ML20140B020
| ML20140B020 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 05/28/1997 |
| From: | Milano P NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20140B023 | List: |
| References | |
| NUDOCS 9706050267 | |
| Download: ML20140B020 (9) | |
Text
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-"1 UNITED STATES p")
E NUCLEAR REGULATORY COMMISSION s*
o WASHINGTON, D.C. son 50001 BOSTON EDISON COMPANY DOCKET NO. 50-293 j
PILGRIM NUCLEAR POWER STATION 4
AMENDMENT TO FACILITY OPERATING LICENSE Amendment No.172 l
License No. DPR-35 1.
The Nuclear Regulatory Commission (the Commission or the NRC) has found that:
I A.
The application for amendment filed by the Boston Edison Company (the
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licensee) dated November 26, 1996, with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations; i
B.
The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.
There is reasonable assurance:
(1) that'the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the C.ommission's regulations;
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D.
The issuance of this amendment will not be inimical to the common j
defense and security or to the health and safety of the public; and l
E.
The issuance of this amendment is in accordance with 10 CFR Part 51
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of the Commission's regulations and all applicable requirements have been satisfied.
2.
Accordingly, the license is amended by changes to the Technical Specifica-tions as indicated in the attachment to this license amendment, and paragraph 2.C(2) of Facility Operating License No. DPR-35 is hereby amended to read as follows:
9706050267 970528 PDR ADOCK 05000293 p
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3.
This license amendment is effective as of its date of issuance and shall be implemented within 30 days.
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FOR THE NUCLEAR REGULATORY COMMISSION 0
h=
Patrick D. Milano, Acting Director i
Project Directorate I-3 l
Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation
Attachment:
l Changes to the Technical l
Specifications l
Date of Issuance: May 28, 1997
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ATTACHMENT TO LICENSE AMENDMENT NO.172 FACILITY OPERATING LICENSE NO. DPR-35
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DOCKET NO. 50-293 Replace the following pages of the Appendix A Technical Specifications with -
s the attached pages. The revised pages are identified by Amendment number and contain vertical lines indicating the area of change.
l Remove Insert 1-3 1-3 l
3/4.2-9 3/4.2-9 1
3/4.2-24 3/4.2-24 3/4.2-26 3/4.2-26 l
B3/4.6-11 B3/4.6-11 B3/4.7-4 B3/4.7-4 l
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r 1.0 DEFINITIONS (Crnt) l' L
Desian Power-Design powIr micns a sticdy-st:ta pow 2r Isvsl of 1998 thermal megawat:s.
l M.
Primary Containment Intearity - Primary containment integrity means that the drywell and prer,sure suppression chamber are intact and all of the following conditions are 1,atisfied:
1.
All manual containment isolation valves on lines connected to the reactors coolant system or containment which are not required to be open during accident conditions are closed.
2.
At lesst one door in each airlock is closed and sealed.
l 3.
All blind flanges and manways are closed.
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4.
Al; automatic primary containment isolation valves and all instrument line l
flow check valves are operable or at least one containment isolation valve in each line having an inoperable valve shall be deactivated in the t
isolated condition.
l 5.
All containment isolation check valves are operable or at least one containment valve in each line having an inoperable valve is secured in the isolated position.
N.
Secondary Containment Intearity - Secondary containment integrity means that the reactor building is intact and the following conditions are met:
1.
At least one door in each access opening is closed.
2.
The standby gas treatment system is operable.
3.
All automatic ventilation system isolation valves are operable or secured in the isolated position.
O.
Operatina Cvele - Interval between the end of one refueling outage and the end of the next subsequent refueling outage.
P.
Refuelina Frecuencies:
1.
Refuelina Outaae - Refueling outage is the period of time between the shutdown of the unit prior to a refueling and the startup of the plant after that refueling. For the purpose of designating frequency of testing and surveillance, a refueling outage shall mean a regularly scheduled outage; however, where such outages occur within 11 months of completion of the previous refueling outage, the required surveillance testing need not be performed until the next regularly scheduled outage.
(Definitions U and V apply) 2.
Refuelina Interval-Refueling interval applies only to ASME Code, Section XIIWP and IWV surveillance tests. For the purpose of designating frequency of these code tests, a refueling interval shall j
mean at least once every 24 months.
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l Revision Amendment No. 36,??,39,43,#13,di9,150,151,152 172 13
NOTES FOR TABLE 3.2.A (Cont) 3.
Instrument set point corresponds to 137.86 inches above top of active fuel.
4.
Instrument set point corresponds to 79.86 inches above top of active fuel.
s 5.
Not required in Run Mode (bypassed by Mode Switch).
6.
Each steam line is monitored by two instrument trip channels per trip system. Therefore, the minimum number of main steam line high flow instruments required to be operable is four per main steam line unless the line is isolated.
7.
These signals also start SBGTS and initiate secondary containment isolation.
8.
Only required in Run Mode (interlocked with Mode Switch).
9.
Deleted.
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Revision Amendment No. 147,151,154,194 172 3/4.2-9
PNPS TABLE 3.2.D RADIATION MONITORING SYSTEMS THAT INITIATE AND/OR ISOLATE 3
Minimum # of Operable Instrument Channels Per Trio system (1)
Trio Function Trio Level Settina Action (2) 2 Refuel Area Exhaust Upscale, <100 mr/hr A or B Monitors 2
Refuel Area Exhaust Downscale A or B Monitors NOTES FOR TABLE 3.2.D 1.
Whenever the systems are required to be operable, there shall be two operable or tripped trip systems. If this cannot be met, the indicated action shall be taken.
2.
Action l
A.
Cease operation of the refueling equipment:
B.
Isolate secondary containment and start the standby gas treatment system.
Revision Amendment No. 89 172 3/4.2-24 4
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PNPS f
TABLE 3.2.F (Cont) l SURVEILLANCE INSTRUMENTATION Mwwnum # of Operable Instrument Parameter Type Indication Notes Channels instrument #
and Ranoe i
}l TI-5021-2A Suppression Chamber Indicator /
l TRU-5021-1A Water Temperature Mulhpoint Recorder (1)(2)(3)(4) 2 30-230*F (Bulk) -
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TI-5022-28 Suppression Chamber Indicator /
TRU-5022-1B Water Temperature Mulbpoint Recorder (1)(2)(3)(4) 30-230*F (Bulk) 1 PID-5021 Drywell/ Torus Diff.
Indicator.25 - +3.0 psig (1)(2)(3) (4)
Pressure i
1 PlD-5067A Drywell Pressure Indicator.25 - +3.0 psig (1)(2)(3 )(4)
PID-50678 Torus Pressure indicator - 1.0 - +2.0 psig 1 Naive (a)Pnmary Safety / Relief Valve (a) Acoustic monitor (5)
(b) Thermocouple or Possbon
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(b) Backup 7
1 N aive (a) Primary Safety Valve Position (a) Acoustic monitor (5) or kulicator (b) Thermocouple (b) Backup 1Nalve See Note (6)
Tail Pipe Temperature Thermocouple (6) l Indication c<.
Li-1001-604A Torus Water Level Indicator /Mulbpoet (1)(2)(3)(4)
LR-1001-604A (Wide Range)
Recorder 0300" H O.
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1-2 Torus Water Level Indicator /Mulhpomt (1)(2)(3)(4)
Li-1001-604B (Wide Range)
Recorder 0-300" H O :
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LR-1001-6048 -
l-Revision Amendment No. 56r42 172 3/4.2-26
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BASES:
3/4.6 PRIMARY SYSTEM BOUNDARY (Cont)
G.
Structural Intearity The Pilgrim Nuclear Power Station Inservice inspection Program conforms to the requirements of 10CFR50.55a(g). Where practical, the inspection of ASME Section XI Class 1,2, and 3 components conforms to the edition and addenda of Section XI of the ASME s
Boiler and Pressure Vessel Code required by 10CFR50.55a(g). When implementation of an ASME Code required inspection has been determined to be impractical for PNPS, a request for relief from the inspection requirement is submitted to the NRC in accordance with 10CFR50.55a(g)(5)(iii).
Requests for relief from the ASME Code inspection requirements will be submitted to the NRC prior to the beginning of each 10 year inspection interval for which the inspection requirement is known to be impractical. Requests for relief from inspection requirements which are identified to be impractical during the course of the inspection interval will be reported to the NRC on an annual basis throughout the inspection interval.
I 1.
Shock Suppressors (Snubbers)
Snubbers are designed to prevent unrestrained pipe motion under dynamic loads as might occur during an earthquake or severe transient, while allowing normal thermal motion during startup and shutdown. The consequence of an inoperable snubber is an increase in the probability of structural damage to piping as a result of a seismic or other event initiating dynamic loads. It is therefore required that all snubbers required to protect the primary coolant system and all other safety related systems or components be operable during reactor operation.
The visualinspection frequency is based on maintaining a constant level of snubber protection to systems. The cumulative number of inoperable snubbers detected during any inspection intervalis the basis for establishment of the subsequent inspection interval and the existing inspection interval should remain in effect until its completion.
When the cause of the rejection of a snubber is clearly established and remedied for that
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snubber and verified by inservice functional testing, that snubber may be exempted from l
being counted as inoperable.
Generically susceptible snubbers are those which are of a specific make or model and have the same design features directly related to rejection of the snubber by visualinspection, and are exposed to the same environmental conditions such as temperature, radiation, and vibration.
When a snubber is found inoperable, an engineering evaluation is initiated, in addition to the determination of the snubber mode of failure, in order to determine if any safety-related l
component or system has been adversely affected by the inoperability of the snubber.
Initiating this evaluation within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> ensures that prompt corrective action will be afforded.
Revision Amendment No. 4&rO3 172 B3/4.6-11
BASES:
l 3/4.7 CONTAINMENT SYSTEMS (Cont) i A.
Primary Containment (Cont)
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capability of the structure over its service lifetime. Additional margin to maintain the containment in the "as built" condition is achieved by establishing the allowable i
operational leak rate. The allowable operational leak rate is derived by multiplying the i
maximum allowable leak rate or the allowable test leak rate by 0.75 thereby providing a
- 25% margin to allow for leakage deterioration which may occur during the period s
between leak rate tests.
The primary containment leak rate test frequency is based on maintaining adequate assurance that the leak rate remains within the specification. The leak rate test frequency is in accordance with 10CFR50 App. J.
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The penetration and air purge piping leakage test frequency, along with the containment leak rate tests, is adequate to allow detection of leakage trends.
Whenever a bolted double-gasketed penetration is broken and remade, the space between the gaskets is pressurized to determine that the seals are performing properly, it is expected that the majority of the leakage from valves, penetrations and seals would be into the reactor building. However, it is possible that leakage into other l
parts of the facility could occur. Such leakage paths that may affect significantly the consequences of accidents are to be minimized. The personnel air lock is tested at 10 i
psig, because the inboard door is not designed to shut in the opposite direction.
Primary Containment Isolation Valves Double isolation valves are provided on lines penetrating the primary containment and open to the free space of the containment. Closure of one of the valves in each line would be sufficient to maintain the integrity of the pressure suppression system.
Automatic initiation is required to minimize the potentialleakage paths from the containment in the event of a loss of coolant accident.
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Group 1 - process lines are isolated by reactor vessel low-low water level in order to allow for removal of decay heat subsequent to a scram, yet isolate in time for proper operation of the core standby cooling systems. The valves in group 1 are also closed when process instrumentation detects excessive main steam line flow, low pressure, l
main steam space high temperature, or reactor vessel high water level.
Group 2 - isolation valves are closed by reactor vessel low water level or high drywell pressure. The group 2 isolation signal also " isolates" the reactor building and starts the standby gas treatment system. It is not desirable to actuate the group 2 isolation signal by a transient or spurious signal.
Group 3 -isolation valves can only be opened when the reactor is at low pressure and the core standby cooling systems are not required. Also, since the reactor vessel could potentially be drained through these process lines, these valves are closed by low water level.
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Revision
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Amendment No. 413,13e 172 B3/4.7-4 i;. -. - -.
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