ML13037A204
| ML13037A204 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 01/31/2013 |
| From: | Franke J A Duke Energy Corp, Florida Power Corp |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 3F0113-08, TAC ME6527 | |
| Download: ML13037A204 (19) | |
Text
PDukeE EnergyCrystal River Nuclear PlantDocket No. 50-302Operating License No. DPR-72January 31, 20133F01 13-08U.S. Nuclear Regulatory CommissionAttn: Document Control DeskWashington, DC 20555-0001Subject: Crystal River Unit 3 -Response to Second Request for Additional Information toSupport NRC Reactor Systems Branch (SRXB) Technical Review of the CR-3Extended Power Uprate LAR (TAC No. ME6527)References: 1. FPC to NRC letter dated June 15, 2011, "Crystal River Unit 3 -LicenseAmendment Request #309, Revision 0, Extended Power Uprate" (ADAMSAccession No. ML1 12070659)2. Email from S. Lingam (NRC) to D. Westcott (FPC) dated November 13,2012, "CR-3 EPU LAR -SRXB Draft RAls (ME6527)"3. NRC to FPC letter dated December 19, 2012, "Crystal River Unit 3 NuclearGenerating Plant -Request for Additional Information for Extended PowerUprate License Amendment Request (TAC No. ME6527)" (ADAMSAccession No. ML12333A089)Dear Sir:By letter dated June 15, 2011, Florida Power Corporation (FPC) requested a license amendmentto increase the rated thermal power level of Crystal River Unit 3 (CR-3) from 2609 megawatts(MWt) to 3014 MWt (Reference 1). On November 13, 2012, via electronic mail, the NRC staffprovided a draft request for additional information (RAI) to support the SRXB technical reviewof the CR-3 Extended Power Uprate (EPU) License Amendment Request (LAR) (Reference 2).By teleconference on December 12, 2012, CR-3 discussed the draft RAI with the NRC staff toconfirm an understanding of the information being requested. On December 19, 2012, the NRCstaff provided a formal RAI needed to complete its evaluation of the CR-3 EPU LAR(Reference 3). The letter identified that response to five of the RAls should be provided within90 days and the remaining thirty one should be provided within 45 days from the date of RAIrequest. By agreement between Mr. Dan Westcott of FPC and Siva Lingam of the NRC onJanuary 29, 2013, the response to RAI 2.8.5.4.5.3 will be changed from the 45 day response andwill be provided as part of the 90 day response.Attachment A to this correspondence, "FPC Response to Second Request for AdditionalInformation -Reactor Systems Branch Technical Review of the CR-3 EPU LAR," provides theformal response to eight of the RAIs.AICrystal River Nuclear Plant* 15760 W. Powerline StreetCrystal River, FL 34428 U.S. Nuclear Regulatory Commission Page 2 of 33F01 13-08Attachment B, "ANP-3195(P), Revision 0, Responses for Crystal River Unit 3 EPU LicensingAmendment Report NRC Reactor Systems Branch Requests for Additional Information(Proprietary)," provides the formal AREVA response to twenty two of the RAIs.Attachment C contains an Affidavit executed by AREVA for withholding of proprietaryinformation.Attachment D, "ANP-3195(NP), Revision 0, Responses for Crystal River Unit 3 EPU LicensingAmendment Report NRC Reactor Systems Branch Requests for Additional Information (Non-Proprietary)," provides the formal redacted AREVA response to twenty two of the RAIs.Attachment E contains a table listing the location of each response by the Attachment where it islocated.This correspondence contains no new regulatory commitments.If you have any questions regarding this submittal, please contact Mr. Dan Westcott, CR-3Regulatory Affairs Manager at (352) 563-4796.Sincerely,J ;A. Franke,vice PresidentCrystal River Nuclear PlantJAF/scpAttachments:A. FPC Response to Second Request for Additional Information -Reactor Systems BranchTechnical Review of the CR-3 EPU LARB. ANP-3195(P), Revision 0, Responses for Crystal River Unit 3 EPU Licensing AmendmentReport NRC Reactor Systems Branch Requests for Additional Information (Proprietary)C. AREVA Request for Withholding of Proprietary InfoirmationD. ANP-3195(NP), Revision 0, Responses for Crystal River Unit 3 EPU Licensing AmendmentReport NRC Reactor Systems Branch Requests for Additional Information (Non-Proprietary)E. Location of Reactor Systems RAI Responsesxc: NRR Project ManagerRegional Administrator, Region ItSenior Resident InspectorState Contact U.S. Nuclear Regulatory Commission Page 3 of 33F0113-08STATE OF FLORIDACOUNTY OF CITRUSJon A. Franke states that he is the Vice President, Crystal River Nuclear Plant for FloridaPower Corporation; that he is authorized on the part of said company to sign and file with theNuclear Regulatory Commission the information attached hereto; and that all such statementsmade and matters set forth therein are true and correct to the best of his knowledge, information,and belief.Jon .Frankee Presidentrystal River Nuclear PlantThe foregoing document was acknowledged before me this ____ day ofj J ,2013, by Jon A. Franke.Signature of Notary PublicState o Plrubie4OL "q 7MM O ~UIUA Awl[ Wil PON%9 .':4~I £GL6 GO # uOlsIMSWW0'3NA1'OIV"(Print, type, or stamp CommissionedName of Notary Public)Personally ProducedKnown / -OR- Identification FLORIDA POWER CORPORATIONCRYSTAL RIVER UNIT 3DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72ATTACHMENT AFPC RESPONSE TO SECOND REQUEST FOR ADDITIONALINFORMATION -REACTOR SYSTEMS BRANCHTECHNICAL REVIEW OF THE CR-3 EPU LAR U. S. Nuclear Regulatory Commission Attachment A3F0113-08 Page 1 of 11FPC RESPONSE TO SECOND REQUEST FOR ADDITIONALINFORMATION -REACTOR SYSTEMS BRANCH TECHNICALREVIEW OF THE CR-3 EPU LARBy letter dated June 15, 2011, Florida Power Corporation (FPC) requested a license amendmentto increase the rated thermal power level of Crystal River Unit 3 (CR-3) from 2609 megawatts(MWt) to 3014 MWt (Reference 1). On November 13, :2012, via electronic mail, the NRC staffprovided a draft request for additional information (RAI) to support the Reactor Systems Branch(SRXB) technical review of the CR-3 Extended Power Uprate (EPU) License AmendmentRequest (LAR). By teleconference on December 12, 2012, CR-3 discussed the draft RAI withthe NRC staff to confirm an understanding of the information being requested. On December19, 2012, the NRC staff provided a formal RAI needed to complete its evaluation of the CR-3EPU LAR.This Attachment contains eight responses prepared by FPC.SRXB REQUEST FOR ADDITIONAL INFORMATION2.8.4.3 Overpressure Protection During Low Temperature Operation2.8.4.3.1 Please address the reduced exposure over which current low-temperatureoverpressure protection (LTOP) and pressure/temperature limits are valid byconfirming that the Technical Specification (TS) is not limited by effective full-power year, or by revising the applicability period contained in TS 3.4.11.Response:As indicated in Section 2.8.4.3 of the CR-3 EPU Technical Report (TR) (Reference 1,Attachments 5 and 7), the current pressure-temperature (P-T) limits continue to be acceptable forEPU operation with a Reactor Coolant System (RCS) radiation embrittlement accumulation ofup to 27.5 effective full power years (EFPY). The change to the P-T limits applicability from32 EFPY to 27.5 EFPY for EPU operation is identified in the markup of Improved TechnicalSpecification (ITS) Bases B 3.4.11, "Low Temperature Overpressure Protection (LTOP)System," which was included in the CR-3 EPU LAR (Reference 1, Attachment 4).As noted in Section 2.8.4.3 of the EPU TR, a vessel fluency of 50.3 EFPY at EPU conditionswas analyzed and it was determined that the current P-T limits and LTOP requirements may notsupport operation at EPU conditions beyond 27.5 EFPY. Additional correspondence regardingthe evaluations of the current CR-3 P-T limits at EPU conditions were provided to the NRCReactor Vessels and Internals Branch in FPC to NRC letters dated September 27, 2012(Reference 2) and December 18, 2012 (Reference 3).P-T LimitsCR-3 Limiting Condition for Operation (LCO) 3.4.3, "RCS Pressure and Temperature (P/T)Limits," requires the P-T limits to be maintained within the limits specified in the RCS Pressureand Temperature Limits Report (PTLR). As required by ITS 5.6.2.19, "Reactor Coolant System(RCS) PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR)," the P-T limits aredeveloped in accordance with the requirements of 10 CFR 50 Appendix G utilizing the analyticalmethods specified in Babcock and Wilcox (B&W) Topical Report BAW-10046A, "Methods of U. S. Nuclear Regulatory Commission Attachment A3F01 13-08 Page 2 of lICompliance with Fracture Toughness and Operational Requirements of 10 CFR 50, AppendixG," (Reference 4). The applicability of the current P-T limits was adjusted from 32 EFPY to27.5 EFPY based on changes in reactor pressure vessel (RPV) fast neutron fluence (neutron E >1.0 MeV) as a result of operation at EPU conditions. As of the end of CR-3 operating Cycle 16,the currently calculated EFPYs is 22.8 (Reference 2). Therefore, the CR-3 ITS requirementsassociated with P-T limits are not required to be specifically modified as a result of limiting thecurrent P-T limits to 27.5 EFPY at EPU conditions at this time.As required by 10 CFR 50.59 and 10 CFR 50.90, FPC will, when required, obtain a licenseamendment to change the ITS prior to EPU operation beyond 27.5 EFPY to address any revisedCR-3 P-T limits.LTOP RequirementsAs stated in the applicable safety analysis section of the CR-3 ITS Bases B 3.4.11, the LTOPapplicability is based on a limiting reactor vessel temperature of 263°F at the 1/4T wall depthand the LTOP enable temperature of 264°F includes correction for instrument uncertainty. ThisLTOP enabling temperature remains conservative and RCS LTOP is maintained duringoperation at EPU conditions up to 27.5 EFPY. Therefore, the LCO 3.4.11 applicability is notrequired to be modified for operation at EPU conditions.As required by 10 CFR 50.59 and 10 CFR 50.90, FPC will, when required, obtain a licenseamendment to change the applicability of LCO 3.4.11 prior to EPU operation beyond 27.5 EFPYto address any revised CR-3 P-T limits.2.8.4.4 Residual Heat Removal System2.8.4.4.1 Page 2.8.4.4-3 of the TR indicates that there are improved actions that could requirethat the plant be in cold shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Please provide citations to thespecific requirements for added clarity, and explain how these requirements "couldrequire" cold shutdown in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, as stated in the TR.Response:Not all CR-3 ITS actions require shutdown to Mode 5 as the end state, but when they do, thestandard time allowed to achieve Mode 5 (i.e., cold shutdown conditions) is 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Forexample: If RCS operational leakage exceeds the limits of LCO 3.4.12, "RCS OperationalLEAKAGE," the ITS actions allow 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to restore the operational leakage to within limits. Ifthe operational leakage is not restored to within the limits in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the plant must be placed inMode 3 (i.e., hot shutdown conditions) within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Thus, ifspecific ITS actions cannot be performed within the required completion time, ITS may require aplant shutdown to cold conditions and the time to achieve cold conditions is typically 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.This time to achieve Mode 5 is consistent with NUREG-1430, "Standard TechnicalSpecifications -Babcock and Wilcox Plants." Other examples include ITS 3.4.3, "RCS Pressureand Temperature (P/T) Limits", ITS 3.5.4, "Borated Water Storage Tank (BWST)", and ITS3.6.3, "Containment Isolation Valves."As described in Section 2.8.4.4 of the EPU TR, a calculation was performed considering EPUconditions to demonstrate that the Decay Heat (DH) Removal System would continue to be U. S. Nuclear Regulatory Commission Attachment A3F0113-08 Page 3 of Ilcapable of achieving Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> from the EPU power level to support compliancewith the ITS cold shutdown requirements.2.8.4.4.2 In CR-3 Updated Final Safety Analysis Report Section 9.4 (Page 20), the followinginformation is provided:a. Decay Heat Removal PumpsTwo 100% capacity pumps are arranged in parallel. Each is capable ofcontinuous operation during the decay heat removal mode and during refuelingoperations. Both pumps are available for emergency operation. The design flowis that required to cool the RC [reactor coolant] system from 280 IF to 140 °F in14 hours, assuming a Nuclear Service and Decay Heat Sea Water (RW) systemtemperature of 85 IF. The steam generators are used to cool the RC system[RCS] from operating temperature to the 280 IF temperature.b. Decay Heat Removal Heat ExchangersDuring a routine shutdown one heat exchanger is capable of removing decay heatfrom the circulated reactor coolant. Both heat exchangers are operated to cool thecirculated reactor coolant from 280 IF to 140 IF in 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />, assuming a RWsystem temperature of 85 °F. As RW system temperature rised (to a maximum of95 IF) cooldown time will extend beyond 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />, but this increase in time isinconsequential. With a single heat exchanger in service, cooldown to 140 IF willrequire 7 days.c. Borated Water Storage TankThe Borated Water Storage Tank (BWST) is located outside the Reactor buildingand the Auxiliary Building. It contains a minimum of 2,270 ppm [parts permillion] boron in solution and is used both for emergency core injection andfilling the fuel transfer canal during refueling. The BWST also supplies boratedwater for emergency cooling to the Reactor Building Spray (BS) system, the DH[decay heat] system, and the MU [make-up] system.In light of the above, please compare the Final Safety Analysis Report (FSAR) discussion to theevaluations discussed in this section of the TR. Explain whether these functional specificationsremain applicable, whether this information is historical, or whether this information will beupdated. If it will be updated, please provide the revised FSAR text.Response:The information related to the CR-3 DH Removal System functional capabilities provided inSection 2.8.4.4 of the EPU TR is based on the assumptions and results in the decay heat removalcooldown calculations performed considering EPU conditions and does not directly align withthe DH Removal System functional capabilities provided in Section 9.4, "Decay Heat RemovalSystem," of the CR-3 FSAR. FPC will update the CR-3 FSAR, as required, in accordance withthe requirements of 10 CFR 50.71(e) to reflect the revised DH Removal System functionalcapabilities at EPU conditions rendering the currently cited information historical. The FSARwill also be revised to identify the new minimum BWST boron concentration of 2600 ppm.
U. S. Nuclear Regulatory Commission Attachment A3F0113-08 Page 4 of 112.8.5.2.3 Loss of Normal Feedwater Flow2.8.5.2.3.1 The TR states that the loss of feedwater AOO is the limiting transient in terms ofestablishing the minimum emergency feedwater (EFW) flow requirements. Pleasediscuss this statement in the context of Title 10 of the Code of Federal Regulations,Part 50, Section 50.36 requirements. For example, cite the applicable TSrequirements that pertain to EFW, discuss what changes are necessary. If thisinformation is contained in material that has already been submitted, a reference tothis material is acceptable.Response:CR-3 ITS 3.7.5, "Emergency Feedwater (EFW) System," provides the LCO and remedial actionrequirements in accordance with 10 CFR 50.36(c)(2)(i) to ensure the EFW System establishesthe minimum EFW flow requirements during a loss of feedwater AOO. SurveillanceRequirement (SR) 3.7.5.2 continues to require a verification that each EFW pump develops therequired discharge head in accordance with the Inservice Testing Program and SR 3.7.5.3continues to require a verification that each EFW pump starts automatically on an actual orsimulated actuation signal every 24 months.In addition, new SR 3.7.5.7 is proposed to perform a Channel Calibration of the required EFWpump flow instrumentation every 24 months. A description of the new SR and the basis for thenew SR are described in Attachment 1, "Description of Proposed Change, Background,Justification for the Request, Determination of No Significant Hazards Considerations," of theCR-3 EPU LAR. As stated in Table 1, "CR-3 Operating License and Technical SpecificationTechnical Changes," in Attachment 1 of the EPU LAR, the current EFW flow requirement forloss of feedwater AOO is 275 gpm per steam generator. At EPU conditions, the EFW flowrequirement increases to 330 gpm per steam generator. In order to increase the flow sufficiently,the EFW pump low flow instrumentation will be modified to automatically isolate recirculationflow when the EFW pumps are automatically actuated and flow reaches an appropriate range.The new SR 3.7.5.7 and the associated Bases are provided in Attachment 2, "Operating Licenseand Improved Technical Specification Changes (Markup)," Attachment 3, "Operating Licenseand Improved Technical Specification Changes (Revision Bar Format)," and Attachment 4,"Improved Technical Specification Bases Changes (Markup)" of the CR-3 EPU LAR(Reference 1). SR 3.7.5.7 is added to ensure the EFW pump minimum flow instruments openthe associated EFW pump recirculation line isolation valves to provide pump low flowprotection and close the associated EFW pump recirculation line isolation valves in time toensure adequate EFW discharge flow to the steam generators as assumed in the safety analysis.The EFW System actuation delay time assumption in the pre-EPU safety analyses is 60 seconds.The EFW System actuation delay time assumption in the EPU safety analyses has been reducedto 40 seconds capturing some EFW actuation delay margin. FPC has confirmed that the actualEFW System actuation delay time has been historically < 40 seconds and is not being revised asa result of EPU. Thus, there are no associated setpoint modifications, calculations, or designchanges to the Emergency Feedwater Initiation and Control System actuation instrumentationdue to this reduced timing in the safety analyses. Also, actuation delay margin continues to existsuch that any additional delay, as a result of the stroke timing of the new EFW pumprecirculation valves, will not impact the ability of the EFW System to deliver the minimumrequired flow within 40 seconds as assumed in the EPU safety analyses (Reference 5).
U. S. Nuclear Regulatory Commission Attachment A3F01 13-08 Page 5 oflI2.8.5.2.3.6 The TR discusses a separate analysis, performed in a nominal condition, which isused to confirm the TS value for the pressurizer water level upper limit. Pleaseprovide additional information explaining how this analysis accomplishes thatpurpose.Response:As stated in the Bases of ITS 3.4.8, "Pressurizer," the basis for the pressurizer upper level limitof 290 inches is to prevent water relief through the pressurizer safety valves, which preserves thesteam space for RCS pressure control and ensures the capability to establish and maintainpressure control for steady state operation and to minimize the consequences of potentialoverpressure transients. However, prevention of water relief through the pressurizer safetyvalves is an operational goal for abnormal operational transients and is not a specific acceptancecriterion for the CR-3 RCS overpressure safety analyses. As indicated in "Condition A -TheSafety analysis RCS overpressure and pressurizer overfill events," in Section 2.8.5.2.3 of theEPU TR, the loss of feedwater analysis performed for EPU conditions assumed an initialnominal pressurizer level of 240 inches. This pressurizer level is automatically controlled,alarmed, and monitored by the operators.Also, to ensure the current pressurizer upper level limit of 290 inches specified in ITS 3.4.8continued to meet the operational goal of prevention of water relief through the pressurizer safetyvalves at EPU conditions, an additional loss of feedwater analysis was performed using an initialpressurizer level of 290 inches and nominal parameters as described in, "Condition B -Thenominal RCS overpressure and pressurizer overfill event," in Section 2.8.5.2.3 of the EPU TR.The additional loss of feedwater analysis demonstrated that the pressurizer upper level limit of290 inches specified in ITS 3.4.8 will continue to prevent water relief through the pressurizersafety valves during abnormal operational transients at EPU conditions.At CR-3, neither the Reactor Protection System, nor the Engineered Safeguards ActuationSystem includes a high pressurizer level actuation.2.8.5.2.4 Feedwater System Pipe Breaks Inside and Outside ContainmentBy letter dated July 17, 2012, the licensee provided ANP-3114(P), which discussed sensitivitystudies performed on the initial conditions. The sensitivity studies identified a new set of limitinginitial conditions. It is this analysis, and the associated initial conditions, that the NRC staffevaluated in support of the proposed EPU.2.8.5.2.4.4 The TR states that the LONF event is used to establish TS requirements for the EFWsystem. Explain what role the FWLB event analysis plays in establishing TSrequirements.Response:The CR-3 feedwater line break (FWLB) event is not used to establish the minimum EFW flowrequirements for ITS 3.7.5, "EFW System" since the FWLB peak pressure occurs at -13 secondswhich is prior to EFW flow initiation at -68 seconds after FWLB event initiation. Therefore,EFW does not contribute to mitigation of the FWLB overpressure event. The loss of feedwater(LONF) event is used to determine the EFW flow required to prevent a liquid-solid pressurizerand subsequent liquid relief through the pressurizer safety valves. This demonstrates that the U. S. Nuclear Regulatory Commission Attachment A.3F01 13-08 Page 6 of 11loss of feedwater accident does not evolve into a worse event, namely a small break loss ofcoolant accident. Per EPU TR Table 2.8.5.2.3-1, "Sequence of Events for Loss of Feedwater -Condition A," peak pressurizer (PZR) liquid level occurs at either 311 or 393 seconds, dependingupon the specific LONF event (overfill or overpressure).2.8.5.2.4.5 ANP-3 114(P) indicated that steam generator initial inventory had a significant effecton the results of the FWLB analyses. Please provide additional informationconcerning the steam generator operating characteristics, both at pre-EPU and post-EPU power levels. Additional information concerning the original once throughsteam generators would also facilitate further comparison between the currentlicensing basis results and the EPU results.Response:Once Through Steam Generators (OTSGs), original (OOTSG) and replacement (ROTSG)contain adjustable internal orifices, which control the feedwater flow resistance between thedowncomer region and the tube region. Level control systems for the OTSGs control feedwaterflow based upon the sensed level in the downcomer region. During startup and low poweroperating conditions, the OTSG is controlled at a low level limit setting. Following transition offlow level limits, the feedwater control system automatically increases the feedwater flow, andthe downcomer water level, in response to the heat being transferred from the Reactor Coolantsystem.The water inventory within the tube region, and the secondary side fluid characteristics, areprimarily dependent on the power (heat transfer) and relatively independent of the downcomerwater level and orifice setting. The orifice setting, therefore, determines the full power operatingindicated level and the mass of water in the downcomer, which then determines the total mass ofwater in the steam generator. In the downcomer region, feedwater is heated by mixing withaspirating steam (from the tube region). The heated feedwater enters the tube region (below theorifice) at near saturated conditions. Within the tube region, the secondary side inventory, andoutlet steam conditions (superheat), will change over time in response to tube plugging and tubefouling. In these respects, the replacement and original steam generators perform the same.The original steam generators had been in operation since initial plant startup and have tubesplugged, whereas the replacement steam generators have not operated since installation and haveno plugged tubes. The primary side parameters (RCS Thot and Tcold) are determined based uponRCS flow rate. The ROTSG has slightly less primary side flow resistance thereby causing aslight increase in forced reactor coolant system flow rate. Given the difference in plugging andfouling, direct comparisons between the original and replacement steam generators are onlymeaningful when stated in terms of comparable power, orifice setting, plugging/fouling and RCSflow rate.The replacement steam generators were designed to be direct replacement and meet the form, fit,and function of the original steam generators. The replacements were also designed inanticipation of an extended power uprate. There are differences in material and physicalcharacteristics between the replacement and original steam generators that will have minoreffects upon operational characteristics during normal operation, and under transient andaccident conditions. The most significant differences that influence thermal performance are asshown below in Table 2.8.5.2.4.5-1.
U. S. Nuclear Regulatory Commission3F01 13-08Attachment APage 7 of 11Table 2.8.5.2.4.5-1Parameter Original OTSG ReplacementOTSGTube Quantity 15531 15607Tube Heated Length (in.) 625.375 629Tube Thermal Conductivity at 10.833 9.854550°F (BTU/ft-hr-°F)Tube Heating Surface Area 133000 134391(ft2)Downcomer Annulus Width 8.25" nom. 8.75" nom.(in.)Net secondary side (cold) 3412 3485volume (ft3)Primary side irrecoverable 31.68 30.8pressure drop (psi) (TDF, 0%plugging).For pre-EPU conditions, 2568 MWt core and the 2609 MWt Measurement UncertaintyRecapture (MUR) power uprate, a ROTSG orifice setting was selected to provide a full poweroperating level between approximately 70% to 72% (indicated, operating range). Under theseconditions, the ROTSG would have slightly greater internal liquid and total secondary inventorymass than the original, new OTSG. The ROTSG will have slightly greater primary side forcedcoolant flow than the unplugged OTSG, and therefore Thot will be slightly colder in the ROTSG,although both will be at a nominal 604'F at RCS Thermal Design Flow Conditions (with Tavecontrolled at 579°F). The ROTSG will produce superheated steam approximately 2.6°F hotterthan the original steam generator (thermal design flow conditions, 0 tube plugging). Within thetube region, the OTSG and ROTSG have comparable boiling tube lengths and superheat regions.Given the additional tubes in the ROTSG, the ROTSG will have slightly greater primary tosecondary heat transfer under natural circulation conditions (compared to the OTSG at the samelevel and plugging conditions).Thermal performance predictions were not performed for the OOTSG at EPU power. However,the original generators can be discussed qualitatively in comparison to the replacements, basedupon the physical differences in the generators. At EPU full power conditions, both the OOTSGand the ROTSG inventory (tube region) will be greater than at lower power, due to increasedboiling length, and the steam superheat will be decreased in comparison to pre-EPU conditions.With lower superheat and greater boiling length, tube inventory increases since the averagedensity of the tube region fluid increases. For EPU, the turbine throttle pressure is increasedfrom 900 to 930 psia, and the RCS Tave control setting is increased from 579 to 582°F. Becauseof the increase in tube region inventory and an increase in downcomer inventory (at comparableindicated operating levels), the analytical assumptions for initial inventory for a main steam linebreak (MSLB) have been increased. The selected orifice setting for EPU operation will maintainthe steam generator inventory below that assumed in the new EPU MSLB analysis, and also U. S. Nuclear Regulatory Commission3F01 13-08Attachment APage 8 of 11below the level that would degrade the aspirating steam's ability to preheat the feedwater in thedowncomer region (or flood the aspirating port) at full EPU conditions.With specific regard to secondary side inventory, the values in Table 2.8.5.2.4.5-2 below arepredicted conditions from the ROTSG manufacturer's THEDA 2 three-dimensional thermal-hydraulic computer code developed specifically for Once-Through Steam Generators. It is notedthat transient code secondary inventory values (RELAP) vary slightly from THEDA-2.Performance information is for each of the two ROTSG planned operating conditions, withoutplugging or significant fouling, at pre-EPU and EPU power level conditions and best estimateRCS flow conditions (approximately 110% of Thermal Design Flow). The values at EPUrequire, and reflect, a greater opening area for the internal orifice when compared to pre-EPUconditions.Table 2.8.5.2.4.5-22609 MWt (core power) 3014 MWt (core power)Downcomer Operating Range 72.2% 80% (Note 1)LevelTube region, liquid, lbm 14200 21100Total Liquid Inventory, lbm 41020 50646Total inventory, lbm 46103 55602Turbine control pressure 900 psia 930 psiaRCS Tave 5790F 5820FSteam Flow rate 5.509 E+6 6.428 E+06ROTSG outlet nozzle steam 920.1 957.7pressure (static, psia)Steam temp. at SG nozzle 594.13°F 590.4°FRCS Thot 602.25°F 608.50FRange of plugging considered 0 to 20% 0 to 5%Note 1- Values are presented for a nominal 80% full EPU power operating range level(determined by orifice opening). A reduction in orifice resistance resulting in a 70% operatinglevel would reduce EPU downcomer inventory (and total inventory) by approximately 3000 lbm.At EPU conditions, a smaller range of plugging conditions (less than 5%) has been used in safetyanalysis and thermal performance analysis, in comparison to the pre-EPU conditions. Thisreduces the analytical complexity when considering the range of operating conditions that mustbe enveloped within the safety analysis. Both the original and replacement OTSGs wouldexperience lowered outlet steam superheat at significant plugging levels. A smaller range ofallowable plugging for the replacement OTSG does not reflect any inherent differences orlimitations of the ROTSG compared to the original OTSG.
U. S. Nuclear Regulatory Commission3F0113-08Attachment APage 9 of 11Table 2.8.5.2.4.5-3 below shows RCS and steam temperatures at nominal full-power operatingconditions in order to demonstrate the changes in these parameters between the original OTSGsand the ROTSGs at pre and post-EPU power levels.The original OTSGs were not evaluated at the EPU power level. However, since the ROTSGswere designed to be functionally identical to the original components, the ROTSG results shouldbe close to what would be expected for the OTSGs. The following 4 cases are useful forcomparison:1) Core power 2568 MWt, original OTSGs, 0% tube plugging2) Core power 2609 MWt (MUR), original OTSGs, Cycle 15 tube plugging (SG A2.4%, SG B 5.7%)3) Core power 2609 MWt (MUR), ROTSGs, 0% tube plugging4) Core power 3014 MWt (EPU), ROTSGs, 0% tube pluggingComparing Case 1 to Case 2 shows a decrease of 1 0F in steam temperature and superheat, due tothe combined effects of SG tube plugging and the MUR core power increase.Comparing Case 2 to Case 3 shows an increase of about 2.5°F in steam temperature andsuperheat, due to the clean, unplugged ROTSGs replacing the original partially-plugged OTSGs.Comparing Case I to Case 3 therefore shows an increase of about 1.5°F in steam temperatureand superheat. This represents a clean, unplugged OTSG at original core power and theROTSGs at MUR power.Comparing Case 3 to Case 4 shows a decrease of 4°F in steam temperature, and a decrease of8.5°F in steam superheat, due to the EPU. The reason for the decrease is the combined effects ofincreased secondary side mass flow and higher turbine throttle pressure setpoint, and is partiallyoffset by the increase in RCS average temperature and resulting increase in hot leg temperature.Table 2.8.5.2.4.5-3Parameter Case 1 Case 2 Case 3 Case 4Core Thermal Power (MWt) 2568 2609 2609 3014SG Type OTSG OTSG ROTSG ROTSGSG A/B Tube Plugging % 0%/0% 2.4%/5.7% 0%/0% 0%/0%Thot (°F) 601.7 602.2 602.1 608.5T0old (°F) 556.2 555.8 555.9 555.6Tawe (OF) 579 579 579 582Turbine Throttle Pressure (psia) 900 900 900 930Full-Power Steam Temp (OF) 593.7 592.6 595.3 591.4Full-Power Steam Superheat (°F) 57.6 56.6 59.0 50.6Superheat Region (% of tube 50% 48% 43% 28%length)
U. S. Nuclear Regulatory Commission Attachment A3F01 13-08 Page 10 of 112.8.5.6 Decrease in Reactor Coolant Inventory2.8.5.6.1 Inadvertent Opening of Pressurizer Pressure Relief Valve2.8.5.6.1.1 Recent NRC staff review experience has indicated that a spurious PORV openingcan cause an engineered safety features actuation, associated with thedepressurization. This actuation can challenge the RCS by overfilling thepressurizer. Please provide information to address this concern.Response:Inadvertent Pilot Operated Relief Valve (PORV) Opening Standard Review Plan requirementswere demonstrated to be met. Refer to Reference 6, FPC letter dated October 11, 2011,Enclosure 2, AREVA 86-9167251-001, "Summary of CR3 EPU Inadvertent Pressurizer ReliefValve Opening." A spurious PORV opening may cause an engineered safety features actuationassociated with RCS depressurization. An engineered safety features actuation should notchallenge the RCS integrity during restoration by the operating crew.The CR-3 PZR is equipped with the PORV and a motor operated PORV Isolation Valve used toprevent a pressurizer steam blowdown in the event that the PORV fails to reclose after beingactuated and also to isolate a leaking PORV. The isolation valve closes in 13.9 seconds. ThePORV actuation setpoint is 2450 psig. The pressurizer is also equipped with two code safetyvalves both with set pressure of 2500 psig. The PORV and code safety valves are equipped withdischarge tailpipe accelerometers to indicate flow and provide an annunciator alarm.Four simulator runs were performed to provide insights on this question and demonstrate that nonew safety concerns exist with an inadvertent opening of the PORV and possible engineeredsafety features actuation. In the simulator runs described here, the same initial conditions wereestablished for each. Those conditions were:* 100.08% EPU power (3017 MWt)* Pressurizer level 220 inches* RCS Pressure 2155 psig* Tave 582°FThe first case was for an inadvertent high pressure injection (HPI) actuation. The results werebenchmarked against the AREVA analysis 86-9168766-001, "CR-3 EPU InadvertentEngineered Safeguards Actuation (IESA) Analysis Summary" submitted as Enclosure 3 inReference 6 and parameter trends were determined to be similar. Also the simulator time forPZR fill was longer than the AREVA analysis due to some simulator normal operatingparameters.The second case evaluated response to an inadvertent PORV opening. In this case, operatorresponse is based on the operator taking established "prompt and prudent action." Operatorresponse is based on indication of the PORV being open from the annunciator alarm, andverification of lowering RCS pressure and PORV tailpipe accelerometer indications available inclose proximity to the PORV block valve controls. Based on these conditions the operator mustisolate the PORV in less than 1 minute to avoid a reactor trip. A reactor trip would lead to eitherthe third or fourth case.
U. S. Nuclear Regulatory Commission Attachment A3F0113-08 Page 11 oflIThe third case fails the PORV open and no operator actions are taken. Following a reactor trip,the RCS continues to depressurize and HPI actuates. When HPI actuates, the PORV is failedclosed to maximize RCS inventory addition. The time for PZR fill was determined to be greaterthan the time for the first case due to loss of RCS inventory while the PORV was open.The fourth case simulates the operating crew not recognizing the PORV has failed open andmethodically working through Emergency Operating Procedures (EOPs). After completing theimmediate actions of the reactor trip procedure, EOP-02, "Vital System Status Verification," thecrew would transition to EOP-03, "Inadequate Subcooling Margin." The first priority focuses onensuring adequate core cooling and then provides guidance to isolate potential RCS leaks. Step3.20 of EOP-03 directs closure of the PORV isolation valve, RCV- 11 which terminates the leak.When adequate Subcooling margin is regained, the EOPs and EOP rules provide guidance tocontrol HPI, control PZR level, establish letdown and re-establish a PZR bubble. During thisevent, the PZR safety valves were not challenged.All simulator runs demonstrated that spurious PORV opening may cause an engineered safetyfeatures actuation, associated with the RCS depressurization. This actuation should notchallenge the RCS integrity during restoration by the operating crew.References1. FPC to NRC letter dated June 15, 2011, "Crystal River Unit 3- License AmendmentRequest #309, Revision 0, Extended Power Uprate." (ADAMS Accession No.ML1 12070659)2. FPC to NRC letter dated September 27, 2012, "Crystal River Unit 3- Response to SecondRequest for Additional Information to Support NRC Vessels and Internals Integrity Branch(EIVB) Technical Review of the CR-3 Extended Power Uprate LAR (TAC No. ME6527)."(ADAMS Accession No. ML12272A344)3. FPC to NRC letter dated December 18, 2012, "Crystal River Unit 3 -Response to ThirdRequest for Additional Information to Support NRC Vessels and Internals Integrity Branch(EVIB) Technical Review of the CR-3 Extended Power Uprate LAR (TAC No. ME6527)."(ADAMS Accession No. ML12361 A010)4. B&W Topical Report BAW-10046A, "Methods of Compliance with Fracture Toughnessand Operational Requirements of 10 CFR 50, Appendix G," Revision 2, dated June 1986.5. FPC to NRC letter dated March 19, 2012, "Crystal River Unit 3 -Response to SecondRequest for Additional Information to Support NRC Instrumentation and Controls Branch(EICB) Technical Review of the CR-3 Extended Power Uprate LAR (TAC No. ME6527)"(ADAMS Accession No. ML12081A293)6. FPC to NRC letter dated October 11, 2011, "Crystal River Unit 3 -Response to Requestfor Additional Information to Support NRC Reactor Systems Branch Acceptance Reviewof the CR 3 Extended Power Uprate LAR (TAC No. ME6527)" (ADAMS Accession No.ML1 1286A092)
FLORIDA POWER CORPORATIONCRYSTAL RIVER UNIT 3DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72ATTACHMENT CAREVA REQUEST FOR WITHHOLDING OF PROPRIETARYINFORMATION AFFIDAVITCOMMONWEALTH OF VIRGINIA )) ss.COUNTY OF CAMPBELL )1. My name is Gayle F. Elliott. I am Manager, Product Licensing, for AREVANP Inc. (AREVA NP) and as such I am authorized to execute this Affidavit.2. I am familiar with the criteria applied by AREVA NP to determine whethercertain AREVA NP information is proprietary. I am familiar with the policies established byAREVA NP to ensure the proper application of these criteria.3. I am familiar with the AREVA NP information contained in the documentANP3195(P) Revision 0, entitled "Responses for Crystal River Unit 3 EPU LicensingAmendment Report NRC Reactor Systems Branch Requests for Additional Information," datedJanuary 2013 and referred to herein as "Document." Information contained in this Documenthas been classified by AREVA NP as proprietary in accordance with the policies established byAREVA NP for the control and protection of proprietary and confidential information.4. This Document contains information of a proprietary and confidential natureand is of the type customarily held in confidence by AREVA NP and not made available to thepublic. Based on my experience, I am aware that other companies regard information of thekind contained in this Document as proprietary and confidential.5. This Document has been made available to the U.S. Nuclear RegulatoryCommission in confidence with the request that the information contained in this Document bewithheld from public disclosure. The request for withholding of proprietary information is made inaccordance with 10 CFR 2.390. The information for which withholding from disclosure is requested qualifies under 10 CFR 2.390(a)(4) "Trade secrets and commercial or financialinformation":6. The following criteria are customarily applied by AREVA NP to determinewhether information should be classified as proprietary:(a) The information reveals details of AREVA NP's research and developmentplans and programs or their results.(b) Use of the information by a competitor would permit the competitor tosignificantly reduce its expenditures, in time or resources, to design, produce,or market a similar product or service.(c) The information includes test data or analytical techniques concerning aprocess, methodology, or component, the application of which results in acompetitive advantage for AREVA NP.(d) The information reveals certain distinguishing aspects of a process,methodology, or component, the exclusive use of which provides acompetitive advantage for AREVA NP in product optimization or marketability.(e) The information is vital to a competitive advantage held by AREVA NP, wouldbe helpful to competitors to AREVA NP, and would likely cause substantialharm to the competitive position of AREVA NP.The information in the Document is considered proprietary for the reasons set forth inparagraphs 6(b) and 6(c) above.7. In accordance with AREVA NP's policies governing the protection and controlof information, proprietary information contained in this Document has been made available, ona limited basis, to others outside AREVA NP only as required and under suitable agreementproviding for nondisclosure and limited use of the information.
- 8. AREVA NP policy requires that proprietary information be kept in a securedfile or area and distributed on a need-to-know basis.9. The foregoing statements are true and correct to the best of my knowledge,information, and belief.SUBSCRIBED before me this _.._____day of _T9ra 2013.Ella Carr-PayneNOTARY PUBLIC, COMMONWEALTH OF VIRGINIAMY COMMISSION EXPIRES: 8/31/2013Reg. #309873