ML18039A258
| ML18039A258 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 12/31/1997 |
| From: | TENNESSEE VALLEY AUTHORITY |
| To: | |
| Shared Package | |
| ML18039A256 | List: |
| References | |
| NUDOCS 9803120072 | |
| Download: ML18039A258 (159) | |
Text
{{#Wiki_filter:TENNESSEE VALLEYAUTHORITY BROWNS FERRY NUCLEAR PLANT ANNUALOPERATING REPORT January 1, 1997- December 31, 1997 Docket Number 50-259, 50-260, and 50-296 License Number DPR-33, DPR-52, and DPR-68 ADOCK 0500025 PDR R
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Broinss Ferry Nuclear Plant 1997 Annual Operating Report Q'()gal+ ~fgpggh~pgW~h. 'VAVpQ)WW"VAVp~'Q'f"Q~WgJ~hV~p@""g~W~g"QV'glhB'Ql~~'
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Regulatory Guide 1.16, Section I.b. (1) and (2) Operational Summary 10CFR50.59(b)(2) - Summary ofSafety Evaluations Core Component and Operating Limits. 10 Fire Protection Report Revisions .. 17 Miscellaneous. 19 Plant Modifications. 33 Procedure Revisions... 60 Temporary Alterations 65 Updated Final Safety Analysis Report Revisions. 68 Regulatory Guide 1.16, Section 1.b. (3) 1997 Release Summary 95 Technical Specification 6.9.1.2 1997 Occupational Exposure Data. 97 Challenges to or Failures of Main Steam Relief Valves..... 102 Teclinical Specification 6.9.2.1 Reactor Vessel Fatigue Usage Evaluation. 105 Summary of Evaluations for Commitment Revisions 107
Tennessee Valley Authori ty Bro>vns Ferry Nuclear Plant l997 Annual Operating Report ACRONYMS LISTING ABN Abnormal AC Alternating Current ADS Automatic Depressurization System, Atmosp heric Dilution System ADSRVs Automatic Depressurization System Relief Valve APRM Avemge Power Range Monitor ARI Alternate Rod Injection ARTS-MELLA APRM & Rod Block Monitor Testing Spec dications, Maximum Extended Load Line Analysis ASME American Society of Mechanical Engineers ASTM American Society of Testing Material ATU Analog Trip Unit ATWS Anticipated Transient Without SCRAM BCSPS Backup Control Sound-Powered System BFN Browns Ferry Nuclear Plant BFPER Browns Ferty Problem Evaluation Report BOP Balance of Plant BPWS Banked Position Withdrawal Sequence BRD Board BWR Boiling Water Reactor BWROG Boiling Water Reactor (hvners Group CCC Control Cell Core CCW Condenser Circulating Water CFR Code of Federal Regulations CMP Control air Compressor COLR Core Operating Limits Report CRD Control Rod Drive CRLD Change Request to a Licensing Document CS Core Spray CSCS Core Standby Cooling System CSST Common Station Service Transformers CTs Current Transformers CTT Cooling Tower Transformers CV Control Valve DBA Design Basis Accident DBE Design Basis Earthquake DC Direct Current DCA Drywell Control Air DCN Design Change Notice DCR Design Change Request DER Design Electrical Rating DG Diesel Generator DWCA Drywell Control AirSystem DZO Depleted Zinc Oxide ECCS Emergency Core Cooling System ECN Engineering Change Notice ECW Emergency Cooling Water EECW Emergency Equipment Cooling Water EFPD Effective Full Power Days EHC Electro Hydraulic Control ELLLA Extended Load Line Limit Analysis Eng Engine
Tennessee Valley Authority Brohi ns Ferry Nuclear Plant 1997 Annual Operating Report A CRONUS LISTING N'"'~"""'@'-"~:" ':w'.';"','i.'"'9'+i
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"'OC End of Cycle EOI Emergency Operating Instruction EQ Environmental Qualification EWR Engineering Work Request FCV Flow Control Valve FFWTR Final Feedwater Reduction FPR Fire Protection Report FSAR Final Safety Analysis Report FW Feedwater FWHOOS Feedwater Heaters Out of Service GE General Electric GE SIL GE Service Information Letter GEMAC General Electric Measurement and Control GEZIP Zinc Injection system GL Generic Letter gpm Gallons per Minute HCV Hand Control Valve HELB High-Energy Line Break Hg Mercury HPCI High Pressure Coolant Injection HVAC Heating Ventilation and Air Conditioning I/A Intelligent Automation I/O Input Output I/P Current to Pneumatic Convendeis ICF Increased Core Flow ICS Integrated Computer System IEEE Institute of Electrical and Electronic Engineers INWC Inches Water Column ISI Inservice Inspection ISTS Improved Standard Technical Specifications kv Kilovolt KW Kilowatt LC Lighting Cabinet LCO Limiting Condition of Operations LCV Lever Control Valve LHGR Linear Heat Generation Rate LLRT Local Leak Rate Test LOCA Loss of Coolant Accident LPCI Low Pressure Coolant Injection LPRM Local Power Range Monitor LPU Local Processing Unit LS Level Switch LTA Load Test Assembly LTTIP Long Term Torus Integrity Program M/A Manual Auto MAPLHGR Maximum Average Planar Lenear Heat Generation Rate MCC Motor Control Center MCPR Minimum Critical Power Ration MCR Main Control Board MDC Maximum Dependable Capacity MELL Maximum Extended Loan Line Limit MMI Mechanical Maintenance Instruction
0 Tennessee Valley Authority Brains Ferry Nuclear Plant l997Annual Operating Report ACRONYMS LISTING MOV Motor Operated Valve MSDIV Main Steam Drain Isolation Unit MSIV Main Steam Isolation Valve MSLRM Main Steam Line Radiation Monitor MSRV Main Steam Relief Valve MVDAs Multi-Vender Data Acquisition System MWD/ST Megawatt Days per Short Ton MWe Megawatt Electrical MWH Mega Watt Hours MWt Megawatt Thermal NEC National Electrical Code NESSD Nuclear Engineering Setpoint and Scaling D ocument NPSH Net Position Suction Head NRC Nuclear Regulatory Commission NUMAC Nuclear Measurement Analysis and Contml NUMACPRNM Nuclear Measurement Analysis and Control Power Range Neutron Monitor NUREG Nuclear Regulatory Commission Regulation OB Out Board OC Offgas Condenser ODCM Offsite Dose Calculation Manual OGC Off Gas Condenser OPRM Oscillation Power Range Monitor OPS Operation PASF Post Accident Sampling Facility PCIOMR Preconditioning Interim Operating Management Recommendations" PCIS Primaty Containment Isolation System PCV Pressure Control Valve PER Problem Evaluation Report PM Preventive Maintenance PRNM Power Range Neutron Monitoring PSIG Pounds Square Inch Gauge PT Pressure Transmitter PUAR Plant Unique Analysis Report QR Quality Related RB Reactor Building RBM Rod Block Monitor RBMTS Rod Block Monitor Trip System RCIC Reactor Core Isolation Cooling RCW Raw Cooling Water RDA Rod Drop Accident RFPT Reactor Feed Pump Turbine RFWCS Reactor Feedwater Control System RFWH Reactor Feedwater Heater RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water RMCS Reactor Manual Control System RMOV Reactor Motor Operated Valve RPS Reactor Protection System RPTOOS Recirculating Pump Trip Out of Service RSTR Rod Scram Time Recorder RTD Resistive Temperature Devices RV Relief Valve
Tennessee Valley Aulhori ty Broils Ferry iVuelear Plant l997Annual Operating Report ACRONYNS LISTIÃG C":::":'.i:: "':i""" '" ": "'-""": "":":~!'."""'-':i'"::.'="'-';: "~. C.":
""'""-.'WCU Reactor Water Cleanup RWE Rod Withdrawal Error RWM Rod Wort Minimizer SAR Safety Analysis Report SB Shut Down Board A, B, C, D SCFM Standard Cubic Feet per Minute SCW Stator Cooling Water SER Sequential Events Recorder, Significant Events Report gNPO)
SI Surveillance Instruction SJAE Steam Jet AirEjector SLMCPR SpcciTic Safety LimitAnalysis SLMCPR Safety Limit Minimum Critical Power Ratio SLO Single Loop Operation SPE Steam Packing Exliauster SRLRr Supplement Reload Licensing Report SRO Senior Reactor Operator SSP Site Standard Pmcticc Stg Storage STV Stem Trap Outlet Shut OffValve TACF Temporary Alteration Control Form TBOOS Turbine Bypass Out of Service TIP Traversing Incore Probe TMI Three Mile Island Incident TRP Stcam Trap TS Technical Specification TSCF Temporary Structure Control Form TVA Tennessee Valley Authority UCB Unit Control Board UFSAR Updated Final Safety Analysis Report USST Unit Station Service Transformers VAC Volts Alternating Current VDC Volts Direct Current VHF Very High Frequency W.O. Work Order WRGERM Wide Range Gaseous Effluent Radiation Monitor Tlus is a list of acronyms and abbreviations used throughout the 1997 Annual Operating Report.
Tennessee Valley Authority Browns Ferry Nuclear Plant l997Annual Operating Report OPERATIONAI
SUMMARY
1997 OPERATIONAL
SUMMARY
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997 Annual 1A)'{'{ Operating Report
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UNIT I Unit 1 remains shutdown on administrative hold to resolve various Tennessee Valley Authority (TVA) and Nuclear Regulatory Commission (NRC) concerns. UNIT 2 On January 1, 1997, the unit's power level was at full power (3290 MWt and 1114 MWe). On April 24, 1997, at 1817 hours, while the unit was at 100% power, the reactor automatically scrammed due to Main Turbine trip due to a simulated, reactor high water level, turbine trip signal. The reactor was again critical on April 26 at 2133 hours and at 100% power on April 28 at 1800 hours. The reactor started coast down for the Unit 2 Cycle 9 refueling outage on August 17, 1997 at 2340. The reactor was manually scrammed on September 27, 1997, at 0900 for the Unit 2 Cycle 9 refueling outage. The reactor was critical on October 18, 1997 at 1145 hours and at 100% power on October 20, 1997 at 1640. The unit experienced an automatic scmm at 1508 hours on October 28, 1997, due to a low reactor water level signal caused by a pressure perturbation in the Electro-Hydraulic Control (EHC) System. The reactor was critical on October 30, 1997 at 0458 hours and at 100% power on November 1, 1997 at 0715. On December 31, 1997, Unit 2 was at full power (3292 MWt and 1114 MWe). UNIT 3 On January 1, 1997, the unit was in coast down with the power level at 93% of full power (3108 MWt and 1022 MWe). The reactor was manually scrammed on February 22, 1997, at 0201 for the Unit 3 Cycle 7 refueling outage. The reactor was critical on March 12, 1997 at 1001 hours and at 100% power on March 20, 1997 at 1150. On December 31, 1997, Unit 3 was at 100% power (3291 MWt and 1115 MWe).
Tennessee Valley Authority BroN ns Ferry Nuclear Plant I997 Annual Operating RePort OPERA TIDAL
SUMMARY
Docket No.: 50-259 OPERATING STATUS
- 1. Unit Name: Browns Ferry Unit One
- 2. Reporting Period: Calendar Year 1997
- 3. Licensed Thermal Power (MWt): 3293
- 4. Nameplate Rating (Gross MWe): 1152
- 5. Design Electrical Rating (Net MWe): 1065
- 6. Maximum Dependable Capacity (Gross MWe): 0
- 7. Maximum Dependable Capacity (Net MWe): 0
- 8. IfChanges Occur in Capacity Ratings (Items Number 3 Through 7)
Since Last Report, Give Reason: N/A
- 9. Power Level to Which Restricted, ifany (Net MWe): 0
- 10. Reason for Restrictions, ifany: Administrative Hold 1997 Cumulative*
Hours in Re orting Period 0 '95,743 12 Hours Reactor Was Critical 0 59,521
- 13. Reactor Reserve Shutdown Hours 0 6,997 14 Hours Generator On Line 0 58,267
- 15. Unit Reserve Shutdown Hours 0 0 16 Gross Thermal Generation (MWh) 0 168,066,787
- 17. Gross Electrical Generation (MWh) 0 55,398,130 18 Net Electrical Generation (MWh) 0 53,796,427
- 19. Unit Service Factor 0 60.9 20 Unit Availabili Factor 0 60.9
- 21. Unit Ca acity Factor (MDC Net) 0 52.8
- 22. Unit Ca aci Factor (DER Net) 0 52.8
- 23. Unit Forced Outa e Rate 0 25.6
- 24. Shutdowns Scheduled Over Next 6 Months (Type, Date, and Duration of Each):
N/A
- 25. IfShutdown at End of Reporting Period, Estimated Date of Startup: To Be Determined
*Excludes hours under administrative hold (June I, 1985 to present)
Tennessee Valley Authority Brogans Ferry Nuclear Plant 1997 Annual Operating Report OPERA TIONAI
SUMMARY
'hx&%44G)'NSM A4Pa'RAV$ 4%rCxy%.4cNwRrAA 'WNN44S.@48ANNk 4~cv.v4444Y'A4kgkoA"%Xa4" ekQka'ox4oQVZ4" X ~
Docket No.: 50-260 OPERATING STATUS
- 1. Unit Name: Browns Ferry Unit Two
- 2. Reporting Period: Calendar Year 1997
- 3. Licensed Thermal Power (MWt): 3293
- 4. Nameplate Rating (Gross MWe): 1152
- 5. Design Electrical Rating (Net MWe): 1065
- 6. Maximum Dependable Capacity (Gross MWe): 1098.4
- 7. Maximum Dependable Capacity (Net MWe): 1065
- 8. IfChanges Occur in Capacity Ratings (Items Number 3 Through 7)
Since Last Report, Give Reason: N/A
- 9. Power Level to Which Restricted, ifany (Net MWe): N/A
- 10. Reason for Restrictions, ifany: N/A 1997 Cumulative*
Hours in Re ortin Period 8,760 148,375 12 Hours Reactor Was Critical 8,157 106,806
- 13. Reactor Reserve Shutdown Hours 0 14,200 14 Hours Generator On Line 8,130 104,413
. 15. Unit Reserve Shutdown Hours 0 0 16 Gross Thermal Generation h) 25,848,384 310,035,484
- 17. Gross Electrical Generation h) 8,581,110 103,002,478 18 Net Electrical Generation (MWh 8,372,926 100,206,091
- 19. Unit Service Factor 92.8 70.4 20 Unit Availabili Factor 92.8 70.4
- 21. UnitCa aci Factor MDCNet 89.7 63.4
- 22. Unit Ca aci Factor (DER Net) 89.7 63.4
- 23. Unit Forced Outage Rate 1.3 14.1
- 24. Shutdowns Scheduled Over Next 6 Months (Type, Date, and Duration of Each):
N/A
- 25. IfShutdown at End of Reporting Period, Estimated Date of Startup:
N/A
*Excludes hours under administrative hold (June 1, 1985 to May 24, 1991)
Tennessee Valley Authority Browns Ferry iVuolear Plant l997 Annual Operating Report OPERA TIDAL
SUMMARY
Docket No.: 50-296 OPERATING STATUS
- 1. Unit Name: Browns Ferry Unit Three
- 2. Reporting Period: Calendar Year 1997
- 3. Licensed Thermal Power (MWt): 3293
- 4. Nameplate Rating (Gross MWe): 1152
- 5. Design Electrical Rating (Net MWe): 1065
- 6. Maximum Dependable Capacity (Gross MWe): 1098.4
- 7. Maximum Dependable Capacity (Net MWe): 1065
- 8. IfChanges Occur in Capacity Ratings (items Number 3 Through 7)
Since Last Report, Give Reason: N/A
- 9. Power Level to Which Restricted, ifany (Net MWe): N/A
- 10. Reason for Restrictions, ifany: N/A 1997 Cumulative*
- 11. Hours in Re ortin Period 8,760 91',597
- 12. Hours Reactor Was Critical 8,320 63,074
- 13. Reactor Reserve Shutdown Hours 0 5,150
- 14. Hours Generator On Line 8,302.2 61,721
- 15. Unit Reserve Shutdown Hours 0 0
- 16. Gross Thermal Generation h) 26,204,256 187,434,913
- 17. Gross Electrical Generation (MWh 8,739,270 62,763,410
- 18. Net Electrical Generation h) 8,523,366 60,205,497
- 19. Unit Service Factor 94.8 67.4
- 20. Unit Availabili Factor 94.8 67.4
- 21. Unit Ca aci Factor (MDC Net) 91.4 61.7
- 22. Unit Ca aci Factor (DER Net) 91.4 61.7
- 23. Unit Forced Outa e Rate 0.0 16.7
- 24. Shutdowns Scheduled Over Next 6 Months (Type, Date, and Duration of Each):
NA
- 25. IfShutdown at End of Reporting Period, Estimated Date of Startup: N/A
*Excludes hours under administrative hold (June 1, 1985 to November 19, 1995)
Tennessee Valley Authority Brogans Ferry Nuclear Plant l997 Annual 0 eratin Re or( 1997
SUMMARY
OF SAFETY EVALUATIONS FOR CORE COMPONENT DESIGN CHANGE REQUESTS AND CORK OPERATING LIMITS REPORTS
Tennessee Valley Authori ty BroN ns Ferry Pic/ear Plant 1997Annual 0 eralin Re ort
SUMMARY
OF SAFETY EVALUATIONS CORE COMPONENT DESIGN CHANGE REQUEST 58 This safety evaluation addresses use of General Electric's GE13 product line of fuel in Browns Ferry Nuclear Plant Units 2 and 3. The most recent reloads for Browns Ferry consisted of the GE11 fuel design. Progressing to advanced fuel assembly designs offers potential for improved fuel cycle economics and plant operations. The GE13 fuel assembly design is very similar to the previously loaded GE11 fuel design. The only significant difference between GE11and GE13 is that GE13 has eight spacers with the part length rods terminating just above the sixth spacer, whereas GE11 has 7 spacers with the part length rods terminating just above the filth spacer. The part length rods in the GE13 design are approximately 12" longer than the part length rods in GE11. Adding an extra spacer in the upper region of the fuel assembly results in an increase of six to eight percent in critical power capability for identical thermal hydraulic state conditions. A detailed description of GE fuel designs is included in the GE licensing topical report GESTAR II which documents the GE design and licensing analysis process. Amendment 22 of GESTAR II created a mechanism which allows for the pre-approval by NRC of fuel designs which meet previously agreed upon criteria. Compliance with Amendment 22 assures that new designs meet the licensing acceptance criteria defined in NUREG-0800, Standard Review Plan. The GE13 fuel product line was designed and licensed by the Amendment 22 process with compliance documented in GE Report NEDE-32198P. Use of the GE13 fuel assembly design in BFN is acceptable from a nuclear safety standpoint. UFSAR Section 3.2, "Fuel Mechanical Design" needs to be updated to add GE13 to the list of approved fuel designs for use in Browns Ferry Units 2 and 3 reload cores. No unreviewed safety question is involved. CORE COMPONENT DESIGN CHANGE REQUEST 61 This safety evaluation addresses use of General Electric's Marathon Control Rod Assembly design in Browns Ferry Nuclear Plant Units 1, 2, and 3. The design description and analyses presented in NEDE-31758P demonstrate that the Marathon design satisfies the performance and licensing acceptance criteria for use as a direct replacement for currently used control rod assemblies. The essential difference between the Marathon control rod and the preceding designs is replacement of the absorber tube and sheath arrangement with an array of square tubes, which results in reduced weight and increased absorber volume. The square tubes are fabricated from a high purity stabilized Type-304 stainless steel that provides high resistance to irradiation-assisted stress corrosion cracking. The absorber tubes are welded lengthwise to form the four wings of the control rod. For the BFN BWR/4 D-lattice design, each wing is comprised of 14 absorber tubes. The absorber tubes each act as an individual pressure chamber for the retention of helium which is produced during neutron absorption reactions. The four wings are then welded to the tie rod to form the cruciform-shaped member of the control rod. The square tubes are circular inside and are loaded with either B4C or hafnium. The B4C is contained in separate capsules to prevent its migration. The capsules are placed inside the absorber tubes and are smaller than the absorber tube inside diameter, allowing the B4C to swell before it makes contact with the absorber tubes, thereby providing improved resistance to stress corrosion. The B4C capsules are fabricated from stainless steel tubing and have stainless steel caps attached by rolling the tubing into grooves in the caps. The capsules are loaded into the individual absorber tubes, which are then sealed at each end by welded end caps. The capsules securely contain the B4C while allowing the helium to migrate through the absorber tube.
Tennessee Val/ey Authority Brogans Ferry Nuclear Plant 1997Annual 0 eratin Re ort
SUMMARY
OF SAFETY EVALUATIONS Recent design changes for the Marathon absorber capsules are described in GE Report WLM-CR-9601. These changes involve both a revision to the B4C loading process and an extension in the length of the capsules. The changes provide a tighter band on density variation in the B4C loading. Recent changes in the velocity limiter design for the Marathon control rods are described in GE Report WLM-CR-9602. The changes are a result of efforts to standardize velocity limiter designs among the various GE Duralife and Marathon product lines in order to provide process and quality improvement. The Marathon design offers increased blade lifetimes due to the increased absorber loading and absorber tube design improvements. Design lifetimes for all GE control blade designs are documented in the GE BWR Control Rod Lifetime report NEDE-30931-4-P. The Marathon blades have a quarter segment, end-of-life 10B-equivalent depletion limit of 68% versus 34% for the original equipment and modified BWR/6 blades, and 56% for the Duralife 160 (hybrid) blades. Use of the GE Marathon Control Rod Assembly design in BFN is acceptable from a nuclear safety standpoint. NRC has given generic approval of the design. FSAR Section 3.4.5.1.1, "Control Rods", needs to be revised to add a description of the Marathon control rod design. Also, a new Figure 3.4-12, "Marathon Control Rod - Isometric", showing an illustration of the Marathon control rod needs to be added. No unreviewed safety question is involved. CORE OPERATING LIIMITSREPORT - BF2C10 This safety evaluation supports the Browns Ferry Nuclear (BFN) Plant Unit 2 Cycle 10 reload core design and the cycle specific Unit 2 Core Operating Limits Report (COLR). The reload core design and licensing analyses for this cycle were performed by General Electric (GE) with results documented in the Supplemental Reload Licensing Report. GE reload core design bases and analysis methods are described in GESTAR II . Operating limits for the cycle [i.e., Linear Heat Generation Rate (LHGR), Minimum Critical Power Ratio (MCPR), and Maximum Average Planar Linear Heat Generation Rate (MAPLHGR)] as determined by the'icensing analyses are incorporated into the TVA BFN Unit 2 COLR. Consistent with NRC commitments, GE completed a cycle specific Safety Limit MCPR (SLMCPR) analysis. The results confirm that the 1.10 SLMCPR contained in the current Unit 2 Technical Specifications is applicable for Cycle 10. The SRLR documents a SLMCPR of 1.11 applicable for Single Loop Operation (SLO) and also addresses MAPLHGR multiplier results associated with SLO. However, BFN Technical Specifications do not currently allow extended operation with SLO. The SLO analysis results are included to support a future Technical Specification change and SLO limits will not be included in the current COLR. The BFN 2 Cycle 10 core is a Control Cell Core (CCC) design with a predicted full power life of approximately 10600 MWD/ST or 476 Effective Full Power Days (EFPD). Increased core flow, feedwater temperature reduction, and coastdown capability may be used to increase this. Design cycle energy at End-of-Cycle 10 is 491 EFPDs, but this may be exceeded as long as peak pellet exposure and Environmental Qualification (EQ) program limits are not exceeded. The fresh fuel type for Cycle 10 is the GE1 3 design. This is the first reload of GE13 fuel at BFN. The only significant difference between GE13 and the previously loaded GE11 fuel design is that GE13 has eight 12
Tennessee Valley A uthori ty Broivns Ferry Ãuclear Plant
'/997Annua/O eratin Re ort
SUMMARY
OF SAFETY EVALUATIONS spacers with the part length rods terminating just above the sixth spacer whereas GE11 has 7 spacers with the part length rods terminating just above the filth spacer. The part length rods in the GE13 design are approximately 12" longer than the part length rods in GE11. The addition of the extra spacer in the upper region of the GE13 fuel assembly results in an increase in the critical power capability due to better flow mixing within the bundle. The GE13 design was previously evaluated and approved for use at BFN. The Cycle 10 core will contain all barrier fuel bundles and there will be no PCIOMR restrictions on Cycle 10 operation. However, PCIOMR-like restrictions will be conservatively applied to fuel with recent operating history at low power. The Cycle 10 core loading will contain 104 3.25/3.26 GE9B assemblies manufactured between 1988 and 1994 which have less degradation resistant cladding. Should any fuel failures occur during the cycle, some form of power suppression and/or PCIOMR-like constraints may be imposed to prevent further degradation. During the Unit 2 End-of-Cycle 9 outage, the existing power range neutron monitoring system will be replaced with a new GE digital NUMAC Power Range Neutron Monitoring (PRNM) retrofit system. This will be the first application of PRNM at BFN. The PRNM system is described in GE Licensing Topical Report NEDC-32410P. Technical Specification changes supporting PRNM have been submitted by TVA to NRC. Installation of the PRNM system will allow BFN to proceed with implementation of the BWR Owner's Group (BWROG) defined "Option III" long-term stability solution. The PRNM equipment includes capability for an automatic Oscillation Power Range Monitor (OPRM) trip to detect and suppress possible thermal hydraulic instabilities in the reactor. However, during Cycle 10 the OPRM portion of the system will be operated in the "indicate only" mode, and the stability trip function will not be enabled in order to allow an evaluation period. As part of the PRNM modification, the number of Average Power Range Monitor (APRM) instrument channels will be reduced from six to four and the Local Power Range Monitor (LPRM) inputs to the APRMs will also be reconfigured. However, all power range monitor functions are maintained, including LPRM signal processing, LPRM averaging, APRM trips, and RBM logic and interlocks. The replacement equipment will continue to enforce control rod blocks and initiate reactor scrams under appropriate specified conditions. This includes the APRM High Flux (120% rated power) scram assumed in the reload licensing transient analyses. BFN Unit 2 Cycle 10 will also indude implementation of the ARTS/MELLLAImprovement Program. This will be the first application of ARTS/MELLLAat BFN. The ARTS/MELLLAimprovements are described in . GE Licensing Topical Report NEDC-32433P. Technical Specification changes supporting ARTS/MELLLA have been submitted by TVA to NRC. The purpose of the ARTS/MELLLAchanges is to enhance operating flexibilityand efficiency by implementing RBM design improvements, incorporating APRM/RBM TS improvements, and expanding the current allowable operating domain to include the MELLLAregion of the power/flow map. As part of the ARTS improvements, the APRM trip setdown is replaced by a combination of power-dependent and flow-dependent MCPR operating limits. Replacement of the current APRM trip setdown requirement by more meaningful power- and flow-dependent thermal limits eliminates the need for manual setpoint adjustments and is expected to enhance administration of thermal limits compliance. The flow-biased APRM setpoints are also changed to restore the slopes of the flow-biased APRM scram and rod block setpoints to their original design basis values, and to restore the original design basis margin between the maximum extended load line and the APRM flow-biased scram set point. These flow-biased APRM setpoint changes maximize plant operating flexibility. Additional ARTS improvements include modification of the RBM system to reconfigure the LPRM to RBM channel assignments to improve the correlation of RBM response with actual changes in fuel thermal margin during control rod withdrawals. The RBM system is also modified from flow-biased to power-dependent trips to allow use of a new generic non-limiting analysis for the Rod Withdrawal Error (RWE). The expanded operating domain provided by MELLLAallows operation at full power down to 75% rated 13
Tennessee Valley Authority Browns Ferry Nuclear Plant
/997AnnualO eratin Re ort
SUMMARY
OF SAFETY EVALUATIONS flow conditions. Expansion of allowable operation to the MELLLAregion provides enhanced ability to achieve and maintain operation at rated power. Because rated power can be maintained with recirculation flow adjustments over a wider flow range, less frequent control rod adjustments are required to compensate for reactivity depletion, and the need for power reductions to perform control rod withdrawals is decreased. Other operating flexibilityoptions analyzed for BFN 2 Cycle 10 include Increased Core Flow (ICF), Final Feedwater Temperature Reduction (FFWTR), Feedwater Heaters Out Of Service (FWHOOS), and Turbine Bypass Out Of Service (TBOOS). The cycle is also analyzed for Banked Position Withdrawal Sequence (BPWS) rod movement. The BPWS procedure must be followed in order to stay within the licensed Rod Drop Accident (RDA) design basis. [Note: The SRLR also includes analysis results for Recirculation Pump Trip Out Of Service (RPTOOS). However, current BFN Technical Specifications do not allow extended operation with RPTOOS above 30% rated power. This option was analyzed to support transition to Improved Standard Technical Specifications (ISTS) and is not included in the current COLR. A revised COLR will be prepared prior to ISTS implementation that will include applicable thermal limits for operation with RPTOOS.] I Cycle 10 is designed for moderate MELLLAspectral shift operation. Spectral shift can extend full power operation by increasing the void content (spectrum hardening) during the fitst part of the cycle which increases plutonium production in the upper part of the core. Spectrum hardening is enhanced with operation at lower flow rates and by using rod patterns to obtain more bottom peaked power distributions. Thus, the lower flow rates afforded by the MELLLAregion also provide increased opportunity for achieving spectral shift benefits. Twelve control blades will be replaced during the End-of-Cycle 9 outage. The replacement blades will be GE Marathon control blades which have been previously evaluated and approved for use . This will be the first application of the GE Marathon control blade design at BFN. The Marathon design offers increased blade lifetimes due to increased absorber loading and absorber tube design improvements. No URM assemblies will be replaced during the End-of-Cycle 9 outage. The following UFSAR sections are affected by the Cycle 10 reload core design: - Section 3.7.6.1, "Power/Flow Operating Map," needs to be revised to note the expanded MELLLA operating region which is licensed for Unit 2. Also, Figure 3.7-1, "Operating Map," needs to be replaced with two unit specific operating maps in order to show the MELLLAregion for Unit 2 and the ELLLAregion for Unit 3. - Section 3.7.7.1.2, "MCPR Operating Limit Calculational Procedure," needs to be revised to include a description of the new power- and flow4ependent MCPR limits associated with ARTS. - Section 3.7.7.2 2, "Operating Flexibility Options," needs to be revised to include ARTS and MELLLA. - The BFN Unit 2 Cycle 10 Supplemental Reload Licensing Report needs to be incorporated into Appendix N of the FSAR. The BFN Unit 2 Cycle 10 reload core design is acceptable from a nuclear safety standpoint. Due to necessary revisions to the UFSAR and the requirement to issue a Unit 2 Cycle 10 COLR, a 10CFR50.59 safety evaluation is required. No additional Technical Specification revisions are required. No unreviewed safety question is involved.
Tennessee Valley Authority Browns Ferry iVuclear Plant
/997 Annual 0 eratin Re ort
SUMMARY
OF SAFETY EVALUATIONS CORE OPERATING LIMITS REPORT - BF3C8 This safety evaluation supports the Browns Ferry Nuclear (BFN) plant Unit 3 Cycle 8 reload core design and the cycle specific Unit 3 Core Operating Limits Report (COLR) . The reload core design and licensing analyses for this cycle were performed by General Electric (GE) with results documented in the Supplemental Reload Licensing Report (SRLR). Operating limits for the cycle [i.e. Linear Heat Generation Rate (LHGR), Minimum Critical Power Ratio (MCPR), and Maximum Average Planar Linear Heat Generation Rate (MAPLHGR)] as determined by the licensing analyses are incorporated into the TVA BFN Unit 3 COLR. A cycle specific MCPR safety limit (SLMCPR) of 1.10 is reported in the SRLR. This is the result of a cycle specific SLMCPR analysis performed in compliance with recent NRC commitments and as now required in revision 13 of GESTAR-II. This value is consistent with Technical Specification Change Number 377. Note: An additional SLMCPR and MAPLHGR multiplier for extended single recirculation loop operation are also reported in the SRLR. Single loop operation is not allowed by current Browns Ferry Technical Specifications. These are included in the SRLR to support a future technical specification change and are not included in this COLR. The BFN 3 Cycle 8 core is a Control Cell Core (CCC) design with a predicted full power life of approximately 10,525 MWD/ST or 479 EFPD. This includes cycle extension utilizing increased core flow. Final Feedwater Temperature Reduction (FFWTR) may be used to further extend full power capability. The Cycle 8 core may continue to operate in a coastdown mode as long as peak pellet exposure and EQ program limits are not exceeded. The fresh fuel type for Cycle 8 is the GE11 design. This is the third reload at Browns Ferry using the GE11 fuel type, the second GE11 reload for Unit 3. The use of the GE11 design at Browns Ferry has been previously evaluated. A modification to the design of the water rod in the GE11 fuel has been made by GE as part of an effort to standardize the larger diameter central portion of the water rod to match GE12 values. This water rod modification differs in two respects from GE11 fuel received previously at Browns Ferry. The transition piece from smaller to larger diameter is located 3.3" lower and the exit hole location has been raised 0.2". GE has evaluated this change for effect on seismic considerations, mechanical considerations, thermal-hydraulics, flow-induced vibration, nuclear design and modeling, and accident analyses. They found the changes to be acceptable with "...no discernible effect on fuel performance reliability and monitoring." The Cycle 7 and 8 GE11 bundles, Cycle 6 GE7B bundles, and a single twice-burnt (Cycle 5) LIA bundle are all of the barrier cladding design with no PCIOMR restrictions. The remaining fuel in the Cycle 8 core does not contain bamer cladding and all PCIOMR constraints remain in effect for these bundles. No control rod or LPRM replacements are currently planned for the end-of-cycle (EOC) 7 outage. BFN 3 Cycle 8 is analyzed for Extended Load Line Limit Analysis, Increased Core Flow, FFWTR, and Feedwater Heaters Out of Service. The cycle is also analyzed for Banked Position Withdrawal Sequence (BPWS) rod movement. The BWPS procedure must be followed in order to stay within the licensed Rod Drop Accident design basis. Note: Two additional operating flexibilityoptions have been included in the SRLR. These are turbine bypass out-of-service and EOC recirculation pump trip out-of-service. These analyses were performed in order to support transition to Improved Standard Technical Specifications (ISTS) during Cycle 8 operation but are not part of the current COLR. A revised COLR will be prepared prior to ISTS implementation that will include these results. 15
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997 Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS Cycle 8 is designed for spectral shift operation. Spectral shift can extend full power operation by increasing the void content (spectrum hardening) during the first part of the cycle which increases plutonium production in the upper part of the core. Spectrum hardening is enhanced with operation at lower flow rates and by using rod patterns to obtain a more bottom peaked power distribution. Failure to achieve the proper power distribution may affect cycle full power capability. This is the first application of SAFER GESTR LOCA analysis for Unit 3. The first BFN application was performed for Unit 2 Cycle 9. This safety evaluation supports a proposed Technical Specification Bases change for Section 3.5.N "References". This change updates the list of references to document the updated LOCA analysis. This evaluation also supports proposed UFSAR modifications required to extend the applicability of the SAFER GESTR LOCA analysis to Unit 3. These changes remove information pertaining to the older SAFE/REFLOOD analysis as well as indicate applicability of SAFER/GESTR to Unit 3. No unreviewed safety question exists. 16
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS 1997
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OF SAFETY EVALUATIONS FOR FIRE PROTECTION REPORT REVISIONS
0 Tennessee Valley Authority Broadens Ferry Pluolear Plant
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OF SAFETY EVALUATIONS FIRE PROTECTION REPORT CHANGE NOTICE ¹96006 This safety evaluation is written in support of Fire Protection Report (FPR) Change Notice ¹96006. FPR Change Notice ¹96006 reflects changes to the Fire Protection Plan, Fire Hazards Analysis, and Appendix R Safe Shutdown Program Sections of Volume 1 of The Fire Protection Report. A synopsis of the changes associated with each of these sections is provided below: Fire Protection Plan: Tables 9.3.11.C and 9.3.11.H dealing with Hose Stations have been combined. The
'Location'nformation has been deleted. Also, other minor corrections and clarifications have been provided.
Fire Hazards Analysis: The affected sections have been revised to reflect changes in the combustible loading and to reflect other minor corrections. Discrepancies in the compartmentation drawings regarding . fire damper information have been corrected. Safe Shutdown Program: The Unit 2 RCIC System was added to the Safe Shutdown Program on a previous change but was inadvertently located in the Unit 3 Program Section based on incorrect page numbers. The page numbers have been corrected to relocate the Unit 2 RCIC System in the Unit 2 Program Section. Previously there has been some confusion over the use of the 250V Shutdown Board Spare Battery Charger and its relationship with the Appendix R Program. Therefore, the 250V Spare Battery Charger has been added to the Safe Shutdown Program Section as an acceptable substitute for the normal 250V Shutdown Board Battery Chargers. Previously there has also been some confusion over the EECWSectionalizing Valves and their role in the Appendix R Program. Therefore, these valves have been added to the Appendix R Safe Shutdown Program to clarify when and where compensatory measures are required for these valves. Finally, the switch numbers for the 250V Distribution Panels (SB-A, SB-B, SB-C and SB-D) were changed as the result of modifications performed under DCN W17273, but did not get changed under the DCN. Therefore, these switch designations are being corrected to agree with the present plant configuration as modified under DCN W17273. There are no physical changes being made to the plant under FPR Change Notice ¹96006, therefore there is no adverse impact on any system operation characteristics. The Fire Protection Report (Vol. I) is referenced in Section 10.11 of the Safety Analysis Report as being the licensing basis for BFN's Fire Protection Program and is treated like any other UFSAR section, therefore a safety evaluation was required. No unreviewed safety question exits. Revision 1 of the safety assessment/safety evaluation was written to address a problem identified by BFPER970870. Specifically, the PER stated that the safety evaluation should contain justifications for the changes as if the plant were actually configured/being operated as described in the existing FPR and the changes were being proposed for future implementation. Therefore, as part of the corrective action for this PER, the safety assessment and the safety evaluation have been revised and a screening review has been added. The conclusion reached for this new revision of the safety evaluation is the same as that from the previous revision in that there is no adverse impact on nuclear safety as a result of the changes being made under FPR Change Notice ¹96006 and thus no unreviewed safety question exists.
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS 1997
SUMMARY
OF MISCELLANEOUS SAFETY EVALUATIONS
Tennessee Valley Authority Browns Ferry Nsclear Planl
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OF SAFETY EVALUATIONS CAUTION ORDER 3-97-635 This safety evaluation addresses Caution Order 3-97-635 which will alter the normal valve alignment of the RCIC system as shown on TVA Drawing 3-47W813- 1. This Caution Order will close the valves 3-SHV-071-0570 and 3-SHV-071-0571, the Reactor Core Isolation Cooling system (RCIC) steam supply trap inlet and outlet shutoff valves. These valves, which are normally open, are being closed to isolate the RCIC steam supply trap, 3-TRP-071-010, which has developed a steam leak in the bottom side of the trap body. These valves will remain closed until a new steam trap is procured and installed by Work Order 97-009032-000. The steam trap maintains the RCIC turbine steam supply line in a standby readiness condition by preventing buildup of condensate/moisture in the RCIC steam supply line. This moisture removal function be performed by the Level Control Valve, 3-LCV-071-005 and its associated control circuit. This LCV 'ill bypasses the normal steam line trap and opens when called upon by a level switch which is physically located above the normal steam trap. This ensures that the water level in the steam line is not excessive". I FSAR Figure 4.7-la shows the functional configuration of the RCIC system. This drawing shows that the steam trap isolation valves, 3-SHV-071-0570 and 3-SHV-071-0571, are normally open. Since this system alignment is not in accordance with the UFSAR Figure, a Safety Evaluation is required. This temporary change does not affect the functional configuration of the system. No unreviewed safety question is involved. OFFGAS STEAM PACKING EXHAUSTER BYPASS LINE ISOLATION This Safety Evaluation documents the isolation of the SPE Bypass Discharge Line during normal power operation. This isolation was necessary because the operability of the in-line back draft dampers could not be assured. This alignment is contrary to the requirement specified in Note 11 of 2-47E809-2 Revision
- 21. It should be noted that the requirement to maintain flow through both SPE discharge flow paths assumes both sets of back daft dampers are operable.
The SPE discharge system consists of two 100% capacity discharge lines. Up until April 1995, the normal operation was for the main line to be in service with the bypass line in standby. Whenever maintenance was required on the main discharge line, the bypass line could be placed into service. However, water was found to accumulate above the back drafts dampers in the out of service line. This condition damaged the damper seals and prevented the dampers from providing the required sealing action. Since the SPE Bypass Discharge Line dampers were found in a configuration which has known detrimental effect on the back draft dampers, the operability of bypass line back draft dampers is questionable. Therefore, the conservative approach was used and the SPE Bypass Discharge Line was isolated. Removal of independent, redundant equipment from service is a normal plant operation. From a plant configuration control, the damper alignment is controlled by Hold Order 0-97-0331 until such time as the material condition of the SPE Bypass Discharge Line back draft dampers can be verified. No unreviewed safety question is involved. 20
Tennessee i~alley Authority Browns Ferry Nuclear Plant l997Annual 0 eralin Re ort
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OF SAFETY EVALUATIONS REACTOR FEEDWA TER PUMP MINIMUMFLOW ISOLATION VALVECLOSURE (WORK REQUES T NUMBER C1 14749) This activity involves temporary isolation of the Reactor Feedwater Pumps Minimum Flow Isolation Valves, 2-3-507, 2-3-516, and 2-3-525. This activity will be used to determine the cycle performance affect from the leaking Minimum Flow Control Valves. No design basis accidents are affected by this activity. Loss of Feedwater and Excess of Coolant Inventory are the related abnormal operational transients associated with this activity. The only credible failure during this activity is the inability to re-open the manual Minimum Flow Isolation Valves when restoring the system to normal. The general operation of the Minimum Flow Control Valves and a description stating that they will open to provide a flow path to the Main Condenser during low flow conditions is mentioned in the text of Section 11.8 of the FSAR. Also, the drawings in Section 11.8 show an open position for the Minimum Flow Line Isolation Valves. This activity will not affect any Technical Specifications nor affect any other related systems Technical Specifications. No unreviewed safety question is involved. TEMPORARY STRUCTURE CONTROL FORM 0-97-001-RB A Temporary Structure Control Form (TSCF) has been prepared to approve the positioning of the Operations Senior Reactor Operator (SRO) shack-on any unit of the refuel floor. This structure is required to be climatically controlled, because it will be the SRO control point for any work performed prior to and during the outage. This building is constructed of prefabricated wall panels approximately 3" thick. This structure can be located on the north side of the refuel floor, on top of the new fuel storage vault covers. There are three ways to ensure the SRO structure will be seismically qualified so that it will not affect any safety related equipment or the spent fuel pool. All of these alternates are described in Engineering Work Request 97-0-303-092. Services to be provided include temporary power for 110v outlets, lighting, air conditioning, and a temporary telephone connection. The temporary power can be furnished through any of the 110v power receptacles located on the south side of the columns R4, R5, or R6, Unit I; R9, R10, or R11, Unit 2; or R16, or R18, Unit 3 and Px-line, on elevation 664'. The 110v power receptacles on elevation 664'how on TVA drawings 1-45N1412-1, 245N2412-1 and 3-45N3412-1, and they are connected to breaker 4 in Lighting Cabinets LC111, LC211, and LC311. These lighting cabinets are connected to 240v Lighting Board 2B in compartments 2A2, 2B1, and 3B2, respectively, which shows on TVA drawing 2-45E734-2. Even if the circuit was overloaded it would only affect this one circuit (Breaker 4, Lighting Cabinet 111, 211, or 311), shown on TVAdrawings 1-45N1412-1, 2-45N2412-1 and 3-45N3412-1 and would not affect any safety related equipment. The only equipment fed from these breakers are claxton warning horns for radiation monitors I-RE-090-0001, 2-RE-090-0001, 2-RE-090-0030 and 3-RE-090-0001. All of the other components of these radiation monitors are fed from the control room and would not be affected. There is also a warning light on the panel which will continue to work even if the horn circuit was affected. The temporary telephone connection will be connected to the closest extension to the building location. All connected power shall be installed in accordance with the Institute of Electrical and Electronic Engineers (IEEE) Standards and the National Electrical Code (NEC). The temporary structure and associated equipment shall be disconnected from temporary power as soon as possible after the outage. The structure will be stored at one of the locations mentioned, until it is 21
Tennessee Valley Authority Browns Ferry Nuclear Plant
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OF SAFETY EVALUATIONS moved to another location for the next outage. The temporary structure which is required to house the refuel floor SRO and other equipment will be installed in such a manner'that it will meet the seismic qualification requirements such that no safety related equipment will be jeopardized by any design condition or event, including seismic equipment inside and outside the SRO structure which will be controlled in accordance with SSP-12.7, Housekeeping/Temporary Equipment Control, and installed in accordance with the NEC. This installation is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. TEMPORARY S TRUC TURE CONTROL FORM 1-97-001-RB I This activity is for moving a temporary structure approved under TSCF 2-95-001-RB at R14 and U-Line, i Unit 2 to between R2-R3 and T-U-Line, Unit 1, and adding another cage of the same type, size and design on the east side of the existing cage on the refuel floor. These structures are for the storage of tools and other equipment used by the refuel floor personnel on all units during their normal operating processes and during outages. This is to keep down the lost time of having to go and check out this material from the Tool Room. Also, some of this material is special to the refuel floor and cannot be used any other place. The existing and new temporary structures are fabricated from 3x3x1/4" angle frames banded at the top and bottom and supported at the corners and in the center of the long walls by the same size angles. All welds for the frame will be butt welds, except for the intermediate columns and they will be fillet welds. There will be 3x3x1/4" angles placed 4'part across the top of the structure which will be welded with a combination of fillet and butt welds. The temporary structures also have sliding access doors made from grating and will have a lock and hasp for controlling access into the structures. The doors will be made from the same material as the rest of the structure and welded in the same manner. The walls and top of the structure are fabricated with 36" wide and 1" deep grating. The grating has 1" deep by 1/4" thick load bars spaced on 1-3/16" centers. The cross bars are resistance welded at right angles to the bearing bars and have a hexagonal cross section. The bearing bars are located on 4" centers. The grating on the top of the structures will be laid long ways from front to back on top of the angles and welded. The grating on long side walls is laid with the load bars horizontal from front to back and the back wall is laid with the load bars horizontal. The grating for the front wall, with the door, is vertical, except above the door which is horizontal. The grating on the long side and the back of the structures will welded. The back will be welded the same as the sides, except there is no interior angle. The grating for the front wall, with the door, is vertical and will be welded. All of the material is ASTM A-36 or SA-36 and all welding has been/will be performed in accordance with approved plant procedures. The temporary structures which are required to store miscellaneous materials for use on the refuel floor were evaluated for seismic concerns by Engineering Work Request (EWR) 97-1-303-090 and found to be of no concern and no safety-related equipment will be jeopardized by any design condition or event, including seismic. The moving of the temporary structure from Unit 2 to Unit 1 will be performed in accordance with SSP-6.6 and NUREG-0612. All of the materials in the temporary structures will be controlled in accordance with SSP-12.7, Housekeeping/Temporary Equipment Control. This installation is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. 22
Tennessee Valley Authority Brogans Ferry >Vue/ear Plant
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OF SAFETY EVALUATIONS TEMI ORARY STRUCTURE CONTROL FORM 1-97-002-RB This safety evaluation is being written in support of a Temporary Structure Control Form (TSCF) which has been prepared to justify the existing Traversing Incore Probe (TIP) rebuild facility located in the Unit 1 reactor building on elevation 621'. This facility is used to rebuild the TIP units when needed during Unit 2 or 3 refueling outages. This structure is dimatically controlled and is considered as a C-Zone by RADCON. The temporary structure is constructed of sheet metal panels approximately 3'-8" wide by 7'-4" high with a 2" rolled flange which is welded at the corners. The sheets are approximately 3/32" thick. The interior panels are attached together with ASTM A307 minimum bolts by 1/4" long and located 6" on centers. The interior joints of the roof panels are attached together in the same manner as the interior joints of the side The corner panels are attached together with 2'x2'x1/4" angle bolted to the two side panels with 'anels. ASTM A307 minimum bolts located 6" on centers. The roof panels are attached to the side panels in the same manner as the corner panels. There is a wood sill between the floor and the wall panels which is attached to the floor. The metal wall panels are attached to the wood sill with nails, but they are not spaced at 6" on center as the procedure requires. This will be corrected so the structure will meet all of the requirements of 0-Tl-287. The entrance door is located at the east of the structure and is located in the center of the panels as stated in the procedure. There is an air conditioner in one of the interior panels on the south wall of the structure. There are windows made of plexiglass in frames on the north side of the structure. The structure is approximately 7'-8"x22'-9"x7'-8" high and is located between column lines R3 - R4 and T -U-Lines on elevation 621'f the Unit I reactor building. The services provided are temporary power for 110v outlets, lighting, and an air conditioner. If a temporary telephone is needed it will be connected to the closest telephone to the structure. The temporary power will be furnished to the structure by a 110v duplex receptacle located on the north side of the column at R4 and U-Line. The 110v duplex receptacle on elevation 593'hows on TVA drawing 1-47N1408-2, which is connected to breaker 7 in Lighting Cabinet (LC) 106 and is connected to the 240v Lighting Board 1A in compartment 3B2, which shows on TVA drawing 1-45E734-1. All connected power to the temporary structure will be installed in accordance with the Institute of Electrical and Electronic Engineers (IEEE) Standards and the National Electrical Code (NEC). The temporary building and associated equipment will be disconnected from the temporary power when the temporary structure is not in use. The temporary structure which is required to house the TIP rebuilding material and other equipment has been erected in such a manner that it will meet the seismic justification requirements such that no safety related equipment will be jeopardized by any design condition or event, including seismic. Equipment inside and outside the TIP rebuild structure will be controlled in accordance with SSP-12 7, Housekeeping/Temporary Equipment Control, and installed in accordance with the NEC. This installation is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. 23
Tennessee Valley Authority Broiuns Ferry /nuclear Plan!
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OF SAFETY EVALUATIONS TEMPORARY S TRUC TURE CONTROL FORM 1-97-003-R8 A Temporary Structure Control Form (TSCF) has been prepared to implement Work Request No. C233428, which request a temporary facility for General Electric (GE) use during the Unit 2 Cycle 9 outage for the Internal Vessel Inspections. This facility is required to be climatically controlled, because it will house all of the computer and test equipment for use prior to and during the outage . During the testing it will be used as a controlled test station. The temporary facility requested is to be a Tube-Loc (Tube and Coupler) scaffold frame, with Herculite attached to the frame structure (1 0'-0"x8'-0"x8'-0" high) and is to be located on the refuel floor of the Unit 1 reactor building between R6 & R7 at P-line on elevation 664'. The frame will be tied together with heavy duty couplers made especially for this purpose. There will be a Tube-Loc box frame around the existing column as described in Engineering Work Request (EWR) 97-0-303-100. The frame shall be anchored to the floor with one 1/2" diameter or larger SDI concrete anchor located at each comer of the frame in accordance with EWR 97-0-303-100. The enclosure is to be anchored at these locations by bolting a Tube-Loc clamp to an eyebolt inserted into the anchor. A tolerance of a 12" along the Tube-Loc may be used for anchor location. The installation of the anchors and box will make the enclosure seismic. The air conditioner platform shall be fabricated from Tube-Loc (Tube and Coupler) scaffolding and shall have members extending to the floor and be rigidly attached to the frame to prevent overturning from accidental bumping or seismic events. Services to be provided include temporary power for 110v outlets, lighting, air conditioning, a temporary telephone connection, a service air supply, and demineralized water. The temporary power will be furnished through a welding receptacle located on the south side of the horizontal brace between column lines R8 & R9 and P-line, on Elev 664. The welding receptacle on Elev. 664 shows on TVA drawing 2-45N2755-5 and is connected to the breaker in the 480V Reactor Building Vent Board 2A in compartment 8D, which shows on TVA drawing 2-45E2755-3. The temporary telephone connection will be connected to the closest extension to the building location. The air supply, if required, will be taken from a service air supply connection located on the west face of the column R9 and P-line. If a demineralized water supply is required it will be taken from a supply connection located on the west side of the column at R9 8 P-line next to the air supply connection. All connected power shall be installed in accordance with the Institute of Electrical and Electronic Engineers (IEEE) Standamls and the National Electrical Code (NEC). The temporary structure and associated equipment shall be removed as soon as possible after the Unit 2 Cycle 9 outage. The temporary enclosure which is required to house the GE computers and other equipment will be erected in such a manner that it will meet the seismic qualification requirements such that no safety related equipment will be jeopardized by any design condition or event, including seismic. Equipment inside and outside the GE enclosure will be controlled in accordance with SSP-12.7, Housekeeping/Temporary Equipment Control, and installed in accordance with the NEC. This installation is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. 24
0 Tennessee Valley Authority Browns Ferry leuc/ear Plant
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OF SAFETY EVALUATIONS TEMPORARY S TRUCTURE CONTROL FORM 2-97-001-RB This safety evaluation is being written in support of a Temporary Structure Control Form (TSCF) which has been prepared to implement Work Request No. C193189, requesting a temporary facility for Inservice Inspection (ISI) use during the Unit 2 Cycle 9 outage. This facility is required to be climatically controlled, because it will house all of the computer and test equipment for use prior to and during the outage. During the testing it will be used as a controlled test station. The temporary facility requested is to be an inflatable tent structure (11'-0"x15'-0"x8'-0" high) and is to be located in the southwest corner of the Unit 2 reactor building between R8 & R9 and T & U-lines on elevation 593'. The frame for the tent will be erected with 12 gauge low carbon steel (1-5/8"x1-5/8") channel with a galvanized finish. The frame will be tied together with heavy duty hardware clips made especially for this purpose. All connections will be bolted with (1/2" - 13x1-1/4") bolts. There are three different clips, the clips for the top intermediate post will have 8 bolts holding them in place, the clips for the bottom of the intermediate post will have 6 bolts holding them in place, and the corner post will have clips at the top and bottom of the frame and they will have 6 bolts holding them in place. The frame shall be anchored to the floor with 3/8" diameter or larger SDI concrete anchors located at the middle of each section on the sides and at the middle of the 2 outside sections of the end frames. The upper horizontal member of the rear (west) frame shall be anchored to the R8 line wall with 1/2" diameter or larger SDI concrete anchors located at the center of the 3 end frame sections. The upper horizontal member of the lelt (south) wall shall be anchored to the U-line wall with 1/2" diameter or larger SDI concrete anchors and a Tube-Loc scaffold member connecting the frame to the anchor. Standard scaffold connections and eye-bolts are to be used. A total of three are required. This member should be perpendicular to the wall and as horizontal as possible. A tolerance of a 45 degrees iri any direction is allowable when locating this member. Any existing anchors in the floor or walls which are used for this installation, shall be pull-tested or have existing pull-test documentation. The inflatable unit is fabricated of 2-layers of 6 mil flame retardant polyethylene. The unit will be inflated to the proper size and then tied to the frame along the top outside rail frame. The air conditioner platform shall be fabricated from Tube-Loc scaffolding and shall have members extending to the floor and be rigidly attached to the frame to prevent overturning from accidental bumping or seismic events. An evaluation for the clean island on the refuel floor which is a smaller Inflatable Abatement Systems structure similar to this structure is contained in calculation CD-N1303-960121. Services to be provided include temporary power for 110v outlets, lighting, air conditioning, a temporary telephone connection, an air supply, and demineralized water. The temporary power will be furnished through a welding receptacle located, on the north side of the column, at R13 and S-line on Elev 593. The welding receptacle on Elev 593 shows on TVA drawing 245N2756-5 and is connected to the breaker in the 480V Reactor Building Vent Board 2B in compartment 9D1, which shows on TVA drawing 2-45E2756-
- 3. The temporary telephone connection will be connected to the dosest extension to the building location.
The air supply, if required, will be taken from a supply connection, located on the north face of the column R9 and T-line and the isolation valve number is 2-33-833. If a demineralized water supply is required it will be taken from a supply connection located on the north side of the column at R9 8 T-line next to the air ,supply connection and the valve number is 2-2-1227. All connected power shall be installed in accordance with the Institute of Electrical and Electronic Engineers (IEEE) Standards and the National Electrical Code (NEC). The temporary structure and associated equipment shall be removed as soon as possible after the Unit 2 Cycle 9 outage. The temporary enclosure which is required to house the ISI computers and other equipment will be 25
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997Annua/0 eratin Re or!
SUMMARY
OF SAFETY EVALUATIONS erected in such a manner that it will meet the seismic qualification requirements such that no safety related equipment will be jeopardized by any design condition or event, including seismic. Equipment inside and outside the ISI enclosure will be controlled in accordance with SSP-12.7, Housekeeping/Temporary Equipment Control, and installed in accordance with the NEC. This installation is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. TEMPORARY STRUCTURE CONTROL FORM 2-97-002-RB A Temporary Structure Control Form (TSCF) has been prepared to implement Work Request No. C233428, which request a temporary facility for General Electric (GE) use during the Unit 2 Cycle 9 outage for the Internal Vessel Inspections. This facility is required to be climatically controlled, because it ~ will house all of the computer and test equipment for use prior to and during the outage. During the testing it will be used as a controlled test station. The temporary facility requested is to be a Tube-Loc (Tube and Coupler) scaffold frame, with Herculite attached to the frame structure (11'-0"x16'-0"x8'-0" high) and is to be located on the refuel floor of the Unit 2 reactor building between R8 & R9 at P-line on elevation 664'. The frame for the enclosure will be erected with Tube-Loc (Tube and Coupler) scaffolding members with a galvanized finish. The frame will be tied together with heavy duty couplers made especially for this purpose. There will be a Tube-Loc box frame around the existing column as described in Engineering Work Request (EWR) 97-0-303-1 00. The frame shall be anchored to the floor with six 1/2" diameter or larger SDI concrete anchor located on the frame. The enclosure is to be anchored at these locations by bolting a Tube-Loc clamp to an eyebolt inserted into the anchor. A tolerance of a 12" along the Tube-Loc may be used for anchor location. The installation of the anchors and box will make the enclosure seismic. The air conditioner platform shall be fabricated from Tube-Loc (Tube and Coupler) scaffolding and shall have members extending to the floor and be rigidly attached to the frame to prevent overturning from accidental bumping or seismic events. Services to be provided include temporary power for 110v outlets, lighting, air conditioning, a temporary telephone connection, a service air supply, and demineralized water. The temporary power will be furnished through a welding receptacle located on the south side of the horizontal brace between column lines R8 & R9 and P-line, on Elev. 664. The welding receptacle on Elev. 664 shows on TVA drawing 2-45N2755-5 and is connected to the breaker in the 480V Reactor Building Vent Board 2A in compartment 8D, which shows on TVA drawing 2-45E2755-3. The. temporary telephone connection will be connected to the closest extension to the building location. The service air supply, if required, will be taken from a supply connection located on the west face of the column R9 and P-line. If a demineralized water supply is required, it will be taken from a supply connection located on the west side of the column at R9 & P-line next to the air supply connection. All connected power shall be installed in accordance with the Institute of Electrical and Electronic Engineers (IEEE) Standards and the National Electrical Code (NEC). The temporary structure and associated equipment shall be removed as soon as possible after the Unit 2 Cycle 9 outage. The temporary enclosure which is required to house the GE computers and other equipment will be erected in such a manner that it will meet the seismic qualification requirements such that no safety related equipment will be jeopardized by any design condition or event, including seismic. Equipment inside and outside the GE enclosure will be controlled in accordance with SSP-12.7, Housekeeping/Temporary Equipment Control, and installed in accordance with the NEC. This installation
Tennessee Valley Authority Browns Ferry nuclear Plant l997 Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. e4'b~~r~&c TEMPORARY S TRUC TURE CONTROL FORM 2-97-003-RB A Temporary Structure Control Form (TSCF) has been prepared to implement Work Request No. C233428, which request a temporary enclosure for General Electric (GE) use during the Unit 2 Cycle 9 outage. This enclosure is required to be climatically controlled because it will house all of the computer and test equipment for use prior to and during the outage. During the testing it will be used as a controlled test station. The temporary enclosure requested is to be a Tube-Loc (Tube and Coupler) scaffold frame, with Herculite attached to the frame structure (1 0'-0"x15'-0"x8'" high) and is to be located on elevation 593'f the Unit 2 reactor building between R9 8 R10 at S 8 T-line. The frame will be tied together with heavy duty couplers made especially for this purpose. The frame shall be anchored to the floor with eight 1/2" diameter or larger SDI concrete anchors located on the frame. The interior anchor locations may be relocated a 2'-0" along the Tube-Loc members to allow for the use of existing SDI anchors installed for the previous temporary structure and to allow flexibilityin the location of the door. The frame is to be connected to the SDI anchors by bolting the Tube-Loc clamps through eyebolts installed into the SDI shells. The framed Tube-Loc structure shall be sufficiently braced to ensure the frame behaves in a rigid manner. Additional Tube-Loc framing shall be provided as required to support the air conditioning unit. This framework shall be attached to the main framing sufficiently to prevent overturning from accidental bumping or a seismic event. The air conditioner platform shall be fabricated from Tube-Loc (Tube and Coupler) scaffolding and shall have members extending to the floor and be rigidly attached to the frame to prevent overturning from accidental bumping or seismic events. Services to be provided include temporary power for 110v outlets, lighting, air conditioning, a temporary telephone connection, a senrice air supply, and demineralized water. The temporary power will be furnished through a welding receptacle located on the south side of R9 and S-line on Elev. 593. The welding receptacle on Elev. 593 shows on TVA drawing 2-45N2756-5 and is connected to the breaker in the 480V Reactor Building Vent Board 2B in compartment 1D1, which shows on TVA drawing 2-45E2755-3. The temporary telephone connection will be connected to the closest extension to the building location. The service air supply, if required, will be taken from a supply connection located on the north face of the column R9 and T-line. If a demineralized water supply is required, it will be taken from a supply connection located on the north side of the column at R9 8 T-line next to the air supply connection. All connected power shall be installed in accordance with the Institute of Electrical and Electronic Engineers (IEEE) Standards and the National Electrical Code (NEC). The temporary structure and associated equipment shall be removed as soon as possible after completion of the associated work and prior to the end of the Unit 2 Cycle 9 outage. The temporary enclosure which is required to house the GE computers and other equipment will be erected in such a manner that it will meet the seismic qualification requirements such that no safety related equipment will be jeopardized by any design condition or event, including seismic. Equipment inside and outside the GE enclosure will be controlled in accordance with SSP-12.7, Housekeeping/Temporary Equipment Control, and installed in accordance with the NEC. This installation is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. 27
Tennessee Valley Authority Browns Ferry Nuclear Plant l997 Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS TEMPORARY STRUCTURE CONTROL FORM 3-97-001-RB A Temporary Structure Control Form (TSCF) has been prepared to implement Work Request No. C193189, which requests a temporary enclosure for Inseivice Inspection (ISI) use during the Unit 2 Cycle 9 outage for magnetic particle testing of the vessel head nuts. The temporary enclosure requested is to be a Tube-Loc (Tube and Coupler) scaffold frame, with Herculite attached to the frame and a scaffold board across one end to be used as a shelf for their equipment. The enclosure (8'X'x8'-0"x8'-0" high) is to be located on the refuel floor of the Unit 3 reactor building between R18 8 RI9 at T-line on elevation 664'. The frame is not required to be tied down in any way due to its location and the evaluation made by Engineering Work Request 97-3-303-098. Services to be provided include temporary power for 110v black lights. The temporary power will be furnished through a 110v receptacle located on the north side of the column lines RI9 and U-line, on Elev. 664. The temporary electncal load will be supplied from 240V Lighting Board No 2B and Compartment i 3A2, shown on TVA drawing 2-45E734-2. Even if the circuit was overloaded it would only affect this one circuit (Breaker 6, Lighting Cabinet 310), shown on TVA drawing 3-45N3412-2 and would not affect any safety related equipment. The only equipment fed from this breaker is a claxton warning horn for Radiation Monitor 3-RE-090-0002. All of the other components of this radiation monitor are fed from the control room and would not be affected. There is also a warning light on the panel which will continue to work even if the horn circuit was affected. The temporary enclosure and associated equipment shall be removed as soon as possible after the Unit 2 Cycle 9 outage. The temporary enclosure which is required to house the ISI for magnetic particle testing of the vessel head nuts will be erected in such a manner that it will meet the requirements such that no safety related equipment will be jeopardized by any design condition or event, including seismic. Equipment inside and outside the ISI enclosure will be controlled in accordance with SSP-12.7, Housekeeping/Temporary Equipment Control, and installed in accordance with the NEC. This installation is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. TECHNICAL SPECIFICATION SECTION 3.7/4.7 BASES CHANGE - TS-388 Maintaining the pressure suppression function of primary containment requires limiting the drywell leakage that bypasses the suppression pool. Technical Specification 4.7.A.4.d requires a test that measures the increase in suppression chamber pressure over a ten minute period with a minimum pressure differential of one pound per square inch. This test verifies that any leakage that bypasses the suppression pool is within allowable limits. The acceptable leakage from the drywell to the suppression chamber per Technical Specification 4.7.A.4.d has been determined to be 0.09 Ib/sec or approximately a 0.25" of water per minute pressure rise in the suppression chamber at a one psi differential pressure. This leakage rate corresponds to approximately a 1" diameter leak path from the drywell to the suppression chamber. Current Technical Specification Bases describe the drywell to suppression chamber leak test as follows. "The drywell pressure will be increased by at least one psi with respect to the suppression chamber and held constant". This Technical Specification Bases change proposes to delete "and held constant" from the end of the previously quoted statement. The purpose of this change is to delete the Technical Specification Bases wording regarding maintaining the drywell to suppression chamber differential pressure constant for the duration of the drywell to suppression chamber leak test. Although the methodology discussed in the bases provides suitable data for verifying that the drywell to suppression chamber leakage is within limits, it requires makeup to the drywell during the test to maintain the pressure 28
Tennessee Valley Authority Broivns Ferry Nuclear Plant
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OF SAFETY EVALUATIONS differential constant. Equivalent results can be achieved by establishing an initial differeritial pressure and allowing the pressure differential to decay during the test and ensuring the final differential pressure is greater than one psi. This methodology does not require makeup and would allow the test to be conducted with minimal resources. Furthermore, eliminating makeup for this test is consistent with the methodology described in Standard Technical Specifications. The proposed change to Technical Specification Bases is in compliance with all design criteria to ensure that the function and operation of primary containment and associated safety related systems are not adversely affected. The proposed changes will affect only the method used to demonstrate that drywell to suppression chamber leakage is within allowable limits as described in Standard Technical Specifications and is conservative in that the initial pressure will be established sufficiently high to ensure the final pressure is above the 1.0 psid differential required. This change will not cause the exceeding of any acceptance limit for any accident analysis, nor does it reduce the margin between the designed failure points or system limits as defined in the basis for any Technical Specification. Therefore, this change will not reduce any margin of safety for the primary containment system or any other system. No unreviewed safety question exists. WARM WATER TO FOREBA Y DIFFERENTIAL INSTRUMENTATION IS NOT AVAILABLEFOR COOLING TOWER OPERATION The 0-L-27-121 and -122 instrument loops alarm in the Unit 2 control room ifthe difference between the warm water channel and the forebay is a negative 2'r more or if the difference is a negative 8'r less. The alarm at a negative 2'r more is to alert operations that the warm water level is approaching a level where, if the cooling towers are in service with a vacuum established in the loop to the warm water channel, a siphon could be established. If this condition were to exist, then a trip of all the condenser circulating water (CCW) pumps could result in a back flow from the warm water channel to the forebay. This would distribute the hot water from the warm water channel to the suction of the Residual Heat Removal Service Water (RHRSN/)/Emergency Equipment Cooling Water (EECWI pumps. This would incapacitate the RHRSW and EECW systems. This function is described in the SAR, however, the margin to be maintained is not specified. The negative 8'r less indicates the warm water channel may be getting too low to support cooling tower operation. The last function ensures that a vacuum is maintained and has no impact from a nuclear safety standpoint. The 0-L-27-121 and -122 instrument loops are currently nonfunctional and cannot be returned to service due to modifications being performed on the loops (DCN T40075). The down stream river temperature may soon reach 90'F. For Unit 2 and 3 to continue operation at full power, it may become required for the cooling towers to be put in service without the 0-L-27-121 and -122 instrument loops. This will require that operations manually monitor the warm water to forebay differential by observing locally the forebay level once a shiit and maintain the warm water channel at least one foot below the forebay level. The forebay level is the same as the reservoir level and will not vary greatly over an eight hour period. This activity is safe from a nuclear standpoint. The system parameters were reviewed with respect to this activity. The breaking of the vacuum to the cooling towers is manual and although the alarm function will be accomplished manually instead of automatically the breaking of vacuum will be taken to maintain a negative 1'argin which will meet the intent of the SAR. The only deviation from the UFSAR is in the content of the technical description. The operation and function of the system remains within the description of the SAR. No unreviewed safety question is involved.
Tennessee Valley Authority Broivns Ferry Pluelear Plant l997Annual 0 eratin Re art
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OF SAFETY EVALUATIONS WORK ORDER 97-004496-000
¹ Work Order (WO) 97-004496-000 will provide power supply to loads off of Panel 2-9-9 Cabinet 2 Distribution Panel from Unit 3 I & C bus A regulating transformer directly after bypassing the transfer switch so that the Normal and Alternate power supply to Panel 2-9-9 Cabinet 2 transfer switch 2-XSW-253-0002A can be removed and preventive maintenance (PM) EPI-0-253-SWZ001 performed on the transfer switch.
In order to tag out normal power supply for 2-XSW-253-0002A temporary power supply hook-up is also required for I & C bus A at Battery Board 2 Panel 8 per Ell-0-253-BRD001. Alternate supply cable 2M12-I is disconnected at terminals EA, EB and EC of transfer switch 2-XSW-253-0002A. Load cable between the transfer switch 2-XSW-253-0002A and Pane1 2-9-9 Cabinet 2 is disconnected at Panel 2-9-9 Cabinet 2 Distribution Panel bus and taped to protect the ends. An extension cable is connected to cable 2M12-I (lifted) and other end of extension cable is terminated at Panel 2-9-9 Cabinet 2 Distribution Panel bus. There will be a loss of power supply to all loads fed by Panel 2-9-9 Cabinet 2 distribution panel during the period alternate supply cable 2M12-I is connected to the Panel 2-9-9 Cabinet 2 distribution panel bus. After PM EPI-0-253-SWZ001 is complete there will be another loss of power supply to all loads fed by Panel 2-9-9 Cabinet 2 distribution panel during the period alternate supply cable 2M12-1 is restored to its normal configuration. These periods are to be kept to a minimum by performing the installation steps in an expedient manner. This WO is performed when Unit 2 is in cold shutdown condition. During normal operation if normal ~ power supply is not available to Panel 2-9-9 Cabinet 2, the transfer switch transfers to provide power to Panel 2-9-9 Cabinet 3 from alternate power supply. During the performance of this WO, the same alternate power supply will still provide power supply to Panel 2-9-9 Cabinet 2 directly with the transfer switch bypassed. There will be two periods during transition at which time there will be a loss of power to all loads fed by this cabinet. Operator actions per 2-AOI-57-5A are required. This period is kept to a minimum by performing the required steps in the WO in an expedient manner. Hence, the activities per this work order are safe from a nuclear safety standpoint. Performance of this work order does not increase the probability or consequences of an accident previously evaluated in the UFSAR and does not increase the probability or consequences of a malfunction of equipment important to safety previously evaluated. Performance of the WO does not create the possibility of an accident or malfunction of a different type than any evaluated in the SAR. This WO has no impact on the margin of safety as defined in the basis for any Technical Specification. No unreviewed safety question is involved. WORK ORDER 97-004496-001
¹ Work Otder (WO) 97-004496-001 will provide power supply to loads off of Panel 2-9-9 Cabinet 3 Distribution Panel from Unit 1 I & C bus B regulating transformer directly after bypassing the transfer switch so that the Normal and Alternate power supply to Panel 2-9-9 Cabinet 2 transfer switch 2-XSW-253-0002B can be removed and preventive maintenance (PM) EPI-0-253-SWZ001 performed on the transfer switch.
In order to tag out normal power supply for 2-XSW-253-0002B temporary power supply hook-up is also required for I & C bus B at Battery Board 2 Panel 8 per Ell-0-253-BRD001. 30
Tennessee Valley Authority Browns Ferry Nuclear Plant I997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS Alternate supply cable 2MI-II is disconnected at terminals EA, EB and EC of transfer switch 2-XSW-2S3-00028. Load cable between the transfer switch 2-XSW-253-0002B and Panel 2-9-9 Cabinet 3 is disconnected at Panel 2-9-9 Cabinet 3 Distribution Panel bus and taped to protect the ends. An extension cable is connected to cable 2MI-II (lifted) and other end of extension cable is terminated at Panel 2-9-9 Cabinet 3 Distribution Panel bus. There will be a loss of power supply to all loads fed by Panel 2-9-9 Cabinet 3 distribution panel during the period alternate supply cable 2M1-II is connected to the Panel 2-9-9 Cabinet 3 distribution panel bus. After PM EPI-0-253-SWZ001 is complete there will be another loss of power supply to all loads fed by Panel 2-9-9 Cabinet 3 distribution panel during the period alternate supply cable 2M1-II is restored to its normal configuration. These periods are to be kept to a minimum by performing the installation steps in an expedient manner. This WO is performed when Unit 2 is in cold shutdown condition. During normal operation if normal power supply is not available to Panel 2-9-9 Cabinet 3, the transfer switch transfers to provide power to Panel 2-9-9 Cabinet 3 from alternate power supply. During the performance of this WO, the same alternate power supply will still provide power supply to Panel 2-9-9 Cabinet 3 directly with the transfer switch bypassed. There will be two periods during transition at which time there will be a loss of power to all loads fed by this cabinet. Operator actions per 2-AOI-57-5B are required. This period is kept to a minimum by performing the required steps in the WO in an expedient manner. Hence, the activities per this work order are safe from a nuclear safety standpoint. Performance of this WO does not increase the probability or consequences of an accident previously evaluated in the UFSAR and does not increase the probability or consequences of a malfunction of equipment important to safety previously evaluated. Performance of the WO does not create the possibility of an accident or malfunction of a different type than any evaluated in the SAR. This WO has no impact on the margin of safety as defined in the basis for any Technical Specification. No unreviewed safety question is involved. WORK ORDER 97-007135-000 This safety evaluation evaluates disabling one phase of the bus differential relaying on the 4KV Shutdown Board to allow testing of the current transformers (CTs) for the differential relaying and the overload relays on the breaker supplying the air compressor installed under DCN T39933. The 4KV shutdown boards are provided with three phases of differential relaying which are intended to operate within 33 cycles (60Hz base) of a phase to phase or a phase to ground fault. In addition, ground over current relaying is provided to clear the board within 16 cycles of a phase to ground fault. The transformers supplying the shutdown boards are provided with high impedance grounding which limits a fault to ground to 1600 amperes. Over current protection is also provided to provide protection for overload conditions. Over current relaying is not intended for fault clearing purposes since operating times are outside limits which would limit bus damage. Removing one phase of differential relaying from service would not adversely affect the reliability of the shutdown board since the protective relaying in actuality is used to clear the board in order to limit damage due to a fault. Regardless of the protective relaying the board will be lost should a fault occur on the bus. The protective relaying does help to reduce the likelihood of upstream boards from being lost. This safety evaluation concludes that there is sufficient redundancy in the protective relaying on the shutdown board to provide adequate fault protection to allow removal of one phase of differential relaying from service for testing purposes without affecting the shutdown boards ability to mitigate an accident or 31
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS equipment/personnel safety. The UFSAR describes the differential relaying on the shutdown board. This activity will disable one phase of the differential relays. This activity does not constitute an unreviewed safety question since the coordination protection to prevent propagation of the fault to other equipment will continue to perform its intended function and the ability of the shutdown board to perform its intended function during design basis accidents is not affected. WORK ORDER 97-009028-003 This safety evaluation is written for the Citrox dilute chemical decontamination of the 2A and 28 Reactor Water Cleanup (RWCU) Pumps using Work Order 97-009028-003. The purpose of the decontamination is to remove metal oxides/corrosion products that may adversely affect pump operation (high amps) and to lower dose rates/personnel doses for future maintenance performed on the pumps. The decontamination boundaries are the pump suction valves (2-HCV-69-521A, 2-HCV-69-5218) and pump discharge valves (2-HCV-69-521A, 2-HCV-69-5218). The dilute chemical decontamination of the Unit 2 RWCU pumps does differ with system operation characteristics (i.e., exceeds design temperature) from that described in the SAR. It does not conflict with or affect a process or procedure outlined, summarized, or described in the SAR. The chemical decontamination of the RWCU pumps does not increase the probability of an accident or malfunction of equipment important to safety previously evaluated in the SAR, create the possibility of an accident or malfunction of a different type than evaluated previously in the SAR, or reduce the maigin of safety as defined in the basis for any Technical Specification. Therefore, an unreviewed safety question does not exist. 32
Tennessee galley Authority Broivns Ferry Pluclear Plant 1997Annual 0 eratin Re orl
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OF SAFETY EVALUATIONS 1992
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OF SAFETY EVALUATIONS FOR PLANT MODIFICATIONS
Tennessee Valley Authori ty Browns Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS PLANT MODIFICATION(DOCUMENTATIONONLY) - UNIT 0- DCN S40339A This DCN modifies Note 6 on Drawing 045E506 to reflect capacitor bank operational requirements as a result of transmission system studies on the Browns Ferry offsite power system. This note currently specifies conditions/limitations (regarding the 161KV Capacitor Banks) which must be observed whenever credit is being taken for the 161KV Athens line as an offsite power source. These conditions/limitations must now also be observed whenever the 161KV Trinity line is being used as a qualified offsite power source also. An exception has been added which allows the capacitor banks to be removed from service and still take credit for the Trinity line provided that the nominal system voltage is maintained at 165KV or higher and the Athens line and Trinity intertie bank are in service (for two units) or just the Trinity intertie bank (for one unit). These conditions will ensure that the minimum system voltage required by the plant will be available without the capacitor banks. The function and operation of the 161KV capacitor banks remains the same. The operation of the 161KV capacitor banks is not described in the UFSAR nor in any process or procedure outlined, summarized or in the SAR. However, since Figure 8.3-6a is affected by DCN S40339A a safety evaluation is 'escribed required. No unreviewed safety question is involved. PLANT MODIFICATION(DOCUMENTATIONONLY) - UNIT 2 - DCN S39677A This safety evaluation is written in support of DCN S39677A which has been issued to provide corrective action for BFPER960512. The change being made under DCN S39677A involves changing the load restrictions concerning Transformers TS1E and TDE. Currently the load restriction notes on the design output drawings (single-lines) do not allow both of these transformers to be in service at the same time. DCN S39677A will revise these notes to allow both transformers to be in service at the same time provided the additional load limitations necessary to allow this configuration are followed. There is a load limit of 555 kVA for Transformer TS1E. With both transformers TS1E and TDE in service at the same time, an additional limit is needed in order to compensate for the additional auto start load on TDE. This additional auto start load is 55 kVA which accounts for the auto start (LOCA) loads on 480V Diesel Auxiliary Board A (or B). Therefore, it is acceptable to have both Transformers TS1E and TDE in service with a load limit of 500 kVA for the combined load of the two transformers. This configuration becomes necessary when 4kV Shutdown Board A is out of service which requires 480V Shutdown Board 1A to be supplied by Transformer TS1E and 480V Diesel Auxiliaiy Board A must be supplied from Transformer TDE. A safety evaluation has been performed to address the changes made under DCN S39677A since the changes involve a revision to drawings contained in the UFSAR as Figures 8.5-12a and 8.5-13a. The BFN Technical Specifications were reviewed for any impact due to the changes being made by DCN S39677A. No impact was identified. The Technical Specifications (Sections 3.9.B.4 and 3.9.B.6) requires the plant to enter a five day Limiting Condition of Operation (LCO) with the loss of either a 4kV Shutdown Boaid and/or a 480V Diesel Auxiliary Board. This requirement remains unchanged and is not impacted by the changes being made under DCN S39677A. No unreviewed safety question is involved.,
Tennessee Valley A uthori ty Browns Ferry Nuclear Plant 1997 Annual 0 eratin Re or!
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OF SAFETY EVALUATIONS This safety evaluation provides the justification for the removal of the concrete shield plugs for the north skimmer surge tanks for Units 1, 2, and 3 (3 plugs total). The concrete shield plugs were replaced with a aluminum frame topped with grating. The aluminum frame with grating replaced the concrete plugs so that operations personnel would be provided visual and personnel access to the surge tank opening while manually adjusting the adjacent shut-off valve. The change to the skimmer surge tank hatch impacts the notation of a component shown in UFSAR Figure 10.2-1b; therefore, a safety evaluation is required. No unreviewed safety question is involved. PLANT MODIFICATION(DOCUMENTATIONONLY) - UNITS 1, 2, 3 - DCN S40218A; Problem Evaluation Report (PER) BFPER961639 RO identifies drawings that indicate the existence of control room ammeters for the Control Rod Drive pump motors associated with Units 1, 2, and 3. However, the ammeters are not installed in their respective control rooms. Site Engineering has evaluated the discrepancy and has decided to remove the subject ammeters from issued documentation. Affected drawings are 0-45E724-1, 0-45E765-6, 1-45E721, 45E763-4, and 345E724-6. The remote ammeters (the ammeters in the control room) are not installed per issued documentation. Each of the CRD pump motors have ammeters mounted on their associated switchgear, there are indicating lights in the control room, and process flow indication in the control room to provide operators with information to determine the pumps'perating condition.
>U There are local CRD pump motor ammeters and there are indicating lights on the unit control board to provide unit operators with information concerning pump motor operation. Therefore, the CRD remote ammeters are not required and shall be removed from the issued drawings.
A review of the UFSAR has determined that a change is required to Section 8.5.3.5. The statement infers that all 4KV motors have ammeters in the control room. However, the CRD pump motors will not have ammeters in the control room. No unreviewed safety question is involved. PLANT MODIFICATION(DOCUMENTATIONONLY) - UNITS 2, 3 - DCN D40582A This safety evaluation supports a plant piping configuration change depicted on UFSAR Figure 11.1-1a as identified in BFPER971513. DCN D40582A implements a drawing discrepancy change on flow diagram 2-47E801-1, R017, to show instrument shutoff valves 2/3-SHV-1-735 8 -736 on the drawing. These instrument shutoff valves are installed in the plant but are not shown on the appropriate flow diagrams. These valves provide isolation to pressure transmitters 2/3-PT-1-16A & B which provide main steam pressure signals to the main turbine Electro-Hydraulic Control (EHC) main steam pressure and setpoint controls. This is a design document change only, no physical change is made in the plant. 35
i t Tennessee Valley Authority Browns Ferry iYuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS This design drawing change to reflect actual plant configuration will not reduce nuclear safety. However, a UFSAR change is necessary, therefore, a 10CFR50.59 safety evaluation is required. No unreviewed safety question is involved.
'LANT MODIFICATION- UNIT2 - DCN T29885A - REFUEL BRIDGE The safety evaluation for this plant modification was summarized in the Browns Ferry'Annual Operating Report for 1996.
PLANT MODIFICATION- UNITS 0 AND 2 - DCN T30200A - NUCLEAR ENGINEERING SETPOINT AND SCALING DOCUMENTS DCN T30200A issues Units 2 and 0 Nuclear Engineering Setpoint and Scaling Documents (NESSDs). The setpoint and scaling changes issued with this DCN impact information presented in UFSAR Table 7.8-2. This table has been revised by CRLD BFEP-BNA-94003 to reflect the current instrumentation and to remove the trip setpoint values. There are no changes to the radwaste system, no adverse impact on the Fire Protection Program, and no special tests or experiments involved with this DCN. This DCN requires changes to the UFSAR, therefore, a 10CFR50.59 safety evaluation is required. The modification is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. PLANT MODIFICATION<<UNIT 2 - DCN T39464A - REPLACE OBSOLETE STATOR COOLING CONDUCTIVITYINSTRUMENTS This safety evaluation is written in support of DCN T39464A. The changes being made under this DCN consist of replacing three Stator Cooling Water (SCW) conductivity cells (2-CE43-16A, -1 6B, and -16C), sparing the fourth (2-CE-43-17), and installing conductivity analyzers (2-CIT43-16A, -16B, and -16C) on SCW Control Panel 2-25-114. The conductivity analyzers provide inputs to the existing Local Processing Unit (LPU) 2-XT-43-1B on panel 2-25-128 in the Chemistry Lab. Analyzer 2-Cl-43-17 on control room panel 2-9-8 is replaced by indicator 2-Cl-43-16A and a resistor is added in the loop to 2-Cl-43-16A to provide a signal to the Integrated Computer System (ICS). To accommodate this input to the ICS, the software is revised. Recorder 2-CR-43-16 on panel 2-25-128 is no longer required and is deleted by this DCN. The control room alarm functions from recorder 2-CR-43-16 for panel 2-25-128 are replaced by alarms from the Local Processing Unit. This DCN also adds sample connections at approximately the 36
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OF SAFETY EVALUATIONS same locations in the piping as the conductivity elements. The existing SCW conductivity measuring equipment is inaccurate and obsolete. The affected systems, 43 and 35, are both non-safety related and this modification does not affect any equipment which performs a plant safety function. A revision is being made to the SCW conductivity instrumentation shown on Figure 10.17-1b of the UFSAR although it is not described in the text. The Unit 2 Technical Specification has been reviewed and no changes are identified for conducting or implementing this modification. Therefore, there are no Technical Specification changes as a result of this modification. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT2 - DCN T39636A - REPLACE VALVES 2-FC V-1-55/56 DCN T39636A documents the replacement of the existing Main Steam Drain Line Isolation Valves (MSDIV) 2-FCV-01-055 & -056 and actuators. The valves are being replaced to enhance the local leak rate testing (LLRT) and closure response time. The existing valves are VELAN pressure seal wedge gate and the new valves are VELAN parallel disc gate. The MSDIVs 2-FCV-01-055 & -056 serve as the inboard and outboard primary containment isolation valves for the common main steam drain line. They perform the nuclear safety function of primary containment isolation and automatically close under accident conditions (Group 1 isolation logic). These normally closed valves are required to cycle during power ascension to drain condensate from the main steam lines and are periodically stroke tested per ASME Section XI and 2-SI-4.7.D.1.a-1. In addition, they are sometimes opened to reduce pressure differential across the Main Steam Isolation Valves (MSIVs) before reopening the MSIVs. This design change also provides for a double valve test connection on the 2-FCV-01-055 valve body to facilitate Appendix J leak testing. As part of the corrective action to BFPER960361 RO, a deflector shield will be placed around the floor penetration closest to valve 2-FCV-01-056. The 24" penetration located in the steam tunnel floor opens to the torus area. The cooler air coming from the torus area has been determined as the probable cause of the moisture condensation in the 2-FCV-01-056 valve operator. The deflector shield will help direct the cooler air away from the valve operator thus preventing moisture buildup and corrosion. The MSDIVs prevent damage to the fuel barrier by limiting the loss of reactor coolant water in case of a leak of the coolant piping inside/outside primary containment. In addition, they provide reactor overpressurization protection and system depressurization of the vessel during Design Basis Accidents and Anticipated Operational Transients. These modifications to the MSDIVs and associated operators, Appendix J test connection, and deflector shield do not affect the design function of the valves or system. This change is intended to increase the reliability of the subject drain valves. The normally closed drain valves are still subject to spurious actuation and failure to close. The new Appendix J test connection is double valve isolated and vents to primary containment. The potential for failure modes for the new valves and test connection is bounded by the original design basis. 37
Tennessee Valley Authority Broivns Ferry Nuclear Plant l997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS The replacement valves and operators are designed to meet the Main Steam System applicable codes, standards, and specifications. This change will enhance the system by providing primary containment isolation valves that will meet the leak rate and stroke time requirements. Therefore, this change will have no adverse impact on nuclear safety. This change shall take place when primary containment is not required. This design change does make a minor change to a UFSAR figure by adding a double isolation test connection to the valve body of 2-FCV-01-55. Various figures in Section 7, 8 8 11 of the UFSAR are affected and will be revised. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT 0 - DCN T39933A-CONTROL AIR COMPRESSOR "G" This safety evaluation is written to support the addition of Control Air Compressor G (System 32), 0-CMP-032-2901. This compressor is capable of providing 1445 SCFM at 120 psig. The air compressor will be operated at 105 psig which is adequate to meet the requirements for control air for normal operation and to pressurize the accumulator tanks for the Main Steam Isolation Valves (MSIVs), Automatic Depressurization System Relief Valves (ADSRVs), and the reactor building Equipment Lock inflatable seals, based on operating experience. The design of the existing Control Air compressors A through D will not be changed. Compressors A through D will automatically start/load if the new compressor fails to provide adequate pressure or is manually shut down. The new compressor will handle the base load and the other four existing compressors will be started/loaded in steps as needed. The new compressor will be connected to the Raw Cooling Water (RCW) and to the Emergency Equipment Cooling Water (EECW) through an intervening closed loop cooling system. The interface connections to the RCW and Control Air systems are "Hot Taps", which allow the host system to remain pressurized while the connection is made, therefore, the Control Air and RCW Systems remain operable during the connection process. The EECW System is a backup to the RCW System and is normally isolated by control valve 0-FCV-67-53. Since the RCW System is normally available, the EECW System can be isolated for the relatively short time needed to install the new EECW piping and valves. Power is supplied to the new compressor from the 4160V Shutdown Board B. Power to the cooling water and lubrication pumps is supplied from the 480V RMOV Board 2A. The new compressor will trip on a loss of voltage to the 4160V Shutdown Board B. The Control Air compressois and the parts of the Control Air, RCW, and EECW Systems affected by this change are not described or referenced in the Technical Specifications. This modification will not adversely affect the safety related portions of the Control Air System, the EECW System, or any portion of the RCW System. FSAR Sections 10.7 and 10.14 are affected. Change requested have been initiated to these UFSAR sections to address the addition of the new compressor to the Control Air System. This change does not decrease nuclear safety as established by the licensing basis criteria. No unreviewed safety question is involved. 38
Tennessee Valley A uthori ty Browns Ferry Nuclear Plant 1997 Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS PLANT MODIFICATION- UNIT 0 - DCN T40236A - RETIRE AUXILIARYRAW COOLING WATER PUMPS IN PLACE DCN T40236A retires Auxiliary Raw Cooling Water Pumps A and B and related equipment in place. This equipment is removed from service. Equipment (except as specified) will remain in place, but will have no functional requirements. To maintain human factors for the operator interface the associated controls, instrumentation and annunciation are removed from the main control rooms (MCR). With the exception of the power to the 4kV pump motor heaters, electrical power is removed from the motor circuits by opening the supply breakers and removing the appropriate control circuit fuses. With the exception of wire and cable associated with changes to unit control room equipment, circuit conductors remain in place and isolated from the power source with the circuit breakers open and the circuit fuses removed. Auxiliary Raw Cooling Water Pumps A and B with their associated breakers and control circuits on 4kV Common Boards A and B respectively are retired in place. Their control switches and ammeters on MCR Panel 1-9-20 are removed. Their associated temperature recorder points on MCR Panel 1-9-47 temperature recorder 1-TR-56-3 are removed. Contacts from the RCW motor controls that are connected to the common 4kV motor overload annunciation are disconnected. Traveling screens/screen wash pumps A and B with their associated breakers and control circuits on the 480V motor operated gate board (including the Swanson control modules) are retired in place. Their control switches on UCB Panel 1-9-20 are removed. Their differential pressure alarms on MCR Panel 1-9-20 annunciator XA-55-20C are removed. A review of the UFSAR shows that the Auxiliary Raw Cooling water pumps functional requirements are described in the UFSAR Sections 10.7 and 11.6.2. The pumps are shown on UFSAR Figures 10.7-1a Sheet 1 and 10.7-2 Sheet 3. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT0 - DCN W39816A - INSTALLATIONOF CHEM NUCLEAR THERMEX~ SYSTEM This safety evaluation supports DCN W39816A which provides documentation for the installation of Chem Nuclear's THERMEX' water processing system on Elevation 598'nd 565'f the radwaste building. THERMEX' system consists of movable skid mounted water processing equipment interconnected with the floor drain and equipment drain subsystems. The system is capable of cleaning both the radwaste floor and equipment drain water to levels required for recycle to the Condensate Storage Tanks. Should plant not need processed water, it will be released to environment the same as current method. It should be noted that releases to environment will contain less radionuclides by use of THERMEX' System. The waste generated by this unit is a concentrated brine solution which is collected in a container located on elevation 565'f radwaste building. Container contents will be packaged by plant personnel for transportation to Chem Nuclear's THERMEX' Central Volume Reduction Facility for further processing. Should problems develop with the THERMEX' System equipment, the original radwaste processing equipment can be placed into service within a short period of time to eliminate possibility of plant flooding. 39
Tennessee Valley Auihoriiy Browns Ferry Nuclear Plan( 1997 Annual 0 eratin Re orl
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OF SAFETY EVALUATIONS This change also makes permanent the addition of accumulators on the suction and discharge piping of the filter aid pumps installed under Temporary Alteration Control Form (TACF) 0-94-04-77. DCN W39816A also documents the removal of the Cation polymer skid unit from output drawings, originally installed under TACF 0-97-04-77. This system will be kept as a backup unit to the THERMEX' System but will be controlled by plant procedures. As discussed in UFSAR Section 9.2 (Liquid Radwaste System), the system is designed to prevent the inadvertent release of significant quantities of liquid radioactive material from the restricted area of the plant so that resulting exposures are within the guideline values of 10CFR20. The concrete walls and slabs of the radwaste building are designed to withstand the Design Basis Earthquake. Should a failure of the THERMEX' system, piping or components occur, the spilled liquid would be retained in the radwaste building. Addition of THERMEX' System will result in new procedures which differ from current operating characteristics than described in the SAR. UFSAR Section 1.6.1.6.1 (Liquid Radwaste System), UFSAR Section 9.2.4.1 (High Purity Wastes), and UFSAR Section 9.2.4.2 (Low Purity Wastes) addresses low and high conductivity liquid processing. CRLD BFEP-MN-96052 RO revises these UFSAR sections to address the use of the THERMEX~ System. This change does not decrease nuclear safety and no unreviewed safety question is involved. PLANT MODII=ICATION- UNIT 2 - DCN T36529B - IMPLEMENTGL 89-10 REQUIREMENTS DCN T36529B provides authorization for the removal and replacement of specific parts, components, or complete actuators that require modification and/or replacement as evaluated by the Unit 2 Environmental Qualification Program and TVA GL 89-1 0 program for the following valves: 2-FCV-69-01, 2-FCV-69-02, 2-FCV-73-03, 2-FCV-73-30, 2-FCV-73-35, 2-FCV-75-22, 2-FCV-73-36, 2-FCV-75-25 & 2-FCV-75-50. The majority of the modifications are necessary to ensure the final configured actuators will be environmentally qualified for harsh environments. The required EQ changes include the following: installation or replacement of T-drains, environmentally qualified terminal blocks, splices, internal wiring, limit switch and torque switch assemblies, motors, and actuators. Additional modifications to incorporate gear ratio changes, motor speed changes, valve torque and thrust changes, and motor/actuator replacements as determined necessary by the TVA GL 89-10 program to ensure proper function of the motor operated valves (MOVs) under normal and accident conditions. DCN T36529B revises the horsepower of the motor and breaker for Core Spray (CS) valve 2-FCV-75-25. This change does not change the functional requirements of the valve, but ensures the existing performance requirements are met. This change is considered a non-significant change to the SAR. DCN T36529B also changes the gear ratio in valve 2-FCV-73-30 (High Pressure Coolant Injection [HPCI] pump minimum flow bypass valve). The new gear ratio changes the stroke time from 10 to 15 seconds. Only stroke time change is evaluated in this safety evaluation. 40
Tennessee Valley Authority Broivns Ferry Nuclear Plant l997 Annual 0 eratin Re ort
SUMMARY
OF SAFETY EVALUATIONS The HPCI system is designed to provide a source of high pressure makeup water to the reactor vessel to restore and maintain the reactor coolant level after transients that result in the isolation of the reactor concurrent with the failure of the Reactor Core Isolation Cooling (RCIC) following loss of Reactor Feedwater System or a loss of coolant accident (LOCA) that does not result in depressurization of the reactor vessel to the level where the low pressure CS can become functional. Valve 2-FCV-73-30 is the HPCI pump minimum flow bypass valve. This valve is automatically initiated upon detection of either low water level in the reactor vessel of high drywell pressure. The valve also receives an auto isolation signal as a result of excessive pressure in the turbine exhaust. The credible modes of failure for this valve are not opening upon receipt of a HPCI initiation signal and not closing (if open) upon receipt of an auto-initiation signaI. This change revises the horsepower and changes the breaker for CS valve 2-FCV-75-25. UFSAR Figure 8.5-7a is impacted by this change. This change does not change the functional requirements of the valve, but ensures the existing performance requirements are met. This DCN also changes the stroke time for HPCI pump minimum flow bypass 2-FCV-73-30 from 10 seconds to 15 seconds in the UFSAR text in Section 7.4.3.2.5 HPCI valve control. The increase in the full opening stroke time criteria for the 73-30 valve from 10 to 15 seconds has no affect on the HPCI System to perform its intended safety function. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT2 - DCN T39576A - REPLACEMENT OF HIGH PRESSURE COOLANTINJECTION (HPCI) SYSTEM WITH REACTOR CORE ISOLATION COOLING (RCIC) FOR FIRE AREA 11 This safety evaluation is written in support of DCN T39576A which has been issued to add the Unit 2 RCIC System to the Appendix R Safe Shutdown Program for Unit 2. Previously, the HPCI System was relied upon for a fire in Fire Area 11 on Unit 2, but the HPCI System was identified as not available for Unit 2 Fire Area 11 per BFPER960125 R2. Therefore, the RCIC System was made available so that a high-pressure make-up system would remain available for Unit 2 Fire Area 11. No physical plant modifications are required to make the RCIC System available whereas a modification (re-route a cable) would have been required in order to restore the availability of the HPCI System. Minor corrections have been made to Section V (Testing and Monitoring) of the Appendix R Safe Shutdown Program contained in Volume 1 of the Fire Protection Report. This change is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved.
Tennessee Valley Authority Bro>vns Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS PLANT MODIFICATION- UNIT 2 - DCN T39852 - PROVIDE ALTERNATEPOWER SOURCE FOR ANALOG TRIP UNIT (A TU) CABINETS 9-81 AND 9-82 This DCN removes one 120VAC to 24VDC power supply from each Emergency Core Cooling Systems (ECCS) Analog Trip Unit (ATU) cabinet in Unit 2 and replaces it with a 250VDC to 24VDC converter. The purpose of this modification is to provide a power supply to each ECCS ATU cabinet that is independent of the cabinet's associated ECCS ATU inverter. This modification will also install fuses in the ECCWATU cabinets to separate the cabinets'ooling fan circuits from the 120VAC to 24VDC supply circuits. The ECCS ATU instrumentation functions and associated setpoints are not altered by this modification. Relevant Technical Specifications, including bases, regaiding this instrumentation are therefore unaffected. The reliability of this instrumentation is enhanced by the additional power supplies. Hence, no Technical Specification margin of safety is reduced. Specific details regarding ECCS ATU power supplies are not given in the SAR. Specific loads from 250VDC logic breakers are not shown on figures in the SAR. However, due to the routing of the 250VDC power cable from the RMOV board breaker to Panel 9-32, measures must be taken for Fire Zone 2-3 during the unavailability of the Division I ECCS ATU inverter and its associated power supply 2-PX-71 1. Since the Fire Protection Report is referenced by the UFSAR in Section 10.11 and this modification requires a change to the Fire Protection Report, UFSAR information is considered to be affected. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT 2 - DCN T39941A - REMOVE POSITION INDICATION2-Zl-074-0054A AND 2-Zl-074-0068A This change removes the indicating lights for disc position of valves 2-FCV-74-54 and 68. The position indication function for the valve actuators with these valves will not be changed by this modification. These testable check valves are the inboard Primary Containment Isolation valves for the Low Pressure Coolant Injection (LPCI) flow paths. The subject valves normally have their control air supply removed during periods of operation and connected only for testing purposes while the unit is in cold shutdown. They are considered to function as check valves during operation and testable check valves during periods of testing. These valves are actuated by system process flow and will close to maintain primary containment integrity whenever Residual Heat Removal (RHR) loop flow is not present. For a design basis event, the LPCI injection flow can be established after the Reactor Coolant System has been depressurized below the discharge pressure of the RHR pumps. Upon RHR pump shutdown, the valves will return to their normally closed position. This flow path is also used for the shutdown cooling mode of RHR. The indicating lights, 2-Zl-74-54A and 68A, give control room indication of valve disc position and are actuated by limit switches 2-ZS-74-54A and B (68A and B). Each set of limit switches on each of these valves is actuated by a position rod and magnet that moves with the valve disc to indicate disc position. The proposed change will delete the disc position indication function for the subject valves. The indicating lights for disc position will be deleted and the position indicating lights for the valve actuator will be rearranged on control room Panel 2-9-3. These valves are safety related and required to function for primary containment integrity and RHR system isolation, however, the disc position indication is not required for the performance of these safety functions. The RHR/LPCI injection flow path has two isolation valves in series with these inboard isolation testable check valves. These two isolation valves are interlocked to prevent both from being opened simultaneously, except when primary system pressure is below the design pressure of the outboard piping.
Tennessee Valley Authority Brogans FerryiVuclear Plant 1997Annual 0 eratin Re ort
SUMMARY
OF SAFETY EVALUATIONS The disc position indicating lights are an operator aid for determining if LPCI injection is occurring. However, the deletion of this indication will not adversely affect the operator ability to accurately assess if LPCI injection is occurring (valve operation) because there are other control room indications such as RHR system flow and Reactor Pressure Vessel level which give operations personnel this same information. The position indication function for the valve actuators associated with these valves will not be changed by this modification. The RHR injection check valves and their associated disc position indication lights are discussed in Section 5.2.3.5, 7.3.4.1, and 7.4.3.5.4 of the UFSAR. In addition, these lights are shown on UFSAR Figure 7.4-6b, Sheets 1 and 2. A request for a UFSAR change will be processed to reflect these changes.
'o unreviewed safety question exists.
PLANT MODIFICATION- UNIT 2 - DCN T40112A - INSTALLATIONOF BYPASS LINE AND TEMPERATURE CONTROL VALVEON RCW DISCHARGE LINE ON TURBINE OIL COOLER DCN T40112A installs an 8" globe valve, 2-TCV-24-75A, on the Unit 2 Main Turbine Oil Coolers 2A and 2B common cooling water discharge line to replace the existing 8" ball valve. In addition, this DCN adds an 8" bypass line around the 8" globe valve. The bypass line includes a 4" globe valve, 2-TCV-24-75B, for low flow control at low river water temperatures. The controller and the electrical to pneumatic converter is being replaced to make the loop match Unit 3 and to upgrade to easier to control and maintain equipment. These modifications will reduce cavitation and temperature control problems caused by an oversized ball valve throttling near the closed position during the winter season. The valves are sized so that at low flow (200 gpm), the 4" valve will be approximately 40% open with the 8" valve closed. At maximum flow, the 4" valve will be fully open and the 8" valve will be open between 50% and 70%. The 8" bypass line is sized to limit the water velocity to below 10 ftlsec for the maximum expected flow in that line. The control air system will be modified to provide motive air to the temperature control valve operators. The control valves are set up for split range flow control. The input signal will provide control from 15-9 psig for the small (75B) control valve during low flow conditions and from 9-3 psig for the large valve (75A) during maximum flow conditions. The controls can be arranged so that the 8" valve will start opening before the 4" valve is fully open. The amount of overlap can be adjusted to suit the process conditions so that neither valve is trying to throttle near its fully closed position. The overlap position can be adjusted and the 8" valve can be controlled so that it is changing position during large changes in river water temperature and thus, will not be near its closed position for long time periods. The Main Turbine Oil Coolers and the associated RCW temperature controls are non-safety related balance-of-plant (BOP) equipment and are not discussed in the Technical Specifications or its bases; therefore, no change to the Technical Specifications is required to implement this DCN. The UFSAR does not describe details of the RCW temperature flow control valves on the Main Turbine Oil Coolers. However, Figures 10.7-1a Sheet 2 and 10.7-2 Sheet 1 are affected because these figures show the piping configuration of the RCW discharge line from the Main Turbine Oil Coolers. No unreviewed safety question is involved.
Tennessee Valley Authority Brains Ferry /i/uclear Plant 1997Annual 0 eratin Re orl
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OF SAFETY EVALUATIONS PLANT MODIFICATION- UNIT 2 - DCN T40209A - INSTALLS POWER SUPPLIES FOR ROD SCRAM TIMING SPLITTER CARDS FOR INTEGRATED COMPUTER SYSTEM This safety evaluation is prepared in support of DCN T40209A which installs updated computer splitter cards, additional power supplies, and fuses in the automatic rod scram time recorder (RSTR) interface in Unit 2, Panel 9-28. The additional power supplies are fed from the plant preferred 120V AC Panel 9-9 and the new cable is routed in existing trays from Panel 9-9 to Panel 9-28. The automatic RSTR is a function of the Integrated Computer System (ICS) which measures control rod scram times any time a rod is scrammed from the full out position. The original RSTR design which used existing power supplies in Panel 9-28 was determined to be inoperable and to reduce the signal strength to Panel 9-16 so that it could not be used as required for the backup manual method of scram timing. Temporary Alteration TACF 2-94-005-85 was implemented to bypass the automatic RSTR interface in Panel 9-28. This DCN, restores the operability of the automatic RSTR interface and maintains the normal signal strength available at Panel 9-16. The Browns Ferry Technical Specifications do not specify the method for obtaining scram timing data nor address the rod drift alarm circuitry or any automatic RSTR system. The Technical Specifications do require that the Rod Worth Minimizer (RWM) be operable when the plant is in the Startup or Run modes below 10% of rated power. During installation of this DCN, the rod drift cables are disconnected and the Reactor Manual Control System (RMCS) will not be able to provide a signal to the RWM, therefore this DCN must be installed at a time when the RWM is not required. This DCN adds a circuit breaker to Panel 9-9 in the Unit 2 Plant Preferred 120VAC system which is depicted on a UFSAR figure. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT 2 - DCN T40210A - REPLACE EXISTING EMERGENCY CORE COOLING SYSTEM (ECCS) BASKET STYLE SUCTION STRAINERS WITH STACKED DISK STYLE STRAINERS The existing BFN Unit 2 basket style ECCS Suction Strainers will be replaced with larger, higher debris capacity strainers. The new strainers employ a passive-type design that does not require any operator action to ensure an uninterrupted suction flow to the ECCS systems. The new strainers have an open flow area approximately twenty-five times larger than the existing strainers and, therefore, accommodate more debris loading. The ECCS configuration consists of a ring header circumscribing the suppression chamber with connection piping to four inlet penetrations through the torus shell into the suppression chamber. Inside the suppression chamber, each connecting line is fitted with a flanged surface for mating to the ECCS strainer fianges. The new 46" diameter by 48.7" long replacement strainers are securely fastened to the existing 150-pound 30" diameter ASME large-diameter flat-faced flanges by twenty-four 3/4" bolts. Each ASME bolting flange face is located approximately 1 foot inside its associated ECCS suction penetration (i.e. penetration X-204A, B, C, or D). The ECCS ring header supplies the normal suction piping of the Residual Heat Removal (RHR) System and Core Spray (CS) System, and the alternate suction for the High Pressure Core Injection (HPCI) and
Tennessee Valley Authority Broivns Ferrv Nuclear Plant
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OF SAFETY EVALUATIONS Reactor Core Isolation Cooling (RCIC) systems. The important function of the RCIC and HPCI systems is for events that do not result in the depressurization 'of the reactor vessel to the level where the low pressure ECCS systems (RHR and CS) operate. Accident and transient analyses potentially impacted by this change include: DBA-LOCA, UFSAR Chapter 14 Plant Safety Analysis, LOCA-Radiological and Earthquake. In all cases, installing the ECCS suction strainers has no adverse effect on these plant safety analyses. The ECCS strainer replacement is a change to a safety system component that requires a change to UFSAR Appendix C. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT 2 - DCN T40231A (F40453A) - INSTALLS ELECTRIC-PNEUMATIC LOGIC TO ENERGIZE MAINSTEAM RELIEF VALVE (MSRV) CONTROL AIR SOLENOIDS WHEN REACTOR PRESSURE EXCEED MSRV SETPOINTS The Main Steam Relief Valves (MSRVs) are experiencing an industry wide phenomena related to mechanical actuation setpoint drilt. The setpoints are drifting high by more than the Technical Specifications allowed 1% tolerance due to growth of spinel oxide corrosion of the pilot seat/disc interface. The recommended fix from the Owners Group is to use safety grade pressure sensors (in a non-safety related function) to actuate the MSRVs during inservice pressure transient events in the relief mode. This method of automatic opening the MSRVs permits application of the full main steamline pressure to break the corrosion bonds that may have developed between the pilot seat/disc interface. When the Relief Mode is actuated the setpoint spring preload is removed from the pilot disc, and a rapidly applied full differential pressure (force) is seen across the pilot disc. This alternate actuation is capable of opening the MSRVs which have pilot seat/disc corrosion bonding with a high degree of confidence. The key advantages to this approach are as follows: (1) It offers a reliable backup means to MSRV setpoint spring actuation. (2) It uses safety grade transmitters arranged in a similar manner to that currently approved for application in the BWR/6 plants. (3) It provides an externally sensed/powered automatic actuation of the MSRVs. (4) It improves the response of the relief valves by assisting actuation performance thus lessening the effect of corrosion induced bonding between the pilot disc and seat. (5) It does not impact the ASME Code or licensing basis while reducing Licensee Event Reports due to inservice results. This modification will provide a defense in depth for the opening of the MSRVs but no credit will be taken for the new logic from a safety related functional standpoint, and it is not relied upon to meet Technical Specification functional requirements for the MSRVs. Stage 2 of this modification makes changes to the annunciator logic for the ADS Logic Bus A and B Inhibit annunciation. These changes are required for corrective action for BFPER961230 and BFPER961764. This stage changes annunciator window 31 and adds window 18 on 2-XA-55-3C. This arrangement will ensure annunciation is received separately for the ADS Logic Bus A and B Inhibit handswitch being placed in the inhibit position. Revision 1 of this safety evaluation was written as a result of DCN F40453A. DCN F40453A redesigns the MSRV Auto Actuation Logic such that failures of the 24VDC power supply to the ATUs do not result in advertent opening of the MSRVs. This is accomplished by eliminating logic contacts contained solely in Panel 2-9-81 for the 1125 psig setpoint MSRVs. Relays 2-63-3-204CCB and 204CCC were added to Panel 2-9-82 and 2-63-3204CC was renamed to 2-63-3-204CCA to accomplish the new logic arrangement. With the new logic, the need for two of the Slave Trip Units and associated relays in Panel 45
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997Annual0 eratin Re ort
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OF SAFETY EVALUATIONS 2-9-81 was eliminated and have been deleted from the design. Calculations ED-Q0256-920695, ED-Q2253-920202, and ED-Q0001-920589 were revised to analyze the changes in electrical loading, fuse coordination, and separation of electrical components. Also, UFSAR Figures 7.4-3 and 7.8-1 Sheet 1 were revised and UFSAR Change Request Form updated to reflect the revised logic. Implementation of this modification will impact other ATU systems, but due to implementation during the cold shutdown reactor mode, this implementation does not create a problem for those systems with inputs from the ATUs. The safety related feature of the MSRVs designed to prevent reactor pressure from exceeding these Technical Specification limits and meet the ASME Code has not been changed by the addition of the new MSRV Auto Actuation Logic. This new logic serves only as a non-safety relate'd backup to those functions and will operate before the system design pressure is exceeded. Therefore, the margin of safety as defined in the Technical Specifications is not reduced as a result of this modification. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT 2 - DCN T40389A - REPLACEMENT OF DRYWELL CONTROL AIR DRYERS 2-DRYA-032-0065 AND 2-DRYA-032-0068 This modification is to replace the dryers (BFN-2-DRYA-032-0065/68) that are a part of the Unit 2 Drywell Control Air System (DWCA). The existing refrigerated dryers were manufactured by the Ingersoll Rand company and have a designation of model 2. The replacement refrigerated air dryers are manufactured by Ingersoll Rand and are dassified as a model DXR10. The replacement dryer will perform the same function, which is to remove moisture from the compressor discharge prior to the receiver tanks. The location of the dryers will be the same, therefore the interfaces with process tubing will require only minimal changes. The temperature switches are being removed since the process air dewpoint will be controlled by a constant pressure expansion valve in the dryer assembly. Minor changes are required to the dryer support stand because the footprint dimensions are slightly changed. The dryer assemblies have a small amount of combustible foam material which consists of insulation on the heat exchanger and insulation on the electrical cables. The total amount of insulation per dryer is less than 15 pounds. An engineering evaluation documents that this is within the combustible load limits evaluated for this part of the reactor building where the component is installed. The Fire Protection Report is not affected and nuclear safety is not decreased. Changes to the Control Air System control diagram are reflected on UFSAR Figure 10.14-4 Sheet 1. Minor wiring changes are shown on UFSAR Figure 8.5-7A. Therefore, a Safety Evaluation is required. No unreviewed safety question is involved. Qg@~d PLANT MODIFICATION- UNIT 2 - DCN T40543A - REMOVE TEST CONNECTION FROM 2-FCV-74-54 AND CAP VALVES 2-TV-074-0636A. REMOVE 2-TV-074-063 TA.
Tennessee Valley Authority Browns Ferry iVuelear Plant l997 Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS DCN T40543A is issued to cut and cap the outboard body drain & test connection on the RHR Injection/Shutdown Cooling Return Line testable check valve 2-FCV-74-54. The valves being removed are 2-74-636A and 2-74-637A. Unit 2 is shutdown and the affected RHR Loop I will be out of service while the test line is being cut and capped. The affected test line was used to perform Appendix J Local Leak Rate Testing (LLRT) on containment penetration X-13A. The LLRT testing for this penetration has been completed for this fuel cycle outage. Removal and capping of the test line will have no affect on LLRT test results. The socket welded cap will restore the pressure boundary of the test line, thus, containment integrity and the reactor coolant pressure boundary are not degraded. An additional test line consisting of valves 2-74-848 and -849 exists at this location thus assuring the capability to Appendix J LLRT this containment penetration in the future. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT2 - DCN W17327A - REACTOR FEEDWATER HEATER (RFWH) LEVEL CONTROL SYSTEM UPGRADE The proposed level control system upgrade will involve the replacement of the existing pneumatic transmitters with state-of-the-art electronic digital transmitters, the addition of an integrated microprocessor based control system to control the fifteen RFWH levels, the addition of current-to-pneumatic (I/P) converters on the local control panels, the replacement of the existing valve positioners with new positioners, splitting the common pneumatic piping to the RFWH drain and bypass valve pairs to allow individual control, the addition of two float type level switches to each RFWH to initiate RFWH string isolation on high level, and the addition of interposing time delay relays between the new level switches and the associated isolation valve close circuitry. Also, a local and main control room System trouble alarm will be added to alert operations to system malfunctions. Two 120V AC power sources will be provided for the system control cabinets, which will provide power for system components, including the level transmitters. The primary source will be the Unit 2 Unit Preferred bus, and the alternate will be from 480V Turbine Motor Operated Valve (MOV) Board 2B. The turbine MOV board supply will feed the control system through a regulating isolating transformer. The proposed microprocessor based digital control system will be located on elevation 586't coordinates h-T7 in the turbine building and will provide a central point for operator interface in the form of Manual/Auto (M/A) stations, graphical CRT displays, and a local annunciator. The proposed control system will have redundant control processors, and the inputs and outputs configured such that the loss of a single component, such as an I/O card, will not cause the loss of level control to more than'a'single RFWH. For the majority of the RFWHs (i.e., those with both a drain and bypass valve), it will require the failure of two control system components to lose level control. Software algorithms will be implemented to provide for level control, level input signal validation, level input failure compensation, high and low level setpoint alarms, and system trouble alarms. The new digital electronic transmitters will be mounted on the existing local panels in the same location as the existing transmitters. Minor tubing modifications will be required to mount the new transmitters, and new test connections will be provided to facilitate calibration. The proposed digital transmitters will provide improved accuracy over the existing pneumatic transmitters, allow the control system to access and modify information (such as zero, span, engineering units, last calibration date, damping, failsafe direction, tag number, tag name, diagnostics, etc.), and by the use of built in diagnostics provide a system trouble alarm on transmitter trouble. Conduit and cable will be routed from the central control system panel to each transmitter.
Tennessee Valley Authority Browns Ferry Nuclear Plant
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OF SAFETY EVALUATIONS The new I/P converters will be mounted on the existing local control panels also. There will be an I/P converter for each drain and bypass valve to allow individual control, versus the existing split range control. To provide for individual control, the single pneumatic lines for the drain and bypass valve pairs will be split into two lines. Minor tubing modifications will be required on the panels to mount the new I/Ps. Conduit and cable will be routed from the central control panel to each I/P converter. The existing valve positionets, many of which are obsolete, will be replaced with new valve positioners to facilitate maintenance and ensure that the associated valve operates reliably. Minor tubing and mounting plate modifications will be required to replace the existing valve positioners. The addition of two float level switches to each RFWH will reduce the susceptibility of the RFWH to spurious isolations due to sense line flashing. The installation of these switches will require the fabrication of a switch volume which will be installed on the RFWHs on existing sense line reference legs and sight glass legs. Modifications to the piping from the RFWH taps is required to assure adequate support. Conduit and cable will be routed from each switch to the appropriate turbine MOV board to an interposing, time delay relay to filter out contact chatter, and these relays will tie into the existing RFWH string isolation logic. Due to the simple construction of these switches and the potential for an undetected failure, the two switches on each RFWH will be arranged in a one-out-of-two trip logic configuration. The existing instrument condensate chambers on the RFWHs will be replaced with new condensate chambers with approximately five times the volume of the existing chambers. This will provide a larger water inventory to reduce the level measurement error caused by any flashing that might occur. An additional annunciator window will be added both locally and in the main control room to alarm on system trouble, such as loss of a transmitter signal, a module failure, a communications failure, etc. This alarm will alert operations personnel to problems occurring with the proposed control system. Also, individual heater high level annunciator windows will be added locally. Cables will be routed from the new central panels to Panel 2-9-6 for the common heater level low alarm and the new system trouble alarm. Cables will also be routed from the new central panels back to the associated local rack to tie to the existing MCR heater level high annunciator cable. The power feeds for the RFWH level control system will be from Battery Board 2 (Unit Preferred) and 480V turbine MOV Board 2B. The regulating isolating transformer for the turbine MOV board feed will be located on the turbine building wall near the control system cabinets. Cabling will be routed from Battery Board 2 to a junction box located behind the control system panels, and cabling from the turbine MOV board to the regulating transformer, and from the regulating transformer to a junction box located behind the control system panels. Fuses for each individual panel feed will be located in these junction boxes. Cables will be routed from the junction boxes to the individual control panels. Pneumatic level alarm switches for each heater will be replaced with software setpoints that will be implemented in the control algorithm. The second transmitter will now provide a redundant signal to the controller. If a faulty transmitter is detected, the controller ignores the defective instrument signal and fails over to the redundant transmitter while operators are alerted of the device failure. Four new panels shall be centrally located on elevation 586'n the turbine building that will incorporate the RFWH M/A stations, I/O modules, local annunciator box, control system processors, etc. A wire trough will be constructed above the four panels to accommodate inter-panel wiring. Each RFWH's level transmitters and current to pneumatic converter(s) will be located on the existing respective local control panel. A graphical display unit to be located in the new central control panel shall provide heater control system parameters. System operation, programming, and maintenance may be performed at this local display station. Per a review of the BFN UFSAR, the proposed modification will not impact system design, functional requirements, text, or graphs presented in the UFSAR. However, UFSAR Figures 8.6-1d and 8.7-3 will
Tennessee Valley Authority Browns Ferry nuclear Plant 1997Annual 0 eratin Re orl
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OF SAFETY EVALUATIONS require updating to reflect the addition of the RFWH normal feed to Battery Board 2 Breaker 1179, and UFSAR Figure 10.17-1c will require updating to show the correct continuations to the associated System 6 control drawings that were created. CRLD-EEB-92024 has been initiated to process this change. The failure modes for the proposed system are bounded by the existing failure modes of the individual valves and control loops. A single controller failure on the existing system can lead to the isolation of a single heater string. A worst case single failure or action will cause the same result in the new system. Therefore, this change does not create the possibility of an accident of a different type than any previously evaluated in the SAR. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT2 - DCN W17459A - ADDITIONALSAMPLEITEST CONNECTION TO DRYWELL CONTROL AIR TO FACILITATECONDUCT OF TECHNICALINSTRUCTION CTI)-176 This modification provides an easily accessible alternative sample point on the Unit 2 west bank Drywell Control Air (DCA) System supply line. The sample connection will provide a means of obtaining periodic air samples from the DCA each six months, as required in 2-Tl-176. The existing test point is difficult to access due to piping and conduit obstructions and occasional contaminated zones. The configuration of the DCA System is shown on flow diagram, 2-47E2847-5 (UFSAR Figure 10.14-4) which is revised by CRLD BFEP-MN-92011 RO to reflect the addition of the test connection. This modification provides a drywell air sample point only. The connection will be located in a non-safety related portion of the DCA. No unreviewed safety question is involved.
Tennessee Valley Authority Browns Ferry iVuolear Plant i997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS PLANT MODIFICATION- UNIT 2 - DCN W35344A - REPLACE AVERAGE POWER RANGE MONITOR (APRM)IROD BLOCK MONITOR (RBM) WITH POWER RANGE NEUTRON MONITORS DCN W35344A replaces all existing power range neutron monitoring equipment in Panel 9-14 of the Unit 2 main control room (MCR) with a digital Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) retrofit system. The Average Power Range Monitors (APRMs), the Rod Block Monitors (RBMs) and their associated electronic components in the main control room are replaced. The number of APRMs is changed from six, configured in a one-out-of-two-taken-twice scram logic, to a total of four, configured in a two-out-of-four scram logic. New two-out-of-four voters are added to interface the APRMs with the Reactor Protection System (RPS). A new fiber-optic APRM bypass switch and four NUMAC Operator Display Assemblies (monitors) are added to Panel 9-5, the unit operator's benchboard. A multi-vendor data acquisition system (MVDAS) which interfaces the NUMAC PRNM equipment with the existing process computer is added. The four existing recirculation flow transmitters which provide signals to the APRMs are replaced, and'four additional recirculation flow transmitters are added. This provides four independent recirculation total flow instrument loops, one for each of the new APRMs. The new APRMs include an oscillation power range monitor (OPRM) function which implements the BWR Owner's Group Option III stability trip function; however, the OPRM trip function is not enabled by this DCN. The proposed change also implements instrument setpoint and hardware changes necessary to support APRM and RBM Technical Specification (ARTS) improvements and operation in the maximum extended. load line limit (MELLL) region of the powerlflow domain. The flow-biased APRM scram and rod-block setpoints are changed; the RBM setpoints are changed from flow-biased to power-dependent values; and the LPRM inputs to the RBMs are reconfigured. The new PRNM equipment is a digital system with software (firmware) control. As such, it has "central" processing points and software controlled digital processing where the existing system has analog and discrete component processing. The result is that the specific failures of hardware and potentially common cause software failures are different from the current system. However, when these are evaluated at the system level there are no new effects. Because the new equipment meets or exceeds requirements of the existing equipment and all design margins are maintained, the margin of safety as defined in the basis of any Technical Specification is not reduced. This plant modification involves an unreviewed safety question and must be revised, canceled, or reviewed by the NRC prior to implementation. The NRC has reviewed and approved a generic description of the PRNM modification. The generic description envelopes the work to be performed under this DCN. TS-353 provides the NRC details of the BFN-specific modification. Obtaining NRC approval of TS-353 is a special requirement of this Safety Evaluation. 50
Tennessee Valley A ulhori ty Browns Ferry IVuelear Plant I997Annual0 eratin Re orl
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OF SAFETY EVALUATIONS PLANT MODIFICATION- UNIT2 - DCN W39776A FCV-002-0190 REPLACEMENT Stage 1 of DCN W39776A documents replacement of the existing pneumatically controlled valve, 2-FCV-002-190, Fisher model number 7610/486U with a motor operated valve, Fisher model number 8532 valve and Limitorque H2BC 90'perator driven by an SMB-OOO with a 5 ft-Ib motor. The new motor operated valve will allow for manual adjustment of the bypass flow from the main control room during reactor power level changes and prevent spurious valve position changes that have caused feedwater transients. The new 18" valve is the same pressure class and has flow characteristics to allow for improved throttling capability over the normal operating flow conditions. Stage 2 of DCN W39776A documents the addition of a platform to provide access to valve 2-FCV-002-190 for inspection and manual operation. The purpose of the Condensate and Reactor Feedwater systems is to provide feedwater to the reactor to maintain constant water level. Condensate leaving the condensate pumps is divided and directed through the Steam Packing Exhauster (SPE), Steam Jet Air Ejector (SJAE) inter-condensers, and the Off-gas condenser (OGC). This equipment is arranged in parallel to minimize the pressure loss in the condensate system. To further minimize pressure losses, the 2-FCV-002-1 90 valve permits part of the condensate flow to bypass these parallel heat exchangers when flow is adequate to satisfy the performance requirements of the heat exchangers. This design change does make a minor change to the Unit 2 condensate flow diagram to change the operator type designation. This drawing, Figure 11.9-1 a in the UFSAR will be revised, therefore, a safety evaluation is required. This change also affects the description of the bypass valve in Section 11.8.3.6. The current description denotes the bypass valve as a "differential pressure control valve" and the new valve will be a manually controlled motor operated butterfly valve. The description change in the UFSAR is also being done under DCN W39776A. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT 2 - DCN W39936A - REPLACING EXISTING SOLID WEDGE 2-FCV-73-l6 WITH A DOUBLE DISC GATE DESIGN TO REDUCE LEAKAGE This safety evaluation is written in support of DCN W39936A, which allows for plant modifications to the Unit 2 High Pressure Coolant Injection (HPCI) System. The design change will replace the existing 10" motor operated flow control gate valve 2-FCV-73-16 with a similar gate valve with a double disc design. This valve is normally aligned in the closed position and is opened for system operation and testing. This valve isolates the steam supply line from the HPCI turbine and opens upon a system initiation signal. During operation, this valve heats up to saturated steam temperature of approximately 500'F. The valve is closed upon system shutdown and the valve cools off to a temperature that is slightly above ambient air conditions. This cool down period can potentially cause a solid wedge gate valve to become thermally bound. Generic Letter 95-07 required an evaluation of power operated valves for susceptibility to thermal 51
Tennessee Valley Authori ty Browns Ferry Nuclear Plant 1997AnnualO eratin Re ort
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OF SAFETY EVALUATIONS binding and pressure locking. The existing valve was determined to not be affected by pressure locking, however, it is susceptible to thermal binding. In order to prevent this condition the new valve provided will utilize a double disc design. Double disc gate valves are designed to prevent thermal binding. The edging mechanism between the disc collapses as the stem rises. This permits the parallel discs to move inward, allowing the bonnet to vent prior to the disk moving significantly up into the bonnet. Therefore the disk can be raised regardless of the change in system temperature. The existing valve motor operator will be reused for the new valve; however, due to the new valve having a longer stem travel, the new valve stroke time (approximately 22 seconds) will exceed the current requirement of 20 seconds. The 20 second requirement is conservative considering the required system response time is 30 seconds. This design change will also change the valve motor operator motor pinion gears to maximize opening thrust available within the response time limitations of the system. This design change will also incorporate the installation of an environmentally qualified motor terminal block. Based on the requirements of NRC Generic Letter GL 89-10, this DCN will document environmental qualification, limit switch setting, thrust and torque capabilities, and compliance with required stroke time. To prevent possible damage to nearby conduit during the rigging process, this DCN will allow for the determination, pull back, and retermination of conduits (DCA-004) and associated cables from junction box 1B-8272 to PNL 2549 (HPCI Pump and conduit and cable associated with level sensor LS-73-5. Turbine,'ontrol) The valve is being replaced with a type better suited for this application. The overall gear ratio in the valve operator is changed which will increase the valve stroke time. By this increased gear ratio and subsequent increase in stroke time, this valve will achieve increased opening capability by approximately 20% staying within the valves allowable capabilities. Therefore this activity is acceptable from a nuclear standpoint. The proposed design change will alter the performance capabilities of the affected system as described in the SAR. The proposed activity does conflict with or affect a process or procedure presently described in ~ the SAR. The UFSAR currently requires a 20 second opening time for FCV-73-16. The stroke time will be increased to 30 seconds. This will require a change to UFSAR Section 7.4.3.2.5. The 30 second stroke time will support the response time requirement of 30 seconds for the system. This design change will cause a revision to the Unit 2 flow diagram 2-47E812-10 (Figure 6.4-2) to remove note concerning s'troking valve to reduce thermal binding and 2-47E611-73-1 (Figure 7.4.-2a) to show limit switch position at closure. Operating Instruction 2-Ol-73 will be revised to remove the requirement to stroke 2-FCV-73-16 valve in order to prevent thermal binding. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT 2 - DCN W40340A - INSTALLATIONOF ZINC INJECTION (GEZIP) SYSTEM DCN W40340 installs a Zinc Injection (GEZIP) System at BFN Unit 2. The GEZIP System consists of a simple recirculation loop off of the feedwater pumps. Specifically, the zinc solution is obtained by passing a stream of feedwater (4-100 GPM) from the feedwater pumps discharge header through a dissolution vessel containing pelletized depleted zinc oxide (DZO) and back to the feedwater pumps suction header. The Zinc Injection System is a part of feedwater system and is a non-safety related installation. The GEZIP process maintains trace quantities of ionic zinc in the feedwater and reactor water by continuously injecting small amounts of DZO into the feedwater during normal plant operation. The presence of trace quantities of zinc has been found to promote the formation of a thin, protective oxide layer on stainless steel piping and components. This oxide layer buildup results in soluble Co-60 and is the primary factor in reducing shutdown dose rates on piping and components, thus reducing occupational exposure to plant personnel. 52
Tennessee lralley Authority Broils Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS This change is a modification to the feedwater system. It is not a special test or experiment. Design and functional requirements and performance characteristics and operation of the feedwater system is not impacted by this change. A new section Zinc Injection Skid, UFSAR Section 11.8.3.10, was added by Unit 3 DCN W36676A. However, the UFSAR must be revised to address applicability of zinc injection system to multiple units. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT3 - DCN T39853A - PROV!DE ALTERNATE POWER SOURCE FOR ANALOG TRIP UNIT (A TU) CABINETS 3-81 AND 9-82 The subject DCN removes one 120VAC to 24VDC power supply from each Emergency Core Cooling Systems (ECCS) Analog Trip Unit (ATU) cabinet in Unit 3 and replaces it with a 250VDC to 24VDC converter. The purpose of this modification is to provide a power supply to each ECCS ATU cabinet that is independent of the cabinet's associated ECCS ATU inverter. This modification will be performed in four stages: Stage 1 will install the new converter in the Division I ECCS ATU cabinet; and Stage 2 will install the new converter in the Division II ECCS ATU cabinet. Stage 3 replaces fuse 3-FU1-256-1F in the Division I ECCS inverter. Stage 4 replaces fuse 3-FU1-256-2D in the Division II ECCS Inverter. These fuses are being changed from 125A to 100A solid state types to provide* improved protection for the inverter Silicon Controlled Rectifiers. Specific details regarding ECCS ATU power supplies are not given in the SAR. Specific loads from 250VDC logic breakers are not shown on figures in the SAR. However, due to the routing of the Division I 250VDC power cable from the RMOV Board to Panel 9-32, measures must be taken for Fire Zone 3-3 during the unavailability of the Division I ECCS ATU inverter and its associated Power Supply 3-PX-71 1. Since the Fire Protection Report is referenced by the UFSAR in Section 10.11 and this modification requires a change to the Fire Protection Report, UFSAR information is considered to be affected. The ECCS ATU instrumentation functions and associated setpoints are not altered by this modification. Relevant Technical Specifications, including bases, regatding this instrumentation are therefore unaffected. The reliability of this instrumentation is enhanced by the additional power supplies. Hence, no Technical Specification margin of safety is reduced. No unreviewed safety question exits. 53
Tennessee Valley Authority Browns Ferry iVuclear Plant l997AnnualO eratin Re ort
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OF SAFETY EVALUATIONS PLANT MOD/I=ICATION- UNIT3 - DCN T39942A - REMOVE POSITION INDICATION 3-ZI-074-0054A AND 3-Z/<<074-0068A This change removes the indicating lights for disc position of valves 3-FCV-74-54 and 68. The position indication function for the valve actuatois with these valves will not be changed by this modification. These testable check valves are the inboard Primary Containment Isolation valves for the Low Pressure Coolant Injection (LPCI) flow paths. The subject valves normally have their control air supply removed during periods of operation and connected only for testing purposes while the unit is in cold shutdown. They are considered to function as check valves during operation and testable check valves during periods of testing. These valves are actuated by system process flow and will close to maintain primary containment integrity whenever Residual Heat Removal (RHR) loop flow is not present. For a design basis event, the LPCI injection flow can be established after the Reactor Coolant System has been depressurized below the discharge pressure of the RHR pumps. Upon RHR pump shutdown, the valves will return to their normally closed position. This flow path is also used for the shutdown cooling mode of RHR. The indicating lights, 3-Zl-74-54A and 68A, give control room indication of valve disc position and are actuated by limit switches 3-ZS-74-54A and B (68A and B). Each set of limit switches on each of these valves is actuated by a position rod and magnet that moves with the valve disc to indicate disc position. The proposed change will delete the disc position indication function for the subject valves. The indicating lights for disc position will be deleted and the position indicating lights for the valve actuator will be rearranged on control room Panel 3-9-3. These valves are safety related and required to function for primary containment integrity and RHR system isolation, however, the disc position indication is not required for the performance of these safety functions. The RHR/LPCI injection flow path has two isolation valves in series with these inboard isolation testable check valves. These two isolation valves are interlocked to prevent both from being opened simultaneously, except when primary system pressure is below the design pressure of the outboard piping. The disc position indicating lights are an operator aid for determining if LPCI injection is occurring. However, the deletion of this indication will not adversely affect the operator's ability to accurately assess if LPCI injection is occurring (valve operation) because there are other control room indications such as RHR system flow and Reactor Pressure Vessel level which give operations personnel this same information. The position indication function for the valve actuators associated with these valves will not be changed by this modification. The RHR injection check valves and their associated disc position indication lights are discussed in Section 5.2.3.5, 7.3.4.1, and 7.4.3.5.4 of the UFSAR. A request for a UFSAR change will be processed to reflect these changes. No unreviewed safety question exists.
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OF SAFETY EVALUATIONS PLANT MODIFICATION- UNIT3 - DCN W17133A - CONTROL ROOM DESIGN REVIEW MODIFICATIONSFOR PANEL 3-9-5 This DCN consists of modifications to Panel 3-9-5 for resolving identified human engineering discrepancies between the design of the Unit 3 control room and TVA's human factors standards. These modifications are applications of Human Engineering principles to improve man-machine interface characteristics, and thus, enhance operator response during abnormal and emergency conditions of the plant. This safety evaluation was previously summarized in the Browns Ferry Annual Operating Report for 1992/ However, Revision 1 of this safety evaluation is issued to address the addition of a suppression filter to the digital meters and to reduce the DCN scope to delete the rewiring of a handswitch. This revision is considered a minor change. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT3 - DCN W17424A - REPLACE DRYWELL ENVIRONMENTALQUALIFICATIONCABLES DCN W17424 provides design for the bulk replacement of electrical cable and components in the Unit 3 drywell, due to employee concerns, environmental qualification, penetration coordination and electrical separations. This DCN involves modifications associated with the following devices: 3-PCV-1-4, -5, -18,- 19, -22, -23, -30, -31, -34, -41, -42, -179 and -180, Main Steam Line Safety Relief Valves; 3-XE-1-4, -5,- 18, -19, -22, -23, -30, -31, -34, -41, -42, -179 and -180, Main Steam Line Safety Relief Valve Acoustic Position Indicators; 3-FCV-1-14, Main Steam Line A Inboard Isolation Valve; 3-FCV-1-26, Main Steam Line B Inboard Isolation Valve; 3-FCV-1-37, Main Steam Line C Inboard Isolation Valve; 3-FCV-1-51, Main Steam Line D Inboard Isolation Valve; 3-FCV-3-98, Reactor Head Vent Inboard Isolation Valve; 3-FCV 99, Reactor Head Vent outboard Isolation Valve; 3-FCV43-13, Inboard Sample Isolation Valve; 3-FCV-68-1, Recirculation Pump 3A Suction Valve; 3-FCV-68-3, Recirculation Pump 3A Discharge Valve; 3-FCV-68-77, Recirculation Pump 3B Suction Valve; 3-FCV-68-79, Recirculation Pump 3B Discharge Valve; 3-FCV-69-1, Reactor Water Cleanup Suction Inboard Isolation Valve; 3-FCV-71-2, RCIC Steam Line Inboaid Isolation Valve; 3-FCV-73-2, HPCI Steam Line Inboard Isolation Valve; 3-FCV-7448, RHR Shutdown Cooling Inboard Isolation Valve; 3-MTR-77-1A, -1 B, -14A, and -14B, Unit 3 Dtywell Floor/Equipment Drain Sump Pumps; and 3-MCHD-94-CHA, -CHB, -CHC, -CHD, and -CHE, Traversing Incore Probe Indexing Mechanism. In addition to the above modifications, this DCN provides design to remove cables abandoned in place by previous change paper. Also, this DCN provides documentation to delete the pressure switches and their associated circuits which were once used for three-stage Main Steam Relief Valve (MSRVI operation. ECN E-0-P0155 provided design to change out the three-stage MSRVs in Unit 3 with two-stage valves, which do not require associated pressure switches. This change involves the modification of safety-related systems. In the final plant configuration, no change is made to the function, operation, or performance of the main steam, feedwater, sampling, recirculation, reactor water cleanup, RCIC, HPCI, RHR, radwaste systems, or any other system. 55
Tennessee Valley Authority Browns Ferry JVuelear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS Implementation of this DCN involves the removal of abandoned equipment as well as the replacement of cables and limit switches with Class 1E, environmentally qualified components. Installation of qualified equipment improves the reliability of the affected circuits. This DCN involves a modification to components in the radwaste system, therefore, a 10CFR50.59 safety evaluation is required. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT 3 - DCN W26519A - REACTOR'FEEDWATER HEATER LEVEL CONTROL SYSTEM This DCN upgrades the Reactor Feedwater Heater (RFWH) Level Control System for BFN Unit 3. The i proposed modification of the RFWH Level Control System will involve the replacement of the existing pneumatic transmitters with state-of-the-art electronic digital transmitters, the addition of current-to-pneumatic (I/P) converters on the local control panels, the replacement of the existing valve positioners with new positioners, splitting the common pneumatic piping to the RFWH drain and bypass valve pairs to allow individual control, the addition of two float type level switches to each RFWH to initiate RFWH string isolation on high level, and the addition of interposing time delay relays between the new level switches and the associated isolation valve close circuitry. Also, a local and main control room System trouble alarm will be added to alert operations to system malfunctions. The existing instrument condensate chambers on the RFWHs will be replaced with new condensate chambers with approximately five times the volume of the existing chambers. This larger water inventory will reduce the potential for sense line flashing and the level measurement errors that result. DCN W26519A will refurbish and upgrade the RFWH level control valves. This modification will enhance the reliability of the level control valves. Valves from Unit 2 removed during the Unit 2 Cycle 8 outage will be refurbished for installation in Unit 3. This set of valves consists of double seated control valves and single seated dump valves. The control valves will be upgraded with equal percentage trim, which will provide improved control response. The dump valve actuators will be upgraded to withstand a higher pressure rating, which will improve the valve sealing characteristics. This modification will not impact system design or functional requirements presented in the UFSAR. However, various UFSAR figures will require updating. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT3 - DCN W39777A - REPLACEMENT OF 3-FC V-2-190 DCN W39777A will replace the existing pneumatically operated 3-FCV-2-1 90 valve with a new 18" motor operated valve. The existing 16" valve provides a condensate bypass for the Steam Packing Exhauster (SPE). During power operations, this valve is throttled to regulate flow through the SPE, the Steam Jet Air Ejectors (SJAEs) and the Offgas Condenser (OC). At full power, the majority of condensate flow is through the bypass line. Failure of this valve due to this high flow condition has caused several reactor trips. The original valve was a Fisher Figure 7600 butterfly valve with a pneumatic operator. This valve has had a history of spurious operation due to failure of the pneumatic controls and a failure of the valve stem. The original valve was replaced under Temporary Alteration Control Form (TACF) 3-96-2-2 with a 56
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OF SAFETY EVALUATIONS 16" Fisher Figure 8532 valve and a Figure 1076 manual operator. This DCN will'supersede this TACF and install an 18" Fisher Figure 8532 and a Limitorque H2BC 90 degree operator driven by a SMB-000 with a 5 ft-Ib motor. This operator will be manually controlled from the main control room. There will be no automatic controls associated with the new valve. In addition, to facilitate proper system flow balancing, the flow indicator, 3-FI-02-42 will be rescaled to provide operations personnel with improved indication of condensate flow through the SJAEs and the OC. The power circuit for the new motor operated valve will be taken from the Unit 3 480V Turbine Building Vent Boaid 3B. The new control circuits will be routed to the Unit 3 main control room and a local control station adjacent to the valve location. The pneumatic equipment for the existing valve controls and pneumatic air supplies to the valve will be removed to facilitate installation of the new valve. This design change does affect the description of the bypass valve in Section 11.8.3.6. The current description denotes the bypass valve as "differential pressure control valve" and the new valve will be a manually controlled motor operated valve. Technical Specifications are not affected by this change. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT 0- DCN T39068A - CHANGE PROTECTIVE RELAY DCN T39068A will revise the protective relaying schemes for the Madison 2 and Trinity 500 kV transmission lines, add a harmonic analyzer to monitor line conditions, remove a carrier telephone set in the communications room, retire carrier coupling equipment in the switchyard, and make minor changes to the protective relaying test switch configuration in the main control room. Taking both the Madison 2 and Trinity 2 500 kV transmission lines out of service will not impact the reliability of the offsite power supply. Also impacted is UFSAR Section 8.3.1 which indicates that there are two lines to Madison. This section will be revised to indicate that there is one line to the Madison 500 kV substation and one line to the Limestone 500 kV substation. Figures 8.3-5 and 8.3-6 will also be revised to show the modification of the protective relaying schemes, the addition of a harmonic analyzer, and the changing of the Madison 2 line name to Limestone. These UFSAR changes are insignificant because they are not associated with nuclear safety and there are no specific design, operational, and/or performance requirements indicated in the text or on the figures. No unreviewed safety question is involved. 57
Tennessee Valley Authority Browns Ferry 1Vuelear Plant 1997Annual0 eratin Re ort
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OF SAFETY EVALUATIONS PLANT MODIFICATION- UNIT 0 - DCN T4030$ A - REVISE DIESEL GENERATOR (DG) 7-DAY TANK LOW LOW LEVEL ALARMSETPOINT; DELETE THE HIGH LEVEL ALARM This safety evaluation is written to support DCN T40301A. There are eight diesel generator units which serve BFN Units 1,2, and 3. A set of four diesel generator units are designated A, B, C, and D located in Unit 1-2 DG Building. Another set of four DG units designated 3A,3B,3C, and 3D are located in Unit 3 DG Building. The DG Fuel Oil System for each diesel generator unit includes a day tank on the engine skid and a 7<ay tank embedded in the DG Building foundation floor. Transfer of fuel oil between the 7-day tanks is accomplished by a manually controlled 200 gpm DG building Fuel Oil Transfer pump. Transfer of fuel oil from outside the DG building to the 7-day storage tanks is accomplished by a manually controlled 200 gpm Yard Fuel Oil Transfer pump. Level instrumentation is provided on each 7-day tank to accomplish the following functions: (1) Local level indication; (2) Abnormal tank level alarm in the main control room . is composed of the low level and high level switches on the 7-day tanks; (3) 7-Day tank high level switch i interlocks with the DG building Fuel Oil Transfer pump and the Yard Fuel Oil Transfer pump to trip before overfilling the 7-day tanks. This modification addresses the concerns of BFPER970766. The existing high level and low level switch setpoints which operate common trouble annunciator window 28 (DIESEL ENG STG TANK LEVEL ABN) on Panels 1-9-20B and 3-9-20B do not agree with the setpoints specified in Procedures 1-ARP-9-20B,3-ARP-9-20B, and 0-Ol-18. The Technical Specification 3.9.A.6 requirement of a minimum of 35,280 gallons of fuel oil is not met by the present low level switch settings. The level in the 7-day diesel storage tanks are maintained within the Technical Specification limit by operator actions in accordance with 0-0I-18 with low level action of refilling at 81% (indicated tank level) and the high level manual pump trip at 86% when filling. This DCN will recalibrate the setpoint for the present low level switches to a setpoint that will ensure Main Control Alarm before the Technical Specification of 35,280 gallons is achieved. The 7-day tank low level must be raised approximately 7:5 inwc (to approximately 83%) above the present setting (approximately 70%). This places the operating points for high and low levels on the 7-day tanks within a narrow band since the high 74ay tank level cannot be raised an equal amount due to tank capacity. The high level setpoint is raised such that the top of the tank minus the instrument inaccuracies equals the setpoint (approximately 94%). The nominal values show that the low level alarm will reset before the high pump trip occurs. However, the differential between the high and low setpoints at worst case tolerance may result in the low level alarm not clearing before a pump trip. Only the high level alarm is being disconnected because the alarm would come in when the pump trips but due to the reset requirement of the switch and the narrow band of operation the alarm would not reset until level dropped to a point near the low level alarm. This would become a nuisance alarm. During the refilling activities, caution should be used since the high level trip is nearer the top of the 7-day tank at the instrument connection than before. Since the tank is sloped and the overfill connection is at the low end of the tank, fuel could possibly be filling the overfill piping. The refilling activities as described in O-OI-1 8 started the filling (81%) at a level above the existing low level setpoint and stopped the filling (86%) at a point below the existing high level pump cutout setpoint. With the change in high (approximately 94%) and low (approximately 83%) level setpoints, the low level alarm will annunciate in the Control Room before the Technical Specification required level of 35,280 gallons is reached but the low level alarm reset value will be above the 86% value previously used. This DCN is staged so that the modification will be performed for one DG at a time, but this modification can be worked in any order or number of diesel generators as allowed by plant conditions and the Technical Specifications. The Fuel Oil System (18) level instrumentation for the 7-day tank is not a available while it is being modified. The proposed modification will require a change to the description of the level switches presented in the UFSAR. The high level alarm switch description will be removed. No UFSAR figures are affected. 58
Tennessee Valley Authority Browns Ferry Nuclear Plant
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OF SAFETY EVALUATIONS Technical Specifications were reviewed for possible impact associated with this change. It was determined that this modification will not impact any Technical Specification requirements or their bases. This modification will raise the low level alarm setpoint to ensure main control room alarm actuation before Technical Specification limit is reached. No unreviewed safety question is involved. PLANT MODIFICATION- UNIT3- DCN W2652IA - INSTALLATIONOF DIGITAL FEEDWATER CONTROL SYSTEM SOFTWARE The upgraded Reactor Feedwater Control System (RFWCS) will consist of Foxboro Intelligent Automation (I/A) hardware and software that shall incorporate all the functions of the existing system except for level 8 trip functions, and in addition, provide for additional features and control schemes to improve system performance and reliability, improve the operator interface, and simplify system and component maintenance. While the existing system is composed of many discrete components, the proposed Foxboro system will incorporate the function of various existing signal processors and modifiers into a redundant fault tolerant central control system. The system hardware and logic is designed such that the failure of any single input or component will not result in any perturbation to the system. This DCN addresses RFWCS software. DCN W26520A will address the RFWCS hardware installation, and W26522A will address the RFPT front standards upgrade. No physical plant work is performed by this DCN. All system operability, functionality, design basis, and licensing issues for the RFWCS as modified by DCNs W26520A, W26521A, and W26522A are addressed as part of this DCN, including an integrated Post-Modification Test scoping document. This DCN and DCNs W26520A and W26522A will affect UFSAR figures (7.8-1 sh1, 7.10-1, 8.7-4c, 11.8-
- 1) and text (Sections 7.8.5.2 and 7.10). These changes do not affect the design basis function of the RFWCS.
This modification does not affect any margins of safety in the BFN Unit 3 Technical Specifications. No unreviewed safety question is involved. 59
Tennessee Valley A uthori ty Browns Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS 1997
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OF SAFKTY EVALUATIONS FOR PROCKDURK REVISIONS 60
Tennessee Valley Authority Browns Ferry nuclear Plant I997Annual 0 eralin Re ort
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OF SAFETY EVALUATIONS PROCEDURE REVISION -,O-OI-TTE, SOLID RADWASTE This safety evaluation is written for a procedure change to O-OI-77E, Solid Radwaste, to allow for processing of brine liner water through a spent resin cask and then returning the eNuent of the cask to the Radwaste building floor drain or to the Waste Package Drain Tank. Brine liners are currently shipped to Chem Nuclear for further processing. The purpose of this change is to reduce the hardness and silica of the brine produced during the operation of Chem Nuclear's THERMEX'System. This change will reduce the number of brine liners shipped by allowing the processed brine to be returned to Browns Ferry's Radwaste tanks for subsequent reprocessing. This process will use existing plant equipment and will take place in the waste packaging truck bay of the Radwaste building. The outside watertight doors are closed prior to the processing to prevent any release in the event of a spill during the processing. Any spills will drain to the Radwaste Building floor drains and will be contained. As discussed in UFSAR Chapter 9.2 (Liquid Radwaste System) the system is designed to prevent the inadvertent release of significant quantities of liquid radioactive material from the restricted area of the plant so that resulting exposures are within the guideline values of10CFR20. The concrete walls and slabs of the Radwaste Building are designed to withstand the Design Basis Earthquake. The processing of THERMEX'System brine through the spent resin cask and returning the water to the Radwaste tanks does not increase the probability of an accident or malfunction of equipment important to safety previously evaluated in the SAR, create the possibility of an accident or malfunction of a different type than evaluated previously in the SAR, or reduce the margin of safety as defined in the basis for any Technical Specification. Therefore, an unreviewed safety question does not exist. PROCEDURE REVISION - O-SI49.A.1.5-1(OL) O-SI-4.9.A.1.b-1(OL) provides instructions for performing the Diesel Generator A Emergency Load Acceptance Test in accordance with Technical Specification 4.9.A.1.b while Unit 2 is in operation and Unit 1 is shutdown and defueled. The performance of this procedure will not result in the loss of capability of any equipment or systems important to nuclear safety other than the 480V Load Shed Logic. Test performance disables Division I of the 480V Load Shed Logic. Loss of a single division of logic has been analyzed and is permitted by Technical Specification 3.9.B.9. Issued procedure steps ensure that plant conditions permit entry into the limiting conditions for operation required for the loss of one division of the logic system. The performance of this procedure will not change the capability of any Technical Specification required equipment or systems other than the 480V Load Shed Logic. Division I of this logic will be disabled during testing to prevent the loss of loads not associated with the diesel under test. The loss of a single division of the logic system has been analyzed and is permitted for a period of 7 days under Technical Specification 3.9.B.9. Because the loss of this logic channel is already addressed by the Technical Specifications, no change is required. During the performance of this procedure the following deviations from the UFSAR descriptions will occur: Section 3.4.5.3- No spare Control Rod Drive (CRD) hydraulic pump will be available during the period that the 1B CRD hydraulic pump is not in the full connect position. As a prerequisite to procedure performance, this pump is verified to be not required to support plant operation. In the event that the 2A CRD hydraulic pump fails, the CRD accumulators would be isolated by a check valve, thus maintaining SCRAM capability.
Tennessee Valley Authority Brogans Ferry Nuclear Plant l997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS There are steps within the procedure to return the 1B CRD hydraulic pump breaker to the full connect position that could be utilized in the event that there was an urgent need for pump availability. Figures 8.5-16b & -16c - Only one division of 480V Load Shed Logic will be available during parts of procedure performance. Loss of a single division of 480V Load Shed Logic has been analyzed and is permitted by Technical Specification 3.9.B.9. Section 10.7.3- While the 1D Raw Cooling Water (RCWI pump load breaker is not in the full connect position only one of the RCW pumps will be available to be operated during a loss of offsite power event. The ECW system performs no functions required for safe shutdown after an accident. There are steps within the procedure to return the 1D RCW pump breaker to the full connect position that could be utilized in the event that there was an urgent need for pump availability. Section 8.5.5 of the UFSAR describes this test as one that is performed during refueling outages. This test will actually be performed while Unit 2 is in operation and Unit 1 is in cold shutdown and defueled. No unreviewed safety question is involved. PROCEDURE REVISION - O-SIC.9.A.1.b-3(OL) O-SI-4.9.A.1.b-3(OL) provides instructions for performing the Diesel Generator C Emergency Load Acceptance Test in accordance with Technical Specification 4.9.A.1.b while Unit 2 is in operation and Unit 1 is shutdown and defueled. The performance of this procedure will not result in the loss of capability of any equipment or systems important to nuclear safety other than the 480V Load Shed Logic. Test performance disables Division II of the 480V Load Shed Logic. Loss of a single division of logic has been analyzed and is permitted by Technical Specification 3.9.B.9. Issued procedure steps ensure that plant conditions permit entry into the limiting conditions for operation required for the loss of one division of the logic system. The performance of this procedure will not change the capability of any Technical Specification required equipment or systems other than the 480V Load Shed Logic. Division II ofthis logic will be disabled during testing to prevent the loss of loads not associated with the diesel under test. The loss of a single division of the logic system has been analyzed and is permitted for a period of 7 days under Technical Specification 3.9.B.9. Because the loss of this logic channel is already addressed by the Technical Specifications, no change is required. During the performance of this procedure, Division II of the 480V Load Shed Logic will be disabled. UFSAR Figures 8.5-16b and -16c show that two divisions of this logic are available. Division I of this logic is completely redundant and will remain available throughout performance of this instruction. Loss of a single division of 480V load shed logic has been analyzed and is permitted by Technical Specification 3.9.B.9. 62
Tennessee Valley A ulhori ty Bro>vns Ferry iVuo/ear Plant
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OF SAFETY EVALUATIONS This procedure will not change the operation characteristics of any system described in th'e SAR. Section 8.5.5 of the UFSAR describes this test as one that is performed during refueling outages. This test will actually be performed while Unit 2 is in operation and Unit 1 is in cold shutdown and defueled. No unreviewed safety question is involved. PROCEDURE REVISION OI-64 AND 3-OI-64 As an integral part of multi-unit operation, shorter refueling outages, and the resultant necessity to overlap maintenance activities during the outages, it has become necessary to consider the effect on secondary containment when work is being done on the outboard Main Steam Isolation Valves (MSIVs) and t Feedwater (FW) check valves. With shorter refueling outages, the possible windows and conditions when secondary containment will not be required will be reduced in number and in duration and be very complex to establish. Thus, this consideration is required, as a release path can exist between the reactor building and the turbine building through the associated piping system(s) with the valves open for maintenance-there is a potential for secondary containment to be lost. The conditions where secondary containment is required are outlined in BFN Technical Specifications 3.7. The limiting condition that affects valve maintenance during refueling outages is that secondary containment is required at all times when fuel is being moved. This makes coordination of maintenance work with the secondary containment requirements critical. This safety evaluation supports the currently chosen methodology of ensuring secondary containment while allowing both fuel movement to continue and maintenance to be performed on outboard MSIVs and FW check valves. UFSAR Section 5.3.3.1 states, "The Reactor Building exterior walls, roof, floor, and penetrations form the secondary containment membrane." UFSAR revision supported by this safety evaluation adds the statement, "During refueling/maintenance activities (ex., OB MSIV, FW check valve maintenance) when secondary containment is required, secondary containment membrane may be extended to analyzed boundaries." immediately following the current description. During an outage when the reactor is in cold shutdown, the activities described in this safety evaluation will be utilized to extend secondary containment into the turbine building via the main steam and/or the feedwater piping. This change will be installed temporarily to allow for maintenance and/or modification to the outboard MSIVs and/or the outboard FW check valves. These temporary changes will be removed prior restarting the reactor. The evolution will be procedurally controlled to ensure that the secondary containment is maintained operable. The UFSAR states that the penetrations are designed to limit the inieakage flow in order to maintain a negative pressure inside the secondary containment following a design basis earthquake. The engineering evaluations documented in this safety evaluation conclude that the main steam and feedwater systems will be capable of meeting this requirement when controlled as described above 2-OI-64 and 3-01-64 provide detailed procedural guidance encompassing the required aspects of this safety evaluation. The associated changes to these procedures and the BFN Safety Analysis Report do not challenge nuclear safety and ensure the associated systems are operated and monitored as specified by this safety evaluation and in a manner consistent with BFN Safety Analysis Report and Technical Specifications. No unreviewed safety question exists.
Tennessee Valley Authority "Browns Ferry Nuclear Plant
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OF SAFETY EVALUATIONS ECI-0-283-BAT004 provides corrective maintenance steps for the safe, proper and documented replacement and/or cleaning of the lead acid stationary batteries of the a 24Vdc Neutron Monitoring t Battery Bank. A temporary battery will be connected to 24Vdc bus if the system is to remain in service. Torquing of cell connections and the battery rack will be performed as necessary during the performance t of this procedure. This instruction is applicable to all the 24Vdc Neutron Monitoring Battery Banks. This instruction allows connection of a temporary battery in the event it is necessary to maintain the a 24Vdc bus energized while the normal battery is removed from service during maintenance. During the period oftime that this temporaiy battery is installed, the description of the Neutron Monitoring Battery provided in UFSAR Section 8.8.2 will not accurately depict the actual configuration and capability. The temporary battery will be installed outside of the battery rooms with the necessary connections to the battery boards made via cables through room penetrations. The temporaiy battery will be adequate to ensure no loss of function during a temporary loss of AC power. Connection of the temporary battery will cause actual configuration to vary from Figure 8.6-1d in that the temporary battery will be connected 'o
'lso the bus through a breaker instead of directly as shown. No unreviewed safety question is involved.
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS 1997
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OF SA.FKTY EVALUATIONS FOR TEMPORARY ALTERATIONS 65
Tennessee Valley Authority Broadens Ferry Nuclear Plant l997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS TEMPORARY ALTERATION0-97-01-77 RO - PORTABLE SUMP PUMP IN RADWASTE OFFGAS CONDENSATE DRAIN SUMP This temporary alteration allows a portable sump pump with integrated level switch to be placed into the radwaste offgas condensate drain sump location on elevation 546'f the radwaste building. This pump utilized 120V AC (2.8 amps) power from a local wall receptacle. Dischatge of pump will be routed to a nearby floor drain. Pump will be held in place by a wire rope, wire clamps, eye bolt, and wall anchor. The radwaste offgas condensate drain sump hatch cover will have a small notch cut out. The notch will allow for routing of portable sump pump discharge hose, power cable, and wire support rope through hatch. These changes will allow hatch to remain in closed position while temporary alteration is in place. This temporary alteration is acceptable from a nuclear safety perspective. No safety related equipment is directly or indirectly affected by this temporaty alteration. In addition, precautions have been taken to ensure radwaste condensate drain sump loop seals are not adversely impacted and that all applicable procedures will be upgraded to ensure proper operation of portable sump pump. No unreviewed safety question is involved. TEMPORARY ALTERATION0-97-04-90 RO - REPLACEMENT OF RADIATION RECORDER This temporary alteration temporarily replaces the existing Main Stack Wide Range Gaseous ENuent Radiation Recorder in Panel 2-9-10 with a Yokogawa type recorder on the Unit Supervisor's desk. The current recorder is a Gulton type recorder which has been removed and returned to the vendor for repair. The data from this recorder is from 0-RM-90-306 Wide Range Gaseous ENuent Radiation Monitor (WRGERM). The data recorded is noble gas concentration over a range of 10E-7 to 10E+5 uC/cc used to calculate post accident release rate. The recorder is identified as a Post Accident Monitor Category 3 instrument in Design Criteria BFN-50-7307, Table 1. The replacement recorder provides the same function as the existing. The new location is temporary and has been determined not to be detrimental to the function of the component. Since the existing recorder was powered from the plant non-preferred power system, there is no impact to the function of the loop by using local available power. The replacement of this recorder, O-RR-90-360, with another type does not impact any equipment required to safely operate or shut down the facility. The recorder affected provides only trend and history information from the WRGERMS radiation monitor. Therefore, this activity is acceptable from a nuclear safety perspective. A safety evaluation is required because the original recorder is shown on UFSAR Figure 7.12-2a Sheet 4 as being in Panel 2-9-10. This temporary alteration places the replacement recorder on the Unit Supervisor's desk.
t Tennessee Valley Authority Broivns Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS This activity does not constitute an unreviewed safety question. Recorder 0-RR-90-360 performs a monitoring function only. The replacement recorder will perform this required function. In addition, the loop is not an accident initiator or mitigator. 67
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997Annual 0 eratin Re ort 1997
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OF SAFETY EVALUATIONS FOR UPDATED FINAL SAFETY ANALYSIS REPORT REVISIONS 68
Tennessee Iralley Authority Browns Ferry Nue/ear Plant
/997Annua/O eratin Re ort
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OF SAFETY EVALUATIONS UFSAR CHANGE TO CHAPTER 8 This safety evaluation was written to address the following UFSAR changes to Chapter 8. A portion of text in Section 8.1 for 250V DC Battery Systems is being revised to clarify the discussion. The fact that the unit batteries and shutdown batteries supply the Essential Safeguard System (ESS) safety related loads while the station batteries do not is emphasized. This is consistent with the discussion of the 250V DC in Section 8.6. Also, text for the 120V AC system is being revised to provide summary of 120V AC systems to correct the description to agree with the as constructed plant as described in Section 8.7. Text for Power System Display Information is being revised to reflect two unit operation and clarify the location of common station service power system controls. Text in Section 8.3.5 is being revised to clearly distinguish the 500kV generator from the 24kV generator breakers that are discussed in Section 8.4 of the SAR. For the purposes of discussion the text is revised to refer to the 500kV breakers that connect the unit to the switchyard bus at unit tie breakers. A portion of the text in Section 8.3.5.2 for 161kV relaying is being revised to delete the incorrect reference to the transformers tripped by the 161kV system as startup transformers. As described in Section 8.4, the unit station service transformers provide startup power. Section 8.3.6 is being revised to reflect the worse case analysis based on transmission studies which include Unit 2 and 3 operation. This section is also being revised to delete the figures that show power flow around the system, voltage and frequency at Browns Feny for various power system conditions. These figures are copies of detailed results from calculations that are performed periodically. They are subject to continual update as system conditions change. The text referencing these figures is being deleted. Other similar type figures have already been removed from the UFSAR and removal of these will enhance the accuracy of the SAR. Portions of text in Section 8.6.4.1.1 for Plant DC Systems is being revised to reflect existing multiple station batteries and to remove the allowance to operate the battery chargers in parallel. There are no procedures or need to operate the chargers in parallel. Removing the implication that we may operate the chargers in parallel will clarify this. Text in Section 8.7.3.1 for 208/120V AC Instrument and Control Power Supply System is being revised to properly designate the regulating transformers as 208/208/120V. The change is typographical and does not change the content of the UFSAR. Section 8.8.1.3 for 48V DC annunciator power automatic transfer is being revised to delete the incorrect description for the location of the transfer. The transfer is at the control room distribution panel. These changes do not adversely impact nuclear safety, and therefore are acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. This safety evaluation is written in support of enhanced wording changes for the description of the Auxiliary Power System in Chapter 8 of the UFSAR. These changes include the use of wording that describes simultaneous operation of Units 2 and 3, corrects typographical errors and enhances descriptions of the Auxiliary Power System for both units. While most of the changes are administrative/descriptive in nature and would not alter the function or mode of operation of any plant system, the following changes require a more detailed review in that they do document physical changes to the plant.
Tennessee Valley Authority Browns Ferry Nuclear Plant
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OF SAFETY EVALUATIONS The cooling tower transformers (CTTs) have been removed as one of the independent auxiliary power sources. A credible failure mode associated with this change would be operator error. Operating procedures and training will ensure that the operator does not try to make an auxiliary power alignment utilizing the CTTs. Therefore, no new failure modes are introduced and the common station service transformers (CSSTs) and emergency diesel generators are available to supply auxiliary power to the plant in the event normal power (via the unit station service transformers) is lost. Information regarding the paralleling of the diesel generators (to supply shutdown loads in the event of a loss of offsite power) has been deleted. Paralleling of the diesels is not longer required based on current analysis which shows that the 250V Unit Batteries 1, 2, and 3 are adequate to supply the required shutdown loads for the duration (four hours) necessary to restore offsite power. A credible failure mode associated with this change would be the failure of the 250V unit batteries to perform their safety function. However, the 250V unit batteries are periodically tested to ensure their capability to perform their design safety function, therefore no new failure modes are introduced. Revision 1 provides corrective action for BFPER970870 which identified discrepancies/problems with some safety evaluations. Specifically, it was concluded that this safety evaluation (and associated safety assessment) did not address the questions in the safety assessment/safety evaluation as if the plant were configured as described in the existing UFSAR. Therefore, this revision provides the additional justification necessary to resolve this concern. These UFSAR changes do not affect the function or operation of any equipment important to safety. No unreviewed safety question is involved. uI=SAR CHANGE TO CHAPTER 8, SECTIONS 8.4 AND 8.5 8.4.3- The text is being revised to change Power Generation to Auxiliary Power System, to state that offsite is the preferred power source and the onsite is the standby power source. These changes are for clarification and are consistent with the system design criteria. These changes are editorial and do not impact the safe operation of the plant. 8.4.4- The text is being revised to clarify that the diesel generators are standby (onsite) diesel generators. This is an editorial change. 8.4.5.1 - The text is being changed to simplify the wording. The unit station service transformer (USST) provides power to the 4160-V Unit Boards which supplies power to the respective operational loads. Removing "operational loads on" does not change the meaning of the text or the description of how the power system is operated. "3B" is being added to the text to be consistent with the wording in the previous paragraph which discusses USSTs 1B and 2B. This change does not change the meaning or intent of the text and does not change any electrical breaker alignments. 8.4.5.2- Loss of voltage initiated transfers have been removed from 4160V Unit Boards 1A, 1B, 2A, and 2B by DCN W1 4030. The description in the UFSAR was not changed at the time the DCN was issued. DCN W14030 provided the justification for the change. 8.4.5.3 - The 480V distribution system is a three phase, ungrounded system. The distribution system is ungrounded in order to allow for the continued operation of the system even though a ground may exist. The ground is detected by the ground detection system and repaired when a system outage is scheduled. Not all 480V substations have an automatic bus transfer scheme as noted in the text. The text is being changed such that each substation without an automatic transfer will no longer be listed. This change does not modify any system design parameters or the safety function of any plant feature. The text is 70
Tennessee Valley Authority Browns Ferry iVuelear Plant 1997 Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS being changed to include all bus ratings. DCN W1 7720 added the HVAC Board which has an 800A bus and does not have an automatic bus transfer. DCH W17720 provided the justification for the change. 8.4.5.4 - The text is being changed to add the source of the 120V AC power for the starters and contactors. The control power transformer is the 120V power source for the starters and contactors. The control power transformers receive power from the same motor control center (MCC) source as the starters and contactors. The addition of the control power transformers does not change the electrical loading. The safety function has not been changed due to the addition of the control power transformer. 8.4.6.1 - The text is being revised to add 480/240V which is a power source rating for some of the equipment listed in this paragraph. This change is to show all control power sources. This paragraph is discussing the normal auxiliary power system control function but does not include the cooling tower controls. The cooling towers are controlled locally and do not have manual controls in the control room. The cooling towers do not perform a safety function and are only used for short periods of time when the river temperature approaches high temperature. The use of local controls is acceptable because the local operator is in communications with the unit control room and the cooling towers do not perform a safety function. There are no electrical load changes or system design parameter changes. The text is being clarified to show that Units 1, 2, and 3 share the same reactor building. Post accident sampling facility (PASF) is being added to define PASF. These are editorial changes and do not change the meaning of the paragraph as stated in the FSAR. The text is being corrected by removing transfer and replacing it with trip which is more correct because any trip of the 4kV unit board source breaker will result in a transfer at the shutdown bus. The automatic transfer results in a faster restoration of offsite power to safety loads should the first source be lost. This wording change does not change the safety function of the normal auxiliary power system. 8.4.8.1.3 - Monitors is being changed to relays which is a more descriptive term for how low voltage is being detected. Additionally, relays and monitors is being used interchangeably and removing monitor will remove a source of possible confusion in the FSAR. These are editorial changes and do not change the meaning of the paragraph as stated in the FSAR. 8.4.8.1.4 - The wording is being revised to be consistent with Section 8.4.8.1.2 which describes in detail how degraded voltage relaying operates. Adding "after a time delay" does not change the safety function or operation of the degraded voltage scheme. 8.5.3.2- The DC driven fuel oil pump operates during the diesel generator start sequence and continues to operate when the diesel generator is running. The DC fuel oil pump is backup to the engine driven pump per Design Criteria BFN-50-7082. The DC fuel oil pump provides redundancy to the fuel oil system and reduces the possibility of a failure of the diesel generator. Having the DC fuel oil pump run continuously improves the reliability of the diesel generator to perform its intended safety function. 8.5.3.4- Diesel fuel alarms are available to ensure that adequate fuel oil is available for the diesel to perform its intended safety function. The storage tank level switch is set to alarm when the fuel oil level drops to the 7 day supply and allows refilling as necessary. This is a clarification to the UFSAR text and does not change design parameters or the safety function of the diesel generators. 8.5.3.5- The text is being revised to clarify that each shutdown board supplies one RHR pump. The text relative to the 250V DC control buses in the shutdown boards is being simplified. The details of how the control bus is connected is shown on Figures 8.5-4a and Pb. These changes are consistent with the design critena and other sections of the UFSAR and do not change the function or operation of any plant systems. 8.5.4.1 - The text is being revised to remove details as to which reactor water level starts the diesel generators. This is an editorial change and is consistent with other sections of the FSAR. 8.5.4.4- With a unit set to operate in the "parallel with the system" mode, a failure causing the unit to be placed in the "single unit" mode may result in an large increase in KW load. If the KW loading becomes 71
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OF SAFETY EVALUATIONS too large the unit may trip. The increase in KW load will be in connection with only a single unit; the remaining units will be available to perform the required safety function. This change does not change any design parameters or the safety function of any plant system. Figure 8.5 Unit 1 accident signals have been disconnected. DCN H2735 provided the justification this change. These changes are acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. UFSAR CHANGE TO CHAPTER 8 This safety evaluation is written in support of enhanced wording changes for the description of the Auxiliary Power System in Chapter 8 of the UFSAR. These changes include the use of wording that describes simultaneous operation of Units 2 and 3, corrects typographical errors and enhances descriptions of the Auxiliary Power System for both units. While most of the changes are administrative/descriptive in nature and would not alter the function or mode of operation of any plant system, the following changes require a more detailed review in that they do document physical changes to the plant. The cooling tower transformers (CTTs) have been removed as one of the independent auxiliary power sources. A credible failure mode associated with this change would be operator error. Operating procedures and training will ensure that the operator does not try to make an auxiliary power alignment utilizing the CTTs. Therefore, no new failure modes are introduced and the common station service transformers (CSSTs) and emergency diesel generators are available to supply auxiliary power to the plant in the event normal power (via the unit station service transformers) is lost. Information regarding the paralleling of the diesel generators (to supply shutdown loads in the event of a loss of offsite power) has been deleted. Paralleling of the diesels is not longer required based on current analysis which shows that the 250V Unit Batteries 1, 2, and 3 are adequate to supply the required shutdown loads for the duration (four hours) necessary to restore offsite power. A credible failure mode associated with this change would be the failure of the 250V unit batteries to perform their safety function. However, the 250V unit batteries are periodically tested to ensure their capability to perform their design safety function, therefore no new failure modes are introduced. Revision 1 provides corrective action for BFPER970870 which identified discrepancies/problems with some safety evaluations. Specifically, it was concluded that this safety evaluation (and associated safety assessment) did not address the questions in the safety assessment/safety evaluation as if, the plant were configured as described in the existing UFSAR. Therefore, this revision provides the additional justification necessary to resolve this concern. These UFSAR changes do not affect the function or operation of any equipment important to safety. No unreviewed safety question is involved. UFSAR CHANGE TO INCORPORATE SAFERIGESTR LOSS OF COOLANT ACCIDENTANALYSIS 72
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OF SAFETY EVALUATIONS This safety evaluation is written in support of a change to UFSAR Chapters 4, 6, 7, 8 and 14 to incorporate the new SAFER/GESTR loss of coolant accident (LOCA) best estimate analysis methodology and the associated BFN specific analyses for Units 1 and 3. A similar change was made for Unit 2 prior to Cycle 8. When SAFER/GESTR was added for Unit 2, the old information was retained in the UFSAR as applicable to Units 1 and 3. The majority of the changes evaluated herein are the application of the new methodology to Units 1 and 3 and the removal of the now non-applicable information which applied to Browns Ferry prior to the reanalysis. Additionally, a change has been made to clarify the assumptions utilized in the reactor vessel blowdown analysis for both units. Section 14.6.3.3.1 assumption "a" appeared to pertain to the assumed power level in the analyses. A review of the parent General Electric (GE) analysis document revealed that the original UFSAR overly paraphrased the assumptions from the GE Analytical Model. The GE Analytical Model was referenced in the UFSAR; therefore the information was available in the original document when the references were consulted. The BFN UFSAR has been revised to clarify that the analysis assumes the reactor is at 100 percent power to maximize the reactor pressure during blowdown which maximizes the blowdown flow rate but the equalizer valve alignment is based upon 80 percent power to maximize the blowdown area. It has also been noted in the UFSAR text that the assumption regarding the effect on the blowdown area resulting from the assumed equalizer valve position is conservative for Unit 3 since the ring header has been split into separate halves via DCN W1 7545 and thus it is not possible to experience interloop cross flow through the equalizer valves. The proposed change for transitioning to the new SAFER/GESTR methodology for Units 1 and 3 does not require a change to the Technical Specifications and is not a special test or experiment. However, the change does represent a significant change to the Safety Analysis Report and thus a safety evaluation is required. This change does not involve an unreviewed safety question. UFSAR CHANGE TO SECTION 1.6.2.8 This safety evaluation supports a change to UFSAR Section 1.6.2.8, "Secondary Containment," which states, "It is designed for an inleakage of less than 100 percent of building volume per day." This sentence is not correct and is being deleted. The Secondary Containment and the Standby Gas Treatment System are described in detail in UFSAR Section 5.3. This change makes this section consistent with information already contained in other sections of the current Technical Specifications. There is no change to the manner in which the Secondary Containment and Standby Gas Treatment Systems operate. The operability and surveillance requirements of the Technical Specifications are unchanged. Therefore, this change will not reduce the margin of safety as defined in the basis for any Technical Specification. UFSAR CHANGE TO SECTION 10.18 REVISION 1 This safety evaluation addresses a revision to Section 10.18 of the UFSAR. This section discusses the BFN Communications System, a nonsafety related system. The only portion of the BFN Communications System with a safety related function is the Backup Control Sound-Powered System (BCSPS). These 73
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OF SAFETY EVALUATIONS changes do not have any affect on the BCSPS. These changes are being made to reflect current design or are editorial in nature. The changes to this UFSAR text will not reduce the margin of safety as defined in the basis for any Technical Specification. These changes are to the description of nonsafety related portions of the system only. These changes are safe from a nuclear safety standpoint. No unreviewed safety question exists. The safety assessment/safety evaluation was revised in response to BFPER970870. This revision places the safety assessment/safety evaluation/screening review in the format now prescribed by SPP-9.4 Revision 0 and revises the responses to questions B.1 - B.7 as required. No new safety concerns or unreviewed questions were identified. UFSAR CHANGE TO SECTION 11.8.3.1 The feedwater pumps and turbines can supply 100% flow to the reactor vessel at rated conditions. This is based on the pump capacity curves and Campbell diagrams for the turbines. The original Turbine Design Specification Sheet for Browns Ferry feed pumps limit rpm to 5500 with two pumps running. The reference in UFSAR 11.8.3.1, where it states that two pumps can carry approximately 75% load, is an overly conservative statement. Two pumps can provide 100% flow at about 5200 rpm and require only a net positive suction head (NPSH) of less than 200 ft. The drivers for the feedwater pulnps are variable speed turbines. Since these turbines are variable speed, they are of a tall bucket design. A turbine designed to run at a specific speed can be made with shorter buckets since the velocity triangles for the stages will be fixed. In a variable speed turbine, the need to operate over a wide range of rpm's requires that the bucket length be longer to accommodate the wide range of relative velocities between the buckets and the working fluid and still maintain acceptable efficiencies. Since the buckets are longer, high frequency stimulus, such as nozzle passing frequency are of no concern. However, the third stage buckets do pass through a resonance beginning at 3000 and exiting it at 4010 rpm. The normal operating speed of 3 pumps is above this range. Lower frequency stimulus (per rev) can cause vibration stress higher than desired in tall bucket design. At Browns Ferry, the sixth stage buckets become resonate with 4 per rev harmonic of the fundamental tangential at speeds above 5050 rpm. The vibration stress induced at and above this speed could result in reliability concerns as analyzed by General Electric. Therefore, to ensure reliability, reactor power should be reduced to approximately 90% power (power is referenced to rated power, 3293 MWt) before removing a reactor feed pump from service. This activity is safe from a nuclear standpoint. The system parameters were reviewed with respect to this activity. The operation of the reactor feed pumps and feed pump turbines up to 5050 rpm is not a concern. No equipment failure will occur as a result of this operation. NPSH requirements will still be meet and equipment reliability will be maintained. This activity is different than currently described in the FSAR. However this change better describes what the feedwater system can do. Since this change operates feedwater pumps within their capability, and the turbine will not be operated at a resonate speed, the reliability of the equipment is not changed. Therefore this condition is not an unreviewed safety question. UFSAR CHANGE TO SECTION 12.2.9.2.2 This safety evaluation is written to support a change to the UFSAR Section 12.2.9.2.2 relative to 74
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OF SAFETY EVALUATIONS emergency access from the equipment access lock. The last paragraph in this section pi'esently states:
"A personnel access lock is provided adjacent to the equipment access lock. This personnel lock provides an emergency access from the equipment access lock to the reactor building or the outside."
The door (230A) which leads from the personnel access lock to the outside has been chained and padlocked. This door is a watertight personnel access door. Emergency access to the outside is therefore not possible through this door from the lock. This door is part of the Radiologically Controlled Area boundary and there are no friskers installed in the immediate vicinity of the door. This door also provides direct access into the plant's Vital Area. The door is chained and padlocked for both radiological and security reasons. Although the outside door is padlocked, the personnel lock continues to provide an emergency access from the equipment access lock to the reactor building. In the last sentence in the paragraph noted above, the last three words "or the outside" will be deleted. This UFSAR change does not constitute an unreviewed safety question because the change will not affect the safety function of any system, structure, or component. UFSAR CHANGE TO SECTION 5.2.3.8 Analysis has identified a condition involving the primary containment purge supply valves that could result in degraded pressure suppression capability. This condition could occur when the inboard primary containment purge supply valves to the drywell and pressure suppression chamber are open, the unit is not at cold shutdown, a Loss of Coolant Accident was to occur and Division I Primary Containment Isolation System (PCIS) logic fails to initiate. This configuration would result in a large bypass path to the pressure suppression chamber steam space and significantly elevate primary containment pressure. As a result of this analysis, parallel purging/inerting has been prohibited. Implementation of this UFSAR change will result in enhanced nuclear safety. The condition of parallel purging/inerting of the drywell and suppression chamber when the reactor was not at cold shutdown was outside the design basis. This change will insure that the plant is never operated in that configuration. Operating the plant in a more conservative manner by prohibiting parallel purging of the drywell and pressure suppression chamber will not reduce any margin of safety as defined in the basis for any Technical Specification. No unreviewed safety question is involved. UFSAR CHANGE TO SECTION 5.3 This safety evaluation supports UFSAR changes to Section 5.3. These changes deal primarily with the method of isolating and maintaining secondary containment regarding the zonal concept. The plant was originally designed to allow secondary containment to be maintained separately in each of the four zones (three reactor zones and a common refueling zone). The plant currently relies on the outer boundary of the secondary containment in the safety/radiological analysis; however, the secondary containment isolation signals isolate only the affected zones. Following an accident, less than four zones of the secondary containment could be isolated initially. Ifthe interzonal boundaries fail to contain the radiological contamination, the radiation monitors in adjacent zones would expand the number of isolated zones so that the outer boundary ultimately provides the radiological protection as described in the radiological analysis. These UFSAR changes clarify the sequence/method of isolation and the 75
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OF SAFETY EVALUATIONS assumptions in the radiological analysis. Additionally, UFSAR changes were made to clarify assumptions in the radiological analysis and to clarify the description of the standby gas treatment building. These changes will not reduce the margin of safety as defined in the basis for any Technical Specification. No unreviewed safety question exists. This safety evaluation evaluates a revision to UFSAR Section 5.3, required due to a design basis change which qualifies sections of Units 1, 2 and 3 Raw Cooling Water (RCW) system dischaige header piping external to the reactor building penetration, including a water or soil seal, to serve as the secondary containment membrane. This change will re-classify check valves 1,2,3-CKV-24-765 to Quality Related (QR), Seismic II pressure retention. Because of the difficulty in isolating the RCW system loads which discharge through these valves, proper maintenance is difficult to achieve on check valves 1,2,3-CKV-24-765, which tend to suffer internal corrosion problems from the river water. Presently, a typical RCWdischarge line secondary containment membrane consists of the check valve and piping (including the radiation monitoring station) through the reactor building wall to the penetration seal/anchor plate. This change will qualify the secondary containment membrane to consist of the discharge piping outside the wall from the penetration to the point under the yard soil where the carbon steel discharge pipe joins clay pipe. The secondary containment membrane will include a water or soil seal as an air in-leakage barrier. No credit will be taken for the check valves'nternals (i.e., the seat and disk) or the discharge piping inside the reactor building upstream of the wall penetration to function as an isolation barrier for secondary containment. This is a documentation change to revise. design basis requirements; no physical change will be made on any plant equipment. This secondary containment boundary change does not affect the capability of the plant ventilation system to maintain at least a 1/4" water gauge negative pressure on the secondary containment volume. Standby Gas Treatment (SGT) system operation and flow capacity are not affected by this change. The air infiltration rate through the compacted clay soil is negligible compared to the calculated post-DBE flow margin available in the SGT system. Therefore, no process parameter operating margins associated with establishing and maintaining secondary containment integrity are reduced by this change. No unreviewed safety question exists. UFSAR CHANGE TO SECTIONS 6.6, 10.9.5, AND 10.10.5 Corrective action for Problem Evaluation Report (PER) BFPER960960 requires revision to UFSAR Sections 6.6 for Core Standby Cooling Systems (CSCS), 10.9.5 for Residual Heat Removal Service Water (RHRSW), and 10.10.5 for Emergency Equipment Cooling Water (EECW) to clarify or explain the method for monitoring system leakage in the reactor building. These sections currently state, "The CSCS (RHRSW, EECW) piping and components in the Reactor Building will be inspected once each operating cycle in order to identify and repair any leakage from these systems. This inspection is performed during operation of each system to ensure that the leakage which would occur following accident conditions is kept at a minimum." These statements take credit for Mechanical Maintenance Instruction (MMI) -93 which implemented a leak reduction surveillance program required by NUREG-0578, recommendation 2.1.6.a. NUREG-0578 titled, "Integrity of Systems Outside Containment Likely to Contain Radioactive Materials", was a result of 76
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OF SAFETY EVALUATIONS lessons learned from the Three Mile Island (TMI) incident. NUREG-0578 was later superseded by NUREG-0737 titled, "Clarification of TMI Action Plan Requirements". The monitoring requirement did not change with the new NUREG. MMI-93 has been canceled based on existing procedures and programs which include inspection for system leaks, notification of appropriate plant management, and correction using the Work Order process. The existing procedures and programs provide inspections that meet the intent of NUREG-0737 and the FSAR. However, the UFSAR sections referenced above require revision to clarify how leakage is monitored. This safety evaluation addresses the changes to the UFSAR to correct this condition. The sections will be revised to state that there are existing procedures and programs in place to monitor for leakage. The changes to UFSAR Sections 6.6, 10.9.5, and 10.10.5 do not represent a special test or experiment described in the SAR. These changes do not change any system design or functional requirements nor is the technical content of any text, tables, graphs, or figures changed. The text is revised to accurately, describe the performance of leakage inspection to maintain system leakage as-low-as-practical. No unreviewed safety question is involved. UI=SAR CHANGE TO SECTION 7.18 This safety evaluation is written in support of enhanced and corrected wording changes for the description of the Backup Control System in Chapter 7 (Section 7.1 8) of the FSAR. These changes include the use of wording that clarifies the description of the Backup Control System, deletes unnecessary and/or incorrect information, corrects discrepancies between the actual plant configuration and the description in the UFSAR and provides clarification of the Backup Control System with respect to the Appendix R Program. None of these chang'es result in any physical changes to the plant which could alter the function or mode of operation of any plant system. The changes are primarily administrative/descriptive in nature. There are no changes to the operating characteristics of any plant equipment or systems. These changes to Section 7.18 do not affect the function or operation of any plant systems or equipment and do not adversely affect the safe shutdown capability of the plant. Therefore, these changes are acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. UFSAR CHANGE TO SECTION 7.3 This safety evaluation addresses a revision to the BFN Safety Analysis Report for Chapter 7, Section 7.3, Primary Containment Isolation System. The following is a synopsis of the items addressed. 7.3-FJN-006- addresses Section 7.3.4.6 and the statement "Conversion to actual closing time can be made using the size of the line to be isolated". The term "actual" will be revised to "nominal", since each valve closing time identified in the UFSAR is verified by testing to be within its prescribed limit, but not to an "actual" value. This is considered clarification of the UFSAR and a non significant change. 7.3-FJN-008- addresses Section 7.3.4.3 which states "an accumulator is located close to each isolation valve to provide pneumatic pressure for valve closing in the event of failure of the normal air supply system". This sentence will be modified to state "an accumulator is located close to each isolation valve 77
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OF SAFETY EVALUATIONS to provide pneumatic pressure to assist valve closing in the event of failure of the normal air supply system". This was done to clarify that the air and accumulator are used to assist in the valve closing and not the sole motive power for closing the valves. This is considered clarification of the UFSAR and a non-significant change. 7.3-FJN-009- is an administrative change, to add the words "main steam isolation valves" to Section 7.3.4.6, Paragraphs 5, 7, and 8 where a discussion of main steam isolation valves has the words "isolation valves". Also in Paragraph 8, a reference to Subsection 4.6, "Main Steam Line Isolation Valves" will be changed to "Main Steam Isolation Valves" with the word "Line" deleted from the text. This is considered clarification of the UFSAR and a non-significant change. 7.3-BWH-003 - Section 7.3.4.8, Item 14 states "System piping outside primary containment is sensed by temperature switches...". The temperature switches were replaced by resistive temperature devices (RTD) and analog trip units (these changes were implemented by ECN P7216 for Unit 2 and DCN W1 9297 for Unit 3). This paragraph is revised to reflect this configuration. 7.3.4.8.3 (OPS) - Section 7.3.8, Item 3 discusses the Main Steam line tunnel temperature indicating switch which provides indication and alarm in the main control room of increasing temperatures in the steam tunnel. The UFSAR states "Upon loss of power, either an alarm condition is present or there is clear indication to the operator that no power exists to the instrumentation." This will be reworded to state "Upon loss of power, an alarm condition is present to alert the operator that the instrumentation is inoperable." This change is considered a clarification of the UFSAR text and is consistent with plant configuration. 7.3.4.6 (OPS) - Section 7.3.4.6, last paragraph states "Slow closure of a valve during testing requires 50 to 60 seconds. The valve mechanical design is discussed in Subsection 4.6...". This is in regards to the, main steam isolation valves (MSIV) and their testing. The statement is not correct, therefore it is deleted since testing of the MSIVs is discussed in Section 4.6 in more detail. This is considered a clarification of the UFSAR text and a non-significant change. 7.3-RLB-001 - Numerous changes identified: a) Section 7.3.3, Item 7.c. states "the event shall result in automatic isolation and shall not impair the ability of the system to respond correctly as other monitored variables exceed their trip points". In this sentence the word "trip points" is changed to "isolation setpoints". This is considered a clarification of the UFSAR text and a non-significant change. b) Section 7.3.2, Item 7f, states "Groups 1-6 in Figure 5.2-22 require deliberate operator action to return the system to normal...". These groups are defined in UFSAR Figure 5.2-22, so the bold section above is an addition to the FSAR. This is considered a clarification of the UFSAR text and a non-significant change. c) Section 7.3.2, under definitions states "Group A isolation valves listed in Figure 5.2-22 are in pipelines that communicate directly with the nuclear system process barrier..." and the second. paragraph states "Group B isolation valves listed in Figure 5.2-22..." Both of these statements imply that Figure 5.2-22 will identify which valves are Group A and Group B valves, which is not correct. The UFSAR figures identify the isolation group signals (Group 1, Group 2, etc.), penetration number, valve type, size, type of service, etc. The Groups A and B are not the same as the isolation group signal (1, 2,3, etc.) or the signal type (A = Reactor Vessel Low water level, B, etc.) as shown on the UFSAR Figure 5.2-22. Therefore the text above will be deleted and a new sentence added that states "See Figures 5.2-22, Sheets 1 through 3, for a list of Primaiy Containment Isolation valves". This change is for clarification,
~ a non-significant change.
d) Section 7.3.4.1 states at the end of the first paragraph "Systems were evaluated and containment isolation provisions were provided based on the following." The word "were" was added to sentence as an editorial change for sentence clarification. e) Section 7.3.4.1, Item 2, states "Essential Systems - These systems are required for postaccident mitigation and are not isolated automatically upon receipt of a PCIS...The following systems are classified essential as a result of their accident-mitigation function:" The word "essential" was added 78
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OF SAFETY EVALUATIONS as an editorial change to clarify the sentence. f) Section 7.3.4.3, middle of second paragraph states "Switches are enclosed in cases to protect them from environmental conditions". This statement is not correct. The switches are environmentally qualified, but typically are enclosed in a manufacturers'ousing. This sentence will be deleted entirely, since it is incorrect and does not represent all cases. The limit switches were replaced and/or modified as part of Unit 2 restart and Unit 3 recovery. g) Section 7.3.4.6, third paragraph states "Direct, solenoid-operated isolation valves and solenoid valves are chosen with electrical and mechanical characteristics which make them suitable for the service which they are intended. Appropriate watertight or weathertight housings are used to ensure proper operation under accident conditions". This last sentence is to be deleted since housings required for Environmental Qualifications (EQ) require weep holes for moisture and condensation removal, special gaskets, and some require conduit seals. This sentence will be deleted rather than describe it for all locations without excessive details. This change is consistent with the EQ program design criteria and generic binder. h) Section 7.3.4.7, Item 1 second paragraph states "Two reactor vessel low-water-level isolation trip settings are used to complete the isolation of the primary containment and the reactor vessel." To clarify the sentence will state "There are two reactor vessel low-water-level isolation trip settings used for (to complete) the isolation of the primary containment and reactor vessel". The text "(to complete)" is removed and replaced with the word "for". This is an editorial change to clarify the sentence and does not change its content or meaning. i) Section 7.3.4.7, Item 1, Page 7.3-14 states "The second and lower of the reactor vessel low-water-level isolation settings was selected low enough to allow removal of heat from the reactor for a predetermined time following the scram, and high enough to complete isolation in time for the operation of Core Standby Cooling Systems in the event of a large break in the nuclear system process barrier". The words "for a predetermined time" are deleted, since there is not an exact time associated with the lower water level, but an analysis that shows the trip setting does allow for heat removal to the condenser without increasing core damage, and thus removal of additional heat is basis for this lower water level isolation signal. j) Section 7.3.4.9 states in the middle of the first paragraph "Motor operators for valves inside the primary containment are of the totally enclosed type; those outside the primary containment have weatherproof-type enclosures. Solenoid valves, whether used for direct valve isolation or as an air pilot, are provided with watertight enclosures. All cables and operators are capable of operation in the most unfavorable ambient conditions anticipated for normal operations. Temperature, pressure, humidity, and radiation are considered in the selection of equipment for the system. Cables used in high radiation areas have radiation resistant insulation. Shielded cables are used where necessary to eliminate interference from magnetic fields." This sentence is deleted and replaced with "All equipment required to operate during a design basis event meets the environmental qualification requirements of Section 1.5". This sentence is replaced, since it has too much detail and is not correct or complete as stated. The following paragraphs were also deleted from Section 7.3.4.9: "Electrical cables are selected with insulation designed for this service. Closing mechanisms and valve operators are considered satisfactory for use in the isolation control system only after completion of environmental testing under loss-of-coolant accident conditions or submission of evidence from the manufacturer describing the results of suitable prior tests." This change was deleted since it is too detailed and does not adequately describe how all procurement of material is performed. This change is consistent with EQ design criteria and generic EQ binder.
"Verification that the isolation equipment has been designed, built, and installed in conformance to the specified criteria is accomplished through quality control and performance tests in the vendor's shop, or after installation at the plant before startup, during startup, and thereafter during the service life of the equipment. See Subsection 1.5 for environmental qualification of electrical equipment. Control is also exercised through review of equipment design during bid review and by approval of vendor's drawings during the fabrication stage. Purchase specifications require extensive control of materials and of the fabrication procedure." These paragraphs are deleted since they are too detailed and are either incomplete or not correct as stated. This change is considered a clarification of UFSAR text.
k) Section 7.3.5, second paragraph states "Design procedure has been to select tentative isolation trip settings that are far enough above or below normal operating levels that spurious isolation and 79
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OF SAFETY EVALUATIONS operating inconvenience are avoided." The word "tentative" was deleted since it implies that we had tentative settings, that we revised or adjusted to account for actual operating conditions. This may be true, but there is no documentation to support a "tentative" trip setting. This change is consistent with the design criteria. I) Section 7.3.5, eighth paragraph states "Steam leaks into the steam tunnel frommain steam line, feedwater line, or RCIC steam line breaks will cause the main steam isolation valves to close if the temperature at the temperature switches reach their setpoints". This sentence will be revised in its entirety to state "The settings for the main steam isolation function will not spuriously isolate due to other steam leaks in other systems". This change is consistent with the design criteria and UFSAR logic diagrams for containment isolation. These changes to the UFSAR do not change or alter plant configuration, any design basis accidents, or anticipated operational transients. The extent of the changes are primarily clarification of text or rewording for consistency with existing plant configuration and design criteria. No unreviewed safety question is involved. UFSAR CHANGE TO SECTION 7.4 t This safety evaluation is written in support of UFSAR changes to Section 7.4. Section 7A.3.1 - An editorial change is being made to reference Section 7.18. Section 7.4.3.2.4- An editorial c h a ng e i's bein g made to dari fythe o p e rating sequence ofthe HPCI initiation sequence. This operating sequence was engineered as a part of the original design for the HPCI System and the UFSAR changes are to make the UFSAR consistent with the as-built plant. The vendor manuals for the HPCI turbines describe the startup sequences for the turbines. No change is being made to the startup sequence. The only change being made is a darification of the sequence in the UFSAR test. Section 7.4.3.2.5- An editorial change is being made to clarify the textual description of the normal position of the maintenance valve shown on Figure 7.4-1a and make it consistent with the UFSAR figure. Also, changes are being made to make the UFSAR text consistent with the UFSAR figures for the logic for the HPCI Min Flow valve, as well as the test return throttle and block valves shown on UFSAR Figure 7.4-2b and for the control of the steam line drain condensate pot depicted on UFSAR Figure 7.4-2a. Section 7.4.3.3.2- An editorial change is being made to the affected text to make it agree with Section 7.4.3.3.3 Paragraph 2 which states in part "... The requirement that at least one of the LPCI pumps or two Core Spray Pumps be running before automatic depressurization starts insures that cooling will be available to the core after the system pressure is lowered." These changes are being made to make the UFSAR consistent with the other UFSAR sections. Another editorial change is required to this section to made a paragraph consistent with itself. The first sentence of this paragraph reads in part "...providing that at least one LPCI pump or two core spray pumps are running,..." This change revises the second sentence to agree with the first changing "the core spray and LPCI pumps are running" to "the core spray or LPCI pumps are running". Section 7.4.3.4.2- Figure 7.4-5c shows the logic for the operation of the Core Spray Injection Valves. The changes are being made to make the UFSAR text consistent with the UFSAR Figures. I Section 7.4.3.4.3- Section 8.4.5.2 states "Each switchgear bus section has an inductive type undervoltage relay which will trip all motors on the bus in case of prolonged undervoltage." Section 8.5.3.5 states in part
"...On loss of normal voltage to a shutdown board, a signal is given to start the corresponding diesel 80
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OF SAFETY EVALUATIONS generator, and all motor feeder breakers in the board are tripped..." Therefore these changes are being made to make the UFSAR consistent with the referenced sections. Section 7.4.3.4.4- Logic for the Core Spray Minimum flow valve is shown in Figure 7.4-5b. Changes are being made to make the UFSAR text consistent with the text. Section 7.4.3.4.5- These pressure switches and associated annunciatois are depicted on Figure 7.4-5c. This change is made to make the UFSAR text consistent with the UFSAR figures. Section 7.4.3.5.4- The switch discussed in this section is clearly a "protected" switch as a keylock switch. This change simply clarifies the type of protection for the switch. The change is editorial to clarify the intent without technically changing the context of the text. Section 7.4.4- The sentence "Control room override of local switches is provided." is being deleted. The control room overrides for these switches are depicted on the various Mechanical Logic Diagrams for the affected systems. Repeating the information here adds confusion to the intent of the affected paragraph, These changes are editorial or nonsignificant changes, and therefore do not adversely affect nuclear safety. No unreviewed safety question is involved. UFSAR CHANGE TO SECTION 7.8 This safety evaluation supports the following UFSAR changes: Section 7.8.5.1 - Remove the last section of the first paragraph which describes the material of thermocouple wires and the installation requirements. This level of detail is not necessary in the UFSAR which does not have any bearing on the safety of the system. The last sentence of Section 7.8.5.1 is reworded as "The temperature of the reactor vessel flange and the vessel wall adjacent to the flange is recorded on a temperature recorder." These temperatures are recorded in TR-68-37, which is a 2 pen recorder. The difference is available by reviewing the chart of this recorder but the recorder is not setup to record the difference in temperatures. Review of the initial design specifications show that this recorder was never set up to record the differential. The difference in temperature does not initiate any operator action. The clarification to this sentence does not affect the safety of the plant. AII the required information is available from the recordings. Section 7.8.5.2- The level instrumentation does not trip RCIC turbine but isolates by closing the steam valve. This was implemented by DCN T17534A. Therefore the word trip is changed to "isolate". This clarification does not change the safety functions of the RCIC system and is acceptable. Section 7.8.5.3- The flow rate through each of the jet pumps is measured by taking the differential pressure across the jet pumps. The square root of the differential pressure is linear to the flow rate. The indicators in the control room provide the differential pressure across the jet pumps except for the four calibration flow instruments which indicate flow in the control room. Flow is not a directly measured variable, but is derived from the differential pressure across the jet pumps. Therefore the words "flow rate through" is changed to "differential pressure across". This is a clarification change and does not affect the safety of the system. Section 7.8.5.4 - Three pressure transmitters input to feedwater control system and the pressure recoider receives the signal from the digital Foxboro control system. The word "two" in the third sentence is changed to "three" and the fifth sentence is re-written as "The recorder receives a pressure signal from 81
Tennessee 1~alley Authority Browns Ferry iVuelear'Plant 1997AnnualO eratin Re ort
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OF SAFETY EVALUATIONS the Feedwater Control System". This change was implemented by DCN W25841A for Unit 2 and DCN W26520A for Unit 3. The pressure switches used to bypass the main steam line isolation valve closure scram were removed by ECN P0672. Therefore, the second item which lists the pressure switches in the pressure instrument listing is removed. UFSAR Section 7.8 is titled "Reactor Vessel Instrumentation" and hence the last row in this list is changed to use the UFSAR Section 7.8 title correctly. This is an editorial change. Section 7.8.5.5- Reactor vessel top head flange leak detection pressure and level instruments are not listed in Table 7.8-1. Therefore, the reference of this table is removed from this section. This is an editorial change and does not change the function of the system. Section 7.8.5.6- Figure 5.2-2 was deleted from the UFSAR in Amendment 11 and Figure 5.2-6 does not exist in the UFSAR." Therefore, the figure reference is removed from the last sentence of this section. These are editorial changes and the safety of the plant is not affected. Section 7.8.7 - The first word "The" is changed to "A" which is an editorial change. Table 7.8 Table 7.8-1 provides the list of primary containment monitoring instrumentation. The suppression chamber pressure indicator and recorder ranges were changed from 040 psig to 0-60 psig by ECN P71 52 and DCN W19562A. Safety evaluations were completed to address this change. Therefore, the ranges for these instruments are changed in the UFSAR table and is acceptable based on safety evaluations prepared for the DCN. The system operation and ability of all safety related systems to perform their required functions are not adversely affected by these revisions to the UFSAR. These revisions will not change any existing safety related system functions or parameters and is acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. UFSAR CHANGE TO SECTION 9.5 This UFSAR change adds clarifying information concerning the Off-gas system in-leakage rate specified in UFSAR Section 9.5. The UFSAR provides data from other operating units to conclude that in-leakage rates on the Browns Ferry units can be maintained below the design rate of 18.5 SCFM. This data was used to determine a design in-leakage rate for Browns Ferry prior to operation. Operating experience shows that this rate varies and has been documented higher than the design rate specified in the FSAR. The Off-gas in-leakage flow rate is one of several parameters that affect the release rate through the Off-gas stack. Based on review of the Off-Gas General Electric Design Specification and the system operation, the in-leakage flow rate is not the primary factor in achieving the system objective. The Off-gas system is designed to minimize and control the release of radioactive Krypton, Xenon N-13, N-16 and 0-19 isotopes sufficiently by allowing optimum decay before discharge to the atmosphere. Also, the Off-gas system reduces the amount of radioactive particulate material released to the atmosphere through filtration of the off-gas before release to the stack. General Electric Specification 22A1230, "Off-gas system", Section 9.1, recommends that an environs and plant site monitoring program be instituted to obtain background data on radiation levels to be continued after operation to prove that the actual doses at points of general public exposure are within acceptable licensing limits. Additionally, it states that the information may be used to adjust the permissible off-gas vent pipe (stack) emission limits up or down to provide a high degree of assurance that general public radiation exposures are always within permissible 82
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OF SAFETY EVALUATIONS annual dose regulations. Section 3.5 of the specification states that an "instantaneous off-gas vent pipe release rate" of ten times the average permissible release rate limit may be permitted as long as the annual average is not exceeded. A safety evaluation dated June 26, 1972 Section 8.2.3, "Gaseous Radwaste System", discusses modifications to the original design of the Off-gas system to reduce the gaseous release rates. The modified system reduces the calculated average release from the common stack for the 3 units from 1.11 Ci/sec to 0.039 Ci/sec. This yields an annual average whole body dose at the maximum dose point on the site boundary from the stack to about 3.0 mRem/yr. Browns Ferry's radiation monitoring provides assurance that the licensing limits are not exceeded. Off-gas post treatment radiation High High-High alarms indicate increasing radiation downstream of the charcoal beds and upon reaching the setpoint will close FCV-66-28 to isolate flow to the stack. This alarm is one of four alarms for high radiation in the Off-gas system. The Radiological Impact Assessment provides empirical data every quarter to document individual and population doses. The data tables are for the entire plant and document dose from airborne eNuents. A sampling of these reports from 1992 to 1996 show dose levels at less than 2% of the limit required by 40CFR190. This limit is 25.0mRem for a year and is the most restricting used for the reporting of airborne eNuents at Browns Ferry. The 'iven empirical data obtained is well below the SER value of 3.0mRem/yr referenced above. Dose levels between September 27 and October 3, 1992, were taken when the in-leakage rates were documented at levels approximately 10 times higher than the original design rate. Operational data shows that gaseous release from the stack at BFN is maintained at a minimum and below regulatory limits. Therefore, the Off-gas system meets the system objective with in-leakage rates higher than the design rate of 18.5 SCFM specified in the FSAR. FSAR Section 1.6.1 6, "Radioactive Waste Systems", states that Radioactive Waste Systems are designed to control the release of plant-produced radioactive material to within the limits specified in the Offsite Dose Calculation Manual (ODCM). Also, in UFSAR Section 1.8.1, " Summary of Radiation Effects-Normal Operation" the UFSAR states that waste systems are designed so that dose to any offsite person will not exceed that permitted within the limits specified in the ODCM and applicable limits in the plant Technical Specifications. This change brings UFSAR Section 9.5 into agreement with UFSAR Sections 1.6.1.6 and 1.8.1. Current operational data shows that in-leakage is dependent on varying factors. The GE Off-gas design specification states that in-leakage varies with the performance of equipment that forms the vacuum boundary for the condenser. This varying rate does not adversely impact the system's objective to minimize the radioactive release. As stated above, the release from the plant stack is within the limits specified in the most restricting regulatory requirements. This UFSAR change documents the original design in-leakage rate given in the UFSAR as historical data. It has been shown that in-leakage rates vary without adversely impacting the functional objective of the system. Therefore, the original design in-leakage rate is not applicable to current plant operation. The values contained in the ODCM are the limiting parameters for the operation of the Off-gas system. The Off-gas system is designed to control the release of plant-produced radioactive material to within the limits specified in the ODCM. The data used in the UFSAR to derive an in-leakage rate and the conclusion for the design rate established prior to Browns Ferry operation will be maintained and documented in the UFSAR as historical information. This evaluation indicates that there are not any changes to the Technical Specifications. However, the technical content of the UFSAR is affected by this change since a specified design value is no longer applicable to support the system's intended function and objective. It is shown that the in-leakage rate specified in the UFSAR has been exceeded and operational data documents that varying rates have not adversely affected the function of the system. Although, exceeding the in-leakage rate is allowed and expected per the GE Off-Gas Design Specifications, a safety evaluation is required since a design flow rate is effectively eliminated from the SAR. No unreviewed safety question is involved. 83
Tennessee Valley Authority Brains Ferry Nuclear Plant 1997Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS UFSAR CHANGE TO SECTION C.5.3 This safety evaluation addresses a proposed change to Section C.5.3 of the BFN UFSAR. In July 1980, the NRC issued NUREG-0661 which describes the acceptable techniques for defining and evaluating suppression pool hydrodynamic loads associated with a loss-of-coolant accident (LOCA) and relief valve (RV) actuation for the Mark I containment system. The BFN Long Term Torus Integrity Program (LTTIP) performed Browns Ferry specific evaluations in accordance with the intent of NUREG-0661. Results of the BFN LTl IP evaluations and implemented modifications are documented in the BFN LTTIP Plant Unique Analysis Report (PUAR). NRC review and acceptance of the PUAR is documented. In reference to the PUAR, the UFSAR states, "There have been no significant changes in the criteria or methods described therein since the LTTIP SER was issued in May 1985." The above UFSAR statement needs to be revised due to new analyses which were performed as part of the corrective action to BFPER951719. As identified in BFPER951719, the evaluations documented in the PUAR are based on a maximum suppression pool water level elevation of 536'-6", which is lower than the allowed Technical Specification upper limit. The Technical Specification upper limit is -1" from a reference elevation of 536'-8" (Section 3.7.A.1 in References 1a through 1c). Potential instrument error requires considering an additional 2", and an additional 1" is needed for future margin. As required by the corrective action plan to BFPER951719, new analyses were performed considering a maximum analytical suppression pool water level elevation of 536'-10", which is 4" higher than the suppression pool water level elevation considered in the PUAR. The analyses and assessments of the increased suppression pool water level are documented. GE-NE-T2300733-00 assessed the impact the increased water level has on containment hydrodynamic loading (pool swell, vent thrust, condensation oscillation and chugging) by comparing analysis results based on the increased suppression pool water level with the original analysis results documented in NEDO-24580, "Mark I Containment Program Plant Unique Load Definition, Browns Ferry Nuclear Plants 1, 2, and 3", Revision 2, January 1982. To minimize the impact of the increased suppression pool water level, the GE-NE-T2300733-00 analysis utilized a computer code (LAMB)which allows for a more detailed LOCA blowdown model relative to the model used in the original analysis. This new model provides a more accurate prediction of the vessel blowdown for a wider range of subcooling conditions. NRC review and acceptance of NEDO-24580 is documented in a letter from R. Tedesco to G. Sheiwood dated February 4, 1981. However, use of the LAMB computer code and the more detailed modeling represents a change in methods with respect to those evaluated in the LTTIP SER. As a result, the UFSAR should be changed as specified below. In UFSAR Section C.5.3 the sentence: "There have been no significant changes in the criteria or methods described therein since the LTTIP SER was issued in May 1985." should be replaced with: "There have been no significant changes in the criteria or methods described therein since the LTTIP SER was issued in May 1985, except as follows: a) Analyses have been performed to account for a maximum analytical suppression pool water level elevation of 536'-10", which is 4" higher than the previously analyzed value. The new analytical water level includes consideration of potential instrument error and a margin for future use. b) Applied pool swell and vent thrust loads were generated based on a more refined Design Basis Accident blowdown analysis performed using the LAMB vessel blowdown model described in NEDO-20566 (reference 41). Structural analysis methods were not changed. c) Stresses and loads remain below the acceptance limits considered in the LTTIP SER." In UFSAR Section C.8 the following reference should be added: "41. NEDO-20566, General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10CFR50 Appendix K, January, 1976." The proposed UFSAR change is not due to a change in the actual suppression pool water level, but rather
Tennessee Valley Authority Broils Ferry Nuclear Plant 1997 Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS addresses a change in the maximum analytical water level considered in determining the'loadings resulting from a DBA LOCA. As previously discussed, the change to the UFSAR is needed because certain methods used to evaluate the maximum analytical suppression pool water level differ from the methods used prior to the I TTIP SER. The new methods consist of use of a computer code (LAMB) which allows for a more detailed vessel blowdown model. This more detailed modeling has been reviewed and accepted by the NRC. Results of the analyses of a suppression pool water level elevation of 536'-10" demonstrate that all applicable acceptance criteria have been met. The changes as described in the proposed UFSAR change are, therefore, acceptable from a nuclear safety standpoint. No unreviewed safety question is involved. UFSAR CHANGE TO SECTIONS 1.3, 5.0, 5.2 AND 7.3 This safety evaluation supports changes to UFSAR Sections 1.3. 5.0, 5.2 and 7.3. Problem Evaluation Report (PER) BFPER961536 identified errors on TVA drawings I-, 2- and 347E474 which are equivalent to 'FSAR Figure 5.2-22 sheets 1, 2 and 3. The UFSAR change addresses and resolves the items identified by the PER. FSAR Figure 5.2-22 shows the Primary Containment Isolation Valves. These valves are also found on TVA drawings 1-, 2-, and 347E474 which are being deleted from the drawing system. A review has been performed and the affected UFSAR sections were identified that require updating as a result of voiding the TVA drawings. Therefore, the tlFSAR change converts UFSAR Figure 5.2-22 sheets 1, 2, and 3 to UFSAR Table 5.2-2, sheets 1 through 8. No unreviewed safety question is involved. UFSAR CHANGE TO SECTIONS 1.6.2.12 AND 5.2.4.3 This safety evaluation supports a change to the UFSAR which involves the Residual Heat Removal (RHR) System containment spray mode of operation. Section 1.6.2.12 states that the RHR containment spray is in excess of the required primary containment energy removal capability and can be placed into service at the discretion of the operator. While this is a true statement for some accidents, it is not true for all accidents such as small steam line breaks in which the containment spray is required to be manually initiated in order to maintain the containment shell below its design temperature. Section 5.2.4.3 discusses the instrumentation that is available to the control room operators to detect the conditions indicative of the need to initiate containment spray. The section is revised to indicate that the sprays are initiated in accordance with the Emergency Operating Instructions. The wording currently implies that when the containment pressure/temperature condition is met, the sprays can be initiated immediately. In actuality, the EOls require the operators to verify that other concerns such as adequate core cooling are being met before the water can be diverted from the reactor to the containment spray function. This is required since core cooling is of greater concern than containment cooling. This UFSAR change revises the wording in these sections to be consistent with other information contained elsewhere in the BFN licensing basis. 85
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OF SAFETY EVALUATIONS The RHR containment spray mode is available to mitigate the effects of pipe breaks inside the primary containment. There is no change to the manner in which the system operates and the system will continue to operate in accordance with the assumptions in the accident analyses. Changing this section of the UFSAR will have no effect on the predicted temperature or pressure following an event and thus the equipment will continue to perform as assumed in the analyses which support the Technical Specifications. Therefore, this activity will not reduce the margin of safety as defined in the basis for any Technical Specification. No unreviewed safety question exists. UFSAR CHANGE TO SECTIONS 1.7, 3. 1, 3.2, 3.6, 3.7, 7.17, AND APPENDIX H This safety evaluation supports various UFSAR revisions resulting from a BFN UFSAR Functional Review which was performed to ensure that the UFSAR reflects the current licensing basis for the plant and that it is being maintained as a "living" document. The sections being revised are those dealing with nuclear reactor fuel and core design. The specific UFSAR revisions are as follows: Section 1.7, Comparison of Principal Design Characteristics - Revise text to clearly note that the comparative data presented in this section is historical. [Note: This section compares BFN plant design data with similar BWR plants owned by other utilities and would be impractical to keep updated. The comparative data served to show viability of the original plant design.] Section 1.7.1, Nuclear System Design Characteristics - Delete statement ... Values for the parameters of Table 1. 7-I for Unit 3 are also given in Appendix N of the FSAR. [Note: This statement is invalid since the Supplemental Reload Licensing Reports contained in Appendix N do not contain all the data included in Table 1.7-1 . Also, the reports in Appendix N contain current data which is inappropriate for Table 1.7-1 which contains historical data (as discussed in Section 1.7 text revision above).] Section 1.7.6, Discussion of Core Design Improvement - Revise text for clarification. [Note: This section provides directory type information indicating where reload fuel and core design information can be found in the FSAR. This. section provides no technical information.] Section 3.1, Summary Description - Delete segments of text stating that information contained in various sections of Chapter 3 is based on initial core 7x7 fuel. [Note: As described below, proposed revisions for sections 3.2, 3.6, and 3.7 will remove initial core 7x7 information and replace it with information based on current reload fuel designs.] Section 3.2, Fuel Mechanical Design - Replace entire section with updated rewrite. [Note: The revised section removes historical initial core 7x7 fuel information and replaces it with current reload fuel design information previously included by reference.] Section 3.6, Nuclear Design - Replace entire section with updated rewrite. [Note: The revised section removes historical initial core 7x7 fuel information and replaces it with current reload fuel design information previously included by reference.] Section 3.7, Thermal and Hydraulic Design - Replace entire section (with exception of subsection entitled "Power/Flow Operating Map") with updated rewrite. [Note: The revised section removes historical initial core 7x7 fuel information and replaces it with current reload fuel design information previously included by reference.] Section 7.17, Nuclear System Stability Analysis - Delete entire section. [Note: This section describes historical stability analyses performed for the initial core 7x7 fuel. Stability considerations for current
Tennessee Valley Authority Brogans Ferry nuclear Plant l997Annual0 eratin Re ort
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OF SAFETY EVALUATIONS Appendix H, Core Thermal Design - Delete entire appendix. [Note: This appendix contains historical information based on the initial core 7x7 fuel. Core thermal design for reload cores with current fuel designs is addressed in the revised Sections 3.6 and 3.7.j General Electric (GE) Licensing Topical Report GESTAR II and the U. S. country specific supplement are the primary sources of information for the proposed revisions to the UFSAR Chapter 3 sections. Design and licensing analyses for BFN reload fuel and reactor cores are currently performed by GE. GESTAR II contains a description of fuel mechanical design, nuclear design, and thermal/hydraulic design for current GE fuel product lines. The analyses performed by GE use Nuclear Regulatory Commission (NRC) approved methodology as described in GESTAR II and the U.S. supplement. In certain instances, the revised UFSAR sections still make reference to GE documents for specific design criteria or detailed design data due to proprietary considerations. The proposed UFSAR revisions provide clarification and remove historical information and replace it information previously included by reference. There are no physical changes to the plant and no with,'urrent changes to the design, licensing, monitoring, or operation of the fuel and reactor cores. There are also no changes to methods for fuel receipt, inspection, handling, or storage. The fuel safety and operating limits will continue to be established by reload safety analyses performed by GE using NRC approved methods and consistent with the current Technical Specifications. Therefore, these UFSAR changes will not reduce the margin of safety as defined in the bases for any Technical Specification. No unreviewed safety question is involved. UFSAR CHANGE TO SECTIONS 3.6 AND 3.7 This safety evaluation supports revisions to UFSAR Section 3.6, "Nuclear Design," and Section 3.7, "Thermal and Hydraulic Design," to address corrective actions for BFPER971205 and BFPER97122. The specific UFSAR revisions are as follows:
- 1. Revisions to UFSAR Section 3.6 (BFPER971205)
(a) The first sentence of Section 3.6.6 should contain "new" for fuel type and "abnormal" should be deleted to agree with information contained in GESTAR II. (b) Delete "normal" before dry and "abnormal" before flooded in the second sentence of Section 3.6.6 since they do not need to be shown in the sentence.
- 2. Revisions to UFSAR Section 3.7 (BFPER971222).
a) Anticipated Operational Occurrences (AOOs) in Section 3.7 should be shown as Abnormal Operational Transients (AOTs) for consistency with other sections of the SAR. b) The first sentence in Section 3.7.6.1.1 under heading 20 Percent Pump Speed Line is misleading and needs deleted. c) In the first sentence in Section 3.7.6.1.1 under heading APRM Rod Block Line delete the last five words to make it consistent with other headings. d) Section 3.7.6.1.1 needs to contain an Increased Core Flow (ICF) Region and Extended Load Line Limit Analysis (ELLLA) Region heading. e) Pump speed in the third sentence of Section 3.7.6.1.2 on page 3.7-10 is incorrect. f) Paragraph under c on page 3.7-11 in Section 3.7.6.1.2 is misleading and needs deleting. g) Figure 3.7-1 needs to label ELLLARegion on operating map. 87
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Tennessee Valley Authority BroM ns Ferry iVuc/ear Plant 1997 Annua/0 eratin Re ort
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OF SAFETY EVALUATIONS Item I (a) above revises the UFSAR text to specify that new fuel as well as spent fuel may'e placed in the spent fuel storage pool. This distinction is made since placement of fuel in the new fuel storage vaults at BFN is currently prohibited by plant procedures. It is noted that placement of-new fuel in the spent fuel storage pool is not a new practice, but is an established and acceptable practice which is being reflected in the UFSAR text. All fuel designs are required to meet specific reactivity design criteria which ensure criticality analyses for fuel storage remain valid. Item 2 (d) adds new UFSAR text to provide a description of the ICF and ELLLAregions of the power flow map. ICF and ELLLAoperation are included in the current licensing basis for the plant but are not reflected in the historical power/flow map description provided in the FSAR. Item 2.(e) changes the specified minimum recirc pump speed during stattup from 20% to 28%. This corrects UFSAR Section 3.6 to be consistent with Section 3.3 in which the same change was previously made. Therefore, this change is administrative. The remaining items are text clarifications or figure enhancements which do not change the technical content of the SAR. No unreviewed safety question is involved. UFSAR CHANGE TO SECTIONS 4.4, 11.8, AND 11.9 This safety evaluation is written in support of the following minor changes to the UFSAR. Section 4.4- Add exception to equipment clearance requirements to exclude main steam relief valve (MSRV) pilot valves. Section 11.8- Add 3-47E803-1 as a UFSAR figure due to implementation of GE zinc injection program equipment. This equipment was installed on Unit 3 only under DCN W36676A. Change the text of UFSAR Paragraph 11.8.4, Inspection and Testing, to indicate that initial testing of the condensate and feedwater pumps, and feedwater heaters consisted of a factory acceptance/hydrostatic test at 150 percent of the design pressure. Delete paragraph in Section 11.9-3 describing how to align the unitized 20" and 24" condensate storage and transfer system headers when removing one header for maintenance and repairs. This capability was removed under ECN L2124. Change specified control rod drive cooling water flow from "about 300 gpm" to "about'65 gpm per operating unit." This UFSAR information is a discrepancy with regard to the operation of the BFN units. The actual demand on the Condensate and Transfer System is about 32000 pounds per hour which is about 65 gpm. These UFSAR changes are documentation only. There is no fieldwork, plant operations, valve/system alignments, or special test associated with these changes. All assessments which involve physical changes have been addressed and reviewed under the Unreviewed Safety Question Determinations, safety assessments, and/or safety evaluations associated with the implementing documents. Two of the changes are clarification of minor UFSAR discrepancies which are not addressed by design change documentation. These changes do not reduce the margin of safety as described in the basis for any Technical Specification. No unreviewed safety question exists. 88
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OF SAFETY EVALUATIONS UFSAR CHANGE TO SECTIONS 7.1, 7.12, AND 7.18 This safety evaluation addresses the following UFSAR changes. 7.1.4.2- Recirculation Flow Control System 7.1.4.4 - Pressure Regulator and Turbine-Generator Controls 7.1.5 - Definitions The UFSAR discussions for the automatic recirculation flow control to follow the turbine speed load changes was removed. The ability to load follow was never connected to the master speed controller, based upon the as-constructed drawings and the initial design drawings from the 1970s. A typographical error on definition 7.1.5.4 is corrected by adding a space between the two words "bistable" and "devices". Section 7.12- Delete the last sentence of the fourth paragraph of Section 7.12.1.3. The main steam line radiation monitor reactor scram and MSIV PCIS closure function of the main steam line radiation monitor was removed by DCN W20206A. Section 7.12.2.5 says that each channel of the offgas radiation monitor can be calibrated by analysis of a grab sample. This cannot be done. A grab sample is taken and analyzed for comparison only. Therefore, this section is being rewritten to state "response can be checked by a known source." The process liquid radiation monitors use a scintillation detector but do not have a preamplifier as stated in Section 7.12.4.5. This section is being corrected. The inspection and testing of process liquid radiation monitors do not have any requirement for calibration in Technical Specifications. Only the calibration frequency is given. Hence, Section 7.12.6.5 is being corrected. Section 7.18.2.h is being revised to remove the word "identification" since the plant configuration does not identify which switch is tumed from its normal position. The third paragraph of Section 7.1 8.5 is being revised to add the word "transfer" to modify the switch and to remove the last sentence about identification for the above mentioned reason. These changes will not reduce the margin of safety as defined in the basis for any Technical Specification. The system operation and ability of all systems to perform their required functions are not adversely affected by these revisions. These changes are acceptable from a nuclear safety standpoint. No unreviewed safety question exists. r.M
, iggw UFSAR CHANGE TO SECTIONS 7.3 AND 7.4 89
Tennessee Valley A uthori ty Bro>vns Ferry isa/ear Plant 1997 Annual 0 eratin Re ort
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OF SAFETY EVALUATIONS This safety evaluation was written in support of UFSAR changes to Section 7.3 and Section 7.4 as follows. Section 7.3 Correct spelling of traversing incore probes. Also, the second paragraph on Page 7.3-14 incorrectly states that a lo-lo (level 2) reactor vessel level initiates a PCIS isolation for main steam lines, main steam line drains, and reactor water sample lines. A lo-lo-lo (level 1) reactor vessel level initiates a Group 1 PCIS isolation signal. The UFSAR is being revised to reflect a reactor vessel level 1 isolation signal to PCIS Group 1. In addition to minor editorial and typographical changes, the following revisions are being made. Section 7.3.4.8.1 - The first paragraph states that eight indicating-type differential pressure transmitters are used. The transmitters were replaced with transmitters which do not have local indication. The UFSAR is being revised to delete indicating-type from text. The last sentence in the first paragraph also has a lo-lo vessel level for PCIS Group 1 isolation as discussed above. This lo-lo statement is being replaced with lo-lo-lo. Section 7.3 The last paragraph states that the testable check valves are included in the PCIS since the operator can check that the valve disc can respond to reverse flow. ECN P7037 and DCN W18065 isolated the control air supply to the testable check valve actuators. Control air is reconnected to the testable check valves via flex hoses as required for testing. This paragraph is being deleted. Section 7.3 The second sentence of the last paragraph implies that control air is the emergency source for closing the MSIVs. The statement is being revised to state that control air aids the spring in the MSIV actuator to fast close the valves. Section 7.3 The second paragraph describes the operation of the actuator for the testable check valve. This description is being revised to reflect the testable check valve being isolated from the control air supply except for testing and the check valve operating due to flow in pipeline. Section 7.4 The second paragraph discusses initiation of the Automatic Depressurization System based on a coincident reactor vessel low level and high primary containment pressure. These lines are being deleted since the high drywell pressure will be bypassed by a low reactor vessel level after a time delay. Section 7.4-16, -22, -24, Table 7.4 If normal AC power is available, the four Core Spray System pumps and LPCI System pumps start one at a time, in order beginning at not 0 seconds as described but at 0.2 seconds as given in NESSDs. In Table 7.4-4, the LPCI sequence delay timer instrument numbers are being deleted since Unit 2 and Unit 3 timer identitication numbers are not the same. The trip setting/analytical limit value for LPCI pump low flow is being changed from 5800 gpm (trip setting) to 1000 gpm (as defined in Calculations). Section 7.4 The second paragraph describes the high reactor vessel level HPCI turbine trip. This paragraph is being revised to reflect Units 2 and 3 design using two differential pressure transmitters inputting into analog trip units arranged to require that both analog trip units trip (coincidence) to initiate HPCI turbine trip. Unit 1 remains the same. Section 7.4 The first sentence states that all automatic valves in HPCI are equipped with remote-manual test capability, so that the entire system can be operated locally or from the main control room. The inboard HPCI steam supply valve does not have local control since it is located inside the drywell. t This section is being revised to add this exception. Section 7.4.3.4.4- The second paragraph describes the operation of the Core Spray discharge valves and test bypass valve. This section is being revised to reflect the actual plant configuration. I Section 7.4.3.4.5 - The last sentence of the second paragraph states that locally mounted pressure gauges in the suction and discharge lines of the Core Spray pumps are used to determine suctions and pump performance. However, the local gauges in the suction line are not accurate enough to perform this 90
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Tennessee Valley Authority Browns Ferrytluc/ear Plant 1997 Annua/0 eratin Re ort
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OF SAFETY EVALUATIONS function and temporary gauges are used during surveillance for this purpose. Section 7.4 This section is being revised to clarify the thill sentence ofthe last paragraph stating that the minimum flow bypass valve for HPCI pump will open on HPCI low flow when a HPCI initiation signal is present until flow exceeds setpoint of flow switch and will close. Other changes to Section 7.4 - Clarification to second sentence in first paragraph of Section 7.4.3.2.1 to state that the HPCI turbine drives both the main and booster pumps. Revision to second paragraph of Section 7.4.3.2.1 to reflect that sensor cables also connect to instruments in the auxiliary instrument room. Revision to second paragraph of Section 7.4.3.2.1 to change the term turbine flow controller to HPCI flow controller. This term is misleading. Revision to second sentence of first paragraph of 7.4.3.2 to reflect that the HPCI turbine drives both a main and booster pump. Revision to 7.4.3.2 last paragraph of page 7.4-7 to change the term prevents outleakage to capable of preventing outleakage. Clarified the second paragraph of page 7.4-9 by adding "suppression chamber" to make the sentence read, "Two level switches monitor the suppression chamber water level." Removed the term "and cooling" from first sentence of first paragraph on page 7.4-10 since it is redundant with the pipeline filled with water. Revised the first paragraph on page 7.4-16 to clarify the sentence, "The power supply for automatic valves is the '- same as that used for the Core Spray pumps" to reflect that the power for the valves is Class 1E and feeds from the same bus structure as the core spray pumps. The second paragraph on page 7.4-18 uses the term "recall" to describe the restart of core spray pumps afler manual load shedding. This term is being revised to the term "restart". These changes to the UFSAR text will not reduce the margin of safety as defined in the basis for any Technical Specification. These changes do not involve any physical changes to the existing or change of operating logic. The changes are made to the UFSAR text and figures to plant'onfiguration reflect existing plant configuration. No unreviewed safety question is involved. Revision 1 of the safety evaluation was issued as part of the corrective action for BFPER970870. The safety assessment/safety evaluation was revised to evaluate the changes to the UFSAR as if the plant were actually configured as described in the UFSAR. Justifications have been added to the safety evaluation taking credit for implemented ECNs/DCNs and Technical Specification Amendments. UFSAR CHANGE TO SECTIONS 7.5 AND 7.19 This safety evaluation is written in support of UFSAR clarifications, enhancements, and administrative changes to Sections 7.5, Neutron Monitoring, and 7.19, Anticipated Transient Without Scram (ATWS). The changes are darifications of the wording and descriptions of the neutron monitoring.and ATWS subsystems to match the actual plant configuration. These changes include listing the correct time delay for an alternate rod injection (ARI) reset, correctly listing Reactor Protection System, and the 250VDC reactor motor-operated valve board for the ARI system. The text for the Neutron Monitoring System is being revised to correctly describe the channel locations and to clarify the UFSAR text. All of these changes to the UFSAR text reflect the as-constructed configuration of the plant, is supported by analysis, and is not in conflict with the Technical Specification nor their basis. No physical changes to any plant equipment or procedures are being made, only changes to the UFSAR text. Therefore, this activity does not reduce the margin of safety as defined in the basis for any Technical Specification. No unreviewed safety question is involved.
Tennessee Valley A uthori ty Browns Ferry Nuclear Plant 1997 Annual 0 eratin Re ort
SUMMARY
OF SAFETY EVALUATIONS UFSAR CHANGE TO SECTIONS 9.2 AND 9.3 This safety evaluation supports changes to UFSAR Sections 9.2 and 9.3. This is a document change only, no physical changes are made in the plant. The following changes are proposed: (1) Section 9.2.4.1.j - Change "sump" to "sumps" and delete the word "and" at the end of the line. (2) Section 9.2.4.1.k - Change to read "Floor drain filter and sample tank pump discharge". (3) Add Section 9.2.4.1.l - Residual Heat Removal System. (4) Section 9.2.4.2.f-Delete the word "and" at the end of the line. (5) Section 9.2.4.2.g - Change "Radwaste" to "Turbine Building". (6) Add Section 9.2.4.2.h - Turbine Building condensate pump pit floor drain pumps. (7) Section 9.2.4.3.d - Delete "waste" and the word "and" at the end of the line. (8) Add Section 9.2.4.3.f-Radwaste floor drain and waste filter decontamination drain. (9) Add Section 9.2.4.3.g - Fuel pool filters decontamination drain. (10) Section 9.2.4.4- Modify the last sentence of the first paragraph to read, "The laundry drain tanks may be cross-tied with the cask decontamination tank. Prior to plant discharge, tank; contents are recirculated through the laundry drain filter, sampled and discharged into the circulating water canal at a rate to not exceed the limits of the ODCM." (11) Page 9.2 "1" in the third line should be "1 0" and the fourth sentence of the second paragraph should read, "The minimum flow in the blowdown line is 50,000 gpm when discharging radwaste through the cooling tower biowdown line." (12) Page 9.3 Insert "cleanup" after the first word of the second paragraph and change "floor" to "equipment" in the third line of the second paragraph. (13) Section 9.3.4.2- Combine the first and second paragraphs and delete the third and fourth paragraphs. (14) Section 9.3.7- Delete the last sentence. These UFSAR text changes serve to clarify and enhance accuracy of the descriptive material in the affected UFSAR sections. Only two changes, could potentially be considered as changes to the facility, process or procedure as described in the SAR. These are discussed as follows: (1) Descriptive text about solid waste compactors is deleted. DCN W17036A removed the plant's solid waste compactors for economic reasons. BFN packs dry solid radioactive waste in suitable containers and ships them to a licensed offsite disposal facility. The compactors only provided a volume reduction capability for packaging solid waste prior to shipment. Removal of these non-safety related compactors does not affect the amount of generated solid waste nor does it impact the quantity of radioactive waste shipped offsite. This change does not alter any sampling and packaging requirements (i.e., curie content) or change any radiological limits for shipment of packaged waste. Thus, this change has no consequential effects on the radiological control and release to the environment or offsite shipment. (2) In describing the laundry drain tanks, the 85% capacity specification when a laundry drain tank is to be discharged is deleted as unnecessary detail. Discharge of the tanks'ontents is a batch process performed as necessary to support plant activities and schedule and could be performed at less than 85% tank capacity. The 85% capacity discharge value is a practical operational specification based on operating experience and is not supported by any design requirement. Furthermore, the capacity specification is not relevant to the discussion in the UFSAR which is intended only to provide a basic functional description of the laundry tanks'ischarge process. Since the tanks'ontents are sampled for radioactivity prior to discharge and a discharged at a controlled rate, deleting the 85% laundry drain tank capacity specification will not adversely affect the plant's ability to meet discharge limit requirements of the Offsite Dose Calculation Manual. None of these UFSAR changes alter any treatment, monitoring, or sampling processes in the Radwaste System. None of the changes alter any existing limits or provisions for controlling the release of radioactive materials to the environment or shipment to offsite disposal facilities. These changes serve to enhance accuracy of the descriptive material in the affected UFSAR sections, therefore, nuclear safety is not reduced. No unreviewed safety question is involved. 92
Tennessee Valley Authority Browns Ferry Nuclear Plant I997Annual0 eratin Re ort
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OF SAFETY EVALUATIONS uI=SAR CHANGES TO SECTION 7.2 This safety evaluation is in support of changes to BFN Safety Analysis Report, Section 7.2, Reactor Protection System. These changes are listed as follows. 7.2-PSH Section 7.2.3.6, Paragraph 10 states "...initiates reactor scram." This sentence will be modified to add the words "...initiates reactor scram for Unit 1 only." The next sentence states that the low vacuum scram is not applicable to Units 2 and 3 and this revision will clarify the previous sentence. 7.2-PSH Section 7.2.3.6, Paragraph 13 states "Low air header pressure-Low air pressure is a condition in..." This sentence is being revised to add the words "Low scram air header pressure-Low air. pressure on the scram air header is a condition in..." This revision is to add clarification of the type of air header. 7.2-PSH Section 7.2.3.8, Paragraph 5 states "...and the low air header pressure trip,..." This sentence is being changed to add clarification of the type of air header, "...and the low scram air header pressure trip,..." In addition, the next sentence which now states "This bypass allows the operator to reset the Reactor Protection System, so that the system is restored to operation while the operator drains the scram discharge volume" will be reworded to say "This bypass allows the operator to reset the Reactor Protection System, so that the system is restored to its normal configuration while the operator drains the scram discharge volume." 7.2-PSH Section 7.2.3.9, Paragraph b is being revised to clarify that only Units 2 and 3 have pressure transmitters for RPS input of steam pressure. The pressure switches were replaced as a part of DCN P0126. The words "On Units 2 and 3 two locally mounted,..." are being added to the second sentence. Also, the new sentence "On Unit 1 locally mounted pressure switches provide the input to the RPS logic" is being added at the end of this paragraph. 7.2-PSH Section 7.2.3.9, Paragraph c is also being revised to clarify that only Units 2 and 3 have differential pressure transmitters for RPS input of reactor low water level. The level switches were replaced as a part of DCN P0126. The words "On Units 2 and 3 reactor vessel low-water level..." are being added to the first sentence and a new sentence "On Unit 1 locally mounted level switches provide input to the RPS logic" is being added at the end of this paragraph. 7.2-PSH Section 7.2.3.9, Paragraph e is being reworded for clanfication. The third sentence states "Each pressure switch provides a signal to one or two channel of the RPS,..." and is being revised to state "Each pressure switch provides a signal to one of the two channels of the RPS,..." 7.2-PSH Section 7.2.3.9, Paragraph f is being revised to make an administrative change in the eighth sentence "...physically separated in the same way that wiring to a duplicate sensor or..." to add the word van 7.2-PSH Section 7.2.3.9, Paragraph h is being revised to clarify that only Units 2 and 3 have pressure transmitters for RPS input of containment pressure. The pressure switches were replaced as part of DCN P0126. The words "On Units 2 and 3 primary containment pressure..." are being added to the first sentence and a new sentence "On Unit 1 locally mounted pressure switches provide the input to the RPS logic" is being added at the end of this paragraph. 7.2-PSH Section 7.2.3.9, Paragraph I is being revised to reflect the installed configuration of the turbine first stage pressure transmitters. The pressure indicating switches were replaced with transmitters 93
Tennessee Valley Authority Browns Ferry Nuclear Plant i997Annual 0 eralin Re ort
SUMMARY
OF SAFETY EVALUATIONS by DCN P0126. The first sentence is revised from "Two turbine first-stage pressure indicating switches are provided..." to "Two turbine first-stage pressure transmitters are provided..." and the second sentence is revised from "The switches are arranged..." to "The transmitters are arranged..." 7.2-PSH Section 7.2.3.9.m, Paragraph I is being revised to clarify the description of the scram air header and to remove unnecessary detail describing what the scram air header pressure input to the RPS operates in conjunction with. The first sentence is revised from "Four pressure switches are provided in the control-rod4rive scram discharge air header and operate in conjunction with the scram-discharge-volume high-water-level input to the Reactor Protection System" to "Four pressure switches are provided on the control-rod-drive scram air header which provide input to the RPS logic." The second sentence is revised from "...upon loss of control air pressure" to "...upon loss of scram air header pressure." 7.2-PSH Section 7.2.4, Paragraph 16 is being revised as a clarification of the original design configuration of the RPS components inside the primary containment., The fourth sentence is being revised from "...are the condensing chambers." to "...are the condensing chambers and the inboard MSIV RPS limit switches" and the last sentence is being revised to state "...in connection with other projects, and the limit switches are environmentally qualified." 7.2-PSH Section 7.2.4, Paragraph 19 is being revised to add the location of the electronic switches which were added by DCN P0126. A new sentence is added following the third sentence which states "Electronic switches associated with RPS transmitters are located in the Control Building Auxiliary Instrument Room." In the next sentence, the word "switch" is revised to "device" for clarification. The sentence is revised from "...setting controls on each switch, a cover..." to "...setting controls on each device, a cover...". 7.2.3.9 (OPS) - Section 7.2.3.9.m, Paragraph 2 states that "Power relays for interrupting the scram pilot- .- valve solenoids are type CR105 magnetic contactors, made by the General Electric Company." This, sentence is being deleted since this much detail about the relay type and model is not required to describe the operation of the RPS instrumentation. Page 7.2.5 (OPS) - Section 7.2.3.4, Paragraph 1 states that "The remaining logic is used for a manual trip signal." A new sentence is being added following that sentence which states "The Source Range Monitoring System and Mode Switch in shutdown trip function actuate through the manual channel." The new sentence is a clarification of the manual channel original design configuration. Page 7.2-11 (OPS) - Section 7.2.3.6.9 states that "When high radiation is detected near the steam lines, a scram is initiated from the non-safety related high radiation signal to limit the fission products released from the fuel for Unit 1 only." This sentence is being revised and an additional sentence added for clarification of unit differences to state "When high radiation is detected near the steam lines, a scram is initiated from the non-safety related high radiation signal to limit the fission products released from the fuel. This scram logic is installed in Unit 1 only and has been deleted from Units 2 and 3." The high steam line radiation scram was deleted from Unit 2 by DCN W20206 and from Unit 3.by W22478. The ability of the Reactor Protection System to perform its nuclear safety function is not affected by these changes to the UFSAR. These changes are administrative or non-significant changes to add clarification or to reduce unnecessary detail. The described changes to the UFSAR will not prevent the Reactor Protection System from performing any safety related function or increase the probability of damage to any equipment, therefore, these changes are acceptable from a nuclear safety standpoint. No unreviewed safety question is involved.
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997 Annual Operating Report RELEASE
SUMMARY
1997 RELEASE
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95
1997 RELEASE
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ANNUALOPERATING REPORT GASEOUS RELEASES LIQUID RELEASES FISSIONS 8 IODINES PARTICULATES TRITIUM FISSIONS 8 TRITIUM DISSOLVED GROSS ACTIVATION >8 DAY HALF- ACTIVATION NOBLE GASES ALPHA MONTH PRODUCTS (Ci) (Ci) LIVES (Ci) (Ci) PRODUCTS (Cl) (Ci) (Ci) (Ci) JANUARY 1.32E+02 7.41E-04 5.94E-04 2.31E+00 1.69E-01 5.64E+00 1.05E-03 ND FEBRUARY 8.81E+01 3.63E-03 5.71E-04 2.66E+00 2.43E-01 5.52E+00 2.22E-03 ND MARCH 9.70E+00 2.45E-03 2.06E-04 5.03E+00 2.62E-01 8.37E+00 2.82E-03 ND APRIL 4.01E+00 1.18E-04 1.23E-04 2.65E+00 1.38E-01 2.82E+00 2.36E-04 ND MAY 1.10E+02 9.06E-05 1.10E-04 3.48E+00 1.26E-01 3.72E+00 2.61E-04 ND JUNE 1 40E+02 2.27E-04 2.07E-04 3.64E+00 1.33E-01 3.53E+00 1.21E-04 ND JULY 1.13E+02 1.01E-03 8.78E-05 4.23E+00 1.74E-01 3.52E+00 4.94E-04 ND AUGUST 2.12E+02 1.58E-03 3.91E-04 4.36E+00 2.28E-01 2.49E+00 2.38E-04 'ND SEPTEMBER 1.89E+02 1.63E-03 3.55E-04 4.12E+00 2.68E-01 2.36E+00 4.06E-04 ND OCTOBER 4.76E+02 8.40E-03 2.01E-03 3.99E+00 2.99E-01 4.74E+00 7.39E-03 ND NOVEMBER 6.10E+02 6.95E-03 2.85E-03 2.81E+00 5.29E-02 4.1 6E-01 8.56E-04 ND DECEMBER 5.05E+02 5.84E-03 1.53E-03 2.24E+00 0.00E+00 0.00E+00 0.00E+00 ND ND is for non-detectable Variation in the data for gaseous releases have been correlated with the numbers of operating fans. There were no excursion of interest nor releases which exceeded Tech Spec limits.
- "Other" has been included in these columns. The NRC Annual Effluent Report will possibly differ slightly due to evaluating "Other" and excluding or including these values.
Page 96
Tennessee Valley Authority Browns Ferry Nuclear Plant I997 Annual Operating Report OCCUPATIONAL KVPOSURZDATA 1997 OCCUPATIONAL EXPOSURE DATA
TBNNBSSEE V EY AUTHORITY RUN DAlE: 01-2748 BFH RADIATIONEXPOSURE SYSfEhf RUN TIME: 0997:16 NUMBER OF PERSONNEL AND MAN-RBMBY WORK JOB FUNCfION TOI'ALNUMBER OP INDIVIDUALS NUhlBER OF PERSONNEL @ 100 hIILLO\Ehg TOTALMAH-REhf hIO~REACfOR OPS SURVEILLANCE GROUP SfATIOH COHfRACf TOTAL STATION Vfllif Y CONTRACT EMPLOYEES AND OTHERS PERSONS EMPLOYEES EMPLOYEES AND OTHERS I. ~EHANCE PERSONNEL 71 10 . 91 172 0.951 0.299 0.761 2.011 OPERATIHO PERSONNEL 115 I 26 142 28.0&2 0269 6.886 35337 HFAL'fH PHYSICS PERSONNEL 36 8 18 62 14.606 1.372 4.215 20.193 SUPP R VI SORY PERSONNEL 42 5 6 53 5.039 0.108 0.234 59&1 ENGIHLERING PERSONNEL 48 5 18 71 3.275 0.042 0.300 3.617 MO 312 29 159 51.953 2.090 12396 66.439 MI=ROOIINMAINTENANCE GROUP Sl'ATION UfILffY COHTRACf TOTAL STATION VflLffY CONI'RACT EMPLOYEES EMPLOYEES AND QfHERS PERSONS EMPLOYEES EMI'LOYEES AHD f7fI ILRS MAINIXHANCEPERSONNEL 215 22 512 809 90.410 8944 207.073 306.427 OPERATING PERSONNEL 135 54 191 27.266 0.286 10.631 38.)83 I IIIALTIIPl I YSICS PERSONNEL 39 9 14 62 8.156 1.091 1.392 10.639 SUI'LkVISORY PERSONNEL 54 6 24 84 8.126 1.497 4.317 14.540 ENGINEERING PERSONNEL 52 10 84 146 I2.078 1.445 S&.831 72354 MO 495 49 748 1292 146.636 13.263 282.244 442.143 MO~INSERVICE INSPECTION GROUP SI'ATION TOfAL VI'ILfl'Y CONfRACr EMPLOYEES PERSONS EhfPLOYEES AND OTHERS MAIHfEHANCEPERSONNEL 87 93 0.033 0.000 2237 2,270 OPERATING PERSONNEL 0 2 0.189 0.000 0.000 0.189 IIEAL'll!PlfYSICS P1iRSONHEL 0 8 0.033 0.090 0.000 0.123 SUPERVISORY PERSONNEL 0 4 0.016 0.095 0.000 0.111 ENGINEERING PERSONNEL 6 16 0.090 0.128 0.151 0369 MO 25 93 )23 0.361 0313 3.062
TBNNESSEB VA Y AUTHORITY RUN DATE 01-2748 BFN RADIATIONEXPOSURE SYSIXM RUN TIME 0927:16 NUMBER OF PERSONNEL AND MAN.REMBY WORK JOB FUNCFION TOTALNUMBER OF INDIVIDUALS NUMBER OF PERSONNEL(>100 MILLEIEM) MO&PRCIALMAINTENANCE GROUP SfATION TOTAL STATION CONI'RACT EMPLOYEES PERSONS EMPLOYEES AND OTHERS MAINTENANCEPERSONNEL 32 131 166 0.938 0.057 8.227 9322 Ol'ERATING PERSONNEL 17 10 28 0.041 0.007 IA37 1.485 IIEALTHPIIYSICS PERSONNEL 18 2 25 1.119 OA70 OA92 2.081 SUPERVISORY PERSONNEL ll 5 17 0.468 0.296 0.123 0.8&7 ENGlNEERING PERSONNEL 4 4 10 0.076 0.393 0.802 1.271 MO 12 152 246 2.642 1.223 11.081 14946 MO~WASFE PROCESSING GROUP SFATION CONF RACI'ND TOFAL SF ATION Ul'ILITY CONI'RACT EMPLOYEES QFIIERS PERSONS EMPLOYEES EMPLOYEES AND QfI~i MAINll%ANCE PERSONNEL 39 87 130 0.591 0.007 2.664 3262 OPERA'I'ING PERSONNL'L 28 31 59 5 l19 0.000 2.209 7.S28 I IEALTH I'II YSICS PER%)NNEL 27 4 34 1.035 0.00& 0.014 1.057 SUPERVISOR Y PERSONNLL ll 2 14 0.'961 0.001 0.000 0962 ENGINEERING PERSONNEL 0 0 1 0.000 0.001 0.000 0.001 MO 105 124 238 0.017 12.810 MO~REFUEL GROUP SI'ATION UfllJf Y TOI'AL STATION UFIISI'Y CONF RA(T TOFAI. EMPLOYEES EMPLOYEES PERSONS EMPLOYEES EMPLOYEES AND OTHERS MAN-REM MAINFENANCB PERSONNEL 46 147 197 1.596 0.034 24.398 26.028 OPERATING PERSONNEL 19 31 Sl 3.14 0320 1362 5.022 IIEALTHPHYSICS PERSONNEL 9 3 15 1329 0.505 0.178 2.012 SUPERVISORY PERSONNEL ll 6 18 03SI 0.23S 0.631 1.217 ENGINEERING PERSONNEL 15 35 52 OA95 0.062 3.320 3.877 MO 222 333 6.911 1.356 29.889 3L156 1119 115 1498 2732 216.409 IR262 342.885 . 557.556
RUN DATE: 01-27-98 RUNTIME: 09.'27:16 t TENNESSEE VALLEY AUTHORITY BFN RADIATIONEXPOSURE SYSTEM NUMBER OF PERSONNEL AND MAN%EMBY WORK JOB FUNCTION TOTALNUMBER OF INDIVIDUALS NUhIBER OF PERSONNEL (>100 MILLIREhP) TOTALMAN-REM GROUP STATION UTILITY CONT RACT TOTAL STATION CONI'RACT EMPLOYEES EMPLOYEES AND OTIIERS PERSONS EMPLOYEES AND mHERS MAINTENANCEPERSONNEL 409 43 1115 1567 94519 9.341 245.360 349.220 OPERATING PERSONNEL 316 5 152 473 64.037 1.082 22.525 &7.644 HEALTHPHYSICS PERSONNEL 136 29 41 206 26.278 3.536 6.291 36.105 SUPERVISORY PERSONNEL 131 16 43 190 15361 2.232 5305 23.098 ENGINEERING PERSONNEL 127 22 147 296 16.014 2.071 63.404 81.4&9 1119 115 1498 2732 216.409 IR262 342.885 577.S56
REXPR219 TBNNESSBB VALLEY AUTHORITY RUN DATE: OI-2748 BPH RADIATIONEXPOSURE SYSIZM RUNTIME: 09 27:16 NUMBER OF PERSONNEL AND MAN%EMBY WORK JOB FUNCTION TOI'ALNUMBER OF INDIVIDUALS GROUP STATION COHmACT MAIHIEHANCEPIMONHEL 217 22 574 813 OPERATING PERSONNEL 136 I 38 17$ IIEALTHPIIYSICS PERSONNEL 39 9 15 63 SUPERVISORY PERSONNEL 60 2 24 86 ENGINEERING PERSONNEL 50 10 90 150 741 1287
Tennessee Valley Authority Bro>vns Ferry Nuclear Plant CHALLENGES TO OR FAILURES OF 1997 Annual Operating Report MAINSTEAM RELIEF VALVES 1997 CHALLENGES TO OR FAILURES OF MAINSTEAM RELIEF VALVES 102
Tennessee Valley Authori ty Browns Ferry Nuclear Plant CHALLENGES TO OR FAILURES OF 1997 Annual Operating Report k"."" "i"'"""">>"::-"; "'""'""'"::-': ".'"'" ""::4k". ~ MAINSTEAM RELIEF VALVES
""""'"""':""""""":"-""""'"'""" >""'<"""'""'"""'"'"':::::!i'""'e:: '0 UNIT I None UNIT 2 All thirteen Unit 2 MSRVs were operable during the entire reporting period. Due to setpoint drift in the Target Rock two-stage valve, the MSRVs were classified as in Maintenance Rule a(1) condition in accordance with 10 CFR 50.65 during the entire reporting period.
The discharge tailpipe temperature trends developed during the first nine months of the reporting'eriod identified two MSRVs as having pilot valve leakage. The proximity of the tailpipe thermocouples to the MSRV discharge flange coupled with the absence of adverse acoustic monitor trends provided indication that the MSRV leakage was minor and had no impact to valve operability. The pilot valves were replaced in October 1997 during the refueling outage. Plant operating data collected following completion of the refueling outage has not indicated any leakage trends associated with the MSRVs. During the reporting period, two automatic and one manual (end of cycle) reactor scrams occurred. The MSRVs experienced a significant challenge during the April 25, 1997, automatic reactor scram. During this scram, the Main Steam Isolation Valves (MSIVs) closed in response to a Group I Primary Containment Isolation System (PCIS) isolation signal. The PCIS isolation signal was initiated when a high instantaneous difFerential pressure was measured across the Main Steam Line flow elements. The differential pressure occurred when a pressure wave propagated along the Main Steam Lines. The pressure wave developed when the momentum energy of the steam converted to static pressure as the Main Steam Turbine Stop valves closed. Plant process computer data was reviewed for the event. Ten MSRV openings were confirmed with five reactor pressure instruments indicating a maximum reactor dome pressure of 1109 to 1112 psig. The three "unopened" MSRVs were all located on Main Steam Line A. At the time of the scram, Main Steam Line A was carrying the lowest indicated steam fiow of the four lines. Additionally, the nominal setpoints for the three "unopened" MSRVs were one at 1115 psig and two at 1125 psig. It is believed that the actual setpoint pressures for the three "unopened" MSRVs were not exceeded in Main Steam Line A due to the low steam flow rate and the measured maximum reactor dome pressure. One of the three "unopened" MSRVs was used for manual reactor vessel pressure control for approximately 20 minutes until the Group I Isolation was reset and the MSIVs were reopened. 103
Tennessee Valley Authority Bro>vns Ferry Nuclear Plant CHALLENGES TO OR FAILURES OF 1997 Annual Operating Report MAIiVSTEAM RELIEF VALVES The second automatic scram occurred in October 1997 prior to reaching full operating power following a refueling outage. Plant process computer data was again reviewed. Peak reactor dome pressure was significantly below the lowest MSRV setpoint of 1105 psig. During the operating cycle, the manual valve cycle test (2-SI-4.6.D.2) was completed as required by Technical Specification 3.6.D. The performance was conducted successfully as part of the power ascension test following completion of the refueling outage. UNIT 3 All thirteen Unit 3 MSRVs were operable during the entire reporting period. Due to setpoint drift in the Target Rock two-stage valve, the MSRVs were classified as in Maintenance Rule a(1) condition in accordance with 10 CFR 50.65 during the entire reporting period. Plant operating data collected during the first two months of the reporting period did not reflect any adverse MSRV discharge tailpipe temperatures trends.. The pilot valves were replaced during the refueling outage in March 1997. Subsequent MSRV discharge tailpipe temperature trends have identified two MSRVs with minor pilot valve leakage and one MSRV with an apparent combination of main and pilot valve leakage. All leakage rates appear minor and no threat to valve operability. This conclusion was reached due to the absence of.a significant increase in Suppression Pool bulk temperature and stable acoustic monitor trends. The proximity of the tailpipe thermocouples to the MSRV discharge flange tends to magnify minor leaks. As a leak rate increases, the measured tailpipe temperature will increase to an adiabatic temperature plateau. At the plateau, a stable temperature trend will develop. The stable trend will exist until the leak rate increases to a point where pressurization of the MSRV discharge tailpipe occurs. The strongest MSRV discharge tailpipe temperature trend is currently increasing at rate of about 0.3'F per day. Based upon this rate of growth and the expected adiabatic temperature plateau, adequate margin exists to support continued operation until the scheduled refueling outage. During the reporting period, one manual (end of cycle) reactor scram occurred. The manual cycle test of the MSRVs (3-SI-4.6.D.2) was conducted once as required by Technical Specification 3.6.D during the reporting period. The performance was conducted successfully as part of the power ascension test following completion of the refueling outage. No other challenges to the MSRVs were encountered. 104
Tennessee Valley Authority Browns Ferry Nuclear Plant 1997Annual Operating Report REACTOR VESSEL FATIGUE USAGEEVALUAT101V 1997 REACTOR VESSEL FATIGUE USAGE EVALUATION 105
Tennessee Valley Authority BroN ns Ferry Nuclear Plant l997Annual Operating Report REACTOR VESSEL FATIGUE USAGEEVALUATIOiV The cumulative usage factors for the reactor vessels are as follows: Location Unit 1 Unit 2 Unit 3 Shell at water line 0.00620 0.00608 0.00461 Feedwater nozzles 0.29782 0.50148 0.31134 Closure studs 0.24204 0.25209 0.17029 106
Tennessee Valley Authority Brogans Ferry Nuclear Plant
SUMMARY
OF EVALUATIONSFOR 1997 Annual Operating Report COMMITMENTREVISIO1VS 1997
SUMMARY
OF EVALUATIONSFOR COMMITMENTREVISIONS 107
REVISED COMMITMENT: RC 97-001 COMMITMENTTRACKING NO: NC0960053001 EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTFOR AN LER (296/96004) SUPPLEMENTAL REPORT. COMMITMENT:'XISTING TVA EXPECTS TO SUBMIT A SUPPLEMENTAL REPORT BY FEBRUARY 5, 1997. REVISED COMMITMENT: TVA EXPECTS TO SUBMIT A SUPPLEMENTAL REPORT BY APRIL 30, 1997. JUSTIFICATION THIS COMMITMENTMUST BE REVISED TO ENSURE THATA CORRECT ROOT CAUSE IS ESTABLISHED AND CORRECTIVE ACTIONS ARE IDENTIFIED TO PRECLUDE RECURRENCE BEFO+ A SUPPLEMENTAL LER IS SUBMITTED. AT THE TIME OF THE COMMITMENT,TVA BELIEVED THAT ADEQUATE TIME WAS ALLOCATEDTO IDENTIFYTHE ROOT CAUSE, REQUIRED CORRECTIVE ACTIONS, AND TIME TO PROCESS THE SUPPLEMENTAL LE% HOWEVER, THE ALLOCATEDTIME WAS NOT ADEQUATE BECAUSE A FOURTH SIMILARTYPE OF EVENT OCCURRED. THE INITIALCOMMITMENT'SSUPPLEMENTAL REPORT DATE WAS SUBSEQUENTLY CHANGED TO NOVEMBER 20, 1996. AFTER ANOTHER SIMILAR EVENT OCCURRED ON NOVEMBER 6, 1996, THE REVISED SUPPLEMENTAL REPORT DATE WAS AGAIN CHANGED TO DECEMBER 20, 1996 WHEN A FOURTH SIMILAREVENT OCCURRED ON DECEMBER 17, 1996. THEREFORE, THE REPORT DATE WAS CHANGED TO FEBRUARY 5, 1997. TVA HAS SENT SYSTEM COMPONENTS TO AN INDEPENDENT CONTRACTOR AND THE VENDOR FOR FAILURE ANALYSISAND IS MONITORING THE CIRCUITRY FOR PERTURBATIONS. CONSEQUENTLY7 THE DATE NEEDED TO BE MOVED TO APRIL 30, 1997. ADDITIONALLYNUREG
- 1022 STATES THAT NRC CONSIDERS A SUPPLEMENTAL REPORT DATE AS AN EXPECTED DATE IS NOT A COMMITMENTDATE.
NEVERTHELESS, TVA AGGRESSIVELY COMMITTED TO A SUPPLEMENTAL REPORT OF OCTOBER 30, 1996, NOVEMBER 20, 1996, AND DECEMBER 20, 1996. THESE DATES COULD NOT BE MET BECAUSE MORE TIME WAS NEEDED TO DETERMINE THE ROOT CAUSE(S) AND CORRECTIVE ACTIONS FOR THE LER. REVISED COMMITMENT: RC 97-002 COMMITMENTTRACKING NO: NCO910113004 108
EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTAS A RESULT OF A BREACH OF PRIMARY CONTAINMENT.THIS COMMITMENTREQUIRED TRAININGMAINTENANCEFOREMEN FOR ASSESSING JOB PERFORMANCE WHEN THE FOREMEN PERFORM SUPERVISORY ROLES. EXISTING COMMITMENT: TVA WILLDEVELOP A SCREENING AND EVALUATIONPROGRAM TO ASSESS THE JOB PERFORMANCE OF MAINTENANCEFOREMEN. THE PROGRAM WILLINCLUDE SCREENING AND EVALUATIONOF BOTH CURRENT FOREMEN AND FUTURE SELECTION CANDIDATES TO ENSURE THEY POSSESS ADEQUATE SKILLS TO PERFORM THEIR SUPERVISORY ROLES. A SIMILAR PROGRAM HAS BEEN SUCCESSFULLY IMPLEMENTED AT THE PEACH BOTTOM PLANT. ( TVAWILLREVIEW THE PEACH BOTTOM PROGRAM AND CONSIDER ITS KEY ELEMENTS FOR INCORPORATION INTO THE TVAPROGRAM. ADDITIONALLY,TVAIS DEVELOPING A CONTINUINGSUPERVISORY TRAININGPROGRAM WHICH ALLFOREMEN WILLATTEND. THIS TRAININGPROGRAM CONSISTS OF 80 HOURS OF INITIALTRAININGAND 40 HOURS OF CONTINUING TRAINING. THESE PROGRAM IMPROVEMENTS WILLBE IN PLACE BY SEPTEMBER 1, 1991. REVISED COMMITMENT: DELETE THE COMMITMENTBECAUSE THE ORIGINAL COMMITMENTWAS MET AND IS NO LONGER APPROPRIATE. JUSTIFICATION THE INTENT OF THE REQUIREMENT FOR THE 80 HOURS OF INITIALTRAININGAND 40 CONTINUING HOURS WAS TO INSTILLOPERATING PLANT KNOWLEDGE AND SENSITIVITYIN PERSONNEL WHO HAD LIMITEDOPERATING PLANT EXPERIENCE. SINCE MEETING THIS COMMITMENT,BROWNS FERRY HAS DEVELOPED AND IMPLEMENTED THE ACCREDITED TRAINING PROGRAM, DERIVED FROM THE SYSTEMATIC. APPROACH TO THE TINNINGPROCESS FOR MAINTENANCESUPERVISORS PER 10 CFR 50.120. IN ADDITION,THE WORKFORCE HAS STABILIZED AND GAINED DUALUNIT OPERATING EXPERIENCE SINCE THE COMMITMENTWAS MADE. THESE CHANGES ARE CONSIDERED TO BE EFFECTIVE IN PREVENTING RECURRENCE OF THE EVENT. THE COMMITMENTIS, THEREFORE, NO LONGER APPROPRIATE. REVISED COMMITMENT: RC 97-003 COMMITMENTTRACKING NO: N/A 109
THIS ISSUE ADDRESSES A COMMITMENTMADE IN A REPLY TO INSPECTION REPORT 84-40 FOR A LACKOF A NDE IIIREVIEW. EXISTING COMMITMENT: REVISE SI<.7.A.2.g-3 TO INCLUDE HOW A NDE LEVEL IIIUSES REFERENCE LEAKRATES AND WHATACTION IS TAKEN TO PREVENT La FROM BEING EXCEEDED. REVISED COMMITMENT: DELETE THE NDE IIIREQUIREMENT FOR REVIEW OF LEAKRATE DATAEXCEEDING REFERENCE LEAKRATES. JUSTIFICATION UNITS 2 AND 3-SI<.7.A.2g-4a AND SI-4.7.A.2g-4b MAINTAINTHE CURRENT TOTAL LEAKRATE FOR THE APPLICATION UNIT. SATISFACTORY COMPLETION OF THE APPLICABLE PROCEDURE ENSURES La IS NOT EXCEEDED. THEREFORE, SPECIFIC NDE IIIREVIEW IS NO LONGER NECESSARY. REVISED COMMITMENT: t RC 97-004 COMMITMENTTRACKINGNO: NCO870212002 EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTMADE IN A RESPONSE TO IE BULLETIN86 STATIC "0" RING DIFFERENTIALPRESSURE SWITCHES. II EXISTING COMMITMENT: REVISE RHR PUMP FLOW RATE TEST TO INCLUDE STEPS TO VERIFY RHR MINIMUMFLOW SWITCH OPERABILITY. REVISED COMMITMENT: DELETE THE COMMITMENTFOR UNITS 1, 2, AND 3. JUSTIFICATION PERFORMANCES OF INSTALLEDSTATIC "0" RING DIFFERENTIALPRESSURE SWITCHES ON UNIT 2 HAVE SHOWN MINIMALDRIFT AND COMMITMENTNCO870212009 WAS DELETED FOR UNITS 1 AND 3 BASED UPON THIS PERFORMANCE DATA. THE ABOVE STEPS ADDED TO'THE TEST WOULD BE CONSIDERED A SHORT TERM ACTION UNTILA MORE PERMANENT FIX WAS MADE. THEREFORE, CONTINUING TO CARRY THE STEPS IN THE PROCEDURES AS N RC COMMITMENTS IS NO LONGER REQUIRED. REVISED COMMITMENT: RC 97-005 COMMITMENTTRACKINGNO: ~ NCO830178001 EXISTING CONDITION:
~ THIS ISSUE ADDRESSES A COMMITMENTMADE IN INSPECTION REPORT (83-18) FOR THE MOVEMENT OF FUEL.
110
TI-.14 WAS REVISED TO INCLUDE MAPS FOR EACH POOL SHOWING THE "TESTED" AND "UNTESTED" STATUS OF EACH HDSFR, AND TO REQUIRE NUCLEAR ENGINEER TO USE THE MAPS FOR PREPARATION OF FUEL ASSEMBLY TRANSFER FORMS. A SECOND-PARTY VERIFICATIONSTEP HAS BEEN ADDED TO THE FUEL ASSEMBLY TRANSFER PACKAGE TO TECHNICALLYVERIFY THE SEQUENCE OF FUEL MOVES. REVISED COMMITMENT: DELETE THE COMMITMENTBECAUSE THE ORIGINAL COMMITMENTWAS MET AND IS NO LONGER APPROPRIATE. JUSTIFICATION THE INTENT OF THE REQUIREMENT PLACING THE STATUS OF THE HIGH DENSITY SPENT FUEL r STORAGE RACKS IN THE SPECIAL NUCLEAR MATERIALCONTROL PROCEDURES WAS TO ENSURE THAT FUEL WAS NOT PLACED INTO RACKS IN WHICH BORON HAD NOT YET BEEN VERIFIED TO BE PRESENT. ALLOF THE INSTALLEDRACKS AT BROWNS FERRY HAVE BEEN TESTED. A REQUIREMENT STILL EXISTS TO ENSURE THAT "FUEL ASSEMBLY TRANSFER FORMS DESCRIBE MOVES WHICH ARE PHYSICALLYPOSSIBLE AND ADMINISTRATIVELY ACCEPTABLE" WHICH WILLPROVIDE REASONABLE ASSURANCE THAT FUEL WILLNOT BE PLACED IN UNACCEPTABLE LOCATIONS. THESE CHANGES ARE CONSIDERED TO BE EFFECTIVE IN PREVENTING RECURRENCE OF THE EVENT. THE COMMITMENTIS, THEREFORE, NO LONGER APPROPRIATE. REVISED COMMITMENT: RC 97-006 COMMITMENTTRACKINGNO: NCO830178002 EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTMADE IN INSPECTION REPORT (83-18) FOR THE MOVEMENT OF FUEL. EXISTING COMMITMENT: TI-14 WILLBE REVISED TO REQUIRE THAT A FIELD CHANGE REQUEST INVOLVINGFUEL MOVEMENTBE MADE ON A SEPARATE FIELD
,CHANGE SHEET.
REVISED COMMITMENT: DELETE THE COMMITMENTBECAUSE THE ORIGINAL COMMITMENTWAS MET AND IS NO LONGER APPROPRIATE. JUSTIFICATION THE INTENT OF THE REQUIREMENT TO MAKE CHANGES AN A SEPARATE FIELD CHANGE SHEET WAS TO INSTILLSENSITIVITYIN PERSONNEL OF THE IMPORTANCE OF CONTROLLING SPECIAL 111
NUCLEAR MATERIALIN PERSONNEL WHO DID NOT RECOGNIZE THE NEED FOR SUCH CONTROI SINCE MEETING THIS COMMITMENT,BROWNS FERRY HAS IMPLEMENTEDAND MAINTAINED THOROUGH CONTROLS ON ALLSPECIAL NUCLEAR MATERIAI IN ADDITION,THE WORK FORCE HAS STABILIZEDAND GAINED EXPERIENCE IN EFFECTIVELY CONTROLL'ING SPECIAL NUCLEAR MATERIALSINCE THE COMMITMENTWAS MADE. RATHER THAN MAKINGCHANGES ON A SEPARATE FIELD CHANGE SHEET, CHANGES WILLNOW BE MADE ON THE SAME TYPE OF FORM USED FOR NORMAL, TRANSFERS. THESE CHANGES ARE CONSIDERED TO BE EFFECTIVE IN PREVENTING RECURRENCE OF THE FUEL MOVEMENTERROR DUE TO OPERATOR INATTENTIONTO DETAII THE COMMITMENTIS, THEREFORE, NO LONGER APPROPRIATE. REVISED COMMITMENT: RC 97-007 COMMITMENTTRACKINGNO: N/A EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTMADE IN A TVA REPLY TO GENERIC LETTER 89-13 (SERVICE WATER SYSTEM PROBLEMS), EXISTING COMMITMENT: INSPECT AND CLEAN THE COOLING WATER SIDE OF THE CONTROL BAY CHILLERS ANNUALLY. REVISED COMMITMENT: INSPECT AND CLEAN THE COOLING WATER SIDE OF THE CONTROI BAY CHILLERS PERIODICALLY. JUSTIFICATION: NRC GENERIC LETTER 89-13, RECOMMENDED ACTION II, REQUIRED UTILITIES TO INITIATEA PROGRAM TO PERIODICALLYTEST HEAT EXCHANGERS TO VERIFY THEY ARE CAPABLE OF PERFORMING THEIR INTENDED FUNCTION. IN LIEU OF A TEST PROGRAM, THE GL ALSO OFFERED LICENSEES THE OPPORTUNITY TO PROVIDE AN EQUALLYEFFECTIVE PROGRAM TO ENSURE THE HEAT REMOVALREQUIREMENTS OF HEAT EXCHANGERS WOULD BE SATISFIED. IN TVA'S RESPONSE TO RECOMMENDED ACTION II, TVA PROVIDED THE NRC WITH A
SUMMARY
OF THE THEN-CURRENT TESTING AND CLEANING PROGRAM FOR HEAT EXCHANGERS COVERED BY THE GL, AND COMMITTEDTO REVISE THIS PROGRAM (BY INCLUDINGOTHER SPECIFIED CHILLERS) AND ADD THE PROGRAM TO THE PREVENTIVE MAINTENANCE(PM) PROGRAM. TVA STATED THAT THIS REVISED TESTING AND CLEANING PROGRAM WOULD BE EQUALLY EFFECTIVE ALTERNATIVETO THE NRC 112
RECOMMENDED TESTING PROGRAM. INCLUDED IN THIS
SUMMARY
WAS THE PROGRAM FOR INSPECTION AND CLEANING OF THE CONTROL BAY CHILLERS, WHICH STATED THAT THE COOLING WATER SIDE OF THESE CHILLERS WAS INSPECTED AND CLEANED ANNUALLY.WHILE TVA COMMITTED TO REVISE THE EXISTING HEAT EXCHANGER TESTING AND CLEANING PROGRAM AND ADD TO THIS PROGRAM TO THE PM PROGRAM, TVA NEVER SPECIFICALLY COMMITTED TO ANY OF THE SPECIFIC INSPECTION FREQUENCIES. SINCE THIS RESPONSE WAS SUBMITTED, TVA HAS BEEN PERFORMING THE CHILLER INSPECTIONS AND CLEANINGS AT THE SPECIFIED FREQUENCY IN ACCORDANCE WITH THE PM PROGRAM. ADDITIONALLY,THE EECW CHEMICAL TREATMENTPROGRAM WAS PUT INTO SERVICE IN NOVEMBER 1994 AND HAS OPERATED CONTINUOUSLY SINCE FEBRUARY 1995 (EECW COOLS THESE HEAT EXCHANGERS) THIS CHEMICALTREATMENTPROGRAM HAS BEEN VERY EFFECTIVE IN CONTROLLING MICRO- AND MACROBIOLOGICALFOULING AND KEEPING THE SYSTEM FLOW PATH UNOBSTRUCTED. INSPECTIONS PERFORMED ON THE 3A CONTROL ~ BAY CHILLER IN APRIL 1997 REVEALED THAT THE HEAT TRANSFER SURFACES WERE IN VERY GOOD CONDITION. BASED ON THE PREVIOUS INSPECTION RESULTS AND THE CHEMICALTREATMENTPROGRAM, TVA INTENDS TO MODIFYTHE PM PROGRAM TO DECREASE THE FREQUENCY OF THE CHILLER CLEANINGS/INSPECTIONS g.E., LONGER INTERVALS BETWEEN CLEANINGS/INSPECTIONS). ALTHOUGH TVA CONSIDERS THAT THE SPECIFIC CLEANING/INSPECTION FREQUENCY WAS NOT A COMMITMENTTO NRC, THIS EVALUATIONIS BEING PERFORMED TO DOCUMENT THE BASIS FOR REVISING THE CLEANING/INSPECTION FREQUENCY. REVISING THIS "COMMITMENT" WILLALLOWTHE PM PROGRAM TO DETERMINE THE APPROPRIATE FREQUENCY FOR CLEANING/INSPECTION OF THESE CHILLERS, AND ALLOWCHANGES TO THAT FREQUENCY BASED ON SYSTEM PERFORMANCE. REVISED COMMITMENT: RC 97-008 COMMITMENTTRACKING NO: NC0850911002 EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTMADE IN A TVA REPLY TO INSPECTION REPORT 84-26. 113
A GENERAL REVISION WAS MADE TO SI 4.5.C TO IMPROVE THE OVERALLCLARITYOF THE INSTRUCTION. REVISED COMMITMENT: DELETE THE COMMITMENT. JUSTIFICATION: AN NRC INSPECTION WAS PERFORMED IN 1984 AND REVEALED THAT SURVEILLANCE REQUIREMENTS WERE NOT BEING FOLLOWED, A NOV WAS ISSUED AND THIS COMMITMENTWAS MADE. THE VIOLATIONWAS A RESULT OF NOT FOLLOWING TECHNICALSPECIFICATION 4.5.C.4 AND THE COMMITMENTWAS TO REVISE THE SI TO CORRECT THIS PROBLEM. THE TECHNICAL SPECIFICATION WAS CHANGED BY AMENDMENT 0169 FOR UNIT 2 AND SECTION 4.5.C.4 WAS DELETED. THEREFORE, THE COMMITMENTIS NO LONGER NEEDED. REVISED COMMITMENT: RC 97-009 COMMITMENTTRACKING NO: NC0970027005 EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTMADE IN A TVA REPLY TO GENERIC LETTER 96 PERIODIC VERIFICATIONOF DESIGN-BASIS CAPABILITYOF SAFETY-RELATED MOTOR-OPERATED VALVES EXISTING COMMITMENT: TO PARTICIPATE IN THE JOINT OWNERS GROUP (JOG) PERIODIC VERIFICATION(PV) PROGRAM AND IMPLEMENTTESTING DURING THE U2C9 OUTAGE. REVISED COMMITMENT: TO PARTICIPATE IN THE JOG PV PROGRAM AND IMPLEMENTTESTING DURING THE U2C10 OUTAGE. JUSTIFICATION: THIS ACTIVITYCANNOT BE MET BECAUSE ADDITIONALTEST CONNECTIONS ARE REQUIRED FOR DATAACQUISITION. THESE CONNECTIONS COULD NOT BE INSTALLED IN THE U2C9 OUTAGE. THEREFORE, THE COMMITMENTHAS BEEN EXTENDED TO THE U2C10 OUTAGE. REVISED COMMITMENT: RC 97-010 COMMITMENTTRACKING NO: NC0960002004 THIS ISSUE ADDRESSES A COMMITMENTMADE IN A TVA LETTER DEALINGWITH A COST BENEFICIALLICENSING ACTION (08), DATED DECEMBER 22, 1995. 114
EXISTING COMMITMENT: DETAILS REGARDING THE METHOD FOR CONTROLLING SUPPRESSION POOL pH AFTER A DESIGN BASIS ACCIDENT WILLBE PROVIDED BY JULY 31, 1997. REVISED COMMITMENT: DETAILS REGARDING THE METHOD FOR CONTROLLING SUPPRESSION POOL pH AFTER A DESIGN BASIS ACCIDENT WILLBE PROVIDED BY SEPTEMBER 30, 1999. JUSTIFICATION: THE ORIGINALCOMPLETION DATE WAS BASED ON A TARGETED NRC APPROVAL DATE THAT SUPPORTED THE UNIT 2 CYCLE 8 OUTAGE'HICH BEGAN ON MARCH 22, 1996. NRC SUBSEQUENTLY INFORMED TVA THAT THIS MILESTONE WOULD NOT BE MET. CURRENTPLANS ARE TO COMPLETE THIS WORK DURING FISCAL YEAR 1999 AND TO SUBMIT THE RESULTS TO NRC AT THE END OF THAT FISCAL YEAR REVISED COMMITMENT: RC 97-011 COMMITMENTTRACKING NO: NC0970061001 EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTMADE IN A TVA UNIT 3 LETTER DEALING,WITH ASME SECTION XI INSERVICE INSPECTION AND REPAIR AND REPLACEMENTS FOR CYCLE 7 OPERATION-
SUMMARY
REPORTS, DATED JUNE 10, 1997. EXISTING COMMITMENT: TVA WILLSUBMIT A REQUEST FOR RELIEF BY AUGUST 15, 1997, FOR BFN UNIT 3 TO ADDRESS THE REDUCED NONDESTRUCTIVE EXAMINATION COVERAGE FOR THE ASME, SECTION XI, INSERVICE INSPECTION, REACTOR PRESSURE VESSEL (RPV) HEAD NOZZLE (N6A) WELD. REVISED COMMITMENT: TVA WILLSUBMITA REVISED NIS-1 FORM TO NRC BY SEPTEMBER 15, 1997, INDICATINGTHAT THE NON-DESTRUCTIVE EXAMINATION(NDE) COVERAGE FOR THE ASME, SECTION XI, INSERVICE INSPECTION REACTOR PRESSURE VESSEL (RPV) HEAD NOZZLE (N6A) WELD MET THE ASME CODE REQUIREMENTS. JUSTIFICATION: THE NONDESTRUCTIVE EXAMINATION COVERAGE WAS CALCULATEDUSING OVERLY CONSERVATIVE METHODOLOGIES. THE CODE REQUIRED NDE COVERAGE CAN BE ACHIEVED USING OTHER COVERAGE CALCULATION PROVISIONS ALLOWED BY THE CODE. REVISED COMMITMENT: RC 97-012 COMMITMENTTRACKING NO: N/A 115
THIS ISSUE ADDRESSES A STATEMENT OF FACT IN THE CORRECTIVE ACTION SECTION OF LER 50-260/89006 R1, DATED JULY 13, 1989. EXISTING COMMITMENT: THE SCAFFOLD CONSTRUCTION PROCEDURE WAS REVISED TO REQUIRE THAT THE POST ERECTION INSPECTION INCLUDEA SURVEY OF PLANT EQUIPMENT IN THE AREA FOR EQUIPMENT WHICH COULD BE INAPPROPRIATELY USED AS HANDHOLDS OR FOOTHOLDS AND TEMPORARILY MARKTHAT EQUIPMENT WITH A WARNING SIGN OR WARNING TAPE. REVISED COMMITMENT: REMOVE COMMITMENTFROM THE PROCEDURE AND THE NRC COMMITMENTDOCKET. JUSTIFICATION: THIS COMMITMENTWAS WRITTEN WHEN THERE WERE NUMEROUS CONTRACTORS ON SITE PRIOR TO THE UNIT 2 RESTART. OUR GENERAL EMPLOYEE TRAININGAND PREJOB BRIEFINGS COVER THIS ISSUE. IF A PERSON USES AN INAPPROPRIATE PIECE OF EQUIPMENT OR OTHER FEATURE FOR A HANDHOLD OR FOOTHOLD, THERE WILLBE A PROBLEM EVALUATIONREPORT (PER) WRITTEN AND DISCIPLINARYACTION TAKEN AGAINST THAT PERSON. THE PROCEDURE IS NOT THE APPROPRIATE FORMAT TO ENSURE THAT PLANT PERSONNEL DO NOT USE EQUIPMENT FOR HANDHOLDS OR FOOTHOLDS. THEREFORE, THE COMMITMENTSHOULD BE REMOVED FROM THE SCAFFOLD ERECTION PROCEDURE, REVISED COMMITMENT: RC 97-013 COMMITMENTTRACKING NO: NCO8802601001 EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTIN A URI REPLY TO INSPECTION REPORT 88-21. NORMALLY,URls DO NOT REQUIRE A REPLY. HOWEVER, WITH THIS URI (88-21-01), A REPLY WAS DOCKETED. EXISTING COMMITMENT: REVISE RCI-17 TO ADDRESS ASSIGNMENT OF HIGH RADIATIONAREA KEYS AND ACCESS NOTIFICATION. REVISED COMMITMENT: RCI-17, SECTION 3.3.1 WILLBE REVISED TO SUBSTITUTE THE CONTROL ROOM UNIT SUPERVISOR FOR THE SOS (NOW SHIFT MANAGER OR SM) AS THE APPROVAL AUTHORITYFOR ENTRY IN LOCKED HIGH RADIATIONAREAS.
THE TECHNICALSPECIFICATION REQUIREMENTS REGARDING KEY CONTROL AND, IMPLICITLY, ACESS AUTHORITYHAVE BEEN REVISED SINCE THE IMPLEMENTATIONOF THE COMMITMENT REQUIREMENT IN RCI-17. THE TS SECTION 6.8.3.2 (JUNE 30, 1988) STATED, IN PART, "THE KEY(S) SHALL BE UNDER THE ADMINISTRATIVE CONTROL OF THE SHIFT ENGINEER". THIS STATEMENT CONCERNING KEY CONTROL IN TS 6.8.3.2 WAS REVISED IN TS CHANGE 335 (DECEMBER 2, 1993) AND WAS PRIMARILYBASED UPON THE REGULATORY POSITION CONTAINED IN REGULATORY GUIDE 8.38 (JUNE 1993). THE STATEMENT CURRENTLY READS "THE KEYS SHALL BE UNDER THE ADMINISTRATIVE CONTROL OF THE DUTY SHIFT OPERATIONS SUPERVISOR, RADIOLOGICALCONTROL MANAGER, OR THEIR RESPECTIVE DESIGNEES". ACCESS NOTIFICATIONIS NOT PARTICULARLY ADDRESED IN EITHER VERSION OF THE TECHNICALSPECIFICATIONS. THE REVISED TS WORDING PERMITS KEY CONTROL TO BE DELEGATED TO INDIVIDUAL(S) DESIGNATED BY THE SOS. KEY CONTROL IS INHERENTLYCONNECTED TO ACCESS. IT WOULD LOGICALLYFOLLOW THAT ACCESS AUTHORITY COULD BE DELEGATED TO DESIGNATED INDIVIDUALS. THE CONTROL ROOM UNIT SUPERVISOR (A SENIOR REACTOR OPERATOR) SERVES AS THE SHIFT MANAGERDESIGNEE FOR THE ASSIGNED REACTOR UNIT(S). CONSEQUENTLY, THE CONTROL ROOM UNIT SUPERVISOR(S) HAVE THE RESPONSIBILITY FOR LHRAACCESS AUTHORITY. REVISED COMMITMENT: RC 97-014 COMMITMENTTRACKING NO: NC0870330006 EXISTING CONDITION: THIS ISSUE ADDRESSES A COMMITMENTFOR A DEVIATIONMADE IN A LETTER DATED MARCH 1, 1988, WHICH STATED THAT FSAR CHANGES WOULD BE UPDATED ANNUALLY. EXISTING COMMITMENT: THE CHAPTER 2 UPDATE PROCESS WILLBE I INCORPORATED INTO SITE DIRECTOR STANDARD PRACTICE 15.7 BY MAY15, 1988. THIS PROCEDURE WILL BE USED FOR THE 1989 FSAR UPDATE. 117
0 THE CHAPTER 2 UPDATE PROCESS WILLBE INCORPORATED INTO THE SITE PROCEDURE THAT CONTROLS FSAR MANAGEMENT. THIS PROCEDURE WILLBE USED FOR FSAR UPDATES IN ACCORDANCE WITH 10 CFR 50.71(e). JUSTIFICATION: THE CURRENT COMMITMENTREQUIRES AN ANNUAL REVIEW OF THE FSAR, CHAPTER 2, TO IDENTIFY SIGNIFICANT LAND USAGE CHANGES (I.E, MAJOR INDUSTRIAL,INSTITUTIONAL,MILITARYFACILITIES) AND HAZARDOUS MATERIALSPASSING OR LOCATED WITHINA 2-MILE RADIUS OF THE PLANT. SIGNIFICANT LAND USAGE CHANGES MUST BE INCORPORATED INTO THE ANNUALFSAR UPDATE SUBMITTAL 10 CFR 50.71(e), 1997, EDITION STATES THAT SUBSEQUENT REVISIONS TO THE FSAR MUST BE FILED ANNUALLYOR 6 MONTHS AFTER EACH REFUELING OUTAGE PROVIDED THE INTERVALBETWEEN SUCCESSIVE UPDATES DOES NOT EXCEED 24 MONTHS. THE REVISED COMMITMENT ALIGNS BFN'S PROCESS FOR UPDATING THE FSAR, CHAPTER 2, WITH THE REQUIREMENTS OF 10 CFR 50.71(e) AND BFN'S CURRENT FSAR UPDATING INTERVAI
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