Text

Application for Technical Specification Changes: Technical Specification Task Force (TSTF) Improved Standard Technical Specification Change Traveler, TSTF-423, Technical Specifications End States
	ML13316B024
Person / Time
Site:	Grand Gulf
Issue date:	11/08/2013
From:	Mulligan K J; Entergy Operations
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	GNRO-2013/00065
	Download: ML13316B024 (118)
	v • d • e

Entergx GNRO-2013/00065 November 8, 2013 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

SUBJECT:

License Amendment Request Operations, Inc, 756 Port Gibson, Mississippi 39150 Kevin J, Site Vice >,no',,,,,,,,, Grand Gu!f Nuclear Station TeL 301,437,7500 Application for Technical Specification Changes; Technical Specification Task Force (TSTF) Improved Standard Technical Specification Change Traveler, TSTF-423, "Technical Specifications End States" Grand Gulf Nuclear Station, Unit 1 Docket No. 50-416 License No. 29

REFERENCE:

TSTF-423, Revision 1, "Technical Specifications End States, NEDC-32988-A"

Dear Sir or Madam:

In accordance with the provisions of Section 50.90 of Title 1 0 of the Code of Federal Regulations (10 CFR), Entergy Operations, Inc. (Entergy) is submitting a request for an amendment to the Technical Specifications (TS) for Grand Gulf Nuclear Station (GGNS), Unit 1. The proposed amendment would modify TS to risk-informed requirements regarding selected Required Action End States as provided in the referenced document.

The availability of the model safety evaluation for this TS improvement was announced in the Federal Register on February 17, 2011, as part of the Consolidated Line Item Improvement Process (CLlIP). Attachment 1 provides a description of the proposed change. Attachment 2 provides the existing TS pages marked up to show the proposed change. Attachment 3 provides the revised technical specification pages, Attachment 4 provides the revised TS Bases pages (for information only). Attachment 5 provides a summary of the new regulatory commitment made in this submittal.

GNRO-2013/00065 Page 2 of 2 Although this request is neither exigent nor emergency, your prompt review is requested.

Once approved, the amendment shall be implemented within 60 days. If you have any questions or require additional information, please contact Mr. Jeffery A. Seiter at (601) 437-2344.

I declare under penalty of perjury that the foregoing is true and correct. Executed on November 8, 2013 Sincerely,

) KJM/jas Attachments:

1. Analysis of Proposed Technical Specification Change 2. Proposed Technical Specification Changes (mark-up)

3. Proposed Technical Specification Changes (clean pages) 4. Changes to Technical Specification Bases Pages (For Information Only) 5. Regulatory Commitment cc: u.S. Nuclear Regulatory Commission ATTN: Mr. Marc Dapas, (w/2) Regional Administrator, Region IV 1600 East Lamar Boulevard Arlington, TX 76011-4511 NRC Senior Resident Inspector Grand Gulf Nuclear Station Port Gibson, MS 39150 U. S. Nuclear Regulatory Commission ATTN: Mr. Alan Wang, NRRlDORL (w/2) Mail Stop OWFN 8 B1 Washington, DC 20555-0001 Dr. Mary Currier, M.D., M.P.H State Health Officer Mississippi Department of Health P. O. Box 1700 Jackson, MS 39215-1700 Attachment 1 GNRO-2013/00065 Analysis of Proposed Technical Specification Change Attachment 1 to GNRO-2013/00065 Page 1 of 5

1.0 DESCRIPTION

The proposed amendment would modify Technical Specifications (TS) to risk-informed requirements regarding selected Required Action End States. The changes are consistent with the Nuclear Regulatory Commission (NRC) approved Industry/Technical Specification Task Force (TSTF) TSTF-423, Revision 0, "Technical Specifications End States, NEDC-32988-A." The availability of this TS improvement was published in the Federal Register (FR) on February 18, 2011, as part of the Consolidated Line Item Improvement Process (CUIP).

2.0 PROPOSED CHANGE

Entergy Operations, Inc. (Entergy) has reviewed the General Electric (GE) topical report (NEDC-32988-A), TSTF-423, and the NRC model Safety Evaluation (SE). Entergy has concluded that the information in the GE topical report and TSTF-423 as well as the Safety Evaluation prepared by the NRC, are applicable to Grand Gulf Nuclear Station (GGNS) and provide justification for the incorporation of the proposed changes into the GGNS TS. The proposed amendment would modify Technical Specifications (TS) to risk-inform requirements regarding selected Required Action end states. Additionally, it would modify the TS Required Actions with a Note prohibiting the use of limiting condition for operation (LCO) 3.0.4.a when entering the preferred end state (Mode 3) on startup. The proposed TS changes are included as Attachment 2 of this submittal.

The variations or deviations from TSTF-423, Revision 1 are of two types; differences in Grand Gulf Nuclear Station (GGNS) specific TS and those TS changes in TSTF-423 which GGNS is not requesting.

In some cases an adaptation of TSTF-423 was required for incorporation into the GGNS, Unit 1 TS due to administrative differences in format (e.g., condition letter designation, etc). Each of these differences are identified in Section 4.1. The associated Bases are included as Attachment 4 for information.

3.0 BACKGROUND

The background for this application is adequately addressed by the NRC "Notice of Availability of the Proposed Models for Plant-Specific Adoption of Technical Specifications Task Force (TSTF) Traveler TSTF-423, Revision 1, "Technical Specifications End States, NEDC-32988-A," for Boiling Water Reactor Plants Using the Consolidated Line Item Improvement Process (CUIP)" published on February 18, 2011. 4.0 TECHNICAL ANALYSIS Entergy has reviewed the Safety Evaluation published on February 18, 2011, as part of the "CUIP Notice of Availability of the Model Safety Evaluation." Entergy has concluded Attachment 1 to GNRO-2013/00065 Page 2 of 5 that the technical justifications presented in the SE prepared by the NRC staff are applicable to GGNS, Unit 1, and therefore justify this amendment for the incorporation of the proposed changes to the GGNS, Unit 1, TS. The following is noted with respect to this conclusion:

The discussion regarding Control Room Air Conditioning (CRAC), per NUREG-1434, "Standard Technical Specifications General Electric Plants, BWR/6," TS 3.7.3 states that this is a non-risk significant system for most BWRs. For Grand Gulf, the OPERABILITY of this system is impacted by interlocks to Switchgear Room cooling, which is another subsystem of the overall Control Building heating and ventilation air conditioning (HVAC) system (HVC) which is a risk significant function.

However, the logic supporting the proposed changes for CRAC remains valid even with consideration of the need for Switchgear Room cooling at Grand Gulf. As discussed in the notice of availability published in the Federal Register on February 18, 2011, for this TS improvement, plant-specific regulatory commitments are made as follows: 1. A revision to Title 10 Code of Federal Regulations (10 CFR) 50.56 implementing Regulatory Guide (RG) 1.182 became effective November 28, 2000. On November 27,2012, RG 1.182 was withdrawn

('17 FR 70846) as the requirements on acceptable methods to meet the provisions of 10 CFR 50.65(a)(4) associated with managing and assessing risk were incorporated in RG 1.161 on May 21,2012 (77 FR 30030). Procedure EN-WM-1 04, "On Line Risk Assessment," ensures procedural compliance with NUMARC 93-01, "Industry Guideline For Monitoring The Effectiveness Of Maintenance At Nuclear Power Plants" requirements and outlines the implementation structure for 10 CFR 50.65(a)(4)

Maintenance Rule programs, No new commitment is required.

2. Entergy will follow the guidance established in TSTF-IG-05-02 "Implementation Guidance for TSTF-423, Revision 2, Technical Specification End States, NEDC-32988-A" with one exception, The following statement on page 2 does not apply: "If Primary Containment is not operable, Secondary Containment and Standby Gas Treatment must be verified operable in order to remain in Mode 3," 4,1 Optional Changes and Variations TSTF-423 is based on NUREG-1434.

GGNS, Unit 1, TS are based on NUREG-1434, but are not identical to this guidance.

As a result, an adaptation of TSTF-423 was required in some cases for incorporation into the GGNS, Unit 1, TS due to administrative differences in format (e,g" condition letter designation, etc,). Changes to individual line items to align with the provisions of TSTF-423 include the following:

1. Changes to GGNS TS 3,6.1.8, "Feedwater Leakage Control System (FWLCS)," are made in accordance with the changes made in TSTF-423 for Standard TS 3.6,1.8, "Penetration Valve Leakage Control System (PVLCS)" since the FWLCS at GGNS Attachment 1 to GNRO-2013/00065 Page 3 of 5 serves a similar purpose to that of the PVLCS described in NUREG-1434.

These changes are consistent with TSTF-423 but require modification to the standard by revising GGNS TS 3.6.1.8 in place of TS 3.1.8 PVLCS. 2. Changes to GGNS TS 3.7.1 are needed to incorporate TSTF-423 line item TS 3.7.1. These changes are consistent with TSTF-423 but require modification to the standard.

The proposed TS for GGNS will separate the shutdown actions into one addressing issues with a single division (revised action E), and one addressing issues with two divisions now designated as new action F (original action E). This allows the single division action to halt at Mode 3 while the remainder of the issues are addressed by the new action (action F), which includes Mode 4 as an end state. The description of changes to the TS are as follows: Revised CONDITION E of TSTF-423 TS 3.7.1 includes conditions which address a single division of Standby Service Water / Ultimate Heat Sink (SSW/UHS) with actions of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or longer applicable.

To align the GGNS actions with the scope of the TSTF, GGNS CONDITION F is added to address both SSW subsystems being inoperable.

Existing GGNS CONDITION D ensures alignment with the TSTF-423 TS 3.7.1 CONDITION B. Revised CONDITION E is for one division of SSW/UHS inoperable, with GGNS items A, C, or D not met. This is consistent with TSTF revised CONDITION C. CONDITION F (portion of former CONDITON Ere-lettered) is revised to address conditions for both divisions of SSW/UHS inoperable.

This is consistent with TSTF-423 TS 3.7.1 revised CONDITION E. The following will also be addressed by this CONDITION:

"Two UHS cooling towers with one or more cooling tower fans inoperable." * "UHS basin inoperable for reasons other than CONDITION C." 3. GGNS TS 3.7.3 Surveillance Requirement (SR) 3.7.3.3 frequency is changed from 18 to 24 months as GGNS has made application to transition from an 18 to a 24-month fuel cycle per "Grand Gulf License Amendment Request to Revise Technical Specifications and Surveillance Requirements to Support Operations with a 24-month fuel Cycle in Accordance with Generic Letter 91-04" (TAC ME9763, Accession No. ML 12289A 158). The application is currently under NRC review and approval is anticipated prior to the approval of the TSTF-423 application.

This change is to ensure the frequency is not inadvertently changed back to 18 months. If the 18-to 24-month application is denied, the frequency will remain at 18 months. 4. Changes to GGNS TS 3.7.4 are needed to incorporate TSTF-423 line item TS 3.7.4. These changes are consistent with TSTF-423 but require modification to the standard.

Attachment 1 to GNRO-2013/00065 Page 4 of 5 CONDITION B already addresses two CRAC subsystems inoperable.

CONDITION B is revised to correct a typographical error in the designation of degrees Fahrenheit and has no technical impact on the submittal.

CONDITION C already addresses exceeding the CONDITON A and CONDITION B Completion Times, combining the TSTF-423 TS 3.7.4 CONDITION Band D actions. GGNS CONDITION C is revised to add the MODE 3 End State allowance in accordance with TSTF-423.

The GGNS revision is consistent with TSTF-423 TS 3.7.4 CONDITION B and CONDITION D. 5. Changes to GGNS TS 3.7.5 are needed to incorporate TSTF-423 line item TS 3.7.5. These changes are consistent with TSTF-423 but require modification to the standard.

CONDITION B does not have Required Action B.1 to isolate all main steam lines. GGNS specifications require the steam jet air ejector to be isolated.

CONDITION B Required Action B.2.1 is revised to incorporate the TSTF-423 End State allowance and renumbered B.2. This is consistent with TSTF-423 TS 3.7.5 CONDITION B Action B.3. 6. Changes to GGNS TS 3.8.4 are needed to incorporate TSTF-423 line item TS 3.8.4. These changes are consistent with TSTF-423, but require modification to the standard.

CONDITION 0 of TS 3.8.4 addresses High Pressure Core Spray System inoperability if Division 3 Direct Current (DC) electrical power subsystem is inoperable.

GGNS CONDITION D is revised to add the MODE 3 End State allowance in accordance with TSTF-423 and re-Iettered as CONDITION E. As a result, current CONDITION E is re-Iettered as CONDITION F and modified to address only the Division 3 DC electrical power subsystem.

The GGNS revision is consistent with TSTF-423 TS 3.8.4 CONDITION B and CONDITION D. 7. Changes to GGNS TS 3.8.7, "Distribution Systems -Operating," are needed to incorporate TSTF-423 line item TS 3.8.9. These changes are consistent with TSTF-423, but require modification to the standard.

GGNS CONDITION C is revised to incorporate the TSTF-423 End State allowance.

This is consistent with TSTF-423 TS 3.8.9 CONDITION D. Note: TS 3.8.9 Distribution Systems -Operating is designated as TS 3.8.7 Distribution Systems -Operating in the Grand Gulf Technical Specifications.

In addition to changes discussed above, GGNS is not requesting changes to two of the line items identified in TSTF-423.

The TS 3.4.4 Safety Relief Valves (SRVs) change is not being requested due to an extended power uprate required change resulting in the existing specification being consistent with TSTF-423.

The change to TS 3.8.7 "Inverters

-Operating" is not being requested due to GGNS current specifications not containing an equivilent section 3.8.7.

Attachment 1 to GNRO-2013/00065 Page 5 of 5 5.0 REGULATORY SAFETY ANALYSIS 5.1 No Significant Hazards Consideration Determination Entergy has reviewed the proposed no significant hazards consideration determination (NSHCD) published in the Federal Register as part of the CLlIP. Entergy has concluded that the proposed NSHCD presented in the Federal Register notice is applicable to Grand Gulf Nuclear Station and is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91(a).

5.2 Applicable

Regulatory Requirements/Criteria A description of the proposed TS change and its relationship to applicable regulatory requirements was provided in the NRC "Notice of Availability of the NRC Model Safety Evaluation of TSTF-423, Revision 1," published on February 2,2011. 6.0 ENVIRONMENTAL CONSIDERATION Entergy has reviewed the environmental evaluation included in the NRC Safety Evaluation published on February 2, 2011, as part of the CLlIP Notice of Availability of the Model Safety Evaluation.

Entergy has concluded that the staffs findings presented in that evaluation are applicable to GGNS, Unit 1, and the evaluation is hereby incorporated by reference for this application.

7.0 REFERENCES

1. TSTF-423, Revision 1, "Technical Specifications End States, NEDC-32988-A," dated December 22, 2009 (ADAMS Accession No. ML093570241).

2. Federal Register, [Vol. 76, No. 34, p.9614J, "Notice of Availability of the Proposed Models for Plant-Specific Adoption of Technical Specifications Task Force (TSTF) Traveler TSTF-423, Revision 1, 'Technical Specifications End States, NEDC-32988-A,' for Boiling Water Reactor Plants Using the Consolidated Line Item Improvement Process," dated [February 18, 2011] (ADAMS Accession No. ML 102730585).

3. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required Action End States for BWR Plants," December 2002 (ADAMS Package Accession No. ML030170090).

4. NRC Model Safety Evaluation of TSTF-423, Revision 1, dated February 2, 2011 (ADAMS Accession No. ML 102730688).

Attachment 2 GNRO-2013/00065 Proposed Technical Specification Changes (mark-up)

Note, markup deletions identified by strikethrough (Gelete) and additions identified by underline (addition).

3.3 INSTRUMENTATION

RPS Electric Power Monitoring 3.3.8.2 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring LCO 3.3.8.2 Two RPS electric power monitoring assemblies shall be OPERABLE for each inservice RPS motor generator set or alternate power supply. APPLICABILITY:

MODES 1, 2, and 3, MODES 4 and 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies.

ACTIONS CONDITION A. One or both inservice power supplies with one electric power monitoring assembly inoperable.

B. One or both inservice power supplies with both electric power monitoring assemblies inoperable.

C. Required Action and associated Completion Time of Condition A or B not met: in MODE 1, 2, or 3. GRAND GULF A.1 B.1 C .1 C. 2 REQUIRED ACTION Remove associated inservice power supply(s) from serv.ice.

Remove associated inservice power supply(s) from service. Be in MODE 3. D eo h! H0BE--4-.-

3.3-80 COMPLETION TIME 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 1 hour 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ;)6 h&8E8 (continued)

Amendment No. He-__

ACTIONS (continued)

CONDITION C. Two ECCS injection subsystems inoperable.

C.1 OR One ECCS injection and one ECCS spray subsystem inoperable.

D. Required Action and 0.1 associated Completion Time of Condition A, -ANa-B, or C not met. D.2 E. One ADS valve E.1 inoperable.

F. One ADS valve F.1 inoperable.

AND OR One low pressure ECCS F.2 su system inoperable.

GRAND GULF REQUIRED ACTION Restore one ECCS su system to OPERABL status. J:::::' Be in MODE 3. Be i,. P40DE 4. Restore ADS valve to OPERABLE status. Restore ADS valve to OPERABLE status. Restore low pressure ECCS injection/spray subsystem to OPERABLE status. 3.5-2 ECCS-Operating

3.5.1 COMPLETION

TIME Insert (at 0.1): ---------NOTE -------LCO 3.0.4.a is not aRRlicable when entering MODE 3, ---------------------------

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hetll"5 14 days 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 72 hours (continued)

Amendment No. -He-_

ACTIONS (continued)

CONDITION Insert (at G.1): ---------NOTE -------r LeO 3.0.4.a is not gpplicable when entering MODE 3. / ---------------------------

ALI.lUN G. Two or more ADS valves inoperable.

G. 1"'" Be in MODE 3. Required Action and associated Completion Time of Condition E or F not met. -AND H. HPCS and Low Pressure H.l Core Spray (LPCS) Systems inoperable.

OR Three or more ECCS injection/spray subsystems inoperable.

OR HPCS System and one or more ADS valves inoperable.

Two or more ECCS injection/spray subsystems and one or more ADS valves inoperable.

GRAND GULF Resyce FeactsF Enter LCO 3.0.3. 3.5-3 ECCS-Operating

3.5.1 LuMPLETION

TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 3Ei I:rSYFS Immediately Amendment No.

3.6 CONTAINMENT

SYSTEMS 3.6.1.6 Low-Low Set eLLS) Valves LLS Valves 3.6.1.6 LCO 3.6.1. 6 The LLS function of six safety/relief valves shall be OPERABLE.

Insert (at B.1): APPLICABILITY

MODES 1, 2, and 3. ACTIONS CONDITION A. One LLS valve A.1 inoperable.

B. Required Action and B.1 associated Completion Ti me of Condi ti on A .#if)-not met. -f1R-GRAND GULF in MODE 3. 3.6-20 leo not COMPLETION TIME to 14 days 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 MOtiFS Amendment No.

3.6 CONTAINMENT

SYSTEMS RHR Containment Spray System 3.6.1.7 3.6.1.7 Residual Heat Removal (RHR) Containment Spray System LCO 3.6.1. 7 Two RHR containment spray subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION A. One RHR containment A.1 spray subsystem inoperable.

B. Two RHR containment B.1 spray subsystems inoperable.

C. Required Action and C.1 associated Completion Time not met. GRAND GULF REQUIRED ACTION COMPLETION TIME Restore RHR 7 containment spray subsystem to OPERABLE status. Restore one R 8

__ -.J containmen spray subsyst to OPERABLE statu . Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 3.6-22 Amendment No .. -+/-rf} _

3.6 CONTAINMENT

SYSTEMS 3.6.1.8 Feedwater Leakage Control System (FWLCS) LCO 3.6.1.8 Two FWLCS subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION A. One FWLCS subsystem inoperable.

B. Two FWLCS subsystems inoperable.

C. Required Action and associated Completion Time not met. SURVEILLANCE REQUIREMENTS A.1 B.1 C.1 -AN{} E.2 -SURVEILLANCE REQUIRED ACTION Restore FWLCS subsystems to OPERABLE status. Restore one FWLCS subsystem RABLE status. Be in MODE 3. Be ; " M99E 4.' FWLCS 3.6.1.8 COMPLETION TIME 30 days insert (at C.1): 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY SR 3 . 6 .1. 8 . 1 Verify RHR jockey pump operates properly.

31 days GRAND GULF 3.6-24 Amendment No ..

3.6 CONTAINMENT

SYSTEMS MSIV LCS 3.6.1.9 3.6.1.9 Main Steam Isolation Valve (MSIV) Leakage Control System (LCS) LCO 3.6.1.9 Two MSIV LCS subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION SURVEILLANCE REQUIREMENTS SR 3.6.1. 9.1 GRAND GULF SURVEILLANCE Operate each outboard MSIV LCS blower 15 minutes. 3.6-25 COMPLETION TIME FREQUENCY 31 days (continued)

Amendment No.

3.6 CONTAINMENT

SYSTEMS RHR Suppression Pool Cooling 3.6.2.3 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling LCO 3.6.2.3 Two RHR suppression pool cooling subsystems shall be OPERABLE.

APPLICABILITY

MODES 1, 2, and 3. ACTIONS CONDITION A. One RHR suppression A.l pool cooling subsystem inoperable.

GRAND GULF REQUIRED ACTION Restore RHR suppression pool cooling subsystem to OPERABLE status. 3.6-31 COMPLETION TIME 7 days Amendment No.

3.6 CONTAINMENT

SYSTEMS 3.6.4.1 Secondary Containment Secondary Containment 3.6.4.1 LCO 3.6.4.1 The secondary containment shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, During movement of recently irradiated fuel assemblies

--t--in the primary or secondary containment, During operations with a potential for draining the reactor vessel (OPDRVs).

-+-ACTIONS CONDITION A. Secondary containment inoperable in MODE 1, 2, or 3. B. Required Action and associated Completion Time of Condition A not met. GRAND GULF REQUIRED ACTION COMPLETION TIME A.l Restore secondary containment to

..-

MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued) 3.6-42 Amendment No.

3.6 CONTAINMENT

SYSTEMS 3.6.4.3 Standby Gas Treatment (SGT) System LCD 3.6.4.3 Two SGT subsystems shall be OPERABLE.

APPLI CABI LITY : SGT System 3.6.4.3 MODES 1, 2, and 3, During movement of recently irradiated fuel assemblies in the primary or secondary containment, During operations with a potential for draining the reactor vesse 1 (OPDRVs).

,+ ACTIONS CONDITION A. One SGT subsystem inoperable.

A.1 REQUIRED ACTION Restore SGT subsystem to B. Required Action and B.1 in MODE 3. associated Completion Time of Condition A not met in MODE 1, 2, or 3.

.... 4r.. C. Required Action and associated Completion Time of Condition A not met during movement of recently irradiated fuel assemblies in the primary or secondary containment or during OPDRVs. ------------NOTE-------------

LCO 3.0.3 is not applicable.

C.1 Place OPERABLE SGT subsystem in operation.

COMPLETION TIME 3& +lol:lrs Immediately (continued)

GRAND GULF 3.6-49 Amendment No. HB __

ACTIONS CONDITION C. (conti nued) Insert (at 0,1): D. Two SGT subsystems inoperable in MODE 1, 2, or 3. E. Two SGT subsystems inoperable during movement of recently irradiated fuel assemblies in the primary or secondary containment or during OPDRVs. GRAND GULF REQUIRED ACTION C.2.1 Suspend movement of recently irradiated fuel assemblies in the primary and secondary containment.

E.1 AND E.2 Initiate action to suspend OPDRVs. Enter LEO Suspend movement of recently irradiated fuel assemblies in the primary and secondary containment.

Initiate action to suspend OPDRVs. 3.6-50 SGT System 3.6.4.3 COMPLETION TIME Immediately Immediately Immediately Immediately + '+ +-,.+-Amendment No.

ACTIONS (continued)

CONDITION C. One drywell purge C.1 vacuum relief

!o r I insert New , 5P1Condition.

! /

____ 1 ,-9-. Two d rywe 11 pu vacuum relief subsystems inoperable for reasons other than Condition A. --&. Two drywell post-LOCA

+;-7 vacuum relief subsystems inoperable for reasons other than Conditi on A. One drywell purge vacuum relief subsystem inoperable for reasons other than Condition A. Required Action and associated Completion Time of Condition A, -&, -.(;, or .-I! not met. GRAND GULF -F-d. AND Drywell Vacuum Relief System 3.6.5.6 REQUIRED ACTION COMPLETION TIME Restore drywell purge 30 days vacuum relief subsystem to OPERABLE status. Restore one drywell 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months purge vacuum relief subsystem to OPERABLE status. Restore one drywell 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months post-LOCA vacuum relief or drywell purge vacuum relief subsystem to OPERABLE status. Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 3.6-65 Amendment No.

ACTIONS (continued)

--6-. lK1 CONDITION Two drywell purge vacuum relief subsystems inoperable for reasons other than Condition A. One or two drywell post-LOCA vacuum relief subsystems inoperable for reasons other than Condition A. GRAND GULF Drywell Vacuum Relief System 3.6.5.6 REQUIRED ACTION COMPLETION TIME Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 3.6-66 Amendment No. -fr&-_

ACTIONS (continued)

CONDITION E. Required Action and associated Completion Time of Condition A, C, or D not met. Beth SSW 1 Reper:aeie. -OR-with one OF-mere SURVEILLANCE REQUIREMENTS E.l SURVEILLANCE IRED ACTION Be ;n MODE 3. SR 3.7.1.1 Verify the water level of each UHS basin i s 7.25 ft. SR 3.7.1. 2 GRAND GULF Operate each SSW cooling tower fan for 2: 15 minutes. 3.7-3 SSW System and UHS 3.7.1 COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 31 days (continued)

Amendment No.

1* i. F. F Both SSW subsystems inoperable.

OR Two UHS cooling towers with one or more cooling tower fans inoperable.

OR UHS basin inoperable for reasons other than Condition C. Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Insert at C.1: ----------

-LC() 3.0.4.a is not CRFA System a.QP-licable when 3.7.3 ACTIONS (continued)

-entering

CONDITION LETION TIME C. Required Action and C.1 \V Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A or ...ANO-B not met in MODE 1, -+ 2, or 3. ..f...+ (;Je MODE 4 36 1:19"'1=$

D. Required Action and D.1 Place OPERABLE CRFA Immediately associated Completion subsystem in + Time of Condition A isolation mode. not met during OPDRVs. OR D.2 Initiate action to Immediately suspend OPDRVs. (continued)

GRAND GULF 3.7-7 Amendment No.

ACTIONS (continued)

E. F. CONDITION Two CRFA subsystems inoperable in MODE 1, 2, or 3 for reasons other than Condition B. Two CRFA subsystems inoperable during OPDRVs. One or more CRFA subsystems inoperable due to inoperable CRE boundary during OPDRVs. E.1.1t F.111\ EI't'Cer LEO 3.0.3. Initiate action to suspend OPDRVs. Insert at F,1: SURVEILLANCE REQUIREMENTS SR 3.7.3.1 SR 3.7.3.2 SR 3.7.3.3 SR 3.7.3.4 SURVEILLANCE Operate each CRFA subsystem for 10 continuous hours with the heaters operating.

Perform required CRFA filter testing in accordance with the Ventilation Filter Testing Program (VFTP). Verify each CRFA subsystem actuates on an actual or simulated initiation signal. Perform required CRE unfiltered air inleakage testing in accordance with the Control Room Envelope Habitability Program. System 3.7.3 TIME Immediately-Immediately FREQUENCY 31 days In accordance with the VFTP +/-8 months In accordance with the Control Room --Envelope Habitability Program GRAND GULF 3.7-8 Amendment No.

3.7 PLANT

SYSTEMS Control Room AC System 3.7.4 3.7.4 Control Room Air Conditioning (AC) System LCO 3.7.4 Two control room AC subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One control room AC A.1 Restore control room 30 days subsystem inoperable.

AC subsystem to OPERABLE status. B. Two control room AC B.1 Verify control room Once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months subsystems inoperable.

area temperature 90BF-. AND 1 0 F I 7 days B.2 Restore one control room AC subsystem to OPERABLE status. C. Required Action and Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A or B not met in MODE 2, or 3. E.2! Be ill M6BE 4. 36110DIS Insert at C.1: (continued)

NOTE ---------LCO 3.0.4.a is not aQQlicable when entering MODE 3. ---------------------------

GRAND GULF 3.7-9 Amendment No.

3.7 PLANT

SYSTEMS 3.7.5 Main Condenser Offgas Main Condenser Offgas 3.7.5 LCO 3.7.5 The gross gamma actlvlty rate of the noble gases measured at the offgas recombiner effluent shall be 380 mCi/second after decay of 30 minutes. APPLICABILITY:

MODE 1, MODES 2 and 3 with any steam jet air ejector (SJAE) in operation.

ACTIONS A. B. CONDITION Gross gamma activity A.l rate of the noble gases not within 1 i mi t. Required Action and B.l associated Completion Time not met. OR B.2""}:-REQUIRED ACTION COMPLETION TIME Restore gross gamma 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months acti vi ty rate of the noble gases to within 1 i mi t. Be in MODE 3 . 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months --ANtr Be M9SE 4. GRAND GULF 3.7-12 Amendment No. -:1:Z{7-__

ACTIONS (continued)

CONDITION D. One required offsite circuit inoperable for reasons other than Condition F. One required DG inoperable for reasons other than Condition F. E. Two required DGs inoperable.

AC Sources-Operating

3.8.1 REQUIRED

ACTION ------------NOTE-------------

Enter applicable Conditions and Required Actions of LCO 3.8.7, "Distribution Systems -Operati ng," when any required division is energized as a result of Condition D. 0.1 OR 0.2 E.1 Restore required offsite circuit to OPERABLE status. Restore required DG to OPERABLE status. Restore one required DG to OPERABLE status. COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 12 hours 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 24 hours if Division 3 DG ;c:: ;nnn",r::lhl",

..

F. One automatic load sequencer inoperable.

G. Required Action and associated Completion Time of Condition A, B, C, 0, E, or F not met. GRAND GULF F.1 G.1 -AND. 6.2 Restore au atic load seq ncer to OPERAB status. in MODE 3. Be ill MOf)E 4. 3.8-4 LeO 3.0.4.a is not applicable when entering MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours (continued)

Amendment No. -rz&-

DC Sources-Operating 3.8.4 'r. CONDITION Division 3 DC electrical power subsystem inoperable for reasons other than Condition A. Required Action and associated Completion Time of E or

-9.1 [] -1:-:1 AND Declare High Pressure Core Spray System inoperable.

Be in MODE 3. Be in MODE 4. SURVEILLANCE REQUIREMENTS SR 3.8.4.1 SR 3.8.4.2 GRAND GULF SURVEILLANCE Verify battery terminal voltage is 129 V on float charge. Verify no visible corrosion at battery terminals and connectors.

Verify battery connection resistance is 1.5 E-4 ohm for inter-cell connections, 1.5 E-4 ohm for inter-rack connections, 1.5 E-4 ohm for inter-tier connections, and 1.5 E-4 ohm for terminal connections.

3.8-27 COMPLETION TIME Immediately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours FREQUENCY 7 days 92 days (continued)

Amendment Insert at C.1: -----------

LC() 3.0.4.a is not Distribution

_____ . __

entering M()DE: 3. ACTIONS (continued)

f--------------

CONDITION jREQUIRED ACTION C. Required Action and C.1 Be in MODE 3. associated Completion Time of Condition A -ANf)-or B not met. E.z Be ; 11 M6SE 4. D. One or more Division 3 D.1 Declare High Pressure AC or DC electrical Core Spray System power distribution inoperable.

subsystems inoperable.

E. Two or more divisions E.1 Enter LCO 3.0.3. with inoperable distribution subsystems that result in a loss of function.

SURVEILLANCE RE UIREMENTS SR 3.8.7.1 GRAND GULF SURVEILLANCE Verify correct breaker alignments and voltage to required AC and DC electrical power distribution subsystems.

3.8-39 Systems-Operating

3.8.7 COMPLETION

TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 Immediately Immediately FREQUENCY 7 days Amendment No.

Attachment 3 GNRO-2013/00065 Proposed Technical Specification Changes (clean pages)

3.3 INSTRUMENTATION

RPS Electric Power Monitoring 3.3.8.2 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring LCO 3.3.8.2 Two RPS electric power monitoring assemblies shall be OPERABLE for each inservice RPS motor generator set or alternate power supply. APPLICABILITY:

MODES 1, 2, and 3, MODES 4 and 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or both inservice A.1 Remove associated 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months power supplies with inservice power one electric power supply(s) from monitoring assembly service. inoperable.

B. One or both inservice B.1 nemove associated 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months power supplies with inservice power both electric power supply(s) from monitoring assemblies service. inoperable.

C. Required Action and C.1 -------Note--------

associated Completion LCO 3.0.4.a is not Time of Condition A applicable when or B not met in entering MODE 3. MODE 1, 2, or 3. -------------------

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued)

GRAND GULF 3.3-80 Amendment No. +/-&G-r ___ _

ACTIONS (continued)

CONDITION C. Two ECCS injection C.1 subsystems inoperable.

OR -One ECCS injection and one ECCS spray subsystem inoperable.

D. Required Action and D.1 associated Completion Time of Condition A, B, or C not met. E. One ADS valve E.1 inoperable.

F. One ADS valve F.1 inoperable.

AND OR ---One low pressure ECCS F.2 ection/spray subsystem inoperable.

GRAND GULF REQUIRED ACTION Restore one ECCS injection/spray subsystem to OPERABLE status. -------NOTE--------

LCO 3.0.4.a is not applicable when entering MODE 3. -------------------

Be in MODE 3. Restore ADS valve to OPEHABLE status. Restore ADS valve to OPERABLE status. Hestore low pressure ECCS injection/spray subsystem to OPERABLE status. ECCS-Operating

3.5.1 COMPLETION

T 11'1E 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 12 hours 14 days 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 72 hours (contlnued) 3.5-2 Amendment No. -+/--2-G, ACTIONS (continued)

CONDITION G. Two or more ADS valves G.l inoperable.

OR Required Action and associated Completion Time of Condition E or F not met. H. HPCS and Low Pressure Core Spray (LPCS) Systems inoperable.

OR Three or more ECCS injection/spray subsystems inoperable.

OR HPCS System and one or more ADS valves inoperable.

OR Two or more ECCS ection/spray subsystems and one or more ADS valves inoperable.

GRAND GULF H.l REQUIR2D ACTION LCO 3.0.4.a is not applicable when entering j\10DE 3. Be in NODE 3. Enter LCO 3.0.3. ECCS-Operating

3.5.1 CONPLET1ON

TINE 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately 3.5-3 Amendment No.

3.6 CONTAINMENT

SYSTEMS 3.6.1.6 Low-Low Set (LLS) Valves LLS Valves 3.6.1.6 LCO 3.6.1.6 The LLS function of six safety/relief valves shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COt-1PLET I ON TIME A. One LLS valve A.1 Restore LLS valve to 14 days inoperable.

OPERABLE status. B. Required Action and B.1 -------NOTE--------

associated Completion LCO 3.0.4. a is not Tirne of Condition

? applicClb1e when not met. entering MODE 3. -------------------

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C. Two or more LLS valves C.l Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months inoperable.

AND C.2 Be in [-lode 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months GRAND GULF 3.6-20 Amendment No.

3.6 CONTAINMENT

SYSTEMS RHR Containment Spray System 3.6.1.7 3.6.1.7 Residual Heat Removal (RHR) Containment Spray System LCO 3.6.1.7 Two RHR containment spray subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR containment A.1 Restore RHR 7 days spray subsystem containment spray inoperable.

subsystem to OPERABLE status. B. Two RHR containment B.1 Restore one RHR 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months spray subsystems containment spray inoperable.

subsystem to OPERABLE status. C. Required Action and C.1 -------NOTE-------

associated Completion LCO 3.0.4.a is not Time not met. applicable when entering MODE 3. ------------------

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GRAND GULF 3.6-22 Amendment No. H.g,

3.6 CONTAINMENT

SYSTEMS 3.6.1.8 Feedwater Leakage Control System (FWLCS) LCO 3.6.1. 8 Two FWLCS subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION A. One FWLCS subsystem A.1 Restore FWLCS inoperable.

subsystems to OPERABLE status. B. Two FWLCS subsystems B.1 Restore one FWLCS inoperable.

subsystem to OPERABLE status. C. Required Action and C.1 ------NOTE---------

associated Completion LCO 3.0.4.a is not Time not met. applicable when entering MODE 3. -------------------

Be in MODE 3. SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3 . 6. 1. 8 .1 Verify RHR jockey pump operates properly.

FWLCS 3.6.1.8 COMPLETION TIME 30 days 7 days 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY 31 days GRAND GULF 3.6-24 Amendment No. __ _

3.6 CONTAINMENT

SYSTEMS MSIV LCS 3.6.1.9 3.6.1.9 Main Steam Isolation Valve (MSIV) Leakage Control System (LCS) LCO 3.6.1. 9 Two MSIV LCS subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION A. One MSIV LCS subsystem A.1 Restore MSIV LCS inoperable.

subsystem to OPERABLE status. B. Two MSIV LCS B.1 Restore one MSIV LCS subsystems inoperable.

subsystem to OPERABLE status. C. Required Action and C.1 -------NOTE-------

associated Completion LCO 3.0.4.a is not Time not met. applicable when entering MODE 3. ------------------

Be in MODE 3. SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3 . 6 . 1. 9 . 1 Operate each outboard MSIV LCS blower 15 minutes. COMPLETION TIME 30 days 7 days 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY 31 days (continued)

GRAND GULF 3.6-25 Amendment No.

3.6 CONTAINMENT

SYSTEMS RHR Suppression Pool Cooling 3.6.2.3 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling LCO 3.6.2.3 Two RHR suppression pool cooling subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR suppression A.1 Restore RHR 7 days pool cooling subsystem suppression pool inoperable.

cooling subsystem to OPERABLE status. B. Required Action and B.1 ------NOTE--------

associated Completion LCO 3.0.4.a is not Time of Condition A applicable when not met. entering MODE 3. ------------------

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C. Two RHR suppression C.1 Restore one RHR 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months pool cooling suppression pool subsystems inoperable cooling subsystem to OPERABLE status D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition C AND --not met. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months D.2 Be in MODE 3. GRAND GULF 3.6-31 Amendment No.

3.6 CONTAINMENT

SYSTEMS 3.6.4.1 Secondary Containment Secondary Containment 3.6.4.1 LCO 3.6.4.1 The secondary containment shall be OPERABLE.

APPLICABILITY:

ACTIONS MODES 1, 2, and 3, During movement of recently irradiated fuel assemblies in the primary or secondary containment, During operations with a potential for draining the reactor vessel (OPDRVs).

CONDITION REQUIRED ACTION COMPLETION TIME A. Secondary containment A.1 Restore secondary 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months inoperable in MODE 1, containment to 2, or 3. OPERABLE status. B. Required Action and B.1 --------NOTE------

associated Completion Leo 3.0.4.a is not Time of Condition A applicable when not met. entering MODE 3. ------------------

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued)

GRAND GULF 3.6-42 Amendment No.

3.6 CONTAINMENT

SYSTEMS 3.6.4.3 Standby Gas Treatment (SGT) System LCO 3.6.4.3 Two SGT subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, SGT System 3.6.4.3 During movement of recently irradiated fuel assemblies in the primary or secondary containment, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION A. One SGT subsystem inoperable.

B. Required Action and associated Completion Time of Condition A not met in MODE 1, 2, or 3. C. Required Action and associated Completion Time of Condition A not met during movement of recently irradiated fuel assemblies in the primary or secondary containment or during OPDRVs. GRAND GULF A.1 B.1 REQUIRED ACTION Restore SGT subsystem to OPERABLE status.

LCO 3.0.4.a is not applicable when entering MODE 3. Be in MODE 3. -------------NOTE------------

LCO 3.0.3 is not applicable.

C.1 OR Place OPERABLE SGT subsystem in operation.

COMPLETION TIME 7 days 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately (continued) 3.6-49 Amendment No.

AC'rIONS ---CONDITION C. (continued)

D. Two SGT subsystems inoperable in MODE 1, 2, or 3. E. Two SGT subsystems inoperable during movement of recently .i.rradiated fuel assemblies in the primary or secondary containment or during OPDRVs. GRAND GULF REQUIRED ACTION C.2.l Suspend movement of recently irradiated fuel assemblies in the primary and secondary containment.

2\ND --C.2.2 Initiate action to suspend OPDRVs. 0.1 --------NOTE------

LCO 3.0.4.a is not applicable when entering MODE ') J. ------------------

Be in t10DE 3. E.l Suspend movement of recently irradiated fuel assemblies in the primary and secondary containment.

AND --E.2 Initiate action to suspend OPDRVs. SGT System 3.6.4.3 COMPLETION TIME Immediately IJllJnediately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately Immediat 3.6-50 Amendment No.

I ACTIONS (contin1led)

CONDITION C. One drywell purge 'l,Tacuum relief subsystem inoperable for reasons other than Conditi.:.m A. D. Required Action and associated Completion Time of Condition B or C not met. E. Two purge vacuum relief subs/stems for reasons other Condition A. than F. Two drywell post-LOCA vacuum relief sUbc;ystems inoperable for roasons other than CondLU.on l'L G. AND One drywell purge vaCU1.lnl relief sUbsystem inoperable for reasons other than Condi t.ion A. Required Action and associated C.l 0.1 E.l F.l G.1 Time of Condition A, AND E or F not met. G.2 GRAND GULF Drywell Vacuum Relief System 3.6.5.6 REQUIRED ACTION Restore drywell purge vacuum relief subsystem to OPERABLE status.

LCD 3.0.4.a is not when t100E 3. Be in

3. Restore one drywell purge vacuum relief subsyscem LO OPERABLE status. Restore one dr/well post-LOCA vacuum relief or drywell purge vacuum reLief subsystem to OPERABLE status. Be in t10DE 3. Be in Li00E 4. COMPLETION TIME 30 days 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 72 hours 72 hOLlrs 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours (continued) 3.6-65 PJrrendment No.

ACTIONS (continued)

CONDITION H. Two drywell purge H.l vacuum relief subsystems inoperable AND for reasons other than Condition A. H.2 AND One or two drywell post-LOCA vacuum relief subsystems inoperable for reasons other than Condition A. GRAND GULF Drywell Vacuum Relief System 3.6.5.6 REQUIRED ACTION COMPLETION TIME Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 3.6-66 Amendment No. HB,-

ACTIONS (continued)

CONDITION E. Required Action and E.l associated Completion Time of Condition A, C, or D not met. F Both SSW subsystems inoperable.

OR Two UHS cooling towers with one or more cooling tower fans inoperable.

OR UHS basin inoperable for reasons other than Condition C. SURVEILLANCE REQUIREMENTS F.l AND F.2 SURVEILLANCE REQUIRED ACTION LCO 3.0.4.a is not applicable when entering MODE 3. Be in MODE 3. Be in Mode 3. Be in Mode 4. SSW System and UHS 3.7.1 COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 12 hours 36 Hours FREQUENCY SR 3.7.1.1 Verify the water level of each UHS basin is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 2 7.25 ft. SR 3.7.1.2 Operate each SSW cooling tower fan for 31 days 2 15 minutes. (continued)

GRAND GULF 3.7-3 Amendment No.

ACTIONS (continued)

CONDITION C. Required Action and associated Completion Time of Condition A or B not met in MODE 1, or 2. D. Required Action and associated Completion Time of Condition A not met during OPORVs. GRAND GOLF C.l 0.1 OR 0.2 REQUIRED ACTION LCO 3.0.4.a is not applicable when entering MODE 3. Be in MODE 3. Place OPERABLE CRFA subsystem in isolation mode. Initiate action to suspend OPDRVs. CRFA System 3.7.3 COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately Immediately ( continued) 3.7-7 Amendment No. 145, ACTIONS (continued)

CONDITION REQUIRED ACTION E. Two CRFA subsystems E.l -------NOTE-------

inoperable in MODE 1, LCO 3.0.4.a is not 2, or 3 for reasons applicable when other than Condition entering MODE 3. B. ------------------

Be in MODE 3. F. Two CRFA subsystems F.l -------NOTE-------

inoperable during LCO 3.0.3 does not OPDRVs. apply. ------------------

OR -Initiate action to One or more CRFA suspend OPDRVs. subsystems inoperable due to inoperable CRE boundary during OPDRVs. SURVEILLANCE REQUIREMENTS SR 3.7.3.1 SR 3.7.3.2 SR 3.7.3.3 SR 3.7.3.4 SURVEILLANCE Operate each CRFA subsystem for 10 continuous hours with the heaters operating.

Perform required CRFA filter testing in accordance with the Ventilation Filter Testing Program (VFTP). Verify each CRFA subsystem actuates on an actual or simulated initiation signal. Perform required CRE unfiltered air inleakage testing in accordance with the Control Room Envelope Habitability Program. CRFA System 3.7.3 COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately FREQUENCY 31 days In accordance with the VFTP 24 months In accordance with the Control Room Envelope Habitability Program GRAND GULF 3.7-8 Amendment No. +/-4-§., 178,

3.7 PLANT

SYSTEMS Control Room AC System 3.7.4 3.7.4 Control Room Air Conditioning (AC) System LCO 3.7.4 Two control room AC subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION A. One control room AC subsystem inoperable.

B. Two control room AC subsystems inoperable.

C. Required Action and associated Completion Time of Condition A or B not met in MODE 1, 2, or 3. GRAND GULF A.1 B .1 AND REQUIRED ACTION Restore control room AC subsystem to OPERABLE status. Verify control room area temper:ature

S; 90°F. B.2 Restore one control room AC subsystem to OPERABLE status. C.1 -------NOTE-------

LCO 3.0.4.a is not applicable when entering fVIODE 3. Be in UIODE 3. COMPLETION TIME 30 days Once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 7 days 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued) 3.7-9 Amendment No. +/-2-G-, 145,

3.7 PLANT

SYSTEMS 3.7.5 Main Condenser Offgas Main Condenser Offgas 3.7.5 LCO 3.7.5 The gross gamma activity rate of the noble gases measured at the offgas recombiner effluent shall be 380 mCi/second after decay of 30 minutes. APPLICABLLITY:

MODE 1, MODES 2 and 3 with any steam jet air ejector (SJAE) in operation.

ACTIONS CONDITION REQUIRED ACTION COMPLETION A. Gross gamma activity A.1 Restore gross gamma 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months rate of the noble activity rate of the gases not within noble gases to within limit. limit. B. Required Action and B.1 Isolate SJAE. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. OR -B.2 -------NOTE-------

LCO 3.0.4. a is not applicable when entering MODE 3. ------------------

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GRAND GULF 3.7-12 Amendment No. TIME ACTIONS (continued)

CONDITION D. One required offsite circuit inoperable for reasons other than Condition F. AND One required DG inoperable for reasons other than Condition F. E. Two required DGs inoperable.

F. One automatic load sequencer inoperable.

G. Required Action and associated Completion Time of Condition A, B, C, D, E, or F not met. GRAND GULF REQUIRED ACTION -----------NOTE--------------

Enter applicable Conditions and Required Actions of LCO 3.8.7, "Distribution Systems C Operating," when any required division is energized as a result of Condition D. 0.1 OR -0.2 E.1 F.l G.1 Restore required offsite circuit to OPERABLE status. Restore required DG to OPERABLE status. Restore one required DG to OPERABLE status. Restore automatic load sequencer to OPERABLE status.

LCO 3.0.4.a is not applicable when entering MODE 3. Be in MODE 3. AC Sources -Operating 3.8.l COMPLETION TUlE 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 12 hours 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OR 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if Division 3 DG is inoperable 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 12 hours 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued) 3.8-4 Amendment No.

ACTIONS (continued)

CONDITION REQUIRED ACTION D. Required Action and 0.1 ---------NOTE

associated Completion LCO 3.0.4.a is not Time for Division I or applicable when 2 DC electrical power entering MODE 3. subsystem for -------------------

condition A, B, or C not met. Be in MODE 3. E. Division 3 DC E.1 Declare High Pressure electrical power Core Spray System subsystem inoperable inoperable.

for reasons other than Condition A. F. Required Action and F .1 Be in MODE 3. associated Completion Time for Division 3 DC AND --electrical power subsystem for F.2 Be in MODS 4. Condition A, B or E not met. SURVEILLANCE REQUIREMENTS S1'\ 3.8.4.1 SR 3.8.4.2 SURVEILLANCE Verify battery terminal voltage is 129 V on float charge. Verify no visible corrosion at battery terminals and connectors.

OR Verify battery connection resistance is 1.5 E-4 ohm for inter-cell connections, 1.5 E-4 ohm for inter-rack connections, S 1.5 E-4 ohm for inter-tier connections, and S 1.5 E-4 ohm for terminal connections.

AC Sources -Operating

3.8.1 COMPLETION

TItvIE 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours FREQUENCY 7 days 92 days (continued)

GRAND GULF 3.8-27 Amendment No.

Distribution Systems-Shutdown

3.8.8 ACTIONS

(continued)

CONDITION C. Required Action and associated Completion Time of Condition A or B not met. C.1 D. One or more Division 3 0.1 AC or DC electrical power distribution subsystems inoperable.

E. Two or more divisions E.1 with inoperable distribution subsystems that result in a loss of function.

SURVEILLANCE REQUIREMENTS SURVEILLANCE REQUIRED ACTION -------NOTE--------

LCO 3.0.4.a is not applicable when entering MODE 3. Be in MODE 3. Declare High Pressure Core Spray System inoperable.

Enter LCO 3.0.3. SR 3.8.7.1 Verify correct breaker alignments and voltage to required AC and DC electrical power distribution subsystems.

COMPLETION TUlE 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately Immediately FREQUENCY 7 days GRAND GULF 3.8-39 Amendment No.

Attachment 4 GNRO*2013/00065 Changes to Technical Specification Bases Pages (For Information Only)

BASES ACTIONS GRAND GULF B.1 (continued)

RPS Electric Power Monitoring B 3.3.8.2 OPERABLE assemblies may then be used to power one RPS bus. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is sufficient for the plant operations personnel to take corrective actions and is acceptable because it minimizes risk while allowing time for restoration or removal from service of the electric power monitoring assemblies.

Alternately, if it is not desired to remove the power supply(s) from service (e.g., as in the case where removing the power supply(s) from service would result in a scram or isolation), Condition C or D, as applicable, must be entered and its Required Actions taken. C.1 and C.2 If any Required Action and associated Completion Time of Condition A or B are not met in MODE 1, 2, or 3, the plant must be brought to a MODE in which overall plant risk is minimized.

The plant shutdown is accomplished by placing the plant in MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. (continued)

B 3.3-236 LBDeR 13028 BASES ACTIONS SURVEILLANCE REQUIREMENTS GRAND GULF RPS Electric Power Monitoring B 3.3.8.2 If any Required Action and associated Completion Time of Condition A or B are not met in MODE 4 or 5, with any control rod withdrawn from a core cell containing one or more fuel assemblies, the operator must immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies (Required Action 0.1). This Required Action results in the least reactive condition for the reactor core and ensures that the safety function of the RPS (e.g., scram of control rods) is not required.

All actions must continue until the applicable Required Actions are completed.

SR 3.3.8.2.1 A CHANNEL FUNCTIONAL TEST is performed on each overvoltage, undervoltage, and underfrequency channel to ensure that the entire channel will perform the intended function.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

As noted in the Surveillance, the CHANNEL FUNCTIONAL TEST is only required to be performed while the plant is in a condition in which the loss of the RPS bus will not jeopardize steady state power operation (the design of the system is such that the power source must be removed from service to conduct the Surveillance).

The 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is intended to indicate an outage of sufficient duration to allow for scheduling and proper performance of the Surveillance.

The 184 day Frequency and the Note in the Surveillance are based on guidance provided in Generic Letter 91-09 (Ref. 3). SR 3.3.8.2.2 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 is based upon the assumption of an 18 month caiibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. (continued)

B 3.3-237 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS (continued)

REFERENCES GRAND GULF SR 3.3.8.2.3 RPS Electric Power Monitoring B 3.3.8.2 Performance of a system functional test demonstrates a required system actuation (simulated or actual) signal. The discrete relays/logic of the system will automatically trip open the associated power monitoring assembly circuit breaker. Only one signal per power monitoring assembly is required to be tested. This Surveillance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function.

The system functional test of the Class 1 E circuit breakers is included as part of this test to provide complete testing of the safety function.

If the breakers are incapable of operating, the associated electric power monitoring assembly would be inoperable.

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 the Surveillance when performed at the 18 month Frequency.

1. FSAR, Section 8.3.1.1.5.

2. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. 3. NRC Generic Letter 91-09, "Modification of Surveillance Interval for the Electric Protective Assemblies in Power Supplies for the Reactor Protection System." B 3.3-238 LBDCR 13028 BASES ECCS -Operating B 3.5.1 ACTIONS C.1 (continued)

GRAND GULF With two ECCS injection subsystems inoperable or one ECCS injection and one ECCS spray subsystem inoperable, at least one ECCS injection/spray subsystem must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In this Condition, the remaining OPERABLE subsystems provide adequate core cooling during a LOCA. However, overall ECCS reliability is reduced in this Condition because a single failure in one of the remaining OPERABLE subsystems concurrent with a design basis LOCA may result in the ECCS not being able to perform its intended safety function.

Since the ECCS availability is reduced relative to Condition A, a more restrictive Completion Time is imposed. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is based on a reliability study, as provided in Reference

12. If any Required Action and associated Completion Time of Condition A, S, or C are not met, the plant must be brought to a MODE in which overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 13) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action 0.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. (continued)

B 3.5-7 LBDCR 13028 BASES ECCS -Operating B 3.5.1 ACTIONS E.1 (continued)

GRAND GULF The LCO requires eight ADS valves to be OPERABLE to provide the ADS function.

Reference 14 contains the results of an analysis that evaluated the effect of one ADS valve being out of service. Per this analysis, operation of only seven ADS valves will provide the required depressurization.

However, overall reliability of the ADS is reduced because a single failure in the OPERABLE ADS valves could result in a reduction in depressurization capability.

Therefore, operation is only allowed for a limited time. The 14 day Completion Time is based on a reliability study (Ref. 12) and has been found to be acceptable through operating experience.

F.1 and F.2 If anyone low pressure ECCS injection/spray subsystem is inoperable in addition to one inoperable ADS valve, adequate core cooling is ensured by the OPERABILITY of HPCS and the remaining low pressure ECCS injection/spray subsystems.

However, the overall ECCS reliability is reduced because a single active component failure concurrent with a design basis LOCA could result in the minimum required ECCS equipment not being available.

Since both a portion of a high pressure (ADS) and a low pressure subsystem are inoperable, a more restrictive Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is required to restore either the low pressure ECCS injection/spray subsystem or the ADS valve to OPERABLE status. This Completion Time is based on a reliability study (Ref. 12) and has been found to be acceptable through operating experience.

If any Required Action and associated Completion Time of Condition E or F are not met or if two or more ADS valves are inoperable, the plant must be brought to a MODE in which overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 13) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. (continued)

B 3.5-8 LBDCR 13028 BASES ACTIONS (continued)

GRAND GULF G.1 ECCS -Operating B 3.5.1 Required Action G.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. When multiple ECCS subsystems are inoperable, as stated in Condition H, the plant is in a degraded condition not specifically justified for continued operation, and may be in a condition outside of the accident analyses.

Therefore, LCO 3.0.3 must be entered immediately.

B 3.5-8a LBDCR 13028 BASES ECCS -Operating B 3.S.1 SURVEILLANCE ,SR 3.S.1.2 (continued)

REQUIREMENTS GRAND GULF capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable.

This allows operation in the RHR shutdown cooling mode during MODE 3 if necessary or alignment to allow for the operation of the ADHRS when MODE 4 is reached. SR 3.S.1.3 Verification every 31 days that ADS accumulator supply pressure is 1S0 psig assures adequate air pressure for reliable ADS operation.

The accumulator on each ADS valve provides pneumatic pressure for valve actuation.

The designed pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator, at least two valve actuations can occur with the drywell at 70% of design pressure (Ref. 1S). The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure of 1S0 psig is provided by the ADS Instrument Air Supply System. The 31 day Frequency takes into consideration administrative control over operation of the Instrument Air Supply System and alarms for low air pressure.

SR 3.S.1.4 The performance requirements of the ECCS pumps are determined through application of the 10 CFR SO, Appendix K, criteria (Ref. 8). This periodic Surveillance is performed (in accordance with the ASME requirements (Ref. i 9) for the ECCS pumps) to verify that the ECCS pumps will develop the flow rates required by the respective analyses.

The ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of 10 CFR S0.46 (Ref. 10). The pump flow rates are verified against a system head that is equivalent to the RPV pressure expected during a LOCA. The total system pump outlet pressure is adequate to overcome the elevation head pressure between the pump suction and the vessel discharge, the piping friction losses, and RPV pressure present during LOCAs. These values may be established during pre-operational testing. A 92 day Frequency for this Surveillance is in accordance with the Inservice Testing Program requirements. (continued)

B 3.S-10 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS (continued)

GRAND GULF SR 3.5.1.6 ECCS -Operating B 3.5.1 The ADS designated S/RVs are required to actuate 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 LCO 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 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 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.

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 required ADS valve (those valves removed and replaced to satisfy SR 3.4.4.1) is performed to verify that the valve is functioning properly.

This SR can be demonstrated by one of two methods. If performed by method 1), plant startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME requirements (Ref. 20), prior to valve installation.

Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test. The 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed for manual actuation after the required pressure is reached is sufficient to achieve stable conditions for testing and (continued)

B3.5-12 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS GRAND GULF SR 3.5.1.7 (continued)

ECCS -Operating B 3.5.1 alternately tested. The Frequency of the required relief-mode actuator testing was developed based on the tests required by ASME OM, Part 1, (Ref. 20) as implemented by the Inservice Testing Program of Specification 5.5.6. The testing Frequency required by the Inservice Testing Program is based on operating experience and valve performance.

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

SR 3.5.1.8 This SR ensures that the HPCS System response time is less than or equal to the maximum value assumed in the accident 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 (Ref. 17). The diesel generator starting and any sequence loading delays along with the Reactor Vessel Water Level -Low Low, Level 2 confirmation delay permissive must be added to the HPCS System equipment response times to obtain the HPCS System ECCS SYSTEM RESPONSE TIME. The acceptance criterion for the HPCS System ECCS SYSTEM RESPONSE TIME is # 32 seconds. HPCS System ECCS SYSTEM RESPONSE TIME tests are conducted every 24 months. This Frequency is consistent with the typical industry refueling cycle and is based on industry operating experience. ( continued)

B 3.5-13a LBDCR 13028 BASES REFERENCES GRAND GULF 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. FSAR, Section 6.3.2.2.3.

FSAR, Section 6.3.2.2.4.

FSAR, Section 6.3.2.2.1.

FSAR, Section 6.3.2.2.2.

FSAR, Section 15.2.8. FSAR, Section 15.6.4. FSAR, Section 15.6.5. 10 CFR 50, Appendix K. FSAR, Section 6.3.3. 10 CFR 50.46. FSAR, Section 6.3.3.3. ECCS -Operating B 3.5.1 12. Memorandum from R.L. Baer (NRC) to V. Ste/lo, Jr. (NRC), "Recommended Interim Revisions to LCO's for ECCS Components," December 1, 1975. 13. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. 14. FSAR, Section 6.3.3.7.8

15. FSAR, Section 7.3.1.1.1.4.2.

16. GNRI-96/00229, Amendment 130 to the Operating License. 17. NEDO-32291-A, "System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995. 18. GNRI-97/00181, Amendment 133 to the Operating License. 19. ASME/ANSI OM-1987, Operation and Maintenance of Nuclear Pumps in Light Water Reactor Power Plants. 20. ASME Code of Operation and Maintenance of Nuclear Power Plants, Part 1. ( continued)

B 3.5-14 LBDCR 13028 LLS Valves B 3.6.1.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.6 Low-Low Set (LLS) Valves BASES BACKGROUND The safety/relief valves (S/RVs) can actuate either in the relief mode, the safety mode, the Automatic Depressurization System mode, or the LLS mode. In the LLS mode (one of the power actuated modes of operation), a pneumatic operator and mechanical linkage overcome the spring force and open the valve. The main valve can be maintained open with valve inlet steam pressure as low as 0 psig. The pneumatic operator is arranged so that its malfunction will not prevent the valve disk from lifting if steam inlet pressure exceeds the safety mode pressure setpoints.

Six of the S/RVs are equipped to provide the LLS function.

The LLS logic causes two LLS valves to be opened at a lower pressure than the relief or safety mode pressure setpoints and causes all the LLS valves to stay open longer, such that reopening of more than one S/RV is prevented on subsequent actuations.

Therefore, the LLS function prevents excessive short duration S/RV cycles with valve actuation at the relief setpoint.

Each S/RV discharges steam through a discharge line and quencher to a location near the bottom of the suppression pool, which causes a load on the suppression pool wall. Actuation at lower reactor pressure results in a lower load. APPLICABLE The LLS relief mode functions to ensure that the containment design SAFETY ANALYSES basis of one S/RV operating on "subsequent actuations" is met (Ref. 1). LCO GRAND GULF In other words, multiple simultaneous openings of S/Rvs (following the initial opening) and the corresponding higher loads, are avoided. The safety analysis demonstrates that the LLS functions to avoid the induced thrust loads on the S/RV discharge line resulting from "subsequent actuations" of the S/RV during Design Basis Accidents (DBAs). Furthermore, the LLS function justifies the primary containment analysis assumption that multiple simultaneous S/RV openings occur only on the initial actuation for DBAs. Even though six LLS S/RVs are specified, all six LLS S/RVs do not operate in any DBA analysis.

LLS valves satisfy Criterion 3 of the NRC Policy Statement.

Six LLS valves are required to be OPERABLE to satisfy the assumptions of the safety analysis (Ref. 2). The requirements of this LCO are applicable to the mechanical and electrical/pneumatic capability of the LLS valves to function for controlling the opening and closing of the S/RVs. (continued)

B 3.6-32 LBDCR 13028 BASES APPLICABILITY ACTIONS GRAND GULF LLS Valves B 3.6.1.6 In MODES 1, 2, and 3, an event could cause pressurization of the reactor and opening of S/RVs. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the LLS valves OPERABLE is not required in MODE 4 or 5. With one LLS valve inoperable, the remaining OPERABLE LLS valves are adequate to perform the designed function.

However, the overall reliability is reduced. The 14 day Completion Time takes into account the redundant capability afforded by the remaining LLS S/RVs and the low probability of an event in which the remaining LLS S/RV capability would be inadequate.

If the inoperable LLS valve cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent to OPERABLE status will be short.

However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action B.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems ( continued)

B 3.6-33 LBDCR 13028 BASES ACTIONS SURVEILLANCE REQUIREMENTS GRAND GULF C.1 and C.2 LLS Valves B 3.6.1.6 If two or more LLS valves are inoperable, there could be excessive short duration S/RV cycling during an overpressure event. The plant must be brought to a condition 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 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. SR 3.6.1.6.1 A manual actuation of each required LLS valve (those valves removed and replaced to satisfy SR 3.4.4.1) is performed to verify that the valve is functioning properly.

This SR can be demonstrated by one of two methods. If performed by method 1), plant startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME requirements (Ref. 4), prior to valve installation.

Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test. The 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed for manual actuation after the required pressure is reached is sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SR. If performed by method 2), valve OPERABILITY has been demonstrated for all installed LLS valves based upon the successful operation of a test sample of S/RVs. 1. Manual actuation of the LLS valve, with verification of the response of the turbine control valves or bypass valves, by a change in the measured steam flow, or 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 LLS valves divert steam flow upon opening. Sufficient time is therefore allowed after the required pressure and flow are 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.

2. The sample population of S/RVs tested each refueling outage to satisfy SR 3.4.4.1 will be stroked in the relief mode during "as-found" testing to verify proper operation of the S/RV. Just prior to installation of the to be newly-installed S/RVs to satisfy SR 3.4.4.1 the valve will be stroked in the relief mode during certification testing to verify proper operation of the S/RV. (continued)

B 3.6-34 LBDCR 13028 SURVEILLANCE REQUIREMENTS REFERENCES GRAND GULF SR 3.6.1.6.1 (continued)

The successful performance of the test sample of S/RVs provides reasonable assurance that the remaining installed S/RVs will be perform in a similar fashion. After the S/RVs are replaced, the electrical and pneumatic connections shall be verified either through mechanical/electrical inspection or test prior to the resumption of electric power generation to ensure that no damage has occurred to the S/RV during transportation and installation.

This verifies that each replaced S/RV will properly perform its intended function.

The STAGGERED TEST BASIS Frequency ensures that both solenoids for each LLS valve relief-mode actuator are alternatively tested. The Frequency of the required relief-mode actuator testing is based on the tests required by ASME OM Part 1 (Ref. 3), as implemented by the Inservice Testing Program of Specification 5.5.6. The testing Frequency required by the Inservice Testing Program is based on operating experience and valve performance.

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

4) SR 3.6.1.6.2 The LLS designed S/RVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to verify that the mechanical portions (Le., solenoids) of the automatic LLS function operate as designed when initiated either by an actual or simulated automatic initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.5.4 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 these components usua!ly pass the Surveillance when performed at the 18 month Frequency.

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

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

This prevents a reactor pressure vessel pressure blowdown.

1. 2. 3. 4. 5. GESSAR-II, Appendix 3B, Attachment A, Section 3BA.8. FSAR, Section 5.2.2.2.3.3.

NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. ASME Code for Operation and Maintenance of Nuclear Power Plants, Part 1. GNRI-96/00229, Amendment 130 to the Operating License. B 3.6-35 LBDCR 13028 BASES RHR Containment Spray System B 3.6.1.7 ACTIONS B.1 (continued)

GRAND GULF With two RHR containment spray subsystems inoperable, one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . In this Condition, there is a substantial loss of the primary containment bypass leakage mitigation function.

The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and because alternative methods to remove heat from primary containment are available.

If the inoperable RHR containment spray subsystem cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state,. Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Times is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. (continued)

B 3.6-38 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS GRAND GULF SR 3.6.1.7.1 RHR Containment Spray System B 3.6.1.7 Verifying the correct alignment for manual, power operated, and automatic valves in the RHR containment spray mode flow path provides assurance that the proper flow paths will exist for system operation.

This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these were verified to be in the correct position prior to locking, sealing, or securing.

This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position.

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency of this SR is justified because the valves are operated under procedural control and because improper valve position would affect only a single subsystem.

This Frequency has been shown to be acceptable based on operating experience.

A Note has been added to this SR that allows RHR containment spray subsystems to be considered OPERABLE during alignment to and operation in the RHR shutdown cooling mode when below the RHR cut in permissive pressure in MODE 3, if capable of being manually realigned and not otherwise inoperable.

At these low pressures and decay heat levels (the reactor is shut down in MODE 3), a reduced complement of subsystems should provide the required containment pressure mitigation function thereby allowing operation of an RHR shutdown cooling loop when necessary.

SR 3.6.1.7.2 Verifying each RHR pump develops a flow rate 7450 gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that pump performance has not degraded below the required flow rate during the cycle. It is tested in the pool cooling mode to demonstrate pump OPERABILITY without spraying down equipment in primary containment.

Flow is a normal test of centrifugal pump performance required by the ASME Code,Section XI (Ref. 3). 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 SR is in accordance with the Inservice Testing Program. ( continued)

B 3.6-39 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS REFERENCES GRAND GULF SR 3.6.1.7.3 RHR Containment Spray System B 3.6.1.7 This SR verifies that each RHR containment spray subsystem automatic valve actuates to its correct position upon receipt of an actual or simulated automatic actuation signal. Actual spray initiation is not required to meet this SR. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.3.6 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 the Surveillance when performed at the 18 month Frequency.

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

1. FSAR, Section 6.2.1.1.5.

2. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. 3. ASME, Boiler and Pressure Vessel Code,Section XI. B 3.6-40 LBDCR 13028 BASES APPLI CABI LlTY ACTIONS GRAND GULF FWLCS B 3.6.1.8 In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to 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, the FWLCS is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.

With one FWLCS subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE FWLCS subsystem is adequate to perform the leakage control function.

The 30 day Completion Time is based on the low probability of the occurrence of a LOCA, the amount of time available after the event for operator action to prevent exceeding this limit, the low probability of failure of the OPERABLE FWLCS subsystem, and the availability of the PCIVs. With two FWLCS subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 7 days. The 7 day Completion Time is based on the low probability of the occurrence of a DBA LOCA, the availability of operator action, and the availability of the PCIVs. If the inoperable FWLCS subsystem cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. ( continued)

B 3.6-42 LBDCR 13028 BASES (continued)

ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES GRAND GULF C.1 (continued)

FWLCS B 3.6.1.8 Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.6.1.8.1 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. 1. FSAR, Section 15.6.5. 2. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.6-43 LBDCR 13028 BASES ACTIONS ( continued)

SURVEILLANCE REQUIREMENTS GRAND GULF MSIV LCS B 3.6.1.9 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 overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a riskassessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Times is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.6.1.9.1 Each outboard MSIV LCS blower is operated for 15 minutes to verify OPERABILITY.

The 31 day Frequency was developed considering the known reliability of the LCS blower and controls, the two subsystem redundancy, and the low probability of a significant degradation of the MSIV LCS subsystem occurring between surveillances and has been shown to be acceptable through operating experience. (continued)

B 3.6-46 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS ( continued)

REFERENCES GRAND GULF SR 3.6.1.9.2 Deleted SR 3.6.1.9.3 MSIV LCS B 3.6.1.9 A system functionai 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. 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 the Surveillance when performed at the 18 month Frequency.

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

1. FSAR, Section 6.7.1. 2. FSAR, Section 15.6.5. 3. NEDC-32988-A, Revision 2, Technical Justification to Support Risk Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.6-47 LBDCR 13028 BASES RHR Suppression Pool Cooling B 3.6.2.3 APPLICABLE The RHR Suppression Pool Cooling System satisfies SAFETY ANALYSES Criterion 3 of the NRC Policy Statement. (continued)

LCO APPLICABILITY ACTIONS GRAND GULF During a DBA, a minimum of one RHR suppression pool cooling subsystem is required to maintain the primary containment peak pressure and temperature below the design limits (Ref. 1). To ensure that these requirements are met, two RHR suppression pool cooling subsystems must be OPERABLE.

Therefore, in the event of an accident, at least one subsystem is OPERABLE, assuming the worst case single active failure. An RHR suppression pool cooling subsystem is OPERABLE when the pump, two heat exchangers, and associated piping, valves, instrumentation, and controls are OPERABLE.

In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment and cause a heatup and pressurization of primary containment.

In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the RHR Suppression Pool Cooling System is not required to be OPERABLE in MODE 4 or 5. With one RHR suppression pool cooling subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining RHR suppression pool cooling subsystem is adequate to perform the primary containment cooling function.

However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment cooling capability.

The 7 day Completion Time is acceptable in light of the redundant RHR suppression pool cooling capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period. If one RHR suppression pool cooling subsystems inoperable and is not restored to OPERABLE status within the required Completion Time, the plant must be brought to a condition in which overall plant risk is minimized.

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 . (continued)

B 3.6-57 LBDCR 13028 BASES ACTIONS GRAND GULF B.1 (continued)

Suppression Pool Water Level B 3.6.2.2 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action B.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, an establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. With two RHR suppression pool cooling subsystems inoperable, one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . In this condition, there is a substantial loss of the primary containment pressure and temperature mitigation function.

The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and the potential avoidance of a plant shutdown transient that could result in the need for the RHR suppression pool cooling subsystems to operate. D.1 and D.2 If the Required Actions and required Completion Time of Condition C cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 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. B 3.6-58 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS REFERENCES GRAND GULF SR 3.6.2.3.1 Suppression Pool Water Level B 3.6.2.2 Verifying the correct alignment for manual, power operated, and automatic valves, in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists for system operation.

This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to being locked, sealed, or secured. A valve is also allowed to be in the nonaccident position, provided it can be aligned to the accident position within the time assumed in the accident analysis.

This is acceptable, since the RHR suppression pool cooling mode is manually initiated.

This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position.

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the subsystem is a manually initiated system. This Frequency has been shown to be acceptable, based on operating experience.

SR 3.6.2.3.2 Verifying each RHR pump develops a flow rate <:: 7450 gpm, with flow through the associated heat exchangers to the suppression pool, ensures that pump performance has not degraded during the cycle. Flow is a normal test of centrifugal pump performance required by ASME Section XI (Ref. 3). This test confirms one point on the pump design curve, and the results are indicative of overall performance.

Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance.

The Frequency of this SR is in accordance with the Inservice Testing Program. 1. FSAR, Section 6.2. 2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk Informed Modification to Selected Required End States for BWR Plants, December 2002. 4. ASME, Boiler and Pressure Vessel Code,Section XI. B 3.6-59 LBDCR 13028 BASES LCO (continued)

APPLICABILITY ACTIONS GRAND GULF Secondary Containment B 3.6.4.1 to the environment.

For the secondary containment to be considered OPERABLE, it must have adequate leak tightness to ensure that the required vacuum can be established and maintained.

In MODES 1,2, and 3, a LOCA could lead to a fission product release to primary containment that leaks to secondary containment.

Therefore, secondary containment OPERABILITY is required during the same operating conditions that require primary containment OPERABILITY.

In MODES 4 and 5, the probability and consequences of the LOCA are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining secondary containment OPERABLE is not required in MODE 4 or 5 to ensure a control volume, except for other situations for which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs) or during movement of recently irradiated fuel assemblies in the primary or secondary containment.

Due to radioactive decay, secondary containment is required to be OPERABLE only during that fuel movement involving the handling of recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ). If secondary containment is inoperable, it must be restored to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining secondary containment during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring secondary containment OPERABILITY) occurring during periods where secondary containment is inoperable is minimal. If the secondary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized.

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 . (continued)

B 3.6-85 LBDCR 13028 BASES ACTIONS GRAND GULF B.1 (continued)

Secondary Containment B 3.6.4.1 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3), because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action B.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. (continued)

B 3.6-85a LBDCR 13028 BASES Secondary Containment B 3.6.4.1 SURVEILLANCE SR 3.6.4.1.3 and SR 3.6.4.1.4 (continued)

REQUIREMENTS REFERENCES GRAND GULF these SRs is to ensure that the SGT subsystem, being used for the test, functions as designed.

There is a separate LCO 3.6.4.3 with Surveillance Requirements which serves the primary purpose of ensuring OPERABILITY of the SGT system. SRs 3.6.4.1.3 and 3.6.4.1.4 need not be performed with each SGT subsystem.

The SGT subsystem used for these Surveillances is staggered to ensure that in addition to the requirements of LCO 3.6.4.3, either SGT subsystem will perform this test. The inoperabiJity of the SGT system does not necessarily constitute a failure of these Surveillances relative to the secondary containment . OPERABILITY.

Operating experience has shown the secondary containment boundary usually passes these Surveillances when performed at the 18 month Frequency.

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

1. UFSAR, Section 15.6.5. 2. UFSAR, Section 15.7.4. 3. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.6-87a LBDCR 13028 BASES APPLICABILITY (continued)

ACTIONS GRAND GULF SGT System B 3.6.4.3 In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the SGT System OPERABLE is not required in MODE 4 or 5, except for other situations under which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs) or during movement of recently irradiated fuel assemblies in the primary or secondary containment.

Due to radioactive decay, the SGT System is required to be OPERABLE only during fuel movement involving the handling of recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ). With one SGT subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE SGT subsystem is adequate to perform the required radioactivity release control function.

However, the overall system reliability is reduced because a single failure in the OPERABLE subsystem could result in the radioactivity release control function not being adequately performed.

The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant SGT subsystem and the low probability of a DBA occurring during this period. If the SGT subsystem cannot be restored to OPERABLE status within the required Completion Time in MODE 1, 2, or 3, the plant must be brought to a MODE in which overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.

However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. (continued)

B 3.6-98 LBDCR 13028 BASES ACTIONS (continued)

GRAND GULF SGT System B 3.6.4.3 Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. C.1! C.2.1! and C.2.2 During movement of recently irradiated fuel assemblies in the primary or secondary containment or during OPDRVs, when Required Action A.1 cannot be completed within the required Completion Time, the OPERABLE SGT subsystem ( continued)

B 3.6-g8a LBDCR 13028 BASES ACTIONS GRAND GULF C.1 J C.2.1 J and C.2.2 (continued)

SGT System B 3.6.4.3 should be immediately placed in operation.

This Required Action ensures that the remaining subsystem is OPERABLE, that no failures that could prevent automatic actuation have occurred, and that any other failure would be readily detected.

An alternative to Required Action C.1 is to immediately suspend activities that represent a potential for releasing a significant amount of radioactive material to the secondary containment, thus placing the unit in a Condition that minimizes risk. If applicable, movement of recently irradiated fuel assemblies must be immediately suspended.

Suspension of these activities shall not preclude completion of movement of a component to a safe position.

Also, if applicable, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. This action should be chosen if the OPDRVs could be impacted by a loss of offsite power. Action must continue until OPDRVs are suspended.

The Required Actions of Condition C have been modified by a Note stating that LCO 3.0.3 is not applicable.

If moving recently irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving recently irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

Therefore, in either case, inability to suspend movement of recently irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

If both SGT subsystems are inoperable in MODE 1, 2, or 3, the SGT System may not be capable of supporting the required radioactivity release control function.

Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. (continued)

B 3.6-99 LDBCR 13028 BASES ACTIONS SURVEILLANCE REQUIREMENTS GRAND GULF 0.1 (continued)

SGT System B 3.6.4.3 Required Action 0.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. E.l and E.2 When two SGT subsystems are inoperable, if applicable, movement of recently irradiated fuel assemblies in the primary and secondary containment must be immediately 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 OPDRVs are suspended.

SR 3.6.4.3.1 Operating each SGT subsystem from the control room for 10 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 excessive vibration can be detected for corrective action. Operation with the heaters on (automatic heater cycling to maintain temperature) for 10 continuous hours every 31 days eliminates moisture on the adsorbers and HEPA filters. The 31 day Frequency was developed in consideration of the known reliability of fan motors and controls and the redundancy avaiiable in the system. (continued)

B 3.6-100 LBDCR 13028 BASES SGT System B 3.6.4.3 SURVEILLANCE SR 3.6.4.3.2 (continued)

REQUIREMENTS REFERENCES GRAND GULF This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). 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 This SR requires verification that each SGT subsystem starts upon receipt of an actual or simulated initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.2.6 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.

1. 10 CFR 50, Appendix A, GDC 41. 2. UFSAR, Section 6.5.3. 3. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.6-101 LBDCR 13028 BASES ACTIONS GRAND GULF A 1 (continued)

Drywell Vacuum Relief System B 30605.6 maintained, and is considered a reasonable length of time needed to complete the Required Action. A Note has been added to provide clarification that separate Condition entry is allowed for each vacuum relief subsystems not closed 0 B.1 and C01 With one or two drywell post-LOCA vacuum relief subsystems inoperable for reasons other than Condition A or one drywell purge vacuum relief subsystem inoperable for reasons other than Condition A, the inoperable subsystem(s) must be restored to OPERABLE status within 30 dayso In these Conditions, the remaining OPERABLE vacuum relief subsystems are adequate to perform the depressurization mitigation function since two 10 inch lines remain availableo The 30 day Completion Time takes into account the redundant capability afforded by the remaining subsystems, a reasonable time for repairs, and the low probability of an event requiring the vacuum relief subsystems to function occurring during this periodo If one or two drywell post-LOCA vacuum relief subsystems are inoperable for reasons other than not being closed or one drywell purge vacuum relief subsystem is inoperable for reasons other than not being closed, and not restored within the provided Completion Time, the plant must be brought to a condition in which the overall plant risk is minimizedo To achieve this status, the plant must be brought to at least MODE 3 within 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months so Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ret 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk stateo Required Action Do 1 is modified by a Note that states that LCO 300Aa is not applicable when entering MODE 30 This Note prohibits the use of LCO 300Aoa to enter MODE 3 during startup with the LCO not met (continued)

B 306-128 LBDCR 13028 BASES ACTIONS GRAND GULF 0.1 (continued)

Drywell Vacuum Relief System B 3.6.5.6 However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. E.1andF.1 With two drywell purge vacuum relief subsystems inoperable or with two drywell post-LOCA and one dryweli purge vacuum relief subsystems inoperable for reasons other than Condition A, at least one inoperable subsystem must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In these Conditions, only one 10 inch line remains available.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account at least one vacuum relief subsystem is still OPERABLE, a reasonable time for repairs, and the low probability of an event requiring the vacuum relief subsystems to function occurring during this period. G.1, G.2, H1, and H.2 If the inoperable drywell vacuum relief subsystem(s) cannot be closed or restored to OPERABLE status within the required Completion Time, or if two drywel/ purge vacuum relief subsystems are inoperable for reasons other than Condition A and one or two drywell post-LOCA vacuum relief subsystem(s) are inoperable for reasons other than Condition A, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 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. (continued)

B 3.6-129 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS GRAND GULF SR 3.6.5.6.1 Drywell Vacuum Relief System B 3.6.5.6 Each vacuum breaker and its associated isolation valve is verified to be closed (except when being tested in accordance with SR 3.6.5.6.2 and SR 3.6.5.6.3 or when the vacuum breakers or isolation valves are performing their intended design function) to ensure that this potential large bypass leakage path is not present. This Surveillance is performed by observing the vacuum breaker or associated isolation valve position indication.

The 7 day Frequency is based on engineering judgment, is considered adequate in view of other indications of vacuum breaker or isolation valve status available to the plant personnel, and has been shown to be acceptable through operating experience.

Two Notes are added to this SR. The first Note allows drywell vacuum breakers or isolation valves opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods are controlled by plant procedures and do not represent inoperable drywell vacuum breakers or isolation valves. A second Note is included to clarify that vacuum breakers or isolation valves open due to an actual differential pressure, are not considered as failing this SR. SR 3.6.5.6.2 Each vacuum breaker and its associated isolation valve must be cycled to ensure that it opens adequately to perform its design function and returns to the fully closed position.

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. ( contin ued) B 3.6-130 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS REFERENCES GRAND GULF SR 3.6.5.6.3 Drywell Vacuum Relief System B 3.6.5.6 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 S 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 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 under 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.

1. UFSAR, Section 6.2. 2. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. B3.6-131 LBDCR 13028 BASES SSW System and UHS B 3.7.1 ACTIONS C.1 (continued)

GRAND GULF A low water level in the UHS basin indicates that the required 30 day water supply for the post LOCA cooling requirements may not be available.

However, changes in water level for such a large volume are slowly occurring events and the degradation when discovered is unlikely to have significantly degraded the basin capability.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time was developed taking into account the remaining capability of the UHS basin, the low probability that this inoperability occurring during the assumed maximum heat load conditions, and the low probability of a DBA occurring during this period. If any Required Action and associated Completion Time of Condition A, C, or 0 are not met the unit must be placed in a MODE in which overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 8) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action E.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. (continued)

B 3.7-5 LBDCR 13028 BASES ACTIONS (continued)

SURVEILLANCE REQUIREMENTS GRAND GULF E1 SSW System and UHS B 3.7.1 If any both SSW subsystems are inoperable, or more than one of the UHS cooling towers have inoperable cooling tower fan(s), the unit must be placed in a MODE in which the LCO 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. SR 3.7.1.1 This SR ensures adequate long term (30 days) cooling can be maintained.

With the UHS water source below the minimum level, the UHS basin must be declared inoperable.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES. SR 3.7.1.2 Operating each cooling tower fan for 15 minutes ensures that all fans are OPERABLE and that all associated controls are functioning properly.

It also ensures that fan or motor failure, or excessive vibration can be detected for corrective action. The 31 day Frequency is based on operating experience, the known reliability of the fan units, the redundancy available, and the low probability of significant degradation of the cooling tower fans occurring between Surveillances.

SR 3.7.1.3 Verifying the correct alignment for each required manual, power operated, and automatic valve in each SSW subsystem flow path provides assurance that the proper flow paths win exist for SSW operation.

This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing.

A valve is also allowed to be in the nonaccident position and yet considered in the correct position, provided it can be automatically realigned to its accident position within the required 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. (continued)

B 3.7-6 LBDCR 13028 BASES SSW System and UHS B 3.7.1 SURVEILLANCE SR 3.7.1.3 (continued)

REQUIREMENTS REFERENCES GRAND GULF This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. Isolation of the SSW System to components or systems does not necessarily affect the OPERABILITY of the SSW subsystem.

As such, when all SSW pumps, valves, and piping are OPERABLE, but a branch connection off the main header is isolated, the SSW subsystem needs to be evaluated to determine if it is still OPERABLE.

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

SR 3.7.1.4 This SR verifies that the automatic isolation valves of the SSW System will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event. This is demonstrated by use of an actual or simulated initiation signal. This SR also verifies the automatic start capability of the SSW pump and cooling tower fans in each subsystem.

The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.5.1.6 overlaps this SR to provide complete testing of the safety function.

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

Therefore, this Frequency is concluded to be acceptable from a reliability standpoint.

1. Regulatory Guide 1.27, Revision 2, January 1976. 2. UFSAR, Section 9.2.1. 3. UFSAR, Table 9.2-3. 4. UFSAR, Section 6.2.1.1.3.3.

5. UFSAR, Chapter 15. 6. UFSAR, Section 6.2.2.3. 7. UFSAR, Table 6.2-2. 8. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.7-7 LBDCR 13028 BASES ACTIONS GRAND GULF B.1, B.2, and B.3 (continued)

CRFA System B 3.7.3 During the period that the CRE boundary is considered inoperable, action must be initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke. Actions must be taken within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to verify that in the event of a DBA, the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of DBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke. These mitigating actions (Le., actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable based on the low probability of a DBA occurring during this time period, and the use of mitigating actions. The 90 day Completion Time is reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability that CRE occupants will have to implement protective measures that may adversely affect their ability to control the reactor and maintain it in a safe shutdown condition in the event of a DBA. In addition, the 90 day Completion Time is a reasonable time to diagnose, plan and possible repair, and test most problems with the CRE boundary.

In MODE 1, 2, or 3, if the inoperable CRFA subsystem or the CRE boundary cannot be restored to OPERABLE status within the required Completion Time, the unit must be placed in a MODE that minimizes overall plant risk. 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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. (continued)

B 3.7-15 LBDCR 13028 BASES ACTIONS (continued)

GRAND GULF C.1 (continued)

CRFA System B 3.7.3 Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. D.1. and D.2 During OPDRVs, if the inoperable CRFA subsystem cannot be restored to OPERABLE status within the required Completion Time, the OPERABLE CRFA subsystem may be placed in the isolation mode. This action ensures that the remaining subsystem is OPERABLE, that no failures that would prevent actuation will occur, and that any active failure will be readily detected .. An alternative to Required Action D.1 is to immediately suspend activities that present a potential for releasing radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes accident risk. 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.

If both CRFA subsystems are inoperable in MODE 1, 2, or 3 for reasons other than an inoperable CRE, the CRFA System may not be capable of performing the intended function and the unit is in a condition outside of the accident analyses.

Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized.

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 . (continued)

B 3.7-16 LBDCR 13028 ACTIONS (continued)

GRAND GULF E.1 (continued)

CRFA System B 3.7.3 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action E.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. Required Action F.1 is modified by a note indicating that LCO 3.0.3 does not apply. During OPDRVs, with two CRFA subsystems inoperable, or with one or more CRFA subsystems inoperable, action must be taken immediately to suspend activities that present a potential for releasing radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes the accident risk. 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. (continued)

B 3.7-16a LBDCR 13028 BASES (continued)

SURVEILLANCE REQUIREMENTS GRAND GULF SR 3.7.3.1 CRFA System B 3.7.3 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. Furthermore, the 31 day Frequency is based on the known reliability of the equipment and the two subsystem redundancy available.

SR 3.7.3.2 This SR verifies that the required CRFA testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, and minimum system flow rate. 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 :::; 4 seconds on an actual or simulated initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.7.1.1 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 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.7.3.4 This SR verifies the OPERABILITY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program. (continued)

B 3.7-16b LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS REFERENCES GRAND GULF SR 3.7.3.4 (continued)

CRFA System B 3.7.3 The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of DBA consequences is no more than 5 rem TEDE and the CRE occupants are protected from hazardous chemicals and smoke. This SR verifies that the unfiltered air inleakage into the CRE is no greater than the flow rate assumed in the licensing basis analyses of DBA consequences.

When unfiltered air inleakage is greater than the assumed flow rate, Condition B must be entered. Required Action B.3 allows time to restore the CRE boundary to OPERABLE status provided mitigating actions can ensure that the CRE remains within the licensing basis habitability limits for the occupants following an accident.

Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3, which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 9). These compensatory measures may also be used as mitigating actions as required by Required Action B.2. Temporary analytical methods may also be used as compensatory measures to restore OPERABILITY (Ref. 10). Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis DBA consequence analysis, repairing the CRE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action, a full scope inleakage test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status. 1. FSAR, Section 6.5.1. 2. FSAR, Section 9.4.1. 3. FSAR, Chapter 6. 4. FSAR, Chapter 15. 5. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. 6. Engineering Evaluation Request 95/6213, Engineering Evaluation Request Response Partial Response dated 12/18/95.

7. Amendment 145 to GGNS Operating license. (continued)

B 3.7-16c LBDCR 13028 BASES REFERENCES (continued)

GRAND GULF 8. UFSAR, Section 9.5 9. NEI 99-03, Control Room Habitability Assessment, June 2001. CRFA System B 3.7.3 10. Letter from Eric J. Leeds (NRC) to James W. Davis (NEI) Use of Generic Letter 91-18 Process and Alternative Source Terms in the Context of Control Room Habitability." (ADAMS Accession No. ML04300694).

B 3.7-16d LBDCR 13028 BASES (continued)

LCO APPLICABI LlTY ACTIONS GRAND GULF Control Room AC System B 3.7.4 Two independent and redundant subsystems of the Control Room AC System are required to be OPERABLE to ensure that at least one is available, assuming a single failure disables the other subsystem.

Total system failure could result in the equipment operating temperature exceeding limits. The Control Room AC System is considered OPERABLE when the individual components necessary to maintain the control room temperature are OPERABLE in both subsystems.

These components include the cooling coils, fans, chillers, compressors, ductwork, dampers, and associated instrumentation and controls.

The heating coils are not required for Control Room AC System OPERABILITY.

In MODE 1, 2, or 3, the Control Room AC System must be OPERABLE to ensure that the control room temperature will not exceed equipment OPERABILITY limits. In MODES 4 and 5, the probability and consequences of a Design Basis Accident are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the Control Room AC System OPERABLE is not required in MODE 4 or 5, except during operations with a potential for draining the reactor vessel (OPDRVs).

With one control room AC subsystem inoperable, the inoperable control room AC subsystem must be restored to OPERABLE status within 30 days. With the unit in this condition, the remaining OPERABLE control room AC subsystem is adequate to perform the control room air conditioning function.

However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in loss of the control room air conditioning function.

The 30 day Completion Time is based on the low probability of an event occurring requiring control room isolation, the consideration that the remaining subsystem can provide the required protection, and the availability of alternate cooling methods. (continued)

B 3.7-18 LBDCR 13028 BASES ACTIONS GRAND GULF B.1 and B.2 Control Room AC System B 3.7.4 If both control room AC subsystems are inoperable, the Control Room AC System may not be capable of performing its intended function.

Therefore, the control room area temperature is required to be monitored to ensure that temperature is being maintained low enough that equipment in the control room is not adversely affected.

With the control room temperature being maintained within the temperature limit, 7 days is allowed to restore a control room AC subsystem to OPERABLE status. This Completion Time is reasonable considering that the control room temperature is being maintained within limits, the low probability of an event occurring requiring control room isolation, and the availability of alternate cooling methods. In MODE 1, 2, or 3, if the control room area temperature cannot be maintained less than or equal to 90°F or if the inoperable control room AC subsystem cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE that minimizes overall plant risk. 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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action B.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. (continued)

B 3.7-19 LBDCR 13028 BASES Control Room AC System B 3.7.4 ACTIONS E.1 (continued)

During OPDRVs if the Required Action and associated Completion Time of Condition B is not met, action must be taken to immediately 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, 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 3.7.4.1 REQUIREMENTS REFERENCES GRAND GULF This SR verifies that the heat removal capability of the system is sufficient to remove the control room heat load assumed in the safety analysis.

The SR consists of a combination of testing and calculation.

The 18 month Frequency is appropriate since significant degradation of the Control Room AC System is not expected over this time period. 1. FSAR, Section 6.4. 2. FSAR, Section 9.4.1. 3. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.7-21 LBDCR 13028 BASES (continued)

APPLICABILITY ACTIONS GRAND GULF Main Condenser Offgas B 3.7.5 The LCO is applicable when steam is being exhausted to the main condenser and the resulting noncondensibles are being processed via the Main Condenser Offgas System. This occurs during MODE 1, and during MODES 2 and 3 with any main steam line not isolated and the SJAE in operation.

In MODES 4 and 5, steam is not being exhausted to the main condenser and the requirements are not applicable.

If the offgas radioactivity rate limit is exceeded, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is allowed to restore the gross gamma activity rate to within the limit. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on engineering judgment considering the time required to complete the Required Action, the large margins associated with permissible dose and exposure limits, and the low probability of a Main Condenser Offgas System rupture occurring.

B.1, and B.2 If the gross gamma activity rate is not restored to within the limits within the associated Completion Time, the SJAE must be isolated.

This isolates the Main Condenser Offgas System from the source of the radioactive steam. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable, based on operating experience, to perform the actions from full power conditions in an orderly manner and without challenging unit systems. An alternative to Required Action B.1 is to place the unit in a MODE in which overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action B.2 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing (continued)

B 3.7-23 LBDCR 13028 BASES ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES GRAND GULF B.1! and B.2 (continued)

Main Condenser Offgas B 3.7.5 inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. SR 3.7.5.1 and 3.7.5.2 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 measured rate of radioactivity increases significantly (by ;:: 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. 1. FSAR, Section 15.7.1. 2. NUREG-0800.

3. 10 CFR 100. 4 NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.7-24 LBDCR 13028 BASES ACTIONS GRAND GULF E.1 (continued)

AC Sources -Operating B 3.8.1 remaining inoperable.

However, with a Division 1 or 2 DG remaining inoperable and the HPCS declared inoperable, a redundant required feature failure exists, according to Required Action B.2. E.J. Each sequencer is an essential support system to both the offsite circuit and the DG associated with a given ESF bus. Furthermore, the sequencer(s) is on the primary success path for most major AC electrically powered safety systems powered from the associated ESF bus. Although loss of an ESF bus's sequencer potentially affects the major ESF systems in the division, a design basis event with the worst single failure would not result in a complete loss of onsite power function (DGs) and would be mitigated to some extent by the redundant onsite sources. In addition, operator action to start the DG affected by the inoperable sequencer and manually connect the required ESF loads to either the affected DG or an available offsite source represents a significant benefit justifying an extended Completion Time over the condition of one DG and one offsite circuit inoperable.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining sequencer OPERABILITY.

This time period also ensures that the probability of an accident requiring sequencer OPERABILITY occurring during periods when the sequencer is inoperable is minimal. If the inoperable AC electrical power sources cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which overall plant risk is minimized.

To achieve this status, the unit must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 8) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action G.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment (continued)

B 3.8-13 LBDCR 13028 BASES ACTIONS (continued)

SURVEILLANCE REQUIREMENTS GRAND GULF G.1 (continued)

AC Sources -Operating B 3.8.1 addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. Condition H corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function.

Therefore, no additional time is justified for continued operation.

The unit is required by LCO 3.0.3 to commence a controlled shutdown.

The AC sources are designed to permit inspection and testing of all important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, GDC 18 (Ref. 9). Periodic component tests are supplemented by extensive functional tests during refueling outages under simulated accident conditions.

The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3), and Regulatory Guide 1.137 (Ref. 11). Where the SRs discussed herein specify voltage and frequency tolerances, the minimum steady state output voltage of 3744 Vand 4576 V respectively, are equal to +/- 10% of the nominal 4160 V output voltage. The specified maximum and minimum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively, are equal to +/- 2% of the 60 Hz nominal frequency.

The specified steady state voltage and frequency ranges are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3). (continued)

B 3.8-14 LBDCR 13028 BASES (continued)

REFERENCES GRAND GULF 1. 10 CFR 50, Appendix A, GDC 17. 2. UFSAR, Chapter 8. 3. Regulatory Guide 1.9, Revision 3. 4. UFSAR, Chapter 6. 5. UFSAR, Chapter 15. 6. Regulatory Guide 1.93. 7. Generic Letter 84-15, July 2,1984. AC Sources -Operating B 3.8.1 8. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. 9. 10 CFR 50, Appendix A, GDC 18. 10. Regulatory Guide 1.137. 11. ANSI C84.1, 1982. 12. ASME, Boiler and Pressure Vessel Code,Section XI. 13. !EEE Standard 308. 14. NUMARC 87-00, Revision 1, August 1991. 15. Letter from E.G. Adensam to L.F. Dale, dated July 1984. 16. GNRI-96/00151, Amendment 124 to the Operating License. 17. Generic Letter 94-01, May31, 1994. 18. GNRI-98/00016, Amendment 134 to the Operating License. 19. GNRI-2000/00065, Grand Gulf Nuclear Station, Unit 1 -Issuance of Amendment Re: Generic Changes to Improved Standard Technical Specifications, Amendment 142 to the Operating License. 20. ER-GG-2002-0466, Evaluation of P75 Standby Diesel Generators to Regulatory Guide 1.9, Rev. 3. B 3.8-34 LBDCR 13028 BASES ACTIONS GRAND GULF C.1 (continued)

DC Sources -Operating B 3.8.4 If one of the required Division 1 or 2 DC electrical power subsystems is inoperable for reasons other than its associated battery charger inoperable, the remaining DC electrical power subsystems have the capacity to support a safe shutdown and to mitigate an accident condition.

Since a subsequent worst case single failure could, however, result in the loss of minimum necessary DC electrical subsystems, continued power operation should not exceed 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 is based on Regulatory Guide 1.93 (Ref. 7) and reflects a reasonable time to assess unit status as a function of the inoperable DC electrical power subsystem and, if the DC electrical power subsystem is not restored to OPERABLE status, to prepare to effect an orderly and safe unit shutdown.

If a Division 1 or 2 DC electrical power subsystem is inoperable and not restored within the provided Completion Time, the plant must be brought to a condition in which overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than tile risk in MODE 4 (Ref. 8) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. Required Action 0.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. ( continued)

B 3.8-55 LBDCR 13028 BASES (continued)

ACTIONS SURVEILLANCE REQUIREMENTS GRAND GULF DC Sources -Operating B 3.8.4 With the Division 3 DC electrical power subsystem inoperable for reasons other than its associated battery charger inoperable, the HPCS System may be incapable of performing its intended functions and must be immediately declared inoperable.

This declaration also requires entry into applicable Conditions and Required Actions of LCO 3.5.1, "ECCS -Operating." F.1 and F.2 If the Division 3 DC electrical power subsystem cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 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. The Completion Time to bring the unit to MODE 4 is consistent with the time required in Reguiatory Guide 1.93 (Ref. 7). SR 3.8.4.1 Verifying battery terminal voltage while on float charge helps to ensure the effectiveness of the charging system and the ability of the batteries to perform their intended function.

Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery (or battery cell) and maintain the battery (or battery cell) in a fully charged state. The voltage requirements are based on the nominal design voltage of the battery and are consistent with the initial voltages assumed in the battery sizing calculations.

The 7 day Frequency is consistent with manufacturer's recommendations and IEEE-450 (Ref. 9). SR 3.8.4.2 Visual inspection to detect corrosion of the battery cells and connections, or measurement of the resistance of each inter-cell, inter-rack, inter-tier, and terminal connection, provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. (continued)

B 3.8-56 LBDCR 13028 BASES (continued)

SURVEILLANCE REQUIREMENTS GRAND GULF SR 3.8.4.2 (continued)

DC Sources -Operating B 3.8.4 The Surveillance Frequency for these inspections, which can detect conditions that can cause power losses due to resistance heating, is 92 days. This Frequency is considered acceptable based on operating experience related to detecting corrosion trends. SR 3.8.4.3 Visual inspection of the battery cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance.

The presence of physical damage or deterioration does not necessarily represent a failure of this SR, provided an evaluation determines that the physical damage or deterioration does not affect the OPERABILITY of the battery (its ability to perform its design function).

The Surveillance Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.32 (Ref. 10) and Regulatory Guide 1.129 (Ref. 11), 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. 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. (continued)

B 3.8-56a LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS (continued)

GRAND GULF SR 3.8.4.4 and SR 3.8.4.5 DC Sources -Operating B 3.8.4 Visual inspection and resistance measurements of inter-cell, inter-rack, inter-tier, and terminal connections provides an indication of physical damage or abnormal deterioration that could indicate degraded battery condition.

The anti-corrosion material is used to ensure good electrical connections and to reduce terminal deterioration.

The visual inspection for corrosion is not intended to require removal of and inspection under each terminal connection.

The removal of visible corrosion is a preventive maintenance SR. The presence of visible corrosion does not necessarily represent a failure of this SR, provided visible corrosion is removed during performance of this Surveillance.

For the purposes of this SR oxidation is not considered corrosion provided the resistance of the connection(s) is within limits. The 18 month Frequency of the Surveillance is based on engineering judgement, taking into consideration the desired unit conditions to perform the Surveillance.

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.

SR 3.8.4.6 Battery charger capability requirements are based on the design capacity of the chargers (Ref. 4). According to Regulatory Guide 1.32 (Ref. 10), the battery charger supply is required to be based on the largest combined demands of the various steady state loads and the charging capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand occurrences.

The minimum required amperes and duration ensure that these requirements can be satisfied.

The Surveillance Frequency is acceptable, given the unit conditions required to perform the test and the other administrative controls existing to ensure adequate charger performance during these 18 month intervals.

In addition, this Frequency is intended to be consistent with expected fuel cycle lengths. (continued)

B 3.8-57 LBDCR 13028 BASES SURVEILLANCE REQUIREMENTS (continued)

GRAND GULF SR 3.8.4.7 DC Sources -Operating B 3.8.4 A battery service test is a special test of the battery's capability, as found, to satisfy the design requirements (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. The Surveillance Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.32 (Ref. 10) 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. The Division 3 test may be performed in MODE 1,2, or 3 in conjunction with HPCS system outages. 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. 9) and IEEE-485 (Ref. 12). These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating. A capacity of 80% shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load reqUirements. ( continued)

B 3.8-58 LBDCR 13028 I BASES DC Sources -Operating B 3.8.4 SURVEILLANCE SR 3.8.4.8 (continued)

REQUIREMENTS REFERENCES GRAND GULF 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 100% of the manufacturer's rating. Degradation is indicated when the battery capacity drops by more than 10% of rated capacity relative to its capacity on the previous performance test or is below 90% of the manufacturer's rating. These Frequencies are based on the recommendations in IEEE-450 (Ref. 9). 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. The Division 3 test may be performed in MODE 1, 2, or 3 in conjunction with HPCS system outages. Credit may be taken for unplanned events that satisfy the Surveillance.

1. 10 CFR 50, Appendix A, GDC 17. 2. Regulatory Guide 1.6, March 10, 1971. 3. IEEE Standard 308, 1978. 4. UFSAR, Section 8.3.2. 5. UFSAR, Chapter 6. 6. UFSAR, Chapter 15. 7. Regulatory Guide 1.93, December 1974. 8. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modificationto Selected Required End States for BWR Plants, December 2002. 9. IEEE Standard 450, 1987. 10. Regulatory Guide 1.32, February 1977. 11. Regulatory Guide 1.129, December 1974. 12. IEEE Standard 485. B 3.8-59 LBDCR 13028 BASES ACTIONS GRAND GULF B.1 (continued)

Distribution Systems -Operating B 3.8.7 providing sufficient time for the operators to perform the necessary evaluations and actions for restoring power to the affected division; and c. The potential for an event in conjunction with a single failure of a redundant component.

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time for DC buses is consistent with Regulatory Guide 1.93 (Ref. 3). The second Completion Time for Required Action B.1 establishes a limit on the maximum time allowed for any combination of required distribution sUbsystems to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an AC bus is inoperable and subsequently returned OPERABLE, the LCO may already have been not met for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . This situation could lead to a total duration of 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months , since initial failure of the LCO, to restore the DC distribution system. At this time, an AC division could again become inoperable, and DC distribution could be restored OPERABLE.

This could continue indefinitely.

This Completion Time allows for an exception to the normal"time zero" for beginning the allowed outage time "clock." This allowance results in establishing the "time zero" at the time the LCO was initially not met, instead of the time Condition B was entered. The 16 hour1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months Completion Time is an acceptable limitation on this potential of failing to meet the LCO indefinitely.

If the inoperable electrical power distribution system cannot be restored to OPERABLE status within the associated Completion Times, the plant must be bought to a MODE in which overall plant risk is minimized.

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 . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. (continued)

B 3.8-77 LBDCR 13028 BASES ACTIONS GRAND GULF C.1 (continued)

Distribution Systems -Operating B 3.8.7 Required Action 0.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met. However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate.

LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. (continued)

B 3.8-77a LBDCR 13028 BASES ACTIONS (continued)

SURVEILLANCE REQUIREMENTS REFERENCES GRAND GULF Distribution Systems -Operating B 3.8.7 With the Division 3 electrical power distribution system inoperable, the Division 3 powered systems are not capable of performing their intended functions.

Immediately declaring the high pressure core spray inoperable allows the ACTIONS of LCO 3.5.1, "ECCS -Operating," to apply appropriate limitations on continued reactor operation.

Condition E corresponds to a level of degradation in the electrical distribution system that causes a required safety function to be lost. When more than one Condition is entered, and this results in the loss of a required function, the plant is in a condition outside the accident analysis.

Therefore, no additional time is justified for continued operation.

LCO 3.0.3 must be entered immediately to commence a controlled shutdown.

SR 3.8.7.1 Meeting this Surveillance verifies that the AC and DC electrical power distribution systems are functioning properly, with the correct circuit breaker alignment.

The correct breaker alignment ensures the appropriate separation and independence of the electrical divisions is maintained, and the appropriate voltage is available to each required bus. The verification of proper voltage availability on the buses ensures that the required voltage 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 AC and DC electrical power distribution subsystems, and other indications available in the control room that alert the operator to subsystem malfunctions.

1. UFSAR, Chapter 6. 2. UFSAR, Chapter 15. 3. Regulatory Guide 1.93, December 1974. 4. UFSAR, Section 8.3. 5. NEDC-32988-A, Revision 2, Technical Justification to Support Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.8-78 LBDCR 13028 Attachment 5 GNRO-2013/00065 Regulatory Commitment Attachment 5 to GNRO-2013/000065 Page 1 of 1 Regulatory Commitment The fol/owing table identifies the actions committed to by Entergy in this document.

Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments.

TYPE (Check one) SCHEDULED ONE-CONTINUING COMPLETION COMMITMENT TIME COMPLIANCE DATE ACTION Entergy will follow the guidance established in X Upon TSTF-IG-05-02 "Implementation Guidance for Implementation TSTF-423, Revision 2, Technical Specification End States, NEDC 32988-A" with one exception.

The fol/owing statement on page 2 does not apply: "If Primary Containment is not operable, Secondary Containment and Standby Gas Treatment must be verified operable in order to remain in Mode 3."

v t e Letter Sequence Request
TAC:MF3175, Technical Specifications End States, NEDC-32988-A (Approved, Closed)
Initiation Request, Request, Request, Request Acceptance, Acceptance Administration Questions 29 July 2014 Answers Results Approval Other: ML15027A183
MONTHYEAR2014-11-19 [Table View]

ML13316B024

Text

SUBJECT:

REFERENCE:

Dear Sir or Madam:

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

5.2 Applicable

7.0 REFERENCES

3.3 INSTRUMENTATION

3.5.1 COMPLETION

3.5.1 LuMPLETION

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.7 PLANT

3.7 PLANT

3.8.1 REQUIRED

3.8.7 COMPLETION

3.3 INSTRUMENTATION

3.5.1 COMPLETION

3.5.1 CONPLET1ON

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.6 CONTAINMENT

3.7 PLANT

3.7 PLANT

3.8.1 COMPLETION

3.8.8 ACTIONS

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