ML20195J545
| ML20195J545 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 01/21/1988 |
| From: | Wessman R Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20195J549 | List: |
| References | |
| NUDOCS 8801280531 | |
| Download: ML20195J545 (31) | |
Text
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NUCLEAR REGULATORY COMMISSION WASHINGTON, D. C,20555
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%.......f COSTON EDISON COMPANY DOCKET NO. 50-293 PILGRIM NUCLEAR POWER STATION AMENDMENT TO FACILITY OPERATING LICENSE Anendment No.113 License Nn. DPR-35 1.
The Nuclear Regulatory Cormission (the Comission) has found that:
A.
The application for amendm mt by Boston Edison Company (the licensee) dated June 4, 1987, as supplemented by letters dated August 13, Septenber 21, and December 8, 1987, complies with the standards and requirements of the Atomic Enercy Act of 1954, as amended (the Act),
and the Comission's rules and regulations set forth in 10 CFR Chapter I; B.
The facility will operate in confornity with the application, the provisions of the Act, and the rules and regulations of the Comi!! ion; C.
There is reasonable assurance (i) 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 Commission's regulations; D.
The issuance of this anendment will not be inimical to the comon defense and security or to the health and safety of the public; and E.
The issuance of this amendment is in accordance with 10 CFR Part 51 of the Comission's regulations and all applicable requirements have been satisfied.
2.
Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paracraph 3.B of Facility Operating License No. DPR-35 is hereby amended to read as follows:
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(2) Technical Snecifications The' TechniEa1 Specifications contained in Appendix A, as revised throuch Amendment No. ll3, are hereby incorporated in the license.
The licensee shall operate the facility in accordance with the Technical Specifications.
3.
This license amendment is effective 30 days after the date of issuance.
FOR THE NUCLEAR REGt!LATORY COMMISSION
$ V Lv.<
Richard H. Wessman, Actino Director Proiect Directorate I-3 Division of Reactor Projects I/II Attachnont:
Changes to tha Technical Specifications Date of Issuance:
January 21, 1988
ATTACHMENT TO LICENSE AtiENDMENT NO. 113 FACILITY OPERATING LICENSE NO. DPR-35 DOCKET NO. 50-793 Replace the following pages of the Appendix A Technical Specifications with the enclosed paces.
The revised pages are identified by amendment number and
.contain vertical lines indicating the areas of chance.
The corresponding overleaf pages are provided to raintain document completeness.
Remove Paaes Insert Paoes ii ii 3
3 5b Sb 48 4R 68 68 69 69 15?
152 152a 15?.o 153-155 153-155 155a 155b 157a 157a 160-171a 160-171a 175 175
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4 Surveillance Page No.
3.7 CONTAINHENT SYSTEMS 4.7 152 A.
152 B.
Standby Gas Treatment System B
158 C.
159 3.8 RADIOACTIVE EFFLUENTS 4.8 177 A.
Liquid Effluents Concentration A
177 B.
Radioactive Liquid Effluent 8
177 Instrumentation l
C.
Liquid Radwaste Treatment C
178 D.
Gaseous Effluents Dose Rate D
179 E.
Radioactive Gaseous Effluent E
180 Instrumentation F.
Gaseous Effluent Treatment F
181 G.
182 H.
Hechanical Vacuum Pump H
183 3.9 AUXILIARY ELECTRICAL SYSTEMS 4.9 194 A.
Auxiliary Electrical Equipment A
194 B.
Operation with Inoperable Equipment B
195 3.10 CORE ALTERATIONS
- 4. l C, 202 A.
Refueling Interlocks A
202 B.
Core Monitoring B
202 l
C.
Spent Fuel Pool Hater Level C
203 3.11 REACTOR FUEL ASSEMBLY 4.11 205A A.
Average Planar Linear Heat A
205A Generation Rate (APLHGR) 8.
Linear Heat Generation Rate (LHGR)
B 205A-1 l
C.
Minimum Critical Power Ratio (MCPR)
C 205B D.
Power / Flow Relationship D
205B-1 3.12 FIRE PROTECTION 4.12 206 A.
Fire Detection Instrumentation A
206 B.
Fire Hater Supply System B
206 C.
Spray and/or Sprinkler Systems C
206c D.
Halon System D
206d E.
Fire Hose Stations E
206e F.
C06e G.
Dry Chemical Systems G
206e-1 H.
Yard Hydrants and Exterior Hose H
206e-1 Houses Amendment No. /E, B/, Ed,113 ji
1.0 DEFINITIONS (Cont'd) valve closure, are bypassed when reactor pressure is less than 600 osig, the low pressure main steam line isolation valve closure trip is bypassed, the reactor protection system is energizec witn IRK neutron monitoring system' trips.and control ro:.itnarawal interlocks in service.
2.
Run Moce - In this mode the reactor system pressure is at or acove 880 psig and the reactor protection system is energized with APRM protection and RBM interlocks in service.
3.
Shutdown Mode - The reactor is in the shutdown mode when the reactor moce switch is in the shutdown mode position and no core alterations are being performed.
Hot Shutdown means conditions as above with reactor a.
coolant temperature greater than 212*F.
b.
Colc Shutdown means conditions as aoove with reactor coolant temperature equal to or less than 212*F.
4.
Refuel Hoce - The reactor is in the refuel mode when the moce switch is in the refuel mode position. When the mode switch is in the refuel position, the refueling interlocks are in service.
L.
Desicn Power - Design power means a steady-state power level of 1998 thermal megawatts.
M.
Primary Containment Integrity - Primary containment integrity means that the crywell and pressure suppression chamber are intact ano all of the following conditions are satisfied:
1.
All manual containment isolation valves on lines connected to the reactor coolant system or containment which are not required to be open during accident conditions are closed.
2.
At least one door in each airlock is closed and sealed.
3.
All blind flanges and manways are closed.
4.
All automatic primary containment isolation valves are operable or at least one containment isolation valve in each line having an inoperable valve shall be deactivated in the isolated condition.
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 Integrity - Secondary containment integrity means that the reactor building is intact and the following conditions are met:
3 Amendment No. 113
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1.0 DEFINITIONS (Continvec)
AA, Action - Action shall be that part of a specification which prescribes remedial measures recuired under cesignated conditions.
65.
Metter(s) of the Putilc' - Member (s) of the public shall include all persons ano are not occupationally associated with the plant.
This category does not include employees of the utility, its contractors, or vendors. Also excluded from this categ0ry are persons who enter the site to service equipment or to make deliveries.
This category does include persons who use portions of the site for recreational, occupational or other purposes not associated with the site.
CC.
_S,i t e 50 u'n d a r y = - The site boundary is shown in figure 1.6,1 in the FSAR.
DD.
Racwaste Treatment Svstet.
1.
Gaseous Rad *aste Treatment System - The gaseous radwaste treatment system is tnat system identified in Figure 4.8-2.
2.
Licuid Rad =aste Treatment Svstem - The liquid radwaste treatment system is that system identified in Figure 4.8-1.
EE.
Automatic prinary Containment Isolation Valves - Are primary containment isolation valves antch receive an automatic primary containment group isolation signal.
I See FSAR Figure 1.6-1
)
Sb Amendment No. AG, 113
PNPS TABLE 3.2-B (Cont'd)
INSTRUMENTATION THAT INITIATES OR CONTROLS THE_ CORE AND CONTAINMENT COOLING SYSTEMS Minimum # of Operable Instrument Channels Per Trip System (1)
Trio Function Irjg_ Level Setting Remarks 2
High Drywell Pressure 12.5 psig
- 1. Initiates Core Spray; LPCI; HPCI.
- 2. In conjunction with Low-Low Reactor Hater Level, 120 second time delay and LPCI or Core Spray pump running, initiates Auto Blowdown (ADS)
- 3. Initiates starting of Diesel Generators.
- 4. In conjunction with Reactor Low Pressure initiates closure of HPCI vacuum breaker containment isolation valves.
1 Reactor Low Pressure 400 psig 25 Permissive for Opening Core Spray and LPCI Admission valves.
1 Reactor Low Pressure 1110 psig In conjunction with PCIS signal permits closure of RHR (LPCI) injection valves.
1 Reactor Low Pressure 400 psig 25 In conjunction with Low-Low Reactor Hater Level initiates Core Spray and LPCI.
2 Reactor Low Pressure 900 psig 2 25 Prevents actuation of LPCI break detection circuit.
2 Reactor Low Pressure 100>P>50 psig In conjunction with High Drywell Pressure initiates closure of HPCI vacuum breaker containment isolation valves.
Amendment No. 48,113 48
BASES:
3.2 In addition to reactor protection instrumentation 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 consequences.
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 systems.
The objectives of the Specifications are (i) to assure the effectiveness of the protective instrumentation when required by preserving its capability to tolerate a single failure of any component of such systems even during periods when portions of such systems are out of service for maintenance, and (ii) to prescribe the trip settings required to assure adequate performance.
When necessary, one channel may be made inoperable for brief intervals to conduct required functional tests and calibrations.
Some of the settings on the instrumentation that initiate or control core and containment cooling have tolerances explicitly stated where the high and low values are both critical and.may have a substantial effect on safety.
The set points of other instrumentation, where only the high or low end of the setting has a direct bearing on safety, are chosen at a level away from the normal operating range to prevent inadvertent actuation of the safety system involved and exposure to abnormal situations.
Actuation of primary containment valves is initiated by protective instrumentation shown in Table 3.2.A which senses the conditions for which isolation is required. Such instrumentation must be available whenever primary containment integrity is required.
The instrumentation which initiates primary system isolation is connected in a dual bus arrangement.
The low water level instrumentation set to trip at 128.26 inches above the top of the active fuel closes all isolation valves except those in Groups 1, 4 and 5.
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 low reactor water level instrumentation is set to trip when reactor water level is 77.26 inches above the tcp of the active fuel
(-49" on the instrument).
This trip closes Main Steam Line Isolation i
1 Amendment No. W/,113 68
3.2 BASES (Cent'd)
Valves, Main Steam Drain Valves, Recirc Samole Valves (Group 1) activates the CSCS subsystems, starts the emergency diesel generators anc tries the recirculation pum;s, This trip setting level was chosen to be high enough to prevent spurious actuation but low effough to initiate CSCS operation and primary system isolation so that no fuel damage will occur and so that post accident cooling can be accorcilsned and the guidelines of 10 CFR 100 will not be violated.
For large breaks up to the complete circumferential break of a 28-inch recirculation line anc with the trip setting given above, CSCS initiation and primary system isolation are initiated in time to meet the above criteria.
I The hign dry. ell pressure instrumentation is a diverse signal to the water level instrumentation anc in addition to initiating CSCS. it causes isolation of Group 2 isolation valves.
For the breaks discussed above, this instrumentation will initiate CSCS operation at about the same tirre as the low low water level instrumentation; thus the results given above are acclicable here also.
The low low water level instrumentation initiates protection for the full spectrum of loss-of-coolant accidents and causes isolation of Group 1 isolation valves.
Venturis are provided in the main steam lines as a means of measuring steam flow and also limiting the loss of mass inventory from the vestel during a steam line break accident.
The primary function of the instrueentation is to detect a break in the main steam line.
For the wocst case accident, main steam line break outside the drywell, a trip setting of 140'l. of 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 uncovered, fuel temperatures remain approximately 1000*F and release of radioactivity to the environs is well below 10 CFR 100 guidelines.
l I
Temperature monitoring instrumentation is provided in the main steam line tunnel and the turbine basement to detect leaks in these areas.
Trips are provided on this instrumentation and when exceeded, cause closure of isolation valves.
The setting of 170'F for the main steam l
line tunnel detector is low enough to detect leaks of the order of 5 to 10 gpm; thus, it is capable of covering the entire spectrum of breaks.
For large breaks, the high steam flow instrumentation is a backup to the temperature instrumentation.
High radiation monitors in the main steam line tunnel have been provided to detect gross fuel failure as in the control rod drop acci-69 Amendment No. 3/,113
l l,
L!MITIN3 CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 1
3.7 CONTAINVENT SVSTEMS 4.7 CONTAINHENT SYSTEMS Applicability:
Applicability:
Applies to the ocerating status of the Applies to the primary and secondary primary anc seconcary containment containment integrity, systems.
Objective:
Objective:
To verify the integrity of the primary To assure the integrity of the primary and secondary containment.
and seconda y containment systems.
Specification:
Specification:
A.
Suceression Pool Suppression Pool 1.
At any time that the nuclear system 1.
- a. The suppression chamber water is pressurized above atmospheric level and temperature shall be pressure or work is being done which checked once per day, has the potential to drain the vessel, the pressure suppression
- b. Whenever there is indication of pool water volume and temperature relief valve operation or shall be maintained within the testing which adds heat to the following limits except as specified suppression pool, the pool in 3.7.A.2 and 3.7.A.3.
temperature shall be continually monitored and also
- a. Minimum water volume - 84,000 ft' observed and logged every 5 mir.utes until the heat addition
- b. Maximum water volume - 94,000 ft' is terminated.
- c. Maximum suppression pool bulk
- c. Whenever there is indication of temperature during normal relief valve operation with the continuous power operation shall bulk temperature of the be 180*F, except as specified in suppression pool reaching 160*F 3.7.A.I.e.
or more and the primary coolant system pressure greater than
- d. Maximum suppression pool bulk 200 psig, an external visual temperature during RCIC, HPCI or examination of the suppression ADS operation shall ba 190'F, chamber shall be conducted except as specified in 3.7.A.I.e.
before resuming power operation.
- d. Whenever there is indication of relief valve operation with the local temperature of the suppression pool T-quencher reaching 200'F or more, an external visual examination of the suppression chamber shall be conducted before resuming power operation, i
Amendmer.t No. $3, 113 152
i LIMITIt.3 CO OITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.'7 CONTAINMEP T SYSTEMS (Con' t) 4.7 CONTAINMENT SYSTEPS (Con't) e.
In order to continue reactor e.
A visual-inspection of the power operation the suppression suppression chamber interior, chamber pool bulk tercerature including water line regions.
must be reduced to <80*F within shall be made at each major 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
refueling outage, f.
If the suppression pool bulk f.
The pressure differential temperature exceeds the limits between the drywell and of Specification 3.7.A.l.d, suppression chamber shall be' RCIC, HPCI or ADS testing shall recorded at lea,st once each be terminated and suppression shift when the differential pool cooling shall be initiated, pressure is required.
g.
If the suppression pool bulk g.
Suppression chamber water temoerature during reactor power level shall be recorded at operation exceeds 110*F, the least once each shift when reactor shall be scrammed.
the differential pressure is required.
h.
During reactor isolation conditions, the reactor pressure vessel shall be depressurized to less than 200 psig at normal cool down rates if the pool bulk temperature reaches 120'F.
1.
Differential pressure between the drywell and suppression chamber shall be maintained at equal to or greater than 1.17 psid, except as specified in j and k.
j.
The differential pressure shall ba established within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of placing the reactor in the run mode following a shutdown.
The differential pressure may be reduced to less than 1.17 psid 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a scheduled shutdown.
k.
The differential pressure may be reduced to less than 1.17 psid for a maximum of four (4r hours for maintenance activities on the differential pressure control system and during required operability testing of the HPCI system, the relief j
valves, the RCIC system and the drywell-suppression chamber vacuum breakers.
i 153 Amendment No.
113 1
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.I CONTAINMENT SYSTEMS (Con't) 4.7 CONTAINMENT SYSTEMS (Cont'd1 1.
If the specifications of Item 1, above, cannot be met, and the differential pressure cannot be restored within the subsequent (6) hour period, an orderly shutdown shall be initiated and the reactor shall be in a cold shutdown condition in twenty-four (24) hours.
m.
Suppression chamber water level shall be maintained between -6 to -3 inches on torus level instrument which corresponds to a downcomer submergence of 3.00 and 3.25 feet respectively, n.
The suppression chamber can be drained if the conditions as specified in Sections 3.5.F.3 and 3.5.F.5 of this Technical Specification are adhered to.
l 154 Amendment No. J/,113
LXHITING CONDXTIONS FOR OPERATION SURi!EILLANCE REQUIREMENTS 3.7.A Primary Containment (Con't) 4.7.A Primary Containment (Con't)
Primary Containment Intearity Primary Containment Intearity i
2.a Primary containment integrity 2.a The primary containment integrity shall be maintained at all times shall be demonstrated by when the reactor is critical or performing Primary Containment when the reactor water temperature Leak Tests in accordance with 10 is above 212*F and fuel is in the CFR 50 Appendix J, as amended thru reactor vessel except while Sept. 22, 1980, with exemptions as performing "open vessel" physics approved by the NRC and exceptions test at power levels not to exceed as follows:
5 Hw(t).
(1) The main steam line isolation Primary containment integrity valves shall be tested at a means that the drywell and pressure 223 psig, and pressure suppression chamber are normalized to a value intact and that all of the equivalent to 45 psig each following conditions are satisfied:
operating cycle.
(1) All manual containment (2) Personnel air lock door seals isolation valves on lines shall be tested at a pressure connected to the reactor 110 psig each operating coolant system or containment cycle.
Results shall be which are not required to be normalized to a value open during accident equivalent to 45 psig.
conditions are closed.
If the total leakage rates listed (2) At least one door in each below are exceeded, repairs and airlock is closed and sealed, retests shall be performed to correct the conditions.
(3) All blind flanges and manways are closed.
(1) All double-gasketed seals:
(4) All automatic primary containment isolation valves (2) All testable penetrations and and all instrument line flow isolation valves:
check valves are operable 60% La (x) except as specified in 3.7.A.2.b.
(3) Any one penetration or isolation valve except main (5) All containment isolation steam line isolation valves:
check valves are operable or 5% Lt (x) at least one containment isolation valve in each line (4) Any one main steam line having an inoperable valve is isolation valve:
secured in the isolated 11.5 scf/hr 923 psig.
- position, where x - 45 psig Lt
.75 La La - 1.0% by weight of the contained air 9 45 psig for 24 hrs.
Amendment No. 17, 113 155
LIMITING CC'O!i10NS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7.A Primary Containment (Cen't) 4.7.A Primary Containment (Con't)
Primarv Containment Isolation Valves Primary Containment Isolation Valves 2.b.
In the event any Primary 2.b.1 The primary containment Containment Isolation Valve that isolation valves surveillance receives an automatic isolation shall be pgrformed as follows:
signal listed in Table 3.7-1 becomes inoperable, at least one a.
At least once per operating containment isolation valve in cycle the operable each line naving an inoperable isolation valves tnat are valve shall be deactivated in power operated and the isolated condition.
(This automatically initiated requirement may be satisfied by shall be tested for deactivating the inocerable simulated automatic valve in tne isolatec initiation anc closure condition. Deactivation means times.
to electrically or oneumatically disarm, or otnerwise secure tne b.
At least once per quarter:
valve.)*
- 1. All normally open power operated isolation valves (except for the main steam line power operated isolation valves) shall be fully closed and reopened.
- 2. Trip the main steam isolation valves individually and verify closure time.
c.
At least twice per week the main steam line power operated isolation valves thall be exercised by partial closure and subsequent reopening, i
d.
At least once per operating cycle the operability of 1
the reactor coolant system instrument line flow check valves shall be verified.
2.b.2 Whenever a primary containment
- Isolation valves closed to satisfy isolation valve, that receives these requirements may be reopened on an automatic isolation signal, an intermittent basis under OR; listed in Table 3.7-1 is approved administrative controls, inoperable, the position of the isolatec valve in each line having an inoperable valve shall be recorded daily,.
Amendment No. 113 155a
LIMITING CONDITION FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7.A Primary Containee,t (Con't) 4.7.A PrimPry Containment (Con't) 2.c Continuous Leak Rate Monitor l
When the primary containment is inerted, the containment shall be continuously monitored for gross leakage by review of the inerting system makeup requirements.
This monitoring system may be taken out of service for maintenance but shall be returned to service as soon as practicable.
2.d Drywell Surfaces l
The interior surfaces of the drywell and torus above the water line shall be visually inspected every refueling outage for evidence of deterioration.
'l 1
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155b i
Amendment No, 113
LIMITING CONDITION FOR OPERATION SURVEILLANCE REQUIREMENTS t
3.7.A Primary Containment 4.7.A Primary Containment l
5.b.
Within the 24-hour period subsecuent to placing the reactor in the Run mode following a shutdown, the containment atmostnere oxygen concentration shall be reduced to less than 4% by volume and maintained in this condition.
De-inerting may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a shutdown.
6.
If the specifications of 3.7.A.1 thru 3.7.A.5 cannot be met, an orderly shutdown shal'1 be initiated and the reactor shall be in Cold Shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
1 i
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Amendment No. $7,113 157a i
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TABLE 3.7-1 PRIMARY CONTAIMENT AND RE_ ACTOR VESSELISOLATION VALVES POWER MAXIMUM OPERATED PENETRATION OPERATING NORMAL ISOLATION GROUP VALVE #.
SYSTEM & DES [RI.PTION IPC/0PC
__ NUMB _LR TIME (SEC1 EOSITION POSITION 1
A0-203-1A Main Steam Line "A" Isolation Valve IPC X-7A 3 sti 5 Open Closed 1
A0-203-2A Main Steam Line "A" Isolation Valve OPC X-7A 3 sti 5 Open Closed 1
A0-203-1B Main Steam Line "B" Isolation Valve IPC X-78 3 sts 5 Open Closed 1
A0-203-28 Main Steam Line "B" Isolation Valve OPC X-78 3 sts 5 Open Closed 1
A0-203-IC Main Steam Line "C" Isolation Valve IPC X-7C 3 sti 5 Open Closed 1
A0-203-2C Main Steam Line "C" Isolation Valve OPC X-7C 3 sts 5 Open Closed 1
A0-203-10 Main Steam Line "D" Isolation Valve IPC X-7D 3 sts 5 Open Closed 1
A0-203-2D Main Steam Line "0" Isolation Valve OPC X-7D 3 Its 5 Open Closed 1
MO-220-1 Main Steam Drain Isolation Valve IPC X-8 30 Closed Closed 1
H0-220-2 Main Steam Drain Isolation Valve OPC X-8 30 Closed Closed 1 1 A0-220-44 Reactor Hater Sample Line Valve IPC X-41A 10 Open Closed 1 1 A0-220-45 Reactor Water Sample Line Valve OPC X-41A 10 Open Closed 2,5 A0-5033A Drywell Purge / Makeup OPC X-26 10 Closed Closed 3
25 A0-50338 Drywell Purge / Makeup OPC X-26 10 Closed Closed 2,5 A0-5033C Torus Makeup OPC X-205 10 Closed Closed 3
25 A0-5035A Drywell Purge / Makeup OPC X-26 5
Closed Closed 25 A0-50358 Drywell Purge / Makeup OPC X-26 5
Closed Closed 25 A0-5036A Torus Purge Inlet OPC X-205 5
Closed Closed 25 A0-5036B Torus Purge Inlet OPC X-205 5
Closed Closed 3
2,5 A0-5041A Torus Exhaust Bypass OPC X-227 10 Closed Closed 3
2,5 A0-50418 Torus Exhaust Bypass OPC X-227 10 Closed Closed 25 A0-5042A Torus Main Exhaust OPC X-227 5
Closed Closed 25 A0-50428 Torus Main Exhaust OPC X-227 5
Closed Closed 2,5 A0-5043A Drywell 2" Exhaust Bypass OPC X-25 10 Closed Closed 3
2,5 A0-50438 Drywell 2" Exhaust Bypass OPC X-25 10 Closed Closed 3
25 A0-5044A Drywell Purge Exhaust OPC X-25 5
Closed Closed 25 A0-50448 Drywell Purge Exhaust OPC X-25 5
Closed Closed 24 A
TIP Ball - Ball Solenoid Valve OPC X-35 5
Closed Closed 24 8
TIP Ball - Ball Solenoid Valve OPC X-35 5
Closed Closed 24 C
TIP Ball - Ball Solenoid Valve OPC X-35 5
Clo.ed Closed 24 D
TIP Ball - Ball Solenoid Valve OPC X-35 5
Closed Closed Amendment No.
M,113 160
TABLE 3.7-1 (con't)
PRIMARY LONTAINMENT AND REACTOR VESSEL ISOLATION VALVES POWER MAXIMUM OPERATED PENETRATION OPERAT.ING NORMAL ISOLATION GRQUP VALVE #
SYSTEM & DESCRIPTION IPC/0PC NUMBER TIME (SEC) EOSITION POSITION R
26 SV-5065-llA H /02 Analyzer Supply OPC X-228J 2
Closed Closed 2
26 SV-5065-138 H /02 Analyzer and Leak Detection Supply OPC X-50A-d 2
Open Closed 2
26 SV-5065-14A H /02 Analyzer and Leak Detection Supply OPC X-106A-b 2
Open Closed 2
26 SV-5065-158 H /02 Analyzer Supply OPC X-228C 2
Closed Closed 2
26 SV-5065-18A H /02 Analyzer Supply GPC X-228J 2
Closed Closed 2
26 SV-5065-20B H /02 Analyzer and Leak Detection Supply OPC X-50A-d 2
Open Closed 2
26 SV-5065-21A H /02 Analyzer and Leak Detec; ion Sr,, ply OPC X-106A-b 2
Open Closed 2
26 SV-5065-22B H /02 Analyzer Sample OPC X-228C 2
Closed Closed 2
H /02 and PASS Sample Return OPC X-46F 2
Open Closed 29 SV-5065-24A 2
H /02 Analyzer Return OPC X-228K 2
Closed Closed 23 SV-5065-25B 2
26 SV-5065-26A H /02 and PASS Sample Return OPC X-46F 2
Open Closed 2
26 SV-5065-27B H /02 Analyzer Return OPC X-223K 2
Closed Closed 2
26 St 5065-31B H /02 Analyzer Supply OPC X-15E 2
Closed Closed 2
26 SV-5065-23A H /02 Analyzer and DASS Supply OPC X-29E 2
Open Closed 2
26 SV-5065-3SB H /02 Analyzer Supply OPC X-15E 2
Closed Closed 2
26 SV-5065-37A H /02 Analyzer and PASS Supply OPC X-29E 2
Open Closed 2
26 SV-5065-63 PASS Reactor Sample Jet Pump #15 OPC X-40A-a 2
Closed Closed 26 SV-5065-64 PASS Reactor Sample Jet Pump #15 OPC X-40A-a 2
Closed Closed 26 SV-5065-71 PASS Liquid Sample Return OPC X-228H 2
Closed Closed 26 SV-5065-72 PASS Liquid Sampie Return OPC X-228H 2
Closed Closed 26 SV-5065-77 PASS Liquid Sample Return OPC X-228G 2
Closed Closed 26 SV-5065-78 PASS Liquid Sample Return OPC X-228G 2
Closed Closed 26 SV-5065-85 PASS Reactor Sample Jet Pump #5 OPC X-40D-c 2
Closed Closed 26 SV-5065-86 PASS Reactor Sample Jet Pump #5 OPC X-400-c 2
Closed Closed 2
CV-5065-91 Leak Detection and 02 Analyzer Return OPC X-32A 5
Opea Closed 2
CV-5065-92 Leak Detection and 02 Analyzer Return OPC X-32A 5
Open Closed 2
A0-70llA R/H Collection D/H Equip. Sump OPC X-19 20 Closed Closed 2
A0-70llB R/H Collection D/H Equip. Sump OPC X-19 20 Closed Closed 2
A0-7017A R/H Collection D/H Floor Sump OPC X-18 20 Closed Closed 2
A0-70178 R/W Collection D/H Floor Sump OPC X-18 20 Closed Closed 2
MO-1001-21 RHR Discharge to Radwaste OPC None 20 Closed Closed 2
MO-1001-32 RHR Discharge to Radwaste OPC None 20 Closed Closed l
Amendment No. 67, 113 161
TABLE 3.7-1 (con't)
ERIMARY CONTAINHENT AND REACTOR VESSEL IS0'>lT. ION VALVES P0HER MAXIMUM OPERATED PENETRATION OPERATING NORMAL ISOLATION GRQUE VALVE #
SYSTEM & DESCRIPTION IPC/0PC NUMBER IINE (SEC) BQSITION POSITION 32 MO-1001-29A RHR Injectica "A" Locp OPC X-51A 30 Closed Closed 32 MO-1001-298 RHR Injection "B" Loop OPC X-51B 30 Closed Closed 3
HO-1001-47 RHR S/D Coolin9 Suction Valve OPC X-12 30 Closed Closed 3
H0-1001-50 RHR S/D Cooling Suction Valve IPC X-12 30 Closed Closed 3
H0-1001-60 Reactor Vessel Head Spray OPC X--17 30 Closed Closed 3
HO-1001-63 Reactor Vessel Head Spray IPC X-17 30 Closed Closed 4
HO-2301-4 HPCI Steam to Turbine IPC X-52 25 Open Closed 4
H0-2301-5 HPCI Steam to Turbine OPC X-52 25 Open Closed i
5 H0-1301-16 RCIC Steam to Turbine IPC X-53 20 Open Closed 5
MO-1301-17 RCIC Steam to Turbine OPC X-53 20 Open Closed 6
MO-1201-2 RHCU Suction IPC X-14 25 Open Closed 6
MO-1201-5 RHCU Suction OPC X-14 25 Open Closed 6
MO-1201-80 RHCU Return OFC X-9A 30 Open Closed 7
HO-2301-33 HPCI Vacuum Breaker Isolation OPC X-219 30 Open Closed 7
HO-2301-34 HPCI Vacuum Breaker Isolation OPC X-219 30 Open Closed 6-58A Feedwater Line A Check Valve IPC X-9A Open Process'
[
6-588 Feedwater Line B Check Valve IPC X-98 Open Process l
6-62A Feedwater Line A Check Valve OPC X-9A Open Process 6-628 Feedwater Line B Check Valve OPC X-98 Open Process 1
1101-15 SBLC Injaction Check Valve IPC X-42 Closed r.ocess 1101-16 SBLC Injection Check Valve OPC X-42 Closed Process Amendment No. pf, 113 162
@TfS FOR TABLE 3.7-1 T
Key:
IPC - Inside Primary Containment OPC - Outside Primary Containment ISOLATION GROUPINGS Group 1:
The valves in this group are closed upon any one of the following conditions.
1.
Reactor low-low water level 2.
Main Steam Line high :bsiation 3.
Main Steam Line high flow 4.
Main Steam Line tunndl high temperature 5.
Main Steam Line low pressure (in run mode only) 6.
Reactor high water level (not in run mode, below 880 psig)
Group 2:
The valves in this group are closed upon any one of the following conditions.
1.
Reactor low water level 2.
High drywell pressure Group 3:
The valves in this group are closed upon any one of the following conditions.
1.
Reactor lo's water level 2.
High reactor pressure 3.
High drywell pressure Group 4:
The valves in this group are closed upon any one of the following conditions.
1.
HPCI steam line high flow 2.
HPCI steam line area high temperature 3.
Low reactor pressure I
Amendment No.
113 163
.NQTES FOR TABLE 3.7-1 Gpn31 Group S: The valves in this group are closed upon any one of the following conditions.
- 1. RCIC steam line high flow
- 2. RCIC steam line area high temperature
- 3. Low reactor pressure Group 6: The valves in this group are closed upon any one of the following conditions.
- 1. Reactor low water level
- 2. Cleanup area high temperature
- 3. Cleanup inlet high flow Group 7: The valves in this group are closed on the following conditions:
- 1. Reactor Low Pressure and High Drywell Pressure FOOTNOTES:
1 The Reactor Water Sample Line Isolation Valves initiate on a Group 1 or a l
I Group 2 isolation signal.
i 2
MO-1001-29A&B Isolate on reactor low water level QR high drywell pressure if H0-1001-50 and H0-1001-47 are not fully closed AND reactor pressure agt high (i.e., not >l10 psig).
3 In addition to Group 2 isolation, these valves also receive a reactor low-low water level isolation which cannot be bypassed by utilizing the valves emergency open feature.
i 4
Reactor vessel low water level or high drywell pressure causes automatic withdrawal of TIP probe. When probe is withdrawn beyond these ball valves, these valves automatically close within 5 seconds.
j 5
In-addition to Group 2 isolation, these valves also receive a Refueling Floor High Radiation isolation.
6 Isolation signals are overridden with the keylocked Control Switch in the i
"Override" position.
164 Amendment No. 113 4
l
\\.
BASES:
j 3.7.A & 4.7.A Primary Containment l
The integrity of the primary containment and operation of the core standby cooling system in combination limit the off-site doses to values less than l
those suggested in 10 CFR 100 in the event of a break in the primary system piping.
Thus, containment integrity is specified whenever the potential for violation of the primary reactor system integrity exists. Concern about such a violation exists whenever the reactor is critical and above atmospheric pressure. An exception was made to this requirement during initial core loading and while the low power test program was being conducted and ready access to the reactor vessel was required.
There was no pressure on the system at this time, thus greatly reducing the chances of a pipe break.
l Should this type of testing be necessary in the future, the reactor may be taken critical; however, restrictive operating procedures would be in effect again to minimize the probability of an accident.
Procedures and the Rod Worth Minimirer would limit control worth such that a rod drop would not result in any fuel damage.
In a6ditiofi, in the unlikely event that an l
excursion did occur, the secondary containment and standby gas treatment system, which shall be operational during this time, offer 6 sufficient barrier to keep off-site doses well below 10 CFR 100 limits.
l The pressure suppression pool water provices the heat sink for the reactor l
primary system energy release following a postulated rupture of the system.
The pressure suppression chamber water volume must absorb the associated decay and structural sensible heat released during prim 3ry system blowdown from 1035 psig.
Since all of the gases in the drywell are purged into the pressure suppression chamber air space during a loss-of-coolant accident, the pressure
{
rer.lting from isothermal compression plus the vapor pressure of the liquid l
l must not exceed 62 psig, the suppression chamber maximum pressure.
The design i
l volume of the suppression chamber'(water and air) was obtained by considering
{
that the total volume of reactor coolant to be condensed is discharged to the i
suppression chamber and that the drywell volume is purged to the suppression chamber.
Using the minimum or maximum water volumes given in the specification, containment pressure during the desigr. basis accident is approximately 45 psig which is below the maximum of 62 psig.
Maximum water volume of 94,000 ft' results in a downcomer submergency of 4'-0" and the minimum volume of 84,000 ft' results in a submergence approximately 12-inches less.
Mark I Containment Long Term Program Quarter Scale Test Facility (QSTF) testing at a downcomer submergency of 3.25 feet and 1.17 psi wetwell to dryvell pressure differential shows a significant suppression chamber load reduction and long Term Program analysis and modifications are based on the above submergence and differential pressure.
l Should it be necessary to drain the suppression chamber, provision will be made to maintain those requirements as described in Section 3.5.F BASES of this Technical Specification.
Amendment No. A2, 113 165
BASES:
3.7.A & 4.7.A Primary Containment Experimental data indicates that excessive steam condensing loaqs can be avoided if the peak local temperature of the pressure suppression pool is maintained below 200*F during any period of relief-valve operation with sonic conditions at the discharge exit. Analysis has been performed to verify th6t the local pool temperature will stay below 200'F and the bulk temperature will stay below 160'F for all SRV transients.
Specifications have been piaced on the envelope of reactor operating conditions so that the reactor can be depressurized in a timely manner to avoid the regime of potentially high pressure suppression chamber loadings.
'In addition to the limits on temperature of the suppression chatnber pool water, operating procedures define the action to be taken in the event a relier valve inadvertently opens or sticks open.
This action would include:
(1) use of all available means to close the valve, (2) initiate suppression pool water cooling heat exchangers, (3) initiate reactor shutdown, anc (4) if other relief valves are used to aepressurize the reactor, their discharge shall be separated from that of the stuck-open relief valve to assure mixing and uniformity of energy insertion to the pool.
Because of the large volume and thermal capacity of the suppression pool, the volume and temperature normally changes very slowly and monitoring these parameters daily is sufficient to establish any temperature trends.
By reauiring toe suppression pool temperature to be continually monitored and frequently logged during periods of significant heat addition, the temperature trends will be closely followed so that appropriate action can be taken. The requirement for an external visual examination following any event where potentially high loadings could occur provides assurance that no significant damage was encountered.
Particul'ar attention should be focused on structural discontinuities in the vicinity of the relief valve discharge since these are expected to be the points of highest stress.
If a loss-of-coolant accident were to occur when the reactor water temperature is below approximately 330*F, the containment pressure will not exceed the The 62psig code permissible pressure, even if no condensation were to occur.
maximum allowable pool temperature, whenever the reactor is above 212*F shall be governed by this specification. Thus, specifying water volume-temperature requirements applicable for reactor-water temperature above 212*F provides additional margin above that available at 330'F.
l 166 Amendment No. 83, 113
l BASES:
l 3.7.A & 4.7 J Primary Containment Prinary Containment Testing The p,imary containment pre-operational test pressures are based upon the calculated primary containment pressure response in the event of a loss-of-coolant accident.
The calculated peak drywell pressure is about 45 M ig which would. rapidly reduce to 27 psig following the pipe break.
Following tN pipe break, the suppression chamber pressure rises to 27 psig, equalizes with drywell pressure and therefore rapidly decays with the drywell pressure decay.
The design pressure of the drywell and suppression chamber is 56 psig. The design leak rata is 0.51/ day at a pressure of 56 'osig.
Based on the calculated containment pre ssure response discussed above, the primary containment pre-operational test pressures were chosen.
Also, based on the primary containment pressure response and the fact that the drywell and suppression chamber function as a unit, the primary containment will be tested as a unit rather than the individual components separately.
The design basis loss-of-coolant acc Mant was evaluated at the primary containment maximum allowable accident leak rate of 1.25%/ day at 45 psig.
Calculations made by the AEC staff with this leak rate and a standby gas treatment system filter efficiency of 95% for halogens and assuming the fission product release fractions stated in TIO 14844, show that the maximum total whole body passing cloud dose is about
'.3 REM and the maximum total thyroid dose is about 110 REM at the site boundary over an exposure duration of two hours. The resultant doses that would occur for the duration of the accident at the low population zone distance of 4.3 miles are about 3 REM total whole body and 70 REM total thyroid.
Thus, the doses reported are the maximum that would be expected in the unlikely event of a design basis loss-of-coolant accident.
These doses are also based on the ass'umption of no holdup in the secondary containmene resulting in a direct release of fission products from the primary containment through the filters and stack to the environs.
Therefore, the specified primary containment leak rate and filter efficiency are conservative and provide margin between expected off-site dose and 10 CFR 100 guidelines.
The maximum allowable test leak rate is 1.0%/ day at a pressure of 45 psig.
This value for the test condition was derived from the maximum allowable accident leak rate of 1.25%/ day when corrected for the effects of containment environment under accident and test conditions.
In the accident case, the containment atmosphere initially would be composed of steam and hot air whereas under test conditions the test medium would be air at ambient conditions. Considering the differences in mixture composition and temperatures, the appropriate correction factor applied was 0.8 as determined from the guide on containment testing.
Establishing the test limit of 1.0%/ day provides an adequate margin of safety to assure the health and safety of the general public.
It it further. considered that the allowable leak rate should not deviate significantly from the containment design value to take advantage of the design leak-tightness 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 operational leak rate.
The allowable operational leak rate is derived by multiplying the max "um allowable leak rate or the allowabie test leak rate by 0.75 thereby providing a 25% margin to allow for leakage deterioration which may occur during the period between leak rate tests.
Amendment No.
E7,113 167
BASES:
3.7.A & 4.7.A Primary Containment The primary containment leak rate test frequency is based on maintaining' aceauate assurance that the lean rate remains within the specification.
The leak rate test frequency is in accordance with 10 CFR 50 App. J as amended through Sept. 22, 1980.
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 1
performing properly.
It is expected that the majority of the leak;ge from valves, penetrations and seals would be into the reactor building.
- However, it is possible that leakage into other parts of the facility could occur.
Such leakage paths that may affect significantly the consequences of accidents are to be minimized.
The personnel air lock is tested at 10 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 potential leakage paths from the containment in the event of a loss of coolant accident.
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, high radiation,, low pressure, 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 crywell pressure.
The group 2 isolation signal also "isolates" the reactor building and starts the standby gas treatment system.
It is not 4
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.
Group 4 and 5 - process lines are designed to remain operable and mitigate the consequences of an accident which results in the isolation of other process lines.
The signals which initiate isolation of group 4 and 5 process lines are therefore indicative of a condition which would render them inoperable.
Amendment No.
113 168
SASES:
l 3. 7. A !, 4. 7. A Primarv Containmeq Grouc 6 - process lines are normally in use and it is therefore not desirable tc cause spurious isolation cue to high drywell pressure resulting free ncn-safety related causes.
To protect the reactor from r possibli pipe break in the system, isolation is proviced by high temperature in the cleanup system area or hign flow througn the inlet to the cleanup system.
Also, since the vessel could potentially be crained through th; cleanup syste,m, a low level isolation is provided.
I Group 7 - The HPCI vacuum breaker line is designed to remain operable when the HFCI sy: tem is required.
The signals which initiate isolation of the HPCI vacuum breaker line are indicative of a break insice containment and reactor pressure below that at which HPCI can operate.
The maximum closure time for the automatic isolation valves of the primary containment anc reactor vessel isolation control system have been selectec in consiceration of the cesign intent to prevent core uncovering following pipe breaks outsice the primary centainment and the need to contain releasec fission products following pipe breaks inside the primary containment.
In satisfying this design intent an additional margin has t;een included in specifying maximum closure times.
This margin permits identification of degraced valve cerformance, prior to exceeding the design closure times.
In order to assure that the doses that may result from a steam line break oo not exceec the 10CFR100 guidelines, it is necessary that no fuel rod perforation resulting from the accident occur prior to closure of the main steam line isolation valves.
Analyses indicate that fuel rod cladding perforations would be avoided for main steam valve closure times, including instrument celay, as long as 10.5 seconds.
These valves are highly reliable, have low service requirements and most are normally closect.
The initiating sensors and associated trip chann," are also checked to demonstrate the capability for automatic isolation. The t.
failureprobabilityof1.1x10ycleforautomaticinitiationresult-interval of once per operating c that a line will not isolate. No ;
,Jent testing for valve operability results in a greater assurance that the valve will be operable when needed.
The main steam line isolation valves are functionally tested on a more frequent interval to establish a high degree of reliability.
The primary containment is penetrated by several small diameter instrument lines connected to the reactor coolant system.
Each instrument line contaics a 0.25 inch restricting orifice inside the primary containment. A program for periodic testing and examination of the excess flow check valves is in place.
Primary Containment Paintino i
The interiors of the drywell and suppression chamber are painted to prevent rusting.
The inspection of the paint during each major refueling outage, approximately every 18 months, assures the paint is intact.
Experiente with l
this type of paint at fossil fueled generating stations indicates that the inspection interval is adequate.
Amendment No. 113 169 i
l BASES:
3.7.4. E, l.
7.A Primary Cortairrenc Vacuur Relief The purpose of the vacuum relief valves is to ecuailze the pressure bet een the cryaell anc su;pression chamcer and reactor building so that the structural integrity of the containment is maintained.
The vacuum relief system from the pressure suppression chamber to reactor building consists of two 1000, vacuum relief bred (ers (2 parallel sets of 2 valves in series).
Operation of either system will maintain the pressure differential less than 2 psig; the externai design pressure. One valve rnay be out of service for repairs for a perio:' of seven days.
If repairs cannot be completed within seven days, the reactor coolant system is brought to a condition where vacuum relief is no longer eauirec.
The cacacity o' the 10 drywell vacuum relief valves is sized to limit the pressure cifferential cetween the suppression cham:er and crywell during post-accident crywell cooling to the design limit of 2 osig.
Tney are sizec on tha basis of the Bocega Bay pressure suppression system tests.
Tne AS'iE Boilet acc Pressure Vessel Coce. Sectior. III, Subsection B, for this vessel allo s a 5 psig vacuum; therefore, with two vacuum relief valves secJred in the closed cosition and eight operable valves, containment integrity is not impaired.
Reactor operation is permissible Pe bypass 3rea between the primary containment drywell an0 suppression chamber does not exceed an allowable area.
The allowable byDass area is based upon analysis considering primary system break area, suppressicn chamber effectiveness, and containment design pressure. Analyses show that the maximum allowable bypass area is 0.2 ft',
which is ecuivalent to all vacuum breakers open 3/32'.
(See letters from Boston Edison to the Directorate of Licensing, dated May 15, 1973 and October 22, 1974)
Reactor opercticn is not permitted if differential pressure decay rate is demonstrated to exceed 25'r. of allowable, thus providing a margin of safety for the primary containment in the event of a small break in the primary system.
Each drywell suppression chamber vacuum breaker is equipped with three switches. One switch provides full open indication only. Another switch provides closed indication and an alarm on Panel C-7 should any vacuum breaker come off its closed seat by greater than 3/32".
The third switch provides a separate and redundant alarm on Panel 905 should any vacuum breaker come off its closed seat by greater than 3/32". The two alarms above are those referred to in Section 3.7.A.4.a(3) and 3.7.A.4.d.
The water in the suppression chamber is used only for cooling in the event of an accident; i.e., it is not used for normal operation; therefore, a daily check of the temperature and volume is adequate to assure that adequate heat removal capability is present.
Amendment No. 113 170 t
l
BASES:
3.7.A 2, 4 7.A Primary Containment Ine ting The relatively sma'l containment volume inherent in the GE-BWR pressure suppression containment and the large amount of zirconium in the core are such that the occurrence of a very limited (a percent or so) reaction of the zirconium and steam during a loss-of-coolant accident could lead to the liberation'of hydrogen combined with an air atmosphere to result in a flammable concentration in the containment.
If a sufficient amount of hydrogen is generated and oxygen is available in stoichiometric quantities, the subsequent ignition of the hydrogen in rapid recombination rate could lead to failure of the containment to maintain a low leakage integrity.
The 4%
oxygen concentration minimizes the possibility of hydr:Aan combustion following a loss-of-coolant The occurrence of primary system leakage following a major refueling outage or other scheduled shutcown is much more probable than the occurrence of the loss-of-coolant accident upon which the specified oxygen concentration limit is based.
Permitting access to the drywell for leak inspections during a startup is judged prudent in terms of the added plant safety offered without significantly reducing the margin of safety.
Thus, to preclude the possibility of starting the reactor and operating for extendec periods of time with significant leaks ir, the primary system, leak inspections are scheduled during startup periods, when the primary system is at or near rated operating temperature and pressure.
The 24-hour period to provide inerting is judged to be sufficient to perform the leak inspection and establish the required oxygen concentration.
The primary containment is normally slightly pressurinc during periods of reactor operation.
Nitrogen used for inerting could leak out of the containment but air could not lesk in to increase oxygen concentration. Once ths containment is filled with nitrogen to the required concentration, no monitoring of oxygen concentration is necessary.
However, at least twice a week the oxygen concentration will be determined as added assurance. Mark I Containment Long Tem Program testing showed that maintaining a drywell to wetwell pressure differential to keep the supprestion chamber downcomer legs clear of water significantly reduced suppression chamber post LOCA hydrodynamic loads. A pressure of 1.17 psid is required to sufficiently clear the water less of the downcomers without bubbling r.itrogen into the suppression chamber at the 3.00 ft downcomer submergence which corresponds to approximately 84,000 ft.' of water. Maximum downcomer submergence is 3.25 ft.
at operating suppression chamber water level.
The above pressure differential and submergence number are used in the Pilgrim I Plant Unique Analysis.
Amendment No 45,113 171
SASES:
3.7.A & 4.7.A primary Containment (Cont'd)
Post LOCA Atmoschere Dilution In order to ensure that the containment atmosphere remains inerted, i.e. the cnygen-hydrogen mixture belon the flammable limit, the capability to inject nitrogen into the containment after a LOCA is provided.
A minimum of 1500 gallons of, liquid N: in the storage tank assures that a three-day supply of N for post-LOCA containment inerting is available. Since the inerting makeup system is continually functioning, no periodic testing of the system is required.
The Post-LOCA Containment Atmospheric Dilution (CAD) System is designed to meet the requirements of AEC Regulatory Guides 1.3,1.7 and 1.29, ASME Section III, Class 2 (except for code stamping) and seismic Class I as defined in the PNPS FSAR.
In summary, the limiting criteria are:
- 1. Maintain hydrogen concentration in the containment during post-LOCA conditions to less than 41.
- 2. Limit the buildup in the containment pressure due to nitrogen addition to less than 28 psig.
- 3. To limit the offsite dose due to containment venting (for pressure control) to less than 300 Rem to the thyroid.
By maintaining at least a 3-day supply of N on site there will be sufficient time after the occurrence of a LOCA for obtaining additional nitrogen supply from local commercial sources
)
The system design contains sufficient redundancy to ensure its reliability.
Thus, it is sufficient to test the operability of the whole system once per operating cycle. The H analyzers will provide redundancy for the drywell 1.e., there are two He analyzers for the Unit.
By permitting reac^or operation for 7 days with one of the two H analyzers inoperable, redurdancy of analyzing capability will be maintained while not imposing an imediate interruption in plant operation. Monthly testing of the analyzers using H will be adequate to ensure the system's readiness because of the design.
Since the analyzers are normally not in operation there will be little deterioration due to use.
In order to de,termine H concentration, the analyzers must be warmed up 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> prior to putting into service.
This time frame is acceptable for accident conditions because a 4% H level will not be reached in the drywell until 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> following the accident. Due to nitrogen addition, the pressure in the containment after a LOCA will increase with time.
Under the worst expected conditions the containment pressure will reach 28 psig in approximately 45 days.
If and when that pressure is reached, venting from the containment shall be manually initiated per the requirements of 10CFR50.44.
The venting path will be through the Standby Gas Treatment system in order to minimize the off site dose.
(1) As listed in Pilgrim Nuclear Power Station Procedure No. 5.4.6 "Post Accident Venting" l
Amendment No. JE,113 171a (the next 09. is 172)
5:5ES:
j l
3.7.C - Seconcary Containment The secondary containment is designed to minimize any ground level release of radioactive materials which might result from a serious accident.
The reactor building provides secondary containment during reactor operation when the drywell is sealed and in service; the reactor building provides primary containment when the reactor is snutdown and the drywell is. open, as during refueling. Because the secondary containment is an integral part of the complete containment system, secondary containment is required at all times that primary containment is required as well as during refueling.
Initiating reactor building isolation and operation of the standby gas treatment system to maintain at least a 1/4 inch of water nega'tive pressure within the secondary containment provides an adequate test of the operation of the reactor building isolation valves, leak tightness of the reactor building and performance of the standby gas treatment system.
Functionally testing the initiating sensors and associated trip channels demonstrates the capability for automatic actuation.
Performing these tests prior to refueling will demonstrate secondary containment capability prior to the time the primary containment is opened for refueling.
Periodic testing gives sufficient confidence of reactor Duilding integrity and standby gas treatment system performance capability.
i Amendment No./l4,113 175 (next pg. is 177) l 1
TABLE 6.9.1 l
Arm Reference Submi ttal-Date a.
Secondary Containment 4.7.C.1.c Upon completion of I
Leak Rate Testing (1) each test (2) b.
(Deleted) c.
(Deleted) d.
Gross Gaseous Release 4.8.8 Ten days after the 0.05 Ci/sec for 48 release occurs Hours e.
Standby Liquid Control 3.4.C.3 Fourteen days after solution enrichment out receipt of a non-of specification complying enrichment report or lack of receipt of such a report within the required thirty days, if enrichment compliance cannot be achieved within seven days.
NOTES:
1.
Each integrated leak rate test of the secondary containment shall be the subject of a summary technical report. This report shall include data on the wind speed, wind direction, outside and inside temperatures during the test, concurrent reactor building pressure, and emergency ventilation flow rate.
The report shall also include analyses and interpretations of those data which demonstrate compliance with the specified leak rate limits.
2.
The report shall be submitted approximately 90 days after I
completion of each test.
Test periods shall be based on the commercial service date as the starting point.
Amendment No. W, 113 225