ML17250A767
| ML17250A767 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 11/05/1980 |
| From: | ROCHESTER GAS & ELECTRIC CORP. |
| To: | |
| Shared Package | |
| ML17250A764 | List: |
| References | |
| RTR-NUREG-0578, RTR-NUREG-578 NUDOCS 8011170205 | |
| Download: ML17250A767 (77) | |
Text
A endiz A 1.
-Add paragraphs 2.C(7) and 2.C(8) to Provisional Opera-tion License No. DPR-18.
2.
3.
Remove Technical Specification pages ii, 2.3-4, 2.3-7, 3.1-2 through 3.1-4, 3.4-1 through 3.4-4, 3.5-1, 3.5-2, 3.5-6, 3.6-1, 3.6-2, 4.1-1, 4.1-7, 4.3-1, 4.3-2, 4.4-5a, 4.4-5b, 4.4-5c, 4.4-8, 4.4-14, 4.8-2, 4.8-3, 6.2-3.,
6.3-1 Insert Technical Specification pages ii, 2.3-4, 2.3-7, 3.1-2 through 3.1-4, 3.1-4a, 3.4-1 through 3.4-3, 3.5-1, 3.5-2, 3.5-6 through 3.5-14, 3.6-1 through 3.6-10, 4.1-1, 4.1-7, 4.1-11, 4.3-1, 4.3-2, 4.4-5a, 4.4-5b, 4.4-5c, 4.4-8, 4.4-14, 4.8-2, 4.8-3, 6.2-3, 6.3-1.
gglllV0$0
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2.C(7)
S stems Inte rit.
The licensee shall implement a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to as low as practical levels.
This program shall include the following:
1.
Provisions establishing preventive maintenance and periodic visual inspection, requirements, and 2.
Leak test requirements for each system at a frequency not to exceed refueling cycle intervals.
I 2.C(8)
Iodine Nonitorin The-licensee shall implement a program which will ensure the capability to accurately determine the airborne iodine concentration in vital areas under accident conditions.
This program shall include the following:
2.
3.
Training of personnel, Procedures for monitoring, and Provisions for maintenance of sampling and analysis equipment.
)
)
V a'
TABLE OF CONTENTS (cont.)
4.0 SURVEILLANCE REQUIREMENTS 4.1 Operational Safety Review 4.2 Inservice Inspection 4.3 Reactor Coolant System 4.4 Containment Tests 4.5 S'afety Injection, Containment Spray and Iodine Removal Systems Tests 4.6 Emergency Power System Periodic'Tests 4.7 Main Steam Stop Valves 4.8 Auxiliary Feedwater System 4.9 Reactivity Anomalies 4.10 Environmental Radiation Survey 4.11 Spent Fuel Pit Charcoal Adsorber Testing 4.12 Effluent Surveillance 4.13 Radioactive Material Source Leakage Test 4.14 Shock Suppressors (Snubbers) 4.15 Fire Suppression System Test.
4.16 Overpressure Protection System DESIGN FEATURES 5.1 Site 5.2 Containment Design Features 5.3 Reactor Design Features 5.4 Fuel Storage Pacae 4.1-1
.4. 1-1 4.2-1 4.3-1 4.4-1 4.5-1 4.6-1 4.7-1 4.8-1 4.9-1 4.10-1 4.11-1 4.12-1 4.13-1 4.14-1 4.15-1 4.16-1 5.1-1 5.2-1 5.3-1 5.4-1
'Proposed
f
2.3.1.3 f.
Low reactor coolant. flow -
90% of normal indicated flow.
F g.
Low reactor coolant pump frequency -
> 57.5 Hz.
Other reactor tri s 2.3.2 a.
High pressurizer water level -
92% of span b.
Low-low steam generator water level -
16% of narrow range instrument span Protective instrumentation settings for reactor trip interlocks shall be as follows:
2.3.2.1 2.3.2.2 Basis:
Remove bypass of "at power" reactor trips at high power (low pressurizer pressure and low reactor coolant flow) for both loops:
Power range nuclear flux < 8.5% of rated power (1)
(Note:
During cold rod drop tests, the pressurizer high level trip may be bypassed.)
Remove bypass of single loss of flow'rip at high power:
Power range nuclear flux <
50% of rated power The high flux reactor trip (low set point) provides redundant protection in the power range for a power excursion beginning from low power.
This trip value was used in the safety analysis.
2.3-4 Proposed
0 J
The high pressurizer water level reactor trip protects the
"-"pressurizer safety valves against, water relief.
Approximately 700 ft.
of water corresponds to 92% of span.
The specified set point contains margin for both instrument, error and transient overshoot of level beyond this trip setting, and therefore the trip fupg$ion prevents the water level from reaching the safety valves.
The low-low steam generator water level reactor trip protects against loss of feedwater flow accidents.
A set point of 5% is equivalent to at least 40,000 lbs. of water and assures that there will be sufficient water inventory in the steam generators at, the time of trig to allow for starting delays for the auxiliary feedwater system.
An additional 11% has been added to the set point to account for error which may be introduced into the steam generator level system at a containment temperature of 286'F as determined by an evaluation performed for temperature effects on level measurements required by IE Bulletin 79-21.
The specified reactor trips are blocked at low power where they are not required for protection and would otherwise interfere with normal plant operations.
The prescribed set point above which these trips are unblocked assures their availability in the power range where needed.
Operation with one pump will not be permitted above 130 MWT (8.5%).
An orderly power reduction to less than 130 MWT (8.5%) will be accomplished if a pump is lost while operating between 130 MWT (8.5%)
and 50%.
Automatic protection is provided so that a power-to-flow ratio is maintained equal to or less than one, which insures that 2
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Proposed
d.
e.
At least one reactor coolant pump shall be in operation for a planned transition from one Reactor Operating Node to another involving an increase in the boron concentration of the reactor coolant, except for emergency boration.
A reactor coolant pump shall not be started with one or more of the RCS cold leg temperatures 330'F unless
- 1) the pressurizer water volume is less than 324 cubic feet (38% level) or 2) the secondary water temperature of each steam generator is less than 50'F above each of the RCS cold leg temperatures.
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b.
One steam generator shall be capable of performing its heat transfer function whenever the average coolant temperature is above 350'F.
The temperature difference across the tube sheet shall not exceed 100'F.
Safet Valves a
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b.
c ~
d.
During cold shutdown or refueling when the reactor head is bolted on the vessel, at, least one pressurizer code safety valve shall be operable with a lift setting of 2485 psig i 1%.
If the conditions of 3.1.1.3.a are not met, immediately suspend all operations involving positive reactivity changes and place an operable RHR loop into operation in the shutdown cooling mode.
Whenever the reactor is at hot shutdown or critical, both pressurizer code safety valves shall be operable with a liftsetting of 2485 psig k 1%.
If one pressurizer code safety valve is not operable while the -reactor is at hot shutdown or critical, then either restore the inoperable valve to operable status within 15 minutes or be in at, least hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and below a Tavg of 350'F within an additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.,
Relief Valves a
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Both pressurizer power operated relief valves (PORVs) and their associated block valves shall be operable whenever the reactor is at hot, shutdown or critical.
3
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Proposed
b.
With one or more PORV(s) inoperable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either restore the PORV(s) to operable status or close the associated block valve(s); otherwise, be in at least hot. shutdown within.the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
c ~
With one or more block valve(s) inoperable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either restore the block valve(s) to operable status or close the block valve(s) and remove power from the block valve(s); otherwise, be in at least hot shutdown within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
3.1.1.5 Pressurizer Whenever the reactor is at hot shutdown or critical the pressurizer shall have at least 100 kw of heaters operable and a water level maintained between 12% and 87% of level span.
If the pressurizer is inoperable due to heaters or water level, restore the pressurizer to operable status within 6 hrs. or have the RHR system in operation within an additional 6 hrs.
Bases:
When the boron concentration of the reactor coolant system is to be reduced the process must be uniform to prevent sudden reactivity changes in the reactor.
Mixing of the reactor coolant will be sufficient to prevent a sudden increase in reactivity if at least one reactor coolant pump or one residual heat removal pump is running while the change is taking place.
The residual heat removal pump will circulate the primary system volume in approxi-mately one half hour.
,The pressurizer is of no concern because of the low pressurizer volume and because the pressurizer boron concentration will be higher than that. of. the rest of the reactor coolant.
When the boron concentration of the reactor coolant system is to be increased, the process must be uniform to prevent sudden reactivity increases in the reactor during subsequent startup of the reactor coolant pumps.
Mixing of the reactor coolant will be sufficient to maintain a uniform boron concentration if at least one reactor coolant pump is running while the change is taking place.
Emergency boration without a reactor coolant pump in operation is not prohibited by this specification.
3
~ 1 3 Proposed
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The specification requires that a sufficient number of reactor
"--coolant pumps be operating to provide core cooling.
The flow provided in each case will keep DNB well above 1.30 as discussed in FSAR Section 14.1.6.
Therefore, cladding damage and release of fission producers to the reactor coolant, will not occur.
Heat transfer analyses' show that. reactor heat equivalent to 130 NWT (8.5%) can be removed with natural circulation only; hence, the specified upper limit, of 1% rated power without operating pumps provides a substantial safety factor.
Each of the pressurizer code safety valves is designed to relieve 288,000 lbs. per hr. of saturated steam at the valve set point.
Below 350'F and 350 psig in the reactor coolant system, the residual heat removal system cari remove decay heat and thereby control system temperature and pressure.
If no residual heat were removed by any of the means available the amount of steam which could be generated at safety valve relief pressure would be less, than half the valves'apacity.
One valve therefore provides adequate defense against overpressurization.
Prohibiting reactor coolant pump starts without a large void in the pressurizer or without a limited RCS temperature differential will prevent RCS overpressurization due to expansion of cooler RCS water as it enters a warmer steam generator.
A 38% level in the pressurizer will accommodate the swell resulting from a reactor coolant pump start with a RCS temperature of 140'F and steam generator secondary side temperature of 340'F, or the maximum temperature which usually exists prior to cooling the reactor with the RHR system.
The specification permits an orderly reduction in power if a reactor coolant pump~j~ lost during operation between 130 NWT and 50% of rated power.
Above 50% power, an automatic reactor trip will occur if either pump is lost.
The power-to-flow ratio will be maintained equal to or less than one which ensures that the minimum DNB ratio increases at lower flow since the maximum enthalpy rise does not increase.
Temperature requirements for the steam generator correspond with measured NDT for the shell and allowable thermal stresses in the tube sheet.
The power operated relief valves (PORVs) operate to relieve RCS pressure below the setting of the pressurizer code safety valves.
These relief valves have remotely operated block valves to pro-vide a positive shutoff capability should a relief valve become inoperable.
The electrical power for both the relief valves and the block valves is capable of being supplied from an emergency power source to ensure the ability to seal this possible RCS leakage path.
Proposed
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The requirement that 100'w of pressurizer heaters and their
'-"associated controls be capable of being supplied electrical power from an emergency bus provides assurance that these heaters can be energized during a loss of offsite power condition to(quintain natural circulation at hot shutdown and during cooldown.
References (1)
FSAR Section 14.1.6 (2)
FSAR Section 7.2.3 (3)
Letter from L. D. White, Jr. to D. L. Ziemann, USNRC, dated October 17, 1979 3.1-4a proposed
l J
gl
Turbine C cle
~lb 1 Applies to the operating status of turbine cycle.
~b'o define conditions of the turbine cycle steam-relieving capacity.
Auxiliary Feedwater System and Service Water System operation is necessary to ensure the capability to remove decay heat, from the core.
The Standby Auxiliary Feedwater System provides additional assurance of capa-bility to remove decay heat from the core should the Auxiliary Feedwater System be unavailable.
f'henthe reactor coolant temperature is above 350'F, the following conditions shall be met:
a ~
b.
A minimum turbine cycle code approved. steam-relieving capability of eight (8 ) main steam valves available (except for testing of the main steam safety valves).
Three auxiliary feedwater pumps and their associated flow paths (including backup supply from the Service Water System) must be operable.
c.
A minimum of 22,500 gallons of water shall be available in the condensate storage tanks for the Auxiliary Feedwater System.
d.
Two Standby Auxiliary Feedwater pumps and associated flow path (including flow path from the Service Water System) must be operable.
Actions To Be Taken If Conditions of 3.4.1 Are Not Met a
~
b.
With one or more main steam code safety valves in-
- operable, restore the inoperable valve(s) to operable status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at. least hot shutdown within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
With one auxiliary feedwater pump inoperable, restore the pump to operable status within 7 days.
If the pump is not restored to operable status within 7 days submit a Thirty Day Written Report in accordance with Specification 6.9.2 outlining the cause of the inoperability and plans for restoring the pump to operable status.
3.4-1 Proposed
IX 0
C.
d.
e.
With two auxiliary feedwater pumps inoperable, restore two pumps to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (and in cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />).
With one standby auxiliary feed pump inoperable, restore two pumps to operable status within 7 days or be in hot shutdown within the next, 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
With the required 22,500 gallons of water unavail-able in the condensate storage tanks, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, either:
2.
Restore the required amount of water or be in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, or Demonstrate the operability of the Service Water System as a backup supply to the auxiliary feed system and restore the required amount of water in the condensate storage tanks within 7 days or be in hot shutdown within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Basis:
A rea 1
ctor shutdown from power requires removal of core decay heat.
Immediate decay heat removal requirements are normally satisfied by the steam bypass to the condenser.
Therefore, core decay heat can be continuously dissipated via the steam bypass to the condenser as feedwater in the steam generator is converted to steam by heat, absorption.
Normally, the capability to return feedwater flow to the steam generators is provided by operation of the turbine cycle feedwater system.
The eight main steam safety valves have a total combined rated capability of 6,580,000 lbs/hr.
This capability exceeds the total full power steam flow of 6,577,279 lbs/hr.
In the event of complete loss of off-site electrical power to the station, decay heat removal is assured by either the steam-driven auxiliary feedwater pump or one of the two motor-driven auxiliary feedwater
- pumps, and steam discha'rge to the atmospherygjy~the main steam safety valves or atmospheric relief valves.
The turbine driven pump can supply 200% of the required feedwater and one motor-driven auxiliary feedwater pump can supply 100% of the required feedwater for removal of decay heat from the plant, so any combination of two pumps can remove decay heat, with a postulated single failure of one pump.
The minimum amount of water in the condensate storage tanks is the amount needed to remoyg~decay heat for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after reactor scram from full power.
An unlimited supply is available from the lake via either leg of the plant service water system for an indefinite time period.
3.4-2 Proposed
t f.
The Standby Auxiliary Feedwater System is,provided to give addi-
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-"-tional assurance of the capability to remove decay heat from the reactor.
The system would be used only if none of the auxiliary feedwater.pumps were available to perform their intended function.
Since operability requirements are established for the auxiliary feedwater
- system, the Standby System would be required only if some unlikely event, should disable,all auxiliary feedwater pumps.
The specified time to restore the Standby System to full capability is longer than for other components since the probabj)sty of being required to use the Standby System is extremely low.
References:
(2)
(3)
(4)
FSAR Section 10.4 FSAR Section 14.1.9 "Effects of High Energy Pipe Breaks Outside the Contain-ment, Building" submitted by letter dated November 1, 1973 from K.
W. Amish, Rochester Gas and Electric Corporation to A. Giambusso, Deputy Director for Reactor Projects.
U.S. Atomic Energy Commission L. D. White, Jr. letter to Nr. D. L. Ziemann, USNRC dated Narch 28, 1980 3.4-3 Proposed
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Instrumentation S stems b'1'pplies to plant instrumentation systems.
~b'o delineate the conditions of the plant instrumentation and safety circuits.
3.5.1 3.5.1.1
.3.5.1.2 3.5.2 3.5.2.1 Operational Safety Instrumentation The number of Minimum Operable Channels for instrumentation shown on Tables 3.5-1 through 3.5-3 shall be OPERABLE for plant operation at rated power.
In the event, the number of channels of a particular sub-system in service falls below the limit, given in the columns entitled Minimum Operable
- Channels, operation shall be limited according to the requirement shown in the last column of Tables 3.5-1 through 3.5-3.
Accident Monitoring Instrumentation The accident monitoring instrumentation channels shown in Table 3.5-4 shall be operable whenever the reactor is at hot shutdown or is critical.
3.5.2.2 While critical, with the number of operable accident monitoring instrumentation channels less than the Total Number of Channels shown in Table 3.5-4, either restore the inoperable channel(s) to operable status within 7
- days, or be in at, least. hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
3.5.2.3 While critical, with the number of operable accident monitoring instrumentation channels less than the MINIMUM CHANNELS OPERABLE requirements of Table 3.5-4, either restore the inoperable channel(s) to operable status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
3.5.3 3.5.3.1 Engineered Safety Feature Actuation Instrumentation The Engineered Safety Feature Actuation System (ESFAS) instrumentation channels shown in Tables 3.5-2 and 3.5-3 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.5-5.
3.5-1 Proposed
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3.5.3.2 I ~
With an instrumentation channel trip setpoint less con-servative than the value shown in the Allowable Values column of Table 3.5-5, declare the channel inoperable
.and apply the applicable ACTION requirement of Tables 3.5-2 and 3.5-3 until the channel is restored to OPERABLE status with the trip setpoint adjusted consistent with the Trip Setpoint Value.
3.5.3.3 With an instrumentation channel inoperable, take the action shown in Tables 3.5-2 and 3.5-3.
Basis:
During plant operations, the complete instrumentation systems will normally be in servi'ce.
Reactor safety is provided by the Reactor Protection
- System, which automatically initiates appropriate action
'o prevent exceeding established limits.
Safety is not compromised,
- however, by continuing operation with certain instrumentation channels out of service since provisions were made for this in the plant design.
This specification outlines limiting conditions for operation necessary to preserve the effectiveness of the reactor control and protection system when any one or more of the channels is out of service.
Almost.all reactor protection channels are supplied with sufficient redundancy to provide the capability for channel calibration and test at power.
Exceptions are backup channels such as reactor, coolant pump breakers.
The removal of one trip channel is accomplished by placing that channel bistable in a tripped mode; e.g.,
a two-out-of-three circuit becomes a one-out-of-two circuit.
Testing does not trip the system unle'ss a trip condition exists in a concurrent channel.'he operability of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess these variables during and following an accident.
This capability is consistent with the recommendations of NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report, and Short-Term Recommendation".
/
Reference:
FSAR Section 7.2.1.
3.5-2 Proposed
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TABLE 3.5-2 (Continued)
EMERGENCY COOLING FUNCTIONAL UNIT 3.
Auxiliary Feedwater Motor and Turbine Driven a.
Manual b.
Stm.
Gen. Water Level-low-low NO.
OF NO.
OF CHANNELS CHANNELS TO TRIP'"""
1/pump 1/pump MIN.
OPERABLE CHANNELS 1/pump MIN.
DEGREE OF REDUNDANCY 5
, 6 OPERATOR ACTION PERMISSIBLE 'F CONDITIONS OF BYPASS COLUMN 3 CONDITIONS CANNOT BE MET
- i. Start Motor Driven Pumps ii. Start Turbine Driven Pump
- c. I,oss of 4 KV Voltage Start Turbine Driven Pump
- d. Safety Injection Start Motor Driven Pumps
- e. Trip of both Feed-water Pumps starts Motor Driven Pumps t
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nnnnn Standb Motor Driven a.
Manual 3/stm.
gen; 3/stm.
gen.
2/bus 2/pump 1/pump 2/stm.,gen.
either gen.
2/stm.
gen; both gen.
1/bus both buses (see Item 1) 1/pump both pumps 1/pump 2/stm.
gen.
2/stm.
gen.
1/bus 1/pump 1/pump
I
TABLE 3.5-2 Continued TABLE NOTATION ACTION STATEMENTS If a functional unit is operating with the minimum operable channels the number of channels to trip the reactor will be column 3 less column 4.
I This start signal is required only during power operation above 5%.
ACTION 1 With the number of operable Channels one less than the Total Number of Channels, restore the inoperable channel to operable status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least hot shutdown within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
ACTION 2 With the number of operable channels one less than the Tot'al Number of Channels, operation may proceed until performance of the next required CHANNEL FUNCTIONAL TEST provided the inoperable channel is placed in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
3.5-7 Proposed
TABLE 3.5-3 INSTRR1ENT OPERATING CONDITIONS FOR ISOIATION FUNCTIONS FUNCTIONAL UNIT 1.
CONTAIQKNT ISOLATION 1.1 Containment Isolation
- a. Manual TOTAI NO.
OF NO.
OF CHANNELS CHANNELS TO TRIP" MIN.
OPERABLE CHANNELS MIN.
DEGREE OF REDUNDANCY 5
OPERATOR ACTION IF CONDITIONS OF COLDS 3 CANNOT BE MET
- b. Safety Injection' C) 1.2 Containment Ventilation Isolation a.
Manual
- b. High Containment Radioactivity
- c. Manual Spray
- d. Safety Injection (See Table 3.5-2, Item 1)
(See Table 3.5-2, Item 2a)
(See Table 3.5-2, Item 1) 0'00 8
TABLE 3.5-3 (Continued)
FUNCTIONAL UNIT 2.
Steam Iine Isolation 1
2 TOTAL NO.
OF NO.
OF CHANNELS CHANNELS TO TRIP" HIN.
OPERABI E CHANNELS 1'1IN.
DEGREE OF REDUNDANCY 5
OPERATOR ACTION IF CONDITIONS OF COLlkiN 3 CANNOT BE HET
- a. Hi-Hi Steam Flow with 2/loop Safety Injection Hot Shutdown "'"":
- b. Hi Steam Flow and 2 of 4 I,ow T with Safety InjecPion c.
20 psi Containment Pressure
- d. Hanual 3.
Feedwater Line Isolation
- a. Safety Injection
- b. Hi Steam Generator Level 2/loop 1/loop 1/loop 3/loop 2 in either loop 1/loop (See Table 3.5-2, Item 1) 2/loop 1/loop Hot Shutdown Hot Shutdown "=-"
Hot Shutdown Hot Shutdown "-
Hot Shutdown --:
TABLE 3.5-3 Continued TABLE NOTATION
- If a functional unit is operating with the minimum operable
- channels, the number of channels to trip the reactor will be column 3 less column 4.
- If minimum conditions are not met within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, steps shall be taken to place the unit, in cold shutdown condi-tions.
ACTION-STATEMENTS ACTION 1 With the number of operable channels one less than the Total Number of Channels, restore the inoperable channel to operable status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least hot shutdown within the next, 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.'CTION 2
With less than the Minimum Channels
- operable, operation may continue provided the containment purge and exhaust valves are maintained closed.
3.5-10 Proposed
TABIE 3.5-4 ACCIDENT MONITORING INSTRUMENTATION INSTRUMENT 1.
Pressurizer Water I,evel-'.
Auxiliary Feedwater Flow Rate"---="
3.
Reactor Coolant System Subcooling Margin Monitor"~
4.
PORV Position Indicator""'.
PORV Block Valve Position Indicator-
6.
Safety Valve Position Indicator'='
I TOTAL NO.
OF CHANNELS 2 per pump 2/valve 1/valve 2/valve MINIMUM CHANNELS OPERABLE 1 per pump 1/valve 1/valve
"-Emergency Power Supply Requirements for Pressurizer Indicators - NUREG 0578 Item 2.1.1
"="Instrumentation for Detection of Inadequate Core Cooling - NUREG 0578 Item 2.1.3.b
"'"'Direct Indication of Power Operated Relief Valve and Safety Valve Position NUREG 0578 item 2.1.3.a.
Two channels include a primary detector and thermocouples as the backup detector.
"' "Auxiliary Feedwater Flow Indication to Steam Generator NUREG 0578 item 2.1-7.b
'0 0
0 8
I I
TABLE 3.5-5 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS FUNCTIONAL UNIT TRIP SETPOINT ALLOWABLE VALUES*
1.
SAFETY INJECTION AND FEEDWATER ISOLATION 4J Ol I
I hJ a.
Manual Initiation b.
High Containment Pressure c.
Low Pressurizer Pressure d.
Low Steam Line Pressure 2.
Manual Initiation b.
High-High Containment Pressure 3.
CONTAINMENT ISOLATION Not Applicable
< 5.0 psig
> 1723 psig
> 514 psig Not Applicable
< 28 psig Not Applicable
< 6.0 psig
> 1715 psig
> 500 psig Not Applicable
< 30 psig 0
0 S
a.
b.
Containment Isolation l.
Manual 2.
From Safety Injection Automatic Actuation Logic Containment Ventilation Isolation 1.
Manual 2.
High Containment Radioactivity 3.
From Safety Injection 4.
Manual Spray Not Applicable Not Applicable Not Applicable
< 10 x Offsite Dose Calculation Manual Setpoint submitted in accordance with Appendix I Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable
TABLE 3.5-5 Continued ENGINEERED SAFETY FEATURE ACTUATION SYSTEN INSTRUNENTATION TRIP SETPOINTS FUNCTIONAL UNIT TRIP SETPOINT ALLOWABLE VALUES*
4.
STEAld LINE ISOLATION lA Vl I
4J a.
Manual b.
High Containment Pressure c.
High Steam Flow., Coincident with Low T and SI avg d.
High-High Steam Line Flow Coincident with SI 5.
FEED MATER ISOLATION Not Applicable
< 18 psig dp corresponding to
< 0.49 x 10 lbs/hr at 755 psig 45oF Tavg-dp correspgnding to
< 3.6 x 10 lbs/hr at 755 psig Not Applicable
< 20 psig dp corresponding to
< 0.55 x 10 lbs/hr at 755 psig T
> 543oF avg-dp corresponding to < 3.7 x 10 lbs/hr at 755 psig a.
High Steam Generator Mater Level 6.
AUXILIARYFEEDWATER
< 67~ of narrow range
< 68~ of narrow range instrument span each instrument span each steam generator steam generator O.
'60 M89 a.
Low-Low Steam Generator Water Level b.
From Safety Injection c.
Loss of 4 kV Voltage (Start TAFP) d.
Feedwater Pu'mp Breakers Open (start l1AFP)
N.A.
62~ of 4160 volts Note 2 Not Applicable N.A.
Note 2
Not Applicable
> 17~ of narrow range
> 17~ of narrow range instrument span each instrument span each steam generator steam generator.
See Note 1.
TABLE 3.5-5 Continued)
ENGINEERED SAFETY FEATURE ACTUATION SYSTE1j INSTRUIIENTATION TRIP SETPOINTS FUNCTIONAL UNIT TRIP SETPOINT ALLOWABLE VALUES 7.
LOSS OF VOITAGE a.
480 V Safeguards Bus Under-voltage (Loss of Voltage) b.
480 V Safeguards Bus Under-voltage (Degraded Voltage) see Figure 2.3-1 (proposed change dated September 9,
1980) see Figure 2.3-1 (proposed change dated September 9,
1980) lA Vl I
8.
ENGINEERED SAFETY FEATURE ACTUATION SYSTEN INTERLOCKS a.
Pressurizer
- Pressure, (block, unblock SI)
< 2000 psig
< 2010 psig Note 1:
A positive 11~ error has been included in the setpoint to account for errors which may be introduced into the steam generator level measurement system at a containment temperature of 286~F as determined by an evaluation performed on temperature effects on level systems as required by IE Bulletin 79-21.
0 0
9 Note 2:
This setpoint value is from inverse time curve for CVT relay (406C883) with tap setting of 82 volts and time dial setting of 1.
Delay at 62~ voltage is 3.6 seconds.
The allowable values are k5~ of the trip setpoint.
- Allowable Values are those values assumed in accident analysis.
Containment S stem A licabilit Applies to the integrity of reactor containment.
~b'o define the operating status of the reactor containment for plant operation.
S ecification:
Containment Inte rit a
~
b.
C.
Except as allowed by 3.6.3 containment integrity shall not be violated unless the reactor is in cold shutdown condition.
The'ontainment integrity shall not be violated when the reactor vessel head is removed unless the boron concentration is greater than 2000 ppm.
Positive reactivity changes shall not be made by rod drive motion or boron dilution whenever the containment integrity is not intact unless the boron concentration is greater than 2000 ppm.
Internal Pressure If the internal pressure exceeds 3 psig or the internal vacuum exceeds 2.0 psig, the condition shall be corrected within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the reactor rendered subcritical.
Proposed
3.6.3 3.6.3.1 Containment Isolation Valves With one or more of the isolation valve(s) specified in
.Table 3.6-1 inoperable, maintain at least one isolation valve operable in each affected penetration that. is open and either:
a.
Restore the inoperable valve(s) to operable status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or b.
Isolate each affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of at least one deactivated automatic valve secured in the isolation position, or Isolate each affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of at least one closed manual valve or blind flange, or d.
Be in at least hot, shutdown within the next; 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
Isolation valves are inoperable from a leakage standpoint if the leakage is greater than that allowed by 10 CFR 50 Appendix J.
3.6-2 Proposed
Basis:
The reactor coolant system conditions of cold shutdown assure that no steam will be formed and hence there would be no pressure buildup in the containment if the reactor coolant system ruptures.
'I I
The shutdown margins are selected based on the type of activities that are being carried out.
The (2000 ppm) boron concentration provides shutdown margin which precludes criticality under any circumstances.
When the reactor head is not to be removed, a cold shutdown margin of 1/pk/k precludes criticality in any occurrence.
P Regarding internal pressure limitations, the containment'design pressure of 60 psig would not be exceeded if the internal pressing~
before a major loss-of;coolant accident were as much as 6 psig.
The contaj~ent is designed to withstand an internal vacuum of 2.5 psig.
The 2.0 psig vacuum is specified as an operating limit to avoid any difficulties with motor cooling.
References:
(1)
FSAR - Section 14.3.5 (2)
FSAR - Section 5.5 3.6-3
TABLE 3.6"1 CONTAINHENT ISOLATION VALVES PENT.
NO.
IDENTIFICATION/DESCRIPTION PRIHARY ISOLATION BOUNDARY lfAZIHUH SECONDARY ISOLATION ISOLATION TIHE *(SEC)
BOUNDARY liAZIHUH ISOLATION TINE *(SEC) 29 Fuel transfer tube 100 charging line to "B" loop 101 SI Pump 1B discharge 102 103 105 I
106 Alternate charging to "A" cold leg Construction Fire Service Water Containment Spray Pump 1A "A" Reactor Coolant Pump (RCP) seal water inlet flange CV 370B CV 889B CV 870B CV 383B welded flange CV 862A CV 304A NA NA NA NA NA NA NA (1)
(2)
(5)
(5)
(2)
HV 5129 (3)
(2)
NA NA NA NA NA NA
~ - -107 108 Sump A discharge to Waste Holdup Tank RCP seal water out and excess letdown to VCT AOV 1728 HOV 313 60 60 AOV 1723 60 (4)
NA 109 110 110 112 113 Containment Spray Pump 1B "B" RCP seal water inlet SI test line RHR to "B" cold leg letdown to Non-regen.
Heat exchanger SI Pump 1A discharge 120 Nitrogen to Accumulators 120 Pressurizer Relief Tank (PRT) to Gas Analyzer (GA)
CV 889A CV 870A.
AOV 846 AOV 539 NA NA 60 60 CV 862B NA CV 304B NA HV 879 NA HOV 720(20)
NA AOV 371 60 (3)
(2)
(5)
(6)
(5)
(5)
CV 8623 HV 546(7)
NA NA NA NA NA NA NA NA NA
)
PENT.
NO.
121 121 121 121 123 124 124 IDENTIFICATION/DESCRIPTION Nitrogen to PRT Reactor Makeup water to PRT Cont. Press.
transmitter PT-945 (10)
Cont. Press.
transmitter PT-946 (10)
Reactor Coolant Drain Tank (RCDT) to GA Excess letdown supply and return to heat exchanger Post Accident air sample "C" fan.
130 131 132 140 O
141 0
142 143 CCH to reactor support cooling CCH to reactor support cooling Depressurization at power RHR pump suction from "A" Hot leg RHR-51 pump suction from Sump B
RHR-g2 pump suction from Sump B
RCDT pump suction
'201 Reactor Compart. cooling Unit A & B 202 "B" Hydrogen recombiner (pilot S< main) 125 Component Cooling Mater (CCW) from 1B RCP 126 CCW from 1A RCP I
127 CCN to 1A RCP 128 CCW to 1B RCP 129 RCDT & PRT to Vent Header PRIlIARY ISOLATION BOUNDARY CV 528 CV 529 PT 945 PT 946 AOV 1789 AOV 745 CV 743 lrv 1569 lIV 1572 HOV 759B MOV 759A CV 750A CV 750B AOV 1787 CV 1713 HOV 813 MOV 814 AOV 7970 MOV 701(20)
MOV 850A(13)
MOV 850B(13)
AOV 1721 IIV 4757 (16)
IIV 4636(16) 11V 1076B MV 1084B MAXIMUM ISOLATION TIME *(SEC)
NA NA NA NA 60 60 NA NA NA NA NA NA NA 60 60 60 NA NA NA 60 NA NA NA NA SECONDARY ISOLATION BOUNDARY 1IV 547(8)
AOV 508 1IV 1819A llV 1819B HV 1655(7)
(>>)
(11)
MV 1571 1IV 1574 (12)
(12)
MOV 749A HOV 749B AOV 1786 (19)
(19)
AOV 7971 (e)
MOV 851A(13)
HOV 851B(13)
(11)
SOV IV"3B SOV IV-5B MAXIMUM ISOLATION TIHE *(SEC)
NA 60 NA NA NA NA NA NA NA NA 60
'60 60 NA 60 NA NA NA 60 60 NA NA NA Normally Closed NA Normally Closed
PENT.
NO.
IDENTIFICATION/DESCRIPTION PRIMARY ISOLATION BOUNDARY HAXIHUH ISOLATION TIME *(SEC)
SECONDARY HAXIMUH ISOLATION ISOLATION BOUNDARY TIlIE *(SEC) lA I
203 Contain. Press.
transmitter PT-947
& 948 PT 947 PT 948 203 Post accident air sample to "B"- fan 204 205 206 206 207 207 209 Purge Supply Duct Hot leg loop sample Przr. liquid space sample "A" S/G sample Przr.
Steam space sample "B" S/G sample Reactor Compart. cooling Units A & B 210 Oxygen makeup to A & B recombiners HV 1563 MV 1566 AOV 5870 AOV 966C AOV 966B AOV 5735 AOV 966A AOV 5736 HV 4758(16)
HV 4635(16)
HV 1080A 300 Purge Exhaust Duct AOV 5878 301 Aux. steam supply to containment MV 6151 303 Aux. steam condensate return MV 6175 304 "A" Hydrogen recombiner (pilot and main)
HV 1084A NA NA NA NA 60 60.
60 60 60 NA NA NA NA NA NA HV 1819C HV 1819D MV 1565 MV 1568 AOV 5869 MV 956D(14)
MV 956E(14)
HV 5733(7)
MV 956F MV 5734(7)
(>>)
(>>)
SOV IV-2A SOV IV-2B AOV 5879 HV 6165(15)
MV 6152(15)
SOV IV-5A NA NA NA NA NA NA NA NA NA NA NA NA Normally Closed NA Normally Closed 5
NA NA NA Normally Closed 305 m
305 305 Radiation Monitors R-ll, R-12 & R-10A Auto Inlet Isol.
R-ll, R-12 & R-10A Outlet
'Post Accident air sample (containment)
MV 1076A AOV 1597 CV 1599 HV 1554'.
MV 1557 MV 1560 NA 60 NA NA NA NA SOV IV-3A HV 1596 AOV 1598 HV 1556 MV 1559 MV 1562 NA Normally Closed NA 60 NA NA NA 307 Fire Service Mater (18)
CV 9227 NA AOV 9229 60
I
PENT.
NO.
IDENTIFICATION/DESCRIPTION PRIMARY ISOLATION BOUNDARY MAXIMUM ISOLATION TIME *(SEC)
SECONDARY ISOLATION BOUNDARY MAXIMUM ISOLATION TIME *(SEC) 308 309 310 310 311 312 313 315 316 317 318 319 320 321 322 323 324 332 0
332 9
401 402 Service Hater to "A" fan cooler leakage test depressurization Service Air to Contain.
Instrument Air to Contain.
Service Hater from "B" fan cooler Service Water to "D" fan cooler leakage test depressurization Service Water from "C" fan cooler Service Hater to "B" fan cooler leakage test supply Dead weight tester Service Hater from "A" fan cooler Service water to "C" fan cooler A S/G Blowdown B S/G Blowdown Service Water from "D" fan cooler Demineralized water to Containment Cont. Press.
Trans.
PT-944, 949 6 950 Leakage test instrumentation lines Main steam from A S/G Main steam from B S/G MV 4627(16) flange CV 7226 CV 5393 MV 4630(16)
MV 4642(16) flange MV 4643(16)
MV 4628(16) flange tubing cap MV 4629(16)
MV 4641(16)
CV 8419 PT 944 PT 949 PT 950 Cap Cap Cap NA**
'NA**
NA NA NA NA NA NA NA NA NA NA NA NA 60 60 NA NA NA NA
.NA NA NA NA NA NA
. (11)
(11)
MOV 7444 (11)
(11)
MOV 7443 MV 549B (11)
(11)
MV 5701(7)
MV 5702(7)
(11)
AOV 8418.
MV 1819G MV 1819F MV 1819E MV 7448 MV 7452 MV 7456 NA NA NA NA Normally Closed NA 60 NA NA NA Normally Closed NA NA NA Normally Closed NA NA NA NA NA NA 60 NA NA NA NA NA NA NA NA
)
I
PENT.
NO.
IDENTIFICATION/DESCRIPTION PRIlfARY ISOLATION BOUNDARY
~
HAXIHUH SECONDARY ISOLATION ISOLATION TIHE *(SEC)
BOUNDARY 1fAXIHUI1 ISOLATION TI11E *(SEC) 403 Feedwater line to A S/G 404 Feedwater line to B S/G 1000 Personnel Hatch 2000 Equipment Hatch NA NA NA**
NA**
NA NA NA NA NA NA NA NA NA NA NA NA lA Ch I
CO
- The maximum isolation time does not include diesel start time.
- The llSIVs and feedwater isolation valves are not considered to be containment isolation valves.
The containment boundary is the steam generator secondary side and tubes.
HV - lfanual Valve HOV lfotor Operated Valve AOV Air Operated Valve CV - Check Valve SOV - Solenoid Operated Valve 0
0 6
. 0
<I l
0 NOTES
--.-(1-)-
The end of the fuel transfer tube inside containment is closed by a double-gasketed blind flange, to prevent, leakage of spent fuel pit, water into the containment during plant operation.
This flange also serves as protection against leakage from the containment following a loss of coolant accident.
The space between these gaskets can also be pressurized by the penetra-tion test system.
(FSAR 5.2.2 pg. 5.2.2-3)
(2)
(3)
(5)
(6)
(7)
(8)
(9)
Incoming lines connected to closed systems outside containment are provided with at least, one check valve or normally closed isolation valve located inside containment.
(FSAR 5.2.2 pg 5.2.2-2)
The Containment Spray System is a closed system outside con-tainment provided with a single containment isolation valve (FSAR Table 5.2.2-1 and Figure 5.2.2-8).
The single remotely controlled, motor operated containment isolation valve is normally open.
The seal water return line is not directly connected to the Reactor Coolant System.
A second automatic isolation barrier is provided by the closed system consisting of the volume control tank and connecting piping.
The Safety Injection system is a closed system outside con-tainment provided with a single containment isolat'ion valve (FSAR Table 5.2.2-1 and Figure 5.2.2-9).
Connections of the test line with other lines inside containment are all missile protected and upstream of check valves connecting to the RCS.
The SI system is in operation following a LOCA and pressurized to a pressure higher than that in containment.
The RHR system is,a closed system outside containment provided with one normally closed, missile'rotected containment iso-lation valve inside containment.
In addition, a second normally closed valve is provided inside the missile barrier (FSAR Table 5.2.2-1 and Figure 5.2.2-2, see also ANSI-N271-1976).
Normally operating outgoing lines not connected to the Reactor Coolant System and not protected against missiles throughout their length inside containment.
are provided with at, least one automatically operated trip valve or one remotely operated stop valve located outside containment.
Manual isolation valves in series with the trip or remote operated valves are also provided outside the containment (FSAR 5.2.2 pg. 5.2.2-1a)..
See FSAR Table 5.2.2-1 and Figure 5.2.2-1.
Incoming lines connected to open systems outside the contain-ment are provided with a check valve located inside containment, and a remote operated valve or check valve and remote operated valve located outside containment.
(FSAR 5.2.2 pg. 5.2.2-2)
~ I 3.6-9 Proposed
I
(10) The pressure transmitter provides a boundary.
.'"(ll) Normally operating incoming and outgoing lines which are connected to closed systems inside containment and protected against, missiles throughout their length, are provided with at, least one manual isolation valve outside containment (FSAR 5.2.2 pg. 5.2.2-2).
(12) The single remotely controlled containment isol'ation valve is normally open and motor operated.
The cooling water return line is not directly connected to the reactor coolant system
- and, should remain open while the coolant pump is running.
A second automatic isolation barrier is provided by the component cooling water loop, a closed system.
(FSAR 5.2.2 pg. 5.2.2-1a)
(13). See FSAR Table 5.2.2-1 and Figure 5.2.2-2.
Sump lines are in operation and filled with fluid following an accident.
Containment leakage testing is not required.
The valves are subjected to RHR system hydrostatic test.
Normally operating outgoing lines connected to the Reactor Coolant System are provided with at. least one automatically operated trip valve and one manual isolation valve in series located outside the containment, In addition to the isolation
- valves, each line connected to the Reactor Coolant System is provided with a remote operated root valve located near its connection to the Reactor Coolant System.
(FSAR 5.2.2 pg.:
5.2.2-1)
(15)
(16)
(17)
(18)
See FSAR Table 5.2.2-1 and Figure 5.2.2-17.
The Service Water system operates at a pressure higher than the containment accident pressure and is missile protected inside containment.
Therefore, these valves are used for flow control only and need not be leak tested.
A manual valve outside containment in series with an automatic valve is provided for normally operating outgoing RCS lines (FSAR pg.,5.2.2-1).
Installation of this penetration and valving is scheduled for 1981.
(19)
(20)
See FSAR Table 5.2.2-1 and Figure 5.2.2-16.
Containment leakage testing is not required per L. D. White, Jr.
letter to Dennis L. Ziemann, USNRC dated September 21, 1978.
3.6-10 Proposed
1 I
1
SURVEILLANCE RE UIREMENTS Specified intervals may be adjusted plus or minus 25% to accommodate normal test schedules.
0 erational Safet Review
~11'pplies to items directly related to safety limits and limiting conditions for operation.
'o specify the minimum frequency and type of surveillance to be applied to plant equipment and conditions.
Calibration, testing, and checking of analog channel and testing of logic channel shall be performed as specified in Table 4.1-1.
Equipment and sampling tests shall be conducted as specified in Table 4.1-2.
Each accident monitoring instrumentation channel shall be demonstrated operable by performance of the channel check and channel calibration operations at, the fre-quencies shown in Table 4.1-3.
Basis:
Check Failures such as blown instrument fuses, defective in-
- dicators, faulted amplifiers which result in "upscale" or "downscale" indication can be easily recognized by simple observation of the functioning of an instrument or system.
Furthermore, such failures are, in many
- cases, revealed 4.1-1 Proposed
TABLE 4.1-1 (Continued)
Channel Descri tion Check Calibrate Test Remarks 25.
Containment Pressure S
R M
Narrow range containment pressure
(-3.0,
+3 psig excluded) 26.
Steam Generator Pressure S
27.
Turbine First Stage Pressure S
28.
Emergency Plan Radiation M
Instruments 29.
Environmental Monitors M
N.A.
N.A.
30.
Trip of Main Feedwater Pumps N.A.
N.A.
P Prior to each startup if not done previous week 0'00 8
Q
TABLE 4.1-3 ACCIDENT MONITORING INSTRlRKNTATION SURVEILIANCE REQUIREMENTS INSTRUMENT CHANNEL CHECK CHANNEL CALIBRATION CHANNEL TEST 1.
Pressurizer Water Level" 2.
Auxiliary Feedwater Flow Rate"=--
3.
Reactor Coolant System Subcooling Margin Monitor"':
4.
PORV Position Indicator: '
(Primary Detector) 5 ~
PORV Position Indicator :='Thermocouples-Backup Detector)
See Table 4.1-1 See Table 4'-1 See Section 4.8.1 NA NA 6.
PORV Block Valve Position Indicator"-
7.
Safety Valve Position Indicator"='='Primary Detector) 8.
Safety Valve Position Indicator--':: (Thermocouples-Backup Detector)
M NA NA NA
"-Emergency Power Supply Requirements for Pressurizer I,evel Indicators - NUREG 0578 Item 2.1.1
=-Instrumentation for Detection of Inadequate Core Cooling - NUREG 0578 Item 2.1.3.b
-'='""Direct Indication of Power Operated Relief Valve and Safety Valve Position NUREG 0578 item 2.1.3.a
AuxiliaryFeedwater Flow Indication to Steam Generator NUREG 0578 item 2.1.7.b 0'00 P
REACTOR COOLANT SYSTEM Applies to surveillance of the reactor coolant system and its components.
To ensure operability of the reactor coolant system and its components.
S ecifications:
Reactor Vessel Material Surveillance Testing The reactor vessel material surveillance testing program is designed to meet the requirements of Appendix H to 10 CFR Part 50.
This program consists of the metal-lurgical specimens receiving the following test:
- tensile, charpy impact and the WOL test.
These tests of the Radiation Capsule Specimens shall be per formed as follows:
~Ca sule Time Tested End of 1st core cycle End of 3rd core cycle
'10 years, at nearest refueling 20 years, at. nearest refueling 30 years, at nearest refueling Standby The report of the Reactor Vessel Material Surveillance shall be written as a Summary Technical Report as required by Appendix H to 10 CFR Part 50.
Pressurizer The pressurizer water level shall be verified to be within its limits at, least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> during power operation and hot shutdown.
4.3-1 Proposed
4.3.3 4.3.3.1 4.3.3.2 Basis:
Relief Valves Each PORV shall be demonstrated operable at least once per 18 months by performance of a CHANNEL CALIBRATION.
Except during cold'nd refueling shutdown each block valve shall be demonstrated operable at least once per 92 days by operating the valve through one complete cycle of full travel unless the valve is already closed.
This material surveillance program monitors changes in the fracture toughness pr'operties of ferritic materials in the reactor vessel beltline region of the reactor resulting from exposure to neutron irradiation and the thermal environment.
The test data obtained from this program will be used to determine the conditions under which the reactor vessel can be operated with adeguate margins of safety against. fracture throughout its service life.
4.3-2 Proposed
b.
The local leakage rate shall be measured for each of the following components:
i.
Containment penetrations that employ resilient
- seals, gaskets or sealant compounds, piping penetrations with expansion bellows and electrical penetrations with flexible metal seal assemblies.
ii.
Air lock and equipment door seals.
iii.
Fuel transf er tube.
iv.
Isolation valves on the testable fluid systems lines penetrating the containment.
v.
Other containment components, which require leak repair in order to meet the acceptance criterion for any integrated leakage rate test.
4.4.2.2 Acce tance Criterion The total leakage from all penetrations and isolation valves shall not exceed 0.60La.
4.4.2.3 Corrective Action a
~
If at any time it is determined that the total leakage from all penetrations and isolation valves exceeds 0.60La, repairs shall be initiated immediately.
4.4-5a
4.4.2.4 b.
Test If repairs are not completed and conformance to the acceptance criterion of 4.4.2.2 is not demonstrated within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, the reactor shall be shutdown and depressurized until repairs are effected and the local leakage meets this acceptance criterion.
Fre uenc a
0 b.
C.
d.
Except as specified in b., c.,
and d. below, in-dividual penetrations and containment. isolation valves shall be tested during each reactor shutdown for refueling, or other convenient intervals, but in no case at intervals greater than two years.
The containment equipment hatch and fuel transfer tube shall be tested at, each refueling shutdown or after each use, if that be sooner.
The containment air locks shall be tested at intervals of no more than six months by pressurizing the space between the air lock doors.
In addition, following opening of the air lock door during the
- interval, a test shall be performed by pressurizing between the dual-seals of each door opened, within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of the opening, unless the reactor was in the cold shutdown condition at the time of the opening or has been subsequently brought to the cold shutdown condition.
A test shall also be performed by pressurizing between the dual seals of each door within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of leaving the cold shutdown condition, unless the doors have not been opened since the last test performed either by pressurizing the space between the air lock doors or by pressurizing between the dual door seals.
Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after each closing when containment integrity is required, except when being used for multiple cycles and then at, least once per 72
- hours, each containment purge isolation valve shall be tested to verify that, when the measured leakage rate is added to the leakage rates determined for all.other Type B and C penetrations, the combined leakage rate is less than or equal to 0.60 La.
4.4.3 Recirculation Heat Removal S stems 4.4.3.1 Test a ~
the portion of the residual heat removal system that is outside the containment. shall either be tested by use in normal operation or hydrostatically tested at 350 psig at the interval specified in 4.4.3.4.
4.4-5b Proposed
b.
Suction piping from containment sump B to the reactor coolant drain tank pump and the discharge piping from the pumps to the residual heat removal system shall be hydrostatically tested at no less than 100 psig at the interval specified in 4.4.3.4.
4.4-5c
J i
C
~
0
4.4.4.2 4.4.5 4.4.5.1 the tendon containing 6 broken wires) shall be inspected.
The acceptance criterion then shall be no more'han 4
broken wires in any of the additional 4 tendons.
If
.thi's criterion is not satisfied, all of the tendons shall be inspected and-if more than 5% of the total wires are broken, the reactor shall be shutdown and depressurized.
Pre-Stress Confirmation Test a.
Lift-offtests shall be performed on the 14 tendons identified in 4.4.4.1a
- above, at the intervals specified in 4.4.4.1b.
If the average stress in the 14 tendons checked is less than 144,000 psi (60% of ultimate stress), all tendons shall be checked for stress and retensioned, if necessary, to a stress of 144,000 psi.
b.
Before reseating a tendon, additional stress (6%)
shall be imposed to verify the ability of the tendon to sustain the added stress applied during accident, conditions.
Containment Isolation Valves Each isolation valve specified in Table 3.6-1 shall be demonstrated to be operable in accordance with the Ginna Station Pump and Valve Test Program submitted in accordance with 10 CFR 50.55a.
4.4.6
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Proposed Containment Isolation Res onse 4.4.6.1 Each containment isolation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION, and CHANNEL FUNCTIONAL TEST operations for the MODES and at the frequencies shown in Table 4.1-1.
4.4.6.2 The
RESPONSE
TIME of each containment, isolation function shall be demonstrated to be within the limit, at least once per 18 months.
Each test shall include at, least one channel per function such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific function as shown in the "Total No. of Channels" Column of Table 3.5-3.
The response time limit shown on Table 3.6-1 does not include diesel generator starting times but does include valfre travel times for all valves that, change position.
The times determined in independent
- tests, such as electronic response of portions of the initiating circuitry and valve travel times, may be combined to determine the total function response time.
Basis:
The containment is designed for an accident. pressure of 60 psig.
While the reactor is operating, the internal environment of the containment will be air at approximately atmospheric pressure and a maximum temperature of about 120'F.
With these initial conditions, the temperature of the steam-air mixture at, the peak accident pressure of 60 psig is calculated to be 286'F.
4.4-8
The pre-stress confirmation test provides a direct measure of the
"- load-carrying capability of the tendon.
If the surveillance program indicates by extensive wire breakage or tendon stress relation that the pre-stressing tendons are not behaving as expected, the situation will be evaluated immediately.
The specified acceptance criteria are such as to alert attention to the situation well before the tendon load-carrying capability would deteriorate to a point that failure during a design basis accident might be possible.
Thus the cause of the incipient deterioration could be evaluated and corrective action studied without need to shut down the reactor.
The containment is pro-vided with two readily removable tendons that might be useful to such a study.
In addition, there are 40 tendons-,
each con-taining a removable wire which will be used to monitor for pos-sible corrosion effects.
Operability of the containment isolation valves ensures that the containment.
atmosphere will be isolated from the outside environ-ment in the event of a release of radioactive material to the containment atmosphere or pressurization of the containment.
Performance of cycling tests and verification of isolation times are covered by the Pump and Valve Test Program.
Compliance with Appendix J to 10 CFR 50 is addressed under local leak testing reguirements.
References:
(1)
FSAR Section 5.1.2.3 (2)
FSAR Section 5.1.2 (3)
FSAR Section 14.3.5 (4)
FSAR Table 6.2-8 (5)
FSAR Section 6.2.3 (6)
FSAR Page 5.1.2-28 (7)
North-American-Rockwell Report 550-x-32, Autonetics Reliability
- Handbook, February 1963.
(8)
FSAR Page 5.1.2-28 4.4-14 Proposed
4.8.5 4.8.6 4.8.7 4.8.8 4.8.9 4.8.10 Except, during cold or refueling shutdowns, the suction, discharge, and cross-over motor operated valves for the Standby Auxiliary Feedwater pumps shall be exercised at
.intervals not to exceed one month.
These tests shall be considered satisfactory if control board indication and subsequent visual observation of the equipment demonstrate that all components have operated properly.
These tests shall be performed prior to exceeding 5% power during a startup if the time since the last test exceeds one month.
At least once per 18 months, control of the standby auxiliary feed system pumps and valves from the control room will be demonstrated.
At least once per 18 months during shutdown a.
Verify that each automatic valve in the flow path for each auxiliary feedwater pump actuates to its correct position upon receipt of each auxiliary feedwater actuation test signal.
b.
Verify that. each auxiliary feedwater pump starts as designed automatically upon receipt of each auxiliary feedwater actuation test signal.
Each instrumentation channel shall be demonstrated
~
OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION, and CHANNEL FUNCTIONAL TEST operations for the NODES and at the frequencies shown in Table 4.1-1.
The
RESPONSE
TIME of each function shall be demonstrated to be within the limit of 10 minutes at least once per 18 months.
Each test shall include at least one channel per function such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific ESFAS function as shown in the "Total No. of Channels" Column of Table 3.5-2.
The times determined in independent tests, such as electronic response of portions of the initiating circuitry and valve travel times, may be combined to determine the total function response time.
Basis The monthly testing of the auxiliary feedwater pumps by supplying feedwatei to the steam generators will verify their ability to meet design.
The flow rates will be measured at a simulated steam generator pressure of 1100 psia. 'he capacity of any one of the three auxiliary feedwater pumps is sufficient to meet decay heat removal requirements.
Proper functioning of the steam turbine admission valve and the feedwater pumps start will demonstrate the integrity of the steam drive pump.
Monthly testing of the Standby Auxiliary Feedwater pumps by supplying water from a condensate supply tank to the steam generators will verify their ability to meet. design.
The flow rate will be measured at a simulated steam generator pressure of 1100 psia.
4.8-2 Proposed
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The Standby Auxiliary Feedwater pumps would be used only if all three auxiliary feedwater pumps were unavailable.
One of the two standby pumps would be sufficient to meet decay heat removal requirements.
Proper functioning of the suction valves from the service water system, the discharge
- valves, and the crossover valves will demonstrate their operability.
,The operability of the standby AFW pump flow paths between the pumps and the steam generators is demonstrated using water from the test tank.
Test-ing of the main AFW pumps using their primary source of water supply will verify the operability of the AFW flow path-.
Verification of correct operation will be made both from instru-mentation within the main control room and by direct visual observa-tion of the pumps.
References:
FSAR - Section 10.4 FSAR Section 14.1.9 FSAR - Section 14.2.5 "Effects of High Energy Pipe Breaks Outside the Containment Build-ing" submitted by letter dated November 1, 1973 from K.
W. Amish, Rochester Gas and Electric Corporation to A. Giambusso, Deputy Director for Reactor Projects, U.S. Atomic Energy Commission.
4.8-3 Proposed
ROCHESTER GAS At8 ELECTRIC CORPORATION GINNA STATICtl ORGANIZATION SO'ER INTEteEtiT TRAINING COORO I NATOR ASS ISTANT SIPER INTM)ENT TECILYICAL ASSISTANT FOR OPERATIONAL ASSESSMENT ENGINEERS SUPER VI SOR CHEMISTRY AIO ltEALTH PHYSICS OPERA'TIONS ENGINEER SRO FIRE PROTECTION MAINTENANCE AM) SAFETY COORD ENGINEER OFF ICE QPERVI SOR TECHNICAL ENGINEER QUALITY COtlTROL ENGINEER CHEMIST'EALTH PHYS IC ISI'S OPERAT IOttS SIT'ERVI SCR SRO MATERIALS COORO INATOR MAINTENhttCE SIPERV ISOR I dc QPERV I SCR NUCLEAR DIGINEER RESULTS d TEST QPERY I SOR TECHtlICIhtlS CHEMJ STRY TECttH C IANS RAG I ATION PROTECTION TECIVIIC IANS SHIF'T TECHNICAL AOVISOR'/SHIFT SHIFT QPERVISOR I/SHIFT SIIG r
HEAD CONTROL J
OPERATOR I/SHIFT RO CONTROL OPERATOR I/SHIFT RO STOCKROOM MAINTENANCE FOREMEN FITTERS MECHANICS HANOYMEN ISC Ah0 ELECTRIC fGREEN TECHNICIANS d REPA IRMEN ELECTRIC IAttS TECHN IC IANS AUXILIARY OPERATCR 2/SHIFT REPORTING
~II GATI Ott aSTA PJJST BE EITIIER SRO OR IIAVE BS OEGJIEE ~
STA IS REQUIREO OiYLY DURIttT POUER OPERATION.
F lgure 6.2-2
1 I.
6.4 STATION STAFF UALIFICATIONS Each member of the facility shall meet or exceed the
~minimum qualifications of ANSI Standard N18.1-1971, "Selection and Training of Nuclear Power Plant Personnel",
as supplemented by Regulatory Guide 1.8, September
- 1975, for comparable positions, except for the Shift Technical Advisor who shall have a bachelor's degree or equivalent in a scientific or engineering discipline or. who shall have a Senior Reactor Operator's License.
I TRAINING 6.4.1 6.4.2 A retraining and replacement training program for the facility staff shall be maintained under the direction of the Training Coordinator and shall meet or exceed the requirements and recommendations of Section 5.5 of ANSI N18.1-1971 and Appendix A of 10 CFR Part 55.
The training program shall meet or, exceed NFPA No. 27, 1975 Section 40, except that (1) training for salvage operations need not be provided and (2) the Fire Brigade training sessions shall be held at least quarterly.
Drills are considered to be training sessions.
6.3-1 Proposed
V 4 I
Attachment B
By letter dated July 2,
- 1980, and received July, 14,
- 1980, from Mr. Darrell G. Eisenhut, the NRC requested that we revise the Ginna Technical Specifications to incorporate the implementation of the TNI Lessons Learned Category "A" items.
Model Technical Specifications (T.S.) were provided for our use.
The proposed changes provided in 'Attachment A generally follow the NRC guidances although certain changes have been made due to plant specific features and due to the fact that Ginna does not, have Standard Technical Specifications.
The Model T.S. for Engineered Safety Feature Actuation System Instrumentation and for Accident Monitoring Instrumentation have been incorporated into Sections 3.5 and 4.1.
The Model T.S. for pressurizer and pressurizer relief valves have been incorporated into Section 3.1 and 4.3.
The Model T.S. for Containment Isolation Valves have been incor-porated into Sections 3.6 and 4.4.
The Model T.S. for Auxiliary Feedwater Systems have been incor-porated into Section 4.8.
Section 3.4 of our Technical Speci-fications has been revised to update the minimum required amount of water in the condensate storage tanks in accordance with our letter of March 28, 1980.
The section underwent, a complete revision with Amendment 29 dated August 24, 1980 so no further changes were suggested by the NRC nor are any other changes reguired.
The Model 'T.S. for Shift Technical Advisor is incorporated in Table 6.2-3 and Section 6.3.
This proposed change also incor-porates several proposed changes in the plant and corporate organization submitted by letter dated April 11, 1980.
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