ML20154Q451
| ML20154Q451 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 10/16/1998 |
| From: | ENTERGY OPERATIONS, INC. |
| To: | |
| Shared Package | |
| ML20154Q446 | List: |
| References | |
| NUDOCS 9810230241 | |
| Download: ML20154Q451 (51) | |
Text
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ATTACHMENT TO GNRO-98/00078 Grand Gulf Technical Specification Bases Revised Pages for Period April 10, 1997 Through October 15, 1998 9810230241 981016 PDR ADOCK 05000416 P
pg comuum
4 Reactor Core SLs B 2.1.1 BASES l
APPLICABLE 2.1.1.1 Fuel Claddina Integrity (continued)
SAFETY ANALYSES ATLAS test data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly critical power at this flow is approximately 3.35 MWt. With the design peaking factors, this corresponds to a 1
THERMAL POWER > 50% RTP.
Thus a THERMAL POWER limit of 25% RTP for reactor pressure < 785 psig is conservative.
Because of the design thermal hydraulic compatibility of the reload fuel designs with the cycle 1 fuel, this justification and the associated low pressure and low flow limits remain applicable for i
future cycles of cores containing these fuel designs.
2.1.1.2 MCPR The MCPR SL ensures sufficient conservatism in the operating-MCPR limit that, in the event of an A00 from the limiting condition of operation,' at least 99.9% of the fuel rods in the core would be expected to avoid boiling transition. The 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 correlation.
References 6 and 7 describe the methodology used in determining the MCPR SL.
The calculated MCPR safety limit is reported to the customary three significant digits (i.e., X.XX); the MCPR operating limit is developed based on the calculated MCPR safety limit to ensure that at least 99.9% of the fuel rods in the core are expected to avoid boiling transition.
The fuel vendor's 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 being estimated. As long as the core pressure and flow are within the range of validity of the correlations, the assumed reactor conditions used in defining the SL introduce conservatism into the limit because bounding high radial power factors and oounding flat
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local peaking distributions are used to estimate the number of rods in boiling trarsition. These conservatisms and the (continued)
GRAND GULF B 2.0-3 LDC 98033
4 Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.2 MCPR (continued) 1 SAFETY ANALYSES inherent accuracy of the fuel vendor's correlation provide a reasonable degree of assurance that 99.9% of the rods in the core would not be susceptible to transition boiling during sustained operation at the MCPR SL.
If boiling transition were to occur, there is reason to believe that the integrity i
'4 (continued)
' GRAND GULF B 2.0-3a LDC 98033
Y j
SR Applicability B 3.0 l
BASES L
SR 3.0.2 The 25% extension does not significantly degrade the (continued) reliability that results from performing the Surveillance at i
its specified Frequency.
This is based on the recognition l
that the most probable result of any particular Surveillance being performed is the verification of conformance with the l
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.
For example, the l
requirements of regulations take precedence over the TS.
i The TS cannot in and of themselves extend a test interval l
specified in the regulations.
Therefore, there is 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 j
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 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 i
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 Completion 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 limit of the specified Frequency, whichever is less, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with SR 3.0.2, and not at the time (continued) l GRAND GULF B 3.0-12 LDC 98024
4 s
l MCPR B 3.2.2 4
. BASES (continued) 4 1
SURVEILLANCE SR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after' THERMAL POWER is 2: 25% RTP and then every
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24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter.
It is compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation.
The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER reaches 2: 25% RTP is acceptable given the 4
large inherent margin to operating limits at low power levels.
REFERENCES 1.
NUREG-0562, " Fuel Failures As A Consequence of Nucleate Boiling or Dry Out," June 1979.
2.
NEDE-24011-P-A, General Electric Standard Application j
for Reactor Fuel (GESTAR-II).
3.
UFSAR, Chapter 15, Appendix 15B.-
)
4.
UFSAR, Chapter 15, Appendix 15C.
5.
UFSAR, Chapter 15, Appendix 15D.
6.
NEDE-30130-P-A, Steady State Nuclear Methods.
7.
NED0-24154, Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors.
8.
Deleted 9.
GNRI-98/00058, Amendment 136 to the Operating License.
l GRAND GULF B 3.2-8 LDC 98033
i LHGR l%
B 3.2.3 l
BASES l
\\
APPLICABLE operating limit specified in the COLR. The analysis also SAFETY ANALYSES includes allowances for short term transient operation above (continued) the operating limit to account for A00s, plus an allowance l
for densification power spiking.
The LHGR limits are multiplied by the smaller of either the l
flow dependent LHGR factor (LHGRFAC,) or the power dependent LHGR factor (LHGRFAC,) corresponding to the existing core flow and power state to ensure adherence to the fuel mechanical design bases during the limiting transient.
LHGRFAC,'s are generated to protect the core from slow flow runout transients. A curve is provided based on the maximum credible flow runout transient for Loop Manual operation.
The result of a single failure or single operator error during operation in Loop Manual is the runout of only one loop because both recirculation loops are under independent control.
LHGRFAC,'s are generated to protect the core from plant transients other than core flow increases.
For GE fuel, the power-and flow-dependent LHGR factors are identical to the power-and flow-dependent MAPLHGR factors.
I The LHGR satisfies Criterion 2 of the NRC Policy Statement.
LCO The LHGR is a basic assumption in the fuel design analysis.
The fuel has been designed to operate at rated core power with sufficient design margin to the LHGR calculated to cause a 1% fuel cladding plastic strain. The operating limit to accomplish this objective is specified in the COLR.
APPLICABILITY The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions. At core thermal power levels < 25% RTP, the reactor is operating with a substantial margin to the LHGR limits and, therefore, the Specification is only required when the reactor is operating at 2: 25% RTP.
ACTIONS A.1 If any LHGR exceeds its required limit, an assumption regarc' an initial condition of the fuel design analysis is not..;. Therefore, prompt action should be taken to (continued)
GRAND GULF B 3.2-10 LDC 97057
s RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.15 REQUIREMENTS (continued)
This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The RPS RESPONSE TIME acceptance criteria are included in the applicable plant procedures.
As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time. Note 2 allows the channel sensors of Functions 3, 4, and 5 to be excluded from specific RPS RESPONSE TIME testing. This allowance to not perform specific response time testing of the sensors is applicable when the alternate testing requirements and restrictions of Reference 10 are performed.
As stated in Reference 10, analysis has demonstrated that other Technical Specification testing requirements (CHANNEL CALIBRATIONS, CHANNEL CHECKS, CHANNEL FUNCTIONAL TESTS, and LOGIC SYSTEM FUNCTIONAL. TESTS) and actions taken in response to NRC Bulletin 90-01 Supplement 1 are sufficient to identify failure modes or degradation in instrument response times and assure operation of the analyzed instrument loops within acceptable limits.
Reference 10 also identifies that there are no known channel sensor failure modes identified that can be detected by response time testing that cannot also be detected by other Technical Specification required surveillances. Therefore, when the requirements, including sensor types, of Reference 10 are complied with, adequate assurance of the response time of the sensors is provided. This assurance of the response time of the sensors when combined with the response time testing of the remainder of the channel ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The calibration shall be performed such that fast ramp or step change to system components during calibrations is performed to verify that the response of the transmitter to the input change is prompt. Technicians shall monitor for response time degradation during the performance of calibrations.
Technicians shall be appropriately trained to ensure they are aware of the consequences of instrument response time degradation. These items are cammitments made per Reference 11.
If the alternate testing requirements of Reference 10 are not complied with, then the entire channel will be response time tested including the sensors.
(continued)
GRAND GULF B 3.3-29 LDC 97078
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l RPS Instrumentation B 3.3.1.1 l
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BASES l
SURVEILLANCE SR 3.3.1.1.15 (continued)
REQUIREMENTS RPS RESPONSE TIME tests are conducted on an 18 month l
STAGGERED TEST BASIS.
Note 3 requires STAGGERED TEST BASIS I
Frequency to be determined based on 4 channels per trip system, in lieu of the 8 channels specified in Table 3.3.1.1-1 for the MSIV Clos'ure Function.
This Frequency is based on the logic interrelationships of the various channels required to produce an RPS scram signal.
Therefore, staggered testing results in response time i
verification of these devices every 18 months.
Tais Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious time degradation, but not channel failure, are infrequent.
REFERENCES 1.
UFSAR, Figure 7.2-1.
l 2.
UFSAR, Section 5.2.2.
3.
UFSAR, Section 6.3.3.
l 4.
UFSAR, Chapter 15.
l l
5.
UFSAR, Section 15.4.1.
i 6.
NED0-23842, " Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.
7.
UFSAR, Section 15.4.9.
l f
l l
I I
(continued)
GRAND GULF B 3.3-29a LDC 97078 l
s RCIC System Instrumentation B 3.3.5.2 BASES BACKGROUND To prevent losing suction to the pump, the suction valves (continued) are interlocked so that one suction path must be open before the other automatically closes.
The RCIC System provides makeup water to the reactor until the reactor vessel water level reaches the high water level (Level 8) trip (two-out-of-two logic), at which time the RCIC steam supply valve closes (the injection valve also closes due to the closure of the steam supply valves) to prevent overflow into the main steam lines.
The RCIC System restarts if vessel level again drops to the low level initiation point (Level 2).
APPLICABLE The function of the RCIC System es to provide makeup SAFETY ANALYSES, coolant to the reactor in resprase to transient events.
LCO, and The RCIC System is not an Engineered Safety Feature APPLICABILITY System and no credit is taken in the safety analysis for RCIC System operation.
Based on its contribution to the reduction of overall plant risk, however, the RCIC System, and therefore its instrumentation, are included as required by the NRC Policy Statement.
Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
The OPERABILITY of the RCIC System instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Tabl e 3.3.5.2-1.
Each Function must have a required number of OPERABLE channels with their setpoints within the specified Allowable Values, where appropriate. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value.
The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values are specified for each RCIC System instrumentation Function specified in the table. Nominal trip setpoints are specified in the setpoint calculations.
The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its i
Allowable Value, is acceptable.
Each Allowable Value specified accounts for instrument uncertainties appropriate to the Function. These uncertainties are described in tha setpoint methodology.
(continued) i GRAND GULF B 3.3-125 LDC 98059
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Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 3.j.
Drywell Pressure-Hiah (continued)
SAFETY ANALYSES, LCO, and The Allowable Value was selected to be the same as the ECCS APPLICABILITY Drywell Pressure-High Allowable Value (LC0 3.3.5.1), since this is indicative of a LOCA inside primary containment.
This Function isolates the' Group 9 valves.
l 3.k.
Manual Initiation The Manual Initiation push button channel introduces a signal into the RCIC System isolation logic that is redunc' ant to the automatic protective instrumentation and provides manual isolation capability.
There is no specific UFSAR safety analysis that takes credit for this Functian.
It is retained for the isolation function as required by the NRC in the plant licensing basis.
There is only one push button for RCIC manual initiation in a single trip system.
There is no Allowable Value for this Function since the channel is mechanically actuated based solely on the position of the push button.
Four channels of RCIC Manual Initiation are available and are required to be OPERABLE.
4.
Reactor Water Cleanup System Isolation 4.a.
Differential Flow-Hiah 1he high differential flow signal is provided to detect a break in the RWCU System. This will detect leaks in the RWCU System when area temperature would not provide detection (i.e., a cold leg break).
Should the reactor l
coolant continue to flow out of the break, offsite dose limits may be exceeded. Therefore, isolation of the RWCU System is initiated when high differential flow is sensed to prevent exceeding offsite doses. A time delay is provided to prevent spurious trips during most RWCU operational transients.
This Function is not assumed in any UFSAR transient or accident analysis-since bounding analyses are performed for large breaks such as MSLBs.
The high differential flow signals are initiated from two transmitters that are connected to the inlet (from the (continued)
GRAND GULF B 3.3-154 LDC 97069
Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES ACTIONS B.1 (continued)
Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic isolation capability being lost for the associated penetration flow path (s). ' The MSL isolation Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip such that both trip systems will generate a trip signal from the given Function on a valid signal. The other isolation Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two PCIVs in the associated penetration flow path can receive an isolation signal from the given Function.
For Functions 1.a, 1.b, l.d, and 1.e, this would require both trip systems to have one channel 0PERABLE or in trip.
For Function 1.c, this would require both trip systems to have one channel, associated with each MSL, OPERABLE or in trip.
For Functions 2.e and 2.f, this would require one trip system with four channels operable or in trip.
For Functions 2.a, 2.b, 2.c, 2.d, 2.g, 3.d, 4.g, 5.b, 5.c and 5.d, this'would require one trip system to have two channels, each OPERABLE or in trip.
For Functions 3.a, 3.b, 3.c, 3.e, 3.f, 3.g, 3.1, 3.j, 4.a, 4.b, 4.c, 4.e, 4.f, and I
4.h, this would require one trip system to have one channel OPERABLE or in trip.
For Functions 3.h, 4.d and 5.a, each consists of channels that monitor several different locations.
Therefore, this would require one channel per location to be OPERABLE or in trip (the channels are not required to be in the same trip system).
The Condition does not include the Manual Initiation Functions (Functions 1.f, 2.h, 3.k, 4.1 and 5.e), since they are not assumed in any accident or transient analysis.
Thus, a total loss of manual initiation capability for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (as allowed by Required Action A.1) is allowed.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities.
The Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
(continued)
GRAND GULF B 3.3-163 LDC 98059
4 m
Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.7 REQUIREMENTS (continued)
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on isolation valves in LC0 3.6.1.3 and LC0 3.6.5.3 overlaps this Surveillance to provide complete testing of the assumed safety function. The 18 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 has shown these components usually pass the Surveillance when performed at the 18 month Frequency.
SR 3.3.6.I.8 This SR ensures that the individual channel response times are less than or equal to.the maximum values assumed in the accidcnt analysis. Testing is performed only on channels where the assumed response time does not correspond to the
)
diesel generator (DG) start time.
For channels assumed to respond within the DG start time, sufficient margin exists in the 10 second start time when compared to the typical channel response time (milliseconds) so as to assure adequate response without a specific measurement test.
Testing of the closure times of the MSIVs is not included in this Surveillance since the closure time of the MSIVs is tested by SR 3.6.1.3.6.
ISOLATION SYSTEM RESPONSE TIME acceptance criteria for this instrumentation is included in the applicable plant procedures.
As Noted, the channel sensor may be excluded from response time testing.
This allowance to not perform specific response time testing of the sensors is applicable when the alternate testing requirements and restrictions of Reference 7 are performed. As stated in Reference 7, analysis has demonstrated that other Technical Specification testing requirements (CHANNEL CALIBRATIONS, CHANNEL CHECKS, CHANNEL FUNCTIONAL TESTS, and LOGIC SYSTEM FUNCTIONAL TESTS) and actions taken in response to NRC Bulletin 90-01 Supplement 1 are sufficient to identify failure modes or degradation in (continued)
GRAND GULF B 3.3-170 LDC 97078
l Primary Containment and Drywell Isolation Instrumentation l'
B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.8 (continued)
REQUIREMENTS instrument response times and assure operation of the analyzed instrument loops within acceptable limits.
Reference 7 also identifies that there are no known channel i
sensor failure modes identified that can be detected by response time testing that cannot also be detected by other Technical Specification required surveillances. Therefore, when the requirements, including sensor types, of Reference 7 are complied with, adequate assurance of the response time of the sensors is provided. This assurance of the response time of the sensors when combined with the response time testing of the remainder of the channel ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.
The calibration shall be performed such that fast ramp or step change to system components during calibrations is performed to verify that the response of the transmitter to the input change is prompt.
Technicians shall monitor for response time degradation during the performance of calibrations.
Technicians shall be appropriately trained to ensure they are aware of the consequences of instrument response time degradation.
These items are commitments made per Reference 8.
If the alternate testing requirements of Reference 7 are not complied with then the entire channel will be response time tested including the sensors.
ISOLATION SYSTEM RESPONSE TIME tests for this instrumentation are conducted on an 18 month STAGGERED TEST BASIS.
This test Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience that shows that random failures of
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instrumentation components causing serious response time degradation, but not channel failure, are infrequent.
REFERENCES 1.
UFSAR, Chapter 6.
2.
UFSAR, Chapter 15.
I (continued)
GRAND GULF B 3.3-170a LDC 97078
_m
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Primary Containment and Drywell isolation Instrumentation B 3.3.6.1 l
l BASES i
REFERENCES 3.
NE00-31466, " Technical Specification Screening (continued)
Criteria Application and Risk Assessment,"
l November 1987.
4.
UFSAR, Section 9.3.5.
5.
NEDC-31677-P-A, " Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"
June 1989.
l 6.
NEDC-30851-P-A, Supplement 2, " Technical 3
l Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
7.
NED0-32291-A, " System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995.
8.
GNRI-97/00181, Amendment 133 to the Operating License.
l l
i 1
I GRAND GULF B 3.3-171 LDC 97078
.. - - ~ - -. -.
LOP Instrumentation l
B 3.3.8.1 o
i BASES APPLICABLE The specific Applicable Safety Analyses, LCO, and SAFETY ANALYSES, Applicability discussions are listed below on a Function by LCO, and Function basis.
APPLICABILITY l
4.16 kV Emergency Bus Undervoltage i
1.a. 1.b. 2.a 2.b.
4.16 kV Emeraency Bus Undervoltaae (Loss of Voltage)
Loss of voltage on a 4.16 kV emergency bus indicates that i
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, i
the power supply to the bus is transferred from offsite power to DG power when the voltage on the bus drops below the Loss of Voltage Function Allowable Values (loss of i
vo". age with a short time delay). This ensures that ad< uate power will be available to the required equipment.
Th Bus Undervoltage Allowable Values are low enough to t
tent inadvertent power supply transfer, but high enough to ensure power is available to the required equipment. The Time Delay Allowable Value for 1.b is long enough to provide 1 l
time for the offsite power supply to recover to normal voltages, but short enough to ensure that pcwer is available t
to the required equipment.
The Time Delay Allowable Value for 2.b is to permit residual voltage of the HPCS pump motor to decay below 25% of rated voltage before sourcing power from the DG, should the pump have been powered via the offsite source and the DG were operating unsynchronized with the offsite source at the time of loss of bus voltage (Reference 5 and 6).
l l
Four channels of 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) Function per associated emergency bus are only required to be OPERABLE when the associated DG is required t
to be OPERABLE.
These four channels are arranged in a one out of two taken twice logic with a timer in each of the one out of two portions of the logic to ensure that no single instrument failure can preclude the DG function.
j (Four channels input to each of the three DGs.) Refer to LC0 3.8.1, "AC Sources-0perating," and LC0 3.8.2, "AC Sources-Shutdown," for Applicability Bases for the DGs.
(continued)
GRAND GULF B 3.3-227 LDC 98003
.. ~. _ _
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LOP Instrumentation B 3.3.8.1 BASES APPLICABLE 1.c 1.d. 2.c, 2.d, 2.e.
4.16 kV Emeraency Bus Undervoltage SAFETY ANALYSES, (Dearaded Voltage)
LCO, and APPLICABILITY A reduced voltage condition on a 4.16 kV emergency bus (continued).
indicates that while offsite power may not be completely 4 -
lost to the respective emergency bus, power may be W
M
)
(continued)
GRAND GULF-B 3.3-227a LDC 98003 1
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LOP Instrumentation B 3.3.8.I o.
BASES SURVEILLANCE SR 3.3.8.1.1 (continued)
REQUIREMENTS The Frequency of 31 days is based on plant operating experience with regard to channel 0PERABILITY and drift that demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare.
SR 3.3.8.1.2 A 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 drifts between successive calibrations consistent with the plant specific setpoint methodology.
The Frequency is based on the assumption of the magnitude of equipment drift in the setpoint analysis.
~
SR 3.3.8.1.3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed in LC0 3.8.1 and LC0 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety functions.
The 18 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 has shown these components usually pass the Surveillance when performed at the 18 month Frequency.
REFERENCES 1.
UFSAR, Section 8.3.1.
2.
UFSAR, Section 5.2.
3.
UFSAR, Section 6.3.
l 4.
UFSAR, Chapter 15.
(continued)
I GRAND GULF B 3.3-231 LDC 98003
~
LOP Instrumentation B 3.3.8.1 j
BASES REFERENCES 5.
AECM-83/0356, " Transmittal of Proposed Changes to (continued)
Grand Gulf Technical Specifications."
6.
MAEC-83/0248, " Amendment 8 to the Facility Operating License No. NPF-13-Grand Gulf Nuclear Station, Unit 1."
i e
1 i
GRAND GULF B 3.3-231a LDC 98003
s RCS P/T Limits a
B 3.4.11 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.11 RCS Pressure and Temperature (P/T) Limits BASES BACKGROUND All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips. This'LC0 limits the pressure and temperature changes during RCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation.
Figure 3.4.11-1 contains P/T limit curves for normal operation (including heatup and cooldown), and inservice leak and hydrostatic testing.
Each P/T limit curve defines an acceptable region for normal operation. The usual use of the curves is operational guidance during heatup or cooldown maneuvering, when pressure and temperature indications are monitored and compared to the applicable curve to determine that operation is within the allowable region (i.e., to the right. of the applicable curve).
The LC0 establishes operating limits that provide a margin to brittle failure of the reactor vessel and piping of the reactor coolant pressure boundary (RCPB).
The vessel is the component most subject to brittle failure.
Therefore, the LCO limits apply mainly to the vessel.
10 CFR 50, Appendix G (Ref. 1), requires the establishment of P/T limits for materi'al fracture toughness requirements of the RCPB materials.
Reference 1 requires an adequate margin l
to brittle failure during normal operation, anticipated operational occurrences, and system hydrostatic tests.
It mandates the use of the American Society of Mechanical Engineers (ASME) Code,Section III, Appendix G (Ref. 2).
The actual shift in the RTNDT of the vessel material will be established periodically by removing and evaluating the irradiated reactor vessel material specimens, in accordance with ASTM E 185 (Ref. 3),10 CFR 50, Appendix H (Ref. 4) and the UFSAR Reactor Materials Surveillance Program (Ref. 9, 10, 11).
The operating P/T limit curves will be adjusted, as (continued)
GRAND GULF B 3.4-52 LDC 97070
_= -
RCS P/T Limits B 3.4.11 BASES BACKGROUND necessary, based on the evaluation findings and the (continued) recommendations of Reference 5.
The P/T limit curves are composite curves established by superimposing limits derived from stress analyses of those portions of the reactor vessel and head that are the most restrictive.
At any specific pressure, temperature, and temperature rate of change, one location within the reactor vessel will dictate the most restrictive limit. Across the span of the P/T limit curves, different locations are more restrictive, and, thus, the curves are composites of the most restrictive regions.
I The criticality limits include the Reference 1 requirement that they be at least 40af above the core not critical limit I curve and not lower than the minimum permissible temperature for the inservice leak and hydrostatic testing.
The consequence of violating the LC0 limits is that the RCS has been operated under conditions that can result in brittle failure of the RCPB, possibly leading to a nonisolable leak or loss of coolant accident.
In the event these limits are exceeded, an evaluation must be performed to determine the effect on the structural integrity of the RCPB components. The ASME Code,Section XI, Appendix E (Ref. 6), provides a recommended methodology for evaluating an operating event that causes an excursion outside the limits.
APPLICABLE The P/T limits are not derived from Design Basis Accident SAFETY ANALYSES (DBA) analyses. They are prescribed during normal operation to avoid encountering pressure, temperature, and temperature rate of change conditions that might cause undetected flaws to propagate and cause nonductile failure of the RCPB, a condition that is unanalyzed.
Reference 7 establishes the methodology for determining the P/T limits. Since the P/T limits are not derived from any DBA, there are no acceptance limits related to the P/T limits.
Rather, the P/T limits (continued)
GRAND GULF B 3.4-53 LDC 97070
-4 RCS P/T Limits B 3.4.11 BASES APPu CABLE are acceptance limits themselves since they preclude SAFE W ANALYSES operation in an unanalyzed condition.
RCS P/T limits satisfy Criterion 2 of the NRC Policy Statement.
LCO The elements of this LC0 are:
a.
RCS pressure and temperature are within the limits specified in Figure 3.4.11-1 and heatup or cooldown rate is s 100af in any one hour period during RCS heatup, cooldown, and inservice leak and hydrostatic testing.
b.
The temperature difference between the reactor vessel bottom head coolant and the reactor pressure vessel (RPV) coolant is s 100aF during recirculation pump startup and during increases in THERMAL POWER or loop flow while operating at low THERMAL POWER or loop fl ow.
c.
The temperature difference between the Nactor coolant in the respective recirculation loop and in the reactor vessel is s 50aF during pump startup and during increases in THERMAL POWER or loop flow while operating at low THERMAL POWER or loop flow.
d.
RCS pressure and temperature are within the criticality limits specified in the applicable Figure 3.4.11-1 based on the current Effective Fuel Power Year (EFPY) prior,to achieving criticality.
The reactor vessel flange and the head flange e.
temperatures is 2: 70aF when tensioning the reactor vessel head bolting studs.
These limits define allowable operating regions and permit a large number of operating cycles while also providing a wide margin to nonductile failure.
The rate of change of temperature limits control the thermal gradient through the vessel wall and are used as inputs for calculating the heatup, cooldown, and inservice leak and (continued)
GRAND GULF B 3.4-54 LDC 97070
o RCS P/T Limits B 3.4.11 4
BASES SURVEILLANCE SR 3.4.11.8 and SR 3.4.11.9 (continued)
REQUIREMENTS Plant specific test data has determined that the bottom head is not subje'ct to temperature stratification with natural circulation at power levels as low as 36% of RTP with any single loop flow rate when the recirculation pump is on high speed operation. Therefore, SR 3.4.11.8 and SR 3.4.11.9 have been modified by a Note that requires the Surveillance to be met only when THERMAL POWER or loop flow is being increased when the above conditions are not met.
The Note for SR 3.4.11.9 further limits the requirement for this Surveillance to exclude comparison of the idle loop temperature if the idle loop is isolated from the RPV since the water in the loop cannot be introduced into the remainder of the reactor coolant system.
j REFERENCES 1.
2.
ASME, Boiler and Pressure Vessel Code,Section III, Appendix G.
3.
ASTM E 185-82, " Standard Practice for Conducting Surveillance Tests For Light-Water Cooled Nuclear Power Reactor Vessels," July 1982.
4.
5.
Regulatory Guide 1.99, Revision 2, May 1988.
6.
ASME, Boiler and Pressure Vessel Code,Section XI, Appendix E.
7.
NED0-21778-A, " Transient Pressure Rises Affecting Fracture Toughness Requirements For BWRs,"
December 1978.
1 8.
UFSAR, Section 15.4.4.
9.
GNRI-96/00176, Amendment 127 Safety Evaluation 10.
GNRI-96/00186, Amendment 127 Safety Evaluation, Correction 11.
UFSAR, Section 5.3.1.6.1 l
12.
GNRI-97/00139, Amendment 132 to the Operating License.
I GRAND GULF B 3.4-60 LDC 97070
ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.7 (continued)
REQUIREMENTS alternately tested.
The Frequency of the required relief-mode actuator testing was developed based on the tests required by the ASME Boiler and Pressure Vessel Code,Section XI as implemented by the Inservice Testing Program of Specification 5.5.6.
The testing Frequency required by the Inservice Testing Program is based on operating i
experience and valve performance.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
SR 3.5.1.8 This SR ensures that the HPCS System response time is less than or equal to the maximum value assumed in the accident j
analysis.
Specific testing of the ECCS actuation i
instrumentation inputs into the HPCS System ECCS SYSTEM RESPONSE TIME is not required by this SR. Specific response time testing of this instrumentation is not required since these actuation channels are only assumed to respond within the diesel generator start time; therefore, sufficient margin exists in the diesel generator 10 second start time when compared to the typical channel response time (milliseconds) so as to assure adequate response without a I
specific measurement test (Ref. 16). The diesel generator starting and any sequence loading delays along with the Reactor Vessel Water Level - Low Low, Level 2 confirmation delay permissive must be added to the HPCS System equipment response times to obtain the HPCS System ECCS SYSTEM RESPONSE TIME.
The a'cceptance criterion for the HPCS System ECCS SYSTEM RESPONSE TIME is s 27 seconds.
(continued)
GRAND GULF B 3.5-13a LDC 97078
ECCS--Operating B 3.5.1 BASES SURVEILLANCE SR' 3.5.1.8 (continued)
REQUIREMENTS HPCS System ECC; SYSTEM RESPONSE TIME tests are conducted 1
'every 18 months. 'This Frequency is consistent with the typical industry refueling cycle and is based on industry l
operating experience.
l REFERENCES 1.
UFSAR, Section 6.3.2.2.3.
2.
UFSAR, Section 6.3.2.2.4.
l 3.
UFSAR, Section 6.3.2.2.1.
i 4.
UFSAR, Section 6.3.2.2.2.
5.
UFSAR, Section 15.6.6.
6.
UFSAR, Section 15.6.4.
7.
UFSAR, Section 15.6.5.
-8.
I' 9.
UFSAR, Section 6.3.3.
10.
11.
UFSAR, Section'6.3.3.3.
' 12. Memorandum from R.L. Baer (NRC) to V. Stello, Jr.
L (NRC), " Recommended Interim Revisions to LC0's for ECCS Components," December 1, 1975.
- 13. UFSAR, Section 6.3.3.7.8.
- 14. UFSAR, Section 7.3.1.1.1.4.2.
- 15. GNRI-96/00229, Amendment 130 to the Operating License.
I 16.
NED0-32291-A, " System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995.
17.
GNRI-97/00181, Amendment 133 to the Operating License i
0 GRAND GULF B 3.5-14 LDC 97078
ECCS-Shutdown B 3.5.2 BASES SURVEILLANCE SR 3.5.2.4 (continued)
REQUIREMENTS initiation signal is allowed to be in a nonaccident position provided the valve will autcmatically reposition in the proper stroke time. This SR does not require any testing cr valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency is appropriate because the valves are operated under procedural control and the probability of their being mispositioned during this time period is low.
In MODES 4 and 5, the RHR System may operate in the shutdown cooling mode, or be aligned to allow alternate means to remove decay heat and sensible heat from the reactor.
Therefore, RHR valves that are required for LPCI subsystem operation may be aligned for decay heat removal. This SR is modified by a Note that allows one LPCI subsystem of the RHR System to be considered OPERABLE for the ECCS function if all the required valves in the LPCI flow path can be manually realigned (remote or local) to allow injection into the RPV and the system is not otherwise inoperable. This will ensure adequate core cooling if an inaavertent vessel draindown should occur.
l (continued) l GRAND GULF B 3.5-19 LDC 97078
~. -... -. _
ECCS-Shutdown 4
B 3.5.2 3
j BASES (continued) i i
4 REFERENCES 1.
UFSAR, Section'6.3.3.4.
2.
GNRI-97/00181, Amendment 133 to the Operating License.
l
(
a d
4 GRAND GULF' B 3.5-20 LDC 97078
Primary Containment B 3.6.1.1 BASES (continued)
SURVEILLANCE SR 3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of 10 CFR 50, Appendix J (Ref. 3), as modified by approved exemptions.
Failure to meet air lock leakage testing (SR 3.6.1.2.1 and SR 3.6.1.2.4), resilient seal primary containment purge valve leakage testing (SR 3.6.1.3.5), main steam isolation valve leakage (SR 3.6.1.3.8), or hydrostatically tested valve leakage (SR 3.6.1.3.9) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A, B, and C acceptance criteria of 10 CFR 50, Appendix J, as modified by approved exemptions (Ref. 3).
As left leakage prior to the first startup after performing a required 10 CFR 50, Appendix J, leakage test is required to be < 0.6 La for combined Type B and C le:tuage, and < 0.75 La for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of s 1.0 La. At $ 1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis.
l REFERENCES 1.
UFSAR, Section 6.2.
2.
UFSAR, Section 15.6.5.
3.
l 4.
UFSAR, Section 6.2.6.
t 5.
GNRI-95/00087, Exemption From the Requirements of 10 l
CFR 50, Appendix J,Section III.D 6.
GNRI-98/00028, Amendment 135 to the Operating License.
GRAND GULF B 3.6-4 LDC 98024
Primary Containment Air Locks B 3.6.1.2 BASES l
ACTIONS D.1 and 0.2 (continued) 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 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 3.6.1.2.1 PEQUIREMENTS Maintaining primary containment air locks OPERABLE requires compliance with the leakage rate test requirements of 10 CFR 50, Appendix J (Ref. 2), as modified by approved exemptions. This SR reflects the leakage rate testing requirements with regard to air lock leakage (Type B leakage tests). The acceptance criteria were established during initial air lock and primary containment OPERABILITY testing. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary containment leakage rate.
l The SR has been modified by two Notes. Note 1 states that an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.
This is considered reasonable since either air lock door is capable of providing a fission product barrier in the event of a DBA. Note 2 has been added to this SR, requiring the results to be evaluated against the acceptance criteria of l
This ensures that air lock leakage is properly accounted for in determinin'g the overall primary containment leakage rate.
Since the overall primary containment leakage rate is only applicable in MODES 1, 2, and 3 operation, the Note 2 requirement is imposed only during these MODES.
SR 3.6.1.2.2 The seal air flask pressure is verified to be at 2: 90 psig every 7 days to ensure that the seal system remains viable.
It must be checked because it could bleed down during or (continued)
GRAND GULF B 3.6-11 LDC 98024
PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.5 REQUIREMENTS (continued)
For primary containment purge valves with resilient seals, additional leakage rate testing beyond the test requirements of 10 CFR 50, Appendix J (Ref. 3), is required to ensure OPERABILITY. Operating experience has demonstrated that this type of seal has the potential to degrade in a shorter time period than do other seal types.
Based on this observation, and the importance of maintaining this penetration leak tight (due to the direct path between primary containment and the environment), a Frequency of 36 i
months, with consideration given to operational experience and safety significance. Additionally, this SR must be performed for all purge valves within 92 days following any purge valve failing to meet it's acceptance criteria.
This ensures that any common mode seal degradation is identified.
The Frequency for this SR is modified by a note that l
indicates that all valves do not have to be retested due to the failure of another valve, provided they have been tested within 92 days prior to any valve failing to meet it's acceptance criteria.
The SR is modified by a Note stating that the primary containment purge valves are only required to meet leakage rate testing requirements in MODES 1, 2, and 3.
If a LOCA inside primary containment occurs in these MODES, purge valve leakage must be minimized to ensure offsite radiological release is within limits. At other times when the purge valves are required to be capable of closing (e.g., during handling of irradiated fuel), pressurization concerns are not present and the purge valves are not required to meet any specific leakage criteria.
SR 3.6.1.3.6 Verifying that the full closure isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY. The full closure isolation time test ensures i
that the MSIV will isolate in a time period that does not (continued)
GRAND GULF B 3.6-24 LDC 98024
s PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.6 (continued) l REQUIREMENTS exceed the times assumed in the DBA analyses. The 3 second time limit is measured from the start of valve motion to complete valve closure. The 5 second time limit is measured from initiation of the actuating signal to complete valve closure.
The Frequency of this SR is in accordance with the Inservice Testing Program.
Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a DBA.
This SR ensures that (continued)
GRAND GULF B 3.6-24a LDC 97094
PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.7 (continued)
REQUIREMENTS each automatic PCIV will actuate to its isolation position on a primary containment isolation signal.
The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.1.7 overlaps this SR to provide complete testing of the safety function.
The 18 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 has shown that these components usually pass this Surveillance when performed at the 18 month Frequency.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
SR 3.6.1.3.8 The analyses in Reference 2 is based on ieakage that is less than the specified leakage rate.
Leakage through all four steam lines must be s 100 scfh when tested at Pt (11.5 psig). The MSIV leakage rate must be verified to be in accordance with the leakage test requirements of Reference 3, as modified by approved exemptions. A Note is added to this SR which states that these valves are only required to meet this leakage limit in MODES 1, 2 and 3.
In the other conditions, the Reactor Coolant System is not pressurized and specific primary containment leakaoa limits are not required.
I SR 3.6.1.3.9 Surveillance of hydro ~ tatically tested lines provides s
assurance that the calculation assumptions of Reference 2 is met.
This SR is modified by a Note that states these valves are only required to meet the combined leakage rate in MODES 1, 2, and 3 since this is when the Reactor Coolant System is (continued)
GRAND GULF B 3.6-25 LDC 98024
Suppression Pool Water Level B 3.6.2.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.2 Suppression Pool Water Level BASES BACKGROUND The suppression pool is a concentric open container of water with a stainless steel liner, which is located at the bottom of the primary containment.
The suppression pool is designed to absorb the decay heat and sensible heat released during a reactor blowdown from safety / relief valve (S/RV) discharges or from a loss of coolant accident (LOCA).
The suppression pool water is also assumed to scrub the iodine from the steam in the design bases LOCA dose analysis, thereby mitigating the affects of the accident. The suppression pool must also condense steam from the Reactor Core Isolation Cooling (RCIC) System turbine exhaust and provides the main emergency water supply source for the reactorvegsel. The suppression pool volumr ranges between 135,291 ft at the low water level limit of 18 ft 4-1/12 3
inches and 138,701 ft at the high water level limit of 18 ft 9-3/4 inches.
If the suppression pool water level is too low, an insufficient amount of water would be available to adequately condense the steam from the S/RV quenchers, main vents, or RCIC turbine exhaust lines.
Low suppression pool water level could also result in an inadequate emergency makeup water source to the Emergency Core Cooling System.
The lower volume would also absorb less steam energy before heating up excessively. Therefore, a minimum suppression pool water level is specified.
If the suppression pool water level is too high, it could result in excessive clearing loads from S/RV discharges and excessive pool swell loads resulting from a Design Basis Accident (DBA) LOCA. An inadvertent upper pool dump could also overflow the weir wall into the drywell. Therefore, a maximum pool water level is specified.
This LC0 specifies an acceptable range to prevent the suppression pool water level from being either too high or too low.
In response to NRC Bulletin 96-03, a design modification i
(Ref. 2) installed a new ECCS/RCIC suction strainer, which rests on the floor of the suppression pool, to replace one of the conical basket strainers on each of the ECCS and itIC system suction strainers.
The ECCS/RCIC suction strainer (continued)
GRAND GF'.F B 3.6-53 LDC 97074 m-
Suppression Pool Water Level B 3.6.2.2 BASES BACKGROUND displaces-500 ft* of suppression pool water.
Analysis has (continued) shown that the displacement of the water does not invalidate the containment LOCA response analyses discussed above.
APPLICABLE Initial suppression pool water level affects suppression SAFETY ANALYSES pool temperature response calculations, calculated drywell pressure during vent clearing for a DBA, calculated pool (continued)
GRAND GULF B 3.6-53a LDC 97074 1
t' a
Suppression Pool Water Level B 3.6.2.2 BASES ACTIONS B.1 and 8.2 (ct:itinued)
If suppression pool water level cannot be restored to within limits within the required Completion Time, 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 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 3.6.2.2.1 REQUIREMENTS Verification of the suppression pool water level is to ensure that the required limits are satisfied.
The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency of this SR was developed considering operating experience related to trending variations in suppression pool water level and water level instrument drift during the applicable MODES and to assessing the proximity to the specified LCO level limits.
Furthermore, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is considered adequate in view of other indications available in the control room, including alar;ns, to alert the operator to an abnormal suppression pool water level condition.
REFERENCES 1.
UFSAR, Section 6.2.
2.
ER 97/0089-00-00, ECCS Suction Strainer Installation.
l I
l GRAND GULF B 3.6-55 LDC 97074
-.________..._._..__._m.._
f Primary Containment and Drywell Hydrogen Igniters B 3.6.3.2 BASES (continued)
SURVEILLANCE SR 3.6.3.2.1 and SR 3.6.3.2.2 l'
REQUIREMENTS These SRs verify that there are no physical problems that j
could affect 'the igniter operation.
Since the igniters are mechanically passive, they are not subject to mechanical failure.
The only credible failures are loss of power or burnout. The verification that each required igniter is energized is performed by circuit current versus voltage measurement.
l The Frequency of 184 days has been shown to be acceptable through operating experience. because of the low failure occurrence, and provides assurance that hydrogen burn j_
capability exists between the more rigorous 18 month Surveillances. Operating experience has shown these components usually pass the Surveillance when performed at a 184 day Frequency. Additionally, these surveillances must be performed every 92 days if four or more igniters in any division are inoperable. The 92 day Frequency was chosen, recognizing that the failure occurrence is higher than normal. Thus, decreasing the Frequency from 184 days to l
92 days is a prudent measure, since only two more inoperable igniters (for a total of six) will result in an inoperable igniter division.
SR 3.6.3.2.2 is modified by a Note that indicates that the Surveillance is not required to be performed until 92 days after four or more igniters in the division are discovered to be inoperable.
I SR 3.6.3.2.3 and SR 3.6.3.2.4 These functional tests are performed every 18 months to j
verify system OPERABILITY.
The current draw to develop a surface temperature of a 1700'F is verified for ign'iters in inaccessible areas, e.g., in a high radiation area.
Additionally, the surface temperature of each accessible igniter is measured to be a 1700*F to demonstrate that a temperature sufficient for ignition is achieved. Operating i
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.
l I
(continued) i GRAND GULF B 3.6-76 LDC 97070 ew m-w e-
.w w w e+iw4=
i==
- ---%r+r Ti r=
N
Primary Containment and Drywell Hydrogen Igniters B 3.6.3.2 j
BASES (continued)
REFERENCES 1.
10 CFR 50, Appendix A, GDC 41, 3.
UFSAR, Section 6.2.5.
l I
4 l
GRAND GULF B 3.6-77 LDC 97070
AC Sources-Operating B 3.8.1 BASES ACTIONS H.1 (continued)
Condition H corresponds to a level of degraaation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function.
Therefore, no additional time is justified for continued operation.
The unit is required by LC0 3.0.3 to commence a controlled shutdown.
SURVEILLANCE The AC sources are designed to permit inspection and REQUIREMENTS testing of all important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, GDC 18 (Ref. 8).
Periodic component tests are supplemented by extensive functional tests during refueling outages under simulated accident conditions.
The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3),
l and Regulatory Guide 1.137 (Ref. 10).
Where the SRs discussed herein specify voltage and frequency tolerances, the minimum and maximum steady state output voltage of 3744 V and 4576 V respectively, are equal to i 10% of the nominal 4160 V output voltage.
The specified minimum and maximum frequencies of the DG of 58.8 Hz and 61.2 Hz, respectively, are equal to i 2% of the 60 Hz nominal frequency. The specified steady state voltago and frequency ranges are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3).
SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power.
The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source and that appropriate independence of offsite circuits is maintained.
The 7 day Frequency is adequate since breaker position is not likely to change without the operator being aware'of it and because its status is displayed in the control room.
(continued)
GRAND GULF B 3.8-14 LOC 98004
+
~_.
AC Sources-0perating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 REQUIREMENTS (continued)
This SR helps to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and i
maintain the unit in a safe shutdown condition.
To minimize the wear on moving parts that do not get lubricated when the engine is not running, this SR is modified by a Note to indicate that all DG starts for this Surveillance may be preceded by an engine prelube period and followed by a warmup period prior to loading.
For the purposes of this testing, the DGs are started from standby conditions. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations for DG 11 and DG 12.
For l
DG 13, standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor.
Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation.
i SR 3.8.1.2 requires that the DG starts from standby conditions and achieves required voltage and frequency within 10 seconds. The DG's ability to maintain the required voltage and frequency is tested by those SRs which require DG loading. The 10 second start requirement supports the assumptions in the design basis LOCA analysis (Ref. 5).
The DGs are started for this test by using one of the following si.gnals: manual, simulated loss of offsite power by itself, simulated loss of offsite power in conjunction with an ESF actuation test signal, or an ESF actuation test signal by itself.
l The 31 day Frequency for SR 3.8.1.2 is consistent with the industry guidelines for assessment of diesel generator performance (Ref. 14).
This Frequency provides adequate assurance of DG OPERABILITY, while minimizing degradation resulting from testing.
L (continued)
GRAND GULF B 3.8-15 LDC 98004 I
AC Sources-0perating B 3.8.1 BASES l
SURVEILLANCE SR 3.8.1.3 (continued)
REQUIREMENTS l
Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.9 lagging and.1.0. The 0.9 value is conservative 4
with respect to the design rating of the machine, while 1.0 is an operational limitation to ensure circulating currents are minimized.
The load band for DG 11 and 12 is provided to^ avoid routine overloading of the TDI DG.
Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
The 31 day Frequency for this Surveillance is consistent l
with the industry guidelines for assessment of diesel generator performance (Ref. 14).
Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized.
1 Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test.
Note 3 indicates that this Surveillance shall be conducted on only one DG at a time in order to avoid common cause l
failures that might result from offsite circuit or grid perturbations.
Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.
SR 3'.8.1.4 This SR provides verification that the level of fuel oil in the day tank is at or above the level at which fuel oil is automatically added.
The level is expressed as an equivalent volume in gallons, and ensures adequate fuel oil for a minimum of 30 minutes of DG operation at the maximum l
expected post LOCA load.
1 i
(continued)
I GRAND GULF B 3.8-16 LDC 98004 l
l
J AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 (continued)
REQUIREMENTS 2) tripping its associated single largest load with the DG solely supplying the bus.
If this load were to trip, it would result in the loss of the DG. As required by IEEE-308 (Ref. 13), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower.
For the Grand Gulf Nuclear Station the lower value results from the first criteria.
The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3).
I This SR has been modified by two Notes.
The reason for Note 1 is that during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems. Credit may be taken for unplanned events that satisfy this SR.
Examples of unplanned events may include:
1)
Unexpected operational events which cause the l
equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and 2)
Post maintenance testing that requires performance of th.is Surveillanc'e in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to l
maintain OPERABILITY or reliability.
In order to ensure that the DG is tested under load conditions that are as close to design basis conditions as possible, Note 2 requires that, if synchronized to offsite power, testing be performed using a power factor s 0.9.
This power factor is chosen to be representative of the actual design basis inductive loading that the DG could experience.
(continued)
GRAND GULF B 3.8-20 LDC 98004
O AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 REQUIREMENTS (continued)
This Surveillance demonstrates the DG capability to reject a full load, i.e., maximum expected accident load, without overspeed tripping or exceeding the predetermined voltage limits. The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions.
This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load.
These acceptance criteria provide DG damage protection. While the DG is not expected to experience this transient during an event and continue to be available, this response enrures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.
In order to ensure that the DG is tested under load conditions that are as close to design basis conditions as possible, testing must be performed using a power factor s 0.9.
This power factor is choser, to be representative of 1
the actual design basis inductive loading that the DG would experience.
The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and 'is intended to be I
consistent with expected fuel cycle lengths.
This SR has been modified by a Note._ The reason for the Note is that during operation with the reactor critical, performance of this SR could cause perturbation to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems.
Credit may be taken for unplanned events that satisfy this SR. Examples 'of unplanned events may include:
1)
Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the reouired performance is available; and (continued)
GRAND GULF B 3.8-21 LDC 98004
AC Sources-Operating B 3.8.1 l
l BASES l
l SURVEILLANCE SR 3.8.1.10 (continued)
REQUIREMENTS l
2)
Post maintenance testing that requires performance of l
this Surveillance in order to restore the component to i
OPERABLE, provided the maintenance was required, or I
performed in conjunction with maintenance required to l
maintain OPERABILITY dr reliability.
SR 3.8.1.11 As required by Regulatory Guide 1.9 (Ref. 3), this I
Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source.
This test verifies all actions encountered from the loss of offsite power, including shedding of the Division 1 and 2 nonessential loads and energization of the emergency buses and respective loads from the DG.
It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time.
The DG auto-start time of 10 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance should be continued ~for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.
The requirement to verify the connection and power supply of permanent and auto-connected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic.
In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation.
For instance, ECCS injection valves are not desired to be stroked open, systems are not capable of being operated at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of i
operation.
In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable.
This testing may include any series of sequential, overlapping, or total steps so that l
the entire connection and loading sequence is verified.
l l
(continued)
GRAND GULF B 3.8-22 LDC 98004
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)
REQUIREMENTS The Frequency of 18 months is consistent with the recommendatiohs of Regulatory Guide 1.9 (Ref. 3) takes into I
consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by two Notes.
The reason for Note 1 is to minimize wear and tear on the DGs during testing.
For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations for DG 11 and DG 12.
For DG 13, standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor.
Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems. Credit may De taken for unplanned events that satisfy this SR.
Examples of unplanned events may include:
1)
Unexpected operational events which cause the equipment to perform the function gecified by this Surveillance, for which adequate documentation of the required performance is available; and 2)
Post maintenance testing that reQJires performance of j
this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.
SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the' required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal) and operates for 2: 5 minutes.
The 5 minute period provides sufficient time to demonstrate (continued)
GRAND GULF B 3.8-23 LDC 98004
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 (continued) i REQUIREMENTS The SR is modified by a Note. The reason for the Note is that performing the Surveillance removes a required DG from service.
Credit may be taken for unplanned events that satisfy this SR.
Examples of unplanned events may include:
1)
Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required nerformance is available; and 2)
Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to l
maintain OPERABILITY or reliability.
SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3) requires demonstration once I
per 18 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s-22 hours of which is at a load equivalent to the continuous rating of the DG, and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of which is at a load equivalent to 110% of the continuous duty rating of the DG. An exception to the loading requirements is made for DG 11 and DG 12.
DG 11 and DG 12 are operated for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> l
at a load greater than or equal to the maximum expected post accident load.
Load carrying capability testing of the Transamerica Delaval Inc. (TDI) diesel generators (DG 11 and DG 12) has been limited to a load less than that which corresponds to 185..psig brake mean effective pressure (BMEP).
Therefore, full load testing is performed at a load 2: 5450 kW but < 5740 kW (Ref. 15). The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.
In order to ensure that the DG is tested under load conditions that are as close to design conditio.ns as possible, testing must be performed using a power factor i
(continued)
GRAND GULF B 3.8-26 LDC 98004
AC Sources-Operating B 3.8.1 BASES SUkVEILLANCE SR 3.8.1.14 (continued)
REQtlIREMENTS s 0.9.
This power factor is chosen to be representative of the actual design basis inductive loading that the DG could experience.
During the test the generator voltage and frequency is 4160 416 volts and 60 1.2 Hz within 10 seconds after the start signal and the steady state generator voltage and frequency is maintained within these limits for the duration of the test.
The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) takes into I
consideration plant conditions required to perform the Surveillance; and is intended to be consistent with expected fuel cycle lengths.
This Surveillance is modified by two Notes. Note I states that momentary transients due to changing bus loads do not invalidate this test. -The DG 11 and 12 load band is provided to avoid routine overloading of the TDI DG.
Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
Similarly, momentary power factor transients above the limit do not invalidate the test. Note 2 stipulates that credit may be taken for unplanned events that satisfy this SR.
Examples of unplanned events may include:
1)
Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and 2)
Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.
l l
t (continued) i I
GRAND GULF B 3.8-27 LDC 98004
1.
AC Sources-0perating B 3.8.1 BASES l
SURVEILLANCE SR 3.8.1.15 (continued)
REQUIREMENTS and frequency within 10 seconds.
The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA.
The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref 3).
I This SR has been modified by two Notes.
Note 1 ensures that the test is performed with the diesel sufficiently hot.
The requirement that the diesel has operated for at least I hour at full load conditions or until operating temperatures stabilized prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. The DG 11 and 12 load band is provided to avoid routine overloading of the TDI DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. Momentary transients due to changing bus loads do not invalidate this test.
Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.
SR 3.8.1.16 As required by Regulatory Guide 1.9 (Ref. 3) this i
Surveillance ensures that the manual synchronization and load transfer from the DG to each required offsite source can be made and that the DG can be returned to ready-to-load status when offsite power is restored.
It also ensures that the undervoltage logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs.
The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the output breaker is open and can receive an auto-close signal on bus undervoltage, and the load sequence logic is reset.
The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) and takes I
into consideration plant conditions required to perform the Surveillance.
l (continued)
I GRAND GULF B 3.8-28 LDC 98004 l
l r
AC Sources-Operating l
8 3.8.1
)
l BASES SURVEILLANCE SR 3.8.1.17 (continued) l REQUIREMENTS The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) takes into I consideration plant conditions required to perform the Surveillance; and is intended to be consistent with expected l
fuel cycle lengths.
This SR has been modified by a Note. The reason for the l
Note is that performing the Surveillance would remove a l
required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.
Credit may be taken for unplanned events that satisfy this SR.
Examples of unplanned events may include:
1)
Unexpected operational events which cause the equipment to perform the function specified by this j
Surveillance, for which adequate documentation of the required performance is available; and 2)
Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.
SR 3.8.1.18 i
Under accident conditions, loads are sequentially connected to the bus by the load sequencing panel. The sequencing logic controls the permissive and starting signals to motor breakers to. prevent ov'erloading of the bus power supplies due to high motor starting currents. The 10% load sequence time interval tolerance ensures that sufficient time exists for the bus power supplies to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 2 provides a summary of the automatic loading of ESF buses.
The Frequ scy of 18 months is consistent with the recommendatioi of Regulatory Guide 1.9 (Ref. 3) takes into I
consideration plant conditions required to perform the Surveillance; and is intended to be consistent with expected fuel cycle lengths.
(continued)
GRAND GULF B 3.8-30 LDC 98004 l
1 o
AC Sources-Operating a
B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 (continued)
REQUIREMENTS This SR is modified by two Notes.
The reason for Note 1 is to minimize wear and tear on the DGs during testing.
For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations for DG 11 and DG 12.
For DG 13, standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor.
Engine jacket water is heated by an immersion heater and circulates through the system by natural circulatica. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.
Credit may be taken for
)
unplanned events that satisfy this SR.
Examples of unplanned events may include:
1)
Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the l
required performance is available; and 2)
Post maintenance testing that requires performance of this Surveillance in order to restore f'1e component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.
SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.
This surveillance is performed when the unit is shut down and its 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3).
I (continued)
GRAND GULF B 3.8-32 LDC 98004 I
l o
.o AC Sources--Operating 0
B 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 (continued)
REQUIREMENTS 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 for DG 11 and DG 12.
For DG 13, standby conditions mean that the lube oil is heated by the jacket water and continuously l
circulated through a portion of the system as recommended by the vendor.
Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation.
l l
1 l
l l
l I
(continued) i t
GRAND GULF B 3.8-33 LDC 98004
i 1
l*
l#
l AC Sources-0perating B 3.8.1 t
1 l.
BASES (continued)
I REFERENCES 1.
10 CFR 50, Appendix A, GDC 17.
2.-
UFSAR, Ch, apter 8.
3.
Regulatory Guide 1.9, Revision 3.
I l
4.
UFSAR, Chapter 6, 5.
UFSAR, Chapter 15.
l 6.
7.
Generic Letter 84-15, July 2, 1984.
8.
10 CFR 50, Appendix A, GDC 18.
9.
Deleted I
10.
- 11. ANSI C84.1, 1982.
- 12. ASME, Boiler and Pressure Vessel Code,Section XI.
13.
14.
NUMARC 87-00, Revision 1, August 1991.
15.
Letter from E.G. Adensam to L.F. Dale, dated July l
1984.
- 16. GNRI-96/00151, Amendment 124 to the Operating License'.
17.
Generic Letter 94-01, May 31, 1994.
18.
GNRI-98/00016, Amendment 134 to the Operating License.
GRAND GULF B 3.8-34 LDC 98004 l
6 d
DC Sources-0perating C
l B 3.8.4 BASES i
SURVEILLANCE SR 3.8.4.8 (continued)
REQUIREMENTS The Surveillance Frequency for this test is normally l
60 months.
If the battery shows degradation, or if the l
battery has reached 85Y. of its expected life and capacity is
< 100Y. of the manufacturer's rating, the Surveillance Frequency is reduced to 12 months. However, if the battery shows no degradation but has reached 85% of its expected l
l life, the Surveillance Frequency is only ' reduced to 24 months for batteries that retain capacity 2: 100% of the l
manufacturer's rating.
Degradation is indicated when the battery capacity drops by more than 10% of rated capacity from its average on previous performance tests or is below 90% of the manufacturer's rating. These Frequencies are based on the recommendations in IEEE-450 (Ref. 8).
This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required DC electrical power subsystem fr'om service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy the Surveillance.
REFERENCES 1.
10 CFR 50, Appendix A, GDC 17.
2.
Regulatory Guide 1.6, March 10, 1971.
3.
IEEE Standard 308, 1978.
4.
UFSAR, Section 8.3.2.
5.
UFSAR, Chapter 6.
6.
UFSAR, Chapter 15.
7.
Regulatory Guide 1.93, December 1974.
8.
IEEE Standard 450, 1987.
9.
Regulatory Guide 1.32, February 1977, i
10.
Regulatory Guide 1.129, December 1974.
11.
GRAND GULF 8 3.8-59 LDC 97070 i