ML18139A832

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Proposed Tech Spec Changes to Amend OLs Incorporating Addl Limiting Conditions of Operation,Surveillance Requirements & Bases for Areas of Instrumentation,Reactor Coolant Sys, Auxiliary Feedwater Sys & Administrative Controls
ML18139A832
Person / Time
Site: Surry  Dominion icon.png
Issue date: 11/14/1980
From:
VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:
Shared Package
ML18139A831 List:
References
NUDOCS 8011190287
Download: ML18139A832 (57)
v • d • e


Text

Objectives To specify those limiting conditions for operation of the Reactor Coolant System which must be met to ensure safe reactor operation.

These conditions relate to: operational components, heatup and cooldown, leakage, reactor coolant activity, oxygen and chloride concentrations, r

minimum temperature for criticality, and reactor coolant system overpres-sure mitigation.

A. Operational Components Specifications

1. Reactor Coolant Pumps
a. A reactor shall not be brought critical with less than two pumps, in non-isolated loops, in operation.
  • TS 3.1-2
b. If an unscheduled loss of one or more reactor coolant pumps occurs while operating below 10% rated power (P-7) and results in less than two pumps in service, the affected plant shall be shutdown and the reactor made subcritical by inserting all control banks into the core. The shutdown rods may remain withdrawn.
c. When the average reactor coolant loop temperature is greater than 350°F, the following conditions shall be met:
1. At least two reactor coolant loops shall be operable.
2. At least one reactor coolant loop shall be in operation.
d. When the average reactor coolant loop temperature is less than or equal to 350°F, the following conditions shall be met:
1. A minimum of two non-isolated loops, consisting of any combination of reactor coolant loops or residual heat removal loops, shall be operable, except as specified in Specification 3.10.A.6.
2. At least one reactor coolant loop or one residual heat removal loop shall be in operation, except as specified in Specification 3.10.A.6.
  • TS 3.1-3
e. Reactor power shall not exceed 50% of rated power with only two pumps in operation unless the overtemperature AT trip setpoints have been changed in accordance with Section 2.3, after which power shall not exceed 60% with the inactive loop ~top valves open and 65% with the inactive loop stop valves closed.
f. When all three pumps have been idle for> 15 minutes, the first pump shall not be started unless: (1) a bubble exists in the pressurizer or (2) the secondary water temperature of each steam generator is less than S0°F above each of the RCS cold leg temperatures.
2. Steam Generator A minimum of two steam generators in non-isolated loops shall be operable when the average reactor coolant temperature is greater than 350°F.
3. Pressurizer Safety Valves
a. One valve shall be operable whenever the head is on the reactor vessel, except during hydrostatic tests.
b. Three valves shall be operable when the reactor coolant average temperature is greater than 350°F, the reactor is critical, or the Reactor Coolant System is not connected to the Residual Heat Removal System.
  • TS 3.1-4
c. Valve lift settings shall be maintained at 2485 psig +/- 1 percent.
4. Reactor Coolant Loops Loop stop valves shall not be closed in more than one loop unless the Reactor Coolant System is connected to the Residual Heat Removal System and the Residual Heat Removal System is operable.
5. Pressurizer
a. The reactor shall be maintained subcritical by at least 1%

until the steam bubble is established and necessary sprays and at least 125 Kw of heaters are operable.

b. With the pressurizer inoperable due to inoperable pressurizer heaters either restore the inoperable heaters within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-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 />.
c. With the pressurizer otherwise inoperable, be in at least hot shutdown with the reactor trip breakers open within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
6. Relief Valves
a. Two power operated relief valves (PORVs) and their associated block valves shall be operable whenever the reactor keff is ~0.99.

b.

  • TS 3.1-5 With one or more PORVs 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) 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 />.
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 />.

Basis Specification 3.1.A-1 requires that a sufficient number of reactor coolant pumps be operating to provide coastdown core cooling flow in the event of a loss of reactor coolant flow accident. This provided flow will maintain the DNBR above 1.30. (l) Heat transfer analyses also show that reactor heat equiva-lent to approximately 10% of rated power can be removed with natural circulation; however, the plant is not designed for critical ope.ration with natural circulation or one loop operation and will not be operated under these conditions.

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 maintain a uni-

. One steam generator capable of performing its heat transfer function will provide sufficient heat removal capability to remove core decay heat after a normal reactor shutdown. The requirement for redundant coolant loops ensures the capability to remove core decay heat when the reactor coolant system average temperature is less than or equal to 350°F. Because of the low-low steam generator water level reactor trip, normal reactor criticality cannot be achieved without water in the steam generators in reactor coolant loops with open loop stop valves. The requirement for two operable steam generators, combined with the requirements of Specification 3.6, ensure adequate heat removal capabilities for reactor coolant system temperatures of greater than 3S0°F.

Each of the pressurizer safety valves is designed to relieve 295,000 lbs.

per hr. of saturated steam at the valve setpoint. Below 350°F and 450 psig in the Reactor Coolant System, the Residual Heat Removal System can remove decay heat and thereby control system temperature and pressure. There are no credible accidents which could occur when the Reactor Coolant System is connected to the Residual Heat Removal System which could give a surge rate exceeding the capacity of one pressurizer safety valve. Also, two safety valves have a capacity greater than the maximum surge rate resulting from complete loss of load.( 2 )

  • TS 3.1-Sb The limitation specified in item 4 above on reactor coolant loop isolation will prevent an accidental isolation of all the loops which would eliminate the capability of dissipating core decay heat when the Reactor Coolant System is not connected to the Residual Heat Removal System.

The requirement for steam bubble formation in the pressurizer when the reactor has passed 1% subcriticality will ensure that the Reactor Coolant System will not be solid when criticality is achieved.

The requirement that 125 Kw 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 maintain natural circulation at hot shutdown.

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 provide 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.

References:

(1) FSAR Section 14.2.9 (2) FSAR Section 14.2.10

1.

  • TS 3.5-2 One residual *heat removal pump may be out of service, provided immediate attention is directed to making repairs.
2. One residual heat removal heat exchanger may be out of service, provided immediate attention is directed to making repairs.

Basis The Residual Heat Removal System is required to bring the Reactor Coolant System from conditions of approximately 350°F and pressures between 400 and 450 psig to cold shutdown conditions. Heat removal at greater temperatures is by the Steam and Power Conversion System. The Residual Heat Removal System is provided with two pumps and two heat exchangers. If one of the two pumps and/or one of the two heat exchangers is not operative, safe operation of the unit is not affected; however, the time for cooldown to cold shutdown conditions is extended.

The NRC requires that the series motorized valves in the line connecting the RHRS and RCS be provided with pressure interlocks to prevent them from opening when the reactor coolant system is at pressure.

References FSAR Section 9.3 - Residual Heat Removal System.

e TS 3.6-1 3.6 TURBINE CYCLE Aj>plicabili ty Applies to the operating status of the Main Steam and Auxiliary Feed Systems.

Objective To define the conditions required in the Main Steam System and Auxiliary Feed System for protection of the steam generator and to assure the capability to remove residual heat from the core during a loss of station power.

Specification A. A unit's Reactor Coolant System temperature or pressure shall not exceed 350°F or 450 psig, respectively, or the reactor shall not be critical unless the five main steam line code safety valves associated with each steam generator in unisolated reactor coolant loops, are operable.

B. To assure residual heat removal capabilities, the following conditions shall be met prior to the commencement of any unit operation that would establish reactor coolant system conditions of 350°F and 450 psig which would preclude operation of the Residual Heat Removal System.

TS 3.6-2

1. Two motor driven auxiliary feedwater pumps shall be operable and one of three auxiliary feedwater pumps for the opposite unit shall be operable.
2. A minimum o,f 96,000 gal of water shall be available in the tornado missile protected condensate storage tank to supply emergency water to the auxiliary feedwater pump suctions. A minimum of 60,000 gal of water shall be available in the tornado protected condensate storage tank of the opposite unit to supply emergency water to the auxiliary feedwater pump suction of that unit.
3. All main steam line code safety valves, associated with steam
  • generators in unisolated reactor coolant loops, shall be operable.

C. Prior to reactor power exceeding 10%, the steam driven auxiliary feedwater pumps shall be operable.

D. System piping, valves, and control board indication required for the operation of the components enumerated in Specification B. 1, 2, 3, and C shall be operable.

E. With one auxiliary feedwater pump inoperable, restore the required auxiliary feedwater 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 following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

F. With two auxiliary feedwater pumps inoperable, 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 the reactor coolant system temperature and pressure less than 3S0°F and 450 psig, respectively, within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

e TS 3.6-3 G. With three auxiliary feedwater pumps inoperable, iDlnediately initiate corrective action to restore at least one auxiliary feedwater pump to operable status as soon as possible.

H. With no operabl~ auxiliary feedwater pump available from the opposite unit, restore one auxiliary feedwater from the opposite unit 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 following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

I. The iodine - 131 activity in the secondary side of any steam generator, in an unisolated reactor coolant loop, shall not exceed 9 curies. Also the specific activity of the secondary coolant system shall be~ 0.10 µCi/cc DOSE EQUIVALENT I-131. If the specific activity of the secondary coolant system exceeds 0.10 µCi/cc DOSE EQUIVALENT I-131, the reactor shall be shutdown and cooled to 500°F or less within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after detection and in the Cold Shutdown Condition within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

J. The requirements of Specification B-2 above may be modified to allow utilization of protected condensate storage tank water with the auxiliary steam generator feed pumps provided the water level is maintained above 60,000 gallons, sufficient replenishment water is available in the 300,000 gallon condensate storage tank, and replenishment of the protected condensate storage tanks is commenced within two hours after the cessation of protected condensate storage tank water consumption.

e e TS 3.6-4 Basis A reactor which has been shutdown from power requires removal of core residual heat. While reactor coolant temperature or pressure is greater than 350°F or 450 psig, respectively, residual heat removal requirements are normally satis-fied by steam bypass to the condenser. If the condenser is unavailable, steam can be released to the atmosphere through the safety valves, power operated relief valves, or the 4 inch decay heat release line.

A minimum of 92,000 gallons of water in the 110,000 gallon condensate tank is sufficient for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of residual heat removal following a reactor trip and loss of all off-site electrical power. If the protected condensate storage tank level is reduced to 60,000 gallons, the immediately available replenishment water in the 300,000 gallon condensate tank can be gravity-feed to the protected tank if required for residual heat removal. An alternate supply

. of feedwater to the auxiliary feedwater pump suctions is also available from the Fire Protection System Main in th.e auxiliary feedwater pump cubicle.

TS 3.6-5 The five main .steam code safety val.ves associated with each steam generator have a total combined capacity of 3,725,575 pounds per hour at their individual set pressure; the total combined capacity of all fifteen main steam code safety valves is 11,176,725 pounds per hour. The ultimate power rating steam flow is 11,167,923 pounds per hour. The combined capacity of the safety valves required by Specification 3.6 always exceeds the total steam flow corresponding to the maximum steady-state power than can be obtained during one, two, or three reactor coolant loop operation.

The operability of the auxiliary feedwater system ensures that the Reactor Coolant System can be cooled down to less than 350°F from normal operating conditions in the event of a total loss of off-site power.

Each motor driven auxiliary feedwater pump is capable of delivering a total feedwater flow of 350 gpm at a pressure of 1080 psig to the entrance of the steam generators. The steam driven auxiliary feedwater pump is capable of delivering a total feedwater flow of 700 gpm at a pressure of 1080 psig to the entrance of the steam generators. This capacity is sufficient to ensure that adequate feed-water flow is available to remove decay heat and reduce the Reactor Coolant system temperature to less than 350°F when the Residual Heat Removal System may be placed in operation.

The availability of the auxiliary feedwater pumps, the protected condensate storage tank, and the main steam line safety valves adequately assures that sufficient residual heat removal capability will be available when required.

e e TS 3.6-6 The limit on steam generator secondary side iodine - 131 activity is /ased on limiting inhalation thyroid does at the site boundary of 1.5 rem after a postulated accident that would result in the release of the entire coJtents of a unit's steam generators to the atmosphere. In this accident, wiih the halogen inventories -in the steam generator being at equilibrium valvel, I-131 would contribute 75 percent of the resultant thyroid dose at the site boundary; the remaining 25 percent of the dose is from other isotopes of iodine. In the

  • analysis, one-tenth of the contained iodine is assumed to reach the slte boundary,

~aking allowance for plate out and retention in water droplets.

The inhalation thyroid dose at the site boundary is given by:

Dose (Rem)= (C) (X/Q) (J:p:,/A) (B.R.)

(.75) (P.F.)

where: C = steam generator I-131 activity (curies)

X/Q = 8.14 x 10- 4 sec/m3 f:p:,/A = 1.48 x 10 6 rem/Ci for I-131

-4 3 B.R. = breathing rate, 3.47 x 10 m /sec.

from TID 14844 P.F. = plating factor, 10 Assuming the postulated accident, the resultant thyroid dose is 1.5 rem.

The steam generator's specific iodine - 131 activity limit is calcullted by dividing the total activity limit of 9 curies by the water volume ofla steam I 3 generator. A full power, with a steam generator water volume of 47.6 M, the specific iodine - 131 limit would be .18 µCi/cc; at zero power, with/ a steam generator water volume of 101 H3 , the specific iodine - 131 limit wo~ld be I

.089 µCi/cc.

II I

I

e e TS 3.6-7 The limitation on secondary system specific activity ensures that the resul-tant off-site radiation dose will be limited to a small fraction of 10 CFR Part 100 limits in the event of a steam line rupture.

References FSAR Section 4 Reactor Coolant System FSAR Section 9.3 Residual Heat Removal System FSAR Section 10.3.1 Main Steam System FSAR Section 10.3.2 Auxiliary Steam System FSAR Section 10.3.5 Auxiliary Feedwater Pumps FSAR Section 10.3.8 Vent and Drain Systems FSAR Section 14.3.2.5 Environmental Effects of a St~am Line Break

e e TS 3.7-1 3.7 INSTRUMENTATION SYSTEMS Operational Safety Instrumentation Applicability:

Applies to reactor and safety features instrumentation systems.

Objectives:

To provide for automatic initiation of the Engineered Safety Features in the event that principal process variable limits are exceeded, and to delineate the conditions of the plant instrumentation and safety circuits necessary to ensure reactor safety.

Specification:

A. For on-line testing or in the event of a sub-system instrumentation channel failure, plant operation at rated power shall be permitted to continue in accordance with TS Tables 3.7-1 through 3.7-3.

B. In the event the number of channels of a particular sub-system in service falls below the limits given in the column entitled Minimum Operable Channels, or Minimum Degree of Redundancy cannot be achieved, operation shall be limited according to the requirement shown in Column 4 of TS Tables 3.7-1 through 3.7-3.

e TS 3.7-2 C. In the event of sub-system instrumentation channel failure permitted by specification 3.7-B, TS Tables 3.7-1 through 3.7-3 need not be observed during the short period of time and operable sub-system channel are tested where the failed channel must be blocked to prevent unnecessary reactor trip.

D. The Engineered Safety Features initiation instrumentation setting limits shall be as stated in TS Table 3.7-4.

E. Automatic functions operated from radiation monitor alarms shall be as st~ted in TS Table 3.7-5.

F. The accident monitoring instrumentation for its associated operable components listed in TS Table 3.7-6 shall be operable in accordance with the following:

1. With the number of operable accident monitoring instrumentation channels less than the total number of channels shown in TS Table 3.7-6, 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 />.
2. With the number of operable accident monitoring instrumentation channels less than the minimum channels operable requirements of TS Table 3.7-6, 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 />.

TS 3.7-3 Basis Instrument Operating Conditions During plant operati9ns, the complete instrumentation system will normally be in service. Reactor safety is provided by the Reactor Protection System, which automatically initiates appropriate action to prevent exceeding established limits.

Safety is not compromised, however, by continuing operation with certain instru-mentation 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 on process control equipment 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. The nuclear instrumentation system channels are not intentionally placed in a tripped mode since the test signal is superimposed on the normal detector signal to test at power. Testing of the NIS power range channel requires: (a) bypassing the Dropped Rod protection from NIS, for the channel being tested; and (b) placing the 6T/T protection channel set that is avg being fed from the NIS channel in the trip mode and (c) defeating the power mismatch section of T control channels when the appropriate NIS channel is avg being tested. However, the Rod Position System and remaining NIS channels still provide the dropped-rod protection. Testing does not trip the system unless a trip condition exists in a concurrent channel.

TS 3.7-4 Instrumentation has been provided to sense accident conditions and to initiate operation of the Engineered Safety Features (l)

Safety Injection System Actuation Protection against a Loss of Coolant or Steam Break Accident is brought about by automatic actuation of the Safety Injection System which provides emergency cooling and reduction of reactivity.

The Loss of Coolant Accident is characterized by depressurization of the Reactor Coolant System and rapid loss of reactor coolant to the containment.

The Engineered Safeguards Instrumentation has been designed to sense these effects of the Loss of Coolant accident by detecting low pressurizer pressure to generator signals actuating the SIS active phase. The SIS active phase is also actuated by a high containment pressure signal brought about by loss of high enthalpy coolant to the containment. This actuation signal acts as a backup to the low pressurizer pressure actuation of the SIS and also adds diversity to protection against loss of coolant.

Signals are also provided to actuate the SIS upon sensing the effects of a steam line break accident. Therefore, SIS actuation following a steam line break is designed to occur upon sensing high differential steam pressure between the steam header and steam generator line or upon sensing high steam line flow in coincidence with low reactor coolant average temperature or low steam line pressure.

e TS 3.7-5 The increase in the extraction of RCS heat following a steam line break results in reactor coolant temperature and pressure reduction. For this reason pro-tection against a steam line break accident is also provided by low pressurizer pressure actuating safety injection.

Protection is also provided for a steam line break in the containment by actuation of SIS upon sensing high containment pressure.

SIS actuation injects highly borated fluid into the Reactor Coolant System in order to counter the reactivity insertion brought about by cooldown of the reactor coolant which occurs during a steam line break accident.

Containment Spray The Engineered Safety Features also initiate containment spray upon sensing a high-high containment pressure signal. The containment spray acts to reduce containment pressure in the event of a loss of coolant or steam line break accident inside the containment. The containment spray cools the containment directly and limits the release of fission products by absorbing iodine should it be. released to the containment.

Containment spray is designed to be actuated at a higher containment pressure (approximately 50% of design containment pressure) than the SIS (10% of design).

Since spurious actuation of containment spray is to be avoided, it is initiated only on coincidence of high-high containment pressure sensed by 3 out of the 4 containment pressure signals provided for its actuation.

e e TS 3.7-6 Steam Line Isolation Steam line isolation signals are initiated by the Engineered Safety Features closing all steam line trip valves. In the event of a steam line break, this action prevents continuous, uncontrolled steam release from more than one steam generator by isolating the steam lines on high-high containment pressure or high steam line flow with coincident low steam line pressure or low reactor coolant average temperature. Protection is afforded for breaks inside or outside the containment even when it is assumed that there is a single failure in the steam line isolation system.

Feedwater Line Isolation The feedwater lines are isolated upon actuation of the Safety Injection System in order to prevent excessive cooldown of the reactor coolant system. This mitigates the effects of an accident such as steam break which in itself causes excessive coolant temperature cooldown.

Feedwater line isolation also reduces the consequences of a steam line break inside the containment, by stopping the entry of feedwater.

Auxiliary Feedwater System Actuation The automatic initiation of auxiliary feedwater flow to the steam generators by instruments identified in Table 3.7-2 ensures that the Reactor Coolant System Decay Heat can be removed following loss of main feedwater flow. This is consistent with the requirements of the "THI-2 Lesson Learned Task Force Status Report", NUREG-05 78, i tern 2. 1. 7. b.

e e TS 3.7-7 Setting Limits

.1. The high containment pressure limit is set at about 10% of design containment pressure. Initiation of Safety Injection protects against loss of coolant( 2 )

or steam iine break( 3 ) accidents as discussed in the safety analysis.

2. The high-high containment pressure limit is set at about 50% of design containment pressure. Initiation of Containment Spray and Steam Line Isolation protects against large loss of coolant( 2 ) or steam line break accidents( 3 ) as discussed in the safety analysis.
3. The pressurizer low pressure setpoint for safety injection actuation is set substantially below system operating pressure limits. However, it is sufficiently high to protect against a loss-of-coolant accident as shown in the safety.analysis. ( 2 )
4. The steam line high differential pressure limit is set well below the differential pressure expected in the event of a large steam line break accident as shown in the safety analysis. ( 3 )
5. The high steam line flow differential pressure setpoint is constant at 40% full flow between no load and 20% load and increasing linearly to 110% of full flow at full load in order to protect against large steam line break accidents. The coincident low Tavg setting limit for SIS and steam line isolation initiation is set below its hot shutdown value.

The coincident steam line pressure setting limit is set below the full load operating pressure. The safety analysis shows that these settings provide protection in the event of a large steam line break. ( 3 )

fl TS 3.7-8 Automatic Functions Operated from Radiation Monitors The Process Radiation Monitoring System continuously monitors selected lines containing or possibly containing, radioactive effluent. Certain channels in this system actuate control valves on a high-activity alarm signal. Additional 4

information on the Process Radiation Monitoring System is available in the FSAR. ( )

Accident Monitoring Instrumentation The operability of the accident monitoring instrumentation in Table 3.7-6 ensures that sufficient information is available on selected plant parameters to monitor and assess these variables during and following an accident. On the pressurizer PORVs, the pertinent channels consist of limit switch indication and acoustic monitor indication. The pressurizer safety valves utilize an acoustic monitor channel and a downstream high temperature indication channel. This capability is consistent with the recommendations of Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident", December 1975, and NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short Term Recommendations".

References (1) FSAR - Section 7.5 (2) FSAR - Section 14.5 (3) FSAR - Section 14.3.2 (4) FSAR - Section 11.3.3

TABLE 3.7-1 REACTOR TRIP INSTRUMENT OPERATING CONDITIONS 1 2 3 4 OPERATOR ACTION IF CONDITIONS OF DEGREE COLUMN 1 OR 2 MIN. OF EXCEPT AS CONDI-*

FUNCTIONAL UNIT OPERABLE CHANNELS REDUN-DANCY PERMISSIBLE BYPASS CONDITIONS TIONED BY COLUMN 3 CANNOT BE MET e

1. Manual 1 Maintain*hot shutdown
2. Nuclear Flux Power Range 3 2 Low trip setting when 2 Maintain hot of 4 power channels greater shutdown than 10% of full power
  • 3. Nuclear Flux Intermediate 1 2 of 4 power channels greater Maintain hot Range than 10% full power shutdown
4. Nuclear Flux Source Range 1 1 of 2 intermediate rang~ 10 Maintain hot channels greater than 10 shutdown amps
5. Overtemperature 6T 2 1 Maintain hot shutdown
6. Overpower 6T 2 1 Maintain hot shutdown
7. Low Pressurizer Pressure 2 1 3 of 4 nuclear power channels Maintain hot and 2 of 2 turbine load shutdown channels less than 10% of rated power
8. Hi Pressurizer Pressure 2 1 Same as Item 7 above Maintain hot shutdown

TABLE 3.7-1 REACTOR TRIP INSTRUMENT OPERATING CONDITIONS 1 2 3 4 OPERATOR ACTION IF CONDITIONS OF DEGREE COLUMN 1 OR 2 MIN. OF EXCEPT AS CONDI-OPERABLE REDUN- PERMISSIBLE BYPASS TIONED BY COLUMN 3 FUNCTIONAL UNIT CHANNELS DANCY CONDITIONS CANNOT BE MET

9. Pressurizer-Hi Water Level 2 1 3 of 4 nuclear power Maintain hot e

channels and 2 of 2 shutdown turbine load channels less than 10% of rated power

10. Low Flow 2/operable loop If inoperable loop Maintain hot channels are not in service shutdown they must be placed in the tripped mode
11. Turbine Trip 2 1 Maintain less than 10% rated power
12. Lo-Lo Steam Generator 2/non-iso- 1/non- Maintain hot Water Level lated loop isolated loop shutdown
13. Underfrequency 4KV Bus 2 1 Maintain hot shutdown
14. Undervoltage 4KV Bus 2 1 Maintain hot shutdown

TABLE 3.7-1

.REACTOR TRIP INSTRUMENT OPERATING CONDITIONS 1 2 3 4 OPERATOR ACTION IF CONDITIONS OF DEGREE COLUMN 1 OR 2 MIN. OF EXCEPT AS CONDI-OPERABLE REDUN- PERMISSIBLE BYPASS TIONED BY COLUMN 3 FUNCTIONAL UNIT CHANNELS DANCY CONDITIONS CANNOT BE MET

15. Control rod misalignment Monitor**

a) rod position deviation 1 Log individual rod positions once/hour, and after a load change

> 10% or after> 30 inches of control rod motion.

b) quadrant power tilt 1 Log individual upper monitor (upper and upper and lower ion lower excore neutron chamber currents once/

detectors) hour and after a load change> 10% or after

> 30 inches of control

16. Safety Injection See Item 1 of TS Table 3.7-2 rod motion e

TABLE 3.7-1 REACTOR TRIP INSTRUMENT OPERATING CONDITIONS 1 2 *3 4 OPERATOR ACTION IF CONDITIONS OF DEGREE COLUMN 1 OR 2 MIN. OF EXCEPT AS CONDI-OPERABLE REDUN- PERMISSIBLE BYPASS TIONED BY COLUMN 3 FUNCTIONAL UNIT CHANNELS DANCY CONDITIONS CANNOT BE MET

17. Low steam generator I/non-iso- Maintain hot water level with lated loop shutdown steam/feedwater I/non-iso-mismatch flow lated loop
    • If both rod misalignment monitors (a and b) inoperable for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or more, the nuclear overpower trip shall be reset to 93 percent of rated power in addition to the increased surveillance noted.

TABLE 3,7-2 ENGINEERED SAFEGUARDS ACTION 1 2 3 4 OPERATOR ACTION MIN. IF CONDITIONS OF DEGREE COLUMN 1 OR 2 MIN. OF EXCEPT AS CONDI-OPERABLE REDUN- PERMISSIBLE BYPASS TIONED BY COLUMN 3 FUNCTIONAL UNIT CHANNELS DANCY CONDITIONS CANNOT BE MET a.

b.

1. SAFETY INJECTION Manual High Containment Press.

1 3

0 1

Cold shutdown*

Cold shutdown (Hi Setpoint)

c. High Differential Press. 2/non-iso- 1/non-iso- Cold shutdown between any Steam Line and lated loop lated loop the Steam Line Header
d. Pressurizer*Low-Low Press. 2 1 Primary Pressure Cold shutdown less than 2000 psig except when reactor is critical
e. High Steam Flow in 2/3 1/steamline *** Reactor Coolant aver- Cold shutdown Steam Lines with Low T 2 T signals 1 age temperature less or Low Steam Line Presl~g 2 sf¥§m Press. 1 than 547°F during Signals heatup and cooldown

TABLE 3.7-2 ENGINEERED SAFEGUARDS ACTION INSTRUMENT OPERATING CONDITIONS 1 2 3 4 OPERATOR ACTION MIN. IF CONDITIONS OF DEGREE COLUMN 1 OR 2 MIN. OF EXCEPT AS CONDI-OPERABLE REDUN- PERMISSIBLE BYPASS TIONED BY COLUMN 3 FUNCTIONAL UNIT CHANNELS DANCY CONDITIONS CANNOT BE MET

2. CONTAINMENT SPRAY e
a. Manual 2 ** Cold shutdown
b. High Containment Press. 3 1 Cold shutdown (Hi-Hi Setpoint)
3. AUXILIARY FEEDWATER
a. Steam Generator Water Level Low-Low
i. Start Motor 2/Stm. Gen. 1 Loop Stop Valve in res- Place inoperable Driven Pumps pective loop closed channel in Tripped ii. Start Turbine 2/Stm. Gen 1 condition within Driven Pumps one hour
b. RCP Undervoltage 2 1 Place inoperable Start Turbine Driven Pump channel in Tripped condition within one hour
c. Safety Injection (All safety injection initiating functions and requirements)

Start Motor Driven Pumps

d. Station Blackout 2 0 Restore inoperable Start Motor Driven Pump channel within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in hot shutdown within next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

TABLE 3.7-2 REACTOR TRIP INSTRUMENT OPERATING CONDITIONS 1 2 3 4 OPERATOR.ACTION MIN. IF CONDITIONS.OF DEGREE COLUMN 1 OR 2 MIN. OF EXCEPT AS CONDI-OPERABLE REDUN- PERMISSIBLE BYPASS TIONED BY COLUMN 3 FUNCTIONAL UNIT CHANNELS DANCY CONDITIONS CANNOT BE MET

e. Trip of Main Feedwater Pumps 1/Pump 1/Pump Restore inoperable Start.Motor Pumps channel within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in hot shutdown within next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
    • Must actuate 2 switches simultaneously
      • With specified minimum operable channels the 2/3 high steam flow is already in the trip mode

TABLE 3.7-3 INSTRUMENT OPERATING CONDITIONS FOR ISOLATION FUNCTIONS INSTRUMENT OPERATING CONDITIONS 1 2 3 4 OPERATOR ACTION IF CONDITIONS OF DEGREE COLUMN 1 OR 2 ,

MIN. OF EXCEPT AS CONDI-FUNCTIONAL UNIT OPERABLE CHANNELS REDUN-DANCY PERMISSIBLE BYPASS CONDITIONS TIONED BY COLUMN CANNOT BE MET 3

e

1. CONTAINMENT ISOLATION
a. Safety Injection See Item No. 1 of Table 3.7-2 Cold shutdown
b. Manual 1 Hot shutdown
c. High Containment Press. 3 1 Cold shutdown (Hi setpoint)
d. High Containment Press. 3 1 Cold shutdown
2. STEAM LINE ISOLATION
a. High Steam Flow in 2/3 lines 1/steamline *** Cold shutdown and 2/3 Low Tav 2 or 2/3 2/T 1 Low Steam Pressure . av2 s1gnal'.s 2 Stm. Press. 1 e

signals

b. High Containment Press. 3 1 Cold shutdown (Hi-Hi Level)
c. Manual 1/line Hot shutdown
3. FEEDWATER LINE ISOLATION
a. Safety Injection See Item No. 1 of Table 3.7-2 Cold shutdown
      • With the specified minimum operable channels the 2/3 high steam flow is already in the trip mode.

TABLE 3.7-4 ENGINEERED SAFETY FEATURE SYSTEM INITIATION LIMITS INSTRUMENT SETTING No. FUNCTIONAL UNIT CHANNEL ACTION SETTING LIMIT 1 High Containment Pressure (High Contain- a) Safety Injection ~5 psig ment PressUij Signal) b) Containment Vacuum Pump Trip c) High Press. Containment Iso.

d) Safety Injecton Contain. !so.

e) F.W. Line Isolation 2 High High Containment Pressure (High High a) Containment Spray ~25 psig Containment Pressure Signals) b) Recirculation Spray c) Steam Line Isolation d) High High Press. Contain. Iso.

3 Pressurizer Low Low Pressure a) Safety Injection ~1,700 psig b) Safety Injection Contain. !so.

c) Feedwater Line Isolation 4 High Differential Pressure Between a) Safety Injection ~150 psi Steam Line and the Steam Line Header b) Safety Injection Contain. !so.

c) F.W. Line Isolation 5 High Steam Flow in 2/3 Steam Lines a) Safety Injection ~40% (at zero load) of full steam flow

~40% (at 20% load) of full steam flow b) Steam Line Isolation ~1101, (at full loa-of c) Safety Injection Contain. Iso. full steam flow d) F.W. Line Isolation Coincident with Low Tavg or Low Steam ~541°F

- Tavg Line Pressure ~500 psig steam line pt'@ssure

TABLE 3. 7'"".4 con't NO. FUNCTIONAL UNIT CHANNEL ACTION SETTING LIMIT 6 AUXILIARY FEEDWATER

a. Steam Generator Water Level Low-Low Aux. Feedwater Initiation ~51, narrow range S/G Blowdown Isolation
b. RCP Undervoltage Aux. Feedwater Initiation ~70% nominal
c. Safety Injection Aux. Feedwater Initiation All S. I. setpoints
d. Station Blackout Aux. Feedwater Initiation ~46.71, nominal
e. Main Feedwater Pump Trip Aux. Feedwater Initiation N.A.

TABLE 3.7-5 AUTOMATIC FUNCTIONS OPERATED FROM RADIATION MONITORS ALARM AUTOMATIC FUNCTION MONITORING ALARM SETPOINT MONITOR CHANNEL AT ALARM CONDITIONS REQUIREMENTS µCI/cc

. -8

1. Process vent particulate Stops discharge from contain. See Specifications Particula;2 ~4x10 and gas monitors vacuum systems and waste 3.11 and 4. 9 Gas ~9xl0 (RM-GW-101 & RM-GW-102) gas decay tanks (shuts, Valve Nos. RCV-GW-160, FCV-GW-260, FCV-GW-101)
2. Component cooling water radiaton monitors Shuts surge tank vent valve HCV-CC-100 See Specifications 3.13 and 4.9

~Twice Background e.

(RM-CC-105 & RM-CC-106)

3. Liquid waste disposal Shuts effluent discharge See Specifications radiation monitors valves FCV-LW-104A and 3.11 and 4.9 (RM-LW-108) FCV-LW-104B
4. Condenser air ejector Diverts flow to the contain- See Specifications ~1.3 radiation monitors ment of the affected unit 3.11 and 4. 9 (RM-SV-111 & RM-SV-211) (Opens TV-SV-102 and shuts TV-SV-103 or opens TV-SV-202 and shuts TV-SV-203)

. -9

5. Containment particulate Trips affected unit's purge See Specifications Particula;~ ~9x10 and gas monitors supply and exhaust fans, 3.10 and 4.0 Gas ~lxlO . ~

(RM-RMS-159 & RM-RMS-160, closes affected unit's RM-RMS-259 & RM-RMS-260) purge air butterfly valves (MOV-VS-lOOA, B, C & Dor MOV-VS-200A, B, C &D)

6. Manipulator crane area Trips affected unit 1 s purge See Specifications ~50 mrem/hr monitors (RM-RMS-162 & supply and exhaust fans, 3.10 and 4.9 RM-RMS-262) closes affected unit's purge air butterfly valves (MOV-VS-lOOA, B, C & Dor MOV-VS-200A, B, C & D

TABLE 3.7-6 ACCIDENT MONITORING INSTRUMENTATION TOTAL NO. MINIMUM CHANNELS INSTRUMENT OF CHANNELS OPERABLE

1. Auxiliary Feedwater Flow Rate 1 per S/G 1 per S/G
2. Reactor Coolant System Subcooling Margin Monitor 2 1
3. PORV Position Indicators 2/valve 1/valve

' ~

4. PORV Block Valve Position Indicator 1/valve I/valve l

' 5. Safety Valve Position Indicators 2/valve I/valve

TS 3.10-1 3.10 REFUELING

,Applicability Applies to operating* limitations during refueling operations.

Ojective To assure that no accident could occur during refueling operations that would affect public health and safety.

Specification

, A. During refueling operations the following conditions are satisfied:

I. The equipment door and at least one door in the personnel air lock shall be properly closed. For those systems which provide a direct path from containment atmosphere to the outside atmosphere, all automatic containment isolation valves in the unit shall be operable or at least one,valve shall be closed in each line penetrating the containment.

2. The Containment Vent and Purge System and the area and airborne radiation monitors which initiate isolation of this system, shall be tested and verified to be operable immediately prior to refueling operations.

e - TS 3.10-2

3. At least one source range neutron detector shall be in service at all times when the reactor vessel head is unbolted. Whenever core geometry or coolant chemistry is being changed, subcritical neutron flux shall be continuously monitored by at least two source range neutron detectors, each with continuous visual indi-cation in the Main Control Room and one with audible indication within the containment. During core fuel loading phases, there shall be a minimum neutron count rate detectable on two operating source range neutron detectors with the exception of initial core loading, at which time a minimum neutron count rate need be established only when there are eight (8) or more fuel assemblies loaded into the reactor vessel.
4. Manipulator crane area radiation levels and airborne activity levels within the containment and airborne activity levels in the ventilation exhaust duct shall be continuously monitored during refueling. A manipulator crane high radiation alarm or high airborne activity level alarm within the containment will automatically stop the purge venti-lation fans and automatically close the containment purge isolation valves.
5. Fuel pit bridge area radiation levels and ventilation vent exhaust airborne activity levels shall be continuously monitored during refueling. The fuel building exhaust will be continuously bypassed through* the iodine filter bank during refueling procedures, prior to discharge through the ventilation vent.

e TS 3.10-3

6. .At least one residual heat removal pump and heat exchanger shall be operable to circulate reactor coolant. The residual heat removal loop may be removed from operation for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> period during the performance of core alterations or reactor vessel surveil-lance inspections.
7. Two residual heat removal pumps and heat exchangers shall be operable to circulate reactor coolant when the water level above the top of the reactor pressure vessel flange is less than 23 feet.
8. At least 23 feet of water shall be maintained over the top of the reactor pressure vessel flange during movement of fuel assemblies.
9. When the reactor vessel head is unbolted, a minimum boron concen-tration of 2,000 ppm_ shall be maintained in any filled portion of the Reactor Coolant System and shall be checked by sampling at least once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
10. Direct communication between the Main Control Room and the refueling cavity manipulator crane shall be available whenever changes in core geometry are taking place.
11. No movement of irradiated fuel in the reactor core shall be accomplished I until the reactor has been subcritical for a period of at least 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />.
  • ,__.,.,*., ,\* -***. _ .,.,. *--**---* *.,. -,* ***~-'.\, -*. . ~ ..-.J~----- **--~~----* ._. . .,__

_._w. - * --.~--,-.-*** *. ..... -... , ... -~---~-----*- ~*-****** -"-***-*~ ----......-~***

e e TS 3.10-4

12. A spent fuel cask or heavy loads exceeding 110 percent of the weight I

of a fuel assembly (not including fuel handling tool) shali not be moved over spent fuel, and only one spent fuel assembly will be handled at one time over the reactor or the spent fuel pit.

13. A spent fuel cask shall not.be moved into the Fuel Building until such time as the NRC has reviewed and approved the spent fuel cask drop evaluation.

B. If any one of the specified limiting conditions for refueling is not met, refueling of the reactor shall cease, work shall be initiated to correct the conditions so that the specified limit is met, and no operations which increase the reactivity of the core shall be made.

C. After initial fuel loading and after each core refueling operation and prior to reactor operation at greater than 75% of rated power, the movable incore detector system shall be utilized to verify proper power distribution.

Basis Detailed instructions, the above specified precautions and the design of the fuel handling equipment, which incorporates built-in interlocks and safety features, provide assurance that an accident, which would result in a hazard to public health and safety, will not occur during refueling operations.

When no change is being made in core geometry, one neutron detector is

-***"<"**-""'.* __ a.-,,..* ,.., ... - * -v~ * .* * .....__ *.~.._ ..* - - * - * * * * - - - * * * * - - - - * - * - - * * " * ~ *"*-*~** *** ,._ ... ,._ .*;

--** - *Jo - ' *- ** * **- - ** *- * - ~ * ..__ * * * * * , * . , - . * -*~***-

TS 3.10-5 sufficient to monitor the core and permits maintenance of the out-of-function instrumentation. Continuous monitoring of radiation levels and neutron flux provides immediate indication of an unsafe condition. Containment high radiation levels and high airborne activity levels automatically stop and isolate the Containment Purge System. The fuel building ventilation exhaust is diverted through charcoal filters whenever refueling is in progress. At least one flow path is required for cooling and mixing the coolant contained in the reactor vessel so as to maintain a uniform boron concentration and to remove residual heat.

The shutdown margin established by Specification A-8 maintains the core subcritical, even with all of the control rod assemblies withdrawn from the core.

During refueling, the reactor refueling water cavity is filled with approximately 220,000 gal of water borated to at least 2,000 ppm boron. The boron concentra-tion of this water is sufficient to maintain the reactor subcritical by approxi-mately 10% A k/k in the cold shutdown condition with all control rod assemblies inserted and also to maintain the core subcritical by approximately 1% with no control rod assemblies inserted into the reactor. Periodic checks of refueling water boron concentration assure the proper shutdown margin. Specification A-9 allows the Control Room Operator to inform the manipulator operator of any impending unsafe condition detected from the main control board indicators during fuel movement.

In addition to the above safeguards, interlocks are used during refueling to assure safe handling of the fuel assemblies. An excess weight interlock is provided on the lifting hoist to prevent movement of more than one fuel assembly at a time. The spent fuel transfer mechanism can accomodate only one fuel assembly at a time.

l_

TS 3.10-6 Upon each completion of core loading and installation of the reactor vessel head, specific mechanical and electrical tests will be performed prior to initial criticality.

The fuel handling accident has been analyzed based on the activity that could be released from fuel rod gaps of 204 rods of the highest power assembly* with a 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> decay period following power operation at 2550 MWt for 23,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />.

The requirements detailed in Specification 3.10 provide assurance that refueling unit conditions conform to the operating conditions assumed in the accident analysis.

Detailed procedures and checks insure that fuel assemblies are loaded in the proper locations in the core. As an additional check, the moveable incore detector system will be used to verify proper power distribution. This system is capable of revealing any assembly enrichment error or loading error which could cause power shapes to be peaked in excess of design value.

  • Fuel rod gap activity from 204 rods of the highest power 15x15 assembly is greater than fuel rod gap activity from 264 rods of the highest power 17x17 demonstration assembly.

e TS 3.10-7 References

  • FSAR Section 5.2 Containment Isolation FSAR Section 6.3 Consequence Limiting Safeguards FSAR. Section 9.12 Fuel Handling System FSAR Section 11.3 Radiation Protection FSAR Section 13.3' Table 13.3-1 FSAR Section 14.4.1 Fuel Handling Accidents FSAR Supplement: Volume I: Question 3.2

e e TS 4.1-1 4.1 OPERATIONAL SAFETY REVIEW Applicability Applies to items directly related to safety limits and limiting conditions for operation.

Objective To specify the minimum frequency and type of surveillance to be applied to unit equipment and conditions.

Specification A. Calibration, testing, and checking of instrumentation channels shall be performed as detailed in Table 4.1-1.

B. Equipment tests shall be conducted as detailed below and in Table 4.l-2A.

1. Each Pressurizer PORV shall be demonstrated operable:
a. At least once per 31 days by performance of a channel functional test, excluding valve operation, and
b. At least once per 18 months by performance of a channel calibration.

e e TS 4.1-la

2. Each Pressurizer PORV block valve shall be demonstrated operable.at least once per 92 days by operating the valve through one complete cycle of full travel.
3. The pressurizer water volum~ shall be determined to be within its limit as defined in Specification 2.3.A.3.a at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> whenever

. the reactor is not subcritical by at least 1% .Mc/k.

C. Sampling tests shall be conducted as detailed in Table 4.l-2B.

D. Whenever containment integrity is not required, only the asterisked items in Table 4.1-1 and 4.l-2A and 4.l-2B are applicable.

E. Flushing of sensitized stainless steel pipe sections shall be conducted as detailed in TS Table 4.l-3A and 4.l-3B.

TABLE 4.1-1 MINIMUM FREQUENCIES FOR CHECK, CALIBRATIONS AND TEST OF INSTRUMENT CHANNELS CHANNEL DESCRIPTION CHECK CALIBRATE TEST REMARKS

1. Nuclear Power Range s D (1) BW(2) 1) Against a heat balance standard M(3) Q (3) 2) Signal of flT; bistable action . .

(permissive, rod stop,*strips) .ill

3) Upper and lower chambers for symelPf'c offset by means of the moveable incore detector system.
2. Nuclear Intermediate Range *S(l) N.A. P(2) 1) Once/shift when in service
2) Log level; bistable action (permissive, rod stop, trip)

. 3. Nuclear Source Range *S(l) N.A. P(2) 1) Once/Shift when in service

2) Bistable action (alarm, trip)
4. Reactor Coolant Temperature *S R BW(l) 1) Overtemperature - flT BW(i) 2) Overpower - flT
s. Reactor Coolant Flow s R M
6. Pressurizer Water Level s R M
7. Pressurizer Pressure (High & s R M Low)
8. 4 Kv Voltage and Frequency s R M Reactor protection circuit only
9. Analog Rod Position *S(l,2) R M(3) 1) With step counters (4) 2) Each six inches of rod motion when data logger is out of service
3) Rod bottom bistable action
4) NA when reactor is in cold shut-down

TABLE 4.1-1 (Continued)

CHANNEL DESCRIPTION CHECK CALIBRATE TEST REMARKS

10. *Rod Position Bank Counters S(l ,2) N.A. N.A. 1) Each six inches of rod motion when data logger is out of service
2) With analog rod position
11. Steam Generator Level s R M
12. Charging Flow N.A. R N.A.
13. Residual Heat Removal Pump Flow N.A R N.A.
14. Boric Acid Tank Level *D R N.A.

ISA. Unit 1 Refueling Water Storage w R N.A.

Tank Level 15B. Unit 2 Refueling Water Storage s R M Tank Level

16. Boron Injection Tank Level 1 w N.A. N.A.
17. Volume Control Tank Level N.A.* R N.A.
18. Reactor Containment Pressure-CLS *D R M(l) 1) Isolation Valve signal and spray signal
19. Processing and Area Radiation *D R M e

Monitoring Systems

20. Boric Acid Control N.A. R N.A.
21. Containment Sump Level N.A. R N.A.
22. Accumulator Level and Pressure s R N.A.
23. Containment Pressure-Vacuum Pump s R N.A.

System

24. Steam Line Pressure s R M

TABLE 4.1-1 CHANNEL DESCRIPTION CHECK CALIBRATE TEST REMARKS

25. Turbine First Stage Pressure s R M
26. Emergency Plan Radiation Instr. *M R M
27. Environmental Radiation Monitors *M N.A. N.A. TLD Dosimeters
28. Logic Channel Testing N.A. N.A. M
29. Turbine,Overspeed Protection N.A. R R Trip Channel (Electrical)
30. Turbine Trip Setpoint N.A. R R Stop valve closure or low EH fluid pressure e
31. Seismic Instrumentation M SA M
32. Reactor Trip Breaker N.A. N.A. M
33. Reactor Coolant Pressure (Low) N.A. R N.A.
34. Auxiliary Feedwater

.a. Steam Generator Water s R M Level Low-Low

b. RCP Undervoltage N.A. R N.A.
c. s. I. (All Safety Injection surveillance requirements)
d. Station Blackout N.A. R N.A.
e. Main Feedwater Pump Trip N.A. N.A. R S - Each shift M - Monthly D Daily P Prior to each startup if not done previous week W - Weekly R - Each Refueling Shutdown NA - Not applicable BW - Every two weeks SA - Semiannually AP - After each startup if not done previous week Q - Every 90 effective full power days
  • See Specification 4.lD

TABLE 4.1-2

. ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

1. Auxiliary Feedwater Flow Rate N.A. R
2. Reactor Coolant System Subcooling Margin Monitor M R
3. PORV Position Indicators M R
4. PORV Block Valve Position Indicator N.A. R e,
5. Safety Valve Position Indicators M R

TABLE 4.1-2A MINIMUM FREQUENCY FOR EQUIPMENT TESTS FSAR SECTION DESCRIPTION TEST FREQUENCY REFERENCE

1. Control Rod Assemblies Rod drop times of all full length Each refueling shutdown or after 7 rods at hot and cold conditions disassembly or maintenance re-quiring the breech of the Reactor Coolant System integrity
2. Control Room Assemblies Partial movement of all rods Every 2 weeks 7
3. Refueling Water Chemical Functional Each refueling shutdown 6 4.

Addition Tank Pressurizer Safety Valves Setpoint Each refueling shutdown 4' *-*

s. Main Steam Safety Valves Setpoint Each refueling shutdown 10
6. Containment Isolation Trip *Functional Each refueling shutdown 5
7. Refueling System Interlocks *Functional Prior to refueling 9.12
8. Service Water System *Functional Each refueling shutdown 9.9
9. Fire Protection Pump and Functional Monthly 9.10 Power Supply
10. Primary System Leakage *Evaluate Daily 4
11. Diesel Fuel Supply *Fuel Inventory 5 days/week 8.5 e
12. Boric Acid Piping Heat ,'I-Operational Monthly 9.1 Tracing Circuits
13. Main Steam Line Trip Functional 10 (1) Full closure (1) Each cold shutdown (2) Partial closure (2) Before each startup

TABLE 4.1-2A MINIMUM FREQUENCY FOR EQUIPMENT TESTS FSAR SECTION DESCRIPTION TEST FREQUENCY REFERENCE

14. Service Water System Valves Functional Each refueling 9.9 in Line Supplying Recircu-lation Spray Heat Exchangers
15. Control Room Ventilation *Ability to maintain positive pres- Each refueling interval 9.13 System sure for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> using a volume of (approx. every 12-18 months) ,,

air equivalent to or less than stored in the bottled air supply

16. Reactor Vessel Overpressure Functional & Setpoint Prior to decreasing RCS None Mitigating System (except temperature below 350°F backup air supply) .and monthly while the RCS is <350°F and the Reactor Vessel Head is bolted
17. Reactor Vessel Overpressure Setpoint Refueling None Mitigating System Backup Air Supply
  • See Specification 4.1.D

e e TS 6.1-1 6.0 ADMINISTRATIVE CONTROLS 6.1 ORGANIZATION, SAFETY AND OPERATION REVIEW Specification A. The Station Manager shall be responsible for the safe operation of the facility. In his absence, the Assistant Station Manager shall be responsible for the safe operation of the facility. During the absence of both, the Station Manager shall delegate in writing the succession to this responsibility.

1. The offsite organization for facility management and technical support shall be as shown on TS Figure 6.1-1.

B. The Station organization shall conform to the chart as shown on TS Figure 6.1-2.

1. Each member of the facility staff shall meet or exceed the minimum qualifications of ANSI N.18.1-1971 for comparable positions, and the supplemental requirements specified in the March 28, 1980 NRC letter to all licensees, except for the Supervisor-Health Physics who shall meet or exceed the qualifications of Regulatory Guide 1.8, September 1975.
  • e TS 6.1-2
2. The Shift Technical Advisor shall have a bachelor's degree or equivalent in~ scientific or engineering discipline with specific training in plant design and response and analysis of the plant for transients and accidents. The requirement for the Shift Technical Advisor becomes effective _on January 1, 1981.
3. The Station Manager is r~ponsible for ensuring that retraining and replacement training programs for the facility staff are maintained and that such programs meet or exceed the requirements and recoDDDendations of Section 5.5 of ANSI Nl8.l-1971 and Appendix "A" of 10 CFR Part 55 and the supplemental requirements specified in the March 28, 1980 NRC letter to all licensees, and shall include familiarization with relevant industry operational experience identified by the SEC staff.
4. Each on duty shift shall be composed of at least the minimum shift crew composition for each unit as shown in Table 6.1-1.
5. A health physics technician shall be on site when fuel is in the reactor.
6. A fire team of at least five members, all of whom have received fire service training, will be maintained on-site at all times.

This excludes personnel in Table 6.1-1 of the minimum shift crew necessary for safe shutdown of the plant and any personnel requried for other essential functions during a fire emergency.

7.

  • e TS 6.1-3 A training program for the fire brigade and fire teams shall be main-tained under the directions of a Fire Marshall and ahall meet or exceed the requirements of the NFPA Code Section 27 (1975), except that training sessions and drills shall be held at least once per 92 days.
8. The health.physics technician and Fire Brigade composition of Specifi-cations 6.1.B.5 and 6.1.B.6

,. may be less than the minimum requirement for a period of time not to exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in order to accomodate unexpected absence provided illlnediate action is taken to fill the required positions.

  • e TS 6.1-4 TABLE 6.1-1 MINIMUM SHIFI' CREW COMPOSITION POSITION NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION ONE UNIT TWO UNITS TWO UNITS IN COLD OPERATING OPERATING SHUTDOWN OR REFUELING ss 1 1 1 SRO 1 1 None RO 3 3 2 AO 3 3 3 STA 1 1 None
  • TABLE 6.1-1 (Continued)

TS 6.1-5 SS Shift Supervisor with a Senior Reactor Operators License.

  • -SRO Individual with a Senior Reactor Operators License.

RO Individual with a Reactor Operators License.

AO Auxiliary Operator

  • sTA Shift Technical Advisor

.lzcept for the Shift Supervisor, the Shift Crew Composition may be one less than the minimum requirements of Table 6.1-1 for a period of time not to

~xceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.in order to accomodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the Shift Crew Composition to within the minimum requirements of Table 6.1-1. This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift crewman being late or absent.

During any absence of the Shift Supervisor from the Control Room while the unit is in operation, an individual (other than the Shift Technical Advisor) with a valid SRO license shall be designated to assume the Control Room command function. During any absence of the Shift Supervisor from the Control Room while the unit is shutdown or refueling, an individual with a valid RO license (other than the Shift Technical Advisor) shall be designated to assume the Control Room coDmland functions.

H.

  • TS 6.4-6 Practice of site evacuation exercises shall be conducted annually, following emergency procedures and including a check of communications with off-site report groups. An annual review of the Emergency Plan will be performed.

I. The industrial security program which has been established for the station shall be implemented, and appropriate investigation and/or corrective action shall be taken if the provisions of the program are violated. An annual review of the program shall be performed.

J. The facility fire protection program and implementing procedures which have been established for the station s4all be implemented. The program shall be reviewed at least once every two years.

K Systems Integrity 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. Integrated leak test requirements for each system at a frequency not to exceed refueling cycle intervals.
____ -~* ..:. ----****'-*-* *.... :. .. ~--*. -~------,-*,- .._.; . _,~.--* *- *-** --- ...... * -----*-**--~----..*-***

TS 6.4-7 I;

L. Iodine Monitoring The licensee shall implement a program which will ensure the capability to accurately determine the airborne iodine concentration in vital area under

~'

accident conditions. This program shall include the following:

1. Training of personnel,
2. Procedures for monitoring, and
3. Provisions for maintenance of sampling and analysis equipment.
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