability, reliability, and capability ofsystems that respond to initiating events. The low reactor steam dome pressure signals areused as permissive for the low pressure ECCS subsystems to inject water into the reactor.

This ensures that, prior to opening the injection valves of the low pressure ECCS subsystems, the reactor pressure has fallen to a value below these subsystems' maximumdesign pressure. Therefore, the failure of the pressure switch could have a credible impact on safety. The inspectors completed a Phase 1 significance determination of this issue usingIMC 0609, "Significance Determination Process," Appendix A, Attachment 1, dated November 22, 2005. The inspectors concluded that the finding impacted the MitigatingSystems cornerstone. The inspectors answered "No" to all five questions under the Mitigating Systems cornerstone column, and the issue screened as having very low safety significance (Green) because the redundant switch PS 2-0263-52A passed all acceptance criteria, was operable all the time, and maintained the safety function. The primary cause of this finding was related to the cross-cutting issue of problemidentification and resolution (corrective action) because the repeated surveillance failures ofthe safety related switch were not promptly identified and corrected.

Enforcement:

Title 10 CFR, Part 50, Appendix B, Criterion XVI, "Corrective Actions,"requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to the above, the licensee failed to identify an adverse trend for the repeated out oftolerance condition associated with the 2-0263-52B pressure switch, a condition adverse to quality. During this period when the switch was repeatedly out of tolerance, the calibration interval of the switch was not changed to assure the switch's operating setpoint values stayed within the TS allowable tolerance range. After the inspectors questioned the lack of identification of a condition adverse to qualityand the untimely corrective actions, the licensee created an action item to review the cause of the event and create corrective actions. The licensee wrote Issue Report (IR) 495327, "Trending IR for 2-0263-52B exceeds TS 6 of 9 Surveillances." The purpose of this IR wasto identify why this adverse trend was not entered into the corrective action system. Asimmediate corrective action, the licensee reduced the surveillance frequency to adequatelymonitor the switch's performance. Also the licensee required all system managers and firstline supervisors to review the station procedure for the instrument performance trending program to ensure applicability and implementation, and initiated a training request forinstrument maintenance technicians to include a manufacturer's recommendation to use smaller step changes in applied pressure to improve set point accuracy. Because of the very low safety significance and because the issue is in the licensee's corrective action program IR 495327, it is being treated as a non-cited violation, consistent withSection VI.A.1 of the NRC Enforcement Policy. (NCV05000237/2006007-02)181R13Maintenance Risk Assessments and Emergent Work Control (71111.13).1Routine Inspections

a. Inspection Scope

The inspectors evaluated the implementation of the licensee's maintenance risk programwith respect to the effectiveness of the risk assessments performed before maintenance activities were conducted on structures, systems, and components and verified that thelicensee managed the risk in accordance with 10 CFR 50.65, "Maintenance Rule." The inspectors evaluated whether the licensee had taken the necessary steps to plan and control emergent work activities. The inspectors also verified that equipment necessary to complete planned contingency actions was staged and available. The inspectors completed evaluations of maintenance activities on the:*Unit 3 Division 1 low pressure coolant injection and containment cooling service waterpumps out-of-service for planned maintenance;*Unit 2 standby liquid control out-of-service for accumulator replacement, squib valve,and oil change;*Unit 3 high pressure coolant injecti on system out-of-service for planned maintenance;*Unit 2 reactor protection system bus swap to reserve power; and

b. Findings

No findings of significance were identified..2Failure to Post Protective Pathway Signs During Unavailability of Torus to Reactor BuildingVacuum Breaker

a. Inspection Scope

The inspectors reviewed risk assessment and controls for maintenance activities on theUnit 2 air operated 2-1601-20B vacuum breaker valve between the Unit 2 torus and the reactor building.

b. Findings

Introduction:

The inspectors identified a non-cited violation of 10 CFR 50.65 (a) (4),having very low safety significance (Green) associated with inadequate management of risk. While working on the Unit 2 1601-20B reactor building to torus vacuum breaker relief valve the Unit 2 risk status was designated as "yellow" and would have gone to "red" if the 2-1601-20A valve was also taken out-of-service. The 2-1601-20A vacuum relief valve was not clearly indicated as a protected pathway and station personnel were not notified of its'"yellow" risk status either through the pre-job brief, posted markings, Plan Of The Day meeting (POD), or POD meeting documentation.

19Description: On May 15, 2006, the inspectors toured the Unit 2 torus catwalk area asrepair work was being performed on the Unit 2 1601-20B reactor building to torus vacuum relief valve. Unit 2 was on-line at full power. The vacuum breakers relieve pressure to the torus to prevent exceeding the external torus pressure. The inspectors noticed that there were no protected pathway signs posted on or near the remainingvacuum breaker 2-1601-20A. Unit 2 was in a "yellow" risk condition from 11:06 a.m. to 12:22 p.m. on May 15, 2006, due to the unavailability of the 2-1601-20B valve and wouldhave gone to red risk if the 2-1601-20A valve had been made unavailable. There was no mention in the POD meeting on May 15, 2006, of Unit 2 being in a"yellow" risk condition for the Unit 2 1601-20B valve work or that the 2-1601-20A valve was a protected pathway. Additionally, neither was the risk condition documented in the plant status sheet for the day or in the schedule review sheet for the day as being "yellow,"nor was 2-1601-20A listed as a protected pathway. The inspectors reviewed procedure, MA-AA-743-310, "Diagnostic Testing And Evaluation Of Air Operated Valves," Revision 4, and WO 99213710-01, and discovered that the pre-job briefing checklist designated protected pathways and equipment as not applicable (NA).The inspectors reviewed procedure, WC-AA-101, "On-Line Work Control Process,"Revision 12. In Attachment 3, this procedure ranked the four configuration risk conditions:

green, yellow, orange, and red. Green is the least configuration risk and red is the worst or discussed as an unacceptable risk condition. Green is optimal defense in depth or no appreciable increase in initiating event frequency or decrease in mitigation capability. Yellow is nominal defense in depth. Orange is marginal defense in depth or significant increase in initiating event frequency or decrease in mitigation capability. Red isunacceptable defense in depth or unacceptable increase in initiating event frequency or decrease in mitigation capability.The inspectors discussed their concern with a lack of a protected pathway for the2-1601-20A valve with the licensee on May 15, 2006. The licensee documented the issuein IR 490307 the same day. The licensee concluded that the vacuum breaker valves were not, but should have been, on the Paragon Model "remain-in-service list" for protected pathway per ER-AA-600-1042, "On- Line Risk Management," Revision 4.Based on the inspectors' finding, the licensee performed an extent of condition by reviewingthe Paragon Model component list to identify any other components that should be on theprotected pathway remain-in-service list. The review looked for items that could cause the configuration risk to change from "yellow" to "orange" or "red" if the protected pathway component was also taken out-of-service. The licensee performed a thorough review and found six other Unit 2 components that could cause the on-line risk to go from "yellow" to "orange" or "red" due to components being taken out-of-service for surveillance testing orfor components that are normally repaired or replaced during an outage but may be repaired or replaced while on-line. Four components were identified for the risk configuration heat removal function and included containment cooling service water discharge valves 2A and 2B and torus cooling trains 2A and 2B. Two other components were identified for the reactivity control function and included ATWS RPT Trip Logic A and Trip Logic B. These components were documented in IR 490307. The same components for Unit 3 were also not on the remain-in-service list and should have been to prevent the risk from becoming "orange" or "red" if the protected pathway component was taken out-of-service.

20Analysis: The inspectors concluded that the failure to identify and protect redundant riskimportant equipment was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," Appendix B, "

Issue Screening," issued on September 30, 2005. Failure to notify plant personnel of risk conditions that are "yellow" and that could change to "red" or "orange" if the redundant component is taken out-of-service could become a more significant safety concern if left uncorrected. This deficiency in the protected pathway program could affect the availability and capability of com ponents and systems that respond to initiating events. Failure to beaware of all the components and systems that could cause an elevated "orange" or "red"risk condition increases the probability that the mitigating systems or components will betaken out-of-service and that they would not be able to respond as designed to an initiating event or accident condition.The inspectors completed a Phase 1 "Significance Determination Process," of IMC 0609Appendix A, Attachment 1, dated November 22, 2005. The inspectors determined that thisfinding impacted the Barrier Integrity cornerstone column. The inspectors answered "No" to all three questions under the Barrier Integrity column on page A1-9 because no actual barrier failure occurred. Therefore, the issue screened out as having very low significance (Green).The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (resources) because the procedure did not list this component as requiring a protected pathway. Specifically, sufficient guidance did not exist in the Paragon Modelremain-in-service list for a protected pathway per ER-AA-600-1042, "On-Line Risk Management," Revision 4.Enforcement: Title 10 CFR 50.65 (a)

(4) states, "before performing maintenance activities(including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The scope of the assessment may be limited to structures, systems, and components that a risk-informed evaluation process hasshown to be significant to public health and safety.Licensee procedure WC-AA-101, On-Line Work Control Process, Revision 12,Attachment 7, required that, "in even the cases of short equipment duration unavailability, aheightened level of sensitivity to the protected equipment must be maintained and it is the responsibility of every department to ensure that personnel working in the plant areinformed as to what components are protected." The procedure also stated in Section 4.1.4that actions shall be taken to protect redundant structures, systems, or components if lossof the redundant component would cause entry into a "red" or "orange" risk configuration.Contrary to the above, from 11:06 a.m. to 12:22 p.m. on May 15, 2006, the licensee didnot assess and manage the increase in risk, in that, Unit 2 was in a "yellow" risk condition due to the unavailability of the 2-1601-20B valve and would have gone to "red"risk if the 2-1601-20A valve had been made unavailable. The licensee took no actions to protect redundant structures, systems, or components. The 2-1601-20A valve was notmarked as a protected pathway. In addition, the licensee did not alert all departments to theprotected pathways through normal methods such as the POD meeting on May 15, 2006, orthe plant status sheet for the day or in the schedule review sheet for the day.

21Furthermore, the licensee identified that the reason this happened was thatprocedure ER-AA-600-1042, "On-Line Risk Management," Revision 4, did not specify that the 2-1601-20A and 2-1601-20B valves were components that needed protectedpathways on the redundant components. Additional licensee review identified six othercomponents for each unit that should have been listed in the Paragon Model remain-in-service list while their redundant component was being repaired or replaced on-line. The licensee has since added the omitted eight components for each unit to their remain-in-service list in ER-AA-600-1042 for protected pathway components that can change risk to "orange" or "red" if removed from service. Because this violation was of very low safety significance and it was entered into the licensee's corrective action program as IR 490307, this violation is being treated as a non-cited violation, consistent with Section VI.A of theNRC Enforcement Policy. (NCV 05000237/2006007-03)1R14Personnel Performance Related to Non-routine Evolutions and Events (71111.14).1Failure to Perform Procedure Steps in the Proper Sequence by Operations CausedEmergency Safety Feature Systems Actuation

a. Inspection Scope

On April 5, 2006, during the swap of the 3A reactor protection system (RPS) bus to reservepower to support repair of the 3B RPS motor generator (MG) set, the Unit 2/3 standby gas treatment auto started and a Unit 3 reactor building ventilation isolation occurred. Thelicensee determined that the cause of this issue was a human performance error for the failure to perform steps in the proper sequence. All systems were restored in accordancewith plant procedures and there was no equipment that was damaged or any personnel thatwere injured. The licensee entered this issue into their corrective action program as IR 475365.This represented one inspection sample.b.FindingIntroduction: A Green finding involving a non-cited violation of TS 5.4.1 was self revealedwhen an auxiliary nuclear station operator (Aux NSO) and a unit supervisor (US) wereperforming Dresden Operating Procedure (DOP) 0500-03, "Reactor Protection System Power Supply Operation," Revision 27. The Aux NSO and the US did not verify that thearea radiation monitor's (ARM) power supply voltage was normal and did not reset all trips on the ARM modules prior to removing a jumper that was installed. This required entry into TS 3.6.4.1 Limiting Condition of Operation, Action A for reactor building low differentialpressure (D/P).Description: On April 5, 2006, operations department staff were placing the 3A reactorprotection system (RPS) bus to reserve power from the normal power source to supportrepair of the 3B RPS motor generator (MG) set using DOP 0500-03. The operators reset a half scram that was expected during this activity and then they proceeded with removing a jumper that was installed, in accordance with the procedure, to allow the transfer. Following the removal of the jumper, the Unit 3 reactor building ventilation tripped and the Unit 2/3 standby gas treatment train auto started. Neither the Aux NSO nor the US verified that theARM power supply was indicating normal and that the 3A reactor building ventilation and 22reactor building fuel pool channel 'A' ARMs were reset prior to jumper removal as requiredby attachment A of DOP 0500-03. Procedure HU-AA-101,"Human Performance Tools and Verification Practices," Revision 3, required the individuals to agree that the system wasready for the action prior to performing the action. The US failed to verify that t he syst emwas reset or to check the proceeding steps had been completed prior to going into the next step. Both operators had been provided with marked up copies of the procedure, and briefed on jumper placement and removal and on the use of concurrent verification prior to the event.Analysis: The inspectors determined that the failure to implement procedure instructions forperforming the swap of the RPS buses to support a planned maintenance activity, that impacted safety-related equipment, was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordancewith Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports,"

Appendix B, "Issue Screening," issued on September 30, 2005, because it impacted thestructures, systems, and components attribute of the Barrier Integrity cornerstone(containment) objective. This deficiency challenged a safety system and could haveaffected the availability and capability of com ponents and systems that respond to initiatingevents.The inspectors completed a Phase 1 significance determination of this issue usingIMC 0609, "Significance Determination Process," Appendix A, Attachment 1, dated November 22, 2005, and determined that this finding impacted the Barrier Integritycornerstone column. The inspectors answered "Yes" to question #1 under the Barrier Integrity column on page A1-9. Therefore, the issue screened out as having very low significance (Green).The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (personnel) because the Aux NSO and the US failed to utilize humanperformance error prevention techniques required to safely implement the station procedure.Enforcement: Technical Specification 5.4.1 required, in part, that written procedures shallbe established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978, paragraph 1.jrequired administrative procedures for the bypassing of safety functions and jumper control. Station procedure DOP 0500-03, Attachment A, "Bypassing and Restoration of SecondaryContainment Isolations and SBGT Initiations When De-Energizing 'A' RPS Bus,"

Revision 27, Removing Jumpers Step 1, stated, "Prior to jumper removal verify ARM power supply 2(3)-1705-7A at 902(3)-10 is indicating normal voltage compared to other power supply;" and Step 2, "Reset ALL trips on the 902-(3)-10 ARM Modules AND verify annunciators are reset.Contrary to the above, on April 5, 2006, neither the NSO nor the US, verified that theARM power supply 2(3)-1705-7A at 902(3)-10 was indicating normal voltage compared to the other power supply or reset all trips on the 902-(3)-10 ARM Modules or verified that the annunciators reset prior to removing jumpers identified in procedure DOP 0500-03, Revision 27.

23Both the Aux NSO and the US had been provided with marked up copies of the procedure,and were briefed on jumper placement and removal and on the use of concurrent verification. As immediate corrective action, the two individuals were temporarily removed from licensed shift duties. The operations department was tasked to develop a dynamic learning activity for placekeeping and jumper manipulation for all operations personnel, and to create an internal OPEX to communicate lessons learned. Because this violation was of very low safety significance and it was entered into the licensee's corrective action program IR 475365, this violation is being treated as non-cited violation (NCV), consistent withSection VI.A of the NRC Enforcement Policy. (NCV 05000249/2006007-04).2Unit 2 High Pressure Coolant Injection (HPCI) System Declared Inoperable

a. Inspection Scope

The inspectors reviewed the Apparent Cause Report for IR 475721, "Shorted PowerLead While Replacing HPCI Temperature Recorder," and Licensee Event Report 237/2006-002-00, "Unit 2 High Pressure Coolant Injection System Declared Inoperable."This represented one inspection sample.

b. Findings

Introduction:

A Green finding was self-revealed when an instrument maintenancetechnician shorted a power lead while performing modification work that resulted in the Unit 2 HPCI system becoming inoperable for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 14 minutes on April 6, 2006. Thisfinding was not considered a violation of regulatory requirements.Discussion: Instrument maintenance technicians were replacing the Unit 2 HPCItemperature recorder on April 6, 2006. During re-installation of the recorder the technician shorted the power lead against the recorder mounting bracket screw. This resulted in the transfer of the essential service system bus to its emergency power supply from motorcontrol center 28-2 and the trip of essential service system circuit 16. This resulted in theHPCI system being inoperable due to a loss of its automatic function from the loss of powerto its flow controller and signal converter. The system was available because control roompersonnel could have manually controlled system operation.Analysis: The inspectors determined that the failure to ensure that the hot power leadwould not come into contact with any piece of the recorder or cabinet that could cause it to short to ground was a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports," Appendix B, "Issue Disposition Screening," issued on September 30, 2005. This finding was more than minor because it involved the Human Performance attribute of the Mitigating Systems objective of ensuring the capability of systems that respond to initiating events to prevent undesirableconsequences.The inspectors evaluated the finding using the SDP in accordance with IMC 0609,"Significance Determination Process," because the finding was associated with the Mitigating Systems cornerstone. Specifically, it impacted the short term heat removal degraded attribute found on page A1-7 of Appendix A. The inspectors performed a Phase I screening of the finding. The inspectors answered "No" to all five questions under the 24Mitigating Systems cornerstone column on page A1-9 and therefore the issue screened asvery low safety significance (GREEN). In addition, the HPCI system was inoperable for ashort time period and could have been manually controlled in the event of an accident.The inspectors also concluded that this finding affected the cross-cutting issue of humanperformance (personnel). Technicians failed to use appropriate human performance techniques to safely implement the procedure. Specifically, the instrument maintenance technician failed to recognize the potential hazard and tape off the mounting bracket screwthat caused the short to ground.Enforcement: The instrument maintenance technician was performing work inaccordance with the work package. The licensee communicated that error preventionwork practices expect the technician to identify and tape off the section of the mounting bracket that the power lead contacted to prevent an inadvertent short, but the workpractices do not procedurally require that action. Therefore, no violation of regulatoryrequirements occurred. This issue was considered a finding of very low safety significance(FIN 05000237/2006-007-05). This issue was entered into the licensee's corrective actionprogram as IR 475721. Licensee Event Report 237/2006-002-00, "Unit 2 High PressureCoolant Injection System Declared Inoperable" is closed..3Unit 2 2D1 Feedwater Heater Normal Level Control Valve Closed

a. Inspection Scope

The inspectors reviewed personnel performance during planned and unplanned plant evolutions. The review was performed to ascertain that operators' responses were in accordance with the required procedures. On April 14, 2006, the Unit 2 2D1 feedwater heater normal level control valve closed. Thelicensee entered Dresden Operating Abnormal procedure DOA 3500-02, "Loss of Feedwater Heaters." The licensee initiated a prompt investigation into the issue anddetermined that the cause of this event was a faulty level switch. The faulty switch was replaced and the licensee entered this issue into their corrective action program as IR 478794.This represented one inspection sample.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15).1Routine Inspections

a. Inspection Scope

The inspectors reviewed operability evaluations (OE) to ensure that operability was properlyjustified and the component or system remained available, such that any non-conformanceconditions were in compliance with Generic Letter 91-18, "Information to Licensees 25Regarding Two NRC Inspection Manual Sections on Resolution of Degraded andNonconforming Conditions and on Operability." The review included issues involving theoperability of:*Engineering Change/Evaluation #359519, MR-90 Technical Evaluation to supportshoring for trenching of underground piping and tank 2/3 B condensate storage tank;*Engineering Change/Evaluation #342944, Unit 3 containment cooling service watersystem water hammer loss of keep-f ill analysis; and*Document # 0006216498, dated July 7, 2000, "Dresden Unit 2 High Pressure CoolantInjection Room Cooler Operability."This represented three inspection samples.

b. Findings

No findings of significance were identified..2Standby Liquid Control Valves Installed In The Plant Different Than Those Assumed In ADesign Calculation

a. Inspection Scope

The inspectors reviewed IR 488251, "Non-Conservative Inputs Used In SBLC [standbyliquid control] Pressure Drop Calculation;" IR 487350, "Standby Liquid Control Valves Do Not Match Calculation;" and Engineering Change Evaluation (EC) 360883, "Impact of Incorrect SLCS [standby liquid control system] Pressure Drop Input on ATWS [anticipatedtransient without scram]

Analysis.

" In addition, the inspectors interviewed design and system engineering personnel.This represented one inspection sample.

b. Findings

Introduction:

The inspectors identified a finding involving a violation of 10 CFR 50.62,having very low safety significance (Green) associated with a licensee-identified material condition. The licensee identified that the inputs to a design analysis (DRE01-0066,"Dresden Unit 2 & 3 Standby Liquid Control System Discharge Piping Pressure Drop,"

Revision 1) were non-conservative. Some of the valves actually installed in the plant were not the same type of valves assumed to be installed in the design analysis. This ultimately resulted in a change in a design calculation that demonstrated that standby liquid controlsystem relief valves could lift upon system initiation during an anticipated transient withoutscram (ATWS) event.Description: On May 5, 2006, during a system walkdown the licensee identified that valves2/3-1101-2A & 2B, 2/3-1101-23, and 2/3 1101-1 are globe valves rather than gate valvesand valves 2/3-1101-43A & 43B, 2/3-1101-15 & 16 are lift check valves rather than swing check valves as shown in calculation DRE01-0066, Revision 1.The impact of having some of the valves actually installed in the plant that were not thesame type of valves assumed to be installed in the ATWS Analysis was that it resulted in a 26higher pressure drop between the pump discharge and the reactor than calculated in DRE01-0066, Revision 1. This higher pressure drop meant that pump discharge pressure had to be higher to get flow to the reactor and the SBLC system relief valves could liftduring an ATWS event. The lifting of the relief valves would cause SBLC system flow to be recirculated to the system storage tank rather than injected into the reactor vessel. Due tothe inability to provide continuous SBLC system design flow into the reactor vessel asrequired by 10 CFR 50.62.c.(4), the licensee would fail to comply with 10 CFR 50.62.c.(4) if the relief valve lifted.A licensee contractor revised calculation DRE01-0066 using the installed valve types. The results indicated that based on a two pump flow of 88 gallons per minute, the calculated system pressure loss increased to 215 psig for Unit 2 (as compared to 141 psig)and 362 psig for Unit 3 (as compared to 232 psi). Based on these results the licensee concluded that the SBLC relief valves would lift, during two pump flow, under the condition when SBLC was required to inject into the vessel.The licensee performed Engineering Change (EC) 360883 to document the justificationfor operability basis stated in IR 488251, "Non-Conservative Inputs Used In SBLCPressure Drop Calculation." Because the revision to calculation DRE01-0066 had not been completed at the time EC 360883 was performed, the licensee assumed higher values of pressure drop in EC 360883 than what was eventually determined to be accurate in DRE01-0066, Revision 2. The licensee assumed a 300 psig drop for Unit 2 and a 390 psig drop for Unit 3 when performing EC 360883. The licensee analyzed for a failed open pressure regulator along with a failure of the alternate rod insertion system. This was assumed to be the most limiting transient. The licensee concluded that vessel peak pressure and temperature, and also peak cladding temperature would not be impacted by the increase in SBLC pressure drop since they occur before the SBLC system would be initiated. In addition, the licensee assumed the event duration was short enough that fuelclad oxidation was not an issue. The licensee did conclude that del ayed SBLC systeminjection would have an impact on the maximum suppression pool temperature and pressure. The licensee concluded that with the assumed higher calculated pressure drops (300 psig and 390 psig), suppression pool temperature could be maintained at an acceptable level, but only by taking credit for the reactor cooling provided by the isolation condenser.The licensee took several conservativisms in EC 360883. For example, all the reactor reliefvalves were assumed to open at their set point plus three per cent and both SBLC systemrelief valves were assumed to open at their set point minus 3 percent. In addition, the licensee assumed that both SBLC system relief valves would open instead of the morelikely scenario that only one would open. If one SBLC relief valve remained closed more flow would be available to the reactor.Compliance with the 10 CFR 50.62The inspectors used the above information to determine that the potential to lift the SBLCrelief valve resulted in the licensee being outside of the design basis and in noncompliance with 10 CFR 50.62 because the system would be unable to meet the required injection flowrate and boron concentration during the time the relief valves were lifting.

27To achieve compliance with 10 CFR 50.62, the licensee planned to increase SBLC boronenrichment from greater than or equal to 30 atom percent boron-10 to greater than or equalto 45 atom percent boron-10. This would allow the licensee to provide the acceptable amount of boron per 10 CFR 50.62 while using only one pump. In addition, licensee's calculation DRE01-0066, Revision 2, demonstrated that the use of one SBLC pump wouldnot result in lifting a SBLC relief valve. The licensee planned to fill the SBLC tank with theenriched boron on each unit during the next refueling outages. Review of TS OperabilityTechnical Specification Surveillance Requirement 3.1.7.7 required the licensee todemonstrate that each SBLC pump was capable of pumping at a rate of at least 40 gpm with a discharge pressure of greater than or equal to 1275 psig. The inspectors reviewed additional information on the relief valves and determined that due to differences in systemhead losses during one and two pump system operation, the licensee could inject flow intothe reactor with one pump at the rate specified in TS Surveillance Requirement 3.1.7.7without lifting the relief valves. Based upon the continued ability to satisfy TS SurveillanceRequirement 3.1.7.7, the licensee determined that the SBLC system remained operableeven though the licensee was unable to continuously inject 86 gpm of sodium pentaborate solution as required to meet 10 CFR 50.62. In addition, the TS Basis stated that with onesubsystem inoperable the requirements of 10 CFR 50.62 cannot be met, however, theremaining subsystem is still capable of shutting down the unit.The Office of Nuclear Reactor Regulation also determined in Task InterfaceAgreement 2001-12, for a similar issue at the Susquehanna plant, that although thelicensee was not in compliance with 10 CFR 50.62, the standby liquid control systemremained operable as required by TS 3.1.7. This determination was based upon information contained in NUREG-1433, "Standard Technical Specifications GeneralElectric Plants," which states that TS 3.1.7 does not require meeting the requirements of10 CFR 50.62 to meet the associated TS Limiting Condition for Operation. Based upon thisinformation, the inspectors concluded that no violation of TSs occurred.Analysis: The inspectors determined that the failure to comply with 10 CFR 50.62 was aperformance deficiency warranting a significance determination. The inspectors concluded that the finding was greater than minor in accordance with IMC 062, "Power Reactor Inspection Reports," Appendix B, "Issue Disposition Screening," issued on September 30, 2005. This finding involved the attribute of design control and could haveaffected the Mitigating Systems objective of ensuring the capability of systems that res pondto initiating events to prevent undesirable consequences.The inspectors completed a significance determination of this issue using IMC 0609,Significance Determination Process," dated November 22, 2005. The finding was associated with the Mitigating Systems cornerstone. Specifically, it impacted the reactivity control degraded attribute found on page A1-7 of Appendix A. The inspectors performed a Phase I screening of the finding. The inspectors answered "Yes" to question 1, under the Mitigating System cornerstone on page A1-9, "is the finding a design or qualification deficiency confirmed not to result in loss of operability per Part 9900, Technical Guidance,Operability Determination Process for Operability and Functional Assessment," andtherefore the issue screened as very low significance (Green). The SBLC system could berecovered during an ATWS event. Cycling of the relief valves would not prevent most of the 28borated solution from being injected into the reactor pressure vessel, and the licensee wasable to demonstrate that the reactor remained within the acceptance criteria of their originalATWS analyses even if no boron solution was injected into the reactor pressure vessel while the relief valves lifted.Enforcement: Part 50.62 of Title 10 CFR requires, in part, that each boiling water reactormust have a SBLC system with the capability of injecting into the reactor pressure vessel aborated water solution at such a flow rate that the resulting reactivity control was at least equivalent to that resulting from the injection of 86 gpm of 13 weight percent sodium pentaborate decahydrate (boron) solution. Contrary to the above, the licensee has failed to have, since 1984, a SBLC system with thecapability of injecting into the reactor pressure vessel a borated water solution at such aflow rate that the resulting reactivity control was at least equivalent to that resulting from the injection of 86 gpm of 13 weight percent sodium pentaborate decahydrate (boron) solution. This condition was considered a performance deficiency. To achieve compliance with 10 CFR 50.62, the licensee planned to increase SBLC boronenrichment from greater than or equal to 30 atom percent boron-10 to greater than or equalto 45 atom percent boron-10. This would allow the licensee to provide the acceptable amount of boron per 10 CFR 50.62 while using only one pump. In addition, licensee's calculation DRE01-0066, Revision 2, demonstrated that the use of one SBLC pump wouldnot result in lifting a SBLC relief valve. The licensee planned to install the enriched boron on each unit during the next refueling outages. The inspectors questioned why the boron enrichment could not be accomplished during a forced outage. The licensee wrote IR 507856 to address this question. The answer was not obtained by the end of the inspection period.Because this violation was of very low safety significance and it was entered into thelicensee's corrective action program as IR 488251, this violation is being treated as a non-cited violation (NCV), consistent with Section VI.A of the NRC Enforcement Policy.(NCV 05000237/2006-007-05; 05000249/2006-007-05)

.1 R19Post Maintenance Testing

Main article: IP 71111.19

a. Inspection Scope

The inspectors reviewed post-maintenance test results to confirm that the tests wereadequate for the scope of the maintenance completed and that the test data met theacceptance criteria in TSs or other design documents. The inspectors also reviewed the tests to determine if the systems were restored to the operational readiness statusconsistent with the design and licensing basis documents. The inspectors reviewed post-maintenance testing activities associated with the following:*Unit 2 planned maintenance on torus to reactor building vacuum relief air operatedvalve 2-1601-20B;*Unit 3 planned maintenance on LPCI loop I full flow bypass test inboard MOV 3-1501-20B;*Unit 3 planned maintenance on LPCI loop I and loop II cross-tie MOV 3-1500-32B; 29*Unit 3 planned maintenance on LPCI loop II full flow bypass outboard test MOV 3-1500-38B; and*Unit 2 replacement of the 2-1641-17A torus to reactor building d/p relay.This represented five inspection samples.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors observed surveillance testing on risk-significant equipment and reviewedtest results. The inspectors assessed whether the selected plant equipment could perform its intended safety function and satisfy the requirements contained in TSs. Following the completion of each test, the inspectors determined that the test equipment was removed and the equipment returned to a condition in which it could perform its intended safety function.The inspectors observed surveillance testing activities and/or reviewed completed packagesfor the tests, listed below, related to systems in the Initiating Event, Mitigating Systems, andBarrier Integrity cornerstones:*Unit 2 DOS 1400-05, "Core Spray System Pump Operability and Quarterly InserviceTesting (IST) with Torus Available," Revision 32;*Unit 3 DOP 2000-24,"Drywell Sump Operation," Revision 13;

  • Unit 3 DOS 6600-12, "Diesel Generator Tests Endurance and Margin/Full LoadRejection/ECCS/Hot Restart," Revision 34;*Unit 2 EPAs MA-DR-773-732, "Calibration/Functional Test of Reactor ProtectionSystem 2A Motor Generator Set," Revision 03;*Unit 3 DOS 1500-02, "Containment Cooling Service Water Pump Test and InserviceTest (IST)," Revision 56; *Unit 3 DIS 1500-29, "Low Pressure Coolant Injection System Division 1 Logic SystemFunctional Testing," Revision 04; and*DES 8300-50, "125 Volt DC Battery Charger Capacity Test for Charger 2-83125-2A,"Revision 3.This represented a total of seven inspection samples, of which two were In Service Testing,one was Reactor Coolant System Leak Detection, and four were Routine Surveillance.

b. Findings

No findings of significance were identified.

301R23Temporary Plant Modifications (71111.23)

a. Inspection Scope

The inspectors screened one active temporary modification and assessed the effect of thetemporary modification on safety-related system functions as specified in the Updated FinalSafety Analysis Report and TSs. The inspectors also determined if the installation was consistent with system design.*Temporary Modification 360461, "Install Temporary Heater to Support SBLC HeatTracing for Suction Line," Revision 0This represented one inspection sample.

b. Findings

No findings of significance were identified.1EP6Drill and Training Evaluations (71114.06)May 31, 2006, Emergency Preparedness Performance Indicator

a. Inspection Scope

The inspectors observed station personnel during a licensee-only-participation emergencypreparedness training exercise on May 31, 2006. The inspectors evaluated the effectiveness of drill participants and the adequacy of the licensee's critique in identifyingweaknesses and failures. The dr ill scenario involved the reactor protection system failure toinitiate an automatic scram and initiation of the alternate rod insertion system.This represented one inspection sample.

b. Findings

No findings of significance were identified.4OA1Performance Indicator Verification (71151)Cornerstones: Initiating Events and Mitigating Systems

.1 Reactor Safety Strategic Area

A.Inspection ScopeThe inspectors sampled the licensee's records associated with the two initiating event performance indicators (PI) listed below for Units 2 and 3. Specifically, the inspectors looked at the period from the first quarter of 2004 through the fourth quarter of 2005. To verify the accuracy of the PI data reported during that period, PI definitions and guidancecontained in Nuclear Energy Institute Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 3, were used to verify the basis in reporting for 31each data element. The inspectors reviewed portions of the operations logs and raw PIdata developed from the monthly operating reports and discussed methods for compilingand reporting the PIs with cognizant licensee personnel. The inspectors compared graphical representations from the most recent PI report to the raw data to verify that thedata was correctly reflected in the report. Licensee event reports (LERs) issued during the referenced time frame, operating logs, and the unit nuclear station operator daily surveillance log for reactor coolant system leakage were also reviewed. All data reviewedcovered the period from April 2004 through March 2006. The inspectors discussed methods for compiling and reporting the PIs with cognizant licensee personnel.*Safety System Functional Failures, Units 2 and 3*Unplanned Transients per 7000 Critical Hours, Units 2 and 3 This represented four inspection samples.

b. Findings

No findings of significance were identified4OA2Identification and Resolution of Problems (71152).1Routine Quarterly ReviewReview of Licensee's Response to the Unit 2 "A" Electrohydraulic Control System (EHC)Pressure Regulator IssueOn March 24, 2005, Unit 2 received two unexpected control room alarms due to anEHC system malfunction. Several seconds later, Unit 2 experienced a steam transientwhich caused a Group 1 isolation and scram. The licensee initiated IR 316625 and initiated a prompt investigation to ensure the details regarding this event were appropriately captured and corrected. a.Effectiveness of Problem Identification (1)Inspection ScopeThe inspectors reviewed the information provided in IR 316625 and the associated rootcause report to verify that the licensee's identification of the problems was complete, accurate, and timely, and that the consideration of extent of condition review, generic implications, and common cause was adequate.

(2)IssuesThere were no issues in the area of Effectiveness of Problem Identification.

32b.Prioritization and Evaluation of Issues(1)Inspection ScopeThe inspectors considered the licensee's evaluation and disposition of performance issues,and application of risk insights for prioritization of issues.(2)IssuesThere were no issues in the area of Prioritization and Evaluation of Issues.

c.Effectiveness of Corrective Actions(1)Inspection ScopeThe inspectors reviewed the licensee's corrective actions which resulted from the rootcause report associated with IR 316625 to determine if the IR addressed generic implications and that corrective actions were appropriate. (2)IssuesThe inspectors reviewed the licensee's actions and concluded that the actions werecomprehensive. Although the cause of the scram was unable to be determined, the mostprobable cause was attributed to an increase in electrical resistance between electrical pins on the A54 circuit card within the EHC system. The card was removed from service and sent to an independent laboratory for additional testing. No obvious deficiencies were identified. The licensee closed the corrective action assignment by completing the work request and repairing the remaining connectors to the "A" EHC pressure regulator "A54" card during the November 2005 Unit 2 refueling outage. The inspectors verified that the licensee completed all corrective actions assigned. However, the corrective action systemdocumentation did not appropriately reflect that the work was completed.This represented one inspection sample..2Semiannual Review for Trends

a. Inspection Scope

The inspectors performed a review of the licensee's corrective action program (CAP) andassociated documents to identify trends that could indicate the existence of a moresignificant safety issue. The inspector's review consisted of a 6 month period from January 2006 through June 2006, although some examples expanded beyond those dates when the scope of the trend warranted. The inspectors reviewed multiple issue reports generated during the time period, in an attempt to identify potential trends. The screening was accomplished as follows:1.IRs dealing with company policies, administrative issues, and other minor issues wereeliminated as being outside the scope of this inspection; 332.The IRs were sorted into categories involving same equipment problems, repetitiveissues, reoccurring departmental problem/challenges and repeated entries into TSs.

The IRs were then screened for potential common cause issues and considered for potential trends; 3.The inspectors removed groups of IRs that discussed strictly programmatic problemsbecause the inspection requirement was primarily for equipment problems and human performance issues;4.The inspectors also removed groups of IRs where their review indicated that duplicateIRs had been written for the same event or failure;5.The remaining groups, considered potential unidentified trends, were provided to thelicensee for discussion in case there was extenuating information that the inspectors were not aware of; and 6.Groups of IRs remaining after all of the above screening were considered trends whichthe licensee had failed to identify.7.The inspectors then were able to make an assessment by comparing the trendsidentified by the licensee to those trends identified by the NRC.In addition, the inspectors reviewed corrective action backlog lists and all of the nuclearoversight assessments and audits conducted during January 2006 to June 2006. This represented one inspection sample.

b. Findings

There were no findings of significance identified. The inspectors determined that licenseeemployees were writing IRs at an appropriate threshold, and that employees at all levels of the organization were writing IRs. The inspectors determined that the licensee had identified issues adequately and appropriately entered them into the corrective action program. Overall, the inspectors identified the same specific trends as the licensee.4OA5Other Activities (71153)(Closed) Unresolved Item 05000237/97019-04; 05000249/97019-04 Concrete ExpansionAnchor (CEA) Safety Factor (SF) for High Energy Line Break (HELB) Pipe Whip Restraints.

TAC Nos. MB7297 through MB7300.The inspectors were concerned that anchor bolts for HELB pipe whip restraints at theDresden and Quad Cities stations were designed with a minimum SF of 2.0, which was less than the SF of 4.0 they expected. (Reference Quad Cities Inspection FollowupItem 05000254/96011-06; 05000265/96011-06). Subsequently, the licensee performed additional analysis, and determined that there are five CEAs at Quad Cities, and one CEA at Dresden that have a designed factor of safety between 2.5 and 3.8. These CEAs areused in pipe whip restraints (HERs) provided for high energy line break mitigation. CEAs used to satisfy seismic design requirements must have a SF of 4.0 or greater. CEAs used for other applications, such as HERs, are typically designed with a SF of 4.0.

34An Internal NRC Memorandum (R. Capra to J. Grobe) dated, July 23, 1997, respondedto an NRC Region III Request for Technical Assistance (Task Interface Agreement(TIA) 96-0325) (G. Grant to J. Roe) dated, September 20, 1996, and provided the NRCOffice of Nuclear Reactor Regulation (NRR) evaluation of the issue. Additional discussions and correspondence between the licensee and NRC staff occurredwith respect to this issue. Additional onsite inspection of this issue occurred as indicated in NRC Integrated Inspection Report 05000254/03-02; 05000265/03-02. Docketed correspondence between the NRC and the licensee included the following:Letter from NRC to L. Pearce (ComEd) dated December 16, 1997;Letter from J. Heffley (ComEd) to NRC dated January 9, 1998; Exelon Response to Verbal Request for Additional Information (K. Jury (Exelon) to NRCDocument Control Desk) dated September 11, 2002; NRC Request for Additional Information, M. Banerjee (NRC) to C. Crane (Exelon) dated,August 10, 2004; andExelon Response to Request for Additional Information (P. Simpson to NRC DocumentControl Desk) dated, September 30, 2004.There is no specific regulatory requirement or commitment regarding the SF for theseCEAs. Therefore, the staff did not identify any non-compliance with a specific regulatory requirement. However, in order to ensure that adequate protection exists given the smaller SFs, the staff requested the licensee to provide a bounding type of analysis to discuss the safety impact of these CEAS failing to perform their safety function upon a postulated failureof the pipe (a beyond design basis analysis).The licensee provided the requested analysis in the letter dated, September 30, 2004,(available in the NRC agencywide document access and management system (ADAMS)under accession number ML042820219). The staff reviewed this analysis and performed a walkdown of the plant areas where some of the protected equipment is located. Thefollowing provides a summary of the licensee's response and the staff's observation during the walkdown regarding the safety impact of postulated failures of the subject CEAs (for Dresden) to restrain the high energy line in the unlikely event of a total circumferential break:Dresden HER PWHP-3This anchor is located on the high pressure coolant injection (HPCI) steam line in the torusarea. During a postulated HPCI steam line circumferential break, if this anchor fails, the whipping pipe could damage certain safety related motor operators for valves in the low pressure coolant injection (LPCI) system (not crediting several structural elements in between the pipe and the valve operators). These valves are in the return line to the torus for one of the redundant torus cooling/spray loops, and hence damage to these valves could cause the loss of one of the two loops of the suppression pool cooling system. Thehigh HPCI steam flow out the ruptured pipe will isolate the system, thus terminating the 35flow. The operators will use symptom based emergency operating procedures (EOPs) toshutdown the reactor from the control room. The suppression pool cooli ng system is notrequired to mitigate the accident, as the isolation condenser system will be available toremove decay heat before normal shutdown cooling could be initiated. Additionally, the main condenser should also be available if the high steam flow does not isolate the main steam lines. ConclusionBased on a review of the information that was provided, the staff agrees that there isreasonable assurance that the plant can be safely shutdown in the event of acircumferential pipe break, and subsequent failure of its related CEA(s) as described above. Therefore, adequate protection exists for a postulated beyond design basis event when the subject CEAs with a SF of less than 4.0 are assumed to fail after a high energy line break. Hence, no further regulatory action is warranted relative to this issue.

The TAC Nos. MB7297 through MB7300 are closed. This unresolved item is also closed.4OA6Meetings.1Exit MeetingThe inspectors presented the inspection results to the Plant Manager, Mr. D. Wozniak, andother members of licensee management on July 18, 2006. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was discussed..2Interim Exit MeetingsInterim exit meetings were conducted for:

Biennial Operator Requalification Program Inspection with Mr. D. Wozniak, Plant Manager,on May 19, 2006.Biennial Operator Requalification Program Inspection with Mr. G. Graff, Operations TrainingManager, on June 12, 2006, via telephone.Unresolved Item 05000237/97019-04; 05000249/97019-04 closure with Mr. D. Wozniak onJune 19, 2006.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

D. Bost, Site Vice President
D. Wozniak, Plant Manager
C. Barajas, Senior Operations Supervisor
H. Bush, Radiation Protection Manager
J. Ellis, Regulatory Assurance Manager
R. Ford, Emergency Preparedness Manager
R. Gadbois, Operations Director
D. Galanis, Design Engineering Manager
V. Gengler, Dresden Site Security Director
G. Graff, Operations Training Manager
J. Griffin, Regulatory Assurance - NRC Coordinator
M. McGivern, CCSW System Engineer
P. O'Connor, Lead License Operator Requalification Training
M. Otten, Corporate Training
B. Rybak, Acting Regulatory Assurance Manager
C. Symonds, Training DirectorNRC pers onnel
M. Ring, Chief, Division of Reactor Projects, Branch 1IEMA personnel
R. Schulz, Illinois Emergency Management Agency
R. Zuffa, Resident Inspector Section Head, Illinois Emergency Management Agency

2

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000237/2006007-01NCVFailure to Identify an Inoperable 3-hour Fire Barrier Wall in theUnit 2 EDG Day Tank Room05000237/2006007-02NCVUnit 2 350 psig Reactor Low Pressure Emergency CoreCooling System Permissive Switch Out-of-tolerance During

Surveillance Testing05000237/2006007-03NCVFailure to Post Protective Pathway Signs During Unavailabilityof Torus to Reactor Building Vacuum Breaker05000249/2006007-04NCVFailure to Perform Procedure Steps in the Proper Sequenceby Operations Caused Emergency Safety Feature Systems

Actuation05000237/2006007-05FINUnit 2 High Pressure Coolant Injection (HPCI) SystemDeclared Inoperable05000237/2006007-06NCVStandby Liquid Control Valves Installed In The Plant05000249/2006007-06Different than those Assumed in a Design CalculationClosed05000237/2006007-01NCVFailure to Identify an Inoperable 3-hour Fire Barrier Wall in theUnit 2 EDG Day Tank Room05000237/2006007-02NCVUnit 2 350 psig Reactor Low Pressure Emergency CoreCooling System Permissive Switch Out-of-Tolerance During

Surveillance Testing05000237/2006007-03NCVFailure to Post Protective Pathway Signs During Unavailabilityof Torus to Reactor Building Vacuum Breaker05000249/2006007-04NCVFailure to Perform Procedure Steps in the Proper Sequenceby Operations Caused Emergency Safety Feature Systems

Actuation05000237/2006007-05FINUnit 2 High Pressure Coolant Injection (HPCI) SystemDeclared Inoperable05000237/2006007-06NCVStandby Liquid Control Valves Installed In The Plant05000249/2006007-06Different than those Assumed in a Design Calculation

305000237/97019-04URIConcrete Expansion Anchor Safety Factor for05000249/97019-04High Energy Line Break (HELB) Whip Restraints237/2006-002-00LERU2 Low Pressure Coolant Injection System DeclaredInoperableDiscussedNone

4

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 or 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 orany part of it, unless this is stated in the body of the inspection report.1R01Adverse Weather-WO
00594962; D3 2Y Complete CCSW Pump Cubicle Cooler Performance Test-DTS 1500-04 Revision 07; CCSW Pump Cubicle Coolers 2(3)-5700-30A&B and 30C&D
Performance Test

-NRC Generic Letter 89-13, Service Water System Problems Affecting Safety RelatedEquipment

-EC

348504 Revision 00; Evaluate the Removal/Isolation of Two Cooling Tube Circuits of the
3-5700-30A Containment Cooling Service Water (CCSW) Room Cooler

-DOP 5750-21 Revision 21; Unit 2/3 Reactor Building Chilled Water System-DOS 0010-24 Revision 08; Securing from Cold Weather Operations for Unit 2

-DOS 0010-27 Revision 06; Securing from Cold Weather Operations for Unit 3

-DOS 0010-21 Revision 11; Securing Cold Weather Operations for U1 & Out Buildings

-DOS 0010-33 Revision 09; Securing from Cold Weather Operations at the Lift Station, GooseLake Pump Station, Security Diesel Building, and Cooling Towers

-CC-AA-309-1001 Revision 2; Calculation for CCSW Cooler Performance and Effectiveness Curve Essential Calc VV-13

-CC-AA-309-1001 Revision 2' Calculation for CCSW Cooler Performance and Effectiveness Curve Essential Calc VV-14

-IR

0049355 Enter
DOA 5750-01 Due to Planned Work; May 25, 20051R04Equipment Alignment-DOP 2300-M1/E1; Revision 34; Unit 3 HPCI System Checklist-DOS 0040-08; Revision 23; Unit 2 Operating Power Sources and Distribution

-DOP 6600-E2; Revision 05; Unit 2(3) Standby Diesel Generator

-DOP 5750-02; Revision 34; Reactor Building Ventilation1R06Flooding-WO

00761944; D3 QTR TSTR CCSW Pump Vault Penetration Surveillance Testing;June 05, 2006

-WO

00679590; D3 18M Test CCSW Pump Vault Water Tight Door Leak Test

-DOS 1500-20; Unit 2(3) CCSW Pump Vault Penetration Surveillance Testing-DOS 1500-21; Unit 2(3) CCSW Pump Vault Watertight Door Leak Test1R11Licensed Operator Requalification-Dresden Station, Units 2 and 3 NRC Integrated Inspection Reports; dated various fromJuly 28, 2004, through May 8, 2006

-TQ-AA-106; Licensed Operator Requal Training Program; Revision 7

-TQ-AA-210-5101; Training Observation Forms; dated various

5-TQ-AA-301; Simulator Configuration Management; Revision 6-TQ-AA-301-0301; Simulator SWR Prioritization, Maintenance, Modification, and Enhancements; Revision 2

-Curriculum Review Committee Meeting Minutes; dated various August 2004 through January 2006

-Training Advisory Committee Meeting Minutes; dated various June 2004 through February 2006

-List of SWRs Completed Past 12 Months; dated May 12, 2006

-List of Open SWRs; dated May 12, 2006

-Dresden 2005 Exam Summary

-Dresden 2006 Licensed Operator Requal Exam Results Summary; Weeks 1 and 2

-TQ-AA-106-0102; Licensed Operator Requal Training Classroom Attendance Sheets;

Cycle 1, 2004 through Cycle 4; 2006

-2006 Dresden Sample Plan; LORT Exam Construction

-Dresden 2005 LORT Written Exams; Weeks 1 through 6

-Dresden 2006 LORT Operating Exam; Weeks 1, 2, and 3

-Dresden Operations Dept. Policy No. 62; Operations Department Standards and Expectations;dated March 3, 2006

-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 Minutes; dated May 18, 2004; September 21, 2004; January 11, 2005;June 30, 2005; and October 25, 2005

-OP-AA-105-102; NRC Active License Maintenance; Revision 7-Ten Licensed Operators' Medical Records; dated various

-TQ-AA-106-0102; Exelon Nuclear LORT Classroom Attendance; Revision 0

-TQ-AA-106-0113; Simulator Demonstration Examination Individual Competency Evaluation Forms; (Annual) Crew 1; dated May 17, 2006

-TQ-AA-106-0114; Simulator Demonstration Examination Crew Competency Evaluation Forms;

(Annual) Crew 1, May 17, 2006

-TQ-AA-210-4101; Remedial Training Notification and Action on Failure; dated various

-TQ-AA-210-4102; Performance Review Committee Data Sheet; dated various

-TQ-AA-106-0304; Licensed Operator Requal Training Exam Development Job Aid; Revision 2

-TQ-AA-201; Examination Security and Administration; Revision 4

-IR

00334912; NOS Identifies Minor Exam Security Issue; dated May 13, 2005

-IR

00460014; Recommendations from LORT Pre-7111.11 FASA; dated February 28, 2006-IR
00487168; Exam Security Issue During The Annual LORT Exam; dated May 6, 2006

-IR

00491450; NRC Identified Procedure Issue; dated May 18, 2006-IR
00491455; NRC Identified - Simulator Testing Enhancements; dated May 18, 2006-Issue Reports Initiated Based on NRC Observations1R12Maintenance Effectiveness

-IR

00473392; LPCI Maint Rule Function Z15-4 Availability Criteria Not Met; 3/31/06-First Quarter 2006 LPCI Maintenance Rule Evaluation dated April 4, 2006, covering criteriaZ15-4, Z15-5 and Z15-6.

-IR

00347372; Glycerin Puddle on D2 East LPCI Room Floor Due to Failed Gauge; 6/24/05

-IR

00394985; Relay Timing Out of Tolerance; 11/05/05

-IR

00368361; EQ Switches Not Torqued During 34Y Replacement; 8/30/05
61R13Maintenance Risk Assessments and Emergent Work Control-DOP 0500-03, Revision 29, Reactor Protection System Power Supply Operation1R14Personnel Performance Related to Non-routine Evolutions and Events-IR
00475365; Rx Bldg Vent System Tripped and 2/3B SBGT Train Auto Started; April 5, 2006-Apparent Cause Evaluation 4753651R15Operability Evaluations

-RSA-D-92-06, HPCI Room Thermal Response with Loss of HPCI Room Cooler, datedNovember 13, 1992

-CHRON #200889, Dresden Station Units 2 and 3, EQ Applicability Determination andEvaluation of Components Located in EQ Zones 4, 5 and 6 EQ Evaluation Transmittal12-93-0084OA2Identification and Resolution of Problems

-IR

00316625; U2 Reactor, Group 1 Isolation and Scram; March 24, 2005 -IR
00317029; NOS ID'D EHC Scram Troubleshooting Discrepancies; March 25, 2005-IR
00471092; Four "on duty" ERO members did not respond to pager test; March 27, 2006

-IR

00471096; Overall pager test contact rate below expectations; March 27, 2006

-IR

00476183; On-duty ERO non-responders to pager test; April 7, 2006

-IR

00481073; Dialogics pager system not receiving call-ins during pager test; April 20, 2006-IR
00496221; ERO call-in pager test was a marginal pass; April 2, 2006

-IR

00454729; ERO Team member on call without an ERO pager; February 16, 2006

-IR

00455267; Dresden off-year exercise development process not followed; February 17, 2006

-IR

00439891; ERO pager test of 2/9/06 had 4 on-duty persons not respond; February 28, 2006
7

LIST OF ACRONYMS

USEDADAMSAgencywide Documents Access and Management SystemARMArea Radiation Monitor

Aux NSOAuxiliary Nuclear Station Operator

CEAConcrete Expansion Anchor

CFRCode of Federal Regulations

CRCondition Report

DFPPDresden Fire Protection Reports

DISDresden Instrument SurveillanceDOPDresden operating Procedure

DOSDresden Operating Surveillance DRPDivision of Reactor Projects

DRSDivision of Reactor Safety

EDGEmergency Diesel Generator

EHCElectro Hydraulic Control

EPEmergency Preparedness

EPRIElectrical Power Research Institute

EOPEmergency Operating Procedures

gpmgallons per minute

HELBHigh Energy Line Break

HERHELB Pipe Whip Restraints

HPCIHigh Pressure Coolant Injection

HVACHeating, Ventilating and Air-Conditioning

IEMAIllinois Emergency Management Agency

IFIInspection Followup Item

IMCInspection Manual Chapter

IRInspection / Issue Report

ISTInservice Test

JPMJob Performance Measure

LORTLicense Operator Requalification Training

LPCILow Pressure Coolant Injection

MCCmotor control center

MGmotor generator

MOVMotor Operated Valve

MWemegawatts electrical

NCVNon-Cited Violation

NFPANational Fire Protection Association

NOSNuclear Oversight

NUREGNuclear Regulatory GuideNRCNuclear Regulatory Commission

NRROffice of Nuclear Reactor Regulation

PARSPublicly Available Records

PIPerformance Indicator

PODMPlan of the Day Meeting

RCICReactor Core Isolation Cooling

RFPReactor Feed Pump

RHRResidual Heat Removal

RPSReactor Protection System

SATSystems Approach to Training

8SBLCStandby Liquid ControlSDPSignificance Determination Process

SFSafety Factor

SROSenior Reactor Operator

SWService Water

TIATask Interface Agreement

TSTechnical Specification

UFSARUpdated Final Safety Analysis Report

USUnit Supervisor

WOW ork Order
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