ML18283A910

Appendix a to Facility Operating Licenses DPR-33, Technical Specification & Bases for Browns Ferry Nuclear Plant Unit 1, Limestone County Alabama, Tennessee Valley Authority, Docket No. 50-259

ML18283A910
Person / Time
Site:	Browns Ferry
Issue date:	03/11/1977
From:	Tennessee Valley Authority
To:	Office of Nuclear Reactor Regulation
References
Download: ML18283A910 (413)

Text

APPENDIX A TO FACILITY OPERATING LICENSE DPR-33 TECHNICAL SPECIFICATION AND BASES FOR BROWNS FERRY NUCLEAR PLANT UNIT 1 LIMESTONE COUNTY, ALABAMA TENNESSEE VALLEY AUTHORITY DOCKET NO. 50-259

TABLE OF. CONTENTS Section ~Pa e No.

Introduction 0 ~ ~ ~ ~ ~ ~ ~ ~ e ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 1 1.0 Definitions 2 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 1.1/2.1 Fuel Cladding Integri.ty . . . . . . . . . . . . . . 8 1.2/2.2 Reactor Coolant System Integrity.......... 27 LIMITING CONDITIONS FOR OPERATION AND SU VEILLANCE RE UIREMENTS Reactor Protection System .............

4 31 3.2/4.2 Protective Instrumentation . . . . . . . . . . . . . 50 A. Primary Containment and Reactor Building-Isolation Functions . . . . . . . . . . . . . . 50 B. Core and Containment Cooling Systems-Initiation and Control . . . . . . . . . . . . . 50 C. Control Rod Block Actuation . . . . . . . . . . 51 D. Off-Gas Post Treatment Isolation Functions e ~ ~ ~ ~ '

~ ~ e ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 51 E. Drywell Leak Detection . . . . . . . . . . . . . 52 F. Surveillance Instrumentation . . . . . . . . . . 52.

G. Control Room Isolation . . . . . . . . . . . . . 52 H. Flood Protection . 53 I. Meteorological Monitoring Instrumentation . . . 53 J. Seismic Monitoring Instrumentation . 54 3.3/4.3 Reactivity Control 120 A. Reactivity Limitations . 120 B. Control Rods . 121 C. Scram Insertion Times 124

Section ~Pa e No.

D. Reactivity Anomalies . . . . . . . . . . . . . . 125 E. Reactivity Control 126 3.4/4.4 Standby Liquid Control System 135 A. Normal System Availability . . . . . . . . . . . 135 B. Operation with Inoperable Components . 136 C. Sodium Pentaborate Solution .......... 137 3.5/4.5 Core and Containment Cooling Systems . . 143 A. Core Spray System ~ ~ 143 B. Residual. Heat Removal System (RHRS)

(LPCI and Containment Cooling) 145 C. RHR Service Water. System and Emergency Equipment Cooling Water System (EECWS) 151 D. Equipment Area Coolers . 154 E. High Pressure Coolant Injection System (HPCIS) 154 F. Reactor Core Isolation Cooling System (RCICS) . . . . . . . . . . . . . . . . . 156 G. Automatic Depressuri zation System (ADS ) o ~ ~ ~ ~ ~ ~ ~ ~ ' ~ ~ ~ o ~ 157 H. Maintenance of Filled Discharge Pipe... 158 I. Average Planar Linear Heat Generation Rate... 159 J. Linear Heat Generation Rate 159 K. Minimum Critical Power Ratio (MCPR) 160 L. Reporting Requirements . 160 3.6/4.6 Primary System Boundary 174 A. Thermal and Pressurization Limitations . 174 B. Coolant. Chemistry 176

Section ~Pa e No.

C. Coolant Leakage . . . . . . . . . . . . . . . . 180 D. Safety and Relief Valves . . . . . . . . . . . . 181 E. Jet Pumps 181 F. Jet Pump Flow Mismatch . . . . . . . . . . . . . 182 G. Structural Integrity . . . . . . . . . . . . . . 182 H. Shock Suppressors (Snubbers) . . . . . . . . . . 185 3.7/4.7 Containment Systems . . . . . . . . . . . . . . . . 227 A. Primary Containment 227 B. Standby Gas Treatment System . . . . . . . . . . 236 C. Secondary Containment . . . . . . . . . ... . . 240 D. Primary Containment Isolation Valves . . . . . . 242 E. Control Room Emergency Ventilation . . . . . . . 244 F. Primary Containment Purge System . . . . . . . . 246 G. Containment Atmo'sphere Dilution System (CAD) . . 248 H.. Containment Atmosphere Monitoring (CAM) System H2 and 02 Analyzer 249 3.8/4.8 Radioactive Material s 281 A. Liquid Effluents .. 281 B. Airborne Effluents . 282 C. Mechanical Vacuum Pump . . . .  : . . . . . . . . 286 D. Miscellaneous Radioactive Materials Sources . . 286 3.9/4.9 Auxiliary Electrical System 292 A. Auxil'iary Electrical Equipment . . . 292 B. Operation with Inoperable Equipment 295 C. Operation in Cold Shutdown . 298 3.10/4.10 Core Alterations . 302 A. Refueling Interlocks . . . . . . . . . . . , . . 302

Section ~Pa e No.

B. Core Monitoring 305 C. Spent Fuel Pool Mater 305 D. Reactor Building Crane .'. 307 E. Spent Fuel Cask 307 F. Spent Fuel Cask Handling-Refueling Floor . . 308 3.11/4.1'1 Fire Protection Systems 315 A. High, Pressure Fire Protection System . . .  ; . . 135 B.'02 Fire Protection System . . 319 C. Fire Detectors '320 D. Roving Fire Watch 321 E. Fire Protection Systems Inspection . .' . . 322 5.0 Major Design Features 330 5.1 Site Features . 330 5.2 Reactor . . . . . . . . . . . . . . . . . . ,330 5.3 Reactor Vessel 330 5.4 Containment . 330 5.5 Fuel Storage 330 5.6 Seismic Design 331 6.0 Administrative 'Controls 332

'.1 Organization 332 6.2 Review and Audit 332 6.3 Procedures 338 6.4 Actions to be, Taken in the. Event of a Reportable Occurrence in Plant Operation 346 6.5 .Actionsto be Taken in the Event a Safety Limit is Exceeded . . 346 6.6 Station Operating Records . 346

Section ~Pa e.N0.

6.7 Reporting Requirements . . . . . . . . . . . . 349 6.8 Minimum Plant Staffing . . . . . . . . . . . . 358 6.9 Overall Restoration Coordinator . . . . . . . . 358

LIST OF TABLES Table Title ~P8 e No.

3.1.A Reactor Protection System Instrumantation Requirements...................

(SCRAM) 33 4 ~ 1.A Reactor Protection System (SCRAM) Instrumentation Functional Tests Minimum Functional Test Frequencies for Safety Instrumentation and Control Circuits . 37 4.1. B Reactor Protection System (SCRAM) Instrument Calibration Minimum Calibration Frequencies for Reactor Protection Instrument Channels ... . . . . 40 3.2,A Instrumentation .................

Primary Containment and Reactor Building Isolation 55 3.2.B Instrumentation that Initiates or Controls the Core and Containment Cooling Systems . . . . . . . . . 62 3.2.C Instrumentation that Initiates Rod Blocks ..... 73 3.2.D Off-Gas Post Treatment Isolation Instrumentation .. 76 3.2.E Instrumentation that Monitors Leakage Into Drywell . 77 3.2.F Surveillance Instrumentation . . . . . . . . . . . . 78 3.2;G Control Room Isolation Instrumentation '. . . . . . . 81 3.2.H Flood Protection Instrumentation . . . . . . . . . . 82 3.2.I Meteorological Monitoring Instrumentation. . . . . . 83 3.2.J Seismic Monitoring Instrumentation ~ . . . ~ . . . . 84 4.2.A Surveillance Requirements for Primary Containment and Reactor Building Isolation Instrumentation . . 85 4.2.8 Surveillance Requirements for Instrumentation that Initiate or Control the CSCS . . ; . . . . . . . . 89 4.2.C Surveillance Requirements for Instrumentation that Initiate Rod Blocks . . . . . . . . . . . . . . . 102 4.2.D Surveillance Requirements for Off-Gas Post Treatment Isolation Instrumentation . . . . . . . . . . . . 103 4.2.E Minimum Test and Calibration Frequency for Drywell Leak Detection Instrumentation...... 104

LIST 'OF TABLES Cont'd Table Title ~Pa e No.

4.2.F Minimum Test and .Calibration Frequency for Surveillance Instrumentation . . . . . . '. . . . 105 4.2.G Surveillance Requirements -for Control Room Isolation Instrumentation .. . . . . . . . . 106 4.2.H Minimum Test and Calibration Frequency for Flood Protection Instrumentation 107 4.2.J. Seismic Monitoring Instrument, Surveillance 108 P

3.6.H Shock Suppressors (Snubbers) . . . . . . . . . . . 190 4.6.A Reactor Coolant System Inservice Inspection Schedule 'I 209 3.,7.A Primary Containment Isolation Valves . . . . . . . 250 3.7.B Testable Penetrations with Double 0-Ring S eals I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 256 3.7.C Testable Penetrations with Testable Bellows . . . . 257 3:7.D Primary Containment Testable Isolation Valves . . . 258 3.7.E Suppression Chamber Influent Lines Stop-Check Globe Valve Leakage Rates . . . . . . . . . . . . 263 3.7.F Check Valves on Suppression Chamber Influent Lsnes ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 263 3.7.H Testable Electrical Penetrations 265 4.8.A Radioactive Liquid Waste Sampling and Analysis 287 4.8.B Radioactive Gaseous Waste Sampling and Analysis . . 288 3.11.A Fire Protection System Hydraulic Requirements . 324 6.3.A Protection Factors for Respirators 343 6.8.A Minimum Shift Crew Requirements . 360

LIST OF ILLUSTRATIONS

~Ft ore Title ~Pa e No.

2.1.1= APRM Settings ..................

Flow Reference Scram and APRM Rod Block

".. 13 2.1-2 APRM Flow Bias Scram Vs. Reactor Core Flow . . . . 26 4.1-1 Graphic Aid in the Selection of an Adequate Interval Between Tests . . . . . . .,. . . . . . 49 4.2-1 System Unavailability . 119 3.4-1 Sodium Pentaborate Solution Volume Concentration Requirements 138 3.4-2 Sodium Pentaborate Solution Temperature Requirements . . . . . . . . . . . . . . . . . . 139 3.5.1-A MAPLHGR Vs. Exposure Initial Core Fuel Type 2... 171 3.5.1-B MAPLHGR Vs. Initial Core Fuel Types 1 8 3..... 172 3.5.2 K f Factor ~... \ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 173 3.6-1 Minimum Temperature 'F Above Change in Transient Temperature . . . . . . . . : . . . . . . . . . . 188 3.6-2 Change in Charpy V Transition Temperature Vs.

Neutron Exposure . . . . . . . . . . . . . . . . 189 6.1-1 TVA Office of Power Organizatioq for Operation of Nuclear Power Plants . . . . . . . . . . . . . 361 6.1-2 Functional Organization . . . . . . . . . . . . . . 362 6.2-1 Review 'and Audit Function............. 363 6.3-1 In-Plant Fire Program Organization ........ 364

REVISED 3-11-77 BROWNS FERRY NUCLEAR PLANT UNIT 1

'TECHNICAL SPFCIFIChTIONS EFFECTIVE PAGE LISTING EFFECTIVE PhGH REVISION DhTH A endix A i-viii 8-20-76 ix-xi 2-24-77 1-9 8-20-76 10 2-7-77 11-23 8-20-76 24 2-7-77 25-35 8-20-.76 36 2-15-77 37-43 8-20-76 44 2-15-77 45-53 8-20-76 54 2-15-77 2-7-77 56-88 8-20-76 89-95 2-15-77 96-111 8-20-76 112 2-7-77 113-122 8-20-76 123-124 2-15-77 125-142 8-20-76 143-146 2-15-77

REVISED 3-11-77 EPPECTIVE PAGE LISTING El%ECTIVE PAGE R3'.VISION DATE

~Aeedfx A 147-149 8-20-76 150-151 2-15-77 152-156 8-20-76 157-158 2-15-77 159-166 8-20-76 167 2-15-76 168-170 8-20-76 171-172 3-11-77 173-186 8<<20-'6 187 2-15-77 188-226 8-20-76 227 2-15-77 228-251 8-20-76 252 2-15-77 253-258 8-20-76 259 2-15-77 260-261 8-2D76 262 2-15-77 263-266 8-20-76 267-270 2-15-77 271-285 8-20-76 286 2-15-77 287-294 8-20-76 295-296 2-15-77

REVISED 3 11-77 EFFECTIVE PACE I.ISTING EFFECTIVE PAGE REVISION PAGE 297-321 8-20-76 322 2-15-77 323-325 8-20-76 326, 2-15-77 327-331 8-20-76 332-333 2-15-77 334-336 8-20-76 337 2-15-77 338-345 8-20-76 346 2-15-77 347-348 8-20-76 349-350 2-15-77 351-353 8-20-76 354 2-15-77 355 8-20-76 356-357 2-15>>77 358-364 8-20-76 A endix 8 1-46 8-20-76

IRTRODUCTION This document presents the technica1 specifications for the Brogans Ferry Nuc1ear Plant Unit 1 only.

1. 0 DEFINITIONS The succeeding frequently used terms ere explicitly defined so that a uniform interpretation of the specifications may be achieved.

able maintenance of the claddingiand primary systems are assured.

Exceeding such a limit requires unit shutdovn and reviev by the htomic Energy Commission before resumption of unit operation.

. Operation beyond such a limit may not in itself result in serious consequences but it: indicates an operational deficiency aub]ect to regulatory. revlev.

b. Limitin Safet S stem 'Settin LSSS) The limiting safety system

~ etting are, settings on instrumentation vhich initiate the automatic protective action at a level such that the sefety limits vill not be exceeded. The region betveen the sefety limit and these settings represent margin vith normal operation lying belov these settings.

The margin has been'.establishd so that vith proper operatio'n of 'the instrumentation the safety limits vill never be exceeded.

C. Limitin Conditions for eration LCO - The limiting 'conditions for operation specify the minimum ecceptable levels of system performanco necessary to assure safe etartup and operation of the facility. 4hen these conditions are met, the plant can be operated safely and abnor-mal situations can. be safely controlled ~

D. DELETED

1,0 DEFINITIONS (Cont'd)

E .Opershie - A systea or coaponcac shsli he considered oparahia rhea it is manner.

capable of performing its intended function ia its 'required p .~eratin Operating aesno that a systoe or coaponant is par;ota ing its intended functions in its required manner.

G. Immediate - Immediate means that the required action vill be ini-tiated ao soon as practicable consideriqg the safe operation of the 'unit and the importance'f the required action.

H. Reactor V<mcr 0<erect<le - <<est<or poser operation ia anp optrstio<<

with the mode svitch in t)gc "Sturtup" or "Run" position with the reactor critical and above 1X rated pover.

I. Hot Stand~b Condition - Hot standby condition means operation vith coolant temperature greater t.)gdgn 212")p, system pressure less than 1055 psig, the main steam iso).ation valves clvsed and the.mxide 'switch in the Startup/Hot Standby position.

J, Cold Condition - Reactor coolant tempd)rature equal to or less than 212 P.

K. Hot Shutdovn - The reactor lo in the shutdown mode and the reactor coolant temperature greater than 212'F,

1. Cold Shutdovn - The reactor is in the shutdown modep the reaCtor coolant temperature equal to or less than 212'F, and the is vented to atmoaphcre.

reactor'essel M. Mode of cretins - A reactor mode svitch selects the proper interns lacks for the operational status of the unit. The following ate the modes and Interlocks prov)i)cd:

1. Startu /)lot Standb Mop)a - In this >code the reactor protection scram tripe initiated by condt.nscr lov vacuum and main steam line isolation valve cl:osure, arc bypassed vhen reactor pressure is loss than 1055 psig, the reactor protection system ia energited with IiN neutron monitoring system trip, the APRN 15X high flux trip, and control rod vithdraval interlocks in serv'ice. This is often referred to as just Startup Mode. -This is intended to triply the Startup/Hot Standby position of the mode switch.

1~0 'DEF INITIOHS (Conc ')

2. Run Mode - Zn thin mode the reactor system pressure is at or above 850 psig snd che renctoc protection system ia energixed with APRM pzotection (excluding the 15X high flux trip) and RBM interlocks in service.

3. Shutdown Mode Placing the mnde switch to the shutdown posi-tion initiates a reactor scrnm and power to the control rod drives is removed. Afcer n aliort time period (about 10 sec),

the scram signal is removed allowing a oczam reset and restoring tha normal valve lineup in che control rod drive hydzaulicsys-tem; also, the main steam line isolation scram and main con-.

denser low vacuum scram 'sre bypss'sed if reactor vessel pressure is below 1055 psig.

4. Refuel Mode - With the mode switch in the refuel position inter>>

locks aze established so that one control rod only may be with-drawn when the Source Range Monitor indicate at least' cps and the refueling crane is not over the reactor; also, the main steam line isolation scram and main condenser low vacuum scram are bypassed if reactor vessel pressure is below 1055 psig. If the refueling crane is over the reactor, all=- rods must be tully inserted.and none can be withdrawn.

8. Rated Power Raced power refers co operation at s reactor power of 3,293 NWt; this is also terra<<d 100 percent power and is the maximum power level nuthorixed by the opernting license. Rated steam flow, rated coolant flow, rated neutron flux, nnd mt<<d nuclear system pressure ref<<>> co the values of chose parameters when the reactoz" is at iated power. Design power, the power to which the safety analysis appliea, corresponds to 3440 MWt.l

0. primer Containment Into rit primary containment integrity means that the drywall and pressure suppression chamber are intact and all of the following conditions are satisfied:

l. All non-aucomatic concainmenc isolation valves on lines connected to the reactor coolant system or. containment which aze not.required to'be open during accident conditions are closed. These valves may be opened to perform necessary operational activities.

2. At leaat one door in each airlock is closed nnd sealed.

ll

3. All automatic containment isolation valves are oporabla or deacti vaced in tho isolated ponition.

4. All blind flangoa and mnnway9 ~re. cioood p~ Secondar Concainmenc Inc<< rit - S<<coodary contiinmeat integrity means that che reactor building is intact and the following condi-tions are met:

L 0 DEFINITIONS (Cont'd) 1~ At least one door in each access opening is closed.

2. The standby gas treatment syst'm is operable.

3. All Reactor Building ventilation system automatic isolation valves are operable or deactivated in the isolated position.

for.a particular unit and the end of the next subsequent refueling outage for the same unit.

the shutdown of the unit prior to a refueling and the startup of the unit after that refueling. For the purpose of designating frequency of testing and surveillance, a refueling outage shall mean a regularly scheduled outage; however, where such outages occur. within 8 months of the completion of the previous refueling outage, the required surveillance testing need not be perfozmed until the next regularly scheduled outage.

a S. Alteration of the Reactor Core - The act of moving any component in the region above the core support plate, below the upper grid and within the shroud. Normal control rod movement with the control rod drive hydraulic system is not defined as a core alteration. Normal movement of in-coze instrumentation and'he traversing in-core probe is not defined as a core alteration.

T, Reactor'VesselePressuze Unless otherwise indicated, reactor vessel pressures listed in the Technical Specifications are those measured by the reactor vessel steam'space detectors.

U. Thermal Parameters

1. Minimum'ritical Power Ratio (MCPR) Minimum Critical Power Ratio MCPR) is the value of the critical power ratio asso-ciated with the most limiting assembly in the reactor coze.

Critical Power Patio (CPR) is the r'atio of that power in a fuel assembly, which is calculated to cause some point, in the assembly to experience boiling transition, to the actual assembly operating power.

2. Transition Boilin - Transition boiling means the boiling regime between nucleate and film boiling. Transition boiling is the regime in which both nucleate and film boiling occur intermit-tently with neither type being completely stable.

3. Total Peakin Factor - The ratio of the maximum fuel rod surface heat flux in anyassembly to the average surface heat flux of the core.

4. Aveta e'lanet Lkaeat Heat Ceaetatlea Hate (hpgg~)

Average Planar Heat Generation Rate is applicable to a specific planar height and is equal to the sum of the linear heat generation rates for all the fuel rods in the specified bundle at the specified height divided by the number of fuel rods in the fuel'undle.

1 0 DEPINITIONS (Cont ')

V. Instruments tion the Instrument Calibration - An instrument calibration means ad)ustment of an instrument signal output so that it corresponds, vithin acceptable range, and accuracy, to a knovn val ( )

parameter vhich the instxument monitors.

2~ Channel - A channel is an arrarigement of a sensor and asso-ciated components used to evaluate plant variables and pro-duce discrete outputs used in logic. A channel terminates and loses'its identity vhera individual channel outputs are combined in logic.

3. Instrument Functional Test - An, instrument functional test means the infection of a simulated signal into the instrument piimary sensor to verify the proper instrument channel response, alarm and/or initiating action.

4. Instrument Cheek An instrument check is qualitative determina-tion of acceptable operability by observation of instrument behavior during operati.on. This determination shall include, vhere possible, comparis'on of the instrument vith other indepen-dent instruments measuring the sama variable.

5. Lo ic S stem Functional Test - A .logic system functional test means a test of all relays and contacts of a logic circuit to insure all components are operable par design intent.. Where practicable, ection vill go to completion; i.e., pumps vill be started and valves operated.

6, Tri S stem A trip system means an arrangement of instrument c annal trip signals and auxiliary equipment required to initiate action to accomplish a protective trip function. A txip system may require one or more instrument channel trip signals relat d to one or more plant parameters in order to ini.tiate tr'p system action. Initiation of protective action may require the tripping of a single trip system or the coincident tripping of tvo trip systems.

7. Protective Action >> An action initiated by the protection system vhan a limit is reached. A protective action can be at a channel or system level.

8. Protective Function - A system protective action vhich results from the protective action of the channels monitoring a parti-cular plant condition.

9. Simulated Automatic Actuation - Simulated automatic actuation means applying a simulated signal to the sensor to actuate the circuit in question.

1.0 DEYIHITIOHS (Cont'd)

10. ~Lo ic - A logic is'an arrangement of relays, contacts, snd other components that produces a decision outout.

(a) ~Initiation - A logic that receive signals iron chenasls sed produces decision outputs to the actuation logic.

(b) Actuation A logic that receives signals (either from initiation logic or channels) 'and produces decision outputs to accomplish a protective action.

M. fuactional Tests - A functional test is the manual operation or initiatioa of 'a system, subsystem, or componeat to verify that it functions vithia desiga toleraaces (a.g., the manual, start of a core spray pump to verify that it runs and that it pumps the required volume of vatar).

X. ghutdova - The reactor is ia s ohutdovn ooadition shen the reactor mode avis'ch io in the shutdovn mode position and no core aitsratioas are beiag performed.

Y. En iaeerad Safe uard - An engineered s'afeguerd is a safety system the actions of erich are essential to a safety action required in response to accidents ~

Z~ Cumulative Downtime - The ox~~tive downtime for those safety components end systems whose downtime is limited to 7 consecutive days prior to require~ reaotor shutdown shall be ~ted to any 7 days in a oonsecutive 30 day period.

SAFETY LIGHT LIHITING SAF"TY SYSTE~f SETTING 1 ~lL CLMDING INTEGRITY 2.3. FUEL CLADDING INTEGRITY h licabilit A licahilit c

Applies to the interrelated vari- Applies to tr ip . et tings of the ables -ssociated with fuel instruments and devices which are thermal behavior. prov'ded to prevent th reactor system safety limits from b ing exceeded.

Gb ective ~Ob ective To establish limits which ensure To define the level of the process the integrity of the fuel clad- variables at which automatic pro-ding o tective action i" initiated to ore-vcnt the fuel cladding integrity safety limit from oeing exceeded.

S ecifications I

A. Reactor Pressure > 800 psia The limiting safety systen settings shall and Core Flow > 10! of Rated. be as specified below:

linen the reactor p essure is A. Neutron Flux Scram greater than 800 psia, the existence of a minimum criti- l. APKN Flux Scram Trip Setting cal power ratio (NCPR) less (Run 1fode) than 1.05 shall constitute

,violation of th fuel claddin" integrity safety limit.

then th Node Switch the Rt'N position, the i'n scran trip setting APP'4'lux shall Pe S< (0. 66W' 5'47.')

where:

S ~ Setting in percent of rated thermal power (3293 t%t)

W ~ Loop recirculation flees ra e in percent oi rated (rated loop recirculation flow rate equals 34 2x10 lb/hr)

SAFETY LIMIT LIMITING SAFETY SYSTEM'l SETTING

l. 1. FUI'I CI.ADI)I;NG INTEGIITTY 2.1 FUEI CLADDING INTFGRTTY In the event of operation with a maximum total peaking factor (MTPF) greater t,hnn the design value of 2.63 the setting shall be modified n.". follows:

2.63 S< {0.66w + ~>4i' >mr>r-where:

MTPF = The value of the existing maximum total peaking factor For no combination of loop recir-culation flow rate and core thermal power shall the APRM flux scram trip setting be allowed to exceed 20% of raced thermal power.

(Note: These::ot;t, i nys a::."umc operation within t)Ie basi< the) mal hydraulic design criteria. These criteria are LHGR < l8.5 kW/ft and MCPR > 1.25. Therefore, at full power operation is not allowed with maximum total peaking factor above 2.63 even if If it the scram setting is reduced. is determined that either of these design cri-teria is being violated during oper-ation, action shall be initiated with-in 15 minutes to restore operation to within the prescribed limits. See specification 3.5.J and 3.5.K. Sur-veillance requirements for maximum total peaking factor are given in Specification 4.1.B.)

2. APRM When the reactor mode switch is in the STARTUP POSITION, the APRM scram shall be set at less than or equal to 15% of rated power.

3.

IRM The IRM scram shall be set at less than or equal to 120/125 of full scale.

Lim't B. APRM Rod Block Tri Settin ~

B. Core Thermal Power (Reacto" Pressure <800 psia) The APRM Rod block trip setting shall be:

Ul.en the reactor pressure is less than or equal to 800 psia,

SAFETY LIMIT LIMITING . AFETY SYSTEM SETTING FUEL CLADDING INTEGRITY 2.1 FUEL CLADDING INTEGRITY or. core coolant flow is less RR< (0.66W + 424) than 10$ of rated, the core thermal power shall not ex- where:

ceed 823 %at (about 255 of rated thermal power). S R>

= Rod block setting is percent of rated thermal power (3293 MWt)

W = Loop recirculation flow rate in percent of rated (rated loop recirculagion flow rate equals 34 2 X 10o lb/hr)

In the event of operation with a maximum total peaking factor (MTPF) greater than the design value of 2.63 the setting shall be modified as follows:

2.63 (0.66W + 42$ } MTPF where:

MTPF = The value of the existing .

maximum total peaking factor C. Whenever the reactor is in C. Scram and isoluation > 538 in. above the shutdown condition with reactor low water vessel zero level irradiated fuel in the reac-tor vessel, the ~ater level shall not be less than 17.7 in. above the top of the D. Scram turbine stop < 10 percent normal active fuel zone. valve closure valve closure E. Scram turbine control valve Upon trip of

1. Fast closure the fast acting solenoid valves

2. Loss of control > 550 psig oil pressure F ~ Scram low con- 23 inches denser vacuum Hg vacuum G. Scram main steam < 10 percent line isolation valve closure H. Main steam isolation > 825 psig valve closure nuclear system low pressure 10

ShFETY LIMIT LIMITING SAFETY SYSTEM SETTING 1.1 Fuel Claddin Into rit 2.1 Fuel Claddin Inta rit I. Core spray and fZCI > 378 in.

actuation reactor above vesse lov vater level aero J. HPCI and RCIC > 490 ir..

actuation->>reactor above vesse.

Iow eater level aero K. Main steam isola- > 490 in.

tion valve closure above reactor lou vater sero level vesse.'1

FI CURL'FLFT!'.D APRM FLOW BIASED SCRAhl gg 80 0 70 APRM ROD BLOCK

~ 60 Cl

~RECIRCULATION FLOW IS DEFINED AS RECIRCULATION LOOP FLOW 60 RECIRCULATION FLOw Qb ot deslsn)

BROWSES. FERRY HUCLEAR PLANT FIHAL SAFETY AHALYSl5 R-PORT APSE Flo~ Reference Scram old APRM Rod Block Iettings

FT!lURR DEI.HTEO BASFS - HJFL CLADDI"!C INTFCRITY SAFETY LIMIT Tne fuel cladding represents one of the physical barriers which separate radio-active materials fzom environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking. Although ome corrosion or use-related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result fzcm thermal stresses which occur from reactor operation significantly above design conditions and the pzotection system setpoints. Wnile fission product migration from cladding pezformation is just as measurable as that from use-related cracking, the thermally-caused cladding perforations signal a threshold, beyond wnich still greater thernal stresses may cause gross rather than incremental cladding deteriora-tion. Therefore, the fuel cladding safety limit is defined in terms of the reactor opezating conditions which can result in cladding perforation.

The fuel cladding integrity limit is set such that no calculated fuel damage would occur as a result of an abnormal operational transient. Because fuel damage is not directly observable, the fuel cladding Safety Limit is defined with margin to the conditions which would produce onset transition boiling (HCPR of 1.0) .

This establishes a Safety Limit such that the minimum critical power ratio (.'!CPR) is no less than 1.05..ICPR >1.05 represents a conCervative margin relative to the conditions required to maintain fuel cladding integrity.

Onset oE transition boiling results in a decrease in heat transfer from the clad and, therefore, elevated clad temperature and the possiblity oE clad failure.

Since boiling transition is not a directly observable paramet'er, the margin to ooiling transition is calculated from plant opera ing parameters such as core power, core flow, feedwater temperature, and core power distribution. The margin for each fuel assembly is characterized by the critical power ratio (CPR) which is the ratio of the bundle power which would produce onset of transition boiling divided by the actual bundle power. The minimum value of.,this ratio for any bundle in the core is the minimum critical power ratio (MCPR). It is assumed that the plant operation is controlled to the nominal protective setpoints via the instru-mented variables, i.e., normal plant operation presented on Figure 2.1,1 by the non inal evnects~ flc w control lir o.. ~ne Safetv Li~it (~~CPn n~ I.nS) has s<<F5 5cient conservat'sm to assure that in the event of an abnorn.al operational transient initiate~. Erom a nor .al operating condition (.'!CPR )> ~ 25) more than 99.9% of the Euel rods in the coze are evpected to avoid b'oiling transition. The margin between MCPR of 1.0 (onset of transition boiling) and the safety limit 1.05 is derived from a detailed statistical analysis considering all of the uncertainties in moni-toring the core operating state including uncertainty in the boiling transition correlation as described in Reference 1. The uncertainties employed in deriving the safety limit are provided at the beginning of each fuel cycl.e.

The HCPR value used in the ECCS performance evaluation (1.18) is less limiting than the MCPR Eor operation (1.25) .

15

1. 1 BASES Because the boiling transition correlation is based on a large ouantity of full scale d"ta there is a very high confidence that operation of a fuel assembly at the condition of 14CPR = 1.05 would not produce boiling tran-sition. Thus, although it is not required to establish the safety limit additional margin exists between the safety limit and the actual occurrence of loss of cladding integrity.

However, be expected.

if boi3Cladding ing tr insition werc temperatures to occur, clad perforation would not woulQ increase to approximately 1100 F which is below the perforation temperature of the cladding ma erial. Tnis has been verified by tests in the General Electric Test Reactor (GEAR) where fuel similar in design to BFkkP operated above the critica'eat flux for a, significant period of time (30 minute.")

without clad perforation.

If reac o" pressure should ever exceed 1400 psia during normal power operating (the limit of applicability of the boiling transition corre-lation) itviola ed.

would be assumed that the fuel cladding integrity Sa.ety Limit has been In addition to the boiling transition limit (kkCPR = 1.05) operation is constrained to a maximum Lk!GR 18.5 Kw/ft. At 100fd power this limit is reached <<ith a maximum total peaking factor (NTPF) of 2.63. For the case of the t. PP e..ceedind 2.63 operation is permitted only at less than 1005 of ratec thermal power and only with reduced APE< "cram settings as reaui ed by specification 2.1.A.1.

A pressures below 800 psia, the core e"evation pressure drop (0 power, 0 flow) is greater than 4.56 psi. At low powers and flows this pressure differential is maintained in the bypass region of the core. Since the pressure d op in the bypass region is essentially all elevation head, the core p. essure drop at low powers and flows wl13. always be greater than 4.56 psi. Analyses show that with a flow of 28X103 lbs/hr bundle flow, bundle p. essure drop is nearly independent of bundle power and has a value of 3.5 psi. Thus,'3 the bundle flow with a 4.56 psi driving head will be g eater than 28x10 . lbs/hr. Full scale ATLAS test data taken at pressu.es from 14.T psia to 800 psia indicate that the fuel assembly critical power at this flow is approximately 3.35 h5!t. Pith th" design peaking ac or" this corresponds to a core thermal power of more than

~

505. Thus, a core thermal power limit of 25$ for reactor pressures below 800 psia is conservative.

For the fuel in the core during periods when the reactor is shut down, con-sideration must also be given to water level requirements due to the effect of decay heat. If water level should drop below the top of the fuel during this tire, the ability to remove decay heat is reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation. As long as the fuel remains covered with water, sufficient cooling is available to prevent fuel clad perforation.

16

1.1 BASES The safety limit has been established at 17.7 in. above the top of the irradiated fuel to provide a point which can be monitored and also pro-vide adequate margin. This point corresponds approximately to the top of the actual fuel assemblies and also to the lower reactor low water level trip (378" above vessel zero).

RFFPRFNCE

1. General Electric BVR Thermal Analysis Basis (GETAB) Data, Correlation and Design Application, NEDO 10958 and NEDE 10958.

PAGE DELETED 18

2.1 BASES

LIHITIiG SAFETY SYSTE f SETTINGS RELATED TO FUEL CLADD NG INTFGRITY

~

The abnormal operational transients applicable to opezation of the Browns Ferry Nuclear Plant have been analyzed throughout the spectrum of planned operating con-ditions up to the design thermal power condition of 3440 >Mt. The analyses were based upon plant operation in accordance with the operating map given in Figure 3.7-1 of the FSAR. In addition, 3293 1%t is the licensed maximum power level of Browns Ferry Nuclear P'nt, and thi.s represents the maximum s teady-state power which shall not knqwingly be exceeded.

Conservatism is incorporated in the transient analyses in estimating the controlling factors, such as void reactivity coefficient, control rod scram wozth, scram delay'ine, peaking factors, pnd axial power shapes. on These factors are selected conservatively with r'espect to their effect the analysis model.

applicable transient zcsut.ts as determined by the current substantiated in opera-This transient model, evolved over many years, has been tion as a conservative 'tool or evaluating reactor dynamic performance.

Result obtained from a General Electric boiling water reactor'ave results been compared with predictions made by the 'model. The comparisions and aze summarized in Reference l.

The absolute value of the void rcactiv'ty coefficient used in thc analysi

'is conservatively estimated to be about 25% greater than the nominal maximum, luc expec"ed to occur during thc core ielifetime. The f scram worth used has total'cram worth o been dcratcd to bc equivalent'to approximately 8(K of the control rods. The scram delay time and rate of rod insertion allowed in<1 vers arc consorva tivcly set equal to thc longest dclgy ar.d, low-st insertion rate acceptable by Technical Specifications, The effect of scram worth, sczam delay time and rod inseztion rate, all conservatively applied, aze of greatest significance in the early portion of the negative reactivity insertion, The rapid insertion of negative reactivity is assured by the time requirements for 57 and 20/ insertion.

By the time the rods are 60/ inserted, approximately four dollars of negative reac-tivity has been inserted which strongly turns the transient, and accomplishes the desired effect. The times for 507. and 907 insertion are given to assure proper completion of the expected performance in the earlier portion of the tiansient, and to establish the'ultimate fully.shutdown steady-state condition.

For analyses of the thermal consequences of the transients a NCPR of 1.25 is

'conservatively assumed to exist prior to initiation of the transients.

inis choice of using conservative values of controlling parameters and initiating transients at the design power level, produces more pessimis"'ic answers than would result by using expected values of control parameters and analyzing at highez power levels.

Steady-state operation without forced recirculation will not be permitt d, except during startup testing.

19

2. 1 BASES In summary:

1. The licensed maximum power level is 3,293 Mt.

2. Analyses of transients employ adequately conservative values of the coatrolling reactor para=eters.

3. The abnormal operational transients were analy"ed to a powez level of 3440 tS'T.

4. The analytical procedur s now used result in a more logical ansver thaa the alternat've method of assumiag a higher startiag power ia coa)unc-tion with the expected values for the parameters.

The bases for individual set points are discussed below:

P.. Neutron Flux Scram

l. APPIAN High Flux Scram Trip Setting (Run Node)

The average power range nonito ing (APiN) system, vhich is calibrated using heat balance data taken during steady-state conditions, reads ia percent of rated paver (3,293 NMc). Because fission chambers pro-vide the basic inpdt signals, the APRM system responds directly to average neutron flux. During transients, the i"stancaaeous rate of heat transfer from t'e fuel (reactor ther. sl power) is less thaa the instancaneoua. neucron flux due co the time constant of the fuel.

Therefore, during transients inC<<ced by disturbances, the the~1 power of the fuel will oe less than that indicated by the neutron flux at the scram sett'ng. Analyses repor- d in Section 14 of the P'aal Safety Analysis Report demonstrated that with a 120 percent scram none of the abaoaxsl operational transients analy=ed v'olac trip'etting, the fuel safecy 'imit and there is a substantial margin ircn fuel damage. Th refore, use oz a flow-biased scram provides even additional Figure 2.1.2 shows the flow biased scram as a function of core flow.

An increase in the APRf sera" setting. vou'd decrease the marg'a pre-sent before the fu<<'lcddin", integrity safety 1i='" is reached. inc APRN serac setting vas deca-.~" ned by an analysis of margins ". quired to prov'de a reasonable range for maneuveriag during operation.

Reducing ch's operating margin would increase th frequency oi spurious acrama, v'hich have nn adverse efface on reactoz'afety because of the resulting chez ml stresses. Thus, the APP'{ sett'ng was selected because it provides adequate margin zor the fuel cladding 'ntegri safety li-it yec al'cvs operating wrgia that reduces ha possibility of y

uaaacssslry pcraas r 20

. 1 BASFS The scram trip setting must be adjusted to ensure that the LHGR transient peak is not increased for, any combination of HTPF and reactor core thermal power. The scram setting is adjusted in accordance with the formula in Specification 2.1.A.l, when the maximum total peaking factor is greater than 2.63.

Analyses of the limting transients show that no scram adjustment ) is required to assure HCPR ) 1.05 when the transient ls initiated from HCPR 1.25 .

2. APRH Flux Scram Trio Settin (Refuel or Start & Hot Standb Node)

Foz operation in ch" starcup node while the reactor is at low pressure, che APR't scram setting of 15 percent of ra d power prov'des adequate thermal margin betveen the setpoinc and the safety limit, 25 percent of raced. The margin is adequate to accommodate anticipated maneuvers associated with power plant startup. Effects of increasing pressure at zero or low void content are minor, cold water from souzces avail-able dur'..g otarcup 's not much colder than that already in the system, temperature coefficients are small, and control rod patterns aze con-strained to be uniform by operating procedures backed up by che rod swzch minimizer and the Rod Sequence Con ro'ystem. Worth of indivi-dual rods is very low in a uniform rod p" ttern. Thus, all of possible sources oE reactivity input, uni.fo. control rod vithdraval is che moot probab! e cause of s'gnificant power rioe. Because the flux distribution associa ed wx h uniform rod withdrawals does not involve high local pea',

and because several rods must be moved to change power b7 a significant percentage of ratec power, thu rate oi power rise is very slow. Generally, the heat flux is in rear equilibrium with the fission rate. In an assumed unifor rod withdrawal approach to chc scram 'ev'el, the rate of power ri.se is no more t"..an 5 percent of rated power per minute, and ne. APRES s; stern would be more chan acequate to assure a scram before cne power could exceed che se ety 1!mit. The 15 percent APK". scram remains active until che ~de swicch is placed in the RUB po"icion. This switch occurs when reactor pressure io greater than 850 psig.

3. IRM Flux Scram Tri Settin The IRH System consists-of 8 chambers, 4 in each oi the reactor protec-tion syscem logic channels. The IRH is a 5-decade instrument wnich covers t'e range of power I"vel between thac covered by che SRH and che APB.'<. The 5 decades are covered by the IRH by means of a range swicch and the 5 decades are broken down into 10 ranges, each being one-hali oi a decade in si"e. The IRN scram setting of 120 divisions is active in each range of che Ilc!. For 21

2. 1 BASES

3. IRM Flux Scram Trio Settin (Continued) example, if the instrument were on range 1, the scram setting would be at 120 if divisions for that range; likewise, the instrument was on range 5, the scram setting would be 120 divisions on that range, Thus, as the HM is ranged up to accommodate the increase in power level, the scram setting is also ranged up, A scram at 120 divisions on the IRM instruments remains in effect as long as the reactor is in the startup mode. In addition, the APRM 15% scram prevents higher power operation without being in the RUN mode, The IRM scram provides protection for changes which occur both locally and over the entire core, The most significant sources of reactivity change during the power increase are due to control rod withdrawal, Por insequence control rod withdrawal, the rate of change of power is slow enough due to the physical limitation of withdrawing control rods, that heat flux is in equilibrium with the neutron flux and an IRM scram would result in a reactor shutdown well before any safety limit is exceeded. Por the case of a single control rod withdrawal error, a range of rod withdrawal accidents was analyzed. This analysis included starting the accident at various power levels, The most severe case involves an initial condition in which the reactor is )ust subcritical and the IRM system is not yet on scale. This condition exists at quarter rod density. quarter rod density is illustrated in paragraph 7.5.5 of the PSAR, Additional conservatism was taken in this analysis by assuming that the IRM channel closest to .the withdrawn rod is bypassed. The results of this analysis show that the reactor is scrammed and peak power limited to orle percent of rated power, thus <afntaining QCPR, above 1.05. Based on the above analysis> the I%/ provides protection against local control rod withdrawal errors and continuous withdrawal of control rods in sequence.

B. APRM Control Rod Block Reactor power level may be varied by moving control rods or by varying the recirculation flow rate. The APRM system provides a control rod block to prevent rod withdrawal beyond a given point at constant rec'r-cuclation flow rate, and thus to protect against the condition of a MCPR less than 1.05. This rod block trip setting, which is automatically varried with recirculation loop flow rate, prevents an increase in the readtor power level to excess values due to control rod with-drawal. The flow variable trip set ting provides substantial margin 22

2.1 BASES from fuel damage, assuming a steady-state'peration at the trip setting, over the entire recirculation flow range. The margin to the Safety Limit increases as the flow decreases for the specified trip setting versus flow relationship; therefore, the worst case MCPR which could occur during steady-state operation is at, 108% of rated thermal power because of the APRM rod block trip setting. The actual power distribution in the core is established by specified control rod sequences and is monitored continuously by the in-core LPRM system. As with the APRM scram trip setting, the APRM rod block trip setting is adjusted downward if the maximum total peaking factor exceeds 2.63, thus preserving the APRM rod block safety margin.

C. Reactor Water Low Level Scram and Isolation (F~ce t Main Steamlines)

The set point for the low level scram is above the bottom of the separator skirt.

This level has been used in transient analyses dealing with coolant inventory decrease. The results reported, in FSAR subsection 14.5 show that scram and isolation of all process lines (except main steam) at this level adequately protects the fuel and the pressure 'barrier, because MCPR is greater than 1.05 in all cases, and system pressure does not reach the safety valve settings. The scram setting'is approximately 31 inches below the normal operating range and is thus adequate to avoid spurious scrams.

D. Turbine Sto Valve Closure Scram The turbine stop valve closure scram trip anticipates the pressure, neutron flux and heat flux -increase that could result from rapid closure of the turbine stop valves. With a scram trip setting of < 10 percent of. valve closure from full open, the resultant increase in bundle power is limited such that MCPR remains above 1.05 even during the worst case transient that assumes the turbine bypass is closed. This scram is bypassed when turbine steam flow is below 30 percent of rated, as measured by turbine first stage pressure. Actuation of the relief valves limits pressure to well below the safety valve setiing.

E. Turbine Control Valve Scram

1. Fast Closure Scram The reactor protection system initiates a scram within 30 Msec after the control valves start to close. This setting and the fact that control valve closure time is approximately twice as long as that for the stop valves

'eans that resulting transients, while similar, are less severe than for stop-valve closure. No fuel damage occurs, and reactor system pressure does not exceed the relief valve set point, which is appr'oximately 280 psi below the safety limit.

23

2.1 BASES

2. Scram on loss of control oil pressure The turbine hydraulic control system operates using high pressure o'il. There are several points in this oil system where a loss of oil pressure could result in a fast closure 'of the tuzbine control valves. This East closure of the turbine control valves is not protected by the generator load rejection scram, since failure of the oil system would not result in the fast closure solenoid valves being actuated. For a turbine control valve fast closure, the core would be protected by the APRM and high reactor pressure scrams. However, to provide the same margins as provided for the generator load rejection scram on fast closure of the turbine control valves, a scram has been added to the reactor protection system, which senses failure of control oil pressure to the tur-bine control system. This is an anticipatory scram and results in reactor shutdown before any significant increase in pressure or neutron flux occurs. The transient response is very similar to that resulting from the generator load rejection.

P. Main Condenser Low Vacuum Scram To protect the main condenser against overpressure, a loss of con-denser vacuum initiates automatic closure. of the turbine stop valves and turbine bypass valves. To anticipate the transient and automatic scram resulting f rom the closure oE the turbine stop valves, low con-denser vacuum initiates a scram, The low vacuum scram set point is selected to initiate a scram befc 'e the closure of the turbine stop v'elves is in i G. 6 H. Main Steam Line Is~ ation on Low Pressure and Main Steam Line Isolation Scram The low pressure isolation of the main steam lines at 825 psig was provided to protect against rapid reactor depressurixation and the resulting rapid cooldown of the vessel. Advantage is taken of the scram feature that occuxs when the. main steam line isolation valves are closed, to provide for reactor shutdown so that high power opex'a" tion at low reactor preasure does not occur, thus providing protection for the fuel cladding integrity safety limit. Operation of the x'eac-tor at px'essures lowez than g2> psig requires that the reactor mode switch be in the STARTUP position, whexe piotection of the fuel cladding integrity safety limit is provided by the IRM and APRM high neutron flux scrams. Thus, the combination of main steam line low pressure isolation and isolation valve closure scram assures the availability of neutron flux scram px'otection over the entire range of applicab'lity of the fuel cladding integrity safety limit. In addition, the isolation valve closure scram anticipates the pressure and flux transients that occur during normal or inadvertent isolation valve closure. With the scrams set at'10 percent of valve closure, neutron flux does not increase.

24

2. 1 BASES I. J. & K. Reactor low water level set oint for initiation of HPCI and RCIC closin main steam isolation valves and startin LPCI and core s ra um s.

These systems maintain adequate coolant inventory and provide core cooling with the objective of preventing excessive clad temperatures.

The design of these .systems to adequately perform the intended func-tion is based on the specified low level scram set point and initia-tion set points. Transient analyses reported in Section 14 of the PSAR demonstrate that these conditions result in adequate safety margins. for 'both the fuel and the system pressure.

L. References I. Linford, R. B., "Analytical Methods of Plant Transient Fvaluations for the General Electric Boiling Water Reactor," NED0-10802, Feb., 1973.

25

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S11PEZY LINI~ LIHITING Sheen SY:"rm SETTING Le 2 REACTOR COOLANT SYSTEH INTEGRITY 2. 2 REACTOR COOM'YSTEH INTEGRITY

~A plxcabilit~ ~Alicebt1t~t Aplies to limits on reactor coolant Applies to trip settings of the system pressure instruments and devices which are provided tn prevent the reactor system safet'y limits from being exceeded.

Ol'Jecttvc ~OO ecctve Tv establish a limit below which To define the level of the process the integrity of the reactor coolant variables at which automatic pro-system's not threatened due to an tective action is initiated to overp: essure condition'. prevent the pressure safety limit from being exceeded.

S ecif ication S ecificatinn A. The pressure at the lowest point The limiting safety system settings of the reactor vessel shall not shall be as specified below:

exceed 1,375 psig whenever irradiated fuel is in the reac- Limiting Safety tor vessele Protective Action S stem- Settin

h. Nuclear system 1,230 psig safety valves + 13, psi,(2 open nuclear valves) system pressure B. Nuclear system 1,080 psig +

relief valves 11 psi (4 open--nuclear valves) system pressure 1,090 psig +

11 psi (4 valves) 1, 100 ps ig +

ll psi (3 valves)

C. Scram nuclear c 1,055 psig system high pressure 27

1. 2 BASES REACTOR COOLAHT SYSTEM INTEGRITY te safety limits for the reactor coolant system pressure have been select:ed s tch that they are below pressures at which it can be shown that the integrity nf the system Is noc endangered. However, t,hc pressure safety limit.'s are s'.t high enough such that no foreseeable circumstances can cause the system pressure to rise over these limits. The pressure safety limits are arbit:rarily selected to be the lowest transient overpressures allowed by the applicable "odes, ASHE Boiler and Pressure Vessel Code, Section III, and USAS Piping

)de, Section 831.1.

'tne design pressure (1,250 psig) of the reactor vessel is established such chac, when che 10 percent allowance (125 psi) allowed by the ASME Boiler and Pressure Vessel Code Section III for pressure transients ls added 'to thc design prc8sure, s transient pressttre limit of 1,375 psig is established.

Correspondingly, the design pressure (1,148 psig for suction and 1,326 psig for discharge) of the reactor recirculation system piping are such that, when the 20 percent allowance (230 and 265 psi) allowed by USAS Piping Code, Section B31.1 for pressure. transient:s arc added to the design pressures, transient pressure limits of 1,378 and 1,591 peag are established. Thus, the pressure safety limit applicable to power operation is established at 1,375 psig (the loucst transient overpressure allowed by the pertinent codes),

ASME Boiler and Pressure Vessel Code,Section III, and USAS Piping Code, Section B31.1.

The Plant Safety Analysis (paragrsph 14.5.1) states tlisc the turbine trip from high power without bypass ie the most severe abnormal operatioital tran-sient resulting directly in a reactor coolant system pressure increase. The reactor vessel pressure code limit of 1,375 psig given in subsecrion 4.2 of rhc safety analysis rcport: is uel'1 above the peak prcssure produced by the overpressurc transient described above. Thus, the pressure safety limit appli cable co power operation is well above t: he peak prcssure that can result duc co reasonably. expected overpressure transients.

lligher design pressures have been established for ptping within the reactor coolant system than for the reactor vessel, These increased design pressures create a cons'istenc design which assures that, if the pressure within t.he reactor vessel does not exceed 1,375 psig', the pressures within the piping cannot exceed their respective transient pressure limits due to static and pump heeds.

The safety limit of 1,375 p sig accuallv applies to any point in the reactor vessel; houever, because of the static water head, che highest pressure point vill occur ac the bottom of the vessel. Because the ptcssure is not monitored at this point, it cannot be directly determined if chis safety limit has been violated. Also, because of the potentially varying head level and flow pres-sure drops, an equivalent p ressure cannot be a priori determined for a

1. 2 BASES pressure monitor higher in thc vessel. Therefore, following any transient that is severe enough to cause concern that this afety limit was violated,

.a calculation will be performed using all available information to deter-mine if the safety limit vas violated.

REFERENCES

1. Plant Safety Analysis (BFNP FSAR Section 14.0)

2. ASME BoiIer and Pressure Vessel Code'Section III

3. USAS Piping Code, Section B31.1

4. Reactor Vessel and Appurtenances Mechanical Design (BFHP FSAR Subsect ion 4.2) 29

2.2 BASES REACTOR COOIANT SYSTEM INTEGRITY The pressure relief system for each unit at the Browns Ferry Nuclear Plant has been sized to meet two design bases. First, the total safety/

relief valve capacity has been establisheQ to meet the overpressure pro-tection criteria, of the ASME Code. Second, the Qistribut.ion of this requ red capacity between safety valves anQ relief'alves ha., been set to meet design basis 4.4.4-1 of subsection 4.4 which states that the nuclear system relief valves shall. prevent opening of the safety valves during normal plant isolations and load regections.

Tne detai' of the analysis which gP0gg compliance with the A"ME Code requirements is presented in subsection 4.4 of the FSAR and the Reactor Vessel Overpressure Protection Smmnary Technical Report submitted in response to question 4.1 dated December 1, 1971.

Thirteen safety-relief valves have been installed on each unit with a total capacity of 74fn of design steam flow. The analysis of the worst overpressure transient, (3-second closure of all main steam line isola-tion valves) neglecting the direct scram (valve position scram) results in a maximum vessel pressure of 1303 psig if a pressure scram is a sumed or 1260 psig if a neutron flux scram is assumed. This results in 72 psig and 115 psig margins respectively to the code allowable overpres use limit of 1375 psig. In addition, the same event was analyzed to determine the number of installed valves which must open to limit peak pres ure to 1350 psig (25 psig margin). The results of this analysis show" that seven valves must open if a neutron flux scram is assumed or ten valves must if a pressure scram is assumed.

open To meet the second design basis, the total safety-relief capacity of 74':

has"been divided into 6lg relief (ll valves) and 13'". safety (2 valves).

Tne analysis of the plant isolation transient (turbine trip with bypass valve failure to open) assuming a turbine trip scram is presented in FSAR paragraph 14.5.1.2 and Figure 14.5-1. This analysis shows that the relief valves limit pressure at the safety valves to 1168 psig, well ll below the setting of the safety valves. Therefore, the safety valves will not open. This analysis shows that peak system pressure is limited to 1210 psig which is 165 psig below the allowed vessel overpressure of 1375 psig.

30

LIMITING CONDITXONS POR OPERATION SURVEILLANCE RE UIREHENTS 3.1 REACTOR PROTECTXON SYSTEM 4.1 REACTOR PROTECTXON SYSTEM A licabilit A licabilit Applies to the instrumentation Applies to the surveillance of and associated devices which the instrumentation and asso-initiate a reactor scram. ciated devices which initiate reactor scram.

Ob. ective ~Ob ective To assure the operability of the To specify the type and frequency reactor protection system. of surveillance to be applied to the protection instrumentation.

S ecification S ecification When there is fuel in the vessel, A. Instrumentation systems shall the setpoints, minimum number of be functionally tested and trip systems, and minimum number calibrated as indicated in of instrument channels that must Tables 4.1.A and 4.1.B respec-be operable for each position of tively.

the reactor mode switch shall be as given in Table 3.1.A. B. Daily during reactor power operation at greater than or equal to 25% thermal power, the maximum total peaking factor shall be checked and the scram and APRM Rod Block settings given by equations in specifications 2.1.A.

and 2.3..B shall be calculated.

C. When it is determined that a channel is failed in the unsafe condition, the other RPS channels that monitor the same variable shall be functionally tested immediately before the trip sys-tem containing the'failure is tripped. The trip system con-taining the unsafe failure may be untripped for short periods of time to allow functional testing of the other trip system. The trip system may be in the untripped position for no more than eight hours per functional test period for this testing.

31

PAGE DELETED 32

ThBLE 3.loA INSTRUMENTATION REQUIREMENT REACTOR PROTECTION SYSTEM (SCRAM)

Min. No.

of Operable Inst. Modes in Which Function Channels Must Be 0 erable Per Trip Shut- Startup/Hot Tri Function Tri Level Settin System (1) ~Action l 1 Mode Svitch in Shutdown l.h 1 Manual Scram 1.A IRR (16)

~n scaleIndicated H ig h .Flux

< 120/125 (5) 1.h Inoperative 1.A (5)

APRR (16) 2 High Flux See Spec. 2.1.A.l 1.A or 1.B X

2 High Flux < 152 rated power 1.A or 1.B 2 Inoperative (13)

X X(17) (15)

X X 1.h or 1.B 2 Downscale + 3 Indicated on Scale (11) 1.A or.l.B (11) X(12)

High Reactor Pressure < 1055 psig X(10) 1.A X X 2 High Dryvell < 2 psig Pressure (14) X(8) X Reactor Lov Water > 538" above vessel zero Level (14) -x x High Water Level in Scram < 50 Ga1.iona Discharge Tank X(2) K l.h

TABLE 3.1.A (Continued)

Min. No.

of Operable Modes in Which Function Inst. Must Be 0 erable Channels Per Trip Startup/Hot

~Ss tern 1 Tri Level Settin Run Action 1 Main Steam Line Isolation < 10K Valve Closure X(3)(6) X(3)(6) X(6) 1.A or 1.C Valve Closure Turbine Cont. Valve Fast Upon trip of the fast X(4) X(4) X(4) 1.A or 1.D Closure acting solenoid valves 4 Stop Valve Closure < lOX Va'lve Closure X(4) X(4) X(4) 1.A or 1.D

urbine Control Valve- > 550 psig X(4) X(4) X(4) 1.A or 1.D Loss of Control Oil Pressure

urbine First Stage < 154 psig X(18) X(18) X(18) (19)

Pressure Permissive

.urbine Condenser Low > 23 In. Hg, Vacuum X(3) X(3) 1.A or 1.C Vacuum l:tain Steam Line High < 3X Normal Full Power X(9) X(9) X(9) 1.A or 1.C

".-.adiation (14) Backg'round (20)

NOTES FOR TAPLK 3.1.A

l. There shall be tMo operrble or tripped trip systems for each function.

If the minimum number of op rable instrument channels per trip system cannot be met for both trip systems, the appropriate actions listed below shall be taken.

A. Initiate insertion of operable rods and complete insertion of all operablc rods within four hours.

B. Reduce power level to IRN range and place mode switch in the StartupiHot Standby position within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

C. Reduce turbine load and close main steam line isolation valves within 8 hours.

D. Reduce power to less than 30X of rated.

2. Scram dfscharge volume high bypass may be used in shutdown or refuel to bypass scram discharge volume scram with control rod block for reactor protection sys'em reset.

3. Bypassed if reactor pressure < 1055 psig and mode switch no- in run.

4. Bypassed when turbine first stage pressure is less than 154 psig.

t

5. IRH's are bypassed vhen APRM's are onscale and the reactor mode switch is in the run position.

6. The design permits closure of any two lines without a scram being initia ted.

7. When the reactor is subcritical and the reactor water temperature is less than'12 F, onlv the following trip functions need to bs operable:

A. Mode switch in shutdown

8. Manual scram C. Iligh flux IRM Q. Scram discharge volume high level E. APRM 15X scram

8. Not required to be operable when primary containm'ent integrity is not required.

9. Not required if all main steamlines are isolated.

3S

10. Hot required to be operable when the reactor pressure vessel

'head is not bolted to the vessel.

11. The APRN downscale trip function is only active when the reactor mode switch is in run.

12, The APRM downscale trip is automatically bypassed when the IRH instxumentation is operable and not high.

13. Less than 14 operable LPRN's will cause a trip system trip.

10. Channel shared by Reactor protection system and Primary Containment and Reactor Vessel Isolation Control System. A channel failure may be a channel failure in each system.

15. The APRN 15% scram is bypassed in the Run Mode.

16. Channel shared by Reactor Protection System and Reactor Manual Control System (Rod Block Portion) . A channel failure may be a channel failure in each system.

17. Not required while performing low power physics. tests at atmospheric pressure during or after refueling at power levels not to exceed 5 MW(t) .

18. Operability is required when normal first-stage pressure is below 30~ (< 154 psig).

19. Action 1.A or 1.D shall be taken. only if the permissive fails in such a manner to prevent the affected RPS logic from performing its intended function. Otherwise, no action is r equired.

20. An alarm setting of 1.5 times normal background at rated power shall be established to alert the operator to abnormal radiation levels in primary coolant.

TAILE 4.1.h REACTOR PROTECTION SYSTEM (SCRAM) INSTRUMEfThTION FUNCTIONAL TESTS MINIMUM PUNCTIONAL TEST FREQUENCIES POR SAFETY INSTR. AND CONTROL CIRCUITS Punctional Test Minimum Frequency (3)

Node Switch in Shutdown Place Mode Switch in Shutdown Each Refueling Outage Manual Scram Trip Channel and Alarm Every 3 Months IRM High Flux Trip Channel and Alarm (4) Once Per Meek During Refuelin

] and Before Each Stsrtup 4

Inoperative Trip Channel aad Alarm (4) Once Per Meek During Refuelin and Before Each Startup APRM High Plux (ISI scram) Trip Output Relays (4) Before 'Each Startup and Meekl Mhen Required to be Operable High Plux Trip Output Relays (4) Once/Meek Inoperative Trip Output Relays (4) Once/Meek Downscale Trip Output Relays (4) Oace/Meek Plow Bias (6) (6)

High Reactor Pressure Trip Channel and ALarm Once/Month (1)

High Drywell Pressure Trip Channel and Alarm Once/Month (1)

Reactor, Low Mater Level (Sj Trip Chaaael aad Alarm Once/Month (1)

High Mater Level in Scram Discharge Tank Trip Chaanel and Alarm Every 3 Months

.Turbine Condenser Low Vacuum Trip Chanael and hlarm Oace/Month (1)

Mein Steam Line High Radiation Trip Channel and Alarm (4) Once/Meek

TABLE 4.1.A (Continued)

~csou (2) Minimum Pre uenc 3>

Main Steam Line Esolation Valve Closure A Trip Channel and Alarm Once/Month (')

Turbine Control Valve Past Closure Trip Channel and 'Alarm Once/Month (1)

Turbine Control Valve - Loss of Oil Pressure A Trip Channel and Alarm Once/Month (1)

Turbine First Stage Pressure Permissive A Trip Channel and Alarm Every > Months Turbine Stop Valve Closure Trip Channel and Alarm Once/Month (1)

l. Initially the minimum frequency ior the indicated tests shall be once per month.

2. A description of the. three groups is .included in the Bases of this specification-.

3. Functional tests are not required when the systems are not required to be operable or are operating (i.e., already tripped). If tests are missed, they shall be performed prior to returning the systems to an operable status.

4. This instrumentation is exempted from the instrument channel test definition. This instrument channel functional test will consist of infecting s simulated elec" rical signal into the measurement channels.

5. The water level in the:eac tor vessel vill be perturbed and tha corres-ponding level indicator changes vill be monitored. This perturbation test will be performed every month sf ter completion of the monthly functional test program.

6. The functional test of the flow bias network is performed in accordance with Table 4.2.C.

39

TABLE 4!.1.S RPgCTOR ) Rr!TEC TIf)N SySTE2{ (SC=;'{) INSTRL'..",NT C<IBRATIf).'!

){14IHL){ CALIBRATION FREqUENCIES POR REtCTOR )'ROTECf ION ..'{STRM.{T CMNELS Instrument Cl!a!!nel 0 rou a 1 i Ca 1 b r w F F .'ifntmnn F>>" '"n.v (2)

IR.'{ High Flux Co!F!parison to APR.". on Control- Note (4) led Shutdowns ("'}

APR~ High Flux Output Signal Heat Balance Once every <<ays Plov Bias Sipnal Calibrate Flov Bias Signal (7) Once/opera inS cycle

'B.'{ Signal TIP System ;raverse Every 1000 Effective Pull Poster H" rs High Reactor Pressure Standard Presser" Source Every 3 Hon hs High Dry!tell Pressure Standard Press -. Source Every 3 Ho= '.;s Reactor Lo!t {later Level Pressure Standar" Every 3 Non hs

)l{gh Mater Level in Scram Discharge Volume A Note (5) Note (5)

Turbine Condenser Lect Vacuum Standard Vacuum Source Every 3 !{on"hs Hai>> S tea Line Isolation Valve Closure Note (5) Note (5)

.!ain Steam I ine ){igl[ Radiation S andard Curren Source (3) Every 3 Mon.!.s Turbine Yirsc Stage Pressure Permissive A Standard Pressure Source Every 6 hoat!!s Turbine Control Valve - Loss of Oil Pressure A Standard Pressure Source Once / ope-e ng cycle Turbine Stop Valve Closure Note (5) Note (5)

NOTES FOR TABLE 4,1.B

1. A description of three groups is included in the bases of this specification.

2. 'Calibrations are not requir'ed when the systems are not required to be operable or are tripped. If calibrations are missed, they shall be performed prior to returning the'system to an operable status.

3. The current source provides an "instrument channel alignment. Cali-bration using a radiation source shall "be made each refueling outage.

4. Maximum frequency required is once per week.

5. Physical inspection and actuation of these position switches, will be performed once per operating cycle.

6. On controlled shutdowns> overlap between the IRH's and APRM's will be verified.

The Flow Bias Signal Calib"ation will consist of calibrating the sensors, flow converters, and signal offset networks during each operating cycle. The instrumentation is an analog type with redun-dant flow signals that can be compared. The flow comparato" trip and upscale will be functionally tested according to Table 4.2;C to ensure the proper operating during the operating cycle. Refer to 4.1 Bases for further explanation of calibration frequency.

41

3. I 8ASES The 1.

2.

reactor protection system automatically initiates Preserve Preserve the the I'ntegrity of the fuel cladding.

integrity nf a

the reactor coolant system.

reactor scram to:

0

3. Minimize the energy which must be absorbed folloving a loss of coolant accident, and prevents criticality.

This specification provides the limiting conditions for operation necessary co preserve the ability oi the system to tolerate single failures and still perform its intended function even during periods when instrument channels may be out of service because of maintenance. When necessary, one channel may be made inoperable for brief intervals to conduct required functional "cats and calibrations.

The reactor protection system is made up of two independent trip systems (refer to Section 7.2, FSAR). There are usually four channels provided to.

monitor each critical parameter, with two channels in each trip system.

The outputs of the channels in a trip system are combined in a logic such

'that either channel trip vill trip that trip system. The simultaneous tripping of both trip systems will produce a reactor scram.

This system meets the intent of IKEE - 279 for Nuclear Power Plant Protec-tion Systems, The system has a reliability greater than that of a 2 out l

of 3 system and somewhat less than that of a out of 2 system.

With the exception of the Average Power Range Monitor (APRM) channels, the Intermediate Rang>> Monitor (IRM) channels, the Hain Steam Isolation Valve closure and the Turbine Stop Valve closure, each trip system logic has one in>>trument channel. When the minimum condition for operation on the number ot operable Instrument channels per untzipped protection trip system is met or if it cannot be met and the effected protection trip system is placed in a tripped condition, the ef fectiveness of the protection system is preserved still i.e., thc system can tolerate a single failure and perform its intended function of scramming the reactor. Three ApRM instrument channels are pro-vided for each protection trip system.

Each protection trip system has one more APRM than is necessary to meet the minimum number required per channel. This allows the bypassing of one APRM per protection trip system foz maintenance, testing or calibration. Addi-tional IRM channels have also been provided to allow for bypassing of one such channe'. The bases for the scram setting for the IRH, APRM, high reac" tor pressure, reactor Iow water lovel, HSIV closure, turbine control valve fust closure, turbine stop valve closure and loss of condensez vacuum are discussed In Specif ication 2.1 and 2.2.

Bus Es Instrumentation (pressure switches) or the drywel1 are provided to detect a loss of coolant accident and initiate the core standby cooling equipment.

A high drywell pressure scram is provided at the same setting as the core cooling systems (CSCS) initiation to minimize the energy which must be accommodated during a loss of coolant accident and to prevent return to criticality. This instrumentation is a backup to the reactor vessel water level instrumentation.

High radiation levels in the main steam line tunnel above that due to the normal nitrogen and oxygen radioactivity is an indication of leaking fuel.

A scram is initiated whenever such radiation level exceeds three times normal background. The purpose of this scram is to reduce the source of such radiation to the extent necessary to prevent release of radioactive material to the turbine. An alarm is initiated whenever ther radiation level exceeds 1.5 times normal background to alert the operator to possible serious radioactivity spikes due to abnormal core behavior. The air ejector off-gas monitors serve to back up the main steam line monitors to provide urther assurarce against release o radioactive materials to site environs by isolating the main condenser off-gas line to the main stack.

A reactor mode switch is provided which actuates or bypasses the various scram functions appropriate to the particular plant operating status.

Ref. Section 7.2.3.7 FSAR.

The manual scram function is active in all modes, thus providing for a manual means of rapidly inserting control rods during all modes of reactor operation.

The IRM system (120/125 scram) in conjunction with the APRM.system (15',l scram) provides protection against excessive power levels and short reactor periods in the s artup and intermediate power ranges.

The control rod drive scram system is designed so that all of the water which is discharged from the reactor by a scram can be accommodated in the discharge piping. The discharge volume tank accommodates in excess of 50 gallons of water and is the low point in the piping. No credit was taken for this volume in the design of the discharge piping as concerns the amount of water which must be accommodated during a scram. During normal operation the discharge volume is empty; however, should it fill with water, the water discharged to the piping from the reactor could not be accommodated which would result in slow scram times or partial control rod insertion. To preclude this occurrence, level switches have been provided in the instrument volume which alarm and scram the reactor when the volume of water reaches 50 gallons. As indicated above, there is sufficient volume in the pioing to accommodate the scram without impairment of the scram times or amount of insertion of the control rods. This function shuts the reactor down while sufficient volume remains to accommodate the discharge water and precludes the situation in which a scram would be required but not be able to perform its function adequately.

A source range monitor (SRM) system is also provided to supply additional neutron level information during startup but has no scram functions. Ref.

Section 7.5.4 FSAR. Thus, the IRN is required in the Refuel and Startup 43

modes. In the power range the APRM system provides requ'red protection.

Ref. Section 7.5.7 PSAR. Thus, the IRM System is no't required in the Run mode. The APRM's and the IRM's pzovida adequate coverage in the startup and intermediate range.

The high reactor pressure, high drywell pressure, zeactor low water level and scram. discharge volume high, level scrams are required for Startup and Run modes of plant operation. They are, therefore, required to be opera-tional for these modes of reactor operation.

The requirement to have the scram functions as indicated in Table 3.1.1 operable in the Refuel mode is to assure that shifting to the Refuel mode during reactor power operation does not diminish the need for th'e reactor protection system The turbine condenser low vacuum scram is only required during power operation and must be bypassed to start up the unit. Belo~ 15'sig tur-bine fizat stage pressure (30X of rated), the scram signal due to turbine stop valve closure, turbine control valve fast closure, and turbine con-trol valve loss of control oil pressure, is bypassed because flux and pressure scram are adequate to pzotact the reactor.

Because of the APRM downscale limit of > 3X when in the Run mode and high level limit of < 15X when in the Startup Mode, the transition between the Startup and Run Modes must ba made with the APLN lnstzumentntioa indicnting between 3X and 15X of rated powez or a control rod scram vill occuz. In addition, the IRM system must be indicating below the High Flux satting (120/125 of scale) or a scram will occur when in the Startup Mode. Por normal operating conditions, these limits provide assuzance of overlap between the IRM system and APRM system so that theza are no "gapa" in the power level indications (i.e., the power level is continuously monitored

!rom beginning of startup to full power and from full power to shutdown).

4'hen power ie being reduced, if a transfer to ths Startup mode ia made and the IRM's have not been fully inserted (a maloperationa'ut not impossible condition) a control rod block immediately occurs so that reactivity ~mssz-tion by control rod withdrawal cannot occur.

4.1 BASES The miniraun functional testing frequency used in this specification is based on a reliability analysis using the concepts developed in reference (1). This concept was specifically adapted to the one out of tvo taken tvice logic of the reactor protection system. The analysis shovs that the sensors are primarily responsible for the reliability of the reactor pro>>

taction system. This analysis makes use of "unsafe failure" rate experi-ence at conventional ond nuclear pover plants in a reliability model for the system. An "unsafe failure" is define as one vhich negates channel operability and which, due to its nature, is revealed only when the channel is functionally tested or attempts tn respond to a real signal. Failures such as blown fuses, ruptured bourdon tubes, faulted amplifiers, faulted cables, etc., which result in "upscale" or "downscale" readings on the reactor instrumentation are "safe" and vill be easily recognized by the operators during operation because they are revealed by an alarm "or a scram, The channels listed in Tables 4.1.A and 4.1.B are divided into three groups

.'or functional tes ting. These are:

On-OEE sensors that provide a scram trip function.

B. Analog devices coupled vith bi-stable trips that provide a scram function.

C. Devices which only serve a useEul function during some restricted mode of operation, such as startup or shutdovn, or for vhich the only practical test is one that can be performed at shutdovn.

The sensors that make up group (A) are specifically selected from among the whole family of industrial on-off sensors that have earned an excellent reputation for reliable operation. During desigp, a goal of 0.99999 pro-bability of success (at the 50Z confidence level} vas adopted to assure that a balanced and adequate design is achieved. The probability of success is primarily a function of the sensor failure rate snd the test interval.

A three-month test interval was planned for group (A) sensors. This is in l eeping with good operating practices, and satisfies the design goal for the logic configuration utilized in the Reactor Protection System.

To satisxy the long-term ob)ective of maintaining an adequate level of safe ty throughout the plant lifctime, a minimum goal of 0. 9999 at the 95Z confidence level is proposed. Mith the (1 out of 2) X (2) logic, this requires that each sensor have an availability of 0,993 at the 95Z confi-dence level. This level of avail. ability may be maintkined by ad)usting the test interval as a Eunction of the observed failure history. (l)

l. Reliability of Engineered Safety Features as a Function of Testing Frequency, I. H. Jacobs, "Nuclear Safety," Vol. 9, No. 4, July-August, 1968, pp, 310-312.

45

4. 1 BASES To facilitate the implementation of this technique, Figure 4.1.1 is pro-vided to indicate en appropriate trend in test interval. The procedure is as follows:

1, Like sensors are pooled into one graup for the purpose of data acquisition.

2. The factor M is the exposure hours and is equal'o the number of sensors in a group, n, times the elapsed time T (M nT) .

3. The accumulated number of unsafe failures is plotted as an ordinate against M as an abscissa on Figure 4.1.1.

4. After a trend is established, the appropriate monthly left test interval to satisfy the goal will be the teat interval to the of the plot tcd points.

5. A test interval of one month will generally be used initially until a trend is estabLished.

Group (B) devices utilize cn analog sensor followed by an amplifier and a bi-stable trip circuit. The sensor and amplifier are active components and a failure is almost always accompanied by an alarm and an indication of the source of trouble. In the event of failure, repair or substitution can start immediately. An "ss-is" failure is one that "sticks" mid-scale and is not capable of going either up or down in response to an out-of-limits input. This type of failure for analog devices is a rare occurrence and is detectable by an operator who observes that one signal does not track the other three. Por purpose of analysis, it is assumed that this rare failure will be detected within two hours.

The bi-stable trip circuit which is a part of the Group (B) devices can sustain unsafe failures which are revealed only on test. Therefore, it is necessary to test them periodically.

A study wae conduct<<; I oE the instrumentation channels included in the Group (B) <levice<< to calculate their "unsafe" failuro rates. The analog devices (sensors and ampli]iers) are predicted to have an unsafe failure rate of lese than 20 x 10 failure/hour. The bi-stable trip circuits are predicted to have unsafe failure rate of less than 2 x 10 failures/hour.

Considering the two hour monitoring interval for the analog devices as.

assumed above, and a weekly test interval for the bi-stable trip circuits, the design reliability goal of 0.99999 is attained with ample margin.

The bi-stable devices are monitored during plant operation to record their failure history and establish a test interval using the curve of Figure 4.1.1. There are numerous identical bi-stable devices used throughout the plant's instrumentation system. Therefore, significant data on the failure rates for the bi-stable devices should be accumulated rapidly.

The frequency of calibration of the APRM Plow Biasing Network has been established as each refueling outage, There are several instruments

~hich must be calibrated and it will take several hours to perform the calibration of the entire network. Mh),le the calibration is being per-formed, a zero flow signal vill be sent to half of the APRM's resulting in a half scram and rod block condition. Thus, if the calibration were performed during operation, flux shaping would not be possible. Based on experience at other generating stations, drift of instruments, such as those in the Plow Biasing Network, is not significant and therefore, to avoid spurious scrams, a calibration frequency of each refueling out-age is established.

Croup (C) devices are active only duzing a given portion of the opera-tional cycle. For example, the IRM is active during startup and inactive during full-power operation. Thus, the only test that is meaningful is the one performed )ust prior to shutdown or startup; i.e., the tests that are performed )ust prior to use of the instrument.

Calibration frequency of the instrument channel is divided into two groups. These are as follows:

1. Passive type indicating devices that can be compared with like units on a continuous basis.

2. Vacuum tube or semiconductor devices and detectors that drift or lose sensitivity.

Experience with passiv 'ype instrument's in generating stations and sub-stations indicates that the specified calibrations are adequate. For those devices which employ amplifiers, etc., drift specifications call for drift to be less than 0.41/month; i.e., in the period of a month a diift of .4X would occur and thus providing Eor adequate margin. Nor the APRM system drift of electronic apparatus is not he only considera-tion in determining a calibration frequency. Change in power distribu-tion and loss of chamber sensitivity dictate a calibration every seven days. Calibration on this Erequency assures plant operation at or below thermal limits.

A comparison of Tables 4.1.A and 4.1.B indi.cates that two instrument channels have not been included in the latter table. These are: mode switch in shutdown and manual scram. All of the devices or sensors associated with these scram functions are simple on-of E switches and.

hence, calibration during operation is not applicable, i.e., the switch is either on. or off.

The maximum total peaking factor shall be checked out once per day to determine if the APRM scram requires ad]ustment. This will normally be done by checking the LPRM 'readings. Only a small number of control rods are moved daily 47

4.1 BASES during ste'ady-state operation and thus the peaking factors are not expected to change stem l~ Irnut'lv.

The sensitivity of LPRf detectors decreases with exposure to neutron flux at a slow and approximately constant rate. This is compensated for in the APRM system by calibrating every 7 days using heat balance data and by calibrating individual IPRM's every 1000 effective full-power hours using TIP traverse data.

48

18 M~ nT n ~ NUMBER OF IOKNTICAL COMPONENTS T ~ INSTRUMENT OPER'ATING HOURS I MONTH 2 MONTHS 3 MONTHS 6 MONTHS I

3 4 5 6 7 8 910 31567891 M FACTOR 8ROWHS FERRY HUCLEAR PLAHT FIHAL SAFETY AHALYSIS REPORT Graphical Aid in the Selection of an Adequate Tests Intcrva'etween Figure 4.1-1

LI.R ITIHO COHO ITIOHS FOR *OPERATION SURVFILLANCE RE UIREHFNTS 3e2 PROTtCTIVE IHSTRUMENTATION 4. 2 PROTECTIVE INSTRlMENTATION A 1 icabilit A licabilit Applies to the plant instrumen- Applies to the surveillance re-tation which initates and con- quirement of the instrumentation trols a protective function. th'at initiates and controls pro-tective functi'on.

~nb ective ~Ob ective To assure the operability of To specify the type and frequency pro tec tive instrumentation. of surveillance to be applied to protective instrumentation.

S ecification A. Primar Containment and Reactor Buildinv Isolation Functions Buildin Isolation Functions When primary containment inte- Instrumentation shall be func-gr l.ty is required, the limiting tionally tested and calibrated conditions of operation for the as indicated in Table 4.2.A.

instrumentation that initia tes primary containment isolation System logic shall be function-are given in Table 3.2.A. This ally tested as indicated in "

includes instrumentation that Table 4.2.A.

initiates isolation of the reac-tor vessel, reactor building, main steam lines, and initiates th. standby gas treatment system.

II. Core end Containment C~oolin B. Cor e and Containment Coo 1 in S stems - Initiation & Control The limiting conditions for Instrumentation shall be func-operation for the instrumenta- tionally tested, calibrated and tion that initiates or controls checked as indicated in Table the core and containment cooling 4.2.B.

systems are given in Table 3.2.B.

This instrumentation must be System logic shall be function-operable when the system(s) it ally tested as indicated in initiates nr controls are re- Table 4.2.B.

quired to be operable as speci-fied in Section 3. 5. Whenever a system or loop is made inoperable because of a required tes t or calibration, the other systems or loops that 50

LIHITINC CONDITIONS FOR OPERATION SURVEILLANCE RZ UI~HNTS 3 2,B Core and Containment Coolin 4.2.B Core and Containment Coolin S stems - Initiation b Control S stems - Initiation 6 Control are required to ba operable shall bo considc ed operable fare if th y are within the required surveil-lance testing frequency and there is no reason to suspect that they inoperable.

C. Control Rod Dlock Actuation C. Control Rod Block hctuation

l. The limiting conditions of Instrumentation shall be function-operation for the instrumen- ally tested, calibrated and checked tation that initiates control as indicated in Table 4.2,C.

rod block are given in Table 3,2,C. System logic shall be functionally teated as indicated in Table 4.2.C.

2. The minimum number ot operable instrument channels specified in Table 3.2.C for the Rod Block Monitor msy be reduced by one in one of the trip systems for tern maintenance and/or testing, pro-vided that this condition does not last longer than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any thirty day period.

Off-Gas Post Treatment Isolation Off-Gas Post Treatment Isolat'on Punction Functions

l. Off Gas Post Treatment Monitors Off-Gas Post Treatment Monitorin

~Ss (a) Except as specified in (b) Instrumentation shall be func-belov, both off-gas tionally tested, calibrated and post treatment radiation checked aa indicated in Table monitors shall be operable 4.2.D.

during reactor operation.

The isolation function System logic shaU, be 'unction-trip settings for the ally tested as indicated in monitors shall be set nt Table 4.2.D.

a value not to exceed the equivalent oi the stack release limit specified in specification 3.8:B.l.

LIN TINC CONDITIONS FOR OPERATION SRVXILLANCE RE IREMENTS 3.2.D Off-Gas Post Treatment Xso1atfon .2.D Off-Ges Post Treatment Isolation Functions Function (b) Tram and after the date that one of the.two off gss post treatment radfatian monitors fs made or found to be fnoparable, continued reactar power'peration fs permissible during the nex seven days, provided that the inoperable monitor fs tripped in the downscale posiCfon. One radiation modftor may ba out at service for four hours for,functional teat and/

or calibration without the monitor b'aine fn a downscale tripped condition.

(c) Upon the loss of both off-ges post treatment radia-tion monitors, initiate en orderly shutdown and shut the mainsteam isolation valves or the off-gas isolation valve within 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. ell etio E. D ell Leak Detection E< D Loan DeC The limiting conditions, of opera- Instrumentation ahall ba calibrated tfon for the fnstzumencatfan that and checked aa indicated fn Table monitors drywall leak detection 4>2.X.

are given in Table 3.2.E.

t, Survefllance Instrumantatfon Pi gurvefllanco Inst ncatfon The limiting conditions far the Inatrunentatfon shall be calibrated inatzumencacfon that prov'das and checked ao fndfcated fn Tabla surveillance information readouts 4.2.7i are given fn Table 3,2.l.

0. Can ral Roon Icola Cfan 0< ConCr Aoam I oint The lfaftfng candftfans for Instrumencatian shall be mlfbracsd I

inetrumentatfon chat tsolacee and chsckod <<s indicated in Table tha control rona and fniciatea 4e2ioe the control roon emergency pressuzitacfon systems ara given in Table 3.1,0.

LIMITINC CONDITIONS FOR OPERATION SURYEILLANCE RE UIREHENTS 3.2.8 Flood Protection 4e2.H Flood Protection The .unit shall be shutdown and Surveillance shall be performed placed in the cold condition on the instrumentation that when Wheeler Reservoir lake monitors the reservoir level as stage rises to a level such indicated in Table 4.2.H.

that water from the reservoir begins to run across the pumping station deck at elevation 565.

Requirements for instrumentation that monitors the reservoir level is given in Table 3.2.H.

3.2.I Meteorolo cal Monitorin 4.2.I Meteorolo ical Monitorin Instrumentation Instrumentation The meteorological monitoring instru- Each meteorological moni oring instrument mentation listed in table 3.2.I shall be channel shall be demonstrated operable operable at all times. by the performance of the CKQCKL CHECK at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and the CHVKr

l. With the number of operable CALIBRATION at least once each 6 montns.

meteorological monitoring channels less than required. by table 3.2.I, t

restore the inoperable channel(s) to operable status within 7 days.

2. With one or more of the meteoro-logical monitoring channels inoperable for more than 7 days, prepare and submit a Special Report to the Commission, pursuant to specification 6.7.3.D within the next 10 days outlining the cause of the malfunction and the plans for restoring the system to operable status.

53

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.2.J Seismic Monitorin Instrumentation 4.2.J Seismic Monitorin Instrumentation

l. The seismic monitoring instruments l. Each of the seismic monitoring instru-listed in table 3.2.J shall be ments shall be demonstrated operable operable at all times. by performance of tc ts at the frequencies listed in table 4.2.J.

2. With the number of seismic monitoring instruments less than the number 2. Data shall be retrieved from all listed in table 3.2. J, re "tore thc sci smic i n st rument s actuated

inoperable instr<mient(n) to opcrabI c clurin)::i >>c'is>nic <<veal >>>>d>>>>alyxcd status withi>> 30 day". 4o dc),chemi>>c the rnag>>itudc of ),)ic vibratory ground motion. A Special

3. With one or more of the instruments Report sha13 be submitted to the listed in table 3.2.J inoperable for Commi.ssinn pursuant to specification more than 30 days, submit a Special 6.7.3. D within 10 days describing Report to the Commission pursuant to the magnitude, frequency spectrum, specification 6.7.3.C within the next and re. ultan); effect>>pon plant 10 days de cribing the cause of the features .important to s:i)'cty.

malfunction and plans for restoring the instruments to operable status.

TABLE 3.2.A PRD{ART COHTAINMEHT AND REACTOR BUILDING ISOLATION INSTRUMEHTATTON Minimum No.

Operable Per Tri S e 1 Punction Tri Level Sett in Action 1 Remarks Iastrumeat Chaanel- > 538" above vessel sero h or l. Belov trip setting does the Reactor Lov Mater Level (6) (B and-E) folloving:

a. Initiates Reactor Building Isolation

b. Initiatee Primary Containment Ieolatioa Co Initiatee SOTS lastrLsseat Chaanel- 100+ psig l. Above trip settiag isolates the Reactor High Pressure 15

'f shutdovn cooling suction valves the RHR system.

Instrument Chaanel- >> 490" above vessel xero. 1. Belov trip setting initiatee Main Reactor Low Mater Level Steam Line Isolation (LZS-3-56A-D, m fl)

Instrument Chaaael- < 2 psig h or 1 Above trip settiag does the High Dryvell Pres'sure (6) (B and E)- 'olloviag:

(PS-64-56A-D) a. Zaitiatea Reactor Building Isolatioa

b. Iaitiatee Primary Containment Isolatioa

c. Iaitiates SCTS Instrument Chaanel- < 3 times normal rated 1. Above trip setting iaitiatee Main High Radiatioa Main Steam full pover background Steam Liae Isolation Line Tunnel (6)

Instrument Channel - > 825 psig (4) 1. Belov trip setting iaitiatee Main Lcw Pressure Main Steam Steam Line Isolation Line 2(3) Instrument Channel 140Z of rated steam floe l. Above trip setting initiates Main High Flov Main Steam Line Steam Line Zsolation

TABLE 3.2.A (Continued)

Minimum No.

Operable Per S s (1) Function iri Level Settle ~Action L) Remarks Instrument Channel < 200 F l. Above trip setting initiates Main Steam Line Tunnel Main Steam Line Isolation High Temperature Instrument Channel 160 180oP l. Above trip setting initiates Reactor Water Cleanup Isolation of Reactor Water System Floor Drain High Cleanup Line from Reactor and Temperature Reactor Water Return Line.

Instrument Channel 160 180oF 1. Same as above Reactor Water Cleanup System Space High Temperature Instrument Channel < 100 mr/hr or downscale G 1. 1 upscale or 2 downscale will Reactor Bu'lding Venti- a. Initiate SGTS lation High Radiation- b. Isolate reactor zone and Reactor Zone refuleing floor.

c. Close atmosphere control system.

Instrument Channel < 100 mr/hr or downscale F 1. 1 upscale or 2 downscale will Reactor Building Venti- a. Initiate SGTS.

lation High Radiation b. Isolate refueling floor.

Refuleing Zone c. Close atmosphere control system.

2 (7)(8) instrument Channel Charcoal Heaters< 2000 H and 1. Below 2000 cfln, trip setting charcoal SGTS Flow - Train A cfm R. H. Heaters< 2000 (A or F) heaters will turn on.

Heaters cfm 2. Below 2000 cfm, trip setting R. H.

heaters will shut off.

2 (7)(8) Instrument Channel Charcoal Heaters< 2000 H and 1. Below 2000 cfm, trip setting charcoal SGTS Flow Train B cfm R.H. Heaters< 2000 (A or F) heaters will turn on.

Heaters cfm 2. Below 2000 cfm, trip setting R.H.

heaters will shut off.

2 (7)(8) Instrument Channel Charcoal Heaters< 2000 cfm H and 1. Below 2000 cd, trip setting charcoal SGTS Plow Train C R.H. Heaters< 2000 cfm (A or F) heaters will turn on.

Heaters 2. Below 2000 cfm, trip setting R.H.

heaters will shut off.

TABLE 3.2.A (Continued)

Minimum ho.

0pezable Per Tri S's 1 Function Tri Level Settin Action 1 Remarks Resc or Building Isolation 0 < t < 2 se<<s. Nor F 1. Belov trip setting prevents Timer (refueling floor) spurious trips and system peztur-bations from initiating isolation Instrument Channel- N/A H or F 1. Located in unit 1 only Static Pressure Control 2. Permissive for static presouze Pe~issive (refueling control (SGTS A, B, or C on) .

floor) Channel shared by pezmissivc on reactor zone static pressure cont.

S: tic Prcssure Control < 1/2" H 0 HorF l. Located in unit 1 only Pze sure Re ulator (Pe- 2. Control" static pressure of fueling Floor) rc f<<cling f loor during zen c tor builCing isolation Mith SCTS running Reactor Building Isolation 0 < t < 2 secs. G or A 1. Belou trip setting prevents Timer.(reactor xone) or H spurious trips anC system peztur-bations from initi<< ing isolation Instrument Channel- N/A 1. Pezmissive for static pzesoure 1(9)

S azic Pres ure Control control (SGTS A, B, or " on).

(reactor Channel shared by pezmiss Jc on Permissive

=one) refueling floor static pzc sure control.

Static Pressure Con rol < I/2" H20 1. Controls-static pressure of 1(9) reactor zone during reactor Pr. cour<<Regulator (reactor conc) building isolation vith SGTS running.

(Znitiating) Logic N/A 1. Refer to Table 3.7.A for list of Group 1 valves.

Group 1 (Actuation) Logic N/A 1. Refer to Table 3.7.A for list of valves.

TABLE 3.2.h (Contiaued)

'nheua Ho curable Per

~Tet S s 1 Puaction Tri Level Set tin Action I Remarks Croup 2 (Iaitiating) Logic H/A A or 1. Refer to Table 3.7.A for list of (B and E) valves.

Croup 2 (RHR Isolation-Actuation) H/h Logic Croup 2 (Tip>>Actuation) Logic H/A Croup 2 (Dryvell Sump Drains- H/h Actuatioo) Logic Croup 2 (Reactor Building 6 Y and C 1. Part of Croup 6 Logic Refueling Yloor, aad Dryvell Vent aad Purge-hctuatioa) Logic Croup 3 (Initiating) Logic N/h 1, Refer to table 3.7.A for Iiet of valves o Croup 3 (Actuatioa) Logic H/h Croup 6 Logic 5/h Y and C 1. Refer to table 3.7.A for list of valves.

Croup 8 (Initiating) Logic H/h 1. Refer to Table 3.7.A for list of valves.

2. Saae as Croup 2 initiating logic Reactor Building Isolation H/A HorP I. Logic has permissive to refueling (refueling floor) Logic floor static pressure regulator.

Reactor Building Isolation H/A H or C or h 1. Logic has permissive to reactor (reactor zone) Logic zone static pressure regulator

TABLE 3.2.A (Con:inued)

Mir imum No.

Op rable Per Function Tri Level Settin Action (1) Remarks l(7)(g) SCTS Train A Logic NIA or (A and F) 1 (7) (8) SCTS Train B Logic N/A or (A and P) 1(7) (8) SG'fS Train C Logic (A"aN F) 1 Stdtic Pressure Control H or F l. Located in unit 1 only (refueling floor) Logic l(9) Static Pressure Control N/A (reactor xone) Logic Refer to Table 3.2.B ror RCIC and HPCX functions including Groups 4, 5, and 7 valves.

HOTES FOR TABLE 3.2.A

l. Whenever the respective functions are required to be operable, there shall be two operable or tripped trip systems for each function.

If the first column cannot be met for one af the trip systems, that trip system or logic for that function shall be tripped (or the appropriate action listed bclov shall be taken). If the column cannot be met far all trip systems, the appropriate action listed below shall be taken.

A. Initiate an arderly shutdovn and have the reactors in Co1d Shutdown Condition in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

B. Initiate an orderly load reduction and have Main Steam Lines isolated within eight hours.

C. Isolate Reactor Mater Cleanup System.

D. Isolate Shutdown Cooling E. Initiate primary containment isolation vithin 24 hours.

F. The handling of spent fuel vill be prohibited and all operations over spent fuels and open reactar veils shall bc prohibited.

G. Isolate the reactor building and start the standby gas treatment system.

H. Immediately perform a logic system functional test on the logic in the other trip sjstemsand daily thereafter not to exceed 7 days.

Ho action required. Reactor xone walla and ceiling designed above suction pressure of the SCTS.

.i. MLthdraw TIP.

K. Manually isolate the affected lines. Refer ta section 4.2.K for the equirements of an inoaerable. system.

L. lf one SGTS train is i~Ãapereble take actions H or action A and F. If two SGTS trains are inoperable take actions A and F

2. When it is determined that a channel is failed in the unsafe candition, the other channels that monitor the same variable shall be functionally tested immediately before the trip system or logic for that function is tripped. The trip system or the logic for that function may remain untripped for short periods of time to allov functional testing of thc nther trip system or logic for that function.

3. There sre four channels per steam line of vhich two must be operable.

4. Only required tn Run Hode (interlocked with Mode Switch).

5. Hot required in Run Hodc (bypassed by mode switch).

60

6. Channel shared by RPS and Primary Containment & Reactor Vessel Isolation

(:ontrol System. A channel failure may be a channel failure in each system.

7. h train is considered a trip system.

8. Two out of three SGTS trains required. A failure of more than one will require action A and F.

9. There is only one trip system with auto transfer to two power sources.

61

TABLE 3-2.B INSTtmmmTIOH ran mrTIATES 0R ConaoLS THE C0Rt.'AHD Con'AleeNT C00LWC SYSTEMS Hiniaaua Mo.

Operable Per Tri S 1 Punction Tri Level Settin Aetian Reaarks Instrument Chznnel- > 490" above vessel zero. 1. Below trip setting initiated HPCI.

Reactor Lou Mater Level Enstrutaent Channel- > 490" above vessel zero. l. Multiplier relays. initiate RCIC.

Reactor Lou Mater Level Instrument Channel- > 378" above vessel !ero. I. Belov trip setting initiates CSS Reactor Lou Mater Level Multiplier relays initiate LPCI.

(LIS-3-58A-D, SQ fl)

2. Hultiplier,relay froa CSS initiates accident signal (15).

t(16) Instnment Channel- > 378" above vessel aero. 1. Belier trip settings in con)unction Reactor Les Mater Level Wth dryvell high pressure, lov (LIS-3-58h-D, SM 02) vater level peraissfve, 120 sec. del tiaaer and CSS or RHR passp nmnfng, initiates ADS.

Instnment Channel- > 544" above vessel zero. l. Below trip setting peraissive for maactor Lov Mater Level initiating signals on ADS.

Peraissive (LIS-3-184 6 l85, SM fl)

Instrument Channel- > 312 5/16" above vessel zero. h 1 Belov trip setting prevents inadver Reatctor Lear Mater Level (2(3 core height) tent operation of containaaent spray (LETS-3-52 6 62, SM 01) during accident condition.

Instrument Channel- lc pc 2 psig 1. Belov trip setting prevents inad Dryvell High Pressure tent operatfon of containaent spray (PS-64-58 E-H) during accident condf tfons

TABLE 3.2.B (Continued)

Ninfmum Ho.

Operable Per Trfn S s {l) Function Tri Level Settin Action Remarks Instrument Channel- < 2 psig l. Above trip setting in con)unction vi DryMe1 1 High Pressure loM reactor pressure initiates CSS.

(PS-64-58 A-D, SV s~) .'tultlnlfer relays initiate HPCI.

2. '.tultiplier relay from CSS initiates accident signal. {15) .

Instrument 'Channel- > 490" above vessel aero 1. Be'.~ ~ trip setting trips recircula-Reactor Lov Mater Level tion pumps (LS-3-56A, B, C, D)

Instrument Channel < 1120 psfg 1. Above trip setting trips recircula-Reactor High Pressure tion pumps (PS-a-ZU4 A, B, C, D)

Instrument Channel- ( 2 psfg 1. Above trip setting in con)unction v'.

Dryvell High Pressure lov reactor pressure initiates LPCi.

(PS-64-58A-0 ~ SM fl) 2(16) Instrument Channel- < 2 psig 1. Above trip setting in conjunctloa vi Dryvell High Pressure loM reactor Mater level, dryvell hig (PS-64-57A-D) pressure, 120 sec. delay timer and C or RHR pump running, initiates ADS.

Instrument Channel- h50 psfg + 15 1, ~elov tri setting permissive zo =reni~a Reactor Lov Pressure CSS and  :~T. admission valves.

(PS-3-74 A & B, SM f2)

(PS-68-95, SM f2)

(PS'-68-96, SM P2)

Instrument Channel- 230 psig + 15 1. Recirculation discharge valve Reactor Lov Pressure ae uation.

(PS-3-74A & B, SM fl)

(PS68-95, SM fl)

(PS-68-96, SM gl)

TABLE 3.2.B (ContinueC)

Xinimum 'Ho.

Operable Per Function Tri Level Settfn Action Remarks Instrument Channel 100 psig + 15 l. Belo~ trip setting in con)unction with Reactor Low Pressure (PS-68-93 & 94, SM tl) containmeut isolation signal and both suction valves open will close RHR (LPCI) admission valves.

Core Spray Auto Sequencing 6< t <8 secs. 1.. Mith diesel power Timers (5) 2, One 'per motor LPCI Auto Sequencing 0< t <1 sec. 1. Mith diesel power Timers (5)

2. One per motor RHRSM A", Bl, C3, and Dl 13 < t < 15 sec. 1. Mith diesel power Timers

2. One per'ump Core Spray and LPCI Auto 0< t<l sec. 1. With normal power Sequencing Timers (6) 6< t < 8 sec. 2. One per CSS motor 12 < t < 16'ec.

18<t<QA sec. 3. Two per RHR motor RHRSM A3, Bl, C3, and Dl 27 < t <29 sec. 1. Mith normal power Timers

2. One per pump

TABLE 3.2.B (Continued-)

Xhataum Ho.

Operable Per Function Tri Level Set tin Action Remarks l(16) ADS Timer 120 sec +5 l. Above trip setting in con$ unc:.:n:

lou reactor Mater level, hig".. -.wc pressure and LPCI or CSS pu..".s run:

initiates ADS.

Instrument Channel- 100 +10 psig h 1. Belov trip setting defers ADS RHR Discharge Pressure actuation.

Instrument Channel 185 +10'sig 1. Belov trip setting defers ADS CSS Pump Discharge Pressure actuation.

l(3) Core Spray Sparger to 2 psid + 0.4 1. Alarm to detect core spiay sparger Reactor Pressure Vessel d/p pipe brcak.

RHR (LPCI) Trip System bus l. ?editors availability of pover to poMer monitor logic systems.

.ABLE 3.2.B (Cc ntinued)

Minimum No.

Operable Per Tri S s (1) Function Trio'evel Settin Action Remarks Core Spray Trip System bus N/A 1. Monitors availability of pover to pover monitor logic systems.

ADS Trip System bus paver N!A 1. Monitors availability ot paver to monitor logic systems and valves.

HPCI Trip System bus pover H/A 1. Monitors availability of pover to monitor logic systems.

RCIC Trip System bus pover 8/A 1. Monitors availability of pave. to monitor logic systems.

1(2) Instrument Channel- > Elev. 1. Belov trip sert'ng vill open HP  :.

Storage Tank Lov 551'ondensate suction valves to the suppression Level (LS-73-55A 6 B) chamber.

l(2) Instrument Channel < 7" above normal va ter 1. Above trip setting vill open HPCI Suppression Chamber High level suction valves to the suppression Level chamber.

2(2) Instrumen Channel- < 583" above vessel zero. l. Above trio setting trips RCIC turbine.

Reactor High Mater Level Instrument Channel- < 450" H20 (7) l. Above trip setting isolates RCIC systet RCIC Turbine Steam Line and trips RCIC turbine.

High Flov

TABLE 3.2.B (Continued)

Minimum No.

Operable Per Function Tri I.evel Settin Action Remarks Instrument Channel- c 200'F. A 1. Above trip setting isolates RCIC trips system'nd RCIC Steam Line Space High RCIC turbine.

Temperature 2(2) Enstrument Channel < 583" above vessel zero. A 1. Above trip setting trips HPCI turbine.

Reactor High Water Level Instrument Channel- '<90 psi (7) A l. Above trip setting isolates HPCE systen HPCI Turbine Steam Line High and trips HPCI turbine.

Flow 4(4) Instrument Channel < 200'F. A l. Above trip setting isolates HPCE HPCE Steam Line Space High system and trips HPCE turbine.

Temperature Core Spray System Logic N/A B 1. Encludes testing auto initiation inhibit to Core Spray Systems in other units.

RCIC System (Initiating) N/A B ' Includes Group 7 valves. Refer to Logic Table 3.7.A for list of valves.

ThBLE 3.2.B (Continued)

.41abaum No.

Operable Per Tri S s 1 Punction Tri Level Settia hction RCIC System (Isolation) 3/h 1. Includes Group 5 valves. Refer to Logic Table 3.7.h for gist of valves.

1(16) mS Logic N/h 1 RHR (LPCI) System (Initiation) 8/h RHR (LPCI) System (Containment 2/h Coolint Spray) Logic HPCI System (Initiating) Logic H/h l. Includes Croup 7 valves. Refer :o Table 3.7.h for list of valves.

HPCI System (Isolation) Logic 3/h Includes Group 4 valves. Refer <<

Table 3 7 h for list of valves Core Spray System auto initiation inhibit (Core

'X/h l. Inhibit due to the core spray systen f

o ano ther unit.

Spray auto initiatioa). 2. The inhibit is considered the contact in the auto initiating logic only; i.Q.

the pensissive function of the inhibk LPCI System auto inhibit initiation I/h l. Iahibit due to the LPCI Systea oi (LPCI auto initiation) aao ther uait.

2. The inhibit is considered the contact in the auto initiating logic only, i.+

the peraissive functioa of the inhibN

TABLE 3.2.B (Continued)

Minimum No.

Operable Per Tri S s 1) Function Tri Level Settin batsman Remarks sq l(3) Core Spray Loop A 0 500 psig Indicator (9) 1. Part of filled discharge pipe Discharge Pressure requirements. Refer to Section 4.5.

(PI-75-20) 1(3) Core Spray Loop B 0 - 500 psig Indicator (9) 1. Part of filled discharge pipe Discharge Pressure requirements. Refer to Section 4.5.

(PI-75-48) 1(3) RHR ~p h Discharge 0 450 psig Indicator (9) 1; Part of filled discharge pipe Pressure (PI-74-51) requirements. Refer to Section 4.5.

1(3) Loop B Discharge 0 450 psig Indicator (9) 1. Part of filled discharge pipe RHR Pressure (PI-74-65) requirements. Refer to Section 4 '.

1(10) Instrument Channel- N/A 1. Starts RHR area cooler fan vhen RHR Start respective RHR motor starts.

1(10) Instrument Channel- < 100'F l. Above trip setting starts MR area Thermostqt (RHR brea Cooler cooler fans.

Fan) 2(10) Instrument Channel N/A 1. Starts Core Spray area cooler fan Core Spray h or C Start vhen Core Spray motor starts 2(10) Instrument Channel >> N/A l. Starts Core -Spray area cooler fan Core Spray B or D @hen Core.Spray motor starts 1(10) Instrument Channel- < 100'F 1. Above trip setting starts Core Spray Thezmostat (Core Spray Area area cooler fans Cooler Fan)

TABLE-3.2.B (Continued)

Minimum No.

Operable Per Tri. S s (1) Punc t ion Tti Level Section Action Remarks 1(10) RHR Area Cooler Fan Logic N/A l(10) Core Spray Area Cooler Fan Logic 8/A 1(11) Instrument Channel- ai/A A 1. Staits RHRSM pumps A3 6 Dl Core Spray Motors A or D Start 1(11) Instrument Channel- N/A A 1. Starts RHRSM pumps Bl 6 C3 Core Spray Motors B or C Start 1(12) Instrunent Channel- N/A A 1. Starts RHRSM pumps A3 Core Spray Loop 1 Accident Signal (15) 1(12) Instrument Channel- X/A A 1. Starts RHRSM pumps Bl 6 Dl Core Spray Loop 2 Accident Signal (15) 1(13) RHRSM Initiate Logic N/A'14)

NOTES FOR TABLE 3.2.8

1. Whenever any CSCS System is required by section 3.5 to be operable, there shall be two operable trip systems except as noted. If a requirement of the first column is reduced by one, the indicated action shall be taken. If the same function is inoperable in more than one tr'ip system or the first column reduced by more than one, action B shall be taken.

Action:

A. Repair in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If the function is not operable in 24 hours, take action B.

B. Declare the system or component inoperable.

C. Immediately take action B until povez's verified on the trip system.

D. No action required, indicators are considered redundant.

2. In only one trip system.

3. Not considered in a trip system.

4. Requires one channel from each physical location (there are 4 loca-tions) in the steam line space.

5. Wi'th diesel power, each RHRS pump is scheduled to start immediately and each CSS pump is sequenced to start about 7 sec later.

6. With normal power, one CSS and one RHRS pump is scheduled to start instantaneously, one CSS and one RHRS pump is sequenced to start after about 7 sec with similar pumps starting after about 14 sec and 21 sec, at which time the full complement of CSS and RHRS pumps vould be operating.

7. The RCIC end HPCI steam line high flov trip level settings are given in terms of differential pressure, The RCICS setting of 450" of H20 corresponds to 300% of rated steam flov at 1140 psia and 210X at 165 psia. The HPCIS setting of 90 psi corresponds to 225X of rated flov at 1140 psia and 160X at 165 psia.

8. Note 1 does not apply to this item.

9. The head tank is designed to assure that the discharge piping from the CS and RHR pumps are full. The pressure shall be maintained at or above the values listed in 3.5.1, vhich ensures vater in the discharge piping

<<nd up to the head tank.

71

NOTES FOR TABLE 3.2.B (Continued)

10. Only one trip system for each cooler fan.

11. In only tvo of the four 4160 Y shutdovn boards, See note 13 ~

12. In only onc of the four 4160 V shutdovn boards. See note 13.

13. An emergency 4160 V shutdovn board is considered a trip system.

14. RHRSM pump vould be inoperable. Refer to section 4.5.C for the requirements of a RHRSM pump being inoperable.

15. The accident signal is the satisfactory completion of a one-out-'f-tvo taken tvice logic of the dryvell high pressure plus lov reactor pres-sure or the vessel lov vatez level (> 378" above vessel cero) originating in the cor>> spray system trip system.

16. The ADS circuitry is capable of accomplishing its protective action vith one operable trip system. Therefore one trip system may be taken out of service for functional testing and calibration for a period not to exceed 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

72

TABLE 3.2.C INSTRUHENTATIOÃ THAT INITIATES ROD BLOCKS Hi+i~ Ho.

Operable Per Tri S s 5 Function Tri Level Settia 2 (1) APRH Upscale (Plov Bias) < 0,66W + 42X (2) 2 (1) APRH Upscale (Startup Mode) (8) < 12Z 2(1) APRH Downscale (9) -> 3Z 2 (1) APRH Inoperative (10 )

RW Upscale (Plov Bias) < 0.66W + 41X (2)

RBM Dovnscale (9) > 3Z RBM Iaopera tive (10 )

3(1) IRH Upscale (8) < 108/125 of full scale 3(1) IRH Dovnscale (3) (8) 5/125 of fuU. scale 3(1) IRH Detector not ia Startup Position (8) 3(l) IRH Inoperative (8) (10 )

5 2(1) (6) Upscale (8) < 1 x 10 counts/sec.

2(1) (6) SRH Downscale (4)(8) > 3 counts/sec.

2(l) (6) SR.'t Detector aot in Startup Position (4)(8) 2(1) (6) SRH Inoperative (8) (10a) 2 (1) ploM Bias Ccmparator < 10Z difference in recirculation flexure 2(1) YloM Bias Upscale < 110Z recirculation flov Rod Block Loeic N/h RSCS Restraint 147 psig turbine (PS-85-61A 5 first stage pressure (approximately 30X pover)

PS-85-618)

l. Vor the etartup and run positions of the Reactor Hnda Selector Svltch, there shall bc tMo operable or trippeJ trip systems for each function.

The SRH, IRH, and APRM (Startup mode), blocks need not be operable in "Run".mode, and the APRH (Plov biased) and RBM rod blocks need not ba operable in "Startup" mode. If the first column cannot be mat for one of tho tvo trip systems, this condition may exist for un to seven days provided that during that time the operable system is functionally teated immediately and daily thereafter; if this condition last longer than seven days, the system vith the inoperable channel shall be tripped.

If the first column cannot be met;for both trip systems, both trip systems shall be tripped.

2, W is the recirculation loop flov in percent of design, Trip Level settina j,s in percent of rated pover (f29) Alt)~ Total pecdZng factors greater than 2.63 are Iu.rmitted at reduced poster. .See Specification 2.1 for control rod block setmint.

it

'PRM ZRM dovnsoale is bypassed vhen is on its lovest range.

4. This function is bypassed vhen the count rate is > 100'cpa and IRM above range 2.

5. One instrument channel; i.e., one APRM or IRM or RBM, per trip system may be bypassed except only one of four SRM may be bypassed.

6. IRM channels A, E, C, G all in range 8 bypasses SRM channels A & C functions.

IRM channels B, P, D, H all in range 8 bypasses SRM channels B 6 D functions.

7. The trip is bypassed vhen the reactor pover is + 30X.

8. This function is bypassed vhen the made svitch is placed in Run.

9. This function is only ective vhen 'the mode svitch is in Run. This function id automatically bypassed vhen the IlN instrumentation is operable and not high.

10. The inoperative trips are produced by the folloving functions:

a. SRK and IRM (1) Local "operatemalibrate" svitch not in operate.

(2) Pover supply voltage lov.

(3) Circuit boards not in circuit.

b. APRH (1) Local "operate-calibrate" svitch not in operate, (2) Leos than 14 LPRN inputs.

(3) Circuit boards not in circuit.

74

(1) Local "operate-calibrate" switch not in operate.

(2) Circuit boards not in circuit.

(3) RM fails to null.

(4) Less than required 'number of LPRM inputs for rod selected.

ll. Detector traverse is ad)usted to 114 +- 2 inchesy placinS the detector lower position 24 inches below the lower core plate.

t

TABLE 3.2,D OFF-GAS POST TREATMENT ISOLATION INSTRU'.XHTATION Kin. No.

erable (1) Function Tri Level Settin bction 2) Remarks Off-Gas.Post Treatment Note 3 A or B 1. 2 upscales, or 1 dovnscal Monitor and 1 upscale, or 2 dovn-scales vill isolate off-'as line.

Off-Gas Post Treatment Note 3 l. One trip system vith auto Isola t ion transfer to another source HOIES:

1 whenever the minimum number operable cannot be met, the indicated action shall be taken.

2. hetman

h. Refer to Section 3.2.D.l.b B. Refer to Section 3.2.D.l.c

3. Trip setting to correspond to Specification 3.2.D.l.a

SABLE 3.2.E INSTRUMENTATION THAT HONIT)RS LEAKAGE INTO DRYMELL S stem 2 Setpoints Action Remarks Equipment Drain 1. Used to determine identifiable reactor Plow Integrator N/A coolant leakage.

Sump Pill Rate 2. Considered part of sump system.

Timer >20.1 min.

Sump Pump Out Rate Timer <13.4 min.

floor Drain 1. Used to determine unidentifiable Plow Integrator N/A ~ reactor coolant leakage.

Sump Pill Rate 2. Considered part of sump system, Tim r >80.4 min.

Sump Pump Out Rate Timer <8.9 min.

Drywell Air Sampling Gas and 3 x Average (3)

Particulate Background NOTES:

(1) whenever a system is required tc be operable, there shaLl be one operable system either automatic or man~1, or the action required in Section 3.6.C.2 shall be taken.

(2) An alternate system to determine the leakage flow is a nanual system whereby the time between sump pump starts is monitored. The time interval will determine the leakage flow because the volume of the sump will be known.

(3) Upon receipt of alarm, immediate action will be taken to confirm the alarm and assess the possibility of increased leakage.

TABLE 3.2,F SURVEILLANCE IHSTRVHEZhTION Hia~ 0 of Opcrablc Instrument Type Indication Channels Instrument f Instrument and Ran c Notes LI-3-46 h Reactor 0ater Level Indicator -107.5" to (1) (2) (3)

LI-3-46 B +107.5" PI-3-54 Reactor Pressure Indicator 0-1200 psig (1) (2) (3)

PI-3-61 PR-64-50 Drywall Pressure Recorder 0-80 psia (1) (2) (3)

PI-64-67 Indicator 0-80 psia TIN4-52 Dryuell Temperature Recorder, Indicator (1) (2) (3)

IR-64-52 0-4 CO'F TR-64-52 Suppression Chaaber hir Recorder 0-400'F O.) (2) (3)

T~rature TI-64-55 Suppression Chamber Mater Indicator, 0<<400'F (1) (2) (3)

TIS&4-55 Tc=peraturo LI-64-54 h Suppresaion Chauber Mater Indicator -25" to O.) (2) (3)

LI-64-66 Level +25 II Nh Control Rod Position 6V Indicating )

Lights )

Heutron Honitoring SRH, IRN, LPRM ) (1) (2) (3) (4:

0 to 100Z pover)

PS-64-67 Dryvell Preoourc Alarm at 35 psig )

)

TR-64-52 and PS-64-58 B and D~ll Temperature Preoourc and Timer and Alarm if temp.

281 P and

)

(1) (2) (3) (4;

)

IS-64-67 prcssure > 2 psig )

after 30 minute )

delay)

LX-84-:>h CAD tank "h" level 3n<jicator 0 to 10('f.

L;-84-1> CAD tank "D" level Indicator 0 to 100$

TABEZ 3.2.F Surveillance Instrumenta ion Minimum g of Operable Instrument r Type Indication Channels Instrument g Instrument and Ra e Notes H2M 37 Drywell H 0.1 - 202t (1)

H M 39 Concentration 02M 43 Drywell 02 02M 41 Concentration O.l - 28$ (1) lt2M 38 Suppression Chember 0.1 - 20fo (1) (4)

H2 Concentration OM- 76- 42 Suppression Chamber 0.1 - 29fg 2

02 Concentration

NOTES POR TABl.E 3.2.P (1) Prom and after the date that one of these parameters is reduced to one indication, continued operation is permissible during the succeeding thirty days unless such instrumentation is sooner made operable.

(2) From and after the date that one of these parameters is not indi-cated in the control room, continued operation is permissible during the succeeding seven days unless such instrumentation is sooner made operablc.

(3) If the requirements of notes (1) and (2) cannot be met, either the requirements of 3.5.H shall be complied vith or an orderly shutdown shall be initiated and the reactor shall be in a Cold Condition vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

(4) Thcsc surveillance instruments are considered to be redundant to each other.

80

TABLE 3.2.G CONTROL ROOM ISOLATION INSTRUMENTATION Minimum 4 of Operable Instrument Channels Function Tri Level Settin Action Rcnntkn Control room air 270 cpm above background (4) (2) 1. Monitors located in supply duct normal control room air Radiation monitors supply ducts.

(RM-90-259 A & B)

2. Also initiates control room emergeacy pressuri-zation system.

(3) Accident signal (3) N/A (3)

NOTES (l) whenever the minimum number operable cannot be met the iadicated action shall be taken.

(2) Action-One channel iaoperabI,e - Repair as soon as possible aad functionally test the other channel daily.

Two channels inoperable Repair as soon as possible. Functionally test the control room particulate monitor (BM-90-53) and radiation monitor (RM-90-8) once per shift. These monitors alarm in the control room oa high activity. This will allow the operator to manually isolate the control room and manually initiate the emer-gency pressurization system. If one air supply duct radiation monitor is not operable within 30 days, declare the system initiated by these monitors inoperabl.e and take action as specified in section 3.7.E.

(3) Aay signal that isolates primary containment also isolates the control room and initiates the control room, emergeacy pressurization system. These signals and the appropriate action to take if the instrumentation is unavailable is indicated in Table 3.2.A.

(4) The~e monitors are set to trip at 270 cpm above background, which is a radiation level corresponding to about 10 l uci/cc of Xenon-133 (about mRem/hr). The initial This setpoint Mill be verified by site operating personnel.

set point's based on manufacturers empirical formulas.

TABLE 3.2.H FLOOD PROTECTION INSTRlHEVZATION Minimum No. of Operable Instrument Instrument Instrument Channels Number Function Tri Settin hotes LS-23-75 A&B Reservoir Elevation 564 (1), (2), (3)

Level Monitoring (1) From and after the date that the number of operable instrument channels is reduced to one, continued operation is permissible only during the succeeding 30 days unless such instrumentation is sooner made operable or unless the manual surveillance program is initiated, see Note (4).

(2) From and after the date that neither of these instrument channels is operable, continued operation is per-missible only during the succeeding 7 days unless 'such instrumentation is sooner made operable or unless the manual surveillance program is initiated, see Note (4).

(3) If the requirements of Notes (1) and (2) above cannot be met, an orderly shutdovn shall be initiated and all reactors shall be placed in a cold condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

(4) The manual surveillance program requires that the reservoir level be monitored by plant personnel every g hours.

Table 3 2. I Hereorolnaica1 Hon? torin Instnxmentation INSTRUHE??T HIHIHUH INSTRUI!EIFP ACCURACY OPERABLE

1. HIND SPEED

a. Channel A Elevation 620 HSL Note 41

b. Channel 8 Elevation 737 HCIL Note i1

c. Channel C Elevation 887 HSL Note 41 2~ MIND DIRE 1'ION

a. Channel A Elevation 620 HSL 50

b. channel. II Elevation 737 HSL 50

c. Channel C Elevation 887 HSL 50

3. AIR TEHPERATUME - DELTA T

a. Channel A Elevation 620-737 HSL 0.1o C

b. Channel II Llevation 620-887 HSL 0.10 C Note 01 starting speed of aneaometer shall be < 1 mph. Accuracy is Mhhin + 1X of nph reading or 0.15 ash, Mhichever is greater.

Table 3.2.J Seismic Monitori Instrumentation MEASUREMENT MINIMUM INSTRUMENT RANGE SETPOINT OPERABLE TRIAXIAL TIME HISTORY ACCELOGRAPHS

a. -1 reactor bid base slab El. 1 0-1.0g .Olg

b. U-1 reactor bid . floor slab El. 621.25 0-1,0g . Olg

c. Diesel- en. bl . base slab El. 565. ) 0-1.06 .Olg TRIAXXAL PEAK ACCELOGRAPHS U-1 RBCCH 10" ie EL. 62 . ~0- .0

b. U-1 RHRS~1 16" ie .EL. 580.0 0-5~0

c. U-3. core s ra s stem 14" ie El. 4;0 0-5~0 BIAXIALSEISMIC SWITCHES

a. U-1 reactor bid . base slab .025-.256 O.lg

b. U-1 reactor bl . base slab .025-.25g O.lg

c. U-1 reactor bid . base slab ~ 025-.258 O.lg

+ Nith control roo!n indication

TABLE 4 2eh SORVEILIANCE REQQIRENENTS FOR PRIHJLRY CONTAINNEK'ND REACTOR BOILDING ISOLATION INSTRUNENTATION Function Functional Test Calibration Frequency Instrument Check Instrument Channel- (5) once/day Reactor Lou Mater Level (LIS-3-203h-D, SM 2-3)

Instrument Channel once/3 months none Reactor High Pressure Instrument Channel- once/3 month once/day Reactor Lov Mater Level (LIS-3-56h-D, SM 01)

Instrument Channel- (5) N/h High Dryvell Pressure (PS-64-56K-0)

Instrument Channel- (5) once/day High Radiation Nain Steam Line Tunnel Instrument Cbannel- once/3 months none Lcw Pressure Main Steam Line Instrument Channel- once/3 months once/day High Flew Nain Steam Line Instrument Channel- once/operating cycle none Hain Steam Line Tunnel High Temperature Instrument Channel- (1) (14) (22) once/3 months once/day (8)

Reactor Building Ventilation High Radiation - Reactor Zone

TABLE 4, 2 ~ A SURVEILLANCE RBQUIRENENTS OR PRINARY TS FOR PR CONTAINMENT AND REACTOR BUILDING ISOLATION INSTRUNENTATION Function unctional Test Calibration Fr uen Instrument Check Instrument Channel- (1) (14) (22) once/3 months once/day (B)

Reactor Building Ventilation High Radiation - Refueling Zone Instrument Channel- (4) (9) N/A SGTS Train A Heaters Instr<lment Channel- (4) (9)

SGTS Train B Heaters Instrument Channel- (4) (9) N/A SGTS Train C Heaters Reactor Building Isolation (4) once/operating cycle N/A Timer (refueling floor)

Instrument Channel- (10) N/A Static Pressure Control Permissive (refueling floor)

Static Pressure Control (4) once/3 months N/A Pressure Regulator (refueling floor)

Reactor Building Isolation (4) once/operating cycle N/A Timer (reactor xone)

Instrument Channel- (10) N/A Static Pressure Control Permissive (reactor xone)

Static Pressure Control (4) once/3 months N/A Pressure Regulator (reactor xone)

TABLE 4 2 A SURVEILLANCE REQUIREHENTS FOR PRIMARY CONI'AINMEM'ND REACTOR BUILDING ISOLATION INSTRUHENTATION Function Functional Test Calibration Frequenc Instrument Check Group 1 (Initiating) Logic Checked during channel functional test. No further test required. (11) N/A N/A Group 1 (Actuation) Logic once/operating N/A cycl e (21)

Group 2 (Initiating) Logic Checked during channel functional test. No further test required. N/A Group 2 (RHR Isolation-Actuation) once/operating N/A Logic cycle (21)

Group 2 (Tip-Actuation) Logic once/operating N/A N/A cycle (21)

Group 2 (Drywell Sump Drains- once/operating N/A Actuation) Logic cycl e (21)

Group 2 (Reactor Building and once/operating N/A Refueling floor, and Drywell cycle (21)

Vent and Purge-Actuation) Logic Group 3 (Initiating) Logic Checked during N/A N/A channel functional test. No further test required.

Group 3 (Actuation) Logic once/operating N/A cycle (21)

TABLE 4 2~A SURVEILLANCE REQDIREMENTS POR PRIMARY CONTAINMENI'ND REACTOR BQILDING ISOLATIOH INSTRUMENTATION Punction Functional Test Calibratxon Pr uenc Instrument Check Group 6 Logic once/operating H/A N/A cycle (18)

Group 8 (Initiating) Logic Checked during channel functional test. No further test required.

Reactor Building Isolation once/6 months (18) (6)

(refueling floor) Logic Reactor Building Isolation once/6 months (18) (6) H/A (reactor xone) Logic SGTS Train A Logic once/6 months (19) N/A N/A SGTS Train B Logic once/6 months (19) N/A SGTS Train C Logic once/6 months (19)

Static Pressure Control once/operating co (refueling floor) Logic cycle (18) (6)

Static Pressure Control once/operating (reactor xone) Logic cycle (18) (6)

Instrument Channel-Reactor Cleanup System Ploor Drain High Temperature once/operating cycle Instrument Channel-Reactor Cleanup System Space Sigh Temperature (23)

a. RTD once/operating cycle ( )

(once/operating cycle)

h. Temperature 8~itch ( )

PAGES DELETED 89 thru 95

TABLE 4.2.8 SURVEILLANCE REgUIRVfPiTS FOR INSTRL~ATI>N THAT INITIATE OR CONTROL THE CSCS Function Functional Test Calibration Instrument Check Instrument Channel once/3 months once/day Reactor Lov Mater Level (LIS-3-58A-D)

Instrument Channel once/3 months once/day Reactor Lov Mater Level (LIS-3-184 & 185)

Instrument Channel once/3 months once/day Reactor Lov Mater Level (LITS-3-52 & 62)

Instrument Channel once/3 months Reactor Lov Mater Level (LS-3-56A-D)

Instrument Channel once/3 months Reactor High Pressure (PS-3-204A-D)

Instrument Channel once/3 months none Dryvell High Pressure (PS-64-58E-H)

Ins trument Channel once/3 months none Dryvell High Pressure (PS-64-58A-D)

Ins trument Channel once/3 months Dryvell High Pressure (PS-64-AA-D)

Instrument Channel once/3 months ReactoR.Lov Pressure (PS-3-74A & B)

(PS-68-95)

(PS-68~96)

TABLE 4.2.B (C,ont~nued)

Function Punctional Test Calibration Instruaent Check Instruaent Channel once/3 aonths Reactor Lov Pressure (PS-68-93 4 94)

Instrument Channel once/3 maths none Reactor Lov Pressure (PS-3-186h 4 B, and PS-3-187h & B)

Core Spray huto Sequencing Tiaers (4) once/operating cycle none (Noraal Pover)

Core Spray Auto Sequencing Tiaers (4) once/operating cycle (Diesel Power)

LPCI Auto Sequencing Tiaers once/operating cycle (EorsLal Pcmer)

LPCI Auto Sequencing Thaers (4) once/operating cycle (Diesel Power)

RBRSQ A3, 51, C3, Dl Tiaiers once/operating cycle (SoraLsl Power)

RHkSV A3, Bl, C3, Dl Tissers (4) once/operating cycle (Diesel Power)

(4) once/operating cycle

ThBLE 4.2.B (Continued)

Function Functional Test Calibration Instrunent Check Instnaaent Channel once/3 nonths none RHR Perp Discharge Pressure Instnaaeat Channel ence/3 months Core, Spray Pump Discharge Pressure Core Spray Sparger to RPV 1/p once/3 months once/day Trip Systea Bus Power Monitor once/operating cycle N/A none Instnuaent Channel Coelensate Storage Tank Low Level once/3 eonths Instrueent Channel Suppression Chamber High Level once/3 eanths Instrueent Channel Reactor High Water Level once/3 months once/day Inst rueent Channel RCIC?hrbine Stean Line High Plow once/3 nonths XnstrLaaent Channel RCIC Steaca Line Space High Temperature once/3 eonths

TABLE 4.2.B (Continued)

Function Functional Test Calibration Instrument Cheek Instrument Channel HPCI Turbine Steam Line High Flo~ once/3 months none Instrument Channel HPCI Steam Line Space High Temperature once/3 months none Core Spray System Logic once/6 months (6) N/A RCIC System (Initiating) Logic once/6 months 2/A N/A RCIC System (Isolation) Logic once/6 months N/A N/A HPCI System. (Initiating) Logic once/6 months (6) N/A HPCI System (Isolation) Logic once/6 mnths N/A 'N/h ADS Logic once/6 months (6) N/h KPCI (Initiating) Logic once/6 sonths (c) N/h LPCI (Containment Spray) Logic once/6 months (6) N/A Core Spray System Auto Initiation-Inhibit (Core Spray Auto Initiation) once/6 sonths (7) H/h N/h LPCI Auto Initiation Inhibit (LPCI Auto Initiation) once/6 months (7) N/h

TABLE 4.2.B (Continued)

Function Punctional Test Calibration Instrument Check Core Spray Loop h Discharge N/h once/6 months once/day Pressure (PI-75-20)

Core Spray Loop B Discharge N/A once/6 months once/day Pressure (PI-75-48)

RHR Loop h Discharge Pressure N/A once/6 months once/day (PI-74-51)

RHR Loop B Discharge Pressure N/h once/6 xmnths once/day (PI-74-65)

Instrument Channel << Tested during N/A N/h RHR Start functional test of RHR pump (refer to section 4.5.B).

Instrument Channel- once/month once/6 maths N/h Thcrmostat (RHR brea Cooler Fan)

Instrument Cbannel- Tested during N/A N/h Core Spray h or C Start functional test of core spray (refer to section 4.5.h).

Instrument Channel -. Tested during 1/h N/h Core Spray B or D start functional test of core spray (refer to section 4.5.h).

Instrument Channel- once/ month once/6 months '8/h Thersostat (Core Spray Area Cooler Pan)

TABLE 4. .B (Continued)

Function Punctional Test Calibration Instrument Check RHR brea Cooler Fan Logic Tested during N/A N/h functional test of instrument channels, RHR motor start and thermostst (RHR area cooler fan) . No other test required.

Core Spray brea Cooler Pan Logic Tested during logic N/h N/A system functional test of instrument channels, core spray motor start and thermo-stat (core spray area cooler fan). No other test required.

Instrument Channel- Tested during functional N/h N/A Core S pray Mo tore h or D S tar t test of core spray pump (refer to section 4.5.h).

Instrument Channel- Tested during functional N/K N/A Core Spray Motors B or C Start test of core spray pump (refer to section 4.5,h) .

Instrument Channel Tested dur'ing logic N/A N/A Core Spray Loop 1 Accident system functional Signal test of core spray system.

Instrument Channel- Tested during logic N/A N/A Core Spray 'Loop 2 Accident system functional Signal test of core spray

'ystem.

RHRSM Initiate Logic once/6 months N/A N/h

TABLE 4.2.C SURVEILLANCE REQOIREHENTS FOR INSTRUPZHYATION THAT INITIATE ROD BLOCKS Function Functional Test Calibration 17) Instrument Check APRH Upscale (Flov Blas) (13) once/3 aoaths once/day (8)

'I APRH Upscale (Startup Node) (13) once/3 months once/day (8)

APRH DoMascale (13) once/3 aoaths once/day (8)

APRt Inoperative (13) N/A once/day (8)

IUM Upscale (Plov Bias) ,(1) (13) once/6 aontbs oace/day (8)

RBH Dounscale (1) (13) ance/6 months once/day (8)

RBH Inoperative (1) (13) N/A once/day (8)

IRH Upscale (1)(2) (13) once/3'enths once/day (8)

ZRH Dovnscale (1)(2) (13> once/3 months once/day (8)

IRH Detector not in Startup (2) (once/opera- once/operating cycle (I2) N/h Position ting cycle)

IRH Inoperative (1>(2) '>>) N/h N/A SRH Upscale (l)(2) (13) once/3 soaths once/day (8)

SRH Douascale (1)(2). (>>) once/3 months once/day (8)

SRH Detector not in Startup (2) (once/opera- once/operating cycle 02) N/h Position ting cycle)

SRH Inoperative (1)(2) (13) N/A N/h Plov Bias Comparator (1)(15) once/operating cycle (2O) N/h Flov Bias Upscale (l)(1S) once/3 months N/h Bod Block Logic (16) N/A N/h RSCS Restraint (1) once/3 months N/A

TABLE 4.2.D SURVEILLA.'iCE REQUIRE{VlTS FOR OFF-GAS POST TREATMENT ISOLATION IHSKSIGZTATION Function Functional Test Calibration Instrument Check Off- Gas Post Treatment Monitor (l) once/3 months once/day (8)

Off-Gas Post Treatment Isolation once/6 nanths N/A N/A

TABLE 4.2.E MINIMUM TEST AND CALIBRATION FREQUENCY FOR DRYVELL LEAK DETECTION INSTRUMENTATION Punction Punctio'nal Test Calibration Instruient Check Equipment. Drain Sump Flov (4) once/6 months once/day Integrator Floor Drain Sump Plov Integrator (4) once/6 months once/day air Sampling System (l) once/3 months once/day Equipment Drain Sump Fill Rate (4) once/operating cycle N/A and Pumpout Rate Timers Floor Drain Sump Pill Rate and (4) once/operating cycle N/A Pumpout Rate Timers Equipment Drain Logic once/operating cycle (6) N/A Floor Drain Logic once/operating cycle (6) N/A

TABLE 4.2.F MINIMUM TEST AND CALIBRATION FREQUENCY FOR SURVEILLANCE INSTRUMENTATION Instrument Channel Calibration Fre uenc Instrument Check

1) Reactor Water Level Once/6 months Each Shift

2) Reactor Pressure Once/6 months Each Shift

3) Drywell Pressure Once/6 months Each Shift

4) Drywell Temperature Once/6 'months Each Shift

5) Suppression Chamber Air Temperature Once/6 months Each Shift

6) Suppression Chamber Water Temperature Once/6 months Each Shift

7) Suppression Chamber Water Level Once/6 months Each Shift

8) Control Rod Position NA Each Shift

9) Neutron Monitoring (2) Each Shift

10) Drywell Prcssure (PS-64-67) Once/6 months

11) Drywell Prcssure (PS-64-58B) Once/6 months

12) Drywcl.l Temperature (TR-64-52) Once/6 months NA

13) Timer (IS-64-67) Once/6 months NA

14) CAD Tank Level Once/6 months Once/day

15) Contdinment Atmosphere Honitors Once/6 months Once/day

TASLE 4.2.G SURVEILLANCE REQUIREMENTS POR CONTROL ROOM ISOLATION INSTRUMENTATION Punction Functional Test Calibration Instrument Check Control Room Air Supply Duct (1) once/3 months once/day (8)

Radiation Monitors Control Room Isolation Logic once/6 months N/A N/A Simulated automatic actuation of control room isolation and emergency pressuriration system once/operating cycle N/A N/A

TABLE 4.2.H MINIM TEST A%) CALIBRATION FREQUENCY FOR FLOOD PROTECTION INSTRUHENTATION Function Functional Test Calibration Instrument Check Instrument Channels Reservoir level (1) once/3 months N/A monitoring

Table 4.2,J Seismic Monitori. Instrunert Surveillance Requirements CHANNEL INSTRIKHT CHANNEL FUNCTIONAL TEST CALIBRATION TRIAXIAL TDE HIS "ORY ACCELOGRAPHS

a. Unit 1 reactor bl . base slab El. 51 .0) kont~. 6 months Unit 1 reactor bldg. floor slab

b. El. 621.25 Monthl+ 6 months Diesel-generator bldg base slab c~ ~

Yonthl~ 6 months CD BIAXIAL SEIS C "t( TCHES

~

Unit 1 reactor bid base lab l!onthl+ 6 months once/operating cycle Monthly. 6 months once/operating cycle C. Uni~treactor bid base lab Monthl+ 6 months once/operating cycle

+Except seismic britches

t NOTES FOR TABLES 4.2.A THROUGH 4.2.H

l. Functional tests shall be performed. once per month.

2. Functional tests shall be performed before each startup with a required frequency not to exceed once per week.

3. This instrumentation is excepted from the functional test definition.

The functional test will consist of injecting a simulated electrical signal into the measurement channel.

4. Tested during logic system functional tests.

5. Refer to Table 4.1.B.

6. The logic system functional tests sha11 include a calibration once per operating cycle of time delay relays and timers necessary for proper functioning of the trip systems.

7. The functional test will consist of verifying continunity across the inhibit with a volt-ohmmeter.

8. Instrument checks shall be performed in accordance with the definition of Instrument Check (see Section 1.0, Definitions). An instrument check is not applicable to a particular setpoint, such as Upscale, but is a qualitative check that the instrument is 'behaving and/or indicating in an acceptable manner for the particular plant condition. Instrument check is -included in this table for convenience and to indicate that an Instrument Check will be performed on the instrument. Instrument checks are not required when these "instruments are not required to be operable or are tripped.

9. Calibration frequency shall be once/year.

10. Tested during logic system functional test of SGTS.

ll. Portion of the logic is functionally tested during outage only.

12. The detector will be inserted during each operating cycle and the proper amount of travel into the core verified.

13. Functional test will consist of applying simulated inputs (see note 3).

Local alarm lights representing upscale and downscale trips will be verified, but no rod block will be produced at this time. The inopera-tive trip will be initiated to produce a rod Mock (SRM and IRM inoperative also bypassed with the mode switch in RUN). The functions that cannot be verified. to produce a rod block directly will be verified during the operating cycle.

109

NOTES FOR TABLES 4.2.A THROUGH 4.2.H Continued

14. Upscale trip ie functionally tested during functional test time as required by section 4.7.B.l.a and 4.7.C.l.c.

15. The flow bias comparator will be tested by putting one flow unit in "Test" (producing 1/2 scram) and adjusting the test input to obtain comparator rod block. The flow bias upscale will be verified by observing a local upscale trip light during operation and verified that it will produce a rod block during the operating cycle.

16. Performed during operating cycle. Portions of the logic is checked more frequently during functional tests of the functions that produce a rod block.

17. This calibration consists of removing the function from service and performing an electronic calibration of the channel.

18. Functional test is limited to the condition ~here secondary containment integrity is not required as specified in sections 3.7.C.2 and 3.7.C.3.

19. Functional test is limited to the time where the SGTS is required to meet the requirements of section 4. 7. C. l.c.

20. Calibration of the comparator requires the inputs from both recirculation loops to be interrupted, thereby removing the flow bias signal to the hPRM and RBH and scramming the reactor. This calibration can only be performed during an outage.

21. Logic test is limited to the time where actual operation of the equipment is permissible .

22. One channel of either the reactor zone or refueling zone Reactor Building Ventilation Radiation Honitoring System may be administratively bypassed for a period not to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for functional testing and calibration.

23. The Reactor Cleanup System Space Temperature monitors are RTD's that feed a temperature switch in the control room. The temperature switch may be tested monthly by using a simulated signal. The RTD itself is a highly reliable instrument and less frequent testing is necessary.

110

BASES

. In addition to reactor protection instrumentation which initiates a reactor scram, protective instrumentation has been provided which initiates action to mitigate the consequences of accidents which are beyond the operator's ability to control, or terminates operator er-rors before they result in serious consequences. This set of speci-fications provides the limiting conditions of operation for the primary system isolation function, initiation of the core cooling systems, con-trol rod block and standby gas treatment systems. The ob]ectives of the Specifications are (i) to assure the effectiveness of the protec-tive instrumentation when required by preserving its capability to tolerate a single failure of any component of such systems even during periods when portions of such systems are out of service for maintenance, and (ii) to prescribe the trip settings required to assure adequate per-formance. When necessary, one channel may be made inoperable for brief intervals to conduct required functional tests and calibrations.

Some of the settings on the instrumentation that initiate or control core and containment cooling have tolerances explicitly stated where the high

. and low values are both critical and may have a substantial effect on safety. The set points of other instrumentation, ~here only the high or low end of the setting has a direct bearing on safety, are chosen at a level away fromthe normal operating range to prevent inadvertent actua-tion of the safety system involved and exposure to abnormal situations.

Actuation of primary containmcnt valves is initiated by protective instru-mentation shown in Table 3.2.A which senses the conditions for which iso-lation is required. Such instrumentation must be. available whenever pri-mary containment integrity is required.

The instrumentation which initiates primary system isolation is connected in a dual bus arrangement.

The low water level instrumentation set to trip at 177.7" (538" above vessel zero) above the top of the active, fuel closes isolation valves in the RHR System, Drywell and Suppression Chamber exhausts and drains and Reactor Water Cleanup Lines (Group 2 and 3 isolation valves). The low reactor water level instrumentation that is set to trip when reactor water level is 129.7" (490" above vessel aero) above the top of the active fuel closes the Hain Steam Line Isolation Valves and Main Steam, RCIC, and HPCI Drain Valves (Group 1 and 7). Details of valve grouping and required closing times are given in Specification 3.7. These trip settings are adequate to prevent core uncovery in the case of a break in the largest line assuming the maximum closing time.

The low reactor water level instrumentation that is set to trip when reactor water level is 129.7" (490" above vessel aero) above the top of the active fuel (Table 3.2.B) also initiate the RCIC and HPCI, provides input to the 111

3~2 BASES LPCX loop selection logic and trips the recirculation pumps. The lov reactor water level instrumentation that is eet to trip when reactor vater level is 17.7" (378" above vessel zero) above the top of the active fuel (Table 3.2.8) initiates the LPCI, Core Spray Pumps, contributes to ADS initiation end starts the diesel generators. These trip setting levels vere chosen to be high enough to prevent spurious actuation but lov enough to initiate CSCS operation so that post accident cooling can be accomplished and the guidelines of 10 CFR 100 vill not be violated.

For large breaks up to the complete circumferential break of a 28-inch recirculation line and with the trip setting given above, CSCS initiation is initiated in time to meet the above criteria.

The high drywell pressurr instrumentation is e diverse signal to the water level instrumentation and in addition to initiating CSCS, it isolation of Groups 2 and 8 isolation valves. For the breaks discussed causes above, this instrumentation will initiate CSCS operation at about the same time as the lov water level instrumentation; thus the results given above ere applicable here also.

Vcnturls are provided in the main steam lines as a means of measuring steam flow end elrro limiting the loss of mass inventory from the vessel during a steam line break accident. The primary function of the instru-mentation is to detect a break in the main stcam line, For the vorst case accident, main steam line brcak outside the drywcll, a trip setting of 140X of rated steam flov in con)unction vith the flov limiters and main steam line valve closure, limits the mass inventory loss such that fuel is not uncovered, fuel cladding temperatures remain below 1000'F end release of radioactivity to the environs is well belov 10 CFR 100 guidelines. Reference Section 14.6.5 FSAR.

Temperature monitoring instrumentation is provided in the main steam line t.urrnel to dc(oct leaks in these arcerr. Tripe erc provided on this instru-mentation and when exceeded, cause closure of isolation valves. The setting of 200'F for thc main steam linc tunnel detector is lov enough to detect icakrr of the c rder of 15 gpm; thus,. it is capable of covering the entire spectrum of breaks. For large breaks, the high steam flov instru-mentation is a backup to the temperature instrumentation.

High radiation monitors in the main steam linc tunnel have been provided to detect gross fuel failure es in the control rod drop accident. Pith the established setting of 3 times normal background, and main steam linc isolation valve closure, fission product release is limited so that 10 CFR 100 guidelines are not exceeded for this accident. Reference Section 14 6.2 FSAR. An alarm, rAth n nornira1 set point of 1.5 x normaf fulL power trackrrround, is provided also.

Pressure instrumentat<on is provided to close the mein steam isolation valves in Run Mode when the main steam line pressure drops below 825 psigo 112

3.2 BASFS The HPCI high flow and temperature instrumentation are provided to detect a break in 'the HPCI steam piping. Tripping of this instrmrentation re-sults in actuation of HPCI isolation valves. Tripping logic for the high flow is a 1 out of 2 logic, and all sensors are required to be operable.

High temperature in the vicinity of the HPCI equipment is sensed by 4 sets of 4 bimetallic temperature switches. The 16 teraperature svitches are arranged in 2 trip systems with 8 temperature svitches in each trip system.

The HPCI trip settings of 90 psi for high flow and 200'F fo" high tera-peratur'e are such that core uncovery is prevented and fission product release is within limits.

The RCIC high flow and temperature instrumentation are arranged the sam as that for the HPCI. The trip setting of 450" H20 for high flov and 200'F for temperature are based on the same criteria as the HPCI.

High tempcratirre at the Reactor Cleanup System floor drain could indicate a break in tire cleanup system. When high temperature occurs, the cleanup system is isolated.

The instrumentation which initiates CSCS action is arranged in a dual bus system. As for other vital instrumentation arranged in this fashion, the Specification preserves thc effectiveness of the ystem even during periods when maintenance or testi'ng is being performed. An exception to thi's is when logic functional testing is being performed.

The control rod block functions are provided to prevent excessive control rod withdrawal so that MCPR does not decrease to 1.05 The trip logic

~

for this function is 1 out of n: c.g., any trip on one of six APRM's, eight IRM's, or four SRH's vill result in a rod block.

The minimum instrument channel rcquireraents assure su ff ic ien t ins t rumen ta-tion to assure the single failure criteria is met. The minimum instrument channel requirements for the RBM may be reduced oy one for maintenance, testing, or calibration. This time period is only 3% of. the operating time in a month and does not significantly increase the risk of preventing an inadvertent control rod withdrawal.

The APRM rod. block function is flow biased and prevents a significant reduc-tion in MCPR, especially during operation at reduced flow. The APRH pro-vides gross core protection; i.e., limits the gross core pover increase from vithdrawal of control rods in the normal vithdraval sequence. The trips are set so that MCPR is maintained greater than 1.05, The RBM rod block function provides Local protection of the core; l.e.,

the prevention of critical power in a local region of the core, for a single rod withdraval error from a limiting control rod pattern.

113

3. 2 BASES If the IRM channels are in the worst condition of allowed bypass, the sealing arrangement is such that for unbypassed IRM channels, a rod block signal is generated before the detected neutrons flux has increased by more than a factor of 10.

A downscale indication is an indication the instrument has failed or the instrument is not sensitive enough. In either case the instrument vill not respond to changes in control rod motion and thus, control rod motion is prevented.

The'efueling interlocks also operate one logic channel, and are required for safety only when the mode switch is in the refueling position.

For effective emergency core cooling for small pipe breaks, the HPCI system must function since r actor pressure does not decrease rapid enough to allow either core spray or LPCI to operate in time. The automatic pressure relief function is provided as e backup to the HPCI in the event the HPCI does not operate. The arrangement of the tripping contacts is such as to provide this function When necessary and minimize spurious operation. The trip settings given in the specification are adequate to assure the above criteria arc mct. Thc specification preserves the effectiveness of the system during periods of maintenance, testing, or calibration, and also minimizes the risk of inadvertent operation; i.e., only one instrument channel out of service.

Two post, treatment off-gas radiation monitors are provided and, >hen their trip point is reached, cause an isolation of the off-gas line. Isolation

'is initiated when both instruments reach their high trip point or one has an upscale trip and the other a downscale trip or both have a downscale trip.

Both instruments are required for trip but the instruments are set so that any instruments are set so that the instantaneous stack release rate limit given in Specification 3.8 is not exceeded.

Four radlntion monitors are provided for each un't ~hich initiate Primary Containment isolation (Group 6 isolation valves) Reactor Building Isolation and operation nf the Standby Gas Treatment System. These instrument channels monitor the radiation in the Reactor zone ventilation exhaust ducts and in the Refueling Zone.

Trip setting of 100 mr/hr for the monitors in the Refueling Zone are based upon initiating normal ventilation isolation and SGTS operation so that none of the activity released during the refueling accident leaves the Reactor Building via the normal ventilation path but rather all the activity is processed by the SCTS.

Flow integrators and sump fill rate determine leakage in the drywell.

and pump out rate timers are used to system whereby the time interval to fill A a known volume will be utilized to provide a backup, An air sampling system is also provided to detect leakage inside the primary containment (See Table 3.2.E).

3.2 BASES For each parameter monitored, as listed in Table 3.2.F, there are two channels of instrumentation except as noted. By comparing readings between the two channels, a near continuous surveillance of instzument performance is available. Any deviation in readings will initiate an early recalibra-tion, thereby maintaining the quality of the instrument readings.

Instrumentation is provided for isolating the control room and initiating a pressurizing system that processes outside air before supplying it to the control room. An accident signal that isolates primary containment will also automatically isolate the control zoom and initiate the emergency pressurization system. In addition, there are radiation monitors in the normal ventilation system that will isolate the control room and initiate the emergency pressurization system. Activity required to cause automatic actuation is about one mRem/hr.

Because of the constant surveillance and control exercised by TVA over the Tennessee Valley, flood levels of large mangitudea can be predicted in advance of their actual occurrence. In all cases, full advantage will be taken of advance warning to take appropriate action whenever zeservoir levels above normal pool are predicted; however, the plant flood protection is always in place and does not depend in any way on advanced warning.

Therefore, during flood conditions, the plant vill be permitted to operate until ~ater begins to run across the top of the pumping station at elevation 565. Seismically qualified, redundant level switches each powezed from a separate division of .power are provided at thc pumping station to give main control room indication of this condition. At that time an orderly shutdown of the plant will be initiated, although surges even to a depth of several feet over the pumping station deck will not cause the loss of the main con-denser circulating water pumps.

The operability of the meteorological instrumentation ensures that suf ficient meteorological data is available -for estimating potential radiation dose to the public as a result of routine or accidental release of radioactive materia1s to the atmosphere. This capability is required to evaluate the need for initiating protective measures to protect the health and safety of the public.

The operability of the seismic instrumentation ensures that sufficient capability is available to promptly d termine the magnitude of a seismic event and evaluate the response of those features impqrtant to safety.

This capability is required to permit comparison of the measured response to that used in the design basis for Browns*perry Nuclear P'ant. The instrumentation provided is consistent with specific portions of the recommendations of Regulatory Guide 1.12 "Instrumentation for Farthquakes."

The instrumentation listed in Table 4.2.A through 4.2.F vill bc func-tionally tested and calibrated at regularly scheduled intervals. The same design reliability goal as the Reactor Protection System of 0.99999 is generally applies for all applications of (1 out of 2) X (2) logic. There-fore, on-off sensors are tested once/3 months, and bi-stable trips asso-ciated vich analog sensors and amplifiers are tested once/week.

Those instruments which, when cripped, result in a rod block have their contacts arranged in a 1 out of n logic, and all are capable of being bypassed. For such a tripping arrangement with bypass capability provided, there is an opcimum test interval that should be maintained in order to maximize the reliability of a given channel (7). This takes account of the fact that testing degrades reliability and the optimum interval betveen tests is approximately given by:

, +z Mhere: i the optimum interval betveen tests.

t the time the trip contacts are disabled from performing their function while the the test is in progress.

r the expected failure rate of the relays.

To test thc trip relays requires that che channel be bypassed, the test made, and thc system returned to its initial'tate. It is assumed this task requires an estimated 30 minutes co complere in a thorough and vork-manlike manner and that the relays have a failure rate of 10 failures per hour. Ilsing this data and the above operation, the optimum test interval is:

~2(0. 5 ~O3

~

10 40 days For additional mar in a test interval of once er month vill be used

~in' ta 1 1 (7) UCRL-50451, Improving Availability end Readiness of Field Equipment Through Periodic Inspection, Ben)amin Epstein, Albert Shiff, July 16, 1968, page 10, Fquetion (24), Lawrence Radiation Laboratory.

Thc sensors and electronic apparatus have not been included here as these are analog devices vich readouts in che control room and the sensors and electronic apparncus can he checked by comparison with other like instru-ments. Thc checks vhich are made on a daily basis are adequate to assure operability of the sensors and electronic apparatus, and the test interval given above provides for optimum testing of the relay circuits.

116

4.2 BASKS The above calculated test interval optimizes each individual channel, considering it to be independent of all others. As an example, assume that there are tvo channels vith an individual technician assigned to each. Each technician tests his channel at the optimum frequency, but the two technicians are not allowed to coramunicate so that one can advise the other that his channel is under test. Under these conditions, it is possible for both channels to be under test simultaneously. Nov, assume that the technicians are required to communicate and that tvo channels are never tested at the same time.

Forbidding simultaneous testing improves the availability of the system over that which would be achieved by testing each channel independently.

These one out of n trip systems will be tested one at a time in order to take advantage of this inherent improvement in availability.

Optiraizing each channel independently may not truly optimize the system considering the overall rules of system operation. However, true system optimization is a complex problem. The optimums arc broad, not sharp, and optimizing the individual channels is generally adequate for the sys tera.

<'he formula given above minimizes the unavailability of a single channel vhich must be bypassed during testing. The minimization oE the unavail-ability is illustrated by Curve No. 1 o) Figure 4.2.1 vhich assumes that a channel has e failure rate of 0.1 x 10 /hour and 0.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> is require to test it. 3The unavailability is a minimum at a test interval i, of 3.16 x 10 hours.

If'vo similar channels are used in a 1 out of 2 configuration, the test interval for minimum unavailability changes as a function of the rules for testing. The siraplest case is to test each one independent of the other. In this case, there is assumed to be a finite probability that both may be bypassed at one tirae. This case is shown by Curve No. 2.

Note that the unavailability is lower as expected for a redundant system and the minimura occurs at the serac test'nterval. Thus, if the tvo channels are tested independently, the equation above yields the test interval for minimun unavailability.

A more usual case is that the testing is not done independently. If both channels are bypassed and tested at the same time, the result is shovn in Curve No. 3. Note that the minimum occurs at about 40,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />, much longer than for cases 1 and 2. Also, the minimum is'ot nearly as lov as Case 2 which indicates that this method of testing does not take Eull advantage of the redundant channel. Bypassing both channels Eor simul-taneous testing should be avoided.

The most likely case vould be to stipulate that one channel be bypassed, tested, and restored, and then immediately folloving, the second channel be bypassed, tested, and restored. This is shovn by Curve No. 4. Note that 117

there is no tzue minimum. The curve does have a definite knee and very little reduction in system unavailability is achieved by testing at a shorter interval than computed by the equation"for a single channel.

The best test procedure of all those examined is to perfectly stagger the tests. That 'i.s, if the test intezval is four months, test one or the other channel every two months. This is shown in Curve No. 5.

The difference between Cases 4 and 5 is negligible. There may be other arguments, ho~ever, that more strongly support the perfectly staggered teats, including reductions in human error.

The conclusions to be drawn are these:

1, A 1 out of n system may be treated the same as a single channel in terms of choosing a test interval; and

2. moze than one channel should not be bypassed for testing at any one time.

The radiation monitors in the refueling area ventilation duct which initiate building isolation and standby gas treatment operation are arranged in two 1 out of 2 logic systems. The bases given for the rod blocks apply heze also and were used to arrive at the functional testing frequency. The off-gas post treatment monitors are connected in a 2 out of 2 logic arrangement. Based on experience with instruments of similar design, a testing intezval of once every three months has been found adequate.

The automatic pressure relief instrumentation ran be considered to bo a 1 out of 2 logic system and the discussion above applies also.

118

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CUIII YG CURY< i I<+ 5 I".) I I 'I

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<00 104 los TEST IHTI:RYAL - (~) tIOUR5 B.<OWH5 lEI'RY HUCLEAR PLAHT FIIIAL 5AF ETY AHALYSI5 REPORT System Unavailability Figu c 4.2-l 119

ITXNC CONDITIONS FOR OPERATION SURVEILLANCE RE UIRZHENTS

).3 REACTIVITY CONTROL 4. 3 REACTIVITY CONTROL Applies to the operational status vf the control rod system Applies to the surveillance require-ments of the control rod system.

4

~Ob ective: ~Ob ective:

To assure the ability of the con- To verify the ability of the con-trol rod system to control reac- trol rod system to contxol reac-tivity. tivity.

~ae c 1 t i c a t t 0 n:

A. React iv i t l.imita t ions h. Reactivit Limitations

l. Reactivit mar in - core l. Reactivit mar in <<core

~loadie ~lnadin A sufficient number of con- Suf f icient control rods shall trol rods shall be operable be vithdravn following a re-so that the core could be fueling outage when core made subcritical in the alterations vere performed to mos t r eac t ive cond i t ion demonstrate vith a margin of during the op'crating cycle 0.38' k/k the core can be vith thc strongest control made subcritical at any'ime rod fully vithdravn and all in the subsequent fuel cycle other operable control ro's with the analytically deter-fully inserted. mined strongest operable con-2-. Reacti~vit mar in ino erable trol rod fully vithdravn and control rods all other operable.,rods fully inserted.

a. Control rod drives which can-not be moved with control rod drive pressure shall be o erable control rods considered inoperable. If a partially or fully with-drawn control rod drive can- a. Each partially or fully withdrawn operable control not be moved with drive or rod shall be exercised one scram pressure the reactor shall be brought to the Cold notch at least once each veek vhen operating above Shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and shall not be 30X pover. In the event started unless (I) investi- power operation is continu-gation has de."..onstr"ted that ing with three or more in-the cause of ;hc failure is operable control rods, this not a failed control rod test shall be performed at drive mechanism collct least once each day, vhen housing and (2) ad quate operating above 30X power.

shutdown margin has been demonstrated as'equired by Specification 4. S.A. 2. c.

b. The contro'od direc-tional control valves for inoperable control rods shall be disa~ad electrically. 120 4

~ .iITIHG CONDITIONS FOR 0?ERATION SURVZILL.ViCE RE UIR~~mTS

3. 3. A REACTIVITY CONTROLS i.3.A REACT'/ITY CONTROLS C~ Control rods with scram A second licensed operator times greater than those shall verify the confor-permit ted by Specif ica- mance to Specification tion 3.3.C.3 are inoper- 3.3.A.2.d befor a rod may able, but if they can be be bypassed in tha Rod inserted with control .rod Sequence Control Syst m drive pressure they need not be disarmed electri- c. hlien it is ini ially dc:e-.-

cally. mined that a control .c= is incapable o= nor;..al insertion

d. Control rods with a fail d an attempt to fully insc "

"Full-in" or "Full-out" the control rod shal'e position switch may be'y- made. If the control rc" canno- be fully insert cd, a passed in the Rod Sequence Control System and consi- shutdown margin tost sh-l.

dered operable if the actual bc made to dcmorstratc un '"

rod position is kno~~. These this condition tha thc "

rods must be moved in sequence can be r.:adc suhc: it'.ca: fully to their correct poaitions any reactivit> condition (full in on insertion or full during thc re'ainder oF t'.".".

out on withdrawal) . operating c>clc with t! c analytical ly dctcrr i ncd,

e. Control rods with inoperable highest worth contro! rod accumulators or those ~hose capable of wi.thdrawal, position canriot be positively withdrawn, and all other determined shall be consi- control rods capable oF dered inoperable. insertion fully inserted.

Inoperable control rods shall d. The control rod accumulators be positioned such that Speci- shall be determined operable fication 3.3.h.l is met. In at least once per 7 days by addition, during reactor power verifying that the pressure operation, no more than one and level detectors are.not in control rod in any 5 x 5 array the alarmed condition.

may be inoperable (at least 4 operable control rods must separate any 2 inoperable ones). If this Specifica-tion cannot be met the reac-tor shall not be started, or if at power, the reactor shall be brought to a shut-doMn condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> B. Control Rods B. Control Rods

l. Each control rod shall be The coupling integ&ty shall be coupled to its driv or verified for each withdrawn con-completely inserted and tha trol rod as xollavs:

121

I.IHITINC CONDITIONS FOR OPERATION SURVEILLANCE RE UIREHENTS

.B Control Rods 4.3.B Control Rods control rod directional control valves disarmed a. Verify that the control rod electrically..This require- is following the drive by ment does not apply in the observing a response in the refuel condition vhen the nuclear instrumentation each reactor is vented. Tvo con- time a rod is moved when trol rod dr'ives the reactor is operating may be removed above the pre-set power as long as Specification level of the RSCS.

3.3.A.l is met.

b. Mhen the rod is fully vith-dravn the first time after each refueling outage or after maintenance, observe that the drive does not go to the overtravel position.

2. The control rod drive 2. The control rod drive housing housing support system shall support system shall be inspected be in place during reactor after reassembly and the results pover operation or vhen the of the inspection recorded.

reactor coolant system is pressurized above atmospheric pressure with fuel in the reac-tor vessel, unless all control rods are fully inserted and Specification 3.3.A.l is met.

3. e. Whenever the reactor is in 3. Prior to the start of control the star'tup or run modes rod withdrawal at startup, and belo~ 2Q rated power the prior to attaining 2(Ff rated Rod Sequence Control System power during rod insertion at shall be operable. 'RSCS) shutdovn, the capability of the The Rod Sequence Control Rod Sequence'Control System (RSCS) an Note: the Rod North Minimizer to System (RSCS) has been evaluated only through th properly fulfill their functions first refueling outage. shall be verified by the follow-A comple t e r e-evalua t ion ing checks:

is required prior to opera tions following the first refueling outage.

122

LIYITIHG COHDITIOHS FOR OPERATION SURVEILLAHCE RZ UIR~~iS

> .3. B Control Rods 4.3.B Control Rods b~ During the shutdown procedure no rod movement is permitted a. The capability of the RSCS to pro-between the testing performed above 20>o power and the rein-perly fulfillits function shall be verified by the following tes'ts:

statement of the RSCS re-straints at or above 20+ Sequence portion Select a sequence power. Alignment of rod and attempt to withdraw a rod in tha groups shall be accomplished remaining sequences. Hove one rod prior to performing the tests. in a sequence and select t'ne remain-ing sequences and attempt 'to move a rod in each. Repeat for all

c. Whenever the reactor is sequences.

in the startup or run modes Group notch portion For each of the below 20X rated power the six comparator circuits go through Rod Morth Minimizer shall be test initiate; comparator inhibit; operable or a second license'd verify; reset. On seventh attempt operator shall verify that test is allowed to continue until the operator at the reactor completion is indicated by console is following tha illumination of test complete light.

control rod program.

b. The capability of the Rod North Minimizer (R~<<N) shall h<<Vao f <<4 <<l Leo so44 JroJ,lvwgg

'checks:

l The correctness of the control rod withdrawal sequence input to the R<<M computer shall be verified before reactor startup or shutdown.

If'pecifications 3.3.B.3.a 2. The RKH computer on line through .c cannot ba met tha diagnostic test shall 'oe reactor shall not ba started, successfully perf ormed.

or if the reactor is in the 3. Prior to startup, proper run or startup modes at less annunciation of the selec-than 20X rated power, it shall be brought to a shut- tion error of at least one down condition i~ediately. out-of-sequence control rod shall be veri ied.

4. Prior to startup, the rod block function of the R'<<l.

shall be verified by oving an out-of-sequence control rod.

5. Prior o obta'n'rg 20K rated power during rod inse :ion at shutdo~w, verify th latch ".g of the pr op er rod 123 group anc proper annunciation after insert errors.

TIna CO~OITIOis FOR 0PERATIO~ SURVEILLANCE RE UIRE~i. NTS 3.3 B Control Rods 4.3.B Control Rods Control rods shall not be When required, the pressncO withdrawn for startup or of a second licensed operator refueling unless at, least to verify the following of tvo source range channels the correct rod prograsL shall have an observed count rate be verified.

equal to or greater than 4. Prior to control rod vithdraval

~

three counts per second. for startup or during refueling,

5. .During operation with verify that, ac least tvo source limiting control rod pat- range channels have an observed terns, as determined by che count rate of at leapt three designated qualified person- counts per second.

nel, either:

a. Both RBH channels shall 5. When a limiting control rod be operable: pattern exists, an instrument or functional test oz the RBA shall be performed prior to

b. Control rod withdrawal withdrawal of tne designated shall be blocked. rod(s) and at least. once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter.

C'. Scram, Inserci~n, Times C. Scram Insertion Times

1. The average scram insertion After each refueling ou age all time, based on the deenergi- operablc rods shall be scram'ime sation, of the scram pilot valve tested f rom the fully withdrawn solenoids as time zero,. of. all position with the nuclear system operable control rod's in the pressuz'c above 950 psig (with reactor power. operation condi-. saturation temperature). This testing tion shall be no greater than: shall oe completed prior to exceeding 40Z po~er. Below 20'4 power, only rods X Inscrtad'rom Avg. Scram Inser- in those sequences (A12 and A34 or Pull Withdrawn B12 and B34) which were fully withdrawn in the region z rom 100Z 5 0.375 ~rod density to 50Ã rod density shall 20 0.90 be scram time tested. During all 50'0 2.0 scram ti..e testing below 20.". power 5.0 the RRA shall be operable.

124

LLNITIHG COHDITIOHS FOR oPERATIOH SHRVEILlAHCE RE UIREMEHTS

3. 3.C Scram Insertion T'mea 4.3.C Scram Insertion Times

2. The average of the scram inn>>r- At 16 ~eek intervals, 10X of the tion times for the three fn! test operable conirol rod drives shall opernblc control rods of all be scram timed above 800 psig.

groups of four control rods in Whenever such scram time measurc-a two-by-two array shall be no mente are made, an evaluation greater than: shall be made to provide. reason>>

able assurance that proper con-X Inserted From Avg. Scram Inser- trol rod drive performance is Full Withdrawn tion Times (sec) being maintained.

5 0.398 20 0.954 50 2.120 90 5.300 The maximum s;ram inscrtic!

time for 90X Insertion of !ny operable control rod shall not exceed 7.00 seconds, D. Reactivit Anomalies The reactivity eq!ivalcnt of During the startup test program and the difference between the actual etartup following refueling outagee, critical rod configuration and the the critical rod conf igura t ions vill expected configurntion during power be compared to the expected confi-operation shall not exceed 1Z 0k. gurations at selected opernting con-If this limit is exceeded, the ditions. These comparisons vill be reactor vill be shut down u~til the used ae base data for reactivity cause has been determined and cor- monitoring during subsequent power rective actions have been taken as operation throughout the fuel cycle.

appropriate. At specific power operating condi-tions, the critical rod configura-tion will be compared to the confi-guration expected based upon appro-priately corrected pant data. This comparison will be made at least every full pover month.

125

LIHITING CONDITIONS FOR OPERATION S'tJR'/EI LLAtiCE REOU IRlRFNTS 3.3 Reactivit Control 4.3 Reactiv~it Control E. If Specifications 3.3.C and .D above 'cannot be met, an orderly shutdown shall be initiated and the reactor shall be in the shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

126

3. 3/4. 1 BASKS:

A. React ivt t Limitet ion The requirements for the contxol rod drive system have been identf f ted by evnlur.x fng the need for reactivity control vis control rod movement over the full spectrum of plant condi-tions and events. A~ discussed in subsection 3.4 of the Pinal Safety Analysis Report, the control rod system design is intended to provide sufficient control of core reactivity that the core could be made subcritical wi.th the strongest rod fully withdrawn. This reactivity characteristic has been a basic assumption in the analysis of plant performance. Com-pliance with this requirement can be demonstrated conveniently only at the time of initial fuel loading or refueling. There-fore, the demonstration must be such that it will apply to the entire subsequent fuel cycle. The demonstration shall be per-formed with the reactor core in the cold, xenon-free condition and will show that the reactor is subcritical by at least R ~ 0,38X hk with the analytically determined strongest control rcd fully withdrawn.

The value of "R", in units of Xhk, is the amount by which the core reactivity, in the most reactive condition at any time in the subsequent operating cycle, is calculated to be greater than at the time of the demonstration. "R", therefore, is the difference between the calculated value of mnxisum cox'e reacti-vity during the operating cycle and the calculated beginning-of-life core reactivity. The value of "R" must be positive or zero and must be determined for each fuel cycle.

Tt e demonstration is pex'formed with a control rod which is cal-culated to be the strongest rod. In determining this "analy-tically strongest" rod, it is assumed that every fuel assembly of tha same type has identical material properties. In the actual core, however, the control cell material properties vary within allowed manufacturing to$ erances, and the strongest rod is determined by a combination of the control cell geometry and local k . Therefore, an additonal margin is included in the shutdown margin tost to account for the fact that the rod ut ed for the denonstation (the "analytically strongest") is not necessarily the strongest rod in t'e cora. Studies have been made which compare experimental criticals with calculated ciiticals. These studies have shown that actual criticals can be predicted within a givon tolerance band. Por gadolinia cores the additional margin required due to control cell material manu-facturing tolerances and calculational uncertainties has experi" mentally bosn detormined to be 0.38X bk. khan this additional margin is demonstrated, requirement is met it assures that the roactivity control

~

2, Reactivitv mar in - ino erable control rods - Specification 3.3.A.2 x'squires thar, a rod be taken out of service if it cannot be moved with drive pressure. If the rod is fully 127

inserted and disarmed electrically", it is in a safe position of maximum contribution to shutdown reactivity. If it is disarmed electrically 3.3/4.3 BASES in a non-fully inserted position, that position shall be consistent vith the )]utdown reactivity limitations stated in Specification 3.3.A.1.

Thi assures that the core can be shut down at all times with the remaining control ro<l assuming the strongest operable control rod does not insert. Also if damage within the control roQ drive mechanism and in p"r"cular, cracks in drive internal housings, canno. be ruled out, t,hc>> i i".cn>> ic 1>roble>>. <<ffccting a number of drives caiinot b" rul c<1 out,.

Circ>:;>I';iei>t.i<il c:rack:: rc"i>) l.iiig from n),r<'.n: iisninled ii>).c rgr:in>!lar occurred in the collet. housiiig of drive't. everal M<s.

corrosion )iavc.calcic):ing This gyp of ~ coiild occur in a number of <1! ives <<iic) if the cracks propagated until severance of the collet housing occurred, scram could be prevented in the affected roQs. Limiting the period of operation with a poten:i"'ly seve ecl rod after detecting one stuck rod will a u. e that the reactor will not be opera'cQ with a large niimber of rods with failed collet housin>gs. The Rod Sequence Control System is no. a>>tom,.tically bvp"s e6 until reactor power is above 20~i )>ower . '"here f'ore, cont,rol rod movement is restricted and the single notch exercise Suryeillance test is only perfo med above this pover level,. The Rod Sequ.:rice Con rol System prevents movement of out-of-sequence rods unless power i above 205.

B. Coii'rol Roc)ts as discussed ir. the FS>i'>R can lead to significant cor dam ge. If coupling integrity is maintaineQ, th possibility of a rod dropout; acci:ci.'. is eliminateQ. The overtravel position feature p. ovides a po itive chec): as only uncoupled dirives may rea h this posi-tion. ))eutron instriimentation rcspor>se to rod i.ovcmcnt provides a verification that. the rod'is follovi>..;-. it 'rive.

Absence of such response to drive movemcnt, could indicn'e an uncoupled condition. Rod position indication is required for proper function of the rod sequence control yst,e;., anQ the ro<l worth minir!iizer.

2. Tne contro'o'ous'ng support restrict. the outwarci move-ment of a con ro) rod to less than 3 inches in he ex remely remot,e e;ent o" a hous'ng failuie. Thc amo<uit of rene ivity vnich co.>ld bc aude,l by this small nz>our> 0> rod vi;.)idrnw!<1,

~

which is less than a normal single wit)id!a!al increment > will not cont. ioute to any damage to the primary coolant; system.

Thc <)c.si!,n ban)n is given in subscct.ion 3.y.P of tli> F;>kR anc) t;he safety evaluation is given in subsection 3.5.4. T!ii .

support; is no reouired if the reactor coolant system is at atmospheric pressure since there would t,hen be no driving force to rapidly eJect a driv housing. Additionally, the support is not required serted .nd if if all control rods are fully in-a.i adequ, te shutdow.i margin with one cont ol rocl vithdr::.wn )."s been demonstrated, since the reactor would remain subcritical even in the event of complete ejection of the strongest con'rol rod.

To disarm the drive electrically, four amphcnol type plug connectors are removed from t,he <li ivc insert anQ vith<lrnwnl sol noids rendering the rod incap b'e of withdrawal. This proceduie ='ouivalent o valving out the drive <ad is preferred because, in tni., condition, drive vater cools an<'i minimizes crud accumulation in the <lrive.

Electrical disa".ming does not eliminate pos't.ion indication.

128

3.3/4.3 BASESI 30 Thc Rod Worth Minimizer (Pl'M) and the Rod Sequence Control System (RSCS) restrict withdrawa!s and in.,crtions of control rods to prc-op<<elf 5<<d scqucnccn. All pat trrns associatcu witl:

these ccqu<<nccs have thc character l.".t lc that, as'uming the worst single deviation from thc scqu<<nce, the drop of any control rod from thc fully inserted position to the position of the control zod drive would not cause the reactor to sustain a power excursion resulting in any pellet average enthalpy in excess of 280 calories per gram. An enthalpy of 280 calories per gram is well below the level at which rapid fuel dispersal could 'occur (i.e., 425 calories per gram). Primary system damage in this accident is not possible unless a significant amount of fuel is rapidly dispersed. Ref. Sections 3.6.6, 7.7.A, 7.16.5.3, and 14.6.2 of the PSAR and NFDO-10527 and supplements thereto.

In performing th fdnction described above, the RVM ard RSCS azc not required to impose any restrictions at coze power levels in excess of 20 percent of rated. Ywtezial in the cited zeferc."t shows that it is impossible to reach 280 calories per gram in ti: ~

event of a control rod drop occurring xt power greater tnan 20

.percent, regardless of the rod pattern. This is true for all normal and abnormal patterns including those which maximize individual control rod worth.

ht power levels below 20 percent of rated, abnormal control rod patterns could prcduce rod worths high enough to be of concern relative to tl;e 280 calorie per gram zod drop limit.

In this range the kWM and the RSCS constrain the control rod sequences a>>d pattrrna to those whi.h involve only acceptable rod worths.

The Rod Worth liinimizer and the Pod Sequence Control System provide automatic supervision to assure that out of seq>>ence control rods will not b withdzawn or inserted; i.e., it limit" operator deviations from planned withdrawal sequences. Ref.

Section 7.16.5.3 of the FSAR. They sozve as a backup to procedure-.e control of control rod sequences, which 1'm't the maximum reacti-vity worth of control rods. In the event that the Rod Worth Minimizer is out of service, when required, a second licensed operator can manually fulfill the control rod pattern con-formance functions of this system. In this case, the RSCS is bach up by independent procedural controls to assure conformance.

129

The function" of thc RWN and RSCS make it unnecessary to specify a license limit on rod wor:h to preclude unacccptablc consequences in the event of a control rod drop. At low powers, below 20 percent, these devices force adherence to acceptable rod patterns. Above 20 percent of rated power, no constraint on rod pattern is required to assure that rod drop accident consequences are acceptable. Control rod pattern constraints above 20 percent of rated power are imposed by power distribution requirements, as defined in Sections 3.5. I, 3.5.J, 4.5. I, and 4.5.J of these technical specifications. Power level for automatic bypass of the RSCS function is sensed by first stage turbine pressure.

4, The Source Range Mo>>it'or (SRM) system performs no automatic safety system function; i.e., it has no scram function. It 130

does provide che operator vfch a visual i'nd'cation of neu-tron L. vel. The consequence<<of re cciv< cy acciderts ar.

functionn of >>he initial nc<<tron flux. The, rcqu<rem nc of at least 3 coun'ts pez second aasurcs that any crnr. iunt, should 0

it occur, oegins at or above hc Initial value of 10 of rated power <<. d in the analyses of trans'ants fzoa co>d conditions. One operabie SRH charm 1 would be adequate to monitoz th approach ca crit'cality us'ng hcmogencous patterns of scatter d control znd wi"hdraval. A 'mini. um of two operable SRH's are provided as an added corse. Iatism.

5. The Rod, Block Nonltor (RBM) is designed to auto~at'cally prevent- fuel dec<age in the event of erroneous rod Mithczaval from locations oi high power density during high poser level operation. Two channels arc provided, ana one of "nese may be bypeseed fzoo the console for nein cnance and/or testing.

Tripping of one of th channels Mill block erroreous rod vithdraval soon enough to prevent fuel damage. The speci-fied restrictions with one channel cut of ezyice conserva-tiv ly assure that fuel danage will noc occur due to rod vithdravel rrors when this condition exis>>s.

h Liaiting control rod patt rn is a pattern which results in the cor being on a thermal hydzaul'c limit (l.e.< l'ICPR - 1.25 or LHGR 18.5). During use of such pat erns, it is Judged that testing of the R<BN system pr'". to withdrawal of such rods to assure its operability will assure chat improper vith-draval does no>> occur; It's normally the rcsponGibility of the Nuclear Engineer to i<lenci!y th..se lim'ing pat"errs and the designated rods either <<hen the patterns are in'tially estaoli.;bed or as they develop duc to ch>> occurrence of inoperable control rods in' hcr than limiting patterns.

Other per'sonnel qualified to perform these functions may be designated by the plant aupezin cndcnt to pezfoxm cnese functions.

C. Scram Ins er t ion T ime s n

'he control rod system is desigred to bring 'ne r actor subcricical at a rate fast enough to p'revenc fu 1 da"age; ' to pzevenc thc from becoming less than'- 05 Tbe Limiting povez transient is that resulting from the inadvezcent operac'on of the HPCI system.

Analysis of th's crans"ent shows that the negative reactivity .at s r suiting from the scram (FSA",.

Figure 3'.l<.15) ~ich the average response of all the drives as giv n in the above speci fication, prorid the required protection, and lCPR remains grea c< r than 1 05.

< ~

Cn an ear'y B4R, some degradation o'ontrol r 'cxam pez omance occurr d duz'ng plant scaxtup ard vas dec - .inec! to be caused by

3. 3/4. 3 BASV.'j:

particulate material (probably construction debris) p.'ui;ging an internal control rod drive filter. The design of the present control rod drive (Hodel 7RDB144B) is gro.sly improved by the relocation of the filter to a lo ation out of the scram drive path: i.e., it Lan no longer interfere with scram performance, even if completely blocked.

The degraded performance of the original drive (CRD7RDB144A) under dirty operating, conditions and the insensitivity of the redesigned drive (CRD7RDB144B) has been demonstrated by a seri s of engineering tests under simulated reactor operating conditions. The successful performance of the new drive under actual operating conditions has also been demonstrated by consLstently good in-service test results for plants using the new Irive and may be inferred from plants using the older model driv with a modified (larger screen size) internal

~

filter which is 1 ss prone to plugging. Data has been documented by surveil-lanc reports in various operating plants. These include Oyster Creek, Monticello, Dresden 2 and Dresden 3. Approximately 5000 drive tests have been recorded to date.

Following identification of thc "plugged filter" problem, very frequent scram testa werc necessary to ensure proper performance.

However, the more frequent scram tests are now considered totally unnecessary and unwise for the following reisons:

1. Erratic scram performance has been identified as due to an obstructed drive filter "B"

in type "A" drives. The drives in BFNP are of the new type design whose scram performance is unaffected by filter condition.

2. The dirt load is primarily released during startup of the reactor when the icactor and its systems are first subjected to flows and pressure and thermal stresses. Special atten-tion and mea~iures <<re now being taken to assure cleaner system's. Recctors with drives identical or similar (shorter stroke, smal]er piston areas) have operated through many refuelLng cyrles with no sudden or erratic changes in scram performance. This preoperational and startup testing is

'ufficLent to detect anomalous drive performance.

3. he 72-hour nutagc limit which initiated the start of the

requent scram testing is arbitrary, having no logical basis other than quantifying a "ma]or outage" which might reasona-bly be caused by an event so severe as to possibly affect drive performance. This requirement is unwise because provides an incentive for shortcut actions to hasten returni.iq it

'on line" to avoid the additional testing due a 72-hour outage.

132

3. 3/4. 3 BASES:

The surveillance requirement for scram testing of all the control rods after each refueling outage and 10X of the control rods at 16-Meek intervals is adequate for determining the opera-bility of the control rod system yet is not so frequent as to cause excessive wear on the control rod system components.

The numerical values assigned to the predicted scram perfor-mance are based on the analysis of data from other BWR's with control rod drives the same as those on Browns Ferry Nuclear Plant.

The occurrence of scram times within the limits, but signifi-cantly longer than the average, should be viewed as an indica-tion of systematic problem with control rod drives especially if the number of drives exhibiting such scram times exceeds eight, the allowable number of inoperable rods.

In the analytical treatment of the transients, 390 milliseconds are allowed between a neutron sensor reaching the scram point and the start of negative reactivity insertion. This is ade-quate and conservative, when compared to the typically observed time delay of about 270 milliseconds. Approximately 70 milli-seconds after neutron flux reaches the trip point, the pilot scram valve solenoid power supply voltage goes to zero an approximately, 200 milliseconds later, control rod motion begins.

The 200 milliseconds are included in the allowable scram inser>>

tion times specified in Specification 3.3.C.

D, Reactivitv Anomalies During each fuel cycle excess operative reactivity varies as fuel depletes and as any burnable poiso'n i'upplementary con-trol is burned. The magnitude of this excess reactivity may be inferred from the critical rod configuration. As fuel burnup progresses, anomalous behavior in the excess reactivity may be detected by comparison of the critical rod pattern 'at selected base states to the predicted rod inventory at that state. Power operating base conditions provide the most sensitive and directly interpret able data relative to core reactivity. Furthermore, using power operating >ass conditions permits frequent reactivity compariso".s.

Requiring a reactivit> comparison at, the specified frequency as'sures that a compare son will be made before the core reactivity 133

3.3/4.3 BASES:

change exceeds 1X 4K. Deviations in core reactivity greater than 1Z 4K are not expected and require thorough evaluation. One per-cent reactivity limit is considered safe since an insertion of the reactivity into the core Mould not lead to transients exceeding design conditions of the reactor system.

134

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS A licabilit A licabilit Applies to the operating status Applies to the surveillance requireee of the Standby Liquid Control ments of the Standby Liquid Control Sys'em ~ System.

~Ob ective ~Ob eccive To assure the availability of 4 To verify the operability of the Standby system with the capability to Liquid Control System.

shut. down the reactor and main-tain,thc shutdown condition Mith-out the use of contro rods.

S ec ficaticn

• A. Normal S stem Availabilit

1. The standby liquid con- The operability of the Standby trol system shall be opera- Liquid Control System shall be veri-ble at all times vhen there fied by the performance of the is fuel in the reactor ves- folloMing tests:

sel and thc reactor ia not in a shutdovn condition l. At least once per month each Mith all operable control pump loop shall be functionee rods fully inserted except al)y tested.

as specified in 3.4.B.1.

2. At least once during each ope'rating cycle:

a. Check tha t the set ting of the system relief valves is 14"5 + 75 psig.

b, Manually initiate the sys-tem, except explosive valves.

Pump boron solution through the recirculation path and back to the Standby Liquid Control Solution Tank. Mini-mum pump flov rate of 39 gpm l35

LIMITINC CONDITIONS FC"-. OPERATION SURVEILLANCE RE UIREMENTS 3.4 STANDBY Ll UID CONTROL SYSTEM STANDBY LI UID CONTROL SYSTEM against a system head of 1275 psig shall be verified. After pumping boron solution, the sys-tem shall be flushed with demineralized water.

c. Manually initiate one of the Standby Liquid Con-trol System loops and pump demineralized water into the :eactor vessel.

This t st check explosion of the charge associated with the tested loop, proper operation of the valves, and pump opera-bility. Replacement charges shall be selected such that the age of charge in service shall not exceed five years from the manufacturers assembly date.

d. Both systems, includinF, both explosive valves, shall be, tested in the onenes:

8.

course of two operatinr, cycles.

Surveillance with Ino erablc e

~Com ~Com onenes:

l. Prom and after the date l. When a component is found tn that a redundant compo- be inoperable, its redundant nent is made or found to component shall bc demon-be inoperable, Specifica- strated to be operable tion 3.4.A.l shall be con- immediately and daily there-sidered fulfilled and con- after until the inopcrablc tinued operation permitted component is repaired.

provided that the component is returned to an operable condition within seven days, 136

L:ll'TING CONDITIONS FOR OPFRAI'ION SURVEILLANCE RE UIREHENTS 3.4 5'1a BY LI UID CONTROL SYSTEH 4.4 STANDBY LI UID CONTROL SYSTEH C. Sodium Pentaborate Solution C. Sodium Pentaborate Solution At all times vhen the Standby The folloving tests shall be Liquid Control System is re- performed to verify the avail-quired to be operable the fol>> ability of the Liquid Control loving conditions shall be met: Solution:

l. The net volume concentra- 1. Volume: Check at least tion of the l iqiid Control once per day Solution in the liquid con-trol tank shall be main- 2. Temperature: Check at tained ns required in least once per day.

Figure 3.4.l.

2. The temperature of the 3. Concentration: Check at liquid control solution least once per month.

shall be maintained above Also check concentration the curve shovn in Figure any time vater or boron 3.4.2. This includes the is added to the solution piping betvcen the standby or solution temperature liquid control rank and is belov the temperature the suction inl't to the required in Figure 3.4.2.

pumps.

D. If specif icatior 3.4.A 'throu> h C cannot be met, the reactor shall be placed in.a Shutdovn Condition vith all operable control rods fully inserted vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

137

21 cv 19 REGION OF REQUIRED Ig VOLUME-CONCENTRATION CV ay F4 (3o350 gal <<16.3$ ) (~,850 EW - 16.3.)

~ 0 o

5 g 14 (4 60 gal-13.4~)

(4630 gal-l2.lie)

'p.'2 LOW.LEVEL ALARM F~ I

~<oooo al-11.6%)

c ll )

I 10 HIGH.LEVELI ALARM I

T NK OVERFLOW ~

2500 3000 3500 4000 4500 5000 NET (OLUME Of SOLUTION IN TANK (gal)

SROWHS FERRY HUCt.EAR PLAHT FIHAL'SAFETY AHALYSIS REPORT GODIlN PEiVZABORATE SOLUTIGN VOLVME-CONCENTRATED REQUIREÃ:-NTS PIGURE 3.4-1 138

~ so SOLUTION TEMPERATURE MUST BE EQUAL TO OR GREATER THAN THAT INDICATED BY THE CUl(VE.

ep 70 f6o Eel 50

~ ..

10 15 SODM PENTABORATE SOLl"l'ION (5$ v/0 NBPBIP016 H20)

~

BROWHS FERRY HUCLEAR PLAHT FINAL SAFETY ANALYSlS REPORT SODIUM PENTABORATE SOLUTION TEMPERATURE REQUIREMENTS FIGURE 3.4 2 139

.4 A. If no more than one operable control rod is withdrawn, the basic shutdown reactivity requirement for the core is satisfied and the Standby L)quid Control System is not required. Thus, the basic reactivity requirement for the core is the primary determinant of when the liquid control sys-tem is required.

The purpose of the liquid control system is to provide the capability of e,

bringing thc reactor fzom full power to a cold, xenon-free shutdown condi-tion assuming that none of the withdrawn control rods can be inserted.

To meet this objectiv,, the liquid control system is designed to inject a quantity of boron that. produces a concentration greater than 600 ppm of boron in the reactor core in less than 125 minutes. The 600 ppm con-centration in the reactor cere is'equired to bring the reactor from full power to a five percent dk subcritical condition, considering the hot to cold reactivity difference, xenon poisoning, etc. The time requirement for inserting the boron solution was selected to override the rate of reactivity insertion caused by cooldown of the reactor fol-

~owing the xenon poison peak.

T e minimum limitation on the relief valve setting is intended to prevent the loss of liquid control solution via the lifting of a relief valve at too low a pressure. The upper limit on the relief valve settings provides system protection from overpressure.

B. Only one of the two standby liquid control pumping loops is needed for operating the system. One inoperable pumping circuit does not immed-iately .threaten shutdown capability, and reactor operation can continue while the circuit is being repaired. Assurance that the remaining system will perform i'ts intended function and that the long-term average availability of the system is not reduced is obtained fro a one-out-of-two system by en allowable equipment out-of-service time of one-third of the normal surveillance frequency. This method determines an equip-ment out-of-service time of ten days. Additional conservatism is introduced by reducing the allowable out-of-service time to seven days, and by increased testing of the operable redundant component, C. Level indication and alarm indicate whether the solution volume has changed, which might indicate a possible solution concentration change.

The test interval has been established in consideration of these factors.

Temperature and llquM level alarms for the system arw annunciated in the control room.

The solution is kept at least l0'F above the saturation temperature to guard against boron preqipitatfon. The margin is included in Figurc 3.4.2.

The volume concentration requirement of the solution are such that should evaporation occur from any point within the curve, a low level alarm will annunciate before the temperature-concentration requirements are exceeded.

140

BASFS:

The quantity of stored boron includes an additional margin (25 percent) beyond the amount needed to shut dovn the reactor to allov for possible i'>perfect mixing of the chemical solution in the reactor vater.

A minimum quantity of 4,160 gallons of solution having a 13.4 percent sodium pentaborate concentration or the equivalent is required to meet this shutdovn requirement as defined in Figure 3.4.1.

+.4 BASES: STANDBY Ll U1D CONTROL SYSTEM Experience with pump operability indicates that the monthly test, in combination Mith the teste during each operating cycle, is sufficient to maintain pump performance. Various components of the system are individually tested periodically, thus making unnecessary more frequent testin of the entire system.

The solution temperature and volume are checked at a frequency to assure a high reliability of operation of the system should it ever be required.

142

t WHITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREHENTS 3.5 CORE AND CONTAINMENT COOLING 4.5 CORE AND CONTAI T COOLING SYSTEMS SYSTEMS A licabilit A licabilit Applies to the operational Applies to the surveillance status of the core snd contain- requirements of the core and ment cooling systems. ~ containment cooling systems @hen the corresponding I'imit&g condi-tion for operatioh io in affect.

~OS ective ~OS ective To assure the operability of To verify the operability of the the core and containment cooling core and containmsnt cooling sys tems under el 1 conditions for systems under all conditions for uhich this cooling capability is uhich this cooling capability is an essential response to plant an essential response to plant abnormal% ties. abnormalities.

deci f ice t ion v A. Core S ra S stem CSS A. Core S ra S'tem CSS

1. The CSS shall be opera- 1. Core Spray System Testings ble:

Item ~tte veee (1) prior to reactor stertup from e Simulated Once/

cold condition; or Automatic Opera ting Actuation Cycle (2) uhen there is irra- test diated fuel in the vessel and uhcn the b. Pump Opera- Once/

reactor vessel pres- bility month BUra is greater than atmospheric prcssure, C ~ Motor Once/

cxccpt as specified Opera ted month in specifications Valve 3.5.A.2, 3.5.B.2, or Operability 3.9.B.3.

d. System flou Once/3 rate: Each months loop shall deliver at least 6250 gpm against a system head corres-ponding to a 143

TING CONDITIONS H)R OP%ATION SUR~r. LLANCE REQUIREMENTS 3.5.A Core S ra S stem C~SS 4.5.A Core S ra S stem CSS

2. tf One CSS loop io inopera- 105 psi dif-ble, the reactor may remain ferential in operation for a period pressure not to exceed 7 days provi- betveen the ding all active components reactor ves-in the other CSS loop and the sel and the RHR system (LPCI mode) and the primary con-diesel generators are operable. tainment.

3. It specification 3.5.A.l Check Valve Once/

or specification 3.5.A.2 Operating cannot be met, the reactor Cycle she'll be shutdovn in the Cold Condition Mithin 24 2. When it is determined that one core spray loop is inoperable hours.

at a time when operability is When the reactor veosel reqUired, the other core spray pressure is atmoopheric loop, the RHRS (LPCI mode), and and irradia t ed fue1 is in the diesel gerlerators sha'l1 be demonstrated to be operable the reactor vessel at least one core spray loop immediately. The operable core Mith one operablc pum'p and spray loop shall be demonstrated associated diesel generator to be operable daily thereafter.

shall be opernble, except vith the reactor vessel head removed as specified in 3.5.A.5 or prior to reactor startup as specified in 3.5.A.l.

5. When irradiated fuel is in the reactor vessel and the reactor vessel head is removed', core spray is not ".eouired provided not in progress vhich has vora's the potential to drain the vessel, provided the fuel pool gates are open and the fuel pool is maintained above the lov level alarm point, and. provided one RHHSV pump and, associated valves supplying the standby coolant supply are operable.

144

t LIMITLiG CO"IDITIOtiS POR 0?E?ETIO I SURVEILLANCE REQUIRE~~

3.5.II Reeldunl Hest Rc((>oval System 4.5sB Residual Hest Removal S stem

~HHHS (LPCI snd Contatnnsnt ~HHHS (LFC( and Contstnnsnt i

Cot71 tip ) Cooling)

1. 'The RIIRS ehell be operable: l. a. Simulated Once/

Automatic Opera ting (l) prior to e reactor Actuatior> Cycle startup from a Cold Test Condition; or (2) when there i>> irra- b. Pu>(>p Opera- Once/

diated fuel in the bility month reactor vessel end when the reactor vessel pres- c. Motor Opera- Once/

sure is greater than ted valve month atmospheric, except as operability specified in specifica-tions 3.5.B.2, through d. Puap Plow Rata Once/3 3.5.8.7 and 3.9.B.3. months

2. With ti>c rcsctnr vessel pres- e. Test Check Valve Once/

sure lee>> tl>en l05 psig, the Operating

>PHRS mey be rentoved from ser- Cycle vice (except that two RHR pumps-containmcnt cooling mode snd Each LPCI pump shal1 aelive associated heat cxchsngers must 9,000 gpm against an ind.'cate" remain operable) for a period sys tem pressure of 125 ps ig. Two not to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> while LOCI pumps in the same loop shall being dra.ned of suppression deliver 15,000 gpm against an chamber quality water and indicated system pressure of filled with prir.:ary coolant 200 psig.

quality ~ster provided that 2. An air test on the drywell and during cooldo(~ two locps w>th torus heede."s and no=ales shall one pump per loop or one loop Wth two pumps, and associated diesel be coniiucted once/5 years. A generators, in the core spray syste water test nay be perforned on are operable. the torus header 'in lieu of the air teat.

3. lf onc RIIR pump (I.PCI mode)

3. When it is determined that one RHR inoperable, Cbe renctor pump (LPCI mode) is inoperable at a may rc mein lr> nperstion <or a time when operability is required, period not to exceed 7 days provided the remaining RHR the remaining RHR pumps (LPCI mode) pump>> (I.PCI mode) and both and active components in both access nccces peti>>> of hc. RHRS paths of the RHRS (LPCI mode) and (I.PCl node) end the CSS and the CSS and the diesel generators the diesel generators remain shall be demonstrated to be opera-operable. ble immediately. The operable RHRS pumps (LPCI mode) shall be demon-strated to be operable every 10 days thereafter until the inoperable pump is returned to normal service.

145

PAGE DELETED 146

<IT I})r, Cl);)AITIONS VAR r)P}',RATIr)H SURVEILLAilC}.'E U IR},"M}.'HTS

d. S. B Raelduai Heat Praauai ~9e".e~ 4.5.B Residual }lent Removal S stem

~llHPS) (LPCl and Cantninnent ~R(C(S (LPCI and Cantainnent Cooling) Cooling) 4, If any 2 RHR puraps (LPCI mode) 4. Vhen it is determined become inoperable, th reactor that more than one RHR shall be placed in the cold. pump (LPCZ mode) as allowed shutdown condition within in 3.5.3.4 is inoperable when 2R ilOUZS operability is required, the CSS, remaining RER pumps, and the diesel generators shall be demonstrated to be operable immediately and daily thereafter until at least three RIIR pumps (LPCI mode) are returned to normal semice.

S. I F one RHR pun r) (conta o's-in- S. When it irs dot zmincd that one mcnt cooltng s>>de) RHR pu:1p (containment cooling sociated'eat exchanger is node) oz associated heat inoperab1.e, the reactor exchanger ia inoparablc at a

)aay remain in opezation for time when opezability is ze-a period not t>> exceed 30 quized, the reraaining RHR days provided t})e remaining pumps (containment cooling node),

R}iR pumps (containment the associated heat exchangcrs cooling mode) and asso- and diesel genezatorsd and all ciated heat exchangezs and active components 'n the access d'csel genera"ors and all paths of the R}BS (containm nt access paths of the RHRS cooling node) shall ba de(wn-(containment cooling mode) strated to be operable im)aediately are operable. and weekly thereafter until the inqpezable RHR pump (containment cooling ~de) snd associated heat exchanger is returned to nornal service.

6. If two RHR pumps (containment 6. N:en it is determined that two cooling mode) nr aosociatad RHi pu(aps (con tainmen t oo ling hea" cxchangezo are tnopera- mode) oz asaociat d heat exchangers blc, the reactor may remain are (noperable at a time when in operation f('r a pP riod operability is required, the not to exceed 7 days pro- remaining RHR pumps (contaf.ruaent vided thc re(ra)ning RHR pumps coo)ning modt) the associated p

(containment cooLing clods) heat exchangers, and diesel and associated heat exchangezs generators, and all active corn<<

and all access paths of the ponent3 in the access paths of RHRS (containment cool'ng mode) ths RHRS (contalnmant cooling 147

L< TING CONDITIONS FOR OPERATION SURVEILLANCE RK UIRVKNTS 3.5.B Residual ))eat Removal S stem 4.5.8 Residual Heat Removal S stem RHRS) (LPCI and Containment ~RRRS (LPCI nnd Cannadnnnnn Cooling) Cooling) are operable. mode) shall be demons rated to be operable immediately and daily thereafter until at least three RHR pumps (containment cooling mode) and associated heat exchengera are return"d to normal service,

7. If two access paths of the, 7 ~ When it is determined that one RHRS (containment cooling or more access paths of the mode) for each phase of the RHRS (containment cooling mode) mode (dry+oil sprays, sup- are inoperable when access is pression chamber sprays, required, all active components and suppression pool cooling) in tho access paths oi the RHRS aze not operable, the unit (containment cooling mode) shall mey remain in operation for a bo demonstrated to be operable period not to exceed 7 days immediately end ell active com-provided at least one path ponents in the access paths or each phase of the mode which are not back d by e second remains opereblo. operable access path for the same phase of the mode (dryMell spzeys, suppression chamber sprays and suppression pool cooling) shall be demonstrated to be ooera-ble daily thereafter until the second path is returned to nor-mal service,

8. If specifications 3.5.B.l 8. No additional surveillance through 3.5,B.7 are not met, requized.

an orderly shutdown shall be initiated end the reactor shall be shutdovn and placed in the cold condition Mithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

9. When the .r actor vessel pres- 9. When tho rea-tor vessel pressure sure is atmospheric end irra- is atmospheric, the MiR pumps diated fuel is in the reactor and valves that aze required to vessel at least one RHR loop be oporabl shall be domonstratad Mith tvo pumps or tvo loops to be operable monthly.

Mith ono pump per loop shell be operable. The pumps'sso-ciated diesol generators must also be operable.

10. If the conditions of specifica-I tion 3.5.A.5 are met, LPCI end containment cooling are not 148 required.

LIMXTXNG CONDXTXONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.5.B Residual Heat Removal S stem 4.5.B Residual tleat Removal S st".m

~RHRS (LPCI and Cnntadnnent ~RHRS (LPCI and Cnnta(nnent Cooling) Cooling)

11. When there is irradiated fuel 10. The RHR pumps on the adja-in the reactor and the reactor cent units which supply vessel pz'essure is greater than cross-connect capability atmospheric, 2 RHR pumps and shall be demonstrated to be associated heat exchangers and operable monthly when the valves on an adjacent unit must cross-connect capability be operable and capable of is required.

supplying cross-connect capabil-ity except as specified in speci-fication 3.5.B.1Z below.

(Note: Because cross-connect capability is not a short term requirement, a component is not considered inoperable i.f cross-connect capability can be re-stored to service within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.)

12.

If one RHR pump or associ- When it is determined ated heat exchanger located that one IUD pump or on the unit cross-connection associated heat exchanger in the adjacent unit is in- located on the unit cross-operable for any reason (in- connection in the adja-cluding valve inoperability, cent unit is inoperable pipe break, etc.), the at a time when operabil-reactor may remain in opera- ity is required, the tion foz a period not to remaining RHR oumo and exceed 30 days provided the associated hea" exchanger remaining RHR pump and on the unit cross-con-associated diesel generator nection and the associ-are operable. ated diesel generator shall be demonstrated to be demonstrated to be operable iaxnediately and every 15 days thereafter until the inoperable pu-and associated heat ex-changer are returned to normal service.

149

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS

13. If RHR cross-connection flow or heat removal capability is host, the unit may remain in operation for a period not to exceed 10 days unless such capability is restored.

12. All recirculation pump discharge valves shall be tested for operability

14. All recirculation pump during any period of discharge valves shall reactor cold shutdown be operable prior to exceeding 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, operability tests if reactor startup (or have closed if permitted elsewhere in these not been performed during the preceding specifications), 31 days, 150

LINITINC CONDITIONS FOR OPERATION SURVEILLANCE REOUIREHENTS 3.5.C RHR Service Water and Emer enc 4.5.C RHR Service Water and Emer encv E ui ment Coolin Water S stems E ui ment Coolin Water S stems

~(EECWE (EECWE)

1. Prior to reactor startup from a l.,a. Each of the RHRSW pumps cold condition, 9 RHRSW pumps must normally assigned to be operable, with 7 pumps (includ- automatic service on ing pump Dl or D2) assigned the EECW headers will to RHRSW service and 2 auto- be tested automatically matically starting pumps each time the diesel assigned to EECW service, generators are tested.

Each of the RHRSW pumps and all associated essential control valves for the EECW headers and RHR heat exchanger headers shall be demon-strated to be operable once every three months.

b. Annually each RHRSW pump shell be flow-rate tested. To be considered operable, each pump shall pump at least 4500 gpm through its normally assigned flow path.

151

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS E ui ment Coolin Water S stems (EECWS) (Continued)

2. During power operation, 2. a. If no more, than two RHRSW pumps must be RHRSW pumps are inop-operable and assigned erable, increased to service as indicated surveillance is not below for the specified required.

time limits.

b. When three RHRSW pumps are inoperable, the remaining pumps, asso-TIME MINIMUM ciated essential con-L IMIT SERVICE ASSIGNMENT EECW**

trol valves, and asso-(DAYS) RHRSW ciated diesel genera-tors shall be operated Indefinite weekly.

30 7A or 6A* 2* or 3*** c. When four RHRSW pumps are inoperable, the remaining pumps, asso-ciated essential con-

• At least one operable pump must be trol valves, and asso-ciated diesel genera-assigned to each header. tors shall be operated

• "Only automatically starting pumps daily.

may be assigned to EECW header service.

• ':*Nine pumps must be operable. Either configuration is acceptable: 7 and 2 or 6 and 3.

3. During power oper- 3. Routine surveillance for ation both RHRSW pumps Dl these pumps is specified and D2 normally or alter- in 4.5.C.1.

nately assigned to the RHR heat exchanger header supplying the standby coolant supply connection must be operable except as specified in 3.5.C.4.a below.

152

LIHITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREHENTS

3. 5.C (Continued) 4.5.C (Continued)

4. 4. When one it is determined that of the RHRSW pumps sup<<

One of the Dl or D2 RHRSW plying standby coolant is pumps may be inoperable inoperable at a time when for a period not'to operability is required, the exceed 30 days provided operable RHRSW pump on the the operable pump is same header and its asso-aligned to supply the RHR ciated diesel generator and heat exchanger and the the RHR heat exchanger associated diesel gen- header and associated essen-erator and the essential tial control valves shall control valves are oper- be demonstrated to be able.. operable immediately and every 15 days thereafter.

5. If Specification 3.5.C.2 through 3. 5.C. 4 are not met, an orderly shutdown of the l

unit shall be initiatedl and the unit placed in cold shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

153

LIMITINC CO'. ITIOUS POR OPERATION SURVEILLANCE REOUIR~c. TS.

3.5.D E ui "..r;nt Arcs Coolerrr 4.5.D E ui ment Area Coolers

l. The equipment arcs cooler 1. Each equipraent area coolers associated with each RHR is operated in con)unction pump and the cquipmcnt area with the equipment served by cooler associated with ecch that patticular cooler; set of core sprav pumps therefore, the equipment area and C or S,and D) raust be coolers are tested at the operable at all times when serac frequency as the pumps the purap or pumps served by which they serve.

that specific cooler is considered to be operable.

2. When an equipment area cooler is not operable, the poses'~

pu=p(s) served by that cooler nus t be considered inoperable for Technical Specification pur-E. Yi h Pressure Coolant In ection E. Hi h Prcssure Coolant In ection S stem HPCIS)

l. The HPCI sygtem shall be 1. HPCI Subsystem testing shall operable: be perforned as iollows:

(1) prior to etartup from " a. Siraulated Once/

Cold Condition; or Automatic operating Actuation cycle (2) whenever there is irra- Test diated fuel in the reac-tor vessel ond the reactor b. Pump Opera- Once/

vessel pressure is greater bility rronth.

than 122 psig, except oo specified in specifica- c. Motor Operated Once/

tion 3.5.E.2. Valve Opera- month bility

d. Plow Rate at Once/3 normal reactor months vessel opera-ting pressure

e. Plow Rate at Once/

150 pa'g operating cycle The HPCX pump shall deliver at least 5000 gpn during each flow rate test.

154

This page intentionally blank 155

LIHIT a."O CO.'lDTTIO.'iS FOP. GP t&TIOM SURVEILLANCE RE"UIRr")E".TS 3.3.E ~Ht 'h l't .a "nto Coolant ln'lcctlon 4.5.E Hi".h Prcssure Coolant In/'Qction

2. If the HPCI system is inopera- 2. When it is determined that ble, thc reactor may remain in thc HPCIS is inoperable the operation for a period not to ADS actuation logic, the exceed 7 days, provided the RCICS, thc RHRS (LPCI), and ADS, CSS, RHRS (LPCI), and the CSS shall bc demonstrated RCICS are operable. to be operable immediately.

The RCICS and ADS logic shall be demonstrated to be operable daily thereafter.

3. If specifications 3.5.E.l or 3.5.E.2 are not met, an orderly shutdown shall be initiated and the reactor vessel pressure shall be reduced to 122 psig or less within 24 hours.

F, Reactor Core Isolation Coolin F. Reactor Core Isolation Coolin

1. The RCIGS.shall be operablc: 1. RCIC Subsystem testing shall be performed as follows:

(1) prior to otartup from a Cold Condition; or a; Sic)ulatcd Auto- Once/

matic Actuation operating (2) whenever there is irra- Test cycle diated fuel in the reac-tor veoocl and the reac- b. Pump Operability Once/

tor vessel pressure is nonth abovel22 psig, except as speci f ied in 3. 5.F. 2. c. Hotor Opera tcd Once/

V alve Ope".'ab ili ty month

d. Flow Rate at Once/3 normal reactor nun ths vessel operating prsssure

e. Flow Rate at 150 Once/

psig opera ti.-..g cycl.c The RCIC pump shall "el ivc:

at least 600 gpm duri"g ea '.;

flow test.

156

LIHITIhn CO;IOI'I'IOTAS V<)I; OPERATII))I SuRVEI I.I.ABACI: RI UIRI"IFNTS 3.5.F R<<nctnr Cnr<< Isolation Cooling 4.5.F Rcacror Core Isolation Cooling

2. If thc RClcs Is inopc rab'c, 2. When it is detcrmincd that the tlic reactor may remain in RCICS's inoperablc, the llPCIS operation for a period not shall be demonstrated to be to exceed 7 days if thc operable immediately and weekly HPCIS is operable during thereafter.

such time.

3~ If specifications 3.5.F.l or 3.5.F.2 are not mct, an orderly shutdown shall be initiated and thc reactor shall bc dcprcssurizcd to less than 122 paig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

C. Automatic Drnrcss<<rization C. Automatic Denressurization Five of t'e six valves nf .-1. During each operating cycle the Automatic Dcpressuri- the following teats shall bc zation System shall be performed on the ADS:

operable:

a. A simulated automatic (1) prior to a itartup actuation test shall be from a Cold Condition, perfo)~cd prior to startup or, after each refueling out-age. Nanual surveillance (2) uhenevcr there is irra- of thc relief valves is diated fuel in the reac- covered, in 4.6.D.2.

tor vessel and the reactor vessel prcssure ia greater than lo5 psig, except as specified in 3.5.G.2 and 3.5.C.3 below.

2. If more than one ADS valve is 2. When it is determined that more than known to be incapable of one of the ADS valves are incapable automatic operation, the of automatic operation, the HPCIS reactor may remain in ooera- shall be demonstrated to be operable tion for a period not to irlmediately and daily thereafter as exceed 7 days, provided the long as Specification 3.5.6,2 HPCI system is operable. applies.

(Note that the pressure relief function of these valves is assured by section 3,6.D of these specifications and that this specification only applies to the ADS function.)

157 Amendments Nos. 28 8 25

LIHITINC CnNIIITTONS FOR OPERATION SURYA I LLANCF. RK IRiWFNTS

'Q.S.G hut nmnt ic Ocnressurization 4.5.G Automntic Dc ressurixation

~Sstr.fff (hl)S) 3 If specifications 3.5.G.l and 3.5.G. 2 cannot be met, an orderly shutdoMn vill be initiated nnd thc reactor vessel prcssure shall bc reduced to lO5 psig or less Mithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ll. Ha Inc.nacre of Ff lie ~aQtachar e Ha Heintenancr, of Filled Dischar c

~Pl c ~pi e Mhcncvcr thc core spray systems, The follouing surveillance rcquireen LPCI, IIPCI, or RGB.are required ments shall bc adhered to to assure to bc operable, thc discharge that the discharge piping of the piping from the pump discharge core spray systemsF LPCIF HPCI, and of these eystcms to thc last RCIC arc filled:

block valve shell bc f illcd.

158

LIMITING CONDITIONS FOR OPFRATION S URVF ILU4VCF. RE Ij I RKMENTS

.H Maintenance of Filled Dischar e Pine 4.5.H Maintenance of F'1'ed Dischar e Pine

~e suction of the RCIC and. HPCI pumps

l. Every month pzior to the tasting 0/aa11 be a1igned to the conde..sate of the RHRS (LPCI and Containment storage tank, and the pressure suppres- Spray) and coze spray systens, the sion chambe head tank shall normally discharge piping of these systems be aligned, to serve the discharg piping shall be vented from the high point of'he RHR and. CS pumps. The condensate'ead and water flow determined.

tan'c may be used to serve the RHR and CS discharge piping if the PSC head 2. Following any period where the LPCI tank is unavailable. The pressure or core spray systems have not been indicators on the discharge of the HHR required to be operable, the dis-and CS pumps shall indicate not less charge piping of the inoperabla sys-than 1isted belo~. tem shall be vented from the high P1-75-20 48 psig point prior to the return of the Pl-75-4S 48 psig system to service.

P1-74-51 48 psig Pl-74-65 48 ps' 3. Whenever the HPCI or 'RCIC system is lined up to take suction from the Avera e P1anaz Linear Heat Generation condensate storage tank, the dis-Rate charge piping of the HPCI and RCIC During steady state power operat'ion, the shall be vented from the high point Maximum Average Planar Heat Generation of the system and water flow observed Rate (MAPLHGR) for each type of fuel as on a monthly basis.

a function of average planar exposure shall not exceed the limiting value 4. When th RHRS and the CSS are re-shown in Figures 3.5.1.A and 3.5.1.B. quized to be operable, the px'essux'e Tf at any time during operation it is indicators which monitor the dis-lWermined by normal surveillance that charge lines shall be monitored the limiting value for APLHGR is being daily and the pressure recorded .

exceeded, action shall be initiated with-in 15 minutes to restore operation to within the prescribed limits. If the APLHGR is not returned to within the prescribed limits within two (2) hours, the reactox shall be brought to the Cold Shutdown condition within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. X. Maximum Average Planar Linear Heat Genera-Suzveillance and corresponding action tion Rate (~iVZLHGR) shall continue until reactor operation The LHGR for each type of f el as a func-is within the prescribed limits. ~i tion of average planar exposur shall be J'. Linear Heat Generation Rate (LHGR) determined daily during reactoz operation at > 25X rated thermal power.

During steady state power operation, the linear heat generation rate (LHGR) of J. Linear Heat Genezation Rate (LHGR) any rod in any fuel assembly at any axial location shall not exceed the The LHGR as a function of core height shal:

maximum allowable LHGR as calculated by the following equation: be checked daily during reactor operation at

> 25Z rated thermal power.

159

T.Il".ITIbG CONDITIONS FOP. OP@.RAT ON SURVF.ILLANCE RF. UlkF2P.NTS LHGR max

< LHGR d

(1 5P/P) max (L/LT)]

LHGR d

Design LHGR ~ 18e5 kW/ft.

(h P/P) max Maximum power spiking penalty

~ 0.026 LT ~ Total core length 12 '. feet L Axial position .above bottom of core If at any time during operation it is deter-mined by normal surveillance that the limiting value for LHGR is being exceeded, action shall be initiated within 15 minutes to restore operation to within the prescribed limits.

If the LHGR is not returned to within the prescribed limits within two (2) hours, the reactor shall be brought to the Cold Shutdown condition within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Surveillance and corresponding action shall continue until reactor operation is within the prescribed limits.

K. Minimum Critical Power Ratio (MCPR) Minimum Critical Powc- Ratio During steady state power operation, MCPR (HCPR) shall be > 1.25. at r'ated power and flow.

For core flows other than rated the MCPR shall MCPR shall be determined daily be ) 1.25 times K where K is as shown in during reactor power operation at Figure 3.5.2. If at any the during operation > 257 rated thermal power and fol-it is determined by normal surveillance that lowing nny change in powe- level or the limiting value for MCPR is being exceeded, distribution that would cause opera-action shall be initiated within 15 minutes to tion with a limiting control rod restore operation to within the prescribed pattern as described in the bases fc limits. If the steady state MCPR is not Specification 3.3.

returned to within the prescribed limits withi two (2) hours, the reactor shall be brought to the Cold Shutdown condition within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, Surveillance and corresponding action shall tontinue until reactor operation is within the prescribed limits.

L. ~Re ortin ~Re nireeenee If any of the limiting values identlf icd in Specifications 3.5.I, J, or K are exceeded and the specified remedial action is taken, the event shall be logged and reported in a 30-day written report.

160

Should one RIIR pump (containmcnt coolfnp, ~;,ode) been+: fnnpe rnble, a corn-pIcm<<nt of thrcc full capacity contafnmcnt heat removal cyst<<mn is still available. Any two of the remaining pumps/hcnt exchanger combinations iauld provide morc than adequate containment cooling for any abnormal or post accident situation. Because of thc availability of equipmcnt in access of normal redundancy requirements, which is demonstrated to be opcrablc immediately and with specified subsequent performance, a 30-day repair period is )ustified.

Should two RHR pumps (containmcnt cooling mode) become inoperable, a full heat removal system is still availablc. The remaining pump/heat exchanger combinations would provide adequate containment cooling for any abnormal post accident situation. Because of the availability of a full complement of heat removal equipmcnt, which is demonstrated to be operable immediately and with specified performance, a 7-day repair period is )ustified.

('bscrvation of thc stated requirements for the containment cooling mode assures that thc suppression pool and thc drywall vill be sufficiently cool<< d, following a loss-of-coolant accident, to prevent primary contain-ment ovcrpressuriration. Thc containmcnt cooling function of the RHRS is permitted only after thc core has rcfloodcd to thc two-thirds core height lcvcl. This prevents inadvertently diverting. water necdcd for core flooding to the less urgent task of containment cooling. The two-thirds core height level interlock may be manually bypassed by a keylock switch.

Since the RHRS is filled with low quality water during power operation, it is planned that the system be filled with demineralized (condensate) water before using the shutdown cooling function of the RHR system. Since it is desirable to have the RHRS in service if a "pipe-break" type of accident should occur, it is permitted to be out of operation for only a restricted amount of time and when the system pressure is low. At least one-half of the containment cooling function must remain operable during this time period. Requiring two operable CSS pumps during cooldown allows for flushing the RHRS even if the shutdown were caused by inabiliry to meet the CSS specifications (3.5.A) on a number of operable pumps, When the reactor vessel pressure is atmospheric, the limiting conditions for operation arc less restrictive. At atmospheric pressure, the minimum requirement is for onc supply of makeup water to thc core. Requiring two operablc RHR pumps and one CSS pump provides redundancy to ensure makeup

~ster availability.

Should one RHR pump or associated heat exchanger located on the. unit cross-connection in thc ad)accnt unit become inopcrablc, nn equal capability for long-term fluid makeup to the reactor and for cooling of thc containmcnt remains operablc. Because nf the availability of an <<qual m kcup and cool>ng capability, which is demonstrated to be operable immediately and with speci-fied subsequent surveillance, a 30&ay repair period is )ustified.

161

t

3. 5 IIASES 3.S.A Core S ra S stem CSS) end 3.5.1l Residual Heat Removal S stem RHRS)

Analyses presented in thc FSAR and analyses presented in conformance with IOCFR50 ~ appendix K demons treted tlat the cqwe spZay sos tern in cong unc tion with twc LPCZ pumps provides adequate cooling to the core to dissipate the energy asso-ciated with the loss-of-coolant accident and to limit fuel clad temperature to below 2,200'F which assures that core geometry remains intact and to limit the core average clad metal-water reaction to less than one percent. Core spray distribution has been shown in tests of systems similar to design to BOP to exceed the minimum requirements. In addition, cooling effectiveness has been demonstrated at less than. 4a3.f the rated flow in simulated fuel assemblies with heater rods to duplicate the decay heat characteristics of irradiated fuel.

The kHRS (LPCI mode) is designed to provide emergency cooling to the core by flooding in the event of e loss-of-coolant accident. This system is completely independent of the core spray system; however, it does function in combination with the core spray sys.em to prevent excessive fuel clad temperature. The LPCI mode of the RHRS and the core spray system provide adequate cooling for break areas of approximately 0.2'quare feet up to and includi.ng the double-ended recirculation line break without assistance from the high-prcssure emergency core cooling subs'ystems.

The intent of the CSS and R11RS specifications is to not allow startup from the cold condition without all associated equipment being operable. However, during operation, certain components may be out of service for the specified allowable repair times. The allowable repel.r times have been selected using engineering judgment based on experiences end supported by availability analysis. Assurance of the availability of the remaining systems is increased by demonstrating operability immediately and by requiring selected testing during the outage period.

Should one core spray loop become inoperable, the remaining core spray loop, the RHR system, and the diesel generators are demonstrated to be operable to ensure their availability should the need for core cooling arise. These provide extensive margin over the operable equipment needed for adequate core cooling. Mith due regard for this margin, the allowable repair time of 7 days was chosen.

Should one RHR pump (LPCI mode) become inoperable, on~ 3 RHR pumps (LPCI mode) and the core spray system are available. Since this leaves only one RHR pump (LPCI mode) in reserve, which along with the remaining 2 RHR pumps (LPCI mode) and core spray system is demonstrated to be operable immediately and daily thereafter, a 7 day repair period is justi.fied.

Should two RHR pumps (LPCI mode) become inoperable, there remains no reserve (redundant) capacity within the RHRS {LPCI mode). Therefore, the affected unit shall be placed in cold shut'down within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

• A detailed functional analysis is given in Section 6 of the BFNP FSAR.

162

Bases The suppression chamber can be drained when the reactor vessel pressure is atmospheric, irradiated fuel is in the reactor vessel, and work is not in progress which has the potential to drain the vessel. By requiring the fuel pool gate to be open with the vessel head removed, the combined

~ater inventory in the fuel pool, the reactor cavity, and the separator/

dryer pool, between the fuel pool low level alarm and the reactor vessel flange, is about 65,800 cubic feet (492,000 gallons). This will provide adequate low-pressure cooling in lieu of CSS and RHR (LPCI ana contain-ment cooling mode) as currently required in specifications 3.5.A.4 and 3.5.B.9. The additional requirements for providing standby coolant supply available will ensure a redundant supply of coolant supply.

Control rod drive'aintenance may continue during this period provided no more than one drive is removed, at a time unless blind flanges are installed during the period of time CRD's are not in place.

163

3. 5 BASES Should, the capability for providing flow through the cross-connect lines be lost, a ten day repair time is allowed before shutdown is required.

This repair time is justified based on the very small probability for ever needing RHR pumps and heat exchangers to supply an adjacent unit.

REFEREIlCES

1. Residual Heat, Removal Sy tern (BFIiP FSAR subsection 4.8)

2. Core St.~dl>y Cooling System".. (BFNP FSAR Section 6)

There are two EECW headers (north and south) with four automatic starting pumps on each header, All components requiring emergency cooling RHRSW water are fed from both headers thus assuring continuity of operation if either header is operable. Each header alone can handle the flows to all components. Two RHRSW pumps can supply the full flow requirements of all essential EECW loads for any abnormal or postaccident situation, There are four RHR heat exchanger headers (A, By Cy 6 D) with one RHR heat exchanger from each unit on each header. There are two RHRSW pumps on each header; one normally assigned to each header (A2, B2, C2, or 92) and one on alternate assignment (Al, Bl, Cl, or D1), One RHR heat exchanger header can adequately deliver the flow si pplied by both RHRSW pumps to any two of the three RHRSW heat exchangers on the header. One RHRSW pump can supply the full flow requirement of one RHR heat exchanger, Two RHR heat exchangers can more than adequately handle the cooling requirements of one unit in any abnormal or postaccident situation.

The RHR Service Water Systems was designed as a shared system for three units. The specification, as written, is conservative when consideration is given to particular pumps being out of service and to possible valving arrangements. Xf unusual operating conditions arise such that more pumps are out of service than allowed by this specification, a special case request may be made to the NRC to allow continued operation if the actual system cooling requirements can be assured.

Should one of the two RHRSW pumps normally or alternately assigned to the RHR heat exchanger header supplying the standby coolant supply connection become inoperable, an equal capability for long-term fluid makeup to the unit reactor and for cooling of the unit containment remains operable. Because of the availeb'lity of an equal makeup and cooling capability which is demonstrated to be operable immediately and with specified subsequent surveillance, a 30-day repair period is justified. Unit 2 may be supplied, standby coolant from either of four pumps--B1, B2, Dl, or D2.

164

t 3.5 BASES 3.5.D E ui ment Area Coolers There is an equipment area cooler for each RHR pump and an equipment area cooler for each set (two pumps, either thc A and C or B and D pumps) of core spray pumps. The equipment area coolers take suction near the cooling air discharge of the motor of the pump(s) served and discharge air near the cooling air suction of the motor of the pump(s) served. This ensures that cool air is supplied for cooling the pump motors.

Thc equipment area coolers also rcmove the pump, and equipment waste heat from the basement rooms housing the,engineered safeguard equipment. The various conditions under which the operation of the equipment air coolers is required have been identified by evaluating the normal and abnormal operating transients and accidents over the full range of planned operations.

The surveillance and testing of the equipment area coolers in each of their various modes is accomplished during the testing of the equipmcnt served by these coolers. This testing is adequate to assure the operability of the equipment area coolers.

REFERENCES

1. Residual Hect Removal System (BFNP FSAR paragraphs 4.8.9.1 and 4.8.9.2)

2. Core Standby Cooling System (BFNP FSAR subsection 6.7)

The HPCIS is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in thc event of a small break in the nuclear system and loss of coolant which does not result in rapid dcpressurisation of the reactor vessel. Thc HPCIS permits thc reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel is depressurized. The HPCIS continues to operate until reactor vessel pres-sure is below thc pressure at which LPCI operation or core spray system operation maintains core cooling.

The capacity of the system is selected to prov:;de this required core cooling.

The HPCI pump is designed to pump 5000 gpm at reactor pressures between 1120 and 150 psig. Two sources of water are available. Initially, water from the condensate storage tank is used instead of in)ecting water from the suppression pool into the reactor.

When the HPCI system begins operation, thc reactor deprcssurixcs morc rapidly then would occur if HPCI was not initiated due to the condensation of steam by the cold fluid pumped into the reactor vessel by the HPCI system, As the reactor vessel pressure continues to decrease, the HPCI flow momentarily reaches equilibrium with the flow through the break. Continued depressurization caused the break flow to decrease below the HPCI flow and the liquid inventory 165

tiASF S begins to risc. This type of response is typicaL of thc small breaks. The core never <<ncnvers and is contin<<a<<sly cooled throughout thc transient so that no core damage oE any kind accurs for breaks that lie within the capa-city range of thc HPCI.

The minimum zcquired NPSH far HPCI i:: 21 feet. There is adequate elevation head between the suppression pool and thc HPCI pump, such that the required NPSll is avai.lable uich a suppression pool cemperaturc up to 140'F with no containment back pressure.

S The HPCIS serves as a backup to the RCICS as a source of feedwaccr makeup during primary system isolation conditions. The ADS serves as a backup to the HPCIS Eor .reactor dcpressurization for postulated transients 'and acci-dent. Both these systems are checked for opez'ability m'ined to be inoperable.

if the HPCX is deter-Considering the redundant systems, an allowable repair time of 7 days uas selected.

The HPCI nnd RCIC as well as all other Core Standby Cooling Systems must be operablc when starting up from n Cold Candiiion. It is realized that the llPCI is not designed to operate at full capacity until reactor pressure exceeds 150 psig and the stcam supply to the liPCI turbine is autom cically isolated before thc rcactar prcssure decreases below 100 psig. It is the intent of this specification to assure that uhen thc zcactor is being started up from a Cold Condition, the HPCI is not known to be inoperable.

Thc various conditions under which thc RCICS plays an essential role in pro-viding makeup uatcr ta the reactor vcsscl have bccn identified by evaluating tbc various plant events over the full range of planned .operations..The speci-fications ensure that the function for which the RCICS uas designed will be available when needed. The minimum required NPSll for RCIC is 20 fcct. There is adequate elevation head between the suppressipn pool and the RCIC pump, such tllat the required NPSH is available with a suppression pool temperature,up to 140'F uith no containment back pressure.

Because the lou-prcssure cooling systems (I.PCI and core spray) are capable oE providing all the. cooling requ'ircd Eor any plant event when nuclear system pz'cssurc is belou 122 psig, the RCICS is not required belou this pressure.

Between 122 psig and 150 psig the RCICS need not provide its design Elaw, but reduced flow is required for certain events. RCICS design flow (600 Bpm) is suf ficicnt to mafntain uater level above the tap of the active fuel for a com-plece loss of fceduatcr flow at design power (105 percent of rated).

Cansideration of the availabilicy of che RCICS reveals chat the average risk associated with failure of the RCICS to cool thc core when required is not increased if chc RCICS is inoperable for no longer than 7 days, provided chat the llPCIS is operable during this period.

RFFERFNCE

1. Reactor Care Isolation Cooling System (BFhP FSAR subsection 4.7) 166

3. 5 nASKS 3.5.C Automatic Oe ressuritation S stem (ADS)

This specification ensures the operability of the ADS under all condi-tions for vhich the depressuritation of the nuclear system is an essen-tial response to station abnormalities.

The nuclear system pressure relief system provides automatic nuclear system depressuriration for small breaks in the nuclear system eo that the loM-pressure coolant in)ection (I.PCI) and the coro spray subsystems can operate to protect the fuel barrier. Note that this specification appliea only to the automatic foature of the pressure relief system.

Specification 3.6.n specifies the requirements for the pressure relief function of the valves. It is possible for any numbor of the valves assincd to the AOS to be incapable of performing their ADS functions because of instrumentation failures yet be fully capable of performing their prcssure relief function.

Because the autorantic dcpressurixation system does not provide makeup to the reactor primary vessel, no credit ie taken for the steam cooling of the core caused by the system actuation to provide further conservatism eo the C"CGA Mith one ADS valve known to be incapable of automatic operation, five valves remain operable to perform their ADS function, The ECCS loss-of-coolant accident analyses for small line breaks assumed that five of the six ADS valves were operable. Reactor operation with two ADS valves inoperable is only allowed to continue for seven days provided that the HPCI system is demonstrated to be operable.

167

3. 5 IIASI,"S If thc dfscharge piping of the core spray, LPCI, HPCIS, and RCICS arc not filled, a water hammer can develop in this piping when the pump and/or pumps are started. To mi.nimizc damage to the discharge piping and to ensure added margin in the operation of these systems, this Technical Specification requires the discharge, lines to bc filled whenever the system'is in an operable condition. If a discharge pipe is not filled, the pumps that supply that line must be assumed to be inoperable for Technical Specification pur-poses.

The core spray and RIIR system discharge piping high point vent is visually checked for water flow once a month prior to testing to ensure that the lines are filled. Thc visual checking will avoid starting the core spray or RIIR system with a discharge linc not filled. In addition to the visual observation and to ensure a filled discharge line oCher than prio to testing, a pressure suppression chamber head. tank is located approximately 20 feet above the discharge line highpoint to supp"y makeup water for these systems. The condensate hend tank located approximately 100 feet above the discharge high point serves as a backup charging system when the pressure suppression chamber head tank is not in service. System discharge pxessuxe indicators are used to determine the ~ater level above the discharge line high point. The indicators willreflect approximately 30 psig for a water level at the high point snd 45 psig for a water level in the pressuresuppression chamber head tank and are mon-itored daily to ensure that the discharge lines are filled.

When in their normal standby condition, the suction for the IIPCI and RCIC pumps are aligned tn thc coahcnsatc storige tank, which is physically .it a higher elevation rlran the IIPCIS and RCICS piping. This assures that the. IIPCI and RCIC discharge pipin~, remains filled. Further assurance is provided by observing watrz flow from these systems high points monthly.

3.5,X. ?Iiximum /verage Planar Linear Heat Generation Rata'MAPLHGR)

This specification assures that the peak cladding temperature following tho postulated design basis loss-of-coolant accident will not exceed the limit specified in thc lOCPR50, hppcndix K.

The peak cladding temperature following a postulated loss-of-coolant acci.-

dent is primarily a function of the average heat generation rate of all the rods of a foci assembly at any axial location and 4s only dependent'econd-arily on thc rod to rod power di tribution within an assembly. Since ex-pected local variations in power di"tribution within a fuel assembly affect the calculated peak clad temperature by less than a-?0 F relative to the peak temperature for a typical fuel design, the limit on the average linear heat generation rate is sufficient to assure that calculated temperatures src within the 10CFR50 Appendix K limit. The limiting value for MAPLHGR is shown in Figures 3.5.I-A and 3.5.1-B.

168

3 ',J, L5nenr Hest Ccneration Rata LHCR This specification assures that the linear heat generation rate in any rod i's less than thc design linear hent generation if fuel pellet densification is postulated. The power spike.penalty specified is based an the anal-ysis presented in Secti.on 3.2.1 of Reference 1 as madified in References 2 and 3, and assumes a linenrly increasing var5otion in axial gaps be-tvecn core bottom and tap, and,assures with a 95% confidence, that no morc than one fuel rad cicccds the design linear hest gencrat5on rate duc to paver spiking. Thc LlICR as a function of core height shall be checl;ed daily dur-ing reactor operation at > 25% power to determine if fuel burnup, or con-trol rod movement has caused changes in power distribution. For LIIGR to be a limiting value below 25% rated thermal power, thc MTPF would have to be greater than 10 wh5.ch is precluded by a considerable marg5.n when employing an~crmissiblc control rod pat tern.

3.5.g,. Minimum Critical Pover Ratio MCPR At core thermal paver levels lees than or equal to 25%, the reactor will be operating at recirculation pump speed and the moderator void vill be very minimum small. For all designated control rod patterns which maycontent be em-ployed at this point, aperating plant experience and thermal hydraulic anal ysis indicated that the resulting MCPR value is in excess of requirements by a considerable margin, Pith this lov void content, any inadvertent core flov increase would only place operation in a more conservative mode rela-tive to MCPR. The daily requirement for calculating MCPR above 25% rated thermal power is sufficient since power distribution shifts are very slov when have not been significant paver or control rod changes. there The requirement for calculating MCPR when a limiting cantrol rad pattern is approached ensures that MCPR vill be known folloving a change in power or pover shape (regardless of magnitude) that could place operation at a thermal limit.

Re ortin Re uirements The LCO's associated with monitoring the fuel rod aperating conditions are required to be met at all times, i.e., there is no allowable time in which the plant can knowingly exceed the limiting values for MAPLHGR, LHGR, and MCPR. It is a requirement, as stated in Specifications 3.5.1,.J that if at any time during steady state power operation, it is determined that the limiting values for MAPLHGR, LHGR, or MCPR are exceeded action is then initiated to restore operation to within the prescribed limits. This action is initiated as soon as normal surveillance indicates that an operating'im-it has been reached. Fach event involving steady state operation beyond a limit shall be logged and reported quarterly. "It must be recognized that specified there is always en action vhich would return any of the parameters (MAPLHGR, LHGR, or MCPR) to within prescribed limits, namely power reduction. Under most circumstances, th5.s will nat be the only alternative.

M. References

1. "Puol Densification Fffects on General Electric Boiling Mater Reactor Puel," Supplements 6, 7, and 8, NEIN-10735, August 1973.

2. Supplement 1 to Technical Report on Densifications of General Electric Reactor Fuels, December 14, 1974 (USA Regulatory Staff).

3. Communication: V. A. Moore to I. S. Mitchell, "Modified GF. Model for Puel Densification," Docket 50-321, March 27, 1974.

169

The testing interval for the core and containment a~ling systems is based on industry practica, quantitative reliability analysis, Judgement and practicality. The core cooling systems have not been designed to be fully teotablc during operation. For example, in the case of the HPCI, automatic initiation during power operation ~ould result in pumping c'old ~ater into the reactor vessel which is not desirable.'omplete ADS testing during power operation causes an undesirable loss-of-coolant inventory. To increase tnc availability of the core and containment cooling system, the components which make up the system; i.e., instrumentation, pumps, valves, etc., are tested frequently. The pumps and motor operated in)ection valves are also tested each month to assure their operability. A simulated automatic actua-tion test once each cycle combined with monthly tests of the pumps and in)ec-tion valves is deemed to be adequate testing of these system's.

N>en components and subsystems are out-of-service, overall core and contain-ment cooling reliability is maintained by demonstrating the operability of the remaining equipment. Thc degree of operability to be demonstrated depends on the nature of the reason for the out-of-service equipment. For routine out~f-service periods caused by preventative maintenance, etc., the pump and valve operability checks will be performed to demonstrate operability of the remaining components. Howcvcr, if a failure, design deficiency, cause the outage, then the demonstration of operability should be thorough enough to assure that a generic problem does not exist. For example, if an out-of-service period was caused by failure of a pump to deliver rated capacity due Co a design deficiency, the other pumps of this type might be sub)ected to a flow rate test in addition to the operability checks.

Whenever a CSCS system or loop is made inoperable because of a required test or calibration, the other'SCS systems or loops that are required to be

'operable shall be considered operable if they are within the required surveil-lance testing frequency and there is no reason to suspect they are inoperablc.

If the function, system, or loop under test or calibration is found inoperable or exceeds the trip level setting, the LCO and the required surveillance testing for the system or loop shall apply.

Redundant operable components are sub)ected to increa ed testing during equip-ment outmf-service times. This adds further conservatism and increases assurance that adequate cooling is available should the need arise.

Maximum Ayers e Planar LHGR LHGR and NCPR The MAPLHGR, LHGR, and MCPR shall be checked daily to determine if fuel burnup, or control rod movement has caused changes in power distribution. Since changes due to burnup are slow, and only a few control rods are moved daily, a daily check of power distribution is adequate.

170

tMXI!lr!AVEP'GE PLA':AR L-NEAP. '.RAT GENEPXTION 1U.TE (~M'L'iIGP.)

VKPSVS PLA:lAR cD-~AGE E~POSUB.

16.2 I

1 10,000 5000 15.9 15,000 15:

1000 15.5 15.2 20,000 12.9 30,000 "0 5, 000 10, 000 l5, 000 ":.0, 000 30,000 PI.A!:P2 AVE~.~GE EM~OSt~:-

('",:2/-'5,000 DROWNS r "RRY iNUCLLAR PLAiNT Fli lAL 5At' TY nf'lA LYSIS R c, C RT

'Pi!!GL'S. E r'OSU"..?

J

)i'flp j gg (\ q qg g f [ tt P

~ ~

7 171

H UvIafR[ AVERAGE P~IAR LIai~EAR H AT GE;IEPmaTIOil RATE (~Q LHCR)

VERSUS PLA'iAR AY~RACE EZL'OSURE

,6.3 10,50 16 15.8 5170 15.5 15,870

15. 15.0 15 2000 21,140

14. 6 14 .

40 13 ~ 7

~g 13 2.

31,560 I I I I I 12 0 5,000 10,000 15,000 20,000 25,000, 30,000 PLANAR AV RAGE E': OSURE (.'D/")

BROVINS F:-P.RY iVUCLEAFI PLANT FINAL SAF" TY ANALYSlS REPORT PIGI.:.E 3.5.1-9 IBPLHCR VS. E::POSURE I:lITIAL CORE H;EL TYPES 1 ~ 3 172

BRONNS FERRY NUCI.EAR PLANT FIGURE 3.5.2 K) FACTOR AUTOMATIC FLOW CONTROL MANUAL FLOW CONTROL Scoop-Tube Set-Point Calibration partition such that Flowmax = 102;5 Vo 107.0 'I 112.0 %

>>r.o'I.

30 60 70 CORE FLOW,5s

LIHITXNG CONDITIONS FOR OPEPATXON SURYA LLANCE RE UIREMENT 3.6 PRIMARY S>YSTFM BONG)ARY 4.6 PRXt 1ARY SYSTP4 BOUNDARY Applies to the operating status Applies to the periodic examination of the reactor coolant; system. and testing requirements for the reactor coolant system.

~Ob 'ctive Ob ective To assure the integrity and safe To determine the condition of the operation of the reactor coolant reactor coolant system and t;he system. operation of the safety devices re1ated to it, S ecification S ecification A. Thermal and Pressurization A. Thermal and Pressurizat'on Limitations Limitations

1. Thc average rate of reactor 1. During heatups and cooldowns, coolant tc>>>t)crrrt>n>'c ch:ultrc the followin~ parimctcrs shall during nota>>al )rcu,t.up c>k bc r(!cr>r(tcd olid r.">ac ter>r'ool-cooldown shall not exceed ant';cmpcrat;urc det,ermi.nest at 100 F/hr when averaged over 15-minute intervals until 3 a one-hour period. successive readings at eacn given location are wi hin 5 F.

a. Steam Dome Pressure (Convert to upper vessel region temperature)

b. Reactor bottom drain temperature

c. Recirculat'n loops A and B

d. Reactor vessel bottom head temperature

e. Reactor vessel shell adjacr rt'o shell flange

2. During a11,operations with a 2. Reactor vessel metal temperature critical core, other than at the outside surface of the for low level physics tests, bottom nead in the vicinity of %bc.

except when the vessel is control rod drive nousin> and vented, the reactor vessel reactor vessel shell adjacent shell and fluid temperatures to shell flange shall, be recorded .

shall bc at or above the at least every 15 minute" du"in8 temperature of curve /]3 of inservice hydrost;atic or leak testing the vessel prcssure figure 3.6-1.

is ) 312 when psig.

174

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.6.A Thermal and Pressurization 4.6.A Thermal and Pressurization Limitations Limitations

3. During heatup by non-nuclear 30 Test specimens representing the means, except when the vessel reactor vessel, base weld, and weld is vented, cooldown fo11owing heat affected zone metal shall be nuclear shutdown on low-level installed in the reactor vessel physics tests, the reactor adjacent to the vessel wall at vessel temperatures shall be Che core midplane level. The at or above the temperatures number and type of specimens of curve gz of figure 3.6-1. will be in accordance with GE report NEDO-10115. The specimens shall meet the intent of ASTM E 185-70. Samples shall be with-drawn at one-fourth and three-fourths service life.

4. The reactor vessel shell 4. Neutron flux wires shall be in-temperatures during inservice stalled. in the reactor vessel hydrostatic or leak testing adjacent to the reactor vessel shall be at or above the wa11 at the core midplane level.

temperatures shown on curve 'The wires shall be ren:oved and gl of figure 3.6-1. tested, during the first refueling outage to experimentally verify the calculated values of neutron fluence at one-fourth of the beltline shell thickness that are used to determine the NDTT shift from Figure 3.6-2 .

5. The reactor vessel head, bolt- 5~ When the reactor vessel head.

ing studs shall not be under bolting studs are tensioned and tension unless the temperature the reactor is in a cold condi-of the vessel head flange and, tion, the reactor vessel "hell the head is greater than 100 F. temperature immediate'ly below the head flange shaU bc per-manently recorded.

6. The pump in an idle recircula- 6. Prior to and during startup of tion loop shall noC be started an idle recirculation loop, Che unless the temperatures of the temperature of the reactor cool.-

coolant within the idle and ant in Che operating and idle operating recirculation loops loops shall be per..wnently are within 50 F of each other. logged.

7. The reactor recirculation pumos 70 Prior to starting a recircula-shall not be started unless the tion pump, the reactor coolant coolant temperatures between temperatures in the dome and in the dome and the bottom head. the bottom head dr.ain "hall be drain are within 145 F. compared and pew.anently logged.

175

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS

3. 6 PRIMARY SYSTEM BOUNDARY , 4. 6 PRIMARY SYSTEM BOUNDARY 0

B. Cool an t Chem istr Coolant Chemistr Prior to startup and 1. Reactor coolant shall be at steaming rates continuously monitored for less than 100,000 conductivity.

lb/hr, the following limits shall apply. a.. Whenever the continuous

a. Conductivity, conductivity monitor is umho/cm@25oC 2.0 inoperable and the condensate demineralizers

b. Chloride, ppm 0. 1 are bypassed, a sample of reactor coolant shall by analyzed for conductivity every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. If the condensate demineralizers are a sample of in'ervice, reactor coolant shall be analyzed for conductivity every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

b. Once a week the continuous monitor shall be checked with an in-line flow cell.

This in-line conductivity calibration shall be per-formed every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> whenever the reactor coolant conductivity is

>1.0 umho/cm at 25'C.

2.. greater At steaming rates than 100,000 2.

During startup prior to pressurizing the reactor above lb/hr, the following atmospheric pressure, measu. e-limits shall apply. ments of reactor water quality shall be performed to show

a. Conductivity, conformance with 5.6.B.1. of umho/cm925oC 1.0 limiting conditions.

b. Chloride, ppm 0. 2 176

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS

3. 6 PRIMARY SYSTEM BOUNDARY 4. 6 PRIMARY SYSTEM BOUNDARY 3 ~ At steaming rates 3. Whenever the reactor is operatin; greater than 100,000 (including hot standby condition.

lb/hr, the reactor measurements of reactor water water quality may quality shall be performed exceed specification according to the following 3.6.B.2 only for the schedule:

time limits specified below. Exceeding a. Chloride ion content shall be these time limits of measured at least once every the following maximum 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />.

quality limits shall be ca'use for placing b. Chloride ion content shall the reactor in the measured at least every be cold shutdown hours whenever reactor 8

condition.

conductivity is >1.0 pmho/cm

a. Conductivity at 25 C.

time above 1 umho/cm925oC c. A sample of primary coolant 2 weeks/year. shall be measured for pH at Maximum Limit least once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 10 umho/cm8254C whenever the reactor coolant conductivity is >1.0 umho/cm

b. Chloride at 25'C.

concentration time above 0.2 ppm -'-

2 weeks/year.

Maximum Limit 0.5 ppm.

c. The reactor shall be shutdown if pH <5.6 or

>8.6 for a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period.

177

LIMITING CONDITIONS POR OPERATION SURVEILLANCE REQUI REMENTS

3. 6 PRIMARY SYSTEM BOUNDARY 4. 6 PRIMARY SYSTEM BOUNDARY When the r actor is 4. Whenever the reactor is not not pressurized, pressurized, a sample of the reactor except during coolant shall be analyzed at least startup, the reactor every 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> for chloride ion water shall be content and pH.

maintained within the fol lowing limits.

a. Conductivi ty 10 umhoicm825<C

b. Chloride - 0.5 ppm

c. pH shall be between 5.3 and 8.6.

S. When the time limits or S. During equilibrium power maximum conductivity or operation an isotopic chloride concentration analys1s, 1nclud~ng limits are exceeded, an quantitative measure-orderly shutdown shall be ments for at least initiated immediately. The I-131, I-132, I-133, and reactor shall be brought to I-134 shall be performed the cold shutdown condition monthly on a coolant as rapidly qs cooldown rate liquid sample.

permits.

178

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RFQUIREMENTS 3 ' PRIMARY SYSTEM BOUNDARY 4 6 PRIMARY SYSTEM BOUNDARY

6. Whenever the reactor is critical, 6. Additional coolant the limits on activity concentra- samples shall be taken tions in the reactor coolant shall whenever the reactor not exceed the equilibrium value activity exceeds one of 3.2 pc/gm of dose equivalent* percent of the equili-I-131. brium concentration specified in 3.6.8.6 This limit may be exceeded and one of the following following power transients for conditions are met:

a maximum of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. During this activity transient the a. During startup i odine concentra ti ons sha 1 1 not b. Following a significant exceed 26 uCi/gm whenever the power change**

reactor is critical. The c. Following an increase reactor shall not be operated in the equilibrium more than 5 percent of its yearly off-gas level exceeding power operation under this 10,000 pgi/sec (at the exception for the equilibrium steam jet air ejector) activity limits. If the iodine within a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period.

concentration in the coolant d. Whenever the equilibrium exceeds 26 >Ci/gm, the reactor iodine limit specified shall be shut down, and the in 3.6.8.4 is exceeded.

s team 1 ime i sol a ti on va ves 1

shall be closed immediately. The additional coolant liquid samples shall be taken at 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> intervals for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, qr unti 1 a stable iodine concentration below the limiting value (3.2 ~pi/

gm) is established. However, at least 3 consecutive samples ahall be taken in all cases. An isotopic analysis shall be perfomed for each sample, and quantitative measurements made to determine the dose equivalent.

I-131 concentration. If the total iodine activity of the sample is below 0.32 uci/gm, an isotopic analysis to determine

• That concentration of I-131 equivalent j-131 is not required.

which alone would produce the same thyroid dose as the quantity **For the purpose of this section of total iodines actually present, on sampling frequency, a significant power exchange is defined as a change exceeding 15'A of rated power in less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, 4 179

LIMITING CONDITIONS FOR OPEPATION SURVEILLANCE REQUIREMENTS

3. 6 PRIMARY SYSTEM BOUNDARY 4-6 PRIMARY SYSTEM BOUNDARY C. Coolant Leaka e C Coolant Leaka e Any time irradiated Reactor coolant fuel is in the system leakage shall reactor v ssel and be checked by the reactor coolant sump and axr sampling temperature is above system and recorded 212~F, reactor at least once per coolant leakage into day.

the primary containment from 2 ~ With the air sampling unidentified sources system inoperable, shall not exceed 5 grab samples shall be gpm. In addition, obtained and analyzed the total reactor at least once every coolant system 24 hours.

leakage into the primary containment shall not exceed 25 gpmo

2. Both the sump and air sampling systems shall be operable during reactor power operation. From and after the date that one of these systems is made or found to be inoperable for any reason, reactor power operation is permissible only during the succeeding seven days.

180

I.I~I r INC CONI>ITION.; NOR O"I,"RATlnII SVRVFII.LAN(:I'. RI:.~VIR1>L'NT

3. 6. C Coolant I.cake ye 4.6.C Coolant I.caka c

3. If the condition in 1 or 2 above cannot be met, an orderly shutdown shall be initiated and thc reactor shall be shut-down in thc Cold Condition within 24 hours. 1. At least one s"fcty valve and approximately one-half of all D. Sa f ct and Relic f Valves relief valves shall bc bench-checked or replaced with a

1. When morc than one valve, bench-checked valve each opera-safety or relief, is known to ting cycle. All 13 valves (2 be failed, an ordery shut- safety and 11 relief) will have down shall be initiated and been checked or replaced upon the reactor depressurizcd to the comolction of every second less thane 105 psig within 24 cycle.

hours.

2. Once during each operating cycle, each relief valve sha'1 be manually opened until thcrmo-couples downstream of the valve indicate steam is flowing from the valve.

3. The integrity of the relief!

safety valve bellows shall be continuously monitored.

4. At least one relief valve shall be disas cmblcd and inspected each operating cycle.

~Jet Pum e E. ~Jet Pue e

1. Whenever the 'reactor ie in the 1. Whenever there is recirculation startup or run modes, all get flow with the reactor in the pumps shell be operable. If startup or run modes with both it is determined that a jet recirculation pumps running, pump is inoperable, or if two )et pump operability shall be or more ]et pump flow instru- checked'aily by verifying that ment failures occur and can- the following conditions do not not be corrected within 12 occur simultaneously:

hours, an orderly shutdown shall bc initiated and the a. The two recirculation loops reactor shall be shutdown in have a flow imbalance of thc Cold Condition within 24 157. or more when the pumps hours e are operated at the same speed.

181

L1MlTINC (ÃN01 f'10'IS FOR OPERAT10!I SURVEILLANCE RV< UlREME1!T

).f>. E .let Pu.~~~ 4.6.E ~Jet Pun a 3.6.F Jet F" ow 14ismatch

b. The indicated value of core

l. When both recirculat'on pumps floM rate varies from the are in steady state operation, value derived from loop the speed of the faster pump flov measurements by more shall be maintained within than 10Z.

12@ the speed o the slower pump when core power i" 80>~~ or c. The diffuser to lmrer plenum more of rated powe. or 135)~ the differential pressure read-speed. of the slower pump when ing on an individual get core power 's below 80)~ of pump varies from the mean rated pover. of all >et pump differen-

2. If specification 3.6.F.l tial pressures by more than 10X.

cannot be met, one recirculation pump sh ~ be tripped.

2. Whenever there is recirculation flow with the reactor in the

3. The reactor sha11 not be Startup or Run Mode and one re-operated. with one recirculation circulation pump is operating loop out of service for more Mith the equalizer valve closed>

than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. With the reactor the dif fuser to lcnrer plenum operating, if one recirculation loop i" out of service, the differential pressure shall b checked daf,ly and the differen-plant shall be placed. in a hot tial pressure of an individual snutdown condition within jet pump in a loop shall not 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> un1ess tne loop is vary from the mean of all )et sooner return d to service. pump differential pressures in that loop by more than 10X.

4. Folio~>ing one pump operation, P. Jet Pum Flow Mismatch the discharge valve of the low speed pump may not 'oe opened. l. Recirculation pump speeds shall urrless the speed. of the faster be checked and logged at least pump is less than 5Py of its once per day.

rated speed.

G. Structural lnte ritv G. Structural Interrit

l. The etructural integrity of l. Table 4.6.A together arith sup-the primary system shall be plementary notes, specifies the 182

t 3 I.J."'V.'EKG CO 6,G ' 1 uet ore 1 tote~ri~t maintained at the level re-quired by thc original accep-tance standards throughout the life of the plant. The reactor shell bc maintained StlRVEJLLANCE RE JlREMENTS 4.6.G Structural Inte rit inservicc inspection surveil-lance requirements of the reec-tor coolant system es follows:

a. areas to bc inspected in a cold shutdown condition until each indication 'of' b, percent of areas to be defect has been investigated inspected during the and evaluated. inspection interval

c. inspection frequency

d. methods used for inspection

2. Evaluation of inscrvicc inepac-tions vill be made to the accep-tance standards specified for the original equipment.

3. The inspection interval shall be 10 years.

4. Additional inspections shell be performed on certain circumferen-tial pipe voids as listed to pro-vide additional protection

<<gaknet pipe vhip, which could damage auxiliary and control sys-tems.

Pcedvater CFW-9, KPM-13 GFM-12, GPM-26, KPW-31 GPM-29, KPM-39 ~CPM-15, K1%-38, 'end GFM-32 Main steam - GMS-6, KMS-24, GKS<<32, KNS-104 GMS-X5, end GMS-24 RHR DSRHR-4, DSRHR-7, DSRHR-BA Core Spray DSCS-12, DSCS-ll, DSCS-5, end DSCS-4 18

LIMITING CONDITIONS FOR OPERATION SURVHILIANCH RHQHIRHMHNTS 3.6.G Structural Inte rit 4.6.G Structural Inte rit Reactor Cleanup DSRMC-4, DSRNC-3 DSRWC-67 DSRVC-5 HPCI THPCI-152 THPCI-153B THPCI 153 THPCI-154

5. System pressure tests in accordance with article IS-500 of section XI of the ASME code including winter 1972 Addenda. The pressure-temperature limits for these tests wi11 be in accordance with specification 3.6.A.3.

6. For Unit 1 an augmented inservice surveillance program shall be performed to monitor potential corrosive effects of chloride residue released during the March 22, 1975 fire.

The augmented inservice surveillance program is specified as follows:

a. Browns Ferry Mechanical Maintenance Instruction 53, dated September 22, 1975, paragraph 4, defines the liquid penetrant examinations required during the first, second, third and fourth refueling outages following the fire restoration.

b. Browns Ferry Mechanical Maintenance Instruction 46, dated July 18, 1975, Appendix B, defines the liquid penetrant examinations required during the sixth refueling outage following the fire restoration.

184

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS

3. 6 PRIMARY SYSTE'4l BOUNDARY 6 P RI i4fARY S YST ~~ EOUN DARY Shock Su ressors Snubbers H Shock Su res sors (Snub6ers J During a 1 1 mod es of The following surveillance operation except Cold requirements apply to all Shutdown and Refuel, hydraulic snubbers listed all safety-related in 3. 6. H. 2.

snubbers shall be operable except as A3.1 byd ra ulic noted in 3. 6. H. 2 snubbers whose seal through 3. 6. H. 5 material has been below. demonstrated by operating experience, lab testing or analysis to be compa tible witn the opera ting envi ronment shall be visually inspected. This inspection shall include, but not necessarily be limited to, inspection of the hydraulic fluid reservoir, fluid connections, and linkage connections to the pipina and anchor to ver'fy tneir operability in accordance wi-h the following schedule:

Number of Next Requi r ed Snubbers Inspection Found Inoper- Interval able During Inspection or Durinc Inspec-tion Interval Operating +23. ~

Cycle 1 12 months + ic,c 2 6 months +25 i 3,4 124 days +25'25<

5,6,7 62 "ays 18

>e 31 days + 25%

The required inspection interval shall not be lengthened more than one step at a time.

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3 6 PRIMARY SYSTEM BOUNDARY 4 6 PRI MARY SYSTEM BOUNDARY Snubbers may be categorized in two qroups, "accessible" or "inaccessible" based on their accessibility for inspection during reactor operation. These two groups may be inspected independently according to the above schedule.

2. The snubbers 2 ~ All hydraulic listed in snubbers whose seal Table 3. 6. H are materials are required to protect other than ethylene the primary coolant propylene or other system or other material that has safety related been demonstrated to systems or components be compatible with and are therefore the operating subject to these environment shall specifications. be .visually inspected for operability every

3. From and after the 31 days.

time that a snubber is determined to be inoperable, 3. The initial continued reactor inspection shall be operation is performed within 6 permissible only months from the date during the succeeding of issuance of these 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> unless the snubber is sooner specifications. For made operable or the purpose of replaced. entering the schedule in Specification

4. 6. H. 1, it Assumed that the shall be facility had been on a 6 month inspection interval.

186

L(HITIN<i CONDITIONS FOR OPEPATION GVRVEZLI.AN(:E Rl.gtl I REPENTS 3 6 PRIORY SYSTEM EOUNDARY PRIMARY SYSTE!0 BOUN DARv If the requirements of 3. 6. B. 1 and Once each refueling cycle, a representative sample

3. 6.H. 3 cannot be of 10 snubbers or met, an orderly approximately 10~ of shutdown shall be the snubbers, whichever initiated and the is less, shall be reactor shall be in a functionally tested for cold shutdown operability including condi tion w ithin 36 verification of proper hours. piston movement, lock up If a snu6ber $ s and bleed. For each unit determined to be in- and subsequent unit found operable while the inoperable, an additional reactor is in tfie 10 or ten snubbers shall sFiutdown or refuel be so tested until no mode, the snubber more failures are found shall be made or all units have been operable or replaced tested. Snubbers of prior to reactor rated capacity greater than 50,000 lb ne d not startup. be functionally tested.

Snubbers may be added to safety-.related systems without prior license amendment to Table 3.6.H provided that a revision to Table 3,6.H is included with a subsequent lic nse amendment request.

187

FIGURE 3.6-1 1600 CURVE gl--Minimum temperature for pressure tests 1400 such as required.

by section XI CURVE g2--Minimum temperature for mechanical heat up or cooldown 1200 following nuclear shutdown CURVE g3--Minimum temperature for core oeeration (criticality)

Includes additional 1600 margin req'd, by 10CFR$ 0 Appendix G 800 CL 0

I 400 200 0

100 200 300 400 500 600 MINIMUM TEMPERATURE F ABOVE CHANGE lN TRAÃSITj05 TEMPERATURE 188

ZOP 150 z0 100 50 0

101 S 1017 1018 1019 NEUTROlU FLuEPJCE ()1 McV) (Pt), net I. IGUR E 3.6-2 CHANGE IN CHARPY V TRANSITION TEMPERATURE VERSUS NEUTRON EXPOSURE 189

Gnubbcrs Snubbers in lligh inaccessible Snubbers Radiation Area During Snubber" ".specially During 1lormal Accessible Durir"-

Snubber Ifo. ~Sstem Elevntion Shutdovn ~ Difficult to Remove Operation Noeoel Ooention SSA1(Z) hhin Steom A 585 ssn2(x) Main Stcom A 585 SSBl(Z) ';lain Steam B 585 SSB2(X) hbin Steam B 585 ssB4(z) hbin Steam B 585 SSB5(Y) Main Steam B 585 sss6(v) lhin Steam B 585 SSCl(Z) Main Stcam C 585 SSC2(X) Main Steam C 585 ssc4(z) hhin Stcam C SSC5(Y) Main Stcam C ssc6(x) Vain Stcam C 585 SSDl(Z) Main Steam D 585 X SSD2(X) h'win Stcam D 585 SSAl(X) Feedvatcr A 6ol SSA2(Z) Fcedvatcr h 6'85 SSA3(Y) Fccdvatcr A ssA4(z) Fccdvatcr h 585

ThOUr 3 ~ 6.iI UIIXT 1 - page c SHOCK SUPPRESSORS (SNUBBERS)

Snubbers Snubbcrs in IIigh- Inaccessible Snubbcrs Radiation Area During Snubbers Especially During IIormal Accessible Durir.

Snub"cr IIo. Syszcm Elevation Shutdown

• Difficult to Remove Operation Iloreal Operatic:

sh5(x) Fecdwater A 601 ssh6(z) Feedwater A 601 sshT(z) Feedwater A 507 ssh8(x) Fccdwater A 587 ss:,::(z) Feedwater A 587 "sBl(x) Fecdwater 9 601 ssoz(z) Feedwater B 601 SSB3(Y) Fcedwater B 585 SGB4(Z) Fecdwater B 585 SSBS(X) Feedwater B 601 ssB6(z) Fcedwater 9 x SSBT(z) Fecdwater B 587 ssBG(x) Fcedwater B 587 SSBg(z) Fcedwatcr 9 587 x Pl << nor h RiIR 537 Rl - east RHR 537 540

TAOt.E, 3.6.u UNIT 1 - page 3 SHOCK SUPPRfSSORS SNUBBfRS Snubbcrs Snubbers in High Xnaccessible Snubbers Radiation Area During Snubbers Especially During llormal Accessible Du"it=

Snubber Ão. S~stem Elevation Shutdovn

• Difficult to Remove Operation ?lomal Operatic..

R3 531 R4 - east . BHR 536 B4 - vest 536 R6 - north RHR 540 R6 - east 540 B6 north BllR 537 R7 - ves 537 B8 - south 558 RG - vest 558 R9 - north BHR 577 R9 - south BHR 577 R10 550 R12 upper 550 B12 lover BHR 550 R13 571 R14 - east RlfR 571 R14 - ~est 571 15 598

Tnora 3.6.s VHIT 1 - yes 4 SHOCK SUPPRESSORS SNUBAERS Snubbcrs Snubber" in High Inaccessible Snubbcrs Radiation Area During Snubbers Especially During Normal Acces"ible DurJ.r~

Snubber lio. Elevation Shutdown

• Difficult to Remove Operation Normal Operaticn R16 upper RIIR 598 B16 lower 598 19 555 B20 upper 549 R21 - east RIIR 572 B21 - dies 572 B22 573 58O R25 RIIB 579 R26 575 R41 inside RIIB 555 R41 outside RHB 555 R29 MR head spray 636 R29 RIIB head spray 636 Bl Control rod drive Control rod drive

room ~6.g UNIT l - page 5 SHACK Sll P FOSSA SMH<n Q Snubber" Snubbcrs in 1ligh Inaccessible Snubbers Radiation Area During Snubbers Especially Du"ing Normal Acces=iblc Dur1r=

Snubber No. ~St C III Elevation Shutdown

• Dizficult to Remove Operation Nor .el Ov ~tfon Rl Core spray X Core spray 6o6 R6 <<north Core spray 544 R6 - south Sore spray 554 R8 Core spray X Core spray 6o9 R13 . north Core spray 544 R13 - south Core spray Rl9 Standby liquid 624 control R21 Standby liquid 624 control R3 - north IFCI 542 R3 - south HPCI 542 BG HPCI 563 HiCI 547 Rll IPCI 532

.R47 HPCI HEI 532

Tnnrr:. 6.H UNIT l - page 6 SHOCK SUPPRESSORS (SNUBBERS)

Snubbcrs Snubbcrs in High Inaccessible Snubbers Radiation Area During Snubbers Espccial3y During Normal Accessible During Snubber 1vo System Elevation Shutdown

• Difficult to Remove Operation No~el Ope ticn R90 HPCZ 540 R91 - north HPCI 538 B9l - south HPCX 538 B4 - north HCIC 520 R4 - south HCIC 520 B5 - east RCIC 538 R5 - .south HCIC 538 B(-c st RCIC 548 (upper)

Rj - '.iest HCIC 548 (laser)

P9 - north BCIC 564 H9 - south HCIC .X Bl upp r Condensatc S+ 548 (ring header)

B'os:er Condensate SOS 548 (ring header)

H2 - north Condensate S88 548 (ring header)

R2 - est Condcnsatc SES 548 (ring header)

IABLE 3.6.H UNIT 1 - page 7 Wn i P r nn SNII RFRS Snubbers Snubbers in High Inaccessible Snubbers Radiation Area During Snubbers Especially During Normal Accessible During Snubber No. ~Sstem Elevation Shutdown* Difficult to Remove 0 eration Normal 0 eration R3 - east Condensate SINS 548 (ring header)

R3 - west Condensate S&S 548 (Ring header)

R4 north Condensate S8S 548 X (ring header)

R4 - east Condensate S8S 548 (ring header)

R5 upper Condensate S8S 548 (ring header)

R5 lower Condensate SSS 548 (ring header)

SSZ-1 PSC (ring header) 525 SSX-2 PSC (ring header) 525 SSX-3 PSC (ring header) 525 SSZ-4 PSC (ring header) 525 SSZ-5 PSC (ring header) 525 SSX-6 PSC (ring header) 525 SSX-7 PSC (ring header) 525 SSZ-8 PSC (ring header) 525 SSX-3A PSC (ring header) 525

TABLE 3.6.H UNIT 1 page SHACK SUPPRESSORS SNUBBERS Snubbers Snubbers in High Inaccessible Snubbers Radiation Area During Snubbers Especially During Normal Accessible During Snubber No. ~Sstem FIevation Shutdown* Difficult to Remove 0 eration Normal 0 eration SS2-4A PSC (ring header) 525 SS2-SA PSC (ring header) 525 SSX-6A PSC (ring header) 525 SSX-7A PSC (ring header) 525 SSZ-BA PSC (ring header) 525 A2 upper Condensate bypass 557 line R2 lower Condensate bypass 557 line Rg Condensate bypass 557 line R13 - east Condensate bypass 557 line R13 - west Condensate bypass 557 line R42 EECM 605 SS1-A Recirculation 556 SS1-B Recirculation 556 SS2-A Recirculation 558 SS2-B Recirculation 558

SABLE 3.6.H UNIT 1 - page 9 SHOCK SUPPRESSORS (SNUBBERS)

Snubbers Snubbers in High Inaccessible Snubbers Radiation Area During Snubbers Especially During Normal Accessible During Snubber No. ~Se tern Elevation Shutdown* Difficult to Remove 0 eration Normal 0 eration SS3-A(295 ) Recirculation 564 SS3-A(335o) Recirculation -. 564 SS3-B(115 ) Recirculation 564 SS3-B(154 ) Recirculation 564 SS4-A Recirculation 570 SS4-B Recirculation 570 SS5-A(262o) Recirculation 581 SS5-B(325 ) Recirculation 581 SS5-B(35o) Recirculation 581 SS5-B(98 ) Recirculation 581 SS6-A Recirculation 568 SS6-B Recirculation 568 SS7 Recirculation 564 SSB Recirculation 564 "Modifications to this Table due to changes in high radiation areas should be submitted to the NRC as part of the next license amendment.

PAGES 19$ -208 DELETED Table 4.6.A REACTOR COOLANT SYSTEM'NSERVICE INSPECTION SCHEDULE AREAS OF INTEREST ACCESS Z INSP. IN INSP. INTERVAL ~PRE UENCY

h. Reactor Vessel

1. Longitudinal and Those veids above 10Z of accessible longitudinal Code (1) Volumetric circumferential sacrificial shield and velds outside core all in closure head 5Z of accessible c'ircumferential region and in ves- are accessible from sel head vessel o.d.

2. Vessel-to-flange Prom flange surface 100Z Code (2) Volumetric circumferential veld Head-to-flange Prom o.d. of head 100Z Code (2) Volumetric circumferential weld

3. Primary nozzle-to- hll nozzles 4 inches 100Z velds Code (2) vessel velds aad aad greater vill be nozzle-to-vessel in- accessible from vessel side radii o.d. Inside radii at the 6 aad 12 Code (2) Volumetric o'lock positions 3a. CRD housing>>to-stun During refueling from 100Z ht time of Visual tube and stub tube- CRD area for signs of system hydro-to-vessel velds and leakage stat incore penetration

4. Primary noxzles to hll nozxles 4 inches 100Z Code (2) Visual, surface safe-ead Dissimilar and larger vill be and volumetric Natal velds accessible

5. Closure studs and Studs ia place, nuts 100Z Code (2) Visual, surface nuts on removal and volumetric

T"ble 4.6.A REACTOR COOLAVI'YSTEH INSERVICE I'INSPECTION SCHEDULE (Continued)

AREAS OP INTEREST ACCESS INSP. IN INSP. INTERVAL ~FRE VENCY HETHOD

6. Closure washers, On removal 1002 Code (2) Visual Bushings In place, when studs When made accessible Visual are removed

7. Integrally ~elded Two sections 2 fee- One foot minimum length Code (2) Volumetric

= vessel supports long each, 18 apart, l80'part - two spots accessible in support skirt to vessel veld

8. Vessel cladding During refueling- 6 predefermined patches Code (2) Visual vessel i.d. (36 in. each)

9. Vessel internals Accessible areas Accessible areas Pirst refuel- Visual and integrally during normal re- ing and every welded internal fueling third refueling supports thereafter

10. Vessel flange- During refueling 100Z Code (2) Volumetric ligsments between threaded stud holes B. Pi in Pressure Bounds Vessel, pump, and Prom pipe o.d. 1001 Code (2) Visual and ourfac valve safe ends-to- and volumetric primary pipe dissimilar metal weldo and safe ends in branch piping zelda 4 inches and larger

Table 4.6.A REACTOR COOLP9 SYSTE.. INSERVICE INSPECTION SCHEDULE (Continued)

AREAS OF INTEREST ACCESS Z INSP. IN INSP. INTERVAL FRE UENCY METHOD

2. Circumferential and Removable insulation 25Z of circumferential velds Code (2) Visual and longitudinal pipe plus 1 foot of ad)acent volumetric velds 4 inches and longitudinal velds over Circumferential- Removable Insulation All those listed in Section Code (1) Visual and type velds 4.6.G.4 of Technical volume tric pipe vhip Specifications protection

3. Pressure-retaining 2 inches and larger 100Z Code (1) Visual and bolting volumetric Bolting under 2, 100Z Signs of inches on piping 4 leakage dur- Visual inches and over ing normal maintenance

4. Piping supports and hangers (a) Integrally Scaf folding as 100Z visual, Code (2) Visual and velded required 25Z Vol. (if suitable geometry) volumetric (b) Nonintegrally Scaffolding as 100Z Code (2) Visual welded supports required C. Pum Pressure Bounds

1. Pump casing Pump pressure boun- Prom pump i.d. only One pump with or vithout Code (1) Visual dary interior when maintenance welds if disassembled if disassembled requires removal of internals

Table 4.6.A REACTOR COOLANT SYSTiZ INSERV ICE INSPECTION SCiiZ)L'LE (Continued)

AREAS OF IVsf.";REST ~

~CRIES 2 INSP. IN INSP. INTERVAL ~PRE UE!ICY !KTHOD

2. Pressure-retaining 2 inches and larger lOOX Code (l) Visual and bolting volumetric Bolting under 2 1001 Signs of Visual inches leakage dur-ing normal aaintenance outage

3. Supports

a. Integrally Scaffolding as 251 Code (2) Visual and velded required volumetric

b. Nonintegrally Scaffolding as 1001 Code (2) Visual velded required

4. Nozxle-to-safe end Removeble insulation 100Z Code (2) Visual and dissimilar metal velds volumetric D. Valve Pressure Bounda

l. Valve body seam Pron valve o.d. 1001 Code (1) Visual and velds volumetric Valve pressure boun- Prom valve i.d. only One va1ve vith or vithout Code (1) Visual dary interior vhen maintenance requires removal of velds if disassembled if disassembled internals

2. Valve-to-safe end Removal insulation 100Z Code (2) Visual and dissimilar metal volumetric velds

Table 4.6.A REACTOR COOLA.'HT SYSTEM INSERVIC:.'NSPECTION SCNEDi.~E (Continued)

AREAS OF INTEREST ACCESS i INSP. IN INSP. INTERVAL ~FHE UE!ICY HETHDD

3. Pressure-retaining 2 inches and larger 100Z Code (1) Visual and bolting volumetric Bolting under 2 inches 100Z Signs of Visual leakage during nor-mal maintenance outage

4. Supports and hangers

a. Integrally Scaffolding as 25Z Vol. (if suitable geometry) Code (2) Visual and welded required 100Z visual volumetric

b. Nonintegrally Scaffolding as 100Z Code (2) Visual welded required

Table 4.6.A REACTOR COOLANT SYSTEM INSERVICE INSPECTION SCHi3ULE (Continued)

Inspection Frequency:

Code (1) Program such that all areas of interest vill be inspected during the inspection interval.

Code (2) Program such that at least 25X of the required examinations shall have been completed after one- hird of the inspection interval has expired (+1th credit for no more than 33-1/3X if additional examinations are completed) and at least 50X after tvo-thirds of the inspection interval has expired (vith credit for no more than 66-2/3X). The remainder shall be completed by the end of the inspection interval.

3.6 4.6 BASES 3.6.A/4.6.A Thermal and Pressurization Limitations The vessel has been analyzed for stresses caused. by ther M and. p essure transients. Heating and cooling tzansients throughout plant life at uniform rates of 100o F per hour were considered in tne temperatu"e range of 100 to 546 F and vere shown to be within he requirements for stress intensity and fatigue limits of Section III of the AStE Boiler and. Pressure Vesse3. Code (65 Edition inc3.uding Summer 3966 addenda).

Operating limits on the reactor vessel pressu e and temperature during normal heatup and cooldown, and, during inservic hydrostatic testir~, vere established using Appendix G of the Summer 1972 Addenda to Sect'on III of the AS."L Boiler and Pressure Vessel Code, 1973. Edition, as a guide. These operating lim's assure tha" a large postulated surzace flav, having a depth of one-quarter o the material thickness, can be safe1y accommodated in regions of the vessel shell remote from discontinuities. For the purpose of setting thes'e operating limits the reference temperature, .'Pi[tDT, of the vessel material way estimated from impact test data taken in accordance with require ents of the Code to r~hich this vessel was designed and. manufactured. (65 Edition to Su"ver 3.966 add"nd .)

The fracture toughness of al1 ferzitic steels gradua13y and uniformly decreases with exposure to fast neutrons aoove a threshold value, and, it is pr dent and, conservative to account for this in the operation oz the RW. Two types oz information are needed in this ana1ysis: 1) A relationsi ip between the change in fractu"e toughness of the RPV steel and. the neutron zluence (integrated. neutron flux), and 'o) a measure of the neutron fluence at the point of interest in the BW wa13..

A relationship between neutron fluence and change in Charpy V, 30-foot pound transition temperature has been develop d f'r SA~023/SA533 s ee3. Cased on at least 35 expe iment 1 oata points as shown n figure 3.6-2. In turn, th" s ch nge in tre..sit on temper tu"e can be related to a change in the temperature ordinate shown in figure G 2l3.0-1 in Appen~~ G of Section I>I of the Boiler Code.

The neutron fluence at any point in the pressu"e vest wall can be computed.

from core physics dam. The neutron fluence can also pe m asured experimental3y on the ID oz the vessel wall. At presen 'M d exper'mental measurements can be made only over time periods oz less th~ 5 years because of the limi-tations of the dosimete mate ials. Thi.s c". uses no problem because of the exact relationship between thez..M powe" oroduced and the number of neutrons prod' d from a given core geometry. A single experiment 'easu event in a time period of one year can be u"ed to predict the fluence for the 1'e oz the plant in terms of thermal power output if no great changes in core geometry are made.

215

3.6. A/I<.6.!

The :easel pressurization temperatures at any time period can be determined fro-. the the...!al power output, of the plant and its relation to the neutron fluencc anc fror. figure 3.6-2. For heatup or coo'down and core operation, see "u ves~",2 & l~'3 on figure 3.6-1. During the first fuel cycle, only calculated net ron fluence values can be used. At the first refueling, neutron dos'::.e er wire" which are installed adjacent to t)!e vesse1. wall can be removed to:e. ify the calculated neu ron flue!!ce. As r!ore experience is gained in cal-cula-.ing the f)uence the need to verify it exper'mentally will <)isappcar.

Beca. se of the many experime;ital points used to derive figure 3.6-2, there is:;o need to reverify if for technica'easons, but in case verificaf;ion is rcc)'red fo" other reasons, three sets of mechanical te.,t specimens repre-s<.ntin;, the base metal, weld metal and weld he-t affected zone metal have bcc:; placed ir< tho vessc'l. Th..:e c(<n be remove.<) and tc.sted a. required.

As described in paragraph ):.2.5 of the afety an. lysi:; report, detailed stress analyses have been mad!~ on the reactor vessel for both st,cady-s.a'c "!!d transient conditi..ns with respect to matc.ri<<1 f'atigue. The res 'ts of these analyses are compared to allowable stress limits.

Bec)uiring h'oolant temperature in an idle recirculation loop to be within 50 o the operating loop temerature before a recirculation pump is s.arted assures that the changes in coolant temperature at the reactor vessel nozzle" and botto!n head region are acceptable.

Thc co<>')art in thc bottom of the vessel is "t a love>'emperature than that in the upp r regions of the ves el when there is no rerirculatiorr flow.

Tnis colder water is forced up when recirculation pumps are started. This wil: no result in stresses which exceed AS)K Boiler and Pressure Vessel Code,Section IXI limits when the tempe. ature differential is not greater th,... 1)>5oF.

'] h(" r<'qlr l )'c"i(::, I.>> I i> i';<> I (I ))<) l L-UJ. <) I I,>>c rc;<( t<)! vcsuc I <' (>.,u!'<<.'1'(':<nc<) on fhc> "II)'!'<.r.per<<L<)r< )>'lu:: 60ol')!ich in dcrivc<I I'."o!ii LI!<: r(qui) cmcnL" of Lho A I!,l Co(lc t<> ) hi< h Ihc v<>>;.>> 'I w u: E>>>i) f.. T))o IIDT 'I(m!>< ) ul >)! c of th c:,'los)>< c

~

f'1<<ni c>>> <<dj <c >>I. h<.:<d u>><l "hc:I I. !>><<L<) un<i

~ 'I <>>I r<<)L< ) I><'I. i" (< rn(<>i)n<r>n The !nirim!nn tempe>tturc for bolt-up is thercf<)re I)0 + 60 = 100 )". <>I'>9o."-.

inc neutron radiation fluence at the closure flandres is well below 17 nvt,10

> l>ilev ani heref'ore radiation effects will be minor and will not influence this tempera're.

3.6.3!)I.6.~ Coolant Chemistry

)>a<,erials in the primary sv Lem are primarily 30)'f,ainlcss steel and t)re Zircaloy cladding. The reactor water chemistry limits are established to prevent d~ age to these materials. Limits are placed on conductivity and chloride concentrations, Conductivity is limited bc'.cause it is continously mea ured and gives an indicat,ion of abnormal condition';. and the presence of unu ual materials in the coolant. Ch'oride limits are specified to p> event, stress corrosion cracking of stainless steel, 216

3. 6/4. 6 BASES 3.6.B/4.6.B Coolant Chemistr Zircaloy does not exhibit similar stress corrosion failures. However there are some operating conditions under which the dissolved oxygen content of the reactor coolant water could be higher than .2-.3 ppm, such as reactor" startup and hot standby. During these periods, the most restrictive limits for conductivity and chlorides have been established. Mhen steaming rates exceed 100,000 lb/hr, boiling deaerates the reactor water. This reduces dissolved oxygen concentration and assures minimal chloride-oxygen content, which together tend to induce stress corrosion cracking.

When conductivity is in its normal range, pH and chloride and other impurities affecting conductivity must also be within their normal range. When conductivity becomes abnormal, then chloride measurements are made to determine whether or not they are also out of their normal operating values. This would not necessarily be the case. Conductivity could be high due to the presence of a neutral salt which would not have an effect on pH or chloride.

In such a case, nigh conductivity alone is not a cause for.

shutdown. In some types of water-cooled reactors, conductivities are in fact high due to purposeful addition of additives. In the case of BWR's, however, where no additives are used and where near neutral pH is maintained, conductivity provides a very good measure of the quality of the reactor water. Significant changes therein provide the operator with a warning mechanism so he can investigate and remedy the condition causing the change before limiting conditions, with respect to variables af fecting the boundaries, of the reactor coolant, are exceeded. Hethods available to the operator for correcting the of -standard condition include operation of the reactor cleanup system, reducing the input of impurities and placing the reactor in the cold shutdown condition. The ma jor benef ir. of cold shutdown is to reduce the temperature dependent corrosion "ates and provide time for the cleanup system to reestablish the purity of the reactor coolant.

The conductivity oi the reactor coolant is continuously monitored. The samples of the coolant which are taken every 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> will serve as a reference for calibration of these monitors and is considered adequate to assure accurate readings of the monitors. If conductivity is within its normal range, chlorides and other impuriti s will also be within tneir normal ranges.

The reactor coolant samples will also be used to determine the chlorides. Therefore, the sampling frequency is considered adequate to detect long-term changes in the chloride ion content.

Dazly sampling is performed when increased chloride concentrations are most probable. Reactor coolant sampling is increased to onc per shift when the continuous conductivity monitor is unavailable.

217

3.6/4.6 BASES:

The basis for the equilibrium coolant iodine activity limit a.s a computed dose to the thyroid of 36 rem at the exclusion distance during the 2-hour period following a steam line break. This dose is computed with the conservative assumption of a release of l40,000 lbs of coolant prior to closure of the isolation valves, and a X/Q value of 3.4 x 10 4 Sec/m3.

The maximum activity limit during a short term transient is established from consideration of a maximum iodine inhalation dose less than 300 rem.

The probability of a steas line break accident coincident with an iodine concentration transient is significantly lower than that of the accident alone, since operation of the reactor with iodine levels above the equilibrium value is limited to 5 percent of total operation.

The sampling frequencies are established in order to detect the occurrence of an iodine transient which may exceed the equilibrium concentration limit, and to assure that the maximum coolant iodine concentrations are not exceeded. Additional sampling is required following power changes and off-gas transients, since present data indicate that the iodine peaking phenomenon is related to these ea entsa 3.6.C/4.6.C Coolant (.a~atca a Allowable leakage rates of coolant from the reactor coolant system have been hns6d on the predicted ILnd experimentally observed behavior of cracks in pipes and on the ability to makeup coolant system leakage in thc event of loss of of faute a-c power. Thc normally expected background leakage due to equipment design and the detection capability for determining coolant sys-tem leakage werc nlao considered in establishing the limits. The behavior of crocks in pfpinp systems has been experimentally and analytically inves-tigated as part of thc VS'AEC sponsored Reactor Primary Coolant System Rupture Study (cho Pipe Rupture Study). Work utilizing the data obtained in this study indicates that leakage from a crack can be detected before the crack RroMs to n dangerous or critical size by mechanically or'hermally induced cyclic loading, or stress corrosion crackinp or some other mechanism characterized by gradual crack growth. This evidence suggests that for leak-age somewhat greater than the limit specified for unidentified leakage, the probability is small that imperfections or cracks associated with such leak-age would grow rapidly. 1lowever, the establishment of allowable unidentified leakage greater than that given in 3a6.C on the basis of the data presently available would he premature because of uncertainties associated with the data. Yor leakage of the order of 5 gpm, as specified in 3.6.C, the experi-mental and analytical data suggest a reasonable margin of safety that such loakaRc magnitude would not result from a crack approaching the critical size for rapid propagation. Leakage less than the magnitude specified can be 218

3. 6/4. 6 BASES detected reasonably in a matter of few hours utilizing the available if leakage detection schemes, and investigation The total and the origin cannot be detcrmincd in reasonably short time the unit should be shut down to allow further corrective action.

leakage rate consists of all leakage, identified. and unidenti-a 4

fied, which flows to the drywell floor drain and equipment drain sumps.

The capacity of the d~ell floor sump pump is 50 gpm and the capacity of the drywell equipment sump pump is also 50 gpm. Removal of 25 gpm from either of these sumps can be accomplished with considerable margin.

REFERENCES

l. Nuclear System Leakage Rate Limits (BFNP FSAR Subsection 4.10) 3.6.D/4.6.D Safet and Relief Valves The safety and relief valves are required. to be operable above the pres-sure (105 psig) at which the core spray systems is not designed to deliver full flow. The pressure relief system for each unit at the Browns Ferry Nuclear Plant has been sized to meet two design bases. First, the total safety/relief valve capacity has been established to meet the overpressure protection criteria of the ASME Code. Second," the distribution of this required capacity between safety valves and relief valves has been set to meet design basis 4.4.4-1 of subsection 4.4 which states that the nuclear system relief valves shall prevent opening of the safety valves during normal plant isolations and load rejections.

The details of the analysis which shows compliance, as modified by Reference 4, with the ASME Code requirements is presented in subsection 4.4 of the FSAR and the Reactor Vessel Overpressure Protection Summary Technical Report submitted in Amendment 22 in response to question 4.1 dated December 6, 1971.

Thirteen safety/relief valves have been installed on each unit with a total capacity of 74/o of design steam flow. The analysis of the worst overpressure transient, (3-second closure of all main steam line isola-tion valves) neglecting the dire@ scram (valve position scram) results in a maximum vessel pressure of 130 psig if a pressure scram is assumed, or 1259 psig margins respectively to the code allowable overpressure limit of 1375 psig. Xn addition, the same event was analyzed to determine the number of installed valves which must open to limit peak pressure to 1350 psig (25 psig margin). The results of this analysis shows that seven valves must open if a neutron flux scram is assumed or ten valves must open if a pressure scram is assumed.

To meet the, second design basis, the total safety/relief capacity of 745 has been divided into 61'elief (11 valves) and 134 safety (2 valves).

The analysis of the plant isolation transient (turbine trip with bypass 219

3.6/4.6 OASES:

valve failure to open) assuming e turbine trip scram is presented in FSAR paragraph 14,5,1.2 end Figure 14.5-1. This analysis shows that che, 11 relief valves limit pressure et the safety valves to 1168 psig, veil below thc setting of the safety valves. Therefor'e, the safety valves vill not open. This analysis shove that peak system pressure is limited to 1210 psig which ie 165 psig below the allowed vessel overpressure of 1375 psig.

Evperience in relief and safety valve operation shows that e testing of 50 pcrccnt of the valves per year is adequate to detect failures or

. dcceriorectons. 'l'hc relief and safety valves are benchtcsced every oeco>>d operacinj cycle to ensure that their set points are within the

+ I percent tolerance. The relief valves are tested in place once per opcraci>>g cycle co establish that they vill open end pass steam.

The rcq>>item( rca established above apply when thc nuclear system can be pressurized above ambient conditions. These requirements are applicable ac>>uclcnr ay~tern pressures bclov normal operating pressures because abnormal operational transients could possible start et these conditions such that eventual overpressure relief would be needed. , However, these transients erc much less severe, in terms of pressure, than those starting ar rated conditions, The valves need not bc functional when the vessel head is removed, since the nuclear system cannot be pressurized.

h REFEREHCFS

1. Nuclear Syscem Pressure Relief System (BFNP FSAR Subsection 4.4)

2. Amendment 22 in response to AEC Question 4,2 of December 6,. 1971.

3. "Protection Against Overpressure" (ASME Boiler and Pressure Vessel Code, Section III, Article 9)

Brown>s Forry liuclser Plant Design Deficiency Report Target Rock Ssfetv-Reliot'alves, transmitted by J. i. Glllelend to F. E, Kruosi, August 29~ 19/3 ~

3.6.E/4.6,E ~Jet Fur 8 Failure of a jet pump nozzle assembly holddovn mechanism, nozzle assembly and/nr riser, vould increase the cross-sectional ilov area for blovdown following the design basis double-ended line break. Also, failure of the diffuser would eliminate the capability to ref lood che core to two-thirds height level following a recirculation line break. Therefore, occurred, repairs must be made.

if a failure The detection technique is as follows. With the tvo recirculation pumps balanced in speed to within + 5 percent, the fiov tates in both recircula-tion loopa vill bc verified by concrol room monitoring instruments. If thc )vo flov race values do not differ by more than 10 percent, riser and nozzle nasemb)y integrity has been verified.

220

,.6/4,fi BASES; If they do differ by )0 percent or more, the. core flov rate measured by the jet pump dif fuser dif ferential pressure system must be checked against the core flov rate derived from the measured values of loop flov to core flow correlation, If the difference between measured and derived core flov rate is 10 percent or more (with the derived value higher) diffuser measurements vill be taken co define the location vithin the vessel of failed )et pump nozr.le (or riser) and the unit shut dovn for repairs. If the potential bloudoun flov area is increased, the system resistance to the recirculation pump ie also reduced; hence, thc affected drive pump will "run out" to a substantially higher flow race (approximately 115 percent to 120 percent for a single nozzle failure). If th, two loops are balanced in flow at the same pump speed, the resistance characteristics cannot have changed. Any imbalance bctueen drive loop flow rates would be indicated by the plant process instrumentation. In addition, thc affected ]ct pump vould provide a leakage path past the core thus reducing the core flow rate. The reverse flow thtough the inactive )et pump would still be indicated by a positive dif fcrencial pressure but the net effect would be a slig'ht decrease (3 per-cent to 6 pcrccnt) in the tocal core flow measured. This decrease, together uich chc loop flov increase, vould result in a lack of correlation between measured and derived core flow rate, Finally, the affected )et pump diffuser differential pressure signal vould be reduced because the backflov vould be less chan the normal forvard flow.

A nnrzlc-riser system fai.lure could also generate the coincident failure of a >ct pump diffuser body; however, the converse ie not true. The lack of any substantial stress in the )et pump diffuser body makes failure impossible vithout an initial nozzle-riser system failure.

3.6.F/4.6.F Jec Pum Flou Hismatch The l.PCI loop selection logic has been previously described in the BFNP FSAR.

For some limited low probability accidence with the recirculation loop opera-ting uith large speed differences, it is possible for the logic to select the wrong loop for in)ection. For these limited conditions the core spray itself is adcquatc to prevent fuel temperatures from exceeding allowable limits. How-ever, to limi,t the probability even further, a procedural limitation has been placed on che allowable variation in speed betveen the recirculation pumps, Analyses indicate that above 80% power the loop select logic could be expected to function at a speed differential up to 14X of their average speed. Belov 80X power the loop select logic vould bc expected to function at a speed diffcrcncia). up co 20% of their average speed. This specification provides margin because che limits are set ec + lOX and + 15X of the average speed for chc above and belov 80% pover cases, respectively. If the reactor is opera-ting on one pump, thc loop select logic trips that pump before making the loop selection.

221

3.6/4.6 BASES:

Requiring the discharge valve of the lower speed loop to remain closed until the speed of the faster pump is below 50'X of its rated speed provides assurance when going from one to two pump operation that excessive vibration of the jet pump risers will not occur.

3.6.G/4 '.G Structural Inte rit The requirements for the reactor coolant systems inservice inspection program have been identified by evaluating the need for a sampling examination of areas of high stress and highest probability of failure in the system and the need to meet as closely as possible the requirements of Section XI, of the ASME Boiler and Pressure Vessel Code.

The program refle'cts the built-in limitations of access to the reactor coolant systems.

It is intended that the required examinations and inspection be completed during each 10-year interval. The periodic examinations are to be done during refueling outages or other extended plant shutdown periods.

Only proven nondestructive testing techniques will be used.

More frequent inspections shall be performed on certain circumferential pipe welds as listed in Section 4.6.G.4 to provide additional protection against pipe whip. These welds were selected in respect to their distance from hangers or supports wherein a failure of the weld would permit the unsupported segments of pipe to strike the drywell wall or nearby auxiliary systems or control systems. Selection was based on judgement from actual plant obsrevation of hanger and support locations and review of drawings. Inspection of all these welds during each 10-year inspection interval will result in there additional examinations above the requirements of Section XI of ASME Code.

An augmented inservice surveillance program is required to determine whether any stress corrosion has occurred in any stainless steel piping, stainless components, and highly stressed alloy steel such as hanger springs, as a result of environmental conditions associated with the March 22, 1975 fire.

222

REFERENCES

l. Inservice Inspection and Testing (BFHP FSAR Subsection 4.12)

2. Inservice Inspection of Nuclear Reactor Coolant Systems,Section XI, ASME Boiler and Pressure Vessel Code

3. ASME Boiler and Pressure Vessel Code, Section III (1968 edition)

4. American Society for Nondestructive Testing No. SNT-TC-1A (1968 edition)

5. Mechanical Maintenance Instruction 46 (Mechanical Equipment,

~

Concrete, and Structural Stell Cleaning Procedure for Residue From Plant Fire - Units 1 and 2)

6. Mechanical Maintenance Instruction 53 (Evaluation of Corrosion Damage of Piping Components Which Were Exposed to Residue From March 22, 1975 Fire)

7. Plant Safety Analysis (BFNP FSAR subsection 4.12) 223

3. 6. H/4 . 6 H Shock Suporessors Snubbers Snubbers are designed to prevent unrestrained pipe motion under dynamic loads as might occur during an earthquake or severe transient, while allowing normal thermal moticn during startup and shutdown. The consequence of an inoperable snubber is an increase in the probability of structural damage to piping as a result of a seismic or other event initiating dynamic loads.

is therefore required that all hydraulic snubbers required to It protect the primary coolant system or any other safety system or component be operable during reactor operation.

Because the snubbe" protection is required only during relatively low probability events, a period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is allowed or repairs or replacements. In case a shutdown is required, the 224

3 ~ 6/rr . 6 BASES allowance of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> to reach a cold shutdown condition will permit an orderly shutdown consistent with standard operating procedures. Since plant startup should not commence with knowingly defective safety related equipment, Specif ication

3. 6. H. 5 prohibits startup with inoperable snubbers.

All safety related hydraulic snubbers are visually inspected for overall integrity and operability. The inspection will include verification of proper orientation, adequate hydraulic fluid level and proper attachment of snubber to piping and structures.

The inspection frequency is based upon maintaining a constant level of snubber protection. Thus the required inspection interval varies inversely with the observed snubber failures.

The number of inoperable snubbers found during a required inspection determines the time interval for the next required inspection. Inspections performed before that interval has elapsed may be used as a new reference point to determine the next inspection. However, the results of such early inspections performed before the original required time interval has elapsed (nominal time less 25%) may not be used to lengthen the required inspection interval. Any inspection whose results require a shorter inspection interval will override the previous schedule.

Experience at operating facilities has shown that the required surveillance program should assure an acceptable level of snubber performance provided that the seal materials are compatible with the operating environment.

Snubbers containing seal material which has not been demonstrated by operating experience, lab tests or analysis to be compatible with the operating environment should be inspected more frequently (every month) until material compatibility is "on f irmed or a n appropriate changeout is completed.

Examination of defective snubbers at reactor facilities and material tests performed at several laboratories (Reference 1) has shown that millable gum polyurethane deteriorates rapidly under the temperature and moisture conditions present in many snubber locations. Although molded polyurethane exhibits greater resistance to these conditions, it also may be unsuitable for application in the higher temperature environments. Data are not currently available to precisely define an upper temperature limit for the molded polyurethane. Lab tests and in-plant experience indicate that seal materials are available, primarily ethylene propylene compounds, which should give satisfactory performance under the most severe conditions expected in reactor installations.

To further increase the assurance of snubber reliability, functional tests should be performed once each refueling cycle.

225

3. 6/4 . 6 HAS ES These tests will incluDe stroking of the snubbers to verify prop r piston movement, lock-up and bleed. Ten percent or snubbers whichever is less, re presents an adequate sample for such tests. Observed failures on these samples should requir testing of additional units. Those snubbers designated in Table

3. 6.H as being in high radiation areas or especially difficult to remove need not be selected for functional tests provided operability was previously verified.

Snubbers of rated capacity greater than 50,000 lb. are exempt from the functional testing requirements because of the impracticabU.ity o, testing such large units.

REFERENCES

1. Report, H. R. Erickson, Bergen Paterson to K. R. Goller, NRC, October 7, 1974,

Subject:

Hydraulic Shock Sway Arrestors 226

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.'7 CONG'Q I HM EHT A~ i i c e ~bi 1 i t SYSTEMS Q. 7 A

COHTAI HMEHT SYSTEMS lxcabz lit 0 Applies to the operating status Applies to the primary and of the primary and secondary secondary containment containment systems. integrity.

~bb 'ective

~ob 'ective To assure the integrity of the primary and secondary To verify the inte-rity,of the containment systems. primary and secondary containment.

Speci f ication Primar Containment Speci fication Primar Containment At any time that the irradiated fuel is in 1. Pressure Suppression the reactor vessel, Chamber and the nuclear system is pressurized a. The suppression above a tmospher ic chamber water level pressure or work is be checked once per being done which has day. Whenever heat the potential to is added to the drain the vessel, the pressure suporession suppression oool by pool water volume and testing of the ECCS temperature shall be or relief valves the maintained within the pool temperature shall fol lowing 1imi ts be continually monitored except as specified and shall be observed in 3v7 ~ A 2 ~ and logged every 5 minutes unti 1'he heat

'a ~ Minimum water addition is terminated.

volume - 123, 000 fthm

b. Maximum ~ater volume - 135,000

c. With the suppression pool water temperature > 95'F initiate pool cooling and restore the te'mperature to <

95'F within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least hot shutdown within the next o hours and in cold shutdown within 227 the following 30 ho~rs.

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7 CONTAINMENT SYSTEMS 4.7 CONTAINMENT SYSTEMS

d. With the suppression pool water temperature > 105'F during testing of ECCS or relief valves, stop all testing, initiate pool cooling and follow the action in specifi-cation 3.7.A.l.c above:

e. With the suppression pool water temperature > 120'F following reactor isolation, depressurize to ( 200 psig at normal cooldown rates.

f. With the suppression pool water temperature > 110'F during startup or power operation the reactor shall be scrammed'28

LI"lIT1" ('.O!lUITIO:4S FOR OPF."ATION SURVF.I LI.Aber. RFOUIR'r"!c.%TED 3.7.A Prtmir~Containmcnt 4. 7.h Prima rv Cour a inmi nt

2. Primary containmenc 2. Inccara ted Leak Race Tescinr.

integrity shall be main-tained at all times when a. Integrated leak race tests the reactor is cri ical (ILlIT's) shall bc per for"..ed or when che reactor to verify primary concain-Mater temperature is mcnt integrity. Primary above 212'F. and fuel containmcnc integrity is is in the reactor vessel except while per-conf fr...ed if the maximu...

allowable integrated leak-forming "open vessel" age race, L , does not ex-physics tests at power ceed che equi.valent of 2 levels not to exceed pcrcenc of che primarv con-5 m(t). tainmenc volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ac the49.6psio, design pres-sure, P P

b. Integrated leak rate tests may be performed at P or at a test pressure, P of noc less han 25 osig pro-vided thc res>>1 canC leakage>>

rate, L,, does nor exceed a pre <<st ai> l I".h>> 3 f reaction oi L

a detqrmined as follows:

Prior to initial operation,

-integraced leak rate tests muse be performed ac P and P w'ch the lower press>>re CPsc performed cirsc co establish the <<'lowablc leak rates (in percent pcr 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) . The leakage ra tes thus measured shall be iden-tified as L and L respec-tively. L snail noF exceed L

a L

cm fo; values L

pm of L ri 0 7.

l.

pm 229

LlnMITINC CONI) ITIONS FOll OIeFRATION SURVE?I.LANCE RE VIREMFNTS

3. 7.A Primtt re Con tn Inmate t 4.7.4 ~primer Cnnrnrnmenr L

t shall not excccd

.5 L

a p 't for values of p

p L

tm

> 0.7.

L pm

c. 1. Test duration shall be at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. Closure of containment isolation valves for the purpose of the test shell be accomplished by the means provided for normal operation of the valves without preliminary'xercises or adjustment.

3. Test accuracy shall be verified by supplemen-tary means, such as measuring the quantity of air required to return to the starting point or by imposing a known leak rate to demon-strate the validity of measurements,

d. The allowable operational leakage rate which shall bc met prior to resumption of power shall not be greater than 75 percent of L if the test prcssure is P or not greater than 75 percent of L if the test pressure is P t

e. The ILRT's shall bc ocrformeo at the following minimum frequency; 230

Primar Con ta inmen t 4.7.A Primary Containment

1. Prior to initial unit nperaCion.

2. ht approximately three and ore-third year intervals so that any ten-year interval would include four ILRT's. These inter-vals may be extended up. to eight months if nec soary to coin-cide with refuclins outage.

f. Except for the initial ILRT, all ILRT's shall be per-formed without leak repai.rs iauacdiately prior to or during the t=st. If leak repairs are necessa;y in order to perfoaa Il.RT, they shall be preceded by local leak measuremen s where

, possible. The leak rate difference prior to end after repair sh" 11 be added to final integrated leak rate results, L or L Following each IIEET, if the measured leak rate cx" eeds L, the condition sha'1 be corrcc ted. Following repairs, elis integrated leak rate test need not bc repeated provided local leakage raC" u easuremcnts before and after repair demonstrate Chat the leakage rate reduction achieved by repairs reduces the overall measured integrated leak rate to an, acceptable value.

g. Local leak rate tests (LLRT's) shall be performed on the primary containment testablc penetrations .".nd isolation valves at not less than 49.6 psig (except for the main steam isolation valves, see 4.7.A. i) each opera-231

.,IHITINC CONDITIONS FOR OPERAT?ON SURVEILLANCE RE UIREHENTS

. 7.'A Prima Containmcnt 4.7.A Primar Containment ting cycle. Bolted double-gasketed seals shall be tested whenever the seal is closed after being opened and at least once per operating cycle.

Acceptable methods of testing are halide gas detection, soap bubbles, pressure decay, hydro-statically pressurized fluid flow or equivalent.

The personnel air lock shall be tested at a pressure of 49.6 psig during each operating cycle. In addition, following each opening, the personnel air lock shall be leak tested at a pressure of > 2.5 psig.

The total leakage from all penetrations and isolation valves shall not exceed 60 percent oi L per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, Penetrations and isolation valves are identified as follows.

(1) Testable penetrations with double 0-ring seals - Table 3.7.8, (2) Testable penetrations with testable bellows-Table 3.7.C, (3) Isolation valves-Tables 3.7.D through 3.7.C, and (4) Testable electrical penetrations - Table 3,7.H

h. (1) If at any time it is deter-mined that the criterion of 4.7.A.2.g is exceeded, repairs shall be initiated immediately.

(2) If conformance to the criterion of 4.7,A.2.g is not demonstrated 232

LIHITING C.i u ITIOUS YOR OPERATION . SURVEILLANCE RE UIR~ AGENTS 3;7.A Prima Containment 4.7.A Prima Containment within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> following detection of excessive local leakage, the reactor shall be shutdown and deprcssurized until repairs are effected and the local leakaFe meets the acceptance cri-terion as demonstrated by retest.

The main steamline isola-tion valves shall bc tested at a prcssure of 25 psig for leakage during each refueling outage. If the leakage rate of 11.5 scf/hr for aay one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

Continuous Leak Rate Monitor When the primary containment is inerted, the containment shall. be continuously tmni-torcd for gross leakage by review of the inertiag system makeup requirements. This monitoring system ~y be taken out of service for maintenance but shall be returned to ser-vice as soon as practicable.

k. Dr 11 and'Torus Surfaces The interior surfaces of t'e drywell and torus above the level one foot below the normal water lin and outside surfaces of the torus below the water line shall be visually i.'oected eacn operating cycle for deterioration and any sip:

of structural damage with particula attention to piping ionnections and supports and for signs of distress or displacement. Zn the event of an extended relief. valve operation when thc temperature of the suppression pool exceeds 130 P.,

233

LIMIT1NG CO.'101T lONS FOR OPFF STION SURVB~LL(!1CF. RFOJtR~K4TS t3. 7.h Primer 3.

Coneninmenc Prcssure Su rcosion Chamber-Reactor Buildinc Vacuum Breakers Except os specified in 3.7.A.3.b below, tvo pressure suppression chamber-reactor building 4.7.A Primary Concainmenc 3.

the reactor shall be placed in cold shutdown and the above inspection performed before the reactor started up.

Pressure Buildin Su Vacuum ression Chamber-Reactor Breakers is sha3'e vacuum breakers shall be operable at all times when a. The pressure suppression chamber-primary concainmenc inte- reactor building vacuum brealeers trity is required. The shall be exercised and the associ-oet point: of the d'ffcren- ated instrumentation including tial pressure inst,rumenta- setpoint shall be functionally tested for proper operation each tion vhich actuates che pressure suppression cham- three months.

ber-rcaccor building vacuum breakers shall be b. A visual examination and determina 0.5 psid, tion that the force required to open each vacuum breaker (check

b. From and after the date valve) does not exceed ".5 psid that one of che pressure will be made each refueling outage.

suppression chamber-reactor building vacuum brenkero is made or found to be inopera-ble for any reanon, reactor operation io permissible only during rhe oucceedl.ng seven days, provided that 4. Dr el l-Prcssure Suppression thc repair procedure does Chamber Vacuum Breakers not violate primary contain-mcnt integrity. a. Fach drywel1-suppression chanbe r. vacuum br eaker shall be exerc)scd through Chamber 'I'ncuum Breakage an opening-closing cycle every month.

&~ When primcry containment is required, all drywell-ouppresoion chamber vacuum breakers shall be operable and pooitioned in the fully closed position (except b. When it is determined chac two vacuum breakers are during testing) except as opecificd in 3.7.A.4.b and inoperable for opening ac a c, below. tine vhen operabitiry is rcquir all other vacuum breaker

b. One drywell-suppression chamber vacuum breaker may be non-fully closed so long as ic ic dcterni'ned to bc not more than 3" open as indicated by che position lights, 234

I.IHITING C~.'.f "C fONS FOR OPERATION SURVEILLANCE RE UIREHENTS

3. 7.A ~Prtmnr Conca1nnenc t .7.A Primar Containment valves shall be exercised inuuediately and every 15 days th reaftcr until the inoperable valve has been 0

returned to normal service.

c. Two drywcl 1-suppression cd Once each operating cycle chamber vacuum breakers each vacuum breaker valve shall may be determined to be be inspected for proper operation inoperable for opening. of the valve and limit swi.tches.

d, If specifications 3.7.A.4.a, d. A leak teat of the drywell

.b, or .c cannot be met, the to suppression chamber unit Ohall be placed in a structure shall be con-cold shutdown condition in ducted during each an orderly manner within 24 operating cycle. Accept-hours. able leak rate is 0.14 ib/

sec of primary containment atmosphere with 1 psi differential.

5. 0 en Concentration

a. After completion of the a. Thc primary containment hydrogen &:

fire-related startup retestin oxygen concentration shall program, be measured and recorded daily.

containment atmosphere shall be reduced to less than 4X oxygen with nitro-gen gas during reactor power operation with reac-tor coolant pressure above 100 psig, except as speci-fied in 3.7.A.5.b.

b. Within the 24-hour period subsequent to placing the reactor in the Run mode following a shutdown, thc containment atmosphere oxygen concentration shall ba reduced to lena than 4Z by weight and maintained in this condition. De-inert-ing may commence 24 hours prior to a shutdown.

c. If specification 3.7.A.5.a and 3.7.A.5. b cannot be met, an orderly 235 shutdown shall be initiated and the reactor shall be in a Cold Shutdown condition within 24 hours.

Ir".ITIVG CONDITIONS FOR OPEPWTIOVi SURVEILLAVCE REQUIREMENTS

). 7 CONTAINMFNT SYSTEHS Q. 7 COP1'AINHENT SYSTEilS B. Standb Gas Treatment S stem B. Standb Gas Treatment

~Sst All Except as specified in Specification At least once per 3.7.B.3 below, all year, the followzng three trains of the conditions shall be standby gas treatment demonstrated.

system and the diesel generators required a ~ Pressure drop for operation of such across the trains shall be combined H W A, operable at all times filters and when secondary charcoal containment integrity adsorber banks is required. is less t:han 6 inches of water at a flow of 9000 cfm (+

10%) .

b. The inlet heaters on each circuit are capable of an output of at least 40 kM when tested in accordance with ANSI '8510-1975.

co Air distr ibu t ion is uniform within 20%

across HEPA filters and charcoal adscrbers.

236

L LMITINC CONDITIONS FOR OPERATION SURVEILLANCE RFQUI REMENTS

3. 7 CONTAINMEN'I SYSTEMS 4. 7 CONTAINMENT SYSTEMS

2. a0 The results of 2. 'a ~ The tests and the in-place sample analysis cold COP and of Specification halogenated 3.7.B.2 shall be hydrocarbon performed at tests at ~ 10'$ least once per design flow on operating cycle HEPA filters and or once every 18 charcoal months whichever adsorber banks occurs first for shall show 299% standby service DOP removal and or after every 299A halogenated 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of hydrocarbon system operation remova1 when and following tested in significant accordance with painting, fire ANSI N510-1975 or chemical

~

release in any

b. The results of ventilation zone laboratory communi cating carbon sample with the system.

analysis shall b. Cold DOP tes ting show 290%

radioactive shall be methyl iodide per formed after removal when each complete or tested in partial accordance with replacement of ANSI N510-1975 the HEPA filter (130oC, 95% bank or after B.H.) . any structural maintenance on C~ Fans shall be the system shown to operate housing.

within +10%

design flow, C ~ Ha logenated hydrocarbon testing shall be performed after each complete or partial replacement of the charcoal adsorber bank or after any structural maintenance on 237 the system housing.

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3' CONTAINMENT SYSTEMS 4.7 CONTAINMENT SYSTEMS

d. Each train shall be operated with t;hc heal;ers on a.

total of at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> every month.

e. Test sealing of gaskets for housing doors shall be performed utilizing chemical smoke generators during each test performed for compliance with Specification 4.7.B.2.a and Specification 3.7.B.2.a.

3. From and after the 3 ~ At least once date that one train per year of the standby gas automatic treatment system is . initiation of made or found to be each branch of inoperable for any the standby gas reason, reactor treatment system operation and fuel shall be handling is demonstrated permissible only from each unit's during the succeeding controls.

7 days unless such circuit is sooner At least once made operable, per year manual provided that during operability of such 7 days all the bypass valve active components of for filter the other two standby cooling shall be gas treatment trains demonstrated.

shall be operable.

238

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS

3. 7 CONTAINMENT SYSTEMS 4 7 CONTAINMENT S YST EMS c~ when one train of the standby gas treatment system becomes inoperable the other two trains shall be demonstrated to be operable within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and daily thereafter.

4. If these conditions cannot be met, the reactor shall be placed in a condition for which the standby qas treatment system 4~ When a unit is operating is not required. at power:

'a ~ The operator shall log the status of the SGTS once each 8-hour shift and at any other time its operability status changes.

b. The operator shall notify the other unit operators should he remove from service or find inoperable unit components which reduce system availability.

239

).JHITTNte CO'NAITIA!75 FOR OPLRATIOtt SURVEILLANCF. RE UIR~FNTS 3.7.C Sccnniec~Conta1nnene 4. 7. C Secondar Containment

l. Secondary containment inte- l. Secondary containment surveil-grity shall bc maintained in lance shall be performed as thc reactor zone nt all times indicated below:

except as specified in 3.7.C.2.

a. A preoperntional secondary containment capability test shall be conducted by iso-lating the reactor building and placing two standby gas treatment system filter trains in operation. Such test shall demonstrate the 240

3. 7.C Secondar Containment 4.7,C Secondar.! Containment capaoility to maintain 1'/4 inch of water vacu. m under calm wind ( < 5 mph) condi-tions with a system inleakage rate of not more than 12,000 cfm,

b. hdditional tests shall b performed during the first operating cycle under an adequate number of dif-ferent environmental wind conditions to enable valid extrapolation of the test results.

c. Secondary containment capa-bility tomaintain 1/0 inch o water vacuum under calm win"

( < 5 mph) conditions with a sys t em inleakage ra t e of not more than l2,000 c fm, shall be demonstrated at each refueling outage prior to refueling.

2. If reactor zone secondary con- 2. hfter a secondary containment tainment integrity cannot be violation is determined the maintained the following con- standby gas treatment system ditions shall be met: will be operated irnnediately after the affected zones are isolated from the remainder of

a. The reactor shall bc made the secondary containment to subcritical and Specifica- confirm its ability to main-tion 3. 3. A shall be me t . tain the remainder of the secondary containment at 1/4-

b. The reactor shall be cooled inch of water negati.ve prcssure down below 212'F and the under calm wind conditions, reactor coolant system vented.

c; Fuel movement shall not be permitted in the reac-tor zone.

d. Priraary containment integri y maintained.

3. Secondary containment integrity shall be ma>ntnined in the re-fueling zone, except as speci-fied in 3.7.C.4.

241

~ '

NC CONDITlnNS FOR nPFRATION SURVEILLANCE. RE. VIP .ClZNTS

~ 7 ~ Second¹r Containment 4.7.C Secondar Containmsnt

4. If refueling zone secondary containment cannot be maintaired the following conditions shall be met:

a ~ Handling oE spent fuel and all opera tions over spent fuel pools and open reac-tor wells containing 'fuel shall be prohibited.

b. The standby gas treatment system suet'ion to the re-fueling zone will be blocked except for a con-tro) led leakage area sized to assure the achieving of a vacuum of at least I/4-inch of water and not over 3 inches of water in all three reactor zones.

Primnr Containment Isolation Valves D. Primar Containment Isola ion Valves

l. During reactor power operation, 1. The primary containment isola-all isolation valves listed in tion valves surveillance shall Table 3.7.A and all reactor be performed as follows:

coolant system instrument line flow check valves shall bc a. At least once per operating operable except as specified cycle the operable isola-in 3.7.D,2. tion valves that are power operated and auto-matically initiated shall be tested for simulated automatic initiation and closure tines.

b. At least once per quarter:

(1) All normally open power operated isolation valves (except for the main steam line power>>

operated isolation valves) phall,bc fully closed and reopened.

242

I.IRITIHO Cl)NI) IT IOUS FOR OPl RATION SURVFII.I,ANCE RF. UIRFAFNTS

'l. 7.I) pz'Imn~rCnntnlnmrnt InoIat Inn Valves o. 7. n ~prrnor conrninnonr l onion ion onion:

(2) With thc reactor power less than 75% trip main steam isolation valves individually and verify closure time.

c. At least twice per week the main steam line power-operated isolation valves shall be ccxercised one at a time by partial closure and subsequent reopening.

d. At least once per operating cycle th'c operability of the reactor coolant system instrument line flow check valves shall be verified.

2. In the event any isolation 2. Whenever an isolation valve valve specified in Table 3.7.A listed in Table 3.7.A is in-becomes inoperable, reactor operablc, the position of at power operation may continue least one other valve in each provMcd at least onc valve line havinp, an inoperable in each linc having an in- valve shall be recorded daily.

operable valve is in the mode correspondinp to the isolated condition.

3. If Specification 3.7.D.l and 3.7,D.2 cannot be met, an orderly shutdown shall be initiated and thc reactor shall bc in the Cold Shut-down condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

243

I.INCITING CONOITIONS FOR OPERATION SURVEILLANCE REQUIREHENTS

.7 CON t AINHENT SYSTENS Q. 7 CONTAINMENT SYSTEHS Ventilation Control Room Emeraenc Ventilation Except as specified in sp cification At leas once per 3.7.E.3 below, both operating cycle, not ccntrol room to exceed 18 months.

emergency the pressure drop pressurization across the combined systems and the HEPA filters and diesel generators charcoal adsorber required for their banks shall be operation shall be d monstrated to be operable at all times less than 6 inches of when any reactor water at system vessel contains design flew rate (+

irradiated fuel. 10%) .

2. ar The results of 2. a ~ The tests and the in-place sample analysis cold O'OP and of Sp cification halogenated 3.7.Z.2 shall be hydrocarbon performed at tests at design least once per flows on HEPA operating cycle filters and or once every 18 charcoal months, adsorLer banks whichever occurs shall show >99% first for DOP removal and standby service

>99% halogenated or after every hydrocarbon 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of removal when system operation tested in and following accordance with signif icant ANSI N510-1975. painting, fire or chemical

b. The results of release in any laboratory ventilation zone carbon sample communicating analysis shall with the system.

show >90%

radioactive b. Cold DOP testing methyl iodide shall be removal at a performed af ter velocity each complete or in when'ested partial accordance with replacement of ANSI 510-1975 Vi the H PA filter (1300C, 95% bank or after R.H.) . any structural maintenance on 244 the system housing.

I IHITING COVQXTIONS = OR OP RATXON SURVEILLANCE REQUI PmP<NTS 3 ~ 7 CORI'AINHENT SYST "HS 4.7 CONTAINHENT SYSTEHS c ~ System flew rate c Halogenated shall be shown hydrocarbon to be within testing shall be

+10~~ design flow when tested in performed aft:er accordance with each complete or ANSX 510-1975 partial N ~

replacement of

3. From and after the the charcoal date that one of the adsorber bank or cont rol room after any emergency structural pressurization maintenance on systems is made or the system found to be housing.

inoperable for any d. Each circuit reason, reactor shall be operation or operated at refueling operations least: 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> is permissible only every month.

during the succeeding 7 days unless such circuit is sooner 3. At least once per made operable. operating cycle not to exceed 1S months, I f these conditions automatic initiation cannot be met, of the control room reactor shutdc'm emergency shall be initiated pressurization system and all reactors shall be shall be in cold demonstrated.

shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for reactor During the simulated operations and automatic actuation test of this system refueling operations shall be terminated (see Table 4. 2.G),

shall be verified it within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.- that the following dampers operate as indicated:

Close. FCO-150Ag Bg Cg D, E, and F Open: FCO-151 FCO-152 245

LIMITING COiVDXTIOHS FOR OPERATXOH SURVEILLANCE REQUIREMENTS

3. 7 CONTAINMENT SYSTEMS 4. 7 COÃZAINMENT SYST MS F. Pximar Conta nment Pur e Svstem Primax Containment Pux e

~Sat em The primary containment shall be 1 ~ At least once per normally vented and operating cycle, not purged thxough the to exceed 18 months primary containment the pressure drop purge system. The ac=oss the combined standby gas treatment HEPA filters and system may be used charcoal adsorber when primary banks shall be containment, purge demonstrated to be system is inoperable. less than 8.5 inches of water at system design flow rate g+

2. a ~ The results of 10'5) .

the in-place 2. a The tests and cold DOP and ~

sample analysis halogenated of Specification hydrocarbon 3.7.F.2 shall be tests at design performed at flows on HEPA least once per filters and operating cycle charcoal or once every 18 adsoxber banks shall show >995 months DOP removal and whichever occurs

>99% halogenated first or after hydrocarbon 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of removal when system operation tested in and following accordance with signif icant A'HSX N510-1975. painting, fire, or chemical

b. The results of release in any laboratory ventilation zone carbon sample communicating analysis shall with the system.

show >85%

radioactive b. Cold DOP testing methyl iodide shall be removal when performed after tested in each complete or accordance with partial ANSI Vi510-1975 replacement of (130oC. 954 the HEPA filter R.H.) . bank or after any structural maintenanc on the system housing.

246

L." J!XT ING CONDITIONS FOR OPF RATION SURVEILLANCE REQUIREMENTS

3. 7 COJ'JTAXNHENT S YSTEMS A.7 CONTAXNi4ENT SYSTEMS c ~ System flow rate c~ Haloqenated shall be shown hydrocarbon to be within testing shall be

+108 of design performed after flow when tested each complete or in accordance partial with ANSI N510- replacement of 1975. the charcoal adsorber bank or after any structural maintenance on the system housing.

247

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREllENTS 3, 7 CONTA INMENT S YSTFAS 4.7 CONTAINMENT SYSTEMS G. Containment Atmos here G. Containment Atmos here Dilution S stem CAD Dxlutron S stem CAD The Containment stem 0 erabilit Atmosphere Dilution S (CAD) System shall be a At least once operable with: ~

per month cycle a Two independent each solenoid

~

systems capable operated of supplying air/nitrogen nitrogen to the valve through at drywell and least one torus. complete cycle of full travel A minimum supply and verify that of 2500 gallons each manual of liquid valve in the nitrogen per flow path is system. open.

2. The Containment b. Verify that the Atmosphere Dilution CAD System (CAD) System shall be contains a operable whenever the minimum supply reactor mode switch of 2500 gals of is in the "RUN" liquid nitrogen posi tion. twice per week.

3. If one system is inoperable, the reactor may remain in operation for a period of 30 days provided all active components in the other system are operable.

4 If Speci 3.7. G. 1 ication and 3. 7. G. 2, o 3.7.G. 3 cannot be met, an ord er' shutdo.m shall be ini"iated and the reactor shall be in the Cold shutdown condition within 2>> hour s.

Primary containment pressure shall be limited to a 248 maximum of 30 psig during repressurization following a loss of coolant accident.

LIilITIiVG CO.'>DITXOVS POR OP=RATION SURVEILLANCE REQUIREMENTS 7 COYiTAIViNEÃi' YSTEMS 4.7 CONTAINllENT SYSTEMS H. Containment Atmosphe e Mon itorin CAM S stem H. Containment Atmosphere Hz and Oz Anal zer Monztorxn CAM System Hz and 02 Anal zer Whenever the reactor is not ' cold Once per month shutdown, two gas perform a channel analyzer systems (one calibration using oxygen and hydrogen standard gas samples sensing circuit per containing a nominal:

system) shall be operable for 'a ~ Three volume monitoring the percent drywell hydrogen, balance nitrogen

2. whenever the reactor and is not in cold shutdown, one gas b. Two vo 1 ume analyzer system (one percent oxygen oxygen and hydrogen balance nitrogen sensing circuit per system) shall be operable f or monitoring the torus.

3. If speci fication 3.7. H. 1 cannot be met, but one system remains operable, the reactor may be operated for a period of 30 days. If both systems are inoperable, the reactor should be placed in shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4 ~ If specification 3.7.H.2 cannot be met, but one sensing circuit remains operable, the reactor may be operated for a period of 30 days.

If both sensing circuits are inoperable, the reactor should be placed in shutdown cond'ion within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

249

ThBLE 3.7.A PRIMARY CONTAI~ ISOLATION VALVES Number of Pover Naximun hction on crated Valves Opera t ing Norrrral Initiating

~Grou Valve Identification Inbo rd Outboard Tine (sec.) Position ~sf nar

'.@in stearrrline isolation valves 3(T< 5 (FCV-1-14,26,37,&5I )1-15, 27, 38, & 52)

Hain stearrrline dra'n isolation 15 SC valves PCV-1-55 & 1-56 Reactor Mater sarrrple line isola- SC tion valves MIRS shutdovn cooling supply isolation valves FCV-74-48 & 47 40 SC MES - LPCI to reactor FCV-74-53, 67 30 SC Reactor vessel head spray isola-tion valves PCv-74-77, 78 30 SC lNRS flush and drain vent to supprerr sion chaster 20 SC PCV-74-102, 103, 119, & 120 Suppression Chaaber Drain PCV-74-57, 58 Dryv=ll equip+mt drain discharge isolstiorr valves FCV-77 15h, 15 Dry+all floor drain discharge irrolatlon valves PCV-77-2h & 2B

ThBLE 3.7.A (Continued)

Number o" Pover Naximum hction on Opera ting Normal Initiating Grou~ Valve Identification Inboard Oorboa-.d Time (sec.) Position ~Sf 1 Reactor vater cle-nup system supply isolation valves FCV-69"li 30 Reactor vater cleanup system return isolation valves FCV-69-12 60 BPCIS steamline isolation valves 20 FCV-73-2 & 3 RCICS steamline isolation valves 15 FCV-71-2 & 3 6 DryMell nitrogen purge 'nlet isola-tion valves (FCV-76-18) 10 SC Suppression chamber nitrogen purge inlet isolation valves (FCV-76-19) 10 SC DryMell Nain Exhaust isolation valves (FCV-64-29 and 30) 90 SC Suppression chamber main exhaust isolation valves (KV-64-32 and 33) 90 Dtyvell/Suppress ion Chamber purge inlet (var-64-17) 0~11 htmosphere purge inlet Q'CV-64-18)

TABLE 3,7.A (Continued)

Number of Power Naximum Action on 0 crated Valves Operating Normal Initiating

~Gr ou Valve Identification Inboar Outboard Time sec. Position ~SI na'I Suppression Chamber purge inlet

( FCV-64-19) 100 SC Drywell/Suppression Chamber nitro-gen purge inlet (FCV-76-17) 10 SC Drywell Exhaust Valve Bypass to Standby Gas Treatment System (FCV-64-31) 10 C SC Suppression Chamber Exhaust Valve Bypass to Standby Gas Treatment System (FCV-64-34) 10 SC RCIC Steamline Drain (FCV-71-6A, 6B) GC RCIC Condensate Pump Drain (FCV-71-7A, 7B) GC HPCI Hotwell pump discharge isola-tion valves (FCV-73-17A, 17B) SC HPCI steamline drain (FCV-75-57, 58) GC TIP euide Tubes (5) 1 per guide HA 'GC tube

TABLK 3.7.A (Continued)

Maximum hction on Number of PoiP"r Initiating crated Valves Opera t ing Normal Valve Identif ication inboard On. board Time (sec.) Position ~St nai

~Grou Standby liquid control system process NA check valves CV 63-526 & 525 Process Peedvat'er check valves CV-3-558, 572, 554, & 568 Control rod hydraulic return Process check valves CV 85 576 & 573 RHRS LPCI to reactor check Process valves CV-74-54 & 68

NOTES FOR TABLE 3.7.A Key: 0 Closed SC ~ Stays Closed Goes Closed Hotc: Isolation groupings arc as follovs:

Group The valvco in Croup 1 are actuated by any one of the folloving conditions:

1. Reactor Vessel Lov Mater Level (490")

2. Main Stcamlinc High Radiation

3. Main Stcamline High Flow 4, Main Steamline Space High Temperature

5. Main Steamline Lov Prcssure Group 2 ~ The valves in Group 2 are actuated by any of tha follovtng conditions:

1. Reactor Vessel Lov Mater Level (538")

2. High Dryvell Pressure Croup 3 ~ The valves in Group 3 are actuated by any of the folloving conditions:

1. Reactor Lov Mater Level (538")

2. Reactor Water Cleanup System High Temperature

3. Reactor Water Cleanup System High Drain Temperature Group 4 ~

The valves fn Group 4 are actuated by any of the folloving conditions:

1. HPCI Steamline Space High Temperature

2. HPCI Stcamlina High Flov

3. HPCI Staamline Lov Pressure Group 5 e The valves in Group 5 are actuated by any of the folloving condition:

1. RCIC Stcamline Space High Temperature

2. RCIC Steamlinc High Flov

3. RCIC Stcamline Low Pressure Group 6: The valves in Group 6 are actuated by any of the folloving conditions:

1, Reactor Vessel Lov Water Level (538")

2. High Dryvell Pressure

3. Reactor Building Ventilation High Radiation 254

Croup 7: The valves in Group 7 are automatically actuated by only the following condition:

1. Reactor vessel lov vater level (490")

Croup 8: The valves in Group 8 are automatically actuated by only the folloving condition:

2. High Dryvell pressure 255

TABLE 3.7.b TtSTaaLE rWrfIATIOMS MITS OOUSLX 0-RISC SZALS X-lA Equipaent Hatch X-15 M Hud Acceea Hatch CRb Reeoval Hatch X-35A T.I P. Drives X-355 X-35C X-35D X-35~

X-35P X-35C xmas Pover Operation Taut X-200k Supp, Chador AccooQ Hatch X-2005 ~ I ~ f se se X-213A Suppression Chamber Drain

+~

DM Flange-Top Bead Shear Lug Inepection Ccwar Pl Retch P2

~ t g3 04 H

~ i

~ t tt 07 1$

256

TABLE 3.7.C TESTABLE PENETRATIONS WITH TESTABLE BELLOWS X-7A Primary Steamline X-11 Steamline to HPCI Turbine X-7B Primary Steamline X-12 RHR ShutdoMn Supply Line X-7C Primary Steamline X-13A RHR Return Line X-7D Primary Steamline X-13B RHR Return Line X-8 Primary Steamline Drain X-14 Reactor Water Cleanup Line X-9A Feedwater Line X-16A Core Spray Line X-9B Fcedvater Line X-16B Core Spray Line X-lO Steamline to RCZC Turbine X-17 RHR Head Spray Line 257

TABLE 3.7.D PRIMARY CONThlhM~WT ISOLATION VALVES Valve Tost Teat Identification Medium Meehed 1-14 Main Stcam Applied between 1-14 <<nd 1 15

• i."'ir(')

1-15 Main Stcam Applied between 1-14 and 1>>15 ~

Inboard valve 1-14 to be vnter sealed at 25 paig.

1-26 Main Steam hir(1) Applied between 1-26 and 1>>27 1-27 Main Steam Applied between 1-26 and 1.27.

Inboard valve 1<<26 to bej vater scaled at 25 paig.

1-37 Main Stcam Applied between 1-37 and 1-38 1-38 Hain Stcam Applied between 1-37 and j-38.

Inboard valve 1-37 to be water sealed at 25 paig.

1-51 Hain Steam Applied between 1-51 and 1-52.

1<<52 Main Steam Applied between 1-51 and 1-52..

Inboard valve 1-51 to be vater acaled at 25 paig.

1-55 Main Stcam Drain Mater Applied between 1-55 and 1-56 1-56 Main Stcam Drain Water( ) Applied betveen 1-55 and 1-56 12-738 Auxiliary Boiler to RCIC Water Applied between 12-738 and 12-747 1 2-741 Auxiliary Boiler to RCIC Water (2) Applied between 12-741 and 12-74:

32-62 Drywell Compressor, Suction Applied between 32-62 and 32W3 32'63 Drywell Compressor Suction hi.(') Applied betveen 32&2 and 32-63 32-336 Drywell Compressor Return Applied between 32-2253 and 32-2i 32-2163 Drywell Compressor Return hi() Applied betveen 32-2253 and 32-33 43-13 Reactor Water Sample Linea W....(') Applied. betveen 43-13 and 43-599 43-14 Reactor Water Sample Linea Wa'tcr Applied betveen 63-14 and 43-599 43-28h RHR Suppreeaion Chamber W.t.,(2) Applied between 74-226 and Sample Linea 43-28A 258

TABLE 3,7.D (Continued)

Val ve Test Test Valves43-28B RHR Identification Suppression Lines Chamber Sample Medium Water(')

Method Applied between 74-226 and 43-283 4 43-29A RHR Suppression Chamber Sample Water (2) .Applied between 74-227 and 43-29A Lines43-29B RHR Suppression Chamber Sample Water (2) Applied between 74-227 and 43-29B Lines 64-17 Drywell and Suppression Chamber Ai (1) Applied between 64-17, 64-18, 64-19, air purge inlet and 76-24 64-18 Drywell air purge inlet Ai (") Applied between 64-17, 64-18, 64-19, and 76-24 64-19 Suppression Chamber air purge Air Applied between 64-17, 64-18, 64-19, inlet and 76-24 64-20 Suppression'hamber vacuum Air(') Applied between 64-20 and 64-(ck) relief 64-(ck) Suppression Chamber vacuum Ai.(') Applied between 64-20 and 64-(ck) relief 64-21. Suppression Air( )

Chamber vacuum Applied between 64-21 and 64-(ck) relief 64-(ck) Suppression Chamber vacuum Air( )

Applied between 64-21 and 64-(ck) relief 64-29 Drywell main exhaust Ai (1) Applied between 64-29, 64-30, 64-32 64-33 and 84-19 64-30 Drywel 1 main exhaust Air(') Applied between 64-29,64-301 64-32, 64-33 and 84-19 64-31 Drywel1 exhaust to Standby Applied between 64-31,64-141, 84-20 and 64-140 64-32 Suppression Chamber Main Air (1) Applied between 64-32, 64-33, 64-29, Exhaust 64>>30 and 84-19 64-33 Suppression Chamber Main Ai Applied between 64-32,64-331 64-291 Exhaust 64-30 and 84-19 64-34 Suppression Chamber to Standby Air Applied between 64-34,64-141 and Gas Treatment 64-139 259

TABLE 3.7.D (Coatiaued)

Valve Tost Test Idantitication Medic Mothod 69-1 RWCU Supply Wat.,(') Applied between 69-1,69-500 sad 10-505 69-2 RWCU Supply W.t.,(') Applied between 69-2 ~ 69 500 aad 10-505 71-2 RCIC Staaa Supply Applied between 71 2 sad 71 3 71-3 RCIC Stcaa Supply Applied between"'71-2 aad 71-3 71-39 RCIC Puap Discharge W (2) Applied between 71-37, 71-38 ~ end 71-39 73-2 HPCI Staaa Supply Air(') Applied between 73-2 aa4 73-3

)

73-3 HPCI Steam Supply Applied between 73-2 oad 73-3 HPCI Puap Discharge Water(2) Applied between 73 34, 73-35 'nd t

73-44 74-47 RHR Shutdovn Suction Mater (2) Applied between 74-47 aad 74%9 74-48 RHR Shutdovn Suction Water(') Applied betweea 74-45 end 74-49 74-53 RHR I,PCI Discharge W.t.r(') Applied botweca 74-53 sad 74>>55 74-57 RHR Suppression Chaaber Water( ) Applied between 74 57, 75 58, and Spray 74-59 74-58 RIIR Suppression Chaabar Water Applied betweea 74-S7 ~ 74-58, aad Spray 74-59 74-60 RHR Drywall Spray Applied between 74-60 aad 74~$ 1 74-61 RHR Dryvcll Spray Applied between 74-60 oad 74-61 74-67 RHR I.PCI Discharge W.ter(') Applied between 74&7 sad 74&9 74-71 RHR Suppression Chaaber Water Applied between 74-71, 74 72 ~ sad Spray 74-73 74-72 RHR Suppression Spray Chaaber Mater Applied between 74<<71, 74-72 74-73

'ad 74-74 RHR Dryvell Spray Mater (2) Applied between 74 74 sad 74 75 260

TABLE'.7,D (Continued)

~ lv8$

>4-75 .RHR Valve Identi fication Oryvell Spray Teat Madiua sac.~<+

Teat Method Applied batveen 74-74 and 74 75 e

74-77 RHR Head Spray W.ter(>> Applied betveen 74-77 <<nd 74-78 14-78 RHR Head Spray Water( ) Applied between 74-77 and 74<<78 74>>

i61/662 RHR Shutdown Suction Water(') Applied betveen 74-660 and 74-661/662 75-25 Core Spray Discharge Wat.r(') Applied between 75-25 and 75 27 75-53 Core Spray Discharge Wat..(') Applied batveen 75-53 and 75-55 I5-57 Core Spray to Auxiliary Water(') Applied betvaen 75-57 and 75-58 Boilers 75-58 Core Spray To Auxiliary Water (2) Applied batveen 75-57 and 75-58 Boilers 17 Dryvoll/Suppression Chamber Nitrogen (1) Applied betveen 76-17, 76-18, 76 19 Nitrogen Purge Inlet 7G-18 Dryvell Nitrogen Purge Inlet Nitrogen (1) Applied between 76-17, 76-18, 76-19 7t -19 Suppression Chsmber Purge Nitrogen (1) Applied batveen 76 17, 76-18, 76-19 Inlet 76-24 Dr'yvell/Suppression Chamber Applied betveen 64-17 ~ 64-18, 64-19, Nitrogan Purge Inlet and 76-24 77-2A Dryvsll Ploor Drain Sump gator(2> Applied between 77-2A and 77-2B 77-2B Dryvell Floor Drain Sump Var,sr<2> Applied betveen 77-2h and 77-2b 77-15A Dryvoll Equipnant Drain Sump Mat,or<2> Applied betveen 77-15A and 77<<15B 77-15D Dryvell Equipmont Drain Sump abator(2> Applied betveen 77-15A and 77-15B

$ 0-254A Radiation Monitor Suction Applied betveen 90-254A, 90-254b, and and 90-255 90-2$ 4b Radiation Monitor Suction Applied between 90-254h, 90-2545, and 90-255

-255 Radiation Monitor Suction hir Applied between 90-254A, 90-254bg and 90-255 261

ThftLa 3.7.D (Continued)

Valve Tea't Tost ilsd<ua <<aiba&

Valves Identification Radiation Honitor Disdhar8a Applied betveea 90-257A <<<<d %0-2$ 7$

90-257A Air+> Applied betvsea 90 2$ 7A <<)<Ll 90<<257%

90-25'7b Radiation Honitor Diocharffe 84-8A Containment Atmospheric Dilution hir Applied between 84-8A and 84~0 84-SB Containment Atmospheric Dilution Air Applied betvean 84-85 and ~L 84-8C Containment Atmospheric Dilution Air Applied between 84<<8C and 84~3 84-SD Containment Atmospheric Dilution Air Applied between 848D and 84&(Yk 84 19 Containment Atmospheric Dilution Air Applied between 64-32 ~ 64-33, 64>>29, 64-3A, and 84<<19

(>> Air/nitrogento test to be 'displacement flow.

(2) Water test be in)ection loss, or downstream collection.

Valve Test Test Valves Mentification <tedium iiethod 7G-?15 (.'ontainment Atmospheric tlnnitor .fair<>> Applied between 76-215 and 76-21S76-217 Cor t:alnment At:mospheric Ifonitor Air hp.)lied between 76<<217 and 76-218 6-22!I Containment Atmospheric tlonitor hir Applied between 7G-220 and 76-223 Containment Atmospheric tfonitor hir Applied bet~teen 76-222 and 76<<223 76~)2> Containment Atmospi<eric iionitor tiJX h))<)lied between 7G-225 a<<3 76-227 76 22G Containment Atmospheric Honitor Air Applied between 76-226 and 76-227 7G-229 Containment Atmospheric >fonitor Air Applied between 76-229 and 76-231 76-230 Containment Atmospheric lfonitor Air Applied between 76-230 and 76-231 76-237 .,Containment Atmospheric Ifonitor Air Applied between 76-237 and 76-240 76-239 Containment Atmospheric Ifonitor Air Applied between 76-239 and 76-240 76 242 Containment Atmospheric Monitor Air Applied between 76-242 and 76-244 76&43 Containment'tmospheric tfonitor Air Applied between 76-243 and 76-244 76-248 Containment Atmosphnric Honitor Air Applied between 76-248 and 76-253 76-250 Containment Atmospheric kionitor Air Applied between 76-250 and 76-251 76-253 Containment Atmospheric Nonitor Air hpplicd between 76-253 and 76-255 76-254 Containment Atmospheric Ifonitor Air Applied between 76-254 and 76-255 84-20 tfain Exhaust to Standby Gas Treatme nt AS.r(>> Applied between 84-20,64-141, 64-140, and 64-31 84-600 Hain Exhaust to Standby Gas Treatment Nitrogen(i) hpplied between 84-4h and 84-600 84-Go 1 tlftin Exhaust tn Standby Gas Treatment tilt:rogcn Applied between S4-88 and 84-601 84-602 tlain Exhaust to Standby ('s Treatment off.trngen hpplfed between 84&(l and 84-603 84-603 Hafn I'.xhaust to Standby Cas Treat<<)ent ttltrq<(en hpplied between 84&0 and 84-602

()4-l4 I l)rywoil t'ross<<riÃntion, Comp. Bypass hir hppll.cd between 64-14l,64-140, 64-30, and 84-20 64-14<0 Drywall Pressurization, Comp. Disc. Air(') Applied betveen 64-141,64-140, 64-31, and 84-20 64-139 Drywcll Pressurization, Comp. Suction Applied between 64-139.,64-141, and 64-34

1) hir/nitrogen test to be displacement flov (2) Water test to be in)ection loss or downstream collection.

262

TABLE 3.7.E SUPPRESSION CHAMBER INFLUENT LINES STOP-CHECK GLOBE ISOLATION VALVES Valve Test Test Valves Identification Med1ue Method 71-14 RCIC Turbine Exhaust Mater Apply betveen 71-14 and 71<<580 71-32 RCIC Vacuum pump Discharge Mater Apply bctveen 71-32 and 71-592 73-23 HPCI Turbine Exhaust Water Apply betveen 73-23 and 73<<603 73-24 HPCI Turbine Exhaust Drain Water hpply betveen 73-24 and 73-609 TABLE 3.7,F CHECK VALVES ON SUPPRESSION CllhMBER INFLUENT LINES Valve Test Test Ve]ve Identification Med1ee Meehed 71-580 RCIC Turbine Exhaust Water Apply betveen 71-14 and 71-580 71-592 RCJC Vacuum Pump Discharge Water Apply betvcen 71-32 and 71-592 73-603 HPCI Turbine Exhauot Water Apply betvcen 73-23 and 73-603 73-609 HPCI Exhaust Drain Water Apply betveen 73-24 and 73-609 263

TABLE 3.7.C CHECK VALVES ON DRYMELL INFLUENT LINES Valve Test Test Identification Medtum Hethod 3-554 Fccdwatcr Mater Applied betveen 3"67, and 3-554, Valves 73-45, 73-44, 73-35, and 73-34 are used to form a water seal on 73-45.

3-558 Fcedwater Water Applied bctveen 3-67 and 3-558 3-568 Fecdwater Matex Applied between 3-66, 3-568, and 69-580. Valves 71-40, 71-39, 71-38, and 71-37 are used to fora a vatcr seal on 71-40.

3-572 Fccdwater Mater Applied between 3-66 and, 3-572 63-525 Standby Liquid Control Water Applied betveen 63-525 and 63-527 Discharge 63-526 Standby Liquid Control Water Applied between 63-526 and 63-527 Discharge 69-579 RMCU Return Mater Applied between 3-66, 3-568,69-579 and 71-40. Valves 71-40, 71-39, 71-38, and 71-37 are uied to form a water soal on 71-40.

71-40 RCIC Pump Discharge Water Applied between 3-66, 3-568 ~ 69 579 and 71-40 73-45 HPCI Pump Discharge Water betveen 3-67, 3-559 and 73-45

'pplied 74-54 RHR 1.PCI Discharge Water Applied betveen 74-54 and 74-55 74-68 R)lR LPCI Discharge Mater Applied between 74-68 and 74-69 75-26 Core Spray Discharge Mater Applied betveen 75-26 and 75-27 75-54 Core Spray Discharge Water Applied between 75-54 and 75-55

8) )73 CRll llydrnulic Return Water Applied betveen 85-573 and '85-577

)1')- ) 74 CRD llydraulic Return Water Applied betveen 85-576 and 85-577 264

TABLE 3.7.H TESTABLE ELECTRICAL PENETRATIONS X<<100A Indication and Control X-100B Neutron Monitoring X-100C X-100D X-100E X-100P X-100G CRD, Rod Position Indic.

X-101A Recirc.. Pump Power X-101B X-101C X-101D X-102 Thermocouples X-103 CRD Rod Position Indic.

X-104A Indication and Control X-104B CRD Position Indic.

X-104C Neutron Monitor X-104D Thermo couples X-104E Indication and Control X-104P X-105A Spar~ (non-testable)

X-1058 Recirc. Pump Power X-105C X-105D Spare X-106 A CRD Rod Position Indic.

X"106B Neutron Monitoring X-107A

TABLE 3.7.H (Continued)

X-107B Spare (testable)

X-108A Power X-108B ~

CRD Rod Position Indic.

X-109 X-110A Power X-110B CRD Rod Position Indic.

X-230 Containment Air Monitoring System 266

PAGE DELETED 267

3ASES 3.7. A 8 4.7.A Primar Containment The integrity of the primary cortainment and operation of the core standby cooling -system in combination, limit the off-site doses to values less than those suggested in 10 CFR 100 in the event of a break in the primary system piping. Thus, containment integrity is specified whenever the potential for violation of the primary reactor system integrity exists. Concern about such a violation exists when-ever the reactor is critical and above atmospheric pressure. An exception is made to this requ'.'rement during initial core loading and while the low power test program is being conducted and ready access to the reactor vessel is required. There wi 11 be no pressure on the 'system at this time, thus greatly reducing the chances of a pipe break . The reactor may be taken critical during thi s period; however, restrictive operating procedures will be in effect again to minimize the probability of an accident occurring. Procedures and the Rod Worth Minimizer would limit control worth such that a rod drop would not result in any fuel damage. In addition, in the unlikely event that an excursion did occur, the reactor building and standby gas trea'tment system, which shall be operational during this time, offer a sufficient barrier to keep offsite doses well below 10 CFR 100 limits.

The pressure suppression pool water provides the heat sink for the reactor primary system energy release following a postulated rupture of the system. The pressure suppression chamber water volume must absorb the associated decay and structural sensible heat released during primary system blowdown from 1,035 psig. Since all of the gases in the drywell are purged into the pressure suppression chamber air space during a loss of coolant accident, the pressure resulting from isothermal compression plus the vapor pressure of the liquid must not exceed 62 psig. the suppression chamber maximum pressure. The design volume of the suppression chamber (water and air) was obtained by considering that the total volume of reactor coolant to be condensed is discharged to the suppression chamber and that the drywell volume is purged to the suppression chamber.

Using the minimum or maximum water volumes given in the specification, containment pressure during the design basis accident is approximately 49 psig which is below the maximum of 62 psig. Maximum water volume of 135,000 ft3 results in a downcomer submergence of 5'2-3/32" and the minimum volume of 123,000 ft3 results in submergence approx irately 12 inches less. The majority of the Bodega tests were run with a submerged length of 4 feet and with complete condensation, Thus, with respect to downcomer submergence, this specification is adequate. The maximum temperature at the end of blowdown tested during the Humbolt 3ay and Bodega Bay tests was 170'F and this is conservatively taken to be the limit for complete condensation of the reactor coolant, although condensation would occur for temperatures above 170'F.

268

BASES Should it be necessary to drain 'the suppression chamber, this should only be done when there is no requirement for core standby cooling systems operatibility Under full power operation conditions, blowdown from an initial suppression chamber water temperature of 95'F results in a peak long term water temperature of 170'F which is sufficient for complete condensation. At this temperature and atmospheric pressure, the available NPSH exceeds that required by both the RHR and core spray pumps, thus there is not dependency on containment overpressure.

Experimental data indicate that excessive steam condensing loads can be avoided if the peak temperature of the suppression pool is maintained below 160'F during any period of relief valve operation with sonic conditions at the discharge exit. Specifications have been placed on the envelope of reactor operating conditions so that the reactor can be depressuirzed in a timely manner to avoid the regime of potentially high suppression chamber loadings.

Limiting suppression pool temperature to 105 F during RCIC, HPCI, or relief valve operation when decay heat and stored energy is removed from the primary system by discharging reactor steam directly to the suppression chamber assures adequate margin for controlled blowdown anytime during RCIC operation and assures margin for complete condensation of steam from the design basis loss-of-coolant accident.

In addition to the limits on temperature of the suppression chamber pool water, operating procedures define the action to be taken in the event a relief valve inadvertently opens or sticks open. This action would include:

(1) use of all available means to close the valve, (2) initiate suppression pool water cooling heat exchangers (3) initiate reactor shutdown, and (4) if other relief valves are used to depressurize the reactor, their discharge shall be separated from that of the stuck-open relief valve to assure mixing and uniformity of energy insertion to the pool.

If a loss-of-coolant accident were to occur when the reactor water temperature is below approximately 330'F, the containment pressure will not exceed the 62 psi g code permissible pressures even if no condensation the were to occur. The maximum allowable pool temperature, whenever reactor is above 212'F, shall be governed by this soecification. Thus, specifying water volume-temperature requirements applicable for reactor-water temperature above 212'F provides additional margin above that available at 330'F.

~Inertin The relatively small containment volume innerent in the GE-BMR pressure suppression containment and the large amount of zirconium in the co "e are such that the occurrence of a very limited (a oercent or so) reaction of the zirconium and steam during a loss-of-coolant accident could lead to the liberation of hydrogen combined with an air atmosphere to result in a flammable concentration in the containment. !f a sufficient amount of hydrogen is generated and oxygen is available in stoichiometric quanti zies the subsequent ignition of the hydrogen in rapid recombination rate could lead to failure oi tne containment to maintain a low leakage '.ntegrity. The 4~ oxygen concentration minimizes the possibility of hydrogen combust. on following a loss-of-coolant accident.

269

BASES The occurrence of primary system leakage following a major refueling outage or other scheduled shutdown is much more probable than the occurrence of the loss-of=coolant accident upon which the specified oxygen concentration limit is based. Permitting access to the drywell for leak inspections during a startup is judged prudent in terms of the added plant safety offered without significantly reducing the margin of safety. Thus, to preclude the possibility of starting the reactor and operating for extended periods of time with significant leaks in the primary system, leak inspections are scheduled during startup periods, when the primary system is at or near rated operating temperature and pressure. The 24-hour period to provide inerting is judged to be sufficient to perform the leak inspection and establish the required oxygen concentration.

To ensure that the oxygen concentration does not exceed 4", following an accident, liquid nitrogen is maintained on-site for containmen. atmosphere dilution. About 2260 gallons would be sufficient as a 7-day supply, and replenishment facilities can deliver liquid nitrogen to the site within one day; therefore, a requirement of 2500 gallons is conservative. Following a loss of coolant accident the Containment Air tlonitoring (CAM) System continuously monitors the oxygen and hydrogen concentration of the containment volume. Two independent systems ( a system consists of one oxygen and one hydrogen sensing circuit) are installed in the drywell and one system is installed in the torus. Each sensor and associated circuit is periodically checked by a calibration gas to verify operation.

Failure of a drywell system does not reduce the ability to monitor system atmosphere as a second independent and redundant system wi 11 still be operable . Failure of the torus system would require a reactor shutdown as no means would be available under accident condit~ons to monitor torus atmosphere. Until a redundant system becomes available in the torus, the monitoring requirements of either a hydrogen or cxygen sensing circuit will be utilized . While this reduc s the offe. ed protection slightly, one sensor can be used tn prevent a combustible atmosphere . In addi tition the torus atmosphere will be mixed with tha drywell atmosphere through the drywell to torus check valves and any increase in the torus hydrooen or oxygen concentration would proportionally change the drywell atmosphere.

270

Vacuum Relief The purpose of the vacuum relief valves is to equalize tl>e pressure between the drywell and suppression chamber and reactor building so that the structural integrity of the containment is maintained. The vacuum relief system from the pressure suppression chamber to reactor building consists of two 100$ vacuum relief breakers (2 parallel sets of 2 valves in series). Operation of either, system will maintain the pressure differential less than 2 psig; the external design pressure. One reactor building vacuum breaker may be out of service for repairs for a period. of seven days. If repairs cannot be completed within seven days, the reactor coolant system is brought to a condition where vacuum relief is no longer required.

Vhen a drywell-suppression chamber vacuum breaker valve is exercised through an opening-closing cycle the position indicating lights in the control room are designed to function as specified below:

Initial and Final Check - On (Fully closed)

Condition Green On Red - Off Opening Cycle Check Off (Cracked open)

Green Off (> 80 Open)

Red On (> 3 Open)

Closing Cycle Check On (Fully Closed)

Green On (< 30~ Open)

Red Off < 3 Open)

The valve position indicating lights consist of one check light on the check light panel which confirms full closure, one green light next to the hand switch which confirms 80 0 of full opening and one red light next to the hand switch which confirms "near closure" (within 3" of full closure). Hach light is on a separate switch. If the check light circuit is operable when the valve is exercised by its air operator there exists a confirmation that the valve will fully close. If the red light circuit is operable, there exists a confirmation that the valve will at least "nearly close" (within 3 of full closure). The green 1ight circuit confirms the valve will fully open. If none of the lights change indication during the cycle, the air operator must be inoperable or the valve disc is stuck.

For this case, a check light on and red light off confirms the disc is in a nearly closed. position even if one of the indications is in error.

Although the valve may be inoperable for full closure, it does not consti-tute a safety threat.

If the red, light circuit alone is inoperable, the valve shall still be considered fully operable. If the green and red or the green light circuit along is inoperable the valve shall be sonsidered. inoperable for 271

BhSF.S opening. If the check and green or check light circuit alone is inoperable, the valve shall be considered inoperable for full closure. If the red and check light circuits are inoperable the valve shall be considered inopera-ble and open greater than 3'. For a light circuit to be considered operable the light must go on and off in proper sequence during the opening-closing cycle. If none of the lights change indication during the cycle, the valve shall be considered inoperable and open unless the check light stays on and the red light stays off in which case the valve shall be considered inopera-ble for opening.

The twelve drywell vacuum breaker valves which connect the suppression chamber and drywcll are sized on the basis of the Bodega pressure suppres-sion system tests. Ten operable to open vacuum breaker valves (18-inch) selected on this test basis and confirmed by the green lights are adequate to limit the pressure differential between the suppression chamber and dry-well during post-accident drywall cooling operations to a value which is within suppression system design values.

The containment design has been examined to determine that a leakage equi-valent to one drywell vacuum breaker opened to no more'han a nominal 3's confirmed by the red light is acceptable.

On this basis an indefinite allowable repair time for an inoperable red light circuit on any valve or an inoperable check and green or check light circuit alone or a malfunction of the operator or disc (if nearly closed) on one valve, or an inoperable green and red or green light circuit alone on two valves is )ustified.

During each operating cycle, a leak rate test shall be performed to verify that significant leakage flow paths do not exist between the dryweL and suppress'ion chamber. The drywell pressure will be increased by at least 1 psi with respect to the suppression chamber pressure and held constant.

The 2 psig set point will not be exceeded. The subsequent suppression chamber prcssure transient'(if any) will be monitored with a sensitive pres-sure gauge. If the drywell pressure cannot be increased by 1 psi over the suppression chcmber pressure it would be because a significant leakage path exists; in this event the leakage source will be identified and eliminated before po~er operation is resumed.

With a differential pressure of greater than 1 psig, the rate of change of the suppression chamber pressure must not exceed .25 inches of water per minute as measured over a 10 minute period, which corresponds to about 0.14 ib/sec of containmcnt air. In the event the rate of change exceeds this value then the source of leakage will be identified and eliminated before power operation is resumed.

The water in the suppression chamber is used for cooling in the event of an accident; i.e., it is not used for normal oparation; therefore, a daily check of thc temperature and volume is adequate to assure that adequate heat removal capability is present.

272

BASES The interior of the drywell is painted with an inorganic zinc primer top-coated with an epoxy coating. This coating provides protection against rusting as well as providing a surface which is decontaminable. The insPection of the Paint during each ma)or zafueling outage, aPProximately once per year, assures the paint is intact. Experience with this type of 0

paint at fossil fueled generating stations indicates that the inspection interval is adequate.

The interior surfaces of unit g, suppression chambers are coated with an organic protective coating of the thermosetting resin type.

The insnection of the coating during each refueling outage, approximately once per year, assures the coating is intact. Dropping the water level to one foot below the normal operating water level enables an inspection of that portion of the suppression chamber where any coating problem. would first begin to show.

If during periodic surviellance, significant rust spots are detected above the

~ater line, these will be recoated.

Coatings used on drywell and supnression chamber interior surfaces have been tested under simulated DBA conditions and were found to withstand these;conditions satisfactorily.

The primary containment preoperational test pressures are based upon the ca'culated primary containment pressure response in the event of a loss-of-coo).ant accident. The peak drywell pressure wou'd be about 49 psig which would rapidly reduce to less than 30 psig within 20 seconds following the pipe break. Following the pipe break, the suppression chamber pressure rises to 27 psig within 25 seconds, equalizes with drywell pressure, and decays with the drywe11 pressure decay.

The design pressure of the drywell and suppression chamber is 56 psig. The design leak rate i 0.5 percent per day at the pressure of 56 psig. As pointed out above, the pressure response of the drywell and suppression chamber following an accident would be the same after about 25 seconds.

Based on the calculated containment pressure response discussed above, the primary containnn'nl prcoperational test pre"sures were cho en. Also based on the primary containment pressure response and the fact that the drywcll and suppression chamber function as a unit, the primary containment will be tested as a unit rather than the individual components separately.

The calculated radiological doses given in Section 14.9 of the FSAR were based on an assumed leakage rate of 0.635 percent at the maximum calculated pressure of 49.6 psig. The doses calculated by the HRC using this 'bases are 0.14 rem, whole body passing cloud gamma dose, and 15.0 rem, thyroid dose, which are respectively only 5 x 10 3 and 10 1 times the 10 CFR 100 reference doses. Increasing the assumed leakag rate at 49.6 psig to 2.0 percent as indicated in the specifications would increase these doses approximately a factor of 3, still leaving a margin between the calculated dose and the 10 CFR 100 reference values.

Establishing the test limit of 2.0g/day provides an adequate margin of safety to assure the health and safety of the general public. It is fur-ther considered that the allowable leak rate should not deviate significantly 273

BhS".>>

from the containment design value to take advnn-nge of the design leak-tightnans capability of the structure over its serv'"e lifetime. Addi-tional margin to maintain the containment in the "as built" condition is achieved by cstnbliahing the allowable operational leak rate. The allow-able operational leak rate is derived by multiplying the maximum allow-able leak rate {49 psig Method) or the allowable test leak rate (25 psig Method) by 0.75 thereby providing a 25X margin to allow for leakage deterioration which may occur during the period between leak rate tests.

The primary containment leak rate test frequency is based on maintaining adcq<<ntc assurance that; the lank rata remains rvithin tha specifi.cation.

Thc leek rate test frequcrrcy is based on the NRC guid'e for developing larrk rate tenting and nurveillnnce of reactor co'ntainment vessels. Allow-ing thc test intervals to bc extended.up to S morrths permi.ts some flexi-bility needed to have the tests coincide with scheduled or unscheduled shutdown periods.

The penetration and air purge piping leakage t st frequency, along with the containmaht leak rate tests, is adequate to allow detection of leak-age trends. Whenever a bolted double-ganketed penetration is broken and remade, thc space bctwcen the gaskets is pressurized to determine that the seals nre performing properly. It is expected that'the ma)ority of the leakage from valves, panetrationn and seals would be into the reactor building. However, 5.t is possible that leakage into other parts of the facility could occur. Such leakage paths, that may affect significantly the consequences of accidents are to be minimized.

The primary contain>>r;ant is normally slightly press<<rizad during period of reactor operation. Nitrogen used for inarting could leak out of the con-tainment but nir could not leak in to increase oxygen concentration. Once thc contninmcnt is filled with ni.trocan to tha cq<<ized concentration, determining the oxygen concentration twice n weak serves as nn added asrrurnncc that the oxygen concc:: ration will not cxcacd 4X.

3,7. 8/3.7.C St andb r Cns Treatment. System and Seconder Containment The secondary containment is designed to minimize my ground level release of radioactive materials which might result from a serious accident. The reactor building provides secondary containment during reactor operation, when the drywall is scaled and in service; the reactor building provides primary, contninment when thc reactor is shutdown and the drywell is open, as during refueling. Because the secondary containment is an integral part of the complete containment system, secondary containment is required at all times that primary containment is required as well as during refueling.

274

HAS>ES The standoy gas treatment system is designed to filter and exhaust the reactor building atmosphere to the stack during secondary containment isolation con-ditions. All three standby gas treatment system fans are designed to automatically start upon containment isolation and to maintain the reactor buildi>>g pressure to the design negative pressure so that all lea1<age should l>c in-leakage.

High efficiency particulate air (HEPA) filters are installed before and after the charcoa'> absorbers to minimize potential release of particulates to the environment and to prevent clogging of the iodine absorbers. Thc ch rco- ebsorbers are installed to reduce the potential r<.lease of radio-iodine :o the environment. T1.e in-place test results should indicate a svstem Leak t'.ghtness of less than 1 percent bypass 3.eakage for the cnarcoal absorbers and a H.'.:-A efficiency of at le<<st 99 percent removal of DOP particulates.

The Labora orv carbon sa...pie test results should indicate a radioactive methyl iodide:emovel effice>>cy of at 3.east 95 percent for expected accident condi-t'ons. Xf the efficiencies of the HEPA filters and charcoaL absorbers are as specified, the resulting doses will be Less than the 10 CFB 100 gui<lelines fo'h;><:ciQent analyzed. Opernti<>n of thc fans signi Ci<.antLy different from thc design flow wi33 ch<<n;;e the removal effic:1ency of the HEPA fi3t<.rn <<nQ charcoal absorbers.

Only t' o. the three standbv gas treatment systems are needed to clean up the reacto: b 'ilding atmosphere upon containment isolation. Xf one syst m i" found to be inoperablc, there is no immediate threat to the containm n system performance and reactor ope:ation or refueling operation may continue while repair" a e being made. If more than one trai>> i" inopera3>lc, thc plant. is brou h to a condition where the "tandby gas tr<.a men'yst: em is r>ot. > quired.

4.7.3/4.7.C Sta>>Qbv Gas Treatment System and Secondary Containment Initiating reactor builQing isolation and operation of the standby gas treatment ystcm to maint'n at lea, t a 1/4 inch of water vacuum within thc s<co>>1ary co>>(.;>ment pr<>vide an adequate tc t vC the oper <tion <>C the reacto! buildin> isoLation valves, leak tightness oC the reactor buil<1i>>g and performance of the standby gas treatment, system. I'unctionally t<'stin<", the initiating se>>aors and <:ssociated trip 3ogic demonstrates the cnp. bi3ity Cor <.utomat ic actus io>>. Performin1> thcsc t.csl," prior to ref Ucling will dcmonstrat c Geco>>dar y cont<>ment, cap>>bi I.) tv prior to t}1o time the primary containment is opened for refueling. Periodic testing gives su.ficient confidence of reactor building integrity and standby gas treatment system performance capability.

The test frequencies are adequate to detect equipment <Leterioration prior to significant defects, but the tests are not frequent enough to load the filters, thus reducing their reserve capacity too quickly. That the test-ing frecue>>cy is ad quate to detect deterioration was demonstrated by the tests which showed no loss of filter efficiency after 2 years of" operation 275

~ i

BASES it< the ru ged ol<lipbnsrd environment on t..e r<S Savannah~OR iL 372~6. Pres-sure <Imp across the cn<~bined IIFPA f il ters and charcoal adsorbers of less tl<an 6 inches of water at the system design flow rate will indicate that the filters and a<Isomers are not clogged by excessive amnunts of foreign matter.

Heater capability, pressure drop and air distribution ..hould be determined at least once per operating cycle to show system perfnr<nance capa'bility.

The frequency of tests and sampIe analysis are necessary to show that the HFPA filters and charcoal adsorbers can perform as evaluated. Tests of the charcoal adsorbers witn halogenated hydrocar'non refriper'ant shall be per-formed in accordance with USAFC Peport DP-1082. Iodine removal efficiency tests shall follow RDT Standard II-16-1T. The charcoal adsorber efficiency cesr. procedures should olios for the reuousl of,a~cod oSher t<gy emptying of one bed from the tray, mixing the adsorbent thoroughly and obtaining at least two samples. Each sample should be at least two inches 'in diameter and a length equal to the thickness of the 'oed. If test results are unacceptable, all adsor'bent in the system shall be replaced with an adsorbent qualified according to Table 1 of Regulatory Guide 1,52. The replacement tray for the adsorber tray removed for the test should meet the same adsorbent quality. Tests of the'FPA filters with DOP aerosol shall be performed in accordance to A:ISI N5>O-3.975. Any HFPA filters found deEective shall be replaced with filters qualified pursuant to Regulatory Position C.3.d of Regulatory Guide 1.52.

All elements of the heater should be demonstrated to be Eunctional and operable during the test" oll heater capacity.

a minimum of lO hrs each month will prevent moisture buildup in the filters and. adsorberand system.

fan in operation, DOP aerosol shall be sprayed externally Vith doors closed nln'ng tile fu11 linear periphery of, each respective door to check the gasket seal. Any detection of. DOP in the fan exhaust shall be considered an unacceptable test result a>>d the gaskets repairs and test repeated .

If significant painting, fire or chemical release occurs such that the chemicalsHFPA filter or charcoal adsorber could become contaminated from the f<mles, or foreign material, the same tests and sample analysis shall be pe formed as required for operational use. The determination of significant shall be made by the operator on duty at the time of the incident. Knowledgeable staff members should be consulted prior to making this determination.

Demonstration of the automatic initiation capability and operability of filter cooling is necessary to assure system performance capability. If one standby gas treatment system is inoperable, the other systerrs must be tested daily. This substantiates the availability of thy operable syste<fs and thus reactor operation and reEueling operation can continue for a limited period of t ime.

3. 7, D/4.7. D Primar Containment Isol ation Valves Double isolation valves arc provided on lines oenctrating the primary con>>

tainment and open to the free space of the containment. Closure oi one of l.he valvco in each linc would bc sufficient to l<<aintain the integrity of the preeoure suppression system. Automatic initiation is required to mini-mize the potential leakage paths from tha containment in th event o a loao of coolant ace:ident.

276

OhSES

~Grou 1 - process lines are isolated by reactor vessel low water level (490") in order to allow Eor removal oE decay heat subsequent to a scram, yct isolate in time for proper operation of the core standby coc ling systems. The valves in group l are also 'closed when process inotrumcntntion detects excessive main steam line flow, high radiation, low pressured or main steam space high temperature.

~garou 1 isolation valves a're closed by reactor vessol lov vater lev'el (538") or high drywell prcssure. The group 2 isolation signal also "iso-latco" the reactor building and starts the standby gas treatment system.

It is not desirnblc to actuate the group 2 isolation signal by a tran-sient or spurious oignal.

~Grou 3 process lines are normally in use and it is therefore not desirable to cause spurious isolation duc to high drywell pressure resulting from non-safety related causes. To protect the reactor from a possible pipe brenk in the eystcia, isolation is provided by high temperature in the cleanup system area or high flow through the inlet to che cleanup system.

hlso, since thc vessel could potentially be drained through the cleanup system, a low level ioolati'on is provided.

Grou~4 dbnil 5 process lines nre designed to remain operable and mitigate thc conocqucnceo of nn accident which results in the isolation of other process lines. Thc signals which initiate isolation of Group 4 and 5 proccos lines nrc thercforc indicative of a condition which would render them inopcrablc.

~Crau 6 - lines are connected to the prinery contairuaent but not directly to the reactor vessel. These valves are isolated on reactor low water level (538"), high drywell pressure, or reactor building ventilation high rndincion which would indicate a possible accident and necessitate primary containment isolation.

~drou 7 - process lines are closed only on reactor lov eater level (490").

Theoe close on the oamc signal that initiates HPCIS and RCICS to ensure that the valves are not open when HPCIS or RCICS accion is required.

Grou~8 line (traveling in-corc probe) is isolated on high drywall pres-sure. This is to assure that this line does noc provide a leakage path when containment pressure indicates a possible accident condition.

The maximum closure cime for the automatic isolation valves of the primary containmcnt and reactor veosel isolation control system have been selected in consideration of the design intent to prevent core uncovering following pipe breaks outside the primary contninment and the need to contain released fission products following pipe breaks inside the primary containment.

In satisfying this design intent an additional margin has been included in specifying maximum closure times. This margin permits identification of degraded valve performance, prior to exceeding the design closure times.

277

BAS ES In order to assure that the doses that may result from a steam line brcak do not exceed the 10 CFR 100 guidelines, it is necessary that no fuel rod perforation resulting from the accident occur prior to closure of the ma/n steam line isolation valves. Analyses indicate that fuel rod cladding pcrforationa would be avoided for main steam valve closure times, including instrument delay, as long as 10.5 seconds.

These valves are highly reliable, have low service requirement and most are normally closed. The initiating sensors and associated trip logic ere also chcckcd to demonstrate thc capability for automatic isolation.

The teat interval of once per operating cyclc7for automatic initiation results in a failure probability of 1.1 x 10 that a line will not iso-late. Nore frequent testing for valve operability results in a greater assurance that the valve will be operable when neede'd.

The main stcam linc isolation valves are functionally tested on a more frequent interval to establish a high degree of reliability.

Thc primary containment is penetrated by several small diametez instru-ment lines connected to the reactor coolant system. Fach instrument line contains a 0.25 inch restricting orifice inside the primary containmcnt and an excess flow check valve outside the px'imary containmcnt.

3.7.E/4.7.E Contzol Room Emer"enc Ventilation The control room emergency ventilation system is designed to filter the con-trol room atmosphere for intake air and/or for recirculation during control room isolation conditions. The control room emergency ventilation system is designed to automatically start upon control room isolation and to maintain the control room pressure to the design positive pressure sn that all leakage should be out leakage.

iligh ef f Lcfcncy particulate absolute (HPPA) I iltezs nre installed before the char-conl adsorbers to prevent clogging of the iodine pdsorbers. The charcoal ad-sorbers are installed to reduce the potential intake of radioiodine to the can-trol room. The in-place test results should indicate a system leak tightness oE less than 1 percent bypass leakage for the charcoal adsorbers and a HFPA

-efficiency oE at least 99 percent removal of DOP particulates. The laboratory carbon sample test x'esults should indicate a radioactive methyl iodide zemoval efficiency of at least 90 percent Eor expected accident conditions. IE the efficiencies of the HFPA filters and chaxcoal adsozbers are as specified, the x'esulting doses will be less than the allowable levels stated in Criterion 19 of the General Design Criteria for Nuclear Power Plants, Appendix A to 10 CFR Part 50. Operation of the fans signiEicantly different from the design flow will change the removal eEficiency of the HFPA filters and charcoal ad-sorbers.

If the system is found to be inoperable, there. is not immediate threat to the control room and reactor operation or refueling operation may continue for a limited period of time while repairs are being made. If the system cannot be repaired within seven days, the reactor is shutdown and brought to cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or refueling operations are terminated. II 278

BASF.S Pressure drop across tne combined HHPA filters and charcoal adsoxbers of less than 6 inches of water at the system design flow rate will indicate that the filters

, and adsorbers axe not clogged by excessive amounts of foreign matter. Pressure drop should be determined at least once per operating cycle to show system performance capability.

The frequency of tests and sample analysis are necessary to show that the HRPA filters and charcoal adsorbers can perform as evaluated. Tests of the charcoal adsorbers with halogenated hydrocarbon shall be performed in accordance with USAZC Report -1082. Iodine removal efficiency tests shall follow RDT Standaxd M-16-1T. The charcoal adsorber efficiency test procedures should allow for the removal of one adsorber tray, emptying of one bed from the tray, mixing the ad-sorbent thoroughly and obtaining at least two samples. Fach sample should be at least two inches in diameter and a length equal to the thickness of the bed.

If test results are unacceptable, all adsorbent in the system shall be replaced with an adsorbent qualified according to Table 1 of Regulatory Guide 1.52. The replacement tray for the adsorber tray renoved for the test should meet the same adsorbent quality. Tests of the HRPA filters with DOP aerosol shall be performed in accordance to ANSI N510-3.975. Any HRPA filters found defective shall be replaced with filters qualified pursuant to Regulatory Position C.3 .d of Regula-tory Guide 1.52.

Op ration of the system for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> every month will demonstrate operability of the filters and adsoxber system and remove excessive moisture built up on the adsorber.

If significant painting, fire or chemical release occurs. such that the HFPA filter or charcoal adsoxber could become contaminated from the fmaes, chemicals or foreign materials, the same tests and sample analysis shall b performed as required for operational use. The determination of significant shall be made by the operator on duty at the time of the incident. Knowledgeable staff members should be consulted prior to making this determination.

Demonstration of the automatic initiation capability is necessary to 'assure system performance capability.

3.7.'F/4.7.F Primar Containment Pur e System The primary containment purge system is designed to provide aix to pu ge and ventilate the primary containment system. The exhaust from the primary con-tainment is first processed by a filter train assembly and then channeled through the reactor building roof exhaust system. During power operation, the primary containment purge and ventilation system is isolated from the primary containment by two isolation valves in series.

HEFA (high efficiency particulate air) filters are installed before the charcoal adsorbers Eollowed by a centrifugal fan. The in-place" test results should indicate a leak tightness of the system housing oi not less than a 1KPA efficiency of at least 99% removal of DOP particulates. The lab-99;.'nd oratory carbon sample test results should indicate a radioactive methyl iodide removal efEiciency of at least 85 percent. Operation oE the fans signif'cantly different from the design flow will change the removal efficiency of the HFPA filters and charcoal adsoxber If the system is found to be inoperable, the Standoy.Gas Treatment System may be used to purge the containment.

279

BASES Pressure droo across the combined HEPA filters and charcoal ndsozbers of less than 8.5 inches of water at the system design flow rate will indicate that the filters and adsorbers are not clogged by excessive amounts of foreign matter.

Pressure drop should be determined at least once per operating cycle to show system performance capability.

'The frequency of tests and sample analysis aze necessary to show that the )GAPA filters and charcoal adsorbers can perform as evaluated. Tests of the charcoal adsorbers with halogenated hydrocarbon shall be performed in accordance with USAEC Report - 1082. Iodine removal efficiency tests shall follow RDT Standard H-16-1T. The charcoal adsorber efficiency test procedures should allow for the removal of one adsorber tray, emptying of one bed from the tray, mixing the adsorbent thoroughly and obtaining at least t'wo samples. Each sample should be at 3.east two inches in diameter and a length equal to the thickness of the bed.

If test results are unacceptable, all adsorbent in the system shall be replaced with an adsorbent qualified according to Table 1 of Regulatory Guide 1.52. The replacement tray for the adsorber tray removed for the test should meet the same adsorbent quality. Tests of the HEPA filters with DOP aerosol shall be performed in accordance to A'vSI D510-1975. Any HEPA filters found defective shall be replaced ~ith filters qualified pursuant to Regulatory Position C.3.d of Regula-tory Guide 1.52.

If significant painting, fire, or chemical release occurs such that the HEPA filter or charcoal adsorber could become contaminated from the fumes, chemicals or foreign materials, the same tests and sample analysis shall be performed as required for operational use. The determination of significance shall be made by the operator on duty at the time of the incident. Knowledgeable staf f members should be consulted prior to mal ing this determination.

280

j,IMITING CONDIT ONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.8 RADIOACTIVE MATERIALS 4.8 RADIOACTIVE MATERIALS Aunlicabilitv A licabilit Applies t.o thc controlled rele Lsc App3ies to t.he periodic test and of radioact,i ve liquids and gases record requirements and sampling from t,h< .":u;,il.it,y. and moni lori ng met,hods tu ed for f:ici it l ho:; effluent'.

~Oo ective ~ob ective To define the limits and conditions To ensure that radioactive liouid for the release of radioactive and gaseous releases from the effluents to the environs to assure facility are maintained within the that any radioactive releases are limits specified by Specifications as low as practicable and within 3.8.A and 3.8.B.

the limits of 10 CFR Part 20.

~secifice ion S ecification A. Li uid Effluents A. Li uid- Effluents The radioactivity release 1 ~ Facility records shall be concentration in liquid maintained of the radio-effluents from the station active concentrations and shall not exceed the values specified in 10 CFR Part 20, Appendix B, Table 2,

II, Column for unrestricted areas.

volume before dilution of each batch of liquid effluent released, and of the average dilution flow and length of time over

~,

which each discharge occurred.

2. ~ne release rate of radio-active liquid effluents, 2. A representative sample excluding tritium and noble of each batch of liquid gases, sha'1 not exceed 20 effluent released shall curies during any calendar be analyzed for the quarter. principal gamma-emmitting nuclides.

3. Du ing release of radio- 3. Radioactive liquid waste active wastes, the following sampling and activity analysis conditions shall be met: shall be performed in accor-dance with Table 4.8.A.

281

LINITINO CONDITIONS VOR OPERATION ~SERVE LL I'CE REIEUIRDIKHTS 3 ~ S.A Li uid Kf f luente 4.8.A Li uid. Ef fluents

a. Liquid waste activity and flow rate shall be contin-uously monitored and re-corded during release, and the effluent control moni-tor shall be set to alarm and automatically close the waste discharge valve before exceeding the limits specified in 3.8.A.1 above.

If this requirement cannot be met, continued release of liquid effluents shall be permitted only during the succeeding 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> provided that, during this 48-hour period, two inde-pendent samples of each tank shall be analyzed and two station personnel shall independently check valving before the dis-charge.

4. The eysEtem as designed to pro- 4. The liquid effluent radiation cess liquid radwastes shall. be monitor shall be calibrated at maintaIned and shall be opera- least quarterly by means of a ted to process, liquid rad- known radioactive source.

waete prior to their discharge Each monitor, as described, when it appears that the pro- shall also have an instrument

)ected cumulative discharg. channel test monthly and a will exceed'R25 curiee during sensor check daily.

any calendar quarter.

5. The maximum activiry to be con- 5 ~ The performance of automatic tained in one I iquid radwa ate isolation valves and discharge tank that can be discharged tank selection valves shall be directly to the environs shall checked annually.

not exceed 10 curies.

B. Airborne Effluents B. Airborne Kf fluents

1. The release rate for gross 1. The gross 8,T and particulate

~ ctivity except for I-131 and activity of gaseous vastes particulates Mth balf-lives released to the environment longer than eight days, shall shall be monitored and recorded:

not exceed:

282

Ll.'fITIYG COAIi)ITIONS FOR OPERATION SURVEILLAN~CE IIE UIR IENTS 3.8.5 AI rbornc Ef f luents 4.8.B Airborne Efflucnts Q2 a. Por effluent streams having 0.13 1.46 continuous monitoring capa-bility, the activity and

<<re l case ra t e f rom flow rate shall be monitored Q! and recorded to enable re-building cxha<<st vents lease rates of gross radio-in Ci/sec. activity to be determined on release rate from main an hourly basis.

stack in Ci,/sec. b. Por effluent streams without continuous monitoring capa-bility, the activity shall be monitored and recorded and the releases through these streams shall be controlled so that the release rates from all

2. The release rates of I-131 streams are within the and particulates with half limits specified in 3.8.B, lives greater than eight days rcleas<<d to the environs 2. Radioactive gaseous waste sam-as part of airborne cfflucnts pling and activity analysis shall not cxcccd: shell b<< performed in accor-dance with Table 4 ~ 8. B.

QIA 03 ~ release rate from building exhaust vents in uCi/sec.

Qq " rclcRse rate from main stack in uCi/scc.

3. Thc rclcasc rate of gross gaseous activity from the plant shall not 3. Samples of offgas effluents exceed 0 10 curies/second when

~

shall be analyzed at, least averaged over 'any calendar weekly to determine the quarter. When the release rate idE!ntity and quantity of the exceeds 0.05 curie /second for a period of greater than 48 hrs pr Incipal radionuclides licks c shall notify the being released.

Director, Directorate of Licensing, i; writ inwi 'hin

~

10 days

4. The release rate of I-13l, and particulate" with half-1;vcs greater than 8 days from thc 283

LIMITING CONDITIONS POR OPERATION SURVEILLANCE RE UIREMENTS

3. 8. B Airborne Ef fluencs 4.8.B Airborne Effluents plant shall not exceed 0.8 4. A11 waste gas monitors shall pCi/sec when averaged over any be calibrated et least quar-calendar quarter. When the terly by means of e known release rate exceeds 0.4 pCi/ radioactive source. Each scc or a period of 1 week, monitor shall have an instru the licensee shall notify the ment channel test at least Director, Direccorace of monthly and a s'ensor check Licensing, in writing within at least daily.

10 days.

5. If che limits of 3.8.B are exceeded, appropriate cor-reccive action, such as an orderly reduction of pouer, shall bc initiated to bring the releases uithin the limice,

6. Radioactive gaseous uaetee relcnsed to the environment shall bc monitored and recorded.

7. During release of gaseous uaetcs through tlute main stack, the follouing con-ditions shall be met:

a. The gross B,T activity monitor, the iodine sampler and pa r c icula t e sampler shall be operating.

b. Isolation devices capa-ble of limiting gaseous release rates from che main stack to within the values specified in 3.8.B.l above shall be operating.

c. If, foe'n effluent release path chere ie no monitor operable, an equivalent monitor can be substituted to monitor this effluent release path or no efflueocs shall be released through chat effluent release path until such monitor is made available.

284

LIHKTPfO CO".(OITIO!tS FOB OP..PATIOt( SUHVFILLPilCE REOUIR~~c.; TS 4.8. 8 Airborne Ef fluents

'3. f'adioactive gases released from each unit's turbine and reactor building roof vents,, the radwaste building roof vents, and the main stack shall be continuously monitored. To accomplish this, at least one reactor building and one turbine building vent monitor-ing system per unit shall be oper-ating whenever that unit's build-ing ventilation syste~ is in ser-vice. Also, one radwaste building system vent monitoring channel shel be operating whenever the radwaste ventilation system is in service.

At least'one main stack monitoring channel shall be operating when-ever any unit's air ejector, mechanical vacuum pump, or a stand-by gas treatment system train is in service. If normal monitoring systems are not available, temp-orary monitors or other systems shall be used to monitor effluent.

A monitoring channel may be out of senrice for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for func-tional testing and calibration without providing a temporary monitor.

If these requirements are not satisfied for the stack or rad-waste monitor, the reactors shall be in the hot shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the stack and 10 days for the radwaste vent.

If these requirements are not satisfied ".or the reactor and turbine building vents, the affected reactor shall be in hot shutdown condition within 10 days.

285

t I'VIIVI' I>I>A!ICE III'<III'JIII'lt>II'lHTI

~ >'.'hal>ica. Vacu>>m I'U>>lt> C. Mechanical Vacuum Pumn

1. "". mechanical vac uum> pump At least once during each operating sha'1 oe capable of being cycle verify automatic securing and omatically isolated iso3.ation of the mechanical vacuum au e" J>'e 'n and a . i!I>>al of'i!;4 "c 'ioactivity in Lhe stcem j>u>Ap.

'.'-.. c whenever the main ctea.-.. D. Miscellaneous Hadioactive Materials Sources isolation valves are open.

l. Surveillance Hc uirements

c. vf ne limits of 3,8.C,3. are ro: met, the vacuum pump sh-'1 Tests for leakage and/or contamination i s Jl ated. shall be performed by the licensee or by other persons specifically authorized D. Miscel:aneou Radioactive by the Commission or an <<greemen State, Mate ia" s Sources as follows:

l. Source Leaka c Test a. Each sealed source, except startup sources subject to co' flux, Each sealed source containi..g containing radioactive material, ra'.'oactive material in excess other than Hydrogen 3, with a half-

o. those quantities of byprod- life greater than thirty days and uct mawerial listed in 10 C":8 in any form "..ther than gas shall 30.71 Schedule B and all other be tested for leal are and/or sources, including alpha contami>>ation at intervals not to e".'rs, in excess of 0.1 exceed six months. The leakage test shall be capable of detecting nicrocurie, shall be free of' 0.005 m'crocurie of remov- the presence of 0.005 nicrocurie of ab'e contamination. Each radioactive materia3. on the test see'ed source with removable senple.

conta).".ination in excess of th above linit shall be b. The periodic leak test recuired i.", diately withdraw fro"..> does not apply to sealed sou ces use and (a) eitl'er decon- that are "tored and not being ta:.i>>>.ted en<) u ed. The source.", excepted from (b) disposed of in accor<la>>'e thi,s test .,hall be tested for with Commission regulationc. leakage prior to any use or transfer to anc>ther u..cr unlesc they have been le"k tested within six months prior to the date of use or transfer.

Xn the absence of a certification from a transferor indicating that a test has been made within six months prior to the transfer, sealed sources shall not be put.

into >> e unti3 tested.

c. Startu~ so>>rccs sh'>33. bc leak tested 286 prior to and fo13owing any repair or mai>>tenane<< nnd bei"ore being subJected to core f3>>x.

Table 4.8-A RADIOACTIVE LIQUID WASTE SAMPLING AND ANALYSIS A. Test Tank Release Type of Minimum Detectable Sam lin Fre uenc Activit Anal sis Concentration uCi ml Each Batch Principal Gamma-Emittin Nuclides S x lo (2)

One Batch/Month Dissolved and Entrained Fission and Activation Gases lo-'0 Monthly Propor t ional Tr it ium Composite (1) Gross Alpha Quarterly Proportional Sr-89, Sr-90 5x10 Composite (1)

NOTES:

(1) A proportional sample is one in which the quantity of liquid sampled is proportional to the quantity of liquid waste discharged from the plant.

(2) For certain mixtures of gamma emitters, it may not be possible to measure radionuclides in concentrations near their sensi-tivity limits when other nuclides are present in the sample in much greater concentrations. Under these circumstances, it will be more appropriate to calculate the concentrations of such radionuclides using observed ratios with those radio-nuclides which are measurable.

287

TABLE 4.8-B Radioactive Gaseous Waste Sam lin and Analysis Sample Sampling Type of Minimum Detectable e Frequency Activity Analysis (1)

Concentration c cc 2

Weekly and Principle Gamma 10 (3) each purge Emitters Gas Monthly and Tritium 10 each purge 12 Weekly I-131 10 Charcoal Monthly (4) I-133, I-135 10" Principal Gamma Weekly Emitters (at least for Ba-140, La-140, I-131) 10-11 Particulates Monthly Gross alpha 10-11 composite of

~eekly samples Quarterly Composite Sr- 9,Sr-90 10-11 of monthly samples (1) The above detectability limits for concentrations are based on technical feasibility and on the potential significance in the environment of the quantities released. For some nuclides, lower detection limits may be readily achievable and vhen,nuclides are measured belov the stated limits they should also be reported.

(2) Analysis shall also be made vithin one month of the initial criticality and folloving each refueling process change or other occur."ence which could alter the mixture of radionuclides.

(3) For certain mixtures of gamrtw emitters, it may not be possible to measure radionuclides at levels near tneir sensitivity limit when other nuclides are present in the sample at much higher levels. Under these circumstances it will te more appropriate to calculate the le'vels of such radionuclides using observed ra ios with those radionuclidcs that ere measurable.

(4) When the average daily gros~ radioactivity release .ate from a, release point equals or exceeds that given in 3.8.B.3 or when the steady state gross radioactivi-y release rate increases by 50~~ove. the previous corresponding power levels'teady s ate re'ease rate, the associated iodine and particulate cartridge shall be analy"ed to determine the release rate increase for iodines and particulates. When samples are taken more often than that shown, the minimum detectable concertrations vill be correspondingly higher.

288

3. 8 BASES Radioactive waste release levels to unrestricted areas should be kept "as law as practicable" and are not to exceed the concentration limits specified in 10 CFR Part 20. At the same time, these specifications permit the flexibility of operation, compatible with considerations of health and safety, to assure that the public io provided a dependable source of po~er under unusual operating conditions which may temporarily result in releases higher than the design objectives but still within the concentration limits specified in 10 CFR Part 20. It is expected that by using this operational flexibility under unusual operation con-ditions, and exerting every effort to keep levels of radioactive materials aa low as. practicable, the annual releaseo vill not exceed a small free" tion of the annual average concentration limits specified in 10 CFR Part 20.

3.8.A Li 'uid Efflucnts Specification 3.8.A.1 requires the licensee 'to limit the release concentra-tion of radioactive materials in liquid offluants from the station to levels specified in 10 CFR Part 20, Appendix I, Table II, Column 2, for unrestricted areas. This specification provides assurance that no member of the general public can be. exposed to liquids containing radioactive materials in excess of limits considered: permisoible under the Commission's Rules and Regulations.

Specification 3.8.A.2 establishes an upper limit for thc release of radio-active liquid efflucnts, excluding tritium and nable gases, of 20 curics during any calcndnr quarter. The intent of this specification is to permit the licensee the flcxibilty nf operation to assure that the public is pro-vided n dependable source of p,iwcr under unusual operating conditions which may temporarily result in releases higher than the levels normally achieva-ble. Releases of up to 20 curics during any calendar quarter vill result in concentrations of radioactive material in liquid effluents at small percent" ages of the limits specified in 10 CFR Part 20.

Specification 3.8.A.3 requires that suitable equipment to control and monitor the releases of radioactive materials in the liquid cffluento are operating during any period theoe releaseo are taking place.

Specification 3.8.A.4 requires that the licensee shall maintain and operate the equipment installed in the radvaste system tu, reduce the release of radioactive materials in liquid effluents to ao lov as practicable consis-tent with the requirements of 10 CFR Part 50.36a. In order to keep releases of radioactive materials as low as practicable, the specification requires vill exceed 1.25 curiae during anyit appears operation of equipment whenever the projected cumulative release calendar quarter.

289

~ 8 BASES Specification 3.8.A.S limits the amount of'adioactivity that may be

.inadvertently released to the environment to an amount Mhich is as I~

as practicable'consistent M5th the requirements of 10 CFR Part 50.36a.

0 6,9 Airborne Effluents Specification 3.8.B.1 provides a method to be used in summing the air-borne cffluents from the main stack and vents which ~ill assure that the release rate does not exceed 10 CPR Part 20, Table XI, Column 1, for unrestricted areas. The constants are determined by the annual average site meteorology and an exposure dose of 500 mrem per year to the @hole body.

Specification 3.8.B.2 provides a method to be used in summing airborne I-131 and particulates vith half-lives greater than eight days released from the stack and vents to assure that the release rate does not exceed 10 CFR Part 20, Appendix B, Table IX, Column 1, for unrestricted areas.

The constants are determined by the annual average site meteorology and an exposure dose of 500 mrem per year to the vhole body or any organ>

and include a factor of 700 to account for reconcentration.

Specification 3.8.B.3 establishes an upper limit for the continuous release of gaseous activity from ths plant Specification 3,8.B.4 is to monitor the'per'formance of the core. A sudden increase in the activity levels of gaseous releases may be the result of tho fuel cladding losing its .integrity. Sinca core performance is of utmost importance in the resulting doses from accidents, a report must be filod vithin 10 days folloving the specified increase in gaseous radio-active releaoeo.

Specification 3.8.B.5 is to require the licensee to take such actions, including reducing power or other appropriate measures, as may be necessary to heap the radioactive gaseous releases Mithin specified limits.

Specification 3.8.B.6 and 7 are in accordance vith Design Criterion 64.

Specification 3.8.B.8 requires that these gaseous monitoring devices be operating Mhenever radioactive gases are generated in the plant.

290

3.8. (:/4.A. (; Mechanical Vscuur~sPurn The purpose of isolating the mechanical vacuum pump line is. to limit the releaur o( activity from the main condenser. During an accident, fission products would bc transported from the reactor through the main steam lines to the condenser. The fission product radioactivity would be sensed by the main steam line radioactivity monitors which initiate isolation.

4.8.A nnd 4.8.B BASES The survc illanec requirements given under Specificat)on 4.8.A and 4.8.B provide assurance that liquid and gaseous wastes are properly controlled and monitorei) during any release of radioactive materials in the liquid and gaseous effluents. These surveillance requirements provide the data for the licensee and the Commission to evaluate the station's performance re) at ivr to radioaet'.ve wastes released to the environment. Reports on the qunntf ties of radioactive materials released in effluents shall be furnished to the Conaaission on the basis of Section 6 of these technical specificatio'ns. On tbe basis of such reports and any additional informa-tion the Comnisaion may obtain from the licensee or others, the Commission may from time to time require the licensee to take such actions as the Commission deems appropriate.

3.8. 0 and 4.8.:j BASES fhc objective of this speci:ication is to assu:u that leakage from byproduct, source, and special nuclear radioactive material sources docs not exceed allowable limits.

29)

.LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RF. UIREMFNTS 3.9 AUXILIARY ELECTRICAL SYSTEM 4.9 AUX1LIARY ELECTRICAL SYSTEM A licabilit Applies to the auxiliary elec- Applies to the periodic testing trical power system. requirements of the auxiliary electrical systems.

~Ob ective ~Ob ective To assure an adequate supply of Veri'fy the operability of the electrical pover for. operation auxiliary electrical system.

systems required for safety.

of'hose S ec ifica t ion S ecification A. Auxiliary Electrical E ui ment A. Auxtlter El ect.rtcel F~ui ment A reactor shall not be started 1. Diesel Generators up (made critical) from the cold condition unless four a. Each diesel generator units 1 and 2 diesel gene- shall be manually started rators are operable, both and loaded once each month 161-kV transmission lines to demonstrate operati'onal are operable and supplying readiness. The teat shall power to the plant, and the continue for at least a requirements of 3.9.A.4 one-hour period at 75X of through 3.9.A.7 are met. rated load or greater.

A reactor shall not be started During the monthly gene-up (made critical) from the rator test the diesel Hot Standby Condition unless generator starting air all of the folloving condi- compressor shall be tions are satisfied: checked for operation and

1. At least one off-site 161-kV its ability to recharge transmission line and its air receivers. The opera-tion of the diesel fuel common transformer are oil transfer pumps shall available and capable'f be demonstrated, and the automatically supplying diesel starting time to auxiliary pover to the reach rated voltage and.

shutdovn boards. speed shall be logged.

2. Three units 1 and 2 diesel b. Once per on'crating cycle generators shall be operable.

a test will be conducted

3. An additional source of to demonstrate the emer-power consisting of one of gency diesel generators the following: will start and accept emergency load vithin

a. A second 161-kV trans-mission line and its 292

LIMITINC CONDITIONS POR OPERATION SURVEILLANCE RE UIRPHEHTS 4.9.h huxiliar Electrical E ui ment common transformer or the specified time sequence.

cooling tover transformer (not parallel with the C~ Once e month the quantity energized common transformer) of diesel fuel available capable of supplying power shall be logged.

to the shutdovn boards.

Each diesel g nerator shall

b. A fourth operable units be given an annual inspec-1 and 2 diesel generators tion in accordance vith instructions based on the

4. Buses and Boards Available manufacturer'e  : commenda>>

tions.

a. Start buses 1A and 1B are e. Once e month a sample of energized. diesel fuel shall be checked for quality. Thc quality

b. The units 1 and 2 4-kV shall bc within the accepta-shutdown boards are ble limits specified in energized. Table 1 of AS'975-68 and logged.

c The 480-V shutdovn boards associated with the unit 2. D.C. Power System - Unit Batteries are energized. (250-Volt) Diesel Generator Bet ter les (125-Volt) and Shutdovn Undervoltage relays Board Batteries "(250-Vol )

operable on start buses 1A and 1B and 4-kV Every week che specific shutdovn boards, A, B, C, gravity and the voltage of and D. the pilot cell, and, tempera-ture of an ed)scent cell end

5. The 250-Vo't unit and shutdovn overall battery voltage hall board batteries and a battery be measured and logged.

charger for each battery end b. Every three ccnchs the mea-associeted battery boards are surements s!;all be made of operable. voltage of each cell co

6. Logic Systems nearest 0.1 volt, specific gravity of each cell, and

a. Common accident signal temperature of every fifth logic system is operable. cell. These measurements shall be logged.

b. 480-V load shedding logic A battery rated discharge system is operable.

(capacity) test shall bo

7. There shall be e minimum of performed and the voltage, 103,300 gallons of diesel fuel time, and outout current in the standby diesel genera- measuremonts shall be logged tor fuel tanks. at intervals not to exceed 24 months.

293

LIK?TING COHO(TIOHS FOR OPERATTON SURVEILLANCE RE UIRRKNTS

).9.h huxillar 'Electrical E ui ment'.9.h huxilier Electrical E ui ment

3. Logic Systems Both divisions of the common accident signal logic system shall be tested every 6 months to demonstrate that it will function on actuation of the core spray system of each reactor to provide an auto-matic start signal to all 4 units 1 and 2 diesel generators.

b. Once every 5 months, the condi-tion under which the 480-Volt load shedding logic system ie required shall be simulated using pendant test switches and/or pushbutton test switches to de-monstrate that the load shedding logic system would initiate load shedding signals on the diesel auxiliary boards, reactor HOV boards, and the 480-Volt shut-down boards.

4. Undervo 1tage Relays

a. Once every 6 months, the con-dition under which the under-voltage relays are required shall be simulated with an undervoltage on start buses lh and 1B to demonstrate that the diesel generators will start.

b. Once every 6 months, the con-ditions under which the under-voltage relays are required shall be simulated with an undervoltage on each shutdown board to demonstrate that the associated diesel generator vill start.

C ~ The undervoltage relays which start the diesel generators from start buses 1A and 1B and the 4-kV shutdown boards, shall be calibrated annually for trip and reset and the measurements logged.

294

LIMITINC CONDITIONS FOR OPERATION SURVEILLANCE REOUIRBZLLTS 3.9.$ eration with Ino erable 4.9eB eration with Inoperable

~Eut ene ~Eui nene Whenever a reactor is in Startup mode or Run mode and not in a cold condition, the availability of electric power shall be as speci-fied in 3.9.A, except as specified herein.

1. Prom and after the date that 1~ When one 161-kV line or one common one 161-kV line or one common station transformer and its para'.el station transformez and its cooling tower transformer or one parallel cooling tower trans- start bus is found to be inoperable, former or one start bus becomes all units 1 and 2 diesel generators inoperable, reactor operation is and associated boards must be permissible under this condition demonstrated to be operable ror seven days. immediately and daily there after.

2. When one of the units 1 and 2 diesel generator is inoperable, 2. When one of the units 1 and 2 continued reactor operation is diesel generator is found to be permissible during the succeeding inopezable, all of the CS, RHR 7 days, provided that both off- (LPCI and Containment Cooling) site 161-kV transmission lines Systems and the remaining diesel and both common station trans- generators and associated boards formers or one common transformer shall be demonstrated to be operable and one cooling tower transformer immediately and daily thereafter.

(not parallel with the energized common transformer) are avail-able, and all of the CS, RHR (LPCI and Containment Cooling) Systems, and the remaining three units 1 and 2 diesel generators are operable. If this requirement cannot be met, an orderly shut-down shall be initiated and both reactors shall be shutdown and in the cold condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

295

ne SIIRVKll.LANCE REOW IRr'~gi4TS 4.9.B 0 aration with Ino erabI Rceui nene ~Eu i en e 3 ~ When one un'ts 1 ard 2 4-kV shutdown board is inoperable, continued reactor operation is permissible for .a period not to exceed 5 days, provided that both off-site 161-kV tr'ansmission lines and both common station transformers or one common ransformer and one cooling tower transforme (not parallel with the 3. When one 4-kV shutdown board is energized common transformer) found co be inoperable, sll are available ard the remain- remaining 4-kV shucdoerr. boards ing 4-kV shutdown board.s and and associated diese'enera-associated diesel gen rators, cors, CS and RGB (LPC? and CS, RHR (LPCl and Contaiw~ent Concainmenc Cooling) Systems Ccoling) Systems, and aM 480 V supplies by the remaining 4-kV emergency powe boards ar shutdown boards shall be dc on-operable. l this requirectent scraced co be operable, im.e-canrot be met, an orderly shut- diacely and daily thereafter.

down shel'e init'ated and boch reactors bourse'rom she'1 Ce sh'utdown and in the cold condition wi hin 24

4. and after the date that one of the three 250-Vol unit ba-tnries and/or s associated i battery board is found to be inoporable for anv reason, continued reactor operation is per&ssiblo during the succeeding seven d~ys. Except for routine surveillance cestirg tne NRC shall be notified within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of tne situacion, the precautions to be taken during this period and the plans to return cne failed component co an operable state.

From and aEter the date chat one of the Eour 250-volt shutdown 296

LIHI T I NC COND IT I ONS FOR OP ERAT ION SVRVEILLANCE RE UIREMENTS

3. 9. 0 0~or n t ton u i th t no~orn h 1 n

~K>ection<<of the TYh 161-kY grid. In the normal mode of opere-tion, the 161-kV system ie operating and four diesel generators are opera-tionnl. If one diesel generator is.out of service, there normally remain the 161-kV sources, thc nuclear generating units, and the other three diesel generators. For a diesel generator to bc considered operable its associated 125 V battery must be operable.

Thr minimum fuel oil requirement of 103,300 gallons is sufficient for 7 dny<<of full lond operation of 3 diesels and is conservatively based on availnbility of a replenishment supply.

Auxiliary power for Browne Ferry Nuclear Plant is supplied from two sources; either thc unit station transformers or from the 161-kV transmission system through the common station transformers or the cooling tower transformers. If a common station transformer is lost, the units can continue to operate since the unit station trans-formers are in service, the othe. common station transformer and t'e cooling tower transformers are available, and four diesel generators are operational.

A 4-kV nhuu!nvn l>nard is allowed to be out of operation for a brief period>>to allow for maintcnancc and testing, providing all remaining 4-kV ehutdovn honrds nnd a<<socintcd diesel generators CS, RHR, (LPCI and Containment Coolinp) Systems supplied by the remaining 4-kV shutdown, boards, and all emergency 480 V power boards are operablc, There nrc eight 250-volt d-c battery systems each of which consists of a hnttcry, !>attcry chnrger, nnd distribution equipment. Three of these sys-tems provide pover for unit control functions, operative power for unit

>>ntor loads, and alternative drive power for a 115-vol't a-c unit preferred motor-generator set. One 250-volt d-c system provides power for common plant and tran<<mission system control functions, drive power for a 115-volt n-r plant prcfcrrrd motor-gcnctator srt, and emergency drive power for certain unit large motor loads. The four remaining systems deliver con-trol power to thc 4160-volt shutdown boards.

299

3.9 BASES Each 250-volt d-c shutdown board control power supply can receive power from its own battery, battery charger, or from a spare charger. The chargers are powered from normal plant auxiliary power or from the standby diesel-driven generator system. Zero resistance short circuits between the control power supply and the shutdown board are cleared by fuses located in the respective control power supply. Each power supply is located in the reactor building near the shutdown board it supplies. Each batt'ery is located in its own independently ventilated battery room.

The 250-volt d-c system is so'rranged, and the batteries sized such, that the loss of any one unit battery will not prevent the safe shutdown and cooldown of all three units in the event of the loss of offsite power and a design basis accident in any one unit. Loss of control power to any engineered safeguards control circuit is annunciated in the main control room of the unit affected. The loss of one 250-volt shutdown board battery affects normal control power only for the 4160-volt shutdown board which it supplies. The station battery supplies loads that are not essen-tial for safe shutdown and cooldown of the nuclear system. This battery was not considered in the accident load calculations .

300

Thc monthly tests of thc diesel generators are primarily to check for failures and deterioratfon in the system since last'se. The diesels will hc Loaded to at least 75 percent of rated power while engine and generator temperatures are stabilized (about onc hour). Thc minimum 75 percent load vill prevent soot fnrmation in the cylinders and in)ection nozzles. Opera-tion up to an equilibrium temperature ensures that there is no overheat problem. The tests also provide an enpine and generator operatinp history to he compared with subsequent enpine-penerator test data to identify end to correct any mechanical or electrical deficiency before it can result in a 's ye t cm fa il<i r c.

Thc test <lurfug refueling outages is more comprehensive, including proce-dures that arc mnst effectively conducted at that time. These include automatic actuation and functional capability tests to verify that the pcucratnrs can start and be ready to assume load in 10 seconds ~ The annual tnspcction wfll detect any signs of wear lonp before failure.

Battery maintenance with regard to the floating charge, equi lizinp charge, an<I electrolyte level will bc based on the manufacturer's instruction and snund maintenance practices. In addition, written records will be main-tained of the battery. performance. The plant batteries will deteriorate wf th tfmc but precipitous failure is unlikely. Thc type of surveillance calle<i for in this specification is that which has been demonstrated through cxpcr fence to provide an indication of a cell becoming irrcpular or unser-viceable lonp bcforc it becomes a failure.

Thc cqualizfnp charpe, as recommended by the manufacturer, is vital to main-tainfng the Ampere-hour capacity of the battery, and will be applied as rccommcndcd.

The test fnp of the lopic systems vill verify the ability of the logic systems to bring thc auxiliary electrical system to running standby readiness with thc presence of nn accident signal from any reactor or an undervoltagc signal ou thc start buses or 4-kV shutdown boards.

'l'ic per fodfc simulation of accident signals in con]unction with diesel gene-rator voltage available signals will confirm the ability of the 480-volt load shcddfng Lopfc system to sequentially shed and res<.'art 480-volt loads if an accident signal were present and diesel generator voltage were the only source of electricaL power.

R Kl'KRENC KS

1. Normal Auxiliary Power System (BFHP FSAR subsection 8.4) 2, Standby A.C. Power Supply and Distribution (BFNV FSAR subsection 8.5)

3. 250-volt D.C. Power Supply and Distribution (BFNP FSAR subsection 8.6) 301

LIHITIHr, CONDITIONS FOR OPERATION SURVEILLANCE RE UIREHENTS 3.10 CORE ALTERATIONS 4e lO CORE ALTERATIONS A licabilit Applies to the fuel handling Applies to the periodic testing and core reactivity limitations. of those interlocks and instru-mentation used during refueling and core alterations.

~Ob eecfvc ~Ob ecttve To ensure that co'z'e reactivity To verify the operability of is vithin the capability of instrumentation and interlocks the control rods and to prevent used in refueling and core criticality during refueling. alters tions.

S ecification S ccification A. Rc fuel in Interlocks A. Refuelin Inter locks

1. The reactor mode svitch 1. Prior to any fuel hand-shall be locked in the ling vith the head off "Refuel" position during the 'reactor vessel, the core alterations and the refueling interlocks refueling interlocks shall be functionally shall be operable except teotcd. They shall be as specified in 3.10.A.5 tested at weekly inter-and 3. 10.A. 6 be lov. vals thereafter until no longer zequired. They shall also be tested fol-loving any repair vork associated vith the inter-locks.

2, Fuel shall not be loaded 2. Prior to performing con-into the reactor coze trol rod or control rod unless all control rods drive maintenance on con-are fully inserted. trol cells without removing fuel assemblies, it shall be demonstrated that the core can be made subcritical by a margin of 0.3S percent bk at any time during the maintenance vith the strongest operable control z'od fully withdrawn and all other operable rods fully inserted. Alterna-tively if the remaining 302

I.,I 81'I'INC CONI) ITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.10.A Rcfuelin interlocks 4.10.A Refuclin Interlocks control rods are fully inserted and have had their directional con-trol valves electrically disarmed, it is suffi-cient to demonstrate that the core is sub-critical with a margin of at least 0.38 Ak at any time during the maintenance. A control rod on which maintenance is being performed shall be considered inoperable.

3~ The fuel grapple hoist load suitch shall be set at < 1,000 lbs.

4. If the frame-mounted auxi-liary hoist, thc monorail-mountcd auxiliary hoist, or the service 'platform hoist lo be used for handling fuel with the head off the reactor vessel, the load limit svitch on the hoist to be used shall be sit at

< 400 lbs.

5. A maximum of tvo non-ad$ scan t con tro1 rods may bc vithdravn from the core for thc purpose of perfor-ming control rod and/or control rod drive mainten-ance, provided the follov-ing conditions are satis-fied:

a. The reactor mode svitch shal) bc locked in the "refuel" position. The refuel tng interlock which prevents more than one control rod from being vithdravn may be bypassed for one of the control rods on vhich maintenance is being performed. All other 303

LIMITING CONI) ITlONS FOR OFERATION SURVEILLANCE RE UIREMPNTS

3. 10. A Rc fuc1 in Interlocks Refuel'in Interlocks 0 b. h sufficient

'.10.A refueling interlocks shall be operable.

number o' control rods shall be operable so that the core can be made sub-critical with the strongest operable con-trol rod fully with-drawn and all other operable control rods

'fully'insert'cd, or all directional control valves for remaining control rods shall be disarmed electrically and suf f icicnt margin to crit'icality shall be demonstrated.

c. If maintenance is to be pcrformcd on two control rod drives they must be separated by morc than two control cells in any direction.

d. -An appropriate number of SRM's.arc available as defined in specifi-cation 3.10.h.

6. Any number of control rode may be withdrawn or removed from the reactor core pro-viding the following condi-tions are satisfied:

a. The reactor mode switch is locked in the."re-fuel" position. The refueling interlock which prevents more than one control rod from 304

l.l~ltl~n CCNnl TJ~~S roR OPKMTIoN SUlNKILLhNCX RE I REAGENTS

3. 10. h Refuelia Interlocks 4. >O,A Iefwlin Intcrlocke being vitbdravn aay be bypaaaad on ~ vithdravn control rod after the twl aaaeeblicc ia Ae cell eeatainlnR (cee trolled by) that cea-trel red have been re-moved froa the reactor core. All ether re fwliag interlocks shall be operable.

B. Core Monitorin

1. During core alterations, except Prior to +aking any alterations as in 3.10.B.2, two SRM's shall to the coro the SN'a shall be be operable, in or adjacent to any tuactionally teated and checked quadrant where fuel or control tor neutron response, Thar ~-

rods are being moved. For an SRM atter. vhilc required to be to be considered operable, the ,operable, tha SRH'c vill be following shall checked daily !or re~ponce.

be satisfied:

a. The SRM shall be inserted to the normal operating level.

(Use of special moveable, dunking type detectors during initial fuel loading and major core alterations in place of normal detectors is per-missible, as long as the detecto is connected to the normal SRM circuit.)

b. The SRM shall have a minimum of 3 cps with all rods fully inserted in the core, if or more fuel assemblies are in one the core.

2. During a complete core removal, the SRM's shall have an initial minimum count rate of 3 cps prior to fuel removal, with all rods fully inserted and rendered electrically inoperable. The count rate will diminish during fuel removal. Individual control rods outside the periphery of the then existing fuel matrix may be electrically armed and moved for maintenance after all fuel in the cell containing (controlled by) that control rod have been removed from the reactor core. 305

LIMITING CONDITIONS FOR OPERATXON SURVEILLANCE RE UIREMENTS 3.10.C S ent'uel Pool Water 4,10.C S ent Fuel Pool Water

l. Whenever irradiated fuel is 1. Whenever irradiated fuel is stored in the spent fuel stored in the spent fuel pool, pool, the pool water level the water level and temperature shall be maintained at a shall be recorded daily depth of 8 1/2 feet or greater above the top of the spent fuel. A minimum of 6-1/2 feet of water shall be maintained over single irradiated fuel assemblies during transfer and handling operations.

2. Whenever irradiated fuel is 2, A sample of fuel pool water in the fuel pool, the pool shall be analyzed in accordance water temperature shall be with the following specifications:

< 150oF.

a. At least daily for conductivity

3. Fuel pool water shall be and chloride ion content.

maintained within the following limits: b. At least once per 8 hours for conductivity and chloride conductivity < 10 umhos/cm content when the fuel pool 825'C cleanup system is inoperable.

chlorides -< 0.5 ppm 306

LIMNI TINC CONnITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.10.D Reactor Buildin Crane 4.10.D Reactor Buildin Crane

l. The reactor building crane 1. The folloMing operational shall be operable: checks and inspections shall be performed on the reactor

a. When a spent fuel cask building crane prior to is handled. handling of a spent fuel cask and new or spent fuel.

b. Whenever neM or spent (These need not be perf'ormed fuel is handled Mith more frequently than the 5-ton hoist. quarterly. ):

a. The cab and pendant con-trols shall be demon-strated to be operable on both the 125-ton hoist and the 5-ton hois t.

b. h visual inspection sh'all be made to insure structural integrity oi the 125-ton hoist, the 5-ton hoi,st and cask yoke safety vire ropes.

c. The overtravel limit switch interlocks, move-ment speed control and braking operations for the bridge, trolley and hoists, the pendant inter-locks, the mein-auxiliary hoist operation interlock, and the remote emergency stop shall be functionally tested.

E. S cnt Fuel Cask S ent Fuel Cask Upon rcccipt, an empty 1. Prior to attachment and fuel cask shall not be lifting of an empty spent lifted until a visual fuel cask from the shipping inspection is made of the trailer, a visual inspection cask-lif ting trunnions and shall be conducted on the fastening connection has lifting trunnions and the been conducted. fasteners used to connect the trunnion to the cask.

307

LlNlTlHfiCANI>ll 1OHS FOR OPERATION SURVEIl.LAC'E RE UIRQKNTS

5. lO.l'. ~Sent Fuel Cask 4.10.E S nt Fuel Cask

2. A visual inspection shall be made of the assembled trunnion on the empty cask to insure proper assembly.

F, S ant Fuel Css'k Handlin Rcfueline Floor

l. Aclmini strative control shall be exercised to limit the height the spent fuel cask is raised above the refueling floor by the reactor building era>>e to 0 inches, except for entry into the cash decontamina-tion el~aber vhere height above the floor vill be approximately 3 feet.

2. The spent fuel cash yoke safety 3.jnlts ~hall be properly posi-tioned at all timey except

%40% the cools io in tbcl decon tamination chamber 308

3. 10 OASES A. Re fuel in Interlocks The refueling interlocks are designed to back up procedural core reacti-vity controls during refueling operations. The interlocks prevent an inadvertent criticality during refueling operations when the reactivity potential of thc core is being altered.

To minimirc the possibility of loading fuel into a cell containing no control rod, it is required that all control rods arc fully inserted when fuel is bein@ loaded into thc reactor core. This requirement assures that during refueling the refueling interlocks, as designed, will prevent in-advcrtcnt criticality.

Thc refueling interlocks reinforce operational procedures that prohibit taking thc reactor critical under certain situations encountered during rcfuclinR operations by restricting the movement of control rods and the operation of re fu cling equipment.

Thc refueling interlocks include circuitry which senses the condition of the refueling equipmcnt and the control rods. Dependinp on the sensed condition, interlocks are actuated which prevent the movement of the re-fueling equipment or withdrawal of control rods (rod block).

Circ>>itry is provided which senses the following conditions:

1. All rods inserted.

2. Refueling platform positioned near or over the core.

3. Refueling platform hoists are fuel-loaded (fuel grapple, frame mounted hoist, monorail mounted hoist).

4. Fuel grapple not full up.

5. Service platform hoist fuel-loaded.

6. One rod withdrawn.

lichen thc mode switch is in the "Re-fuel" position, interlocks prevent- the refucllnc platform from being moved over the core if a control rod is with-drawn and fuel is on a hoist. Likewise, if the refueling platform is over thc core with fuel on a hoist, control rod motion is blocked by the inter-locks. Mien the m'ode switch is in the refuel position only one control rod can be withdrawn. The refueling interlocks, in combination with core nuclear design and rcfuclinp procedures, limit the probability of en i>>advert.c>>t criticality. The nuclear characteristics of the core assure that. thc reactor is subcritical even when the highest worth control rod is fully withdrawn., The combination of refueling interlocks 'for control 309

cods and, the refueling platform provide redundant methods of preventing inadvertent criticality even atter procedural violations. The interlocks on hoists provide yet another method of avoiding inadvertent criticality.

Fuel handling is normally conducted with the fuel grapple hoist. The total load on this hoist when the interlock is required consists of the weight of the fuel grapple and the fuel assembly. This total is approxi-mately 1,500 lbs, in comparison to the load-trip setting of 1,000 lbs.

Provisions have also been made to allow fuel handling with either of the three auxiliary hoists and still maintain the refueling interlocks. The 400-lb load-trip setting on these hoists is adequate to trip the interlock when nne of the more than 600-lb fuel bundles is being handled.

During certain periods, it is desirablo to perform maintenance on two control rods and/or control rod drives at the sama time. The maintenance io performed with the mode switch in the "refuel" position to provide the refueling interlocks normally available during refueling operations. In order to withdraw a second control rod after withdrawal of the first rod, it is necessary to bypass the refueling interlock on thc first control rod which prevents morc than one control rod from being withdrawn at the same time. The requirement that an adequate shutdown'margin be demonstrated or that all remaining control rods have their directional control valves electrically disarmed ensures that inadvertent criticality cannot occur during this maintenance. The adequacy of the shutdown margin is verified by demonstrating .that the core is shut down by a margin of 0.38 percent hk with the strongest operable control rod fully withdrawn, or that at least 0.38Z hk shutdown margin is available if the remaining control rods have ha'd their directional control valves disarmed. Disarming the direc-tional control valves does not inhibit control rod scram capability.

Specification 3.10.A.6 allows unloading of a significant portion of the reactor core. This operation is performed with the mode switch in the "refuel" position to provide the refueling interlocks normally available during refueling operations. In order to withdraw more than one control rod, it is necessary to bypass the refueling interlock on each withdrawn control rod which prevents morc than one control rod from being withdrawn at a time. The requirement that the fuel assemblies in the cell controlled by thc control rod be removed from the reactor core before the interlock can be bypassed ensures that withdrawal of another control rod does not result in inadvertent criticality. Each control rod provides primary reactivity control for the fuel assemblies in the cell associated wt th that control rod.

Thus, removal of an entire cell (fuel assemblies plus control rod) results in a lower reactivity potential of the core. The requirements for SR.'f operability during these core alterations assure sufficient core monitoring.

1i 40 ~ BASES REFERENCES

1. Refueling interlocks (BFNP FSAR Subsection 7.6)

B. Core Monitorin The SRM's are provided to monitor the core during periods of station shutdown and to guide the operator during refueling operations and station startup. Requiring two operable SRM's in or adjacent to any core quadrant where fuel or control rods are being moved assures ade-quate monitoring of that quadrant during such alterations. The require-ment of 3 counts per second provides assurance that neutron flux is being monitored and ensures that startup is conducted only if the source range flux level is above the minimum assumed in the control rod drop accident.

Under the special condition of removing the full core with all control rods inserted and electrically disarmed, it is permissible to allow SRM count rate to decrease below 3 cps. All fuel moves during core unloading will reduce reactivity. Xt is expected that the SRM's will drop below 3 cps before all of the fuel is unloaded.

Since there will be no reactivity additions during this period, the low number of counts will not present a hazard. When all of the fuel has been removed to the spent fuel storage pool, SRM's will no longer be required. Requiring the SRM's to be functionally tested prior to fuel removal assures that the SRM's will be operable at the start of fuel removal. The daily response check of the SRM's ensures their continued operability until the count rate diminishes due to fuel removal. Control rods in cells from which all fuel has been removed and which are outside the periphery of the then existing fuel matrix may be armed electrically and moved for maintenance purposes during full core removal, provided all rods that control fuel are fully inserted and electrically disarmed.

REFERENCES

1. Neutron Monitoring System (BFNP FSAR Subsection 7.5)

2.  %(organ, W. R.,uIn-Core Neutron Monitoring System for General Electric Boiling Water Reactors," General Electric Company, Atomic Power Equipment Department, November 1968, revised April 1969 (APED-5706)

C. S ent Fuel Pool Water The design of the spent fuel storage pool provides a storage location for approximately 140 percent of, the full core load of fuel assemblies in the reactor building which ensures adequate shielding, cooling, and reactivity control of irradiated fuel. An analysis has been performed which shows that a water level at or in excess of eight and one-half feet over the top of the stored assemblies will provide shielding such that the maximum calculated radiological doses do not exceed the limits of 10 CFR 20.

The normal water, level provides 14-1/2 feet of additional water shielding.

The capacity og the sk$ ~er'urge tanks is avai,lable to maintain the pater level at its normal height for three days in, the absence of additf,onal water input from the condensate storage tanks. All penetrations of the fuel pool have been installed at such a height that their presence does not provide a possible drainage route that could lower the normal water level more than one-half foot.

311

3.10.C BASES The fuel pool cooling system is designed to maintain the pool water temperature less than 125'P during normal heat loads. Xf the reactor core is completely unloaded when the pool contains two previous discharge batches, the temperature may increase to greater than 125'P.

The RHR system supplemental fuel pool cooling mode will be used under these conditions to maintain the pool temperature to less than 125'P.

3.10.D/4.10.D BASES Reactor Buildin Crane The reactor building crane and 125-ton hoist are required to be operable for handling of the spent fuel in the reactor building. The controls for the 125-ton hoist are located in the crane cab. The 5-ton has both cab and pendant controls.

A visual inspection of the load-bearing hoist wire rope assures detec-tion of signs of distress or wear so that corrections can be promptly made if needed.

The testing of the various limits and interlocks assures their proper operation when the crane is used.

3.10.E 4.10.E S ent Puel Cask The spent fuel cask design incorporates removable lifting trunnions.

The visual inspection of the trunnions and fasteners prior to attach-ment to the cask assures that no visual damage has occurred during prior handling., The trunnions must be properly attached to the cask for lifting of the cask and the visual inspection assures correct installation.

3.10.F S-.cnt i'ucl (:ask ))andlinr. - H fuelin.~ F3oor A'.tho -h sin.",lc failure prot.ection has been provided in the dcsit~n of the 125-ton hoist drum shaft, wire ropes, hook and lowe" block 'assembly on .he reactor building crane, the limiting of lift hei);ht of a spen%

fue'ask controls the amount of energy available in a dropped cask accident when the cask is over thc cfuclin fioor.

An an 'ysis has been m de which shows 4ha4 thc f3oor and support members in the area of cask ent y into the decontamination facility can sati-factorily sustain a dropped cask from a height of 3 feet.

The yoke safety links provide single failure protection for the hook and 3ower bloc) ~sscm¹y and limit cask rotation. Cask:otation is necess ry for decontamina ion and the safety links are removed din in@

decontamination.

313

A. Refuelin Interlocks Complete functional testing of all refueling interlocks before any refueling outage will provide positive indication that the interlocks operate in the situations for which they were designed. By loading each hoist with a weight equal to the fuel assembly, positioning the refueling platform, and withdrawing control rods, the interlocks can be subjected to valid operational tests. Where redundancy is provided in the logic circuitry, tests can be performed to assure that each redun-dant logic element can independently perform its function.

B. Core Monitorin Requiring the SHM's to be functionally tested prior to any core altera-tion assures that the SEC's will be operable at the start of that altera-tion. The daily response check of the SHM's ensures their continued operability.

REFl."RhNCL'S

1. Fuel 'Pool Cooling and Cleanup System (BFNP FSAR Subsection 10.5)

2. Spent Fuel Storage (BFNP FSAR Subsection 10.3) 314

LIMITING CONDXTXONS FOR OPEPWTXON SURVEXLLANCE REQUXRENENTS

<I. 1 1 FIRE pRti't'r AT()N '!iY'st't'Hs A~lica~bilit A licabilit Applies to operating status of the high pressure water and CO, Applies to the surveillance fire protection systems for the requirements of the high reactor bui1ding, diesel pressure water and CO~ fire generator buildings, control protection systems for the bay, intake pumping station, reactor building, diesel cable tunnel to the intake generator buildings, control pumping station, and the fixed bay, intake pumping station, spray syst m for cable trays 'cable tunnel to the intake along the south wall of. the pumping station, and the fixed turbine buildng, elevation 586. spray system for cabl trays ilong t.h. oiit.n w<ill of the t;uibiiii. hiii litiiur, 1( v;it'ion 586 when the corresponding limiting

~ob activ conditions for operation are in effect.

To assure availability of Fire Pro" ec tion Sy stems. Ob ective:

Speci f.ica tion: To verify the operability of the Fire Protection Systems.

Hi h Pres .ure F.ire Protection S stem S 'ecification:

The High Pressure A Hi h Pressure Fire Fire Protection Protection S stem System shall have:

High Pressure Fire av Two (2) high Protection System pressure fire Testing:

pumps op. r;ibl<:

arid a signed t.o Pre uenc" the high pressure fire a. Simulat ed Once/year head r. automatic and manual

b. Automatic actuation of initiation logic high pressure operable. pumps

b. Pump Once/month Cperability

c. Automatic Once/3 valve months operability

d. Pump Once/3 capability years 315

LIMITING CONDITIONS FOR OPEPATION SURVEILLANCE REQUXREMENTS 3 1 1 FIRE PROTECTION SYSTEMS 1 1 FXRE PROTECTXON SYSTEMS checked to be 2664 gpm at 250 feet head

e. Spray Once/year header and nozzle inspection for blockage t.'. System Twice/year flush in conjunction with semi-annual addition of biocide to the Raw Cooling Water System

g. Building Once/3 hydraulic years performance verification

h. Yard loop Once/year and cool-ing tower loop hydraulic performance verification 316

LItlITXNG CONDITIONS FOR OPERATXON SURVEILLANCE REQUIRKIENTS

3. 1 1 FXRE PROTECTION SYSTEMS 0. 1 1 FXRE PROTECTXON SYSTEMS

2. If specification 2. When it is determined that only one pump is 3.11.A.1.a or

3. 11.A. l. b cannot he operable, that pump met, a patrolling shall be demonstrated fire watch wi t:h operable immediately portable f ire and daily thereafter equipment available until specification shall be establish d 3.11.A 1 a can be to insure that eac'n met.

area where protection is lost is checked hourly. 3. Raw Service Water

3. If only one high S stem Testin pressure fire pump is operable, the Item Frecruenc .

reactors may remain Simulated Once/yea-in operation for a automatic period not to exceed and manual 7 days, provided the requirements of ac tua tion speci f ica tion of raw service 3.11.A.1.b above are water pumps and me t. operation of tank level Xf specification swit:ches 3.11.A.3 cannot be The high pressure met, the reactor fire protection shall b placed in system pressure shall the cold shutdown be logged daily.

condition in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. 5. Principal header and Removal of any component isolation component in the High valves shall be Pressure Fire System checked open at from service for any intervals no greater reason other than than three months.

testing or emergency operations shall require Plant Superintendent approval.

6. The Raw Service Water storage tank level shall be maintained above level 723'7" by the raw service water pump s 317

LI51ITING CONDITIONS FOR OPEPATION SURVEILLANCE REQUIREMENTS

3. 1 1 FIRE PROTECTION S YSTEi4!S 4. 1 1 FIRE PRCTECTION SYSTEMS

7. If specification be 3.11.A.6 cannot met a fire pump shall be started and run continuously until the raw service water pumps can maintain a raw service water storage tank level above 723'7".

8. L'he fire protection water distribution system shall have a minimum capacity of 2664 gpm at 250'ead.

9. The i f re pro tee tion system shall be capable of supp'lying the individual loads listed in Table

3. 11.A.

318

LIMXTXNG CONDITIONS FOR OPEPATION SURVEILLANCE REQUIREMENTS

3. 1 1 FXR} l>ROT i:( TlON 'i Y.'i'l.'EMS rr. 1 1 FIRE PROTECTION SYSTEMS 0'.

CO z Fire Protection Sv tern B. CO~ Fire Protection S stem.

1. The CO~r Fire Protectiorr System CO< Fire Protection shall be operable: Testing:

a0 With a minimum I tern Fr~euen~c of 8-1/2 tons (0. 5 Tank) CO d Once/yea r in storage units a utoma txc 1 and 2. and manual actuation

b. With a minimum of 3 tons (0 5 b. Storage Checked Tank) CO<. tank dai ly storage unit 3. pressure and level

c. hutomaU.c initiation 'ogic d. CO~ Spray Once/3 operable. header and years nozzle

2. If specification inspection for 3.11.8.1.a or blockage 3.1.1.B.1.b or

3. 11. B. 1. c cannot be 2. When the cable met, a patrolling spreading room CO>

fire watch with Fire Protection is portable fire inoperable, one 125-equipment shall be pound (or larger) established to ensure portable fire that each area where extinguisher shall be protection is lost is placed at, each checked hourly. entrance.

3. If specifications

3. 11. B. 1. a, 3.11; B. 1.b, or 3.11.B.1.c ace not met within 7 days, the a ffected unit (s) shall he in cold shutdown within 2rr hours.

3)9

LIMITING CONDITIONS FOR OPEPWTION SURVEILLANCE REQUIREMENTS 3 1 1 FIRE PROTECTION SYSTEMS'. 11 FIRE PROTECTION SYSTEMS I f CO> fi re protec~tion is lost to a cable spreading room or to any diesel generator building area a continuous fire watch shall be established immediately and shall be continued until CO< fire protection is restored.

5. Removal of any component in the CO<

'Fire Protection System from service for any reason other

. than testing or emergency operations shall require Plant Superintendent approval.

C Fire Detectors C. Fire Detectors

'1 ~

I o The fire detection All heat and smoke system'eat. and detectors shall be smok >t d~.t'rc tot s f'<) t test:ed i.n accordance a I L pro t uc to<'J z ')n( ~

with industrial shall be operable standards or other except that one approved methods detector for a given semiannually.

protected zone may be

,inoperable for a 2. The non-Class A period no greater supervised detector than 30 days. circuitry for those

2. If specification detectors which

3. 11. C. 1 cannot be provide 'alarm only met, a pa trolling will be tested onc fire watch will be each month by established to ensure actuating the that each protected detector at the end zone or area with of the line or end of inoperable detectors the branch such that is checked at the largest number of intervals no greater circuit conductors t'h ill ()ni ich hour wil.l b>> checked.

320

LIMITING CONDITXONS FOR OPEPATION SURVEILLANCE REQUIREMENTS

3. 11 FIRF. PBOTFCTTON . Y.. TENS 4. 1 1 FIRE PROTECT ION SYSTEMS

3. The class A.

supervised detector alarm circuit will be tested once each two months at the local panels.

The circuit" between the local panels in Q. 11. C. 3 and the main control room will be tested monthly.

5. Smoke detect or sensitivity will be checked in accordance with manufacturer's instruction ann'ually.

D. A roving fire watch will D. A monthly walk-through by tour each area in which the Safety Engineer will autnm.gati c fito re uppression be made to visually systems are be inspect the plant fire installed (as described in protection system for the "Plan for Evaluation, signs of damage, Repair, and Return to deterioration, or abnormal Service of Brnwns Ferry conditions which could Units 1 and 2,"Section X) jeopardize, proper at intervals no greater operation of the system.

than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. A keyclock recording type system shall be used to monitor the routes of the roving fire watch. The patrol will be discontinued as the automatic suppression systems are installed and made operable for each specified area.

321

LIMITING CONDITIONS FOR OPEPATION SURVEILLANCE REQUIREMENTS

3. 11 FIRE PROTECTION SYSTEMS Q. 11 FIRE PROTECTION SYSTEMS Fir Protection S stem E. Fire Protection S stems Insaection An independent f ire Any insoection or audit protection and loss will review and evaluate prevention inspection the effectiveness of fire and audit shall be prevention and protection performed annually by physical inspection of utilizing either plant facilities, systems, qualified TVA and equipment as r.elated personnel o" an to fire safety.

outside fire Evaluations will be made protection firm. of, but not -necessarily limited to, the following:

2. An inspectionand audit by an outside Administrative control qualified fire documentation, maintenance consultant will be of fire related records, performed at physical plant inspection, intervals no greater relat d histor'cal than 3 years. (The research and application, first inspection and and management interviews.

audit will be during the period of JUne September 1977. )

F. If it becomes necessary to breach a fire stop, an attendant shall be posted on each gide of the open penetratiun until work is completed and the penetration is re sealed.

G. The minimum in-plant fire protection organization and duties shall be as depicted in Figure 6.3-1.

322

LIffITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS

3. 1 1 FIRE PROTECTION S YSTEMS 4. 1 1 FIRE PROTECTION SYSTEMS e

H. A minimum of fifteen air masks and thirty 500 cubic inch air cylinders shall be available at all times except that a time period of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> following emergency use is allowed to permit recharging or replacing.

A continuous f ire watch shall be stat'ioned in the immediate vicinity where work involving open flame welding, or burning is in progress.

There shall be no use of open flame, welding, or burning in the cable spreading room unless the reactor is in the cold shutdown'ondition.

323

TABLE 3. 11. A FIRE PROTECTION SYSTEM HYDRAULIC REQUIREMENTS Flow Required Residual Pressure Station pm S3.g

.l. Reactor Building Roof A. Valve 26-849 200 65 B. Valve 26-889 . 200 65 2.. Refuel Floor A. Valve 26-835 75 70 B. Valve 26-843 75 70 C. Valve 26-870 75 70 D. Valve 26-865 75 70 E. Valve 26-876 75 70 F. Valve 26-888 75 70 G. Valve 26-898 75 70

3. Cable Tray Fixed Spray A. Unit 1 Station I 300 70 B. Unit 1 Station II 200 70 C. Unit 1 Station III X80 65 D. Unit 2 Station II 200 70 E. Unit 2 Station 1II 200 70 F. Unit 3 Station II 200 70 G. Unit 3 - Station III 265 75 H ~ Turbine Building 30 55

4. Diesel Generator Buildings A. Valve 26-1032 75 70 B. Valve 26-1069 75 70

5. Pump Intake Station A. Valve 26 -578 70

TABLE 3.11.A FIRE PROTECTION SYSTEM HYDRAULIC REQUIREMENTS Flow Required Residual Pressure Station gpttt ps3.g 6, Control Bay 75 70 A. Valve 26-1076

7. Yard Loop (1)

A. Hydrant at valve 0-26-526 500 65 B. Hydrant at valve 0-26-530 500 65

8. Cooling Tower Loop A. Hydrant at valve 0-26-1023-6 500 65 Not:e (1) Yard hydra.its and the cooling tower hydrant are to be tested using the longest na t.h for f.low.

3.11 BASES The High Pressure Fire and CO> Fire Protection specifications are provided in order to meet the preestablished levels of operability during a fire in either or all of the three units.

Requiring a patrolling fire watch with portable fire equipment the automatic initiation is lost will provide (as does the if automatic system) for early reporting and immediate fire fighting capability in the event of a fire occurrence.

The High pressure Fire Protection System is supplied by three pumps aligned to the high pressure fire header. The reactors may remain in operation for a period not to exceed 7 days if two pumps are out of service. If at least two pumps are not made operable in seven days or if all pumps are lost during this seven day period, the reactors will be placed in, the cold shutdown condition witt.in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

For the areas of applicability, the fire prot ction water distribution system minimum capacity of 2664 gpm at 250'ead at the fire pump discharge consists of the following design loads:

1. Sprinkler System (0. 30 gpm/f tz/4440 ftz area) 1332 gpm

2. 1 1/2" Hand Hose Lines 200 gpm

3. Raw Service Water Load 1132 cram TOTAL 2664 gpm The CO~ Fire Protection System is considered op rable with a minimum of 8 1/2 tons (0. 5 tank) CO z in storage or units 1 and 2; and a minimum of 3 tons (0.5 tank) CO> in storage for uni 3.

An immediate and continuous fire watch in the cable spreading room or any diesel generator building area will be established fire protection is lost in this room and will continue until if CO, CO, fire protection is restored.

To assure close supervision of fire protection sys=em activities, the removal from service of any component in eit..er the Hian Pressure Fire System or the CO~ Fire Protection Svstem or any reason other than testing or emergency operations will require Plant Superintendent approval.

Early reporting and immediate fire fighting capability in the event of a fire occurrence will be provided (as with the automatic system) by requiring a patrolling f i"e watch than one detector for a given protected zone is inoperable.

if more A roving fire watch for areas in which automatic =ire suppression systems are to be installed will provice additional interim fire protection for areas that hav been determined to need add'ional pro" ection.

326

The fire protection system is designed to supply the required flow and pressure to an individual load listed on Table 3.11.A while maintaining a design raw service water load of 1132 gpm.

4. 1 1 BASES Periodic testing of both the High Pressure Fire System and the CO~

Fire Protection System will provide positive indication of their operability. Xf only one of the pumps supplying the High Pressure Fire System is operable, the pump that is operable will be checked immediately and daily thereafter to demonstrate operability. If the CO~. Fire Protection System becomes inoperable in the cable spreading room, one 125-pound (or larger) fire extinguishere will be placed at each entrance to the cable spreading room.

Wet fire header flushing, spray header inspection for blockage, and nozzle inspection for blockage will prevent, detect, and remove buildup of sludge or other material to ensure continued oper'ability. System flushes in conjunction with the semiannual addition of biocide to the Raw Cooling Water System will help prevent the growth of crustaceans which could reduce nozzle discharge.

Semiannual tests of heat and smoke detectors are in accordance with the NFPA code.

with the exception of continuous strip heat detectors panels, all non-class A supervised detector circuits which provide alarm only are hard'wired through conduits and/or cable trays from the detector to the main control room alarm panels with no active components betw en. Non-class A circuits also actuate the HPCI water-fog system, the CO< system in the dj.esel generator buildings, and isolate ventilation in shutdown board rooms. The test frequency and methods specified are justified for the following reasons:

1. An analysis was made of worst-case fire detection circuits at Browns Ferry to determine the probability of no undetected failure of the circuits occurring between system test times as specified in the surveillance requ:.rements. A circuit is defined as the wire connections and components that affect transmission of an alarm signal between the fire detectors and the control room annunciator. Three circuits were analyzed which were repres('ntltive of an <<larm-only circuit, a water-fog circuit, and a CO~ circuit. The spreading room B smoke detector was selected as the worst-case alarm-only circuit because it had the largest number of wires and connections in a single circuit. The HPCI water-fog circuit was selected for analysis because it is the only water-fog circuit in the area of applicability for technical specifications. The Standby Diesel Generator Room A CO, 327

circuit was select'ed because it contained 2 out of 3 detector most complicated CO, circuit logic. Calculations logic, the were based on failure rates for wires, connections, and circuit componerrts as shown in Appendix XXI of WASH-1400.

Failure rates w re considered for the following circuit components:

1. Open circuit

2. Short to ground

3. Short to power

4. Timing motor failure to start

5. Relay failure to energize

6. Normally open contact, failure to close

7. Normally open or normally closed contact short.

8. ,Normally closed contact opening

9. Timing switch failure to transfer The calculated probabilities (Pf) for no undetected failure of the circuits occurring were as follows, based on the specified test frequency.

AREA TEST FREQUENCY Spreading Room B One Month 0.975287 HPCI Water Fog Six Months 0. 977175 Standby Diesel Gen Room A CO~ Six Months 0.957595 The worst case of the three areas considered is Spreading Room I'. The probability of undected failure is approximately 1/40, which means that one undetected failure will occur on the average every 40 months over an extended period of time and that the failure could exist up to one month. The frequency of testing is thus much greater than the'requency of failure and produces circuits with adequate reliability.

2. Circuits checks by initiation of end of the line or end of the branch detectors will more thoroughly test the parallel curcuits than testing on a rotating detector basis. This test is not a detector test, but is a test to simulate the effect of electrical supervision as defined in the NFPA code

3. Testing of circuits which ac'quate CO< , water, or ventilation sys ems requires disabling the automatic feature of the fire protection system for the area. A surveillance program which disabled these circuits monthly would significantly reduce the ability of these circuits to provide fire suppression.

+Ref. NFPA Code 720-9, paragraph 1111, Code 72D-15, paragraph 1312 for def inition of Class A systems, and Code 72A-1d, Article 240.

328

Daily tests of annunciation lights and audible devices are performed as a routine operation function.

5. The cO>, system manufacturer recommends semiannual testing of CO~ system fire detection circuits.

Figure 6. 3-1 describes the in-plant fire protection organization including the roving fire watch. Xn addition, other operating personnel periodically inspect the plant during their normal operating activities for fire hazards and other abnormal conditions.

Smoke detectors will be tested "in-place" using inert freon gas applied by a pyrotronics type. applicator which is accepted throughout the industrial fire protection industry for testing products of combustion detectors or by use of the blSA chemical smoke generators. At the present time the manufacturers have only approved the use of "punk" for creating smoke. TVA will not use "punk" for testing smoke detectors.

329

S.O HAUOR OFSFOV FEATURES

5. I SITE FEATt)RES Growns Ferry unit. l is located at Srowns Ferry Nuclear Plant site on property owned by the United States and in custody of thc TVA.. The site shall consist of'pproximately 840 acres on the north shore of Wheeler Lake at Tennessee River Rile 294 in Limestone County, Alabama. The minimum distance from the outside of the secondary containment building, to the boundary of the exclusion area as defined in 10 CFR 100.3 shall be 4,000 feet.

5' REACTOR AD The core shall consist of 764 fuel assemblies

,of 49 fuel rods each.

B. The reactor core shall contain 185 cruciform-shaped control rods. The control material shall be boron carbide powder (B4C) compacted to approximately 70 percent of theoretical density.

5.3 REACTOR VESSEL The reactor vessel shall be as described fn Table 4.2-2 of the FSAR. The applicable design codes shall be as described in Table 4.2-1 of the FSAR.

5. 4 CONTA IN.'(EiVT A. The principal design parameters for thc primary containment shall bc as given in Table 5.2-1 of the FSAR. The applicable design codes shall be as described in Section 5.2 of thc FSAR.

B ~ The secondary containment shall be as described in Section

5. 3 of the FSAR.

0 C. Pcnetratione to the primary containment and piping passing, through such penetrations shall be designed in accordance with the standards set forth in Section 5.2.3.4 of the FSAR.

5.5 FUEL STORAOE A. The arrangement of fuel in the new-fuel storage facility shall be such that k ff, for dry conditions, is less than 0.90 and flooded is fess than 0.95 (Section 10.2 of FSAR).

330

5.0 HAJOR DFSIGH FEATVRL'S (Continued)

B. The k ff of the spent fuel storage pool shall be less than or equal to 0.90 for normal conditions and'.95 for abnormal conditions (Sections 10.3 of the FSAR).

5.6 SVIS~LC ngsZCN Thc station class I structures and systems have been designed to withstan<l a design basis earthquake arith ground accelera-tion of 0.2g. Thc operational basis earthquake used in the plant design assumed a ground acceleration of O.lg (see Section 2.5 of the FSAR).

331

6 0 'DMINISTRATIVE CONTROLS 6.1 OrcCanizatian The plant superintendent has on-site responsibility for the safe'peration of the facility and shall report to the Chief, Nuclear Generation Branch. In the absence of the plant superintendent, the assistant superintendnet will assume his responsibilities.

B. The portion of TVA management which relates to the operation of the plant is shown in Figure 6.1-1.

C. The functional organization for the operation of the station shall be as shown in Figure 6. 1-2.

D. Shiit manning requirements shall, as a minimum, be as described in section 6.8.

E. Qualifications of the Browns Ferry Nuclear Plant management and operating staff shall meet the minimum acceptable levels as described in ANSI - N18. 1, Selection and Training of Nuclear Power Plant Personnel, dated March 8, 1971.

F. Retraining and replacement training of station personnel shall be in accordance with ANSI - N18.1, Selection and Training of Nuclear Power Plant Personnel, dated March 8, 1971. The minimum frequency of the retraining program shall be every two years.

G~ An Industrial Security Program shall be maintained for the life of the plant.

H. Responsibilities of a post-fire overall restoration coordinator will consist of duties as described in section 6.9.

The Safety Engineer shall have the following qualifications:

a ~ Must have a sound understanding and thorough technical knowledge of safety and fire protection practices, procedures, standards, and other codes relating to electrical utility operations. Must be able to read and understand engineering drawings. Must possess an analytical ability for problem solving and data analysis.

Must be able to communicate well both orally and in writing and must be able to write investigative reports and prepare written procedures. Must have the ability to secure the cooperation of management, employees and groups in the implementation of safety programs. Must be able to conduct safety presentations for supervisors and employees.

b. Should have experience in safety engineering work at this level or have 3 years experience in safety and/or ire protection engineering. It is desirable that the incumbent be a graduate of an accredited college or university with a degree in inductri al, mechanical, electrical, or safety engineering or fire protection engineering.

6 0 ADMINISTRATIVE CONTROLS 6.2 Review and Audit The Manager of Power is responsible for'he safe operation of all TVA power plants,-including the Browns Ferry Nuclear Plant. The functional organization for Review and Audit is shown in Figure 6.2-1.

Organizational units for the review of facility operation shall be constituted and have the responsibilities and authorities listed below.

A. ,Nuclear Safet Review Board NSRB The NsRB shall consist of a chairman and at least five other members appointed'r approved by the Manager of Power. A majority of the members shall be independent of the Division of Power Production.

The qualifications of members shall meet the requirements of ANSI Standard N18.7-1972.

Membership shall include at least one outside consultant and representatives of the following TVA organizations: Office of Engineering Design and Construction; Division of Environmental Planning; Division of Power Production; Division of Power Resource Planning. An alternate chairman may be designated by the chairman or, in his absence or inCapacity, may be selected by the NSRB. The NSRB chairman shall appoint a secretary.

2. Minimum Meetin Fre uen The NSRB shall meet at least quarterly and at more frequent intervals at the call of the chairman, as required.

3~ uorum A quorum shall consist of four members, a minority f

o which s hall be rom Production.

f the Division o f Power 4~ Res nsibilities a ~ Review proposed tests 'and experiments, and their results, when such .tests or experiments may constitute an unreviewed safety question as defined in Section 50. 59, Part 50, Title 10, Code of Federal Regulations.

b>> Review proposed changes to equipment, systems or procedures, which are described in the Final Safety Analysis Report or which may involve an unreviewed safety question, as defined in Section 50.59, Part 50, Title 10, Code of Federal Regulations, or" which are referred by the operating, organization.

C>> Review proposed changes to Technical Specifications or licenses.

333

6.O AOMrNrSTRATrVB CONTROr.s

d. Review violations of applicable statutes, codes, regulations, orders, Technical Specif ications, license requirements, or of internal procedures or instructions having safety significance.

e. Review signficant operating abnormalities or deviations from normal and expected performance of plant equipment.

f. Review reportable occur rences, as defined in the Technical Specifications.

Review information received indicating that there may be an unanticipated deficiency in some aspect of design or operation of safety-related systems or components.

h. Review the reports of annual audits of plant operation to verify that operation complies with the terms, conditions and intent of any license, permit, or other applicable regulations.

Review the minutes of Plant Operations Review Committee meetings to determine considered by that committee involve if matters unreviewed or unresolved safety questions.

5. ~Atthorit The Nuclear Safety Review Board shall be advisory to the Manager of Power in matters relating to nuclear plant safety.

The Nuclear Safety Review Board shall have access to all TVA nuclear facilities, as well as design, construction, and operating records as necessary to perform it assigned f unctions.

MemLers have access to advice and services of technical specialists within their respective organizations and outside consulting services are available as required through contractual arrangements.

6. Records The chairman shall prepare a final copy of the minutes and forward them to the Manager of Power.

334

AI)MJ. N I!l'VRA'I'IVI" CONTROL,!i A summary of the more significant discussions and conclusions of the NSRB will be transmitted along with the, final minutes.

7. Charter A written charter delineating the establishment,

'omposition, and mission of the NSRB and the dissemination of NSRB minutes and reports shall be maintained; this may be amended as required. The charter shall identify the responsibility 'and authority of the NSRB in conducting reviews, including responsibility to identify problems and to recommend solutions to the Manager of Power.

B. Plant 0 erations Review Committee PORC The PORC shall consist of the plant superintendent, assistant plant superintendent, maintenance supervisor, health physics supervisor, operations supervisor, power plant results supervisor,, and QA staf f supervisor. An assistant plant supervisor may serve as an alternate committee member when his supervisor is absent.

The plant superintendent will serve as chairman of the PORC. The assistant plant superintendent will serve as chairman in the absence of the plant superintendent.

Meetin Fre uen The PORC shall meet at regular monthly intervals and for special meetings as called by the chairman or as requested by individual members.

3. uorum Superintendent or assistant superintendent, plus four of the five other members, or their alternate, will constitute a quorum. A member will be considered present if he is in telephone communication with the committee.

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6. 0 ADMINISTRATIVE CONTROLS

'l'he k<)HC nerv~s in an advisory rapaci t y to the plant superintendent and .ss at> investigating and reporting body to the Nuclear Safety Review Board in matters related to safety in plant operations.

The plant superintendent has the final responsibility in determining the matters that should be referred to the Nuclear Safety Review Board.

The responsibility of the committee will include:

Review all standard and emergency operating and maintenance instructions and any proposed xevisions thereto, with principal attention to provisions for safe operation.

b. Review porposed changes to the Technical Specifications.

c Review proposed changes to equipment or systems having safety significance, or which may constitute "an unreviewed safety question,<<pursuant to 10 CFR 50.59.

d. Investigate reported or suspected incidents involving safety questions, violations of the Technical Specificati."ons, and violations of plant instructions pertinent to nuclear safety.

e. Review reportable occurrences, unusual events, operating anomalies and abnormal performance of plant eouioment.

Maintain a general surveillance of plant activities'o identify possible safety hazards.

gi Review plans for special fuel handling, plant maintenance, operations, and tests or experiements which may involve special safety considerations, and the results thereof, whexe applicable.

h. Review adequacy of quality assurance program and recommend any appropriate change -.

Review implementating procedures of the, Radiological Emexgency Plan and the Industrial Security Program on an annual basis.

336

6. 0 ADilINISTRATIVF'ONTROLS

j. R'eview adequacy of employee and recommend change.

training programs

5. ~Auttorit The PORC shall be advisory to the plant superintendent.

6. Records Minutes shall be kept for all PORC meetings with copies sent to Director, Power Production; Chief, Nuclear Generation Branch; Chairman, NSRB.

7. Procedures Written'dministrative procedures for committee operation shall be prepared and maintained describing the method for submission 'and content of presentations to the committee, review and approval by members of committee actions, dissemination of minutes, agenda and scheduling of meetings.

C. alit Assurance and Audit Staf The Office of Power Quality Assurance and Audit Staff (QACAS) shall formally audit operation of the nuclear plant. Audits of selected aspects of plant operations shall be. con'ducted on a frequency commensurate with their safety significahce and in such a manner as to assure that an audit of safety-related activities is completed within a period oz two years.

The audits shall be performed in accordance with appropriate written instructicns or procedures and should include verification oz compliance with internal rules, procedures (for example, normal off/normal, emez gency, operating, maintenance, surveillance, test, security, and radiation control procedures and the emergency plan), regulations, and license provisions; training, qualification, and performance of operating staff; and corrective actions following pepppt;ab]e occurr ences.

337

6 0 A INXSTRATZVE CONTROLS A Detailed written procedures, including applicable check-off li'sts covering items listed below shall be prepared, approved and adhered to.

1. Normal startup, operation and shutdown of the reactor and of all systems and components involving nuclear safety of the facility.

2. Refueling operations.

3. Actions to be taken to correct specific and foreseen potential malfunctions of systems or components, including responses to alarms, suspected primary system leaks and abnormal reactivity changes.

0. Emergency conditions involving potential or actual release of Radioactivity.

5. Preventive or corrective maintenance operations which could have an effect on the safety of the reactor.

6 Surveillance and testing requirements.

7. Radiation control procedures.

8. Radiological Emergency Plan implementing procedures.

9. Plant security program implementing procedures.

10. Pire protection and prevention procedures.

Written procedures pertaining to those items listed R

B, above shall be reviewed by PORC and approved by the plant superintendent prior to implementation. Temporary changes to a procedures which do not change the intent of the approved procedure may be made by a member of the plant staff knowledgeable in the area affected by the procedure except that temporary changes to those items listed above except item 5 require the additional approval of a member of the plant staff who holds a Senior Reactor Operator license on the unit affected.

Such changes shall be documented and subsequently reviewed by PORC and approved by the plant superintendent.

338

6.0 AD N STRATXVE CONTROLS C Drills on actions to be taken under emergency conditions involving release of radioactivity are specified in the radiological emergency plan and shall be conducted annually. Annual drills shall also be conducted on the actions to be taken following failures of safety related systems or components.

D. Radiation Control Procedures Radiation Control Procedures shall be maintained and made available to all station personnel. These procedures shall show permissible radiation exposure and shall be consistent with the requirements of 10 CPR 20.

This radiation protection program shall be organized to meet the requirements of 10 CFR 20 except in lieu of the "control device" or "alarm signal" required by paragraph 20.203(c) (2) of 10 CFR 20:

1. Each High Radiation Area in which the intensity of radiation is greater than 100 mrem/hr but less than 1,000 mrem/hr shall be barricaded and conspicuously posted as a High Radiation Area, and entrance thereto shall be controlled by issuance of a special work permit. Any individual or group of individuals permitted to enter such areas shall be, provided with a radiation monitoring device which continuously indicates the radiation dose rate in the area.

2 ~ Each High Radiation Area in which the intensity of radiation is greater than 1,000 mrem/hr shall be subject to the provisions of (a) above; and, in addition, locked doors shall be provided to prevent unauthorized entry into such areas, and the keys shall be maintained under administrative contr'ol of the shift engineer on duty.

3 Pursuant to 10 CFR 20.103 (c) (1) and (3), allowance can be made for the use of respiratory protective equipment in con)unction with activities authorized by the operating license for this plant in determining whether individuals in r'estricted areas are exposed to concentrations in excess of the limits specified in Appendix B, Table I, Column 1 ~

of 10 CFR 20, sub) ect to the following condition and limitations:

a. The limits provided in section 20.103(a) and (b) are not exceeded.

339

6~0 AHRI ISTRA Z CONTR LS b If the radioactive material is of such form that intake through the skin or other additional route is likely~ individual exposures to radioactive material shall be controlled so that the radioactive content of any critical organ from all routes of intake averaged over 7 consecutive days does not exceed that which would result from inhaling such radioactive material for 00 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> at the pertinent concentration values provided in Appendix B, Tab,e I, Column 1 of 10 CPR 20.

co For radioactive materials designed "sub" in the "Isotope" column of Appendix 3, Table I, Column 1 of 10 CFR 20, the concentration value specified is b~sed upon exposure to the material as an external radiation source.

Individual exposures to these materials shall be accounted for as part of the limitation on individual dose in 20.101. These materials shall be subject to applicable process and other engineering controls.

In all operations in which adequate limitation of the inhalation of radioactive'aterial by the use of process or other engineering controls is impracticable, the licensee'may permit an individual in a restricted area to use respiratory protective equipment to limit -the inhalation of airborne radioactive material, provided:

a ~ The limits specified in paragraph 1 above are not exceeded.

b Respiratory protective equipment is selected and used so that, the"'peak concentrations of airborne radioactive material inhaled by an individual wearing the.equipuent does not exceed the pertinent ooncentratiae'alues specified in Appendix 8, Table I, Column 1, of 10 CPR 20

~r the purposes of this subparagrpah, the concentration of radioactive material that is inhaled when respirators are worn may be determined by dividing the anbient airborne concentration by the protection factor specified in Table 16.3.A, appended to this specification for the respirator protective equipment worn. If the intake or radioactivity is later determined by other miasureiaents to have been different than that 340

6 .0 ADMIX STRA XVE CONTROLS initially estimated the later quantity shall be used in evaluating the exposures.

Co The licensee advises each respirator user, that, he may leave the area at any time for relief from respirator use in case of equipment malfunction significant physical or psychologic~i discomfort, or any ather condition that might cause reduction in the pratection affarded the wearer.

The licensee maintains a respiratory protective program adequate to assure t)sat the requirements above are met and incorporates practices fo- respiratory protection consistent with those recommended by the American National Standards Institute {ANSI-K88.2-1969) . Such a program shall include:

(1) Air sampling and other surveys sufficient to identify the hazard, to evaluate individual exposuxes, and to permit proper selection of respiratory protective equipment.

(2) Written procedures to assure proper selection, supervision, and training of personnel using such protective equipment.

(3) Written procedures to assure the adequate fitting of respirators; and the testing af respiratory protective equipuent for operability immediately prior to use.

{4) Written procedures for maintenance to assure, full effectiveness of respiratory protective equipment, including issuance, cleaning and decontamination, inspection~

repair, and storage.

{5) Written opertional and ad~inistrative procedures for proper use of respiratcu~

protective 'equipment including provisions for planned limitations on working times as necessitated by operational conditions.

(6) Bioassays and/or whole body counts of individuals (an other surveys, as 341

0 AMXNIST.RATIVE CORPROLS nppr"praite) to evaluate individual eicposures and to assess protection actually provided.

The licensee uses equipment approved by the U.S. Bureau of Hines under its appropriate approval schedH~es as set forth 9x Table 6.3.A bnlo~, P~uipment not, approved under U.S.

Bureau of Nines Approval Schedules may be used only if the licensee has evaluated the equipment and can. demonstrate by testing, or on the basis of reliable test, inionaation, Umt the material and performance characteristics of the equipment are at least equal 4o those afforded by, U.S Bureau of Nines approved equipment of the same specified in Table 6.3.A bein<.

t~, as Unless othervise authorized by the Commission, the licensee Goes not, assign protection factors in excess of those specified in Table 6 3.A helot'n selecting and using rispiratory protective equipment.

"Zne-'e specifications ~ith respect co the provision of 20.103 shall be superseded by adoption of proposed changes to 10 C2% 20, section 20.103, which would make this specification unnecessary.

342

TABLE 6. 3. A PI<OTEC"I'ION FACTORS FOR RESPII(ATOAS PROTECTION FACTOI(S 2/ GUIDES TO SELECTIOtt OF EQUIPMENT DESCIII PTION MODES 1/, PARTICULATES AND VAPORS AND GASES FXCEPT BUAEAV OF MINES APPROVAL SCH}T)ULES>

FOR EQUIPMEttT CAPAIII E OF PI!OVIDING AT I,EAST EQVIVAI.ENI'ROTECTION FAC'IOAS TRITIUM OXIDE 3/ 'or schedule superseding for equipment-of type listed AIR PURIFYING RESPIRATORS Facepiece, half-mask part J

}'acepiece, full PD 1,000 30 CFA l>art 11 Subpart J Hood CI'F 5/ 30 CFR Part 11 Subpart J Sui't 5/ 6/

2. Sel t- conta inc<3 t>r<!a~thin Facepiece, full 7/ D 100 30 CFR Part 11 Subpart H

}'acepiece, full PD 1 ~ 000 30 CFR Part 11 Subpart H Facepiece, full R 1,000 30 CFA Part 11 Subpart H III. CO! IBINATIC)V IIFSPII><'<VAR hny combination of air- Protection factor 30 CFR Part 1 1 )I I. 63 (b) puri f yi ng an<3 a tmosphere- for type and mode supplying respirator of operation as listed above 1/, 2/, 3/, > not more zhan approximately 2 is appropriate when atmosphere-supplying respirators are used to protect against tritium oxide. Air-purifying respi ators are not r ecommended for use against trit'm ox'e. See also foot note 5/, below, concerning supplied-air suits and hoods.

0/ Under chin type only. Not recommended for use wnere it might be possible for the ambient airborne concentration to reach 344

6.0 AONIHISTRATIV:- COUTROLS instantaneous values greater than 5 times the pertinent values in Appendix B, Table I, Column 1 of 10 CFR, Part 20.

5/ Appropriate protection factors must he determined taking account of the design of the suit or hood and its permeability to the containment under conditions of use. No protection factor greater than 1,000 shall be used except as autno ized by the Commission.

6/ Yo aop oval schedules currently available for this equipment.

Equipment must be evaluated by testing or on basis of available 'test information.

7/ Only for shaven faces.

Note 1: Protection factors for respirators, as may b approved by the U.S. Bureau of Mines anc/or hlIOSH according to approval schedules for respirators to protect against, airborne radionuclides, may be used to the extent that they do not exceed the protection factors listed in this table.

The protection factors in this table may not. be appropria"e to circumstances where chemical or other respiratory hazards exist in addition to radioactive hazards. The selection and use of respirators for sucn circumstances should take into account approvals of the U.S. Bureau of Mines and/or NIOSH in accordance with its applicable schedules.

hlote 2: Radioactive contaminants for whicn the concentration values in Appendix B, Table I, of this part are based on int .mal dose due to inhalation may, in addition, present ext mal exposure hazards at higher concentrations- Under such circumstances, limitations on occupancy may have to be governed by external dose limits.

345

6 0 ADAIH ISTRATI VE CONTROLS 6.4 Actions to be Taken in the Event or a Reportable Occurrence in Plant Ooeration Ref. Section 6.7 A. Any reportable occurrence shall be promptly reported to the Chief, Nuclear Generation Branch and shall be promptly reviewed by PORC. This committee shall prepare a separate report for each reportable occurrence. This report shall include an evaluation of the cause of the occurrence and recommendations for appropria e action to prevent or reduce the probability o a repetition of the occurrence.

Copies of all such reports shall be submitted to the Chief, Nuclear Genera" ion Branch, the Manager of Power, the Division of Power Resource Planning, and the Chairman of the NSRB for their review.

C. The plant superintendent shall notify the NRC as specified in Specification 6.7 of the circumstances of any repor able occur ence.

6. 5 Action to be Taken in the =-vent a Sa f et Limit is Exceeded Zf a safety limit is exceeded, tne reactor shall be shut, down and reac" or operation shall not be resumed until authorized by the NRC. A prcmpt report shall be made to the Chief, Nuclear Generation Branch and the Chairman of the NSRB. A complete analysis of the circumstances leading up to and resulting from the situation, together w'h recommendations to prevent a recurrence, shall be prepared by the PORC. This reoort shall be submitted to the Chief, Nuclear Generation Branch, the Manager of Power, the Division of Power Resource Planning, and the NSRB. Noti ication of such occurrences will be made to the NRC by the plan"- superintendent within 24 hou s.

6.6 Station Ooeratina'Reco ds A. Records and/or logs shall be kept in a manner convenient, for review as indicated below:

All normal plant operation including such items as power level, fuel exposure, and snutdowns 2 ~ Principal main" enance activities

3. Reportable occurrences 346

6. 0 ADMINISTRATIVE CONTROLS

4. Checks, inspections, tests, and calibrations of components and systems, including such diverse items as source leakage

5. Reviews of changes made to the procedures or equipment or reviews of tests and experiement to comply with 10 CFR 50.59

6. Radioactive shioments

7. Test results, in units of microcuries, for leak tests performed pursuant to.Specification 3.8.E

8. Record of annual physical inventory verifying accountability of sources on record

9. Gaseous and liquid radioactive waste released to the environs

10. Off-site environmental monitoring surveys

11. Fuel inventories and transfers

12. Plant radia" ion and contamination surveys

13. Radiation exposures for all plant personnel

14. Updated, corrected, and as-built drawings of the plant

15. Reactor coolant system inservice inspection

16. Minutes of meetings or the Nuclear Safety Review Board

17. Design fatigue usage evaluation a ~ Monitoring, recording, evaluating, and reporting requirements contained in 17.b, below will be met fox various portions of the reactor coolant pxessuxe boundary (RCPB) for which detailed fatigue usage evaluation per the ASHE Boiler and Pressure Vessel Code Section III was performed~ for the conditions defined in the design specification. In this

1. See paragraph N-415.2, ASME Section III, 1965 Edition.

347

6. 0 AOi4/I HI STRATI VE CON'ZROLS plant, the applicable codes required fatigue usage evaluation for the reactor pressure vessel only. The locations to be monitored shall be:

1. The feedwater nozz les

2. The shell at or near the waterline

3. The flange studs

b. Recording, Evaluating, and Reporting (1) Transients that occur during plant operations will be reviewed and a cumulative fatigue usage factor determined.

(2) For'transients which a e more severe than the transients evaluated in the stress report, code fatigue usage calculations will be made and tabulated separately.

(3) In the annual Operating Report, the fatigue usage factor determined for the transients defined in (1) and (2) above shall be added and a cumulative fatigue usage factor to date shall be listed.

When the cumulative usage factor reaches a value of 1.0, an inservice inspection shall be included for the specific location at the next scheduled inspection (3-1l3-year interval) period and 3-1/3-year intervals thereafter, and a subsequent evaluation performed in accordance with the rules of ASME Section XI Code if any flaw indications are detected. The results of the evaluation shall be submitted in a Special Report (Section 6.7.3) for review by the Commission.

Except where covered by applicable regulations, items through 8 above shall be retained for a period of at least 5 years and items 9 through 17 shall be retained for the life of the plant. A complete inventory of radioactive materials in possession shall be maintained current at all times.

348

~ .0 AD~I <<i rSTr~TZ VS Com Ror.S 6.7 Reeortin Reauirements In addition to the applicable reporting requirements of Title 10, Code of Federal Regulations, the following identified repor" s shall be submitted to the Director of the appropriate Reqional Office of Inspection and Enforcement unless otherwise noted.

Routine Reports a Startu Report. A summary report of plant startup and powe escalation testing shall be submitted following (1) receipt of an opexating license, (2) amendment to the license involving a planned increase in power level, (3) installation of fuel that has a different design or has been manufactured by a dif erent fuel supplier, and (4) modifications that may have signi icantly altered the nuclear, thermal, or hydraulic performance of the plant The report shall addr'ess each of the tests identified in the FSAR and shall in general include a description of the measured values of tne operating conditions or characteristics obtained during the test program and a comparison of these values with design predictions and specifications.

Any corrective actions that were required to obtain satisfactory operation shall also be described.

Any additional specific details required in license conditions based on other commitments shall be included in this report.

Startup reports shall be submitted witnin (1) 90 days following completion of the staxtup test program, (2) 90 days -following resumption or commencement of commercial power operation, or (3) 9 months following initial criticality, whicheve is earliest. If the Startup Report does not cover all three events (i.e., initial criticality, completion of startup test program, and resumption or commencement of commerical;)ower operation),

supplementary reports. shall be submitted at least every three months until all three events have been completed.

b. Annual Ooerat na Report. ~ Routine operating reports covering the ooeration of the unit during the previous calendar year shall be submitted prior to March of each year. The initial report shall 1

be submit ed prior to March 1 of the year following intial criticality.

6, 0 ADMINISTRATIVE CONTROLS The annual operating reports made by 'licensees shall provide a comprehensive summary of the operating experience gained during the year, even though some repetition of previously reported information may be involved. References in the annual operating report to previously submitted reports shall be clea Each annual operating report shall include:

(1) A narrative summary of operating expe ience during the report period relating to safe operation of the facility, including safety-related maintanance not covered in item

1. b. (2) (e) below.

(2) For each outage or forced reduction in power~

of over twenty percent of design power level where the reduction extends for greater than four hours:

(a) the proximate caUse and the system and major component involved (i the outage or forced reduction in power involved equipment malfunction);

(b) A brief discussion of (or reference to reports of) any reportable occurrences pertaining to the outage of power reduction; (c) corrective action taken to reduce the probability of recurrence, appropriate; if (d) operating time lost as a result of the outage or power reduction (for scheduled or forced outages,~ use the generator off-line hours; for forced reductions in power, use the approximate duration of operation at reduced power);

(e) a description of major safety-related corrective maintenance performed during the outage or power reduction, including the system and component involved and identification of the critical path activity dictating the length of the outage or power reduction; and 350

6. 0 AD.iINISTRATIVE CONTROLS (f) a report of any single release of radioactivity or radiation exposure specifically associated with the outage which accounts for more than 10% of the allowable annual values.

(3) A tabulation on an annual basi" of the number of station, utility and other personnel.

(including contractors) receivinq exposures greater than 100 mrem/yr and their associated man rem exposure according to work and job functions,'.g., reactor operations and surveillance, inservice inspection, routine maintenance, special maintenance (describe maintenance), was"e processing, and refueling.

The dose assignment to various duty functions may be estimates based on pocket dosimeter, TLD, or film badge measurements. Small exposures totalling less than 20% of the individual total dose need not be accounted for. In the aggregate, a" least 80'X of the total whole body dose received from external sources shall be assigned to specific major work functions.

(4) Indications of failed fuel resulting from irradiated fuel examinations, including eddy current tests, ultrasonic tests, or visual examinations completed during the report period.

c Monthl 0 erati n Re ort. Routine reports of operating statistics and shutdown experience shall be submitted on a monthly basis to the Office of Inspection .and Enforcement, U.S. Nuclear Regulatory Commission, Washington, C.C. 20555, with a copy to the appropriate Regional Office, to be submitted no later than the tenth of each month following the calendar month c'overed by the report.

2 ~ Reportable Occurrences Reportable occurrences, including corrective actions and measures to prevent reoccurrence, shall bn reported to the NRC. Supplemental reports may be required to fully describe final resolution of occurr nce. In case of corrected or supplemental reports, a licensee event report shall be completed and reference shall be made to the original report date.

351

6. 0 ADMINISTRATIVE CONTROLS a ~ Prom t Notification With Written Followuo. The types of events listed below shall be reported as expeditiously as possible, but within 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> by telephone and confirmed by telegraph, mailgram, or facsimile transmission to the Director of the appropriate Regional Office, or his designate no later than the first working day following the event, with a written followup report within two weeks. The written followup report shall include, as a minimum, a completed copy of a licensee event report form. Information provided on the licensee event report form shall be supplemented, as needed, by additional narrative material'o provide complete explanation of the circumstances surrounding the event.

(1) Failure of the reactor protection system or other syst'ems subject to limiting safety system settings to initiate the required protective function by the time a monitored parameter reaches the setpoint specified as the limiting safety system setting in the technical specifications or failure to complete the required protective function.

Note: Instrument drift discovered as a result of testing need not be reported under this item but may be reportable under items 2.a(5),

2. a (6), or 2. b (1) below.

(2) Operation of the unit or affected systems when any parameter or operation subject to a limiting condition is less conservative than the least conservative aspect of the limiting condition for operation established in the technical specifications.

Note: If specified action is taken when a system is found to be operating between the most conservative and the least conservative aspects of a limiting condition for operation listed in the technical specifications, the limiting condition for operation is not considered to have been violated and need not be reported under this item but it'ay be reportable under item 2.b(2) below.

(3) Abnormal degradation discovered in fuel cladding, reactor coolant pressure boundary, or primary containment 352

6.0 ADMINISTRATIVE CONTROLS Note: Leakage of valve packing or gaskets within the limits for identified leakage set forth in technical specifications need not be reported under this item.

Reactivity anomalies, involving disagreement with the predicted value of reactivity balance under steady state conditions during power operation,- greater than or equal to 1% dk/k; a calculated reactivity balance indicating a shutdown margin less conservative than specified in the technical specifications; short-term reactivity increases that corresopond to a reactor period of less than 5 seconds or, if sub-critical, an unplanned reactivity insertion of more than 0.5% dklk; or occurrence of any unplanned criticality.

(5) Failure or malfunction of one or more components which prevent or could prevent, by itself,. the fulfillment of the functional requirements of system(s) used to cope with accidents analyzed in the SAR.

(6) Personnel error or procedural inadequacy which prevents or could prevent, by itself, the fulfillment of the functional requirements of systems required to cope with accidents analyzed in the SAR.

Note: For items 2. a (5) and 2.a (6) reduced redundancy that does not result in a loss of system function need not be reported under this section but may he reportable under items 2.b(2) and 2.b(3) below.

Conditions arising from natural or man-made events that, as a direct result of the event require plant shutdcwn, opera'tion of safety systems, or other protective measures required by technical specifications.

Errors discovered in the transient or accident analyses or in the methods used for such analyses as described in the safety analysis report or in the .bases for the technical specifications that have or could have permitted reactor operation in a manner less conservative than assumed in the analyses.

353

6 0 ADMINI STRATI VE CONTROLS (9) Performance of structures, systems, or components that requires remedial action or corrective measures to prevent operation in a manner less conservative than assumed in the accident analyses in the safety analysis report or technical spec'ications bases; or discovery during plant life of conditions not specifically considered in the safety analysis report or technical specifications that require remedial, action or corrective measures to prevent the existence or development of an unsafe condition.

Note: This item is intended to provide for reporting of potentially generic problems.

b. Thirt -Da Written Reports. The reportable occuxxences discussed below shall be tne subject of written reports to the Director of the appropriate Regional Office within thirty days of occurrence of the event. The written report shall include, as a minimum, a completed copy of a licensee event report form. Xnformation provided on the licensee event report form shall be supplemented, as needed, by additional narrative material to provide complete explanation of the circumstances surrounding the event.

(1) Reactor protection syst: em or engineered safety feature instrument settings which are found to be less conservative than those established by the technical speci ications but which do not prevent the fulfillment of the functional requirements of affected systems.

(2) Conditions leading to operation in a degraded mode permitted by a limiting condition for operation or plant shutdown required by a limiting condition for operation.

Note: Routine surveillance testing, instrument calibration, or preventative maintenance which require system configurations as described in items 2.b. (1) and 2.b. (2) need not be reported excect where test results themselves reveal a degraced mode as described above.

(3) Observed inadequacies in the implementation of administrative ox procedural controls which 354

6 0 ADMINISTRATIVE CONTROLS treaten to cause reduction of degree of redundancy provided in reactor protection systems or engineered safety feature systems.

(4) Abnormal degradation of systems other than those speci f ied in item 2. a (3) above designed to contain radioactive material resulting from the fission process.

Note: Sealed sources or calibration sources are not included under this item. Leakage of valve packing or gaskets within the limits for identified leakage set forth in technical specifications need not be reported under this item.

Uni ue Re ortin Re uirements A. Radioactive Effluent Release Re ort A report on the radioactive discharges released from the site during the previous 6 months of operation shall be submitted to the Director of the Regional Office of Inspection and Enforcement within 60 days after January 1 and July 1 of each year. The report shall include a summary of the quantities of radioactive liquid and gaseous effluents released and solid waste shipped from the plant as delineated in Regulatory Guide 1.21, Revision 1, "Measuring, Evaluating, and Reporting Radioactivity in Solid Wastes and Releases of Radioactive Materials in Liquid and Gaseous Effluents from Light-Hater-Cooled Nuclear Power Plants," with data summarized on a quarterly basis following the format of Appendix B thereof.

The report shall include a summary of the meteorological conditions concurrent with the release of gaseous effluents during each quarter as" outlined in Regulatory Guide 1.21, Revision 1, with data summari ed on a quarterly basis following the format of Appendix 8 thereof. Calculated offsite dose to humans resulting from the release of effluents and their subsequent dispersion in the atmosphere shall be reported as recommended in Regulatory Guide 1. 21, Revision 1.

355

6 0 ADMINISTRATIVE CONTROLS B. Source Tests Results of required leak tests performed on sources if the tests reveal the presence of 0.005 microcurie or more of removable contamination.

C. Special Be orts (in writing to the Direc or of Regional Office of Inspection and Enforcement).

Reports on the following areas shall be submitted as noted:

a. Secondary Containment 4.7.C Within 90 Leak Rate Testing (5) days of completion of each test.

b. Fatigue Usage 6.6 Annual Evaluation Operating Report C. Seismic Instrumentation 3.2.J.3 Within 10 da<> plant Cire protection and pre-vention pro<<ra ln accords<<c ~ vlth

~ nprovod standard ~ and pr<<ctlcos ae

<<Inntoc for sl<<nt need ~ .

As ~ lst the .urerlntondoat In prn<<rsn

<<Iolnlotretlon and directly r<<spnnsll *

~

Assistant Poser I'lant Ruperlntcnsont neer plant hnusotooninn as It Iarv>>ts Cire or<<vcntlnn effnrts, provides consultation to plant nsi>>daent on all fits safety oattersl Coordinates and evaluate ~ to ~ 'tlndp alntvnancs ~ s<>>>ends corrective Safety Engineer actlonsI cooduct ~ fits t!uining a<<I cvaiuateo fifo dti11CI Provides on the scene sdvlco to fits brigade leaders duting fire <<crgcncles

~ s applloable. Interpret and evaluate requires>>oto for control of transient fire ioado. Rovievo pre-fire plans an1 oo<<rgency planning docus>>ots. participates Ia establishing outusi aod ~ Id

~ greeaents. provides sutvol11ance of cutting, voiding, open-f1ss>> voth Controls Ooot41na'to ~ fltc safety halters os resulted uitb v<<<<Coty Engineering SCCVICC ~ ~

Reoponolhl ~ for orraalslnv, arrl trntnlnn the plant Cire hrI<<<<des srocurr, I'Iant i>pe rations Supervisor needed Clreftchtlnn oculo<<cat a<<I supollrel coordinates arson<<vacate Cnr v<<rtual nldl re<<leva vork plans Cor I'Irc totootlals aH Inltlatoe

<<sptoptlate conttolsl rorleve and <<vale<<t<<<< the status of fire protection and 4etoction systoso; arel rcaslns cogntsaat of oysteao teaova4 froa service asd lnterin controls plsoe4 ln effect, Reopoaslble for lnpiaeetatlon of osernoocy plans II'eeded oo

~ hlftl Provides control a<<I ~ Incls point of contoCt Cor all Plant Ihornenty Director (On Duty Shift Snnineerl ccntlncaCICCI attend ~ pire Drlnod ~ ieadet Course every 5 years:

conducts on ~ 'hlft brief into of Clro brig<<do an4 Initiates sorlodlo fits drlilel sn4 controls veldlnr. cutting ~ o<<d oooo fisc>> vorh.

Sooponslbl ~ Cnr control a<>rtor<<ance OC Cire br!rail ~ der IIV. Cire e<<or/one Its'oncoct<< n<<

plant rIr<<nrI<<oijo I>>ader <<bitt brief ln, s nr brin<<le>>~hvrsl rrvlcvs trr-(Aeoirn<<4 A<<st. chlct ynnr. on-Duty) I'Ire plane <<n4 v<<errsncy biennia. dcciosontsl rosa'Ins concI sant of pleat fly~ Icwl sta'tuo fire

~ ystsno and eouIIsseot a<<I vorb activities hovtn<<

fits potootlelsl a<<1 ntteo4s ylr~ stI<<sdc ik<<I<<r Course every 5 years.

Roetonolhlc Cnr pl<<nt Clreclcntlnn <<ctlvltlvsl fillet CItt nricod ~ n<<ob<<ro

<<ttc<<I plant Cire tralnlnc cvurs<<e ach  : vc<<rsl ons sr<< rc<<nnnsihl<< Car tnovl<< Ivl<<<<I ns ~ Idn

{AC<<Inn<<4 RI<<nt) n<<ntr In <<sin<<is<<ncv vlth plant rlri nina.

Co<<sects rosin<< Cire t<<trois on << rv<<ularly <<osI<<<<<<4 o<<el ~ :

I'lent rtri v<<tchcs r<<soonolbl ~ for detvctlnc <<n4 roportlnc Cire has<<res ond lnl'tlstlnc first aid flroflchtlns IC needed: <<nc vill bo olace4 on cloak resistors until all olonnod CIsec Cire

~ yotoso sro Iaetolled ano ooor<<be .

~ o.5-1 364

APPENDIX B TO FACILITY OPERATING LICENSE DPR -33 FOR BROVNS FERRY NUCLEAR PLANT UNIT l TENNESSEE VALLEY AUTHORITY DOCKET NO. 50-259

0 ENVIRONMENTAL TECHNICAL SPECIFICATIONS FOR BROWNS FERRY NUCLEAR PLANT TABLE OF CONTENTS Page No.

1.0 DEFINITIONS 2.0 LIMITING CONDITIONS FOR OPERATION 2.1 Thermal Discharge Limits 2 2.2 Chemical 2.2.1 Makeup Water Treatment Plant Spent Demineralizer Regenerants 2.2.2 Chlorine 3.0 DESIGN FEATURES AIG) OPERATING ,

8 PRACTICES'hemical 3.1 Usage 3.1.1 Oils and Hazardous Materials 3-1-2 Other Chemicals 3.2 Land Management 10 3.2.1 Power Plant Site 10 3.2.2 Transmission Line Right-of-Way Maintenance lo 3+3 Onsite Meteorological Monitoring 10 4.0 KPfIROIiMENTAL SURVEILLANCE 4.1 Ecological Surveillance 12 4.1.1 Abiotic 12 4.1. 2 Biotic 13

4. 1. 3 Special Studies 18 Radiological Environmental .Monitoring Program 18 5.0 ADMINISTRATIVE CONTROLS 5.1 Responsibility 23 5.2 Organization 5.3 Review and Audit 5.4 Action to be Taken is Exceeded if an Environmenta1 LCO

TABLE OF CONTENTS (cont. )

Page No.

5~5 Procedures 24 5.6 Reporting Requirements 25 5.7 Environmental Records 27 Tables 29 Figures

1.0 DEFINITIONS The following terms are defined for uniform interpretation of these specifications.

Adxinistrative Terminolo Environmental limiting condition for operation any limiting condition for plant operation as stated in Section 2 of the Browns Ferry Nucleax P1ant Environmental Technical Specifications.

Unusual event with the potential for a significant environmenta1 impact an event that results. in noncompliance with an environmental technical specification, or an event that results in uncontrolled or unplanned releases of chemical, radioactive, thermal, or other discharges from the Browns Ferry Nuclear Plant in excess of applicable Federal, state, and local regulations.

Thermal Properties Thecal limits limits defined. for temperatures, spatial changes in temperature, and temporal changes in temperature within )lheeler Reservoir that are attributable to thermal discharges from Browns Ferry Nuclear Plant.

Intake temperature the average temperature at a given time within the intake system at a point beyond the intake pumps.

Discharge temperature the average temperature at h given time in the cooling water return channel or at the condenser outlast 'butterfly valves.

Delta T Q T) the difference in temperatures of the river at the control monitors attributable to thermal discharges from Brawns Ferry Nuclear Plant.

Instrumentation Pro erties Accuracy a measure of the difference between the true and measured values of a given parameter, hence a measure of error.

Minimum detectable level that level below which a specific detector, instrument, ox analysis is unable to detect the presence of a given constituent.

Sensitivity the minimum change in the variable detected. by a given sensox.

2,0 LIMITING CONDITIONS FOR OPERATION

2. 1 THERMAL DISCHARGE LIMITS Monitorin Re uirement

~0b ective The vater temperature data collected by the thermal monitoring netvork is tele-The purpose of this specification is to metered to the Browne Ferry meteoro-limit the thermal stress on aquatic life logical station. The meteorological fn Wheeler Reservoir by operating Brovns station vill receive the data and auto-Ferry Nuclear Plant so as to meet the matically record the readings every 60 applicable vater quality temperature minutes. All temperature data are standards of the State of Alabama. recorded on paper tape and mafatained for record keeping purposes. The 5-foot depth temperature dita vhich are need to S ecificatfon prevent exceeding the limiting 'condition vill be transmitted to the control room The plant-induced reservoir vater tempera- and vill be visually displayed for moni; ture at the 5-foot depth at the dovaetream toring purposes. The accuracy of the control point shall not exceed the vater system and the sensitivity of the temperature measured at the 5-foot depth thermistor seas8re are designed to be of the upstream control monitor by more +0.3 F and 0.01 F, respectively.

than the applicable maximum temperature iee (currently 5 F) nor shall the reser- Three thermal monitors spaced across the voir vater temperature measured at the 5- reservoir in the vicinity of river mfle foot depth at the downstream control point 292.5 shall serve as the downstream con-exceed the applicable maximum vater tem- trol. Tvo monitors located above the plant, perature (currently 90'F t)due to the oae located at about river mile 297.6, discharge of the condenser cooling vater. and a second located in this vicinity If this limiting condition is exceeded, vill provide thc upstream vatcr temperature the plant operator shall initiate control data. The system is designed eo that the measures. The control measures shall be downstream control monitors serve as backup (1) to reduce the waste heat discharged to for one another and sfmilarly for thc taro the reservoir and/or (2) to request modf- upstream monitors. The locations of fications in the releases from TVA'e cxfetiag temperature monitors are displayed Cuntersvflle and/or Wheeler Dame to in Figure 2.1-1.

increase the streamflow by the Brovae Ferry plant. In the event the system described is out of service, an alternate method vill be employed three times a day (once each shift) to measure the river temperature at the 5-foot depth in the vicinity of the upstream and downstream control monitors and thus determine the tem-perature rise and the, maximum river vater temperature belov the plant.

When such a method vouId result ia an imminent and substantial endangerment to VA shall immediately advise the Coranission the safety of personnel, this paragraph if more stringent limitations (which would or the State.

shell not apply.

then govern) are imposed by EPA

2. I Continued Eases e

TVA, as a Federal agency, is required by Section 313 of the Federal Rater Pollution Control Act Amendments of 1972 (P.L.92-500) and by Executive Order 11507, "Prevention, Control and Abatement of Air and Mater Pollution at Federal Facilities,". to meet applicable Federal, state, and local water quality standards. On July 17, 1972, the State of Alabama adopted and on September 19, 1972, the Environmental Protection Agency approved thermal criteria for surface waters in the State of Alabama. The current applicable thermal standards are to limit the maximum temperature rise above natural temperature before the addition of artificial heat to 5 F and the maximum vater temperature to 86 F. In the application of this temperature criteria the temperature shall be measured, in the case of Wheeler Reservoir, at a depth of 5 feet. The higher temperature limits during the special diffuser performance study during the summer of 1977 vill be for brief periods and vill not adversely affect the environment.

The Tennessee Valley Authority has taken action to comply with applicable thermal water quality standards of the State of Alabama in the operation of the 3-unit Browns Ferry facility by installing mechanical draft cooling towers. However, inadequate cooling tower performance has resulted in drastic curtailment of power generation during summer periods when peak load demands are critical on the TVA system to meet thermal standards.

The Browns Ferry Nuclear Plant Environmental Statement analyzed the environmental effects of operating the plant with a 10 F rise and 93 F, maximum temperature limitation. This evaluation concluded that the 10 F and 93 F limitations would be adequate to protect aquatic life. Hydrologic studies recently conducted confirm that a 90 F limitation would not'esult in excessive temperature conditions in the cool vater fisheries habitat downstream from the plant. An additional environmental assessment recently completed by TVA concludes that operation at or near the 90 F maximum temperature limitations will not result in adverse impacts on the biota of the reservoir.

TVA has requested from EPA and the State of Alabama that the maximum temperature limitation be increased to 90 F. The EPA stayed the 86 F maximum temperature requirements of the Browns Ferry NPDES permit in accordance with 40 CFR 5125.35 and 40 CFR 5125.36. EPA has requested while the stay is in effect that TVA comply with the 90'F maximum temperature limit. A letter confirming concurrence with EPA's position was received from the staff of Alabama Yater Improvement Commission dated July 18, 1977.

sys,tems described for thermal discharge limits vill be operational  !

prior to any significant discharge of vaste heat. The placement of the  !

temperature monitoring instruments shall be such that compliance vith vater quality criteria will be demonstrated. The placement of the temperature sensors at the 5-foot depth in the waters of Wheeler Reservoir is in accordance with the requirements of the vater quality criteria of the State of Alabama. The temperature data is converted to digital data a' the station on the reservoir. The transmission, computer storage, and monitoring system is being used at other facilities and has performed accurately and reliably.

2. 2 CHEHlCAL 2.2.1 lhakeu Mater Treatment Plant 14onitorin Re uirement S ent Demineralizer Re enerants The pH of spent demineralizer

~Ot ective vastes shall be monitored in a waste collection sump or settling Treatment of makeup ~ater treat- pond and. shall be adJusted"to ment plant demineralizer waste vithin the range of 6.0 to 9-0 (spent regenerant solutions) is immediately before offsite releas provided to assure that the pH of the waste stream i's within limits All measurements vill be performed to protect the quality of the by plant personnel using standard receiving stream and vithin appli- instrumentation and. operating cable regu1ations. instructions. Surveillance instructions and records vill be kept on file at the plant.

S ecification The pH of the spent deminera1izer regenerants shall be adJusted to vithin the range of 6.0 to 9.0 before release offsite.

Bases Regeneration of makeup vater treatment plant demineralizers requires the sul~c use of S04 acid and sodium hydroxide, vhich resu1ts in releases of and. Na and excess su1furic acid and sodium hydroxide used. in the regeneration cycle. Treatment of these vastes viU. consist of pumping the acid, and caustic vastes into a settling pond to allov for dilution and neutralization. The vastes vill be held in the pond as long as is practicable. Norma11y, natural losses such as evaporation will reduce the pond. level. %hen offsite releases of vaste vater from a pond become mandatory, pH wi11 be monitored and adJusted to within the range of 6.0 to 9.0.

Should circumstances force the direct offsite release of regenerative vastes from the makeup plant, the pH of the waste will be monitored, recorded and adJusted to vithin the range of 6.0 to 9.0 before discharging.

2.2 CHEMICAL (continued) 2.2.2 Chlorine Monitorin Re uirement

~ot ective The residual chlorine in the auxiliary rav cooling vater system shall be Control,af the use of the chlorine sampled weekly during periods when as a biocide in the auxiliary raw the raw cooling water systems are cooling water system is exercised, being chlorinated except as noted to assure that discharge to the in Section 4.1.3. Concentration receiving stream is belov levels in the main condenser cooling vater which could be harmfu1 to aquatic discharge will be computed. using biota. measured concentration and, condenser cooling water end auxiliary raw S ecification cooling vater flows.

A total chlorine residual of'.05 As an alternate, the concentration mg/1 shall not be exceeded at the in the condenser circulating vaCer discharge of'he main condenser may be determined directly on a cooling water to the river due to weekly basis, eliminating the need, chlorination of the auxiliary rav for raw cooling water sampling or cooling water system. If a total condenser cooling ~ater flow chlorine residual of 0.05 mg/1 is determination.

exceeded at the discharge of the main condenser cooling water to All analyses vill be performed by the river due to chlorination of plant personnel using standard the auxiliary rav cooling vater analytical procedures for the system, the chlorine feed shall determination of residual chlorine.

be immediately discontinued and." The procedure used, shall be one not resumed until the feed rate which has been approved by the has been reduced and the calibra- Environmental Protection Agency for tion of'he feed equipment checked. this purpose. Surveillance instruc-tions and records vil3. be kept on file in the plant.

Beses 4

Chlorine is to be used as a biocide for the control of Asiatic clams in the auxiliary rav cooling vater system.- It is expected. that the use of chlorine for this purpose vi11 be required only during the early and. late stages of the spawning periods of Asiatic clams. The rav cooling water to be treated vill be discharged to th<: main condenser cooling water system. Operating experience has show~ that the reservoir water has a chlorine demand. of about 0.5 mg/1. Du>> to the relative flov of the condenser cooling vater and. the auxiliary raw cool'ng water system" (approximately 20:1) and the chlorine demand of the diluted stream, it is expected that the chlorine residual vill react sufficiently ouch Chat only chlorides will be discharged. The flov in the main condenser cooling vater system vill be determined from the design characteristics circulating vatcr pumps operating during chlorination of'he main condenser periods.

Page deleted 3.0 DESIGN FEATURES AUD OPERATING PRACTICES This section describes those design features and operating practices not covered in Section 2.0, "Limiting Conditions for Operation " and which, result in significant effects on environmental impacts.

if changed, could 3.1 Chemical Usa e 3.1.1 Oils and Hazardous Materials Stora e and Handlin - Storage facilities for oils and hazardous materials vill be protected. by contain-ment facilities to insure no releases to the aquatic environment. The plant areas vhere oils or other hazardous materials are routinely handled.

are equipped with separate drain systems and containment sumps.

The table below shbvs the materials stored, the quantities, and method of control.

Total Storage Item ~Stera e Ca acit Control Insulating Oil 2 tanks 74,000 gals. Surrounded by 3" sand bed, Diesel Oil 2 tanks 142,000 gals. Retention Basin (Sump)

Lubricating Oil 2 tanks 60,000 gals. Retention Basin (Sump)

Sulfuric Acid 1 tank 3,400 gals. Limestone Bed.

Turbine Lube Oil 6 tanks 34,200 gals. Sump Provided Reactor Feed Pump Oil 9 tanks 9,000 gals. Sump Provided Sodium Hydroxide 1 tank 3,200 gals. Sump Provided Liquid Nitrogen 1 tank (insulated) Isolated. Storage Askarel All transformers Sumps Provided, Chlorine 26 cylinders - 52,000 lbs. Isolated Storage

3.1.2 Other Chemicals - Table 3.1.2-1 summarizes /he uses of'ther chemicals used in plant processes, and the expected maximum quantity of chemical end products.

Table 3.1.2-2 shovs the expected chemical concentrations of the effluent in the river after mixing.

3.2 Land Mana ement 3.2.1 Power Plant Site - The site shall be appropriately landscaped as allowed by completion of construction. All areas which are either unpaved, or not committed for specific purposes will be provided'with appropriate vegetative cover.

3.2.2 Transmission- Line Ri t-of-$l Maintenance'ob ective The sole purpose of this section is to provide reporting requirements (to USNRC) on herbicide usage, if any, for purposes of'right-of-way maintenance regarding only those transmission lines undex USNRC's )urisdiction for the Browns Ferry Nuclear Plant.

S ecification A statement as to whether or not herbicides have been used. in maintaining rights of way for those transmission lines associated with the Browns Ferry Nuclear Plant shall be provided. If herbicides have been used, a description of the types, volumes, concentrations, manners and frequencies of application, and miles of right of wsy that have been treated, shall be included.

Re ortin Re uirements Information as specified above shall be proVided in the annual environmental operating xeport.

Bases Vegetation growth on a transmission line right of way must be controlled in such a manner that it will neither interfere with safe and reliable opexa-tion of the line nor impede restoration of service when outages occur.

Vegetation growth is controlled by mechanical cutting and the limited use of herbicides. Selected chemicals approved by ZPA for use as herbicides are assigned (by EPA) label instructions which pxovide guidance on and procedures for their use. A px'oposed program for chemical treatment of TVA transmission line right of-way maintenance is submitted each year to the Federal >1orking Group on Pest Management for their review.

3. 3 Onsite Heteorolo ical Monitorin The onsite meteorological monitoring program measures and documents meteorological conditions at the site, specifically at heights above ground that allow reasonable estimates. of atmospheric dispersion conditions for airborne plant effluents. The onsite program shal3. conform to the recom-mendations and intent of Regulatory Guide 1-23, Onsite Mcteorolo icrQ

~pro raus (February 1972), and include instruments to sense vind speed and direction at 10m, 46m, and 93m; to allow calculation of vertical tempera-ture gradient between 10m and 46m and between 10m and 91m; and to measure ambient temperature and dew point at 10m. The location of 'the meteorological tower is as specified. in Section 2.3e7 of'he Bxowns Fexry Nuclear Plant Final Safety Analysis Report (see Amendment 63). A quality assurance program shall be in effect for all meteorologi.cal measurements and observations.

Meteorological,data shall be summarized and reported consistent with the recommendations of Regulatory Guide 1.21 (June 1974) snd Regulatory Guide: 1.23 (February 1972), and meteorological qbservations shall be

,recorded'in a form consistent with National Heather Service procedures.

If the outage'f any meteorological instrument(s) required by Regulatory Guide'1.23 (February 1972) exceeds seven consecutive days, the total outage time, the dates of outage, the cause of the outage, and the instru-.

ment(s) involved shall be reported, within 30 days of the initiation of the outage to the USNRC, Office of Inspection and Enforcement, with a copy to the Office of Nuclear Reactor Regulation, Division of Operating Reactors. Elements of this program may be modified or terminated, in accordance with Subsection 5.6.3(c).

The collection of meteorological data at the plant site provides information for use in developing atmospheric diffusion parameters for estimating potential radiation doses to the public resulting from actual xoutine or abnormal releases of. radioactive materials to the atmosphere, and for assessing the actual impact of the plant cooling system on the atmospheric

.environment of the site area. A meteorological data collection prcgran as described. above is necessary to meet the requirements of subparagraph 50.36a(a)(2) of 10 CFR Part 50, Appendix D to 10 CFB Part 50, and Appendix E to 10 CFR Part 50.

~

4. 0 EHVIROR ENTAIL SURVEILLANCE The program elements described. below are designed to detect and. measure the impact of plant operation on the environment. If on the basis of this program it is established that no significant adverse of environmental impact has resulted.

plant, elements or is likely to result from operation the Browns Ferry Nuclear of the environmental surveillance program may be modified or terminated, in accordance with Subsection 5.6.3(c).

4.1 Ecolo ical Surveillance Abiotic (a) Water Quality Surveys

~Ob ective Water quality surveys are performed. quarterly in Wheeler Reservoir.

Baseline levels for water quality parameters in Wheeler Reservoir

'were established by previous sampling and will be compared to that data received. once the plant is in operation. Significant variations in compared. numbers wiU. be utilized to define potential water quality problems and provide solutions to these pxoblems.

S ecification Water quality data in Wheeler Reservoir are determined quarterly at the locations shown in Table 4'.l-l.. Pax'ameters monitored. include dissolved oxygen, temperature, biochemical oxygen demand (5 day, 20o C.),

chemical oxygen demand, pH, alkalinity, specific conductance, sodium, sulphates, chlorides, nitrogens (NH , N02 + N03, and. organic), and solids (dissolved., suspended, and t)tal). All analyses vill be perfoxmed using standard documented analytical procedures for water quality ans1ysis. Details of the analytical procedures are on file in the office of the Mater Quality end Ecology Branch, Chattanooga, Tennessee.

Renortin Re uirement Water quality data are stored on the STORET computerized. data-handling system that is operated, by the U.S. Environm~tal Protection Agency and are also kept on'ile in the Mater Quality and Ecology Branch office.

These data are used for identifying exLsting water quality conditions in the plant area. The results will be summarized in annual repox'ts of the nonxadiological environmental monitoring pxogxam.

Bases The reservoir monitoring program vill, at a minimum, evaluate the parameters directZg associated with the added" waste discharges originating from Browns Ferry. Maintenance of these parameter" at or within the applicable standards will help to assure satisfactory water quality conditions within Wheeler Reservoir.

(b) Thermal Plume Mapping

~Ob ective Verify the accuracy of thermal plume models used in predicting environ-mental effects from the thermal releases from the Browns Ferry plant.

S ecification Mater temperature will be monitored at numerous depths from the water surface to the reservoir bottom at various locations in Wheeler Reservoir.

Data >rill be used. to verify predicted thermal. plume models.

4.1.2 Biotic (a) Benthic Monitoring

~Ob ective The benthic monitoring program will compare preoperational data with that obtained after Browns Ferry Nuclear Plant begins operation to ascertain if changes have occurred. Benthic organisms generally spend their life cycle in a localized area. Thus, species abundance should provide the best indication of induced change.

S ecification The program consists of quarterly sampling et the sampling stations identified in Table 4.1-1. All benthic monitoring will be performed

'using standard accepted biological sampling and enumeration procedures for benthic fauna. These procedures are on file in the office of the

>later Quality and Ecology Branch, Muscle Shoals, Alabama. B nthic organisms are sorted from the sediment by washing fine material through a sieve and separating. from the larger sediment particles. The four principal benthic macroinvertebrates selected f'r study are burrowing mayflies (Hexagenia), ~uatic worms (Oligochaeta), midges (Chironomidae),

and Asiatic clams (Corbicula).

Renortin Re uirement The results will be summarized in annual reports of the nonradiological environn>ental monitoring program.

Bases The four benthic macroinvertebrates selected. for study represent the pre-,

dominant benthic fauna in wheeler Reservoir. Normally currents in a reservoir do not affect the location and movement of benthic populations.

Thus, these organisms can be studied. at a specific location over an extended period, to determine significant, population changes.

(b) Phytoplankton Monitoring

~OB cess ve The obgectives of phytoplankton monitoring are to assess population changes within the areas monitored and to provide a basis for determining the effect of plant-induced, population changes.

S ecification Quarterly monitoring of phytoplankton wiU. be conducted at the locations shown in Table 4.1-3.. All phytoplankton monitoring will be performed using standard accepted procedures for phytoplankton sampling, enumeration, and. biomass and productivity determinations. These procedures are on file in the office of the Mater Qua1ity and Ecology Branch, muscle Shoals, Alabama.

Re ortin Re uirement The results wil3. be summarized. in annual reports of thc nonradiological environm ntal monitoring program.

Bases Changes to populations of phytoplankters, either in numbers or species, may indicate effects on alga1 growth and photosynthesis from natural variability in water temperature, light intensity, and. nutrient concentra-tions as well as from plant-induced-changes Change'ay occur that are not detectable because of the high variability associated with sampling on a quarterly frequency. AdditionaU.y, prolonged exposure to high tempera-tures during late summer or fall enhances the growth of blue-green algae.

In a1gal communities exposed. to these conditions, dominance usually shifts successively from diatoms to green algae and eventually to blue-green algae.

Enumeration and biomass estimates are used to assess the standing crop of phytoplankton. Productivity measurements are used. to determine the vitality of phytoplankton cells. The procedure is based on the amount of carbon-14 assimilated by viable cells over a measured period of time in a water sample of known volume.

(c) Zoo lankton Monitorin

~Ob ective The objective of the zooplankton monitoring is to assess population chang s and movement within the areas monitored and provide a basis for determining the effect of the plant on the zooplankton population.

Soecification Quarterly zooplankton samples will be collected at the locations shown in Table 4.1-1. All zooplankton monitoring vill be performed using standard accepted zooplankton sampling and enumeration procedures. These procedures are on file in the office of the plater Quality and. Ecology Branch, Muscle Shoals, Alabama.

Re ortin Requirement The results will be summarized in annual reports of the nonradiological environmental monitoring program.

Bases I

Because zooplankton are important links in the aquatic food chain, taxonomy and population changes will be important indices in evaluating the effects of plant operation on reservoir ecology. However, since zooplankters are capable of limited movement -and do change their vertical distribution during the daily cycle, data derived from sampling specified depths at discreet times msy not pr'esent a complete picture. Since a relatively high degree of variability due to sampling procedures is expected, these studies are limited to providing a historical record for use in assessing such factors as gross population changes, percentage changes in groups (Copepoda, Cladocera, Rotifera), and the deletion or addition of any species after Browns Ferry Nuclear Plant becomes operational.

(d) Fish Population and Distribution Studies

~Ob ective e

Studies are to assess plant impact on moveme'nt of fish, relative abundance, creel harvest, species composition, and growth of fish.

S ecification Net sampling will be conducted. quarterly at four of the locations shown in Table 4.1-1. All fisheries monitoring will be conducted using standard

accepted sampling and eva1uation procedures. procedur These proce ures are on i the ofhce of the Division of Forestry, Fisheries', and Wildlife Development, Norris, Tennessee.

To determine nor;.al movemert in the reservoir, selected species of fish collected bJ rap nets will be tagge'. Gill n t catche" will also supplem nt information on species co,oos" t on, rela. ive abundance, distribu 'on, and movement.;J.ectrofishing will be used, to supple-..ert.

the tagging o" specxes not o tained in sufficient numbers by trap ne4ting-g1 rap nets also furnish fisn for routine grow h studies.

Rotenone sampling of selected, areas will be conducted during late August and early September of each year to estimate standing stocks, species composition, and reproductive success.

~reel census stuccoes are cord cted each month to es abl'sh catch per hour and per trip, species and weights of i h taken, ~d hou"s fished s

pcr trip in each o six areas of thc reservoir. Previously recorded.

da a will be the basis fox determining the locatior. and. mamitude of the sport fisnery before op ration of the Brows Ferry Nuclear Plant-L.oval fi"h "e a'so being investigated,. Infonaation on species numbers, and distribution of larval fishes present in four areas of the reservoir du ing the sampling period before operation begins will be compared with data collected al'ter the plan becomes operatiora1 to assess effects of plan operation.

Renor in.- Renuiremert

'lne results will be suu~rixed in annual reports of the nonraaiological environmental monitoring program.

Oases An important interaction of Browns Ferry Nuclear Plant with the environment vill be tne hea dissipated from tre plant in 3Tneeler Reservoir. The effect of the added heat on fish resources i" to be determined.

(e) Entrainment of Fish Eec;s and Larvae

~Ob. ective To quantify the ertrainmert of fish eggs and la vae in the cooling water system.

S ecification The entrainment of fish eggs and larvae in th coo'ing water system shaL'e monitored we"kly du"ing the rigor spawning per'od o- t~~ ch th ough July and an estimate made of the total number of fish egg" and larvae entrained.

Honitoring will be performed, using standard. accepted. sampling procedures which arc on file in the office of the Division of Forestry, Fisherics, and Mildlife Development, Norris, Tennessee.

Re ortin Re uirement The results will be summarized annually in the annual reports of the nonradiological environmental monitoring program.

Beset A significant proportion of the river flow vill be routed through the plant for cooling purposes, and during periods when larval fish are abundant there is %he potential 'for entrai'nment of large numbers of fishes.

The specified study will determine the numbers of fish eggs and larvae entrained in the cooling water system resulting from plant operation and identify the need for possible corrective action.

(f) Fish Xm in ement on intake Screens

~Ob ective To detect and quantify fish impingement upon the intake screens.

Once each week, fish which have been impinged on operating intake screens over the preceding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> shall be estimated. The impinged. fish shall be collected during screen washing and classified as: 1) shad and herring,

2) catfish, 3) bass (largemouth, smallmouth, and. spotted bass), 4) crappie,

5) sunfish, 6) drum, and 7) other species.

Re ortin Re uirements Five copies of a quarterly report to be prepared by TYA's Division of Power Production in coordination with the Division of Power Resource Planning shall be submitted to the USNRC Director of Division of Operating Reactors within 30 days following the end of each calendar quarter. The 'report sha11 inclu tabulated impingement data by screen and a summary of any specific studies or investigations which TVA is conducting to evaluate the significance of impingement losses or techniques for reducing these losses. A copy will be sent to TVA's Division of Forestry, 1'isheries, and Hildlife data Development for review and assessment. A summary of the impingement (with the estimated total annual impingement per -unit for each of the seven specified. fish groups) shall be included in the annual nonradiological environmental operating report.

Bases I

Quantification of impinged. fish upon the intake screens will provide an assessment of fish losses from normal plant operation and identify the need for possible corrective action.

4. 1. 3 Special Studies Ot >acti rc To demonstrate the adequacy of weekly sampling of chlorine residualduring chlorination of the auxiliary 'raw cooling water systems by demonstrating that chlorine residual in auxi,liaxy raw cooling water (RCH) systems remains relatively constant during chlorination.

S ecification TVA will perform special studies during the first two periods (including a spring and a fall period) df chlorination of the RCH systems after September 1975, which are of at least 3 weeks'uration. During the special studies period. wh n the RC>t systems are being chlorinated, samples wil3. be taken dai+ from the RCV systems and. analyzed for chloxine residual. Records of the daily sampling and analyses will be maintained. and submitted to the NRC staff for their xeview foUowing the end of the special study period.

Chlorine feed. rate and equivalent RCW concentration will be reported for the special studies period.

Sampling during-the special study period will be considered to satisfy the monitoring requirements of Section 2.2.2 qf the environmental technic@.

specifications.

'4.2 Radiolo ical Environmental Monitorin Pro ram

~Oir ective An environm ntal radiological monitoring pxogram is conducted to verify proJected, or anticipated radioactivity concentrations and related public exposures.

S ecification An environmental monitoring program shall be conducted. a" described below at locations indicated in Figures 4.2-1, 4.2-2, and 4.2-3 and Tables 4.2-1, 4.2-2, 4.2-3, and 4.2-4,-with sampling and analysis frequencies given in Table 4.2-1. An81ytical techniques used shall be such that the detection capabilities in Table 4.2-5 are achieved.

1. Atmos heric Monitorin

a. The atmospheric monitoring network is divided into three subgroups consisting of ll monitoring stations. Five local monitor" are located on or adjacent to the plant site, as shown in Figure 4.2-1.

The four perimeter and two remote monitoring stations are shown 4.2-2. Atmospheric and terrestrial monitoring station on'igure locations for Browns Ferry Nuclear Plant are listed. in Table 4.2-2.

Each monitor shall be capable of continuously sampling air at regulated flow of approximately three cubic feet per minute through a particu1ate filter. In series with, but downstream of, the particulate filter is a charcoal filter used to collect iodine.

Each monitor has a collection apparatus to obtain rainwater on a continuous basis and a horizontal platform that is covered with gummed acetate to catch and hold heavy particulate fallout.

Each local monitor shall be equipped with a 6-M tube located next to the particulate filter. The data from thi" de'ector are recorded on stripchart recorders located at the station and in the plant control room.

Thermoluminescent dosimeters shall be used to record gamma radiation levels at each remote and perimeter station (Figure 4.2-2) and at nine stations near the site boundary as shown in Figure 4.2-1.'he TLD's shall be processed quarterly.

b. The particulate filters shall be removed weekly from each monitoring station and analyzed for gross beta activity. In addition, the filters for each station shall be composited monthly and quantitatively and qualitatively analyzed for at least 10 specific gamma-emitting radionuclides.*

The charcoal filters shall be removed weekly from each station and analyzed for X.

Rainwater shall be collected monthly when available from each station and each sample is analyzed for at least 10 specific gamma-emitting radionuclides*, and tritium.

Gummed paper shall be changed monthly, ashed and the gross beta activity shall be determined.

2. Reservoir Monitorin a~ River water shall be sampled automatically from the locations shown in Table 4.2-3 and Figure 4.2-3.

b. Samples shall be collected automatically and analyzed monthly from three points on the Tennessee River. The samples shall be analyzed for at least 10 specific gamma-emittin~ radionuclides*, and shall be composited quarterly for tritium, Sr and Sr analyses.

Samples of sediment, clams, and a representative commercial and a representative game species of fish sh <ll be collected at least semiannually from the locations noted gn Table 4.2-3 and Figure 4.2-3. Plankton is collected in at least one of the 'two quarters of greatest plankton abundance during the year at the locations noted in Table 4.2-3 and Figure 4.2-3. Sediment, clam shells, fish, and when quantities are sufficieat, plankton and clam flesh will be analyzed for at least 10 gamma-emitting radionuclides*.

Strontium 89 and 90 content shall be determined in sediment and clam shells.

~e laboratory is presently gamma scanning a sample both quantitatively and cualitatively for the following

~" "

radionuclides:

Cs, "Cs ~ Ru, sZr, Nb Ba- La ~X, K, Co soCo shM xCr, and Zn.

3. Tcrres trial Monitorin

a. Soil shall be collected at least once every three years from an area near the atmospheric monitors mentioned in paragraph 4.2.1-a>

as indicated in Table 4.2-1 and Figures 4.2-1 and 4.2-2. Each sample shaU. be analyzed for at least 10 gamma-emitting radio-nuclides, Sr and Sr.

b. Milk shall be collected monthly when animals are off pasture, from at least four farms in the vicinity'of the plant and analyzed as indicated in Table 4.2-1 and Figure 4.2-1.

During the seasons that animals producing milk for human consumption are on pasture, samples of fresh milk will be obtained* from these animals at representative locations that may be significantly affected by emissions from the Browns Perry Nuclear Plant, and analyzed for their radioiodine content, calculated as iodine-131-Analysis will be carried out within eight days (one I-131 half life) of sampling. Suitable analytical procedures will be used to determine the radioiodine concentration to a sensitivity of 1.5 picocurie per liter of milk at the time of sampling. 'For activity levels at or, above 1.5 picocurie per liter, overall error of the analysis will be within 125Z. Results will be reported as picocuries of X-131 per liter of milk at the time of sampling, in accordance with Reporting. Requirements for Environmental Radiological Monitoring.

If the census of animals producing milk for human consumption indicates that, an animal exists in an area where the calculated dose is >15 mrem/yr and- the owner of the animal will not sell the milk to TVA for analysis, green leafy vegetables or other vegetation will be obtained from that location for analysis for X-131. The analysis and subsequent calculations will.determine the dose to the individuals consuming the milk.

A census of animals producing milk for human consumption shall be conducted at the beginning and at the middle of the grazing season to determine their locations and number with respect to the site.

The census shell be conducted under the following conditions:

l. Within a 1-mile radius from the plant site or within the.

lg mrem/yr isodose line, whichever fs larger, enumeration by a door-to-door .or equivalent cou'>ting technique.

2. Vithin a 5-mile radius for cows and for goats, enumeration by using referenced information from county agricultural agents or other reliable sources.

<Milk samples will be collected and analyzed weekly in areas where the calculated dose to a child's thyroid exceeds 15 mrem/year. Sampling and analysis will be conducted semimonthly in areas where the dose is calculated to be <15 mrem/year. The calculational model as published in Regulatory Guide 1.109 and Regulatory .Guide 1.111 shall be used.

If it is learned from this census that animals are present at a location which yields a calculated thyroid dose greater than from previously sampled animals, the new location shall be added to the surveillance program as soon as practicable if the farmer is willing to participate in the program. The sampling location having the lowest calculated dose may then be dropped from the surveillance program at the end of the grazing season during which the census was conducted. Also any location from which milk can no longer be obtained may be dxopped from the surveillance pxogram. The NRC shall be notified in writing that milk-producing animals are no longer present at that location. An additional milk sampling location will then be added to the program, with sampling frequency based on calculated dose.

c. Vegetation shall be collected at least quarterly from at least four of the farms mentioned in the preceding paragraph (see Pigure 4.2-1).

Each sample is analyzed for at least ten specific gamma-emitting radionucl ides.

d. Pood crops shall be collected annually within a 10-mile radius.

Type and number of samples will vary according to availability (See Subsection 4.2.4).

e. Well water is collected automatically and analyzed monthly from the well most likely to be affected by the plant ~ (See Table 4.2-1 and Pigure 4.2-1) A well remote fxom the plan't is sampled monthly as a background. The samples shall be analyzed for at least ten gamma-emitting radionuclides.

f. Samples of potable surface water supplies shall be collected monthly from the locations in Table 4.2-4. The samples shall be analyzed for tritium, and at least ten specific gamma-emitting radionuclides.

4. Deviations are permitted from the required sampling schedule if specimens are unobtainable due to hazardous conditions, seasonal unavailability or to malfunction of automatic sampling equipment. If the latter, every effort shall be made to complete corrective action prior to the end of the next sampling period. All deviatiops from the sampling schedule shall be described in the annual report.

Bassa The operational environmental monitoring program is based upon a pxeoperational program which is described in Section 2.6 of the PSAR. Sample collection and analysis were initiated in April 1968, and will continue indefinitely.

Evaluations after plant staxtup will. be made on the basis of baselines, con-sidering geography and time of year where these factors are applicable, and by comparisons to control stations where the concentration of station effluents is expected to be negligible.

The reference samples provide a running background which will make it possible to distinguish significant radioactivity introduced into the environment by the operation of the station from that introduced by nuclear detonations and other sources.

<<22 In those cases where a. statistically significant increase may be seen in a particular sampling vector but not in the control station, meteorology and/or specific radionuclide analysis will be used to identify the source of the increase.

The planned sampling frequencies and analysis sensitivities will assure that changes in the environmental radioactivity can be detected. The materials which first show changes in radioactivity are sampled most frequently.

Those which are less affected by transient changes but'show long term accumulations are sampled less frequently. However, the specific sampling dates are not crucial,'nd adverse weather conditions or equipment failure may on occasion prevent collection of specific samples.

A report shall be submitted to the USNRC at the end of each six of operation specifying total quantities of radioactive material months'eriod released to unrestricted areas in liquid and gaseous effluents during the previous six months and such other information on releases as may be required to estimate exposures to the public resulting from effluent releases. If quantities of radioactive material released during the repoxting period axe unusual for normal reactor operations, including expected operational occurrences, the report shall cover this specifically.

A concentration of I-131 in milk of 3.1 picocuries per liter will result in a dose to the thyroid of a 0 year-old child of 15 mrem/yr, based upon consumption of one liter per day for the year. To assure that no child will receive a dose of greater than 15 mrem/year/reactor to the thyroid, it is necessary to know the radioiodine concentration in the milk to the sensitivity of 1.5 pCi/liter.

<<23 5-0 ADMINISTRATIVECONTROLS Ob)ective This section describes the administrative and management controls established to provide continuing protection to the environment and to implement the environm n al technical specifications. Measures to be specified in-this section include the as ignment of responsibilities, organizational structure, operating procedures, review and audit functions, and. reporting requirements.

S ecifications 5.1.1 The power plant superintendent has responsibility for operating the plant within the limiting conditions for operation (LCO).

5.1.2 The Director, Division of Environmental Planning, is responsible for the envirorimental monitoring program outside the plant.

5.2.1 The organization of TVA management which directly relate to operation of the plant is shown on Figure 5.2-1.

5.2.2 The principal divisions within TVA which are concerned with environ-mental matters related to nuclear power plant operation are the Division of Power Production (DPP), Division of Forestry, Fisheries, and lildlife Development (FF>H)), Division of Power Resource Planning (DPRP), and the Division of Environmental Planning (DEP). The DPP and DPRP are in the Office of Po~er. The Office of Power Quality Assurance end Audit 5taff is a special .staff within the Office of Power. The Office of Power, DEP, and FPilD report to the General Manager. This is depicted in Figure 5.2-2.

5. 3 Review and Audit 5.3.1 The Director, DEP, is responsible for review of plant operation related to LCO to insure that plant operation is being conducted within the limits defined in Section 2 of this document.

5. 3.2 The Office of Power Quality Assurance and Audit Staff shaLL conduct a periodic audit of the environmental mor.itoring program at intervals not to exceed, one year.

5, 3, 3 The DPRP and/or DEP shall review and con5ribute to the following items:

a. Preparation of the proposed environmental technical specifications.

b. Coordination of environmental technical specificatio'n development with the safety technical specifications to avoid conflicts and maintain consistency.

c. Proposed changes to the environmental technical specifications and the evaluated impact of the change.

d. Proposed written procedures, as described in Section 5.5 and proposed changes thereto which could significantly affect the plant' environmental impact.

e. Proposed changes or modifications to plant systems or equipment which could significantly affect the plant's environmental impact and the evaluated impact of the changes.

f. Results of the environmental monitoring programs prior to their submittal in each Annual Operating Report. See Sections 5.6.1 and 5.6.2.

g. Repoxted instances of violations of environmental technical specifications. Where investigation indicates, evaluation and formulation of recommendations to prevent recurrence.

5.4 Action to be Taken if an Environmental LCO is Exceeded 5.4. 1 Follow any remedial action permitted by the technical specifications until the condition can be met.

5.4.2 The DPP shall promptly report the violation to the Manager of Power and the Director, DEP.

5.4. 3 DEP will then conduct an independent investigation of the incident.

DEP will then report the results of its investigation to the Manager of Power, the Office of Power. Quality Assurance Manager, the Director, DPP, and the Director, DPRP.

5.4.4 An investigation of reported or suspected incidents involving violation shall be=initiated. This investigation shall consist of the circumstances leading to and resulting from the situation together with recommenda-tions to prevent a recurrence. The xe"ults shall be submitted to the Manager of Power, the Office of Power Quality Assurance Manager, the Director, DPP, the Director, DPRP, and the Dixector, DEP.

5.4.5 Notification of the Director of the Regional Regulatory Operations Office, Region II of NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> shall be made as, specified in Section 5.6.3. Reporting requirements for this paxagraph are described in Section 5.6.3.

5.5 Procedures 5.5.1 Detailed written procedures for the in-plant nonradiological monitoring program, including check-off lists, where applicable, shall be prepared by DPP and approved by the plant superintendent and adhered to.

A quality control pxogram has been establislied with the AJ.abama Department of Public Health Environmental Health Administration Laboratory and the Environmental Protection Agency, Montgomery, Alabama. Samples of air, water, milk, and vegetation collected around the BFNP are forwarded to these laboratories for analysis; and results are exchanged for comparison.

An internal quality control program is being conducted whereby roughly one 'tenth of all samples are analyzed in duplicate. A quality control program is conducted with the Environmental Protection Agency in Las Vegas in which spiked samples are analyzed and the results compared.

5.5.2 Detailed written procedures for the environmental monitoring program outside the plant, including check-off lists, where applicable, shall be prepared, approved by t;he Director, DEP, and adhered to.

5.5.3 All procedures described in Section 5.5.1 and all changes thereto shall be reviewed and approved prior to implementation and on an annua1 basis thereafter by the plant management. Temporary changes to procedures which do not change the intent of the original procedure may be made, provided such changes axe documented and are approved by two of the following plant personnel:

Superintendent Assistant Superintendent Operations Supervisor Assistant Operations Supervisor Shift Engineer 5.6 Re ortin Re uirements 5.6.1 A report shall be prepaxed by DEP and submitted to DPP following the end of each 12-month period of operation, which shall summarize the results of the nonradiological environmental monitoring pxogram.

5.6.2 Routine R ortin

a. A summary report shall be prepared by the DPP for both the inplant monitoring and the nonradiological environmental monitoring programs and submitted by the Manager of Power, TVA, to the Director of Division of Operating Reactors, NRC, as part of the Annual Operating Report within 90 days of December 31.

b. Radiolo ical Environmental Monitorin Routine Re ortin Reporting Requirements:

1. TVA shall prepare a report ent'tied "Environmental Radio-activity Levels Browns Ferry Nuclear Plant Annual Report."

The report shall cover the previous 12 months of operation and shall be submitted to the Director of the NRC Region II Office (with a copy to the Director, Office of Nuclear Reactor Regulation) within 120 days after January 1 of each year.

The report format shown in Regulatory Guide 4.8 Title 1 shall be used. The report shall include summaries, interpretations, and evaluations of the results of the radiological environmental surveillance activities for the report period, including s comparison with preoperational studies and/or operational

controls (as appropriate), and an assessment of the observed impacts of the plant operation on the environment. Xf harmful effects or evidence of irreversible damage are detected by the monitoring, the licensee shall provide an analysis of the problem and a proposed course of action to alleviate the problem.

2. Results of all radiological environmental samples taken shall be summarized and tabulated on an annual basis. In the event that some results axe not available within the 120-day period, the report shall be submitted noting and explaining the reasons for the missing results. The missing data shall be submitted as soon as possible in a supplementary report.

5.6.3 Non-Routine Re orts Anomalous Heasuxements

1. If, during any 12-month report period, a measured level of radio-activity in any environmental medium other than those associated with gaseous radioiodine releases exceeds ten times the control station value, a written notification will be submitted within one week advising the NRC of this condition.~ This notification should include an evaluation of any release conditions, environ-mental factors, or other aspects necessary to explain the anomalous result.

2. If, during any 12-month report period, a measured level of radioactivity in any environmental medium other than those associated with gaseous radioiodine releases exceeds four times the control station value, a written notification will be submitted within 30 days advising the NRC of this condition.

This notification should include an evaluation of any release conditions, environmental factors, or other aspects necessary to explain the anomalous resul-.

3. If individual milk samples show I-131 concentrations of 10 picocuries per liter or greater, a plan shall be submitted within 10 days advising the NRC of the proposed action to ensure the plant related annual doses will be within the design obgective of 15 mrem/yr/reactor to the thyroid of any individual.

4. If milk samples collected over a calendar quarter show average concentrations of 6.0 picocuries per liter or greater, a plan shall be submitted within 30 days advising the NRC of the proposed action to ensure theplant-related nnual doses will be within the design ob)ective of l5 mxem/yr/reactoz ro the thyroid of any individual.

• In the case of a tentatively anomalous value for radiostxontium, a confirmatory reanalysis of the original, a duplicate or a new sample may be desirable. In this instance the results of the confirmatory analysis shall be completed at the earliest time consistent with the analysis, and if the high value is real the report to the NRC shall be submitted within one week following this analysis.

5~ If such levels as discussed in 5 ' '(a)3 and 5 ' '(a)4 can be definitely shown to result from sources other than the Browns Perry Nuclear Plant, the reporting action called for in 5;6.3(a)3 and 5.6.3(a)4 need not be taken. Justification for assigning high levels of radioactivity to sources other than the Browns Feriy Nuclear Plant must be provided in the annual report.

b. Nonradiolo ical In the event a limiting condition for operation is exceeded or an unusual event with a potential for a significant environmental impact occurs, a report shall be made within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by telephone or telegraph to the Director of the'egional Office of Inspection and Enforcement, Region IX, followed by a written report summarizing the results of investigations by DEP and DPP within 10 days from the Office of Power to the Director of the Pegional Office, of Inspection and Enforcement, Region II (copy to the Director of Division of Operating Reactors) .

c. ~Chan es 1~ Vhere a change to the plant desigp, the plant operation, or to procedures is planned which could have a significant adverse effect on the environment or which involves an environmental matter or question not previously reviewed and evaluated by the NRC, a request for the change shall be made to the implementation. NRC'efore

2. Changes or additions to permits and certificates required for the protection of the environment shall be reported. When the required changes are submitted to the concerned agency for approval, they shall also be submitted to the Director, Division of Operating Reactors, USNRC, for information.

3. Requests for changes in environmental technical specifications shall be submitted to the Director, Division of Operating Reactors, USNRC, for prior review and authorization.

5 ' Environmental Records 5.7.1 Operational information concerning the inplant portion of the environ-mental technical specifications shall be kept by DPP in a manner convenient for review, This includes plant records and/or logs as indicated below".

a. Related plant operations

b. Related maintenance activities

c. LCO violation

d. Updated, corrected, and as-built drawings of the plant Item (a) through (c) above shall be retained for a period of at least six years and item (d) shall be retained for the life of the plant

5.7.2 Records and/or logs shall be maintained by DEP and/or DWM in a manner convenient for review. This information concerning the environmental monitoring pxogram is indicated below:

a. Checks, inspections, tests, and calibra ion of components and systems.

Principal maintenance activities associated with environmental monitoring equipment and systems.

c. Results of environmental monitoring surveys related to RFNP.

Items (a) and (b) shall be retained for a period of at least six years and item (c) shall be retained for the life of the plant.

T b 3,1,2 Sources of A";cd. Chemicals and Resul" in End rcduct Ch=.icels Maximum Resulting Chemical iilazimur. E;.;stc End End Product Added. Annual Cqe P. oc,act Annual Mean Daily S stem Source Chemical Chemical lbs lbs Makeup Mater Treatment Alum Plant ,( o), 8 ,0 15,800 Al(0~) 3,7oo

~10 So) 6,8oo Suspended solids. 13g500 Soda Ash Na2 C03 (100$ ) 7 ~900 3,4oo Sodium 3>950

'C1 26o lkypochlorite NaOC1 (2lg Solution) 570 CoagQ.ation Aid 590 Coag. Aid 590 Makeup vater Sulfuric Acid 98$ 270,000 S04 259,000 ~710 Treatment Plant Demincraliier Rcgcncration Sodium Hydroxide

(5o"). 205,000 59~000 Auxiliary Steam Ammonia Variable Generator

)iH3 ~0.02 Blovdovn Hydrazine Variable NH3 0.4 <0.001 Rav cooling vater Chlorine Variable OC1 and Cl Variable 1,620 System a ~ Based on 24-hour operation 365 days/year a demonstrated maximum capacity of equipment.

bo Suspended. materials that vill make up the vater treatment plant sludge, on a dry veight basis, C ~ Estimates from suspended solids data ob ervcd at TPA 300.3, d, Pnmonia vill be added as needed to keep pH of system at 9.0, ee Hydrasine vill be added ao nccded as a DO scavenger,

Table 3.1.2-2 SONNY OF CHFtGCAL DISCHARCES lfaste b Maximum Product , Observed Total Annual Chemical Concentrations in Concentrations i%xximB Discharge Contribution Reservoir Mater in River Allovable of Product to Discharge at TM4 300.3 After Mixing Concentrations l'aste Product Chemical Concentrations mc/1 m /1 in River Cher ical lbs mp/1 Average Hmimum ~Avera e Mexiaaae m 1 Sul fates 265,800 0. 031 15. 0 23. 0 .15.027 23.027 250 (S04 )

Sodiua 62,700 0-007 5.92 9.18 5.9263 9.1863 (i:a.+)

Chlorides 34,600 0.068 lb.0 21.0 14,060 21.060 250 Ar ~onia f 6.4 0.02 0.07 0.02 0.07 HH Total Dissolved 363,106 0.106 104.0 129.0 104.093 129.093 500 Solids

a. Based on 24-hour operation 365 days per year at demonstrated maximum capacity of equipment and chemical requirements.

b. Discharge flcris based on 3-unit operation.

c. Concentrations bascd3on downstream riverflov of 5,000 ft3/s. However, heat dissipation considerations vill require minimum of 23,000 ft /s for open mode.

Ho specific standard has been identified'but contribution to dissolved solids has been included.

e. Computation is for chlorides since the chlorine demand of the cooling vater is such that no residual chlorine <ill be discharged. Chlorides and total dissolved solids reflect maximum daily usc of chlorine in rav cooling voter.

f.'mmonio and hydrazine added to auxiliary steam generator for pH and dissolved oxygen control." Hydrazine conservati~ y

'a"sumcd to decompose to ammonia..

g. Alabama .'ster Improvement Coranission Stream Standards.

'Cable 4,}.-3.

St@MARY OF hOMRADIOLOGICAL MO'NITORINC PROCRAM Rl04'llS FnlRY llUCLFAB PLANT Zooplankton, Chlorophyll Productivity Benthic =

end P o lankton Gm lin l~casulcment Fnuna Salivant Fish Second Creek Babayment Station 277.9S X 263,94 X Elk Mver BAayment Station ZOO.78 X 291.76 X 293.70 x' 2n.O7 299.00 301e06 307o5'2

- Indicates at least ono quarterly oemplc co&ected at the epecificd station,

a. Fish sa~pling et a specific station vill Wc by either chill nct, trap nct, rotcnonc, pr clcctrofishirg, Hovevcr>

depending upon thc snpling lscthod thc frcpucncy of samplins at each location mcv bc lcs,"than cuartcrly.

A>elysis - Dissolved oiypen and temperatures c<<Analysis - Dissolved oxygen, temperature BOD~~ COD,,l, alkalinity, specific conductance, Ãa, SOl,, chlorides>

nitro"cns (llll3,,N02+NO~, and orSanic) and s61ids (8's".olvcd, suspended, and total),

Table 4.2-1

".nvironmental Radiolo ical Monitorin Exposure Pathway Number of Samples Sampling and Type of Frequency and/or Sam le and Locations Collection Fre uenc of Anal sis AIRBORNE Particulates 4 samples from locations {in different sectors) at or near the site boundary 1 'sample from the residence having the highest X(Q Continuous sampler operation Gross beta folloving filter change vith sample collection veekly Composite {by location) monthly 4 samples from communities for ~amma scan. Composite quarterly approximately 10 miles for Sr, Sr. If any filter distant from the plant indicates a gross beta concentration 1.0 pCi/m greater than the average 2 samples from control of the control stations, a gamma locations greater than scan vill be performed on the filter Radioiodine 10 miles from the plant Samples from same locations as air particulates Continuous sampler operation with filter collection weekly

'I weekly Fallout Samples rrom same locations Heavy particle fallout Cross beta monthly as air particulates collected continuously on gummed acetate paper vith paper collection monthly Rainwater Samples from same locations Rainwater collected con- Gamma scan, monthly as air particulates tinuously with composite sample analyzed monthly Soil Samples from same locations Once per 3 years Gamma scan, Sr, Sr as air particulates once each 3 years

Table 4,2-1 (Continued)

Exposure Pathvay Number of Samples Sampling and, Type and Frequency and/or Sam le and Locations Collection Frecuenc of Anal sis DIRECT 2 or more dosimeters placed't Quarterly Gamma dose quarterly the air, particulate sampling stations located greater than 5 miles from the plant 2 or more dosimeters placed at 8 locations (in different secotrs) at or near the site boundary WATERBORNE Surface 1 sample upstream CoU.ected by automatic Gamm can monthly 1 sample immediately dovn- sequential-type sampler omposite for tritium, stream of discharge vith composite sample 9Sr and, ~ Sr quarterly 1 sample downstream, after taken monthly dilution 1 sample adJacent to plant Collected by automatic Gamma scan monthly sequential-type sampler 3H quarterly on monthly vith composite sample composite taken monthly 1 sample from ground vater hhnthly Gehenna scan monthly source upgradient H quarterly on monthly composite Drinking 1 sample at the first Collected by automatic potable surface vater supply sequential-type sampler downstream from the plant vith composite sample taken monthly

Table 4.2-1 (Continued)

Exposure Pathway Number of Samples Sampling and Type and Frequency and/or Sam le and Locations Collection Fre uenc of Anal sis 1 sample at the second Monthly Gross beta end gamma scan dovnstream potable surface monthly. gomposite (or vater supply (19.1 miles tritium, >Sr, and 9 Sr dovnstream) quarterly 2 samples at control -Monthly locations AQUATIC Sediment and 1 sample upstream from Asiatic Clams discharge point 1 sample in immediate Semiannually Gamma scan, Sr, snd Sr dovnstream area of discharge analyses semiannually ( 9Sr, point and VOSr on sediment and clam shells only) 2 samples downstream (4.9 and 15.7 miles)

Plankton 1 sample upstream from discharge point 1 sample in immediate dovn- Semiannually stream area of discharge point 1 sample dovnstream (15,7 Gross beta sgmiannually, miles) Gamma scan~ o9Sr 90Sr vhen sufficient quantities are available INGESTION

Table 4.2-1 (Continued)

Exposure Pathvay Number of Samples Sampling and Type and Frequency and/or Sam le and Locations Collection Fre uenc of Anal sis 131 4 samples from dairy farms Weekly or semimonthly (vhen 1 analysis veekly o in the immediate vicinity animals are on pasture) semimonthly when cattle of the plant depend.'ng on calculated are on pasture doses."'onthly vhen animals are off pasture.

1 sample from control Gamma scan, Sr, and Sr location monthly Fish 1 sample each of a commercial and, a game species in Guntersville Reservoir above the plant 1 sample each of a commercial Semiannually Gamma scan semiannually.

and a game species in Wheeler Reservoir near the plant 1 sample each of a commercial and a game species in Wilson Reservoir belov the plant

'egetation 4 samples from the dairy Quarterly Gamma scan, (Pasturage farms from vhich milk is and Grass,) obtained "Milk samples vill be collected"and analyzed veegly in areas where the calculated dose toa chil/'s thyroid exceeds 3.5 mrem/year. Sampling and analysis vi11 be-conducted semimonthly in areas vhere the dose is calculated to .be sl5 mrem/year.

Table 4.2-1 (Continued)

Exposure Pathway Number of Samples Sampling and Type and Frequency and/or Sam le and Locations Collection Fre uenc of Anal sis Fruits and Samples of corn, green Annually, at time of Gamma scan on edible portion Vegetables beans, tomatoes, and harvest potatoes grown at private gardens and/or farms in the immediate vicinity of the plant location determined by census.

1 sample of each of the same foods grown at greater than 10 miles distance.

from the plant.

Table 4.2-2 Atmos heric and Terrestrial Monitorin Station Locations Browns Per Nuclear Plant Location Sam le Station Distance and direction from lant IM-1 BF 1.0 mile N'.9 LM-2 BF miles NNE LH-3 BP 1.0 miles NE LM-4 BP 1.7 miles NNtI LM-5 BF 2.5 miles WSW PH-1 BF (Rogersville, AL) 13.8 miles NW PM-2 BP (Athens, AL) 10.9 miles NE PM-3 BF (Decatur/Trinity, AL) 8.2 miles SSE PM-4 BP (Courtland, AL) 10.5 miles WSV RM-1 BP (Muscle Shoals, AL) 32.0 miles W RH-2 BP (Lawrenceburg, TN) 40.5 miles NNW

Table 4.2-3 TYPES AND LOCATIONS OF SAMPLES COLLECTED FOR OPERATIONS RAD ANALYSIS IN WHEELER RESERVOIR IN RELATION TO THE BROWNS FERRY NUCLEAR PLANT TRM Station Water a Plankton b Asiatic Clams Sediment Fish c 307.52 305. 0 293.70 293.5 291.76 288.78 285. 2 277. 98

a. Collected automatically

b. Vertical tovs

c. G/E - Gill net and/or electroshocker vill be used for collection.

Samples of fish vill be collected from Guntersville, Wheeler, and Wilson Reservoirs.

Table 4.2-4 LISTING OF TENNESSEE RIVER SURFACE WATER SUPPLIES TO BE SAMPLED IN ENVIRONMENTAL MONITORING PROGRAM Distance from Plant

~Su ~1 (miles)

Courtland (Champion Paper Co.) 11.6 Decatur b 32.0 Wheeler Hydro Plant 19.1 Sheffield 39-7

a. First potable eater supply dovnstream of the plant. Sample collected automatical~ and analyzed monthly.

b. Decatur is upstream of the Browns Ferry Nuclear Plant.

TAELE 4. 2-5 Detection Capabilities for Environmental Sam le Analysis Nominal Lower Limit of Detection (LLD)

Airborne Particulate Pish, Heat, Water or Ga~ or Poultry Hilk Vegetation Soil

~Anal sis ~(C i/l) Ci/m ) I ) ( Ci/k , wet) ( Ci/k d )

gross beta ,01 H 330 1 44( e* 30 .03 90 115 "Cr< 60 .07 200 240 131Z 151> Ql* 50% 1.5 7 0r>

106R

• 30 .04 150 150 1 34( s>r. 10 .Ol 40 50 137Cs 10 .01 40 10 50 120

" Zr-Nb<< I 10 .01 40 50 O

60(.

• 15 .02 55 70 I

'4Mn* 10 .02 40 50 "Zn~ 15 .02 70 75 6 0(. 10 .Ol 30 40

" K> 100 .10 400 500 1408a La* 15 .02 150 15 145 09S . 005 40 10 90S . 001 150 These measurements are performed by gamma spectroscopy. The LLD values are calculated by the method of Pasternack and llarley as discussed in HASL-300. The original method was published in Nucl. Instr. Methods 91, 533-40 (1971) ~

These LLD values are expected to vary depending the activities of components in the samples. These figures will be rarely, if ever, attainable. Water is counted in a 3.5 liter Marinelli beaker. Vegetation is counted in a 1-pint container as dry weight, then corrected to wet weight using an average moisture content of 80/. Average dry weiglrt is 125 grams. Fish, meat, and poultry are counted in a 1-pint concair.er as dry weight, then corrected co wec;/eight using an average moisture content of 70/. Average dry weight is 250 grams. Air Particulate Filters are counted in a well crystal. The councing system consists of a multichannel analyzer and eicher a 4" x 4" solid NaI crystal or a 4" x 5" NaI well crystal. The counting time is 4,000 seco..ds. All calculations are performed bY the least-squares comp:c'r program ALPHA"M The assumption is made that all samples are analy"ed within or.c week of collection.

~r

.9

';"REELER.-,; /.."..'g~~

DIM g~

AM' pe BROVINS FERRY NUCLEAR PLANT

.':,::,4,.;, xos g::,':::...Q::::;:;::.:-; 'wx:,.::-'

'EXlSTlNG TEMPERATURE MONlTOR Figure 2.1-1 MONITORING LOCATIONS IIItHEELER RESERVOtR 0

SCauS OP wats ~ f,l pt fCCtlCITXCK'&I {

42.-

Figure 4.2-1 LQCAL MQNlTQRIMG STAT[QNS BROWNS FERRY NUCLEAR PLANT ATHENS US HWY 72 BFNP ALA. HVIY 20 Legend 0 Air Monitor, DECATUR 0 Air Monitor 8 TLD Station N TLD Station AUtomatic Vlell Sampler Scale B Dairy Farm 0 I 2 8 0 6 Miles

lI3 Figure 4 .2-2 Brogans Ferry Nuclear Plant ATMOSPHERlc AND TERRcSTRIAL MOIUITORliilG NETV/ORK RM 2BF LAWRENCKBURG gPULASKI FAYETTKVILLE fy'M.IBF WILSON WHEELER RPGERSyiLL OAM OA h'I ATHENS FLORENCE PM-2BF 8

FFIKL r~m MUSCLE SHOALS

$ RM. I BF LEIGHTON TUSCUMBIA tp 8'UNTSVILI.E BROWNS FERRY NUCLEAR PL NT

~fW COURTLAN0$

Ph'I-4BF DECATUR PM-30FO IO MII.ES RUSSELLVILLE S VIL c S GUN T OAM HARTSELLE 25 S HALEYVILLE

@CULLMAN 45 MILKS Q- KNVIROiNMKNTAL hIONITORING STATION NOTE: THE FOLLOWING SAhIPLES ARE COLLECTEO FROM EACH STATIOhl:

AIR PARTICULATES RAINWATER RAOIOIOOINE SOIL HEAVY PARTICLE FALLOUT VEGETATION

44 Figure 4.2-3 Browne Ferry Nuclear Plant R ES ERVOI R MONlTORl N G NETWORK Elk River M/HEELER DAM mile 270.90 mile 277.98.

Rogersville 0

mile 29l.76 Athens mite 282.6 0

~mile 285.2 B.F. NUCLEAR PLANT B

Champion Pap r Co. .

mile 28878 mite 293.50 mite 305.0 Cour tland mile 293.70 0

Decatur mile 307.52 Scale of Miles o- Automatic Sam ler 0

HANAGER OF POWER DIVISION OF POWER PRODUCTION CHIEF, NUCLEAR GENERATION BRANCH NUCLEAR PLANTS BROWNS FERRY NUCLEAR PLANT TVA Office of Power Organization for Operation of Nuclear Plants Figure 5.2-l

BOARD OF DIRECTORS OFFICE OF THE GENERAL HANAGER AUDIT STAFF INFORNATIDN OFFICE MASHIHGTOH OFFICE EQUAL EHPLOYHEHT OPPORTUHITY STAFF DIVISION OF DIVISION OF DIVISIOH OF DIVISION OF DI VIS IOH OF LAHD BETWEEN LAM PERSONNEL F INAHCE PURCHASING PROPERTY PHD SERVICES THE LAKES DIYISIOH OF OFFICE OF OFFICE OF POMER OFFICE OF DIVISIOH OFFICE OF MATER ENGINEERING DESIGN AGRICULTURAL AND OF TRIBUTARY DIV IS IOHS:

HAHAGEHENT AND CONSTRUCTION CNEHICAL DEVELOPHEHT HEDICAL AREA POMER RESOURCE PLANHIHG SERVICES OEV ELOPlEENT DIYI5 IOHS: DIVISIONS:

TRANSMISSION PLANHIHG ENGINEERING DES IGN AHO EHGINEERIHG AGRICULTURAL DEYELOPHEHT DIVISION OF CON STRUCTIOH POMER CONSTRUCTION CHEHICAL DEVELOPHEHT DIVISION DIVISION OF NAVIGATION POKER PRODUCTIOH CNEHICAL OPERATIONS OF FORESTRY'ISHERIES'HD DEVELOPHENT POMER SYSTEH OPERATIONS ENVIROHNENTAL AHD REGIOHAL POMER UTIL IZATIOH PLANNING MILOLIFE STUDIES DEVELOPHEHT STAFFS:

(gALITY ASSURANCE AHD AUDIT STAFF NUCLEAR SAFETY REVIEM BOARD BROMHS FERRY NUCLEAR PLANT POMER RESEARCH STAFF Organlzatlon of the Tennessee Valley AuthorIty Figure 5,2-2