IR 05000282/2006002

Download: ML061320461

Text

May 11, 2006

EA 05-231 Mr. T. PalmisanoSite Vice President Prairie Island Nuclear Generating Plant Nuclear Management Company, LLC 1717 Wakonade Drive East Welch, MN 55089

SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000282/2006002;05000306/2006002

Dear Mr. Palmisano:

On March 31, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed an integratedinspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on April 13, 2006, with you and other members of your staff. This 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.On the basis of 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/Richard A. Skokowski, ChiefBranch 3 Division of Reactor Projects Docket Nos. 50-282; 50-306License Nos. DPR-42; DPR-60

Enclosure:

Inspection Report 05000282/2006002; 05000306/2006002

w/Attachment:

Supplemental Information See Attached Distribution DOCUMENT NAME:E:\Filenet\ML061320461.wpdG Publicly AvailableG Non-Publicly AvailableG SensitiveG 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 copyOFFICERIIINAMERSkokowski:dtpDATE05/11/06OFFICIAL RECORD COPY T. Palmisano-2-cc w/encl:C. Anderson, Senior Vice President, Group OperationsM. Sellman, Chief Executive Officer and Chief Nuclear Officer Regulatory Affairs Manager J. Rogoff, Vice President, Counsel & Secretary Nuclear Asset Manager Tribal Council, Prairie Island Indian Community Administrator, Goodhue County Courthouse Commissioner, Minnesota Department of Commerce Manager, Environmental Protection Division Office of the Attorney General of Minnesota T. Palmisano-3-ADAMS Distribution:MLC RidsNrrDirsIrib GEG KGO JTA CAA1 LSL (electronic IR's only)

C. Pederson, DRS (hard copy - IR's only)

DRPIII DRSIII PLB1 JRK1 ROPreports@nrc.gov (inspection reports, final SDP letters, any letter with an IR number)

EnclosureU.S. NUCLEAR REGULATORY COMMISSIONREGION IIIDocket Nos:50-282; 50-306License Nos:DPR-42; DPR-60Report No:05000282/2006002; 05000306/2006002 Licensee:Nuclear Management Company, LLC Facility:Prairie Island Nuclear Generating Plant, Units 1 and 2Location:1717 Wakonade Drive East Welch, MN 55089Dates:January 1 through March 31, 2006 Inspectors:J. Adams, Senior Resident InspectorD. Karjala, Resident Inspector M. Mitchell, Radiation SpecialistApproved by:R. Skokowski, ChiefBranch 3 Division of Reactor Projects Enclosure1

SUMMARY OF FINDINGS

IR 05000282/2006002, 05000306/2006002; 1/01/06 - 3/31/06; Prairie Island NuclearGenerating Plant, Units 1 and 2. This report covers a 3-month period of baseline resident inspection and announced baselineinspection on radiation protection and emergency preparedness. The inspection was conducted by the resident inspectors and inspectors from the Region III office. No findingswere 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 safe operation ofcommercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process,"Revision 3, dated July 2000.A.Inspector-Identified and Self-Revealed FindingsNone

B.Licensee-Identified Violations

Two violations of very low safety significance, which were identified by the licensee,have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. This violation and the licensee's corrective action tracking numbers are listed in Section 4OA7.

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REPORT DETAILS

Summary of Plant StatusUnit 1 operated at or near full power throughout the inspection period except that power wasreduced to about 65 percent on January 17, 2006, for condenser tube repairs and cleaning. The unit was returned to 100 percent power on January 22, 2006, where it operated for the remainder of the inspection period.Unit 2 operated at or near full power throughout the inspection period except that power wasreduced to about 98 percent from January 11, 2006, until January 18, 2006, during replacementof the Emergency Response Computer System. On February 5, 2006, Unit 2 was shut down as required by Technical Specifications (TS) due to the inoperability of diesel generator D6 causedby high crankcase pressure. The diesel generator was repaired and the unit returned to 100 percent power on February 22, 2006. The unit operated at or near 100 percent power forthe remainder of the inspection period.1.REACTOR SAFETYCornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity1R04Equipment Alignment (71111.04)

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed three partial system equipment alignment inspection samplescomprised of in-plant walkdowns of accessible portions of trains of risk-significant equipment associated with the mitigating systems and barrier integrity cornerstones. The inspectors conducted the inspections during times when the trains were of increased importance due to the redundant trains or other related equipment beingunavailable. The inspectors also reviewed documents entering deficient conditions associated with equipment alignment issues into the corrective action program (CAP)verifying that the licensee was identifying issues at an appropriate threshold and entering those issues into their corrective action program in accordance with the fleet corrective action procedures.The inspectors utilized the valve and electric breaker checklists, where applicable, toverify that the components were properly positioned and that support systems werelined up as needed. The inspectors also examined the material condition of the components and observed operating parameters of equipment to verify that there wereno obvious performance deficiencies. The inspectors reviewed outstanding work orders (WOs) and CAPs associated with the operable trains to verify that those documents did not reveal issues that could affect the completion of the available train's safety functions.

The inspectors used the information in the appropriate sections of the Updated Safety Analysis Report (USAR) to determine the functional requirements of the systems.

3The inspectors verified the alignment of the following trains: *D2 diesel generator during the unavailability of the D1 diesel generator forplanned maintenance on January 23, 2006;*D5 diesel generator during the unavailability of the D6 diesel generator forpreventive maintenance on January 31, 2006; and*121 control room special ventilation system during the unavailability of the122 control room special ventilation system on March 6, 2006. Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

During the week of January 22, 2006, the inspectors performed a detailed in-plantwalkdown of the alignment and condition of the Unit 1 auxiliary feedwater system. Theauxiliary feedwater system is a risk-significant and safety-related mitigating system thatprovides a heat sink to remove decay heat from the reactor coolant system during off-normal and accident conditions. This inspection effort constituted one complete systemalignment inspection sample. In addition, the inspectors reviewed CAPs associated with equipment alignment issues to verify that the licensee was identifying issues at anappropriate threshold and entering them into their corrective action program in accordance with fleet corrective action procedures.The inspectors conducted in-plant walkdowns using the applicable alignment checklistsand plant drawings to verify that system components were properly positioned tosupport the completion of system safety functions and to verify that the as-found systemconfiguration matched the configuration specified in the system alignment checklist andplant drawings. The inspectors examined the material condition of the components, such as pumps, motors, valves, instrumentation, controls, bus relay settings, and electrical panels. The inspectors observed operating parameters of equipment to verify that there were no obvious performance deficiencies and examined all applicable outstanding design issues, temporary modifications, and operator workarounds (OWAs).

The inspectors verified that tagging clearances were appropriate and attached to the specified equipment where applicable. The inspectors reviewed outstanding WOs and CAPs associated with the trains to determine if any degraded conditions existed that could affect the accomplishment of the system's safety functions. The inspectors referred to the TS, USAR, and other design basis documents to determine the functional requirements of the systems and verified those functions could be performed if needed. Key documents used by the inspectors in conducting this inspection are listed in the

to this inspection report.

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b. Findings

No findings of significance were identified.1R05Fire Protection Area Walkdowns (71111.05)

a. Inspection Scope

The inspectors conducted in-office and in-plant reviews of portions of the licensee's FireHazards Analysis and Fire Strategies to verify consistency between these documentsand the as-found configuration of the installed fire protection equipment and features inthe fire protection areas listed below. The inspectors selected fire areas for inspection based on their overall contribution to internal fire risk as documented in the Individual Plant Examination of External Events (IPEEE), their potential to impact equipment which could initiate a plant transient, or their impact on the plant's ability to respond to asecurity event. The inspectors assessed the control of transient combustibles and ignition sources, the material and operational condition of fire protection systems andequipment, and the status of fire barriers. In addition, the inspectors reviewed CAPs associated with fire protection issues to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with fleet corrective action procedures. The following nine fire areas were inspected by in-plant walkdowns supporting thecompletion of nine fire protection zone walkdown samples:*Fire Area 25, D1 diesel generator room, on January 18, 2006;*Fire Area 31, auxiliary feedwater pump room, on January 17, 2006;*Fire Area 32, auxiliary feedwater pump room, on January 17, 2006;*Fire Area 41A, diesel-driven cooling water pump area, on January 19, 2006;

• Fire Area 41B, screenhouse below grade, on January 19, 2006;

• Fire Area 81, bus 15 room, on January 18, 2006;

• Fire Area 113, D5 day tank room, on January 18, 2006;

• Fire Area 115, D5 lubricating oil make-up tank room, on January 18, 2006; and

• Fire Area 117, bus 25 room, on January 19, 2006.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.

b. Findings

No findings of significance were identified.1R06Flood Protection Measures (71111.06)

a. Inspection Scope

The inspectors performed an in-office review of the most recently completedsurveillance procedure for the inspection of plant flooding barriers and the abnormal procedure for flooding. The contents of these documents were compared to the plant

5flood protection design sections in the USAR and the assumption contained in theIPEEE associated with an external flooding event. This inspection effort completed one annual external flood protection inspection sample.The inspectors performed an in-plant inspection of flood protection barriers in theauxiliary building, turbine building, D5/D6 building, and the intake screenhouse duringthe period of March 6 through 29, 2006, comparing the as-found conditions of the flood protection panels against the acceptance criteria in the surveillance procedure. Theinspectors also verified that the actions specified in the abnormal procedure for flooding could be performed in a timely manner (3 days) if required, and the necessary hardware and consumable materials were available and still within their shelf life. The inspectors reviewed several CAP items to verify that minor deficiencies identifiedduring this inspection were entered into the licensee's corrective action program, that problems associated with plant equipment relied upon to prevent or minimize flooding were identified at an appropriate threshold, and that corrective actions commensurate with the significance of the issue were identified and implemented. As part of this inspection, the inspectors reviewed the documents listed in the Attachment.

b. Findings

On March 29, 2006, the inspectors visited the main warehouse to verify the existence ofthe flood protection materials listed in Table 1 of Surveillance Procedure 1293,"Inspection of Flood Control Measures," Revision 13. All the listed materials were found by inspectors but the Deck-O-Seal Gun Grade sealant was found 1 year beyond its shelf life expiration date. Deck-O-Seal Gun Grade sealant is necessary during an exterior flood event to sealeight exterior doors for the turbine, auxiliary, and Unit 2 diesel generator buildings inaccordance with the flood bulkhead installation instruction in Abnormal Operating Procedure AB-4, Attachment J, Figure J-1. In addition, AB-4 also specifies the use of the sealant to seal any gaps on the 11 exterior flood protection panels for the turbine building, auxiliary building, screenhouse, and Unit 2 diesel generator building inaccordance with AB-4, Figure J-2. These doors and panels provide a flood barrier that protects plant safety-related equipment located at or below the 695 foot (above meansea level) elevation. The condition of the Deck-O-Seal Gun Grade sealant found by the inspectors was not inaccordance Surveillance Procedure 1293, Step 7.2.7.C. This was an annual inspectionthat was completed by the licensee on February 17, 2006. Step 7.2.7.C specifies thatthe performer of the flood control measures inspection inform warehouse personnel to order four new kits of the sealant and to dispose of the expired shelf life sealant. This step was signed off as completed. However, upon inspection of the material in the warehouse, the inspectors noted a hand written date of March 2005 written on thesealant kits. The licensee's Shelf Life Program procedure FP-SC-PE-05, Revision 0, Step 3.7.2, requires the identifying and labeling of age-sensitive items with a shelf lifeexpiration date on the attached part tag or quality tag as appropriate. Assuming that the licensee had followed their Shelf Life Program requirement to label the material with the expiration date, the inspectors concluded that the sealant was one year beyond its

6expiration date. The inspectors requested additional documentation that would confirmthe manufacture or purchase date but was told by the licensee that no additional purchase documentation could be located.The inspectors noted that the licensee had failed to follow the Self Life Program asrequired by procedure FP-SC-PE-05. Step 5.3.1 states that the receipt of the sealantand its corresponding self life shall be entered into the Material Management System database. The licensee determined that the Deck-O-Seal Gun Grade sealant had notbeen entered into Material Management System database. This failure resulted in the sealant exceeding its shelf life by one year.Finally, the inspector concluded that Surveillance Procedure 1293, Step 7.2.7.C wasinadequate as written since it only required personnel performing the flood control measures inspection to notify warehouse personnel to order new sealant kits and dispose of the outdated material. There was no action to track the actual completion of the step (ie; the actual receipt of new and the disposal of the expired sealant).The inspectors reviewed the issue for significance using the guidance provided inInspection Manual Chapter 0612, Appendix B, dated September 30, 2005. Theinspectors concluded that the issue was a performance deficiency since the warehouse personnel failed to enter the receipt of the material and its associated shelf life into the Material Management System database as required by procedure FP-SC-PE-05, and failed to reorder the Deck-O-Seal Gun Grade sealant when informed to do so by personnel performing Surveillance Procedure 1293.The inspectors reviewed the examples of minor findings provided in Inspection ManualChapter 0612, Appendix E, dated September 30, 2005, and concluded that none of theexamples closely matched this finding. The inspectors then used the minor questions presented in Inspection Manual Chapter 0612, Appendix B, Section 3. The inspectors concluded that the performance deficiency may be minor if the expired sealant was tested and satisfactory performance was demonstrated. The inspectors discussed the potential significance of this issue with the licensee and was later informed by the licensee that they were planning to test of the expired sealant. This issue is being considered an Unresolved Item (URI 05000282/2006002-01; 05000306/2006002-01)pending completion of the expired sealant performance test.1R11Licensed Operator Requalification (71111.11)

.1 Quarterly Observation of Licensed Operator Requalification Simulator Training

a. Inspection Scope

On January 30, 2006, the inspectors performed a quarterly review of licensed operatorrequalification training in the simulator, completing one licensed operator requalification inspection sample. The inspectors observed a crew during an evaluated exercise in the plant's simulator facility. The inspectors compared crew performance to licenseemanagement expectations. The inspectors verified that the crew completed all of the critical tasks for each exercise scenario. For any weaknesses identified, the inspectors

7observed that the licensee evaluators noted the weaknesses and discussed them in thecritique at the end of the session.The inspectors assessed the licensee's effectiveness in evaluating the requalificationprogram ensuring that licensed individuals would operate the facility safely and withinthe conditions of their licenses; and evaluated licensed operator mastery of high-risk operator actions. The inspection activities included, but were not limited to, a review of high-risk activities, emergency plan performance, incorporation of lessons learned, clarity and formality of communications, task prioritization, timeliness of actions, alarm response actions, control board operations, procedural adequacy and implementation, supervisory oversight, group dynamics, interpretations of TS, simulator fidelity, and licensee critique of performance.

b. Findings

No findings of significance were identified.1R12Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors reviewed repetitive maintenance activities to assess maintenanceeffectiveness, including maintenance rule (10 CFR 50.65) activities, work practices, and common cause issues. The inspectors performed two issue/problem-oriented maintenance effectiveness samples. The inspectors assessed the licensee's maintenance effectiveness associated with problems on the following structures, systems, and components: *station and instrument air compressors, and*containment spray system.The inspectors conducted in-office reviews of the licensee's maintenance ruleevaluations of equipment failures for maintenance preventable functional failures and equipment unavailability time calculations, comparing the licensee's evaluationconclusions to applicable Maintenance Rule (a)1 performance criteria. Additionally, the inspectors reviewed scoping, goal-setting (where applicable), performance monitoring, short-term and long-term corrective actions, functional failure definitions, and current equipment performance status.The inspectors reviewed CAPs for significant equipment failures associated with risk-significant and safety-related mitigating equipment to ensure that those failures wereproperly identified, classified, and corrected. The inspectors reviewed other CAPs to assess the licensee's problem identification threshold for degraded conditions, the appropriateness of specified corrective actions, and that the timeliness of the implementation of corrective actions were commensurate with the safety significance of the identified issues. Key documents used by the inspectors in conducting this inspection are listed in the Attachment to this report.

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b. Findings

No findings of significance were identified.1R13Maintenance Risk Assessments and Emergent Work Control (71111.13)

a. Inspection Scope

The inspectors conducted in-plant walkdowns and in-office reviews of risk assessmentsfor two planned maintenance activities and two maintenance activity that involved emergent equipment failures. The inspectors' efforts completed four risk assessmentand emergent work control inspection samples. The following combinations of equipment unavailability were reviewed:*the planned unavailability of diesel generator D2, the 121 instrument aircompressor, the 21 cooling water pump, one of two cooling water supply valves to the instrument air compressors, and the 11 circulating water pump on January 18, 2006;*the emergent failure of the D6 diesel generator with the unavailability of the124 air compressor, and the failure of CV-31876, 21 main feedwater pump recirculation valve on February 5, 2006;*the emergent unavailability of diesel generator D6 with the planned unavailabilityof diesel generator D2 and the 122 safeguards traveling screen on February 13, 2006; and*the planned unavailability of 12 component cooling water pump, 12 componentcooling water heat exchanger, 121 and 122 bypass gates, and the 122 air compressor on March 14, 2006.The inspectors compared the licensee's risk management actions to those actionsspecified in the licensee's procedures for the assessment and management of risk. Theinspectors verified that evaluation, planning, control, and performance of the work weredone in a manner to reduce the risk and minimize the duration where practical, and that contingency plans were in place where appropriate. The inspectors used the licensee'sdaily configuration risk assessment records, observations of shift turnover meetings, daily plant status meetings, and equipment walkdowns to verify that the equipmentconfigurations had been properly listed; that protected equipment had been identifiedand was being controlled where appropriate; and that significant aspects of plant risk were communicated to the necessary personnel. The documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

91R14Personnel Performance Related to Non-Routine Plant Evolutions and Events (71111.14)

.1 Operator Response to the Failing Open of the 21 Main Feedwater Pump RecirculationValve

a. Inspection Scope

On February 3, 2006, the 21 main feedwater pump recirculation valve failed open due tothe failure of a solenoid controlling air to the valve's diaphragm. The failure diverted aportion of the feedwater pump output back to the main condenser. The failure resulted in a plant transient on both the secondary and primary cycles. The inspectors reviewedthe operator's response to this transient completing one personnel performance to non-routine plant event inspection sample. The inspectors observed the performance of operations personnel in the control roomduring the unplanned and non-routine evolution comparing their response to the actions specified in the applicable plant procedures. The inspectors also reviewed selected plant parameters to ensure the plant responded as designed. The documents reviewedby the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Technical Specifications Required Shutdown of Unit 2

a. Inspection Scope

On February 5, 2006, the inspectors observed operator performance during a Unit 2shutdown required by TS due to the inoperability of diesel generator D6. Theobservation of operator performance constituted one personnel performance to non-routine plant evolution inspection sample. The inspectors observed the performance of operations personnel in the control roomduring the shutdown and cooldown of Unit 2 (a non-routine evolution) to verify that operators conducted the evolution in accordance with plant procedures. The documentsreviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.1R15Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors reviewed the technical adequacy of six operability evaluationscompleting six operability evaluation inspection samples. The inspectors conducted

10these inspections by in-office review of associated documents and in-plant walkdowns ofaffected areas and plant equipment. The inspectors compared degraded or nonconforming conditions of risk-significantstructures, systems, or components associated with barrier and mitigating systems andagainst the functional requirements described in the TS, USAR, and other design basis documents; determined whether compensatory measures, if needed, were implemented; and determined whether the evaluation was consistent with therequirements of Administrative Work Instruction 5AWI 3.15.5, "OperabilityDeterminations." The following operability evaluations were reviewed by inspectors:on January 12, 2006, Operability Recommendation (OPR) 01008542, thatdocumented the operability of the D1 and D2 diesel generators during extremecold weather; on January 18, 2006, Prompt Operability Determination 01010676, thatdocumented the operability of the D2 diesel generator with a fuel oil leak on themechanical seal of the fuel oil booster pump;on January 25, 2006, OPR 01011307, that documented the operability ofcontainment particulate radiation monitors 1R11 and 2R11 following the discovery that the filter paper drive was operating at twice the speed specified inthe technical manual;on February 13, 2006, OPR 01009304, that documented the operability of Unit 1and 2 auxiliary feedwater pumps following the discovery that the steamgenerator blowdown flow control valve's quality classification were non-safety-related; on March 9, 2006, OPR 01011774, that documented the operability of 16 steamgenerator blowdown indication lights and two motors following a change of classification from non-safety-related to safety-related; and on March 28, 2006, OPR 01020661, that documented the operability of D1 dieselgenerator following discovery of a jacket water cooling leak.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.

b. Findings

No findings of significance were identified.1R19Post-Maintenance Testing (71111.19)

a. Inspection Scope

The inspectors completed four assessments of post-maintenance testing completingfour post-maintenance test inspection samples. The inspectors selected post-

11maintenance tests associated with important mitigating and barrier integrity systems toensure that the testing was performed adequately, demonstrated that the maintenancewas successful, and that operability of associated equipment and/or systems wasrestored. The inspectors conducted these inspections by in-office review of documents and in-plant walkdowns of associated plant equipment. The inspectors observed and assessed the post-maintenance testing activities for the following maintenance activities:Surveillance Procedure (SP) 2307, D6 Diesel Generator 6-Month Fast Start Test; and SP 2335, D6 Diesel Generator 18-Month 24-Hour Load Test, following replacement of cylinder pistons and liners on February 16, 2006;122 control room chiller and air handler following completion of Test Procedure1806, "122 Control Room Chiller Inspection," and Preventive MaintenanceProcedure 3147-2-122, "122 Control Room Air Handler Annual Inspection," on March 7, 2006;WO 00265122-02, post-maintenance test of SV-33498, D2 diesel generatorroom outside air damper following replacement of a solenoid valve on March 14, 2006; andWO 00091187 Task 4, post-maintenance test of cooling water tube leak repairson the 14 containment fan cooling unit on March 28, 2006.The inspectors reviewed the appropriate sections of the TS, USAR, and maintenancedocuments to determine the systems' safety functions and the scope of themaintenance. The inspectors also reviewed CAPs to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with fleet corrective action procedures. Key documents used by the inspectors in conducting this inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.1R20Refueling and Other Outage Activities (71111.20)

.1 Unit 2 Maintenance Outage

a. Inspection Scope

The inspectors observed the licensee's performance during the Unit 2 maintenanceoutage 2F2401 conducted between February 5 and February 21, 2006, to perform repairs and modifications to D5 and D6 diesel generators. These inspection activities represent one outage inspection sample.

12This inspection consisted of an in-office and in-plant review of outage activitiesperformed by the licensee. The inspectors conducted in-office reviews of outage related documentation and in-plant observations of the following daily outage activities:*observed outage management turnover meetings to verify that the currentshutdown risk status was accurate, well understood, and adequately communicated;*performed main control room walkdowns to observe the alignment of systemsimportant to shutdown safety;*observed operability of reactor coolant system instrumentation and comparedchannels and trains against one another;*observed ongoing work activities and foreign material exclusion control; and

• 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.Additionally, the inspectors performed in-plant observations or in-office reviews of thefollowing specific activities:*observed the reactor shutdown from full power to hot shutdown; and*reviewed SP 2750, Post Outage Containment Close-Out Inspection.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.

b. Findings

No findings of significance were identified.1R22Surveillance Testing (71111.22)

a. Inspection Scope

During this inspection period, the inspectors completed four surveillance inspectionsamples. Observation of SP 1102 completed the quarterly inservice testing inspectionrequirement of a risk-significant pump or valve. The inspectors selected the following surveillance testing activities:SP 1102, Turbine-Driven Auxiliary Feedwater Pump Monthly Test, Revision 85,on January 27, 2006;SP 1002A, Analog Protection System Calibration, Revision 36, Channel B hotloop temperature, cold loop temperature, average temperature, and differentialtemperature instruments on February 2, 2006; *SP 2101, 21 Motor-Driven Auxiliary Feedwater Pump Once Every RefuelingShutdown Flow Test, Revision 37; and SP 2103, 22 Turbine-Driven AuxiliaryFeedwater Pump Once Every Refueling Shutdown Flow Test, Revision 42, on February 21, 2006; and*SP 1295, D1 Diesel Generator 6-Month Fast Start, Revision 36, onFebruary 27, 2006.

13During completion of the inspection samples, the inspectors observed in-plant activitiesand reviewed procedures and associated records to verify that:* preconditioning did not occur;* effects of the testing had been adequately addressed by control room personnelor engineers prior to the commencement of the testing;* acceptance criteria was clearly stated, demonstrated operational readiness, andwas consistent with the system design basis;* plant equipment calibration was correct, accurate, properly documented, and thecalibration frequency was in accordance with TS, USAR, procedures, and applicable commitments;* measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy;

• applicable prerequisites described in the test procedures were satisfied;

• test frequency met TS requirements to demonstrate operability and reliability;* the tests were performed in accordance with the test procedures and otherapplicable procedures;* jumpers and lifted leads were controlled and restored where used;

• test data/results were accurate, complete, and valid;

• test equipment was removed after testing;

• where applicable for in-service testing activities, testing was performed inaccordance with the applicable version of Section XI, American Society of Mechanical Engineers Code, and reference values were consistent with the system design basis;* where applicable, test results not meeting acceptance criteria were addressedwith an adequate operability evaluation or declared inoperable;* where applicable for safety-related instrument control surveillance tests,reference setting data have been accurately incorporated in the test procedure;* equipment was returned to a position or status required to support theperformance of its safety functions; and* all problems identified during the testing were appropriately documented in thecorrective action program.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.

b. Findings

No findings of significance were identified.1R23Temporary Plant Modifications (71111.23)

a. Inspection Scope

The inspectors conducted an in-office review of documentation associated withtemporary modification EC 623 completing one temporary modification inspection sample. Temporary modification EC 623 installed a blind flange in the upper coil of the east face of the 11 Containment Fan Coil Unit as a temporary repair for a leak. As part

14of this inspection, the documents listed in the Attachment were utilized to evaluate thepotential for an inspection finding.The inspection activities included, but were not limited to, a review of design documents,safety screening documents, and the USAR to determine that the temporary modification was consistent with modification documents, drawings, and procedures.

The inspectors also reviewed actual impact of the temporary modification on the permanent and interfacing systems. The inspectors also reviewed the CAPs listed inthe Attachment to verify that the licensee was identifying issues at an appropriatethreshold and entering them into their corrective action program in accordance with the fleet corrective action procedure.

b. Findings

No findings of significance were identified.2.RADIATION SAFETYCornerstone: Public Radiation Safety2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems(71122.01)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the most current Radiological Effluent Release Report, datedMay 12, 2005, to determine if the program was implemented as described in Radiological Effluent Technical Standards (RETS)/Offsite Dose Calculation Manual (ODCM), and to determine if ODCM changes were made in accordance with Regulatory Guide 1.109 and NUREG-0133. The inspectors determined if any modifications madeto radioactive waste system design and operation changed the dose consequence tothe public. The inspectors determined if technical and/or 10 CFR 50.59 reviews were performed when required, and determined whether radioactive liquid and gaseous effluent radiation monitor set-point calculation methodology changed since completion of the modifications. The inspectors reviewed the licensee's 2005 Tritium Ground Water Sampling Results for anomalies which included one onsite monitoring well that has measurable levels of tritium, and to assure the licensee reported findings from the previous year in the Annual Effluent Report. The inspectors determined if anomalous results reported in the current Radiological Effluent Release Report were adequately resolved.The inspectors reviewed the RETS/ODCM to identify the effluent radiation monitoringsystems and its flow measurement devices, effluent radiological occurrenceperformance indicator incidents in preparation for onsite follow-up, and the USAR description of all radioactive waste systems. This review represents one sample.

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b. Findings

No findings of significance were identified. However, the inspectors evaluated theadequacy of the licensee's surveillance program for onsite tritium ground watermonitoring. This program was instituted in response to unexpectedly high sample results found in 1989, which have fluctuated to the present. While elevated tritium levels have not been detected consistently since the licensee took specific actions to reducetritium release to the ground water, 1 well of 20 monitored has recently showed measurable levels of tritium. The licensee stated that the measurable and fluctuatingtritium in the single well has been explained as a ground water flow anomaly in the past period of study. The licensee notes that the tritium levels in the ground water fluctuateat levels less than 5 percent of the Environmental Protection Agency's drinking water standard of 20,000 picocuries/liter. During the inspection, the licensee was continuingthe process of assessing the potential cause(s) of the slightly elevated sample results. The NRC will continue review of the licensee's assessment when it is completed. Therefore, this issue remains under review by the NRC and is categorized as anUnresolved Item (URI), (URI 05000282/2006002-02; 05000306/2006002-02).

.2 Onsite Inspection

a. Inspection Scope

The inspectors walked-down the major components of the gaseous and liquid releasesystems, (e.g., radiation and flow monitors, demineralizers and filters, tanks, andvessels) to observe current system configuration with respect to the description in the USAR, ongoing activities, and equipment material condition. This review represents one sample.The inspectors observed the routine processing, (including sample collection andanalysis), and release of radioactive liquid waste to determine if the appropriate treatment equipment was used, and that radioactive liquid waste was processed and released in accordance with procedure requirements, and observed the sampling and compositing of liquid effluent samples. The inspectors reviewed several radioactive gaseous effluent release permits, including the projected doses to members of the public to determine if appropriate treatment equipment is used and that the radioactivegaseous effluent is processed and released in accordance with RETS/ODCM requirements. This review represents one sample.The inspectors reviewed the records of abnormal releases or releases made withinoperable effluent radiation monitors, and reviewed the licensee's actions for these releases to ensure an adequate defense-in-depth was maintained against an unmonitored, unanticipated release of radioactive material to the environment. This review represents one sample.The inspectors reviewed the licensee's technical justification for changes made by thelicensee to the ODCM, as well as to the liquid or gaseous radioactive waste systemdesign, procedures, or operation since the last inspection. The review was performed to determine whether the changes affected the licensee's ability to maintain effluentsAs-Low-As-Reasonably-Achievable, and whether changes made to monitoring

16instrumentation resulted in a non-representative monitoring of effluents. This reviewrepresents one sample.The inspectors reviewed a selection of monthly, quarterly, and annual dose calculationsto ensure that the licensee properly calculated the offsite dose from radiological effluent releases, and to determined if any annual RETS/ODCM dose limits, (i.e., Appendix I to 10 CFR Part 50 values) were exceeded. This review represents one sample.The inspectors reviewed air cleaning system surveillance test results to ensure that thesystems were operating within the licensee's acceptance criteria. The inspectorsreviewed surveillance test results the licensee uses to determine the stack and vent flow rates. The inspectors determined if the flow rates were consistent with RETS/ODCM or USAR values. This review represents one sample.The inspectors reviewed records of instrument calibrations performed since the lastinspection for each point of discharge effluent radiation monitor and flow measurement device, and reviewed any completed system modifications and the current effluentradiation monitor alarm set-point value for agreement with RETS/ODCM requirements.

The inspectors also reviewed calibration records of radiation measurement (i.e., counting room) instrumentation associated with effluent monitoring and release activities and the quality control records for the radiation measurement instruments. This review represents one sample.The inspectors reviewed the results of the interlaboratory comparison program todetermine the quality of radioactive effluent sample analyses performed by the licensee. The inspectors reviewed the licensee's quality control evaluation of the interlaboratory comparison test and the associated corrective actions for any deficiencies identified. The inspectors reviewed the licensee's assessment of any identified bias in the sample analysis results and the overall effect on calculated projected doses to members of the public. In addition, the inspectors reviewed the results from the licensee's Quality Assurance audits to determine whether the licensee met the requirements of the RETS/ODCM. This review represents one sample.

b. Findings

No findings of significance were identified.

.3 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed the licensee's self-assessments, audits, Licensee EventReports, and Special Reports related to the radioactive effluent treatment and monitoring program since the last inspection to determine if identified problems were entered into the corrective action program for resolution. The inspectors also reviewed the licensee's self-assessment program to determine if it was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

17The inspectors also reviewed corrective action reports from the radioactive effluenttreatment and monitoring program since the previous inspection, interviewed staff and reviewed documents to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk: *initial problem identification, characterization, and tracking;*disposition of operability/reportability issues;*evaluation of safety significance/risk and priority for resolution;

• identification of repetitive problems;

• identification of contributing causes;

• identification and implementation of effective corrective actions;

• resolution of Non-Cited Violations (NCVs) tracked in the corrective actionsystem; and*implementation/consideration of risk significant operational experiencefeedback.This review represents one sample.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES4OA1Performance Indicator Verification (71151)Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

.1 Reactor Safety Strategic Area

a. Inspection Scope

The inspectors reviewed the licensee submittals for two performance indicators forPrairie Island Units 1 and 2, completing four performance indicator verification inspection procedure samples. The inspectors used performance indicator guidance and definitions contained in Nuclear Energy Institute Document 99-02, Revision 3,

"Regulatory Assessment Performance Indicator Guideline," to verify the accuracy of the performance indicator data. The inspectors' review included, but was not limited to, conditions and data from logs, Licensee Event Reports, condition reports, and calculations for each performance indicator specified. The inspectors also reviewed the CAPs listed in the Attachment to this report to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with corrective action procedures.The licensee's reporting of the following performance indicators were verified:

18Unit 1*Reactor Scrams for the 2nd quarter 2004 through the 4th quarter 2005;*Reactor Scrams with Loss of Normal Heat Removal for the 2nd quarter 2004through the 4th quarter 2005.Unit 2*Reactor Scrams for the 2nd quarter 2004 through the 4th quarter 2005;*Reactor Scrams with Loss of Normal Heat Removal for the 2nd quarter 2004through the 4th quarter 2005.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.

b. Findings

No findings of significance were identified.4OA2Identification and Resolution of Problems (71152)

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewedissues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's corrective action program at an appropriate threshold, that adequate attention was given to ensure timely corrective actions, and that adverse trends were identified and addressed. This does not count as an annual sample.

b. Findings and Observations

No findings of significance were identified.

.2 Annual Problem Identification and Resolution Sample

a. Inspection Scope

During the week of February 6, 2006, the inspectors selected a corrective actionprogram issue for detailed review, completing one problem identification and resolution annual inspection sample. The inspectors selected an issue associated with elevated crankcase pressure on diesel generator D6 that was identified and entered into the corrective action program with CAP 01013473.The inspectors conducted a review of the Root Cause Evaluation report, previousevaluations, and corrective actions in order to assess the effectiveness of the licensee's efforts to correct the identified problem. The inspectors also ensured that

19the licensee had identified the full extent of the issue, conducted an appropriateevaluation, and that licensee-identified corrective actions were appropriately prioritized. The key documents reviewed by the inspectors associated with this inspection arelisted in the Attachment to this report.

b. Findings and Observations

No findings of significance were identified.

.3 Review of Corrective Action Aspects of the Maintenance of Emergency Action Levelsfor the External Flooding Event

a. Inspection Scope

The inspectors conducted an in-plant and in-office review of the licensee'simplementation of their corrective action program as it applied to their identification thatplant transformers may not be relied upon to a river level of 698 feet above mean sea level as specified in the Prairie Island USAR. This issue was originally presented as a preliminary White finding in Inspection Report 05000282/2005011; 05000306/2005011.

The focus of this issue was associated the establishment of a potentially non-conservative emergency action classification process, as contained in Prairie Island Emergency Plan. That process potentially would not have resulted in the licensee staff declaring a required Site Area Emergency under certain flooding conditions (see also Section 4OA5.1). This review does not constitute an inspection sample, as this was an inspection sample in the previous quarter. b.ObservationsIn the previous inspection period, the inspectors identified an apparent violation havingpreliminarily low to moderate safety significance for a failure to maintain in effect emergency plans that met the requirements specified in 10 CFR 50.54(q) and risk-significant planning standard 10 CFR 50.47(b)(4). Specifically, the establishment of a non-conservative emergency action level classification process. This condition was initially identified as the result of a licensee evaluation thatconcluded transformers associated with each offsite power source to both the Unit 1 and 2 safety-related and non-safety-related 4160 volt buses had limiting elevations below 698 feet above mean sea level. The USAR, Section 2.4.3.5, "Floods," stated that the transformers will function when flooded to 698.0 feet above mean sea level. The entry conditions for the licensee's declaration of a Site Area Emergency at 698 feet above mean sea level was based on a river water level above which the functionality of site transformers can no longer be relied upon. The licensee initiated corrective action and changed the USAR referenced river elevation to 695 feet above mean sea level but failed to correct references to the 698 feet above mean sea level for the Site Area Emergency in the current emergency action level scheme or in the Nuclear Energy Institute 99-01, Revision 4 emergency action level scheme submittal that was under preparation at the time of discovery.

20On March 1, 2006, the licensee attended a regulatory conference at the NRC Region IIIoffice to present information associated with the significance of the issue. Based on the information presented at the regulatory conference and additional information obtained by the licensee through a third party analysis, NRC Region 3 Managementconcluded that additional inspection and reviews of the impact of a river level of 698 feet above mean sea level on plant transformers and other critical electrical equipment were warranted. As a result of the additional inspection, the inspectors concluded that plant transformers would remain available with the river level of 698 feet. Since the transformers remained available at the pre-existing river level of 698 feet, then the emergency action level in the Prairie Island Emergency Plan for the site area emergency never technically required a change to the 695 foot elevation. Therefore, no violation of emergency preparedness requirements occurred when the licensee failed to implement their corrective action process and change the emergency action level for the flooding site area emergency following the change to the USAR. Based on the inspectors review of this issue, they noted two shortcomings related tolicensee's implementation of their corrective action program. First, the inspectors concluded that the licensee performed an inaccurate evaluation of the potentialproblem that resulted in an unnecessary change to the USAR. Second, once the licensee identified and implemented a corrective action to change the USAR referenced river level from 698 to 695 feet above mean sea level, they failed to also revise the current emergency action level scheme and Nuclear Energy Institute 99-01, Revision 4 emergency action level scheme submittal. Both of these documents had their basis tied to the river level referenced in the USAR. The inspectors reviewed this event for potential enforcement action as it applied toproblem identification and resolution requirements. The inspectors concluded that this issue was associated with the functional area of emergency preparedness and 10 CFR 50, Appendix B, criteria do not apply to the emergency preparedness functional area. Therefore, there was no violation of the requirements contained in10 CFR 50, Appendix B, Criterion XVI, "Corrective Actions." When the inspectors discussed these deficiencies with licensee plant management acknowledged that theirimplementation of the corrective action process did not meet management expectation nor the corrective action procedural requirements. The licensee has entered the deficient condition into their corrective action program with CAP 01001641.4OA5Other Activities

.1 (Closed) Apparent Violation (AV)05000282/2005011-03; 05000306/2005011-03:Degraded Risk-Significant Planning Standard Follow Up and Resolution

a. Inspection Scope

The inspectors conducted additional in-plant and in-office review of informationpresented by the licensee at a regulatory conference held in the NRC Region III officeon March 1, 2006, to discuss the significance of the preliminary White finding. The preliminary White finding was associated the establishment of a potentiallynon-conservative emergency action classification process, as contained in Prairie Island Emergency Plan. That process potentially would not have resulted in the

21licensee staff declaring a required Site Area Emergency under certain floodingconditions (IR 050000282/2005011; 050000306/2005011). The inspectors conducted a physical walkdown of the switchyard, relay house, andplant transformers and interviewed plant engineers. Additionally, inspectors reviewed information contained in a third party-evaluation of plant transformers and associated critical electrical component elevations, the design and routing of underground cables, the licensee's root cause evaluation report, and actions specified in plant normal and abnormal procedures to verify that electrical supplies would have remained available at a river level of 698 feet above mean sea level.

b. Findings

In the previous inspection period, the inspectors identified an apparent violation havingpreliminarily low to moderate safety significance for a failure to maintain in effect emergency plans that met the requirements specified in 10 CFR 50.54(q) and risk-significant planning standard 10 CFR 50.47(b)(4). Specifically, the establishment of a non-conservative emergency action level classification process, as contained in Prairie Island Emergency Plan potentially would not have resulted in the licensee staff declaring a required Site Area Emergency under certain flooding conditions. This condition was initially identified as the result of a licensee evaluation thatconcluded transformers associated with each offsite power source to both the Unit 1 and 2 safety-related and non-safety-related 4160 volt buses had limiting elevations below 698 feet above mean sea level. The USAR, Section 2.4.3.5, "Floods," stated that the transformers will function when flooded to 698.0 feet above mean sea level. Inaddition, the entry conditions for the licensee's declaration of a Site Area Emergency at 698 feet above mean sea level was based on a river water level above which the functionality of site transformers can no longer be relied upon. The licensee initiated corrective action and changed the USAR referenced river elevation to 695 feet above mean sea level but failed to correct references to the 698 feet above mean sea level for the Site Area Emergency in the current emergency action level scheme or in their Nuclear Energy Institute 99-01 Revision 4 emergency action level scheme submittal that was under preparation at the time of discovery. Subsequently this oversight wasidentified by the inspectors. On March 1, 2006, the licensee attended a regulatory conference at the NRC Region IIIoffice to present information associated with the significance of the issue. Based on the information presented at the regulatory conference and additional information recently obtained by the licensee through additional third party analysis, the inspectors conducted additional inspection and reviews of the effect of a river level of 698 feet above mean sea level on plant transformers and other critical electrical equipment.

The inspectors concluded that plant transformers would remain available with the river level of 698 feet. Since alternating current power remained available to plant transformers at a river level of 698 feet above mean sea level, NRC Head Quarters andRegional Emergency Preparedness staff concluded that the risk-significant planning standard 10 CFR 50.47(b)(4) was not degraded and therefore, there was no finding and no violation of NRC requirements. These two AV's are closed.

22

.2 Implementation of Temporary Instruction (TI) 2515/165 - Operational Readiness ofOffsite Power and Impact on Plant Risk

a. Inspection Scope

The objective of TI 2515/165, "Operational Readiness of Offsite Power and Impact onPlant Risk," was to confirm, through inspections and interviews, the operational readiness of offsite power systems in accordance with NRC requirements. OnMarch 21 through March 24, 2006, the inspectors reviewed licensee procedures and discussed the attributes identified in TI 2515/165 with licensee personnel. In accordance with the requirements of TI 2515/165, the inspectors evaluated thelicensee's operating procedures used to assure the functionality/operability of theoffsite power system, as well as the risk assessment, emergent work, and/or gridreliability procedures used to assess the operability and readiness of the offsite powersystem.The information gathered while completing this TI was forwarded to the Office ofNuclear Reactor Regulation for further review and evaluation.

b. Findings

No findings of significance were identified.

.3 Resolution of URI 05000282/2005011-02, Previously Unevaluated OWA Associatedwith the Cold Weather Operation of the Unit 1 Diesel Generators.

a. Inspection Scope

During the previous inspection period, inspectors identified a condition associated withthe operation of the Unit 1 diesel generator ventilation during cold weather conditions.

The ventilation system is a risk-significant support system for the Unit 1 safety-relateddiesel generators D1 and D2. This condition was previously unidentified and unevaluated as an OWA by the licensee. The licensee entered the condition into their corrective action program with CAP 01007904.

The inspectors reviewed the licensee's evaluation of the OWA and performed anindependent assessment as to the operator's ability to implement abnormal andemergency operating procedures. Additionally, the inspectors reviewed the results of a time validation study of expected operator actions following a postulated event concurrent with the existence of the OWA. The inspectors also reviewed OWA for increased potential for personnel error including:*required operations contrary to past training or required more detailedknowledge of the system than routinely provided;*required a change from longstanding operational practices;

• required operation of system or component in a manner that is different fromsimilar systems or components; *created the potential for the compensatory action to be performed on equipmentor under conditions for which it is not appropriate;

23*impaired access to required indications, increase dependence on oralcommunications, or required actions under adverse environmental conditions; and*required the use of equipment and interfaces that had not been designed withconsideration of the task being performed. Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.

b. Findings

No findings of significance were identified and URI 05000282/2005011-02 is closed. 4OA6Meeting(s)

.1 Exit MeetingThe inspectors presented the inspection results to Mr. T. Palmisano and othermembers of licensee management at the conclusion of the inspection on

April 13, 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 MeetingsAn interim exit meeting was conducted for:

• Radioactive Gaseous and Liquid Effluent Treatment and Monitoring ProgramInspection with Mr. P. Huffman, Plant Manager, on March 17, 2006.

.3 Regulatory ConferenceA public meeting was conducted on March 1, 2006, at the Nuclear RegulatoryCommission (NRC) Region III office in Lisle, Illinois.

This was concerning a possiblegreater than green finding and apparent violation for a non-conservative emergency action level scheme. The meeting summary is available in ADAMS (ML061020547).

The NMC presentation materials are also available (Package Accession Number ML060740345).4OA7Licencee-Identified ViolationsThe following violations of very low significance were identified by the licensee and areviolations of NRC requirements which meet the criteria of Section VI of the NRCEnforcement Manual, NUREG-1600, for being dispositioned as NCVs.

24Cornerstone: Mitigating Systems

.1 It is required, in part, in 10 CFR 50, Appendix B, Criterion III, that the design controlmeasures shall provide for verifying or checking the adequacy of design.

Further, the Prairie Island USAR, Section 8.1, requires that emergency power for engineered safety features shall conform to General Design Criteria 39, Emergency Power for Engineered Safety Features (U.S. Atomic Energy Commission, Proposed General Design Criteria for Nuclear Power Plant Construction Permits, July 10, 1967) to provide capacity assuming a failure of a single active component. Contrary to the above the metering portion of the circuits was added as part of the Station Blackout modification in 1989 without adequately verifying or checking the adequacy of the design as evidenced by the determination that the Prairie Island Unit 1 design of thephase and ground relay current transformer circuits for safeguards buses 15 and 16 were vulnerable to a failure of a common portion of the circuit. As a result, plant operators declared Unit 1 safeguards buses 15 and 16 inoperable and declared one path from the grid inoperable. The buses were transferred to an alternate source, the relaying disconnects were opened, and the buses were declared operable. On February 8, 2005, a temporary modification of the relaying scheme was implemented.

This issue was identified based on the licensee's review of an event reported at another licensee, and was described in CAP 040867 and Licensee Event Report 05000282/2005001-00 dated February 5, 2005. Furthermore, this issue was the subject of URI 05000282/2005004-02. Subsequently, the licensee further evaluated the design and determined that a single failure would not result in a loss ofboth Unit 1 safeguards buses. Regional inspectors reviewed the licensee's evaluation and found it to be acceptable, therefore, this URI is closed.Cornerstone: Public Radiation Safety

.2 The licensee's ODCM states the minimum number of operable radioactive liquideffluent monitoring instrumentation channels required during operation.

Table 2.2 ofthe ODCM describes the action required by the licensee when less than the minimumnumber of operable radioactive liquid effluent monitoring instrumentation channels are available. The ODCM specifically requires one Discharge Canal Monitor R-21 be operable at all times. If R-21 is inoperable, the licensee is required to take grab samples at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and analyze the sample for gamma emitters.

Additionally, they must restore R-21 within 30 days. Contrary to the above, and as described in CAP040479, on January 8, 2005, R-21 was taken out of service and the licensee failed to conduct a Discharge Canal grab sample in the first 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The licensee identified the missed sample and conducted the required sampling and analysis approximately 17.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after declaring R-21 out of service. The sample showed no increases when compared with other Discharge Canal sampling. During the period R-21 was out of service the licensee released the 121 Aerated Drain Tank monitor tank. The release was monitored using the Liquid Radwaste Effluent Line (R-18). No increase was noted on R-18 during the release and no alarms were received. The finding is of very low safety significance because it did not result in an unmonitored discharge nor were any effluent dose limits approached.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

J. Anderson, Radiation Protection Manager

T. Bacon, Operations Training Supervisor

N. Bibus, Plant Engineering Supervisor

S. Brown, Site Engineering Director

J. Callahan, Emergency Planning Manager

C. Chovan, Production Planning Manager

L. Clewett, Business and Support Manager

F. Forrest, Operations Manager

P. Huffman, Plant Manager

J. Lash, Training Manager

k. Ludwig, Maintenance Manager

S. McCall, Engineering Programs Manager

S. Northard, Nuclear Safety Assurance Manager

T. Palmisano, Site Vice President

M. Runion, Engineering Plant and Systems ManagerNuclear Regulatory Commission

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened05000282/2006002-01

05000306/2006002-01URIEvaluation of Expired Sealant Performance for FloodProtection

05000282/2006002-02

05000306/2006002-02URILicensee Continuing Onsite Tritium Well SampleResults Assessment (Section 2PS1.1)

Closed

05000306/FIN-2005011-02URIUnit 1 Diesel Generator Operation During Cold Weather

05000282/FIN-2005004-02URIInadequate Design Control Causes Single Failure

05000282/2005011-0305000306/2005011-03AVDegraded Risk Significant Planning StandardDiscussedNone.

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 selected sections of portions of the documents were evaluated as part of the overall inspection effort.

Inclusion of a document on this list does not imply NRC acceptance of the document orany part of it, unless this is stated in the body of the inspection report.1R04Equipment AlignmentD2 Diesel GeneratorIntegrated Checklist C1.1.20.7-5; D2 Diesel Generator Valve Status; Revision 20Integrated Checklist C1.1.20.7-6; D2 Diesel Generator Auxiliaries and Local Panels andSwitches; Revision 10

Integrated Checklist C1.1.20.7-7; D2 Diesel Generator Main Control Room Switch andIndicating Light Status; Revision 13

Integrated Checklist C1.1.20.7-8; D2 Diesel Generator Circuit Breakers and Panel Switches;Revision 16

CAP 043678; Control Room Operator Aid Book Not In Agreement with the On-Line List Condition Evaluation

008541; Control Room Operator Aid Book Not In Agreement with the On-Line ListD5 Diesel GeneratorIntegrated Checklist C1.1.20.7-9; D5 Diesel Generator Valve Status; Revision 11Integrated Checklist C1.1.20.7-10; D5 Diesel Generator Auxiliaries and Local Panels andSwitches; Revision 9

Integrated Checklist C1.1.20.7-11; D5 Diesel Generator Main Control Room Switch andIndicating Light Status Integrated Checklist C1.1.20.7-12; D5 Diesel Generator Circuit Breakers and Panel Switches;Revision 9121 Control Room Special VentilationIntegrated Checklist C1.1.37-1[2]; Ventilation Systems; Revision 14System Pre-Start Checklist C37.11-1; Chilled Water Safeguards System; Revision 17

Operating Procedure C37.11; Chilled Water System Operation; Revision 19CAP

01017534; Unable to Unplug

CL-20-44Unit 1 Auxiliary Feedwater Complete System WalkdownSystem Pre-Start Checklist C28-2; Auxiliary Feedwater System Unit 1; Revision 44Drawing

NF-39222; Flow Diagram Unit 1 Feedwater System; Revision BA

WO 088959;

MS-31998 Diagnostic and Repack

WO 088083; Replace Packing on 11 Turbine-Driven Auxiliary Feedwater Pump DischargeValve

WO 074716; Oil Leak on the 12 Motor-Driven Auxiliary Feedwater Pump Lube Oil PumpWO

0100533; 11 Turbine-Driven Auxiliary Feedwater Pump Steam Block Valve Leak-ByWO

0100207;

AF-16-02 Auxiliary Feedwater to 12 Steam Generator Check Valve Has Leak-By Attachment3CAP

01013051; Found 3-Inch Bolt on the Floor of the 11 Turbine-Driven Auxiliary FeedwaterPump Room1R05Fire ProtectionPlant Safety Procedure F5, Appendix A; Fire Strategies for Fire Areas 25, 31, 32, 41A, 41B,81, 113, 115, and 117

Plant Safety Procedure F5, Appendix F, Revision 20; Fire Hazard Analysis for Fire Areas 25,

31, 32, 41A, 41B, 81, 113, 115, and 117

IPEEE

NSPLMI-96001, Appendix B; Internal Fires Analysis; Revision 2

CAP 01010751; Fire Watch in the Safety Injection Pump Area Identified that

CAP 025815 was Inappropriately Closed Without Complete Evaluation of Potential Discrepancies1R06Flood Protection MeasuresAbnormal Operating Procedure

AB-4; Flood; Revision 28Surveillance Procedure 1293; Inspection of Flood Control Measure; Revision 13; performed February 7 through February 17, 2006

Fleet Procedure

FP-SC-PE-05; Shelf Life Program; Revision 0

CAP 01012782; Leather glove found in Safeguards Cooling Water Pump Area

CAP 01011939 Yellow Slippery When Wet Found in Screenhouse Vital Area

CAP 01021256; Deck-O-Seal Sealant Found with Questionable Shelf Life

CAP 01022931; Re-Order of Sealant Not Completed1R11Licensed Operator Requalification Program - Quarterly Simulator ObservationSimulator Evaluation Guide P9160S-001, ATT SQ53; Revision 05AWI 3.15.0; Plant Operation; Revision 171R12Maintenance Rule ImplementationAir CompressorsMaintenance Rule System Specific Basis Document, Station and Instrument Air; Revision 11121 Air Compressor Troubleshooting Support/Refute Matrix; January 4, 2006

2 Air Compressor Troubleshooting Support/Refute Matrix; January 4, 2006Containment SprayMaintenance Rule A(1) Action Plan; Containment Spray SystemRoot Cause Evaluation Report

01011427; 21 CS Pump into Maintenance Rule a(1)

CAP 01011427; Develop an a(1) Action Plan for the CS System1R13Maintenance Risk Assessments and Emergent Work ControlProcedure H24.1; Assessment and Management of Risk Associated with MaintenanceActivities; Revision 9

Unit 1 Configuration Risk Assessment for January 18, 2006

Operations Log Entries for January 18, 2006

Unit 2 Configuration Risk Assessment for February 5, 2006

Operations Log Entries for February 5, 2006

Attachment4Unit 1 Configuration Risk Assessment for February 13, 2006Operations Log Entries for February 13, 2006

Unit 1 Configuration Risk Assessment for March 12, 2006

Operation Log Entries for March 12, 2006

CAP 01013116; Delay in Restoring Work Orders

00100621 and 001006221R14Non-Routine EvolutionsFailure of the 21 Main Feedwater Pump Recirculation ValveOperating Logs for February 3, 2006Emergency Response Computer System Trend of Unit 2 Generator Gross Megawatts Emergency Response Computer System Trend of Unit 2 Power for the Thermal Power Monitor Calculation Emergency Response Computer System Trend of Unit 2 Loop A Feedwater Header Pressure Emergency Response Computer System Trend of Unit 2 Loop A Steam Generator Narrow Range Level Emergency Response Computer System Trend of Unit 2 Loop A Feedwater Flow Emergency Response Computer System Trend of Unit 2 Loop B Steam Generator Narrow Range Level

CAP 01013448; 21 Feedwater Recirculation Valve Failed OpenUnit 2 Shutdown and CooldownOperating Procedure 2C1.3; Unit 2 Shutdown; Revision 55Operating Procedure 2C1.4; Unit 2 Power Operation; Revision 37Operating Procedure 2C15; Residual Heat Removal System Unit 2; Revision 33

Operating Procedure 2C14; Component Cooling Water System Unit 2; Revision 25

CAP 01013524; 2FR-475 Steam Flow/Feed Flow Recorder Stayed at 100% Power Value

CAP 01013526; 2FI-495 21 Steam Generator Flow Indicator Failed Downscale

CAP 01013527; Left Stop Valve Dual Indication and Downstream Pressure Indicates Valve Open Operating Logs for February 4 and 5, 20061R15Operability EvaluationsD1 and D1 Cold Weather Operation OPROPR

01008542; Continuous Operation of D1 and D2 During Cold Weather; Revision 0OPR

01008542; Continuous Operation of D1 and D2 During Cold Weather; Revision 1

Engineering Calculation

ENG-ME-026; Emergency Diesel Generator Ventilation Testing/Analysis; Revision C

Operating Procedure C18.1; Engineering Safeguards Equipment Support Systems;Revision 19

Operating Procedure 1C20.7; D1/D2 Diesel Generators; Revision 22

CAP 01008542; Request OPR Associated with CAP 01008485

CAP 01008542; Continuous Operation of D1 and D2 During Cold Weather

CAP 01007904; Evaluate Continuous Operation of D1 and D2 in Cold Weather as an OperatorWorkaround Attachment5Prompt Operability Evaluation D2 Fuel Oil LeakCAP

01010676; Fuel Oil Leak Causes Entry Into Abnormal Operating Procedure D14.3 AOP1Sharepoint Attachment to

CAP 010106761R11 and 2R11 OPROPR

01011307; Filter Paper Drive Speed Twice What Is Specified in Technical Manual;Revision 0

USAR Section 7.5.2; Containment Radiation Monitors; Revision 28

CAP 01011307; Filter Paper Drive Speed Twice What Is Specified in Technical ManualAuxiliary Feedwater PumpsOPR

01009304; Steam Generator Blowdown Valves Not Maintained as Safety-RelatedCAP

01009304; Steam Generator Blowdown Valves Not Maintained as Safety-RelatedSteam Generator Blowdown Upgraded to Safety-RelatedOPR

01011774; Steam Generator Blowdown System Change to Safety-Related; Revision 0CAP01011774; Steam Generator Blowdown System Change to Safety-RelatedD1 Diesel Generator Jacket Water Leak OPROPR

01020661; D1 Diesel Generator Jacket Water Leak OPR; Revision 0Operating Instruction 06-35; Instruction for the Filling of the Jacket Water Expansion TankRemote Alarm Response Procedure C55300-0203; Jacket Coolant Level Low Expansion Tank; Revision 7

Temporary Change Notice

TCN-008A to Remote Alarm Response Procedure C55300-0203;

Jacket Coolant Level Low Expansion Tank; Revision 7

Remote Alarm Response Procedure C55300-0204; Jacket Coolant Pressure Low; Revision 6

Remote Alarm Response Procedure C55300-0301; Jacket Coolant Temperature High;

Revision 6

CAP 01020661; D1 Diesel Generator Jacket Water Leak Operating Logs for March 27, 20061R19Post-Maintenance TestingD6 Diesel GeneratorSP 2307; D6 Diesel Generator 6-Month Fast Start Test; Revision 23SP 2335; D6 Diesel Generator 18-Month 24-Hour Load Test; Revision 11122 Control Room Air Handler and ChillerWO

00109479; 122 Control Room Air Handler Annual InspectionWO

00109480; 122 Control Room Chiller InspectionD2 Outside Air DamperSP 1307; D2 Diesel Generator 6-Month Fast Start Test; Revision 29WO

00265122-02; Post-Maintenance Test Operating Procedure 1C37.10; D1/D2 Diesel Generator Room Cooling System; Revision 5CAP

01018372;

CD-34049 122 Diesel Generator Outside Air Damper Did Not Open Attachment614 Containment Fan Cooling Unit Tube Leak RepairWO

00091187, Task 4; Repair Cooling Water Leaks on 14 Containment Fan Cooling UnitMaintenance Operating Procedure 1M-ZC-174-013; 14 FCU Isolation and Restoration;Revision 1

CAP 01020709; Increasing Level on 14 FCU Condensate Collecting Pot1R20Refueling and Other Outage Activities

SP 2705; Post Outage Containment Close-Out Inspection; Revision 29Unit 2 Shutdown Safety Assessments for February 7 through February 17, 2006

Operating Procedure 2C1.3; Unit 2 Shutdown; Revision 55Operating Procedure 2C1.4; Unit 2 Power Operation; Revision 37Operating Procedure 2C15; Residual Heat Removal System Unit 2; Revision 33

Operating Procedure 2C14; Component Cooling Water System Unit 2; Revision 25

CAP 01013524; 2FR-475 Steam Flow/Feed Flow Recorder Stayed at 100 percent Power Value

CAP 01013526; 2FI-495 21 Steam Generator Flow Indicator Failed Downscale

CAP 01013527; Left Stop Valve Dual Indication and Downstream Pressure Indicates Valve Open Operating Logs for February 4 and 5, 20061R22Surveillance TestingSP 1102Operating Logs, dated October 13, 2005

CAP 01000971;

SP 1118 Not Done Within 1 Hour as Required By Technical SpecificationsSP 1002ACAP

01013345; 1TC-404R Found Out-of-Tolerance During SP 1002A

SP 2101 and

SP 2103CAP

01014039; D6 Engine 2 Piston B8 Has Combustion Bowl Crack

SP1295Temporary Change Notice to

SP 1295; Revision 36; dated March 18, 2005CAP

01014590; Preventive Maintenance Procedure Guidance Differs from Vendor Guidance1R23Temporary ModificationsEngineering Change 621; Install Blank Flange for 11 FCU Face; January 7, 2006Prairie Island Nuclear Generating Plant Calculation

ENG-ME-648; 11 Containment Fan CoilUnit Analysis with One Coil Blanked; January 16, 20062PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems Offsite Dose Calculation Manual; Revision 19USAR; Section 7; Revision 28

2004 Annual Radioactive Effluent Report and ODCM; dated May 16, 2004

2005 Tritium Ground Water Sampling Results; dated January 11, 2006

Attachment7Observation Report 2004-002-6-022; Nuclear Oversight Observation Report RadioactiveWaste Processing Assessment; dated June 25, 2004

Observation Report 2005-002-6-019; Nuclear Oversight Observation Report REMP Annual Assessment; dated June 17, 2004

CAP 00730187; Inadvertent Boration of Unit 2 Reactor Coolant System; dated July 8, 2004

CAP 0078591; Control of Containment Openings During Outage; dated December 10, 2004CAP

00851081; Determine if a Release Rate Calculation is Required After Initial Containment Release; dated May 28, 2005

CAP 00857852; Effluent Composite Sample Results Elevated; dated July 19, 2005

CAP 00876712; 124/126 Waste Gas Decay Tank Pressure Decreasing; dated August 13, 2005

CAP 00880560; ODCM Quarterly Composite Sample Lost; dated August 26, 2005

CAP 01000875; Niobium-95, Mis-Quantified, Due to Software Issue; dated October 13, 2005CAP

01015585; Loss of Waste Gas Inventory; dated February 20, 2006

CAP 01018821; Discharge Pipe Extension and Leak Detection in the USAR; dated March 16, 2006

CAP 040479; Missed 12 Hour Sample Requirement for R-21 Out of Service; dated January 8, 2005

1783.2B; NMC Radiation Monitor Electronic Calibration Train B; Revision 0

1783.1A; Westinghouse Radiation Monitor Electronic Calibration Train A; Revision 1

SP 1140.1; 121 Spent Fuel Pool Special and In-Service Purge Ventilation System Filter Removal Efficiency Test; Revision 16

SP 1055.2; 122 Control Room Clean Up Ventilation System Filter Removal Efficiency Test;

Revision 13

SP1055.2; 122 Control Room Clean Up Ventilation System Filter Removal Efficiency Test;

Revision 15

SP 1176A; Auxiliary Building Special Ventilation Train A Flow Verification; Revision 3SP 1080.2; 12 Shield Building Ventilation Filter Removal Efficiency Test; Revision 15

SP 1081.1; 121 Auxiliary Building Special Ventilation Filter Removal Efficiency Test;Revision 13

SP 1184A; Spent Fuel Pool Special Ventilation Train A Flow; Revision 2

SP 1185B; Control Room Clean Up Ventilation Train B Flow Verification; Revision 3

SP 1186B; Shield Building Ventilation Train B Flow Verification; Revision 0

SP 2080.2; 22 Shield Building Ventilation Filter Removal Efficiency Test; Revision 11

SP 2186B; Shield Building Ventilation Train B Flow Verification; Revision 1

QF-406; Snap-Shot Report Chemistry; dated February 20, 20064OA1Performance Indicator VerificationCalculated Performance Indicator Data for the Unit 1 and Unit 2 Reactor Scrams for the 2ndQuarter 2004, 3rd Quarter 2004, 4th Quarter 2004, 1st Quarter 2005, and the 2nd Quarter 2005,3rd Quarter 2005, and 4th Quarter 2005Calculated Performance Indicator Data for the Unit 1 and Unit 2 Reactor Scrams with Loss of Normal Heat Removal for the 2nd Quarter 2004, 3rd Quarter 2004, 4th Quarter 2004, 1st Quarter2005, and the 2nd Quarter 2005, 3rd Quarter 2005, and 4th Quarter 2005Unit 1 Operating Logs from April 1, 2004, through December 31, 2005

Unit 2 Operating Logs from April 1, 2004, through December 31, 2005

Plant Procedure H33.1; Performance Indicator Reporting Instructions; Revision 5

Plant Procedure H33; Performance Indicator Reporting; Revision 5

Attachment8CAP

040989; Need to Determine if Pinhole Leak in Containment Fan Cooling Unit Results in aLoss of Safety Function

CAP 041859; NRC Monthly Operating Report Error in Reactor Hours Critical for February andMarch4OA2Identification and Resolution of ProblemsAnnual SampleCAP

01013473; D6 Experienced High Crankcase PressureRoot Cause Evaluation

01013473; D6 High Crankcase Pressure Resulting in Unit 2 ShutdownReview of Corrective Action Aspects of the Maintenance of Emergency Action Levels for theExternal Flooding EventAutomated Engineering Services Corporation Evaluation; Transformer External FloodElevation at Elevation 698; dated February 19, 2006

CAP 01001641; Potential Error in Flooding Level for Declaring Site Area Emergency Root Cause Evaluation

01001641; Potential Error in Flooding Level for Declaring Site Area Emergency4OA5Other ActivitiesDegraded Risk-Significant Planning Standard Follow Up and ResolutionAutomated Engineering Services Corporation Evaluation; Transformer External FloodElevation At Elevation 698; dated February 19, 2006Implementation of

TI 2515/165 - Operational Readiness of Offsite Power and Impact on PlantRiskTI 2515/165; Operational Readiness of Offsite Power and Impact on Plant Risk; datedMarch 3, 2006

Operating Procedure C20.3; Electrical Power System Security Analysis; Revision 3

Abnormal Operating Procedure C20.3 AOP1; Evaluating System Operating Conditions WhenSecurity Analysis is Out of Service; Revision 6

Procedure

H24; Maintenance Rule Program; Revision 9

Procedure

H24.1; Assessment and Management of Risk Associated with MaintenanceActivities; Revision 9

Procedure

H24.1; Appendix A; Phase 1 Risk Assessment; Revision 1Unit 1 Diesel Generator OWA5AWI 3.10.8; Equipment Problem Resolution Process; Revision 7Design Basis Document DBD

SYS-38; Emergency Diesel Generator System; Revision 2

CAP 01007439; Evaluate 1C20.7 Steps 5.3.6.D.1 and 5.4.6.D.1 for Workarounds

CAP 01007904; Evaluate Operation of D1/D2 in Cold Weather as OWA

CAP 01008485; Continuous Operation of D1/D2 During Cold Weather OperationCAP

01008542; Request an OPR Associated with CAP 1008485

OPR 01008542; Continuous Operation of D1 and D2 During Cold Weather; Revision 0

OPR 01008542; Continuous Operation of D1 and D2 During Cold Weather; Revision 1

Operating Procedure C18.1; Engineering Safeguards Equipment Support Systems;Revision 19

Operating Procedure 1C20.7; D1/D2 Diesel Generators; Revision 22

Attachment9Validation of 1C20.7; Continuous Operation of D1/D2 During Cold Weather OperationOperator Time Validation to Perform Actions; dated February 20, 2006

Attachment10

LIST OF ACRONYMS

USEDAD [[]]

AMSA gencywide Documents Access and Management SystemAWIAdministrative Work Instruction

CA [[]]

PC orrective Action Program/Corrective Action Program Action Request

CF [[]]

RC ode of Federal Regulations

DRPD ivision of Reactor Projects

EAEnforcement ActionIPEEEIndividual Plant Examination of External Events

IRI nspection Report

NC [[]]

VN on-Cited Violation

NR [[]]

CU.S. Nuclear Regulatory Commission

ODC [[]]

MO ffsite Dose Calculation Manual

OPRO perability Recommendation

OWAO perator Workaround

PAR [[]]

SP ublicly Available Records

RET [[]]

SR adiological Effluent Technical Standards

SD [[]]

PSignificance Determination Process

SPSurveillance Procedure

TITemporary Instruction

TST echnical Specifications

UR [[]]

IU nresolved Item

USA [[]]

RUpdated Safety Analysis Report

WOW ork Order