ML18025B693

Proposed Tech Spec Changes to Accommodate Reload 4,Cycle 5 Operation

ML18025B693
Person / Time
Site:	Browns Ferry
Issue date:	12/09/1981
From:	TENNESSEE VALLEY AUTHORITY
To:
Shared Package
ML18025B692	List: ML18025B691 ML18025B693 ML20039B701 ML20039B708
References
NUDOCS 8112230437
Download: ML18025B693 (98)

Text

SAFETY LIMIT LIMITING SAFETY SYSTEM SETTING 1

1 U

Ro1 L

Applies to the interrelated variables associated with fuel thecal behavior.

~oh ee ve To establish limits ~hich ensure the integrity of)the fuel cladding.

Applies to trip settings of the instruments and devices which are provided to prevent the reactor syst: em safety limits from being exceeded.

9l~eci~

To define the leve'l of the process variables at which automatic protective action is initiated to prevent the fuel cladding integrity safety limit from being exceeded.

e c

A.,Reactor Pressure

> 800 psia and Core Flow >

10%

of Rated.

When the reactor pressure is greater'han 800 psia, the existence of a minimum critical power ratio

{MCPR) less than 1.07 shall constitute violation of the fuel cladding integrity safety limit.

I The limiting safety system settings shall be as specified below:

ut o APRM Flux Scram Trip Setting (Flow biased)

When the Mode Switch is in the RVN position, the APRM flux scram trip setting shall be:

SS{0.66W i 50%)

where:

S ~ Setting in per-cent of rated thermal power

{3293 MWt) 8112230437 811209j PDR ADQCK 05000296 P

PDR,'

SAFETY LIMIT LIMITING SAFETY SYSTEM SETTING l.l FUEL CLADDING INTEGRITY 2 ~ 1 FUEL CLADDING INTEGRITY If it is determined that either of these design crite'ria is being violated during operation, action

.shall be initiated within 15 minutes to restore operation within the prescribed limits.

2.

3 0 4,

Surveillance requirements for APRM scram sct-points are given in Specification 4.1.B)-

APRM--when the reactor mode switch is in the STARTUP pos'.tion, the APBM scram shall be set at less than or equal to 15% of rated power.

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

Fixed High Neutron Flux Scram Trip Setting When the mofe switch is in the RUN position, the APRM fixed high flux scram trip setting shall be:

S<120% power.

2.

1 JASON'Sr LIHITI NG SAFETY SYSTEN SETT RELATED TO FUEL CLAODZN4 1N~TEGRi Y

'I'he ahnOrmaI Our ratiOnaI t ranaientS appliCable tO OperatiOn Of the Irrowns Ferry Nuclear Plant have been analyzed throughout the

~n~ctrum ot planned operatinq condit:ons up to the design thermal pOWr I COnditiOn Of 3rrrro Mwt.

The o.l>LySeS Were baSed upOn plant operation in accordance with the operatirrg map,qiven in Figure 3.7-1 of the FSAR.

In addition, 3293 Hwt is the licensed maximum power level of Browns Ferry Nuclear Plant, and this represents the maximum steady-state power which shall not knowingly be exceeded.

as further and Con se rvatism is incorporated in the transient analyses in estimating the controlling factors, such as void reactivity coef ficient, control rod scram worth, scram delay time, peaking

factors, and axial power shapes.

These factors are selected conservatively with respect to their effect on the applicalbe transient results as determined by the current analysis model.

This transient

model, evolved over many years, has been substantiated in operation as a c'onservative 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 summarired in Reference l, 2, and 3.

The absolute value of the void reactivity coef ficient used in the analysis is conservatively estimated to Le about 25% greater than the nominal maximum value expected to occur during the core lifetime.

The scram worth used has been derated to be equivalent to approximately 80% of the total scram worth, of the control, rods.

The scram delay time and rate of rod insertion allowed by the analyses are conservatively set equal to the longest delay and slowest insertion rate acceptable by Technical Specifications

• described in,preference 4.

The effect of scram worth, scram delay time rod insert'won rate, all conservatively applied, are of greatest siqnificance 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% in'sert,ed, approximately four dollars of negative reactivity has been inserted which strongly turns the transient, and accomplishes the desired effect.

The times for 50% and 90%

insertion are given to'ssure proper completion of the expected performance in the earlier portion of the transient, and to establish'the ultimate fully shutdown steady-state conditiun.

For analyses of the thermal consequences of the transients a

HCPR of <<<<

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

This choice of usinq conservative values of

.controllinq parameters and initiating transients at the design power level, produces more pessimistic answers than would result by usinq expected values of control parameters and analyzing at higher power levels.

<<<<See Section 3.5.K.

C 0

t e /

~

I lg+

I

,> ".u '-4 q5i Zn summary:

The licensed maximum po~er leve is 3,293 MMt.

2.

Analyoeo of transients employ adequately conservative values of the controllinq reactor parameters.

3o The abnormal operational transient,s were analyzed to a power level of 3440 MWt.

The analytical procedurco now" used result in a morc logical answer than the alternative method of assuming a h'gh ota rting power in con)unction with the expected values for n

ig er the parameters.

The bases for individual set points are discuooed below:

I Heutron lux sc am a

1, APRM Flow Biased High F'lux Scram Trip Setting (Run Mode)

The average power range monitoring (APRM) system, which is calibrated using heat balance data taken during steady-state conditions, reads in percent of rated power (3293 MWt).

Because fission chambers provide the basic input signals, the APRM system responds directly to core average neutron flux.

During transients, the instantaneous fuel surface heat flux is less than the instantaneous neutron flux by an amount depending upon the duration of the transient and the fuel time constant.

For this reason, the flow biased scram APRM flux 'signal is passed through a filtering network with a time constant which is representative of the fuel time constant.

As a result of this'filtering, APRM flow biased scram will occur only if the neutron flux signal is in excess of the setpoint and of sufficient time duration to overcome the fuel time constant and result in an average fuel surface heat flux which is equivalent to the neutron flux trip setpoint.

This setpoint is variable up to 120% of rated power based on recirculation drive flow according to the equations given in section 2.1.A.1 and the graph in figure 2.1.2.

For the purpose of licensing transient analysis, 19

neutron flux scram is assumed to occur at 120/ of rated power.

Therefore, the flow biased provides additional margin to the thermal limits for slow transients such as loss of feedwater heating.

No safety credit is taken for flow biased scrams.

4 The scram trip setting must be adjusted to ensure that the LIIGR transient peak is not increased for any combination of CMFLPD and FRP.

The scram setting is adjusted in accordance with the formula in specifica'tion 2.1.A..1 when the CHFE.PD exceeds FRP.

l Analyses of the limiting transients show that no scram ad3ustment is required to assure MCPR ) 1.07 when the transient is initiated from MCPR 2.

3 ~

APRH Flux Scram Tr Sett n

f el o Sta t G

ot Stand Mode For operation in the startup mode awhile the readtor is at low pressure, the APRM scram setting of

'15 percent of rat<<d power provides adequate thermal margin between the setpoint and the safety limit, 25 percent of rated.

The marqin is adequate to accomod~te'anticipated maneuvers associated with power plant startup.

Effects of increasing pressure at zero or low void content are minor, cold ~ater from sources available during startup is not much colder than that already in the system, temperature coefficients are small, and control rod pat terns are constrained to be uniform by operating procedures backed up by the rod worth minimizer and the Rod Sequence Control System.

North of individual'ods is very loi in a uniform rod pattern.

Thus all of possible sources of reactivity input, uniform control rod withdrawal is the most probable cause of significant power rise.

Because the flux, distribution associated with"uniform rod ~ithdrawals does not involve high local

peaks, and because several rods must be moved to change power by a signif icant percentage of rated power, the rate of power rise is very slow.

Generally, the heat flux is in near equilibrium with the fission rate.: In an assumed uniform rod withdrawal approach to the scram level, the rate of power rise is no more than 5 percent of rated power per minute, and the APRM system would be more than adequate to assure a scram before the power could exceed the safety limit.

The 15 percent APRH scram remains active until the 'mode switch is placed in the RUN position.

This a~itch occurs when reactor pressure is qreater than 850 psig.

I JAM-Flux Scram Tri S ttin The lRM System consists of 8 chambers',

4 in each of the reactor protection system logic channels.

The IBM is a

<<<< ~ See SeCtfon 3.5.K.

I'0 I

i

'C, 0

V 5-d<~cadv. instrument

~ which covers the range of power

]ev<<I b<<tween that covered by the sRM and the APRH.

The decaeJi.s are. covered by the IRH by means of a range switch and the 5 decades are broken down into 10 ranges,

<<hach beinj ohe half of a decade in size.

The IRH scram setting of 120 divisions ii. active in each range of the IBM.

For example, if,the '.iistrument vere on range 1 ~

the scram 8ettinq 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 xange.

Thus, as the IRH is ranged up to accommodate the increase in pover level ~ the scram setting is also ranged up.

A scram at 120 divisions on the IRH instruments remains in effect as long as the reactor is in the startup mode.

The APRH 15 percent scram vill prevent higher power operation vithout being in the run mode.

The IRH scram provides protection for changes which occur both locally and'ver the entire aore.

The most significant sources of reactivity chanqe during the power increase are due to control rod withdraval ~

For insequence control rod vithdraval. the rate of change of,power is slow enough due to the physical limitation of withdrawing control rode, that heat flux is in equilibrium vith'he neutron flux and an IRH scram vould result in a reactor shutdown well before any safety limit is exceeded.

For the case of a single control rod withdraval error this transient has been analyzed in paragraph 7.5. 5.4 of the PSAR.

In order to ensure that the IRH provides adequate protection against the single rod withdrawal error, a range of rod vithdraval accidents vas analyzed.

This analysis included starting the accident at various pmer levels.

The most severe case involves an initial condition in vhich the reactor is 5ust subcritical and the IRH system is not.yet on scale.

This condition exists at quarter rod density.

guarter rod density is illustrated in paragraph 7.5.5 of the FSAR.

Additional conservatism vas taken in this analysis by assuming that the IRH

~channel closest to the withdrawn rod is bypassed.

The results of this analysis shov that the reactor is Iscrammed and peak po~er limited to one percent of rated

'lpower, thuS maintaininq HCPR above 1.07.

Based on the

'above analysis, the IRH provides protection against local contxol rod withdrawal errors and continuous vithdraval of control rods in sequence.

Fixed, Hi h Neutron Flux Scram Tri The average'power range monitoring (APRi) system, which is calibrated using heat balance data taken during steady-state conditions, reads in percent of rated power (3293 MWt).

The APBM system responds directly to neutron flux.

Licensing analyses have demonstrated that with a neutron flux scram of 120/ of rated power, none of the abnormal operational transients analyzed violate the fuel safety limit and there is a substantial margin from fuel damage.

I B.

APRH 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

position, where protection of the fuel cladding integrity safety limit is provided by the IRH 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 ranqe of applicability o the fuel cladding integrity saf ety limit. In addition, the xsolation valve closure scram anticipates the pressure and flux transients that occur durinq normal or inadvertent isolation valve closure.

With the scrams set at 10 percent of valve closure, neutron flux does not increase.

I. J.

6 K.

Reactor low wa er level set int for initiation of HPCI and RCIC closin main steam isolation valves and startin PCI and ore s ra um s These systems maintain adequate coolant inventory and provide core cooling with'he objective of preventing excessive clad temperatures.

iThe design of these systems to adequately perform the'interided function is based on the specified low level scram set point and initiation set points.

Transient analyses reported'n Section H14 of the FSAR demonstrate that these conditions result in adequate safety margins for both the fuel and the system pressure.

I L.

References 1.

Linford,.R. B., <<Analytical Methods of Plant Transient Evaluations for the General Electric Boiling Water

Reactor,

<< HED0-10802,. Feb;,

1973.

2 ~

Generic Reload Fuel Application, Licensing Topical Report NEDE 24011-P-A and Addenda.

3.

"Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactor",

NED0-24154, NEDE-24154-P, October 1978.

4.

Letter from R. H. Buchholz (GE) to P.

S.

Check (NRC), "Response to NRC request for information on ODYN computer model,"

September 5,

1980.

24

~ I th

(

Shl'CTY LItilIT LIMITING SAFETY SYSTEM SETTING I.C kEACTOR COOLANT SYSTEM "INTEGHTTY I

2. 2 REACTOR COOLANT SYSTEN INTEGRITY Applies to limits on reactor coolant system pressure.

~Ob 'ective To establish a limit below which the integrity of the reactor coolant system is not threatened due to an overpressure condition.

A licabilit Applies to trip settings of the instruments and devices

which,

'are provided to pr event the reactor system saf ety limts from being exceeded.

~Ob 'ective To define the level of the process variables at which automatic.protective action is initiated to prevent the pressure safety limit from being exceeded.

S ecification S eci fica tion A.

The pressure at 'the lowest point of the reactor vessel shall not exceed

1. 375 psig whenever irradiated fuel is in the reac tor

• ves se l.

Hue leer system re 1 Ie f vdl ves open--nuclear syotc~ prcssure 1105 ps<S

+

p ~ I (Ie va lvs 4)

The limiting safety system settings shall be as specified belo~:

1125 Ps<8

+

ll pdl

(

5 valves) 0, Scrsst--nuclear systca hISh proosure e 1,055 psII 26

(:

SAFETY LIMIT LIMITING SAFETY SYSTEM SETTING

4. 2 PEACTOR COOLANT SYSTEM INTEGER ITY 27

The saf ty limit of 1,375 psig actually applies to any P int in the,, reactor vessel;

however, because of the static ~ater

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, becau. e of the pote 'l head level an o entia y varying eve and flow pressure

drops, an equivalent pressure cannot be<a prior~i determined for a pressure monitor higher in the vessel.

Therefore, following any transient that is severe enough to cause concern that this safety limit waa

violated, a calculation will be performed using all available information to determine if the safety limit was violated.

RFPERENCES 2 ~

5.

Plant Safety Analysis (BFNP FSAR Section N14.0)

ASHE Boiler and Pressure Vessel Code Section III USAS Piping Code, Section B31.1 Subsection 4.2)

Reactor VEsaql: and Appurtenances Hechanical Design (BFNP FSAR I

Generic Reload Fuel Application, Licensing Topical Repor t, NEDE-24011-P-A 'and Addenda.

29

2.2 BASES REACTOR COOLANT SYSTEM INTEGRITY To meet the safety basis thirteen relief valves have been installed on the,unit with a total capacity of 83.77/ of nuclear boiler rated steam flow.

The analysis of the worst overpressure transient, (3-second closure of all main steam line isolation valves) neglecting the direct scram (valve position scram) results in a maximum vessel pressure which, if.a neutron flux scram is assumed considering 12 valves operable, results in adequate margin to the code allowable overpressure limit of 1375 psig.

To meet operational

design, the analysis of the plant isolation "transient (generator load regect with bypass valve failure tn open) shows that 12 of the 13 relief valves limit peak system pressure to a value which is well below the allowed vessel overpressure of 1375 psigo 30

fLLLtLleh 1CACXCN tSCCRW~ ~ZQt {~ Q~CKCRfRTIOH SJQWR~

ILS %4 af Opcrahke L40t0

~macle tcs trip kr~~~

~m%XLRs 1

bode artcch ta aheakoea tSo4ea fb lA1Ch ~fOn ab Cat stsstepllot 8~ ~

~ ~1 S~hh X

C K

Em RaSnnQl X

1 h

'I Ittoesl 4csaa XM (tt) 1 Stqb slee isopesat tee X

1 Seh 4 1%/515 aadtcato4-oa sca1e x(22)

-x (22) x l$)

i+1 CS) t h 2

2 2

2 2

x(21) x(21)

(11)

APRM- (16), (23),'24)

High Flux.(Flow biased)

See Spec. 2.1.A.l High Flux (Fixed, trip)

<120%

High Flux

< 15% rated power Inoperative (13)

Downscale

> 3 indicated on scale x

x(17) (15) x(17) x (ll) x(12) 1.A or 1.B 1.A or 1.B 1.A or 1.B 1.A or 1.B 1.A or 1.B 2

High Reactor Pressure

< 1055 psig x(10) 1.A 2

High Drywell Pressure

• 'l4)

< 2.5 psig x(8) x{8) x 1 A 2.

Reactor Low Water Level (14)

> 538" above vessel zero x x

1.A 2

High Water Level in Scram Discharge Tank

< 50 gallons x

x{2) x x

1.A Hain Steam Line Isolation Valve Closure 10% valve closure x(3)(6) x(3)(6) x(6) 1.A or 1.C 2

Turbine Cont. Valve Fast Closure Upon trip of the fast acting solenoid valves x(4) x(4) x(4) l,A or 1,D

TABLE a I ~

REACTOR PROTECTION STSTEN (SCRAN)

INSTRUNEHTATION FUNCTIONAL TESTS

~

NININUN FUNCTIONAL TEST FRE()QEHCIES FOR SAFETT IHS?R AHD CONTROL CIRCUITS 0

Node Switch in Shutdown Nanual Scraa IRN High Flux Inoperative

~Croa 2

Functional Test Place Node switch in Shutdovn Trip channel and Alarm Trip Channel and Ala+a {a)

Trip Channel and Alara (a)

Niniaua Frequency (3)

Each Refueling Outage Every 3 Nonths Once Per Meek Dur(.ng Refueling and Before Each Startup Once Per Meek During Refueling and Before Each Startup APRM High Flu'x (15% scram)

Trip Output Relays (4)

Before Each Startup and Weekly When Required to be Operable High. Flux (Fixed trip)

High Flux (Flow bias)

B B

Trip Output Relays (4)

Trip Output Relays (4)

Once/Week Once/Week Inoperative Trip Output Relays (4)

Once/Week Downscale B

Trip Output Relays (4)

Once/Week Flow Bias High Reactor Pressure High Drywell Pressure Reactor Low Water Level (5)

A A

Trip Channel and Alarm Trip Channel and Alarm Trip Channel and Alarm.

Once/Month (1)

Once/Month (1)

Once/Month (1)

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

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3 ~ 3 REACTIVITY CONTROL 4

3 REACTIV TY CONTROL 2 ~

The control rod drive housing support system shall be in place during reactor power operation or when the reactor coolant system is pressurized above atmospheric pressure with fuel in the reactor vessel, unless all control rods are fully inserted and Specification 3.3.A. 1 is met ~

2.

The control rod drive housing support syst: em shall be inspected after reassembly and the results of the inspect.ion recorded.

Q 3.

a.

Whenever the reactor is in the startup or run modes below 20% rated po~er the Rod Sequence Control System (RSCS) shall be operable except the RSCS 'constraints may be suspended by means of

'he individual rod bypass switches for 1 special criticality

tests, or 2 - control rod scram tim$ng per 4.3.C.l.

'When RSCS is bypassed on individual rods for'hese, exceptions RWM must be oper-able per 3;3.B.3.c and a second licensed operator may not be used in lieu of RWM.

3.a prior to the start of control rod withdrawal at

startup, the capability of the Rod Sequence Control System tRSCS) and the Rod Worth Minimizer to properly fulfill their functions shall be verified by the following checks:

123

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RFQUIREMENTS 3.3 REACTIVITY CONTROL 4.3 REACTIVITY CONTROL

" b.

During the shutdown pro-,

cedure,,

no rod movement is permit'ted between the testing performed above 20% "power and the reinstatement of the RSCS restraints at or above 20% power.

Alignment of rod groups'hall be accomplished prior to performing the tests.

c.

Whenever the, reactor is in the s tar tup or run modes below 20% rated power, the rod worth minimizer shall be operable.

A second licensed operator may verify that the operato'r. at the reactor con-sole is following the control rod program in lieu 'of RWM except as specified in 3.3.B.3.a.

Sequence portion Select a sequence and attempt to withdraw a rod in the remaining sequences.

Move one rod in a sequence and select the remaining sequences and attempt to

- move a rod in each.

Repeat for all sequences.

Group notch portion For each of the six comparator circuits go through test initiate; comparator inhibit; verify; reset.

On seventh

attempt, test is allowed to continue until completion is indicated by illuminat'ion of test complete light.

b.

Prior to attaining 20% rated power during rod insertion at shutdown, the tests in 4.3.8.3.a shall be performed to verify RSCS capa-

~ bility.

c.

The capability of the rod worth minimizer (R%1) shall be verified by the following checks:

124

0 LIMXTXHG CONDITIONS FOR OPERATION SURVEILLANCE REQUXREHENTS 3, 3 REAC1'IVITY CON'IROL 4

3 REACTIVITY CONTROL control rod~

5.

Prior to obtaining 20% rated power

.during rod insertion at

shutdown, verify the

"'.atchinq of the proper rod group and proper annuncia tion after insert errors.

d.

Mhen the RWif is not

operable, a second licensed operator will verify that the, correct rod program is followed except as specified in 3.3.B.3.a.

126

reqardless of the rod pattern.

This is true for all normal and abnormal patteins including those which maximize individual control rod worth.

power levels below 20 percent of rated, abnormal control rod patterns could produce rod worths high enough to be of concern relative to the 200 calorie per gram rod drop limit.

In this range the RWM and the RSCS constrain the control rod sequences and patterns to those which involve only acceptable rod worths.

The Rod North Minimizer and the Rod Sequence Control System provide automatic supervision to assure that out of sequence control rods will not be withdrawn or inserted; i.e., it limits operator deviations from planned withdrawal sequences.

Ref. Section

7. 16.5.3 of the FSAR.

They serve as a backup to procedure control of control rod sequences, which limit the maximum reactivity worth of control rods.

Fxceot during specified exceptions when the Rod Worth Pinimizer is out of service, second licensed operator can manually fulfillthe control rod pattern conformance functions of this system.

In this case, the RSCS is backed up by independent procedural controls to assure conformance.

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, these devices force adherence to acceptable rod patterns.

Above 20 percent of rated power, no constraint on rod pattern is required to assure that rod drop accident consequences are acceptable.

Control rod pattern constraints above 20 percent of rated power are imposed by power distribution requirements, as. defined in Section 3.5. I,

3. 5.J, 4.5.I, and 4.5.J of these technical specifications.

Power level for automatic bypas of the RGCS 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.

A Because it is allowable to bypass certain rods in the HSCG during scram time testing below 20$ of rated power in the startup nr run modes, a second licensed operator i s not an acceptable substitute for t):e HWM during this

);esting.

The Source Range Monitor (SRM) system performs no automatic safety system functions; i.e., it has no scram function. It does'rovide the operator with a visual indication of neutron level.

The consequences of reactivity accidents are functions of the initial neutron flux.

The requirement of at least 3 counts per second assures that any transient, should it occur, begins at or above the initial value of 10-~ of rated power used 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 133

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3 '

CORE AND CONTAINMENT COOLING S YSTEMS 4 ~ 5 CORE AND CORI'AINMEPI'OOLING SYSTEMS A 'icabilit Applies to the operational status of the core and containment, cooling systems.

A~1Kcabal it Applies to the surveillance requirements of the core and containment cooling systems when the corresponding limiting condition for'peration is in effect.

~cb 'ective To assure the operability of the core and containment cooling sy'stems under all conditions for which this cooling capability is an esstential response to plant abnormalities.'b ective To verify the operability of the core and containment cooling systems under all conditions for which this cooling capability is an essential response to plant abnormalities.

S ecification S

cification Core S ra S stem CSS A

Core.S ra S stem CSS (2) when there is irradiated fuel in the vessel and when the reactor vessel pressure is

'reater than atmospheric

pressure, except as specified in specifications 3.5.A.2 1.

The CSS shall be operable:

{1) prior to reactor startup from a cold condition, or Frecru~enc a.

Simulated Once/

Automatic Operating Actuation Cycle test b.

Pump Operability Once/

month

c. Motor Once/'peratedmonth Valve Operability 1.

Core Spray System Testing.

I 146

0

LfMITXNG CONDITIONS POR OPEPATXON SURVEILLANCE 'Rr~MEMENTS 3

5 CORE AND CONTAINMENT COOLING SYSTEMS II 0 ~ 5 CORE AND CONTAINMENT COOLING SYSTEMS Ra sidual Heal Removal

."~ete~mRRRR (LPCL aad Containment Cooling)

B.

Residual Heat Removal Containment Cooling) 1 ~

2.

The RHRS shall be operable:

(1) prior to a reactor startup from a Cold Condition; or (2) when there is irradiated fuel in the reactor vessel and when the reactor vessel pressure is greater than atmospheric, except as

'specified in specifications 3.5.B.2, through 3.5.B.7 Nith the reactor vessel pressure less than 105 psig, the RHR may be removed from service

'(except that two RHR pumps-containment cooling mode and associated heat exchangers must remain operable) for a period not to exceed 2Q hours while being drained of 1.

a.

Simulated Automatic Actuation Test Once/

Operating Cycle b.

Pump Opera-Once/

bility month

c. Motor Opera-ted valve operability a

d.

Pump -Plow Rat,e

e. Testable check valve.

Once/

month Once/3 Months Once/

operatin'q cycle

.Each LPCI pump shall deliver 9,000 gpm against an indicated system pressure of 125 psig'wo LPCI pumps in the same loop shall deliver 15,000 gpm against an indicated system pressure, of 200 psig.

t tt 2.

An air test on the drywall and torus headers and nozzles shall be conducted once/5-years.

A

~

water. test may. be performed on the torus header in lieu of the air test.

149

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RFQUIREMENTS 3 ~ 5 CORE AND CONTAINMFNT COOLING SySTEMS 4

5 CORE AND CONTAINMENT COOLING SYSTEMS I.

Avera e Planar Linear Heat Generation Rate I.

'Maximum Avera e Planar Linear Heat Generation During steady state power operation, the Maximum Average Planar Heat Generation Rate (MAPLHGR) for each type of fuel as a

function of average planar exposure shall not exceed s

the limiting value shown in Tables

3. 5. I-l through 3.5.I-6.

If at any time during operation, it is determined by normal surveillance that the limiting value for APLHGR is being exceeded, action shall be initiated within 15 minutes to restore.

operation to.within, the prescribed limits.

Zf the APLHGR is not.returned to within the prescribed limits within two (2)

hours, the reactor shall be brought to the Cold Shutdown condition within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

Surveillance and corresponding action shall continue until reactor operation is within the prescribed limits.

The MAPLHGR for each type of fuel as a function of average planar exposure shall be determined daily during reactor operation at

?

25% rated thermal power.

165

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.5 COBE hNO CONTAINMENT

'OOLING SYSTEMS 4~ 5 CORE AND CONrAINMENT COOL~IG SYSTEMS Linear Heat Generation Rate (LHGR)

During steady state power operation, the linear heat, generation rate (LHGR) of any rod in any fuel assembly at any axial location shall not exceed 13.4 kW/ft.

J.

Linear Heat Generation The LHGR shall be checked daily during reactor operation at I 25%

rated thermal power.

I If at any time during operation it is determined by normal surveillance that the limiting value for LHGR is being

exceeded, acti. on shall be initiated within 15 minutes to restore operation to within the prescribed limits. If the.

LHGR is not returned to within the prescri.bed limits within two (2)

hours, the reactor shall be brought to the Cold Shutdown condition within 36 'hours.

Surveillance and corresponding action shall continue unt'l reactor operation is within the prescribed limits.

I

IMITING CONDITIONS FOR OPERATION

~

~

3.5 CORE AND CONTAINMENT COOI ING SYSTFMS SURVEILLANCE REQUIRFMENTS 4.5 CORE AND CONTAINMENT COOLING SYSTEMS'.5.K Minimum Critical Power Ratio

~MCPR The minimum critical power ratio (MCPR) asa function of scram time and core

,flow, shall be equal to or greater tha shown in Figure 3.5.K-l multiplied by the Kf shown in Figure 3.5. 2, where:

0 or~ave

B, whichever is

~A-B Brearer

~A~Oe90 sec (Specification 3.3.C.1 scram time limit to 20% insertion from fully withdrawn)

~B~0.710+1.65 N

~.(0.053)

Ref 5

n number of surveillanke rod test performed to date in cycle (in-cluding BOC test).

l

= scram time to 20/ insertion from fully withdrawn of the ith rod e

N ~ total number of active rods measured in Specification 4.3.C.l at BOC 4.5. K Minimum Critical Power Ratio

~RCP R 1.

HCPR shall be determined daily during reactor power operation at

>25% rated thermal power and following any change in power level or distribution that would cause operation with a limiting control rod pattern as described in the bases for Specification 3.3.

2.

The MCPR limit shall be deter-mined for each fuel type

SXS, SX8R, P8X8R, from Figure 3.5.K-1 respectively using:

a.

C = 0.0 prior to initial scram time measurements for the cycl<

performed in ac'cordance with Specification 4.3.C.1.

b. f as defined in Specification 3.5.K following the conclusion of each scram time surveillanc<

test requireh by Specification.

4.3.C.1 and 4.3.C.2.

The determination oC the limi.t must be completed with 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

of each scram time surveillance required by Specification 4.3.C.

If at any time during steady state operation it is determined by normal surveillance that the limiting value for MCPR is being exceeded,,iaction shall be initiated within 15 minutes to restore operation to within the prescribed limits.'If the steady state HCPR is not returned to within the prescribed limits within two (2)

hours, the reactor shall be brought to the Cold Shutdown condition within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, surveillance and correspondi g

action shall continue until reactor operation is within the prescribed limits.

167

~e~ee e

ISIe ee

~

~e'~ee W>> eeaeer leeee b

,,fl a

~ A* ~,re B

LIMITJNG CONDITIONS FOR OPERATION SURVEILLANCE REOUIREMENTS 3.5 CORE AND CONTAINMENT COOLING SYSTEMS 4.5 CORE AND CONTAINMENT COOLING SYSTEMS L.

Re ortin Re uirements If any of the limiting values identified in

'pecifications 3.5.I, J, or K are exceeded and the specified remedial action is

taken, the event shall be logged and reported in a 30-day written report.

167a

testirrq to ensure that the lines are filled.

The visual checkinq will avoid startinq the core spray or RHR system with z discharge line not filled.

In addition to the visual observation and" to ensure a filled discharqe line other than prior to testinq, 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 discharqe high point serves as a backup charqinq system when the pressure suppression chamber head tank is not in service.

system clischarqe pressure indicators are used to determine the water level above the discharge line high point.. The indicators will reflect approximately 30 psig for a water level at the hiqh point and 45 psig for a water level in the p"essure suppression chamber head tank and are monitored daily to ensure that the discharge lines are filled.

when in their normal standby condition, the suction for the HPCI and RCIC pumps are aligned to the condensate storage

tank, which is 'physically at a hiqher elevation than the HPCIS and RCICs piping.

This assures that the HPCZ and RCIC discharqe pipinq remains filled.

Further assurance is prov'ided by observing'water flow from these systems high points monthly.'his specificadion assures that the peak cladding temperature Eollcving the postulated design basis loss-of-coolant accident will riot exceed the limit specified in the 10 CFR 50,'pp'endix K'he peak cladding temperature following a postulated loss-of-coolant accident is primarily a -function of the average heat qeneration rate of all tne rods of a fuel assembly at any axial lodation and is onl'y dependent secondarily on the rod to rod gower distribution within an assembly.

since expected local variations in power distribution within a fuel assembly affect the calculated peak clad temperature by less than

+

20 F relative to the peak temperature for a typical fuel

'design, the limit on the average linear heat generation rate is suf ficient to assure. t'hat calculated.temperatures are within the 10 CFR 50 Appendix K limit.

The limitinq value for PAPLHGR is shown in Tables 3.5.l-l through~6.

The analvses supporting,tnese limiting values is presented in reference 4

L'near Heat Generation Rate LHGR

. This specification assures that the linear heat generation rate in any rod is less than the design linear heat 176

TABLE 3.5.I-1 MAPLHGR VERSUS AVERAGE PLANAR EXPOSURE Plant:

BF-3 Fuel Type:

Initial Core Type 1

Average Planar Exposure (HWd/t) 200 1,000 5,000

, 10,000 15, (LOO 20,000 25,000 30,000 35,000 MAPLHGR (kM/ft)

11. 2 11.3 11.8 12.1 12.3 12.1 11 '

10.2 9.6 TABLE 3.5.I-2 MAPLHGR VERSUS AVERAGE PLANAR EXPOSURE Plant:

BF-3 Fuel Types:

8DRB265L and P8DRB265L Average Plinar Exposure (Mt'/t) 200 1,000 5,000 10,000 15,000 20,000 25,000 30,000 35,000 407000 i

'I MAPLHGR (kW/ft) 11.,6 ll.6 12.1 12.1 12.1

- 11.9 11.3 10.7 lo. 2

'9. 6 The values in this table are conservative for both prepressurized and non-pressurized fuel.

181

TABLE 3.5.I-3 MAPLHGR VERSUS "AVERAGE PLANAR EXPOSURE Plant:

BF-3 Fuel Type:

P8DRB299 Average Planar Exposure

{>md/t) 200 li000 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45i000 MAPLHGR (Nc/st)

10. 9 11.0 11.5 12 ~ 2

12. 3 12.2 11.9 11.3 10.9 10.4 10.0 TABLE 3.5.I-4 MAPLHGR VERSUS AVERAGE PLANAR EXPOSURE Plant:

BF-3 Fuel Type:

P8DRB284Z Average Planar Exposure (MWd/t) 200 1,000 5,000 10,000 15,000 20,000 25,000 30,000'35,000 40,000 45,000 MAPLHGR (kW/ft)

11. 2 11.2 llew 7

12.0 12.0 11.9 11.3 10.8 10.'4

, 9 ~ 9 9.5 182

TABLE 3.5.I-5 MAPLHGR VERSUS AVERAGE PLANAR EXPOSURE Plant:

BF-,3 Fuel Type:

P8DRB283 (LTA)

Average Planar Exposure, (md/t) 200 1,000 50000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,'000 MAPLHGR (M</ft) 11.2 11.2 11.7 12.0

'2 11.9 11.3 10.8 10.4 10.0 9.5 TABLE 3.5.l-6 MAPLHGR VERSUS AVERAGE PLANAR EXPOSURE Plant:

BF-3 Fuel Type:

P8DRB314 (LTA)

Average Planar Exposure

. (MWd/t) 200 1,000 5,000 10,000 15,000 20,000 25,000 30>000 35,000 40,000 45,000 MAPLHGR (kW/ft) 10.6 10.7 11,3 11.7 11.5 11.2 10.6 10.1 9.7 9.3 8.8 182a

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0.0 0.1 0.2 0.3 0.4 0.5 Oe6 0.7 0.8 0.9 1.0 Figure 3.5.K-l MCPR LIMITS 182b

8

LZMITINC CONDITIONS FOR OPERATION SURVEILLANCE REQVIREMENTS 4

I. <

+R~tNAR SYSTt.f BC ROARY I~ 6 PRY HAR S

STK'H HOUHOARY 0.

Relief Valves When more than one relief>vLlve o be failed, an orderly shutdown shall be "initiated'and the reactor depressurixed to less than 105 psig within 2a pours.

Relief Valves approximately one-half of all relief valves shall te bench-checked or replaced with a bench-checked valve each operatinq cycle.

All 13 valves vill have been checked or replaced upon the completion of every second cycl eo 2.

Once durino each opera tin S

cycle, each relief valve shall be manually opened until thermocouples and acoustic mo'nitors downstream of the valve indicate steam,is flowing from the valve.

At least one relief valve shall be

'fsassembied and "inspected each operating cycle.

192

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUI REMENTS

l. 6 PR MARY SYSTEM BOUNDARY 4 ~ 6 PR MARY SYSTEM BOUNDARY F.

Recirculation Pum 0 eration Reci rcu lat ion pump speeds shall be checked and logged at least once per day.

l.

The reactor shall not be operated with one recirculation loop out of service fox more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

with the reactor operating, if one recirculation loop is out of service, the pl'ant shall be placed in a hot shutdown condition withi'n 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless the loop is sooner returned to service.

Following one-pump opera tion, the discharge valve of the 'low speed pump may not be opened unless thy speed of the 'faster pump is less than 50% of its rated speed.'9

limit spaciticd for unidentified leakaqc, the probability is st ll that imperfections or cracks associated with such leakage Mould crow rapidly.

Ho~ever, the establishment of allowable unidcntif icd leakage greater than that given in 3.6.C on the basis of the data presently available would be premature because of uncertainties associated with thc data.

for leakage of the order of 5 qpm, as specified in 3.6.C, the experimental and'nalytical data suqgest a reasonable marqin of safety that such leakaqe maqnitude would not result from a crack approaching the critical size for rapid propaqation.

Leakage less than the maqnitud~

op ciiiud can be detected reasonably in a matter of fcw hours utilixinq he available'eakage detection

schemes, and if the oriqin cannot be determined in a reasonably short time the uni't should be shut down to allow further inveotiqatfon and corrective action.

The total leakaqe rate consists of all leakaqe, identified and un~dentificd, which flows to the drywell floor drain and equipment drain oumpo.

P The capacity of the drywell floor sump pump is 50 gpm and the capacity ot the drywell equipment sump pump is also 50 qpm.

Removal of 25 qpm from either of these sumps can be accomplished with considerable margin.

F EREN~C I

I Huclear System Leakage Rate Limits (BPNP.

fSAR Subsection 4, 10) 224

3. 6. D/4. 6. D Relief Valves To meet the safety basis, thirteen relief valves have been installed on the unit with a total capacity of 83.77% of nucl'ear boiler rated steam flow.

The analysis of the worst overpressure transient, (3-second closure of all main steam line isolation valves) neglecting the direct scram (valve position scram) results in a maximum vessel pressure which, if a neutron flux scram is assumed considering 12 valves operable, results in adequate margin to the code allowable overpressure limit of 1375 psig.

To meet operational

design, the analysis of the plant isolation transient (generator load reject with bypass valve failure to open) shows that 12 of the 13 relief valves limit peak system pressure to a value which is well below the allowed vessel overpressure of 1375 psig.

225

nozzle-riser system failure could also qenerate the coiticident failure 'of a jet pump diffuoer body;

however, the converse is not:

true.

The lack of any substantial stress in the jet pump diffuser body makes failure impossible without an initial nozzle-ri er system failure.

3. 6.F/4. 6. F Recirculation Pum 0 eration Steady-state operation without for"ed recirculation will not be permit:ted for more than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

And t:he st;art of' recirculation pump from Llie natural circulation condition will not be permitted unless the temperature difference between the loop to be started and the core coolant temperature is less than 75 F

~

This reduces the posit.'ive reactivity insertion to an 0

acccptnb]y low value.

Ruquirinq t. e i c d's barge valve of the lower speed loop to remain

'l the speed of the faster pump is below'~0'%ated sp e<l provides assurance when going, oper ition that excessive vibration of the jet pump risers wi not occur.

'I'he requirements for.'he reactor coolant systems inservice inspection program have been identified by evaluating the need for a sampliiiq examination of areas of high tre"s and highct t probability of failure in the system and the need to meet as closely as possible the requirements of 'Section XZ, of tlie BSHE Doiler and Pressure vess el Code.

The proclram reflects the built-in limitations of access to the reactor coolant s y, rema.

227

LINITINC CONDITIONS FOR OPERATION SuRvEILLANCE REOVI REAGENTS Cofgg f NMENT~SSTENS a ~ 7 COHTAINH EVi T S YST ENS 0

a.

~primer Containe.nt i,

1.

At any time that the irradiated fuel is in the reactor vessel, and the nuclear system is pr es sur ized aLove atmospheric pressure or work is

.being done which has the potential to drain the vessel, the pressure suporession pool ~ater level and temperature shall be maintained within the following limits

.except as specified in 3. 7. A. 2.

a.

Minimum water level ~

-6.25" (differential

'ressure control

>0 psid)

~a

~to a ~ni iit Applies to the operating status of the primary and secondary containment systems.

Ob~ective To assure th<< zntegrxty of the primary and secondary con ainment systems.

Soeci Eicatinn licabi Applies to the primary and secondary containment integrity.

Soeci Eication Primar Containment 1.

Pressure Suppress cn Chamtee a

~

The suppress)on chamber water level be checked once per day.

whenever heat fs added to the suppress)on oool by testing of the ECCS or rel)ef valves the pool temperature shall be continually monitored and shall be observed and logged every 5

m)nutes unt) 1 the heat addition )s tennknated.

o~b'ect ive To verify the inte-rity of the primary and secondary cont a inment e Ia

-7.25" (0 psid differ ential pressure contr b.

Maximum water level ~

ill 231

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7 COFPAINMENT SYSTEMS 4 ~ 7 CONTA NMENT SYSTEMS c.

If the specifications of 3. 7.A. 5.a throuqh 3.7.A-5-b cannot

'e 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 />,',

6.

Drywell-Suppression Chamber Differential Pressure a.

Differential pressure between the drywell and suppression chamber shall be maintained at equal to or greater than l,3 psid except as specified in (1) and (2) below:

6.

Drywall-Suppression Chamber Differential Pressure I

a.

The pressure differ-ential between'he drywell and suppression chamber shall be recorded at least once each shift.

(l) This differential shall be estab-lished within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of achieving operating temperature and pressure.

The differenbial pressure may be reduced to less than'.3 psid 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a schedul'ed shutdown.

(2) This differential may be decreased to I

less than 'l.l paid for a maximum of four hours during required operability testing of the HPCX system, RCIC system, and the drywell-pressure suppression chamber vacuum breakers.

246

TABLE 3-7 A PRIMARY COHTAZHNEST ISOLATION VALVES Group 2

Valve Identification l(ain steanline isolation valves (PCV 1 14r 26r 37r 6 51(

1>>15r 27, 38 6 52)

Nain steawline drain isolation valves (PCV-1-55 6 1-56)

Reactor Mater sample line isola-tion valves RHRS shutdown cooling supply isolation valves (FCV-74-48 6 47)

Hunber of P~r-Operated Valves Inboard Outboard 4

Maximum Operating Time (sec.)

3<T<5

, 15 40 Boreal Position 0

C Action on Initiating Signal GC 2

RHRS - LPCI to reactor (PCV-74-53 6 67)

Reactor vessel head spray isola-tion valves (PCV-74-77 6 78)

RHRS flush and drain vent to suppression chanber (PCV-74-102r 103r 119r 6 120)

Suppression Chmaber Drain (PCV-75-57 6 58)

Dryvell equipaent drain discharge isolation valves (PCV-77-15A 6 15B)

Drywell f1oor drain discharge

. isolation valves (PCV-77-2A 6 28) 30 30 20 15 15 15 SC SC

TASLE 3;7.h (Continued)

Valve Identiffcation Reactor vater cleanup system supplv isolation valises FCV-69-1,

& 2 1uAer o Pouer Inboard Outboa".8 maximum Operating

~Tive see.)

30 Horaal Position hction os laitiating

~Si 1

FCV 73-SI (Bypass around PP'3-3)

BPClS steamline isolation valves PCV-73-2

& 3 1I 10 20 0

0 RCICS steaaifne fsolation vaIves PCV-71-2. & 3 I5 DryMell nitrogen purge 'nlet isola-tfon valves (PCV<<76-18)

C Suppression chamber nitrogen purge inlet isolation valves (FCV-76-19)

SC Dry@all Hain Exhaust isolation valves (PCV-64-29 and 30) 2.5 SC Suppression chamber main exhaust fee lation valves (b V-6$-32 and 33) 2;5 llxyvell/Suppression Chamber purge inlet (Nf-Q-17)

Drywell htaosphere purge inlet (ECV-64-1 8) 2.5 2.5

TABLE

.7.A (Continued)

~Grou Valve Identification Number of Power Operated Valves

. Inboard Outboard Maximum Operating Time (Sec.)

Normal-Position Action on Initiating Si al Suppression Chamber purge inlet (FCV-64-19) 2.5 SC Drywell/Suppression Chambei nitro-gen purge inlet (FCV-76-17)

SC 6

.Drywell Exhaust Valve Bypass to Standby.

Gas Treatment System (FCV-64-31)

Suppression Chamber Exhaust Valve Bypass to Standby Gas Treatment System (FCV-64-34)

SC SC System Suction Isolation Valves to Air Compressors "A" and "B" (FCV-32-62, 63)

Drywell/Suppression Chamber Nitrogen Purge Inlet (FCV-76-24)

Torus Hydrogen Sample Line Valves Analyzer A (FSV-76-55, 56) 15 0

Note 1

SC SC Torus Oxygen Sample Line Valves Analyzer A (FSV-76-53, 54)

NA Note 1

SC Drywell Hydrogen Sample Line Valves Analyzer A (FSV-76-49, 50)

NA Note 1

SC Drywell Oxygen Sample Line Valves Analyzer A (FSV-76-51, 52)

Sample Return Valves Analyzer A (FSV-76-57, 58)

NA NA Note 1

SC GC 6

Torus Hydrogen Sample Line Valves Analyzer B (FSV-76-65, 66)

NA Note 1

SC

0 TABLE 3.7.

Continued)

~Grou Valve Identification Torus Oxygen Sample Line Valves-Analyzer B

(FSV-76-63, 64)

Number of Power Operated Valves.

Inboard Outboard Maximum Operating Time (Sec.

NA Normal Position Note 1

Action on Initiating

~St nal SC Drywell Hydrogen Sample Line Valves-Analyzer B

(FSU-76-59, 60)

NA Note 1

SC Drywell Oxygen Sample Line Valves-Analyzer B

(FSV-76-61-,

62)

NA Note 1

SC c

7 Sample Return Valves-Analyzer B (FSV-76-67, 68)

RCIC Steamline Drain (FSV 6A$ 6B)

NA GC SC RCIC Condensate Pump Drain (FCV-71-7A$ 7B)

HPCI Hotwell pump discharge isola-tion valves (FCV-73-17A, 17B)

SC SC 8

HPCI steamline drain (FCV-73-6A, 6B)

TIP Guide Tubes (5) 1 per guide tube NA GC GC NOTE 1:

Analyzers are such that one is sampling drywell hydrogen and oxygen (valves from drywell open valves from torus closed) while the other is sampling torus hydrogen and oxygen (valves from torus open valves from drywell closed)

TABLE 3 7 A PRIORI CORTAI?BiZHT ISOLATION VALVES Group Valve Zdeatification Rasher of Power Operated Valves Znboard Outboard Haxiaua operating Norlal Tiae (sec.)

Position Action on Initiating signal standby liquid control systaa check valves (CV 63-526 6 525)

Peedvater check valves (cv-3-558'72'54 6 568)

Control rod hydraulic retara check valves (CV-85-576 6 573)

RHRS - LPCZ to reactor check valve~

(CV-78-58 6 68)

Core Spray discharge to reactor check valves (FCV-75-26 and 54)

Process Process Process Process Process Drywe115P air compressor suction valve (FCV 64-139)

Drywell 5P air compressor discharge valve (FCV 64-140)

Drywell CAM discharge valves (FCV 90-257A and 257B) 10 10 10 SC SC GC Drywell CAM suction valves (FCV 90-254A and 254B)

Drywell CAM suction valve (FCV 90"255) 10 10 0

0 GC

TABLI 3.7.D AIR TESTED ISOLATION VALVES Valve Valve Identif ~ cation 1

14 1-1 i-26 1-27 1-37 1-38 1-51 1-52 1-55 1-56 2-1192 2-1383 3-554 3-558 3-568 3-572 32-62 32-63 32-336 32-2163 33-1070 33-785 43 13 43-14 63-525 63-526 64-17 64-18 64-19 64 20 64-c.v.

64-21 64-c.v.

64-29 64-30 64 32

,64-33 64-31 64-34 64-139 64-1ll0 68 508 68-523 68-550 68-555 Main Steam Hain S team Main Steam Hain Steam Main Steam Main Steam Main Steam Hain Steam Main Steam Drain Main Steam Dr ain Service Water Service Water Feedwater Feedwater Feedwater Feedwater Drywell Compressor Suction Drywell Compressor Suction Drywell Compressor Suction Drywell Compressor Suction Service 'Air Service Air Reactor Water Sample Lines Reactor Water Sample l.ines Standby Liquid Control Discharge Standby Liquid Control Discharge Drywell and Suppression Chamber Air Purge Inlet Drywell Air Purge Inlet Suppression Chamber Air Purge Inlet Suppression, Chamber Vacuum Relief Suppression Chamber Vacuum Relief Suppression Chamber Vacuum Relief Suppression Chamber Vacuum Relief Drywell Main Exhaust Drywell Main Exhaust Suppression Chamber Main Fxhaust Suppression=

Chamber Hain Exhaust Drywell Exhaust to Standby Gas Treatment Suppression Chamber to Standby Gas Treatment Drywell Pressurization, Compressor Suction

'rywell Pressurizatidn, Compressor Discharge CRD to RC Pump Seals CRD to RC Pump Seals CRD to RC Pump Seals CRD to RC Pump Seals 270

rABLE 3.7.D AIR TESTED ISOLATTON VALVES Valve)

Valve Identification 69-1 69-2 69-579 69-"624 7 1-2 I'1-3 71-39 1->>0 I.p 2 73-3 73-01 4>>

i3 7>>

l,'7 74-rlR 7>>-661 74-662 76-17 76-10 76-19 76-24 76->>9 76-50 76>>51 r>p 76-53 76-54 5r>

76-56 76-57 76-50 76-59 76'-60 76-61, 76-62 76-63 76-6>>

76-65 r6-66 76-67 76-60 77-2A 77-2D

/7-1r~A 77-15B 8>>-8A G>>-GB 04-Gc 84-8D 04-19 0>>-20 en Purge Inlet en Purge Inlet ment RWCU Supply RWCU Supply RWCU Return RWCU Return RCXC Steam Supply RCIC Steam Supply RCIC Pump Discharge RCIC Pump Discharge HPCX Steam Supply HPCI Steam Supply HPCX Steam Supply Bypass HPCI Pump Discharge HPCI Pump Discharge RHR Shutdown Suction RHR Shutdown Suction RHR Shutdown Suction RHR Shutdown Suction Drywell/Suppression Chamber Nitrog Drywell Nitrogen Purge Xnlet Suppression

Chamber, Purge Inlet Drywell/Suppression Chamber Nitrog Containment Xnerting Containment Xnerting Containment Inerting Containment Inerting Containment Inerting Containment Incr ting Containment Incr ting Containment Xnerting Containment Inerting Containment Xnerting Containment Inerting Containment Inerting Containment Xnerting Containment Inerting Containment Xnerting Containment Xner ting Containment Xnerting Containment lnerting Containment Inerting Containment Inerting Dvywell Floordrain Sunrp Drywell Floordrain Sump Drywell Equipment Drain Sump Drywell Equipment Drain Sump Containment Atmospheric Dilution

'ontainment, Atmospheric Dilution Containment Atmospheric Dilution Containment Atmospheric Dilution Containment Atmospheric Dilution Hain Exha<rst to Standby Gas Tvcat 271

TABLE 3.7.D AIR TESTED ISOLATION VALVES Valve I

Valve Identification A~~-600 8~i-601 GA-602 8lt-60'5-576 90 25liA 90 25llB 90-255 90-257A 90-2578 Hain Exhaust to Standby Gas Treatment Hain Exhaust to Standby Gas Treatment Main Exhaust to Standby Gas Treatment Main Exhaust to Standby Gas Treatment CRD Hydraulic Return Radi,ation Monitor Suction Radiation Monitor Suction Radiation Monitor Suction Radiation Monitor Discharge Radiation Monitor Discharge 272

(DELETED) 273-278

TABLE 3.7.E PREPAY COio~AI)2Z?IT ISOLATZOII VALVES !'IIIICIITiKIIIMTE BEL61 TILE SUPPRESSIO?'I POOL HATER LEVEL Valve 12-s33 12-!41 4.3-2GA 43-28B 43 20A 43 29 2-1143 71-14

.1-32

'?1 r)"0

".1-)92 73 23

~3 2!;

3-603

~ 3-609

-,4 -.22

)-)1 75-58

'alve Identii'ication Auxili.ary Boiler to RCIC AuxiliaryBoiler 4o RCIC RIIR Suppression Cnamber Sample Lines RIIR Suppression Chamber Sample Lines R:E Suppression Chamber Sample Lines "RHR Suppression Chamber Sample Lines Deminerali "ed Hater RCIC Turoine Exhaus RCIC Vacuum Pump Discharge RCIC Turbine Exhaust RCXC Vacuum Pump Discharge I!PCI Turbine Exhaust IIcCX Turbine Exhaust Drain l?PCX Turbine Exhaust IIPCX Exhaust Drain RHR Core Spray to AuxiliaryBoiler Core Spray to AuxiliaryBoiler Core Spray to AuxiliaryBoiler 279

TABLE 3.7.P PBXIIAR'I COI/TAXUZhT ISOLATION VALVES LOCATED IlI UA~~

SEALED SEISMIC CLASS 1 LX:IES Valve 74-53 74 54

".4-5A 14-6O 74-t'1 74 g, (4-.)0 "4-";1 "4-72

,4 -,5

,P~

75 25

( 5 r.'u 75-53 75-54 Valve Identification R.'E LECX Discharge R!%

RW Suppression Chamber RIP Suppression Chamber RHR Drywe13. Spray RIE Dryrrell Spray RIE LAX Discharge RHR LAX Discharge RIE Suppression Chamber RHR Suppression Chamber RIE Drywell Sp ay RIE Dr~rell Spray RIE Head Spray KE Head Spray Core Spray Discharge Core Spray Discharge Core Spray Discharge Core Spray Discharge Spray Spray Spray Spray 280

(:

TABLE 3.7.G 1

(This table intentionally left blank) 281-282

3 7.A 6 rr ~ 7.A Primar Conta nment The integrity of the primary containment and operation of the core standby coolinq 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 pipinq.

Thus, containment integrity is specified whenever the potential for violation of the primary reactor system integrity exists.

Concern about such a violation ex'ists whenever the reactor is critical and above atmospheric pressure.

An exception is made to this requirement durinq initial core loading and while the low power test program is being conducted and ready access to the reactor v'essel is required.

There will be no pressure on the system at this time, thus greatly reducing the chances of a pipe break.

The reactor may be taken critical during this period; however, restrictive operating procedures will be in effect again to minimize the probability of'n accident occurring.

Procedures and the Rod Worth Minimixer would limit control worth such that a rod drop would not result in any fuel damage.

In addition, in the unlikely event that an excursion did occur, the reactor buildinq and standby gas treatment

system, which shall be operational during this time, offer a sufficient barrier to keep offsite doses well below 10 CPR 100 limits.

The pressure suppression pool water provides the heat sink for the reactor primary system energy release followinq a postulated rupture of the system.

The pressure suppression chamber ~ater 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 callant

accident, the pressure resulting from isothermal compression plus the vapor pressure of the liquid must'not exceed 62 psig, the suppression chamber maximum pressure.

The design volume of the suppression chamber (water and air) was obtained by considering that the total volume of reactor coolant to be condensed is discharged to the'suppression chamber and that the drywell volume is purged to the suppression chamber.

Using the minimum or inaximum water levels given in the specification, con-tairrment pressure during the design basis accidcnc is approximately 49 psig, vhich is below the maximum of 62 psig.

The mrrximum water level indi-cation of <<l inch corresponds to a dovncomer submergence of 3 feet 7 inches and a water volume of 127,800'ubic feet vith or 128,700ft without the drywall-suppression chamber differential pressure control.

The minimum

• water level indication of -6.25 inches with differential pressure con-trol and -7.25 inches without differential pressure control cot'responds to s downcomer submergence of approximately 3'Edet and a water volume of approximately 123,000 cubic feet.

Haincainirrg the water level between these levels will assure that the torus vater volume and do~m-comcr submergence are within the aforementioned limits during. normal plant operation.

Alarms, adjusted for instrument error, vill notify the operator when the limits of the torus water level are approached.

, The majority of the Bodegrr tests vere run vith a submerged length of 4 feet and with complete condensation.

Thus, with respect to down-comer submergence, this specification is adequate.

The maximum temperature at the cnd of blowdown tested during the Humboldt Bay rrnd Bodega Bay tests was 170'F and this is conservatively taken to bc the limit for complete condensation of the reactor coolant, although corrdensation would occur for temperatures above 170'F.

285

~ ~

~

~

should it Le necessary to drain the suppresoion chamber, this should only be dona when there is no requirement for core o andby cooling syote'ms cpe'rability.

Under full power operation conditions, blowdown from an initial suppression chamber watex temperature or 95oF results in a peak long term water temperature of 170oF which is sufficient for complete condensation.

At this temperature and atmospheric pres-ouxe, the available NPSH e>:ceedo

~

that required by both the RPR and core spray

pumps, thus there is no dependency on containment overpxeosure.

Eiperinmntal data indicate tnat exce sive steam condensiig loads can be avoj!ed if the peak temperat

~ of th suppression pool s neintained below 200 F ]ocn1.

Specifications have been placed on the envelop of reactor operating condition so that the reactor can be depressurized in a timely manner to avoid the regine of potentially high suppression chamber loadings.

Limitinq suppression pool temperature to 105 F during RCIC,

HPCI, or relief valve operation when decay heat and stored energy is removed from the primary system gy diocharqinq reactor ot am directly to the suppression chamber assures adequate margin for controlled blowdown anytime.durinq RCIC omeration and assu=es margin for complete condensation of steam from the design basis loss-of-coolant accident.

In additicn to the 1M.ts on temperature of the suoprcssion cl~~er pool water, operating procedures define the action to be taken in the event a relief valve inadvertently opers or sticks open.

This action would include:

(1) u"e of all ava'lable m ans to close the valve, (2) initiate suppress'on pool water cool 'ng heat exchangers, (3) initiate reactor shutdown, and

(~l) if other relief valves are used to depressurize the reactor,'theu discharge shall be separated from that of the stuck-open relief valve to a sure miving and uniformity of enemy inserticn to the pool.

If a loss-of-coolant accident were to occur when the reac or water temperature is -below approximately 330 F, the containment preosure will not evceed the 62 psig code permissible

preoourc, even if no condensation were to occur.

The maximum allowable pool temperature, whenever the reactor is above 212oF, ohall'e-governed by this specification.

Thus, specifying water volume-temperature requirements applicable for reactor-water temperature above 212oF provides additional margin above that available at 330oF+

In conjunction with the Mark I Conteinm'cnt Short Term program, n plant unique analysis was performed ("Torus Support System and Attached Piping Analysis for the Browns Ferry Nuclear Plant Units 1, 2, and 3," dated September 91976 and supplemented October 12, 1976) which demonstrated a factor of safety of at least two for the weakest element in thc suppression chamber support system end attached piping.

The meintcnencc of e drywell-supprcssion chamber diffcrcn-tiel prcssure oi 1.1 psid and a suppression chamber water level corresponding to e downcomer submergence range of 3,06fcet to 3.58 feet will assure the integrity of the suppression chamber when subjected to post-LOCA suppression pool hydrodynamic forces.

ENCLOSURE 2

DESCRIPTION AND JUSTIFICATION OF CHANGES (TVA BFNP TS 170)

Chan es Related to Reload 4

(Reference attachments C and D)

Pages 18, 24, and 178 - This is the first reload for BF-3 in which She transients were analyzed by General Electric's ODXN code as required by the staff.

An additional citation is being added to the technical specifications to reference NRC's approval of this code for core reloads.

Page 29 - A reference to the GE Generic Reload Topical Report, NEDE-24011-P-A and Addenda, was added to provide further support for the section 2.1 bases.

Pages 26, 27, 30,

192, 224, and 225 - During the reload 4 outage, the two presently installed main steamline safety valves will be replaced with 2-stage Target Rock safety/relief valves (S/RVs) identical to the other 11 S/RVs.

This change was recognized in the reload analyses.

In addition, in sections 2.2 (bases for reactor coolant system integrity) and 3.6.D/4.6.D (bases for relief valves),

the value for the total capacity of the 13 relief valves is being increased to 83.77 percent.

The value of 83.77 percent total relief capacity is derived from the values of 77.33 percent for 12 SRVs operable out of a total of 13 SRVs.

The capacity of 77.33 percent of nuclear boiler rated steam flow, as listed in the BF 3 Reload 4 Supplemental Licensing Submittal, was calculated based on certified valve capacity for a

5. 125-inch throat diameter valve (870,000 lbs/hour at 1,090 +3 psig) issued by the ASME National Board of Boiler and Pressure Vessel Inspectors.

The certified values are obtained by testing and are listed as 90 percent of the measured capacity values for conservatism.

Pages

123, 124,

126, and 133 - During reload 4, eight lead test assemblies (LTAs) will be loaded.

Zn order to obtain additional physics data,'pecial cold criticality tests have been planned for this cycle.

These criticality tests require suspension of the rod sequence control system (RSCS) constraints by means of the individual rod bypass switches, This testing is planned as part of the Lead Test Assembly Program in which 'TVA and GE are participating.

An analysis was performed to show that a postulated rod 'drop accident involving control rods withdrawn during the cold critical test would not exceed the peak, fuel enthalpy design limit of 280 cal/gm.

The rod worth minimizer '(RWM) will be programmed to ensure adherence to the withdrawal sequence specified in the cold critical test procedure.

The RWMImust be operable for this test; a second licensed operator may not be'used in lieu of the RWM for this testing.

Pages vi'., 165,

176, 181,

182, and 182a - During the reload 4

refueling, the last of the initial core type-2 fuel assemblies will be

removed.

Therefore, reference to this fuel type is being deleted.

In

addition, the exposure limits for the presently installed fuel types have been extended as supported by NEDO-24194A (see attachment D).

Finally, MAPLHGR tables have been added for the new fuel types and LTAs loaded this cycle.

Pages ii, viii, 166,

167, 167a, and 182b As supported by the reload submittal, the operating limit MCPRs are being changed.

Since the MCPRs were determined by the ODYN code (rather than the REDY code),

OLMCPRs are now calculated from two curves rather than being a single value (or a ramp change with fuel exposure).

Ch es Related to Torus Modifications Numerous modifications are being implemented in the unit 3 torus during the reload 4 refueling outage as part of the Mark I Containment Program.

These modifications are required by NRC to restore the originally intended margins of safety in the containment design.

The structural modifications to the torus containment include addition of torus tiedowns, addition of ring girder reinforcement and reinforcing attached piping nozzles.

Vent system modifications include shortening the'owncomers, adding local reinforcement to the vent header, and adding new tie bars to the downcomers.

Attached piping is being strengthened including modification of the ECCS header support.

Many changes are being made to the safety relief valve piping system including adding quencher arms to the ramshead, adding quencher arm and ramshead

supports, adding 10-inch vacuum valves, reinforcing the ring girder at the SRV hanger attachemnt, rerouting of piping, and adding new snubbers and supports for the piping.

Pages 231 and 285 - The minimum torus water level limits in section 3.7.A.1.a and in the bases for this section are being changed from

-7 inches (differential pressure control greater than 0 psid) to

<<6.25 inches and from -8 inches (0 psid differential pressure control) to -7.25 inches; a ohange in each case of 0.75 inch.

There are 15-.

inch by 15-inch sealed box beams being added as support for the safety relief valve lines and HPCI-RCIC internal supports.

Addition of these supports will result in-appreciable water displacement.

Calculations indicate that the box beams and HPCI-RCIC supports will increase the torus water level approximately 3/4 inch due to their presence.

This rise in the torus water level is reflected in these revised technical specification values.

Pages 246 and 286 - In section 3.7.A.6.a (and the bases therefore),

the setpoint for the drywell-suppression chamber (wetwell) differential pressure control (AP) is being changed from 1.3 psid to 1.1 psid.

Downcomer water clearing loads are greatly reduced by physically shortening the downcomers (by almost one foot) and imposing a drywell>>wetwell AP.

The Browns Ferry unique loads were determined by considering a differential pressure of 1. 10 psid at the maximum allowable torus water level.

In order to be consistent with this ana'ysis, the technical specification associated with the AP control has been established at 1.10 psid.

Pages 286 - In the bases for the limits established for primary containment, there is a discussion of steam condensing loads assooiated with relief valve operation.

The peak temperature of the torus water used in the evaluation is being changed from 160 F to 200 F looal temperature.

During the current refueling outage, the T-quenchers are being added.

to the safety-relief valve discharge device.

The NRC licensed value for the T-quencher is 200 F local water temperature (to avoid excessive steam condensing loads).

This technical specification change is needed to reflect that T-quencher licensed value of temperatur e.

C.

Adminstrative Chan es Pages iii, 19,

195, and 227 - The paragraph title pertaining to recirculation pump operation has been changed to be more consistent with the speoification intent.

Additionally, section 2.1 of the technical specifications contains the bases for the "limiting safety system settings related to fuel cladding integrity."

At the top of page 19 there is presently a paragraph relating to operation'n the natural circulation mode.

This paragraph is being moved, verbatim, to the bases for recirculation pump operation on page 227, which is a more appropriate location.

There is no safety significance to this reformatting of the technical specifications.

/

Pages 146 and 149 - These changes are administrative changes that remove references to nonapplicable technical specification requirements.

These changes do not affect any actual limiting conditions for operation; therefore, plant safety is not affected.

Page 95 - Surveillance requirements due to addition of RCIC steam flow isolation time delay relay have been added.

Surveillance on HPCI time delay relay required by NUREG-0737 item II.k.3.15 is also added.

Page 178 - Reporting requir ements changed to be consistent with other units.

Descri tion Justification and Safet Anal sis for Thermal Power Monitor Technical S ecification Chan es - Unit 3 Descri tion Page 9 - Add "Flow Biased" to title of Section 2.1.A.1.

Page 11 - Add Section 2.1.A.4.

Pages 19, 20 - Reword basis 2.1.A.1 to reflect features of thermal power monitor.

'age 21 - Add basis 2.1.A.4 to describe fixed trip.

Page 32 - Change table 3. 1.A to reflect addition of fixed trip function.

Page 35 - Add notes 23 and 24.

Page 36 - Change table 4.1.A to reflect addition of fixed trip.

Justification The addition of the thermal power monitor will prevent a flow biased neutron flux scram when a transient-induced neutron flux spike oocurs that is of short time duration and does not result in an instantaneous heat flux in exoess of transient limits.

Heat flux is damped by approximately a

6-second fuel,time constant.

This feature will reduce the number of scrams due to small est flux transients such as those which result from control valve and MSXV testing and small perturbations in water level and pressure.

Safet Anal sis The APRM flow biased scram will occur when the fuel surface heat flux resulting from a neutron flux transient reaches a point equivalent to the

-thermal power trip setpoint.

This is done by passing the neutron flux signal through a filter network with a time constant representative of the fuel thermal time constant.

There is a separate trip unit which initiates a scram at less than 120 percent instantaneous neutron.flux.

This scram function is the basis for transient and accident analysis and no credit is taken for the flow biased scram function.

Any flow biased scram function therefore provides additional margin from fuel damage beyond that of the transient analysis.

Description and Justification Primar Containment Isolation Valves Tables 3.7.A to 3.7.G are being revised to reflect several plant modifi-.

cations.

All revisions to these tables that were submitted in previous technical specification submittals are also being incorporated in these proposed revisions.

The revisions to this table will'upercede revisions of the following submittals:

TVA BFNP TS 133~ 146, and-162 Supplement, Table 3.7.A FCV-1-55 and 1-56 drain valves are required to be open for extended periods during power operation.

Therefore, these valves will be considered as normally open and technical specification surveillance requirement 4.7.D.l.b will apply.

It is proposed to delete valve FCV-69-12 from Table 3.7.A.

This valve is not a containment isolation valve.

Isolation is provided by check valves69-579 and 3-572.

FCV-73-81, the bypass valve around the HPCI steam supply outboard isolation valve (FCV-73-3), was added to unit 3 during the 1980 refuel outage.

During quarterly surveillance testing on HPCI isolation valve FCV-73-3 in which the valve is closed and reopened, the steamline downstream from FCV-73-3 is subject to 'thermal stresses from the closure and subsequent reopening.

FCV-73-81 was added to relieve those thermal stresses.

This is a 1-inch valve. It is an isolation group 4 valve with a maximum closure time of 10 seconds.

In response to our generic letters of September 27, 1979 and October 22, 1979 to "AllLight Water Reactors,"

TVA is modifying the containment purge system for unit 3 during this outage to satisfy applicable require-ments of NRC Branch Technical Position CSB 6-4 regarding valve closure times and addition of debris screens.

Pages 263 and 264 are being revised to reflect the significant reduction in the maximum allowable operating time for the purge valves.'n the nitrogen purge valves, the operating time is being reduced from 10 seconds to 5 seconds and on the purge inlet and isolation valves, the operating time is being reduced from 90 seconds'o only 2.5 seconds.

The faster valve closure times significantly reduce potential offsite doses.

The addition of the debris screens provides protection against foreign material entering the purge ducting and inter-fering with closure of the purge valves.

In our letter of June 2, 1981, TVA provided the data and analysis to demonstrate that the purge valves are adequate for closure against the design basis, loss-of-coolant accident forces.

During the 1980 refueling outage on unit 3, the hydrogen-oxygen analyzer system was replaced with the new Hays-Republic Hydrogen-Oxygen analyzer system.

The safety evan'uation for that new system was done at the time the system was installed, i.e.,

the refuel outage.

All system 76 (contain-ment inerting system) valves added to pages 274 and 274A were installed in the plant as part of the new H -0 system.

The table is updated to reElect plant configuration.

System suction isolation valves to the drywell air compressors "B," FCV-32-62 and FCV-32-63, have been installed in the plant a system modification.

The drywell air compressors supply air operated valves in containment.

This table should reflect the "A" and as part of to the air-change.

Thu normal position of FCV-71-7A, 7B is closed and page 274A should be changed to reflect this.

The core spray discharge to reactor check valves FCV-75-26 and FCV-75-54 should be included in this table.

They are primary containment isolation valves and were inadvertently omitted from this table.

lt is proposed to add to table 3.7.A valves FCV-64-139 and FCV-64-140.

These are the drywell AP air compressor suction and discharge valves.

They are containment isolation valves and should be verified for operating time.

These valves are a part of the addition of the drywall pressurization system.

The following additions are proposed for table 3.7.A because these valves were inadvertently omitte'd in the original technical specifications.

These valves are all containment isolation valves,and should be verified for operating time.

FCV-90-'254A arid B, drywell CAM suction valve FCV>>90-'257A and B, drywell CAM discharge valves FCV-90-255, drywell CAM suction valve Tables 3.7.D throu h 3.7.G Tables 3.7.D through 3.7.G have been completely revised to be more consistent with standard technical specifications.

These tables contain a "Test Medium" and "Test Method."

The proposed tables have been revised to contain the "Test Medium" within the title of the table and eliminate the "Test Method" altogether.

The standard technical specifications do not contain a test method Eor testing isolation valves and therefore should be deleted for these tables.

The test methods for these valves are contained in their specific testing instructions and therefore should not be contained in the technical specifications.

The deletio'n of the test methods should not have any adverse impact on safety.

The following valves have been added to table 3.7.D.

Valve 76-66 on the new Hays-Republic H -0 analyzer Valve 73-81, bypass valve around HPCI outboard isolation valve 73-3 2

Test connections were added to unit 3 so that the following valves could be tested.

FdV-2-119 2 FCV-2-1383 FCV-33-1070 FCV-33-785 FCV-68-508 FCV-68"523 FCV-68-550 FCV-68-555 Service Water Service Water Service Air Service Air CRD to RC Pump Seals CRD to RC Pump Seals CRD to RC Pump Seals CRD to RC Pump Seals h

Valves 74-54 and 74-68 have been added to table 3. 7. D due to inadver ten tly omitting them from this table.

They are tested and should be included in the technical specifications.

Valves76-215 to 76-254 have been deleted from table 3.7.D due to the replacement of the H -02 analyzer system.

Valve 64-141 has also been deleted because it is not an isolation valve and is not tested.

Valve 85-573 has been omitted from this table due to a plant modification that eliminated the containment penetration for this CRD return line.

9'able 3.7.E Table 3.7.E has been revised to include valve 2-1143 which is now being

'tested.

SUMMARY

The plant modifications and changes described above are significant improvements in plant safety.

Tables 3.7.A through 3.7.G have been revised to reflect all plant modifications affecting the primary containment Isolation syst: em.

Since these proposed revisions reflect changes which should not adversely affect plant safety, they should be approved.