IR 05000413/2007005

IR 05000413-07-005, 05000414-07-005 on 10/01/2007 - 12/31/2007 for Catawba, Units 1 and 2; Inservice Inspection Activities, Maintenance Risk Assessments, Permanent Plant Modifications, and Post-Maintenance Testing

ML080350444
Person / Time
Site:	Catawba
Issue date:	01/31/2008
From:	Moorman J NRC/RGN-II/DRP/RPB1
To:	Morris J Duke Energy Carolinas, Duke Power Co
References
EA-08-034, FOIA/PA-2010-0209 IR-07-005
Download: ML080350444 (72)

Text

January 31, 2008EA-08-034Duke Power Company LLC d/b/a Duke Energy Carolinas, LLCATTN:Mr. J. R. MorrisSite Vice PresidentCatawba Site4800 Concord RoadYork, SC 29745-9635SUBJECT:CATAWBA NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000413/2007005 AND 05000414/2007005

Dear Mr. Morris:

On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at your Catawba Nuclear Station Units 1 and 2. The enclosed inspection reportdocuments the inspection results, which were discussed on January 10, 2008, with Mr. BillPitesa 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 yourlicenses. The inspectors reviewed selected procedures and records, observed activities, andinterviewed personnel. This report documents four NRC-identified findings of very low safety significance (Green)which were determined to be violations of NRC requirements. In addition, one licensee-identified violation is also listed in this report. However, because of their very low safetysignificance and because they have been entered into your corrective action program, the NRCis treating these violations as non-cited violations (NCVs) in accordance with Section VI.A.1 ofthe NRC's Enforcement Policy. If you contest any NCV in this report, you should provide awritten response within 30 days of the date of this inspection report, with the basis for yourdenial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington,DC, 20555-0001; with copies to t he Regional Admi nistrator Region II; the Director, Office ofEnforcement, United States Nuclear Regulatory Commission, Washington, DC, 20555-0001;and the NRC Senior Resident Inspector at the Catawba Nuclear Station.

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

Sincerely,

/RA/

James H. Moorman, III, ChiefReactor Projects Branch 1Division of Reactor ProjectsDocket Nos.:50-413, 50-414License Nos.:NPF-35, NPF-52

Enclosure:

Integrated Inspection Report 05000413/2007005 and 05000414/2007005w/Attachments: (1) Supplemental Information; and (2) Status of Generic Letter(GL) 2004-02 Commitments for Catawba 2

REGION IIDocket Nos.:50-413, 50-414License Nos.:NPF-35, NPF-52Report No.:05000413/2007005 and 05000414/2007005Licensee:Duke Power Company LLCFacility:Catawba Nuclear Station, Un its 1 and 2Location:York, SC 29745Dates:October 1 through December 31, 2007Inspectors:A. Sabisch, Senior Resident InspectorG. Williams, Resi dent InspectorE. Rodriguez-Cruz, General EngineerB. Miller, Reactor Inspector (Sections 1R08, 4OA5.2)C. Peabody, Reactor Inspector (Section 4OA5.1)Approved by:James H. Moorman, III, ChiefReactor Projects Branch 1Division of Reactor Projects SUMMARY OF FINDINGSIR 05000413/2007005, 05000414/2007005; 10/01/2007 - 12/31/2007; Catawba NuclearStation, Units 1 and 2; Inservice Inspection Activities, Maintenance Risk Assessments,Permanent Plant Modifications, and Post-Maintenance Testing.The report covered a three-month period of inspection by two resident inspectors, onegeneral engineer, and two reactor inspectors. Four 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.NRC-Identified and Self-Revealing FindingsCornerstone: Mitigating Systems

• Green. The inspectors identified a Green non-cited violation (NCV) of 10 CFR50.55a(g)(4) for the failure to perform periodic leakage testing of buried pipingportions of the service water system as required by Section XI of the ASME Codefor the second 10-year Inservice Inspection interval for Units 1 and 2. Thelicensee entered this issue into their corrective action program for resolution.This finding is more than minor because it affects the Equipment Performanceattribute of the Mitigating Systems cornerstone objective of ensuring availability,reliability, and capability of systems that respond to initiating events to preventundesirable consequences. This finding is of very low safety significancebecause it did not represent an actual loss of a system's safety function. (Section 1R08.1) *Green. The inspectors identified a Green NCV of 10CR50.65(a)(4) for the failureto manage and minimize the risk associated with the replacement of portions ofthe nuclear service water (RN) system. More specifically, the licensee failed todevelop a Complex Lift Plan as required by Corporate procedures and developappropriate risk management actions as part of the Critical Activity Plan. The finding was more than minor because it was associated with the "ProtectionAgainst External Factors" attribute of the Mitigating Systems cornerstone andaffected the cornerstone objective of ensuring the availability, reliability andcapability of systems designed to prevent undesirable consequences wasmaintained. An unexpected loss of the 2A train of spent fuel pool cooling (froman inadequately controlled RN piping lift above it) could have resulted inundesirable consequences with the recently off-loaded reactor core being in thespent fuel pool. The inspectors completed a Phase 1 screening of the findingusing Appendix K of Inspection Manual Chapter 0609, "Maintenance RiskAssessment and Risk Significance Determination Process," and determined that 4Enclosurethe performance deficiency represented a finding of very low safety significanceon the basis that the actual RN piping replacement had not begun at the time thedeficiencies were identified and the lifts were deferred until the appropriateactions were developed and implemented. The finding directly involved thecross-cutting area of Human Performance under the "Safety Significant/RiskSignificant Decisions" aspect of the "Decision Making" component (H.1.a), in thatthe licensee failed to develop a lift plan and applicable risk management actionsin accordance with station and corporate requirements to ensure the riskassociated with moving RN piping over in-service spent fuel pool cooling pipingwas controlled and minimized. This finding was entered into the licensee'scorrective action program. (Section 1R13)*Green. The inspectors identified a Green NCV of 10 CFR 50, Appendix B,Criterion X, Inspections, for the licensee's failure to adequately implementinspections of the new Unit 2 emergency core cooling system (ECCS)containment sump to ensure it was installed in accordance with designspecifications so as to support operability when required by TechnicalSpecifications (TSs).The finding was more than minor because it was associated with the DesignControl attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability ofsystems that respond to initiating events to prevent undesirable consequenceswas maintained. Following final inspections of the ECCS containment sumpmodification, inspectors identified deficiencies that required resolution prior todeclaring the sump operable as required by TSs to support unit restart. Theinspectors determined that the finding was of very low safety significance usingthe Phase 1 Screening Worksheet of Inspection Manual 0609, Maintenance RiskAssessment and Risk Significance Determination Process, based on the fact thatUnit 2 had not yet entered an operational mode in which the ECCS containmentsump was required to be operable at the time the construction deficiencies wereidentified. The finding directly involved the cross-cutting area of HumanPerformance under the "Human Performance and Error Prevention" aspect of the"Work Practices" component, in that the licensee failed to implement the requiredinspections of the ECCS sump to ensure the permanent modification wasinstalled in accordance with design specifications and would remain operableunder all postulated accident conditions (H.4.a). This finding was entered intothe licensee's corrective action program. (Section 1R17)Cornerstone: Barrier Integrity

• Green. The inspectors identified a Green NCV of 10 CFR 50, Appendix B,Criterion XVI, Corrective Action, for the licensee's failure to promptly identify andcorrect a significant condition adverse to quality affe cting the ability of bothcontrol room area ventilation system (CRAVS) chille rs to operate as designedfollowing a station blackout (SBO).

5EnclosureThe finding was more than minor because it was associated with theConfiguration Control attribute of the Barrier Integrity cornerstone and affectedthe cornerstone objective of providing reasonable assurance that physical designbarriers provide protection from radio-nuclide releases caused by accidents orevents. While the CRAVS would have remained operable in terms of filtering air in the areas it services, without chilled water prov iding cooling, operators wouldhave had to bypass the filtered air paths using abnormal operating procedure(AP) guidance in order to maintain area temperatures at values needed to ensureequipment in the areas remained operable. The inspectors determined thefinding to be of very low safety significance using the Phase 1 ScreeningWorksheet of Inspection Manual 0609, Maintenance Risk Assessment and RiskSignificance Determination Process, based on the fact that the issue would onlybecome evident if one CRAVS chiller was out-of-service at the time of a SBOevent and the time availabl e to restore at least one chiller before the AP wouldhave had to be entered and the filtered air flow paths bypassed. Based on areview of station Probab ilistic Risk A ssessment data, the likelihood of a SBOevent in conjunction with one chiller being inoperable wa s determined to beextremely low. The finding directly involved the cross-cutting area of ProblemIdentification and Resolution under the "Thorough Evaluation of IdentifiedProblems" aspect of the "Corrective Action Program" component, in that thelicensee failed to take the necessary actions to identify and correct the cause(i.e., high resistance fuse installed in temperature reset circuit) of the "A" CRAVSchiller failing to restart during engineered safety features (ESF) te sting to ensureboth chillers would function as designed under all postula ted transient s (P.1.c). This finding was entered into the licensee's corrective action program. (Section 1R19)B.Licensee-Identified ViolationsOne violation of very low safety significance, which was identified by the licensee, hasbeen reviewed by the inspectors. Corrective actions taken by the licensee have beenentered into the licensee's corrective action program. This violation and the licensee'scorrective action program tracking number are listed in Section 4OA7 of this report.

EnclosureReport DetailsSummary of Plant StatusUnit 1 began the inspection period operating at 100 percent Rated Thermal Power (RTP)and remained at 100 percent RTP through the end of the inspection period.Unit 2 began the inspection period in a refueling outage that started on September 14,2007. The reactor achieved criticality on November 14, 2007, and the main generatorwas placed on-line for the first time on November 15, 2007. Physics testing and powerascension was performed through November 21, 2007, when 100 percent RTP wasachieved. The unit remained at 100 percent RTP through the end of the inspectionperiod.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather (Preparation) a.Inspection ScopeThe inspectors reviewed the licensee's preparations for adverse weather associatedwith cold ambient temperatures. This included field walkdowns to assess the materialcondition and operation of freeze protection equipment (e.g., heat tracing, instrumentbox heaters, area space heaters, etc.), as well as other preparations made to protectplant equipment from freeze conditions. Risk significant systems reviewed included thestandby shutdown facility, nuclear service water (RN) pump house, and the refuelingwater storage tanks. 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 Attachment 1of this report. b.FindingsNo findings of significance were identified.1R04Equipment Alignment.1Partial System Walkdowns a.Inspection ScopeThe inspectors walked down the four partial system alignments listed below andassessed whether critical portions of equipment alignments for selected trains remainedoperable while the redundant trains were inoperable. Plant documents were reviewed to 7Enclosurefind the correct system and power alignments, and the required positions of selectvalves and breakers. The inspectors determined if the licensee had properly identifiedand resolved equipment alignment problems that could cause initiating events or impactmitigating system availability. Documents reviewed during this inspection are listed in Attachment 1 of this report.*Protection of "A" train equipment designated in the Critical Activity Plansupporting the two planned Limiting Condition for Operation (LCO) entriesassociated with removing the safety-related portion of the "B" train of RN fromservice to relocate valves and install new piping*Protection of "B" train equipment designated in the Critical Activity Plansupporting the planned LCO entry associated with removing the safety-relatedportion of the "A" train of RN from service to relocate valves and install newpiping*Protection of equipment associated with the "A" and "B" trains of spent fuel poolcooling (KF) with the recently offloaded core in the spent fuel pool when RNpiping replacement was in-progress in close proximity to the KF piping*Protection of equipment designated in the Risk Management Actions supportingthe emergent repairs on the 2B Diesel Generator (DG) Battery Charger withtransformer 2ATD unavailable b.FindingsNo findings of significance were identified.2.Complete System Walkdown a.Inspection ScopeThe inspectors conducted one detailed walkdown/review involving the alignment andcondition of both of the Unit 1 DGs and associated support systems within the diesel generator rooms. The inspectors utilized licensee procedures, as well as licensing anddesign documents to determine whether the system (i.e., pump, valve, and electrical)alignment was correct. During the walk downs, the inspectors also assessed whether:valves and pumps exhibited leakage that would impact their function; major portions ofthe system and components were correctly labeled; hangers and supports were correctlyinstalled and functional; and essential support systems were operational. In addition,pending design and equipment issues were reviewed to determine if the identifieddeficiencies significantly impacted the system's functions. Items included in this reviewwere: the operator workaround list, the temporary modification list, System andComponent Health Reports, and outstanding maintenance work requests/work orders. A review of open Problem Investigation Process reports (PIPs) was also performed toascertain if the licensee had appropriately characterized and prioritized diesel generator-related equipment problems for resolution in the corrective action program. Documentsreviewed during this inspection are listed in Attachment to this report. b.Findings 8EnclosureNo findings of significance were identified.1R05Fire Protection a.Inspection ScopeThe inspectors walked down accessible portions of the plant to assess the licensee'scontrol of transient combustible material and ignition sources, fire detection andsuppression capabilities, fire barriers, and any related compensatory measures. Theinspectors observed the fire protection suppression and detection equipment todetermine whether any conditions or deficiencies existed which could impair theoperability of that equipment. The inspectors selected the areas based on a review ofthe licensee's safe shutdown analysis, probabilistic risk assessment based on sensitivitystudies for fire related core damage accident sequences, and summary statementsrelated to the licensee's 1992 Initial Plant Examination for External Events Submittal tothe NRC. The inspectors toured the eight areas important to reactor safety listed below. The documents reviewed during this inspection are listed in Attachment 1 of this report.*Unit 2 Annulus *Unit 1 "A" and "B" Safety Injection (NI) Pump rooms, 543 foot elevation *Unit 2 Refueling Water Storage Tank*Unit 2 "A" and "B" Containment Spray (NS) pumps, 522 foot elevation*Auxiliary Building, 560 foot elevati on, Room 300 *Unit 1 Auxiliary Feedwater (CA) Pump room and pits for the 1A, 1B and #1 CA pumps*Standby Shutdown Facility, 594 and 611 foot elevations *Unit 1 Turbine Building, 568 foot elevation b.FindingsNo findings of significance were identified.1R07Heat Sink Performance - Annual Resident Inspection a.Inspection ScopeThe inspectors reviewed the performance of Periodic Test PT/1/A/4400/0067E; KD HeatExchanger 1A Heat Capacity Test, Rev. 24, and evaluated the test data for acceptableperformance of the diesel generator jacket water cooling water (KD) system. Theinspectors reviewed the system configuration associated with the test, heat loadrequirements, the methodology used in calculating heat exchanger performance, and themethod for tracking the status of tube plugging activities via the data logger andcomputer processing equipment. b.Findings 9EnclosureNo findings of significance were identified.1R08Inservice Inspection (ISI) Activities.1Inservice Inspection activities other than Steam Generator Tube Inspections, PWRVessel Upper Head Penetration Inspections, and Boric Acid Corrosion Control a.Inspection ScopeFrom September 24 - October 5, 2007, the inspectors reviewed the implementation ofthe licensee's ISI program for monitoring degradation of the reactor coolant system(RCS) boundary and other risk significant piping system boundaries for Unit 2. Theinspectors selected a sample of American Society of Mechanical Engineers (ASME)Boiler and Pressure Vessel Code,Section XI required examinations for review.The inspectors conducted an on-site review of nondestructive examination (NDE)activities to evaluate compliance with Technical Specifications (TS) and the applicableeditions of ASME Section V and XI (1989 Edition/No Addenda for examinations creditedto the second 10-year ISI interval, and 1998 Edition/2000 Addenda for examinationscredited to the third 10-year ISI interval), and determine that indications and defects (ifpresent) were appropriately evaluated and dispositioned in accordance with therequirements of ASME Section XI acceptance standards.Specifically, the inspectors directly observed the NDE activities described below andreviewed the corresponding NDE procedures, NDE reports, equipment andconsumables certification records, and personnel qualification records:*Ultrasonic (UT) examination CN-2SM-059 weld numbers 2, 4A-A, and 01 (MainSteam piping, ASME Class 2)*Liquid Penetrant examination of CN-2NC-52 weld numbers 6, 7, and 8(Charging line injection to Reactor Coolant System, ASME Class 1)The inspectors reviewed the following NDE reports with recordable indications to ensurethey were properly dispositioned in accordance with the applicable ASME Section XIacceptance criteria:*VT-3 examination of rigid pipe support F01.020.033/2-R-ND-0323*VT-3 examination of rigid pipe restraint F01.021.091/2-R-NS-1208The inspectors reviewed a welding activity performed during this outage and one activitysince the last refueling outage. The inspectors reviewed welding procedures, procedurequalification records, welder qualification records, and NDE reports for the followingwelds:

10Enclosure*Weld Overlay of 2NC8-3V, Pressurizer Surge Nozzle to Pipe, ASME Class 1*Weld 2NI 2492-NI.00-139-25, Safety Injection Accumulator Circumferentialweld, ASME Class 2The inspectors also reviewed the results of the Nuclear Service Water (RN) pipinginspections performed during the second 10-year ISI interval to determine compliancewith the requirements of the ASME Code,Section XI, Article IWA-5244. b.FindingsIntroduction: The inspectors identified a Green Non-Cited Violation (NCV) of 10 CFR50.55a(g)(4) for failure to perform periodic leakage testing of buried piping sections ofthe RN system as required by Section XI of the ASME Code for the second 10-year ISIinterval for Units 1 and 2. Description: On October 2, 2007, the inspectors identified that the licensee had notperformed the required change in flow rate test for buried piping portions of the RNsystem during the second 10-year ISI interval in accordance with the 1989 Edition of theASME Code,Section XI, Article IWA-5244. The licensee was committed to this CodeEdition for the second interval. Both units are currently in the third ISI interval and theone-year period allowed to submit for regulatory relief following the second interval hasexpired. The failure to perform the requirements of IWA-5244 constitutes a violation ofthe ASME Code. Article IWA 5244 Part (b) required, in part, that in redundant systemswhere the buried components are non-isolable, the visual examination VT-2 shall consistof a test that determines the change in flow between the ends of the buried components. The licensee had not performed this change in flow test during the second interval. The buried RN piping is carbon steel and susceptible to corrosion by the raw water thatis pumped through it. The licensee has previously conducted crawl through inspectionsof the buried RN headers and coated the piping weld surfaces to inhibit corrosion. Thesecoatings, however, do not cover the lengths of piping between the welds. System flowtests were successfully completed on a bi-annual basis to verify sufficient flow wasmaintained to downstream components. However, and notwithstanding, the Coderequired means of confirming structural and leakage integrity of this buried piping wasthrough the periodic leakage testing required by IWA 5244 Part (b).Analysis: The inspectors determined the failure to perform the required periodic testingof RN buried piping was a performance deficiency. This finding was more than minorbecause it affects the Equipment Performance attribute of the Mitigating Systems cornerstone objective of ensuring availability, reliability, and capability of systems thatrespond to initiating events to prevent undesirable consequences. Should a significantleak, rupture, or piping collapse occur due to undetected degradation, this piping couldnot reliably deliver cooling water to downstream mitigating system components whichare relied upon to respond to an initiating event. This finding was evaluated usingPhase 1 of Inspection Manual Chapter 0609, "Significance Determination Process 11Enclosure(SDP)." This finding is of very low safety significance (Green) because it did notrepresent an actual loss of a system's safety function.Enforcement: 10 CFR 50.55a(g)(4) requires, in part, that throughout the service life of aboiling or pressurized water reactor facility, components classified as ASME Code Class1, 2, and 3 must meet the requirements set forth in Section XI of the ASME Code. The1989 Edition of Section XI, IWA-5244 "Buried Components" paragraph (b) states, in part,"In redundant systems where the buried components are non-isolable, the visualexamination VT-2 shall consist of a test that determines the change in flow between theends of the buried components." Contrary to this, the licensee failed to perform therequired testing on buried portions of the Class 3 RN system during the second 10-yearISI interval for which the 1989 Edition of the ASME Code was applicable. Therefore,because this finding is of very low safety significance and because this issue wasentered into the licensee's corrective action program (PIP C-07-05738), it is beingtreated as a Non-Cited Violation (NCV) consistent with Section VI.A.1 of theEnforcement Policy: NCV 050000413,414/2007005-01, Failure to Perform RequiredASME Code Section XI Leakage Testing..2 Boric Acid Corrosion Control (BACC) Inspection Activities a.Inspection ScopeThe inspectors reviewed the licensee's BACC activities to ensure implementation inaccordance with applicable industry guidance documents and the requirements of 10 CFR 50 Appendix B. Specifically, the inspectors performed an on-site record reviewof procedures, self assessments, and completed boric acid walkdown procedures fromthis outage and the forced outage in May 2006. The inspectors also accompaniedlicensee personnel during the Mode 3 containment walkdown.The inspectors reviewed a sample of engineering evaluations completed for boric acidfound on piping and components of borated water systems to establish that leakevaluations were being properly completed in accordance with program and procedurerequirements. The inspectors also reviewed licensee corrective action documentsinitiated for evidence of boric acid leakage to confirm that they were consistent withrequirements of Section XI of the ASME Code, 10 CFR 50 Appendix B Criterion XVI,and licensee BACC procedures. Specifically, the inspectors reviewed the following boricacid engineering evaluations (documented in corrective action documents):*PIP C-07-01970, Pipe cap on boron recycle valve 2NB-503 has gone frominactive to active leak*PIP C-07-01978, Dried boron found on body to bonnet, stud, and nut materialon valve 2KF-19*PIP C-07-02546, Boron between cap and body of fueling water storage valve2FW-53 12Enclosure b. FindingsNo findings of significance were identified. .3Steam Generator (SG) Tube Inspection Activities a.Inspection ScopeFrom October 1 - 5, 2007, the inspectors reviewed the Unit 2 SG tube eddy currenttesting (ECT) examination activities to ensure compliance with TSs, applicable industryoperating experience and technical guidance documents, and ASME Code Section XIrequirements.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 TS Sheets, the most recent SGdegradation assessment, and the last condition monitoring and operational assessment. The inspectors reviewed documentation to ensure that the ECT probes and equipmentconfigurations used were qualified to detect the expected types of SG tube degradation,and a sampling of tube data was reviewed with a qualified analyst. The inspectors alsofound that appropriate inspection scope expansion criteria were applied based oninspection results. 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. FindingsNo findings of significance were identified..4 Identification and Resolution of ProblemsThe inspectors performed a review of ISI related problems, including welding, BACC andSG ISI, that were identified by the licensee and entered into the corrective actionprogram as PIPs. The inspectors reviewed the PIPs to confirm that the licensee hadappropriately described the scope of the problem and had initiated corrective actions. The inspectors performed this review to ensure compliance with 10 CFR Part 50,Appendix B, Criterion XVI, "Corrective Action" requirements. The corrective actiondocuments reviewed by the inspectors are listed in Attachment 1 of this report.

13Enclosure1R11Licensed Operator Requalification a.Inspection ScopeThe inspectors observed Licensed Operator Requalification Training Scenario OP-CN-LOR-S-07 to assess the performance of licensed operators during a training session. The exercise included a loss of normal letdown, slow failure of a 125VDC vital inverter,anticipated transient without scram, loss of secondary heat sink due to a condensate linebreak and subsequent loss of feedwater, and the establishment of bleed and feed toremove heat from the primary system. The inspection focused on high-risk operatoractions performed during implementation of the abnormal and emergency operatingprocedures, and the incorporation of lessons-learned from previous plant and industryevents. The classification and declaration of the Emergency Plan by the Shift TechnicalAdvisor and Operations Shift Manager was also observed during the scenario. Being atraining session, immediate feedback was provided to the operators by the instructorswhen warranted. The documents reviewed during this inspection are listed inAttachment 1 of this report. b.FindingsNo findings of significance were identified.1R12Maintenance Effectiveness a.Inspection ScopeThe inspectors reviewed the licensee's effectiveness in performing the four maintenanceactivities listed below. This review included an assessment of the licensee's practicespertaining to the identification, scope, and handling of degraded equipment conditions,as well as common cause failure evaluations and the resolution of historical equipmentproblems. For those structures, systems, and components scoped in the maintenance rule, the inspectors assessed whether reliability and unavailability were properlymonitored, and that 10 CFR 50.65 (a)(1) and (a)(2) classifications were justified in lightof the reviewed degraded equipment condition. The documents reviewed during thisinspection are listed in Attachment 1 of this report.*Maintenance and repair activities on the 2B DG during the Unit 2 end-of-cycle(EOC) 15 refueling outage in cluding the pos t-maintenance operability run at thecompletion of the maintenance work *Troubleshooting and repair of the failure of the Unit 2 rod control system tomove shutdown banks C, D and E during pre-start up rod cluster controlassembly (RCCA) movement testing *Troubleshooting and repair of the N-9 shutdown bank control rod positionindication *Repair of the #8 stud hole on 2D SG cold leg primary manway during 2EOC15 14Enclosure b.FindingsNo findings of significance were identified.1R13Maintenance Risk Assessments and Emergent Work Evaluation a.Inspection ScopeThe inspectors reviewed the licensee's assessments concerning the risk impact ofremoving from service those components associated with the five work items listedbelow. This review primarily focused on activities determined to be risk-significant withinthe Maintenance Rule. The inspectors also assessed the adequacy of the licensee'sidentification and resolution of problems associated with maintenance risk assessmentsand emergent work activities. The inspectors reviewed Nuclear System Directive (NSD)415, Operational Risk Management (Modes 1-3), and NSD 403, Shutdown RiskManagement (Modes 4,5,6, and No Mode), for appropriate guidance to comply with 10CFR 50.65 (a)(4). The documents reviewed during this inspection are listed inAttachment 1 of this report.*Review of planned work associated with removing the safety-related returnheader of the "A" RN system from service to support relocation of valves andinstallation of new piping *Review of new methodology of purging air from the steam generator U-tubes tosupport reactor coolant system refill*Review of licensee's assessment of the potential for continued operation withboth units at power using the SATB transformer in place of 2ATD *Review of planned and emergent work during the period 2B DG and batterycharger were unavailable which placed Unit 2 in an Orange risk profile *Assessment of post modification testing associated with the automatic voltageregulator and risk management actions developed to support the testing b.FindingsIntroduction: The inspectors identified a Green NCV of 10CR50.65(a)(4) for the failure tomanage and minimize the risk associated with the replacement of portions of the RNsystem. More specifically, the licensee failed to develop a Complex Lift Plan as requiredby Corporate procedures and develop appropriate risk management actions as part ofthe Critical Activity Plan.Description: During the Fall 2007 Unit 2 refueling outage, several portions of RN pipinglocated in the Auxiliary Building were scheduled to be replaced due to ongoing internalcorrosion issues. The modification replaced the existing carbon steel piping with pipingconsisting of a chrome-molybdenum alloy in sections weighing up to 1,300 pounds. Dueto the limited space surrounding the piping, which was located in the overhead area ofthe 577 foot elevation in the Auxiliary Building, cont ract master riggers were brought in 15Enclosureto remove the old piping and re-install the new piping utilizing Du ke proceduralguidance. KF piping was located directly beneath the RN piping being replaced. At thepoint in the outage where the piping was scheduled to be removed, the Unit 2 core hadbeen transferred from the reactor vessel into the spent fuel pool and the KF pipingbeneath the RN piping was providing cooling to the spent fuel pool to remove decayheat. The calculated time-to-boil in the spent fuel pool with a loss of both trains of KFwas approximately 17.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.The inspectors asked the work crew at the job site was asked for a copy of the lift planassociated with the piping replacement project; however, a lift plan could not be located. Follow-up discussions with the Major Projects Group, which was responsible for theimplementation of the modification, determined that while a lift plan was required by theDuke Energy Nuclear Lifting Program, one had not been developed for the pipingreplacement to ensure the safety-related KF piping in the area was adequatelyprotected. This was due to a misinterpretation of the requirements contained in theDuke Energy Nuclear Lifting Program by those reviewing the modificationimplementation package.Based on the increased risk resulting from removing the "B" train of RN for greater than50 percent of the allowed LCO time to support the piping replacement, NSD 213, "RiskManagement Process", dictated that a Critical Activity Plan be developed to support theactivity. While a Critical Activity Plan had been developed for the work in accordancewith NSD 213, the potential consequences resulting from a pipe drop had not beenconsidered in the plan's development. As a result, no risk mitigation actions weredefined to ensure the adjacent KF piping was adequately protected during movement ofthe RN piping.Once it was determined that a lift plan had not been developed for the piping work norrisk management actions established to address the adverse consequences of a pipedrop, the licensee suspended all work until a load drop analysis was completed and theprocedurally-required actions were properly documented and implemented. At the timethe work was suspended, no actual movement of RN piping had taken place.Analysis: The inspectors determined that the licensee's failure to develop a complex liftplan and establish risk management actions as required by the corporate and stationprocedures to support the replacement of RN piping and protect adjacent safety-relatedequipment was a performance deficiency. The finding was more than minor because itwas associated with the "Protection Against External Factors" attribute of the MitigatingSystems cornerstone and affected the cornerstone objective of ensuring the availability,reliability and capability of systems designed to prevent undesirable consequences wasmaintained. An unexpected loss of the 2A train of KF and inadvertent draining of thespent fuel pool could have resulted in undesirable consequences with the recentlyoff-loaded reactor core being in the spent fuel pool.

16EnclosureThe inspectors completed a Phase 1 screening of the finding using Appendix K ofInspection Manual Chapter 0609, "Maintenance Risk Assessment and Risk SignificanceDetermination Process," and determined that the performance deficiency represented afinding of very low safety significance (Green) on the basis that the actual RN pipingreplacement had not begun at the time the deficiencies were identified, and that the liftswere deferred until the appropriate actions were developed and implemented.The finding directly involved the cross-cutting area of Human Performance under the"Safety Significant/Risk Significant Decisions" aspect of the "Decision Making"component, in that the licensee failed to develop a lift plan and applicable riskmanagement actions in accordance with station and corporate requirements to ensurethe risk associated with moving RN piping over in-service KF piping was controlled andminimized. This finding has been entered into the licensee's Corrective Action Programas PIPs C-07-5440 and C-07-5447.Enforcement: 10CFR50.65(a)(4), Requirements for monitoring the Effectiveness ofMaintenance at Nuclear Power Plants, requires in part, that prior to performingmaintenance activities, the licensee shall assess and manage the increase in risk thatmay result from the proposed maintenance activities.NSD 403, Operational Risk Management (Modes 4, 5, 6 and No-Mode) per10CFR50.65(a)(4), implements the requirements set forth in 10FR50.65(a)(4) duringshutdown conditions. NSD 403 in part states that prior to performing maintenanceactivities, risk assessments shall be performed to assess and manage the increased riskthat may result from the proposed maintenance activities. Section 403.7.3.7 defines therequirement to establish and implement appropriate prevention measures to minimizethe likelihood and consequences of a load dropping and striking equipment.NSD 213, Risk Management Process, specifies the requirements of station personnel toidentify, direct, control and manage risk-significant activities at the station, including thedevelopment of Critical Activity Plans to manage and minimize the risk resulting from theplanned activity. The NSD states that a Critical Activity Plan is required if an activity isplanned to exceed 50 percent of the allowed LCO time in TSs (which the RN pipingreplacement work required) and specifies the requirement to assess the activity, identifypotential adverse consequences, and develop contingency plans or risk managementactions to minimize the potential impact on the plant.The Duke Energy Nuclear Lifting Program Manual, Appendix E, Lift Plan Checklist,Revision 13 states in part that a lift evolution is considered to be a complex lift, requiringa documented lift plan that includes a risk assessment and contingency actions, if duringthe lift an uncontrolled movement or loss of the load could adversely affect any decayheat removal systems.Contrary to the above, on September 27, 2007, it was determined that the licensee hadfailed to identify the need to develop and document a complex lift plan as required by the 17EnclosureDuke Energy Nuclear Lifting Program Manual in preparation for the replacement ofseveral sections of RN system piping located above the operating 2A train of KF. Inaddition, the Critical Activity Plan that controlled the piping replacement project failed toassess the potential consequences of a pipe drop event on the KF piping and developrisk mitigation actions to minimize the risk associated with the activity as required by NSD 213 and NSD 403.Because this finding is of very low safety significance and has been entered into thelicensee's corrective action program as PIPs C-07-5440 and C-07-5447, this violation isbeing treated as an NCV consistent with Section VI.A of the NRC Enforcement Policy:NCV 05000414/2007005-02, Failure to Develop a Lift Plan and Risk ManagementActions for the Replacement of Piping Over a Safety-Related Systems, Structures andComponents (SSCs).1R15Operability Evaluations a.Inspection ScopeFor the ten operability ev aluations listed below, the inspectors evaluated the technicaladequacy of the evaluations to ensure that TS operability was properly justified and thesubject component or system remained available such that no unrecognized increase inrisk occurred. The inspectors reviewed the Updated Final Safety Analysis Report(UFSAR) to determine whether the system or component remained available to performits intended function. In addition, the inspectors reviewed compensatory measuresimplemented to find that they worked as stated and that they were adequately controlled. The inspectors also reviewed a sampling of PIPs to determine if the licensee wasidentifying and correcting any deficiencies associated with operability evaluations. Thedocuments reviewed during this inspection are listed in the Attachment to this report.*PIP C-07-4984; A piece of yellow duct tape was found adhered to the side of thetrough below the suction header in the 2A ECCS containment sump*PIP C-07-5347; Immedi ate Determination of Operability conc erning the inabilityto perform TS surveillance requirement SR 3.8.1.8 on Unit 1 for B train powerdue to the issues related to transformer 2ATD *PIP C-07-5441; Potential non-conservatism with the methodology used tocalculate Net Positive Suction Head margins for the ND and NS pumps*PIP C-07-6578; Immedi ate Determination of Operability of t he ice condenser icebaskets replenished during 2EOC15 *PIP C-07-6675; Evaluation is required to assess the voltage drops and loadingof SATA and SATB for accident loading when either Unit is in Mode 1 through 4and is supplying power to one of the vital buses through these transformers *PIP C-07-5046; ECCS motor coolers were found to have cooling water supplyand return lines installed incorrectly *PIP C-07-6479; The "A" Controlled Area Chilled Water (YC) chiller failed to start 18Enclosureduring "A" train engineered safety feature (ESF) testing on Unit 2 / PIP C-07-6503; Unplanned Technical Specification Action Item Log (TSAIL) entry for the"B" YC chiller failure to restart during "B" train ESF testing *PIP C-07-7048; Small leak identified on the 2B Chemical and Volume Control(NV) system pump at the discharge head-to-pump casing mechanical joint*PIP C-07-6273; Ev aluation needed to address the inability to meet theacceptance criteria of the ECCS Flow Balance surveillance due to thereplacement of NV pump 2B rotating element *PIP C-07-7544; A vulnerability exists for a pocket of gas to be trapped in theUnit 2 NS pump A and B suction headers b.FindingsNo findings of significance were identified.1R17Permanent Plant Modifications a.Inspection ScopeThe inspectors reviewed the following four permanent plant modifications to ascertainthe adequacy of the modification packages, and to evaluate the modifications foradverse affects on system availability, reliability and functional capability. Documentsreviewed during this inspection are listed in the Attachment to this report.*CD201296; Modify Unit 2 reactor coolant system loop drain lines to precludeinadvertent loss of reactor coolant system inventory*CD201528; Add stop and modify arms on the Unit 2 submarine hatch betweenlower and upper containment*CD200863; Install body vent valves on two refueling water system valves (2FW-27A and 2FW-55B) to eliminate to potential for pressure locking of the valves ifrequired during a Mode 4 loss of coolant accident (LOCA)*CD200490; Unit 2 ECCS containment recirculation sump strainer modification b.FindingsIntroduction: The inspectors identified a Green NCV of 10CFR50, Appendix B, CriterionX, Inspections, for the licensee's failure to adequately implement inspections of the newUnit 2 ECCS containment sump to ensure it was installed in accordance with designspecifications, so as to support operability when required by TS.Description: Catawba installed a modified ECCS containment sump on Unit 2 during theFall 2007 refueling outage. The sump utilized an entirely new design that incorporatedindividual strainer assemblies known as top hats attached to a series of plenums affixedto a section common to both the "A" and "B" ECCS suction headers. The elimination ofthe train separation found on the old sump design greatly increased the potential for a 19Enclosurecommon mode failure of the ECCS system if foreign material was allowed to enter thesump during a LOCA that required transitioning to hot or cold leg ECCS recirculation.This vulnerability was identified and addressed th rough detailed assembly instructionsand Quality Control checks that specifically inspected for any gaps that could allowforeign material to bypass the strainers, enter the ECCS system, and subsequentlyimpede flow through either throttle valves or orifices in the system.On November 10, 2007, the inspectors identified a gap between a strainer assembly andthe sump plenum on the newly installed ECCS containment sump during the pre-Mode 4containment cleanliness inspection. This gap was subsequently found to be greaterthan the 1/16 inch acceptance criteria. To ensure the ECCS sump was properlyassembled, the licensee re-inspected 100 percent of all strainers on the two sidesections and as much of the center section as possible without performing a totaldisassembly of the sump. No additional gaps exceeding the 1/16 inch criteria wereidentified through these supplemental inspections.While observing the licensee's plenum-top hat gap inspections, the inspectors identifiedinsufficient thread engagement on three nut-to-stud connections holding the stainlesssteel banding in place that covered the gaps where individual plenum sections werejoined together. Following an evaluation of the condition by the licensee and theengineering firm that designed the sump, the threaded stock was replaced with longerones and the nuts were affixed as depicted in the assembly drawings.These deficiencies were identified after Quality Control inspectors assigned to the ECCSsump project had signed off their final inspection document and Engineering hadcompleted their formal inspection of civil structures within the containment building. Thedeficiencies were identified by the inspectors after the licensee had completed all sumpinspections and had declared it operable (i.e., ready to support entry into Mode 4 andsubsequent power ascension).Analysis: The inspectors determined that the licensee's failure to take the necessaryactions to ensure the new ECCS containment sump was constructed in accordance withthe design specifications and commitments made to the NRC in the associated licenseamendment request was a performance deficiency. The finding was more than minorbecause it was associated with the Design Control attribute of the Mitigating Systemscornerstone and affect ed the cornerstone objective of ensuring the availability, reliabilityand capability of system s that respond to initiating events to prev ent undesirableconsequences was maintained. Following final inspections of the ECCS containmentsump modification, inspectors identified deficiencies that required resolution prior todeclaring the sump operable as required by TSs to support unit restart. The inspectorsdetermined the finding to be of very low safety significance (Green) using the Phase 1Screening Worksheet of Inspection Manual 0609, "Maintenance Risk Assessment andRisk Significance Determination Process", based on the fact that Unit 2 had not yetentered an operational mode in which the ECCS containment sump was required to beoperable. In addition, the likelihood of sufficient debris entering the sump structure 20Enclosurethrough the single gap that exceeded 1/16 inch to adversely affect either train of ECCSwas determined to be extremely low. This finding has been entered into the licensee'sCorrective Action Program as PIP C-07-6876.The finding directly involved the cross-cutting area of Human Performance under the"Human Performance and Error Prevention" aspect of the "Work Practices" component,in that the licensee failed to implement the required inspections of the ECCS sump toensure the permanent modification was installed in accordance with designspecifications and would remain operable under all postulated accident conditions(H.4.a).Enforcement: 10CFR50, Appendix B, Criterion X, Inspection, states in part that "Aprogram for inspection of activities affecting quality shall be established and executed bythe organization performing the activity to verify conformance with the documentedinstructions, procedures, and drawings. Examinations, measurements, or tests ofmaterial or products processed shall be performed for each work operation wherenecessary to assure quality."Contrary to the above, on November 10, 2007, inspectors identified deficienciesassociated with the assembly of the new Unit 2 ECCS containment recirculation sumpfollowing the completion of the final operability inspections by both the Quality Controland Engineering groups. These deficiencies required rework, additional inspections,and replacement of components in order to declare the sump operable to support unitrestart.Because this finding is of very low safety significance and has been entered into thelicensee's corrective action program as PIP's C-07-6876, this violation is being treatedas an NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000414/2007005-03, Inspections of the ECCS Containment Sump Installation Failed to IdentifyDeficiencies Prior to Declaring the Safety-Related Structure Operable.1R19Post-Maintenance Testing a.Inspection ScopeThe inspectors reviewed the five post-maintenance tests listed below to determinewhether procedures and test activities ensured system operability and functionalcapability. The inspectors reviewed the licensee's test procedures to determine if: (1)the procedures adequately tested the safety function(s) that may have been affected bythe maintenance activities; (2) the acceptance criteria in the procedures were consistentwith information in the applicable licensing basis and/or design basis documents; and (3)the procedures had been properly reviewed and approved. The inspectors alsowitnessed the tests and/or reviewed the test data to establish whether the test resultsadequately demonstrated restoration of the affected safety function(s). The documentsreviewed during this inspection are listed in the Attachment to this report*PT/2/A/4350/002B; Dies el Generator 2B Operability Test, performed following 21Enclosureplanned maintenance and repairs during the 2EOC15 refueling outage*PT/2/A/4350/002A; Dies el Generator 2A Operability Test, performed followingplanned maintenance during the 2EOC15 refueling outage *OP/2/A/6100/

001, Controlling Procedure for Unit Startup, Rev.

144, Enclosure4.1, Unit Startup - sections that performed functional checks of the pressurizerheaters following reconnection of the heater power cables removed during theperformance of the Alloy 600 weld overlay project in 2EOC15 *Restoration of 6.9kV transformer 2ATD to service following replacement andremoval of transformer SATB from service and placing it in standby*Post-maintenance testing and troubleshooting activities associated with thefailure of the "A" and "B" YC chillers to rest art during portions of ESF testingconducted during the 2EOC15 refueling outage b.FindingsIntroduction: The inspectors identified a Green NCV of 10 CFR 50, Appendix B, CriterionXVI, Corrective Action, for the licensee's failure to promptly identify and correct acondition adverse to quality affecting the ability of both control room area ventilationsystem (CRAVS) chillers to operate as designed following a station bla ckout (SBO).Description: On October 25, 2007, the "A" train of the ESF circuitry was being tested onUnit 2 during the 2EOC15 refueling outage. While performing the section of theprocedure that simulated a SBO in conjunction with a LOCA, the "A" control room areachiller, which had been in operation, failed to restart after receipt of a start signal fromthe diesel generator load sequencer following the load-shed that occurred on loss ofpower as designed. There are two CRAVS chillers t hat are shared between the twounits and provide chilled water to maintain the areas cooled by the CRAVS below 90°F. Consequently, following the failure of the "A

" chiller to restart, both units entered a30-day TS LCO action statement to rest ore the "A" chiller to operable status.Troubleshooting identified a valve that supplied cooling water to the chiller's oil coolerout of the correct throttle position, resulting in elevated oil temperatures. Personnelinvolved in the troubleshooting focused on the cooling water valve position as the causefor the oil temperature approaching the trip/reset setpoints; thereby, preventing thechiller from restarting as expected. The valve was adj usted and the "A" CRAVS chillerwas restarted using the guidance contained in the system operating procedure for anormal start. The chiller ran satisfactorily for approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> pr ior to beingsecured and placed in standby. The portion of the test that simulated a SBO with aLOCA was not re-performed based on the decision that the sole cause of the originalfailure of the "A" chiller to restart was the mispositioned oil cooler cooling water supplyvalve.On October 27, 2007, while performing the "B" train ESF te sting, the "B" CRAVS chilleralso failed to restart during the section that tested the overall plant response to a SBO inconjunction with a LOCA. Initial troubleshooting for this event did not find any cooling 22Enclosurewater valve alignment issues as had been experienced on the "A" train two days earlier. A multi-disciplinary team was assembled to determine the cause of the "B" chiller failingto restart following receipt of the load-shed signal when sequenced on by the dieselgenerator sequencer circuit. The team discovered that a fuse which had been replacedearlier in 2007 as a like-for-like replacement (same part number and amperage rating)had a significantly higher resistance than the original fuse. This additional resistance in the temperature monitoring circuit on both chillers resulted in approximately a 45F shiftin the measured temperature versus actual temperature of the oil. As a result, when a station blackout signal was received and the chiller's power was lost, the sensedtemperature was above the reset temperature and the contacts would not re-close inorder for the chiller to be restarted when called upon to do so by the diesel generatorsequencer circuit.The licensee implemented a modification that removed the fuse from the temperaturecircuit and following testing, which included a simulated SBO and LOCA signal, declaredthe "B" chiller fully operable. Once the testing confirmed that the fuse had been thecause of the chiller failing to restart following a SBO ra ther than the mispositionedcooling water valve, the "A" chiller was dec lared inoper able until the same modificationcould be installed in its circuitry. TS 3.0.3 was entered for the time when both the "A"and "B" chillers were inoperable and was exited 23 minutes later after the "B" chiller wasreturned to fully operable status.The earlier fuse replacement had occurred on the "A" ch iller on April 10, 2007, and onthe "B" chiller on January 3, 2007.

During the time period in which the replacement fusewas in the temperat ure circuit and the opposite CRAVS chiller wa s inoperable, neitherchiller would have been available if called upon following a SBO event.Analysis: The licensee's failure to conduct adequate troubleshooting and post-maintenance testing following failure of the "A" CRAVS chiller to restart during ESFtesting, resulted in an existing condition adverse to quality to remain undetected anduncorrected. This inadequate corrective action was determined to be a performancedeficiency. The finding was more than minor because it was associated with theConfiguration Control attribute of the Barrier Integrity cornerstone and affected thecornerstone objective of providing reasonable assurance that physical design barriersprovide protection from radio nuclide releases caused by accidents or events. While theCRAVS would have remained operable in terms of filtering air in the areas it services,without chilled water providi ng cooling, operators would have had to bypass the filteredair paths using abnormal operating procedure (AP) guidance in order to maintain areatemperatures at values needed to ensure equipment in the areas remained operable.The inspectors determined that the finding was of very low safety significance (Green)using the Phase 1 Screening Worksheet of Inspection Manual 0609, "Maintenance RiskAssessment and Risk Significance Determination Process", based on the fact that theissue would only become evident if one CRAVS chiller was out-of-service at the time ofa SBO event and the time ava ilable to restore at least one chiller before the AP would 23Enclosurehave had to be entered and the filtered air flow paths bypassed. Based on a review of station Probabilisti c Risk Assessment data, the likelihood of a SBO event in conjunctionwith one chiller being inoperable was determined to be extremely low. The findingdirectly involved the cross-cutting area of Problem Identification and Resolution underthe "Thorough Evaluation of Identified Problems" aspect of the "Corrective ActionProgram" component, in that the licensee failed to take the necessary actions to identifyand correct the cause of the "A" CRAVS chiller failing to restart during ESF testing toensure both chillers would func tion as designed under all postu lated transient s (P.1.c). This issue has been entered into the licensee's Corrective Action Program as PIPsC-07-6848 and C-07-6503. Enforcement: 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," requires, inpart, that "measures shall be established to assure that significant conditions adverse toquality, such as failures, malfunctions, deficiencies, deviations, defective material andequipment, and nonconformances are promptly identified and corrected."Contrary to the above, on October 25, 2007, the licensee failed to conduct adequatetroubleshooting and post-maintenance testing to ensure the cause for the "A" CRAVSchiller failing to restart during ESF testing was promptly identified and corrected. Theactual cause was not identified until a subsequent similar failure of the "B" CRAVS chilleroccurred which placed both units in TS 3.0.3 for a limited period of time. Because thisfinding is of very low safety significance and has been entered into the licensee'scorrective action program as PIPs C-07-6848 and C-07-6503, this violation is beingtreated as an NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV05000413, 414/2007005-04), Failure to Promptly Identify and Correct a SignificantCondition Adverse to Quality Affecting the Ability of Both CRAVS Chillers to Operate asDesigned Following a SBO due to Inadequate Troubleshooting and Post-MaintenanceTesting.1R20Refueling and Outage Activities.1Unit 2 2EOC15 Refueling Outage Activities a.Inspection ScopeThe inspectors evaluated licensee outage activities to determine whether the licensee:considered risk in developing outage schedules; adhered to administrative risk reductionmethodologies they developed to control plant configuration; adhered to operatinglicense, TS, and Selected Licensee Commitment requirements, as well as proceduralguidance that maintained defense-in-depth; and developed mitigation strategies forlosses of the key safety functions identified below:*Decay Heat Removal*Inventory Control*Reactivity Control 24Enclosure*Containment Control*Spent Fuel Cooling*Power AvailabilityThe inspectors reviewed the licensee's outage risk control plan to assess the adequacyof the risk assessments that had been conducted and that the licensee had implementedappropriate risk management strategies as required by 10CFR50.65(a)(4).Following core reload and cavity drain-down, the inspectors performed an inspection ofthe reactor vessel bottom head to determine if any potential leakage had occurred at thewelds associated with the bottom head penetrations and assess the overall cleanlinessof the reactor vessel bottom head. This inspection was done in conjunction with thelicensee's Engineering personnel.The inspectors observed the items or activities described below, to substantiate that thelicensee maintained defense-in-depth commensurate with the outage risk control planfor the key safety functions identified above and applicable TS when taking equipmentout-of-service.*Clearance activities; hanging and removing safety tags*Reactor Coolant System Instrumentation*Realigning electrical power*Establishing and maintaining Decay Heat Removal*Maintaining Spent Fuel Pool Cooling*Inventory control including reduced inventory conditions*Controlling reactivity*Establishing and maintaining Containment ClosureThe inspectors reviewed the licensee's responses to emergent work and unexpectedconditions, to establish that resulting configuration changes were controlled inaccordance with the outage risk control plan.The inspectors also observed fuel handling operations (core reload) and other ongoingactivities, to determine that those operations and activities were being performed inaccordance with TS and procedural guidance. Additionally, the inspectors observedrefueling activities to substantiate that the locations of the fuel assemblies were trackedthrough core reload. The inspectors viewed the final in-core fuel assembly positionverification video prior to re-installation of the reactor internals and head.Prior to mode changes and on a sampling basis, the inspectors reviewed system lineupsand/or control board indications to substantiate that TSs, license conditions, and otherrequirements, commitments, and administrative procedure prerequisites for modechanges were met. Also, the inspectors periodically reviewed the setting andmaintenance of containment integrity, to establish that the RCS and containmentboundaries were in place and had integrity when necessary.Prior to reactor startup, the inspectors walked down upper and lower containment to 25Enclosureobserve that debris had not been left which could affect performance of the containmentECCS sumps. In addition, the inspectors performed a walkdown of the upper and lowerice condenser areas to establish that debris had not been left which could affect icecondenser performance.The inspectors observed the "Just-in-Time" training conducted for the personnelinvolved in the unit startup on November 1, 2007, which simulated bringing the unit fromMode 3 to criticality and through portions of the power ascension process.The inspectors observed the reactor startup/pull to criticality on November 8, 2007, unitsynchronization to the grid, and portions of the subsequent power ascension to assureprocedure compliance and that systems performed as designed. The inspectorsreviewed reactor physics testing results to determine that core operating limitparameters were consistent with the core design.Periodically, the inspectors reviewed the items that had been entered into the licensee'scorrective action program, to establish that the licensee had identified problems relatedto outage activities at an appropriate threshold and had entered them into the correctiveaction program. Documents reviewed in support of the Unit 2 2EOC15 refueling outage are listed inAttachment 1 of this report. b.Findings and ObservationsNo findings of significance were identified..2NRC Operating Experience Smart Sample FY2007-03 a.Inspection ScopeIn response to operational experience concerns regarding reactor vessel head lifts (NRCOperating Experience Smart Sample FY2007-03), the inspectors reviewed licenseeprograms and procedures to determine whether past and current practices were withinthe licensing basis. The inspectors observed the Unit 2 reactor vessel head removaland replacement during the Fall 2007 EOC15 Catawba Unit 2 refueling outage. Theinspectors reviewed the documents listed in Attachment 1 to this report related to heavyload lifts of the reactor vessel head, and conducted discussions with licensee personnelinvolved in the development of lifting plans and conducting the actual lifts. b.Findings 26EnclosureThe 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 reactor vessel head lifts, whichprior to the Fall 2007 Unit 2 outage had lifted the head to approximately 40 feetover the irradiated fuel in the reactor vessel, were bounded by the designcalculations which evaluated the drop of the head through air onto the reactorvessel, upper internals, and irradiated fuel for distances up to 16 feet through airor 18 feet through air followed by 24 feet through water.*Until revised prior to the Fall 2007 Unit 2 refueling outage, the licensee could notdemonstrate that their procedures for the reactor vessel head removal andinstallation ever limited their head lifts to the bounds contained in an August 17,1984, letter sent to the NRC concerning a load drop analysis for reactor vesselhead lifts.Failure to update the Final Safety Analysis Report pursuant to 10 CFR 50.71(e) to reflectaspects of handling the reactor vessel head was considered a potential violation.The NRC has found industry uncertainty regarding the licensing bases for handling ofreactor vessel heads, and as a result issued Enforcement Guidance Memorandum07-006, Enforcement Discretion for Heavy Load Handling Activities, on September 28,2007. The Nuclear Energy Institute has informed NRC of industry approval of a formalinitiative that specifies actions each plant will take to ensure that heavy load liftscontinue to be conducted safely and that plant licensing bases accurately reflect plantpractices. The NRC staff believes implementation of the initiative will resolve uncertaintyin the licensing bases for heavy load handling, and enforcement discretion related to theuncertain aspects of the licensing basis is appropriate during the implementation of theinitiative. The inspectors determined that the licensee implemented the following actions prior tothe specified lifts in accordance with the industry initiative to warrant enforcementdiscretion:(1) For all heavy load lifts within the reactor building, the licensee has defined andimplemented safe load paths, load handling procedures, and standards fortraining of crane operators, use of special lifting devices, use of slings, anddesign, inspection, testing, and maintenance of the reactor building polar crane.(2) To support the Fall 2007 Unit 2 refueling outage, the process for lifting thereactor vessel head was changed to ensure the lift was conducted within thebounds of the 1984 reactor vessel head load drop analysis with respect to loadweight, load height, and medium present under the load. The licensee 27Enclosuremaintained the bottom of the reactor vessel head less than 15 feet above thereactor vessel or the refueling cavity water surface when the head was lifted toensure consequences of a load drop event were bounded by the originalanalysis. Once the cavity was fully flooded to greater than 23 feet above thereactor vessel flange, the reactor vessel head was allowed to be lifted toapproximately 16 feet above the water surface as necessary to lift the headabove immovable structures around the refueling cavity. This change has beenmade to the procedures used on both Catawba units.(3) Westinghouse has been contracted to re-analyze the reactor vessel head dropevent prior to the Spring 2008 Unit 1 refueling outage to determine if additionalmargin is available to allow greater flexibility in defining a safe load path for thereactor head once it clears the reactor head guide studs. Any changes to thecurrent process which ensures the 16 foot bounding distance is maintained willbe done with sufficient time for a multi-disciplinary review to be performed priorto the start of the refueling outage.(4) The movement of heavy loads will have administrative controls and riskassessments established as required to implement the requirements of 10CFR50.65(a)(4). Therefore, consistent with the intent of Enforcement Guidance Memorandum 07-006,enforcement discretion (EA-08-034) is being exercised for the violation described abovein accordance with Section VII.B.6 of the NRC Enforcement Policy without anyenforcement action.1R22Surveillance Testing a.Inspection ScopeThe inspectors observed and/or reviewed the 15 surveillance tests listed below todetermine that TS surveillance requirements and/or Selected Licensee Commitmentrequirements were properly complied with, and that test acceptance criteria wereproperly specified. The inspectors determined whether proper test conditions wereestablished as specified in the procedures, that no equipment pre-conditioning activitiesoccurred, and that acceptance criteria had been met. Additionally, the inspectors alsodetermined if equipment was properly returned to service and if proper testing wasspecified and conducted to ensure that the equipment could perform its intended safetyfunction. The documents reviewed during this inspection are listed in Attachment 1 ofthis report.Surveillance Tests 28Enclosure*PT/2/A/4350/002 B, Diesel Generator 2B Operability Test, Rev. 89*PT/2/A/4350/002 A; Diesel Generator 2A Operability Test, Rev. 89*PT/2/A/4550/001 D; Reactor Building Manipulator Crane Load Test, Rev. 12 *PT/0/A/4600/031; NAC-UMS Cask Surveillance, Rev. 00 *PT/2/A/4200/001A, Containment Integrated Leak Rate Test, Rev. 011 *SM/0/A/8510/008, Ice Condenser Foreign Material Exclusion Inspection, Rev.

003*PT/2/A/4200/009A; Auxiliary Safeguards Test Cabinet Periodic Test, Rev 191;Enclosures 13.27 (Containment Ventilation Isolation, Train A), 13.28(Containment Ventilation Isolation, Train B), and 13.36 (Containment IsolationPhase A, Train B) *PT/2/A/4600/001, RCCA Movement Test, Rev. 30 *IP/2/A/3200/001A; Solid State Protection System (SSPS) Train A PeriodicTesting, Rev. 005*PT/2/A/4350/002A; Di esel Generator 2A Operability Test, Rev. 089*PT/2/A/4150/001D; RCS Leakage Calculation, Rev. 64In-Service Tests*PT/1/A/4200/021 A; Component Cooling Water (KC) Valve Inservice Test, Rev.

072 *PT/1/A/4200/004B; Containment Spray Pump 1A Performance Test, Rev. 059 Containment Isolation Valve Tests

• PT/2/A/4200/001 I; As Found Containment Isolation Valve Leak Rate Test, Rev.013 -Testing of Penetration M220 for 2VI-79, 2VI-312A and 2VI-77B Ice Condenser Tests*MP/0/A/7150/006, Ice Condenser Lower Inlet Doors (LID) Inspection andTesting, Rev. 029, Sections 11.4 (Door Inspection), 11.5 (LID Initial OpeningForce As-Left Test) and 11.6 (LID 40 Degree As-Left Testing) b.FindingsNo findings of significance were identified.Cornerstone: Emergency Preparedness 29Enclosure1EP6Drill Evaluation a. Inspection ScopeThe inspectors observed and evaluated the licensee's performance during twoemergency drills conducted on February 21 and March 7, 2007. The inspectorsobserved licensee activities in the Control Room Simulator and in the Technical SupportCenter. The NRC's assessment focused on the timeliness and accuracy of theemergency classification, offsite agency notifications, and the licensee's response to theevent. The performance of the emergency response organization was evaluated againstthe applicable licensee procedures and regulatory requirements. The inspectors attended the post-exercise critique for the drills to evaluat e the licensee's selfassessment process for capturing potential deficiencies relating to classification,notification and response to the failures in the scenarios. Documents reviewed are listedin Attachment 1of this report. b. FindingsNo findings of significance were identified.4.OTHER ACTIVITIES 4OA1Performance Indicator VerificationInitiating Events, Mitigating Systems, and Barrier Integrity a.Inspection ScopeThe inspectors sampled licensee data to establish the accuracy of the data reported forthe 14 performance indicators (PI) listed below. To determine the accuracy of thereported PI elements, the reviewed data was assessed against PI definitions andguidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory AssessmentIndicator Guideline.Initiating Events*Unplanned Scrams per 7,000 Critical Hours, Unit 1 - The inspectors reviewedthe Unplanned Scrams per 7,000 Critical Hours Performance Indicator resultsfor the period of October 1, 2005, through September 30, 2007, for Unit 1. Theinspectors reviewed operating logs, PIPs, and monthly operating reportsassociated with any manual and automatic scrams that occurred in that periodand determined whether the data reported for the PI corresponded to the unit'spower profile. The documents reviewed during this inspection are listed inAttachment 1 of this report.Mitigating Systems 30Enclosure*Mitigating System Performance Indicator - The inspectors reviewed the licensee's procedures and methods for compiling and r eporting the PIs listedbelow, including the Reactor Oversight Program Mitigating System PerformanceIndicator (MSPI) Basis Document for Catawba. The inspectors reviewed theraw data for the PIs listed below for the first, second, and third quarters of 2007. The inspectors also independently screened TSAIL logs, selected control roomlogs, work orders and surveillance pr ocedures, and maintenance rule failure determinations to determine if unavailability/unreliability hours were properlyreported. The inspectors compared the licensee's raw data against thegraphical representations and specific values contained on the NRC's publicweb page for the first, second and third quarters of 2007. The inspectors alsoreviewed the past history of PIP's for systems affecting the MSPI indicatorslisted below for any that might have affected the reported values. Theinspectors reviewed NEI 99-02, Regulatory Assessment Performance IndicatorGuideline, to determine whether industry reporting guidelines were applied. Additional documents reviewed during this inspection are listed in Attachment 1of this report.*Mitigating Systems Performance Index - High Pressure Safety Injection,Units 1 and 2*Mitigating Systems Performance Index - Heat Removal, Units 1 and 2*Mitigating Systems Performance Index - Residual Heat Removal, Units 1 and 2*Mitigating Systems Performance Index - Emergency AC Power, Units 1 and 2*Mitigating Systems Performance Index - Cooling Water Systems, Units 1 and 2Safety System Functional Failures, Units 1 and 2 - The inspectors reviewed the SafetySystem Functional Failures Performance Indicator results for the period of October 1,2006 through September 30, 2007 for Units 1 and 2. The inspectors reviewed licenseeevent reports, maintenance rule reports and selected work orders to ensure that anyfailure that prevented or could have prevented the fulfillment of a safety function in thatperiod was identified and reported for the PI. The documents reviewed during thisinspection are listed in the Attachment to this report.Barrier Integrity*Reactor Coolant System Leakage, Unit 2 - The inspectors reviewed the ReactorCoolant System Leakage PI results for the period of October 1, 2005, throughSeptember 30, 2007, for Unit 2. The inspectors reviewed the Auto Log entrieswhich captured the results of the daily RDS leakage calculations compared tothe Technical Specification limiting value of 10 gallons per minute for identifiedreactor coolant system leakage. In addition, the inspectors reviewed theperformance of an RCS leak rate calculation by control room operators anddiscussed the results of the completed surveillance with the on-shift personnel.

31EnclosureThe documents reviewed during this inspection are listed in Attachment 1 of thisreport. b.FindingsNo findings of significance were identified.4OA2Identification and Resolution of Problems.1Daily ReviewAs 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 screening of items entered into thelicensee's corrective action program. This was accomplished by reviewing copies ofPIPs, attending daily Site Direction and PIP screening meetings, and accessing thelicensee's computerized database..2Annual Sample Review (1)Hydrostatic Seals a. Inspection ScopeThe inspectors reviewed PIPs, work orders and action requests associated with licenseeactions taken in response to hydrostatic seal issues that resulted in multiple internalflooding events at Catawba in 2006. The hydrostatic seals had been installed duringinitial construction and were designed to prevent water intrusion into below-grade areasof the plant containing safety-significant or risk-significant equipment. As part of the rootcause investigation, the licensee developed corrective actions to implement revised PMinspections of selected seals, assess the material and processes used to sealbelow-grade penetrations, and ensure drawings accurately reflect the as-builtconfiguration of conduit manholes, penetrations and conduit seals. Inspectors reviewedthe actions taken in response to past events at the station to assess their timeliness andeffectiveness. The inspectors interviewed Engineering and Maintenance personnelinvolved in the development and implementation of the corrective actions and conductedfield walkdowns of selected hydrostatic seals. The documents reviewed during thisinspection are listed in Attachment 1 of this report. b.FindingsNo findings of significance were identified. (2)Airlock Penetration 32Enclosure a.Inspection ScopeThe inspectors selected one PIP for detailed review. PIP C-05-03781 involved testingfailures on the Unit 1 airlock penetration, PC24, that met the performance level criteriafor maintenance rule a(1) status. The PIP was reviewed to determine whether the fullextent of the issues were identified, an appropriate evaluation was performed, andappropriate corrective actions were specified and prioritized. The inspectors evaluatedthe PIP against the requirements of the licensee's corrective action program documentand 10 CFR 50, Appendix B. The inspectors interviewed Engineering and Maintenancepersonnel involved in the development and implementation of the corrective actions toaddress the failures and remove the airlock penetration from (a)(1) status as required bythe 10CFR50.65. b. FindingsNo findings of significance were identified..3Semi-Annual Review to Identify Trends a.Inspection ScopeAs required by Inspection Procedure 71152, Identification and Resolution of Problems,the inspectors performed a review of the licensee's CAP and associated documents toidentify trends that could indicate the existence of a more significant safety issue. Theinspectors' review was focused on repetitive equipment issues, but also considered theresults of daily inspector CAP item screenings discussed in section 4OA2.1 above,licensee trending efforts, and licensee human performance results. The inspectors'review primarily considered the six-month period of July 2007 through December 2007,although some examples expanded beyond those dates when the scope of the trendwarranted. The review also included issues documented outside the normal CAP inmajor equipment problem lists, plant health team lists, Independent Nuclear OversightTeam reports, system and component health reports, self-assessment reports,maintenance rule reports, and Safety Review Group Monthly Reports. The inspectorscompared and contrasted their results with the results contained in the licensee's latestquarterly trend reports. Corrective actions associated with a sample of the issuesidentified in the licensee's trend report were reviewed for adequacy. b.Assessment and ObservationsThe inspectors followed the actions being implemented by the licensee in response tothe trend previously identified by the inspectors associated with insufficient managementoversight and control of vendors and contractors (non-station personnel). This trendstatement has been discussed in the following NRC Inspection Reports: 05000413,414/2005005, 05000413,414/2006003, 05000413,414/2006005 and 05000413,414/2007003,Semi-Annual Review to Identify Trends. Based on the inspectors' initial identification of 33Enclosurethis trend, the licensee had concluded that a major contributor to the adverse trend wasa lack of guidance in the Duke Nuclear Site Directive 105, Control of Non-AssignedIndividuals. The licensee stated in corrective action documents generated in responseto this adverse trend that this deficiency was evident in large projects undertaken atCatawba such as the raw water piping project and the refueling outages conducted in2006, as well as at Oconee during the steam generator replacement project andMcGuire during the installation of the new Unit 1 Emergency Core Cooling System sumpstrainer. Senior Duke Management revised fleet procedures to incorporate specificdecision points into the planning and approval process for major projects to ensureoversight controls are considered and developed as part of an overall projectdevelopment plan. Catawba station management recognized the need for additionalattention in this area and worked on implementing corrective actions prior to the start ofthe Fall 2007 Unit 2 refueling outage. These actions included the development of aHuman Performance Improvement Plan directed at non-site assigned personnel,assignment of additional supervisors qualified to station standards to oversee workactivities staffed primarily with non-station personnel, providing additional details inproject oversight plans, and holding daily plan-of-the-day meetings with all crewmembers conducting work at Catawba.During the Fall 2007 Unit 2 refueling outage approximately 2,000 non-station personnelwere on-site performing work to support the outage scope. Overall, the correctiveactions taken by the licensee were shown to be effective in providing a formal structurefor supervising work conducted at Catawba by non-station personnel and enabled anumber of complex activities to be performed with only minimal issues being identified. The licensee is continuing to monitor progress in this area and implement additionalcorrective actions as needed. Accordingly, this trend statement w ill no longer befollowed in subsequent integrated inspection reports.4OA3Event Followup.1(Closed) Licensee Event Report (LER) 05000413/2007003-00, Under-Voltage ConditionResulted in the Actuation of the Emergency Diesel Generators. On August 25, 2007, atransformer fault occurred at a generating facility located within the Duke electrical gridbut operated by another utility. Protective relaying at the facility fa iled to isolate the faultfrom the grid as designed. The resulting degraded voltage condition on the grid wassensed at the Catawba switchyard and reached 75% of nominal voltage. Once thesetpoint for degraded voltage on the 4.16kV vital busses was reached, all four dieselgenerators received an auto-start signal. The diesels started; however, since protectiverelaying on the Duke electrical grid functioned as designed and isolated the fault, thediesel generator output breakers were not required to close in and supply power to the4.16kV vital buses. The licensee made the required 8-hour notification to the NRC forthe diesel generators receiving a valid auto start signal due to low voltage on the 4.16kVvital busses. Once grid conditions were determined to have stabilized and the fault atthe remote location was isolated from the Duke system, the diesel generators weresecured and equipment restored to the standby alignment. Both units at Catawba 34Enclosureremained at 100 percent RTP during the event. A team consisting of members fromCatawba and the General Office has been established to conduct an additionalassessment of the Catawba switchyard and associated Duke Energy relaying to ensureadequate protection against external perturbations exists. The system engineer for thediesel generators at Catawba assessed the performance of the diesels and theassociated relaying, and determined that the equipment had functioned as designed. This LER is closed..2(Closed) LER 05000413/2007002-00 Technical Specification Violations Associated withDivider Barrier Integrity. On June 10, 2007, an unexpected entry into TS LCO 3.6.14.c(Containment Systems; Divider Barrier Integrity) was made due to the containmentsubmarine hatch on both units found in the unlatched position when checked on weeklyoperator rounds. These hatches provide emergency egress from lower containment toupper containment; however, if opened, would provide a pathway that would bypass theice condenser and result in elevated post-accident containment pressures. They arerequired to be secured in the closed position when in Modes 1 to 4. The hatches onboth units were found to have their locking mechanism out of position, which would haveallowed the hatch to open if a higher pressure existed beneath the hatch such asexperienced during a LOCA. The hatches were resecured in the closed position asrequired. The licensee implemented Fleet and Site procedures to assess the issue andimplemented applicable compensatory actions until the assessment was completed. Amodification to the hatch was developed which included: a positive stop on the hatchclosing mechanism to allow personnel to ensure the door is properly secured; paintingthe hatch to provide easy visual verification of the hatch position; and installation of alocal alarm that indicates if the hatch is not secured. This modification was installed onUnit 2 during the Fall 2007 refueling outage (see section 1R17) and is scheduled to beinstalled on Unit 1 in the Spring 2008 refueling outage. Interim corrective actions beingtaken on Unit 1 include providing additional guidance to operators conducting weeklychecks of the submar ine hatch and enhanced proc edural instructions for installing thetamper seal which was used in June 2007 when the Unit 1 hatch was resecured. Thisissue was captured in the licensee's CAP as PIPs C-07-02911 and C-07-02912. Bypassanalysis indicates that this failure to comply with TS 3.6.14.c constitutes a violation ofminor significance; therefore, it is not subject to enforcement action in accordance withSection IV of the NRC's Enforcement Policy. This LER is closed..3(Closed) LER 05000414/2007001-00; Failure to Comply with Action Statement inTechnical Specification 3.3.1 for Loss of a Channel of the Solid State Protection System.On May 10, 2007, while replacing a failed 48VDC power supply in the 2B Solid StateProtection System, the channel 4 over-temperature delta-temperature (OTDT) tripfunction became inoperable due to a failure of the axial flux imbalance circuit card. When attempting to reinstall a fuse associated with the power supply, an arc occurredwithin the cabinet. An unexpected control room annunciator was received; however,neither the maintenance technicians nor control room operators recognized that theOTDT channel was inoperable following the receipt of the alarm. As a result, the 35Enclosureinoperable channel was not placed in the tripped condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> as required byTechnical Specification 3.3.1. Additional troubleshooting was performed on the followingshift, and in the course of this activity, the failed axial flux imbalance circuit card wasidentified in the SSPS cabinet. Once the failed card was identified, the channel wasdeclared inoperable and placed in the tripped condition in accordance with TS. Thisaction was taken approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> after the actual failure occurred. The card wasreplaced and operability restored for the affected channel approximately 8.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> later. The OTDT circuitry is designed to protect the reactor from approaching conditions thatcould produce a Departure fr om Nucleate Boiling and potentially challenge fuel claddingintegrity. It operates on a two-out-of-four logic and generates a reactor trip protectionsignal when the calculated setpoint is reached. While the Channel 4 OTDT trip functionwas inoperable for approximately 21.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, the remaining three channels wereoperable and would have generated a protection system signal if actual conditions hadexisted that required an OTDT trip signal to be generated. The licensee conductedtraining specific to this event with personnel in Operations, I&C and Engineering toensure proper actions are taken when unexpected alarms/indications are receivedduring maintenance activities. Enhancements were made to the model work ordersused when conducting work within the 7300 cabinets. This event has been captured inthe licensee's corrective action program as PIPs C-07-2365 and C-07-2484. Asindicated above, this failure to comply with TS 3.3.1 constitutes a violation of minorsignificance; therefore, it is not subject to enforcement action in accordance with SectionIV of the NRC's Enforcement Policy. This LER is closed..4(Closed) LER 05000413/2007004-00; Control Area Chilled Water system inoperable inexcess of Technical Specification requirements due to Unanticipated ComponentInteractions.On October 25, 2007, while performing the section of a test procedure that simulated aSBO in conjunction with a loss of coolant accident (LOCA), the "A" control room areachiller - which had been in operation - failed to restart. Due to the two station control room area chillers being shared between the two units, bot h units entered a 30-day TSLCO action statement with the "A" chiller inoperable. Troubleshooting initially identifieda mispositioned cooling water throttle valve; however, following the repositioning of thevalve, inadequate testing was performed to ensure that the valve position had been theactual cause of the chiller fa ilure. On October 27, 2007, the "B" chiller failed to restartwhile performing the same section of the procedure. A more rigorous assessment of thefailure determined that a fuse, which had been installed on both chillers earlier in theyear was introducing an error into the sensed oil temperature; thereby, keeping thechiller from restarting if it had been in operation and a station blackout event caused thechiller to trip.The licensee implemented a modification that removed the fuse from the temperaturecircuit and following testing which included a simulated SBO and LOCA signal, declaredthe "B" chiller fully operable. Once the testing found that the fuse had been the cause ofthe chiller failing to restart following a SBO rather than t he mispositioned cooling water 36Enclosurevalve, the "A" chiller was declared inoper able until the same modification could beinstalled in its circuitry. TS 3.0.3 was entered for the time when both the "A" and "B"chillers were inoperable and was exited 23 minutes later after the "B" chiller wasreturned to fully operable status. A non-cited violation was identified due to theinadequate troubleshooting and post-maintenance testing that was performed after thefirst failure of a chille r to restart occurred (see Section 1R19 of this report). The licenseeentered this issue into their corrective action program and implemented severalcorrective actions including enhancing the troubleshooting guidance document to ensureproper retest requirements are specified when resolving issues related to safety-relatedequipment. This LER is closed..5Identification of Tritium in Ground Water Samples from Within the Protected Area a.Inspection ScopeOn October 8, 2007, elevated levels of tritium were detected in one of the newly-installedground water monitoring wells within the protected area of the Catawba site. Based onthe communication protocols established under the NEI Ground Water ProtectionInitiative, the licensee notified the NRC, the South Carolina Department of Health andEnvironmental Control (SC DHEC), York County Emergency Management Services andthe local news media. Representatives from SC DHEC took samples from on-site andsurrounding drinking water wells for analysis. They provided the licensee with splitsamples from these locations to allow for independent analysis to be performed. Subsequent analysis of these samples by both the licensee and SC DHEC did notidentify any other locations where tritium levels approached the EnvironmentalProtection Agency (EPA) limit for drinking water. Five additional monitoring wells wereinstalled in the vicinity of the one well found to have elevated levels of tritium. Initialsample results confirm that the ground water containing tritium at levels above the EPAlimit for drinking water was being contained within the protected area boundary of thesite. On December 6, 2007, a public meeting was held with representatives from theNRC, SC DHEC and Duke Energy providing a presentation on tritium, the results of thesampling that had been conducted and actions being taken by the licensee. The resident inspectors and Region II will continue to moni tor and assess the licensee'sactions in response to this issue. b.FindingsNo findings of significance were identified.4OA5Other Activities.1(Closed) Temporary Instruction (TI) 2515/166, Pressurized Water Reactor ContainmentSump Blockage (NRC Generic Letter 2004-02) - Unit 2 a.Inspection Scope

37EnclosureThe inspectors reviewed Unit 2 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. These commitments included the permanentmodification of the Containment Building ECCS sump strainer assembly, and trashracks. The inspectors reviewed the sump strainer assembly design change packages,corresponding 10 CFR 50.59 evaluation, and ECCS sump inspection requirements. Theinspectors also reviewed variation notices (field changes) and corrective actions relatedto the strainer installation. The inspectors conducted a visual walkdown to verify theinstalled strainer assembly configuration was consistent with drawings and specificationsprovided in the design change packages. b.Findings and ObservationsNo findings of significance were identified in the completion of this TemporaryInstruction. However during other baseline inspection activities, the resident inspectorsobserved a violation of 10 CFR 50 Appendix B; Criterion X "Inspections" pertaining toQA/QC inspections associated with the installation of the new ECCS containment sump. That finding is documented in Section 1R17 of this report.The inspectors determined the following answers to the Reporting Requirementsdetailed in TI 2515/166-05 issued 5/16/07:05.aDuke Energy implemented plant modifications and procedure changes atCatawba Unit 2 committed to in their GL 2004-02 response for Unit 2. A list ofcommitments and their respective completion dates is listed in Attachment 2,Status of GL 2004-02 Commitments for Catawba 2, of this report.05.bDuke Energy updated the Catawba 2 licensing bases to reflect the correctiveactions taken in response to GL 2004-02.05.cCatawba Unit 2 has received an extension of the December 31, 2007 deadlineset forth in GL 2004-02. This extension pertains to additional time required toanalyze the results of ongoing chemical effects testing to validate thereplacement strainer design. The extended deadline for Unit 2 chemical effectsis April 30, 2008. Catawba Unit 1 has also received a general extension of the 12/31/2007 deadline as the Unit 1 strainers will be replaced in the Spring 2008 refuelingoutage. The general deadline extension for Unit 1 expires May 19, 2008. Somestation-wide procedural changes apply to this extension.TI 2515/166 is closed for Catawba Unit 2, as no additional modifications or proceduralchanges under GL 2004-02 are anticipated.

38Enclosure.2(Closed) TI 2515/150, Reactor Pressure Vessel Head and Head Penetration Nozzles(NRC Order EA-03-009) - Unit 2 a.Inspection Scope From September 24 to October 1, 2007, the inspectors reviewed the licensee's activitiesrelated to the non-destructive examination (NDE) of the reactor pressure vessel head(RPVH) nozzles, the bare metal visual (BMV) examination of the RPVH nozzles andhead surface area, and the visual examination to identify potential boric acid leaks frompressure-retaining components above the RPVH. These activities were reviewed duringthe Unit 2-Fall 2007 refueling outage in order to verify licensee compliance with theregulatory requirements of NRC Order EA-03-009 Modifying Licenses dated February20, 2004 (hereinafter the NRC Order) and gather information to help the NRC staffidentify possible further regulatory positions and generic communications. The inspector's review of the NDE of RPVH nozzles included: a) review of NDEprocedures; b) assessment of NDE personnel training and qualification; c) review ofNDE equipment certification and performance demonstration; and d) observation andassessment of ultrasonic (UT) and surface penetrant test (PT) examinations. Theinspectors also held discussions with contractor representatives (Areva) and licenseepersonnel involved in the RPVH examination. Specifically, the inspectors reviewed asample of NDEs as follows: *Observed portions of in-process UT scanning for RPVH nozzles with thermalsleeves*Reviewed the UT data sheets and electronic data for RPVH nozzle Nos. 4, 8,18, and 32.*Reviewed the UT data sheets for RPVH nozzle Nos. 54, 67, 76, and 77, and thePT and UT data sheets for the RPVH vent line penetration*Reviewed the results of the UT examination performed to assess for leakageinto the annulus between the RPVH penetration nozzle and the RPVH low-alloysteel (interference fit zone) for penetration Nos. 4, 8, 18, 32, 54, 67, 76, and 77.*Reviewed training and qualification records for NDE personnel who performedthe above volumetric and surface examinations*Reviewed certification, performance demonstration, and calibration records forNDE equipment used to perform the above volumetric examinations*Reviewed Areva's examination procedures used to perform the abovevolumetric and surface examinations.The inspector's review of the BMV examination for the RPVH nozzles and head surfacearea included: a) review of procedures used to perform the examination; b) directobservation of a portion of the examination; and c) review of results as documented in acorrective action document.The inspector's review of the visual examination to identify potential boric acid leaksfrom pressure-retaining components above the RPVH consisted of the review of 39Enclosurelicensee procedures used to meet this requirement and the results from the visualexaminations performed in the Unit 2-Fall 2007 refueling outage.The inspectors also reviewed the licensee's effective degradation years calculation,which was performed to det ermine the RPVH's susceptibility category and itsexamination requirements. b. Observations and FindingsIn 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 qualifiedpersonnel. All examiners were qualified in accordance with the ASME Codeand had additional training on RPVH examination, as required in Areva's"Written Practice for the Qualification and Certification of NDE Personnel"document.2) Were the examinations performed in accordance with demonstratedprocedures?Yes. Catawba's RPVH (Unit 2) has 78 control rod drive mechanism (CRDM)penetrations and 1 vent line penetration. Fifty seven (57) of the 78 penetrationscontain thermal sleeves and the remaining 21 penetrations have open bores. All penetration nozzles, including the vent line, were examined by remoteautomated UT from the inside diameter (ID) surface in accordance with Arevaapproved procedures 54-ISI-604-004 for open bore penetrations, 54-ISI-603-003 for sleeved penetrations, and 54-ISI-605-03 for small bore penetrations (i.e.vent line).In addition to the CRDM and vent line penetrations, Catawba's RPVH has 4auxiliary head adapter penetrations. These penetrations consist of an Alloy 600nozzle welded to the top of the RPVH with a dissimilar metal full penetrationweld. These welds were not examined as part of the NDEs required to meet theNRC Order. However, these welds were included within the scope of theInservice Inspection Program as required by Section XI of the ASME Code.The inspectors found that Areva examination procedures for CRDM nozzleswere demonstrated to be able to detect and size flaws in the RPVH nozzles inaccordance with Electric Power Research Institute (EPRI) NDE Center's protocol contained in "Materials Reliability Pr ogram: Demonstration of VendorProcedures for the Inspection of Control Drive Mechanism Head Penetrations 40Enclosure(MRP-89)." Areva's equipment demonstration took place from August 14 toAugust 24, 2006. Areva had performed a similar demonstration in 2002, asdocumented in MRP-89. However, because Areva modified its equipmentincluding changing the essential variables of the demonstration in 2002, thedemonstration was repeated. The 2006 demonstration was performed withthree RPVH nozzle mockups with multiple tube flaws representing the expectedfield degradations. These mockups were different from the ones used duringthe demonstration performed in 2002 (i.e. demonstration documented in MRP-89). The demonstration adopted security provisions from the EPRI PerformanceDemonstration Initiative protocol by restricting the access to the mockups andmaking them available to Areva only when the EPRI NDE personnel werepresent. EPRI letter to Duke Energy Corporation, dated September 5, 2007,documents the comparison of the recent Areva's equipment demonstration withthe previous demonstration performed in 2002. The letter states that the scatterobserved is within the variability of the examination and the reliability of theexaminations conducted with the new instrumentation will be comparable to theprevious demonstration.The procedure used for the RPVH vent line was not demonstrated under aspecific program because one doesn't exist. However, the procedure wasdeveloped with NDE techniques similar to the CRDM procedures with regard tobasic fundamental ultrasonic techniques. The procedure used for the PTexamination of the vent line weld surface was developed in accordance with theASME 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 bereported for further examination and disposition as specified in Areva's NDEprocedures. Based on observation of the examination process and discussionswith vendor personnel, the inspectors considered that deficiencies would beappropriately identified, dispositioned, and resolved. UT indications associatedwith the fabrication of the J-groove weld and nozzle tube material were identifiedat several RPVH penetrations. These indications did not exhibit crack-likecharacteristics and were documented for future reference.4) Was the examination capable of identifying the primary water stress corrosioncracking (PWSCC) and/or RPVH corrosion phenomena described in the NRCOrder?Yes. The NDE techniques employed for the examination of RPVH CRDMnozzles had been previously demonstrated under the EPRI MRP/InspectionDemonstration Program as capable of detecting PWSCC type manufacturedcracks. Based on the review of performance demonstration documents,observation of in-process examinations, and review of NDE data, the inspectors 41Enclosureconsidered that the licensee was capable of identifying PWSCC and/orcorrosion 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)?A bare metal visual (BMV) examination was performed per licensee procedureMP/0/A/7150/042D by engineering personnel and two VT-2 qualified inspectors. All RPVH penetrations were inspected either by direct visual examination orvisual examination using a mirror on a pole and flashlights. The CRDM shroudwas removed and the examiners were able to have access to essentially 100%of the required examination surface. No evidence of boron deposits indicatingactive leakage from the annular gaps around the penetrations was observed. The licensee did identify minor general surface corrosion on the dome area ofthe RPVH and light boron stains on some CRDM penetrations, but they werenot indicative of active RCS leakage. The licensee compared the results fromthis BMV examination with the previous one and found no changes that wouldindicate pressure boundary leakage.The inspectors observed part of the BMV examination and performed anindependent assessment of the RPVH condition and found no indications ofleakage from the RPVH nozzles and no significant corrosion of the RPVH topsurface area around the penetration nozzles. The head surface was generallyclear of dirt, insulation, and debris.6) Could small boron deposits, as described in NRC Bulletin 2001-01, be identifiedand characterized?Yes. As noted above, the licensee was able to have access to essentially 100%of the required examination surface. The examination procedure establishedrequirements for the illumination and resolution of the examination equipment. Per procedure, the light intensity (minimum of 50 ft-candles) must allow theexaminer to see a 0.105 inch lower case character height at a 6 ft distance. Based on the inspector's assessment of the BMV examination implementation,the review of personnel qualifications, the review of the BMV examinationprocedure, and the review of the licensee's observations captured in theexamination resu lts, the inspectors considered that t he licensee had the abilityto identify and characterize small boron deposits in the examination area.7) What material deficiencies (i.e., cracks, corrosion, etc.) were identified thatrequired repair?There were no identified examples of RPVH penetration cracks, leakage,material deficiencies, or other flaws that required repair. As indicated above, UT 42Enclosureindications were identified at several RPVH penetrations but were dispositionedas fabrication indications (not crack-like or service induced).8) 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 required volumetric examination coverage extends from a minimum of 2inches above the highest point of the J-groove weld to the maximum coveragepossible below the lowest point of the J-groove weld, with a minimum of 1 inchcoverage if justified by a stress analysis. A stress analysis was performed andjustified the minimum 1 inch coverage below the weld. All examinations met thisrequirement except for thermocouple penetrations 74 -78. The worst caseexamination coverage for these penetrations was 0.70 inches below the lowestpoint at the toe of the J-groove weld. The examination coverage limitation wasdue to the nozzle length, the weld profile on the downhill side of the nozzle, andthe ID tapered tip of the thermocouple nozzle. At the time of the NRCinspection, the licensee was working on a request for relaxation from the NRCOrder requirements.The BMV examination did not have any impediments to performing an effectiveexam. 9) What was the basis for the temperature used in the susceptibility rankingcalculation?The inspectors reviewed the susceptibility ranking calc ulation and the basis forthe RPVH temperature used in the calculation. The calculation determined theRPVH Effective Degradation Years (EDY) and susceptibility ranking since thefirst operating cycle until the current operating cycle using best estimate valuesof effective full power days (EFPD). This calculation has been updated at theend of every operating cycle since the NRC Order was effective. Thetemperature used for the calculation was the reactor coolant system cold legtemperature. The use of this temperature was based on the RPV upperinternals temperature documented in WCAP-13493, "Reactor Vessel ClosureHead Penetration Key Parameters Comparison," and WCAP-9404, "Study ofReactor Vessel Upper Head Region Fluid Temperature."10) During non-visual examinations, was the disposition of indications consistentwith the NRC flaw evaluation guidance?There were no indications considered to be flaws found during the RPVHexamination. 11) Did procedures exist to identify potential boric acid leaks from pressure-retainingcomponents above the RPVH?

43EnclosureYes. Procedure MP/2/A/7150/042, "Reactor Vessel Head Removal andReplacement," was implemented, in part, to conduct inspection activitiesrequired by the NRC Order to identify potential boric acid leaks from pressure-retaining components above the RPVH. This procedure has steps to inspectabove and through the CRDM shroud windows for evidence of leakage everyrefueling outage. The licensee also generates a model work order everyrefueling outage to inspect pressure-retaining components above the head. This outage, the work order provided instruction to inspect the upper andintermediate canopy seal welds because the BMV examination procedurecovered the examination of the lower canopy seal welds in addition to thepenetration nozzles and the head surface area.12)Did the licensee perform appropriate follow-on examinations for indications ofboric acid leaks from pressure-retaining components above the RPVH?There were no indications of leakage found during this outage. 4OA6Meetings, Including ExitExit MeetingOn January 10, 2008, the inspectors presented the inspection results to Mr. J. Pitesaand other members of licensee management, who acknowledged the findings. Theinspectors confirmed that all proprietary information provided or examined during theinspection period had been returned.4OA7Licensee-Identified ViolationsThe following violation of very low safety significance (Green) was identified by thelicensee and is a violation of NRC requirements which meets the criteria of Section VI ofthe NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCV.*10 CFR 50 Appendix B, Criterion XVI requires that measures shall beestablished to assure that conditions adverse to quality are promptly identifiedand corrected. Contrary to the above, the licensee failed to identify and correctthe misaligned 1A safety injection pump bearing oil cooler following the receiptand evaluation of industry operating experience detaili ng the same issue in2004. While the issue was entered into the Component Health Report, noinspections of installed plant equipment or other actions were taken in responseto the industry operating experience. The condition was discovered at Catawbaafter maintenance personnel conducting routine maintenance at McGuireidentified four end bells improperly installed on September 4, 2007. Catawbacorrected the end bell orientation immediately upon discovery and entered thecondition into their corrective action program as PIP C-07-4662. The risk wasdetermined to be of very low safety significance as the licensee demonstrated 44Enclosure through their operability calculation that the safety injection pump would havebeen able to perform its safety function under worst case accident conditions.ATTACHMENTS:(1) SUPPLEMENTAL INFORMATION(2) STATUS OF GL 2004-02 COMMITMENTS FOR CATAWBA 2 Attachment 1SUPPLEMENTAL INFORMATIONKEY POINTS OF CONTACTLicensee PersonnelE. Beadle, Emergency Planning ManagerW. Byers, Security ManagerJ. Caldwell, Modification Engineering ManagerB. Cauthen, RN System EngineerG. Cornwell, Project ManagerJ. P. Downing, Manager, Steam Generator MaintenanceB. Ferguson, Mechanical, Civil Engineering ManagerJ. Foster, Radiation Protection ManagerP. Gillespie, Operations ManagerE. Haack, Performance Testing EngineerT. Hamilton, Safety Assurance ManagerG. Hamrick, Engineering ManagerR. Hart, Regulatory Compliance ManagerG. Hudson, QA/QC Team LeaderT. Jackson, Regulatory ComplianceL. Keller; Supervisor, Reactor and Electrical SystemsD. Llewellyn, Alloy 600 Program DirectorS. Mays, BACC ProgramJ. McConnell, Shift Operations ManagerJ. Morris, Catawba Site Vice PresidentK. Nicholson, Regulatory ComplianceJ. Pitesa, Station ManagerM. Sawicki, Regulatory Compliance EngineerE. Sherwood, CNS Work ControlC. Trezise, Reactor and Electrical Systems Manager A. Young, Licensing Engineer NRCJ. Moorman, III, Chief, Reactor Projects Branch 1LIST OF ITEMS OPENED, CLOSED, AND REVIEWEDOpened and Closed050000413,414/2007005-01NCVFailure to Perform Required ASME Code SectionXI Leakage Testing (Section 1R08.1)05000414/2007005-02NCVFailure to Develop a Lift Plan and RiskManagement Actions for the Replacement of PipingOver a Safety-Related SSC (Section 1R13)

2Attachment 105000414/2007005-03NCVInspections of the Unit 2 ECCS Containment SumpInstallation Failed to Identify Deficiencies Prior toDeclaring the Safety-Related Structure Operable(Section 1R17)05000413,414/2007005-04NCVFailure to Promptly Identify and Correct aSignificant Condition Adverse to Quality Affectingthe Ability of Both CRAVS Chillers to Operate asDesigned Following a SBO due to InadequateTroubleshooting and Post-Maintenance Testing. (Section 1R19)Closed05000413/2007003-00LERUnder-Voltage Condition Resulted in the Actuationof the Emergency Diesel Generators (Section4OA3.1)05000413/2007-002LERTechnical Specification Violations Associated withDivider Barrier Integrity (Section 4OA3.2)05000414/2007001-00 LERFailure to Comply with Action Statement inTechnical Specification 3.3.1 for Loss of a Channelof the Solid State Protection System (Section4OA3.3)05000413/2007004-00LERControl Area Chilled Water Sy stem Inoperable inExcess of Technical Specification Requirementsdue to Unanticipated Component Interactions(Section 4OA3.4)2515/166TIPressurized Water Reactor Containment SumpBlockage (NRC Generic Letter 2004-02) - Unit 2(Section 4OA5.1)2515/150TIReactor Pressure Vessel Head and Vessel HeadPenetration Nozzles (NRC Order EA-03-009)- Unit2 (Section 4OA5.2)

Attachment 1LIST OF DOCUMENTS REVIEWEDSection 1R01: Adverse Weather PT/0/B/4700/038, Cold Weather Protection, Rev. 26IP/0/B/3560/013; Calibration Procedure for DigiTrace 200N Heat Trace Controller; Rev. 0IP/0/B/3560/008; Preventative Maintenance and Operational Check of Freeze Protection HeatTrace and Instrument Box Heaters (EHT/EIB) Systems (Fall PM) Rev. 50 IP/0/B/3560/009; Operational Check for Winter Months and Extreme Cold Weather Surveillanceof Freeze Protection Heat Trace and Instrument Box Heaters (EHT/EIB) Systems, Rev. 11IP/0/B/3560/011; Summer Preventive Maintenance and Operational Check Of Self Regulatedand Constant Wattage Freeze Protection Heat Trace And MHIB Heaters (EHT/EIB) Systems,Rev. 16PIP C-07-6856; Investigation into why the heating water converters were not heating up. Coldweather protection PT in progressPIP C-06-8177; Freeze Protection circuit 1RC18 damaged during maintenance activitiesPIP C-07-00480; Possible freeze protection issues with RW Cabinets at RN and RL RW shedsPIP C-07-00633; Thermostats for ventilation heaters not set correctlyPIP C-07-00811; Cold weather curtains in exterior Doghouse not securedPIP C-07-06633; Procedure OP/1/A/6450/004 Enclosure 4.9: Unable to completely drain waterper procedure from the Fuel Pool Ventilation SystemPIP C-07-06808; Breakers that control the Waste Solidification Building heaters found inthe "off" position.PIP C-07-04371; Freeze Protection circuits 1CF01 and 1CF03 found failed during Summer PM PIP C-07-00124; Equipment Reliability concerns with Freeze Protection on Service Bldg and AuxBldg roof.PIP C-07-00078; Low voltage on Freeze protection circuits in WC pitPIP C-06-08211; RES/MCE need to evaluate RC freeze protection prior to mod's CD100691 andCD200692 (new controllers and circuits for Unit 1 & 2 RC pit) are designed.PIP C-06-05500; Freeze Protection Summer PM found 1MIHB0011 and 1MIHB0012 deletedOAC Alarm Responses for points C1P0118 (Ambient Dry Bulb Temperature); C1P1821(Ambient Wet Bulb Temperature),C2P0118 (Ambient Dry Bulb Temperature), and C2P1821(Ambient Wet Bulb Temperature)NSD 317; Freeze Protection Program, Rev. 3Section 1R04: Equipment Alignment PIP C-07-6945; Non-licensed operator placed protected equipment tape on 2B RN pump vs. 1B RN pumpDrawing CN 1609-1.0, Flow Diagram of DG Engine Cooling Water System, Rev. 15Drawing CN 1609-2.0, Flow Diagram of DG Lube Oil System, Rev. 24Drawing CN 1609-2.0, Flow Diagram of DG Lube Oil System, Rev. 22Drawing CN 1609-4.0, Flow Diagram of DG Engine Starting Air System, Rev. 23Drawing CN 1609-2.0, Flow Diagram of DG Engine Starting Air System, Rev. 22Drawing CN 1609-3.0, Flow Diagram of DG Engine Fuel Oil System, Rev. 21Drawing CN 1609-3.1, Flow Diagram of DG Engine Fuel Oil System, Rev. 17 4Attachment 1Drawing CN 1609-5.0, Flow Diagram of DG Engine Air Intake and Exhaust System, Rev. 6Drawing CN 1609-7.0, Flow Diagram of DG Room Sump Pump System, Rev. 10OP/1/A/6350/002; Diesel Generator Operation, Rev. 138OP/1/A/6550/001; Diesel Generator Fuel Oil System Operation, Rev. 62OP/1/A/6550/002; Diesel Generator Lube Oil System Operation, Rev. 60OMP 2-28; Diesel Generator Logbook for the 1A and 1B diesel generatorsTS 3.8.1, AC Sources - Operating and TS 3.8.2; AC Sources - Shutdown\Emergency Diesel Generator Health Report; 2007Q1, 2007Q2 and 2007Q3125 VDC Diesel Auxiliary Power Syst em Heath Report; 2007Q1, 2007Q2 and 2007Q3PIP C-0700685; High temperature aftercooler water inlet annunciator came into alarm 10minutes into the runPIP C-07-1719; T he 1A DG tripped during its operability PT and the com puter indicated 1ETA-18 lockout.PIP C-07-3411; Valve 1KD24 has excessive corrosion present due to a leak PIP C-07-3610; DG 1B tripped on vibrati on during the 5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> operability PTPIP C-07-3634; During performance of OP/1/A/6350/002, DG 1B tripped at full load due to highvibrationPIP C-07-3635; Unexpected TSAIL entry C1-07-01665 for the 1B DG failure to achieve 3950volts to 4370 volts following a diesel start. The actual voltage was 4400 volts.PIP C-07-4475; This documents a station blackout signal event which lasted long enough tostart all 4 diesel generators, but since it was less than 8.5 seconds, none of the sequencersactuated (no loads were shed)Section 1R05: Fire Protection Station Fire Impairment LogPre-Fire Plan for Fire Strategy Area RB-1; Unit 2 Reactor Building, Section 2.20Pre-Fire Plan for Fire Strategy Area 4, Auxiliary Building 543 level, Rooms 200 - 248Pre-Fire Plan for Fire Strategy Area 1, Auxiliary Building 522 level, Rooms 100 - 112Pre-Fire Plan for Fire Strategy Area 3, Auxiliary Building 543 level, Rooms 250, 250A, 255 and256 (Unit 1 CA Pump Room and Motor Driven CA Pump Pits)Pre-Fire Plan for Fire Strategy Area 40, Auxiliary Building 543 level, Room 254 (Unit 1 CATurbine Driven Pump Pit)Pre-Fire Plan for Fire Strategy Area 11, Auxiliary Building 560 level, Rooms 200 - 248Pre-Fire Plan for Fire Strategy Area AW, Standby Shutdown Facility, 594 foot ElevationPre-Fire Plan for Fire Strategy Area AX, Standby Shutdown Facility, 611 foot ElevationPre-Fire Plan for Fire Strategies D and E, Catawba Nuclear Station Turbine Building Unit 1, 568foot elevationSelect Licensee Commitments Section 16.9-4; Fire Hose StationsSelect Licensee Commitments Section 16.9-5; Fire rated AssembliesNSD 313, Control of Combustible and Flammable Material, Rev. 6NSD 314; Hot Work Authorization, Rev. 6PIP C-07-7058; Fire hose cabinet downstream of 1RFA-64 (outside of Unit 1 CA pump room)found to be in a poor state of repair by NRC ResidentPIP C-0707059; Fire hose cabinet outside of the Unit 2 CA pump room found to be in poorcondition after notified of the condition of the Unit 1 hose cabinet 5Attachment 1Section 1R07: Annual Heat Sink PerformanceUFSAR Section 9.5.5; Diesel Generator Jacket Cooling Water SystemCNS-1274.00-00-0016; License Renewal Basis Specification, Section 4.16.3; Diesel GeneratorEngine Cooling Water Heat ExchangersDAP2000 Computer Application Version Tracking systemSection 1R08: Inservice Inspection Activities NDE-600, Ultrasonic Examination of Similar Metal Welds in Ferritic and Austenitic Piping,Revision 17NDE-35, Liquid Penetrant Examination, Revision 21PT/2/A/4150/001 H, Inside Containment Boric Acid Check, Revision 14MP/0/A/7650/040, Inspection, Evaluation and Cleanup of Boric Acid on Plant Materials,Revision 14NSD 322, Boric Acid Corrosion ProgramPIP C-07-05248, 2007 CNS Boric Acid Corrosion Program AssessmentSGMEP 105, Westinghouse Model D5 Specific Assessment of Degradation Mechanisms forCatawba Unit 2 EOC 15, Revision 6Condition Monitoring and Operational Assessment for Catawba Unit 2 EOC 14CNC 2201.01-00-0007, Evaluation of Foreign Objects in the Preheater of the Catawba Unit 2Steam Generators, Revision 1Relief Request 07-GO-001, Proposed Alternative to support application of full structural weldoverlays on various pressurizer nozzle-to-safe end weldsConfirmatory Action Letter No. NRR-07-015, regarding Alloy 82/182 butt welds in thepressurizerPIP C-07-05738 NRC ISI Inspector has questioned the Station's use of IWA-5244 Section (b) 2for conducting the system pressure test for buried portions of the RN SystemPIP C-07-05659 Crack-like indication was detected just above the top of the tubesheet in the2B steam generator.PIP C-07-05445 Document the inspection of the U2 NV Letdown line from the point were thepipe exits the regenerative heat room through the "B" accumulator room and the "B & C" fanroom, to the wall of the "C" accumulator roomPIP C-07-05264 Surface indication found during augmented ISI MT examPIP C-07-05205 Preliminary findings from General Visual Inspection PT/2/A/4200/078performed in the area of the Unit 2 ECCS sump on 9/21/07PIP C-07-01970 Pipe cap on 2NB-503 has gone from an inactive leak to an active leakPIP C-07-01978 Dried boron was found on the body to bonnet joint and also the stud and nutmaterial on valve 2KF-19PIP C-07-02546 Boron between Cap and Body of 2FW-53 cannot be thoroughly cleanedPIP C-07-05536 Alloy 600 - Welding Services Incorporated (WSI) confirmed today (9/29/07)they have issues with the layout and punchmarks on PZR PORV nozzle weld overlayRT Examination Report for Weld 2 NI 2492-NI.00-139-25UT Examination Data Sheets for Surge Line Pressurizer Overlay NW-1-WBM-WOL, -DM, and -SSUT Examination Reports UT-07-745 through -747 (welds 2SM59-01, -02, and -4A-A)

6Attachment 1PT Examination Reports PT-07-478 through -480 (welds 2NC-52-6, -7, and -8) Weld Process Control Record for Work Order: 01748154 (weld 2492-NI.00-139-25)VT-3 examination reports for F01.020.033/2-R-ND-0323 and F01.021.091/2-R-NS-1208Section 1R11: Licensed Operator Requalification OP-CN-LOR-S-07; LOR Task Requirement Guide, Rev. 14AP/1/A/5500/012; Loss of Charging or Letdown, Rev. 25EP/1/A/5000/FR-H.1; Response to Loss of Secondary Heat Sink, Rev. 30Section 1R12: Maintenance Effectiveness PT/2/A/4350/002B, Diesel Generator 2B Operability Test, Rev. 89 Unit 2 Autolog entries associated with the 2B DG break-in and operability runsPIP C-07-5829; Delays in performing break-in run for the 2B DG due to air leaks on the 3-wayvalvePIP C-07-5949; Received alarm for loss of control power on the 2B DGPIP C-07-6789; Unit 2 DRPI did not change when attempting to move shutdown banks C, D andE during RCCA movement testingPIP C-07-6792; During performance of PT/2/A/4600/001 (RCCA movement test), the RPI Non-Urgent failure annunciator was received due to shutdown bank N9 rod indication problemsWO 01780921; Determine cause of the failure of shutdown banks C, D and E to move andrepair PT/2/A/4600/001, RCCA Movement Test, Rev. 30 (performed twice, once as a functional retestof the system following completion of repair activities)Failure Investigation Process troubleshooting and repair plan for Unit 2 control rod shutdownbanks C, D, and E IP/0/A/3890/001; Controlling Procedure for Troubl eshooting and Corrective Maintenance; Rev.

056Unit 2 AutoLog entries associated with the shutdown bank movement issuesWO 01748147; Repair shutdown bank N9 Rod Data B failure PIP C-07-01169; Rod N-9 DRPI indication failingCD201320; Temporary design Change to install and subsequently remove Operator AidComputer point data to exclude N-9 data from the Data B alarm logic CD201264 Install Helicoil into 2D SG cold leg primary manwayWO 01726965; Repair #8 Stud hole on 2D SG cold leg primary manwayMP/0/A/7650/070; Helicoil Installation, Rev. 9MP/0/A/7650/148; ASME Section XI Repairs or Replacements, Rev. 16TM/0/A/7550/044; Westinghouse Procedure - Steam Generator Primary Manway Stud HoleRepair for Catawba Unit 2, Rev. 0PIP C-06-02442; Steam Generator 2D cold leg primary manway has damaged threads in studhole #8 7Attachment 1Section 1R13: Maintenance Risk Assessments and Emergent Work Evaluation Risk Management Actions for 2B DG Battery Charger repairs conducted under WO 1782004 on13 November, 2007 2DGCB Charger Repair Plan under Work Order 1782004-01PIP C-07-6926; Performance of Immediate Determination of Operability for 2B DG BatteryCharger due to spurious alarmsPIP C-07-6948; 2B DG Battery Charger placed Unit 2 in an unplanned ORAM OrangeSOER 91-01 Package for the Commissioning Testing of the Automatic Voltage Regulator Replacement Installed during Catawba Unit 2 2EOC15 Refueling OutageWO 01118529, Post Modification Testing of the Unit 2 Automatic Voltage RegulatorDuke Energy Nuclear Lifting Program, Rev. 13NSD 213; Risk Management Process, Rev. 6NSD 403; Operational Risk Management (Modes 4, 5, 6, and No-Mode) per 10CFR50.65(a)(4),Rev. 16Critical Activity Plan for Modification CD200411, Auxiliary Building RN Pipi ng ReplacementWork Order 01723595, Unit 2 replacement of valve 2RN-838 and relocate valve 2RN229BDuke Energy Nuclear Lifting Program ManualPIP C-07-5440; Cutout of RN piping and valves was being done without a lift plan or other riskmanagement actions on Unit 2PIP C-07-5447; Error found in the oversight plan for the RN piping replacementCatawba UFSAR Section 17.0; Quality Assurance ProgramCritical Activity Plan; NC Fill and Vent using NCP's to purge air from Steam Gener ator U-tubes,Rev. 1 Section 1R15: Operability Evaluations Alden Labs testing report on ECCS throttle valve clogging from debris induced into the flowstreamWCAP 8110, Supplement 9, Ice Fallout from Seismic Testing of Fused Ice Basket, dated May 1974Atomic Energy Commission letter to Westinghouse Electric Corporation providing anassessment of WCAP 8110, Supplement 9 dated November 21, 1974 PIP G-00-0438; Duke's position regarding the applicability of WC AP-8110, Supplem ent 9, datedMay 1974 needs to be documentedMcGuire PIP M-02-2830; Update UFSAR to remove references to WCAP-8110, Supplement 9Catawba UFSAR Section 6.6.20PIP C-04-1209; NV pump 1A has a discharge head-to-casing leak that requires a formalevaluation when the ISI system pressure test is performedPIP C-04-1168, Cover leak identified on the 2B NS pumpPIP M-07-5135; UFSAR ND and NS pump Net Positive Suction Head calculation discrepancyCalculation CNC-1223.04-00-0104; Evaluation of Runout Limits on NV pumps, Rev. 0Calculation CNC-1223.12-00-0057; Hydraulic Model of the Unit 1 Emergency Core CoolingSystem. Rev. 8Calculation CNC-1223.04-00-0063; Acceptance Criteria Verification for PT/1(2)/A/4400/001,ECCS Flow Balance, Rev. 9 8Attachment 1ODMI Assessment of the return of Unit 2 to service without having transformer 2ATD available PIP C-07-5347; O perations requests an Immediate Determination of Operability concerning theinability to perform SR 3.8.1.8 on Unit 1 for B train power due to the failure of transformer2ATDPIP C-07-5160; Transformer 2ATD temperatures increased rapidly when the 6.9kV feederbreaker was closedCNSD-0111-03; System Description for the 600 V Blackout Auxiliary Power System, Rev. 6CNSD-01115-02; System Description for the 4.16kV Blackout Auxiliary Power System, Rev. 3CNSD-0116-01; System Description for the 6.9kV Normal Auxiliary Power System, Rev. 6NUREG-0954; Safety Evaluation Report related to the operation of Catawba Nuclear StationUnit 1 and 2, February 1983Section 1R17: Permanent Plant Modifications PIP C-06-8777; Unusual event occurred when the loop drain valves on the "C" NC loopinadvertently opened during plant heat-up on Unit 1PIP C-07-2912; Unexpected entry into TSAIL for submarine hatch not being securedPIP C-07-5682; New operator installed on 2FW-27A requiring engineering evaluationPIP C-07-5945; 2FW-27A failed its required acceptable stoke time for "open to close" and "closeto open"PIP C-07-6100; 2FW-55B failed its required acceptable stoke time for "close to open" and "opento close"PIP C-07-6102; New operator installed on 2FW-55B requiring engineering evaluationCD201296; Modify Unit 2 reactor coolant system loop drain lines to preclude inadvertent loss ofReactor Coolant System inventoryCD201528; Add stop and modify arms of the Unit 2 submarine hatch between lower and uppercontainmentCD200863; Install body vent valves on 2FW-27A and 2FW-55B to eliminate to potential forpressure locking of the valves if required during a Mode 4 Loss of Coolant Accident (LOCA)CD200490; ECCS Unit 2 containment recirculation sump strainer modificationRoot Cause Directional Discussion / Interim Corrective Actions associated with the submarinehatches on both units being found unsecured during power operation (contained in PIP's C-07-2911 and C-07-2912)PIP C-07-6876; Unacceptable gap observed between top hat and plenum on east wing sectionFP-14PIP C-07-6781; Working copy of TN/2/A/CD200490/02M being used in containment was foundto be the wrong revision of the procedureWO 01731978, Task 14; Re-inspect gaps on ECCS sump prior to entry into Mode 4PT/2/A/4400/018; Unit 2 Containment Building Civil Structures Inspection, Rev. 003TN/2/A/CD200490/02M; Installation of New Unit 2 Containment Recirculation Sump StrainerTrains A and B, Rev. 0 and Changes A and BVideos of the internal inspections conducted on the ECCS sump structureAs built drawings CNM 2144.06-005.001 and CNM 2144.06-0033.001 9Attachment 1Section 1R19: Post-Maintenance TestingComplex Activity Plan for restoration of transformer 2ATD LER 05000413/2007-004; Control Area Chilled Water System Inoperable in Excess of TechnicalSpecification Requirements due to Unanticipated Component InteractionsRoot Cause Failure Analysis Report; Train A YC Chiller Failure During ESF Testing, Rev. 0Engineering Troubleshooting Process Guide Failure Investigation Process report for the YCChiller B failing to start during the 2B LOCA ESF testingAP/0/A/5500/039; Control Room High Temperature, Rev. 05PIP C-07-6479; A YC chiller fa iled to start duri ng A train ESF te sting on Unit 2 PIP C-07-6848; Complete loading sequence for the B YC chiller not verifi ed during the ESFtesting PIP C-07-6503; Unplanned TSAIL entry for B YC due to the B YC chiller failure to restart duringthe B train ESF testingTSAIL reports for the A and B YC chillers covering the periods in which the replacement fuses were installed in the temperature circuitry for the chillersAutolog entries for the period of 10/25/07 through 10/30/07Work Order 01779183; 0YC Chiller A; I/R not st arting during ESF testingStation Modification CD201603; Remove redundant fuse on YC chiller 2CRA-C-1Station Modification CD101604; Remove redundant fuse on YC chiller 1CRA-C-1Section 1R20: Refueling and Outage Activities 2EOC-15-IRT Unit 2 Outage Risk AssessmentSite Directive 3.1.30, Unit Shutdown Configuration Control (Modes 4, 5, 6 or No Mode), Rev. 35Nuclear System Directive, NSD-403, Shutdown Risk Management (Modes 4, 5, 6 and NoMode), per 10CFR50.65(a)(4); Rev. 16NSD 500; Red Tags / Configuration Control Tags; Rev. 24PT/2/A/4350/003, Electrical Power Source Alignment Verification, Rev. 45OP/2/A/6200/005, Spent Fuel Cooling System, Rev. 64PT/0/A/4150/037, Fuel / Component Movement Accounting, Rev. 9; Enclosure 13.3; ReloadTransfer SheetPT/2/A/4200/002C, Containment Closure Verification (Part I); Rev. 64PT/2/A/4200/002I, Containment Closure Verification (Part II); Rev. 36PT/2/A/4200/002J, Containment Closure Verification Penetration Status Change; Rev. 13OP/0/A/6100/014, Penetration Control for Modes 5 and 6; Rev.32 OP/2/A/6150/001, Filling and Venting the Reactor Coolant System, Encl osure 4.16, ReactorCoolant System Vacuum Refill Wi thout Solid Operation; Rev. 75OP/2/A/6150/006, Draining the Reactor Coolant System; Rev. 70; Enclosure 4.2, Decreasingthe NC System Level and Enclosure 4.3, Increasing the NC System LevelOP/2/A/6550/006, Transferring Fuel with the Spent Fuel Manipulator Crane; Rev. 54OP/2/A/6550/007, Reactor Building Manipulator Crane Operation; Rev. 34OP/2/A/6550/008, Fuel Transfer System Operation; Rev. 10 & 11MP/0/B/7150/012, Refueling Canal Cleanliness; Rev. 7PT/2/A/4550/001B; Reactor Building and Fuel Transfer Refueling Component Test, Rev. 19 10Attachment 1PT/2/A/4550/001C, Refueling Communications Test; Rev. 16PT/2/A/4550/001D; Reactor Building Manipulator Crane Load test; Rev. 12 PT/2/A/4550/001E; Spent Fuel Building Manipulator Crane Load test; Rev. 7PT/0/A/4550/003C, Core Verification; Rev. 9 - Superseded by PT/0/A4550/003 C; PostRefueling Core Verification, Rev. 0PT/0/A/4150/022, Total Core Reloading; Rev. 39 PT/0/A/4150/037; Fuel / Component Movement Accountability, Rev. 10PT/0/A/4200/002, Containment Cleanliness Inspection; Rev.29SM/0/A/8510/008, Ice Condenser Foreign Material Exclusion Inspection; Rev. 3PT/0/A/4150/019; 1/M Approach to Criticality; Rev.34PT/0/A/4150/001J, Zero Power Physics Testing; Rev. 3PT/0/A/4150/001, Controlling Procedure for Startup Physics Testing; Rev. 41PT/0/A/4150/019B, NC System Dilution Following Refueling, Rev. 15OP/0/A/6100/006; Reactivity Balance Calculation, Rev. 72 OP/2/A/6100/001, Controlling Procedure for Unit Startup; Rev. 144 OP/2/A/6100/003, Controlling Procedure for Unit Operations; Rev. 100OP/2/B/6300/001, Turbine Generator Startup; Rev.74OP-CN-JITT-ZPPT/Turbine; Just In Time Training Package; Initial Startup / Zero Power PhysicsTesting / Turbine On-Line; Rev. 7PT/0/A/4150/001J, Zero Power Physics Testing Pre-Job Briefing PackageMP/2/A/7150/042; RX Vessel Head Removal & Replacement, Rev. 39Catawba Unit 2 Spent Fuel Pool Assembly Location MapCNEI-0400-149, Catawba 2 Cycle 16 Core Operating Limits Report; Rev. 0Critical Activity Plan; NC F ill and Vent using NCP's to purge air from SG U-tubes, Rev. 1PIP C-07-4838; Assessment of industry initiative of heavy load liftsPIP C-07-4954; One train of containment sump recirculation was not available as required bySite Directive 3.1.30PIP C-07-4990; Post transient assessment of the turbine trip on low condenser vacuum duringthe Unit 2 shutdownPIP C-07-4991; Reactor Engineering's shutdown plan was low on the amount of boric acidestimated to be required for the shutdownPIP C-06-2136; Bottom head inspections of the reactor vessel during the 2EOC14 outage in 2006PIP C-07-6305; An anomaly was noted on the core barrel for the 2C hot leg during the upperinternals inspectionPIP C-07-6308; Operations assessment of the cooldown from Mode 3 to Mode 5 for Unit 2EOC15 refueling outagePIP C-06-1882; Documentation of the Unit 2 2EOC14 Ice Condenser WalkdownPIP C-07-5638; Documentation of the Unit 2 2EOC15 Ice Condenser WalkdownPIP C-07-6849; Material found in upper containment during the performance ofPT/0/A/4200/002 at the end of 2EOC15PIP C-07-6852; Lower inlet door exceeded the acceptance criteria of 15.5 lbs while performingthe "As-Left" initial opening force testPIP C-07-5190; 2EOC15 Ice Basket Damage Assessment 11Attachment 1PIP C-07-5237; The top strut of support 2-NC-1599 is missing the inner bolt and nuts of the 2bolt clampPIP C-07-5196; Support 2-NV-1614 is missing the load pin between the strut and the 2 boltclampPIP C-07-5376; Replacement rotating element in 2B NV pump has a higher horsepowerrequirement than the previous element and that in the 2A NV pumpMP/0/B/7650/145; Containment Polar Crane, Rev. 009MP/2/A/7150/042, Reactor Vessel Head Removal and Replacement, Rev. 37, 38 and 39MPM/0/A/7650/057, Polar Crane Operation and Upper Containment Load Paths, Rev. 20Complex Activity Plan for the Unit 2 Reactor Vessel Head Removal and Replacement Within theBounds of the Catawba Specific Head Drop AnalysisNRC Regulatory Issue Summary 2005-25, Supplement 1, Clarification of NRC Guidelines forControl of Heavy LoadsNUREG-0954; Catawba SER Supplement 4, Appendix F, Control of Heavy Loads at NuclearPower Plants: Catawba Nuclear Station Units 1 and 2 (Phase II)PIP C-97-2354; Present method of lifting the reactor vessel head during outages does notconform to the guidelines of NUREG-0612 and Generic Letter 81-07PIP C-07-4838; Industry initiative on heavy load liftsPIP C-07-7181; Enforcement Guidance Memorandum 07-006; Enforcement Discretion forHeavy Load Handling ActivitiesMemo from W. Parker (Duke Power Company) to H. Denton (NRC) dated September 24, 1981on NUREG-0612, Control of Heavy Loads at Nuclear Power Plants Memo from W. Parker (Duke Power Company) to H. Denton (NRC) dated July 1, 1982 onNUREG-0612, Control of Heavy Loads at Nuclear Power Plants Memo from H. Tucker (Duke Power Company) to H. Denton (NRC) dated August 6, 1982 onNUREG-0612, Control of Heavy Loads at Nuclear Power Plants Memo from H. Tucker (Duke Power Company) to H. Denton (NRC) dated April 19, 1984providing the results of the NUREG-0612 Phase I and Phase II technical evaluationsMemo from H. Tucker (Duke Power Company) to H. Denton (NRC) dated August 17, 1984 onNUREG-0612, Control of Heavy Loads at Nuclear Power PlantsCatawba Nuclear Station Calculation CNS-1144.00-00-0010; Appendix B, Reactor BuildingLifting DevicesCatawba Nuclear Station Calculation CNS-1144.03-14-0004; Reactor Building Vessel HeadDrop and Other Heavy Load Drops on the Operating FloorSection 1R22: Surveillance Testing PIP C-07-6353; Procedure discrepancies identified in PT/2/A/4550/001 D; Reactor BuildingManipulator Crane Load Test, during performance prior to core reload91-01 Pre-Job Brief for the Containment Integrated Leak rate Test, PT/2/A/4200/001A, Rev. 2PIP C-06-1882; Documentation of the Unit 2 2EOC14 Ice Condenser WalkdownPIP C-06-3513; 2EOC14 Ice Condenser Outage CritiquePIP C-07-5738; Documentation of the Unit 2 2EOC15 Ice Condenser WalkdownPIP C-07-6852; Lower inlet door exceeded the acceptance criteria of 15.5 lbs while performingthe "As-Left" initial opening force test 12Attachment 1MP/0/A/7150/139; Ice Condenser Walkdown and Inspection (completed copy), Rev. 002 PIP C-07-7445; 2A D/G Operability test has conflicting standby LD temperatures (NRCidentified)DocuTracks Request CNS-2007-005487 for PT/2/A/4150/001D (NC System LeakageCalculation) - The references to LCO action statements are incorrect and need to beupdated to reflect the current TS amendmentDocuTracks Request CNS-2007-005488 for PT/1/A/4150/001D (NC System LeakageCalculation) - The references to LCO action statements are incorrect and need to beupdated to reflect the current TS amendmentSection 1EP6: Drill EvaluationCatawba Emergency Response Organization Drill Scenar io Guide 07-01Catawba Emergency Response Organization Drill Scenar io Guide 07-02RP/0/A/5000/020, TSC Activation Procedure, Rev. 23 Catawba Nuclear Site Critique Summary Report for Drill 07-01Catawba Nuclear Site Critique Summary Report for Drill 07-02Section 4OA1: Performance Indicator VerificationNSD 225, NRC Performance Indicators, Rev. 3NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Rev. 4 and Rev. 5LER 413/06-002, Safe shutdown potentially challenged by an external flooding event andinadequate design and configuration controlLER 413/06-003; Technical Specification violations associated with the hydrogen ignitionsystemLER 413/07-001; Safe shutdown capability potentially challenged by fire protection deficienciesattributed to design oversightLER 413/07-002; Technical Specification violations associated with divider barrier integrityLER 414/07-001; Failure to comply with action statement in Technical Specification 3.3.1 for theloss of a channel of solid state protection systemConsolidated Data Entry 3.0 MSPI Derivation Reports; Unavailability Index and UnreliabilityIndex; September 2007 - reports for each MSPI listed under the Mitigating Systemscornerstone on Section 4OA.1PT/2/A/4150/001D, NC System Leakage Calculation, Rev. 64DocuTracks Request CNS-2007-005487 for PT/2/A/4150/001D (NC System LeakageCalculation) - The references to LCO action statements are incorrect and need to beupdated to reflect the current TS amendmentDocuTracks Request CNS-2007-005488 for PT/1/A/4150/001D (NC System LeakageCalculation) - The references to LCO action statements are incorrect and need to beupdated to reflect the current TS amendmentLER 05000413/2006-001; Loss of Offsite Power Event Resulted in a Reactor Trip of BothCatawba Units from 100% Power 13Attachment 1Section 4OA2: Identification and Resolution of ProblemsPIP C-06-3902; Unit 2 Cooling Tower overflowed and entered the 1A DG roomPIP C-06-7420; During the NRC flood inspection the week of 10/30/06, several issues wereidentified with the condui t seals that enter the Standby Shutdown FacilityWR 00199298; Inspect conduit seals in manholes CMH 2, 3, 18A, 18B and 21 on an 18-monthfrequencyWO 1013458; Increase the frequency of inspecting the monitored tank building trench hatchcovers from annually to semi-annuallyAR 00158155; Perform annual inspections of the cooling tower yard drains, WC pond yarddrains and switchyard drainsAR 00158158; Conduct annual inspections of berms and curbs around the siteAR 00199697; Perform semi-annual inspections of the DG roof hatch sealsAR 00199700; Perform semi-annual inspections of the Conduit Manhole missile shield coversealsAR 00159414; Inspect and clean the transformer yard conduit manhole drains every 18 monthsAR 00208859; Inspect the conduit seals that enter the turbine buildings from the transformeryard conduit manholes AR 00165873; Periodically inspect the Standby Shutdown Facility cable trench penetrationsealsSection 4OA3: Event Follow-up PIP C-07-2365; Unexpected TSAIL entry due to OTDT Channel 4 loss of powerPIP C-07-2484; Lessons Learned from the replacement of the power supply and channel 4 cardin the Unit 2 B train SSPS cabinetPIP C-07-3408; PORC Meeting to review the LER associated with the failure to comply with theaction statement of TS 3.3.1 for a loss of a channel of SSPSRoot Cause Failure Analysis Report; Train A YC Chiller Failure During ESF Testing, Rev. 0Engineering Troubleshooting Process Guide Failure Investigation Process report for the YCChiller B failing to start during the 2B LOCA ESF testingPIP C-07-6479; A YC chiller fa iled to start duri ng A train ESF te sting on Unit 2 PIP C-07-6848; Complete loading sequence for the B YC chiller not verifi ed during the ESFtesting PIP C-07-6503; Unplanned TSAIL entry for B YC due to the B YC chiller failure to restart duringthe B train ESF testingPIP C-07-5892; A sample contained from groundwater monitoring well #213 was found tocontain tritium levels that triggered the communication protocol of the NEI initiative onground water protectionPIP C-07-5968; SC DHEC request for drinking water samples from on-site wellsSC DHEC News Releases dated October 10, 2007 and November 2, 2007PNO-II-07-012; Onsite Groundwater Tritium ContaminationPNO-II-07-012A; Update - Onsite Groundwater Tritium Contamination at the Catawba NuclearStation Site 14Attachment 1Event Notification Form #43703; NRC Notification of elevated tritium levels in a groundwatermonitoring well within the Protected Area at Catawba, 10/09/07Section 4OA5: Other Activities

[TI 2515-166]Design Change PackagesCD200490, CMP U2 ECCS Replace Containment Recir Sump StraineCorrective ActionsPIP C-07-06672, Limited Areas of Without Coatings related to the Unit 2 ECCS Sump ModPIP C-07-06781, Working Copy of TN/A/CD/200490/02M Not RevisedPlant ProceduresPT/0/A/4200/002, Containment Cleanliness Inspection, Rev. 027PT/2/A/4400/018, Unit 2 Containment Building Civil Structures Inspection, Rev. 003[TI 2515-150]Procedures54-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. 351-9045055-000, "RPV Head Penetration Inspection Plan & Coverage Assessment for CatawbaUnit 2 and McGuire Unit 1."MP/0/A/7150/042D, "Reactor Vessel Head Penetration Visual Inspection," Rev. 3Engineering DocumentsCalculation No. CNC-1201.01-00-0022, "Determination of Interim Inspection Requirements forthe Reactor Vessel Heads and RV Head Inspection Documentation," Rev. 6Dominion Engineering Calculation C-3023-00-02, "Catawba Unit 2 Upper Head CRDM NozzleWelding Residual Stress Analysis," Rev. 0Corrective Action DocumentsPIP C-07-05751 Work OrdersWO 01731046-01, "2NC Rx Head: RV Head CRDM Canopy Seal Welds - Visual 15Attachment 1Other RecordsEPRI Letter from Mr. Jack Spanner (Program Mgr.) to Ms. Rachel Doss (Duke Power Corp.)dated September 5, 2007Personnel Certification Records for Areva NDE examinersAreva UT Transducer Reports and/or Acceptance Test Report for UT inspection probes: 2928-07003 (Gimbald probe), S5003NL (blade probe), S5025NL (blade probe), 9269-07005 (ventline probe).PT examination report for RPVH vent lineSection 4OA7: Licensee-Identified Violations Inspection Report 05000369, 370/2007-009, Special Inspection ReportMP/0/A/7650/056, Heat Exchanger Corrective Maintenance, Rev. 030 Calculation CNC-1223.12-00-0074; Determination of Heat Removal Capability of NI Pump 1AOil Cooler in Degraded Condition PIP C-07-4662; Reportability determination of NI pump 1A oil cooler issueTSAIL entries associated with the 1A NI pump to fa cilitate end bell o il cooler repairsWork history for the bearing and speed changer oil coolers on the NI and NV pumps for Unit 1and Unit 2American Standard drawing 5-162-06-018-003, Heat Exchanger, Rev. 03American Standard Heat Transfer Division Operating Instructions and Parts List for Type BCF,HCF and SSCF heat exchangers, dated 10/1/74Component Health Report for Heat Exchangers covering the 1 st trimester of 2004LIST OF ACRONYMSAP-Abnormal Operating ProcedureAR-Action RequestBACC-Boric Acid Corrosion ControlBMV-Bare Metal VisualCA-Auxiliary Feedwater SystemCAP-Corrective Action ProgramCFR-Code of Federal RegulationsCMH-Conduit ManholeCNS-Catawba Nuclear StationCRDM-Control Rod Drive MechanismCRAVS-Control Room Area Ventilation System DG-Diesel GeneratorECCS-Emergency Core Cooling SystemECT-Eddy Current TestingEOC-End-of-CycleEPA-Environmental Protection AgencyEPRI-Electric Power Research Institute 16Attachment 1ESF-Engineered Safety FeatureID-Inside DiameterISI-Inservice InspectionKD-Diesel Generator Jacket Water CoolingKF-Spent Fuel Pool CoolingLCO-Limiting Condition for OperationLER-Licensee Event ReportLOCA-Loss of Coolant AccidentMSPI-Mitigating System Performance IndicatorMTB-Monitored Tank Building NCV-Non-Cited ViolationNDE-Non-Destructive ExaminationNEI-Nuclear Energy InstituteNRC-Nuclear Regulatory CommissionNS-Containment Spray SystemNSD-Nuclear System DirectiveNUREG-Nuclear RegulationsNV-Chemical and Volume ControlOTDT-Over Temperature Delta TemperaturePI-Performance IndicatorPIP-Problem Investigation Process reportPT-Penetrant TestPWSCC-Pure Water Stress Corrosion CrackingRCCA-Rod Cluster Control AssemblyRCS-Reactor Coolant SystemRN-Nuclear Service WaterRPVH-Reactor Pressure Vessel HeadRTP-Rated Thermal PowerSBO-Station BlackoutSCDHEC-South Carolina Department of Health and Environmental Control SG-Steam GeneratorSR-Surveillance RequirementSSC-System, Structure and ComponentSSPS-Solid State Protection System TS-Technical SpecificationTSAIL-Technical Specification Action Item LogUFSAR-Updated Final Safety Analysis ReportUT-Ultrasonic TestingWO-Work OrderYC-Controlled Area Chilled Water Attachment 2ATTACHMENT 2Catawba 2 GL 2004-02 Commitments Applicable to TI 2515/166GL 2004-02RequestActions implementedStatusGL 2004-02,2(b) Ageneraldescriptionof andimplementat ionschedule for allcorrectiveactionsincludingany plantmodifications that youidentifiedwhileresponding to thisgeneric letter.The corrective actions required by thisGeneric Letter will be completedon or before December 31, 2007as follows:1. A baseline evaluation has beenperformed for Catawba byEnercon Services, Inc. Thisevaluation was performed usingthe guidance of NEI 04-07. Theevaluation is currently underreview by Catawba and will becompleted by June, 30, 2006 byEnercon Services, Inc.2. A refined evaluation using theguidance of NEI 04-07 will becompleted for Catawba by June30, 2006. This evaluation willprovide plant-specific refinementsto the baseline evaluation that canbe justified for Catawba. Thisevaluation is expected to provideadditional head loss margin for thecontainment sump.3. A downstream effects evaluationwill be completed for Catawba byEnercon Services, Inc. Thisevaluation will be performed usingthe methodology provided byWCAP-16406-P, " Evaluation ofDownstream Sump Debris Effectsin Support of GSI 191." Anyadditional plant modifications orprocedure changes associatedwith this evaluation will becompleted by December 31, 2007.1. The baseline evaluation for CatawbaNuclear Station has been reviewedand accepted by Catawba. Thiscommitment is closed.2. This evaluation was covered inCatawba Calculation CNC-1223.11-00-0037. The original scope of therefined analysis has been reviewedand accepted by Catawba. Thiscommitment is closed.3. The Downstream effects evaluation forerosion and blockage of components(pumps, valves, and orifices) iscomplete and demonstrated inEnercon report DUK008-PR-01, Rev.0. Necessary plant modifications toaddress potential blockage of ECCSvalves have been identified and will becompleted by December 31, 2007. The documentation of theeffectiveness of the bypass eliminatorsregarding fuel blockage is complete. Minor Design Change CD101006 forUnit 1, and CD201007 for Unit 2, havebeen initiated per the associatedEngineering Change Request withinthe proposed corrective actionfollowing the normal modificationpractice. This is an engineeringrequest to install smaller ECCS floworifices in order to provide greaterclearance on the ECCS throttle valvesin order to comply with sump debrisdownstream effect evaluation. Unit 2was completed during 2EOC15, andUnit 1 was unsuccessful during itsprevious outage, but will complete themodification during 1 EOC 17. Therefore this commitment is onschedule to be completed by April

30, 2008.

2Attachment 24. Chemical effects will be evaluatedto confirm that sufficient marginexists in the final sump design toaccount for any associated headloss. The evaluation will becompleted by June 30, 2006. Anyadditional plant modifications orprocedure changes associatedwith this evaluation will becompleted by December 31, 2007.5. Confirmatory walkdowns ofcontainment using the guidance ofNEI 02-01, "ConditionAssessment Guidelines: DebrisSources Inside PWRContainments" (NEI 02-01) werecompleted for Catawba Unit 2 inthe fall of 2004 and for CatawbaUnit 1 in the Spring of 2005.6. A confirmation of the conservatismof the 200 pound latent debrisassumption used in the baselineanalysis will be performed bylatent debris surveys samplingduring the Catawba Unit 2 Springrefueling outage in 2006.7. The plant labeling process will beenhanced to require that anyadditional labels or signs placedinside containment are evaluatedto ensure that the design basis fortransportable debris is notinvalidated. This corrective actionwill be completed by December 31, 2007.4. The replacement strainers are beingdesigned with additional margin in aneffort to accommodate increased headloss due to chemical effects. Testingand analysis to address chemicaleffects are not complete. Testing forchemical effects started on June 2,2006. Upon completion of testing , theresults will be evaluated and furtheractions will be determined. Downstream chemical effects are stillunder investigation by the industry withthe intent of addressing this issue byDecember 31, 2007. An IntegratedPrototype Test (IPT) started October23, 2007 in Huntsville, Alabama, andthe testing is being conducted by WyleLabs. This is a new commitmentdate, and is on schedule to beclosed April 30, 2008. 5. The walkdowns of containment usingthe guidance of NEI 02-01 werecompleted in the fall of 2004 for Unit 2and the Spring of 2005 for Unit 1. This is a new commitment date, andis on schedule to be closed April 30, 2008.6. Latent debris sampling completed byEnercon Services, Inc. During theCatawba Unit 2 Spring 2006 refuelingoutage confirmed in the conservatismof the 200 pound latent debrisassumption. This commitment isclosed.7. In lieu of a containment cleanoutprocedure, model work orders havebeen created for each unit to showcontainment cleanout as a regularlyscheduled activity in the overall outageschedule. Model work Order98775894 has been created for UnitOne activity, and Model Work Order98775902 has been created for Unit 2activity. Nuclear Site Directive (NSD)503, Rev. 6, revised the stationdirective to include requirements to 3Attachment 28. Testing will be performed toconfirm that the replacementstrainer head loss is acceptableunder design basis debris loadedconditions. This testing will beconducted prior to installation ofthe replacement strainers.9. A modified containment sumpstrainer and supporting structurewill be installed during 1EOC17for Catawba Unit 1 and during2EOC15 for Catawba Unit 2.10. Replacement of the Microtherminsulation (currently installed onportions of the Reactor VesselHeads) will be completed in theFall of 2006 for Catawba Unit 1and in the Fall of 2007 forCatawba Unit 2. The replacementof this insulation will reduce thepostulated accident debris loadingon the sump strainer.11. Duke will evaluate the modificationprocess to determine if additionalcontrols are needed in order tomaintain the validity of inputs toanalyses performed in resolvingGSI-191 concerns. Thisevaluation will be completed byJune 30, 2006.8. Head loss testing has been completedby Enercon Services, Inc. Test reportshave been issued by Enercon andafter review of these tebris testingreports, they have been foundacceptably by Catawba. Thiscommitment is closed.9. CD200490 is the modification packagefor the ECCS Unit 2 ContainmentRecirculation Sump Strainer, which willbe completed at the conclusion of2EOC15. The installation of thecontainment sumps is on track tobe completed as committed.10. Equivalent Change CE201028 wasinitiated to replace the Unit 2 R.V.Head Microtherm insulation with mirrorinsulation (with CE100933 initiate forUnit 1 R. V. Head Microthermreplacement). CE201028 wasimplemented by the work order task(01112604 01) associated with thisDesign Change to replace the Unit 2R.V. Head Microtherm insulation withmirror insulation. This commitmentis closed.11. The subject evaluation has beencompeted and documented in theDuke corrective action program. Additional controls were deemedprudent. Revision 4, EngineeringDirective Manual (EDM), Appendix K5has been enacted on October 31,2007 to capture the suggestions fromthis evaluation. This commitment isclosed.

4Attachment 2GL 2004-02,2(f)A description ofthe existingor plannedprogrammatic controlsthat willensure that potentialsources ofdebrisintroduced intocontainment (e.g.,insulations,signs,coatings,and foreignmaterials)will beassessedfor potentialadverseeffects on ECCS and CSSrecirculationfunctions.Catawba has several programmaticcontrols in place to ensure thatpotential sources of debrisintroduced into containment willbe assessed for adverse effectson ECCS and Containment SpraySystem recirculation functions. These programmatic controlsinclude requirements related tocoatings, containmenthousekeeping, material conditionand modifications. Someprogrammatic controls aredescribed in more detail below.Catawba Operations:1. Perform the following inspections toensure that containment drainagepaths are unblocked: PT/0/A/4200/002(Containment cleanliness Inspection)2. PT/1/A/4600/016 (SurveillanceRequirements for Unit Startup). Thistest includes an inspection of therefueling cavity drains. Each drain isverified visually by line of sight wherepossible.3. PT/1(2)/A/4600/003B (QuarterlySurveillance Items). Quarterly visualinspection of refueling canal andUpper Containment compartment toverify there is no debris that couldobstruct the refueling canal drains.Catawba Maintenance:1. Verify the operability and freedom fromdebris of ice condenser drains.2. SM/0/A/8150/004 (Inspection of IceConsenser Floor Drains) andProcedure PT/1(2)/A/4400/018 hasbeen developed to support theinspectio nof containment civil featuresincluding crane wall penetrationsdedicated as sump recirculation flowpaths, containment sump integrity forboth screens and structure, and IncoreInstrument Enclosure door and hatchfor closure.

5Attachment 2Coatings ProgramAs described in Duke's November 11,1998 response to GL 98-04,"Potential for Degradation ofECCS and CSS after LOCAbecause of Construction andProtective Coating Deficienciesand Foreign Materials InsideContainment," Duke hasestablished controls for theprocurement, application, andmaintenance of Service Level 1protective coatings used insidecontainment. The requirements of10 CFR 50 Appendix B areimplemented through thespecification of appropriatetechnical and quality requirementsfor the Service Level 1 coatingprogram. For Service Level 1coatings, Duke is committed tocomply with Reg Guide 1.54 atCatawba. Per the GL 98-04response, vendor suppliedmechanical equipment (valves,pumps, hoists, tanks, etc.) thatwas procured prior to the issuanceof Reg Guide 1.54 (or that areimpractical to purchase withqualified coatings) all havecoatings that cannot be certified tocomply with the standards, andare thus defined as unqualified.Coatings ProgramThe comprehensive Duke Energycorporation Containment CoatingsAssessment Program in effect atCatawba Nuclear Station is used toidentify degraded qualified/acceptablecoatings and determine the amount ofdebris that will result from thesecoatings. This program also ensuresthat qualifies/ acceptable coatingsremain in compliance with plantlicensing requirements for design-basis accident (DBA) performance.A primary containment coatings conditionassessment is conducted during eachrefueling outage or any other extendedoutage. Visual inspections areconducted and documented by ANSIN45.2.6 Level II personnel and/orpersonnel who have demonstratedoverall technical knowledge ofcoatings. The resultant data isreviewed by the site Coating Specialistand is used to facilitate properplanning and prioritization of coatingsmaintenance as needed to maintainthe integrity of qualified/acceptableprimary containment coating systems.The primary containment coating conditionassessment protocol consists of a100% visual inspection of allaccessible coated areas by qualifiedpersonnel. The use of visualinspection by qualified personnel forcontainment coating assessment hasbeen validated by the recently-issuedEPRI Report 1014883 'Plant SupportEngineering: Adhesion Testing ofNuclear Coating Service Level 1Coatings."

6Attachment 2Containment Housekeeping/Material ConditionDuke's August 7, 2003 response toBulleting 2003-01, " PotentialImpact of Debris Blockage onEmergency Sump Recirculation atPWRs," described plannedactions regarding containmentcleanliness. These actions havebeen implemented and involvecontainment cleaning and visualinspections. Extensivecontainment cleaning is performedduring refueling outages usingwater spray, vacuuming, and handwiping. In general, this is limitedto the space in lower containmentthat would be submerged underlarge break LOCA conditions. Additionally, localized washdownsare performed as needed. Visualinspections are performed on theremaining areas of containment. Foreign material is removed asnecessary. Material accountabilitylogs are maintained in Modes 1through 4 for items carried intoand out of containment. Thesecontrols are implemented usingadministrative procedures.Containment Housekeeping/Material ConditionSite Directive 3.1.2 was revised to adddetail to material accountability logs,which must be kept for items carriedinto and out of containment in Modes 1through 4.In lieu of a containment cleanoutprocedure, model work orders havebeen created for each unit to showcontainment cleanout as a regularlyscheduled activity in the overall outageschedule. Model Work Order98775894 has been created for UnitOne activity, and Model Work Order98775902 has been created for Unit 2activity.

7Attachment 2Modification ProcessDuke's modification process currentlyincludes an administrativeprocedure that directs the designand implementation ofengineering changes to the plant. This procedure directs thatengineering changes be evaluatedfor system interactions. As part ofthis evaluation, there is directionto include consideration of anypotential adverse effect withregard to debris sources and/ordebris transport paths associatedwith the containment sump. Whilethese existing controls provideassurance that modifications tothe plant will be assessed forpotential adverse effects on thecontainment sump, Duke plans toprovide further evaluation todetermine if additional controls areneeded. Duke will identify anyadditional controls that may beneeded in order to maintain thevalidity of inputs to analysesperformed in resolving GSI-191concerns.Plant Labeling ProcessThe plant labeling process will beenhance to ensure that anyadditional labels or signs placedinside containment are evaluatedto ensure that the design basis fortransportable debris is notinvalidated. This corrective actionwill be completed by December 31, 2007.Modifications ProcessRevision 4, Engineering Directive Manual(EDM), Appendix K5 has beenenacted October 31, 2007.Plant Labeling ProcessIn response to the direction that "the plantlabeling process will be enhanced torequire that any additional labels orsigns placed in containment areevaluated to ensure that the designbasis for transportable debris is notinvalidated", the following changeswere made.NSD 503, STATION LABEL AND SIGNSTANDARDS, Rev. 6, issued 09/18/06incorporated changes in the Purpose(503.1) for the Label/Sign program tobe designed to provide guidance to"Prevent Labels/Signs insidecontainment from being transported tothe ECCS Containment Sumpsuction." In section 503.5.2 approvedlabel/sign materials for insidecontainment are specified as StainlessSteel and Porcelain covered StainlessSteel which meet the transportabledebris criteria. These changes havebeen adopted by all three DukeEnergy nuclear sites.