IR 05000254/2006004

IR 05000254-06-004, 05000265-06-004; 01/01/2006 - 03/31/2006; Quad Cities Nuclear Power Station, Units 1 & 2; Routine Integrated Inspection Report, Permanent Plant Modifications

ML061220587
Person / Time
Site:	Quad Cities
Issue date:	05/01/2006
From:	Ring M NRC/RGN-III/DRP/RPB1
To:	Crane C Exelon Generation Co, Exelon Nuclear
References
IR-06-004
Download: ML061220587 (30)

Text

May 1, 2006Mr. Christopher M. CranePresident and Chief Nuclear Officer Exelon Nuclear Exelon Generation Company, LLC Quad Cities Nuclear Power Station 4300 Winfield Road Warrenville, IL 60555SUBJECT:QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000254/2006004; 05000265/2006004

Dear Mr. Crane:

On March 31, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed an integratedinspection at your Quad Cities Nuclear Power Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on April 4, 2006, with Mr. Tulon and other members of your staff.The inspection examined activities conducted under your license as they relate to safety and tocompliance 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, no findings of significance were identified.

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

Sincerely,

/RA/

Mark A. Ring, ChiefBranch 1 Division of Reactor ProjectsDocket Nos. 50-254; 50-265License Nos. DPR-29; DPR-30

Enclosure:

Inspection Report 05000254/2006004; 05000265/2006004 w/Attachment: Supplemental Information DOCUMENT NAME:E:\Filenet\ML061220587.wpd G Publicly Available G Non-Publicly Available G Sensitive G Non-SensitiveTo receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copyOFFICERIIINAMEMRing:dtpDATE05/1//2006OFFICIAL RECORD COPY C. Crane-2-

REGION IIIDocket Nos.:50-254, 50-265 License Nos.:DPR-29, DPR-30 Report No.:05000254/2006004 and 05000265/2006004 Licensee:Exelon Nuclear Facility:Quad Cities Nuclear Power Station, Units 1 and 2Location:Cordova, Illinois Dates:January 1, 2006, through March 31, 2006 Inspectors:K. Stoedter, Senior Resident InspectorM. Kurth, Resident Inspector R. Baker, Resident Inspector - Duane Arnold D. Jones, Reactor Inspector D. Melendez-Colon, Reactor Engineer D. Tharp, Resident Inspector - ClintonR. Winter, Reactor Inspector R. Ganser, Illinois Emergency Management AgencyApproved by:M. Ring, ChiefProjects Branch 1 Division of Reactor Projects Enclosure 1

SUMMARY OF FINDINGS

IR 05000254/2006004, 05000265/2006004; 01/01/2006 - 03/31/2006; Quad Cities NuclearPower Station, Units 1 & 2; Routine Integrated Inspection Report, Permanent PlantModifications.The report covered a 3-month period of inspection by resident inspectors, anannounced inspection by a regional inservice inspector, and the completion of

Temporary Instruction 2515/165, "Operational Readiness of Offsite Power and Impact on Plant Risk." No findings of significance were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC)0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC'sprogram for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.A.

NRC-Identified and Self-Revealing Findings

No findings of significance were identified.

B.Licensee-Identified Violations

No findings of significance were identified.

2

REPORT DETAILS

Summary of Plant StatusUnit 1 began the inspection period operating at 85 percent power due to potential ERV actuatordegradation concerns. On January 6 the licensee shut down Unit 1, inspected the actuators,and found several areas of degradation. Over the next 3 days, the licensee performed ERV actuator replacement activities and other associated outage work. Unit 1 returned to pre-extended power uprate power levels on January 9. Approximately 1 week later, the licensee shut down Unit 1 again due to identifying a new ERV actuator failure mechanism.

Over the next 4 days, the licensee re-inspected the ERV actuators to address the new failuremode. Unit 1 returned to power on January 19.Approximately 1 month later, Unit 1 experienced a reactor scram due to a main powertransformer differential current relay actuation. Subsequent troubleshooting determined thatthe relay actuated due to an electrical ground created by excessive vibrations of the main power transformer. In response to this event, the licensee inspected the main power transformer protective circuitry and wiring. Due to the types and levels of degradation identified, the licensee disconnected portions of the wiring and installed additional wiring external to the transformer. Unit 1 returned to power on February 24. Unit 1 continued to operate at 85 percent power for the remainder of the inspection period.Unit 2 also began the inspection period operating at 85 percent power. On January 13 thelicensee shut down Unit 2 to address additional ERV actuator degradation concerns identified during an NRC Special Inspection. During this shut down, the 3D ERV failed to operate asexpected. The licensee's troubleshooting activities identified an additional ERV actuator failure mode which had not been previously identified. As part of the 6 day outage, the licenseecompleted actions to address concerns developed by the NRC Special Inspection Team andthe newly identified failure mechanism. Details regarding the ERV actuator issues and related outages were documented in NRC Special Inspection Report 05000254/2006009 and05000265/2006009. Unit 2 returned to pre-extended power uprate power levels on January 19 and remained there until the refueling outage began on March 24. The refueling outage wasongoing at the conclusion of the inspection period.1.REACTOR SAFETYCornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1Partial Walkdowns

a. Inspection Scope

The inspectors performed partial walkdowns of the systems listed below to verify theoperability of redundant trains and components when safety equipment was inoperable. The inspectors attempted to identify any discrepancies that could impact the function of 3 the system, and therefore, potentially increase risk. The inspectors reviewed applicableoperating procedures; walked down control systems components; and verified thatselected breakers, valves, and support equipment were in the correct position to support system operation. The inspectors searched corrective action program documentation toverify that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systemsor barriers to perform their function. *Unit 1 emergency diesel generator*Unit 2 emergency diesel generator

• Unit 1 reactor core isolation cooling system

• Units 1 and 2 electrohydraulic control systemsThese inspections represented the completion of four quarterly samples..2Complete Walkdown

a. Inspection Scope

The inspectors conducted one complete walkdown of the diesel fire pumps andassociated piping. The inspectors used the licensee's procedures and other documents provided in the list of documents reviewed to determine the piping configuration, theposition of associated valves, and the types of instrumentation used withi n the system. The inspectors reviewed design documents to determine the electrical power requirements for the system. The walkdowns also included evaluation of system pipingand supports against the following considerations during an in-plant walkdown:*Piping and pipe supports did not show evidence of water hammer*Oil reservoir levels appeared normal

• Snubbers did not appear to be leaking hydraulic fluid

• Hangers were functional

• Component foundations were not degradedA review of outstanding maintenance work orders was performed to verify that theknown outstanding deficiencies did not significantly affect t he system's ability to performits function. In addition, the inspectors reviewed the issue report database to verify that fire protection equipment alignment problems were being identified and appropriately resolved.

b. Findings

No findings of significance were identified.

41R05Fire Protection (71111.05).1Fire Protection - Tours

a. Inspection Scope

The inspectors conducted a tour of the 14 areas listed below to assess the materialcondition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with the licensee's administrative procedures; fire detection and suppression equipment was available for use; that passive fire barriers were maintained in good material condition; and that compensatory measures for out-of-service, degraded, or inoperable fire protection equipment were implemented in accordance with the licensee's fire plan. *Fire Zone 1.1.1.3 - Unit 1 623 Feet Elevation, Mezzanine Level, Reactor Building*Fire Zone 1.1.2.3 - Unit 2 623 Feet Elevation, Mezzanine Level, Reactor Building

• Fire Zone 3.0 - Service Building 609 Feet Elevation, Cable Spreading Room

• Fire Zone 6.3 - Service Building 595 Feet Elevation, Auxiliary Electric Room*Fire Zone 8.2.7.A - Unit 1 Turbine Building 615 Feet Elevation, Hydrogen SealOil Area and Motor Control Centers*Fire Zone 8.2.7.E - Unit 2 Turbine Building 615 Feet Elevation, North MezzanineFloor*Fire Zone 9.1 - Unit 1 Turbine Building 595 Feet Elevation, Diesel Generator*Fire Zone 9.2 - Unit 2 Turbine Building 595 Feet Elevation, Diesel Generator*Fire Zone 17.1.1 - Unit 1 Main Transformer 595 Feet Elevation

• Fire Zone 17.1.2 - Unit 1 Auxiliary Transformer 595 Feet Elevation*Fire Zone 17.1.3 - Unit 1 Reserve Auxiliary Transformer 595 Feet Elevation *Fire Zone 17.2.1 - Unit 2 Main Transformer 595 Feet Elevation

• Fire Zone 17.2.2 - Unit 2 Auxiliary Transformer 595 Feet Elevation*Fire Zone 17.2.3 - Unit 2 Reserve Auxiliary Transformer 595 Feet Elevation

b. Findings

No findings of significance were identified..2Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed a fire drill conducted in the turbine building on the 611 footelevation. The drill was observed to evaluate the readiness of the plant fire brigade tofight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the dr ill debrief, and took appropriatecorrective actions. Specific attributes evaluated included:

5*Proper wearing of turnout gear and self-contained breathing apparatus *Proper use and layout of fire hoses

• Employment of appropriate fire fighting techniques

• Transporting sufficient fire fighting equipment to the scene

• Effectiveness of fire brigade leader communications, command, and control

• Effectiveness of search for victims and propagation of the fire

• Smoke removal operations

• Utilization of pre-planned strategies *Adherence to the pre-planned dr ill scenario*Accomplishment of drill objectives

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

The inspectors reviewed the licensee's program for inspecting, cleaning, andmaintaining the residual heat removal service water intake bay. This item was chosen for inspection because this bay supplies water to the safety related service water systems used to remove heat from the residual heat removal system, the emergencydiesel generators, and the emergency core cooling system equipment rooms. Theinspectors observed the as-found inspection of the intake bay including visual inspections of the separation screens, the 1/2 B fire diesel pump strainer, and the residual heat removal service water system intake piping. The inspectors focused onidentifying areas where river water debris, silt, or zebra mussels had accumulated and blocked the flow of water to the safety related equipment served by the bay. In addition, the inspectors witnessed an inspection of the concrete structures which form the bay and verified that the concrete had not degraded to a point where the structural integrityof the bay was jeopardized. The inspectors also reviewed prior inspection results and compared them to the as-found inspection results to determine whether the bay conditions were as expected. After the bay was cleaned, the inspectors observed the as-left inspection of the bay to ensure that the debris had been removed and that the equipment served by the bay would continue to perform its safety function.This inspection represented the completion of one annual heat sink inspection sample.

b. Findings

No findings of significance were identified.

61R08Inservice Inspection Activities (71111.08)

a. Inspection Scope

From March 20 to 23, 2006, the inspectors conducted a review of the implementationof the licensee's inservice inspection activities program for monitoring degradation of the reactor cool ant system boundary and the risk significant pipi ng syst emboundaries during the Unit 2 outage (Q2R18). The inspectors selected the American Society of Mechanical Engineers Boiler and Pressure Vessel Code Section XI required examinations and Code components in order of risk priority as identified in Section 71111.08-02 of IP 71111.08, "Inservice Inspection Activities," based upon the inservice inspection activities available for review during the onsite inspection period.The inspectors conducted an onsite review of the following types of nondestructiveexamination activities to evaluate compliance with the American Society of Mechanical Engineers Code Section XI and Section V requirements and to verify that indications and defects (if present) were dispositioned in accordance with the American Society of Mechanical Engineers Code Section XI requirements. Specifically, the inspectors observed/reviewed the following examinations:*Ultrasonic examination of a pipe-to-elbow weld (weld 2B-RH-1006C-4), residualheat removal*Ultrasonic examination of a elbow-to-pipe weld (weld 2B-RH-1006C-3), residualheat removal*Magnetic Particle examination of the 2A residual heat removal riser clamp lugwelds (1008A-W-203A)*Liquid Penetrant examination of the 2A residual heat removal riser clamp lugwelds (1024A-W-201A)The inspectors reviewed an examination with recordable indications that was acceptedfor continued service to verify that the licensee's acceptance was in accordance with the American Society of Mechanical Engineers Code or an NRC approved alternative. Specifically, the inspectors reviewed the following record:*Report No. Q2R17-085, automated ultrasonic examination of the ReactorPressure Vessel N2A Nozzle, six acceptable indications were recorded which were found to have no determinable throughwall dimensions and were acceptable to the requirements of American Society of Mechanical Engineers IWB-3000There were no pressure boundary welds for Class 1 or 2 systems completed by thelicensee; and hence, the inspectors did not perform the step of the inspection procedurethat verifies that the welding process and welding examinations were performed inaccordance with American Society of Mechanical Engineers Code requirements or an

NRC approved alternative.

7The inspectors performed a review of inservice inspection related problems that wereidentified by the licensee and entered into the corrective action program. Additionally, the inspectors' review included confirmation that the licensee had an appropriate threshold for identifying issues and had implemented effective corrective actions. The inspectors evaluated the threshold for identifying issues through interviews with licensee staff and review of licensee actions to incorporate lessons learned from industry issues related to the inservice inspection program. The inspectors performed these reviews to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action,"

requirements. The corrective action documents reviewed by the inspectors are listed in the attachment to this report. In addition, the inspectors verified that the licensee correctly assessed operating experience for applicability to the inservice inspectiongroup. The reviews as discussed above counted as one inspection sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11Q)

a. Inspection Scope

On January 30, 2006, the inspectors observed operations crews in the simulator. Theobserved scenario consisted of reactor power increase using reactor recirculation flow, a failed feedwater flow transmitter, and a loss of stator water cooling.The inspectors evaluated crew performance in the areas of:

• Clarity and formality of communications*Ability to make timely actions in the safe direction

• Prioritization, interpretation, and verification of alarms

• Procedure use

• Control board manipulations

• Oversight and direction from supervisors

• Group dynamics Crew performance in these areas was compared to licensee management expectations and guidelines as presented in the following documents:*OP-AA-101-111, "Rules and Responsibilities of On-Shift Personnel"*OP-AA-103-102, "Watchstanding Practices"

• OP-AA-103-104, "Reactivity Management Controls"

• OP-AA-104-101, "Communications"The inspectors verified that the crews completed the critical tasks listed in the abovescenarios. If critical tasks were not met, the inspectors verified that crew and operator 8performance errors were detected and adequately addressed by the evaluators. Theinspectors verified that the evaluators effectively identified crews requiring remediationand appropriately indicated when removal from shift activities was warranted. Lastly, the inspectors observed the licensee's critique to verify that weaknesses identified during this observation were noted by the evaluators and discussed with the respective crews.This inspection represented the completion of one quarterly sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors reviewed documentation associated with the four maintenance rulefunctions listed below and compared the information to industry guidance to ensure that the functions had been appropriately scoped into the maintenance rule program. Once the scoping was verified, the inspectors reviewed the licensee's performance criteria and performed simple calculations to verify that the criteria would meet pre-established reliability/availability goals provided in the licensee's probabilistic risk assessment. Theinspectors then performed searches of the licensee's corrective action program database, open maintenance work documents, and control room logs to identify maintenance work practice issues, common cause issues, or equipment issues which impacted the maintenance rule availability or reliability for the functions inspected. Theinspectors then performed additional calculations to determine the amount of maintenance rule unavailability associated with each pre-selected sample. The resultsof these calculations were then compared to the licensee's data to ensure thatunavailability was appropriately captured. The inspectors performed a similar review forthose functions which utilized condition monitoring rather than reliability and/oravailability. Functions reviewed incl uded:*Process Radiation Monitoring (Function Z1700)*Residual Heat Removal System (Function Z1000)

• Service Water (Function Z3900)

• Control Rod Drive (Function Z0300)

b. Findings

No findings of significance were identified.

91R13Maintenance Risk Assessments and Emergent Work Evaluation (71111.13)

a. Inspection Scope

The inspectors reviewed the following six activities to verify that the appropriate riskassessments were performed prior to removing equipment for work. The inspectors held discussions with operations, work control, and engineering personnel to verify that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors verified the appropriate use of the licensee's risk assessment tool and risk categories in accordance with procedures.*Work Week February 6-10 which included planned maintenance on the Unit 1emergency diesel generator, the Unit 2 125 Volt battery charger, the 1A and 1B residual heat removal service water pumps, and Bus 23-1 and emergent work on the 1 A and 1 B diesel fire pumps*Work Week February 13-19 which included planned maintenance on the Unit 2high pressure coolant injection system, the Unit 2 125 Volt direct current charger,and Unit 1 station blackout diesel generator*Work Week February 27 through March 5 which included planned maintenanceon the Unit 1D residual heat removal service water system, the Unit 1C residualheat removal system, and emergent work on the 1 A diesel fire pump*Work Week March 6-12 which included planned maintenance on the Unit 2reactor core isolation cooling system, the 1 250 Volt battery charger, the1 A standby gas treatment system, the 2A service water pump, and the1C residual heat removal service water pump *Work Week March 13-18 included surveillance testing of the 1 emergency dieselgenerator and the Unit 2 station blackout emergency diesel generator, and planned maintenance on the Unit 1 low pressure coolant injection supply valves, the 2C circulating water pump, and the 2B residual heat removal service water pump*Work Week March 19-25 included surveillance testing of the Unit 1 emergencydiesel generator, planned maintenance on the 2A residual heat removal room cooler, pre-outage work associated with the refueling outage, and planned work in the switchyard

b. Findings

No findings of significance were identified. However, Issue Reports 468904 and 469454were written as a result of this inspection.

101R14Operator Performance During Non-Routine Evolutions and Events (71111.14)

a. Inspection Scope

The inspectors reviewed the operator performance during the February 22, 2006,unanticipated Unit 1 turbine trip and subsequent reactor scram due to a turbine/generator load reject. The load reject was caused by the actuation of the Unit 1 main power transformer "B" phase differential overcurrent relay. The inspectors verified that the operators entered the appropriate procedures and determined that the reactorscram was initiated and addressed without complications. The inspectors also conducted interviews and reviewed operator logs, plant computer data, and various strip charts to determine that the operators and equipment responded appropriately during the non-routine evolution. In addition, the inspectors verified that the reactor wasoperated and maintained in a safe shutdown condition following the event.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

For the operability evaluations listed below, the inspectors evaluated the technicaladequacy of the evaluations by comparing the results to information contained in Technical Specifications and/or the Updated Final Safety Analysis Report to ensure that operability was properly justified and that the subject component or system remainedavailable to perform its intended function. *Issue Report 444345 - Control Rod Drive 42-47 Notched to 46 and Was Not Ableto be Withdrawn*Operability Evaluation 244267-02, Revision 3 - 1 A Diesel Fire Pump Unable toSupply All Fire Suppression Systems in Plant if 1 B Fire Pump Out of Service *Issue Report 438650 - Unit 1 B Core Spray Pump Breaker Tripped ImmediatelyWhen Starting*Issue Report 463220 - Component Issues Identified During 4 Hour Load Test -1 250 Volt direct current Battery Charger*Operability Evaluation 337433-02, Revision 0 - Reactor Vessel Level Narrow andWide Range InstrumentationIn addition, the inspectors reviewed any compensatory measures implemented to verifythat the measures worked as stated and that the measures were adequately controlled. The inspectors also reviewed a sampling of issue reports to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Thisinspection represented the completion of five samples.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications (71111.17)

a. Inspection Scope

During the inspection period, the inspectors reviewed the following permanent plantmodification:*Engineering Change 358944; "Unit 2 Electromatic Relief Valve GuidePost Beveled Washer Modification," Revisions 0, 1, and 2 (Engineering Change 358947; Revisions 0 and 1, is the equivalent change for Unit 1)The inspectors reviewed the design adequacy of the modifications by verifying one ormore of the following:*Energy requirements were able to be supplied by supporting system s underaccident and event conditions*Replacement components were compatible with physical interfaces

• Replacement component properties met functional requirements under eventand accident conditions*Replacement components were environmentally and seismically qualified

• Sequence changes remained bounded by the accident analyses and loading onsupport systems was acceptable*Structures, systems, and components response times were sufficient to serveaccident and event functional requirements assumed by the design analyses *Control signals were appropriate under accident and event conditions

• Affected operations procedures were revised and training needs were evaluatedin accordance with station administrative proceduresThe inspectors verified that the post modification testing demonstrated systemoperability by verifying no unint ended system interactions occurred, system performancecharacteristics met the design basis, and post-modification testing results met all acceptance criteria. The inspectors also reviewed issue reports related to permanent plant modifications to ensure that the licensee was entering issues into its corrective action program at an appropriate threshold. The review represented the completion of one inspection sample.

b. Findings

No findings of significance were identified 121R19Post Maintenance Testing (71111.19)

a. Inspection Scope

The inspectors reviewed the five post-maintenance tests listed below to verify thatprocedures and test activities ensured system operability and functional capability. The inspectors reviewed the licensee's test procedure to verify that the procedure adequately tested the safety function(s) that may have been affected by the maintenance activity, that the acceptance criteria in the procedure were consistentwith information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed the test data, to verify that test results adequately demonstrated restoration of the affected safety function(s).*Work Order 850917-01 - 1 Diesel Generator Tach and Speed Sensing Switches*Work Request 200332 - 1 B Fire Diesel Loss of Coolant/Overheating

• Work Order 777072 - Replace 1 A Diesel Fire Pump and Issue Report450390 - High Vibration Amplitudes on Right Angle Drive*Work Order 845414 - Repack Reactor Water Cleanup Valve 1-1201-5

• Work Order 590322 - 1D Residual Heat Removal Service Water Pump MotorInspection

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities (71111.20).1Maintenance Outage and Forced Outage Activities

a. Inspection Scope

As discussed in the Summary of Plant Status Section of this report the licenseeconducted three maintenance outages to address ERV actuator degradation concerns. The outages began on January 6 (Unit 1), January 13 (Unit 2), and January 15 (Unit 1).

An additional outage occurred on February 22 following a Unit 1 reactor scram. During the outages, the inspectors performed the following activities daily:*Attended control room operator and/or outage management turnover meetings toverify that the current shutdown risk status was well understood and communicated*Performed walkdowns of the main control room to observe the alignment ofsystems important to shutdown risk*Reviewed selected issues that the licensee entered into its corrective actionprogram to verify that identified problems were being entered into the program with the appropriate characterization and significance 13Additionally, the inspectors observed the following specific activities, as appropriate:*Shutdown and cooldown activities*Troubleshooting efforts associated with equipment other than the ERVs*Reactor startup and power ascensionIssue Report 461761 was initiated as a result of this inspection. These inspectionsrepresented the completion of four outage inspection samples.

b. Findings

No findings of significance were identified..2Unit 2 Refueling Outage

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (offsite power) and contingency plansfor the Unit 2 refueling outage, which began on March 24, to confirm that the licenseehad appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the refueling outage, the inspectors observed portions of the shutdownand cooldown processes and monitored licensee controls over the outage activities listed below. *Licensee configuration management, including maintenance of defense-in-depthcommensurate with the offsite power for key safety functions and compliance with the applicable Technical Specification when taking equipment out of service*Implementation of clearance activities and confirmation that tags were properlyhung and equipment appropriately configured to safely support the work or testing*Installation and configuration of reactor coolant pressure, level, and temperatureinstruments to provide accurate indication and an accounting for instrument error*Controls over the status and configuration of electrical systems to ensure thatTechnical Specification and outage safety plan requirements were met, and controls over switchyard activities*Monitoring of decay heat removal processes

• Controls to ensure that outage work was not impacting the ability of theoperators to operate the spent fuel pool cooli ng syst em*Reactor water inventory controls including flow paths, configurations, andalternative means for inventory addition, and controls to prevent inventory loss*Controls over activities that could affect reactivity

• Maintenance of secondary containment as required by Technical Specification

• Refueling activities, including fuel handling and sipping to detect fuel assemblyleakage*Licensee identification and resolution of problems related to refueling outageactivities 14This inspection was not counted as a completed inspection sample since the outagewas ongoing at the conclusion of the inspection period.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors witnessed eight surveillance tests and/or reviewed test data of selectedrisk-significant structures, systems, and components listed below, to assess, asappropriate, whether the structures, systems, and components met the requirements ofthe Technical Specification; the Updated Final Safety Analysis Report; and American Society of Mechanical EngineersSection XI. The inspectors also determined whether the testing effectively demonstrated that the structures, systems, and components wereoperationally ready and capable of performing their intended safety functions.*QCIS 1300-03 - Reactor Core Isolation Cooling Steam Line High FlowCalibration and Functional Test*QCOS 1400-01 - Quarterly Core Spray System Flow Rate Test (Unit 1 "B")

• MA-QC-IM-1-13101 - Unit 1 Reactor Core Isolation Cooling Low ReactorPressure Isolation Calibration and Functional Test*QCOS 2300-06 - High Pressure Coolant Injection System Power Operated ValveTest*QCOS 2300-10 - High Pressure Coolant Injection Pump Discharge Flow SwitchCalibration and Functional Test*QCOS 2300-11 - Contaminated Condensate Storage Tank/Torus Level SwitchFunctional Test*QCOS 2300-12 - High Pressure Coolant Injection Motor Operated LocalController Test*QCOS 2300-15 - High Pressure Coolant Injection Drain Pot Level Switch, DrainValve, Gland Seal Condenser High Level Alarm, and Steam Line Drain Functional Verification

b. Findings

No findings of significance were identified.

15Cornerstone: Emergency Preparedness1EP6Drill Evaluation (71114.06)

a. Inspection Scope

Resident inspectors evaluated the conduct of a routine licensee emergency drill onFebruary 21, 2006, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulated control room to verify that event classification and notifications were done in accordance with procedures. The inspectors also attended the licensee critique of the drill to compareany inspector-observed weakness with those identified by the licensee in order to verify whether the licensee was properly identifying failures.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES

4OA1 Performance Indicator Verification

a. Inspection Scope

Cornerstone: Initiating Events The inspectors sampled the licensee's records associated with the three initiating eventsperformance indicators listed below. The inspectors used definitions and guidance contained in Revision 3 of Nuclear Energy Institute Document 99-02, "Regulatory Assessment Performance Indicator Guideline," to verify the accuracy of the performance indicator data reported to the NRC. Specifically, the inspectors reviewed licensee records associated with performance indicator data reported for the period of January 2004 through December 2005. Reviewed records included: licensee event reports, operating logs, NRC inspection reports, and issue reports. The following sixperformance indicators were reviewed:*Unit 1 and Unit 2 Unplanned Scrams per 7000 Critical Hours*Unit 1 and Unit 2 Scrams with Loss of Normal Heat Removal

• Unit 1 and Unit 2 Unplanned Transients per 7000 Critical Hours

b. Findings

No findings of significance were identified.

164OA2Identification and Resolution of Problems (71152).1Review of Items Entered into the Corrective Action ProgramAs required by Inspection Procedure 71152, Identification and Resolution of Problems,and in order to help identify repetitive equipment failures or specific human performance issues for followup, the inspectors performed screening of all items entered into the licensee' corrective action program. This was accomplished by reviewing the description of each new issue report and attending daily management review committee meetings.4OA3Event Followup (71153).1(Closed) Licensee Event Report 05000254/05-006; 05000265/05-006: Failure of theControl Room Emergency Ventilation Air Conditioning Compressor Due to a Manufacturing Defect in an Electrical Relay. On November 30, 2005, the "B" Control Room Emergency Ventilation Air Conditioning compressor failed during monthly testing.

The licensee determined that the compressor failed due to an electrical relay in the unloading circuit failing to de-energize once a compressor low suction pressurecondition was reached. In response to this event, the licensee sent the failed relay off for further analysis, replaced the failed relay, and completed repairs to the compressor.

Subsequent analysis showed that the relay failed to de-energize due to a manufacturing defect. This licensee event report was reviewed by the inspectors and no findings of significance or violations were identified. This issue was previously documented in Inspection Report 05000254/2005006; 05000265/2005006..2(Closed) Licensee Event Report 05000254/05-002; 05000265/05-002: Main SteamRelief Valve Actuator Degradation. This licensee event report was submitted to describe degradation of the ERV actuators which resulted in multiple shutdowns between December 30, 2005, and January 19, 2006. As discussed in previous sections of this report, the NRC also performed a special inspection of the ERV actuator issues.The results of this inspection were documented in Inspection Report 05000254/2006009; 05000265/2006009. The results included the initiation of an unresolved item to address any potential performance deficiencies and findings that were identified following the completion of the licensee's root cause efforts. The inspectors reviewed the event report and determined that no new information was provided. As a result, the inspectors closed this event report to Unresolved Item 05000254/2006009-01; 05000265/2006009-01.

4OA5Other Activities.1(Closed) Unresolved Item 05000265/2005006-02: Adequacy of Risk AssessmentAssociated with Unit 2 Electromatic Relief Valves. On January 26, 2006, the inspectors were provided with the licensee's analysis of the discrepancies identified between the licensee's risk assessment tool and anticipated transient without scram analysis of record. The licensee's analysis concluded that although the anticipated transientwithout scram analysis of record required 13 valves to function during an anticipated 17transient without scram event, it was appropriate that the risk assessment tool onlyrequired 12 of 13 valves to function following an anticipated transient without scram for the following reasons:*The licensing calculation which required the 13 valves was overly conservative*The peak vessel pressure experienced during anticipated transient withoutscram conditions with only 12 of 13 valves operating increased by only 17 psig*There was approximately 25 psig of conservatism added to the computer codesused to calculate the peak vessel pressure during an anticipated transient without scram event*The computer codes used to calculate the peak vessel pressure following ananticipated transient without scram event utilized the reaction time for poweroperated relief valves rather than ERVs. This resulted in a higher peak vessel pressure since the power operated relief valves operated slower than the ERVsThe inspectors reviewed the licensee's analysis and discussed the results with aregional senior reactor analyst and maintenance rule risk assessment individuals.

Through these discussions the inspectors concluded that the licensee's initial ERV risk assessment completed on December 21, 2005, was acceptable.

.2 (Closed) Unresolved Item 05000254/2005006-03; 05000265/2005006-03:

PotentialInoperability of Multiple Electromatic Relief Valves. On January 9, 2006, the NRCinitiated a Special Inspection to evaluate the licensee's effectiveness in identifying and correcting the deficiencies which led to the degradation of multiple ERV actuators. As part of this inspection, the Special Inspection Team was tasked with determining the number of ERVs which would have been unable to perform their safety function. At the conclusion of the Special Inspection, the licensee had not completed the analysisneeded to determine the number of ERVs that were non-functional. As a result, the Special Inspection Team initiated Unresolved Item 05000254/2006009-01; 05000265/2006009-01 to evaluate the adequacy of the licensee's analysis upon completion. This unresolved item is being closed since the subject of the item will be captured by the item identified during the Special Inspection..3(Closed) Unresolved Item 05000254/2005003-02; 05000265/2005003-02: BatteryRoom Ventilation System Heater Currents. The inspectors obtained the minimum licensing and design temperatures for the battery rooms, battery electrolyte, the turbine building and outside air temperatures. Using this information, the inspectors completed a simple calculation (similar to one performed previously by the licensee) and concluded that the battery room ventilation system would remain operable and support continuedbattery operability during worst case outside air temperature conditions. The results ofthis calculation were then used to conclude that the licensee's initial maintenance rule (a)(1) classification made in October 2004 was appropriate.

18.4Implementation of Temporary Instruction 2515/165 - Operational Readiness of OffsitePower and Impact on Plant Risk

a. Inspection Scope

The objective of Temporary Instruction 2515/165, "Operational Readiness of OffsitePower and Impact on Plant Risk," was to confirm, through inspections and interviews, the operational readiness of offsite power systems in accordance with NRCrequirements. On March 20 through 23, 2006, the inspectors reviewed licensee procedures and discussed the attributes identified in Temporary Instruction 2515/165 with licensee personnel. In accordance with the requirements of Temporary Instruction 2515/165, the inspectors evaluated the licensee's operating procedures usedto assure the functionality/operability of the offsite power system, as well as, the riskassessment, emergent work, and/or grid reliability procedures used to assess theoperability and readiness of the offsite power system.The information gathered while completing this temporary instruction was forwarded tothe Office of Nuclear Reactor Regulation for further review and evaluation.

b. Findings

No findings of significance were identified.4OA6Meetings.1Exit MeetingThe inspectors presented the inspection results to Mr. T. Tulon and other members oflicensee management at the conclusion of the inspection on April 4, 2006. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Interim Exit MeetingsInterim exits were conducted for:

• Inservice inspection (Inspection Procedure 71111.08) with Mr. T. Tulon onMarch 23, 2006.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

T. Tulon, Site Vice President

R. Gideon, Plant Manager

R. Armitage, Training Manager

D. Barker, Work Control Manager

W. Beck, Regulatory Assurance Manager

D. Craddick, Maintenance Manager

D. Moore, Nuclear Oversight Manager

K. Moser, Deputy Engineering Manager

V. Neels, Chemistry/Environ/Radwaste Manager

K. Ohr, Radiation Protection Manager

M. Perito, Operations ManagerNuclear Regulatory Commission personnel

M. Ring, Chief, Reactor Projects Branch 1

M. Banerjee, NRR Project M

anager

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Closed

05000254/05-006LERFailure of the Control Room Emergency Ventilation Air

05000265/05-006Conditioning Compressor Due to a Manufacturing Defectin an Electrical Relay (Section 4OA3.1)05000254/05-002LERMain Steam Relief Valve Actuator Degradation05000265/05-002(Section 4OA3.2)05000265/2005006-02URIAdequacy of Risk Assessment Associated with Unit 2Electromatic Relief Valves (Section 4OA5.1)05000254/2005006-03URIPotential Inoperability of Multiple Electromatic Relief

05000265/2005006-03Valves (Section 4OA5.2)05000254/2005003-02URIBattery Room Ventilation System Heater Currents05000265/2005003-02(Section 4OA5.3)2515/165TIOperational Readiness of Offsite Power and Impact onPlant Risk (Section 4OA5.4)

2

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