ML20097J669
| ML20097J669 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 01/25/1996 |
| From: | POWER AUTHORITY OF THE STATE OF NEW YORK (NEW YORK |
| To: | |
| Shared Package | |
| ML19311B958 | List: |
| References | |
| NUDOCS 9602050095 | |
| Download: ML20097J669 (137) | |
Text
.-
e ATTACHMENT I to JPN-96-003 Proposed Changes to the Technical Specifications Regarding Extension of Instrumentation and Miscellaneous Surveillance Test Intervals to Accommodate 24-Month Ooeratina Cveles (JPTS-95-001G)
New York Power Authority JAMES A. FITZPATRICK NUCLEAR POWER PLANT Docket No. 50-333 DPR-59 9602050095 960125 DR ADOCK 0500 3
u
L JAFNPP
~
1.0 (cont'd) opened to perform necessary operational activities.
deficiency subject to regulatory review.
2.
At least one door in each airlock is closed and S.
Secondary Containment Intearity - Secondary containment sealed.
integrity means that the reactor building is intact and the following conditions are met:
3.
All automatic containment isolation valves are operable or de-activated in the isolated position.
1.
At least one door in each access opening is closed.
4.
All blind flanges and manways are closed.
2.
The Standby Gas Treatment System is operable.
N.
Rated Power - Rated power refers to operation at a reactor 3.
All automatic ventilation system isolation valves are power of 2,436 MWt. This is also termed 100 percent operable or secured in the isolated position.
i power and is the maximum power level authorized by the operating license. Rated steam flow, rated coolant flow, T.-
Surveillance Freauency Notations / Intervals rated nuclear system pressure, refer to the values of these parameters when the reactor is at rated power.
The surveillance frequency notations / intervals used in these specifications are defined as follows:
O.
Reactor Power Operation - Reactor power operation is any operation with the Mode Switch in the Startup/ Hot Notations Intervals Freauency Standby or Run position with the reactor critical and above 1 percent rated thermal power.
D Daily At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> W
Weekly At least once per 7 days P.
Reactor Vessel Pressure - Unless otherwise indicated, M
Monthly At least once per 31 days reactor vessel pressures listed in the Technical O
Quarterly or At least once per 92 days Specifications are those measured by the reactor vessel every 3 months steam space sensor.
SA Semiannually or At least once per 184 days every 6 months Q.
Refuelino Outaae - Refueling outage is the period of time A
Annually or Yearly At least once per 366 days
' between the shutdown of the unit prior to refueling and 18M 18 Months At least once per 18 months (550 the startup of the Plant subsequent to that refueling.
days)
R Operating Cycle At least once per 24 months (731 R.
Safety Limits - The safety limits are limits within which days) the reasonable maintenance of the fu,1 cladding integrity S/U Prior to each reactor startup and the reactor coolant system integrity are assured.
NA Not applicable Violation of such a limit is cause for unit shutdown and review by the Nuclear Regulatory Commission before resumption of unit operation. Operation beyond such a limit may not in itself result in serious consequences but it indicates an operational Amendment No.
- i, 131,188,227, 5
JAFNPP 3.1 LIMITING CONDITIONS FOR OPERATION 4.1 SURVEILLANCE REQUIREMENTS 3.1 REACTOR PROTECTION SYSTEM 4.1 REACTOR PROTECTION SYSTEM Anolicability:
Anolicability:
Applies to the instrumentation and associated devices which Applies to the surveillance _of the instrumentation and associated initiate the reactor scram.
devices which initiate reactor scram.
Obiective:
Obiective:
To assure the operability of the Reactor Protection System.
To specify the type of frequency of surveillance to be applied to the protection instrumentation.
Soecification:
Specification:
A. The setpoints and minimum number of instrument A.
Instrumentation systems shall be functionally tested and channels per trip system that must be operable for each calibrated as indicated in Tables 4.1-1 and 4.1-2 respectively.
position of the reactor mode switch, shall be as shown in Table 3.1-1.
The response time of the reactor protection system trip functions listed below shall be demonstrated to be within its limit once per 24 months. Neutron detectors are exempt l
- from response time testing. Each test shallinclude at least one channel in each trip system. All channels in both trip systems shall be tested within two test intervals.
- 1. Reactor High Pressure (02-3PT-55A, B, C, D)
- 2. Drywell High Pressure (05PT-12A, B, C, D)
- 3. Reactor Water Level-Low (L3) (02-3LT-101 A, B, C, D)
- 4. Main Steam Line Isolation Valve Closure (29PNS-80A2, B2, C2, D2)
(29PNS-86A2, B2, C2, D2)
- 5. Turbine Stop Valve Closure (94PNS-101,102,103,104)
- 6. Turbine Control Valve Fast Closure (94PS-200A, B, C, D)
- 7. APRM Fixed High Neutron Flux
- 8. APRM Flow Referenced Neutron Flux Amendment No. GN, 3Og
JAFNPP t
4.1 BASES (cont'd) l t
For the APRM System, drift of electronic apparatus is not The measurement of response time provides assurance j
the only consideration in determining a calibration that the Reactor Protection System trip functions are frequency. Change in power distribution and loss of completed within the time limits assumed in the transient chamber sensitivity dictates a calibration every 7 days.
and accident analyses.
l Calibration on this frequency assures plant operation at or below thermal limits.
In terms of the transient analysis, the Standard Technical Specifications (NUREG-0123, Rev.3) define individual trip The frequency of calibration of the APRM flow biasing function response time as "the time interval from when the
[
network has been established as once per 24 months. The monitored parameter exceeds its trip setpoint at the flow biasing network is functionally tested at least once channel sensor until de-energization of the scram pilot l
every three months and, in addition, cross calibration valve solenoids." The individual sensor response time checks of the flow input to the flow biasing network can defined as " operating time" in General Electric (GE) design be made during the functional test by direct meter reading.
specification data sheet 22A3083AJ, note (8), is "the There are several instruments which must be calibrated and maximum allowable time from when the variable being it will take several days to perform the calibration of the measured just exceeds the trip setpoint to opening of the entire network. While the calibration is being performed, a trip channel sensor contact during a transient." A transient zem flow signal will be sent to half of the APRM's resulting is defined in note (4) of the same data sheet as "the i
j in a half scram and rod block condition. Thus,if the maximum expected rate of change of the variable for the calibration were performed during operation, flux shaping accident or the abnormal operating condition which is would not be possible. Based on plant specific evaluation postulated in the safety analysis report.
i of drift over a 24 month operating cycle, it was determined that drift of instrumentation used in the flow biasing network is not significant. Therefore, to avoid spurious scrams, a calibration frequency of once per 24 months is established.
Amendment No. 427 37
t JAFNPP i
4.1 BASES (cont'd)
The individual sensor response time may be measured by B. The MFLPD is checked once per day to determine if the f
4 simulating a step change of the particular parameter. This APRM scram requires adjustment. Only a small number of 1
method provides a conservative value for the sensor control rods are moved daily and thus the MFLPD is not i
response time, and confirms that the instrument has retained expected to change significantly and thus a daily check of its specified electromechanical characteristics. When sensor the MFLPD is adequate.
l response time is measured independently, it is necessary to also measure the remaining portion of the response time in The sensitivity cf L*RM detectors decreases with exposure L
the logic train up to the time at which the scram pilot valve to neutron flux at a slow and approximately constant rate.
solenoids de-energize. The channel response time must This is compensated for in the APRM system by calibrating include all component delays in the response chain to the twice a week using heat balance data and by calibrating ATTS output relay plus the design allowance for RPS logic individual LPRM's every 1000 effective full power hours, system response time. A response time for the RPS logic using TIP traverse data.
relays in excess of the design allowance is acceptable provided the overall response time does not exceed the response time limits specified in the UFSAR. The basis for l
excluding the neutron detectors from response time testing l
is provided by NRC Regulatory Guide 1.118 Revision 2, f
section C.S.
Two instrument channels in Table 4.1-1 have not been included in Table 4.1-2. These are: mode switch in shutdown and manual scram. All of the devices or sensors associated with these scram functions are simple on-off switches and, hence, calibration during operation is not applicable.
4 l
I Amendment No. i', 80,134,183,227, 38
JAFNPP TABLE 4.1-2 REACTOR PROTECTION SYSTEM (SCRAM) INSTRUMENT CALIBRATION MINIMUM CALIBRATION FREQUENCIES FOR REACTOR PROTECTION INSTRUMENT CHANNELS Instrument Channel Groun (1)
Calibration Freauency (2)
IRM High Flux C
Comparison to APRM on W
Controlled Shutdowns APRM High Flux Output Signal B
Heat Balance D
Flow Bias Signal B
Internal Power and Flow Test R
with Standard Pressure Source LPRM Signal B
TIP System Traverse Every 1000 effective full power hours High Reactor Pressure B
Standard Pressure Source (Note 6)
High Drywell Pressure B
Standard Pressure Source (Note 6)
Reactor Low Water Level B
Standard Pressure Source (Note 6)
L High Water Level in Scram A
Water Column (Note 5)
R (Note 5)
Discharge Instrument Volume High Water Level in Scram B
Standard Pressure Source Q
l Discharge Instrument Volume Main Steam Line Isolation A
(Note 4)
(Note 4)
Valve Closure Turbine First Stage Pressure B
Standard Pressure Source (Note 6)
Permissive Amendment No. 12,12, S2, 75, SS,136,183, 207, 46
l
\\
i JAFNPP TABLE 4.1-2 (Cont'd)
REACTOR PROTECTION SYSTEM (SCRAM) INSTRUMENT CAllBRATION MINIMUM CAUBRATION FREQUENCIES FOR REACTOR PROTECTION INSTRUMENT CHANNELS
[
Instrument Channel Groun (1)
Calibration Freauency (2)
Turbine Control Valve Fast A
Standard Pressure Source R
Closure Oil Pressure Trip l
Turbine Stop Valve Closure A
(Note 4)
(Note 4) i i
NOTES FOR TABLE 4.1-2 1.
A description of three groups is included in the Bases of this Specification.
2.
Calibration test is not required on the part of the system that is not requered to be operable, or is tripped, but is required prior to return to service.
3.
Deleted l:
4.
Actuation of these switches by normal means will be performed once per 24 months.
5.
Calibration shall be performed utilizing a water column or similar device to provide assurance that damage to a float or other portions of the float assembly will be detected.
6.
Sensor calibration once per 24 months. Master / slave trip unit calibration once per 6 months.
i l
l t
i i
Amendment No. 13, S2, Se,136,183, 207, i
47 i
l-.
i JAFNPP L
3.2 LIMITING CONDITIONS FOR OPERATION 4.2 SURVEILLANCE REQUIREMENTS 3.2 INSTRUMENTATION 4.2 INSTRUMENTATION
{
Acolicability:
Acolicability:
Applies to the plant instrumentation which either (1) initiates and Applies to the surveillance requirement of the instrumentation controls a protective function, or (2) provides information to aid -
which either (1) initiates and controls protective function, or (2) the operator in monitoring and assessing plant status during provides information to aid the operator in monitoring and l
normal and accident conditions.
assessing plant status dunng normal and accident conditions.
r Obiective:
Objective:
To assure the operability of the aforementioned instrumentation.
To specify the type and frequency of surveillance to be applied to I
the aforementioned instrumentation.
Soecifications:
Soecifications:
A. Primary Ccnitaininent isolation Functions A. Pnmary Containment isolation Functions When primary containment integrity is required, the limiting instrumentation shall be functionally tested and calibrated as conditions of operation for the instrumentation that initiates indicated in Table 4.2-1. System logic shall be functionally primary containment isolation are given in Table 3.2-1.
tested as indicated in Table 4.2-1.
The response time of the main steam isolation valve actuation i
instrumentation isolation trip functions listed below shall be demonstrated to be within their limits once per 24 months.
Each test shall include at least one channel in each trip system. All channels in both trip systems shall be tested within two test intervals.
l
- 1. MSIV Closure - Reactor Low Water Level (L1)
(02-3LT-57A,B and 02-3LT-58A,B)
- 2. MSIV Closure - Low Steam Line Pressure i
(02PT-134A,B,C.D)
Amendment No. 130,1"3,227, 49
I JAFNPP 3.2 BASES (cont'd)
I The remote / alternate shutdown capability at FitzPatrick is Not all instruments, controls, and necessary transfer switches provided by a remote shutdown panel (25RSP) and five are located at the remote / alternate shutdown panels. Some alternate safe shutdown panels (25 ASP-1, 25 ASP-2, 25 ASP-controls and transfer switches will have to be operated locally 3,25 ASP-4, and 25 ASP-5). These panels are used in at the switchgear, motor control centers, or other local conjunction with the Automatic Depressurization System stations.
(ADS) relief valve control panel (02 ADS-71) adjacent to 25RSP, the emergency diesel generator (B & D) control panels Operability of the remote shutdown instrumentation and l
(93EGP-B and 93EGP-D) opposite 25 ASP-3, the reactor control functions ensure that there is sufficient information building vent and cooling panel (66HV-3B) near 25 ASP-1, available on selected plant parameters to piece and maintain i
instrument rack 25-51, and instrument rack 25-6 opposite the plant in a shutdown condition should the control room j
25RSP. All of these locations are linked by communications become inaccessible. The instrumentation and controls and are provided with emergency lighting.
installed on the remote /altemate shutdown panels are listed in i
Table 3.2-10. This table only includes those isolation / transfer I
This Remote Shutdown capability provides the necessary switches that do not have an associated control switch.
instrumentation and controls to place and maintain the plant in Operability of isolation / transfer switches that have an a safe shutdown condition from a location other than the associated control switch will be demonstrated when the i
control room in the event the control room becomes control functions are tested as required by Surveillance i
inaccessible due to a fire or other reason.
Requirement 4.2.J.
This specification ensures the operability of the remote The remote shutdown instruments and control circuits covered i
shutdown instrumentation and control circuits. Operability of by this LCO do not need to be energized to be consedered components such as pumps and valves, which are controlled operable. This LCO is intended to ensure that the instruments from these panels, is covered by other specifications. This' and control circuits will be operable if plant conditions require specification does not impose conditions on plant operation the use of the remote shutdown capability. Performance of which are more restrictive than those already imposed by the instrument check once every 31 days ensures that a gross I
other specifications. For example, Specification 3.7.D includes failure of instrumentation has not occurred and is intended to provisions for continued operation with one or more ensure that the instrumentation continues to operate properly containment isolation valves inoperable. The 30 day time between each instrument channel calibration.
limitation imposed by 3.2.J would not apply in this situation, provided that the actions taken for the inoperable valve (s) to As specified in the surveillance requirements, an instrument satisfy 3.7.D are also consistent with the safety function (s) check is only required for those instruments that are normally l
required for fire protection.
energized. Performance of this surveillance provides assurance that undetected outright instrument failure is limited I
to 31 days. The surveillance frequency is based upon plant operating experience which indicates that channel failure is i
rare.
Amendment No. 106,120,130,1SO,181,21S, 60 l
JAFNPP 3.2 BASES (cont'd)
Surveillance Requirement 4.2.J requires that each remote shutdown transfer / isolation switch and control circuit be periodically tested to demonstrate that it is capable of performing its intended function. The requirements of this section apply to each remote shutdown control circuit on the panels listed in Table 3.2-10. This demonstration is performed from the remote shutdown panel and locally, as appropriate. This will ensure that if the control room becomes inaccessible, the plant can be placed and maintained in a shutdown condition from the remote shutdown panel and the local control stations.
Three channels of the Reactor Vessel Water Level-High instrumentation are provided as input to a two-out-of-three initiation logic thet trips the two feedwater pump turbines 4
and the main turbine. An event involving excessive feedwater flow results in a rising reactor vessel water level, which upon reaching the reactor vessel water level trip setpoint, results in a trip of both feedwater pump turbines, and the main turbine. The feedwater pump turbine trip under these conditions limits further increase in the reactor vessel water level due to feedwater flow. A trip of the main turbine protects the turbine from damage due to excessive water carryover.
i Amendment No. 21S, 225, 60s i
JAFNPP TABLE 3.2-2 (cont'd)
CORE AND CONTAINMENT COOLING SYSTEM INITIATION AND CONTROL INSTRUMENTATION OPERABILITY REQUIREMENTS Minimum No. of Operable instrument Total Number of Channels Per Instrument Channels item Trip System Provided by Design No.
(Notes 1 and 2)
Trio Function Trio Level Settina for Both Trio Systems Remarks 26 (1 per 4kV bu,! 4kV Emergency Bus 110.6 i O.8 2
Initiates both 4kV (Note 9)
Undervoltage Relay secondary volts Emergency Bus Undervoltage (Degraded Voltage)
Timers. (Degraded Voltage LOCA and non-LOCA)
(Notes 4 and 6) 27 (1 per 4kV bus) 4kV Emergency Bus 8.96 i O.55 sec.
2 (Note 5)
(Note 9)
Undervoltage Timer (Degraded Voltage LOCA) 28 (1 per 4kV bus) 4kV Emergency Bus 43.8 1 2.8 sec.
2 (Note 5)
(Note 9)
Undervoltage Timer (Degraded Voltage non-LOCA) 29 (1 per 4kV bus) 4kV Emergency Bus 85 i 4.81 2
Initiates 4kV Emergency Bus (Note 9)
Undervoltage Relay secondary volts Undervoltage Loss of (Loss of Voltage)
Voltage Timer.
(Notes 4 and 7) 30 (1 per 4kV bus) 4kV Emergency Bus 2.50 i 0.11 sec.
2 (Note 5)
(Note 9)
Undervoltage Timer (Loss of Voltage) 31 2
Reactor Low Pressure 285 to 335 psig 4
Permits closure of recirculation pump discharge valve.
Amendment No. 3, SS, ?24, 70
JAFNPP TABLE 3.2-10 I
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS
[ Refer to Notes on Page 770]
i INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAllBRATION TEST
?
1.
RHR Service Water Flow (Loop B) 25RSP M
R NA (10F1-134) 2.
RHR Service Water Pump Control 25RSP NA NA R
(10P-1 B) 3.
RHR Service Water Heat Exchanger Outlet 25RSP NA NA R
Valve Control (10MOV-89B) 7 4.
RHR Service Water to RHR Cross-Tie Valve 25 ASP-1 NA NA R
Control (10MOV-148B) 5.
RHR Service Water to RHR Cross-Tie Valve 25 ASP-1 NA NA R
Control (10MOV-1498) 6.
RHR Flow (Loop B) 25RSP M
R NA (10F1-133) 7.
RHR Discharge Pressure (Pump D) 25RSP M
R NA (10PI-279) 8.
RHR Pump Control 25RSP NA NA R
(10P-3D) 9.
RHR Heat Exchanger Bypass Valve Control 25RSP NA NA R
[
Am::ndment No. 344, 77f
.J
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS (Refer to Notes on Page 770]
INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAllBRATION TEST 10.
RHR Inboard injection Valve Control 25RSP NA NA R
(10MOV-258) 11.
RHR Heat Exchanger Steam inlet Valve 25 ASP-1 NA NA R
Control (10MOV-70B) 12.
RHR Heat Exchanger Vent Valve Control 25 ASP-1 NA NA R
(10MOV-1668) 13.
RHR Heat Exchanger Outlet Valve Control 25 ASP-1 NA NA R
(10MOV-128) l 14.
RHR Pump D Torus Suction Valve Control 25 ASP-2 NA NA R
i (10MOV-13D) 15.
RHR Pump D Shutdown Cooling Suction Valva 25 ASP-2 NA NA R
l Control (10MOV-15D) 16.
RHR Pump B Minimum Flow Valve Control 25 ASP-2 NA NA R
(10MOV-16B) 17.
RHR Heat Exchanger inlet Valve Control 25 ASP-2 NA NA R
(10MOV-65B) 18.
RHR Outboard injection Valve Control 25 ASP-2 NA NA R
(10MOV-278) l Am:ndment No. GM, l
77g i
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS
[ Refer to Notes on Page 770]
INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CALIBRATION TEST 19.
RHR Heat Exchanger Discharge to Torus Valve 25 ASP-2 NA NA R
Control (10MOV-21B) 20.
Torus Cooling isolation Valve Control 25 ASP-2 NA NA R
(10MOV-39B) 21.
DW Spray Outboard Valve Control 25 ASP-3 NA NA R
(10MOV-268) 22.
ADS & Safety Relief Valve A Control 02 ADS-71 NA
_NA R
(02RV-71 A) 23.
ADS & Safety Relief Valve B Control 02 ADS-71 NA NA R
(02RV-71 B) 24.
ADS & Safety Relief Valve C Control 02 ADS-71 NA NA R
(02RV-71C) 25.
ADS & Safety Relief Valve D Control 02 ADS-71 NA NA R
(02RV-71 D) 26.
ADS & Safety Relief Valve E Control 02 ADS-71 NA NA R
(02RV-71 E) 27.
ADS & Safety Relief Valve G Control 02 ADS-71 NA NA R
(02RV-71 G)
Amendment No. G44, 77h
...m
-u m.m-.
x e
F'
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUWlENTATION AND CONTROLS
[ Refer to Notes on Page 770]
INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAllBRATION TEST 28.
ADS & Safety Relief Valve H Control 02 ADS-71 NA NA R
(02RV-71 H) i 29.
Safety Relief Valve F Control 02 ADS-71 NA NA R
(02RV-71 F) 30.
Safety Relief Valve J Control 02 ADS-71 NA NA R
(02RV-71J) 31.
Safety Relief Valve K Control 02 ADS-71 NA NA R
(02RV-71 K) 32.
Safety Relief Valve L Control 02 ADS-71 NA NA R
(02RV-71 L) 33.
Main Steam Line Drain Outboard isolation 25 ASP-2 NA NA R
Valve Control (29MOV-77) 34.
Drywell Temperature 25RSP M
R NA (68TI-115) 35.
Torus Water Temperature 25RSP M
R NA (27TI-101) 36.
Torus Water Level 25RSP M
R NA (23LI-204)
Amendment No. 446, 77i
--- =
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS IRefer to Notes on Page 7701 -
INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAL!BRATION TEST 37.
Reactor Vessel Pressure Rack 25-6 M
R NA (02-3PI-60B) 38.
Reactor Vessel Water Level Rack 25-6 M
R NA (02-3LI-58A) 39.
Reactor Vessel Water Level Rack 25-51 M
R NA (02-3LI-93) 40.
HPCI Steam Supply Outboard Isolation Valve 25RSP NA NA R-Control (23MOV-16) 41.
HPCI Outboard Isolation Bypass Valve Control 25 ASP-2 NA NA R
(23MOV-60) 42.
HPCI Minimum Flow Valve Control 25 ASP-2 NA NA R
(23MOV-25) 43.
CAD B Train inlet Valve Control 25RSP NA NA R
(27AOV-126B) 44.
Nitrogen Instrument Header Isolation Valve 25RSP NA NA R
Control (27AOV-1298) 45.
Reactor Water Cleanup Outboard Isolation 25 ASP-2 NA NA R
Valve Control (12MOV-18)
Amendment No. 446, 77j
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS
[ Refer to Notes on Page 770]
INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL -
OR CONTROL LOCATION CHECK CAllBRATION TEST 46.
Emergency Service Water Pump B Control 25 ASP-3 NA NA R
(46P-2B) 47.
ESW Loop B Supply Header Isolation Valve 25 ASP-3 NA NA R
Control (46MOV-101B) 48.
ESW Pump B Test Valve Control 25 ASP-3 NA NA R
(46MOV-102B) 49.
Bus 11600 Supply Breaker Control 25RSP NA NA R
(71-11602) 50.
EDG B & EDG D Tie Breaker Control 25 ASP-3 NA NA R
(71-10604) 51.
Bus 10400-10600 Tie Breaker Control 25 ASP-3 NA NA R
(71-10614) 52.
Unit Substation L16 & L26 Feeder Breaker 25 ASP-3 NA NA R
Control (71-10660) 53.
Bus 12600 Supply Breaker Control 25 ASP-3 NA NA R
l (71-12602) 54.
Breaker 71-10614 Synchronizing Check Control 25 ASP-3 NA NA R
55.
EDG B Control Room Metering Check Control 25 ASP-3 NA NA R
Amendment No. 444, 77k
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS (Refer to Notes on Page 770]
INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAllBRATION TEST 56.
EDG B Engine Start /Stop Control 25 ASP-3 NA NA R
57.
EDG D Control Room Metering Check Control 25 ASP-3 NA NA R
58.
EDG D Engine Start /Stop Control 25 ASP-3 NA NA R
59.
EDG B Governor Switch 93EGP-B NA NA R
60.
EDG B Synchronizing Switch 93EGP-B NA NA R
61.
EDG B Load Breaker Control (71-10602) 93EGP-B NA NA R
62.
EDG B Motor Control 93EGP-B NA NA R
63.
EDG B Frequency Meter (93FM-1B) 93EGP-B NA R
NA 64.
EDG B Voltage Control 93EGP-B NA NA R
65.
EDG B Emergency Bus Meter (71VM-600-1B) 93EGP-B M
R NA 66.
EDG B incoming Bus Meter (93VM-12B) 93EGP-B NA R
NA 67.
EDG B Running Bus Meter (93VM-118) 93EGP-B NA R
NA 68.
EDG D Governor Switch 93EGP-D NA NA R
69.
EDG D Synchronizing Switch 93EGP-D NA NA R
Amendment No. 244, 7 71
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS i
[ Refer to Notes on Page 770]
l INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAllBRATION TEST l
l 70.
EDG D Load Breaker Control (71-10612) 93EGP-D NA NA R
71.
EDG D Motor Control 93EGP-D NA NA R
72.
EDG D Frequency Meter (93FM-1D) 93EGP-D NA R
NA i
73.
EDG D Voltage Control 93EGP-D NA NA R
74.
EDG D Emergency Bus Meter (71VM-600-1D) 93EGP-D M
R NA l
75.
EDG D incoming Bus Meter (93VM-12D) 93EGP-D NA R
NA 76.
EDG D Running Bus Meter (93VM-11D) 93EGP-D NA R
NA 77.
Reactor Head Vent Isolation Switch 25RSP NA NA R
[
(02AOV-17) 78.
Outboard MSIV A Isolation Switch 25 ASP-4 NA NA R
(
(29AOV-86A) 79.
Outboard MSIV B Isolation Switch 25 ASP-4 NA NA R
(29AOV-86B) 80.
Outboard MSIV C isolation Switch 25 ASP-4 NA NA R
(29AOV-86C) i Amendment No. 444, 77m i
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS (Refer to Notes on Page 770)
INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAllBRATION TEST 81.
Outboard MSIV D isolation Switch 25 ASP-4 NA NA R
(29AOV-86D) 82.
East Crescent Area Unit Cooler B,D,F 66HV-3B NA NA R
(66UC-22B, 22D, 22F) Isolation Switch 83.
East Crescent Area Unit Cooler H,K ESHV-3B NA NA R
(66UC-22H, 22K) Isolation Switch 84.
ADS & Safety Relief Valve A 25 ASP-5 NA NA R
isolation Switch (02RV-71 A) 85.
ADS & Safety Relief Valve B 25 ASP-5 NA NA R
isolation Switch (02RV-71B) 86.
ADS & Safety Relief Valve C 25 ASP-5 NA NA R
Isolation Switch (02RV-71C) 87.
ADS & Safety Relief Valve D 25 ASP-5 NA NA R
I isolation Switch (02RV-71D) i 88.
ADS & Safety Relief Valve E 25 ASP-5 NA NA R
Isolation Switch (02RV-71E) i 89.
Safety Relief Valve F 25 ASP-5 NA NA R
isolation Switch (02RV-71F)
Amendment No.
77n s
k
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAllBRATION TEST 90.
ADS & Safety Relief Valve G 25 ASP-5 NA NA R
isolation Switch (02RV-71G) 91.
ADS & Safety Relief Valve H 25 ASP-5 NA NA R
Isolation Switch (02RV-71H) 92.
Safety Relief Valve J 25 ASP-5 NA NA R
isolation Switch (02RV-71J) 93.
Safety Relief Valve K 25 ASP-5 NA NA R-Isolation Switch (02RV-71K) 94.
Safety Relief Valve L 25 ASP-5 NA NA R
isolation Switch (02RV-71L)
NOTES FOR TABLE 3.2-10 1.
Minimum required number of divisions for all instruments and controls listed is 1.
i Amendment No.
770
JAFNPP TABLE 4.2-2 CORE AND CONTAINMENT COOUNG SYSTEM INSTRUMENTATION TEST AND CAUBRATION REQUIREMENTS Instrument Channel Instrument Functional Test Calibration Frequency Instrument Check (Note 4) 1)
Reactor Water Level Q (Note 5)
SA / R (Note 15)
D 20)
Drywell Pressure (non-ATTS)
Q Q
NA 2b)
Drywell Pressure (ATTS)
O (Note 5)
SA / R (Note 15)
D 3s)
Reactor Pressure (non-ATTS)
Q O
NA 3b)
Reactor Pressure (ATTS)
Q (Note 5)
SA / R (Note 15)
D 4)
Auto Sequencing Timers NA 18M NA 5)
O Q
NA 6)
Trip System Bus Power Monitors Q
NA NA 7)
Core Spray Sparger d/p Q
Q D
8)
HPCI & RCIC Suction Source Levels Q
Q NA 9) 4kV Emergency Bus Under-Voltage R
R NA (Loss-of-Voltage, Degraded Voltage LOCA and non-LOCA) Relays and Timers.
10)
LPCI Cross Connect Valve Position R
NA NA NOTE:
See notes following Table 4.2-5.
Amendment No. 2, 80,1 S9,181, 201, 217, 227, 80
JAFNPP TABLE 4.2-3 CONTROL ROD BLOCK INSTRUMENTATION TEST AND CALIBRATION REQUIREMENTS Instrument Functional Instrument Instrument Channel Test (Note 5)
Calibration Check (Note 4) 1)
APRM - Downscale Q
Q D
2)
APRM - Upscale Q
Q D
3) lRM - Upscale S/U (Note 2)
Q (Notes 3 & 6)
D 4) lRM - Downscale S/U (Note 2)
Q (Notes 3 & 6)
D 5) lRM - Detector Not in Startup Position S/U (Note 2)
NA NA 6)
RBM - Upscale Q
Q D
7)
RBM - Downscale Q
Q D
8)
SRM - Upscale S/U (Note 2)
Q (Notes 3 & 6)
D 9)
SRM - Detector Not in Startup Position S/U (Note 2)
NA NA 10)
Scram Discharge Instrument Volume -
O Q
D High Water Level (Group B instruments)
NOTE: See notes following Table 4.2-5.
l l
Amendment No. 3, Se,93, 227, 82
JAFNPP TABLE 4.2-5 MINIMUM TEST AND CALIBRATION FREQUENCY FOR DRYWELL LEAK DETECTION Instrument Functional Calibration Instrument Check Instrument Channel Test Frequency (Note 4) 1)
Equipment Drain Sump Flow Integrator (Note 1)
Q D
2)
Floor Drain Sump Flow Integrator (Note 1)
Q D
NOTE: See notes following Table 4.2-5.
l Amendment No. 3S,89,181, 83
JAFNPP NOTES FOR TABLES 4.2-1 THROUGH 4.2-5
- 1. Initially once every month until acceptance failure rate data are 8.
Reactor low water level, and high drywell pressure are not available; thereaftar, a request may be made to the NRC to included on Table 4.2-1 since they are listed on Table change the test frequency. The compilation of instrument 4.1-2.
failure rate data may include data obtained from other boiling water reactors for which the same design instruments operate 9.
The logic system functional tests shall include a calibration in a environment similar to that of JAFNPP.
of time delay relays and timers necessary for proper functioning of the trip systems.
- 2. Functional tests are not required when these instruments are not required to be operable or are tripped. Functional tests
- 10. (Deleted) shall be performed within seven (7) days prior to each startup.
- 11. Perform a calibration once per 24 months using a radiation l
- 3. Calibrations are not required when these instruments are not source. Perform an instrument channel alignment once required to be operable or are tripped. Calibration tests shall every 3 months using a current source.
l be performed within seven (7) days prior to each startup or prior to a pre-planned shutdown.
- 12. (Deleted)
- 4. Instrument checks are not required when these instruments
- 13. (Deleted) are not required to be operable or are tripped.
- 14. (Deleted)
- 5. This instrumentation is exempt from the functional test definition. The functional test will consist of injecting a
- 15. Sensor calibration once per 24 months. Master / slave trip simulated electrical signal into the measurement channel.
unit calibration once per 6 months.
- 6. These instrument channels will be calibrated using simulated
- 16. The quarterly calibration of the temperature sensor consists electrical signals once every three mon hs.
of comparing the active temperature signal with a redundant temperature signal.
- 7. Simulated automatic actuation shall be performed once per 24 months.
l Amendment No. Si, SS, 57,89,181,207,227, 84
JAFMPP TABLE 4.2-6 FEEDWATER PUMP TURBINE AND MAIN TURBINE TRIP INSTRUMENTATIDN TEST AND CALIBRATION REQUIREMENTS Instrument Channel Instrument Functional Logic System Functional Calibration Frequency Instrument Check Test Frequency (Note 2)
Test Frequency Frequency Reactor Vessel Water Level - High Note 1 R
R D
NOTES FOR TABLE 4.2-6
- 1. Perform the instrument functional test:
- a. Once per 24 months during each refueling outage, and
- b. Each time the plant is in cold shutdown for a period of mere than 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 92 days.
- 2. This instrumentation is exempt from the instrument channel functional test definition. The functional test will consist of injecting a simulated electrical signal into the instrument channel as close to the sensor as practicable.
Amendment No. 336, 84a
JAFNPP TABLE 4.2-8 MINIMUM TEST AND CAllBRATION FREQUENCY FOR ACCIDENT MONITORING INSTRUMENTATION Instrument Instrument Instrument Functional Test Calibration Frequency Check 1.
Stack High Range Effluent Monitor 18M 18M D
2.
Turbine Building Vent High Range Effluent Monitor 18M 18M D
3.
Radwaste Building Vent High Range Effluent Monitor 18M 18M D
4.
Containment High Range Radiation Monitor R
R D
5.
Drywell Pressure (narrow range)
N/A R
D 6.
Drywell Pressure (wide range)
N/A R
D 7.
Drywell Temperature N/A R
D 8.
Torus Water Level (wide range)
N/A R
D 9.
Torus Bulk Water Temperature N/A R
D 10.
Torus Pressure N/A R
D 11.
Primary Containment Hydrogen / Oxygen Concentration N/A Q
D Analyzer 12.
Reactor Vessel Pressure N/A R
D 13.
Reactor Water Level (fuel zone)
N/A R
D 14.
Reactor Water Level (wide range)
N/A R
D Amendment No. 3,172,181,221, 86
i JAFNPP TABLE 4.2-8 (cont'd)
MINIMUM TEST AND CAllBRATION FREQUENCY FOR ACCIDENT MONITORING INSTRUMENTATION Instrument Instrument Instrument Functional Test Calibration Frequency Check 15.
Core Spray Flow N/A R
D 26.
Core Spray Discharge Pressure N/A R
D 17.
D 18.
RHR Service Water Flow N/A R
D 19.
Safety / Relief Valve Position Indicator R
N/A M
(Primary and Secondary) 20.
Torus Water Level (narrow rangc)
N/A R
D 21.
Drywell-Torus Differential Pressure N/A R
D Amendment No. 12^,181,229, 86a
JAFNPP s
3.5 LIMITING CONDITIONS FOR OPERATION 4.5 SURVEILLANCE REQUIREMENTS t
3.5 CORE AND CONTAINMENT COOLING SYSTEMS 4.5 CORE AND CONTAINMENT COOLING SYSTEMS Anolicability:
Anolicability:
Applies to the operational status of the Emergency Core Cooling Applies to periodic testing of the Emergency Core Cooling Systems, i
Systems, the suppression pool cooling, and containment spray the suppression pool cooling and containment spray mode of the modes of the Residual Hrsat Removal (RHR) System.
Residual Heat Removal (RHR) System.
i Obiective:
Obiective:
i To assure operability of the Core and Containment Cooling Systems To verify {he operability of the Core and Containment Cooling I
under all conditions for which this cooling capability is an essential Systems under all conditions for which operability is essential.
~
r sponse to plant abnormalities.
(
Specification:
Soecificatisn:
A.
Core Sorav System and Low Pressure A. Core Sorav System and Low Pressure Coolant Iniection (LPCI)
Coolant Iniection (LPCI) Mode of the RHR System Mode of t!!e (RHR) System l
)
1.
Both Core Spray Systems shall be operable when ever 1.
Surveillance of the Core Spray System shall be performed irradiated fuel is in the reactor vessel and prior to reactor as foFows:
startup from a cold condition, except as specified below:
llem Freauency a.
Simulated Refer to Table 4.2-2 Automatic i
Actuation
[
Test l
l t
Amendment No.
-112
JAFNPP 3.5 (cont'd) 4.5 (cont'd) b.
Flow Rate Test -
Once/3 months Core spray pumps shall deliver at least 4,265 gpm against a system head corresponding to a reactor vessel pressure greater than or equal to 113 psi above primary containment pressure.
c.
Pump Operability Once/ month d.
Motor Operated Valve Once/ month e.
Core Spray Header ap Instrumentation Check Once/ day Calibrate Once/3 months Test Once/3 months f.
Logic System Refer to Table 4.2-2 Functional Test t
g.
Testable Check Tested for operability Valves any time the reactor is in the cold condition exceeding 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, if operability tests have not been performed during the preceding 31 days.
Amendment No. 40,119,204, 113
JAFNPP 3.5 (cont'd) 4.5 (cont'd) b.
When the reactor water temperature is greater b.
The power source disconnect and chain lock to than 212 F, the motor operator for the RHR motor operated RHR cross-tie valve (10MOV-20),
l cross-tie valve (10MOV-20) shall be maintained and lock on manually operated gate valve disconnected from its electric power source. It (10RHR-09) shall be inspected once per month to shall be maintained chain-locked in the closed verify that both valves are closed and locked.
position. The manually operated gate valve l_
(10RHR-09) in the cross-tie line, in series with the motor operated valve, shall be maintained locked in the closed position.
4.
a.
The reactor shall not be started up with the RHR System supplying cooling to the fuel pool.
b.
The RHR System shall not supply cooling to the spent fuel pool when the reactor coolant temperature is above 212 F.
Amendment No. 55,95,'10, 115
t JAFNPP 3.5 (Cont'd) 4.5 (Cont'd)
E.
Reactor Core Isolation Coolina (RCIC) System E.
Reactor Core Isolation Coolina (RCIC) System 1.
The RCIC System shall be operable whenever there 1.
RCIC System testing shall be performed as follows is irradiated fuel in the reactor vessel and the reactor provided a reactor steam supply is available. If pressure is greater than 150 psig and reactor coolant steam is not available at the time the surveillance
[
temperature is greater than 212*F except from the test is scheduled to be performed, the test shall be time that the RCIC System is made or found to be performed within ten days of continuous operation inoperable for any reason, continued reactor power from the time steam becomes available.
operation is permissible during the succeeding 7 days unless the system is made operable earlier item Freauency i
provided that during these 7 days the HPCI System is operable.
a.
Simulated Automatic Once per 24 Months Actuation (and Restart )
t 2.
If the requirements of 3.5.E cannot be met, the Test reactor shall be placed in the cold condition and pressure less then 150 psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
Pump Operability Once/ month 3.
Low power physics testing and reactor operator c.
Motor Operated Once/ month i
training shall be permitted with inoperable Valve Operability components as specified in 3.5.E.2 above, provided that reactor coolant temperature is s212*F.
d.
Flow Rate Once/3 months 4.
The RCIC system is not required to be operable
- e. Testable Check Tested for operability during hydrostatic pressure and leakage testing with Valves any time the reactor is reactor coolant temperatures between 212*F and in the cold condition 300 F and irradiated fuel in the reactor vessel exceeding 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, if provided all control rods are inserted.
operability tests have not been performed I
during the preceding 31 days.
f.
Logic System Once per 24 Months Functional Test Automatic restart on a low water level signal which is subsequent to a high water level trip.
Amendment No. 40,107,120,*?9, 121
JAFNPP 4.5 BASES The testing interval for the Core and Containment Cooling The RCIC flow rate is described in the UFSAR. The flow rates to Systems is based on a quantitative reliability analysis, industry be delivered to the reactor core for HPCI, the LPCI mode of RHR, practice, judgement, and practicality. The Emergency Core and CS are based on the SAFER /GESTR LOCA analysis. The flow Cooling Systems have not been designed to be fully testable rates for the LPCi mode of RHR and CS are modified by a 10 during operation. For example, the core spray final admission percent reduction from the SAFER /GESTR LOCA analysis. The valves do not open until reactor pressure has fallen to 450 psig; reductions are based _on.a sensitivity analysis (Gar==t metric thus, during operation even if high drywell pressure were MDE-83-0786) performed for the parameters used in the simulated, the final valves would not open. In the case of the SAFER /GESTR analysis.
HPCI, automatic initiation during power operation would result in pumping cold water into the reactor vessel which is not The CS surveillance requirement includes an allowance for system desirable.
leakage in addition to the flow rate required to be delivered to the reactor core. The leak rate from the core spray piping inside the The systems will be automatically actuated once per 24 months.
reactor but outside the core shroud is assumed in the UFSAR and in the case of the Core Spray System, condensate storage tank includes a known loss of less than 20 gpm from the 1/4 inch water will be pumped to the vessel to verify the operability of diameter vent hole in the core spray T-box connection in each of the core spray header. To increase the availability of the the loops, and in the B loop, a potential additional loss of less than individual components of the Core and Containment Cooling 40 gpm from a clamshell repair whose structural weld covers only Systems the components which make up the system i.e.,
5/6 of the circumference of the pipe. Both of these identified instrumentation, pumps, valve operators, etc. are tested more sources of leakage occur in the space between the reactor vessel frequently. The instrumentation is functionally tested each wall and the core shroud. Therefore flow lost through these leak month. Likewise,the pumps and motor-operated valves are also sources does not contribute to core cooling.
tested each month to assure their operability. The combination automatic actuation test and monthly tests of the pumps and The surveillance requirements to ensure that the discharge piping valve operators is deemed to be adequate testing of these of the core spray, LPCI mode of the RHR, HPCI, and RCIC systems.
Systems are filled provides for a visual observation that water flows from a high point vent. This ensures that With components or subsystems out-of-service, overall core and containment cooling reliability is maintained by verifying the operability of the remaining cooling equipment. Consistent with the definition of operable in Section 4.0.C, demonstrate means conduct a test to show; verify means that the associated surveillance activities have been satisfactorily performed within the specified time interval.
Amendment No. 'i, '18, 204, 132
JAFNPP 3.7 (cont'd) 4.7 (cont'd) e.
At least once per operating cycle, manual operability of the bypass valve for filter cooling shall be demonstrated.
f.
Standby Gas Treatment System Instrumentation Calibration:
differential Once per 24 Months pressure switches 2.
From and after the date that one circuit of the Standby Gas Treatment System is made or found to be inoperable 2.
When one circuit of the Standby Gas Treatment for any reason, the following would apply:
System becomes inoperable, the operable circuit shall be verified to be operable immediately and daily a.
If in Start-up/ Hot Standby, Run or Hot Shutdown thereafter.
mode, reactor operation or irradiated fuel handling is permissible only during the succeeding 7 days unless such circuit is sooner made operable, provided that during such 7 days all active components of the other Standby Gas Treatment Circuit sh=" 'm operable.
b.
If in Reftd. or Cold Shutdown mode, reactor operation or irradiated fuel handling is permissible only during the succeeding 31 days unless such circuit is sooner made operable, provided that during such 31 days all active components of the other Standby Gas Treatment Circuit shall be operable.
3.
If Specifications 3.7.B.1 and 3.7.B.2 are not met, the reactor shall be placed in the cold condition and
- 3. Intentionally Blank irradiated fuel handling operations and operations that could reduce the shutdown margin shall be prohibited.
Amendment No. 10, SS,
- iS,154, 183
i I
JAFNPP 3.7 (cont'd) 4.7 (cont'd) i c.
Secondary containment capability to maintain a 1/4 in. of water vacuum under calm wind conditions with a filter train flow rate of not more than 6,000 cfm, shall be demonstrated at each refueling outage prior to refueling.
t D.
Primary Containment Isolation Valves D.
Primary Containment Isolation Valves i
1.
Whenever primary containment integrity is required per 1.
The primary containment isolation valves surveillance 3.7.A.2, containment isolation valves and all instrument shall be performed as follows:
line excess flow check valves shall be operable, except as specified in 3.7.D.2. The containment vent and purge a.
At least once per operating cycle, the operable valves shall be limited to opening angles less than or isolation valves that are power operated and
{
equal to that specified below:
automatically initiated r. hell be tested for simulated automatic initiation and for closure time.
Valve Number Maximum Openina Anale 27AOV-111 40' b.
Once per 24 months, the instrument line excess 27AOV-112 40' flow check valves shall be tested for proper 27AOV-113 40*
operation."
c.
At least once per quarter:
i 27AOV-116 50' 27AOV-117 50' (1.) All normally open power-operated isolation 27AOV-118 50*
valves (except for the main stream line and Reactor Building Closed Loop Cooling Water System (RBCLCWS) power-operated isolation i
valves) shall be fully closed and reopened.
The current surveillance interval for testing instrument line excess flow check valves is extended until the end of 3
the R11/C12 refueling outage scheduled for January, 1995. This is a one-time extension, effective only for i
this surveillance interval. The next surveillance interval will begin upon completion of this surveillance.
Amendment No.
185 i
4 JAFNPP l
t f
3.9 (cont'd) 4.9 (cont'd) 3.
From and after the time both power supplies are made or I
found inoperable the reactor shall be brought to cold condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
l G.
REACTOR PROTECTION SYSTEM ELECTRICAL PROTECTION G.
REACTOR PROTECTION SYSTEM ELECTRICAL PROTECTION fSSEMBLIES ASSEMBLIES l
Two RPS electrical protection assemblies for each inservice The RPS electrical protection assemblies instrumentation shall i
RPS MG set and inservice alternate source shall be operable be determined operable by:
I except as specified below:
1.
Performing a channel functional test each time the plant is 1.
With one RPS electrical protection assembly for an in cold shutdown for a period of more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, inservice RPS MG set or an inservice alternate power unless performed in the previous 6 months.
l supply inoperable, restore the inoperable channel to i
operable status withm 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the associated 2.
Once per 24 months, demonstrating the operability of i
RPS MG set or alternate power supply from service.
over-voltage, under-voltage and under-frequency protective instrumentation by performance of a channel i
2.
With two RPS electrical protection assemblies for an calibration including simulated automatic actuation of the j
inservice RPS MG set or an inservice alternate power protective relays, tripping logic and output circuit l
supply inoperable, restore at least one to operable status breakers and verifying the following setpoints:
i 4
within 30 minutes or remove the associated RPS MG set or attemate power supply from service.
OVER-VOLTAGE s132V s4 second Time Delay UNDER-VOLTAGE 2112.3V l
s4 second Time Delay l
1 UNDER-FREQUENCY 257Hz l
54 second Time Delay l
Amendment No. 4',70,189, (continued on page 222d) 222c l
+
4.9 BASES (cont'd)
D.
Not Used E.
Battery System i
Measurements and electrical tests are conducted at specified intervals to provide indication of cell condition and to determine the discharge capability of the batteries.
Performance and service tests are conducted in accordance i
with the recommendations of IEEE 450-1987.
4 F.
LPCI MOV Independent Power Sunolv Measurement and electrical tests are conducted at specified intervals to provide indication of cell condition, to determine the discharge capability of the battery. Performance and service tests are conducted in accordance with the I
recommendations of IEEE 450-1987.
G.
Reactor Protection Power Sunolies Functional tests of the electrical protection assemblies are conducted at specified intervals utilizing a built-in test device l
and once per 24 months by performing an instrument calibration which verifies operation within the limits of Section 4.9.G.
I i
i Amendment No. 30,76,131,167,189,190 226
JAFNPP i
3.11 - (cont'd) 4.11 (cont'd)
I ventilation air supply fan and/or filter may be out of b.
Di-octylphtalate (DOP) test for particulate filter service for 14 days.
efficiency greater than 99% for particulate greater than 0.3 micron size.
c.
Freon-112 test for charcoal filter bypass as a measure of filter efficiency of at least 99.5% for halogen removal.
j d.
A sample of charcoal filter shall be analyzed once a year to assure halogen removal efficiency of at least i
99.5%.
t 2.
The main control room air radiation monitor shall be 2.
Operability of the main control room air intake radiation operable whenever the control room emergency monitor shall be tested once/3 months.
ventilation air supply fans and filter trains are required to be operable by 3.11.A.1 or filtration of the control room ventilation intake air must be initiated.
i 3.
The control room emergency ventilation system shall not 3.
Temperature transmitters and differential pressure l
be out of service for a period exceeding 3 days during switches shall be calibrated once per 24 months.
normal reactor operation or refueling operations. In the event that the system is not returned to service within 3 deys, the reactor shall be in cold shutdown within 24 l
hours and any handling of irradiated fuel, core alterations, and operations with a potential for draining the reactor
[
vessel shall be suspended as soon as practicable 4.
Not Used 4.
Main control room emergency ventilation air supply system capacity shall be tested once every 18 months to l
assure that it is i10% of the design value of 1000 cfm.
[
i l
l r
Amendment No. '11,129,192, 238 t
i JAFNPP l
3.11 (cont'd) 4.11 (cont'd)
B.
Crescent Area Ventilation B. Crescent Area Ventilation Crescent area ventilation and cooling equipment shall be 1.
Unit coolers serving ECCS components shall be l
operable on a continuous basis whenever specification 3.5.A, demonstrated operable once/3 months.
3.5.B, and 3.5.C are required to be satisfied.
2.
Each unit cooler temperature control instrument shall be 1.
From and after the date that more than one unit cooler calibrated once per 24 months.
j serving ECCS compartments in the same half of the crescent area are made or found to be inoperable, all ECCS components in that half of the crescent area shall be considered to be inoperable for purposes of specification 3.5.A, 3.5.B, and 3.5.C.
t 2.
If 3.11.B.1 cannot be met, the reactor shall be placed in a cold condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
j i
C.
Battery Room Ventilation C. Battery Room Ventilation
[
Battery room ventilation shall be operable on a continuous Battery room ventdation equipment shall be demonstrated i
basis whenever specification 3.9.E is required to be satisfied.
operable once/ week.
l
[
1.
From and after the date that one of the battery room
- 1. When it is determined that one battery room ventilation ventilation systems is made or found to be inoperable, system is inoperable, the remaining ventilation system shall its associated battery shall be considered to be be verified operable and daily thereafter.
l inoperable for purposes of specification 3.9.E.
- 2. Temperature transmitters and differential pressure switcheo shall be calibrated once per 24 months.
I I
Amendment No. iS, 32,12S,134, 'iS,150, 239 i
l
JAFNPP LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7 OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MIXTURE 3.7 OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MIXTURE INSTRUMENTATION INSTRUMENTATION Anolicability Apolicability Applies to the condenser offgas treatment system recombiner Applies to the offgas treatment system instrumentation, which operation.
monitors the critical operating parameters of the primary recombiner.
Obiective Obiective To ensure proper conditions for the offgas recombiner to To ensure that instrumentation required for automatic isolation operate at design efficiency in order to prevent an explosive is maintained and calibrated.
mixture of gases in the charcoal treatment system.
Specifications Soecifications a.
The concentration of either hydrogen or oxygen in the a.
The concentration of either hydrogen or oxygen in the main condenser offgas treatment system shall be main condenser offgas treatment system shall be limited determined to be within the limits of Specification 3.7.a to less than or equal to 4% by volume, by continuously monitoring the waste gases in the main condenser offgas treatment system whenever the main condenser evacuation system is in operation with the hydrogen or oxygen monitors. Operation of the hydrogen or oxygen monitors shall be verified in accordance with Specification 3.7.b.1 and 3.7.b.4.
b.
In lieu of continuous hydrogen or oxygen monitoring, the b.
Whenever continuous hydrogen or oxygen monitoring is following instrumentation shall be operational and not available, operation of the explosive gas mixture capable of providing automatic isolation of the offgas instruments listed in Specification 3.7.b shall be verified.
Amendment No. 93, 32
5 JAFNPP LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS treatment system under the following conditions:
1.
An instrument check shall be performed daily when the offgas treatment system is in operation.
1.
The offgas dilution steam flow instrumentation shall alarm and automatically isolate the offgas recombiner 2.
An instrument channel functional test of the system at a low flow setpoint greater than or equal to instrumentation listed in Specification 3.7.b shall be 6300 pounds per hour and at a high flow setpoint less performed once per 24 months.
than or equal to 7900 pounds per hour.
3.
An instrument channel calibration of the instrumentation 2.
The offgas recombiner inlet temperature sensor shall listed in Specification 3.7.b shall be performed once per alarm and automatically isolate the offgas recombiner 24 months.
system at a temperature setpoint of greater than or equal to 125*C.
4.
An instrument channel functional test and calibration of the off-gas hydrogen or oxygen monitors shall be 3.
The offgas recombiner outlet temperature sensor shall performed once every 3 months.
alarm and automatically isolate the offgas treatment system at a temperature setpoint of greater than or equal i
to 150 C.
c.
In lieu of continuous hydrogen or oxygen monitoring, the c.
With condenser offgas treatment system recombiner in i
condenser offgas treatment system recombiner effluent shall service, in lieu of continuous hydrogen or oxygen monitoring, be analyzed to verify that it contains less than or equal to 4%
the hydrogen content shall be verified weekly to be less than hydrogen by volume.
or equal to 4 % by volume.
d.
With the requirements of the above specifications not in the event that the hydrogen content cannot be verified, I
satisfied, restore the recombiner system to within operating operation of this system may continue for up to 14 days.
specifications or suspend use of the charcoal treatment system within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
Amendment No. 93,127,187,203, 33 i
T
+
JAFNPP TABLE 3.10-2 MINIMUM TEST AND CALIBRATION FREQUENCY FOR RADIATION MONITORING SYSTEMS" instrument Instrument Channel Instrument Channel Logic System instrument Channels Check" Functional Test" Calibration Function Test"
Main Stack Exhaust Monitors and Recorders Daily Quarterly Quarterly I
Rsfuel Area Exhaust Monitors and Recorders Daily Quarterly Quarterly R; actor Building Area Exhaust Monitors, Recorders, Daily Quarterly Quarterly Semiannually and Isolation Turbine Building Exhaust Monitors and Recorders Daily Quarterly Quarterly l
Radwaste Building Exhaust Monitors and Recorders Daily Quarterly Quarterly I
SJAE Radiation Monitors /Offgas Line Isolation Daily Quarterly Quarterly Semiannually Main Control Room Ventilation Monitor Daily Quarterly Quarterly l
Mechanical Vacuum Pump Isolation
- Once per 24 Months Liquid Radwaste Discharge Monitor /
Daily When Quarterly Quarterly Semiannually Isolation "W'"
Discharging M
Liquid Radwaste Discharge Flow Rate Daily Quarterly Once per Measuring Devices" 18 Months Liquid Radwaste Discharge Radioactivity Daily Quarterly Once per i
Recorder "
18 Months Normal Service Water Effluent Daily Quarterly Quarterly l
Semiannually -
SBGTS Actuation 7
Amendment No. 93,127,213, 38 i
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JAFNPP NOTES FOR TABLE 3.10-2 (a)
Functional tests, calibrations and instrument checks need not be performed when these instruments are not required to be operable or are tripped.
(b)
Instrument checks shall be performed at least once per day during these periods when the instruments are required to be operable.
(c)
A source check shall be performed prior to each release.
(d)
Liquid radwaste effluent line instrumentation surveillance requirements need not be performed when the instruments are not required as the result of the discharge path not being utilized.
(e)
An instrument channel calibration shall be performed with known radioactive sources standardized on plant equipment which has been calibrated with NBS traceable standards.
(f)
Simulated automatic actuation shall be performed once per 24 months. Where possible, all logic system functional tests will be performed using the test jacks.
(g)
Refer to Appendix A for instrument channel functional test and instrument channel calibration requirements (Table 4.2-1). These requirements are performed as part of main steam high radiation monitor surveillances.
(h) The logic system functional tests shall include a calibration of time delay relays and timers necessary for proper functioning of the trip systems.
(i)
This instrumentation is excepted from the functional test definition. The functional test will consist of injecting a simuisted electrical signal into the measurement channel. These instrument channels will be calibrated using simulated electrical signals once every three months.
Amendment No. 93, 207, 39
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6
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l ATTACHMENT ll to JPN-96-003 i
Safety Evaluation For Proposed Changes to the Technical Specifications Regarding Extension of Instrumentation and Miscellaneous Surveillance Test Intervals to Accommodate 24-Month Oneratina Cveles (JPTS-95-001G)
New York Power Authority JAMES A. FITZPATRICK NUCLEAR POWER PLANT Docket No. 50-333 DPR-59
s o
Attachment ll to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 1 of 50 1.
DESCRIPTION OF THE PROPOSED CHANGES This application for amendment to the FitzPatrick Operating License proposes the following changes to the Technical Specifications: (A) extend instrumentation and miscellaneous surveillance test intervals (STI) to support 24 month operating cycles, (B) revise Technical Specification Trip Level Setpoints in support of 24 month operating cycles, and (C) incorporate miscellaneous editorial, clarification and Bases changes.
A.
Channes to Extend Instrumentation and Miscellaneous Surveillance Test intervals to Suonort 24-Month Ooeratina Cveles 1.
Page 5, Specification 1.0.T Frequency column for Notation "R," Change from "At least once per 18 months (550 days)" to "At least once per 24 months (731 days)." Delete Note 1 and reference to Note 1 in the " Intervals" column, and add " Operating Cycle." Between Notations "A" and "R," add Notation "18M" with an Interval of "18 months" and frequency of "At least once per 18 months (550 days)." The applicable portion of the revised Specification reads:
"18M 18 Months At least once per 18 months (550 days)
R Operating Cycle At least once per 24 months (731 days)"
2.
Page 30g, Surveillance Requirement (SR) 4.1.A, change the response time testing STI for the reactor protection trip system from "at least once per 18 months" to "once per 24 months." The revised SR reads:
"The response time of the reactor protection system trip functions listed below shall be demonstrated to be within its limit once per 24 months."
3.
Page 47, Note 4 for Table 4.1-2, change "during the refueling outages" to "once per 24 months." The revised note reads:
" Actuation of these switches by normal means will be performed once per 24 months."
4.
Page 47, Note 6 for Table 4.1-2, change "once per operating cycle" to "once per 24 months." The revised note reads:
" Sensor calibration once per 24 months. Master / slave trip unit calibration once per 6 months."
l 1
O 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 2 of 50 5.
Page 49, SR 4.2.A, change the response time testing STI for the main steam isolation valve actuation instrumentation isolation trip functions from "at least once per 18 months" to "once per 24 months." The revised SR reads:
"The response time of the main steam isolation valve actuation instrumentation -
isolation trip functions listed below shall be demonstrated to be within their limits once per 24 months."
6.
Page 80, Table 4.2-2 Item 4, Auto Sequencing Timers, change the calibration frequency from "R" to "18M." This item is not extended to a 24 month STl.
7.
Page 82, Table 4.2-3 Control Rod Block !nstrumentation, Delete the Logic System Functional Test portion of the table.
8.
Page 84, Note 7 for Tables 4.2-1 through 4.2-5, change "each operating cycle" to "per 24 months." The revised note reads:
" Simulated automatic actuation shall be performed once per 24 months."
9.
Page 84, Note 11 for Tables 4.2-1 through 4.2-5, change " operating cycle" to "24 months" and remove the reference to the built-in current source. The revised note reads:
" Perform a calibration once per 24 months using a radiation source. Perform an instrument channel alignment once every 3 months using a current source."
10.
Page 84, Note 15 for Tables 4.2-1 through 4.2-5, change " operating cycle" to "24 months." The applicable portion of the revised note reads:
" Sensor calibration once per 24 months."
11.
Page 86, Table 4.2-8 Items 1,2 and 3, denote the STI for the Instrument Functional Test and the Calibration Frequency as "18M." These items are not extended to a 24 month STI.
12.
Page 112, SR 4.5.A.1.a, delete "Each operating cyde" and replace with " Refer to Table 4.2-2."
13.
Page 113, SR 4.5.A.1.f, delete "Once/each operating cycle" and replace with
" Refer to Table 4.2-2."
i i
I
Attachment ll to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 3 of 50 14.
Page 115, SR 4.5.A.3.b, change "each operating cycle" to "per month" and add the affected valve component designations. The revised SR reads:
"The power source disconnect and chain lock to motor operated RHR cross-tie valve (10MOV-20), and lock on manually operated gate valve (10RHR-09), shall be inspected once per month to verify that both valves are closed and locked."
15.
Page 121, SR 4.5.E.1.a and SR 4.5.E.1.f, change the frequency for RCIC cimulated automatic actuation (and restart) test and logic system functional test from "once/ operating cycle" to "Once per 24 months."
16.
Page 183, SR 4.7.B.1.f, change the Standby Gas Treatment System instrumentation calibration STI for differential pressure switches from "Once/ operating cycle" to "Once per 24 months."
17.
Page 185, SR 4.7.D.1.b, change the frequency for instrument line excess flow check valves testing from "At least once per operating cycle" to "Once per 24 months." The revised SR reads:
"Once per 24 months, the instrument line excess flow check valves shall be tested for proper operation."
18.
Page 222c, SR 4.9.G.2, change "At least once per operating cycle" to "Once per 24 months." The revised SR reads.
j "Once per 24 months, 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:"
19.
Page 238, SR 4.11.A.3, change the temperature transmitter and differential pressure switch calibration STI from "once/ operating cycle" to "once per 24 months." The revised SR reads:
" Temperature transmitters and differential pressure switches shall be calibrated once per 24 months."
20.
Page 239, SR 4.11.B.2, change crescent area ventilation unit cooler temperature control instrument calibration STI from "once/ operating cycle" to "once per 24 months." The revised SR reads:
"Each unit cooler temperature control instrument shall be calibrated once per 24 months."
, 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 4 of 50 21.
Page 239, SR 4.11.C.2, change battery room ventilation instrument calibration STI from "once/ operating cycle" to "once per 24 months." The revised SR reads:
" Temperature transmitters and differential pressure switches shall be calibrated once per 24 months."
22.
RETS Page 32, SR 3.7.a change " Operation of the hydrogen or oxygen monitors shall be verified in accordance with Specification 3.7.b.1,2 and 3" to
" Operation of the hydrogen or oxygen monitors shall be verified in accordance with Specification 3.7.b.1 and 3.7.b.4."
23.
RETS Page 33, SR 3.7.b.2, change the off-gas system instrument channel functional test STI from "once per operating cycle" to "once per 24 months" and clarify that this SR applies to the instrumentation listed in Specification 3.7.b.
The revised SR reads:
"An instrument channel functional test of the instrumentation listed in Specification 3.7.b shall be performed once per 24 months."
24.
RETS Page 33, SR 3.7.b.3, change the off-gas system instrument channel calibration STI from "once per operating cycle" to "once per 24 months" and clarify that this SR applies to the instrumentation listed in Specification 3.7.b.
The revised SR reads:
"An instrument channel calibration of the instrumentation listed in Specification 1
3.7.b shall be performed once per 24 months."
25.
RETS Page 33, add new SR 3.7.b.4 to define the calibration and functional test frequency of the off-gas hydrogen or oxygen monitors as once every 3 months.
The new SR reads:
"4.
An instrument channel functional test and calibration of the offgas hydrogen or oxygen monitors shall be performed once every 3 months."
26.
RETS Page 38, Table 3.10-2 Item 8, Mechanical Vacuum Pump Isolation, change Logic System Functional Test frequency from "Once per Operating Cycle" to "Once per 24 months."
27.
RETS Page 38, Table 3.10-2 Item 10, Liquid Radwaste Discharge Flow Rate Measuring Devices, change Instrument Channel Calibration frequency from "Once per Operating Cycle" to "Once per 18 months." This item is not extended to a 24 month STl.
28.
RETS Page 38, Table 3.10-2 Item 11, Liquid Radwaste Discharge Radioactivity
, 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 5 of 50 Recorder, change Instrument Channel Calibration frequency from "Once per Operating Cycle" to "Once per 18 Months." This item is not extended to a 24 month STI.
29.
RETS Page 38, Table 3.10-2 Item 12, Normal Service Water Effluent, delete reference to Note (f).
30.
RETS Page 39, Note (f), change "each operating cycle" to "per 24 months."
The revised note reads:
" Simulated automatic actuation shall be performed once per 24 months."
B.
Revision to Trio Level Setooints 1.
Page 70, Table 3.2-2, item 26, change the Trip Level Setting for the 4kV Emergency Bus Undervoltage Relay (Degraded Voltage) from "110.6 1.2 secondary volts" to "110.6 0.8 secondary volts."
2.
Page 70, Table 3.2-2, item 27, change the Trip Level Setting for the 4kV Emergency Bus Undervoltage Timer (Degraded Voltage LOCA) from "9.0 1.0 sec." to "8.96 0.55 sec."
3.
Page 70, Table 3.2-2, Item 28, change the Trip Level Setting for the 4kV Emergency Bus Undervoltage Timer (Degraded Voltage non-LOCA) from "45.0 5.0 sec." to "43.8 2.8 sec."
4.
Page 70, Table 3.2-2, Item 29, change the Trip Level Setting for the 4kV Emergency Bus Undervoltage Relay (Loss of Voltage) from "85 4.25 secondary volts" to "85 4.81 secondary volts."
5.
Page 70, Table 3.2-2, item 30, change the Trip Level Setting for the 4kV Emergency Bus Undervoltage Timer (Loss of Voltage) from "2.50 0.05 sec."
to "2.50 0.11 sec."
6.
Page 222c, SR 4.9.G.2, change the RPS MG Set Source Undervoltage setpoint from "z108V" te "2112.3V".
C.
Editorial. Clarification and Bases Chanaes 1.
Bases Page 37, first column second paragraph, change "each refueling outage" to "once per 24 months." The revised bases reads:
"The frequency of calibration of the APRM flow biasing network has been established as once per 24 months."
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 6 of 50 2.
Bases Page 37, first column second paragraph last sentence, change "each refueling outage" to "once per 24 months." The revised bases reads:
" Based on plant specific evaluation of drift over a 24 month operating cycle, it was determined that drift of instrumentation used in the flow biasing network is not significant. Therefore, to avoid spurious scrams, a calibration frequency of once per 24 months is established."
3.
Bases Page 38, first column, second paragraph, currently discusses the response time testing interval as being based on NRC NUREG-0123, Revision 3, " Standard Technical Specifications." Since the proposed response time testing STI is extended to support 24-month operating cycles in accordance with Reference 1, this paragraph no longer applies and is deleted.
4.
Page 46 and 47, Table 4.1-2, reformat table to make consistent with Amendment 227 and Standard Technical Specifications. The surveillance frequency column is revised to use the notations in Specification 1.0.T.
5.
Bases page 60, second column second paragraph, delete sentences three and four and replace with the following:
"This table only includes those isolation / transfer switches that do not have an associated control switch. Operability of isolation / transfer switches that have an associated control switch will be demonstrated when the control functions are tested as required by Surveillance Requirement 4.2.J."
6.
Bases page 60a, first column first paragraph, delete "and on panels 25 ASP-4, 25 ASIA 5, and 66HV-3B." The revised bases reads:
"The requirements of this section apply to each remote shutdown circuit on the panels listed in Table 3.2-10."
7.
Pages 77f through 77m, change table format to make consistent with Arnendment 227 and Standard Technical Specifications. The surveillance frequency column will use the notations in Specification 1.0.T.
8.
Revise page 77m and add new pages 77n and 770 to clarify the SR for equipment not previously identified on Table 3.2-10. Move notes on current page 77m to page 770. Revise note on current pages 77f through 771, and add note to current page 77m, to say " Refer to Notes on Page 77o."
9.
Page 77g, Table 3.2-10 Item 16, delete "P-3" to make consistent with other Table 3.2-10 item nomenclature. The revised specification reads:
"RHR Pump B Minimum Flow Valve Control (10MOV-16B)"
i Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 7 of 50 10.
New page 77o, Table 3.2-10, delete Notes B,C, and D and change the designation of Note "A" to Note "1."
11.
Page 771, Table 3.2-10 item 65, change the component designator for EDG B Emergency Bus Meter from "93VM-600-1B" to "71VM-600-1B" to correct typographical error.
12.
Page 771, Table 3.2-10 item 65, add surveillance requirement for a monthly instrument check.
13.
Page 77m, Table 3.2-10 Item 74, change the component designator for EDG D Emergency Bus Meter from "93VM-600-1D" to "71VM-600-1D" to correct typographical error.
14.
Page 77m, Table 3.2-10 Item 74, add surveillance requirement for a monthly instrument check.
15.
Page 82, Table 4.2-3, correct typographical error in title from "Instrumention" to
" Instrumentation."
16.
Page 83, Table 4.2-5, change table format to make consistent with Amendment 227 and Standard Technical Specifications (Reference 25). The surveillance frequency columns will use the notations in Specification 1.0.T.
17.
Page 84a, Table 4.2-6, change table format to make consistent with Amendment 227 and Standard Technical Specifications (Reference 25). The surveillance frequency columns will use the notations in Specification 1.0.T.
18.
Page 84a, Table 4.2-6, revise Note la to include the statement "Once per 24 months." This change provides clarification and does not revise the STI. The revised note reads:
"a.
Once per 24 months during each refueling outage, and" 19.
Pages 86 and 86a, Table 4.2-8, change table format to make consistent with Amendment 227 and Standard Technical Specifications (Reference 25). The surveillance frequency column will use the notations in Specification 1.0.T.
20.
Page 115, Specification 3.5.A.3.b: (1) change the component designator on the i
third line from "MOV20" to "10MOV-20" and, (2) change the component designator on the sixth line from "10-RHR-09" to "10RHR-09." These are editorial change to reflect standard component labeling terminology and do not change the actual va:ves referenced.
21.
Bases page 132, first column second paragraph, change "during a refueling
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 8 of 50 outage" to "once per 24 months." The revised bases reads-4 "The systems will be automatically actuated once per 24 months."
22.
Bases page 226, 4.9 Bases Section G, change "once per operating cycle" to "once per 24 months." The revised bases reads:
" Functional tests of the electrical protection assemblies are conducted at specified intervals utilizing a built-in test device and once per 24 months by performing an instrument calibration which verifies operation within the limits of Section 4.9.G."
II.
PURPOSE OF THE PROPOSED CHANGES This application for amendment to the James A. FitzPatrick Nuclear Power Plant Technical Specifications proposes to extend surveillance test intervals (STI) for instrumentation and miscellaneous systems to accommodate 24-month operating cycles. These changes will eliminate the need to shut the plant down mid-cycle to conduct these surveillances. In addition, this application proposes changes to Technical Specification Trip Level Settings for (1) the Emergency AC Bus loss of voltage and degraded voltage relays and timers, and (2) the Reactor Protection System (RPS) Normal Supply Electrical Protection Assembly (EPA) undervoltage trip.
Various administrative changes that are editorial in nature are also made in this application.
Extended STis are identified in the proposed Technical Specifications as being performed "once per 24 months" or "R." Those STis not extended are identified as being performed "once per 18 months" or "18M." These changes follow the guidance provided by Generic Letter 91-04, " Changes in Technical Specification Surveillance Intervals to Accommodate 24-Month Fuel Cycle," (Reference 1).
Ill.
TECHNICAL BASIS FOR THE PROPOSED CHANGES TO INSTRUMENTATION FUNCTIONAL TEST AND CAllBRATION FREQUENCY l
The instrument calibration extension program involves plant specific drift evaluations, loop accuracy /setpoint calculations, and system evaluations. These calculations and j
evaluations provide the technical basis for extending instrument calibration intervals to support a 24-month operating cycle.
The Authority's 24-month operatin0 cycle program, including drift analysis, setpoint calculation and drift monitoring, was discussed at a February 23,1993 meeting with NRC Staff members (Reference 2). The methodology presented below is the same as j
was used by the Authority in justifying instrument calibration extensions for the Indian i
Point 3 (IP3) Plant. This represents a generic approach in addressing calibration
, 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 9 of 50 extension issues and, as such, is applicable to the FitzPatrick Plant.
NRC Generic Letter 91-04 (Reference 1), Enclosure 2 provides guidance on the type of analysis and information required to justify a change to instrument calibration intervals. The approach taken in evaluating 24-month calibration extensions at the FitzPatrick Plant meets the requirements of this enclosure. Seven specific actions were delineated and are repeated below with the Authority's response. This discussion provides insight to the methodology used by the Authority in evaluating the effects of an increased STI on instrument drift. The effects of an increased STI on specific instrumentation are discussed in Section IV of this safety evaluation.
From Generic Letter 91-04, Enclosure 2:
- 1. Confirm that instrument drift as determined by as-found and as-left calibration data from surveillance and maintenance records has not, except on rare occasions, exceeded acceptable limits for a calibration interval.
- 2. Confirm that the values of drift for each instrument type (make, model, and range) and application have been determined with a high probability and a high degree of confidence. Provide a summary of the methodology and assumptions used to determine the rate of instrument drift with time based upon historicalplant calibration data.
- 3. Confirm that the magnitude ofinstrument drift has been determined with a high probability and a high degree of confidence for a bounding calibration interval of 30 months for each instrument type (make, model number and range) and application i
that performs a safety function. Provide a list of the channels by TS section that identifies these instrument application.
Instrument Drift Evaluations (IDES) were developed to address issues 1,2, and 3. The IDES document past performance and calculations to statistically extrapolate the effect of the longer calibration interval on instrument drift.
Historical calibration data for components currently calibrated once per 18 months was evaluated to assess the acceptability of extending the calibration interval to 24 months
(+25% for a maximum of 30 months). In general, the IDES are comprised of two phases. Phase 1 compares past instrument performance to theoretical acceptance limits (Vendor Drift Allowance (VDA) or Calibration Tolerance (CT)). Phase 2 predicts future drift by statistically extrapolating derived drift data to predict maximum expected drift over a 30 month interval (MED30).
The historical calibration data is the absolute value of the difference between the "as-found" and previous "as-left" calibration values. In addition to instrument drift, this data reflects instrument reference accuracy, measuring and test equipment uncertainties, and the effects of ambient environmental conditions (temperature, pressure, humidity,
o-
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 10 of 50 and radiation). Therefore, the term " drift" as used throughout the IDE actually represents total instrument calibration uncertainties.
Calibration data is collected and categorized by component type (instruments having the same manufacturer, model number, calibration span, and application) for analysis.
The tabulated drift values are then compared to theoretical acceptance limits (VDA or CT). If the derived drift data falls within these limits at least 80% of the time, past performance is considered acceptable (i.e. failures are considered a " rare occurrence").
Deviations from this criteria are evaluated on a case-by-case basis.
Phaso 2 of the IDE predicts future instrument performance over a maximum 30 month period using Phase 1 data. Field drift data is analyzed, using the square root of the sum of the squares technique, to arrive at a value normalized to a 30 month interval.
A value of MED30 is statistically derived from normalized field drift data. The MED30 value bounds hardware performance with a 95% probability at a 95% confidence level (i.e. there is a 95% probability that 95% of all past, present and future calibration results will be less than the maximum expected drift).
The MED30 value is then compared to the vendor drift allowance extrapolated to a 30 month time period (VDA30), or CT if vendor performance limits are not available. If MED30 is within VDA30 or CT, further analysis is not performed and the instrument is acceptable for extension to a 24 month STI. If MED30 exceeds VDA30 or CT, then further analysis is performed and loop accuracy and setpoint calculations are updated to include MED30.
The IDES associated with this Technical Specification amendment are references for this submittal and are included as Attachments. A more detailed description of the IDE methodology is contained in these references.
From Generic Letter 91-04, Enclosure 2:
- 4. Confirm that a comparison of the projected instrument drift errors has been made with the values of drift used in the setpoint analysis. If this results in revised setpoints to accommodate larger drift errors, provide proposed TS changes to update trip setpoints. If the drift errors issult in revised safety analysis to support existing setpoints, provide a summary of the updated analysis conclusions to confirm that safety limits and safety analysis assumptions are not exceeded.
- 5. Confirm that the projected instrument errors caused by drift are acceptable for control of plant parameters to effect a safe shutdown with associated instrumentation.
- 6. Confirm that all conditions and assumptions of the setpoint and safety analysis have been checked and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel checks, channel functional tests and
Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 11 of 50 channel calibrations.
The Authority has evaluated the effects of an increased calibration interval on instrument errors to confirm that drift will not exceed the conditions and assumptions of the setpoint and safety analysis.
Loop accuracy calculations were performed to determine total channel uncertainties by accounting for instrument inaccuracies. The methodology used is consistent with the methods described in ISA-RP-67.04 (Reference 3). Loop accuracy calculations for instrument channels generally use the most conservative choice between the vendor specified uncertainties and MED30. If MED30 is unreliable because too few data points were used for its estimation, the vendor specified uncertainty values are used.
Loop accuracy /setpoint calculations are required to show that sufficient margin exists j
between the analytical limit and the existing field trip setting to confirm that the safety analysis and safety limit assumptions are not exceeded. The calculations verify that Technical Specification limits provide sufficient margin over the analytical limit to allow for instrument inaccuracies.
If the loop /setpoint calculation shows that sufficient margin exists so that the assumptions of the safety analysis are not violated, reasonable assurance exists that the calibration interval may be safely extended. If the loop accuracy /setpoint calculation shows that insufficient margin exists, considering 30 month drift uncertainties, one of the following actions is taken: (1) the calibration interval is not extended, (2) new field trip setpoints are calculated and the setpoint is revised to ensure sufficient margin exists, or (3) analysis is performed to establish new Technical j
Specification Trip Level Settings that will ensure that safety actions are initiated consistent with the assumptions of the safety analysis.
Instrumentation requiring field trip setpoint changes are identified in Section IV.A and Table 1, List of Commitments. The safety implications of the Technical Specification Trip Level Setting changes are discussed in Section IV.B of this safety evaluation. All required instrument setpoint changes will be completed prior to implementing the 24-month surveillance test interval (STI).
Each instrument loop considered for extension to a 24-month STI is evaluated in a
" System Report." The System Report brings together the results of the IDE, loop accuracy /setpoint calculations, and surveillance history, and evaluates the results to determine if instrument drift resulting from the longer STI will result in exceeding safety limits or invalidating safety analysis assumptions. The System Report identifies the Technical Specification, procedure or field setpoint changes required for implementation of a 24-month STI. The applicable System Reports are references for this submittal and are included as Attachments.
o Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 12 of 50 From Generic Letter 91-04, Enclosure 2:
- 7. Provide a summary description of the program for monitoring and assessing the effects of increased calibration surveillance intervals on instrument drift and its effect on safety.
The evaluation process described above identifies the expected instrument drift for a 30-month calibration interval (MED30). Calculations have factored this drift into the selection of the nominal trip setpoints and Allowable Values (AV), as well as for the selection of As-Found acceptance criteria for calibration procedures. The Surveillance Testing Program requires that completed surveillance tests receive management review to ensure acceptance criteria is met, and a Deficiency Event Report (DER) be initiated for any instrument discovered to have exceeded its "as-found" tolerance. This process results in notification of plant management and evaluation of out of tolerance instruments to determine the cause. This evaluation will identify problems that develop as a result of the extended calibration interval.
The present process has set limits on instrument drift expected to occur during the increased calibration interval. Tha Surveillance Testing Program provides sufficient administrative controls to ensure that instrumentation experiencing excessive drift due to the longer calibration interval is identified and evaluated, and appropriate corrective action taken.
To ensure that the effects of instrument drift are properly evaluated, the Surveillance Testing Program will be enhanced to provide additional guidance for detecting additional and unexplained drift that can be attributed to the longer calibration interval.
If additional drift is verified, appropriate corrective actions will be taken to correct this condition. The Surveillance Testing Program changes will be completed prior to implementation of the 24-month STI extensions.
IV.
SAFETY IMPLICATION OF THE PROPOSED CHANGES I
This section evaluates the impact of the proposed changes on plant safety. The evaluation is divided into three groups of changes:(A) extension of instrumentation and miscellaneous STis to support 24-month operating cycles, (B) changes to Technical Specification Trip Level Settings, and (C) miscellaneous editorial, clarification and Bases changes. The heading for each specific Surveillance Requirement (SR) discussion contains an item number in parentheses. This number cross-references the item number in Section I, " Description of the Proposed Changes" for which the discussion applies.
a Attachment ll to JPN-96-003 instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 13 of 50 A.
Chanaes to Extend Instrumentation and Miscellaneous Surveillance Test Intervals to Sunnort 24-Month Oneratina Cveles 1.
Soecification 1.0.T (Chance I.A.1)
This specification defines the surveillance frequency notations / intervals used in the Technical Specifications. The definitions were added in Amendment 227 to permit the use of notations for surveillance test intervals on the instrument tables, and to relate all surveillance intervals to a consistent and precise time period. The note in Section 1.0.T clarifies "once per operating cycle," and similar phrases, by relating the interval to the definition of the frequency notation "R." The following changes are proposed to this specification:
The notation "R"is defined as " Operating Cycle" with a frequency of "At least once per 24 months (731 days)."
A new notation, "18M," is defined as "18 Months" with a frequency of "At least once per 18 months (550 days)."
Note 1 to the specification is deleted.
i All STI changes on the Technical Specification Volume 1 A Instrumentation Tables are made using the notations contained in this specification. All instrumentation currently having an "R" surveillance frequency notation in the instrumentation tables are evaluated for extension to the 24-month STI in the following sections of this safety evaluation. Those items that can be extended to a 24-month STl will remain with an "R" notation. Those items that can not be extended are denoted with an "18M."
Note 1 to this specification :s deleted because the changes proposed in this submittal, and past 24-month operating cycle STI extension submittals, have removed phrases such as "once each operating cycle,""once per operating cycle,""each refueling outage," "at least during each operating cycle," and "once each operating cycle not to exceed 18 months." These phrases have been replaced with phrases that specify the required time intervals such as "once per 24 months" and "once per 18 months."
These changes eliminate the need for the clarification provided in Note 1.
This proposed change has no impact on plant safety because it is an administrative change to the method by which STis are presented in the Technical Specifications.
Changes to specific STls are evaluated separately in the following discussions.
!^..
Attachment ll to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 14 of 50 l
2.
Reactor Protection Svstem (RPS) Instrumentation The RPS provides protection against the onset and consequences of conditions that threaten the integrity of the fuel cladding and reactor coolant pressure boundary. _ The RPS limits the uncontrolled release of radioactive material from the fuel and the reactor coolant pressure boundary by terminating excessive temperature and pressure increases through the initiation of an automatic scram.
The RPS has two independent trip systems (A and B) each normally powered from an AC motor generator set, through redundant electrical protection assemblies (EPAs).
The EPAs protect system components from damage due to sustained undervoltage (UV), overvoltage (OV) or underfrequency (UF) conditions. RPS trip systems A and B have two automatic scram trip channels (A1,A2 & B1,82 respectively) and one manual trip channel (A3 & B3 respectively). The outputs of the scram trip channels are arranged in a logic so that the trip of any channel will trip the associated trip system.
Tripping of both systems will initiate a reactor scram (one of two taken twice logic).
Functional diversity is provided by monitoring a wide range of dependent and independent parameters. The RPS willinitiate a scram on the following conditions:
High neutron flux Reactor coolant system high pressure e
o Reactor vessel low water level Turbine stop valve closure e
Turbine control valve fast closure e
Scram discharge instrument volume high water level High drywell pressure e
e Main steam line isolation e Manual scram o Reactor mode switch in " Shutdown" These trip functions provide rapid reduction of reactivity by insertion of all control rods into the core.
The RPS system uses instrumentation that is highly reliable and meets safety-related design criteria. The system has redundant and independent channels which provide a means to verify proper instrumentation performance during operation. The RPS has sufficient redundancy to ensure a high confidence in system performance even with the faibre of a single component. The RPS is designed to be tested during normal plant op.erations. Testirig consists of channel checks, instrument functional tests and instrumut channel calibrations. Gross instrument failures are detected by alarms and by comparison with redundant and independent indications. These surveillances provide assurance that the instrument channels are functioning properly.
1 NRC Bulletin 90-01, Supplement 1(Reference 4) established criteria for monitoring of
1 j
l Attachment ll to JPN-96-003 i
instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 15 of 50 certain model Rosemount transmitters considered susceptible to failures due to loss of l
fill oil. All Rosemount devices used in the RPS are exempt from additional sensor monitoring requirements based on the criteria established in Reference 4. Therefore, the loss of fill oil concern does not preclude extension of RPS transmitter calibrations to support a 24-month operating cycle.
Based on the redundant and highly reliable design of the RPS, and on-line testing that will identify degrading or failed equipment, the Authority has concluded that the impact on system reliability is small, if any, as a result of these calibration interval extensions.
i This conclusion is verified by the analysis of past and predicted performance discussed below. Extension of RPS surveillance test intervals was evaluated in Reference 5.
Evaluation of past and future drift for RPS instrumentation is contained in Reference 6.
j l
RPS Instrument Response Time Testing - SR 4.1.A (Change I.A.2)
This SR currently requires that the response time of the RPS trip functions listed in Specification 4.1.A be demonstrated at least once per 18 months. This testing verifies j
that RPS trip functions are completed within the time limits assumed in the accident and transient analyses. Each test consists of one instrument channel in each trip system, with all instrument channels in both trip systems being tested within two test intervals. In terms of the transient and accident analyces, the individual parameter response time interval begms when the monitored parameter exceeds the trip setpoint i
at the channel sensor and ends when the scram pilot valve solenoids are de-energized.
This SR can be extended to support a 24-month STI because of the redundant design of the RPS and adequate on-line testing to detect failures that could affect RPS response times. This conclusion is supported by a review of past surveillance test results that indicates all required acceptance criteria have consistently been met.
i Table 4.1 Reactor Protection System (Scram) Instrumentation Test Requirements item 1 Mode Switch in Shutdown Functional Test (Change 1.A.1)
The reactor mode switch is a multi-position keylock switch provided to actuate or bypass the vanoes scram functions appropriate to the particular plant operating mode.
Placing the switch b " Shutdown" enforces a reactor shutdown with all control rods inserted condition by inserting a reactor scram input into the RPS. The scram signal is removed after a 10 second time delay, permitting the scram to be reset and the Control Rod Drive Hydraulic system to be restored to a normallineup. This testing demonstrates the ability of the reactor mode switch to cause a reactor scram when the switch is placed in " Shutdown" and demonstrates that the time delay for the reset relays is 210 seconds. The change in the STI from 18 to 24 months is made by revision of the Specification 1.0.T definition of "R."
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Attachment il to JPN-96-003 instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 16 of 50 The scram inserted by the mode switch in " shutdown" position is not considered a protective function because it is not required to protect the fuel or the reactor coolant pressure boundary, and it bears no relationship to minimizing the release of radioactive material from any barrier. The reactor mode switch is a General Electric (GE) Type SB-9 switch designed for highly repetitive use. In the event of an undetected mode switch failure, the RPS will continue to provide automatic and manual scram capability.
Based on this discussion, the once per operating cycle mode switch in shutdown functional test can be safely extended to support a 24-month STi. A review of surveillance test history supports this conclusion.
Table 4.1 Reactor Protection System (Scram) Instrument Calibration Minimum Calibration Frequencies For Reactor Protection Instrument Channels (Change
- 1. A.1,1. A.3,1. A.4) i I
Item 3 Flow Blas Signal item 5 High Reactor Pressure item 6 High Drywell Pressure item 7 Reactor Low Water Level item 8 High Water Level in the SDIV (Group A)
Item 10 MSIV Valve Closure item 11 Turbine First Stage Pressure Permissive Item 12 Turbine Control Valve Fast Closure Oil Pressure Trip Item 13 Turbine Stop Valve Closure i
Note 4 Actuation of Switch By Normal Means for items 10 & 13 Note 6 Sensor Calibration Note for items 5,6,7 & 11 This table currently requires a once per operating cycle calibration for the above listed RPS System instrument channels to ensure that the instruments are properly calibrated and actuation takes place at previously evaluated setpoints. The change to the STI is made by revising the Specification 1.0.T definition of "R," and revising Note 4 (for Items 10 and 13) and Note 6 (for items 5,6,7 and 11) of Table 4.1-2 on page 47 of the Technical Specifications.
The review of past performance for items 5,6,7,8,11,12 and 13 confirmed that past drift values were within the specified calibration tolerances, except on rare occasions.
Therefore, this instrumentation has an acceptable past performance record as defined by Generic Letter 91-04.
, 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 17 of 50 i
Past drift for the APRM Flow Bias Signal (ltem 3) flow transmitters (Manufactured by Barton and Foxboro) routinely exceeded the specified calibration tolerance. As a result, they were replaced in 1993 with Rosemount transmitters. Square Root and Summing components of the APRM flow bias loop were found out of procedural tolerance in the past due to tight CT. New calibration tolerances have been calculated based on past performance and should bound future drift.
4 A review of past performance of the MSIV Limit Switches (Item 10) shows that these switches were within the specified CT, except on rare occasions. Therefore, the switches have an acceptable past performance record as defined by Generic Letter 91-
- 04. These limit switches have experienced problems during plant operation primarily due to failure of the switches to reset, and slow resets during the periodic MSIV limit switch instrument functional test. The majority of the limit switch failures were related to reset of the switches, rather than instrument drift. The failure to reset problem has been addressed by installation of modified actuating levers during the Reload 11/ Cycle 12 Refueling Outage.
Projected values of future drift were incorporated into loop accuracy calculations for items 5,6,8,11, and 12. The calculations determined that sufficient margin exists between the field trip settings and the analytical limit when the 30 month drift uncertainties are considered. For the APRM flow bias signal transmitters (Item 3), the i
projected drift of the new Rosemount transmitters is significantly less than the old transmitters eva!uated in the drift analysis using past drift data. Therefore, it is acceptable to extend the calibration interval for these instruments to support a 24 month operating cycle.
Extension of the calibration intervals for Items 7,10 and 13 requires changes to the field trip setpoints to ensure that Technical Specification limits will not be exceeded due to drift over the longer STI. Changes to the Technical Specification trip level setting listed on Table 3.1-1 are not required to support these field setpoint changes.
The field trip setpoint changes will be completed prior to implementation of the 24-month STI.
Reactor Protection System EPA Channel Calibration - SR 4.9.G.2 (Change A.1.18)
This SR currently requires a once per operating cycle calibration of the overvoltage (OV), undervoltage (UV) and underfrequency (UF) protective instrumentation. This includes simulated automatic actuation of relays, logic and output breakers.
Analysis of historical surveillance data confirmed that past drift values were within required calibration tolerance, except on rare occasions. Therefore, the EPAs have an acceptable past performance record as defined by Generic Letter 91-04.
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems i
SAFETY EVALUATION Page 18 of 50 Calculations, using projected values of future drift, determined that existing trip settings 3
for the Normal and Alternate EPA UF and OV trips, and the Alternate EPA undervoltage trips, are adequate to accommodate drift and uncertainties associated j
with a bounding 30 month calibration interval. Therefore, extension of these items to support a 24-month STI is acceptable.
Extension of the calibration interval for the Normal and Alternate EPA time delays is i
acceptable provided that changes are made to the field trip setpoints. These setpoint changes will ensure that sufficient margin is available to accommodate the projected drift and uncertainties associated with a 30 month calibration interval. Changes to the setpoints stated in Technical Specification 4.9.G.2 are not required to support these field setpoint changes. The field trip setpoint changes will be completed prior to implementation of the 24-month STl.
The loop accuracy calculations determined that extension of the calibration interval for the Normal EPA UV trip setpoints is acceptable provided that changes are made to the field trip setpoint and the Technical Specification Setpoint identified in Specification 4.9.G.2. The changes to the Technical Specification Setpoint are evaluated in Section IV.B of this safety evaluation. Extension of the calibration interval for the Normal EPA UV trip to support a 24-month STI is acceptable provided that these setpoint changes are implemented. The setpoint change will be completed prior to implementation of the 24 month STI.
3.
Primarv Containment Isolation System (PCIS) Instrumentation The PCIS initiates isolation of the primary containment if monitored plant parameters approach limits assumed in the plant safety analyses. This function is necessary to prevent or limit the release of radioactivity in the event of a loss of coolant accident (LOCA) or reactor coolant pressure boundary leak.
The PCIS uses instrumentation that is highly reliable and meets safety-related design criteria. The system has redundant and independent channels which provide a means to verify proper instrumentation performance during operation. The PCIS has sufficient redundancy to ensure a high confidence in system performance even with the failure of a single component. The PCIS is designed to be tested during normal plant operations. On-line testing consists of channel checks, functional tests, master / slave trip unit calibrations and logic system functional tests. For the Main Steam Line High Radiation instrumentation, an instrument channel calibration is performed quarterly using a current source. Gross instrument failures are detected by alarms and by comparison with redundant and independent indications. These on-line surveillances provide assurance that the instrument channels and trip systems are functioning properly.
I 4
Attachment ll to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 19 of 50 NRC Bulletin 90-01, Supplement 1 (Reference 4) established criteria for monitoring of certain model Rosemount transmitters considered susceptible to failures due to loss of fill oil. The Rosemount devices used for the reactor vessel level, main steam line flow, main steam line pressure, and the HPCI and RCIC steam line isolation functions require additional monitoring basad on the criteria established in Reference 4 The enhanced monitoring program, described in the Authority's response to Bulletin 90-01 l
Supplement 1 (Reference 7), consists of a daily operational instrument check, weekly operational verification check, response time testing and once per operating cycle drift monitoring. The once per operating cycle drift monitoring interval for this program was chosen to avoid the risks associated with performing on-line calibrations of this instrumentation. During power operations, hydraulic transients in the instrument sensing lines, coupled together by common piping, are known to cause safety function actuations or trips when instruments are valved in and out of service at operating pressure. Cahbration of these instruments at power exposes the plant to a possible transient that could challenge safety systems. Therefore, the once per operating cycle drift monitoring performed as a part of the enhanced monitoring program will be pedormed on a nominal 24-month interval (+25% for a maximum of 30 months).
Based on the redundant and highly rullable design of the PCIS, and on-line testing that will identify degrading or failed equipment, the Authority has concluded that the impact on system reliability is small, if any, as a result of these calibration interval extensions.
This conclusion is verified by the analysis of past and predicted performance discussed j
below. Extension of PCIS surveillance test intervals was evaluated in Reference 8.
Evaluation of past and future drift for PCIS instrumentation is contained in Reference 9.
j PCIS Instrument Response Time Testing - SR 4.2.A (Change 1.A.5)
This SR currently requires that response times of the Main Steam isolation Valve (MSIV) actuation trip functions listed in SR 4.2.A be demonstrated within specified limits once per 18 months. This verifies that trip functions are completed within the time limits assumed in the accident and transient analyses. Each test consists of one instrument channel in each trip system, with all instrument channels in both trip systems tested within two test intervals. The response time interval begins when the monitored parameter exceeds the trip setpoint at the channel sensor and ends when the MSIV pilot solenoid relay contacts open.
The safety analyses assume MSIV closure in $10.5 seconds for both off-site dose calculations and analysis of a main steam line break outside of containment. The Technical Specifications require an MSIV closure time of not less than 3 seconds or not greater than 5 seconds. The instrument response times for the reactor low level and low steam line pressure instrumentation is s1.0 second, and for high steam line flow is 5 5 seconds. Total closure time is a combination of the instrument response 2
time and the Technical Specification MSIV closure time. Combining these values (worst case would be 7.5 seconds) shows that there is margin available to accommodate potentially slower instrument response times due to drift without
, 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 20 of 50 presenting a safety concern.
This SR can be extended to support a 24-month operating cycle because of the redundant design of the PCIS, adequate on-line testing to detect failures that could affect PCIS response times, available margin to accommodate potentially slower response times, and a monitoring program in place to detect failures of these transmitters due to loss of fill oil. This conclusion is supported by a review of past surveillance results which indicates that all required acceptance criteria have consistently been met.
l l
Table 4.2 PCIS Instrumentation Test and Calibration Requirements (Changes l
1.A.1,1. A.9,1. A.10) l Item 2 Reactor Low-Low-Low Water Level item 3 Main Steam Line Tunnel High Temperature l
Item 4 Main Steam Line High Flow item 5 Main Steam Line Low Pressure item 7 Condenser Low Vacuum item 8 Main Steam Line Tunnel High Radiation item 9 HPCI & RCIC Steam Line High Flow item 10 HPCI & RCIC Steam Line/ Area High Temp item 11 HPCI & RCIC Steam Line Low Pressure This table currently requires a once per operating cycle sensor calibration of the above listed PCIS System trip functions to ensure that the instruments are properly calibrated and actuation takes place at previously evaluated setpoints. The change to the STI is made by revising the Specification 1.0.T definition of "R," and revising Notes 11 and 15 on page 84 of the Technical Specifications. The Note 11 reference to the built-in current source is deleted. An external current source is used to obtain required "as-found" and "as-left" calibration data.
Analysis of historical surveillance data confirmed that past drift values for all devices associated with these line items were within specified tolerances, except on rare occasions. Therefore, this instrumentation has an acceptable past performance record as defined by Generic Letter 91-04.
Projected values of future drift are incorporated into loop accuracy calculations for each listed PCIS trip function. The calculations determined that the calibration intervals for Items 2,3,4,8,10,11 and the RCIC Steam Line High Flow portion of item 9 can be extended to a 24-month STI because sufficient margin exists between the field trip setpoint and the analyticallimit considering 30 month drift uncertainties. Therefore, extension of the calibration intervals for these items to support a 24-month operating cycle is acceptable.
Extension of the calibration interval for items 5,7 and the HPCI Steam Line High Flow
Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 21 of 50 portion of item 9 requires a change to the field trip setpoints to ensure that the analytical limit is not exceeded due to drift over the longer calibration interval.
Changes to the Technical Specification trip level settings listed in Table 3.2-1 are not required to support these field setting changes. The field trip setpoint changes will be completed prior to implementation of the 24-month STl.
Table 4.2 PCIS Simulated Automatic Actuation Requirements (Change 1.A.8)
Item 1 Main Steam Line Isolation Valves, Main Steam Line Drain Valves, and Reactor Water Sample Valves item 2 RHR - Isolation Valve Control and Shutdown Cooling Valves item 3 Reactor Water Cleanup Isolation item 4 Drywell isolation Valves, TIP Withdrawal, and Atmospheric Control Valves item 5 SGT System and Reactor Building isolation item 6 HPCI Subsystem Auto isolation item 7 RCIC Subsystem Auto isolation Table 4.2-1 defines the Logic System Functional Test (LSFT) and Simulated Automatic Actuation (SAA) requirements for the PCIS system. The LSFT frequencies are not revised by this proposed amendment and remain at a six month frequency. The change to the SAA test intervalis made by revision of Note 7 on page 84 of the Technical Specifications.
The SAA testing confirms the ability of the PCIS to perform its intended function by confirming proper operation of electrical and mechanical components. The mechanical components in the system are highly reliable and have low service requirements.
These components are operated during normal plant operations and are tested periodically in accordance with the ASME Section XI Inservice Testing (IST) Program.
Initiating and actuation logic are subjected to periodic channel checks, functional tests,
)
and LSFTs. This on-line testing is adequate to verify proper system response and identify degrading or failed equipment. Gross instrument failures are detected by alarms and by comparison with redundant and independent indications.
The STI for SAA testing of the PCIS system may be extended based on the high reliability of system components, the redundant design of the PCIS and existing on-line testing. A review of historical surveillance data supports this conclusion.
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 22 of 50 4.
Core and Containment Coolina Instrumentation The instrumentation evaluated in this section consists of those that initiate and control the Emergency Core Cooling Systems (ECCS), containment cooling systems and the Reactor Core Isolation Cooling (RCIC) system.
The ECCS, in conjunction with other systems and structures, limits the release of radioactive materials to the environs following a postulated loss of coolant accident (LOCA) so that resulting radiation exposures are kept within the guideline values given in 10 CFR 100. This objective is primarily achieved by maintaining core inventory to prevent fuel damage. The ECCS consists of the following:
i High Pressure Coolant injection (HPCI) System e
Automatic Depressurization System (ADS)
=
Core Spray System Low Pressure Coolant injection (LPCI) mode of the Residual Heat Removal (RHR) o system The systems are designed to limit fuel clad temperature over the complete spectrum of possible break sizes in the Reactor Coolant Pressure Boundary, including the design basis break.
The Containment Cooling mode of the RHR system removes heat energy from the Primary Containment in the event of a LOCA. Each subsystem of the containment cooling mode of the RHR system consists of two RHR pumps, two RHR Service Water pumps, one RHR Heat Exchanger and a flowpath capable of recirculating water from the suppression pool through the heat exchanger and back to primary containment.
The RCIC system provides makeup water to the reactor vessel for periods when the normal heat sink is unavailable. The RCIC system also provides makeup water to the 1
reactor vessel during a total loss of alternating current (AC) electrical power (Station Blackout).
Instrumentation used in the Core and Containment Cooling Systems is highly reliable.
This instrumentation has redundant and independent channels which provide a means to verify proper instrument performance during operation. The ECCS instrumentation is designed with sufficient redundancy to ensure a high confidence of ECCS performance even with a single failure. On-line testing of these instruments includes channel checks, functional tests and master / slave trip unit calibrations. Gross instrument failures are detected by alarms and by comparison with redundant and independent indications. The on-line surveillances provide assurance that the instrument channels are functioning properly.
. to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 23 of 50 NRC Bulletin 90-01, Supplement 1 (Reference 4) established criteria for monitoring of certain model Rosemount transmitters considered susceptible to failures due to loss of fill oil. All Rosemount devices used in the core and containment cooling systems, with the exception of HPCI and RCIC steam line flow transmitters, are exempt from additional sensor monitoring requirements based on the criteria established in Reference 4. These steam line flow transmitters are associated with the isolation of the steam line and are discussed in the evaluation of PCIS instrumentation. Therefore, the loss of fill oil concern does not preclude extension of the core and containment cooling system transmitter calibrations to support a 24-month operating cycle.
Based on the redundant and highly reliable design of the Core and Containment Cooling Systems, and on-line testing that will identify degrading or failed equipment, the Authority has concluded that the impact on system reliability is small, if any, as a result of these calibration interval extensions. This conclusion is verified by the analysis of past and predicted performance discussed below. Extension of core and containment cooling system STls was evaluated in Reference 10 and 11. Evaluation of past and future drift for this instrumentation is contained in Reference 12.
Table 4.2 2 - Core and Containment Cooling System Instrumentation Test and Calibration Requirements (Changes 1.A.1,1.A.6 and 1.A.10)
Item 1 Reactor Water Level item 2b Drywell Pressure (ATTS)
Item 3b Reactor Pressure (ATTS)
Item 4 Auto Sequencing Timers item 9 4kV Emergency Bus Under-Voltage Relays & Timers Item 10 LPCI Cross Connect Valve Position This table currently requires a once per operating cycle calibration of items 1,2b,3b,4 and 9, and an instrument functional test for items 9 and 10, to ensure the instruments are properly calibrated and actuation takes place at previously evaluated setpoints.
j The calibration interval for Item 4 is not extended at this time because sufficient data is not available to properly evaluate the effects of the longer STI on instrument drift.
Calibration of these timers on an 18-month STI is not necessary to support a 24-month operating cycle because the testing can be done with the plant on-line. Therefore, the calibration frequency will be designated as "18M." The change to the STI for the remainder of the items is made by revising the Specification 1.0.T definition of "R," and revising Note 15 (for items 1,2b and 3b) on page 84 of the Technical Specifications.
l
l Attachment ll to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 24 of 50 The instrument functional test for the LPCI cross-connect valve position indication channel (Item 10) demonstrates that an annunciator alarms when either the LPCI cross-connect valve control room panel keylock switch is in the "Open" position or the LPCI cross-connect valve is not full closed. Review of historical data shows that there have been no recorded failures of this function during testing or operations. These devices are extremely reliable and do not exhibit time dependent performance failures.
The valve is verified locked closed on a monthly basis. Therefore, the safety function is verified more often than the STI and extension of this test interval to accommodate a 24-month operating cycle is acceptable.
Analysis of historical surveillance data for items 1,2b,3b, and 9 confirmed that past drift values for these devices were within the specified tolerances, except on rare occasions. Therefore, this instrumentation has an acceptable past performance record as defined by Generic Letter 91-04. A review of the 4kV emergency bus undervoltage and degraded voltage relays and timers functional test reveals that all required acceptance criteria have consistently been met.
Predicted values of future drift were incorporated into loop accuracy calculations for items 1,2b,3b and 9. The calculations determined that the STI for items 1,2b and 3b can be extended to support a 24-month operating cycle because sufficient margin currently exists between the field trip setpoint and the analytical limit considering 30 month drift uncertainties.
The STI for the instrument functional test and calibration of the 4kV emergency bus undervoltage relays and timers (Item 9) can be extended to support a 24-month operating cycle provided that changes are made to the field trip settings and the i
Technical Specification Trip Level Settings listed on Table 3.2-2. These changes will ensure that safety limits are not exceeded for the duration of the longer operating cycle. The field trip settings will be changed prior to 24-month STI implementation, j
The basis for the changes in the Trip Level Settings of Table 3.2-2 is discussed in Section IV.B of this safety evaluation.
i
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 25 of 50 Table 4.2 Core and Containment Cooling Systems LSFT and Simulated Automatic Actuation Requirements (Change 1.A.8)
Item 1 Core Spray Subsystem item 2 Low Pressure Coolant Injection Subsystem item 4 HPCI Subsystem item 5 ADS Subsystem Section 4.5 - Core and Containment Cooling Systems Surveillance Requirements (Changes 1.A.12 and 1.A.13) 4.5. A.1.a Core Spray Simulated Automatic Actuation Test 4.5. A.1.f Core Spray LSFT 4.5. A.3 LPCI Simulated Automatic Actuation Test and LSFT 4.5.C.1 HPCI Simulated Automatic Actuation Test and LSFT 1
Table 4.2-2 defines the Logic System Functional Test (LSFT) and Simulated Automatic
]
Actuation (SAA) requirements for ECCS logic. The SAA and LSFT requirements of ltems 1,2 and 4 are duplicated in Section 4.5.A.1,4.5.A.3 and 4.5.C.1 of the Technical Specifications. However, for the LSFT requirements, the surveillance frequency listed in Section 4.5 is once per operating cycle while the frequency listed in Table 4.2-2 is once per six months. The proper LSFT interval of once per six months is not revised by this proposed amendment. To resolve this discrepancy, the LSFT and SAA frequencies listed in Section 4.5 will be revised to reference the Surveillance Requirement in Table 4.2-2. The change to the STI is made by revision of Note 7 on page 84 of Technical Specifications.
Simulated Automatic Actuation testing confirms the ability of the ECCS to perform its intended function by confirming proper operation of electrical and mechanical components. Mechanical components of the system (pumps and valves) are tested periodically on-line in accordance with the ASME Section XI Inservice Testing (IST)
Program. ECCS initiation and actuation logic is subjected to periodic on-line channel checks, functional tests, and LSFTs. These on-line tests are sufficient to identify degrading or failed equipment. Gross instrument failures are detected by alarms and by comparison with redundant and independent indications.
It is acceptable to extend the SAA testing interval for these systems based on high reliability of system components, the redundant design of the ECCS and existing on-I.. i testing. A review of historical surveillance data supports this conclusion.
Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 26 of 50 4.5.E.1.a RCIC Simulated Automatic Actuation Test (Change 1.A.15) 4.5.E.1.f RCIC LSFT (Change 1.A.15)
SR 4.5.E.1.a and 4.5.E.1.f define the LSFT and Simulated Automatic Actuation (SAA) requirements for the RCIC system. The change to the STI is made by revision of the frequency from "Once/ operating cycle" to "Once per 24 months."
The SAA testing confirms the ability of RCIC to perform its intended function by confirming proper operation of electrical and mechanical components. The LSFT confirms that components are operable per the design intent by testing of relays and contacts of a logic circuit from sensor to actuated device. Mechanical components of the RCIC system are tested periodically _on-line in a manner similar to ASME Section XI Inservice Testing (IST) program testing of ECCS systems. RCIC system initiation and actuation instrumentation is subjected to periodic on-line channel checks and functional tests. These on-line tests are sufficient to identify degrading or failed equipment. Gross instrument failures are detected by alarms and by comparison with redundant and independent indications.
It is acceptable to extend the STI for RCIC system LSFT and SAA testing based on the high reliability of system components and existing on-line testing. A review of historical surveillance data supports this conclusion.
5.
Control Rod Block Instrumentation Test and Calibration Reauirements Table 4.2 Control Rod Block System Logic Check and Simulated Automatic Actuation Requirement (Change 1.A.7)
Table 4.2-3 currently requires a once per six month LSFT and once per operating cycle SAA testing for the control rod block instrumentation. This amendment proposes to eliminate the LSFT and SAA testing requirements because more frequent channel functional testing and calibration adequately test the control rod block circuitry.
The control rod block functions are provided to ensure fuel design limits are not 4
exceeded for postulated transients or accidents. The control rod block logic is arranged as two similar logic circuits that are energized when control rod movement is allowed. Each logic circuit receives input signals from the neutron monitoring system, reactor protection system, refueling interlocks, and the reactor recirculation system. A rod block signal is generated, and control rod withdrawal is inhibited, when one of the logic circuits is deenergized. Therefore, the trip logic is arranged in a 1 out of n configuration (e.g., any trip on one of the input signals will result in a rod block).
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page of 50 As defined in the Technical Specifications, SAA testing means applying a simulated signal to the sensor to actuate the circuit in question. This type of testing demonstrates that a logic circuit can perform its design function by applying simulated signals to the minimum number of sensors required to initiate the primary function of the logic system. Even though the SAA does not demonstrate that all contacts and coils in a system are operable, it does demonstrate that the minimum number of coils and enntacts required to achieve the system function are operational. The LSFT is a test of relays and contacts of a logic circuit frer, sensor to actuated device to ensure components are operable per design intent. 7nis testing demonstrates the ability of the subject system and components to respon9 to initiations, actuations, and interlocks per design intent.
Table 4.2-3 instrumentation is subjected to channel functional tests, calibrations, and i
instrument checks. The channel functional test verifies proper instrument channel response, alarm and initiating actions. The calibration adjusts the instrument signal output so that it corresponds, within acceptable range and accuracy, to a known value of the parameter which the instrument monitors. Calibration encompasses the entire instrument channel including actuation, alarm or trip. The instrument check qualitatively determines operability by observation of instrument behavior during operation. This determination includes, where possible, comparison of the instrument with other independent instruments measuring the same variable.
The channel functional tests and calibrations adequately test the control rod block functions. Because the control rod block logic is arranged in a "1 of n" configuration, a rod block signal is generated each time a channel functional test or calibration is performed. Therefore, these tests are equivalent to a simulated automatic actuation because the testing actuates the control rod block circuitry. This adequately demonstrates the control rod block circuit design function. In addition, because the circuit is a "1 of n" configuration, the functional testing and calibrations satisfy the requirements of an LSFT.
In consideration of the above, the Authority proposes deletion of the SAA and LSFT requirements in Table 4.2-3. This deletion will also make the periodic test requirements for the control rod block instrumentation consistem with BWR Standard Technical Specifications (References 24 and 25). Prior to imph mntation.of this amendment, the Authority will conduct a review of surveillance te: w procedures to verify that testing performed on the control rod block logic is consom"t with the requirements stated in the Standard Technical Specifications.
Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 28 of 50 6.
ATWS Recirculation Pumo Trio Instrumentation Table 4.2 ATWS Recirculation Pump Trip instrumentation Test and Calibration Requirements (Change 1.A.1)
Item 1 Reactor Pressure-High item 2 Reactor Water Level-Low Low This table currently specifies once per operating cycle channel calibration, SAA and LSFT of the Anticipated Transient Without Scram (ATWS) instrumentation. The change to the STI is made by revision of the Specification 1.0.T definition of "R."
Extension of these STis was evaluated in References 10 and 11. Evaluation of past and future drift is contained in Reference 12.
The ATWS recirculation pump trip circuitry limits the consequences of an ATWS event by tripping the recirculation pumps to reduce core flow and thereby reducing core power generation. The instrumentation used is highly reliable and independent from the reactor protection system. On-line testing consists of channel checks, channel functional tests and transmitter and trip unit calibrations. Gross instrument failures are detected by alarms and by comparison with redundant and independent indications.
Therefore, the Authority has concluded that the impact on system reliability is small, if any, as a result of extension of the instrument calibration interval. This conclusion is verified by the analysis of past and predicted future performance discussed below.
NRC Bulletin 90-01, Supplement 1(Reference 4) established criteria for monitoring of certain model Rosemount transmitters considered susceptible to failures due to loss of fill oil. All Rosemount devices used for the ATWS function are exempt from additional sensor monitoring requirements based on the criteria established in Reference 4.
Therefore, the loss of fill oil concern does not preclude extension of ATWS transmitter calibrations to support a 24-month STI.
The LSFT and SAA testing can be extended to a 24-month STI because the instrumentation used is highly reliable and independent, and there is sufficient on-line testing to verify operability of the system. A review of past surveillance test results supports this conclusion.
Analysis of historical calibration data confirmed that past drift values for these instruments were within specified tolerances, except on rare occasions. Therefore, the ATWS instrumentation has an acceptable past performance record as defined by Generic Letter 91-04. Predicted values of future drift were incorporated into loop accuracy calculations for each listed circuit. The calculations determined that the ATWS instrument calibrations can be extended to a 24-month STI because sufficient margin exists between the field trip setpoint and the analytical limit.
Attachment Il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 29 of 50 7.
Accident Monitoring Instrumentation Table 4.2 Minimum Test and Calibration Frequency for Accident Monitoring Instrumentation (Change 1.A.1 and 1.A.11)
Item 1 Stack High Range Effluent Monitor item 2 Turbine Building Vent High Range Effluent Monitor item 3 Radwaste Building Vent High Range Effluent Monitor item 4 Containment High Range Radiation Monitor item 5 Narrow Range Drywell Pressure item 6 Wide Range Drywell Pressure item 7 Drywell Temperature item 8 Wide Range Torus Water Level item 9 Torus Bulk Water Temperature item 10 Torus Pressure item 12 Reactor Vessel Pressure item 13 Fuel Zone Reactor Water Level item 14 Wide Range Reactor Water Level item 15 Core Spray Flow item 16 Core Spray Discharge Pressure item 17 LPCI (RHR) Flow item 18 RHR Service Water Flow item 20 Narrow Range Torus Water Level item 21 Drywell-Torus Differential Pressure This table currently requires a once per operating cycle calibration for all of the above listed instruments and a once per operating cycle instrument functional test for Items 1, 2,3 and 4. The calibration and functional test STI for items 1,2 and 3 is not extended at this time because past performance does not justify the STI extension. Functional testing and calibration of these items on an 18 month frequency does not impact implementation of the 24-month operating cycle because the testing can be done with the plant on-line. The instrument Functional Test and Calibration STI for Items 1,2 and 3 will be denoted as "18M" on Table 4.2-8. The changes to the STI for the remainder of the items is made by revising the Specification 1.0.T definition of "R."
The instrumentation listed in Table 4.2-8 provides reliable information to plant operators to monitor transient plant behavior and to verify proper safety system performance following an accident. The instrumentation conforms with the acceptance criteria of NUREG-0737, NUREG-0578, and Generic Letter 83-36 and includes Regulatory Guide 1.97 Type A variables. Extension of these surveillance test intervals was addressed in References 8,10,14, and 15. Evaluation of past and predicted drift of this instrumentation was evaluated in References 9,12, and 16.
Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 30 of 50 On-line testing for these instruments includes periodic instrument checks. In addition, by comparing a reading of each channel to the reading of redundant or related instruments, a nearly continuous surveillance of instrument performance is available.
item 4 requires a once per operating cycle instrument functional test and calibration of the containment high range radiation monitors. The containment high range radiation monitors consist of two physically separated, redundant radiation detectors that provide information on the extent of core damage following an accident. The monitors also provide isolation signals to the PCIS to shut the Drywell and Torus vent and purge valves on high drywell radiation. Analysis of historical surveillance data confirmed that past drift va:ues for the containment high range radiation monitors were within the specified tolerances, except on rare occasions. Therefore, these monitors have an acceptable past performance record as defined by Generic Letter 91-04. Postulated values of future drift were incorporated into loop accuracy calculations for these monitors. The calculations determined that sufficient margin exists between the field i
trip setpoint and the analyticallimit when the 30 month drift uncertainties are considered, provided that the field trip setpoint is changed. Changes to the Technical Specification trip setting is not required to support this change. The field trip setting will be changed rior to implementation of a 24-month STl.
Analysis of historical surveillance data for the remainder of the above listed items confirmed that past drift values for all these devices were within the specified tolerances, except on rare occasions. Therefore, this instrumentation has an acceptable past performance record as defined by Generic Letter 91-04.
Predicted values of future drift were incorporated into loop accuracy calculations for each listed circuit. The calculations determined that theso items can be extended to a 24-month STI because the increase in channel uncertainty due to drift from the longer operating cycle is minimal, and considered to be negligible.
8.
Remote Shutdown Instrumentation Remote Shutdown Capability instrumentation and Controls (Change 1.A.1)
Table 3.2-10 Note C instrument Calibration for Each Required Instrument Channel Note D Demonstrate Control Circuit and Transfer Switches Function This table currently requires a once per operating cycle calibration of all required instrument channels, and demonstration that each required control circuit and transfer / isolation switch is capable of performing its intended function.. Operability of components, such as pumps and valves, that are controlled from these panels is covered by other specifications. The format of this table has been changed to make it consistent with Technical Specification Amendment 227 and BWR Standard Technical
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 31 of 50 Specifications (Reference 25). These changes are discussed in Section IV.C of this safety evaluation. Changes to the STI is made by revising the Specification 1.0.T definition of "R."
Extension of these surveillance test intervals was addressed in References 13 and 15. Evaluation of past and future drift for the instrumentation was evaluated in Reference 16.
Remote shutdown capability is provided by the Remote Shutdown Panel (25RSP) and five Alternate Shutdown Panels (25 ASP-1,2,3,4 & 5), in conjunction with the ADS Relief Valve Control Panel, the EDG Control Panels, the Reactor Building Ventilation and Cooling Control Panel, and Instrument Racks 25-6 and 25-51. This capability ensures that sufficient instrumentation and controls are available to place and maintain the plant in a safe shutdown condition should the control room become uninhabitable.
Analysis of historical surveillance data for the remote shutdown instrumentation confirmed that past drift values for all these devices were within the specified tolerances, except on rare occasions. Therefore, this instrumentation has an acceptable past performance record as defined by Generic Letter 91-04. Predicted values of future drift for these instruments were incorporated into loop accuracy calculations to ensure that sufficient margin exists between the field trip setpoint and the analytical limit, when 30 month drift uncertainties are considered. The results
)
support the calibration interval extension for a majority of the components, while i
postulated drift for the balance of the instruments can be accommodated for by minor procedural changes in calibration tolerance. Therefore, the instrument calibrations can be extended to a 24-month STI.
i A review of past performance of the control circuit and transfer switch functional tests show no test failures. Therefore, extension of the STI for the control circuit and transfer switch functional test can be extended to support a 24-month operating cycle.
9.
Miscellaneous Instrumentation Calibrations and Functional Tests Standby Gas Treatment (SGT) System Differential Pressure Switch Calibration -
SR 4.7.B.1.f (Change 1.A.16)
This SR currently requires calibration of the SGT system differential pressure switches once per operating cycle. Extension of the calibration intervals for the above listed instruments is evaluated in Reference 13. Evaluation of past and future drift for the above instruments is contained in Reference 17.
The SGT system maintains the secondary containment at a negative pressure with respect to the environment to control reactor building leakage and provide filtration for removal of particulates and iodines prior to release from the main stack. The system consists of two redundant full capacity air filtration trains that ensure availability of the system in the event of a failure that disables one filter train. The system is normally in a standby condition, therefore gross plugging or fouling of the filters is minimized.
Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 32 of 50 Individual filter differential pressures are monitored during periods of system operation.
The function of these differential pressure switches is to monitor the SGT filter train for mechanical failure or filter blockage, and provide annunciation in the Control Room of this condition.
Based on the redundant design of the SGT system, the normal standby condition of the system, and monitoring of filter differential pressures during periods of system operation, the Authority has concluded that the impact on system reliability is small, if any, as a result of this change.
Analysis of past instrument performance confirmed that drift values for these devices have been within the specified tolerances, except on rare occasions. Predicted values of future drift were incorporated into loop accuracy calculations for these circuits. The calculations determined that sufficient margin exists between the field trip setpoint and the analyticallimit when the 30 month drift uncertainties are considered. Therefore, the calibration interval for the SGT differential pressure instrumentation can be extended to 24-months.
SR 4.11.A.3 Control Room Ventilation Temperature Transmitter and Differential Pressure Switch Calibrations (Change 1.A.19)
The Control Room is served by two full capacity redundant units which consist of air handling units, recirculation exhaust fans, special filter trains and emergency control room supply fans. This system is completely independent from other plant heating, ventilating, and air conditioning systems, which ensures operation during normal, shutdown, and design basis accident modes, instrumentation is provided to monitor the status of the system, control area temperatures, and start redundant units in the event of an equipment failure.
The Control Room emergency ventilation system consists of two filter trains, each consisting of a pre-filter, High Efficiency Particulate Air (HEPA) filter, two charcoal filters in series and a second HEPA filter. The filter trains are 100% capacity redundant units designed to supply up to 1000 cfm of clean filtered outside air for breathing and maintain a positive pressure in the control room. This system is manually initiated during a design basis accident, if radiological conditions warrant.
This SR currently requires calibration of the temperature transmitters and differential pressure indicating switches (DPIS) once per operating cycle. Extension of the calibration intervals was evaluated in Reference 18. Evaluation of past and future drift for the above instruments is contained in Reference 19.
j A review of drift data for DPIS switches and temperature transmitters indicates that drift values were within the required calibration tolerance, except on rare occasions.
Therefore, the instrumentation has an acceptable past performance record as defined in Generic Letter 91-04. Review of past drift data for the normal ventilation supply and
L Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 33 of 50 exhaust fan DP switches indicates that the drift values exceeded specified calibration tolerance on more than rare occasions. As a result, they have been replaced with newer model switches. Past drift for the temperature indicating controllers has exceeded the CT on more than rare occasions with four out of the five failures occurring in 1988 or before. Past drift for the emergency trains differential pressure switches has exceeded the CT on more than rare occasions. All these failures were minimally above CT and did not jeopardize the switch design function. New calibration tolerances have been calculated for these instruments based on past performance to bound future drift.
Predicted values of future drift were incorporated into loop accuracy calculations for these instruments. New calibration tolerance bands for the DPS, DPIS and certain temperature instrumentation were calculated based on past instrument performance.
No field setpoint changes are required as a result of the newly calculated cts. The calculations determined that future drift over the longer STI is predicted to remain within the existing or revised calibration tolerance.
The calibration STI for this instrumentation may be extended to 24 months because the redundancy of the system provides assurance that the system will be operable in all required modes. The results of the IDE for these instruments support the extension for a majority of the components, while predicted drift for the balance of the instruments can be accommodated for by minor procedural changes in calibration tolerance. In all cases the field trip settings are not affected.
SR 4.11.B.2 Crescent Area Unit Cooler Temperature Control Instrumentation Calibrations (Change 1.A.20)
The Reactor Building crescent area houses the ECCS and other safeguards equipment and associated auxiliaries. The crescent area unit coolers maintain temperatures within design limits of the safeguards equipment to ensure continued operability of this equipment during and following a design basis accident. Eight of the ten unit coolers are equipped with a temperature switch that starts the associated unit cooler fan when temperature reaches a predetermined setpoint. The remaining two unit coolers are equipped with temperature indicating controllers that modulate the cooling water supply to each of the coolers while the associated fans run continuously.
This SR currently requires calibration of this instrumentation once per operating cycle.
Extension of the STI was evaluated in Reference 18. Evaluation of past and future drift for the above instruments is contained in Reference 19.
A review of drift data for the fan control temperature switches and the temperature indicating controllers indicates that drift values were within the required calibration tolerance, except on rare occasions. Therefore, the instrumentation has an acceptable past performance record as defined in Generic Letter 91-04.
1
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 34 of 50 Predicted values of future drift for these instruments were incorporated into loop I
accuracy calculations to ensure that sufficient margin exists between the field setpoint and the analyticallimit considering 30 month drift uncertainties. The results support the extendon of the calibration interval for the temperature control instrumentation.
SR 4.11.C.2 Battery Room Ventilation Temperature Transmitter and Differential 1
Pressure Switch Calibrations (Change 1.A.21)
The battery room ventilation system provides ventilation and maintains station battery room temperatures within design limits. The system is independent of other plant ventilation systems which ensures operation of the system during normal, shutdown and accident conditions. Each of the two battery rooms is supplied by a full capacity system that includes one air handling unit (AHU), two exhaust fans and one recirculation fan. These units are manually started. Temperature controlis provided by modulating the recirculation dampers and heating coil controls in response to a thermostat. Alarms are provided in the Control Room to indicate equipment malfunctions.
This SR currently requires calibration of this instrumentation once per operating cycle.
Extension of the calibration intervals was evaluated in Reference 18. Evaluation of past and future drift for the above instruments is contained in Reference 19.
A review of past drift data for the temperature control instrumentation indicates that drift values were within the required calibration tolerance, except on rare occasions.
The temperature transmitters and switches experienced failures that exceeded the CT in May,1994. When this instrumentation was recalibrated in 1995, the results were well within the CT. Therefore, the problem experienced with the temperature instrumentation is considered a rare occurrence and this instrumentation has an acceptable past performance record as defined in Generic Letter 91-04.
A review of past drift data for the differential pressure switches indicates that drift has exceeded the CT on more than rare occasions. These failures were on the AHU and recirculation fan switches, which provide annunciation only and do not perform a safety-related function, and the exhaust fan switches which provide an automatic start for the exhaust fans. New CT's have been calculated for these instruments based on past performance to bound future drift.
Predicted values of future drift for these instruments were incorporated into loop accuracy calculations to ensure that sufficient margin exists between the field trip setpoint and the analyticallimit, when 30 month drift uncertainties are considered. The results support the extension for a majority of the components, while predicted drift for the balance of the instrurnents can be accommodated for by minor procedural changes in calibration tolerance. In all cases the field trip settings are not affected.
T
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 35 of 50 RETS SR 3.7.a,3.7.b.2 and 3.7.b.3 Off-Gas System Explosive Gas Instrumentation Channel Functional Test and Instrument Calibrations (Changes 1.A.22,1.A.23,1.A.24,1.A.25)
This SR currently requires calibration and functional testing of the Off-gas (OFG) treatment system instrumentation once per operating cycle. This instrumentation consists of the OFG dilution steam flow, recombiner inlet / outlet temperature, and recombiner hydrogen indication instruments.
Extension of the calibration intervals was evaluated in Reference 18. Evaluation of past and future drift for the above instruments is contained in Reference 19.
The OFG system processes, holds and controls the main condenser off-gases to ensure that gases released from the main stack to the environment are below regulatory limits. To ensure that the concentration of explosive gases remains below design limits, the system continuously recombines the hydrogen (H,) and oxygen (0 )
2 to form steam. Prior to recombination, the gas mixture is diluted with steam to reduce the H, concentration to <4% by volume. This dilution ensures that the gas mixture is maintained below the flammable concentration for hydrogen. The recombiner system also reduces the volume of offgas to ensure adequate holdup time for the decay of short-lived radioactive isotopes of noble gas and iodine.
The primary method of ensuring that the hydrogen concentration is within acceptable limits is direct monitoring of this parameter. This monitoring is provided by redundant hydrogen analyzers. If continuous monitoring is not available, alternate monitoring methods use the dilution steam flow and recombiner inlet / outlet temperature instruments. When H, monitoring is not available, Radiological Effluent Technical Specification (RETS) 3.7.c requires weekly verification of H content less than or equal i
2 to 4% by volume.
Operation of the explosive gas mixture instruments is verified by a daily instrument check and once per operating cycle channel calibration and functional tests.
Calibration of the H, analyzer is performed quarterly in accordance with the vendors recommendations. This is more frequent than is required by RETS.
A review of past drift data for the steam flow and recombiner temperature instruments indicates that drift values were within the required calibration tolerance, except on rare occasions. Therefore, the instrumentation has an acceptable past performance record as defined in Generic Letter 91-04.
Past drift for the hydrogen analyzers has exceeded the CT on more than rare occasions. Review of H, analyzer performance shows that the STI can not be extended for these instruments. The manufacturer recommends that these units be calibrated once per quarter. New RETS SR 3.7.b.4 is being added to require calibration of these instruments once per quarter. Changing the STI to once per
l Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 36 of 50 quarter will not affect the ability to operate the plant on a 24-month operating cycle because the calibration can be performed with the plant on-line.
Predicted values of future drift for the dilution steam flow and recombiner temperature instruments were incorporated into loop accuracy calculations to ensure that sufficient margin exists between the field setpoint and the analytical limit considering 30 month drift uncertainties. The results support the extension of the calibration interval for these instruments.
Technical Specification SR 3.7.b.2 and SR 3.7.b.3 apply to the dilution steam flow and recombiner temperature instrumentation and are revised to an STI of 24 months. New l
SR 3.7.b.4 applies to calibration of the H, analyzers and will require an STI of once per quarter.
Calibration Frequency for Radiation Monitoring Systems (Changes 1.A.27 and
- 1. A.28)
RETS Table 3.10-2 Item 10 Liquid Radwaste Discharge Flow Rate Measuring Devices Instrument Channel Calibration item 11 Liquid Radwaste Discharge Radioactivity
)
Recorder instrument Channel Calibration This table currently requires a once per operating cycle calibration for the above listed j
instrument channels. The STI for Item 10 is not extended at this time because past performance does not justify extension. The instrument channel calibration interval for Item 11 is not extended because insufficient data is available to justify the extension.
The STI for items 10 and 11 will be denoted as "Once per 18 Months." This does not affect the ability to operate the plant on a 24-month operating cycle because the testing can be performed with the plant on-line. These STI changes were evaluated in 1
Reference 14.
The STI for these items remains at once per 18 months. The changes in notation from "Once per Operating Cycle" to "Once per 18 Months" clarify the testing requirements, and therefore are administrative in nature and have no safety implications.
RETS Simulated Automatic Actuation and LSFT Requirements (Changes 1.A.26, 1.A.29 and 1.A.30) 1 Table 3.10-2 Item 3 Reactor Building Area Exhaust Monitors, Recorders and Isolation Simulated Automatic Actuation (Note f)
Item 6 SJAE Radiation Monitors /Offgas Line isolation Simulated Automatic Actuation (Note f)
Item 8 Mechanical Vacuum Pump Isolation Simulated Automatic Actuation (Note f) and LSFT
, 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 37 of 50 Item 9 Liquid Radwaste Discharge Monitor / Isolation Simulated Automatic Actuation (Note f) ltem 12 Normal Service Water Effluent (Note f) i item 13 SBGTS Actuation (Note f)
Table 3.10-2 defines the LSFT and SAA requirements for the radiation monitoring system. The LSFT STI for items 3,6,9 and 13 are not revised by this proposed amendment and remain at six months. The LSFT frequency for item 8 is changed from "Once per Operating Cycle" to "Once per 24 Months" by revision of the Table 3.10-2 notation. The change to the SAA surveillance test interval is made by revision i
of Note f on page 39 of the RETS. The SAA requirement denoted for item 12 by Note f is deleted. These changes were evaluated in References 8,14,18 and 20.
The SAA testing of the reactor building area exhaust monitor isolation (Item 3) demonstrates the ability of the logic systems to isolate reactor building ventilation, shut primary containment vent and purge, atmosphere control, sampling and pressure sensing isolation valves, and initiate the SGT system upon receipt of a trip signal from the reactor building ventilation exhaust radiation monitors. These monitors provide a trip signal if one monitor senses radiation levels exceeding the high-high trip setpoint, or if both monitors have a downscale trip. This instrumentation is subjected to periodic on line functional testing, channel calibration and instrument checks that will identify degraded or failed equipment. The surveillance test and work history review reveals no failures that prevented isolation of the above systems, or initiation of the SGT system in response to a high radiation condition.
Simulated automatic actuation testing of the off-gas line isolation (item 6) demonstrates the ability of the off-gas system to automatically isolate on a simulated high radiation condition. The OFG isolation logic is subjected to periodic on-line functional testing to verify proper response and identify degrading or failed equipment. A review of surveillance test and work history revealed no failures of the OFG system that would prevent isolation in response to a high radiation condition.
l Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 38 of 50 The SAA testing of the mechanical vacuum pump isolation (Item 8) demonstrates that the condenser air removal pump will trip and isolate in response to a main steam line high radiation signal. The LSFT confirms that components are operable per the design intent by testing of relays and contacts of the logic circuit from sensor to actuated device. The condenser air removal pumps are normally shutdown and isolated except during plant startup. On-line testing consists of periodic testing of pump and valve operability and functional tests of the instrument channels that initiate isolation. This testing provides assurance that malfunctions of the pumps, valves and instrument I
channels will be detected. A review of surveillance test and work history revealed no failures that would prevent this isolation in response to a high radiation condition.
The SAA testing of the liquid radwaste discharge radiation monitors (item 9) demonstrates that a high-high trip of the monitors will result in closure of the liquid radwaste discharge valves. On-line testing consists of trip setpoint calibration of the monitor and calibration of the monitor using a known source at the detector. Review of historical surveillance data shows no failures to meet acceptance criteria and no corrective actions required for operability.
SAA testing of the SGT system (Item 13) ensures, in conjunction with other system tests, that the system is capable of performing its design safety function. System i
instrumentation is periodically tested on-line. System motor operated valves are cycled and the fans are started periodically to verify operability. The SGT system has redundant filter trains and is normally in the standby condition. Therefore, extension of this STI to 24 months is acceptable. Review of historical surveillance data supports this conclusion.
Based on periodic on-line testing and review of surveillance history, it is acceptable to extend the simulated automatic actuation STI for the above systems (Items 3,6,8,9 and 13), and the LSFT STI for item 8, to support 24-month operating cyc!es.
This amendment proposes to delete the SAA testing requirement for the Normal Service Water Effluent instrument channel (Item 12). This monitor provides indication of the normal service water effluent radioactivity level, and annunciation if this level exceeds preset limits. The monitor has no isolation function. A quarterly instrument channel functional test and calibration is performed that verifies the indication and alarm functions. During calibration, a source check is performed to ensure that the detector responds properly to a known source of radioactivity. This combination of testing meets the intent of the SAA testing, which is to actuate the circuit in question oy applying a simulated signal to the sensor. Therefore, the once per operating cycle SAA testing requirement for this instrumentation is redundant to testing performed on a quarterly basis. Deleting the SAA requirement for the Normal Service Water Effluent Monitor is acceptable because this instrument loop has no isolation function, and is adequately tested during the quarterly instrument channel functional tests and calibrations.
a Attachment Il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 39 of 50 10.
Non-Instrumentation Related 24-Month Ooeratino Cvele Changes SR 4.5.A.3.b Verification of RHR Cross-Tie Valves Closed and Locked (Change 1.A.14)
This SR verifies that the RHR cross-tie manual valve (10RHR-09) and motor operated valve (10MOV-20) are locked closed and power is removed from the MOV operator once per operating cycle. Maintaining these valves closed ensures that each LPCI subsystem remains independent and a failure of the flowpath in one subsystem will not i
affect the flowpath in the other.
Valve 10MOV-20 is disabled in the closed position with electrical leads disconnected, j
the breaker in the off-position, and thermal overloads removed. In addition, the operator is chain locked to prevent manual operation. Valve 10RHR-09 is closed with
^
a locking device positioned so that the valve can not be opened without removing the locking device. The MOV is equipped with an annunciator which alarms in the Control Room when the valve is not in the fully closed position.
7he cross-tie valves are verified locked closed once every month, and prior to startup.
j The frequency of the LPCI cross-tie verification as listed in the BWR Standard Technical Specifications (Reference 25) is once per 31 days. This change proposes that the STI for SR 4.5.A.3.b be reduced to once per month to make it consistent with actual plant practice and Reference 25.
SR 4.7.D.1.b Instrument Line Excess Flow Check Valve Testing (Change 1.A.17)
This SR currently requires that the instrument line excess flow check valves be tested for proper operation once per operating cycle. Extension of this item was evaluated in Reference 13.
The Primary Containment is penetrated by small diameter instrument lines that are connected to the reactor coolant system and dead ended at instruments located in the Reactor Building. Each of these lines contain a 0.25 inch restricting orifice located inside primary containment, a manual valve, and an excess flow check valve located outside primary containment. The excess flow check valve minimizes the leakage into the secondary containment in the event of a break in the instrument line downstream i
of the valve. The 0.25 inch orifice will reduce the blowdown due to a break in the instrument line and a failure of the excess flow check valve to a rate that will not result in secondary containment overpressurization. Therefore, the consequence of an excess flow check valve failure following an instrument line break is minimal.
Attachment ll to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 40 of 50 A review of surveillance test data from 1988 to the present shows a failure rate of approximately two percent. Therefore, based on design redundancy and past performance, it is concluded that instrument line excess ficw check valve testing can be extended to a 24-month STI.
B.
Chanaes to Technical Snecification Trio Level Settinas 1.
Chanaes to the Trio Level Settinos of 4kV Emeraency Bus Undervoltaae and Degraded Voltage Relavs and Timers (Changes 1.B.1 through 1.B.5)
A calculation (Reference 21) was performed to determine the total channel uncertainties associated with the 4kV Emergency Bus undervoltage trip system relays and time delays over a 24-month operating cycle. Based on results of this calculation, the following changes to the Table 3.2-2 Trip Level Settings are required:
Table 3.2-2 Item Present TS Trip Level Proposed TS Trip Level Setting Setting Item 26-Degraded 110.6 1.2 110.6 0.8 Voltage relay secondary volts secondary volts Item 27-Degraded 9.0 1.0 8.96 0.55 Voltage Timer (LOCA) seconds seconds Item 28-Degraded 45 5.0 43.8 2.8 Voltage Timer (Non-seconds seconds LOCA)
Item 29-Loss of 85 4.25 85 4.81 Voltage Relay secondary volts secondary volts item 30-Loss of 2.50 0.05 2.50 0.11 Voltage Timer seconds seconds These changes are necessary for the Authority to implement a 24-month STI. The new Trip Level Settings were calculated using the methodology of ISA-RP-67.04, Part ll (Reference 3). The calculation (Reference 21) supporting these changes is included as an Attachment to this submittal.
i The Emergency Bus Undervoltage Trip System transfers the 4kV emergency electrical buses to the Emergency Diesel Generators (EDGs) in the event that an undervoltage condition is detected. The system has two levels of protection: (1) degraded voltage protection, and (2) loss of voltage protection. Degraded voltage protection prevents a sustained low voltage condition from damaging safety-related equipment. The degraded voltage protection has two time delays. A short time delay coincident with a
Attachment ll to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 41 of 50 LOCA, and a longer time delay with no LOCA signal present, to prevent unnecessary starting of the EDGs during normal plant evolutions which may cause transient degraded voltage conditions. The loss of voltage protection prevents a more severe voltage drop from causing a long-term interruption of power. Time delays are included in the system to prevent inadvertent transfers due to spurious voltage decreases.
Therefore, both the duration and severity of the voltage drop are sensed by the Emergency Bus Undervoltage Trip System.
The degraded voltage protection trip level setting is presently at 110.6 secondary volts (approximately 93% of 4,160 volts on the bus) with a 9.0 second time delay if coincident with a LOCA, and a 45 second time delay for non-LOCA conditions. This trip provides protection for safety-related loads from thermal damage, or tripping of protective devices, due to degraded voltage conditions. Previous analysis has shown that the 600 V bus must be maintained at 90% of nominal at the load center bus to ensure proper operation of safety-related 600V loads, Motor Control Center (MCC) control circuits and control circuits fed from 120V AC buses. To maintain 90% nominal voltage at the 600V bus, a minimum of 92% nominalis required at the 4,160V bus.
The setting of 93% of nominal takes into account instrument inaccuracies. The proposed change tightens the tolerance for the degraded voltage setpoint based on the actual drift history of the relays.
The degraded voltage protection time delay settings are designed to allow for recovery of bus voltage due to momentary voltage dips caused by starting of large motors during normal operation, the transfer of loads during startup and sequential starting of ECCS pump motors during accident conditions. The time delays ensure that the maximum time delays assumed in the accident analyses are not exceeded, while providing protection for safety-related loads in the event of a degraded voltage condition. The proposed changes revise the settings of both degraded voltage time delay relays to account for instrument inaccuracies, and tighten the setpoint tolerances based on predicted future drift of the relays.
The 4kV emergency bus undervoltage trip level setting is presently 85 secondary volts (approximately 71.5% of 4,160 volts on the bus) with a 2.5 second time delay. The voltage setting is high enough to allow for proper operation and protection from damage to 4kV safety-related motors, and is low enough to prevent a trip due to a momentary voltage drop caused by normal starting of any motor in the plant. The 2.5 second time delay is long enough to assure proper coordination with protective devices, yet short enough to be less than the maximum time delay assumed in the FSAR analysis. The proposed changes expand the tolerance for these setpoints to accommodate drift predicted for the longer STI.
Attachment il to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 42 of 50 The proposed Trip Level Setting changes for the 4kV undervoltage and degraded voltage protection relays and timers are adequate to ensure that the emergency AC electrical system performs as assumed in the transient and accident analysis. These changes are necessary to accommodate instrument drift predicted for the duration of a 24-month operating cycle. The field trip setpoints will be revised consistent with these proposed Trip Level Settings prior to implementation of a 24-month STI.
2.
Changes to the RPS Normal Sucolv EPA Undervoltage Trio Settina in SR 4.9.G.2 (Chanae 1.B.6)
A calculation (Reference 22) was performed to determine the total channel uncertainties associated with the Normal RPS EPA trip setpoints over a 24-month operating cycle. This calculation also considered the results of a voltage drop evaluation performed or; me RPS system (Reference 23). Based on the results of this calculation, the RPS MG Set Source Undervoltage (UV) setpoint specified in SR 4.9.G.2 requires revision from its present value of 2 108V to 2 112.3V. The field trip setpoint for the Normal RPS EPA UV trip has been raised to address the issue of voltage drop, however, the setpoint specified in SR 4.9.G.2 requires revision to correct the present Technical Specification limit. The new setpoint was calculated using the methodology of ISA-RP-67.04, Part II (Reference 3). The referenced calculations are included as an Attachment to this submittal.
The Reference 23 evaluation analyzed the impact of the voltage drop from the EPAs to the scram pilot valve solenoids and other relays, based on actual voltage measurements taken at RPS System loads. The evaluation concluded that the RPS scram pilot valve solenoids are the components that require the h;ghest minimum voltage to ensure proper operation. Due to the location of the Normal supply EPAs (Turbine Building Electric Bays), the feeder cable run between the supply and the RPS distribution panels (located in the Relay Room) results in a significant voltage drop that affects the final RPS load voltages. The voltage drop between the Alternate supply EPA's and the RPS distribution panels, both located in the Relay Room, is acceptable due to the short cable length between them.
Evaluation has determined that the minimum UV trip values to assure the Normal supply EPAs provide 90% nominal voltage protection at the scram pilot valve solenoids are 111.4 and 112.3 volts for the "A" and "B" side EPAs respectively. The proposed l
SR 4.9.G.2 RPS MG Set Source UV setpoint is 2 112.3V, which is the most
]
conservative value of the two.
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 43 of 50 The proposed Normal Supply EPA UV Setpoint ensures adequate protection for the RPS, and other essential components, from undervoltage conditions on the RPS power supplies. These changes are necessary to accommodate instrument drift predicted for the duration of a 24-month operating cycle, and correct the Technical Specification setpoint that did nnt adequately consider the effects of voltage drop on all RPS system components. The field trip setpoints will be revised prior to implementing the 24 month STl.
C.
Editorial. Clarification and Bases Chances 1.
Changes to the Instrumentation Tables to Make Consistent With Amendment 227 and BWR Standard Technical Soecifications (Changes 1.C.4.1.C.7.1.C.15.1.C.16.1.C.17.
1.C.18.1.C.19 and 1.C.20)
Technical Specification Tables 4.1-2,3.2-10,4.2-5,4.2-6 and 4.2-8 are revised to make the format consistent with the changes made in Amendment 227 and the BWR Standard Technical Specifications. The frequency notations designated in Specification 1.0.T are substituted for the present requirement stated in the table (e.g.,
an item with a frequency of " Daily" is changed to state the frequency as "D"). The changes do not revise any STI currently denoted in the tables. Items extended to a 24-month STI (analyzed in this safety evaluation section IV.A) are denoted, as stated in Specification 1.0.T, as "R". Items not extended to a 24-month STI are denoted as "18M". In addition, the title of Table 4.2-3 is revised to correct a typographical error, and the component designators used in Specification 3.5.A.3.b are changed to reflect standard component labeling terminology.
Table 4.2-6 Note la is revised to clarify that the reactor vessel water level-high instrument functional test is performed once per 24 months during each refueling outage. Table 4.2-6 was added to the Technical Specifications by Amendment 225 to clarify operability and surveillance requirements for the reactor vessel overfill protection instrumentation. The basis for the instrument functional test frequency specified in Note 1 of the Table is to permit testing of this function while the plant is shutdown, thereby avoiding the risk of a plant transient. The Safety Evaluation for Amendment 225 acknowledges that the length of the FitzPatrick fuel cycle is based on a 24 month period, therefore, this change is administrative in nature and does not change the STI for the instrument functional test.
These changes are editorial in nature and do not change any Technical Specification requirement. As such, there are no safety implications in these proposed changes.
i l
O Attachment ll to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 44 of 50 2.
Editorial Changes to Table 3.2-10 Remote Shutdown Instrumentation and Associated Bases Section (Changes 1.C.5.1.C.6.1.C.8.1.C.9.1.C.10.1.C.11.1.C.12.1.C.13.
1.C.14)
The changes to Table 3.2-10 clarify operability and surveillance requirements by adding components previously omitted from the table, and reformat the table to make it consistent with other instrumentation tables in the Technical Specifications.
Table 3.2-10 was added to the Technical Specifications in Amendment 216 to provide operability and surveillance requirements for the remote shutdown instrumentation and controls. The table lists the instrumentation and control functions for the remote
)
shutdown capabilities. The transfer / isolation switches, which transfer control of the particular function from the control room to the remote location, were not listed on the table based on the premise that testing of a control switch also demonstrates operability of its associated transfer / isolation switch. During implementation of Amendment 216, it was noted that certain transfer / isolation switches have control functions, but no separate control switch, and therefore should be listed on Table 3.2-
- 10. In addition, typographical errors and omission of a monthly instrument check for two meters were also discovered.
The following specific changes are proposed to correct these errors:
Revise Table 3.2-10 to add isolation switches for the reactor head vent valve (02AOV-17), the outboard main steam isolation valves (MSIVs), the East crescent area coolers, safety relief valves and Automatic Depressurization System (ADS) valves. Although these switches are not currently listed on the table, they have 1
been tested under the requirements of SR 4.2.J since implementation of Amendment 216. These changes result in the addition of pages 77n and 77o to 1
the Technical Specifications, relocation of the Notes section to page 77o, and revision to the note at the top of each page referring the user to the Notes on page 77o.
Revise the format of the table to be consistent with other instrument tables in the Technical Specifications by adding columns for Instrument Check, Instrument Calibration and Functional Testing frequency. The frequency is designated using the notations in Specification 1.0.T. Addition of these eliminates the need for Notes B,C and D, that are currently on page 77m.
Change the component designator for the EDG B and D Emergency Bus meters (Items 65 and 74) to correct a typographical error. This does not change the actual meter used for this function.
1
, 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 45 of 50 Added requirement for a monthly instrument check for Items 65 and 74. The instrument check requirement was overlooked in the development of the original table. A monthly instrument check is required on these meters because they are normally energized. Although not currently identified on the table for Items 65 and 74, a monthly instrument check of these meters has been performed under the requirements of SR 4.2.J since implementation of Amendment 216.
These changes clarify operability and surveillance requirements for remote shutdown equipment, and incorporate editorial changes to Table 3.2-10. These changes do not propose any new surveillance requirements, nor revise any existing requirement. As such, there are no safety implications in these proposed changes.
3.
Changes to the Technical Soecification Bases to reflect chance in ooeratina cycle from 18 to 24 months (Changes 1.C.1.1.C.2.1.C.3.1.C.20 and 1.C.21)
These changes to the Technical Specification Bases revise terms such as "each refueling outage," "during refueling outage," "once per operating cycle," and "once per 18 months" to "once per 24 months" to provide consistency between the surveillance test intervals and the Bases discussion. The basis changes clarify the new STis and do not propose new or different system design limits. As such, there are no safety implications in these proposed bases changes.
V.
EVALUATION OF SIGNIFICANT HAZARDS CONSIDERATION Operation of the FitzPatrick pl ant in accordance with the proposed Amendment would not involve a significant hazards consideration as defined in 10 CFR 50.92, since it would not:
1.
involve a significant increase in the probability or consequences of an accident previously evaluated.
The proposed STI changes evaluated in Section IV.A do not involve any physical changes to the plant, do not alter the way these systems function, and will not degrade the performance of the plant safety systems. Proposed instrument setpoint changes ensure that plant safety limits are not exceeded due to instrument drift predicted for the longer calibration interval. The type of testing and the corrective actions required if the subject surveillances fail remains the same. The proposed changes do not adversely affect the reliability of these systems or affect the ability of the systems to meet their design objectives. A historical review of surveillance test results supports these conclusions.
l
- 1 to JPN-96-003 l
Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 46 of 50 The Trip !evel Setpoint changes evaluated in Section IV.B ensure that the related systems per'orm as assumed in the transient and accident analysis by ensuring that 3
plant sa! 41 mits are not exceeded due to instrument drift predicted for the longer d
calibration interval. The changes do not alter the system function, and will not degrade the performance of plant safety systems. The proposed Trip Level Setting changes do not adversely affect the reliability of these systeins or adversely affect the ability of these systems to meet their design objectives.
The editorial, clarification and Bases changes evaluated in Section IV.C propose enhancements t%t clarify the Technical Specifications requirements and are editorial in nature. These changes do not alter any Technical Sp7cification requirement, do not involve physical changes to the plant, or alter any operational setpoints. There are no safety implications in these proposed changes.
2.
create the possibility of a new or different kind of accident from any accident previously evaluated.
The proposed STI changes evaluated in Section IV.A do not modify the design or operation of the plant, therefore, no new failure modes are introduced. Proposed instrument setpoint changes ensure that plant safety limits are not exceeded due to i
instrument drift resulting from the longer calibration interval. No changes are proposed to the type and method of testing performed, only to the length of the surveillance test interval. Past equipment performance and re line testing indicate that longer test intervals will not degrade these systems. A nistorical review of surveillance test results supports these conclusions.
1 The Trip Level Setpoint changes evaluated in Section IV.B ensure that the related systems perform as assumed in the transient and accident analysis by ensuring that plant safety limits are not exceeded due to instrument drift predicted for the longer calibration interval. The changes do not alter the system function, introduce any new failure modes, and will not degrade the performance of plant safety systems. The proposed Trip Level Setting changes do not adversely affect the reliability of these systems or adversely affect the ability of these systems to meet their design objectives.
The editorial. clarification and Bases changes evaluated in Section IV.C propose enhancemmte, that clarify the Technical Specifications requirements and are editorial in nature. Tnese changes do not alter any Technical Specification requirement, do not involve physical changes to the plant, or alter any operational setpoints. There are no safety implications in these proposed changes.
hve -
e
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 47 of 50
- 3.
involve a significant reduction in a margin of safety.
Although the proposed STI changes evaluated in Section IV.A will result in an increase in the interval between surveillance tests, the impact on system reliability is minimal.
This is based on more frequent on-line testing and the redundant design of the evaluated systems. A review of past surveillance history has shown no evidence of failures which would significantly impact the reliability of these systems. Operation of the plant remains unchanged by these proposed STI extensions. The assumptions in the Plant Licensing Basis are not adversely impacted. Therefore, the proposed changes do not result in a significant reduction in the margin of safety.
The Trip Level Setpoint changes evaluated in Section IV.B ensure that the related systems perform as assumed in the transient and accident analysis by ensuring that plant safety limits are not exceeded due to instrument drift predicted for the longer catioration interval. The changes do not alter the system function, introduce any new failure modes, and will not degrade the performance of plant safety systems. The proposed Trip Level Setting changes do not adversely affect the reliability of these systems or adversely affect the ability of these systems to meet their design objectives.
The editorial, clarification and Bases changes evaluated in Section IV.C propose enhancements that clarify the Technical Specifications requirements and are editorial in nature. These changes do not alter any Technical Specification requirement, do not involve physical changes to the plant, or alter any operational setpoints. There are no safety implications in these proposed changes.
VI.
IMPLEMENTATION OF THE PROPOSED CHANGE Implementation of the proposed changes will not adversely affect the ALARA or Fire Protection Programs at the FitzPatrick plant, nor will the changes affect the environment.
Implementation of this proposed Amendment requires changes to certain plant instrumentation setpoints. The affected instruments have been identified in Section IV of the safety evaluation, and on Table 1, List of Commitments. The Authority requests approval of these proposed changes to support implementation upon startup from Refueling Outage 13 (currently scheduled for fall 1996).
Vll.
CONCLUSION Based on the discussion above, the identified STis can be safely extended to accommodate a 24 month operating cycle. The assumptions in the FitzPatrick licensing basis are not invalidated by performing these surveillances at the bounding interval limits (30 months) to accommodate the 24 month operating cycle.
The Plant Operating Review Committee (PORC) and the Safety Review Committee
l Attachment !! to JPN-96-003 Instrumentation and Miscellaneous Systems l
SAFETY EVALUATION Page 48 of 50 (SRC) have reviewed these proposed changes to the Technical Specifications and l
have concluded that they do not involve an unreviewed safety question, or a significant hazards consideration, and will not endanger the health and safety of the public.
Vill.
REFERENCES 1.
Generic Letter 91-04, " Changes in Technical Specification Surveillance intervals to Accommodate 24-Month Fuel Cycle."
2.
Meeting Minutes for February 23,1993, Meeting to Discuss Extension of Reactor Protection System Surveillance Intervals Required for a 24 Month Refueling Cycle (TAC No. M85824)(IP3).
3.
Instrument Society of America Report ISA-RP-67.04, Part 11, August 1994, i
Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation.
4.
NRC Bulletin No. 90-01, Supplement 1, " Loss of Fill Oil in Transmitters Manufactured by Rosemount," dated December 22,1992.
5.
NYPA Report JAF-RPT-RPS-01324 Revision 3, " Reactor Protection System Surveillance Test Extencions," dated December 1995.
6.
NYPA Report JAF-RPT-RPS-004FC, E.evision 1, " Instrument Drift Analysis for RPS,"
dated October,1993.
7.
NYPA letter to NRC, JPN-93-010, dated March 5,1993, " Response to NRC Bulletin No. 90-01, Supplement 1 Loss of Fill-Oil in Transmitters Manufactured by Rosemount."
l 8.
NYPA Report JAF-RPT-PC-01529 Revision 1, " Primary Containment Isolation Surveillance Test Extensions," dated September 22,1995.
9.
NYPA Report JAF-RPT-PC-01283, " Instrument Drift Analysis for PCIS," dated February 18,1994.
1 10.
NYPA Report JAF-RPT-MULTI-01530 Revision 2,"ECCS Actuation Systems Surveillance Test Extensions," dated November,1995.
l 11.
NYPA Report JAF-RPT-MULTI-01561 Revision 1, " Surveillance Test Extensions for l
ECCS Mechanical Systems," dated September 1,1995.
1 i
l
. 1 to JPN-96-003 Instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 49 of 50 12.
NYPA Report JAF-RPT MULTI-01359, " Instrument Drift Analysis for ECCS," dated February,1994.
13.
NYPA Report JAF-RPT-MISC-02082 Revision 1, " Miscellaneous Surveillance Test Extensions," dated December 14,1995.
14.
NYPA Report JAF-RPT-MULTI-01545 Revision 1, " Radiation Monitoring System Surveillance Test Extensions," dated December,1995.
15.
NYPA Report JAF-RPT-MULTI-02101, " Indicating Instruments Surveillance Test Extensions," dated September,1995.
16.
NYPA Report JAF-RPT-MULTI-01427, " Instrument Drift Analysis for Indicating Instruments," dated October 31,1994.
17.
NYPA Report JAF-RPT-MISC-01536, " Instrument Drift Analysis for Miscellaneous Instruments," dated November 28,1994.
18.
NYPA Report JAF-RPT-MULTI-00606 Revision 2, " Ventilation Systems Surveillance Test Extensions," dated November,1995.
19.
NYPA Report DC-92-006 Revision 2 (NOS-93-238), Instrument Drift Analysis for JAFNPP Ventilation Systems.
20.
NYPA Report JAF-RPT-MULTI-01116 Rev.2, " Containment Systems Surveillance Test Extensions," dated 12/20/95.
21.
NYPA Calculation JAF-CALC-ELEC-01488 Rev.1, "4kV Emergency Bus Loss of Voltage, Degraded Voltage, and Time Delay Relay Uncertainty and Setpoint Calculation," dateo 11/29/95.
22.
NYPA Calculation JAF-CALC-ELEC-00757 Rev. 6, "Setpoint Calculations to Extend Operating Cycle, and for Power Uprate-71 EPA-RPS1 A1G,1 A2G,181G,1B2G RPS EPA (Normal Supply Feeder)," dated December 1995.
23.
NYPA Calculation JAF-CALC-RPS-01516,"RPS Voltage Drop Assessment."
24.
NUREG-0123, Revision 3, " Standard Technical Specifications for General Electric Boiling Water Reactors (BWR/5)," dated Fall 1980.
25.
NUREG-1433, Revision 1, " Standard Technical Specifications for General Electric Plants, BWR/4," dated April 1995.
~..
Attachment ll to JPN-96-003 instrumentation and Miscellaneous Systems SAFETY EVALUATION Page 50 of 50 Table 1: List of Commitments Commitment Commitment Due Date Number JPN-95-XXX-01 Implement procedural guidance to evaluate 1996 Refuel Outage loop calibration failures considering 24 month (Reload 12/ Cycle 13) operating cycle drift.
JPN-95 XXX-02 Change the RPS Reactor Water Level 1996 Refuel Outage Instrument setpoint (Table 4.1-2 Item 7)
(Reload 12/ Cycle 13)
JPN 95-XXX-03 Change the MSIV limit switch setpoints (Table 1996 Refuel Outage 4.12 Item 10)
(Reload 12/ Cycle 13)
JPN-95-XXX-04 Change the Turbine Stop Valve limit switch 1996 Refuel Outage setpoints (Table 4.1-2 Item 13)
(Reload 12/ Cycle 13)
JPN-95-XXX-05 Change the RPS EPA Normal & Alternate 1996 Refuel Outage Time Delay Relay setpoints (Reload 12/ Cycle 13)
JPN-95-XXX-06 Change the RPS Normal Supply EPA 1996 Refuel Outage Undervoltage Trip setpoint (Reload 12/ Cycle 13)
JPN-95-XXX-07 Change the Main Steam Low Pressure Trip 1996 Refuel Outage setpoint (Table 4.2-1 Item 5)
(Reload 12/ Cycle 13)
JPN-95-XXX-08 Change the Main Condenser Low Vacuum 1996 Refuel Outage Trip setpoint (Table 4.2-1 Item 7)
(Reload 12/ Cycle 13)
JPN-95-XXX-09 Change the HPCI Steam Line High Flow Trip 1996 Refuel Outage setpoint (Table 4.2-1 Item 9)
(Reload 12/ Cycle 13)
JPN-95-XXX-10 Change the 4kV Undervoltage and Degraded 1996 Refuel Outage Voltage Relay and Timer setpoints (Table 4.2-(Reload 12/ Cycle 13) 2 Item 9)
JPN-95-XXX-11 Review Control Rod Block Surveillance 1996 Refual Outage Procedures to verify consistent with testing (Reload 12/ Cycle 13) stated in Standard Technical Specifications.
JPN-95-XXX-12 Change the Containment High Range 1996 Refuel Outage Radiation Monitor setpoint (Table 4.2-8 Item 4)
(Reload 12/ Cycle 13)
1 1
ATTACHMENT lll to JPN-96-003 l
Markup of the current Technical Specification pages Extension of instrumentation and Miscellaneous Survel! lance Test Intervals to Accommodate 24-Month Oneratina Cveles (JPTS-95-001G) i i
New York Power Authority JAMES A. FITZPATRICK NUCLEAR POWER PLANT Docket No. 50-333 DPR-59
sAF9FP i
1.0 (cont'd) opened to perform necessary operational activities.
deficency subject to regulatory review.
l 2.
At least one door in each autock is closed and sealed.
S.
Secondary _Contammeollolegnty - Secondary contairvnent integnty means that the reactor buddog is intact and the following conditions 3.
_ All automatic contamment isolation valves are operable are met:
or de-activated in $te lectated position.
1.
At least one door in each access opening is closed.
4.
All blind flanges and manways are closed.
The Standby Gas Treatment System is operable.
[
2.
3 N.
Rated Power - Rated power refers to operation at a reactor 3.
All automatic ventilation system isolation valves are operable i
power of 2,436 MWt. This is also termed 100 percert power and is the mammum power level authorized by the operatmg or secured in the isolated position.
bcense Rated steam flow, rated coolant flow, rated nuclear T.
Sur ^"mce Frenancy Notations / Intervals l
system pressure, refer to the values of those parameters l
when the reactor is at rated power.
The survedlance frequency notations / intervals used in these l
O.
Reactor Power Operation - Reactor power operation is any specifications are defined as follows operation with the Mode Switch in the Startup/ Hot Standby Notahans intervals Eteguency or Run position with the reactor cntmal and above 1 percent l
rated thermal power
~
D Daily At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> P.
Reactor Vessel Pressure - Unless otherwise mdmated, W.
Weekly At least once per 7 days
(
M Monthly At least once per 31 days reactor vesset pressures listed in the Technmal O
Quarterly or At least once per 92 days Spechcahons are those measured by the reactor vessel every 3 months steam space sensor SA Semiannually or At least once per 184 days i
O.
Refuehng Outage - Refuehng outage is the penod of time every 6 months
- I between the shutdown of the unit prior to refuehng and the A
Annually or Yearty At least once per 366 days startup of the Plant mW= wit to that refuehng.
Rgor.g eg At least once per @nionths a50 i
days) 93; S/U Prior to each reactor startup R.
Safety umds - The safety limits are limits withm whch the reasonable mamtenance of the fuel claddog integnty and the NA Not applicable l;
reactor coolant system integrity are assured. Violation of
[t 1:
e ch rating e." "
e per opera ing cycle,' 3 l
such a limit is cause for unit shutdown and review by the i
r outa," "at t onc during ach ratir cyc."
I l
l Nuclear Regulatory Commission before resumption of unit onc r
cy not to ceed mot s" o un i
operation. Operation beyond such a limit may not in itself f
result in senous consequences but it indmates an operational
,are e iv to the inition r fr ency ota m IFr lg meaAs Ri. Jy3.t. euc, g gy l
- M OS d*30 Amendment No. [1/,1)d, K 5
JAFf#P 3.1 i SUITING CONDITIONS FOR OPERATION 4.1 SURVElLLANCE REQUIREMENTS 4.1 REACTOR PROTECTION SYSTEM 3.1 REACTOR PROTECTION SYSTN Appicabddy.
Apolcabsty.
Applies to the instrumentation and W devces which Apphes to the survesilance of the instrumentation and associated devees whch inshate reactor scram.
l indsate the reactor scram.
h Obgechve:
To assure the operabdity of tie Rancear Protechon System.
To specdy the type of frequency of survedance to be applied to the protechon instrumentation.
Specihcahon.
Specdcahon.
i l
A. The setpoints and mmemum number of instrument channels A. Instrumentation systems shall be functionally tested and caNbrated as indicated in Tables 4.1-1 and 4.1-2 i
per trip system that must be operable for each posdion of the l
reactor modo switch, shau be as shown in Table 3.1-1.
respectively.
i The response time of the reactor protection system trip
, funcbons licted below shall be demonstrPied to be within its l
ilmit@Heinstefocfe,a6V1FmdhthfC Neutron detectors are
~
l)
- F 44 exempt from respunse time testing. Each test shau include at least one channel in each trip system. All channels in both trip systems shall be tested within two test intervals.
i
- 1. Reactor High Pressure (02-3PT-55A, B, C, D) l
- 2. Drywou High Pressure (05PT-12A, B, C, D)
- 3. Reactor Water Level-Low (L3) (02-3LT-101 A, B, C, D)
- 4. Main Steam Line isolation Valve Closure (29PNS-80A2, B2, C2, D2)
(29PNS-86A2, B2, C2, D2)
E Turtune Stop Valve Closure (94PNS-101,102,103,104)
- 6. Turtune Control Valve Fast Closure (94PS-200A, B C, D)
- 7. APRM Fixed High Neutron Flux
- 8. APRM Flow Referenced Neutron Flux Amendment No. y l
J 30g
JAFNPP 4.1 BASES (cont'd) i i
For the APRM System, drift of electronic apparatus is not the The measurement of response time provides assurance that the Reactor Protection System trip functions are completed only consideration in determinin0 a cabbration frequency withen the time limits assumed in the transient and accident Change in power distreudon and loss of chamber sensdevity thetales a cabbration every 7 days. Cahbrabon on this analyses frequency assures plant operallon at or below thermal Imtsom Wl in terms of the transient analysis, the Standard Techtwcal The frequency of cahbradon of the APRM flow bg *#6 -
Specifications (NUREG-0123, Rev.3) define individual trip network has been aetahanhed as@ rdM M=*
The funchon response time as "the time intesval from when the flow baasing network is functonaNy tested at least once every monitored parameter exceeds its trip setpoint at the channel three months and, in mMihnn, cross calibrabon checks of the sensor until de-energization of the scram pilot valve solenoids " The individual sensor response time defined as flow input to the flow baasing network can be made dunng the funchonal test by direct speler reading. There are several
" operating time" in General Electric'(GE) design specification i
instruments which must be calibrated and it wlE take several data sheet 22A3083AJ, note (8), is "the maximum allowable time from when the vanable being measured just exceeds the i
days to perform the cabbration of the endre network. While the cabbrabon is being performed, a zero flow signal wit be trip setpoent to operung of the trip chamel sensor contact i
sent to half of the APRnts resulbng in a half scram and rod dunng a transient." A transierd is defined in note (4) of tim block condibon. Thus,if the cahbraHon were pedormed same data sheet as "the maxunum expected rate of change of the variable for the accident or the abnormal operatirw]
durim operabon, hux shaping would not be possible (Tm at misiiur dnN or condehon which is postulated in the safety analysis report I
<sIuch in 3
iS j
8
... ~,u -
~
t; i
cycle.,,v
.n,ruA opahraskunmolahad mD
&, pt. one a
cL M..ebJU deoN o
was t
n s a. a,u., u n a s.v. w s.
-1Lue Ge, -/v avoid spur o n sce" s, a c.1%.M See yJcacy oC once. pce
-W maaA,s os a,s M s G 0.
Amendment No. 227) 37 L
?
~
I JAFMPP 1
r 4.1 BASES (cont'd)
B. The MFLPD is checked once per day to determine it the 7)
The indvidual sensor response time may be measured by APRM scram requires adjustment Only a small number of l
samulating a step chan0s of tie parecular parameter. This control rods are moved daily and thus the MFLPD is not s
method provides a conserwegue welus for tie sensor response expected to change segnihcantly and thus a daily check of the time, and con $rms that Wie instannent has retained its specilled I
electromechanical diernreadmaca %Rien sensor response time MFLPD is adequate.
i is measured independenty, R is neesseery to also measure the The sensatmty of LPRM detectors dec'reases with exposure t
remaining portion of tie response time in Wie logic train up to to neutron flux at a slow and approximately constant rate.
the time at which Wie scram pact valve acionoids de-energize.
This is esTvemated for in the APRM system by calibrating The channel response eme must include au component delays twice a week using heat balance data and by calibrating i
in the response chain to tie ATTS output relay plus sie design individual LPRM's every 1000 effective full power hours, l
aNowance for RPS logic system response time. A response time for to RPS lo@c relays in excess of tie design eBowance using TIP traverse data.
y is accardaNa provided tie owerat response time does not exceed the response time limits specNied in the UFSAR. The i
basis sor exceueno tw neutron % from response time l
testing is pmvided by PRC Reguietary Guide 1.118, Revision 2, section C.S.
l 8
time Miterval '
on 1
3, C
'--d
,W 31 -
Q Two instrument channels in Table 4.1-1 have not been 1
included in Table 4.1-2. These are: modo switch in shutdown j
and manuel scram. As of the devices or sensors associated with these scram functions are simp 5e on cN switches end,
]
hence, caubradon dudPo operation is nm app 5 cable.
y 5
^aanenent No. ph, % IM p[>
38 I
I JAFNPP TABLE 4.1-2 REACTOR PROTECTION SYSTEM (SCRAM) INSTRUMENT CALIBRATION
- ".:'""-'_m C.At BRRATION FREQUENCIES FOR REACTOR PROTECTION INSTRUMENT CHANNELS Instrument Channel Group (1)
Cahhratinn dQierwnumlFreouency (2)
IRM High Flux C
Comparison to APRM on (Euamum um-ncy once/ wee #w Controlled Shutdowns APRM High Flux Output Signal B
Heat Balance D
Flow Bias Signal B
Internal Power and Flow Test (Every refueling outaD R
with Standard Pressure Source LPRM Signal B
TIP System Traverse Every 1000 effective full power hours High Reactor Pressure B
Standard Pressure Source (Note High Drywell Pressure B
Standard Pressure Source (Note Reactor Low Water Level B
Standard Pressure Source (Note High Water Level in Scram A
Water Column, Note (5)
Once/ operating cycleTNot Discharge Instrument Volume High Water Level in Scram B
Standard Pressure Source
@ery 3 mown Q Discharge instrument Volume Main Steam Une isolation A
(Not
)
(Note Valve Closure Turbine First Stage Pressure B
Standard Pressure Source (Note )
Permissive i
l Amendment No. 4/, M. @, [, f, Ih, if3
~
j
JAFNPP TABLE 4.1-2 (Cont'd)
REACTOR PROTECTION SYSTEM (SCRAM) INSTRUMENT CALIBRATION
~
r""--"as cas mRATION FREQUEEia FOR REACTOR PROTECTCN WSTHUMENT CHANNELS
_/
instrument Channel Groun (1)
C*ralian (Mwunum]Freauency (2)
Turbine Control Valve Fast A
Standard Pressure Source (t5nce/operatina k
i Closure Oil Pressure Trip i
Turbine Stop Valve Closure A
(Not
)
(Not
)
NOTES FOR TABLE 4.1-2 1.
A description of ttwee groups is included in the Bases of this Specification.
2.
Cahbration test is not required on the part of the system that is not requiind to be operable, or is tripped, but is required prior to retum to service.
l 3.
Deleted eac,_ p, rq m oaf 4 5 4.
Actuation of these switches by normal means will be performed @uring the refuehng outagesp 5.
Cahbration shall be performed utilizing a water column or similar device to provide assurance that damage to a float or other portions of the float assembly will be detected.
[
6.
Sensor cabbration once per65erating cyglsP Master / slave trip unit cahbration once per 6 months.
24 m.A s I
r i
Amendment No. 4f, h, h, Ih, ikI,
~
47 i
~
(
t JAFNPP i
3.2 LIMITING CONDITIONS FOR OPERATION 4.2 SURVEILLANCE f1EQUIREMENTS 4.2 INSTRUMENTATION 3.2 INSTRUucNTATION i
Applicabildr 800ficiatahbG Apphes to the plant instrumentation which either (1) initiates and Applies to the survedlance requirement of the instrumentation whicli i
controls a protective function, or(2) A iniormation to aid the either (1) initiates and controls protective function, or (2) provides operator in monstonng and anseseirIS plant status during normal and information to aid the operator in monitoring and assessing plant status dunng normal and acodent conditions.
accedent cons 9hons.
Otychve Otigactost:
To assure the operatuhty of the aforemanhoned instrumentahon.
To specdy the type and frequency of surveillance to be applied to the aforementioned instrumentation.
S@eCdiCaInsMis' M*
A. Primary Coc w sentatiari Furweintis a
T== le " " -7 Furw*was A. Primarv Cor a
Instrumenlahon shall be functionally tested and calibrated as l
When pnmary containment integnty is required, the hmeting indicated in Table 4.2-1. System logic shall be functionally condmons of operation for the instrumentation that initiates tested as indicated in Table 4.2-1.
primary containment isolabon are given in Table 3.2-1.
The response time of the main steam isolation valve actuation OI instrumentahon isolation trip functions listed below shall be demonstrated to be within their limits (at least orice per ifD "
"$p A Each test shallinclu e at east one c anne n each trip d
l h
li y
system. All channels in both trip systems shall be tested within j
two test intervals.
- 1. MSIV Closure - Reactor Low Water Level (Lt) t (02-3LT-57A,B and 02-3LT-58A,B) l
- 2. MStV Closure - Low Steam Line Pressure (02PT-134A,B C.D) l
- 3. MStV Closure - High Steam Line Flow j
402DPT-1 16A-D, 1 17 A-D, 1 18A-D, 1 19 A-D)
/ l b
b 4
k i
.m-..
JAFNPP j
3.2 BASES (cont'd)
I m
1 provided by a remote shutdown panel (25RSP) and five alternate The remote /altemate shutdown capabihty at FitzPatrick is and transfer switches wiH have to be operated locally at the switchgear, motor control centers, or other local stations.
safe shutdown panels (25 ASP-1,25 ASP-2,25 ASP-3,25 ASP-4, and 25 ASP-5). These panels are used in conjunchon with the Operabshty of the remote shutdown instrumentation and control j
Auiomatic Depresswization System (ADS) relief valve control funchons ensure that there is sufficient information available on I
pene! (02 ADS-71) adjacent to 25RSP, the emergency diesel selected plant parameters to place and maintain the plant in a generator (B & D) control panels (93EGP-B and 93EGP-D) shutdown condticm should the control room become opgmite 25 ASP-3, the reactor buddng vent and coolmg panel inaccessible. The instrumentation and controls instaNed on the (66HV-38) near 25 ASP-1, instrument rack 25-51, and instrument rack 25-6 opposite 25RSP. AN of these locatens are linked by
. remote / alternate shutdown panels are listed in Table 3.2-10.
(T t
does not ~
the '
ahon/tr <fer sw' s for communicahons and are provided with emergency hghtmg.
I ons the rem alternat hutdow panels.
s.
S ediance 4.2.J. t oper ~
of the 4
This Remote Shutdown capahady provides the necessary will demons ed w the rem e/ alternate instrumentation and controls to place and maintain the plant in a shtddown control areAested.
j safe shutdown condition from a locahon other than the control I
room in the event the control room becomes inaccessible due to The remote shutdown instruments and control circuits covered by a fire or other reason, this LCO do not need to be energized to be considered operable.
This LCO is intended to answa that the instruments and control l
This specdicahon ensures the operabihty of the remote shutdown circuits win be operable if plant conditions require the use of the
(
instrumentation and control circuits. Operabihty of components remote shutdown capahdity. Performance of the instrument such as pumps and valves, wtuch are controNed from these check once every 31 days ensures that a gross failure of panels, is covereil by other specdicahons. This specdicalmn instrumentation has not occurred and is intended to ensure that i
does not impose condhons on plant operation which are more the instrumentation contmuss to operate properly between each restnchve than those already imposed by other speedicatens.
instrument channel cahbration.
For example, Speedcation 3.7.D includes provisions for contmued operation with one or more contamment isolation As specified in the survedlance requirements, an instrument valves inoperable. The 30 day time Imutation imposed by 3.2.J check is only required for those instruments that are normaNy would not apply in this situation, provided that the actens taken energized. Performance of this survedlance provides assurance for the inoperable valve (s) to satisfy 3.7.D are also consistent that undetected outnght instrument failure is limited to 31 days.
with the safety function (s) required for fire protection.
The survedlance frequency is based upon plant operating expenence which mdcates that channel failure is rare.
Not all instruments, controls, and necessary transfer switches are L) e located at the remote / alternate shutdown panels. Some coatrols
_M M'c wl sacludes de imInd/hk l
%. -$~f {e p i,. ve ae3 o3 soc:adeel co&oI S<aIIcle - O **'*A'j g
f l
OC sso/n,h g h sp,.ss.asick s -NsJ-bsM-9 *' *Ssocicdecf Coki s.'lel, aa ll Le d<moask=d d <A.o h cohh Amendment No. 166,120,.136,14iO;.18t', JW
.R,a c4 ur 1,sleJ e opmd 5y 3 i"s //* '*- /b"'
c,re I
60 Y. 2. 7 r;
8
t t
JAFNPP j
3.2 BASES (conrd)
Surveltance Recpsivement 4.2.J requires that each remote t
l ehutdown trenefer / isolellon swildi and control circuit be portoscopy tested to demonstrate that it is capable of i
persorming its intended funcGon. The requirements of this esclion apply to each amate shutdoum control circuit on he t
panois Ested in Tobis 3.2-10rgies on panels 25 ASP-43 a
-5, and 86Hv@ This 1...
--A-. is pedormed from
" tie' remote shutdown penal and laceBy, as appspdate. This wie ensure tiet N tw contml room becomes inaccesette, the plant can be placed and maintained in a shutdown constion t
l from the remote shutdown panel and Rio local contml elellons.
O l Three channels of tie Reactor Vessel Water Level - High l
instrumentellon am provided.as input to a tum out-of-three l
l inillation logic tiet trips the two feedwater pump turbines and the main tuttine. An event involving excessive foodwater Row results in a rising reactor vessel water level, which upon seeching Wie mactor veneel water level trip se$oint, results in a trip of both foodwater pump turbines, and the main turbine.
l The feedwater pump turbine trip under these constions Emits j
l further increase in the reactor vessel water level due to l
feedweler flow. A Idp of the mein turbine protects the turbine from damage due to excesehe weler carryover.
1 i
i 1
i Amendment No. m, 32I eos
4 JAFWP TABLE 32-2 fcontd)
I i
CORE AfD CONTAlfEAENT COOLING SYSTEM MTIATION. AfjD CONTROL MASTRubE.NTATION OPERABE.lTY IMEQUEERAENTS c
h l
W No. $
Operable instrument Total Number of I
Channels Per Instrument Channels
~
ltem Trip System Provided by Design l
No.
(Nna= 1 and 21 Trin Fur %
Trio Level %
for Rnah Trio Splams Remarks 26 (1 per 4kV bus) 4kV Emergency Bus 110.6 1 8
2 initiates both 4kV (Note 9)
Undervoltage Relay cocondary volts Emergency Bus Undervoltage (Degraded Votage)
Tuners. (Degraded Voltage LOCA and non-LOCA, F
(Notes 4 and 6) 27 (1 per4kV bus) 4kV Emergency Bus (9.0 i 1.0 sec 2
(Note 5) i (Note 9)
U6Gi-uit.g Tirner F.% 1 o.55 se_c_-
(Dograded Voltage LOCA) 28 (1 per 4kV bus) 4kV Emergency Bus (45 t 5.0 sec[.
2 (Note 5) l (Note 9)
Urder.uii.[p Timor 9 3, g 3,,7, y g,c ~
(Degraded Voltage non-LOCA) j 29 (1 per 4kV bus) 4kV Emergency Bus 85 i El 2
initiates 4kV Emergency Bus (Note 9)
Users.uiiage Relay secondary volts Undervoltage Loss of
(
(Loss of Voltage)
Voltage Tuner.
t (Notes 4 and 7)
I 30 (1 per 4kV bus) 4kV Emergency Bus 2.50 i sec.
2 (Note 5)
(Note 9)
Undervoltage Tuner o, p (Loss of Voltage) 31 2
Reactor Low Pressure 285 to 335 psig '
4 Permits closure of recirculation i
pump discharge valve.
k Amendment No. /, %, J 70
~
TABLE 3.2-10 REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS
[ Refer to Notes on Page 7 INSTRUMENT PANEL OR Jas % 4 J-s W hw' OR CONTROL LOCATION owA
- c. 8. w L nct 1.
RHR Service Water Flow (Loop B) 25RSP M
k M4 (10F1-134) 2.
RHR Service Water Pump Control 25RSP (10P-18) 3.
RHR Service Water Heat Exchanger Outlet Valve 25RSP Control (10MOV-898) 4.
RHR Service Water to RHR Cross-Tie Valve 25 ASP-1 O
k Control (10MOV-1488) 5.
RHR Service Water to RHR Cross-Tie Valve 25 ASP-1 N4 NA Control (10MOV-1498) 6.
RHR Flow (Loop B) 25RSP m
MA.
(10F1-133) 7.
RHR Discharge Pressure (Pump D) 25RSP M
k MA (10PI-279) 8.
RHR Pump Control 25RSP NA NA (10P-3D) 9.
RHR Heat Exchanger Bypass Valve Control 25RSP Mk N/}
Amendment No.
~
TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY BdSTRUMENTATION AM CONTROLS
[ Refer to Notes on Page 77 os g
INSTRUMENT PANEL OR w.sitawr rAsreaurt M
OR CONTROL LOCATION cMcA Werno er 10.
RHR inboard injechon Valve Control 25RSP ug g4 g
(10MOV-258) 1 11.
RHR Heat Exchanger Steam inlet Valve Control 25 ASP-1 NA gg 4
(10MOV-708) 12.
RHR Heat Exchanger Vent Valve Control 25 ASP-1 MA pk
(
(10MOV-1668) 13.
RHR Heat Exchanger Outlet Valve Control 25 ASP-1 Mk NA k
(10MOV-128) 14.
RHR Pump D Torus Suchon Valve Control 25 ASP-2 NA MA k
(10MOV-130) i 15.
RHR Pump D Shutdown Coolmg Suchon Valve 25 ASP-2 NA MA k
Control (10MOV-15D) 16.
RHR P Mmunum Flow Valve Control 25 ASP-2 MA 4
i (10MOV-168)
Nd 17.
RHR Heat Exchanger inlet Valve Control 25 ASP-2 (10MOV-65B) i b
NA 18.
RHR Outboard injection Valve Control 25 ASP-2 (10MOV-278) 2f)
Amendment No.
779 t
~
JAFNPP TABLE 3.2-10 (cont'd)
RPMTE SHUTDGAM CAPAma ITY BASTan-"TATION ^_@ OfMTROLS
[ Refer to Notes on Page 7 O
INSTRUMENT PANEL OR
_rerramser _porew we OR CONTROL LOCATION ourck ggw g 7-19.
RHR Heat Exchanger Discharge to Torus Valve 25 ASP-2 94 g4 R
l Control (10MOV-218) 20.
Torus Cooling isolation Valve Control 25 ASP-2 A)4 f)A A
(10MOV-398) 21.
DW Spray Outboard Valve Control 25 ASP-3 d4 NA g
(10MOV-268) 22.
ADS & Safety Relief Valve A Control 02 ADS-71 AJA MA k
(02RV-71A) 23.
ADS & Safety Relief Valve B Control 02 ADS-71 Ne NA g
(02RV-718) 24.
ADS & Safety Relial Valve C Control 02 ADS-71 N g.
MA (02RV-71C) 25.
ADS & Safety Relief Valve D Control 02 ADS-71 M&
MA 8
(02RV-71D) 26.
ADS & Safety Relief Valve E Control 02 ADS-71 t)A
- 4 (02RV-71E) fk k
l 27.
ADS & Safety Reliel Valve G Control 02 ADS-71 NA (02RV-71G)
Amendment No. )6",
77h
JAFNPP TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS
[ Refer to Notes on Page 7 o
INSTRUMENT PANEL OR zu.snamwr n:ra#
@~ cnw<-
OR CONTROL LOCATION cerck Cxc.w Tatsr 28.
ADS & Safety Relief Valve H Control 02 ADS-71 p4 gA.
Q (02RV-71H) 29.
Safety Relief Valve F Control 02 ADS-71 N4 eJA R
(02RV-71F) 30.
Safety Relief Valve J Control 02 ADS-71 (JA Ma q
(02RV-71J) 31.
Safety Relief Valve K Control 02 ADS-71 NA (V4 S
(02RV-71K) 32.
Safety Relief Valve L Control 02 ADS-71 NA NA k
(02RV-71L) 33.
Main Steam Line Drain Outboard Isolation Valve 25 ASP-2 N&
Alh k
Control (29MOV-77) 34.
Drywell Temperature 25RSP rY)
R lb4 (68TI-115) 35.
Torus Water Temperature 25RSP IY)
R y4 (27TI-101) 36.
Torus Water Level 25RSP m
R yA (23LI-204)
Amendment No. pff 1
77i
a JAFHPP TABLE 3.2-10 (cont'd)
BEMQTE SHUTDOWN CAPABILITY _lNSTRUMENTATION AND CONTROLS
[ Refer to Notes on Page 7Wo e-w INSTRUMENT PANEL OR J ures or Iwr w a r
- c**
OR CONTROL LOCATION cwd.
G <-
7P5T 37.
Reactor Vessel Pressure Rack 25-6 m
A MA (02-3PI-608) 38.
Heactor Vessel Water Level Rack 25-6 M
R NO (02-3Li-58A) 39.
Reactor Vesse! Water Level Rack 25-51 M
(1 g/l (02-3LI-93) 40.
HPCI Steam Supply Outboard Isolation Valve 25RSP MA k
gg Control (23MOV-16) 5 41.
HPCI Outboard Isolation Bypass Valve Control 25 ASP-2 gg g4 k
(23MOV-60) 42.
HPCI Minimum Flow Valve Control 25 ASP-2 gg gA 4
(23MOV-25) 43.
CAD B Train inlet Valve Control 25RSP N/1 gA q
(27AOV-1268) 44.
Nitrogen Instrument Header isolation Valve 25RSP Ng g/4 R
Control (27AOV-1298) 45.
Reactor Water Cleanup Outboard Isolation Valve 25 ASP-2 MA MN k
Control (12MOV-18)
Amendment No. 2 77j
l l
JAFNPP TABLE 3.2-10 (cont'd)
RgnaOTE SNUTDOWN CAPABEJTY INSTRUnaENTATION AND CONTROLS
[ Refer to Notes on Page t
INSTRUMENT PANEL OR
.xu m r ru m mwar se m OR CONTROL LOCATION
& ck u.m
-rest-46.
Emergency Serwce Water Pump B Control 25 ASP-3 g4 4
q (46P-28) l 47.
ESW Loop B Supply Header Isolation Valve 25 ASP-3 g
g k
Control (46MOV-1018) 4 48.
ESW Pump B Test Valve Control 25 ASP-3 gg.
gg k
I 49.
Bus 11600 Sipply Breaker Control 25RSP A/4 gg g
{
(71-11602) i 50.
EDG B & EDG D Tie Breaker Control 25 ASP-3 g4 g
q (71-10604)
\\
51.
Bus 10400-10600 Tie Breaker Control 25 ASP-3 gA gg.
q l
(71-10614) 52.
Unit Substation L16 & L26 Feeder Breaker 25 ASP-3 NA Mk Control (71-10660) 53.
Bus 12600 Supply Breaker Control 25 ASP-3 tJA NA k
(71-12602) 54.
Breaker 71-10614 Synchronizing Check Control 25 ASP-3 N4 N4 k
55.
EDG B Control Room Metering Check Control 25 ASP-3
/\\/q-N/Y q
Amendment No. pff, 77k
l l
l JAFNPP 1
i TABLE 3.2-10 (cont'd) l i
j l
REasoTE CRITDOWN CAPABILITY INSTRUMENTATION AND CONTRots f
[ Refer to Notes on Page 7W l
O INSTRUMENT PANEL OR
/usneanovr _zmresswr Gcm )
OR CONTROL LOCATION chcA c4u sa,m,;
fas. r 56.
EDG B Engme Start /Stop Control 25 ASP-3 pa g4 g
57.
EDG D Control Room Metering Check Control 25 ASP-3
- A pa R
58.
EDG D Engme Start /Stop Control 25 ASP-3 NA NA k
59.
EDG B Governor Switch 93EGP-B NA NA S
60.
EDG B Synchronning Switch 93EGP-B NA MA f(
t f1 dh J
61.
EDG B Load Breaker Control (71-10602) 93EGP-B 62.
EDG B Motor Control 93EGP-B NA 94 k
63.
EDG B Frequency Meter (93FM-19) 93EGP-B MA k
~0 l
t g
[
64.
EDG B Voltage Control 93EGP-B pfe 65.
EDG B Emergency Bus Meter
-600-18) 93EGP-B M
(
N4 66.
EDG B locoming Bus Meter (93VM-128) 93EGP-B Ma R
pg 67.
EDG B Running Bus Meter (93VM-118) 93EGP-B M4 k
Nd I
68.
EDG D Governor Switch 93EGP-D (JA y3 A
69.
EDG D Synchronizing Switch 93EGP-D N&
mar k
Amendment No. p6, t
7 71
~
JAFNPP TABLE 3.2-10 (cont'd)
RFMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS (RC, 4 Ab/e r
& ee ?no )
os INSTRUMENT PANEL OR
_n~2 %r sarce Avene OR CONTROL LOCATION cArch
%uw wr 70.
EDG D Load Breaker Control (71-10612) 93EGP-D M4 UA 4
71.
EDG D Motor Controi 93EGP-D g/i-A>+
4 72.
EDG D Frequency Meter (93FM-1D) 93EGP-D g4 R
d4 73.
EDG D Voltage Controi 93EGP-D fJr Ar.4
/{
74.
EDG D Emergency Bus Meter 600-1D) 93EGP-D M
4 A/A 75.
EDG D incoming Bus Meter (93VM-12D) 93EGP-D A//,-
R N4 76.
EDG D Running Bus Meter (93VM-11D) 93EGP-D AJA f(
y4 Ik4r /LJ VJ Iso /~L sh (wits-n) 2 rah' pr y,
iz
~7'1 NOTES FOR TABLE 3.2-10
) muc le 1
Minimum required number of divisions for all instruments and controls listed is 1.
< I,BI ' Pefformjnsfrument chpck for,ench required trumpt that is no y energized once per 31
.)
he normail ergizfd instrbment /are' tifiedin line i s1
, 7, 3 5,3,37,38
/
P orm instrument c ati or e r
~ ed ins en ~
channelone per
'ng
' e.
^
/
I 7
./ Dem/ /
requir/
onstrEte sa ed c 01 circuit a sf / isol.
sw is c e of forming heQ intended functio'n once per operatinjcycle.
D E. c +%el mssv A Isouk) su1%OW-M 'W'N
^ ' "
o
'79. Go Aed msW G Tselob L s'l<1(2 %v.'/so).;2643r-4 A/A Amendment No. J1ti, u g.
g go, 3 %,2 mg,y c 23fA _r, u g%,_ g,c)
,g g __ y
,m
i s
c.
JAFNPP gg TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS (Refer to Notes on Page 77ol 1
INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAllBRATION TEST f
81.
Outboard MSIV D isolation Switch 25 ASP-4 NA NA R
(29AOV-86D) 82.
East Crescent Area Unit Cooler B,D,F 66HV-3B NA NA R
(66UC-228, 22D, 22F) Isolation Switch 83.
East Crescent Area Unit Cooler H,K 66HV-3B NA NA R
(66UC-22H, 22K) Isolation Switch 84.
ADS & Safety Relief Valve A 25 ASP-5 NA NA R
isolation Switch (02RV-71 A) 85.
ADS & Safety Relief Valve B 25 ASP-5 NA NA R
isolation Switch (02RV-71B) 86.
ADS & Safety Relief Valve C 25 ASP-5 NA NA R
Isolation Switch (02RV-71C) 87.
ADS & Safety Relief Valve D 25 ASP-5 NA NA R
[
Isolation Switch (02RV-71D) 88.
ADS & Safety Relief Valve E 25 ASP-5 NA NA R
l Isolation Switch (02RV-71E) 89.
Safety Relief Valve F 25 ASP-5 NA NA R
isolation Switch (02RV-71F)
Amendment No.
77n
l t
MW l
- p TABLE 3.2-10 (cont'd)
REMOTE SHUTDOWN CAPABILITY INSTRUMENTATION AND CONTROLS l
INSTRUMENT PANEL OR INSTRUMENT INSTRUMENT FUNCTIONAL OR CONTROL LOCATION CHECK CAllBRATION TEST i
90.
ADS & Safety Relief Valve G 25 ASP-5 NA NA R
lsolation Switch (02RV-71G) 91.
ADS & Safety Relief Valve H 25 ASP-5 NA NA R
isolation Switch (02RV-71H) 92.
Safety Relief Valve J 25 ASP-5 NA NA R
isolation Switch (02RV-71J) 93.
Safety Relief Valve K 25 ASP-5 NA NA R
Isolation Switch (02RV-71K) 94.
Safety Relief Valve L 25 ASP-5 NA NA R
i isolation Switch (02RV-71L) i i
NOTES FOR TABLE 3.2-10 1.
Minimum required number of divisions for all instruments and controls listed is 1.
Amendment No.
770
JAFNPP TABLE 4.2-2 CORE AND CONTAINAMENT COOUNG SYSTEM INSTRUMENTATION TEST AND CAUARATION REQUIREMENTS Y
instnmient Channel instrument FunctNmel Test Cahtwation Frequency instrument Check (Note 4) 1)
Reactor Water Level O (Note 5)
SA / R (Note 15)
D 2.2)
Drywell Pressure (non-ATTS)
Q Q
NA 2td Drywell Pressure (ATTS)
Q (Note 5)
SA / R (Note 15)
D 3a)
Reactor Pressure (non-ATTS)
Q O
NA 3td Reactor Pressure (ATTS)
Q (Note 5)
SA / R (Note 15)
D 4)
Auto Sequencing Tuners NA -
7 /Em NA 5)
O, Q
NA 6)
Trip System Bus Power Monnors Q
NA NA 7)
Core Spray Sperger d/p Q
Q D
8)
HPCI & RCIC Suction Source Levels Q
O NA 9) 4kV Emergency Bus Under-Voltage R
R NA (Loss-of-Voltage, Degraded Voltage LOCA and non-LOCA) Relays and Tamers.
IC)
LPCI Cross Connect Valve Position R
NA NA NOTE:
See notes following Tatde 4.2-5.
Amendment No. 3, 00,1 SS,12?, 201, 217, pf, 80
~
TABLE 4.2-3 CONTROL ROD BLOCK kTR8'"""4TM JN574umeyr477av TEST AND CALEBRATION REQUIREMENTS Instrument
~
Instrument Functonal Instrument Channel Test (Note 5)
Calibration Check (Note 4) 1)
APRM - Downscale Q
Q D
Q Q
D 2)
APRM - Upscale 3)
IRM - Upscale S/U (Note 2)
Q (Notes 3 & 6)
D 4)
IRM - Downscale S/U (Note 2)
O (Notes 3 & 6)
D 5)
IRM - Detector Not in Startup Possbon S/U (Note 2)
NA NA Q
O D
6)
RBM - Upscale
[
7)
RBM - Downscale Q
Q D
8)
SRM - Upscale S/U (Note 2)
Q (Notes 3 & 6)
D 9)
SRM - Detector Not in Startup Positon S/U (Note 2)
NA NA 10)
Scram Discharge instrument Volume -
Q O
D High Water Level (Group B instruments)
/
/
/
/
ci Sys[em Fundion Te (Not
&9)
FrAW{uency
/
/
/
SA 1
S em L C
l l
NOTE: See notes following Table 4.2-5.
l Amendment No. /, %, %, 327,
w yv w
S e
O JAFNPP TM3LE 42-5
_59NIR8URE TEST AND CALMBRA710N FREQUENCY FOR DRYWELL LEAK DEYECTION kWrument Functonal Catrabon huerumore Check instrument Channel Test Frequency (p.@x v3
^
1)
Eau;pi,4 Drain Sump Rorf inseyasar
- 1) (pot O (pumn q
DMl a
nooro,. Sump eo.
Irweyanor NoA/)
Conce#%"q D @/7 l
l NOTE:
See notes sonowing Tdlile 4.2-5.
e t
t i
9 2
}
83 i
JAFNPP NOTES FOR tam 8 82 4.2-1 THROUGH 4.2-4
- 1. InhiaNy once every month unta acceptance failure rate data are 8.
Reactor lex water level, and high drywell pressure are not avagable; tieresher, a request sney be made to du NRC to Irv*= tad on Table 4.2-1 since they are listed on Table 4.1-2.
change tw test kequency. The e of instrument fagure rate data may indude data 'obtained Isom other boung water 9.
The logic system funcbonal tests shall include a cadwation of reactors for which tie same deellp Inetsuments operate in a time delay relays and timers necessary (N proper functionog environment aimber to tiet of.lAFM8P.
of the trip systems.
- 2. Functional toets are not requimd when these instruments are not
- 10. (Deleted)
.Np As y required to be operable or am adpped. Functional toets shes be
- 11. Perform a caNbrabon once per(4peranno cycig>using a pedonned witiin savon (7) days pdor to sech stadup.
ratsanari source. Perfonn an instrument channet a5gnment
- 3. CaNbrations are not required when those instrumente are not once every 3 months using (ie butt-h cupent source.
a required to be operable or are tilpped. CaRwallon tests shes be i
- 12. (dew podormed witiin seven (7) days pdor to each stanup or pdor,lo a pn> planned shutdoum.
- 13. (D-W
- 4. Instrument diecks are not required when tisse instruments are
()
- 14. (Deleted) l not required to be operable or are Idpped.
/
m a,.
I
- 5. This instrumentation is exempt kom the functional tes' delinition.
- 15. Sensor caNbndion once perdi55tanna cycse;) Master / stave trip The lunctional test wW consist of Ir(eding a s' mdated elecidcol unit caubndian once per 6 months.
a
- 16. The quartedy cahbrabon of the temperature sensor consists f
- 6. These inetmment cherwiels wW be caRwated using simulated of compedng the acdve temperature sigive with a redundant elocidcol signals once every twee monts.
temperature signal.
()
- 7. Simulated automatic actuallon sher be performed 6me ea7 capsiialance-ee aq muuo.
V I
am.aom.nt no. p A. pt. vo, vn. W. pf, 84
t JAFNPP TABLE 4.24 FEEDWATER Putr TURBBE AND REAM TUPBEE TRF MSTRURAENTATEN TEST Alm CAUBRATION IEMNIERAENTS
. w.
instrument Functional Logic System Functional CaNbradon Frequency Instrument Check Instrument Channel Test Fsequency (Note 2)
Test Fmquency Frequency R
D R
/
y Reactor Vessel Water t.svel- % "3 (Once overy 24 month]s @ every 24 montig) f Note 1 i
NOTES FORJAM.E 424
- 1. Perkra the inoimment funcilonel test:
- a. % cw w.74 mat,s each refueEng outage, and
- b. Each Nne the plant is in cold shutdown for a pedod of more then 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 92 days.
- 2. Tus instrumentenan is esempt from the instrument channes functional test dennman. The funcuaner test we consist of irteceng a simulated elselcol signal into the instmment channel as close to the sensor as pecIlcalde.
l i
W Amendment No. 31) ya
JAFMP TABLE 4.2-8 RANIMUM TEST AND CAllBRATION FREQUENCY FOR ACCBENT PAONITORBdG BGSTRURENTATION tratrument Instrument Functonal Test Calibration Frequency Check lastrument 1.
Stack HiWi Range Effluent Momtor
/pfGv4Gu s= Gvcle[ Once/Cuo.&w GG,5 Oiice/dag-2.
Turtune Buddng Vent High Range Efiluent Mondor
/PICOnce/OperalNM GvcHIf' 6nce/Oceratino cygm N
Radwaste Buildng Vent HiWi Range Efiluent Montor / hating Gvce Once/Operaemo Gyg 3
4.
Contamment High Range Radalmn Momtor R dnceNatinha (Dnce/Operalma C (Once/ day N/A (Dnce/Onerasmo Gycle{
5.
DryweN Presswo (narrow range)
N/A L0ncetoperating Gygg -
6.
DryweN Presstra (wide range)
N/A dTnce/Operatino GvGiD - --
Qrice/dajby g
7.
DryweN Temperatwe N/A
@6ceruperaeno uvau{
Once/W 8.
Torus Water Level (wide range)
N/A Gice#0perasino c Q
9.
Torus Buk Water Temperatwo N/A Once/Operatingg once w g o
10.
Torus Presswe
<Q5cer3 morO ~R
@p h 11.
Primary Containment Hydrogen # Oxygen Concentration N/A Ane z.
r N/A dlncetonaratino cuckDy (Once/dag 12.
Reactor Vessel Presswo N/A (Once/Operalmo Gvcle'r Moce/dg 13.
Reactor Water Level (fuel zone)
~
14.
Reactor Water Level (wide range)
N/A
@etOperatmg GycIW Qncerdah D
I Amendment No. Apf,jff K )
n
JAFNPP TARI F 4.2-B iconrdi RANIMUM TEST AND CALIBRATION FREQUENCY FOR ACCEENT RAONITORRIG INSTRURGENTATIOpd Instrument instrument Instrument Functional Test Calibration Frequency Check N/A (f)nce/Operatmg Cy@
O Cnce/C 15.
Core Spray Flow N/A g gnce/ Operating Cyc7 b 16.
Core Spray Discharge Presswa il/A g CCince/OperatiW D W 17.
( dlocs/Operatino CvC DM" 18.
RHR Service Water Flow 19.
Salety/ReGel Valve Positon inc5cator (Once/24 months N/A M Cnce/monHP dl (Primary and Secondary) 20.
Torus Water Level (norrow range)
N/A
/( COnce/ Operating CyF o W !
q (Qnce/ Operating Cych f) @nce/d}e-l 21.
Drywell-Torus Differential Pressure N/A 1
Amendment No. Jad,J8f g) asa
[
t JAFNEP 4.5 SURVEILIANCE REOUIREMENTS 3.5 I.IMITING CONDITIONS FOR OPERATION 4.5 CORE AND CONTAINMENT COOLItG 3.5 CORE AND CONTAItHENT COOLItG SYSTEMS Applicability:
Applicability:
Applies to periodic testing of the Due Applies to the operational status of the Emergency Core Cooling Systems, the gency Core Cooling
- Systems, the suppression pool cooling and containment 1
suppression pool
- cooling, and spray mode of the Residual lleat Removal containment spray snodes of the Residual (RilR) System.
licist Removal (RilR) System.
Obiective:
Miective:
To verify the operability of the Core l
To assure operability of the Core and and Containment Cooling Systems under Containment Cooling Systems under all all conditions for which operability is conditions for which this cooling essential.
capability is an essential response to plant abnormalities.
Specification:
Specification:
A.
Core Spray System and Low Pressure Coolant Iniection (LPCI) Mode of the A.
Core Spray System and Low Pressure f
Coolant Injection (LPCI) Mode of the RIIR System (RllR) System j
f 1.
Doth Core Spray Systems shall 1.
Surveillance of the Core Spray
[
i he operable whenever irradiated fuel is in the reactor vessel System shall be performed as follous:
and prior to reactor startup from a cold condition, except Item Frequency as specified below:
- a. Simulated Each operating Automatic cycle
,"*'I "
Re G - de 7 f/e_ f. 2 - 4 We+1bmsed-YO.
l i
112 1
f
JAFNPP 3.5 (cont'd) 45 (cont'4 b.
Flow Rate Test-Once/3 Months
/
Core spray pumps shaN desver atinest 4,2ss opm l
agenst a system head t
correspondng to a reactor W pressure greater than or equalto 113 poiabove primary containment pressure.
c.
Pump OperabNity Once/ month l
t d.
Motor Operated Once/ month N
e.
Core Spray Handar
~
opinstrumentation Check Once/ day CaNbrate Once/3 months Test Once/3 months f.
Logic System
'(Once/Q4.G A FunctionaiTest (operating cycleM/e f.t-2 )
g.
Testable Check Tested for l
Valves operabihty any time the reactoris in the cold condition exceedmg 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />,if operability tests have i
not been performed dunng the preceding 31 days.
Amm&nst No. [ 1/9 p[j j
4 JAFNPP 3.5 (cont'd) 4.5 (cont'd)
(f oRM-o9) ---,
~
F-l and J,.hain lock to l b.
When the reactor water temperature is greater than b.
The power source disconnect 21 motor operator for the RHR cross-tie valve rnotor operated RHR cross-tie valve and lock on (somd-2 shaN be maintaned disconnected from its rr operated gate valveshall be inspected electnc power source. It shaN be mamtaned once operahna cyclelo verify that both valves cham-locked in the clogd pGeit;cni. The manuaNy are closed andlocked. Q g
operated gate valve (10iHHR-09) in the cross-tie line, in senes with the motor operated valve, shall be mamtained locked in the closed postion.
i 4.
a.
The reactor shaN not be started up with the RHR System supplyng coolmg to the fuel pool.
b.
The RHR System shaN not supply coolmg to the j
spent fuel pool when the reactor coolant i
temperature is above 212"F.
1 t
I
~
l Amendment No.dg 1
1
?
JAFNPP 35 (Cont'4 4 5 (Cont'd)
E.
Reactor Core isotahon Coolmg (RCIC) System E.
Reactor Core twdnsion Coohng (RCIC) Sysicm 1.
The RCIC System sheE be operable whenever there is 1.
RCIC System teshng shall be perfoemed as follows l
irradiated fuel in Sie reactor veneet and the reactor provided a reactor steam supply is avadable. It steam is pressure is grosser Sten 150 peig and reactor mrdarit not avadahia at the time the survedlance test is scheduled tsmperalure is greater then 2127 esecept from tio time to be performed, the test shaN be performed within ten that the RCIC System is made or formd to be inoperabio days of continuous operation from the time steam i
for any reason, continued reactor power operation is becomes avammeen.
pom nanda during Wie emnemnerig 7 days unless the e
system is made opera' so certler provided Stat during tisse ite m Frequency u
7 days #ie MCI Systemis operable.
a.
Simuissed Auiomanc
/ operating 2.
If the requirements of 3.5.E cannot be mel, the reactor Actuation (and Restart )
cycle -
sheE be placed in the cold condition and pressure less Test On geaymwds then 150 peig wiIhin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
Pump Operabluty Once/ month 3.
Low power physics testing and reactor operator training c.
Motor Operated
,Or:ce/ month shaE be permilled whh inoperable components as specilled in 3.5.E.2 above, provided thes reactor cooient h Operabeny d.
Flow Rate Once/3 rnonths i
4.
The RCIC system is not required to be operable dunng e.
Ta=8mhle Check Tested for operabihty W preneure and W W wth p cootent temperatures behveen 2127 and 30lFF and any time #ie reactor is en Wie cold conddion irradated fuel in the reactor vessel provided a5 control ex
- hours, if rods are inserted.
operabibly tests have not been performed dwing the precedmg 31 days.
f.
Logic System (Once/ operating Functional Test
(
Once per.N mw4s Automatic restart on a low water level signal which is-
~
Amendment No.
,t sW=am_ wit to a high water level trip.
8
}
JAFNPP i
4.5 BASES I
=l The testing intervai for the Core and Containment Coolmg The RCIC Row rate is described in the UFSAR. The flow rates
[
Systems is based on a quantitative ramahlhey analysis, industry to be delivered to the raar*r core for HPCI, the LPCI rnode of prachce, judgement, and practicalky. The Emergency Core RHR, and CS are hmar* on the SAFER /GESTR LOCA analysis.
Coolmg Systems have not been designed to be luny ta=tahia The Now rates for the LPCI mode of RHR and CS are modified during operation. For example. Wie core spray Anal admission by a 10 percent rartenarvi from the SAFER /GESTR LOCA valves do not open untB reactor pronou o has fasen to 450 poig; analysis. The rartreirmis are based on a sensitivity analysis thus, during operation even if hlW1 drywet pressure were poneral Flectric MDE-834786) performed for the parameters sinud=8 art, Sie Ansi valves wodd not open. In Sie case of the usedin114 SAFER /GESTR analysis.
HPCI, automatic initiallon during power operation wodd result E
I" The CS survemance requirement includes an aNowance for 1
doeirable.
system leakage in arireairwi to the Sow rate required to be om-PWY M 6 delwered to the reactor core. The leak rate from the core spray The systems wM be automaticeNy actueled(durino a resueNno}8 -
piping inside the reactor but outside the core shroud is in the case of the Core Spray System, condensate assumed in the UFSAR and includes a known loss of less than storage tank water wlE be purnped to tie veneel te verify the 20 gam from the 1/4 inch, dameter vont hole in the core spray operability of the core spray header. To incremos the avanshamy Tbox connection in each of the loops, and in the B loop, a of the indvidual components of tie Core and Containment potential addnional loss of less than 40 gpm from a clamsheN i
Cooling Systems Wie cornponents which mehe up the system repair whose structure weld covers only 5/6 of the i.e., instrumentation, pumps, valve operators, etc., are tested circumference of the pipe. Both of these identded sources of more frequendy. The 3netrumentation is ks-A-2,- tested leakage occur in the space between the reactor vessel wall and each month. LNeewtoo, the pumps and motor-operated valves the core shroud. Therefore flow lost through these leak are also tested each monih to aneure their operabuity. The sources does not conertbute to core coolmg.
(<
m test W m W the pumps W W operators b W to be We W The surveluance requirements to ensure that the discharge of twee systems.
piping of the core spray, LPCI mode of the RHR, HPCI, and RCIC Systems are filled provides for a visual caservation that With components or subsystems out<3f-service, overaN core weer flows from a high point vent. This ensures that and contamment cooling reliabNity is maintained by verifying the operability of the remaining cooling equipment. Consistent with the definition of operable in Section 4.0.C, demonstrate mems conduct a test to show; verify means that the l
associated surveillance activities have been satisfacionly j
performed withm the specilled time interval.
I t
O.
j
JAFNPP 3.7 (cord'd) 4.7 (cont'd)
At least once per operating cycle, manual operabehty e.
i of the bypass valve for filter coohng shaN be demonstrated.
f.
Standby Gas Treatmerd System instrumentation Cahbration-differentsal Once/ operating pressure C
smtches m
p,,.2./ moy #,3 2.
From and aner the date that one drcuit of the Stan@y Gas Treatment System is made or found to be inoperabio for 2.
When one circuit of the Standby Gas Treatment System any reason,the toNowing wodd apply:
becomes anoperable, the operable circuit shall be venised to be operable immartataly and daily thereafter.
a.
N in Start-up/ Hot Stan@y, Run or Hot Shutdown modo, reactor operation or irradated fuel hancNing is permissible only during the =% 7 days l
unless such circuit is sooner made operable, provided that dunn0 such 7 days all acave components of the other Stan@y Gas Trealment Circuit ehes be operable.
b.
N in Refuel or Cold Shutdown mode, reactor operation or irradiated fuel handing is pemussible j
only during the are==rerig 31 days unless such circuit is sooner made operable, provided that j
during such 31 days as aceve components of the l
other Standby Gas Treatment Circuit shaN be j
3.
If 9meiEr'a8ns 3.7.B.1 and 3.7.B.2 are not met, the reactor shaN be placed in the cold condition and irradiated i
fuel hancSeng operations and operations that could reduce the st= ddnwn margin shall be protubited.
Amendment No. jd.f4, }MI, k f
iaa i
'J 3.7 (cont'd) 4.7 (cont'd)
Secondary containment capability to maintain a c.
1/4 in. of water vactrim under calm wind conditions with a filter train flow rate of not more than 6,000 cim, shall tm demonstrated at each refueling outage prior to refueling.
D.
Pnmary Contanment laciation Valvan D.
Primary Containment isolation Valves 1.
Whenever primary contamment integnty is required per 1.
The primary containment isolation valves survedlance 3.7.A.2, containment isolabon valves and all instrument shaR be performed as follows:
line excess flow check valves shaN be operable, except as specded in 3.7.D.2. The containment vent a.
At least once per operating cycle, the operable and purge valves sher be limited to openmg angles isolation valvas that are power operated and less than or equal to that specded below:
automatically initiated shall be tested for simulated automatic initiation and for closure Valve Number Marimum namnen Arvda 27AOV-111 40*
~
time.
Aw W wAs,
( tieast once per operating cycle)ythe instrument j
27AOV-112 40' b.
27AOV-113 40' line excess flow check valves shall be tested for 27AOV-114 50*
proper operation.*
l 27AOV-115 50*
27AOV-118 50*
c.
At least once per quarter:
27AOV-117 50*
27AOV-118 50' (1.) AN normally open power-operated isolation valves (except for the main stream line and Reactor Buildng Closed Loop Cooling Water System (RBCLCWS) power-operated isolation valves) shall be fully closed and reopened The current surveillance interval for testing instrument line excess flow check valves is extended until the end of the R11/C12 refueling outage scheduled for January,1995. This is a one-time extension, effective only for this surveillance interval. The next surveillance interval will begin upon completion of this surveillance.
Arnendment No. t64. % 197 2
185
JAFNLT 3.9 (cont'd) 4.9 (cont'd) 3.
From and after the time both power supphes are made or found moperable the seector shnu be brought to cold condition wethen 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
G.
REACTOR PROTECTION SYSTEM ELECTRICAL PROTECTION G.
REACTOR PROTECTION SYSTEM ELECTRICAL PROTECTION ASSEldK.lES ASSEfMILIES I
Two RPS electncal protection assemblies for each inservice The RPS alectrical protection assemblies ' strumentation shaN m
RPS MG set and inservice sleemose source shou be operable be determmed operable by:
except es W below:
j 1.
Performeng a channel functiormt test each time the plant is 1.
Wsth one RPS electncal protection assemtdy for an in cold shutdown for a ponod of more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, I
inservice RPS MG set or an irservice attemete power unless performed in the previous 6 months.
supply inoperable, restore the inoperable channel to Oct F #Vmds 6tiosst once por operanno c[ demonstrating the operable status withm 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the =-ed 2.
RPS MG set or altamate pourat supply from sorwece.
operability of over-voltage, under-voltage and under-frequency protective instrumentation by 2.
With two RPS electrical pretection assembhos for an performance of a chenest caletwation including samulated
[
ismorwece RPS MG set or ar4 inservice attemete power automatic actuation of the protective relays, trippeng logic l
supply inog stable, restore at least one to operaine status and output circuit tweakers and verifying the following l
within 30 minutes or remove the associated RPS MG set set pomas:
or sleemste power aupsh from sorwece.
RPS MG. SET _ SOURCE OVER-VOLTAGE s132V s4 second Time Delay l
i V
UNDER-VOLTAGE 2(lO8y) //2 3 V 54 second Time Delay l
UNDER-FREQUENCY 257HZ l
s4 second Time Delay l
Amendment No.
, 1)N (continued on pape 222d) j
AFNPP 4.9 BASES (con't)
D.
Not Used
. E.
Battary System Moesurements and electrical tests are conducted at specified intervals to provide indmotion of cell condition and to determine the discharge capointity of the betteries. Performance and service tests are r.onducted in accordence with the recommendatione of IEEE 450-1987.
e fl F.
LPCI MOV indanandant Power Summhr Moseurement and electrical tests are conducted at specified intervals to provide indication of cell condition, to determine the discharge capebility of the bettery.
Performance and service toets are conducted in accordance with the recommendations of IEEE 450-1987.
l G.
Reactor Protection Prwar Sunabas Functional tests of the electncal protection assemblies are conducted at specified intervals uggging a built-in test device and once per(operating cycif>by performeng an instrument cabbration which@ operation within the l
limits cf Section 4.9.G.
\\
i 24 mh3 I
i f
'** Y Y' f' Y' Y'
^
)
ggg i
I
[
JAFNPP 3.11 (cont'd) 4.11 (cont'd) ventilation air supply fan and/or filter may be out of b.
Di-octylphtelete (DOP) test for particulate filter t
service for 14 days.
officiency yester then 99% for particulate greater than 0.3 micron size.
l c.
Freon-112 test for charcoal filter bypass as a measure of filter efficiency of at least 99.5% for halogen removal.
d.
A sample of charcoal filter shall be analyzed once a year to assure hologen removal efficiency of at least 99.5 %.
2.
The main control room air redestion monitor shell be 2.
Operability of the main control room air intake radiation operable whenever the control room emergency monitor shall be tested once/3 months.
ventilation air supply fans and filter trains are requwed to be operable by 3.11.A.1 or filtration of the control room ventilation intake air must be initiated.
i
)
Temperature transmitters and differential pressur[e 3.
The control room emergency ventdation system shen not 3.
switches shall be calibrated 6nce/ operating cycle be out of service for a period eve =adirig 3 days dunng normal reactor operation or refuelira operations. In the ogc,_ p,q,,4g*
event that the system is not retumed to service within 3 days, the reactor shen be in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and any handing of irradiated fuel, core alterations, i
and operations with a potenteel for draining the reactor t
vessel shell be suspended as soon as practicable t
l 4.
Not Used 4.
Mein control room emergency ventilation air supply system capacity shen be tested once every 18 months to l
assure that it is 110% of the design value of 1000 cfm.
j i
1 Amendment No.1)4, If, J9[
/
238 i
s a
JAFNPP 3.11 (cont'd) 4.11 (cont'd)
B.
Crescent AreaVsondahnn B.
Crescent AreaVentilation l
Crescent area venidation and cooling equiprnent shall be 1.
t s semng EM Ws M be operable on a conhnuous basis whenever specdication 35.A, L
3.5.0, and 3.5.C are required to be sabslied raw wh once/3 MM.
2.
Each unit coolet's temperature control instrument shall be l 1.
Frorn and aner the date that more than one unit cooler cahbrated 6nce/operatvia cycle,] -
semng ECCS compartments in the same haN of the cuc4. par-.N maa M s.
crescent area are made or found to be inoperable, all ECCS compormits in that trJf of the crescent area shas be considered to be inoperable for purposes 1 pahan 3.5.A. 3.5.B. and 3.5.C.
2.
If 3.11.B.1 cannot be met, the reactor shall be placed in a cold condehon within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
C.
Battery Floom Ventilation
"'Y Battery room ventilation equipmerd shall be demonstrated Battery room ventilahon shall be operable on a conhnuous basis operable once/ week.
whenever aghaarn 3.9.E is required to be tahatad.
1.
When it is determined that one battery room ventilation 1.
From and after the date that one of the battery room system is anoperable, the remaining ventilatiors system i
venhiation systems is made or found to be inoperable, its shall be verified operable and daily thereafter.
associated battery shall be consadored to be inoperable for 1
Tw ho hh W dhis pme purposes d W 3.9E switches shall be cahbrated@6ce/ operating cycse.)
o.)ce_ (ur :N meu AS.
I i~.
O b"4 e
O gg j.ty tA. g
r k
e e
s LINITING CONDITIONS FOR OPERATION St@ EILLANCg REQUIREMENTS 3.7 OFFCAS TREA1NENT SYSTEM EIPLOSIVE CAS MIITURE 3.7 0FFCAS TREATMENT SYSTEM EXPLDSIVE CAS MIKTtMtE INSTRtMENTATION INSTRtMENTATION i
i Applicability Applicability h
(
l Applies to the condenser offgas treatment sys-Applies to the offgas treatment system instru-
{
tem recombiner operation.
mentation, which monitors the critical oper-attes parameters of the primary recombiner.
objective Objective e
To ensure proper conditions for the offges re-To ensare that instrumentation required for au-combiner to operate at desiga efficiency in tomatic isolation is maintained and calibrated.
order to prevent en explosive misture of gases in the charcoal treatment system.
Specifications Specifications
- a. The concentration of either hydrogen or oxy-
- a. The concentration of either hydrogen or oxy-4 ges in the esta condenser of fgas treatment gen in the usin condenser offgas treatment system shall be limited to less than or system shall be determined to be within the equal to 41 by volume.
limits of Specification 3.7.a by continuous-ly monitoring the waste gases in the main condenser offgas treatment system whenever i
the main condenser evacuation system is in operation with the hydrogen or oxygen-mont-tors. Operation of the hydrogen or oxygen monitors shall be verified in accordance I
with Specificetion 3.7 b. I@d73,'7,f,f, l
- b. Whenever continuous hydrogen o'r oxygen non-spanitoring, the following instrumentation itoring is not available, operation of the l
shall be operational and capable of pro-explosive gas mixture instruments listed in viding automatic isolation of the offgas Specification 3.7.h shall be verified.
I i
Amendment No. [ )
32 1
1
6 i
JAFNPP LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS treatment system % the fotowsng conditions:
1.
An instrument check shall be performed daily when the cifgas treatment system is in operation.
1.
The offgas dilution steem flow instrumentation shall M C ' M u. n,I alarm and automaticaRy isolate the offges recombener 2.
An instrument channel functional test shaR be performed I
system at a low How seapoint greater then or aquel to once pe(operating cycle 7 m way 6300 pounds per hour and at a high flow setpoint less
-N mw Ar.
iso Sr.e.ru Ao an.b An instrument channel calibration (shaN be performed then or equel to 7900 pounds per hour.
3.
once per 6sratmo cycssW 2.
The offgas recombiner inlet temperature sensor shen
.N me A.
storm and automatically isoiste the offges recombiner
(
system at a temperature seapoent of greater then or aquel T-4" W b M d '"" d A b ^'
j ""#
g'"
g)
M & o% e hd~pa & exy3=4 me.lileu sktl W.
l to 125'C.
3 Por % ma0 cace ennr3 3 mobs,
h7 3.
The offges recombiner outlet temperature sensor shou atorm and automaticaNy isolete the offges treatment systwo at a temperature setpoint of greater then or equel to 150*C.
I c.
In lieu of continuous hydrogen or oxygen monitoring, the c.
With condenser offgas treatment system recombiner in f
condenser offges treatment system recombiner effluent shen service, in lieu of continuous hydrogen or oxygen monitoring, he analyzed to verify that it contains less then or equel to 4%.
the hydrogen content shall be verified weekly to be less than l
hydrogen by volume.
or equel to 4 % by volume.
d.
With the requirements of the above specifications not in the event that the hydrogen content cannot be verified, satisfied, restore the recombener system to within operating operation of this system may continue for up to 14 days.
specifications or suspend use of the charcoal treatment system withm 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
i l
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i Amendment No. [,1[,1[, %
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i NOTES FOR TABLE 110-2 (a)
Functional tests, calibrations and instrument checks need not be performed when 4
j these instruments are not required to be operable or are tripped.
(b) instrument checks shall be performed at least once per day during these periods when j
the instruments are required to be operable.
(c)
A source check shall be pe: formed prior to each release.
(d)
Uquid radwaste effluent line irstrumentation surveillance requirements need not be performed when the instruments are not required as the result of the discharge path i
j not being utilized.
(e)
An instrument channel calibration shall be performed with known radoactive sources standardized on plant equipment which has been calibrated with NBS traceable
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standards.
s co-p < M m w k (f)
Simulated automatic actuation shall be performed 6nce e c=-.c cvue,a Where e
possible, aN logic system functional tests will be performed using the test jacks.
(g)
Refer to Appendx A for instrument channel furbilonal test and instrument channel l
calibration requirements (Table 4.2-1). These requirements are performed as part of main steam high radation monitor surveillances.
(h)
The logic system functional tests shall include a caNbration of time delay relays and timers renesary for proper functioning of the trip systems.
(i)
This instrumentation is excepted from the functional test definition. The functional test we consist of injecong a simulated electrical signal into the measurement rhannel.
These instrument channels wNl be ceNbrated using simulated electrical signals once every three months.
s Amendment No. k 2,0[
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