ML20010E682
| ML20010E682 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 08/26/1981 |
| From: | NEBRASKA PUBLIC POWER DISTRICT |
| To: | |
| Shared Package | |
| ML20010E678 | List: |
| References | |
| NUDOCS 8109080142 | |
| Download: ML20010E682 (18) | |
Text
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COOPER NUCLEAR STATION-or TABLE 3. 2. B (PAGE 3)
M RESIDUAL llEAT REMOVAL SYSTEM (LPCI FK)DE) CIRCUITRY REQUIREMENTS o
unco g*g Minimum Number of Action Required When om Instrument Operable Components Component Operability M
Instrument I.D. No.
Setting Limit Per Trip System (1)
Is Not Assured
- o m RilR Pump Low Flow RilR-dPIS-125 A & B
>2500 gpm 1
A Time Delays RilR-TDR-K45, lA&lB 4.251T15.75 min.
1 A
RilR Pump Start RilR-TDR-K75A & K70B 4.51T15.5 Sec.
1 A
Time Delay RilR-TDR-K75B & K70A 1 5 sec.
1 A
RllR lleat Exchanger RilR-TDR-K93, A & B 1.81T12.2 min.
1 B
Bypass T.D.
RllR Crosstie Valve RllR-LMS-2 Valve Not closed (3)
E Position l
Bus IA Low Volt.
27 X 3/lA Loss of Voltage 1
B Aux. Relay
' il3 Bus IB Low Volt.
27 X 3/lB Loss of Voltage 1
B 8
Aux. Relay l
Bus IF Low Volt, 27 X 1/lF Loss of Voltage 1
B Aux. Relays 27 X 2/lF Loss of Voltage 1
B Bus 1G Low Volt.
27 X 1/lc Loss of Voltage 1
B Aux. Relays 27 X 2/1C Loss of Voltage Pump Discharge Line CM-PS-266
>5 psig (3)
D CM-PS-270
>15 psig
-(3)
D l
Emergency Buses 27/lF-2, 27/lFA-2 3600 15%
2 B
Undervoltage Relays 27/1C-2, 27/lCB-2 8 second 12 sec.
2 B
g (degraded voltage) time delay 1
B Emergency Buses Loss 27/lF-1,~27/1FA-1, 2900V 15%
of Voltage Relays 27/lG-1, 27/lCB-1, 5 second il sec.
27/ET-1, 27/ET-2 delay 1
B l
Emergency Buses Under-27X7/lF, 27X7/lG, Voltage Relays Timers 10 second 12 sec.
1 B
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COOPER NUCLEAR STATION TABLE 3.2.B (PAGE 5)
IIPCI SYSTEM CIRCUITRY REQUIREMENTS Minimum Number of Action Required When Instrument Operable Components Component Operability i
Instrument I.D. ho.
Setting Limit Per Trip System (1)
Is Not Assured Suppression Charaber llPCI-LS-91 A & B 2 " 11 0 (5" Above 1(2)
A 2
liigh Water Level NormaI) i IIPCI Cland Seal Cond.
IIPCI-LS-356 B
>18" 1(3)
A llotwell Level llPCI-LS-356 A 146" 1(3)
A llPCI Turbine Stop IIPCI-LMS-4 N.A.
1(2)
B l
Valve Monitor j
Suppression Chamber llPCI-LMS-2 N.A.
J(2)
A llPCI Suction d,
Valve 23-58 y
ilPCI Control Oil llPCI-PS-2787-Il
>85 psig 1(2)
B Pressure Low IIPCI-PS-2 787-L
>20 psig Turbine Conditional llPCI-TDR-K14 13.51T116.5 sec.
1(3)
E Supervisory Alarm Actuation Timer Pump Discharge Line Low Pressure CM-PS-268
>10 psig (3)
D 4
llPCI Steamline liigh IIPCI-TDR-l*33 2.91T13.3 sec.
1 A
6P Actuation Timer IIPCI-TDR-K43 f
v
COOPER NUCLEAR STATION TABLE 3.2.B (PAGE 6)
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REACTOR CORE ISOLATION COOLING SYSTEM (RCIC) CIRCUITRY REQUIREMENTS Minimum Number of Action Required When Instrument Operable Components Component Opernbility Instrument I.D. No.
Setting Limit Per Trip System (1)
Is Not Assured I
RCIC liigh Turbine RCIC-PS-72, A & B 125 ps*,
1(2)
A Exhaust Press.
4 RCIC Low Pump Suction RCIC-PS-67-1 1-15" lig 1(2)
Press.
RCIC Steam Line Space RCIC-TS-79, A,B,C,6D
<200 F 2(4)
A Excess Temp.
RCIC-TS-80, A,B,C,6D RCIC-TS-81, A,B,C,&D RCIC-TS-82, A,B,C,&D RCIC Steam Line liigh RCIC-dPIS-83 & 84 370" 1S1620" 11 0 1
A 2
AP RCIC Steam Supply RCIC-PS-87, A,B,C.6D 3,50 psig 2(2)
A Press. Low p
RCIC Low Pump RCIC-FIS-57 2,40 gpm 1(2)
A Disch. Flow j
Pump Discharge Line CM-PS-269 3,10 psig (3)
D Low Pressure i
RCIC Turbine Condition-RCIC-TDR-K9 13.5 1 T 1 16.5 (3)
E i
al Supervisory Alarm Timer Reactor Low Water.
10A-K80, A & B 3-37" Indicated Level 2(2)
A Level 10A-K79, A & B (NBI-LIS-72, A,B,C,
& D) i i
Reactor Iligh Water NBI-LIS-101, A & C #2 1+58.5 Indicated Level 2(2)
A Level RCIC Steamline High RCIC-TDR-K12 2.7<T13.3 sec 1
A AP Actuation Timer RCIC-TDR-K22
COOPER NUCLEAR STATION TABLE 4.2.B (Page 2)
RilR SYSTEM TEST & CALIBRATION FREQUENCIES I
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i Instrument Item Item I.D. No.
Functional Test Freq.
Calibration Freq.
Check Ins trumenta tion l.
Drywell High Pressure
-PC-PS-101, A, B, C & D Once/ Month (1)
Once/3 Months None i
2.
Reactor Vessel Shroud Level NBI-LITS-73, A & B #1 Once/ Month (1)
Once/3 Months once/ Day 3.
Reactor Low Pressure RR-PS-128 A & B Once/ Month (1)
Once/3 Months None 4.
Reactor Low Pressure HBI-PS-52 A & C' Once/ Month (1)
Once/3 Months None i
NBI-PIS-52 B & D 5.
Drywell Press.-Containment PC-PS-Il9, A,B,C & D Once/ Month (1)
Once/3. Months None Spray 6
RilR Pump Discharge Press.
RilR-PS-120, A,B,C & D once/ Month (1)
Once/3 Months None 7.
RllR Pump Discharge Press.
RllR-PS-105, A,B,C & D Once/ Month (1)
Once/3 Months None d
8.
RilR Pump Low Flow Switch RHR-dPIS-125 A & B Once/ Month (1)
Once 3 Months None i'
9.
RilR Pump Start Time Delay RilR-TDR-K70, A & B Once/ Month (1) _
Once/Oper. Cycle None 10.
RilR Pump Start Time Delay RilR-TDR-K75, A & B Once/ Month (1)
Once/Oper. Cycle None j
11.
RHR lleat Exchanger Bypass T.D.
Rild-TDR-K93, A & B Once/ Month (1)
Once/Oper. Cycle None 12.
RilR Cross Tie Valve Position RilR-LMS-2 Once/ Month (1)
N.A.
13.
Low Voltage Relays 27 X 3/lA (7)
None 14.
Low Voltage Relays 27 X 3/1B (7)
None 15.
Low Voltage Relays 27 x 2/lF, 27 X 2/lG (7)
None 16
. Low Voltage Relays 27 X 1/lF, 27 X 1/lG (7)
.None l
j 17.
Pump Disch. Line Press. Low CM-PS-266, CM-PS-270 Once/3 Months Once/3 Months None i
18.
Emergency buses Undervoltage 27/lF-2, 27/lFA-2, 27/lG-2, once/ Month once/18 Months once/12 hrs.
1 Relays (Degraded Voltage) 27/lGB-2 l
j 19.
Emergency Buses Loss of 27/lF-1, 27/lFA-1, 27/lG-1, Once/ Month Once/18 Months once/12 hrs.
Voltage Relays 27/lGB-1, 27/ET-1, 27/ET-2 j
20.
Emergency Buses Undervoltage 27X7/lF, 27X7/lG Once/ Month once/18 konths None Relays Timers 1
i
TABLE 4.2.C SURVELLLANCE RE1]UIREMENTS FOR ROD WITilDRAWAL BLOCK INSTRUMENTATION Functional Function Test Freq.
Calibration Freq.
Instrument Check APRM Upscale (Flow Bias)
(1)
(3)
Once/3 Months Once/ Day APRM Upscale (Startup Mode)
(1)
(3)
Once/3 Months once/ Day APRM Downscale (1)
(3)
Once/3 Months once/ Day APRM Inoperative (1)
(3)
N.A.
Once/ Day RBM Upscale (Flow Bias)
(1)
(3)
Once/6 Months once/ Day RBM Downscale (1)
(3)
Once/6 Months Once/ Day RBM Inoperative (1)
(3)
N.A.
Once/ Day IRM Upscale (1)
(2)
(3)
Once/3 Months once/ Day l
1101 Downscale (1)
(2)
(3)
Cace/3 Months Once/ Day d
IRM Detector Not Full In (2)
(Once/oper-Once/Oper. Cycle (10)
Once/ Day i
l ating cycle) 1101 Inoperative (1)
(2)
(3)
N.A.
N.A.
Slet Upscale (1)
(2)
(3)
Once/3 Months once/ Day Slet Downscale (1)
(2)
(3)
Once/3 Months Once/ Day SRM Detector Not F:
In (2)
(Once/ ope r-Once/Oper. Cycle (10)
N.A.
ating cycle)
S101 Inoperative (1)
(2)
(3)
N.A.
N.A.
Flow Bias Comparator (1)
(8)
Once/Oper. Cycle N.A.
Flow Bias Upscale (1)
(8)
Once/3 Months N.A.
Rod Block Logic (9)
N.A.
N.A.
RSCS Rod Group C Bypass (1)
Once/3 Months N.A.
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l COOPER NUCLEAR STATION
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TABLE 4.2.F PRIMARY CONTAINMENT SURVEILLANCE 7:4STRilMENTATION TEST AND CALIBRATION...cQUENCIES l
l Instrument Instrument I.D. No.
Calibretion Frequency Instrument Check Reactor Water Level NBI-LI-85A Once/6 Months Each Shift NBI-LI-85B Once/6 Months Each Shift 1
Reactor Pressure RFC-PI-90A.
Once/6 Months Each Shift RFC-PI-90B Once/6 Months Each Shift Drywell Pressure PC-PR-512A Once/6 Months Each Shift PC-PI-512B Once/6 Months Each Shift Drywell Temg erature PC-TR-503 Once/6 Months Each Shift PC-TI-505 Once/6 Months Each Shift 1
Suppression Chamber PC-TR-21A Once/6 Months Each Shift
?
Air Temperature PC-TR-23, Ch. 1&2 Once/6 Months Each Shift Suppression Chamber PC-TR-21B Once/6 Months Each Shift Water Temperature PC-Tk-22, Ch. 1 & 2 Once/6 Months Each Shift Suppression Chamber PC-L1-10 Once/6 Months Each Shift Water Level PC-L!t-l l once/6 Months Each Shift PC-LI-12 Once/6 Months Each Shift PC-LI-13 Once/6 Months Each Shift Suppression Chamber PC-PR-20 Once/6 Months Each Shift Pressure Control Rod Position N.A.
N.A.
Each Shift Neutron Monitoring (APRM)
N.A.
Once/ Week Each Shift Torus to Drywell PC-dPR-20 Once/6 Months Each Shift Dif ferential Pressure Suppression Chamber /
PC-PR-20/513 (2)
Once/6 Months Each Shift Drywell Pressure (AP)
NOTES FOR TABLES 4.2.A TRROUGH 4.2.F 1.
Initially once every month until exposure (M ao defined on Figure 4.1.1) is l
2.0 X 10 ; thereaf ter, according to Figure 4.1.l(af ter NRC approval).
The compilation of instrument failure rate data may include data obtained f rom other boiling water reactors for which the same design instrument operates in an environment similar to that of CNS.
2.
Functional tests shall be performed before each startup with a required frequency not to exceed once per week.
3.
This instrumentation is excepted frem the functional test definition. The functional test will consist of applying simulated inputs.
Local alarm lights representing upscale and downscale trips will be verified but no I
rod block will be pro'uced at this time. The inoperative trip will be initiated to produce a rod block (SRM and IRM inoperative also bypassed with the mode switch in RUN).
The functions that cannot be verified to produce a rod block directly will be verified during the operating cycle.
4.
Simulated automatic actuation shall be performed once each operating cycle.
Where possible, all logic system functional tests will be performed using the test jacks.
5.
Reactor low water level, high drywell pressure and high radiation main steam line tunnel are not included on Table 4.2. A since they are tested on Table 4.1.2.
6.
The logic system functional tests shall include an actuation of time delay relays and timers necessary for proper functioning of the trip systems.
7.
These units are tested as part of the Core Spray System tests.
8.
The flow bias comparator will be tested by putting one flow unit in " Test" (producing 1/2 scram) and adjusting the test input to obtain comparator rod block.
The flow bias upscale will-be verified by observing a local upscale trip light during operation and verifying that it will produce a rod block during the operating cycle.
f 9.
Performed during operating cycle.
Portions of the logic is checked rot'.
frequently during functional tests of the functions that produce a rod block.
10.
The detector will be inserted during each operating cycle and the proper amount of travel into the core verified.
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3.2 BASES In addition to reactor protection ins trymentation which initiates a reactor scram, protective instrumentation has been provided which initiates action to mitigate the consequences of accidents which are beyond the operator's ability to control, or terminates operator errors before they result in serious con-sequences. This set of specifications provides the limiting conditions of operation for the primary system isolation function, initiation of the core cooling systems, control rod block and standby gas treatment sys t ems.
The obj ectives of the Specifications are (i) to assure the effectiveness of the protective instrumentation when required even during periods when portions of such systems are out of service for maintenance, and (ii) to prescribe the trip settings required to assure adequate performance. When necessary, one channel may be made inoperable for brief intervals to conduct required I
functional tests and ca:ibrations.
Some of the settings on the instrumentation that initiate or control core and containment cooling have tolerances explicitly stated where the high and low values are both critical and may have a substantial ef fect on safety.
The est points of other ins trumentation, where only the high or low end of the setting has a direct bearing on safety, are chosen at a level away from the normal operating rarge to prevent inadvertent actuation of the safety system involved and expusure to abnormal situations.
Actuation of primary containment valves is initiated by protective instru-mentation shown in Table 3.2.A which senser the conditions for which isola-tion is required.
Such instrumentation aust be available whenever primary containment integrity is required.
1 The instrumentation which initiates primary system isolation is connected in a dual bus arrangement.
1 l
The low water level instrumentation,n, set to trip at 176.5" (+12.5") above the top l
of the active fuel, closes all isolation valves except those in Groupe 1, 4, l
and 5.
Details of valve grouping and required closing times are given in Specification 3.7.
For valves which isolate at this level this trip setting is adequate to prevent core uncovery in the case of a break in the largest line assuming a 60 second valve closing time.
Required closing times are less than this.
The low reactor water level ins trumentation is ser to trip when reactor water level is 12/ ' (-37") abova the top of the active fuel.
This trip closes Main Steam Line Isolation Valves, Main Steam Drain Valves, Recire Sample Valves (Groups 1 and 7), initiates the HPCI and RCIC.
The low reactor water I
level instrumentation is set to trip when the water level is 19" (-145") above the top of the active fuel.
This trip activates the remainder of the CSCS subsystems, and s tarts the emergency diesel generators.
Thdse trip level settings were chosen to be high enough to prevent spurious actuation but low enough to initiate CSCS operation and primary system isolation so that post j
accident cooling can be accomplished, l
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3.2 BASES
(Cont'd) arid the guidelines of 10CFR100 will not be exceeded.
For large breaks up to the complete circumferential break of a 28-inch recirculation line and with the trip setting given above, CSCS initiation and primary system isolation are initiated in time to meet the above criteria.
Reference Paragraph VI.5.3.1 FSAR.
The high drywell pressure instrumentation is a diverse signal for mal-functions to the water level instrumentation and in addition to initiating CSCS, it causes isolation of Group 2 and 6 isolation valves.
For the breaks discussed above, this instrumentation will generally initiate CSCS operation before the low-low-low water level instrumentation; thus the results given above are applicable here also. The water level instrumen-tatf on initiates protection for the full spectrum of loss-of-coolant acciaints and causes isolation of all isolation valves except Groups 4 and 5.
Venturis are provided in the =ain steam lines as a means of measuring steam flow and also limiting the loss of mass inventory from the vessel during a steam line break accident.
The primary function of the instru-mentation is to detect.a break in the main steam line.
For the worst case of accident, main steam line break outside the drywell, a trip setting of 140% cf rated steam flow in conjunction with the flow limiters and main steam line valve closure, limits the mass inventory loss such that fuel is not unceyered, fuel temperatures peak at approximately 1000 F and release of radioactivity to the environs is below 10CFR100 guidelines. Reference Section SIV.6.5 FSAR.
Temperature monitoring instrumentation is provided in the main steam tunnel and along the steam line in the turbine building to detect leaks in these areas.
Trips are provided on this instrumentation and when exceeded, cause closure of isolation valves.
See Spec. 3.7 for Valve Group. The setting is 200 F for the main steam leak detection system.
For large breaks, the high steam flow instrumentation is a backup to the temp. ins trumentation.
High radiation monitors in the main steam tunnel have been provided to detect gross fuel failure as in the control rod drop accident. With the established setting of 3 times normal background, and main steam line I
isolation valve closure, fission product release is limited so that 10CFR100 guidelines are not exceeded for this accident.
Reference Sec-tion XIV.6.2 FSAR.
s Pressure instrumentation is provided to close the main steam isolation l
valves in RUN Mode when the main steam line pressure drops below Speci-fication 2.1.A.6.
The Reactor Pressure Vessel thermal transient due to an inadvertent opening of the turbine bypass valves when not in the RUN l
Mode is less severe than the loss of feedwater analyzed in Section XIV.5 l
of the FSAR, therefore, closure of the Main Steam Isolation valves for thermal transient protection when not in RUN mode is not required.
l l
The HPCI high flow and temperature instrumentation are provided to detect a l
l l
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3.3 and 4.3 BASES (cont'd.)
The degraded performance of the original drive (CRD7RDB144A) under dirty operating conditions and the insensitivity of the redesigned drive (CRD7RDB144B) has been demonstrated by a series of engineering tests under simulated reactor operating conditions. The successful performance of the new drive under actual operating conditions has also been demonstrated by consistently good in-service test results for plants using the new drive and may be tuiarred from plants using the older model drive with l
a modified (larger screen size) internal filter which is less prone to plugging.
Data has been documented by surveillance reports in various operating plants.
These include Oyster Creek, Monticello, Dresden 2 and Dresden 3.
Approximately 5000 drive tests have been recorded to date.
Following identification of the " plugged filter" problem, very frequent scram tests were necessary to ensure proper performance. However, the more frequent scram tests are now considered totally unnecessary and unwise for the following reasons:
1.
Erratic scram performance has been identified as due to an obstructed drive filter in type "A" drives. The drives in CNS are of the new "B" type design whose scram performance is unaffected by filter condition.
2.
The dirt load is primarily released during startup of the reactor when the reactor and its systems are first subjected to flows and pressure and thermal stresses.
Special attention and measures are now being taken to assure cleaner systems.
Reactors with drives identical or similar (shorter stroke, smaller piston areas) have operated through many refueling cycles with no sudden or erratic changes in scram performance.
This preoperational and startup testing is sufficient to detect anomalous drive performance.
3.
The 72-hour outage limit which initiated the start of the frequent scram testing is arbitrary, having no logical basis other than quanti-fying a " major outage" which might reasonably be caused by an event so severe as to possibly affect drive performance. This requirement is unwise because it provides an incentive for shortcut actions to hasten returning "on line" to avoid the additional testing due to 72-hour outage.
The surveillance requirement for scram testing of all the control rods j
af ter each refueling outage and 10% of the control rods at 16-week intervals is adequate for detennining the operability of the control rod system yet is not so frequent as to cause excessive wear on the control rod system components.
The numerical values assigned to the predicted scram performance are based on the analysis of data from other BWR's with control rod drives the same as those on Cooper Nuclear Station.
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I LD11 TING CONDITIONS EUR OPERATION SURVEILLANCE REQUIRE iENTS 3.6.D Safety and Relief Valves 4.o.D Safety and Relief Valves 1.
During reactor power operating condi-1.
Approximately half of the safety valves tions and prior to reactor startup and relief valves shall be checked or f rom a Cold Condition, or whenever replaced 'with bench checked valves reactor coolant pressure is greater once per operating cycle. All valves than atmospheric and temperature will be tested every two cycles.
greater than 212 F, all three safety valves and the safety modes of all The set point of the safety valves relief valves shall be operable, ex-shall be as specified in Specification cept as specified in 3.6.D.2.
2.2.
2.
2.
At least one of the relief valves shall be disassembled and inspected each re-a.
From and af ter the date that the fueling outage.
safety valve function of one relief valve is made or found to be inopera-ble, continued reactor operation is permissible only during the succeeding thirty days unless such valve function is sooner made operable.
b.
From and af ter the date that the safety valve function of two relief valves is made or found to be inoperable, con-tinued reactor operation is permissible only during the succeeding seven days unless such valve function is sooner made operable.
3.
If Specification 3.6.D.1 is not met, 3.
The integrity of the relief safety valve an orderly shutdown shall be initiated bellows on any three stage valve and the reactor coolant pressure shall shall be continuously monitored.
l be reduced to a cold shutdown condi-l tion within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
l l
4.
From and af ter the date that position 4.
The operability of the bellows monitoring indication on any one relief valve is system shall be demonstrated once every made or found to be inoperable, contin-three months when three stage valves ued reactor operation is permissible are installed.
only during the succeeding thirty days unless such valve position indication 5.
Once per operating cycle, with the is sooner made operable, reactor pressure > 100 psig, each relief valve shall be manually opened until l
the main turbine bypass valves have i
closed to compensate for relief valve opening.
l 6.
I a.
Operability of the relief valve position i
indicating pressure switches and the j
safety valve position indicating thermocouples shall be demonstrated l
once per operating cycle.
I b.
An Instrument Check of the safety and l
relief valve position indicating devices shall be performed monthly.
-136-
s COOPER NUCLEAR STATION i
TABLE 3.7.1 (Page 2)
PRIMARY CONTAINMENT ISOLATION VALVES Number of Power Maximum Action On Operated Valves Operating Normal Initiating Valve & Steam Inboard outboard Time (Sec) (1)
Position (2)
Signal (3)
Primary Containment Purge & Vent 2
15 C
SC j
PC-246AV, PC-231MV Primary Containment & N Supply 2
15 C
SC 2
PC-238AV, PC-232MV ACAD Supply MV 1303, MV 1304 2
15 0
GC MV 1305, MV 1306 2
15 0
CC I?
Suppression Chamber Purge & Vent 1
40 C
SC(4)
PC-230MV Bypass (PC-305MV)
Primary Containment Purge & Vent 1
40 C
SC(4)
PC-231MV Bypass (PC-306MV) 4 i
1
i NOTES FOR TABLE 3.7.1
.i 1.
Maximum valve operating times in seconds in the closed direction. This is the direction required for Primary Containment isolation.
2.
Normal position indicates the normal valve position during power operations.
0 = Open C = Closed 3.
Action on initiating signal indicates the valve operation af ter the tsignal initiation.
i GC = Goes Closed SC = Stays Closed i
4.
PC-305MV & PC-306MV have override switches (key operated) which can be l
used to open valves when isolation signals are in.
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4.9 BASES The monthly test of the diesel generator is conducted to check for equipment failures and deterioration. Testing is conducted up to equilibrium operating conditions to demonstrate proper operation at these conditions..The diesel generator will be manually started, synchronized and connected to the bus and load picked up.
The diesel generator should be loaded to at least 357 of rated load to prevent fouling of the engine.
It is expected that the diesel generator will be run for at least two hours.
Diesel generator experience at other generating stations indicates that the testing frequency is adequate and provides a high reliability of operation should the system be required.
Each diesel generator has two air compressors and two air receivers for l
s tarting.
It is expected that the air compressors will run only inf requently.
During the monthly check of the diesel generator, each receiver in each set of receivers will be drawn down below the point at which the corresponding compressor automatically starts to check operation and the ability of the compressors to recharge the receivers.
The dietel generator fuel consumption rate at full load is approximately 275 gallons per hour.
Thus, the monthly load test of the diesel generators will test the operation and the ability of the fuel oil transfer pumps to refill the day tank and will check the operation of these pumps from the emergency Source.
The test of the diesel generator during the refuelinr, outage will be more comprehensive in that it will functionally test the system; i.e. it will check diesel generator starting and closure of diesel generator breaker and sequencing of load on the diesel generator. The diesel generator will be
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s tarted by simulation of a loss-of-coolant accident.
In addition, an undervoltage condition will be imposed to simulate a loss of off-site power.
Periodic tests between refueling outages verify the ability of the diesel generator to run at full load and the core and containment cooling pumps to deliver full flow.
Periodic testing of the various components, plus a func-tional test once-a-cycle, is sufficient to maintain adequate reliability.
Although station batteries will deteriorate with time, utility experience indicates there is almost no possibility of precipitous failure.
The type l
of surveillance described in this specification is that which has been demonstrated over the years to provide an indication of a cell becoming irregular or unserviceable long before it becomes a failure.
In addition, the checks described also provide adequate indication that the batteries have the speci-i l
fied ampere-hour capability.
The diesel fuel oil quality mut..e checked te ensure proper operation of the diesel generators. Water content should be minimized because water in the i
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o 6.2 (cont'd) 1.
Membe rship a.
Senior Division Manager of Power Operations (chairman) b.
Division Manager of Licensing and Quality Assurance (alternate Chair-man) c.
Division Manager of Power Projects d.
Division Manager of Power Supply e.
Division Manager of Environmental Affairs f.
Censultants (as required)
The Board members shall collectvely have the capability required to rev'.ew problems in the following areas: nuclear power plant operations, nuclear engineering, chemistry and radiochemistry, metallurgy, instrumentation and control, radiological safety, mechanical and electrical engineering, and other appropriate fields associated with the unique characteristics of the nuclear power plant involved.
When the nature of a particular problem dictates, special consultants will be utilized.
Alternate members shall be appointed in writing by the Board Chairman to serve on a temporary basis; however, no more than two alternates shall serve on the Board at any one time.
2.
Meeting frequency:
Semiannually, and as required on call of the Chairman.
3.
Quorum:
Chairman or Vice Chairman, plus three members including alternates. No more than a minority of the quorum shall be from groups holding line responsibility for the operation of the plant, 4.
Respo nsibilities : The following subjects shall be reported to and reviewed by the NPPD Safety Review and Audit Board.
a.
The safety evaluations for 1) changes to rTocesures, equipment or systems and 2) tests or experiments cot,0 ;ted under the provision of Section 50.59, 10 CFR, to verify that such actions did not constitute an unreviewed safety question.
b.
Proposed changes to procedures, equipment or systems which involve an unreviewed safety question as defined in' Section 50.59, 10 CFR.
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1.
A tabulation on an annual basis of the number of station, utility and other personnel (including contractors) re-ceiving exposures greater than 100 arem/yr and their associated man rem exposure according to work and job functions, 1/ e.g., reactor operations and surveillance, inservice inspection, routine maintenance, special main-tenance (describe maintenance), waste processing, and refueling. The dose assignment to various duty functions mt j be estimates based on pocket dosimeter, TLD, or film b udge measurements.
Small exposures totaling less than 20%
of the individual total dose need not be accounted for.
In the aggregate, at least 80% of the total whole body dose received from external sources shall be assigned to specific major work functions.
2.
A summary description of facility changes, tests or experi-ments in accordance with the requirements of 10CFR50.59(b).
3.
Pursuant to 3.8.A, a report,f radioactive source leak t es ting.
This report is required only if the tests reveal the presence of 0.005 microcuries or more of removable contamination.
D.
Monthly Operating Report Routine reports of operating statistics, shutdown experience, and a narrative summary of operating experience relating to safe operation of the facility, shall be submitted on a monthly basis to the Director, Of fice of Management Information and Program l
Control, U.S. Nuclear Regulatory Commission, Washington, DC 20555, with a copy to the appropriace Regional Office, no later j
than the tenth of each month following the calendar month covered l
by the report.
6.7.2.
Reportable Occurrences Reportable occurrences, including corrective actions and measures to l
prevent reaccurrence, shall be reported to the NRC.
Supplemental reports may be required to fully describe final resolution of l
occurence.
In case of corrected or supplemental reports, a licensee event report shall be completed and reference shall be made to the original report date.
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This tabulation supplements the requirements of $20.407 of 10CFR Part 20.
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=
i 6.7.3.
Unique Reporting Requirements I
l Reports shall be submitted to the Director, Nuclear Reactor Regulation, USNRC, Washington, DC 20555, as follows:
i A.
Reports on the following areas shall be submitted as noted:
None.
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e
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N;briska Public Power District
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MANAGEMENT ORGANIZATION CHART General Manager
'i NPPD Safety P.eview and Audit Board i
Deputy General Manager i
Assistant General Manager Assistant General Manager Ennineoring & Construction Operations i
e ta j
y Senior Division Manager of Power Operations I
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Division Manager Division Manager Division Manager of Licensing Division Manager of Power Projects of Power Supply
& Quality Assurance of Environtnental Affairs l
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Cooper Nuciear Station Cooper Nuclear Station Quality Assurance Manager Engineering Support Station Superintendent i
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i Cooper Nuclear Station
- Quality Assurance Supervisor
- Fksponsible for the Fire Protection Program Fsgure 6.1.1 NPPD Management Organizahon Chart