ML12104A267

Catawba Nuclear Station, Units 1 & 2 - Proposed Alternative Request Number 11-CN-002 for the Third Ten-Year Inservice Inspection Interval Response to NRC Request for Additional Information

ML12104A267
Person / Time
Site:	Catawba
Issue date:	04/11/2012
From:	Morris J R Duke Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
11-CN-002, TAC ME7182, TAC ME7187
Download: ML12104A267 (8)

Text

Duke JAMES R. MORRISVice PresidentDuke EnergyCatawba Nuclear Station4800 Concord RoadYork, SC 29745803-701-4251803-701-3221 faxApril 11, 2012 10 CFR 50.55aU.S. Nuclear Regulatory CommissionAttention: Document Control DeskWashington, DC 20555-0001

Subject:

Duke Energy Carolinas, LLC (Duke Energy)Catawba Nuclear Station, Units 1 and 2Docket Numbers 50-413 and 50-414Proposed Alternative Request Number 11-CN-002 for the Third Ten-YearInservice Inspection IntervalResponse to NRC Request for Additional Information(TAC Nos. ME7182 through ME7187)

Reference:

Letter from Duke Energy to NRC dated September 13, 2011The reference letter requested NRC approval of proposed alternative testing for the remainderof the third ten-year inservice inspection interval at the Catawba Nuclear Station. On March 1,2012, Requests for Additional Information (RAis) were electronically received from the NRC.The purpose of this letter is to formally respond to these RAIs. The attachment to this lettercontains Duke Energy's response. The format of the response is to restate each RAI question,followed by the response.This submittal document contains no regulatory commitments.If there are any questions or if additional information is needed, please contact L.J. Rudy at(803) 701-3084.Very truly yours,James R. MorrisAttachmentwww. duke-energy. corn U.S. Nuclear Regulatory CommissionPage 2April 11, 2012xc (with attachment):V.M. McCreeRegional AdministratorU.S. Nuclear Regulatory Commission -Region IIMarquis One Tower245 Peachtree Center Ave., NE Suite 1200Atlanta, GA 30303-1257G.A. Hutto, IIINRC Senior Resident InspectorU.S. Nuclear Regulatory CommissionCatawba Nuclear StationJ.H. Thompson (addressee only)NRC Project Manager (Catawba Nuclear Station)U.S. Nuclear Regulatory CommissionMail Stop 0-8 G9AWashington, DC 20555-0001 ATTACHMENTRESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATIONREQUEST FOR RELIEF 11-CN-002 OFFICE OF NUCLEAR REACTOR REGULATIONREQUEST FOR ADDITIONAL INFORMATIONRELIEF REQUEST 11-CN-002PROPOSED ALTERNATIVE REQUEST NUMBER 11 -CN-002 FOR THETHIRD TEN-YEAR INSERVICE INSPECTION INTERVALDUKE ENERGY CAROLINAS, LLCCATAWBA NUCLEAR STATION, UNITS 1 AND 2DOCKET NOS. 50-413 AND 50-414By letter dated September 13, 2011, Duke Energy Carolina, LLC (the licensee) submitted ReliefRequest (RR) 1 1-CN-002, "Proposed Alternative Request Number 11-CN-002 for the Third Ten-Year Inservice Inspection Interval" (Agencywide Documents Access and Management System(ADAMS) Accession No. ML1 1264A028) to the U.S. Nuclear Regulatory Commission (NRC) forreview and approval. In the subject RR, the licensee proposed alternative pressure testing forthe American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code(Code) Class 1 piping and component segments connected to (or part of) the reactor coolantsystem (RCS) in lieu of requirements of the ASME Code,Section XI, pressure testing. Theproposed alternative is requested for the remainder of the third 10-year in service inspection(ISI) interval of Catawba 1 (which commenced on June 29, 2005, and will end on July 14, 2014)and Catawba 2 (which commenced on October 15, 2005, and will end on August 19, 2016).The NRC staff has reviewed the information provided by the licensee in RR 11-CN-002 andfinds the following additional information is needed to complete its review.1. RR 11 -CN-002 documented that the design pressure for piping and components inSegments 1, 2, 3, 4, and 5 is 2500 psig, while the section titled "Proposed Alternative"states that a system leakage test will be performed at a pressure not less than 300 psigfor Segments 1, 2, and 5 and not less than 42 psig for Segment 3. The NRC staff notesthat the section titled "Bases for the Proposed Alternative" states, "The proposed systemleakage test conducted at a pressure of at least 300 psig (Segments 1, 2 and 5) and atleast 42 psig (Segment 3) is acceptable because leakage (if it were to occur) would stillbe detectable at this reduced pressure, although at a reduced rate."a. Provide the maximum pressure that the subject piping and piping components forSegments 1, 2, 3, 4, and 5 would experience during normal operating, stagnant,accident, and fault conditions.Duke Energy Response:Area Normal Stagnant11' Accident(2) FaultOperating*1) (psig) (psig) Conditions(2)(psig) (psig)Segment 1 2235 2235 2235 2235Segment 2 2235 2235 385 385Segment 3 2235 2235 1845 1845Segment 4 2235 2235 (see footnote (see footnote3) 3)Segment 5 2235 2235 2485 2485(1) Maximum pressure assuming leakage from first isolation valve offthe RCS.(2) Maximum pressure assuming segment is placed in service underaccident or faulted condition.1 (3) The segment 4 valves remain closed during accident operation;therefore, accident and fault pressure are not applicable to thesesegments.b. In light of the documented design pressure of 2500 psig for Segments 1, 2, 3, 4,and 5, and maximum pressures (identified in the response to RAI question la),provide justification for performing a system leakage test at such a reducedpressure to ensure the structural integrity of the system.Duke Energy Response:Nondestructive Examination (NDE) has been performed on selected welds inpiping segments 1, 2, 3, 4, and 5 as required by the ASME Code.In addition, the Boric Acid Corrosion Control program would detect evidence ofany leakage during the previous operating cycle by identifying boron deposits onthe outside surface of the components within these piping segments.Performing the system leakage tests at the proposed reduced test pressures isacceptable because leakage, if it were to occur, would be detected at the reducedpressures, although at a reduced leakage rate. This position is consistent withthe basis documented in the Safety Evaluation Report for Relief Request 04-CN-004 (ADAMS Accession No. ML051780164).For the above reasons, Duke Energy maintains that the proposed alternative toconduct the system leakage testing at the reduced pressures provides anacceptable level of assurance of the leak-tight and structural integrity of pipingsegments 1, 2, 3, 4, and 5.2. On pages 8 and 9 of the subject RR, several related industry RRs are cited. Discusswhether during the second (previous) 10-year ISI interval of Catawba 1 and 2, a RR forpressure testing requirements was submitted to the NRC staff for the same piping andpiping components of Segments 1, 2, 3, 4, and 5.Duke Energy Response:Duke Energy submitted and received approval to use Relief Request 04-CN-004 for sevenpiping segments during the 2nd 10-year interval as documented in a Safety Evaluationdated June 23, 2005 (ADAMS Accession No. ML051780164). Five of the seven pipingsegments listed in Relief Request 04-CN-004 are similar to those listed in Relief Request11-CN-002. Duke Energy has determined that relief is not needed during the 3rd 10-yearinterval for the other two segments identified in Relief Request 04-CN-004.3. Are there any welded connections in piping and components for Segments 1, 2, 3, 4,and 5? If the answer is yes, provide number and type (e.g., full penetration butt weldand fillet weld) of welds. Discuss any nondestructive examinations (NDEs) that wereperformed on the welded connections. Discuss any industry or plant-specific operatingexperience regarding potential degradation (e.g, fatigue, stress corrosion cracking,overloading, and corrosion) of welds in piping and components for the subject segments.Duke Energy Response:The answer to question 3 is "Yes". The table below provides the number of welds, type2 of welds, and type of NDE listed in the ISI Plan for the welds.Area Dwg Unit No. of No. of Type of Weld NDE PerformedWelds in WeldsSegment ExaminedSeg# 1 CN-1554-1.0 1 22 7 Socket SurfaceCN-2554-1.0 2 24 7 Socket SurfaceSeg# 2 CN-1561-1.0 1 12 3 Butt Surface & Volumetric3 0 Socket ExemptCN-2561-1.0 2 16 3 Butt Surface & VolumetricCN-1561-1.1 1 15 3 Butt Surface & VolumetricCN-2561-1.1 2 15 4 Butt Surface & VolumetricSeg# 3 CN-1562-1.0 1 16 4 Socket SurfaceCN-2562-1.0 2 18 5 Socket SurfaceSeg# 4 CN-1 553-1.0 1 36 7 Socket Surface2 0 Butt None SelectedCN-2553-1.0 2 28 8 Socket Surface2 2 Butt SurfaceSeg# 5 CN-1553-1.1 1 10 0 Socket ExemptCN-2553-1.1 2 10 0 Socket ExemptThe recordable indication identified in one weld of a stagnant portion of the safetyinjection system (see OE on corrosion) was not in any of the piping segments listed inRelief Request 11-CN-002.Duke Energy Response Regarding OE on Corrosion:Duke Energy recognizes there is potential for stress corrosion cracking to occur giventhe operating conditions of systems containing borated water and stainless steelmaterials. Stress corrosion cracking was identified during inservice inspection duringthe Catawba lEOC18 refueling outage in 2009. A recordable indication was identified inone weld of a stagnant portion of the safety injection system by ultrasonic examination.The flaw was ID connected and located in the heat affected zone of the butt weld that hadbeen repaired during construction. The flaw was determined to be the result ofintergranular stress corrosion cracking of the stainless steel material.Ultrasonic examinations were performed on 36 additional welds located in stagnantportions of the safety injection system during the lEOC18 outage. No additionalrecordable indications were identified. Additionally, a review of the construction historyfor welds on Catawba Units 1 and 2 located in the stagnant portions of safety injectionpiping located inside containment was performed to determine which welds had beenrepaired. Ultrasonic examinations were performed during the next refueling outage on37 butt welds for Unit I and 44 butt welds for Unit 2 which had a history of repair. Norecordable indications were identified as a result of these subsequent examinations.3 Other than the single indication identified in the safety injection system, CatawbaNuclear Station has not detected evidence of stress corrosion cracking or othercorrosion degradation in borated water systems containing stainless steel welds orstainless steel piping.Duke Energy Response Regarding OE on Fatigue and Overloading:A search of the database of Duke Energy's Corrective Action Program2 and IndustryOperating Experience3 related to thermal fatigue failures and overloading1 revealed nosite-specific leakages attributable to thermal or vibration fatigue for the subject pipingsegments. However, Duke Energy acknowledges there have been 1) industry fatiguefailures in non-isolable portions of branch lines off the RCS due to thermal stratificationcycling and 2) thermal fatigue failures in RHR system mixing tees; Duke Energy ismanaging these per EPRI MRP-146/MRP-192 guidelines, respectively. However, thepiping segments in Relief Request 11-CN-002 are not within the scope of piping affectedby these guidelines.Footnotes:1. It is assumed that the term "overloading" in the RAI refers to any known pastidentified loadings that fell outside the bounds of the original analysis and design,such as cyclic loadings due to thermal stratification.2. Duke Energy's Corrective Action Program (Problem Investigation Process or PIP) asadministered through Nuclear Policy Manual Directive NSD 208.3. Industry Operating Experience as related to thermal fatigue failures is taken fromEPRI document MRP-85 "Operating Experience Regarding Thermal Fatigue of PipingConnected to PWR Reactor Coolant Systems".4. NRC Information Notice (IN) 2011-04, "Contaminants and Stagnant Conditions AffectingStress Corrosion Cracking [SCC] in Stainless Steel Piping in Pressurized waterReactors," (ADAMS Accession No. ML103410363), discusses potential SCC in stainlesssteel piping. Discuss the potential for SCC in piping and piping components forSegments 1, 2, 3, 4, and 5.Duke Energy Response:Duke Energy recognizes there is potential for stress corrosion cracking to occur in thepiping and piping components for Segments 1, 2, 3, 4, and 5, due to the operatingconditions of each system and the stainless steel materials present. However, controlsexist to prevent stress corrosion cracking of these segments of piping by controlling theenvironment and substances which cause stress corrosion cracking of stainless steelmaterials. Additionally, system leakage tests and walkdowns looking for evidence ofleakage inside containment are performed every refueling outage. If evidence of leakageis detected, actions are taken to identify the source of leakage and resolve the cause.NRC Information Notice (IN) 2011-04 has been distributed to both the Catawba and DukeEnergy Nuclear fleet Boric Acid Corrosion Program engineers for awareness. Catawbahas also implemented the NEI 03-08 good practice recommendation documented inPWROG Letter OG-10-436 dated December 20, 2010 and PA-MSC-0563. This goodpractice ensured a consistent and minimum level of awareness was communicated to theplant staff regarding the stainless steel outside diameter stress corrosion cracking4

.Ievents that have occurred in the industry.5. ASME Code Case N-731, "Alternative Class 1 System Leakage Test PressureRequirements," approved for use in Regulatory Guide (RG) 1.147, Rev. 16 (ADAMSAccession No. ML101800536), provides an acceptable alternative to existing provisionsof the ASME Code, Section X1. Discuss whether piping and piping components forSegments 1, 2, 3, 4, and 5 for which relief is requested, meet the requirements of ASMECode Case N-731.Duke Energy Response:Code Case N-731 allows Class 1 system leakage test pressure requirements to belowered for portions of Class I safety injection systems where the portions arecontinuously pressurized during an operating cycle to a lower pressure than thatpressure currently required by IWB-5221(a). Code Case N-731 does not apply to thesegments listed in Relief Request 11 -CN-002 because those segments are either not partof the safety injection system or are not continuously pressurized during plant operation.5