IR 05000327/2007005

IR 05000327-07-005, 05000328-07-005 on 10/01/2007 - 12/31/2007 for Sequoyah, Units 1 and 2, Refueling and Outage Activities

ML080350386
Person / Time
Site:	Sequoyah
Issue date:	01/30/2008
From:	Nease R L Reactor Projects Region 2 Branch 6
To:	Campbell W R Tennessee Valley Authority
References
FOIA/PA-2010-0209 IR-07-005
Download: ML080350386 (47)

Text

January 30, 2008

Tennessee Valley AuthorityATTN:Mr. William R. CampbellChief Nuclear Officer and Executive Vice President6A Lookout Place1101 Market StreetChattanooga, TN 37402-2801

SUBJECT: SEQUOYAH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT05000327/2007005 AND 05000328/2007005

Dear Mr. Campbell:

On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at your Sequoyah Nuclear Plant, Units 1 and 2. The enclosed inspection reportdocuments the inspection results, which were discussed on January 9, 2008, with Mr. TimothyCleary and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.The inspectors reviewed selected procedures and records, observed activities, and interviewedpersonnel.This report documents one NRC-identified finding of very low safety significance (Green), whichwas determined to involve a violation of NRC requirements. However, because of the very lowsafety significance and because it was entered into your corrective action program, the NRC istreating this finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRCEnforcement Policy. If you contest any NCV in this report, you should provide a response within30 days of the date of this inspection report, with the basis for your denial, to the NuclearRegulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, UnitedStates Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC ResidentInspector at the Sequoyah Nuclear Plant.

TVA2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public ins pection in theNRC Public Document Room or from the Publically Available Records (PARS) component ofNRC's document system (ADAMS). ADAMS is accessible from the NRC Website athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/

Rebecca L. Nease, ChiefReactor Projects Branch 6Division of Reactor ProjectsDocket Nos.:50-327, 50-328License Nos.:DPR-77, DPR-79

Enclosure:

Inspection Report 05000327/2007005 and 05000328/2007005

w/Attachment:

Supplemental Informationcc: w/encl: (See page 3)

_________________________OFFICERII:DRPRII:DRPRII:DRPRII:DRPRII:DRSRII:DRSRII:DRSSIGNATURE/RA//RA//RA by E-mail//RA by E-mail//RA By BBonser//RA by BBonser//RA By Bbonser/NAMETNazarioRNeaseSFreemanMSpeckWLooNGriffisANielsenDATE1/29/081/29/081/25/081/25/-081/29/081/25/081/29/08 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICERII:DRSRII:DRSRII:DRSSIGNATURE/RA By E-mail//RA//RA By E-mail/NAMEBMillerARogersRTaylorDATE1/25/081/25/081/28/08 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO TVA3cc w/encls:Ashok S. BhatnagarSenior Vice PresidentNuclear Generation Development and ConstructionTennessee Valley AuthorityElectronic Mail DistributionJames R. DouetVice President, Nuclear SupportTennessee Valley AuthorityElectronic Mail DistributionH. Rick Rogers, Vice PresidentNuclear Engineering & Technical ServicesTennessee Valley Authority3R Lookout Place1101 Market StreetChattanooga, TN 37402-2801Timothy P. ClearySite Vice PresidentSequoyah Nuclear PlantTennessee Valley AuthorityP.O. Box 2000Soddy-Daisy, TN 37384-2000General CounselTennessee Valley AuthorityElectronic Mail DistributionJohn C. Fornicola, General ManagerNuclear Assurance Tennessee Valley AuthorityElectronic Mail DistributionBeth A. Wetzel, ManagerCorporate Nuclear Licensing and Industry AffairsTennessee Valley AuthorityElectronic Mail DistributionJames D. Smith, ManagerLicensing and Industry AffairsSequoyah Nuclear PlantTennessee Valley AuthorityElectronic Mail DistributionChristopher R. ChurchPlant ManagerSequoyah Nuclear Plant Tennessee Valley AuthorityP.O. Box 2000Soddy Daisy, TN 37384-2000Lawrence E. Nanney, DirectorTN Dept. of Environment & ConservationDivision of Radiological HealthElectronic Mail DistributionCounty MayorHamilton County CourthouseChattanooga, TN 37402-2801Larry E. Nicholson, General ManagerPerformance ImprovementTennessee Valley Authority4X Blue Ridge1101 Market StreetChattanooga, TN 37402-2801Ann Harris341 Swing LoopRockwood, TN 37854James H. Bassham, DirectorTennessee Emergency Management AgencyElectronic Mail Distribution TVA4Letter to William from Rebecca L. Nease dated January 30, 2008

SUBJECT: SEQUOYAH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT 05000327/2007005 AND 05000328/2007005Distribution w/encl

Bob Pascarelli, NRRB. Moroney, NRRC. Evans, RIIL. Slack, RII OE Mail RIDSNRRDIRSPUBLICNRC Resident InspectorU.S. Nuclear Regulatory Commission2600 Igou FerrySoddy-Daisy, TN 37379 EnclosureU. S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos:50-327, 50-328License Nos:DPR-77, DPR-79Report No:05000327/2007005 and 05000328/2007005Licensee:Tennessee Valley Authority (TVA)Facility:Sequoyah Nuclear PlantLocation:Sequoyah Access RoadSoddy-Daisy, TN 37379Dates:October 1, 2007 - December 31, 2007Inspectors:S. Freeman, Senior Resident InspectorM. Speck, Resident Inspector W. Loo, Senior Health PhysicistJ. Griffis, Health PhysicistA. Nielsen Health PhysicistB. Miller, Reactor InspectorA. Rogers, Reactor InspectorR. Taylor, Reactor InspectorApproved by:R. Nease, Chief Reactor Projects Branch 6Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000327/2007-005, IR 05000328/2007-005; 10/01/2007 - 12/31/2007; SequoyahNuclear Plant, Units 1 and 2; Refueling and Outage Activities.The report covered a three-month period of inspection by resident and regionalinspectors and health physicists. The significance of most findings is indicated by theircolor (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,"Significance Determination Process" (SDP). Findings for which the SDP does not applymay be Green or be assigned a severity level after NRC management review. TheNRC's program for overseeing the safe operation of commercial nuclear power reactorsis described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.A.

Cornerstone: Barrier Integrity

$

Green.

The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,Criterion V, for failure to implement licensee Procedure SPP-6.5, Foreign Material Control. During a review of the core verification video following refuelingand reactor vessel head installation, the inspectors identified debris within theReactor Coolant System (RCS), not previously identified by the licensee. Thelicensee took immediate action to enter the problem into their corrective actionprogram and evaluate whether the reactor coolant system could safely operatewith the material left behind.The finding was more than minor because the material could have been removedhad it been properly identified and because an evaluation was required to justifyleaving it after the reactor head was installed. The finding was of very low safetysignificance because it affected only the fuel barrier and not the RCS barrier. The finding had no cross-cutting aspects. (Section 1R20.1)

B. Licensee-Identified Violations

None.

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 began the period at 79% rated thermal power (RTP) and operated there untilOctober 4, 2007 when it was shutdown for a refueling outage. Unit 1 achieved criticalityon November 15, 2007 and reached Mode 1 on November 16, 2007. The unit was shutdown on November 17, 2007 due to rod control system power supply problems. Following repairs, Unit 1 returned to critical on November 17, 2007 and reached 100%RTP on November 21, 2007 where it remained for the duration of the reporting period.Unit 2 operated at or near 100% RTP until November 1, 2007 when power was reducedto 58% RTP to correct problems on the Number 3 Heater Drain Tank level controlsystem. Unit 2 returned to 100% RTP on November 2, 2007 and remained there for theduration of the reporting period.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather Protection

a. Inspection Scope

The inspectors reviewed design features and licensee preparations for protecting bothUnit 1 and Unit 2 refueling water storage tanks (RWSTs) and the essential raw coolingwater (ERCW) intake structure from extreme cold and freezing conditions. Theinspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and TechnicalSpecifications (TS), reviewed and observed implementation of licensee freeze protectionprocedures, and walked down portions of the systems to assess deficiencies and thesystem readiness for extreme cold weather and discussed prioritization and status ofcorrecting deficiencies with licensee personnel. Documents reviewed are listed in theAttachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

a. Inspection Scope

Partial System Walkdowns. The inspectors performed a partial walkdown of the Unit 2Emergency Core Cooling system Train A during Train B maintenance to verify theoperability of redundant or diverse trains and components when safety equipment wasinoperable. The inspectors attempted to identify any discrepancies that could impact thefunction of the system, and, therefore, potentially increase risk. The inspectors reviewedapplicable operating procedures, walked down control system components and verifiedthat selected breakers, valves, and support equipment were in the correct position to 4Enclosuresupport system operation. The inspectors also verified that the licensee had properly identifiedand resolved equipment alignment problems that could cause initiating events or impact thecapability of mitigating systems or ba rriers and enter ed them into the corrective action program.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors conducted a tour of the nine areas listed below to assess the materialcondition and operational status of fire protection features. The inspectors verified thatcombustibles and ignition sources were controlled in accordance with the licensee'sadministrative procedure; fire detection and suppression equipment was available foruse; that passive fire barriers were maintained in good material condition; and thatcompensatory measures for out-of-service, degraded, or inoperable fire protectionequipment were implemented in accordance with the licensee's fire plan.

$Auxiliary Building Elevation 749 (Pressurizer Heater Transformer Rooms andCRDM Equipment Rooms)

$Control Building Elevation 706 (Cable Spreading Room)

$ Emergency Diesel Generator Building

$Control Building Elevation 669 (Mechanical Equipment Room, 250-VDC Batteryand Battery Board Rooms)

$Control Building Elevation 685 (Auxiliary Instrument Rooms)

$Control Building Elevation 732 (Mechanical Equipment Room and Relay Room)

$Auxiliary Building Elevation 690 (Corridor)

$Auxiliary Building Elevation 714 (Corridor)

$Essential Raw Cooling Water Building

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed the turbine building internal flood protection design todetermine the strategy for mitigating a flood caused by a break in a large circulatingwater pipe and the potential flood propagation to the auxiliary and control buildings. Theinspectors reviewed the Sequoyah Probabilistic Safety Assessment Indivi dual PlantExamination to verify that assumptions and mitigating elements of various floodscenarios were addressed by plant procedures and operator actions. The inspectorsreviewed the most recent performances of the preventative maintenance work orders on 5Enclosurethe various turbine building sumps to verify that flooding in the turbine building would bedetected. The inspectors also walked down selected areas of the turbine building toview flood protection doors and level detection devices to assess material condition andgeneral condition. Documents reviewed are listed in the Attachment.

b. Findings

No Findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors observed performance and reviewed the results of licensee Procedure 2-PI-SFT-070-001.0, Performance Testing of Component Cooling Heat Exchangers 2A1,2A2, Revision 15, to verify that the acceptance criteria and results appropriatelyconsidered differences between testing conditions and design conditions; that testresults were appropriately categorized against pre-established acceptance criteria; thatthe frequency of testing was sufficient to detect degradation prior to loss of heat removalcapability below design basis va lues; and that test results consider ed test instrumentinaccuracies and differences. Documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities (ISI).1Piping Systems ISI

a. Inspection Scope

From October 7-17, 2007, the inspectors reviewed the implementation of the licensee'sISI program for monitoring degradation of the RCS boundary and risk significant pipingsystem boundaries. The inspectors reviewed a sample from activities performed duringthe Unit 1-Fall 2007 / Refueling Outage (1SR21) including nondestructive examinations(NDE) required by the 1989 Edition, no addenda, of American Society of MechanicalEngineers (ASME) Boiler and Pressure Vessel Code,Section XI, and augmentedexamination commitments. The inspectors observed and reviewed non-destructive examination (NDE) activities. Specifically:Ultrasonic Examination (UT):*CVC socket weld, elbow to pipe, weld # CVC-2599*CVC socket weld, pipe op elbow, weld # CVC-2600*Safety Injection valve to pipe weld, weld # SI-1605 6Enclosure*Safety Injection pipe to elbow weld, weld # SI-1606*Pressurizer spray line elbow to safe end weld, weld # RCF-23*Pressurizer relief line safe end to elbow weld, weld #: RCF-24*Pressurizer safety line safe end to elbow weld, weld #: RCF 36*Pressurizer safety line safe end to elbow weld, weld #: RCF 42*Pressurizer safety line safe end to elbow weld, weld #: RCF 45*Pressurizer nozzle to shell weld, weld # RCW 15Penetrant Testing (PT):*Reactor Coolant System (RCS) hanger, ID # 1-RCH-027-IA Visual Examination (VT):*Chemical Volume Control System (CVCS) rigid support, ID # 1-CVCH-007*Chemical Volume Control System (CVCS) rigid support, ID # 1-CVCH-010*Reactor Vessel Bottom head penetrations #'s 29, 43, 8, 55, 49, 48, 14, 46Qualification and certification records for examiners, inspection equipment, andconsumables along with the applicable NDE procedures for the previously referenced ISIexamination activities were reviewed and compared to requirements stated in ASME Section V, ASME Section XI, and other industry standards.The inspectors reviewed welding activities from the previous outage. The inspectors reviewed drawings, work instructions, weld process sheets, weld travelers, pre-heat requirements and radiography records for welding of an ASME Class 1 and 2 pressure boundary weld. The inspectors reviewed and observed weld overlay activities associated with the Pressurizer weld overlay activities. Specifically:*Pressurizer spray nozzle, weld # RCW-24-SE*Pressurizer safety relief valve nozzle, weld # RCW-25-SE*Pressurizer safety relief valve nozzle, weld # RCW-27-SE*Pressurizer safety relief valve nozzle, weld # RCW-28-SE

b. Findings

No findings of significance were identified..2PWR Vessel Upper Head The inspectors completed this activity by performance of Temporary Instruction2515/150, Revision 3, which is documented in Section 4OA5..3Boric Acid Corrosion Control (BACC) ISI

a. Inspection Scope

The inspectors reviewed the licensee's Boric Acid Corrosion Control (BACC) program toensure compliance with commitments made in response to NRC Generic Letter 88-05, 7Enclosure"Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWRPlants."The inspectors conducted an on-site record review as well as an independent walkdownof parts of the reactor building that are not normally accessible during at-poweroperations to evaluate compliance with licensee BACC program requirements and 10CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requirements. In particular, the inspectors verified that the visual examinations focused on locationswhere boric acid leaks can cause degradation of safety-significant components and that degraded or non-conforming conditions were properly identified in the licensee's corrective action system.

The inspectors reviewed a sample of engineering evaluations completed for boric acid found on reactor coolant system piping and components to verify that the minimum design code-required section thickness had been maintained for the affectedcomponents. The inspectors also reviewed licensee corrective actions and problem evaluation reports (PERs), as well as corrosion assessments implemented for evidence of boric acid leakage to confirm that they were consistent with requirements.

b. Findings

No findings of significance were identified..4Steam Generator (SG) Tube ISI

a. Inspection Scope

From October 12-17, 2007, the inspectors reviewed the Unit 1 SG tube eddy current testing (ECT) examination activities to ensure compliance with Technical Specifications (TS), applicable industry operating experience and technical guidance documents, and ASME Code Section XI requirements.The inspectors reviewed licensee SG inspection activities to ensure that ECTinspections were conducted in accordance with the licensee's SG Program andapplicable industry standards. The inspectors reviewed the SG examination scope, ECTacquisition procedures, site-specific Examination Technique Specification Sheets(ETSS), ECT analysis guidelines, the most recent SG degradation assessment, and thelast operational assessment. The inspectors reviewed documentation to ensure that theECT probes and equipment configurations used were qualified to detect the expectedtypes of SG tube degradation, and a sampling of tube data was reviewed with a Level IIIanalyst.

The inspectors ensured that all tubes with relevant indications wereappropriately screened for in-situ pressure testing. No tubes met the criteria for in-situtesting. Additionally, the inspectors monitored the licensee's secondary side activities,which included a foreign object search and recovery for loose parts, and sludge lancing.

b. Findings

No findings of significance were identified.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of SG and ISI-related problems that were identifiedby the licensee and entered into the corrective action program. The inspectors reviewedthese corrective action program documents to confirm that the licensee hadappropriately described the scope of the problems. In addition, the inspectors' reviewincluded confirmation that the licensee had an appropriate threshold for identifyingissues and had implemented effective corrective actions. The inspectors evaluated thethreshold for identifying issues through interviews with licensee staff and review oflicensee actions to incorporate lessons learned from industry issues related to the ISIprogram. The inspectors performed these reviews to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requirements.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors observed licensed operator requalification testing on December 3, 2007. The testing consisted of two scenarios requiring an Alert declaration. The first involveda steam generator tube rupture. An emergency diesel generator engine developed alubricating oil leak requiring it to be taken out of service followed by a loss of maincondenser vacuum. This resulted in operators initiating a manual reactor trip. Followingthe trip, a steam generator tube rupture occurred with the associated main steamisolation valve failing to operate, both requiring operator actions. The second scenarioinvolved a motor trip of the running centrifugal charging pump and a loss of one mainfeed pump resulting in a turbine runback followed by a failed open pressurizer safetyrelief valve. This resulted in a manual reactor trip and safety injection initiation. Thiswas compounded by all A-train emergency core cooling pumps failing to startautomatically and a failed intermediate range nuclear instrument. The inspectorsobserved crew performance in terms of communications; ability to take timely and properactions; prioritizing, interpreting and verifying alarms; correct use and implementation ofprocedures, including the alarm response procedures and emergency plan eventclassification; timely control board operation and manipulation, including high riskoperator actions; over sight and direction provided by shift m anager, including the abilityto identify and implement appropriate TS actions; independent event classification by theShift Technical Advisor; and group dynamics involved in crew performance. Theinspectors also observed the examining staff's assessment of the crew's performance 9Enclosureand compared them to inspector observations. Documents reviewed are listed in theAttachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the following two maintenance activities to verify theeffectiveness of the activities in terms of: 1) appropriate work practices; 2) identifyingand addressing common cause failures; 3) scoping in accordance with 10 CFR 50.65(b); 4) characterizing reliability issues for performance; 5) trending key parameters for condition monitoring; 6) charging unavailability for performance; 7) classification inaccordance with 10 Code of Federal Regulations (CFR) 50.65(a)(1) or (a)(2); 8)appropriateness of performance criteria for structure, system, or components (SSCs)and functions classified as (a)(2); and 9) appropriateness of goals and corrective actionsfor SSCs and functions classified as (a)(1). Documents reviewed are listed in theAttachment.

$PER 134770, Incorrect Containment Purge Exhaust Filter Replaced

$Unit 1 and Unit 2 Main Steam Isolation Valves

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the following four activities to verify that the appropriate risk assessments were performed prior to removing equipment from service formaintenance. The inspectors verified that risk assessments were performed as requiredby 10 CFR 50.65 (a)(4), and were accurate and complete. When emergent work wasperformed, the inspectors verified that the plant risk was promptly reassessed andmanaged. The inspectors verified the appropriate use of the licensee's risk assessmenttool and risk categories in accordance with Procedure SPP-7.1, On-Line WorkManagement, Revision 10, and Instruction 0-TI-DSM-000-007.1, Risk AssessmentGuidelines, Revision 8. Documents reviewed are listed in the Attachment.

$ERCW B-Train Outage for Cross-Tie Piping Installation

$Testing Emergency Diesel Generator (EDG) 1B While in ORAM OrangeCondition Due to Reduction in RCS Vent Path Area 10Enclosure$Removal of Unit 2 Turbine-Driven Auxiliary Feedwater (AFW) Pump from Servicefor Testing

$ERCW B Train Inoperable due to Motor-Operated Valve Testing on ComponentCooling System (CCS) Heat Exchanger Outlet Valve 0-FCV-67-152

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

For the five operability evaluat ions described in the PERs listed below, the inspectorsevaluated the technical adequacy of the eval uations to ensure that TS operability wasproperly justified and the subject component or system remained available, such that nounrecognized increase in risk occurred. The inspectors reviewed the UFSAR to verifythat the system or component remained available to perform its intended function. Inaddition, the inspectors reviewed compensatory measures implemented to verify that thecompensatory measures worked as stated and the measures were adequatelycontrolled. The inspectors also reviewed a sampling of PERs to verify that the licenseewas identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the Attachment.

$PER 132400, Unplanned Limiting Condition for Operation (LCO) Entry on EDG 1B

$PER 132653, Vital Inverter Declared Inoperable

$PER 133211, Foreign Material on Core Baffle Former Plate

$PER 133270, ERCW Low Flow Condition

$PER 120682, Tornado Effects on EDG Ventilation System

b. Findings

No findings of significance were identified.

1R17 Current Review of Ongoing Modifications

a. Inspection Scope

The inspectors reviewed DCN D22161-A, Install High Point Vents in ERCW DischargeHeaders, and interviewed engineering personnel regarding the modification andassociated post-modification testing to verify that

(1) the design bases, licensing bases,and performance capability had not been degraded through this modification, and

(2) themodification was not performed during increased risk-significant configurations thatplaced the plant in an unsafe condition. The inspectors also reviewed applicablesections of the UFSAR, plant modification procedures, system drawings, supportinganalyses, technical specifications, and related PERs.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the four post-maintenance tests listed below to verify that procedures and test activities ensured system operability and functional capability. Theinspectors reviewed the licensee's test procedure to verify that the procedure adequatelytested the safety function(s) that may have been affected by the maintenance activity,that the acceptance criteria in the procedure were consistent with information in the applicable licensing basis and/or design basis documents, and that the procedurehad been properly reviewed and approved. The inspectors also witnessed the test orreviewed the test data, to verify that test results adequately demonstrated restoration ofthe affected safety function(s). Documents reviewed are listed in the Attachment.

$Work Order (WO) 07-780665-000, Adjust Motor-Operated Valve Striker Plates on1-FCV-62-132 and 1-FCV-62-133

$WO 04-783124-000, Unit 1 Reactor Trip Switch Replacement

$WO 07-780645-000, Unable to Manually Stroke Atmospheric Relief Valve 1-PCV-01-005

$WO 05-777910-000, Troubleshoot/Repair Leakage of Valve 1-VLV- 063-0561

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities.1Unit 1 Refueling Outage

a. Inspection Scope

For the Unit 1 refueling outage that began on October 4, 2007, the inspectors evaluatedlicensee activities to verify that the licensee considered risk in developing outageschedules, followed risk reduction methods developed to control plant configuration,developed mitigation strategies for the loss of key safety functions, and adhered tooperating license and TS requirements that ensure defense-in-depth. The inspectorsalso walked down portions of Unit 1 not normally accessible during at-power operationsto verify that safety-related and risk-significant SSCs were maintained in an operablecondition. Specifically, between October 4 and November 17, 2007, the inspectorsperformed inspections and reviews of the following outage activities. Documentsreviewed are listed in the Attachment.

12Enclosure*Outage Plan. The inspectors reviewed the outage safety plan and contingencyplans to confirm that the licensee had appropriately considered risk, industryexperience, and previous site-specific problems in developing and implementinga plan that assured maintenance of defense-in-depth.*Reactor Shutdown. The inspectors observed the shutdown in the control roomfrom the time the reactor was tripped until operators placed it on the ResidualHeat Removal (RHR) system for decay heat removal to verify that TS cooldownrestrictions were followed. The inspectors also toured the lower containment assoon as practicable after reactor shutdown to observe the general condition ofthe RCS and emergency core cooling system components and to look forindications of previously unidentified leakage inside the polar crane wall.*Licensee Control of Outage Activities. On a daily basis, the inspectors attendedthe licensee outage turnover meeting, reviewed PERs, and reviewed thedefense-in-depth status sheets to verify that status control was commensuratewith the outage safety plan and in compliance with the applicable TS when takingequipment out-of-service. The inspectors further toured the main control roomand areas of the plant daily to ensure that the following key safety functions weremaintained in accordance with the outage safety plan and TS: electrical power,decay heat removal, spent fuel cooling, inventory control, reactivity control, andcontainment closure. The inspectors also observed a tagout of the ERCWsupply and discharge headers to verify that the equipment was appropriatelyconfigured to safely support the work or testing. To ensure that RCS levelinstrumentation was properly installed and configured to provide accurateinformation, the inspectors reviewed the installation of the Mansell levelmonitoring system. Specifically, the inspectors discussed the system withengineering, walked it down to verify that it was installed in accordance withprocedures and adequately protected from inadvertent damage, verified thatMansell indication properly overlapped with pressurizer level instruments duringpressurizer draindown, verified that operators properly set level alarms toprocedurally required setpoints, and verified that the system consistently trackedRCS level while lowering to reduced inventory conditions. The inspectors alsoobserved operators compare the Mansell indications with locally-installedultrasonic level indicators during entry into mid-loop conditions.During the outage, the inspectors also reviewed the licensee's control of heavyloads to ensure the licensee was properly handling heavy loads in areas where aload drop could impact fuel in the reactor core or equipment that would berequired to achieve safe shutdown. To do this the inspectors examined thelicensee's basis for considering the containment polar crane to be single-failureproof in order to verify that it met industry standards, reviewed the polar cranetesting and inspection done prior to lifting the reactor head, and observed theinitial head lift to verify that it complied with the safe load path specified inlicensee procedures.*Refueling Activities. The inspectors observed fuel movement at the spent fuelpool and at the refueling cavity in order to verify compliance with TS and that 13Enclosureeach assembly was properly tracked from core offload to core reload. In order toverify proper licensee control of foreign material, the inspectors verified thatpersonnel were properly checked before entering any foreign material exclusion(FME) areas, reviewed FME procedures, and verified that the licensee followedthe procedures. To ensure that fuel assemblies were loaded in the corelocations specified by the design, the inspectors independently reviewed therecording of the licensee

=s final core verification.*Reduced Inventory and Mid-Loop Conditions. Prior to the outage, the inspectorsreviewed the licensee

=s commitments to Generic Letter 88-17. Before enteringreduced inventory conditions the inspectors verified that these commitments were in place, that plant configuration was in accordance with thosecommitments, and that distractions from unexpected conditions or emergentwork did not affect operator ability to main tain the required reactor vessel level. While in mid-loop conditions, the inspectors verified that licensee procedures forclosing the containment upon a loss of decay heat removal were in effect, thatoperators were aware of how to implement the procedures, and that otherpersonnel were available to close containment penetrations if needed.*Heatup and Startup Activities. The inspectors toured the containment prior toreactor startup to verify that debris that could affect the performance of thecontainment sump had not been left in the containment. The inspectorsreviewed the licensee

=s mode change checklists to verify that appropriateprerequisites were met prior to changing TS modes. To verify RCS integrity andcontainment integrity, the inspectors further reviewed the licensee

=s RCSleakage calculations and containment isolation valve lineups. In order to verifythat core operating limit parameters were consistent with core design, theinspectors also observed portions of the low power physics testing, includingapproach to reactor criticality.

b. Findings

Introduction:

The inspectors identified a NCV of 10 CFR 50, Appendix B, Criterion V, forfailing to remove or evaluate foreign material in the reactor vessel prior to installing thereactor vessel head as required by licensee procedure.Description: On October 20, 2007 the licensee completed core reload as part of theoutage. Following core verification per Procedure TI-45, Physical Verification of CoreLoad Prior to Vessel Closure, Revision 25, the licensee continued with reactorreassembly, set the reactor vessel head, and returned the RCS to service. Theinspectors reviewed the video made during the core verification and identified severalpieces of foreign material adjacent to the fuel assemblies that had not been previouslyidentified by the licensee. The inspectors then reviewed licensee Procedure, SPP-6.5,Foreign Material Control, Revision 12, and concluded that the licensee failed toprescribe instructions or procedures of a type appropriate to the circumstances asrequired by SPP-6.5 and failed to identify and remove the foreign material prior toclosing the system. Procedure TI-45 contained no instructions to look for foreign 14Enclosurematerial in the core and no other process existed which verified foreign material hadbeen removed prior to closing the reactor vessel. This programmatic gap in thelicensee=s foreign material control process could result in future recurrence.Analysis: The finding was more than minor because the RCS was returned to servicewith unevaluated foreign material that could have been removed had it been properlyidentified by the licensee. This is similar to the more than minor example in IMC 0612,Appendix E, Example 5a. Furthermore, the inspectors determined the finding impactedthe Human Performance attribute (FME Loose Parts) of the Barrier Integrity Cornerstoneto maintain fuel cladding functionality. Licensee evaluation of the size, location, andcharacterization of the foreign material showed that the material was a small piece ofmetal, most likely a steel badge clip, in a low flow area, and would not likely carry overinto other parts of the RCS. The licensee also determined that if it did carry over, it hada low probability of causing any fuel cladding damage, would not affect reactor coolantsystem integrity, and was bounded by previous foreign material evaluations. Since thefinding affected only the fuel barrier and not the RCS barrier, the finding was of very lowsafety significance (Green).

Enforcement:

10 CFR 50, Appendix B, Criterion V, requires in part, that activitiesaffecting quality shall be prescribed by documented instructions or procedures of a typeappropriate to the circumstances. Licensee Procedure SPP-6.5 required that theresponsible supervisor perform a final inspection of the system for foreign material withthe intent that all foreign materials were accounted for and had not been left within theopen system or component. Contrary to this, on October 20, 2007, the licensee failed toeffectively implement Procedure SPP-6.5 by allowing foreign material, which could havebeen removed, to be left in the reactor coolant system. Because this finding is of verylow safety significance and because it was entered into the licensee

=s corrective actionprogram as PER 133211, this violation is being treated as a NCV, consistent withSection VI.A of the NRC Enforcement Policy: NCV 05000327/2007005-01, Failure toEffectively Implement Foreign Material Control Requirements in the RCS.

1R22 Surveillance Testing

a. Inspection Scope

For the five surveillance tests identified below, the inspectors verified that the SSCsinvolved in these tests satisfied the requi rements described in the TS surveillancerequirements, satisfied the UFSAR, applicable licensee procedures, and that the testsdemonstrated that the SSCs were capable of performing their intended safety functions. This was accomplished by witnessing testing and/or reviewing the test data. Documentsreviewed are listed in the Attachment.

$1-SI-SXP-074-202.0, RHR Pump 1A-A and 1B-B Comprehensive Performanceand Check Valve Test, Revision 2*

$0-SI-SLT-088-259.4, Upper Personnel Ai rlock Interlock Operability Test, Revision 1

$0-SI-MIN-061-105.0, Ice Condenser - Ice Weighing, Revision 5**

15Enclosure$0-SI-MIN-061-109.0, Ice Condenser Intermediate and Lower Inlet Doors andVent Curtains, Revision 5

$1-SI-SLT-088-156.0, Containment Integrated Leak Rate Test, Revision 3*This procedure included inservice testing requirements.**This procedure included an ice condenser system surveillance.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the temporary modification described in Temporary AlterationControl Form (TACF) 0-06-011-077, Piping From Floor Drain Collector Tank to theCondensate Demineralizer Waste Evaporator, Revision 2, and the associated 10CFR50.59 screening, and compared it against the UFSAR and TS to verify that themodification did not affect the operability or availability of any safety system. Theinspectors walked down the TACF to ensure it was installed in accordance with themodification documents and reviewed post installation and removal testing to verify theactual impact on permanent systems was adequately verified by the tests. Theinspectors also verified that permanent plant documents were updated to reflect theTACF to ensure that plant configuration control as maintained. Documents reviewed arelisted in the Attachment.

b. Findings

No findings of significance were identified.2.RADIATION SAFETYCornerstone: Occupational Radiation Safety (OS) and Public Radiation Safety (PS)2OS1Access Control To Radiologically Significant Areas

a. Inspection Scope

Access Controls The inspectors evaluated licensee guidance and its implementation forcontrolling worker access to radiologically significant areas and monitoring jobs in-progress. The inspectors evaluated the adequacy of procedural guidance; directlyobserved implementation of administrative and physical radiological controls; evaluatedradiation worker (radworker) and health physics technician (HPT) knowledge of andproficiency in implementing radiation protection requirements; and assessed workerexposures to radiation and radioactive material.

16EnclosureDuring facility tours, the inspectors directly observed postings and physical controls forradiation areas and high radiation areas (HRAs) within the Unit 1 (U1) and Unit 2 (U2)containment buildings, shared auxiliary building, exter nal buildings , and the independentspent fuel storage installation (ISFSI). The inspectors independently measured radiationdose rates and contamination levels or directly observed conduct of licensee radiationsurveys for selected Radiologically Controlled Area (RCA) locations. Results werecompared to current licensee surveys and assessed against established postings andRadiation Work Permit (RWP) controls. Licensee key control and access barriereffectiveness were observed and evaluated for selected Locked High Radiation Area(LHRA) locations. Implementation of procedural guidance for LHRA and Very HighRadiation Area controls were discussed in detail with health physics supervisors andmanagement. Physical controls for storage of irradiated material within the spent fuelpool were observed. In addition, licensee controls for areas where dose rates couldchange significantly as a result of refueling operations or radwaste activities werereviewed and discussed.The inspectors observed pre-job RWP briefings and reviewed RWP details, includingengineering controls for potential airborne radioactivity and surface contamination, toassess communication of radiological control requirements. Radworkers' adherence toRWP guidelines and HPT proficiency in providing job coverage, including use ofcontamination controls and airborne surveys, were evaluated through observation ofjobs in-progress. Jobs observed included U1 Steam Generator nozzle dam removal andmanway closure, U1 Reactor Coolant System filter change-outs, a U2 at-powercontainment entry, and various refueling activities. Electronic dosimeter (ED) alarm setpoints were evaluated against area radiation survey results and ED alarm responseactions were discussed with radworkers and HP supervisors. In addition to the jobsdirectly observed, inspectors also reviewed activities and documents associated with theU1 Pressurizer Overlay activities, and the removal and replacement of Hold-Up Tank"A." The inspectors evaluated the effectiveness of radiation exposure controls, including airsampling, barrier integrity, engineering controls, and postings through a review of bothinternal and external exposure results. Licensee evaluations of skin dose resulting fromdiscrete radioactive particle or dispersed skin contamination events during the lastrefueling outage were reviewed and assessed. For HRA tasks involving significant dose rate gradients, the inspectors evaluatedprocedural guidance and implementation for the use and placement of whole body andextremity dosimetry to monitor worker exposure, including the use of multiple badgingduring U1 Cycle 15 Refueling Outage (C15 RFO), and the last refueling outage. Theinspectors also reviewed and discussed selected whole-body count analyses conductedduring U1 C15 RFO and the last refueling outage. Radiation protection (RP) activities were evaluated against the requirements of UFSARChapter 12; TS Sections 6.8 and 6.12; 10 Code of Federal Regulations (CFR) Part 20;and approved licensee procedures. Records reviewed are listed in Section 2OS1 and4OA1 of the report Attachment.

17EnclosureProblem Identification and Resolution The inspectors reviewed and assessed selectPERs associated with access control to radiologically significant areas. The inspectorsevaluated the licensee's ability to identify, characterize, prioritize, and resolve theidentified issues in accordance with procedure SPP-3.1, Corrective Action Program,Revision (Rev.) 12. In addition, the inspectors reviewed self-assessments related to thearea of access controls. Specific corrective action program documents associated withaccess control issues, personnel radiation monitoring, and personnel exposure eventsreviewed and evaluated during inspection of this program area are identified in Section2OS1 and

4OA5 of the report Attachment.The inspectors completed 21 of the required line-item samples described in InspectionProcedure (IP) 71121.01.

b. Findings

No findings of significance were identified.2OS2ALARA Planning and Controls

a. Inspection Scope

As Low As Reasonably Achievable (ALARA) Implementation of the licensee's ALARAprogram during the U1 C15 RFO was observed and evaluated by the inspectors. Theinspectors reviewed ALARA planning, dose estimates, and prescribed ALARA controlsfor outage work tasks expected to incur the maximum collective exposures. Reviewedactivities included U1 Initial Containment Entry, U1 Letdown Heat Exchanger work, andU1 Steam Generator nozzle dam removal and manway closure. Incorporation ofplanning, established work controls, expected dose rates, and dose expenditure into theALARA pre-job briefings and RWPs for those activities were also reviewed. Theinspectors directly observed performance of these activities while evaluating thelicensee's use of engineering controls, low-dose waiting areas, and on-the-jobsupervision. The inspectors reviewed the licensee's exposure tracking system todetermine whether it adequately supported control of collective exposures. RWPs werejob-specific, with approximately 150 written for the current outage. EDs includedadministrative limits (warning to employee and manager, followed by ED lockout, ifdesignated limits were exceeded) on individual worker exposure.Selected elements of the licensee's source term reduction and control program wereexamined to evaluate the effectiveness of the program in supporting implementation ofthe ALARA program goals. Shutdown chemistry program implementation and theresultant effect on containment and auxiliary building dose-rate trending data werereviewed and discussed with cognizant licensee personnel. A review of chemistryactivities included the U1 crudburst and use of hydrogen peroxide which resulted in adose rate reduction of ~8 times from what they had observed before these activities hadbeen conducted. Also, the inspectors reviewed the licensee's source-term controlstrategy.

18EnclosureTrends in individual and collective personnel exposures at the facility were reviewed. Records of year-to-date individual radiation exposures sorted by work groups wereexamined for significant variations of exposures among workers. The inspectorsexamined the dose records of all declared pregnant workers during October 2005 toSeptember 2007 to evaluate total or current gestation dose. The applicable RPprocedure was reviewed to assess licensee controls for declared pregnant workers. Trends in the plant's three-year rolling average collective exposure history, outage, non-outage and total annual doses for selected years were reviewed and discussed withlicensee representatives.The licensee's ALARA program implementation and practices were evaluated forconsistency with UFSAR Chapter 12, Sections 1-5, Radiation Protection; 10 CFRPart 20 requirements; Regulatory Guide 8.29, Instruction Concerning Risks fromOccupational Radiation Exposure, February 1996; and licensee procedures. Documentsreviewed during the inspection of this program area are listed in Section 2OS2 of thereport Attachment.Problem Identification and Resolution The inspectors reviewed PER documents listed inSection 2OS2 of the report Attachment that were related to the ALARA program. The inspectors assessed the licensee's ability to identify, characterize, prioritize, and resolvethe identified issues in accordance with SPP - 3.1, Corrective Action Program, Rev. 12.The inspectors completed 15 of the required line-item samples described in IP 71121.02.

b. Findings

No findings of significance were identified.2PS1Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems

a. Inspection Scope

Groundwater Monitoring The inspectors discussed current and future programs foronsite groundwater monitoring with licensee corporate staff, including number and placement of monitoring wells and identification of plant systems with the most potentialfor contaminated leakage. The inspectors also reviewed procedural guidance foridentifying and assessing onsite spills and leaks of contaminated fluids. In addition, theinspectors reviewed records of historical contaminated spills retained fordecommissioning purposes as required by 10 CFR Part 50.75(g).In 2007, hydrological studies were performed and several new groundwater monitoringwells were installed. Analyses are performed for tritium and, for selected samples, hard-to-detect radionuclides. To date, tritium has been the only radionuclide identified in thewell samples. One of the wells shows elevated levels of tritium due to historical spills. No levels exceeding the EPA drinking water limit of 20,000 picocuries per liter 19Enclosure (corresponding to 4 millirem per year to a member of the public) have been identified inthe onsite or offsite environs.The inspectors completed one of the required line-item samples described in IP 71122.01.

b. Findings

No findings of significance were identified.2PS2Radioactive Material Processing and Transportation

a. Inspection Scope

Waste Processing and Characterization During inspector walk-downs, accessiblesections of the liquid and solid radioactive waste (radwaste) processing systems wereassessed for material condition and conformance with system design diagrams. Inspected equipment included liquid waste demineralizer skids; resin transfer piping;floor drain collector tanks; and abandoned radwaste evaporators. The inspectorsdiscussed component function, processing system changes, and radwaste programimplementation with licensee staff.The 2006 Radioactive Effluent Report and radionuclide characterizations from 2005 -2007 for each major waste stream were reviewed and discussed with radwaste staff. For Chemical Volume and Control Systems (CVCS) Resin and Dry Active Waste theinspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scalingfactors, and examined comparison results between licensee waste streamcharacterizations and outside laboratory data. Waste stream mixing and concentrationaveraging methodology for resinous waste was evaluated and discussed with licenseestaff. The inspectors also reviewed the licensee's procedural guidance for monitoring changesin waste stream isotopic mixtures.Radwaste processing activities and equipment configuration were reviewed forcompliance with the licensee's Process Control Program and UFSAR, Chapter 11. Waste stream characterization analyses were reviewed against regulations detailed in10 CFR Part 20, 10 CFR Part 61, and guidance provided in the Branch TechnicalPosition on Waste Classification and Waste Form. Reviewed documents are listed inSection 2PS2 of the report Attachment.

Transportation The inspectors directly observed preparation activities for a shipment ofcontaminated laundry and Type A package containing equipment. The inspectors notedpackage markings and placarding, performed independent dose rate measurements,and interviewed shipping technicians regarding Department of Transportation (DOT)regulations.

20EnclosureFive shipping records were reviewed for consistency with licensee procedures andcompliance with NRC and DOT regulations. The inspectors reviewed emergencyresponse information, DOT shipping package classification, radiation survey results, andevaluated whether receiving licensees were authorized to accept the packages. Forselected shipment records, the licensee's handling of Type B shipping casks wascompared to Certificate of Compliance (CoC) requirements. In addition, training recordsand training curricula for individuals currently qualified to prepare shipments ofradioactive material were reviewed.Transportation program implementation was reviewed against regulations detailed in 10CFR Part 20, 10 CFR Part 71, 49 CFR Parts 172-178; as well as the guidance providedin NUREG-1608. Training activities were assessed against 49 CFR Part 172 Subpart H. Documents reviewed during the inspection are listed in Section 2PS2 of the reportAttachment.Problem Identification and Resolution Selected PERs in the area of radwaste/shippingwere reviewed in detail and discussed with licensee personnel. The inspectorsassessed the licensee's ability to characterize, prioritize, and resolve the identifiedissues in accordance with licensee procedure SPP-3.1, Corrective Action Program, Rev.12. The inspectors also evaluated the scope of the licensee's internal audit programand reviewed recent assessment results. Documents reviewed for problem identificationand resolution are listed in Section 2PS2 of the report Attachment.The inspectors completed 6 of the required line-item samples specified in IP 71122.02.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES 4OA1Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors sampled licensee submittals for the six PIs listed below for the periodfrom July 1, 2006 through September 30, 2007 for both Unit 1 and Unit 2. To verify theaccuracy of the PI data reported during that period, PI definitions and guidancecontained in NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 5, wereused to verify the basis in reporting for each data element.Cornerstone: Mitigating Systems

• Mitigating Systems Performance Index: Emergency AC Power*Mitigating Systems Performance Index: High Pressure Injection System*Mitigating Systems Performance Index: Heat Removal System (AFW)*Mitigating Systems Performance Index: Residual Heat Removal System 21Enclosure*Mitigating Systems Performance Index: Cooling Water System*Safety System Functional FailuresThe inspectors reviewed portions of the operations logs and raw PI data developed frommonthly operat ing reports and discussed the methods for compiling and reporting thePIs with engineering personnel. The inspectors also independently calculated selectedreported values to verify their accuracy and compared graphical representations fromthe most recent PI report to the raw data to verify that the data was correctly reflected inthe report. Specifically for the Mitigating Systems Performance Index (MSPI), theinspectors reviewed the basis document and derivation reports to verify that the licenseewas properly entering the raw data as suggested by NEI 99-02. For Safety SystemFunctional Failures, the inspectors also reviewed LERs issued during the referencedtimeframe. Documents reviewed are listed in the Attachment.Cornerstone: Occupational Radiation Safety The inspectors reviewed the Occupational Exposure Control Effectiveness PI resultsfrom May 2006 through September 2007. For the assessment period, the inspectorsreviewed electronic dosimeter alarm logs and assessed corrective action programdocuments to determine whether HRA, VHRA, or unintended radiation exposures hadoccurred. The inspectors also reviewed licensee procedural guidance for collecting anddocumenting PI data. In addition, the inspectors reviewed selected personnelcontamination event data and internal dose assessment results. Report section 2OS1contains additional details regarding the inspection of controls for exposure significantareas. Documents reviewed are listed in sections 2OS1 and

4OA1 of the reportAttachment.Cornerstone: Public Radiation Safety

The inspectors reviewed records used by the licensee to identify occurrences ofquarterly doses from liquid and gaseous effluents in excess of the values specified inNEI 99-02 guidance. Those records included monthly effluent dose calculations forOctober 2006 through September 2007. The inspectors also interviewed licenseepersonnel that were responsible for collecting and reporting the PI data. In addition,licensee procedural guidance for classifying and reporting PI events was evaluated. Reviewed documents are listed in Section

4OA1 of the report Attachment.The inspectors completed two of the required samples for IP 71151, one sample for theOS PI and one sample for the PS PI.

b. Findings

Introduction:

The inspectors identified an unresolved issue (URI) regarding licenseefailure to submit accurate information regarding the Emergency AC Power MitigatingSystems Performance Indicator (MSPI).

22EnclosureDescription: The inspectors reviewed the importance weighting ratios for both theunavailability and unreliability portions of the five different MSPI i ndicators as delineatedin the MSPI basis document. The inspectors noted that, for Emergency AC Power, aseparate ratio was specified for each EDG on each unit so that when calculating MSPIfor Unit 1 there was one ratio for EDG 1A, one ratio for EDG 1B, one ratio for EDG 2A,and one ratio for EDG 2B. The importance of the Unit 1 EDGs was higher for the Unit 1indicator than the Unit 2 EDGs with each Unit 2 EDG having an identical importance forUnit 1. The opposite was true for Unit 2. The Unit 2 EDGs were more important. However, when reviewing the derivation reports for the Emergency AC Power indicator,the inspectors noted that the same importance ratios were used on each EDG for eachunit so that each EDG was equally important to each unit. The inspectors determinedthat the basis document was correct but the importance ratios had been improperlyentered into the CDE database that calculated the Emergency AC Power MSPI. Inaddition, while reviewing the indicator as part of addressing inspector questions,engineering personnel determined that three previous failures not had not beenclassified properly.The licensee had originally classified a failure of EDG 2A on October 3, 2005, whichinvolved a broken sight glass on one of the generator bearings, as a demand failurebased on the inability of the EDG to complete its function. After reviewing it further thelicensee realized that the EDG would have started but would not have been able tocomplete its mission because the bearing would have failed due to loss of oil. Thereforethey reclassified the failure of October 3, 2005, as a failure to run. The licensee alsodetermined that two previous failures on July 20, 2006 and August 7, 2007, were notactually failures because the affected equipment was outside the boundary of thesystem.Analysis: The as-reported numbers for the Emergency AC Power MSPI for the quarterending September 2007 were -5.3E-7 for Unit 1 and -5.3E-7 for Unit 2. The effect of theimproper use of the importance measures was to change the unreliability portion of theindicator from a negative to positive number while the total indicator remained negative. After adjusting for importance measures the numbers would have been -2.0E-7 for Unit1 and -7.0E-8 for Unit 2. With the additional classification changes to the failure data thenumbers became -1.12E-6 for Unit 1 and -1.17E-6 for Unit 2. While these numbersremained in the green band, the changes also affected earlier time periods. In twoprevious quarters, June 2006 and March 2007, the Unit 2 indicator was 1.04E-6. Because this information involved licensee failure to provide complete and accurateinformation concerning a ROP performance indicator, the inspectors determined that ithad the potential to impact NRC ability to perform its regulatory function.Enforcement: 10 CFR 50.9 requires that information provided to the NRC be completeand accurate in all material respects. Contrary to this, from July 1, 2006 until December 31, 2007, the licensee provided information regarding the Emergency ACPower MSPI indicator that was inaccurate. Specifically, the importance ratios for boththe unavailability and unreliability portions of the indicator were improperly entered intothe calculation for determining the indicator resulting in inaccurate reporting of the MSPIfor Emergency AC Power. However, this item will remain unresolved pending NRC 23Enclosurereview of the previous data for the indicator and is identified as URI05000327,328/2007005-02, Improper Information Provided for MSPI. This item hasbeen entered into the licensee's corrective action program as PER 135288.4OA2Identification and Resolution of Problems.1Daily Review As required by Inspection Procedure 71152, Identification and Resolution of Problems,and in order to help identify repetitive equipment failures or specific human performanceissues for follow-up, the inspectors performed a daily screening of items entered into thelicensee's corrective action program. This was accomplished by reviewing thedescription of each new PER and attending daily management review committeemeetings..2Annual Sample Review of Breaker Problems that Resulted in Missed PreventiveMaintenance (PM)

a. Inspection Scope

In March 2007, the licensee identified two breakers that required 60-month PM byTechnical Requirements Manual (TRM) Surv eillance Requirement 4.8.3.3 had exceededthe surveillance interval and the 25% grace period. In addition, several other safety-related breakers had also exceeded the PM frequency by more than 25%. While operators complied with TRM and TS requirement s, problems controlling PM candevelop into more significant issues. Therefore, in order to understand the cause andthe work control process, the inspectors reviewed licensee actions to resolve this issue. The inspectors reviewed the PER dealing with this event, PER 120990; interviewedmaintenance, engineering, and training personnel; and reviewed several of thecorrective actions. Documents reviewed are listed in the Attachment.

b. Findings and Observations

There were no findings of significance identified during this review. The inspectorsdetermined that the root cause was thorough and that immediate and long termcorrective actions appeared to be adequate. The root cause team performed both abarrier analysis and event & causal factor analysis and determined that the transition ofbreaker preventive maintenance from the Surveillanc e Instruction (SI) schedulingprogram to the PM scheduling program lacked independent barriers to ensure breakermaintenance was kept current. They also concluded that the change managementprocess had not provided an adequate barrier. The licensee developed several actionsto address these causes and implemented them beginning in June 2007. Theseincluded designating a breaker program manager, training non-maintenance personnel on the change management process, developing a job familiarization worksheet on thechange management process for maintenance supervisors, a review of breakersurveillance packages and breaker swap WO's to ensure the documentation wasaccurate, and a walkdown of all 480V and 6.9kV drawout type breakers to ensure that 24Enclosurebreaker data was properly entered in the plant database. The actions also includedupdating PM and WO scheduling tools with the correct information. The inspectorsreviewed these actions and verified that they addressed the cause and were actuallybeing implemented.However, the inspectors noted that actions to train supervisors in the changemanagement process were not completed even though stated in the PER. Additionally,the inspectors noted that the package review and breaker walkdown actions were notcomplete. The inspectors reviewed what had been completed on these actions anddetermined that the plant database had not been completely updated but that themajority of breakers were tracked properly. For those breakers that were not tracked,the shop personnel were able to determine the correct information. The inspectorsfound the process to be cumbersome and complicated, which could increase thepotential for mistakes..3Semi-Annual Trend Review

a. Inspection Scope

As required by Inspection Procedure 71152, the inspectors performed a review of thelicensee's corrective action program and associated documents to identify trends thatcould indicate the existence of a more significant safety issue. The inspectors' reviewwas focused on repetitive equipment issues, but also included licensee trending effortsand licensee human performance results. The inspectors' review nominally consideredthe six-month period of July 2007 through December 2007, although some examplesexpanded beyond those dates when the scope of the trend warranted. Specifically, theinspectors consolidated the results of daily inspector screening discussed in Section4OA2.1 into a log, reviewed the log, and compared it to licensee trend reports for theperiod from January 2007 through October 2007 in order to determine the existence ofany adverse trends that the licensee may not have previously identified. The inspectorsalso independently reviewed RCS leakage data for the six-month period of July 2007through December 2007.

b. Findings and Observations

No findings of significance were identified. In general, the licensee had identified trendsand appropriately addressed them in their corrective action program. The inspectorsevaluated the licensee trending methodology and observed that the licensee hadperformed a detailed review. The licensee routinely reviewed cause codes, involvedorganizations, key words, and system links to identify potential trends in their data. Theinspectors compared the licensee process results with the results of the inspectors' dailyscreening and did not identify any discrepancies or potential trends that the licensee hadfailed to identify. There were two issues that had potential significance, both of whichwere tracked in the corrective action program.Following the End-of-Cycle 14 Outage in December 2006 the licensee noticed higherlevels of formaldehyde, two to three ppm, in the Unit 2 containment atmosphere prior to 25Enclosureeach weekly entry. To ensure worker safety, the licensee began increased purging ofthe Unit 2 containment in order to reduce concentrations down to less than 0.3ppm. This was a conservative decision as other methods were available to protect workers;however, by the end of the inspection period the licensee had used all of the 1000 hour0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br />sallowed by TS for purging the containment and had not yet been successful in locatingthe source. During the inspection period, the licensee applied for and received a onetime change to the TS to add 400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br />. Formaldehyde concentrations had previouslydecreased to approximately 1ppm prior to containment entries and that trend remainedstable throughout the inspection period. The licensee has installed a filtration unit in theUnit 2 containment and has indicated they would proceed with a TS amendment requestto remove the purge limit. The licensee has also contracted the services of a specialistto perform more detailed sampling on the Unit 2 containment as a further attempt tolocate the source of the formaldehyde. Before the End-of-Cycle 15 Outage on Unit 1 thelicensee also identified formaldehyde in the Unit 1 containment. These concentrationsranged from 0.2 to 0.6ppm and have been lower than that since the beginning of thenew cycle in November 2007, typically less than 0.3ppm. Because of this, less purginghas been required. The licensee has continued to monitor levels in Unit 1. Theinspectors had no further concerns with the licensee's corrective actions associated withformaldehyde.During the End-of-Cycle 15 Outage in November 2007, there were several instances onUnit 1 where foreign material was found in or entered unexpected places. Theseincluded the reactor vessel, the main condenser, the ice condenser, the main generator,and the reactor cavity. While each incident was properly entered into the correctiveaction program and none had more than minor safety significance, the actualintroduction of foreign material into unexpected places represented a decliningperformance trend from recent outages. Prior to the Unit 1 outage foreign materialincidents involved process issues by site personnel as opposed to actual foreignmaterial intrusion. The licensee initiated plans to institute specific FME control plans fordifferent areas like the spent fuel pit, reactor cavity, main turbine, and main generator. The inspectors had no current concerns with the licensee's corrective actions associatedwith FME but determined the trend should be monitored.4OA5Other Activities.1(Closed) NRC Temporary Instruction 2515/150, Rev. 3, Reactor Pressure Vessel Headand Vessel Head Penetration Nozzles (NRC Order EA-03-009) (Unit 1)

a. Inspection Scope

From October 10 - 17, 2007, the inspectors reviewed the licensee's activities associatedwith the non-destructive examination (NDE) of the reactor pressure vessel head (RPVH)penetration nozzles, the bare metal visual examination of the top surface of the RPVH,and the visual examination to identify potential boric acid leaks from pressure-retainingcomponents above the RPVH. These activities were performed in response to NRCBulletins 2001-01, 2002-01, 2002-02, and the first revision of NRC Order EA-03-009, 26Enclosure"Modifying Licenses," dated February 20, 2004, (hereafter referred to as the NRCOrder). The inspectors' review of the NDE of RPVH penetration nozzles included independentobservation and evaluation of ultrasonic (UT) examinations (for both data acquisitionand analysis), review of NDE procedures, personnel qualifications and training, and NDEequipment certifications. The inspectors also held interviews with contractorrepresentatives (Areva) and other licensee personnel involved with the RPVHexamination. The activities were reviewed to verify licensee compliance with the NRCOrder and to gather information to help the NRC staff identify possible further regulatorypositions and generic communications.The inspectors reviewed a sample of the results from the volumetric UT examinations ofRPVH penetration nozzles. Specifically, the inspectors reviewed or observed thefollowing:*Observed portions of in-process UT data acquisition scanning of RPVHpenetration nozzle 23.*Reviewed the UT electronic data with the Level III analyst for RPVH nozzles 1, 5, 19, 25, 45, 47, 68, 75, vent line, and the calibration block for the Auxiliary HeadAdaptor (AHA) probe. Nozzles reviewed included CRDM penetrations both withand without thermal sleeves and one AHA.*Reviewed the results of the UT examination performed to assess for leakage intothe annulus (interference fit zone) between the RPVH penetration nozzle and theRPVH low-alloy steel for all penetrations listed in the previous bullet.*Reviewed the procedures and results for the visual exam performed to identifypotential boric acid leaks from pressure-retaining components above the RPVH.*Reviewed the RPVH susceptibility r anking and calculation of effectivedegradation years (EDY), including the basis for the RPVH temperature used inthe calculation.

b. Observations and Findings

In accordance with the requirements of TI 2515/150, the inspectors evaluated andanswered the following questions:1) Were the examinations performed by qualified and knowledgeable personnel?

Yes. The inspectors reviewed personnel training and qualifications to verify thatvolumetric and surface NDEs were performed by trained and qualified personnel. Allexaminers were qualified in accordance with the ASME Code and had additional trainingon RPVH examination, as required in Areva's "Written Practice for the Qualification andCertification of NDE Personnel" document.

27Enclosure2) Were the examinations performed in accordance with demonstrated procedures?Yes. The Sequoyah Unit 1 RPVH has 57 control rod drive mechanism (CRDM) nozzleswith thermal sleeves, 13 with open housings (including 5 instrument column nozzles), 8with part lengths, 4 upper head injection (UHI) nozzles, and 1 vent line nozzle, for a totalof 83 nozzles. All penetration nozzles, including the vent line, were examined by remoteautomated UT from the inside diameter (ID) surface in accordance with Areva approvedprocedures 54-ISI-604-004 for open bore penetrations not using a dummy sleeve, 54-ISI-603-003 for sleeved penetra tions (including open bores which did utilize dummysleeve), and 54-ISI-605-03 for small bore penetrations (i.e. vent line).The inspectors found that Areva examination procedures for CRDM nozzles weredemonstrated to be able to detect and size flaws in the RPVH nozzles in accordancewith Electric Power Research Institute (EPRI) NDE Center's protocol contained in"Materials Reliability Program: Demonstration of Vendor Procedures for t he Inspection ofControl Drive Mechanism Head Penetrations (MRP-89)." Areva's equipmentdemonstration took place from August 14 to August 24, 2006. Areva had performed asimilar demonstration in 2002 as documented in MRP-89. However, because Arevamodified its equipment including changing the essential variables of the demonstration in2002, the demonstration was repeated. The 2006 demonstration was performed withthree RPVH nozzle mockups with multiple tube flaws representing the expected fielddegradations. These mockups were different from those used during the demonstrationperformed in 2002 (i.e. demonstration documented in MRP-89). The demonstrationadopted security provisions from the EPRI Performance Demonstration Initiative protocolby restricting the access to the mockups and making them available to Areva only whenthe EPRI NDE personnel were present. EPRI letter to Mr. Joel Whitaker of TennesseeValley Authority, dated October 8, 2007, documents the comparison of the recent Arevaequipment demonstration with the previous demonstration performed in 2002. The letter states that the scatter observed is within the variability of the ex amination and thereliability of the examinations conducted with the new instrumentation will be comparableto the previous demonstration.The procedure used for the RPVH vent line was not demonstrated under a specificprogram such as the EPRI MRP. This procedure was developed with NDE techniquessimilar to the CRDM procedures with regard to basic fundamental ultrasonic techniques. The procedure used for the PT examination of the vent line weld surface was developedin accordance with the ASME Code.3) Was the examination able to identify, disposition, and resolve deficiencies?

Yes. All indications of cracks or interference fit zone leakage are required to be reportedfor further examination and disposition. Based on observation of the examinationprocess, the inspectors considered deficiencies would be appropriately identified,dispositioned, and resolved. UT indications associated with the geometry and surfacefeatures of the examined volume were identified in several penetration tubes. None ofthe indications exhibited crack-like characteristics and were appropriately dispositionedin accordance with procedures.

28Enclosure4) Was the examination capable of identifying the primary water stress corrosioncracking (PWSCC) and/or RPVH corrosion phenomena described in the NRCOrder EA-03-009?Yes. The NDE techniques employed for the examination of RPVH nozzles had beenpreviously demonstrated under the EPRI MRP/Inspection Demonstration Program ascapable of detecting PWSCC-type manufactured cracks as well as cracks from actualsamples from another site. Based on the demonstration, observation of in-processexaminations, and review of NDE data, the inspectors determined that the licensee wascapable of identifying PWSCC and/or corrosion as required by the NRC Order. 5) What was the physical condition of the RPVH (e.g. debris, insulation, dirt, boronfrom other sources, physical layout, viewing obstructions)?The licensee performed a 100% bare metal visual (BMV) inspection of the top of theRPVH, including 360 around each penetration using a remote visual robotic crawler forareas inside the lead shielding and underneath the raised insulation package. Thesurface sloping down from the shielding to the flange was visually inspected directly by aqualified VT-2 examiner. The inspectors independently reviewed portions of the remoteinspection video, particularly in the area around penetration 75, which revealed boricacid crystals around the penetration and on the sloping head surface both above andbelow the penetration. This area was reinspected after cleaning, and the boric acid wasjustifiably attributed to an identified conoseal leak above the vessel head. The ultrasonicinspection confirmed that there was no through-wall leakage at the penetration. For theother areas of the head, no insulation, dirt, or other general debris was present thatcaused viewing obstructions in the areas of interest. The inspectors determined that thephysical condition of the head and the actions taken by the licensee were adequate tomeet the requirements of the NRC Order.6) Could small boron deposits, as described in NRC Bulletin 2001-01, be identifiedand characterized?Yes. The BMV examination was determined by the inspectors to be capable ofidentifying and characterizing small boron deposits as described in NRC Bulletin 2001-01. The remote exam was VT-2 qualified and able to resolve, at a minimum, the 0.105-inch characters on an ASME IWA-2210-1 Visual Illumination Card.7) What material deficiencies (i.e., cracks, corrosion, etc.) were identified thatrequired repair?There were no identified examples of RPVH penetration cracks, leakage, materialdeficiencies, head corrosion, or other flaws that required repair. As discussedpreviously, there were some UT indications at J-groove welds that were dispositioned asmetallurgical/geometric indications (not service related). Additionally, there were someminor surface indications detected on some of the tubes, likely due to thermal sleevecentering pad wear.

29Enclosure8) What, if any, impediments to effective examinations, for each of the appliedmethods, were identified (e.g., centering rings, insulation, thermal sleeves,instrumentation, nozzle distortion)?The penetration nozzles with thermal sleeves and centering pads did not impedeeffective collection of data. Concerning examination coverage, the NRC Order requiresthat each tube's volume is inspected from a minimum of 2 inches above the highestpoint of the J-groove weld to 2 inches below the lowest point of the J-groove weld, or 1inch with a stress analysis. The licensee had performed a stress analysis and theinspectors verified that the minimum examination coverages required by the NRC Orderwere met. 9) What was the basis for the temperature used in the susceptibility rankingcalculation? NRC Order EA-03-009 requires that licensees calculate the effective degradation years(EDY) of the RPVH to determine its susceptibility category, which subsequentlydetermines the scope and frequency of required RPVH examinations. The operatingtemperature of the RPVH is an input to this calculation. Therefore, an incorrect temperature i nput could result in pl acing the RPVH in an incorrect susceptibilitycategory. The licensee uses the cold leg temperature in this calculation. In Supplement No. 1 to the NRC's Safety Evaluation Report (SER) dated February 1980,the NRC concluded that scale model tests provided reasonable assurance that theupper head would operate at the cold leg temperature. However, the NRC staff alsorequired that plant data be acquired to confirm the head temperature. The inspectorsreviewed this data which confirmed that the head operated at approximately cold legtemperature with some minor thermocouple variations. In addition, both units underwenta modification since this testing to increase bypass flow to the head from 4% to about7%. This gives further assurance that the RPVH operates at cold leg temperature. Forthese reasons, the inspectors concluded that the licensee had an adequate basis for their temperature input to the susceptibility ranking calculation, which results in Unit 1being placed in the Low category.10) During non-visual examinations, was the disposition of indications consistent withthe NRC flaw evaluation guidance?There were no indications considered to be flaws found during the RPVH examination.

11) Did procedures exist to identify potential boric acid leaks from pressure-retainingcomponents above the RPVH?Yes. Procedure 0-PI-DXX-068-100.R, Rev. 1, "Monitoring of Reactor Head Canopy SealWelds for Leakage," is implemented every outage and meets the requirements of theNRC Order. However, inspection of conoseals and other bolted connections above theRPVH, such as the RVLIS line, are covered under the Boric Acid Program. Theinspectors determined that the program and procedure implementation met the 30Enclosurerequirements of the NRC Order. The inspectors reviewed the inspection results for thisoutage and found that no indications of boric acid leakage from canopy seal welds wereidentified. However, as discussed previously, a boric acid leak from a conosealconnection was identified (see further discussion below).12)Did the licensee perform appropriate follow-on examinations for indications ofboric acid leaks from pressure-retaining components above the RPVH?Yes. A conoseal leak was identified during inspection. The licensee performedappropriate follow-on examinations by tracing the leak down to the RPVH and noting theaffected areas and penetrations. The noted areas were then cleaned and re-inspectedto verify the integrity of the RPVH base metal. An action to fix the conoseal leak wasalso taken to prevent further leakage onto the RPVH. The inspectors reviewed thelicensee's actions and determined that they were in accordance with the requirements ofthe NRC Order..2(Closed) Temporary Instruction (TI) 2515/166, Pressurized Water Reactor ContainmentSump Blockage (NRC Generic Letter 2004-02) - Units 1 and 2

a. Inspection Scope

The inspectors verified the Unit 1 implementation of the licensee's commitmentsdocumented in their September 1, 2005, response to Generic Letter 2004-02, PotentialImpact of Debris Blockage on Emergency Recirculation During Design Basis Accidentsat Pressurized Water Reactors. The commitments included a permanent screenassembly modification, a license amendment request to change the UFSAR descriptionof the sump screen analysis methodology, and submittal of a supplemental response toGL 2004-02. This review included the sump screen assembly installation procedure,screen assembly modification 10 CFR 50.59 evaluation, structural (debris) loadingcalculation, and validation testing of the modified sump screen design. The inspectorsalso reviewed the foreign materials exclusion controls and the completed QualityAssurance / Quality Control records for the screen assembly installation. The inspectorsconducted a visual walkdown to verify the installed screen assembly configuration wasconsistent with drawings and the tested configuration. The inspectors also verified thedesign criteria for screen gap. Additionally, the inspectors reviewed the status of Unit 2GL 2004-02 commitment items that were not verified complete during the Unit 2 TI2515/166 inspection performed on December 12-13, 2006.b.Findings and ObservationsNo findings of significance were identified.

The inspectors determined the following answers to the Reporting Requirementsdetailed in TI 2515/166-05 issued 5/16/07:05.aTVA implemented plant modifications and procedure changes at Sequoyahcommitted to in their GL 2004-02 response for Unit 1.

31Enclosure05.bTVA updated the Sequoyah Unit 1 licensing bases to reflect the correctiveactions taken in response to GL 2004-02.05.cNo extensions of 12/31/2007 deadline for GL 2004-02 commitment completionshave been applied for or granted to Sequoyah Unit 1. An extension may besought based on the results of ongoing chemical effects testing to validate thedesign.Unit 2 GL 2004-02 commitment items were complete.

TI 2515/166 is closed for Sequoyah Unit 1 and Unit 2, no additional modifications orprocedural changes under GL 2004-02 are anticipated.4OA6Meetings, Including ExitExit Meeting SummaryOn January 9, 2008, the resident inspectors presented the inspection results to Mr.Timothy Cleary and other members of his staff, who acknowledged the findings. Theinspectors asked the licensee whether any of the material examined during theinspection should be considered proprietary. No proprietary information was identified.An interim exit was conducted on October 19, 2007, to discuss the findings of theTI2515/166 inspection. Although proprietary information was reviewed during theinspection, no proprietary information is included in this report.In addition, on October 26, 2007, the inspectors discussed results of the onsite radiationprotection inspection. The inspectors noted that proprietary information was reviewedduring the course of the inspection but would not be included in the documented report.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

D. Bodine, Chemistry/Environmental Manager

D. Boone, Radiation Protection Manager

C. Church, Plant Manager

K. Clayton, Maintenance Manager

T. Cleary, Site Vice President

L. Cross, Maintenance Shop Superintendent

B. Dungan, Outage and Site Scheduling Manager

K. Jones, Engineering Manager

Z. Kitts, Licensing Engineer

A. Little, Acting Site Security Manager

T. Marshall, Operations Superintendent

G. Morris, Licensing Manager

M. Palmer, Operations Manager

K. Parker, Maintenance and Modifications Manager

J. Proffitt, Li

censing Engineer

J. Smith, Licensing Supervisor and Industry Affairs Manager

N. Thomas, Licensing Engineer

K. Wilkes, Emergency Preparedness Manager

NRC personnel

R. Bernhard, Region II, Senior Reactor Analyst

B. Moroney, Project Manager, Office of Nuclear Reactor Regulation

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000327,328/2007005-02 URIImproper Information Provided for MSPI (4OA1).Opened and

Closed

05000327/FIN-2007005-01 NCVFailure to Effectively Implement Foreign Material Control Requirements inthe RCS (Section 1R20).TI 2515/150TIReactor Pressure Vessel Head and VesselHead Penetration Nozzles Sequoyah Unit 1(NRC Order EA-03-009) (Section 4OA5.1)

2AttachmentTI 2515/166TIPressurized Water Reactor ContainmentSump Blockage (NRC Generic Letter 2004-02) - Units 1 and 2) (Section 4OA5.2)

LIST OF DOCUMENTS REVIEWED

Section R01: Adverse Weather ProtectionSPP-10.14, Freeze Protection, Revision 00-PI-OPS-000-006.0, Freeze Protection, Revision 460-GO-14-2, Operator Rounds - Aux Bldg Round, Revision 191-PI-EFT-234-706.0, Freeze Protection Heat Trace Functional Test, Revision 332-PI-EFT-234-706.0, Freeze Protection Heat Trace Functional Test, Revision 191,2-45W1635-92, Wiring Diagrams Local Instrument Panels Connection Diagrams, Revision 6Section R06: FloodingSequoyah Nuclear Plant Probabilistic Safety Assessment Individual Plant Ex amination Volume3, Revision 1WO 04-775349-000, Turbine Building Station Sump Level Switch Functional TestWO 05-775248-000, Turbine Building Demin Sump Alarm Level Switch Functional TestWO 06-777324-000, Turbine Building Oil Sump Level Alarm Level Switch Functional TestSection R07: Heat Sink PerformanceFSAR 9.2.1, Component Cooling System1,2-47W859-1, Mechanical Flow Diagram - Component Cooling System, Revision 52Section R08: Inservice Inspection Activities0-TI-DXX-000-097.1, Boric Acid Corrosion Control program, Rev. 0001N-UT-65, Generic Procedure for the Ultrasonic Through Wall Sizing in pipe Welds, Rev. 41-SI-SXI-068-114.3, Steam Generator Tubing Inservice Inspection and Augmented Inspections, Rev. 00010-SI-DXI-000-114.3, ASME SECTION XI ISI/NDE PROGRAM UNIT 1 and UNIT 2, Rev. 00021-SI-SXI-068-114.3, Steam Generator Tubing Inservice Inspection and Augmented Inspections, Revision 1Degradation Assessment for Sequoyah Unit 1 Cycle 15Operational Assessment Report from Unit 1 Cycle 13 Refueling OutageUnit 1 Cycle 15 Replacement Steam Generator Tubing Examination Scan Plan, Revision 0Self Assessment

CRP-ENG-009 SQN ASME Section XI ProgramSelf Assessment 06SQN-12-ENG-XI ASME Section XI Inservice Inspection (ISI) ProgramSQN-ENG-03-007 Boric Acid Program Effectiveness AssessmentSPP-9.7, Corrosion Control Program, Rev. 13Technical Instruction 0-TI-DXX-000-097.1, Rev. 01, Boric Acid Corrosion Control ProgramBP-257, Rev. 5, TVA Business Practice, Integrated Material Issues Management Plan, App. A

3AttachmentN-UT-76, Rev. 6, Generic Procedure for Ultrasonic Examination of Ferritic Pipe Welds.N-UT-64, Rev. 9, Generic Procedure For The UT Examination of Austenitic Pipe WeldsN-VT-1, Visual Examination Procedure for ASME Section XI Preservice and Inservice N-VT-15, Rev. 5, Visual Examination of Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants0-VI-MOD-068-001.0, Vendor Instruction for Welding Activities Associated with Alloy 690 WeldOverlays, Rev. 0002PER

100694, Leak check of the main generator bushings for H2 leakage prior to depressurizingthe generatorPER

100931, U-1 wafer valve floor penetration has signs of leakage of dried boric acid.PER

100940, Boric acid corrosion: 1-VLV-67-661A, Borated Water Leak.PER

104474,

SQN-1-VLV-062-0546 has packing leakage (one drop per minute) identified underWO 06-775022-000PER

101708, A crack indication was identified on Unit 1 Low Pressure Turbine (TN 12751)at balance hole 27 on the inlet side of disc number 2 (generator end) with depth measuring 1.15 in.PER

100929, When preparing to add chemicals to U1 S/G #2 a leak was discovered at a hose coupling in the mainsteam vent line.PER

101471, During the Unit 1 Cycle 14 Reactor Vessel internal examination by the Inservice Inspection Organization (ISO) two indications were noted on the vessel outlet nozzle mating surface for the # 4 Hot Leg (ISI inspection location N-18).PER

117945, Missed inspection of 11 SG tubes during U2C13 contrary to TechnicalSpecificationsSection R11: Licensed Operator RequalificationE-0, Reactor Trip or Safety Injection, Revision 29ES-0.5, Equipment Verifications, Revision 0E-1, Loss of Reactor or Secondary Coolant, Revision 23E-3, Steam Generator Tube Rupture, Revision 17FR-Z.1, High Containment Pressure, Revision 17AOP-S.01, Loss of Normal Feedwater, Revision 12AOP-S.02, Loss of Condenser Vacuum, Revision 10Section R12: Maintenance Rule ImplementationWO 07-779781-000, Replace Unit 2 B-train Containment Purge Air Exhaust Charcoal FilterTagout 2-TO-2007-0018, Clearance 2-30-0712

SPP-10.2, Clearance Procedure to Safely Control Energy, Revision 11SPP-6.6, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -10CFR50.65, Revision 9TI-4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -10CFR50.65, Revision 0020Sequoyah System Status Report, Main Steam System, October 2007Section R13: Maintenance Risk Assessments and Emergent Work Evaluation1,2-47W845-2, Mechanical Flow Diagram - Essential Raw Cooling System, Revision 94

4Attachment1,2-47W845-4, Mechanical Flow Diagram - Essential Raw Cooling System, Revision 161,2-47W845-6, Mechanical Flow Diagram - Essential Raw Cooling System, Revision 30Sentinel Runs - October 9 to October 23, 2007Tagout 1-TO-2007-0017, Component Cooling Heat Exchanger Discharge Valve to Header

BORAM-Sentinel Outage Safety Assessment for October 30, 2007Sentinel Run - November 12 to December 2, 2007Sentinel Run - December 10 to December 23, 2007Section R15: Operability Evaluations1,2-45N779-6, Wiring Diagram, 480V Shutdown Aux Power Schematic Diagrams Sheet 6,Revision 131,2-45N765-3, Wiring Diagram, 6900 Volt Shutdown Aux Power Schematic Diagram Sheet 3,Revision 221,2-45N765-4, Wiring Diagram, 6900 Volt Shutdown Aux Power Schematic Diagram Sheet 4,Revision 31,2-45N700-1, Key Diagram - 12V AC and 125V DC Vital Plant Control Power System,Revision 40Functional Evaluation 42301 - Vital Inverter Switch Lug Load CapacityNEDP-22, Functional Evaluations, Revision 5OPN218E.018, Electrical Training Lesson Plan - 120V AC Systems1-SI-SFT-067-739.0, ERCW Lower Containment Flow Balance, Revision 6MDQ0300-980037, Diesel Generator Operabililty with Outsi de Air Dampers Closed Based onRoom Temperature, Revision 0Section R19: Post Maintenance Testing1-SI-OPS-000-009.0, Actuation of ECCS and Boron Injection Flowpath Valves via SI Signal,Revision 1PER

132143, MOV Striker Plates MisadjustedSI-93, Reactor Trip Instrumentation Functional Tests Conditional 31 Days Prior to Startup,Revision Draft 28BPER

132552, Reactor Trip Breakers Did Not ClosePER

132554, New Reactor Trip Switch is Sensitive1,2-45N699-1, Wiring Diagrams Reactor Protection System Schematic Diagrams Sheet 1,Revision 71-45N1624-11, Wiring Diagram Reactor Trip Switchgear Connection Diagram Sheet 11,Revision 11-PI-OPS-000-003.0, Periodic Stroking of Unit 1 Time Critical Valves, Revision 11-SI-SXV-063-206.0, Residual Heat Removal Primary and Secondary Check Valve IntegrityTest, Revision 91-47W811-1, Flow Diagram Safety Injection System, Revision 72Section R20: Refueling and Outage Activities1-PI-IXX-068-005.0, Installation and Removal of the Mansell Level Monitoring System DuringRefueling Outages, Revision 12

5Attachment

0-GO-13, Reactor Coolant System Drain and Fill Operations, Revision 581,2-47W813-1, Flow Diagram Reactor Coolant System, Revision 520-MI-MRR-068-005.0, Removal of Reactor Pressure Vessel Head and Attachments, Revision

280-MI-MXX-000-026.0, Control of Heavy Loads in Critical Lifting Zones

NUREG-0612, Revision

170-MI-ECR-303-911.0, Reactor Building (Polar) Crane Periodic Inspection, Revision 5WO 06-781659-000, Reactor Pressure Vessel DisassemblyWO 06-777976-000, Unit 1 Polar Crane InspectionTVA Response to Phase I Requests of Generic Letters80-110 and 81-07, dated March 1, 1982TVA Response to Phase I Requests of Generic Letters80-110 and 81-07, dated February 25, 1983TVA Response to Phase I Requests of Generic Letters80-110 and 81-07, dated February 28, 1984TVA Response to Phase I Requests of Generic Letters80-110 and 81-07, dated July 27, 1984TVA Response to Phase I Requests of Generic Letters80-110 and 81-07, dated December 7, 1984TVA Response to Phase II Requests of Generic Letters80-110 and 81-07, dated January 24, 1985NRC Safety Evaluation Report on Control of Heavy Loads, dated March 26, 1985DCN M-06332-A, Install Removable Shielding to Reactor Head Lifting Columns, Revision 0SQN Unit 1 Cycle 15 Outage Safety Plan, Revision C ScheduleNUMARC 91-06 Guidelines for Industry Actions to Assess Shutdown Management0-GO-15, Containment Closure Control, Revision 23TVA 90-Day Response Letter to Generic Letter 88-17, dated February 2, 1989,

FHI-3, Movement of Fuel, Revision 510-PI-OPS-068-673.W, Weekly Requirements for Modes 5 and 6 Operations, Revision 10SQN-SQS2-0133, Midloop Design Information Calculation, Revision 60-TI-OXX-068-001.0, Reactor Coolant System Hot Leg Vents and Generic Letter 88-17 Issues,Revision 151-PI-OPS-068-673.D, Daily Requirements for Reduced Inventory/Midloop Operation, Revision

11TI-45, Physical Verification of Core Load Prior to Vessel Closure, Revision 25PER

126835, Containment Closure Under Adverse Conditions0-SI-OPS-000-011.0, Containment Access Control During Modes 1-4, Revision 280-RT-NUC-000-003.0, Low Power Physics Testing, Revision 210-RT-NUC-000-008.0, Low Power Physics Testing Acceptance Criteria, Revision 80-GO-2, Unit Startup From Hot Standby to Reactor Critical, Revision 28Section R22: Surveillance TestingFSAR Section 6.3, Emergency Core Cooling SystemFSAR Figure 6.3.2-5, RHR Pump Minimum ECCS Performance Curve1,2-47W810-1, Flow Diagram Residual Heat Removal System, Revision 501-47W811-1, Flow Diagram Safety Injection System, Revision 71USNRC memo of December 13, 1999, NRR Response to

TIA 99-02, Adequacy of SequoyahIce Condenser Ice Bed and Baskets

6AttachmentR.G. 1.163, Performance Based Containment Leak Test ProgramNEI 94-01, Industry Guideline for Implementing Performance Based Option of 10 CFR Part 50Appendix J, Revision 0ANSI/ANS 56.8-1994, Containment System Leakage Testing RequirementsSection R23: Temporary Plant ModificationsWO 06-772888-000, Install CDWE

TACF0-SO-77-7, Floor Drain Collector Tank, Revision 6UFSAR Section 9.3.3, Equipment and Floor DrainageUFSAR Section 11.2, Liquid Waste Systems1,2-47W830-2, Mechanical Flow Diagram - Waste Disposal System, Revision 291,2-47W830-2, Mechanical Flow Diagram - Waste Disposal System, Revision 301,2-47W830-7, Mechanical Flow Diagram - Waste Disposal System, Revision 181,2-47W830-7, Mechanical Flow Diagram - Waste Disposal System, Revision 19SPP-9.5, Temporary Alterations, Revision 8

Section 2OS1: Access Control To Radiologically Significant AreasTennessee Valley Authority (TVA), Sequoyah Nuclear Plant (SNP), Radiological Control

Instruction (RCI)-01, Radiation Protection Program, Rev. 64TVA, SNP,

RCI-03, Personnel Monitoring, Rev. 48TVA, SNP,

RCI-11, Bioassay Program, Rev. 15TVA, SNP,

RCI-14, Radiation Work Permit (RWP) Program, Rev. 39TVA, SNP,

RCI-15, Radiological Postings, Rev. 15TVA, SNP,

RCI-16, Radiography, Revisions 10 and 11TVA, SNP,

RCI-21, Control of Radioactive Materials, Rev. 13TVA, SNP,

RCI-22, Contamination Control, Rev. 16TVA, SNP,

RCI-24, Control of Very High Radiation Areas, Rev. 8TVA, SNP,

RCI-28, Control of Locked High Radiation Areas, Rev. 6TVA, SNP,

RCI-29, Control of Radiation Protection Keys, Rev. 7TVA, SNP, Radiation Protection Management Directive (RMD)

FO-02, Radiation and

Contamination Surveys, Rev. 19TVA, SNP, RMD

FO-03, Alpha Contamination Monitoring and Controls, Rev. 0TVA, SNP, RMD

FO-08, Radiological Surveys of Equipment and materials leaving the RCA,

Rev. 0TVA, SNP, Technical Instruction 0-TI-NUC-000-002.0, Storing Material in Spent Fuel Pool or

New Fuel VaultTVA Standard Programs and Processes (SPP) - 3.1, Corrective Action Program, Rev. 12Air Sample Survey Numbers (Nos.)

101307005,

101307023,

101307030,

101307050,

101407021,

101407032,

101507019,

102507009, and 102507010Internal Dose Calculation Report generated on 10/14/07LHRA Key Control Log SheetsPositive Whole Body Count Tracking Log (SQN QA Form 1.36), Dated 08/28/07-10/23/07Printout of 20 Individuals with Highest TEDE Dose for 2006 and 2007, printed on 10/02/07Printout of PER summaries for all personal contaminations from May 2006 through October

2007

7AttachmentRadiation Work Permit (RWP) No.

07000805, Revision (Rev.) 0, Unit 2 Outside Polar Crane

Wall - Fan Rooms, Acc. Rooms, and RacewayRWP No.

07024240, Rev. 0, Unit 1 Lower Containment, Routine Plant MaintenanceRWP No.

07034020, Rev. 0, Unit 1 Lower Containment, Steam Generator Primary Side 1-4SDE/DDE/LDE Dose Calculation Package for PC# 20070036Sequoya Nuclear Station (SNS) Visual Survey Data System (VSDS) Survey Nos. 080207-5,

100607-5, 100907-1, 100907-2, 100907-5,

100907-25, 101007-7, 101507-3, 101107-2,

101607-6, 102107-6,

102207-15, and 102307-507-SQN-30-RAD-RD, Snapshot Self-Assessment Report, February 12 - 13, 2007Problem Evaluation Report (PER)

112196, ALPHA MonitoringPER

115630, VHRA Key Control - Procedural ViolationPER

130039, Radiographer dose rate alarmPER

131962, U1C15 Personal ContaminationsPER

132777, Radcon has posted signs on U1 and U2 West Valve Vault Room doorsPER

132792, Access at 714'PER

132821, Clothing impact on skin dose assessmentPER

132822,

PCM-1B Trouble LightSQN-RP-06-002, Self-Assessment Report, Dated 09/07/062OS2 ALARA Planning and ControlsTVA, SNP,

RCI-10, ALARA Program, Rev. 30TVA, TVAN RCDP - 105, Personnel Inprocessing and Dosimetry Administrative Processes,

Rev. 0TVA, TVAN SPP, SPP - 3.1, Corrective Action Program, Rev. 12TVA, TVAN SPP, SPP - 5.2, ALARA Program, Rev. 3ALARA Outage Report for U2C14ALARA Outage Report for U1C14Dose Records of all declared pregnant workers (4) during the period 10/05 to 09/07Fiscal Year 2005 and 2006 Personnel Exposure by Section and GoalsList of Active Hot Spots, Dated 08/229/07RCI-19, Rev. 10, Appendix A, Temporary Shielding Request Form, U1 C15 Upper Containment

Reactor Head StandRWP No.

07024240, U-1 Containment - General Walkdowns of Various Systems, Engineering

Activities to Include:

Installation of /Removal of ECCS Flow Test Equipment, Manipulation of

Throttle Valves and Tech Support Temperature and Pressure Walkdowns for Mode 3RWP No.

07024260, U-1 Lower Containment, Inside Excess Letdown Heat Exchanger Room,

Inspections, Tests and Valve AlignmentsRWP No.

07034020, U-1 Lower Containment Steam Generators

1-4, Full Jump for Installing and Removing Nozzle DamsRWP No.

07034080, U-1 Lower Containment - IPCW/)PCW and 734' Elevation, Aux Building,

Radcon, Laborer, Boilermaker and Westinghouse Support to include Equipment Monitoring,

Movement of Equipment into and out of Zones, Transferring Trash, Cleaning Stud Bolts (No

Entry to Platform)RWP No.

07044131, U-1 Upper Containment/Reactor Cavity:

Tension/Detension Reactor

Reactor Head Stud Bolts and Associated Work

8AttachmentSNS VSDS Survey Report, Survey Nos.

100407-04, 1R112.WMF - R112 U1 #2 RCP Seal

Platform, Dated 10/04/07; and

100407-16, 1R141.WMF - R141 U1 Inside Polar Crane Wall,

Dated 10/04/07Sequoyah Nuclear Plant (SQN) - ALARA Committee Meeting Minutes dated01/17/07,

02/21/07,

04/18/07, 08/03/07, 08/13/07 and 08/27/07SQN ALARA Planning Report (APR) 2007-10, U1 C15 RFO, U1 Upper Containment, Aux

Building, DAW Building and other areas as necessarySQN

APR 2007-12, U1 C15 Steam Generator Primary Side Inspection and MaintenanceSQN

APR 2007-31, U1 C15 Reactor Head Penetration Volumetric ExamsSQN

APR 2007-32, U1 C15 Pressurizer Alloy 600 Weld OverlaySQN

APR 2007-41, U1 C15 Excess Letdown Flow Control Valve RepairSQN

APR 2007-44, U1 C15 Reactor Head Bare Metal InspectionSQN

APR 2007-45, Inspect and Repair Pressurizer Heater CablesSQN NQA Form 5.47, Steam Generator Dose Awareness Form, Dated 10/13/07U1 C15 ALARA Summary, Dated 10/25/07U1 C15 Baseline Outage Estimate and ProjectsPER

132048, U1C15 ALARA Planning Report 2007-31, Reactor Head Penetration Exams and

2007-44 Reactor Head Bare Metal Inspection exceeded their total task dose estimate prior to site ALARA committee review, Dated 10/15/07Self-Assessment Report, Assessment No.

SQN-RP-06-001, ALARA Dose Controls2PS1Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems0-PI-CEM-000-010.3, Ground Water Monitoring, Rev.

000010 CFR Part 50.75(g) Decomissioning FilesTritium sample results, Sample wells 24, 31, and

GP-13, August 2003 - August 20072PS2 Radioactive Material Processing and Transportation0-SO-77-29, Waste Processing, Rev. 11Process Control Program, Rev. 3Radioactive Material Shipment Manual, Vols. II & III, Rev. 38RHSI-1, Packaging Dry Active Waste for Shipment to a Waste Processor/Broker or a

Commercial Radwaste Burial Facility, Rev. 8RWTP-100, Radioactive Material/Waste Shipments, Rev. 4RWTP-101, 10

CFR 61 Waste Characterization, Rev. 0RWTP-102, Use of Casks, Rev. 1SPP-3.1, Corrective Action Program, Rev. 1210 CFR Part 61 Radioactive Waste Stream Analysis Reports, DAW, Dated 05/17/05 and

12/31/06; CVCS Resin, Dated 07/01/06 and 02/12/072006 Annual Radioactive Effluent Release ReportCoC No. 9168, Model No. CNS 8-120B Shipping Package, Rev. 15Mechanical Flow Diagram No. 1,2-47W830-2, Waste Disposal System, Dated 07/06/88Shipment Number (No.) 05-0706, DAW, Dated 07/29/05Shipment No. 06-1011, Filters, Dated 10/30/06Shipment No. 06-1216, Welding Equipment, Dated 12/19/06

9AttachmentShipment No. 07-0505, Long Handle Tools, Dated 05/11/07Shipment No. 07-0801, Primary Resin, Dated 08/08/07Survey No. 092307-2, Waste Evaporator Package Rooms, Dated 09/23/07TACF 0-06-009-077, 50.59 Screen for Temporary Liquid Radwaste Line, Rev. 1Torque Wrench Tool Room Issue Ticket, No.

304678, Dated 08/06/07Westinghouse Electric Company Radioactive Materials License No.

SNM-770, Amend. 25CRP-BPS-05-003, Transportation and Shipping of Radioactive Materials Focused Self-

Assessment, Dated 07/18/05 - 08/12/05PER

131420, Discrepancy found on liquid radwaste system diagram, Dated 10/04/07PER

108962, Resin beads found in Holdup Tank A, Dated 08/17/06PER

111786, Resin identified at the discharge port of sandpiper pump, Dated 09/28/06PER

116014, Radioactive material shipment received at warehouse without proper radcon notification, Dated 12/06/06PER

120424, Cable found protruding from lid of HIC, Dated 02/26/07PER

131421, Differences discovered between vendor lab and in-house gamma analyses of

10

CFR 61 radwaste samples, Dated 10/04/07

Section 4OA1: Performance Indicator VerificationNEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5NUREG 1022, Event Reporting Guidelines - 10

CFR 50.72 and 50.73, Revision 2Mitigating System Performance Index Basis Document, Revision 3MSPI Derivation Report, Unit 1 and Unit 2 Unavailability Index, Emergency AC Power System,September 2007MSPI Derivation Report, Unit 1 and Unit 2 Unreliability Index, Emergency AC Power System,September 2007MSPI Derivation Report, Unit 1 and Unit 2 Unavailability Index, High Pressure Injection System,September 2007MSPI Derivation Report, Unit 1 and Unit 2 Unreliability Index, Hi gh Pressure Injection System,September 2007MSPI Derivation Report, Unit 1 and Unit 2 Unavailability Index, Heat Removal System,September 2007MSPI Derivation Report, Unit 1 and Unit 2 Unreliability Index, Heat Removal System,September 2007MSPI Derivation Report, Unit 1 and Unit 2 Unavailability Index, Residual Heat Removal System,September 2007MSPI Derivation Report, Unit 1 and Unit 2 Unreliability Index, Residual Heat Removal System,September 2007MSPI Derivation Report, Unit 1 and Unit 2 Unavailability Index, Cooling Water System,September 2007MSPI Derivation Report, Unit 1 and Unit 2 Unreliability Index, Cooling Water System,September 2007Sequoyah Nuclear Plant Desktop Guideline for Identification and Reporting of

NEI 99-02

Performance Indicators for Occupational Exposure Control EffectivenessSPP-3.4, Performance Indicator and MOR Submittal Using INPO Consolidated Data Entry,

Rev. 6SNS VSDS Survey No. 112806-10Sequoyah Nuclear Plant (SNP), Semiannual Radioactive Effluent Release Report - 2006,

10Attachment

Gaseous Effulents - Summation of All Releases, U1, 10/01 - 12/31/06SNP, Semiannual Radioactive Effluent Release Report - 2007, Gaseous Effulents - Summation of All Releases, U1, 01/01 - 09/30/07TVA, SNP, Gaseous Radioactive Waste Release Permits 2007216.027.039G and

2007152.008.049.LPER

115482, Dose AlarmPrintout of PER summaries for all dose and dose-rate ED alarms from 5/01/06 - 9/30/07

Section 4OA2: Identification and Resolution of ProblemsSI-266.2.1, Inspection Verification of

ITE 7.5HK-500 6900V Breakers and Siemens 6900VVacuum Breakers, Revision 29SPP-2.1, Administration of Standard Programs & Processes and Standard DepartmentProcedures, Revision 12EMQ003.004, Task Qualification Standard for ITE/ABB 7.5HK500 Circuit BreakerRefurbishment, Revision 0EMQ002.002, Task Qualification Standard for Repair/Adjust/Inspect/Clean/Test WestinghouseDS Circuit Breakers, Revision 0MTE211.006, Westinghouse DS Breaker Reconditioning Lesson Plan, Revision 1MTE211.008, Westinghouse DS Breaker Maintenance Lesson Plan, Revision 0TRN-3, Administration of On-The-Job Training and Task Performance Evaluation, Revision 13TNA 2007-5-MTG-MS, Training Needs Analysis on Change Management, Revision 0MTS037.100, Maintenance Supervisor Training Job Familiarization Guide, Revision 0MST001.028, Maintenance Supervisor Continuing Training on Change Management, Revision 0MMMD 07-001, Rack Out Breaker Program, Revision 0Breaker Walkdown Database, dated June 8, 2007PER 76068, Breakers Passed the SQN Extension DateSequoyah Nuclear Plant Integrated Trend Report for May 1 to October 31, 2007Sequoyah Nuclear Plant Integrated Trend Report for January 1 to April 30, 2007

Section 4OA5: OtherDCN 22178, Modify Containment Sump Screens as required by

NEI Methodology, dated 3/2/07TVA letter to NRC, Sequoyah Response to

GL 2004-02. dated 9/01/05GL 2004-02 Supplemental Response, Sequoyah Nuclear Plant Units 1 & 2, - NRC

GL 2004-02,Potential Impact of Debris Blockage on Emergency Reicrculation during Design Basis Accidentsat PWRs (Draft dated 12/15/06)0-PI-DXX-068-100.R, Monitoring of Reactor Head Canopy Seal Welds For Leakage, Rev. 10-SI-DXI-000-114.3 Attachment 10, Augmented Examinations (Unit 1)54-PT-200-07, "Color Contrast Solvent Removable Liquid Penetrant Examination ofComponents," Rev. 754-ISI-604-004, "Automated Ultrasonic Examination of Open Tube RPV Closure HeadPenetrations," Rev.454-ISI-603-003, "Automated Ultrasonic Examination of RPV Closure Head PenetrationsContaining Thermal Sleeves," Rev. 3 54-ISI-605-03, "Automated Ultrasonic Examination of RPV Closure Head Small BorePenetrations," Rev. 3

11AttachmentN-VT-17, Visual Examination for Leakage of PWR Reactor Head Penetrations, Rev. 4Engineering Information Record 51-9027415-000, RPV Head Penetration Inspection Plan andCoverage Assessment for Sequoyah Units 1 and 2Calculation

C-3217-00-02, Sequoyah 1 and 2 CRDM and Instrument Column Nozzle StressAnalysisCalculation

MDQ-001-068-2007-0180, Calculation for the Determination of Total EffectiveDegradation Years (EDY) for the Sequoyah Unit 1 Reactor Pressure Vessel (RPV) HeadPER

131744, Boron leak discovered at L-15 conosealO-SI-DCS-079-001.0

HI-Trac Average Surface Dose Rates, NRC COC #1014, Amendment 1,

Rev. 3O-SI-DCS-079-002.0

HI-Trac Contamination Surveys, NRC COC #1014, Amendment 1, Rev. 3O-SI-DCS-079-003.0

HI-Storm Average Surface Dose Rates, NRC COC #1014, Amendment 1,

Rev. 3O-SI-DCS-079-004.0

HI-Storm Shielding Effectiveness Surveys, NRC COC #1014, Amendment

1, Rev. 0O-SI-DCS-079-005.0

HI-Trac Surface Dose Rates, NRC COC #1014, Amendment 2, Rev. 1O-SI-DCS-079-006.0

HI-Trac Contamination Surveys, NRC COC #1014, Amendment 2, Rev. 0O-SI-DCS-079-007.0

HI-Storm Surface Dose Rates, NRC COC #1014, Amendment 2, Rev. 1SQN, QA Form 1.22, Area TLD Posting Data Sheets, 4

th Quarter 2006; 1

st Quarter 2007;

2nd Quarter 2007; and 3

rd Quarter 2007SNS VSDS Quarterly Survey Reports for Dry Cask Storage Pad