Text

Proposed Tech Specs,Revising TS Bases to Include Changes Since 950221 Approval of TS Bases
	ML20097C354
Person / Time
Site:	Grand Gulf
Issue date:	02/01/1996
From:	; ENTERGY OPERATIONS, INC.
To:	;
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ML20097C351	List: ML20097C349; ML20097C354;
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	NUDOCS 9602080238
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Reactor Core SLs B 2.1.1 I BASES (continued)

SAFETY LIMIT 2.2.1 VIOLATIONS If any SL is violated, the NRC Operations Center must be )

notified within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , in accordance with 10 CFR 50.72 (Ref. 3).- ,

i 2.2.2 Exceeding an SL may cause fuel damage and create a potential for radioactive releases in excess of 10 CFR 100, " Reactor i Site Criteria," limits (Ref. 4). Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . (The required actions for a violation of the reactor water level SL include manually initiating ECCS to restore water level and depressurizing i the reactor vessel, if necessary, for ECCS operation.) The !

2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time ensures that the operators take ,

prompt remedial action and also ensures that the probability of an accident occurring during this period is minimal.

2.2.3 If any SL is violated, the General Manager, Plant Operations and the Vice President, Operations GGNS shall be notified within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period provides time for plant operators and staff to take the appropriate immediate action and assess the condition of the unit before reporting to the senior management.

2.2.4 If any SL is violated, a Licensee Event Report shall be prepared and submitted within 30 days to the NRC in accordance with 10 CFR 50.73 (Ref. 5). The report will I describe the applicable circumstances preceding the '

violation, the effect of the violation upon unit components, systems, or structures, and the corrective actions taken to prevent recurrence. A copy of the report shall also be submitted to the General Manager, Plant Operations and the Vice President, Operations GGNS.

l (continued) I GRAND GULF B 2.0-5 Revision No. 1 960208023e 960201 PDR ADOCK0500g6 P

Reactor Core SLs B 2.1.1 BASES SAFETY LIMIT 2.2.5 VIOLATIONS (continued) If any SL is violated, restart of the unit shall not commence until authorized by the NRC. This requirement ensures the NRC that all necessary reviews, analyses, and actions are completed before the unit begins its restart to normal operation.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10.

2. XN-NF524(A), Revision 2, April 1989.

3. 10 CFR 50.72.

4. 10 CFR 100.

5. 10 CFR 50.73.

GRAND GULF B 2.0-6 Revision No. I

RCS Pressure SL B 2.1.2 BASES SAFETY LIMIT 2.2.2 (continued)

VIOLATIONS excess of 10 CFR 100, " Reactor Site Criteria," limits (Ref. 4). Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time ensures that the operators take prompt remedial action and also ensures that the probability of an accident occurring during this period is minimal.

2.2.3 If any SL is violated, the General Manager, Plant Operations and the Vice President, Operations GGNS shall be notified within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period provides time for plant operators and staff to take the appropriate immediate action and assess the condition of the unit before reporting to the senior management.

2.2.4 If any SL is violated, a Licensee Event Report shall be prepared and submitted within 30 days to the NRC in accordance with 10 CFR 50.73 (Ref. 8). The report will describe the applicable circumstances preceding the violation, the effect of the violation upon unit components, systems, or structures, and the corrective actions taken to prevent recurrence. A copy of the report shall also be submitted to the General Manager, Plant Operations and the Vice President, Operations GGNS.

2.2.5 If any SL is violated, restart of the unit shall not commence until authorized by the NRC. This requirement ensures the NRC that all necessary reviews, analyses, and l actions are completed before the unit begins its restart to normal operation.

l (continued)

GRAND GULF B 2.0-9 Revision No. I

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t RCS Pressure SL B 2.1.2 BASES (continued) l l

REFERENCES 1. 10 CFR 50, Appendix A, GDC 14, GDC 15, and GDC 28.

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2. ASME, Boiler and Pressure Vessel Code,Section III.

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! 3. ASME, Boiler and Pressure Vessel Code,Section XI, j Article IWA-5000.

l l 4. 10 CFR 100.

l l 5. ASME, Boiler and Pressure Vessel Code,1971 Edition, l Addenda, winter of 1972.

6. ASME, Boiler and Pressure Vessel Code,1974 Edition.

l 7. 10 CFR 50.72.

8. 10 CFR 50.73.

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i GRAND GULF B 2.0-10 Revision No. 1

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LC0 Applicability B 3.0 BASES LC0 3.0.6 exists, the appropriate Conditions and Required Actions of (continued) the LCO in which the loss of safety function exists are required to be entered.

LC0 3.0.7 There are certain special tests and operations required to be performed at various times over the life of the unit.

These special tests and operations are necessary to demonstrate select unit performance characteristics, to perform special maintenance activities, and to perform special evolutions. Special Operations LCOs in Section 3.10 allow specified TS requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed if required to comply with the requirements of these TS. Unless otherwise specified, all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect.

The Applicability of a Special Operations LC0 represents a condi't ion not necessarily in compliance with the normal requirements of the TS. Compliance with Special Operations LCOs is optional. A special operation may be performed either under the provisions of the appropriate Special Operations LC0 or under the other applicable TS requirements. If it is desired to perform the special operation under the provisions of the Special Operations LCO, the requirements of the Special Operations LC0 shall be followed. When a Special Operations LC0 requires another LC0 to be met, only the requirements of the LC0 statement are required to be met regardless of that LCO's Applicability (i.e., should the requirements of this other ,

LC0 not be met, the ACTIONS of the Special Operations LC0 l apply, not the ACTIONS of the other LCO). However, there are instances where the Special Operations LC0's ACTIONS may direct the other LCO's ACTIONS be met. The Surveillances of 1 the other LC0 are not required to be met, unless specified l in the Special Operations LCO. If conditions exist such l that the Applicability of any other LC0 is met, all the l other LCO's requirements (ACTIONS and SRs) are required to be met concurrent with the requirements of the Special Operations LCO. ,

GRAND GULF B 3.0-9 Revision No. 1 I

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SR Applicability B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs 'SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

SR 3.0.1 SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the LC0 apply, unless otherwise specified in the individual SRs. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and coraponents, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO.

Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when:

a. The systems or components are known to be inoperable, although still meeting the SRs; or

b. The requirements of the Surveillance (s) are known to be not met between required Surveillance performances.

Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the i requirements of the associated LCO are not applicable, i unless otherwise specified. The SRs associated with a l Special Operations LC0 are only applicable when the Special l Operations LC0 is used as an allowable exception to the i requirements of a Specification.

Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply.

Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status.

(contirjpg i

GRAND GULF B 3.0-10 Revision No. 1 I

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SR Applicability B 3.0 BASES SR 3.0.4 The precise requirements for performance of SRs are (continued) specified such that exceptions to SR ?.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 performance of Surveillances when the prerequisite condition (s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LC0 prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LC0 Applicability would have its Frequency specified such that it is not "due" until the specific conditions needed are met. Alternately, 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 l specified condition in the Applicability only while operating in MODE 1, 2, or 3. The requirements of SR 3.0.4 do not apply in MODES 4 and 5, or other specified conditions of the Applicability (unless in MODE 1, 2, or 3) because the ACTIONS of individual Specifications sufficiently define the remedial measure to be taken. .

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GRAND GULF B 3.0-15 Revision No. 1

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' SDM B 3.1.1 'i B 3.1' REACTIVITY CONTROL SYSTEMS.

-B 3.1.1- Shutdown Margin-(SDM) ,

l BASES l

BACKGROUND SDM requirements are specified to ensure:

a. . The reactor can be made subcritical from all operating

cor.ditions and transients and Design Basis Events;

b. The reactivity transients associated with postulated accident conditions are controllable within acceptable limits; and

_c. The reactor will be maintained sufficiently '

subcritical to preclude inadvertent' criticality in' the shutdown condition.

These requirements'are satisfied by the control rods, as

' described in GDC 26 (Ref. 1), which can compensate for the reactivity effects of the fuel and water temperature changes experienced during all operating conditions.

l APPLICABLE' The control rod drop accident (CRDA) analysis (Refs. 2 l SAFETY ANALYSES- and 3) assumes the core is subcritical with the highest- l worth control rod withdrawn. Typically, the first control rod withdrawn has a very high reactivity worth and, should the core be critical during the withdrawal of the first i control rod, the consequences of a CRDA could exceed the i fuel damage limits for a CRDA (see Bases for LCO 3.1.6, !

" Control Rod Pattern"). Also, SDM is assumed as an initial ,

condition for the control rod removal error during a i refueling accident (Ref. 4). The analysis of this reactivity ' insertion event assumes the refueling interlocks are OPERABLE when the reactor is in the refueling mode of operation. These interlocks prevent the withdrawal of more I than one control rod from the core during refueling.

(Special consideration and requirements for multiple control rod withdrawal during refueling are covered in Special l Operations LC0 3.10.6, " Multiple Control Rod Withdrawal-Refueling.") The analysis assumes this condition is acceptable since the core will be shut down ,

with the highest worth control rod withdrawn, if adequate !

SDM has been demonstrated. j l

l (continued) l l

GRAND GULF B 3.1-1 Revision No. 1 L'-

Control Rod OPERABILITY B 3.1.3 BASES SURVEILLANCE SR 3.1.3.2 and SR 3.1.3.3 (continued)

REQUIREMENTS trippability (OPERABILITY) must be made and appropriate action taken.

SR 3.1.3.4 Verifying the scram time for each control rod to notch position 13 is :s 7 seconds provides reasonable assurance that the control rod will insert when required during a DBA or transient, thereby completing its shutdown function.

This SR is performed in conjunction with the control rod scram time testing of SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4. The LOGIC SYSTEM FUNCTIONAL TEST in LC0 3.3.1.1, " Reactor Protection System (RPS) l Instrumentation," and the functional testing of SDV vent and drain valves in LC0 3.1.8, " Scram Discharge Volume (SDV)

Vent and Drain Valves," overlap this Surveillance to provide complete testing of the assumed safety function. The associated Frequencies are acceptable, considering the more frequent testing performed to demonstrate other aspects of control rod OPERABILITY and operating experience, which shows scram times do not significantly change over an operatir.g cycle.

SR 3.1.3.5 Coupling verification is performed to ensure the control rod is connected to the CRDM and will perform its intended function when necessary. The Surveillance rcquires verifying that a control rod does not go to the withdrawn overtravel position when it is fully withdrawn. The overtravel position feature provides a positive check on the coupling integrity, since only an uncoupled CRD can reach the overtravel position. In addition, during this Surveillance any indicated response of the nuclear instrumentation while withdrawing the control rod is observed as a backup to the withdrawn overtravel position indication. The verification is required to be performed anytime a control rod is withdrawn to the " full out" (continued)

GRAND GULF B 3.1-19 Revision No. 1

Control Rod OPERABILITY B 3.1.3

.1 4

f BASES

. . SURVEILLANCE SR 3.1.3.5 (continued)

REQUIREMENTS i

position (notch position 48) or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling. This includes control rods inserted one notch and then returned to the " full out" position during the performance of SR 3.1.3.2. This

, Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not ,

being moved and operating experience related to uncoupling '

events.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26, GDC 27, GDC 28, and

GDC 29.

2. UFSAR, Section 4.3.2.5.5.

3. UFSAR, Section 4.6.1.1.2.5.3. I

4. UFSAR, Section 5.2.2.2.3.

5. UFSAR, Section 15.4.1.

6. UFSAR, Section 15.4.9.

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7. NED0-21231, " Banked Position Withdrawal Sequence,"

Section 7.2, January 1977.

8. NEDE-24011-P-A, " General Electric Standard Application for Reactor Fuel GESTAR II," September 1988.

9. AECH-90/0146, Proposed Amendment to the Operating l License (PCOL-90/07, Revision 1), dated August 15, 1990.

10. MAEC-90/0285, Issuance of Amendment No. 73 to Facility Operating License No. NPF Grand Gulf Nuclear Station, Unit 1, Regarding Fuel Cycle 5 Reload (TAC No. 76992), dated November 15, 1990.

GRAND GULF B 3.1-20 Revision No. 1

Control Rod Scram Times B 3.1.4 BASES LC0 To ensure that local scram reactivity rates are maintained (continued) within acceptable limits, no " slow" control rod may occupy a location adjacent to another " slow" control rod or adjacent to a withdrawn stuck control rod.

Table 3.1.4-1 is modified by two Notes, which state control rods with scram times not within the limits of the Table are ,

considered " slow" and that control rods with scram times

> 7 seconds are considered inoperable as required by SR 3.1.3.4.

This LC0 applies only to OPERABLE control rods since inoperable control rods will be inserted and disarmed '

(LC0 3.1.3). Slow scramming control rods may be conservatively declared inoperable and not accounted for as

" slow" control rods.

APPLICABILITY In MODES I and 2, a scram is assumed to function during transients and accidents analyzed for these plant conditions. These events are assumed to occur during startup and power operation; therefore, the scram function .

of the control rods is required during these MODES. In MODES 3 and 4, the control rods are not able to be withdrawn !

since the reactor mode switch is in shutdown and a control I rod block is applied. This provides adequate requirements for control rod scram capability during these conditions. ,

Scram requirements in MODE 5 are contained in LC0 3.9.5, l

" Control Rod OPERABILITY--Refueling."

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ACTIONS A.1 When the requirements of this LC0 are not met, the rate of negative reactivity insertion during a scram may not be within the assumptions of the safety analyses. Therefore, the plant must be brought to a MODE in which the LC0 does i not apply. To achieve this status, the plant must be l brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion !

Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

1 (continued)

GRAND GULF B 3.1-23 Revision No. 1

Control Rod Scram Accumulators B 3.1.5 l

BASES

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APPLICABLE Control rod scram accumulators satisfy Criterion 3 of the l SAFETY ANALYSES NRC Policy Statement.

(continued)

LC0 The OPERABILITY of the control rod scram accumulators is )

required to ensure that adequate scram insertion capability 4 exists when needed over the entire range of reactor i pressures. The OPERABILITY of the scram accumulators is I based on maintaining adequate accumulator pressure. !

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APPLICABILITY In MODES 1 and 2, the scram function is required for mitigation of DBAs and transients and, therefore, the scram l accumulators must be OPERABLE to support the scram function. !

In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control I rod block is applied. This provides adequate requirements i for control rod scram accumulator OPERABILITY under these conditions. Requirements for scram accumulators in MODE 5 are contained in LC0 3.9.5, " Control Rod )

OPERABILITY-Refueling." l ACTIONS The ACTIONS table is modified by a Note indicating that a ,

separate Condition entry is allowed for each control rod scram accumulator. This is acceptable since the Required l Actions for each Condition provide appropriate compent,atory action for each affected control rod. Complying with the Required Actions may allow for continued operation and subsequent aff et ced control rods governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 With one control rod scram accumulator inoperable and the reactor steam dome pressure 2: 600 psig, the control rod may be declared " slow," since the control rod will still scram at the reactor operating pressure but may not satisfy the required scram times in Table 3.1.4-1. Required Action A.1 is modified by a Note, which clarifies that declaring the control rod " slow" is only applicable if the associated control scram time was within the limits of Table 3.1.4-1 during the last scram time test. Otherwise, the control rod (continued)

GRAND GULF B 3.1-28 Revision No. 1

SLC System B 3.1.7 BASES APPLICABLE that is above the pump suction shutoff level in the boron SAFETY ANALYSES solution storage tank. No credit is taken for the portion (continued) of the tank volume that cannot be injected.

The SLC System satisfies the requirements of the N1C Policy Statement because operating experience and probabilistic l risk assessment have generally shown it to be important to public health and safety.

LC0 The OPERABILITY of the SLC System provides backup capabi"

for reactivity control, independent of normal reactivi control provisions provided by the control rods. The OPERABILITY of the SLC System is based on the conditions of the borated solution in the storage tank and the availability of a flow path to the RPV, including the OPERABILITY of the pumps and valves. Two SLC subsystems are required to be OPERABLE, each containing an OPERABLE pump, an explosive valve and associated piping, valves, and instruments and controls to ensure an OPERABLE flow path.

APPLICABILITY In MODES 1 and 2, shutdown capability is required. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control I-rod block is applied. This provides adequate controls to ensure the reactor remains subcritical. In MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies. Demonstration of adequate SDM (LC0 3.1.1, " SHUTDOWN MARGIN (SDM)") ensures that the reactor will not become critical. Therefore, the SLC System is not required to be OPERABLE during these conditions, when only a single control rod can be withdrawn.

ACTIONS A.I and A.2 i

When the boron concentration is in the Limited Operation j region (between 15.2 weight percent and 28.5 weight !

percent), the SBLC System contains sufficient boron to perform its design basis functions. But the associated solution temperatures required to prevent precipitation of the boron from solution is potentially greater than the primary containment's ambient temperature. As a result, the i non safety tank heaters may be required to maintain the tank 1

(continued)

GRAND GULF B 3.1-38 Revision No. 1

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SLC System B 3.1.7 BASES SURVt'ILLANCE SR 3.1.7.7 REQUIREMENTS (continued) Demonstrating each SLC System pump develops a flow rate a 41.2 gpm at a discharge pressure 21300 psig without actuating the pump's relief valve ensures that pump performance has not degraded during the fuel cycle. This minimum pump flow rate requirement ensures that, when combined with the sodium pentaborate solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. This test confirms one point on the pump design curve, and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accordance with the Inservice Testing Program.

SR 3.1.7.8 and SR 3.1.7.9 These Surveillances ensure that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of that batch successfully fired. The pump and explosive valve tested should be alternated such that both complete flow paths are tested every 36 months, at alternating 18 month intervals.

The Surveillance may be performed in separate steps to prevent injecting boron into the RPV. An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. 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 test when performed at the 18 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

GRAND GULF B 3.1-43 Revision No. 1

SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.8 and SR 3.1.7.9 (continued)

REQUIREMENTS Demonstrating that all heat traced piping between the boron solution storage tank and the suction inlet to the injection pumps is unblocked ensures that there is a functioning flow path for injecting the sodium pentaborate solution. An acceptable method for verifying that the suction piping is unblocked is to pump from the storage tank to the test tank and then draining and flushing the piping with demineralized water. The 18 month Frequency is acceptable since there is a low probability that the subject piping will be blocked due to precipitation of the boron from solution in the heat traced piping. This is especially true in light of the daily temperature verification of this piping required by SR 3.1.7.3. However, if, in performing SR 3.1.7.3, it is determined that the temperature of this piping has fallen below the specified minimum, SR 3.1.7.9 must be performed once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the piping temperature is restored 2: 75'F after the piping temperature has been

< 75'F.

REFERENCES 1. 10 CFR 50.62.

2. UFSAR, Section 9.3.5.3.

3. GNRI-91/00153, Issuance of Amendment No. 79 to Facility Operating License No. NPF Grand Gulf Nuclear Station, Unit 1, Regarding Standby Liquid Control System Technical Specifications, dated July 30,1991.

l GRAND GULF B 3.1-44 Revision No. 1

SDV Vent and Drain Valves B 3.1.8 l

BASES APPLICABLE allow continuous drainage of the SDV during normal plant l SAFETY ANALYSES operation to ensure the SDV has sufficient capacity to l (continued) contain the reactor coolant discharge during a full core '

scram. To automatically ensure this capacity, a reactor scram (LCO 3.3.1.1, " Reactor Protection System (RPS)

Instrumentation") is initiated if the SDV water level-exceeds a specified setpoint. -The setpoint is chosen such that all control rods are inserted before the SDV has l insufficient volume to-accept a full scram.

SDV vent and drain valves satisfy Criterion 3 of the NRC Policy Statement.

l LC0 The OPERABILITY of all.SDV vent and drain valves ensures that, during a scram, the SDV vent and drain valves will close to contain reactor water discharged to the SDV piping.

Since the vent and drain lines are provided with two valves in series, the single failure of one valve in the open position will not impair the isolation function of the system. Additionally, the valves are required to be open to ensure that a path is available for the SDV piping to drain freely at other times.

APPLICABILITY In MODES I and 2, scram may be required, and therefore, the i SDV vent and drain valves must be OPERABLE. In MODES.3 !

and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block I is applied. This provides adequate controls to ensure that only a single control rod can be withdrawn. Also, during MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies. Therefore, the SDV vent and drain valves are not required to be OPERABLE in these MODES since the reactor is subcritical and only one rod may be withdrawn and subject to scram.

ACTIONS The ACTIONS table is modified by a Note indicating that a separate Condition' entry is allowed for each SDV vent and i drain line. This is acceptable, since the Required Actions j for each Condition provide appropriate compensatory actions i for each inoperable SDV line. Complying with the Required 1 Actions may allow for continued operation, and subsequent inoperable SDV lines are governed by subsequent Condition entry and application of associated Required Actions.

(continued) ,

i GRAND GULF B 3.1-46 Revision No. 1 I

LHGR B 3.2.3 BASES ACTIONS A.1 (continued) within'the design limits of the fuel rods. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is normally sufficient to restore the LHGR(s) to within its limit and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LHGR out of specification.

B.1 If the LHGR cannot be restored to within its required limit within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LC0 does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.3.1 REQUIREMENTS The LHGRs are required to be initially calculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is a: 25% RTP and then every !

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. They are compared with 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and l recognition of the slowness of changes in power distribution under normal conditions. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER a 25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels.

REFERENCES 1. UFSAR, Chapter 15.

2. UFSAR, Chapter 4.

3. NUREG-0800, " Standard Review Plan," Section 4.2, II.A.2(g), Revision 2, July 1981.

I GRAND GULF B 3.2-11 Revision No. 1

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RPS Instrumentation B 3.3.1.1 B 3.3 INSTRUMENTATION B 3.3.1.1 Reactor Protection System (RPS) Instrumentation BASES BACKGROUND The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limit, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS), and minimize the energy that must be absorbed following a loss of coolant accident (LOCA). This can be accomplished either automatically or manually.

The protection and monitoring functions of the RPS have been designed to ensure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on other reactor system parameters, and equipment performance. The LSSS are defined in this Specification as the Allowable Values, which, in conjunction with the LCOs, establish the threshold for protective system action to prevent exceeding acceptable limits, including Safety Limits (SLs), during Design Basis Accidents (DBAs).

The RPS, as shown in the UFSAR, Figure 7.2-1 (Ref. 1),

includea sensors, relays, bypass circuits, and switches that i are necessary to cause initiation of a reactor scram. 1 Functio nal diversity is provided by monitoring a wide range of depecident and independent parameters. The input .

parameters to the scram logic are from instrumentation that !

monitors reactor vessel water level; reactor vessel l pressure; neutron flux; main steam line isolation valve !

position; turbine control valve (TCV) fast closure, trip oil l pressure low; turbine stop valve (TSV) closure trip oil l pressure, low; drywell pressure; and scram discharge volume (SDV) water level; as well as reactor mode switch in shutdown position and manual scram signals. There are at least four redundant sensor input signals from each of these parameters (with the exception of the reactor mode switch in i shutdown scram signal). Most channels include electronic !

equipment (e.g., trip units) that compares measured input '

signals with pre-established setpoints. When a setpoint is )

exceeded, the channel output relay actuates, which then !

outputs an RPS trip signal to the trip logic. ;

I (continued)

GRAND GULF B 3.3-1 Revision No. 1

RPS Instrumentation B 3.3.1.1 BASES l

APPLICABLE 5. Reactor Vessel Water Level-High, Level 8 (continued)

SAFETY ANALYSES, l LCO, and Reactor Vessel Water Level-High, Level 8 signals are l APPLICABILITY initiated from four level transmitters that sense the difference between the pressure due to a constant column of l water (reference leg) and the pressure due to the actual l water level (variable leg) in the vessel. The Reactor Vessel Water Level-High, Level 8 Allowable Value is ,

specified to ensure that the MCPR SL is not violated during I the assumed transient. The Function ~is bypassed when the reactor mode switch is not in the run position.

i Four channels of the Reactor Vessel Water Level-High, level 8 Function, with two channels in each trip system arranged in a one-out-of-two logic, are available and are l required to be OPERABLE when THERMAL POWER is 2: 25% RTP to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. With THERMAL POWER < 25% RTP, this Function is not required since MCPR is not a concern below 25% RTP. I

6. Main Steam Isolation Valve-Closure MSIV closure results in loss of the main turbine and the I condenser as a heat sink for the Nuclear Steam Supply System and indicates a need to shut down the reactor to reduce heat generation. Therefore, a reactor scram is initiated on a Main Steam Isolation Valve-Closure signal before the MSIVs 1 are completely closed in anticipation of the complete loss !

of the normal heat sink and subsequent overpressurization transient. However, for the overpressurization protection analysis of Reference 2, the Average Power Range Monitor Fixed Neutron Flux-High Function, along with the S/RVs, limits the peak RPV pressure to less than the ASME Code limits. That is, the direct scram on position switches for MSIV closure events is not assumed in the overpressurization analysis. Additionally, MSIV closure is assumed in the transients analyzed in Reference 4 (e.g., low steam line pressure, manual closure of MSIVs, high steam line flow).

The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

(continued)

GRAND GULF 8 3.3-12 Revision No. 1

RPS Instrumentation .

B 3.3.1.1 !

BASES I

APPLICABLE 6. Main Steam Isolation Valve-Closure (continued)

SAFETY ANALYSES, _

LCO, and MSIV closure signals are initiated from position switches _ ,

APPLICABILITY located on each of the eight MSIVs. Each MSIV has two '

position switches; one inputs to RPS trip system A while the i other inputs to RPS trip system B.: Thus, each RPS trip r system receives an input from eight _ Main Steam Isolation ,

Valve-Closure channels, each consisting of one position :

switch. The logic for the Main Steam Isolation Valve-Closure Function is arranged such that either the -

inboard or outboard valve on three or more of the main steam i lines (MSLs) must close in order for a scram to occur. The :

Function is bypassed _when the reactor mode switch _is not in :

the run position.

The Main Steam Isolation Valve-Closure Allowable Value is I specified to ensure that a scram occurs prior to a !

significant reduction-in steam flow, thereby reducing the '

severity of the subsequent pressure transient.

Sixteen channels of the Main Steam Isolation Valve-Closure Function with eight channels in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude the scram from this Function on a 'I' valid signal. This Function is only required in MODE 1 since, with the MSIVs open and the heat generation rate high, a pressurization transient can occur if the MSIVs close. In MODE 2, the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection.

7. Drywell Pressure-Hiah High pressure in the drywell could indicate a break in the RCPB. A reactor scram is initiated to minimize the possibility of fuel damage and to reduce the amount of energy being added to the coolant-and the drywell. The Drywell Pressure-High Function is a secondary scram signal to Reactor Vessel Water Level-Low, Level 3 for large break LOCA events inside the drywell. This Function was not specifically credited in the accident analysis, but it is retained for the RPS as required by the NRC approved licensing basis.

(continued)

GRAND GULF B 3.3-13 Revision No. 1

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 7. Drywell Pressure-Hiah (continued)

SAFETY ANALYSES, LCO, and High drywell pressure signals are initiated from four APPLICABILITY pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary containment.

)

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GRAND GULF B 3.3-13a Revision No. 1

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RPS Instrumentation B 3.3.1.1-

< BASES APPLICABLE 11. Reactor Mode Switch-Shutdown Position (continued)

SAFETY ANALYSES, LCO, and There is no Allowable Value for this Function since the ;

APPLICABILITY channels are mechanically actuated based solely on reactor j mode switch position.

Four channels of Reactor Mode Switch-Shutdown' Position Function, with two channels in each trip system, are i available and required to be OPERABLE. The Reactor '

Mode-Switch Shutdown Position Function is required to be l OPERABLE in MODES 1 and 2,.and in MODE 5 with any control l rod withdrawn from a core cell containing one or more fuel l assemblies, since these are the MODES and other specified J conditions when control rod: are withdrawn. j

12. Manual Scram -

The Manual . Scram push button channels provide signals, via the manual scram logic channels, to each of the four RPS logic channels that are redundant to the automatic- ,

protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically ,

credited in the accident analysis, but it is retained for !

the RPS as required by the NRC approved licensing basis. '

There is one Manual Scram push button channel for each of the four RPS logic channels. In order to cause a scram it is necessary that at least one channel in each trip system be actuated.

There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.

Four channels of Manual Scram with two channels in each trip system arranged in a one-out-of-two logic, are available and required to be OPERABLE in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

ACTIONS A Note has been provided to modify the ACTIONS related to RPS instrumentation channels. Section 1.3, Completion (continuedl i

GRAND GULF B 3.3-18 Revision No. 1 i

l

- -,, .._ .. . -- -_ - ---. .- .-~.. - - . . - - - - - ~ - - - - - - - . . . - - - - - - - - . . . . - ~ - - - - . ~ . ~ ~ - - - . ~ - . - - - - - ~ - -

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__ _ .__ ._ _. ~ __ _ . _ _ . __ _

RPS Instrumentation B 3.3.1.1 BASES ACTIONS D.1 (continued) of Condition A, B, or C, and the associated Completion Time has expired, Condition D will be entered for that channel and provides for transfer to the appropriate subsequent '

Condition.

E.1, F.1, G.1, and H.1 If the channel (s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LC0 does not apply.- The Completion Times are reasonable, based on operating experience, to reach the specified condition from full power conditions in an orderly manner- l and without challenging plant systems. In addition, the '

Completion Time of Required Action E.1 is consistent with the Completion Time provided in LC0 3.2.2, "MINIMVM CRITICAL l POWER RATIO (MCPR)."

1.1 If the channel (s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LC0 does not apply. This is done by immediately initiating !

i action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are, therefore, not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted. Subsequently, if the manual scram channels are inoperable, the reactor mode switch is locked in the shutdown position to prevent inadvertent control rod withdrawals.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each RPS REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.5.1.1-1.

( +1nued)

GRAND GULF B 3.3-22 Revision No. I

1 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE The Surveillances are modified by a Note to indicate that, REQUIREMENTS when a channel is placed in an inoperable status solely for (continued) performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the RPS reliability analysis (Ref. 9) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RPS will trip when necessary.

SR 3.3.1.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not accurred. A CHANNEL CHECK is normally a comparison of the parimeter indicated on one channel to a similar parameter oa other channels. It is based on the assumption that inst ument channels monitoring the same parameter should read approximately the same value. Significant deviatiots between the instrument channels could be an indicatian of excessive instrument drift on one of the channels or something even more serious. A CHANNEL CHECK will decect gross channel failure; thus, it is key to verifying the instrumentation 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 outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECX supplements less formal, but more frequent, checks of channels during normal operational use of the display, associated with the channels required by the LCO.

(continued)

GRAND GULF B 3.3-23 Revision No. 1

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.3 (continued)

REQUIREMENTS A Frequency of 7 days provides an acceptable level of system average availability over the Frequency interval and is based on reliability analysis (Ref. 9).

SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire chanu11 will perform the intended Function. A Frequency of 7 days provides an acceptable level of system average availability over the Frequency and is based on the reliability analysis of Reference 9. (The Manual Scram Function's CHANNEL FUNCTIONAL TEST Frequency was credited in the analysis to extend many automatic scram Functions' Frequencies.)

SR 3.3.1.1.5 and SR 3.3.1.1.6 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status.

The overlap between SRMs and IRMs is required to be !

demonstrated to ensure that reactor power will not be .

increased into a region without adequate neutron flux I indication. This is required prior to withdrawing SRMs from i the fully inserted position since indication is being' i transitioned from the SRMs to the IRMs.

The overlap between IRMs and APRMs is of concern when !

reducing power into the IRM range. On power increases, the !

system design will prevent further increases (initiate a rod j block) if adequate overlap is not maintained.

Overlap between IRMs and APRMs exists when sufficient IRMs and APRMs concurrently have onscale readings such that the transition between MODE 1 and MODE 2 can be made without either APRM downscale rod block, or IRM upscale rod block.

Overlap between SRMs and IRMs similarly exists when, prior to withdrawing the SRMs from the fully inserted position, IRMs are above 2/40 on range 1 before SRMs have reached the l upscale rod block.

1 (continued)

GRAND GULF B 3.3-25 Revision No. 1 1

s RPS INSTRUMENTATION l B 3.3.1.1 '

4 WATER LEVEL NOMENCLATURE t 'T NOTE: SCALE IN INCHES HEIGHT ABOVE HElGHT RELATIVE VESSEL ZERO TO ]NSTRUMENT A80VE VESSEL ZERO LEVEL No. (INCHES) ZERO (INCHES)

M (8) 586.5 53.5 (7) 573.7 40.7 8ee-- (4) 565.7 32.7 (3) 544.4 11.4 (2) 4 91.4 -41.6 75e-- (1) 382.7 -150.3 VESSEL -

- FLANGE'-

7ee--

~

-648-MAIN STE LINE ,

see--

C ""- 586}'9) +6e -- ;g;= -*

, n7,

= g5.7(4)

Og 550 - j ,, gyg

- 544.4(3) 11.4 c3)-RgScaAM SEPARATOR

-SKIRT -517.38- 533-!NSTRUMENT- -e-o e e- -

FEED-493.35EL:- ZERO ggtgg, R - g ,4(2)

3 CORE hiN!'i ATE RCIC. AND 45e-- P *S TART IV !!!

g X.B DG.A DW.

416.3 4gg =_ g

- 82.74)

C -16e I[N 1 TE RHR LPCS AND

" 25e = '" ' !=Ilni'i' L.'S a

a so" N CLOSE MSiv'S y 3ee--

25e-- Q

(8) TRIP MAIN AND RCIC.

TURBINES.CLOSE HPC$.

216.3 2eg == 216.3 INJ. PATH:RX. SCRAM

/ -179.3- RECIF4. UN RUN)

RECIRC.-172.3- DISCHARGE /

15 0 -- N0ZZLE SUCTION N0ZZLE lee--

se __

BASES FIGURE B 3.3.1.1-1 REACTOR VESSEL WATER LEVEL GRAND GULF B 3.3-30e REVISION No.1

.J 4._a. m 5 u -a m _ 4...-em..m _ er p..A 2. a .a.m.s_sw.a 4

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SRM Instrumentation B 3.3.1.2

i c ,

BASES' 1 ACTIONS A.1 and B.1 (continued) take corrective actions to restore the required SRMs to OPERABLE status or to establish alternate IRM monitoring capability. During this time, control rod withdrawal and power increase are not precluded by this Required Action. '

Having the ability to monitor the core with at least one '

-SRM, proceeding to IRM Range 3 or greater (with overlap

, required by SR 3.3.1.1.5).and thereby exiting the Applicability of this LCO, is acceptable for ensuring adequate core monitoring and allowing continued operation. >

With four required SRMs inoperable, Required' Action B.1 ;

allows no positive changes in reactivity (control rod withdrawal must be immediately suspended) due to the inability to monitor the changes. Required Action A.1 still applies and allows 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to restore monitoring capability prior to requiring control rod insertion. This allowance is based on the limited risk of an event during this time, provided that no control rod withdrawals are allowed, and the desire to concentrate efforts on repair, rather than to -

immediately shut down, with no SRMs OPERABLE.

C.1 In MODE 2, if the required number of SRMs is not restored to OPERABLE status within the allowed Completion Time, the reactor.shall be placed in MODE 3. With all control rods fully inserted, the core is in its least reactive state with the most margin to criticality. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 in an orderly manner and without challenging plant systems.

D.1 and D.2 With one or more required SRM channels inoperable in MODE 3 or 4, the neutron flux monitoring capability is~ degraded or ,

nonexistent. The requirement to fully insert all insertable l control rods ensures that the reactor will be at its minimum !

reactivity level while no neutron monitoring capability is l available. Placing the reactor mode switch in the shutdown 1 position prevents subsequent control rod withdrawal by j maintaining a control rod block. Subsequently, the reactor I (continued)

GRAND GULF B 3.3-34 Revision No. 1

T SRM Instrumentation B 3.3.1.2 BASES ACTIONS D.1 and 0.2 (continued) mode switch is locked in the shutdown position to prevent inadvertent ~ control rod withdrawals. The allowed Completion Time of I hour is sufficient to accomplish the Required Action, and takes into account the low probability of an event requiring the SRM occurring during this time.

E.1 and E.2 With one or more required SRMs inoperable in MODE 5, the capability to detect local reactivity changes in the core during refueling is degraded. CORE ALTERATIONS must be immediately suspended, and action must be immediately initiated to insert all insertable control rods in core cells containing one or more fuel assemblies. Suspending CORE ALTERATIONS prevents the two most probable causes of reactivity changes, fuel loading and control rod withdrawal, from occurring. Inserting all insertable control rods ensures that the reactor will be at its minimum reactivity, given that fuel is present in the core. Suspension of CORE ALTERATIONS shall not preclude completion of the movement of a component to a safe, conservative position.

Action (once required to be initiated) to insert control rods must continue until all insertable rods in core cells containing one or more fuel assemblies are inserted.

SURVEILLANCE The SRs for each SRM Applicable MODE or other specified REQUIREMENTS condition are found in the SRs column of Table 3.3.1.2-1.

SR 3.3.1.2.1 and SR 3.3.1.2.3 Performance of the CHANNEL CHECK 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 the same parameter indicated on other similar channel s. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect (continued)

GRAND GULF B 3.3-35 Revision No. 1 i

l SRM Instrumentation B 3.3.1.2 i

l BASES l

SURVEILLANCE SR 3.3.1.2.4 REQUIREMENTS I

(continued) This Surveillance consists of a verification of the SRM !

instrument readout to ensure that the SRM reading is greater 1 than a specified minimum count rate. This ensures that the detectors are indicating count rates indicative of neutron flux levels within the core. Verification of the signal to noise ratio also ensures that the detectors are inserted to ;

a normal operating level. In a fully withdrawn condition, l the detectors are sufficiently removed from the fueled region of the core to essentially eliminate neutrons from reaching the detector. Any count rate obtained while fully .

withdrawn is assumed to be " noise" only. With few fuel I assemblies loaded, the SRMs will not have a high enough count rate to satisfy the SR. Therefore, allowances are made for loading sufficient " source" material, in the form of irradiated fuel assemblies, to establish the minimum count rate.

To accomplish this, the SR is modified by a Note that states that the count rate is not required to be met on an SRM that 4 has less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies are in the associated core quadrant. With four or less fuel assemblies loaded around each SRM and no other fuel assemblies in the associated quadrant, even with a control rod withdrawn the configuration will not be critical.

The Frequency is based upon channel redundancy and other information available in the control room, and ensures that the required channels are frequently monitored while core reactivity changes are occurring. When no reactivity ,

changes are in progress, the Frequency is relaxed from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SR 3.3.1.2.5 Performance of a CHANNEL FUNCTIONAL TEST demonstrates the associated channel will function properly.

The 31 day Frequency is based on operating experience and on other Surveillances (such as CHANNEL CHECK) that ensure proper functioning between CHANNEL FUNCTIuNAL IESTS.

(continued)

GRAND GULF B 3.3-37 Revision No. 1

Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.1, SR 3.3.2.1.2, SR 3.3.2.1.3, and REQUIREMENTS SR 3.3.2.1.4 (continued) control rod block occurs. Proper operation of the RWL is verified by SR 3.3.2.1.1 which verifies proper operation of the two-notch withdrawal limit and SR 3.3.2.1.2 which i verifies proper operation of the four-notch withdrawal limit. Proper operation of the RPC is verified by SR 3.3.2.1.3 and SR 3.3.2.1.4. Any setpoint adjustment I shall be consistent with the assumptions of the current plant specific setpoint methodology. As noted, the SRs are not required to be performed until I hour after specified conditions are met (e.g., after any control rod is withdrawn in MODE 2). This allows entry into the appropriate conditions needed to perform the required SRs. The ,

Frequencies are based on reliability analysis (Ref. 7). I SR 3.3.2.1.5 The LPSP is the point at which the RPCS makes the transition between the function of the RPC and the RWL. This transition point is automatically varied as a function of power. This power level is inferred from the first stage !

turbine pressure (one channel to each trip system). These power setpoints must be verified periodically to be within ,

the Allowable Values. If any LPSP is nonconservative, then I the affected Functions are considered inoperable. Since i' this channel has both upper and lower required limits, it is not allowed to be placed in a condition to enable either the i RPC or RWL Function. Because main turbine bypass steam flow '

can affect the LPSP nonconservatively for the RWL, the RWL is considered inoperable with any main turbine bypass valves open. The Frequency of 92 days is based on the setpoint methodology utilized for these channels.

SR 3.3.2.1.6 This SR ensures the high power function of the RWL is not bypassed when power is above the HPSP. The power level is inferred from turbine first stage pressure signals.

Periodic testing of the HPSP channels is required to verify the setpoint to be less than or equal to the limit.

Adequate margins in accordance with setpoint methodologies are included. If the HPSP is nonconservative, then the RWL is considered inoperable. Alternatively, the HPSP can be placed in the conservative condition (nonbypass). If placed (continued) ,

GRAND GULF B 3.3-46 Revision No. I a

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I

PAM Instrumentation !

B 3.3.3.1 i

BASES i

l SURVEILLANCE SR 3.3.3.1.1 (continued) :

REQUIREMENTS Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, '

including isolation, indication, and readability. If a channel is outside the criteria, it may be an indication

l. that the sensor or the signal processing equipment has

! drifted outside its limit.

The Frequency of 31 days is based upon plant operating ,

experience with regard to channel OPERABILITY and drift, -

l which demonstrates that failure of more than one channel of

l a given function in any 31 day interval is rare. The l CHANNEL CHECK supplements less formal, but more frequent, j checks of channels during normal operational use of those '

displays associated with the required channels of this LCO. l SR 3.3.3.1.2 and SR 3.3.3.1.3 !

For all Functions except the containment and drywell !

hydrogen concentration analyzers, a CHANNEL CALIBRATION is ;

performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the i instrument loop including the sensor. The test verifies ;

that the channel responds to the measured parameter with the :

necessary range and accuracy. The Frequency is based on '

operating experience and consistency with the typical !

industry refueling cycles. t For the containment and drywell hydrogen concentration i analyzer and monitor the CHANNEL CALIBRATION is performed !

every 92 days. This calibration is performed using a sample ,

gas containing one volume percent hydrogen'with the '

j remainder nitrogen, and four volume percent hydrogen with

the remainder nitrogen. This Frequency is based on operating experience. j l

For Functions 12 and 13 the CHANNEL CALIBRATION consists of I an electronic calibration of the channel, not including the j detector, for range decades above 10R/hr and a one point l calibration check of the detector below 10R/hr with an i installed or portable gamma source. The neutron detectors '

are excluded from the CHANNEL CALIBRATION because they cannot readily be adjusted. The detectors are fission (continued)

GRAND GULF B 3.3-60 Revision No. 1

PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.2 and SR 3.3.3.1.3 (continued) 1 REQUIREMENTS chambers that are designed to have a relatively constant sensitivity over the range, and with an accuracy specified for a fixed useful life.

REFERENCES 1. Regulatory Guide 1.97, " Instrumentation for

1. Light-Water Cooled Nuclear Power Plants to Assess

! Plant and Environs Conditions During and Following an l Accident," Revision 2, December 1980.

2. NRC Safety Evaluation Report, "Conformance to l regulatory Guide 1.97, Revision 2, Grand Gulf Nuclear Station, Unit 1," dated January 12, 1987.

3. GNRO-93/00032, Grand Gulf Nuclear Station (GGNS) Plant i

Specific Design Evaluation for NED0-31558, dated March 15, 1993.

4. UFSAR, Section 7.5. l l

!~

l l

GRAND GULF B 3.3-61 Revision No. 1

l ECCS Instrumentation 4

B 3.3.5.1 2

BASES APPLICABLE 1.a. 2.a. Reactor Vessel Water level--Low Low low, level 1 SAFETY ANALYSES, (continued) i LCO, and APPLICABILITY Reactor Vessel Water Level-Low Low Low, Level 1 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

The Reactor Vessel Water Level-Low Low Low, Level 1 Allowable Value is chosen to allow time for the low pressure core flooding systems to activate and provide adequate cooling. !

Two channels of Reactor Vessel Water Level-Low Low Low, level 1 Function per associated Division are only required to be OPERABLE when the associated ECCS is required to be I i 0PERABLE, to ensure that no single instrument failure can preclude ECCS initiation. (Two channels input to LPCS and LPCI A, while the other two channels input to LPCI B and LPCI C.) Refer to LC0 3.5.1 and LC0 3.5.2, "ECCS-Shutdown," for Applicability Bases for the low pressure ECCS subsystems; LC0 3.8.1, "AC Sources-0perating"; and LCO 3.8.2, "AC Sources-Shutdown," for Applicability Bases '

for the DGs. I 1.b, 2.b. Drywell Pressure-High High pressure in the drywell could indicate a break in the reactor coolant pressure boundary (RCPB). The low pressure ECCS and associated DGs are initiated upon receipt of the Drywell Pressure-High Function in order to minimize the possibility of fuel damage. The core cooling function of 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.

High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary containment. Negative barometric fluctuations are accounted for in the Allowable Value. '

The Drywell Pressure-High Function is required to be OPERABLE when the associated ECCS and DGs are required to be OPERABLE in conjunction with times when the primary (continued)

GRAND GULF B 3.3-95 Revision No. 1

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RCIC System Instrumentation i B 3.3.5.2 BASES t SURVEILLANCE Conditions and Required Actions may be_ delayed as follows:

REQUIREMENTS (a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 2 and 5; and (b) for up (continued) to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 1, 3, and 4 provided the associated Function maintains trip capability. Upon completion of the i Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the ,

channel must be returned to OPERABLE status or the .

applicable Condition entered and Required Actions taken.

This Note is based on the reliability analysis (Ref.1) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RCIC will initiate when necessary.

SR 3.3.5.2.1 l Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 other channels. It is based on the assumption that instrument I channels monitoring the same parameter should read ,

approximately the same value. Significant deviations '

between the instrument channels could be an indication of 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 instrumentation 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 ;

outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Frequency is based upon operating experience that l demonstrates channel failure is rare. The CHANNEL CHECK '

supplements less formal, but more frequent, checks of l channel status-during normal operational use of the displays i associated with the channels required by the LCO. l i

(continued)

GRAND GULF B 3.3-133 Revision No. 1

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l Primary Containment and Drywell Isolation Instrumentation )

B 3.3.6.1 i BASES APPLICABLE 2.a. Containment and Drywell Ventilation Exhaust SAFEiY ANALYSES, Radiation-High (continued)

LCO, and !

APPLICABILITY- Four channels of Containment and Drywell Ventilation 1 Exhaust-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Values are chosen to promptly detect gross failure of the fuel cladding and to ensure offsite doses remain below 10 CFR 20 and 10 CFR 100 limits.

The Function is required to be OPERABLE during CORE ALTERATIONS, operations with a potential for draining the l reactor vessel (OPDRVs), and movement.of irradiated fuel l assemblies in the primary or secondary containment because l the capability of detecting radiation releases due to fuel l failures (due to fuel uncovery or dropped fuel assemblies) must be provided to ensure offsite dose limits are not exceeded.

This Function . isolates the Group 7 valves. I 2.h. Manual Initiation The Manual Initiation push button channels introduce signals into the primary containment and drywell isolation logic l that are redundant to the automatic protective instrumentation and provide manual isolation capability.

There is no specific UFSAR safety analysis that takes credit for this Function. It is retained for the isolation I function as required by the NRC in the plant licensing I basis.

Thera are four push buttons for the logic, two manual initiation push buttons per trip system. There is no i Allowable Value for this Function since the channels are l mechanically actuated based solely on the position of the !

push buttons. q Four channels of the Manual Initiation Function are available and are required to be OPERABLE.

(continued) i GRAND GULF B 3.3-148 Revision No. 1

Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 i

BASES APPLICABLE 5.b. Reactor Vessel Water level-Low, level 3 (continued)

SAFETY ANALYSES, LCO, and Water Level-Low, Level 3 Function are required to be APPLICABILITY OPERABLE in MODES 4 and 5 (both channels must input into the same trip system) provided the RHR Shutdown Cooling System

~

integrity is maintained. System integrity is maintained provided the piping is intact and no maintenance is being performed that has the potential for draining the reactor vessel through the system. When only one trip system is OPERABLE in MODE 4 or 5, the trip system should be considered inoperable if the associated RHR Shutdown Cooling System suction from the reactor vessel isolation valve (i.e., the IE12-F008 or 1E12-F009) is not associated with an OPERABLE diesel generator.

The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low, Level 3 Allowable Value (LC0 3.3.1.1) since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level-Low, Level 3 Function is-required to be OPERABLE in MODE 3 with reactor pressure less than the RHR permissive pressure, MODE 4, and MODE 5 to prevent this potential flow path from lowering reactor vessel level to the top of the fuel. This instrumentation-is required to be OPERABLE in MODES I and 2 and in MODE 3 I with reactor steam dome pressure greater than or equal to the RHR cut-in permissive pressure to support actions to ensure that offsite dose limits of 10CFR100 are not exceeded.

This Function isolates the Group 3 valves.

5.c. Reactor Steam Dome Pressure-Hiah The Shutdown Cooling System Reactor Steam Dome Pressure-High Function is provided to isolate the shutdown cooling portion of the RHR System. This interlock is provided only for equipment protection to prevent an intersystem LOCA scenario and credit for the interlock is not assumed in the accident or transient analysis in the UFSAR.

(continued),

GRAND GULF B 3.3-160 Revision No. I

Pr'. nary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.c. Reactor Steam Dome Pressure-Hiah (continued)

SAFETY ANALYSES, The Reactor Steam Dome--High pressure signals are initiated from four transmitters. Four channels of Reactor Steam Dome Pressure--High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization.

This Function isolates the Group 3 valves.

i (continued)

GRAND GULF B 3.3-160a Revision No. 1

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Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 !

BASES' APPLICABLE 5.d. Drvwell' Pressure-Hiah SAFETY ANALYSES, LCO, and High drywell pressure can indicate a break in the RCPB. The

APPLICABILITY isolation of some of the PCIVs on high drywell pressure (continued). 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 RHR Shutdown Cooling System is not modeled in any UFSAR accident or transient analysis because other leakage paths (e.g., MSIVs) are more limiting.

! High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Four channels of Drywell Pressure-High Function 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 ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.1), ~ since this may be indicative of a LOCA inside primary containment.

This Function isolates the Group 3 valves.

5.e. Manual Initiation The Manual Initiation push button channels introduce signals into the RHR Shutdown Cooling System isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability. There'is no specific UFSAR safety analysis that takes credit for this Function. It is retained for the isolation function as required by the NRC in the plant licensing basis.

There are four push buttons for the logic, two manual initiation push buttons per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons. ;

Four channels of the Manual Initiation Function are available and are required to be OPERABLE.

(continued)

GRAND GULF B 3.3-161 Revision No. 1

Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES ACTIONS F.1 (continued)

If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operation may continue if the affected penetration flow path (s) is isolated. Isolating the affected penetration flow path (s) ;

accomplishes the safety function of the inoperable channels. l When the affected penetration is isolated due to the :

inoperability of RHR System isolation instrumentation, the valve used to isolate the penetration must be locked closed.

Alternately, remote indication may be used to verify the valve is closed and the valve is subsequently electrically disarmed.

For some of the Ambient Temperature Functions, the affected penetration flow path (s) may be considered isolated by isolating only that portion of the system in the associated room monitored by the inoperable channel. That is, if the RWCU pump room A ambient channel is inoperable, the A pump room area can be isolated while allowing continued RWCU operation utilizing the B RWCU pump.

Alternatively, if it is not desired to isolate the affected penetration flow path (s) (e.g., as in the case where isolating the penetration flow path (s) could result in a reactor scram), Condition H must be entered and its Required Actions taken. .

The Completion Time is acceptable because it minimizes risk I while allowing sufficient time for plant operations l personnel to isolate the affected penetration flow path (s). l l

G.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path (s) is isolated. Isolating the affected penetration flow path (s) accomplishes the safety function of the inoperable channels.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is acceptable due to the fact that these Functions (Manual Initiation) are not assumed in any accident or transient analysis in the UFSAR. 1 Alternately, if it is not desired to isolate the affected (continued) i GRAND GULF B 3.3-165 Revision No. 1 l

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' Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES l

ACTIONS G.1 I (continued) penetration flow path (s) (e.g., as in the case where isolating the penetration flow path (s) could result in a ,

reactor scram), Condition H must be entered and its Required !

Actions taken.

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(continued)

GRAND GULF B 3.3-165a Revision No. 1

__. . e4 A 6 4 A e,--, .-, J J ,4 44- . O as--*.- me-es a e sam.- e-- 4 Eh- m 4-w-y4-m- Aehe.4-e4 ..h _.dd.m -.a m aAh 1

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Primary Containment and Drywell Isolation Instrumentation l B 3.3.6.1 BASES ACTIONS H.1 and H.2 '

(continued)

If the channel is not restored to OPERABLE status or placed in trip, or any Required Action of Condition F or G is not met and the associated Completion Time has expired, the plant must be placed in a MODE or other specified condition ,

in which the LC0 does not apply. This is done by placing i the plant in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 !

within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant ccnditions from full power conditions in an orderly manner and without challenging plant systems.

I.1 and I.2 If the channel is not restored to OPERABLE status within the allowed Completion Time, the associated SLC subsystem (s) is 4 declared inoperable or the RWCU System is isolated. Since this Function is required to ensure that the SLC System performs its intended function, sufficient remedial measures are provided by declaring the associated SLC subsystem ;

inoperable or isolating the RWCU System. I l

The Completion Time of I hour is acceptable because it I minimizes risk while allowing sufficient time for personnel 1 to isolate the RWCU System. .

I J.1, J.2, J.3.1, J.3.2. and J.3.3 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the RHR Shutdown Cooling System suction from the reactor vessel flow path i should be isolated. However, if the shutdown cooling l function is needed to provide core cooling, these Required Actions allow the penetration flow path to remain unisolated provided action is immediately initiated to restore the channel to OPERABLE status or to provide an alternate decay heat removal capability and subsequently isolate the RHR Shutdown Cooling System to minimize any potential fission product release to the environment. This includes ensuring secondary containment is OPERABLE; one standby gas treatment subsystem is OPERABLE; and secondary containment isolation capability (i.e., at least one isolation valve and (continued) l GRAND GULF B 3.3-166 Revir'an No. 1 l l

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i Primary Containment and Drywell Isolation Instrumentation i B 3.3.6.1 BASES

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-ACTIONS J.1, J.2,~J.3.1, J.3.2, and J.3.3 (continued) l-

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associated instrumentation are OPERABLE or other acceptable !

administrative controls to assure isolation capability) in 1 each secondary containment penetration flow path not isolated that is assumed to be isolated to mitigate +

radioactivity releases. This may be performed as an ,

administrative check, by examining logs or other !

information, to determine if the components are out of !

service for maintenance or other reasons. It is not !

necessary to perform the Surveillances needed to demons.. ate l the OPERABILITY of the components. If, however, any i required component is inoperable, then it must be restored :

to OPERABLE status. In this case, the Surveillances may .

need to be performed to restore the component to OPERABLE ,

status. Actions must continue until all required components !

are OPERABLE. !

K.1, K.2.1, K.2.2, and K.2.3 If the channel is not restored to OPERABLE status.or placed ,

in trip within the allowed Completion Time, the associated penetration flow path (s) should be isolated (Required Action K.1). Isolating the affected penetration flow path (s) accomplishes the safety function of the inoperable :

instrumentation. Alternately, the plant must be placed in a condition in which the LCO does not apply. If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies must be immediately suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe condition. Also, if applicable, action i

must be.immediately initiated to suspend OPDRVs to minimizo l the probability of a vessel draindown and subsrquent '

potential for fission production release. Actions must continue until OPDRVs are suspended.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each REQUIREMENTS Isolation Instrumentation Function are found in the SRs column of Table 3.3.6.1-1.

The Surveillances are also modified by a Note to indicate that when a channel is placed in an inoperable status solely ,

for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains (continued) ]

GRAND GULF B 3.3-167 Revision No. 1 i

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RHR Containment Spray System Instrumentation B 3.3.6.3 BASES l

SURVEILLANCE SR 3.3.6.3.3 (continued)

REQUIREMENTS tr.ip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Frequency of 92 days is based upon the reliability analysis of Reference 3.

SR 3.3.6.3.4 and SR 3.3.6.3.5 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that 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 of SR 3.3.6.3.4 and SR 3.3.6.3.5 is based on the assuc tion Jf the magnitude of equipment drift in the setpoint analysis.

SR 3.3.6.3.6 >

The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LC0 3.6.1.7, " Residual Heat Removal (RHR) Containment Spray," 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.

i (continued)

GRAND GULF B 3.3-194 Revision No. 1

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Relief and LLS Instrumentation B 3.3.6.5 B 3.3 INSTRUMENTATION.

B 3.3.6.5 Re1ief'and Low-Low Set (LLS)' Instrumentation BASES' BACKGROUND The safety / relief valves (S/RVs) prevent overpressurization of the nuclear steam system. Instrumentation is provided to support two modes of S/RV. operation-the relief function )

(all valves) and the LLS function (selected valves). Refer to LC0 3.4.4, " Safety / Relief Valves (S/RVs)," and i LC0 3.6.1.6, " Low-Low Set (LLS) Safety / Relief Valves l (S/RVs)," Applicability Bases for additional information on .)

these modes of S/RV operation.. '

The relief function of the S/RVs prevents overpressurization of the nuclear steam system. The.LLS function of the S/RVs is designed to mitigate the effects of postulated pressure loads on the containment by preventing multiple actuations !

in rapid succession of the S/RVs. subsequent to their initial I ac,tuatim .

Upon any S/RV; actuation, the LLS logic assigns' preset opening and reclosing setpoints to six preselected S/RVs. 1 These setpoints are selected to override the normal relief l setpoints such 'that the LLS S/RVs'will stay open longer, thus releasing more steam (energy) to the suppression pool;- .

hence more energy (and time) is required for repressurization and subsequent S/RV openings. The LLS logic increases the time between (or prevents) subsequent actuations to limit S/RV subsequent actuations to one valve, so that. containment loads will also be reduced. The LLS mode is divided into three setpoint groups: the low group actuating IB21-F051D, the medium group actuating 1821-F0518, and the high pressure group actuating IB21-F0470, 1821-F047G, 1B21-F051A, and 1B21-F051F.

The relief instrumentation consists of two trip systems, with each trip system actuating one solenoid for each S/RV.

There are'two solenoids per S/RV, and each solenoid can open its respective S/RV. The relief mode (S/RVs and associated '

trip systems) is divided into three setpoint groups (the low with one S/RV, the medium with 10 S/RVs, and the high with nine S/RVs), although one S/RV, 1821-F0518, in the medium I (continued)

GRAND GULF B 3.3-208 Revision No. 1-

Relief and LLS Instrumentation B 3.3.6.5 BASES BACKGROUND group initially opens at 1103

15 psig due to the LLS logic. The S/RV relief function is actuated by transmitters (continued) ,

that monitor reactor steam dome pressure. The reactor steam dome pressure transmitters send signals to trip units whose outputs are arranged in a two-out-of-two logic for each trip -

system in each of three separate setpoint groups (e.g., the medium group of 10 S/RVs opens when at least one of the e

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(continued)

GRAND GULF B 3.3-208a Revision No. 1

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Relief and LLS Instrumentation B 3.3.6.5

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I BASES 1

BACKGROUND associated trip systems trips at its assigned setpoint).

(continued) Once an S/RV has been opened, it will reclose when reactor steam dome pressure decreases below the opening pressure !

setpoint. This logic arrangement ensures that no single instrument failure can preclude the S/RV relief function.

The LLS logic consists of two trip systems similar to the i S/RV relief function. Either trip system can actuate the LLS S/RVs by energizing the associated S/RV solenoid. Each LLS trip system is enabled and sealed in upon initial S/RV actuation from the existing reactor steam dome pressure sensors of any of the normal relief setpoint groups except for 1821-F051B whose initial opening is 1103 i 15 psig due to the LLS function. The reactor steam dome pressure channels used to arm LLS are arranged in a one-out-of-three taken twice logic. The reactor steam dome pressure channels that control the opening and closing of the LLS S/RVs are arranged in either a one-out-of-one or a two-out-of-two logic depending on which LLS S/RV group is being controlled.

This logic arrangement ensures that no single instrument failure can preclude the LLS S/RV function. The channels l include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a LLS or relief initiation signal, as applicable, to the initiation logic.

APPLICABLE The relief and LLS instrumentation are designed to prevent j SAFETY ANALYSES overpressurization of the nuclear steam system and to ensure that the containment loads remain within the primary containment design basis (Ref. 1). I Relief and LLS instrumentation satisfies Criterion 3 of the NRC Policy Statement.

LC0 The LC0 requires OPERABILITY of sufficient relief and LLS instrumentation channels to provide adequate assurance of 1 successfully accomplishing the relief and LLS function, l assuming any single instrumentation channel failure within the LLS logic. Therefore, two trip systems are required to be OPERABLE. The OPERABILITY of each trip system is i

(continued) 1 GRAND GULF B 3.3-209 Revision No. 1 i

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Relief and LLS Instrumentation B 3.3.6.5 BASES LC0 dependent upon the OPERABILITY of the reactor steam dome (continued) pressure channels associated with required relief and LLS S/RVs. Each required channel shall have its setpoint within the specified Allowable Value. A channel is inoperable if I

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GRAND GULF B 3.3-209a Revision No. 1

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Relief and LLS Instrumentation B 3.3.6.5 BASES :

LC0 its actual' trip setpoint is not within its required (continued) Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.

Allowable Values are specified for each channel in SR 3.3.6.5.3. 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 Allowable Value, is acceptable. ,

i Trip setpoints are those predetermined values of output at j which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel pressure), and when the measured output value of the process parameter exceeds the setpoint, the associated i device (e.g., trip unit) 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 I calibration, process, and some of the instrument errors. ;

The trip setpoints are then determined, accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environmelts as defined by 10 CFR 50.49) are accounted for.

For relief, the actuating Allowable Values are based on the transient event of main steam isolation valve (MSIV) closure with an indirect scram (i.e., neutron flux). This analysis is described in Reference 1. For LLS, the actuating and reclesing Allowable Values are based on the transient event of PSIV closure with a direct scram (i.e., MSIV position swi;ches). This analysis is also described in Reference 1.

APPLICABILITY The relief and LLS instrumentation is required to be OPERABLE in MODES 1, 2, and 3, since considerable energy exists in the nuclear steam system and the S/RVs may be needed to provide pressure relief. If the S/RVs are needed, then the relief and LLS functions are required to ensure that the primary containment design basis is maintained. In MODES 4 and 5, the reactor pressure is low enough that the (continued)

GRAND GULF B 3.3-210 Revision No. 1

Recirculation Loops Operating B 3.4.1 BASES (continued)

SURVEILLANCE SR 3.4.1.1 REQUIREMENTS This SR ensures the recirculation loop flows are within the allowable limits for mismatch. At low core flow (i.e.,

< 70% of rated core flow), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is < 70% of rated ,

core flow. The recirculation loop jet pump flow, as used in l this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop.

The mismatch is measured in terms of percent of rated core l fl ow. This Surveillance can be met by verifying that the l recirculation loop drive flow mismatch, when two loops are i in operation, is < 5% of rated recirculation drive flow with core flow a: 70% of rated core flow and < 10% of rated recirculation drive flow with core flow < 70% of rated core flow.

This SR is not required when both loops are not in operation I since the mismatch limits are meaningless during single loop or natural circulation operation. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is consistent with the Frequency for jet pump OPERABILITY verification and has been shown by operating experience to be adequate to detect off normal jet pump loop flows in a timely manner.

SR 3.4.1.2 This SR ensures the reactor THERMAL POWER and core flows are within appropriate parameter limits to prevent uncontrolled power oscillations. The limits are Region D of Figure 3.4.1-1, or if withdrawing control rods for startup, either Region D or Region C. At low recirculation flows and high reactor power, the reactor exhibits increased susceptibility to thermal hydraulic instability. Interim actions have been developed based on the guidance provided in References 4 and 5 to respond to operation in these conditions. This SR identifies when the conditions requiring these interim actions are necessary. The Frequency is based on operating (continued)

GRAND GULF B 3.4-7 Revision No. 1

Recirculation Loops Operating B 3.4.1 BASES SURVEILLANCE SR 3.4.1.2 (continued)

REQUIREMENTS i experience and the operators' inherent knowledge of reactor status, including significant changes in THERMAL POWER and core flow.

' REFERENCES 1. UFSAR, Section 6.3.3.7.

2. UFSAR, Section 5.4.1.1.

I

3. UFSAR, Chapter 15, Appendix 15C.

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4. NRC Bulletin 88-07, Supplement 1, " Power Oscillations

. in Boiling Water Reactors," December 1988. >

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5. GE Letter, " Interim Recommendations for Stability Actions, November 1988.

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J GRAND GULF B 3.4-8 Revision No. 1 l

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RCS PIV Leakage B 3.4.6 BASES SURVEILLANCE SR 3.4.6.1 (continued)

REQUIREMENTS The Frequency is every 18 months and is required by the i Inservice Testing Program is within the ASME Code,Section XI, Frequency requirement.

Therefore, this SR is modified by a Note that states the leakage Surveillance is only required to be performed in MODES 1 and 2. Entry into MODE 3 is permitted for leakage testing at high differential pressures with stable conditions not possible in the lower MODES.

I REFERENCES 1. 10 CFR 50.2.

2. 10 CFR 50.55a(c).

3. 10 CFR 50, Appendix A, GDC 55.

4. ASME, Boiler and Pressure Vessel Code,Section XI, Subsection IWV.

5. NUREG-0677, "The Probability of Intersystem LOCA: l Impact Due to Leak Testing and Operational Changes," '

May 1980.

6. ASME, Boiler and Pressure Vessel Code,Section XI, IWV-3423(e).

7. NEDC-31339, "BWR Owners Group Assessment of ECCS !

Pressurization in BWRs," November 1986.

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GRAND GULF B 3.4-31 Revision No. 1

RCS P/T Limits B 3.4.11 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.11 RCS Pressure and Temperature (P/T) Limits !

t 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 heatup, l cooldown, and inservice leak and hydrostatic testing. The heatup curve provides limits for both heatup and -

criticality.

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 l 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. I 10 CFR 50, Appendix G (Ref.1), requires the establishment l of P/T limits for material fracture toughness requirements of the RCPB materials. Reference 1 requires an adequate !

margin to brittle failure during normal operation, j anticipated operational occurrences, and system hydrostatic l tests. It mandates the use of the American Society of 1 Mechanical Engineers (ASME) Code,Section III, Appendix G (Ref. 2).

The actual shift in the RT, 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) and 10 CFR 50, Appendix H (Ref. 4).

The operating P/T limit curves will be adjusted, as (continued) l l

GRAND GULF B 3.4-52 Revision No. 1

RCS P/T Limits B 3.4.11 BASES SURVEILLANCE SR 3.4.11.2 REQUIREMENTS (continued) A separate limit is used when the reactor is approaching criticality (curve C). Consequently, the RCS pressure and I temperature must be verified within the appropriate limits before withdrawing control rods that will make the reactor critical.

Performing the Surveillance within 15 minutes before control I rod withdrawal for the purpose of achieving criticality provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the control rod withdrawal.

l SR 3.4.11.3 and SR 3.4.11.4 ,

Differential temperatures within the applicable limits ensure that thermal stresses resulting from the startup of ;

an idle recirculation pump will not exceed design :

allowances. In addition, compliance with these limits ;

ensures that the assumptions of the analysis for the startup '

of an idle recirculation loop (Ref 8) are satisfied. :

Performing the Surveillance within 15 minutes before i starting the idle recirculation pump provides adequate l assurance that the limits will not be exceeded between the J time of the Surveillance and the time of the idle pump start.

An acceptable means of demonstrating compliance with the temperature differential requirement in SR 3.4.11.4 is to compare the temperatures of the operating recirculation loop and the idle loop.

SR 3.4.11.3 and SR 3.4.11.4 have been modified by a Note that requires the Surveillance to be met only in MODES 1, 2, 3, and 4 during recirculating pump start. In addition, SR 3.4.11.3 is only required to be met when reactor steam dome pressure a: 25 psig. In MODE 5, the overall stress on j limiting components is lower; therefore, AT limits are not ;

required. !

1 (continued) i GRAND GULF B 3.4-58 Revision No. 1 !

- _~. - - -.. - - -. - . -. - _ - - - - - - . -. - -_ _ _ -._ - ..- - _ _ -

1 l ECCS-Operating l B-3.5.1 BASES P

t SURVEILLANCE SR 3.5.1.4 (continued). [

REQUIREMENTS. t losses, and RPV pressure present during-LOCAs. These values ;

may be established during pre-operational testing. - The Frequency for this Surveillance is in accordance with the :

Inservice Testing Program requirements. t

)

SR 3.5.1.5 1

The ECCS subsystems are required to actuate automatically to-perform their design functions. This Surveillance test verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCS, LPCS, and LPCI will cause the systems or subsystems to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup, and actuation of all automatic valves to their required positions. This Surveillance also ensures that the HPCS System will automatically restart on an RPV low water {

level (Level 2) signal received subsequent to an RPV high '

water level (Level 8) trip and that the suction is automatically transferred from the CST to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LC0 3.3.5.1, " Emergency Core Cooling System (ECCS) i Instrumentation," 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 i Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually !

pass the SR when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

I This SR is modified by a Note that excludes vessel injection / spray during the Surveillance. Since all active ,

components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.

l l (continued)

GRAND GULF B 3.5-11 Revision No. 1 l

) ECCS-Operating

B 3.5.1 BASES SURVEILLANCE SR 3.5.1.6 REQUIREMENTS (continued) The ADS designated S/RVs are required to actuate I

, automatically upon receipt of specific initiation signals.

A system functional test is performed to demonstrate that

, the mechanical portions of the ADS function (i.e.,

solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components. SR 3.5.1.7 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LC0 3.3.5.1 overlap this Surveillance to provide complete testing of the !

assumed safety function.

The 18 month Frequency is based on the need to perform this l 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 I pass the SR when performed at the 18 month Frequency, which l 1s based on the refueling cycle. Therefore, the Frequency '

was concluded to be acceptable from a reliability standpoint.

1 This SR is modified by a Note that excludes valve actuation. !

This prevents an RPV pressure blowdown.

SR 3.5.1.7 A manual actuation of each ADS valve is performed to verify that the valve and solenoids are functioning properly and that no blockage exists in the S/RV discharge lines. This is demonstrated by the response of the turbine control or bypass valve, by a change in the measured steam flow, or by any other method suitable to verify steam flow (e.g.,

tailpipe temperature or pressure). Adequate reactor steam pressure must be available to perform this test to avoid damaging the valve. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the ADS valves divert steam flow upon opening. Sufficient time is therefore allowed, after the required pressure and flow are l achieved, to perform this test. Adequate pressure at which this test is to be performed is consistent with the pressure ,

recommended by the valve manufacturer. Reactor startup is I allowed prior to performing this test because valve 1 (continued)

GRAND GULF B 3.5-12 Revision No. 1

____ s

ECCS-Operating B 3.5.1 BASES

-SURVEILLANCE SR 3.5.1.7- (continued)

REQUIREMENTS OPERABILITY and the setpoints for overpressure protection ,

are verified, per ASME requirements, prior.to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12Lhours after reactor steam pressure and flow are adequate to perform the test. SR 3.5.1.6 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.

The Frequency of 18 months on a STAGGERED TEST BASIS ensures that both solenoids for each ADS valve are alternately tested. The Frequency is based on the need to perform this Surveillance under the conditions that apply just prior to or during a startup from a plant outage and the potential for unplanned transients. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency, which is based on the refueling cycle. 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 analysis. Specific testing of the ECCS actuation 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 specific measurement test. The diesel generator starting and any sequence loading delays must be added to the HPCS .

System equipment response times to obtain the HPCS System 1 ECCS SYSTEM RESPONSE TIME. The acceptance criterion for the l HPCS System ECCS SYSTEM RESPONSE TIME is :s; 27 seconds.

(continued) j GRAND GULF B 3.5-13 Revision No. 1 1 I

l ECCS--Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.8 (continued) i REQUIREMENTS HPCS System ECCS SYSTEM RESPONSE TIME tests are conducted I every 18 months. This Frequen.y is consistent with the I typical industry refueling cycle and is based on industry operating experience.

REFERENCES 1. UFSAR, Section 6.3.2.2.3.

2. UFSAR, Section 6.3.2.2.4.

3. UFSAR, Section 6.3.2.2.1. !

l

4. UFSAR, Section 6.3.2.2.2. j 1

5. UFSAR, Section 15.6.6. l

6. UFSAR, Section 15.6.4.

7. UFSAR, Section 15.6.5.

8. 10 CFR 50, Appendix K.

9. UFSAR, Section 6.3.3. I

10. 10 CFR 50.46. i l

11. UFSAR, Section 6.3.3.3.

12. Memorandum from R.L. Baer (NRC) to V. Stello, Jr.

(NRC), " Recommended Interim Revisions to LC0's for l ECCS Components," December 1, 1975. l

13. UFSAR, Section 6.3.3.7.8. l l

14. UFSAR, Section 7.3.1.1.1.4.2.

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I GRAND GULF B 3.5-14 Revision No. 1 l

ECCS-Shutdown B 3.5.2 B 3.5' EMERGENCY-CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION' COOLING (RCIC) SYSTEM B 3.5.2 ECCS-Shutdown BASES.

BACKGROUND A' description of the High Pressure Core Spray (HPCS) System, Low Pressure Core Spray (LPCS) System, and low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System is provided in the Bases for LC0 3.5.1, "ECCS-Operating."

APPLICABLE. ECCS performance is evaluated for the entire spectrum of SAFETY ANALYSES break sizes for a postulated loss of coolant accident (LOCA). The long term cooling analysis following a design basis LOCA (Ref. 1) demonstrates that only one ECCS injection / spray subsystem is required,-post LOCA, to maintain the peak cladding temperature below the allowable limit. It is reasonable to assume, based on engineering judgement, that while in MODES 4 and 5, one ECCS subsystem can maintain adequate reactor vessel water level. To provide redundancy, a minimum of two ECCS subsystems are required to be OPERABLE in MODES 4 and 5.

The ECCS satisfy Criterion 3 of the NRC. Policy Statement.

LC0 Two ECCS injection / spray subsystems are required to be OPERABLE. At.least one of the required ECCS' subsystems must have a OPERABLE diesel generator capable of. supplying electrical power. The ECCS injection / spray subsystems are defined as the three LPCI subsystems, the LPCS System, and the HPCS System. The LPCS System and each LPCI subsystem consist of one motor driven pump, piping, and valves to transfer water from the suppression pool to the reactor pressure vessel (RPV). The HPCS System consists of one motor driven pump, piping, and valves to transfer water from the suppression pool or condensate storage tank (CST) to the RPV.

One LPCI subsystem may be aligned for decay heat removal in MODE 4 or 5 and considered OPERABLE for the ECCS function, if it can be manually realigned (remote or local) to the (continued)

GRAND GULF B 3.5-15 Revision No. 1

ECCS-Shutdown B 3.5.2 BASES LC0 LPCI mode and is not otherwise inoperable. Because of low (continued) pressure and low temperature conditions in MODES 4 and 5, sufficient time will be available to manually align and initiate LPCI subsystem operation to provide core cooling prior to postulated fuel uncovery.

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(continued)

GRAND GULF B 3.5-15a Revision No. 1

PAGE INTENTIONALLY LEFT BLANK I

ECCS-Shutdown B 3.5.2 BASES (continued)

APPLICABILITY OPERABILITY of the ECCS injection / spray subsystems is required in MODES 4 and 5 to ensure adequate coolant inventory and sufficient heat removal capability for the irradiated fuel in the core in case of an inadvertent draindown of the vessel. Requirements for ECCS OPERABILITY during MODES 1, 2, and 3 are discussed in the Applicability section of the Bases for LC0 3.5.1. ECCS subsystems are not required to be OPERABLE during MODE 5 with the upper containment reactor cavity and transfer canal gates removed, and the water level maintained at 2: 22 ft 8 inches above the RPV flange. This provides sufficient coolant inventory to albw operator action to terminate the inventory loss prior to fuel uncovery in case of an inadvertent draindown.

The Automatic Depressurization System is not required to be OPERABLE during MODES 4 and 5 because the RPV pressure is '

< 150 psig, and the LPCS, HPCS, and LPCI subsystems can provide core cooling without any depressurization of the primary system.

ACTIONS A.1 and B.1 If any one required ECCS injection / spray subsystem is inoperable, the required inoperable ECCS injection / spray subsystem must be restored to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . In this Condition, the remaining OPERABLE subsystem can provide sufficient RPV flooding capability to recover from an inadvertent vessel draindown. However, overall system reliability is reduced because a single failure in the remaining OPERABLE subsystem concurrent with a vessel draindown could result in the ECCS not being able to perform its intended function. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time for restoring the required ECCS injection / spray subsystem to OPERABLE status is based on engineering judgment that considered the availability of one subsystem and the low probability of a vessel draindown event.

With the inoperable subsystem not restored to OPERABLE status within the required Completion Time, action must be initiated immediately to suspend operations with a potential for draining the reactor vessel (0PDRVs) to minimize the p;obability of a vessel draindown and the subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

(continued)

GRAND GULF B 3.5-16 Revision No. I k

ECCS-Shutdown i B 3.5.2 l BASES i

SURVEILLANCE SR 3.5.2.4 (continued)

REQUIREMENTS initiation signal is allowed to be in a nonaccident position :

provided the valve Hll automatically reposition in the proper stroke time. This SR does not require any testing or ;

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. l In MODES 4 and 5, the RHR System may operate in the shutdown i 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 1 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 inadvertent vessel draindown should occur.

SR 3.5.2.7 l This SR ensures that the HPCS System response time is less than or equal to the maximum value assumed in the accident analysis. Specific testing of the ECCS actuation 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 :.ctuation 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 specific measurement test. The diesel generator starting i and any sequence loading delays must be added to the HPCS 1 System equipment response times-to obtain the HPCS System ECCS SYSTEM RESPONSE TIME. The acceptance criterion for the HPCS System ECCS SYSTEM RESPONSE TIME is s 27 seconds.

(continued)

GRAND GULF B 3.5-19 Revision No. 1

ECCS-Shutdown B 3.5.2

' BASES SURVEILLANCE SR 3.5.2.7 (continued)

REQUIREMENTS HPCS System ECCS SYSTEM RESPONSE TIME tests are conducted every 18 months. This Frequency is consistent with the I typical industry refueling cycle and is based on industry operating experience.

REFERENCES 1. UFSAR, Section 6.3.3.4.

1 GRAND GULF B 3.5-20 Revision No. 1

l i

PCIVs i B 3.6.1.3 I BASES I l

ACTIONS A.1 and A.2 (continued) periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident, and no longer capable of being automatically

. isolated, will be isolated should an event occur. This ,

Required Action does not require any testing or device !

manipulation. Rather, it involves verification that those l devices outside primary containment, drywell, and steam tunnel and capable of being mispositioned are in the correct position. The Completion Time for this verification of !

"once per 31 days for isolation devices outside primary containment, drywell, and steam tunnel," is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low.

For devices inside primary containment, drywell, or steam tunnel, the specified time period of " prior to entering MODE 2 or 3 from MODE 4, if not performed within the previous 92 days," is based on engineering judgment and is j considered reasonable in view of the inaccessibility of the .

devices and the existence of other administrative controls l ensuring that device misalignment is an unlikely possibility. )

Required Action A.2 is modified by a Note that applies to isolation devices located in high radiation areas and allows them to be verified by use of administrative means. .

Allowing verification by administrative means is considered I acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment; once they have been verified to be in the proper position, ;

is low. '

B.1 With one or more penetration flow paths with two PCIVs inoperable except due to leakage not within limits, either the inoperable PCIVs must be restored to OPERABLE status or ;

the affected penetration flow path must be isolated within I hour. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers ;

that meet this criterion are a closed and de-activated-automatic valve, a closed manual valve, and a blind flange. I The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LC0 3.6.1.1. .

(continued)

Y GRAND GULF B 3.6-18 Revision No. 1 l

PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.3 (continued)

REQUIREMENTS to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. For devices inside primary containment, drywell, or steam tunnel, the Frequency of " prior to entering MODE 2 or 3 from MODE 4, if not performed within the previous 92 days", is appropriate since these devices are operated under administrative controls and the probability of their misalignment is low.

Two Notes are added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing ;

verification by administrative controls is considered acceptable since access to these areas is typically restricted during MODES 1, 2, and 3. Therefore, the probability of misalignment of these devices, once they have been verified to be in their proper position, is low. A second Note is included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.

SR 3.6.1.3.4 Verifying the isolation time of each power operated and each i automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3.6. l The isolation time test ensures that the valve will isolete in a time period less than or equal to that assumed in the safety analysis. Generally, PCIVs in a direct leak path (open path from containment to environs) must close more rapidly than PCIVs in indirect leak paths. Maximum isolation times are based on system performance requirements, equipment qualification, regulatory requirements, or offsite dose analyses for specific accidents. These requirements ensure the radiological consequences do not exceed the guideline values established by the applicable regulatory documents (10CFR 100 or GDC 19). Closure times explicitly assumed in accident analyses are listed in UFSAR Table 6.2-44 Note d. The Frequency of this SR is in accordance with the Inservice Testing Program.

(continued)

GRAND GULF B 3.6-23 Revision No. 1

PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.5 (continued)

REQUIREMENTS 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 j observation, and the importance of maintaining this <

penetration leak tight (due to the direct path between primary containment and the environment), a Frequency of 184 days was established. Additionally, this SR must be performed within 92 days after opening the valve. The 92 day Frequency was chosen recognizing that cycling the valve could introduce additional seal degradation (beyond that which occurs to a valve that has not been opened).

Thus, decreasing-the interval (from 184 days) is a prudent measure after a valve has been opened.

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 i valve leakage must be minimized to ensure offsite i radiological release is within limits. At other times when i 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.

1 l

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 that the MSIV will isolate in a time period that does not 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. !

(continued)

GRAND GULF B 3.6-24 Revision No. 1

PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.7 REQUIREMENTS (continued) ' 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 I

(continued)

GRAND GULF B 3.6-24a Revision No. 1

- -s - e-PAGE INTENT 10NALLY LEFT BLANK I

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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 i 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 leakage 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 i 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 leakage limits =

are not required. The Frequency is required by 10 CFR 50, Appendix J (Ref. 3), as modified by approved exemptions; thus, SR 3.0.2 (which allows Frequency extensions) does not :

apply, i SR 3.6.1.3.9 Surveillance of hydrostatically tested lines provides assurance that the calculation assumptions of Reference 2 is met. The combined leakage rates must.be demonstrated at the frequency of the leakage test requirements of Reference 3, as modified by approved exemptions; thus, SR 3.0.2 (which allows Frequency extensions) does not apply. l This SR is modified by a Note that states these valves are only required to meet the combined leakage rate in MODES 1, i 2, and 3 since this is when the Reactor Coolant System is l (continued)

GRAND GULF B 3.6-25 Revision No. 1

.s .

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PCIVs B 3.6.1.3 BASES ;

i l SURVEILLANCE SR 3.6.1.3.9 (continued) l REQUIREMENTS pressurized and primary containment is required. In some instances, the valves are required to be capable of '

automatically closing during MODES other.than MODES 1, 2, and 3. However, specific leakage limits are not applicable in these other MODES or conditions. <

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REFERENCES 1. UFSAR, Chapter 15.

l L 2. UFSAR, Section 6.2.

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3. 10 CFR 50, Appendix J. ;

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GRAND GULF B 3.6-25a Revision No. I t.

Primary Containment Air Temperature B 3.6.1.5 ,

BASES I SURVEILLANCE- SR 3.6.1.5.1 (continued)

REQUIREMENTS The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR is considered acceptable based on observed slow rates of temperature increase within primary containment as a result of environmental heat sources (due to large volume of the primary containment).

Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal primary containment air temperature condition.

REFERENCES 1. UFSAR, Section 6.2.

GRAND GULF B 3.6-31 Revision No. 1

FWLCS B 3.6.1.8 BASES (continued)

SURVEILLANCE SR 3.6.1.8.1 REQUIREMENTS Proper operation of the RHR jockey pump is required to verify the capability of the FWLCS to provide sufficient sealing water to each isolated section of each feedwater line to initiate and maintain the fluid seal for long term leakage control. The 31 day Frequency is considered adequate based on operating experience, on the procedural controls governing ECCS operation, and on the low probability of major changes in pump capability-during the period.

REFERENCES 1. UFSAR, Section 15.6.5.

GRAND GULF B 3.6-43 Revision No. 1

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MSIV LCS B 3.6.1.9 BASES ACTIONS C.1 and C.2 (continued)

If the MSIV LCS subsystem cannot be restored to OPERABLE status 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . 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.

l SURVEILLANCE SR 3.6.1.9.1 REQUIREMENTS i Each outboard MSIV LCS blower is operated for a 15 minutes I to verify OPERABILITY. The 31 day Frequency was developed i considering the known reliability of the LCS blower and I controls, the two subsystem redundancy, and the low I probability of a significant degradation of the MSIV LCS subsystem occurring between surveillances and has been shown l to be acceptable through operating experience.

l SR 3.6.1.9.2 l DELETED SR 3.6.1.9.3 A system functional test is performed to ensure that the MSIV LCS 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 correct, that the blowers start and develop the required flow rate and the necessary vacuum, and the upstream heaters meet current or wattage draw requirements. The 18 month l

(continued)

GRAND GULF B 3.6-46 Revision No. 1

Drywell Purge System i B 3.6.3.3 i

BASES !

B.1 and B.2 ACTIONS. (continued) provided by one division of the hydrogen igniters. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time allows a reasonable period of time to ;

verify that a loss of hydrogen control function does not exist. The verification may be performed as an administrative check by examining logs or other information to determine the ~ availability of the alternate hydrogen control system. It does not mean to perform the '

surveillances needed to demonstrate OPERABILITY of the alternate hydrogen control system. If the ability to perform the hydrogen control function is maintained, continued operation is permitted with two drywell purge subsystems inoperable for up to 7 days. Seven days is a reasonable ;

time to allow two drywell purge subsystems to be inoperable because the hydrogen control function is maintained and because of the low probability of the occurrence of a LOCA .

that would generate hydrogen in amounts capable of exceeding :

the flammability limit.

C.1 If any Required Action and associated Completion Time cannot- ,

be met, the plant must be brought to a MODE in which the LC0 1 does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 3.6.3.3.1 REQUIREMENTS Performance of a CHANNEL FUNCTIONAL TEST demonstrates the ;

associated channel will function properly. Any setpoint i adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The 31 day Frequency is reasonable, based on operating experience. !

SR 3.6.3.3.2 ,

Operating each drywell purge subsystem from the control room i for a: 15 minutes ensures that each subsystem is OPERABLE and I

(continued)

GRAND GULF B 3.6-81 Revision No. 1

. . . . ._. ~_ .. _ _ _.

l Drywell Purge Systc.5 B 3.6.3.3 BASES SURVEILLANCE SR 3.6.3.3.2 (continued)

REQUIREMENTS that all associated controls are functioning properly. It also ensures that blockage, compressor failure, or excessive vibration can be detected for corrective action. The 92 day Frequency is consistent with Inservice Testing Program Frequencies, operating experience, the known reliability of the compressor and controls, and the two redundant subsystems available.

SR 3.6.3.3.3 Operating each drywell purge subsystem for a 15 minutes and verifying that each drywell purge subsystem flow rate is a 1000 scfm ensures that each subsystem is capable of maintaining drywell hydrogen concentrations below the flammability limit. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage when the drywell boundary is not required. 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.

SR 3.6.3.3.4 This SR verifies that the pressure differential required to open the vacuum breakers is 5 1.0 psid and that the isolation valve differential pressure actuation instrumentation opens the valve at 0.0 to 1.0 psid (drywell minus containment). This SR includes a CHANNEL CALIBRATION of the isolation valve differential pressure actuation instrumentation. 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. Regulatory Guide 1.7, Revision 1.

2. UFSAR, Section 6.2.5.

GRAND GULF B 3.6-82 Revision No. 1

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SCIVs B 3.6.4.2 BASES-SURVEILLANCE SR 3.6.4.2.1 (continued)

REQUIREMENTS relatively easy, the 31 day Frequency was chosen to provide added assurance that the SCIVs are in the correct positions.

Two Notes have been added to this SR. The first Note applies to valves, dampers, rupture disks, and blind flanges located in high radiation areas and allows'them to be verified by use of. administrative controls. Allowing verification by administrative controls is considered acceptable, since access.to these areas is typically restricted during MODES 1, 2,.and 3 for ALARA reasons.

Therefore, the probability of misalignment of these SCIVs, once they have been verified to be in the proper position, is low.

A second Note has been included to clarify that SCIVs that are open under administrative controls are not required to meet the SR during the time the SCIVs are open.

SR 3.6.4.2.2 Verifying the isolation time of each power operated and each automatic SCIV is within limits is required to demonstrate OPERABILITY. The isolation time test ensures that the SCIV will isolate in a time period less than or equal to that assumed in the safety analyses. Generally, SCIVs must close within 120 seconds to support the functioning of the Standby Gas Treatment System. SCIVs may have analytical closure times based on a function other than secondary containment isolation, in which case the more restrictive time applies.

The Frequency of this SR is in accordance with the Inservice Testing Program.

SR 3.6.4.2.3 Verifying that each automatic SCIV closes on a secondary containment isolation signal is required to prevent leakage of radioactive material from secondary containment following a DBA or.other accidents. This SR ensures that each automatic SCIV will actuate to the isolation position on a-secondary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.2.5 overlaps this SR to provide complete testing of the safety function. The 18 month (continued)

GRAND GULF B 3.6-94 Revision No. 1 i,

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SCIVs j B 3.6.4.2 ;

l BASES l

l SURVEILLANCE SR 3.6.4.2.3 (continued) l REQUIREMENTS l 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 i Surveillance when performed at the 18 month Frequency. l Therefore, the Frequency was concluded to be acceptable from l a reliability standpoint. j l

REFERENCES 1. UFSAR, Section 15.6.5.

2. UFSAR, Section 6.2.3.

3. UFSAR, Section 15.7.6.

4. UFSAR, Section 15.7.4.

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I GRAND GULF B 3.6-95 Revision No. 1 4

1 SGT System B 3.6.4.3 ,

BASES ACTIONS E.1, E.2, and E.3 (continued) suspended. Suspension of these activities shall not -

preclude completion of movement of a component to a safe position. Also, if applicable, actions must be immediately- ;

initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission -

product release. Action must continue until 0PDRVs are ,

suspended. ;

SURVEILLANCE SR 3.6.4.3.l' REQUIREMENTS _

Operating each SGT subsystem from the control room for 210 I continuous hours ensures that both subsystems are OPERABLE )

and that all associated controls are functioning properly. ;

It also ensures that blockage, fan or motor failure, or l excessive vibration can be detected-for corrective action.

Operation with the heaters on (automatic heater cycling to l maintain temperature) for a 10 continuous hours every 31 days eliminates moisture on the adsorbers and HEPA filters. The 31 day Frequency was developed in i consideration of the known reliability of fan motors and I controls and the redundancy available in the system. i SR 3.6.4.3.2 1

This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The SGT System filter tests are in accordance with Regulatory Guide 1.52 (Ref. 3). The VFTP includes testing HEPA filter- performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specified test frequencies and additional information are discussed in detail in the VFTP.

SR 3.6.4.3.3 I This SR requires verification that each SGT subsystem starts ;

upon receipt of an actual or simulated initiation signal. l l

(continued) .j GRAND GULF B 3.6-100 Revision No. 1

Drywell B 3.6.5.1 BASES (continued)

ACTIONS A.I. ,

In the event the drywell is inoperable, it must be restored -

to OPERABLE status within I hour. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining the drywell OPERABLE during MODES 1, 2, and 3. This time period also ;

ensures that the probability of an accident (requiring !

drywell 0PERABILITY) occurring.durir.1 periods when the !

drywell is inoperable is minimal. Also, the Completion Time l is the same as that applied to inoperability of the primary containment in LC0 3.6.1.1, " Primary Containment."

1 B.1 and B.2 If the drywell cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a j 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . 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 I challenging plant systems. l l

SURVEILLANCE SR 3.6.5.1.1 REQUIREMENTS The analyses in Reference 2 are based on a maximum drywell bypass leakage. This Surveillance ensures that the actual drywell bypass leakage is less than or equal to the acceptable A/VTc design value of 0.9 ft assumed in the safety analysis. The testing is performed from an initial differential pressure of 3.0 psid with one airlock door open (the airlock door remaining open is changed for the performance of each required test) and the drywell bypass leakage is calculated from the measured leakage. As left drywell bypass leakage, prior to the first startup after performing a required drywell bypass leakage test, is required to be $ 10% of the drywell bypass leakage limit.

At all other times between required drywell leakage rate .

tests, the acceptance criteria is based on design AA/Tc. i At the design A /VTc the containment temperature and .!

pressurization response are bounded by the assumptions of i (continued) i GRAND GULF B 3.6-104 Revision No. 1 i

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Drywell y B 3.6.5.1 l

BASES SURVEILLANCE SR 3.6.5.1.1 (continued)

REQUIREMENTS the safety analysis. The leakage test is performed every 18 ,

months, consistent with the difficulty of performing the 1 test, risk of high radiation exposure, and the remote I possibi ity that a component failure that is not identified l

by some other drywell or primary containment SR might occur.

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.

1 SR 3.6.5.1.2 The exposed accessible drywell interior and exterior surfaces are inspected to ensure there are no apparent physical defects that would prevent the drywell from performing its intended function. This SR ensures that !

drywell structural integrity is maintained. The Frequency '

was chosen so that the interior and exterior surfaces of the ,

drywell can be inspected in conjunction with the inspections l of the primary containment required by 10 CFR 50, Appendix J (Ref. 2). Due to the passive nature of the drywell structure, the specified Frequency is sufficient to identify component degradation that may affect drywell structural integrity. j l

REFERENCES 1. UFSAR, Chapter 6 and Chapter 15. j

2. 10 CFR 50, Appendix J.

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GRAND GULF B 3.6-105 Revision No. 1 i

Drywell Air Temperature B 3.6.5.5 BASES (continued)

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining drywell average air temperature within the limit is not required in MODE 4 or 5.

ACTIONS A.1 When the drywell average air temperature is not within the limit of the LCO, it must be restored within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The Required Action is necessary to return operation to within the bounds of the safety analyses. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is acceptable, considering the sensitivity of the analyses to variations in this parameter, and provides sufficient time to correct minor problems.

B.1 and B.2 If drywell average air temperature cannot be restored to within limit within the associated 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 l at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within :

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant i conditions from full power conditions in an orderly manner and without challenging plant systems. j SURVEILLANCE SR 3.6.5.5.1 REQUIREMENTS Verifying that the drywell average air temperature is within the LC0 limit ensures that operation remains within the limits assumed for the drywell analysis. Drywell air temperature is monitored in all quadrants and at various elevations. Since the measurements are uniformly distributed, an arithmetic average is an accurate representation of actual drywell average temperature.

(continued)

GRAND GULF B 3.6-124 Revision No. 1

Drywell Air Temperature B 3.6.5.5 BASES SURVEILLANCE SR 3'.6.5.5.1 (continued)

REQUIREMENTS The drywell average air temperature is the arithmetical average of the temperatures at the following' locations:

Elevation Azimuth

a. -119'-0" 20's A s 70*

b. -119'-0" 110's A s 160'

c. -119'-0" 200's A s 250'

d. -119'-0" 290's A s 340'

e. -139'-0" 20's A s 70' I

f. -139'-0" 110's A s 160'

g. -139'-0" 200's A s 250'

h. -139'-0" 290's A s 340' l

i. -166'-0" 20's A s 70'

j. -166'-O' 110's A s 160'

k. -166'-0" 200's A s 250'

1. -166'-0" 290's A s 340' The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of the SR was developed based on operating experience related to variations in drywell average air temperature variations during the applicable MODES. Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal drywell air temperature condition.

REFERENCES 1. UFSAR, Section 6.2.

GRAND GULF B 3.6-125 Revision No. 1

Drywell Vacuum Relief Systen B 3.6.5.6 BASES SURVEILLANCE SR 3.6.5.6.2 (continued)

REQUIREMENTS This Surveillance includes a CHANNEL FUNCTIONAL TEST of the isolation valve differential pressure actuation instrumentation. This provides assurance that the safety analysis assumptions are valid. The Frequency of this Surveillance is in accordance with Inservice Test Program.

SR 3.6.5.6.3 Verification of the opening pressure differential is necessary to ensure that the safety analysis assumption that the vacuum breaker or isolation valve will open fully at a differential pressure of 1.0 psid is valid. This SR verifies that the pressure differential required to open the vacuum breakers is < 1.0 psid and that the. isolation valve differential pressure actuation instrumentation opens the valve at 0.0 to 1.0 psid for the drywell purge vacuum relief subsystem and -1.0 to 0.0 psid for the post-LOCA vacuum I relief subsystems (drywell minus containment). This SR-includes a CHANNEL CALIBRATION of the isolation valve differential pressure actuation instrumentation. This Surveillance includes a calibration of the position indication as necessary. The 18 month Frequency is based on the need to perform this Surveillance unde.' the conditions that apply during a plant outage and the potential for violating the drywell boundary. Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 6.2.

GRAND GULF B 3.6-130 Revision No. 1

CRFA System i B 3.7.3 BASES APPLICABLE is assumed to operate following a loss of coolant accident, SAFETY ANALYSES main steam line break, fuel handling accident, and control (continued) rod drop accident. The radiological doses to control room personnel as a result of the various DBAs are summarized in Reference 4. No single active or passive failure will cause the loss of outside or recirculated air from the control room.

The CRFA System satisfies Criterion 3 of the NRC Policy Statement.

LCO Two redundant subsystems of the CRFA System are required to be OPERABLE to ensure that at least one is availabic, assuming a single failure disables the other subsystem.

Total system failure could result in a failure to meet the dose requirements of GDC 19 in the event of a DBA.

The CRFA System is considered OPERABLE when the individual components necessary to control operator exposure are OPERABLE in both subsystems. A subsystem is considered OPERABLE when its associated:

a. Fan is OPERABLE;

b. HEPA filter and charcoal adsorber are not excessively restricting flow and are capable of performing their filtration functions; and

c. Heater, demister, ductwork, valves, and dampers are OPERABLE, and air circulation can be maintained.

In addition, the control room boundary must be maintained, including the integrity of the walls, floors, ceilings, ductwork, and access doors. The control room boundary is maintained when the boundary can be rapidly isolated and established to meet in-leakage limits as outlined in Ref. 6.

APPLICABILITY In MODES 1, 2, and 3, the CRFA System must be OPERABLE to control operator exposure during and following a DBA, since the DBA could lead to a fission product release.

In MODES 4 and 5, the probability and consequences of a DBA are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the CRFA System (continued)

GRAND GULF B 3.7-12 Revision No. I l _

CRFA System B 3.7.3 BASES ACTIONS E.1. E.2. and E.3 (continued)

OPDRVs, with .two CRFA subsystems inoperable, action must be taken immediately.to suspend activities that present a potential for releasing radioactivity that might require isolation of the control room. This places the unit in a condition that minimizes risk.

If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblic in the primary and secondary containment must be sui vnd,d immediately. Suspension of these activities sh11 not preclude completion of movement of a component - a safe position. If applicable, actions must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential

.for fission product release. Actions must continue until the OPDRVs are suspended.-.

SURVEILLANCE SR 3.7.3.1 REQUIREMENTS This SR verifies that a subsystem in a standby mode starts from the control room on demand and continues to operate.

Standby systems should be checked periodically to ensure that they start and function properly. As the environmental and normal operating conditions of this system are not severe, testing each subsystem once every month provides an adequate check on this system. Monthly heater operation dries out any moisture accumulated in the charcoal from humidity in the ambient air. Systems with heaters must be I operated for a: 10 continuous hours with the heaters energized. Furthermore, the 31 day Frequency is based on <

the known reliability of the equipment and the two subsystem '

redundancy available.

l SR 3.7.3.2 This SR verifies that the required CRFA testing is performed i in accordance with the Ventilation Filter Testing Program l

(VFTP). The CRFA filter tests are in accordance with ,

Regulatory Guide 1.52 (Ref. 5). The VFTP includes testing {

HEPA filter performance, charcoal adsorber efficiency, j

_ (continued)

GRAND GULF B 3.7-15 Revision No. 1

1 l

CRFA System B 3.7.3 BASES SURVEILLANCE SR 3.7.3.2 (continued)

REQUIREMENTS minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.

SR 3.7.3.3 This SR verifies that each CRFA subsystem starts and operates and that the isolation valves close in s 4 seconds I on an actual or simulated initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.7.1.5 overlaps this SR to provide complete testing of the safety function. While this Surveillance can be performed with the reactor at power, operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 6.5.1.

2. UFSAR, Section 9.4.1.

3. UFSAR, Chapter 6.

4. UFSAR, Chapter 15.

5. Regulatory Guide 1.52, Revision 2, March 1978.

6. Engineering Evaluation Request 95/6213, Engineering Evaluation Request Response Partial Response dated 12/18/95.

GRAND GULF B 3.7-16 Revision No. I

Main Condenser Offgas B 3.7.5 BASES ACTIONS 8.1. B.2. B.3.1. and B.3.2 (continued)

An alternative to Required Actions B.1 and B.2 is to place the unit in a MODE in which the LC0 does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating ,

experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. ,

SURVEILLANCE SR 3.7.5.1 and 3.7.5.2 REQUIREMENTS ,

. SR 3.7.5.2, on a 31 day Frequency, requires an isotopic analysis of an offgas sample to ensure that the required limits are satisfied. The noble gases to be sampled include Xe-133, Xe-135, Xe-138,-Kr-85, Kr-87, and Kr-88. If the offgas pretreatment monitor measured release rate of I' radioactivity increases significantly (by ;t: 50% after correcting for expected increases due to changes in THERMAL POWER), an isotopic analysis is also performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 'after the increase is noted as required by SR 3.7.5.1, to ensure that the increase is not indicative of a ,

sustained increase in the radioactivity rate. The 31 day Frequency is adequate in view of other instrumentation that continuously monitor the offgas, and is acceptable based on operating experience.

SR 3.7.5.2 is modified by a Note indicating that the SR is not required to be performed until 31 days after any SJAE is in operation. Only in this condition can radioactive fission gases be'in the Main Condenser Offgas System at significant rates.

REFERENCES 1. UFSAR, Section 15.7.1.

2. NUREG-0800.

3. 10 CFR 100.

GRM3 GULF B 3.7-24 Revision No. I

Fuel Pool Water Level B 3.7.6 i

BASES (continued)

REFERENCES 1. UFSAR, Section 9.1.2.

2. UFSAR, Section 15.7.4. t

3. UFSAR, Section 15.7.6. t

4. NUREG-0800, Section 15.7.4, Revision 1, July 1981. !

5. 10 CFR~100. i

6. Regulatory Guide 1.25, March 1972.

t I

l GRAND GULF B 3.7-27 Revision No. I l

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AC Sources-Operating 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 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 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.

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 signals: 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.

The normal 31 day Frequency for SR 3.8.1.2 (see Table 3.8.1-1, " Diesel Generator Test Schedule") is consistent with the industry guidelines for assessment of diesel generator performance (Ref.14). These Frequencies provide adequate assurance of DG OPERABILITY, while 3 minimizing degradation resulting from testing.

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(continued) l l

GRAND GULF B 3.8-15 Revision No. 1

AC Sources-0perating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 REQUIREMENTS (continued) This Surveillance demonstrates that the DGs are capable of synchronizing and accepting greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

i (continued) t

( GRAND GULF B 3.8-15a Revision No. I

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AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 (continued)

REQUIREMENTS 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 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 normal 31 day Frequency for this Surveillance (see Table 3.8.1-1) is consistent 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.

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 ,

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 expected post LOCA load.

(continued)

GRAND GULF B 3.8-16 Revision No. 1

AC Sources-0perating B 3.8.1 BASES SVRVEILLANCE SR' 3.8.1.6 (continued)

REQUIREMENTS The design of the fuel transfer systems is such that pumps operate automatically in order to maintain an adequate volume of fuel oil in the day tanks during or following DG testing. Therefore, a 31 day Frequency is specified to correspond to the maximum interval for DG testing.

SR 3.8.1.7 Vnder 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 i breakers to prevent overloading of the bus power supplies due to high motor starting currents. The load sequencing ensures that sufficient time exists for the bus power supply 1 to restore frequency and voltage prior to applying the next l load and that safety analysis assumptions regarding ESF j equipment time delays are not violated. Reference 2 provides a summary of the automatic loading of ESF buses.

This Surveillance is a manual test of the load shedding and sequencing panels and verifies the load shedding and sequencing panels respond within design criteria to the i following test inputs: LOCA, bus undervoltage, bus !

undervoltage followed by LOCA, and LOCA followed by bus l undervoltage. l The Frequency of 31 days is based on engineering judgment, taking into consideration plant conditions required to perform the Surveillance. Operating experience has shown that these components usually pass the SR when performed at the 31 day Frequency. Therefore, the Frequency was I concluded to be acceptable from a reliability standpoint.

SR 3.8.1.8 Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit. The 18 month frequency of the Surveillance is based on engineerhg judgment taking into consideration the plant conditions required to perform the Surveillance, and is (continued)

GRAND GULF B 3.8-18 Revision No. 1

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 (continued)

REQUIREMENTS intended to be consistent with expected fuel cycle lengths.

Operating experience has shown that these components usually pass the SR when performed on the 18 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

GRAND GULF B 3.8-18a Revision No. 1

a..4 4,-J 4. e mu sa A m.A ..~.e m -au-->.m-ea-+Mv. m,w.a.4sA.-..au r - -_- - - - - - - ---w------------ --

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AC Sources-Operating ,

B 3.8.1 l BASES

)

SURVE1LLANCE SR 3.8.1.12 (continued) ;

REQUIREMENTS '

I 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 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 3.8.1.13 This Surveillance demonstrates that DG non-critical protective functions:

Generator loss of excitation, Generator reverse power, High jacket water temperature, Generator overcurrent with voltage restraint, Bus underfrequency (DG 11 and DG 12 only),

Engine bearing temperature high (DG 11 and DG 12 only),

Low turbo charger oil pressure (DG 11 and DG 12 only),

High vibration (DG 11 and DG 12 only),

High lube oil temperature (DG 11 and DG 12 only),

Low lube oil pressure (DG 13 only),

High crankcase pressure, and l Generator ground overcurrent (DG 11 and DG 12 only) are bypassed on an ECCS initiation test signal and critical protective functions trip the DG to avert substantial damage to the DG unit. The non-critical trips are bypassed during DBAs and provide alarms on an abnormal engine conditions, i These alarms provide the operator with necessary information I to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against l (continued)

GRAND GULF B 3.8-25 Revision No. 1

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 (continued)

REQUIREMENTS minor problems that are not immediately detrimental to emergency operation of the DG.

The 18 month Frequency is based on engineering judgment, taking into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

4 l

(continued)

GRAND GULF B 3.8-25a Revision No. 1

r. J.-

4 - = a> a, .er4.

1 l

1 i

PAGE INTENT 10NALLY LEFT BLANK i

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 (continued)

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 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 3.8.1.14 Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(3), requires demonstration once 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s--22 hours of which is at a load i equivalent to the continuous rating of the DG, and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 l 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. i In order to ensure that the DG is tested under load l conditions that are as close to design conditions as l possible, testing must be performed using a power factor (continued) l 1

GRAND GULF B 3.8-26 Revision No. 1 i

AC Sources-Operating B 3.8.1 I

BASES SURVEILLANCE SR 3.8.1.14 (continued)

REQUIREMENTS .

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 i 416 volts and 60 i 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 1.108 (Ref. 9),

paragraph 2.a.(3); takes into consideration plant conditions required to perform the Surveillance; and is intended to be i consistent with expected fuel cycle lengths. i This Surveillance is modified by two Notes. Note 1 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 i order to maintain DG OPERABILITY. Similarly, momentary i power factor transients above the limit do not invalidate the test. The reason for Note 2 is that during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that would 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 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.

(continued)

GRAND GULF B 3.8-27 Revision No. 1

AC Sources--Operating-B 3.8.1

BASES i

SURVEILLANCE SR 3.8.1.15 1

REQUIREMENTS (continued) This Surveillance demonstrates that the diesel engine can

restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage ;

'l I

1 l

i i

(continued)

GRAND GULF B 3.8-27a Revision No. 1

Je .E a ~ , ;*_. -- 7 m .

4_e.-2A%__ ..m.m.. d. _ , ,.. u A_

PAGE INTENTIONALLY LEFT BLANK ll l

i l

I

AC Sources-Operating B 3.8.1 BASES 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 1.108 (Ref. 9),

paragraph 2.a.(5).

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 1.108 (Ref. 9), )

paragraph 2.a.(6), this 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 i voltage, the output breaker is open and can receive an l auto-close signal on bus undervoltage, and the load sequence l logic is reset. ;

The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 9),

paragraph 2.a.(6), and takes into consideration plant ;

conditions required to perform the Surveillance. 1 i

(continued) i GRAND GULF B 3.8-28 Revision No. 1 1

i

AC Sources-0perating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.18 (continued)

REQUIREMENTS I This SR is modified by a Note. The reason for the Note is !

that performing the Surveillance during these MODES would !

challenge plant safety systems. Credit may be taken for l unplanned events that satisfy this SR. Examples of l 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 i

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 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates the DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal. For the purposes of this Surveillance the DG 13 autoconnected emergency loads are verified to be energized in s 20 seconds. In lieu of actual demonstration of connection and loading of 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 the entire connection and loading sequence is verified.

The Frequency of 18 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length of 18 months.

(continued)

GRAND GULF B 3.8-31 Revision No. 1

AC Sources-0perating 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 i 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 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.

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 1.108 (Ref. 9).

(continued)

GRAND GULF B 3.8-32 Revision No. 1

AC Sources-0perating 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 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.

Diesel Generator Test Schedule i The DG test schedule (Table 3.8.1-1) implements the industry guidelines for assessment of diesel generator performance (Ref. 14). The purpose of this test schedule is to provide timely test data to establish a confidence level associated with the goal to maintain DG reliability at > 0.95 per test.

According to the industry guidelines (Ref.14), each DG unit should be tested at leas.t once every 31 days. Whenever a DG has experienced 4 or more valid failures in the last 25 valid tests, the maximum time between tests is reduced to 7 days. Four failures in 25 valid tests is a failure rate of 0.16, or the threshold of acceptable DG performance, and hence may be an early indication of the degradation of DG reliability. When considered in the light of a long history of tests, however, 4 failures in the last 25 valid tests may only be a statistically probable distribution of random events. Increasing the test Frequency allows a more timely accumulation of additional test data upon which to base judgment of the reliabiliity of the DG. The increased test Frequency must be maintained until seven consecutive failure free tests have been performed.

The Frequency for accelerated testing is 7 days, but no less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Tests conducted at intervals of less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months may be credited for compliance with Required Actions. However, for the purpose of re-establishing the normal 31-day Frequency, a successful test at an interval of (continued)

GRAND GULF B 3.8-33 Revision No. 1

AC Sources-0perating B 3.8.1 BASES SURVEILLANCE Diesel Generator Test Schedule (continued)

REQUIREMENTS less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months should be considered an invalid test and not count towards the seven consecutive failure free starts, and the consecutive test count is not reset.

A test interval in excess of 7 days (or 31 days, as appropriate) constitutes a failure to meet SRs and results in the associated DG being declared inoperable. It does not, however, constitute a valid test or failure of the DG, and any consecutive test count is not reset.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17,

2. UFSAR, Chapter 8.

3. Regulatory Guide 1.9.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

6. Regulatory Guide 1.93.

7. Generic Letter 84-15, July 2, 1984.

8. 10 CFR 50, Appendix A, GDC 18,

9. Regulatory Guide 1.108,

10. Regulatory Guide 1.137.

11. ANSI C84.1, 1982.

I

12. ASME, Boiler and Pressure Vessel Code,Section XI.

13. IEEE Standard 308.

14. NUMARC 87-00, Revision 1, August 1991.

15. Letter from E.G. Adensam to L.F. Dale, dated July i 1984.

l GRAND GULF B 3.8-34 Revision No. 1

{

l

\ - - .

l, Diesel Fuel Oil, Lube Oil, and Starting Air B 3. 3.3 BASES ACTIONS B.1 (continued) based on the remaining capacity (> 6 days), the low rate of usage, the fact that procedures will be initiated to obtain replenishment, and the low probability of an event during this brief period.

C.1 This Condition is entered as a result of a failure to meet l the acceptance criterion for particulates. Normally, trending of particulate levels allows sufficient time to i correct high particulate levels prior to reaching the limit '

of acceptability. Poor sample procedures (bottom sampling),

contaminated sampling equipment, and errors in ' laboratory analysis can produce failures that do not follow a trend.

Since the presence of particulate does not mean failure of ,

the fuel oil to burn properly in the diesel engine, since j particulate concentration .is unlikely to change ;

significantly between Surveillance Frequency intervals, and since proper engine performance has been recently demonstrated (within 31 days), it is prudent to allow a brief period prior to declaring the associated DG l inoperable. The 7 day Completion Time allows for further !

evaluation, resampling, and re-analysis of the DG fuel oil. I l

D.1 With the new fuel oil properties defined in the Bases for SR 3.8.3.3 not within the required limits, a period of 30 days is allowed for restoring the stored fuel oil properties. This period provides sufficient time to test the stored fuel oil to determine that the new fuel oil, when mixed with previously stored fuel oil, remains acceptable, to restore the stored fuel oil properties. This restoration i may involve feed and bleed procedures, filtering, or a combination of these procedures. Even if a DG start and load was required during this time interval and the fuel oil properties were outside limits, there is high likelihood that the DG would still be capable of performing its intended function, t

(continued) I GRAND GULF B 3.8-45 Revision No. 1

l Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 l

l BASES I l

SURVEILLANCE SR 3.8.3.3 REQUIREMENTS :

(continued) The tests of fuel oil prior to addition to the storage tanks ,

are a means of determining whether new fuel oil is of the I appropriate grade and has not been contaminated with substances that would have an immediate detrimental impact on diesel engine combustion and operation. If results from these tests are within acceptable limits, the fuel oil may be added to the storage tanks without concern for i contaminating the entire volume of fuel oil in the storage i tanks. These tests are to be conducted prior to adding the new fuel to the storage tank (s). The limits and applicable I ASTM Standards for the tests listed in the Diesel Fuel Oil l Testing Program of Specification 5.5.9 are to verify in I accordance with the tests specified in ASTM D975-92a I (Ref. 6) that the sample has a water and sediment content of l s 0.05 v/o, and a kinematic viscosity at 40*C of a: 1.9 l centistokes and s 4.1 centistokes.

These tests are required every 92 days for fuel oil in the storage tanks and prior to addition for new fuel oil by ,

Specification 5.5.9. Failure to meet any of the above 1 limits is cause for rejecting the new fuel oil, but does not represent a failure to meet the LC0 since the fuel oil is not added to the storage tanks. j Following the initial new fuel oil sample, the fuel oil is I analyzed to establish an impurity level of < 2 ng/100 ml 1 when tested in accordance with ASTM 2274-70 (Ref. 6). These additional analyses are required by Specification 5.5.9, I Diesel Fuel Oil Testing Program, to be performed within 7 days following addition. The 7 day period is acceptable I because the fuel oil properties of interest, even if not within stated i l

l l

(continued)

GRAND GULF B 3.8-47 Revision No. 1

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 i l

l I

BASES SURVEILLANCE SR 3.8.3.5 REQUIREMENTS I

(continued) Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water l environment in order to survive. Removal of water from the l storage tanks once every 92 days eliminates the necessary ;

environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and from breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 2). This SR is for preventive maintenance. The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of the Surveillance.

SR 3.8.3.6 Draining of the fuel oil stored in the supply tanks, removal of accumulated sediment, and tank cleaning are required at 10 year intervals by Regulatory Guide 1.137 (Ref. 2),

paragraph 2.f. This SR is typically performed in conjunction with the ASME Boiler and Pressure Vessel Code,Section XI (Ref. 7), examinations of the tanks. To preclude the introduction of surfactants in the fuel oil system, the cleaning should be accomplished using sodium hypochlorite solutions, or their equivalent, rather than soap or l detergents. This SR is for preventive maintenance. The I presence of sediment does not necessarily represent a failure of this SR provided that accumulated sediment is removed during performance of the Surveillance.

REFERENCES 1. UFSAR, Section 9.5.4.

1

2. Regulatory Guide 1.137.

3. ANSI N195, Appendix B, 1976.

(continued)

GRAND GULF B 3.8-49 Revision No. I

u- - - . - - . . ,= -san. ~ - ....a u. - n z - ~

1 DC Sources-Operating !

B 3.8.4 BASES APPLICABLE a. An assumed loss of all offsite AC power or of all I SAFETY ANALYSES onsite AC power; and i (continued)

b. A worst case single failure.

The DC sources satisfy Criterion 3 of the NRC Policy Statement.

LC0 The DC electrical power subsystems are required to be OPERABLE to ensure the availability of the required power to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (A00) or a postulated DBA. The DC electrical power subsystems consist of: i

a. Division 1

1. 125 volt battery 1A3 and

2. 125 volt full capacity charger IA4 or 1AS,

b. Division 2

1. 125 volt battery 183 and

2. 125 volt full capadty charger 184 or 185,

c. Division 3 l

1. 125 volt battery IC3 and

2. 125 volt full capacity charger 104, and the corresponding control equipment and interconnecting cabling supplying power to the associated bus within the divisions. Loss of any DC electrical power subsystem does not prevent the minimum safety function from being performed (Ref. 4).

APPLICABILITY The DC electrical power sources are required to be OPERABLE !

in MODES 1, 2, and 3 to ensure safe unit operation and to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of A00s or abnormal transients; and (continued)

GRAND GULF B 3.8-53 Revision No. 1

DC Sources--Operating B 3.8.4 BASES APPLICABILITY b. Adequate core cooling is provided, and containment (continued)- integrity and other vital functions are maintained in the event of a postulated DBA.

The DC electrical power requirements for MODES 4 and 5 are addressed in the Bases for LC0 3.8.5, "DC Sources--

Shutdown." .

l ACTIONS A.1 Condition A represents one division with a loss of ability to completely respond to a long term event, and a potential loss of ability to remain energized during normal operation.

Since eventual failure of the battery to maintain the required battery cell parameters is highly probable, it is l

(continued)

GRAND GULF B 3.5-53a Revision No. 1

_a--_ _. 4 . -- e.,, m-__wa .._a.4..m. s mA - A.m, _ . . ,+ws, ss_.e _ ap.,m_ m ,_.m a --mm.m us._,,a m-..- w_-mmp a m. 4 e, ., _4 l

1 PAGE INTENTIONALLY LEFT BLANK i

i

DC Sources-0perating B 3.8.4 BASES ACTIONS A.1 (continued) imperative that the operator's attention focus on stabilizing the unit, minimizing the potential for complete loss of DC power to the affected division. The additional time provided by the Completica Time is consistent with the capability of the battery to maintain its short term capability to respond to a design basis event.

A Note is added to take exception to the allowance of LC0 3.0.4 to enter MODES or other specified conditions in the Applicability. Even though Condition A Required Actions do not in themselves require a plant shutdown, or require exiting the MODES or other specified conditions in the Applicability, the condition of the DC system is not such that extended operation is expected. Therefore, the Note would require restoration of an inoperable battery charger to OPERABLE status prior to increasing power. This exception is not intended to preclude the allowance of LC0 3.0.4 to always enter MODES or other specified conditions in the Applicability as a result of a plant shutdown.

B.1 If the battery cell parameters cannot be maintained within the Category A limits, the short term capability of the !

battery is also degraded and the battery must be declared I inoperable.

C.1 Condition C represents one division with a loss of ability to completely respond to an event, and a potential loss of !

ability to remain energized during normal operation. It is, therefore, imperative that the operator's attention focus on i stabilizing the unit, minimizing the potential for complete I loss of DC power to the affected division. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months limit is consistent with the allowed time for an inoperable DC distribution systen division.

l (continued) l GRAND GULF B 3.8-54 Revision No. 1

DC Sources-Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.7 REQUIREMENTS )

(continued) A battery service test is a special test of the battery's ,

capability, as found, to satisfy the design requirements 1 (battery duty cycle) of the DC electrical power system. The discharge rate and test length (4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for Division 1 and Division 2 and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for Division 3) correspond to the design duty cycle requirements as specified in Reference 4. j The Surveillance Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.32 (Ref. 9) and Regulatory Guide 1.129 (Ref.10), which state that the battery service test should be performed during refueling operations or at some other outage, with intervals between tests not to exceed 18 months.

This SR is modified by two Notes. Note 1 allows the once per 60 months performance of SR 3.8.4.8 in lieu of SR 3.8.4.7. This substitution is acceptable because SR 3.8.4.8 represents a more severe test of battery capacity than SR 3.8.4.7. The reason for Note 2 is that performing the Surveillance would remove a required DC electrical power subsystem from service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy the Surveillance.

SR 3.8.4.8 A battery performance test is a test of constant current capacity of a battery, normally done in the as found condition, after having been in service, to detect any change in the capacity determined by the acceptance test.

The test is intended to determine overall battery degradation due to age and usage.

The acceptance criteria for this Surveillance is consistent with IEEE-450 (Ref. 8) and IEEE-485 (Ref. 11). These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating. A l capacity of 80% shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load requirements.

(continued)

GRAND GULF B 3.8-58 Revision No. 1

DC Sources-0perating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.8 (continued)

REQUIREMENTS The Surveillance Frequency for this test is normally 60 months. If the battery shows degradation, 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 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 a 100% of the ;

manufacturer's rating. Degradation is indicated, according '

to !EEE-450 (Ref. 8), when the battery capacity drops by more than 10% relative to its capacity on the previous 1 performance test or when it is 210% below 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 from service, perturb the ,

electrical distribution system, and challenge safety :

systems. Credit may be taken for unplanned events that I 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. I

8. IEEE Standard 450, 1987.

9. Regulatory Guide 1.32, February 1977.

i

10. Regulatory Guide 1.129, December 1974.

11. IEEE Standard 485.

GRAND GULF B 3.8-59 Revision No. 1

Battery Cell Parameters B 3.8.6 BASES ACTIONS A.1, A.2, and A.3 (continued)

Continued operation is only permitted for 31 days before !

battery cell parameters must be restored to within i Category A and B limits. Taking into consideration that !

while battery capacity is degraded, sufficient capacity exists to perform the intended function and to allow time to fully restore the battery cell parameters to normal limits, this time is acceptable for operation prior to declaring the DC batteries inoperable.

B.1 When any battery parameter is outside the Category C limit for any connected cell, sufficient capacity to supply the maximum expected load requirement is not assured and the corresponding DC electrical power subsystem must be declared i inoperable. Additionally, other potentially extreme l conditions, such as not completing the Required Actions of Condition A within the required Completion Time or average electrolyte temperature of representative cells falling below 60'F, also are cause for immediately declaring the associated DC electrical power subsystem inoperable.

SURVEILLANCE SR 3.8.6.1 REQUIREMENTS The SR verifies that Category A battery cell parameters are consistent with IEEE-450 (Ref. 3), which recommends regular ;

battery inspections including float voltage, specific '

gravity, and electrolyte level of pilot cells. The 7 day Frequency ensures that these inspections are performed within that Frequency recommended by IEEE-450 (Ref. 3).

SR 3.8.6.2 The quarterly inspection of specific gravity and voltage is consistent with IEEE-450 (Ref. 3). In addition, within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months of a battery overcharge > 150 V, the battery must be demonstrated to meet Category B limits. This inspection is also consistent with IEEE-450 (Ref. 3), which recommends special inspections following a severe discharge or overcharge, to ensure that no significant degradation of the battery occurs as a consequence of such overcharge.

(continued)

GRAND GULF B 3.8-67 Revision No. 1

Battery Cell Parameters B 3.8.6 BASES SURVEILLANCE SR 3.8.6.3 REQUIREMENTS (continued) This Surveillance verification that the average temperature of representative cells (every sixth connected cell) is I a 60*F is consistent with a recomendation of IEEE-450 (Ref. 3), which states that the temperature of electrolytes in representative cells should be determined on a quarterly basis.

Lower than normal temperatures act to inhibit or reduce battery capacity. This SR ensures that the operating temperatures remain within an acceptable operating range.

This limit is based on manufacturer's recomendations.

Table 3.8.6-1 This table delineates the limits on electrolyte level, float voltage, and specific gravity for three different.

categories. The meaning of each category is discussed below.

Category A defines the normal parameter limit for each designated pilot cell in each battery. The cells selected as pilot cells are those whose level, float voltage, and level, float specific gravity approximate the state of charge of the entire battery.

The Category A limits specified for electrolyte level are based on manufacturer's recommendations and are consistent with the guidance in IEEE-450 (Ref. 3), with the extra 1/4 inch' allowance above the high water level indication for operating margin to account for temperature and charge effects. In addition to this allowance, footnote a to Table 3.8.6-1 permits the electrolyte level to be above the specified maximum level during equalizing charge, provided it is not overflowing. These limits ensure that the plates suffer no physical damage, and that adequate electron transfer capability is maintained in the event of transient conditions. IEEE-450 (Ref. 3) recommends that electrolyte level readings should be made only after the battery has been at float charge for at least 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

The Category A limit specified for float voltage is a 2.13 V per cell. This value is based on the recommendation of IEEE-450 (Ref. 3), which states that prolonged operation of cells below 2.13 V can reduce the life expectancy of cells.

(continued)

GRAND GULF B 3.8-68 Revision No. 1

1 Distribution Systems-Shutdown B 3.8.8 BASES ACTIONS A.1, A.2.1. A.2.2 A.2.3, A.2.4, and A.2.5 (continued) would not be entered. Therefore, Required Action A.2.5 is provided to direct declaring RHR-SDC inoperable, which results in taking the appropriate RHR-SDC ACTIONS.

The Compietion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required distribution subsystems should be completed as quickly as possible in order to minimize the time the plant safety systems may be without power.

SURVEILLANCE SR 3.8.8.1 REQUIREMENTS This Surveillance verifies that the required AC and DC electrical power distribution subsystems are functioning properly, with the buses energized. The verification of proper voltage availability on the required buses ensures that the required power is readily available for motive as well as control functions for critical system loads connected to these buses. The 7 day Frequency takes into account the redundant capability of the electrical power distribution subsystems, as well as other indications available in the control room that alert the operator to subsystem malfunctions.

REFERENCES 1. UFSAR, Chapter 6.

2. UFSAR, Chapter 15.

GRAND GULF B 3.8-83 Revision No. 1

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Control Rod Position Indication B 3.9.4 BASES (continued)

LC0 One control rod full-in position indication channel for each control rod must be OPERABLE to provide the required inputs to the refueling interlocks. A channel is OPERABLE if it provides correct position indication to the refueling equipment interlock all-rods-in logic (LC0 3.9.1), and correct position indication to at least one channel of the refuel position one-rod-out interlock logic (LC0 3.9.2). The full-in position indication is provided by any combination of reed switches 00, FII, or FI2. For the refueling equipment interlock all-rods-in logic the required full-in position indication channel for each control rod is Channel A. At all other times (when the refueling equipment I interlocks are not required to be OPERABLE) either Channel A or Channel B OPERABILITY for each control rod satisfies the LCO.

APPLICABILITY During MODE 5, the control rods must have OPERABLE full-in position indication channels to ensure the applicable refueling interlocks will be OPERABLE.

In MODES 1 and 2, requirements for control rod position are specified in LC0 3.1.3, " Control Rod OPERABILITY." In MODES 3 and 4, with the reactor mode switch in the shutdown position, a control rod block (LC0 3.3.2.1) ensures all control rods are inserted, thereby preventing criticality during shutdown conditions.

ACTIONS A Note has been provided to modify the ACTIONS related to control rod position indication channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable control rod position indication channels provide appropriate compensatory measures for separate inoperable channels. As such, this Note has been provided, which allows separate Condition entry for each inoperable required control rod position indication channel.

(continued)

GRAND GULF B 3.9-13 Revision No. 1

Control Rod Position Indication B 3.9.4 BASES ACTIONS .A.I.1, A.1.2, A.l.3, A.2.1, and A.2.2 (continued)

With one or more required full-in position indication channels inoperable, compensating actions must be taken to protect against potential reactivity excursions from fuel assembly insertions.or control rod withdrawals. This may be accomplished by immediately suspending in-vessel fuel movement and control rod withdrawal, and immediately

, initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies.

Actions must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted. Suspension of in-vessel fuel movements and control rod withdrawal shall not preclude moving a component to a safe position.

Alternat 4vely, actions may be immediately initiated to fully insert tre control rod (s) associated with the inoperable full-in position indicators (s) and to disarm the drive (s) to ensure that the control rod is not withdrawn. Actions must continue until all associated control rods are fully inserted and drives are disarmed. Under these conditions (control rod fully inserted and disarmed), an inoperable full-in channel may be bypassed to allow refueling operations to proceed. An alternate method must be used to ensure the control rod is fully inserted (e.g., use the "00" or other available position indication). l SURVEILLANCE SR 3.9.4.1 REQUIREMENTS The full-in position indication channels provide input to the one-rod-out interlock and other refueling interlocks that require an all-rods-in permissive. The interlocks are activated when the full-in position indication for any control rod is not present, since this indicates that all rods are not fully inserted. Therefore, testing of the full-in position indication channels is parformed to ensure that when a control rod is withdrawn, tb 'ull-in position indication is not present. The full-in po;,ttion indication channel is considered inoperable even with the control rod fully inserted, if it would continue to indicate full-in with the control rod withdrawn. Performing the SR each time a control rod is withdrawn is considered adequate because of (continued)

GRAND GULF B 3.9-14 Revision No. 1

RHR-High Water Level B 3.9.8 B 3.9 REFUELING OPERATIONS B 3.9.8 Residual' Heat Removal (RHR)-High Water Level BASES BACKGROUND The purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required by GDC 34. Each of the.two shutdown cooling loops of the RHR System is designed to maintain the reactor coolant bulk average temperature .:s; 140'F. Each loop consists of one motor driven pump, two heat exchangers, and associated piping and valves. Both loops have a comon suction from the same recirculation loop. Each pump discharges the reactor coolant, after it has been cooled by circulation through the respective heat exchangers, to the reactor via separate feedwater lines or to the upper containment pool via a comon single flow distribution sparger, or to the reactor via the low pressure coolant injection path. The RHR heat exchangers transfer heat to the Standby Service-Water System. The RHR shutdown cooling mode is manually controlled.

An Alternate Decay Heat Removal System (ADHRS) is also available to provide the required decay heat removal. The ADHRS provides a single. subsystem consisting of two motor driven pumps, two heat exchangers, and associated piping and valves. The system utilizes the comon RHR shutdown cooling suction line and some fuel pool cooling and cleanup piping.

The system is not safety-related and cannot be powered from an onsite diesel generator. The ADHRS heat exchangers i transfer heat to the Plant Service Water System (PSW). The l ADHRS is manually controlled and isolated from the comon !

portions of the other systems.

In addition to the above subsystems, the volume of water above the reactor pressure vessel (RPV) flange provides a heat sink for decay heat removal.

APPLICABLE With the unit in MODE 5, neither the RHR System nor the SAFETY ANALYSES ADHRS is required to mitigate any events or accidents evaluated in the safety analyses. The RHR System, or the ADHRS, is required for removing decay heat to maintain the temperature of.the reactor coolant.

(continued)

GRAND GULF B 3.9-25 Revision No. 1

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RHR-High Water Level B 3.9.8 BASES APPLICABLE Although the RHR System does not meet a specific criterion SAFETY ANALYSES of the NRC Policy Statement, it was identified in the NRC (continued) Policy Statement as an important contributor to risk reduction. Therefore, the RHR System is retained as a Specification. The ADHRS is included in the Specification to provide requirements for decay heat removal capability during an outage while the RHR System is out of service.

LCO Only one RHR shutdown cooling subsystem is required to be OPERABLE in MODE 5 with irradiated fuel in the RPV and the water level 2 22 ft 8 inches above the RPV flange. Only one subsystem is required because the volume of water above the RPV flange provides backup decay heat removal capability.

An OPERABLE RHR shutdown cooling subsystem consists of an RHR pump, two heat exchangers, valves, piping, instruments, and controls to ensure an OPERABLE flow path. The required RHR shutdown cooling subsystem must have a OPERABLE diesel generator capable of supplying electrical power.

Additionally, each RHR shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. Operation (either continuous or intermittent) of one decay heat removal subsystem (either RHR or ADHRS) can maintain and reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow >

for accurate average reactor coolant temperature monitoring, nearly continuous operation is required. A Note is provided to allow a 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months exception to shut down the operating subsystem every 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

APPLICABILITY One RHR shutdown cooling subsystem must be OPERABLE in MODE 5, with irradiated fuel in the RPV and the water level 2 22 ft 8 inches above the top of the RPV flange, to provide decay heat removal. RHR System requirements in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS); Section 3.5, Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC)

System; and Section 3.6, Containment Systems. RHR Shutdown Cooling System requirements in MODE 5, with the water level

< 22 ft 8 inches above the RPV flange, are given in j LC0 3.9.9, " Residual Heat Removal (RHR)-Low Water Level." j i

(continued)

GRAND GULF B 3.9-26 Revision No. 1 l 1

l

RHR-Low Water Level B 3.9.9 8 3.9 REFUELING OPERATIONS B 3.9.9 Residual Heat Removal (RHR)-Low Water Level BASES BACKGROUND The purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required by GDC 34. Each of the two shutdown cooling loops of the RHR System is designed to maintain the reactor coolant bulk average temperature :s; 140'F. Each loop consists of one motor driven pump, two heat exchangers, and associated piping and valves. Both loops have a common suction from the same recirculation loop. Each pump discharges the reactor coolant, after it has been cooled by circulation through the respective heat exchangers, to the reactor via separate feedwater lines, to the upper containment pool via a common single flow distribution sparger, or to the reactor ,

via the low pressure coolant injection path. The RHR heat i exchangers transfer heat to the Standby Service Water System. The RHR shutdown cooling mode is manually 1 controlled. ;

An Alternate Decay Heat Removal System (ADHRS) is also available to provide the required decay heat removal. The ADHRS provides a single subsystem consisting of two motor driven pumps, two heat exchangers, and associated piping and valves. The system utilizes the common RHR shutdown cooling suction line and some fuel pool cooling and cleanup piping.

The system is not safety-related and cannot be powered from an onsite diesel generator. The ADHRS heat exchangers transfer heat to the Plant Service Water System (PSW). The ADHRS is manually controlled and isolated from the common portions of the other systems.

APPLICABLE With the unit in MODE 5, neither the RHR System nor the SAFETY ANALYSES ADHRS is required to mitigate any events or accidents evaluated in the safety analyses. The RHR System, or the ADHRS, is required for removing decay heat to maintain the temperature of the reactor coolant.

Although the RHR System does not meet a specific criterion of the NRC Policy Statement, it was identified in the NRC Policy Statement as an important contributor to risk reduction. Therefore, the RHR System is retained as a (continued)

GRAND GULF B 3.9-29 Revision No. 1

RHR-Low Water Level B 3.9.9 l BASES APPLICABLE Specification. The ADHRS is included in the Specification SAFETY ANALYSES to provide requirements for decay heat removal capability (continued) during an outage while the RHR System is out of service.

LC0: In MODE 5 with irradiated fuel in the reactor pressure i vessel (RPV) and the water level < 22 ft 8 inches above the RPV flange both RHR shutdown cooling subsystems must be OPERABLE, or the ADHRS may be substituted for one of the RHR !

subsystems.

An OPERABLE RHR shutdown cooling subsystem consists of an RHR pump, two heat exchangers, valves, piping, instruments, .

and controls to ensure an OPERABLE flow path. An OPERABLE ADHRS consists of two pumps, two heat exchangers,_ valves, piping, instruments and controls to ensure an OPERABLE flow path. At least one of the required RHR shutdown cooling subsystems must have a OPERABLE diesel generator capable of supplying electrical power. 1 Additionally, each RHR shutdown cooling subsystem is ;

considered OPERABLE if it can be manually aligned (remote or -

local) in the shutdown cooling mode for removal of decay !

heat. Operation (either continuous or intermittent) of one l decay heat removal subsystem (either RHR or ADHRS) can maintain and reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required. A Note is provided to ~ allow a 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months exception to shut down the operating subsystem every 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

APPLICABILITY Two decay heat removal subsystems are required to be OPERABLE in MODE 5, with irradiated fuel in the RPV and the water level < 22 ft 8 inches above the top of the RPV flange, to provide decay heat removal. RHR System requirements in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS); Section 3.5, 1 Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC) System; and Section 3.6, Containment Systems. RHR Shutdown Cooling System requirements in MODE 5, with the water level 2: 22 ft 8 inches above the RPV flange, are given in LC0 3.9.8,

" Residual Heat Removal (RHR)-High Water Level."

(continued)

GRAND GULF B 3.9-30 Revision No. 1 i

RHR--Low Water Level B 3.9.9 BASES (continued)

SURVEILLANCE SR 3.9.9.1 REQUIREMENTS This Surveillance demonstrates that one RHR shutdown cooling subsystem or ADHRS is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystem in the control room.

REFERENCES None.

GRAND GULF B 3.9-33 Revision No. 1

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Reactor Mode Switch Interlock Testing B 3.10.2 B 3.10 SPECIAL OPERATIONS B 3.10.2 Reactor Mode Switch Interlock Testing BASES

~

BACKGROUND The purpose of this Special Operations LC0 is to permit operation of the reactor mode switch from one position to another to confirm certain aspects of associated interlocks during periodic tests and calibrations in MODES 3, 4, and 5.

The reactor mode switch is a conveniently located, multiposition, keylock switch provided to select the necessary screm functions for various plant conditions (Ref. 1). The reactor mode switch selects the appropriate trip relays for scram functions and provides appropriate bypasses. The mode switch positions and related scram interlock functions are summarized as follows:

a. Shutdown-Initiates a reactor scram; bypasses main steam line isolation and reactor high water level scrams; !

b. Refuel-Selects Neutron Monitoring System (NMS) scram function for low neutron flux level operation (but does not disable the average power range monitor scram); bypasses main steam line isolation and reactor high water level scrams;

c. Startup/ Hot Standby-Selects NMS scram function for low neutron flux level operation (intermr iiate range monitors and average power range moi 'rs); bypasses main steam line isolation and reacte ..sgh water level scrams; and

d. Run-Selects NMS scram function for power range operation.

The reactor mode switch also provides interlocks for such functions as control rod blocks, scram discharge volume trip bypass, refueling interlocks, suppression pool makeup, and main steam isolation valve isolations.

In MODES 3, 4, and 5, the reactor mode switch is generally locked in the shutdown or refuel position, as appropriate, to prevent inadvertent MODE changes.

(continued)

GRAND GULF B 3.10-5 Revision No. 1

Reactor Mode Switch Interlock Testing B 3.10.2 I

BASES (continued) I APPLICABLE The acceptance criterion for reactor mode switch interlock l SAFETY ANALYSES testing is to prevent fuel failure by precluding reactivity excursions or core criticality.

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(continued)

GRAND GULF' B 3.10-5a Revision No. I k.- - A - - .Ase,. ,-a- M b .a a -a @ 14 se_mRm,. a ea J+- ~ -,aFa,.,iL._ a ,wv--e g emn__Am e Ma. A- Om an l

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Reactor Mode Switch Interlock Testing i B 3.10.2 l l

BASES APPLICABLE The interlock functions of the shutdown and refuel positions SAFETY ANALYSES of the reactor mode switch in MODES 3, 4, and 5 are provided (continued) to preclude reactivity excursions that could potentially result in fuel failure. Interlock testing that requires moving the reactor mode switch to other positions (run, or )

startup/ hot standby) while in MODE 3, 4, or 5, requires ,

administratively maintaining all control rods inserted and i no other CORE ALTERATIONS in progress. With all control l rods inserted in core cells containing one or more fuel assemblies and no CORE ALTERATIONS in progress, there are no ,

credible mechanisms for unacceptable reactivity excursions i during the planned interlock testing.

l For postulated accidents, such as control rod removal error during refueling or loading of fuel with a control rod j withdrawn, the accident analysis demonstrates that fuel failure will not occur (Ref. 2). The withdrawal of a single I control rod will not result in criticality when adequate SDM is maintained. Also, loading fuel assemblies into the core with a single control rod _ withdrawn will not result in criticality, thereby preventing fuel failure. 1 As described in LC0 3.0.7, compliance with Special l Operations LCOs is optional, and therefore no criteria of l the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by ,

appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases.

LC0 As described in LC0 3.0.7, compliance with this Special Operations LC0 is optional. MODES 3, 4, and 5 operations not specified in Table 1.1-1 can be performed in accordance with other Special Operations LCOs (i.e., LC0 3.10.1,

" Inservice Leak and Hydrostatic Testing Operation,"

LC0 3.10.3, " Single Control Rod Withdrawal-Hot Shutdown," ,

LC0 3.10.4, " Single Control Rod Withdrawal-Cold Shutdown," I and LC0 3.10.8, "SDM Test-Refueling") without meeting this LC0 or its ACTIONS. If any testing is performed that involves the reactor mode switch interlocks and requires repositioning beyond that specified in Table 1.1-1 for the current MODE of operation, the testing can be performed, l provided all interlock functions potentially defeated are administratively controlled. In MODES 3, 4, and 5 with the reactor mode switch in shutdown as specified in Table 1.1-1, (continued)

GRAND GULF B 3.10-6 Revision No. 1 1

Single CRD Removal-Refueling B 3.10.5 BASES (continued)

ACTIONS A.1, A.2.1 and A.2.2 If one or more of the requirements of this Special Operations LC0 are not met, the immediate implementation of these Required Actions restores operation consistent with the normal requirements for failure to meet LC0 3.3.1.1, LCO 3.3.8.2, LC0 3.9.1, LC0 3.9.2, LCO 3.9.4, and LC0 3.9.5 (i.e., all control rods inserted) or with the allowances of this Special Operations LCO. The Completion Times for Required Action A.1, Required Action A.2.1, and Required Action A.2.2 are intended to require these Required Actions be implemented in a very short time and carried through in an expeditious manner to either initiate action to restore the CRD and insert its control rod, or initiate action to ;

restore compliance with this Special Operations LCO.

Actions must continue until either Required Action A.2.1 or Required Action A.2.2 is satisfied.

l SURVEILLANCE SR 3.10.5.1. SR 3.10.5.2, SR 3.10.5.3. SR 3.10.5.4, and REQUIREMENTS SR 3.10.5.5 Verification that all the control rods, other than the control rod withdrawn for the removal of the associated CRD, are fully inserted is required to ensure the SDM is within limits. Verification that the local five by five array of control rods other than the control rod withdrawn for the removal of the associated CRD, is inserted and disarmed electrically or hydraulically, while the scram function for I the withdrawn rod is not available, is required to ensure that the possibility of criticality remains precluded.

Verification that a control rod withdrawal block has been inserted ensures that no other control rods can be inadvertently withdrawn under conditions when position 1 indication instrumentation is inoperable for the withdrawn control rod. The Surveillance for LC0 3.1.1, " SHUTDOWN MARGIN (SDM)," which is made applicable by this Special Operations LCO, is required in order to establish that this Special Operations LC0 is being met. Verification that no !

other CORE ALTERATIONS are being made is required to ensure the assumptions of the safety analysis are satisfied.

Periodic verification of the administrative controls established by this Special Operations LC0 is prudent to preclude the possibility of an inadvertent criticality. The (continued)

GRAND GULF B 3.10-23 Revision No. 1 J

SDM Test-Refueling B 3.10.8 i

BASES ACTIONS A.1 and A.2 (continued) hydraulically) within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Inserting a control rod l ensures the shutdown and scram capabilities are not adversely affected. The control rod is disarmed to prevent inadvertent withdrawal during subsequent operations. The ,

control rods can be hydraulically disarmed by closing the ^

drive water and exhaust water isolation valves.

Electrically, the control rods can be disarmed by disconnecting power from all four directional control valve i solenoids. Required Actions A.1 and A.2 are modified by a i Note that allows control rods to be bypassed in the Rod Action Control System (RACS) if required to allow insertion and disarming of the inoperable control rods and continued i operation. SR 3.3.2.1.9 provides additional requirements when the control rods are bypassed to ensure compliance with the CRDA analysis. ,

The allowed Completion Times are reasonable, considering the small number of allowed inoperable control rods, and provide time to insert and disarm the control rods in an orderly manner and without challenging plant systems.

Condition A is modified by a Note allowing separate Condition entry for each uncoupled control rod. This is acceptable since the Required Actions for this Condition provide appropriate compensatory actions for each uncoupled )

control rod. Complying with the Required Actions may allow J for continued operation. Subsequent uncoupled control rods are governed by subsequent entry into the Condition and I application of the Required Actions.

B.1 With one or more of the requirements of this LC0 not met for reasons other than an uncoupled control rod, the testing should be immediately stopped by placing the reactor mode switch in the shutdown or refuel position. This results in a condition that is consistent with the requirements for MODE 5 where the provisions of this Special Operations LC0 are no longer required.

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GRAND GULF B 3.10-35 Revision No. 1

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SDM Test-Refueling B 3.10.8 l

BASES -(continued)

SURVEILLANCE SR 3.10.8.1. SR 3.10.8.2 and SR 3.10.8.3 REQUIREMENTS The other LCOs made applicable in this Special Operations LC0 are required to have applicable Surveillances met to establish that this Special Operations LC0 is being met.

However, the control rod withdrawal. sequences during the SDM tests may be enforced by the RPC (LC0 3.3.2.1, Function Ib, MODE 2 requirements) or by a second licensed operator or other qualified member of the technical staff. As noted, either the applicable SRs for the RPC (LCO 3.3.2.1) must be satisfied according to the applicable Frequencies (SR 3.10.8.2), or the proper movement of control rods must be verified (SR 3.10.8.3). This latter verification (i.e.,

SR 3.10.8.3) must be performed during control rod movement to prevent deviations from the specified sequence. lnese i surveillances provide adequate assurance that the specified test sequence is being followed. j SR 3.10.8.4 ,

Periodic verification of the administrative controls established by this LC0 will ensure that the reactor is operated within the bounds of the safety analysis. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is intended to provide appropriate assurance that each operating shift is aware of and verifies 1 compliance with these Special Operations LC0 requirements. l l

SR 3.10.8.5 t

A coupling verification such as described in the Bases for l SR 3.1.3.5 is performed to ensure the control rod is ;

connected to the control rod drive mechanism and will l perform its intended function when necessary. The l verification is required to be performed any time a control rod is withdrawn to the " full out" notch position or prior

-to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling. This Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not '

being moved as well as operating experience related to uncoupling events.

L (continued)

GRAND GULF B 3.10-36 Revision No. I x

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ML20097C354

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