Text

Forwards Corrections to Final Draft Tech Specs.Errors Grouped by Processing Changes to Unit 1 Tech Specs Published in Fr,Specific Unit 2 Changes & Word Processing Mishaps
	ML20151Z212
Person / Time
Site:	Catawba
Issue date:	02/10/1986
From:	Tucker H; DUKE POWER CO.
To:	Harold Denton, Youngblood B; Office of Nuclear Reactor Regulation
References
	NUDOCS 8602140096
	Download: ML20151Z212 (51)
	v • d • e

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,9 DUKE W

3, CHAMMYMT. N,0. 88242 HALH. TUCKER trLarusamn

.n momen (704) UF:>4fkN f

February 10, 1986 Mr. Harold R. Denton, Director Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, D. C.

20555 Attention:

Mr. D. J. Youngblood, Project Director PWR Project Directorate No. 4 Re Catawba Nuclear Station, Units 1 and 2 Docket Nos. 50-413 and 50-414 Final Draft Technical Specifications

Dear Mr. Denton:

Attached are corrections to the Final Draft Technical Specifications found by our ongoing review.

The errors identified can be grouped into three categories, (1)

Errors due to processing changes made to the Unit 1 Technical Specifications that have been published in the Federal Register; (2)

Errors in processing' Unit 2 specific changes; and (3)

Errors due to word processing mishaps during the Final Draft printing.

Errors that fall under item (1) are those on pages: 3/4 3-24, 3-38, 4-40, 9-14, D 3/4 6-3, D 3/4 7-3, D 3/4 9-1, D 3/4 9-3, 6-4, 6-18, and 6-21 (Note, changes to the Bases pages are not license amendments and therefore have not been published in the Federal Register).

The errors on the following pages fall under item (2):

3/4 3-31, 3-69, 3-73, 3-74, 3-76, 6-29 and attached insert pages, 6-46, 7-9, 7-34, 7-35, 8-12, 8-19, 8-32, 8-35, 8-58, 8-61, B 3/4 4-2, D 3/.4 4-9 and 6-5.

The errors identified as falling under item (3) appear on pages:

1-9, B 2-1 through L 2-8, 3/4 3-52 and D 3/4 4-4.

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Mr. Hcrold R. Danton, Dircctor February 10, 1986 Page Two If you have any questions regarding this submittal please contact Mr. Roger W.

Ouellette at (704)373-7530.

Very truly yours, fA /.^^

/h/

Hal B.

Tucker RWO:slb Attachment cc:

Dr. J. Nelson Grace, Regional Administrator U.

S. Nuclear Regulatory Commission Region II 101 Marietta Street, NW, duite 2900 Atlanta, Georgia 30323 NRC Resident Inspector Catawba Nuclear Station

.. 1 s.

JAN 8 1986 FINAL. DRAff TABLE 1.2 OPERATIONAL MODES REACTIVITY

% RATED AVERAGE COOLANT MODE

_ CONDITION. K THERMAL POWER

TEMPERATURE ff 0.99

> ) 5%

?

350*F

1.. POWER OPERATION E/

2.

STARTUP 3g ). 99 I,,,P SX 2

1 350*F 3.

HOT STANDBY

4. / 3.99 3

350*F 4.

HOT SHUTDOWN 4 / 0.99 0

350*F T"#9 y $2007 5.

COLD SHUTDOWN 4

F 0.99 0

f, 200*F 6.

REFUELING **

f, / 0.95 0

g 140*F V

" Excluding decay heat.

- Fuel in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.

De CATAWBA - UNITS 1 & 2 1-9 p.,, jogg

O JAN 8 1986 j-2.1 SAFETY LIMITS s

BASES 2.1.1 REACTOR CORE 1

possible cladding perforation which would result in th products to the reactor coolant.

by restricting fuel operation to within the nucleate boiling regime heat transfer coefficient is large and the cladding surface temperature is slightly above the coolant saturation temperature.

resurit in excessive cladding temperatures because from nucleate boiling (DNB) and the resultant sharp reduction in heat tran coefficient.

DN8 is not a directly measurable parameter during operation and er therefore THERMAL POWER and Reactor Coolant Temperature and Pr related to DN8 through the WRB-1 correlation.

uniform and nonuniform heat flux distributions.been develope particular core location to the local heat flux, and is margin to DN8.

The DNB design basis is as follows:

'N there must be at least a 95%

II events is greater than or equal to the DN8R limit of j

being used (the WRB-1 correlation in this application).

that there is a 95% probability with 95% confidence The correlation DN8R when the minimum DN8R is at the DNBR limit.

In meeting this design basis, uncertainties in pl nt operating parameters nuclear and thermal parameters, and fuel fabrication parameters are consid statistically such that there is at least a 95% confidence that the minimum DN8R for the limiting rod is greater than or equal to the DNBR Ifmit uncertainties in tte above plant parameters are used to determine the plant

. The DNBR uncertainty.

This DN8R uncertainty, combined with the correlation DNBR limit, establishes a design DNBR value which must be met in plant safety analyses using values of input parameters without uncertainties.

Reactor Coolant System pressure and average tempera at the vessel exit is less than the enthalpy of saturated l

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NIf1 h CATAWBA -

8 2-1 DEC 3 ' ICM i

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'W JAN 8 1985 2.1 SAFETY LIMITS BASES This curve is based on a nuclear enthalpy rise hot channel factor, N

F f 1.49 and a reference cosine with a peak of 1.55 for axial power shape.

AH, An allowance is included for an increase in Fh at reduced power based on the expression:

N Fg = 1.49 [1 + 0.3 (1-P)]

Where P is the fraction of RATED THERMAL POWER.

These limiting heat flux conditions are higher than those calculated for the range of all control rods fully withdrawn to the maximum allowable control rod insertion assuming the axial power imbalance is within the limits of the (AI) function of the Overtemperature trip. When the axial power imbalance f2 is not within the tolerance, the axial power imbalance effect on the Over-temperature AT trips will reduce the Setpoints to provide protection consistent with core Safety Limits.

2.1.2 REACTOR COOLANT SYSTEM PRESSURE The restriction of this Safety Limit protects the integrity of the Reactor Coolant System from overpressurization and thereby prevents the release of radionuclides contained in the reactor coolant from reaching the containment A

atmosphere.

The reactor vessel, pressurizer, and the Reactor Coolant System piping, valves, and fittings are designed to Section III of the ASME Code for Nuclear Power Plants which permits a maximum transient pressure of 110% (2735 psig) of design pressure.

The Safety Limit of 2735 psig is therefore consistent with the design criteria and associated Code requirements.

The entire Reactor Coolant System is hydrotested at 125% (3110 psig) of design pressure, to demonstrate integrity prior to initial operation.

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FINAL DRAFT

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2. 2 LIMITING SAFETY SYSTEM SETTINGS BASES 2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS The Reactor Trip Setpoint Limits specified in Table 2.2-1 are the nominal values at which the Reactor trips are set for each functional unit.

Setpoints have been selected to ensure that the core and Reactor CoolantThe Trip System are prevented from exceeding their safety limits during normal operation and design basis anticipated operational occurrences and to assist the Engi-neered Safety Features Actuation System in mitigating the consequences of accidents.

The Setpoint for a Reactor Trip System or interlock function is considered to be adjusted consistent with the nominal value when the "as measured" Setpoint is within the band allowed for calibration accuracy.

To accommodate the instrument drift assumed to occur between operational tests and the accuracy to which Setpoints can be measured and calibrated.

Allowable Values for the Reactor Trip Setpoints have been specified in Table 2.2-1.

Operation with Setpoints less conservative than the Trip Setpoint but within the Allowable Value is acceptable since an allowance has been made in the safety analysis to accommodate this error.

An optional provision has been included for determining the OPERABILITY of a channel when its Trip Setpoint is found to exceed the Allowable Value.

The methodology of this option utilizes the "as measured" deviation from the specified calibration point for rack and sensor components in conjunction with a statistical combina-T tion of the other uncertainties of the instrumentation to measure the process J

variable and the uncertainties in calibrating the instrumentation.

In Equa-tion 2.2-1, Z + R + S < TA, the interactive effects of the errors in the rack and the sensor, and the "as measured" values of the errors are considered.

Z, as specified in Table 2.2-1, in percent span, is the statistical summation of errors assumed in the analysis excluding those associated with the sensor and rack drift and the accuracy of their measurement. TA or Total Allowance is the difference, in percent span, between the Trip Setpoint and the value used in the analysis for Reactor trip. R or Rack Error is the "as measured" devia-tion, in percent span, for the affected channel from the specified Trip Set-point.

S or Sensor Error is either the "as measured" deviation of the sensor from its calibration point or the value specified in Table 2.2-1, in percent span, from the analysis assumptions. Use of Equation 2.2-1 allows for a sensor drift factor, an increased rack drift factor, and provides a threshold value for REPORTABLE EVENTS.

The methodology to derive the Trip Setpoints is based upon combining,all of the uncertainties in the channels.

Inherent to the determination of tM Trip Setpoints are the magnitudes of these channel uncertainties.

Sensors and other instrumentation utilized in these channels are expected to be capable W operating within the allowances of these uncertainty magnitudes.

Rack drift in excess of the Allowable Value exhibits the behavior that the rack has not met its allowance.

Being that there is a small statistical chance that this will happen, an infrequent excessive drift is expected.

Rack or sensor drift, in excess of the allowance that is more than occasional, may be indicative of sore serious problems and should warrant further investigation.

t 3

CATAWBA-UNIjl/2.

8 2-3 DEC 31 1985

JAN 8 1986 LIMITING SAFETY SYSTEM SETTINGS BASES 5

REACTOR TRIP SYSTEM INSTRUMENTATION SET breakers whenever a condition monitored by the or trip preset or calculated level.

design approach provides a Reactor Trip System which mo%

ystem reaches a variables, therefore providing Trip System functional diversity umerous system diverse Reactor trips for which no direct credit wa The functional analysis to enhance the overall reliability of the Reactor Trip Syste ry or e accident Reactor Trip System initiates a Turbine trip signal whenever Re m.

The initiated.

from excessive Reactor Coolant System cooldown and actor trip is l

~

actuation of the Engineered Safety Features Actuation System unnecessary Manual Reactor Trio The Reactor Trip System includes manual Reactor trip capabil Power Range,~ Neutron Flux In each of the Power Range Neutron Flux channels there are O

bistables each with its own trip setting used for setting.,The Low Setpoint trip provides protection,a High and Low Range t

'/

endent A

power operations to mitigate the consequences of a power excursion be during subcritical and low.

from low power, and the High Setpoint trip provides protection d g nning operations to mitigate the consequences of a reactivity excursion from uring power power levels.

The Low Setpoint trip may be manually blocked above P-10 (a of approximately 10% of RATED THERMAL POWER) and is auto i

below the P-10 Setpoint.

e Power Range, Neutron Flux, High Rates l

increases which are characteristic. of a rupture of a t

Specifically, this trip complements the Power Range Neutron Flux H ux e housing.

l trips to ensure that the criteria are met for all rod ejection accide t and Low n s.

The Power Range Negative Rate trip provides protection for contro drop accidents.

At high power a rod drop accident could cause local flux peaking which could cause an unconservative local DN8R to exist No credit is taken for operation of the Power Ran i

or.

those control rod drop accidents for which DN8Rs will be greater than th or applicable design limit DNBR value for each fuel type.

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b CATAWBA (- UNIf1hb7 8 2-4 i

DEC 31 1985

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5 JAN 8 1986 LIMITING SAFETY SYSTEM SETTINGS BASES Intermediate and Source Range, Neutron Flux The Intermediate and Source Range, Neutron Flux trips provide core pro-tection during reactor startup to mitigate the consequences of an uncontrolled rod cluster control assembly bank withdrawal from a subcritical condition.

These trips provide redundant protection to the Low Setpoint trip of the Power Range, Neutron Flux channels.

The Source Range channels will initiate a Reactor trip at about 105 counts per second unless manually blocked when P-6 becomes active or automatically blocked when P-10 becomes active.

The Intermediate Range channels will initiate a Reactor trip at a current level equivalent to approximately 25% of RATED THERMAL POWER unless manually blocked when P-10 becomes active.

Overtemperature AT 4

The Overtemperature AT trip provides core protection to prevent DNS for all combinations of pressure, power, coolant temperature, and axial power distribution, provided that the transient is slow with respect to piping transit delays from the core to the temperature detectors (about 4 seconds),

and pressure is within the range between the Pressurizer High and Low Pressure trips. The Setpoint is automatically varied with: (1) coolant temperature to correct for temperature-induced changes in density and heat capacity of water N

and includes dynamic compensation for piping delays from the core to the loop

(

j temperature detectors, (2) pressurizer pressure, and (3) axial power distribu-tion.

With normal axial power distribution, this Reactor trip limit is always below the core Safety Limit as shown in Figure 2.2-1.

If axial peaks are greater than design, as indicated by the difference between top and bottom power range nuclear detectors, the Reactor trip is automatically reduced according to the notations in Table 2.2-1.

Overpower AT The Overpower AT trip provides assurance of fuel integrity (e.g., no fuel pellet melting and less than 1% cladding strain) under all possible overpower conditions, limits the required range for Overtemperature AT trip, and provides a backup to the High Neutron Flux trip. The Setpoint is l

automatically varied with:

(1) coolant temperature to correct for temperature-induced changes in density and heat capacity of water, and (2) rate of change i

l of temperature for dynamic compensation for piping delays from the core to the loop temperature detectors, to ensure that the allowable heat generation rate (kW/ft) is not exceeded. The Overpower AT trip provides protection to mitigate the consequences of various size steam breaks as reported in WCAP-9226,

" Reactor Core Response to Excessive Secondary Steam Releases."

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FiWfd. D h n LIMITING SAFETY SYSTEM SETTINGS BASES Pressurizer Pressure In each of the pressurizer pressure channels, there are two independent bistables, each with its own trip setting to provide for a High and Low Pressure trip thus limiting the pressure range in which reactor operation is permitted.

The Low Setpoint trip protects against low pressure which could lead to DN8 by tripping the reactor in the event of a loss of reactor coolant pressure.

On decreasing power the Low Setpoint trip is automatically blocked by P-7 (a power level of approximately 10% of RATED THERMAL POWER with turbine impulse chamber pressure at approximately 10% of full power equivalent); and on increasing power, is automatically reinstated by P-7.

The High Setpoint trip functions in conjunction with the pressurizer relief and safety valves to protect the Reactor Coolant System against system overpressure.

Pressurizer Water Level The Pressurizer High Water Level trip is provided to prevent water relief through the pressurizer safety valves. On decreasing power, the Pressurizer High Water Level trip is automatically blocked by P-7 (a level of approxi-mately 10% of RATED THERMAL POWER with a turbine impulse chamber pressure at,

A i

/

approximately 10% of full power equivalent); and on increasing power, is automatically reinstated by P-7.

Reactor Coolant Flow The Low Reactor Coolant Flow trips provide core protection and prevents DNS by mitigating the consequences of a loss of flow resulting from the Icss of one or more reactor coolant pumps.

On increasing power above P-7 (a power level of approximately 10% of RATED THERMAL POWER or a turbine impulse chamber pressure at approximately 10%

of full power equivalent), an automatic Reactor trip will occur if the flow in more than one loop drops below 90% of nominal full loop flow. Above P-8 (a power level of approximately 48% of RATED THERMAL POWER) an automatic Reactor trip will occur if the flow in any single loop drops below 90% of nominal full loop flow.

Conversely, on decreasing power between P-8 and P-7 an automatic Reactor trip will occur on low reactor coolant flow in more than one loop and below P-7 the trip function is automatically blocked.

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LIMITING SAFETY SYSTEM SETTINGS BASES Steam Generator Water Level The Steam Generator Water Level Low-Low trip protects the reactor from loss of heat sink in the event of a sustained steam /feedwater flow mismatch resulting from loss of normal feedwater. The specified Setpoint provides allowances for starting delays of the Auxiliary Feedwater System.

Undervoltaos and Underfrequency - Reactor Coolant Pump Busses The Undervoltage and Underfrequency heactor Coolant Pump Bus trips pro-vide core protection against DNB as a result of complete loss of forced coolant flow.

The specified Setpoints assure a Reactor trip signal is generated before the Low Flow Trip Setpoint is reached.

Time delays are incorporated in the Underfrequency and Undervoltage trips to prevent spurious Reactor trips from momentary electrical power transients.

For undervoltage, the delay is set so that the time required for a signal to reach the Reactor trip breakers following the simultaneous trip of two or more reactor coolant pump bus circuit breakers shall not exceed 2 seconds.

For underfrequency, the delay is set so that the time required for a signal'to reach the Reactor trip breakers after the Underfrequency Trip Setpoint is reached shall not exceed 0.3 second.

On decreasing power the Undervoltage and Underfrequency Reactor Coolant Pump Bus trips are automatically blocked by P-7 (a power level of approximately 10%

}

of RATED THERMAL POWER; with a turbine impulse chamber pressure at approxi-mately 10% of full power equivalent); and on increasing power, reinstated i

automatically by P-7.

Turbine Trio A Turbine trip initiates a Reactor trip. On decreasing power the Reactor trip from the Turbine trip is automatically blocked by P-9 (a power level of approximately 69% of RATED THERMAL POWER); and on increasing power, reinstated automatically by P-9.

Safety Injection Input from ESF If a Reactor trip has not already been generated by the Reactor Trip System instrumentation, the ESF automatic actuation logic channels will initiate a Reactor trip upon any signal which initiates a Safety Injection.

The ESF instrumentation channels which initiate a Safety Injection signal are shown in Table 3.3-3.

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CATAWBA UNIl51f 2;.

B 2-7 DEC 3t 1985

s LIMITING SAFETY SYSTEM SETTINGS BASES Reactor Trip System Interlocks The Reactor Trip System interlocks perform the following functions:

P-6 On increasing power P-6 allows the manual block of the Source Range trip (i.e., prevents premature block of Source Range trip), deener-gizes the high voltage to the detectors.

On decreasing power, Source Range Level trips are automatically reactivated and high voltage restored.

P-7 On increasing power P-7 automatically enables Reactor trips on low flow in more than one reactor coolant loop, reactor coolant pump bus undervoltage and underfrequency, pressurizer low pressure and pressurizer high level. On decreasing power, the above listed trips are automatically blocked.

P-8 On increasing power P-8 automatically enables Reactor trips on low flow in one or more reactor coolant loe;s. On decreasing power, the P-8 automatically blocks the above listed trips.

P-9 On increasing power P-9 automatically enables Reactor trip on Turbine trip. On decreasing power, P-9 automatically blocks Reactor

~ ~N trip on Turbine trip.

S

]

P-10 On increasing power P-10 allows the manual block of the Intermediate

/

Range trip and the Low Setpoint Power Range trip; and automatically blocks the Source Range trip and deenergizes the Source Range high voltage power.

On decreasing power, the Intermediate Range trip and the Low Setpoint Power Range trip are automatically reactivated.

Provides input to P-7.

P-13 Provides input to P-7.

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l CATAWBA UNI $1h'L 8 2-8 DEC 1 ' ic85

(

)

Q TABLE 3.3-3 (Continued) c E

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION s

c

i MINIMUM c

TOTAL NO.

CHANNELS CHANNELS APPLICABLE 5

FUNCTI0fA'

"'T OF CHANNELS TO TRIP OPERABLE MODES ACTION

~

6/A lary Bull i Filtered e.

.....::_1 L. E aus Operation (Continued

,o I

A a',

ection r-See Item 1. above for all Safety Injection initiating functions and requirements.

17. Diesel Building Ventilation Operation I

a.

Manual Initiation 2

1 2

1,2,3,4 18

)

b.

Automatic Actuation Logic j

y

.and Actuation Relays 2

1 2

1,2,3,4 21 i

c.

Emergency Olesel Generator j

Operation See Item 15. above for all Emergency Diesel Generator Operation initiating functions and requirements.

18. Engineered Safety Features j

Actuation System Interlocks a.

Pressurizer Pressure, 3

2 2

1,2,3 20 P-11 l

b.

Pressurizer Pressure, 3

2 2

1,2,3 20 E

not P-11 g

4 P

Low-Low T,yg, P-12 c.

4 2

3 1,2,3 20 D

d.

Reactor Trip, P-4 2

2 2

1,2,3 22 e.

Steam Generator Water 4/sta. gen.

2/sta. g<.n.

3/sta.

1, 2, 3 20 Level, P-14 in any gen. In g

o operating each qi g

stm. gen.

operating

- -l vi stm. gen.

J

i j

FABLE 3.2

.tinued) f ENGINEEREDSAFETYFEATURESACTUATION'SYSTEMINSTRUMENTATIONTRIPSETPOINTS n

NSOR k

h La M

ROR me g FUNCTIONAL tmII ALLOWANCE (TA)

(S)

TRIP SETPOINT ALLOWA8LE VALUE j

' 8. Auxiliary Feedwater (Continued) a m

c.

Steam Generator Water d

Level - Low-Low 1.

Unit 1 17 14.2

1. 5

> 17% of span

> 15.3% of i

e' m

rrom UX m span from 0% to

[30% RTP G0X RT_P increasinP Y

increast j

innearly to linearly to a

> 53.2% of span 1 54.9% of q

from 30% to 100%

3 span from 30%

l RTP l

t to 100% RTP J j

2.

Unit 2 17 14.2 1.5

>17% of narrow >15.3% of narrow Frange instrum W

range instrument Laent span J span y

d.

Safety Injection See Item 1. above for all Safety Injection Setpoints and Allowable Values.

I

[

e.

Loss-of-Offsite Power N.A.

N.A.

N. A.

> 3500 V

),3200 V h

f.

Trip of All Main Feedwater l

Pumps N.A.

N.A.

g.

Auxiliary Feedwater Suction i

Pressure-Low M

namen

1) CAPS 5220, 5221, 5222 N.A.

N.A.

1

-> 10.5 psig

> 9.5 psig

2) CAPS 5230, 5231, 5232 g

1 a.

Unit 1 N.A N.A.

N.A.

1 6.2 psig

> 5.2 psig D.

Unit 2 N.A.

N.A.

-> 6.0 psig

-> 5.0 psig j

9. Containment Sump Recirculation C".;I NEA j

a.

Automatic Actuation Logic N.A.

N.A.

j and Actuation Relays gg3 j

j; b.

Refueling Wat'er Storage N.A.

N.A.

M.A.

1 177.15 inches > 162.4 inches mapg

) g se o

Tank Level-Low ar..::j i

Coincident With Safety

{ ". "

Injection See Item 1. above for all Safety Injection Setpoints and Allowable Values.

1 m

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JAN 8 1986 FlhjAL ED 1 oua 2

_ TABLE 3.3-5 (Continued)

ENGINEERED SAFETY FEATURES RESPONSE TIMES INITIATING SIGNAL AND FUNCTION RESPONSE TIME IN SECONDS 2.

Containment Pressure-High (Continued)

11) Ann entilation Operation 1 23 12), uxiliarv 1 ding Filtered Exhaust Operation N. A.

3) Containee Sump Recirculation N.A.

3.

Pressurizer Pressure-Low Safety Injection (ECCS) 1 27(1)/12(3) a.

1)

Reactor Trip i2 2)

Feedwater Isolation

<7 3)

Phase "A" Isolation (2)

}3g(3)/28(4) 4)

Purge and Exhaust Isolation

<6 5)

Auxiliary Feedwater(5) jj,3, 6)

Nuclear Service Water Operation 1 65(3)/76(4) 7)

Turbine Trip H.A.

8)

Component Cooling Water 5 65(3)/76(4) 9)

Emergency Diesel Generator Operation 1 11 10)

Control Room Area Ventilation Operation N.A.

11)

Annulus Ventilation Operation 1 23 12)

Auxiliary Building Filtered N.A.

Exhaust Operation 4

13)

Containment Sump Recirculation N.A.

4.

Steam Line Pressure-Low SafetyInjection(ECCD 1 12(3)/22(4) a.

1)

Reactor Trip i2 2)

Feedwater Isolation

<7 3)

Phase "A" Isolation (2) h1853)/28I4) 4)

Purge and Exhaust Isolation 16 5)

Auxiliary Feedwater(5) 1 60 6)

Nuclear Service Water Operation 1 65(3)/76(4) 7)

Turbine Trip 9

H.A.

8)

Component Cooling Water

< 65(3)/76(4) 9)

Emergency Diesel Generator Operation 11 CATAWBA - UNITS 1 & 2 3/4 3-38 DEC' 31 1985

2 TABLE 3.3-6 h'

5 RADIATION MONITORING INSTRUMENTATION FOR PLANT OPERATIONS s

i E

MINIMUM CHANNELS CHANNELS APPLICABLE ALARM / TRIP

]

FUNCTIONAL UNIT TO TRIP / ALARM OPERABLE MODES SETPOINT ACTION

[

1.

Containment

a. Ccr.tainment Atmosphere - High 1

1 All Gaseous Radioactivity (Low 30 i

Range - EMF-39)

b. Reactor Coolant System Leakage j

Detection

1) Particulate Radioactivity

{

(Low Range - EMF-38)

N.A.

1 1,2,3,4 N. A.

33

2) Gaseous Radioactivity w

g (Low Range - EMF-39)

N.A.

1 1,2,3,4 N.A.

33 1

2.

Fuel Storage Pool Areas

. ' 'e

a. High Gaseous Radioactivity (Low Range - EMF-42) 1 1

$ 1.7x10 4 pC1/mi 34 "T1

b. Criticality-Radiation Level (Fuel Bridge - Low Range -

{

IEMF-15, 2 EMF-4) 1 1

5 15 mR/h 32 M

3.

Control Room P

Air Intake-Radiation Level -

1/ intake -

2 (1/in-All

< 1.7x10 4 pCi/ml 31 D

High Gaseous Radioactivity take) m (Low Range - EMF-43 A & 8) i S

M o

4.

Auxiliary Building Ventilation 1

1 1,2,3,4 5 1.7x10 4 pCi/ml 35 "lF1 High Gaseous Radioactivity g

w (Low Range - EMF-41)

S.

Component Cooling Water System

' EMF-46 A&B) 1 1

All

< 1x10 3 pCi/mi

. I

\\

s 1

h

g.,

..%./

I TABLE 4.3-7 (Continued) 9 3;;!

ACCIDENT. MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS I

le CHANNEL CHANNEL INSTRUMENT (Continued)

CHECK CALIBRATION E

]

}

15.

In Core Thermocouples M

R H

16. Unit Vent - High-High Range Area Monitor (EMF-54)

M R

1 i

N

17. Steam Relief Valve Exhaus adiation Monitor (1

-26, 27, 28 and 29 and 2 EMF-10,

_1 M

R

18. Containment Area -_High R Radiation Monito (EMF-53 A&B)

M R*

19. Reactor Vessel Water Level M

R I

20. Reactor Coolant Radiation Level (EMF-48)

M R

Y 4

i

CHANNEL CALIBRATION may consist of an electronic calibration of the channel, not including the detector, for range decades above 10R/h and a one point calibratic.: check of the detector below 10R/h with an j

installed or portable gamma source.

1 M

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wam h

i W

1 a

Y NTED i

Sri 4

l

s

't

s... /

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y TABLE 3.3-11 9

5!

FIRE DETECTION INSTRUMENTS I

E E""

a FIRE c.5 ZONE DESCRIPTION MINIMUM INSTRUMENTS OPERABLE

LOCATION SM0KE FLAME HEAT FUNCTION **

d 1

R.H.R. Pump IB GG-53 E1.522 + 0 1

0 1

A 2

R.H.R. Pump 1A FF-53 E1.522 + 0 1

0 1

A n.

3 Cont. Spray Pump 18 GG-54 E1.522 + 0 3

0 3

A m

4 Cont. Spray Pump 1A GG-55 E1.522 + 0 2

0 2

A 5

R.H.R. Pump 2B GG-61 E1.522 + 0 1

0 1

A 6

R.H.R. Pump 2A FF-61 E1.522 + 0 1

0 1

A 7

Cont. Spray Pump 28 GG-60 E1.522 + 0 3

0 3

A 8

Cont. Spray Pump 2A GG-59 E1.522 + 0 2

0 2

A 9

Aux. F. W. Pumps BB-51 E1.543 + 0 14 0

12(6)

A(B)

IG Mech. Pene. Room JJ-52 E1.543 + 0 3

0 3

A 11 Corridor / Cables NN-51 E1.543 + 0 6

0 6

A 12 Recip. Chg. Pump JJ-53 E1.543 + 0 1

0 1

A 13 Safety Inj Pump 18 HH-53 E1.543 + 0 1

0 1

A u,

}

14 Safety Inj Pump 1A GG-53 E1.543 + 0 1

0 1

A 15 Cent. Chg. Pump IB JJ-54 E1.543 + 0 2

0 2

A u,

1 16 Cent. Chg. Pump 1A JJ-55 E1.543 + 0 2

0 2

A w

17 Alsles/ Cables KK-56 E1.543 + 0 18 0

18 A

18 Alsles/ Cables EE-55 E1.543 + 0 6

0 6

A

,19 AFW Pumps (Unit 2) M k b

)%N-61 E1.543 + 0 76

/0 86

)FA 88-63 E1.543 + 0 14 0

12(6)

A(8) 21 Aisles / Cables A g

22 Recip. Chg. Pump

/ JJ-60 E1.543 + 0 J

1 60 3

1 AA

"'P]

23 Safety Inj. Pump 28 HH-60 E1.543 + 0 1

0 1

A 8""

]

24 Safety Inj. Pump 2A 754,2 g/.5(S+o GG-60 E1.543 + 0 1

0 1

A b

25 Cent. Chg. Pump 28 JJ-59 E1.543 + 0 2

0 2

A D

4 26 Cent. Chg. Pump 2A JJ-58 E1.543 + 0 2

0 2

A 27 Aisles / Cables KK-59 E1.543 + 0 20 0

20 A

p4 28 Aisles / Cables EE-58 E1.543 + 0 6

0 6

A j

29 SW Gear Equip. Room AA-50 E1.560 + 0 7

0 0

A

{.

u 30 Elect. Pene. Room CC-50 E1.560 + 0 8

0 0

A

.J S

g 31 Corridor / Cables EE-53 E1.560 + 0 5

0 5

A

"_y n

32 Corridor / Cables KK-52 E1.560 + 0 8

0 8

A

]

33 Corridor / Cables NN-54 E1.560 + 0 10 0

10 A

n.,.g G

w i

l'

+

\\

TA8LE 3.3-11 (Continued) i S

-4 e.

FIRE DETECTION INSTRUMENTS h

h h

FIRE ZONE DESCRIPTION MINIMUM INSTRUMENTS OPERA 8LE*

LOCATION SMOKE FLAME HEAT FUNCTION **

d

[

34 Alsles/ Cables JJ-56 E1.560 + 0 14 0

14 A

35 Motor Control Centers GG-56 E1.560 + 0 2

0 2

A i

36 Cable Tray Access FF-56 E1.568 + 0 2

0 2

A 37 Equip. Batteries 00-55 E1.554 + 0 5

0 4

A 38 Equip. Batteries CC-55 E1.554 + 0 5-0 4

A 39 Battery Room CC-56 E1.554 + 0 17 0

0 A

l 41 SW Gear Equip. Room g.43 E.MO AA-64 E1.560 + 0 7

-0 0

A' 42 Elect. Pene. Room CC-65.E1.560 + 0 8

0 j

43 Corrider/ Cables FF-61 E1.560 + 0 8

0 A.

g0 k5k4 AS Afsles/ Cables " k3 MN

% 5 O

-60 E1.560 + 0 13 0

13 A

46 Afsles/ Cables HH-59 E1.560 + 0 13 0

13 A

I 47 Motor Control Center GG-58 E1.560 + 0 2

0 2

AM 1

N 48 Cable Tray Access FF-58 E1.560 + 0 2

0 2

A N'"

}

49 Equip. Batteries D0-60 E1.560 + 0 5-0 4

A 'j.f 4

50 Equip. Batteries CC-60 E1.560 + 0 5

0

.4 A %33 51 Battery Room CC-59 E1.560 + 0 17 0

0 A hasa j

53 SW Gear Equip. Room AA-49 E1.577 + 0 7

0 0

A 8 54 Aisles / Cables CC-50 E1.577 + 0 10 0

0 A

55 Afsles/ Cables NN-52 E1.577 + 0 9

0 9

A

}

56 Aisles / Cables PP-55 E1.577 + 0 13 0

13 A

1 57 Afsles/ Cables LL-55 E1.577 + 0 11 0

11 A

p

}

58 Afs1s:/ Cables HH-55 E1.577 + 0 21 0

21 A

59 Motor Control Center EE-54 E1.577 + 0 2

0 2

A 9

60 Cable Room CC-56 E1.574 + 0 18 0

15 A

i 62 SW Gear Equip. Room AA-64 E1.577 + 0 7

0 0

A j.

63 Elect. Pene. Room CC-64 E1.577 + 0 10 0

0 A

)

64 Alsles/ Cables PP-62 E1.577 + 0 9

0 9

A 1

55 Aisles / Cables PP-59 E1.577 + 0 16 0

16 A

l b

66 Aisles / Cables LL-59 E1.577 + 0 11 0

11 A

E 2

~67 Afsles/ Cables NH-59 E1.577 + 0 21 0

21 A

]

68 Motor Control Center FF-60 E1.577 + 0 2

0 2

A t

M a

h 1

0

j 4

w' w

TABLE 3.3-11 (Continued)

I*

FIRE DETECTION INSTRUMENTS E

R FIRE MINIMUM INSTRUMENTS OPERA 8LE*

5 ZONE DESCRIPTION LOCATION SMOKE FLAME HEAT FUNCTION"*

-e

[ 147-Reactor 81dg.

135*-180*

Be1. E1.593 + 2 10 0

0 A

148 Reactor 81dg.

180*-225*

Be1. E1.593 + 2%

2 0

0 A

149 Reactor Bldg.

315*-0*

Be1. E1.593 + 2%

7 0

A y

150 Reactor 81dg. (Unit 2) 0*-45" Be1. E1.565 + 3 4.

O A

151 Reactor 81dg. (Unit 2) 45'-90*

8el. E1.565 + 3 3

/0 gi a

152 Reactor Bldg. (Unit 2) 90*-135*

Be1. E1.565 + 3 4

/0 gO A

153 Reactor 81dg. (Unit 2) 135*-180*

Be1. E1.565 + 3 5

0 A

i 154 Reactor 81dg. (Unit 2) 180*-225*

Be1. E1.565 + 3 3

0 A

155 Reactor 81dg. (Unit 2) 270*-315*

Be1. E1.565 + 3 4

0 0

A 156 Reactor 81dg. (Unit 2) 315*-0*

Be1. E1.565 + 3 6

0 0

A 157 Reactor 81dg. (Unit 2) 0*-45*

8el. E1.586 + 6 6

0 0

A 158 Reactor 81dg. (Unit 2) 45*-90*

8el. E1.586 + 6 4

0 0

A 159 Reactor 81dg. (Unit 2) 90*-135' Be1 E1.586 + 6 3

0 0

A

)

160 Reactor 81dg. (Unit 2) 135*-180*

8el. E1.586 + 6 8

0 0

A sm:n 161 Reactor 8149 (Unit 2) 180*-225' 8el. E1.586 + 6 5

0 0

A M

w 2,

162 Reactor 81dg. (Unit 2) 315*-0*

8el. E1.586 + 6 5

0 0

A m

163 Reactor 81dg. (Unit 2) 0*-45*

8el. E1.593 + 2 13 0

0 A

g 164 Reactor 81dg. (Unit 2)

.-90*

8el. E1.593 + 2%

17 0

0 A

165 Reactor 81dg. (Unit 2)

"O" Be1. E1.593 + 2 13 0

0 A

166 Reactor 81dg. (Unit 2) 135*-1 Be1. E1.593 + 2%

10 0

0 A

O 167 Reactor 81dg. (Unit 2) 180*-225 8el. E1.593 + 2%

2 0

0 A

"gd 168 Reactor 81dg. (Unit 2) 315*-

Be1. E1.593 + 2%

7 0

0 A.

169 RCP-1A p

tor 81dg.

E1.593 + 2 0

0 1

A 170 RCP-18 q

Reactor 81dg.

E1.593 + 2 0

0 1

A 171 RCP-IC Reactor 81dg.

E1.593 + 2 0

0 1

A M

j 172

.RCP-ID Reactor Bldg.

E1.593 + 2 0

0 1

A 173 RCP-2A 45' Be1. E1.593 + 2%

0 0

1 A

174 RCP-28 135*

8el. E1.593 + 2%

0 0

1 A

775 RCP-2C 225' Be1. E1.593 + 2%

0 0

1 A

176 RCP-20 315' 8el. E1.593 + 2h 0

0 1

A

.Mc

~177 Filter Bed Unit 18 Reactor 81dg.

Be1. E1.565 + 3 2

0 2

A 9 E 178 Filter Bed Unit 1A Reactor Ridg.

Be1. E1.565 + 3 2

0 2

A w

~~

M G

io"*

@5

(

m

JAN E 1320 r

i

~

REACTOR COOLANT SYSTEM hj}.5

?g[, K(d;;;' T s

l.C 2 h

3/4.4.11 REACTOR COOLANT SYSTEM VENTS LIMITING CONDITION FOR OPERATION 3.4.11 two valves in series powered from emergency buses s at each of the following locations:

closed

a.

Reactor Vessel head b.

Pressurizer steam space APPLICABILITY: Modes 1, 2, 3 and 4 ACTION:

With one of the above Reactor Coolant System vent paths inoperable a.

STARTUP and/or POWER OPERATION may continue provided the vent path is maintained closed with power removad '-- the valve actua-tor of all the valves in the inoperable vent able vent path to OPERABLE status within 30 th; re e the inoper-within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within t e follaysgorgbe n HOT STANDB)

O, b.

30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

With both of the'above Reacter Coolant System vent paths inoperable maintain the inoperable vent paths closed with power removed from th d

valve actuators of all the valves in the inoperable vent paths, and restore at least one of the vent paths to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in HOT STAND 8Y within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in C within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.4.11 at least once per 18 months by:Each Reactor Coolant System vent path a.

Verifying all man isola M

n valves in each vent path are locked in the open post o

b.

Cycling each va in th l

nt path through at least one complete cycle of full traves rros the control room during COLD SHUTDOWN or j

REFUELING.

"For the plants using power operrted relief valve (PORV) as a vent path block is not required to be closea if the PORY is operable.

, PORY i

")

CATAWBA - UNITS 1 & 2 3/4 4-40 DEC' 31 1985

)

s y,

N

=

TABLE 3.6-2 (Continued)

CONTAllMENT ISOLATION VALVES i

s Q'

=

e g

VALVE NUMBER FUNCTION MAXIMUM t

b ISOLATION TIME (s) 3.

Manual (Continued) w e.

SM-103#

Main Steam C i

m SM-119#

Main Steam C N.A.

SM-141#

Main Steam C N.A.

SA-4#

AainSteam)C N.A.

4 SM-19#

Main Steam TD N.A.

SM-70f*

Main Steam 3D N.A.

SM-102#

Main 5 teas %

N.A.

SM-118#

Main Steam 50 N.A.

i SM-140#

Main Steam K N.A.

R WE-20*

Cont Bldg Supply Isol N.A.

WE-22*

Cont 81dg Supply Isol H.A.

'i' WE-56*

Cont Bldg Supply Isol N.A.

l l$

FW-4*

Refueling Water N.A.

j NV-862#*

Pressurizer Auxiliary Spray ND Outside Containment N.A.

h.A.

WLA-21#*

Steam Generator Drain Pump Discharge Outside Containment isolation N.A.

{

WLA-24#*

Steam Generator Drain Pump Discharge Outside Containment Isolation N.A.

p

.N TA8LE NOTATIONS l

May be opened on an intermittent basis under administrative control.

M f

N

- Valve also receives a High Radiation (H) and/or a High Relative Humidity isolation signal.

M3 h

g cra

Not subject to Type C leakage tests.

NOTE:

Times are for valve operation only, and do not include any sensor response or circuit delay times. SQ l

See Specification 3/4 3.2 for system actuation response times.

e 9

gg

"%i1

.i.

/

~;

< res TABLE 3.6-2 9g CONTAINMENT ISOLATION VALVES 5

2 MAXIMUM g

VALVE NUMBER FUNCTION ISOLATION TIME (s) 1.

Phase "A" Isolation 8B-578#

Steam Generator /ABlowdownContainmentOutsideIsolation

<10 g

BB-218#

Steam Generator #B Blowdown Containment Outside Isolation

<10 BB-611?d Steam Generator /C Blowdown Containment Outside Isolation 20 1

BB-lGB#

Steam Generator /0BlowdownContainmentOutsideIsolation

<10 BB-56A#

Steam Generator JA Blowdown Containment Inside Isolation 20 1

BB-19A#

Steam Genecator fBBlowdownContainmentInsideIsolation 210 BB-60A#

Steam Generator (C Blowdown Containment Inside Isolation 2 10 BB-8A#

Steam Generator D Blowdown Containment Inside Isolation E10 BB-1488#

Steam Generator Blowdown Containment Isolation Bypass

<10 m

}

88-150B#

Steam Generator B Blowdown Containment Isolation Bypass

<10 B8-1498#

Steam Generator Blowdown Containment Isolation Bypass

$ 10 m

4 8B-1478#

Steam Generator % Blowdown Containment Isolation Bypass

<10 CA-149#

Steam Generator gA Main feedwater to Auxiliary feedwater Nozzle Isolation

<5 CA-150#

Steam Generator fB Main Feedwater to Auxiliary feedwater Nozzle Isolation

<5 CA-151#

Steam Generator -)tC Main feedwater to Auxiliary feedwater Nozzle Isolation 5

CA-152#

Steam Generator 50 Main feedwater to Auxiliary Feedwater Nozzle Isolation 25 CA-185#

Auxiliary Nozzle Temper SG A E5 CA-186#

Auxiliary Nozzle Temper SGJB E

25 CA-187#

Auxiliary Nozzle Temper SGfC

<5 CA-188#

Auxiliary Nozzle Temper SG

<5 CF-60#

Steam Generator (D Feedwater Containment Isolation

<5 CF-Sl#

Steam Generator fC Feedwater Containment Isolation 25 CF-42#

Steam Generator JB feedwater Containment Isolution

'S Cf-33#

Steam Generator JA feedwater Containment Isolation

<5 CF-90#

Steam Generator (A Feedwater Purge Valve 15 CF-89#

Steam Generator feedwater Purge Valve

<5 CF-88#

Steam Generator C feedwater Purge Valve 5

CF-87#

Steam Generator D feedwater Purge Valve 5

1

1 TABLE 3.6-2 (Continued)

CONIAINMENT ISOLATION VALVES 4 g s>

e MAXIMUM VALVE NUMBER FUNCTION ISOLATION TIME (s) y 1.

Phase "A" Isolation (Continued)

KC-3058#

E Excess Letdown Hx Supply Containment Isolation (Outside)

<20 KC-315B#

Excess Letdown Hx Return Header Containment Isolation (Outside) 220 KC-320A#

NCDT Hx Supply Hdr Containment Isolation (Outside) 220 KC-332B#

NCDT Hx Return Hdr Containment Isolation (Inside) 220 KC-333A#

NCDT Hx Return Hdr Containment Isolation (Outside) 220 KC-429B RB Drain Header Inside Containment Isolation 210 KC-430A RB Drain Header Outside Containment Isolation

[10 NB-260B Reactor Makeup Water Tank to Flush Header

<10 NC-53B Nitrogen to Pressurizer Relief Tank #1 Containment Isolation Outside

<10 T

NC-54A Nitrogen to Pressurizer Relief Tank #1 Containment Isolation Inside 210 0

NC-568 RMW Pump Disch Cont Isolation 310 NC-1958 NC Pump Motor Oil Containment Isolation Outside

<10 NC-196A NC Pump Motor Oil Containment Isolation Inside

~10 9

NF-228A Unit Air Handling Units Glycol Supply Containment Isolation Outside

$10 NF-233B Uni Air Handling Units Glycol Return Containment Isolation Inside

$10 NF-234A Uni Air flandling Units Glycol Return Containment Isolation Outside

<10 NI-47A Accumulator N Supply Outside Containment Isolation

$10 2

NI-95A Test Hdr Inside Containment Isolation (10 NI-968 Test Hdr Outside Containment Isolation 210 NI-120B Safety Injection Pump to Accumulator Fill Line Isolation 210 NI-122B#

Hot Leg Injection Check RI124,dNil?8 Test Isolation

- - 2.

510 NI-154B#

HotLegRecirculationCheck'JN1125,$NI129lestIsolation

<10 NI-2558 UHI Check Valve Test Line Isolation s10 NI-258A UHI Check Valve Test Line Isolation i10 NI-2648 UHI Check Valve Test Line Outside Containment Isolation y 10

b Jf.

TABLE 3.6-2 (Continued) l/*(l/

CONTAINMENT ISOLATION VALVES s.

2 e

VALVE NUMBER MAXIMUM FUNCTION ISOLATION TIME (s) 1.

' Phase "A" Isolation (Continued)

N Hi-266A UHI Check Valve Test Line Inside Containment Isolation NI-267A (10 UHI Check Valve Test Line Inside Containment Isolation 210 NI-153A#

Hot Leg injection Check nil 56, NI159 Test Isolation 210 NM-3A Pressurizer Liquid Sample Line Inside Containment Isolation (10 NM-6A Pressurizer Steam Sample Line Inside Containment Isolation 210 NM-7B Pressurizer Sample Header Outside Containment Isolation

< 10 NM-22A NC Hot Leg A Sample Line Inside Containment Isolation i10 NM-25A NC Hot Leg C Sample Line Inside Containment Isolation 210 t

NM-26B NC Hot Leo Sample Hdr Outside Containment Isolation ilo NM-728 f N1 Accumulato Sample Line inside Containment Isolation T

NM-758 NI-Accumulator 8 Sample Line Inside Containment isolation 210

< 10 NM-78B A

N1 Accumulato Sample Line inside Containment Isolation (10 NM-81B I

NI Accumulato Sample Line Inside Containment Isolation

<10 NH-82A L

N1 Accumulator Sample Hdr Outside Containment Isolation (10 NM-187A#

w fA Upper Shell Sample Containment Isolation Inside NM-190A#

SG /A Blowdown Line Sample Containment Isolation Inside

[10

<10 NM-1918#

SG Sample Hdr Containment Isolation Outside (10 NM-1978#

SG Upper Shell Sample Containment Isolation Inside

< 10 NM-200B#

SG Blowdown Line Sample Containment Isolation Inside

<10 NM-201A#

SG Sample Hdr Containment Isolation Outside (10 NM-207A#

SG Upper Shell Sample Containment Isolation Inside

<10 NM-210A#

SG Blowdown Line Sample Containment Isolation Inside

<10 NM-2118#

SG Sample Hdr Containment Isolation Outside

<10 NM-2178#

SG pfD Upper Shell Sample Containment Isolation Inside (10 NM-220B#

SG jfD Blowdown Line Sample Containment Isolation Inside

<10 NM-221A#

SGipD Sample Hdr Containment Isolation Outside

<10 NV-ISB Letdown Containment isolation Outside

<10 NV-89A NC Pumps Seal Return Containment Isolation inside 10 NV-918 NC Pumps Seal Return Containment Isolation Outside

10 NV-3148#

Charging Line Containment isolation Outside 10

- sp p/h [

W$

TABLE 3.6-2 (Continued)

{

CONTAINMENT ISOLATION VALVES E

E VALVE NUMBER MAXIMUM FUNCTION b

ISOLATION TIME (s) s 1.

Phase "A" Isolation (Continued)

NV-IIA 45 gpm Letdown Orifice Outlet - Containment Isolation NV-13A 75 gpm Letdown Orifice Outlet - Containment

$10 Isolation NV-10A High Pressurizer Letdown Orifice Outlet - Containment

$10 NV-872A Isolation Standby Makeup Pump to RCS seals

$10

$10 RF-3898 Interior fire Protection Containment Hose Rack Isolation Valve i

(Outside Containment)

$5 RF-4478 Reactor Building Sprinklers Containment Isolation Valve (Outside Containment)

$5 A

VB-83B Breathing Air Unit Containment Isolation

$10 VY-18B**

Containment H.

Purge to Annulus inside Containment isolation 2

VY-17A**

Containment H Purge to Annulus Outside Containment Isolation

' $ 10 2

VY-ISB**

Containment H Purge Blower Outlet, Containment Isolation (Outside)

$10

$10 2

VI-312A RB Isolation Valve for VI Supply to annulus Vent.

$10 VP-1B**

Upper Containment Purge Supply'#1 Outside Isolation VP-2A**

Upper Containment Purge Supply #1 Inside Isolation

$5 VP-38**

Upper Containment Purge Supply #2 Outside Isolation

$5 VP-4A**

Upper Containment Purge Supply #2 Inside Isolation (5

VP-68**

Lower Containment Purge Supply #1 Outside Isolation y5 VP-7A**

Lower Containment Purge Supply #1 Inside Isolation (5

VP-88**

Lower Containment Purge Supply #2 Outside Isolation

$5 VP-9A**

Lower Containment Purge Supply #2 Inside Isolation

<5 VP-10A**

Upper Containment Purge Exhaust #1 Inside Isolation

$5 (5

TABLE 3.6-2 (Continued)

./ydLWe5 s:g CONTAINMENT ISOLATION VALVES 2

i MAXIMUM VALVE NUMBER FUNCTION ISOLATION TIME (s)

[

1.

Phase "A" Isolation (Continued)

[

VP-llB**

Upper Containment Purge Exhaust #1 Outside Isolation

<S VP-12A**

Upper Containment Purge Exhaust #2 Inside Isolation 25 VP-138**

Upper Containment Purge Exhaust #2 Outside Isolation 25 VP-lSA**

Lower Containment Purge Exhaust #1 Inside Isolation 25 VP-16B**

Lower Containment Purge Exhaust #1 Outside Isolation 25 VP-17A**

Incore Instru. Room Purge Supply Inside Isolation 55 VP-18Ba*

Incore Instru. Room Purge Supply Outside Isolation

<S VP-19A**

Incore Instru. Room Purge Exhaust Inside Isolation

<5

{

VP-20B**

Incore Instru. Room Purge Exhaust Outside Isolation 55 i

VQ-2A**

Containment Air Release Inside Isolation

<5 VQ-3B**

Containment Air Release Outside Isolation 25 VQ-ISB**

Containment Air Addition Outside Isolation 25 VQ-16A**

Containment Air Addition Inside Isolation

[5 VS-548 Unit Containment Header Outside Isolation

<15 WL-8078#

NCDT Pumps Discharge Outside Containment Isolation

<10 WL-80SA#

NCDT Pumps Discharge Inside Containment Isolation 210 WL-450A NCDI Vent Inside Containment Isolation 210 WL-4 SIB NCDT Vent Outside Containment Isolation 210 WL-825A#**

RB Sump Pump Discharge Inside Containment Isolation 210 WL-8278#**

RB Sump Pump Discharge Outside Containment Isolation

<10 l

YM-1198 Demin. Water Containment Outside Isolation

<10 2.

Phase "B" Isolation KC-3388#

NC Pump Supply Header Pent. Isolation (Outside)

$40 KC-4248#

NC Pumps Return Hdr. Pent. Inside Isolation

<40 KC-42SA#

NC Pumps Return Hdr. Outside Isolation

<40

{}l TABLE 3.6-2 (Continued) 9,g CONTAINMENT ISOLATION VALVES 2

e c

VALVE NUMBER MAXIMUM FUNCTION ISOLATION TIME (s) 2.

Phase "B" Isolation (Continued) p RN-437B Supply to NC Pumps and LCVU Supply Outside Containment Isolation Return from NC Pumps and LCVU Return Inside Containment Isolation

$60 RN-484A Return from NC Pumps and LCVU Return Outside Containment Isolation

$60 RN-487B

$60 RN-404B Supply to Upper Containment Supply Ventilation Units Containment Isolation (Outside)

$10 RN-429A Return from Upper Containment Ventilation Units Containment Isolation (Inside)

$10 RN-432B Return from Upper Containment Ventilation Units Containment Isolation (Outside)

$10 U

VI-77B Instrument Air Containment Outside Isolation

$10 Z

SM-1 #

MainSteamgGIsolation SM-3 #

Main Steam Isolation

$5 SM-5 #

Main Steam Isolation

$5

<5 SM-7 #

Main Steam Isolation

'S SM-9 #

Main Steam p Isolation Bypass Ctrl.

55 SH-10 #

Nain Steam C Isolation Bypass Ctrl.

55 SM-11 #

Main Ste.

Isolation Bypass Ctrl.

$5 SM-12 #

Main St am fA solation Bypass Ctrl.

55 3.

SV-19 #

Main team fA RV SV-13 #

Main PORV.

55 SV-7 #

Main Steam JC PORV

$5 SV-1 #

Main Steard @D PORV

$5

$5 WL-867A**

Containment Vent Unit Orains Inside Containment Isolation Containment Vent Unit Orains Outside Containment Isolation

$10 WL-869Ba*

<10

gh, M TABLE 3.6-2 (Continued)

[

n h

CONTAINMENT ISOLATION VALVES E

p MAXIMUM VALVE NUMBER FUNCTION 4

ISOLATION TIME (s)

[

3.

Manual p

NC-141 NC Pump H Drain Tank Pump Discharge 2

N.A.

NC-142 NC Pump H2 Drain Tank Pump Discharge N.A.

NI-3 Boron Injection Tank line to Cold Legs N.A.

FW-11 Refueling Water Pump Suction N.A.

FW-13 Refueling Water Pump Suction N.A.

CF-91#

FeedwaterfA N.A.

CF-93#

Feedwater fB N.A.

CF-95#

Feedwater /C N.A.

CF-97#

Feedwater -fD

{

CA-121#

Aux. Feedwater N.A.

N.A.

BW-1#

Aux. Feedwater T

CA-120#

Aux. Feedwater N.A.

i BW-26#

Aux. Feedwater.jfB N.A.

N.A.

CA-119#

Aux. Feedwater gC N.A.

BW-17#

Aux. Feedwater fC

[

N.A.

CA-118#

Aux, Feedwater N.A.

BW-10#

Aux. Feedwater N.A.

SM-16#

Main Steam k N.A.

SM-73#*

Main Steam /A N.A.

SM-105#

Main Steam /A N.A.

SH-121#

Main Steam gA N.A.

SM-143#

Main Steam gA N.A.

SM-72#*

Main Steam -pB N.A.

SM-104#

Main Steam #B N.A.

SM-120#

Main Steam A N.A.

SM-142#

Main Steam %

N.A.

SM-1#

Main 5 team /B N.A.

SM-17#

Main Steam 4 N.A.

SM-18#

Main 5 team /C I

.'s. A.

SM-71#a Main Steam gl N.A.

o.

N TABLE 3.6-2 (Continued)

S E

CONTAINMENT ISOLATION VALVES c

VALVE NUMBER MAXIMUM FUNCTION ISOLATION TIME (s)

M 3.

Manual (Continued)

Tp SM-103#

Main 5 team (t SM-119#

Main Steam 5t N.A.

SM-141#

Main Steam $'

N.A.

SA-4#

Main Steam N.A.

SM-19#

Main Steam N.A.

SM-70#*

Main Steam $)

N.A.

SM-102#

Main Steam #D N.A.

SM-118#

Main Steam (D N.A.

SM-140#

Main Steam ID N.A.

t' WE-20*

Cont Bldg Supply Isol N.A.

WE-22*

Cont Bldg Supply Isol N.A.

T WE-56*

Cont Bldg Supply Isol N.A.

FW-4*

' Refueling Water N.A.

NV-862#*

N.A.

Pressurizer Auxiliary Spray ND Outside Containment WLA-21#*

N.A.

Steam Generator Drain Pump Discharge Outside Containment Isolation WLA-24#*

N.A.

Steam Generator Drain Pump Discharge Outside Containment Isolation N. A.

TABLE NOTATIONS

May be opened on an intermittent basis under administrative control.

l

- Valve also receives a High Radiation (H) and/or a High Relative Humidity isolation signal.

Not subject to Type C leakage tests.

NOTE:

Times are for valve operation only, and do not include any sensor response or circuit delay tienes.

I See Specification 3/4 3.2 for system actuation response times.

JAN 8 1986 O M 'h P50. ' t U[ih f

i{

~

CONTAINMENT SYSTEMS CONTAINMENT VALVE INJECTION WATER SYSTEM i

LIMITING CONDITION FOR OPERATION r

3.6.6 Both trains of the Containment Valve Injection Water System shall be OPERABLE.

~

APPLICA8ILITY: MODES 1, 2, 3 and 4.

ACTION:

With one train of the Containment Valve Injection Water System inoperable, restore the inoperable system to OPERA 8LE status within 7 days or be in at least HOT STAN08Y within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.6.1 Each train of the Containment Valve Injection Water System shall be j

demonstrated OPERA 8LE at least once per 31 days by verifying that the system

/

is pressurized to greater than or equal to 1.10 P, (16.2 psig) and has ade-quate capacity to maintain system pressure for at least 30 days.

4.6.6.2 Each train of the Containment Valve Injection Water System shall be demonstrated OPERA 8LE at least once per 18 months by verifying that the valve seal injection flow rate is less than 1.7 gpa for' Train A and 1.4 gpm for a

TrainBwithatankpressuregreaterthanor4qualto45psigandeachauto-matic valve in the flow path actuates to its correct position on a Containment Pressure-High or a Containment Pressure-High High test signal.

l 6WM\\ 1.5yn (unit z.)

(Unit ih 1./mym dine-2d CATAWBA - UNITS 1 & 2 3/4 6-46 OEC' 31 1985

~

s J

JAN 8 1986 PLANT SYSTEMS CONDENSATE STORAGE SYSTEM LIMITING CONDITION FOR OPERATION c

3. 7.1. 5 The Condensate Storage System (CSS 8 ' Condensate Storage Tank, Upper Surge and Condenser Hotwell) shall be ABLE with a contained water volume of at least 225,000 gallons of water.

APPLICABILITY: MODES 1, 2, and 3. (Ur.it 2)

ACTION:

With the CSS inoperable, within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months either:

Restore the CSS to OPERA 8LE status o a.

within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in H0 be in at least HOT STANOBY hours, or OWN within the following 6 pQ l

b.

Demonstrate the OPERABILITY fl the sta by nuclear service water pond as a backup supply to hepuxil ry feedwater pumps and restore the CSS to OPERABLE status ithi days or be in at least HOT STANDBY within the next 6 ho and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REOUIREMENTS 4.7.1.5 The CSS shall be demonstrated OPERA 8LE at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months by verifying the contained water volume is within its limits.

/

3 CATAWBA - UNITS 1 & 2 3/4 7-9 JAN 7 1986 JAN 6 1986 DEC' 31 1985

JM 8 1986

[,

FIRE HOSE STATION 5

)

LOCATION ELEVATION 1.

Auxiliary Building HOSE RACK #

59, FF 55, FF 522+0 153-64, KK 522+0 1RF235 63, M 543+0 1RF248 60, MM 543+0 1RF21(

58, PP 543+0 1RF211 59, GG-HH 543+0 1RF212 60-61, FF-GG 543+0 1RF218 63, CC 543+0 1RF236 57, JJ 543+0 1RF237 54-55, GG 543+0 1RF238 57,FF 543+0 1RF242 52-53, GG 543+0 1RF249 51, CC 543+0 1RF250 50-51, JJ-KK 543+0 1RF255 53, M 543+0 1RF256 50-51, NN 543+0 1RF262 62, M-NN 543+0 1RF26B 63, JJ-KK 560+0 1RF271 560+0 1RF203 3

58, PP

^

56, M NN 560 RF211 57 KK I

+y5 Wg 14 19 A

1 20 54 s,rr uu 60+0-y 51, KK 5 v.;

1. 243

.52, M-NN 560+0 1RF251 58, BB 560+0 1RF263 65, BB-CC 554+0 1RF269 62, AA-BB 560+0 1RF484 56, BB 560+0 1RF485 52, AA-BB 554+0 1RF486 49, BB-CC 560+0 1RF487 68-69, BB 560+0 1RF488 45-46,'BB 560+0 1RF489

$3, NN 560+0 1RF996 61, LL 577+0 1RF997 63, KK-LL 577+0 1RF204 58, PP 577+0 1RF214 59, JJ 577+0 1RF214 58, GG 577+0 1RF221

'56, KK 577+0 1RF230 54, GG 577+0 1RF240 52-53, KK 577+0 1RF244 51, KK 577+0 1RF252 51-52, NN 577+0 1RF258 56, PP 577+0 1RF264 68-69, BB 577+0 1RF272 577+0 1RF278

-me 1RF478 CATAWBA - UNITS 1 & 2 3/4 7-34 OEC'31 1985

P JAN 8 1966 TABLE 3.7-3 (Continued)

FIRE HOSE STATIONS LOCATION ELEVATION HOSE RACK #

ti5, BB-CC 577+0 1RF479 59, 00 574+0 1RF480 A0, AA 574+0 1RF481 49, BB-CC 577+0 1RF490 45, BB 577+0 1RF491 55, 00 574+0 1RF492 54, AA 574+0 1RF493 63, AA 577+0 1RF993 51, AA 577+0 1RF998 62, NN 594+0 1RF205

i7, M 594+0 1RF222

.'53,JJ 594+0 1RF231 57, H

594+0 1RF245 57, EE 594+0 1RF253 51, JJ 594+0 1RF259 53, NN 594+0 1RF275

_64, BB 594+0 1RF984 5

594+0 1RF985 6, )2(N 605+10 1RF265 5

605+10 1RF233' 33-64, M 631+6 1RF483 50-51, M 631+6 1RF495

/

2.

Fuel s

UU 605+10 1RF208.

~

-UU 605+10 1RF2 h -(a N

_ __ __, M 605+10 1RF g

Z s"T, M 605+10 1RF8 3.

Nuclear Service Water Pump Structure East Section 600+0 1RF939 West Section 600+0 1RF940

~.

7 JAN 6 1566 CATAWBA - UNITS 1 & 2 3/4 7-35 DEC' 31 1985

PJAN 8 1986 1

N[ 6%Ehd=

ELECTRICAL POWER SYSTEMS 3/4.8.2 D.C. SOURCES OPERATING LIMITING CONDITION FOR OPERATION 3.B.2.1 The following D.C. channels and trains shall be OPERABLE and energized:

Channel I consisting of 125-Volt D.C. Bus No.' EDA, 125-Volt D.C.

a.

Battery Bank No. ESA and a full capacity charger,*

b.

Channel 2 consisting of 125-Volt D.C. Bus No. EDB,125-Volt D.C.

Battery Bank No. EBB and a full capacity charger,*

Channel 3 censisting of 125-Volt D.C. Bus No. EDC, 125-Volt D.C.

t c.

Battery Bank No. EBC and a full capacity charger,"

d.

Channel 4 consisting of 125-Volt D.C. Bus No. EDD,125-Volt D.C.

Battery Bank No. ESD and a full capacity charger,"

Train A consisting of 125-Volt D.C. Bus No. EDE, and e.

f.

Train B consisting of 125-Volt D.C. Bus No. EDF.

i i

APPLICABILITY: MDDES 1, 2, 3, and 4.

ACTION:

'\\

a.

With 125 VDC Bus EDE or EDF inoperable, restore the inoperable bus to OPERABLE status with'in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

b.

With one 125 VDC Bus EDA,.EDB,.IDC or EDD inoperable, restor 9 the 1

l inoperable bus to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

With either 125 VDC Battery Bank No. EBB or EBC and/or its full-c.

capacity charger inoperable, restore the inoperable battery and/or full-capacity charger to OPERABLE status within 10 days or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the fallowing 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

d.

h eith 5 VDC Battery Bank No. EBA or EBD and/or its full-it ar incperable and 125 VDC diesel generator Batteries ad $G their full-capacity chargers in service powering s sKED

$DFduringthisperiodoftime,restoretheinoper-ab ba ry cd/

full-capacity charger to OPERABLE status within

A vital bus may be disconnected from its D.C. source for up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for the purpose of performing an equalizing charge on its associated battery bank provided that the vital busses associated with the other battery banks are OPERABLE and energized. Also when the spare charger is being used as a replacement for the normal battery charger verify that the A.C. input to the charger is from the same A.C. division as the normal charger which it is s

replacing.

CATAWBA - UNITS 1 & 2 3/4 8-12 DEC'34 1S85

FliiAL MAFT 1

ELECTRICAL POWER SYSTEMS i

3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES i

CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION 3.8.4 All containment penetration conductor overcurrent protective devices given in Tables 3.8-la and 3.8-Ib shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

With one or more of the containment penetration conductor overcurrent protective device (s) given in Tables,3.8-la and 3 8-lb inoperable:

Restore the protective device (s) to OPERA 8LE status or de-energize a.

the circuit (s) by tripping the associated backup circuit breaker or racking out or removing the inoperable circuit breaker within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , declare the affected system or component inoperable.

-and verify the backup circuit breaker to be tripped or the inoper-able circuit breaker racked out or removed at least once per 7 days thereafter; the provisions of Specification 3.0.4 are not applicable to overcurrent devices in circuits which have their backup circuit T

breakees tripped, their inoperable circuit breakers racked out, or removed, or b.

Be in at least HOT STANOBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.8.4 A innen+ mnetration conductor overcurrent protective devices given in 1

ha"1 be demon d OPERABLE:

4 e4 3.s-th a.

At 1 nce per 18 months:

i 1)

By verifying that the medium voltage (4-15 kV) circuit breakers are OPERABLE by selecting, on a rotating basis, at least 10% of the circuit breakers of each voltage level, and performing the following:

a)

A CHANNEL CALIBRATION of the associated protective relays, b)

An integrated protective system functional test which includes simulated automatic actuation of the system and verifying that each relay and associated circuit breakers function as designed, and j

CATAWBA - UNITS 1 & 2 3/4 8-19 DEC 3f 1965

- =

8=

ggg bilMT TABLE 3.8-1A (Continued)

UN:T(IN0NTAINMENTPENETRATIONCONDUCTOROVERCURR w

DEVICE NUMBER & LOCATION SYSTEM POWERED 1.

600 VAC MCC (Continued)

IMXN-F060 Primary Bkr Ice Condenser Air Haadling Backup Fuse Unit 1A4 Fan Motor A & B IMXN-F07B Primary Bkr Ice Condenser Air Handling Backup Fuse Unit 185 Fan Motor A & B IMXN-F07C Primary Bkr Ice Condenser Air Handling Backup Fuse Unit 1A6 Fan Motor A & B 1MXN-F08A Primary Bkr Ice Condenser Air Handling Backup Fuse Unit 187 Fan Motor A & B IMXN-F08B

.\\

Primary Bkr Ice Condenser Air Handling

.A i

Backup Fuse Unit 1A8 Fan Motor A & B IMXN-F08C Primary Bkr Ice Condenser Air Handling Ba,ckup Fuse Unit 189 Fan Motor A & B 1MXN-F080 Primary Bkr Ice Condenser Air Handling Backup Fuse Unit 1A10 Fan Motor A & B 1MXN-F09A Primary Bkr Ice Condenser Air Handling Backup Fuse Unit 1B11 Fan Motor A & B 1MXN-F09B Primary Bkr Ice Condenser Air Handling Backup Fuse Unit IA12 Fan Motor A & B IMXN-F09C Primary Bkr Ice Condenser Air Handling Backup Fuse Unit 1813 Fan Motor A & S IMXN-F090 Primary Bkr Ice Condenser Air Handling Backup Fuse Unit 1A14 Fan Motor A & B

-)

CATAWBA - UNITS 1 & 2 3/4 8-32 i

i DEC' 31 1985

/

JAN 8 1986 TABLE 3.8-1A (Continued)

UNIT 1 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DE DEVICE NUMBER & LOCATION SYSTEM POWERED 2.

600 VAC MCC (Continued)

IMXR-F01B Primary Skr Incore Instrument Room Ventila-Backup Fuse tion Unit 1B Fan Motor 1MXR-F028 Primary Bkr Control Rod Drive Vent Backup Fuse Fan Motor 10 1MXR-F03A Primary Bkr Lower Containment Ventilation Backup Fuse Unit 10 Fan Motor 1MXR-F04C Primary Bkr

-Upper Containment Ventilation Backup Fuse Unit 1D Fan Motor 1MXY-F02A T

Primary Bkr NC Pump 1A Oil Lift Pump Motor 1

./

Backup Fuse 1MXY-F02B Primary Bkr NC Pump 1D 011 Lift Pump Motor 1 Backup Fuse 1MXY-F02C Primary Bkr Reactor Building Lower Containment Backup Fuse Welding Machine Receptaclej 1MXY-F03A 14CPLOf85 Primary Bkr Reactor Coolant Drain Tank Pump Backup Fuse Motor 1A 1MXY-F03D Primary Bkr Ice Condenser Refrigeration Backup Fuse Floor Cool Pump Motor 1A 1MXY-F05A Primary Bkr Lighting Trtnsformer Backup Fuse ILR8 1MXY-F05B Primary Bkr Lighting Transformer Backup Fuse ILR11 s

CATAWBA - UNITS 1 & 2 3/4 8-35 DEC' 31 1985

--.---n-..

g

/

JAN 8 1986 m r :;,7 o

n. ' y

y TABLE 3.8-1B (Continued)

UNIT 2 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVI DEVICE NUMBER & LOCATION SYSTEM POWERED 2.

600 VAC MCC (Continued) 2MXR-F018 Primary Bkr Incore Instrument Room Ventila-Backup Fuse tion Unit 2B Fan Motor 2MXR-F028 Primary Bkr Control Rod Drive Vent Backup Fuse Fan Motor 20 2MXR-F03A Primary Bkr Lower Containment Ventilation Backup Fuse Unit 20 Fan Motor 2MXR-F04C Primary Bkr Upper Containment Ventilation Backup Fuse Unit 20 Fan Motor 2MXY-F02A d

h, Primary Bkr NC Pump 2A 011 Lift Pump Motor 1

,/

Backup Fuse 2MXY-F028 Primary Bkr NC Pump 2D Oil Lift Pump Motor 1 Backup Fuse 2MXY-F02C Primary Bkr Reactor Butiding Lower Containment Backup Fuse Welding Machine Receptacle 2RCPLO185 QMX F03A rimary Bkr Reactor Coolant Drain Tank Pump Backup Fuse Motor 2A 2MXY-F03D l

Primary Bkr Ice Condenser Refrigeration Backup Fuse Floor Cool Pump Motor 2A 2MXY-F05A Primary Bkr Lighting Transformer Backup Fuse 2LR8 2MXY-F05B Primary Bkr Lighting Transformer Backup Fuse 2LR11 CATAWBA - UNITS 1 & 2 3/4 8-58 DEC' 31 1985

P

[ d3h3 I

]dia c$.

f TABLE 3.8-18 (Continued)

UNIT 2 CONTAINMENT PENETRATION CONOUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER & LOCATION SYSTEM POWERED 2.

600 VAC MCC (Continued) 2MXZ-F07C Primary Skr 5 Ton Jib Crane in Containment Backup Fuse Crane No. R006 2MXZ-F07D Primary Bkr Reactor Cavity Manipulator Backup Fuse Crane No. R008 & R028 2MXZ-F08A Primary Skr Steam Generator Drain Pump Backup Fuse Motor 2 2MXI-F08C Primary Bkr.

15 Ton Equipment Access Hatch Backup Fuse Hoist Crane No. R010 2MXZ-F080 Primary Bkr Control Rod Drive 2 Ton Jib Backup Fuse Hoist Crane No. R018 2MXZ-F08E Primary Bkr Reactor Side Fuel Handling Backup Fuse Control Console SMXG-F06B Primary Bkr Standby Makeup Pump Drain Isol Backup Fa~

Viv 2NV876 P.. Y -

SMX RO

., our Pressurizer Heaters 28, 55 & 56 Backup Fuse SMXG-F06C Primary Bkr Standby Makeup Pump to Seal Backup Fuse Water Line Isol Viv 2NV877 3.

600 VAC Pressurizer Heater Power Panels PHP2A-F01A t

Primary Bkr Pressurizer Heaters Backup Fuse 1, 2, & 22 PHP2A-F01B

~ Primary Bkr Pressurizer Heaters Backup Fuse 5, 6, & 27 CATAWBA - UNITS 1 & 2 3/4 8-61 1

DEC's 1 1985

JAN

~~

g gggg

./

REFUELING OPERATIONS 3/4.9.11 FUEL HANDLING VENTILATION EXHAU TEM M *3 LIMITING CONDITION FOR ODERATION

=

3.9.11 shall be OPERABLE.At least one train of the Fuel Handling Ven z

ation Exhaust System APPLICABILITY:

Whenever irradiated fuel is in the stor ACTION:

age pool.

a.

With both trains of the Fuel Handling Ventil inoperable the storage, pool or crane operation with lsuspend all o OPERABLE status.until the Fuel Handling Ventilation Ex e within s em is restored to b.

The provisions of Specifications 3 0 3 and 3 0

~ SURVEILLANCE REQUIREMENTS 4 are not applicable.

4.9.11.1 determined to be operating and discharging thOne tra g

adsorbers at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months whenever irrough the HEP x aust System shall be the storage pool and during crane operati on with loads over the storage poo 4.9.11.2 demonstrated OPERABLE:Both trains of the Fue) Handling Venti x aust System shall be a.

At least once per 31 days by initiating that the system operates for at least inflow through r ers and verifying heaters operating; g continuous hours with the b.

At least once per 18 on the HEPA filter nths or (1) after y structur r

painting, fire ads housings, or (al maintenance or ical communicating w,ith the system by::'...se in any ventilation zone

2) following t

1)

Verifying that the cleanup system satisfies th penetration and bypass leakage testing acceptanc e in place of less than 1% and uses the test RegulatoryPositionsC.5.a.C.S.c,procedureguidancein e criteria Guide 1.52, Revision 2, March 1978, and the s of Regulatory and C.5.d is 16,565 cfm i 10%;

i ystem flow rate s

d)

The requirement for reducing refrigerant i

satisfied by operating the system for 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with hconcentration to CATAWBA - UNITS 1 & 2 eaters on and operating.

3/4 9-14 DEC:31 1985

JAN 8 tagg f

REACTOR COOLANT SYSTEM BASES i

SAFETY VALVES (Continued) relief capability and will prevent overpressurization Overpressure Protection System provides a diverse mean. In addition, the i

overpressurization at low temperatures.

s of protection against prevent the Reactor Coolant System from being Limit of 2735 psig.

to greater than the maximum surge rate resulting from a c a ety assuming no Reactor trip until the first Reactor Trip System Trip oad reached (i.e.

and also assum,ing no operation of the power-operated on s

dump valves.

eam Demonstration of the safety valves' lift settings will occur onl shutdown and will be performed in accordance with the provisions y during of the ASME Boiler and Pressure Code.

on XI

_3/4.4.3 PRESSURIZER N

parameter is maintained within the normal steady-s

/

a e

assumed in the SAR.

The 12-hour periodic surveillance is sufficient to ensure that operation is restored to within its limit following expected transient ope e parameter maximum water volume also ensures that a steam bub ration. The Reactor Coolant System is not a hydraulically solid system that a minimum number of pressurizer heaters be OPERABLE enhanc e

The requirement of the plant to control Reactor Coolant System pressure and estab es the capability circulation.

3/4.4.4 RELIEF VALVES The power-operated reifef valves relieve Reactor Coolant System pressure (PORVs) and steam bubble function to including the design step load decrease with steam dumduring all design transients up PORVs minimizes the undesirable opening of the spring p.

Operation of the safety valves.

positive shutoff capability should a relief valve become in

" 2.. T '. ~...... '

- ' t m.. :, ", : ; ; '. "- "- "- M L.,, ~. - _. _ 6

. i.. ^.

m._

.m

' L :. : u w

-':L ;"'. :LT:s :L ",': "..Pr'"A"' C'1 -

_____,...,,,__~m2.

..,.. - ~. -

T '.

_ :,. _ _ _. : L~. ~

~.,.., -..

3/4.4.5 STEAM GENERATORS ensure that the structural integrity of this portion of the j

System will be maintained.

The program for inservice inspection of steam CATAWBA - UNITS 1 & 2 B 3/4 4-2 DEC' 31 1985

/.. ' '

JAN 8 1986 REACTOR COOLANT SYSTEM BASES 3/4.4.6.2 OPERATIONAL LEAKAGE These Detection Systems are consistent with the recommendations of Regulatory I

Guide 1.45, " Reactor Coolant Pressure Boundary Leakage Detection Systems,"

May 1973.

PRESSURE BOUNDARY LEAKAGE of any magnitude is unacceptable since it may be indicative of an impending gross failure of the pressure boundary. Therefore, the presence of any PRESSURE BOUNDARY LEAKAGE requires the unit to be promptly placed in COLD SHUTDOWN.

Industry experience has shown that while a limited amount of leakage is expected from the Reactor Coolant System, the unidentified portion of this leakage can be reduced to a threshold value of less than 1 gpm.

This thres-hold value is sufficiently low to ensure early detection af additional leakage.

The total steam generator tube leakage limit of 1 gpa for all steam generators not isolated from the Reactor Coolant System ensures that the dosage contribution from the tube leakage will be limited to a small fraction of 10 CFR Part 100 dose guideline values in the event of either a steam generator tube rupture or steam line break.

The 1 gpa limit is consistent with the assumptions used in the analysis of these accidents.

The 500 gpd leakage limit per steam A

\\

generator ensures that steam generator tube integrity is maintained in the event of a main steam line rupture or under LOCA conditions.

The 10 gpa IDENTIFIED LEAKAGE limitation provides allowance for a limited amount of leakage from known sources whose presence will not interfere with the detection of UNIDENTIFIED LEAKAGE by the Leakage Detection Systems.

TheCONTRbLLEDLEAKAGElimitationrestrictsoperationwhenthetotalflow supplied to the reactor coolant pump seals exceeds 40 gpa with the modulating valve in the supply line fully open at a nominal Reactor Coolant System pres-sure of 2235 psig. This limitation ensures that in the event of a LOCA, the safety injection flow will not be less than assumed in the safety analyses.

The 1 gpm leakage from any Reactor Coolant System pressure isolation valve is sufficiently low to ensure early detection of possible in-series check valve failure.

l It is apparent that when pressure isolation is provided by two in-series check valves and when failure of one valve in the pair can go undetected for a substantial length of time, verification of valve integrity is required.

Since these valves are important in preventing overpressurization and rupture l

of the ECCS low pressure piping which could result in a LOCA that bypasses containment, these valves should be tested periodically to ensure low probability I

of gross failure.

The Surveillance Requirements for Reactor Coolant System pressure isolation valves provide added assurance of valve integrity thereby reducing the prob-i ability of gross valve failure and consequent intersystem LOCA.

Leakage from the pressure isolation valve is IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit.

l l

CATAWBA - UNITS 1 & 2 8 3/4 4-4 gpff 31 M

~.

D gk

{>

TABLE B 3/.4-1A 9

REACTOR VESSEL 10 S

g

>5 8

m 50- T-)'@

SHELF" 35 i It ENERGY T""' N TEMP MAT'L CU P

RT NPWO*

E COMPONENT HEAT NO.

SPEC. NO.

h, X 'F

'F FT-LB NOT M

g* l70 Closure Head Dome 55888-1 A5338, CL.1

.011 10 86 Closure Head Ring 007055 A508, CL.2

.006 16 23 16 101 Closure Head Flange 527038 A508, CL.2

.05

.013

-4

-2

-4 104 Vessel Flange 411212 A508, CL.2

.004

-31

-47

-31 153 Inlet Nozzle 526827 A508, CL.2

.05

.010

-13 7

-13 87 Inlet Nozzle 526829 A508, CL.2

.07

.010

-4 43

-4 86 Inlet Nozzle 526859 A508, CL.2

.04

.013 23

-4 81 Inlet Nozzle 526857 A508, CL.2

.05

.012

-13 23

-4 77 Outlet Nozzle 526827 A508, CL.2

.05

.011

-22 27

-22 84 Outlet Nozzle 526829 A508, CL.2

.07

.010

-4 2

-4 87 Outlet Nozzle 526859 A508, CL.2

.04

.011

-13 38

-13 81 om w

Outlet Nozzle 526857 A508, CL.2

.05

.013

-4 38

-4 60

)

Nozzle Shell 411077 A508, CL.2

.007

-40 34

-26 101 4

Inter. Shell 411343 A508, CL.2

.08

.004

-40 52

-8 100 a

tower Shell 527708 A508, CL.2

.04

.008

-13 16

-13 101 Bottom Head Ring 527428 A508, CL.2

.06

.013

-4 74 -

14 68 Botton Head Segment 55292-1 A533B, CL.1

.006

-22 5

-22 79 Botton Head Segment 55292-1 A5338, CL.1

.006

-13 34

-13 79 Botton Head Segment 55163-2 A5338, CL.1

.011

-4 38

-4 80 Botton Head Segment 55163-2 A5338, CL.1

.011

-13 74 14 70 Botton Head Dome 55178-1 A5338, CL.1

.010

-31 84 24 64 Nozzle Shell to Weld (P710)

Inter Shell to Lower Shell Weld Root (P710)

.03

.009 0**

0**

T Lower Shell to Bot. Head Ring Weld (P710)

Inter Shell to Lower Shell Weld (R747)

.05

.010

-76

,9

-51

_?

w

Estimated per NRC Standard Review Plan Section 5.3.2 from data obtained in the principal direction, g

y

- Estimated per NRC Standard Review Plan Section 5.3.2 from charpy tests performed at 10' F.

m

~

J

N 8 1985 J

m FINAL DRMt CONTAINMENT SYSTEMS 8ASES

)

3/4.6.1.8 ANNULUS VENTILATION SYST The OPERABILITY of +P.

h conditions, contai entilat ystem ensures that during LOCA essel ea age i the HEPA filters he annulus will be filtered through d ^ 1 adsor Operation of the system with t rains prior to discharge to the atmosphere.

using automatic ontrol aters operating to maintain low humidity least 10 continuous hours in a 31-day period is sufficient to re This requirement is necessary to meet the assumptions used in analyses and limit the SITE BOUNDARY radiation deses to w e safety line values of 10 CFR Part 100 during LOCA conditions.

used as a procedural guide for surveillance testing.

e-ANSI NS10-1980 will be 3/4.6.1.9 CONTAINMENT PURGE SYSTEMS The containment purge supply and exhaust isolation valves for compartment and the upper compartment (24-inch, and instrum and the Hydrogen Purge System (4-inch) are requ) ired to be r

plant operation since these valves have not been demonstrated c during a LOCA.

Maintaining these valves sealed closed during plant operation T

osing ensures that excessive quantities of radioactive materials will not be via the Containment Purge System.

j released valves cannot be inadvertently opened, the valves are sealed c or lock the valve closed, or prevents power from ord-operator.

tainment Air Release and Addition System valves sinceTh ment and the upper compartment, instrument room, and the Hydro valves, these 4-inch valves are capable of closing during a LOCA i

em the SITE BOUNDARY dose guideline values of 10 CFR Part 100 would Therefore, i

in the event of an accident during containment purging operation o

e exceeded with the line o 4-inch valves. pen will be limited to 2000 hours0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months during a calendar year for the

. Operation The total time the containment purge (vent) system isolation valves may be open during MODES 1, 2 of anticipated need and operating exp,erience.3, and 4 in a calendar year is a function Only safety related reasons; to facilitate personnel access for surveillance and mai be used to support the additional time requests.

v es, may ment purge supply and exhaust valves will provide material seal degradation and will allow opportunity for repair before g ent leakage failures could develop. The 0.60 L, leakage limit of Specificati 3.6.1.2b. shall not be exceeded when the leakage eakage for all valves and penetrations subject to Type B and C tests CATAWBA - UNITS 1 & 2 8 3/4 6-3 DEC' 31 1985

.e 7

JAN 8 1986 1

PLANT SYSTEMS BASES

/

200 psig are based on a steam generator RTa

~

The limita to prevent brittle fracture.

ons of 70*F and NT fMF d are sufficient 3/4.7.3 COMPONENT COOLING WATER SYSTEM ficient cooling capacity is available for continThe OP ystem ensures that suf-equipment during normal and accident conditions ued operation of safety-related capacity of this system, assuming a sin The redundant cooling assumptions used. in the safety analyses.gle failure, is consistent with the 3/4. 7. 4 NUCLEAR SERVICE WATER SYSTEM The OPERABILITY of the Nuclear Service Water System cooling capacity is available for continued operation of saf t ensures that sufficient ment during normal and accident conditions.

this system, assuming a single failure e y related equip-The redundant cooling capacity of used in the safety analysis.

i s consistent with the assumptions N

3/4.7.5 STANDBY NUCLEAR SERVICE WATER POND temperature ensure that sufficient cooling capacitTh (1) provide normal cooldown of the facility evel and y is available to either:

accident conditions within acceptable limits., or (2) mitigate the effects of on providing a 30-day cooling water supply to sa erature are based exceeding its design basis temperature and is consistent with th equipment without ations of Re e

March 1974. gulatory Guide 1.27, " Ultimate Heat Sink for Nucle e recommend-

_3/4.7.6 CONTROL ROOM AREA VENTILATION SYSTEM (1) the ambient air temperature does not exceed the em ensures that:

continuous-duty rating for the equipment and instrumentation co owable temperature for system and (2) the control room will remain habitable for operations during,and following all credible accident conditions oe y this system with the heaters operating to maintain low humidity usin personnel Operation of the control for at least 10 continuous hours in a 31-day period is suffi reduce the buildup of moisture on the adsorbers and HEPA filt automatic OPERABILITY of this system in conjunction with control ro c ent to is based on limiting the radiation exposure to pers om design provisions ers.

The room to 5 rems or less whole body, or its equivalentonnel occupying the control sistent with the requirements of General Design Criterion 19 of ATh 10 CFR Part 50. ANSI H510-1980 lance testing.

will be used as a procedural guide for sur, il ppendix A ve CATAWBA - UNITS 1 & 2 B 3/4 7-3 JAN 6 1996

' DEC' 1

1985

.e---

.--.s

W

.o

N 8 tMe FINAL FNdsr 3

-3/4.9 REFUELING OPERATIONS ud g BASES 3/4.9.1 BORON CONCENTRATION (1) the reactor will remain subcritical during CORE ALT uniform boron concentration is maintained for reactivity control in the water volume having direct access to the reactor vessel.

These limitations are consistent with the initial conditions assumed for the boron dilut in the safety analyses.

The value of 0.95 or less for K,ff includes a 1% Ak/k conservative allowance for uncertainties.

Similarly the boron allowance of 50 ppe boron. concentration value of 2000 ppe or greater' includ refueling operation precludes the possibility of uncontrolled boron of the filled portion of the Reactor Coolant System.

to the Reactor Coolant System of unborated water by closing flow paths fromThi sources of unborated water.

3/4.9.2 INSTRUMINTATION The OPERABILITY of the Source Range Neutron Flux Monitors ensures that redundant monitoring ca condition of the core. pability is available to detect changes in the reactivity N

3/4.9.3 DECAY TIME The minimum requirement for reactor suberiticality prior to movement of irradiated fuel assemblies in the reactor vessel ensures that suffi has elapsed to allow the radioactive decay of the short-lived fission products.

This decay time is consistent with the assu.nptions used in t saf t analyses.

3/4.9.4 CONTAINMENT BUILDING PENETRATION!

y The requirements on containment building penett

'of the Reactor Building Containment Purge System en o

losure and ( PERABILITY re tha release of radioactive material within containment will be re ricted rom leak to the environment or filtered through the HEPA filters d&

M ads rs prior to release to the atmosphere. The OPERABILITY an closure re etions are sufficient to restrict radioactive material releas based upon the lack of containment pressurization potential while in theuel eleme.,t rupture REFUELING MODE.

Operation of the Reactor Building Containment Purge System and the resulting iodine removal capacity are consistent with the assumption of the safety analysis.

maintain low humidity using automatic control for at least 10 contin in a 31-day period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters.

ANSI H510-1980 for surveillance testing.

will be used as a procedural guide

.)

CATAWBA - UNITS 1 & 2 B 3/4 9-1 DEC' 3 t 1985

~

m JAN F icec REFUELING OPERATIONS BASES 1

3/4.9.9 and 3/4.9.10 WATER LEVEL - REACTOR VESSEL and STORAGE P0uL The restrictions on minimum water level ensure that sufficient water depth is available-to remove 99% of the assumed 10% iodine gap activity released from the rupture of an irradiated fuel assembly.

The minimum water depth is consistent with the assumptions of the safety analysis.

[_

i 3/4.9.11 FUEL HANDLING VENTILATION EXHAUSL4rY5fEA jf#

The limitations on the Fuel Han ng tilation Exhaust tem ensure that all radioactive material relea d from a rradiated assembly will be filtered through the HEPA filte and -"-

'a r prior to discharge to the atmosphere. Operation of th s tain low huaidity using automatic cos._ystem w e heaters operating to main-n' or at least 10 continuous hours in a 31-day period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters.

The OPERABILITY of this system and the resulting iodine removal capacity are consistent with the assumptions of the safety analyses.

ANSI N510-1980 will be used as a procedural guide for surveillance testing.

4 o

CATAWBA - UNITS 1 & 2 8 3/4 9-3 DEC' 31 1985

f r; r JAN 8 1986 RNAL DRAFT s

i!!

sali E =r uli" i l P5

!!i si:

si:

s!;

s!a.

125 12=

it s I

j i 11 i~

i~ $

I I

E le!!

=

c, j==

q e

E8 gg 5y 21

s g-is

5

l::

gr gg E:::

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3 gy f;

[5 g!

Sfi SE I!

I I

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8

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<T 3

! g~l I!!

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8ll 'il

!!5 E!

I-j!!j1 III I

.12:

I I

.J CATAWBA - UNITS 1 & 2 6-4 DEC' 31 1985

a F

,A Y JAN 8 1986 h

O TABLE 6.2-1 MINIMUM SHIFT CRE" COMPOSITION POSITION NUMBER OF INDIVIOUALS REQUIRED TO FILL POSITION i

One Unit in Mode Both Units in 1, 2, 3 or 4 and Both Units in MODE 5 or 6 One Unit in Mode 5 MODE 1, 2, 3, or 4

~ or Defue.ad or 6 or Defueled SS 1

1 1

SRO 1

NoneN 1

RO 3#

2#

3#

NEO 3#

3#

STA 1

None 1

SS Shift Supervisor with a Senior Operator license SRO Individual' with a Senior Operator license RO Individual with an Operator license NEO Nuclear Equipment Operator STA Shift Technical Advisor

.The Shift Crew Composition may be one less than the minimum requirements of 3

Table 6.2-1 for a period of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate

.A unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements of Table 6.2-1.

This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift crewman being late or absent.

During any absence of the Shift Supervisor from the control room while the unit is in MODE 1, 2, 3, or 4, an individual (other than the Shift Technical Advisor *) with a valid Senior Operator license shall be designated to assume the control room command function. During any absence of the Shift Supervisor from the control room while the unit is in MODE 5 or 6, an individual with a valid Senior Operator license or Operator license shall be designated to assume the control room command function.

0n occasion when there is a need for both the Shift Supervisor and the SRO to be absent from the control room, the STA shall be allowed to assume the control room command function and serve as the SRO in the control room provided that:

O) the Shift Supervisor is available to return to the control room within 10 minutes, puhe assumption of SRO duties by the STA be Ifmited to periods not i ess o minutes duration and a total time not to exceed I hour duri anyg M umme s ft, and (3) the STA has a Senior Operator license on the t.

At least one of the required individuals must be assigned to the designated position for each unit.

NAt least one licensed Senior Operator or licensed Senior Operator Limited

/

to Fuel Handling must be present during CORE ALTERATIONS on either unit, who has no other co.: current responsibilities.

CATAWBA - UNITS 1 & 2 6-5 DEC'1i 1985

[

JM 8 1986

: ., t p n=

_ ADMINISTRATIVE CONTROLS 6

SEMIANNUAL RADI0 ACTIVE EFFLUENT RELEASE REPORT (Continued)

The Radioactive Efflue information for ea elease Reports shall include the following waste (as defined by 10 CFR Part 61) shipped offsite du ing te report d:

^

C\\ ass Total Container vog, %}

a.

b.

Total ri q paterminedbymeasurementorestimate),

Principal radi nuclides (deterpined by measurement or estimate),

c.

Spes whsiwr4' d.

eppe of wast e.g., dewatered' spent resin compacted dry waste, Sourot.

evaporator bottoms),% and procasoy e,mployed i

e.

- l t '- - "

d gg

,g$x.

NTye 8, key f.

Solgification, agent or absorbent (e.g., come Q.

_y d I

~

~ '~ V wea facmeNshy tbe The Semiannual dioactive Effluent Release Report to be submitted within 60 days after Janua 1 of each year shall include an annual summary of hourly meteorological data llected over the previous year. This annual summary may be.etther in the form wind direction, atmospheric stability, and precipitation (if measured),

N the form of joint frequency distributions of wind speed, wind direction, and atmospheric stability.*

This same report shall include an assessment of the radiation doses due to the radioactive liquid and gaseous effluents released from the unit or station during the previous calendar year.

shall also include an assessment of the radiation doses from radioactiveThis same repo liquid and gaseous effluents to MEMBERS OF THE PUBLIC due to their activities inside the SITE BOUNDARY (Figure 5.1-3) durin tions used in making these assessments, i.e.,g the report period. All assump-specific activity, exposure time and location shall be included in these reports. The meteorological conditions concurr,ent with the time of release of radioactive materials in gaseous effluents, as determined by sampling frequency and measurement, shall be used for determining the gaseous pathway doses.

The assessment of radiation doses shall be performed in accordance with the methodology and parameters in the OFFSITE DOSE CALCULATION MANUAL (00CM).

The Semiannual Radioactive Effluent Release Report to be submitted within 60 days after January 1 of each year shall also include an assessment of radiation doses to the likely most exposed MEM8ER OF THE PUBLIC from reactor releases and other nearby uranium fuel cycle sources, including doses from primary effluent pathways and direct radiation, for the previous calendar year to show conformance with 40 CFR Part 190, " Environmental Radiation Protection Standards for Nuclear Power Operation". Acceptable methods for calculating the dose contribution from liquid and gaseous effluents are given in Regulatory Guide 1.109, Rev. 1, October 1977.

"In lieu of submission with the Semiannual Radioactive Effluent Release Report, the licensee has the option of retaining this summary of required meteorological data on site in a file that shall be provided to the NRC upon request.

CATAWBA - UNITS 1 & 2 6-18 DEC 31 198$

JAN 8 1986 a

FldstDRAFT e

ADMINISTRATIVE CONTROLS RECORD RETENTION (Continued) h.

Specifications; Records of inservice inspections performed purs cal i.

Records of reviews performed for changes made to procedures or equipment or reviews of tests and experiments pursuant t j.

Records of meetings of the NSRB and reports required by Specification 6.5.1.10; k.

Records of the service lives of all hydraulic and mechanical s required by Specification 3.7.8 including the date at which the s life commences and associated installation and ma e

1.

Records of secondary water sampling and water quality; and Records of analyses required by the Radiological Environmental m.

Monitoring Program that would permit evaluation of the accurac the analysis at a later date.

x This should include procedures effective at specified times and QA records showing that these ocedures were followed.

D^n r2.

Quality quality assurance activities required by the Operational by ANS 5.2g19 nual shall be retained for a period of time as recommended T

_6.11 RADIATION PROTECTION PROGRAM

/

6.11 with the requirements of 10 CFR Part 20 and shall be app ent adhered to for all operations involving personnel radiation ex,posure maintained, and 6_.12 HIGH RADIATION AREA 6.12.1 In lieu of the " control device" or " alarm signal" required by paragraph 20.203(c)(2) of 10 CFR Part 20, each high radiation area in 10 CFR Part 20, in which the intensity of radiation is equal to or les

, as defined 1000 mR/h at 45 cm (18 in.) from the radiati*on source or from any s an the radiation penetrates shall be barricaded and conspicuously posted a c

high radiation area and entrance thereto shall be controlled by requirin sa issuance of a Radiation Work Permit (RWP).

g protection procedures (e.g., Health Physics Technician) or personnel co i

ously escorted by such individuals may be exempt from the RWP issu ment during the performance of their assigned duties in high radiation areas with exposure rates equal to or less than 1000 mR/h, provided they are o wise following plant radiation protection procedures for entry into su radiation areas.

such areas shall be provided with or accompanied by one or m following:

i a.

A radiation monitoring device which continuously indicates the l

radiation dose rate in the area; or

'j b.

A radiation monitoring device which continuously integrates the radiation dose rate in the area and alarms when a preset integrated CATAWBA - UNITS 1 & 2 6-21 JAN 6 1986 DEC'31 1985

.

ML20151Z212

Text

Dear Mr. Denton:

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