IR 05000413/2006010

IR 05000413-06-010, 05000414-06-010, on 11/27/2006-12/1/2006 for Catawba, Units 1 and 2, Special Inspection

ML070090208
Person / Time
Site:	Catawba
Issue date:	01/05/2007
From:	Casto C Division Reactor Projects II
To:	Morris J Duke Energy Carolinas, Duke Power Co
References
IR-06-010
Download: ML070090208 (41)

Text

January 5, 2007Duke 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 - SPECIAL INSPECTON REPORT05000413/2006010 AND 05000414/2006010

Dear Mr. Morris:

On December 6, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed a SpecialInspection at your Catawba Nuclear Station Units 1 and 2. The enclosed inspection reportdocuments the inspection results, which were discussed at the exit meeting on December 6,2006, with you and other members of your staff. The determination that the Special Inspection would be conducted was made by the NRC onNovember 22, 2006. This determination was based on the risk and deterministic criteriaspecified in Management Directive 8.3, "NRC Incident Investigation Program." The SpecialInspection Team (SIT) was dispatched to the site on November 27, 2006 and conducted inaccordance with Inspection Procedure 93812, "Special Inspection." The purpose of thisinspection was to inspect and assess your corrective actions for degraded seals on safetyrelated and risk-important below grade electrical penetrations. The inspection focus areasare detailed in the Special Inspection Team Charter (Attachment 5). 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 yourlicense. The inspectors reviewed selected procedures and records, observed activities, andinterviewed personnel.The report documents two NRC-identified findings of very low safety significance (Green).One of these findings was determined to involve a violation of NRC requirements. However,because of the very low safety significance and because it is entered into your correctiveaction program, the NRC is treating this finding as a non-cited violation (NCV) consistent withSection VI.A.1 of the NRC Enforcement Policy. If you contest the NCV in this report, youshould provide a written response within 30 days of the date of this inspection report, with thebasis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk,Washington, DC, 20555-0001; with copies to the Regional Admini strator Region II; theDirector, Office of Enforcement, 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 DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system(ADAMS). ADAMS is accessible from the NRC Web site at www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA By Harold Christensen For/

Charles A. Casto, DirectorDivision of Reactor ProjectsDocket Nos.: 50-413, 50-414License Nos.: NPF-35, NPF-52

Enclosure:

Special Inspection Report 05000413/2006010 and 05000414/2006010w/Attachments: 1.Key Points of Contact 2.List of Items Opened, Closed and Discussed 3.List of Documents Reviewed 4.List of Acronyms 5.Special Inspection Team Charter 6.Simplified Catawba Site Layout Drawing 7.Potential impact of flooding on the transformers or terminalcabinets within the turbine building basement floodwallenclosures 8.Potential impact of flooding in the Standby ShutdownFacility (SSF) on equipment within the structure 9.Turbine Building Floodwall Enclosure drawings 10.Standby Shutdown Facility floor plan drawings

REGION IIDocket Nos.: 50-413, 50-414License Nos.: NPF-35, NPF-52Report Nos.: 05000413/2006010 and 05000414/2006010Licensee: Duke Energy CorporationFacility: Catawba Nuclear Station, Units 1 and 2Location: 4800 Concord RoadYork, SC 29745Dates: November 27 - December 6, 2006Team Leader: Ryan Taylor, Reactor InspectorEngineering Branch 1Division of Reactor SafetyInspectors: A. Sabisch, Senior Resident Inspector, CatawbaS. Sanchez, Resident Inspector, St. LucieApproved by: Charles A. Casto, DirectorDivision of Reactor Projects

SUMMARY OF FINDINGS

IR 05000413/2006010, 05000414/2006010; 11/27/06-12/1/06; Catawba Nuclear Station, Units 1and 2; Special Inspection.This inspection was conducted by a team consisting of inspectors from the NRC's Region IIoffice and resident inspectors from the Catawba and St. Lucie Nuclear Stations. The NRC'sprogram for overseeing the safe operation of commercial nuclear power reactors is described inNUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000. A Special InspectionTeam was established in accordance with NRC Management Directive 8.3, "NRC IncidentInvestigation Program" and implemented using Inspection Procedure 93812, "Special InspectionTeam." A.

Cornerstone: Mitigating Systems

Green: A Non-Cited Violation (NCV) of Technical Specification (TS) 5.4.1.b wasidentified for failing to es tablish procedures required by Regulatory Gu ide 1.33,Appendix A, Section 6, Procedures for Combating Emergencies and Other SignificantEvents. Specifically, no procedure existed to combat or mitigate the consequences froman external flooding event.The finding is greater than minor because the failure to establish appropriate proceduresto cope with an external flood affects the Mitigating Systems cornerstone objective ofensuring the availability, reliability, and capability of sy stems that res pond to initiatingevents to prevent undesirable consequences. Using Manual Chapter 0609, Appendix A,Attachment 1, "Significance Determination Process," Phase 1 Worksheet, the finding isdetermined to have very low safety significance because it only affected the mitigatingsystems cornerstone and did not result in the total loss of any safety function thatcontributes to external event initiated core damage accident sequences. (4OA5.4)Green: An NRC-identified finding was identified for the licensee's failure to conductadequate extent of condition reviews following multiple water intrusion events at the siteby limiting the focus of the reviews to only safety-related structures, systems, andcomponents (SSC's) and excluding those identified as being risk significant. The finding is greater than minor as it was associated with the Protection AgainstExternal Factors and Equipment Performance attributes of the Mitigating Systemscornerstone in that by narrowly focusing extent of condition reviews to only encompasssafety-related SSC's and excluding risk-significant SSC's, systems required to respondto and mitigate initiating events could be adversely affected. It was determined to be ofvery low safety significance because, while limiting extent of condition reviews to safety-related SSC's has the potential to adversely affect the ability of the station to respond toinitiating events, failing to include risk significant equipment in the reviews conducted forthe water intrusion events in 2006 after the 1A DG conduit seals were repaired did notresult in an overall increase in plant risk in excess of the green/white threshold. Thevulnerabilities of other risk-significant SSC's to flooding have been addressed by thestation. (4OA5.7)2B. Licensee Identified Findings None.An NRC Special Inspection Team was dispatched to the site on November 27, 2006 to reviewthe water intrusion events that have occurred at Catawba in 2006. The team found that thelicensee's response to the water-intrusion events was limited in the scope of the extent ofcondition reviews that had been performed following each event. As a result, the licenseemissed several opportunities to identify and address deficiencies prior to subsequent waterintrusion events. The team identified one issue that has been dispositioned as a non-citedviolation, one issue that has been dispositioned as a finding and one unresolved item that is stillunder review by Region II personnel.

REPORT DETAILS

Summary of Plant EventsOn May 22, 2006, water overflowing from the Unit 2 cooling towers as a result of cloggedscreens entered the 1A diesel generator (DG) room through unsealed electrical conduitsresulting in the 1A DG being declared inoperable. Following repairs of the conduit seals,inspection of DG support equipment and functional testing, the 1A DG was returned to operablestatus on May 24, 2006. The licensee reviewed additional below-grade electrical conduits in the diesel generator and auxiliary buildings through an extent of condition review conducted prior torestarting both units. Due to this flooding event and an unrelated dual unit loss of offsite power(LOOP), the NRC dispatched an Augmented Inspection Team (AIT) to the site on May 23, 2006. The inspection results are documented in Inspection Report 05000413, 414/2006009.In mid-2006, due to extensive construction projects on-site, Engineering recalculated maximumstanding water level in the power house yard that would result from the Predicted MaximumPrecipitation event defined in the licensing basis for Catawba. Following this reanalysis, thestation assessed the impact that the higher water level would have on safety-related structures,systems and components (SSC's) through a corrective action program document. Other nonsafety-related risk-significant SSC's were not included in this review.On August 30, 2006, following a period of severe rain activity on the site, flooding occurred atseveral locations in the Unit 1 and Unit 2 turbine buildings, including within floodwalls that hadbeen recently constructed to protect station 6.9kV transformers and associated terminalcabinets from damage due to a flood from piping internal to the turbine building. Promptoperator action of opening drain lines installed in the floodwalls prevented the loss of anyequipment within the enclosures. The flooding had been caused by plugged drain lines intransformer yard cable pits and unsealed electrical conduit penetrations that entered the turbinebuilding from these pits and other external locations.During the week of October 30, 2006, an NRC flooding inspection was conducted by a regionalinspector and the Catawba resident inspector. During this inspection, it was identified that thebelow-grade penetrations that entered the Standby Shutdown Facility (SSF) were not sealedproperly and water had the potential to enter the structure through these degraded seals andbeneath the doors resulting in a potential loss of the SSF. Inspection Scope Based on the probabilistic risk and determi nistic criteria specified in Management Directive 8.3,"NRC Incident Investigation Program," Inspection Procedure 71153, "Event Follow-up," and thesignificance of the operational events which occurred, a Special Inspection was initiated inaccordance with Inspection Procedure 93812, "Special Inspection Team." The inspection focusareas included the following charter items:*Develop a sequence of events related to the conditions.

• Conduct an extent of condition review of the SSF flooding vulnerability. Asappropriate, provide any new information that is identified that would affect therisk analysis, to the Region II, Senior Reactor Analyst.

4*Identify corrective actions taken by the licensee in response to the SSF floodingvulnerability and eval uate their timeliness and effectiveness. *Evaluate Catawba's preparedness to cope with a Predicted MaximumPrecipitation (PMP) event. Specifically, determine if plant procedures provideadequate guidance to cope with the event and operator training is adequate tosupport the level of detail provided by the plant procedures for the event.*Determine and assess the licensee's previous corrective actions and lessonslearned associated with the flooding from unsealed below-grade electrical and/ormechanical penetrations.*Determine if other site structures were adversely affected and have becomesusceptible to flooding as a result of the change in PMP level.*Evaluate the licensee's decision making process associated with their extent ofcondition review conducted for the 1A diesel generator room and turbine buildingflooding events; including their understanding of the risk associated with theconditions.*Brief the Regional Administrator and Regional management daily.

• Document the inspection findings and conclusions in an inspection report within30 days of the inspection.4.

4OA5 Special Inspection

.1 Develop a sequence of events related to the conditions.

a. Inspection Scope

For the purposes of this Special Inspection, the team identified the major water intrusionevents that have occurred at Catawba in 2006 and documented the specific events andthe corrective actions that were developed following the events in chronological order. In order to develop this sequence of events, the inspection team reviewed correctiveaction documents, unified control room logs, and an event chronology developed bylicensee personnel prior to the inspection team arriving on-site. The inspection teamalso interviewed several licensee staff members in the Engineering and Operationsdepartments in order to validate and further establish the sequence of eventsdocumented in this report.

b. Findings and Observations

Background InformationThe Catawba Nuclear Station is located on a site situated on a peninsula boundeddirectly by Lake Wylie on two sides. The power house yard general ground elevation is 5approximately 594 feet above mean sea level (MSL). The electrical switchyard islocated on a hill to the west of the power house and is at 632 feet MSL. The coolingtowers for the station are lo cated on a hill to the east and are at 620 feet MSL. The plantitself was constructed with much of the actual facility located below the grade of thepower house yard. The lowest elevation in the plant is at 522 feet MSL or approximately72 feet below grade. The site layout and below-grade construction of Catawba results inflooding being the major contributor to the core damage frequency calculationsdeveloped in the Catawba Probab ilistic Risk Assessment model. Site construction and engineering drawings provide details on how below-gradepenetrations are to be constructed to prevent water intrusion into plant structures. Drawing CN-1938-01; Catawba Nuclear Station Electrical Equipment Layout, OutdoorArea General Plan, contains a note which states "All conduits shall be sealed at theentrances to buildings; i.e., diesel, auxiliary, nuclear service water, turbine, etc., toprevent water drainage from entering the buildings."The SIT member inspection activities were formulated based on the importance of floodmitigation and protection at Catawba and several water intrusion-related events thatoccurred at the site in 2006. A summary of the 2006 events is provided below:May 22, 2006During recovery actions following a dual-unit loss-of-offsite power (LOOP) that occurredon May 20, 2006, water was reported entering the Unit 1 "A" DG room. Operatorsresponding to the notification determined that the source was external to the room andworked to identify the source of the flooding and remove the water to minimize anyimpact on the DG. The water was found to have been a result of overflow from the Unit2 cooling towers which traveled through unsealed conduit trenches and entered the DGroom though below-grade penetrations in the outer wall containing safety-relatedcabling. Prior to returning the units to service, the licensee inspected other below-grade electrical conduits entering the Auxiliary and Diesel Gener ator buildings. Numerouselectrical conduit seals were found to have degraded seals which required repair inorder to restore their functionality. The NRC identified that the licensee had notestablished a preventative maintenance program to periodically inspect below-gradehydrostatic seals which had a finite lifetime. The issues of the missing seals on the conduits entering the 1A DG room and thedegraded seals on other conduits were dispositioned in NRC Inspection Reports05000413,414/2006-03 and 05000413,414/2006-04.

June 2006The licensee identified the need to reassess the depth of water in the power house yardfollowing a PMP event as a result of site topography changes that had occurred overrecent years. These changes were due to major projects such as the raw water pipingupgrade, the Independent Spent Fuel Storage (ISFSI) haul road, and relocation of thesecurity fence. The calculation determined that an increase in PMP level would beobserved and a Problem Investigation Process (PIP) document was initiated todetermine the impact this increased water level would have on plant equipment. The 6areas identified within the scope of this review were limited to those containingsafety-related SSC's. This condition was entered into the licensee's corrective actionprogram and was closed out once the review of safety-related SSC's had beencompleted.August 30, 2006A heavy rain occurred which resulted in the site receiving almost 4 inches of rain in lessthan 45 minutes. This rainfall overwhelmed the yard drain system in several locationsaround the plant and allowed water to enter four

(4) cable pits in the Unit 1 and Unit 2transformer yards. Unsealed penetrations in these pits, as well as other below-gradelocations around the turbine building foundation, allowed water to enter the turbinebuilding basement, which is 26 feet below the power house yard. Some water enteredthe recently-constructed flood wall enclosures surrounding the 6.9kV transformers andassociated terminal cabinets. These transformers provide normal and alternate power tothe 4.16kV vital busses. The flood walls had been constructed to reduce the overall riskexposure from an internal pipe break in the turbine building, which could cause loss ofthe 6.9kV transformers. However, the potential influent of water inside of the flood wallsfrom electrical penetrations had not been adequately assessed during the design andconstruction phase as evidenced by the water entering the enclosures through unsealedelectrical penetrations. This condition was entered into the licensee's corrective actionprogram and is being tracked for resolution.November 4, 2006An inspection of flood vulnerability was conducted the week of October 30, 2006 as apart of the baseline inspection program. During this inspection, the inspectors identifiedthat the Standby Shutdown Facility (SSF) had not been included in extent of conditionreviews performed after the previous flooding events in 2006. The inspectors identifiedthat the seals for the below-grade electrical penetrations entering the SSF weredegraded and had allowed some water to enter the cable trench inside the building. Inaddition, the doorways entering the building had ~0.5 inch gaps beneath them whichwould have allowed water to enter the structure in the event of a PMP event based onthe floor of the SSF being 9 inches below the predicted maximum water level in thepower house yard. This condition was entered into the licensee's corrective actionprogram and is being tracked for resolution.December 1, 2006Inspectors on the SIT conducted a walkdown of the site within the protected area andidentified several storm water catch basins that were entirely or partially obstructed withgravel, silt fencing or other debris blocking water from entering the drainage system. The site has 88 committed catch basins, of which 80 are required to fully operable in order to ensure the storm drain system can fulfill its design function and maintainstanding water in the power house yard at levels accounted for in the plant floodinganalysis. A subsequent walkdown and analysis by licensee personnel determined thattwo catch basins were 100% non-functional and three additional catch basins were 50%non-functional. The apparent cause for these conditions developing at the site and notbeing identified was a breakdown in the implementation of a station procedure that had 7been developed to address a similar condition in 2001. This condition was entered intothe licensee' s corrective action program and is being tracked for resolution.

.2 Conduct an extent of condition review of the SSF flooding vulnerability.

As appropriate,provide any new information that is identified that would affect the risk analysis, to theRegion II, Senior Reactor Analyst.

a. Inspection Scope

The inspectors reviewed licensee calculations that had been used in the PRA-basedjustification to construct the floodwall enclosures in the turbine building basement aroundthe 6.9kV transformers and their associated terminal cabinets. The enclosures were designed to reduce the overall station core damage probability identified in the PRAmodel resulting from flooding events damaging these components. The flood walls wereconstructed on April 6, 2005 (Unit 1) and March 31, 2005 (Unit 2). Prior to theconstruction of the floodwalls, flooding had been determined to be a 25% contributor tocore damage at Catawba.In addition to reviewing the effect a turbine building basement flooding event could haveon the station, the inspectors also reviewed several sections of the Updated Final SafetyAnalysis Report (UFSAR) and Design Basis Document (DBD) to confirm theassumptions made in the aforementioned calculations as well as identify what otherequipment could be affected by a flooding event in additional site buildings such as theStandby Shutdown Facility (SSF).A tabulation of equipment that would be affected by flooding of the individual turbinebuilding floodwall enclosures and the SSF was developed by the inspectors andprovided to the Region II Senior Reactor Analyst (SRA). (See Attachment 7 and 8 for thelist of affected equipment)Discussions are continuing between the licensee's PRA group in the corporate officeand the Region II SRA's to validate assumptions made in the risk models maintained byboth organizations regarding equipment that could have been affected by a floodingevent based on the as-found condition of below grade penetrations at Catawba prior toand subsequent to the 1A DG room flooding on May 22, 2006. The likelihood of theevents needed to produce water levels used in the PRA models was also discussed.

b. Findings and Observations

Following the flooding of the 1A DG room that occurred on May 22, 2006, the licensee'sPRA staff worked with the Region II SRA's to determine the risk significance thatresulted from this event. The flooding event was documented as Unresolved Item (URI)05000413/2006009-03 in the AIT report issued on June 29, 2006. The URI was openedto review the root and contributing causes, the extent of condition, and the correctiveactions associated with the failure to seal conduits into manholes and the 1A DG roomas required by design and construction documents. The issue was dispositioned as aGreen NCV in Inspection Report 05000413,414/2006-04. It was determined to be ofvery low safety significance (Green) based on the results of the SignificanceDetermination Process Phase 1 screening, the Phase 2 evaluation using the Catawba 8Plant Notebook, and the Phase 3 evaluation. The team identified Unresolved Item05000413,414/2006010-01 to re-quantify the station risk resulting from the cumulativeeffect of the missing conduit seals, degraded conduit seals and water ingress paths thathave been identified as being present over the time period of April 6, 2005 and May 22, 2006.

.3 Identify corrective actions taken by the licensee in response to the SSF floodingvulnerability and eval

uate their timeliness and effectiveness

.

a. Inspection Scope

The inspectors reviewed the permanent and interim corrective actions taken to addresspotential water ingress into the SSF. The inspectors also conducted a walk-down of theSSF to asses the effectiveness of the licensee's actions and reviewed design documents to determine what flooding vulnerabilities existed in relation to the SSF.b.Findings and ObservationsOnce the issue of potential SSF flooding was identified during the November 2006flooding inspection, actions were taken to inspect and refurbish the seals associatedwith the below-grade cable trench penetrations that entered the SSF. The licensee performed a flood routing study to identify paths for water to enter the SSFbased on a PMP event. In addition to the path through the below-grade electricalconduits identified by the NRC, additional entry points including the SSF door thresholdsand the diesel air intake plenum were identified. The study demonstrated that the waterlevel would rise high enough to adversely affect components in the SSF diesel controlpanel as well as compartments in the SSF diesel generator output load center followinga PMP event. As a result, the licensee took immediate compensatory actions to stagesandbags at both SSF exterior doors to limit water intrusion in the event of a severerainfall. The licensee intends to use the flood routing study information as inputs into arisk evaluation to determine SSF vulnerability to severe rainfall events ranging from a fullPMP event to lesser rainfalls typically experienced at the site.

.4 Evaluate Catawba's preparedness to cope with a PMP event.

Specifically, determine ifplant procedures provide adequate guidance to cope with the event and operatortraining is adequate to support the level of detail provided by the plant procedures for theevent.

a. Inspection Scope

Inspectors reviewed plant procedures intended to address flooding conditions on-site. These included Abnormal Operating Procedures (AP), Response Procedures (RP) andOperator Aid Computer response procedures. In addition, inspectors conductedinterviews with Operations, Engineering, and Emergency Planning personnel with afocus on what guidance and training was available to respond to the flooding of plantSSC's, particularly from external sources.

9b.Findings and ObservationsThere is only one abnormal procedure which deals with plant flooding, AP/0/A/5500/030,Plant Flooding. The stated purpose of this procedure is "To provide guidance to mitigate the effects of internal flooding in the Auxiliary , Diesel, Turbine or Service Buildings thatthreatens essential plant equipment from leakage from systems including RC, RF, RY,RN, RL or CS." This procedure, and the corresponding training provided to Operationspersonnel, focuses all actions on combating leakage from systems internal to theaforementioned structures.Procedure RP/0/A/S000/007; Natural Disaster and Earthquake, contains an enclosure tobe used when lake levels exceed 593.5 feet or a sudden lake tidal wave is spotted. Enclosure 4.5, Flooding Due to High Lake Level or Lake Tidal Wave, is administrative innature and, with the exception of ensuring the Auxiliary Buildi ng roll-up doors are closed,provides no specific guidance to address flooding from sources external to the affectedbuilding. The majority of this enclosure addresses offsite notifications that would berequired, direction to shutdown the units and the need to assess the extent of damagecaused by the flooding once the immediate concern is over.Interviews with Operations personnel, particularly those that had been involved inresponding to the May 22, 2006 1A DG room flooding event, confirmed that proceduralguidance and training was focused solely on addressing flooding of SSC's from systems internal to the build ings. Operators used their experience and familiarity with the plantdesign in responding to the May 22 event once it was determined that the water wascoming from an external source and that AP/0/A/5500/030 would not provide anyassistance in mitigating the flooding.Introduction: The inspectors identified a Green Non-Cited Violation (NCV) of TechnicalSpecification (TS) 5.4.1.b, for failure to adequately establish procedures required byRegulatory Guide 1.33, Appendix A, Section 6, Procedures for Combating Emergenciesand Other Significant Events. Specifically, no procedure existed to combat or mitigatethe consequences from an external flooding event.Description: On May 22, 2006, the control room was notified of water flooding into the1A DG room. Operators were dispatched and identified that the flooding was coming inthrough below-grade electrical conduits on the south wall. The source of the water wasdetermined to be overflow from the Unit 2 cooling towers, through the cooling towercable trench, into two safety-related manholes, and finally into the 1A DG room. Oncethe cooling towers had been secured, the in-leakage stopped. The water flowed overthe starting air compressors, the DG battery enclosure and load sequencer cabinets,and collected in the DG room sump. The rate of flooding exceeded the capacity of theinstalled DG sump pumps. Additional sump pumps had to be brought in to keep thewater from reaching the lube oil sump tank and the generator. The 1A DG was declaredinoperable and the applicable TSs were entered.The inspectors reviewed several licensee procedures that were related to plant flooding. Procedure AP/0/A/5500/030, Plant Flooding, provides guidance to the operators tomitigate the effects of internal flooding in the Auxiliary, Diesel, Turbine, and/or ServiceBuildings. Procedure RP/0/B/5000/030, Severe Weather Preparations, is implemented 10by Emergency Planning and provides direction when either high winds or iceaccumulation is expected to occur. Procedure RP/0/A/5000/007, Natural Disaster andEarthquake, provides direction when high lake level results in flooding, however thisdirection is more general in nature than what would be necessary for operators tocombat or mitigate the consequences of a flood. In addition, neither internal flooding orhigh lake level are considered UFSAR described Predicted Maximum Precipitationevents.After discussions with NRC personnel who responded to the site during the event andlicensed operators who were on-shift during the event, the inspectors determined that noprocedure was utilized or available to the operators to cope with the external flood event.

Instead, the operators had to rely on skill-of-the-craft abilities and fortuitously availablesump pumps to aide in combating the effects of water intrusion into the 1A DG room.Analysis: The inspectors determined that the licensee's failure to establish a procedureto combat or mitigate an external flooding event was a performance deficiency. Theinspectors concluded that the finding was greater than minor in accordance with IMC0612, "Power Reactor Inspection Reports," Appendix B, "Issue Disposition Screening." The failure to establish appropriate procedures to cope with an external flood affects theMitigating Systems cornerstone objective of ensuring the availability, reliability, andcapability of systems that respond to initiating ev ents to prev ent undesirableconsequences. The finding involved the attribute of protection against external factors(i.e., flood hazard). Using Manual Chapter 0609, Appendix A, Attachment 1,"Significance Determination Process," Phase 1 Worksheet, the finding is determined tohave very low safety significance because it only affected the mitigating systemscornerstone and did not result in the total loss of any safety function that contributes toexternal event initiated core damage accident sequences.Enforcement: TS 5.4.1.b requires that written procedures as described in RG 1.33,Revision 2, Appendix A, be established, implemented, and maintained. Reg Guide 1.33,Appendix A, Section 6, Procedures for Combating Emergencies and Other SignificantEvents, Subsection W, requires that procedures be developed to combat emergenciesand other significant events, such as acts of nature (e.g., flood). Contrary to the above,on November 30, 2006, the inspectors determined that the licensee had not establisheda procedure to combat or mitigate the consequences from an external flooding event. Because this violation was determined to be of very low safety significance and wasplaced in the corrective action program as PIP C-06-08287, this violation is being treatedas a NCV in accordance with Section VI.A.1 of the Enforcement Policy, and is identifiedas NCV 05000413,414/2006010-02, Failure to Establish a Procedure for Mitigating theConsequences of an External Flooding Event.

.5 Determine and assess the licensee's previous corrective actions and lessons learnedassociated with the flooding from unsealed below-grade electrical and/or mechanicalpenetrations

.a.Inspection ScopeThe inspectors reviewed the permanent and interim corrective actions taken by thelicensee in response to flooding from unsealed below-grade electrical penetrations and 11mechanical penetrations. Inspectors also reviewed the corporate level specification forpenetration seals, the site specific specification with detailed vendor information forpenetration seals, and the seal installation procedure.

b. Findings and Observations

Following each of the water intrusion events in 2006 the licensee implementedcorrective actions which involved inspection and repair of penetration seals and floodbarriers. The repair of penetration seals involved the application of new sealant over thedegraded seals. The vendor recommendations for penetration sealing gave instruction for preparationand application of new seals, however, it did not address preparation and application ofnew sealant over existing sealant material that might be degraded. The corporatedesign specification for sealant and the station's seal installation procedure included thevendor recommendations for sealant application, however, there was no discussion asto the application of new sealant over existing, degraded seals. The licensee initiatedPIP C-06-8341 to review the process used to reseal existing conduits and developguidance to ensure they are properly prepared prior to applying the sealant. Theindividual corrective actions implemented as a result of the 2006 water intrusion eventsare identified below.May 22, 2006Actions taken by the licensee in response to this event and completion dates are listedbelow:ACTION DESCRIPTIONCOMPLETIONDATEInspected/repaired conduits between conduit manholes(CMH) and all four DG Rooms5/24/06Inspected/repaired conduits / cable penetrations in theAuxiliary Building and Unit 1 & 2 4.16kV vital switchgear Rooms5/26/06Installed redundant seal between the cooling tower cabletrench and CMH 4 at the CMH interface7/31/06Reviewed design configuration of subterranean mechanicalpiping penetrations into the Auxiliary Building to validate waterintrusion not applicable8/3/06Inspected/repaired cooling tower, WC Pond, and Switchyardcable trench flood barriers and berms8/7/06Established a model WO to perform annual inspection ofcooling tower, WC Pond, and Switchyard cable trench floodbarriers and berms10/17/06Develop and implement a preventative maintenance programto periodically inspect penetration seals credited for floodmitigationIn ProgressInitiated assessment of cumulative effect of site topographychanges on flooding design basis & updated UFSAR In Progress 12August 30, 2006Actions taken by the licensee in response to this event and completion dates are listedbelow:ACTION DESCRIPTIONCOMPLETIONDATEInspected/repaired conduits between transformer yard conduitmanholes & Unit 1 / Unit 2 Turbine Building9/8/06Inspected/cleaned transformer yard conduit manhole drains9/906Inspected/repaired penetrations in all Unit 1 / Unit 2 TurbineBuilding and Service Building substructure walls11/26/06November 4, 2006Actions taken by the licensee in response to the additional flooding related inspectionand completion dates are listed below:ACTION DESCRIPTIONCOMPLETIONDATEInspected/repaired SSF cable trench penetrations11/8/06Performed flood routing study to determine maximum waterlevel in each SSF room during PMP11/23/06Implemented temporary procedure to install sand bags at SSFexterior doors in the event of severe rainfall11/25/06Perform PRA risk analysis of SSF vulnerability during rainfalleventsIn Progress

.6 Determine if other site structures were adversely affected and have become susceptibleto flooding as a result of the change in PMP level.

a. Inspection Scope

Inspectors conducted site walk downs and reviewed site layout drawings to determine additional structures or components had become vulnerable to flooding from externalsources as a result of the change in PMP level. The inspectors reviewed flood levelcalculations, flood protection requirements and procedures. This review was comparedto the results of the assessment conducted by the licensee.

b. Findings and Observations

The inspectors did not identify any additional plant structures that might be susceptibleto flooding that had not been evaluated by the licensee following the water intrusionevents between May and November, 2006.During the site walk down, the inspectors noted extensive construction in-progress tosupport the ISFSI haul road, the new security fence modification and other minor 13projects. Some of this activity was in close proximity to site yard drains and catchbasins. There were two types of catch basins at Catawba, a Type I and a Type IIdevice. There were 88 Type I catch basins on-site and these were included inCatawba's flood level calculations. In order for the calculation to remain valid, aminimum of 80 were required to be operable to ensure water drained away from theplant as expected. The inspectors noted several catch basins which had berms builtaround them, as well as dirt, debris or covers partially or totally blocking others. Thisprompted the inspectors to discuss the program used to control and maintain these floodmitigation features with the licensee.The licensee performed an independent walkdown of the area noted by the inspectorsand concurred that the programmatic controls that had been instituted following similaroccurrences in 2001 and documented in PIP C-01-4230 had not been followed. StationProcedure EWP 8.1, Pre-Project Planning, described how work was to be planned andexecuted in the vicinity of yard drains and catch basins to ensure they were not blocked. If blockage was required to keep debris or oil from entering it, Engineering was requiredto evaluate the impact this blockage would have on the site flooding analysis. Inaddition, Environmental, Health and Safety personnel were to notify Engineering whenany catch basin blockage was identified during the performance of their weeklywalkdown of construction areas. These guidelines had not been rigorously followed.The station's Civil Engineering group conducted a full inspection of the Type I catchbasins after the blockage issue was raised by the inspection team. This walkdownidentified six catch basins that were at least partially blocked. Calculations determinedthat the as-found condition resulted in a loss of 4.5 catch basins.The licensee initiated PIP C-06-8179 for this condition.

.7 Evaluate the licensee's decision making process associated with their extent of conditionreview conducted for the 1A diesel generator room and turbine building flooding events;including their understanding of the risk associated with the conditions

.

a. Inspection Scope

The inspectors reviewed the corrective action documents associated with the waterintrusion-related events that had occurred at Catawba in 2006 and are described inSection 4OA5.1 of this report to evaluate the extent of condition reviews that had beenconducted for each event. In addition to reviewing the associated PIP's, the inspectorsreviewed design specifications, construction drawings, risk models, and licensing documents pertaining to internal and external flooding vulnerabilitie s and prot ection. The inspectors also conducted interviews with Engineering, Operations and Licensingpersonnel to discuss the extent of condition assessments and corrective actionsdeveloped for the specific events.

b. Findings and Observations

Following each of the water intrusion-related events that occurred in 2006, the licenseeperformed an extent of condition review to identify appropriate corrective actions in orderto address the specific problem that occurred. The sole focus of these reviews was to 14ensure safety-related SSCs were either unaffected, or if the potential for adverselyimpacting these SSCs existed, that corrective actions needed to mitigate that impactwere identified an implemented. While the extent of condition reviews that the licenseeconducted were timely, their narrow focus on safety-related SSCs resulted in risk-significant SSCs remaining vulnerable to damage or loss in the event of a floodingevent.Introduction: The inspectors identified a Green Finding for the licensee's failure toconduct adequate extent of condition reviews following flooding events on May 22, 2006,and August 30, 2006.

Description:

On May 22, 2006, while returning Unit 2 to service following a dual-unitLOOP, water from the cooling towers overflowed due to flow channel blockage causedby a build-up of freshwater clams and heavy winds. Water entered the cable trenchleading towards the plant and entered an adjacent safety-related conduit manholebunker due to missing conduit seals in the below-grade penetrations. The water flowedfrom the manhole bunker through additional unsealed penetrations into the 1A dieselgenerator room resulting in the diesel generator being declared inoperable while repairswere conducted. Following the flooding event, the licensee inspected additional below-grade electrical conduit seals in the remaining three diesel generator rooms and thecommon auxiliary building. These inspections identified a number of degraded conduitseals, which were repaired prior to returning the units to service. The licensee narrowlydefined the scope of the additional inspections performed at this time as only thoseareas which contained safety-related SSCs and documented the results of theseinspections in corrective action program document PIP C-06-3902.On August 30, 2006, Following a period of heavy rain, water entered the Unit 1 and Unit2 turbine buildings at several locations. Four of these locations were from unsealedelectrical conduits that connected the 22kV main transformer output to the 6.9kVtransformers located in the turbine building basement. The 6.9kV transformers supplynormal and alternate power to the station's 4.16kV vital busses. Due to the risksignificance of these transformers and their associated terminal cabinets, the licenseehad installed 5-foot high flood walls in 2005 to protect them from flooding if a circulatingwater leak occurred inside the turbine building. Rainwater entered these enclosuresthrough the unsealed electrical conduits. The level in two enclosures (surrounding1ATC22/1ATC30 and 2ATC22) reached the high level alarm setpoint, which requiredimmediate operator actions to prevent the loss of the loads controlled through thecabinet. Subsequent investigation determined that these conduits had been unsealedsince initial construction. Potential leak paths into the flood wall enclosures had notbeen evaluated when the flood walls were constructed in 2005 or following the May 22,2006 flooding event associated with the 1A DG despite the fact that they contained risk-significant equipment. The corrective actions developed following the turbine buildingflooding event and documented in PIPs C-06-6197, C-06-6201 and C-06-6224 focusedon ensuring other below-grade penetrations in the turbine buildings were sealed, but didnot include other risk-significant SSC's on the plant site in the extent of condition review.During the week of October 20, 2006, an NRC inspection identified that below-gradeelectrical conduit penetrations entering the SSF were not adequately sealed to preventwater in-leakage in the event the cable trench filled with water. Additionally, the 15inspectors determined that water could enter the SSF during a PMP flooding eventthrough the building's two doors and diesel room ventilation panels. The degradedconduit seals had not been inspected following either of the two previous 2006 floodingevents due to the licensee failing to recognize the risk-significance of the SSF. The factthat the SSF would be rendered inoperable in the event of a PMP was not identified bythe licensee following the revision of the calculated PMP flood level because the SSF isnot designed to be a safety-related structure and site engineering personnel did notrecognize the risk significance that the SSF had in terms of the Catawba PRA model.Duke Energy Procedure NSD 208, Problem Investigation Process (PIP), describes thenuclear organization's corrective action program. This NSD defines a PIP as themechanism used to identify and document problems that are Conditions Adverse toQuality as well as other issues. The NSD defines "conditions adverse to quality" asabnormal or unexpected conditions, including malfunctions, involving safety-related, risk-significant or power generation significant SSCs." NSD 208, section 208.10, ProblemEvaluation, requires an extent of condition determination be performed on PIP's codedas Category 1, 2 or 3 generated for "conditions adverse to quality." The licensee'sassessment of the May 22 and August 30, 2006, events diesel generator flooding eventfailed to adequately assess the potential for the flooding of other risk-significant SSCs inaddition to the SSCs included in the PIP's assessment. This omission was continued inthe review and analysis done as part of the assessment of the revised PMP flood levelcalculation in June 2006.Analysis: The inspectors determined that failure to conduct an adequate extent ofcondition review following multiple water intrusion events and the revision of thecalculated maximum PMP flood leve l at the station to identify plant vulnerabilities was aperformance deficiency. The inspection team determined that the finding was of morethan minor significance since the finding was associated with the Protection AgainstExternal Factors and Equipment Performance attributes of the Mitigating Systemscornerstone in that by narrowly focusing extent of condition reviews to only encompasssafety-related SSCs and excluding risk-significant SSCs, systems required to respond toand mitigate initiating events could be adversely affected. The finding was determined to be of very low safety significance because, while limitingextent of condition reviews to safety-related SSC's has the potential to adversely affectthe ability of the station to respond to initiating events, failing to include risk significantequipment in the reviews conducted for the water intrusion events in 2006 after the 1DGconduit seals were repaired did not result in an overall increase in plant risk in excess ofthe green/white threshold. The vulnerabilities of other risk-significant SSCs to floodinghave been addressed by the station.This finding has a cross-cutting aspect (Corrective Action Program) in the area ofProblem Identification and Resolution, in that the licensee failed to conduct adequateextent of condition reviews as delineated by the corrective action program'simplementing procedure and thereby prevent similar, subsequent events from occurring.Enforcement: The failure to conduct an adequate extent of condition review and includerisk-significant SSCs did not constitute a violation of regulatory requirements.

Thisfinding is identified as FIN 05000413,414/2006-010-3, Failure to Conduct an Adequate 16Extent of Condition Review Following Multiple Water Intrusion Events to Ensure Risk-Significant SSCs Were Protected From Loss Due To Flooding. The licensee hasconducted an assessment to ensure all risk-significant and power-generation relatedSSCs, in addition to safety-related SSCs, have been reviewed and found to be protectedfrom flooding events. The licensee has captured the issue of conducting appropriateextent of condition reviews in PIPs C-06-8246 and C-06-8311.4OA6 Meetings Exit Meeting SummaryOn December 6, 2006 the inspection team presented the Special Inspection results toMr. Morris and members of his staff. Mr. Morris acknowledged the findings andobservations of the team at that time. All proprietary information reviewed by the teamwas returned to the licensee.ATTACHMENT -

SUPPLEMENTAL INFORMATION

1.Key Points of Contact2.List of Items Opened, Closed and Discussed3.List of Documents Reviewed4.List of Acronyms5.Special Inspection Team Charter6.Simplified Catawba Site Layout Drawing7.Potential impact of flooding on the transformers or terminal cabinets within the turbinebuilding basement floodwall enclosures8.Potential impact of flooding in the Standby Shutdown Facility (SSF) on equipment withinthe structure9.Turbine Building Floodwall Enclosure drawings10.Standby Shutdown Facility floor plan drawings

1Key Points of Contact

Licensee Personnel

G. Hamrick, Mechanical / Civil Engineering Manager

R. Hart, Regulatory Compliance

W. Hogan, Fire Protection Engineer, Civil Engineering

D. Kaul, Civil Engineer

J. Morris, Catawba Site Vice President

T. Pitesa, Station Manager

R. Repko, Engineering Manager

G. Strickland, Regulatory Compliance Specialist

D. Ward, Civil Engineering Section Head

NRC Personnel

C. Casto, Director DRP, Region II

J. Moorman, Branch Chief, Branch I, DRP, RII

W. Rogers, RII Senior Reactor Analyst

R. Bernhard, RII Senior Reactor Analyst

2LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened05000413, 414/2006010-01 URI Assess the Overall Increase In Station RiskResulting From the Combination OfUnsealed Electrical Conduits Entering the1A DG Room And Turbine Buildings andFloodpaths Into the SSF (Section 4OA5.2)Opened and Closed

05000413, 414/2006010-02 NCV Failure to Establish a Procedure forMitigating the Consequences of an ExternalFlooding Event (Section 4OA5.4)05000413, 414/2006010-03 FIN Failure to Conduct an Adequate Extent ofCondition Review Following Multiple WaterIntrusion Events to Ensure Risk SignificantSSC's Were Protected From Loss Due toFlooding (Section 4OA5.7)

3List of Documents ReviewedLicensing Basis and Design Basis Documents

• UFSAR Chapter 2, Section 2.4; Hydrologic Engineering SSF Design Basis Document;CNS-1560.SS-00-0001; Rev. 21Drawings*CN-1938-01; Catawba Nuclear Station Electrical Equipment Layout, Outdoor GeneralPlan*CN-1145-8; Turbine and Service Building Substructure, Construction Layout, 566' 9";

Rev. 3*CN-1148-1; Turbine and Service Building Unit 1 Substructure; Rev. 8

• CN-1148-2; Turbine and Service Building Unit 1 Substructure; Rev. 10

• CN-1148-3; Turbine and Service Building Unit 1 Substructure; Rev. 3

• CN-2148-1; Turbine and Service Building Unit 2 Substructure; Rev. 7

• CN-2148-2; Turbine and Service Building Unit 2 Substructure; Rev. 4

• CN-2148-3; Turbine and Service Building Unit 2 Substructure; Rev. 5

• CN-1100-07-02; Turbine Building Unit 2 General Arrangement Basement Floor Elevation

568'; Rev. 29

• CN-1100-07-03; Turbine Building Unit 2 General Arrangement Basement Floor Elevation

568'; Rev. 16

• CN-1151-11.02; Turbine Building Unit 1 Flood Wall Details; Rev. 0

• CN-2925-01; Electrical Equipment Layout - Turbine Building - Unit 2, Below Mezzanine

level; Rev. 05

• CN-1022-17; Powerhouse Yard Drainage Layout; Rev 6A

• CN-1022-18; Cooling Tower Yard Area Drainage Layout; Rev 0Procedures / Surveillances

• Environmental Work Practice 8.1; Pre-Project Planning; Rev. 8

• AP/0/A/5500/030; Plant Flooding, Rev. 07

• RP/0/A/5000/007; Natural Disaster and Earthquake; Rev. 25

• RP/0/B/5000/030; Severe Weather Preparations; Rev. 05

• OP/1/A/6100/010I; Alarm Response Procedure for Panel 1AD-8; Windows A/4, B/4

• OP/1/B/6100/010N; Alarm Response Procedure for Panel 1AD-13; Windows D/1, D/2and D/3*OP/2/A/6100/010I; Alarm Response Procedure for Panel 2AD-8; Windows A/4, B/4

• OP/2/B/6100/010N; Alarm Response Procedure for Panel 2AD-13; Windows D/1, D/2

and D/3*AM/0/B/5100/008, Enclosure 6.4, RC Recovery Submersible Pump Setup

2Attachment 3

• NSD 208, Problem Investigation Process; Rev. 27

• NSD 210; Corrective Action Program, Rev. 4

• NSD 223; Trending Program; Rev. 5Work Orders

• 01064006; Model work order to perform annual inspections of the yard drains and catchbasins*00880635; Model work order to remove vegetation and debris from yard drains and

catch basins on a semi-annual basis

• 00966988; Inspect cable pull box in the Unit 2 B DG sequencer hallway to inspect for

source of water leakage

• 00966988; Properly seal the conduits entering the pull box in the 2B DG load sequencer

hallway*01712134-01; Model work order to pump down the 1B DG WN sump

• 00966988; Inspect pull box in 2B DG sequencer hallway leaking water

• 01131411; Seal conduits to 1A DG

• 01131423; Seal conduit sleeves in CMH-02

• 01131420; Seal conduit sleeves in CMH-18A

• 01131419; Seal conduit sleeves in CMH-18B

• 01132080; Seal conduit sleeves in CMH-4A

• 01131422; Seal conduit sleeves in CMH-4A at the trench

• 01131703; Reseal conduit with Duxseal and RTV732 in Aux Bldg

• 01131705; Reseal conduit with Duxseal and RTV732 in Aux Bldg

• 01131702; Inspect conduits at AA-49, 577' Aux Bldg

• 01131706; Reseal conduit with Duxseal and RTV732 in Aux Bldg

• 01131649; Miscellaneous walls between Unit 1 and 2 - inspect water barrier

• 01131741; Cooling tower yard berms need to be validated

• 01132823; Inspect or repair the barriers in the waste water pond and switch yard

• 01709667; Seal conduit at 1A manhole adjacent to the Unit 1 Turbine Building RR Bay

• 01709669; Seal conduit at 1B manhole adjacent to the Unit 1 Turbine Building RR Bay

• 01709676; Seal conduit at 2A manhole adjacent to the Unit 2 Turbine Building RR Bay

• 01709677; Seal conduit at 2A manhole adjacent to the Unit 2 Turbine Building RR Bay

• 01709547; Install seal plate in 6" sleeve in Unit 1 Turbine Building

• 01720514; Seal unsealed pipe sleeves in the Unit 2 turbine building walls

3Attachment 3PIPs*C-01-4230; Documentation of partial blockage of 7 Type I yard drains

• C-06-8179; NRC inspectors identified that the requirements in Environmental WorkPractice 8.1 related to routine yard drain and catch basin inspections were not beingfollowed*C-06-6197; Water intrusion into the Unit 1 and Unit 2 turbine buildings following a majorthunderstorm on 8/30/06

• C-06-3902; Water intrusion into the 1A DG room through unsealed electrical conduits

• C-06-6224; Water intrusion into the floodwall enclosures in the turbine building

basement areas

• C-06-7420; Questions raised by the NRC related to SSF flooding

• C-06-8195; Assessment of vulnerability to flooding issues identified at McGuire

• C-00-3784; Yard drains at cooling towers covered with grass clippings and would notdrain*C-04-6921; Potential DG room WN sump clogging issue

• C-05-1544; In order to update the Catawba PRA model, information is needed regarding

the new flood wall enclosures in the turbine building basement

• C-05-1992; PRA recommends changing NSD-403 to incorporate flooding concerns per

PIP G-03-0087

• C-05-4922; WL isolation valves discussed in the WL DBD to isolate the Service Building

from the Auxiliary Building in case of flooding due to

tornado are not proceduralized

• C-06-4824; EIT team associated with water entering the 1A DG room identified twoprocedure improvements

• C-06-6192; Site access was flooded following heavy rains

• C-06-7160; PMP flood analysis revision shows that the maximum flood level in the

powerhouse yard is higher than previously calculated

• C-96-2001; The turbine building sump was flooded due to heavy rains

• C-06-4447; Re-evaluate the changes to the site topography

• C-06-7846; Breakdown in communication occurred between the PA group, Catawba

Regulatory Compliance and Engineering when preparing the LER on the 1A DG floodingeventMiscellaneous Documents

• Dow Corning 732 Multi-Purpose Sealant Product Data Sheet

• AP-30 Flooding Lesson Plan, Rev. 0

• Emergency Plan 2 Lesson Plan, CN0080, Rev. 3

• Sump Systems Lesson Plan, Rev. 25

• Standby Shutdown Facility Lesson Plan, Rev. 30

4LIST OF ACRONYMSAITAugmented Inspection TeamAP Abnormal Operating ProcedureCFR Code of Federal RegulationsCMH Conduit ManholeCSCondensate Storage SystemDBDDesign Basis DocumentDG Emergency Diesel GeneratorDRSDivision of Reactor SafetyEIT Event Investigation TeamEP Emergency Operating ProcedureFINInspection FindingISFSIIndependent Spent Fuel Storage InstallationIMCInspection Manual Chapter KV KilovoltLOOP Loss of Offsite PowerMSLMean Sea LevelNCV Non-Cited ViolationNRC Nuclear Regulatory CommissionOP Normal Operating ProcedurePIP Problem Investigation Process (report)PMPPredicted Maximum PrecipitationPRAProbabilistic Risk AnalysisRCCirculating Water SystemRFFire Water SystemRLLow Pressure Service Water SystemRNNuclear Service Water SystemRPResponse ProcedureRYFire Protection SystemSDP Significance Determination ProcessSIT Special Inspection TeamSRASenior Risk AnalystSSCSystems, Structures and ComponentsSSFStandby Shutdown FacilityTSTechnical SpecificationTSAIL Technical Specification Action Item LogTSC Technical Support CenterUFSAR Updated Final Safety Analysis ReportURI Unresolved ItemWO Work OrderWR Work Request

5November 22, 2006

MEMORANDUM TO: Ryan Taylor, Team LeaderSpecial Inspection Team FROM: William D. Travers Regional Administrator SUBJECT: CATAWBA SPECIAL INSPECTION TEAM CHARTER A Special Inspection Team (SIT) has been established for Catawba to inspect and assess thefacts surrounding the licensee's corrective actions for degraded seals on safety-related and risk-important below-gr

ade electrical penetra

tions. Additional team members will be assigned, asappropriate, based on the issues identified. Your inspection should begin on November 27, 2006.The objectives of the inspection are to: (1) review the facts surrounding degraded seals onbelow-grade electrical penetrations and lack of watertight seals on the Standby ShutdownFacility doors; (2) assess the licensee's response and investigation of these conditions; (3)identify any generic issues associated with the event; and (4) conduct an extent of conditionreview.For the period during which you are leading this inspection and documenting the results, youwill report directly to me. The guidance in

Inspection Procedure 93812, "Special Inspection"and Management Directive 8.3, "NRC Incident Investigation Procedures," applies to yourinspection.If you have any questions regarding the objectives of the enclosure charter, contact Charles A.Casto at (404) 562-4500Docket Nos.: 50-413 and 50-414License Nos.: NPF-35 and NPF-52Enclosure: Special Inspection Team Charter

5SPECIAL INSPECTION TEAM (SIT) CHARTERCATAWBA UNSEALED BELOW-GRADE ELECTRICAL PENETRATIONS RESULT IN FLOODING Basis for the Formation of the SIT - On May 22, 2006, water overflowing from the Unit 2 coolingtowers traveled through unsealed electrical conduits in cable trenches and manholes andentered the 1A diesel generator room through unsealed, below-grade electrical penetrations. This resulted in the 1A diesel generator being declared inoperable. An extent of conditionreview determined that other electrical conduits and below-grade electrical penetrations haddegraded seals. The licensee corrected some of the degraded penetration seals. The licenseecorrected these degraded penetration seals prior to restarting both units which had beenremoved from service following a dual-unit LOOP event on May 20, 2006. No additionalinspections of below grade penetrations into other plant buildings were performed at that time. On August 30, 2006 unsealed below-grade electrical penetrations in the turbine building allowedwater from a heavy rainstorm to enter the turbine building and accumulate inside of the floodbarriers surrounding the transformers from offsite power which provide normal and alternatepower to the 4.16lV vital buses. The flood walls had been constructed to protect thetransformers and terminal cabinets from possible flooding caused by a break in one of thesecondary cooling systems located in the turbine building basement based on the adverseimpact a flood event had on the station's PRA risk model.During the week of November 6, 2006, further inspection of susceptible below-grade electrical

penetrations determi

ned that the Standby Shutdown Facility was susceptible to flooding fromtwo possible sources. The first source was through below-grade electrical penetrations that haddegraded sealing material surrounding the cables. The second source was flooding throughunsealed doors to the SSF located at ground level. The threshold of the doors is at elevation594 feet. The predicted maximum precipitation (PMP) flood level had been changed from anoriginal elevation of 594 feet to 594 feet, 8 inches due to changes in the characteristics of thefacility yard and a re-analysis of the predicted maximum rainfall t

hat the site could experience.Objectives of the SIT - (1) review the facts surrounding degraded seals on below-grade

electrical penetrations and lack of watertight seals on the Standby Shutdown Facility doors; (2)assess the licensee's response and investigation of these conditions; (3) identify any genericissues associated with the event; and (4) conduct an extent of condition review. To accomplishthese objectives, the following will be performed:a.Develop a sequence of events related to the conditions.b.Conduct an extent of condition review of the SSF flooding vulnerability. Asappropriate, provide any new information that is identified that would affect therisk analysis, to the Region II, Senior Reactor Analyst. c.Identify corrective actions taken by the licensee in response to the SSF floodingvulnerability and eval

uate their timeliness and effectiveness. d.Evaluate Catawba's preparedness to cope with a PMP event. Specifically,determine if plant procedures provide adequate guidance to cope with the event

2Attachment 5and operator training is adequate to support the level of detail provided by theplant procedures for the event.e.Determine and assess the licensee's previous corrective actions and lessonslearned associated with the flooding from unsealed below-grade electrical and/ormechanical penetrations.f.Determine if other site structures were adversely affected and have becomesusceptible to flooding as a result of the change in PMP level.g.Evaluate the licensee's decision making process associated with their extent ofcondition review conducted for the 1A diesel generator room and turbine buildingflooding events; including their understanding of the risk associated with theconditions.h.Brief the Regional Administrator and Regional management daily.I.Document the inspection findings and conclusions in an inspection report within30 days of the inspection.

5Attachment 6SIMPLIFIED CATAWBA SITE LAYOUT DRAWING

7Potential Impact of Flooding On the Transformers or Terminal Cabinets Within The TurbineBuilding Basement Floodwall EnclosuresThere are three (3) floodwall enclosures in each unit's turbine building basement designed toprotect transformers 1ATC, 2ATC, 1ATD, 2ATD, SATA and SATB along with their associatedterminal cabinets 1ATC22, 2ATC22, 1ATC23, 2ATC23, 1ATC30 and 1ATC31. The floodwallswere constructed to reduce the PRA model's risk that resulted from a postulated break of a pipewithin the turbine building and subsequent loss of these components. The followingsummarizes what the impact could be on station operation if one of these components was lostdue to flooding. Attachment 9 contains drawings showing the floodwalls for each unit, whatequipment is enclosed by each and the water ingress flow paths that existed prior to their repairin September 2006.I.Flood within Unit 1, Floodwall A which encloses Terminal Cabinets 1ATC23 and1ACT31Water entering a terminal cabinet enclosure is unpredictable and could vary based onthe water's condition (i.e. temperature, pressure, flow) and the operating state ofenclosed equipment (i.e. cabinet cooling fans on/off). Once moisture enters a terminal

cabinet enclosure, the assurance of equipment reliability cannot

be guaranteed.A review of circuits contained in 1ATC23 & 1ATC31 was performed to identify thepotential effected circuit loss. Based on the licensee's detailed review of electrical andinstrumentation drawings associated with 1ATC23 and 1ATC31, the following scenarioswere determined to be plausible in the event the terminal cabinets were lost due toflooding.*Unit 1 - Zone B Lockout

• Unit 1 - Zone G Lockout

• Loss of Busline 1B (Switchyard Breakers 14 & 15)

• Loss of Busline 2B (Switchyard Breakers 23 & 24)

• Generator Breaker 1B Trip (50% Runback)

• Switchyard to Plant Transfer Trip (86TT/2B) - Trip PCB 2B, Trip 6.9 kV Switchgear Breakers 2TB & 2TD fed from Transformer 2T1B, Trip 6.9 kV Switchgear Breakers 2TA & 2TC fed from Transformer 2T2B

• Switchyard to Plant Transfer Trip (86TT/1B) - Trip PCB 1B, Trip 6.9 kV Switchgear Breakers 1TB & 1TD fed from Transformer 1T1B, Trip 6.9 kV Switchgear Breakers 1TA & 1TC fed from Transformer 1T2B

• Generator Breaker 1A Trip (50% Runback) Ref CNEE-189-02.02

• Loss of 125VDC due to Short Circuit - CDA FDR F07 & CDB FDR F07 (Power to MainProtective Relaying - Panel board 1A & 1B)

2Attachment 7I

I. Flood within Unit 1, Floodwall B which encloses transformers 1ATC, SATA and1ATDFlooding within Floodwall B could lead to the loss of Transformers 1ATD, 1ATC, & STAand switchgear 1GTA & 1GT

B. The transformers and switchgear are not sealed andthus would likely be lost during a flooding event. Based on the licensee's detailedreview of electrical and instrumentation drawings associated with 1ATC, 1ATD andSATA, the following scenarios were determined to be plausible in the event they werelost due to flooding.

• Loss of 1ATC, SATA & 1GTA (4 kV Essential & Blackout Aux Power - Train A) &Loss of 1ATD & 1GTB (4 kV Essential & Blackout Aux Power - Train B) will leadto the following:

• Unit 1 LOOP due to loss of Transformers 1ATC & 1ATD (Primary feeds to TrainA (1ETA) and Train B (1ETB))

• Blackout on the 1ETA bus and starting / loading of the 1A Diesel Generator

which is tied to the 1ETA bus. The 1ETA bus provides power for equipmentnecessary for plant safety during a LOCA or blackout.

• Blackout on the 1ETB bus and starting / loading of the 1B Diesel Generatorwhich is tied to the 1ETB bus. The 1ETB bus provides power for equipmentnecessary for plant safety during a LOCA or blackout.

• Loss of 4160 V Blackout System (Bus 1FTA). Under normal shut downconditions following a blackout, 1FTA supplies power to non-essential loadsnecessary to achieve normal shutdown following a blackout, but not requiredduring a LOCA. The blackout bus (1FTA) can be fed from switchgear 1ETA or1GTA. The Breaker in switchgear 1GTA is electrically interlocked with theswitchgear breakers 1ETA-2 & 1FTA-1. Flooding of switchgear 1GTA (Primaryfeed for Blackout Bus 1FTA) could prevent the swap-over from 1GTA to thealternate feed (Switchgear breakers 1ETA-2 & 1FTA-1) since these breakers areelectrically interlocked and thus a loss of the 1FTA blackout bus would occur.

• Loss of 4160 V Blackout System (Bus 1FTB). Under normal shut downconditions following a blackout, 1FTB supplies power to non-essential loadsnecessary to achieve normal shutdown following a blackout, but not requiredduring a LOCA. The blackout bus (1FTB) can be fed from switchgear 1ETB or1GTB. The Breaker in switchgear 1GTA is electrically interlocked with theswitchgear breakers 1ETB-2 & 1FTA-1. Flooding of switchgear 1GTB (Primaryfeed for Blackout Bus 1FTB) could prevent the swap-over from 1GTB to thealternate feed (Switchgear breakers 1ETB-2 & 1FTB-1) since these breakers areelectrically interlocked and thus a loss of the 1FTB blackout bus would occur. III.Flood within Unit 1 Floodwall C which encloses Terminal Cabinets 1ATC22 and1ATC30)

3Attachment 7A review of circuits contained in 1ATC22 & 1ATC30 was performed to identify thepotential effected circuit loss. Based on the licensee's detailed review of electrical andinstrumentation drawings associated with 1ATC22 and 1ATC30, the following scenarioswere determined to be plausible in the event terminal cabinets were lost due to flooding.

• Loss of Busline 2A (PCBs 20 & 21)

• Zone A Lockout

• GCB 1A Trip

• Switchyard to Plant Transfer Trip (86TT/1A) - Switchyard PCB Breaker FailureLock-out, Trip PCB 1A, Trip 6.9 kV Switchgear Incoming Breakers 1TC & 1TDfed from Transformer 1T1A, Trip 6.9 kV Incoming Switchgear Breakers 1TA &1TB fed from Transformer 1T2A, Trips 13.8 kV Switchgear 1HTA IncomingBreaker fed from 1ATE

• GCB 1B Trip

• EHC 50% Runback

• Loss of Busline 1A (PCBs 17 & 18)

• Switchyard to Plant Transfer Trip (86TT/2A): Switchyard PCB Breaker FailureLock-out, Trip PCB 1A, Trip 6.9 kV Switchgear Breakers 2TC & 2TD fed fromTransformer 2T1A, Trip 6.9 kV Switchgear Breakers 2TA & 2TB fed fromTransformer 2T2A, Trips 13.8 kV Switchgear 1HTA Incoming Breaker fed from2ATE *Spurious IPB, Zone A Transformer, Generator PCB 1A alarms

• Spurious Switchyard Event Recorder PointsIV.Flood within Unit 2, Floodwall A which encloses Terminal Cabinet 2ATC23A review of circuits contained in 2ATC23 was performed to identify the potential effectedcircuit loss. Based on the licensee's detailed review of electrical and instrumentationdrawings associated with 2ATC23, the following scenarios were determined to beplausible in the event terminal cabinets were lost due to flooding.

• Unit 2 - Zone B Lockout

• Unit 2 - Zone G Lockout

• Loss of Busline 1B (Switchyard Breakers 14 & 15)

• Loss of Busline 2B (Switchyard Breakers 23 & 24)

• Generator Breaker 2B Trip (50% Runback)

• Switchyard to Plant Transfer Trip (86TT/2B) - Trip PCB 2B, Trip 6.9 kVSwitchgear Breakers 2TB & 2TD fed from Transformer 2T1B, Trip 6.9 kVSwitchgear Breakers 2TA & 2TC fed from Transformer 2T2B

• Switchyard to Plant Transfer Trip (86TT/1B) - Trip PCB 1B, Trip 6.9 kVSwitchgear Breakers 1TB & 1TD fed from Transformer 1T1B, Trip 6.9 kVSwitchgear Breakers 1TA & 1TC fed from Transformer 1T2B

• Generator Breaker 2A Trip (50% Runback)

4Attachment 7

• Possible Loss of 125VDC due to Short Circuit - Power to Main Power ProtectiveRelaying V.Flood within Unit 2, Floodwall B which encloses transformers 2ATD, SATB and2ATC)Flooding within Floodwall B could lead to the loss of Transformers 2ATD, 1ATC, andSTA and switchgear 2GTA & 2GTB. The transformers and switchgear are not sealedand thus would likely be lost during a flooding event.

• Unit 2 LOOP due to loss of Transformers 2ATC & 2ATD (Primary feeds to TrainA (2ETA) and Train B (2ETB))

• Blackout on the 2ETA bus and starting / loading of the 2A Diesel Generator

which is tied to the 2ETA bus. The 2ETA bus provides power for equipmentnecessary for plant safety during a LOCA or blackout.

• Blackout on the 2ETB bus and starting / loading of the 2B Diesel Generatorwhich is tied to the 2ETB bus. The 2ETB bus provides power for equipmentnecessary for plant safety during a LOCA or blackout.

• Loss of 4160 V Blackout System (Bus 2FTA). Under normal shut downconditions following a blackout, 2FTA supplies power to non-essential loadsnecessary to achieve normal shutdown following a blackout, but not requiredduring a LOCA. The blackout bus (2FTA) can be fed from switchgear 2ETA or2GTA. The Breaker in switchgear 2GTA is electrically interlocked with theswitchgear breakers 2ETA-2 & 2FTA-1. Flooding of switchgear 2GTA (Primaryfeed for Blackout Bus 2FTA) could prevent the swap-over from 2GTA to thealternate feed (Switchgear breakers 2ETA-2 & 2FTA-1) since these breakers areelectrically interlocked and thus a loss of the 2FTA blackout bus would occur.

• Loss of 4160 V Blackout System (Bus 2FTB). Under normal shut downconditions following a blackout, 2FTB supplies power to non-essential loadsnecessary to achieve normal shutdown following a blackout, but not requiredduring a LOCA. The blackout bus (2FTB) can be fed from switchgear 2ETB or2GTB. The Breaker in switchgear 2GTA is electrically interlocked with theswitchgear breakers 2ETB-2 & 2FTA-1. Flooding of switchgear 2GTB (Primaryfeed for Blackout Bus 2FTB) could prevent the swap-over from 2GTB to thealternate feed (Switchgear breakers 2ETB-2 & 2FTB-1) since these breakers areelectrically interlocked and thus a loss of the 2FTB blackout bus would occur.

5Attachment 7VI.Flood within Unit 2, Floodwall C which encloses terminal cabinet 2ATC22A review of circuits contained in 2ATC22 was performed to identify the potential effectedcircuit loss. Based on the licensee's detailed review of electrical and instrumentationdrawings associated with 2ATC22, the following scenarios were determined to beplausible in the event terminal cabinets were lost due to flooding.

• Loss of Busline 2A (PCBs 20 & 21)

• Zone A Lockout

• GCB 2A Trip

• Switchyard to Plant Transfer Trip (86TT/1A) - Switchyard PCB Breaker FailureLock-out, Trip PCB 1A, Trip 6.9 kV Switchgear Incoming Breakers 1TC & 1TDfed from Transformer 1T1A, Trip 6.9 kV Incoming Switchgear Breakers 1TA &1TB fed from Transformer 1T2A, Trips 13.8 kV Switchgear 1HTA IncomingBreaker fed from 1ATE

• GCB 2B Trip

• EHC 50% RUNBACK

• Loss of Busline 1A (PCBs 17 & 18)

• Switchyard to Plant Transfer Trip (86TT/2A): Switchyard PCB Breaker FailureLock-out, Trip PCB 1A, Trip 6.9 kV Switchgear Breakers 2TC & 2TD fed fromTransformer 2T1A, Trip 6.9 kV Switchgear Breakers 2TA & 2TB fed fromTransformer 2T2A, Trips 13.8 kV Switchgear 1HTA Incoming Breaker fed from2ATE *Spurious IPB, Zone A Transformer, Generator PCB 1A alarms

• Spurious Switchyard Event Recorder Points

8Potential Impact Of Flooding In The Standby Shutdown Facility (SSF) On Equipment Within The StructureThe licensee conducted an assessment of what the impact water intrusion into the SSF wouldhave on equipment in each of the four (4) rooms within the facility. Attachm

ent 10 to thisinspection report shows the floor plan of the SSF and should be referred to when reviewing theequipment affected listed below by room. The calculation looked at the recently revised PMPlevel and then a 70% PMP level used in PRA modeling.The postulated impact on the SSF's equipment following a PMP event was determined to havebeen as follows:

• MCC / Switchgear Room: Approximately 2 inches of water would result in thetripping of breakers in SLXG which provide power to the normal and standby batterychargers. Water entering into a 600V MCC could likely cause additional failures.

• Battery Room: No impact identified with up to 9" of water in the room

• Control Room: Approximately 6.5 inches of water would result in the failure of fusesthat would disable the primary system instrumentation on the SSF control consoleaffecting the ability to control both units.

• DG Room: Approximately 2.25 inches of water would cause blowing of fusesassociated with transformers in the bottom of the DG control panel as the panel isnot water tight. Water could leak through the door at 3.35 inches and additionalwater would enter at 4.25 inches through vent panels in the side of the room. Theloss of these fuses would cause the DG to trip if running or keep it from starting if itwas not yet operating.The licensee's calculation shows that on a 70% PMP event there will be no loss of function inany of the rooms within the SSF; however, the SSF would be adversely impacted following aPMP event.

9Turbine Building Floodwall Enclosure drawingsUNIT 1

9Turbine Building Floodwall Enclosure drawingsUNIT 2

10Standby Shutdown Facility Floor Plan DrawingsNOTE: The floor elevation of the SSF is at 594' above Mean Sea Level (MSL). The PMP floodlevel at Catawba is currently 594' 9" above MSL.