ML20080L635
| ML20080L635 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 09/15/1983 |
| From: | Schwencer A Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20080L639 | List: |
| References | |
| NUDOCS 8310030085 | |
| Download: ML20080L635 (122) | |
Text
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w MISSISSIPPI POWER AND LIGHT COMPANY HlDULL buuTH LNERbY, IfiC.
SOUTH HISSI5blPPI ELECTRIC POWER ASSOCIATION DOCKET NO.00-410 GRAND GULF huCLLAk $TATION, UNIT 1 AMLhuhtHT TO FACILITY OPLRATlhu LICENSE License No. hPF-13 Amendment No. 9 1.
The Nuclear Regulatory Comission (the Commission or the HRC) has found that:
A.
The applications for the amendment filed by the Mississippi Power and Light Company dated June 9,1983, June 14,1983, June 23,1983, June 29,1983, July 19,1983, August 1, 1983, August 9, 1983, August IS,1983, and August 29, 1983, comply with the standards and requirenents of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in 10 CFR Chapter I; B.
The facility will operate in conformity with the applications, the provisions of the Act, and the regulations of the Comission; i
C.
There is reasonable assurance:
(1) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (11) that such activities will be conducted in compliance with the Cc.nmission's regulations; D.
The issuance of this amendment will not be inimical to the comon defense and security or to the health and safety of the public; and E.
The issuance of this amendment is in accordance with 10 CFR Part 51 of the Comission's regulations and all applicable requirements have been satisfiec.
2.
Accordingly, the license is amended as follows:
A.
Page changes to the Technical Specifications as indicated in the attachment l
to this license amendment and paragraph 2.C.(2) to read as follows:
i (2) The Technical Specifications contained in Appendix A, as revised l
through Amendment No. 9, and the Environmental Protection Plan I
contained in Appendix B, are hereby incorporated in the license.
The licensees shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
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This amendment is effective as of the date of issuance.
FOR THE liUCLEAR REGULATORY ComISSION Original signed by A. Schwencer, Chief Licensing Branch No. 2 Division of Licensing Date of Issuance: September 15, 1983
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ATTACHMENT TO LICENSE AMENDMENT NO. 9 FACILITY OPERATING LICENSE NO. NPF-13 DOCKET NO. 50-416 Replace the following page of the Appendix "A" Technical Specifications with i
the enclosed page. This revised page is identified by Amendment number and contains a vertical line indicating the area of change.
REMOVE INSERT 3/4 1-4 3/4 1-4 3/4 1-7 3/4 1-7 3/4 3-8 3/4 3-8 3/4 3-10 3/4 3-10 thru thru 3/4 3-23 3/4 3-23a 3/4 3-25 3/4 3-25 3/4 3-56 3/4 3-56 3/4 3-58 3/4 3-58 3/4 3-59 3/4 3-59 3/4 3-70 3/4 3-70 3/4 3-72 3/4 3-72 3/4 3-76 3/4 3-76 3/4 3-77 3/4 3-77 3/4 3-78 3/4 3-78 3/4 3-79 3/4 3-79 3/4 3-80 3/4 3-80 3/44-5 3/4 4-5 3/44-6 3/4 4-6 3/4 4-22 3/4 4-22 3/4 5-4 3/45-4 l
3/46-1 3/46-1 3/4 6-27 3/4 6-27 3/4 6-29 3/4 6-29 3/4 6-30 3/4/6-30 3/4 6-31 3/4 6-31 3/4 6-32 3/4 6-32 3/4 6-33 3/4 6-33 3/4 6-34 3/4 6-34 3/4 6-35 3/4 6-35 l
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t REMOVE INSERT 3/4 6-37 3/4 6-37 3/4 6-38 3/4 6-38 3/4 6-39 3/4 6-39 3/4 6-40 3/4 6-40 3/4 6-41 3/4 6-41 3/4 6-42 3/4 6-42 3/4 6-44 3/4 6-44 3/4 6-46 3/4 6-46 3/4 6-47 3/4 6-47 3/4 6-48 3/4 6-48 3/4 6-53 3/4 6-53 3/4 6-54 3/4 6-54 3/4 7-1 3/4 7-1 3/4 7-4 3/4 7-4 3/4 7-5 3/4 7-5 3/4 7-6 3/4 7-6 3/4 7-31 3/4 7-31 thru thru 3/4 7-45 3/4 7-46 3/4 8-3 3/4 8-3 3/4 8-4 3/4 8-4 3/4 8-5 3/4 8-5 3/4 8-6 3/4 8-6 2
3/4 8-9 3/4 8-9 3/4 8-14 3/4 8-14 3/4 8-17 3/4 8-17 3/4 8-18 3/4 8-18 3/4 8-21 3/4 8-21 thru thru 3/4 8-46 3/4 8-46 B3/4 6-5 B3/4 6-5 B3/4 6-6 B3/4 6-6 B2/4 6-7 B3/4 7-1 B3/4 7-1 l
6-9 6-9 6-16 6-16 l
6-20 6-20
REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)
ACTION (Continued) 2.
If the inoperable control rod (s) is inserted, within one hour disarm the associated directional control valves ** either:
a)
Electrically, or b)
Hydraulically by closing the drive water and exhaust water isolation valves.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
3.
The provisions of Specification 3.0.4 are not applicable.
c.
With more than 8 control rods inoperable, bo in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
SURVEILLANCE REQUIREMENTS 4.1.3.1.1 The scram discharge volume drain and vent valves shall be demonstrated OPERABLE by:
a.
At least once per 31 days verifying each valve to be open,* and b.
At least once per 92 days cycling each valve through at least one complete cycle of full travel.
4.1.3.1.2 When above the low power setpoint of the RPCS, all withdrawn control rods not required to have their directional control valves disarmed electrically or hydraulically shall be demonstrated OPERABLE by moving each control rod at least one notch:
a.
At least once per 7 days, and b.
At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when any control rod is immovable as a result of excessive friction or mechanical interference.
4.1.3.1.3 All control rods shall be demonstrated OPERABLE by performance of Surveillance Requirements 4.1.3.2, 4.1.3.3, 4.1.3.4 and 4.1.3.5.
- These valves may be closed intermittently for testing under administrative controls.
~
May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status.
GRAND GULF-UNIT 1 3/4 1-4 Amendment No. 9 n-a
-. -. ____. -~ _ _ _ _
i:
3 REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)
ACTION:
(Continued) b.
With a " slow" control rod (s) not satisfying ACTION a.1, above:
- i 1.
Declare the " slow" control rod (s) inoperable, and 2.
Perform the Surveillance Requirements of Specification 4.1.3.2.c at least once per 60 days when operation is continued with three or more " slow" control rods declared inoperable.
Otherwise, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
c.
With the maximum scram insertion time of one or more control rods exceeding the maximum scram insertion time limits of Specification 3.1.3.2 as deter-mined by Specification 4.1.3.2.c, operation may continue provided that:
1.
" Slow" control rods, i.e., those which exceed the limits of Specification 3.1.3.2, do not make up more than 20% of the 10% sample of control rods tested, i
l' 2.
Each of these " slow" control rods satisfies the limits of ACTION a.1.
3.
The eight adjacent control rods surrounding each " slow" control rod are:
i a)
Demonstrated through measurement within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to satisfy the maximum scram insertion time limits of Specification 3.1.3.2, and i
b)
4.
The total number of " slow" control rods, as determined by Specifica-tion 3.1.3.2.c, when added to the sum of ACTION a.3, as determined by Specification 4.1.3.3.s and b, < foes not exceed 7.
Otherwise, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
l SURVEILLANCE REQUIREMENTS 4.1.3.2 The maximum insertion time of the control rods shall be demonstrated thraugh measurement with reactor coolant pressure greater than or equal to
[
950 psig and, during single control rod scram time tests, the control rod l
drive pumps isolated from the accumulators:
a.
For all control rods prior to THERMAL POWER exceeding 40% of RATED i
THERMAL POWER following CORE ALTERATIONS
- or after a reactor shutdown I
that is greater than 120 days, b.
For specifically affected individual control rods ** following l
maintenance on or modification to the control rod or control rod drive system which could affect the scram insertion time of those I
specific control rods, and c.
For at least 10% of the control rods, on a rotating basis, at least once per 120 days of POWER OPERATION.
"Except movement of SRM IRM, or special removable detectors or normal control rod movement.
- The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITION 2 provided this surveillance is completed prior to entry into OPERATIONAL CONDITION 1.
GRAND GULF-UNIT 1 3/4 1-7 Amendment No. 7, 9 g
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TABLE 4.3.1.1-1 (Continued)
REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS
[
E CHANNEL OPERATIONAL G
CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH ch FUNCTIONAL UNIT CHECK TEST CALIBRATION SURVEILLANCE REQUIRED t
9.
Scram Discharge Volume Water f9)
Level - High S
M R
1, 2, 5 I9) 10.
Turbine Stop Valve - Closure S
M R
1 11.
Turbine Control Valve Fast Closure Valve Trip System Oil I9)
Pressure - Low S
M R
1 12.
Reactor Mode Switch Shutdown Position NA R
NA 1,2,3,4,5 13.
Manual Scram NA M
NA 1,2,3,4,5 f
(a) Neutron detectors may be excluded from CHANNEL CALIBRATION.
(b) The IRM and SRM channels shall be determined to overlap for at least 1/2 decade during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be deter-mined to overlap for at least 1/2 decade during each controlled shutdown, if not performed within the previous 7 days.
(c) Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to startup, if not performed within the previous 7 days.
(d) This calibration shall consist of the adjustment of the APRM channel to conform to the power values calculated by a heat balance during OPERATIONAL CONDITION 1 when THERMAL POWER > 25% of RATED THERMAL POWER. Adjust the APRM channel if the absolute difference is greater than 2% of RATED 5
THERMAL POWER. Any APRM channel gain adjustment made in compliance with Specification 3.2.2 l
E shall not be included in determining the absolute difference.
R (e) This calibration shall consist of the adjustment of the APRM flow biased channel to conform to a P,
calibrated flow signal.
2 (f) The LPRMs shall be calibrated at least once per 1000 effective full power hours (EFPH) using the TIP system.
~
(g) Calibrate trip unit at least once per 31 days.
y i
(h) Verify measured drive flow to be less than or equal to established drive flow at the existing flow con-l trol valve position.
(i) This calibration shall consist of verifying the 6 i 1 second simulated thermal power time constant.
TABLE 3.3.2-1 ISOLATION ACTUATION INSTRUMENTATION E
VALVE GROUPS MINIMUM APPLICABLE G
OPERATED BY OPERABLE CHANNELS OPERATIONAL y
TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b)
CONDITION ACTION Z
1.
PRIMARY CONTAINMENT ISOLATION a.
Reactor Vessel Water Level-Low Low, Level 2 6A, 7, 8, 10(c)(d) 2 1, 2, 3 and #
20 b.
Reactor Vessel Water Level-Low Low Level 2 (ECCS -
Division 3) 6B 4
1, 2, 3 and #
29 c.
Reactor Vessel Water i.evel-Low Low Low, Level 1 (ECCS -
In)
Division 1 and Division 2)
S 2
1, 2, 3 and #
29 d.
Drywell Pressure - High 6A, 7(c)(d)
{
2 1,2,3 20 w
e.
Drywell Pressare-High 4
(ECCS - Division 1 and IS ")
2 1,2,3 29 Division 2) f.
Drywell Pressure-High (ECCS - Division 3) 6B 4
1,2,3 29 g.
Containment and Drywell Ventilation Exhaust 2 *)
1, 2, 3 and
- 21 I
Radiation - High High 7
h.
Manual Initiation 6A, 7, 8, 10(c)(d) 2 1, 2, 3 and *#
22 2.
MAIN STEAM LINE ISOLATION a.
Reactor Vessel Water Level-g Low Low Low, Level 1 1
2 1,2,3 20 m
R b.
Radiation - High 1, 10(I) 2 1,2,3 23 a
c.
Pressure - Low 1
2 1
24 P
d.
Main Steam Line I9)
Flow - High 1
2 1, 2, 3 23 u
e.
Condenser Vacuum - Low 1
2 1,2,3 23 e
n TABLE 3.3.2-1 (Continued) 5g ISOLATION ACTUATION INSTRUMENTATION h
VALVE GROUPS MINIMUM APPLICABLE T
OPERATED BY OPERABLE CHANNELS OPERATIONAL g
TRIP FUNCTION SIGNAL (a), PER TRIP SYSTEM (b)
CONDITION ACTION i
[
2.
MAIN STEAM LINE ISOLATION (Continued) f.
Main Steam Line Tunnel Temperature - High 1
2 1,2,3 23 g.
Main Steam Line Tunnel a Temp.- High 1
2 1,2,3 23 h.
Manual Initiation 1, 10 2
1,2,3 22 i
3.
SECONDARY CONTAINMENT ISOLATION a.
Reactor Vessel Water R
Level-Low Low, Level 2 N.A.(c)(d)(h) 2 1, 2, 3, and #
25
[
b.
Drywell Pressure - High N.A.(c)(d)(h) 2 1,2,3 25 c.
Fuel Handling Area N.A.II) 2 1, 2, 3, and
- 25 h
Ventilation Exhaust Radiation - High High I
d.
Fuel Handling Area i
Pool Sweep Exhaust j
Radiation - High High N.A.(I) 2 1, 2, 3, and
- 25 i
e.
Manual Initiation 2
1,2,3 6
Ig 4.
REACTOR WATER CLEANUP SYSTEM ISOLATION a.
A Flow - High 8
1 1,2,3 27
&g b.
A Flow Timer 8
1 1,2,3 27
[
l c.
Equipment Area Temperature -
8 1/ room 1, 2, 3 27
.o High
.m d.
Equipment Area a Temp. -
l High 8
1/ room 1,2,3 27 u
e.
Reactor Vessel Water Level - Low Low, Level 2 8
2 1,2,3 27
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TABLE 3.3.2-1 (Continued)
E g
ISOLATION ACTUATION INSTRUMENTATION VALVE GROUPS MINIMUM APPLICABLE Q
OPERATED BY OPERABLE CHANNELS OPERATIONAL E
TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b)
CONDITION ACTION l
5 i
]
4.
REACTOR WATER CLEANUP SYSTEM ISOLATION (Continued) i 4
f.
Main Steam Line Tunnel 8
1 1,2,3 27 Ambient Temperature - High g.
Main Steam Line Tunnel A Temp. - High 8
1 1,2,3 27 I
4 I) h.
SLCS Initiation 8
NA 1, 2, 3 27 el l
1.
Manual Initiation 8
2 1,2,3 26 l
5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION f
w
'S w
a.
RCIC Steam Line Flow - High 4
1 1,2,3 27 4
^)
b.
RCIC Steam Supply e
g)
Pressure - Low 4, 9 1
1,2,3 27 l
7 c.
RCIC Turbine Exhaust i
Diaphragm Pressure - High 4
2 1,2,3 27 d.
RCIC Equipner,i. Room Ambient Temperatura - High 4
1 1,2,3 27 i
e.
RCIC Equipment Room A Temp.
l
- High 4
1 1,2,3 27 k
f.
Main Steam Line Tunnel R
Ambient Temperature - High 4 1
1,2,3 27
?.
5 g.
Main Steam Line Tunnel A Temp. - High 4
1 1,2,3 27 z
P h.
Main Steam Line Tunnel Temperature Timer 4
1 1,2,3 27 P
m
..m TABLE 3.3.2-1 (Continued)
S g
ISOLATION ACTUATION INSTRUMENTATION VALVE GROUPS MINIMUM APPLICABLE i: '
G; OPERATED BY OPERABLE CHANNELS OPERATIONAL j.
TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b)
CONDITION ACTION 5
5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION w
i.
RHR Equipment Room Ambient Temperature - High 4
1/ room 1, 2, 3 27 j.
RHR Equipment Room A Temp. -
High 4
1/ room 1, 2, 3 27 k.
RHR/RCIC Steam Line Flow -
High 4
1 1,2,3 27 1.
Manual Initiation 4(k) 1 1,2,3 26 9 ")
1 1,2,3 27 f
m.
Drywell Pressure-High (ECCS-Division 1 and w
Division 2) 6.
RHR SYSTEM ISOLATION a.
RHR Equipment Room Ambient Temperature - High 3
1/ room 1, 2, 3 28 l-b.
RHR Equipment Room A Temp. - High 3
1/ room 1, 2, 3 28 c.
Reactor Vessel Water k
Level - Low, Level 3 3
2 1,2,3 28 5g d.
Reactor Vessel (RHR Cut-in Permissive) Pressure -
=
I)
[
High 3
2 1,2,3 28 II) e.
Drywell Pressure - High 3
2 1,2,3 28 f.
Manual Initiation 3
2 1,2,3 26
INSTRUMENTATION TABLE 3.3.2-1 (Continued)
ISOLATION ACTUATION INSTRUMENTATION ACTION ACTION 20 Be in at least HOT SHUTOOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 21 Close the affected system isolation valve (s) within one hour or:
a.
In OPERATIONAL CONDITION 1, 2, or 3, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
In Operat%1 Condition *, suspend CORE ALTERATIONS, handling of irradiated fuel in the primary containment and operations with a potential for draining the reactor vessel.
ACTION 22 Restore the manual initiation function to OPERABLE status within
+
48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 23 Be in at least STARTUP with the associated isolation valves closed within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or be in at least HOT SHUT 00WN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Be in at least STARTUP within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
ACTION 24 ACTION 25 Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within one hour.
ACTION 26 Restore the manual initiation function to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or close the affected system isolation valves within the next hour and declare the.affected system inoperable.
ACTION 27 Close the affected system isolation valves within one hour and declare the affected system inoperable.
ACTION 28 Lock the affected system isolation valves closed within one hour and declare the affected system inoperable.
ACTION 29 Close the affected system isolation valves within one hour and declare the affected system or component inoperable or:
a.
In OPERATIONAL CONDITION 1, 2 or 3 be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
In OPERATIONAL CONDITION # suspend CORE ALTERATIONS and operations with a potential, for draining the reactor vessel.
l NOTES l
When handling irradiated fuel in the primary or secondary centainment and l
during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
During CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
(a) See Specification 3.6.4, Table 3.6.4-1 for valves in each valve group.
l (b) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for l'
required surveillance without placing the trip system in the tripped con-li dition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter.
(c) Also actuates the standby gas treatment system.
t (d) Also actuates the control room emergency filtration system in the isolation mode of operation.
(e) Two upscale-Hi Hi, one upscale-Hi Hi and one downscale, or two downscale signals from the same trip system actuate the trip system and initiate isolation of the associated containment and drywell isolation valves.
l GRAND GULF-UNIT 1 3/4 3-14 Amendment No. 7, 9 i
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INSTRUMENTATION TABLE 3.3.2-1 (Continued)
ISOLATION ACTUATION INSTRUMENTATION NOTES (Continued)
(f) Also trips and isolates the mechanical vacuum pumps.
(g) A channel is OPERABLE if 2 of 4 instruments in that channel are OPERABLE.
Each trip system must have at least one instrument per Main Steam Line OPERABLE in order for the channels to be considered OPERABLE.
(h) Also actuates secondary containment ventilation isolation dampers and valves per Table 3.6.6.2-1.
(i) Closes only RWCU system isolation valves G33-F001, G33-F004, and G33-F251.
(j) Actuates the Standby Gas Treatment System and isolates Auxiliary Building penetration of the ventilation systems within the Auxiliary Building.
(k) Closes only RCIC outboard valves. A concurrent RCIC initiation signal is required for isolation to occur.
(1) Valves E12-F037A and E12-F0378 are closed by high drywell pressure. All other Group 3 valves are closed by high reactor pressure.
(m) Valve Group 9 requires concurrent drywell high pressure and RCIC Steam Supply Pressure-Low signals to isolate.
(n) Valves E12-F042A and E12-F042B are closed by Containment Spray System initiation signals.
GRAND GULF-UNIT 1 3/4 3-14a Amendment No. 7, 8, 9
TABLE 3.3.2-2 S3 ISOLATION ACTUATION INSTRUMENTATION SETPOINTS E
o ALLOWABLE o
EE TRIP FUNCTION TRIP SETPOINT VALUE m \\
1.
PRIMARY CONTAINMENT ISOLATION y
a.
Low Low, Level 2 1 -41.6 inches *
> -43.8 inches r
b.
Reactor Vessel Water Level-
-> -41.6 inches *
-> -43.8 inches Low Low, Level 2 (ECCS -
Division 3) c.
Reactor Vessel Water Level-1 -150.3 inches *
> -152.5 inches Low Low Low, Level 1 (ECCS Division 1 and Division 2) d.
Drywell Pressure - High 1 1.73 psig 1 1.93 psig w
A e.
Drywell Pressure-High (ECCS -
1 1.89 psig i 1.94 psig w
d.
Division 1 and Division 2) us f.
Drywell Pressure-High (ECCS -
5 1.89 psig 5 1.94 psig Division 3) g.
Containment and Drywell Ventilation Exhaust Radiation - High High 5 2.0 ar/hr**
$ 4.0 mr/hr**
h.
Manual Initiation NA NA 2.
MAIN STEAM LINE ISOLATION F
a.
Low Low Low, Level 1
> -150.3 inches
- 1 -152.5 inches k
b.
Main Steam Line Radiation - High 5 3.0 x full power 1 3.6 x full power 5
background background y
c.
Main Steam Line Pressure - Low 1 849 psig 1 837 psig d.
Main Steam Line Flow - High 5 169 psid.
1 176.5 psid
~
e.
Condenser Vacuum - Low
> 9 inches Hg. Vacuum 1 8.7 inches Hg. Vacuum oo
~
f.
Main Steam Line Tunnel Temperature - High 1 185"F**
5 191*F**
TABLE 3.3.2-2 (Continued) m
$g ISOLATION ACTUATION INSTRUMENTATION SETPOINTS o
E ALLOWA8LE TRIP FUNCTION TRIP SETPOINT VALUE G
2.
MAIN STEAM LINE ISOLATION (Continued) g.
Main Steam Line Tunnel A Temp. - High 5 101*F**
5 104*F**
h.
Manual Initiation NA NA 3.
SECONDARY CONTAINMENT ISOLATION a.
Low Low, Level 2 1 -41.6 inches
- 1 -43.8 inches b.
Drywell Pressure - High 1 1.73 psig 5 1.93 psig c.
Fuel Handling Area Ventilation
{
Exhaust Radition - High High 1 2.0 mR/hr**
1 4.0 mR/hr**
w d.
Fuel Handling Area Pool Sweep h
Exhaust Radiation - High High 1 18 mR/hr**
1 35 mR/hr**
e.
Manual Initiation NA NA 4.
REACTOR WATER CLEANUP SYSTEM ISOLATION a.
A Flow - High 5 79.gpm 5 89** g b.
A Flow Timer i 45 seconds 1 57 seconds c.
Eqaipment Area Temperature - High 1.
RWCU Hx Room
< 124*F
< 130*F E
2.
RWCU Pump Rooms 7 174"F 7 180*F 3.
RWCU Valve Nest Room 7.'.39*F I 145 F 4.
RWCU Demin. Rooms 7 139*F 7 145*F 5.
RWCU Rec. Tank Room i 139*F 7 145 F
[
6.
RWCU Demin. Valve Rocs 3135F 5141F d.
Equipment Area A Temp. - High u
1.
RWCU Hx Room
< 65*F
< 66*F 2.
RWCU Pump Rooms 7 115*F 7 118*F
~
3.
RWCU Valve Nest Room 7 70 F 7 73*F e
4.
RWCU Demin Rooms 7 70*F 7 73*F 5.
RWCU Rec. Tank Room 7 70*F 7 73 F 6.
RWCU Demin. Valve Room 7 71*F 774*F
TABLE 3.3.2-2 (Continued)
~
h ISOLATION ACTUATION INSTRUMENTATION SETPOINTS E
ALLOWABLE TRIP FUNCTION TRIP SETPOINT VALUE g
4.
REACTOR WATER CLEANUP SYSTEM ISOLATION (Continued) y e.
Reactor Vessel Water Level - Low Low, Level 2 1 -41.6 inches
- 1 -43.8 inches g
f.
Main Steam Line Tunnel Ambient Temperature - High 5 185*F**
5 191*F**
g.
Main Steam Line Tunnel A Temp. - High 5 101*F**
1 104*F**
h.
SLCS Initiation NA NA i.
Manual Initiation NA NA 5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION R
a.
RCIC Steam Line Flow - High 5 363" H O 5 371" H O 2
2 b.
RCIC Steam Supply Pressure - Low 1 60 psig 1 53 psig t;
c.
RCIC Turbine Exhaust Diaphragm Pressure - High 5 10 psig i 20 psig d.
RCIC Equipment Room Ambient Temperature - High 5 189 F**
1 195*F**
e.
RCIC Equipment Room a Temp. - High 5 125 F**
5 128"F**
f.
Main Steam Line Tunnel Ambient Temperature - liigh 5 185*F**
1 191 F**
g g.
Main Steam Line Tunnel A Temp. - High 5 101 F**
1 104*F**
h.
Main Steam Line Tunnel Temperature Timer 5 30 minutes 5 30 minutes g
g i.
RHR Equipment Room Ambient Temperature -
High 5 169*F**
5 175*F**
2 j.
RHR Equipment Room A Temperature -
High 5 105"F**
5 108*F**
e k.
RHR/RCIC Steam Line Flow - High 5 145" H O 5 160" H O 2
2
t TABLE 3.3.2-2 (Continued)
ISOLATION ACTUATION INSTRUMENTATION SETPOINTS ALLOWABLE TRIP FUNCTION TRIP SETPOINT VALUE 9
E 5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION (Continued) 5 i
]
1.
Manual Initiation NA NA m.
Drywell Pressure-High (ECCS Division 1 5 1.89 psig i 1.94 psig and Division 2) 6.
RHR SYSTEM ISOLATION a.
RHR Equipment Room Ambient Temperature -
High 5 169 F**
1 175'F**
b.
RHR Equipment Room A Temperature - High 5 105*F**
1 108*F**
w 30 w
c.
Reactor Vessel Water Level - Low, Level 3
> 11.4 inches *
> 10.8 inches h
d.
Reactor Vessel (RHR Cut-in Permissive)
Pressure - High 1 135 psig 1 150 psig e.
Drywell Pressure - High 5 1.73 psig i 1.93 psig f.
Manual Initiation NA NA l
4 El a
$e 5
C l
a See Bases Figure B 3/4 3-1.
us AA Initial setpoint.
Final setpoint to be determined during startup test program. Any required change to this setpoint shall be submitted to the Commission within 90 days of test completion.
t
1 TABLE 3.3.2-3 ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)#
1.
PRIMARY CONTAINMENT ISOLATION a.
Reactor Vessel Water Level - Low Low, Level 2
< 13(a) b.
Reactor Vessel Water Level - Low Low,
-7 13(a)
Level 2 (ECCS - Division 3) c.
Reactor Vessel Water Level-Low Low
-< 13(,)
Low, Level 1 (ECCS - Division 1 and Division 2) d.
Drywell Pressure - High
< 13(a) e.
Drywell Pressure-High (ECCS - Division 1 513(a) and Division 2) f.
Drywell Pressure-High (ECCS - Division 3) 1 13(a) g.
Containment and Dryweg) Ventilation Exhaust
< 13(3)**
Radiation - High High h.
Manual Initiation NA 2.
MAIN STEAM LINE ISOLATION a.
Reactor Vessel Water Level - Low Low Low,.
Level 1
< 1.0*/< 13(3)**
b.
Main Steam Line Radiation - High(b) 7 1.0*/7 13((a),,
c.
Main Steam Line Pressure - Low 7 1.0*/7 13 a),,
d.
Main Steam Line Flow - High 30.5*/313(a),,
e.
Condenser Vacuum - Low NA f.
Main Steam Line Tunnel Temperature - High NA g.
Main Steam Line Tunnel A Temp. - High NA h.
Manual Initiation NA 3.
SECONDARY CONTAINMENT ISOLATION a.
Reactor Vessel Water Level - Low Low, Level 2
< 13(a) b.
Drywell Pressure - High 513(a) c.
Fuel Handling Area Ventilation Exhaust Radiation - High High(b)
$ 13(a) d.
Fuel Handling Area Pool Sweep Exhaust Radiation - High High(b)
$ 13(3) e.
Manual Initiation NA 4.
REACTOR WATER CLEANUP SYSTEM ISOLATION a.
A Flow - High NA b.
A Flow Timer NA c.
Equipment Area Temperature - High NA d.
Equipment Area A Temp. - High NA e.
Reactor Vessel Water Level - Low Low, Level 2 1 13(,)
f.
Main Steam Line Tunnel Ambient Temperature - High NA g.
Main Steam Line Tunnel A Temp. - High NA h.
SLCS Initiation NA i.
Manual Initiation NA GRAND GULF-UNIT 1 3/4 3-18 Amendment No. 7, 9
INSTRUMENTATION TABLE 3.3.2-3 (Continued)
ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME 1
2 TRIP FUNCTION RESPONSE TIME (Seconds)#
1 5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.
RCIC Steam Line Flow - High
< 13(*) #
b.
RCIC Steam Supply Pressure - Low 513(*)
c.
RCIC Turbine Exhaust Diaphragm Pressure - High NA d.
RCIC Equipment Room Ambient Temperature - High NA e.
RCIC Equipment Room A Temp. - High NA f.
Main Steam Line Tunnel Ambient Temp. - High NA g.
Main Steam Line Tunnel A Temp. - High NA h.
Main Steam Line Tunnel Temperature Timer NA 1.
RHR Equipment Room Ambient Temperature - High NA j.
RHR Equipment Room A Temp. - High NA k.
RHR/RCIC Steam Line Flow - High NA 1.
Manual Initiation-NA
~
m.
Drywell Pressure - High (ECCS Division 1 and Division 2) 5 13(,)
6.
RHR SYSTEM ISOLATION a.
RHR Equipment Room Ambient Temperature - High NA b.
RHR Equipment Room A Temp. - High NA c.
Reactor Vessel Water Level - Low, Level 3 5 13(,)
d.
Reactor Vessel (RHR Cut-in Permissive)
Pressure - High NA 2
2 e.
Drywell Pressure - High NA f.
Manual Initiation NA (a) The isolation system instrumentation response time shall be measured and recorded as a part of the ISOLATION SYSTEM RESPONSE TIME.
Isolation system instrumentation response time specified includes the delay for diesel generator starting assumed in the accident analysis.
l (b) Radiation detectors are exempt from response time testing.
Response time shall be measured from detector output or the input of the first electronic component in the channel.
" Isolation system instrumentation response time for MSIVs only.
No diesel generator delays assumed.
- Isolation system instrumentation response time for associated valves j
except MSIVs.
- Isolation system instrumentation response time specified for the Trip Function actuating each valve group shall be added to isolation time shown in Tables 3.6.4-1 and 3.6.5.2-1 for valves in each valve group to obtain ISOLATION SYSTEM RESPONSE TIME for each valve.
- Without 13 second time delay.
GRAND GULF-UNIT 1 3/4 3-19 Amendment No. 7, 9 1
w---gm y-m--y--
g y..g.,.e-.,
-y y
9
.y a,
.m,,99--.yw
,3.
,..---.y
+ru h
emr 7-*** 1 m'
T
- u'v w
i t
i TABLE 4.3.2.1-1 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS S
CHANNEL OPERATIONAL E
CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH y
TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED 1.
PRIMARY CONTAINMENT ISOLATION a.
Low Low, Level 2 S
M R
1, 2, 3 and #
IC) b.
Reactor Vessel Water Level-S M
R 1, 2, 3 and #
Low tow, Level 2 (ECCS -
Division 3) c.
Reactor Vessel Water Level-S M
R(c) 1, 2, 3 and #
Low Low Low, Level 1 (ECCS -
Division 1 and Division 2)
A d.
Drywell Pressure - High S
M R
1,2,3 Y
e.
Drywell Pressure-High (ECCS -
S M
R(c) 1, 2, 3 Division 1 and Division 2) t.
Drywell Pressure-High (ECCS -
S M
R(c) 1, 2, 3 "ivision 3) g.
Containment and Drywell Ventilation Exhaust Radiation - High High S
M R
1, 2, 3 and
- h.
Manual Initiation NA M(a)
NA 1, 2, 3 and *#
l 2.
MAIN STEAM LINE ISOLATION E
a.
{
Low Low Low, Level 1 S
M R
1,2,3 5
b.
Main Steam Line Radiation -
5 High S
M R
1,2,3 E
c.
Main Steam Line Pressure -
]
Low S
M R
1
]
d.
Main Steam Line Flow - High S
M R
1,2,3 e.
Condenser Vacuum - Low S
M R
1, 2**, 3**
'1 TABLE 4.3.2.1-1 (Continued)
O ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS E
Q; CHANNEL OPERATIONAL
/-
CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED
[
2.
MAIN STEAM LINE ISOLATION (Continued) f.
Main Steam Line Tunnel Temperature - High S
M R
1,2,3 g.
Main Steam Line Tunnel A Temp. - High S
M R
1,2,3 h.
Manual Initiation NA M(a)
NA 1, 2, 3 3.
SECONDARY CONTAINMENT ISOLATION a.
Reactor Vessel Water wD Level - Low Low, Level 2 S
M R
1, 2, 3 and #
[
b.
Drywell Pressure - High S
M R
1,2,3 c.
Fuel Handling Area Ventilation Exhaust Radiation - High High S M
R 1, 2, 3 and
- ri.
Fuel Handling Area Pool Sweep Exhaust Radiation - High High S M
R 1, 2, 3 and
- e.
Manual Initiation NA M(a)
NA 1, 2, 3 and
- 4.
REACTOR WATER CLEANUP SYSTEM ISOLATION a.
A Flow - High S
M R
1,2,3
)
g b.
A Flow Timer NA M
Q 1,2,3 to g
c.
Equipment Area Temperature -
g High S
M R
1,2,3 5
d.
Equipment Area Ventilation g
A Temp. - High S
M R
1,2,3 e.
Reactor Vessel Water e
Level - Low Low, Level 2 S
M R
1,2,3 i
i
l I
TABLE 4.3.2.1-1 (Continued)
E 2-$
ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS S
q; CHANNEL OPERATIONAL a
CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED
)
4.
REACTOR WATER CLEANUP SYSTEM ISOLATION (Continued) f.
Main Steam Line Tunnel Ambient Temperature - High S
M R
1, 2, 3 g.
Main Steam Line Tunnel A Temp. - High S
M R
1, 2, 3 h.
SLCS Initiation NA M(b)
NA 1,2,3 1.
Manual Initiation NA M(a)
NA 1,2,3 R
b 5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION h
a.
RCIC Steam Line Flow - High 5
M R
1,2,3 b.
RCIC Steam Supply Pressure -
Low S
M R
1,2,3 c.
RCIC Turbine Exhaust Diaphragm Pressure - High S
M R
1,2,3 d.
RCIC Equipment Room Ambient Temperature - High S
M R
1,2,3 l
l e.
RCIC Equipment Room A Temp. -
High S
M R
1,2,3 f.
Main Steam Line Tunnel Ambient y
Temperature - High S
M R
1,2,3 k
g.
Main Steam Line Tunnel g
A Temp. - High S
M R
1,2,3 5
0
TABLE 4.3.2.1-1 (Continued)
S.
2 5
ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS S
G; CHANNEL OPERATIONAL E
CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH
'E TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED H
5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION (Continued) g h.
Main Steam Line Tunnel Temperature Timer NA M
Q 1,2,3 i.
RHR Equipment Room Ambient Temperature - High S
M R
1,2,3 j.
RHR Equipment Room A Temp. -
High S
M R
1,2,3 k.
RHR/RCIC Steam Line Flow -
w 3E High S
M R
1,2,3
)
1.
Manual Initiation NA M(a)
NA 1,2,3 m.
Drywell Pressure-High S
M R(c) 1, 2, 3 (ECCS Division 1 and Division 2) 2 6.
RHR SYSTEM ISOLATION a.
RHR Equipment Room Ambient Temperature - High S
M R
1,2,3 b.
RHR Equipment Room A Temp. - High S
M R
1,2,3 c.
R Low, Level 3 S
M R
1,2,3 3
d.
Reactor Vessel (RHR Cut-in Permissive) Pressure - High S
M R
1,2,3 5
TABLE 4.3.2.1-1 (Continued) 5 4
j 5
ISOLATION ACTUATION INSTRUMENTATION SURVEfft.ANCE REQUIREMENTS E
G; CHANNEL OPERATIONAL E
CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED s
6.
RHR SYSTEM ISOLATION (Continued) l e.
Drywell Pressure - High S
M R
1, 2, 3 f.
Manual Initiation NA M(*)
NA 1,2,3 i
i
- When handling irradiated fuel in the primary or secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
u3 3
- When reactor steam pressure > 1045 psig and/or any turbine stop valve is open.
- During CORE ALTERATION and operations with a potential for draining the reactor vessel.
u, 4
(a) Manual initiation switches shall be tested at least once per 18 months during shutdown. All other s'
circuitry associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once i
per 31 days as part of circuitry required to be tested for automatic system isolation.
l (b) Each train or logic channel shall be tested at least every other 31 days.
(c) Calibrate trip unit at least once per 31 days.
4
)
i I
8 r
i i
TABLE 3.3.3-1 n5g EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION h
MINIMUM OPERABLE APPLICABLE m
CHANNELS PER OPERATIONAL h
TRIP FUNCTION TRIP FUNCTION (a)
CONDITIONS ACTION Z
A.
DIVISION I TRIP SYSTEM g
1.
RHR-A (LPCI-MODE) & LPCS SYSTEM a.
Reactor Vessel Water Level - Low Low Low, Level 1 2hb 1, 2, 3, 4*, 5*
30 b.
Drywell Pressure - High 2
1,2,3 30 c.
LPCI Pump A Start Time Delay Relay 1
1, 2, 3, 4*, 5*
31 d.
Manual Initiation 1/ system 1, 2, 3, 4*, 5*
32 2.
AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A"#
a.
Reactor Vessel Water Level - Low Low Low, Level 1 2(b) 1, 2, 3 30 CD) b.
Drywell Pressure - high 2
1, 2, 3 30 y
c.
ADS Timer 1
1,2,3 31 d.
Reactor Vessel Water Level - Low, Level 3 (Permissive) 1 1,2,3 31 y
e.
LPCS Pump Discharge Pressure-High (Permissive) 2 1,2,3 31 g
f.
LPCI Pump A Discharge Pressure-High (Permissive) 2 1,2,3 31 g.
Manual Initiation 1/ valve 1,2,3 32 B.
DIVISION 2 TRIP SYSTEM 1.
Reactor Vessel Water Level - Low, Low Low, Level 1 2
1, 2, 3, 4*, 5*
30 b.
Drywell Pressure - High 2
1,2,3 30 c.
LPCI Pump B Start Time Delay Relay 1
1, 2, 3, 4*, 5*
31 d.
Manual Initiation 1/ system 1, 2, 3, 4*, 5*
32 E
2.
AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM B"#
k a.
Reactor Vessel Water Level - Low Low Low, Level 1 2
1,2,3 30 g
b.
Drywell Pressure - High 2
1,2,3 30
=
c.
ADS Timer 1
1,2,3 31
[
d.
Reactor Vessel Water Level - Low, Level 3 (Permissive) 1 1,2,3 31 l
o e.
LPCI Pump B and C Discharge Pressure - High (Permissive) 2/ pump 1,2,3 31 f.
Manual Initiation 1/ valve 1,2,3 32
~ -.
. r 6
TABLE 3.3.7.1-1 y
RADIATION MONITORING INSTRUMENTATION 5
o MINIMUM CHANNELS APPLICABLE ALARM / TRIP MEASUREMENT
{
INSTRUMENTATION OPERABLE CONDITIONS SE1 POINT RANGE ACTION E
1.
Component Cooling 5
Water Radiation 5
6 Monitor 1
At all times
<1 x 10 cpe/NA 10 to 10 cpm 70 2.
Standby Service Water System Radiation 5
6 Monitor 1/ heat 1, 2, 3, and* 11 x 10 cpa/NA 10 to 10 cpm 70 exchanger train 3.
Offgas Pre-treatment 3
6 i
Radiation Monitor 1
1, 2 15 x 10 mR/hr/NA 1 to 10 mR/hr 70 1'
4.
Offgas Post-treatment 2 ")
1, 2 il x 10 cpm (Hi), 10 to 10 cp, 77 I
5 6
{
Radiation Monitor 6
51.0 x 10 cpm (Hi Hi Hi) w E
5.
Carbon Bed Vault 6
Radiation Monitor 1
1, 2 1 2 x full power 1 to 10 mR/hr 72 j
background /NA 6.
Control Room Ventila-
-2 2
tion Radiation Monitor 2/ trip system 1,2,3,5 and** $4 mR/hr/
10 to 10 mR/hr 73 15 mR/hr#
7.
Containment and Drywell Ventilation Exhaust E
Radiation Monitor 3(h)
At all times
<2.0 mR/hr/
10 to 10 mR/hr 74
-2 2
k
-<4 mR/hr(b)#
s 8.
Fuel Handling Area
.l Ventilation Exhaust 3(h) 1,2,3,5 and**
< 2mR/hr/
10 to 10 mR/hr 75
_2 2
l E
Radiation Monitor
}4mR/hr(d)#
1 I
9.
Fuel Handling Area Fool ao Sweep Exhaust Radiation Monitor 3(h)
(c)
< 18 mR/hr/
10 to 10 mR/hr 75
_2 2
~
fd)#
35 mR/hr t
i
m.,...
INSTRUMENTATION TABLE 3.3.7.1-1 (Con;inued)
RADIATION MONITORING INSTRUMENTATION ACTION ACTION 70 -
With the required monitor inoperable, obtain and analyze at least one grab sample of the monitored parameter at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 71 -
a.
With one of the required monitors inoperable, place the inoperable channel in the downscale tripped condition within one hour.
b.
With both of the required monitors inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
ACTION 72-With the required monitor inoperable, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 73 a.
With one of the required monitors in a trip system inoperable, l
place the inoperable channel in the downscale tripped condition within one hour; restore the inoperable channel to OPERABLE status within 7 days, or, within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, initiate and maintain operation of at least one control room emergency l
filtration system in the isolation mode of operation.
b.
With both of the required monitors in a trip system inoperable, initiate and maintain operation of at least one control room emergency filtration system in the isolation mode of operation within one hour.
ACTION 74 -
a.
With one of the required monitors inoperable, place the inoperable channel in the downscale tripped condition within one hour.
b.
With two of the required monitors inoperable, isolate the containment and drywell purge and vent penetrations within i
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
ACTION 75 a.
With one of the required monitors inoperable, place the t
I inoperable channel in the downscale tripped condition within one hour.
b.
With two of the required monitors inoperable, initiate and maintain operation of at least one standby gas treatment subsystem within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
GRAND GULF-UNIT 1 3/4 3-58 Amendment No. 9 v -
r-r
~-
-e
TABLE 4.3.7.1-1 x
RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS c2 OPERATIONAL E
CHANNEL CONDITIONS FOR T
CHANNEL FUNCTIONAL CHANNEL WHICH SURVEILLANCE E
INSTRUMENTATION CHECK TEST CALIBRATION REQUIRED 1.
Component Cooling Water Radiation Monitor S
M R
At all times i
2.
Standby Service Water System l
Radiation Monitor S
M R
1, 2, 3, and*
3.
Offgas Pre-treatment Radiation Monitor S
M R
1, 2 4.
Offgas Post-treatment Radiation Monitor S
M R
1, 2 5.
Carbon Bed Vault Radiation Monitor S
M R
1, 2 6.
Control Room Ventilation Radiation Monitor S
M(a)
R 1, 2, 3, 5 and**
7.
Containment and Drywell Ventilation Exhaust Radiation Monitor S
M y
R At all times 8.
Fuel Handling Area Ventilation T
Radiation Monitor S
M R
1, 2, 3, 5 and**
9.
Fuel Handling Area Pool Sweep Exhaust Radiation Monitor S
M R
(b) 10.
Area Monitors a.
Fuel Handling Area Monitors 1)
New Fuel Storage Vault S
M R
(c) 2)
Spent Fuel Storage Pool S
M R
(d) i 3)
Dryer Storage Area S
M R
(e)
,E b.
Control Room Rajiation Monitor 5
M R
At all times E
2 With RHR heat exchangers in operation.
5 When irradiated fuel is being handled in the primary or secondary containment.
l (a) The CHANNEL FUNCTIONAL TEST shall demonstrate that control room annunciation occurs if any of the following 2
P conditions exist.
1.
Instrument indicates measured levels above the alarm / trip setpoint.
y 2.
Circuit failure.
3.
Instrument indicates a downscale failure.
4.
Instrument controls not in Operate mode, i
(b) With irradiated fuel in the spent fuel storage pool.
i (c) With fuel in the new fuel storage vault.
t (d) With fuel in the spent fuel storage pool.
y (e) With fuel in the dryer storage area.
.i 4
TABLE 3.3.7.5-1 E
E ACCIDENT MONITORING INSTRUMENTATION MINIMUM
(;
REQUIRED NUMBER CHANNELS d.
INSTRUMENT OF CHANNELS OPERABLE ACTION i
1 z
H 1.
Reactor Vessel Pressure 2
1 80 2.
1 80 j
3.
Suppression Pool Water Level 2
1 80 4.
Suppression Pool Water Temperature 6, 1/ sector 6, 1/ sector 80 5.
Drywell/ Containment Differential Pressure 2
1 80 6.
Drywell Pressure 2
1 80 l
7.
Drywell and Control Rod Drive Cavity Temperature 2 (each) 1 (each) 80 y
8.
Containment Hydrogen Concentration Analyzer and Monitor 2
1 80 w
4 9.
Drywell Hydrogen Concentration Analyzer and Monitor 2
1 80 l
10.
Containment Pressure (wide and narrow range) 2 (each) 1 (each) 80 11.
Containment Air Temperature 2
1 80 12.
Safety / Relief Valve Tail Pipe Pressure Switch L
i Position Indicators 1/ valve 1/ valve 80 f
13.
Containment /Drywell Area Monitors 2
1 81
,l 14.
Containment Ventilation Monitor 1
1 81 k
15.
Off gas and Radwaste Bldg. Ventilation Monitor 1
1 81 5
16.
Fuel Handling Area Ventilation Monitor 1
1 81 4
.E
- 17. Turbine Bldg. Ventilation Monitor 1
1 81 e
18.
Standby Gas Treatment System A & B Exhaust Monitors 1/each 1/each 81
- ach for containment and drywell.
E i
t i
TABLE 4.3.7.5-1 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION 1.
Reactor Vessel Pressure M
R 2.
R 3.
Suppression Pool Water Level M
R 4.
Suppression Pool Water Temperature M
R 5.
Drywell/ Containment Differential Pressure M
R 6.
Drywell Pressure M
R 7.
Drywell and Control Rod Cavity Temperature M
R 8.
Containment Hydrogen (cncentration i
Analyzer and Monitor NA M*
l 9.
Drywell Hydrogen Concentration Analyzer and Monitor NA M*
l
- 10. Containment Pressure M
R 11.
Contai ent Air Temperature M
R 12.
Safety / Relief Valve Tail Pipe Pressure Switch Position Indicators M
R
- 13. Containment /Drywell Area Monitors M
R**
- 14. Containment Ventilation Monitor M
R
- 15. Off gas and Radwaste Bldg. Ventilation Monitor M
R 16.
Fuel Handling Area Ventilation Monitor M
R
- 17. Turbine Bldg. Ventilation Monitor M
R 18.
Standby Gas Treatment System A & B Exhaust Monitors M
R l
- Using sample gas containing:
l a.
One volume percent hydrogen, remainder nitrogen.
i b.
Four volume percent hydrogen, remainder nitrogen.
- The CHANNEL CALIBRATION shall consist of an electronic calibration of the l-channel, not including the detector, for range decades above 10R/hr and a one point calibration check of the detector below 10R/hr with an installed or portable gamma source.
l l
l GRAND GULF-UNIT 1 3/4 3-72 Amendment No. 9 l
~
INSTRUMENTATION FIRE DETECTION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.9 As a minimum, the fire detection instrumentation for each fire detection zone shown in Table 3.3.7.9-1 shall be OPERABLE.
APPLICABILITY: Whenever equipment protected by the fire detection instrument is required to be OPERABLE.
ACTION:
With the number of OPERABLE fire detection instruments less than the Minimum Instruments OPERABLE requirement of Table 3.3.7.9-1:
a.
Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, establish a fire watch patrol to inspect the zone (s) with the inoperable instrument (s) at least once per hour, unless the instrument (s) is located inside the containment, steam tunnel or dry-l well, then inspect the primary containment at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or monitor the containment, steam tunnel and/or drywell air tempera-l ture at least once per hour at the locations listed in Specifica-tion 3.7.8, 4.6.1.8 and 4.6.2.6.
l b.
Restore the minimum number of instruments to OPERABLE status within 14 days or, in lieu of any other report required by Specification 6.9.1, prepare and submit a Special Report to the Commission pur-suant to Specification 6.9.2 within 30 days outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the instrument (s) to OPERABLE status.
c.
The provisions of Specifications 3.0.3 and 3.0.4 r. not applicable.
l l
SURVEILLANCE REQUIREMENTS l
l 4.3.7.9.1 Each of the above required fire detection instruments which are l
accessible during unit operation shall be demonstrated OPERABLE at least once per 6 months by performance of a CHANNEL FUNCTIONAL TEST.
Fire detectors which are not accessible during unit operation shall be demonstrated OPERABLE by the i
I performance of a CHANNEL FUNCTIONAL TEST during each COLD SHUTDOWN exceeding I
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless performed in the previous 6 months.
4.3.7.9.2 The NFPA Standard 720 supervised circuits supervision associated with the detector alarms of each of the above required fire detection instruments shall be demonstrated OPERABLE at least once per 6 months.
GRAND GULF-UNIT 1 3/4 3-76 Amendment No. 9 l
l y
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v
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-.---m__
TABLE 3.3.7.9-1 FIRE DETECTION INSTRUMENTATION MINIMUM INSTRUMENTS OPERABLE
- INSTRUMENT LOCATION ZONE (1)
HEAT (2)
FLAME SM0KE(3) a.
Containment Building 1.
Return Duct Mounted Detectors NA NA NA 3
ROOM NO.
ELEV.
ROOM NAME b.
Control Building 1.
OC202 111' DIV I SWGR RM 1-4 6
NA 4
2.
OC207 111' DIV I BATTERY RM 1-4 NA NA 1
3.
OC208 111' DIV II REMOTE 1-27 1
NA 1
SHUTDOWN PANEL ROOM 4.
OC208A 111' DIV I REMOTE 1-27 1
NA 1
SHUTDOWN PANEL ROOM 5.
OC209 111' DIV III BATTERY RM 1-5 NA NA 1
6.
OC210 111' DIV III SWGR RM 1-5 4
NA 2
7.
OC211 111' DIV II BATTERY RM 1-6 NA NA 1
8.
OC215 111' DIV II SWGR RM 1-6 7
NA 4
9.
OC307 133' ELECTRICAL CHASE 1-10 NA NA 1
l 10.
OC306 133' ELECTRICAL CHASE 1-10 NA NA 1
11.
OC302 133' HVAL EQUIP. ROOM 1-11 NA NA 13 12.
OC402 148' CABLE SPREADING RM 1-15 7
NA 10 l
-13.
OC403 148' COMPUTER ROOM 1-14 12 NA 7
f 14.
OC407 148' INSTR. MOTOR GEN ROOM 1-15 2
NA 1
15.
OC503 OC504 166' CONTROL ROOM 1-18 NA NA 16 16.
OC702 189' CABLE SPREADING RM 1-23 12 NA 14
- 17. OC703 189' CONTROL CAB. ROOM 1-24 4
NA 6
18.
OC707 189' INSTR MOTOR GEN. RM 1-23 NA NA 1
The fire detection instruments located within the primary containment are not required to be OPERABLE during the performance of Type A Containment Leakage Rate Tests.
(1) Zones apply only to smoke detectors.
(2) Heat detectors provide warning and activation of automatic extinguishing systems.
(3) Smoke detectors provide early warning capability.
GRAND GULF-UNIT 1 3/4 3-77 Amendment No. 7, 9
..m m
m----
m
-a g.
+
g-p-
=, -
I TABLE 3.3.7.9-1 (Continued)
FIRE DETECTION INSTRUMENTATION INSTRUMENT LOCATION MINIMUM INSTRUMENTS OPERABLE
- ROOM NO.
ELEV.
ROOM NAME ZONE (1)
HEAT (2)
FLAME SMOKE (3) c.
Auxiliary Building 1.
1A102 93' RHR 'A' HT EX RM 2-4 NA NA 1
2.
1A103 93' RHR 'A' PUMP RM 2-4 NA NA 2
3.
1A104 93' RCIC PUMP RM 2-4 NA NA 2
4.
1A105 93' RHR 'B' PUMP RM 2-4 NA NA 2
5.
1A106 93' RHR 'B' HT EX RM 2-4 NA NA 1
6.
1A109 93' HPCS PUMP RM 2-17 NA NA 2
7.
1A111 93' PIPING PENETRATION RM 2-17 NA NA 1
8.
1A114 93' FAN COIL AREA 2-14 NA NA 4
9.
1A115 93' PIPING PENETRATION RM 2-14 NA NA 1
10.
1A116 93' PIPING PENETRATION RM 2-14 NA NA 1
11.
1A117 93' MISC. FQUIP AREA 2-14 NA NA 4
12.
1A118 93' RHR 'C' PUMP ROOM 2-14' NA NA 2
13.
1A119 93' LPCS PUMP ROOM 2-14 NA NA 2
14.
1A120 93' CCW PUMP AND HX AREA 2-14 NA NA 3
15.
1A121 103' EAST CORRIDOR 2-17 NA NA 5
i6.
1A122 103' SOUTH CORRIDOR 2-17 NA NA 3
2-14 NA NA 0
17.
1A123 103' NORTH CORRIDOR 2-17 NA NA 5
2-14 NA NA 0
18.
1A201 119' EAST CORRIDOR 2-18 NA NA 6
19.
1A202 119' RHR 'A' HX RM 2-4 NA NA 1
20.
IA203 119' PIPING PENETRATION RM 2-4 NA NA 2
21.
1A204 119' PIPIN5 PENETRATIOM RM 2-4 NA NA 2
22.
1A205 119' PIPING PENETRATION RM 2-4 NA NA 2
23.
1A206 119' RHR 'B' HX RM 2-4 NA NA 1
e, 24.
1A207 119' ELECT. SWGR ROOM 2-4 3
NA 2
j 25.
1A208 119' ELECT. SWGR ROOM 2-4 3
NA 2
5 26.
1A209 115' RWCU RECIRC PUMP 'A' RM 2-4 NA NA 1
l 27.
1A210 115' RWCU RECIRC PUMP '8' RM 2-4 NA NA 1
28.
1A211 119' NORTH CORRIDOR 2-18 NA NA 14 2-2 NA NA 0
29.
1A215 119' SOUTH CORRIDOR 2-2 NA NA 5
30.
1A219 119' ELECT. SWGR RM 2-3 2
NA 2
GRAND GULF-UNIT 1 3/4 3-78*
Amendment No. 9 y
y
.-m
,y.---
-7
,--g-
-,v,
t TABLE 3.3.7.9-1 (Continued)
FIRE DETECTION INSTRUMENTATION INSTRUMENT LOCATION MINIMUM INSTRUMENTS OPERABLE
- ROOM NO.
ELEV.
ROOM NAME ZONE (1)
HEAT (2)
FLAME SM0KE(3)
- c. Auxiliary Building (Continued) 31.
1A220 119' PIPING PENETRATION RM 2-3 NA NA 1
32.
1A221 119' ELECT. SWGR RM 2-3 2
NA 2
33.
1A222 119' WEST CORRIDOR 2-2 NA NA 18 34.
1A301 139' NORTHEAST CORRIDOR 2-6 NA NA 2
35.
1A302 139' SOUTHEAST CORRIDOR 2-6 NA NA 1
36.
1A303 139' RHR 'A' HX RM 2-6 NA NA 1
37.
1A304 139' PIPING PENETRATION RM 2-6 NA NA 1
38.
1A305 139' STEAM TUNNEL 2-20 NA NA 2
39.
1A306 139' PIPING PENETRATION RM 2-6 NA NA 1
40.
1A307 139' RHR 'B' HX RM 2-6 NA NA 1
41.
1A308 139' ELECT. PENETRATION RM 2-6 3
NA 2
42.
1A309 139' ELECT. PENETRATION RM 2-6 3
NA 2
2-6 3
43.
1A314 139' SOUTH CORRIDOR 2-19 NA NA 3
2-6 NA NA 0
44.
1A316 139' NORTH CORRIDOR 2-6 NA NA 12 45.
1A318 139' ELECT. PENETRATION RM 2-5 2
NA 2
46.
1A319 139' RPV INSTR. TEST RM 2-5 NA NA 1
47.
1A320 139' ELECT. PENETRATION RM 2-5 2
NA 2
48.
1A321 139' MCC AREA 2-19 NA NA 3
49.
1A322 139' CENTRIFUGAL CHILLER 2-19 NA NA 4
AREA 50.
1A323 139' SGTS AREA 2-19 NA NA 1
51.
1A324 139' HVAC EQUIP AREA 2-19 NA NA 1
52.
1A326 139' SGTS AREA 2-19 NA NA 1
53.
1A401 166' NORTHEAST CORRIDOR 2-8 NA NA 2
54.
1A402 166' STEAM TUNNEL ROOF 2-8 NA NA 1
L 55.
1A403 166' SOUTHEAST CORRIDOR 2-8 NA NA 2
56.
1A404 166' UNASSIGNED AREA 2-8 NA NA 1
t.
l' 57.
1A405 166' CNTMT VENT. EQUIP RM 2-8 NA NA 1
58.
1A406 166' CNTMT EXHAUST FILTER 2-8 NA NA 1
AND VENT ROOM GRAND GULF-UNIT 1 3/4 3-79 Amendmen,t No. 7, 9 l
l
TABLE 3.3.7.9-1 (Continued)
FIRE DETECTION INSTRUMENTATION INSTRUMENT LOCATION MINIMUM INSTRUMENTS OPERABLE
- ROOM NO.
ELEV.
ROOM NAME ZONE (1)
HEAT (2)
FLAME SM0KE(3)
- c. Auxiliary Building (Continued) 59.
1A407 166' MCC AREA 2-8 2
NA 1
60.
1A410 166' MCC AREA 2-8 2
NA 1
61.
IA417 166' NORTH CORRIDOR 2-8 NA NA 14 62.
1A420 166' SOUTH CORRIDOR 2-7 NA NA 4
63.
1A424 166' SET DOWN AREA 2-7 NA NA 1
2-8 NA NA 1
64.
IA428 166' WEST CORRIDOR 2-7 NA NA 4
65.
1A432 166' FPC AND CU PUMP RM 2-7 NA NA 1
66.
1A434 166' PASSAGE 2-7 NA NA 1
67.
1A519 185' STORAGE AREA 2-9 NA NA 4
68.
1A527 185' LOAD CENTER AREA 2-9 NA NA 5
69.
1A539 185' CABLE CHASE 2-15 NA NA 1
70.
1A602 208'10" STORAGE AREA 2-13 NA NA 6
71.
1A603 208'10" PASSAGE 2-13 NA NA 3
72.
1A604 208'10" FUEL HANDLING AREA 2-13 NA NA 13 73.
1A606 245' HVAC EQUIP AREA 2-13 NA NA 9
d.
Diesel Generator Building 1.
Unit 1 El. 158'-0" HPCS 2-10 7
6 NA Generator 2.
Unit 1 E1. 158'-0" Bus B 2-11 7
6 NA Generator 3.
Unit 1 El. 158'-0" Bus A 2-12 7
6 NA Generator e.
Standby Service Water Pump House 1.
1M110 Pump House A 2-1 NA NA 1
2.
IM112 Valve Room A 2-1 NA NA 1
3.
2M110 Pump House B 2-1 NA NA 1
4.
2M112 Valve Room B 2-1 NA NA 1
f.
Charcoal Filter Trains 1.
Standby Gas Treatment NA 1
NA NA System Filter Train (Allison Thermistor Wire)
Auxiliary Building El. 139'-0" 2.
Control Room Standby NA 1
NA NA Fresh Air System Filter (Allison Thermistor Wire)
Train, Control Building E1. 133'-0" GRAND GULF-UNIT 1 3/4 3-80 Amendment No. 9
. - - - - -..-.~
. ~..- - -
REACTOR COOLANT SYSTEM 3/4.4.2 SAFETY VALVES SAFETY / RELIEF VALVES LIMITING CONDITION FOR OPERATION 3.4.2.1 Of the following safety / relief valves, the safety valve function of at least 7 valves and the relief valve function of at least 6 valves other than those satisfying the safety valve function requirement shall be OPERABLE with the specified lift settings:
Number of Valves Function Setpoint* (psia) 8 Safety 1165 + 11.6 psi 6
Safety 1180 1 11.8 psi 6
Safety 1190 1 11.9 psi 1
Relief 1103 1 15 psi 10 Relief 1113 + 15 psi 9
Relief 1123315 psi APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.
ACTION:
a.
With the safety and/or relief valve function of one or more of the above required safety / relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
With one or more safety / relief valves stuck open, provided that suppression pool average water temperature is less than 105*F, close the stuck open relief valve (s); if unable to close the open valve (s) within 2 minutes or if suppression pool average water temperature is 105'F or greater, place the reactor mode switch in the Shutdown position.
i c.
With one or more safety / relief tail pipe pressure switches inoperable, restore the inoperable switch (es) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN i
within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
SURVEILLANCE REQUIREMENTS 4.4.2.1.1 The tail pipe pressure switch for each safety / relief valve shall be demonstrated OPERABLE with the setpoint verified to be 30 1 5 psig by performance of a:
a.
CHANNEL FUNCTIONAL TEST at least once per 31 days, and a b.
CHANNEL CALIBRATION at least once per 18 months.**
4.4.2.1.2 The relief valve function pressure actuation instrumentation shall be demonstrated OPERABLE by performance of a:
a.
CHANNEL FUNCTIONAL TEST, including calibration of the trip unit, at least once per 31 days.
b.
CHANNEL CALIBRATION, LOGIC SYSTEM FUNCTIONAL TEST and simulated automatic operation of the entire system at least once per 18 months.
- The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.
- The provisions of Specification ~4.0.4 are not applicable provided the surveillance is performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reactor steam pressure is L
adequate to perform the test.
GRAND GULF-UNIT 1 3/4 4-5 Amendment No. 9 T
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j's REACTOR COOLANT SYSTEM SAFETY / RELIEF VALVES LOW-LOW SET FUNCTION LIMITING CONDITION FOR OPERATION 3.4.2.2 The relief valve function and the low-low set function of the following reactor coolant system safety / relief valves shall be OPERABLE with the following low-low set function lift settings:
Setpoint* (psia) i 15 psi Valve No.
Open Close F051D 1033 926 F051B 1073 936 F047D 1113 946 F047G 1113 94G F051A 1113 946 F051F 1113 946 APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.
ACTION:
a.
With the relief valve function and/or the low-low set function of one of-the above required reactor coolant system safety / relief valves inoperable, restore the inoperable relief valve function and the low-low set function to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following i
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
With the relief valve function and/or the low-low set function of more i
than one of the above required reactor coolant system safety / relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD i
SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
SURVEILLANCE REQUIREMENTS 4.4.2.2.1 The relief valve function and the low-low set function pressure actuation instrumentation shall be demonstrated OPERABLE by performance of a:
a.
CHANNEL FUNCTIONAL TEST, including calibration of the trip unit, at least once per 31 days.
b.
CHANNEL CALIBRATION, LOGIC SYSTEM FUNCTIONAL TEST and simulated automatic operation of the entire system at least once per 18 months.
l l
"The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.
GRAND GULF-UNIT 1 3/4 4-6 Amendment No. 9 wt-*--T ww-e
I REACTOR COOLANT SYSTEM 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.4.7 Two main steam line isolation valves (MSIVs) per main steam line shall be OPERABLE with closing times greater than or equal to 3 and less than or equal to 5 seconds.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.
ACTION:
a.
With one or more MSIVs inoperable:
1.
Maintain at least one MSIV OPERABLE in each affected main steam line that is open and within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, either:
a)
Restore the inoperable valve (s) to OPERABLE status, or b)
Isolate the affected main steam line by use of a deactivated MSIV in the closed position.
2.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
The provisions of Specification 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.4.7 Each of the above required MSIVs shall be demonstrated OPERABLE by verifying full closure between 3 and 5 seconds when tested pursuant to Specification 4.0.5.
The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITIONS 2 or 3 provided the surveillance is performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reaching a reactor steam pressure of 600 psig and prior to entry into OPERATIONAL CONDITION 1.
l i
GRAND GULF-UNIT 1 3/4 4-22 Amendment No. 9
m
~.._
EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.1 ECCS division 1, 2 and 3 shall be demonstrated OPERABLE by:
At least once per 31 days for the LPCS, LPCI and HPCS systems:
a.
1.
Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water.
2.
Performance of a CHANNEL FUNCTIONAL TEST of the:
a)
Discharge line " keep fill'ed" pressure alarm instrumentation, and j
b)
Header delta P instrumentation.
3.
Verifing that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.
b.
Verifing that, when tested pursuant to Specification 4.0.5, each:
1.
LPCS pump develops a flow of at least 7115 gpm with a total developed head of greater than or equal to 261 psid.
2.
LPCI pump develops a flow of at least 7450 gpm with a total developed head of greater than or equal to 89 psid.
3.
HPCS pump develops a flow of at least 7115 gpm with a total developed head of greater than or equal to 182 psid.
c.
For the LPCS, LPCI and HPCS systems, at least once per 18 months:
1.
Performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence and verifying that each automatic valve in the flow path actuates to its correct position. Actual injec-tion of coolant into the reactor vessel may be excluded from this test.
2.
Performing a CHANNEL CALIBRATION of the:
a)
Discharge line " keep filled" pressure alarm instrumentation and verifying the:
1)
High pressure setpoint of the:
(a) LPCS system to be 580 + 20, - O psig.
(b) LPCI subsystems to be 480 + 20, - 0 psig.
GRAND GULF-UNIT 1 3/4 5-4 Amendment No. 3, 9
~
-9
- ri-F 9'
- ---'evy
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3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 -PRIMARY CONTAINMENT PRIMARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be maintained.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3.
ACTION:
Without PRIMARY CONTAINMENT INTEGRITY, restore PRIMARY CONTAINMENT INTEGRITY within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
SURVEILLANCE REQUIREMENTS 4.6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be demonstrated:
a.
After each closing of each penetration subject to Type B testing, except the containment air locks, if opened following Type A or B test, by leak rate testing the equipment hatch seals with gas at Pa, 11.5 psig, and verifying that when the measured leakage rate for these seals is added to the leakage rates determined pursuant to Surveillance Requirement 4.6.1.2.d for all other Type B and C penetrations, the combined leakage rate is less than or equal to 0.60 La.
b.
At least once per 31 days by verifying that all containment penetrations ** not capable of being closed by OPERABLE containment automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic valves secured in position, except as provided in Table 3.6.4-1 of Specification 3.6.4.
c.
By verifying each containment air lock OPERABLE per Specification 3.6.1.3.
d.
By verifying the suppression pool OPERABLE per Specification 3.6.3.1.
"See Special Test Exception 3.10.1
- Except valves, blind flanges, and deactivated automatic valves which are located inside the containment, steam tunnel or drywell and are locked, sealed or otherwise secured in the closed position.
These penetrati.ons shall be verified closed during each COLD SHUTDOWN except such verification need not be performed more often than once per 92 days.
GRAND GULF-UNIT 1 3/4 6-1 Amendment No. 9.
4 CONTAINMENT SYSTEMS 3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.4 The containment and drywell isolation valves shown in Table 3.6.4-1 shall be OPERABLE with isolation times less than or equal to those shown in Table 3.6.4-1.
APPLICABILITY:
OPERATIONAL CONDITIONS 1, 2, 3, and #.
ACTION:
With one or more of the containment or drywell isolation valves shown in Table 3.6.4-1 inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:
a.
Restore the inoperable valve (s) to OPERABLE status, or b.
Isolate each affected penetration by use of at least one deactivated automatic valve secured in the isolated position,* or c.
Isolate each affected penetration by use of at least one closed manual valve or blind flange.*
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
t
- Isolation valves closed to satisfy these requirements may be reopened on an intermittent basis under administrative controls.
- Isolation valves shown in Table 3.6.4-1 are also required to be OPERABLE when their associated actuation instrumentation is requl red to be OPERABLE per-Table 3.3.2-1.
GRAND GULF-UNIT 1 3/4 6-27 Amendment No. 9 n
g
- ~--,.-
r-,-,g--
.---------s
_.m.._
TABLE 3.6.4-1 CONTAINMENT AND DRYWELL ISOLATION VALVES MAXIMUM SYSTEM AND PENETRATION ISOLATION TIME VALVE NUMBER NUMBER VALVE GROUP (a)
(Seconds) 1.
Automatic Isolation Valves a.
Containment Main Steam Lines B21-F028A 5(0)*
1 5
Main Steam Lines B21-F022A 5(I)*
1 5
Main Steam Lines B21-F067A-A 5(0)*
1 6
Main Steam Lines B21-F0288 6(0)*
1 5
Main Steam Lines B21-F0228.
6(I)*
1 5
riain Steam Lines B21-F0678-A 6(0)*
1 6
Main Steam Lines B21-F028C 7(0)*
1 5
Main Steam Lines B21-F022C 7(I)*
1 5
Main Steam Lines B21-F067C-A 7(0)*
1 6
Main Steam Lines B21-F0280 8(0)*
1 5
Main Steam Lines B21-F022D 8(I)*
1 5
Main Steam Lines B21-F0670-A 8(0)*
1 6
4 RHR Reactor E12-F008-A 14(0)(c) 3 40 Shutdown Cooling Suction RHR Reactor E12-F009-B 14(I)(c) 3 40 Shutdown Cooling Suction Steam Supply to E51-F063-B 17(I) 4 20 RHR and RCIC Turbine Steam Supply to E51-F064-A 17(0) 4 20 RHR and RCIC Turbine Steam Supply to E51-F076-B 17(I) 4' 20 RHR and RCIC Turbine RHR to Head Spray E12-F023-A 18(0)(c) 3 90 Main Steam Line B21-F019-A 19(0) 1 15 Drains (a) See Specification 3.3.2, Table 3.3.2-1, for isolation signal (s) that operates each valve group.
(b) Hydrostatically tested to ASME Section XI criteria.
(c) Hydrostatically tested with water to 1.10 P, 12.65 psig.
Hydrostatically tested by pressurizing syst$m to 1.10 0 l
(d)
Hydrostatically tested during system functional tests.,,12.65 psig.
(e)
(f) Hydrostatically sealed by feedwater leakage control system. Type C test not required.
(g) Normally closed on locked closed manual valves may be opened on an intermittent basis under administrative control.
- The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITIONS 2 or 3 provided the surveillance is performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reaching a reactor steam pressure of 600 psig and prior to entry into OPERATIONAL CONDITION 1.
GRAND GULF-UNIT 1 3/4 6-29 Amendment No. 9
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES MAXIMUM SYSTEM AND PENETRATION ISOLATION TIME VALVE NUMBER NUMBER VALVE GROUP (a)
(Seconds)
Containment (Continued)
Main Steam Line B21-F016-B 19(I) 1 15 Drains RHR Heat Exchanger E12-F042A-A 20(I)(c) 5 22 "A" to LPCI RHR Heat Exchanger E12-F028A-A 20(I)(c) 5 78 "A" to LPCI RHR Heat Exchanger E12-F037A-A 20(I)(C) 3 63 "A" to LPCI RHR Heat Exchanger E12-F0428-8 21(I)(c) 5 22 "B" to LPCI R!!R Heat Exchanger E12-F0288-B 21(I)(c) 5 78 "B" to LPCI RHR Heat Exchanger E12-F0378-B 21(I)(c) 3 63 "B" to LPCI RHR "A" Test Line E12-F024A-A 23(0)(d) 5 90 to Supp. Pool RHR "A" Test Line E12-F011A-A 23(0)(d) 5 36 l
to Supp. Pool
.~ to"Supp. ' Pool -
_ E12-F290A-A 23(0)(d)
. 6 8
RHR "A" Test Line
~~
RHR "C" Test Line E12-F021-B 24(0)(d) 5 101 to Supp. Pool HPCS Test Line E22-F023-C 27(0)(d) 6B 60 RCIC Pump Suction E51-F031-A 28(0)(d) 4 56 RCIC Turbine E51-F077-A 29(0)(c) 9 26 Exhaust LPCS Test Line E21-F012-A 32(0)(d) 5 144 l
Cont. Purge and M41-F011 34(0) 7 4
Vent Air Supply Cont. Purge and M41-F012 34(I) 7 4
Vent Air Supply Cont. Purge and M41-F034 35(I) 7 4
and Vent Air Exh.
Cont. Purge and M41-F035 35(0) 7 4
and Vent Air Exh.
~
Plant Service P44-F070-B 36(I) 6A 33 Water Return
' Plant Service P44-F069-A 36(0) 6A -
24 Water Return Plant Service P44-F053-A 37(0) 6A 24 Water Supply Chilled Water P71-F150 38(0) 6A 30 Supply GRAND GULF-UNIT 1 3/4 6-30 Amendment No. 9
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES MAXIMUM SYSTEM AND PENETRATION ISOLATION TIME VALVE NUMBER NUMBER VALVE GROUP (a)
(Seconds)
Containment (Continued)
Chilled Water P71-F148 39(0) 6A 30 Return Chilled Water P71-F149 39(I) 6A 30 Return Service Air P52-F105 41(0) 6A 4
Supply Inst. Air Supply P53-F001 42(0) 6A 4
RWCU to Main G33-F034-A 43(0) 8 31 Condenser RWCU to Main G33-F028-B 43(I) 8 23 Condenser RWCU Backwash to G36-F106 49(I) 6A 30 C/U Phase Sep. Tank RWCU Backwash to G36-F101 49(0) 6A 30 C/U Phase Sep. Tank Drywell & Cont.
P45-F067 50(I) 6A 4
Equip. Drain Sump Disch.
Drywell & Cont.
P45-F068 50(0) 6A 7
Equip. Drain Sump Disch.
Drywell & Cont.
P45-F061 51(I) 6A 4
Floor Drain Sump Disch.
Drywell & Cont.
P45-F062 51(0) 6A 4
Floor Drain Sump Disch.
Condensate Supply P11-F075 56(0) 6A 30 FPC & CU to Upper G41-F028-A 57(0) 6A 44 Cont. Pool Upper Cont. Pool G41-F029-A 58(0) 6A 40 to Fuel Pool Drain Tank Upper Cont. Pool G41-F044-B 58(I) 6A 40 to Fuel Pool Drain Tank Aux. Bldg. Fir.
P45-F273-A 60(0) 6A 23 and Equip. Drn.
Tks. to Supp. Pool Aux. Bldg. Fir.
P45-F274-B 60(0) 6A 23 and Equip. Drn.
Tks. to Supp. Pool GRAND GULF-UNIT 1 3/4 6-31 Amendment No. 9
%m, I
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND ORYWELL ISQLATION VALVES MAXIMUM SYSTEM AND PENETRATION ISOLATION TIME VALVE NUMBER NUMBER VALVE GROUP (a)
(Seconds)
Containment (Continued)
Comb. Gas Control E61-F009 65(0) 7 4
~'.
Cont. Purge (Outside Air Supply)
Comb. Gas Control-E61-F010 65(I) 7 4
Cont. Purge (Outside Air Supply)
Purge Rad.
E61-F056 66(I) 7 4
Detector Purge Rad.
E61-F057 66(0) 7 4
Detector RHR "B" Test Line E12-F024B-B 67(0)(d) 5 90 To Suppr. Pool RHR "B" Test Line E12-F0118-B 67(0)(d) 5 27 To Suppr. Pool RHR "B" Test Line E12-F2908-B 67(0)(d) 6 8
To Suppr. Pool Refueling Water P11-F130 69(0)(c) 6A 4
Transf. Pump Suction Refueling Water P11-F131 69(0)(c) 6A 8
Transf. Pump Suction Instr. Air to ADS P53-F003-A 70(0) 6A 4
RCIC Turbine Exh.
E51-F078-B 75(0) 9 7
Vacuum Breaker RWCU to Feedwater G33-F040-B 83(I) 8 30 -
RWCU to Feedwater G33-F039-A 83(0) 8 29 Chemical Waste P45-F098 84(I)
SA 4
Sump Discharge Chemical Waste P45-F099 84(0) 6A 4
Sump Discharge Supp. Pool Clean-P60-F009-A 85(0) 6A 8
up Return Supp. Pool Clean-P60-F010-8 85(0) 6A 4
up Return Demin. Water P21-F017-A 86(0) 6A 10 Supply to Cont.
Demin. Water P21-F018-B 86(I) 6A 10 Supply to Cont.
RWCU Pump Suction G33-F001-B 87(I) 8 30 GRAND GULF-UNIT 1 3/4 6-32 Amendment No. 9
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES MAXIMUM SYSTEM AND PENETRATION ISOLATION TIME VALVE NUMBER NUMBER VALVE GROUP (a)
(Seconds)
Containment (Continued)
RWCU Pump Suction G33-F252-A 87(I) 8 30
-j RWCU Pump Suction G33-F004-A 87(0) 8 30 RWCU Pump Disch.
G33-F053-B 88(I) 8 22 RWCU Pump Disch.
G33-F054-A 88(0) 8 22 b.
Drywell Instrument Air P53-F007-B 327(0) 6A 4
Plant Service P44-F076-A 331(I) 6A 32 Water Return Plant Service P44-F077-B 331(0) 6A 32 Water Return Plant Service P44-F074-8 332(0) 6A 32 Water Return RWCU Pump Suction G33-F250-A 337(I) 8 30 RWCU Pump Suction G33-F251-B 337(0) 8 30 Combustible Gas E61-F003B-B 338(0) 5 60 Con.
Combustible Gas E61-F003A-A 339(0) 5 60 Con.
Combustible Gas E61-F005A-A 340(0) 5 84 Con.
Combustible Gas E61-F005B-B 340(0) 5 84 Con.
Combustible Gas E61-F007 341(0) 5 9
Con.
Combustible Gas E61-F020 341(0) 5 18 Con.
Drywell Air Purge M41-F015 345(I) 7 4
Supply Drywell Air Purge M41-F013 345(0) 7 4
Supply Drywell Air Purge M41-F016 347(I) 7 4
Exhaust Orywell Air Purge M41-F017 347(0) 7 4
Exhaust Equipment Drains P45-F009 348(I) 6A 4
Equipment Drains P45-F010 348(0) 6A 4
Floor Drains P45-F003 349(I) 6A 4
Floor Drains P45-F004 349(0) 6A 4
Service Air PS2-F195-B 363(0) 6A 16 Chemical Sump P45-F096-A 364(I) 6A 8
Disch.
Chemical Sump P45-F097-B 364(0) 6A 8
Disch.
RWCU to Heat G33-F253_
366(0) 8 30 Exch.
Reactor Water B33-F019 465(I) 10 28.4 Sample Line Reactor Water B33-F020 465(0) 10 28.4 Sample Line GRAND GULF-UNIT 1 3/4 6-33 Amendment No. 9 I
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES l
SYSTEM AND PENETRATION VALVE NUMBER NUMBER 2.
Manual Isolation Valv_es_(9) a.
Containment Main Steam Lines E32-F001A-A 5(0)
Main Steam Lines E32-F001E-A 6(0)
Main Steam Lines E32-F001J-A 7(0)
Main Steam Lines E32-F001N-A 8(0)
Feedwater Inlet 821-F065A-A 9(0)(b)
Feedwater Inlet B21-F0658-A 10(0)(D)
RHR Pump "A" E12-F004A-A 11(0)(d)
Suction RHR Pump "B" E12-F004B-B 12(0)(d)
Suction RHR Pump "C" E12-F004C-8 13(0)(d)
Suction RHR Heat Ex. "A" E12-F027A-A 20(0)(c) to LPCI RHR Heat Ex. "B" E12-F0278 21(0)(c) to LPCI RHR Pumo "C" to E12-F042C-B 22(0)(c)
~
LPCI RHR "A" Test Line E12-F064A-A 23(0)(d)
To Suppr. Pool RHR "C" Test Line E12-F064C-B 24(0)(d)
To Suppr. Pool HPCS Suction E22-F015-C 25(0)(d)
HPCS Discharge E22-F004-C 26(0)(C) 27(0)(cf d
HPCS Test Line E22-F012-C RCIC Turbine Exh.
E51-F068-A 29(0)( )
LPCS Pump Suction E21-F001-A 30(0)(c)
LPCS Pump E21-F005-A 31(0)
Discharge LPCS Min. Flow E21-F011-A 32(0)(d)
CRD Pump C11-F083-A 33(0)
Discharge CCW Supply P42-F066-A 44(0)
CCW Return P42-F067-A 45(0)
CCW Return P42-F068-B 45(I)
RCIC Pump E51-F019-A 46(0)(d)
Discharge Min. Flow Reactor Recirc.
833-F128-B 47(I)
Post Accident Sampling GRAND GULF-UNIT 1 3/4 6-34 Amendmeat No. 9 w--
,_u.
w a
p
- +
-e,-
1 e
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUMBER NUMBER Containment (Continued)
Reactor Recirc.
B33-F127-A 47(0)
Post Accident Sampling Vent Header to E12-F073B-B 48(0)(d)
Supp. Pool RHR Pump "B" E12-F0648-B 67(0){d)
Test Line RHR "C" Relief E12-F346-B 718(0)(c)
V1v. Vent Hdr.
to Suppr. Pool
& Post-Acc.
Sample Ret.
RHR Heat Ex. "A" E12-F073A-A 77(0)(d)
Relief Reactor Recirc.
B33-F126-B 81(I)
Accident Sampling Reactor Recire.
B33-F125-A 81(0)
Accident Sampling 89(0)((c))
l c
SSW Supply "A" P41-F159A-A SSW Return "A" P41-F168A-A 90(I)(c)
SSW Return "A" P41-F160A-A 90(0)(c)
SSW Return "B" P41-F1688-B 91(I)(c)
SSW Return "B" P41-F160B-B 91(0)(c)
SSW Supply "B" P41-F1598-B 92(0)
Drywell Press.
M71-F593-A 101C(0)
Inst.
Drywell Press.
M71-F591A-A 101F(0)
Inst.
Drywell Press.
M71-F5918-8 102D(0)
Inst.
Ctat. Press. Inst. M71-F592A-A 1030(0)
Ctat. Press. Inst. M71-F5928-B 104D(0)
Drywell H2 E61-F595C 106A(0)
Analyzer Sample Drywell H2 E61-F5950 106A(I)
Analyzer Sample l
Drywell H2 Ana-E61-F597C 106B(0) lyzer Sample Ret.
Drywell H2 Ana-E61-F597D 106B(I) lyzer Sample Ret.
Ctat. H E61-F596C 105A(0) 2
(
Analyzer Sample Ctat. H E61-F5960 105A(I) 2 Analyzer Sainple Ctat. H2 Analyzer E61-F598C 106E(0)
Sample Ret.
t 2 Analyzer E61-F5980 106E(I)
Ctat. H Sample Ret.
GRAND CULF-UNIT 1 3/4 6-35 Amendment No. 9
a,
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND ORYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUMBER NUMBER b.
Drywell Cont. Cooling P42-F114-8 329(0)
Water Inlet Cont. Cooling P42-F116-A 330(I)
Water Outlet Cont. Cooling P42-F117-8 330(0)
Water Outlet 3.
Other Isolation Valves (9) a.
Containment Fuel Transfer F11-E015 4(I) l Tube Feedwater Inlet 821-F010A 9(I)(I)
Feedwater Inlet 821-F032A 9(0)(#)
Feedwater Inlet B21-F010B 10(I)(I)I) 10(0)(d)
Feedwater Inlet 821-F032B 11(0)(d)
RHR "A" Suction E12-F017A 12(0)(
RHR "B" Suction E12-F0178 RHR "C" Suction E12-F017C 13(0)
RHR Shutdown E12-F308 14(I)
Cooling Suction RHR Head Spray E51-F066 18(I)
RHR Head Spray E12-F344 18(I)(c)
RHR Heat Ex. "A" E12-F044A 20(I) to LPCI RHR Heat Ex. "A" E12-F025A 20(I)(c) to LPCI RHR Heat Ex. "A" E12-F107A 20(I)(c) to LPCI RHR Heat Ex. "B" E12-F025B 21(I)(c) to LPCI RHR Heat Ex. "B" E12-F044B 21(I)(c) to LPCI RHR Heat Ex. "B" E12-F107B 21(I)(c) to LPCI GRAND GULF-UNIT 1 3/4 6-37 Amendment No. 4, 7, 9 Y
m---
m-
-w g
w w
+
TABLE 3.6.4.1_ (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES SYSTEH AND PENETRATION VALVE NUMBER
- NUMBER
, Containment (Continued)
RHR Heat Ex. "C" E12-F234 22(0)(c) to LPCI RHR Pump "C" to E12-F041C-8 22(I)(c)
LPCI RHR Pump "A" Test E12-F259 23(0)(*)
Line to Suppr.
Pool RHR Pump "A" Test E12-F261 23(0)(*)
Line to Suppr.
Pool RHR Pump "A" Test E12-F227 23(0)(*)
Line to Suppr.
Pool RHR Pump "A" Test E12-F262 23(0)(')
Line to Suppr.
Pool RHR Pump "A" Test E12-F228 23(0)(*)
Line to Suppr.
Pool RHR Pump "A" Test E12-F338 23(0)(C)
Line to Suppr.
' Pool RHR Pump "A" Test E12-F339 23(0)(c)
Line to Suppr.
Pool RHR Pump "A" Test E12-F260 23(0)(*)
Line to Suppr.
24(0){')/
Pool RHR Pump "C" Test E12-F200 Line to Suppr.
Pool RHR Pump "C" Test E12-F281 24(0)(')
Line to Suppr.
Pool HPCS Suction E22-F014 25(0)(d) 26(I)((c)
HPCS Discharge E22-F005 26(I) c)
HPCS Discharge E22-F218 HPCS Discharge E22-F201 26(I)(c)
HPCS Test Line E22-F035 27(0)(d)
HPCS Test Line E22-F302 27(0)(')
HPCS Test Line
- E22-F301 27(0)
LPCS Pump Suction E21-F031 30(0)(c)
LPCS Discharge E21-F006 31(I)(c)
LPCS Discharge E21-F200 31(I)(e)
LPCS Discharge E21-F207 31(I)(,)
LPCS Test Line E21-F217 32(0)(*)
LPCS Test Line E21-F218 32(0)
GRAND GULF-UNIT 1 3/4 6-38 Amendment No. 9
l TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUMBER NUMBER Containment (Continued)
CRD Pump C11-F122 33(I)
Discharge PSW Supply P44-F043 37(I)
Plant Chilled P71-F151 38(I)
Water Supply Service Air PS2-F122 41(I)
Supply Instr. Air Supply P53-F002 42(I)
CCW Supply P42-F035 44(I)
RCIC Disch.
E51-F251 46(0)(,)
Min. Flow RCIC Disch.
E51-F252 46(0)(*)
Min. Flow RHR Heat Ex. "B" E12-F055B 48(0)(d)
Relief Vent Header RHR Heat Ex. "B" E12-F103B 48(0)(d)
Relief Vent Header RHR Heat Ex. "B" E12-F104B 48(0)(d)
Relief Vent Header Refueling Wtr.
G41-F053 54(0)
Stg. Tk. to Upper Ctmt. Pool Refueling Wtre G41-F201 54(I)
Stg. Tk. to Upper Ctmt. Pool Condensate Supply P11-F004 56(I)
FPC & CU to Upper G41-F040 57(I)
Cont. Pool Stby. Liquid C41-F151 61(I)
Control Sys.
Mix. Tk.
(future use)
Stby. Liquid C41-F150 61(0)
Control Sys.
Mix. Tk.
(future use)
RHR Pump "B" Test E12-F276 67(0)(*)
Line RHR Pump "B" Test E12-F277 67(0)(*)
Line RHR Pump "B" Test E12-F212 67(0)(*)
Line GRAND GULF-UNIT 1 3/4 6-39 Amendment No. 9
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND ORYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUM8E_R Ntr4BER Containment (Continued)
RHR Pump "B" Test E12-F213 67(0)(')
Line RHR Pump "B" Test E12-F249 67(0)(')
Line RHR Pump "B" Test E12-F250 67(0)(')
Line RHR Pump "B" Test E12-F334 67(0)(c)
Line RHR Pump "B" Test E12-E335 67(0)(c)
Line Inst. Air to ADS P53-7006 70(I)
LPCS Relief Valve E21-F018 71A(0)(d)
Vent Header RHR Pump "C" E12-F025C 71B(0)(d)
Relief Valve Vent Header RHR Shutdown E12-F036 73(0)(d)
Vent Header RHR Shutdown E12-F005 76B(0)(d)
Suction Relief Valve Disch.
RHR Heat Ex.
"A" E12-F055A 77(0)(d)
Relief Vent Header RHP. Heat Ex. "A" E12-F103A 77(0)(d)
Relief Vent Header RHR Heat Ex. "A" E12-F104A 77(0)(d)
Relief Vent Header SSW "A" Supply P41-F169A 89(I)
SSW "B" Supply P41-F1698 92(I) l Ctmt. Leak Rate M61-F015 110A(I)
Test Inst.
Ctat. Leak Rate M61-F014 110A(0)
Test Inst.
Ctat. Leak Rate M61-F019 110C(I)
Test Inst.
Ctmt. Leak Rate M61-F018 110C(0)
Test Inst.
l Ctmt. Leak Rate M61-F017 110F(I)
Test Inst.
Ctmt. Leak Rate M61-F016 110F(0)
Test Inst.
GRAND GULF-UNIT 1 3/4 6-40 Amendment No. 9
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUMBER NUMBER b.
Drywell LPCI "A" E12-F041A 313(I)
LPCI "B" E12-F041B 314(I)
LPCI "B" E12-F236 314(0)
CRD to Recirc.
B33-F013A 326(I)
Pump A Seals CRD to Recirc.
B33-F017A 326(0)
Pump A Seals Instrument Air P53-F008 327(I)
Standby Liquid C41-F007 328(I)
Control Standby Liquid C41-F006 328(0)
Control Cont. Cooling P42-F115 329(I)
Water Supply Plant Service P44-F075 332(I)
Water Supply Condensate Flush B33-F204 333(I)
Conn.
C'ondensate Flush B33-F205 333(0)
Conn.
CR0 to Recire.
B33-F0138 346(I)
Pump B Seals CRD to Recirc.
B33-F017B 346(I)
Pump B Seals Service Air PS2-F196 363(I)
Cont. Leak Rate M61-F021 438A(I)
Test Inst.
Cont. Leak Rate M61-F020 438A(0) l Sys.
BLIND FLANGES Cont. Leak Rate NA 40(I)(0)
Sys.
Cont. Leak Rate NA 82(I)(0)
Sys.
Containment NA 343(I)(0)
Leak Rate System GRAND GULF-UNIT 1 3/4 6-41 Amendment No. 9
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND ORYWELL ISOLATION VALVES SYSTEM AND PENETRATICH VALVE NUMBER NUMBER 4.
Test Connections (9) a.
Co itainment Main Steam T/C B21-F025A 5(0)
Main Steam T/C B21-F0258 6(0)
Main Steam T/C B21-F025C 7(0)
Main Steam T/C B21-F025D 8(0)(f)
Feedwater T/C B21-F030A 9(0)(f)
Feedwater T/C B21-F063A 9(0) (f)
Feedwater T/C B21-F0638 10(0)(f)
Feedwater T/C B21-F030B 10(0)(c)
RHR Shutdown Cool.
E12-F002 14(0)
Suction T/C RCIC Steam Line E51-F072 17(0)
T/C RHR to Head E12-F342 18(0)(c)
Spray T/C RHR to Head E12-F061 18(0)(c)
Spray T/C 22(0)((c) c LPCI "C" T/C E12-F056C
)
RHR "A" Pump E12-F322 23(0)
Test Line T/C RHR "A" Pump E12-F336 23(0)(c)
Test Line T/C RHR "A" Pump E12-F349 23(0)(c)
Test Line T/C RHR "A" Pump E12-F303 23(0)(c)
Test Line T/C RHR "A'"
Pump E12-F310 23(0)(c)
Test Line T/C RHR "A" Pump E12-F348 23(0)(C)
Test Line T/C RHR"C" Pump E12-F311 24(0)(c)
Test Line T/C l
RHR"C" Pump E12-F304 24(0)(c) i Test Line T/C 26(0)((c)
C HPCS Discharge T/C E22-F021 27(0)(c) l HPCS Test uke T/C E22-F303
)
HPCS Test Line T/C E22-F304 27(0)
RCIC Turbine E51-F258 29(0)(c) i Exhaust T/C l
RCIC Turbine E51-F257 29(0)(c) l I
Exhaust T/C LPCS T/C E21-F013 31(0) l LPCS Test Line E21-F222 32(0) i T/C LPCS Test Line E21-F221 32(0)(c)
T/C GRAND GULF-UNIT 1 3/4 6-42 Amendment No. 4, 7, 9 y
o -
-~--,.me ee--.s
4 TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUMBER NUMBER Containment (Continued)
RHR "B" Test Line E12-F350 67(0)(c)
T/C RHR "B" Test Line E12-F312 67(0)(c)
T/C RHR "B" Test Line E12-F305 67(0)(c)
T/C Refueling Water P11-F42.5 69(0)(c)
Transf. Pump Suction T/C Refueling Water P11-F132 69(0)(c)
Transf. Pump Suction T/C Inst. Air to ADS P53-F043 70(0)
T/C Cont. Leak Rate M61-F010 82(I)
T/C RWCU To Feedwater G33-F055 83(0)
T/C Suppr. Pool P60-F011 85(0)
Cleanup T/C Suppr. Pool P60-F034 85(0)
Cleanup T/C RWCU Pump Suction G33-F002 87(0)
T/C RWCU Pump G33-F061 88(0)
Discharge T/C SSW T/C P41-F163A 89(0)(c)
SSW T/C P41-F1638 92(0)(c) b.
Drywell LPCI "A" T/C E12-F056A 313(0)
LPCI "B" T/C E12-F056B 314(0)
Instrument Air T/C P53-F493 327(0) l SLCS T/C C41-F026 328(0)
Service Air T/C PS2-F476 363(0)
RWCU T/C G33-F120 366(I) l Reactor Sample B33-F021 465(0) i T/C GRAND GULF-UNIT 1 3/4 6-44 Amendment No. 9
CONTAINMENT SYSTEMS 3/4.6.6 SECONDARY CONTAINMENT SECONDARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.6.1 SECONDARY CONTAINMENT INTEGRITY shall be maintained.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *.
ACTION:
Without SECONDARY CONTAINMENT INTEGRITY:
a.
In OPERATIONAL CONDITION 1, 2 or 3, restore SECONDARY CONTAINMENT INTEGRITY within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
In Operational Condition
, suspend handling of irradiated fuel in the primary or secondary containment, CORE ALTERATIONS and operations l
with a potential for draining the reactor vessel.
The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.6.6.1 SECONDARY CONTAINMENT INTEGRITY shall be demonstrated by:
a.
Verifying at least once per 31 days that:
1.
All Auxiliary Building and Enclosure Buf1 ding equipment hatches and blowout panels are closed and sealed.
2.
The door in each access to the Auxiliary Building and Enclosure Building is closed, except for routine entry and exit.
3.
All Auxiliary Building and Enclosure Building penetrations not capable of being closed by OPERABLE secondary containment automatic isolation dampers / valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic dampers / valves secured in position.
b.
At least once per 18 months:
1.
Verifying that one standby gas treatment subsystem will draw down the secondary containment to greater than or equal to 0.25 inches of vacuum water gauge in less than or equal to 120 seconds, and 2.
Operating one standby gas treatment subsystem for one hour and maintaining greater than or equal to 0.266 inches of vacuum water l
gauge in the secondary containment at a flow rate not exceeding 4000 CFM.
- When irradiated fuel is being handled in the primary or secondary containment l
and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
GRAND GULF-UNIT 1 3/4 6-46 Amendment No. 9
% ogawv h - mu-- m m ee e=
u m
-- ~- - -
y
- m--
m u--
3 i
CONTAINMENT SYSTEMS SECONDARY CONTAINMENT AUTOMATIC ISOLATION DAMPERS / VALVES LIMITING CONDITION FOR OPERATION 3.6.6.2 The secondary containment ventilation system automatic isolation dampers / valves shown in Table 3.6.6.2-1 shall be OPERABLE with isolation times less than or equal to the times shown in Table 3.6.6.2-1.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *.
ACTION:
With one or more of the secondary containment ventilation system automatic isolation dampers / valves shown in Table 3.6.6.2-1 inoperable, maintain at least one isolation damper / valve OPERABLE in each affected penetration that is open, and within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> either:
a.
Restore the inoperable damper / valve (s) to OPERABLE status, or b.
Isolate each affected penetration by use of at least one deactivated automatic damper / valve secured in the isolation position, or c.
Isolate each affected penetration by use of at least one closed n,anual valve or blind flange.
Otherwise, in OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Otherwise, in Operational Condition
, suspend handling of irradiated fuel in the primary or secondary containment, CORE ALTERATIONS and opera-l tions with a potential for draining the reactor vessel.
The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.6.6.2 Each seconoary containment ventilation system automatic isolation damper / valve shown in Table 3.6.6.2-1 shall be demonstrated OPERABLE:
a.
Prior to returning the damper / valve to service after maintenance, repair or replacement work is performed on tne damper / valve or its associated actuator, control or power circuit by cycling the damper / valve through at least one complete cycle of full travel and verifying the specified isolation time.
b.
During COLD SHUTDOWN or REFUELING at least once per 18 months by verifying that on a containment isolation test signal each isolation damper / valve actuates to its isolation position.
~
By verifying the isolation time to be within its limit when tested c.
pursuant to Specification 4.0.5.
- When irradiated fuel is being handled in the primary or secondary containment l
and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
GRAND GULF-UNIT 1 3/4 6-47 Amendment No. 9
-,,,,-m
j r
i TABLE 3.6.6.2-1 j
SECONDARY CONTAINMENT VENTILATION SYSTEM AUTOMATIC ISOLATION DAMPERS / VALVES MAXIMUM ISOLATION TIME DAMPER / VALVE FUNCTION (Number)
(Seconds) a.
Dampers Auxiliary Building Ventilation Supply Damper (QlT41F006) 4 Auxiliary Building Ventilation Supply Damp,er (QlT41F007) 4 Fuel Handling Area Ventilation Exhaust Damper (QlT42F003) 4 Fuel Handling Area Ventilation Exhaust Damper (Q1T42F004) 4 Fuel Handling Area Ventilation Supply Damper (Q1T42F011) 4 Fuel Handling Area Ventilation Supply Damper 1
(Q1T42F012) 4 Fuel Pool Sweep Ventilation Supply Damper (Q1T42F019) 4 Fuel Pool Sweep Ventilation Supply Damper (QlT42F020) 4 Containment & Drywell Area Ventilation Supply Damper 4
(Q1M41F007)
Containment & Drywell Area Ventilation Supply Damper 4
(QlM41F008)
Containment & Drywell Area Ventilation Exhuast Damper 4
(QlM41F036)
Containment & Drywell Area Ventilation Exhaust Damper 4
(Q1M41F037)
+
?
4 GRAND GULF-UNIT 1 3/4 6-48 Amendment No. 4, 7, 9
=ve y.-m<w--g
-g.w--
c
- e,7-=e--y w.,,g e mg A
'a-es.i->
y 9-,. * - -.
.-e-,
--%-J
-y.--
-t-e~
t er
-'F'+
j CONTAINMENT SYSTEMS STANDBY GAS TREATMENT SYSTEM LIMITING CONDITION FOR OPERATION 3.6.6.3 Two independent standby gas treatment subsystems shall be OPERABLE.
APPLICABILITY:
OPERATIONAL CONDITIONS 1, 2, 3 and *.
ACTION:
a.
With one standby gas treatmant subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days, or:
1.
In OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
2.
In Operational Condition suspend handling of irradiated fuel in the primary or secondary containment, CORE ALTERATIONS and l
operations with a potential for drai.ning the reactor vessel.
The provisions of Specification 3.0.3 are not applicable.
b.
With both standby gas treatment subsystems inoperable in Operational Condition *, suspend handling of irradiated fuel in the primary or l
secondary containment, CORE ALTERATIONS or operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3.
are not applicable.
SURVEILLANCE REQUIREMENTS 4.C.6.3 Each standby gas treatment subsystem shall be demonstrated OPERABLE:
a.
At least once per 31 days by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates for at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> with the heaters OPERABLE.
- When irradiated fuel is being handled in the primary or secondary containment l
and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
GRAND GULF-UNIT 1 3/4 6-53 Amendment No. 9 y
--+ -
---y~
y-,
. -.,, - ~. -
yw-
--.y
--e w.
g
l 1
CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMEN15 (Continued) b.
At least once per 18 months or (1) after any structural maintenance i
on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the subsystem by:
1.
Verifying that the subsystem satisfies the in place testing acceptance criteria and uses the test procedures of Regulatory Positions C.S.a, C.5.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 4000 cfm i 10%.
2.
Verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.
3.
Verifying a subsystem flow rate of 4000 cfm i 10% during system operation when tested in accordance with ANSI N510-1975.
c.
After every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of charcoal adsorber operation by verifying within 31 days after removal that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1973, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.
d.
At least once per 18 months by:
1.
Performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence for the:
a)
LOCA, and b)
Fuel handling accident.
2.
Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is-less than 9.2 inches Water Gauge while operating the filter train at a flow rate of 4000 cfm i 10%.
3.
Verifying that the filter train and isolation dampers receive the l
appropriate actuation signal by each of the following test conditions.
For at least one of these test conditions, verify that the filter train starts and isolation dampers open on j
receipt of the actuation signal.
a.
Drywell pressure - high, b.
Reactor vessel water level - low low, level 2, c.
Fuel handling area ventilation exhaust radiation - high, d.
Fuel handling area pool sweep exhaust radiation - high, and e.
Manual initiation from the Control Room.
4.
Verifying that the fan can be manually started.
5.
Verifying that the heaters dissipate 50 t 5.0 kW when tasted in accordance with ANSI N510-1975 (except for the phase balance criteria stated in Section 14.2.3).
GRAND GULF-UNIT 1 3/4 6-54 Amendment No. 7, 9
3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER SYSTEMS STANDBY SERVICE WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.1.1 Two independent standby service water (SSW) system subsystems shall be OPERABLE with each subsystem comprised of:
a.
An OPERABLE flow path capable of taking suction from the associated SSW cooling tower basin and transferring the water through the RHR heat exchangers, ECCS pump room seal coolers, and associated coolers and pump heat exchangers.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5 and *.
ACTION:
a.
In OPERATIONAL CONDITION 1, 2 or 3:
1.
With one SSW subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
2.
With both SSW subsystems inoperable, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN ** within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
In OPERATIONAL CONDITION 3 or 4 with the SSW subsystem, which is associated with an RHR loop required OPERABLE by Specification 3.4.9.1 or 3.4.9.2, inoperable, declare the associated RHR loop inoperable and take the ACTION required by Specification 3.4.9.1 or 3.4.9.2, as applicable.
c.
In OPERATIONAL CONDITION 4 or 5 with the SSW subsystem, which is associated with an ECCS pump required OPERABLE by Specification 3.5.2, inoperable, declare the associated ECCS pump inoperable and take the ACTION required by Specification 3.5.2.
d.
In OPERATIONAL CONDITION 5 with the SSW subsystem, which is associated with an RHR system required OPERABLE by Specification l
3.9.11.1 or 3.9.11.2, inoperable, declare the associated RHR system t
inoperable and take the ACTION required by Specification 3.9.11.1 l
or 3.9.11.2, as applicable.
e.
In Operational Condition *, with the SSW subsystem, which is associated with a diesel generator required OPERABLE by Specifica-tion 3.8.1.2, inoperable, declare the associated diesel generator inoperable and take the ACTION required by Specification 3.8.1.2.
The provisions of Specification 3.0.3 are not applicable.
l' n
l When handling irradiated fuel in the primary or seconcury containment.
l nn l
Whenever botn SSW subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.
GRAND GULF-UNIT 1 3/4 7-1 Amendment No. 9
PLANT SYSTEMS ULTIMATE HEAT SINK LIMITING CONDITION FOR OPERATION 3.7.1.3 At least the following independent SSW cooling tower basins, each with:
a.
A minimum basin water level at or above elevation 130'3" Mean Sea Level, USGS datum, equivalent to an indicated level of > 87".
b.
Two OPERABLE cooling tower fans,#
shall be OPERABLE:
a.
In OPERATIONAL Condition 1, 2 and 3, two basins, b.
In OPERATIONAL Condition 4, 5 and *, the basins associated with systems and components required OPERABLE by Specifications 3.7.1.1 and 3.7.1.2.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5 and *.
ACTION:
a.
In OPERATIONAL CONDITION 1, 2, 3, 4, 5 and
- with one SSW cooling tower basin inoperable, declare the associated SSW subsystem inoperable and, if applicable, declare the HPCS service water system inoperable, and take the ACTION required by Specifications 3.7.1.1 and 3.7.1.2, as applicable, b.
In OPERATIONAL CONDITION 1, 2, 3, 4 or 5 with both SSW cooling tower basins inoperable, declare the SSW system and the HPCS service water system inoperable and take the ACTION required by Specifications 3.7.1.1 and 3.7.1.2.
c.
In Operational Condition
- with both SSW cooling tower basins inoperable, declare the SSW system inoperable and take the ACTION required by Specification 3.7.1.1.
The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.7.1.3 At least the above required SSW cooling tower basins shall be deter-mined OPERABLE at least once per:
a.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by verifying basin water level to be greater than or equal to 87".
b.
31 days by starting each SSW cooling tower fan from the control room and operating the fan for at least 15 minutes, c.
18 months by verifying that each SSW cooling tower fan starts automatically when the associated SSW subsystem is started.
A B
When handling irradiated fuel in the primary or secondary containment.
l
- The basin cooling tower fans are not required to be OPERABLE for HPCS service water system OPERABILITY.
GRAND GULF-UNIT 1 3/4 7-4 Amendment No. 8, 9
PLANT SYSTEMS 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM LIMITING CONDITION FOR OPERATION 3.7.2 Two independent control room emergency filtration system subsystems shall be OPERABLF.
APPLICABILITY:
All OPERATIONAL CONDITIONS and *.
ACTION:
a.
In OPERATIONAL CONDITION 1, 2 or 3 with one control room emergency filtration subsystem inoperable, restore the inocerable subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLn SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
In OPERATIONAL CONDITION 4, 5 or *:
1.
With one control room emergency filtration subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days or initiate and maintain operation of the OPERABLE subsystem in the isolation mode of operation.
2.
With both control room emergency filtration subsystems inoperable, suspend CORE ALTERATIONS, handling of irradiated fuel in the primary or secondary containment and operations with a potential l
for draining the reactor vessel.
c.
The provisions of Specification 3.0.3 are not applicable in Operational Condition *.
SURVEILLANCE REQUIREMENTS 4.7.2 Each control room emergency filtration subsystem shall be demonstrated OPERABLE:
a.
At least once per 31 days on a STAGGERED TEST BASIS by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates for at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> with the heaters OPERABLE.
b.
At least once per 18 months or (1) after any structural maintenance on the HEPA filter or charcoa'i adsorber housings, or (2) following painting, fire or chemical release in any sentilation zone communicating with the subsystem by:
1.
[ DELETED]
When irradiated fuel is being handled in the primary or secondary containment.
GRAND GULF-UNIT 1 3/4 7-5 Amendment No. 7, 9
1 PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 2.
Verifying that the subsystem satisfies the in place testing f
acceptance criteria and uses the test procedures of Regulatory Positions C.S.a, C.S.c and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 4000 cfm i 10%.
3.
Verifying within 31 days after removal that a laboratory analysis of a representative car'on sample obtained in accordance with o
Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.
4.
Verifying a subsystem flow rate of 4000 cfm i 10% during subsystem operation when tested in accordance with ANSI N510-1975.
c.
After avery 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of charcoal adsorbar operation by verifying within 31 days after removal that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Positon C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.
d.
At least once per 18 months by:
1.
Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 7.2 inches Water Gauge while operating the subsystem at a flow rate of 4000 cfm i 10%.
2.
Verifying that the subsystem receives an appropriate isolation actuation signal by each of the following test conditions.
For at least one of the test conditions, verify that the subsystem automatically switches to the isolation mode of operation and the isolation valves close within 4 seconds.
a)
High radiation in the outside air intake duct, b)
High chlorine concentration in the outside air intake duct, c)
High drywell pressure, d)
Low reactor water level, and e)
Manual initiation from the Control Room.
3.
Verifying that the heaters dissipate 20.7 1 2.1 kW when tested in accordance with ANSI N510-1975 (except for the phase balance criteria stated in Section 14.2.3).
e.
After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter banks remove greater than or equal to 99.95% of the DOP when they are tested in place in accordance with ANSI N510-1975 while operating the system at a flow rate of 4000 cfm 1 15.
f.
After each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorbers remove 99.95% of a halogenated hydrocarbon refrigerant test gas when they are tested in place in accordance with ANSI N510-1975 while operating the system at a flow rate of 4000 cfm 10%.
GRAND GULF-UNIT 1 3/4 7-6 Amendment No. 8, 9 7
9
,g-y.--
7 y----m7 m--
-r' a-
>g
-*w' C"-
v*du
PLANT SYSTEMS SPRAY AND/0R SPRINKLER SYSTEMS LIMITING CONDITION FOR OPERATION 3.7.6.2 The following spray / sprinkler systems shall be operable:
a.
Diesel Generator Building 1.
Diesel Generator A pre-action sprinkler system N1P64D142A 2.
Diesel Generator B pre-action sprinkler system N1F540142B 3.
Diesel Generator C pre-action sprinkler system N1P64D142C b.
Auxiliary Building 1.
Elevation 93'/103' Northeast Corridor N1P64D150 2.
Elevation 119' Northeast Corridor N1P640151 3.
Elevation 139' Northeast Corridor N1P64D152 4.
Elevation 166' Northeast Corridor N1P64D153 5.
Elevation 119' West Corridor N1P640158 6.
Elevation 139' West Corridor N1P640159 c.
Control Building 1.
Elevation 148' Lower Cable Room N19640154 2.
Elevation 189' Upper Cable Room N1P64D155 3.
Elevation 93' N1P640140 d.
Fire Pump House NSP64D136A/B APPLICABILITY: Whenever equipment protected by the spray / sprinkler systems is required to be OPERABLE.
ACTION:
a.
With one or more of the above required spray and/or sprinkler systems inoperable, within one hour establish a continuous fire watch with backup fire suppression equipment for those areas in which redundant systems or components could be damaged; for other areas, establish an hourly fire watch patrol.
Restore the system to OPERABLE status within 14 days or, in lieu of any other report required by Specifica-tion 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 30 days outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPFRABLE status.
b.
The orovisions of Specification 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.7.6.2 The above required spray and sprinkler systems shall be demonstrated OPERABLE:
a.
At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path is in its correct position.
GRAND GULF-UNIT 1 3/4 7-31 Amendment No. 9 L
I PLANT SYSTEMS SURVEILLANCE REQUIREMENTS Continued) b.
At least once per 12 months by cycling each testable valve in the flow path through at least one complete cycle of full travel.
c.
At least once per 18 months:
1.
By performing a system functional test which includes simulated automatic actuation of the system, and:
a)
Verifying that the automatic valves in the flow path actuate to their correct positions on a test signal, and b)
Cycling each valve in the flow path that is not testable during plant operation through at least one complete cycle of full travel.
2.
By a visual inspection of the dry pipe spray and sprinkler headers to verify their integrity.
l l
l l
i l
l l
l GRAND GULF-UNIT 1 3/4 7-32 Amendment No. 9 i
l
PLANT SYSTEMS CO SYSTEMS 2
LIMITING CONDITION FOR OPERATION 3.7.6.3 The following low pressure CO systems shall be OPERABLE:
2 Area Location System Number Electrical Penetration Room Auxiliary Bldg. E1.139'6" N1P640201A, B, C, D Electrical Penetration Room Auxiliary Bldg. E1. 119'0" N1P64D200A, B, C, D Control Cabinet Room Control Bldg. E1. 189'0" N1P640216 Division I Switchgear Room Control Bldg. E1. 111'0" N1P640207 Division III Switchgear Room Control Bldg. El. 111'0" N1P64D209 Division II Switchgear Room Control Bldg. E1. 111'0" N1P640208 Emergency Shutdown Panel Rm Control Bldg. El. 111'0" N1P640212 Motor Generator Room Control Bldg. E1. 148'0" N1P64D214 Electrical Switchgear Room Auxiliary Bldg. El. 166'0" N1P640217A, B Lower Cable Spreading Room Control Bldg. El. 148'0" N1P64D213 Upper Cable Spreading Room Control Bldg. El. 189'0" N1P640215 APPLICAP.ILITY: Whenever equipment protected by the CO systems is required to 2
be OPERABLE.
ACTION:
a.
With one or more of the above required CO, systems inoperable, within one hour establish a continuous fire watch wit 5 backup fire suppres-sion eouipment for those areas in which redundant systems or components could be damaged; for other areas, establish an hourly fire watch patrol.
Restore the system to OPERABLE status within 14 days or, in lieu of any other report required by Specification 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specifi-cation 6.9.2 within the next 30 days outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.
b.
The provisions of Specification 3.0.3 and 3.0.4 are not applicable.
GRAND GULF-UNIT 1 3/4 7-33 Amendment No. 9 wr
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PLANT SYSTEMS SURVEILLANCE REQUIREMENTS 4.7.6.3.1 Each of the above required CO2 systems shall be demonstrated OPERABLE at least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path is in its correct postion.
Position verification of differential pressure selector valves is not required, however, the valves' release levers shall be verified to be in the correct position.
4.7.6.3.2 Each of the above required low pressure CO2 systems shall be demonstrated OPERABLE:
a.
At least once per 7 days by verifying the CO 2 storage tank level to be greater than 50% and pressure to be greater than 275 psig, and b.
At least once per 18 months by:
1.
Verifying that the system valves and associated v'entilation system fire damper logic actuates automatically or manually, if applicable, upon receipt of a simulated actuation signal (actual CO release, electrothermal link burning, and dif-2 ferential pressure valve opening may be excluded from this test),and 2.
Flow from each nozzle by performance of a " Puff Test", and 3.
Exercising each ventilation system fire damper to the closed 4
position and verifying the dampers move freely.
GRAND GULF-UNIT 1 3/4 7-34 Amendment No. 9
i i
PLANT SYSTEMS HALON SYSTEMS LIMITING CONDITION FOR OPERATION 3.7.6.4 The following Halon systems shall be OPERABLE with the storage tanks having at least 95% of full charge weight and 90% of full charge pressure:
a.
Control Building, elev. 148'0", Computer and Control Panel Room b.
Control Building, elev.166'0", PGCC Under Floor Area c.
Control Cabinet Room, elev. 189'0", PGCC Under Floor Area APPLICABILITY: Whenever equipment protected by the Halon systems is required to be OPERABLE.
ACTION:
a.
With one or more of the above required Halon systems inoperable, within one hour establish a continuous fire watch with backup fire suppression equipment for those areas in which redundant systems or components could be damaged; for other areas, establish an hourly fire watch patrol.
Restore the system to OPERABLE status within 14 days or, in lieu of any other report required by Sp.ecification 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specifica-tion 6.9.2 within the next 30 days outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.
b.
The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.7.6.4 Each of the above required Halon systcms shall be demonstrated OPERABLE:
a.
At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path is in its correct position.
b.
At least once per 6 months by verifying Halon storage tank weight and pressure.
c.
At least once per 18 months by:
1.
Verifying that the system, including associated ventilation 4
system fire damper logic, actuates automatically upon receipt of a simulated actuation signal (Actual Halon release, Halon bottle initiator valve acuation, and electro-thermal link burning may be excluded from the test), and 2.
Performance of a flow test through headers and nozzles to assure no blockage, and 3.
Exercising each ventilation system fire dampers to the closed position and verifying the dampers move freely.
GRAND GULF-UNIT 1 3/4 7-35 Amendment No. 8, 9 w --.-
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PLANT SYSTEMS FIRE HOSE STATIONS.
LIMITING CONDITION FOR OPERATION 3.7.6.5 The fire hose stat'ons shown in Table 3.7.6.5-1 shall be OPERA 8LE.
APPLICA8ILITY: Whenever equipment in the areas protected by the fire hose stations is required to be OPERABLE.
ACTION:
a.
With one or more of the fire hose stations shown in Table 3.7.6.5-1 inoperable, route an additional fire hose of equal or greater diameter
- ^
to the unprotected area (s) from an OPERA 3LE hose station within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> if the inoperable fire hose is the primary means of fire suppression; otherwise, route the additional hose within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Restore the inoperable hose station (s) to OPERABLE status within 14 days or, in lieu of any other report required by Specificaton 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 30 days outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.
b.
The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.7.6.5 Each of the fire hose stations shown in Table 3.7.6.5-1 shall be demonstrated OPERABLE:
a.
At least once per 31 days by a visual inspection of the fire hose stations accessible during plant operation to assure all required equipment is at the station.
b.
At least once per 18 months by:
1.
Visual inspection of the fire hose stations not accessible during plant operation to assure all required equipment is at the station.
2.
Removing the hose for inspection and re-racking, and 3.
Inspecting all gaskets and replacing any degraded gaskets in the couplings.
c.
At least once per 3 years by:
.E 1.
Partially opening each hose station valve to verify valve OPERABILITY and no flow blockage.
2.
Conducting a hose hydrostatic test at a pressure of 150 psig or at least 50 psig above the maximum fire main operating pressure, whichever is greater.
l GRAND GULF-UNIT 1 3/4 7-36 Amendment No. 9 2
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4 TABLE 3.7.6.5-1 FIRE HOSE STATIONS HOSE RACK LOCATION ELEVATION INDENTIFICATION 4
AUXILIARY BUILDING Q.1-6.0 103'-0" 13A Q-5.7 119'-0" 138 Q.1-6.1 139'-0" 13C Q-6.0 166'-0" 130 Q-5.9 185'-0" 13E Q-6.0 208'-0" 13F Q-11.3 93'-0" 14A P.4-9.0 119'-0" 14B P.4-9.0 139'-0" 14C P.4-8.6 166'-0" 140 P.4-9.5 185'-0" 14E P-10 208'-10" 14F P.4-12.5 139'-0" 15A P.4-12.5 166'-0" ISB P.4-13.1 185'-0" 15C R-13.7 208'-10" 15D M.2-15.1 103'-0" 16A M.7-15.1 119'-0" 16B L.7-15.1 139'-0" 16C L.7-15.1 166'-0" 16D L.7-15.1 185'-0" 16E M.7-15.1 208'-10" 16F H.3-13.8 103'-0" 17A J.4-13.8 119'-0" 178 H-13.8 139'-0" 17C J-13.8 166'-0" 17D G.4-11 103'-0" 18A G.4-11.7 119'-0" 188 G.4-12.2 139'-0" 18C G.4-11.3 166'-0" 18D G.4-7.5 103'-0" 19A G.4-8.3 119'-0" 198 G.4-7.5 139'-0" 19C G.4-8.4 166'-0" 190 G.6-6.4 103'-0" 20A G.6-6.4 119'-0" 20B i
H-6.2 139"-0" 20C H-6.2 166'-0" 200 L-6.2 103'-0" 21A L-6.2 119'-0" 218 L-6.2 139"-0" 21C L-6.2 166'-0" 210 4
GRAND GULF-UNIT 1 3/4 7-37 Amendment No. 9 9-- 4 s,-
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TABLE 3.7.6.5-1 (Continued)
FIRE HOSE STATIONS HOSE RACX LOCATION ELEVATION INCENTIFICATION CONTAINMENT M.7-7.8 120'-10" 22A H.8-8.1 135'-4" 23A J.1-8.1 161'-10" 238 J.8-7.2 184'-6" 23C J.4-7.5 208'-10" 23D M.2-7.2 135'-4" 24A M.8-7.9 161'-10" 248 M.2-7.2 184'-6" 24C N-8.2 208'-10" 240 M.6-12.4 135'-4" 25A N.2-11.5 161'-10" 25B N.3-11.3 208'-10" 25C J.1-12.0 135'-4" 26A J-11.6 161'-10" 26B K.2-13.1 184'-6" 26C J-11.8 208'-10" 26D CONTROL BUILDING J.9-18.8 133'-0" 53A K.2-1G.8 111'-0" 53B G.1-18.4 111'-0" 548 G.2-18.4 133'-0" 54C G.1-18.7 148'-0" 540 G.2-18.8 166'-0" 54E G.1-18.7 189'-0" 54F K.2-18.8 148'-0" 55A K.2-18.8 166'-0" 558 K.2-18.8 189'-0" 55D DIESEL GENERATOR BUILDING R-10.6 133'-0" 66A R-8.4 133'-0" 66B GRAND GULF-UNIT 1 3/4 7-38 Amendment No. 9 4
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PLANT SYSTEMS YARD FIRE HYDRANTS AND HYORANT HOSE HOUSES LIMITING CONDITION FOR OPERATION 3.7.6.6 The yard fire hydrants and associated hydrant hose houses shown in Table 3.7.6.6-1 shall be OPERABLE.
APPLICABILITY: Whenever equipment in the areas protected by the yard fire hydrants is required to be OPERA 8LE.
ACTION:
a.
With one or more of the yard fire hydrants or associated hydrant hose houses shown in Table 3.7.6.6-1 inoperable, routs sufficient additional lengths of fire hose of equal or greater diameter located in an adjacent OPERABLE hydrant hose house to provide service to the unprotected area (s) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Restore the inoperable hydrant (s) and/or hose OPERABLE status within 14 days or, in lieu of any other report required by Specification 6.9.1, prepare and submit a Special Report to the Commis-sion pursuant to Specification 6.9.2 within the next 30 days outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.
b.
The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.7.6.6 Each of the yard fire hydrants and associated hydrant hose houses shown in Table 3.7.6.6-1 shall be demonstrated OPERABLE:
a.
At least once per 31 days by visual inspection of the hydrant hose house to assure all required equipment is at the hose house.
b.
At least once per 6 months, during March, April or May and during September, October or November, by visually inspecting each yard fire hydrant and verifying that the hydrant barrel is dry and that the hydrant is not damaged.
c.
At least once per 12 months by:
1.
' Conducting a hose hydrostatic test at a pressure of 150 psig or at least 50 psig above the maximum fire main operating pressure whichever is greater.
2.
Replacement of all degraded gaskets in couplings.
3.
Performing a flow check of each hydrant.
GRAND GULF-UNIT 1 3/4 7-39 Amendment No. 9 I
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TABLE 3.7.6.6-1 YARD FIRE HYDRANTS AND ASSOCIATED HYDRANT HOSE HOUSES LOCATION HYDRANT NUMBER / HYDRANT HOSE HOUSE NUMBER North Coord.
East Coord.
Elevation 9,616.00 10,500.00 133'0" D021/HHD 0298 l
9,570.00 10,299.00 133'0" D023/HHD 029C 9,570.00 10,012.50 133'0" 00:4/HHD 0290 9,798.00 9,979.00 133'0" 0025/HHD 029E 10,112.50 9,753.92 133'0" 0010/HHO 029G 9,886.00 9,758.25 133'0" 0009/HHD 029Q 9,641.00 9,766.25 133'0" 0008/HHD 029F 10,097.12 10,500.00 133'0" 0019/HHD 029I 9,871.87 10,534.33 133'0" 0020/HHD 029A l
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4 GRAND GULF-UNIT 1 3/4 7-40 Amendment No. 9
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PLANT SYSTEMS 3/4.7.7 FIRE RATED ASSEMBLIES LIMITING CONDITION FOR OPERATION 3.7.7 All fire rated assemblies (walls, floor / ceilings, cable tray enclosures and other fire barriers) separating safety related fire areas or separating portions of redundant systems important to safe shutdown within a fire area, and all sealing devices in fire rated assembly penetrations (fire doors, fire windows, fire dampers, cable and piping penetration seals and ventilation seals) shall be OPERABLE.
APPLICABILITY:
At all times.
ACTION:
a.
With one or more of the above required fire rated assemblies and/or sealing devices inoperable, within one hour establish a continuous fire watch on at least one side of the affected assembly (s) and/or sealing device (s) or verify the OPERABILITY of fire detectors on at least one side of the inoperable assembly (s) and/or sealing device (s) and establish an hourly fire watch patrol.
Restore the inoperable fire rated assembly (s) and/or sealing device (s) to OPERABLE status within 7 days or, in lieu of any other report required by Specifica-tion 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 30 days outlining the action taken, the cause of the inoperable fire rated assembly (s) and/or sealing device (s) and plans and schedule for restoring the fire rated assembly (s) and/or sealing device (s) to OPERABLE status.
b.
The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.7.7.1 Each of the above required fire rated assemblies and sealing devices shall be verified OPERABLE at least once per 18 months by performing a visual inspection of:
a.
The exposed surfaces of each fire rated assembly.
b.
Each fire window / fire damper and associated hardware, c.
At least 10 percent of each type of sealed penetration.
If apparent changes in appearance or abnormal degradations are found, a visual inspection of an additional 10 percent of each type of sealed
+
penetration shall be made. This inspection process shall continue until a 10 percent sample with no apparent changes in appearance or abnormal degradation is found.
l GRAND GdLF-UNIT 1 3/4 7-41 Amendment No. 9 r
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PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 4.7.7.2 Each of the above required fire doors shall be verified OPERABLE by inspecting the automatic hold-open, release and closing mechanism and latches at least once per 6 months, and by verifying:
a.
The OPERABILITY of the fire door supervision system for each electrically supervised fire door by performing a CHANNEL FUNCTIONAL TEST at least once per 31 days.
b.
That each locked-closed fire door is closed at least once per 7 days, c.
That doors with automatic hold-open and release mechanisms are free of obstructions at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and performing a functional test of these mechanisms at least once per 18 months.
d.
That each unlocked fire door without electrical supervision is closed at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
1 GRAND GULF-UNIT 1 3/4 7-42 Amendment No. 9 e
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- i PLANT SYSTEMS 3/4.7.8 AREA TEMPERATURE MONITORING i
LIMITING CONDITION FOR OPERATI0li 1
3.7.8 The temperature of each area shown in Table 3.7.8-1 shall be maintained within the limits indicated in Table 3.7.8-1.
APPLICABILITY: Whenever the equipment in an affected area is required to be OPERABLE.
ACTION:
With one or more areas exceeding the temperature limit (s) shown in Table 3.7.8-1:
a.
For more than eight hours, in lieu of any report required by Specification 6.9.1 prepare ano submit a Special Report to the Commis-sion pursuant to Specification 6.9.2 within the next 30 days providing a record of the amount by which and the cumulative time the temperature in the affected area exceeded its limit and an analysis to demonstrate the continued OPERABILITY of the affected equipment.
b.
By more than 30*F, in addition to the Special Report required above, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either restore the area to within its temperature limit or declare the equipment in the affected area inoperable.
SURVEILLANCE REQUIREMENTS 4.7.8 The temperature in each of the areas shown in Table 3.7.8-1 shall be determined to be within its limit at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
GRAND GULF-UNIT 1 3/4 7-43 Amendment No. 9 4
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TABLE 3.7.8-1 AREA TEMPERATURE MONITORING AREA TEMPERATURE LIMIT (*F)
EQUIPMENT EQUIPMENT NOT OPERATING OPERATING a.
Containment Inside Drywell 135 150 CRD Cavity 135 185 Outside Drywell 80 105 Steam Tunnel 125 125 b.
Auxiliary Building General 104 104 ECCS Rooms 105 150 ESF Electrical Rooms 104 104 l
Steam Tunnel 125 125 c.
Control Building ESF Switchgear and Battery Rooms 104' 104 Control Room 77 77 d.
Diesel Generator Rooms 125 125 e.
SSW Pumphouse 104*
104*
"For this area, the limit shall be the greater of 104*F or outside ambient temperature plus 20*F, not to exceed 122*F for greater than ene hour.
's GRAND GULF-UNIT 1 3/4 7-44 Amendment No. 9 l
1 PLANT SYSTEMS 3/4.7.9 SPENT FUEL STORAGE POOL TEMPERATURE LIMITING CONDITION FOR OPERATION 3.7.9 The spent fuel storage pool temperature shall be maintained at less than or equal to 150*f.
APPLICABILITY: Whenever irradiated fuel is in the spent fuel storage pool.
ACTION: With the spent fuel storage pool temperature greater than 150*F, restore the pool temperature to less than or squal to 150*F within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
SURVEILLANCE REQUIREMENTS 4.7.9 The spent fuel storage pool temperature shall be verified to be less than or equal to 150*F by determining the pool cooling system inlet temperature at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
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i GRAND GULF-UNIT 1 3/4 7-45 Amendment No. 9
PLANT SYSTEMS 3/4.7.10 EMBANKMENT STABILITY LIMITING CONDITION FOR OPERATION 3.7.10 The downstream access road slope at Culvert No. 1 and the drainage basin slopes shall remain stable.
APPLICABILITY: At all times.
ACTION:
If Culvert No. I has blockage exceeding 15% of its cross-sectional area, the Culvert shall be cleaned and the slope embankments verified to be stable.
SURVEILLANCE REQUIREMENTS 4.7.10 The downstream access road slope at Culvert No. 1 and the drainage basin slopes shall be confirmed to be stable by:
a.
At least once per year, performing a visual inspection of the embankments and Culvert No. 1.
b.
At least once per five years, performing a five year survey to confirm no significant degradation to the base-line data.
c.
Following the occurrence of earthquakes, hurricanes, tornados, or intense local rainfalls, a visual inspection of the embankments and Culvert No. I will be made.
If this special inspection reveals evidence of change, a survey will be performed to confirm no significant degradation to the base-line data.
GRAND GUL.F-UNIT 1 3/4 7-46 Amendment No. 9
t ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS 4.8.1.1.1 Each of the above required independent circuits between the offsite transmission network and the onsite Class lE distribution system shall be:
a.
Determined OPERABLE at least once per 7 days by verifying correct breaker alignments and indicated power availability, and b.
Demonstrated OPERABLE at least once per 18 months during shutdown by manually transferring uni; power supply from the normal circuit to the
+
alternate circuit.
4.8.1.1.2 Each of the above required diesel generators shall be demonstrated OPERABLE:
a.
In accordance with the frequency specified in Table 4.8.1.1.2-1 on a STAGGERED TEST BASIS by:
1.
Verifying the fuel level in the day tank.
2.
Verifying the fuel level in the fuel storage tank.
3.
Verifying the fuel transfer pump starts and transfers fuel from the storage system to the day tank.
4.
Verifying the diesel starts from ambient condition and accelerates to at least 441 rpm for diesel generators 11 and 12 and 882 rpm for diesel generator 13 in less than or equal to 10 seconds. The generator voltage and frequency shall be 4160 1 416 volts and 60 1 1.2 Hz within 10 seconds after the start signal. The diesel generator shall be started for this test by using one of the following signals:
a)
Manual.
b)
Simulated loss of offsite power by itself.
c)
Simulated loss of offsite power in conjunction with an ESF actuation test signal.
d)
An ESF actuation test signal by itself.
5.
Verifying the diesel generator is synchronized, loaded to greater than or equal to 7000 kW for diesel generators 11 and 12 and 3300 kW for diesel generator 13 in less than or equal to 60 seconds, and operates with these loads for at least 60 minutes.
6.
Verifying the diesel generator is aligned to provide standby power to the associated emergency busses.
7.
Verifying the pressure in all diesel generator air start receivers to be greater than or equal to:
a) 160 psig for diesel generator 11 and 12, and b) 175 psig for diesel generator 13.
b.
At least once per 31 days and after each operation of the diesel where the period of operation was greater than or equal to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> by checking for and removing accumulated water from the day fuel tanks.
GRAND GULF-UNIT 1 3/4 8-3 Amendment No. 7, 8, 9 e
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ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) c.
At least once per 92 days and from new oil prior to addition to the storage tanks by verifying that a sample obtained in accordance with ASTM-D270-1975 has a water and sediment content of less than or equal to.05 volume percent and a kinematic viscosity @ 40*C of greater than or equal to 1.9 but less than or equal to 4.1 when tested in accordance with ASTM-D975-77, and an impurity level of less than 2 mg. of insolubles per 100 ml. when tested in accordance with ASTM-D2274-70, except that the test of new fuel for impurity level shall be performed within 7 days after addition of the new fuel to the storage tank.
d.
At least once per 18 months, during shutdown, by:
1 1.
Subjecting the diesel to an inspection in accordance with pro-cedures prepared in conjunction with its manufacturer's recom-mendations for this class of standby service, i
2.
Verifying the diesel generator capability to reject a load of greater than or equal to 1200 kW (LPCS Pump) for diesel generator 11, greater than or equal to 550 kW (RHR B/C Pump) for diesel generator 12, and greater than or equal to 2180 kW (HPCS Pump) for diesel generator 13 while maintaining less than or equal to 75% of the difference between nominal speed and the overspeed trip setpoint, or 15% above nominal, whichever is less.
3.
Verifying the diesel generator capability to reject a load of 7000 kW for diesel generators 11 and 12 and 3300 kW for diesel generator 13 without tripping. The generator voltage shall not exceed 5000 volts during and following the load rejection.
4.
Simulating a loss of offsite power by itself, and:
a)
For Divisions 1 and 2:
1)
Verifying deenergization of the emergency busses and j
load shedding from the emergency busses.
2)
Verifying the diesel generator starts on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After ener-gization, the steady state voltage and frequency of the emergency busses shall be maintained at 4160 t 416 volts and 60't 1.2 Hz during this test.
b)
For Division 3:
1)
Verifying de-energizatioq of the emergency bus.
2)
Verifying the diesel generator starts on the auto-start signal, energizes the emergency bus with the loads within 10 seconds and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization, the steady state voltage and 4
frequency of the emergency bus shall be maintained at 4160 416 volts and 60 i 1.2 Hz during this test.
GRAND GULF-UNIT 1 3/4 8-4 Amendment No. 7, 9 1
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ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 5.
Verifying that on an ECCS actuation test signal, without loss of offsite power, the diesel generator starts on the auto-start signal and operates on standby for greater than or equal to 5 minutes. The generator voltage and frequency shall be 4160 t 416 volts and 60 t 1.2 Hz within 10 seconds after the auto-start signal; the steady state generator voltage and frequency shall be maintained within these limits during this test.
6.
Verifying that on a simulated loss of the diesel generator, with offsite power not available:
a.
For Divisions 1 and 2:
1.
The loads are shed from emergency busses associated with Diesel Generators 11 and 12.
2.
Subsequent loading of the diesel generators is in accordance with design requirements.
b.
For Division 3:
1.
Tha associated output breaker for Diesel Generator 13 opens automatically.
2.
Subseqent loading of the diesel generator is in accordance with design requirements.
7.
Simulating a loss of offsite power in conjunction with an ECCS actuation test signal, and:
a)
For Divisions 1 and 2:
1)
Verifying deenergization of the emergency busses and load shedding from the emergency busses.
2)
Verifying the diesel generator starts on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected shutdown loads through the load sequencar and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads.
After energization, the steady state voltage and frequency of the emergency busses shall be maintained at 4160 t 416 volts and 60 1 1.2 Hz during this test.
b)
For Division 3:
1)
Verifying de energization of the emergency bus.
2)
Verifying the diesel generator starts on the auto-start signal, energizes the emergency bus with the permanently connected loads within 10 seconds and the autoconnected y
emergency loads within 20 seconds and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads.
After energization, the steady state voltage and frequency of the emergency bus shall be maintained at 4160 i 416 volts and 60 1 1.2 Hz during this test.
GRAND GULF-UNIT 1 3/4 8-5 Amendment No. 7, 9
- ~.
. ~ ~
- ~..
l ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 8.
Verifying that all automatic diesel generator trips are automatically bypassed upon an ECCS actuation signal except:
a)
For Divisions 1 and 2, engine overspeed, generator differential current, low lube oil pressure, and generator ground overcurrent.
b)
For Division 3, engine overspeed and generator differential current.
9.
Verifying the diesel generator operates for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
During the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of this test, the diesel generator shall be loaded to greater than or equal to 7700 kW for diesel gen-erators 11 and 12 and 3630 kW for diesel generator 13 and during the remaining 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> of this test, the diesel generator shall be loaded to 7000 kW for diesel generators 11 and 12 and 3300 kW for diesel generator 13.
The generator voltage and frequency shall be 4160 t 416 volts and 60 1 1.2 Hz within 10 seconds after the start signal; the steady state generator voltage and frequency shall be maintained within these limits during this test. Within 5 minutes after completing this 24-hour test, perform Surveillance Requirement 4.8.1.1.2.d.7.a).2) and b).2)*.
10.
Verifying that the auto-connected loads to each diesel generator do not exceed the continuous rating of 7000 kW for diesel generators 11 and 12 and 3300 kW for diesel generator 13.
11.
Verifying the diesel generator's capability to:
a)
Synchronize with the offsite power source while the generator is loaded with its emergency loads upon a simulated l
restoration of offsite power, l
b)
Transfer its loads to the offsite power source, and c)
Be restored to its standby status.
12.
Verifying that with the diesel generator operating in a test mode and connected to its bus that a simulated ECCS actuation signal:
a)
For Divisions 1 and 2, overrides the test mode by rcturn-ing the diesel generator to standby operation.
b)
For Division 3, overrides the test mode by bypassing the diesel generator automatic trips per Surveillance Require-ment 4.8.1.1.2.d.8.b).
13.
Verifying that with all diesel generator air start receivers l
pressurized to less than or equal to 256 psig and the compres-L' sors secured, the diesel generator starts at least 5 times from i
ambient conditions and accelerates to at least 441 rpm for l
diesel generators 11 and 12 and 882 rpm for diesel generator 13 l
in less than or equal to 10 seconds.
aIf Surveillance Requirement 4.8.1.1.2.d.4.a)2) or b)2) are not satisfactorily completed, it is not necessary to repeat the preceding 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test.
- Instead, the diesel generator may be operated at rated load for one hour or until operating temperatures have stabilized.
GRAND GULF-UNIT 1 3/4 8-6 Amendment No. 7, 9 e.*e
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ELECTRICAL POWER SYSTEMS A.C. SOURCES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.1.2 As a minimum, the following A.C. electrical power sources shall be OPERABLE:
a.
One circuit between the offsite transmission network and the onsite Class 1E distribution system, and b.
Diesel generator 11 and/or 12, ano diesel generator 13 when the HPCS system is required to be OPERABLE, with each diesel generator having:
1.
A day tank containing a minimum of 220 gallons of fuel.
2.
A fuel storage system containing a minimum of:
a) 48,000 gallons of fuel each for diesel generators 11 and 12.
b) 39,000 gallons of fuel for diesel generator 13.
3.
A fuel transfer pump.
APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *.
ACTION:
a.
With all offsite circuits inoperable and/or with diesel generators 11 and/or 12 of the above required A.C. electrical power sources inoperable, suspend CORE ALTERATIONS, handling of irradiated fuel in the primary or secondary containment, operations with a potential for draining the reactor vessel and crane operations over the spent fuel storage pool when fuel assemblies are stored therein.
In addition, when in OPERATIONAL CONDITION 5 with the water level less than 23 feet above the reactor pressure vessel flange, immediately initiate corrective action to restore the required power sources to OPERABLE status as soon as practical.
b.
With diesel generator 13 of the above required A.C. electrical power sources inoperable, restore the inoperable diesel generator 13 to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.
c.
The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS
. 4.8.1.2 At least the above req'uired A.C. electrical power sources shall be demonstrated OPERABLE per Surveillance Requirements 4.8.1.1.1, 4.8.1.1.2 and 4.8.1.1.3, except for the requirement of 4.8.1.1.2.a.5.
- When handling irradiated fuel in the primary or secondary containment.
l GRAND GULF-UNIT 1 3/4 8-9 Amendment No. 9 i
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ELECTRICAL POWER SYSTEMS D.C. SOURCES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, Divi 'an 1 or Division 2, and, when the HPCS system is required to be OPERABLE, Division 3, of the D.C. electrical power sources shall be OPERABLE with:
a.
Division 1 consisting of:
1.
125 volt battery 1A3.
2.
125 volt full capacity charger 1A4 or 1AS.
b.
Division 2 consisting of:
1.
125 volt battery 183.
2.
125 volt full capacity charger 184 or 185.
c.
Division 3 consisting of:
1.
125 volt battery IC3.
2.
125 volt full capacity charger 1C4.
APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *.
ACTION:
a.
With both Division 1 battery and Division 2 battery of the above required D.C. electrical power sources inoperable, suspend CORE 4
ALTERATIONS, handling of irradiated fuel in the primary or secondary containment and operations with a potential for draining the reactor vessel.
b.
With Division 3 battery of the above required D.C. electrical power sources inoperable, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.
c.
With the above required full capacity charger inoperable, demonstrate the OPERABILITY of its associated battery by performing Surveillance Requirement 4.8.2.1.a.1 within one hour and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter.
If any Category A limit in Table 4.8.2.1-1 is not met, declare the battery inoperable.
d.
The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.8.2.2 At least the above required battery and charger shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.1.
's When handling irradiated fuel in the primary or secondary containment.
GRAND GULF-UNIT 1 3/4 8-14 Amendment No. 9 1
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ELECTRICAL POWER SYSTEMS DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.3.2 As a minimum, the following power distribution system divisions shall be energized:
I a.
For A.C. power distribution, Division 1 or Division 2, and when the HPCS system is required to be OPERABLE, Division 3, with:
1.
Division 1 consisting of:
a) 4160 volt A.C. bus 15AA.
b) 480 volt A.C. MCCs 15B11,15821,15B31,15841,15B51 and 15861.
c) 120 volt A.C. distribution panels in 15P11,15P21,15P31, 15P41, 15P51 and 15P61.
d)
LCCs 15BA1, 15BA2, 15BA3, 15BA4, 15 BAS and 15BA6.
2.
Division 2 consisting of:
a) 4160 volt A.C. bus 16AB.
b) 480 volt A.C. MCCs 16811, 16B21, 16831, 16841, 16B51 and 16B61.
c) 120 volt A.C. distribution panels in 16P11, 16P21, 16P31, 16P41, 16P51 and 16P61.
d)
LCCs 16B81, 16BB2, 16883, 16884, 16BB5 and 16BB6.
3.
Division 3 consisting of:
a) 4160 volt A.C. bus 17AC.
b) 480 volt A.C. MCCs 17801 and 1.7811.
c) 120 volt A.C. distribution panels 17P11.
4.
The OPERABLE load shedding and sequencing panel associated with the division (s) required to be energized.
b.
For D.C. power distribution, Division 1 or Division 2, and when the HPCS system is required to be OPERABLE, Division 3, with:
1.
Division 1 consisting of 125 volt D.C. distribution panel 1DA1 and 10A2.
2.
Division 2 consisting of 125 volt D.C. distribution panel IDB1 and 1082.
3.
Division 3 consisting of 125 volt D.C. distribution panel 1DC1.
APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *.
When handling irradiated fuel in the primary or secondary containment.
GRAND GULF-UNIT 1 3/4 8-17 Amendment No. 9
ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)
ACTION:
a.
For A.C. power distribution:
1.
With both Division 1 and Division 2 of the above required A.C.
distribution system not energized and/or with the load shedding and sequencing parel associated with the division (s) required to be energized inoperable, suspend CORE ALTERATIONS, handling i
of irradiated fuel in the primary or secondary containment and I
operations with a potential for draining the reactor vessel.
2.
With Division 3 of the above required A.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.
b.
For D.C. power distribution:
1.
With both Division 1 and Division 2 of the above required D.C.
distribution system not energized, suspend CORE ALTERATIONS, handling of irradiated fuel in the primary or secondary con-l tainment and operations with a poten'tial for draining the reactor vessel.
2.
With Division 3 of the above required D.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.
c.
The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.8.3.2.1 At least the above required power distribution system divisions shall be determined energized at least once per 7 days by verifying correct breaker alignment on the busses /LCs/MCCs/ panels and voltage on the busses /LCs.
4.8.3.2.2 The above required load shedding and sequencing panel (s) shall be demonstrated OPERABLE:
a.
At least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> by determining that the auto-test system is operating and is not indicating a faulted condition.
b.
At least once per 31 days by performance of a manual test and verifying resaonse within the design criteria to the following test inputs:
a)
LOCA.
b)
Bus undervoltage.
c)
Bus undervoltage followed by LOCA.
d)
LOCA followed by bus undervoltage.
GRAND GULF-UNIT 1 3/4 8-18 Amendment No. 7, 9
TABLE 3.8.4.1-1 PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES TRIP
RESPONSE
SYSTEM /
DEVICE NUMBER SETPOINT TIME COMPONENT AND LOCATION (Amperes)
(Cycles)
AFFECTED a.
6.9 kV Circuit Breakers 7200/45/110%l 252-1103-B 60 Reactor Recir. Pump 252-1103-C 7200/45/ 10%
60 Pump B33C001A 252-1205-B 7200/45/1 10%,
60 Reactor Recir. Pump 252-1205-C 7200/45/1 10%,
60 Pump B33C0018 b.
480 VAC Circuit Breakers Stored Energy Type K6005 with SS3G3 Tripping Device TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-12202 1200 0.05 CONTAINMENT COOLING FILTER TRAIN HEATERS (N1M41D0028-N) 52-12209 2000 0.05 CNTMT POLAR CRANE (Q1F13E001-N) 51-11502 1200 0.05 CNTMT CLG. FILTER TRAIN HEATER (N1M410002A-N) 52-15105 2000 0.05 DRYWELL PURGE COMPRESS.
(Q1EelC001A-A) 52-16204 2000 0.05 DRYWELL PURGE COMPRESS.
(Q1E61C0018-B) 52-16404 1200 0.05 HYDROGEN RECOMBINER (Q1E61C0038-B) 52-15205 1200 0.05 HYDROGEN RECOMBINER (Q1E61C003A-A)
- rimary current /setpoint.
P GRAND GUL.c-UNIT 1 3/4 8-21 Amendment No. 8, 9
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TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1112-01 500 0.100 NEUTRON MON SYS DRIVE MECHANISM (1C51-J001A) 52-1112-02 500 0.100 NEUTRON MON SYS DRIVE MECHANISM (1C51-J0018) 52-1112-03 500' O.100 NEUTRON MON SYS DRIVE MECHANISM (1C51-J001C) 52-1112-04 500 0.100 NEUTRON MON SYS DRIVE MECHANISM (1C51-J001D) 52-1112-05 175 0.100 3 TEAM TUNNEL CLR INSIDE CTMT FAN (N1M41C004A-N) 52-1112-06 500 0.100 NEUTRON MON SYS DRIVE MECHANISM (1C51-J001E) 52-1112-07 1200 0.100 LIGHTING XFMR 15105 l
(N1R185105-D) l 52-1112-10 1200 0.100 LIGHTING XFRM 1X109 (N1R18S109-D) 52-1112-15 320 0.100 RWCU BACKWASH TRANSFER PUMP (N1G36C004-N) 52-1112-18 24 0.100 PREC0AT TANK AGITATOR (N1G36D019-N) 52-1112-20 90 0.100 RWCU FILTER DEMIN HOLDING PUMP (N1G36C001A-N)
GRAND GULF-UNIT 1 3/4 8-22 Amendment No. 4, 9
-49 Www ww-rt e-w
~
TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
40 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1112-21 800 0.100 480 V RECEPTACLE 52-1112-22 5
0.100 MOV-STM TUNNEL COOLER INLET (N1P44F105A-N) 52-1112-24 32 0.100 MOV CLEANUP LINE RECIRC LOOP A (Q1G33F100-N)
I 52-1112-27 24 0.100 RESIN TANK AGITATOR i
(NIG360020-N) 52-1112-28 38 0.100 MOV RWCU HEAT EXCHANGER BYPASS (N1G33F104-N) 52-1112-31 38 0.100 MOV RWCU HEAT EXCHANGER BYPASS (N1G33F044-N) 52-1112-36 500 0.100 REAC. RECIRC. PUMP SPACE HEATER (TB1833C001A) i S2-1112-37 800 0.100 480 V RECEPTACLE 52-1112-41 6
0.100 REAC RECIRC SAMPLE PANEL ISOL MOV (N1033F129) 52-1113-07 125 0.100 CNTMT FLOOR DRAIN SUMP PUMP (N1P45C0198-N) 52-1113-21 60 0.100 DRYWELL EQUIP DRAIN SUMP PUMP (N1P45C0028-N) e 52-1113-30 28 0.100 MOV RWCU HX OUTL ISOL VLV (N1G33F254-N)
GRAND GULF-UNIT 1 3/4 8-23 Am'endment No. 4, 9 i
-s n..g
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-,md-syne,aw.--,,,.e4.ge.-g,-.y,w,---m-ww,
=,-mm1
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r
TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
483 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP RESPONSJ BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1113-44 800 0.100 480 V RECEPTACLE 52-1113-47 500 0.100 SPARE 52-1151-06 240 0.100 CNTMT COOLING FILTER TRAIN FAN (N1M41D002A-N) 52-1151-07 17.5 0.100 REAC. RECIRC. HPU OIL PUMP FAN (N18330003A3-N) 52-1151-10 600 0.100 REAC. RECIRC. HPU OIL PUMP (N18330003Al-N) 52-1151-12 75 0.100 MOV - RECIRC PUMP SUCTION (Q1833F023A-N) 52-1151-19 75 0.100 MOV RECIRC PUMP DISCHARGE (Q1833F067A-N) 52-1151-20 600 0.100 REAC. RECIRC. HPU OIL PUMP (N18330003A2-N) 52-1151-21 17.5 0.100 REAC. RECIRC. HPU OIL PUMP FAN (N18330003A4-N) 52-1151-22 60 0.100 DRYWELL CHEMICAL WASTE SUMP PbMP (N1P45C029-N) 52-1151-27 60 0.100 DRYWELL EQPT. DR.
SUMP PUMP (N1P45C002A-N) 52-1151-28 125 0.100 CNTMT FLOOR DR.
SUMP PUMP (N1P45C019A-N)
~
GRAND GULF-UNIT 1 3/4 8-24 Amendment No. 4, 9
-y r,wwf g_-3 g
m,4 y---c.
---4
- -.----+-
+y--
,,-.y---+----+
r
'I 1
TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1222-04 800 0.100 CNTMT CLR FAN COIL UNIT FAN (N1M418001B-N) 52-1222-05 240 0.100 CNTMT COOLING SYS CHAR TRAIN FAN (N1M4100028-N) 52-1222-09 1200 0.100 LIGHTING XFMR 1X104 (N1R18S204-E) 52-1222-11 800 0.100 480 V RECEPTACLES 52-1222-18 500 0.100 REAC. RECIRC. PUMP SPACE HEATER (TB1833C0018) 52-1222-19 75 0.100 MOV - RWCU RETURN TO REACTOR (N1G33F042-N) 52-1222-20 32 0.100 MOV - VESSEL DRAIN LINE RECIRC.
(Q1G33F101-N) 52-1222-21 75 0.100 MOV - CLEANUP LINE SUCT. IN DRYWELL (Q1G33F102-N) 52-1222-22 32 0.100 MOV - CLEANUP LINE RECIRC LOOP B (Q1G33F106-N) 52-1251-01 175 0.100 STEAM TUNNEL CLR INSIDE CNTMT i
(N1M41C0048-N) 52-1251-07 60 0.100 CNTMT CHEM WASTE SUMP PUMP (N1P45C027A-N)
GRAND GULF-UNIT 1, 3/4 8-25 Amendment No. 4, 9
TABLE 3.8.4.1_1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1251-13 800 0.100 CNTMT CLR FAN COIL UNIT FAN (N1M41B001C-N) 52-1251-15 32 0.100 MOV - RWCS HX INL ISOL VLV (N1G33F256-N) 52-1251-18 38 0.100 MOV - REGEN HEAT EXCHANGER BYPASS (Q1G33F107-N) 52-1251-19 38 0.100 MOV - RWCU DRAIN FLOW ORIFICE BYP (N1G33F031-N) 52-1251-20 320 0.100 CNTMT EQUIP DRAIN PUMP (N1P45C0048-N)
~
52-1251-22 32 0.100 MOV - RWCU TO FLT "S" ISOL VLV (N1G33F255-N) 52-1251-26 1200 0.100 LIGHTING XFMR 1X112 l
(N1R18S112-0) 52-1251-28 5
0.100 MOV - STM TUNNEL COOLER INLET (N1P44F105B-N) 52-1252-23 60 0.100 ORYWELL FLOOR DRAIN SUMP PUMP (N1P45C0018-N) 52-1411-01 38 0.100 MOV - VESSEL HEAD VENTILATION (Q1821F002-N)
GRAND GULF-UN T 1 3/4 8-26 Amendment No. 4, 9 AMe
+-em
o TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT Pn0TECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1412-01 17.5 0.100 REAC RECIRC HPU l
OIL PUMP FAN (N1833D003B3-N) l 52-1412-02 60 0.100 CNTMT CHEM WASTE SUMP PUMP (N1P45C0278-N) 52-1412-03 60 0.100 DRYWELL FLOOR DRAIN SUMP PUMP (N1P45C001A-N) 52-1412-05 12.5 0.100 MOV CRD C00LWTR PRESS CONTROL (NIC11F003-N) 52-1412-08 105 0.100 MOV REAC RECIRC PUMP B SUCTION (Q1833F0238-N) 52-1412-09 175 0.100 RWCU DEMIN PREC0AT PUMP (N1G36C002-N) 52-1412-12 90 0.100 RWCU DEMIN HOLDING PUMP (N1G36C0018-N) 52-1412-15.
600 0.100 REAC RECIRC HPU OIL PUMP (N1833D003B1-N) 52-1412-17 320 0.100 CNTMT EQUIP DRAIN SUMP PUMP (N1P45C004A-N) 52-1412-20 800 0.100 480 V RECEPTACLE 52-1412-23 600 0.100 REAC RECIRC HPU OIL PUMP (N18330003B2-N)
GRAND GULF-UNIT 1 3/4 8-27 Amendment No. 4, 9
TABLE 3.8.4.1-1 (Continued)
PRIMARY CON 1AINMENT PENETRATION CONDUCTOR OVERCURkENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Conticued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINI TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1412-25 17.5 0.100 REAC RECIRC HPU OIL PUMP FAN (N18330003B4-N) 52-1412-26 38 0.100 MOV REACTOR VESSEL HEAT VENT (Q1821F001-N) 52-1412-28 38 0.100 MOV REACTOR VESSEL HEAT VENT (Q1821F005-N) 52-1412-32 800 0.100 CNTMT CLR FAN COIL UNIT FAN (N1M418001A-N) 52-1412-33 105 0.100 MOV - REAC RECIRC PUMP A DISCHARGE (Q1833F0678-N) 52-1412-35 500 0.100 CRD REMOVAL HOIST (N1M31E003-N) 52-1412-39 1200 0.100 DRYWELL VALVE HOIST (Q1M31E002-N) 52-1412-41 32 0.100 CNTMT AIRLOCK AIR SHOWER FAN (N1M41C005-N) 52-1511-07 50 0.100 MOV - RWCS INL INB ISOL VLV (Q1G33F250-A) 52-1511-24 50 0.100 MOV - RWSC OUT INB ISOL VLV (Q1G33F252-A) 52-1511-44 12.5 0.100 MOV - DRYWELL CLG' WATER ISOL (Q1P42F116-A)
GRAND GULF-UNIT 1 3/4 8-28 Amendment No. 4, 9
+. -.
- - - * - =
e,,, -
ye p.,..9-y-
---au--w
- w mey--4vsT-Frwv"
---ee-ye-="fr-t y
---e--r*y-mywe-e---
-p=---a+4
---e--&me-m
,y-e-y
- -+
-1re-Y 4
...m..
TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1511-54 24 0.100 Spare 52-1521-02 6
0.100 MOV COMBUSTIBLE GAS CONTROL SYS (Q1E61F003A-A) 52-1521-03 6
0.100 MOV COMBUSTIBLE GAS CONTROL SYS (Q1E61F005A-A) 52-1521-07 10 0.100 MOV - SUPPR. POOL MAKE-UP VALVE (Q1E30F002A-A) 52-1521-14 600 0.100 SLC SYSTEM PUMP (Q1C41C001A-A) 52-1521-15 5
0.100 STORAGE TANK OUTLET VALVE (Q1C41F001A-A) 52-1521-28 12.5 0.100 MOV - INST LINE ISOL VALVE (Q1M71F595-A)
~
52-1521-44 10 0.100 MOV - SUPPR POOL MAKE-UP VALVE (Q1E30F001A-A) 52-1531-24 12.5 0.100 MOV - DRYWELL COOLER ISOLATION (Q1P44F076-A) 52-1531-25 8
0.100 MOV - REACTOR WATER SAMPLE (Q1833F020-A)
GRAND GULF-UNIT 1 3/4 8-29 Amendment No. 4, 9 3
--3 sy7
--w-.>-y-
- - - -p,ye.es.*y-ym-,-y e
.y,-,-
egweg eyn+---w s
--69w--,n-e-,-
e.
---ge- - - -
e
---w'm w
w-w--,r
4 TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1531-36 320 0.100 MOV - LPCI A INJECTION ISOL (Q1E12F042A-A) 52-1531-44 125 0.100 MOV - SHR A UPPER CMT POOL SPRAY (Q1E12F037A-A) 52-1531-49 32 0.100 MOV - DRWELL CHEM WASTE ISOL (Q1P45F096-A) 52-1531-50 105 0.100 MOV - RHR A CONTAINMENT SPRAY (Q1E12F028A-A) 52-1541-32 32 0.100 MOV - COMB GAS CONT COMP A OUT (Q1P41F168A-A) 52-1542-05 320 0.100 DRYWELL COOLER FAN COIL UNIT (N1M518001A-A) 52-1542-06 320 0.100 DRYWELL COOLER FAN COIL UNIT (N1M5B002A-A) 52-1542-07 320 0.100 DRYWELL COOLER i
FAN COIL UNIT (N1M51B003A-A) 52-1542-08 320 0.100 DRYWELL COOLER a
FAN COIL UNIT
' l (N1M518004A-A) i 52-1542-09 320 0.100 DRYWELL COOLER FAN COIL UNIT (N1M518005A-A)
GRAND GULF-UNIT 1 3/4 8-30 Amendment No. 4, 9
TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM 4
TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1542-10 320 0.100 DRYWELL COOLER FAN COIL UNIT (NIM 518006A-A) 52-1542-14 5
0.100 MOV - DRYWELL COOLER INLET (N1P44F055-A) 52-1542-15 5
0.100 MOV - ORYWELL COOLER INLET (N1P44F057-A) 52-1542-16 5
0.100 MOV - DRYWELL COOLER INLET (N1P44F059-A)
^
52-1542-17 5
0.100 MOV - DRYWELL COOLER INLET (N1P44F061-A) 52-1542-18 5
0.100 MOV - DEYWELL COOLER INLET (NIP 44F063-A) 52-1542-19 5
0.100 MOV - DRYWELL COOLER INLET (N1P44F065-A) 52-1542-21 800 0.100 SLCS OPERATING HEATER (NIC41D002) 52-1542-22 24 0.100 DRWL PURGE COMP i
AUX OIL PUMP
]
(Q1E61C001A-A) i 52-1542-23 500 0.100 REFUELING PLATFORM ASSY (Q1F15E003-A) 52-1542-26 175 0.100 DRYWELL RECIRC FAN (N1M51C001-A)
GRAND GULF-UNIT 1 3/4 8-31 Amendment No. 4, 9 w,.,
e
'~
.j TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES l
c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED f
52-1542-29 1200 0.100 STBY LIQ CONTROL SYS MIXING HEATER (Q1C41D003) l 52-1611-10 12.5 0.100 MOV - DRYWELL COLL TK OUTLET ISOLATION (Q1G41F044-B) 52-1611-15 12.5 0.100 MOV - PSW CTMT STM TNL CLR ISOL (Q1P44F070-8) 52-1611-25 12.5 0.100 MUV - DRYWELL CLG WTR ISOL (Q1P42F117-8) 52-1611-31 12.5 0.100 MOV - DRYWELL l
CLG WTR INL ISOL (Q1P42F114-B) 52-1611-32 32 0.100 MOV - CTMT CLG WTR ISOLATION (Q1P42F068-B) 52-1611-42 12.5 0.100 MOV PSW STEAM TUNNEL CLR ISOL (Q1P44F074-B) 52-1611-43 12.5 0.100 MOV PSW STEAM l
TUNNEL CLR ISOL (Q1P44F077-B) 52-1611-44 38 0.100 MOV - SERVICE AIR l
DRYWELL ISOLATION (Q1PS2F195-B) 52-1621-03 7
0.100 MOV - DRWL HYDR INST LINE ISO (Q1E61F5958-B) 52-1621-04 7
0.100 MOV - DRWL HYDR INST LINE ISO (Q1E61F5978-B)
GRAND GULF-UNIT 1 3/4 8-32 Amendment No. 4, 9 y
e g.
e p
=
an v
8y
____.__._____.__m_.
.i
- 49
'Ag
((gfY s[)ff (9 k
IMAGE EVALUATION k//7% '(' @ /
TEST TARGET (MT-3) k@
- 4,,,p ppp I.0 52 M E
- N'==a
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- !!!!!=N lH H1.25 1.4 1.6 Il 4
150mm 4
6"
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4 150mm 4
6"
>,,///?
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TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1621-05 7
0.100 MOV - DRWL HYDR INST LINE ISO (Q1E61F5950-B) 52-1621-06 7
0.100 MOV - DRWL HYDR INST LINE ISO (Q1E61F5970-B) 52-1621-07 7
0.100 MOV CTMT HYDR INST LINE ISOL (Q1E61F5968-B) 52-1621-08 7
0.100 MOV CTMT HYDR INST LINE ISOL (Q1E61F5988-B)
~
52-1621-09 7
0.100 MOV CTMT HYDR INST LINE ISO (Q1E61F596D-B) 52-1621-10 7
0.100 MOV CTMT HYDR INST LINE ISO (Q1E61F5980-B) 52-1621-16 10 0.100 CONTAINMENT ISOL VALVE (Q1833F128-B) 52-1621-17 6
0.100 MOV - DRWL PURGE INLET (Q1261F0038-B) 52-1621-18 6
0.100 MOV. DRWL PURGE VACUUM RELIEF (Q1E61F0058-B) 52-1621-19 24 0.100 SPARE GRAND GULF-UNIT 1 3/4 8-33 Amendment No. 4, 9
TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1621-40 32 0.100 MOV - COMB GAS CONT COMP B OUT (Q1P41F1688-B) 52-1631-06 125 0.100 MOV - RHR B UPPER CTMT P0OL SPRAY (Q1E12F0378-B) 52-1631-13 320 0.100 MOV - RHR B LPCS (Q1E12F042B-B) 52-1631-15 105 0.100 MOV-SSW TO RHR SYSTEM (Q1E12F0968) 52-1631-20 12.5 0.100 MOV - MAIN STEAM LINE DRAIN INBD (Q1821F016-B) 52-1631-29 600 0.100 STANDBY LIQUID CONTROL PUMP (Q1C41C001B-B) 52-1631-33 105 0.100 MOV - RHR B TO CONTAINMENT SPRAY (Q1E12F0288-B) 52-1631-34 105 0.100 MOV - RCIC STEAM SUPPLY LINE ISOL (Q1E51F063-B) 52-1631-35 5
0.100 STORAGE TANK OUTLET VALVE (Q1C41F0018-B)
~
52-1631-37 240 0.100 MOV
."HR'A.SHT ON CLG INBD ISO (Q1E12F009-B) 52-1631-38 32 0.100 MOV - RCIC STEAM i
WARMUP LINE ISOL (Q1E51F076-B)
GRAND GULF-UNIT 1-3/4 8-34 Amendment No. 4, 9
TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1631 *1 8
0.100 MOV - REACTOR WATER SAMPLE (Q1833F019-8) 52-1631-47 50 0.100 MOV - INST AIR DRWL OUTBD ISOL (Q1P53F007-8) 52-1631-50 32 0.100 MOV - RWCU OUTLET TO MAIN CONDENSER (Q1G33F028-B) 52-1631-51 32 0.100 MOV RWCU SYS ISOLATIN VALVE (Q1G33FL53-B) 52-1631-52 50 0.100 MOV - RWCU SYS ISOLATION (Q1G33F040-B) 52-1631-53 50 0.100 MOV - RWCU SYS ISOLATION (Q1G33F001-B) 52-1641-06 32 0.100 MOV - MAKE UP WATER CNTMT ISOL (Q1P21F018-B) 52-1641-07 50 0.100 MOV - RWCS INL OUT ISOL VLV t
l (Q1G33F251-B) 52-1641-08 50' O.100 MOV - RWCS INL
~
OUT ISOL VLV (Q1G33F253-B) 52-1641-16 7-0.100 MOV INSTRUMENT LINE INBOARD ISO (Q1023F591-B)
GRAND GULF-UNIT 1 3/4 8-35 Amendment No. 4, 9
., 1 _._
TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES I
c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUM6ER (Amperes)
(Seconds)
AFFECTED 52-1641-18 7
0.100 MOV - INSTRUMENT LINE INBOARD ISO (Q1D23F593-B) 52-1641-24 7
0.100 CONTAINMENT ISOL VALVE (Q1833F126-B) 52-1641-26 32 0.100 MOV - DRYWELL CHEM WASTE ISOL (Q1P45F097-B) 52-1641-35 10 0.100 MOV - SUPPR POOL MAKE UP VA.LVE (Q1E30F0018-B) 52-1641-36 10 0.100 MOV - SUPPR POOL MAKE UP VALVE (Q1E30F0028-B) 52-1642-05 320 0.100 DRYWELL COOLER FAN COIL UNIT (NIM 5180018-B) 52-1642-06 320 0.100 DRYWELL COOLER FAN COIL UNIT (N1M5180028-B) 52-1642-07 320 0.100 DRYWELL COOLER FAN COIL UNIT (N1M5180038-B) 52-1642-08 320 0.100 DRYWELL COOLER FAN COIL UNIT (N1M5180048-B) 52-1642-09 320 0.100 DRYWELL COOLER FAN COIL UNIT (N1M5180058-B)
GRAND GULF-UNIT 1 3/4 8-36 Amendment No. 4, 9
TABLE 3.8.4.1-1 (Continued)
PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.
480 VAC Circuit Breakers (Continued)
Molded Case, Type NZM TRIP
RESPONSE
BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)
(Seconds)
AFFECTED 52-1642-10 320 0.100 DRWELL COOLER FAN COIL UNIT (N1M5180068-B) 52-1642-14 12.5 0.100 MOV - DRWELL COOLER INLET (N1P44F056-B) 32-1642-15 12.5 0.100 MOV - ORWELL COOLER INLET (N1P44F058-B) 52-1642-16 12.5 0.100 MOV - DRWELL COOLER INLET (N1P44F060-B) 52-1642-17 12.5 0.100 MOV - ORWELL COOLER INLET (N1P44F062-B) 52-1642-18 12.5 0.100 MOV - DRWELL COOLER INLET (N1P44F064-B) 52-1642-19 12.5 0.100 MOV - DRWELL COOLER INLET (N1P44F066-B) 52-1642-21 24 0.100 DRWL PURGE COMP AUX OIL PUMP (Q1E61C0018-8) 52-1642-29 175 0.100 DRWL RECIRC FAN (N1M51C0028)
GRAND GULF-UNIT 1 3/4 8-37 Amendment No. 4, 9 r-7 y
. - ~.
6 4
ELECTRICAL POWER SYSTEMS MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION LIMITING CONDITION FOR OPERATION 3.8.4.2 The thermal overload protection of each valve shown in Table 3.8.4.2-1 shall be OPERABLE or shall be bypassed either continuously or only under accident conditions, as indicated, by an OPERABLE bypass device.
APPLICABILITY: Whenever the motor operated valve is required to be OPERABLE.
ACTION:
With the thermal overload protection for one or more of the above required valves not OPERABLE or not bypassed either continuously or only under accident conditions, as indicated in Table 3.8.4.2-1, take admii.istrative action to bypass the thermal overload within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or declare the affected valve (s) inoperable and apply the appropriate ACTION statement (s) for the affected system (s).
SURVEILLANCE REQUIREMENTS 4.8.4.2.1 The thermal overload protection which is' bypassed either continuously or only under accident conditions for the above required valves shall be veri-fied to be bypassed continuously or only under accident conditions, as applicable, by an OPERABLE bypass device (1) by the performance of a CHANNEL FUNCTIONAL TEST of the bypass circuitry for those thermal overloads which are normally in force during plant operation and bypassed under accident conditions and (2) by verifying that the thermal overload protection is bypassed for those thermal overloads which are continuously bypassed and temporarily placed in force only when the valve motors are undergoing periodic or maintenance testing:
a.
At least once per 92. days for those thermal overloads which are normally in force during plant operation and bypassed under accident conditions.
b.
At least once per 18 months for those thermal overloads which are con-tinuously bypassed and temporarily placed in force only when the valve motors are undergoing periodic or maintenance testing.
c.
Following maintenance on the motor starter.
4.8.4.2.2 The thermal overload protection which is not bypassed for the above required valves shall be demonstrated OPERABLE at least once per 18 months by the performance of a CHANNEL CALIBRATION of a representative sample of at least 25% of all thermal overloads for the above required valves.
4.8.4.2.3 The thermal overload protection for the above required valves which is continuously bypassed and temporarily placed in force only when the valve
~
motor is undergoing periodic or maintenance testing shall be verified to be bypassed following periodic or maintenance testing during which the thermal overload protection was temporarily placed in force.
GRAND GULF-UNIT 1 3/4 8-38 Amendment No. 4, 9 j
ww-w-
=
7 wrw w-w--9w
--w-"w w
w
-www
--w---w-wwwwrw e-w+
=
w--niw-s-
,T w
"'"'-9'
"-' w
t TABLE 3.8.4.2-1 MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)
VALVE NUMBER CONDITIONS) (NO)
AFFECTED Q1E51F010-A Continuous RCIC System Q1E51F013-A Continuous RCIC System 01E51F019-A Continuous RCIC System Q1E51F022-A Continuous RCIC System Q1E51F031-A Continuous RCIC System Q1E51F045-A Continuous RCIC System Q1E51F046-A Continuous RCIC System Q1E51F059-A Continuous RCIC System Q1E51F068-A Continuous RCIC System Valve on Turbine Q1E51C002 C.ontinuous RCIC System Q1821F065A-A No Reactor Coolant System Q1821F065B-A No Reactor Coolant System Q1821F098A-B No Reactor Coolant System Q1821F0988-B No Reactor Coolant System Q1821F098C-B No Reactor Coolant System Q1821F0980-8 No Reactor Coolant System Q1821F019 Continuous Reactor Coolant System Q1821f067A Continuous Reactor Coolant System Q1821F0678 Continuous Reactor Coolant System Q1821F067C Continuous Reactor Coolant System Q1821F0670 Continuous Reactor Coolant System Q1821F016 Continuous Reactor Coolant System Q1821F147A Continuous MSL Drain Post LOCA Leak-age Control Q1821F1478 Continuous MSL Drain Post LOCA Leak-age Control Q1833F019 Continuous Recirculation System Q1833F020 Continuous Recirculation System Q1833F125 Continuous Recirculation System Q1833F126 Continuous Recirculation System Q1833F127 Continuous Recirculation System Q1833F128 Continuous Recirculation System l,
Q1D23F591B Drywell Monitoring System Q1D23F592A Drywell Monitoring System
,^
Q1023F5938 Drywell Moni'toring System r
Q1D23F594A Drywell Monitoring System Q1E12F040 Continuous RHR System ~
Q1E12F023 Continuous RHR System l
Q1E12F006A Continuous RHR System l
Q1E12F052A Continuous RHR System j
Q1E12F008 Continuous RHR System GRAND GULF-UNIT 1 3/4 8-39 Amendment No. 4, 8,.9 l
e TABLE 3.8.4.2-1 (Continued)
MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)
VALVE NUMBER CONDITIONS) (NO)
AFFECTED i
Q1E12F074A Continuous' RHR System Q1E12F026A Continuous RHR System l
Q1E12F082A No RHR System Q1E12F082B No RHR System
'7 Q1E12F290A Continuous RHR System Q1E12F047A Continuous.
RHR System Q1E12F027A Continuous RHR System Q1E12F073A Continuous RHR System Q1E12F346 Continuous RHR System Q1E12F024A Continuous.
RHR System Q1E12F087A Continuous RHR System Q1E12F048A Continuous RHR System Q1E12F042A Continuous RHR System Q1E12F004A Continuous RHR System Q1E12F003A Continuous RHR System Q1E12F011A Continuous RHR System Q1E12F053A Continuous RHR System Q1E12F037A Continuous RHR System Q1E12F028A Continuous RHR System Q1E12F064A Continuous RHR System Q1E12F2908 Continuous RHR System t
Q1E12F004C Continuous RHR System Q1E12F021 Continuous RHR System Q1E12F064C Continuous RHR System Q1E12F042C Continuous RHR System Q1E12F0488 Continuous RHR System Q1E12F049 Continuous RHR Systein Q1E12F0378 Continuous RHR System Q1E12F0538 Continuous RHR System Q1E12F0748 Continuous RHR System Q1E12F042B Continuous RHR System Q1E12F064B-Continuous RHR System Q1E12F096 Continuous RHR System Q1E12F094 Continuous RHR System Q1E12F006B Continuous RHR System
, Q1E12F0118 Continuous RHR System Q1E12F052B Continuous RHR System Q1E12F047B Continuous RHR System i
Q1E12F027B Continuous RHR System Q1E12F0048 Continuous RHR System -
Q1E12F087B Continuous RHR System Q1E12F0038 Continuous RHR System Q1E12F026B Continuous RHR System
,i Q1E12F0248 Continuous RHR System Q1E12F0288 Continuous RHR System Q1E12F009 Con'. 'nuous RHR System Q1E12F073B Continuous RHR System i
i GRAND GULF-UNIT 1 3/4 8-40 Amendment No. 4, 8,~9 l
3 e.-3%m,.,---,--
,----+,,...,.,.,,-w.,
.-m,..-
,m.w
_y-,,
yywy.p_
yy_,_e_,.,,y.
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9
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, - - -y-f 9-p
o TABLE 3.8.4.2-1 (Continued)
MOTOR OPERATED VALVES THERMAL OVERL0A0 PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)
VALVE NUMBER CONDITIONS) (NO)
AFFECTED Q1C11F083 No CR0 Hydraulic System Q1C11F322 Continuous CRD Hydraulic System Q1C41F001A Continuous Standby Liquid Control Q1C41F001B Continuous Standby Liquid Control Q1E21F001 Continuous LPCS System Q1E21F011 Continuous LPCS System Q1E21F012 Continuous LPCS System Q1E21F005 Continuous LPCS System Q1E30F002A Continuous Suppression Pool Makeup System Q1E30F591A Suppression Pool Makeup System Q1E30F592A Suppression Pool Makeup System Q1E30F593A Suppression Pool Makeup System Q1E30F594A Suppression Pool Makeup System Q1E30F001A Continuous Suppression Pool Makeup System Q1E30F0018 Continuous Suppression Pool Makeup System Q1E30F002B Continuous Suppression Pool Makeup System Q1E30F591B Suppression Pool Makeup System Q1E30F5928 Suppression Pool Makeup System Q1E30F5938,
Suppression Pool Makeup System Q1E30F594B Suppression Pool Makeup System Q1E31F100A Continuous Fuel Pool Cooling and Cleanup System Q1E31F1008 Continuous Fuel Pool Cooling and Cleanup System Q1E32F001A Continuous MSIV - LCS Q1E32F001E Continuous MSIV - LCS Q1E32F003A Continuous MSIV - LCS Q1E32F003E Continuous MSIV - LCS Q1E32F003J Continuous MSIV - LCS Q1E32F003N Continuous MSIV - LCS Q1E32F001J Continuous MSIV - LCS Q1E32F001N Continuous MSIV - LCS Q1E32F002A Continuous MSIV - LCS Q1E32F002E Continuous MSIV - LCS Q1E32F002J Continuous MSIV - LCS Q1E32F002N Continious MS.IV - LCS Q1E32F006' Continuous MSIV - LCS i
Q1E32F007 Continuous MSIV - LCS Q1E32F008 Continuous MSIV - LCS Q1E32F009 Continuous MSIV - LCS Q1E38F001A Continuous Feedwater LCS Q1E38F001B Continuous Feedwater LCS GRAND GULF-UNIT 1 3/4 8-41 Amendment No. 4, 8, 9 v
.e-r m
y-y e-r--
TABLE 3.8.4.2-1 (Continued) 4 MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINU0US) (ACCIDENT SYSTEM (S)
VALVE NUMBER CONDITIONS) (NO)
AFFECTED 4
Q1E51F064 Continuous RCIC System Q1E51F063 Continuous RCIC System Q1E51F076 Continuous RCIC System Q1E51F077 Continuous RCIC System Q1E51F078 Continuous RCIC System Q1E22F001 Continmus HPCS System Q1E22F004 Continuous HPCS System Q1E22F010 Continuous HPCS System Q1E22F011 Continuous HPCS System Q1E22F012 Continuous HPCS System Q1E22F015 Continuous HPCS System Q1E22F023 Continuous HPCS System Q1E61F595A Combustible Gas Control System Q1E61F596A Combustible Gas Cortrol System Q1E61F597A Combustible Gas Cont.rol System Q1E61F598A Combustible Gas Control System Q1E61F595C Combustible Gas Control System Q1E61F596C Combustible Gas Control System Q1E61F597C Combustible Gas Control System Q1E61F598C Combustible Gas Control System Q1E61F595B Combustible Gas Control System Q1E61F5968 Combustible Gas Control System Q1E61F597B Combustible Gas Control System Q1E61F5988 Combustible Gas Control System Q1E61F5950 Combustible Gas Control System Q1E61F596D Combustible Gas Control System Q1E61F5970 Combustible Gas Control System Q1E61F5980 Combustible Gas Control System.
Q1E61F003A Continuous Combustible Gas Control System Q1E61F005A Continuous Combustible Gas Control System l.
Q1E61F0038 Continuous Combustible Gas Control System Q1E61F005B Continuous Combustible Gas Control System Q1G33F251 Continuous RWCU System QIG33F253 Continuous RWCU System Q1G33F004 Continuous RWCU System Q1G33F039 Continuous RWCU System Q1G33F034 Continuous RWCU System L',
Q1G33F054 Continuous RWCU System Q1G33F028 Continuous RWCU System l
Q1G33F053 Continuous RWCU System Q1G33F040 Continuous RWCU System Q1G33F001 Continuous RWCU System Q1G33F250 Continuous RWCU System Q1G33F252 Continuous RWCU System l
L I
GRAND GULF-UNIT 1 3/4 8-42 Amendment No. 4, 8, 9
e TABLE 3.8.4.2-1 (Continued)
MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)
VALVE NUMBER CONDITIONS) (NO)
AFFECTED Q1G41F028 Continuous Spent Fuel Pool Cooling and Cleanup System Q1G41F029 Continuous Spent Fuel Pool Cooling and Cleanup System Q1G41F044 Continuous Spent Fuel Pool Cooling and Cleanup System Q1G41F021 No Spent Fuel Pool Cooling and Cleanup System Q1G41F043 No Spent Fuel Pool Cooling and Cleanup System Q1M71F591A Containment /Drywell I&C Q1M71F593A Containment /Drywell I&C Q1M71F5928 Containment /Drywell I&C Q1M71F595 Containment /Drywell I&C Q1M71F5918 Containment /Drywell I&C Q1M71F592A Containment /Drywell I&C Q1M71F594 Containment /Drywell I&C Q1P21F017 Continuous Makeup Water Treatment System Q1P21F018 Continuous Makeup W ter Treatment System Q1P41F237 Continuous SSW System Q1P41F018 Continuous SSW System Q1P41F241 Continuous SSW System Q1P41F238 Continuous SSW System QSP41F081A Continuous SSW System QSP41F064A Continuous SSW System Q1P41F068A Continuous SSW System Q1P41F014A Continuous SSW System Q1P41F159A Continuous SSW System Q1P41F160A Continuous SSW System Q1P41F113 Continuous SSW System Q1P41F168A Cor.tinuous SSW System Q1P41F001A Continuous SSW System Q1P41F016A Continuous SSW System Q1P41F015A Continuous SSW System Q1P41F006A Continu'us SSW System 1
Q1P41F005A Cont...
SSW System j
Q1P41F007A Continuous SSW System QSP41F074A Continuous
'd System
?l QSP41F066A Continuous b..
'am QSP41F125 Continuous SSW Sys.
Q1P41F0188 Continuous SSW System Q1P41F1608 Continuous SSW System Q1P41F1598 Continuous SSW System Q1P41F1688 Continuous SSW System QSP41F154 Accident Conditions SSW System GRAND GULF-UNIT 1 3/4 8-43 Amendment No.
4,.8, 9
TABLE 3.8.4.2-1 (Continued)
MOTOR OPF MTED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)
VALVE NUMBER CONDITIONS) (NO)
AFFECTED QSP41F155A Accident Conditions SSW System Q1P41F068B Continuous SSW System QSP41F155B Accident Conditions SSW System Q1P41F014B Continuous SSW System QSP41F064B Continuous SSW System QSP41F081B Continuous SSW System Q1P41F006B Continuous SSW System Q1P41F007B Continuous SSW System Q1P41F001B Continuous SSW System Q1P41F016B Continuous SSW System Q1P41F0058 Continuous SSW System Q1P41F015B Continuous SSW System QSP41F0668 Continuous SSW System QSP41F074B Continuous SSW System QSP41F189 Continuous SSW System Q1P41F011 Continuous SSW System Q1P41F119A No SSW System Q1P41F119B No SSW System Q1P41F121A No SSW System Q1P41F121B No SSJ System Q1P41F122A No SSW System Q1P41F122B No SSW System QSZ51F007 Continuous Control Room HVAC QSZ51F008 Continuous Control Room HVAC QSZ51F014 Continuous Control Room HVAC QSZ51F016 Continuous Control Room HVAC Q1P42F067 Continuous CCW System Q1P42F116 Continuous CCW System Q1P42F028A Continuous CCW System Q1P42F032A Continuous CCW System Q1P42F201A Continuous CCW System Q1P42F204 Continuous CCW System Q1P42F205 Continuous CCW System Q1P42F105
' Continuous CCW System Q1P42F200A Continuous CCW System Q1P42F203 Continuous CCW System Q1P42F117 Continuous CCW System Q1P42F114 Continuous CCW System Q1P42F068 Continuous CCW System Q1P42F2008 Continuous CCW System Q1P42F028B Continuous CCW System Q1P42F201B Continuous CCW System Q1P42F032B Continuous CCW System Q1P42F066 Continuous CCW System
- Manual bypass of thermal overload protection of manually controlled valve.
GRAND GULF-UNIT 1 3/4 8-44 Amendment No. 4, 8, 9
TA8LE 3.8.4.2-1 (Continued)
MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)
VALVE NUMBER CONDITIONS) (MO)
AFFECTED Q1P44F053 Continuous Plant SW System Q1P44F069 Continuous Plant SW System Q1P44F076 Continuous Plant SW System Q1P44F070 Continuous Plant SW System Q1P44F074 Continuous Plant SW System Q1P44F077 Continuous Plant SW System Q1P44F042 Continuoca Plant SW System Q1P44F054 Continuous Plant SW System Q1P44F067 Continuous Plant SW System Q1P45F096 Continuous Floor & Eqmt. Drain System Q1P45F097 Continuous Floor & Eqmt. Drain System Q1P52F195 Continuous Service Air System Q1P53F003 Continuous Instrument Air System Q1P53F007 Continuous Instrument Air System Q1T48F005 Continuous SGTS Q1T48F006 Continuous SGTS Q1T48F024 Continuous SGTS Q1T48F026 Continuous SGTS Q1T48F023 Continuous SGTS Q1T48F025 Continuous SGTS Q1P45F273 Continuous Floor & Egmt. Drain System Q1P45F274 Continuous Floor & Eqmt. Drain System I
GRAND GULF-UNIT 1 3/4 8-45 Amendment No. 8, 9
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ELECTRICAL POWER SYSTEMS REACTOR PROTECTION SYSTEM ELECTRIC POWER MONITORING i-LIMITING CONDITION FOR OPERATION 3.8.4.3 Two RPS electric power monitoring assemblies for each inservice RPS MG set or alternate power supply shall be OPERABLE.
APPLICABILITY: At all times.
ACTION:
a.
With one RPS electric power monitoring assembly for an inservice RPS MG set or alternate power cupply inoperable, restore the inoperable power monitoring system to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the l
associated RPS MG set or alternate power supply from service.
b.
With both RPS electric power monitoring assemblies for an inservice RPS MG set or alternate power supply inoperable, restore at least one electric power monitoring assembly to OPERABLE status within 30 minutes or remove the associated RPS MG set or alternate power supply from service.
SURVEILLANCE REQUIREMENTS 4.8.4.3 The above specified RPS electric power monitoring assemblies shall be determined OPERABLE:
a.
At least once per six months by performance of a CHANNEL FUNCTIONAL TEST, and b.
At least once per 18 months by demonstrating the OPERABILITY of over-voltage, under-voltage and under-frequency protective instrumentation by performance of a CHANNEL CALIBRATION including simulated automatic actuation of the protective relays, tripping logic and output circuit breakers and verifying the following setpoints:
1.
Over-voltage < 132 VAC, 2.
Under-voltage 1 117 VAC, and 3.
Under-frequency 1 57 Hz.
GRAND GULF-UNIT 1 3/4 8-46 Amendment No. 4, 9
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CONTAINMENT SYSTEMS BASES DEPRESSURIZATION SYSTEMS (Continued) excessive containment pressures and temperatures. The suppression pool cooling mode is designed to limit the long term bulk temperature of the pool to 185*F considering all of the post-LOCA energy additions. The suppression pool cooling trains, being an integral part of the RHR system, are redundant, safety-related component systems that are initiated following the recovery of the reactor vessel water level by ECCS flows from the RHR system.
Heat rejection to the standby service water is accomplished in the RHR heat exchangers.
The suppression pool make-up system provides water from the upper contain-ment pool to the suppression pool by gravity flow through two 100% capacity dump lines following a LOCA.
The quantity of water provided is sufficient to account for all conceivable post-accident entrapment volumes, ensuring the long term energy sink capabilities of the suppression pool and maintaining the water coverage over the uppermost drywell vents.
The minimum freeboard distance above the suppression pool hign water level to the top of the weir wall is adequate to preclude flooding of the drywell in the event of an inadvertent dump. During refueling, neither automatic nor manual action can open the make-up dump valves.
3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES The OPERABILITY of the containment isolation valves ensures that the con-tainment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the containment atmosphere or pres-surization of the containment and is consistent with the requirements of GDC 54 through 57 of Appendix A to 10 CFR Part 50.
Containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA.
The operability of the drywell isolation valves ensures that the drywell atmosphere will be directed to the suppression pool for the full spectrum of pipe breaks inside the drywell.
Since the allowable value of drywell leakage is so large, individual drywell penetration leakage is not measured. By checking valve operability on any penetration which could contribute a large fraction of the design leakage, the total leakage is maintained at less than the design value.
The maximum isolation times for containment and drywell automatic isolation valves are the times used in the FSAR accident analysis for valves with analy-tical closing times.
For automatic isolation valves not having analytical closing times, closing times are derived by applying margins to previous valve closing test data obtained by using ASME Section XI criteria. Maximum closing times for these valves was determined by using a factor of two times the allow-able (from previous test closure to next test closure) ASME Section XI margin and adding this to the previous test closure time.
3/4.6.5 DRYWELL POST-LOCA VACUUM BREAKERS The post-LOCA drywell vacuum breaker system is provided to relieve the vacuum in the drywell due to steam condensation following blow-down.
Contain-ment air is drawn through the vacuum breaker check valves in the two branches of the separate post-LOCA vacuum relief line and in a branch of each drywell purge compressor discharge line.
Vacuum relief initiates at a differential pressure of one psi.
This vacuum relief, in conjunction with the rest of the GRAND GULF-UNIT 1 B 3/4 6-5 Amendment No. 9
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4 CONTAINMENT SYSTEMS BASES
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DRYWELL POST-LOCA VACUUM BREAKERS (Continued) drywell purge system, is necessary to insure that the post-LOCA drywell H2 concentration does not exceed 4% by volume.
Following vacuum relief, the drywell purge system pressurizes the drywell, forcing noncondensibles through the horizontal vents and into the containment at a rate designed to maintain the H2 concentration below the flammable limits.
There are two 100% vacuum relief systems so that the plant may continue operation with one system out of service for a limited period of time.
3/4.6.6 SECONDARY CONTAINMENT Secondary containment is designed to minimize any ground level release of radioactive material which may result from an accident. The Auxiliary Building and Enclosure Building provide secondary containment during normal operation when the containment is sealed and in service. When the reactor is in COLD SHUTDOWN or REFUELING, the containment may be open and the Auxiliary Building and Enclosure Building then become the only containment.
The maximum isolation times for secondary containment automatic isolation
~
dampers / valves are the times used in the FSAR accident analysis for dampers /
valves with analytical closing times.
For automatic isolation valves not having analytical closing times, closing times are derived by applying margins to previous valve closing test data obtained by using ASME Section XI criteria.
Maximum closing times for these valves was determined by using a factor of two times the allowable (from previous test closure to next test closure) ASME Section XI margin and adding this to the previous test closure time.
Establishing and maintaining a vacuum in the Auxiliary Building and r
Enclosure Building with the standby gas treatment system once per 18 months, along with the surveillance of the doors, latches, dampers and valves, is ade-quate to ensure that there are no violations of the integrity of the secondary containment.
l-The OPERABILITY of the standby gas treatment systems ensures that sufficient iodine removal capability will be available in the event of a LOCA.
l The reduction in containment iodine inventory reduces the resulting site boundary radiation doses associated with containment leakage.
The operation of this system and resultant iodine removal capacity are consistent with the assumptions used in the LOCA analyses.
Cumulative operation of the system with the heaters OPERABLE for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> over a 31 day period is sufficient to reduce the buildup of moisture on the absorbers and HEPA filters.
The surveillance testing for verifying heat dissipation for the Standby Gas Treatment System heaters is performed in accordance with ANSI N510-1975 with the exception of the 5% current phase balance criteria of Section 14.2.3.
The offsite power system for the Grand Gulf Nuclear Station consists of a non-transpositional 500 KV grid.
The grid has an inherent unbalanced load distri-bution which results in unbalanced voltages in the plant. Voltage unbalances exceeding the ANSI N510-1975 5% criteria are not atypical.
1 1
GRAND GULF-UNIT 1 B 3/.4 6-6 Amendment No. 9 u.
s CONTAINMENT SYSTEMS BASES 3/4.6.7 ATMOSPHERE CONTROL The OPERABILITY of the systems required for the detection and control of hydrogen gas ensures that these systems will be available to maintain the hydrogen concentration within the containment below its flammable limit during post-LOCA conditions. The hydrogen recombiner and the hydrogen ignition systems are capable of controlling the expected hydrogen generation associated with (1) zirconium-water reactions, (2) radiolytic decomposition of water and (3) corrosion of metals within containment.
Two 100% drywell purge systems are the primary means of H2 control within the drywell purging hydrogen produced following a LOCA into the containment volume.
Hydrogen generated from the metal-water reaction and radiolysis is assumed to evolve to the drywell atmosphere and form a homogenous mixture through natural forces and mechanical turbulence (ECCS pipe break flow).
The drywell purge system forces drywell atmosphere through the horizontal vents and into the containment and as a result no bypass path exists.
The hydrogen control system is consistent with the recommendations of Regulatory Guide 1.7, " Control of Combustible Gas Concentrations in Containment Following a LOCA", March 1971.
The operability of at=least 41 of 45 ignitors in either hydrogen ignition subsystem will maintain an' effective coverage throughout the containment and drywell.
Each subsystem of ignitors will initiate combustion of any significant amount of hydrogen released after a degraded core accident.
This system will ensure burning in a controlled manner as the hydrogen is released instead of allowing it to be ignited at nigh concentrations by a random ignition source.
GRAND GULF-UNIT 1 B 3/4 6-7 Amendment No. 9
3/4.7 PLANT SYSTEMS BASES 3/4.7.1 SERVICE WATER SYSTEMS The OPERABILITY of the service water systems ensures that sufficient cooling capacity is available for continued operation of safety-related equipment during normal and accident conditions. The redundant cooling capacity of these systems, assuming a single failure, is consistent with the assumptions used in the accident conditions within acceptable limits.
3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM The OPERABILITY of the control room emergency filtration system ensures that the control room will remain habitable for operations personnel during and following all design basis accident conditions. Cumulative operation of the system for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> with the heaters OPERABLE over a 31 day period is sufficient to reduce the buildup of n;oisture on the adsorbers and HEPA filters.
The OPERABILITY of this system in conjunction with control room design provisions is based on limiting the radiation exposure to personnel occupying the control room to 5 rem or less whole body, or its equivalent. This limitation is con-sistent with the requirements of General Design Criteria 19 of Appendix "A",
The surveillance testing for verifying heat dissipation for the Control Room Emergency Filtration System heaters is performed in accordance with ANSI N510-1975 with the exception of the 5% current phase balance criteria of Sec-tion 14.2.3.
The offsite power system for the Grand Gulf Nuclear Station consists of a non-transpositional 500 KV grid. The grid has an inherent unbalanced load distribution which results in unbalanced voltage: in th: 91 ant.
Voltage unbalances exceeding the ANSI N510-1975 5% criteria are not atypical.
3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM The reactor core isolation cooling (RCIC) system is provided to assure adequate core cooling in the event of reactor isolation from its primary heat sink and the loss of feedwater flow to the reactor vessel without requiring actuation of any of the Emergency Core Cooling System equipment. The RCIC system is conservatively required to be OPERABLE whenever reactor pressure exceeds 135 psig even though the LPCI mode of the residual heat removal (RHR) system provides adequate core cooling up to 225 psig.
The RCIC system specifications are applicable during OPERATIONAL CONDITIONS 1, 2 and 3 when reactor vesse' 3ressure exceeds 135 psig because RCIC is the primary non-ECCS source of eme icy core cooling when the reactor is pressurized.
With the RCIC system inoperable, adequate core cooling is assured by the OPERABILITY of the HPCS system and justifies the specified 14 day out-of-service period.
The surveillance requirements provide adequate assurance that RCICS will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation during reactor operation, a complete functional test requires reactor shutdown. The pump discharge piping is maintained full to prevent water hammer damage and to start cooling at the earliest possible moment.
GRAND GULF-UNIT 1 B 3/4 7-1 Amendment No. 7, 9
ADMINISTRATIVE CONTROLS 6.5.2 SAFETY REVIEW COMMITTEE (SRC)
FUNCTION 6.5.2.1 The SRC shall function to provide independent review and audit of designated activities in the areas of:
a.
nuclear power plant operations b.
nuclear engineering c.
chemistry and radiochemistry d.
metallurgy e.
instrumentation and control f.
radiological safety g.
mechanical and electrical engineering h.
quality assurance practices COMPOSITION 6.5.2.2 The SRC shall be composed of the:
Chairman:
Vice President-Nuclear Member:
Manager of Nuclear Plant Engineering Member:
Manager of Quality Assurance Member:
Designated Representative, Middle South Services, Inc.
Member:
Nuclear Plant Manager Member:
Manager of Nuclear Services Member:
Manager of Radiological and Environmental Services l
Member:
Principal Engineer, Operations Analysis Member:
- Advisor to the Vice President-Nuclear l
Two or more additional voting members shall be consultants to Mississippi
- l Power and Light Company consistent with the recommendations of the Advisory Committee on Reactor Safeguards letter, Mark to Palladino dated October 20, 1981.
The SRC members shall hold a Bachelor's degree in an engineering or physical science field or equivalent experience and a minimum of five years of technical experience of which a minimum of three years shall be in one or more of the disciplines of 6.5.2.la through h.
In the aggregate, the membership of the l
committee shall provide specific practical experience in the majority of the disciplines of 6.5.2.la through h.
ALTERNATES 6.5.2.3 Al'1
' ternate members shall be appointed in writing by the SRC Chairman to s.ve on a temporary basis; however, no more than two alternates shall particit e as voting members in SRC activities at any one time.
"Non voting member.
l l
l GRAND GULF-UNIT 1 6-9 Amendment No. 9 1
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l ADMINISTRATIVE CONTROLS STARTUP REPORTS (Continued) 6.9.1.2 The startup report shall address each of the tests identified in the FSAR and shall include a description of the measured values of the operating conditions or characteristics obtained during the test program and a comparison of these values with design predictions and specifications.
Any corrective actions that were required to obtain satisfactory operation shall also be described.
Any additional specific details required in license conditions based on other commitments shall be included in this report.
6.9.1.3 Startup reports shall be submitted within (1) 90 days following completion of the startup test program, (2) 90 days following resumption or commencement of commercial power operation, or (3) 9 months following initial criticality, whichever is earliest.
If the Startup Report does not cover all three events, i.e., initial criticality, completion of Startup test program, and resumption or commencement of commercial operation, supplementary reports shall be submitted at least every three months until all three events have been completed.
ANNUAL REPORTSM 6.9.1.4 Annual reports covering the activities of the unit as described below for the previous calendar year shall be submitted prior to March 1 of each year.
The initial report shall be submitted. prior to March 1 of the year following initial criticality.
- 6. 9.1. 5 Reports required on an annual basis shall include a tabulation on an annual basis of the number of station, utility, and other personnel, including contractors, receiving exposures greater than 100 mr manrem exposure according to work and job functions,g/yr and their associated e.g., reactor operations and surveillance, inservice inspection, routine maintenance, special maintenance (describe maintenance), waste processing, and refueling. The dose assignments to various duty functions may be estimated based on pocket dosimeter, TLD, or film badge measurements.
Small exposures totalling less than 20 percent of the individJal total dose need not be accounted for.
In the aggregate, at least 80 percent of the total whole body dose received from external sources should be assigned to specific major work functions.
Reports shall also include documentation of all challenges to safety and relief valves.
1/A single submittal may be made for a multiple unit station.
The submittal should combine those sections that are common to all units at the station.
MThis tabulation supplements the requirements of $20.407 of 10 CFR Part 20.
GRAND GULF-UNIT 1 6-16 Amendment No. 9
.a W
AF ADMINISTRATIVE CONTROLS PROMPT NOTIFICATION WITH WRITTEN FOLLOWUP (Continued) i d.
Reactivity anomalies involving disagreement with the predicted value of reactivity balance under steady state conditions during power opera-tion greater than or equal to 1% delta k/k; a calculated reactivity balance indicating a SHUTDOWN MARGIN less conservative than specified in the technical specifications; short-term reactivity increases that correspond to a reactor period of less than 5 seconds or, if subcritical, an unplanned reactivity insertion of more than 0.5% delta k/k; or occurrence of any unplanned criticality.
e.
Failure or malfunction of one or more components which prevents or could prevent, by itself, the fulfillment of the functional require-ments of system (s) used to cope with accidents analyzed in the SAR.
f.
Personnel error or procedural inadequacy which prevents or could prevent, i
by itself, the fulfillment of the functional requirements of systems required to cope with accidents analyzed in the SAR.
g.
Conditions arising from natural or man-made events that, as a direct result of the event, require unit shutdown, operation of safety systems, or other protective measures required by technical specifications.
h.
Errors discovered in the transient or accident analyses or in the methods used for such analyses as described in the safety analysis report or in the bases for the technical specifications that have or could have permitted reactor operation in a manner less conservative than assumed in the analyses.
i.
Performance of structures, systems, or components that requires remedial action or corrective measures to prevent operation in a
{
l manner less conservative than assumed in the accident analyses in f
the safety analysis report or technical specifications bases; or dis'covery during unit life of conditions not specifically considered in the safety analysis report or technical specifications that require remedial action or corrective measures to prevent the existence or development of an unsafe condition.
j.
Offsite releases cf radioactive materials in liquid and gaseous effluents which exceed the limits of Specification 3.11.1.1 or 3.11.2.1.
k.
Exceeding the limits in Specification 3.11.1.4 for the storage of radioactive materials in the listed tanks, The written follow-up report shall include a schedule and a description of activities planned and/or taken to reduce the contents to within the specified limits.
i 1.
Failure or malfunction of the safety or relief valves.
GRAND GULF-UNIT 1 6-20 Amendment No. 7, 9 s.
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g, SEP 15 1983 GRAND GULF AMENDMENT NO. 9 DISTRIBUTION:
- Document Control :(50-416) ~ "-
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PRC l
LB#2 Rdg.
E. Hyl to n M. D. Houston A. Schwencer M. Wagner, OELD H. R. Denton D. G. Eisenhut/R. A. Purple E. L. Jordan, DEQA:IE J. M. Taylor, DRP:IE L. J. Harmon, IE File J. Souder W. Miller, LFMB I. Dinitz W. Jones, OA T. Barnhart (4)
B. P. Cotter, ASLBP A. Rosenthal, ASLAP ACRS (16)
F. Pagano, IE D. Brinkman, SSPB c
Region II, RA l
l l
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