ML062200431

Request for Additional Information, Increase Maximum Authorized Power Level (TS-431)

ML062200431
Person / Time
Site:	Browns Ferry
Issue date:	08/10/2006
From:	Chernoff M NRC/NRR/ADRO/DORL/LPLII-2
To:	Singer K Tennessee Valley Authority
Chernoff M, NRR/DORL, 415-4041
Shared Package
ML062200554	List: ML062200431
References
TAC MC3812
Download: ML062200431 (13)

Text

August 10, 2006Mr. Karl W. SingerChief Nuclear Officer and Executive Vice President Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801

SUBJECT:

BROWNS FERRY NUCLEAR PLANT, UNIT 1 - REQUEST FOR ADDITIONALINFORMATION FOR EXTENDED POWER UPRATE - ROUND 8 (TS-431) (TAC NO. MC3812)

Dear Mr. Singer:

By letter dated June 28, 2004, as supplemented by letters dated August 23, 2004, February 23,April 25, June 6, and December 19, 2005, February 1 and 28, March 7, 9, 23, and 31, April 13,May 5, 11, 15, and 16, and June 2, 2006, the Tennessee Valley Authority submitted to theU.S. Nuclear Regulatory Commission (NRC) an amendment request for Browns Ferry NuclearPlant, Unit 1. The proposed amendment would change the Unit 1 operating license to increase the maximum authorized power level from 3293 to 3952 megawatts thermal. This change represents an increase of approximately 20 percent above the current maximum authorizedpower level for Unit 1. The proposed amendment would also change the Unit 1 licensing bases and associated Technical Specifications to credit 3 pounds per square inch gauge (psig) for containment overpressure following a loss-of-coolant accident and increase the reactor steam dome pressure by 30 psig. A response to the enclosed request for additional information is needed before the NuclearRegulatory Commission (NRC) staff can complete the review. The steam dryer questions(EEMB) in this request were provided on July 12, 2006, while the remaining questions (SBWB) were provided July 13, 18 and 20, 2006. The July 20, 2006 questions are in support of an audit planned for August 8, 2006 at the site. These requests were discussed with your staff on August 2, 2006, and it was agreed that a response would be provided by August 18, 2006. As stated in a letter dated August 8, 2006, some of the steam dryer questions containinformation from Continuum Dynamics Incorporated (CDI) Report No.05-28P, Bounding Methodology to Predict Full Scale Steam Dryer Loads from In-Plant Measurements, Revision 1 (05-28P) which was requested withheld from public disclosure pursuant to Title 10 of the Code of Federal Regulations (10 CFR), Section 2.390. However, information needed to complete the NRC staff's withholding review for this information has not been provided. Therefore, the NRC K. Singer- 2 -staff will release the information sought to be withheld after 30 days of this letter unless theinformation is withdrawn or amended consistent with the requirements of 10 CFR 2.390(b). If you have any questions, please contact me at (301) 415-4041.Sincerely,/RA by EBrown for/Margaret H. Chernoff, Project ManagerPlant Licensing Branch II-2 Division of Operating Reactor Licensing Office of Nuclear Reactor RegulationDocket No. 50-259

Enclosures:

1. Redacted Request for Additional Information 2. Proprietary Request for Additional Information cc w/enclosure 1 only: See next page K. Singer- 2 -staff will release the information sought to be withheld after 30 days of this letter unless theinformation is withdrawn or amended consistent with the requirements of 10 CFR 2.390(b). If you have any questions, please contact me at (301) 415-4041.Sincerely,/RA by EBrown for/Margaret H. Chernoff, Project Manager Plant Licensing Branch II-2 Division of Operating Reactor Licensing Office of Nuclear Reactor RegulationDocket No. 50-259

Enclosures:

1. Redacted Request for Additional Information 2. Proprietary Request for Additional Informationcc w/enclosure 1 only: See next page DISTRIBUTION

PUBLIC LPL2-2 R/F RidsNrrDorlLpl2-2 RidsNrrLACGoldstein RidsNrrLABClayton (Hard Copy)

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RidsnrrDeEemb RGoel Package: ML062210554Encl2: ML062200547ADAMS Accession No. ML062200431 NRR-088OFFICELPL2-2/PMLPL2-2/PMLPL2-2/LASBWB/BCNAMEEBrownEBrown for MChernoffCGoldsteinGCranston by memoDATE8/9/068/ 9 /068/ 9 /06 7/26/06OFFICEEEMB/BCSCVB/BCLPL2-2/BCNAMEKManoly by memoRDennig by memoLRaghavanDATE 7/27/06 7/26/200608/10 /06 K. Singer- 3 -OFFICIAL RECORD COPY REDACTED REQUEST FOR ADDITIONAL INFORMATION EXTENDED POWER UPRATETENNESSEE VALLEY AUTHORITYBROWNS FERRY NUCLEAR PLANT, UNIT 1DOCKET NO. 50-259EEMB 71.[

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]ACVB59.Discuss which break flow model (Moody, HEM) is used for containment peak pressureat uprated conditions.60.Address whether the only difference between the values of updated final safety analysisreport peak drywell pressure of 50.6 pounds per square inch gage (psig) and the current method of 47.7 psig is due to the difference in LAMB models discussed in note (3) of Table 4-1 of the PUSAR. Discuss whether the method of inputting LAMB output for the current method at uprated conditions is the same as that used for the Vermont Yankeeextended power uprate (EPU). 61.a. Provide a technical manual or a description of the MULTIFLOW program forcalculating pressure losses in piping systems which is used for the EPU net positive suction head (NPSH) calculations.

- 6 -b. Discuss what, if any, conservatism is included in the MULTIFLOW calculations.c. Enclosure 6 of the March 23, 2006 submittal contains MD-Q0999-970046, NPSHEvaluation of Browns Ferry residual heat removal and core spray Pumps. Page 12, states that a piping roughness value of 1.5E-4 ft was selected, which corresponds to condensate quality water. Justify why this is acceptable for suppression pool water, and address whether this a significant assumption.SBWB32. In the SRLR (Supplemental Core Reload Report) dated May 15, 2006, different initialminimum critical power ratio (MCPR) values are given for different application conditions. However, for pressurization transients, the operating MCPR for normal operation with all the equipment operating is not given. Provide the operating limitMCPR with all equipment in operation. Address which transient is the limiting transient in determining the operating MCPR. Provide a table similar to the Table for Non-pressurization transients in Section 11 on page 38.

33.Pages 23 to 36 of the SRLR gives the uncorrected delta CPR (critical power ratio) forvarious events. Address why they are uncorrected. Discuss the purpose for no correction of the associated events.

34.In response to SBWB-25, which was transmitted in a letter dated March 7, 2006, TVAstated on page E1-136 that turbine trip with bypass failure will be analyzed for the firstUnit 1 EPU core design (Cycle 7). The NRC staff has reviewed the SRLR and notesthat it does not appear to include the turbine trip with bypass failure analysis. Address whether the analysis was reperformed as indicated and discuss why the analysis is not contained in the Cycle 7 Unit 1 SRLR.35.Based on the Unit 1 EPU core design, demonstrate that the impact of the bypassvoiding on the reliability and accuracy of the instability protection c apability (e.g., detectand suppress capability (Option III), safety limit MCPR protection and the armed regioncalculation). Use limiting core conditions in the calculations such as the in-channel voids assumed at different elevations and the codes approved for Option III stabilitysolution.36. Figure 2-2 of NEDC-33173P shows a plot of the typical void-quality relation at highpower/flow ratio. Evaluate the database supporting the void fraction correlation and plot the supporting validation measurement data on Figure 2-2. Identify the type ofvalidation data on the plot. Provide a table summarizing the test conditions (e.g.,

pressure, mass flux), the type of the validation data (e.g., 4x4 bundle with part-length, multi-rod ) and the applicability range. As is the norm, exclude the data used to developthe correlation. 37.Unit 1 is an initial core, with potential control rod blade replacement or the use of bladesstored for long durations. a. Address whether all or part of the control rods be replaced with new ones. Provide acontrol rod (CR) replacement plan. If CR blades in the spent fuel storage and being

- 7 -used, explain how the calculated CR worth is verified or assessed. Explain how it isconfirmed that the CR worths used in the safety analyses (e.g., control rod drop analyses [CRDA], the scram worth) are consistent with the worth of the actual CRblades at the plant.b. Assuming that the Unit 1 Technical Specification (TS) will be identical to Units 2 and3, TS Section 3.1.1, SHUTDOWN MARGIN (SDM), states that SDM shall be within the limits provided in the core operating limit report (COLR). It appears that although the SDM requirement and the corresponding value do not c hange on cycle-specific bases,the SDM value has been relocated from the TS to the COLR. The Cycle 7 Ksro at the most reactive state (Ksro +R) is 0.984 K/K and the all- rods-in Keff is 0.945 K/K. Thisresults in a one-rod-out control rod worth of 3.8 % K/K. Address whether this value isconsistent with the assumptions made in the generic CRDA analyses. c. Unit 1 has been out of operation for over 20 years and therefore, no trend line existsto define the analytical methods

[

] calculations for Unit 1, and provide the basis for the biasapplied.d. Unit 1 does not have sufficient historical data to define a predictable and consistent

[ ]. In addition, Unit 1 has some uncertainty defining theworth of individual control rods (e.g., aging if not new). Cycle 7 requires a whole-core reload, for which there is less industry experience. Cycle 8 will consist mostly ofonce-burned fuel, for which, again, there is little industry experience. Considering the above statements, justify why a local critical SDM demonstration is not warranted.e. The response to SBWB-28, which was provided in a letter dated March 7, 2006,states that

[

]Address whether this shutdown margin value will also be applied to future Unit 1 cycles,including Cycle 8.f. The June 30, 2006 response to RAI R2.1-1 provides the local critical eigenvalues forplant C (240 bundle core, yearly Cycle, 51.7 KW/l power density, 110% uprate, 1097 MWt, 17 % batch fraction, extended load line limit analyses [ELLLA] operating domain).

Table R2.1-1 shows that for Cycle 30, Local 1, the difference between the designeigenvalue and the local measurement is -0.003 K. In this case, criticality was reached

[ ]. For this case (Local 1 Cycle 30),provide the actual calculated SDM. Justify why a SDM of 0.38 % should not be increased to the design value.g. The response to SBWB-28 provides the cold critical calculation for Units 2 and 3. Unit 3 Cycle 10 shows a difference between projected and actual eigenvalue of

[ ]. The plant reached criticality

[ ]. For Unit 3Cycle 10 provide the actual calculated SDM. Justify why a SDM of 0.38 % should not be increased to the design value. Given this level of uncertainty, justify why the TS required SDM should not be increased to the values seen in the analytical component of the SDM uncertainties. Based on this data, the potential of underprediction by a value greater 0.38 seems plausible.

- 8 -38.Table 2-10 of NEDC-33173P provides sensitivity calculations of the impact of the 40%VF depletion assumption on the thermal overload protection (TOP) and maintenance outline procedure (MOP) for the LRNBP transient. The sensitivity analyses was based on a plant that differs from Unit 1 and may not be bounding. The following questions relate to the margins available for Unit 1 TOP/MOP.a. The sensitivity analyses show that the impact in terms of percent difference inTOP/MOP is approximately between

[ ]. Address the corresponding TOP and MOPfor GE13 and GE14 fuel types for Unit 1. Confirm that the LRNBP TOP/MOP for Unit 1 has sufficient margin available to account for the potential impact determined in the sensitivity analysis.b. Provide discussion on why the values established in the sensitivity analyses basedon the reference plant are bounding for Unit 1 and the GE13 fuel loaded in the core. c. State the TOP/MOP limits for the GE14 fuel and GE13 fuel. Explain if these are thelimits developed in the generic GE14 compliance to Amendment 22 or limits derived from specific GE14 and GE13 fuel design lattice loading types (e.g., plant-specific GE14 compliance to Amendment 22).39.The NRC staff's assessment of GE's neutronic methods is based on improved versionof TGBLA06. Specify the current NRC- approved production versions approved underAmendment 26 to GESTAR II (e.g. based on MFN-035-99 submittal). Also document the changes made to TGBLA06/PANAC11 since the approval of MFN-035-99 in Amendment 22 to GESTARII. State if the Unit 1 calculations are based on the Amendment 26 approved versions or the updated changes to TGBLA06/PANAC11. If the latter is true, provide the plant-specific information needed to support the necessary review and approval.40.Describe the process followed by Tennessee Valley Authority to implement Long Term(L/T) Solutions including approved methodologies used, hardware modifications, and any interface between fuel vendors.41.Address where Browns Ferry Nuclear Plant (BFN) is today in the implementationschedule and what is its implementation status. Address the affect, if any, of multiple fuel vendors.42.Describe the BFN TSs affected by the L/T Solution implementation. Identify the relatedtech spec operability requirements.43.Discuss the BFN experience with the period-based detection algorithm (PBDA) inresponse to noise and Solution III setpoint adjustment. Describe what actions are takenduring cycle reload confirmations if the calculated setpoints are lower than ex pected. Describe the acceptance testing process used during the Solution III testing process.

Include a description of PBDA results where false alarms were detected.44.Describe any changes for the backup stability implementation (e.g. interim collectiveactions) associated with different fuel vendor's calculating method. Discuss whether BFN uses cycle-specific calculations for backup stability or generic regions. Describe

- 9 -any Solution-III hardware implementation issues such as: location of the new hardware,periodic testing procedures, and signal response quality. 45.Describe the implications for operator training with respect to handling false alarms.

46.Describe what is the effect, if any, of the EPU upgrade on anticipated transient withoutscram and emergency operating instructions.47.The NRC staff reviewed the response to SRXB A.11 submitted in the Unit 2 and 3docket. In the response, the following statement was included:Because the maximum rod line does not change as a result ofEPU, the power/flow history after RPT [recirculation pump trip] is similar for both EPU and pre-EPU. This statement may be true for Units 2 and 3 since maximum extended load line limitanalyses (MELLLA) was approved before the EPU. But for Unit 1, MELLLA is not approved, the maximum rod line is changed, and the reactor decay heat is increased due to EPU. Describe in detail the reasons for the suppression pool temperature decrease for Unit 1. Since the calculated pool temperature is 214 degrees F, sufficient justification is needed for the operability of emergency core cooling system pumps whichmay not meet the pump NPSH requirements due to cavitation.48.Since Unit 1 is loaded with fresh GE14 and GE13, provide the peak data for the two fuel types. a) For the peak power fuel assemblies, provide the limiting axial power distributions andradial peaking factors. For different exposures, select bundles with limiting axial power peaking operating with bottom peaked, double-hump or mid-peaked, and top peaked axial power distributions. Assure that the axial power distribution corresponding to the exposure with the highest hot bundle exit void fraction is also provided. b) Include in the selected bundles, the power distribution and peaking corresponding tothe maximum powered bundle selected for the cycle state point of 10 gigawatt days perstandard ton. In the response to question 26, Figure 26-1 also shows that the bundle isoperating at approximately 7.75 megawatts. Provide the corresponding predicted bundle operating conditions, including axial power distribution, void fraction distribution and bundle nodal exposure. c) Also include the bundle inlet mass flow rate and inlet temperature.

Mr. Karl W. SingerBROWNS FERRY NUCLEAR PLANTTennessee Valley Authority

cc:

Mr. Ashok S. Bhatnagar, Senior Vice President Nuclear Operations Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Mr. Larry S. Bryant, Vice PresidentNuclear Engineering & Technical Services Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801Brian O'Grady, Site Vice PresidentBrowns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609Mr. Robert J. Beecken, Vice PresidentNuclear Support Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 General CounselTennessee Valley Authority ET 11A 400 West Summit Hill DriveKnoxville, TN 37902Mr. John C. Fornicola, ManagerNuclear Assurance and Licensing Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801Mr. Bruce Aukland, Plant ManagerBrowns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609Mr. Masoud Bajestani, Vice PresidentBrowns Ferry Unit 1 Restart Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609Mr. Robert G. Jones, General ManagerBrowns Ferry Site Operations Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609Mr. Larry S. MellenBrowns Ferry Unit 1 Project Engineer Division of Reactor Projects, Branch 6 U.S. Nuclear Regulatory Commission 61 Forsyth Street, SW.

Suite 23T85 Atlanta, GA 30303-8931 Mr. Glenn W. Morris, Manager Corporate Nuclear Licensing and Industry Affairs Tennessee Valley Authority 4X Blue Ridge 1101 Market Street Chattanooga, TN 37402-2801Mr. William D. Crouch, M anagerLicensing and Industry Affairs Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609Senior Resident InspectorU.S. Nuclear Regulatory Commission Browns Ferry Nuclear Plant 10833 Shaw Road Athens, AL 35611-6970State Health OfficerAlabama Dept. of Public Health RSA Tower - Administration Suite 1552 P.O. Box 303017 Montgomery, AL 36130-3017ChairmanLimestone County Commission 310 West Washington Street Athens, AL 35611