ML13032A009

San Onofre Nuclear Generating Station, Unit 2, Response to Request for Additional Information (RAI 14) Regarding Confirmatory Action Letter Response (TAC No. Me 9727)

ML13032A009
Person / Time
Site:	San Onofre
Issue date:	01/29/2013
From:	St.Onge R J Southern California Edison Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC ME9727
Download: ML13032A009 (8)

Text

SOUTHERN CALIFORNIA Richard 1. St. OngeE DISON Director, Nuclear Regulatory Affairs and-D Emergency PlanningAn EDISON INTERNATIONAL Company10 CFR 50.4January 29, 2013U.S. Nuclear Regulatory CommissionATTN: Document Control DeskWashington, DC 20555-0001Subject: Docket No. 50-361Response to Request for Additional Information (RAI 14)Regarding Confirmatory Action Letter Response(TAC No. ME 9727)San Onofre Nuclear Generating Station, Unit 2References: 1. Letter from Mr. Elmo E. Collins (USNRC) to Mr. Peter T. Dietrich (SCE), datedMarch 27, 2012, Confirmatory Action Letter 4-12-001, San Onofre NuclearGenerating Station, Units 2 and 3, Commitments to Address Steam GeneratorTube Degradation2. Letter from Mr. Peter T. Dietrich (SCE) to Mr. Elmo E. Collins (USNRC), datedOctober 3, 2012, Confirmatory Action Letter -Actions to Address SteamGenerator Tube Degradation, San Onofre Nuclear Generating Station, Unit 23. Letter from Mr. James R. Hall (USNRC) to Mr. Peter T. Dietrich (SCE), datedDecember 26, 2012, Request for Additional Information Regarding Responseto Confirmatory Action Letter, San Onofre Nuclear Generating Station, Unit 2Dear Sir or Madam,On March 27, 2012, the Nuclear Regulatory Commission (NRC) issued a Confirmatory ActionLetter (CAL) (Reference 1) to Southern California Edison (SCE) describing actions that the NRCand SCE agreed would be completed to address issues identified in the steam generator tubesof San Onofre Nuclear Generating Station (SONGS) Units 2 and 3. In a letter to the NRC datedOctober 3, 2012 (Reference 2), SCE reported completion of the Unit 2 CAL actions andincluded a Return to Service Report (RTSR) that provided details of their completion.By letter dated December 26, 2012 (Reference 3), the NRC issued Requests for AdditionalInformation (RAIs) regarding the CAL response. Enclosure 1 of this letter provides theresponse to RAI 14.S etA0P.O. Box 128 K9San Clemente, CA 92672 Document Control Desk-2-January 29, 2013There are no new regulatory commitments contained in this letter. If you have any questions orrequire additional information, please call me at (949) 368-6240.Sincerely,Enclosures:1. Response to RAI 14cc: E. E. Collins, Regional Administrator, NRC Region IVR. Hall, NRC Project Manager, SONGS Units 2 and 3G. G. Warnick, NRC Senior Resident Inspector, SONGS Units 2 and 3R. E. Lantz, Branch Chief, Division of Reactor Projects, NRC Region IV ENCLOSURE 1SOUTHERN CALIFORNIA EDISONRESPONSE TO REQUEST FOR ADDITIONAL INFORMATIONREGARDING RESPONSE TO CONFIRMATORY ACTION LETTERDOCKET NO. 50-361TAC NO. ME 9727Response to RAI 14Page 1 of 6 RAI 14Provide a summary disposition of the U2C1 7 calculations relative to the planned reduced-poweroperation.RESPONSE:The calculations pertinent to each of the evaluations covered under the responses to RAI 11,12, and 13 are included in their respective responses. Additional evaluations performed tosupport the planned reduced-power operation are summarized as follows.Mechanical Design EvaluationsAssessments of the reactor vessel internals (RVI) analyses, reactor coolant system (RCS)structural analyses, loss of coolant accident (LOCA) hydraulic blowdown loads analyses, andRCS natural circulation analyses of record (AOR) were completed. The assessmentsaddressed the range of power levels from 50% to 100%, and steam generator (SG) tubeplugging (SGTP) ratios from 0% to 8%. The results bound and support the planned operation ofUnit 2 at 70% power with approximately 3% SGTP.LOCA blowdown loads, fuel uplift forces, changes in RVI and fuel configuration, and RVIhydraulic loads were addressed to determine the continued validity of the RVI AOR to supportthe planned Unit 2 operating conditions. The LOCA blowdown loads calculated to support 50%power operation during SONGS Unit 3 Cycle 15 were evaluated and confirmed to bound theplanned Unit 2 operating conditions. Fuel uplift force decreases, due to reduction in power andSGTP, are negligible such that the resulting LOCA loads will not be affected and the AORremains valid for the planned Unit 2 operating conditions. The fuel configuration has beenassessed as having no effect on the existing AOR for seismic and LOCA events. Additionally,reduced power operation does not have an effect on the lateral loading on the RVI or fuel andcontinues to be valid for 70% power. The RVI hydraulic loads are not affected by operation at70% power. The AOR for RVI remains valid for the planned Unit 2 operating conditions.For RCS structural analyses, the AOR addresses the faulted load combination consisting ofnormal operation, safe shutdown earthquake, and pipe break loads. The hydraulic blowdown,cavity pressure, thrust, and jet impingement loads were determined to be bounded by thecurrent design basis analyses. The designs of all RCS components remain bounding for plantoperation between 50% and 100% power with up to 8% SGTP.The LOCA Hydraulic Blowdown Loads Analysis previously performed for the Unit 3 originalsteam generator (OSG) plant configuration for Cycle 15 operation at 50% power was evaluatedfor its applicability to the present replacement steam generator (RSG) plant configuration inUnit 2 over the 50% to 100% power range with SGTP ratios up to 8%. The Unit 3 Cycle 15analysis identified bounding initial values for the critical input parameters for the analysis,including 2300 psia for the maximum RCS pressure (per the U2C1 7 Reload Ground Rules),5330F for the minimum RCS cold leg temperature (TcOLD), 423,822 gpm for the maximum RCSflow rate, and an RCS hot leg temperature (THOT) which was computed from the TcOLD value andthe enthalpy rise at 50% power. The evaluation demonstrated that the planned Unit 2 restartconditions are bounded by the conditions used in the Unit 3 Cycle 15 analysis for 50% poweroperation and concluded that the analysis results are applicable for the planned Unit 2 operatingconditions.Page 2 of 6 The Reactor System Branch (RSB) 5-1 Natural Circulation analysis AOR was assessed forimpacts that would result from plant operation between 50% and 100% power with up to 8%SGTP. The assessment concluded that the changes in the 100% power initial conditions withup to 8% SGTP have an insignificant effect on the condensate water needed for an RSB 5-1natural circulation cooldown. The condensate requirement at 100% power operation boundsthe requirement at lower power levels. The planned reduced power operation with SGTP ratiosup to 8% will not affect the plant's ability to establish natural circulation.I&C Design EvaluationsThe Unit 2 instrumentation and control (I&C) systems were assessed for potential impacts fromplant operation at 70% power with SGTP ratios up to 8%. The potentially impacted systemsincluded the main steam, main feedwater, and steam generator blowdown flow instruments, thesteam generator narrow-range (NR) water level instruments, the plant protection system (PPS)setpoints, the steam bypass control system (SBCS), the digital feedwater control system(DFWCS), and the pressurizer level setpoint and RCS reference temperature (TREF) programs.The results of these assessments are summarized in the following paragraphs.Whenever the plant operates at reduced power (below 100% power), steam generatorsaturation pressure and temperature will be higher than the corresponding full-power values.This change in the steam generator conditions affects the process conditions at the sensors ofthe secondary-side instruments listed above. The transmitter scaling for these secondary-sideinstruments in Unit 2 was changed for Cycle 17 and is now based on the process conditions thatexist at 100% power with a full-power TCOLD of 550'F. The indicated value of the measuredparameter of each instrument is subject to a process measurement bias error whenever theprocess conditions at the sensor or transmitter deviate from the base calibration conditions.The consequences of the bias errors that will result from the planned reduced-power operationand increased SGTP during Unit 2 Cycle 17 were found to be acceptable in all cases. Noadditional transmitter rescaling or instrument recalibration is required.Main Steam Flow InstrumentsIndicated main steam flow at 70% power will be 2.07% less than actual main steam flowbecause of the higher steam density at the main steam venturis at 70% power compared to theventuri steam density assumed for main steam flow transmitter calibration. Steam pressure atthe main steam venturis increases as plant power decreases from 100%. The core operatinglimit supervisory system (COLSS) main steam flow algorithm does not include dynamicpressure compensation. The algorithm's main steam compressibility factor is fixed and is onlyaccurate at the main steam flow transmitter base calibration conditions (i.e., full-power withTcOLD at 550°F). The COLSS main steam secondary calorimetric result (MSBSCAL) will includea bias error that increases as reactor power diverges from 100% power (assuming thatcalibration to the ultrasonic flow measurement system is unavailable at the reduced powerlevel). The MSBSCAL function is not used by COLSS below 80% power. Main steam flow willnot be used for plant power measurement while Unit 2 operates at 70% power. The main steamflow signal is also provided to the DFWCS. The DFWCS is designed to automatically controlindicated steam generator water level at its setpoint, at plant power levels greater than 3%,using uncompensated main steam flow, main feedwater flow, and steam generator water levelas inputs. Operation at 70% power is bounded by the 3% design specification. The main steamflow density-related bias error will not adversely impact the DFWCS.Page 3 of 6 Main Feedwater Flow InstrumentsAt 70% power, indicated feedwater flow will be 1.75% less than actual flow because of thehigher liquid density at the feedwater venturis at 70% power compared to the venturi liquiddensity assumed for transmitter calibration. Since the COLSS feedwater flow algorithmcompensates for the density variation that creates this bias error, the feedwater secondarycalorimetric result (FWBSCAL) is not impacted by the error. The uncertainty in FWBSCALbecomes larger as power level drops as addressed in the response to RAI 12.Steam Generator Blowdown Flow InstrumentsAt 70% power, the indicated volumetric steam generator blowdown flow will be 0.41% less thanactual volumetric flow (assuming all other error contributors are zero) because of the higherliquid density at the blowdown orifice plates at 70% power compared to the orifice plate liquiddensity assumed for transmitter calibration. The calibrated range of the steam generatorblowdown flow indicators is 0 to 350 gpm. Steam generator blowdown flow is limited by theblowdown processing system design to approximately 275 gpm per steam generator. Normalflow is maintained within the range of approximately 200 to 250 gpm per steam generator. Withthe blowdown bypass system in service, steam generator blowdown flow is directed to the plantcirculating water discharge; maximum blowdown flow during this mode of operation is limited to200 gpm per steam generator. At these flow values, the 0.41% bias error at 70% powercorresponds to an indication error of approximately 1 gpm (indicated flow lower than actual flow)which will have no adverse impact on either blowdown processing system operation orblowdown bypass system operation. The blowdown flow parameter is an input to the COLSSsecondary calorimetric. The 0.41% error in blowdown flow (actual flow greater than indicatedflow) is approximately 0.01% of feedwater flow. The impact of the blowdown flow bias error onthe COLSS secondary calorimetric result is insignificant because the error is minute comparedto the feedwater flow term, the major input to the calorimetric power computation.Steam Generator Narrow-Range Water Level InstrumentsA bias error is introduced into the steam generator NR water level measurements whenever theplant operates at power levels less than 100%. The bias error is negative; i.e., indicated waterlevel will be less than actual water level. The densities of the steam generator saturated liquidand vapor and subcooled downcomer water vary with steam generator saturation pressure andmain steam flow (i.e., plant power level) to create the measurement bias error. The error ispresent over the entire measurement range but varies with water level. Its magnitude isgreatest at the high end of the calibrated range and least at the low end of the range. At 70%power with actual level at the high end of the range, the bias error is approximately -2.0% ofspan. At the low end of the range, the bias error is approximately -1.0% of span. The bias erroraffects both indication and control. At the normal operating water level (68.2% NR), the biaserror is approximately -1.75%. Actual water level will be approximately 70% NR when indicatedlevel is at the 68.2% control point (assuming all other error contributors are zero).Plant Protection System SetpointsThe uncertainties and setpoint margins associated with the various Unit 2 PPS trips and alarmswere reviewed for potential impacts due to reduced-power operation and increased tubeplugging during operating cycle U2C17. The work included preparation of a newuncertainty/setpoint margin calculation for the steam generator NR water level PPS trips andalarms and a review of the existing uncertainty/setpoint margin calculation for all other PPS tripsPage 4 of 6 and alarms. The new NR water level uncertainty/setpoint margin calculation and the parallelreview of the existing PPS uncertainty/setpoint margin calculation confirmed that the installedPPS setpoints for Unit 2 are acceptable with 550'F full-power TCOLD from hot zero power to100% power with up to 8% tube plugging.The negative bias error in indicated steam generator NR water level that exists at 70% powerresults from the changes in steam generator saturation pressure that accompany plant powerlevel changes. For the steam generator NR water level PPS setpoints that address decreasinglevel (e.g., the low-level reactor trip setpoint at 21% of span), the negative bias error isconservative. With the bias error produced at 70% power and with indicated water level at thelow-level setpoint, actual level in the vessel will be above the 0.0% of span low-low analysisvalue used in the safety analyses (i.e., the low-low analysis value bounds the worst-case actuallevel at 70% power). Since the concern for the low-level setpoints is too little water volumeabove the vessel lower instrument tap, the extra water is beneficial. For the PPS setpoints thataddress increasing level (e.g., the high-level reactor trip setpoint at 89% of span), the bias isnon-conservative. For the high-level trip, actual water level in the vessel with the error presentwill be higher than indicated level and closer to flooding the vessel upper instrument tap. If theupper tap becomes flooded, further increases in actual level cannot be seen because theadditional head is applied equally to both the transmitter variable leg and the transmitterreference leg. Indicated level reaches its maximum value when actual level reaches theelevation of the upper tap. The high-level trip provides protection during the excessivefeedwater malfunction transient to prevent overfilling the steam generators and turbine damage.The setpoint is 11% of span below the upper tap to provide assurance that the trip will occurbefore the upper tap floods, even if actual instrument channel error at the time is as large as thecalculated maximum total loop uncertainty. The pressure variation bias error at 70% power isbounded by the pressure variation bias error that is produced during the excessive feedwaterevent. The negative bias error at 70% power does not adversely impact the high-level tripfunction. Actual steam generator water level will be at or below the vessel upper instrument tapwhen indicated level reaches the high-level trip setpoint. The trip condition will be correctlysensed and processed.Differential pressure transmitters across the primary side of the steam generators provide theinputs for the PPS RCS low-flow trips. Westinghouse was contracted by SCE to evaluate theimpact due to reduced-power operation and tube plugging on the RCS low-flow trip setpoints.The resulting Westinghouse evaluation concluded that the existing RCS low-flow trip setpointsremain acceptable for steam generator differential pressure (AP) values between 27 psid and45 psid with flow noise up to 2 psid peak-to-peak. In the event the peak-to-peak flow noisevalue would exceed 2 psid, then the maximum permissible steam generator differential pressure(45 psid) would have to be decreased proportionately. Post tube-plugging steam generator APsignal sampling confirmed that flow noise will be less than 2 psid peak-to-peak when Unit 2 isplaced back into service. The average AP values in the eight instrument channels ranged fromapproximately 35 psid to approximately 38 psid, about midway in the 27 psid to 45 psid bandspecified by Westinghouse. The maximum peak-to-peak noise signal in any of the channelsduring the sampled period was 1.5130 psid. This observation confirmed that the flow noise limitidentified in the Westinghouse evaluation (2 psid peak-to-peak) will not be exceeded whenUnit 2 is returned to service.Pressurizer Level Setpoint Programs and RCS Reference Temperature ProgramsThe pressurizer level setpoin't programs and the TREF programs run on discrete controllers.Each program adjusts its output (pressurizer level setpoint or TREF) in response to plant powerPage 5 of 6 level changes. Within the pressurizer level setpoint program, the computed RCS averagetemperature (TAVE) parameter is used as the measure of plant power. The TREF program usesthe high-pressure (HP) turbine first-stage pressure parameter for the power input.The HP turbine first-stage pressure versus power profile for restored TCOLD (550'F at full-power)is not changed by the 70% power limitation proposed for the U2C1 7 operating cycle. A givenpower output requires a specific HP turbine first-stage pressure. Consequently, there will be noimpact to the TREF controller output. No changes are needed in the TREF controllerconfigurations to support reduced-power operations.At 70% power, plugging 8% of the steam generator tubes has the effect of increasing TAVE from568.1 OF to 568.70F and will consequently change the pressurizer level setpoint program outputfrom 48.86% of the pressurizer level instrument span to 49.18% of span, an increase of 0.32%of span. With the current 2% and 3% tube plugging ratios in the Unit 2 steam generators, theactual pressurizer level setpoint shift going into the U2C17 operating cycle will be even smallerthan the insignificant 0.32% value for 8% tube plugging. No changes are needed in thepressurizer level setpoint controller configurations to support reduced-power operations withtube plugging ratios up to 8%.Nuclear Steam Supply System Control SystemsWestinghouse previously analyzed the nuclear steam supply system (NSSS) control systemconfigurations for the TCOLD restoration project, which changed full-power TCOLD to 5500F. Theanalysis provided new values for the NSSS control system calibrations (including values for theDFWCS and the SBCS). The new calibration values were installed during the R2C17 outage.As part of the Unit 2 return-to-service effort, the NSSS control system configurations werereviewed again to identify potential impacts from operating at reduced power for an extendedperiod with steam generator tube plugging ratios up to 8%. The review found the installedNSSS control system configurations for 550'F full-power TCOLD to be acceptable from hot zeropower to 100% power with up to 8% tube plugging.Page 6 of 6