ML072540771

IR 05000285-07-007, on 05/14 Through 07/25/2007, Fort Calhoun Station; Component Design Basis Inspection

ML072540771
Person / Time
Site:	Fort Calhoun
Issue date:	09/07/2007
From:	William Jones Division of Reactor Safety IV
To:	Ridenoure R Omaha Public Power District
References
IR-07-007
Download: ML072540771 (58)

See also: IR 05000285/2007007

Text

September 7, 2007R. T. RidenoureVice PresidentOmaha Public Power DistrictFort Calhoun Station FC-2-4 Adm.P.O. Box 550Fort Calhoun, NE 68023-0550SUBJECT:FORT CALHOUN STATION - NRC COMPONENT DESIGN BASESINSPECTION REPORT 05000285/2007007 AND NOTICE OF DEVIATIONDear Mr. Ridenoure:

On July 25, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed a componentdesign bases inspection at your Ft. Calhoun Station. The enclosed report documents ourinspection findings. The findings were discussed via telecom on July 25, 2007, with Mr. JeffReinhart, Site Director, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license. The team reviewed selected procedures and records, observed activities, and interviewedcognizant plant personnel.Based on the results of this inspection, the NRC identified one Notice of Deviation from alicense commitment, and five findings that were evaluated under the risk significancedetermination process. Violations were associated with the five findings. Each of the findingswere found to have very low safety significance (Green) and the violations associated withthese findings are being treated as noncited violations, consistent with Section VI.A.1 of theNRC Enforcement Policy. If you contest the Notice of Deviation, any of the noncited violations,or the significance of the violations you should provide a response within 30 days of the date ofthis inspection report, with the basis for your denial, to the U.S. Nuclear RegulatoryCommission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to theRegional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan PlazaDrive, Suite 400, Arlington, Texas 76011; the Director, Office of Enforcement, U.S. NuclearRegulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at theFort Calhoun Station.

Omaha Public Power District-2-In accordance with 10 CFR 2.390 of the NRC's Rules of Practice, a copy of this letterand its enclosure will be available electronically for public

inspection in the NRC PublicDocument Room or from the Publicly Available Records (PARS) component of NRC's documentsystem (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).Sincerely,

/RA/William B. Jones, ChiefEngineering Branch 1Division of Reactor SafetyDockets: 50-285License: DPR-40Enclosure:Inspection Report 05000285/2007007 w/Attachments: 1. Supplemental Information 2. DC Transfer Switches 3. Diesel Generator Minimum DC Voltage for Field Flashing, June 12, 2007 4. Fort Calhoun Station Position on Emergency Diesel Generator Field Flash Voltage 5. Initial Information Requestcc w/Enclosure: Joe l. McManis, Manager - LicensingOmaha Public Power DistrictFort Calhoun Station FC-2-4 Adm.P.O. Box 550Fort Calhoun, NE 68023-0550David J. BannisterManager - Fort Calhoun StationOmaha Public Power DistrictFort Calhoun Station FC-1-1 PlantP.O. Box 550Fort Calhoun, NE 68023-0550James R. CurtissWinston & Strawn1700 K Street NWWashington, DC 20006-3817

Omaha Public Power District-3-ChairmanWashington County Board of SupervisorsP.O. Box 466Blair, NE 68008Julia Schmitt, ManagerRadiation Control ProgramNebraska Health & Human ServicesDept. of Regulation & LicensingDivision of Public Health Assurance301 Centennial Mall, SouthP.O. Box 95007Lincoln, NE 68509-5007Daniel K. McGheeBureau of Radiological HealthIowa Department of Public HealthLucas State Office Building, 5th Floor321 East 12th StreetDes Moines, IA 50319Ronald L. McCabe, ChiefTechnological Hazards BranchNational Preparedness DivisionDHS/FEMA9221 Ward ParkwaySuite 300Kansas City, MO 64114-3372

Omaha Public Power District-4-Electronic distribution by RIV:Regional Administrator (BSM1)DRP Director (ATH)DRS Director (DDC)DRS Deputy Director (RJC1)Senior Resident Inspector (JDH1)Resident Inspector (LMW1)Branch Chief, DRP/E (JAC)Senior Project Engineer, DRP/E (GDR)Team Leader, DRP/TSS (CJP)RITS Coordinator (MSH3)DRS STA (DAP)M. Kunowski, OEDO RIV Coordinator (MAK3)D. Pelton, OEDO RIV Coordinator (DLP)ROPreportsFCS Site Secretary (BMM)SUNSI Review Completed: ____ADAMS: Yes G No Initials: _WBJ

_____ Publicly Available

G Non-Publicly Available

G SensitiveNon-SensitiveSRI:EB1RI:EB!RI:EB1C:EB1ACESC:PBEC:EB1RAKopriva/lmbGAGeorgeJReynosoWBJonesMVasquezJAClarkWBJones

/RA//RA//RA//RA//RA/K.Fuller for/RA//RA/9/6/079/6/079/6/079/7/079/7/079/7/079/7/07

OFFICIAL RECORD COPY T=Telephone E=E-mail F=FaxNOTICE OF DEVIATIONOmaha Public Power District Docket No. 50-285Fort Calhoun Station FC-2-4 Adm.License No. DPR-40P.O. Box 550Fort Calhoun, NE 68023-0550During an NRC inspection conducted from May 21 through July 25, 2007, a deviation of acommitment that Omaha Public Power District made in a September 6, 1979, letter to the U.S.Nuclear Regulatory Commission, was identified. In accordance with the NRC EnforcementManual, the deviation is listed below: In the September 6, 1979, letter in support of the licensee's application forLicense Amendment 52, Fort Calhoun Station committed to "install temperaturedetectors, with readouts and alarms, in the control room to monitor safetyinjection pump room temperatures."Contrary to the above, the licensee did not install temperature detectors, withreadouts and alarms, in the control room to monitor safety injection pump roomtemperatures, as stated in the September 6, 1979, letter. The deviation occurredon October 14, 1980, the date when License Amendment 52 was issued based,in part, on the modification to install temperature detectors. In addition, onNovember 1, 1999, after modifying operating procedures to restore ventilation tothe safety injection pump rooms after an accident, the licensee did not notify theNRC that the commitment was never implemented. Please provide a reply to this Notice of Deviation, to the U.S. Nuclear Regulatory Commission,ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the RegionalAdministrator, Region IV, and a copy to the NRC Resident Inspector office at Fort CalhounStation in writing within 30 days of the date of this Notice. The reply should be clearly markedas a "Reply to a Notice of Deviation;" and should include: (1) the reason for the deviation, or ifcontested, the basis for disputing the deviation; (2) the corrective steps that have been taken

and the results achieved; (3) the corrective steps that will be taken to avoid further deviations;and (4) the date when your corrective action will be completed. Where good cause is shown,consideration will be given to extending

the response time. Dated this 7th day of September, 2007

-1-EnclosureU.S. NUCLEAR REGULATORY COMMISSION REGION IV Docket:50-285 License:DPR-40Report:05000285/2007007Licensee:Omaha Public Power DistrictFacility:Fort

Calhoun StationLocation:Fort Calhoun Station FC-2-4 Adm.P.O. Box 399, Highway 75 - North of Fort CalhounFort Calhoun, Nebraska Dates:May 14 through July 25, 2007Team Leader:R. Kopriva, Senior Reactor Inspector, Engineering Branch 1Inspectors:G. George, Reactor Inspector, Engineering Branch 1J. Reynoso, Reactor Inspector, Engineeering Branch 1AccompanyingPersonnel:P. Wagner, Electrical Engineer, Beckman and AssociatesS. Speigelman, Mechanical Engineer, Beckman and AssociatesL. Ellershaw, PE, ConsultantApproved By:W

illiam B. Jones, ChiefEngineering Branch 1Division of Reactor Safety

-2-EnclosureSUMMARY OF FINDINGSIR 05000285/2007007; May 14 through July 25, 2007; Fort Calhoun Station; Component DesignBasis Inspection.The report covers an announced inspection by a team of three regional inspectors, and threecontractors. Five findings and one deviation were identified. All of the findings were of very lowsafety significance. The final significance of most findings is indicated by their color (Green,White, Yellow, Red) using Inspection Manual Chapter 0609, "Significance DeterminationProcess." Findings for which the significance determination process does not apply may beGreen or be assigned a severity level after NRC management review. The NRC's program foroverseeing the safe operation of commercial nuclear power reactors is described inNUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.A.NRC-Identified FindingsCornerstone: Mitigating Systems; Barrier Integrity

• Green. The team identified a noncited violation of Fort Calhoun TechnicalSpecification 5.8, "Procedures," for an inadequate Technical Specificationrequired procedure. Specifically, Abnormal Operating Procedure 11, "Loss ofComponent Cooling Water," could not be performed as written for establishingbackup raw water to the containment fan coolers during post-accident conditionswith a loss-of-component cooling water. The licensee has entered this findinginto their corrective action program as Condition Report 2007-02268. The finding is greater than minor because it is associated with the barrier integritycornerstone attribute for operating post event procedure quality. Using thesignificance determination process of Manual Chapter 0609, Appendix A, for thecontainment barrier cornerstone, the finding did not represent an actual openpathway in the physical integrity of reactor containment or involve an actualreduction of defense-in-depth for the atmospheric pressure control of the reactorcontainment. The finding had a cross-cutting aspect in the area of humanperformance resources (H.2.c) because the licensee did not ensure thatprocedures to assure nuclear safety, in this case establishing backup raw waterto the containment fan coolers during post-accident conditions with a loss-of-component cooling water, were complete, accurate and up-to-date (Section 1R21.b.1).*Green. The team identified a noncited violation of 10 CFR Part 50, Appendix B,Criterion III, for the failure to perform a complete and adequate analysis of safetyinjection pump room temperatures to support operation of two high pressuresafety injection pumps in one room during a design basis accident. The licenseeperformed the design calculation based on a limiting case with only one highpressure safety injection pump operating. However, at the operators discretion,the second high pressure safety injection pump could be started. The starting ofthe second high pressure safety injection pump in pump Room 21 wouldincrease the room temperature to near equipment qualification temperature

-3-Enclosurelimits. The licensee has entered this finding into their corrective action programas Condition Report 2007-02441.This finding is more than minor because the engineering calculation results didnot include a second high pressure safety injection pump running which wouldincrease the temperature in pump Room 21 to near equipment qualificationtemperature limits. This unanalyzed condition raised reasonable doubt on theoperability of the components within the room.

Using the Manual Chapter 0609, Phase 1 screening worksheet, the issue screened as having very low safety

significance because it was a design deficiency confirmed not to result in loss of

operability in accordance with NRC Manual Chapter

Part 9900, Technical

Guidance, Operability Determination Process for Operability and Functional

Assessment (Section 1R21.b.2). *Green. The team identified a noncited violation of 10CFR Part 50, Appendix B,Criterion III, for the failure

to translate the Fo

rt Calhoun Station raw water strainercomponent's design basis into specifications, procedures, and instructions. Theraw water strainers are equipment necessary to ensure that nuclear safetyfunctions provided by Safety Class 1, 2, or 3 equipment (raw water) are capableof accomplishing those functions. The licensee has entered this finding into theircorrective action program as Condition Report 2007-3046.This finding is more than minor because it affected the mitigating system

cornerstone objective (design contro

l attribute) to ensure the reliability andcapability of the raw water system to mitigate initiating events

such that the rawwater strainer function was necessary and relied upon for ensuring the nuclearsafety functions that are provided by Safety Class 1, 2, or 3 equipment. UsingManual Chapter 0609, Phase 1 screening worksheet, the issue screened ashaving very low safety significance because it was a design or qualificationdeficiency confirmed not to result in a loss of operability per Part 9900, TechnicalGuidance, Operability Determination Process for Operability and FunctionalAssessment (Section 1R21.b.3). *Green. The team identified a noncited violation of 10 CFR 50, Appendix B,Criterion XVI, Corrective Action, for failure to promptly identify and correctconditions adverse to quality. Specifically, between November 11, 2005, to

April 28, 2006, during quarterly surveillance tests of the steam bypass warmupvalves for the turbine driven auxiliary feedwater pump, the licensee noteddegrading conditions (change in flow coefficient, Cv) of the bypass warmupvalves. During a postulated steam line break, the deteriorating bypass warmupvalves could pass more steam than designed. Passing more steam through apipe break would not maintain a mild environment to Room 19, where theauxiliary feedwater pumps are located, and, therefore w

ould not ensure theoperability of the safety-rela

ted equipment in the room. This issue was enteredinto the corrective action program as Condition Report 2007-2489. This issue was more than minor because the degrading throttle valve would haveaffected the ability to maintain a mild environment in Room 19 during apostulated steam line break as it pertained to the Mitigating Systems cornerstone

-4-Enclosureobjective of equipment reliability associated with the motor-driven auxiliaryfeedwater pump. Using Manual Chapter 0609, Phase 1 screening worksheet,the issue screened as having very low safety significance, because it was adesign or qualification deficiency confirmed not to result in a loss-of-safetyfunction, in accordance with NRC Manual Chapter Part 9900, TechnicalGuidance, Operability Determination Process for Operability and FunctionalAssessment. The finding had a cross-cutting aspect in the area of humanperformance decision making (H.1.b). The licensee had repeated opportunitiesto identify and correct the degrading bypass warmup valve but did notdemonstrate conservative decision making to ensure the throttle valve differentialpressure did not fall below established acceptance criteria (Section 1R21.b.4)

.*Green. The team identified a noncited violation of 10 CFR Part 50, Appendix B,Criterion III, "Design Control," for the failure to meet the single valve failurerequirements for the component cooling water surge tank. The componentcooling water surge tank water and nitrogen supply lines were credited with onlya single check valve for meeting single failure criteria requirements. Based onengineering review, this configuration is not considered acceptable. ManualIsolation Valves AC-1179 and NG-290 have now been administratively changedin accordance with the Safety Analysis for Operability from the normally openposition to the normally closed position to meet the single failure criteriarequirements for the component cooling water Surge Tank AC-2. UpstreamCheck Valves AC-391 and NG-113 were previously credited with meeting thesingle failure criteria. This issue was entered into the corrective action programas Condition Report 2007-2622.This finding is more than minor because it affected the mitigating system

cornerstone objective (design contro

l attribute) to ensure the reliability andcapability of the equipm

ent needed to mitigate initiating events.

Using the Phase1 worksheet in Manual Chapter 0609, "Significance Determination Process," thisfinding is determined to be of every low safety significance because there was noactual loss of a safety function (Section 1R21.b.5).*Deviation. The team identified a Notice of Deviation for failure to installtemperature monitoring of the safety injection pump room as committed to in aletter to the NRC, dated September 6, 1979. The commitment was submitted tosupport the licensee's application for License Amendment 52. During theinspector's review of other issues related with the safety injection pump roomtemperature, it was identified on June 6, 2007, that the temperature monitoringinstrumentation was never installed, as committed in the 1979 letter. Since theproposed modification was never completed, the inspector concluded that thelicensee failed to satisfy a written commitment, as documented in theSeptember 6, 1979, letter. In addition, on November 1, 1999, after modifyingoperating procedures to restore ventilation to the safety injection pump roomsafter an accident, the licensee missed an opportunity to notify the NRC that thecommitment was never implemented. This issue was entered into the licensee'scorrective action program as Condition Report 2007-0448.

-5-EnclosureThe failure to install temperature monitoring is a performance deficiency becausethe licensee failed to satisfy a written commitment. This written commitment isnot a legally binding requirement, as defined by the NRC Enforcement Manual.Since the performance deficiency is not legally binding, it will be treated as anadministrative action with non-escalated enforcement action, consistent withChapter 3 of the NRC Enforcement Manual. Since the licensee failed to satisfy awritten commitment, this issue is being treated as a Notice of Deviation (DEV)consistent with Section VI.E of the NRC Enforcement Policy (Section 1R21.b.6).

-6-EnclosureREPORT DETAILS1REACTOR SAFETYInspection of component design bases verifies the initial design and subsequentmodifications and provides monitoring of the capability of the selected components andoperator actions to perform their design bases functions. As plants age, their designbases may be difficult to determine and important design features may be altered or

disabled during modifications. The pl

ant risk assessment model

assumes the capabilityof safety systems and components to perform their intended safety functionsuccessfully. This inspectable area verifies aspects of the Initiating Events, MitigatingSystems and Barrier Integrity cornerstones for which there are no indicators to measureperformance.1R21Component Design Bases Inspection (71111.21)The team selected risk-significant components and operator actions for review usinginformation contained in t

he licensee's probabilisti

c risk assessment. In general, thisincluded components and operator actions that had a risk achievement worth factorgreater than two or a Birnbaum value greater than 1E-6. a.Inspection Scope

To verify that the selected components would function as required, the team revieweddesign basis assumptions, calculations, and procedures. In some instances, the teamperformed calculations to independently verify the licensee's conclusions. The teamalso verified that the condition of the components was consistent with the design bases

and that the te

sted capabilities met t

he required

criteria.The team reviewed maintenance work records, corrective action documents, andindustry operating experience records to verify that licensee personnel considereddegraded conditions and their impact on the components. For the review of operatoractions, the team observed operators during simulator scenarios, as well as duringsimulated actions in the plant.The team performed a margin assessment and detailed review of the selectedrisk-significant components to verify that the design bases have been correctlyimplemented and maintained. This design margin assessment considered originaldesign issues, margin reductions because of modifications, and margin reductionsidentified as a result of mate

rial condition issues.

Equipment reliability issues were alsoconsidered in the selection of components for detailed review. These included itemssuch as failed performance test results; significant corrective actions; repeatedmaintenance; 10 CFR 50.65(a)1 status; operable, but degraded conditions; NRCresident inspector input of problem equipment; system health reports; industry operatingexperience; and licensee problem equipment lists. Consideration was also given to theuniqueness and complexity of the design, operating experience, and the availabledefense in-depth margins.

-7-EnclosureThe inspection procedure requires a review of 15-20 risk-significant and low designmargin components, 3-5 relatively high-risk operator actions, and 4-6 operatingexperience issues. The sample selection for this inspection was 20 components,8 operator actions, and 5 operating experience issues. The components selected for review were:

• 4160 circuit breakers

• Station batteries - including battery transfer switches

• Nitrogen admission to component cooling water surge tank, pressure controlValve PCV-2610*Component cooling water shutdown heat exchanger inlet Valve HCV-480

• Safety injection and refueling water storage tank level indicators

• Raw water strainers

• Air accumulators - outside containment

• Safety injection pump room ventilation

• Reactor coolant pump seal coolant heat exchangers

• Turbine driven auxiliary feedwater governor*High pressure core injection minimum flow recirculation isolationValves HCV-385 and -386.*Emergency diesel generator room ventilation

• Safety injection refueling water tank discharge Valves HCV 383-1, 2, 3, and 4

• Safety injection recirculation - through recirculation sump and safety injectionrefueling water tank*High pressure core injection pump - net positive suction head and sequencing ofvalve manipulation (including safety injection refueling water tank vortexcalculation needed to evaluate pump net positive suction head)*High pressure core injection valve, motor-operated Valve HCV-312

• Raw water and component cooling water - interface

• Containment spray system - isolation Valves HCV-344 and -345.

• Control element assemblies

-8-Enclosure*Low pressure core injection - jockey pump*Discharge side of component cooling water pressure control Switches 412

and 413The risk significant operator actions included:

• Steam break outside containment

• Loss-of-auxiliary feedwater/loss-of-ins

trument air*Station blackout/minimizing dc loads

• Loss of power

• Large break loss-of-coolant accident/loss-of-raw water

• Inter-system loss-of-coolant accident/outside containment loss-of-componentcooling water*Loss-of-turbine plant cooling water/loss-of-instrument air

• Potable water to air compressor

The operating experience issues were:

• Pressurizer power operated relief valve concerns

• Raw water underground piping

• Information Notice 1998-041,"Spurious Shut Down of Emergency DieselGenerators"*Gas voiding of emergency core cooling systems

• Information Notice 2006-017, "Recent Operating Experience of Service WaterSystems Due to External Conditions"Unresolved item review for closure:

• Intake Structure Design, Unresolved Item 05000285/2005011-05*Safety Status of Raw Water Strainer, Unresolved Item 05000285/2005009-01

-9-Enclosure b.Findings

b.1.Inadequate Abnormal Operating Procedure for Loss-of-Component Cooling WaterIntroduction: The team identified a Green, noncited violation of Fort Calhoun TechnicalSpecification 5.8, "Procedures," for an inadequate Technical Specification requiredprocedure. Specifically, Abnormal Operating Procedure 11, "Loss of ComponentCooling Water," could not be performed as written for establishing backup raw water tothe containment fan coolers during post-accident conditions with a loss-of-componentcooling water.Description: The team reviewed condition reports and calculations related to AbnormalOperating Procedure 11, "Loss of Component Cooling Water." Abnormal OperatingProcedure 11 is a recommended procedure in accordance with Regulatory Guide 1.33,"Quality Assurance Program Requirements." In 1994, the licensee concluded inCalculation FC05662, "Check of Back Pressure at Containment Air Cooling Coils," thatwith the maximum raw water flow to the containment air cooling coils and minimum riverwater level, the back pressure of the raw water system is insufficient to prevent flashingof the water in the containment air coolers under post-accident conditions in thecontainment. More recently, in July 2006, the licensee performed Calculation FC06621,"Containment Air Cooler Thermal Hydraulic Analysis for Accident with Loss-of-OffsitePower (LOOP)," which confirmed that the back pressure of the raw water system wasinsufficient to prevent flashing in the containment fan coolers under post-accidentconditions. Therefore, aligning the raw water system to the containment fan would notbe successful under all accident conditions as written in Abnormal OperatingProcedure 11.The team noted that after the condition was confirmed in July 2006, the licensee did notenter the condition into their corrective action program until October 2006, asdocumented in Condition Report 200604647. The action was to change all affecteddocuments, including Abnormal Operating Procedure 11, by March 2007. As of April2007, no changes had been made to the affected documents. ConditionReport 200701130 was initiated to revise Abnormal Operating Procedure 11 byNovember 2007. In June 2007, the team determined that no interim guidance had been provided to theoperating crews during the time period in which Abnormal Operating Procedure 11 wasbeing revised. In addition, the Team identified that operators were being trained on thecontinued use of the inadequate procedure during the revision period. The licenseesubsequently notified the operators that certain steps of Abnormal OperatingProcedure 11 could not be completed as written. The licensee has stopped training onthe use of the procedure until the revision has been completed as identified in ConditionReport 200701130.Analysis: The failure to establish an abnormal operating procedure to address a loss ofcomponent cooling water to the containment fan coolers is a performance deficiency. The finding is greater than minor because it is associated with the barrier integritycornerstone attribute for operating post event procedure quality. Using the significancedetermination process of Manual Chapter 0609, Appendix A, for the containment barrier

-10-Enclosurecornerstone, the finding did not represent an actual open pathway in the physicalintegrity of reactor containment or involve an actual reduction of defense-in-depth for theatmospheric pressure control of the reactor containment. The finding had a cross-cutting aspect in the area of human performance resources because the licensee did notensure that procedures to assure nuclear safety, in this case establishing backup rawwater to the containment fan coolers during post-accident conditions with a loss-of-component cooling water, were complete, accurate and up-to-date. Enforcement: Fort Calhoun Technical Specification 5.8, "Procedures," states, in part,that written procedures shall be established, implemented and maintained covering theapplicable procedures recommended in Appendix A of Regulatory Guide 1.33,Revision 2. Item 6.i of Appendix A requires a procedure to combat a loss-of-componentcooling system and cooling to individual components. Contrary to the above, AbnormalOperating Procedure 11, "Loss of Component Cooling Water," could not be performedas written for establishing adequate backup raw water to the containment fan coolersduring post-accident conditions with a loss-of-component cooling water. Specifically,inadequate back pressure of the raw water system could result in flashing of the rawwater in the containment fan coolers when called upon during a loss-of-componentcooling water condition. The team determined this issue to be of very low safetysignificance. Since this issue was entered into the licensee's corrective action programas Condition Report 200702268, the finding is being treated as a noncited violation,consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000285/2007007-01, Inadequate Abnormal Operating Procedure for Loss-of-Component Cooling Water. b.2.Failure to Analyze Impact of Heat Loading in Safety Injection Pump Room 21 from theStart of a Third High Pressure Safety Injection PumpIntroduction: The team identified a Green noncited violation of 10 CFR Part 50,Appendix B, Criterion III, for the failure to perform a complete and adequate analysis ofsafety injection pump room temperatures to support operation of 2 high pressure safetyinjection pumps in one room during a design basis accident. The licensee performedthe design calculation based on a limiting case with only one high pressure safetyinjection pump operating. However, at the operators discretion, the second highpressure safety injection pump could be started.

Discussion: There are eight safety injection pumps divided into pump Rooms 21 and 22. In safety injection pump Room 21, there is one low pressure safety injection pump, onecontainment spray pump, and two high pressure safety injection pumps. In safetyinjection pump Room 22, there is one low pressure safety injection pump, twocontainment spray pumps, and one high pressure safety injection pump. The teamreviewed the safety injection pump rooms' ventilation analysis for a design basisaccident. The rooms were reviewed because of the low temperature margin and highsafety significance of the safety injection pumps. The maximum temperature of therooms was analyzed in Calculation FC06747, Revision 3. The calculation assumes thatthere would be one high pressure safety injection pump, one low pressure safetyinjection pump, and one containment spray pump operating in each of the rooms. Thisassumption resulted from a 1999 design change that removed the automatic startfeature for the third high pressure safety injection pump and third containment spraypump. The team found that adequate precautions were taken to restrict operation of one

-11-Enclosureof the two containment spray pumps in Room 22; but the second of the two highpressure safety injection pumps in Room 21 could be started at the operator's discretion. The starting of the second high pressure safety injection pump would increase the roomtemperature to near the equipment qualification temperature limits.

In response to this finding, Condition Report 2007-02441 was i

ssued and an

operabilityevaluation was performed for the increased room heating that would result from startinga second high pressure safety injection pump in Room 21. The evaluation determinedthat the room temperature was slightly below the equipment qualification temperaturelimits with the second of the two high pressure safety injection pumps operating, andthat the safety injection pumps in Room 21 would remain operable.Analysis: The failure to meet design control requirements associated with the safetyinjection pump room temperature design was a performance deficiency. This finding ismore than minor because the engineering calculation results did not include theoperation of a second high pressure safety injection pump running which would increasethe temperature in pump Room 21 to near equipment qualification temperature limits.This unanalyzed condition rais

ed reasonable doubt on the operability of

the componentswithin the room. The team used Manual Chapter 0609, Phase 1 screening worksheetand determined that the finding was of very low safety significance because the findingis a design deficiency that did not result in the loss-of-safety function.Enforcement: Part 50 of Title 10 of the Code of Federal Regulations, Appendix B, Criterion III, "Design C

ontrol," requires, in

part, that measures be established to providefor the verification of the adequacy of design. These measures may includecalculations. The licensee used Calculation FC06747, Revision 3, to demonstrate theadequacy of the safety injection pump room temperature to assure the function of thesafety injection pumps. Contrary to the above, as of September 2, 1999, the calculateddesign temperature limits control measures for safety injection pump Room 21 were nonconservative, in that, Calculation FC06747 assumed that only one high pressure safetyinjection pump would be operating when it should have assumed that both high pressuresafety injection pumps in safety injection pump Room 21 would be operating. Theviolation is of

very low safety significance because it was a design deficiency confirmed

not to result in loss-of-operability in accordance with NRC Manual Chapter Part 9900,Technical Guidance, Operability Determination Process for Operability and FunctionalAssessment: NCV 05000285/2007007-02, Failure to Analyze Impact of Heat Loading inSafety Injection Pump Room 21 for the Start of a Second High Pressure Safety Injection

Pump. b.3.Use of Non Safety-Related Components in the Raw Water System Pump DischargeStrainers (Unresolved Item 05000285/2005009-01) Introduction: The team identified a Green, noncited violation of 10CFR Part 50,Appendix B, Criterion III, for the failure to

translate the Fort Calhoun Station raw waterstrainer component's design basis into specifications, procedures, and instructions. Theraw water strainers were incorrectly translated as non safety-related for their function offiltering small debris from the raw water system, although the equipment is relied upon toensure the operation of the raw water system.

-12-EnclosureDescription: The raw water system takes suction from the Missouri River, which is anopen cycle cooling system and is the plant's ultimate heat sink. The river water comesinto the intake structure through a series of traveling screens through three separatecells or bays. Four raw water pumps draw their suction from these cells. The pumpshave cross-connected pump discharge headers, which discharge into one of two rawwater strainers and then into the plant through a common header, to the componentcooling water heat exchangers. The licensee established "screened river water" tomean water drawn through the intake structure traveling screens. Screened river waterenters the cells or bays along with small gravel and debris, which collects near the rawwater pump suctions. Upon starting the raw water pumps, this buildup of gravel anddebris can be pumped into one of the two operating strainers. The strainers, which arecontinuously back washed, can become plugged. On several occasions this hasresulted in complete blockage of one strainer and loss-of-cooling water in one header. The licensee's Design Basis Document SDBD-AC-RW-101 provides that the raw waterstrainers must be able to pass sufficient flow to meet the system flow requirements. According to design basis calculations and vendor documents, rotation of the strainer isneeded to ensure adequate back wash flow is available to remove entrapped debrisfrom the screened water flow. The team noted that the licensee has not demonstrated

that a degraded strainer would still meet its function and pass flow. Without properstrainer function or flow, the raw water system's capability to mitigat

e the consequencesof an accidents is jeopardized. There have been several events over the last few yearswhere changing river conditions have shown that a strainer can become clogged to sucha degree that raw water flow is blocked in one header. River debris has clogged a rawwater strainer resulting in the strainer motor tripping on current overload. The operatorsin the control room have no indication of a raw water strainer motor trip and rely onstrainer differential pressure alarms or roving equipment operators to alert them of atripped strainer motor. The team concluded that the raw water strainer is required tosupport the safety function of the raw water system and must be to screen out graveland debris to maintain adequate cooling water flow to the component cooling water heatexchangers. Because this issue continues to be a concern at the Fort Calhoun Station,licensee management has placed the raw water strainer function under maintenancerule monitoring status in accordance with 10CFR 50.65 (A)(1).The raw water strainer function was an original plant design feature that the licenseeconsidered non safety-related. There is no mention of the raw water strainers or theirfiltering function in Fort Calhoun Station Updated Safety Analysis Report, Section 9.8. This section states only that the raw water pumps provide "screened river water" to thecomponent cooling water heat exchangers. In a letter dated May 10,1988, "SafetyEvaluation for Item 2.2 of Generic Letter 83-26," the NRC reviewed the licensee'sresponse of criteria used to identify safety-related equipment and components. Thelicensee stated, "for mechanical criteria, the response identifies a special class whichcorresponds to a safety-Class 3 in ANSI NI8.2 and other components under ASMESection III Code." The licensee had classified the pressure boundary aspect of the rawwater strainers as safety-related, but made no mention of the raw water strainer functionor operability in their response or in the Updated Safety Analysis Report. Based on thelicensee's review, the NRC concluded the licensee's response met the requirements andwas acceptable.

-13-EnclosureIn a letter dated November 16, 1992, the licensee provided the NRC a list of theirimplemented actions at Fort Calhoun Station to meet the recommendations of GenericLetter 89-13, Service Water System Problems Affecting Safety-Related Equipment. Oneof these actions was to establish a maintenance program for open-cycle service watersystem piping and components (including raw water components), such that, "corrosion,erosion . . . silting . . . cannot degrade the performance of safety-related systemssupplied by service water." At Fort Calhoun Station, the service water system includesthe component cooling water and raw water systems. Several modifications to the rawwater system have been completed, but river debris, including small gravel, continue toimpact the service water flow through the raw water strainers. Assumptions in the FortCalhoun Station design basis calculation state that the raw water strainer must be incontinuous operation, which means constantly back washing the strainer. Thecomponents required to maintain the strainer in continuous backwash were classified bythe licensee as non safety-related (.i.e., strainer motor, backwash valve).During the April 2005 Fort Calhoun Problem Identification and Resolution inspection,Unresolved Item 05000285/2005009-01 was issued. The team identified a concern withthe classification of the raw water strainer motors and the straining function. Theunresolved item was documented in Condition Report 2005-04740 with a response tothe NRC dated May 19, 2005. In addressing this unresolved item, the licensee statedthere had been one documented case of raw water header flow going to zero gallons perminute in year 2005 and two in 2006. Since then there have been seven more incidentsof a strainer being plugged and blocking flow. The function of the raw water strainers isto remove debris to minimize fouling of the component cooling water heat exchangerand reduce maintenance. The licensee provided that the safety function of the rawwater system can be achieved and maintained without the filtering function but inanother case makes a conclusion that there are redundant strainer headers that providesufficient margin to accommodate blockage. At the times when the raw water strainerwas plugged, only one train became inoperable. The other strainer and train of rawwater was always available. The team concluded that corrective actions have not beensufficient to prevent raw wa

ter strainer blockage and that the capability of raw watersystem to remain functional during and following design basis events has not beendemonstrated.The team discussed the safety classification of the raw water strainers with the NRCDivision of Nuclear Reactor Regulation (NRR). In correspondence received from NRRdated June 25, 2007 a review of the safety classification of the raw water strainers wasperformed. Part of this assessment is provided below:According to the Fort Calhoun Station Updated Safety Analysis Report,Appendix N, Section 2.1, "The equipment assigned to Safety Class 1, 2,or 3 is that relied upon in the plant design to accomplish nuclear safetyfunctions." Section 2.1.3 states, in part, that Safety Class 3 shall apply toequipment (not included in Safety Class 1 or 2) that is necessary toensure that nuclear safety functions are able to be performed by SafetyClass 1, 2, or 3 equipment (such as heat removal). The equipment inquestion, the raw water system strainers, fall into this category becausethey are necessary and relied upon for ensuring the nuclear safetyfunctions that are provided by Safety Class 1, 2, or 3 equipment, such as

-14-Enclosurethe capability to remove heat. Therefore, unless the licensee hasspecifically evaluated the capability of Safety Class 1, 2, and 3 equipmentto perform their safety functions without relying on the raw water strainersand has conclusively demonstrated that the strainer function is notrequired for this purpose, the strainers should have been classified assafety-related (SC-3) in accordance with the Updated Safety AnalysisReport criteria.The team concluded the raw water strainer function was necessary and relied upon forensuring the nuclear safety functions that are provided by Safety Class 1, 2, or 3equipment to remain functional and that the strainers were required to be classified asSafety Class 3. Analysis: The failure to correctly classify the raw water strainers as Class 3 to supportthe operation of the safety-related raw water system is a performance deficiency. Thisfinding is more than minor because it affected the mitigating system cornerstoneobjective (design control attr

ibute) to ensure the reliability and capability of the raw watersystem to mitigate initiating events such that the raw water strainer function wasnecessary and relied upon for ensuring the nuclear safety functions that are provided bySafety Class 1, 2, or 3 equipment. Using Manual Chapter 0609, Phase 1 screeningworksheet, the issue screened as having very low safety significance because it was adesign or qualification deficiency confirmed not to result in a loss of operability perPart 9900, Technical Guidance, Operability Determination Process for Operability andFunctional Assessment" The raw water system always had one train available, makingthe system operable.Enforcement: Part 50 of Title 10 of the Code of Federal Regulations, Appendix B,Criterion III, requires, in part, that measures be established to assure that applicableregulatory requirements and the design basis are correctly translated into specifications,drawings, procedures, and instructions. Contrary to the above, the licensee failed tocorrectly translate the applicable regulatory requirements and design basis to the rawwater strainers to ensure the raw water system safety functions were able to beperformed. This violation is being treated as a noncited violation, consistent withSection VI.A.1 of the NRC Enforcement Policy: NCV 05000285/2007007-03, Failure toTranslate Regulatory Requirements and Design Basis to Equipment Required to Supportthe Raw Water System. b.4.Inadequate Procedure for the Turbine Driven AFW (TDAFW) Keep Warm Line BypassThrottle Valves MS-366 and 368Introduction: The team identified a noncited violation of 10 CFR 50, Appendix B,Criterion XVI, Corrective Action, for failure to promptly identify and correct conditionsadverse to quality. Specifically, between November 11, 2005, to April 28, 2006, duringquarterly surveillance tests of the steam bypass warmup valves for the Turbine DrivenAuxiliary Feedwater pump, the licens

ee noted degrading conditions (change in flowcoefficient, Cv) of the bypass warmup valves. The bypass throttle valves are used torestrict steam flow to maintain the TDAFW 2-inch steam supply line warm, were in an"as-found" condition open beyond their acceptable range. In this condition, the valveswere further open than assumed in the design basis calculations and a break in the 2-

-15-Enclosureinch steam line could allow more steam flow into Room 19 than what the room wasanalyzed for. This condition would have impacted the non environmentally qualifiedmotor-driven auxiliary feedwater pump and, therefore, produced a condition in whichboth safety-related auxiliary feedwater pumps could not perform their safety-relatedfunction to mitigate design basis accident. This issue was entered into the correctiveaction program as Condition Report 2007-2489.Description: The turbine driven and motor driven auxiliary feedwater pumps are locatedin Room 19. A 2-inch steam line transverses Room 19 and supplies driving steam to theTDAFW pump. The licensee has established a method to maintain the 2-inch steamsupply line warm by using a small bypass line around the normally closed supply valves. This bypass line has a small valve which is throttled to setup a pressure drop across thevalve. Design calculations established the throttle position which limit flow through thewarm-up line. Bypass warmup Valves MS-366 and -368 are 1/2-inch throttle valves, onseparate supply lines, which were installed to limit the release of steam in the event of asteam line break in the steam supply piping to the TDAFW Pump 10. Part of the surveillance test performed on these valves is to check the throttle valveand record the differential

pressure across the throttle valves. SurveillanceProcedure OP-ST-AFW-0005, "Auxiliary Feedwater (AFW) Steam Supply Line Check,"is performed quarterly in accordance with the Fort Calhoun Station Inservice InspectionProgram. This surveillance procedure requirements are set to limit the release of steamin the event of a steam line break through the warmup line, assuring that the mildenvironment condition in the associated room, Room 19, is not exceeded. Room 19

also contains other safety-related equipment, such as the electric driven auxiliaryfeedwater pump, which has not been shown to operate in other than a mild environment.The team noted that the licensee had not established effective surveillance test criteriato assure that the as left position of the adjustable throttle flow valves, used to restrictsteam flow into Room 19, would not degrade and result in excessive steam leakage inthe event of a steam line break before the conduct of the next surveillance. Duringquarterly surveillance tests between November 11, 2005, to

April 28, 2006, the licenseenoted degrading conditions (change in flow coefficient, Cv). This condition wasevaluated under Condition Report 200601771 after the throttle valve could no longer beadjusted to obtain the proper differential pressure. The wear on the valves wasdetermined to be minor. The team noted that the licensee had not adequately evaluatedthe condition of the valve until the throttle valve material condition had degraded and

needed replacement. During the performance of the surveillance test, the "as-found"differential pressure across the throttle valves was less than the acceptance criteriarange. On May 28, 2005, February 3 and April 28, 2006, the tests found that thedifferential pressures were less then 50 psi. The procedure permits an engineeringevaluation of this condition. This evaluation, however, did not address the potential thatthe valve's condition could have degraded beyond design basis conditions. Instead thevalve was allowed to degrade to the extent that it was scheduled to be replaced duringthe next test. The valve internal clearances appear to have been degraded beyond theassumptions used to calculated steam flow and, therefore, outside design conditions. The team was concerned when the as-found differential pressure conditions haddecreasing trends. The throttle valve had to be adjusted to ensure the as-left differentialpressures were in the acceptable range. Warmup steam flow into the supply line is

-16-Enclosurebased on the differential pressure across the throttle valve with a steam trap in service. Differential pressure is determined after the steam trap is isolated and the pressure isrecorded. The team raised the concern with the licensee that a steam line break wouldresult in conditions exceeding a mild environment. The licensee performed anoperability determi

nation and concluded that the auxiliary feedwater system remainedoperable because of expected operator actions to isolate header pressure duringpostulated events. Analysis: The team determined that allowing the throttle valve differential pressure tofall below established acceptance criteria to ensure a mild environment in Room 19during a postulated steam line break was a performance deficiency. This issue was

more than minor because the degrading throttle valve would have affected the ability tomaintain a mild environment in Room 19 during a postulated steam line break as itpertained to the Mitigating Systems

cornerstone objective of equipment reliabilityassociated with the motor-driven auxiliary feedwater pump. Using ManualChapter 0609, Phase 1 screening worksheet, the issue screened as having very lowsafety significance, because it was a design or qualification deficiency confirmed not toresult in a loss-of-safety function, in accordance with NRC Manual Chapter Part 9900,Technical Guidance, Operability Determination Process for Operability and FunctionalAssessment. The finding had a cross-cutting aspect in the area of human performancedecision making (H.1.b). The licensee had repeated opportunities to identify and correctthe degrading bypass warmup valve but did not demonstrate conservative decisionmaking to ensure the throttle valve differential pressure did not fall below establishedacceptance criteria Enforcement: Part 50 of Title 10 of the Code of Federal Regulations, Appendix B,Criterion XVI, Corrective Actions, requires, in part, that measures be established toassure conditions adverse to quality are promptly identified and corrected. Contrary tothe above, Procedure OP-ST-AFW-0005 did not identify that the deteriorated bypasswarmup valves would allow the throttle valve differential pressure to fall belowestablished acceptance criteria, as required by the licensee's commitment to maintain amild environment to Room 19 and, therefore, ensure the operability of the safety-relatedequipment in the room during a postulated steam line break. The acceptance criteria didnot account for the as-found differential pressure throttle valves being in a condition thatwould challenge the assumptions made in the design basis calculations. The licenseewas evaluating additional corrective actions, including possibly revising the testprocedure. Because the violation was of very low safety significance and licenseepersonnel entered the finding into the corrective action program as ConditionReport 2007-2489, this violation is being treated as a noncited violation, consistent withSection VI.A.1 of the NRC Enforcement Policy: NCV 2007007-04, InadequateCorrective Actions for the Turbine Driven Auxiliary Feedwater Keep Warm Line BypassThrottle Valves MS-366 and 368.

-17-Enclosure b.5.Component Cooling Surge Tank Nitrogen and Demineralized Water Supply LineIsolation Valves

.Introduction: The team identified a Green, noncited violation of 10 CFR Part 50,Appendix B, Criter

ion III. Since initial plant

startup until J

une 23, 2007, thedemineralized water and nitrogen makeup lines to the component cooling water surgetank did not comply with American National Standards Institute (ANSI) Standard 51.1,"Nuclear Safety Criteria for the Design of Pressurized Water Powerplants," with respectto single failure criteria (double isolation), as referenced in Updated Safety AnalysisReport, Appendix N. Description: The primary isolation points for the two makeup lines to the componentcooling water surge tank were Check Valves AC-391 (demineralized water) and NG-113(nitrogen gas). The lines from the surge tank to these isolation points are classified asCQE (safety-related). Everything upstream of these two valves is non CQE (non safety-related), including an additional check valve on each line. The piping arrangement was not originally designed to facilitate in-service test leaktesting of Check Valves AC-391 and NG-113. If either of the check valves failed theleak rate test, the entire component cooling water system would be inoperable, thus,placing the plant in Technical Specification 2.0.1 (immediate shutdown). This conditionexisted because there was no way to isolate the check valves in order to repair them (ifneeded), and depressurization of the surge tank would render the component coolingwater system inoperable. The in-service leak test became a requirement circa 1994. Maintenance Request 97-007 was created to deal with several issues, includinginstallation of new manual isolation valves between the surge tank and CheckValves AC-391 and NG-113. Manual Valves AC-1179 and NG-290 would provide analternate isolation point if the primary isolation points (the check valves) failed the leaktest. The new manual valves can also be used to isolate the check valves from thesurge tank if the check valves need repair. This would also make it less likely that theplant would have to enter Technical Specification 2.0.1 as a result of failure of the checkvalves to pass the surveillance test. Further, the maintenance request provided forrelocating the existing check valves to a more convenient location, which would allow foreasier operation and maintenance. The existing check valves were replaced with newcheck valves. With respect to inservice testing, Check Valves NG-113 and AC-391 would remain in thein-service test program (Category A valves - specified maximum leak rates). Themanual ball valves installed downstream of the check valves would be part of the safety-related pressure boundary, but would not be in the in-service test program because theyfunction only as alternate backup isolation points if the corresponding check valve failsthe leak test. These manual valves were in a normally open position.

-18-EnclosureOn June 13, 2007, the team raised a question regarding double isolation requirements,and how was the licensee taking credit for the manual valves as isolation valves whenthey were in a normally open position. On June 14, 2007, the licensee initiatedCondition Report 2007-2554 in response to the question. This led to the initiation of

Condition Report 2007-2622, where the licensee performed an operability evaluation,dated June 21, 2007, Safety Analysis for Operability 07-002 and a 10 CFR 50.59 review,dated June 23, 2007.The operability concern was the single failure criteria for the demineralized water andthe nitrogen supply to the component cooling water surge Tank AC-2 was not being met. Updated Safety Analysis Report, Appendix N, "Reclassification of Systems," Section 1,is based on ANSI Standard N51.1, for boundary requirements and provides variousconfigurations to meet single failure criteria. However, a single check valve does notmeet the requirement for a safety Class 3 to non-class boundary. Having the manualvalves in an open position caused the system to be inoperable (not in compliance). Thelicensee took steps to realign the two supply lines by closing the manual valves, thus,providing a double isolation arrangement. The 10 CFR 50.59 review determined that"During normal plant operations, the closed manual isolation valves meet single failurecriteria and all other design requirements." During the limited time period when themanual isolation valves are open for tank maintenance activities (filli

ng), the singlefailure criteria is not met since only a single CQE check valve (NG-113 or AC-391)provide the safety class boundary and pressure boundary function. It is not reasonablypracticable to provide further CQE redundant components during this limited period oftime. The single check valve will not fail by the initiating event it is

required to

protectagainst. The non-redundant check valve under the applicable plant conditions can meetthe safety requirements while filling the tank. The reliability of the check valve isassured by its current testing in accordance with the in-service test Program. Anoperator would be available at the manual isolation valve providing the ability to recoverfrom failure of the check valve in an adequate time frame. Other considerations whichadd reliability include the supply line pressure bei

ng higher than

the tank pressure andthe availability of

the non-CQE PCV and LCV (upstream check valves) to close if afailure occurs."Based on review of PED-GEI-16 (Document 10, Section 5) and EPRI-6895 (Document9, Section 7) Single Failure Analysis does not need to consider situations where onetrain (in this case one valve) is temporarily rendered inoperable due to short-termmaintenance allowed by technical specifications. Based on this guidance, the proposedplant configuration is not a deviation from the guidance of ANSI N51-1 as referenced inUpdated Safety Analysis Report Appendix N." Prior to 1998, the licensee did not have a credible double isolation arrangement for thedemineralized water and nitrogen makeup lines to the component cooling water surgetank as required by ANSI N51.1. In 1998, after installation of the manual valves in thesafety-class portion of the system, they still did not comply with having

a credibl e doubleisolation arrangement because the valves were in a normally open position. As shownin the 50.59 Applicability Dete

rmination, on June

23, 2007, the manual isolation valveswere changed from the normally open position to the normally closed position to meetthe single failure criteria for the component cooling water Surge Tank AC-2. While thesevalves are maintained in the closed position all requirements are met. It will be

-19-Enclosurenecessary to periodically open these valves to add water and nitrogen to the surge tank. During the period of time these valves will be open, single failure criteria will not be met. This period of time is very short. An operator will be avail

able at the manual valve(s) toclose it during this period of time if required." Additionally, the licensee created Operations Memorandum 2007-01, Revison 0,"Required Manual Actions to Make Additions to the component cooling water SurgeTank AC-2." This document provides the operating crews with manual methods to adddeaerated water and nitrogen gas to the component cooling water Surge Tank AC-2. Further, there is a check list and signature/initial blocks for the operators to showcompliance to the above guidance. Analysis: The failure to comply with ANSI 51.1, "Nuclear Safety Criteria for the Designof Pressurized Water Powerplants," with respect to single failure criteria (doubleisolation) for the demineralized water and Nitrogen makeup lines to the ComponentCooling Water (CCW) surge tank is a performance deficiency. This finding is more thanminor because it affected the mitigating system cornerstone objective (design control

attribute) to ensure the reliability and capability of

the equipment

needed to mitigateinitiating events. Specifically, the failure of the check valves for the demineralize waterand/or nitrogen supply to the component cooling water surge tank would have anadverse effect on the function and operability of the component cooling water surgetank. Using the Manual Chapter 0609, Phase 1 screening worksheet, the issuescreened as having very low safety significance because it was a design deficiencyconfirmed not to result in loss-of-operability in accordance with NRC Manual ChapterPart 9900, Technical Guidance, Operability Determination Process for Operability andFunctional Assessment. Enforcement: Part 50 of Title 10 of the Code of Federal Regulations, Appendix B,Criterion III, Design Control, requires, in part, that measures shall be established toassure that applicable regulatory requirements and the design basis, as defined inPart 50.2 and as specified in the license application, for those structures, systems, andcomponents to which this appendix applies are correctly translated into specificationsdrawings, procedures, and instructions. Also included are the selection and review forsuitability of application of ma

terials, parts, equipment, and pr

ocesses that

are essentialto the safety-related functions of the structures, systems and components. Contrary tothe above, from initial operation of the plant until July 23, 2007, the licensee was not incompliance with Updated Safety Analysis Report Appendix N "Reclassification ofSystems," Section 1, which is based on ANSI N51.1 for double isolation and boundaryrequirements for safety-related systems, or components, until such time as the manualvalves were realigned to the normally closed position. Because the violation is of verylow safety significance and has been entered into the licensee's corrective actionprogram as Fort Calhoun Condition Report 2007-2622, this violation is being treated asa noncited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy:NCV 05000285/2007007-05, Failure to Meet Single Failure Criteria Configuration forComponent Isolation Valves.

-20-Enclosure b.6.Failure to Install Temperature MonitoringIntroduction: The inspector identified a Notice of Deviation for failure to installtemperature monitoring of the safety injection pump room as committed to in a letter tothe NRC, dated September 6, 1979. Description: In a letter to the NRC, dated September 6, 1979, the licensee committed toinstalling remote temperature detectors with displays and alarms in the control room tomonitor safety injection pump room temperature. The commitment was submitted tosupport the licensee's application for License Amendment 52. License Amendment 52permitted the use of reduced air flow rates in the safety injection pump room; in addition,permitted the modification of associated technical specifications. To ensure safetyinjection pump room temperatures could be controlled under the safety injection pumps'maximum qualified temperatures, the licensee proposed, in the 1979 letter, to "install thetemperature detectors, with readout and alarms, in the control room to monitor safetyinjection pump room temperatures."During the inspector's review of other issues related with the safety injection pump roomtemperature, it was identified on June 6, 2007, that the temperature monitoringinstrumentation was never installed as committed to in the 1979 letter. Further research,led inspectors to review the NRC Safety Evaluation Report to support LicenseAmendment 52. The Safety Evaluation Report, dated October 14, 1980, states:"To further ensure the integrity of the ECCS (i.e. safety injection) pumps,the licensee is in the process of installing temperature detectors, withreadout and alarms, in the control room to monitor safety injection pumproom temperature. In the event that additional cooling is needed for thepump rooms, two actions can be taken. If activity levels are low enough,portable fans and blowers can be brought into the area. Otherwise,operator action can be taken from the control room to re-balance theventilation system in order to provide increased cooling."Based on our [NRC's] review of the licensee's submittals, we concludethat the safety injection pump room temperature has been adequatelyaddressed and that the proposed technical specifications are acceptable."Since the proposed modification was never completed, the team concluded that thelicensee failed to satisfy a written commitment, as documented in the September 6,1979, letter. In addition, based on the review of the Safety Evaluation Report, the teamconcluded that NRC's issuance of License Amendment 52 was based, in part, on theproposed installation of the temperature monitoring instrumentation. Through further inspection, the team discovered that on November 1, 1999, the licenseemade a procedure modification affecting emergency and abnormal operatingprocedures. The modification was to restore forced air flow, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, to thesafety injection pump rooms for equipment cooling in the event of safety injectionactuation. Because of the modification to restore ventilation, the licensee made adecision to no longer adhere to the commitment for temperature monitoring

-21-Enclosureinstrumentation. Although the licensee made the decision to not follow the commitment,the NRC was not notified of the decision.

Analysis: The failure to install temperature monitoring is a performance deficiencybecause the licensee failed to satisfy a written commitment. This written commitment isnot a legally binding requirement, as defined by the NRC Enforcement Manual. Sincethe performance deficiency is not legally binding, it will be treated as an administrativeaction with non-escalated enforcement action, consistent with Chapter 3 of the NRCEnforcement Manual.Enforcement: In the September 6, 1979, letter, Fort Calhoun Station committed to"install temperature detectors, with readouts and alarms, in the control room to monitorsafety injection pump room temperatures." Contrary to the above, the licensee did notinstall temperature detectors, with readouts and alarms, in the control room to monitorsafety injection pump room temperatures as stated in the September 6, 1979, letter. This deviation occurred on October 14, 1980, the date when License Amendment 52was issued based, in part, on the modification to install temperature detectors. During an inspection conducted on June 6, 2007, the team identified that the licenseehad not made this modification to the plant although the NRC had approved the revisionto the Technical Specifications on October 14, 1980. The NRC's reliance on this modification was reflected in the NRC's Safety EvaluationReport dated October 14, 1980, which states, ". . . to further ensure the integrity of theECCS (i.e. safety injection) pumps, the licensee is in the process of installingtemperature detectors, with readout and alarms, in the control room to monitor safetyinjection pump room temperature. Based on our (NRC's) review of the licensee'ssubmittals, we conclude that the safety injection pump room temperature has beenadequately addressed and that the proposed Technical Specifications are acceptable." This issue was entered into the licensee's corrective action program as ConditionReport 2007-0448. Since the licensee failed to satisfy a written commitment, this issueis being treated as a Notice of Deviation(DEV) consistent with Section VI.E of the NRCEnforcement Policy: DEV 05000285/2007007-06, Failure to Install TemperatureMonitoring. b.7.Safety Injection Refueling Water Tank Vortexing Introduction: The team identified an unresolved item concerning the safety injectionrefueling water tank. The issue concerns the minimum safety injection refueling watertank water level when the swap over to use containment sump recirculation occursduring a large break loss-of-coolant accident. An insufficient level at the time the swapover occurs could result in air entrainment from vortexing in the tank and losing netpositive suction head of the pumps.Description: The safety injection reactor water tank provides water to the safety injectionpumps during the injection phase of a design basis accident. The tank was selected forinspection to determine if it has sufficient water to satisfy the Technical Specificationrequirements and to provide assurance that there would not be adverse impact on the

-22-Enclosuresafety injection pumps due to insufficient net positive suction head or air entrainment. The team found the empty level of the tank was set at 16 inches, +0/-2 inches. Theuncertainty calculation for the tank was +/- 1.25 inches which would be outside of theempty level. The licensee performed an operability assessment

and determi

ned that,based on the current instrument settings, that the tank remained operational.Early in the inspection, the licensee's engineers stated that the question of vortexformation was earlier evaluated and it was determined by the licensee that the vortexeliminator would prevent the formation of the vortex. Condition Report 1998-00284documented the evaluation results. The vortex eliminator is located at the entrance ofthe discharge pipe, however, the licensee did not have supporting calculations or testresults to provide assurance that there would be no detrimental air entrainment duringwater discharge. The condition report was not acceptable because there was nosupporting test or analytical evidence that the vortex eliminator would perform itsfunction as expected. In lieu of such evidence, the NRC asked how the licensee wouldprovide reasonable assurance that the minimum tank level was adequate. The conditionreport stated that the current industry methods of analysis were unreliable and that withthe vortex eliminator there was no need for a vortex analysis. The team informed thelicensee that without test data or an analysis available to support the function of the"vortex eliminator" then the team would have to consider that no vortex eliminatorexisted and that the licensee would have to determine the proper tank height to assureus that there were no vortices formed at the critical point of switching from the tank to therecirculation sump, and that the net positive suction head was always maintained. Thelicensee engaged a contractor to perform a test program to determine the acceptableminimum water height of the safety injection refueling water tank. The contractorperformed a series of tests, and when questioned on the results from the first tests,elected to perform a second series of testing.Following review of the results from the vortex testing, the team had additional questionsconcerning the testing results, test report and correlation that is being used to determinethe design basis empty water level of the safety injection refueling water tank. Thisissue is unresolved pending further NRC review of such supporting documents(Unresolved Item 05000285/2007007-07).Analysis: The NRC will complete a significanc

e determination, if warranted, whenclosing out the unresolved item.Enforcement: The NRC will consider enforcement, if necessary, when closing out theunresolved item. b. 8. 4160 Volt Circuit Breakers Inspection ScopeThe team reviewed the electrical controls for the 4160 Volt safety-related circuit breakersto verify that the Updated Safety Analysis Report provisions were being properlyimplemented. The team reviewed electrical schematic and logic diagrams to verify thatthe control circuitry for selected circuit breakers incorporated the appropriate relaycontact configurations to implement the required automatic actuations and the interlock

-23-Enclosurefunctions. The team checked the maintenance procedures for the circuit breakers toensure the manufacturer's recommendations had been incorporated. The teamreviewed the circuit breaker testing procedures to verify that the trip and interlockfunctions had been incorporated. The team also verified that adequate voltage would beavailable at the end of the station battery's coping cycle to operate the reviewed circuitbreakers. The team reviewed the offsite power systems and the interlocks provided to ensure thereliability of the two offsite supplies. The team evaluated the systems that were installedto provide protection from degraded grid voltage conditions to verify that thoseconditions would be detected and managed. The electrical schematics for the controlcircuitry were compared to the electrical distribution design information to verify properimplementation of the protective features. The team also reviewed the degraded voltagecalculations to evaluate the adequacy of the determined voltage levels. The calculatedvoltage levels were utilized in the team's evaluation of selected motor-operated valvesas discussed below. The team then reviewed the testing and calibration procedures forthe degraded voltage and loss of voltage sensing relays to verify that the calculatedvalues had been appropriately incorporated into the relay setpoints. The team also evaluated the controls that were being implemented to ensure properfuse control as part of the evaluation of fuse protection provided for the circuit breakercontrol circuitry. (Proper fuse application was also reviewed as part of the evaluation ofother components during this inspection.) b.FindingsNo findings of significance were identified. b.9.Station Batteries a.Inspection ScopeThe team evaluated the station batteries to ensure there was adequate capacity to fulfillthe design provisions stated in the Updated Safety Analysis Report and other designcommitments. The team reviewed the testing procedures to verify that the batterieswere being adequately tested. The team also reviewed the dc voltage calculations toverify that sufficient voltage would be available at the terminals of selected loads toensure their proper operation under end of cycle battery conditions. The teamperformed physical inspections of the installed batteries including the inter-cellconnections and the inter-tier connection cables. The team also reviewed a number of dc transfer switches that provide the capability forswitching the power supply for selected components switched from one battery bus tothe other. The team verified that the feeder cables routed to each transfer switchenclosure from each of the battery busses were protected by a Class 1E circuit breaker. The team also verified that those circuit breakers were being routinely tested. However,the team questioned the adequacy of the protection of the installations from fire damage. The transfer switches apparently had not been the subject of a detailed fire hazardsanalysis. The team reviewed available information and discussed these installations

-24-Enclosurewith licensee personnel. The licensee's evaluation was presented to the team in theform of a position paper. A copy of the position paper is provided as Attachment 2. The team reviewed the licensee's

studies and calculations pertaining to the ability of thefacility to cope with a stat

ion blackout. In addition to

ensuring adequate voltage wouldbe available to perform such functions as 4160 Volt circuit breaker actuations, the teamalso reviewed the capability to supply adequate voltage for emergency diesel

generatorfield flash capability at the end of the four hour

station black

out coping period. The teaminspected the emergency diesel generator nameplate information and themanufacturers' technical manuals to locate any documented minimum voltagespecification for emergency diesel generator field flashing. The licensee informed theteam of their discussions on the aspects and considerations for emergency dieselgenerator field flashing with other facilities. The licensee's doc

umented discussionconcerning the ability to flash the emergency diesel generator field is provided asAttachment 3 to this input. The licensee's position on the ability to flash the FortCalhoun Station emergency diesel generators' field is provided as Attachment 4 to thisinput. The team reviewed the testing procedures and the results of recently completed batterycapacity test to verify that the station batteries could perform the safety functionsdescribed in the Updated Final Safety Analysis Report. The team noted that the testingmethodology and electrolyte temperature correction factors ('k') being used differedslightly from the methods and values provided in IEEE-450 Standard. Licenseepersonnel stated that the battery testing method and the 'k' factors had not been revisedwhen Updated Final Safety Analysis Report commitments were revised to include theIEEE-450 Standard. The licensee initiated Condition Report 2007-2484 to revise thebattery testing procedures to incorporate IEEE-450 Standard guidance. As part of the station blackout reviews, the team included a review of the offsite powersupply system to ensure that an instability on one of the systems (345 or 161 kV) wouldnot result in the loss of the other system. The team also reviewed battery systems forboth switch yards to verify that maintenance and testing was being conducted. Theteam performed inspections of both batteries to evaluate their physical condition. b.FindingsNo findings of significance were identified. b.10.High Pressure Core Injection Motor-Operated Valve HCV-312 a.Inspection ScopeThe team reviewed the schematic diagrams for Motor-Operated Valve HCV-312 to verifythat the actuation and interlock functions discussed in design documentation wereappropriately incorporated into the circuitry. The team reviewed the informationcollected by the licensee during their physical inspections of the motor-operated valveand its power supply system and verified that findings had been adequately addressed. The team included a review of the fuse program and verified that the fuse list specifiedthe appropriate type and size of the fuses used in the control circuitry. The team also

-25-Enclosureverified that the motor's overload protection feature was bypassed except when theactuator was being tested. As part of the evaluation of Valve HCV-312, the team reviewed the degraded voltageanalysis and related motor-operated valve calculations to ensure that the actuator motorwould be able to produce adequate torque at degraded voltage levels to operate thevalve. b.FindingsNo findings of significance were identified.4OTHER ACTIVITIES

4OA3Event Followup(Closed) Unresolved Item 05000285/2005-009-01 Use of non safety-related componentsin the raw water system pump discharge strainers. This issue is addressed inSection 1R21.b.3 of this report.4OA5 Other(Closed) Use of Non Safety-Related Components in the Raw Water System PumpDischarge Strainers (Unresolved Item 05000285/2005009-01)This unresolved item is discussed in Section 1R21.b.3 of this report and closed toFinding 05000285/2007007-03, NCV-Failure to Translate Regulatory Requirements andDesign Basis to Equipment Required to Support the Raw Water System.

4OA6Meetings, Including ExitOn July 25, 2007, the team leader presented the preliminary inspection results toMr. Jeff Reinhart, Site Director, and other members of the licensee's staff. The licenseeacknowledged the findings during each meeting. On September 7, 2007, the teamleader discussed the inspection results with Mr. Matzke. While some proprietaryinformation was reviewed during this inspection, no proprietary information was includedin this report.Attachments: 1. Supplemental Information 2. DC Transfer Switches 3. Diesel Generator Minimum DC Voltage for Field Flashing, June 12, 2007 4. FCS Position on emergency diesel generator Field Flash Voltage 5. Initial Information Request

Attachment 1-1-SUPPLEMENTAL INFORMATIONKEY POINTS OF CONTACTLicensee PersonnelS. Anderson, Supervisor, DEN - MechanicalS. Baughn, Supervisor, Reactor Performance Analysis D. Bannister, Plant ManagerG. Cavanaugh, Supervisor, Regulatory ComplianceR. Clemens, Division Manager, Nuclear Engineering DivisionM. Core, Manager, System EngineeringH. Faulhaber, Division Manager, Nuclear Asset ManagementM. Ferm, Manager, Shift OperationsM. Frans, Manager, QualityD. Guinn, Licensing Engineer J. Herman, Manager, Engineering ProgramsJ. Jacobsen, Design Engineering J. Johnson, ECC Systems Engineer D. Lakin, Manager, Corrective Action ProgramT. Matthews, Supervisor, Nuclear Licensing E. Matzke, Compliance Engineer J. McManis, Manager, Licensing D. Pier, Operation Engineering - OperationsS. Miller, Supervisor, System Engineering R. Mueller, Supervisor, Electrical / I&C EngineeringM. Puckett, Work ManagementJ. Reinhart, Site ManagerJ. Skiles, Manager, Design Engineering C. Sterba, Supervisor, Design EngineeringS. Swearngin, Supervisor, Design Engineering - MechanicalD. Taylor, Engineering, Design Engineering - Mechanical R. Westcott, Manager, Quality J. Zagata, Engineering ProgramsNRC personnelD. Powers, Acting Branch Chief, Engineering Branch 1L. Willoughby, Acting Senior Resident InspectorLIST OF ITEMS OPENED, CLOSED, AND DISCUSSEDOpened and Closed05000285/2007007-01 NCV Inadequate Abnormal Operating Procedure for Loss-of-Component Cooling Water(Section 1R21.b.1)

Attachment 1-2-05000285/2007007-02NCV Failure to Analyze Impact of Heat Loading in SafetyInjection Pump Room 21 from the Start of a Third HighPressure Safety Injection Pump(Section 1R21.b.2)05000285/2007007-03NCVFailure to Translate Regulatory Requirements and DesignBasis to Equipment Required to Support the Raw WaterSystem - Unresolved Item 05000285/2005009-01(Section 1R21.b.3)05000285/2007007-04NCV Inadequate Corrective Actions for the Turbine DrivenAuxiliary Feedwater Keep Warm Line Bypass ThrottleValves MS-366 and -368(Section 1R21.b.4)05000285/2007007-05NCV Failure to Meet Single Failure Criteria Configuration forComponent Isolation Valves (Section 1R21.b.5)05000285/2007007-06DEVFailure to Install Temperature Monitoring(Section 1R21.b.6)

Opened05000285/2007007-07URISafety Injection Refueling Water Tank Vortexing(Section 1R21.b.7) Closed05000285/2005-009-01URIUse of Non-safety-related Components in the Raw WaterSystem Pump Discharge Strainers (Section 4OA5)LIST OF DOCUMENTS REVIEWEDAction Requests

199701532 199800284 199802335 199902722 200000127 200001220 200103349 200201089 200201182 200201930 200302653 200302694 200304924 200400846 200401345 200501228 200501804 200501955 200502017 200502771 200502867 200503018 200503169 200503746 200504001 200504287 200504287 200504328 200504346 200504740 200505027 200505030 200505207 200505795 200505897 200600508 200600613 200600630 200600860 200601319 200603222 200604605 200604647 200604756 200604989 200605139 200605663 200605721 200605723 200606038 200700613 200700662 200700892 200701130 200701942 200702013 200702208 200702268 200702270 200702281 200702304 200702309 200702381 200702470 200702489 200702533 200702753 200702917

Attachment 1-3-CalculationsNumberTitleRevision/DateFC-05038Evaluation of Stroke Time on Valves HCV-480, -481,-482, -483, -484, -4852 (11/22/06)FC-05872HPSI Header Isolation MOVs (HCV-311, -314, -317,-320, and HCV-312, -315, -318, and -321)0 (2/13/92)FC-05455ECCS Pump NPSH and 383-Series Valve StrokeTimes 0FC-85-25-003Ampacity Derating to be Applied Due to FireWrapping02/04/86FC-90-057Updated Degraded Voltage Calc 4160V/480V7FC-03-026Period[ic] Evaluation of the Offsite PowerRequirements

1FC04990Feeder Cable Derating Due to Fire Wrapping12/27/91FC05690Battery Load Profile and Voltage Drop Calculation 6FC05829MOV Degraded Voltage Calculation10FC05876Analysis of MOV Torque/Thrust15FC06096[MOV} Contactor Pickup and Holding Voltage6FCO5455ECCS Pump NPSH and 383 Series Valve StrokeTimes 3FC05384Min Performance Curves for HPSI, LPSI and CS1FC07076Safety Injection and Containment Spray System,Proto Flow, Model Development

8FC07077Safety Injection Phase performance for ContainmentSpray and safety injection Pumps, 1FC070078circulation Phase Plant System PerformanceforSafety Injection and Containment Spray Systems

1FC05384Minimum Pump Performance Curves for HPSI, LPSIand CS Pumps

1FC08839Containment Minimum Performance Requirements2

Attachment 1-4-FC06642, Uncertainty Calculations to support ISI Testing,2HPSI Safety Injection Phase Performance for SafetyInjection Containment Spray Systems

1FC06747safety injection Pump Room (21 and 22) Heat-upduring pump operation, Computer Analysis

3FC06941LPSI Critical Void Size and Operator Action Time1FC06904Category 1 Air Operated Valve Operator MarginAnalysis 2FC05876Evaluation of MOV Degraded Voltage, NED-DEN-06-0087 0FC00284Variable Setpoints for PORV Actuation0FC05038Evaluation of Stroke Time on Valves on HCV-480, 481-483, 485 2FC05561CCW Relief Valve Setpoints2FC05692Minimum NPSHA Calculation for CCW Pumps3FC05729High Pressurizer Pressure Setpoint Calculation1FC06156PORV Loop Seal Condensation Flow Rate0FC06227Post-RAS Containment Heat Removal by ShutdownCooling Heat Exchangers and Containment Air Coolers

1FC06621Containment Air Cooler Thermal Hydraulic Analysis forAccident with LOOP

1FC06700NPSH for Single Operation CCW Pump0EA-96-055Overpressurization of CCW System0FC07217Fort Calhoun Element Drive Mechanism ComponentCooling Water Supply Flow Rates

0FC06604Bearing Cooling Water Flow BalanceBFC-05045FW-10 Steam Line HELB1

Attachment 1-5-MR-FC-89-81FW-10 Steam Supply Line Break Protection, throttlevalves recommended.2/4/1992EA-FC-92-030Seismic Classification of SER system4/22/1992FC-03109Auxiliary Feedwater

Seismic calcul

ations 1/22/1985FC-06174Required Coping Duration for Station Blackout2/28/2000EA-FC-03-004Long Term Core Cooling Verification0EA-FC-89-023Electrical Equipment Qualification analysis2FC-05928SIRW Tank Level (RAS)6/19/1992FC-05659Development of Flow Coefficients for the Raw Waterand CCW system analysis.

1FC-05888Raw Water Flows to the CCW heat exchangers1FC-06273Raw water flows to CCW HEX based on pumpperformance

0FC-01438Air Accumulator Capacity for IA-411FC-04280Verification of Air Accumulator bubbler Flowrates0FC-06277SIRWT Level Indication Total Loop Uncertainty(TLU) Calculation

2FC-06679Raw Water Strainer Resistance for Winter RiverTemperatures

0AC-12ASEWSScreening Evaluation Work Sheet, Motor drivenStrainer Seismic capacity vs demand 10/21/1994FC-07259FCS RW/CCW GOTHIC model- cases8Design Bases DocumentsNumberTitleRevision/DateSDBD-AC-RW-101Raw Water30SDBD-CA-IA-105Instrument Air26

Attachment 1-6-SDBD-AC-CCW-100Component Cooling Water38MR-FC-97-007Final Design Issue0SDBD-AC-RW-101Raw Water Design Basis Document30PED-FC-92-1827MR-FC-89-081 "FW-10 Steam Supply lineBreak Protection2/4/1992.EA-FC-96-042HELB Steam Migration From Room 81 viaDuctwork11/21/1996SDBD-AC-CCW-100Component Cooling Water Design Basis

Document 37SDBD-AC-RW-101Raw Water Design Basis Document 28SDBD FW-AFW-117Auxiliary Feedw

ater Design Basis Document32USAR-9.7Auxiliary Systems Component Cooling WaterSystem 8USAR-9.8Auxiliary Systems Raw Water System15LER-92-0530GL 89-13, Service Water System Problems11/16/1992TBD-VIIITechnical Data Book, Equipment OperabilityGuidance 30DrawingsNumberTitleRevision/Date11405-M-100Raw Water Flow Diagram P&ID9111405-M-40, Sh 1Auxiliary Cool

ant Component Cooling SystemFlow Diagram P&ID

36E-23866-210-130,Sh 3Safety Injection and Containment Spray FlowDiagram P&ID

16Spec No. 16.04,Rev Sh 21864Sheet Electric Motor Operated Valves2Spec No. 55S2372A-1 Rev Sh 36188, Sheet Streamless Butterfly Valves, AllisChalmers 5

Attachment 1-7-2498-20-5-20," Wafer Style Butterfly Valve 150# Class withBettis T-316 Actuator

CSpec No 11.87,Sheet Safety Injection System Control Valves8273, 19

E-23866-210-130, .Sheet Cov., Composite Flow Diagram SI andCS Sys P&ID

39E-23866-210-130. ,Sheet 1, Safety Inj. And Cont. Spraiy Sys FlowDiagram 8912702, 35759,, Safety Injection Aux Bldg (SI) (IsometricDrawing)1111450-M-97 Sheet 2. Misc. HVAC Flow Diagram5A-6282SIRWT Vortex Arrestors011405-M-87Auxiliary Building V

entilation El 989', 0" FuelHandling Area

911405-M-45,Auxiliary Building

Ventilation, Sections andDetails, 1811045-M-2 Sh 1Auxiliary Buildi

ng Heating and V

entilation FlowDiagram P&ID

5711045-M-97 Sh2Misc HVAC Flow Diagram P&ID5

EM-871 Sh2I&C Equipment List (Damper Drawing)1711045-M-84 Aux Building Ventilation 971', 0" (SI Room)1435617 SI Isometric IC-70-A&C-SITs1035618SI Isometric IC-71 B&D SIT1035619SI Isometric IC-72 HCV 331 and 3331335759SI Piping Isometric7/28/7035620SI Isometric IC-73 HCV 329935621SI Isometric IC-74 HCV 3271035622SI Isometric IC-7510

Attachment 1-8-35623SI Isometric IC-76, 835624SI Isometric IC-77 HVC 327935625SI Isometric IC-79 HVC 329 & 3331034627SI Isometric IC-80 HVC 331923423ISI Isometric, SWIRT and Sump exit Piping8B120F11503, Sh. 1EDG Electrical Control Schematic 19B120F11503, Sh. 2EDG Electrical Panels Layout 21B120F11503, Sh. 1EDG Electrical Control Connections 13B120F14501, Sh. 1EDG Engine Control Schematic 6B120F15502, Sh. 1EDG AC and DC Distribution Panels10B120F15502, Sh. 2EDG AC and DC Distribution Panels10B120F15503, Sh. 1EDG Electrical Control Cabinets 19B120F15503, Sh. 2EDG Electrical Control Cabinets 21B120F15503, Sh. 3EDG Control Cabinets Full Line Diagram13B120F15509, Sh. 3EDG Field Flashing and Remote Start Control 21B-4280, Sh. 1Limit Switch and 43/SW Contact Development2D-841C&D Power Systems DischargeCharacteristics

1D-4097, Sh. 1CCW Low Pressure Schematic Diagram7D-4097, Sh. 6CCW Low Pressure Schematic Diagram5D-4665DG-1 Diesel Generator Connections One LineDiagram 5D-4666DG-2 Diesel Generator Connections One LineDiagram 5E-3335-1Substation No. 1251/3451 One Line Diagram10

Attachment 1-9-E-3335-2Substation No. 1251/3451 One Line Diagram11E-4027, Sh. 1Off-Site Power Low voltage Matrix A & B1344D302335Full Wave Static Exciter60223R0455, Sh. 4Bus 1A3 Lockout Circuit Schematic Diagram30223R0455, Sh. 6Bus 1A3 Power & Control Circuit Schematic30223R0455, Sh. 10Power & Control Schematic for EDG #1CB 70223R0456, Sh. 8Power & Control Schematic for EDG #2 CB 120223R0456, Sh. 23Power & Control Schematic for 480 BusFeeder CB

80223R0456, Sh. 26Power & Control Schematic for RCP 3D CB Rev. 8136B2432, Sh. 64160 Volt Circuit Breaker Control SwitchDevelopment

18136B2493, Sh. 3HElectrical Controls - PCS 412 & 4130136B2493, Sh. 65Elementary Diagram - PCS 412 23136B2493, Sh. 66Elementary Diagram - PCS 4132136B2493, Sh. 115Elementary Diagram - PCS 412 4136B2493, Sh. 116Elementary Diagram - PCS 413 4161F532, Sh. 2Main Breaker Control Schematic Diagram -4.16 kV 30161F532, Sh. 3Main Breaker Control Schematic Diagram -4.16 kV 32161F532, Sh. 3AMain Breaker Control Schematic Diagram -4.16 kV 29161F532, Sh. 5Main Breaker Control Schematic Diagram -4.16 kV 27161F532, Sh. 7Main Breaker Control Schematic Diagram -4.16 kV 28

Attachment 1-10-161F532, Sh. 10Main Breaker Control Schematic Diagram -4.16 kV 28161F532, Sh. 13Main Breaker Control Schematic Diagram -4.16 kV 29161F532, Sh. 17Main Breaker Control Schematic Diagram -4.16 kV 291111317Internal Circuit Breaker Schematic211405-E-14.16 kV Control Relay Connection Diagram4311405-E-34.16 kV One Line Diagram2111405-E-4, Sh. 1480 Volt MCC One Line Diagram3011405-E-5, Sh. 2480 Volt MCC One Line Diagram2911405-E-6, Sh. 1480 Volt MCC One Line Diagram7111405-E-7, Sh. 1480 Volt MCC One Line Diagram5411405-E-29, Sh. 3SI Valves Schematic Diagram2611405-E-29, Sh. 11Limitorque Valve Schematic - HCV-312 811405-E-360, Sh. 7DC Power Transfer Switches ControlSchematics

1120-12776AI-133A & 133B [EDG Control Panels] MaterialList 1935759SI Piping Isometric07/28/7011405-M-10, Sh. 2Auxiliary Coolant Component CoolingSystem Flow Diagram

1411405-M-42, Sh. 1Nitrogen, Hydrogen, Methane, Propane, andOxygen Gas Flow Diagram

9011405-M-5, Sh. 2Demineralized Water System Flow Diagram222374AC-2 Comp. Cooling Water Surge1136B2431, Sh. 26Electrical Diagram Electrical Control Valves &

Pumps 30

Attachment 1-11-136B2431, Sh. 3Electrical Control Valves and Pumps5B-4250, Sh. 285Cable Block Diagram, HCV-4850B-4250, Sh. 282Cable Block Diagram, HCV-4801303.165-M-01HCV-480/481 Instrument Air Upgrade2303.165-M-01HCV-480/481 Instrument Air Upgrade2B-4250, Sh. 283Cable Block Diagram HCV-4811136B2431, Sh. 2Electrical Control Valves and PumpsElementary Diagram

13136B2431, Sh. 25Electrical Diagram Electrical Control Valves and

Pumps 2911405-E-56, Sh. 8Auxiliary Coolant System Wiring Diagram2111405-E-148, Sh. 2Schematic, Auxiliary Cooling System10D-4097, Sh 6.AC Raw Water Interface Valves - SecondarySolenoid Valves and Pressure Switches WiringDiagrams 5136B2493, Sh. 65Electrical Control Valves and PumpsElementary Diagram

23136B2493, Sh. 3HElectrical Control Valves & Pumps028308Governor FW-10 Emergency Feedwater pump401128Governor Gear Box and Oil pumpA11405-M-252Flow Diagram Steam P&ID9811405-E-137 Wiring Diagram YCV-1045 FW-102611405-M-100Raw Water Flow Diagram91 11405-M-254Flow Diagram Condensate P&ID35NOD-Qp-31Operability Determination Process34PED-SEI-9Setpoint/tolerance Change and Review12OI-RW-1Raw Water System Normal Operation78

Attachment 1-12-STM 35System Training Manual Vol 35, Raw Water21STM 4System Training Manual Vol 4, AuxiliaryFeedwater system

35STM 8System Training Manual Vol8, ComponentCooling Water System

27E-23866-210-130Safety Injection and Containment Spray P&ID39Engineering ChangeNumberTitleRevision/DateEC 27584Isolation of Flow to Containment Coolers onFlow Interruption

0MR-FC-92-039RW/CCW Interface Valve Modification3MR-FC-97-007Correction of CCW System Deficiencies0

Attachment 1-13-Maintenance DocumentNumberTitleRevision/Date00177675Underground RW Piping Internal Inspection0100266504AC-1D, Performance Monitoring Test for CCW

HX 0100265456AC-1C, Performance Monitoring Test for CCW

HX 0100265455AC-1B, Performance Monitoring Test for CCW

HX 0100252620 01AFW pump FW-10 Operability Test01/25/07253665 01Instrument Air Accumulator Check valve Test 11/15/06248269 01Operability Test of IA-YCV 104512/03/0600265454AC-1A, Performance Monitoring Test for CCW

HX 0100180415 01AFW steam supply line check09/17/0400230114 01AFW steam supply line check04/28/0600253641 01AC-10D Raw Water Pump Quarterly inservicetest01/19/07IC-CP-01-FW-64Calibration of Back Pressure Trip Device onAFW FW-10 3IC-CP-07-0001Calibration of Pressure Gauges9IC-CP-01-0923Calibration of AFW pump FW-10 steam inletlow pressure switch PS-923

2OP-ST-AFW-0005Auxiliary Feedwater Steam Supply line Check3OP-ST-RW-3031AC-10D Raw Water Pump Quarterly in-servicetest 4OP-PM-AFW-001AFW flow path verification9FW-AFWPMPMaintenance Rule Data05/24/07

Attachment 1-14-OP-ST-AFW-004AFW FW-10 Operability test4IC-ST-AFW-3002Instrument Air Accumulator check valveoperability Test

4IC-ST-IA-3001Surveillance Test, SIRWT air accumulatorcheck valve leakage test

7IC-ST-SI-0002Channel Calibration of SIRWT low levelmonitoring switches, Loops A, B, C and D/l-

383 7MR 0113FCS Maintenance Rule Functional ScopingData Sheet, (ACS RWSTRN), Raw waterstrainer 700251929 01SIRWT air Accumulator Check01/17/07IC-ST-SI-002Channel Calibration of SIRWT Low LevelMonitoring Switches

4SE-EQT-MX-0002Equipment Test Procedure, Carbon Steel &alloy steel fasteners in-service test refuelinginspections

8ManualsNumberTitleRevision/DateTD A391.0090Anchor Darling 20" Butterfly Valve with GH BettisT3165 OperatorTD 237. 0310Bettis Nuclear Series Vendor Manual0TD 237.0300Bettis Operating Manual and Instructions NT3.And NT4, OSTM30Reactor Protective System Systems TrainingManual, Reactor Protective System DiverseScram SystemVol 38TD C173.0020C&D Battery Installation and OperatingInstructions

4TD C173.0030Specifications for C&D LCR Lead CalciumBatteries 4TD C490.0370ABB Vacuum Replacement Breakers 0

Attachment 1-15-TD G080.2800Static Exciter Regulator for AC Generators1ModificationsNumberTitleRevision/DateEC 27405Low Pressure Safety Injection Void Detection10EC 36972LPSI Header Jockey Pump0DCR-10982Aux Building Ventilation after SIAS of SI PuimpRoom CoolingTM-96-42CCW Surge Tank Relief Valve Setpoint an CCWSystem Thermal Relief Valve Gagging

0Operator Training ScenariosSimulator Scenario, Main Steam Line Break & Loss-of-Component Cooling WaterSimulator Scenario, Large Break Loss-of-Cooling Accident (Premature RAS)Simulator Scenario, Reactor Cooling System Leak to CCW SystemSimulator Scenario, MSLB Outside Containment & SBO (AFW failed to start, loss of IA)Simulator Scenario, Loss-of-Raw Water System at PowerIn-plant exercise AOP-18 "Loss of Raw Water."In-plant exercise Initiate Air Compressor Backup CoolingIn-Plant exercise Minimizing DC Loads.Performance Training Checklist, Local slow start of FW-10ProceduresNumberTitleRevision/DateSO-G-23Surveillance Test Program53EOP-03 Loss-of-Coolant Accident 11/22/06OI-ST-1 SI Normal operation102OI-DSS-1 Diverse Scram System (DSS), Normal operationOI-FH-3Refueling Water Transfer from Refueling Pool toSIRWT1/25/06EM-PM-EX-0200APreventative Maintenance 4160 V Circuit Breakers13EM-ST-EE-0005Battery No.1 Capacity Discharge Test15EM-ST-EE-0006Battery No. 2 Capacity Discharge Test13EOP-07Station Blackout11

Attachment 1-16-PED-EEI-2Instructions for Power Cable Sizing4PED-EWP-10Electrical Work Procedure - Cable Installation8 SO-M-100Standing Order - Conduct of Maintenance 43SO-M-101Standing Order - Maintenance Work Control72SP-CP-08-DEVAR-T1A1Calibration of Devar Relay for T1A1 9SP-CP-08-DEVAR-T1A2Calibration of Devar Relay for T1A2 10AOP-11Loss-of-Component Cooling Water11OI-CC-1Component Cooling System Normal Operation58

OP-ST-CCW-

3001AComponent Cooling Category B Valve Exercise Test 9OP-ST-CCW-

3005AComponent Cooling Category A and B Valve ExerciseTest 7OP-ST-RC-3004Power Operated Relief Valves (PORVs) LowTemperature Low Pressure Exercise Test (PCV-102-1and PCV-102-2)

24PED-EWP-10Electrical Work Procedure/ Cable Installation8QC-ST-CCW-

3001Component Cooling Water System Forty MonthInservice Test

0SE-ST-CCW-

3003Component Cooling Water Surge Tank Leakage Test10SO-G-30FCS Standing Order111IC-CP-01-0413Calibration of Component Cooling Water PressureControl Switch PCS-413

6IC-CP-01-0412Calibration of Component Cooling Water PressureControl Switch PCS-412

6NOD-QP-31Operability Determination Process34SO-G-74Fort Calhoun Station EOP/AOP Generation Program12PED-QP-3Calculation Preparation, Review, and Approval12OI-RC-2ARCS Fill and

Drain Operations54SO-0-1Conduct of Operations72AOP-17Loss-of-Instrument Air11AOP-20Loss-of-Bearing Water Cooling1AOP-18Loss-of-Raw Water6AOP-28Auxiliary Feedwater System Malfunctions12EOP-01Reactor Trip Recovery10EOP-12Functional recovery12

Attachment 1-17-TBD-AOPTechnical Basis Document -AOP1Surveillance Test ProceduresNumberTitleRevision/DateSE-ST-CCW-3003Component Cooling Water Surge Tank LeakageTest 10SE-ST-RW-3002Raw Water Pump Post Maintenance OperabilityTest 18OP-ST-RW-3011AC-10B Raw Water Pump Quarterly InserviceTest 30QC-ST-SI-3008Refueling High Pressure Safety Injection (HPSI)Leak Rate Determination

3OP-ST-SI-3007High Pressure Safety Injection System Pumpand Check Valve Test

22OP-ST-SI-3015Containment Sump Recirc Valves Exercise andPosition Verification Test

0OP-ST-SI-3001Safety Injection System Category A and B ValveExercise Test

32OP-ST-VX-3005AComponent Cooling Water Remote PositionIndicator Verification Surveillance Test

7OP-ST-CCW-

3001AComponent Cooling Category B Valve ExerciseTest 9OP-ST-CCW-

3001BComponent Cooling Category B Valve ExerciseTest 4OP-ST-SI-3002Safety injection System Category A, B, and CValve Exercise Test

25OP-ST-CEA- 2006CEA Rod Drop Test11/26/06OP-ST-CEA- 2006CEA Rod Drop Test12/2/06OP-ST-CEA- 2006CEA Rod Drop Test8/26/03OP-ST-CEA- 2006 CEA Rod Drop Test 4/17/05OP-ST-CEA- 2006CEA Rod Drop Test 5/30/05Test Data For The Following Pumps and Valves

Attachment 1-18-ComponentTest Type/FrequencyDates of TestsSI-2AQuarterly Differential Pressure and Flow TestsSince 11/09/04SI-2CQuarterly Differential Pressure and Flow TestsSince 02/17/05SI-2BQuarterly Differential Pressure and Flow TestsSince 11/09/04AC-10BQuarterly Flow and Vibration TestsSince 09/05/05AC-10CQuarterly Flow and Vibration TestsSince 09/05/05HCV-312Quarterly Open and Close Stroke Time TestsSince 09/05/05HCV-480 and -481Quarterly Open Stroke Time TestsSince 02/17/05HCV-345Cold Shutdown Open and Close Stroke TimeTestsSince 04/19/01HCV-344Refueling Outage Open and Close Stroke TimeTestsSince 05/24/02HCV-385 and -386Refueling Outage Open and Close Stroke TimeTestsSince 04/19/01LCV-383-1, -2, -3,and -4Refueling Outage Open and Close Stroke TimeTestsSince 07/24/98HCV-438A/B/C/DCold Shutdown Close Stroke TimeSince 02/24/05AC-391Quarterly Leak TestSince 01/28/05NG-113Quarterly Leak TestSince 01/28/05Work orderNumberTitleRevision/DateWO220640 D.G. Damper10/12/2005WO246656Periodic Evaluation of Offsite PowerRequirements12/23/03Miscellaneous DocumentsNumberTitleRevision/DateFort Calhoun Station Pump and Valve InserviceTesting Program Plan, 4

th Ten Year Interval ThroughSeptember 25, 2013Revision 3, dated06/09/06

Attachment 1-19-Pump Relief Request Number E-4 for ComponentCooling water Pumps AC-3A, -3b, -3C, and RawWater Pumps AC-10A, -10B, -10C, and -10DEngineering Assistance Request & Response(EAR)90-08911/19/92Engineering Assistance Request & Response (EAR)96-102August 27, 1996PED-N-89-243B, Evaluation of Valve Stroke Timesfor Safety Injection and Containment Spray SystemsJune 26, 1989PED-FC-1959, Stroke Time Limits for SpecifiedValvesMay 9, 1990PED-FC-90-1959, Stroke Time Limits for SpecifiedValvesJune 1, 1990Program Basis Document PBD-9, Relief ValveProgram 12Modification Request 97-007, Correction of CCWSystem deficienciesFebruary 11, 1997HPSI AOI risk assessment,5/3/2006IN 1994-036 Gas Accumulation in the RCSIN 2006-021 Air Entrainment into the ECCS and CS SystemsreviewPCR Minuteson CEDM 07-

007Continued Operations with an Inoperable CEA10CFR50.59 Screening - Action Item 11 of

CR199901103 OperabilityEvaluation Attachment to CR 200702441OPPD Letter:T. Short to H.VoigtApplication for Amendment,3/13/1978OPPD Letter:T. Short to H.Robert ReidRevision to Amendment Request,3/6/79OPPD Letter:W. Jones toRobert ReidAdditional information re license amendment,request9/6/79

Attachment 1-20-OPPD Letter:T. Short to H.VoigtResponse to Questions regarding LicenseAmendment,4/28/78NRC Safety Evaluation for Amendment 52,10/14/1980NRC Letter: W.Jones to R.Clark, Issuance of License Amendment 52, 10/14/80NRC Letter R.Clark to W.Jones, Amendment 52 to Facility Operati ng LicenseNRC Letter Issuance of Amendment 198 Re CharcoalAbsorbersNEI 96-04 Guidance of Managing NRC Commitment Changes,July 1999Journal of Fluid Mechanics,, Lubin and Springer,The Formation of a Dip on the Surface of a LiquidDraining from a Tank

,1967, volume 29part 2 pp 385-3909/1967Journal of the Hydraulics Division, ASCE, Jain, Rajuand Garde, Air Entrainment in radial flow towardsIntakes ,9/1976International Association for Hydraulic Research,Harleman, Morgan and Purple, Selective Withdrawalfrom a vertically Stratified Fluid

,8/1959 NRCInformationNotice, 2007-02Failure of Control Rod Drive Mechanism Lead ScrewMechanism Lead Screw Male Coupling at B&W

Designed Facility3/2007ABB Letter ABB 4kV Replacement Breakers - Control Voltage7/14/1995(Not Controlled) Fort Calhoun Fuse List7NED-DEN-06-

0087Evaluation of MOV Degraded Voltage (Not Dated)NFPA-70 National Electric Code2002 EditionS069126Purchase Order for C&D Batteries12/11/1991CID 910096/01Erosion Program for Component Cooling Water andRaw Water1/31/1992CID 910032/01Activities Related to Erosion Program for Raw Water(GL 89-13 Related)2/15/1991PED-SYE-90-

006JService Water System Problems Affecting Safety-Related Equipment1/4/1990

Attachment 1-21-PED-STE-91-

016Generic Letter 89-13 Lessons Learned Follow-upMeeting2/19/1991LIC-90-0050Response to Generic Letter 89-131/26/1990CID 900590/04Power-operated Relief Valve & Block Valve Reliability& Generic Issue 94, Additional Low TemperatureOverpressure Protection for Light Water Reactor11/18/1996TDB-VIIITechnical Data Book, Equipment OperabilityGuidance 30R06-AD-620NLO Requal Lesson Plan, AOP-20" loss-of-bearingcooling water".1/11/2007 00 NRCSimulator Scenario, MSLB & Loss-of-CCW001 NRCSimulator Scenario, Large Break Loca082105aSimulator Scenario, RCS Leak to CCW System482110Simulator Scenario, MSLB Outside Containment &

SBO 482111m NRC Simulator Scenario, Loss-of-Raw Water System atPower 7R07-SYS-11Lesson Plan, AOP-18 "Loss-of-Raw Water."6/11/2002TAP-12Training Administration Procedure, conduct of OJT254-20-8Lesson Plan, Emergency & abnormal operatingprocedures

2PTC-0047Performance Training Checklist, Equipment operatorNuclear-Auxiliary

3JPM-0225A Job Performance Measure, Initiate Air CompressorBackup Cooling

8OI-CA-5Operating Instruction, Instrument air system80PTC-0809Performance Training Checklist, Local start of FW-

54 7OI-RW-1Operating Instruction, Raw Water78PTC-0808Performance Training Checklist, Local slow start ofFW-10 5OI-AFW-4Operating Instruction, Auxiliary Feedwater System63

Attachment 1-22-PTC-0958APerformance Training Checklist, Minimizing DC

Loads 4JPM-0304Job Performance Measure, Minimizing DC Loads5

Attachment 2-1-DC Transfer Switches6/6/07DC Manual Transfer Switches - CDBI issueQUESTION: How are the DC manual transfer switches evaluated with respect to theAppendix R analysis?

RESPONSE:The switches are provided to align either a normal or emergency source of DC control powertothe plant switchgear (4160V and 480V). The switches are a break-before-make design.CQE(Class 1E) circuit breakers from each DC bus are provided for the normal and emergencypositions of the DC manual transfer switch. The breakers protect the bus(es) from a fault withinor associated with the switch. Therefore, for the case of a fire at the location of the transferswitch, a circuit fault and subsequent tripping of the DC bus circuit breaker is credited to occur. No specific analysis of the transfer switch is contained in the post-fire safe shutdown(PFSSD)analysis based on the methodology used by FCS. The methodology of the FCS post-fire safe shutdown analysis is to determine what equipment is necessary to safely achieveshutdown conditions following a postulated fire in any given fire area. Equipment location, cableand circuit routing, fire barrier location, fire hazards, fire suppression/detection are thendetermined for input into the analysis. In the case of these switches, the following assumptionsare made: * Only the normal alignment (power source) for the switch is credited. No credit isassumed for the emergency position for PFSSD.* The circuit break

ers protecting the feeder cable to each switch will trip to

protect thebus under faulted conditions.* For a fire in the fire area where the switch is located, the switch and power source isassumed to be lost. These DC manual transfer switches are not specifically evaluated in the post fire safe shutdownanalysis. The analysis assumes that circuits are protected by fault protection devices - circuitbreakers or fuses. The analysis does not evaluate every circuit within a given fire area,therefore there is no detailed evaluation of the location and function of these manual transferswitches with respect to post-fire safe shutdown (Appendix R). EA-FC-89-050, Associated Circuits Analysis, evaluated these switches and the associatedloads as acceptable with regards to multiple high impedance faults caused by a fire. FCS considers the methodology of the post-fire safe shutdown analysis to be appropriate anddoes not consider the location or function of these switches to be pertinent to the analysisbased on the fact that the switch is treated as a single power source, i.e. no switch function isnecessary. Response: David Buell - Fire Protection Program Engineer - x7316Inspector: Phil Wagner References: EA-FC-89-050, OP-ST-EE-0010, USAR 8.3, Fig 8.1-1 (file 12234), FC06355, EAFC-89-055, EA-FC-97-044

Attachment 3-1-Diesel Generator Minimum DC Voltage for Field Flashing June 12, 2007A question was raised regarding the minimum value of DC voltage that would be required at thediesel generator panels (AI-133A and AI-133B) to flash the field of the generators. GE drawing44D302335 File No. 6622 shows "125 VDC for flashing" at the input to the AI-133 cabinet. Ifthis value is not the minimum voltage required at these terminals then what is the minimum? (Note: the voltage in question is at location B2 of the drawing.)Engineering has researched this question and come to the conclusion that there is not a singlevalue of voltage that would be required to flash the field under all circumstances due tovariations in the residual magnetic flux of the generator rotor and variations in the assumedtemperature of the field windings. Field flashing is dependent on the magnetic flux emanatingfrom the generator rotor as the rotor spins within the stator windings. The magnetic flux isprovided by three separate mechanisms: a contribution from the residual magnetism of therotor core, a contribution from current flow from the station battery and a contribution fromcurrent flow from the generator stator output as voltage induced in the stator windings is fedback to the field through the exciter rectifiers.Many generators, including some generators at nuclear plants, do not use any external fieldvoltage to flash the field, but instead rely just on the residual magnetism in the rotor core iron. This residual magnetism is always present in iron core rotors but the strength of the magneticfield may vary depending on generator's condition, age and the amount of time that has passedsince the last operation of the generator. When the rotor spins inside the stator windings themagnetic flux from the residual magnetism induces voltage in the stator, and a portion of thestator output voltage is fed back to the excitation circuit. This stator AC voltage output isrectified by the exciter to DC voltage for the generator field. According to the generator opencircuit saturation curve, when the output of the generator stator is at about 25% of rated voltage,the output from the excitation transformer to the field winding would be 60 volts. This 60 volts isrectified by the exciter circuit and contributes 60 volts / 6.2 ohms = 9.6 amps of current flow (andtherefore additional flux) to the field. The generator manufacturer publishes a characteristicgenerator curve for the

FCS generator that shows that 10 amps of field current will produceapproximately 25% of full voltage output from the generator. This output voltage value iscontinually fed back to the exciter rectifier where it produces more and more field current untilfull voltage is achieved. The logical conclusion that can be reached is that even a small amountof residual magnetism will flash the field.Normally, station battery voltage is applied via the field flash relay (2CR) to the field flashresistors. These resistors are current limiting resistors with a value of 5.1 ohms total resistance. (Four resistors are arranged such that each of the two pair of 5.1 ohm resistors are in parallelwith each other and each pair is in series with the generator field as well as each other.) Thefield resistance is 1.3 ohms at 75 degrees C and 1.1 ohms at 25 degrees C. The addition of thefield flash current limiting resistance and the winding resistance is a total resistance of 6.2ohms. Normal field flash current (following a few time constants due to the inductive fieldcircuit) would be 125 volts / (1.1 + 5.1 ohms) = 20 amps. The normal field current causes thefield flash to occur in around one to two seconds. Lower levels of current may require longerperiods of time to achieve the same voltage output. The following query was sent to System Engineers at approximately 50 nuclear power plants inthe US via the Electro Motive Diesel Generator Owners Group (EMDOG):

Attachment 3-2-One of the questions being asked by the NRC is the minimum voltage required toflash the generator. We have searched our technical manuals and have notfound a value. Our generator is a General Motors Corporation, Electro-Motive Division model A-20-C2. Isthere anyone who has a value for minimum voltage required to flash the generator, or who cangive us guidance on how to calculate the value.Approximately 10 responses have been received. No other plants reported having been askedthis question about minimum field flash voltage during their CDBI inspection and no other plantshad values for the minimum field flash voltage required to flash their field. Several respondentsindicated that their diesels would flash at the minimum expected DC bus voltage, but norespondents indicated they had ever done any testing to verify this assumption. Severalrespondents indicated that they believed their diesels would flash on residual magnetism alone. One plant has an abnormal operating procedure for using a 12 volt car battery for flashing thefield in the event that the field does not flash from residual magnetism. Another plant indicatedthat the question of minimum field flash voltage may be in the realm of severe accidentmanagement guidelines rather than plant accident design basis. A need or requirement for FCS to determine the reduced DC voltage available for field flash hasnever been identified. The FCS degraded DC voltage calculations (FC05690) have determinedthat the minimum voltage expected at the diesel panels is 104.5 volts DC. The minimumvoltage required to operate the diesel field flash relays (which must operate to complete the fieldcircuit) has been determined to be 92 volts DC. If at least 92 volts DC is present at the AI-133

panels it is reasonable to a

ssume that the diesel field flash will occur.

Attachment 4-1-Fort Calhoun Station Position on Emergency Diesel Generator Field Flash VoltageFort Calhoun Station emergency diesel generator Flashing

The emergency diesel generator System Engineer was contacted at ANO. Unit 1 has an EMDdiesel and generator, approximately 2750 kW rate power. This is nearly identical to the FCSemergency diesel generator approximately 2700 kW rated power. ANO have a procedure to

start the diesel on residual magnetism and a surve

illance test to verify this.Unit 2 has an EPI generator and they have a procedure to use a backup field flash circuit of 24volts. We have a copy CR-2-99-0615 from ANO in a report and it states they have contactedthe EPI vendor and the generator would flash as low as 12 volts. Therefore, due to the similarities of the FCS diesel and the ANO Unit 1, FCS is confident thatthe diesel would flash using residual magnetism with no voltage applied. The FCS DegradedVoltage Calculation FC05690 has determined that the voltage at the end of 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> stationblackout scenario would result in a voltage of 104.5 volts at the diesel panel (i.e. field flashterminals) and would have enough voltage (104.5 volt margin) to successfully flash the field. Inaddition the 104.5 volts is greater than the pickup voltage of 92 volts for the field flash relay andthis would be more than adequate to start the generator automatically without taking manualaction. Joseph F. JacobsenNuclear Design Engineer (Dated 6/15/07)

Attachment 5-1-The team provided the following information request in writing to the licensee prior to theinspection.Initial Information RequestComponent Design Basis Inspection (71111.21)Fort Calhoun StationPlease provide the following information in order to support the NRC's component design basisinspection effort at your facility. If there are problems obtaining any of this information, pleasecall the Team Leader, Ronald Kopriva at (817) 860-8104 to discuss alternate arrangements. We would like to have the information ready when we arrive on site for the "bag-man" portion ofthe inspection on May 1, 2007.We prefer, but it's not required, that the information be provided electronically and in asearchable format, such as Adobe, Word, Word Perfect, or Excel. Other licensee's have foundthat providing the information on a CD is effective and efficient.1.The risk ranking of components from your site specific probabilistic safety analysissorted by Risk Achievement Worth and by Birnbaum Importance.2.A list of your top 500 cutsets from your probabilistic safety analysis.3.Risk ranking of operator actions from you site specific probabilistic safety analysis sortedby Risk Achievement Worth. Provide copies of your human reliability worksheets forthese items (you may limit this list to the 100 most risk significant actions).4.If you have an external events or fire probabilistic safety analysis model, provide theinformation requested in Items 1 and 2 for external events and fire.5.Any pre-existing evaluation or list of components and calculations with low designmargins (i.e. pumps closest to the design limit for flow or pressure, diesel generatorsclose to design required output, heat exchangers close to rated design heat removaletc.)6.For the last two years, a list of operating experience evaluations, modifications andcorrective actions sorted by component or system. A one line, or short, description isacceptable.7.A list of any common-cause failures of components in the last 5 years at your facility.8.A list of Maintenance Rule functions.

9.A list of your Maintenance Rule a(1) components.

10.A list of your current temporary modifications.

11.A current list of "operator work arounds."

12.Piping and instrument drawings for your emergency core cooling systems, emergencydiesel generators and off-site power supplies. At this time, only the mechanical pipingdrawings are needed for the emergency core cooling systems and the emergency dieselgenerators.

Attachment 5-2-In addition to the above, if available electronically, please provide a copy of each of thefollowing on CD.1.Final/Updated Safety Analysis Reports

2.Technical Specifications

3.Design Bases Documents for the emergency core cooling systems (including auxiliaryfeedwater), emergency diesel generators and off-site power supplies4.System descriptions or operator training manuals for the emergency core coolingsystems, emergency diesel generators and off-site power supply systemsThank you for your cooperation in these matters.