ML18283B912

Appendix a to Facility Operating License DPR- Technical Specification and Bases for Browns Ferry Nuclear Plant Unit 3, Limestone County, Alabama, Tennessee Valley Authority, Docket No. 50-296

ML18283B912
Person / Time
Site:	Browns Ferry
Issue date:	09/19/1975
From:	Tennessee Valley Authority
To:	Office of Nuclear Reactor Regulation
References
Download: ML18283B912 (407)

Text

ENCLOSURE 1 COP

@EQULATGRY DOC'<~'-'" ~LE APPENDIX A TO FACILITY OPERATING LICENSE DPR-TECHNICAL SPECIFICATION AND BASES FOR BROWNS FERRY NUCLEAR PLANT UNIT 3 LIMESTONE COUNTY, ALABAMA TENNESSEE VALLEY AUTHORITY DOCKET NO. 50-296

l n TABLE OF CONTENTS Section P~ee No.

Introduction ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ e e ~ ~ e ~

1.0 Definitions e ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ e e SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 1.1/2.1 Fuel Cladding Integrity 1.2/2.2 Reactor Coolant System Integrity . 27 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE RE UIREMENTS 3el/4.1 Reactor Protection System 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 D. Off-Gas Post Treatment Isolation Functions ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 51

~ E. Dryvell Leak Detection . 52 i F. Surveillance Instrumentation . . . . . . . . . 52 G. Control Room Isolation . . . . . . . . . . . . 52 H. Flood Protection . 53 3.3/4.3 Reactivity Control 108 A. Reactivity Limitations B. Control Rods ~ ~ ~ ~ 109 C. Scram Insertion Times ~ ~ ~ ~ ~ ~ ~ ~ ~ 112 D. Reactivity Anomalies . . . . . . . . . . . . . 113

0 0

Section ~Pe e No.

I E. Reactivity Control . . . . . . . . . . . . . . 114 3.4/4.4 Standby Liquid Control System 122 A. Normal System Availability . 122 B. Operation with Inoperable Components . . . . . 123 C. Sodium Pentaborate Solution . . . , . . . . . 124 3.5/4.5 Core 'and Containment Cooling Systems . . . . . . . 130 A. Core Spray System 130 B. 'Residual Heat Removal System (RHRS)

(LPCI and, Containment Cooling) . . . '. . . . . 132 C. RHR Service Water System and Emergency ~uipment Cooling Water System (EECWS) e ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ e ~ ~ ~ 135 D. Ecjuipment Area Coolers . . . . . . . . . . . . 138 E. High Pressure Coolant Infection System

' 138 (HPCIS) ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ , ~ ~ ~

F. Reactor Core Isolation Cooling System (RCICS) . . . . . . . . . . . . . . . . 139 G. Automatic Depressurization System

( ADS) ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

'I

~ ~ ~

' ~ ~

'40 H. Maintenance of Filled Discharge Pipe . 141 I. Average Planar Linear Heat Generation Rate 142 J. Linear Heat Generation Rate ~ - ~ ~ 142 K. Minimum Critica1 Power Ratio (MCPR) 142-A L. Reporting Requirements............ 142-A 3.6/4.6 Primary System Boundary e ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 151 A. Thermal and Pressurization Limitations.... 151 B. Coolant Chemistry 153 C. Coolant Leakage 154 D. Safety and Relief Valves . . . . , . . . . . . 155

Section ~Pe e No.

E. Jet Pumps 155 F. Jet Pump Flow Mismatch . 156 G. 'tructural Integrity . 156 H. Hydraulic Snubbers 158a 3.7/4.7 Containment Systems 175 A. Primary Containment 175 B. Standby Gas Treatment System . 183 C. Secondary Containment 184a D. Primary Containment Isolation Valves 186 E. Control Room Emergency Ventilation . 188 F. Primary Containment Purge System . 188a 3.8/4.8 Radioactive Materials 217 A. Liquid Effluents 217 B. Airborne Effluents . 218 C. Radiological Environmental Monitoring Pr ogram ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 221 D. Mechanical Vacuum Pump . 227 E. Miscellaneous Radioactive Materials Sources 227 3.9/4.9 Auxiliary Electrical System 24O A. Auxiliary Electrical Equipment 24O B. Operation with Inoperable Equipment 243 C. Operation in Cold Shutdown 245a

3. 10/4.10 Core Alterations ~ ~ ~ ~ ~ ~

A. Refueling Interlocks 249 B. Core Monitoring 252 C. Spent Fuel Pool Water 252 D. Reactor Building Crane 253 E. Spent Fuel Cask 253

Section Paape No.

F. Spent Fuel Cask Hand1ing-Refueling Floor . . . . . . . . . . . . . . . . . . . . 254 5 ' Ma )or Design Features ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 261 5.1 Site Features . 261 5.2 Reactor/ . 261 5.3 Reactor Vessel ~ ~ ~ ~ '261 5.4 Containment ~ ~ ~ ~ 261 5.5 Fuel Storage 261 5.6 Seismic Design ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 262 6.0 Administrative Controls ............. 263 6.1 Organization . 263 6.2 Reviev and Audit . 263 6.3 Procedures 267a 6.4 Actions to be Taken in the Event of Ar.

Abnormal Occurrence in Plant Operation . . . 273 6.5 Action to be Taken in the Event a Safety Limit is Exceeded . . . . . . . . . . . . . . 273 6.6 Station Operating Records . . . . . . . . . . 274 6.7 Reporting Requirements . . . . . . . . . . . 276 6.8 Minimum Plant Staffing . . . . . . . . . . . 284

LIST OP TABLES Table Title ~Pa a 3.1.A Reactor Protection System (SCRAM) Instrumentation Requirements . 33 4.1.A Reactor Protection System (SCRAM) Instrumentation Functional Tests Minimum Functional Test Frequencies for Safety Instr. and Control Circui'ts ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 37 4.1.B Reactor Protection System (SCRAM) Instrument Calibration Minimum Calibration Frequencies for Reactor Protection Instrument Channels . 40 3.2.h Primary Containment and Reactor Building Isolation Instrumentation 54 3.2,B Instrumentation that Initiates or Controls the Core and Containment Cooling Systems. . . . . . . . . 61 3i2.C Instrumentation that Initiates Rod Blocks...- .. 72 3.T.n ,Off-Gas Post Treatment Isolation

( Instrumentation . . . . . . . . . . . . . ~ ~ 75 3.2.E Instrumentation that Monitors Leakage Into Dtgvell ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 76 3.2.P Surveillance Instrumentation.......... ~ 77 3t2tG Control Room Isolation Instrumentation . . . . o . 79 3o2tH Flood Protection Instrumentation . . . . . . . . . 80 4.2.A . Surveillance Requirements for Primary Containment and Reactor Building Isolation Instrumentation . 81 4.2.B Surveillance Requirements for Instrumentation that Initiate or Control the CSCS.......... 85 4 '.C Surveillance'equirements for Instrumentation that Initiate Rod Blocks . . . . . . . . . . . . . . 91

'4.2.D Surveillance Requirements for Off-Gas Post Treatment Isolation Instrumentation . . . . . .' . . . . 92 4.2.E Minimum Teat and Calibration Frequency 'for Drywall Leak Detection Instrumentation . . . . ~ 93

LIST OF TABLES Cont'd Teble Title ~Te e 4.26F Minimum Test and Calibration Frequency for Surveillance Instrumentation . 94 4.2.G Surveillance Requirements for Control Room Isolation Instrumentation . 95 4.2.H Minimum Test and Calibration Frequency fox'lood Protection Instrumentation . 96 4.6.h Reactor Coolant System Inservice Inspection Schedule ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 160 I

3 6H Hydraulic Snubbers Subject to Inspection 165a 367th Primary Containment Isolation Valves . 189 3,7.B Testable Penetretions with Double 0-Ring Seals . . 195 3 '.C Testable Penetrations with Testable Bellows. ~ . ~ 196 3,7eD Primary Containment Testable Isolation Valves... 197 3.76E Globe Valve Leakage Rates .......;

Suppression Chamber Influent Lines Stop-Check

..'. 202 3e 7.F Check Valves on Suppression'hamber Influent Linea . . . . . . . . . . . . . . . . . . . . . 202 3'76G Che'ck Valves'n Drywall Influent Lines . . . ' '03 3.7eH Testable Electrical Penetrations . . . ~ ~ . . . . 204 4.8.h Radioactive Liquid Waste Sampling and Analysis .

4.8.B Radioactive Gaseous Waste Sampling and Analysis 4.8.C Listing of Municipal Watex Supplies to be 1 Sampled in Environmental Monitoring Prograa.

4.8.D Types and Locations of Biological Samples. Cc1llacted 231 4.8.E Reservoir Samples Collected ~ 231 468.F Radiological Envixonmental Surveillance Progx'am . 232 6.3.A Protection Factors for Respirators . . . , . . . . 271 6egeA Minimum Shift Crew Requirements , . . .' . . . . 285

LIST OF ILLUSTRATIONS

\

~Fi ure Title 2.1.1 APRM Flow Reference Scram and APRM Rod Block Settings 13 2.1-2 APRM Flow Bias Scram Relationship to Normal Operating Conditions 26 4.1-1 Gr'aphic Aid in the Selection of an Adequate Interval Between Tests . . . . . , . . . , . . . ~

4.2-1 System Unavailability . . . . . . . . . , . . . . . . . . 107 3.4-1 Sodium Pentaborate Solution Volume Concentration Requirements ~ ~ ~ ~ ~ ~ ~

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 125 3.4-2 Sodium'entaborate Solution Temperature Requirements . . . . . . . ~ ~ ~ . ~ ~ . ~ . ~ ~ ~ i ~ a 126 3.5;1-A MAPLHGR vs. Planar Average Exposure

( Type 2) ~ ~ ~ ~ ~ ~ ~ ~, ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ \ ~ ~ i 150-b 3.5il-B MAPLHGR vs. Planar Average Exposure (Type 1 & 3) ~ ~ ~ ~ ~ ~ ~ a ~ ~ a ~ i o e ~ ~ ~ ~ ~ ~ ~ ~ 150-c 3 5.2 Kf Factor vs. Percent Core Flow . 150-d 3.6-1 Temperature-Pressure Limitations vs. Neutron Exposure ... . . . , . . . , . ~ 159 3.6-2 Chloride Stress Corrosion Teat Results at 500'F. . . , . 174 4.8-1 Atmospheric and Terrestrial Monitoring Network . 234 4.8-2 Reservoir Monitoring Network. 235 6.1-1 TVA Office of Power Organization for Operation of Nuclear Power Plants. 286 6.1-2 Functional Organization

. ~ ~ 287 ~

6.2-1 Review and Audit Function . ~ a ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 288 vii

INTRODUCTXON This document presents the technical specifications for the Browns Perry Nuclear Plant Unit 3 only.

~ mm<<

1.0 DEPINITIONS The succeeding frequently used terms are explicitly defined so that a uniform interpretation of the specifications may be achieved.

able maintenance of t)le claddingsnnd primary systems are assured.

Exceeding such a limit requires unit shutdown and review by the Atomic Energy Conaaisoion before resumption of unit operation.

Operation beyond such a limit may not in itself result in serious consequences but it indicates all operational deficiency subject to regulatory review.

B. Limit<a Safet S s!em Settin~h".SS) - The limiting safety system setting are settings on instrumentation which initiate the automatic protective action at a level such that che safety limits will not be exceeded. The region between the safety limit and these settings represent margin with normal operation lying below these settings.

The margin has been establishd so that with proper operation of the instrumentation the safety limits will never be exceeded.

"'"""' 'n operation specify the minimum acceptable levels of system performance necessary to assure safe startup and operation of the facility. When these conditions are met tile plant ran be operated safely and abnor-mal situations can be safely controlled.

D. Abnormal Occurrence - An abn<>rmal occurrence means the occurrence of a plnnt condition t)lac rh>>>ult < 3n any of the following conditions:

l. A <<<<Coty <<yf>l:c<>>><-tl )llc ';!ll> co><l<.s. vot<ve than the limiting'etting

<'.st'<>b I i<<hell 3<l '>> <<< < l<<t ~

> <'!l l i!<mc ) ! j('> l

~ <A>if< ~

2. V in)><< i<i<> <!l  ;:": .Cl.on established in the 7<su)u> l C f<<) .>I' '

3<< Al> 'll<lnn<ll l i'> l i ~ ~ -<>)!!;.<.C)ve material from p)>lnt;>'!i. -.;

l; ', >li.i;l<"s J'or sucll material

'ny

~

in d<>>c<>><t >> i !i.,> t fi ), i<<<) Cs prescribed in TeC)>><in<> <

4 Vllilllrl'f <" >>.-'! i v <!dture or safety system> t l<h 'l !'!. ' ~ ~

.'e

~

) ff iirul e or Aystem to

$ u<:!<l>u)s)>> ~ l ll<",l )<>>> c<s <lefined in thee<<> ) ~ '<'l <i $ ! <1 ...f<l <;ty,ln<>lysis Report.

5. Abnor<<>i< l <><<g<<'<>><<

COntaill rh~ rdi'l>>l< -) lv,

., <"ill l nun<)aries designed to

!i,;> i <<<<.< t l .'><i) f l'old the prose<<<>.

6. Unco<ltr<>) )<d < y <<> ~>i> f<,>>c<:ivity greater Chan 1Xu k.

1.0 DEFINITIONS (Cont 'd)

7. Observed inadequacies in the implementation of administrative or procedural controls such that the inadequacy causes or threatens to cause the existence or development of an unsafe condition in connection with the operation of the plant.

8. Conditions arising from natural or offsite manmade events that affect or threaten to affect the safe operation of the plant.

R ~enable A system or component shall bc considered operable shen it is capable of performing its intended function in its required manner.

p. ~gratin Operatint means that a system or compoaent is perform-ing its intended functions in its required manner.

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

H. Reactor poser Operation Reactor poser operation is aay operation with the mode switch in the "Startup" or "Run" position with the reactor critical and above lX rated power.

coolant temperature greater than 212"F, system pressure less than 1055 psig, the main steam isolation valves closed and the mode switch in the Startup/Hot Standby position.

J. Cold Condition Reactor coolant temperature equal to or less than 212 F.

K. Hot Shutdown The reactor is in the shutdown mode and the reactor coolant temperature greater than 212'F.

L. Cold Shutdown - The reactor is in the shutdown mode, the reactor coolant temperature equal to or less than 212'F, and the reactor vessel is vented to atmosphere.

locks for the operational status of the unit. The following are the modes and interlocks provided:

l. Startu /Hot Standb Mode In this mode the reactor protection scram trips initiated by condenser low vacuum and main steam line isolation valve closure, are bypassed when reactor pressure is less than 1055 psig, the reactor protection system is energized with IRM neutron monitoring system trip, the APRM 15Z high flux trip, and control rod withdrawal interlocks in service. This is often referred to as )ust Startup Mode. This is intended to imply the Startup/Hot Standby position of the mode switch.

1 0 DEFINITIONS (Cont'd)

2. Run Mode In this mode the reactor system pressure is at or above 850 psig snd the reactor protection system is energized with APRM protection (excluding tha 15X high flux trip) and RBM interlocks in service.

3. Shutdown Mode - Placing the mode switch to the shutdown posi-tion initiates a reactor scram and power to the control rod drives is removed. After a short time period (about 10 sec),

the scram signal is removed allowing a scram reset and restoring the normal valve lineup in the control rod drive hydraulic sys-tem; also, the main steam line isolation scram and main can-denser low vacuum scram are bypassed if reactor vessel pressure is below 1055 psig.

4. Refuel Mode - With the mode switch in the refuel position inter-locks are established so that one control rod only may be with-drawn when the Source Range Monitor indicate at least 3 cps and the refueling crane is not over the reactor; also, the main stcam 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 fully inserted and none can be withdrawn.

N. Rated Power - Rated power refers to operation at a reactor power of 3,293 MWt; this is also termed 100 percent power and is the maximum power level authorized by the operating license. Rated steam flow, rated coolant flow, rated neutron flux, and rated nuclear system pressure refer to the values of these parameters when the reactor is at rated power. Design power, the power to which the safety analysis applies, is 105X of rated power, which corresponds to 3,440 MWt.

0. Primar Containment Inte rit - Primary containment integrity means that the drywall and pressure suppression chamber are intact and all of the following ronditions are satisfied:

1. All non-automatic containment isolation valves on lines connected to the reactor coolant system or containment which are not required to be open during acrident conditions are closed. These valves may be opened to perform necessary operational activities.

2. At least one door in each airlock is closed and sealed.

3. All automatic containment isolation valves are operable or deacti-vated in tha isolated position.

4. All blind flanges and manways are closed.

P. Secondar Containment Inta rit - Secondary containment integrity means that the reactor building is intact and the following condi>>

tions are met:

1.0 DEFINITIONS (Cont'd)

1. ht least one door in each access opening is closed.

2. The standby gas treatment system 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.

R. Refuelin Outa e Refueling outage is the period of time between 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 performed until the next regularly scheduled outage.

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-core instrumentation and the traversing in-core probe is not defined as a core alteration.

T. Reactor Vessel Pressure Unless otherwise indicated, reactor vessel pressures listed in the Technical Specifications are those measured by the reactor vessel steam space detectors.

U. Thermal Parameters

l. Minimum Critical 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 core.

Critical Power Patio (CPR) is the ratio 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. t

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

'I V. Instrumentation

1. Instrument Calibration - An instrument calibration means the ad)ustment of an instrument signal output so that it corresponds, within acceptable range, and accuracy, to a known value(s) of the

'arameter which the instrument monitors.

I

$ .0 D XNITIONS (gy)fr)I)

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xnstrument Functional Test -

H

3. + insgrumcnt functional test means the'$n')ection o 'pimqlatqd sfgns1 into the instrument pr'ipary Wensoy to verify tge proper ipspument channel response, 4)orm and/or initiatiny action,',

Xnstrument Check - An instrument check is qualitative determina-tioq of acceptable operability by observation of instrument behavior derring operation. This determination shall include, chery possible, cor(Iparison of the instrument vith other indepen-dent; instrqqents qeasuring the same variable.

Lo ic S stem Functional Test - A logic system functional test means a "tost of all xelays 'and contacts of a logic circuit to insure all components are operable per design intent. Wher((r, practicable, action vill go to completion; i,e., pumps vill be started and valves operated.

channel',txIip sf,goals and'auxiliary equipment required to initiate action ta, acpoqpliyg a protective trip function. A txip system may require pnq or mqre instrument channel trip signals related to oqq or agre" plant pararqeters in order to initiate trip system actioq, Xnitiatgon of'rotective action may require the tripping ol'he, coincident I

of a single tr'ig system tripping of two trip systegse

' t Protective Action - An action initiated by the protection system 7, ~

vhen a limit ia 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 coqdition.

9. Simulated Automatic Actuation - Simulated automatic actuation

<<L means applying a simulated signal to the sensor to actuate the circuit in question.

10. ~ho ic - d logic ia an arrangement of relaysconta, cts, and other components that'roduces 'a decision outout.

u, produces decision outputs to the actuation logic.

(h) Actuation - A logic chat receives signals (either from dt)it(ation logic or channais) and produces decision outputs to <<cccimplish a protective action.

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SAFETY LIMIT LiiITING SAFETY SYSTEM SETTING

1. 1 FUEL CLADDING INTEGRITY .1 FUEL CLADDING INTEGRITY In the event of operation with a maximum total peaking factor (MTPF) greater than the design value of 2.481 the setting shall be modified as follows:

2.481 S~ Q.58W + 62% ) ~F where:

MTPF ~ The value of the exis ting maximum total peaking factor For no combination of loop recir-culation flow rate and core thermal power shall the P"P; flux scram trip setting be allowed to exceed 120% of rated thermal pow z (NOTE: These settings assume operation within the basic thermal hydraulic design criteria. These criteria are LHGR < 13.4kW/ft and MCPR > ~ Therefore, at full pow operation is not allowed with max-total factor above imum 2.481even ifpeaking the scram setting is reduced. If it is determinedcri-that either of these design teria is being violated during opera tion, action must be taken immediate to return to operation within these criteria. Surveillance requirements for . maximum peaking factor are given in Sp'ecification 4.1.B.)

2. APRM--When the reactor mode switch is in the STARTUP position, th 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.

B. Core Thermal Power Limit Reactor Pressure 6800 sia

',he APRM Rod block trip setting shall When the reactor pressure is be:

less than or equal to 800 psia,

SAFETY LIMIT LIMITING SAFETY SYSTEM SETTING

1. 1 FUEL CLADDING INTEGRITY 2' FUEL CLADDING INTEGRITY or core coolant flow is less SRE<'0.58W'+

than 10% of rated, the core 50%)'here:

thermal power shall not ex-ceed 823 MWt (about 25% of rated thermal power). S~ Rod block setting in percent of rated thermal power (3293 MWt)

W Loop recirculation flow rate in percent of rated (rated loop recircula)ion flow rate equals 34.2 x 10 lb/hr)

In the event of operation with a maximum total peaking factor (MTPF) greater than the design value of 2,481 the setting shall be modified as follows:

2.481 S~< (0.58W + 50% )~

where:

MTPF ~ The value of the existing maximum total peaking factor C. Whenever the reactor is in C. Scram and isolation > 538 in. above the shutdown condition with reactor low water vessel zero irradiated fuel in the reac- level tor vessel, the water level shall not be less than 17.7 in. above the top of the normal active fuel zone.

D. Scram--turbhe stop < 10 percent valve closure valve closure Ei Scram turbine control valve Upon trip of

1. Fast closure the fast act-ing solenoid valves

2. Loss of control > 1,100 psig oil pressure F. Scram low con- o 23 inches denser vacuum Hg vacuum G. Scram--main steam < 10 percent line isolation valve closure H. Main steam isolation 0'50 psig valve closure nuclear system low pressure

SAPEIY LIMIT LIMITING ShPETY SYSTEM SETTING L 1 Fuel Claddin Inta rit 2.1 Fuel Claddin Inta rit I. Core spray and LPCI > 378 in.

actuation reactor above vessel low eater level aero J. HPCI and RCIC i 490,.in.

actuation reactor above vessel lev eater level sero K. Main stcam isola- > 490 in.

tion valve closure above vessel reactor'ow eater 'sero level

FIGURE DELETED

~ ~ ~ ~

e, 110 APRM FLOW BIASED SCRAM 80 APRM ROD BLOCK 0

70 X

Q R

o 40

~RECIRCULATION FLOW IS DEFINED AS RECIRCULATION LOOP FLOW 10 80 120

~RECIRCULATION FLOW I% of dcsignI BROIIItNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT APRM Flow Reference Scram and APRM Rod Block Settings Figure 2.1-1

FAILURE DELETED BASES: FUEL CLADDING INTEGRITY SAFETY LIMIT The fuel cladding represents one of the physical barriers which separate radio-active materials from environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking. Although some 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 from thermal stresses which occur from reactor operation significantly above design.

conditions and the protection system setpoints. While fission product migration from cladding performation is gust as measurable as that from use-related cracking, the thermally-caused cladding perforations signal a threshold, beyond which still greater thermal stresses may cause gross rather than incremental c1add ng deteriora-tion. Therefore, the fuel cladding safety limit is defined in terms of the reactor operating 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 L'imit is defined with margin to the conditions which would produce onset transition boiling (MCPR of 1.0). >>

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

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

Since boiling transition is not a directly observable parameter, the margin to boiling transition is calculated from plant operating 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 t'e 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 (HCPR). 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 nominal expected Qow control line. The Saf~tv Limit (RCPT iaaf'.A'~) has sufficient conservatism to assure that in the event of an abnormal operationa$ transient initiated from a normal operating condition (MCPR >. ) more than 99.9% of the fuel rods in the core are expected to avoid boiling 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 cycle.

l. 1 BP.M?S Becaus th>> boiling transition correlation is based on a large quant:ity of F>>11 scale data there is a very high confidence that operation of a fuel assembly at t)>e conclition of l'1CPR ~ 1.05would not produce boi3.ing tran-sition. Thus, although it is not required to establish the safety limit additional r>argin ex<<ta between the safety limit and 't: he actual occurrence of loss of cladding integrity.

However, if boiling transition were to occur, clad perforation would not be. expected. Cladding temperatures would increase to approximately 1100'F which is below t;he perforation temperature of the claclding mat:erial. This hn been verified by tests in the General Fleet:ric Te t Reactor (GETR) where fuel similar in design toBPNP operatccl above the critical heat flux for a significant period of time (30 minut:es) without: clad perforation.

k Xf reactor. pressure should ever exceed 1400 psia during normal power operat:ing (the 3.imit of applicability of the boiling transition corre-lation) it would be assumed tlrat the fuel cladding integrity Safety Limit has bc.en violat:ed.

ln addition to the boiling transition limit (IfCPR 1 03 ) operatic'n is constrained to a maximum LRGR 13.4 Rm/ft. At 100% poser this limit is reached with a maximum total peaking factor (1)TPP) of: 2.481. Por t)te case.

of tI>e HTPP exceeding p ~48, operation is permitt:c.d only at less t)tan 100/ of rated thermal power and onJy wit:h reduced Ai7PA scram sett:ings ns required by specification 2,1.A.1.'t pressures below 800 psia, the core elevation pressure drop (0 power, 0 f3ow) is greater thnn 4.56 psi. At low powers tncl f:lows this pressure differential is maintained in t)rc bypass region of the core. Since t)>e pres.,ure clrop in t)rc,)>ypnss region is essentially all elevation head, the core pressure drop a'our powers and flows wi3.3. a3way" be great:er t:han 4.56 psi. Analyses sltow t)tnt with a f3.otr of 28x3.03 llrs/hr 1>undle flow, lrundlc pressure drop is ncnrly independent of lrund3e power nnd has a value of 3.5 psi. T)rus, the b<<ndle flow with a <<.56 psi clriving he id will hr greater t)>an 28x103 lbs/hr. Puli scale AT1,AS te. t: clatn tnl;cn at pressures from 14.7 psia to 800 psia inclicate tltat the fuc.l assembly critical power at: t)tis flow is approximately 3.35 )1)b't. 1)lt)r t)rc. design peaking .f ctors this corrcs)bonds t:o a core t.hcrmal po rer of more t.)>an 50%. T)>us, a core thermal power limit of 25% for react:or pres. ures below 800 psia is conservative.

Fo<<he fuel in the core during period)a when t)>e reactor 's shut down, con-sideration must a3.so be, given to,wat:er level requirements due to t:hc e.feat of decay heat. if: water level should drop belabor the top of che fuel during thirI time, t)t>> nbility to remove decay heat is reduced; This reduction in coo3.ing cnpnbi3.ity coul<) lead to elevated cladding temperatures and c" ad perforntion. Ar< long as the fuel remains coverea irith wat:cr, ufficient c,oo)itic, is available to prevent fuel clad perforation.

1.1 BASES The safety limit has been established at 17.7 in. above the top of the irrddiated 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).

REFERENCE

1. General Flectric BWR Thermal Analysis Basis (GFTAB) Data, Correlation and Design Application, NEDO 10958 and NFDF. 10958.

17

PAGF. DHLFTFD 18

2.1 BASES

LIMITING SAFETY SYSTEM SETTINGS RELATED TO FUEL CLADDING INTFGRITY The abnormal operational transients applicable to operation 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 MWt. The analyses were based upon plant operation in accordance with the operating map given in Figure 3.7-1'f the FSAR. In,'addition, 3293 MWt is the licensed maximum power'evel of Browns Ferry Nuclear Plant, and this represents the maximum steady<<state power which shall'ot knowingly be exceeded.

Conservatism is incorporated in the transient analyses in estimating the controlling factors, such as void reactivity coefficient, control ro'd scram worth, scram delay time, peaking facctors, ynd axial power shapes. These factors are selected conservatively with respect to their effect on the applicable transi'ent results as determined by the current analysis model.

This transient model, evolved over many years, has bee'n substantiated in opera-

. tion ds.a conservative tool for evaluating 'reactor dynamic performance.

Results obtained from a General Electric boiling water reactor, have been compared with predictions made by'the 'model. 'The comparisions and results are summarized in Refeience 1.

The absolute value of the void reactivity coefficient used in the analysis is conservatively estimated to be about 25% greater than the nominal maximum valuue expected to occur during the core lifetime. The scram worth used has been dcrated to be equivalent'to approximately 8V'f the total scram worth of thc control rods. Thc scram delay time and rate of rod insertion allowed

'r)in ~n~lvcr s arc conservatively set equal to thc longest delny ard slow>>

est insertion rate acceptable by Technical Specifications.

The efie'ct of scram worth, scram delay time and rod insertion rate, all conservatively a'pplied, 'are 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 5% and 20% insertion.

By the time the rods are 60% inserted, approximately four dollarq of negative reac-tivity hss been inserted which strongly turns the transient,.and accomplishes the desired effect. The times for 50% and 90/ insertion are given to assure proper completion of the expected perfo'rmance in the earlier portion of 'the transient, and to establish the ultimate fully shutdown steady'-state condition.

For analyses of the thermal consequences of the transients a MCPR of is conservatively assumed to exist prior to initiation of the transients.

This choice of using conservative values of controlling parameters and initiating transients at the design power level, produces more pessimistic answers than would result by using expected values of, control parameters and analyzing at higher power levels.

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

19

Xn GuU5)ary )

L. The Licensed maximum power level io 3,293 KMt.

Analyses of traraicntr cmp3.oy adequately conservative values ox the ontlollin~+ reactor ))ala)i)e erst The abnormal. operational transients were analyzed to a power level of 3440 APT i

Ti;< ~:-'i>>)v! 9r i". -,-.c')uros no;r l)sed real!lt iz a rebore loc'ical answer tni)n I ~

ti(in ~': til w";,.') I )',i I t:d v.~lu><)

The bares for individual sct points are discussed below:

Neutroni influx Scram

1. APRN liigh Flux Scram Trip Setting (Run Node)

The average power r;.nge monitoring (i~ J'i) :-ystcm, which is calibrated usinp heat bal"nc>> da a ta!ce)< during steady-state condign'.Ons, reads in '0cx el' o~ ""c'd ">'"'e" (3,293 Ail"} "'Qca"Gc 'icosi')J ci ".mci=i.'s pio- ~

vide the 'oasic input ui~);ala, the PZiU4 system responds direct).." o aver'a;:;r,'. ne:ltro."i s-.Lux. 1;l)rin~; transients L');c instanLa)) -oi:a r.".;~. Oi.

a't LLvl),'f)r fre, 'l'.hc fuc3 ),r4ac f r }icxTIJLL ))0 Jcr) is 3 Osl'i: .x: thci 5 uatcntP~neoun'Ieut~on f ux duc to tiic tiT,.:.'onst n't ox Thlix Qfo):ei dur:.)'ip, t)".ill)niente il)c'need by dist))~'b.".))ccs, t))G ti)crixisl power ox thc uel )Jill be 3esa ih"n ti.at indicate'.d by t!)-. neutron flL'.".

nt the acre:s s) tting. k~alyaes reported in Sect:;on F14 of the V.'.nal.

Safety Pnal>sio Rcpo'tonstratcd that rlth a, 12(3 percc)le:.,cr-'~ t".ip octtirrnone of, thc abnormal operational t an))ienL8 analy cd v'l')leyte the fuel safety limit nnd ther i)) a substantial margin fr~ xuc-'

T I 'i' ~

rir'i Qoa o f a f i oii 'sLic ac i ap,'.; (*/ Os

- ~ 'i ',.I),, ic ' Ao iiA

+r) i'< Figure 2 1 i 2 silows the f30w blasedi scrl)m ss a fun'"tlon of

~

~

core flow.

i' increase in th f'ZR>f. sera netting would d"crea"-e th margin pre-ill sent before the fuel clcdding integrity saxetv Lirzkt. is rcaci)ed, s"'.l".) settin~. was determined by an ann'lysis of lllarg Iis I qu red to provide n rcasonablc rsn~e for maneuverirg during operation Reducinj; t 1is o,)ercf ing m c$ 1I'I <<ou d i, crl a"li" tile: "'iuency 0 sou iouc octans, '-'i)ich have an adverse c"fcct on r ctox safe'y b canoe of 'the

,in@ t'):c.a3. Dtrcssc>>, Thus, t'e ApW~i setting was oc3.ccte4 r"..":l'.."

Qoci!u:;; c .". t . ovid c)) adequate i )ari;.'.ii xor tha fuel clncdin~i" intr),:". ity c' v'L(. ycK iI11 cva Gnc&itiQI( Lv'rgb.n vtl:+t reducers t~iic 'Qcau9.v.~.Lit J o unilcc~f, 0!i) 3 Q'ca.<Tan 5~

2.2 BASBS The scram trip setting must be adjusted to ensure that the LHGR transient peak is not increased for any combination of MTPF and reactor core thermal power. The scram setting is adjusted in accordance with the formula in Specification 2.1.A.1, when the maximum total peaking factor is greater than 2. 481 Analyses of the limting transients show that no scram adjustment is required to assure MCPR > 1.05 when the transient is initiated from MCPR > 1, 2.

i'or op'." ation 'iil the JtF rtup mo e while tile r(;sctol is at low 51'essvre s tho A'foal scram uet xng of 15 p rcent o'ated powe provides aQ'e>>uP';c thecal margin between the setpoint and the safety limit, 25 percent of rated. The marg'n is adeQuate to accoainodate anticipated maneuvers associated with power plant startup. Effects of increasing pressure at zero or low void content are minor, cold wa er from sources avail-ab3.e during startup is not much colder than that'already in the system, temperature coefficients are small, and contxol rod patterns are con-strained to be uniform by operating procedures backeQ up by the rod

<orth minimizer anQ the Rod Sequence Contro3. System. Worth of indivi-dua3, rods is very low in a uniform red pattern. Thus, all of poos'ble sources of reactivity i;lput, uniform control rod withdrawal is the most prob,".ble cause of significant power rise. Because the flux distributioa associated with uniform rod withdrawals does not involve high loc-3. pea'.;",

and becaus several rods must be movea to change power by a significant percentage of rated power, the rate of power rise is very slow. C nerally, the heat flux is in rear equilibrium with the fission rate. 'Kn an assailed uniform rod withdrawal approach to thc scram level, the rate of power rise is no more tilan 5 percent of rated power per m'nute, and the APRM syotem would be morc than adequate to ascure a scram before the power could e::ce "d the ;'xf<<ty 3 imit. The 15 scrccnt APPA sc".s..l remains active unti3. t. e t." Qe rlwitc.l ii, placed in th 'USB,position. This uwitch occur" when reactor pressure is greater than 850 psig.

3~ IRM Flux Scram Tri Sett~in The IRM System consists of 8 chambers, 4 in each of the reactor protec-tion system logic channels. The IRM is a 5-decade instrument which covers the range of power level between that covered by the SRM and the APRM. The 5 decades are covered by the IRM by means of a range switch and the 5 decades are broken down into 10 ranges, each being one-half of a decade in size. The IRM scram setting of 120 divisions is active in each range of the II%. For.

21

2.1 BASFS

3. IRM Flux Scram Tri Settin (Continued) example, if the instrument were on range 1, the scram setting would be at 120 divisions for that range; likewise, if the instrument was on range 5, the scram setting would be 120 divisions on that range. Thus, as the IRM 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. The'PRM 15 percent scram will prevent higher power operation without being in the run mode.

The IRM scram pro-vides protection for changes which occur both locally and over the entire core.

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 recir-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 valried with recirculation loop flow rate, prevents an increase in the reactor power level to excess values due to control rod with-drawal. The flow variable trip setting provides substantial margin 22

fror>> fuel damage, assuming a steady-state operation 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 xated thexnal power because of the APED 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 2.481, thus preserving the APPA rod block safety margin.

The set point for thc low level scram i. above the bottom of the sepnrator skirt.

Tliis level hrs been <<sed Jn t 'ansient analyses de" ing i:1th c'..ant i~ vf ntory decrease. The r ults reported in PS/f'. subsection N14.5 show th i ."cram -"." isolat.ion) 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 avo"d spurious scxams ~

The turbine stop valve closure scram trip anticipates the pressure, neutzon flux and heat flux increase that could result from rapid'closure of the turb're stop va3ves. ~tith a scram tr:p setting of < 10 percent of valve closure fron, fugal open, the resultant increase ln 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 ro.lie".. valves limits pressure to well below the safety valve setting.

E Turbine Control Valve S ran:

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 means that resulting transients, while similar, are less severe than for.

stop-valve closure. No fuel damage occurs, and reactor syst: em pressure does not exceed the relief valve set point, which is approximately 280 psi below the safety limit.

23

2.1 BASES 2, Scram on loss of control oil pxessure The turbine hydraulic control system operates using high pressure oil. There are several points in this oil system where a loss of oil pressure could result in a fast closure of the turbine control valves. This fast closure of the turbine control valves is not protected by the generator load x'ejection 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 should 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 x'eactor 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 ag~inst overpressuxe, 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 from the closure of the turbine stop valves, low con-denser vacuum initiates a scram. The low vacuum scram set point is selected to- is~'te a scram befc 'e the closure of the tux'bine stop valves is in'.

& 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 850 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 occurs when the. main steam line isolation valves are closed, to provide for reactor shutdown so that high power opera-tion at low reactor pressure does not occur, thus providing protection for the fuel cladding integx'ity safety limit. Operation of the reac-tor at pressures lower than 850 psig requires that the reactor mode switch be in the STARTUP position, where protection 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 protection over the entire xange of applicability of the fuel cladding integrity safety limit. In addition, the isolation valve, closure scram anticipates the pressuxe and flux transients that occur

'during normal or inadvertent isolation valve closure. With the scrams set at 10 percent of valve closure, neutxon flux does not increase.

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 th'e intended func-tion is. based on the specified low level scram set point and initia-tion set points. Transient analyses reported in Section N14 of the FSAR demonstrate that these conditions result in adequate safety margins. for both the fuel and the system pressure.

L. References

1. Linford, R. B., "Analytical Methods of Plant Transient Evaluations for the General Electric Boiling Water Reactor," NED0-10802, Feb., 1973.

25

120 APRM FLOW 110 BIAS SCRAM 90 BLOCK 80 NOMINALEXPECTED E FLOW CONTROL LINE 0

~o 70 0

o- 60 zO tt:

I D

50 z

O 20% PUMP SPEED LINE O

40 NATURAL CIRCULATION 30 20 10 0 10 20 30 40 50 60 70 80 90 100 110 120

'ORE COOLANT I LOW RATE (! of rated)

APRM FLOW BIAS SCI4Qf vs REACTOR CORE FLOW FIG ~ 2 1.2,

~

26

SAFETY LIMIT LXMITXNG SAFETY SYSTEM . ETTING 1.2 REACTOR COOLANT SYSTEM INTEGRITY 2.2 REACTOR COOLANT SYSTEM INTEGRITY A ia.cabilit A licabilit Applies to limits on reactor coolant Applies to trip setting's of the system pressure instruments and devices which are provided to prevent the reactor

~

system safety limits from being exceeded.

~Ob ective ~Ob ective To establish a limit below which To define the level of the process the integrity of the reactor coolant variables at which automatic pro-system is not threatened due to an tective action is initiated to overpressuje condition.' prevent the pressure safety limit from being exceeded.

ecification S ecification A. The pressure at the'owest 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 vessel. Protective Action S 'otem Settin A. Nuclear system 1,250 psig safety valves + 13 psi (2 open nuclear valves) system, pressure S. Nuclear system 1,080 poig +

relief valves 11 poi (4 open nuclear valves) system pressure 1,090 poig +

ll psi (4 valves) 1,100 psig +

ll psi (3 valves)

C. Scram nuclear < 1,055 psig system high pressure

l. 2 B*SKS REACTOR COOLANT SYSTEM INTEGRITY

"'he safety limits for the reactor coolant system pressure have been selected s ich that they are below pressures at which it can be shown that the integrity of the system is not endangered. However, the pressure safety limits are set high enough such that no foreseeable circumstances can cause the system pressure to rise over these limits. The pressure safety limits are arbitrarily selected to be the lowest transient overpressures.allowed by the applicable codes, ASME Boiler and Pressure Vessel Code, Section III, and USAS Piping

'>de. Section B31.1.

'lee design pressure (1,250 psig) of the reactor vessel is established such that, when the 10 percent allowance (125 psi) allowed by the ASME Boiler and Pressure Vessel Code Section III for pressure transients is added to th<<

design pressure, s transient pressure 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 t'hat, when the 20 percent allowance (230 and 265 psi) allowed by USAS Piping Code, Section B31. 1 for pressure. transients are added to the design pressures, transient pressure limits of 3.,378 and 1,591 psig are established. Thus, the pressure safety limit: applicable to power operation is established at 1,375 psig (the lowest transient.overpressure allowed by the pertinent codes),

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

The Plant Safety Analysis (paragraph N14.5.1)states that the turbine trip from high power without bypass is the most severe abnormal operational tran-sient resulting directly. in a reactor coolant system pressure increase. The reactor vessel pressure code limit of 1,375 psig given in subsection 4.2 of the safety analysis report is well above the peak pressure produced by transient described above. Thus, the pressure safety limit appli-.

the'vecpressurc cable to power operation is well above the peak pressure that can result due to reasonably expected overpressure transients.

Nigher design pressures have been established for piping within the reactor coolant system than for the reactor vessel. These increased design pressures create a consistent design which assures that, if the pressure within the 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 heads.

The safety limit of 1,375 psig actually applies to any point in the reactor vessel; however, because of the static water head, the highest pressure point will occur at the bottom of the vessel. Because the pressure is not monitored at this point, it cannot be directly determined if this safety limit has been violated. Also, because of the potentially varying head -level and flow pres-drops, an equivalent pressure cannot be 'a priori determined for a 'ure 28

l. 2 BASES pressure monitor higher in the vessel. Therefore, following any transient that is severe. enough to cause concern that this afety limit was violated, a calculation vill be performed using all available information to deter-mine if the safety limit was violated..

REFERENCES

1. Plant Safety Analysis (BPNP PSAR Section N14.0)

2. ASME Boiler and Pressure Vessel Code Section I?I

3. USAS Piping Code, Section B31.1

4. Reactor Vessel. and Appurtenances Mechanical Design (BPNP PSAR Sub s e c t ion '4. 2) 29

2~2 BASES RFACTOR COOLANT 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 established to meet the overpressure pro-tection criteria of the ASMH 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 regections.

Thirteen safety/relief valves have been installed on .each unit with a total capacity of 74% of design steam flow. The total safety/relief capacity o8 74% has been divided into 61% relief (11 valves) and 13%

safety (2 valves).

LIMITINO CONDITIONS VOk OPERATION SURVEILLANCE REQUIREMENTS 4.1 REACTOR PROTECTION SYSTEM

~Alicabili~c

'Applies to the instrumentation Applies to the surveillance of

,and associated'evices which the instrumentation and.'asso-initiate-a reactor scram. ciated devices which initiate r'eactor scram.

'Ob ace ice ~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 The set'points, minimum number of A. Instrumentation systems shall trip systems, and minimum number be functionally tested and of instrument channels that must calibrated as indicated in be operable for each position of Tables 4.1.A and 4.1.B respec-the reactor mode a~itch shall be tively.

as given in Table 3.1.A. The system response times from the B. Daily during reactor power op<<ning of the sensor contact up oPeration, the maximum total to and including the opening of Peaking factor shall be checked the trip actuator contacts'ha'll ~ and the scram and APRM Rod not exceed 100 milli-seco'nds. Block settings given by equations specifications 2 1 A 1

'n and 2.1.B shall be calculated.

C. When it is determined that a channel is failed in the unsafe condition, the other RPS cnannels that monitor the same variable shall be func tio nally 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.

PAGE DELETED 32

TABLE 3.1.A INSTRUMENTATION REQUIREMENT REACTOR PROTECTION SYSTEM. (SCRAM)

Min ~ ,No.

of Operable Inst. Modes in Which Function Channels Must Be 0 erable Per Trip Startup/Hot System (1)'ri Function Tri Level Settin Shut-.

~Aatian f 1 Mode S~itch in Shutdown l.h 1 . Manual Scram l.h I

IRM (16) < 120/1251Indicated 3 - High Flux (5) l.h 3 Inoperative (5) lych

'PRM (16) 2 High Flux See Spec..2.1.A.l 1.A or 1.$

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

+ 3 (13)

Indicated on Scale X

X X(17) X '.h or 1.B Downscale (ll) X(12) -l.h or 1.B High Reactor Pressure < 1055 psig X(10) X 1.A High Drywell < 2 psig x(s) 1.A

'ressure (14) x(s)

Reactor Low Water a 538" above vessel cero l.h Level (14)

'2 High Water Level in Scram < 50 Gallons x(2) l.h Discharge Tank

Min. No.

of TABLE 3.1.A (Continued)

Operable Inst.

Channels Modes in Which Function Per Trip Must Be erable System (1) ri Function Tri Level Set tin Refuel(7} Startup Hot Run Action(1)

Hain Steam Line Isola ion

-Valve Closure < 10X Valve Closure X(3) (6) X(3)(6) X (6) 1.A or 1.C 2 Turbine Cont. Valve Fast Upon trip of the fast Closure acting solenoid valves X(4) X(4) X(4) 1.A or 1.D 4 Turbine Stop Valve Closure < lOX Valve Closure X(4) X(4) X(4) 1.A or 1.D.

2 Turbine Control Valve - Loss of Control Oil Pr'essure > 1,100 psig X(4) X(4) X(4) l.h or 1.D 2 Turbine First Stage Pressure. < 220 psig X(18) X(18) X(18) (19)

Permissive 2 Reactor Pressure Permissive <1055 psig< X X (20).

2 Turbine. Condenser Low > 23 In. Hg, Vacuum X(3) X(3) X l.h or l.C Vacuum Main Steam Line High

< 3X Normal Full Power X(9) X(9) X(9) '.h or 1.C 2 Background Radiation (14)

NOTES I'OR 7'AF.l.E '3. l.A There shal1 be two operable nr tripped trip systems for each function.

, If the minimum number of operable 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 operable rnds within four hours.

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

C.'educe u;~bi.ne load and close main steam line isola'tion valves within 8 hours.

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

2. dlsch'arge refuel

'oScrambypass scram volume high bypass may be used in shutdown or discharge volume scram with control rod block for reactor protection system reset.

3. Bypassed if reactor pressure < 1055 psig and mode switch not in run.

4. Bypassed when turbine first stage pressure is less then 220 psig.

5. IRM's =are bypassed when APRM's are onscale and the reactor mode switch is ih the run position.

6, The design permits closure of any two lines without a scram being initiated.

7. When the r'eactor is subcritical and. the 'reactor wa'ter-temperature is less th'an 212'Y, onlv the following trip functions need'to be operable:

A.. Hode swi'tch in shutdown B. Manual scram C. Nigh flux IRM D.'cram discharge volume high level

\

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

9. Not required if all main steamlines are isolated.

35 '..

10. Not required'o be operable when 'the reactor press u r e vesseL head is not bolted to the vessel.

ll. The APRH dovnscale trip function is only active vhen the reactor mode evitch ie in run.

12, The APRM dovnscale trip is automatically bypassed vhen the XRM inetrume'ntation is operable and not high.

13. Less than 14 operable LPRM's vill cause a trip system trip, 14.. Channel shared.by Reactor Protection System and Primary Containment and

'eactor Vessel IsnIation Control System. 'A channel failure may be a .

channel failure in each system.

15. The APRH 15K scram is bypassed in the Run Mode.'6.

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

17. Not required while performing lov power physics tests at'tmospheric pressure duri'ng or after refueling at pover levels n o t to exceed 5 MW(t) l.

~

18. Operability is required when normal first-stage pressure is below 30X (a220 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 inten ed.

function. Otherwise, no action ie required.

20.'ction L.A or 1.C 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 required.

36

TABLE 4.1.A atoned PROTECTION SVSTEM (SCRAM) INSTRUMENTATION PUNCTIONAL TESTS MINIMUM PUNCTIONAL TEST PREQQENCIES POR SAFETY INSTR. AND CONTROL CIRCUITS QzRxp /~2 Punctional Test Minimum Prequency (3)

Mode Svftch in Shutdown Place Mode Svitch in Shutdown Each Refueling Outage Manual Scram Trip Channel and Alarm Every 3 Months IRM

. High Flux Trip Channel and Alarm (4) Once Per Seek During Refuelin and Before Each Startup Trip Channel and Alarm (4) Once Per. Seek During Refuelin and Before Each Startup APRM High Flux (15X scram) Trip Output Relays (4) Before Each Startup and Weekl

%hen Required to be Operable High Plux Trip Output Relays (4) Once/Reek Inoperative B -Trip Output Relays (4) Once/Reek Domumale Trip Output Relays (4) Once/Meek Plow Bias B (6) (6)

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

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

Reactor Lmr Mater Level (5j Trip Channel and Alirm Once/Month (1)

High Rater Level in Scram Discharge Tank Trip Channel and Alarm Every 3 Months Turbine Condenser Lmr Vacuum Trip Channel and Alarm Once/Month (1)

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

TABLE 4.1.A (Continued)

~Grou (2) Minimum Pre uenc 3>

Main Steam Line Isolation Valve Closure "A Trip Channel and Alarm Once/Month (1)

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 Trip Channel and Alarm Every 3 Months Turbine Stop Valve Closure Trip Channel.and Alarm Once/Month (1)

Reactor Pressure Permissive A Trip Channel and Alarm Every 3 Months

NOTES FOR TAGI.E 4. l.h

l. Xnitially the minimum fr'equency nc or tthee indicated for n tests shall be once per month. As instrumen failure rate data is comp e li

'ument include data obtained from other boiling vater t r reactors r for vhich instruments of the same desig n o p crate in an env iron ment similar to "that of,BFNP, the e'xposure (M as defined on F gure cate that lees frequent testing is appropriate, at w c may request a less frequent testing'interval,

2. A description of the three groups iss included nc u in the Bases of this sp ecification.

3 ~ Functional tests are not require re uired v vhen the systems are not re q uired to op or ar op r ting n ((i.e., already trippe d) 'Xf tests are missed they shall be performed prior to return ng e o'perable status.

is exemp e ted from the instrument channel test definition. 'I his, , instrument ns channel func tional tes t v infecting a simulated electrical si t e me nal into the signal measurement channels.

5. -

The water level in the reactor ctor vesse vessel will w bee perturbed p and the cortes-ca-po g o g es will be monitore . s test vill be performed every month after complet on o

'functional test program.

6.

6 The functional'est funct ona of the flow bias network s p's 'erformed in'accordance with Table 4.2.C. 1 39

TABLE 4.1.B REACTOR PROTECTION SYSTEM (SCUD) INSTRViKNT CALIBRATION MI!fIMUM CALIBRATION FREQUENCIES FOR REACTOR PROTECTION INSTRL'HDiT CHANNELS Instrument Channel ~Groun 1) Calibration Minimun Fre uenc (2)

IR.'f High Flux Compar'ison to APR~ on Control- Note (4) led Shutdowns (b)

APRw. High Flux .

Outout Signal B Heat Balance Once every 7 days Plow Bias Signal B Calibrate Flow Bias Signal (1) Once/operating cycle LPR'f Signal TIP System Traverse Every 1000 Effective Pu}l Power Hours High Reactor Pressure Standard Pressure'ource Every 3 Months High Drywell Pressure Standard Pressure Source Every 3 Months O

Reactor Low Mater Level Pressure Standard Every 3 Months High Mater Level in Scram Discharge Volume . A Note (5) Note (5)

Turbine Condenser Low Vacuum Standard Vacuum Source Every 3 Months Main Steam Line Isolation Valve Closure Note (5) Note (5)

'fain Steam Line High, Radiation B Standard, Current Source (3) Every 3 Months Turbine First Stage Pressure Permissive Standard Pressure Source Every 6 Months Turbine Control Valve Loss of Oil Pressure A Standard Pressure Source Every 3 Months Turbine Stop Valve Closure Note'5) Note (5)

Reactor Pressure Permissive Standard Pressure Source Every 6 Months

NOTES FOR TABLE 4.1.B

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

2. Calibrations are not 'required 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 IRM's and APRM's will be verified.

7. The Flow Bias Signal Calibration 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 comparator 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.

3. 1 BASES The reactor protection system automatically initiates a 'reactor scram to:

1.'reserve the i'ntegrity of the fuel cladding.

2. Preserve the'ntegrity of the reactor coolant t

system.

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

This specification provides the limiting conditions for operation necessary ro preserve the ability of 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

'ats and calibrations.

The reactor protection system is made up of two independent trip systems (refer to Section 7.2, FSAR), There are us&ally four channels providhd to monitor each critical parameter, vith two channels in each trip system.

The outputs of the'hannels in a trip system are combined in a logic such that either channel trip will trip that trip system. The simultaneous tripping of both trip systems will produce a reactor scram.

This system meets the intent of IEEE - 279 for Nuclear Power Plant Protec-tion Systems,. The system has a reliabil'ity greater than that of a.2 out of 3 system and somewhat less than that of a 1 out of 2 system.

With the exception of the Average Power Range Monitor (APRM) channels, the Intermediate Range Monitor -(IRM) channels, the Hain Steam Isolation Valve closure and the Turbine Stop Valve closure, each trip system logic has one instrument channel.'hen the minimum condition for operation on the number of oper'uble instrument channels per untripped protection trip system is met or if it cannot be met and the effected protection trip system is placed in a tripped condition, the effectiveness of the protection system is preserved; i.e., thc system can tolerate a single failure and still perform its intended function of scramming the reactor.'hree 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 for maintenance, testing or calibration. Addi>>

tional IRM channels have also been provided to allow for bypassing of one such channel. The bases for the scram setting for the IRM, APRM, high reac-tor pressure, reactor low water level, MSIV 'closure, turbine control valve fast closure, turbine. stop valve closure'and loss of'ondenser vacuum are discussed in Specification 2.1 and 2.2.

BASES Instrumentation (pressure switches) for the drywell are provided to detect a loss of coolant accident and initiate the core standby cooling equipment.

A high drywell pressur'e 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 whenev'er 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 excessive turbine con-tamination. Discharge of'xcessive amounts of radioactivity to the site environs is prevented by the air effector off-gas monitors which cause an isolation of the main condenser off-gas line.

h 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 PSAR.

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

The IRH system (120/125 scram) .in con]unction with'the APRM system (15K scram).provides piotection against excessive power levels and short reactor periods in the startup 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 t~ken 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 accommo-dated which would result in slow scram times or partial control rod inser-tion. 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 piping to accommodate the icram without impairment of the scram times or amount of insertion of the control rods. This function shuts the reac'tor 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 i:ts function adequately..

A source range monitor (SRN) system is also provided to supply additional .

neutron level;information dur'ing startup .but has no scram functions Reft Section 7.5.4 FSAR. Thus, the IRH is'equired in the Refuel and Startup 43

3.i 8Asas modes. In the power range the APRM system provides required protection.

Ret, Section 7.5.7 PSAR. Thus, the IRM System is not required in the Run mode. The APRM's and the IRM's provide adequate coverage. ia the startup and intermediate range.

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

The requirement to have the scram functions as indicaCed in Table 3.1.1 operable in 'the Refuel, mode is to assure that shifting to the Refuel mode during reactor power operation doei not diminish Che need for Che reactot protection system.

The turbine condenser low vacuum scram is only xequired during pover operation and must be bypassed to start up the unit. Below 205 psig tur" bine first stage pressure (30X of rated), the scram signal due to turbine stop valve closure, turbine'ontrol valve fast closure, and tutbiae con-tx'ol valve loss of control oil pressure, is bypassed becauso flux aad px'assure scram 'ax'e adequate to protect the reactor.

Because of the APRM downscale limit of ~ 3X vhen ia the Run mode.and high level limit of < 15X vhen in the Startup Mode, the txansition botveea the Startup and Run Modes must be made vith the APRM insttumentatioa indicatiag between 3X and 15X of rated pover or a control rod scram. vill occur. In addition, the IRM system must be indicating belov the High Plux setting (120/125 of scale) or a scram vill occur vhen in che Stattup Mode+ Pot normal operating conditions, these limits provide assurance of overlap betveen the IRM 'system and APRM system so that thex'e are ao "gapa" in the pover level indications (i.e.," the pover level is continuously, monitored from beginning of startup to full pover aad from full pover to shutdown).

When pover is being reduced, if a transfer Co the Stcrtup mode io made aad the IRM's. have not been fully inserted (a maloperatioaal but aot impossible condition) a control rod block immediately occux's so chat reactivity inset" tion by control rod vithdraval cannot occur.

'44

The minimun 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 two taken twice logic of the reactor protection system. The analysis shows that the sensors are primarily responsible for, the reliability of the reactor pro-tection system. This analysis makes use of "unsafe failure" rate experi-ence at conventional and nuclear power plants in a reliability model for the system. An "unsafe failure" is define as one which negates channel operability and which, due to its nature, is revealed only when the channel is functionally tested or attempts to respond to a real signal. Pailures such as blown fuses, ruptured bourdon tubes, faulted amplifiers, faulted cables,. etc., which result in "upscale" or "downscale" readings on the reactor instrumentation are "s'afe" and will be easily recognised 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 for functional testing. These are!

On-Off sensors that provide a scram trip function, B. Analog devices coupled with bi-stable trips that provide a scram function.

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

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

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

To satisiy the long-term objective'of maintaining an adequate level of safety throughout the plant lifetime, a minimum goal of 0.9999 at the 95X 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 9SX confi-dence level. This level. of availability may be maintained by ad)usting the test interval, as a function- of the observe'd failure history. (1) .

1. Reliability of Engineered Safety Features as a Function of Testing Prequency, I.. H. Jacobs, "Nuclear Safety," Vol. 9, No. 4, July>>August>

1968, pp. 310-312.

45

To facilitate the.implement'ation of thistechnique, Figure 4.1.1 is pro-vided to indicate an'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. Th'e 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 test interval to satisfy'he goal will be the test intervil to the left of the plotted points.

5. A test interval of one month vill 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 ac'tive 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 "as<<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 throe.= For'urpose o'f analysis, it is 'assumed that this rare failure will'be detected within two hours.

The bi-stable trip circuit which is a par't of the Group (8) devices can sustain unsafe f'ailures which are revealed only. on test.

necessary to test them periodically.

Therefore, it is A study was conducted of the instrumentation channels included in the Group (B) devices to calculate their "unsafe" failure rates. The (sensors and ampli]ieis) are predicted to have an unsafe failure analog'evices rate of less than 20 x 10 failure/hour. The bi-stable trip circuits are

'predicted to have unsafe failure rate of lese '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.-

BASES The frequency of calibration of the APRM Plow Biasing Network has been established as each refueling outage. There are several instruments which must be calibrated and it will take several hours'o perform the calibration of the entire network. Phile the calibration is being per-formed, a'ero flow signal will 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 Flow Biasing Network; is not significant and therefore, to avoid spuriou's scrams, a calibration frequency of each refueling out-age is established.

Group (C) devices are active only during a given'ortion 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 just prior to shutdown or startup; i.e., the tests that are performed just prior to use of the'nstrument.

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 Pevices and detectors that drift or lose sensitivity.

Experience with passiv type instruments in generating stations and sub-

,stations indicates that the specified calibrations are adequate. For those devices which employ amplifiers, etc., drift specifications 'cell for drift to be less than 0.4X/month; i.e., in the period of a month a drift of .4X would occur and'thus providing for adequate margin.considera- For the APRM system drift of electronic apparatus is not the only tion in determining 'a calibration fxequency. Change in power distribu-

'tion and loss of- chamber sensitivity dictate a calibration every seven days.'alibration on this frequency assures plant operation at or below thermal limits.

A comparison of Tables 4.1.A and 4.1.B indicates 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-off 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 sdram requires adj ustment. This will normally be done by checking

. the LPRM Yeadings. Only a small number of control rods are moved daily 47

i

/y. j BASES during steady-state operation and thus the peaking factors are not expected

-""" "t'o'"change The signif icantly, sensitivity of LPBM 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

'y calibrating individual LPRM's every 1000 effective full-power hours

~

using TIP traverse data.

48

18'6 M~ nT n ~ NUMBER OF IOENTICAL COMPONENTS T ~ INST RUMEN T OP ERA TING HOURS 12 ill 1 MONTH 10 ED 2 MONTHS 8

3 MONTHS 6 MONTHS I

10' 5 6 7 8 910 3 5 6 7 8 9 I M FACTOR SROWHS FERRY HUCLEAR PLAHT FINAL SAFETY AHALYSIS REPORT Graphical Aid in the Selection ot an Adequate Tests Intcrva.'Ietveen Figure 4.1-1 4g

0 SURVEILLANCE RE UIREMENTS PROTECTIVE INSTRUMENTATION 4. 2 .PROTECTIVE INSTRUMENTATION A licabilit Applies to the plant instrumen- Applies to the surveillance re-tation Mhich initetes-and con- quirement of the instrumentation trols a protective fun'ction. th'at,initiates and controls pro-

~ot ective To assure the operability of protective instrumentation.

'Ob tective function.

To ect1ve specify the type and frequency of surveillance to be applied to pr'otective instrumentation.

h, Primer Containment end Reactor A. Primer Containment end Reactor Buildin Isolation Functions When primary containment inte- Instrumentation shall be func-grity is required, the limiting tionally tested and calibrated conditions of operation for the as indicated. in Table 4.2.A, instrumentation that initiates 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, mein steam lines,, and initiates the standby gas treatment system, B., Core end tontetnme'nt ~Caolin B. Core and Containment Coolin S stems - Initiation & Control The limiting conditions for Instrumentation shall be func-operation for the instrumenta- tionally tested, calibrated and tion that initiates o'r contr'ols checked as indicated in Table the core and containment cooling 4.2,B.

systems are given in Table 3.2.8.

This instrumentation must be System logic shall be function-operable when the system(s) it ally tested as indicated in initiates or 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 e

, required test or calibration, the other'ystems or loops'hat 50

LIMITING CONDITIONS POR OPERATION SURVEILLANCE RE UIREMENTS 3.2.B Core and Containment Coolin 4.2.8 Core and Containment Coolin S stems - Initiation 6 Control S stems - Initiation 6 Control are required to be operable shall be considered operable if they are within the required surveil-testing fr'equency and there 'ance is no reason to suspect that they are inoperable.

C. Control Rod Block Actuation C. Control Rod Block Actuation

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 tested as indicated in Table 4.2.C.

2. The minimum number og operable instrument channels specified in Table 3.2.C for the Rod Block Monitor may be reduced by one in one of the trip systems for maintenance and/or testing, pro-vided that this condition does not last longer than 24. hours in any thirty day period.

Off-Gas Post Treatment Isolation Off-Gas Post Treatment Isolation Function Functions

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

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

during reactor operation.

The isolation function System logic shall be function-trip settings for the ally tested as indi.cated in monitors shall be set at Table 4.2.D.

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

51

Il LIMITING CONDITIONS POR OPERATION URVEILLhÃCE RE UIREMENTS 3.2.D Off-Gas Post Treatment Isolation .2oD Off-Gas Post Treatment Isolation Functions Function (b) Prom and after the date that one of the two off-gas post treatment radiation monitors is made or found to be inoperable, continued reactor power operation is permissible during the next

~ even days, provided that the inoperable monitor is tripped in the downscale position. One radiation monitor msy be out of service for four hours for functional teat end/

or calibration without the monitor being in a downscale tripped condition.

t;c) Upon the loss of both off-gas post treatment radia-tion monitors, initiate an 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 />. E. D 1 Leak Detection E. Dr ell'Leak'Detection The limiting conditions of opera- Instrumentation shall be calibrated tion for the instrumentation that and checked ae indicated in Table monitors drywall leak detection 4o2oE, are given in Table 3.2. E, P. Surveillance Instrumentation P.'urya llanos I strumentation The limiting conditions. for the Instrumentation shall be calibrated instrumentation that provides and checked ae indicated in Table

~ urveillance information readouts 4.2eTo are given in Table 3.2,1,

0. Control Room Isolation 0, Contr 1 Room I ol n The limiting conditions for Instrumentation shall be calibrated instrumentation that isolatee and checked as indicated in Table the control room and initiatea 4.2.0e the control room emergency pressurisation systems are given in Table 3.2,0.

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.2.H Flood Protection 4.2.H Flood Protection The 1lnit shal1 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.

53

TABLE 3.2.A PRIMARY CONTAINMENT AND REACTOR BUILDING ISOLATION INSTRUMENTATION Miaimust No.

Operable Per Tri a 1 Punction Remarks Instrument Channcl- > 538" above vessel sero A or. l. Below trip settiag does the Reactor Lov Mater Level= (6) (B and B) following:

a. Initiates Reactor Building Isolation

b. Initiates Prioary Containment Isolation c Initiates SCTS Instrument Chaaacl- 100+ 15.p Ig 1. Above trip setting isolates the Reactor High Pressure 'fshutdovn cooling suction valves the RHR systeia.

Instrument Chanael- > 490" above vessel sero. 1, Below trip setting initiates Maia Rcactor Lov Vater Level Steam Line Isolation (LIS-3-56Am, SW fl)

Instrument Channel - c 2 psig" A or

. 1, Above trip setting does the High Dryvell Pressure (6) (B and Z) .

follcnrtng:

(PS-64-5 6 A-D) a. Initiates Reactor Building Isolatioa b., Initiates Primary Containment Isolation

c. Initiates SGTS Instrument Cumnel- < g times normal rated. 1. Above trip setting Initiates Main High Radiation Main Steam full power background Steam Line Isolation Line Tunnel (6)

Instrument Channel- > 850 psig (4) B 1. Belov trip setting Initiates Main Lov Pressure Main Steam . Steam Line Isolation Line Instrument Channel 140X of rated steam flov B l. Above trip setting initiates Isolation

'(3)

Main High Plov Main Steam LIne ~ Steam Line

TABI~. 3.2.A (Ccntirued)

Minima. ?3o.

'Operable Per Aetio.. '(1) Remarks Trio Svs (1) Function Instrumert Ch"rncl.- < 200'= l. Above trip setting initiates Main Stcam Line Tunnel.

Main Steam Line Isolation.

High 'Te'perat re Instru-.,ent Chennei- 160 180'Z 1. Above trip setting initiates Reactor Pater Cieanup Sys Isolation of Reactor Mater Cleanup Lire from R actor and en F1oor Drain High Reactor Vater Return Line.

~

"mnerature Irattument Channol- 160-180'F 1. Same as above Reactor 4ater Cleanup System Space High Tom.er ture

< 100 mx'/hr ox'ownscale 1. 1 upscale or 2 downscale will Instrument Channel a. Iritiate SGTS.

Reactor Building Venti- b. Isolate reactor zone and lation High Rcdiation- refueling floor.

Rca tor Zone c. Close atmosplnore control system.

mrfhr or downscale 1 upscale or 2 dcvnscet. vill Instrument Channel >> < 100

a. Initiate SGTS.

.Reactor Building Uenti- b. Iso1ate l.ation Hi.gh Radiation- refueling floor.

Refueling Zone c. Close atmosphere control system.

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

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

heaters will shut off.

Instrument Channel Charcoal Heaters g 2000 cfm H and Belov 2000 cfm, trip setting charcoal 2 (7)(8) 1.

SGTS Flow Train B R.H. Heaters + 2000 cfm (A or F) heaters will turn on.

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

heaters will shut off.

2 (7)(8) Instrument Channel Charcoal Heaters <, 2000 cfm H and 1. Below 2000 cfm, trip setting charcoal SGTS Plow Train C R.H. Heaters < 20DO cfm (A or P) heaters will turn on.

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

heaters will shut off.

TABLE 3.2.A (Continued)

Minimum No.

Operable Per Tri S s (1) Punction Tri Level Settin Action 1 Remarks Reactor Building Isolation 0 < t < 2 secs. HorP Below trip setting prevents Timer (refueling floor) spurious trips and system pertur>>

bations from initiating isolation Instx'ument Channel- N/A HorP l. Located in unit 1 only Static Pressure Control 20 Permissive for static pressure Permissive (refueling control (SGTS A B- pr C on).

Channel shared Ey permissive on floor) reactor zone static pressure cont.

Static Pressure Control Pressure Regulator (Re-fueling Ploor)

< 1/2" H20 HorP '.

1. Located in unit 1 only Controls static pressure of refueling floor during reactor building isolation with SGTS running Reactor Building Isolation 0 < t < 2 secs. CorA Belo~ trip setting prevents ox H spurious trips and system pertur-Timer (reactor zone) bations fxom initiating isolation Instrument Channel N/A Permissive for static pressure 1(9) control (SOTS A; B, or C on).

Static Pressure Control Channel shared by permissive on Permissive (reactor refueling floor static pressure xone) control.

rol < 1/2" Controls static pressure of 1(9) Static Pressure Con H20 reactor zone during reactor Pr..ssure Regulator (reactor building isolation with SGTS "one) running.

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

TABLE 3.2.A (Continued)

Hinimum No.

Operable Per Tri S s 1 Function Tri Level Set tin Action 1) Remarks Croup 2 (Initiating) Logic N/A A or 1. Refer to Table 3.7.A for list of (B and E) valves.

Group 2 (RHR Isolation-Actuation) N/A Logic Group 2 (Tip-Actuation) Logic N/A

~

Croup 2 (Degvell Sump Drains- N/A hctuation) Logic Croup 2 (Reactor Building & N/A P and C 1., Part of Croup 6 Logic Refueling Floor, and Drywell Vent and Purge-Actuation) Logic Group 3 (Initiating) Logic N/A I. Refer to Table 3.7.A for list of valves.

Group 3 (hctuation) Logic N/A Group 6 Logic N/A P and C '1. Refer to Table 3.7.A for list .of valves.

Group 8 (Initiating) Logic N/A 1. Refer to Table 3.7.A for list of valves.

2. Same as Croup 2 initiating logic Reactor Building Isolation N/A H or P 1. Logic has permissive to refueling (refueling floor) Logic floor static pressure regulator.

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

9 9 TABLE 3.2.A (Continued)

Hinimum No.

Operable'Per Tri S s 1) Function Tri Level Set tin Action (1) Remarks 1(7)(8) SGTS Train A Logic N/A ox (A and F) 1 (7)(8) SGTS Train B Logic N/A ox (A and F) 1( ) ( ) Train Logiq (A anK F) 1 SGTS C Static Pressure Contxol H ox F l. Located in unit 1 only (refueling floor) Logic 1(9) Static Pressure Control N/A (reactor zone) Logic Refer to Table 3.2.B xor RCIC and KPCI functions including Groups 4, 5, .and 7 valves.

NOTES FOR TABLE 3.2.A

1. Whenever the respective functions are required to be operable, there shall be'wo operable or tripped trip'ystems for each function.

If the first column cannot be met for one of the trip systems, that trip system or logic for that function shall be tripped (or the

'ppropriate action listed below shall be taken). If the column cannot be met for all trip systems, the appropriate 'action listed below shall be taken.

A. Initiate an orderly shutdown and have the reactor in Cold Shutdown Condition in 24 hours.

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

C. 'Isolate Reactor Water Cleanup System.

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

F. The handling of spent fuel will be prohibited and all operations over spent fuels and open reactor wells shall be 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'ystemsand daily thereafter not to eiceed 7 days.

I. No action required. Reactor zone walls and ceiling designed above suction pressure of the SGTS.

J. Withdraw TIP.

K. Manually isolate the affected lines. Refer to section 4.2.E for the requirements of an inonerable. system. If L. j.t one SFrk train is Noperable take actions H or action A and F. two SGTS trains are inoperable take actions A and F.

2. When it is determined that a channel is failed in the unsafe condition, 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 unt'ripped for short periods of time to allow functional testing of the nther trip system or logic for that function.

3. There are four channels per steam line of which two must be operable.

4. Only required in Run Mode (interlocked with Mode Switch).

5. Not required in Run Mode (bypassed by mode switch).

6. ,Channel shared by RPS and Primary Containment 6 Reactor Vessel Isolation Control System. A channel failure may be a channel failure in each system.

7. A 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.

TABLE 3.2.B INSTRUNENThTION THAT INITIATES OR CONTROLS THE CORE AND CONThINMENT COOLING SYSTEMS Minimum No.

Operable Per Function Tri Level Set tin hetman Remarks Instrument Channel- > 490" above vessel zero. l. Belov trip setting initiated HPCI.

Reactor Low Rater Level

. Instrument Channel- > 490" above vessel zero. 1. Belov trip setting, associated vith Reactor Low Mater Level LPCi loop selection. Multiplier relays initiate RCIC.

Instrument Channel - . > 378" above v'easel zero. -1. Belov trip setting initiates CSS.

Reactor Low Mater Level Multiplier relays initiate LPCZ.

- (LIS-3-58AM, SN f1)

.2. Multiplier relay from CSS initiates accident signal (15).

2(16) Instrument Channel - , > 378",above vessel zero. 1. Belch trip settings in con)unction Reactor Low Rater Level with dryvell high pressure, lov (LIS-3-58A-D, SW f2) 4 water level permissive, 120 sec. del

. timer and CSS or RHR pump running, initiates ADS.

1(16) Xnstrumeat Chmnel- > 544" above vessel zero. 1; Belov trip setting permissive for Reactor Low Rater Level initiating signals on ADS.

Permissive (LIS-3-184 &

185 'M fl)

Instrument Qumael- > 312 5/16" above vessel zero. A 1; Below trip setting prevents inadver-Reactor Low Mater Level (2/3 core height) tent operation of containment spray (LITS-3-52 & 62, SW fl) during accident condition.

Iastrumeat Channel- 1< pc 2 psig A l. Below trip .setting prevents inadver" Dryvell High Pressure tent- operation of containment spray (PS-64-58 E-H) during accident conditions.

TABLE 3.2;B (Continued)

'.finimum Mo.

Operable Per Trio S s (1) Function Tri Level Settin Action Instrument Channel- < 2 psig l. Above trip setting in conjunction wi Drywell High Pressure low reactor pressure initiates CSS.

(PS-64-58 A-D, SM f2) '.fulti6lier relays initiate HPCZ.

2. '.jul'tiplier relay from CSS initiates accident signal. (15) .

Instrument Channel > 490" above vesse1. zero 1; Below trip setting trips. recircula-Reactor Low Mater Level ~ tion pumps (LS-3-56A,.B, C, D)

Instrument Channel < 1120 psig A l. Above trip setting trips recircula-Reactor High Pressure tion pumps (PS-o-204 h, B, C, D) 2 Instrument Channel- < 2 psig 1. 'Above trip setting in conjunction vi Drywell High Pressure lov reactor pressure initiates LPCI.

(PS-64-58A-D, SM fl) 2(16) Instrument Channel < 2 psig A . l. Above trip setting in conjunction wi Dryve11. High Pressure lov reactor water .level, dryvell hig (PS-64-57A-D) pressure, 120 sec. delay timer and C or RHR pump .running, initiates ADS.

'nstiument Channel- 500 psig + 15 . 1. Below trip'etting'ermissive for Reactor Low Pressure opening CSS admission valves..

(PS-3-.74 A & B, SW f2)

(PS-68-95, SM f2)

(PS-68-96, SQ f2)

Instrument Channel 500 psig + 15 1. Belov trip setting permissive for Reactor Lov Pressure 'I opening LPCI admission valves (PS-3-74A & B, SM fl)

(PS-68-95, SM fl)

(PS-68-96, SM fl)

TABLE 3.2.B (Continued)

Ainimum No.

Operable Per Tri S s (1) Function Tri Level Settin Action Remarks Instrument Channel 100 psig + 15 1. Belov trip setting in con)unction with Reactor Lov Pressure containment isolation signal and both (PS-68-93 & 94, SW tl) suction valves open will close RHR {LPC admission valves.

Instrument Channel 900 psig + 15 1. Belov trip setting permissive for Reactor Lov Pressure actuation of LPCI break. detection (PS-3-186 A & B) circuit.

Core Spray Auto Sequencing 6< t<8 secs. 1. With diesel power Timers (5) 2. One per motor LPCI Auto Sequencing 0< t <1 sec. 1. With diesel pover Timers (5)

2. One per motor RHRSW Al, B3, Cl, and D3 13 < t < 15 sec. 1. With diesel power Timers

2. One per pump Core Spray and LPCI Auto 0< t <<1 sec. 1. 'With normal pover Sequencing Timers (6) 6< t< 8 sec.

12 < t < 16'ec. 2. One per motor 18 < t < Q4" sec.

RHRSW Al, B3, Cl, and D3 27 < t <29 sec. 1. With normal power Timers

2. One per pump LPCI Break detection Timer 0< t< 1 sec. A 1. Belov trip setting permissive to K28A& B allow logic to determine whether li both recirculation pumps are on.

LPCI Break Detection Timer 1 < t<3 sec. A l. Above trip setting permissive for K34 A & B allowing water perturbations to settl

TABLE 3.2.B (Continued)

Aixxixana No.

Operable Per Tri S s (1) Funct ion Tri Level Settin Action Remarks LPCI Break Detection Timer' 0 <-t c 1 sec. l. Belov trip set'ting allovs logi xo K40 A & B determine which recirculation icop select for. in)ection.

1(16) ADS Timer 120 sec +5 l. Above trip setting in conjunc".'=..:

lov reactor water level, high =typic pressure and LPCI or CSS pu...s xun:

initiates ADS.

Instrument Channel- 100 +10 psig 1. Below trip setting defex's ADS RHR Discharge Pressure -actuation.

Instrument Channel 185 +10 psig 1. Below txip setting defers ADS CSS Pump Discharge Pressure actuation.

2 Instrument Channel c 2 psid Above trip setting determines p~p Recirculation Pump A running.

Running

2. Part of LPCI Break Detection 'ogic Instrument Channel . <2 psid l. Above trip setting determines , p Recirculation Pump B running.

Running

2. Part of LPCI- Break Detection Logic Instrument Channel .5 cp cl.5 psid .

1. Above trip setting determines sump Recirculation Jet Pump  ; running.

Risex d/p

2. Part of LPCI Break Detection Logic 1(3) Core Spray Sparger to Z psid + 0 4 l. Alarm to detect core soray sparger Reactor Pressure Vesse1. d/p pipe break.

RHR (LPCI) Trip System bus. N/A 1. Nonitors availability of power to power monitor logic systems.

.ABLE 3.2.8 (Continued)

Minimum No.

Operable Per Tri S s (1) Function Trio Level Settin Action Remarks Core Spray Trip System bus N/A 1. Monitors availability of power :o power monitor logic systems.

ADS Trip System bus power N/A Monitors availability of power to monitor logic systems and valves.

HPCI Trip System bus power N/A C- 1. Monitors availabilit'y of powe" to monitor logic systems.

RCIC Trip System bus power N/A Monitors availability of power to monitor logic systems.

l(2) Instrument Channel- > Elev. Below trip setting vill open HPCI Storage Tank Low 551'ondensate suction valves to the suppression Level (LS-73-5SA & B) chamber.

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

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

Reactor High Water Level Instrument Channel- < 450" 820 (7) A . l. Above trip setting isolates RCIC systet RCIC Turbine Steam Line and trips RCIC turbine.

High Flow

V TABLE 3.2.B (Continued)'inimum No.

Operable Per (u Function Tri Level Settin Action Remarks 4 (4) Instrument Channel- < 200'F. A 1. Above trip setting .isolates RCEC trips system'nd RCIC Steam Line Space High RCIC turbine.

Temperature 2 (2) Instrument Channel < 583" above vessel zero. A l. Above trip setting\

trips HPCI turbine.

Reactor High Water Level Instrument Channel HPCI Turbine Steam Line High

< 90 psi (7) A,l ~ Above trip setting isolates HPCE system and trips HPCI turbine.

Flo~

o 4(4) Instrument Channel- < 200'F. A 1. Above trip setting isolates HPCE HPCI Steam Line Space High system and trips HPCI 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 l. Includes Group 7 valves. Refer to Logic Table 3.7.A for list of valves.

TABLE 3.2.B (Continued)

Aini%um No.

Operable Per Tri S s 1) Function Tri Level Settin Action Remarks RCIC System (Isolation) '8/A .1. Includes Group 5 valves. Refer to Logic Table 3.7.A for list of valves.

l(16) ADS Logic 8/A RHR (LPCI) System (Initiation) '8/A RHR (LPCI) System (Break H/A Detection) Logic MR (LPCI) System'Containment N/A-Cooling Spray) Logic HPCI System (Initiating) Logic N/A 1. Includes Group 7 valves. Refer to Table 3.Z.A for list of.'valves; HPCI System (Isolation) Logic .'C/A l. 3ncludes Group 4 valves. Refer to Table 3.7.A for list of valves.

'0 TABLE 3.2.B (Continued) nimum No.

Operable Per Tri S s 1) Function Tri Level Settin .Action Remarks 5g 1(3) Core Spray Loop=-A 0 500 psig Indicator (9) l. 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) l. Part of filled discharge pipe Discharge Pressure requirements. Refer to Section 4.5.

(PI-75-48) 1(3) RHR Loop A Discharge 0 450 psig Indicator (9) . D .1:. Part of filled discharge pipe Pressure (PI-74-51) requirements. Refer to Section 4.5.

1(3) RHR Loop B Discharge 0 - 450 psig Indicator (9) 1. Part of filled discharge pipe Pressure (PI-74-65) requirements. Refer to Section 4.5.

1(10) Instrument Channel- H/A 1. 'tarts RHR area cooler fan vhen RHR Start respective RHR motor starts.

1(10) Instrument Channel- <100 F A -; 1. Above trip setting starts RHR area Thermostwt (RHR Area Cooler cooler fans.

Fan) 2(10) Instrument Channel- N/A Starts Core Spray area cooler fan Core Spray A or C Start +hen Core Spray motor starts 2(10) Instrument Channel- N/A 1. Starts Core'-Spray area cooler fan Core Spray B or D when Core.Ypiay motor starts 1(10) Instrument Camel << c 100'F. I. Above trip setting starts Core Spray Thermostat (Core Spray Area area cooler'ans Cooler Fan)

TABLE 3.2.B (Continued)

Minimum No.

Operable Per S s (1) Function Trio Level Settin Action Remarks 1(lo) RHR Area Cooler Pan Logic N/A 1(10) Core Spray Area Cooler Fan Logic ';t/A l(11) Instrument Channel lt/A 1. Starts RHRSW pumps Al, Cl, B3>

Core Spray Motors A B C> << D and D3 Start 1(12} Instrument Channel- N/A l. Starts RHRSW pumps Al,Cly B3> and Core Spray Loop 1 Accident D3 Signal (15) l(12) Instrument Channel- N/A 1, Starts RHRSW pumps Al, Cl, B3, and Core Spray Loop 2 Accident D3 Signal (1S) l(13) RHRSW Initiate Logic N/A (14)

NOTES FOR TABLE 3.2.8

1. Whenever an y CSC S System is required by section ).5 to be operable, there shall be two operable trip systems except as noted. Xf a requirement of the first column, is reduced by;one, the indicated action shall be taken. Xf the same function is inoperable in more than one trip system or the a'ction B shall be taken.

firit column reduced, by more than one, hction:

h. 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 power is verified on the trip system ~

D. No action required, indicators are considerqd redundant.

2. In only one trip system.

3. Not considered inf 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 would be operating.

7. The RCIC end HPCI steam line high flow trip'evel settings are given in terms of differential pressure. The RCXCS setting of 450" of H20 corresponds to 300X of rated steam flow at 1140 psia and 210K at 165 psia. The HPCIS setting of 90 psi corresponds to 225X of rated flow 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 RllR pumps're full. The pressure shall be maintained at or above the values listed in 3.5.1, wh'ich ensures water in the discharge piping and up to the head tank.

.70

NOTES FOR TABLE 3.2.B (Continued)

10. Only one trip system for each cooler fan.

ll. In only two of the four 4160 V shutdown boards. See note 13.

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

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

14, RHRSW pump would be inoperable. Refer to section 4.5.C for the requirements of a RHRSW pump being inoperable.

15. The accident signal is the satisfactory completion of a one-out-of-two taken twice logic of the drywell high pressure plus low reactor pres-sure or the vessel low water level (~.378" above vessel cero) originating in the core spray system trip system.

16, The ADS circuitry is capable of accompl'ishing its protective action with 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 />.

71

TABLE 3.2;C INSTRUMENTATION THAT INITIATES ROD BLOCKS YBni~vm No.

Opera le Per \

Trim S s 5) Function Tri Level Settin 2(lj APRM Upscale (Plow Bias) < O SSW+50X (2) 2(l) APRM Upscale (Startup Node) (8) < 12X 2(l) APRM Downscale (9) > 3X 2(1) APRM Inoperative (lob>

1(7) 1P~ Upscale (Plow Bias) < 0.64m + I4X (2) 1(?) RBM Downscale (9) 3X RBM Inoperative (10 )

3(1) IRM Upscale (8) <108/125 of full scale 3(1) IRM Downscale (3) (8) 5/~5 of full. sca1e 3(u IRM Detector not in Startup Position (8) 3(1) IRM Inoperative (8) (io')

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

~

2(l) (6) SRM Downscale (4) (8) > 3 counts/sec.

2(1.) (6) SRM Detector not in Startup Position (4)(8) 2(1) (6) RM Inoperative (8) (108) 2(l) Plow Bi s Ccmparator <10X difference in recirculation flows 2(1} Plow Bias Upscale < llOX recirculation flow Rod Block Logic

NOTI'.S FOR TABI,R 3. 2. C

l. For thc startup and run positions ol'he Reactor Mode Selector Switch, there shall be two operable or tripped trip systems for each function.

The SRM, IRM, and APRM (Startup mode), blocks need not be operable in "Run" mode, and the APRM (Flow biased) and RBM rod blocks need not be operable in "Startup" mode. If the first column cannot be met for one of the two trip systems, this condition may exist for up to seven days provided that during that time the operable system is functionally tested immediately and daily thereafter; if this condition last longer than seven days, the system with the inoperable channel shall be tripped.

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

2. M is the recirculation loop flow in percent of design. T'rip level setting is in percent of rated power (3293 Pdt) Total peak'ing factors

~

greater than 2.481 are permitted at reduced power. See Specification 2.1 for APRM control rod block setpoint.

XfUl downscale is bypassed when it is on its lowest range.

4. This function is bypassed when the count rate is > 100 cps and IRM above ranpe 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, F, D, H all in range 8 bypasses SRM channels B & D functions.

'7. The trip is bypassed when the reactor power is < 30X.

8. This function is bypassed when the mode switch is placed in Run.

9. This function is only active when the mode switch is in Run. This function is automatically bypassed when the IRM instrumentation is operable and not high.

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

a. SRN and IRM (I) Local "operate-calibrate" switch not in operate.

(2) Power supply voltage low.

(3) Circuit boards not in circuit.

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

(2) Less than 14 LPRM inputs.

(3) Circuit boards not in circuit.

73

'0 0

(l) Local "operate-calibrate" switch not in operate; (2) Circuit boards not in circuit.

(3) RBM fails to null.

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

ll. Detector traverse is ad)usted to 114 +- 2 inches,',placing the detector lower'osition 24 inches below the lower core plate.

TABLE 3.2,0 OFF-GAS POST TREATMENT ISOLATION INSTRU'.SNTATION Min. No.

erable (1) Function Tri Level Settin Action (2) Remarks Oi'i'-Gas Post Treatment Note 3 AorB l. 2 upscales, or 1 domsca1 Monitor and 1 upscale, or 2 dovn-scales ~ill isolate off-gas line.

Off-Gas Post Treatment l. One trip system vith auto Isolation transfer to another source EXES:

l. Whenever the=minimum number operable cannot be met, the indicated action shall be taken.

2. kctfon

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 INSTRDKNTATIOH THAT YONIT)RS LEAKAGE INTO DRYWELL S stan 2 Setpoints Action Remarks Equipment Drain 1. Used to determine identifiable reactor Flow Integrator N/A coolant leakage.

Sump Fill Rate- >20.1 min.

2. Considered part of sump system.

Timer Sump Pump Out Rate Timer <13.4 min.

floor Drain 1. Used to determine unidentifiable P1ow Integrator N/A . reactor coolant leakage.

Sump Pill Rate 2. Considered part of sump system.

TSJC~~ >80.4 min.

Sump Pump Out Rate Timer <8.9 min.

Air. Sampling N/A N/A N/A NOTES:

(1) Whenever a system is required to be operable, there shaL1 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.

1

TABLE 3.2.F SURVEILLANCE INSTRUMENT'ATION Minimum 0 of Operable Instrument Type Indication Channels Instrument f Instrument and Ran e Notes LI-3%6 A Reactor Mater Level Indicator -107.5" to (1) (2) (3)

LI-3&6 B +107.5" PI-3-54 Reactor Pressure Indicator 0-1200 psig (1) (2) (3)

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

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

TR-64-52 ~00'F TR-64-52 Suppression Chamber Air Recorder 0-400'F (1) (2) (3)

Temperature TI&4-55 Suppression Chamber Mater Indicator, 0-400'F (1) (2) (3)

TIS-64-55 Teeiperature LI&4-54 h Suppression Chamber Vater Indicator -25" to (1) (2) (3)

LI-64>>54 B Level +25II Control Rod Position 6V Indicating )

Lights )

Neutron Monitoring SRM, IRW, LPRM ) (1). (2) (3) (4.:

0 to 100'ower)

PS-64-67 Dryvell'Pressure Alarm at. 35 psig )

)

TR-64-52 and Drywell Temperature and Alarm if temp. )

).

PS-64-58 B and Pressure and Timer > 281 F and (1) (2) (3) (4' IS-64-67 pressure > 2 psig )

after 30 minute )

delay)

NOTES FOR TABLE 3.2.F

{l) From 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 operable.

(3) Xf the requirements of notes (l) and (2) cannot be met, either the requirements'of 3.5.H shall be complied with or. an orderly shutdown shall be initiated and the reactor'hall be 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) These surveillance instruments are considered to be redundant to each other.

78

TABLE 3.2.G CONTROL ROOM ISOLATION INSTRUMENTATION Minimum 0 of Operable Instrument Channels Function Tri Level Settin Action Remarks Control room air 270 cpm above background (4) (2) l. Monitors located in supply duct - 'normal control room air Radiation monitors supply ducts.

(RM-90-259 A & B)

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

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

(1) Whenever the minimum number operable cannot be met the indicated action shall be taken.

(2) Action-One channel inoperable Repair as soon as possible and functionally test the other channel. daily.

Tm channels inoperable Repair as soon as possible. Functionally test the control room particulate monitor (RM-90-53) and radiation monitor (RM-90-8) once per shift. These monitors alarm in the control room on high activity. This viLl 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 vLthin 30 days, declare the system initiated by these monitors inoperable and take action as specified in section 3.7.E.

(3) Any signal that isolates primary containment also isolates the control room and initiates the contro1. room emergency pressurization system. These signals and the appropriate action to take if the instrumentation is unavailable is indicated in Table 3.2.A.

(4) monitors are set to trip at270 cpm above background, which is a radiation level corresponding to about Thee 10 yci/cc of Xenon-133 (about 1 mRem/hr). The initial set point is based on manufacturers empirical formulas.

This setpoint Mll be verified by site operating personnel.

TABLE 3.2.H PLOOD PROTECTION INSTRUMENTATION Minimum No. of Operable Instrument Instrument Instrument Channels Number Punction hotes LS-23-75 A&B Reservoir Elevation 564 (1)t (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) Prom 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 shutdown shall be initiated and al1 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 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

TASLE 4.2.h SURVEILLANCE REQUIREMBCS FOR PRIMARY CONTAINMENT AND REACTOR BUILDING ISOLATION INSTRUMElTATION Function Functional Test Calibration Pre uenc Instrument Check Instrument Channel << (5) (5) (5)

Reactor Lov Mater Level (LIS-3-56A-D, SM 82)

Instrument Channel - once/3 months none High Pressure 'eactor Instrument Channel- (l)- once/3 months once/day.

Reactor Los Mater Level (LIS-'3-56', SV fl)

Instcmmnt Channel- (5) (5) (5)

High Dryvell Pressure (Psm-56A-D)

Instruaent Channel << (5) (5) (5)

Higa Raaiation Main Stean Line Tunnel Instrmaeat Channel- once/3 aentbs Lov Pressure Main Steam Line Instrument Channel- once/3 nenths once/day High Plow Main Steaza Line Instrument Channel- once/operating cycle none Kdn Steaxa Line Tunnel High Temperature

TABLE 4.2.A (Continued)

Function Functional Test Calibration Fre uenc Instrument Check Instrument Channel (1) (14) (22) once/3 months once/day {S)

Reactor Building Ventilation High Radiation - Reactor Zone Instrument Channel (1)(14)(22) once/3 months once/day (8)

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

SGTS Train B Heaters N/A'nstrument Channel- (4) N/A SGTS Train C Heaters Re"ctor 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 zone)

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

TABLE 4.2.h mtiaued)

Function Functional Test Calibration Pre uenc - Instrument Check Static Pressure Control (4) once/3 months N/A Pressure Regulator (reactor noae)

Group 1 (Initiating) Logic Checked during channel further functional'est.

No test required. (11) N/A N/A Croup 1 (Actuation) Logic once/operating cycle (21) N/A N/A C~p 2 (Initiating) .Logic Checked during channel functional test. No further test. required. N/A N/A Croup 2 (RHR Isolation-Actuation) once/operating N/A N/A Logic cycle (21)

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

Croup 2 (Drywell Sump Drains>> oace/operating N/A N/h Actuation) Logic cycle (21)

Croup 2 (Reactor Building aad once/operating N/A Refueliag floor, and Dryvell cycle (21)

Vent and Purge-Actuation) Logic Group 3 (Initiating) Logic Checked during channel functional test. No further test required. N/A N/A Group 3 (Actuation) Logic once/operating N/A cycle (21)

Group 6 Logic once/operating N/A N/A cycle (18)

TABLE 4.2.A (Continued)

Function Functional Test Calibration Fre uenc Instrument Check Group 8 (Initiating) Logic Checked during channel functional test.'o further test required. N/A N/A Reactor Building Isolation once/6 months (18) (6) N/A (refueling floor) Logic Reactor Building Isolation once/6 months (18) (6) N/A (reactor zone) Logic SGTS Train A.Logic ance/6 months (19) (6) N/A SGTS Train B Logic once/6 months (19) (6) N/A SGTS Train C Logic once/6 months (19) (6) w/a Static Pressure Con rol once/operating (refueling floor) Logic cycle (18) (6) N/A Static Pressure Control once/operating (reactor zone) Logic cycle (18) (6) N/A Instrument Channel Reactor Cleanup System Floor Drain High. Temperature once/operating cycle N/A

~

Instrument Channel-Reacto" Cleanup System Space High Temperature (23)

a. RTD once/operating cycle ( )

(once/operating cycle) N/A

b. Temperature Switch '(1) ( )

TABLE 4.2.B

• SURVEILLANCE REQUIRVIP. TS FOR INSTRI~ATI<N THAT INITIATE AR CONTROL THE CSCS Function Functional Test Calibration Instrument Check Instrument Channel once/3 months once/day Reactor Ixnr Mater Level (LIS-3-58A-D)

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

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

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

Instrument Channel once/3 months Reactor High Pressure (PS-3-2O4A-D)

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

Instrument Channel ence/3 months none Drywell High Pressure (PS-64-58A-D)

Instrument Channel once/3 months DryMell High Pressure (PS64-Ah-D)

Instrument Channel once/3 months Reactor;Low Pressure (PS-3-74A & B)

(PS-68-95)

(PS-68-.96)

TABLE 4.2.B (Continued)

Function' Functional Test Calibration Instrument Check Instrument Channel once/3 months none Reactor Low Pressure (PS-68-93 & 94)

Instrument Channel once/3 months none Reactor Low Pressure (PS-3-186A & B, and PS-3-187A & B)

Core Spray Auto Sequencing Timers (4) once/operating cycle none (Normal Power)

Core Spray Auto Sequencing Timers (4) once/operating cycle none (Diesel Power)

LPCI.Auto Sequencing Timers (4) ance/operating cycle none (Normal Power)

LPCI Auto Sequencing Timers -(4) once/operating cycle none (Diesel Power)

RHRSW Al, B3, Cl, D3 (4) once/operating cycle none Timers (Normal Power)

RHRSW Al, B3, Cl, D3 (4) once/operating cycle none Timers (Diesel Power)

LPCI Break Detection. Timer (4) once/operating cycle none K28A & B LPCI Break Detection Timer (4) once/operating cycle none K34A & B LPCI Break Detection Timer (4) once/operating cycle none K40A & B ADS Timer (4) once/operating cycle none

TABLE 4.2.B (Continued)

Puaction Puactioaal Test Calibration Instrument Check Instrument Channel once/3 xmnths none RHR Pump Discharge Pressure Iastrument Channel once/3 months none Core Spray Pump Discharge Pressure Instrument Channel Recirculation Pump Running once/3 months once/day Instrument Channel Recirculation Jet Pump Riser d/p once/3 nnnths once/day Core Spray Sparger to RPV d/p once/3 months once/day Trip System Bus Power Monitor once/operating cycle N/A none Iastrument Channel Condensate Storage Tank Low Level once/3 maths none Instrument Channel Suppression Chamber High Level once/3 months none Instrument Chinnel Reactor High Water Level once/3 breaths once/day Instrument Channel RCIC Turbine Steam Line High Plow once/3 aanths none Instrument Channel

.RCIC Steam Line Space High Temperature once/3 months none

TABLE 4.2.B (Continued)

Function-- .- Functional Test Calibration Instrument .Check Instrument Channel HPCI Turbine Steam Line High Plow once/3 months none Instrument Channel HPCI Steam Line Space High Temperature once/3 months none Core Spray System Logic ance/6 months (6) N/A RCIC System (Initiating) Logic once/6 months N/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 months N/A N/A ADS Logic once/6 months (6) N/A LPCI (Initiating) Logic once/6 months (6) N/A LPCI (Break Detection) Logic (11) once/6 months (6) N/A LPCI (Containment Spray) Logic once/6 months (6) N/A

TABLE 4.2.B (Continued)

Function Punctioaal Test Calibration Instrument Check Core Spray Loop A Discharge N/A once/6 months once/day Pressure (PZ-75-20)

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

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

RHR Loop B Discharge Pressure N/A once/6 xanths once/day (PI-74&5)

Instnaaent Channel- Tested during N/A N/A RHR Start functional test of RHR pm'refer to scctioa 4.5 B).

Instrmnent Chaanel- once/aenth once/6 maths W/h Thermostat (RHR Area Cooler Pan)

Instrmnent Channel- Tested during N/A N/h Core Spray h or C Start functiona1 test of core spray (refer to section 4.5.h)..

Instrmacnt Chaanel -. Tested during N/A N/h Core Spray B or D start functional teit of 'core spray (refer to section 4.5.h).

Instrument Channel.- once/ month once/6 aonths N/A Thcrmostat (Core Spray Area Cooler Pan)

TABLE ..B (Continued)

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

Core Spray Area Cooler Fan Logic Tested during logic N/A 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/A N/A Core Spray Motors A or D Start test of core spray pump (refer to section 4.5.A).

Instrument Channel- Tested during functional N/4 N/A Core Spray Motors B ox' Start test of core spray pump (refer to section 4.5.A).

Instrument Channel Tested during 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 system.

RHRSV Initiate Logic once/6 months N/A N/A

0 "fg

TABLE 4 2 C SURVEILLANCE RKQUIRKHENTS FOR INSTRUMENTATION THAT VflTIATE ROD BLOCKS Function Functional Test. Calibration 17) .-Instrument Check APRX Upscale {Floe Bias) -

{l3) once/3 months once/day (8)

APR4 Upscale {Startup '.tode) .{l) (13) once/3 months once/day (8)

APRM DoMnscale {l) {l3) once/3 maths once/day (8}

AH% Inoperative N/A once/day {8)

MH Upscale {Floe Bias) (13) .

once/6 once/day (8) mnths'nce/6 RM Dcanscale (1) (13) mnths once/day {8)

RRf:Inoperative (1) (13) N/A once/day {8)

(l)(2) (13) once/3 mnths once/day {8)

UN Downscale '(l)(2) -(l3) once/3 mnths once/day {8)

XRH Detector not iIL $ tartup . -(2) (once/opera- once/operating cycle (12)

Foeitton ting cycle)

XNM Inoperative (1)(2) (13) Nfh N/A SNN Upscale (1)(2) (D) once/3 aonths once fday {8)

SW.Downscale (l)(2). (13) ance/3 mmtha once /day (I)

--SRM Detector oot ia Startup ...,(2) (ciace/opera- once/operating -cycle'(X2) "'N/h foaition etag cycle)

SIN Inoperative N/h W/h Bias Coaparator (l)(D) once/operating cycle (20) '~lh 'lev thwr Iias Upscale -(1) {15) .once/3 maths . N/h Rod Block -Loiie {16) N/A 1/A

TABLE 4.2.D SURVEILIJDCE REQUIRBKNTS FOR OFF-GAS POST TREATMENT ISOLATION .INSTRUMENTATION Function Functional Test Cal ibra tion Instrument Check Off- Gas Post Treatment Monitor (l) once/3 months once/day (8)

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

ThBLE 4.2.E MINQSM TEST hND ChLIBRhTION FREQUENCY POR DRYMELL LEhK DETECTION INSTRPKNThTION Punction Punctional Test Calibratioa Instrument Check Equipment Drain Sump Plow (4) once/6 months oace/day Integrator Floor Drain Sump Flaw Integrator (4) once/6 months oace/day air Sampling System (1) once/3 months once/day Equipment Drain Sump Fill Rate (4) once/operating cycle N/h aad Pumpout Rate Timers Ploor Drain Sump Pill Rate and (4) oace/operating cycle N/h Payout Rate Timers Equipment Drain Logic oace/operating cycle (6) N/A Floor Drain Logic once/operating cycle. (6) N/h

I' TABLE 4.2.F MININMZEST AND CALIBRATION FREQUENCY FOR SURVEILLANCE INSTRUMENThTION ...

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) Dryvell Prcssure Once/6 months Each Shift

4) D~ell Temperature Once/6 months Each Shift

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

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

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

8) Control Rod Position Each Shift

9) Neutron Monitoring (2) Each Shift

10) Dryvell Pressure (PS-64-67) Once/6 months ll) Dryvell Pressure (PS-64-58$ ) Once/6 months

12) Dryvell Temperature (TR&4-52) Once/6 months

13) Timer (IS-64-67) Once/6 maths

ThBLE 4.2.6 SURVEILLANCE RE(gIREMENTS FOR CONTROL ROON ISOLATION INSTRUMENTATION Punction Punctional 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 Simulated automatic actuation of control room isolation and emergency pressurisation system once/operating cycle N/A N/A

TABLE 4 '.H mNrmt TEST Am CALIBRATION PREqUENCT POR PLoon PROTECTION INSTRmamATION Punction Punctional Test Calibration Instrument Check Instrument Channels Reservoir level (I) once/3 months N/A monitoring

NOTES FOR TABLES 4.2.A THROUGH 4.2.H E I. Initially once per 4.l.l) indicates a time the NRC may month until exposure hours (M as defined on Pig.

less frequent interval is in order, at which bc requested to change the interval.

r

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

30 This instrumentation is excepted from the functional test definition.

The functional test will consist of in)ecting a simulated electrical signal into the measurement channel.

Tested during logic system functional tests.

5. Refer to Table 4.1.B.

6. Th'e logic system functional tests shall include a calibration once

'er operating cycle >>f time delay relays and timers necessary for proper functioning of the trip systems.

4

7. The functional test will consist of verifying continunity across th6 inhibit with a voltohmmeter.

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 ire not requix'ed 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.

l3. Functional teat vill consist of applying simulated inputs (see note 3).

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

NOTES FOR TABLES 4.2.A THROUGll 4.2.8 Continued

14. Upscale trip is 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 flov unit in "Test" (producing 1/2 scram) and ad)usting the test input to obtain comparator rod block. The flov bias upscale will be verified by observing a local upscale trip light during operation and verified that it vill 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 where 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 vhere 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

'oops to be interrupted, thereby removing the flow bias signal to the APRM and RBM and scramming the reactor. This calibration can only be performed during an outage.

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

22. One channel of either the reactor zone or refueling zone Reactor Building Ventilation Radiation Monitoring 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 svitch may be "

tested monthly by using a simulated signal. The RTD itself is a highly reliable instrument and lass frequent testing is necessary.

3 2 BASKS I ddition to reactor protection instrumentation which initiates a reactor scram, protective instrumentation has been provided whic h 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 containment cooling have tolerances explicitly stated where the high 'nd and low values are both critical and may have a substantial effect on safety. The set points of other instrumentation, where only the high or low end of the setting has a direct bearing on safety, are chosen at a level away from the normal operating range to prevent inadvertent actua-tion of the safety system involved and exposure to abnormal situations.

Actuation of primary containment 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 zero) 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 k

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 ze'ro) above the top of the active fuel (Table 3.2.B) also initiate the RCIC and HPCI, provides input to the

BASES LPCI loop selection logic and trips the recirculation pumps. The low reactor water level instrumentation that is set to trip when reactor water 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 and starts the diesel generators. These trip setting levels were chosen to be high enough to prevent spurious actuation but low enough to initiate CSCS operation so that post accident cooling can bel accomplished and the guidelines of 10 CPR 100 will 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.

T)e high drywell pressure instrumentation is a diverse signal to the water level instrumentation and in addition to initiating CSCS, it causes isolation of Groups 2 and 8 isolation valves. For the breeks discussed above, this instrumentation will initiate CSCS operation at about the same time as the low water'evel instrumentation; thus the results given above are applicable here also.

Venturis are provided in the main steam lines as a means of measuring steam flow and also limiting the loss of mass inventory from the vessel during a s'team line break accident. The primary function of the instru-mentation is to detect a break in the main steam line. Por the worst case accident, main steam line break outside the drywell, a trip setting of 140X of rated steam flow in con)unction with the flow 'limiters and main steam line valve closure, limits the mass inventory loss such is not uncovered, fuel cladding temperatures remain below 1000'P that'uel end release of radioactivity to the environs is well below 10 CPR 100 guidelines. Reference Section 14.6.5 PSAR.

Temperature monitoring instrumentation is provided in the main steam line tunnel to detect leaks in these areas. Trips are prnvidcd on this instru-mentation and when exceeded, cause closure of isolation valves. The setting of 200'F for the main steam line tunnel detector is low enough to detect leaks of the crder of 15 gpm; thus, it is capable of covering the entire 'spectrum of breaks. For large breaks, the high steam flow instru-mentation

)

is a backup to the temperature instrumentation.

High radiation monitors in the main steam line tunnel have been provided to>detect gross fuel failure as in the control rod drop accident, With the established setting of 3 times normal background, and mein steam line 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,is with a nom>al set, point of 1.5 x normal full power background, provided eLso, Pressure instrumentation is provided to close the mein steam isolation, valves in Run Mode when the main steam line pressure drops below 850 psige I

100

~ .

3.2 HAS t':S The ilPCI high flow and temperature instrumentation are provided to detect a break in the HPCI stea,. piping. Tripping of this instru-ientation re-sults in actuation of HPCI isolation valves. Tripping logic for the high flow is a 1 out of 2 logic, and all sensors "re 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 temperature switches are arranged in 2 trip systems with 8 temperature switche in each tiip system.

The HPCI trip settings of 90 psi for high flow and 200 F for high tem-perature are such that core uncovery is prevented and fission product release is within limits.

The kCIC high flow and temperature instrumentation are arranged the sam ~

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

High temperature at the. Reactor Cleanup System floor drain could indicate a break in the 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 the effectiveness of the system even during periods when maintenance or testing is being performed. An exception to this is when logic functional testing is being pe"formed.

The control rod block functions are provided to prevent excessive control rod withdrawal so that MCPR does not decrease to 1.05. The trip logi'c

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

The minimum instrument channel requirements assure sufficient instrumenta-tion to assure the single failure criteria is met. The minimum instrument channel requirements for the RBM may be reduced by 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 APRM pro-vides gross core protection; i.e., limits the gross core power increase from withdrawal of control rods in the normal withdrawal 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; i.e.,

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

101

eASES If the IlN channels are Ln the worst condition of allowed bypass, the scaling arrangement l.s 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 Ls not sensitive enough. In either case the instrument will not respond to changes in control rod motion and thus, control rod motion is'prevented.

l The refueling 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 reactor pressure does not decrease rapid enough to allow either core spray or 1.PCI to operate in time. The automatic press'ure relief function is proyided as a backup to the HPCI in the event the HPCI does not operate. The arrangement of the tripping contacts is such as to prov1de this function when necessary and minimize spurious operation. The trLp set tinl;s gLven in the specification are adequate to assure the above criteria are met. 'l'he specification preserves the effectiveness of the during periods of maintenance, testing, or calibration, and also 'ystem minimizes the'isk of inadvertent. operation; i.e., onLy on'e instrument channel out oE service.

Two post 'treatment off-gas radiation monitors are provided and, when point is reached, cause an isolation of the off-gas line. Isolation their'rip 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 w4 pi l

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 radiation monitors are provided for each un't which initiate Primary Containment isolation (Group 6 isolation valves) Reactor Building Isolation and operation of the Standby Gas Treatment System. These instrument channels monitor the radiatfon 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 SGTS.;

Flow integrators and sump fill rate Aand pump out rate timers are used to determine leakage in the drywell. system whereby the time interval to fill 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) .

102

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 instrument 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 room 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 mangitudes 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 reservoir 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 will 'be permitted to operate until water begins to run across the top of the pumping station at elevation 565. Seismically qualified, redundant level switches each powered from a separate division of power are provided at the pumping station to give main control room indication of'his 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 waterpumps.

103

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

Those instruments which, when tripped, result in a rod block have their contacts arranged in a 1 out of n logic, and all are capable df being bypassed. For such a tripping arrangement with bypass capability provided, there ie an optimum 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 between teste is approximately given by:

Where: i the optimum interval between tests.

t the time the trip contacts are disabled from perfo'rming their function while the

, the test is 'in progress.

r ~ the expected failure rate of the relays.

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

2 0.5 x 10 3 10'

~ 40 days For additional mar in a test interval of-once er month will be used

~fnieiall (7) ., UCRL-50451,'mproving Availability and Readinees of Field Equipment Through Periodic Inspection, Ben)amin Epstein, Albert Shiff, July 16, 1968, page 10, Equation (24), Lawrence Radiation Laboratory.

Thc sensors and electronic apparatus have not been included here as these are analog devices with readouts in the control room and the sensors and electronic apparatus can be checked by comparison with other like instru-ments. The checks which '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.

104

BASES The,above, calculated test interval optimizes each individual channel, considering it to be independent of all others. As an example, assume that there are two 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 communicate 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 two channels are never tested't the same time.

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

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

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

'i'he formula given above; minimizes the unavailability of a single channel which must be bypassed during testing. The'minimization of the unavail-ability is illustrated by Curve No. 1'o) Figure 4 ~ 2 ~ 1 which assumes that a channel has a failure rate o'f 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 i'minimum at a test interval i, 'of 3.16 x 10 hours.

Xf two similar channels are used in a 1 out of 2 configuration, the test interval foi minimum unavailability chan'ges as a function of the rules for 'testing. The simplest case is to test. each one independent of the other. In this ca'se, there is assumed to be a finite probability that both may be bypassed at one time. This case is shown by Curve No. 2.

Note that the unavailability is lower as expected for a redundant system and'he minimum occurs at the same test 'interval. Thus, if the two channels are tested independently, the equation'bove yields the-test interval for minimun unavailability.

'A more usual case is that the testing is not done independently. Xf both channels are bypassed and tested at the same time, the result is shown 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 not nearly as lov as Case 2 which indicates that this method of testing does not take full advantage of the redundant channel. Bypassing both channels for simul-taneous testing should be avoided.

II The most likely case vould be to. stipulate that one channel be bypassed, tested,,and restored, and then .immediately following, the'econd channel be bypassed, tested, and restored. This is shown by Curve No. '4. Note that

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

The best test procedure of all those examined is to perfectly stagger the tests. That is, if the test interval 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, however, that more strongly support the perfectly staggered tests, including reductions in human error.

The conclusions to be drawn are these:

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

2. more 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 here also and were used to arrive at the functional testing frequency. The ofi'-gas post treatment monitors are connected in a 2 out of 2 logic arrangement. Based on experience with instruments of similar design, a testing interval of once every three months has been found adequate.

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

106

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IO4 I)I5 IP TEST IHTERVAL - (p) HOURS BROILS FERRY NUCLEAR PLAHT FINAL SAFETY AHALYSIS REPORT System Unavailability Figure I).2 L

ITING CONDITIONS POR OPERATION SURVEILLANCE RE UIREMENTS REACTIVITY CONTROL 4.3 REACTIVITY CONTROL Applies to the operational status Applies to the surveillance require-af the control rod system. ments of the control rod system.

~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 control reac-tivity. tivity.

A. Reactivit Limitations h. Reactivit Limitations

1. Reactivit mar in core 1. Reactivit mar in core

~loedio ~loadie P h sufficient number of con- Sufficient control rods shall trol rods shall be operable be withdrawn following a re-so that the core could be fueling outage when made subcritical in the were performed to cori'lterations most reactive condition demonstrate with a margin of

'during the operating cycle, 0.38X h k/k the core can be with the strongest control made subcritical at any time rod fully withdrawn and all in the subsequent fuel cycle other operable control rods with the;analytically deter-fully inserted. mined strongest operable con-trol rod fully withdrawn and all other operable rods fully inserted.

2. Reectivit mar in in-o erable control rods o ereble control rods

a. Control rod drives which a. Each partially or fully cannot be moved with con withdrawn operable control trol rod drive pressure rod shall be exercised one shall'e considered in- , notch at least once each operable. week when operating above 30X power. In the event b., The controod direc- power operation is continu-tional control valves 'ng with three or more in<<

for inoperable control operable control rods, this rods shall be disarmed test shell be performed at electrically. least once each day, when operating above 30Z,power.,

108

SURVEILLANCE RE UIREMENTS 3.3. A REACTIVITY CONTROLS .3.A REACTIVITY CONTROLS Co Control rode vith scram b. A second licensed operator times greater than those shall verify the confor-permitted by Specifica- mance to Specification tion 3.3.C.3 are inoper- 3,3.A.2.d before a rod may able, but if they can be be bypassed in the Rod inserted with control rod Sequence Control System.

drive pressure they need not be disarmed cally.

electri- c. When it is initially determined that a control rod is incapable of normal insertion, an attempt d, Control rods vith a failed to fully insert the control rod "Full-in" or "Pull-out" shall be made. If the control position evitch may be by- rod cannot be fully inserted thi passed in the Rod Sequence reactor shall be brought to the Control System and consi- Shutdown Condition within 'old dered operable if the actual 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and a shutdown margin t6et 'made to demonstrate'nder rod position ie known. These rode must be moved in sequence this condition that the core ca to their correct positions be made subcritical for any rea (full in on insertion or full tivity condition during the re<<

out on withdrawal). mainder of the operating cycle

'I vith the analytically determin-

e. Control rods vith inoperable ed, higheet worth control rod accumulators or 'those whose capable of withdrawal, fully position cannot be positively vithdravn, and all other contro determined shall be consi- rode capable of insertion fully dered inoperable. inserted.

Inoperable control rods shall be positioned such that Speci-fication 3.3.A.1 is met. In addition, during reactor power operation, no more than one control rod in any 5 x 5 array may be inoperable (at least 4 operable control rode 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-down condition within 24 hours B. Control Rods B. Control Rods

l. Each control rod shall be l. The coupling integrity shall be coupled to its drive or verified for each withdrawn con-completely inserted and the trol rod as follows:

109

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS

.3.3.B Control Rods 4.3.B Control Rods control rod directional a. When a rod is withdrawn the control valves disarmed first time after each re-electrically. This require- fueling outage or after ment does not apply in the maintenance, observe dis-

. refuel condition when the cernible response of the reactor is vented. Two con- nuclear instrumentation.

trol rod drives may be removed However, for initial rods as long as Specification when response is not dis-3.3.A.1 is met. cernible, subsequent exer-cising of these rods after the reactor is above 2g power-shall be performed to verify instrumentation

'response.

b. When the rod is fully with-drawn 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 power operation or when 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. a. Whenever the reactor is in 3. Prior to the start of control

• the startup or run modes rod withdrawal at startup, and below 2Q rated power the prior to attaining 20$ rated Rod Sequence Control System power during rod insertion at (RSCS) shall be operable. shutdown, the capability of the Rod Sequence Control System (RSCS) and Note: The Rod Sequence Control the Rod Worth Minimizer to System (RSCS) has been properly fulfilltheir functions evaluated only through th shall be verified by the follow-

.first refueling outage. ing checks:

A complete re-evaluation is required prior to opera tions following the. first refueling outage.

110

LIMITING CONDITIONS POR OPERATION SURVEILLANCE RE UIREHENTS 3.3.B Control Rode 4.3.8 Control Rods be During the shutdown procedure no rod movement is permitted The capability of the RSCS to pro-fo11owing the testing per- perly fulfillits function shall be formed above 20% power and thd verified by the following tests:

reinstatement of the'SCS restraints at or above 20% Sequence portion Select a sequence power. A1ignment of rod and attempt to withdraw a rod in the groups shall be accomplished remaining sequences. Move one rod prior to performing the in a sequence and select theI remain-tests. 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 20% rated power the six comparator circuits go through Rod Worth Miniinizer'hall be test initiate; comparator inhibit; operable or a second licensed 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 the illumination of test complete light.

control rod program.

The capability of the Rod Worth Minimizer (RWM) shall ho vow < F(hA Lot 4L est JVAJVltIlls

~

checks:

l. The correctness of the control rod withdgawal sequence input to the RUM computer, shall be'erified.

2. The RWM computer on line diagnostic test shall be If Specifications successfully performed.,

3.3.B.3.a through .c cannot be met the 3. Proper annunciation of;the.

reactor shall not ba started, selection error of at or if the reactor is in the least one outmf-sequence run or startup modes at less control rod in each fully than 20% rated power, it shall be brought to a shut- inserted group shall be down condition immediately.

verified.

4. The rod block function of the RWH 'shall be verified by withdrawing the first rod is in out-of-sequence control rod no more than to the block point.

0 1 When of required, the presence a second licensed operator to verify the following of the correct rod program shall be" verified.

~ II%~

LIi'!ITIHG CONDITIONS FOR OPFRATTON SURVEILLhNCE RE UIRFAENTS 4.3.E Control Rods

4. Control rods shall not be 4. Prior to control rod withdrawal withdrawn for startup or for startup or during refueling, refueling unless at 'east verify that at least two source ten source range channels range channels have an observed, have an observed count rate count rate of at least thre'e equal to or greater than counts per second.

three counts pcr second.

5. .During operation with 5. When a limiting control rod:

limiting control .rod pat- pattern exists, an instrument terns, as determined by the test of tt.e RRN -'unctional designated qualified person- shall be performed prior toi nel, either: withdrawal of the designated rod(s) .

a. Both RBH channels shall be operable:

or

b. Control rod withdrawal shall be blocked:

or c, The operating power level shall be limited so that the YiCPR will remain above 1.05 assuming a single error that results in complete withdrawal of any single operable con-trol rod.

C. Scram ~Insertion Times C. Scram Insertion Times

1. Th average scram insertion After each refueling outage all time, based on the deenergi- operable rods shall be scram time zation of the scram pilot valve tested from the fully withdrawn so/,enoids as time zero, of, all position with the nuclear system operable control rods in th pressure above 950 psig (with reactor power operation condi- saturation t mperature). This testing tion sl:all be no greater thun: shall oe completed prio" to rexceecing 40% power. Below 20% power, only rods X Inserted From Avg. Scram Inser- "n tho e sequences (A12 and A34 or Full. Vithdravn tion Times (sec) B12 and B34), which were fully

~

withdrawn i.n the region from 100/

5 0.:475 ~rod density to 50K rod density shall 20 0. 90 be scram time tested. During all 50 2.0 scram time testing below 20%%d povs.'r 90 5.0 thc RRf shall be operab'le.

112

LIHITING CONDITIONS POR OPERATION SURVEILLANCE RE UIREMENTS 3.3.C Scram Insertion Times 4.3.C Scram Insertion Times

2. The average of the scram inser- 2. At 16-week intervals, 107.'f the

'ion times for the three fastest operable control rod driv'es shall .

operable control rods of all be scram timed above 800 psig.

"=

groups of four control rods in Whenever such scram time measure-.

'a two-'y-two array shall be no ments are made, an evaluation greater than: shall be made to provide 'rea'yen-'.

able assurance that proper con-X Inserted Prom Avg. Scram Inser- trol rod drive performance is being maintained. t 5 0.398 20 0.954 50 2.120 90 5.300 The maximum scram insertion

'ime for 90X insertion of any "operable control rod shall not exceed 1.00 seconds.

D. Reactivit Anomalies D. Reactivit Anomalies The reactivity equivalent of During the startup test program and the difference between the actual startup following refueling outages, critical rod configuration and the the critical rod configurations will expected configuration during pover be compared to the expected confi>>

operation shall not exceed 1X hk. gurations.at selected operating con-If this limit is exceeded, the ditions. These comparisons vill be reactor will be shut down until the used as base data for reactiyity cause has been determined and cor- monitoring during subsequent'pover rective actions have been taken as operation throughout the fuel cycle.

appropriate, At specific pover oper'ating jondi-tions, the critical rod configura-tion will be compared to the,confi-guration expected based upon<appro-priately corrected past data'his comparison vill be made at least every full pover month.

113

LIM TING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS Reactivit Control 4.3 Reactiuit Control If Specificationa 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 />'14

3.3/4.3 USES:

A. Reac tivit Limitation

1. The requirements for the control rod drive system have been identified by evaluating the need for reactivity control>via control rod movement over the full spectrum of plant condi-tions and events. As discussed in subsection 3.4 of the"t 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 with the strongest rod fully withdrawn. This reactivity characteristic hasibeen a basic assumption in the analysis of plant performance. Cme- ~

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 vill show that the reactor is subcritical by 'at least-R + 0.38X hk with the analytically determined strongest control rod fully withdrawn.

The value of R in units of XAk, is the amount by which the

~

core reactivity, in the most reactive condition at any time in the subsequent operating cycle, ie calculated to be greater than at the time o8 the demonstration. "R", therefore, is the difference between the calculated value of maximum core,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.

The demonstration is performed with a control rod which d.s cal-culated to be the strongest rod. In determining this "analy-tically strongest" rod, it is assumed that every fuel assembly of the same type has identical material properties. In:the core, however, the control cell material propert%be vary- 'ctual vithin allowed manufacturing tolerances, and the stronge'st 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 used for the demonstntion (the "analytically strongest")~ is not necessarily the strongest rod in the core. Studies"have been made which compare experimental criticals with calq'uleted criticals. These studies have shown that actual criticals can be predicted within a given tolerance band. For gadolinia cores the additional margin required due to control cell material manu" facturing tolerances and calculational uncertainties has'xpari-mentally bosn determined to be 0.38X hk. When this additional margin is demonstra'ted requirement is mat.

it assures that the reactivity control

2. Reactivit mar in - ino arable control rods - Specification 3.3.A.2 requires that a rod be taken out of service if it cannot be moved with drive pressure. If the rod is fully 115

0

~ ~ 1

/

3.3/4.3 BASES: j inserted and disarmed electrically , it is in a safe position of maximum contribution to shutdown reactivity.

If it is disarmed electrically in a non-fully inserted position, that positiion shall be consistent with the shutdown reactivity limitations stated in Specification; 3.3.A. l. This assures that the core can be shutdown at".

all times with the remaining control rods assuming the operable control rod does not insert. The Rod util

'trongest Sequence Control System is not automatically bypassed reactor power is above about 30% power. Therefore, control rod movement is restricted and the single notch exercise surveillance test is only performed above this power level.

The Rod Sequence Control System prevents movement of out-of-sequence rods unless power is above 30%.

4'

~-

B. Control Rods

1. Control rod dropout accidents as discussed in the TSAR can lead to significant core damage. If coupling integrity's maintained, the possibility of a rod dropout accident i's eliminated. The overtravel position feature provides check 83 only uncoupled drives may reach this posi-a'ositive tion. Neutron instrumentation response to rod movement provides a verification that the rod is following its drive.

Absence of such response to drive movement could indicate an uncoupled condition. Rod position indication is required for proper function of the rod sequence control system and the rod worth minimizer.

2~ The control rod housing support restricts the outward move-ment of a control rod to less than 3 inches in the extremely remote event of a housing failure. The amount of reactivity which could be added by this small amount of rod withdrawal, which is less than a normal single withdrawal increment, will not contribute to any damage to the primary coolant system.

The design basis is given in subsection 3.5.2 of the P)AR and the safety evaluation is given in subsection 3.5.4. This support is not required if the reactor coolant system is at atmospheric pressure since there would then be no driving force to rapidly eject a drive housing. Additionally, the support is not required if all control rods are fully mLn aerted and if an adequate shutdown margin with one control rod withdrawn has been demonstrated, since the reactor would remain subcritical even in the event of complete ejection of the strongest control rod.

• To disarm the drive electrically, four amphenol type plug connectors are removed from the drive insert and withdrawal solenoids rendering the rod incapable of withdrawal. This procedure is equivalent to valving out the drive and is preferred because, in this condit:ion>

drive water cools and minimizes crud accumulation in the drive.

Electrical disarming does not eliminate position indication.

116

3.3/4.3 BASES:

The Rod Worth Nnimizer (PWM) ond the Rod Sequence Control System (RSCS) r<<::trf.."t withdrawn).". and inocrtioni3 of control rods to prr.-op<<cLf i<<d scqucnc<<o. All pot trrns associated with these oequ<<ncos have the cliarocter istic that, assuming the worst single deviation from the sequence, the drop of any control rod from the fully inserted position to the position Of the control rod 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 FSAR and NFDO-10527 and supplements thereto.

In performing the fdnction described above, the RWM and RSCS arc not required to impose any restrictions at core power levels in excess of 20 percent of rated. Material in the cited refero."i.

, shows that it is impossible to reach 280 calories per gram in tr event of a control rod drop occurring,xt power greater than 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 produce rod worths high enough to be of concern relative to the 280 calorie per grani rod drop limit.

Zn this range the RM and the, RSCS constrain the control rod sequences aiid patterns to those whi h involve only acceptable rod worths, The Rod Vorth Minimizer and the Rod Sequence Control System provide automatic supervision to assure that out of seqiiencc control rods will not be withdrawn or inserted; i.e., it limit deviations from planned withdrawal sequences. 'Ref. 'perator Section 7.16.5.3 of the FSAR. They serve as a backup to procedure control of control rod sequences, which liniit the maxinnlm reacti-vity worth of control rods. In the event that the Rod cnorth Minimizer is out of service, when required, a second licensed

.operator can manually fulfill the control rod pattern cIIin-formance functions of this system. In 'this case, the RSCS is bacl:

up by independent procedural controls to assure conform'ance.

117

The functions of the RWM and RSCS make it unnecessary to specify a license limit on rod worth to preclude unacceptable consequences in the event of a control rod drop. At low powers, below 20 percent, t'hese devices force adherence to acceptable rod patterns. Above 20 pere'ent 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 by 'power distribution requirements, as defined in

'mposed 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.

Because the instrument has an instrument error of

+10 percent of full power the nominal instrument setting is 30 percent, of rated power.

4. The Source Range Manit'or (SRM) syst: em performs no automatic s'afety system'function; i.e., it has no scram function. It

~ I 117a

does provide the operato>> wit<<a visual indication of neu-tron level, The consequences or reactivity accidents are>

functions of the initial neutron flux. The requirement of at least 3 counto per second assures that any transient, should it occur, begins at or above the in" tial value of 10 of xated power u." d in the analyses of transients from cold conditions. One operable SRM channel would be adequate to monitor the approach to criticality using homogeneous patterns of scattered control rod withdrawal. A minimum of two operable SRM's are provided as an added conservatism.

5. The Rod Block Monit:or (RBM) is designed to automatically prevent fuel damage in the event of erroneous rod withdrawal from locations of high power density duxing high power level operation. Two channels are provided, and one of these may bc by j)aso('d from c e conan J e for ma ei!ance aud /oi.'esting.

~

Ti happ.ing of onc of th~. ctiaun'.16 ll .1 block erroneou! cd withdrawal soon enough to prevent fuel damage. The speci-fied restrictions with one channel out of service conserva-tively aooure that fuel damage will not occur due to rod withdrawal errors when this condition exists.

A 1'miting control rod pattern io a pattern which results in the core being on a thermal hydx'aulic limit (i.e., >fCPR or LHGR - 13.4). During use of such p!itterno, it is Judged that i.'e t:ing of the RBM system prior to withdrawal of such rods to assure ito operab5.3.sty will Go'8iirc t iat improper with-drawal does iiot occur. Tt is norma13.; I:he responoibili t;y of the Nuclear Engineer to identify these limiting pa-terns "nd the designated rodo either when the patterns are initially established or as they develop due to the occurrence of inoperable control rods in other than limiting patterns.

Other personnel qualified to perform these functions may be deoignated by the plant superintendent t:o perform these functions.

Sci'!lm Tn4('rt$ !>a I imco

'he control rod system io designed to bring t.hc reactor subcritical at a rate fast enough to prevent fuel damage' e to prevent the from'becoming leos t:han'-."." The liotiting power transient is

~

that resulting from th:

Ailalysis of this 'tcilnsient shows that the negativr. reactivity r!ites resulting from the scram (CESAR Figure N3.6-9) with the average x'esponse of all the drives as given in the above. opecification, provide the required protection, and MCPR xemains gre..ter than 1,Q5, On an early BMR, some degradation of control rod scram performance occurred during plant otartup and wao determined to be'.caused by 118

3.3/4.3 BASES:

particulate material (probably construction debris) p~ui;ging an internal control rod drive filter. The design of the present control rod drive (Model 7RDB144B) is grossly improved by the relocation of the filter to a location out of the scram drive path; i.e., it can no longer interfere with scram performance, even if completely blocked. 4 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 series of engineering tests under simulated reactor operating conditions. The successful performance of the new drive under actual operating conditions has also been demonstrated by consistently good in-service test results for plants using the new drive and may be inferred from plants using the older model drive with a modified (larger screen size) internal filter which is less prone to plugging. Data has been documented by surveil-lance 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 the "plugged filter" problem, very frequent scram tests were necessary to ensure proper performance.

However, the more frequent scram tests are now considered totally unnecessary and unwise for the following reasons:

1. Erratic scram performance has been identified as due to an obstructed drive filter in type "A" drives. The drives in BFNP are of the new "B" type design whose scram performance is unaffected by filter condition.

2. The dirt load is primarily released during startup of the reactor when the reactor and its systems are first sub)ected to flows and pressure and thermal stresses. Special atten-tion and measures are now being taken to assure cleaner,,

systems. Reactors with drives identical or similar (shorter stroke, smaller piston areas) have operated through many refueling cycles with no sudden or erratic changes in scram performance. This preoperational and startup testing is sufficient to detect anomalous drive performance.

3. The 72>>hour outage limit which initiated the start of the frequent 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 it provides an incentive for shortcut actions to hasten,returni..>g "on line" to avoid the additional testing due a 72-hour outage.

119

3.3/4.3 BBSES:

The surveillance requirement for scram testing of all the control rods after each refueling outage and lOX of the control rods at 16-week 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.

Reactivit Anomalies During each fuel cycle excess operative reactivity varies as fuel depletes and as any burnable poison in supplementary 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 interpretable data relative to core reactivity. Furthermore, using power operating base conditions permits frequent reactivity comparisons.

Requiring a reactivity comparison at the specified frequency assures that a comparison will be made before the core reactivity 120

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 would not lead to transients exceeding design conditions of the reactor system.

121

L ITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 4e4 STANDBY LI UID CONTROL SYSTEM A licabilit A licabilit P

Applies to the operating status Applies to the surveillance require-of the Standby Liquid Control ments of the Standby Liquid Control System. System.

Ob ective Ob ective To assure the availability of a To verify the operability of the Standby system with the capability to Liquid Contgol System.

shut down the reactor and main-tain the shutdown condition with-out the use of control rods.

S ec. fication S ecification A, Normal S stem Availabilit A. Normal S stem Availabilit

l. The standby'iquid con- The operability of the Standby shall veri-trol system shall be opera- Liquid Control System be ble at all times when there fied by the performance of the is fuel in the reactor ves- following tests:

sel and the reactor is not in a shutdown condition 1. At least once per month each with all operable control pump loop shall be function-rods fully inserted except ally tested.

as specified in 3.4.8.1.

2. At least once during, each operating cycle:

a. Check that the setting of the system relief valves is 1425 + 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 flow rate of 39 gpm 122

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.4 STANDBY LI UID CONTROL SYSTEM 4.4 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 reactor vessel.

This test checks explo-sion of the charge asso-ciated with the tested loop, proper operation of the valves,. and pump operability. Replacement charges shall be selected such that the age of charge in service shall not exceec five years from the manu-facturers assembly date.

d. Both systems, including both explosive valves, shall be tested in the course of two operating cycles.

B. 0 eration with Ino erable B. Surveillance with Ino erable

1. From and after the date 1. When a component is found to that a redundant compo- be inoperable, its redundant nent is made or found to component shall be demon-be inoperable, Specifica- strated to be operable tion 3.4.A.1 shall be con- immediately and daily there-sidered fulfilled and con- after until the inoperable tinued operation permitted component is repaired.

provided that the component is returned to an operable condition within seven days.

123

LXHITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.4 STaNDBY LI UID CONTROL SYSTEH 4.4 STANDBY LI UID CONTROL SYSTEH.

"C. Sodium Pentaborate Solution C. Sodium Pentaborate Solution At all times when the Standby The following tests shall be Liquid Control System is re- performed to verify the avail-quired to be operable the fol- ability of the Liquid Control lowing conditions shall be met: Solution:

1. The net volume concentra- 1. Volume: Check at least tion of the 'Liquid Control once per day.

Solution in the liquid con-trol tank shall be main- 2. Temperature: Check at tained as required in least once per day.

Figure 3.4.1.

2. The temperature of the Concentration: Check at liquid control solution least once per month.

shall be maintained above Also check concentration the curve shown in Figure any time water or boron D.

pumps'.

3.4.2. This includes the piping between the standby liquid control tank and the suction inlet to the If specification 3.4.A through is added to the solution or solution temperature is below the temperature required in Figure 3.4.2.

C cannot be met, the reactor shall be placed in a Shutdown Condition with all operable control rods fully inserted within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

124

19 REGION OF REQUIRED o 18 VOLUME-CONCENTRATION FO CV 17 (3>350 gal - 16.34) (>,85O gELl - 16.3$ )

0 16 15 o 14 (4 60 gal-l3.4k)

~x 13 I

{4630 gal-12.1%)

12 LOI LEYEI ALARM l

~(48SO al-11.6%)

11 10 HIGH. LEVEL ALARM ~

I T NKOVERFLOYI ~

2000 2SOO 3500 4000 4500 5000 .,

NET VOLUME OF SOLUTION IN TANK (gal)

BROWS FKRRY NUCLEAR Pt.AHT FIHAI.'SAF'ETY AHAl.YSIS REPORT SODIUM PENTABORATE SOLUTION VOIlJMEWONCENTRATED REQJZRIRENTS FIGURE 3o4 1 125

90 SOLUTION TEMPERATURE MUST BE EQUAL TO OR GREATER THAN THAT INDICATED BY THE CUI'(VE 8o 70 Pe g 6o fi 10 15 SODIUM PENTABORATE SOLUTION (aa V/o Na2BIOO16.H20)

BROWHS FERRY NUCLEAR PLAHT FIHAL SAFETY ANAlYSIS REPORT SODIUM PENTABORATE SOLUTION TEMPERATURE REQUIREMENTS FIGURE 3,4~2

BASES' STANDBY LI UID CONTROL SYSTEM A. If no more than one operable control rod is withdrawn, the basic shutdown.

reactivity requirement for the core is satisfied and the Standby Liquid Control System is not required. Thus,-the basic reactivity requirement for the core is the primary determinant of w'hen the liquid control sys-tem is required.

The purpose of the liquid coetrol eyatee ie to provide the capability of i bringing the reactor from full power to a cold, xenon-free shutdown condi-;,

tion assuming that none of the withdrawn control rods can be 'inserted.

To meet this ob)ective the liquid control system is designed to infect p

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 can-centration in the reactor core is required to bring the reactor from full power to a five percent hk 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-lowing the xenon poison peak.

T' 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 l 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 whi(e the circuit is being repaired. Assurance that the remaining system will perform its intended function and that the long-term average of the system is not reduced is obtained fro a one-out-of" 'vailability two system by in 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, I

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 and liquid level alarms for the system are annunciated in the factors'emperatu're control room. "

The, solution is kept at least 10'F above the saturation temperature to guard against boron precipitation. The margin 'is included in Figure. 3.4.2e f

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.

127

1 I

BASES:

The quantity of stored boron includes an additional margin (25 percent) beyond the amount needed to shut down the reactor to allow for possible i;>perfect mixing of the chemical. solution in the reactor waters 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 shutdown requirement as defined in Figure 3.4.1.

4.4 BASES

STANDBY LZ DID CONTROL SYSTEM Experience with pump operability indicates that the monthly test, in combination Mith the tests 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.

I 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.

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.5 CORE AND CONTAINMENT COOLING 4.5 CORE AND CONTAINMENT COOLING SYSTEMS SYSTEMS A licabilit Applies to the operational Applies to the surveillance status of the core and contain- requirements of the core and ment cooling systems. containment cooling systems when the corresponding limiting condi-tion for operation is in effect.

~ob cct've ~ot ecttve To assure the operability of To verify the operability of the the core and containment cooling core and containment cooling systems under all conditions for systems under all condit'ons for which this cooling capability is which this cooling capability is an essential response to plant an essential response to plant abnormalities. abnormalities.

~S ecification S ecification A. Core S ra S stem CSS A. ~Core S re S stem CSS

1. The CSS shall be opera- 1. Core Spray System Testing.

ble:

Item 'rre eeoc (1) prior to reactor startup from a a. Simulated Once/

cold condition, or Automatic Operating Actuation Cycle (2) when there is irra- test diated fuel in the vessel and when the b. Pump Opera-. Once/

reactor vessel pres- bility month sure is greater than atmospheric pressure, C ~ Motor Once/

except as specified Operated month in specifications Valve 3.5.A.2, 3.5.B.2, or Operability 3.9.8.3.

d. System flow Once/3 rate: Each months loop shall deliver at least 6250 gpm against a system head corres-ponding to a 0

130

t LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.5.A Core S ra 5 stem C~SS 4.5.A Core S ra S stem CSS 2~ If 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- between the ding all active components reactor ves>>

in .the other CSS loop and the eel and the RHR system (LPCI mode) and the primary con-diesel generators are operablo. tainment.

3 ~ Ii'pecification 3.5.A.l 2. When it is determined that one or specification 3.5.A.2 core spray loop is inoperable, cannot be met, the reactor at a time when operability is shall be shutdown in the required, the other core spray Cold Condition within 24 loop, the RHRS (LPCX mode), and the diesel generators shall be hours'hen demonstrated to be operable I) ~ the reactor vessel immediately. The operable core pressure is atmospheric spray loop shall be demonstrated and irradiated fuel is in to be operable daily thereafter.

the reactor vessel at least one core spray loop with one operable pum'p and associated diesel generator shall be operable, except with the reactor vessel head removed as specified in 3.5.A.5 or prior to reactor startup as specified. in 3.5.A.1.

5~ When irradiated fuel is in the reactor vessel and. the r'eactor vessel head. is removed, core spray is not required provided work is not in progress which has the potential to drain the vessel, provided. the fuel pool gates are open and the fuel pool is maintained above the low level alarm point, and. provided. one RHRSW pump and associated valves supplying the standby coolant supply are operable.

131

t 3.5.8 l.

(2)

'URVEILLANCE LIMITING CONDITIONS Resldunl Heat Removal S stem

~RHRS Cooling)

(LPCI and Centatnnent The RHRS (l) prior shall to a be startup from a Cold Condition; or when FOR OPERATION

'operable:

reactor there is irra-diated fuel in the reactor vessel and when the reactor vessel pres-sure is greater than atmospheric, except as specified in specifica-tions 3.5.8.2, through 3.5.8e7 and 3.9.B.3,

~RHRS Coolin'g) a.

b.

c.

d, Test Pump bility RE UIREMENTS 4.5.8 Residual Heat'emoval (LPCI and Cnntainnent Simulated Automatic Actuation Opera-Motor Opera-Pump valve operability Flow Rate

'ed S stem Once/

Once/

month Once/

month Operating Cyclo Once/3 months

2. With the rcactnr vessel pres- Three LPCI pumps shall sure less than 105 paip, the deliver 30,000 gpm against RHRS may be removed from ser- a system head corresponding vice (except that two RHR pumps- to a 20 psi differential containment cooling mode and between the reactor vessel associated heat cxchangers must and the primary containment.

remain operable) 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 /> while 2. An air test on the drywell and being drained of suppression torus headers and nozzles shall chamber quality water and be conducted once/5 years, A "filled with primary coolant water test may be performed on quality water provided that the tarus header in lieu of the during cooldown two loops with air test.

one pump per loop or one loop with two pumps, and associated diesel generators, in the core spray syste 3. When it is determined that one RHR are operable. pump (LPCI made) is inoperable at a time when operability is rcqu" rcd, the remaining RHR pumps (LPCI mode)

3. If one RHR pump (LPCI mode) and active components in both access is inoperable, the reactor paths of the RHRS (LPCI mode) and may remain in operation for a the CSS and the diesel generators period not to exceed 30 days shall be demonstrated to be opera-provided the remaining RHR ble immediately, The operable RHRS pumps (LPCI mode) and bath pumps (LPCI mode) shall be demon-ncccss paths of the RHRS strated to bc aperable every 10 days (LPCI mode) and the CSS and thereafter until the inoperable the diesel generators remain pump is returned to normal service.

operable.

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE VIREMENTS t 3.5PB Residual Heat Removal S stem

~RRRS Cooling) 4, (LPCI and Containnent If more than one RHR pump 4.5,8 Residual Heat

~RRRS Cooling)

4. When it is Removal S stem (LPCI and Containnent determined that more (LPCI mode) is inoperable than one RHR pump (LPCI mode) or an access path of the is inoperable at a time when RHRS (LPCI mode) is inopera- operability is required or 'that ble, the reactor may remain one or both access paths of the in operation for a period RHRS (LPCI mode) are inoperable not to exceed 7 days pro- when access is required, the CSS vided the CSS and the die- and the diesel generators shall sel generators remain be demonstrated to be operable operable. immediately and daily thereafter until at least three RHR pumps (LPCI mode) and both access paths of the RHRS (LPCI mode) are returned to normal service.

5.. If one RHR pump (contain- 5. When it is determined that one ment cooling mode) or as- RHR pump (containment cooling sociated heat exchanger is mode) or associated heat inoperable, the reactor exchanger is inoperable at a may remain in operation for time when operability is re-a period not to exceed 30 quired, the remaining RHR days provided the remaining pumps (containment cooling mode),

RHR pumps (containment the associated heat exchangcrs cooling mode) and asso- 'and diesel generators, and all ciated heat exchangers and active components in the access diesel generators and all paths of the RHRS (containment access paths of the RHRS cooling mode) sh'all be demon-(containment cooling mode) strated to be operable immediately are operable. .and weekly thereafter until the inoperable RHR pump (containment cooling mode) and associated heat exchanger is returned to normal service.

6. If two RHR pumps (containment 6. When it is determined that two cooling mode) or associated RHR pumps (containment cooling heat exchangers are inopera- mode) or associated heat exchangers ble, the reactor may remain in operation for a period are inoperable at i time when operability is required, the not to exceed 7 days pro- remaining RHR pumps (containment vided the remaining RHR pumps cooling mode), the associated (containment cooling mode) heat exchangers, and diesel and associated heat exchangers generators, and all active com-and all access paths of t: he ponents in the access paths of RHRS (containment cooling mode) the RHRS (containment cooling 133

LDfITINC CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 4.5.8 Residual Heat Removal S stem

3. 5. 8 Residual Heat Removal S stem

~ ~

RHRS) (LPCI end Containment ~RHRS (LPCI and Containment 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 exchengers are returned 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 ench phase of the RHRS (containment cooling mode) mode (drywell sprays, sup- are inoperable when access is pression chamber sprays, required, all active components and suppression pool cooling) in the access paths of the RHRS are'ot operable, the unit (containment cooling mode) shall mey remain in operation for a bo demonstrated to be operable period not to exceed I days immediately and all active com-provided at least one path ponents in the access paths

'oreach phase of the mode 'which are not backed by a second remains operable. operable access path fax'he same phase of the mode (drywell sprays, suppression chamber sprays and suppression pool cooling) shall be'emonstrated to be opera-ble daily thereafter until the second path is returned to nor-

'al service.

8. If specifications 3.5,8.1 8. No additional surveillance through 3.5.8a7 are not met, required.

an orderly shutdown shall be initiated end the reactor shell be shutdown and placed 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 />.

9,'hen the reactor vessel pres- 9. When the reactor vessel pressure sure is atmospheric and irra- is atmosphexic, the RHR pumps diated fuel is in the reactor and valves that are required to vessel at least one RHR loop be operable shall be demonstrated with two pumps or two loops to be operable monthly.'

with one pump per loop shall be operable. The pumps'sso-ciated diesel generators must also bc operable.

10. If, the conditions of specifica- !

tion 3.5.A.5 are met, LPCI and containment cooling ere not required.

LIHITING CONDITIONS FOR OPERATION SURVEILLANCE RF. UIREMENTS

3. 5. 8 Residual Heat Removal S stem 4.5.B Residual Heat Removal S stem.

(Rllllg) (LPCZ nnd Containmont HRS) (LPCI and Cooling) Containment'ooling)

11. When there is irradiated fuel 10. The B, D RHR pumps on in the reactor and the reactor unit 2" which supply cross-connect vessel pressure is greater than capability shall bo demonstrated atmospheric, unit 2 RHR pumps to be oporablo monthly when the B, D with associated heat ex- cross-connect capability is changers and valves must required.

be oporablo and capable of supply ing cross-connect caoability oxcopt as specified in specifica-tion 3.5.8.11 below.

(Note: Because cross-connect capability is not a short term requirement, a component is not considered inoperable

'onnect if cross-capability ca'n be restored 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 RHk pump or associated ll. When it is determined that one heat exchanger located on the RHR pump or associated heat unit cross-connection in exchanger located on the unit unit 2 is inoporablo fox cross-connection in the adjacent any reason (including valve unit is inoperable at a time inoperability, pipe break, otc. ), when operability is required, tho roactor may remain in opera>> the remaining RHR pump and isso-tion for a period not to oxcood

'0 days provided the remaining ciated heat exchanger on the unit cross-connection and the asso-RHR pump and associated diesel ciated. diesel generator shall be generator are operable. demonstrated to be operable immediately and every 15 >days thereafter until the inoperable pump and associated heat exchanger are returned to normal service.

13. If RHR cross-connection flow 12. No additional surveillance or heat removal capabilit:y is required.

lost, the unit may remain in operation for a period not to exceed 10 days unless such capability is restored.

Limitin Conditions for eration Surveillance Re uirements 3.5.C RHR Service Water and.

.5.C RHR Service Water and. Emer enc' Emer enc ui~ment Coolin ui ment Coolin Water S stems Prior to reactor startup 10 ao Each of'he RHRSW pumps from a cold. condition, 9 normally assigned. to RHRSW pumps must be automatic service on the operable, with 7 pumps, EECW headers will be including Bl or B2, tested automatically assigned. to RHRSW service each time the diesel .r and 2 automatically generators are tested.;

starting pumps assigned. Each of- the RHRSW pumps to EECW service. 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.

Annually each RHRSW pump shall be flow-rate tested. To be considered operable, each pump shall pump at least 4500 gpm through its normally assigned flow path.

2. During reactor power op- 2e ao If no more than two RHRSW pumos eration, RHRSW pumps must are inoperable, increased.

be operable and assigned. surveillance is not to service as indicated. required..

below for the specified I time limits. b. When three RHRSW pumps are inoperable, the remairiing pumps, associated. essential T IME MINIlfUM control valves, and. asso-4 t,MIT SERVICE ASSIGNMENT ciated diesel generators (DAYS) RIjRSW EECW**

shall be operated. weekly.

Indefinite Ce When four RHRSW pumps are 30 7* or 6** 2* or 3*** inoperable, the remaining pumps, associated essential control valves, and. asso-ciated. diesel generators shall be operated. daily.

• At least one operable pump must be assigned to each header.

• ~Only automatically starting, pumps may be assigned to EECW header service.

• "'*Nine pumps must be operable. Either configuration is acceptable: 7 and 2 or 6 and 3.

336

Limiting Conditions for Operation ur'veillance Requirements 3.5.C RHR Service Water and. Service Water and.

Emer enc Eaui ment Coolin Emer enc E ui ment Coolin ater S stems

3. During power operation, Routine surveillance for tb.'se both RHRSW pumps Bl and pumps is specified. in'4.5.C.1.

B2 normal'Ly or alternately assigned. to the RHR heat exchanger header supplying the standby coolant supply connection must be operable; except as specified: in 3.5.C.4 below.

4. One of the B1 or B2 RHRSW When it Bl or B2 is determined that the .

is inoperable pumps may be inoperable RHRSW pump for a period. not to exceed. at a time when operability is 30 days provided. the required., the operable RHRSW pump operable pump is aligned. on the same header and. its to supply the RHR heat associated. diesel generator and.

exchanger header and. the the RHR heat exchanger header associated. diesel gen- and associated, essential control erator and. essential con- valves shall be demonstrated.

trol valves are operablei to be operable immediately ancL every 15 days thereafter.

5. If specifications 3.5.C.2 through 3.5.C.4 are not met, an orderly shutdown sha11 be initiated ancL the unit placed, in the cold shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

6. There shall be at least 2 RHRSW pumps, associated.

with the selected, RHR pumps, aligned. for RHR heat ex-changer service for each reactor vessel containing irradiated. fuel.

137

LIMITINC CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS .

3.5.9 E ui ment Area Coolers 4.5.D E ui ment Area Coolers 0 The equip~cut area cooler associated with each RHR

l. Each equipment area is coolers operated in con)unction pump and the equipment area with the, equipment served by cooler ass'ociatcd with each that particular cooler; set of core spray pumps (L therefore, the equipment area and C or B and D) must be coolers are teated at the operable at all times vhen "

same frequency ao the pumps

'the pump or pumpo served by vhich they serve.

that specific cooler is considered to be operable.

2. When an equipment area cooler is not operable, the pump(s) served by that cooler must be considered inoperable for Technical Specification pur-poses.

E. Hi h Pressure Coolant In ection E. Hi h Prcssure Coolant In ection S stem HPCIS

1. The HPCI sygtem shall be 1. HPCI Subsystem testing shall operable:

e be performed as follovs:

(1) prior to otartup from a a. Simulated Once/

Cold Condition; or ~

Automatic operating Actuation cycle (2) whenever there is irra- TeSt diated fuel in'he reac-tor vessel and the reactor b. Pump Opera- Once/

vessel pressure is greater bility month than 105 psig, except ao specified in. specifica- c.- Motor Operated Onc'/

tion 3.5.E.2. Valve Opera- month.

bility

d. - Flow Rate at Once/3

~ normal reactor months

'essel opera-ting pressure e., Plov Rate at Once/

150 psig operating cycle The HPCI pump shall deliver at least 5000 gpm during each flov tate test.

138

LXMITI'.lG CO'ADIT'LORS FOP. OPERATION SURVEILLANCE RE UIRRMENTS 3.5.E ~EI h Prcacurc Coolant In1attioc 4.5.E Ei h Praacura Coolant In~action

2. If the HPCI system, is inopera- 2. Mhen it is determined that ble, the rea'ctor may remain in the HPCIS is inoperable the operation for a period not to ADS actuation logic, the exceed 7 days, provided the RCICS, the RHRS (LPCI), and ADS; CSS, RHRS (LPCI), and the CSS shall be 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 order1y shutdown shall be initiated and the reactor vessel pressure shall be reduced to 105 psig or less within 24 hours.

F. Reactor Core Isolation Coolin F. Reactor Core Isolation Coolin 1, The RCIGS shall be. operable: 1. RCIC Subsystem testing shall be performed as follows:

(1) prior to startup from a "Cold'ondition; or a> Simulated Auto- Once/

matic Actuation operatirtg (2) whenever, there is irra- Test cycle diated fuel in the reac- /

tor vessel and the reac- b. Pump Operability .Once/

tor vessel pressure is month above 1DS psig, except as specified in 3.5.F.2. c. 'otor Operated, Once/

Valve Operability month

d. Flow Rate at , Once/3 normal reactor months

'essel operating.

pressure

e. Flow Rate at 150 Once/

psig operating cycle The RCIC pump shall deliver at least 600 gpm during each flow test.

139

LIHITIY(i COHO)TIOAS F()R OP),"RAT)()H S))RVEl ).I.ANC)'::R)."~lJIRF.if)'.NTS 3.5.F Reactor (:ore isolation'on~lin 4.5.F Reactor Core Isolation Coolin

2. IC thc RC)CS 3s inoperable, 2. When it is determined that the

~ thc reactor may remain in RCICS is inoperable, the HPCIS operation for a period not shall be demonstrated to be to exceed 7 days if the operable immediately and weekly HPCIS is operable during thereafter.

such time.

3. If specifications 3.5.F.1 or 3.5.F.2 are not mct, an orderly shutdown shall be initiated and the reactor shall bc depressurizcd to less than 105 psig within 24 hours.

C. Auccmacic Da~rassarisaciaa G. Automatic De ressurizat$ .on h.

1. Five of the six valves'f 1. During each operating cycle the hutomatic Dcpressuri- the following tests shall be zation System shall be ~ performed on the ADS:

operable:

, a. A simulated automatic (1) prior to a Ãtartup actuation test shall be from a Cold Condition, performed prior to startup or, after each refueling out-age. Manual surveillance (2) whenever there is irra- of the relief valves is

. diated fuel in the reac- covered, in 4.6.D.2..

tor vessel and the reactor vessel prcssure is greater than 105 psff' except As specified in 3.5.G.2 and 3.5.0.3 below.

2. If two ADS valves are known to be incapable of automatic

'. When ADS it is determined that two valves are incapable of operation, the reactor may automatic operation, the HPCIS remain in operation for a and the actuation logic of the period not to exceed 30 days, other ADS valves shall be demon-provided the ))PCI system is strated to be operable immediately operable. (Nnte that the and every 7 days thereafter as prcssure relief function of long as Specification 3.S.G.2 these valves is assured by applies.

section 3.G.)) nf these specifications and that thi>> specification only applies to the ADS function.)

140

LIMITING CONDITIONS FOR OPEPATION SURVEILLANCE RE UIRENENTS Autosetic De~ressurtzstiou

~Sstotn (*l>S) ~M 4.5.G Automatic Dc ressurization

3. If more than two ADS valves are 3. When it is determined that known to bc incapable of auto- more than two ADS valves are matic operation, 'thc reactor incapable of automatic opera-may remain in operation for a tion, the HPCIS shall be period not to exceed 7 days ~ shown" to. be ope'rable immess provided thc HPCI is diat'ely and daily thereafter operable. as'ong as 3.5.G.3 applies.

1 If specifications s

4. 3.5.G.2 and .3.5.G.3 cannot'e met, an orderly shutdown will be initiated an'd thc reactor vessel pressure sliall 'be reduced to 1O5 psig or less within 24 hours.

H. Maintenance of Filled Dischar e H. Wiintenance cif Filled Dischar e

~Pi c Whenever the core spray systems, LPCI, HPCI, or RCIC.are required to bc operable, the discharge piping from the pump discharge of these, systems to the '.last block valve shall bc filled.

'he ~Pi e ments.

following surveillance require-shall be adhered 'to to assure that the discharge piping of the

core RCIC spray systems,,

are filled:

LPCX, HPCI, and 141

LIMITINC CONDITIONS FOR OPERATION SURVFILLANCF. RE UIREMENTS 3.5.H Maintenance of Filled Dischar e Pi e 4.5.H Maintenance of Filled Dischar e Pi e suction of the RCIC and HPCI pumps The sha11 be aligned to the condensate l. Every month prior to the testing storage tank, and the pressure suppres- of the RHRS (LPCI and Containment-sion chamber head tank shall normally Spray) and core spray systems, the discharge piping of these systems be aligned.,to serve the discharge piping shall be v'ented from the high point of %he RHR and CS pumps. The condensate'ead and ~ater flow determined..

tank 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 pot been indicators on the discharge of the RHR required to be operable, th'e dis-and, CS pumps shall indicate not less charge piping of the inoper'able sys-than listed below.

tem shall be vented from the high Pl-75-20 48 psig point prior to the return of the Pl-75-4S 48 psig system to service. l Pl-74-51 48 psig Pl-74-65 48 psig 3. Whenever the HPCI or RCIC system is

~Avert e P'anat Linear Heat Ceneratien lined up to take suction from the Rate condensate storage tank, the dis-During steady state power operation, the charge piping of the HPCI and RCIC Maximum Average Planar Heat Generation shall be vented from the high point Rate (MAPLHGR) for each type of fuel as of the system and water flow observed a function'f average planar exposure on a monthly basis.

shall not,exceed the limiting value 4. When the'HRS and the CSS are re-shown in Figures 3.5.1.A and 3.5.1.B.

If at any time during steady state oper- quired,to be'perable, the pressure ation it is deterpined by normal sur- indicators which monitor the dis-veillance .that the limiting value for charge lines shall. be monitored MAPLHGR is being exceeded, action shall daily and the pressure recorded.

then be initiated to restore operation to within the prescribed limits. Sur-veillance and corres'ponding action shall continue until the prescribed limits are again being met. I Linear Heat Generation Rate (LHGR X, Maximum Ayers e Planar Linear Heat Genera-During steady state power operation, the tion Rate (MAPLHGR) i linear heat generation rate (LHGR) of The MAPLHGR for each type of fuel",as a.func-any rod in any fuel assembly at any axi tion of average planar exposure shall .,be location shall not exceed the maximum determined daily during reactor operation .

allowable LHGR as calculated by the fol- at > 25K rated thermal power.

lowing equation: i J. Linear Heat Generation Rate (LHGR)

LHGR < LHGRd[l QP/P) (L/LT)}]

Design LHGR 13.4 kW/ft.

The LHGR as a function of core height shall LHGRd .

be checked,.daily .during reactor operation at (AP/P) max Maximum power spiking pen- >.25X rated thermal'power. l I

0.021 LT ~ Total core length ~ 12.2 feet L ~ Axial position above bottom of core 142

LIMITING CONDITIONS FOR OPERAT ON SURVEILLANCE RF. VIRFMFNTS 3.5Q. Linear Heat Generation Rate (LHGR)

If at any time during steady state operation it is determined by nor-mal surveillance that the limiting value for LHGR is being exceeded, action shall be initiated to re-store operation to within the pre-scribed limits. Surveillance and corresponding action shall continue until the prescribed limits are again being met.

K. Minimum Critical Power Ratio MCPR Minimum Critical Power Ratio (MCPR)

During steady-state power operation, MCPR shall be > at rated power MCPR shall be determined daily and flow. For core flops other than during reactor power operation at rated the MCPR shall be > times > 25K rated thermal power and fol-Kf, where K 's as shown in Figure loving any change in power level or 3.5.2. ff at any time during steady distribution that would cause opera-state power operation it is determin-ed that the limiting value for MCPP.

tion with a limiting control rod pattern as described in'the bases for is being exceeded, action shall then Specification 3.3.

be initiated to restore operation within the prescribed limits. Sur-veillance and corresponding action shall continue until the prescribed limits are again being met.

L. Re ortin Re uirements If any 6f the limiting values identified in Specifications 3.5.I, J, or K are exceeded ther event"shall.be, logged and

'zeportedon a quar'terly basis.

142-a

C J ~ J H A!? 'L'.S

3. 5.A

?

?

Analyses presented in the FSAR and analyses presented in conformance with 10CFR50, appendix K, demonstrated.that the cope spray system provides adequate cooling to the core to di'ooipate the energy associated with the loss-of-coolant accident and to limit fuel clad temperature to belo'w 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 'n tests of syst:ems similar in design to BFNP to exceed the minimum reeuire-r)ents. In addition, cooling effectiveness has been demonstrated at less t:han half t.he rated flow, in simulated fuel assemblies with heater rods to duplicate the d cay heat characteristics of ir adiated fuel.

Vhc l<l)RS ().)'CI mode) is d>>oi),red tc provide cm>>rgcncy coolfng to the core by i3ooding in'tlie event of a loon-of-coolant accident. This system is comp)ctcly 'ndep>>ndent of the core spray system; however, it does function in combination wit)i the core spray system to prcvcnt excessive fuel clad temperature. T)ie LPCI mode of the RHRS and th>> core spray system provide

idequate coolinp for break areas of approximat>>i.y 0.2 square feet up to and including the double-endcd recirculation line break without assistance from t

he high-pressure emergency core cooling subsy. tems.

The intent of the CSS and R))RS specifications is to not allow startup from t: he cold condition wit)iout all associated equipment being operable.

oper at:ion certain components may be out of oervice fol thc speci f 'ed However,'uring allowable repiir times. The allowable repair times have bccn selected i:sin.-

erigincering fudgmcrrt based on exp riences and support:ed by availability analysis. Assurance of the availability of tne remaining systems is increased:

by demonstrating operability irrmediately and by requiring selected tasting during the outage period.

)

Should one core spray loop become inoperable, the remaining core spray loop, t)ie RHR system, and the diericl g".n>>rators are dcmonstratcd to be operable

,to noiire t)ieir availability ohould the need fo; core ccolinp arise.:-The.".c provide extensive margin over th>> operable cc uip;Ant needed for. adcqu;.tc cc' cooling. With due regard for this margin, the allowable repair time 'oi days wris chosen.  ?

Should one l<)l)'. pu"..ip ().PCI mode) become inoperable, a full complement of redun-dant core cooling equipm"nt is still availab3.>>. Because of the availability of a full co,.plcment of redundant core cooling equipment, wnich s demonstra-cc to be operable immediately and with opecified system surveillance, a 30-day repair period io )ustified.

Should more than one RHR pump (LPCI mode) or either of both access paths oi the RHR's~ (Ll'CI mode) become inoperable,'he CSS alone wou3.d provide adequate post accid>>nt: core cooling. Because the CSS iti demonstrated to be operable immediately and with specified suboequent performance, a 7-day repair t'r-'e .is

)ustified.

• A detailed functional analysis is given iri Section 6 of the BFNP FSAR.

14'

. S)iould one )tHR pump (contninmcnt. cooling rode) bccom~ inoperable, a com-p)emcnt of three full capacity rontniiuncnt heat removal systemo is still available. Any two oC the remaining pumps/hent exchanper combinations would provide morc than adequate containment cooling for any abnormal or post accident situation. Because of the avnilab'lity of equipment in access of normal redundancy requirements, which is demonstrated to be operable immediately and with specified subsequent performance, a 30-day repair period is )ustified.

Should two RllR pumps (containment coolinp mode) become inoperable, a full heat removal system io still available. 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 equipment, which is demonstrated to be operable immediately nnd with specified performance, a 7-dny repair period io )ustified.

(,boervntion of the stated requirements for the containment cooling mode assures that the suppression pool and the drywell will be sufficiently coolc d, following n loso-of-coolant accident, to prevent primary contain-.

ment. overpreoourizntion. The containment cooling function of the RHRS is permitted only after the core hno rcflooded to thc two-thirdo core height level. This prevents inadvertently diverting water needed for core flooding to the less urpent tnok of containment coolinp. The two-thirds core height level interlock may be manually bypaosed 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 cooli'ng 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 inability 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 nre leoo restrictive. At atmospheric pressure, the io for one supply of makeup water to the core. Requiring twominimum'equirement "operable RHR pumpo nnd one CSS pump provides redundancy to ensure makeup wa ter. avn ilab ili ty. I Should one RilR pump or <<ooocinted heat exchnnper located on the unit cross-connection in t)ic nd)ncent unit become inoperable, an equal capability for long-term fluid makeup to the reactor nnd for coolinp of the containment remains operable. Because of the availability of an equal makeup nnd cooling capability, which io demonstrated to be operable immediately nnd with speci-fied subsequent surveillance, n 30-dny repair period is )ustified.

144

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 water 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 (LPCX and, 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'maintenance 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.

~

]

144-a

3.5 BASES Should the. capability for providing flow through the cross-connect 'ines be lost, a ten day repair time is allowed before shutdown is required, This repair time is )ustified based on the very small probability for ever needing RHR pumps and hest exchangers to supply an ad5acent unit.>'EFERENCES

l. Residual Heat Removal System (BFNP FSAR subsection 4.8) 2; Core Standby Cooling Systems (BFNP FSAR Section 6) t ui ment Coolin 4

3.5,C R1IR Service Mater S stem and Fmer enc E Mater S stem,(EECMS)

There. are two FECM headers (north and south) with four automatic starting .

RURSW plumps on each header I I All components requiring emergency cooling 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'wo RHRSM'purIr can supply the full flow requirements of .all essential"EEC<f loads for any abnormal o~ postaccident situation.

There are four'HR heat exchanger headers (A, B, C, D) with one RHR heat exchanger from each unit on each header. There are two RHRSM pumps on each header; nn.. normally assigned to the header (A2, 92, C2, or D2) and one on alternate assignment (Al, B3., Cl, or Dl which are normally assigned to an EECM header). One RIIR heat exchanger header can adequately deliver t/ie flow supplied by both MIRSM pumps to any two of the three RHR heat.exchanjers on the header. One RHRSM pump can supply the full flow requirement of one RHR heat exchanger. Two RHR heat exchangers can moro than adequately handle the cooling requirements of one unit in any abnormal or postaccident situation.

The RHR Service Mater System was designed as a shared system for three units.

N The specification, as written, is conservative>>hen considera-tion is given to particular pumps being out of service and to possible valving arrangements. If 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 actuaX system cooling requirements can be assured.

I Should one of the two RHRSM 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 availability of an cqu,.l makeup and cooling capability which is demonstrated to be operable immediately and with specified subsequent surveillanc~, a 30-day repair pnriod is )ustified.

~ '

3.5 BASES There is an equipment area cooler for each RHR pump and an equipment area cooler for each eet (two pumps, either the A snd C or B and D pumps) of core spray pumps. The equipment area coolers take suction near the of the motor of the pump{e) served and discharge air near cooling'ir"'discharge air suet'ion of the motor of the pump(s) served. This ensures that 'the'ooling cool sir ie supplied for cooling the pump motors.

The equipment area coolers also remove the pump, and equipment waste heat fromm 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 operatiocis.

The surveillance snd testing of the equipment area coolers in each of their various modes is accomplished during the testing of the equipment served by these coolers. This testing is adequate to assure the operability of the equipment area coolers.

REPERENCES

1. Residual Heat Removal System (BPNP PSAR paragraphs 4.8.9.1 snd 4.8.9.2)

2. Core Standby Cooling System (BPNP PSAR .subsection 6.7) 1 3.i.q Hi h Pressure Coolant In ection S stem HPCIS The HPCIS is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the nuclear system and loss of coolant'which does not result in rapid depreesurization of the reactor vessel. The HPCIS permits the 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'r core spray system operation maintains core cooling.

The capacity of the system is selected to provide 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, the'eactor depressurises more rapidly than 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 depresiurization caused the break flow to decrease below the HPCI flow and the liquid inventory 146

3.5 HAS l'.S bcgfns to rise. This type ol response is typical of the small breaks. The core "never <<ncovero and is continuously cooled throughout thc transient

'no core damage of any kind occurs for breaks that lie within thc capa-so'hat city 'range of the HPCI.

1 The minimum-required NPSH for HPCI is 21 feet. There is adequate elevation head 'between the suppression pool and the HPCI pump, such that the required NPSH is available with a suppression pool temperature up to 140'F with no; containment back pressure.

The HPCIS serves as a backup to the RCICS as a source of feedwater makeup primary system isolation conditions. The AOS serves as a backup to~ 'uring the HPCIS for .rea'ctor depresourization for postulated transients and acci-dent.'oth these systems are checked for 'operability if the HPCI is deter-m'oned to be inoperable. Considering the redundant systems, an, allowable repair time of 7 days was selected.

The HPCl and RCIC as well as all other Core Standby Cooling Systems must be operable when starting up from a Cold Condition. It is realized that the HPCT 'io not designed to operate at full capacity until reactor pressure exceeds 150 poig and the steam supply to the HPCI turbine is before the reactor preosure decreases below 100 psig. It is the, automatically'solated intent of this specification to assure that when the reactor is being started up from a Cold Condition, the HPCI is not known to be inoperable.

3.5,F The various'onditions under which the RCICS plays an essential role in pro-viding makeup water to the reactor vessel have been identified by evaluating the various plant events over the full range of planned .operations. .The speci-fications ensure 'that the function for which the RCICS was designed will be avai].able when needed. The minimum required NPSH for RCIC is 20 feet.- There is adequate elevation head between the suppression pool and the RCIC'pump, such

=that the required NPSH io available with a suppression pool temperature up to 140'Flwith no containment back pressure, Because the low-pressure cooling systems (I.PCI and core spray) are capable of providing all the cooling-required for any plant event when nuclear system pressure is below 105 psig, the RCICS is not required below this pressure."

Between 105 psig and 150 psig the RCICS need not provide its design flow, abut reduced flow is required for certain events. RCICS design flow (600 gpm) is sufficient to maintain water level above the top of the active fuel for a com- .

plete loss of feedwater flow at design power (105 percent of rated).

I il Consideration of the availability of the RCICS reveals that the average risk assocfated with failure of the RCICS to cool the core when required is not increased if. the RCICS is inoperable for no longer than 7 days, provided that the llPCIS is operable during t'his period.

,I RFFERENCF.

1. Reactor Core Isolation Cooling System (BFNP FSAR subsection 4.7)

3. 5 l)AS),"S 3.5.G

~ ~ Aetcmattc De tessattzattce 3 stem (ADD)

This specification ensures the operability of the ADS under all condi-tions for which the depressurixation of the nuclear system is an essen-tial response to station abnormalities, The nuclear system pressure relief system provides automatic nuclear system depressurization for small breaks in the nuclear system so that, the low-pressure coolant injection (LPCI) and the core spray iubsystcms can operate to protect the fuel barrier. ,Note that this specification applies only to the automatic feature of the pressure relief system.

Spccif5cation 3.6.D specifies the requirements for the prcssure relief z

function of t)ie valves. It is possible for any numbor of the valves assigned to the ADS to be incapable of performing their ADS functions

)because of instrumentation failures yet be fully capable of, performing their'pressure relief. function.

'ecause the automatic depressurization system does not provide makeup to the reactor primary vessel, no credit is taken for the steam cooling of the core caused by the system actuation to provide further conservatism t . thc CSCS. Performance analysis of the automatic depressurisation sys-tem is consi<lered only with respect'o its depressurixinj effect in eon-

'unction with LPCI or core spray and is based on four valves. There are six valves connected to the ADS circuitry. Since credit was taken for nnly four in the performance evaluation of the ADS, it is appropriate that one'alve may be out indefinitely'without appreciably lowering the pro-bability that the system will perform satisfactorily.

Mf.th two valves known to be incapable of automatic operation (only one of these may be failed in a way that negates the pressure relief function as specif5.ed in specification 3.6.D) four valves remain operable to perform tlieir ADS function. ))owever, because of the difficulty in proving the operability of the ADS function (actuation of the ADS for testing would cause an unnecessary system blowdown), unit operation is only allowed to continue for 30 days'roviding the HPCI is demonstrated to be operable and" the actuation logic of the four remaining valves is demonstrated to be operable.

With more than two valves known to be incapable of performing their ADS 1

function, the ADS is assumed to be inoperable even though the relief valises (this applies to all of the relief valves not just those assigned to the ADS) may be manually operated (by switches in the control room) to accomplish system depressurisation. The allowable out-of-service time for more than two ADS valves is determined as 7 days because of the redundancy and because the HPCIS is demonstrated to be operable during this period.

Therefore, redundant protection for the core with a small break in the nuclear system is still available.

3. 5 BASE':S If the discharge piping of the core spray, LPCI, HPCIS, and RCICS are not filled, a water hammer can develop in this piping when the pump and/or pumps are started. To minimize damage to the discharge piping and to ensure added m'argin in the operation of these systems, this Technical Specification rcquircs the discharge lines to be. filled whenever the sy tern is in an operable condition. If a discharge pipe is not filled, the pumps that sup'ply that line must be assumed to be inoperable for Technical'pecification pur-poses.

The core spray and RllR 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. The visual checking will avoid starting the core spray or RilR system with a discharge line not filled. In addition to the visual observation and to ensure a filled discharge line other than prior to testing, a pressure suppression chamber head tank is located. approximately 20 feet above the discharge line highpoint to supply makeup water for these systems. The condensate head 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 pressure indicators are used to determine the water level above the discharge line high point. The indicators willreflect approximately 30 psig for a water level at the high point and. 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..

Mien in their normal standby condition, the suction for the llPCI and RCIC pumps are aligned tn the condensate storage tank, which is physically at a hil,her elevation than the llPCIS and RCICS piping. This assures that the tlPCI and RCIC discharge piping remains filled. Further assurance is provided by observinR water flow from these systems high points monthly. )

1 lfiximum )verage Planar Linear Heat Generation Rate (MAPLHGR) '.5.I.

This specification assures that the peak cladding temperature following the postulated design basis loss-of-coolant accident will not exceed the limit specified in the 10CFR50, Appendix K.

I 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 is only dependent second-arily on the rod to rod power distribution within an assembly. Since ex-pected local variations in power distribution within a fuel assembly affect the calculated peak clad temperature by less than .9- ?0 F relative to the peak temperature for a typical fuel design, the limit on t'e average linear heat generation rate is sufficient to assure that calculated temperatures are within the 10CFR50 Appendix K limit. The limiting value for MAPLHGR is shown in Figures 3.5.1-A and 3.5.1-B.

149

3.5.J. Linear Heat Generation Rate LHGR This specification assures that the linear heat generation rate in any rod i's less than the design linear heat generation if fuel pellet densification is postulated. The power spike penalty specified is based on the anal-ysis presented in Section 3.2.1 of Reference 1 ae modified in References 2 and 3, and assumes a linearly increasing variation in axial gaps be-tween core bottom and top, and assures with a 95/ confidence', that no more than one fuel rod exceeds the design linear. heat generation rate duc to power spiking. Thc LIIGR as a function of core height shall bc checked daily dur-ing reactor operation at > -25/ power to determine if fuel burnup; or con-trol rod movement has caused cha'nges in power distribution. Por L)IGR to be a limiting value below 25/ rated thermal power, thc HTPF, would have to be greater than 10 which is precluded by a considerable margin I when employing an~permissible control rod pattern.

3.5.K. Minimum Critical Power Raoio MCPR At core thermal power levels lese than or equal to 25X, the reactor will be operating at minimum recirculation pump speed and the moderator void content will be very small. Por all designated control rod patterns which may be em-ployed at this point, operating plant experience and thermal hydraulic anal yeis indicated that the resulting MCPR value is in excess of. requirements by a considerable margin. With this low void content, any inadvertent core flow increase would 'only place operation in a more conservative mode rela-tive to MCPR. The daily requirement for calculating MCPR above 25'ated thermal power is sufficient since power distr'ibution"shifts are very slow when there have not been significant power or control rod changes. The requirement" for calculating MCPR when a limiting control rod pattern. is approached ensures that MCPR will be known following"a change in power or power shape (regardless of magnitude) that could place operation at a thermal limit.

'3.5.L. Re ortin Re uirements The LCO's associated with monitoring the fuel rod operating 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.I,,J, and .K.

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 indicat'es that an operating lim-it has been reached. Each event involving steady state operation beyond a specified limit shall be logged and reported quarterly. 'It must be recognized that there is always an action which would-return any of the parameters (MAPLHGR, LHGR, or MCPR) to within prescribed limits, namely power reduction. Under most circumstances, this wi13, not be the only alternative.

References

1. "Fuel Densification Effects on General Electric Boiling Water Reactor Puel," Supplements 6, 7, and 8, NEW-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 GE Model for Puel Densification," Docket 50-321, March 27, 1974.

150

4.5 The'esting interval for the core and containment soling systems is based on industry practice, quantitative reliability analysis, Judgement and practicality. The core cooling systems have not been designed 'to be fully te'stable during operation. For example, in the case of the HPCE, automatic initiation during po~er operation would result in pumping c'old water into the reactor vessel which is not desir'able; Complete ADS testing .during power operation causes an undesirable'oss-of-coolant in'ventory. To increase tne availability of the core and containment cooling system, the components which make up the system; i.e., instrumentation, pumps, valves, etc., are teated 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 systems.

When components and subsystems are out>>of-service, overall coze and contain>>

ment cooling reliability is maintained by demonstrating the operability of the remaining equipment. The degree of operability to be demonstrated depends on the nature of the reason for the out-of-service equipment. For routine out-of-service periods caused by preventative maintenance; etc., the pump and valve operability checks will be performed to demonstrate operability of the remaining components. However,,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 to 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 CSCS systems or loops tha't 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 inoperable.

If the function, system, or. loop under test or calibration's 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 increased testing during equip-ment out-of-service times. This adds further conservatism and increases assurance that, adequate cooling is available should the need arise.

Maximum Avera e Planar LHGR LHGR and MCPR The MAPLHGR, I.HGR, and MCPR shall be checked daily to determine if fuel burnup, or control rod movemen't has caused changes ia power distribution. Since changes due 'to burnup aze slqw, and only a few control rods are moved daily, a daily check of power distribution is adequate.

'50-a

HAXIIHMAVERAGE PLANAR LINEAR HEAT GENERATION RATE (MAPLHGR)

VERSUS PLANAR AVERAGE EXPOSURE 12 11 ~ 8 11 '

J,l.6 11. 5 11 '

10 '

10.0 5,000 10,000 15,000 20,000 25,000 30,000 PLANAR AVERAGE EXPOSURE (NWD/0)

BROWNS FERRY NUCLEAR PLANT FINALSAFETY ANALYSIS REPORT FIGURE 3.5.1-A MAPLHGR VS'XPOSURE INITIAL CORE PUEL TYPE 2

MAXIM'VERAGEPLANAR LINEAR HEAT GENERATION RATE PIAPLHGR)

VERSUS PLANAR AVERAGE EXPOSURE 12 11 F 6 11.5 11.4 11.2 W

11 4 hl p

10 5 10 10 ~ 0 H

9 0 5,000 10,000 15,000 20,000 25,000 30,000 PLANAR AVERAGE EXPOSURE (MWD/0)

BROWNS FERRY NUCLEAR PLANT FINALSAFETY ANALYSIS REPORT 0 FIGURE 3 ~ 5 ~ 1-B MAPLHGR VS'XPOSURE 150-c INITGP COLS FUEL TYPE 1

BROWNS FERRY NUCLEAR PLANT F IG URE 3.5.2 Kf FACTOR AUTOMATlC FLOW CONTROL MANUAL FLOW CONTROL Scoop-Tube Set-Point Calibration position such that Flovrrnax -"102;S '/o 107.0 /

1'l2.0 /o 117.0 /

30 40 60 . 70 80 90 CORE FLOW,X

LIMITINC CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMERK'.6 PRIMARY SYSTEM BOUNDARY 4.6 PRIMARY SYSTEM BOUNDARY A licebilit ~Alicabil~it Applies.to the operating status Applies to the periodic examination of the reactor coolant system. and testing requirements for the reactor coolant system,

~cb ective ~cb ective To assure the integrity and safe To determine the condition of the operation of the reactor coolant reactor coolant system end the system. operation of the safety devices, related to't.

S ecificetion S ecificetion A. Thermal and Pressurization A. Thermal and Pressurization Limitations Limitations

1. The average rate of reactor 1, .During heatups end cooldowns, coolant temperature change the following parameters shell during normal heatup or be recorded end reector cool-cooldown shall not exceed ant temperature determined at 100'F/hr 'when averige'd over 15 minutes intervals until 3 a one>>hour period; successive readings at each given location are within 5'F.

a. Steam Dome Pressure (Convert to upper vessel re'gion temperature) b, Reactor bottom drain temperature

c. Recirculation loops A end

2. The reactor vessel shell be 2. Reactor vessel shell tempera-vented end power operation ture and reactor coo'lant shall not be conducted un- pressure shall be permanently less the reactor vessel logged at least every 15 temperature'ie equal to or minutes whenever the shell greater then that shown in temperature is below 220'F Figure 3.6.1. The reactor end the reactor vessel is

~

vessel shell not be pressuri- not vented.

zed above 250 psig unless the reactor vessel temperature is equal to or greeter than 1.85'F, when fuel is in the reactor vessel.

151

fTTINC CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS

.6.A Thermal and Pressurixation 4.6.A Thermal and Pressurixation Limitations Limitations

3. The reactor vessel head bolt- 3~ Test specimens of thc reactor ing studs shall not be under vessel base, weld and heat af<<

tension unless the temperature fected xone metal subjected to of the vessel head flange and the highest fluence of greater the head is greater then 100'F. than l Mev neutrons shall be installed in the reactor vessel adjacent to the vessel wall at

'the core midplane level. The specimens and sample program shall conform to the require-ments of AS' 185-66.

4. The pump in an idle recir'cula- 4~ Neutron flux wires shall be in-

~

tion loop shall not be started stalled in the reactor vessel unless the temperatures of the adjacent to 'the reactor vessel coolant within the idle and wall at the core midplane level, operatinp recirculation loops The wires shall be removed and are within 50'F of each'ther. tested during the first refuel-ing outage to experimentally verify the calculated values of integrated neutron flux that are used to determine the NDTT

.from Figure 3.6.1.

5. The reactor recirculation 5. When the reactor vessel head pumps shall not be started un- bolting studs are tensioned and lese the coolant. temperatures the reactor is in a Cold Condi-between the dome and .the 'bot- tion, the reactor, vessel shall tom head drain are within temperature immediately below 145'F. the head flange shall be per-manently recorded,

'6. Prior to and during startup of an idle recirculation loop, the temperature of the reactor cool-ant in the operating and idle loops shall be permanently logged.

Prior to starting a recircula-tion pump, the reactor coolant temperatures in the dome and in the bottom head drain shall be compared and permanently logged.

152

0 LIMITING CONnITlONS

~ FOR OPERATION SURVEILLANCE RE UIREMENTS 3.6.B

~ ~ C666616666I: Che66~tStr 6.6

1. Prior to startup and during l. A sample of reactor coolant

'he operation of the reactor shall be analyzed:

the following. limits shall apply: i. at least every 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> for conductivity and

a. Conductivity, chloride ion content.

.umhos/cm825'C.'.0

b. at least every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

b. Chloride, ppm'.2 during startups, until the reactor prcssure is 1000 psig, for conductivity and chloride ion content.

c. at least every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for conductivity and chloride ion content when the con-tinuous conductivity monitor is inoperable.

2. At reactor pressure of 1000 During equilibrium power ope'ration an isotopic analysis. including psig and above the reactor quantitative measurements for atI-13 water quality may exceed the least I-131, I-132, I>>133, and limits of Specification sha11 be performed monthly on a 3.6.B.l only for the'ime,. coolant liquid sample.

limits specified below.

Exceeding these time limits of 3. Additional coolant samples shall be the following maximum quality ~ taken whenever the reactor activity limits'hall bc cause for exceeds one percent of the equilib-placing the reactor in the rium'concentration sp'ecificd in cold shutdown conditiont 3.6,B.4 and one of the following

'onditions arc met:

a. Conductivity time above a. During startup 2 umho/cm(~25'C b. Following a significant power 4 weeks/year. change+*

Maximum l.imit c. Following an increase in the 10 pmhos/cm825'C equil'ibrium off-gas level exec ing 10,000 uci/sec (at the stc

b. Chlor lde concentration Set air e)ector) within a 48 time above 0.2 ppm- hour. period.

4 weeks/year. d. Whenever the equilibrium iodin Haximum I ppm.

Ltmit- lait specified in 3.6.B.4 is exceeded.

3. When the reactor is not pre- The additional coolant liquid surizcd, except during startup 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 /> thc reactor water shall be main>>

tnincd within the follow'ing

• For the purpose of this section on samplin; limits: frequency, a significant power exchange is defined as a change exceeding 15K of rated Conductivity, 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 />.

10 lwhoH/cm925'C Chloride, 0 ~ 5 ppm li3

t I>IMITING CONI) ITIONS FOR OPERATION SURVEILLANCE RE VIRESCENT

.'B. Coolant Chrmis~tr 4.6.8 Coolant Chemistr Whenever the reactor is critical, the limits on activity concentra- 'intervals for .48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, or until tions in the reactor coolant shall a stable iodine concentration not exceed the equilibrium value below the limiting value (3.2 pci/gm) of 3.2 pc/gm of dose equivalent* is established, However, at least I-131. 3 consecutive samples shall be This limit may be exceeded taken in all cases. An isotopic following power transients for a analysis shall be performed for each maximum of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. During this sample, and quantitative measurements activity transient the iodine con- made to. determine the dose equivalent centrations shall not exceed the I-131 concentration. If the total equilibrium values by a factor of iodine activity of the sample is below more than 10 whenever the reactor .032 pci/gm, an isotopic analysis to is critical. The reactor shall not determine equiv+ent I-131 is not be operated more than 5 percent of required.

its yearly" power operation under this exception for the equilibrium activity limits. If the iodine concentration in the coolant ex-ceeds the equilibrium limit by a factor of ten, the reactor shall be shut down and the steam line isolation vaives shall be closed immediately. C. Coolant Leaks e C.~ Coo lant Lea~ka,e l.~ Any time irradiated fuel is I. Reactor coolant syst'm leakage in the reactor vessel and shall-be checked by the sump reactor coolant temperature and air sampling system and ie above 212'F, reactor cool- recorded at least once per day.

ant leakage into the primary containment, from unidentified sources shall not exceed 5 gpm.

In addition, the total reactor coolant system leakage into the primary containment shall not exceed 25 gpm.

2. Both the sump and air sampling systems shall be operable dur-ing"reactor power operation.

From and after the date that one of these systems ie made or found to be inoperable for any

. reason, reactor power operation is permis'sible only during the succeeding seven days.

< That concentration of I-131 which alone'would produce the same thyroid dose as the quantity of total iodine actually present.

154

LIMITINC CONnXTIONS roR OPLPRATION SURVEILLANCE RE VIREHENT 4.6.C Coolant Leaka e

3. If the condition in 1 or 2 above cannot be met, an orderly shutdown shall be initiated

'and the reactor shall be shut-down in the Cold Condition within 24 hours. l. At least one safety valve and I approximately one-halE of all D. Safet and Relief Valves relief valves shall be bench-checked or replaced with a

1. When more than one valve, bench-checked valve each opera-safety or relief, is to ting cycle. All 13 valves (2 be failed, an known ordery shut- safety and ll relief) will have checked or replaced down shall be initiated and been upon the reactor depressurized to the comoletion of every second less than. 105 psig within 24 cycle.

hours.

2. Once during each operating cycle, each relief valve shall

. be manually opened until thermo-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 disassembled and inspected each operating cycle.

~Jet'dw s E.'Jet Pum s

1. Whenever the reactor is in the l. Whenever there is recirculation startup or run modes, all'get flow with the reactor in the pumps shall be operable. If startup or run modes with both it is determined that a )et 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 be initiated and the a. The two recirculation loops reactor shall be shutdown in have, a flow imbhlance of the Cold Condition within 24 15K or more when the pumps hours. are operated at the same speed.

'55

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RF. VIREMENT 1.6.Y

~ ~ ~Jet Pue s 4.6.E ~Jet Pum s

b. The indicated value of core flow rate varies from the value derived from loop flov measurements by more than 10X.

c. The diffuser to lower plenum differential pressure read-ing on an individual get pump varies from the mean of all 5et pump differen-tial pressures by more than 10X.

2. Whenever there is recirculation flov, vith the reactor in the Startup or Run Mode and one re-circulation pump is operating vith the equalizer valve closed, the diffuser to lower plenum differential pressure shall be checked daily and the differen-

~

tial pressure of an individual

)et pump in a loop shall not vary from the mean of all )et pump differential pressures in that loop .by more than 10X.

F. Jet Pum Flow Mismatch P. Jet Pum Flow Mismatch

1. When both recirculation pumps are in steady state operation,

'. Recirculation be checked,and pump speeds shall logged at least the speed of the faster pump once per day..

may not exceed 122X the speed of the slover pump vhen core pover is 80Z or more of rated power or 135Z the speed of the slover pump when core pover is belov 80X of rated power.

2. Folloving one-pump operation, the discharge valve of the low speed pump raay not be opened unless the speed of 'the faster pump is less than 50X of its rated speed.

G. Structural Inte rit G. Structural Inte rit 1.

~ The structural integrity of 1. Table 4.6.A together with sup-the primary system shall be plementary notes, specifies the 156

)hl I':r<O CONnlTIOhS F<)R i)Pl:.RATION Sl)RYEILLANCE RE UIR&fFNTS 3.6,G .'>t ructural 1l)t.e~ri~t 4.6.G Structural Inte rit maintained at the level re- inservice inspection surveil-quired by thc original accep- lance requirements of the reac-tznCc s tandards throughout tor coolant system as follows:

the life 'of the plant. The reactor shall be maintained a. areas to bc inspected in a cold shutdown condition until each indication 'nf" a b. percent of areas to be defect hna l>cen investigated inspected during, the and evaluated. inspection interval

c. inspection frequency

d. methods used for inspection

2. Evaluation of inservice inspec-tions will be >unde to the accep-tance standards specified for the original equipment.

3. The inspe.ction interval shall be 10 years.

4. Additional inspections shall be performed on certain circumferen-tial pipe welds as listed to pro-vide additional protection against pipe whip, which could damage auxiliary and control sys-tems.

Fcedwater GFW-9, KFW-13 GFW-12, G~-26, KFW-31) GFW-29, KFW-39, GFW-15, KFW-38, and GFW-32 Main steam GMS-6, KMS-24, GMS-32, KHS>>104 GMS-15, and GMS-24 RHR DSRHR- 6, DSRHR-7, and DSRHR-4 Core Spray DSCS-12, DSCS-11, DSCS-5, and DSCS-4

~WWg~g~WP~~

S LEMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.6.G Structural Inte rit 4.6.G Structural Inte rit Reactor Cleanup - DSRWC-4, DSRWC-3, DSRWC-6, and DSRMC-5 HPCZ Unit 3 THPCI-70 THPCI-70A THPCI-71, and THPCI-72

5. System hydrostatic tests in accordance with,Article IS-500 oi Section XI of the ASNE Code will be performed at or near the end of each inspection interval; REFERENCE

1. Plant Safety Analysis (BFNP.

FSAR subsection 4.12)

LfNITING CO'NMTION 'FOR OPERATION 3'.6,8 H draulic 'Snubbers 4.6.H H draulic Snubbers

1. During all modes of operation 'The following surveillance requirements except Cold Shutdown and Refuel, apply to all hydraulic snubbers all hydraulic snubbers shall be listed in 3.6.8.2.

operable except as noted in 3.6.8~.2 through 3.6.H.5 below. 1 A11 hydraulic snubbers whose seal-material has been demonstrated by

'2. The hydraulic snubbers listed operating experience, lab testing in Table 3.6.8 are required to or analysis to be compatible protect the primary coolant with the operating enviror~ent system or other safety related shall be visually inspected to systems or components and are verify their operability in therefor'e subject to these accordance with the fo'lowing specifications. schedule:

3. From and'fter the time that a Number of Snubbers Next Required hydraulic snubber is determined Found Inoperable Inspection to be inoperable, During Inspection Interval operation is'ermissible or During Inspection continued'eactor only during tne succeeding 72 Interval hours unless the snubber is sooner made operable, Less than 27. Operating Cycle +25/

27, to 5% 12 months +25 %

4. If the requirements of 3.6.H. 1 be met, an 57, to 10%

107, to 15%

~

6 months*+25%

124 days +25%

and 3,6.H.3 cannot orderly shutdown shall be initiated 15/ to 20% 62 days ~25%

and the reactor shall be in a Grea ter than 20% 31 days +25%

cold 'shutdown condition within 36 hours.

If a,hydraulic h

5. snubber is determined to be inoperable while tne reactor is in the shutdown or refuel mode, Snubbers may be categorized in the snubber shall be made operable two groups, "accessible" or prior to reactor startup. "inaccessible" based on their accessibility for inspection during reactor operation. These two groups may be inspected independently according to-the above schedule.

2. All hydraulic snubbers whose seal materials have not been certified by the snubber manufacturer to be compatible witn the operating environment shall be 'visually inspected for operability every 31 days.

158a

à LIMITING CONDITION FOR OPERATION SURVEILLANCE RE UIREMENT 4.6.H H draulic Snubbers (cont'd)

3. The initial inspection shall be performed within 6 months from the date of issuance of these speci-fications. For the purpose of entering the schedule in Specification 4.6.H.1, it shall be assumed Shat the facility had been on a 6 month inspection interval.

4. Once each refueling cycle, a representative sample of 5 snubbers or approx-imately 5% of the snubbers, whichever is less, shall be functionally tested for op'erability including veri-fication of proper piston movement, lock up and bleed.

.For each unit and subse-quent unit found inoperable, an additional 5% or five snubbers shall be so tested until no more failures are found or all units have been tested.

5. Once each refueling cycle at least two representative snubbers from a relatively severe environment shall be completely disassembled and examined for damage and abnormal seal degradation.

158b

RWSlR EMORY waar

~SM as H~W~ W

~

RL

~mar ar.aaraa

~858%

%%M%

fa

~

8 R I

l Table 4.6.A REACTOR,COOLANT SYSTEM INSERVICE INSPECTION SCHEDULE AREAS OF INTR%ST ACCESS X INSP. IN INSP. INTERVAL ~ttUENCY A. Reactor Vessel

1. Longi.tudinal and Those weids above 10X of accessible longitudinal Code (1) Volumetri.c circumferential sacrificial shield and velds outside core all in closure head 5X of accessible circumferential region and in ves- are accessible from sel head vessel o.d.

2. Vessel-to-flange Prom flange surface 100X Code (2) Volumetric circumferential veld Head-to-flange Prom o.d. of head 100X Code (2) Volumetric o'a circumferential veld O

3. Primary nozzle-to- -

All nozzles 4 inches 100X velds Code (2) vessel velds and and greater vill be nozzle-to-vessel in- accessible from vessel side radii o.d. Inside radii at the 6 and 12 Code (2) Volumetric o'lock positions 3a. CRD housing- to-stub During refueling from 100Z At time of Visual tube and stub tube- CRD area for signs of system hydro-to-vessel velds and leakage ~ Stat incore penetration

4. Primary nozzles to All nozzles 4 inches 100X Code (2) Visual, surface safe-end Dissimilar and larger vill be and volumetric Hetal velds accessible

5. Closure studs and Studs in place, nuts 100X Code (2) Visual, surface.

nuts on removal and volumetric

T ble 4.6.A REACTOR COOLANT SYSTEH INSERVICE INSPECTION SCHEDULE (Continued)

AREAS OP INTEREST . ACCESS INSP. IN INSP. INTiRVAL PRE ENCY HETSOD

6. Closure washers, On remova1 100X Code (2) Visual Bushings In place, when studs When made accessible Visual are removed

7. Integrally ~elded Two sections 2 feet -One foot minimum length Code (2) Volumetric vessel supports long each, 18'part, 180'part two spots accessible in support skirt to vessel weld

8. Vessel cladding During refueling 6 prede)ermined patches Code (2) Visual vessel i.d. (36 in. each)

9. Vessel internals Accessible areas Accessible. areas First refuel- Visual and integrally during normal re- ing and every welded internal fueling third refueling supports thereafter

.10. Vessel flange- During refueling 100X Code (2) Volumetric ligaments between threaded stud. holes B. Pi in Pressure Bounds

1. Vessel, pump, and From pipe o.d. 100X Code (2) Visual and surfac valve safe ends-to- and volumetric primary pipe dissimilar metal welds and safe ends in.branch piping

<<elds 4 inches and larger

Table 4.6.A REACTOR COOLANT .SYSTEM INSERVICE INSPECTION SCHEDULE (Continued)

AREAS OF INTEREST ACCESS Z INSP. IN INSP. INTVZifAL ~FRE UEMCY METHOD

2. Circumferential and Removable insulation 25X of circumferential velds Code (2) Visual and longitudinal pipe plus l 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 4.6.0.4 of Technical volumetric pipe vhip 'pecifications protection

3. Pressure-retaining 2 inches and larger LOOZ Code (1) Visual and boLting volumetric Bolting under 2 LOOZ Signs of inches on piping 4 Leatmge dur- Visual inches and over ing normaL maintenance

4. Piping supports and hangers (a) IntegralLy Scaffolding as 100X visual, Code (2) Visual and velded required 25X Vol. (if suitable geometry) volumetric (b) Nonintegrally Scaffolding as 100X Code (2) Visual velded supports required Pressure Bounda

1. Pump casing Pump dary pressure boun-interior Prom pump i;d. only vhen maintenance One pump velds vith or vithout if disassembled Code if (1) 'isual disassembled

-requires-rival of internals

Table 4.6.A REACTOR COOLAÃT SYSTEM INSERVICE INSPECTION SCHEDULE (Continued)

AREAS OF INTEREST ACCESS X INSP. IN INSP. INTERVAL FRE iJENCY NETEOD

2. Pressure-retaining 2 inches and larger, '100X Code- (1) Visual and bolting volumetric Bolting under 2 100Z Signs of Visual inches leakage dur-ing normal maintenance outage

3. Supports

a. Integrally Scaffolding as 25Z Code (2} Visual and welded required volumetric

b. Nonintegrally Scaffolding as - 100Z Code (2) Visual welded required

4. Notable-to-safe end Removable insulation 100Z Code (2) Visual and dissimilar metal welds volumetric D. Valve Pressure Bounda

1. Valve body .seam Pron valve o.d. 100Z Code (1) Visual and welds volumetric Valve pressure boun- Prom valve i.d. only One valve with or without. . Code (1) Visual dary interior when maintenance welds if disassembled if disassembled requires removal of internals

2. Valve-to-safe end Removal insulation 10OZ Code (2) Visual and disshailar cmta1 volumetric welds

Table 4.6.A REACTOR COOLA.'YT SYSTBf INSERVIC:. INSPECTION SCHEDLLE (Continued)

AREAS OF INTEREST ACCESS X INSP. IN INSP. INTERVAL ~PRE UEÃCY NETHOD

3. Pressure-retaining 2 inches-and larger 100X Code (1) Visual and bolting volumetric Bolting under 2 inches 100X Signs of Visual leakage during nor-mal maintenance outage

4. Supports and hangers-

a. Integrally Scaf folding as 25X Vol. (if suitable geometry) Code (2) Visual and welded required 100X visual volumetric

b. Nonintegrally Scaffolding as 100X Code (2) Visual welded required

Table 4.6.A REACTOR COOLANT SYSTEM INSERVICE INSPECTION SCHWA)ULE (Continued)

Inspec tion- Prequency:

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-third of the inspection interval has expired (vith 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 (~ith credit for no more than 66-2/3X). The remainder shall be completed by the end of the inspection interval..

t H TABID 3 beH

.~B~S (tHICH P>- I;lACCZSSIBL-'IRE;1G RFJCTOB OP;.='t.

~

~Sstem OI,'rrestor Elevation t'lo.

58o SSA1 .

Main stea~ A 58o SSA2 Vain steau A 58o SSB1 Y~in ste "~ B 58o SSB2 V~ain ate~a B 580 SSB4 hhin stean B 58o SSB5 h'"in stea-.. B 58o ssB6 Yogin stem B 58o Yogin

" em' SSC1 58o SSC2 hhin s eon C 58o ssc4 hhin steam C 58o SSC5 Yogin steve C 58o ssc6 hain stem C 58o SSD1 Nakn stem D ~

58o SSD2 hain stea~ D 58o SSA1 $'ee":;ater A Fee"~'ater A 58o SSA2 58o SSA3 Feedwater A 58o SSA4 Feec uter A Feed"a e A 58o SSA5 580 SSA6 Feed"a er A i<mt A 58o SSA7 Fe Feed~.at r A 58o SSA8 (north) 58o SSAO (south) Feedi'ater A Fee";ater B 58o SSB1 SSB2 Feed:.eat " 3 58o Feed~"= er B 580 SSB3 58o ssB4 Feei'.zter B Feed";ater 9 58o SSB5 58o SSB6 Feed~ater B Feed-.:ater B 58o SSB7 58o SSBB Feed;.:ater B Feedvater B 58o SFi)o 636 R-72 RHR heac spray RE head spray 636 R-73 (east) 636 R-73 (-~est) BE heac spray RE head spray 636 R-73 (top) 636 R-73 (hottoa) HE heai spray 636 RHR nead spray R-75 6o3.

R-1 Control rod drive Contrcl rod drive 6o3 R-2 598 R-1 Core spray Core spray 598 R-2 598 R-8 Core sp av 5n8 R-9 Core spray Stand'ay licuid control 624 R-lo 563 R-6 HPCI .

RCIC 565 Rn (north) 565 RCIC R-P (south) 165 a

TABLE 3.6.H

, Arrestor 1lo. ~Stem Elevate.on R-67, RHR 58o

~ R-67 R-69 Ssl-A RHR RHR Recirculation 58o 58o 556 SS1-B Recirculation 556 SS2-A Recirculation ~

558 SS2-B Recirculation 558 SS3-A (295 ) Recircula ion 564 SS3-A (335') Recirculation 564 SS3<<B (115') Recirculation 564 SS3-3 (F54 ) Recirculation 564 SS4-A Recirculation 570 SS4-3 Recirculation 570 SS5-A (265') Recirculation 581 SS5-A (325 ) Recirculation 581 SS5-3 (35 ) Recirculation 581 SS5-B (1OO') Recirculat on 581 SS6-A Recirculation 568 SS6-B Recirculation 568 SS7 Recirculation 564 ss8 Recirculation 564 SS9-A Recirculation 559 SS9-B Recirculation 559 Ul!IT 3 S!'.U33;.a" ':iHICH ARK ACCT:SIBL.

DURDE" R.".ACr08 CP

~'.TICe'Setem Arrestor Iio. Elevation R-6 (north) Core spray 598 R-6 (south) Core spray 598 R-13 (north) Core spray 543 R-13 (south) Core spray 543 R-21 R-3 (top)

Standbv HPCI li nui6 control 624.

543 R-3 (cottom) HPCX R-4 (north) HPCI 538 R-4 (south) HPCI 538 R-12 HPCI 538 R<<19 HPCI 555 R-20 HPCX 555 R-4 (north) RCIC 519 R-4 (south) RCIC 519 R-5 (south) RCIC 53o R-5 (east ) RCIC 539 R-7 (upper) RCIC 555 R-7 (lo. r) RCXC 555 R-1 (upper) Con<1cnsate Si'S 555 R-1 (lo~'er) Con~ensate GZB 555 R-2 (left Co:vlcnsate SV 555

Arrestor 't'Jo. ~Sstem . Elevation R-2 (right) Condensate'88 555 R-3 (le~) Condensate SEB 555 R-3 (right) Condensate G&S 555 R-4 (le~) Condensate SBS 555 R-4 (right) Condensate SEB 555 B-5 (unper) Condensate S89 555 R-5 (lover) Condensate SFS 555 SS1-Z PSC (ring header) 525 SS2-X PSC (ring header) 525.

SS3-X PSC (ring header) 525'25 ss4-z PSC (ring header)

SS5-Z PSC (rin~ header) 525 ss6-x PSC (ring hea" r) 525 SS7-X PSC (rin- heaaer) 525 ss8-z PSC (ring he der) 525 Sslz-A PSC (rin; header) 525 SS2K-A PSC (ring header) 525 SS3X-A ~ PSC (ring header} 525 SS4Z-A PSC (ring heade") 525 SS5Z-A PSC (ring header) 525 SS6X-A PSC (ring header) 525 R-4 R-10 'HBHR 56o 56o R-12 (upper) BHR 555 R-12 (lo-;~er) EHH 555

'B 20 (up"..cr) RK~ 56o R-20 (lo"er) BHR 56o R-.41 (ou s de) BFB 56o R<<41 (inside) BK~ 56o R-51 (no-'th) RFZ 535 R-51 (south) RIP. 535 R-52 (~iTc st ), RHR 550 R-52 (north) BFP 550 R-53 (e st) RW 535 R-53 (north) RHR 535 RM 535 R-55 RrE 535 R-56 BHR 535 R-57 (vest) RIB 535 R-57 (eas ) R3B 535 R 58 (north)

R-58 (south) RfB 575 p 5n RHE 564 R-6o (vest) RW< 565 R-60 (cast) EQB 565 (lover) 5o6 R-61 (uuver) RHR 5c6 R-62 (north) RlR. 5g6 165 c

TABIZ 3' Arrester Fo. ~Stem Elevaticn R-62 (south) RHR 596 R-62 RHR 596 R-64 (eest) FAR 565 R-64 (vest) RHR 565 R-77 RHR 580 R-1 (upper) RBCCtV 615 R-l (lo.rer) RBCCt,r 6l5 R-2 (up er) RBCCN 615 R-3 (upper) RBCCW 6'15 a-3 (lover). RBCViT R-a (upper) RBCCtf 6l5 165 g

3.6/4.6 BASES:

3.6.A/4.6.A Thermal and Pressoriaaeion Limitations The requirement for the reactor vessel have been identified by evaluating the need for its integrity over the fulL spectrum of plant conditions and events.

As described in paragraph 4.2.5 of the safety analysis report, detailed stress analyses have been made on the reactor vessel for both steady-state and transient conditions with respect to material fatigue. The resul'ts of these analyses are compared 'to allowable stress limits The ~

specific conditions analyzed included a maximum of 238 cycles of normal startup and shutdown (a heatup is considered one cycle and cooldown is another cycle) with a heating and cooling rate of 100'F per hour applies continuously over a temperature range of 100'F to 546'F. 'he expected num-ber of normal heatup and cooldown cycles to which the vessel will be sub-

)ected is 80.

The reactor vessel is constructed such that its initial maximum nil-ductility transition temperature is not greater than 40'F, as cited in paragraph 4.2.7 of the safety analysis report. As prescribed by the ASME Code, the reactor vessel shall not be pressurized at a temperature less than 60'F above the NDTT. Thus, the initial minimum pressurization tern-perature is 100'F.. As the total integrated neutron exposure increases with time, the NDTT increases and the minimum pressurization temperature increases correspondingly as represented in Figure 3.6.1.

Current NRC bases dictate that the vessel pressure should be limited below 250 psig when the vessel temperature is below 185'F. Other investigators indicate that this limit is unnecessarily conservative. This matter is under technical review by the applicable code committees. Based upon the results of this review and the accumulation of additional specific data,.

the applicant may ask for a revision to this limit in the'.future. This limit is reflected as the upper line on Figure 3.6.1.

The maximum calculated, neutron fluence of 1 mev or greater, based on 100 percent ~yted power and 100 percent availability for 40 years, is 3.8 x 10 nvt. The neutron flux wires are removed and tested during the first .refueling outage to experimentally verify the calculated values of integrated neutron flux. The first refueling period wi/) occur well before the elapsed time necessary .to yield a fluence of 1 x 10 nvt, a fluence level still below that necessary to show a NDTT shift. The NDTT is determined from Figure 3.6.1 of the safety analysis report by utilizing the value of the fluence measured at the core midplane level. This approach is conservative, since the fluence level decreases as the point of measure-ment is removed from the core midplane level.

Tightening the studs on the reactor vessel head flexes it slightly to bring together the entire contract surfaces adjacent to the "0" rings of the head and vessel flange. The reactor vessel head flange and head are constructed such that their initial maximum NDTT is 10'F, as cited in paragraph 4.2.7 of the safety analysis report. Therefore, the initial minimum temperature at 166

which the studs can be placed in tension is established at 40'F + 60'F or 100'F. Since the total integrated neutron flux in the head flange rggion wil) be less than that at the core midplane level by a factor of 10 or 10 , the may)mum calculated fluence in the head flange region will be 1 x 10 nvt. With such'e low total integrated neutron flux in the fax'elow heed flange region, there vill be no detectable or significant NDTT shift, and the minimum stud tightening temperature remains at 100'F.

As described in paragraph 4.2.5 of the safety analysis report, detailed stress analyses have been made on the reactor vessel for both steady>>

state and transient conditi.ous vith respect to material fetigure. The of these analyses are compared to allovable stress limits. 'esults Requiring the coolant temperature in an idle recirculation loop to be within 50'F of the operating loop temperature before a recirculation pump is started assures that the changes in coolant temperature at the reactor vessel nozzles and bottom head region ere acceptable.

The coolant in the bottom of the vessel is at a lower temperature than that in the upper regions of the vessel vhen there is no recirculation flow.

This colder water is forced up when recirculation pumps are started. This vill not result in stresses which exceed ASME Boiler and Pressure Vessel Code,Section III limits- when the temperature differential is not greater than 145'F.

Neutron flux vireo and samples of vessel material are installed in the reactor. vessel ad]acent to the vessel vail at the core midplene level. The wires and samples will be removed and tested to experimentally verify the values used for Figure 3.6.1.

REFERENCES

l. Re'actor Vessel and Appurtenance Mechanical Design (BFNP FSAR Subsection 4.2) 2, ASME Boiler and Pressure Vessel Code, Section III

3. USAS Piping Code, Piping Code, Section B.31.1 3.6.8/4.6;B Coolant Chemistr Materials in the primary system are primarily 304 stainless steel and the Zircaloy cladding. The reactor water chemistry limits are established to prevent. dnmege to these materials. Limits are placed on conductivity and chloride concentrations. Conductivity is limited becauue it is continuously measured and gives an indication of abnormal conditions and the presence .of unusual materials in the coolant. Chloride. limits are specified to prevent stress corrosion cracking of stainless steel. According to teet data, l67

3.6/4.6 OASES:

allowable chloride concentrations could be set several orders of magnitude above the established limit at the oxygen concentration'(.2-,3 ppm) experienced during power operation without causing significant failures.

Figure 3.6.2 illustrates the results of tests on stressed 304 stainless steel specimens. Failures occurred at concentrations above the curve; no failures occurred at concentrations below the curve. Zircaloy does not exhibit similar stress corrosion failures.: However, there are some opera-ting conditions under which the dissolved oxygen content of the xeactor coolant water could be higher than .2-.3 ppm, such as reactor startup and hot standby. During these periods, the most restrictive limits for conduc-tivity and chlorides have been established. When reactor pressure reaches 1000 psig, 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 impuri-ties affectinp 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, high conductivity alone is not a cause for shut-down. In some types of water-cooled reactors, conductivities are in fact high duc to purposeful addition of additives. In the case of BWR's, however, where no additives are used and where near neutral pH's maintained, conduc-tivity prouides a very good measure of the quality of the reactor water.

Significant changes therein provide the operator with a warning mechanism so he can investi'gage and remedy the condition causing the change before limit-ing conditions, with respect to variables affecting the boundaries of the reactor coolant, are exceeded. Nethods available to the operator for correcting the off-standard condition include operation of the reactor cleanup

'ystem, reducing the input of impurities and placing the reactor in the cold shutdown condition. The ma)or benefit of cold shutdown is to reduce the temperature dependent corrosion rates and provide time for the cleanup .system to re-establish the purity of the reactor coolant.

The conductivity of 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 impurities will also be within their nor-mal 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. Daily sampling is performed when increased chloride concentrations are most probable. Reactor coolant sampling is increased to once per shift when the continuous conduc-tivity monitor is unavailable.

168

3. 6/4. 6 BASF.S:

Thc. basis for the equilibrium coolant iodine activity limit ~s a computecl dose to the thyroid of 30 rem at the exclusion distance during the 2-hour period following a stcam line break. This dose is computed with the conservative assumption of a release of )40,000 lbs of coolant prior to closure of the isolation valves, and a X/Q value of 2.9 x 10-4 Scc/m3.

The maximum activity limit. during a short term transient is established from consideration of a maximum iodine inhalation dose less than 300 rem.

Thc jrobnbility of a stea~r, line break accident coincident with an iodine concentrnLion transient is 'significantly lover than that of the accident alone, since operaLion of the reactor with iodine levels above the equilibrium value is limited to 5 percent of total operation, Thc: sampling Erc.quencies are established in order to detect the occurrence of nn iodine transient which may exceed the equilibrium concentration limiL, nud to assure Lhat the maximum coolant iodine conccntr~Lions nrc not exceeded.

conccntrnLt.ons Additional sampling is required foll.owing power changes nnd off-gas transients, since present data indicate that. the iodine peaking phenomenon is related to these: c! nts.

Allowable leakage rates of coolant from the reactor coolant system have been based on the predicted and experimentally observed behavior of cracks in pipes nnd on the ability to makeup'oolant system leakage in the event of loss of offsite a-c power. The normally expected background 1eakage due to equipment design nnd the detection capability for determining coolant sys-tem leakage were also considered in establishing the limits. The behavior of cracks in pkping systems hns been experimentally and analytically inves-tigated as pnrt: of the lJSARC sponsored Reactor Primary Coolant System Rupture Study {the Pipe Rupture Study). Work utilizing the data obtained in this study indicates that leakage from n crack can be detected before the crack grows to n dangerous or critical size by mechanically or thermally induced cyclic loading, or stress corrosion cracking 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 probnbi1ity is small that imperfections or cracks associated with such leak-age would grow rapidly. However, the establishment of allowable unidentified leakage greater than that given in 3.6.C on the basis of the data presently available would he premature because of uncertainties associated with the dntn. For leakage of the order of 5 gpm, as specified in 3.6.C, the experi-mental and nnnlytical data suggest a reasonable margin of safety that such leakage magnitude would not result from a crack approaching the critical size for rapid propagation.'eakage less than the magnitude specified can"'be

dct<<ct<<d reasonably ln a matter of few hours uti3l <it@ the available leakage detection schemes, and if the origin cannot be determined in'a reasonably short time the unit'hould be shut down to allow further investigation and corrective action.

The total leakage rate consists of all leakage, identified and unidenti-fied, which flows to the drywell floor drairi and equipment drain sumps.

The capacity of the drywell floor sump pump is 50 gpm and the capacity of tlie drywell equipment sump pump is also 50 gpm. Removal of 25 gpm from either of these sumps can be accomplished with considerable margin.

REF F.R I'.N C t'.S

l. Nuclear System Leakage Rate L5.mits (BFNP FSAR Subsection 4.10) 3.6.1)/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 thc 'core spray system is not designed to deliver full flow. The pressure relief system for each unit at the Browns Ferry Nuclear Plant 'hiia been sized to meet two design bases. First, the total safety/relief valve capacity has .been established to meet the overpressure protection crit cria of the hSME 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.

Thirteen safety/relief valves have been installed on each unit with a total capacity, of 74X of design steam flow. The total safety/relief capacity of 74% Iias been divided'nto 61%'elief (11 valves) and 13%

safety (2 valves).

170

Experience in relief and safety'alve operation shows that a testing of 50 percent of the valves per year is adequate to detect failures or dcteriorations. Thc relief and safety valves are benchtested every eeco>>d operating cycle to ensure that their set points are within the

+ 1 percent tolerance. The relief valves are tested in place once per operating cycle to establish that they vill open and pass steam.

The rcquircments established above apply when the nuclear system can be preeeurized above ambient conditions. These requirements are applicable at nuclear system pressures below normal operating pressures because abnormal operational transients could possible start ht these conditions such that eventual overpressure relief would be needed. Hovever, these transients are much less severe, in terms of pressure, than those start'ing et rated conditions. The valves need not be functional when the vessel head is removed, since the nuclear system cannot be pressurized.

RFFERENCES 1, Nuclear System Pressure Relief System (BFNP FSAR Subsection 4.4)'.

"Protection Against Overpressure" (ASME Boiler and Pressure Vessel .

Code, Section III, Article 9)

3. Brooke Fnrry Nuclear Plant Des9.rm Doficiency Report-Target Rock Valves, transmitted by J. E. 611leland to F. E. Kruosi> August ~9~ 1973.

Safety'eliof 3.6.E/4.6,E ~Jet Pum 8 Failure of a )et pump nozzle assembly holddovn mechanism, nozzle assembly and/or riser, would increase the cross-sectional flow ares for blowdown following the design basis double-ended line break. Also'ailure of the diffuser would eliminate the capability to reflood the core to two-thirds height level following a recirculation line break. Therefore, if a failure occurred, repairs must be made.

The detection technique is ae follows. With the two recirculation pumps balanced in speed to vithin + 5 percent, the flov rates in both recircula-tion loops vill be verified by control room monitoring instruments.

thc two flow rate values do not differ by more than 10 percent, riser snd If nozzle assembly integrity has been verified.

171

3. 6/4. 6 llASES:

If tlrey do differ by 10 percent or more, the core flow rate measured by. the

)et pump diffuser differential pressure system must be checked against the core flow rate derived from the measured values of loop flov to core flow correlation. If the difference between measured and derived core flow rate is 10 percerrt or more (with the dex'ived value highe'r) diffuser measurements will be taken to define the location within the vessel of failed 5et pump nozzle (or riser) and the gnit shut down for repairs. If the potent:ial blowdown flow area is increa'eed, the system resistance to the recirculation pump is also reduced; hence, the affected drive pump will "run out" to a substantially higher flow rate (approximately 115 percent to 120 percent for a single nozzle failure). If. the two loops are balanced in flov at the same pump speed, the resistance characteristics cannot have changed. Any imbalance between drive loop flov rates would be indicated by the plant process instrumentation. In addition, the affected )et pump would provide a leakage path past the core thus reducing the core flow rate. The reverse flow thxouplr the inactive jet pump would still be indicated by a positive dif,ferentinl pressure but the net effect would be a sliglrt decrease (3 per-cent to 6 percent) In t)re total core flov measured. This decrease, together, with the loop flow increase, would result in a lack of correlation between measured and derived core flow rate. Finally, the afFected get pump di'ffuser differential pressure signal would be reduced because the backflow would be less than the normal forward flow.

A nozzle-riser system failure could also generate the coincident failure of a )et pump diffuser body; however, the converse ie not true. The lack of any substantial stress in the )et pump diffuser body makes failure impossible without an init:ial nozzle-riser system failure.

3.6.F/4.6.F Jet Pum Flow Mismatch The 1.PCI loop selection logic has been previously described in the BFNP FSAR.

For some limited low probability accidents with the recirculation loop 'opera-ting witlr lnxge speed differences, it is possible for the logic to select the wronp loop for in)ection. For these limited conditions the core spray itself is adequate to prevent fuel temperatures from exceeding allovable limits.'ow-ever, to limit the probability even further, a procedural limitation has been placed on the allowable variation in speed betveen the recirculation pumps.

Analyeee indicate that above 80% pow'er the loop select logic could be expected to function at a speed differential up to 14% of their average speed, Below 80% pover the loop select logic would be expected to function at a speed differential up to 20% of their average speed. This specification provides, margin because the limits are set at + 10% and + 15% of the average speed'or.

the above nnd below 80% power cases, respectively. If the reactor is opera-ting on one pump, the loop select logic trips that pump before making the loop selection.

172

3.6/4.6 BASES:

Requiring the discharge'alve of the lower speed loop tn remain. closed until the speed of the faster pump is below 50/ nf its rated speed provides assurance when going from one to two pump operation that excessive vibra-tion of the )et pump risers will not occur.

3.6.G/4.6.G Structural I~nte 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 require-ments of Section Xl, of the ASME Boiler and Pressure Vessel Code.

The pr'ogram reflects the built-in limitations of access to the reactor coolant systems.

1t is i.ntended that t.he 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 drywall wall or nearby auxiliary systems or control systems. Selection was based on )udgment from actual plant observation of hanger and support locations and review of drawings.

Inspection of all those welds during each 10-year inspection interval will result in three additional examinations above the requi'rements of Section XI of ASHE Code.

Rt."YEREMCES

1. -Inservice Inspection and Testing (BFNP FSAR Subsection 4.12)

2. Inservice Inspection of Nuclear Reactor Coolant Systems,Section XI, ASME Boiler and Pressure Vessel Code

3. ASHF. Boiler and Pressure Vessel Code, Section III.(1968 edition)

4. American Society for Nondestructive Testing No. SNT-TC-1A (1968 edition)

BASES:

3.6.H/4.6.H H draulic 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 motion 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. Xt is therefore required that all hydraulic snubbers required to protect the primary coolant system or any other safety system or componen't be operable during reactor operation.

Because the snubber 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 for repairs or replacements. In case a shutdown is required, the 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, Specification 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 b'e inspected more frequently (every month) until material compatibility is confirmed or an appro-priate 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 temper-ature limit for the molded polyurethane. Lab tests and in-plant experience indicate that seal materials are available, primarily. ethylene propylene 173a

~~

4 BASES: 4S 3."6;H/4.6.H H draulic Snubbers (cont'd) 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. These tests: will include .stroking of the snubbers to verify proper piston movement, lock-up and bleed, Five percent or fivesnubbers, whichever is less, represents an adequate sample for such tests.

Observed failures on these samples should require testing of additional units.

Snubbers in high radiation areas or those especially difficult to remove need

~ not be selected for functional tests provided operability was previously verified.

To complement the visual external inspections, disassembly and internal examination for component damage and abnormal seal degradation should be performed. The examination of two units, each refueling cycle, selected from relatively severe environments should adequately serve this purpose. Any observed wear, breakdown or deterioration will provide a basis for additional inspections.

References (1) Report, H. R. Erickson, Bergen Paterson to K. R. Goller, NRC, October 7, 1974,

Subject:

Hydraulic Shock Sway Arrestors 173b'

1000 100 Failur,e 30 No Failure 0.1

Reference:

"Corrosion and Wear Handbook" D. J. DePaul, Ed.

0. 01 O.l 10 100 1000 Chloride-ppm BROWHS FERRY HUCLEAR PLAHT FIHAL SAFETY AHALYSIS REPORT Chloride Stress Corrosion Test Results at 500 F FIGURE 3"6-2 174

LIMITINr. CONDITIONS ":OR OPERATION SURVEILLhbi'CE RE UIRCHE'.iTS

3. 7 CONTAINMENT SYSTEMS 4' CONTAINMENT SYSTEMS

~Alice~bilit

~ .

Applies to the operating status hpplies to the primary and secon-of the primary and secondary dary containment integrity.

containment systems.

~Ob ective ~Ob ective To assure thc integrity of thc To verify the integrity of the primary and oecondery contain- primary and secondary containment.

ment- systcmse S eci.fication

h. Primar Containment A. Primer Containment

l. At any time that the irra- 1. Pressure Suppression diated fuel is in tho reactor Chamber vessel, and the nuclear sys-tem is pressurized above a. The suppression chamber atmospheric pressure or work .water level and tempera-is being done which has the ture sha11 be checked potential to drain the ves- once a day except sel, thc prqssurc suppres- that during RCIC, HPCI, sion pool water volume and or relief valve temperature: shall be main- operation with the reactor isolated, they tained within the following shall be checked limits cxccpt as specified hourly.

in 3.7.A.2.

a. Minimum wa)er volume-123,000 ft

.b. Maximum wa)er volume-135,000 ft

c. Maximum suppression pool temperature during nor-mal power operation suppression pool 95'.'aximum temperature during RCIC, HPCI, or rclicf valve operation - 105'F.

e. During reactor opera-tion ut greater than one percent of rated power, the suppression pool temperature shall not exceed 110'P.

175

0 LIMITING CO.,'tiITIONS FOR OI RRATION SURVEIU ANCE REAUERPiENTS 3.7.A Primar Containment 4.7.A Primary Containment

f. The suppression pool temperature during operation with the reactor isolated shall not exceed 2. Integrated Leak Rate Teston 120 F.

If the limits speci- Integrated leak rate tests

g. (ILRT's) shall be performed fied in e. and f. to verify primary contai.n-above are exceeded, the reactor shall be ment integrity. Primary manually scrammed containment integrity'is and depressurized. confirmed if the maximum allowable integrated leak-

h. In order to continue age rate, L , does not ex-reactor power oper- ceed the equivalent of 2 ation after HPCI,: percent'f the primary con-RCIC, or relief valve operation, the chamber sup-'ression

't tainment volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> the49.6psig design pres-sure, P .

P temperature must be reduced to 95'F. b. Integrated leak rate tests within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> fol- may be performed at P or lowing the return at a test pressure, P of to reactor power not less than 25 psig pro-operation. vided the resultant leakag>>

rate, L , does not exceed a

2. Primary containment preestafilished fraction oi integrity shall be main- L determined as follows:

tained at all times when a the reactor is critical Prior to initial operation, or when the reactor in tegra ted leak ra te tes ts water temperature is must be performed at P, and above 212'F. and fuel P with the lower pressure is in the reactor t8st performed first Po vessel except while per- establish the allowabl'e leak forming "open vessel" rates (in percent per 24 physics tests at power hours). The leakage rates levels not to exceed 'hus measured shall be iden-(t). tified as L and L <respec-tively. L shall nlrb]exceed L

a L

tm for values P

L Pill of L tm r<,. 0 7.

L Pill

LIMITING CONnlTIONS FOR OPFRATION SURVEILLANCE RE U IR &)ENTS

4. 7.h Primar Containment L

L shall not exceed 0 .5 L

a P

.t for values of;:

P p

L tm

> 0.7. I L

pm

c. 1. Test duration sha19. be at least 24 hours.'.

Closure of containment isolation valves for the purpose of "the test shall be accomplished by the means provi'ded for normal opera t ion of the valves without preliminary exercises o'r ad)ustment.

3. Test accuracy shall. be verified by supplcmen- I 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 be met prior to resumption of power shall not be greater than 75 peicent of La if the test pressure is P or not greater than 75 percent of L if the test pressure isP.

e. The ?LRT's shall be perfnrmeo at the following miniir,um frequency:

177 V

i. 7.A Primar Containment 4.7.A Primary Caneakniaent

1. Prior to initial unit operation.

2. At approximately three and one-third year intervals so that a'y ten-year interval would include four ILRT's. These inter-vals may be extended up to eight months if necessary to coin-cide with refueling outage.

Except for the initial ILRT, all ILRT's shall be per-formed without leak repairs immediately prior to or during the test. If leak repairs are necessary in order to perform ILRT, they shall be preceded by local leak measurements where possible. The leak rate difference prior to and after repair shall be added to final integrated leak rate results, L or L Following each P5:f, if the measured leak rate ex"eeds L, the condition shall be cSrrected. Following repairs, the integrated leak rate test need not be repeated provided local leakage rat measurements before and after repair demonstrate that the leakage rate reduction achieved by repairs reduces the overall measured integrated leak rate to an acceptable value.

Local leak rate tests (LLRT's) shall be performed on the primary containment testable penetrations and isolation valves at not less than 49.6 psig (except for the main steam isolation valves, see 4.7.A.i) each opera-

LIHITING CONDITIONS FOR OPERATZON SURVEILLANCE RE UXREMENTS 3.7.A Prima Containment 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 of 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.B, (2) Testable penetrations with testable bellows-Table 3.7.C, (3) Isolation valves-Tables 3.7.D through 3.7.G, 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 0 criterion of 4.7.A.2,g is not demonstrated 179

LIHITING CONDITIONS POR OPERATION SURVEILLANCE RE UIRWENTS 3.7.A Primnr 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 depressurized until repairs are effected and the local leakage meets the acceptance cri-terion as demonstrated by retest.

~

i. The main steamline isola-tion valves shall be tested at a pressure of 25 psig for leakage during each refueling outage., If the leakage rite of 11.5 sc f/hr for any one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

j. Continuous L ak Rate Monitor When the 'primary containment is inerted, the containment shall be continuously for gross leakage by moni-'ored review of the inerting system makeup requirements. This monitoring system may be taken out of service for maintenance but shall be returned to ser-vice as soon as practicable.

k. Dr ell Surfaces The interior surfaces of the drywell and torus above the level one foot below the normal water line and outside surfaces of the torus below the water line shall be visually &soected each operating cycle for deterioration and any signs of structural damage with particular attention to piping connections and supports and for signs of distress or displacement. In the event of 0 an extended relief valve operation when the temperature of the suppression pool exceeds 130'P.,

180

l.IMITING CONDITIONS FOR OPERATION SURVEILLANCE RF. UIRVfF2iTS 3.7.A Primar Containment 4.7.A Primar Containment

3. Prcssure Su ression Chamber-the'bove inspections will be performed as soon as the reactor Reactor Buildia Vacuum Breakera can be shutdown and brought to the cold condition.

a. Except as specified in 3.7.A.3.b below, two pressure suppression chamber-reactor building vacuum breakers shall be operable at all times when primary containment inte-trity is required. The Reactor Buildin Vacuum Breakers set point of the differen-tial pressure instrumenta- The pressure suppression tion which actuates the chamber-pressure suppression cham- reactor building vacuum breakers ber-reactor building and associated instrumentation vacuum breakers shall be including set point shall be 0.5 psid. checked for proper operation every three months.

b. Prom and after the date that one of the pressure suppression chamber-reactor building vacuum breakers is made or found to be inopera-ble for any reason, reactor operation is permissible only during the succeeding 4. Dr ell-Pressure Su pression seven days, provided that Chamber Vacuum Breakers the repair procedure does not violate primary contain- a. Fach drywell-suppression ment integrity. chamber vacuum 'breaker ell-Pressure Su ression shall be exercised through

4. ~Dr an opening-closing cycle Chamber Vacuum Breakers every month.

a. :When primary containment is required, all drywell-suppression chamber vacuum breakers shall be operable and positioned in the fully b. When it is determined chat closed position (except two vacuum breakers are during testing) except as inoperable for opening at a specified in 3.7.A.4.b and tine when operability is required c, below. all other vacuum breaker

b. One drywell-suppression chamber vacuum breaker may be non-fully closed so long as it is determined to be not more than as indicated by the 3'pen position lights.

181

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREHENTS 4.7.A Primar Containment valves shall be exercised immediately and every 15 days thereafter until the inoperable valve has been returned to normal service.

c.'wo drywell-suppression c. Once each operating cycle, chamber vacuum breakers 'ach vacuum breaker valve may be determined to be shall be visually inspected inoperable for opening. to insure proper mainten-ance and operation.

d. If specifications 3.7.A.4.a, d. A leak test of the dryvell

.b, or .c cannot be met, the to suppression chamber unit shall be placed in a structure shall be con-cold shutdovn condition in ducted during each an orderly manner within 24 operating cycle. Accept-hours. able leak rate is 0.14 lb/

sec of primary containment atmosphere vith 1 psi differential.

5. Ox en Concentration 5. 0 en Concentration

a. After completion of elec- a. The primary containment trical output and net plant oxygen concentration shall heat rate demonstration be measured and recorded containment atmosphere at least twice weekly.

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 b. The quantity of liquid subsequent to placing the nitrogen in the liquid reactor in the Run mode nitrogen storage tank following a shutdown, the shall be determined tvice containment atmosphere ~

per week when the volume oxygen concentration shall requirements of 3.7.A.5.c be reduced to less than 4X are in effect.

by weight and maintained in this condition. De-inert-ing may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a shutdown.

182

LIKITI'NG CONl)ITIONS FOR OPERATION SURVEXLI.ANCE RE UIRPIENTS

3. 7. A Pr fearContninmcnt 4.7. A Primar Containment.

c. Mien the conta(nmcnt ctmos-phere oxygen concentration is ri'quired to be less than 4% the minimum quantity of liquid nitrogen in the liquid nitrogen storage tank ohall be 2500 gal.

d. If the specifications of through 3.7.A.5.c '.7.A.5.a cannot be met, an orderly shutdown shall be initiated and the reactor shall be in a Cold Shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

B. Standb Gas Treatment S stem B. Standb Gas Treatment S stem

1. Except as specified in Speci- l. At least once per operating fication 3.7.B.3 below, all cycle, the following condi-three trains of the standby gas tions shall be demonstrated.

treatment system and the diesel generators required for oper- a. Pressure drop across the ation of such trains shall combined HFPA filters and be operable at all times charcoal adsorber banks is when secondary containment less than 6 inches of water integrity is required. at the system design flow rate.

2. a. The results of the in-place cold DOP and halogenated The inlet heaters on each hydrocarbon tests at design circuit are capable of an out-flows on HFPA filters and put of at least 40 kg.

charcoal adsorber banks shall show >99% DOP re- c. Air distribution is uni-moval and >99% halogen- form within 20% across HEPA ated hydrocarbon removal. filters and charcoal adsorbers.

b. The results of laboratory 2. a. The tests and sample analysis carbon sample analysis of Specification 3.7.B.2 shall shall show >95% radio- be performed initially and active methyl iodide at least once per year for removal at a velocity with standby service or after in 20% of actual system 3 every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of system design, 0.5 to 1.5 mg/m operation and following inlet methyl iodide con- significant painting, fire centration, >70% R.H. or chemical release in any and >190 F. ventilation zone communicating with the system.

c. I'ans shall be shown to operate within +10% design b. Cold DOP testing shall be flow. performed after each com-plete or partial replace-

. ment of the HFPA filter bank or after any structural maintenance on the system housing.

3,83

LIMTTIYG CON))ITIONS FOR OPERATION SURVEII.LANCE RE~IJIR~r.; AGENTS 4.7.B Standb Gas Treatment System

c. Halogenated hydrocarbon testing shall be performed after each complete or partial replacement of the charchqal adsorber bank or after any structural maintenance on the system housing.

d. Fach train shall be oper-ated with the heaters 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 downstream of the IIFPA filters and charcoal adsorbers shall be performed at'nd in conform-ance wit'h each test performed for compliance with Specifi-cation 4.7.B.2.a and Specifi-cation 3.7.B.2.a.

3. From and after the date that one train of the standby gas treatment system is made or found to be inoperable for any reason, reactor opera- a. At least once per year auto-tion and fuel handling matic initiation of each branch is permissible only dur- of the standby gas treatment ing the succeeding 7 days system shall be demonstrated unless such circuit is from each unit's controls.

sooner made operable, provided that during b. At least once. per year such 7 days all active manual operability components of the other of the bypass valve for standby gas treatment trains shall be oper-filter cooling shall be demonstrated.

able.

c. When one train of the standby

4. If these conditions can- gas treatment system becomes not be met, procedures inoperable the other shall be initiated im- shall be demonstrated to be mediately to establish operable immediately and daily reactor conditions for thereafter.

which the standby gas treatment system is not required.

184

i.wrvrvr, cn~nlvrn.<s r'nR oprarviow SURVFILLABCE RE UIR~r..sENTS 3.y.C geenngar~Containment 4. 7. C Secondar Containment

1. Secondary containment inte- -

1. Secondary containment surveil-grity shall be maintained in lance shall be performed as thc'eactor zone nt'll times indicated below:

except as speci.fied in 3.7.C.2.

a. A preoperational secondary containment capability test shall be conducted by iso-lating the reactor building and,placing two standby, gas treatment system filter trains'n operation, Such test shall demonstrate the 184a

3.7.C Secondar Containment 4. 7.

capability to maintain 1/4 inch of water vacuum under calm wind ( < 5 mph) condi-tions with a system inleakage rate of not more than

, 12,000 cfm.

b. Additional tests shall be performed during the first unit 3 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 system inleakage not more than 12,000 cfm, shall be demonstrated at each refueling outage prior to refueling.

2. If reactor zone secondary con- 2. After a secondary containment tainment integrity cannot be violation is determined the maintained the following con- standby gas treatment system ditions shall be met: trill be operated immediately after the affected zones are isola ted from the rema ind e r of

a. The reactor shall be made the secondary containment to subcr it if ical and Spec ica- 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 negative pressure down below 212'F and the under calm wind conditions.

reactor coolant system 3

vented.

c; Fuel movement 'shall not be permitted in the reac-tor zone.

d. Primary containment integrity maintained.

3.. Secondary containment integrity shall be mafntnined in the re-fueling zone, except as speci-fied in 3. 7.C.4.

L,WHITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREHENTS J.7.C Secondar. Containment 4.7.C Secondar Containment If secondary containment can-not be maintained because of a violation in the refueling zone, the following conditions shall be met.

a. Handling of spent fuel and all operations over spent fuel pools and open reac-tor wells shall be prohibited.

b. The standby gas treatment system suet'ion to the re-fueling zone will be except for a con-

'locked trolled leakage area sized to assure the achieving of a vacuum of at least 1/4-inch of. water and not over 3 inches of water in all three reactor zones.

ll. Primar Containment Isolation Valves D. Primar Containment Isolation Valves 1.

'll During reactor power operation, isolation valves listed in Table 3.7.A and all reactor

1. The primary containment isola-tion valves surveillance shall

.be performed as follows:

coolant system instrument line flow check valves shall be 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 times.

b. At least once per quarter:

(1) All normally open power operated isolation valves (except for the main steam line power-operated isolation valves) yhall be fully closed and reopened.

186

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIRMEVaZS

'$.7.D Primar Containment Isolation Valves 4. 7. D Primar Containment Isolation. Valves (2) Mith the reactor power less .than 7S/ trip main steam isolation valves individually and verify closure time.

c. At least twice per'eek the main steam line power-opera'ted isolation valves shall be exercised one at a time by partial closure and sub'sequent reopening.

d. At least once per operating cycle the operability of the reactor coolant system instrument line. flaw 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 3i7.A is in-becomes inoperable, reactor operable, the position of at power operation may continue least one other valve in each provided at least one valve line having an inoperable in each line having an in>> valve shall be recorded daily.

operable valve is in the mode corresponding to the isolated condition.

3. If Specification 3.7.D.1 and 3.'7.D.2 cannot be met, an orderly shutdown shall be initiated and the reactor shall be 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 />.

187

LINITINC CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.i ~E Control Room v~er enc Ventilation 4.7.E Control Room Emer enc Y

1. Except as specified in specifica- l. At least once per operating cycle, the tion 3.7.E.3 below, 'both control pressure drop across the combined HEPA room emergency pressurization filters and charcoal adsorber banks systems and the diesel generators shall be demonstrated to be less than required for operation of these 6 inches of water at system design flow systems sha11 be operable at all rate.

times when any reactor vessel contains irradiated fuel. 2. a. The tests and sample analysist of Specification 3.7.F..2 shall be per-2~ a. The jresults of the in-place formed initially and at least once Col/ DOP and halogenated per year for standby service or hydrocarbon tests at design after every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of system flows on ((EPA filters and 'operation and following significant charcoal adsorber banks shall painting, fire or chemical release show >99% DOP removal and in any ventilation zone communicating

>99% halogenated hydrocarbon with the system.

removal.

b. Cold DOP testing shall be performed

b. The results of laboratory car after each complete or partial bon sample analysis'hall replacement of the'FPA filter show >90% radioactive methyl bank or after any structural mainte-iodide removal at a velocity nance on the system housing.

within 20Ã of system design, 0.05 to 0.15 mg/m inlet c. 'alogenated hydrocarbon testing shall iodide concentration, > 90% be performed after each complete or R.){. and,> 97'F, partial replacement of the charcoal

'dsorbey bank or after any structural cd System flow rate shall be maintenance on the system housing.

shown to be within +10% /

design flow. d. Fach circuit shall be operated at 3.From and after the date that one of

. least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> every month.

the control room emergency pressur- 3. At least once per operating cycle auto-ization systems is made or found to matic initiation of the control""room be inoperable for any reason, emergency pressurization system shall reactor operation or. refueling be demonstrated.

operations is permissible only during the succeeding 7 days unless such circuit is sooner made operabl During the simulated automatic actuation test of this system

4. If. these conditions cannot be 'met, (see Table 4.2.G), it shall be reactor shutdown shall be initi- verified that the following ated and all reactors shall be dampers operate as indicated:

in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Close: PC0-150h, B, for reactor operations and CD D Ei and P refueling operations shall be Open: PCO-151 terminated immediately .. PCO-152

'88

LIMITING'CONDITIONS'FOR'OPERATION '

'URVEILLANCE'RE UIREHENTS '

3.7.F Primar Containment Pur e S stem 4.7.F Primar Containment Pur e S stem

1. The primary containment shall be l. At least once per operating cycle, normally vented and purged through the pressure'rop across the com-the primary containment purge bined HEPA filters and charcoal system. The standby gas treat- adsorber banks shall be demon-ment system may be used when pri- strated to be less than 8.5 inches'f mary containment purge system water at system design flow is inoperable. rate.

2. a. The results of the in-place 2>> a>> The tests and sample analysis cold DOP and halogenated hy- of Specification 3.7;F.2 shall drocarbon tests at design be performed initially and at flows on HEPA filters and least once per year or after charcoal adsorber banks shall 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of system operation show >99% DOP removal and and following significant

>99% halogenated hydrocarbon painting, fire, or chemical removal. release in any ventilation zone communicating with the system.

b. The results of laboratory car b. Cold DOR testing shall be per-bon sample analysis shall formed after each complete or show >85% radioactive methyl partial replacement of the iodide removal at a velocity HEPA filter bank or after any within 20% of system design, structural maintenance on the "

0.05 to 0,15 mg/m inlet io-. system housing.

dide concentration, >90% R.H.

and >97'F.

System flow rate shall be c. Halogenated hydrocarbon test-shown to be within +10% of ing shall be performed after design flow. each complete or partial re-placement of the charcoal adsorber bank or after any structural maintenance on the system housing.

188a

TA3LE 3.7.A PRLNARY CONTAIN'"VI'SOLATIONVALVES Number of Pover - Maximum Action on crated Valves Opera ting No~il Xnitiating

~Grou Valve Identi. ication Inboar d Outboard Tine (sec.) position Bain steamline isolation valves 4 4 3<T<5 (FCV-1-14,26,37,&5t ~1-15, 27, 38, & 52)

Hain steamline drain isolation SC valves FCV-1-55 & 1-56 Reactor Water sample line isola- SC tion valves RHRS shutdown cooling supply isolation valves FCV-74-48.& 47 40 SC RHRS LPCI to reactor FCV-74-53, 67 2 30 SC Reactor vessel head spray isola-tion valves FCV-74-77, 78 30 SC RHRS flush and drain vent to suppression chamber 20 SC FCV-74-102, 103, 119, & 120 SC Suppression Chamber Drain FCV-74-57, 58 Drywell equipment drain discharge isolation valves FCV-77-15A, & 15B 0 GC Drywell floor drain discharge GC isolation valves FCV-77-2A & 2B 15

TABLE 3.7.A (Continued)

Number of Power Naximum Action on Operating Normal Initiating Groua Valve Identification Inboard Outboard Time (sec.) Position Reactor vater cleanup system supply isolation valves FCV-69-1, & 2 30 0 Reactor ~ater cleanup system return isolation valves FCV-69-12 60 0 HPCIS steamline isolation valves 20 0 GC FCV-73-2 & 3 RCICS steamline isolation valves 15 0 GC FCV-71-2 & 3 6 Dryvell nitrogen purge 'nlet isola-tion valves (FCV-76-18) 10 SC Suppression chamber nitrogen purge inlet isolation valves (FCV-76-19) 10 SC Dryvell Hain Exhaust isolation valves (FCV-64-29 and 30) 90 SC Suppression chamber main exhaust isolation valves (FCV-64-32 and 33) 90 SC Dryvell]Suppression Chamber purge inlet (FCV-64-17) 90 SC Dryvell Atmosphere purge inlet (FCV-64-18) 90 SC

TABLE 3.7.A (Continued)

Nmuber of Pover "aaximum Action on crated Valves Operating Normal Initiating

~Grau Valve Identification Inboard Outboard Time (sec.) Position ~Si al Suppression Chamber purge inlet (FCV-64-19) 100 SC Dryvell/Suppression Chamber nitro-gen purge inlet (FCV-76-17) 10 SC Drywell Exhaust Valve Bypass to Standby Gas Treatment System (FCV-64-31) 10 SC Suppression Chamber Exhaust Valve Bypass to Standby Gas Treatment System (FCV-64-34) 10 SC Nain Exhaust Valve to Standby Gas Treatment System (FCV-64-35) 10 SC RCIC Steamline Drain (FCV-71-6A, 6B) 0 RCIC Condensate Pump Drain (FCV-71-7A, 7B) 0 HPCI Howell pump discharge isola-tion valves (FCV-73-17A, 17B) SC HPCI steamline drain (FCV-73&A, 6B) 0 TIP Guide Tubes (5) 1 per guide NA tube

TABLE 3.7.A (Continue'd)

Number of Po~er Haximum Action on crated Valves Operating Normal Initiating

~Grou Valve Identification Inbcard Ou board Time ( .ec.) Position Standby liquid control system check valves CV 63-526 & 525 'h Process Feedvater check valves NA 0 Process CV-3-558, 572, 554, & 568 Control rod hydraulic return check valves CV 85 576 & 573 0 Process RHRS LPCI to reactor check valves CV-74-54 & 68 NA Process

NOTES FOR ThBLE 3 '.A Closed SC ~ Stays Closed Goes Closed Note: Isolation groupings are as follows:

Group The valves in Gxoup 1 are actuated by any one of the following conditions:

1. Reactor Vessel Low Mater Level (490")

2. Main Steamline High Radiation

3. Main Steamline High Flow

4. Main Steamline Space High Temperature

5. Main Steamline Low Pressure Group 2 ~ The valves in Group 2 are actuated by any of the following conditions:

l. Reactor Vessel Low Matex'evel (538")

2. High Drywell Pressure Group 3 ~

The valves in Group 3 are actuated by any of the following conditions:

1. Reactor Low Mater Level (538")

2. Reactor Mater Cleanup System High Temperature

3. Reactor Mater Cleanup System High Drain Temperature Group 4 ~ The valves $ n Gx'oup 4 are actuated by any of the following conditions:

1, HPCI Steamline Space High Temperature

2. HPCI Steamline High Flow

3. HPCI Steamline Low Pressuxe Croup 5 ~

The valves in Group 5 are actuated by any of the following condition:

1. RCIC Steamline Space High Temperature

2. RCIC Steamline High Plow

3. RCXC Steamline Low Pressure Group 6 ~ The valves in Group 6 are actuated by any of the following conditions:

1. Reactor Vessel Low Mater Level (538")

2. High Drywell Pressure

3. Reactor Building Ventilation High Radiation

Group 7: The valves in Group 7 are automatically actuated by only the following condition:

1. Reactor vessel low water level (490")

Group 8: The velves in Group 8 are automatically actuated by only the following condition:

2. High Drywell pressure

TABLE 3.7.B TESTABLE PENETRATIONS WITH DOUBLE 0-RING SEALS X-1A Equipment Hatch X-1B X-4 DW Head Access Hatch X-6 CRD Removal Hatch X-35A T.I.P. Drives X-35B X-35C X-35D X>>35E X-35F X-35G X-47 Power Operation Test X-200A Supp. Chamber Access Hatch II It X-2008 DW Flange>>Top Head Shear Lug Inspection Cover Pl I~

Hatch 82 II II d3 II II 04 II II II tl II n6 It tl 87 II ll 08 195

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 Shutdown Supply Line X-,7C Primary Steamline X-13A RHR Return Line X-7D Primary S teamline X-13B RHR Return Linc X-8 Primary Steamline Drain X-14 Reactor Water Cleanup Line X-9A Feedwater Line X-16A Core Spray Line X-9B Fcedwater Line X-168 Core Spray Line X-10 - Gteamlinc to RCIC Turbine X-17 RHR Head Spray Line 196

v TABLE 3.7.D PRIMARY CONTAINMENT ISOLATION VALVES Valve Test Test Valves Identification Medium Methed i

1-14 Main Steam Aii(1) Applied between 1-14 and 1-15 I

1-15 Main Steam Applied between 1-14 and 1-15.

Inboard valve 1-14 to be water sealed at 25 psig.

1-26 Main Steam Ai (>> Applied between 1-26 and 1-27 1-27 Main Steam Ai (>> Applied between 1-26 and 1 -27.

Inboard valve 1-26 to be water sealed at 25 psig.

1-37 Main Stcam Applied between 1-37 and 1-38 1-38 Hain Steam Ai () Applied between 1-37 and 3-38.

Inboard valve 1-37 to be water sealed at 25 psig.

1-51 Main Steam Applied between 1-51 and 1-52.

1-52 Main Steam AS.<'> Applied between 1-51 and 1-52.

Inboard valve 1-51 to be water sealed at 25 psig.

1-55 Main Steam Drain Water Applied between 1-55 and 1-56 1-56 Main Steam Drain W.t.r(') Applied between 1-55 and 1-56

)12-738 Auxiliary Boiler to RCIC Water Applied between 12-738 "and 12-742 12-741 huxiliary Boiler to RCIC Water( ) Applied between 12-741 and,l2-742 32-62 Reactor Control Air Supply Air(') Applied between 32-62 and 32-63 32-63 Reactor Control Air Supply Applied between 32-62 ind 32-63 32-27 Reactor Control Air Suction Air Applied between 32-27 andid 32-336 32-336 Reactor Control Air Suction Ai,(>> Applied between 32-27 ind 32-336 43-13 Reactor Water Sample Lines Water(') Applied between 43-13 and 43-14 43-14 Reactor Water Sample Lines W.t..(') l Applied between 43-14 and 43-13 l

43-28A 10lR Suppression Chamber w.t..(') Applied from reactor side of valve Sample Lines43-28A 197

TABLE 3.7.D (Continued)

Valve Test Valves Identification Medias Method 43-28B RHR Suppression Chamber Water (2) Applied from reactor side of valve Sample Lines43-28B 43-29A RHR Suppression Chamber Sample Lines Wate."'est Water 43-29A S

Applied from reactor side of valve 43-29B RHR Suppression Chamber Applied from reactor side of valve Sample Lines43-29B 64-17 Dryvell and Suppression Chamber hir (>> Applied between. 64-17, 64-18, 64>>19; air purge inlet and 76-24 s 64-18 Dryvell air purge inlet Applied betveen 64>>17, 64-18, 64-19, and 76-24 64-19 Suppression Chamber air purge hir (1) Applied betveen 64-17, 64-18, 64-19.,

inlet and 76-24 64<<20 Suppression Chamber vacuum Ai 0) Applied between 64-20 and 64-(ck) relief 64-(ck) Suppression Chamber vacuum Air(l) Applied between 64-20 and 64-(ck) relief \

64-21 Suppression Chamber vacuum Applied between 64-21 and 64-(ck) relief 64-(ck) Suppression Chamber vacuum Ai,(>> Applied between 64-21 and 64.-(ck) relief 64-29 Dryvell main exhaust Air Applied between 64-29 and 64-30 64-30 Dryvell main exhaust Applied betveen 64-29 and 64-30 64-31 Dryvell exhaust to Standby Applied between 64-31, 64-34., and Gas Treatment 64-35 64-32 Suppression Chamber Main Applied between 64-32 and 64-33 Exhaust 64-33 Suppression Chamber Main hi (1) Applied betveen 64-32 and 64-33 Exhaust 1 64-34 Suppression Chamber to Standby Air(1) Applied betveen 64-31, 64-34, and Gas Treatment 64-35 198

TABLE 3.7.D (Continued) t Velvee 64<<35 Yalve Identification Mnin Exhaust to Standby Test Medium Test Method Applied between 64-31, 64-34, and I

t Gas Treatment 84-20 69-1 RWCU Supply W.t..(') Applied between 69-1,69-500 and I 10-505 69-2 RWCU Supply W.t.,(') Applied between 69-2,69-500 and 10-505 71>>2 RCIC Steam Supply Applied betveen 71-2 and 71-3 e

1 71-3 RCIC Steam Supply A<<(1) Applied betveen 71-2 and 71-3 71-39 RCIC Pump Discharge Water Applied betveen 71-37, 71-38, and 71-39 73-2 HPCI Steam Supply Ai,(1) Applied betveen 73-2 M1du 73-3 73-3 HPCI Steam Supply Applied between 73 2 and 73 3

~'l-44 HPCI Pump Discharge W.t.r(') Applied betveen 73-34, 73-35, and 73-44 74-47 RHR Shutdown Suction Mater (2) Applied betveen 74-47 and 74-49 74-48 RHR Shutdown Suction Water( ) Applied between 74-48 and 74-49 74-53 RHR 1,PCI Discharge Water Applied betveen 74-53 and 74-55 74-57 R)lR Suppression Chamber Water Applied betveen 74-57, 75-58, and Spray 74>>59 74-58 RHR Suppression Chamber Water Applied between 74-57, 74-58, and Spray 74-59 74-60 RHR Dryvell Spray W t r(2) Applied betveen 74-60 and 74-61 74-61 RHR Dryvell Spray Water(') Applied betveen 74-60 and 74-61

/4-67 RHR LPCI Discharge Water Applied betveen 74<<67 and 74-69 74-71 'RHR Suppression Chamber Water(2) Applied betveen 74-71, 74-72 'nd Spray 74-73 74-72 R)lR Suppression Chamber Water Applied betveen 74-71, 74-72, and Spray 74-73 74-74 RHR Drywall Spray Mater (2) Applied betveen 74-74 and 74-75 199

~,

TABLE'.7.D (Continued)

Valve Test Test elves Identification Medius Method 74-75 RHR ~Drywall Spray Water Applied betveen 74-74 and 74-75 74-77 RHR Head Spray w.t..(') Applied betveen 74-77 and 74-78 74-78 RHR Hend Spray Water(') Applied between 74-77 and 74-78 74-661/662 RHR 'Shutdown Suction Water(') Applied betveen 74-660 and 74-661/662 75-25 Core Spray Discharge Water Applied betveen 75-25'and 75-27 75-53 Core Spray Discharge Water(') Applied betveen 75-53 and 75-55 75-57 Coro Spray to huxiliary Wat..(') Applied betveen 75-57 and 75-58 Boilers 75-58 Core Spray To Auxiliary Water (2) Applied betveen 75-57 and 75-58 Boilers 76-17 Drywoll/Suppression Chamber Nitrogen Applied betveen 76-17, 76-18, 76-19 '1)

Nitrogen Purge Inlet Q-l8 Drywell Nitrogen Purge Inlet Nitrogen,(1) Applied betveen 76-17, 76-18, 76-19 76-19 Suppression Chamber Purge (1) Applied betveen 76 17, 76-18, 76-19 Nitrogen Inlet Applied betveen 64-178-64-18> 64-19,

'6-24 Drywell/Suppression Chamber Nitrogen Purge Inlet

-'nd 76-24 e

7 7-2A Drywell Floor Drain Suap Water<'> Applied betveen 77-2A and 77-2B

/7-28 Drywell Floor Drain Sump Water<'> Applied betveen 77-2h and 77.-2B 77-15A Drywall Equipment Drain Sump Water<2> Applied betveen 77-15h and 'l7-15B ti 77-159 Dryvell Equipmont Drain Sump Water<'> Applied betveen 77<<15h and 77<<15B 90-254A Radiation Monitor Suction hir(') Applied betveen 90-254h, 90-254B, and e

and 90-255 90-254B Radiation Monitor Suction I

Ai (2) Applied betveen 90-,254h, 90-254B,'nd 90-255 90-255 Radiation Honitor Suction Air(') Applied betveen 90-254h, 90-254B, and 90-255 200

TABLE 3.7.D (Continued),

Valve Test Test Identification Mediuie Method 90-257A Radiation Monitor Discharge Applied between 90-257A and'0<<257B C 90>>2578 Radiation Monitor Discharge Air(') Applied between 90-257A and 90-2578,=;,

84-SA Containment Atmospheric Dilution Air between 84-SA and 84-600 I/'pplied 84-SB Containment Atmospheric Dilution Air Applied between 8'4-SB and 84-601" 84-8C Containment Atmospheric Dilution Air Applied between 84-8C and 84>>603 t

84-SD Containment Atmospheric Dilution Air Applied between 84-8D and 84-602 84-19 Containment Atmospheric Dilution Air Applied between 84-19 and 84-.20 (1) hir/nitrogen test to be displacement flow.

(2) Qatar test to be in)ection loss or doynstream collection.

201

TABLE 3.7.E SUPPRESSION CHAMBER INFLUENT LINES STOP-CHECK GLOBE ISOLATION VALVES Valve Test Test Identification Medias Method 71-14 RCIC Turbine Exhaust Water Apply between 7i-14 and 71-580 71-32 RCIC Vacuum pump'ischarge Water Apply between 71-32 and 71-,'592 73-23 HPCI Turbine Exhaust Water , Apply between 73-23 and 73-603 73-24 HPCI Turbine Exhaust Drain Water Apply between 73-24 and 73-609 TABLE 3.7.P CHECK VALVES ON SUPPRESSION CHAMBER INFLUENT LINES Valve Teat Test Valves Identification Meddue Method 71-580 RCIC Turbine Exhaust Water Apply between 71-14 and 71-580 71-592 RCIC Vacuum Pump Discharge Water Apply between 71-32 and 71-592 73-603 HPCI Turbine Exhaust Water Apply between 73-23 and 73-603 73-609 liPCI Exhaust Drain Water Apply between 73-24 and 73-609 202

TABLE 3.7eG .

CHECK VALVES ON DRYWELL INFLUENT LINES'alves Valve Test Test Idencificncion Medium Hechod 3-554 I'ccdwatcr Mater Applied between 3-67, and 3-554.

Valves 73-45, 73-44, 73-35, and 73-34 are used to form a water seel on 73-45.

3-558 'Fcedwater Mater Applied between 3-67 end 3-558 3-568 Feedwater Water Applied between 3-66, 3-568, and 69-580. Valves 71-40, 71-39, 71-38, and 71-37 are used to form a water seal on 71-40.

3-572 Fccdwater Mater Applied between 3-66 and 3-572 63-525 Standby Liquid Control Water Applied between 63-525 and 63-527 Discharge 63-526 Standby Liquid Control Mater Applied between 63-526 and 63-527 Dlscliargc 69-579 RWCU Return Wa ter Applied between 3-66, 3-568,69-579 and 71-40. Valves 71-40, 71-39, 71-38, and 71-37 are used to form a water seal 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 Mater Applied between 3-67, 3-559 and 73-45 74-54 RHR LPCI Discharge Water Applied between 74-54 and 74-55 74-68 Rlm LPCI Discharge Water Applied between 74-68 and 74-69 75-26 Core Spray Discharge Water Applied between 75-26 and 75-27 I

75-54 Core Spray Discharge Water Applied between 75-54 and 75-55 85-573 CRI) Ilydraulic Return Mat Applied between 85-573 and '85-577 I

R5- >76 CRD llydraulic Return Mater Applied between 85-576 and 85-577 203

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-101 A X-101C X-101D II II X-102 Thermocouples X-103 CRD Rod Position Indic.

X-104A Indication and Control X-1048 CRD Position Indic.

X-104C Neutron Monitor X-104D Thermocouples X-104E Indication and Control X-104F X-105A Spare X-1058 Recirc. Pump Power X-105C II II X-105D Spare X-106A CRD Rod Position Indic.

X-1068 Neutron Monitoring X-107A 204

TABLE 3.7.H (Continued)

X-1078 Spare X-108A Power X-1088 CRD Rod Position Indic.

II II II It X-109 X-110A Power X>>1108 CRD Rod Position Indic.

X-230 Containment Air Moni.toring System 205

BASES 3.7.A

~ ~ 6 4.7.A Primar Containment The integrity of the primary containment 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 whenever the reactor is critical and above atmospheric pressure. An exception is made to this requirement during initial core loading and while the low power teat program is being conducted and ready access to the reactor vessel is required. There will be no pressure on the system at this time, thus greatly reducing the chances of a pipe brea'c. The reactor may bc taken critical during this period; however, restrictive operating procedures will be in effect again to minimize the probability of an accident occurring. Procedures and the Rod Worth Hinimizcr would limit control worth such that a rod drop would not result in any fuel damage. ln addition, in the unlikely event that an excursion did occur, the reactor building and standby gas treatment system, which shall be operational during this time, offer a sufficient barrier to keep offoite doses well;below 10 CFR 100 limits.

The pressure suppression pool wate'r provides the heat sink for the reactor primary system energy release following a postulated rupture of the system.

The prcssure 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 acci-dent, thc pressure resulting from isotherma3. 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 dry-well volume is purged to the suppression chamber.

Uaing thc minimum or maximum water volumes given in the specification, containment pressure during the design basis accident is approximately 49 pang which3is below the maximum of 62 psig. Haximum water volume of 135,000 ft results )n a downcomer submergency of 5'2-3/32" and the minimum volume of 123,000 ft results in submergency approximately 12 The ma)ority of the Bodega tests vere run with a submerged length inches'eos.

of 4 feet and with complete condensation. Thus, with respect to down-comer submergence, this specification is adequate. The maximum temperature at the end of blowdown tested during the Humbolt Bay and Bodega Bay test was 170'F and this is conservatively taken to be the limit for complete condensa-tion of the reactor coolant, although condensation would occur for temperatures above 170'F.

Should it be necessary to drain the suppression chamber, this should only be done when there is no requirement for 'core standby cooling systems operability.

206

0 Under full power operation conditions, blowdown from an initial sup-pression cham)per water temperature of 95"F results in a peak long term wat,er t.cmperaLurv of, i.'/0"t'hich is sufixc1ont; z'or comp3.eca condensation. at this temperature and atmosohoric pressure, the

~vailablo NPSH exceeds that required by both the H.!R md core

s. ray punps, thus there is no dependoncy on containment overpressure.

l.imitinp suppression pool temperature to 105'F during RCIC, HPCI, or relief valve operation when decay heat and stored energy is removed from thc primary system by disch<<rging reactor steam directly to the suppres-sion chamber assures adequate margin for controlled blowdown anytime during RCIC operation "nd assures margin for complete condensation of steam from the design basis loss-of-coolant accident.

If a lo~s-of-coolant accident were to occur when the reactor water temperature is below approximately 330'F, the containment pressure will not exceed) the 62 palp code permissible pressure, even if no condensa-tion were to occur. The maximum allowable pool temperature, whenever t)~e reactor is a)iove 212'F, shall be governed by this specification.

Thus, specifyins, water=volume-tenperature requirements applicable for reactor-water temper<<turc above 212'F provides additional margin above that available at 330'F.

Inertin~

Thc rel<<tively sm<<)1 containment volume inherent in the GE-BWR pressure suppression containment and thc large amount of zirconium in the core are such that the occurrence of a very limited (a percent or so) reaction of the zirconium and steam during a loss-of-coolant accident could lead to the 1ibcration of hydrogen combined with an air atmosphere to result in a flammablc concentration in the containment. If a sufficient amount of lsy~lrnpcn is generated and oxygen is available in stoichiometric quantities, the subsequent ignition of the hydrogen in rapid recombination rate could lead to failure of the containment to maintain a low leakage integrity.

The 4/ oxygen concentration minimizes the possibility of hydrogen combus-tion following a loss-of-coolant accident.

The occurrence of primary system leakage following a major refueling out-age or other scheduled shutdown is much more probab1.e than the occurrence of the loss-of-coolant accident upon which the specified oxygen concentra-tion 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 inspec-tions are scheduled during startup periods, when the primary system is at or near rated operating temperature and pressure. The 24-hour period to orovidc inerting is fudged 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 containment atmosphere 207

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.

Vacuum Relief The purpose of the vacuum relief valves is to equalize the 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 3.00X 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.

When a drywell-suppression chamber vacuum breaker valve is exercised through an opening-closing cycle the position indicating lights'n 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'pen>

Red - On (> 3'pen)

Closing Cycle Check - On (Fully Closed)

Green On ( <80'pen)

Red << Off ( (3'pen)

The valve position indicating lights consist of one check light on the check light panel which confirms full closure, one green light next to 80'f full opening and one red light next the hand switch which confirms to the hand switch which confirms "near closure" (within closure). Each light is on a separate switch. If 3'f full 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'f full closure). The green light 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 ie 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 cir-cuit along is inoperable the valve shall be considered inoperable for 208

BASES opening.

n . t e ccheck Ef the ec anand green or check light circuit alone is inoperable, the valve shall be considered inoperable for full closure. e If the red and check light circuits are inoperable the valve shall be considered and open greater than 3'. Por a light circuit to be considered operable inopera-'le 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. ll The twelve drywell vacuum breaker valves which connect the suppression chamber and drywell are sized on the basis of the Bodega pxeseure 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 t li it th reesure differential between the suppression chamber and dry-well during post-accident drywell cooling operations to a value whic h iee within suppression system design values.

The containment design has been examined to determine that a leakage equi-to one drywell vacuum breaker opened to no more'han a nomina n1 3'alent as confirmed by the red light is acceptable.

0n thi Sas b ie an indefinite allowable repair time for an inoperable red light circuit on any valve or an inoperable check and green or c ec g cixcuit alone or a malfunction of the operator or disc {if nearly closed) on one valve, or an inoperable green and red or green light ccircuit rc alone on two valves ie )ustified.

During each operating cycle, a leak rate test shall be pexformed to vexify that significant leakage flow paths do not exist between the dryweL and suppression chamber. The drywell pressure will be increased by at least 1 psi with respect to the suppression chamber pressure and held constant.

The 2 pnig 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 prcssure cannot be increased by 1 psi over the suppression chamber pressure it would be because a significant leakage path exists; in this event the leakage source will be identified and eliminated before power operation is resumed.

Pith a differential pressure of greater than 1 peag, the rate of change ane of o the suppression chamber pressure must not exceed .25 inchee of water per minute ae measured over a 10 minute periodi which corresponds to about u 0.14 lb/sec of containment 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 operation; therefore, a daily check of the temperature and volume is adequate to assure that adequate heat remove

, capability ie present.

209

BASES The interior of the drywell is painted with an inorganic zinc primer top-with an epoxy coating. This coating provides protection against 'oated rusting as well ae providing a surface whic!i is decontaminable. The inspection of the paint during each ma]or refueling outaFe, appro..imately once pcr year, assures the paint is intact. Expcricnce with this type of paint at fossil fueled generating stations indicateo that the inspection interval is adequate.

The interior surfaces of unit 3 suppression chamber is coatecl with an organic protective coating of the thermosetting resSn type.

The inspection of the =oating during each. refueling outage, approxiinately once per year, assures the coating is intact. Dropping the water level to one foot below the normal operating water level enables an inspectS. on of that portion of the suppressS.on chamber where any coating problems would first begin to show.

Xf during periodic surVeillance, significant rust spots are detected above the water line, these will be recoated.

Coatings used on drywell and suppression chamber interior surfaces have been tested under simulated DBA conditions and vere found to withstand these conditions oatisfactorily.

The primary containmcnt preoperational test pressures are based upon the calculated primary containment pressure response in the event of a loss-of-coolant accident. The peak drywell pressure would 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 supp cesion chamber pressure rises to 27 psig within 25 seconds, cqualizes with drywcll prcssure, and decays with the drywell prcssure decay.

The design prcssure of thc drywcll and suppression chamber io 56 psig. The design leak rate i O.S percent per day at the pressure of 56 poig. As pointed out above, the prcssure response of the drywell and suppression chamber following an accident would be thc same after about 25 seconds.

Booed on the calculated containmcnt prcssure response d'scuseed above, the primary containment prcoperational teat prc sures vere chosen. Also based on the primary containment pressure response and the fact that the drywe11 and oupprcosion chamber function as a unit, the primary containmcnt will be tcstcd 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 ' psig. The doses calculated by 'the NPC using this bases are 0.14 rem, whole body passing cloud gai>ma dose, and 15.0 rem, thyro'd dose, which are reop ctivclv only 5 x 10 and 10 timco the 10 CFR 100 reference doses. Increasing the asr.umed lea!~ge rotc at 49.6 psig to 2.0 percent ne indicated in the specifica-ions would increase 'these doses approximately e factor of 3, stS.11 leaving a,margin between the calculated dose and the 10 CFR 100 reference valueo.

Establishing the ccot limit of 2.0X/day provides an adequate margin of safety to assure the health and oafety of the general public. It is fur-0 ther considered that the allowable leak rate should not deviate significantly

.2 10

BhSPS from thc containment dcsipn value to take advnn-sgc of the design leak- .

tightncno capab11 ity of the structure over itn ocrv'"c lifetime. Addi-tional margin to maintain the containment in the "as built" condition is achieved by establishing the allowable operational leak rate. The allow-able operational 1cak rate is derived by multiplying the maximum allow able leak rate (49 psig Hcthod) or the allowable test leak rate (25 psig Hcthod) by 0.7S 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, adcqgntc assurance that the lank rate remains within the specif5cntion. r The leak race test frequency is based on the NRC guid'e for developing leak rate testing and surveillance of reactor containment vessels. Allow-ing thc test intervals to bc extended up to S months permits some flexi" hility needed to have the teste coincide with scheduled or unscheduled shutdown periods. I The penetration and air purge piping leakage to st frequency, along with the containmcnt leak rate teste, is adequate to allow detection of leak-age trends. Whenever a bolted double-gaoketed penetration is broken and remade, the space between the gnskets is pressurized to determine that the seals nre performing properly. Zt is expected that'the ma)ority of the leakage. from valves, penetrations and seals would be into the reactor building. However, it is possible that leakage into other parts of the facility could occur. Such leakage paths that may affect significantly thc consequences of accidents are to be minimized.

Thc primary contain77cnt is normally slightly pressurized during period of reactor operation. Ã5trogen used for inerting could leak out of thc con-tainment but air could not leak i>> to increase oxygen concentration. Once thc containment is filled with nitrog'cn to the. cquircd concentration, determining the oxygen conce>>tration twice a week serves is an added assur'nncc thnt the oxygen concc::tration will not cxcced 4Z.

3. 7. S/3.7. C Standi>r Gee Treatment S etem end Sernnder Centeknment Thhe secondary containment ie designed to minimize;:.ny ground level release of rndionctivc materials which might result from a serious accident. The reactor building provides secondary containment during reactor operation, when the drywcll is sealed and in service; the reactor building contninmcnt when the reactor is shutdown and the drywell is open, provides'rimary 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.

BhSES The standby gas treatment system is designed to filter and exhaust the reactor building atmosphere to the stacl: 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 building pressure to the'esign negative pressure so that all leakage should be'in-leakage.

11igh ef ficiencv particulate air (1)RPA) filters are installed before andi after the charcoal adsorbers to minimize potential release of particulates to the environment and to prevent clogging of the iodine adsorbers. The charcoal adsorbers are installed to reduce the potential release of radio-iodine to the environment. The in-place test results should indicate a system leak tightness of less than 1 percent bypass leakage'for the charcoal adsorbers and a IIFPA efficiency of at least 99 percent removal of DOP particulates.

The laboratory carbon sample test results should indicate a readioactive methyl iodide removal efficiency of at least 95 percent for expected accident condi-tions. Zf the efficiencies of the HRPA filters and charcoal adsorbers are as specified, the resulting doses will be less than the 10 CFR 100 guidelines for the accidents analyzed. Operation of the fans significantly different from the design flow will change the removal*efficiency of the IIFPA filters and charcoal ..dsorbers.

Only two of the three standby gas treatment systems are needed to clean up the reactor building atmosphere upon containment isolation. If one system is found to be inoperable, there is no immediate threat to the containment system performance and reactor operation or refueling operation may continue while repairs are being made. If more than one train is inoper'able, the plant is brought to a condition where the standby gas treatment system is n'ot required.

4.7.II/4.7.C Ste~ndb Cas Treatment S stem snd Seeendnr Centatnment Initiating reactor building isolation and operation of thc standby gas treatment ryr.tcm to maintain at 1c/4st a 1/4 inch of water vacuum within t)~c acconJnry contninmcnt provides an adequate test of thc operation of the reactor build)ing isolation valves, leak tightness of the reactor building and performance of the standby gas treatment system. Functionally testing t)ie initiating sensors and associated trip logic demonstrates the capability for automatic actuation. Performing these tests prior to refueling vill demonstrate secondary containmcnt capability prior to the t imc the primary containment is opened for refueling. Periodic testing gives sufficient confidence of reactor building integrity and standby gas tree tmcnt sys t cm per f ormance capability.

Thc test frcqucncics are adequate to detect equipment deterioration prior Co signl fican(. 4icfects, but the tests are not filters, .thus reducing t)Seir reserve capacity frequent enough to load the too quickly. That the test-ing frequency is adequate to detect deterioration was demonstrated by thc tests which showed no loss of filter efficiency after 2 years of operation 212

SASFS sure drop across the combined HFPA filters and charcoal adsorbers of less than 6 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.

Heater capability, pressure drop and air distribution 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 >

HFPA filters and charcoal. adsorbers can perform as evaluated. Teats of the charcoal adsorbers with halogenated hydrocarbon refrigerant shall be per-formed in accordance with USAFC Peport DP-1082. Iodine removal efficiency tests shall follow RDT Standard H-16-1T. The charcoal adsorber efficiency test procedures should allow for the removal of o e d b r t a emptying of one bed from the tray, mixing the adsorbent 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 removed for the test should meet the same adsorbent quality. Tests of the HFPA filters with DOP aerosol shall be performed in accordance to ANSI Any HFPA filters found defective shall be replaced with filters '101.1-1972.

qualified pursuant to Regulatory Position C.3.d of Regulatory Guide 1.52.

All elements of the heater should be demonstrated to be functional and operable during the'est of heater capacity. Operation of the heaters will prevent moisture buildup in the filters and adsorber system.

With doors closed and fan in operation, DOP aerosol shall be sprayed. externally along the full 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 and the gaskets repairs and .test repeated.

If significant painting, fire or chemical release occurs .such that the HFPA filter or charcoal adsorber could become contaminated from the fumes, chemicals or foreign material, the same tests and sample analysis shall be 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 and operability of l!

If lt filter cooling, is necessary to assure system performance capability. one

(

standby gas treatment system is inoperable, the other system-must be tested daily. This substantiates the availability of the operable system; and thus reactor operation .and refueling operation can continue for a limited period of time.

II 3.7.D/4.7.D Prima Containment Isolation Valves Double isolation valves are provided on lines penetrating the primary con-tainment and open to the free space of the containment. Closure of one'of the valves in each line would be. sufficient to nwintain the integrity of the pressure suppression system, Automatic initiation is required to mini-

.mize the potential leakage paths from 'the containment in the event of d.)10Bs of .coolant accident.

)

213

BASES

~Crou 1 - process lines are isolated by reactor vessel low water level (490") in order to allow for removal 'of decay heat subsequent to a scram, yet isolate in time for proper operation of the core standby co( ling systems. The valves in group 1 are also closed when process instrumentation detects excessive main steam line flow, high radiation, low pressured or main steam space high temperature.

3 Grou 2 - isolation valves are closed by reactor ve.ssel low water level (536".) or high drywall prcssure. The group 2 isolation signal also "iso-latco" the reactor building and starts the standby gas treatment system.

It is not desirablco actuate the group 2 isolation signal by a tran-sient or spurious signal.

~Crou 3 - process lines are normally in use and it is therefore not desirable to cause spurious isolation duo to high drywall pressure resulting from non-safety related causes. To protect the reactor from a possible pipe break, in the system, isolation is provided by high temperature in the cleanup system area. or high flow through the inlet to the cleanup system.

Also, since thc vessel could potentially be drained through the cleanup system, a low level,isolati'on is provided.

Grou~4 an(i 5 - process lines are designed to remain operable and mitigate the conocqiicncua of nn accident which results in the isolation of other process lines. The signals'hich 'initiate isolation of,Group 4 and 5 proccas lines are therefore indicative of a condition which would render them inoperable.

Grou 6 - lines ara'connected to the primary containment but not directly to the reactor vessel. These valves ara isolated on reactor low vster level (536"), high drywall pressure, or reactor building ventilation high radiation which would indicate a possible accident and necessitate primary containment isolation.

Grou 7 - process lanai are closed only on reactor low water level f49QIIN( ).

These close on the same signal that initiates HPCIH" and RCICH to ensure that the valves are not open when HPCIS or RCICS action is required.

Crou~8 line (traveling in-core probe) is isolated on high drywell pres-sure. This is to assure that this line does not provide a leakage path when containment pressure indicates a possible accident condition.

The maximum closure time for the automatic isolation valves of the primary containment and reactor vessel isolation control system have been selected in consideration of the design intent to prevent core uncovering following pipe breaks outside the primary containment 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 o degraded valve performance, prior to exceeding the design closure times.

2l4

BASES C~

I In order to assure that the doses that may result from. a steam line breik 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 main steam line isolation valves. Analyses indicate that fuel rod perforations would be avoided for main steam valve, closure .'ladding times, including instrument delay, as long as 10.5 seconds.

'I These valves are highly reliable, have low service requirement and most>

are normally closed. The initiating sensors and associated trip logic are also checked to demonstrate the capability for automatic isolation.:

The test interval of once per operating cycle for automatic initiation results in a, failure probability of 1.1 x 10 -7 that a line will not iso-.

late. Nore frequent testing for valve operability results in a greater.

assurance that the v'alve will be operable when needed.

The main steam line isolation valves are functionally tested on a more  :

frequent interval to establish a high degree of reliability.

The primary containment is penetrated by several small diameter instru-ment lines connected to the reactor coolant'ystem. Fach instrument line contains a 0.25 inch restricting orifice inside the primary containment:

end an excess flow check valve outside the primary containment.

'I i

/

3.7 .E/4.7.E Control Room Emer enc Ventilation I

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 isolati'on-.'and. to maintain the control room pressure to the design positive pressure so that all leakage should be out leakage.

lligh el'flcicncy particulate absolute (HPPA) lilters are installed before the char-coal adsorbers to prevent clogging of the iodine adsorbers. Tlie charcoal ad-sorbers are installed to reduce the potential intake of radioiodine to the con-trol room. The in-place test results should indicate a system leak tightness of less than 1 percent bypass leakage for the charcoal adsorbers and a HEPA efficiency of at least 99 percent removal of DOP particulat'es. The laboratory carbon sample test results should indicate a radioactive methyl iodide removal efficiency of at least 90 percent for expected accident conditions. If the of the HHpA filters and charcoal adsorbers are as specified", 'fficiencies the resulting 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 significantly different from the design flow will change the removal efficiency 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.

215

~

BASES Pressure drop across the combined HEPA filters and charcoal adsorbers of less than 6 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 are necessary to show that the HEPA 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 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; Each 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 removed for the test should meet the same adsorbent quality. Tests of the HFPA filters with DOP aerosol shall be performed in accordance to ANSI N101.1-1972. Any HEPA filters found defective shall be replaced with filters qualified pursuant to Regulatory Position C.3.d of Regula-tory Guide 1.52.

Operation 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 adsorber system and remove excessive moisture built up on the adsorber.

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 t 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. l 3.7.P/4.7.P Primar Containment Pur e S stem The primary containment purge system is designed to provide air to purge 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. I HEPA (high efficiency particulate air) filters are installed before the charcoal adsorbers followed by a centrifugal fan. The in-place test results should indicate a leak tightness of the system housing of not less than 99% "

and a HEPA efficiency of at least 99% removal of DOP particulates. The carbon sample test results should indicate a radioactive methyl iodide lab-'ratory removal efficiency of at least 85 percent. Operation of the fans significantly different from the design flow will change the removal efficiency of the HEPA filters and charcoal adsorbers.

If the system's found to be inoperable',::the Standby Gas Treatment System may be"used to purge the containment.

216

BASES

"F--""

Pressure drop across the combined HEPA filters and charcoal adsorbers of "1'ess .

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'erformance capability.

lf The frequency of tests and sample analysis are necessary to show that the HEPA 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 Staridard 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 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'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 .,~i.'~

adsorbent quality.. Tests of the HEPA filters with DOP aerosol shall be performed in accordance to ANSI N101.1-1972. Any HEPA- filters found defective shall be replaced with filters qu'alified pursuant to Regulatoiy Position C.3.d of Regula-tory Guide 1.52.

If significant painting, fire, or chemical release occurs such that the HEPA filter'r 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 staff members should be to making this determination.

consulted.'rior 216a

LlHXTIt:"'O."DXVIONSFOR OP "LIV.TXON

3. 8 RAI)XOACTXUH YiATERXAI,S 4.8 )V.nXOACTXV."; HATERXALS g>plkcub~ilit Applies to rhe controlled release Applies to the periodic test and of radioactive liquids and gases record requirements and samplin..

from the facility. and monitoring methods uused for facilities effluents. t I

Ob'ectf.ve ~Ob ec.ti.e t To define the limits and conditions To ensure that radioactive liquW for the release of radioactive and gaseous releases from the effluents to the e>>yirons to assure facility are maintained within the that any radioactive releases "re limits specified by Specifications ao low as practicable and within 3.8.A a>>d 3.8.a.

the limits of 10 CPR Part 20.

S ecification A; Li uid Effluents A. LieulA Bffluente

1. The radioactivity release 1. Facility records'hall be concentration in liquid ~aintained of the radio-efflucnts from the station active concentration anc shall not exceed the values volume before dilution of specified in 10 CPR Part 20, each batch oi liquid Append ix 8, Table X X, Column effluent rele sed, and of 2, for unrestricted areas. the verage dilut'on flow and length of time over which each discharge occurrede C

The release rate of radio- 2. A representative sample active liquid effluents, of each batch of liquid excluding tritium and noble effluent released shall gases, shall not exceed 20 be analyzed for the curies during any calendar principal gamma-emmitting quarter. nuclides.

3. l)uring release of rad'o- Radioactive liq<<'d waste active wastes, the following sampling and activity analys conditions shall be met: sh,",ll be performed in acco".-

dance with Table 4.SeA.

217

LINITINC CONDITIONS POR OPERATION SURVE L4h'CE RE UIREHENTS 3.8.A Li uid Efflu'eats 4.8.A Li uid.Effluents

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 limit) specified in 3.8.A.l above this requirement cannot

'f 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 system as designed to pro- 4. The liquid effluent radiation cess liquid radwastes shall be monitor shall be calibrated et maintained and shall be opera- least quarterly by means of a ted to process, liquid red- known radioactive source.

vaste prior to their discharge Each monitor, as described, vhen it appears that the pro- 'shall also have an instrument jected cumulative discharg. channel test monthly and a vill exceed 1.25 curies during sensor check daily.

any calendar quarter.

5. The maximum activity to be con- The performance of automatic tained i.n one liquid radvaste isolation valves and discharge tank that can be diecha'rged tank selection valves shall be directly to the environs shall checked annually.

not exceed 10 curries.

B. Airborne Effluents B. Airborne Ef fluents

1. The release rate for gross 1. The gross B,Y and particulate activity except for I-131 and activity of. gaseous Mastes particulates Mth half-lives released to the environment longer than eight days, shall shall be monitored and recorded:

not exceed:

SURVEILLANCE RE UIRWc. ENTS

3. 8. B Ai rborne Ef f luents 4.8.B Airborne Effluents Q) + Q2 a. Por effluent streams having 0.13 1.46 continuous monitoring capa-bility, the activity and release rate from flow rate shall be monitored building exhaust vents and recorded to enable re-in .Ci/sec. lease rates, of gross radio-activity to be determined on rclcasc rate from main an hourly basis.

stack in Ci/sec.

b. Por effluent streams without

. continuous monitoring capa-the activity 'ility, 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 yith half

'imits .specified in 3.8.B.

lives greater than eight days released to thc environs 2. Radioactive gaseous waste sam-as part of airborne cffluents pling and,activity analysis shall not cxcccd: shall be performed in accor-dance with Table 4.8.B.

Q3 ~ release rate from building exhaust vents in uCi/sec.

Qq release rate from main stack in uCi/scc.

3. Thc release rate of gross gaseous activity from the plant shall not 3. Samples of offgas effluents exceed 0. 10 curies/second when averaged over any calendar

'hall be analyzed at. least weekly to determine the quarter. When the release rate identity and quantity of the exceeds 0.05 curies/second for a period of greater than 48 hrs principal radionuclides being released.

licensee shall notify the Director, Directorate of Licensing, in 'writing within 10 days.

4. The release rate of I-131 and particulates with half-lives greater than 8 days from the 219

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE UIREMEHTS a

3.8.B Airborne Effluents 4'.8.B Airborne Effluents plant shall not exceed 0,8 4~ All waste gas monitors shall pCl/sec when averaged over any be calibrated at least quar-calendar quarter. When the terly by means of a known release rate exceeds 0.4 pCi/ radioactive source. Each sec for a period of 1 week, monitor shall have an instru the licensee shall notify the ment channel test at least Director, Directorate of monthly and a s'ensor check Licensing, in writing within at loaet daily.

10 days.

5. If the limits of 3.8.B are

. exceeded, appropriate'or-rective act'ion, su'ch as an orderly reduction of power, shall bc initiated to bring the releases within the limits.

6. Radioactive gaseous wastes released to the environment shall be monitored and recorded.

7. During release of gaseous wastes through the main stack, the follouing con-

'itions shall be met:

a. The gross B,y activity monitor, the iodine sampler and particulate sampler shall be operating.

b. Isolation devices capa-ble of limiting gaseous release rates fiom the main stack to within the values specified in 3.8.B.l above shall be operating.

c. Ii, for an effluent release path there is no monitor operable, an equivnlent monitor can be substituted to monitor this effluent release path or no, effluents shall be released through that effluent release path'ntil such monitor is made available, 220

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 4;8.B Airborne Effluents

8. Radioactive gases released from each unit's turbine and reactor building roof vent~> the radwaste bui3ding roof vents, and the main stack'shall be continuously monitored. To accoraplish 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 system is in ser-vice. Also, one radwaste building system vent monitoring channel .shal 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 service for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for '., Radiolo ical Environmental Monitorin Pro ram testing and calibration func-'ional without providing a temporary An environmental monitoring monitor. be conducted as described program'hall below If these and outlined in Table 4.8.P.

requirements are not satisfied for the stack or rad- 1. 'Atmos heric waste monitor, the reactors shall Monitorin',

be in the hot shutdown cdndition .The atmospheric monitoring 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 network is divided into 10 days for the radwaste vent. three subgroups consisting of 12 monitoring stations, of If these requirements are not which 9 stations shall be satisfied for the reactor and operable at all times. Thc turbine building vents, the monitoring stations are affected reactor shall be in hot shown on Figure 4.8-1.

shutdown condition within 10 days. These monitoring locations ere subject to change'epen-dent upon continued evalua-tion of the environmental monitoring program, The sta-tion at Muscle Shoals vill bc used as background reference.

Each monitor shall be capable of continuously sampling air at regulated flow of approxi-

.mately three cubic feet per 221

LINET)NG CONl))TIONS FOR OPFRATION SURVF.I LLANCK RF~UIREMF:NTS 3.8. C Radiolngf cal Fnvfronmental 4.8. C Radiolo ical Fnvironmcntal

>foni t or in~Pro~ ram l<onitorin Pro rara An environmental monitoring minute through a particulate pxogram shall be conducted to filter. In series with, but evaluate the effects of station downstream of, the particu-operation on the environs and to late filter is a charcoal verify the effectivenoss of the filter used to collect io-source controls on radioactive dine. Each monitor has a materials. collection vessel to obtain rain-water on a continuous basis and a horizontal platform that is covered with gummed acetate to catch and hold heavy particulate fallout.

The local and perimeter monitors shall be equipped with a G-F) tube located next to the particulate filter which provides local and re-mote readout in the control room on stripchart recorders.

The counting efEiciency of the instrument is approxi-mately ten percent with a six decade range.

Thermoluminescent dos ime ters shall be used to record gamma radiation levels at each re-mote and perimeter station.

The TLD shall be prpcessed quarterly.

b. The particulate filters shall be removed weekly from each monitoring station and ana-lyzed for gross beta activity.

In addition, the Eil ters for each station shall b? com-posited monthly and quanti-tatively and qualitatively analyzed for at least 10 specific gamma-emitting radionucl ides.

• The laboratory is presently gamma scan-ninp a sample both quantitatively and qualitatively for the following radio-

'37cs '"Cs ) 0" ) <<'Ru nuclides 141? ) 44Ce 9'iP>> 95N)) f 40ga ) 40La 1 31 40$ 'i OCo 58Co, ')n "1Cr, and 0[2 222

LJ HlTING CONDITIONS FOR OPERATION SU1Cv'EILl ANCE RE UIREMENTS

3. 8 Kadicilog ical. 1'.nvironmental 4. 8 Radiolo ical .Environmental Moni tor'i~n Program

~

Monitorin Pro ram The charcoal filters shall be removed weekly from each station and analyzed for 1311 Rainwater shall be collected monthly when available from each station and each sample is analyzed for gross beta, at least 10 specific gamma-emitting radionuclides, strontium 89 and 90, 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 from the locations shown in Table 4.8.E on a quarterly basis.

b. Samples of river water shall be collected monthly near the plant discharge and on the Elk River, which flows into the Tennessee River downstream of the plant.

Samples shall be taken quar-terly from at least 4 of the points on the Tennessee River, one of which will be located 500 feet downstream from the plant, Samples will be obtained at varying depths in the cross section at each location, as indicated in Table 4.8.E, The samples 223

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIRE:jENTS 3.8.C Radiolo ical Environmental 4,S,C Radiolo ical Environmental 1/onitorin Pro ram Monitorin Pro ram t

shall be analyzed for gross beta, gross alpha, at least 10 specific gamma-emitting radionuclides, radiostrontium 89 and 90, and tritium.

Co Samples of sediment, clams, and two species of fish shall be collected at least semiannually from the loca-tions noted in Table 4. 8.D.

Plankton is collected in at least one of the two quarters of greatest plankton abun-dance during the year at the locations noted in Table 4,8.D. Gross beta activity and at least 10 gamma-emit-ting radionuclides shall be determined in plankton, sedi-ment, shell, and flesh of clams, flesh'r a commercial and game fish species and also in the whole body of the commercial species.

Strontium 89 and 90 content shall be determined in all samples except the flesh of clams.

Note: Because of seasonal movement of these vectors it may at times be impracti-cal to obtain samples as out-lined above. All samples shall be obtained when avail-able.

3. Terrestrial Monitorin

a. Soil shall be collected at le'ast semiannually from an area near the atmospheric monitors mentioned in para-

. graph 4.8.C.l.a. Each sample shall be analyzed for 224

.MIV~NG CONDn XONS FOR OPERATION SUP'Phl.i LANCE RE UIREMENTS 3.8.C Radio)~oical Hnv5.ronmental 4.S,C Radiolorical Fnvironmental Monii'nri~>1 )~to znm Monitoxin Pro ram gross beta and at least ten gamma-emitting radionuclides.

b. Milk shall be collected monthly from at leas t four farms in the vicinity of the plant and analyzed as indi-cated in Table 4,8.F.

During the seasons that animals producing milk for human consumption are on pasture, samples of fresh milk will be obtained weekly

.from these animals at repre-sentative locations that may be significantly affected by emissions from the Browns Ferry Nuclear Plant, and analyzed for their radio-iodine content, calculated as iodi ne-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 0.5 pico-curie per liter of milk at the time of sampling. For activity levels at or above 0.5 picocurie per liter, over-all error of the analysis will be within +25K. Results will be reported as picocuries of I-131 per liter of milk at the time of sampling, in accordance with Reporting Requirements for Environmental Radiological Monitoring. A cow census shall be conducted every six months {during the beginning and middle of the grazing season) to determine that samples are being col-lected of the milk having the highest concentration of I-131.

225

.IHJTING CONDITIONS FOR OPERATION SURVEILLhNCE RE UZREM'.NTS 4.8.C Radiolo ical Environmental Honitorin Pro ram 'Monitorin 'Pro ram

c. Vegetation shall be collected at least quarterly from at least four of the farms mentioned in the preceding paragraph; samples are also collected at least semiannually from an area near each of the atmospheric monitoring stations mentioned in paragraph 4.8.C.l.a. Each sample is analyzed for gross beta, 'gross alpha, at least ten specific gamma-emitting radionuclides, and strontium 89 and 90. Gross alpha analyses are not performed on the samples taken from the farms mentioned above,

d. Food crops shall be collected annually within a 10-mile radius.

Type and number of samples will vary according to availability.

Analysis shall include gross90 beta, gamma scan, Sr and Sr.

e. Well water is collected at least quarterly from at least four farms and quarterly from two additional private well supplies within onc mile of the plant site. The samples shall be analyzed for gross beta and at least ten radionuclides.

Samples of municipal water supplies shall be collected fxom the locations in Table 4.8. C. Decatur, Wheeler Dam, 226

LIMITING CONDITIONS POR OPERATIONS SURVEILLANCE RE 'JIREMENTS 4.8.C Radiolo ical Environmental Monitoxin Pro ram Monitorin Pro ram Scheffield, and Champion Paper Company are sampled monthly. All other supplies shown in Table 4,8.C are sampled quarterly. The sample" shall be analyzed for gross beta, tritium,'and at least ten specific gaaaaa-emitting radio-nuclides.

D., Mechanical Vacuum Pum D. Mechanical Vacuum Pum

1. The mechanical vacuum pump At least once during each operating shall be capable of being cycle verify automatic securing and automatically isolated and isolation of the mechanical vacuum secured on a eignal of high pumpo radioactivity in the steam E. Miscellaneous Radioactive Materials Sources lines whenever the main steam isolation valves axe open. l. Surveillance Re uirement Tests for leakage and or contamination

2. If the limits of 3.8.D.1 are shall be performed by the licensee or not met, the vacuum pump shall by other persons specifical37 authorized be isolated. by the Commission or an agreement Miscellaneous Radioactive State,'s follows!

E.

Materials Sources a, Each sealed source, except startup sources subject to core flux, li Source Loaka e Tost containing rad1oact1ve material, other than Hydrogen 3, with a half-The lea.kage tost shall be life greater than thirty days and capable of detect,ing tho in any form other than gas shall prosence of 0.005 microcurie be tested for leakage and/or of radioactivo mator1al on contamination at int,ervals not t,o the tost sample. Xf the test exceed six months.

reveals the presence of 0.005 b+ The periodic leak test required microcurie or more of remov- does not app3g to sealed sources ablo contamination, it shell that are stored and not berg immediately be withdrawn fr om used. The sources excepted from use, decontaminated,and this test shall be tested for repaired, or disposed of leakage prior to any use or transfer in accordanco with Commission to another user unless they have=

regulations. Sealed sources been leak tested within six months are exempt from such leak pr1or to the date or use or transfer tests whon the source contain Xn the absonce of a certification 100 microcuries or less of from a transferor indicating that beta and/or gamma emitting a test has been made within six material or l0 microcuries or months pr1or to the transfer, less of alpha emitting sealed souroes shall not be put raate rial. into use unt13. tested.

o< .Startup souroes shall be leak tested pr'ior to and following any repair or maintenance and before 227 being sub)ected to oore flux.

Table 4.8-A RADIOACTIVE LIQUID WASTE SAMPLING AND ANALYSIS A. Test Tank Release Type of Minimum Detectable

' lin Fre uenc Activit Anal sis Concentration uCi/ml Each Batch Pr inc ipal Gamma-Emittin Nuclides 5 x 10 (2)

One Batch/Month Dissolved and Entrained Fission and Activation Gases 10 Monthly Proportional Tritium 10 Composite (1) Gross Alpha Quarterly Proportional Sr-89, Sr-90 5 x 10 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.

228

TABLE 4.8-B Radioactive Gaseous Waste Sam lin and Anal sis Sample Sampling Type of Minimum Detectable Type Frequency Activity Analysis (1)

Concentration c cc 2

Weekly and Principle Gamma 10 (3) each purge Emitter s Gas Monthly and Tritium 10 each purge Charcoal Weekly '-131 Monthly (4) I-133, I-135 10 10 W-kly("'rincipal Gamma Emitters (at least for 10-11 Ba-140, La-140, I-131)

Par ticulate s Monthly 11 Gross alpha 10 composite of weekly samples Quarterly Composite Sr-89,Sr-90 10 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 when nuclides are measured below the stated limits they should also be reported.

(2) Analysis shall also be made within one month of the initia1 criticality and following each refueling process change or other occurrence which could a1ter the mixture of radionuclides.

(3) For certain mixtures of gamma emitters, it may not be possible to measure radionuclides at levels near their sensitivity limit when other nuclides are present in the sample at much higher levels. Under these circumstances it will be more appropriate to calculate the levels of such radionuclides using observed. ratios with those radionuclides that are measurable.

(4) When the average daily gross radioactivity release rate from a release point equals or exceeds that given in 3.8.B.3 or when the steady state gross radioactivity release rate increases by 50$ over the previous corresponding power levels'teady state release rate, the associated iodine and particu1ate cartridge shal1 be analyzed. to determine the release rate increase for iodines and particulates. When samples are taken more often than that shown, the minimum detectable concentrations will be correspondingly higher.

229

Table 4.8.C LISTING OF MUNICIPAL WATER SUPPLIES TO BE SAIPLED IN ENVIRONMENTAL MONITORING PROGRAM Distance From Plant Supply (miles)

Trinity 7.0 a

Clemente High School 9.0 Athens a 10.5 Courtland (Champion Paper Co.) b 11.6 Decatur b,c a

Town Creek b

Wheeler Hydro Plant b

Wilson Hydro Plant 34.6 Sheffield b 39.7 Colbert Steam Plant b 49.0

a. Ground water supplies

b. Surface water supplies (Tennessee River)

c. Decatur is upstream of the Browns Ferry Nuclear Plant.

230

Table 4.8.D I

j TYPES AND LOCATIONS OF BIOLOGICAL SAMPLES COLLECTED FOR PRFOPERATIQNAL AND OPERATIONAL RAD ANALYSIS IN WHEELER RESERVOIR IN REI.ATION TO THE BROWNS FERRY NUCLEAR PLANT c

TRM Station Plankton ',b Asiatic Clams Sediment Fish 307.52 293.70 291.76 288.78 277.98

a. Vertical tows

b. Replicate samples

c. Replicate samples of Asiatic clam flesh

d. G/E - Gill net and/or electroshocker will be used for collection. Samples of fishi will be collected from Guntersville, Wheeler, and Wilson Reservoirs.

Table 4,8.E RESERVOIR WATER SAMPLES COLLECTED TO MONITOR PREOPERATIONAL AND OPERATIONAL CONDITIONS IN WHEELER RESERVOIR IN RELATION TO THE BROWNS FERRY NUCLEAR PLANT Distance From TRM Left Bank Depths for Water Station (Normal Full Pool Elev.) (meters)

(Feet) (Percent) 307.52 1<800 24 1, 5 2,800 37 1 295.87 4,000 44 7,500 82 293.70 6,800 65 1 9,200 88 1, 5 291. 76 5,000 60 1 7,000 84 1, 5 283.94 3, 600 40 1 7,100 78 1$ 10 ~ 1

a. This station will be located 500 feet downstream from the point of release.

231

T. 4.8.F FADIOLOGICAL ENVIRON""NTAL SURVEILIJDCE PROGRAM Criteria and Sam lin Locations Collection Fre uenc Anal sis/Countin X. Atmospheric A. Air

1. Particulate Pilter paper at 12 locations Weekly Gross beta as shown on Figure 4.8-1 (gamma scan monthly)

2. Radioiodine Charcoal filter same Weekly 1311 locations as I.A.1.

B. Fallout Gummed acetate, same Monthly Gross beta locations as X.A.l.

C. Rainwater Same locations as Z.A.l, Monthly Gross beta, Sr, 9 Sr II. Reservoir A. Mater

1. Municipal (public Locations as shown in Monthly Gross beta, gamma scan, supplies) Table 4.8.C Quarterly SH

2. River Plant discharge and Elk Monthly Gross alpha, Iwross beta River Five locations given Quarterly gamma scan, 8 Sr, 90Sr in table 4.8.E ~H B. Aquatic Biota

1. Pish (buffalo ~ee locations Semiannually Gross beta, gamma scan, and crappie) 89Sr 90Sr

2. Shellfish Four locations Semiannually Gross beta, gamma scan, (Asiatic clams) ( 9Sr, Sr shells only

3. Plankton Three locations Semiannually Gross beta, gamma scan 89Sr 90Sr C. Sediment Pour locations Semiannually Gross beta, ganja scan.

89$ r 90$ r

a. See 4.8.C.3.f for definition of sample frequency.

TABLE 4.8-F (Continued)

Criteria S lin Locations Collection Fre uenc Anal sis/Countin III. Terrestrial A. Soil Atmospheric monitoring Semiannually Gross beta, gamma sca locations given in I.A.I B. Vegetation

1. Pasturage and Four farms Quarterly Gross alpha, gross be grass

2. Pood crops Mithin 10-mile radius of plant Annually Gamma scan, 89Sr, 90S gross beta C. Milt Four farms Monthly 1311 89Sr 9oSrb gamma scan D. Mell Mater Six locations within five Quar terly Gross beta, gamma sca miles of plant E. Direct Radiation TLD's at remote and perimeter Quarterly Dose determination monitors and onsite locations

a. See 4.8.C.3.b for explanation of milk sampling program. Samples for I-131 analysis shall be taken weekly when cows are on pasture.

b. Sr and Sr content will be determined on one sample per month.

TERRESTR lAL MON ITGR iNv NE."NORK RM-2BF

" tJ~'"L~tCC GLlA9 u'

l'~~,4 0

RM-3BF 3

'T ~P)

!!LOAOICKp TIILSO>a ~'AM WHFELEA p"Mg ',<o REMAP'!LL J ncaa CPl~f 2BF P~Vg; TCViL' StlCFFI ~ ~ QWlSCLK 6RQYRS Fc, RY MJCLKAR PL NT

+Rtl-1 DF I

~gyps qetjgP CC'"lTL/d-'1~

PM-4BF CQ&TU O'J!I ABV~U>.

c.'> sr."am Q

EQi-5BF

~)i~ALKYVLLK W f~

state Cg 5TATl0tJ O" SINMMV~AL uONTCR00 (Air particle, radioiodine, fallout, rainwater, soil, and vegetation)

Figure 4.8-1 234

Ilk River

%HEELER DAM tnfla 270.SO mlle 877.88 Roger sville 0

mlle 29l.76 Athera 0

B F. NUCLEAR PLANT mile 28@37 80l0" il mlle,298.78 mJle 288,94 0

Couitland glle 893.70 SAMPLE LOCATION mile 299.

0 Oeootur elle 807.62 Scale ot Mlles BROWH$ FERRY HOCi.EAR PLhHT 0 flHAL SAPETY AHAi.YSlS REPO "T Rtsteoir hlonitorino Network clues 4.0-2 235

3.8 BASES Radioactive waste release levels to unrestricted areas should be kept "as low as practicable" and arc 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 is provided a dependable source of power 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 as low as practicable, the annual releases will not exceed a small frac-tion of thc annual average concentration limits specified in 10 CPR Part 20.

3.8,A Li uid Effluents Specification 3.8.A.1 requires the licensee 'to limit the release concentra-tion of radioactive materials in liquid effluents from the station to levels specified in 10 CFR Part 20, Appendix B, 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 permissible under the Commission's Rules and Regulatione.

Specification 3.8.A.2 establishes an upper limit for. thc release of radio-active liquid effluents, excluding tritium and noble gases, of 20 curies during any calendar quarter. The intent of this specification is to permit the licensee thc flexibilty of operation to assure that the public is pro-vided a dependable source oC power under unusual operating conditions which may temporarily result in releases higher than the levels normally achieva-ble. Releasee of up to 20 curies during any calendar quarter will 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 effluents are operating during any period these releasee are taking place.

Specification 3.8.A.4 requires, that the licensee shall maintain and operate the equipment installed in the radwaste system to reduce the release of radioactive materials in liquid effluents to as low as practicable consis-tent with the requirements of 10 CPR Part 50.36a. In order to keep releases of radioactive materials as low as practicable, the specification requires operation of equipment whenever it appears the projected cumulative release vill exceed 1.25 curiae during any calendar quarter.

236

3. 8 RASES

. Specification 3.8.A.5 limits the amount of radioactivity that may be

',inadvertently released to the environment to an amount which is as low as practicable'consistent with the requirements of 10 CFR Part 50.36a.'

1 I

3.8. B Airborne Ef fluents

,Specification 3.8.B,l provides a method to be used in summing the air-borne effluents from the main stack and vents which will assure that the release rate does not exceed 10 CFR Part 20, Table II, 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 whole body.

Specification 3.8.B.2 provides a method to be used in summing airborne I-131 and par'ticulates with 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 II, 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 whole body oz 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 the 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 the fuel cladding losing its integrity. Since core performance is of

'utmost importance in the resulting doses from accidents, a report must be

, filed within 10 days following the specified increase in gaseous radio-active releaseo.

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 keep the .radioactive gaseous releases within specified limits.

Specification 3.8.B.6 and 7 are in accordance with Design Criterion 64.

Specification 3.8.B.8 requires that these gaseous monitoring devices be operating when'ever radioactive gases'a're generated in the plant.

237

e

3. B.C/4. B.C t nvironmental Monitorin Yro ram The operational environmental monitoring program is based upon a preoperational program which is described in Section 2.6 of the PShR. Sample collection and analysis was initiated, in April 1968 and vill continue indefinitely.

Evaluations after plant startup 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 ta be negligible.

The. reference samples provide a running background vhich vill make it possible to distinguish significant radioactivity intraduced into the environment'y the operation of the station from that introduced by nuclear detonations and other sources.

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 nuclide analysis will be used to identify the source of the increase.

The planned sampling frequencies vill assure that changes in the environmental radioactivity can be detected, The materials vhich first shov changes in radioactivity are sampled most frequently. Those vhich are less affected by transient changes but shov long term accumulations are sampled less frequently.

However, the specific sampling dates are not crucial and adverse weather con-ditions or equipment 'failure may on occasion prevent collection of specific samples.

h report shell be submitted to the Commission at .the end of each of operation specifying total quantities of radioactive material re-sixmonths'eriod leased to'.unrestricted areas in liquid and gaseous effluents during, the previous eix months and such other information on releases ae may be required to estimate exposures to the public resulting fram effluent releases. If quantities of radioactive material released during the reporting period are unusual for normal reactor operations, including expected aperational occur-rences, the report shall cover this specifically, A concentration nf I-l31 in milk of 0.8 picocuries per liter vill result in a dose to the thyroid of a 0-2 year old child of 5 mrem/year, based upon con-sumption of one liter per day far the year. To assure that no child vill receive a dose of greater than 5 mr'em/year ta the thyroid, it is necessary to know the radioiodine concentration in the milk to the sensitivity of 0.5 pCi/

liter.

The four farms from vhich milk samples are taken are located in various direc-tions from the plant. Every six months a cow census is conducted to ensure that samples are being collected of the milk containing the highest concentra-tion of I-131. If n milk cow is found at a mare critical location than is already being sampled, the sampling procedure: shall be changed to include milk from this cov. Mhen this point is idded to the sampling procedure, a

'ample" point at a less 'critical farm may be deleted.

238

3.8. D/4.8. D Mechanicai Uacuua The purpose of isolating the mechanical vacuum pump line is to limit the release of activity from the main condenser. During an accident, fission products.vould be transported from the reactor through the main steam lines to the condenser.. The fission product radioactiuity mould be sensed by, the

, main steam lin'e radioactiuity monitors vhich initiate isolation.

4.8.A and 4.8.8 BASES The surveillance zequircments giuen under Specification 4.8,A and 4.8.B provide assurance that liquid and gaseous vastes are properly controlled nnd monitored during any release of radioactive materials in the liquid and gaseous effluents. These surveillance requirements prouide the data for the licensee and the Condaiseion to evaluate the station's performance relative to radioactive vestee released to the environment. Reports on the quantities of radioactive materials released in effluents shall be furnished to the Commission on the basis of Section 6 of these technical specifications. On the basis of such reports and any additional informa-tion the Commission may obtain from the licensee or others', the Commission may from time to time require the 1iceeaey to take such actions as the

'ommission deems appropriate..'

3.8.E and 4.8.E BASES Thc ob5ective of this specification is to assure that leakage from byproduct, source, and special nuclear radioactive material sources docs not'exceed allowable

.liaits'39

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS AUXILIARY ELECTRICAL SYSTEM 4.9 AUXILIARY ELECTRICAL SYSTEM A licabilit A licabilit Applies to the auxiliary elec- Applies to the periodic testing trical power system.. requirements of the auxiliary electrical systems.

~Ob ective ~Ob eatfve To assure an adequate supply of Verify. the operability of the electrical power for operation of 'auxiliary electrical system.

those systems required for safety.

~Seci fice tine S ecification A. Auxiliar Electrical E ui ment A. Euxiliet Electticel F~uf ment Thernactor shall not be started 1. Diesel Generators up (made critical from the cold conditiog unless fourunit 3 die-. a'. Each unit 3 diesel generator sel generators (3A, 3B, 3C, and shall be manually started 3D) are operable, both 161-kV and loaded once each month transmission lines are operable to demonstrate operational and supplying power to the plant, readiness. The test shall and the requirements of 3.9.A.4 continue for at least a through 3,9.A.7 are met. one>>hour period at 75% of The roactor shall not be. started rated load or greater.

up (made critical from the Hot Standby Conditio/ unless all of , During the monthly gene-the following conditions are rator test the diesel satisfied: generator s'tarting air compressor shall be

1. At least one off-site 161-kV checked for operation and transmission line and its its ability to recharge common station-service trans- air receivers. The opera-former or cooling tower tion of the diesel fuel transformer are available and oil transfer pumps shall capable of automatically sup- be demonstrated,'and the plying auxiliary power to the diesel starting time to shutdown boards. reach rated voltage and.

speed shall be logged.

2. Three unit 3 diesel generators shall be operable. ~ ~

b. Once per Unit 3 operating cycle 3.'n additional source of power a test will be conducted to demonstrate the lunit 3 emer-consisting of one of the gency diesel generators following: will start and accept.

a. A second 161-kV trans- emergency load within mission line and its com-mon transformer or cooling tower trans-240

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS

>>* 4.9.h huxilia Electrical ui ment former (not parallel with the the specified time sequence.

energized common transformer) are capable of supplying ppwe Co Once a month the quantity to the shutdown boards. of diesel fuel available

b. The'koarth operable unit 3 shall be logged.

diesel generator.

d. Each diesel generator shall

4. Buses and Boards Available be given an annual inspec-tion in accordance with

a. Start buses 1A and 1B are instructions based on the energized. manufacturer's recommenda-tions.

The 4-kV bus tie board and shutdown boards (3EA, 3EB, Once a month a sample of 3EC, 3ED) are energized. diesel fuel shall be checked

c. The 480-V shutdown boards for quality. The quality associated with the unit shall be within the accepta-are energized. ble limits specified in Table 1 of ASTH D975-68 and

d. Undervoltage relays logged.

operable on start buses 1A and 1B and 4-kV 2. D.C, Power System Unit Batteries shutdown boards, 3EA, 3EB, (250-Volt): and Diesel Generator 3EC, and 3ED. Batteries (125-Volt)

5. The 250-Volt unit-batteries and a battery .a. Every w'eek the specific charger for each battery and gravity and the voltage of associated battery boards are the pilot cell, and tempera-operable. ture of an ad)scent cell and overall battery voltage shall

6. Logic Systems be measured and logged.

a. Accident signal logic b. Every three months the mea-system is operable. surements shall be made of voltage of each cell to nearest 0.1 volt, specific gravity of each cell, and temperature of every fifth

7. There shall be a minimum of cell. These measurements 103,300 gallons of diesel fuel shall be logged.

in theunit 3 standby diesel generator fuel tanks. C~ A battery rated discharge (capacity) test shall be performed and the voltage, time, and output current measurements shall be logged at intervals not to exceed 24 months.

241

LIHITXNC CONDITIONS FOR OPERATION SURUEILLANCE RE UIREHENTS 3.9.A Auxiliar Electrical E ui ment 4.9.A Auxilia Electrical E ui ment

3. Logic Systems

a. Both divisions of the accident signal logic system shall be tested every 6 months to demonstrate that it will

'function on actuation of the core spray system of the.

reactor to provide an auto-matic start signal to all '4 diesel generators.

4. Undervoltage 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 lA 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 will start.

c. The undervoltage relays which start the diesel generators from start buses 1A and 18 and the 4-kV shutdown boards, shall be calibrated annually for trip and reset and,the measurements logged.

242

.IMXTINC CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.9.8 0 eration with Ino erable 4.9.B eration with Ino erable

~Eui ment ~Eu~iinent Whenever the 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 1. When one common herein. station transformer and one cooling tower transformer (not

1. From and after the date that one parallel with the'nergized common trans common station transformer and one former) or one 161 kV line is cooling tower transformer (not found to be inoperable allunit 3 parallel with the energized common diesel generators and associated transformer) or one 161-kV line boards must be demonstrated to be becomes inoperable, reactor opera- operable immediately and daily tion is permissible under this con thereafter.

dition for seven days.

2. When one unit 3 diesel generator 2~ When one unit 3 diesel generator is (3A, 3B, 3C, or 3D) is inoperable, found to be inoperable, all of continued reactor operation is the CS, RHR (LPCI and Contain-permissible during the succeeding ment Cooling) Systems and the 7 days, provided that both offsite ~ remaining unit 3 diesel generators and 161-kV transmission lines, both associated boards shall be common transformers or one common demonstrated to be operable transformer and one cooling tower immediately and daily transformer (not in parallel with thereafter.

the energized common transformer) are available and capable of sup-plying power to the unit 3 shut-down boards, and all of the CS, RHR (LPCI and Containment Cooling)

Systems, and the remaining three unit 3 diesel generators are oper-able. If this requirement cannot be met, an orderly shutdown shall be initiated and the reactor shall be shutdown and in the cold condi-tion within 24 hours.

243

<<'gy ~.4 >e lNfTlNO CONlll'l'lONS

~ ~

~

~ l:OR OPERATION SURVEU.LANCE RE UIRWENTS,":: .'.'<<".<<:,'..".x".'-i;

.~'"Pa'ration

~ 4.9.B: with Ino erable;..'.",",.',"

~Rut ment E uimnent Of 4

1

\ e 1

t em 4

~I Mh'en one unit 3 4-kV shutdown boar 3. hen one unit 3 4-kV sputdawn pojj-d is inoperable, continued reac- to be inoperably; *all-. jg'ound tor operation is permissible remaining unit 3 4-kV;shutdown."-ho, Ys",:..

for a period not to exceed 5 and assoc iated diesel. jjpers-"',".",.', ".:,,"',."",'.;

days, provided that b'oth off- tora, CS and RHR (LQCK ayd:

sitc 161-kV transmission lines Containme nt Cooling) Sykeemi "',~ "".>;".'y and both common transformers or supplied the one common and one cooling tower shutdown remaining;4.-'kV,;;;.'oards shall- be dcmoj>> "j' ".:,'.'

transformer {not parallel with the strated t be operablg,." fmje-;.'.~~,",>4;'" ..

energized common transformer) are diately a nd daily ther'eaf ter.".,':",;.;"- .~z-,",'.. --,-l available and the remaining unit 3 4-kV shutdown boards and associ-ated diesel generators, CS, RHR (LPCI and Containment Cooling)

Systems, and all unit 3 480-V

~ 'l" 4).n<<fg gQ'<r> <

emergency power boards are oper-able. If this requirement cannot met, an orderly shutdown shall

'e be initiated and the reactor shall be shutdown and in the cold condi- e = ~,et <<4I<<

tion within 24 hours. "1 44

<<'4 '\'<<<<m, 4~ Prom and after the date that one of the three 250-Volt unit batem tories and/or fits associated battery board is found to be inoporablo for any reason, continued reactor operation is pored.ssiblo during the succeeding seven days. Tho NRC shall be notified within 2'ours of the situation, tho precautions to be ~'

taken during this period and the plans to return tho failed component to an operable state.

244

4

~

I LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.9.8 ~Oeration with Ino erable 4.9.B 0 eration with Ino erable

~F. u1 ment F~ui ament

'Mhen one division of the Logic System is inoperable, continued reactor operation is permissible under this condition for seven days, provided the CSCS require-ments listed in specification 3.9.8. 2 are satisf ied. The 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 the situation, the precautions to be taken during this period an

. the plans to return the failed component to an operable state.

3.9.C '0 eration'in"Cold'Shutdown'Condition whenever the reactor is in the cold shutdown condition with irradiated fuel in the reactor, the availability of electric power shall be as specified in Spection 3.9.A except as specified herein.

1. At least two unit 3 diesel genera-tors and their associated 4-kV shut down boards shall be operable.

2. An additional source of power con-sisting of one of the following:

a. One 161-kV transmission line and its associated common trans former or cooling tower trans-former capable of supplying pow to the unit 3 shul:down boards.

b. A third operable diesel genera-tor.

3. At least one unit 3 480-V shutdown board must be operable.

3. 9 BASFS The ob)ective of this specification is to assure an adequate source o' electrical power to operate facilities to cool the unit during shut-down and to operate the engineered safeguards following an accident.

There are two sources of alternating current electrical energy available, namely, the 161-kV transmission system, and the diesel generators.

The 161-kV offsite power supply consists of two lines which are fed from different sections of the TVh 161-kV grid. In the normal mode of opera-tion, the 161-kV system is operating and four diesel generators are opera-tional. If one diesel generator i'i out of service, there normally remain the 161-kV sources, and the other three diesel gcncrators. For a diesel generator to.'be considered operable its associated 125 V battery must be opeiable.

The minimum fuel oil requirement of 103,300 gallons is sufficient for 7 days of full load operation of 3 diesels and is conservatively .based on availability of a replenishment supply.

Offsite auxiliary power for Browns Ferry Nuclear Plant is supplied from two sources; either the unit station transformers, or from the lb'-kV trans-mission system through the common station transformers or the cooling tower trans-former. If a common station transformer ia lost, the unit can continue to operate

.since the unit station transformer ia in aeryice, the other common station trans-former and the cooling tower t'ransformers are available, and four diesel generators are operational.

A 4-kY shutdown board is allowed to be out of operation for. a brief period to allow for maintenance and testing, providing all remaining 4-kV shutdown boards and associated diesel generators CS, RHR, (LPCI and Containment Cooling) Systems supplied by the remaining 4-kV shutdown boards, and all emergency 480 V power boards are operable.

There are four 250-volt d-c battery systems each 'of which consists of a battery, battery charger, and distribution equipment. Three of these sys-tems provide power for unit control functions, operative power for unit motor loads, and alternative drive power for a 115-volt a-c unit preferred motor-generator set. One 250-volt d-c system provides power for common plant and transmission system control functions, drive power for a 115-volt n-c plant prcf'erred motor-generator set, and emergency drive power for certain unit large motor loads. The four remaining systems deliver con-trol power to the units 1 and 2 4160-volt shutdown boards.

246

The 250-volt d-c system is so arranged, 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 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.

247

0-4.9 BASES The monthly tests of the diesel generators are primarily to check for failures and deterioration in the system since last use. The diesels will be loaded to at least 75 percent of rated power while engine and generator temperatures are stabilized (about one hour). The minimum 75 percent load will prevent soot formation in the cylinders and in)ection nozzles. Opera-tion up to an equilibrium temperature ensur'es that there is no overheat problem. The tests also provide an enpine and generator operatinp history to be compared with subsequent enpine-generator test data to, identify and to correct any mechanical or electrical deficiency before it can result in a system failure.

The test during refuelinp outages is more comprehensive, including proce-dures that are most effectively conducted at that time. These include automatic actuation and functional capability tests to verify that the penerators can start and be ready to assume load in 10 seconds. The annual inspection vill detect any signs of wear lonp before failure.

Battery maintenance vith regard to the floating charge, equilizinp charge, and electrolyte level vill bc based on the manufacturer's instruction and sound maintenance practices. In addition, written records will be main-tained of the battery performance. The plant batteries will deteriorate wrath time but precipitous failure is unlikely. The type of surveillance called for in this specification is that which has been demonstrated through experience to provide an indication of a cell becoming irregular or unser-viceable lonp before it becomes a failure.

The equalizinp charpe, as recommended by the manufacturer, is vital to main-taininp the Ampere-hour capacity of the battery, and vill be applied as recommended.

The tcstinp of the logic systems will verify the ability of the lopic systems to bring the auxiliary electrical system to runninp standby readiness with the presence of nn accident signal from any reactor or an undervoltape signal on the start buses or 4-kV. shutdown boards.

REFERE'ACES

l. Aormal Auxiliary Power System (BFNP FSAR subsection 8.4)

2. Standby A.C. Power Supply and Distribution (BFNl'SAR subsection 8.5)

3. 250-volt D.C. Power Supply and Distribution .(BFNP FSAR subsection 8.6) 248

l.lMETING CONI)1TIONS FOR OPYRATION SljRVEILLANCE RE UIREMENTS

3. 10 CORE AI.TERATIONS 4o l0 CORE ALTERATIONS A licabilit Applies to. the fuel handling Applies to the periodic testing

.and.core re'activity limits'tions. 'of -those interlocks and instru-mentation used during. refueling and core alterations.

~Ob ective ~Ob ective To ensure that co're reactivity To verify the operability of is within the capability of instrumentation and interlocks the control rods and to prevent used in refueling and core criticality during refueling. alterations.

S eciiication S ecification A, Rcfuelin Inteilocks h. Refuelin Interlocks

1. The reactor mode switch l. 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 oper'able except tested. They shall be as specified in 3.10,A.S tested at weekly inter-and 3.10.h.6 below. .. vals. ther'eafter until no longer required. They shall also be tested fol-loving any repair work associated with the inter-locks.

2. Fuel shall not be loaded 2. Prior to performing con-into the reactor core trol rod or control rod unless all control rods drive maintenance on con-are- fully inser ted. trol cells without removing fuel assemblies, it shall be demonstrated that the c'ore can be made subcr'itical by a margin of 0.38 percent hk at any time during the maintenance vith the strongest operable control rod fully withdrawn and all other operable rods fully inserted. Alterna-tively if the remaining

l.<BITING CONI)ITIONS

~ FOR OPFRATZON SURVEILLANCE R ZREHENTS

~ O.A Rc fuelin Interlocks 4.10.A Refuelin Znterlocks control rods are fully inserted and have had their- directional con-trol valves electrically disarmed, it is suffi-cient to demonstrate that the c'ore's sub-c'ritical vith a margin of at least 0;38 4k at any time during the maintenance., h control rod on which maintenance is being performed shall, be 'considered 'inoperable.

3. The fuel grapple hoist load switch shall be set at < 1,000 lbs.

4. IE the frame-mounted 'auxi-

, liary hoist, tha monorail-mounted auxiliary hoist, or the service 'platform hoist is to be used for handling ..

fuel Mith the head off vessel,'the, loadthe'eactor limit switch on the hoist to'be used shall be'set at *

~ < 400 lbs.

5.' maximum 'of two non-adjacent control rods may bc Mithdrawn from the core for thc purpose of perfor-ming control rod and/or control rod drive mainten-ance, provided .the follow-ing conditions are satis fied:

s. The reactor mode a@itch shall bc locked fn the "refuel" position. The refueling interlock Mhich prevents more than one control rod from being withdravn may be bypassed for one of the control rods on vhich maintenance is being performed. All other 25D

~. LIMITING CONUITIONS FOR OFERATION SURVEILLANCE RE UIREMFNTS ~

3.10.h Rcfuclin Interlocks 4.10.A Rcfuelin Interlocks' refueling'interlocks shall be operable.

b. A sufficient number o' control rode shall be

~ 'perabl'e so that the core can b'e made sub-critical with the strongest operable con<<

trol rod fully with-drawn and all other operable control rods

'fully inserted, or all directional control valves for remaining control rods shall be disarmed electrically and sufficient margin to crit'icality shall be demonstrated.

C~ If maintenance is to be performed on two control rod drives they must be separated by more than two control cells in any direction.

d. An appropriate number o f SRM'. are available as defined in specifi-cation 3.lO.A.

6. hny number of control rods may be withdrawn or removed from the reactor core pro-viding thc following condi-tions are satisfied:

a~ The reactor mode "re-switch's, locked in the fuel" position. The refueling interlock which prevents more than one control rod from 251

(

LlMlTlNC CONnlTlONS FOR OPERATION SURVEILLhNCE RE UIREMENTS 3..10. A Rc Iuc lin Interlocks 4.10,h Refuelin Interlocks being withdrawn may be bypassed on a withdrawn

. 'control rod after the fuel assemblies in the cell c'ontaining (con-,

trolled by) that con-trol rod have been re-moved from the reactor core. All other re-fueling interlocks shall be operable; ii. Care Honit~oein B. Core Monitorin During core alterations two Prior to making any alterations SRiM's shall be 'operable, onc to the core the SRM's shall be in the core quadrant where fuel functionally tested and checked or control. rods are being moved for neutron response. There-and one in nn ad)acent quadrant. after, while required to be For an SRM to be considered operable, the SRM's will be

~

operable, thc following .condi<< checked daily for response.

tions shall bc satisfied:

l. The SRM shall be inserted to the normal operating level.

(Use of special moveable, dunking type detectors during initial fuel loading and ma)or core altciations in place of- normal detectors is pcrmissiblc as long as the detector is connected to the normal SRM circuit.)

2. The SRH shall have 'a minimum of 3 cps with all rods fully inserted in the core.

C. ~S ent Fuel Pool Mater C. S ent Fuel Pool Mater

1. Mhencvcr irradiated fuel is 1. Mhenever irradiated fuel is stored in thc spent fuel pool, stored in the spent fuel pool, thc pool water level shall be the water level and temperature maintained at a depth oi' 1/2 shall be recorded dai1y.

i'eet or greater above the top of the spent fuel.

R52

LIMITItI0 COIII)I'I'V)IIS P)II OI'I'IIA'I'TON. aSURVHDiLANCI". IIIXIITBINI".NT.>

'3.10.C S ent I'uel Pool Water 4.10.C S ent Fuel Pool Water

2. IIhenever irradiated fuel is'n 2. A sample of fuel pool water the fuel pool, the pool water shall be analyzed in accordance temperature shall be < 150'P. with the following specifi-cations:

'3. Fuel pool water shall be main-tained within the following a. At least daily for con-limits: ductivity and chloride ion content.

"conductivity < 10 umhos/cm 9 25 C b. At least once per 8 hours for conductivity and chloride chlorides < 0.5 ppm content when the fuel pool cleanup system is inoperable.

252a '

1.7MITJNG COND1TIONS FOR OPERATION SURVEILLANCE RE UIREMENTS

3. 10. D Rcac'tor Buildin Crane 4.10.D Reactor Buildin Crane

l. The

'hall reactor building crane be aperable: ~

1, The

'hecks j

folloMin operational and inspections shall be performed on the reactor

e. Mhen a spent fuel cask building crane prior to is handled. handling of a spent fuel cask and neo or spent fuel.

b. Mt>cncver neM or spent (These need not be performed fuel is handled vith 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 hoist.

b. h visual inepectian shall be made to insure structural integrity of, the 125-ton hoist, the 5-ton hoist and cask yoke safety vire ropes,

c. The over'travel limit evitch interlocks, move-ment speed control and braking operations far the bridge, trolley and hoists, the pendant inter-locks, the main-auxiliary .

hoist operation interlock, and the remote emergency stop shall be functionally tested.

1. Upon receipt, an'empty 1. Prior to attachment and fuel cask shall not be lifting of an empty spent lifted until a visual fuel cask fram the shipping inspection is made of the trailer, a visual inspection cask-lifting trunnione and shall be conducted on the fastening connection 'has lifting trunnions and the been conducted. fasteners'sed to cannect the trunnion to the cask.

25$

t I

I. ltd I 'I'N(A COMI) ITIOUS FOR OPF RAT ION 3.10.1 ~Sent Fuel Cnsk SURVEILLANCE RE UIREMENTS 4.10.E S ent Fuel Cask

2. A visual inspection shall be 'made of the assembled trunnion on the empty cask to insure proper assembly.

Rc fuel in Floor

l. Aclministrativc control shall bc exercised to limit the height the spent fuel cask is raised above the refueling floor by the reactor building crane to G inches, except for entry into thc cask decontamina-

, tion'hamber'vhcre height above

'he (loor vill bc approximately.

3 feet.

2. Thc spent fuel'ask yoke safety 1inks shall be properly at all times except posi-'ioned vhcn tlic cask .is in the decon-Lamination chamber.

I

3. 10 OASES A. Rc fucl in Interlocks The refueling interlocks are designed to back'upprocedural core reacti-vity controls during- refueling operations. The interlocks prevent an inadvertent criticality during refueeling operations'when- the reactivity potential of the core is being altered.

To minimixc the possibility of loading fuel into a cell containing no control rod, it is required that all control. x'ods axc fully inserted .when fuel is being loaded into the reactox core> This requirement assures that during refueling the refueling interlocks, as designed, will prevent in-advertent criticality.

Thc refueling interlocks reinforce opex'ational procedures that prohibit taking thc rcactox', critical under certain situations encountered during rcfucling operations'by restricting the movemint of control rods and the operation of refueling equipment.

The refueling interlocks include circuitry which senses the condition of the refueling equipment and the control rode. Depending. on the sensed condition, interlocks are actuated which prevent the movement of the xe-fueling equipment or withdrawal of control rods {rod block).

Circuitry is provided which senses the following conditions:

l. All rods inserted.,

2. Rcfucling 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'ot full up.

5,: Service platform hoist fuel>>loaded.

6. One rod withdrawn, When tlie mode switch is in the "Re<<fuel" position, interlocks prevent the refueling 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 .

the 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 he withdrawn. The refueling interlocks, in combination with core nucjcar design and refueling procedures, limit the probability of an inadvertent criticality. The nucleax characteristics oi. the core assure than the reactor. is subcritical even when the highest worth control rod is fully withdrawn. The 'combination of refueling intexlocks for control 2js

BASKS rods and the refueling platform provide redundant methods of preventing inadvertent criticality even after 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 vhen the interlock 'is required consists of the vcight of thc 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 vith either of the three auxiliary hoists and still maintain the refueling interlocks. The 400-ib load-trip setting on these hoists 'is adequate to trip the interlock when nne of the more than 600-lb fuel bundles is be'ing handled.

During certain periodsy it is deairablo to perform maintenance on tvo control rods an'd/or control'od drives at the same time. The maintenance is performed vith the mode svitch in Che "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'ecessary to bypass the refueling interlock on the first control rod which prev'cnts more than one control rod 'from being withdrawn at the same time.. The requirement Chat an adequate shutdovn 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 Shat the core is shut dovn by a margin of,0.38 percent hk with the strongeot operable control rod fully vithdravn, or that at .

, least 0.38X hk shutdown margin is available if the remaining control rnds have had their directional control valves disarmed. Disarming the direc-tional control valves does not inhibit control rod scram capability.

Specification 3.10.h.6 allovs unloading oi' significant portion of the reactor core. This operation is performed vith the mode svitch 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 vithdrawn control rod which prevents more than one control rod from being withdravn at a time. The requirement that the fuel assemblies in the cell controlled by thc control rod be removed from .the react'or co'rc before the interlock can be bypassed ensures that vithdraval of another control rod does in inadvertent criticality..Each control rod provides primary not'esult reactivity 'control for the fuel assemblies in the cell associated vith 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 SRM operability during these core alterations assure sufficient core monitoring".

256

3. 10 BASI S

!hiI'IRINCES

1. Rc fuclinp interlocks (BFNP FSAR Subsection 7. 6)

Cora Monitorinp The SRM's are proviclad to monitor the core during periods of station shutdown and to puide the operator durinp refueling operations and station startup. Requiring two operable SRM's in or ad)acent to any core quadrant where fuel or control rods are being moved assures ade<<

quate monitorinp of that quadrant durinp such alterations. The require>>

mant of 3 counts per seconal provides assurance that neutron flux is bcinp monltorcd and insures that startup is conducted only if the source range flux level is above the minimum assumed in the control rod drop accident.

ltl;.FERENCI',S

1. Neutron Monitorinp System (BFNP FSAR Subsection 7.5)

2. 'orpan, M. R., "In-Cora Neutron Monitoring System for General Electric Boilinp Mater Reactors," General Electric Company, Atomic Power Equipment Department, November 1968, revised April 1969 (APED-5706)

C. S cnt Fuel Pool Mater Thc dcsipn of tha 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 aipht and one-half feet over the top of the stored assemblies will provide shieldinp such that the maximum calculated radiolopical doses do not exceed the limits of 10 CFR 20.

.Thc normal water level provides 14-1/2 feet of additional water shielding.

Thc capack ty of thc skimmer surge tanks is available to maintain the water level at its normal haipht for three days in the absence of additional water input from the condcnsata storage tanks. All penetrations of the fuel pool-have been installsli at such a height that their presence does not provide a possible drainage route that could lower the normal water lcvci morc than one-half foot.

The fuel pool cooling syst m is designed to maintain the pool water temperature less than 125' during normal heat loads.

core is completely unloaded when the pool contains two previous If the reactor discharge batches, the temperature may increase to greater than 125'.

The RHR system supplemental fuel pool cooling mode vill be used under these conditions to maintain the pool temperature to less than 125'.

t Reactor 8<<ildin Crane The reactor building crane and 125-ton hoist are 'required to be operable for handling of thc 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.

h visual. inspection of thc load-bearing hoist wire rope assures detec-tion nf'igns of distress or wear so that corrections can be promptly made tf <<ceded.

'I'lie testing of thc various limits and interlocks ass<<res their proper operation when the crane is used.

3. 10. I'./~i. I O. I

~Sent Fuel Cask Thc spent fuel cask design incorporates removable .lifting trunnions.

Thc visual inspection of thc trunnions and fasteners prior to attach-ment to thc cask assur'es that no visual damage has occurred during prior handling. Thc trunnions must be, properly attached to 'the cask for lifttnI; nf the, cask and the visual inspection assures correct installation.

l. In.y k~one I:nnl (:aak Ilandlln - IIefnolln Plane Although single failure protection has been provided in the design'f thc 125-ton hoist drum shaft, Mire ropes, hook and lover block assembly on'. thc reactor biiildiag crane, the limiting of lift height of a spent fuel cask controls thc amount of energy availablc in a dropped cask accident when thc cask is over the refueling floor.

An analysis lies been made which shows that the floor and support members in t.hc area of cask entry into the dccoittamination facility can satis-factorily sustain a dropped cask from a height of 3 feet.

Tlute yoke safety links provide single failure protection for the hook and lower block assembly and limit cask rotation.. Cask rotation is necessary for decontamination and the safety 3.<~s are removed during ctccontamination.

259

A. Re fuel in Interlocks C mplctc functional testing of all refueling interlocks before any refueling outage will provide positive indication that the interloc k s operate in the situations for which they were designed. By loading each h*l.st with a wcipht equal to the fuel assembly, positioning the rcf<<cling platform, and withdrawing control rods, the interlocks can be sub)ected to valid operational tests. Where redundancy is provided in thi logic circuitry, tests can be performed to assure that each redun-dant log5c clement can independently perform its function.

ll. (:nrc .'ln<<itor5np Rrq<<l ring thc SRN's to be functiona]ly tested prior tn any core altcra-t in>> ass<<ms that thc SRN's will be operable at the start of that alteration. Thc daily response check of the SRM's ensures their con-t 5n<<cd operability.

Ri'.FRRl:.WCi'.S 1, F<<cl l'ool Cooling and Cleanup System (BFHP FSAR Subsection 10.5)

?, Spent Fuel Storage (BFNP FSAR Subsection 10.3) a6o

5.n MA.IOR DESIGN FEATURES

5. I SITE FL'ATURES

"<<wns Ferry units 1, 2, and 3 are located at Browns perry Nuclear plant site on property owned by the United States and in custody of the TVA. The site shall consist of approximately 840 acres on the north shore of" 1&cele'r Lake at Tennessee River Mile 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.

5.2 REACTOR A. The core sha11 consist of 764 fuel assemblies of 63 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 in 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 CONTAINMENT A. The principal design parameters for the primary containment shall be as given in Table 5.2>>1 of the FSAR. The applicable design codes shall be as described in Section 5.2 of the FSAR.

B. The secondary containment shall be as described in Section 5.3 of the FSAR.

C. Pcnctrations 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

h. 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 t'han 0.95 (Section 10.2 of FSAR),

261

5.0 HAJOR DESIGN FEATURES (Continued)

8. The k eff of the spent fuel storage pool shall be less than or equal to 0.90 for normal conditions and 0.9~r for abnormal conditions (Sections 10.3 of the FSAR).

5.6 SEISMIC DESIGN The station class I structures and systems have been designed to withstand a design basis earthquake with ground accelera-tion of 0.2g. The operational basis earthquake used in the plant design assumed a ground acceleration of O.lg (see Section 2.5 of the FSAR).

262

6. 0 ADHINISTRATIVE CONTROLS 6.1 ~Or anization A. The plant superintendent has on-site responsibility for the safe operation of the facility and shall report to the Chief, Nuclear Generation Branch. In the absence of the plant superintendent, the assistant superintendent 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 'n Figure 6.1-2.

D. Shift manning requirements shall, as a minimum, be as described in section 6.8.

E. Qualificatkons of the Brown Ferry Nuclear Plant management and operating staff shall muut the minimum acceptable levels as described in ANSI. Hi.8.1, Selection and Training of Nuclear Power Plant Personnel, dated starch 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. A'n Industrial Security Program shall be maintained for the life of the plant. I 6.2 Review and Audit The Manager of I'ower is responsible for the safe operation of all TVA power plants, including t.he Drowns Ferry Nuclear Plant. The functional organization for Review and Audit is shown in Figure 6.2-1.

263

.Organizational units for the review of facility operation shall be constituted and have the responsibilities and authorities listed below.

A. NuClear'Safest 'Re iM:Board (NSRB)

The NSRB.shall consist of a chairman and at leastfive other members appointed or approved by the Manager of Power. A ma)ority of the members shall be independent of the Division of Power Production. The qualifications of members shall meet the requirements of ANSX Sthnctard. N3.8.7-1972.

Membership shall include at least one outside consultant and representatives of the following TVA organizations: Office of Engineering Design and Con-struction; Division of. Envoi.ronmental 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 uenc The NSRBshall meet at least quarterly and at more frequent intervals at the call of the chairman, as required.

3. Quorum A quorum shall consist of four members, a minority nf which shall be from the Division of Power Production.

4, Res onsibilities

a. Review proposed tests and experiments, and their results, when such tests or experiments may constitute an un-reviewed safety question as defined in Section 50.59, Part 50, Title 10,'ode of Federal Regulations.

b. Review proposed changes to equipment, systems or pro-cedures, which are described in the Final Safety Analysi.s 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 opera-ting organization.

c. Review proposed changes to Technical Specifications or licenses.

d. Review violations of applicable statutes, codes, regulations, orders, Technical Sp cifications, license requirements, or of internal procedures or instructions having safety

, significance.

264

e. Review significant operating abnormalities or deviations from normal and expected performance of plant equipment.

f. Review abnormal occurrences, as defined in the Technical Specifications.

g. 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, condi-

'ions and intent of any license, permit, or other applicable regulations.

i. Review the minutes of Plant Operations Review Ccmmittee meetings to determine if matters considered by that committee involve unreviewed or unresolved safety questions.

5. ~Authorft

'he Nuclear Safety Review Board shall be advisory to the Yanager oi:

Power in matters relating to nuclear plant safety.

The Nuclear Safety Review Board shall have access to all TVA m:"..lear facilities, as well as design, construction, and operating records as necessary to perform its a'ssigned functions.

Members have access to advice and services of technical specialists within their respective organizations and outside consulting services are available as required through con-tractual arrangements.

6. Records The chairman shall prepare a final copy of the minutes and forward them to the Manager of Power. 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, composition, and mission. of theNSRB 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.

265

B. Plant 0 erations Review Committee PORC)

The PORC shall consist of the plant superintendent, assis-tant plant superintendent, maintenance supervisor, health physics supervisor, operations supervisor, power plant results supervisor, and QA staff 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.

2. M~eetin Fre3ucnc~

The PORC shall meet at regular monthly intervals and for special meetings as called by the chairman or as requested

~

by individual members.

3. guorum Superintendent or assistant superintendent, plus four of the five other members, or their alternate, will constitute a quorum. Awembqr will be considered present if he is in telephone communication with the committee.

4. Duties and Res onsibilities The PORC serves in an advisory capacity to the'lant superin-tendent and as an investigating and reporting body to the Nuclear Safety Review Board in matters related to safe'ty in plant operations. The plant superintendent has the final responsi-bility in determining the matters that should be referred to the Nuclear Safety Review Board.

The responsibility of the committee will include:

a. Review all standard and emergency operating and main-tenance instructions and any proposed revisions thereto, with principal attention to provisions for safe operation.

b. Review proposed 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 d.'nvestigate reported or suspected incidents involving safety questions, violations of the Technical Specifications, and violations of plant instructions pertinent to nuclear safety.

266

e. Review abnormal occurrences, unusual events, operating anomalies and abnormal performance of plant equipment.

f. Maintain a general surveillance of plant activities to identify possible safety hazards.

g, Review plans for special fuel handling, plant maintenance, operations, and tests or experiments which may involve special safety considerations, and the results thereof, where applicable.

h. Review adequacy of quality assurance program and recom-mend any appropriate changes.

i. Review implementating procedures of the Radiological Emergency Plan and the Industrial Security Program on an annual basis.

Review adequacy oi'mployee training programs and reccommend change.

5. ~Authortt The PORC shall be advisory to the plant superintendent.

6. Records Minutes shall be kept for all PORC meetings with copies sent to Director, Powex'roduction; Chief, ?iucloar Generation Branch; Chairman, NSRB.

7. Procedures Written administrative 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. ualit Assurance and Audit Staff The Office of Power Quality Assurance and Audit Staff (QAGAS) shall formally audit operation of the nuclear plant. Audits of selected aspects of plant operations shall be conducted on a frequency commensurate with their safety significance and in such a manner as to assure that an audit of safety-related activities is completed within a period of two years.

The audits shall be performed in accordance with appropriate written instructions or procedures and should include verification of compliance with internal rules, procedures (for example, normal off/normal, emergency, 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 abnormal occurrences.

267

6. 3 Procedures

h. Detailed written procedures, including applicable check-off lists 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.

267a

4. Emergercy conditions involving pote:.tial or actual release of radioactivity.

5. Preventive or corrective maintenance operations which could have an effect on the safety nf the reactor.

6. Surveillance and testing requirements.

7. Radiation control procedureo.

8. Radiological Emergency Plan implementing procedures.

9. Plant security program implementing procedures.

Mritten procedureo pertaining to those items listed above shall be reviewed by PORC and approved by the plant superintendent prior to implementation except that temporary changes to pro-cedures which do not change the intent of the origina'rocedure may be made with the concurrence r.f two persons holding senior operator licenses. Such changes shall be documented and subse-quently reviewed by PORC and approval by the plant superintendent.

C. Drills on actions to be taken under emergency conditions involving release of radioactivity are specified in the radiological emer-gency plan and shall be conducted annually. Annual drills shall also be conducted on the actions to be taker. following failures of

'safety related systems or components.

D. Radiation Contxol Procedures Padiation Control Procedures shall be maintained and. made available to aU. station personnel. These procedures shall show permissible radiation exposure and shall be consistent with the.

requirements of 10 CFR 20. This radiation protection program shaU. be organized to neet the requiremen0s of 10 CFR 20 except in lieu of the "control device" or "alarm oigna1" required by paragraph 20,203(c)(2) of 10 CFR 20; Each High Radiation Area in which the intensity of radiation is greater than 100 mrera/'n" but less than 1,000 mrem/hr shall bc 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 thon 1,000 mrcm/hr shall be subject

'to the provisions of (o.) above; and, in addition, locked doors shall be provided to prevent unauthorized entry into such axeas, and the keys shal1 be maintained under adnd.nistrative control of the shift engineer on dutye

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 authori.zed by the operating license for this plant in determining whether individuals in restricted areas are exposed to concentrations in excess of the limits specified in Appendix 8, 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.

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 268a

controlled so that the r>~ f v..'ve content of any critical organ from all routes nf intake averaged over 7 consecutive days does not cx a "! that which would resul't from inhaling such radioactive material, for 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> at'he pertinent concentration values provided in Appendix B, Table I, Column 1 of 10 CFR 20.

1 C ~ For radioactive materials designated "sub" in the "Isotope" column of Appendix B, Table I, Column 1 of 10 CFR 20, the concentration value specified is based upon exposure to the material as an external radiation source. Individual exposures to these materials shell be accounted for as part of tne I!mitation on indivi-dual dose fn 20.10l. These materials shell be subject to applicable process and other engineering controls.

4. In all operations in which adequate limitation of the inhala-tion of radioactive materiel by the usc of process or other engineering controls is impracticable, the llccnsce mny permit an individual in e restricted area to use respiratory protective equipment to limit the inhalation of airborne radioactive material, provided:

a. The limits specified in paragraph above are not exceeded.

1 Respiratory protective equipment is selected and used so that the peak concentrations of airborne radioactive material inhaled by an individual wearing the equipment does not exceed the pertinent concentration values spcci-ficd in Appendix B, Table I, Colu'mn 1, of 10 CFR 20.

For the purposes of this subparagrepn, the concentration of radioactive material that is inhaled when respirators are wn'rn may'be determined by dividing the ambient.air-borne concentration by the protection factor specified in Table 16.3.A, ~nnended to this spc'if lection for t~ic respira-tor protective equipment worn. If the intake or radio-activity is later determined by other measurements to have been different than that initially estimated, the later quantity shall be used in evaluating the exposures.

C ~ 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 psychological discomfort, or any other condition that might cause reduction in the protection afforded the wearer.

d. Thc licensee maintains e respiratory protective program adequate to assure chat the requirements above are mct and indorporates practices for rcspirntory proasction consistent with those recommended by the American National Standards Institute {ANSI-Z88.2-1969). Such e.program .

shall include:

(1) Air sampling and other survey; suf ficient to identify the hazard, to evaluate individual exposures, 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)'ritten procedures to assure the adequate fitting of respirators; and the testing of respiratory protective equipment 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 operational and administrative procedures for proper use of respiratory protective equipment including provisions for planned limitations on

'working times as necessitated by operational'con-ditions.

(6) Bioassays and/or whole body counts of individuals (an other surveys, as appropriate) to evaluate

'individual exposures and to assess protection actually provided.

e. The licensee uses equipment approved by the U.S. Bureau of Mines under its appropriate approval schedules as set forth in Table 6.3.A below. Equipment not approved under U.S. Bureau of Hines Approval Schedules may be used only if the licensee has evaluated the equipment and can demon-strate by testing, or on the basis of reliable test infor-mation, that the material and performance characteristics of the equipment are at least equal to those afforded by U.S. Bureau of Mines app'roved equipment of the same type, as specified in Table 6.3.A below.

f. Unless otherwise authorized by the Commission, the licensee does not assign protection factors in excess of those speci-fied in Table 6.3.A below in selecting and using respira-tory protective equipment.

5. These specifications with respect to the provision of 20.103 shall be superseded by adoption of proposed changes to 10 CFR 20,'ection, 20.103, which would make this specification unneces-sary.

270

Table 6.3.A PROTECTION FACTORS FOR RESPIRATORS PROTECTION FACTORS 2/ GUIDES TO SELECTION OF EQUIP~~T PARTICULATES BUREAU OF NINES APPROVAL SCHEDt:LES*

DESCRIPTION .tODES- AND VAPORS AND FOR EQUIPMENT CAPABLE OF PROVIDING AT GASES EXCEPT LEAST EQUIVALENT PROTECTION FAC.ORS TRITIUM OXIDE- *or schedule superseding for equip. ent of type listed I. AIR-PURIFYING'ESPIRATORS Facepiece, half~sk 4/ 7/ '5 2lB 30 CFR 14.4(b)(4)

Facepiece, full 7/ -NP 100 21B 30 .CFR 14.4(b)(5); 14F 30 CFR 13 II ATHOSPHERE-SUPPLYING RESPIRATOR

1. Airlfne Res irator Facepiece, half-mask CF 100 19B 30 CFR 12.2(c)(2) Type C(i)

Facepiece, full CF 1,000 19B 30 CFR 12.2(c)(2) Type C(i)

Facepiece, full 7/ D 100 19B 30 CFR 12.2(c)(2) Type C(ii)

Facepiece, full PD 1,000 19B 30 CFR 12.2(c)(2) Type C(iii)

Hood CF 5/ 6/

Suit CF 5/ 6/

2. Self-contained

~breathin a ratus (SCBA)

Facepiece, full 7/ D 100 13E 30 CFR 11.4(b)(2)(i)

Facepiece, full PD .1,000 13E 30 CFR 11.4(b)(2)(ii)

Facepiece, full R li000 13E 30 CFR 11.4(b)(1)

III. COHBINATION RESPIRATOR Any combination of air- Protection factor 19B CFR 12.2(3) or applicable purifying and atmosphere- for type and mode schedules as'isted above supplying respirator of operation as listed above 1/, 2/, 3/, 4/, 5/, 6/, 7/, (These notes are on the following pages)

I/,Sce thc following symbols:

CF: continuous flow D demand NP ncgat ive pressure (i.e., negative phase- during inhalation)

PD: pressure demand (i.e., always positive pressure)

R rcc ircula t ing (closed circuit) 2/ (a) For purposes of this specification the protection factor is a measure of the degree of protection afforded by a respirator, defined as the ratio of the concentration of airborne radio-active material outside the respiratory protective equipment to that inside the equipment (usually inside the facepiece) ~

under conditions of use. It is applied to the ambient air-borne concent'ration to estimate the 'concentration inhaled by the wearer according to the following formula:

Ambient Airborne Concentration Concentration Inhaled ~ Protection Factor (b) The protection factors apply:

(i) only for trained individuals wearing properly fitted respirators used and maintained under supervision in a well-planned respiratory protective program.

(ii) for air-purifying'espirators only when high efficiency (abovc 99.9X removal efficiency by U.S. Bureau of Mines type dioctyl phthalate (DOP) test) particulate filters and/or sorbents appropriate to the hazard are used in atmospheres not deficient in oxygen.

(iii) for atmosphere-supplying respirators only when supplied with adequate respirable air.

3/ Excluding radioactive contaminants that present an absorption or submersion hazard. For tritium oxide approximately half of the intake occurs by absorption through the skin so that an overall protection factor of not more than approximately 2 is appropriate when atmosphere-supplying respirators arc used to protect against tritium oxide. Air-purifying respirators are not recommended for use against tritium oxide. See also footnote 5/, 'below, concerning supplied-air suits and hoods.

4/ Under chin type only. Not recommended for use where it might be possible for the ambient airborne concentration to reach instan-taneous values greater than 5 times the pertinent values in Appendix B, Table I, Column 1 of 10 CFR, Part 20.

s/ Appropriate protection factors must be 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 authorized by the Commission.

6/ No approval 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 be approved by the U.S. Bureau of Mines 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 t)iis table. The protection factors in this table may not be appropriate to circumstances where chemical or other respiratory hazards exist in addition to radioactive hazards. The selection and use of respirators for such circumstances should take into account approvals of the U.S. Bureau of Mines in accordance with its applicable schedules.

NOTE 2: Radioactive contaminants for which the concentration values in Appendix B, Table I of this part are based on internal dose due to inhalation may, in addition, present external exposure hazards at higher concentrations. Under such circumstances, limi-tations on occupancy may have to be governed by external dose limits.

6.4 Actions to be Taken in the Event of an Abnormal Occurrence in Pla~nt 0 eratinn A. Any abnormal occurrence shall be promptly reported'to the Chief, Nuclear Generation Branch and shall be promptly ~viewed by PORC This committee shall prepare a separate report for each abnormal occurrence. This report shall include an evaluation of the cause of the occurrence and recommendations for appropriate action to prevent or reduce the probability of a repetition of the occurrence.

B. Copies of all such reports shall be submitted to the Ch<<fP Nuclear Generation 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 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, as specified in Specification 6.7 of the circumstances of any abnormal occurrence. A written report shall follow within 10 days.

6.5 Action to be Taken in the Event a Safet ).imit is Exceeded If a safety limit is exceeded, the reactor shall be shut down and reactor operation shall not be resumed until authorized by the NRC, A 273

prompt report shall be made to the Chief, Nuclear Generation Branch and the Chairman of the NSRB. A complete analysis of the circum-stances leading up to and resulting from the situation, together with recommendations to prevent a recurrence, shall be prepared by the PORC. This report shall be submitted to the Chief, Nuclear Generation Branch, the Manager of Power, the Division of Power Resource Planning, and the NSRB. Notification

,cf such occurrences will.be made to theNRC by the plant superintendent within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as specified in Specification 6.7.

6.6 Station 0 eratin Records A. Records and/or logs shall be kept in a manner convenient for review as indicated below:

l. All normal plant operation including such items as power

'evel,, fuel exposure, and shutdowns

2. Principal maintenance activities

3. Abnormal occurrences

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 experiments to comply with 10 CFR 50.59

6. Radioactive shipments Test'esults, 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 relea.,e<l to the environs

10. Of f-site environmental monitoring surveys ll>> Fuel inventories and transfers 32>> Plant radiation and contamination surveys 13>> Radiation exposures for all plant personnel lrI>> tlpdated, corrected, and as-built drawings of the plant 15>> Reactor coolant system inservic'e inspection

16. Minutes of meetings vf the Nuclear Safetv Review Board 17>> Design fatigue usage evaluation a.. Monitoring, recording, evaluating, and reporting require-ments contained in l5.b, below, will be met for various portions of the reactor coolant pressure boundary (RCPB)

I

for which detailed fatigue usage evaluation per the ASME Boiler and Pressure Vessel Code Section III was performed for the conditions defined in the design specification. In this plant, th'e applicable codes required fatigue usage evaluation for the reactor pressure vessel only. The locations to be monitored shall be:

1. The feedwater nozzles

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 are more severe than the tran-sients evaluated in the stress report, code fatigue usage calculations will be made and tabulated separately.

(3) In the semiannual 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 cumu-lative usage factor reaches a value of 1.0, an inser-vice inspection shall be included for the specific location at the next scheduled inspection (3-1/3-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 evalua-tion shall be submitted in a Special Report (Section 6.7.3) for review by the Commission.

B. Except where covered by applicable regulations, items 1 through 8 above sha11 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 bo maintained current at all times,

1. See paragraph N-415.2, ASME Section III, 1965 Edition.

275

6.7 Re ortin Re uircrnents

l. Routine Reports a.

()~. *"

Operations Reports power escalation testing should be submitted following receipt of an operating license, following an amendment,to the license involving a-planned increase in power level, following the installation of fuel that has a different design or has been manufactured by a different fuel supplier, or follow'ing modifications th'at may have significantly altered the nuclear, thermal, or hydraulic performance of the plant. The report should include a description of the measured values of the 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 should also be described.

Startup Report for Unit 3 should be submitted within (1) 90 days following completion of the stnrtup test program, (2) 90 days following resumption or commencement of commercial power operation, or (3) 9,months following initial criticality, whichever 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 commercial power operation, supplementary reports should be submitted at least every- three months until all three events are completed.

Reports in this category should be submitted in writing to the Director of NRC Regulatory Operations - Region II.

276

(R) aoaiann~ual 0 aratin~~Re orts. Routine operatlnR reporta t

covering t.he operation of the 'previous 6 months should be submitted within 60 days after January 1 and July 1 of each year. The initial report should be submitted within 60 days after the end of the first six-.month period during which initial criticality took place. Each report should include the following:

(a) 0 erations Summar . A summary of operating experience occurring during the reporting period that relates to the safe operation of the facility, including a summary of:

(i) changes in facility design, (ii) performance characteristics (e.g., equipment and fuel performance),

(iii) changes in operating procedures which were necessitated by (i) and (ii) above or which otherwise were required to improve the safety of operations, (iv) results of surveillance tests and inspections required by the licensee's technical specifications,'v) the results of any periodic containment leak rate tests performed during the reporting period, (vi) a brief summary of those changes, tests, and experiments requiring authorization from the Commission pursuant to 10 CFR 50.59(a), and (vii) any changes in the plant operating staff for those positions designated as key supervisory personnel positions in the technical specifications.

(b) Power Generation. A summary of power generated during

..the reporting period including:

. (i) gross thermal power generated (in MWH),

(ii) gross electrical power generated '(in MWH),

(iii) number of hours the reactor was critical, (iv) number of hours the generator was on line, and (v) histogram of thermal power vs. time.

(c) Shutdowns. Descriptive material covering all outages occurring during the reporting period, For each outage; information should be provided on:

(i) the cause of the outage, (ii) the method of shutting, down the reactor; e.g., trip, automatic rundown, or manually controlled deliberate shutdown, (iii) duration of the outage (in hours),

(iv) plant status during the outage; e.g., cold shutdown or hot standby, and (v) corrective action taken to prevent'epetition, if appropriate.

3 A single submittal may be made for a multiple facility station.

The submittal should combine those sections that are common to all facilities at the station.

277

(d) Maintenance. A discussion of corrective maintenance (excludinpreventive maintenance) performed during the reporting period

'on sa.'ety-related systems and components" and on systems and components that rcJuce or prevent the release of radioactive 'materials to the environs.

'or any mal'function for which corrective maintenance was required, information should be provided on:

(i) the system or component involved, (ii) the cause of the malfunction, (iii)

~""'" "

the results and effect on safe operation, and (iv) corrective action taken to prevent repetition.

t ) '""

• summary of the safety evaluation for those changes, tests, and experiments, carried out without prior'ommission approval pursuant to the provisions of 10 CFR 50.59(b).

(f) Primar C'oolant Chemistr . A tabulation on a monthly basis of the maximum, average, and minimum values for the following primary coolant system parameters:

(i) Gross. radioactivity in uCi/ml, (ii) Suspended solids in parts per million, (iii) Gross tritium in uCi/ml, (iv) Iodine 131 in pCi/ml, l tlute-I>> ic JvQJ r )~ w.'I s. r ye~~ Ji JJi bv JvQJne

~~ ~~

~ svo sv vs 4 JJ

~ ~

~4~

(vi) Chloride in parts per million, and (vii) pH at 25'C.

(g) Occu ational Personnel Radiation Ex osure (i) A tabulation of the number of occupational personnel exposures for plant operations personnel (permanent and temporary) in the followinc.posure increments for the reporting period: less than 100 mrem, 100-250 mrem, 250-500 mrem, 500-750 mrem, 750-1000 mrem, 1-2 rem, 2-3 rem, 3-4 rem, 4-5 rem, 5-6 rem, and greater than 6 rem.

~

(ii) A tabulation of the number of personnel receiving more than 500 mrcm exposure in the reporting period according to duty function

[c.g.. rou';jnc plant surveillance and inspection (regular duty), routine plant: r~lutcnance (describe maintenance), routine fueling operation, special rcCucling operation (describe operation), andother )ob-related exposure".]

(iii) A tabulation annually of the number of personnel receiving more than 3 zen and the ma)or cause(s) ~

coolant prcssure boundary, the capability to shut down prevent the reactor and maintain it in a safe shutdown condition, or the capability to or mitigate the conseq'uenccs of accidents which could result in offsite exposur'es comparable to the guideline exposures of 10 CFR Part 100.

278

A report will be submitted to the Commission within 60 days after January 1 and July 1 of each year, specifying the quantity of each of the principal radionuclides released to unrestricted areas in liquid and in gaseous effluents during the previous 6 months of operation, and such other information as may be required by the Commission to estimate maximum potential annual radiat'on doses to the public resulting from effluent releases. The items listed belo~

will make up these repoits:

Effluent Releases Effluent data should be summarized quarterly, except in instances when more detailed data are needed, and the items listed below reported semiannually on the standard form "Report of Radioactive Effluents".

(i) Gaseous Releases 1 total radioactivity (in curies) releases of noble and activation gases.

2 average release rate (~~Ci/sec) of fission and activation gases for the quarterly periods 3 total radioactivity (in curies) releases, by nuclide, based on representative isotopic analyses performed.

4 percent of technical specification limit.

5 quarterly sums of total curies of tritium determined to be released in gaseous effluents.

6 average release rate. (pCi/sec) of tritium.

7 percent of MPC for tritium.

(ii) Iodine Releases 1 quarterly sums of total curies of iodine-131

~

released.

l total radioactivity (in curies) released, by nuclide, based on representative iostopic analyses performed.

percent of technical specification limit for iodine-131.

4 average release rate (yQi/sec) of iodine-131.

(ii'i) Particulate Releases quarterly sums of tota'uries of radioactive material in particulate form with half-lives greater than 8 days determined to be released.

279

2 gross alpha radioactivity released (( in curies) excluding background radioactivity.

3 total radioactivxt.y released (in curies) of nuclides with half-lifes greater than 8 days.

4 percent of technical specification limit for r~~<oactiv>>ster~.al in particulate form with half-lives greater than 8 days,

.5 average release rate (yCi/sec) of radioactive material in particulate form with half-lives greater than 8 days.

(iv) Li uid Releases sums of total curies of radioactive material determined to be released (not including tritium, dissolved and entrained gases, and alpha-emitting material).

2 average concentration (pCi/ml) of the material in item 1.

3 percent of technical specification limit for the average concentration above. l sums of total curies for each of the radionuclides determined to be released.

5 sums of total curies of tritium in liquid effluents.

average concentration (pCi/mg of tritium.

percent of 3 x 10 -3 yCi/ml of average concen-tration of tritium released.

8 sums of total curies of gaseous radioactive material determined to be released in liquid

~ -- effluents.

9 average concentrations (pCi/ml) of dissolved and entrained gaseous radioact've material released to unrestricted areas.

10 percent of technical specification limit of average concentration of gaseous radioactive material.

11 sums of total curies of each radionuclide deter-mined to be released as dissolved and entrained gases in liquid effluents.

280

12 sums of total curies of gross alp)a-emitting

~

material determined to be released\ in liquid e ff luents.

13 sums, in liters, of total'easured volume, prior to dilution, of liquid effluent released.

sums of total determined volume, in liters, of di-lution water used during the period of the report.

15 average flow of the receiving stream during periods effluent release.

(i) Solid Radioactive Waste g) Total quantity in cubic meters an'otal radioactivity in curios for he types of solid waste involved; (ii) An esthnat.. of the ma)or nuclide co@position in the types of waste involved.

(<ii) Dates and. di~osition of solid waste shipments including 5.rradiated fuel 'nipments.'))

Source Tests Results of required leak 'tosts performed. on sources if tho tests reveal tho presence of 0.005 microcurie or more of romovablo contamination, B. Radiolo ical Environmental.'Mnnitorin

a. TVA shall prepare a report entitled "Environmental Radioactivity Levels-Browns Ferry Nuclear Plant - Semiannual Report." The report shall cover

. six-month periods commencing January 1, and July l. The report hall be submitted to NRC during the six months subsequent to the reporting period.

'lv The time required to process the environmental samples precludes submission of the report within 60 days after the sampling period.

280a

I b'f'nuclide statistically significant variations of off-site environmental radio-concentrations with time are observed, a comparison of these results with effluent releases shall be provided.

c. Individual samples which show higher than normal levels (25% above back-ground for external dose, or twice background for radionuclide content) should be noted in the reports.

2. NON-ROUTINE REPORTS A. Events requiring notification within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by telephone and telegraph to the Director of Regulatory Operations, Region II, followed by a written report within 10 days to the Director, Directorat'e of Licensing, USNRC, Washington, DC 20545; with a copy to the Director of the Regional Regulatory Operations Office, shall include:

(1) Incidents or conditions that result in exceeding a safety limit, or that result in safety system settings less con-servative than the limiting safety system setting, or that result in violation of a limiting condition for operations established in the technical specifications, (2). Abnormal degradation of one of the several boundaries which are designed to contain radioactive materials, or any un-planned release of radioactive materials from the site,.

{3) Uncontrolled or unanticipated changes in reactivity which could significantly affect safety operations, (4) Incidents or conditions which prevented or could have prevented the performance of the intended safety function of an engineered safety feature or of the reactor protec-tion system.

(5) Any observed inadequacy in the implementation of admini-strative or procedural controls during. the operation of the facility which could significantly affect. the safety of operations, (6) Occurrences or conditions involving an offsite threat to the safety of operation of the facility, such as torna<<

does, earthquakes, flooding, repetitious aircraft over-flights, attempted sabotage, or civil disturbances.

281

Appendix A to Regulatory Guide 1.16 "Standard Format for Reporting Abnormal Occurrences," should be used as, guidance when submitting abnormal occurrence reports.

B. Events requiring reports within 30 days to the Director of Licensing and to the Director of Regulatory Operations Office, Region II, shall include:

Discovery of any substantial errors in the transient or accident analyses, or in the methods used for such analyses, as described in the Safety hnalayis Report or in the bases for the technical specifications.

(2) Any substantial variance from performance specifications contained in the technical specifications or in the Safety Analysis Report.

(3) Any condition involving a possible single failure which, for a system designed against assumed single failures, could result in a loss of the capability of the system to perform its safety function.

C. Radiolo ical Environmental Monitor~in Anomalous Measurements

1. If, during any six-month report period, a measured level of radioactivity 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, environmental factors, or other aspects necessary to explain the anomalous result.

2. If, during any six-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 'result.

• In the case of a tentatively anomalous value for radiostrontium, 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.

282

Hilk Pathwa Measurements

3. Xf individual milk samples show X-131 concentrations of 10 picocu."ics per liter or greater, a plan shall be submitted within one week advising thc NRC of the proposed action to cnsurc the plant related annual doses will be within the design objective of 15 mrem/yr to the thyroid of any individual.

4. If milk samples collected over a calendar quarter show average concentrations of 4.8 picocuries pcr liter or gxcatex, a plan shall be submitted within 30 days advising the NRC of the proposed action to ensure the plant related annual doses will be within the design ob5ective of 15 mrcm/yr to the thyroid of any individual.

5. Xf such levels as discussed in 6.7.C 3 and 4 can bc definitely shown to result from sources other than the Browns Ferry Nuclear

?lant, the reporting action called for in 6.7,C.3 and 4 need not be taken. Justification fox assigning high levels of radioactivity to sources othcx'han the Hrowns Ferry Nuclear Plant must be provided in thc semi-annual report.

t p. Spl'.CXAL R)'.l>ORTS 7epio~na 1.

Oi Fice:

{in writing to the Directox of the Regulatory Operations Reports on the following areas shall be submitted as noted:

Area Reference Submitta3. Date (3)

a. .Primary Containment 4.7.A Upon completion of Leak Rate Testing (1) each test.

b. Secondary Containment 4.7. C Upon completion of Leak Rate Testing (2) each test.

282a

NOTES: l. Each integrated leak rate test of the primary containment shall be the sub-

)ect of a summary technical report including results of the local leak rate tests since the last report.

The report as described in the AFC Guide on Containment Testing dated January 16, 1966, shall include data, analysis and interpretations of the results'hich demonstrate compliance in meeting the specified leak rate limits.

2. Each integrated leak rate test of the secondary containment shall be the sub-j ec t of a nummary tcchnical repor t.

'his report should include data on the wind speed, wind direction, outside and inside temperatures during the test, concurrent reactor 'building pressure, and emergency ventilation flow rate.

The report shall also include analyses and interpretations of those data which demonstrate compliance with the speci-fied leak rate limits.

l 3~ The report shall be submitted within the period of time listed based on the com-mercial'ervice date as the starting point.

283

6.8 Minimum Plant Staffin The minimum plant staffing for monitoring and conduct of. operations is as follows.

l. A licensed senior operator shall be present at the site at all times when there is fuel in the reactor.

2. A licensed operator shall be in the control room whenever there is fuel in the reactor.

3. A licensed senior operator shall be in direct charge of a reactor refueling operation; i.e., able to devote full time to the refueling operation.

4. A. health physics technician shall be present at the facility at all times there is fuel in the reactor.

5. Two license operators shall be in the control room during any cold startups, while shutting down the reactor, and during recovery from unit trip.

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6. Either the plant superintendent or the assistant plant superintendent shall have acquired the experience and training normally required for examination by theNRC for a Senior Reactor Operator's License, whether or not the eximination is taken. In addition, either the operations supervisor or the assistant operations supervisor shall have an SRO license.

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Table 6.8.A Minimum Shift Crev Re uirements Units in 0 Oration Shift Position of License Shift Engineers (SZ) 1 1 1 SRO Assistant Shift Engineers (ASE) 0, 1 2 Licensed Reactor Operator 1 1 1 RO 1 2 3 Unit Operators (UO}

Assistant Unit Operators (AUO)

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4,

'" 4, 6 Hone Health Physics'echnician I Hone Minimum Shift Cree 8 10 14 Notes: SRO - Seni'or Reactor Operator RO - Reactor Operator Note for Table 6.0.A

1. This position is normally filled by an assistant shift engineer, but as a minimum it may be filled by a licensed reactor operator. When the incumbent is not a senior reactor operator, he shall not be assigned duties requiring him to direct licensed activities of reactor operators.'65

V MANAGER OF POWER DIVISION OF POWER PRODUCTION N I NUCLEAR GENERATION BRANCH NUCLEAR PLANTS BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT TVA OPPICE OF POWER ORGANIZATION POR OPERATION OF NUCLEAR PLANTS FIGURE 6,1-1 286

e' QUALITY PLANT ASSURANCE SUPERINTENDENT MANAGFR SUPERVISOR QUALITY ASSURANCE STAFF DIVISION OF ASSISTANT DIVISION OF QUALITY ENVIRON%NTAL PLANT MEDICAL SERVICES ASSURANCE PLANNING SUPERI NTFNDFNT COORDINATOR QUALITY ASSURANCF.

ENGINEFRS HFILTH MAINTENANCE RESULTS OPERATIONS PHYSICIST NURSF. SUPFRVISOR SUPFRVISOR SUPERVISOR HEALTH TFCHNICAL ASSISTANT. ASSISTANT PHYSICS FNGINFFRS OPFRATIONS MAINTFNANCE TECHNICIANS SUPFRVISOR SUPERVISORS FORFIIEN AhD SHIFT FOREMEN AND INSTRl&IENT OPERATING MFCHANICAL MF.CHANICS PERSONNEL CRAFTSMEVl

~RONHS FERRY NUCLEAR PLAHT FINAL SAFETY ANALYSIS REPORT FUNCTIONAL ORGANIZATION FIGURE 6.1-2

MANAGER OF POWER QUALITY ASSURANCF. NUCLEAR SAFETY AND RHVIHW BOARD AUDIT STAFF

'IVISION OF POWER PRODUCTION NUCLEAR GRKRATION 3RANCH NUCLEAR PLANT SUPERINTENDENT PLMiT OPERATIONS REVIEW COMMITTEE

~ 8ROWHS FERRY HUCLEAR PLANT FIHAL SAFETY ANALYSIS REPORT RFVIEW AND AUDIT FUNCTION FIGURE 6,2-1.

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