ML20132C613
| ML20132C613 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 07/24/1985 |
| From: | GEORGIA POWER CO. |
| To: | |
| Shared Package | |
| ML20132C607 | List: |
| References | |
| TAC-59309, NUDOCS 8507300406 | |
| Download: ML20132C613 (66) | |
Text
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VI. PROPOSED TECHNICAL SPECIFICATIONS REVISIONS-The Technical Specifications'for HNP-1 (Appendix A to Operating License DPR-57) are proposed for revision as presented in this section. Table 6.1 provides the instructions for incorporating the revision (s).
O-O _.
8507300406 850724 6~I PDR ADOCK 05000321 P PDR
t A TABLE 6.1 U.
INSTRUCTIONS FOR INCORPORATING TECHNICAL SPECIFICATIONS REVISIONS L If the Technical Specifications revisions are accepted as proposed, the HNP-1 Technical Specifications (Appendix A to Operating License DPR-57) should be incorporated as follows:
n i Deletions Insertions Applicable SER*ca>
l Item (Page) (Page) Section(s) 1 1.1-3 1.1-3 4.B.4 2 1.1-5 1.1-5 4.B.4 l 3 Fig. - 2.1-1 Fig. 2.1-1 4.B.4 4 1.2-2 1.2-2 4.B.7 l 5 1.2-6 1.2-6 4.B.7 l 6 3.1-4 3.1-4 4.B.4, 4.B.7 7 3.1-7 3.1-7 ATTS l 8 3.1-12 3.1-12 4.B.7 3.2-2 3.2-2 9 4.B.4, 4.B.6, 4.B.7, 10 3.2-3 3.2-3 4.8.6, 4.B.7 11 3.2-5 3.2-5 4.B.4, 4.B.6, 4.B.7 12 3.2-6 3.2-6 4.B.6, 4.B.7 13 3.2-8 3.2-8 4.B.1, 4.B.4, 4,8.6, 4.B.7
.O 14 15 3.2-9 3.2-10 3.2-9 3.2-10 4.8.8. 4.B.7 4.B.2, 4.B.4, 4.B.6, 4.B.7 16 3.2-11 3.2-11 4.B.2, 4.B.4, 4.B.5, 4.B.6, 4.B.7 17 3.2-12 3.2-12 4.B.6, 4.B.7 18 3.2-14 3.2-14 4.B.1, 4.B.4, 4.B.5, 4.B.6, 4.B.7 19 3.2-22 3.2-22 4.B.3, 4.B.6 20 3.2-24 3.2-24 ATTS, 4.B.6 21 3.2-25 3.2-25 ATTS, 4.B.6 22 3.2-27 3.2-27 ATTS, 4.B.6 23 3.2-28 3.2-28 ATTS, 4.B.6 24 3.2-30 3.2-30 ATTS, 4.B.6 25 3.2-31 3.2-31 ATTS, 4.B.6 26 3.2-32 3.2-32 ATTS 27 3.2-33 3.2-33 ATTS 28 3.2-34 3.2-34 ATTS 29 3.2-35 3.2-35 ATTS, 4.B.6, 4.B.7 30 3.2-36 3.2-36 ATTS 31 3.2-38 3.2-38 ATTS, 4.B.6, 4.B.7 4 32 3.2-39 3.2-39 ATTS 33 3.2-48 3.2-48 4.B.3, 4.B.6 34 3.2-49 3.2-49 4.B.3 35 3.2-50 3.2-50 4.B.4 36 3.2-50a 3.2-50a 4.B.4 37 3.2-51 3.2-51 4.B.7 38 3.2-52 3.2-52 4.B.4, 4.B.6, 4.B.7 39 3.2-53 3.2-53 ATTS, 4.B.6, 4.B.7 O 40 3.2-54 3.2-54 4.B.6, 4.B.7 6-2
~% Deletions Insertions Applicable SER.<a>
x_,) Item (Page) (Page) Section(s) 41 3.2-55 3.2-55 ATTS, 4.B.4, 4.B.6, 4.B.7 42 3.2-56 3.2-56 ATTS, 4.B.6, 4.B.7 43 3.2-57 3.2-57 4.B.6, 4.B.7 i 44 3.2-58 3.2-58 4.B.4, 4.B.7 45 3.2-59 3.2-59 4.B.7 46 3.2-60 3.2-60 4.B.4, 4.B.5, 4.8.6, 4,B.7 47 3.2-61 3.2-61 ATTS, 4.B.4, 4.B.6, 4.B.7 48 3.2-62 3.2-62 4.B.4, 4.B.5, 4.B.7 49 3.2-63 3.2-63 ATTS, 4.B.7 50 3.7-19 3.7-19 4.B.6 l
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!v )
I SER - Safety Evaluation Report
- a. 1. ATTS refers to proposed revisions justified in Section III of this submittal.
es 2. 48.1 through 48.7 refer to justifications presented in Section IV (v) of this submittal.
6-3
- - - -. . . . ~ . . .... . .- . . - .. . . ... .- - . . . -. - ._
,m 1
'1 ' ' SAFETY LIMITS LIMITING SAFETY SYSTEM SETTINGS 2.1.A.1.d APRM Rod Block Trip Setting This s'ection deleted I
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O t
2.1.A.2. Reactor Vessel Water Low Level Scram Trip Setting (Level 3)
Reactor vessel water low level scram l trip setting (Level 3) shall be ';
- 2 10.0 inches (narrow range scale). l
- 3. Turbine Stop Valve Closure Scram Turbine stop valve closure scram trip setting shall 5e s 10 percent valve closure from full open. This scram is onl/ effective when tur-
. bine steam flow is above that corres-ponding to 3b% of rated core thermal
- ~s, p/ power, as measured by turbine first L stage pressure.
l.
- 1.1-3
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~2 SAFETY LIMITS LIMITING SAFETY SYSTEM SETTINGS 2.1.B. Reactor Vessel Water tevel Trip Settings Which Initiate Core Standby Cool-ing Systems (CSCS)
Reactor vessel water level trip settings which initiate core standby cool-ing systems shall be as shown in Tables 3.2-2 thru 3.2-6 at normal operating conditions.
- 1. HPCI Actuation (Level 2)
HPCI actuation (Level 2) shall occur at a water level 2 -47 l inches.
- 2. Core Spray and LPCI Actuation (Level 1)
Core Spray and LPCI actuation (Level 1) shall occur at a water level 2 -113 inches. l
/m s-
!!o) 1.1-5 l
- "T NOTE: SCALE IN INCHES ABOVE VESSEL ZERO f WATER LEVEL NOMENCLATURE
(/ HEIGHT ABOVE 800 - - VESSEL ZERO g flNCHES) READING INSTRUMENT (8) 573.5 + 56.5 BARTON/ROSEMOUNT 750 -- (7) 559 +42 GE/MAC
- (4) 549 +32 GE/MAC
- - 723.56 FLANGE (3) 527 +10.0 BARTON/ROSEMOUNT
' (2) 470 -47 BARTON/ROSEMOUNT 700 - -
404 -113 BARTON/ROSEMOUNT (1)
(0) 315 -202 BARTON/ROSEMOUNT 650 -- MAIN STE AM
-- 640 -
LINE f
600 --
577
- 573.5 (8) +60 - - +60 - +60 - -
+60--
% - 559 (7) (8)- 56.5 (7) 42 Hi ALARM 550 -= 54 9(4) HPCI& (4) '32 LO ALARM RCIC TRIPS (3) -10.0 LOW (LEVEL 3)
BOTTOM OF STE AM - 527(3) ~1' O-- 0 -- REACTOR f
-ORYER SKIRT 517 INSTRUMENT 0-0 R CONTRIBUTE TO ADS SCRAM 500 --
17 -.- FEEO - - 47 LOW LOW REVEL 2)
WATER
- 470 (2) CORE % [
465 g INITIATE HPCI, RCIC, PRAY 450 --
8 400 -- - -113 LOW LOW LOW (LEVEL 1)
INITIATE RHR, C.S.,
- 367 -150 - -
352.56 START DIESEL AND 350- " CONTRl8UTE TO A.D.S.
CLOSE MSIV'S 2/3 CORE
-202 HEIGHT 315 (0)
PERMISSIVE 300 -- la (LEVEL 01 ACTIVE FUEL 250--
317 I- 200 ' = 208.56
~ ~ ' "
RECIRC NOZZLE ,
SUCTION - 161.5 NOZZLE 150 --
100 --
6 50 --
0--
9380-2 A FIGURE 2.1 1 <
/ '
)
k/ REACTOR VESSEL WATER LEVEL i
SAFETY LIMITS LIMITING SAFETY SYSTEM SETTINGS 2.2.A Nuclear System pressure (cont.)
The allowable setpoint relief error for each valve shall be + 1%. In the event that an instalIed safety-relief valve requires replacement, a spare valve whose setpoint is lower than that of the failed valve may be substituted for the failed valve until the first refueling outage following such substitution.
No more than two valves with lower setpoints may be substituted in place of valves with higher setpoints. Spare valves which are used as substitutes under the abovementioned provisions shall have a setpoint equal to 1080 psig +1%
or 1090 psig +1%,
1.2.A.2. - When Operating The RHR Sys- 2.1.A.2. When Operating The RHR System tem in the Shutdown Cooling in the Shutdown Cooling Mode Mode
() The reactor vessel steam dome The reactor pressure trip set-ting which closes (on increas-ing pressure) or permits open-pressure shall not exceed 162 psig at any time when operat- ing (on decreasing pressure) of ing the RHR system in the Shut- the shutdown cooling isola-down Cooling Mode. tion valves shall be s 145 psig. l l,
O 1.2-2
BASES FOR LIMITING SAFETY SYSTEM SETTINGS 2.2 REACTOR COOLANT SYSTEM INTEGRITY A. Nuclear System Pressure
- 1. When Irradiated Fuel is in the Reactor The 11 relief / safety valves are sized and set point pressures are estab-lished in accordance with the following requirements of Section III of the ASME Code:
- a. The lowest relief / safety valve must be set to open at or below vessel design pressure and the highest relief / safety valve must be set to open at or below 105% of design pressure.
- b. The valves must limit the reactor pressure to no more than 110% of design pressure.
The primary system relief / safety valves are sized to limit the primary system pressure, including transients, to the limits expressed in the ASME Boiler and Pressure Vessel Code,Section III, Nuclear Vessels.
No credit is taken from a scram initiated directly from the isolation event, or for power operated relief / safety valves, sprays, or other power operated pressure relieving devices. Thus, the probability of failure of the turbine generator trip SCRAM or main steam isolation valve closure SCRAM is conservatively assumed to be unity. Credit is taken for subsequent indirect protection system action such as neutron
/G flux SCRAM and reactor high pressure SCRAM, as allowed by the ASME d Code. Credit is also taken for the dual relief / safety valves in their ASME Code qualified mode of safety operation. Sizing on this basis is applied to the most severe pressurization transient, which is the main steam isolation valves closure, starting from operation at 105 percent of the reactor warranted steamflow condition.
Reference 2, Figure 4 shows peak, vessel bottom pressures attained when the main steam isolation valve closure transients are terminated by various modes of reactor scram, other than that which would be initiated clirectly from the isolation event (trip scram). Relief /
safety valve capacities for this analysis are 84.0 percent, represen- .
tative of the 11 relief / safety valves.
The relief / safety valve settings satisfy the Code requirements for relief / safety valves that the lowest valve set point be at or below the vessel design pressure of 1250 psig. These settings are also sufficiently above the normal operating pressure range to prevent unnecessary cycling caused by minor transients. The results of postu-lated transients where inherent relief / safety valve actuation is required are given in Section 14.3 of the FSAR.
- 2. When Operating the RHR System in the Shutdown Cooling Mode An interlock exists in the logic for the RHR shutdown cooling valves, which are normally closed during power operation, to prevent opening of n the valves above a preset pressure setpoint of 145 psig. This setpoint is selected to assure that pressure integrity of the RHR system is
(") tained. Administrative operating procedures require the operator to 4
1.2-6
O O O Table 3.1-1 (Cont'd)
Scram Operable Number Source of Scram Trip Signal Channels Scram Trip Setting Source of Scram Signal is Required Per Required to be Operable (a) Trip System Except as Indicated Below (b)
Not required to be operable when l 2 < l.92 psig 5 Drywell Pressure-High primary containment integrity is not required. May be bypassed when necessary during purging for containment inerting or deinerting.
2 > 10.0 inches l w 6 Reactor Vessel Water Level - ~
Low (Level 3)
^
Permissible to bypass (initiates 7 Scram Discharge Volume sligh control rod block) in order to High Level reset RPS when the Mode Switch is in the REFUEL or SHUTDOWN position.
- a. Float Swltches 2 171 gallons
- b. Thermal Level Sensors 2 171 gallons 8 APRM Flow Referenced Simulated 2 S < 0.66W+62%
Thermal Power Monitor (Not Spec Tech to exceed 2.1.A.I.c117%)(1)
Fixed High-liigh Neutron 2 S < 120% Power Flux Tech Spec 2.1. A.1.c (2) 2 Not Applicable An APRM is inoperable if there Inoperative are less than two LPRM inputs per level or there are less than 11 LPRM inputs to the APRM channel.
O O O Table 4.1-1 Reactor Protection System (RPS) Instrumentation Functional Test, Functional Test Minimum Frequency, and Calibration Minimum Frequency i'
Scram . Instrument Functional Test Instrument Calibration Number Source of Scram Trip Signal Group Minimum Frequency Minimus Frequency (a) (b) (c) 1 Mode Switch in SHUTDOWN A Once/ Operating Cycle Not Applicable 2 Manual Scram A Every 3 months Not Applicable 1 3 IRM High High Flux C Once/ Week during refueling Once/ Week i and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of Startup (e)
) Inoperative C Once/ week during refueling Once/ Week.
and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of Startup (e)
F 4 Reactor Vessel Steam Dome D Once/ Month Once/ operating cycle y Pressure - High
- 4 "
- 5 Drywell Pressure-High D Once/ Month Once/ operating cycle 6 Reactor Vessel Water Level - D Once/ Month (g) Once/ Operating Cycle i Low (Level 3) 7 Scram Discharge Volume High High i Level
- a. Float Switches A Once/ Month (f) (h) l b. Thermal Level Sensors B Once/ Month (f) Once/ operating cycle l 8 APRM Fixed High-High Flux B Once/ Week (e) Twice/ Week i
i Inoperable B Once/ Week (e) Twice/ Week i
Downscale B Once/ Week (e) Twice/ Week l
I Flow Reference Simulated B Once/ Week (f) Once/ Operating Cycle
- Thermal Power Monitor I 15% Flux C Within 24 Hours of Startup (e) Once/ Week t'
3.1.A.4. Reactor Vessel Steam Dome Pressure - High (Continued) setting also protects the core from exceeding thermal hydraulic limits as
(' a result of pressure increases from some events that occur when the reactor is operating at less than rated power and flow.
- 5. Drywell Pressure - High High pressure in the drywell could indicate a break in the primary pressure boundary system. The reactor is tripped to minimize the possibility of fuel damage and reduce the amount of energy being added to the coolant. The trip setting was selected as low as possible without causing spurious trips.
- 6. Reactor Vessel Water Level - Low (Level 3)
The bases for the Reactor Vessel Water Level-Low Scram Trip Setting (Level
- 3) are discussed in the bases for Specification 2.1.A.2.
- 7. Scram Discharge Volume High High Level The control rod drive scram system is designed so that all of the water which is discharged frcm the reactor by a scram can be accommodated in the discharge piping. A part of this piping is an instrument volume which is the low point in the piping. No credit was taken for this volume in the design of the discharge piping as concerns the amount of water which must be accommodated during a scram. During normal operation the discharge volume is empty; however, should the discharge volume fill with water, the water discharged to the piping from the reactor could not be accommodated which would result in a slow scram time or partial or no
( control rod insertion. To preclude this occurrence, level switches have V] been provided in the instrument volume which scram the reactor .when the volume of water reaches 71 gallons. As indicated above, there is suffi-cient volume in the piping to accommodate the scram without impairment of the scram times or amount of insertion of the control rods. This function shuts the reactor down while sufficient volume remains to accommodate the dis-charged water and precludes the situation in which a scram would be required but not able to perform its function adequately.
- 8. APRM Three APRM instrument channels are provided for each protection trip sys-tem. APRM's A and E operate contacts in one trip logic and APRM's C and E operate contacts in the other trip logic. APRM's B, D and F are arranged similarly in the other protection trip system. Each protection trip sys-tem has one more APRM than is necessary to meet the minimum number re-quired per channel. This allows the bypassing of one APRM per protection trip system for maintenance, testing or calibration.
- a. Flow Referenced Simulated Thermal Power Monitor and Fixed High-High Neutron Flux The bases for the APRM Flow Referenced Simulated Thermal Power Monitor and Fixed High-High Neutron Flux Scram Trip Settings are discussed in the bases for Specification 2.1.A.1.c.
tO v
3.1-12
e, n Table 3.2-1 INSTRUMENTATION WHICH INITIATES REACTOR VESSEL AND PRIMARY CONTAINMENT ISOLATION Required Ref. Trip Operable Action to be taken if Instrument Condition Channels Trip Setting number of channels is No. not met for both trip Remarks (d)
(a) Nomenclature per Trip System (b) systems (c)
Initiate an orderly Initiates Group 2 & 6 1 Reactor Vessel Low (Level 3) 2 1 10.0 inches isolation.
Water Level Narrow Range shutdown and achieve the Cold Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or isolate the shutdown cooling system.
initiate an orderly Starts the SGTS, l Low Low 2 3-47 inches shutdown and achieve initiates Group 5 w (Level 2) the Cold Shutdown isolation, and Condition within 24 initiates 8
hours. secondary containment isolation.
Initiate an orderly Initiates Group 1 l Low Low Low 2 > -113 inches shutdown and achieve isolation.
(Level 1) the Cold Shutdown Con-dition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Low Permissive ~<145 psig Isolate shutdown Isolatestheshutdownl 2 Reactor Vessel Steam 1 cooling, cooling suction valves Dome Pressure (Shut- of the RHR system.
down Cooling Mode)
Initiate an orderly Starts the standby l 1 Drywell Pressure fligh 2 5 1.92 psig gas treatment system, shutdown and achieve ,
the Cold Shutdown initiates Group 2 Condition within 24 isolation and second-hours ary containment isolation.
g k \
Tcble 3.2-1 (Cont.)
Required Ra f. Trip Operable Action to be taken if No. Instrument Condition Channels Trip Setting number of channels is (a) Nomenclature per Trip not met for both trip Remarks (d)
System (b) systems (c) 4 Main Steam Line High 2 53 times normal Initiate an orderly load Initiates Group 1 Radiation full power back- reduction and close MSIVs isolation.
ground within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
5 Main Steam Line Low 2 >825 psig Initiate an orderly load Initiates Group 1 Pressure reduction and close isolation. Only MSIVs within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, required in RUN mode, therefore activated when Mode Switch is in RUN position.
6 Main Steam Line High 2 5138% rated flow Initiate an orderly load Initiates Group 1 Flow (sIIS psid) reduction and close MSIVs isolation.
m within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
h7 w
Main Steam Line Tunnel Temperature High 2 $194 F Initiate an orderly load reduction and close MSIVs Initiates Group 1 isolation l
within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
8 Reactor Water High 1 20-80 gpm Isolate reactor water Final trip setting Cleanup System cleanup system. will be determined Differential Flow during startup test program.
9 Reactor Water High 2 5124 F Isolate reactor water Cleanup Area cleanup system.
l Temperature 10 Reactor Water High 2 567 F Isolate reactor water Cleanup Area cleanup system.
Ventilation Differential Temperature 11 Condenser Vacuum Low 2 >7" Hg. vacuum Initiate an orderly load Initiate Group 1 reduction and close HSIVs isolation within 8 hrs.
O O O Table 3.2-2 1
INSTRUMENTATION WHICH INITIATES OR CONTROLS HPCI Trip Setting Remarks Raf. Instrument Trip Required
) Condition Operable
- No.
(c) Nomenclature Channels per Trip System (b)
- 1. Reactor Vessel Water Level Low Low 2 > -47 inches Initiates HPCI; Also initiates l (Level 2) RCIC.
5 1.92 psig Initiates HPCI; Also initiates l
- 2. Drywell Pressure High 2 LPCI and Core Spray and pro-l vides a permissive signal to l ADS.
- Trips HPCI turbine l
- 5. HPCI Pump Suction Pressure Low 1 $ 12.6 inches Hg vacuun
- 6. Reactor Vessel Water level High 2 5 +56.5 inches Trips HPCI turbine (Level 8)
HPCI Pump Discharge Flow High 1 _;t 8 70 gpm Closes HPCI minimum flow bypass
- 7. line to suppression chamber.
(>_9.04 inches)
Low 1 < 605 gpm Opens HPCI minimum flow bypass f14.36 inches) line if pressure permissive is present.
- 8. HPCI Emergency Area High 1 1 169*F Closes isolation valves in Cooler Ambient Temperature HPCI system, trips HPCI turbine.
- ~
fs n
/
Table 3.2-2 (Cont.)
Raf. Instrument Trip Required Trip Setting Remarks No. Condition Operable (a) Nomenclature Channels per Trip System (b)
- 9. HPCI Steam Supply Pressure Low 2 >100 psig Closes isolation valves in l HPCI system, trips HPCI turbine.
- 10. HPCI Steam Line AP (Flow) High 1 5303% rated Close isolation valves in flow HPCI system, trips HPCI turbine.
- 11. HPCI Turbine Exhaust High 1 120 psig Close isolation valves in l Diaphragm Pressure , HPCI system, trips HPCI turbine.
y 12. Suppression Chamber Area High 1 5169 F Close isolation valves in cn Ambient Temperature HPCI system, trips HPCI turbine.
- 13. Suppression Chamber Area High 1 -<42 F Close isolation valves in l Differential Air temperature HPCI system, trips HPCI turbine.
- 14. Condensate Storage Tank Low 2 ->0 inches Automatic interlock switches Level suction from CST to suppression chamber,
- 15. Suppression Chamber Water High 2 <l54.2 inches Automatic interlock switches Level with respect to suction from CST to torus invert suppression chamber.
- 16. HPCI Logic Power failure 1 Not Applicable Monitors availability of Monitor power to logic system.
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 3.2-2 and items in Table 4.2-2.
L. LJ G Table 3.2-3 INSTRUMENTATION WHICH INITIATES OR CONTROLS RCIC Ref. Instrument Trip Required Trip Setting Remarks No. Condition Operable (a) Nomenclature Channels per Trip System (b)
- 1. Reactor Vessel Water Level Low Low 2 >-47 inches Initiates RCIC; also initiates l (Level 2) HPCI.
Mechanical 1 5125% rated Trips RCIC turbine.
, Pressure
'i' 4. RCIC Pump Suction Pressure
- Low I $12.6 inches Trips RCIC turbine. l m Hg Vacuum
- 5. Reactor Vessel Water Level High 2 5+56.5 inches Trips RCIC; automatically resets (Level 8) when water drops below level 8, system automatically restarts at level 2.
(>IO.6 inches) bypass line to suppression chamber.
Low 1 553 gpm Opens RCIC minimum flow
(<3.87 inches) bypass line if pressure permissive is present.
- 7. RCIC Emergency Area High 1 -< 169F Closes isolation valves in Cooler Ambient Temperature RCIC system, trips RCIC turbine.
O O O i
~ Table 3.2-3 (cont )
Raf. Instrument Trip Required Trip Setting Remarks No. Condition Operable (a) Nomenclature Channels per Trip System (b)
- 8. RCIC Steam Supply Pressure Low 2 >60 psig Closes isolation valves in l RCIC system, trips RCIC turbine.
- 9. RCIC Steam Line AP (Flow) High 1 5306% rated Closes isolation valves in flow RCIC system, trips RCIC turbine.
- 10. RCIC Turbine Exhaust High 1 $20 psig Closes isolation valves in l Diaphragm Pressure RCIC system, trips RCIC turbine.
u 11.
Suppression Chamber Area High 1 5169*F Closes isolation valves in g Ambient Temperature RCIC system, trips RCIC 4 turbine.
- 12. Suppression Chamber Area High 1 542 F Closes isolation valves in l Differential Air RCIC system, trips RCIC Temperature turbine.
- 13. RCIC Logic Power Failure 1 Not Applicable Monitors availability of l Monitor power to logic system.
- 14. Condensate Storage Tank Low 2 -> 0" Transfers suction from CST l Water Level to suppression pool
- 15. Suppression Pool Water High 2 -
< 0" Transfers suction from CST l Level to suppression pool
i O o o Table 3.2-4 INSTRUMENTATION WHICH INITIATES OR CONTROLS A05 Trip Setting Remarks Raf. Instrument Trip Required i
No. Condition Operable l Channels l (a) Nomenclature per Trip
! System (b)
Confirms low level, ADS permissive
- 1. Reactor vessel Water Level Low (Level 3) 1 3 10.0 inches Low Low Low 2 1-113 inches Permissive signal to ADS timer Reactor Vessel Water Level (Level 1)
High 2 -< 1.92 psig Initiates HPCl; also initiates LPCI
- 2. Drywell Pressure and core spray and provides a permissive signal to ADS timer High 2 3112 psig Permissive signal to ADS timer l
- 4. CS Pump Discharge Pressure 120 1 12 seconds With Level 3 and Level 1 and high S. Auto Depressurization 1 drywell pressure and CS or RHR pump Timer at pressure, timing sequence begins.
If the ADS timer is not reset it will initiate ADS.
1 Not applicable Monitors availability of power to
- 6. Automatic Blowdown Control logic system Power Failure Monitor
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 3.2-4 and items in Table 4.2-4.
- b. Whenever any CCCS subsystem is required to be operable by Section 3.5, there shall be two operable trip systems. If the required number of operable channels cannot be met for one of the trip systems, that system shall be repaired or the reactor shall be placed in the Cold Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after this trip systems is made or found to be Inoperable.
7 O O O Table 3.2-5 INSTRUMENTATION WHICH INITIATES OR CONTROLS THE LPCI MODE OF RHR Raf. Instrument Trip Required Trip Setting Remarks No. Condition Operable Nomenclature Channels (a) per Trip System (b)
- 1. Reactor Vessel Water Level Low Low Low 2 1 -113 inches Initiates LPCI mode of RHR l (Level 1)
- 2. Drywell Pressure High 2 1 1.92 psig Initiates LPCI mode of RHR. Also initiates HPCI and Core Spray and provides a permissive signal to ADS Reactor Vessel Steam low Permissive 1 5 145 psig With primary containment isola-
, 3. tion signal, closes RHR (LPCI)
- Dome Pressure inboard motor operated injection 7
"' valves e.
Low 2 1 335 psig Permissive to close Recirculation l Discharge Valve and Bypass Valve Low 2 1460 psig Permissive to open LPCI injection l valves
- 4. Reactor Shroud Water Level Low 1 1-202 inches Acts as permissive to divert (Level 0) some LPCI flow to containment spray
- 5. LPCI Cross Connect N/A 1 Valve not Initiates annunciator when valve Valve Open Annunciator closed is not closed
,- /~ ,-
O, \ N L_.]
Table 3.2-5-(Cont.)
INSTRUMENTATION WHICH INITIATES OR CONTROLS THE LPCI MODE OF RHR Raf. Instrument Trip Required Trip Setting Remarks No. Condition Operable (a) Nomenclature Channels per Trip System (b) 6 RHR (LPCI) Pump Flow Low 1 >I670 gpm Opens LPCI minimum flow line upon
[4.7 inches) receipt of low flow signal from both pumps and closes LPCI minimum flow line when signal from either pump is not present w 7 RHR(LPCI) Pump Start Timers 1 0<t<1 seconds With loss of normal power, and l 4 upon receipt of emergency power, w 1 9<t<11 seconds one RHR pump starts immediately, the other three follow in 10 seconds 8 Valve Selection Timers 1 ->10 minutes Cancels LPCI injection valve l initiation signal 9 RHR Relay Logic Power 1 Not Applicable Monitors availability of power l Failure Monitor to logic system
v Tabl 2-6 INSTRUMENTATION WHICH INITIATES OR CONTROLS CORE SPRAY Trip Required Trip Setting Remarks Ref. Instrument No. Condition Operable (a) Nomenclature Channels per Trip System (b)
- 1. Reactor Vessel Water Level Low Low Low > -113 inches Initiates CS. l (Level 1) 2
- 2. Drywell Pressure High 2 1 1.92 psig Initiates CS. Also initiates HPCI and LPCI Mode of RHR and provides a permissive signal to ADS
- 3. Reactor Vessel Steam Dome Low 2 > 460 psig Permissive to open CS l Pressure injection valves.
- 4. Core Spray Sparger 1 To be determined Monitors integrity of CS m
. Differential Pressure during startup piping inside vessel and core testing shroud.
7 5 5. CS Pump Discharge Flow Low 1 > 610 gpm Minimum flow bypass line is 1
(>4.13 inches) closed when low flow signal is not present.
- 6. Core Spray Logic Power 1 Not Applicable Monitors availability of Failure Monitor power to logic system.
- a. the column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 3.2-6 and items in Table 4.2-6.
- b. Whenever =ay CCCS subsystem is required to be operable by Section 3.5, there shall be two operable trip systems. If the required number of operable channels cannot be met for one of the trip systems, that system shall be repaired or the reactor shall be placed in the Cold Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after this trip system is made or found to be inoperable.
L
O -
O O I Table 3.2-11 INSTRUMENTATION WHICH PROVIDES SURVEILLANCE INFORMATION Required Ref. Operable No. Instrument Instrument Type and (a) (b) Channels Range Action Remarks 1 Reactor Vessel Water Level 1 Recorder -150" to +60" (c) (d) 2 Indicator -150" to +60" (c) (d) 2 Shroud Water Level 1 Recorder -317" to -17" (c) (d) l 1 Indicator -317" to -17" (c) (d) 3 Reactor Pressure 1 Recorder 0 to 1500 psig (c) (d) 2 Indicator 0 to 1500 psig (c) (d) l 4 Drywell Pressure 2 Recorder -10 to +90 psig (c) (d) 5 Drywell Temperature 2 Recorder 0 to 500 F (c) (d)
. 6 Suppression Chamber Air Temperature 2 Recorder 0 to 500 F (c) (d) h7 Suppression Chamber Water Temperature 2 Recorder 0 to 250 F (c) (d) 8 Suppression Chamber Water Level 2 Indicator 0 to 300" (c) (d) 2 Recorder 0 to 30" (c)(e) (d) 9 Suppression Chamber Pressure 2 Recorder -10 to +90 psig (c) (d) 10 Rod Position Information System (RPIS) 1 28 Volt Indicating Lights (c) (d) 11 Hydrogen and Oxygen Analyzer 1 Recorder 0 to 52 (c) (d) 12 Post LOCA Radiation Monitoring System 1 Recorder (c) (d)
Indicator 1 to 106 R/hr
~
(c) (d) 1 13 a) Safety / Relief Valve Position Primary 1/SRV Indicating Light at 85 psig (f)
Indicator b) Safety / Relief Valve Position Secondary 1 Recorder 0 to 600 F (f)
Indicator
O
/
Table 4.2-1 l>
Check,- Functional Test, and Calibration Minimum Frequency for Instrtmentation Which Initiates Reactor Vessel and Primary Containment Isolation Raf. Instrument Check Instrument functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum Frequency QJ (b) _
(c) 1 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Levels 1, 2, and 3) 2 Reactor Vessel Steam Dome Once/ shift Once/ month Once/ operating cycle l Pressure (Shutdown Cooling Mode) ,
3 Drywell Pressure Once/ shift Once/ month Once/ operating cycle l 4 Main Steam Line None Once/ week (e) Every 3 months (f)
Radiation y 5 Main Steam Line None (d) Every 3 months u
Pressure 6 Main Steam Line Flow Once/ shift Once/ month Once/ operating cycle 7 Main Steam Line Tunnel Once/ shift Once/ month Once/ operating cycle Temperature 8 Reactor Wcter Cleanup None (d) Every 3 months System Differential Flow 9 Reactor Water Cleanup Once/ shift Once/ month Once/ operating cycle Area Temperature b
y~ rs
[
O V .
O Table 4.2-1 (Cont'd)
Raf. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Fregeency Minimum Frequency Minimum Frequency (a) (b) (c) 10 Reactor Water Cleanup Once/ shift Once/ month Once/ operating cycle Area Ventilation Differential Temperature 11 Condenser Vacuum None (d) Every 3 months Notes for Table 4.2-1
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 4.2-1 and items in Table 3.2-1.
U b. Instrument functional tests are not required when the instruments are not required to be operable or are tripped. However, if functional tests are missed, they shall be performed prior to returning the instrument to an operable status.
- c. Calibrations are not required when the instruments are not required to be operable. However, if calibrations are missed, they shall be performed prior to returning the instrument to an operable status.
- d. Initially once per month or according to Figure 4.1-1 with an interval of not less than one month nor more than three months. The compilation of instrument failure rate date may include data obtained
b .6 O i
! Table 4.2-2 Check, Functional Test, and Calibration Minimum Frequency for Instrumentation l
Which Initiates or Controls HPCI Raf. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum Frequency (a) (b) (c) 1 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 2) 2 Drywell Pressure Once/ shift Once/ month Once/ operating cycle l 3 HPCI Turbine Overspeed - None N/A Once/ operating cycle l w 4 HPCI Turbine Exhaust Once/ shift Once/ month Once/ operating cycle l j
y Pressure b5 HPCI Pump Suction Pressure Once/ shift Once/ month Once/ operating cycle l l
6 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 8) 7 HPCI Pump Discharge Flow Once/ shirt Once/ month Once/ operating cycle 8 HPCI Emergency Area Once/ shift Once/ month 0nce/ operating cycle Cooler Ambient Temperature 9 HPCI Steam Supply Pressure Once/ shift Once/ month Once/ operating cycle i
) '_
Table 4.2-2 (Cont'd)
R:f. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum Frequency (a) (b) (c) 10 HPCI Steam Line Once/ shift Once/ month Once/ operating cycle
.iP (Flow) 11 HPCI Turbine Exhaust Once/ shift Once/ month Once/ operating cycle l Diaphragm Pressure 12 Suppression Chamber Area Once/ shift Once/ month Once/ operating cycle Ambient Temperature ,
w 13 Suppression Chamber Area Once/ shift Once/ month Once/ operating cycle L Differential i
Air Temperature m
14 Condensate Storage None (d) Every 3 months Tank Level 15 Suppression Chamber Once/ shift Once/ month Once/ operating cycle l Water Level 16 HPCI Logic Power None Once/ operating cycle None Failure Monitor l Notes for Table 4.2-2 l
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 4.2-2 and items in Table 3.2-2.
I c ~]
O '
Oe . U.
Table 4.2-3 i
Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates or Controls RCIC Raf. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum Frequency (a) (b) (c) 1 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 2) 2 RCIC Turbine Overspeed Electrical / None N/A Once/ operating cycle Mechanical None N/A Once/ operating cycle 3 RCIC Turbine Exhaust Once/ shift Once/ month Once/ operating cycle l m
- Pressure Y
w 4 RCIC Pump Suction Once/ shift Once/ operating cycle l Once/ month Pressure 5 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 8) 6 RCIC Pump Discharge Flow Once/ shift Once month Once/ operating cycle 7 RCIC Emergency Area Once/ shift Once/ month Once/ operating cycle Cooler Ambient Temperature 8 RCIC Steam Supply Pressure .Once/ shift Once/ month Once/ operating cycle l
i i
J i
- ~-.- -- - -- .
1 O .
O O.
y l ~,a _
- r f _ . ,.
7 -
Table 4.2-3 (Cont'd) '
, w-Ref. . Instrument Check - Instrument functional Test Minimum Frequency Instrument Calibration Minimum Frequency N
No. Instrument Minimum Frequency (b) (c) i (a) ___-
9 RCIC Steam Line Once/ shift Once/ month Once/ operating cycle AP (Flow) 10 RCIC Turbine Exhaust ~
Once/ shift Once/ month ' Once/ operating cycle l Diaphragm Pressure i f
11 Suppression Chamber Area Once/ shift Once/ month Once/ operating cycle w Ambient Temperature .
.a Y 12 Suppression Chamber Area Once/ shift Once/ month / Once/ operating cycle #
Differential Air '
Temperature 13 RCIC Logic Power None f- Once/ operating cycle None
'l Failure Monitor r /
Monthly I4 Condensate Storage Tank Level None' Every 3 months
] /
15 res Pool None Monthly Every 3 months -
l
-Notes for Table 4.2-3
- a. -The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be
~ established between items in Table 4.2-3 and items in Table 3.2-3.
- b. Instrument functional tests are not required when the instruments are not required to be operable or are tripped. However, if functional tests are missed, they shall be performed prior to returning the instrument to an operable status.
J
O O O Notes for Table 4.2-3 (Cont'd)
- c. Calibrations are not required when the instruments are not required to be operable. However, if calibrations are missed, they shall be performed prior to returning the instrument to an operable status.
u 5
u M
Logic system functional test and simulated automatic actuation shall be performed once each operating cycle for the following:
- 1. RCIC Subsystem Auto Isolation The logic system functional tests shall include a calibration of time relays and timers necessary for proper functioning of the trip systems.
9
-b O U
O v
v Table 4.2-4 Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates or Controls ADS-Raf. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimus Frequency Minimum Frequency Minimum Frequency (a) (b) (c) l 1 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 3)
Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 1) 2 Drywell Pressure Once/ shift Once/ month Once/ operating cycle l
- 3 RHR Pump Discharge Once/ shift Once/ month Once/ operating cycle l i Pressure 0 Once/ operating cycle l 4 CS Pump Discharge Once/ shift Once/ month Pressure l 5 Auto Depressurization None N/A Once/ operating cycle Timer .
l 6 Automatic Blowdown No'ne Once/ operating cycle None Control Power Failure l Monitor l i
Notes for Table 4.2-4
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 4.2-4 and items in Table 3.2-4.
O O O Notes for Table 4.2-4 (Cont'd)
- b. Instrument functional tests are not required when the instruments are not required to be operable or are tripped. However, if functional tests are missed, they shall be performed prior to returning the instrument to an operable status.
l i
- c. Calibrations are not required when the instruments are not required to be operable. However, if calibrations are missed, they shall be--performed prior to returning the instrument to an operable status.
'T Logic system functional tests and simulated automatic actuation shall be performed once each operating cycle for the following: -
- 1. ADS Subsystem The logic system functional tests shall include a calibration of time relays and timers necessary for proper functioning of the trip systems.
O O O Table 4.2-5 Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates or Controls the LPCI Mode of RHR Ref. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency- Minimum Frequency Minimum Frequency (a) (b) (c) 1 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 1) 2 Drywell Pressure -0nce/ shift Once/ month Once/ operating cycle l
3 Reactor Vessel Steam Once/ shift Once/ month Once/ operating cycle Dome Pressure 4 Reactor Shroud Water Level Once/ shift Once/ operating cycle Once/ month (Level 0) y5 LPCI Cross Connect Valve None Once/ Operating cycle None g Open Annunciator 6 RHR (LPCI) Pump Flow Once/ operating cycle Once/ shift Once/ month 7 RHR (LPCI) Pump None N/A Once/ operating cycle Start Timers 8 Valve Selection Timers None N/A Once/ operating cycle l 9 RHR Relay Logic Power None Once/ operating cycle None l Failure Monitor
O O O Notes for Table 4.2-5
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 4.2-5 and items in Table 3.2-5.
- b. Instrument functional tests are not required when the instruments are not required to be operable or are tripped. However, if functional, tests are missed, they shall be performed prior to returning the instrument to an operable status,
- c. Calibrations are not required when the instruments are not required to be operable. However, if calibrations are missed, they shall be performed prior to ceturning the instrument to an operable y status, w
m Logic system functional tests and simulated automatic actuation shall be performed once each operating cycle for the following:
- 1. LPCI Subsystem
- 2. Containment Spray Subsystem
Table 4.2-6 Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates or Controls Core Spray
. Ref. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum Frequency j (a) (b) (c) d 1 Reactor Vessel _ Water Level Once/ shift Once/ month Once/ operating cycle I
(Level 1) 2 Drywell Pressure ,0nce/ shift Once/ month Once/ operating cycle 1
3 Reactor Vessel Steam Dome Once/ shift Once/ month Once/ operating cycle 4 Pressure
, w g 4 Core Spray'Sparger Once/ day N/A Once/ operating cycle
- Differential Pressure l $
. 5 CS Pump Discharge Flow Once/ shift Once/ month Once/ operating cycle e
i 6 Core Spray Logic Power None Once/ operating cycle None
- Failure Monitor 1
1
)
Notes for Table 4.2-6 i a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be t established between items in Table 4.2-6 and items in Table 3.2-6.
O O O Notes for Table 4.2-6 (Cont'd)
- b. Instrument functional tests are not required when the instruments are not required to be operable or are tripped. However, if functional tests are missed, they shall be performed prior to returning the instrument to an operable status.
- c. Calibrations are not required when the instruments are not required to be operable. However, if calibrations are missed, they shall be performed prior to returning the instrument to an operable status.
Y 7
0 Logic system functional tests and simulated automatic actuation shall be performed once each operating cycle for the following:
- 1. Core Spray Subsystem The logic system functional tests shall include a calibration of time delay relays and timers necessary for proper functioning of the trip systems.
O O O Table 4.2-11 Check and Calibration Minimum Frequency for Instrumentation Which Provides Surveillance Information Ref. Instrument Instrument Check Instrument Calibration No. Minimum Frequency. Minimum Frequency (a) (b) (c) 1 Reactor Vessel Water Level Each shift Once/ operating cycle (f) 2 Shroud Water Level Each shift Once/ operating cycle (f) 3 Reactor Pressure Each shift Once/ operating cycle (f) 4 Drywell Pressure Each shift Every 6 months 5 Drywell Temperature Each shift Every 6 months 6 Suppression Chamber Air Each shift Every 6 months Temperature 7 Suppression Chamber Water Each shift Every 6 months Temperature 8 Suppression Chamber Water Each shift Every 6 months i Level co 9 Suppression Chamber Each shift Every 6 months Pressure 10 Rod Position Information Each shift N/A System (RPIS) 11 Hydrogen and Oxygen Each shift Every 6 months Analyzer 12 Post LOCA Radiation Each shift Every 6 months 13 a) Safety / Relief Valve Position Pri- Monthly Every 18 months mary Indicator b) Safety / Relief Valve Position Monthly Every 18 months Secondary Indicator
/7 O J U Notes for Table 4.2-11
?
E a. The column entitled "Ref No." is only for convenience so that a one-to-one relationship can be z established between items in Table 4.2-11 and items in Table 3.2-11.
4 9 b. Instrument checks are not required when the instruments are not required to be operable or are c- tripped. However, if instrument checks are missed, they shall be performed prior to returning the g instrument to an operable status.
~
- c. Calibrations are no't required when the instruments are not required to be operable or are tripped. However, if calibrations are missed, they shall be performed prior to returning the instrument to an operable status,
- d. Functional tests are not required when the instruments are not required to be operable or are tripped. However, if functional tests are missed, they shall be performed prior to returning the instrument to an operable status.
fd e. Calibration of a drywell high range monitor shall consist of an electronic calibration of the
? channel, not including the detector, for range decades above 10 R/hr and one point calibration
$ check of the detector below 10 R/hr with an installed or portable gamma source.
- f. The entire loop shall be calibrated once per 18 months; however, the recorder itself must be calibrated at least once per 12 months.
_ - ~
BASES FOR LIMITING CONDITIONS FOR OPERATION
(} 3.2 PROTECTIVE INSTRUMENTATION In addition to the Reactor Protection System (RPS) instrumentation which in-itiates a reactor scram, protective instrumentation has been provided which initiates action to mitigate the consequences of accidents which are beyond the operators ability to control, or terminates operator errors before they result in serious consequences. This set of Specifications provides the lim-iting conditions for operation of the instrumentation:
(a) which initiates reactor vessel and primary containment isolation, (b) which initiates or controls the core and containment cooling systems, (c) which initiates control rod blocks, (d) which initiates protective action, (e) wnich monitors leakage into the drywell and (f) which provides surveil-lance information. The objectives of these specifications are (1) to assure the effectiveness of the protective instrumentation when required by preserv-ing its capability to tolerate a single failure of any component of such sys-tems even during periods when portions of such systems are out of service for maintenance, and (ii) to prescribe the trip settings required to assure ade-quate performance. When necessary, one channel may be made inoperable for brief intervals to conduct required functional tests and calibrations.
A. Instrumentation Which Initiates Reactor Vessel and Primary Containment Isolation (Table 3.2-1)
Isolation valves are installed in those lines which penetrate the primary con-tainment and must be isolated during a loss of coolant accident so that the radiation dose limits are not exceeded during an accident condition. Actua-tion of these valves is initiated by protective instrumentation shown in Table
.O 3.2-1 which senses the conditions for which isolation is required. Such in-strumentation must be available whenever primary containment integrity is re-quired. The objective is to isolate the primary containment so that the guidelines of 10 CFR 100 are not exceeded during an accident. The events when isolation is required are discussed in Appendix G of the FSAR. The instrumentation which initiates primary system isolation is connected in a dual bus arrangement.
- 1. Reactor Vessel Water Level Reactor Vessel Water Level Low (Level 3) (Narrow Ranoe) a.
The reactor water level instrumentation is set to trip when reactor water level is approximately 14 feet above the top of the active fuel. This level is referred to as Level 3 in the Technical Speci-fications and corresponds to a reading of 10.0 inches on the Narrow Range Scale. This trip initiates Group 2 and 6 isolation but does not trip the recirculation pumps.
- b. Reactor Vessel Water Level Low Low (Level 2)
The reactor water level iswater level instrumentation approximately 9 feet aboveisthe settop to trip when of the reactor l active fuel. This level is referred to as Level 2 in the Technical Speci-fications and corresponds to a reading of -47 inches. l This trip initiates Group 5 isolation, starts the standby gas O treatment system, and initiates secondary containment isolation.
3.2-50
BASES FOR LIMITING CONDITIONS FOR OPERATION 3.2.A.1.c. Reactor Vessel Water Level Low Low Low (Level 1)
The reactor water level instrumentation is set to trip when the reactor water evel is approximately 51 inches above the top of l the active f.: This level is referred to as Level 1 in the Technical Specifications and corresponds to a reading of of.-113-inches. This trip initiates Group 1 isolation. l l
)
l 1
I O
O 3.2-50a
}
BASES FOR LIMITING CONDITIONS FOR OPERATION 3.2.A.2. Reactor Vessel Steam Dome Pressure (Shutdown Cooling Mode) Low Permissive l J(~~)
This setpoint is chosen to preserve the pressure integrity of the RHR system under conditions of increasing reactor pressure (startup). The RHR suction valves from the reactor (shutdown cooling mode) would be closed when the 145 psig setpoint is reached. This function protects l against RHR system pipe breaks during the shutdown cooling mode of op-eration. Additionally, at reactor pressures below this setpoint the primary containment isolation signals are permitted to close the.in-board motor operated injection valve (LPCI mode).
- 3. Drywell Pressure High The Bases for Drywell Pressure High are discussed in the Bases for Specif-ication 3.1.A.5. Pressure above the trip setting starts the SGTS and in-intiates primary and secondary containment isolation.
- 4. Main Steam Line Radiation High Radiation monitors in the main steam line tunnel have been provided to detect gross fuel failure as in the control rod drop accident. This in-strumentation causes a Group 1 isolation. With the established setting of approximately three times normal full power background, fission product re-lease is limited so that 10 CFR 100 guidelines are not exceeded,for this accident. Ref. Section 14.4.4 FSAR.
() 5. Main Steam Line Pressure Low The Bases for Main Steam Line Pressure Low are discussed in the Bases for Speci fication 2.1. A.6.
- 6. Main Steam Line Flow High Venturis are provided in the main steam lines as a means of measuring steam flow and also J4miting the loss of mass inventory from th'e"velsel during a steam line break accident. In addition to monitoring steam flow, instru-mentation is provided which initiates Group 1 isolation. The primary func-tion of the instrumentation is to detect a break ~in the main steam line.
For the worst case accident, a main steam line break outside the drywell, the trip setting of 115 psid, corresponding to 138% of rated steam flow, l in conjunction with the flow limiters and main steam isolation valve clo-sure, limits the mass inventory loss such that fuel is not uncovered. Fuel temperatures remain approximately 1000 F and release of radioactivity to the environs is well below 10 CFR 100 guidelines. Ref. Section 14.6.5 of the FSAR.
- 7. Main Steam Line Tunnel Temperature High Temperature monitoring instrumentation is provided in the main steam line tunnel to detect leaks in this area. Trips are provided on this instrumen-tation and when exceeded cause a Group 1 isolation. Its setting is low enough to detect leaks of the order of five to 10 gpm; thus, it is capable of covering the entire spectrum of breaks. For large breaks, it is a back-O up to high steam flow instrumentation discussed above, and for small breaks 3.2-5'1 L
BASES FOR LIMITING CONDITIONS FOR OPERATION n
3.2.A.7 Main Steam Line Tunnel Temperature High (Continued)
()
with the resultant small release of radioactivity, gives isolation before the
' guidelines of 10 CFR 100 are exceeded.
- 8. Reactor Water Cleanup System Differential Flow High Gross leakage (pipe break) from the reactor water cleanup system is detected by measuring the difference of flow entering and leaving the system. The set point is low enough to ensure prompt isolation of the cleanup system in the event of such a break but, not so low that spurious isolation can occur due to normal system flow fluctuations and instrument noise. Time delay relays are used to prevent the isola-tion signal which might be generated from the initial flow surge when the cleanup system is started or when operational system adjustments are made which produce short term transients.
- 9. Reactor Water Cleanup Area Temperature High and
- 10. Reactor Water Cleanup Area Ventilation Differential Temperature High Leakage in the high temperature process flow of the reactor water cleanup system external to the primary containment will be detected by temperature sensing elements. Temperature sensors are located in the inlet and outlet ventilation ducts to measure the temperature difference. Local ambient temperature sensors are located in the compartment containing equipment and 7 piping for this system. An alarm in the main control room will be set to
(
' . annunciate a temperature rise corresponding to a leakage within the identi-fied limit. In addition to annunciation, a high cleanup room temperature will actuate automatic isolation of the cleanup system.
- 11. Condenser Vacuum Low The Bases for Condenser Vacuum Low are discussed in The Bases for Specifica-tion 2.1.A.7.
B. Instrumentation Which Initiates or Controls HPCI (Table 3.2-2)
- 1. Reactor Vessel Water Level Low Low (Level 2)
The reactor vessel water level instrumentation setpoint which initiates HPCI is 2 -47 inches. This level is approximately 9 feet above l the top of the active fuel and in the Technical Specifications is refer-red to as Level 2. The reactor vessel low water level setting for HPCI system l initiation is selected high enough above the active fuel to start the HPCI system in time both to prevent excessive fuel clad temperatures and to pre-vent more than a small fraction of the core from reaching the temperature at which gross fuel failure occurs. The water level setting is far enough below normal levels that spurious HPCI system startups are avoided.
- 2. Drywell Pressure High
'T The drywell pressure which initiates HPCI is s2 (V psig. High drywell pressure could indicate a failure of the nuclear system process barrier. This pressure is selected to be as low as possible without inducing spurious HPCI system startups. This instrumentation ser-ves as a backup to the water level instrumentation described above.
3.2-52
BASES FOR LIMITING CONDITIONS FOR OPERATION n
3.2.B.3 HPCI Turbine Overspeed (Qi The HPCI turbine is automatically shut down by tripping the HPCI turbine stop valve closed when the 5000 rpm setpoint on the mechanical governor is reached. A turbine overspeed trip is required to protect the physi-cal integrity of the turbine.
- 4. HPCI Turbine Exhaust Pressure High When HPCI turbine exhaust pressure reaches the setpoint (s 146 psig) the HPCI l turbine is automatically shut down by tripping the HPCI stop valve closed.
HPCI turbine exhaust high pressure is indicative of a condition which threat-ens the physical integrity of the exhaust line.
- 5. HPCI Pump Suction Pressure Low A pressure switch is used to detect low HPCI system pump suction pressure and is set to trip the HPCI turbine at s 12.6 inches of mercury vacuum. l This setpoint is chosen to prevent pump damage by cavitation.
- 6. Reactor Vessel Water Level High (Level 8)
A reactor water level of +56.5 inches is indicative that the HPCI system has performed satisfactorily in providing makeup water to the reactor vessel. The reactor vessel high water level setting which trips the HPCI turbine is near the top of the steam separators and is sufficient to prevent gross moisture carryover to the HPCI turbine. Two analog dif-ferential pressure transmitters trip to initiate a HPCI turbine shutdown.
- 7. HPCI Pump Discharge Flow High l i
To prevent damage by overheating at reduced HPCI system pump flow, a pump discharge minimum flow bypass is provided. The bypass is controlled by an automatic, D. C. motor-operated valve. A high flow signal from a flow meter downstream of the pump on the main HPCI line Will cause the bypass valve to close. Two signals are required to open the valve: A HPCI pump discharge pressure transmitter high differential pressure signal must be I received to act as a permissive *to open the bypass valve in the presence of a low flow signal from the differential pressure transmitter.
NOTE:
Because the steam supply line to the HPCI turbine is part of the nuclear system process barrier, the following con-ditions (8-13) automatically isolate this line, causing shutdown of the HPCI system turbine.
- 8. HPCI Emergency Area Cooler Ambient Temperature High l
High ambient temperature in the HPCI equipment room near the emergency area cooler could indicate a break in the HPCI system turbine steam line.
The automatic closure of the HPCI steam line valves prevents the ex-cessive loss of reactor coolant and the release of significant amounts of O- radioactive material from the nuclear system process barrier. The high 3.2-53
BASES FOR LIMITING CONDITIONS FOR OPERATION 3 3.2.B.8 HPCI Emergency Area Cooler Ambient Temperature High (Continued)
(G temperature setting of s 169 F was selected to be far enough above anti-cipated normal HPCI system operational levels to avoid spurious isolation but low enough to provide timely detection of HPCI turbine steam line break.
- 9. HPCI Steam Supply Pressure Low Low pressure in the HPCI steam line could indicate a break in the HPCI steam line. Therefore, the HPCI steam line isolation valves are auto-matically closed. The steam line low pressure function is provided so in the event that a gross rupture of the HPCI steam line occurred up-stream from the high flow sensing location, thus negating the high flow indicating function, isolation would be effected on low pressure. The allowable value of 2 100 psig is selected at a pressure sufficiently high enough to prevent turbine stall.
- 10. HPCI Steam Line AP (Flow) High HPCI steam line high flow could indicate a break in the HPCI turbine steam line. The automatic closure of the HPCI steam line isolation valves prevents the excessive loss of reactor coolant and the release of signi-ficant amount of radioactive materials from the nuclear system process barrier. Upon detection of HPCI steam line high flow the HPCI turbine r^N steam line is isolated. The high steam flow trip setting of 303% flow d was selected high enough to avoid spurious isolation, i.e., above the high steam flow rate encountered during turbine starts. The setting was selected low enough to provide timely detection of an HPCI turbine steam line break.
- 11. HPCI Turbine Exhaust Diaphragm Pressure High High pressure in the HPCI turbine exhaust could indicate that the turbine rotor is not turning, thus allowing reactor pressure to act on the turbine exhaust line. The HPCI steam line isolation valves are automatically closed to prevent overpressurization of the turbine exhaust line. The turbine ex-haust diaphragm pressure trip setting of s 20 psig is selected high enough l to avoid isolation of the HPCI if the turbine is operating, yet low enough to effect isolation before the turbine exhaust line is unduly pressurized.
- 12. Suppression Chamber Area Ambient Temperature High A temperature of 169 F will initiate a timer to isolate the HPCI turbine steam line.
(v) 3.2-54
BASES FOR LIMITING CONDITIONS FOR OPERATION
/ 3.2.B.13 Suppression Chamber Area Differential Air Temperature High V] A differential air temperature greater than the trip setting of s 42 F between the inlet and outlet ducts which ventilate the suppression chamber area will initiate a timer to isolate the HPCI turbine steam line.
- 14. Condensate Storage Tank Level Low The CST is the preferred source of suction for HPCI. In order to provide an adequate water supply, an indication of low level in the CST automat-ically switches the suction to the suppression chamber. A trip setting of 0 inches corresponds to 10,000 gallons of water remaining in the tank.
- 15. Suppression Chamber Water Level High A high water level in the suppression chamber automatically switches HPCI suction to the suppression chamber from the CST.
- 16. HPCI Logic Power Failure Monitor The HPCI Logic Power Failure Monitor monitors the availability of power to the logic system. In the event of loss of availability of power to the logic system, an alarm is annunciated in the control room.
C. Instrumentation Which Initiates or Controls RCIC (Table 3.2-3) p 1. Reactor Vessel Water Level Low Low (Level 2)
The reactor vessel water level instrumentation setpoint which initiates RCIC is 2-47 inches. This level is approximately 9 feet above the top of the active fuel and is referred to as Level 2. This setpoint insures that RCIC is started in time to preclude conditions which lead to inade-quate core cooling.
- 2. RCIC Turbine Overspeed The RCIC turbine is automatically shutdown by tripping the RCIC turbine stop valve closed when' the 125% speed at rated flow setpoint on the mech-anical governor is reached. Turbine overspeed is indicative of a condi-tion which threatens the physical integrity of the system. An electrical tachometer trip setpoint of 110% also will trip the RCIC turbine stop valve closed.
- 3. RCIC Turbine Exhaust Pressure High When RCIC turbine exhaust pressure reaches the setpoint (s 45 psig), the l RCIC turbine is automatically shut down by tripping the RCIC turbine stop valve closed. RCIC turbine exhaust high pressure is indicative of a con-dition which threatens the physical integrity of the exhaust line.
- 4. RCIC Pump Suction pressure Low One differential pressure transmitter is used to detect low RCIC system pump suction pressure and is set to trip the RCIC turbine at s 12.6 inches of mer-cury vacuum.
3.2-55
BASES FOR LIMITING CONDITIONS FOR OPERATION r] 3.2.C.5 Reactor Vessel Water Level High (Level 8)
V A high reactor water level trip is indicative that the RCIC system has performed satisfactorily in providing makeup water to the reactor vessel.
The reactor vessel high water level setting which trips the RCIC turbine is near the top of the steam separators and sufficiently low to prevent gross moisture carryover to the RCIC turbine. Two differential pressure trans-mitters trip to initiate a RCIC turbine shutdown. Once tripped the system is capable of automatic reset after the water level drops below Level 8.
This automatic reset eliminates the need for manual reset of the system before the operator can take manual control to avoid fluctuating water levels.
- 6. RCIC Pump Discharge Flow l
To prevent damage by overheating at reduced RCIC system pump flow, a pump discharge minimum flow bypass is provided. The bypass is controlled by an automatic, D. C. motor-operated valve. A high flow signal from a flow meter downstream of the pump on the main RCIC line will cause the bypass valve to close. Two signals are required to open the valve: A RCIC pump discharge pressure transmitter high differential pressure signal must be l received to act as a permissive to open the bypass valve in the presence of a low flow signal from the differential pressure transmitter. l Note:
's Because the steam supply line to the RCIC turbine is part of s the nuclear system process barrier, the following conditions (7 - 13) automatically isolate this line, causing shutdown of the RCIC system turbine.
- 7. RCIC Emergency Area Cooler Ambient Temperature High l High ambient temperature in the RCIC equipment room near the emergency area cooler could indicate a break in the RCIC system turbine steam line.
The automatic closure of the RCIC steam line valves prevents the exces-sive loss of reactor coolant and the release of significant amounts of radioactive material from the nuclear system process barrier.. The high temperature setting of s 169 F was selected to be far enough above anti- l cipated normal RCIC system operational levels to avoid spurious iso.lation but low enough to provide timely detection of a RCIC turbine steam line break.
- 8. RCIC Steam Supply Pressure Low Low pressure in the RCIC steam supply could indicate a break in the RCIC steam line. Therefore, the RCIC steam supply isolation valves are auto-matically closed. The steam line low pressure function is provided so that in the event a gross rupture of the RCIC steam line occurred up-stream from the high flow sensing location, thus negating the high flow indicating function, isolation would be effected on low pressure. The iso-lation setpoint of 2 60 psig is chosen at a pressure below that at which the RCIC turbine can effectively operate.
V 3.2-56
BASES FOR LIMITING CONDITIONS FOR OPERATION
[3 3.2.C.9 RCIC Steam Line ( AP) Flow High l
%)
RCIC turbine high steam flow could indicate a break in the RCIC turbine steam line. The automatic closure of the RCIC steam line isolation valves prevents the excessive loss of reactor coolant and the release of signifi-cant amounts of radioactive materials from the nuclear system process 1 barrier. Upon detection of RCIC turbine high steam flow the RCIC turbine steam line is isolated. The high steam flow trip setting of 306's flow l was selected high enough to avoid spurious isolation, i.e., above the high steam flow rate encountered during turbine starts. The setting was ;
selected low enough to provide timely detection of a RCIC turbine steam line break.
- 10. RCIC Turbine Exhaust Diaphragm Pressure'High High pressure in the RCIC turbine exhaust could indicate that the turbine rotor is not turning, thus allowing reactor pressure to act on the turbine exhaust line. The RCIC steam line isolation valves are automatically closed to prevent overpressurization of the turbine exhaust line. The tur-bine exhaust diaphragm pressure trip setting of s 20 psig is selected high l enough to avoid isolation of the RCIC if the turbine is operating, yet low enough to effect isolation before the turbine exhaust line is unduly pres-surized.
- 11. Suppression Chamber Area Ambient Temperature High l C As in the RCIC equipment room, and for the same reason, a temperature of s 169 F will initiate a timer to isolate the RCIC turbine steam line. l
- 12. Suppression Chamber Area Differential Air Temperature High A high differential air temperature between the inlet and outlet ducts which ventilate the suppression chamber area will initiate a timer to l isolate the RCIC turbine steam line.
- 13. RCIC Logic Power Failure' Monitor The RCIC Logic Power Failure Monitor monitors the availability of power to the logic system. In the event of loss of availability of power to the logic system, an alarm is annunciated in the control room.
- 14. Condensate Storage Tank Level Low
! The low CST level signal transfers RCIC suction from the CST to the suppression pool. The setpoint was chosen to ensure an uninterrupted supply of water during suction transfer.
- 15. Suppression Pool Water Level High A high water level in the suppression chamber automatically switches RCIC suction from the CST to the suppression pool.
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3.2-57 L
i i
i BASES FOR LIMITING CONDITIONS FOR OPERATION l
[3 D. Instrumentation Which Initiates or Controls ADS (Table 3.2-4)
V The ADS is a backup system to HPCI. In the event of failure by HPCI l to maintain reactor water level, ADS will initiate depressurization of the reactor in time for LPCI and CS to adequately cool the core. Four signals are required to initiate ADS: Low water level, confirmed low water level, high drywell pressure, and either a RHR or Core Spray pump available. The simultaneous presence of these four signals will initiate a 120 second timer which will depressurize the reactor if not reset.
- a. Reactor Vessel Water Level Low (Level 3)
The second reactor vessel low water level initiation setting
(+10.0 inches) is selected to confirm that water level in the vessel is in fact low, thus providing protection against inadvertent depressurization in the event of an instrument line (water level) failure. Such a failure could produce a simultaneous high drywell pressure. A confirmed low level is
. one of four signals required to initiate ADS.
- b. Reactor Vessel Water Level Low Low Low (Level 1)
The reactor vessel low water level setting of -113 inches is l p, selected to provide a permissive signal to open the relief valve d and depressurize the reactor vessel in time to allow adequate cooling of the fuel by the core spray and LPCI systems following a LOCA in which the other make up systems (RCIC and HPCI) fail to maintain vessel water level. This signal is one of four required to initiate ADS.
- 2. Drywell Pressure High A primary containment high pressure of 2 2 psig indicates that a breach of the nuclear system process barrier has occurred inside the drywell. The signal is one of four required to initiate the ADS.
3.2-58
BASES FOR LIMITING CONDITIONS FOR OPERATION 3.2.0. 3. RHR Pump Discharge' Pressure High 4
An RHR pump discharge pressure of 2 112 psig indicates that LPCI l flow is available when the reactor is depressurized. The presence of this signal means low pressure core standby cooling is available. Low pressure core standby cooling available is one of the four signals required to initiate ADS.
- 4. Core Spray Pump Discharge Pressure High A core spray pump discharge pressure of 2 137 psig indicates that l
- Core Spray flow is available when the reactor is depressurized.
The presence of this signal means low pressure core standby cooling is available. Low pressure core standby cooling available is one of the four signals required to initiate ADS.
- 5. Auto Depressurization Timer The 120-second delay time setting is chosen to be long enough so that the HPCI system has time to start, yet not so long that the core spray system and LPCI are unable to adequately cool the core if HPCI fails to start. An alarm in the main control room is annunciated each time either of the timers is timing. Resetting the automatic depressurization system logic in the presence of tripped initiating signals recycles the timers.
(
\]/ 6. Automatic Blowdown Control Power Failure Monitor The Automatic Blowdown Control Power Failure Monitor monitors the availability of power to the logic system. In the event of loss of availability of power to the logic system, an alarm is annunciated in the control room.
E. Instrumentation Which Initiates or Controls the LPCI Mode of RHR (Table 3.2-5)
- 1. Reactor Vessel Water Level Low Low Low (Level 1) , ,
Reactor vessel low water level (Level 1) initiates LPCI and indi-cates that the core is in danger of being overheated because of an insufficient coolant inventory. This level is sufficient to allow the timed initiation of the various valve closure and loop selection routines to go to completion and still successfully perform its design function.
l lO 3.2-59 1
BASES FOR LIMITING CONDITIONS FOR OPERATION I
.I 2. Drywell Pressure High Primary containment high pressure could indicate a break in the l nuclear. system process barrier inside the drywell. The high drywell pressure setpoint is selected to be high enough to l avoid spurious starts but low enough to allow timely system initiation.
- 3. Reactor Vessel Steam Dome Pressure Low l The Bases for Reactor Pressure (Shutdown Cooling Mode) are discussed in the Bases for Specification 3.2.A.2.
With an analytical limit of 2 300 psig and a nominal trip setpoint of 370 psig, the recirculation discharge valve will close successfully during l a LOCA condition.
Once the LPCI system is initiated, a reactor low pressure setpoint of 460 l psig produces a signal which is used as a permissive to open the LPCI in-jection valves. The valves do not open, however, until reactor pressure falls below the discharge head of LPCI.
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3.2-60
BASES FOR LIMITING CONDITIONS FOR OPERATION
/' ') 3.2.E.4 Reactor Shroud Water Level Low (Level 0)
(J A reactor water level 2-202 inches below instrument zero is indicative that LPCI has made progress in reflooding the core. A simultaneous high drywell pressure trip indicates the need for containment cooling. The 2-202 inch l setpoint acts as a permissive for manual diversion for some of the LPCI flow to containment spray.
- 5. LPCI Cross Connect Valve Open Annunciator With the modified LPCI arrangement, the cross connect valve status was changed from normally open to normally closed. Inadvertent opening of this valve could negate the LPCI system injection when needed. The annunciator will alarm when the LPCI cross connect valve is not fully closed.
\
- 6. RHR (LPCI) Pump Flow Low A flow element and differential pressure transmitter are provided down-stream of each pair of RHR pumps in their common line. To protect the pumps from overheating at low flow rates, a minimum flow bypass with a O,_,
s restricting orifice is provided for each pump which routes water through the common motor-operated valve to the suppression chamber. This mini-
, mum flow bypass valve automatically opens upon sensing low flow in the common discharge piping. The valve automatically closes whenever the flow (whether from both pumps or a single pump) is above the low flow setting.
, l l
i If normal AC power is available, four pumps automatically , start without delay. If normal AC power is not available one pump starts without de-
! lay as soon as power becomes available from the standby sources. The l other three pumps start after a 10-second delay. The timer provides cor-i rect sequencing of the loads to the diesel generator.
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V 3.2-61 i
L
BASES FOR LIMITING CONDITIONS FOR OPERATION
('O ') 3.2.E.8 Valve Selection Timers l
After 10 minutes, a timer cancels the LPCI signals to the injection valves.
The cancellation of the signals allows the operator to divert the water for other post-accident purposes. Cancellation of the signals does not cause the injection valves to move.
- 9. RHR Relay Logic Power Failure Monitor The RHR Relay Logic Power Failure Monitor monitors the availability of power to the logic system. In the event of loss of availability of power to the logic system, an alarm is annunciated in the control room.
F. Instrumentation Which Initiates or Controls Core Spray (Table 3.2-6)
- 1. Reactor Vessel Water Level Low Low Low (Level 1)
A reacter low water level of -113 inches (level 1) initiates Core Spray l This level is indicative that the core is in danger of being overheated because of an insufficient coolant inventory.
- 2. Drywell pressure High Primary containment high pressure is indicative of a break in the nuclear system process barrier inside the drywell. The high drywell pressure set-point of 5 2 psig is selected to be high enough to avoid spurious system initiation but low enough to allow timely system initiation.
(]
v
- 3. Reactor Vessel Steam Dome Pressure Low Once the core spray system is initiated, a reactor low pressure setpoint of 460 psig produces a signal which is used as a permissive to open the core l spray injection valves. The valves do not open, however, until reactor pres-sure falls below the discharge head of the core spray system.
- 4. Core Spray Sparger Differential Pressure A detection system is provided to continuously confirm the integrity of the core spray piping between the inside of the reactor vessel and the core shroud. A differential pressure switch measures the pressure difference be-tween the top of the core support plate and the inside of the core spray sparger pipe just outside the reactor vessel. If the core spray sparger pip-ing is sound, this pressure difference will be the pressure drop across the core resulting from inter-channel leakage. If integrity is lost, this pres-sure drop will include the steam separator pressure drop. An increase in the normal pressure drop initiates an alarm in the main control room.
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3.2-62
BASES FOR LIMITING CONDITIONS FOR OPERATION Tl 3.2.F.5. Core Spray Pump Discharge Flow D
A differential pressure transmitter is provided downstream of each core spray l pump to indicate the condition of each pump. To protect the pumps from over-heating at low flow rates a minimum flow bypass line, which routes water from the pump discharge to the suppression chamber, is provided. A single motor-operated valve controls the condition of each bypass line. The minimum flow bypass valve automatically opens upon sensing low flow in the discharge line.
The valve automatically closes whenever the flow is above the low flow setting.
- 6. Core Spray Logic Power Failure Monitor The Core Spray Logic Power Failure Monitor monitors the availability of power to the logic system. In the event of loss of availability of power to the logic system, an alarm is annunciated in the control room.
G. Neutron Monitoring Instrumentation Which Initiates Control Rod Blocks (Table 3.2-7)
These control rod block functions are provided to prevent excessive control Q
V rod withdrawal so that MCPR does not decrease to 1.07. The trip logic for this function is 1 out of n: e.g. , any trip on one of six APRM's, eight IRM's or four SRM's will result in a rod block.
The minimum instrument channel requirements assure sufficient instrumentation to assure that the single failure criteria is met.
- 1. SRM
- a. Inoperative This rod block assures that no control rod is withdrawn during low neutron flux level operations unless proper neutron monitoring capa-bility is available, in that all SRM channels are in service or properly bypassed.
- b. Not Fully Inserted Any source range monitor not fully inserted into the core when the SRM count rate level is below the retract permit level will cause a rod block. This assures that no control rod is withdrawn unless all SRM detectors are properly inserted when they must be relied upon to pro-vide the operator with a knowledge of the neutron flux level.
- c. Downscale This rod block assures that no control rod is withdrawn unless the
[ SRM count rate is above the minimum prescribed for low neutron flux level monitoring.
3.2-63
r Table 3.7-1 (Concluded) g Primary Containment Isolation Valves V These notes refer to the lower case letters in parentheses on the previous page.
NOTES:
- a. Key: 0 = Open SC = Stays closed C = Closed GC = Goes closed
- b. Isolation Groupings are as follows:
GROUP 1: The valves in Group 1 are actuated by any one of the following conditions:
- 1. Reactor vessel water level Low Low Low (Level 1)
- 2. Main steam line radiation high
- 3. Main steam line flow high
- 4. Main steam line tunnel temperature high
- 5. Main steam line pressure low
- 6. Condenser vacuum low GROUP 2: The valves in Group 2 are actuated by one one of the following conditions:
- 1. Reactor vessel water level low (Level 3)
- 2. Drywell pressure high GROUP 3: Isolation valves in the high pressure coolant injection (HPCI) system are actuated by any one of the following conditions:
- 1. HPCI steam line flow high
- 2. High temperature in the vicinity of the HPCI steam line
- 3. HPCI steam supply pressure low
- 4. HPCI turbine exhaust diaphragm pressure l GROUP 4: Primary Containment Isolation valves in the reactor core isolation cooling (RCIC) system are actuated by any one of the following conditions:
- 1. RCIC steam line flow high
- 2. High temperature in the vicinity of the RCIC steam line
- 3. RCIC steam supply pressure low l GROUP 5: The valves in Group 5 are actuated by any one of the following conditions:
- 1. Reactor vessel water level Low Low (Level 2)
- 2. Reactor water cleanup area temperature high
- 3. Reactor watdr cleanup area ventilation differential emperature high .
- 4. Reactor water cleanup system differential flow high
- 5. Actuation of Standby Liquid Control System - closes outside valve or.ly
- 6. High temperature following non-regenerative heat exc1 anger - closes outside valve only GROUP 6: The valves in Group 6 are actuated by the following conditions:
- 1. Reactor vessel water level low (Level 3)
- 2. Reactor vessel steam dome pressure low permissive l
- c. Requires a Group 2 signal or a Reactor Building ventilation hjgh radiation isolation signal.
- d. For redundant lines, only one set of valves is listed. Other sets are identical except for valve numbers, which are included. Valve numbers are listed in order from within primary containment outward for each line.
- e. Not applicable to check valves.
O 3.7-19
9 APPENDIX 1 SIGNIFICANT HAZARDS REVIEW 4
. 4 9
/" ' Overview of the Individual 10 CFR 50.92 Evaluations of the Proposed ATTS-As Related Technical Specifications Changes for the Edwin I. Hatch Nuclear Plant-Unit 1 The proposed Technical Specifications changes, which Georgia Power Company (GPC) is proposing for use with the new analog transmitter trip system (ATTS) currently being installed at Hatch 1, include new instrument trip setpoints/ allowable values and surveillance intervals which take credit for the advantages that the new devices have over those currently installed at the plant, in terms of setpoint drift and instrument accuracy. In addition to these types of revisions, this submittal also proposes a number of other types of Technical Specifications changes including the following:
e Changes which account for modifications to instrument loops or trip logic resulting from the new ATTS design.
e Changes which correct minor typographical or descriptive errors found in the Hatch 1 Technical Specifications during the safety review process for ATTS. (The errors found do not necessarily affect sections covering requirements for ATTS components.)
e Changes to the Technical Specifications Bases sections which correct existing errors and update them with respect to the other proposed ATTS changes.
All of these proposed modifications were based on Nuclear Regulatory r-'s Commission (NRC) and industry standards listed in Table Al-1 of this (j appendix, to the extent practicable. It should be noted that use of several documents in Table Al-1 goes beyond the extent of commitments made by GPC, including those made in the Hatch 1 FSAR, and that their use in the design and implementation of ATTS does not represent an extension by GPC of these commitments to other plant systems designed to other criteria. If conflicts arose between the requirements of the FSAR and those contained in the listed standards, the requirements of Hatch 1 FSAR section 7.1 and Appendix F were followed by GPC. -
The individual 10 CFR 50.92 evaluations contained in the following pages, when taken collectively, provide a complete evaluation for significant hazards resulting from all proposed ATTS-related license changes. Based on the conclusion of each of the individual reviews, which was that each type or group of changes did not result in a significant hazard as defined in 10 CFR 50.92, GPC has determined that the same conclusion is valid for this entire license change proposal.
4 1
lO i Al-1 i
I
s TABLE Al-1
(}
ANALOG TRANSMITTER TRIP SYSTEM CONFORMANCE CRITERIA (SHEET 10F 3) i IEEE Standards .
IEEE-279-1971: Criteria for Protection System for Nuclear Power Generating Station IEEE-323-1974: Qualifying Class IE Equipment for Nuclear-Power Generating Stations i
IEEE-336-1977: Installation, Inspection and Testing Requirements for Instrumentation and Electrical Equipment During the Construction of Nuclear Power Generating Stations IEEE-338-1977: Criteria for Periodic Testing of Nuclear Power Generating Station Safety Systems IEEE-344-1975: Recommended Practices for, Seismic Qualification of Class 1E
?
Equipment for Nuclear Power Generating Stations -
IEEE-397-1977: Application of the Single-Failure Criterion to Nuclear Power Generating Station Class 1E Systems Trial-Use Guide for Class 1E Control Switchboards for Nuclear O IEEE-420-1973:
Power Generating Stations IEEE-494-1974: Method for Identification of Documents Related to Class 1E
- Equipment and Systems for Nuclear Power Generating Stations NRC Regulatory Guides i Regulatory Guide 1.22
- Periodic Testing of Protection System Actuation Functions Regulatory Guide 1.28: Quality Assurance Program Requirements Regulatory Guide 1.29: Seismic Design Classification Regulatory Guide 1.30: Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electrical Equipment
! Regulatory Guide 1.38: Quality Assurance Requirements for Packing, Shipping, Receiving, Storage, and Handling of Items for Water-Cooled Nuclear Power
, Plants
! Regulatory Guide 1.47: Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems 4
/O TABLE Al-1 (SHEET 2 0F 3)
U NRC Regulatory Guides (continued)
Regulatory Guide 1.53: Application of the Single-Failure Criterion to Nuclear Power Plant Protection Systems Regulatory Guide 1.61: Damping Value for Seismic Design of Nuclear Power Plants.
Regulatory Guide 1.62: Manual Initiation of Protective Actions Regulatory Guide 1.64: Quality Assurance Requirements for the Design of Nuclear Power Plants Regulatory Guide 1.68: Initial Test Program for Water-Cooled Reactor Power Plants Regulatory Guide 1.75: Physical Independer.:e of Electrical Systems Regulatory Guide 1.89: Qualification of Class 1E Equipment for Nuclear Power Plants Regulatory Guide 1.92: Combining Modal Responses and Spatial Components in Seismic Response Analysis Regulatory Guide 1.97: Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident Regulatory Guide 1.100: Seismic Qualification of Electric Equipment for Nuclear Power Plants Regulatory Guide 1.131: Qualification Tests of Electric Cables, Field Splices, and Connections for Light-Water-Cooled Nuclear Power Plants NRC Regulations
- Regulation 10 CFR 21: Reporting of Defects and Noncompliance Regulation 10 CFR 50.49: Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants Regulation 10 CFR 50.55a: Issuance, Limitation and Conditions of Licenses and Construction Permits (CP) - Codes and Standards Reg'ulation 10 CFR 50, Appendix A: General Design Criteria (GDC) for Nuclear Power Plants O
t TABLE Al-1 (SHEET 3 0F 3)
General Design Criteria GDC 1: Quality Standards and Records GDC 2: Design Basis for Protection Against Natural Phenomena GDC 5: Sharing.of Structures, Systems, and Components GDC'10: Reactor Design GDC 13: Instrumentation and Control GDC 20: Protection System Functions GDC 21: Protection System Reliability and Testability GDC 22: Protection System Independence GDC 23: Protection System Failure Mode GDC 24: Separation of Protection and Control Systems GDC 29: Protection Against Anticipated Operational Occurrences
._O 9
(N A
10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica-tions Surveillance Requirements as a Result of the Installation of the Analog Transmitter Trip System for Edwin I. Hatch Nuclear Plant-Unit 1<a>
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92.as they relate to the proposed Technical Specification changes due to the installation of the analog transmitter trip system (ATTS). ATTS replaces the pressure, level, and temperature switches in the reactor protection system and the emergency core cooling system (ECCS) with analog sensor / trip unit combinations. The system is designed to improve sensor intelligence and reliability, while still providing continued monitoring of critical parameters and performing the intended basic logic function. Since the ATTS instrumentation is superior in design to the mechanical switches currently used at Plant Hatch, certain surveillance intervals may be extended without any significant effect on the expected magnitude of sensor drift or frequency of instrument malfunction. GPC proposes to change the surveillance requirements for the ATTS instrumentation to once per shift for channel checks, once per month for channel functional tests, and once per operating cycle for channel calibrations. These proposed surveillance requirements were previously approved on a generic bases for ATTS equipment by the Nuclear Regulatory Commission (NRC) review of the General Electric Company topical report NEDO 21617-A. These standardized interval changes for ATTS were also approved for specific use at Plant Hatch in License Amendments 33 and 39 for Unit 2 and 103 and 104 for Unit 1. Additional changes to the nomenclature used in the Technical Specifications are included for clarification and consistency with this proposed change.
GPC reviewed the proposed changes and considers them not to involve a significant hazards consideration for the following reasons:
- 1. They would not significantly increase the probability or consequences of an accident previously evaluated, because the new ATTS instrumenty have been demonstrated to be superior in design to the existing devices in terms of instrument inaccuracy and drift characteristics. In addition, the new setpoints have been rigorously calculated, assuming the proposed surveillance '
frequencies.
- 2. They would not create the possibility of a new or different accident from any accident previously evaluated, because the new surveillance intervals for ATTS were developed to be consistent with the Plant Hatch-Unit 1 Final Safety Analysis Report (FSAR) descriptions.
- 3. They would not involve a significant reduction in a margin of safety, because the new surveillance requirements are tailored to the ATTS instruments, using the methodology of Regulatory Guide 1.105. In addition, the bases for the margins of safety, as described in the FSAR, have been maintained,
- a. See section 3B (page 3-3) for discussion of proposed revisions.
Al-2
/Q 10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica-V tions due to the Reactor Core Isolation Cooling Turbine Exhaust Pressure Trip Setpoint Modification for Edwin I. Hatch Nuclear Plant-Unit 1<a>
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed change to the Technical Specifications due to the reactor core isolation cooling (RCIC) turbine exhaust pressure trip setpoint modification. The proposed Technical Specifications raise the trip setpoint/ allowable value for the RCIC turbine exhaust pressure from 25 psig to 45 psig. As discussed in NEDC-30136, this change will increase RCIC availability during small and intermediate break loss-of-coolant accidents by allowing a longer period of RCIC operation before its turbine is tripped off by high pressure in the primary containment. Raising the setpoint also allows RCIC to provide a backup to high pressure coolant injection (HPCI) over a range of small breaks and provides more time for an operator to recover other systems if either HPCI and/or automatic depressurization system are unavailable.
GPC reviewed the proposed change and considers it not to involve a significant hazards consideration for the following reasons:
- 1. It will not significantly increase the probability or consequences of an accident previously evaluated, because the radiological effects due to the increased RCIC availability during accident conditions are well within 10 CFR 20 limits.
[)
L. 2. It will not create the possibility of a new or different kind of accident from any accident previously evaluated, because RCIC will still operate as required by design.
- 3. It will not involve a significant reduction in a margin of safety, because the slight increase in onsite radiological effects is outweighed by the potential for increased RCIC operability.
- a. See subsection 48.1 (page 4-2) for discussion of proposed revisions.
O Al-3
,r 10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica-( )) tions due to the Deletion of Drywell Pressure Sensors E11-N011A, B, C, D for Edwin I. Hatch Nuclear Plant-Unit 1ca Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed change to the Technical Specifications due to the deletion of drywell pressure sensors E11-N011A, B, C, D. This change proposes to make drywell pressure sensor configuration consistent with water levels 2 and 3 sensor logic. Drywell pressure sensors E11-N010A, B, C, D may be used to provide signals for all four systems of the eniergency core cooling system and still maintain single failure criteria. The Technical Specifications change involves adding to the Remarks column all the functions of the drywell pressure sensors.
GPC has reviewed the proposed change and considers it not to involve a significant hazards consideration for the following reasons:
- 1. It will not significantly increase the probability or consequences of an accident previously evaluated, because the new logic configuration still fulfills the FSAR criteria.
- 2. It will not create the possibility of a new or different kind of accident from any previously evaluated, because the new logic will still basically operate in the same manner as the current configuration.
O
(_,/ 3. It will not involve a significant reduction in a margin of safety, because the current level of instrument redundancy will be maintained by the new logic, i
f I
- a. See subsection 48.2 (page 4-3) for discussion of proposed revisions.
O Al-4
10 CFR 50.92 Evaluation for the Proposed Change to the Post-Accident Monitoring Instrument Technical Specifications for Edwin I. Hatch Nuclear Plant-Unit Ica>
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed changes to the Technical Specifications due to the post-accident monitoring instrument modifications. The proposed. Technical Specifications revised the instrument ranges for the reactor vessel water level, shroud level and reactor pressure recorders and indicators, which are being replaced to be compatible with ATTS. It is also proposed to revise the -
calibration frequency from a six month interval to once per operating cycle for the instrument loop but also require that the ' recorders themselves be calibrated once per twelve months. The yearly calibration for the recorders is the manufacturer's recommended interval. The manufacturer's recommended calibration frequency for the indicators is once per S years. Since the pro-posed loop surveillance is once per 18 months, an individual calibration fre-quency for the indicators is not required. These changes in calibration frequency take into account the abilities of ATTS and the new recorders.
GPC reviewed the proposed changes and considers them not to involve a significant hazards consideration for the following reasons:
- 1. They will not significantly increase the probability or consequences of an accident previously evaluated because the revisions to the instrument ranges merely updates information and the proposed
[ calibration frequency is tailored to the new instruments.
- 2. They will not create the possibility of a new or different kind of accident from any accident previously evaluated, because the instrument functions, as described in the FSAR, are unchanged.
- 3. They willnot involve a significant reduction in a margin of safety, because the revisions to the instrument ranges merely updates information and the proposed calibration frequency takes credit for -
the improved instrumentation.
- a. See subsection 48.3 (page 4-4) for discussion of proposed revisions.
Al-5
r'% 10 CFR 50.92 Evaluation for the Proposed Trip Setpoint/ Allowable Values for h Rosemount Transmitters Chan HatchNuclearPlant-Unitl'gestotheTechnicalSpecificationsforEdwinI.
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed Technical Specification changes to the trip setpoint/ allowable values for reactor vessel ' vater levels 1, 2 and 3; shroud water level and reactor steam dome pressure instruments. The new values were determined using the criteria of Regulatory Guide 1.105 and the specifications of both the Barton Model 764 and Rosemount Model 1154 Transmitters. This will allow Rosemount transmitters, as well as, Bartons to be installed in the plant.
GPC reviewed the proposed changes and considers them not to involve a significant hazards consideration for the following reasons:
- 1. They will not significantly increase the probability or consequences of an accident previously evaluated, because the Barton and Rosemount transmitters are considered equivalent instruments. In addition, the new setpoints were calculated using the criteria of Regulatory Guide 1.105, and therefore, still meet the FSAR criteria.
- 2. They will not create the possibility of a new or different kind of accident from any accident previously evaluated, because the trip q functions, as described in the FSAR, remain unchanged.
D 3. They will not involve a significant reduction in a margin of safety, because the original basis for the setpoints is maintained. In addition, the setpoints were determined using the criteria of
-Regulatory Guide 1.105.
- a. See subsection 48-4 (page 4-5) for discussion of proposed revisions.
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o 10 CFR 50.92 Evaluation for the Proposed Reactor Steam Dome Pressure d Permissive Modification to the Technical Specifications for Edwin I. Hatch Nuclear Plant-Unit 1<a>
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed reactor steam dome pressure permissive modification to the Technical Specifications. This change proposes to delete the upper bound limit to the reactor steam dome pressure permissive to the CS and LPCI injection valves. The current Technical Specifications have an upper and lower limit. The 500 psig upper bound limit was originally in the Technical Specifications to provide overpressurization protection for the RHR systen..
However, the reactor pressure permissive signal requires a concurrent LOCA signal to open the normally closed injection valves to provide a flow path for LPCI injection. The concurrent signal requirements are intended to minimize the potential for inadvertent valve opening during normal power operation. During normal power operation, the injection valves also serve as the redundant isolation valves to the F050A,B valves. During accident conditions the LPCI signal takes precedence and demands the injection valves to open. The transient time at the pressure slightly above the minimum design pressure of the low pressure piping is relatively short. The containment isolation check valves (F050A,B) and the relief valves are capable of providing adequate overpressure protection during this short period in an accident.
GPC reviewed the proposed change and considers it not be involve a significant hazard consideration for the following reasons:
- 1. It will not significantly increase the probability or consequences of an accident previously evaluated because adequate overpressurization protection is still available for the system, and the system design as described in the FSAR is unchanged.
- 2. It will not create the possibility of a new or different kind of accident from any accident previously evaluated because the overpressurization protection of the system is maintained, and the system design as described in the FSAR is unchanged.
- 3. It will not involve a significant reduction in the margin of safety because the original basis of this Technical Specification, which is to ensure CS and LPCI operation as reactor pressure drops during accident conditions, is maintained. In addition, the new trip setpoint/ allowable value was calculated using methodology previously approved by the NRC and is more conservative than the current value with respect to the lower analytical limit.
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- a. See subsection 4B-5 (page 4-6) for discussion of proposed revisions.
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A 10 CFR 50.92 Evaluation for the Proposed Trip Function Identification 1'~~J Changes to the Technical Specifications for Edwin I. Hatch Nuclear Plant-Unit Ica>
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed trip function identification changes to the Technical Specifications. Since the proposed changes only involve revisions in nomenclature, GPC considers them to be purely administrative in nature.
As discussed above, the proposed changes only involve changes in nomenclature. GPC determined that these proposed changes are consistent with Item (1) of the " Examples of Amendments that are Considered Not Likely to Involve Significant Hazards Considerations" listed on page 14,870 of the April 6, 1983, issue of the Federal Register and will not involve a significant hazards consideration.
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- a. See subsection 48.6 (page 4-7) for discussion of proposed revisions.
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n 10 CFR 50.92 Evaluation for the Proposed Miscellaneous Trip Setpoint/ Allow-( ) able Value Modifications to the Technical Specifications for Edwin I. Hatch Nuclear Plant-Unit 1<a>
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed miscellaneous trip setpoint/ allowable value modifications to the Technical Specifications. The purpose of this change is to update the Technical Specifications trip setpoints being eplaced by the analog transmitter trip system (ATTS). Since the time that original setpoints were determined, a better calculational method has been developed.
This proposed change uses the Regulatory Guide 1.105 methodology in updating the setpoints for the instruments being replaced with the ATTS units, and takes credit for the improved error and drift characteristics of the new system. This change replaces the trip setpoints listed in the Technical Specifications which are the original analytical limits with the newly evaluated allowable values determined through Regulatory Guide 1.105 methodology.
GPC reviewed the proposed changes and considers them not to involve a significant hazards consideration for the following reasons:
- 1. They will not significantly increase the probability or consequences of an accident previously evaluated, because the new ATTS instruments are of a superior design as compared to the current instruments. In addition, the setpoints were determined using the e criteria of Regulatory Guide 1.105, and therefore, still meet the
!m) Final Safety Analysis Report (FSAR) criteria.
- 2. They will not create the possibility of a new or different kind of accident from any accident previously evaluated, because the basic trip functions, as described in the FSAR, are unchanged.
- 3. They will not involve a significant reduction in a margin of safety, because for most trips, the original design basis was maintained.
Any w design bases were fully addressed with regard to FSAR requirements. In addition, Regulatory Guide 1.105 criteria were used in the calculation of the new setpoints.
- a. See subsection 48.7 (page 4-8) for discussion of proposed revisions.
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APPENDIX 2 NEDC-303?6
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