IR 05000269/2007005

IR-05000269-07-005, 05000270-07-005, 05000287-07-005 on 10/10/2007 - 12/31/07 for Ocenee, Units 1,2 & 3; Refueling & Outage Activities

ML080350435
Person / Time
Site:	Oconee
Issue date:	01/31/2008
From:	Moorman J H NRC/RGN-II/DRP/RPB1
To:	Baxter D Duke Energy Carolinas, Duke Power Co
References
EA-08-037 IR-07-005
Download: ML080350435 (34)

Text

January 31, 2008

EA-08-037Duke Power Company LLCd/b/a Duke Energy Carolinas, LLCATTN:Mr. David BaxterVice PresidentOconee Nuclear Station7800 Rochester HighwaySeneca, SC 29672

SUBJECT: OCONEE NUCLEAR STATION - INTEGRATED INSPECTION REPORT05000269/2007005, 05000270/2007005, 05000287/2007005

Dear Mr. Baxter:

On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at your Oconee Nuclear Station. The enclosed report documents the inspectionfindings which were discussed on January 09, 2008, with Mr. M. Glover and other members ofyour staff.The inspection examined activities conducted under your licenses as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of yourlicenses. The inspectors reviewed selected procedures and records, observed activities, andinterviewed personnel.This report documents two findings (one self-revealing and one NRC-identified) of very lowsafety significance (Green) which were determined to be violations of NRC requirements. Inaddition, two licensee-identified violations are also listed in this report. However, because oftheir very low safety significance and because they have been entered into your correctiveaction program, the NRC is treating these violations as non-cited violations (NCVs) inaccordance with Section VI.A.1 of the NRC's Enforcement Policy. If you contest any NCV inthis report, you should provide a response within 30 days of the date of this inspection report,with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN:Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcemen t, United States Nu clear R egulatoryCommission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Oconeefacility.

DPC2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letterand its enclosure will be available electronically for public inspection in the NRC PublicDocument Room or from the Publicly Available Records (PARS) component of NRC's documentsystem (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/

James H. Moorman, III ChiefReactor Projects Branch 1Division of Reactor ProjectsDocket Nos.:50-269, 50-270, 50-287License Nos.:DPR-38, DPR-47, DPR-55

Enclosure:

NRC Integrated Inspection Report 05000269/2007005, 05000270/2007005,05000287/2007005

w/Attachment:

Supplemental Informationcc w\encl.: (See page 3)

_________________________OFFICERII:DRPRII:DRPRII:DRPRII:DRPRII:DRSRII:DRSSIGNATUREDWR /RA/GAH /RA/ETR /RA/JHM /RA/AVM /RA/AVM /RA for/NAMEDRichGHuttoERiggsJMoormanAVargasMendezMCourseyDATE01/25/200801/25/200801/25/200801/24/200801/25/200801/25/2008 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO DPC3Compliance Manager (ONS)Duke Power Company LLCd/b/a Duke Energy Carolinas, LLCElectronic Mail DistributionLisa F. VaughnAssociate General Counsel and Managing AttorneyDuke Energy Corporation526 South Church Street-EC 07HCharlotte, NC 28202Kathryn B. NolanSenior CounselDuke Energy Corporation526 South Church Street -EC07HCharlotte, NC 28202David A. RepkaWinston & Strawn LLPElectronic Mail DistributionBeverly Hall, Chief RadiationProtection SectionN. C. Department of Environmental Health & Natural ResourcesElectronic Mail DistributionHenry J. Porter, Assistant DirectorDiv. of Radioactive Waste Mgmt.S. C. Department of Health and Environmental ControlElectronic Mail DistributionR. Mike GandyDivision of Radioactive Waste Mgmt.S. C. Department of Health and Environmental ControlElectronic Mail DistributionCounty Supervisor of Oconee County415 S. Pine StreetWalhalla, SC 29691-2145Lyle Graber, LISNUS CorporationElectronic Mail Distribution R. L. Gill, Jr., ManagerNuclear Regulatory Issues and Industry AffairsDuke Power Company LLC.d/b/a Duke Energy Carolinas, LLC526 S. Church StreetCharlotte, NC 28201-0006Charles BrinkmanDirector, Washington OperationsWestinghouse Electric Company12300 Twinbrook Parkway, Suite 330Rockville, MD 20852 DPC4Letter to David Baxter from James H. Moorman, III dated January 31, 2008

SUBJECT: OCONEE NUCLEAR STATION - INTEGRATED INSPECTION REPORT 05000269/2007005, 05000270/2007005, 05000287/2007005Distribution w/encl

L. Olshan, NRRC. Evans, RIIL. Slack, RIIOE MailRIDSNRRDIRSPUBLIC EnclosureU. S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos:50-269, 50-270, 50-287 License Nos:DPR-38, DPR-47, DPR-55Report No:05000269/2007005, 05000270/2007005, 05000287/2007005Licensee:Duke Power Company LLCFacility:Oconee Nu clear Stati on, Units 1, 2, and 3 Location:7800 Rochester HighwaySeneca, SC 29672Dates:October 1, 2007 - December 31, 2007Inspectors:D. Rich, Senior Resident InspectorA. Hutto, Resident InspectorE. Riggs, Resident InspectorA. Vargas-Mendez, Reactor Inspector (Sections 1R08, 4OA7) M. Coursey, Reactor Inspector (Sections 1R08, 4OA7) Approved by:James H. Moorman, III, ChiefReactor Projects Branch 1Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000269/2007005, IR 05000270/2007005, IR 05000287/2007005, 10/01/2007 -12/31/2007; Oconee Nuclear Station, Units 1, 2, and 3; Refueling & Outage Activities.The report covered a three-month period of inspection by the three onsite residentinspectors and two regional reactor inspectors. Two Green non-cited violations (NCVs)were identified. The significance of most findings is indicated by their color (Green,White, Yellow, Red) using IMC 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity levelafter NRC management review. The NRC's program for overseeing the safe operationof commercial nuclear power reactors is described in NUREG-1649, "Reactor OversightProcess," Revision 4, dated December 2006.A.

Cornerstone: Initiating Events

Green.

A self-revealing non-cited violation (NCV) of Technical Specification (TS)5.4.1 was identified for failure to establish and implement an adequate procedurefor loss of the Unit 3 spent fuel pool (SFP) cooling and/or level. More specifically,Abnormal Procedure AP/3/A/1700/035, Loss of SFP Cooling and/or Level, didnot reflect the dependency that Unit 3 SFP cooling has on condenser circulatingwater (CCW) booster pump flow. If it had, the unexpected Unit 3 SFPtemperature increase on December 1, 2007, could have been mitigated in amore timely manner and the SFP temperature increase limited to a lower value.The licensee's failure to adequately establish and implement the procedure forloss of spent fuel pool cooling was a performance deficiency. The finding wasconsidered to be more than minor because it affected the initiating eventscornerstone objective to limit the likelihood of those events that upset plantstability and challenge critical safety functions. The finding was not suitable forSDP evaluation, but was reviewed by NRC management and was determined tobe of very low safety significance, because the rate of SFP heatup was low (10degrees F in four hours), the operator s demonstrated the ability to restore CCWbooster pump flow within a relatively short time period with respect to the heatuprate, and the Unit 1 and 2 recirculating cooling water (RCW) system wasavailable to be lined up to supply cooling to the Unit 3 SFP cooling heatexchangers per existing plant procedures if needed.This finding was entered into the licensee's corrective action program. It had across-cutting aspect of complete, accurate, and up-to-date procedures (H.2.c), asdescribed in the resources component of the human performance cross-cuttingarea. (Section 1R20b.(1))

Cornerstone: Barrier Integrity

Green.

The inspectors identified an NCV of TS 5.4.1 for the failure to establishand implement adequate procedures for containment closure following a 3Enclosurepotential loss of decay heat removal (LDHR) event. More specifically, existingprocedures did not adequately address control of vehicles blocking theequipment hatch opening, as was the case on October 31, 2007.The licensee's failure to implement adequate procedures to close the equipmenthatch in the event of a LDHR was considered to be a performance deficiency. The finding was determined to be more than minor as it was associated with thebarrier integrity cornerstone attribute of procedure quality, thereby impacting theassociated cornerstone objective of providing reasonable assurance thatphysical design barriers (fuel cladding, reactor coolant system, and containment)protect the public from radionuclide releases caused by accidents or events. Theinspectors reviewed this finding in accordance with IMC 0609, Appendix G,Shutdown Operations Significance Determination Process, Attachment 1,Checklist 3. This finding did not meet the criteria in the checklist for requiring aPhase 2 or 3 analysis, and was therefore determined to be of very low safetysignificance.This finding was entered into the licensee's corrective action program. It had across-cutting aspect of complete, accurate, and up-to-date procedures (H.2.c), asdescribed in the resources component of the human performance cross-cuttingarea. (Section 1R20b.(2))

B. Licensee-Identified Violations

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

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 began the report period at 100 percent rated thermal power (RTP). On October12, 2007, the unit was reduced to 20 percent RTP to add oil to the 1B1 and 1B2 reactorcoolant pumps. The unit was returned to 100 percent RTP on October 13, 2007, whereit remained until the end of the inspection period.Unit 2 began the report period at 100 percent RTP. On November 23, 2007, the unitwas reduced to approximately 88 percent RTP for turbine valve movement testing. Theunit was returned to 100 percent RTP on November 24, 2007, where it remained untilthe end of the inspection period.Unit 3 began the report period at 100 percent RTP. On October 16, 2007, the unitbegan an end-of-cycle (EOC) coast down until October 26, when it was shutdown from87 percent RTP for refueling outage EOC 23. On December 16, 2007, Unit 3 was takencritical following outage activities and achieved 100 percent RTP on December 23,2007, where it remained until the end of the inspection period.1.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection Cold Weather Preparations

a. Inspection Scope

The inspectors reviewed the licensee's preparations for adverse weather associatedwith cold ambient temperatures for the three risk significant systems listed below. Thisincluded field walkdowns to assess the material condition and operation of freezeprotection equipment (e.g., heat tracing, instrument box heaters, area space heaters,etc.), as well as other preparations made to protect plant equipment from freezeconditions. In addition, the inspectors conducted discussions with operations,engineering, and maintenance personnel responsible for implementing the licensee'scold weather protecti on program to assess the licensee's ability to identify and resolvedeficient conditions associated with cold weather protection equipment prior to coldweather events. Documents reviewed during this inspection are listed in the Attachmentto this report.* Essential Siphon Vacuum System* Unit 1, 2 and 3 Borated Water Storage Tank Level Instrumentation

• Elevated Water Storage Tank Level Instrumentation

b. Findings

No findings of significance were identified.

5Enclosure1R04Equipment Alignment.1Partial Walkdown

a. Inspection Scope

The inspectors conducted partial equipment alignment walkdowns to evaluate theoperability of selected redundant trains or backup systems while t he other train orsystem was inoperable or out-of-service (OOS). The walkdowns included, asappropriate, reviews of plant procedures and other documents to determine correctsystem lineups, and verification of critical components to identify any discrepancieswhich could affect operability of the redundant train or backup sy stem. Documentsreviewed are listed in the Attachment to this report. The following three systems wereincluded in this review:* 3A and 3B Motor Driven Emergency Feedwater pumps with the Unit 3 TurbineDriven Emergency Feedwater (TDEFW) pump OOS for maintenance* Unit 1/2/3 TDEFW pumps with the Standby Shutdown Facility (SSF) AuxiliaryService Water pump OOS for maintenance* Keowee Hydro Unit (KHU) 1 with KHU 2 OOS for 6 month preventivemaintenance (PM)

b. Findings

No findings of significance were identified..2Complete Walkdown of the Unit 3 Emergency Feedwater System (EFW)

a. Inspection Scope

The inspectors performed a system walkdown on accessible portions of the Unit 3 EFWsystem. The inspectors focused on verifying proper valve and breaker positioning,power availability, no damage to piping or cable tray structural supports, and materialcondition. A review of Problem Investigation Process reports (PIPs) and open maintenance workorders was performed to verify that material condition deficiencies did not significantlyaffect the EFW system's ability to perform its design functions and appropriate correctiveaction was being taken by the licensee.The inspectors conducted a review of the system engineer's trending data and systemhealth reports to verify that appropriate trending parameters were being monitored andthat no adverse trends were noted. Documents and drawings reviewed for this semi-annual inspection sample are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R05 Fire ProtectionFire Area Walkdowns

a. Inspection Scope

The inspectors conducted tours in eleven areas of the plant to verify that combustiblesand ignition sources were properly controlled, and that fire detection and suppressioncapabilities were intact. The inspectors selected the areas based on a review of thelicensee's safe shutdown analysis and the probabilistic ri sk assessment basedsensitivity studies for fire-related core damage sequences. Documents reviewed arelisted in the Attachment to this report. Inspections of the following areas were conductedduring this inspection period:*Unit 1 and 2 Low Pressure Injection (LPI) Pump Rooms (3)*Unit 1 and 2 High Pressure Injection (HPI) Pump Rooms (1) *Unit 1 and 2 Penetration Rooms (4)*CT-5 Transformer (1)*Unit 1, 2, and 3 Blockhouses (2)

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (Internal)

a. Inspection Scope

The inspectors reviewed the licensee's turbine building flood control measures whileperforming Unit 3 condenser maintenance during its refueling outage commencing inOctober 2007. The inspectors determined that the licensee complied with the applicableUnit 1 waterbox and condenser circulating water (CCW) inlet and outlet de-watering andwatering operating procedures (OP/1/A/1104/012 E and G). The inspectors also walkeddown the appropriate CCW valve isolations to verify that they were established perSelected Licensee Commitments 16.9.11.

b. Findings

No findings of significance were identified.

7Enclosure1R08Inservice Inspection (ISI) Activities.1Piping Systems ISI

a. Inspection Scope

From November 5-16, 2007, the inspectors reviewed the implementation of thelicensee's ISI program for monitoring degradation of the reactor coolant system (RCS)boundary and risk significant piping system boundaries. The inspectors reviewed asample from activities performed during the Unit 3 Fall 2007 refueling outage includingnon-destructive examinations (NDE) required by the 1998 Edition, 2000 Addenda, ofAmerican Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, and augmented examination commitments. The inspectors observed and reviewed non-destructive examination (NDE) activities. Specifically:Ultrasonic Examination (UT):*Low Pressure Injection flange to pipe, weld # 3-LPS-0762-1*2B Steam Generator main steam line pipe to nozzle*3A Steam Generator nozzle to pipe weld, weld # 3SGA-W3*3B Steam Generator reducer to nozzle, weld # 3MS-137-19V*3B Steam Generator reducer to nozzle, weld # 3MS-137-22VLiquid Penetrant Testing (LPT):*High Pressure Injection elbow to pipe, weld #'s 3HP-252-5 *High Pressure Injection pipe to flange, weld #'s 3HP-252-4AVisual Examination (VT):*Reactor Vessel (RV) Head Penetrations*RV Closure Head Control Rod Drive Mechanism NozzlePenetrationMagnetic Particle Testing (MT):*2B Steam Generator main steam line pipe to nozzle*Reactor Coolant System pipe to elbow, weld #3RC-283-8V*3A Steam Generator nozzle to pipe weld, weld # 3SGA-W3Qualification 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 ASMESection V, ASME Section XI, and other industry standards.The inspectors reviewed welding activities from the previous outage. The inspectorsreviewed drawings, work instructions, weld process sheets, weld travelers, pre-heatrequirements and NDE for welding of an ASME Class 1 and 2 pressure boundary weld.Specific items included:

8Enclosure*Radiograph Examination (RT): Letdown cooler chemical sealconnector, weld #: 1-44773-1-8*LPT: 3B letdown cooler, weld #: 3HP0503-31*LPT/UT: Low pressure service water piping, weld #: 3LPS-0762-1,3LPS-076-2The inspectors reviewed and observed weld overlay and NDE activities associated withthe Pressurizer weld overlay activities. Specifically welding and LPT for PressurizerSafety Relief Valves:*PZR-WP-91-1*PZR-WP-91-2*PZR-WP-91-3

b. Findings

No findings of significance were identified.

.2 Boric Acid Corrosion Control (BACC) Program

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,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 and10CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. Inparticular, the inspectors assessed whether the visual examinations focused onlocations where boric acid leaks can cause degradation of safety-significant componentsand that degraded or non-conforming conditions were properly identified in thelicensee's corrective action system.

The inspectors reviewed a sample of engineering evaluations completed for boric acidfound on reactor coolant system piping and components to verify that the minimumdesign code-required section thickness had been maintained for the affectedcomponents. The inspectors also reviewed licencee PIPs and corrosion assessmentsimplemented for evidence of boric acid leakage to confirm that they were consistent withrequirements.

b. Findings

No findings of significance were identified.

9Enclosure.3Steam Generator (SG) Tube ISI

a. Inspection Scope

The inspectors reviewed the SG examination scope, expansion criteria, eddy currenttesting (ET) acquisition procedures, ET analysis procedures, the SG OperationalAssessment, in-situ tube pressure testing procedures, and records and examinationreports to confirm that:*The SG tube ET scope was sufficient to identify tube degradation, confirming thatthe ET scope completed was consistent with the licensee's procedures and plantTS requirements. In addition, the inspectors reviewed the SG tube ET scope todetermine that it was consistent with that recommended in EPRI "PressurizedWater Reactor Steam Generator Examination Guidelines," Revision 6, andincluded tube areas which represent ET challenges, such as the tube sheetregions, expansion transitions and support plates.*The ET probes and equipment configurations used to acquire ET data from theSG tubes were qualified to detect the known/expected types of SG tubedegradation in accordance with Appendix H, "Performance Demonstration forEddy Current Examination," of EPRI "Pressurized Water Reactor SteamGenerator Examination Guidelines," Revision 6.*The licensee adequately evaluated for any contractor deviations from their ETdata acquisition or analysis procedures or EPRI "Pressurized Water ReactorSteam Generator Examination Guidelines," Revision 6.

b. Findings

No findings of significance were identified.

.4 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 CFRPart 50, Appendix B, Criterion XVI, "Corrective Action," requirements.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator RequalificationSimulator Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on October 19, 2007. Thescenario involved training on emergency operating procedure rules one through five. This basis for specific actions in each rule was discussed, and the operator's proficiencyin mitigating associated events was exercised. The inspectors observed crewperformance in terms of communications; ability to take timely and proper actions;prioritizing, interpreting, and verifying alarms; correct use and implementation ofprocedures, including the alarm response procedures; timely control board operationand manipulation, including high-risk operator actions; and oversight and directionprovided by the shift supervisor, including the ability to identify and implementappropriate Technical Specification (TS) actions and properly classify the simulatedevent.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the licensee's effectiveness in performing routine maintenanceactivities. This review included an assessment of the licensee's practices pertaining tothe identification, scoping, and handling of degraded equipment conditions, as well ascommon cause failure evaluations. For each item selected, the inspectors performed adetailed review of the problem history and surrounding circumstances, evaluated theextent of condition reviews as required, and reviewed the generic implications of theequipment and/or work practice problem. For those structures, systems, andcomponents (SSCs) scoped in the maintenance rule, the inspectors verified thatreliability and unavailability were properly monitored and that 10 CFR 50.65 (a)(1) and(a)(2) classifications were justified in light of the reviewed degraded equipmentcondition. The inspectors reviewed the following items:*PIP O-07-4674, 2A High Pressure Injection Pump Shaft/Seal Overheating Due toThrottle Bushing Contact*PIP O-07-6179, 3CCW-79 Actuator Needs to be Replaced

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessment and Emergent Work Evaluations

a. Inspection Scope

For the six selected SSCs and activities listed below, the inspectors evaluated thefollowing attributes: (1) the effectiveness of the risk assessments performed beforemaintenance activities were conducted; (2) the management of risk; (3) that, uponidentification of an unforeseen situation, necessary steps were taken to plan and controlthe resulting emergent work activities; and (4) that maintenance risk assessments andemergent work problems were adequately identified and resolved.*PIP O-07-5669, SSF Unavailable Due to Heating, Ventilation and Cooling ControlTimer Failures*PIP O-07-5705, KHU 1 Gove rnor Oil Pump Operability With Scheduled YellowBus Maintenance*PIP O-07-5829, Potential Orange Risk Condition With 3A LPI OOS andInstrument Air Valve 3IA-91 Open*Orange Operational Risk Assessment Management Risk Condition, SSF MonthlyPMs During Unit 3 EOC 23 (Auxiliary Building/Turbi ne Building Flood)*Critical Action Plan for SSF Monthly Diesel Surveillance During Unit 3 EOC 23*230 KV Switchyard Work (PCB-8 PMs) with the Keowee Overhead Path OOS

b. Findings

Inspectors noted one licensee identified violation associated with PIP O-07-5829, whichis documented in Section

==4OA7 of this report.

1R15 Operability Evaluations

==

a. Inspection Scope

The inspectors reviewed selected operability evaluations affecting risk significant systems, to assess, as appropriate: (1) the technical adequacy of the evaluations;(2) whether continued system operability was warranted; (3) whether other existingdegraded conditions were considered; (4) whether identified compensatory measureswere in place, would work as intended, and were appropriately controlled; and (5) theimpact on TS limiting conditions for operation, wher e continued operability wasconsidered unjustified. Documents reviewed are listed in the Attachment to this report. The inspectors reviewed the following seven operability evaluations:*PIP O-07-5593, KHU Governor Control System Critical Alarms*PIP O-07-5711, Unit 3 Voltage and Load Margin Assessment 12Enclosure*PIP O-07-5786, Foreign Material Found in the 3A LPI Cooler When Opened forCleaning and Eddy Current Inspection*PIP O-07-5872, 2B LPI Pump Inboard Bearing Oil Bubbler Emptied Twice DuringPost-Maintenance Testing Following Lubrication PM*PIP O-07-6053, Uninterruptible Power Supply Failure*PIP O-07-6149, Keowee Main Transformer Fan OOS*PIP O-07-6314, 3PAM MT0080 Was Found Out of Tolerance

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (PMT)

a. Inspection Scope

The inspectors reviewed PMT procedures and/or test activities, as appropriate, forselected risk significant systems to assess whether: (1) the effect of testing on the planthad been adequately addressed by control room and/or engineering personnel; (2) testing was adequate for the maintenance performed; (3) acceptance criteria wereclear and operational readiness was adequately demonstrated consistent with designand licensing basis documents; (4) test instrumentation had current calibrations, range,and accuracy consistent with the application; (5) tests were performed as written withapplicable prerequisites satisfied; (6) installed jumpers or lifted leads were properlycontrolled; (7) test equipment was removed following testing; and (8) equipment wasreturned to the status required to perform its safety function. Documents reviewed arelisted in the Attachment to this report. The inspectors observed testing and/or reviewedthe results of the following five tests:*PT/2/A/0203/006A, 2B Low Pressure Injection Pump Test - RecirculationFollowing Mechanical Seal Cleaning and Pump Lubrication*PT/3/A/0600/012, Unit 3 TDEFW Pump Test Following the Addition of Stiffenersto the Turbine Support Frame (OD301925)*PT/1/A/0230/015, High Pressure Injection Motor Cooler Flow Test Following theRelocation of the Low Pressure Service Water (LPSW) Emergency Supply CunoFilter (OD101743)*PT/1/A/0251/001, Low Pressure Service Water Pump Test Following a Repack ofthe Unit 1/2 A Pump*PT/3/A/0610/028, Main Feeder Bus Lockout Relay Test Following Relay62BXS23 Replacement

b. Findings

No findings of significance were identified.

13Enclosure1R20Refueling & Outage Activities

a. Inspection Scope

The inspectors conducted reviews and observations for selected outage activities toensure that: (1) the licensee considered risk in developing the outage plan; (2) thelicensee adhered to the outage plan to control plant configuration based on risk; (3) thatmitigation strategies were in place for losses of key safety functions; and (4) the licenseeadhered to operating license and TS requirements. Between October 27, 2007, andDecember 22, 2007, the following activities related to the Unit 3 EOC 23 refuelingoutage were reviewed for conformance to applicable procedures and selected activitiesassociated with each evaluation were witnessed:*outage risk management plan/assessment*clearance activities*reactor coolant system instrumentation*plant cooldown*mode changes from Mode 1 (power operation) to No Mode (defueled)*shutdown decay heat removal and inventory control*containment closure*refueling activities*plant heatup/mode changes*core physics testing*power escalationAdditionally, in response to operational experience concerns regarding reactor vessel(RV) head lifts (NRC Operating Experience Smart Sample FY2007-03), the inspectorsreviewed licensee programs and procedures to determine whether current practiceswere within the current licensing basis. The inspectors reviewed licensee programsrelating to Generic Letter 80-113, Control of Heavy Loads, and NUREG 0612, Control ofHeavy Loads at Nuclear Power Plants, and interviewed licensee personnel.

b. Findings

(1)Inadequate Loss of Spent Fuel Pool Cooling Abnormal ProcedureIntroduction: A Green self-revealing NCV of TS 5.4.1 was identified for failure toestablish and implement an adequate procedure for loss of the Unit 3 spent fuel pool(SFP) cooling and/or level.Description: On December 1, 2007, Unit 3 was in no mode with the core off-loaded tothe Unit 3 SFP when a degraded flow condition occurred in the CCW booster pump flowto the recirculating cooling water (RCW) heat exchangers. This in turn had an effect onSFP cooling, since RCW removes heat from the SFP cooling heat exchangers. Thedegraded flow was a result of air entrainment by the Unit 3 CCW booster pumps whenthe Unit 3 CCW header was refilled at approximately 1300 hours0.015 days <br />0.361 hours <br />0.00215 weeks <br />4.9465e-4 months <br />. There were no CCWbooster pump flow alarms available to the operators in the control room; therefore, this 14Enclosurecondition was not initially recognized. At approximately 3:00 pm, the Unit 3 operator atthe controls noted that the SFP temperature had increased from 96 degrees F to 99degrees F. SFP temperature continued to increase to 103 degrees F by 4:00 pm. During the time of the SFP temperature increase, the operators reviewedAP/3/A/1700/035, Loss of SFP Cooling and/or Level, but never entered the procedure,even though one of the entry conditions was an unexpected increase in SFPtemperature. Additionally, the AP does not provide instructions to check CCW boosterpump flow, even though this flow is the ultimate heat sink for spent fuel decay heat.At 4:00 pm, control room operators checked CCW booster pump flows and determinedthat the flow was degraded (approximately 300 gpm verses an expected 2500 gpm). The operators correlated the restoration alignment to the SFP temperature increase andoperators were dispatched to stop and vent the CCW booster pumps one at a time, aswell as the pump suction strainer. This action re-established adequate CCW boosterpump flow to the RCW coolers and the SFP temperature eventually decreased to itsoriginal value. The maximum SFP temperature resulting from this event wasapproximately 106 degrees F, for a 10 degree F increase over a four hour period. Hadthe operators complied with the entry conditions of AP/3/A/1700/035 and entered the APwhen the unexpected SFP temperature was recognized, and had the procedurecontained instructions to check CCW booster pump flow to RCW, the condition couldhave been mitigated in a more timely manner and the SFP temperature increase limitedto a lower value. Without adequate procedural guidance, the operators relied on plantknowledge to diagnose the reduced CCW booster pump flow.Analysis: The inspectors determined that the licensee's failure to adequately establishand implement the procedure for loss of spent fuel cooling was a performancedeficiency. The finding was considered to be more than minor because it affected theinitiating events cornerstone objective to limit the likelihood of those events that upsetplant stability and challenge critical safety functions. The finding was not suitable forSDP evaluation, but was reviewed by NRC management and was determined to be afinding of very low safety significance (Green), because the rate of SFP heatup was low(10 degrees F in four hours), the oper ators demonstrated the ability to restore CCWbooster pump flow within a relatively short time period with respect to the heatup rate,and the Unit 1 and 2 RCW system was available to be lined up to supply cooling to theUnit 3 SFP cooling heat exchangers per existing plant procedures if needed. Thisfinding had a cross-cutting aspect of complete, accurate, and up-to-date procedures(H.2.c), as described in the resources component of the human performance cross-cutting area.

Enforcement:

TS 5.4.1 requires that procedures shall be established, implemented andmaintained covering the applicable procedures recommended in Regulatory Guide 1.33. Regulatory Guide 1.33, Appendix A, Section 5, requires procedures for abnormal, offnormal, or alarm conditions. Contrary to the above, the licensee failed to adequatelyestablish and implement the abnormal operating procedure for loss of spent fuel cooling. Because the finding was determined to be of very low safety significance and has beenentered into the licensee's corrective action program as PIP O-07-7069, this violation is 15Enclosurebeing treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy:NCV 05000287/2007005-01, Inadequate Loss of Unit 3 SFP Cooling Procedure.

(2) Inadequate Containment Closure ProceduresIntroduction: The inspectors identified a Green NCV of TS 5.4.1 for the failure toestablish and implement adequate procedures for containment closure following apotential loss of decay heat removal (LDHR) event.Description: On October 27, 2007, Unit 3 was shutdown for a planned refueling outage. On October 31, 2007, with the unit in Mode 5, the equipment hatch open, the reactorcoolant system vented, and a core-boil time of 23.3 minutes, the inspectors identified atractor-trailer rig parked in the equipment hatch opening. The rig was unattended andwas blocking the equipment hatch and missile shield doors. Security personnel at thehatch and maintenance personnel stationed to close the hatch in an emergency werenot aware of the location of the tractor operators or the keys. The licensee subsequentlyfound that the vehicle operators were at another location on the plant site.Site Directive 1.3.5, Shutdown Protection Plan, required that with a core-boil time of lessthan 30 minutes, designated maintenance personnel must be pre-positioned outside ofthe equipment hatch for immediate initiation of hatch closure activities perAM/0/A/1400/002B (Equipment Hatch - Reactor Building - Emergency Closing) in theevent of a loss of decay heat removal. The inspectors noted these personnel werestationed as required, but that procedures did not address control of vehicles blockingthe hatch opening. The Shutdown Protection Plan provided a time requirement toachieve containm ent closure based on time to core boil and habitability time. Therequired closure time on October 31 was 53.3 minutes. When interviewed, maintenancepersonnel stated if necessary, they would remove the vehicle with the crane provided tohandle the equipment hatch. This plan was somewhat re-enforced by prerequisite 6.8 ofprocedure AM/0/A/1400/002B, which stated, "Use mobile crane to clear hatch area." Inan emergency, this may have been a success path. However, no specific procedures,rigging, or training had been provided for this purpose. With a large, unattended vehicleblocking the equipment hatch, there was less than adequate assurance thatmaintenance personnel could remove the vehicle and shut the equipment hatch withinthe required time.The licensee estimated that the average containment temperature would reach 110degrees F approximately 68.3 minutes after a loss of decay heat removal, assuming lossof all containment cooling. The inspectors acknowledged that 68 minutes was areasonable estimate of the time required to remove the vehicle and shut the equipmenthatch. The inspectors also noted additional margin was available, as temperatures atthe hatch would be lower than average building temperature, the required tasks could becompleted at temperatures above 110 degrees F, and core uncovery and damage wouldnot occur until several hours into the event.

16EnclosureAs immediate corrective action, the licensee improved pre-shift briefings of personneldesignated to control containment openings, including temporary measures to controlobstructions at containment openings.Analysis: The licensee's failure to implement adequate procedures to close theequipment hatch in the event of a LDHR was considered to be a performance deficiency. The finding was determined to be more than minor as it is associated with the barrierintegrity cornerstone attribute of procedure quality; thereby, impacting the associatedcornerstone objective of providing reasonable assurance that physical design barriers(fuel cladding, reactor coolant system, and containment) protect the public fromradionuclide releases caused by accidents or events. The inspectors reviewed thisfinding in accordance with IMC 0609, Appendix G, Shutdown Operations SignificanceDetermination Process, Attachment 1, Checklist 3. This finding did not meet the criteriain the checklist for requiring a phase 2 or 3 analysis, and was therefore determined to beof very low safety significance (Green). This finding had a cross-cutting aspect ofcomplete, accurate, and up-to-date procedures (H.2.c), as described in the resourcescomponent of the human performance cross-cutting area.Enforcement: TS 5.4.1 requires that written procedures shall be established,implemented, and maintained covering activities related to procedures recommended inRegulatory Guide 1.33, Rev. 2, Appendix A, 1978. Regulatory Guide 1.33 requiresprocedures for maintaining containment integrity. Contrary to the above, the licenseefailed to implement adequate procedures to establish and maintain containment closureduring a potential loss of decay heat removal event. The established procedures failedto provide control of obstructions in the equipment hatch, such that obstructions could berapidly removed during an event. Because this violation is of low safety significance andhas been entered into the licensee's corrective action program as PIP O-07-6083, it isbeing treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy:NCV 05000287/2007005-02, Failure to Establish Adequate Procedures for ContainmentClosure Following a Loss of Decay Heat Removal Event.

(3)Review of Heavy Lift PracticesThe inspectors identified the following issues:

• The licensee could not demonstrate that the Updated Final Safety AnalysisReport (UFSAR) had been adequately updated to reflect information andanalyses provided to the NRC in response to generic communications regardingheavy loads.

• The licensee could not demonstrate that their RV head lifts, which lift the head toapproximately 7 feet above the reactor vessel flange, were bounded by anydesign calculations which evaluated the drop of the head through air onto theRV, upper internals, and irradiated fuel.

17Enclosure* The licensee could not demonstrate that their procedures for the RV headremoval and installation ever limited their head lifts to the bounds contained in anJune 22, 1982, letter sent to the NRC concerning a load drop analysis for RVhead lifts. Failure to update the Final Safety Analysis Report pursuant to 10 CFR 50.71(e) to reflectaspects of handling the RV head was considered a potential violation. The NRC has found industry uncertainty regarding the licensing bases for handling ofRV heads, and as a result issued EGM 07-006, "Enforcement Discretion for Heavy LoadHandling Activities," on September 28, 2007. By letter dated September 14, 2007,(ML072670127), the Nuclear Energy Institute (NEI) has informed the NRC of industryapproval of a formal initiative that specifies actions each plant will take to ensure thatheavy load lifts continue to be conducted safely and that plant licensing basesaccurately reflect plant practices. The NRC staff believes implementation of the initiativewill resolve uncertainty in the licensing bases for heavy load handling, and enforcementdiscretion related to the uncertain aspects of the licensing basis is appropriate during theimplementation of the initiative.The inspectors determined that the licensee met the following criteria to warrantenforcement discretion:1.For RV head lifts occurring during and after April, 2007, the licenseeimplemented load handling procedures consistent with the existing load dropanalysis.2.Inspections of the following areas revealed no findings of significance:(a)Licensee implementation of safe load paths, load handling procedures,and standards for training of crane operators, use of special liftingdevices, use of slings, and design, inspection, testing, and maintenanceof the reactor building crane.(b)For spent fuel cask lifts over the spent fuel pool, a load drop analysis wasprovided that bounds the planned lifts with respect to load weight, loadheight, and medium present under the load. Procedures for handling theload reflected the applicable safety basis.(c)The movement of heavy loads was included as a configurationmanagement activity in administrative controls established to implement10 CFR50.65(a)(4). Therefore, consistent with the intent of EGM 07-006, the NRC is exercising enforcement discretion (EA-08-037) for the above violation in accordance with Section VII.B.6 of theNRC Enforcement Policy without any enforcement action.

18Enclosure1R22Surveillance Testing

a. Inspection Scope

The inspectors witnessed surveillance tests and/or reviewed test data of the five risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met TS, theUFSAR, and licensee procedure requirements. In addition, the inspectors determined ifthe testing effectively demonstrated that the SSCs were ready and capable ofperforming their intended safety functions. Documents reviewed are listed in theAttachment to this report.*PT/1/A/0600/012, Unit 1 Turbine Driven Emergency Feedwater Pump Test (IST)*PT/0/A/0251/010, Auxiliary Service Water Pump Test (IST)*PT/0/A/0711/001, Zero Power Physics Test (Unit 3)*PT/3/A/0251/024, Unit 3 HPI Full Flow Test (IST)*PT/3/A/0151/019, Penetration 19 Leak Rate Test (CIV)

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed documents and observed portions of the installation of twoselected temporary modifications. Among the documents reviewed were system designbases, the UFSAR, TS, system operability/availability evaluat ions, and the 10 CFR50.59 screening. As appropriate, the inspectors determined if: the installation wasconsistent with the modification documents; it was in accordance with the configurationcontrol process; adequate procedures and changes were made; and post installationtesting was adequate. The following items were reviewed under this inspectionprocedure:*OD 500822, Installation and Removal of CCW Discharge RTDs*OD 101602, Install Jumpers in Unit 1 Main Transformer Control Cabinet toBypass Switch 43C (Cooler Selector Switch)

b. Findings

No findings of significance were identified.

19Enclosure4.OTHER ACTIVITIES4OA1Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors verified the Mitigating Systems Performance Indicators (MSPI) listed inthe table below (for all three units), to determine its accuracy and completeness againstrequirements in NEI 99-02, Regulatory Assessment Performance Indicator Guideline.Cornerstone: Mitigating SystemsPerformance IndicatorVerification PeriodRecords ReviewedMSPI- high pressure injection- emergency feedwater- emergency AC power- residual heat removal - support cooling water 4 th quarter, 2006; 1 st , 2 nd , and 3 rd quarter, 2007* Operating Logs, TrainUnavailability Data* Maintenance Records* Maintenance Rule Data* Corrective Action Program

• Consolidated Data EntryDerivation Reports* System Health Reports

b. Findings

No findings of significance were identified.4OA2Identification and Resolution of Problems.1Daily Screening of Corrective Action ReportsAs required by Inspection Procedure (IP) 71152, "Identification and Resolution ofProblems," and in order to help identify repetitive equipment failures or specific humanperformance issues for follow-up, the inspectors performed daily screening of itemsentered into the licensee's corrective action program. This screening was accomplishedby reviewing copies of PIPs, attending daily screening meetings, and accessing thelicensee's computerized database..2Semi-Annual Trend Review

a. Inspection Scope

As required by IP 71152, "Identification and Resolution of Problems," the inspectorsperformed a review of the licensee's Corrective Action Program (CAP) and associateddocuments to identify trends that could indicate the existence of a more significant safetyissue. The inspectors review was focused on repetitive equipment issues, but alsoconsidered the results of daily inspector CAP item screenings discussed in Section 20Enclosure4OA2.1 above, licensee trending efforts, and licensee human performance results. Theinspectors' review nominally considered the six month period of July 2007 throughDecember 2007, although some examples expanded beyond those dates when thescope of the trend warranted. The review also included issues documented outside the normal CAP in major equipment problem lists, plant health team vulnerability lists, focusarea reports, system health reports, self-assessment reports, maintenance rule reports,and Safety Review Group Monthly Reports. The inspectors compared and contrastedtheir results with the results contained in the licensee's latest quarterly trend reports.Corrective actions associated with a sample of the issues identified in the licensee'strend report were reviewed for adequacy.

b.Assessment and ObservationsNo findings of significance were identified. In general, the licensee has identified trendsand has appropriately addressed the trends with their CAP.

.3 Focused Review

a. Inspection Scope

The inspectors performed an in-depth review of one issue entered into the licensee'sCAP, and also performed an in-depth review of existing plant operator workarounds. The samples were within the Mitigating Systems Cornerstone and involved risksignificant systems. The inspectors reviewed the actions taken to determine if thelicensee had adequately addressed the following attributes:*Complete, accurate and timely identification of the problem*Evaluation and disposition of operability and reportability issues*Consideration of previous failures, extent of condition, generic or common causeimplications*Prioritization and resolution of the issue commensurate with safety significance*Identification of the root cause and contributing causes of the problem*Identification and implementation of corrective actions commensurate with thesafety significance of the issue.The following issues and corrective actions were reviewed:

• Operator Workarounds*PIP 07-3982, SSF Auxiliary Service Water (ASW) Su ction Pipe Ai r EjectorPerformance Has Degraded

b. Findings

No findings of significance were identified.

21Enclosure4OA3Event Followup(Closed) Licensee Event Report (LER) 05000269/2007002-00, Cask Shipments IncludeStartup Neutron Sources Not Listed in Certificate of Compliance (COC). This issueconcerned a shipment of spent fuel from Oconee to McGuire in 1987 which included twostartup neutron sources. Shipping fuel assemblies with a startup source violatedshipping cask COC Number 9015, Revision 13. The issue was identified by the licenseeand adequately addressed in the corrective action program under PIPs M-07-5072,O-06-4569, and G-95-0896. This failure to comply with the COC constitutes a violationof minor significance that is not subject to enforcement action in accordance withSection IV of the NRC's Enforcement Policy. This LER is closed.4OA6Management Meetings (Including Exit Meeting).1Exit Meeting SummaryThe inspectors presented the inspection results to Mr. M. Glover, Oconee StationManager, and other members of licensee management at the conclusion of theinspection on January 9, 2008. The licensee acknowledged the findings presented. Theinspectors asked the licensee whether any of the material examined during theinspection should be considered proprietary. No proprietary information was identified..2Regulatory Performance MeetingA public Regulatory Performance Meeting was held on December 5, 2007, at theOconee World of Energy Visitor Center. The purpose of this meeting was to discuss theperformance deficiencies, lessons learned, and the proposed corrective actionsassociated with the two White findings and the White performance indicator in theMitigating Systems Cornerstone that resulted in the performance of all three OconeeUnits being in the Degraded Cornerstone Column of the NRC's Action Matrix from thefourth quarter 2006 to the third quarter 2007. The required supplemental inspection ofthese three White issues was completed on August 31, 2007, and the results werereported in NRC Supplemental Inspection Report 05000269,270,287/2007009, datedOctober 12, 2007. Meeting attendees are listed in the Attachment below.4OA7Licensee Identified ViolationsThe following violations of very low safety significance (Green) were identified by thelicensee and are violations of NRC requirements which meet the criteria of Section VI ofthe NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCVs.*10 CFR Part 50.65 (a)(4), requires, in part, that prior to performing maintenanceactivities, the licensee assess the potential risk increase resulting from theproposed maintenance activities. Contrary to the above, on October 21, 2007,the licensee failed to adequately assess the risk associated with activities topressurize the Unit 3 Reactor Building (RB) while the 3A LPI cooler was OOS formaintenance. On October 22, 2007, the licensee identified and corrected the 22Enclosureinadequate risk assessment, which changed the unit's risk profile from Yellow toOrange. The licensee halted activities to pressurize the U3 RB, which returnedthe unit's risk profile to Yellow. In accordance with Inspection Manual Chapter(IMC) 0612 Appendix B, "Issue Screening" and Appendix E, "Examples of MinorIssues", Section 7. Maintenance Rule Issues, Example e., the issue wasdetermined to be more than minor. This finding is of very low safety significance because the incremental core damage probability was determined to be zero, and the incremental large early release probability was determined to be lessthan 1.2 E-9. This finding was documented in the licensee's corrective actionprogram as PIP O-07-5829.*10 CFR 50.55a(g)(4) requires, in part, that components classified as ASME Code Class III must meet the requirements set forth in Section XI of the ASME Code. The 1998 Edition of Section XI, Article IWA-5244, "Buried Components", requiresthat in non-redundant systems where the buried components are isolable bymeans of valves, the visual examination for leakage (VT-2) shall consist of aleakage test that determines the rate of pressure loss. Alternatively, the test maydetermine the change in flow between the ends of the buried components. Contrary to the above, the licensee had not met these requirements during theirthird ISI interval which ended in 2005. The licensee recently identified this issuein their corrective action program as PIP O-07-06007. The licensee generatedcorrective actions to identify all code class buried piping and update the ISIprogram in order to support testing of the affected piping. This finding is of verylow safety significance because it was not a design or qualification deficiencyresulting in a loss of operability, did not r epresent an actual loss of a safetyfunction, did not result in exceeding a TS allowed outage time, and did not affectexternal event mitigation.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

E. Anderson, Superintendent of Operations*

S. Batson, Engineering Manager *

D. Baxter, Site Vice President

R. Brown, Emergency Preparedness Manager*

E. Burchfield, Reactor and Electrical Systems Manager*

S. Capps, Mechanical and Civil Engineering Manager

N. Constance, Operations Training Manager

C. Curry, Mechanical/Civil Engineering Manager

P. Culbertson, Maintenance Manager

G. Davenport, Compliance Manager

R. Freudenberger, Safety Assurance Manager

M. Glover, Station Manager*

C. Gray, Regulatory Compliance

D. Hubbard, Training Manager

T. King, Security Manager*

B. Meixell, Regulatory Compliance*

J. Smith, Regulatory Affairs

J. Steeley, Training Supervisor*

S. Severance, Regulatory Compliance

J. Twiggs, Radiation Protection Manager*

J. Weast, Regulatory Compliance

NRC*

J. Moorman, III, Chief, Reactor Projects Branch 1, RII*

L. Olshan, Project Manager, NRR*

C. Casto, Acting Deputy Regional Administrator, RII*

D. Rich, Senior Resident Inspector*

K. Clark, Senior Public Affairs OfficerOther*

G. Brouette, HSBCT, Site ANII*

T. Clements, Nuclear Watch South*

P. Wilkie, SCDHEC*

R. Chandler, Anderson Independent*

A. Simon, Greenville News*

D. Mangrum, WGOG/WSNW*Note: asterisk (*) reflects attendance at Regulatory Performance Meeting on December 5, 2007

Attachment

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed

05000287/2007005-01NCVInadequate Loss of Unit 3 SFP CoolingProcedure (Section 1R20b.(1))05000287/2007005-02NCVFailure to Establish Adequate Proceduresfor Containment Closure Following a Lossof Decay Heat Removal Event (Section1R20b.(2))

Closed

05000269/LER-2007-002-00 LERCask Shipments Include Startup NeutronSources Not Listed in Certificate ofCompliance (Section 4OA3)Items

Discussed

None

Section 1R01: Adverse Weather Protection

OP/1,2,3/A/1102/020 A, Primary RoundsOP/1,2,3/A/1102/020 C, Turbine Building Third and Fifth Floor RoundsOP/2/A/1102/020 D, SSF and Outside RoundsCSM, 4.14, Chemistry Area Rounds and Equipment StatusRP/0/B/1000/035, Severe Weather PreparationsIP/0/B/1606/009, Preventive Maintenance and Operational Check of Freeze ProtectionNuclear System Directive (NSD-317), Freeze Protection ProgramElectrical Heat Trace Health Reports for 2006 and 2007

Section 1R04: Equipment Alignment

OSS-0254.00-00-1000, Design Basis Specification for the Emergency Feedwater and theAuxiliary Service Water SystemsOSS-0254.00-00-2005, Design Basis Specification for Keowee Emergency PowerUFSAR Section

8.3.1.1.1, Keowee Hydro StationUFSAR Section 7.4.3, Emergency Feedwater ControlsUFSAR Section 10.4.7, Emergency FeedwaterDrawing

OFD-121D-1.1, Flow Diagram of Emergency Feedwater System - Unit 1

3AttachmentDrawing

OFD-121D-2.1, Flow Diagram of Emergency Feedwater System - Unit 2Drawing

OFD-121D-3.1, Flow Diagram of Emergency Feedwater System - Unit 3Drawing

OFD-121A-3.8, Flow Diagram of Condensate System (Condensate Makeup andEmergency Feedwater Pump Suction) - Unit 3 Drawing

OFD-121A-3.7, Flow Diagram of Condensate System (Upper Surge Tanks 3A and 3B,Upper Surge Tank Dome and Condensate Storage Tank)- Unit 3OP/3/A/1106/006, Emergency Feedwater

OP/3/A/0600/018, Emergency Feedwater Train OperabilityEP/3/A/1800/001 Rule 3, Loss of Main or Emergency FeedwaterEmergency Feedwater System Health Reports for 2006 and 2007Technical Specification (TS) 3.3.14, 3.7.5, and 3.7.6Selected Licensee Commitment (SLC) 16.7.3 16.10.3, 16.10.6, and 16.10.7

Section 1R05: Fire Protection

UFSAR Section 9.5.1, Fire Protection SystemDesign Basis Specification

OSS-0254.00-00-4008, Fire ProtectionSection 1R08: Inservice Inspection Activities ProceduresNDE-600, Ultrasonic Examination of Similar Metal Welds in Ferritic and Austenitic Piping,Revision 17QAP 9.21, Liquid Penetrant Inspection Procedure Solvent Removable Visible Dye, Rev. 1NDE-35, Liquid Penetrant Examination, Revision 21NDE-25, Magnetic Particle Examination, Rev. 23NDE-640, Ultrasonic Examination Using Longitudinal Wave and Shear Wave, Straight BeamTechniques, Rev. 4PDI-UT-2, "PDI generic Procedure for the Ultrasonic Examination of Austenitic Pipe Welds, "Rev. C OP/0/A/1102/028, "Reactor Building Tour," Revision 24MP/0/A/1800/132, "Evaluation of Boric Acid Leakage on Mechanical, Structural, and ElectricalComponents," Revision 1GTSM0808-1, "Welding Procedure Specification," Revision 7Areva Procedure 54-ISI-400-14, "Multi-Frequency Eddy Current Examination of TubingCorrective Actions (PIPs)O-07-06007-3, Discrepancy between

OFD-124A-3.1 and

OFD-133A-3.1 for embedded pipingbetween CCW and LPSW pump suctions.O-06-03525, Unit 3 reactor building tour results. Engineering startup mode 3 walkdownO-07-05928, U3EOC23 mode 3 shutdown reactor building tour- performed by engineeringmaintenance team.O-06-02417, documentation of engineer/maintenance U3EOC22 shutdown mode 3 reactorbuilding tour.

4AttachmentOtherAreva Eddy Current Examination Plan for Oconee Unit 3 EOC23Steam Generator Health Report Areva FTP Site for Data Analysis Personnel Qualification and CertificationOconee Unit 3

EOC 23 Steam Generator Condition Monitoring and Repair LimitsData Acquisition and Analysis Personnel Qualification for Level II Data Operators, Level II A andLevel III AnalystsSummary of ONS Steam Generator Tube Wear Inspection

Section 1R15: Operability Evaluations

OSS-0254.00-00-2005, Design Basis Specification for Keowee Emergency PowerOSS-0254.00-00-1028, Design Basis Specification for the Low Pressure Injection and CoreFlood SystemsUFSAR Section : 8.3.1.1.1, Keowee Hydro StationUFSAR Section 6.3, Emergency Core Cooling systemTS 3.3.8, TS 3.5.3, and TS 3.8.1

Section 1R19: PMT

UFSAR Section 6.3.3.2, Low Pressure Injection and Core Flood SystemsUFSAR Section 10.4.7, Emergency Feedwater SystemUFSAR Section 9.2.2.2.3, Low Pressure Service Water SystemUSFAR Section 6.3.2.2.1, High Pressure Injection System

Section 1R20: Refueling Activities

MP/0/B/1710/022, Operation of Reactor Building Polar Crane, Rev 24MP/0/A/1710/017B, Crane-Whiting-Polar-Periodic & Quarterly InspectionMP/0/A/1710/012, Lifting Equipment, General Safety InspectionDuke Power Letter, June 26, 1981, Turbine Building, Control of Heavy LoadsDuke Power Letter, February 1, 1982, Turbine Building, Control of Heavy LoadsDuke Power Letter, October 1, 1981, Evaluation of Oconee Reactor Building, Control of Heavy LoadsDuke Power Letter, June 22, 1982, Evaluation of Oconee Heavy Load Handling Systems in theReactor BuildingDuke Power Letter, October 8, 1982, Control of Heavy LoadsDuke Power Letter, November 5, 1982, Control of Heavy LoadsAnalysis of the Effect of Reactor Vessel Head Drop On the Reactor Vessel,

BAW-171OP,March 1982, 77-1132379-00Problem Investigation Report 4-087-0205, Investigation Report 087-39-4.PIP O-07-02348, Compliance with NUREG 0612 Phase II requirementsPIP O-07-05598, Enforcement Guidance

Memorandum 07-006NRC NUREG 0612, Control of Heavy Loads at Nuclear Power Plants, January, 1980NRC Generic Letter 80-113, December 22, 1980NRC Generic Letter 81-07, Control of Heavy Loads, February 3, 1981

5AttachmentNRC Generic Letter 85-11, Completion of Phase II of "Control of Heavy Loads at Nuclear PowerPlants", NUREG -0612, June 28, 1985NRC

RIS 2005-25, Clarification of NRC Guidelines for Control of Heavy Loads, October31,2005NRC

RIS 2005-25, Supplement 1, Clarification of NRC Guidelines for Control of Heavy Loads,May 29, 2007EGM 07-006, Enforcement Discretion for Heavy Load Handling Activities, September 28, 2007PIP O-07-6083, Some improvements could be made to eliminate potential delaying emergencycontainment closure

PIP O-07-6153, C

ontainment closure capability drill critiquePIP O-06-3002, Unit 3 Loss of offsite power and decay heat removal

NSD 403, Shutdown Risk Management (Modes 4, 5, 6 and No-Mode) per 10CFR50.65 (a)(4),Appendix A, Basis for Equipment Hatch and ConfigurationSD 1.3.5, Shutdown Protection Plan AP/3/A/1700/026, Loss of Decay Heat RemovalAM/0/A/1400/002B (Equipment Hatch - Reactor Building - Emergency Closing)NRC Generic Letter 88-17, Loss of Decay Heat RemovalSLC 16.5.3Section 1R22: Surveillance Testing Drawing

OFD-121D-1.1, Flow Diagram of Emergency Feedwater System - Unit 1Drawing

OFD-121D-1.2, Flow Diagram of Emergency Feedwater System (AuxiliaryService Water)UFSAR Section 10.4.7, Emergency Feedwater SystemOconee 3 Cycle 24, Core Operating Limits ReportTS 3.7.5 and SLC 16.9.9

Section 4OA2: Identification and Resolution of Problems

PIP O-07-2119, Operation of 1/2/3CCW-410 to control SSF ASW flow is difficultPIP O-98-3400, Access to TDEFWP restricted by instrument trays and supportsPIP O-96-1596, Control problems with

LPSW-51 on each unitNSD 223, Trending Program, Appendix A Group Trend Reports:Maintenance, 3

rd Quarter 2007Radiological Protection, 3

rd Quarter 2007Operations, 3

rd Quarter 2007

LIST OF ACRONYMS

ADAMS-Agency wide Documents Access and Management SystemAP-Abnormal ProcedureASME-American Society of Mechanical EngineersASW-Auxiliary Service WaterBACC-Boric Acid Corrosion ControlCAP-Corrective Action Program

6AttachmentCCW-Condenser Circulating WaterCFR-Code of Federal RegulationsCOC-Certificate of ComplianceDEC-Duke Energy CorporationEFW-Emergency FeedwaterEOC-End-of-CycleEP-Emergency ProcedureET-Eddy Current Testinggpm-Gallons per MinuteHPI-High Pressure InjectionIP-Inspection ProcedureIR-Inspection ReportIST-Inservice TestKHU-Keowee Hydroelectric UnitkV-Kilo VoltLCO-Limiting Condition for OperationLDHR-Loss of Decay Heat RemovalLER-Licensee Event ReportLPI-Low Pressure InjectionLPSW-Low Pressure Service WaterLPT-Liquid Penetrant TestingMSPI-Mitigating Systems Performance IndicatorNCV-Non-Cited ViolationNDE-Non-Destructive ExaminationNEI-Nuclear Energy InstituteNRC-Nuclear Regulatory CommissionNRR-Nuclear Reactor Regulation ONS-Oconee Nuclear StationOOS-Out-of-ServiceMT-Magnetic Particle ExaminationPARS-Publicly Available RecordsPI-Performance Indicator PIP-Problem Investigation Process reportPM-Preventive MaintenancePMT-Post-Maintenance TestingPT-Performance TestRB-Reactor BuildingRCS-Reactor Coolant SystemRCW-Recirculating Cooling WaterRII-Region IIRT-Radiograph ExaminationRTP-Rated Thermal PowerRV-Reactor VesselSDP-Significance Determination ProcessSFP-Spent Fuel PoolSG-Steam GeneratorSLC-Selected Licensee Commitments

7AttachmentSSC-Structure, System and ComponentSSF-Standby Shutdown FacilityTB-Turbine BuildingTDEFW-Turbine Driven Emergency FeedwaterTS-Technical SpecificationUFSAR-Updated Final Safety Analysis ReportUT-Ultrasonic ExaminationVT-Visual Examination