ML20198A705
| ML20198A705 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/30/1998 |
| From: | WASHINGTON PUBLIC POWER SUPPLY SYSTEM |
| To: | |
| Shared Package | |
| ML17292B455 | List: |
| References | |
| NUDOCS 9812170093 | |
| Download: ML20198A705 (126) | |
Text
9 REVISIONS 8 THROUGH 13 TO THE WNP-2 TECHNICAL SPECIFICATION BASES A
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REVISIONS 8 THROUGH 13 TO THE WNP-2 TECHNICAL SPECIFICATION BASES O
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REVISION 8 TECHNICAL SPECIFICATION BASES O
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REVISION NO. 8 WNP-2 TECHNICAL SPECIFICATIONS O-The following instructional information and checidist is furnished to help you insert revised pages for Revision 8 into the Washington Public Power Supply System Plant No. 2 Technical Specification Bases.
Discard the old sheets and i:. sert the new sheets as listed below.
~
If you have any questions concerning insertion of this revision, or if you are missing any pages, please contact Lori Walli at (509) 377-4149.
Discard Insert Old Page New Pace BAS LEP-3/ BAS LEP-4 BAS LEP-3/ BAS LEP-4 B 3.7-3 / B 3.7-4 B 3.7-3 / B 3.7.4 O
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SW System and UHS B 3.7.1 BASES APPLICABLE The SW System, together with the UHS, satisfy Criterion 3 of SAFETY ANALYSES Reference 7.
(continued)
LC0 The OPERABILITY of subsystem A (Division 1) and subsystem B (Division 2) of the SW System is required to ensure the effective operation of the RHR System in removing heat from the reactor, and the effective operation of other safety related equipment during a DBA or. transient.
Requiring both subsystems to be OPERABLE ensures that either subsystem A or B will be available to provide adequate capability to meet cooling requirements of the equipment required for safe shutdown in the event of a single failure.
A subsystem is considered OPERABLE when:
a.
The associated pump is OPERABLE; and b.
The associated piping (including the suction piping and spray ring in the associated UHS spray pond),
valves, instrumentation, and controls required to perform the safety related function are OPERABLE.
OPERABILITY of the UHS is based on a maximum water temperature of 77'F and an instantaneous average minimum l
water level of both ponds at or above elevation 432 ft 9 inches mean sea level and an average sedimentation depth of < 0.5 ft, consistent with the
- analysis of Ref. 2, and an OPERABLE siphon line between the two spray ponds.
The isolation of the SW System to components or systems may render those components or systems inoperable, but does not affect the OPERABILITY of the SW System.
OPERABILITY of the High Pressure Core Spray (HPCS) Service Water (SW) System is addressed by LC0 3.7.2.
APPLICABILITY In MODES 1, 2, and 3, the SW Syster and UHS are required to be OPERABLE to support OPERABILITY of equipment serviced by the SW System and UHS that is required to be OPERABLE in these MODES.
(continued)
WNP-2 B 3.7-3 Revision 8
SW System and bHS B 3.7.1 i
BASES l
APPLICABILITY In MODES 4 and 5, the OPERABILITY requirements of the SW System and UHS are determined by the systems they support, (continued) and therefore, the requirements are not the same for all facets of operation in MODES 4 and 5.
Thus, the LCOs of the systems supported by the SW System and UHS'will govern SW System and UHS OPERABILITY requirements in MODES 4 and 5.
i ACTIONS A.I With average sediment depth in either or both spray ponds 2 0.5 and < 1.0 ft, water inventory is reduced such that the combined cooling capability of both spray ponds may be less than required for 30 days of operation after a LOCA.
Therefore, action must be taken to restore average sediment depth to < 0.5 ft. The Completion Time of 30 days is based on engineering judgement and plant operating experience and takes into consideration the low probability of a design basis accident occurring in this time period.
B.1 If one SW subsystem is inoperable, it must be restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. With the unit in this condition, the remaining OPERABLE SW subsystem is adequate to perform the heat removal function.
However, the overall reliability is reduced because a single failure in the OPERABLE SW subsystem could result in loss of SW function.
The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time was developed taking into account the redundant capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.
The Required Action is modified by two Notes indicating that the applicable Conditions of LC0 3.8.1, "AC Sources--
Operating," and LC0 3.4.9, " Residual Heat Removal (RHR)
Shutdown Cooling System-Hot Shutdown," be entered and the Required Actions taken if the inoperable SW subsystem results in an inoperable DG or RHR shutdown cooling subsystem, respectively. This is in accordance with LC0 3.0.6 and ensures the proper actions are taken for these components.
(continued)
O WNP-2 B 3.7-4 Revision 5
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TECHNICAL SPECIFICATION BASES i
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REVISION NO. 9 WNP-2 TECIINICAL SPECIFICATION BASES O
The following instructional information and checklist is furnished to help you insert revised pages for Revision 9 into the Washington Public Power Supply System Plant No. 2 Technical Specification Bases.
Discard the old sheets and insert the new sheets as listed below.
If you have any questions concerning insertion of this revision, or if you are missing any pages, please contact Lori Walli at (509) 377-4149.
Discard Insert Old Page New Page BAS LEP-1/ BAS LEP-5 BAS LEP-1/ BAS LEP-5 B 3.6-68 / B 3.6-69 B 3.6-68 / B 3.6-69 1
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Prinary Containment Hydrcgen Recombiners B 3.6.3.1 BASES ACTIONS
.G.d (continued)
If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS Performance of a system functional test for each primary containment hydrogen recombiner ensures that the recombiners are OPERABLE and can attain and sustain the temperature necessary for hydrogen recombination.
In particular, this SR requires verification that the minimum heater outlet temperature increases to a 500*F in s 90 minutes and that it is maintained a 500*F and cycles about its setpoint for 2 45 minutes to check the capability of the recombiner to l
properly function (and that significant heater elements are O
not burned out). The SR also verifies that the catalyst efficiency is confirmed.
This is performed by introducing m 1 v/o hydrogen into the catalyst bed preheated to a temperature s 300*F, and verifying: a) the effluent stream has a hydrogen concentration s 25 ppm by volume; and b)
= 75% of the temperature increase occurs above the fourth temperature measuring device in the catalyst bed.
Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
SR 3.6.3.1.2 This SR ensures that there are no physical problems (i.e.,
loose wiring or structural connection, or deposits of foreign materials) that could affect primary containment hydrogen recombiner operation.
Since the recombiners are mechanically passive, they are not subject to mechanical (continued)
O WNP-2 B 3.6-68 Revision 9
Primary Containment Hydrogen Recombiners B 3.6.3.1 h
BASES i
SURVEILLANCE SR 3.6.3.1.2 (continued)
REQUIREMENTS failure. The only credible failures involve loss of power, blockage of the internal flow path, missile impact, etc.
A visual inspection is sufficient to determine abnormal conditions that could cause such failures.
Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
SR 3.6.3.1.3 This SR requires performance of a resistance to ground test of each heater phase to ensure that there are no detectable grounds in any heater phase.
This is accomplished by verifying that the resistance to ground for any heater phase is 2 10,000 ohms within 30 minutes following completion of a system functional test or heatup of the system to normal operating temperature.
Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
REFERENCES 1.
2.
10 CFR 50, Appendix A, GDC 41.
3.
Regulatory Guide 1.7, Revision 1, September 1976.
4.
FSAR, Section 6.2.5.
5.
O WNP-2 B 3.6-69 Revision 5
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REVISION 10 TECHNICAL SPECIFICATION BASES O
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WNP-2 TECHNICAL SPECIFICATIONS BASES
'Ihe following instructional information and checklist is furnished to help you insert a revision into the Washington Public Power Supply System Plant No. 2 Technical Specification Bases.
If you have any questions concerning insertion of this revision, or if you are missing any pages, please contact 1.ori Walli (509) 377-4149.
Discard Insert Old Paeg New Pane BAS LEP-I through BAS LEP-5 BAS LEP-1 through BAS LEP-5 B 3.6-26/B 3.6-27 B 3.6-26/B 3.6-27 B 3.6-28/ blank B 3.6-28/ blank B 3.6-68/B 3.6-69 B 3.6-68/B 3.6-69 O
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PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.8 REQUIREMENTS (continued)
This SR requires a demonstration that each EFCV is OPERABLE by verifying that the valve actuates to the isolation position on an actual or simulated instrument lins break condition. This SR provides assurance that the instrumentation line EFCVs will perform as designed.
The excess flow check valves in reactor pressure sensing lines are tes:ed by providing an instrument line break signal with-l pressure at 85 psig to 110 psig. Testing within this pressure range provides a high degree of assurance that these valves will close during an instrument line break while at normal operating pressure. The excess flow check l
valves in primary containment pressure sensing lines are tested by providing an instrument line break signal with pressure at approximately ~35 psig, since this is the pressure they would expect to experience during a DBA.
The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.
,n Operating experience has shown that these components usually
(")
pass this Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
In addition, due to operational concerns, the Surveillance should not be l
performed during MODES 1, 2, or 3.
This restriction has been established to limit the thermal cycles at the containment penetration.
SR 3.6.1.3.9 The TIP shear isolation valves are actuated by explosive charges. An in place functional test is not possible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. Other administrative controls, such as those that limit the shelf life and (continued)
D\\b WNP-2 B 3.6-26 Revision 10
PCIVs 8 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.9 (continued)
REQUIREMENTS operating life, as applicable, of the explosive charges, must be followed. The Frequency of 24 months on a STAGGERED TEST BASIS is considered adequate given the administrative controls on replacement charges and the frequent checks of circuit continuity (SR 3.6.1.3.4).
SR 3.6.1.3.10 This SR ensures that the leakage rate of secondary containment bypass leakage paths is less than the specified This provides assurance that the assumptions leakage rate.
in the radiological evaluations that form the basis of the FSAR (Ref. 1) are met. The leakage rate of each bypass leakage path is assumed to be the maximum pathway leakage (leakage through the worse of the two isolation valves) unless the penetration is isolated by use of one closed and de-activated automatic valve, closed manual valve, or blind In this case, the leakage rate of the isolated flange.
bypass leakage path is assumed to be the actual pathway leakage through the isolation device.
If both isolation valves in the penetration are closed, the actual leakage rate is the lesser leakage rate of the two valves. The Frequency is required by the Primary Containment Leakage This SR simply imposes additional Rate Testing Program.
acceptance criteria.
SR 3.6.1.3.11 The analyses in Reference 1 are based on leakage that is less than the specified leakage rate.
Leakage through each This MSIV must be :s 11.5 scfh when tested at P, (25 psig).
ensures that MSIV leakage is properly accounted for in determining the overall primary containment leakage rate.
The Frequency is required by the Primary Containment Leakage Rate Testing Program.
(continued)
O B 3.6-27 Revision 10 WNP-2
PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.12 REQUIREMENTS (continued)
Surveillance of hydrostatically tested lines provides assurance that the calculation assumptions of Reference 1 are met. The acceptance criteria for the. combined leakage of all hydrostatically tested lines is s 1.0 gpm times the total number of hydrostatically tested PCIVs when tested at 1.1 P. (41.8 psig). The combined leakage rates must be tested at the Frequency required by the Primary Containment Leakage Rate Testing Program.
1 REFERENCES 1.
FSAR, Chapter 6.2.
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2.
FSAR, Section 15.2.4.
i 3.
4.
Licensee Controlled Specifications Manual.
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O WNP-2 B 3.6-28 Revision 10
Primary Containment Hydrcgen Recembiners B 3.6.3.1 BASES ACTIONS
.G.J.
(continued)
If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be i
brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS Performance of a system functional test for each primary containment hydrogen recombiner ensures that the recombiners I
are OPERABLE and can attain and sustain the temperature necessary for hydrogen recombination.
In particular, this l
SR requires verification that the minimum heater outlet temperature increases to a 500*F in s 90 minutes and that it is maintained a 500*F and cycles about its setpoint for l
2 45 minutes to check the capability of the recombiner to 1
properly function (and that significant heater elements are O
not burned out). The SR also verifies that the catalyst efficiency is confirmed.
This is performed by introducing i
= 1 v/o hydrogen into the catalyst bed preheated to a temperature s 300*F, and verifying: a) the effluent stream l
has a hydrogen concentration s 25 ppm by volume; and b) m 75% of the temperature increase occurs above the fourth temperature measuring device in the catalyst bed.
Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
SR 3.6.3.1.2 This SR ensures that there are no physical problems (i.ec, loose wiring or structural connection, or deposits of foreign materials) that could affect primary containment hydrogen recombiner operation.
Since the recombiners are mechanically passive, they are not subject to mechanical (cortinued)
O WNP-2 B 3.6-68 Revision 9 e.
7
Primary Containment Hydrogen Recombiners B 3.6.3.1 BASES SURVEILLANCE SR 3.6.3.1.2_
(continued)
REQUIREMENTS The only credible failures involve loss of power, failure.
A blockage of the internal flow path, missile impact, etc.
visual inspection is sufficient to determine abnormal conditions that could cause such failures.
Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Therefore, the Frequency was concluded to be Frequency.
acceptable from a reliability standpoint.
SR 3.6.3.1.3 This SR requires performance of a resistance to ground test of each heater phase to ensure that there are no detectable This is accomplished by grounds in any heater phase.
verifying that the resistance to ground for any heater phase is 2 10,000 ohms within 30 minutes following completion of a system functional test or heatup of the system to normal operating temperature.
Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
1 l
I REFERENCES 1.
10 CFR 50, Appendix A, GDC 41.
3.
Regulatory Guide 1.7, Revision 1, September 1976.
4.
FSAR, Section 6.2.5.
5.
O WNP-2 B 3.6-69 Revision 5
O REVISION 11 TECHNICAL SPECIFICATION BASES O
O
WNP-2 TECHNICAL SPECIFICATIONS BASES The following instructional information and cwuict is furnished to help you insert a revision into the Washington Public Power Supply System Plant No. 2 Technical Specification Bases.
If you have any questions concerning insertion of this revision, or if you are missing any pages, please contact R Fernald (509) 377-5307.
Discard Insert Old Page New Pane BAS LEP-1 through BAS LEP-5 BAS LEP-1 through BAS LEP-5 B 2.0-3/B 2.0-4 B 2.0-3/B 2.0-4 O
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_ _ - _ _ _. _.. _ _ _. _. _.. _ _ _ _ _.. ~
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Reactor Core SLs B 2.1.1 O
BASES v
APPLICABLE 2.1.1.1 Fuel Claddina Intearity (continued)
SAFETY ANALYSES bundle flow for all fuel assemblies that have a relatively high power and potentially can approach a l
critical heat flux condition. The minimum bundle flow is > 28 x 10' lb/hr. The coolant minimum bundle flow and maximum flow area are such that the mass flux is
> 0.25 x 10' lb/hr-ft.
Full scale critical power 2
tests taken at pressures down to 14.7 psia indicate that the fuel assembly critical power at 0.25 x 10' lb/hr-ft' is approximately 3.35 MWt. -At j
25% RTP, a bundle power of approximately 3.35 Mwt I
corresponds to a bundle radial peaking factor of
> 2.9, which is significantly higher than the expected peaking factor. Thus, a THERMAL POWER limit of 25% RTP for reactor pressures < 785 psig is conservative.
2.1.1.2 Mf3 The MCPR SL ensures sufficient conservatism in the operating MCPR limit that, in the event of an A00 from the limiting O
condition of operation, at least 99.9% of the fuel rods in the core would be expected to avoid boiling transition. The i
margin between calculated boiling transition (i.e.,
MCPR - 1.00) and the MCPR SL is based on a detailed statistical procedure that considers the uncertainties in monitoring the core operating state. One specific uncertainty included in the~SL is the uncertainty inherent in the critical power correlations. ~ Reference 7 describes the interim use of increased ANFB additive constant uncertainty for the SPC ATRIUM-9X fuel during Cycle 14.
l Reference 4 describes the methodology used in determining the MCPR SL for Siemens Power Corporation fuel.
Reference 5 describes the methodology used in determining the MCPR SL for ABB CEN0 fuel.
The critical power correlations are based on a significant body of practical test data, providing a high degree of assurance that the critical power, as evaluated by the correlation, is within a small percentage of the actual critical power. As long as the core pressure and flow are l
within the range of validity of the critical power correlations, the assumed reactor conditions used in defining the SL introduce conservatism into the limit because bounding high radial power factors and bounding flat (continued)
WNP-2 B 2.0-3 Revision 11 1
Reactor Core SLs B 2.1.1 BASES f
APPLICABLE 2.1.1.2 tiCP3 (continued) l SAFETY ANALYSES local peaking distributions are used to estimate the number This conservatism and the l
of rods in boiling transition.
inherent accuracy of the critical power correlations provide a reasonable degree of assurance that there would be no transition boiling in the core during sustained operation at If boiling transition were to occur, there is the MCPR SL.
reason to believe that the integrity of the fuel would not Significant test data accumulated by the be compromised.
NRC and private organizations indicate that the use of a boiling transition limitation to protect against cladding Much of the data failure is a very conservative approach.
indicate that BWR fuel can survive for an extended period of time in an environment of boiling transition.
_2.1.1. 3 Reactor Vessel Water level During MODES I and 2, the reactor vessel water level is required to be above the top of the active irradiated fuel With fuel in the to provide core cooling capability.
reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due If the water level should drop to the effect of decay heat.
below the top of the active irradiated fuel during thisThis period, the ability to remove decay heat is reduced.
reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that The the water level becomes < 2/3 of the core height.
reactor vessel water level SL has been established at the top of the active irradiated fuel to provide a point that can be monitored and to also provide adequate margin for effective action.
reactor core SLs are established to protect the ir.tegrity of the fuel clad barrier to prevent the release of Th SAFETY LIMITS SL 2.1.1.1 and radioactive materials to the environs.
SL 2.1.1.2 ensure that the core operates within the fuel SL 2.1.1.3 ensures that the reactor vessel design criteria. water level is greater than the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations.
(continced)
Revision 7l 8 2.0-4 WNP-2
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REVISION 12 TECHNICAL SPECIFICATION BASES l
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WNP-2 O
TECHNICAL SPECIHCATIONS BASES
'Ihe following instructional information and checklist is furnished to help you insert a revision into the Washington Public Power Supply System Plant No. 2 Technical Specification Basra.
If you have any questions concerning insertion of this revision, or if you are missing any pages, please contact R Fernald (509) 377-5307.
Discard Insert Old Pane New Page BAS LEP-1 through BAS LEP-5 BAS LEP-1 through BAS LEP-5 B 3.3-106/B 3.3-107 B 3.3-106/B 3.3-106a B 3.3-106b/B 3.3-107 B 3.3-155a/ blank B 3.3-156/B 3.3-157 B 3.3-156/B 3.3-156a B 3.3-157/ blank O
ECCS Instrumentation B 3.3.5.1 l
L BASES O
APPLICABLE 1.b. 2.b.
Drywell Pressure-Hich (continued)
SAFETY ANALYSES, l
LCO, and to pressurize the primary containment to Drywell l
APPLICABILITY Pressure-High setpoint.
Refer to LC0 3.5.1 for Applicability Bases for the low pressure ECCS subsystems and te LCO 3.8.1 for Applicability Bases for the DGs.
1.c. 1.d. I.e. 2.c. 2.d J.e.
LPCS and LPCI Pumos A. S. and j
C Start-LOCA Time Delav Relav and LPCI Pumos A and B l
Start-LOCA/ LOOP Time Delav Relav The purpose of these time delays is to stagger the sta"t of l
the ECCS pumps that are in each of Divisions 1 and 2,
.hus limiting the starting transients on the 4.16 kV emergency buses.
The LOCA Time Delay Relay Function is only necessary when the power is being supplied from the TR-S transformer, l
and the LOCA/ LOOP Time Delay Relay Function is only necessary when power is being supplied from the standby i
power sources (DG). However, since the LOCA/ LOOP time delay does not degrade ECCS operation, it remains in the pump start logic at all times. The Pump Start-LOCA and LOCA/ LOOP Time Delay Relays are assumed to be OPERABLE in l
the accident and transient analyses requiring ECCS initiation. That is, the analysis assumes that the pumps will initiate when required and~ excess loading will not cause failure of the power sources due to a degraded voltage condition (see Table 3.3.8.1-1),
There are four Pump Start-LOCA Time Delay Relay channels, one in each of the low pressure ECCS pump start logic circuits.
Each of the LOCA Time Delay Relay channels consists of a Drywell Pressure-High and Reactor Level 2 sensor, auxiliary relay logic, and circuit breaker position switches to initiate the LOCA time delay relay when on TR-S.
The LOCA Time Delay Relay channel sensors also provide Drywell Pressure-High RPS Trip (Table 3.3.1.1-1 Function 6) and Drywell Pressure / Level 2 Primary Containment and RWCU Isolation (Table 3.3.6.1-1 Functions 2.b, 2.c, and 4.j) and Secondary Containment Isolation (Table 3.3.6.2-1 Functions 1 and 2) channel signals. A Drywell Pressure-High and a Level 2 sensor are in series and deenergize (either instrument) to initiate a LOCA Time Delay Relay channel.
Two LOCA Time Delay Relay channels are provided for each division low pressure ECCS Function.
Initiation of one LOCA Time Delay Relay channel will result in the other c0CA Time (continued)
WNP-2 B 3.3-106 Revision 12 l
ECCS Instrumentation B 3.3.5.1 BASES 1.c. 1.d. l.e. 2.c. 2.d. 2.e.
LPCS and LPCI Pumos A. B. and APPLICABLE C Start-LOCA Time Delay Relay and LPCI Pumos A and B SAFETY ANALYSES, LCO, and Start-LOCA/ LOOP Time Delav Relay (continued)
APPLICABILITY Delay Relay channel in the division initiating simultaneously to assure a nominal 8.5 second difference in low pressure ECCS subsystem starts within each ECCS function (LPCS/LPCI-C are set at 10 seconds and LPCI-A/LPCI-B are set While at 18.5 seconds with appropriate allowable values.)
each channel is dedicated to a single pump start logic, a single failure of an instrument sensor or logic relay could potentially result in failure of the offsite 230 kV supply.
One low pressure ECCS pump on either ESF bus could start simultaneously with the HPCS pump followed shortly by a second low pressure ECCS pump start while powered from the 230 kV offsite supply and potcntially trip the 230 kV circuit supply to both ESF bu es and HPCS.
The transfer would occur due to degraded voltage relay operation.
If loss of the 230 kV source occurs, transfer to the 115 kV or DGs will occur within the ECCS RESPONSE TIMF. (for MODE 1, 2, or 3). Thus, single failure criteria is met for this However, the supported ECCS features are condition.
impacted and appropriate Actions and Completion Times have Additionally, been established in LC0 3.3.5.1, Action C.
the 230 kV offsite supply is a supported feature by the LOCA Time Delay Relay channels for use in meeting LC0 3.8.1 or LCO 3.8.2 (assumes HPCS or the low pressure ECCS pumps on the affected division are not disabled to prevent automatic In MODE 4 or 5, when HPCS is not being relied loading.)
upon to meet LCO 3.5.2 (i.e., disabled), LC0 3.8.2 should not be affected. Use of the Safety Function Determination Program (TS 5.5.11) provides the means for AC Sources OPERABILITY determination.
There are two pump Start-LOCA/ LOOP Time Delay Relay channels, one in each of the RHR "A" and RHR "B" pump start logic circuits.
The LOCA/ LOOP Time Delay Relay channels consist of Level 1 and Drywell Pressure-High sensors (Table 3.3.5.1-1 Functions 1.a,1.b, 2.a, and 2.b),
auxiliary relay logic, circuit breaker position switches and power available relays. While each time delay is dedicated to a single pump start logic, a single failure of a Pump Start LOCA/ LOOP Time Delay Relay could result in the failure of the two low pressure ECCS pumps, pcwered from the same ESF bus, to perform their intended function within the assumed ECCS RESPONSE TIMES (MODE 1, 2, or 3). In this case, both ECCS pumps on one ESF bus could start simultaneously h
I (continued)
B 3.3-106a Revision 12 WNP-2
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 1.c. 1.d. 1.e. 2.c. 2.d. 2.e.
LPCS and {PCI Pumos A. B. and SAFETY ANALYSES, C Start-LOCA Time Delay Relay and LPCI Pumos A and B LCO, and Start-LOCA/ LOOP Time Delay Relay (continued)
APPLICABILITY when powered by the associated onsite DG due to an inoperable LOCA/ LOOP time delay relay and cause loss of the ESF bus.
In tLe case of simultaneous starts of both ECCS pumps on a DG, this still leaves two of the four low pressure ECCS pumps OPERABLE; thus, single failure criterion is met (i.e., loss of one instrument does not preclude ECCS initiation within the ECCS RESPONSE TIME requirements).
The Allowable Values for the Pump Start-LOCA and LOCA/ LOOP Time Delay Relay channels are chosen to be long enough so that most of the starting transient of the first pump is complete before starting the second pump on the same 4.16 kV emergency bus, and short enough so that ECCS operation is not degraded. Appropriate Actions and Completion Times are l
specified to limit the time a LOCA or a LOCA/ LOOP Time Delay Relay channel can be inoperable.
(continued)
O C/
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AV WNP-2 B 3.3-106b Revision 12 j
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ECCS Instrumentation B 3.3.5.1 BASES LPCS and LPCI Pumos A. B. and
_1. c. 1. d. 1. e. 2. c. 2. d. 2. e.
j;_ Start-LOCA Time Delay Relay and LPCI Pumos A and _B APPLICABLE SAFETY ANALYSES, Start-LOCA/ LOOP Tir>e Delav Relay (continued)
LCO, and APPLICABILITY Each channel of Pump Start-LOCA and LOCA/ LOOP Time Delay Relay Function is only required to be OPERABLE when the Refer associated LPCI subsystem is required to be OPERABLE.
to LC0 3.5.1 and LC0 3.5.2 for Applicability Bases for the LPCI subsystems.
Reactor Vessel Pressure-Low (Iniection 1,f, 2.f.
Permissivel_
Low reactor vessel pressure signals are used as permissives This ensures that, for the low pressure ECCS subsystems.
prior to opening the injection valves of the low pressureEC The below these subsystems' maximum design pressure.
Reactor Vessel Pressure-Low is one of the Functions assumed l
tn be OPERABLE and capable of permitting initiation of the ECCS during the transients analyzed in References 1 and 3.
I In addition, the Reactor Vessel Pressure-Low Function is h
directly assumed in the analysis of the recirculation lineThe core coo break (Refs. 2, 4, 5, and 6).
the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
The Reactor Vessel Pressure-Low signals are initiated from four pressure switches that sense the reactor dome pressure (one pressure. switch for each low pressure ECCS injection valve).
The Allowable Value is low enough to prevent overpressurizing the equipment in the low pressure ECCS, but high enough to ensure that the ECCS injection prev 10 CFR 50.46.
Each channel of Reactor Vessel Pressure-Low Function (one per valve) is only required to be OPERABLE when the associated ECCS is required to be OPERABLE to ensure that no (continued)
O Revision 12 B 3.3-107 WNP-2
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.
Primary Containment Isolation SAFETY ANALYSIS, LCO, and 2.a. 2.b.
Reactor Vessel Water level-Low. Level 3 and APPLICABILITY Reactor Vessel Water Level-Low Low. Level 2.(continued)
The Reactor Vessel Water Level-Low Low, Level 2 Function (MS-LS-61A-D) is also used to initiate the LOCA Time Delay Relays of LC0 3.3.5.1.
These LOCA Time Delay Relays stagger ECCS pump loading when the ECCS power source is aligned to
~
the 230 kV offsite circuit to assure ECCS loading, during pump starts, does not overload the offsite source transformer. This branching to LCO 3.3.5.1 requires instrument OPERABILITY when LCO 3.3.5.1 LOCA Time Delay Relay Function is required to be OPERABLE.
Actuation of either required instrument channel per trip system will' initiate the LOCA Time Delay Logic for the low pressure ECCS Function (LPCS/LPCI-AorLPCS-B/LPCI-C).
The LCO Actions of 3.3.6.1 (place the channel in trip) may not be the more restrictive Action and Completion Times required of-these Level 2 instruments.
The LOCA Time Delay Relay channel Actions in LCO 3.3.5.1 are more restrictive if the associated ECCS subsystems are required to be OPERABLE.
O This is because the LCO 3.3.6.1 Action to place the channel in trip will complete part of the logic for both ECCS subsystems in the division (assuming the instrument failure does not already result -in the channel being in a tripped condition).
If the 230 kV offsite source is supplying the safety buses, the LOCA Time Delay Relays will start timing out immediately and will no longer sequence the delay after HPCS pump starts.
If the 230 kV offsite source is not supplying safety buses, the LOCA Time Delay Relays will begin timing out upon transfer to the 230 kV source supply rather than initiating on a LOCA signal at the same time because the HPCS pump starts from different reactor Level 2 instruments.
In either case, the LOCA Time Delay Relays may not be properly sequenced to delay start of the low pressure ECCS subsystems tied to when the HPCS pump starts.
(continued)
O WNP-2 B 3.3-155a Revision 12 l
Pricary Containzent Isolation Instrumentation B 3.3.6.1 l
BASES nU APPLICABLE 2.c.
Drywell Pressure-Hioh SAFETY ANALYSES, LCO, and High drywell pressure can indicate a break in the RCPB APPLICABILITY inside the drywell. The isolation of some of the PCIVs on (continued) high drywell pressure supports actions to ensure that offsite dose limits of 10 CFR 100 are not exceeded.
The Drywell Pressure-High Function associated with isolation of the primary containment is implicitly assumed in the FSAR accident analysis as these leakage paths are assumed to be isolated post LOCA.
High drywell pressure signals are initiated from pressure switches that sense the pressure in the drywell.
Four channels of Drywell Pressure-High are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value was selected to be the same as the RPS Drywell Pressure-High Allowable Value (LC0 3.3.1.1), sinceth The above Function isolates the Group 2, 3, 4, and'5 valves. l The Drywell Pressure-High Function is also used to initiate A
the LOCA Time Delay Relays of LCO 3.3.5.1.
These LOCA Time Delay Relays stagger ECCS pump loading when the ECCS power source is aligned to the 230 kV offsite circuit to assure ECCS loading, during pump starts, does not overload the offsite source transformer.
This branching to LC0 3.3.5.1 requires instrument OPERABILITY when LC0 3.3.5.1 LOCA Time Delay Relay Function is required to be OPERABLE. Actuation of either required instrument channel per trip system will initiate the LOCA Time Delay Logic for the low pressure ECCS Function (LPCS/LPCI-A or LPCI-B/LPCI-C).
Thus, actuation of either Drywell Pressure-High instrument will complete the logic for both subsystems in the division.
The LC0 Actions of 3.3.6.1 (place the channel in trip) may not be the more restrictive Action and Completion Times required of these Drywell Pressure-High instruments.
The LOCA Time Delay Relay channel Actions in LC0 3.3.5.1 are more restrictive if the associated ECCS subsystems are required to be OPERABLE. This is because the LCO 3.3.6.1 Action to place the channel in trip will complete part of the logic for both ECCS subsystems in the division (assuming the instrument failure does not already result in the channel being in a tripped condition).
If the 230 kV (continued)
WNP-2 B 3.3-156 Revision 12
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.c.
Drvwell Pressure-Hiah (continued)
SAFETY ANALYSES, offsite source is supplying the safety buses, the LOCA Time LCO, and APPLICABILITY Delay Relays will start timing out immediately and will no If the longer sequence the delay after HPCS pump. starts.
230 kV offsite source is iot supplying safety buses, the LOCA Time Delay Relays will begin timing out upon transfer to the 230 kV source supply rather than initiating on a LOCA signal at the same time as HPCS (pump starts from different In either case, the Drywell Pressure-High instruments).
LOCA Time Deley Relays may not be properly sequenced to delay start of the low pressure ECCS subsystems tied to when the HPCS pump starts.
2.d.
Reactor Buildina Vent Exhaust plenum Radiation-Hiah High ventilation exhaust radiation is an indication of possible gross failure of the fuel cladding.
The release may have originated from the primary containment due to a break in the RCPB. When Exhaust Radiation-High is detected, valves whose penetrations communicate with the primary containment atmosphere are isolated to limit the release of fission products.
The Reactor Building Vent Exhaust Plenum Radiation-High signals are initiated from radiation detectors that are located in the ventilation exhaust plenum. The signal from each detector is input to an individual monitor whose trip outputs are assigned to an isolation channel.
Four channels of Reactor Building Vent Exhaust Plenum Radiation-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
(continued)
O WNP-2 B 3.3-156a Revision 12
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Primary Containment Isolation Instrumentation B 3.3.6.1 BASES O
APPLICABLE 1.d.
Reactor Buildina Vent Exhaust Plen'um Radiation-Hiah SAFETY ANALYSES, (continued)
LCO, and APPLICABILITY The Allowable Values are chosen to ensure offsite doses remain below 10 CFR 100 limits.
This Function isolates the Group 3 valves.
2.e.
Manual Initiation The Manual Initiation switch and push button channels introduce signals into the primary containment isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability.
There is no specific FSAR safety analysis that takes credit for this Function.
It is retained for overall redundancy and diversity of the isolaticn function as required by the NRC in the plant licensing basis.
For the Group 3 valves, there are four switch and push buttons (with two channels per switch and push button) for the logic, with two switch and push buttons per trip system.
O
(
For the Group 2, 4, and 5 valves, there are two switch and push buttons (with two channels per switch and push button) for.the logic, one switch and push button per trip system.
Eight channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the Primary Containment Isolation automatic Functions are required to be OPERABLE.
There is no Allowab'e Value for this Function since the channels are mechanically actuated based solely on the position of the switch and push buttons.
This Function isolates the Group 2, 3, 4, and 5 valves.
3.
Reactor Core Isolation Coolina System Isolation 3.a.
RCIC Steam Line Flow-Hiah RCIC Steam Line Flow-High Function is provided to detect a break of the RCIC steam lines and initiates closure of the steam line isolation valves.
If the steam is allowed to continue flowing out of the break, the reactor will O
(continued)
WNP-2 B 3.3-157 Revision 5
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REVISION 13 TECHNICAL SPECIFICATION BASES b
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O WNP-2 TECHNICAL SPECIFICATIONS BASES The following instrucdonal information and checklist is furnished to help you insert a revision into the Washington Public Power Supply System Plant No. 2 Technical Specification Bases.
If you have any questions concerning insertion of this revision, or if you are missing any pages, please contact R Morse (509) 37/-5307.
Discard Insert Old Pane New Page BAS LEP-1 through BAS LEP-5 BAS LEP-1 through BAS LEP-5 B 3.0-12/B 3.0-13 B 3.0-12/B 3.0-13 B 3.0-14/B 3.0-15 B 3.0-14/B 3.0-15 B 3.1-50/ blank B 3.1-50/ blank A
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i BAS LEP-5 Revision No. 13
SR Applicability B 3.0 BASES SR 3.0.2 The 25% extension does not significantly degrade the (continued) reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the SRs.
The exceptions to SR 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the Frequency does not apply. These exceptions are stated in the individual Specifications. The requirements of regulations take precedence over the TS. Therefore, when a test interval is specified in the regulations, the test interval cannot be extended by the TS, and the SR includes a Note in the Frequency stating, "SR 3.0.2 is not applicable."
As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per..." basis. The 25%
extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedial-action, is considered a single action with a single Completion Time. One reason for not allowing the 25%
extension to this Completion Time is that such an action.
O usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.
The provisions of SR 3.0.2 are not intended to be used.
repeatedly merely as an operational convenience to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completior. Time intervals beyond those specified.
SR 3.0.3 SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been completed within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limits of the specified Frequency, whichever is less, applies from the point in time " is discovered that the Surveillance has not been performeo.a.ccordance with SR 3.0.2, and not at the time that the specified Frequency was not met. This delay period provides adequate time to complete Surveillances that (continued)
O WNP-2 B 3.0-12 Revision 5
SR Applicability B 3.0 g
BASES have been missed. This delay period permits the completion SR 3.0.3 of a Surveillance, or allows time to obtain a temporary (continued) waiver of the Surveillance Requirement (Ref.1), before complying with Required Actions or other remedial measures that might preclude completion of the Surveillance.
The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements.
When a Surveillance with a Frequency based not on time intervals, but upon specified unit conditions or operational situations, is discovered not to have been performed when specified, SR 3.0.3 allows the full delay period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to perform the Surveillance.
SR 3.0.3 also provides a time limit for completion of Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.
Failure to comply with specified Frequencies for SRs is Use of the delay expected to be an infrequent occurrence.
period established by SR 3.0.3 is a flexibility which is not intemfed to be used as an operational convenience to extend Survrti. lance intervals.
If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable then is considered outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon expiration If a Surveillance is failed within the of the delay period.
delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon the failure vf the Surveillance.
Completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the ACTIONS, restores compliance with SR 3.0.1.
(continued)
O, Revision 13 B 3.0-13 WNP-2
SR Applicability B 3.0 BASES (continued)
SR 3.0.4 SR 3.0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified condition in the Applicability.
This Specification ensures that system and ' component OPERABILITY requirements and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit.
The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.
However, in certain circume'ances, failing to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed per SR 3.0.1, which states that Surveillances do not have to be performed on inoperable equipment. When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance (s) within the specified Frequency, on equipment that is inoperable, does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability. However, since the LC0 is not met in this instance, LC0 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specificd condition changes.
The provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS.
In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown.
The precise requirements for performance of SRs are specified such that exceptions to SR 3.0.4 are not necessary.
The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows (continued)
Ov WNP-2 B 3.0-14 Revision 5
~
SR Applicability B 3.0 g
BASES performance of Surveillances when the prerequisite condition (s) specified in a Surveillance procedure require SR 3.0.4 (continued) entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the performance A Surveillance that could or completion of a Surveillance.
not be performed until after entering the LC0 Applicability would have its Frequency specified such that it is not "due" Alternately, until the specific conditions needed are met.
the Surveillance may be stated in the form of a Note as not required (to be met or performed) until a particular event, condition, or time has been reached.
Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency.
SR 3.0.4 is only applicable when entering MODE 3 from MODE 4, MODE 2 from MODE 3 or 4, or MODE 1 from MODE 2.
Furthermore, SR 3.0.4 is applicable when entering any other specified condition in the Applicability only while The requirements of SR 3.0.4 operating in MODE 1, 2, or 3.
do not apply in MODES 4 and 5, or in other specified conditions of the Applicability (unless in MODE 1, 2, or 3) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken.
O NRC Generic Letter 87-09, " Sections 3.0 and 4.0 of the REFERENCES 1.
Standard Technical Specifications (STS) on the Applicability of Limiting Conditions for Operation and Surveillance Requirements."
Revision 13 8 3.0-15 WNP-2
SDV Vent and Drain Valves B 3.1.8
)(
BASES l
SURVEILLANCE SR 3.1.8.3 (continued)
REQUIREMENTS unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
REFERENCES 1.
FSAR, Section 4.6.1.1.2.4.2.5.
l 2.
3.
NUREG-0803, " Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping,"
J August 1981.
4.
L I
!O O
WNP-2 B 3.1-50 Revision 13
E0C-RPT Instrumentation B 3.3.4.1 O
BASES L.)
SURVEILLANCE SR 3.3.4.1.3 (continued)
REQUIREMENTS can be placed in the conservative condition (nonbypass).
If placed in the nonbypass candition, this SR is met and the channel considered OPERABLE.
The Frequency of 18 months is based on engineering judgement and reliability of the components.
SR 3.3.4.1.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the pump breakers is included as a part of this test, overlapping the LOGIC SYSTEM FUNCTIONAL TEST, to provide complete testing of the associated safety function. Therefore, if a breaker is incapable of operating, the associated instrument channel would also be inoperable.
The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant
(
outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.
Operating experience h?s shown these components usually pass the Surveillance test when performed at the 24 month Frequency.
SR 3.3.4.1.5 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The E0C-RPT SYSTEM RESPONSE TIME acceptance criteria are included in Reference 8.
A Note to the Surveillance states that breaker arc suppression time may be 2ssumed from the most recent performance of SR 3.3.4.1.6.
This is allowed since the arc suppression time is short and does not appreciably change, due to the design of the breaker opening device and the fact that the breaker is not routinely cycled.
E0C-RPT SYSTEM RESPONSE TIME tests are conducted on t 24 month STAGGERED TEST BASIS. Response times cannou oc determined at power because operation of final actuated N]J (contingedl d
WNP-2 B 3.3-85 Revision 5-
EOC-RPT Instrumentation B 3.3.4.1 h
BASES SURVEILLANCE SR 3.3.4.1.5 (continued)
REQUIREMENTS devices is required. Therefore, the 24 month Frequency is consistent with the refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components that cause serious response time degradation, but not channel failure, are infrequent occurrences.
SR 3.3.4.1.6 This SR ensures that the RPT breaker arc suppression time is provided to the E0C-RPT SYSTEM RESPONSE TIME test.
The 60 month Frequency of the testing is based on the difficulty of performing the test and the reliability of the circuit breakers.
RFFERENCES 1.
FSAR, Section 7.6.1.5.
l 2.
FSAR, Section 5.2.2.
3.
FSAR, Sections 15.2.2, 15.2.3, 15.2.5, and 15.2.6.
l 4.
FSAR, Section 15.F.2.1.
5.
CENPD-300-P-A, " Reference Safety Report for Boiling Water Reactor Reload Fuel," July 1996.
6.
7.
GENE-770-06-1-A, " Bases for Changes To Surveillance l
Test Intervals And Allowed Out-0f-Service Times For Selected Instrumentation Technical Specifications,"
December 1992.
8.
Licensee Controlled Specifications Manual.
O WNP-2 B 3.3-86 Revision 13
LOP Instrumentation B 3.3.8.1 B 3.3 INSTRUMENTATION B 3.3.8.1 Loss of Power (LOP) Instrumentation BASES
. BACKGROUND Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power sources for energizing the various components such as pump motors, motor operated valves, and the associated control. components.
The LOP instrumentation monitors the 4.16 kV emergency buses.
Offsite power is the preferred source of power for the 4.16 kV emergency buses.
If the monitors determine that insufficient power is available, the buses are disconnected from t.ne offsite power sources and connected to the onsite diesei generator (DG) power sources.
Each 4.16 kV emergency bus has its own independent LOP instrumentation and associated trip logic.
The voltage for the Division 1, 2, and 3 buses is monitored at two levels, which can be consie red as two different undervoltage functions:
loss of voltage and degraded voltage.
The Division 1 and 2 TR-S Loss of Voltage and the Division 3 Loss of Voltage Functions are monitored by two instruments per bus whose output trip contacts are arranged in a one-out-of-two logic configuration per bus. The Division 1 and 2 TR-B Loss of Voltage Function is monitored by one instrument per bus where output trip contacts are arranged
- in a one-out-of-one logic configuration per bus. The Degraded Voltage Function for Division 1 and 2 4.16 kV Engineered Safety Feature (ESF) buses is monitored by three instruments per bus whose output trip contacts are arranged in a two-out-of-three logic configuration per bus. The Degraded Voltage Function for the Division 3 4.16 kV ESF bus is monitored by two instruments whose output trip contacts are arranged in a two-out-of-t to logic configuration (Ref.
1).
Upon a TR-S loss of voltage signal on the Division 1 and -2 4.16 kV ESF buses, the associated DG is started and a three and one half second timer is initiated to allow time to l
verify loss of voltage and to establish the TR-S source of power. At the end of the three and one half second timer, if bus voltage is still below the setpoint (as sensed by one l of the two channels), the Division 1 and 2 IE bus breakers for TR-N1 and TR-S are tripped, the bus ESF loads ere shed (continued)
WNP-2 B 3.3-205 Revision 13
-e-.,--
.m,,>
m-
.-a
LOP Instrumentation B 3.3.8.1 BASES BACKGROUND (except for the 480 V buses) and an additional timer is initiated (a two second timer). After the two second time l
(continued) delay an attempt is made to close the TR-B breaker if the backup source is available. These two timers constitute the Division 1 and 2 TR-S Loss of Voltage-Time Delay Function.
In addition, at the end of the three and one half second l
timer, a third timer is initiated that inhibits the DG breakers close signal for four seconds. This provides enough time for the 4.16 kV ESF buses to connect to the backup source if it is available. After the four second i
delay the DG breaker is allowed to close (if the TR-B breaker did not close) once the DG attains the proper r
frequency and voltage. This timer is not considered part of the LOP Instrumentation (it is tested in LCO 3.8.1, "AC Sources-0perating," and LC0 3.8.2, "AC Sources-Shutdown").
Upon a TR-B loss of voltage signal on the Division 1 and 2 4.16 kV ESF buses while these buses are tied to TR-B, a 3.5 second timer is initiated to allow time to verify loss of voltage and to establish the TR-B source of power.
At the end of the 3.5 second timer, if bus voltage is still belo.i the setpoint, the Division 1 and 2 1E bus breakers for TR-B are tripped.
This timer constitutes the Division 1 and 2 TR-B Loss of Voltage-Time Delay Function. The associated DG is started and the bus ESF loads are shed (except the 480 V buses) by the TR-S Loss of Voltage Function, as described earlier.
Upon a Mss of voltage signal on the Division 3 4.16 kV ESF bus, a two second timer starts to allow recovery time for the failing source. At the end of the two second time delay the preferred source breaker is tripped if bus voltage is still below the setpoint (as sensed by one of the two channels). This timer constitutes the Division 3 Loss of Voltage-Time Delay Function.
In addition, at the end of the two second time delay, a 1.3 second timer is initiated.
At the end of the 1.3 second timer the HPCS DG is started and the DG breaker closes as the DG reaches rated frequency.
This timer is not considered part of the LOP Instrumentation (it is tested in LC0 3.8.1 and LCO 3.8.2).
Upon degraded voltage on Division 1, 2, or 3 4.16 kV ESF buses there is an eight second time delay before any action is taken to allow the degraded condition to recover. The Division 1 and 2 eight second time delay is further divided into a primary time delay of five seconds and a secondary time delay of 3 seconds. There are two primary time delay (continued)
WNP-2 B 3.3-206 Revision 13
LOP Instrumentation B 3.3.8.1 BASES BACKGROUND relays, but only one secondary time delay relay.
The (continued) secondary time delay relay is started when both degraded voltage relays are tripped and their respective primary time delays have timed out. After the eight second time delay the feeder breakers connecting the sources'to the respective 4.16 kV ESF buses are tripped. The actions for Division 1 and 2 at this point during the degraded voltage condition are the same (utilizes the same timers) as the loss of voltage condition for Division I and 2 except the first three and one half second timer is bypassed.
The actions l
for Division 3 at this point dur!ag the degraded voltage condition are the same (utilizes the same timers) as the loss of voltage condition for Division 3 except the first two second timer is bypassed.
i APPLICABLE The LOP instrumentation is required for the Engineered SAFETY ANALYSES, Safety Features to function in any accident with a loss of LCO, and offsite power. The required channels of LOP instrumentation APPLICABILITY ensure that the ECCS and other assumed systems powered from the DGs provide plant protection in the event of any of the analyzed accidents in References 2, 3, and 4 in which a loss p
of offsite power is assumed. The initiation of the DGs on Q
loss of offsite power, and subsequent initiation of the ECCS, ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Accident analyses credit the loading of two of the three DGs (i.e., the DG function) based on the loss of offsite power during a loss of coolant accident (LOCA).
The diesel starting and loading times have been included in the delay time associated with each safety system component requiring DG supplied power following a loss of offsite power.
The LOP instrumentation satisfies Criterion 3 of Reference 5.
The OPERABILITY of the LOP instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.8.1-1.
Each Function must have a required number of OPERABLE channels per 4.16 kV emergency bus, with their setpoints within the specified Allowable Values. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
(continued)
C\\
V WNP-2 B 3.3-207 Revision 13
LOP instrumentation B 3.3.8.1 BASES f
l The Allowable Values are specified for each Function in the APPLICABLE SAFETY ANALYSES, Table.
Nominal trip setpoints are specified in the setpoint LCO, and calculations.
The nominal setpoints are selected to ensure APPLICABILITY that the setpoint does not exceed the Allowable Value between CHANNEL CALIBRATIONS.
Operation with a trip (continued) setpoint less conservative than the nominal trip setpoint, but within the Allowable Value, is acceptable.
A channel is i
inoperable if its actual trip setpoint is not within its required Allowable Value.
Trip setpoints are those predetermined values of output at which an action should take place.
The setpoints are compared to the actual process parameter (e.g., degraded voltage), and when the measured output value of the process parameter exceeds the setpoint, the associated device changes state.
The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis.
The Allowable Values are derived from the analytic limits, corrected for process and all instrument uncertainties, except drift and calibration.
The trip setpoints are derived from the analytic limits, corrected for process and all instrument uncertainties, including drift and calibration.
The trip setpoints derived in this manner provide adequate protection because all instrumentation uncertainties and process effects are taken into account.
Some functions have both an h
upper and lower analytic limit that must be evaluated.
The Allowable Values and the trip setpoints are derived from both an upper and lower analytic limit using the methodology described above.
Due to the upper and lower analytic limits, Allowable Values of these Functions appear to incorporate a range.
However, the upper and lower Allowable Values are unique, with each Allowable Value associated with one unique analytic limit and trip setpoint.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
1.a. 1.b. 1.c. 1.d. 2.a. 2.b.
4.16 kV Emeraency Bus Undervoltaae (Loss of Voltaae)
Loss of voltage on a 4.16 kV emergency bus indicates that offsite power may be completely lost to the respective emergency bus and is unable to supply sufficient power for proper operation of the applicable equipment.
Therefore, the power supply to the bus is transferred from offsite power to DG power when the voltage on the bus drops below (continued)
WNP-2 B 3.3-208 Revision 13l
RCS Operational LEAKAGE B 3.4.5
[
BASES ACTIONS C.1 and C.2 (continued) ba:ed on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.4.5.1 REQUIREMENTS The RCS LEAKAGE 15 monitored by a variety of instruments designed to provide alarms when LEAKAGE is indicated and to quantify the various types of LEAKAGE.
Leakage detection instrumentation is discussed in more detail in the Bases for LC0 3.4.7 "RCS Leakage Detection Instrumentation." Sump flow rate is typically monitored to determine actual LEAKAGE rates. However, any method may be used to quantify LEAKAGE within the guidelines of Reference 8.
In conjunction with alarms and other administrative controls, a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency for this Surveillance is appropriate for identifying changes in LEAKAGE and for tracking required trends (Ref. 9).
REFERENCES 1.
2.
3.
10 CFR 50, Appendix A, GDC 55.
4.
GEAP-5620, " Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flows," April 1968.
5.
NUREG-75/067, " Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactors," October 1975.
6.
FSAR, Section 5.2.5.5.2.
l 7.
8.
Regulatory Guide 1.45, May 1973.
9.
Generic Letter 88-01, Supplement 1, February 1992.
O WNP-2 B 3.4-29 Revision 13
_ _ _. - - _ =. _ _
RCS Leakage Detection Instrumentation B 3.4.7 BASES SURVEILLANCE SR 3.4.7.2 REQUIREMENTS (continued)
This SR requires the performance of a CHANNEL FUNCTIONAL TEST of the required RCS leakage detection instrumentation.
The test ensures that the monitors can perform their function in the desired manner. The test also verifies the alarm setpoint and relative accuracy of the instrument string. The Frequency of 31 days considers instrument reliability, and operating experience has shown it proper for detecting degradation.
SR 3.4.7.3 This SR requires the performance of a CHANNEL CALIBRATION of the required RCS leakage detection instrumentation channels.
The calibration verifies the accuracy of the instrument string, including the instruments located inside the drywell. The Frequency of 18 months is a typical refueling cycle and considers channel reliability. Operating experience has proven this Frequency is acceptable.
REFERENCES 1.
10 CFR 50, Appendix A, GDC 30.
2.
Regulatory Guide 1.45, May 1973.
3.
FSAR, Section 5.2.5.5.3.
l 4.
GEAP-5620, " Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flaws," April 1968.
5.
NUREG-75/067, " Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactors," October 1975.
6.
FSAR, Section 5.2.5.5.
7.
O WNP-2 B 3.4-39 Revision 13
Primary Containment B 3.6.1.1 BASES (centinued) i REFERENCES 1.
FSAR, Section 6.2.1.1.3.
l 2.
FSAR, Section 15.F.6.
3.
10 CFR 50, Appendix J, Option B.
4.
FSAR, Section 6.2.6.1.
5.
O O
WNP-2 B 3.6-5 Revision 13
1 MSLC System B 3.6.1.8 BASES ACTIONS C.1 and C.2 (continued) i l
If the MSLC subsystem cannot be restored to OPERABLE status within the required Completion Time, the plant must be l'
brought to a MODE in which the LCO does not apply. To I
achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging' plant systems.
SURVEILLANCE SR 3.6.1.8.1 REQUIREMENTS Each MSLC System blower is operated for a 15 minutes to verify OPERABILITY. The 31 day Frequency was developed considering the known reliability of the MSLC System blower l
and controls, the two subsystem redundancy, and the low probability of a significant degradation of the MSLC subsystem occurring between Surveillances and has been shown to be acceptable through operating experience.
I SR 3.6.1.8.2 The electrical continuity of each inboard MSLC subsystem heater is verified by a resistance check, by verifying the rate of temperature increase meets specifications, or by i
verifying the current or wattage draw meets specifications.
The 31 day Frequency is based on operating experience that has shown that these components usually pass this Surveillance when performed at this Frequency.
Sft 3.6.1.8.3 A system functional test is performed to ensure that the MSLC System will operate through its operating sequence.
This includes verifying that the automatic positioning of the valves and the operation of each interlock and timer are L
correct, that the blowers start and develop a flow rate of i
2 24 cfm and 5 36 cfm, at a vacuum of 2 17 inches water l
gauge, and the upstream heaters meet current or wattage draw (continued)
I WNP-2 B 3.6-50 Revision 5
=
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MSLC System B 3.6.1.8 g
BASES SURVEILLANCE SR 3.6.1.8.3 (continued)
REQUIREMENTS The 18 month Frequency is based on the need requirements.
to perform this Surveillance under the conditions that apply during a plant outage and the potential fo~r an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
REFERENCES 1.
FSAR, Section 6.7.3.
l 2.
FSAR, Section 6.7.2.1.
l 3.
FSAR, Sections 15.6.5 and 15.F.6.
4.
O O
WNP-2 B 3.6-51 Revision 13
Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS E.1 and E.2 (continued)
Continued addition of heat to the suppression pool with pool temperature > 120*F could result in exceeding the design basis maximum allowable values for primary-containment temperature or pressure.
Furthermore, if a blowdown were to occur when temperature was > 120*F, the maximum allowable bulk and local temperatures could be exceeded very quickly.
SURVEILLANCE SR 3.6,2.1.1 REQUIREMFNTS The suppression pool average temperature is regularly monitored to ensure that the required limits are satisfied.
Average temperature is determined by taking an arithmetic average of eight functional suppression pool water temperature channels, two per sector (there is no divisional requirement for this SR). The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency has been shown to be acceptable based on operating experience. When heat is being added to the suppression pool by testing, however, it is necessary to monitor suppression pool temperature more frequently. The 5 minute Frequency during testing is justified by the rates at which testing will heat O
up the suppression pool, has been shown to be acceptable based on operating experience, and provides assurance that allowable pool temperatures are not exceeded. The Frequencies are further justified in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.
REFERENCES 1.
FSAR, Section 6.2.1.1.3.3.
l 2.
FSAR, Section 3A.3.1.2.3.
l 3.
4.
O WNP-2 B 3.6-56 Revision 13
RHR Suppression Pool Cooling B 3.6.2.3 BASES ACTIONS B.1 and B.2 (continued)
If the Required Action and associated Completion Time of Condition A cannot be met or if two RHR suppression pool cooling subsystems are inoperable, the plant must be brought to a MODE in which the LC0 does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 nours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.6.2.3.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves, in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to being locked, sealed, or secured.
h A valve is also allowed to be in the nonaccident position, I
provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable, since the RHR suppression pool cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system. This Frequency has been shown to be acceptable, based on operating experience.
SR 3.6.2.3.2 Verifying each RHR pump develops a flow rate 2 7100 gpm, while operating in the suppression pool cooling mode with flow through the associated heat exchanger, ensures that the primary containment peak pressure and temperature can be (continued)
WNP-2 8 3.6-62 Revision 5
RHR Suppression Pool Cooling 8 3.6.2.3 4
BASES SURVEILLANCE 3.6.2.3.2 (continued)
^
REQUIREMENTS maintained below the design limits during a DBA (Ref. 2).
The normal test of centrifugal pump performance required by ASME Section XI (Ref. 4) is covered by the' requirements of LC0 3.5.1, "ECCS-Operating."
Such inservice tests confirm component OPERABILITY, and detect incipient failures by indicating abnormal performance.
The Frequercy of this SR is in accordance with the Inservice Testing hmram.
REFERENCES 1.
FSAR, Section 6.2.1.1.3.3.
l 2.
FSAR, Section 6.2.2.3.
3.
4.
ASME, Boiler and Pressure Vessel Code,Section XI.
O i
WNP-2 B 3.6-63 Revision 13
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 (continued)
REQUIREMENTS The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 12), paragraph C.2.2.14.
This SR is modified by a Note. The reason for the Note is to minimize wear on the DG during testing.
For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.
REFERENCES 1.
10 CFR 50, Appendix A, GDC 17.
2.
FSAR, Chapter 8.
3.
FSAR, Figure 8.3-3.
l 4.
FSAR, Tables 8.3-1, 8.3-2, and 8.3-3.
5.
Safety Guide 9, Revision 0, March 1971.
6.
FSAR, Chapter 6.
7.
FSAR, Chapters 15 and 15.F.
8.
j 9.
Regulatory Guide 1.93, Revision 0, December 1974.
10.
Generic Letter 84-15, July 2, 1984.
11.
10 CFR 50, Appendix A, GDC 18.
12.
Regulatory Guide 1.9, July 1993.
13.
Regulatory Guide 1.108, Revision 1, August 1977.
14.
Regulatory Guide 1.137, Revision 1, October 1979.
15.
Supply System Calculations Nos. E/I-02-87-07 and E/I-02-90-01.
(continued)
WNP-2 B 3.8-33 Revision 13
. ~ _.. - -.
l AC Sources-Operating B 3.8.1 g
BASES REFERENCES 16.
FSAR, Section 15.F.6.
(continued) 17.
ASME, Boiler and Pressure Vessel Code,Section XI.
18.
l O
O WNP-2 8 3.8-34 Revision 5
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'l REVISION 12 WNP-2 LICENSEE CONTROLLED SPECIFICATIONS O
O
WNP-2 LICENSEE CONTROIJE SPECHICATIONS The following instructional information and checklist is fumished to help you insert a revision into the Washingon Public Power Supply System Plant No. 2 Licensee Controlled Specifications.
If you have any questions concerning insertion of this mision, or if you are missing any pages, please contact Lori Walli (509) 377-4149.
Discard Insert Old Paae New Pane LCS LEP-1/LCS LEP-2 LCS LEP-1/LCS IEP-2 1.3-2%1ank 1.3-2%1ank 1.8-14/1.8-15 1.8-14/1.8-15 B 1.3-12/B 1.3-13 Bl.3-12/B 1/3-13 O
Remote Shutdtwn System 1.3.3.2 Table 1.3.3.2-3(page1of1) l Remote Shutdown System Equipment Status Monitoring MINIMUM CHANNELS FUNCTION LOCATION REQUIRED 1.
Residual Heat Removal (RE) Pisup Room R7 1
2 Temperature
- 2..MCC 88 Room Temperature R410 1
3.
MCC 888 Room Temperature R612 1
4.
Remote Shutdown RoomTemperature C207 1
5.
SM-8 Room Temperature C206 1
6.
Battery Room 2 Temperture C215 1
7.
Battery Charger Room 2 Temperature C224 1
8.
062 Switchgear Room Temperature D116 1
9.
SM-7 Room Temperature C208 1
- 10. Battery Roum 1 Temperature C210 1
- 11. Battery Charger Room 1 Temperature C216 1
R15 1
Pump Room Temperature
- 13. Service Water (SW) Pumphouse IB Room 6200 1
Temperature
- 14. MCC $2/1A Room Temperature R212 1
- 15. R R Pump Room 1 Temperature R6 1
- 16. MCC 78 Room Temperature R411 1
- 17. MCC 788 Room Temperature R611 1
- 18. D61 Switchgear Room Temperature D115 1
- 19. SW Pisuphouse 1A Roow Temperature 6100 1
- 20. Division 2 Battery Voltage Meter C224 1
- 21. 062 Local Voltage Meter 0116 1
- 22. D62 Local Frequency Meter D116 1
J WNP 1.3-26 Revision 12
l I
l MOV Thermal Overload Protection 1.8.11 1.8 ELECTRICAL POWER SYSTEM 1.8.11 Motor Operated Valve (MOV) Thermal Overload Protection l
RF0 1.8.11 The thermal overload protection for each MOV shown in Table 1.8.11-1 shall be OPERABLE.
?
l APPLICABILITY:
Whenever the MOV is required to be OPERABLE.
1 COMPENSATORY MEASURES i
NOTE-------------------------------------
Separate Condition entry is allowed for each MOV thermal overload.
CONDITION REQUIRED COMPENSATORY MEASURE COMPLETION TIME A.
One or more MOV A.1 Continuously bypass 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thermal overloads the inoperable MOV inoperable.
thermal overload.
B.
Required Compensatory B.1 Declare the MOV Immediately Measure and inoperable.
associated Completion Time not met.
SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 1.8.11.1 Perform a CHANNEL CALIBRATION of a 18 months representative sample, on a rotating basis, on the MOV thermal overloads.
O l
WNP-2 1.8-14 Revision 7 l
MOV Thermal Overload Protection g
1.8.11 TABLE 1.8.11-1 (page 1 of 2)
Motor Operated Valves Thermal Overload Protection SYSTEM (S)
SYSTEM (S)
VALVE NUMBER AFFECTED VALVE NUMBER AFFECTFD
- a. CAC-V-2 Containment
- g. MSLC-V-1A Main Steam Isolation CAC-V-4 Atmospheric Control MSLC-V-1B Valve Leakage Control CAC-V-6 System MSLC-V-1C System CAC-V-8 MSLC-V-ID CAC-V-11 MSLC-V-2A CAC-V-13 MSLC-V-28 CAC-V-15 MSLC-V-2C CAC-V-17 MSLC-V-2D MSLC-V-3A
- b. CIA-V-20 Containment MSLC-V-3B CIA-V-30A Instrument Air System MSLC-V-3C CIA-V-30B MSLC-V-3D MSLC-V-4
- c. FPC-V-149 Fuel Pool Cooling MSLC-V-5 FPC-V-153 System MSLC-V-9 FPC-V-154 MSLC-V-10 FPC-V-156 FPC-V-172
- h. RCC-V-5 Reactor Closed FPC-V-173 RCC-V-21
. Cooling Water System FPC-V-175 RCC-V-40 g
FPC-V-181A RCC-V-104 FPC-V-181B RCC-V-129 FPC-V-184 RCC-V-130 RCC-V-131
- d. HPCS-V-1 High Pressure Core HPCS-V-4 Spray System
- i. RCIC-V-1 Reactor Core HPCS-V-10 RCIC-V-8 Isolation Cooling l
HPCS-V-11 RCIC-V-10 System HPCS-V-12 RCIC-V-13 HPCS-V-15 RCIC-V-19 l
i HPCS-V-23 RCIC-V-22 RCIC-V-31 l
- e. LPCS-V-1 Low Pressure Core RCIC-V-45 LPCS-V-5 Spray System RCIC-V-46 LPCS-FCV-11 RCIC-V-59 LPCS-V-12 RCIC-V-63 RCIC-V-68
- f. MS-V-1 Main Steam System RCIC-V-69 MS-V-2 RCIC-V-76 MS-V-16 P.CIC-V-110 l
MS-V-19 RCIC-V-113 MS-V-20 MS-V-67A
- j. RFW-V-65A Reactor Feedwater MS-V-67B RFW-V-65B System MS-V-67C g
MS-V-670 MS-V-146 WNP-2 1.8-15 Revision 12
PAM Instrumer.tation B 1.3.3.1 BASES O
REQUIREMENTS
- 6. Main Steam Isolation Valve Leakaae control System FOR OPERABILITY Pressure indication (continued)
Main steam isolation valve (MSIV) leakage control system pressure indication is a Category 2 Type D variable provided to indicate the fo"' tion of the main steam leakage control system.
Increar ing pressure of this variable indicates that the main steam isolation. valve may be leaking, and the MSIV leakage control system may not be operating properly. This could increase the potential for a radionuclide release.
- 7. Neutron Flux Indication Neutron Flux indications for average power range monitor (APRM), intermediate range monitor (IRM) and source range monitor (SRM) are a Category 2 Type D variable provided to indicate that the reactor shutdown has been successful. The neutron flux level is an indication of reactor core power.
An insertion of negative reactivity and the subsequent decrease in neutron. flux are indications used in the emergency operating procedures to confirm protective system actions and make decisions regarding the direction of subequent emergency action.
- 8. Reactor Core Isolation Coolina (RCIC) Flow Indication RCIC flow indication is a Category 2 Type D variable provided to indicate the operation of.the RCIC System.
- 9. Hiah Pressure Core Sorav (HPCS) Flow Indication i
HPCS flow is a Category 2 Type D variable provided to j
indicate the operation of the HPCS System. HPCS flow indication is monitored post accident to fulfill the RPV Level and RPV flooding functions of the emergency procedures.
I
- 10. Low Pressure Core Sorav (LPCS) Flow Indication
)
LPCS flow is a Category 2 Type D variable provided to indicate the operation of the LPCS System.
LPCS flow 1
indication is monitored post accident to fulfill the RPV Level and RPV flooding functions of the emergency procedures.
1 i
(continggdl O
WNP-2 B 1.3-12 Revision 12
PAM Instrum:ntation B 1.3.3.1 S
BASES REQUIREMENTS
- 11. Standbv Liauid Control (SLC) System Flow Indication FOR OPERABILITY (continued)
SLC System flow is a Category 2 Type D variable provided to indicate flow in the SLC System.
SLC flow is an indication that SLC is injecting and used as verification of function in the RPV control reactor power ATWS portion of the emergency procedures.
- 12. SLC System Tank level Indication SLC System tank level is a Category 3 Type D variable provided to indicate the availability of SLC inventory for injection. Decreasing SLC tank level is an indication that SLC is injecting, and is used in the RPV control reactor power ATWS portion of the emergency procedures to secure the SLC function.
- 13. Residual Heat Remoyal (RHR) Flow Indication RHR flow is a Category 2 Type D variable provided to indicate flow for low pressure cooling injection (LPCI) and shutdown cooling. RHR flow indication is monitored post accident to fulfill the RPV level and RPV flooding functions of the emergency procedures.
- 14. RHR Heat Exchanaer Outlet Temoerature Indication RHR heat exchanger outlet temperature is a Category 3 Type D variable provided to indicate temperature of the water leaving the RHR heat exchanger. This instrumentation is backup to RHR/ Service Water flow indications used for post accident monitoring.
- 15. Standby Service Water Flow Indication Standby service water flow is a Category 2 Type D variable provided to indicate standby service water as cooling flow for equipment needed to support post accident operation.
Standby service water is supplied to equipment that functions in response to accident conditions.
Indication of standby service water flow provides assurance that the cooling water to support tho equipment operation is functioning.
(continued)
O.
WNP-2 B 1.3-13 Revision 7
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I REVISION 13 WNP-2 LICENSEE CONTROLLED SPECIFICATIONS O
O
WNP-2 LICENSEE CONTROLLED SPECIFICATIONS O
The following instructional information and checklist is fumished to help you insert a revision into the Washington Public Power Supply System Plant No. 2 Licensee Controlled Specifications.
If you have any questions concerning insertion of this revision, or if you are missing any pa please contact Lori Walli (509) 377-4149.
Discard Insert Old Page New Page LCS LEP-1/LCS LEP-2 LCS LEP-1/LCS LEP-2 1.6-16/1.6-17 1.6-16/1.6-17 O
O
Secondary Containment Isolation 1.6.4.2 Table 1.6.4.2-1 (page 1 of 1)
Secondary Containment Ventilation System Automatic Isolation Valves
NOTE-------------------------------------
Tables 1.6.4.2-1, 2, and 3 list valves required to support OPERABILITY for LCO 3.6.4.2.
See Technical Specification LCO 3.6.4.1 and applicable Bases for further application details.
MAXIMUM ISOLATION TIME VALVE FUNCTION (Seconds) 1.
Reactor Building Ventilation Supply Valve ROA-V-1 15 2.
Reactor Building Ventilation Supply valve ROA-V-2 15 3.
Reactor Building Ventilation Exhaust Valve REA-V-1 8
4.
Reactor Building Ventilation Exhaust Valve REA-V-2 8
O O
WNP-2 1.6-16 Revision 13
Secondary Containment Isolation 1.6.4.2
. Table 1.6.4.2-2 (page 1 of 1)
Secondary Containment System Automatic Isolation
.....................--NOTE-------------------------------------
Tables 1.6.4.2-1, 2, and 3 list valves required to support OPERABILITY for LC0 3.6.4.2.
See Technical Specification LC0 3.6.4.1 and applicable Bases for further application details.
FUNCTION VALVE NUMBER 1.
ECCS room sump discharge to Radwaste FDR-V-219 2.
ECCS room sump discharge to Radwaste FDR-V-220 3.
ECCS room sump discharge to Radwaste FDR-V-221 4.
ECCS room sump discharge to Radwaste FDR-V-222 5.
Reactor Building sump discharge to Radwaste EDR-V-394 6.
Reactor Building sump discharge to Radwaste EDR-V-395 O
~-
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9 WNP-2 1.6-17 Revision 7
i o
i l
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REVISION 14 4
1 1
i
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WNP-2 LICENSEE CONTROLLED SPECIFICATIONS s
1 i
i 1
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i i
i a
4 M
4 1
2 5
I i
?
WNP-2 LICENSEE CONTROLIyn SPECIFICATIONS The following instructional information and dwHi" is fumished to help you insert a revision in the Washington Public Power Supply System Plant No. 2 Licensee Controlled Specificatio If you have any questions concerning insertion of this mision, or if you are missing an please contact R Femald (509) 377-5307.
Discard Insett Old Pare New Paee LCS LEP-1/LCS LEP-2 LCS LEP-1/LCS LEP-2 1.6-3/1.64 1.6-3/1.6-4 1.6-13/ Blank 1.6-13/ Blank 1.8-12/1.8-13 1.8-12/1.8-13 COLR Cycle 13 COLR Cycle 14 O
Pricary Containment Isolation Valves 1.6.1.3 Tabit 1.6.1.3-1 (page 3 of 13)
/'
Primary Containment Isolation Valves
(
MAXIMUM ISOLATION TIME l
VALVE FUNCTION AND NUMBER VALVE GROUP (a)
(Seconds)
- 1. Automatic Isolation Valves (continued) 1 i
- i. Reactor Closed Cooling 4
60 l
RCC-V-5 i
RCC-V-21 L
RCC-V-40 RCC-V-104 i
L
- j. Radiation Monitoring Supply & Return 4
5 l
PI-VX-250 4
l PI-VX-251 l
PI-VX-253 PI-VX-256 PI-VX-257 l
PI-VX-259
' k. Residual Heat Removal l
RHR-V-Igg $,B(i) 5 15 j
RHR-V-81 1 6
40 RHR-V-9(i)(*)
6 40 l
RHR-V-23(i) 6 90 RHR-V-53A,B((i) 6 40 RHR-V-24A,B e) 10 270 RHR-V-21 10 270 RHR-V-27A,B(e) 10 36 (continued)
.(a)
See Technical Specification Bases 3.3.6.1 for the isolation signal (s) which operate each group.
(e)
May be opened on an intermittent basis under administrative control.
(1)
Not subject to Type.C. test. Test per Technical Specification SP. 3.4.6.1.
(m).
During operational conditions 1, 2 & 3 the requirement for automatic isolation does not apply to RHR-V-9.
RHR-V-9 may be opened in l
operational conditions 2 & 3 provided control is returned to the control room, with the interlocks reestablished, and reactor pressure
~is less than 135 psig.
O WNP-2 1.6-3 Revision 14
Primary Containment Isolation Valves 1.6.1.3 Table 1.6.1.3-1 (page 4 of 13)
Primary Containment Isolation Valves MAXIMUM ISOLATION TIME VALVE GROUP (a)
(Seconds)
VALVE FUNCTION AND NUMBER
- 1. Automatic Isolation Valves (continued)
- 1. Reactor Water Cleanup System 7
RWCU-V-1(f) 30(l) l)
21(
RWCU-V-4
- m. Reactor Core Isolation Cooling RCIC-V-8 8
26 RCIC-V-63 8
16 RCIC-V-76 8
22 n.
Low Pressure Core Spray LPCS-V-12 10 180
HPCS-V-23 11 180
- 2. Excess Flow Check Valves (9)
- a. Containment Atmosphere NA PI-EFC-X29b PI-EFC-X29f PI-EFC-X30a PI-EFC-X30f PI-EFC-X42c PI-EFC-X42f PI-EFC-X61c (continued)
(a)
See Technical Specification Bases 3.3.6.1 for the isolation signal (s) which operate each group.
(f)
Not closed by SLC actuation signal.
(g)
Not subject to Type C Leak Rate Test.
(1)
Reflects closure times for containment isolation only.
O WNP-2 1.6-4 Revision 7
.-_._.._.....__...._._____.m..._.-
1
]-
Primary Contain ent Isolation Valves -
2 1,6.1.3 Table 1.6.1.3-1 (page 13 of 13)
Primary Containment Isolation Valves MAXIMUM ISOLATION TIME VALVE FUNCTION ANU NUMBER VALVE GROUP (a)
(Seconds)
- 4. Other Containment Isolation Valves (continued)
- n. Transversing Incore Probe System NA TIP-V-6 TIP-V-7,8,9,10,11(9)
- o. Reactor Closed Cooling NA RCC-V-219 (a)
See Technical Specification Bases 3.3.6.1 for the isolation signal (s) which operate each group.
(g)
Not subject to Type C Leak Rate Test.
I O
- WNP-2 1.6-13 Revision 14
Pri=ary Containment Penetration Conductor Overcurrent Protection 1.8.10 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 1.8.10.3
NOTE---------------------
For each overcurrent circuit breaker that is found inoperable, another representative sample shall be tested until no more inoperabilities are found or until all overcurrent circuit breakers have been tested.
Functionally test a representative sample, 18 months on a rotating basis of the required 480 V overcurrent circuit breakers.
SR 1.8.10.4 Inspect and perform preventative maintenance 60 months on each associated circuit breaker.
O O
I L
WNP-2 1.8-12 Revision 7
Primary Containment Penetration Conductor Overcurrc;nt Protection 1.8.10 TABLE 1.8.10-1 (page 1 of 1)
Primary Containment Penetration Conductor Overcurrent Protective Devices E0UIPMENT PRIMARY PROTECTION BACKUP PROTECTION a.
6900 V Circuit Breakers RRC-P-1A RRC-CB-RRA (Relay)
E-CB-S/S (Relay) E-CB-N2/5 (Relay) l RRC-P-1B RRC-CB-RRB (Relay)
E-CB-S/6 (Relay) E-CB-N2/6 (Relay) b.
480VAC Fused Disconnects MS-V-16 MC-88-A Fused MC-88 Fused RWCU-V-1 MC-88-A Fused MC-8B Fused RHR-V-9 RHR-DISC-V/9 Fused MC-88-A Fused l
RCIC-V-63 MC-8B-A Fused MC-8B Fused O'
RCC-V-40 MC-88-A Fused MC-8B Fused RHR-V-123B MC-88-A Fused MC-88 Fused RCIC-V-76 MC-88-A Fused MC-8B Fused RHR-V-123A MC-88-A Fused MC-88 Fused O
WNP-2 1.8-13 Revision 14
4 COLR 98-14, Revision 0 i
Controlled Copy No.
i
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WNP-2 Cycle 14 Core Operating Limits Report May 1998 1
1 i
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l Washington Public Power Supply System O
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REVISION 15 WN~P-2 LICENSEE CONTROLLED SPECIFICATIONS O
O
WNP-2 LICENSEE CONTROLLFD SPECIFICATIONS The following instructional information and checklist is furnished to help you insert a revision into the qWashington Public Power Supply System Plant No. 2 Licensee Controlled Specifications.
i If you have any questions concerning insertion of this revision, or if you are missing any pages, please contact R Morse (509) 377-5307.
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l Revision 15 LCS LEP-2
f-1
' LICENSEE CONTROLLED SPECIFICATIONS MANUAL TABLE OF CONTENTS DEFINITIONS................................
I 1.0 APPLICABILITY 1.0-1 j
1.1 REACTIVITY CONTROL SYSTEMS 1.1.4 Control Rod Scram Times.................
1.1-1 1.1.6 Feedwater Temperature 1.1-3l 1.2 POWER DISTRIBUTION LIMITS 1.3 INSTRUMENTATION 1.3.1.1 Reactor Protection System Instrumentation 1.3-1 1.3.2.1 Control Rod Block Instrumentation 1.3-4 1.3.2.2 Feedwater and Main Turbine High Water l,
Level Instrumentation..,.............
1.3-10 i
L 1.3.3.1 Post Accident Monitoring (PAM) Instrumentation......_1.3-11 I
1.3.3.2 Remote Shutdown System.................
1.3-16 L'
1.3.4.1 EOC-RPT Instrumentation................
1.3-27 1.3.4.2 ATWS-RPT Instrumentation................. I'.3-29 l
1.3.4.6 Reactor Coolant System (RCS) Interface Valves I
Leakage Pressure.................... 1.3-30 1.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation..
1.3-33 1.3.5.2 Automatic Depressurization System (ADS) Inhibit _....
1.3-36 O
1.3.5.3 Reactor Core Isolation Cooling (RCIC) Instrumentation 1.3-38 1.3.6.1 Primary Containment Isolation Instrumentation.....
1.3-41
'l.3.6.2 Secondary Containment Isolation Instrumentation....
1.3-46
.1.3.7.1 Control Room Emergency Filtration System Instrumentation...................
1.3-47 1.3.7.2 Seismic Monitoring Instrumentation...........
1.3-48 1.3.7.3 Explosive Gas Monitoring Instrumentation........
1.3-51 1.3.7.4 New Fuel Storage Vault Radiation Monitoring Instrumentation...................
1,3-53' 1.3.7.5 Spent Fuel Storage Pool Radiation Monitoring Instrumentation...................
1.3-54 1.3.7.6 Turbine Overspeed Protection System..... !....
1.3-55 1.3.7.7 Traversing In-Core Probe (TIP) System........., 1.3-57 1.3.8.1 Loss of Power (LOP) Instrumentation..........
1.3-59 1.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring...................
1.3-60 1.4 REACTOR COOLANT SYSTEM 1.4.1 Reactor Coolant System (RCS) Chemistry..........
1.4-1 1.4.6 Reactor Coolant System Pressure Isolation Valves.....
1.4-5 (continued)
O WNP-2 i
Revision 15 I
LICENSEE CONTROLLED SPECIFICATIONS MANUAL TABLE OF CONTENTS (continued)
)
1.5 ECCS and RCIC SYSTEM 1.5-1l 1.5.1 ECCS Operating......................
1.6 CONTAINMENT SYSTEM 1.6-1 Primary Containment Isolation Valves...........
1.6.1.3 1.6.1.5 Suppression Pool Spray.................
1.6-14 1.6-16 1.6.4.2 Secondary Containment Isolation 1.7 PLANT SYSTEMS 1.7-1 1.7.1 Area Temperature Monitoring 1.7-4 1.7.2 Control Room Emergency Chillers 1.7-5 1.7.3 Snubbers.........................
1.7-7 1.7.6 Main Turbine Bypass System................
1.7-8 1.7.8 Sealed Source Contamination 1.8 ELECTRICAL POWER SYSTEM 1.8-1 1.8.4 24 VDC Sources......................
1.8-4 1.8.6 24 VDC Battery Parameters 1.8-6 1.8.7 24 VDC Distribution System................
1.8.9 Circuits Inside Primary Containment 1.8-9 1.8.10 Primary Containment Penetration Conductor Overcurrent Protection................
1.8-10 1.8.11 Motor Operated Valve (MOV) Thermal Overload Protection......................
1.8-14 1.9 REFUELING OPERATIONS 1.9.1 Refuel ing Pl atform....................
1.9-1 1.9.2 Crane Travel.......................
1.9-3 O
WNP-2 11 Revision 10
~~-.,.._,.._.mn, I
LICENSEE CONTROLLED SPECIFICATIONS MANUAL BASES (m~)
I B 1.0 APPLICABILITY B 1.0-1 l
B 1.1 REACTIVITY CONTROL SYSTEMS B 1.1.6 Feedwater Temperature B1.1-1l B 1.2 POWER DISTRIBUTION LIMITS B 1.3 INSTRUMENTATION B 1.3.2.1 Control Rod Block Instrumentation B 1.3-1 B 1.3.3.1 Post Accident Monitoring (PAM) Instrumentation.....
B 1.3-8 B 1.3.3.2 Remote Shutdown System Equipment Status Monitoring..
B 1.3-19a B 1.3.4.6 Reactor Coolant System (RCS) Interface Valves l
Leakage Pressure Monitors.............. B 1.3-20 J
B 1.3.5.2 Automatic Depressurization System (ADS) Inhibit
. B 1.3-23 B 1.3.5.3 Reactor Core Isolation Cooling (RCIC) Instrumentation
. B 1.3-26 B 1.3.7.2 Seismic Monitoring Instrumentation........... B 1.3-29 B 1.3.7.3 Explosive Gas Monitoring Instrumentation........ B 1.3-35 B 1.3.7.4 New Fuel Storage Vault Radiation Monitoring Instrumentation................... B 1.3-39 B 1.3.7.5 Spent Fuel Storage Pool Radiation Monitoring Instrumentation................... B 1.3-42 B 1.3.7.6 -
Turbine Overspeed Protection System.......... B 1.3-45 B 1.3.7.7 Traversing In-Core Probe (TIP) System......... B 1.3-50 B 1.4 REACTOR COOLANT SYSTEM s
B 1.4.1 Reactor Coolant System (RCS) Chemistry.........
B 1.4-1 B 1.5 ECCS and RCIC SYSTEM B 1.6 CONTAINMENT SYSTEM B 1.6.1.5 Suppression Pool Spray.................
B 1.6-1 B 1.7 PLANT SYSTEMS B 1.7.1 Area Temperature Monitoring B 1.7-1 B 1.7.2 Control Room Emergency Chillers B 1.7-5 B 1.7.3 Snubbers........................
B 1.7-9 B 1.7.8 Sealed Source Contamination.............. B 1.7-20 B 1.8 ELECTRICAL POWER SYSTEMS l
B 1.8.4 24 VDC Sources.....................
B 1.8-1 B 1.8.6~
24 VDC Battery Parameters B 1.8-9 8 1.8.7 24 VDC Distribution System............... B 1.8-15 i
B 1.8.9 Circuits Inside Primary Containment.......... B 1.8-18 l
B 1.8.10 Primary Containneent Penetration Conductor Overcurrent Protection................ B 1.8-20 B 1.8.11 Motor Operated Valve (MOV) Thermal Overload Protection.......
.............. B 1.8-23 (continued) l O l
WNP-2 Bi Revision 15
LICENSEE CONTROLLED SPECIFICATIONS MANUAL TABLE OF CONTENTS (continued) g B 1.9 REFUELING OPERATIONS B 1.9.1 Refueling Pl atform..............
l{,{
B 1.9.2 Crane Travel.............
CORE OPERATING LIMITS REPORT (COLR)
O O.
Revision 7 B ii WNP-2
1 RF0 Applicability 1.0 i
a 1.0 REQUIREMENTS FOR OPERABILITY (RFO) APPLICABILITY v
i RF0 1.0.1 RFOs shall be met during the MODES or other specified f'
conditions in the Applicability, except as provided in RF0 1.0.2.
l RF0 1.0.2 Upon discovery of a failure to meet an RF0, the Required Compensatory Measures of the associated Conditions shall be met, except as provided in RF0 1.0.5 and RF0 1.0.6.
If the RF0 is met or is no longer applicable prior to expiration of the specified Completion Time (s), completion of the Required Compensatory Measure (s) is not required, unless otherwise stated.
RF0 1.0.3 When an RF0 is not met and the associated Compensatory Measures are not. met, an associated Compensatory Measure is not provided, or if directed by the associated Compensatory Measures, the unit shall be placed in a MODE or other specified condition in which the RF0 is.not applicable or any supported equipment shall be declared inoperable. A Problem Evaluation Request (PER) shall be initiated to identify the failure to meet the RF0 and any further corrective actions.
Exceptions to this Specification are stated in the individual Specifications.
Where corrective measures are completed that permit operation in accordance with the RF0 or Compensatory Measures, completion of the actions required by RF01.0.3 is not required.
RF0 1.0.3 is only applicable in MODES 1, 2, and 3.
RF0 1.0.4 When an RF0 is not met, entry into the MODE or other specified condition in the applicability shall not be made except when the associated Compensatory Measures to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. This Specification shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with actions or that are a part of a shutdown of the unit.
Exceptions to this Specification are stated in the individual Specifications.
(continued)
O WNP-2 1.0-1 Revision 15
RF0 Applicability 1.0 1.0 RF0 APPLICABILITY Exceptions to this Specification are stated in the RF0 1.0.4 individual Specifications. These exceptions allow entry (continued) into MODES or other specified conditions in the Applicability when the associated COMPENSATORY MEASURES to be entered allow unit operation in the MODE or other specified condition in the Applicability only for a limited period of time.
RF01.0.4 is only applicable for entry into a MODE or other specified condition in the Applicability in MODES 1, 2, and 3.
Equipment removed from service or declared inoperable to RF0 1.0.5 comply with Compensatory Measures may be returned to service under administrative control solely to perform testing required to demonstrate its OPERABILITY or the OPERABILITY of other equipment. This is an exception to RF0 1.0.2 for f
the system returned to service under administrative control to perform the testing required to demonstrate OPERABILITY.
When a supported system RF0 is not met solely due to a RF0 1.0.6 support system RF0 not being met, the Conditions and Required Compensatory Measures associated with this supported system are not required to be entered. Only the support system RF0 Compensatory Measures are required to be entered. This is an exception to RF0 1.0.2 for the supported system.
When a support system's Required Compensatory Measure directs a supported system to be declared inoperable or directs entry into Conditions and Required Compensatory Measures for a supported system, the applicable Conditions and Required Compensatory Measures shall be entered in accordance with RF0 1.0.2.
O Revision 10 1.0-2 WNP-2
Control Rod Scram Times
.1.1.4 p
Figure 1.1.4-1 (page 1 of 2)
Q Correction of Scram Time Data to 800 psig Reactor Pressure
NOTE------------------------------------
Figure 1.1.4-1 provides information to be used in conjunction with SR 3.1.4.3.
See Technical Specification 3.1.4 and applicable Bases for further application l details.
1 CRD SCRAM has vs. Reactor h u
L9 u
A u
[
u jr u
u u--.
p u
P Le A
u r
u j
u u
,r %
j i
.u
()
J u 14 j
u u
, L4 g
u 2
f a
u-- pa o
u u
e.7 u-poo39 u
u g
u u
u--
pos46 u---
g u
a = m m m m w.
.=
a.
s n.
u.
u.
m m RewerPmem in PSIG 3(d WNP-2 1.1-1 Revision 15
~
Control Rod Scram Times 1.1.4 Figure 1.1.4-1 (page 2 of 2)
Correction of Scram Time Data to 800 psig Reactor Pressure N91E Corrected scram times shall be less than the normal scram times (NSS)
The correction factor is obtained from Figure 1.1.4-1 specified in the COLR.
and the following calculation:
C, = T/Teoo where C, = correction factor Scram Time at the test pressure, from Figure 1.1.4-1 Tp -
Teoo = Scram Time at 800m psig, from Figure 1.1.4-1 The measured scram time is divided by a correction factor C, to obtain the corrected scram time.
T, = T + C, where m
T, = Corrected scram time T - Scram time measured at test pressure O
O Revision 7 f
1.1-2 WNP-2
Feedwater Temperature 1.1.6 1.1 REACTIVITY CONTROL SYSTEMS
- g-t' 1.1.6 Feedwater Temperature RF0 1.1.6 For cycle extension, feedwater temperature entering the reactor vessel shall not be < 355'F.
APPLICABILITY:
MODE 1, after the E0C exposure has been achieved with steady state THERMAL POWER a: 47% of RTP.
l COMPENSATORY MEASURES CONDITION REQUIRED COMPENSATORY MEASURE COMPLETION TIME A.
Feedwater temperature A.1 Initite corrective 15 minutes q
l
< 355*.
action.
l AND-A.1 Restore feedwater 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> temperature to within e
O'^\\
limits.
08 A.3 Reduce THERMAL POWER 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to <25% RTP.
i i
!O WNP-2 1.1-3 Revision 15 4
4 4
~
Feedwater Temperature 1.1.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY At least once SR 1.1.6.1 Verify feedwater temperature entering reactor vessel is 2: 355'F.
per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> AND Initially after establishing reduced feedwater ter.perature lineup O
O WNP-2 1.1-4 Revision 15
ECCS Instrumentation 1.3.5.1 Table -1.3.5.1-1 (page 1 of 4)
Emergency Core Cooling System Instrumentation Trip Setpoints
........______........____.---------NOTE--------------------------------
Table 1.3.5.1-1 lists required instrument trip setpoints times to support OPERABILITY of LCO 3.3.5.1.
See Technical Specification 3.3.5.1 and applicable Bases.for further application details.
. FUNCTION TRIP SETPOINT 1.
Low Pressure Coolant Injection-A (LPCI) and Low Pressure Core Spray (LPCS) Subsystems a.
Reactor Vessel Water Level-Low Low Low, 2 -129 inches Level 1 l
b.
Drywell Pressure-High s 1.68 psig l
c.
LPCS Pump Start-LOCA Time Delay Relay a 8.67 seconds and I
s 10.50 seconds d.
LPCI Pump A Start-LOCA Time Delay Relay 2 17.70 seconds and s 21.07 seconds e.
LPCI Pump A Start-LOCA/ LOOP Time Delay a 3.19 seconds s':d Relay s 5.85 seconds f.
Reactor Vessel Pressure-Low (Injection a 466 psig and Permissive) s 488 psig g.
LPCS Pump Discharge Flow-Low (Minimum 2 698 gpm and Flow) s 1047 gpm i
h.
LPCI Pump A Discharge Flow-Low (Minimum a 650 gpm and Flow) s 956 gpm i
1.
Manual Initiation NA LPCI B and LPCI C Subsystems 2.
L a.
Reactor Vessel Water Level-Low Low Low, 2 -129 inches Level 1 i
(continued) g, i;O WNP-2 1.3-33 Revision 15 i
b
ECCS Instrumentation 1.3.5.1 Table 1.3.5.I-1 (page 2 of 4)
Emergency Core Cooling System Instrumentation Trip Setpoints FUNCTION TRIP SETPOINT
Drywell Pressure-High s 1.68 psig l
LPCI Pump B Start-LOCA Time Delay Relay 2 17.70 seconds and c.
s 21.07 seconds d.
LPCI Pump C Start-LOCA Time Delay Relay 2 8.67 seconds and s 10.50 seconds LPCI Pump B Start-LOCA/ LOOP Time Delay a 3.19 seconds and e.
s 5.85 seconds Relay f.
Reactor Vessel Pressure-Low (Injection 2 466 psig and Permissive) s 488 psig g.
LPCI Pumps B & C Discharge Flow-Low 2 650 gpm and (Minimum Flow) s 956 gpm O
NA l
h.
Manual Initiation 3.
High Pressure Core Spray (HPCS) System i
Reactor Vessel Water Level-Low Low, 2 -50 inches a.
Level 2 b.
Drywell Pressure-High s 1.68 psig l
c.
Reactor Vessel Water Level-High, s 54.5 inches Level 8 d.
Condensate Storage Tank Level-Low a 448 ft 3 inch elevation s 466 ft 8 inches Suppression Pool Water Level-High e.
elevation (continued)
O WNP-2 1.3-34 Revision 15
Explosiva Gas Monitoring Instrumentation l
1.3.7.3 1
1.3 INSTRUMENTATION 1.3.7.3 Explosive Gas Monitoring Instrumentation RF0 1.3.7.3-One Main Condenser Offgas Treatment System Hydrogen Monitor 1
- shall be OPERABLE.
I APPLICABILITYi During Mein. Condenser Offgas Treatment System operation.
COMPENSATORY MEASURES
___........___.............----------NOTE-------------------------------------
RF01.0.3 is not applicable.
CONDITION REQUIRED COMPENSATORY MEASURE COMPLETION TIME A.
One required Hydrogen A.1 Monitor Main 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Monitor inoperable.
Condenser Offgas Treatment System M
Os Hydrogen concentration.
Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter M
A.2 Restore inoperable 30 days monitor to operable status.
B.
Required. Compensatory B.1 Initiate Problem 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Measure and associated Evaluation Request Completion Time not (PER).
met.
O WNP-2 1.3-51 Revision 7
Explosive Gas Monitoring Instrumentation 1.3.7.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 1.3.7.3.1 Perform CHANNEL CHECK.
12 months SR 1.3.7.3.2 Perform CHANNEL CALIBRATION.
O O
1.3-52 Revision 15 WNP-2 U
Turbine Overspeed Protection System 1.3.7.6 l
(
1.3 INSTRUMENTATION i
l.3.7.6 Turbine Overspeed Protection System p
i RF0 1.3.7.6 One Turbine Overspeed Protection System shall be OPERABLE.
l APPLICABILITY:
MODES 1 and 2.
COMPENSATORY MEASURES 1
NOTE--------
l RF01.0.4 is not applicable.
l REQUIRED COMPENSATORY MEASURE COMPLETION TIME I
~
CONDITION i
l A.
One high pressure A.1 Restore high pressure 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
-turbine valve turbine valve to l
OPERABLE status.
l B.
One low pressure B.1 Restore low pressure 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> j
turbine valve turbine valve to inoperable.
OPERABLE status.
{
C. ' Required Compensatory C.1 Isolate the affected 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Measure and associated steam line from the Completion Time of__
steam supply.
Condition A or B not f_
met.
l M
M Required; Turbine C.2 Isolate the main 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Overspeed Protection turbine from the System inoperable for steam supply.
reasons other than l
Condition A or B.
1 l
4 i
!O WNP-2 1.3-55 Revision 10
Turbine Overspeed Protection System 1.3.7.6 l
SURVEILLANCE REQUIREMENTS g
...................--------------------NOTE-----------------------------------
SR 1.0.4 is not applicable.
FREQUENCY 1
SURVEILLANCE SR 1.3.7.6.1
NOTE------------------
Not required to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after valve has been opened with adequate steam flow available.
1 Cycle each of the following valves 92 days through at least one complete cycle from the running position for the overspeed protection control system, the electrical overspeed trip system, and the mechanical overspeed trip system:
Four high pressure turbine throttle a.
valves; b.
Six low pressure turbine reheat stop w
valves; c.
Four high pressure turbine governor valves; and d.
Six low pressure turbine interceptor valves.
I SR 1.3.7.6.2 Perform CHANNEL CALIBRATION.
18 months SR 1.3.7.6.3 Disassemble at least one of each of the 40 months above valves, perform a visual and surface inspection of all valve seats, disks and stems and verify no unacceptable flaws or excessive corrosion.
If unacceptable flaws or l
excessive corrosion are found, all other valves of that type shall be inspected.
O WNP-2 1.3-56 Revision 15 l
l l
~ _ _ _. _ _ _._
r Primary Containment Isolation Valves 1.6.1.3 Table 1.6.1.3-1 (page 11 of 13)
Primary Containment Isolation Valves MAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER VALVE GROUP (a)
(Seconds)
- 4. Other Containment Isolation Valves (continued)
- h. Containment Atmosphere Control (e)(k)
NA (H2 Recombiner)
CAC-V-2 L
.CAC-FCV-2A,B CAC-V-15 CAC-FCV-1A,B CAC-V-11 CAC-V-6 CAC-V-4 CAC-FCV-4A,B CAC-V-13' CAC-V-17 CAC-FCV-3A,B CAC-V-8
- i. Containment Purge System NA CSP-V-5 CSP-V-6 CSP-V-7 C57-7-8 CSP-V-9 CSP-V-10
- j. Reactor Recirculation (Seal Injection)
NA RRC-V-13A,B RRC-V-16A,B (continued)
(a)
See Technical Specification Bases 3.3.6.1 for the isolation signal (s) which operate each group.
(e)
May be opened on an intermittent basis under administrative control.
(k)
May be tested as part of Type A test.
If so tested, Type C test results may be excluded from sum of other Type B and C tests.
i l10 V
WNP-2 1.6-11 Revision 15
Primary Containment Isolation Valves 1.6.1.3 Table 1.6.1.3-1 (page 12 of 13)
Primary Containment Isolation Valves MAXIMUM ISOLATION TIME VALVE GROUP (a)
(Seconds)
VALVE FUNCTION AND NUMBER
- 4. Other Containment Isolation Valves (continued)
NA
- k. Containment Instrument Air CIA-V-20 CIA-V-21 CIA-V-30A,8 CIA-V-31A,8
- l. Post-Accident Sampling System (e)
NA PSR-V-X73-1 PSR-V-X73-2 PSR-V-X77Al PSR-V-X77A2 PSR-V-X77A3 PSR-V-X77A4 PSR-V-X80-1 PSR-V-X80-2 PSR-V-X82-1 PSR-V-X82-2 PSR-V-X82-7 PSR-V-X82-8 PSR-V-X83-1 PSR-V-X83-2 PSR-V-X84-1 PSR-V-X84-2
}
PSR-V-X88-1 PSR-V-X88-2
- m. Radiation Monitoring NA PI-V-X72f/1
~
PI-V-X73e/1 (continued)
(a)
See Technical Specification Bases 3.3.6.1 for the isolation signal (s) which operate each wroup.
(e)
May be opened on an intermittent basis under administrative control.
O WNP-2 1.6-12 Revision 7
. ~.. _. _. - - _ _. _
Area Temperature Monitoring 1.7.1 Table 1.7.1-1 (page 1 of 1)
O Area Temperature Monitoring AREA TEMPERATURE LIMIT 1.
Control Room
< 104*F 2.
Auxiliary Electric Equipment Rooms
< !04*F l
3.
Primary Containment (Drywell)
< 150*F 4.
High Pressure Core Spray, Low Pressure Core Spray,
< 150*F Reactor Residual Heat Removal, Reactor Core l
Isolation Cooling Rooms 5.
Primary Containmaat Beneath Reactor
< 165'F Pressure Vessel 6.
Switchgear Rooms
< 104*F
..r,...
1 O
i O
WNP-2 1.7-3 Revision 15
...----...~...~..-.m.-.-
-.---..sa.---..-a.
s--~-
---~~-..an~-
a.--n.-~~a.-n..an...,.>..>.-a.~.--na.--n.w-wana--u.n.s.
+
I 4
4 l
1 I
l O
i i
l i
a O.
J
~ ~ ~ - - - -
Control Room Emergency Chillers 1.7.2 1.7 PLANT SYSTEMS 1.7.2 Control Room Emergency Chillers RF0 1.7.2:
Control Room Emergency Chillers shall be OPERABLE.
APPLICABILITY:
At all times.
COMPENSATORY MEASURES CONDITION REQUIRED COMPENSATORY MEASURE COMPLETION TIME A.
One control room A.1 Restore control room 30 days chiller inoperable.
chiller to OPERABLE status.
B.
Two control room B.1 Restore one control 14 days chillers inoperable.
room chiller to OPERABLE status.
O C.
Required Compensatory C.1 Initiate Problem 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Measure and associated Evaluation Request Completion Times of (PER).
Condition A or B not met.
SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 1.7.2.1 Verify each control room chiller has the 31 days l
capability to remove control room heat load.
t 1
i
- O WNP-2 1.7-4 Revision 15
- -. =.
Feedwater Temperature B 1.1.6 B 1.1 REACTIVITY CONTROL SYSTEMS B 1.1.6 Feedwater Temperature 1
BASES BACKGROUND Final feedwater temperature reduction is used at the end of cycle (E0C) for the purpose'of increasing net core reactivity. The EOC is the core exposure at which RATED THERMAL POWER (RTP), rated core flow and rated feedwater temperature would be achieved if all control rods were fully withdrawn.
Final feedwater temperature reduction is the operation at or beyond E0C for the purpose of extending the normal fuel cycle by plant operation with a final feedwater temperature reduced from the normal rated power temperature condition.
The process involves feedwater heater manipulations, core reactivity changes, plant maneuvering, and an awareness of special licensing restrictions. The general philosophy is to trade subcnoling reactivity for rod and flow reactivity during the latter portion of the operating cycle.
As part of the original WNP-2 SER (Ref.1), the Supply
/]
System was asked to justify that operation with partial V
feedwater heating to extend the cycle beyond the normal E0C condition would not result in a more limiting change in MINIMUM CRITICAL POWER RATIO (MCPR) than that obtained using the assumption of normal feedwater heating.
The Supply
-)
System responded that analyses would be provided prior to operation in that mode, if a decision is made to implement final feedwater temperature reduction.
As a result, Condition 2.C.(17) was incorporated into the WNP-2 Operating License to prohibit operation with partial feedwater heating for the purpose of extending the normal fuel cycle unless acceptable justification was provided to and approved by the NRC staff.
i Operation with partial feedwater heating for the purpose of extending the normal fuel cycle was approved by Amendment No. 77 to the WNP-2 Operating License (Ref. 9).
Issuance of Amendment No. 77 satisfied WNP-2 Operating Lic.ense Condition 2.C.(17).
(continued) lO WNP-2 B 1.1-1 Revision 15
Feedwater Temperature B 1.1.6 BASES (continued)
APPLICABLE For the purpose of extending cycle, feedwater temperature SAFETY ANALYSES may be used for reactivity addition to compensate for the reactivity loss due to fuel depletion. The analysis performed is applicable to core flow values up to the maximum attainable (106 percent of rated core flow) and to feedwater temperature reductions as low as 355'F.
It is anticipated that a thermal coastdown from rated power with feedwater temperature reduction of this order is desirable.
The analysis also covers a reduction in power by thermal coastdown to 47% of RTP with feedwater temperature held at or above 355'F.
During a normal feedwater lineup, a feedwater temperature at 355'F entering the reactor vessel is achieved at approximately 47% of RTP. The Requirement for Operability clearly does not apply during reactor startups and shutdowns when reactor power is below the point at which a feedwater temperature of 355'F is attainable with a normal feedwater system lineup.
Prior to reaching the EOC exposure, operation with an abnormal feedwater lineup is permissible because the short term effect of increased subcooling is to more strongly bottom peak the axial power shape. This allows a scram to suppress the flux faster.
Compensation for the long term effect of a pronounced bottom burn can be made by rod pattern adjustments and axial flux shape monitoring.
REQUIREMENTS For the purposes of cycle extension, the feedwater FOR OPERABILITY temperature entering the reactor vessel shall not be reduced to < 355'F.
APPLICABILITY MODE 1, after the E0C exposure has been achieved with steady state THERMAL POWER 2: 47% of RTP.
COMPENSATORY A.I. A.2. and A.3 MEASURES With feedwater temperature entering the reactor vessel at a value < 355'F, initiate corrective action within 15 minutes and restore feedwater temperature to within the limit within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or reduce THERMAL POWER to < 25% of RTP within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
(continued)
O WNP-2 B 1.1-2 Revision 15
Feedwater Temperature B 1.1.6 BASES (continued)
SURVEILLANCE SR 1.1.6.1 REQUIREMENTS During cycle operation beyond EOC exposure, the feedwater temperature entering the reactor vessel shall be determined to be m 355'F at least once per. 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and initially after establishing a reduced feedwater temperature lineup.
REFERENCES 1.
NUREG-0892, " Safety Evaluation Report Related to the Operation of WPPSS Nuclear Project No. 2, Docket No.
50-397," March 1982 2.
WNP-2 Operating License, Condition 2.C.(17),
" Operation with Partial Feedwater Heating (Section 15.1,SER)"
3.
General Electric Topical Report NEDC-31107, " Safety Review of WPPSS Nuclear Project No. 2 at Core Flow Conditions Above Rated Flow Throughout Cycle 1 and Final Feedwater Temperature Reduction," March 1986 4.
Advanced Nuclear Fuels Report XN-NF-87-92, "WNP-2 Plant Transient with Final Feedwater Temperature Reduction," June 1987 5.
Letter G02-87-286, dated December 15, 1987 6.
Letter G02-88-198, dated September 14, 1988 7.
Letter G02-89-102, dated June 1, 1989 8.
Letter G02-90-024, dated February 14, 1990 9.
WNP-2 Operating License, Amendment No. 77, dated March 1, 1990 10.
Letter G02-90-069, dated April 5, 1990 O
WNP-2 B 1.1-3 Revision 15
_._________:.......~c...
Control Rod Block Instrumentation B 1.3.2.1 e
B 1.3 INSTRUMENTATION B 1.3.2.1 Control Rod Block Instrumentation BASES BACKGROUND The purpose of the control rod block instrumentation is to mitigate rod withdrawal errors. Control rods provide the primary means for control of reactivity changes. The most significant source of reactivity changes during power increase is due to control rod withdrawal. Control rod block instrumentation includes channel sensors, logic circuitry, switches, and relays arranged so that a trip in any channel will result in a control rod block (Ref.1).
l The Average Power Range Monitoring (APRM) instrumentation will initiate a rod block to prevent control rod withdrawal if the average core flux exceeds mode switch dependent upscale setpoints. Downscale (MODE 1 only) and INOP generated rod blocks prevent rod withdrawal if the channel is not operating as expected.
The Source Range Monitor (SRM) instrumentation provides a rod block to prevent control rod withdrawal if the SRM is c
not fully inserted into the core when the count level is N
below the retract permissive setpoint. This is to assure that the SRM is correctly inserted when it must be relied upon to provide neutron flux level information. The SRM instrumentation also provides a rod block if the localized neutron flux exceeds a predetermined setpoint.
This is to assure that the SRM is correctly retracted during a reactor startup.
The SRM also provides a rod block if the localized neutron flux falls below a predetermined setpoint, or is inoperative during control rod manipulations. This is to ensure that the SRM is correctly inserted and responding to the neutron flux signal.
The Intermediate Range Monitors (IRM) instrumentation provides a rod block to prevent control rod withdrawal if the IRM is not fully inserted into the core when in MODE 2 or 5.
This is to assure that no control rod is withdrawn during low neutron flux level operations unless proper neutron monitoring capability is available. The IRM instrumentation provides a rod block if the localized neutron flux exceeds a predetermined setpoint.
This is to
}
assure that no control rod is withdrawn unless the IRM instrumentation is correctly upranged during a reactor startup.
This rod block also provides a means to stop rod (continued)
WNP-2 B 1.3-1 Revision 15
Control Rod Block Instrumentation B 1.3.2.1 BASES withdrawal in time to avoid conditions requiring Reactor BACKGROUND Protection System (RPS) action (scram) in the event that a (continued) rod withdrawal error is made during low neutron flux level The IRM instrumentation provides a rod block to operations.
prevent control rod withdrawal if the IRM count level is downscale except when the IRM range switch is on the lowest range, or is inoperative. This assures that no control rod is withdrawn unless the neutron flux is being correctly monitored.
The scram discharge volume (SDV) high level instrumentation will initiate a rod block when the level is above the setpoint, or the SDV high water trip is bypassed. This assures that no control rod is withdrawn unless the high discharge level trip is in service, and enough capacity is available in the SDV to accommodate a scram.
The reactor coolant recirculation flow unit instrumentation provides total recirculation loop flow signals to the APRM and rod block monitor (RBM) systems for generation of flow biased settings for RPS and rod block trips. The reactor coolant recirculation flow units will generate a rod block when any channel indicates high flow, a mis-match between channels or a IN0P condition to prevent rod withdrawal if the channel is not operating as expected.
The control rod block instrumentation supports the APPLICABLE SAFETY ANALYSES initiation of a rod block when initiating conditions exceed preset limits.
REQUIREMENTS
- 1. Trio Setooint Allowances FOR OPERABILITY Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor power), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e,g.,
trip unit) changes state. The actual retpoints are calibrated consistent with applicable setpoint methodology.
Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Values between successive CHANNEL CALIBRATIONS.
Operation with a (continued)
WNP-2 B 1.3-2 Revision 7 l
Control Rod Block Instrumentation B 1.3.2.1 I
BASES
- O 1
SURVEILLANCE SR 1.3.2.1.4 (continued)
REQUIREMENTS Performance of a CHANNEL CALIBRATION every 18 months ensures that the instrumentation used for low power operation is calibrated to account for instrument drift between seccessive calibrations consistent with the plant specific i
setpoint methodology.
SR 1.3.2.1.5 Performance of a LOGIC SYSTEM FUNCTIONAL TEST every i
24 months demonstrates the OPERABILITY of the required rod I
block trip logic through each activity control. path of the Reactor Manual Control System (RMCS) for a specific RMCS input and reactor mode switch position.
The functional testing of APRM, SRM, IRM, SDV and reactor coolant recirculation flow, in SR 1.3.2.1.1 through SR 1.3.2.1.4, overlap this Surveillance to provide complete testing of l
each Function.
Each CHANNEL FUNCTIONAL TEST and CHANNEL i
CALIBRATION verifies the channel through the common point where the channels lose their identity to the RMCS inputs (Npd,Nu,Npu,Hw).
Several channe.ls are combined into the O
RMCS mode dependent logic to develop the rod block output signal. The LOGIC SYSTEM FUNCTIONAL TEST is summarized as a verification of each RMCS activity control path resulting in i
rod blocks for Npd, Npu and Hw inputs in MODE 1; Nu, Npu and Hw inputs in MODE 2; and Nu for MODE 5.
The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage due to the reactor mode switch inputs.
1 REFERENCES 1.
FSAR, Section 7.7.1.2.2.2.
l 2.
FSAR, Section 15.4.1.
3.
FSAR, Section 15.4.2.
E i
i O WNP-2 B 1.3-7 Revision 15 t
.w---
Explosive Gas Monitoring Instrumentation B 1.3.7.3 B 1.3 INSTRUMENTATION B 1.3.7.3 Explosive Gas Monitoring Instrumentation BASES BACKGROUND The Off-Gas Treatment System is the principle pathway for j
the release of gaseous radioactivity to the environment during normal plant operations. The Off-Gas Treatment System is designed to limit dose to offsite per ons from routine station releases to significantly less than the limits specified in 10 CFR Part 20 and Part 50 and to operate within the emission rate limits established in the i
Technical Specifications.
Hydrogen and oxygen are produced in a boiling water reactor (BWR) by the radiolysis of water. The hydrogen and oxygen produced, along with fission products and other noncondensible gases, are removed from the main condenser by a steam jet air ejector and exhausted to the Off-Gas
(
Treatment System. The potential exists for hydrogen and oxygen to exist in flammable or explosive concentrations.
l The BWR industry has experienced a number of fires in the Off-Gas Treatment System. A catalytic recombiner is provided'in the Off-Gas Treatment System to recombine hydrogen and oxygen.
The Off-Gas Treatment System is designed
- maintain the hydrogen concentration upstream of the recombiner to less than the flammable limit (4% by volume) by steam dilution.
The hydrogen recombiner is designed to ensure that the hydrogen concentration at the outlet is less than 1% on a dry basis.
There are two hydrogen analyzers (explosive gas monitors) to 4
monitor the hydrogen concentration downstream of the hydrogen recombiner. The hydrogen concentration is measured in volume percent and is indicated and recorded in the control room. There is also an independent alarm annunciator for high hydrogen concentration (> 1%).
Calibration checks are accomplished automatically at periodic intervals by isolating the off-gas process line and admitting a calibrat hn gas.
(continued) i
'O WNP-2 B 1.3-35 Revision 7
Explosive Gas Monitoring Instrumentation B 1.3.7.3 g
BASES The Off-Gas Treatment System design eliminates ignition BACKGROUND (continued) sources, so that a hydrogen detonation is highly unlikely in the event of a recombiner failure. Also the system is designed to be detonation resistant.
APPLICABLE The explosive gas monitoring instrumentation is not used i
i SAFETY ANALYSES for, nor is capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary.
The explosive gas monitoring instrumentation is not used to monitor any process variable that is an initial condition of a design basis accident (DBA) or transient.
Excessive system hydrogen is not an indication of a DBA or transient.
The explosive gas monitoring instrumentation is not part of a primary success path in the mitigation of a DBA or transient.
REQUIREMENTS One Main Condenser Off-Gas Treatment System hydrogen monitor FOR OPERABILITY shall be OPERABLE.
An OPERABLE hydrogen monitor consists of a hydrogen analyzer g skid (A or B), the recorder channel in the main control room (MCR) on 0G-H2R-605 (A or B), the high hydrogen alarm in the MCR for the corresponding channel and the common support equipment.
APPLICABILITY During Main Condenser Off-Gas Treatment System operation (steam jet-air ejectors are in operation).
COMPENSATORY Ad MEASURES If there are no OPERABLE explosive gas monitor instruments and the Main Condenser Off-gas Treatment System is in t
i operation, then monitor (Chemistry will take grab sample and analyze) the Main Condenser Off-gas Treatment System hydrogen concentration within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, and once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter, and within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> from disco"9ry of each change l
in recombiner temperature or THERMAL POWER.
l A Note has been provided that states RF0 1.0.3 is not applicable because adequate Compensatory Measures are provided in the RF0.
(continued)
WNP-2 B 1.3-36 Revision 15 1
i l
l 1
Explosive Gas Monitoring Instrumentation B 1.3.7.3 BASES (continued) p V
I I
SURVEILLANCE SR 1.3.7 11 REQUIREMENTS i
Performanct of the CHANNEL CHECK once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on the other channel.
It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of i
excessive instrument drift in one of the channels, or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying that the instrument continues to operate properly between each CHANNEL CALIBRATION.
Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability.
If a channel is I
outside the criteria, it may be an indication that the instrument has drifted outside of its limit.
The Frequency is based upon gerating experience that i (3 demonstrates less formal, but are frequent, checks of l
s.)
channels during normal operation.1 use of the displays i
associated with the channels required by the RF0.
SR 1.3.7.3.2 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drift between successive calibrations consistent with the plant specific setpoint methodology.
The Frequency is based upon the assumption of a 12 month calibration interval based on industry experience, vendor I
recommendation, and the nitrogen purging which functions as an auto calibration.
(continued)
O V
WNP-2 B I.3-37 Revision 15
Explosive Gas Monitoring Instrumentation B 1.3.7.3 BASES (continued)
REFERENCES 1.
Technical Specification 5.5.8.
2.
Technical Specification 3.7.5.
3.
FSAR, Section 11.3.
O O
WNP-2 B 1.3-38 Revision 15l
Control Room Emergency Chillers B l.7.2 BASES i
COMPENSATORY is expected that personnel could tolerate elevated control MEASURES room temperatures for several days with minimal performance (continued) degradation, personnel rotation would provide an added level of assurance.
The plant could also restore radwaste chilled water or other cooling water supplies to reduce the control room temperature.
SURVEILLANCE A conservative monthly Surveillance Requirement has been REQUIREMENTS identified to establish a data base of equipment failure rates. Acquisition of sufficient data may be used at a future time to revise the surveillance interval based on equipment reliability and operability trends.
The monthly surveillance consists of operating each control room chiller with the control room heat load applied for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The chillers are required to maintain the control rocm temperature at 75'F i 3* dry bulb to satisfy the habitability limit of 85'F.
The monthly chiller OPERABILITY check is performed under the (G
preventive maintenance process and scheduled and tracked in
)
accordance with PPM 1.5.13 and 1.3.71.
In addition, the applicable Inservice Testing Prcgram surveillance procedure provides assurance of control chilled water pump OPERABILITY.
REFERENCES 1.
System Description No. 82-RSY-13-5-T6, Control Room, Cable Room and Critical Switchgear Rooms - HVAC (CR-HVAC), dated 2/17/91.
2.
FSAR Section 6.4.2.2.
l 3.
FSAR Section 9.4.1.1.
l 4.
NUREG/CR-3786, A Review of Regulatory Requirements Governing Control Room Habitability Systems, Sandia-National Laboratories, dated August 1984.
(continued)
O WNP-2 B 1.7-7 Revision 15
Control Room Emergency Chillers B 1.7.2 BASES Industrial Ventilation, Manual of Recommended Practices, High Environmental Dry and Wet Bulb REFERENCES 5.
(continued)
Temperatures That can Be Tolerated In Daily Work By Healthy Acclimatized Men Wearing Warm Weather Clothing,14th edition.
Reply to Supply System to NRC letter No. G02-94-126, Notice of Violation 94-12, dated May 27, 1994.
6.
Cooling Supply System calculation number ME-02-93-52, Loa 7.
I l
Conditions, Rev. O.
WNP-2, PPM 1.3.71, Work Closecut Activities.
8.
WNP-2, PPM 1.5.13, Scheduled Maintenance Systec:.
9.
WNP-2 PPM 4.10.2.5, Control Room High Temperature.
10.
WNP-2, PPM OSP-CCH/IST-Q701, Control Room Chilled l 11.
Water Punip Operability.
O O
Revision 10 B 1.7-8 WNP-2
l 24 VDC Sources B 1.8.4 BASES O
l SURVEILLANCE SR 1.8.4.8 (continued)
REQUIREMENTS Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 1.8.4.8; however, only the modified performance discharge test may be used to satisfy SR 1.8.4.8 while satisfying the requirements of SR 1.8.4.7 at the same time.
The acceptance criteria for this Surveillance is consistent with IEEE-450 (Ref. 4) and IEEE-485 (Ref. 5) for the 24V batteries. These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating, since IEEE-485 (Ref. 5) recommends using an aging factor of 125% in the battery sizing calculations. A capacity of 80% for the 24V battery shows that the battery is getting old and capacity will decrease more rapidly, even if there is ample capacity to meet the load requirements.
The Surveillance Frequency for this test is normally 60 months.
If the battery shows degradetion, or if the battery has reached 85% of its expected life and capacity is
< 100% of the manufacturer's rating, the Surveillance
(]
Frequency is reduced to 12 months. However, if the battery V
shows no degradation but has reached 85% of its expected life, the Surveillance Frequency is only reduced to 24 months for batteries that retain capacity 2: 100% of the manufacturer's rating. - Degradation is indicated, according to IEEE-450, 1975 (Ref. 6), when the battery capacity drops by more than 10% relative to its average on previous performance tests or when it is below 90% of the manufacturer's rating. The 12 month and 60 month Frequencies are consistent with the recommendations in IEEE-450 (Ref. 4). The 24 month Frequency is derived from the recommendations in IEEE-450 (Ref. 4).
REFERENCES 1.
FSAR, Section 8.3.2.1.2.
l 2.
Technical Specification 3.3.1.1.
l 3.
WNP-2 Calculation 2.05.01, Res. 8, February 1990.
4.
IEEE Standard 450, 1987.
(continued)
/"~h b
WNP-2 B 1.8-7 Revision 15
24 VDC Sources B 1.8.4 g
BASES REFERENCES 5.
IEEE Standard 485, 1983.
(continued) 6.
IEEE Standard 450, 1975.
O O
WNP-2 B 1.8-8 Revision 7
24 VDC Battery Parameters B 1.8.6 BASES O
SURVEILLANCE Table 1.8.6-1 (continued)
REQUIREMENTS The specific gravity readings are corrected for actual electrolyte temperature and level. For each 3*F (1.67'C) above 77'F (25'C), 1 point (0.001) is added to the reading; 1 point is subtracted for each 3*F below 77'F.
The specific gravity of the electrolyte in a cell increases with a loss of water due to electrolysis or evaporation.
Level correction will be in accordance with manufacturer's recommendations.
Category B defines the normal parameter limits for each connected cell. The term " connected cell" excludes any battery cell that may be jumpered out.
The Category B limits specified for electrolyte level and float voltage are the same as those specified for Category A and have been discussed above. The Category B limit specified for specific gravity for each connected cell is 2: 1.195 (0.020 below the manufacturer's fully charged, nominal specific gravity) with the average of all connected cells > 1.205 (0.010 below the manufacturer's fully charged, nominal specific gravity). These values are based on A
manufacturer's recommendations. The minimum specific V
gravity value required for each cell ensures that a cell with a marginal or unacceptable specific gravity is not masked by averaging with cells having higher specific gravities.
Category C defines the limit for each connected cell. 1hese values, although reduced, provide assurance that sufficient capacity exists to perform the intended function and maintain a margin of safety. When any battery parameter is outside the Category C limit, the assurance of sufficient capacity described above no longer exists and the battery must be declared inoperable.
The Category C limit specified for electrolyte level (above the top of the plates and not overflowing) ensure that the plates suffer no physical damage and maintain adequate electron transfer capability. The Category C limit for float voltage is based on IEEE-450, Appendix C (Ref. 2),
which states that a cell voltage of 2.07 Y or below, under float conditions and not caused by elevated temperature of the cell, indicates internal cell problems and may require cell replacement.
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Od WNP-2 B 1.8-13 Revision 7
24 VDC Battery Parameters B,1.8.6 I
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BASES SURVEILLANCE Table 1.8.6-1 (continued)
REQUIREMENTS The Category C limit of average specific gravity (2: 1.195),
is based on manufacturer's recommendations (0.020 below the manufacturer's recommended fully charged, nominal specific In addition to that limit, it is required that gravity).
the specific gravity for each connected cell must be no less than 0.020 below the average of all connected cells.
This limit ensures that a cell with a marginal or unacceptable specific gravity is not masked by averaging with cells having higher specific gravities.
The footnotes to Table 1.8.6-1 that apply to specific gravity are applicable to Category A, B, and C specific Footnote b requires the above mentioned correction gravity.
for electrolyte level and temperature, with the exception that level correction is not required when battery charging current is < 2 amps on float charge. This current provides, in general, an indication of acceptable overall battery condition. Because of specific gravity gradients that are produced during the recharging process, delays of several days may occur while waiting for the specific gravity to stabilize. A stabilized charging current is an acceptable alternative to specific gravity measurement for determining the state of charge. This phenomenon is discussed in IEEE-450 (Ref. 2). Footnote c allows the float charge current to be used as an alternate to specific gravity for up to 7 days following a battery recharge. Within 7 days each connected cell's specific gravity must be measured to confirm the state of charge.
Following a minor battery recharge (such as an equalizing charge that does not follow a deep discharge), specific gravity gradients are not significant, and confirming measurements may be made in less than 7 days.
REFERENCES 1.
FSAR, Section 8.3.2.1.2.
l 2.
IEEE Standard 450, 1987.
O B 1.8-14 Revision 15 WNP-2
24 VDC Distribution System B 1.8.7 BASES O
COMPENSATORY With one or more 24 VDC electrical power subsystem MEASURES inoperable, immediately declare required supported equipment (continued) inoperable. OPERABLE DC electrical power distribution subsystems require the associated buses to be energized to their proper voltage.
SURVEILLANCE SR 1.8.7.1 REQUIREMENTS This Surveillance verifies that the DC electrical power distribution systems are functioning properly, with the correct circuit breaker alignment. The correct breaker alignment ensures the appropriate separation and independence of the electrical divisions is maintained and power is available to each required bus.
The verification of energization of the buses ensures that the required power is readily available for motive as well as control functions for critical system loads connected to these buses. This may be performed by verification of absence of low voltage alarms or by verifying a load powered from the bus is operating.
The 7 day Frequency takes into account the redundant capability of the DC electrical power distribution subsystems and other indications available in the control room that alert the operator to subsystem malfunctions.
REFERENCES 1.
FSAR, Section 8.3.2.1.2.
l 2.
Technical Specification 3.3.1.1.
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WNP-2 B 1.8-17 Revision 15
Circuits Inside Primary Containment B 1.8.9 B 1.8 ELECTRICAL POWER SYSTEMS B 1.8.9 Circuits Inside Primary Containment BASES BACKGROUND Primary containment electrical penetrations and penetration conductors are protected by either deenergizing power circuits not required during reactor operation or by demonstrating the OPERABILITY of primary and backup overcurrent protection devices by periodic surveillances.
Those AC circuits inside primary containment, which are kept normally deenergized, do not participate in plant safety actions. These circuits are primarily for lighting, utility outlets, and convenience power to be used for plant walkdowns, maintenance, and in-situ tests and/or j
observations.
These circuits are non Class IE.
APPLICABLE The AC circuits inside primary containment are kept normally SAFETY ANALYSES deenergized and do not participate in plant safety actions.
Thus, these circuits have no impact on plant safety systems.
O REQUIREMENTS The following AC circuits shall be deenergized:
FOR OPERABILITY
- a. Circuits off of breakers 2AR and 8AR of E-MC-8C.
- b. Circuits off of panel E-LP-6 BAG.
- c. Circuits off of panel E-LP-3DAG.
- d. Circuits off of breakers 2BL, ID, and 2CR of E-MC-3DA.
APPLICABILITY MODES 1, 2, and 3, except during entries into the drywell.
This is consistent with the applicability of other primary containment requirements.
Primary containment OPERABILITY is not required in MODES 4 and 5.
Additionally, these circuits may be energized to support maintenance activities during outages.
(continued) lO WNP-2 B 1.8-18 Revision 7
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I Circuits Inside Primary Containment B 1.8.9 BASES (continued)
COMPENSATORY Ad MEASURES With one or more required circuits energized, deenergize the required circuit within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This Completion Time is consistent with other primary containment requirements.
SURVEILLANCE SR 1.8.9.1 and SR 1.8.9.2 REQUIREMENTS Every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> verify that each required circuit that is not locked, sealed, or otherwise secured in the deenergized condition is deenergized.
Every 31 days verify that each required circuit that is locked, sealed, or otherwise secured in the deenergized position has remained deenergized. The 31 day Frequency is acceptable considering the additional administrative controls to assure the required deenergized position is maintained.
REFERENCES 1.
FSAR, Section 1.8.
2.
FSAR, Section 3.8.2.2.4.
3.
FSAR, Section 7.1.2.3.
4.
FSAR, Section 8.3.1.
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WNP-2 B 1.8-19 Revision 15
M0V Thermal Overload Protection B 1.8.11 i
B 1.8 ELECTRICAL POWER SYSTEMS B 1.8.11 Motor Operated Valve (MOV) Thermal Overload Protection BASES BACKGROUND For valves with thermal overload protection (i.e., trip on overload condition), the valve function should be accomplished prior to overlo:td trip. The overload protection for these valves is meant to take precedence over the valve function.
If the overload condition occurs during valve operation, the electric circuit will open to protect the equipment.
In case of failure of the overload U
protection operation to disconnect the load, the equipment may suffer potential damage.
Motor thermal overloads for Class 1E MOVs are selected two sizes larger than the normally selected thermal overload.
l (This approximates 140% of motor full load amperage.)
Selection of overloads in this range permits Class IE MOVs to operate for extended periods of time at moderate overloads; tripping occurs just prior to motor damage.
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APPLICABLE The bypassing of the MOV thermal overload protection V
SAFETY ANALYSES continuously or during accident conditions ensures that the thermal overload protection will not prevent safety related valves from performing their function. The Surveillance 4
Requirements for demonstrating the bypassing of the thermal overload protection continuously and during accident conditions are in accordance with Regulatory Guide 1.106
" Thermal Overload Protection for Electric Motors on Motor l
Operated Valves," Revision 1, March 1977.
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REQUIREMENTS The thermal overload protection for each M0V shown in i
FOR OPERABILITY Table 1.8.11-1 shall be OPERABLE.
APPLICABILITY Whenever the MOV is required to be OPERABLE.
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!O WNP-2 B 1.8-23 Revision 7
MOV Thermal Overload Protection B 1.8.11 BASES (continued)
COMPENSATORY A.1 and B.1 MEASURES With one or more MOV thermal overloads inoperable, continuously bypass the inoperable MOV thermal overload within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
If the thermal overload is not bypassed, the MOV must be declared inoperable and any applicable Required Compensatory Measures (because the MOV is incamrable) must be taken.
SURVEILLANCE SR 1.8.11.1 REQUIREMENTS Every 18 months perform a CHANNEL CALIBRATION of a representative sample of 2: 25% on a rotating basis, on the M0V thermal overloads.
REFERENCES 1.
FSAR, Section 8.3.1.1.9.
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WNP-2 B 1.8-24 Revision 15
Refueling Platform B 1.9.1 BASES (continued)
REQUIREMENTS Any functions of the refueling platform being used to move FOR OPERABILITY fuel assemblies or control rods shall be OPERABLE.
APPLICABILITY The refueling platform and associated interlocks are required to be OPERABLE for the hoist being used during movement of fuel assemblies or control rods within the reactor pressure vessel.
Equipment that is not being used is not required to be OPERABLE.
t,0MPENSATORY With the refueling platform and associated interlocks MEASURES
' inoperable, immediately suspend all movement of fuel assemblies and control rods within the reactor pressure vessel with the refueling platform. (NOTE: This measure does RQI prevent placing the load in a safe location prior to suspension).
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SURVEILLANCE SR 1.9.1.1 throuah SR 1.9.1.7 REQUIREMENTS Verifying that the refueling platform interlocks function once within 7 days of using the equipment ensures that the equipment will be protected against improper operation.
This Frequency is based on engineering judgement and equipment history.
REFERENCES 1.
Letter G02-93-191, dated July 29, 1993, " Refueling Platform Load Limits".
i 2.
FSAR, Section 9.1.4.
l 3.
FSAR, Section 9.1.4.2.10.2.1.4.
l 4.
FSAR, Section 15.4.1.1.
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WNP-2 B 1.9-3 Revision 15 l
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Crane Travel B 1.9.2 B 1.9 REFUELING OPERATIONS B 1.9.2 Crane Travel BASES BACKGROUND To prevent transporting loads over the spent fuel storage pool that are greater than the allowed load limit, the crane travel is restricted by interlocks (Ref 1). These interlocks are established so that the crane will stop if an attempt is made to transport material over the spent fuel storage pool.
The interlocks are bypassed only when it is necessary to operate the crane in the fuel pool area in conjunction with activities associated with fuel handling and storage.
During the occasions when the interlocks are bypassed, administrative controls are used to prevent the crane from carrying loads that are not necessary for fuel handling or storage, and which are in excess of the rack design drop load (one fuel assembly at four feet above the top of the fuel rack) (Ref 2).
Load limits are applied to the loads carried over the spent fuel.
Loads over a given weight are limited as to the height that they can be carried over the spent fuel storage pool.
APPLICABLE The restriction on movement of loads in excess of the SAFETY ANALYSES nominal weight of a fuel assembly over other fuel assemblies in the storage pool ensures.that in the event this load is dropped: (1) the activity release will be limited to that assumed in the fuel handling accident (Ref. 3); and (2) any possible distortion of fuel in the storage racks will not result in a critical array. This assumption is consistent with the activity release assumed in the safety analyses.
The most severe fuel handling accident from a radiological viewpoint is dropping a fuel assembly onto the top of the core. This accident analysis bounds the accident for a dropped fuel assembly over the spent fuel pool (Ref 3).
The ability to withstand a dropped fuel bundle is included in the design of the spent fuel racks (Ref 4).
REQUIREMENTS The load and height of a load over the spent fuel pool shall FOR OPERABILITY be within the limits of the graph (Figure 1.9.2-1).
(continued)
O WNP-2 B 1.9-4 Revision 7
trana Travel B 1.9.2 BASES (continued)
APPLICABILITY The load and load height limits are required whenever there is irradiated fuel in the spent fuel pool.
COMPENSATORY A note has been added to state that the requirements of MEASURES RF01.0.3 are not applicable.
When the load and height limitations are not met, immediately initiate actions to move the crane load from over the spent fuel storage pool racks.
SURVEILLANCE SR 1.9.2.1 REQUIREMENTS ihe system functional test involves demonstrating that the crane interlocks and physical stops that prevent crane travel with loads in excess of 1500 pounds over fuel assemblies in the pent fuel pool rack are OPERABLE.
This Surveillance Requirement is only required when the crane is in use. Verifying crane travel limits function every 7 days when the crane is in use ensures that the equipment will be protected against improper operation.
O REFERENCES 1.
FSAR, Section 9.1.2.3.3.
2.
FSAR, Section 9.1.2.3.2.
3.
FSAR, 15.7.4.
4.
FSAR 9.1.2.1.1.1.
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l WNP-2 B 1.9-5 Revision 15 l
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