Text

Submittal of Revision 25 to the Fermi 2 Updated Final Safety Analysis Report (Ufsar), 10 CFR 50.59 and 10 CFR 72.48 Evaluation Summary Reports, Commitment Management Report, Revisions to the Technical Requirements Manual and the Technical
	ML24318C477
Person / Time
Site:	Fermi, 07200071
Issue date:	11/08/2024
From:	Domingos C; DTE Electric Company
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NRC-24-0056
	Download: ML24318C477 (1)
	v • d • e

Christopher P. Domingos Site Vice President DTE lectric Company 6400 N. Dixie I Iighway, Newport, Ml 48166 Tel: 734.586.5025 Fax: 734.586.5295 Email: christopher.dom ingos<md teenergv.com DTE Security-Related Information - Withhold Under 10 CFR 2.390 10 CFR 50.71(e)

November 08, 2024 NRC-24-0056 10 CFR 50.54(a)(3) 10 CFR 50.4(6)(6) 10 CFR 50.59(d)(2) 10 CFR 54.37(6) 10 CFR 72.48( d)(2)

U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 Fermi 2 Power Plant NRC Docket No. 50-341 and 72-71 NRC License No. NPF-43

Subject:

Submittal of Revision 25 to the Fermi 2 Updated Final Safety Analysi Report (UFSAR), 10 CFR 50.59 and 10 CFR 72.48 Evaluation Summary Reports, Commitment Management Report, Revisions to the Technical Requirements Manual and the Technical Specifications Bases, and a Summary of the Excessive Detail Removed from the UFSAR Pursuant to 10 CFR 50.71(e) and 10 CFR 50.4(6)(6), DTE Electric Company (DTE) hereby submits an electronic version of Revision 25 to the Fermi 2 Updated Final Safety Analysis Report (UFSAR).

In accordance with 10 CFR 50.71 (e), Revision 25 of the UFSAR reflects changes made as a result of license amendments and other changes made under the provi ion of 10 CFR 50.59.

Revision 25 includes plant configuration changes made through the end of the twenty-second refueling outage which concluded on May 12, 2024.

Sections, Tables, and Figures that have been changed in Revision 25 are marked "REV 25 11/24" in the lower right-hand corner of each page and are annotated by revision bars in the appropriate margin. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled.

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USNRC NRC-24-0056 Page 2 Security-Related Information - Withhold Under 10 CFR 2.390 In a previous UFSAR revision, numerous UF AR figures that are ba ed on control led plant drawings were removed from the UF AR and replaced with references to the controlled plant drawings. The current revi ions of the associated control led plant drawing are being provided electronically in Enclosures 2 and 3.

Based on NRC Regulatory I sue Summary (RTS) 2015-17, "Review and ubmission of Update to Final Safety Analysis Reports, Emergency Preparedness Documents, and Fire Protection Documents," DTE has reviewed Revision 25 of the UFSAR, and the associated controlled plant drawings being provided, for security-related information ( RI). contains the entire UFSAR Revision 25. contain mo t of the controlled plant drawings associated with UFSAR figure.

The Enclosure doe not contain any SRI and is suitable for public di closure. contains the remainder of the control led plant drawings associated with UFSAR figures. The Enclosure does contain SRI that should be withheld from public disclosure under 10 CFR 2.390.

This submittal also includes seven Attachments as described below: provides the l O CFR 50.59 Evaluation ummary Report including brief description of 10 FR 50.59 Evaluations performed since the previous report submitted with UFSAR Revision 24. This report is being submitted in accordance with the requirements of 10 CFR 50.59(d)(2). provides the Commitment Management Report which contains brief summarie of commitments that have been deleted or changed since the previous report submitted with UF AR Revision 24. OT 's Fermi 2 administrative programs and procedures are consistent with the Nuclear Energy lnstitute's (NEI) "Guidelines for Managing NRC Commitment Changes," NEI 99-04, Revision 0, dated July 1999. provides revised pages of Volume 1 of the Technical Requirements Manual (TRM) issued since the previous report submitted with UF AR Revision 24. The TRM is incorporated by reference in the UFSAR; therefore, these pages are being submitted in accordance with 10 CFR 50.71(e). provides revised pages of the Technical pecifications Bases (TSB) issued since the previous report submitted with UFSAR Revision 24. The e pages are being submitted in accordance with the TSB control program in Technical pecification Section 5.5.10. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled.

Security-Related Information - Withhold Unde1* 10 CFR 2.390 USNRC NRC-24-0056 Page3 provides a summary of changes made to remove excessive detail from the UFSAR. The removed information was determined to be redundant or obsolete and has been removed in accordance with the guidance contained in NEI 98-03, Revision 1, "Guidelines for Updating Final Safety Analysis Reports," and Regulatory Guide 1.181. provides the 10 CFR 72A8 Evaluation Summary Repoit including brief descriptions of 10 CPR 72.48 Evaluations performed in accordance with the general license under docket number 72-71 since the previous report submitted with UFSAR Revision 24.

This report is being submitted in accordance with the requirements of 10 CPR 72.48( d)(2). provides the results of the aging management review in accordance with the requirements of 10 CPR 54.37(6) for the Fermi 2 renewed license.

Should you have any questions or require additional information, please contact Mr. Eric Frank, Manager - Nuclear Licensing, at (734) 586-4 772.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on November 8, 2024 Cft(-

Christopher P. Domingos Site Vice President for Fermi 2 and NRC; Enclosures 2 & 3 for NRC Only:

1. UFSAR Revision 25

2. UFSAR Revision 25 Figures (CD For Public Use - For NRC Only) 3.* UFSAR Revision 25 SRI Figures (CD Contains SRI; Not For Public Use-For NRC Only)

Attachments:

I. 10 CPR 50.59 Evaluation Summary Report

2. Commitment Management Report

3. Summary of Revisions to Technical Requirements Manual, Volume I, and Revised Pages

4. Summary of Revisions to Technical Specifications Bases and Revised Pages

5. Summary of Excessive Detail Removed from the Fermi 2 UFSAR

6. 10 CFR 72.48 Evaluation Summary Report

7. License Renewal Requirements for 10 CFR 54.37 cc:

NRC Project Manager NRC Resident Office Regional Administrator, Region III contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled.

Security-Related Information - Withhold Under 10 CFR 2.390 ATTACHMENT 1 TO NRC-24-0056 10 CFR 50.59 Evaluation Summary Report contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled.

Security-Related Information - Withhold Under 10 CFR 2.390 Attachment I to NRC-24-0056 Page 1 10 CFR 50.59 Evaluation Summary Report 50.59 Evaluation No:

19-0042 Rev. A UFSAR Revision No.

Reference Document:

EDP-80057C02 Section(s) 10.2.2. 1 Table(s)

NIA Figure Change D Yes 25 CK] No Title of Change: EDP 80057C02 - Replacement of the Main Generator Static Excitation System This Engineering Design Package (EDP) replaces the Automatic Voltage Regulator (A VR). The existing system, an ABB UNITROL P unit, is considered obsolete and is being replaced with an ABB UNITROL 6000 X-Power static excitation system. Installation and implementation of this modification includes Instrumentation & Control (I&C) changes where existing functions performed using analog components will subsequently be handled with new digital components.

This includes the overcurrentrelay (newPIS#N30Kl021) in panel Hl I P841 which is currently an electro-mechanical relay, the excitation transformer temperature monitors (N30N363 &

N30N364) which will have a new digital output capability, and the rotor ground detection relay being replaced with a digital ground monitor. While all of these components are non-safety related and not required for establishing or maintaining the plant in a safe shutdown condition, failure of the A YR system can result in a turbine generator trip transient. The replacement A YR components incorporate digital control capabilities in place of the existing analog controllers which is a fundamental change to how the A YR system functions.

The proposed replacement of the existing analog components with digital equivalents as part of the A VR modification will not reduce the margin of safety as defined in the Technical Specifications, SER or UFSAR. The replacement digital components perform the same function as the existing analog components in supporting regulation of the main generator voltage and reactive power. Fai lure of a new digital component would have the same results as a failure of an existing analog component. There are no more than minimal effects to previously evaluated accidents or malfunctions, no potential for the creation of a new type of event no adverse impacts to fission product barriers and no impact to evaluation methodologies as described in the UFSAR.

Therefore, prior NRC approval of this change is not required. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled.

Security-Related Information - Withhold Under 10 CFR 2.390 to NRC-24-0056 Page 2 50.59 Evaluation No:

20-0 I 35 Rev. 0 UFSAR Revision No.

Reference Document:

EDP-80116 Section(s) 8.1, 8.2.1.3, 8.2.2.3, 8.3.1. 1.3 Table(s)

NIA Figure Change D Yes 25

~No Title of Change:

EDP 80116 - Transformer 65 Replacement with Load Tap Changer This Engineering Design Package (EDP) replaces System Service Transformer #65 (SS65)

(Rl 200S00 1) with a new unit that includes automatic load tap changers. The existing unit will not support Fermi 2's compliance with Nuclear Plant Operating Agreement (NPOA) requirements for meeting steady state voltage range and changes in switchyard voltage for agreed upon single contingencies when the suspension of operation of other regional power plants occurs by the end of 202 1. Installation and implementation of this modification includes Instrumentation & Control (I&C) changes where new monitoring and control instrumentation is added, and existing functions performed using analog components will subsequently be handled with new digital components. While SS65 is non-safety related and non-seismic it is the preferred power supply for the Division II engineered safety feature (ESF) buses. The incorporation of digital control capabilities in place of the existing analog controls constitutes a fundamental change to how SS65 functions.

The proposed replacement of System Service Transformer #65 (SS65) does not require prior approval by the NRC. The addition of digital components, the addition of an automatic tap changer, and the replacement of analog components with digital components that perform the same function does not result in a more than minimal increase in frequency/likelihood or consequences of accidents or malfunctions previously evaluated, does not create the potential for a new type of event or malfunction with a different result, and does not impact fission product barriers or evaluation methodologies. Postulated fai lures for the new transformer would have the same results as a failure of the existing transformer. Also, incorporation ofLTCs with the replacement transformer does not alter how it would fail when compared to the existing unit.

Based upon the results of this evaluation, the replacement of SS65 can be implemented per plant procedures without obtaining a License Amendment.

Therefore, prior NRC approval of this change is not required. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled.

Security-Related Information - Withhold Under 10 CFR 2.390 Attachment I to NRC-24-0056 Page 3 50.59 Evaluation No:

22-0103 Rev. 0 UFSAR Revision No.

Reference Document:

Procedure Section(s)

NIA 20.307.01 Table(s)

NIA Figure Change D Yes 25 Title of Change: Revision 22 to Procedure 20.307.01 based CARDs 22-28800 and 22-28738 CARD 22-28800, and 22-28738 document a concern with the design of the Emergency Diesel Generator (EDG) high crankcase trip in the event of a tornado occurring after a loss of off site power. A tornado differential pressure could cause the EDG crankcase high pressure trip. This trip is the result of environmental conditions present during the time a tornado is passing over the Residual Heat Removal (RHR) complex. Engineering has determined that this event is plausible and has a duration of approximately 30 seconds. The postulated EOG trip on high crankcase pressure during a design basis tornado is a non-conforming condition because UFSAR section 8.3.1.1.8.2.i states that The EDG system is designed to be operable during and after a design-basis tornado.

This evaluation determines that the additional actions required to re-start the EDGs (if a tornado causes them to trip) after a loss of offsite power does not increase the time to initiate Torus cooling to more than the time specified in the verification of time critical operator actions (20 min), therefore there will not be a negative effect on plant systems. The proposed activity does not result in more than a minimal increase in the frequency occurrence, nor the consequences of an accident previously evaluated in the UFSAR and does not result in more than a minimal increase in the likelihood of a malfunction of any Structures, Systems, and Components (SSC) important to safety nor the consequences of such a malfunction previously evaluated in the UFSAR. The proposed activity does not create a possibi lity for an accident of a different type than any previously evaluated in the UFSAR nor create the possibility for a malfunction of an SSC important to safety with different result than any previously evaluated in the UFSAR. There are no impacts to fission product barriers and there are no departures from a method of evaluation described in the UFSAR used in establishing the design bases or in the safety analyses.

Therefore, prior NRC approval of this change is not required. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled.

Security-Related Information - Withhold Under 10 CFR 2.390 to NRC-24-0056 Page 4 50.59 Evaluation No:

24-0059 Rev. 0 Reference Document:

CR 2023-35073 EDP-800005 UFSAR Revision No.

Section(s)

NIA Table(s)

NIA Figure Change D Yes 25 Title of Change:

Methodology Evaluation Regarding Use of AutoPIPE Version 23.00 (CR 2023-35073)

AutoPTPE is a computer aided engineering program for calculating piping stresses, flange analysis, pipe support design, and equipment nozzle loading analysis. It is referenced in UFSAR

§3.13.3.18 as a computer program for such purposes for both static and dynamic loading conditions. As established in NEI 96-07, Rev I, §4.2.1.3, the use of a revised method of evaluation is controlled under 1 0CFR50.59. Per the 50.59 process at Fermi 2, a software version change is evaluated under 10CFR50.59(c)(2)(viii) for a potential departure of methodology for an UFSAR described method.

This evaluation determines that use of computer code AutoPIPE, Version 23.00, in place of AutoPIPE, Version I 1.0 I, does not require prior NRC approval. This conclusion is based on the establishment that while there is a methodology revision, the changes made under Version 23.00 corrects identified errors in the mathematical algorithms and inputs into the mathematical algorithms to correct/restore the calculation final results to the intended mathematical calculation results and the results are essential ly the same between the two versions, with the exception of the specific corrected error/defect impacts. Therefore, use of AutoPIPE, Version 23.00, is not a departure from a method of evaluation described in the UFSAR used in establishing the design bases or in the safety analyses.

Therefore, prior NRC approval of this change is not required. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled.

Security-Related Information - Withhold Under 10 CFR 2.390 Attachment l to NRC-24-0056 Page 5 50.59 Evaluation No:

24-0090 Rev. 0 UFSAR Revision No.

Reference Document:

TSR l 00552 Section(s) 5.5.6.2.2 LCR 24-010-UFS Table(s)

NIA Figure Change D Yes 25 (I] No Title of Change:

Updates to DC-5779 Vol. I due to E5150F007 Valve Stroke Time Increase - TSR 100552 Rev.0 Tt was identified that the gearing in the E5 l 50F007 Reactor Core Isolation Cooling (RCIC)

Steam Line Primary Containment Inboard Isolation Valve was 23 seconds (21.4 seconds + 1.6 seconds margin), when in DC-5779 Vol I it was documented as 15 seconds. This was due to a change in gearing which was made in the past. Reference CR-2024-38279. The change in stroke time is evaluated on overall Mass and Energy Release using a hand calculation in DC-5779 Vol I, Pg. 33a, which is the same methodology as the original calculation. The change is justified by removing conservatism embedded within the break isolation time which included loss of offsite power when it was not required by the US NRC Standard Review Plan 3.6.1, BTP ASB 3-1 Section 3.b(l ), and using the actual valve flow curve provided by the E5 I 50F007 valve manufacturer (Powell) which can be found in TSR l 00552 Rev.0.

The calculation uses this available margin in the original calculation to compensate for the increased stroke time. A detailed review ofNUREG.0798, Safety Evaluation Report related to the operation of Enrico Fermi Atomic Power Plant, Unit No. 2, including Supplements 1 through 6 revealed that this margin was not credited by the NRC in the approval of the RCIC System.

The change in the E5 l 50F007 valve stroke timing from 15 seconds to 23 seconds (21.4 seconds

+ l.6 seconds margin) in Cale DC-5779 Volume 1 Page 20 has been evaluated in a hand calculation (which matches the original methodology.) The calculation offsets this increase in stroke time by not including a Loss of Offsite Power (LOP) event in the E5150F007 valve stroke timing. This will now match the stroke time for the E5 l 50F007 valve in Cale DC-2712, Volume

1. As the methodology for the calculations (hand calculation) impacted by this change match the original (hand calculation) and calculational assumptions and methodologies, the proposed activity does not result in a departure from a method of evaluation described in the UFSAR.

Therefore, prior NRC approval of this change is not required. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled.

Security-Related Information - Withhold Under 10 CFR 2.390 ATTACHMENT 2 TO NRC-24-0056 Commitment Management Report contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled

Security-Related Informatiou - Withhold Under 10 CFR 2.390 to NRC-24-0056 Page 1 Commitment Management Report Fermi 2 administrative programs and procedures are consistent with the Nuclear Energy Institute's (NEI) "Guidelines for Managing NRC Commitment Changes," NEI 99-04, Revision 0, dated July 1999. These guidelines discuss the need for a report to be submitted either annually or along with the UFSAR updates required by 10 CFR 50.7l(e).

This report involves changes that have been made in the Fermi 2 commitment management database (referred to as the Regulatory Action Commitment and Tracking System or RACTS).

Commitment changes are included in the following two tables:

Table I : Commitments that have been deleted from the Fermi 2 RACTS database because they are no longer applicable.

Table 2: Commitments that have been revised in the RACTS database. The table includes the original commitment and reference document in addition to a brief description of the change.

In some cases, the RACTS database contains items that are not regulatory commitments per the definition in NEI 99-04. Examples include internal tracking of actions that were never submitted to the NRC or tracking ofrecurring regulatory actions such as routine submittals. Changes to these types of RACTS items are not identified in Table l or Table 2 because the items were never regulatory commitments per the NEI 99-04 definition. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled to RC-24-0056 Page 2 Security-Related Information - Withhold Under 10 CFR 2.390 Table 1 Regulatory Commitments Deleted from the Regulatory Commitment Tracking System (RACTS)

RACTS ORIG.

REFERENCE DESCRIPTIO OF COMMITMENT BASIS FOR DELETIO NO.

DATE DOCUMENT 006659 9/19/ 1985 DTE Letter This commitment is to demonstrate a leak Due to becoming obsolete, this RC-LG-85-0041 tight integrity of the post LOCA thermal commitment is changed to one-time recombiner system, a system leakage test is closed. TS 5.5.2 was revi ed to delete conducted once per reactor refueling hydrogen recombiners.

(approximately once per 18 months) 020256 8/16/2007 DTE Letter This commitment was to maintain Due to becoming obsolete, the RC-07-0043 administrative controls to ensure that the commitment was changed to One-Time acceptance criteria for EDG surveillance Closed. The current Tech Spec values voltage verification account for potential approved in License Amendment 227 measurement uncertainty. This commitment

(+/- 0.85%) now contain additional was made in response to NRC letter dated margin to count for measurement July 3, 2007, "Request for Additional uncertainty to make these values Information Related to proposed License conservative with respect to required Amendment to Revise the Minimum Engineered Safety Feature (ESF) loads.

Emergency Diesel Generator Voltage in Therefore, the commitment no longer Technical Specification 3.8.1 urveillance needs to be embedded in administrative Requirements".

controls.

004103 11/26/1984 DTE Letter The commitment is to enhance the fuel oil The commitment was revised to reflect EF2-72015 system for the diesel fire pump and for the the replacement of the diesel fire pump starting diesel for the applicable combustion with a model that has been sized to turbine generator by installing a fuel oil provide the driving power for the pump warming device prior to the respective fuel to meet its performance requirements for filter.

outdoor cold weather use, therefore a fuel warmer is no longer required. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled to RC-24-0056 Page 3 Security-Related Information - Withhold Under 10 CFR 2.390 Table 2 Regulatory Commitments Revised in the Regulatory Commitment Tracking System (RACTS)

RACTS ORIG.

REFERE CE DESCRIPTIO OF COMMITMENT BASIS FOR NO.

DATE DOCUMENT COMMITMENT CHANGE 020318 4/24/2014 DTE Letter The commitment is to enhance the F2 self-assessment The commitment was RC-14-0028 process to provide for periodic evaluation of the revised to add the missing effectiveness of each aging management program aging management program described in the UFSAR supplement. For new aging for Coating Integrity for management programs, the first evaluation will be Internal Surfaces.

performed within five years of implementing the program (the initial estimated compliance date is based on the first new program being implemented by end of 2016).

020322 4/24/2014 DTE Letter The commitment is to enhance the BWR Vessel Internals The commitment i RC-14-0028 Program by evaluating the susceptibility to neutron or complete and the status thermal embrittlement for reactor vessel internal changed to ongoing -

components composed of cast austenitic stainless steel closed due to implementing (CA S) and X-750 alloy will be evaluated.

the open items of UFSAR Appendix B, Table B-1 Item 7.a.

020323 4/24/2014 DTE Letter The commitment is to enhance the BWR Vessel Internals The commitment is NRC-14-0028 Program. The BWR Vessel Internals Program procedures complete and the status wi 11 be revised as follows. Portions of the susceptible changed to ongoing -

components determined to be limiting from the standpoint closed due to implementing of thermal aging susceptibility, neutron f\\uence, and the open items of UFSAR cracking susceptibility (i.e., applied stress, operating Appendix B, Table B-1 temperature, and environmental conditions) will be Item 7.6.

inspected, using an inspection technique capable of detecting the critical flaw size with adequate margin. The contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled to RC-24-0056 Page 4 RACTS ORIG.

NO.

DATE 020324 4/27/2015 020325 4/24/2014 Security-Related Information - Withhold Under 10 CFR 2.390 REFERENCE DESCRIPTION OF COMMITME T BASIS FOR DOCUMENT COMMITMENT CHANGE initial inspection will be performed either prior to 03/20/2025 or before 03/20/2030. The program/procedure revisions will be performed prior to 09/20/2024, or the end of the last refueling outage prior to 03/20/2025, whichever is later.

DTE Letter The commitment is to enhance the BWR Vessel Internals The commitment is NRC-15-0044 Program. The BWR Vessel Internals Program will be complete and the status revi ed in accordance with applicant action item for changed to ongoing-BWRVIP-25 safety evaluation: (a) install core plate closed due to implementing wedges prior to the period of extended operation, or (b.)

the open items of UFSAR Complete a plant-specific analysis that justifies no Appendix B, Table B-1 inspections are required or (c.) Complete a plant-specific Item 7.c.

analysis to determine acceptance criteria for continued inspection of core plate hold-down bolts in accordance with BWRVIP-25.

DTE Letter The commitment is to enhance the Compressed Air The commitment was NRC-14-0028 Monitoring Program prior to 09/20/2024 revised to remove the air sampling requirement commitment UF AR Appendix B, Table B-1 Item 8.a. Removing the air sampling requirement of the commitment is justified since existing equipment installed in the system adequately serves the function of controlling starting air quality to within acceptable limits. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled to RC-24-0056 Page 5 RACTS ORIG.

NO.

DATE 020326 1/15/2015 020327 5/19/2015 020328 4/24/2014 Security-Related Information - Withhold Under 10 CFR 2.390 REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DOCUMENT COMMITMENT CHANGE DTE Letter The commitment is to enhance the Containment Inservice The commitment changed RC-15-0004 Inspection (CII) - TWE Program be enhanced prior to typo " UREG-1399" to 09/20/2024 or the end of the last refueling outage prior to REG-1339".

03/20/2025, whichever is later. The enhancements are to revise plant procedures.

The commitment i complete and the status changed to ongoing-closed due to implementing the open items of UF AR Appendix B, Table B-1 Item 9.

DTE Letter The commitment is to enhance the Diesel Fuel The commitment is RC-14-0056 Monitoring Program prior to 09/20/2024 or the end of the complete and the status last refueling outage prior to 03/20/2025, whichever is changed to ongoing-later. The enhancements are to revise plant procedures.

closed due to implementing UF AR Appendix B, Table B-1 Item 10.

DTE Letter The commitment is to enhance the Fatigue Monitoring The commitment was RC-14-0028 Program at least two years prior to 03/20/2025.

completed and the status changed to ongoing -

closed due to implementing the open items of UF AR Appendix B, Table B-1 Item 12. Changed closure date to 9/26/23 and Compliance Milestone to PEO. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled to NRC-24-0056 Page 6 RACTS ORIG.

NO.

DATE 020333 4/24/2014 020334 4/24/2014 020337 4/24/2014 020338 4/24/2014 020339 5/1 9/2015 Security-Related Information - Withhold Under 10 CFR 2.390 REFERENCE DESCRIPTION OF COMMITME T BASIS FOR DOCUMENT COMMITMENT CHANGE DTE Letter The commitment is to implement a ew Internal Surfaces The commitment is NRC-14-0028 in miscellaneous Piping and ducting Components complete and the status Program prior to 09/20/2024.

changed to ongoing-closed due to implementing the open items of UFSAR Appendix B, Table B-1 Item 18.

DTE Letter The commitment is to implement a ew Metal Enclosed The commitment is NRC-14-0028 Bus Inspection Program prior to 09/20/2014 or the end of complete and the status the last refueling outage prior to 03/20/2025, whichever is changed to ongoing -

later.

closed due to implementing the open items of UFSAR Appendix B, Table B-1 Item 19.

DTE Letter The commitment is to implement a new on-EQ The commitment is RC-14-0028 Inaccessible Power Cables (400 V to 13.8 kV) Program complete and the status prior to 09/20/2024 or the end of the last refueling outage changed to ongoing-prior to 03/20/2025, whichever is later.

closed due to implementing UFSAR Appendix B, Table B-1 Item 22.

DTE Letter The commitment is to implement a new on-EQ The commitment is NRC-14-0028 Instrumentation Circuits Test Review Program prior to complete and the status 09/20/24 or the end of the last refueling outage prior to changed to ongoing-03/20/2025, whichever is later.

closed due to implementing UFSAR Appendix B, Table B-1 Item 23.

DTE Letter The commitment is to implement a new Non-EQ The commitment is NRC-15-0056 Insulated Cables and Connections Program prior to complete and the status changed to ongoing - contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled to NRC-24-0056 Page 7 RACTS ORIG.

NO.

DATE 020340 4/24/2014 020341 4/24/2014 020342 4/24/2014 Security-Related Information - Withhold Under 10 CFR 2.390 REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DOCUMENT COMMITMENT CHANGE 09/20/24 or the end of the last refueling outage prior to closed due to implementing 03/20/2025, whichever is later.

UFSAR Appendix B, Table B-1 Item 24.

DTE Letter The commitment is to enhance the Oil Analysis Program The commitment is RC-14-0028 prior to 09/20/2024. The enhancements are to revise complete and the status procedures.

changed to ongoing-closed due to implementing UFSAR Appendix B, Table B-1 Item 25.

DTE Letter The commitment is to implement a new One-Time The commitment is RC-14-0028 Inspection Program with inspections performed within the complete and the status ten years prior to 03/20/2025.

changed to ongoing -

closed due to implementing UFSAR Appendix B, Table B-1 Item 26.

DTE Letter The commitment is to implement a new One-Time The commitment was NRC-14-0028 Inspection - Small-Bore Piping Program with inspection revised ASME edition from performed within the six-year period prior to 03/20/2025.

"2001 with 2003 Addenda" to "2013 Edition", since Fermi 2 is committed to the 2013 edition of the A ME Code Section XI and required to update to the latest edition every 10 years.

The commitment is complete and the status changed to ongoing-contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled to NRC-24-0056 Page 8 RACTS ORIG.

NO.

DATE 020343 4/24/2014 020346 4/24/2014 020347 4/24/2014 020348 4/24/2014 Security-Related Information - Withhold Under 10 CFR 2.390 REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DOCUMENT COMMITMENT CHANGE closed due to implementing UFSAR Appendix B, Table B-1 Item 27.

DTE Letter The commitment is to enhance the Protective Coating The commitment is NRC-14-0028 Monitoring and Maintenance Program prior to complete and the status 09/20/2024. The enhancements are to revise plant changed to ongoing -

procedures.

closed due to implementing UFSAR Appendix B, Table B-1 Item 29.

DTE Letter The commitment is to implement a new Selective The commitment is RC-14-0028 Leaching Program with inspection performed within 5 complete and the status years prior to 03/20/2025.

changed to ongoing -

closed due to implementing UFSAR Appendix B, Table B-1 Item 32.

DTE Letter The commitment is to enhance the Service Water The commitment is RC-14-0028 Integrity Program prior to 09/20/2024. The enhancements complete and the status are to revise plant procedures.

changed to ongoing -

closed due to implementing UFSAR Appendix B, Table B-1 Item 33.

DTE Letter The commitment is to enhance the tructures Monitoring The commitment is NRC-14-0028 Program prior to 09/20/2024. The enhancements are to complete and the status revise plant procedures.

changed to ongoing -

closed due to implementing UFSAR Appendix B, Table B-1 Item 34. contains Security-Related Information - Withhold Under 10 CFR 2.390.

When separated from Enclosure 3, this document is decontrolled to RC-24-0056 Page 9 RACTS ORIG.

NO.

DATE 020349 3/1 9/2015 020355 4/1 0/2015 020356 1/1 5/20] 5 020358 4/1 2/2016 Security-Related Information - Withhold Under 10 CFR 2.390 REFERENCE DESCRIPTION OF COMMITME T BASIS FOR DOCUMENT COMMITMENT CHANGE DTE Letter The commitment is to enhance the Water Chemistry The commitment is NRC-15-0030 Control - Closed Treated Water Systems Program prior to complete and the status 09/20/2024. The enhancements are to revise plant changed to ongoing-procedures.

closed due to implementing UFSAR Appendix B, Table B-1 Item 35.

DTE Letter The commitment is to enhance the Fire Water System The commitment is NRC-15-0031 Program prior to 09/20/2024 or the end of the last complete and the status refueling outage prior to 03/20/2025, whichever is later.

changed to ongoing -

The exception is that activities described in this closed due to implementing commitment for piping segments designed to be dry but UFSAR Appendix B, Table determined to be collecting water shall be conducted B-l Item 14 within five years prior to 03/20/2025.

DTE Letter The commitment is to enhance the Periodic Surveillance The commitment is NRC-15-0002 and Preventive Maintenance Program prior to 09/20/2024.

complete and the status changed to ongoing -

closed due to implementing UFSAR Appendix B, Table B-1 Item 28.

DTE Letter The commitment is to implement a new Buried and The commitment was NRC-16-0027 Underground Piping Program prior to 09/20/2024 or the revised for clarification to end of the last refueling outage prior to 03/20/2025, reflect the commitment whichever is later.

wording more closely in NRC-16-0027 Initial directed inspections and soil testing (if the and UFSAR Appendix B, reduction in inspections based on soil testing is taken) will Table B-1 Item 6 be performed within the ten years prior to March 20, 2025.

The commitment is complete and the status contains Security-Related Information - Withhold Under 10 CFR 2.390.

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DATE 020359 2/12/2015 020363 2/5/2015 090091 1/26/1 990 Security-Related Information - Withhold Under 10 CFR 2.390 REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DOCUMENT COMMITMENT CHANGE changed to ongoing -

closed due to implementing UFSAR Appendix B, Table B-1 Item 6 DTE Letter The commitment is to enhance the Fatigue Monitoring The commitment is NRC-15-0011 Program prior to 09/20/2024.

complete and the status changed to ongoing -

closed due to implementing UFSAR Appendix B, Table B-1 Item 12 DTE Letter The commitment is to implement the Coating Integrity The commitment is NRC-15-0021 Program prior to 09/20/2024.

complete and the status changed to ongoing -

closed due to implementing UFSAR Appendix B, Table B-1 Item 36 DTE Letter Commitments made on service water systems in response The commitment was RC-90-0012 to Generic Letter (GL) GL 89-13 by implementing revised for clarification to Inspection and Maintenance Programs for Service Water reflect the commitment Systems piping and components to ensure that corrosion, wording more closely.

protective coating failure, silting and biofouling problems do not degrade the performance of the safety related systems supplied by service water. contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 ATTACHMENT 3 TO NRC-24-0056 Summary of Revisions to Technical Requirements Manual, Volume I, and Revised Pages contains Security-Related Information - Withhold Under 10 CFR 2.390.

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7

Security-Related Information - Withhold Under 10 CFR 2.390 to NRC-24-0056 Page 1 Revision 133 01/11 /2023 Revision 134 08/25/2023 Revision 135 12/14/2023 Revision 136 02/08/2024 Summary of the Technical Requirements Manual (TRM)

Volume I Changes Revised TRSR 3.12.2.7 due to installation of a new diesel fire pump fuel oil pump and tank. In order for the diesel fire pump to operate continuously for 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , an increase in fuel supply from 150 gallons to 195 gallons is necessary.

Revised TRSR 3.3.3.3 to extend the performance of procedures 44.120.030 and 44.120.031, Functions 6 & 7, from every 92 days to every 184 days. This will result in I&C testing burden reduction, on-line schedule reduction, and test caused error reduction.

Revised TRSR 3.3.6.5.2 to extend the performance of procedure 44.220.011 from every 92 days to every 184 days. The survei I lance is a Channel Functional test of the narrow range level low alarm. This will result in I&C testing burden reduction, on-line schedule reduction, SSC wear & tear reduction, and test caused error reduction.

Revised TRSRs 3.3.12.2 and 3.3.12.3 to extend the performance of procedures 44.080.501, "Off Gas Hydrogen Monitoring System Channel Functional Test," and 44.080.502, "Off Gas Hydrogen Monitoring System Channel Calibration/Functional" from 92 days to 184 days. This will result in l&C testing burden reduction, on-line schedule reduction, SSC wear & tear reduction, and test caused error reduction.

Revised Section 4 of the Core Operating Limits Report (COLR) for changes to the Moisture Separator Reheater off rated MCPR limits. The Reference section is updated with the information on the revised limits.*

Revised TRSR 3.12.2.6 and 3.12.3.1 to change surveillance frequencies from 31 days to 6 months to optimize surveillance frequencies per guidance in the NEIL Loss Control Manual and EPRI Fire Protection Surveillance Optimization Guide. This will result in I&C testing burden reduction, on-line schedule reduction, and test-caused error reduction. contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 to NRC-24-0056 Page 2 Revision 137 04/25/2024 Revision 138 05/02/2024 Revised the Core Operation Limits Report (COLR) to include the new Cycle 23 operating limits.

Revised TRM Table TR3.6.3-l to change the maximum isolation time of the Inboard Reactor Core Isolation Cooling (RCIC) Steam Line Isolation Valve from 15 seconds to 23 seconds based on valve stroke field testing results.

The following pages are information only copies of the revised TRM pages for the above revisions.

Pages of the COLR from Revision 135 and 137 of the TRM are not attached. The COLR is included in Volume I of the TRM for convenience and ease of reference; however, it is not part of the information incorporated by reference into the UFSAR. contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 Accident Monitoring Instrumentation TR 3.3. 3 SURVEILLANCE REQUIREMENTS

NOTE--------------------------------------

These SRs apply to each Function in Table TR3.3.3-l.

TRSR 3. 3. 3. 1 TRSR 3. 3. 3.2 TRSR 3. 3. 3. 3 TRSR 3. 3. 3. 4 TRM Vol. I SURVEILLANCE Perform CHANNEL CHECK.

NOTE----------------------

Only applicable to Functions 1, 2, 3, 4,

5. a and 5.b.

Perform CHANNEL CALIBRATION.

NOTES---------------------

1.

Only applicable to Functions 6 and 7.

2.

Not required to be performed until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for one channel, and 7 days for the second channel after~ 15% RTP.

Perform CHANNEL CALIBRATION.

NOTE----------------------

Only applicable to Functions 5. c and 5. d.

Perform CHANNEL CALIBRATION.

TRM 3. 3-13a FREQUENCY 31 days 24 months 184 DAYS 18 months REV 134 08/23 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 TWMS Narrow Range Suppression Pool Water Level Instrumentation TR 3. 3. 6. 5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRSR 3. 3. 6. 5. 1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months TRSR 3. 3. 6. 5. 2 Perform CHANNEL FUNCTIONAL TEST.

184 days TRSR 3. 3.6.5. 3 Perform CHANNEL CALIBRATION.

The setpoints 24 months shall be :

TRM Vol. I a.

High water level < 14 ft. 8 inches ;

and b.

Low water level> 14 ft. 4 inches.

TRM 3. 3-29 REV 134 08/23 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 Explosive Gas Monitoring I nstrumentation TR 3. 3. 12 ACTIONS (continued)

CONDITION REQUIRED ACTION C.

Required Action and C. l Submit a Corrective associated Completion Action Document Time of Required explaining why the Action A. 3 not met.

inoperability was not corrected in a timely manner.

D.

Offgas hydrogen D. 1 Restore hydrogen concentration not concentration to within limit.

within the limit.

SURVEILLANCE REQUIREMENTS SURVEILLANCE TRSR 3. 3. 12. 1 Perform CHANNEL CHECK of the hydrogen monitor.

COMPLETION TIME Immedi ately 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months FREQUENCY 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months TRSR 3. 3. 12. 2 Perform CHANNEL FUNCTIONAL TEST of the 184 days TRSR 3. 3. 12. 3 TRM Vol. I hydrogen monitor.

Perform CHANNEL CALIBRATION of the hydrogen 184 days moni t or.

The alarm setpoint shall be< 4%

hydrogen by volume.

I nclude the use of standard gas samples containing a nominal :

a.

One volume percent hydrogen, balance nitrogen, and b.

Four volume percent hydrogen, balance nitrogen.

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Security-Related Information - Withhold Under 10 CFR 2.390 TABLE TR3. 6.3-1 (Page 3 of 23)

Primary Containment Isolation Valves FUNCTION

1.

Automatic Isolation Valves 1* 1 (continued) f.

Group 6 -

High Pressure Coolant Injection (HPCI) System HPCI Turbine Steam Supply Isolation Valves Inboard :

E4150-F002 Outboard :

E4150-F003 HPCI Turbine Steam Supply Outboard Isolation Bypass Valve E4150-F600 HPCI Booster Pump Suction from Suppression Chamber Isolation Valve 151 E4150-F042 g.

Group 7 -

High Pressure Coolant Injection (HPCI) Vacuum Breakers HPCI Turbine Exhaust Line Vacuum Breaker Isolation Valves E4150-F075 E4150-F079

h.

Group 8 - Reactor Core Isolation Cooling (RCIC) System RCIC Steam Line Isolation Valves Inboard :

E5150-F007 Outboard E5150-F008 i.

Group 9 - Reactor Core Isolation Cooling (RCIC) System Vacuum Breakers RCIC Turbine Exhaust Line Vacuum Breaker Isolation Valves E5150-F062 E5150-F084 PCIVs TR 3. 6. 3 MAXIMUM ISOLATION TIME (seconds) lul 15 45*

15 60 60 60 23 15 60 60 (continued)

E4150- F003 is required to open in less than 45 seconds to ensure HPCI delivers full rated flow within 60 seconds.

TRM Vol. I TRM 3. 6-5 REV 138 05/24 contains Security-Related lnformation - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 Fire Suppression Water System TR 3.12.2 SURVEILLANCE REQUIREMENTS TRSR 3. 12. 2.1 TRSR 3. 12. 2. 2 TRSR 3. 12. 2. 3 TRSR 3. 12. 2. 4 TRSR 3.12. 2. 5 TRSR 3. 12. 2. 6 TRM Vol. I SURVEILLANCE Verify the general service water intake structure water level is> 562 ft.

Verify the electrolyte level of each diesel-driven fire pump starting 24-volt battery bank battery is above the plates.

Verify the battery specific gravity of the diesel-driven fire pump starting 24-volt battery bank corrected to 77°F, is~ 1. 235.

NOTE--------------------

The voltage is to be checked with the battery charger connected.

FREQUENCY 7 days 7 days 7 days Verify the diesel-driven fire pump starting 7 days 24-volt battery bank battery voltage, is~

26. 2 volts.

Start the electric motor-driven fire suppression pump and operate it for 15 minutes on recirculation flow.

NOTE--------------------

For valves that are not accessible during unit operation, not required to be performed in MODES 1, 2, and 3, or MODE 4 of< 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Verify that each manual, powered-operated, or automatic valve in the flow path is in the correct position.

TRM 3. 12-9 31 days 6 months (continued)

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Security-Related lnfo1*mation - Withhold Under 10 CFR 2.390 Fire Suppression Water System TR 3.12.2 SURVEILLANCE REQUIREMENTS (continued)

TRSR 3. 12. 2. 7 TRSR 3. 12.2. 8 TRSR 3. 12. 2. 9 TRSR 3. 12. 2. 10 TRSR 3. 12.2.11 TRSR 3. 12. 2.12 TRM Vol. 1 SURVEILLANCE Verify the diesel-driven fire suppression pump fuel storage tank contains at least 195 gallons of fuel.

Start the diesel-driven fire suppression pump from ambient conditions and operate for> 30 minutes on recirculation flow.

NOTE-------------------

Obtain the sample of diesel fuel in accordance with ASTM-D270-65 (reapproved 1980).

FREQUENCY 31 days 31 days Verify that a sample of diesel fuel from 92 days the diesel-driven fire suppression pump fuel storage tank is within the acceptable limits specified in Tabl e 1 of ASTM-D975-77 when checked for viscosity, water and sediment.

Perform a fire suppression water system flush.

NOTE--------------------

For valves that are not accessible during unit operation, not required to be performed in MODES 1, 2, and 3, or MODE 4 of< 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

12 months Cycle each testable valve in the flow path 12 months through at least one complete cycle of full travel.

Perform a system functional test which includes simulated automatic actuation of the system throughout its operating sequence.

3. 12-10 18 months (continued)

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Security-Related Information - Withhold Under 10 CFR 2.390 Spray and Sprinkler Systems TR 3. 12. 3 SURVEILLANCE REQUIREMENTS

NOTE--------------------------------------

These SRs apply to each Area in Table TR3.12. 3-l.

TRSR 3.12. 3. 1 TRSR 3.12. 3. 2 TRSR 3.12. 3. 3 TRSR 3.12. 3. 4 TRM Vol. I SURVEILLANCE

NOTE--------- --- --------

For valves that are not accessible during unit operation, not required to be performed in MODES 1, 2, and 3, or MODE 4 of< 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Verify each manual, powered-operated, or automatic valve in the flow path is in its correct position.

----NOTE--------------------

For valves that are not accessible during unit operation, not required to be performed in MODES 1, 2, and 3, or MODE 4 of< 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Cycle each testable valve in the flow path through at least one complete cycle of full travel.

NOTE--------------------

The ventilation room manual flooding system is exempt from the automatic actuation.

Perform a system functional test, which includes the simulated automatic actuation of each system by opening the inspectors test valve and verifying the water flow alarm annunciator.

Perform a visual inspection of the sprinkler header to verify its integrity.

TRM 3. 12-14 FREQUENCY 6 months 12 months 24 months 24 months REV 136 02/24 contains Security-Related Information - Withhold Under IO CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 ATTACHMENT 4 TO NRC-24-0056 Summary of Revisions to Technical Specifications Bases and Revised Pages contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 to NRC-24-0056 Page 1 Revision 92 04/11/2023 Revision 93 08/18/2023 Revision 94 09/21/2023 Revision 95 03/07/2024 Revision 96 03/19/2024 Summary of Technical Specification Bases (TSB) Changes Revised Tech Spec Bases section B 3.3.5.3 to show that the Residual Heat Removal (RHR) hutdown Cooling (SDC) valves under function 3.a are Group 4 and not Group 3.

Revised Tech Spec Bases section B 3.6.3.1 to add MODE 2 to the Applicability regarding Primary Containment Oxygen Concentration and increase some related Completion Times.

These changes are associated with the license amendment request documented in NRC-23-0055 and approved in Amendment 224.

Revised Tech Spec Bases sections B 3.3.5.3, B 3.3.6.1, B 3.3.8. l, B 3.5.2, B 3.6. l.3, and B 3.8.2. These changes are associated with the license amendment request docwnented in NRC-23-0023 and approved in License Amendment 223.

Administrative changes were made to the Bases for TS 3.5.2 by adding the word "each" along with splitting the Actions A.1 and B.1 from a single paragraph to two paragraphs. Also, the Bases for section for SR 3.5.2.9 was revised to use the singular "subsystem" for both Core Spray and Low Pressure Coolant Injection.

Revise the Technical Specification Bases section B 3.8. l to implement the changes associated with the license amendment request documented in NRC-22-0026 and approved in License Amendment 227.

Revise the Technical Specification Bases to correct a typo in section B 3.4.5 to implement the change associated with the license amendment request documented in NRC-23-0010 and approved in License Amendment 228.

The following pages are information only copies of the revised TSB pages for the above rev1s1ons. contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control Instrumentation B 3.3.5.3 B 3.3 INSTRUMENTATION B 3.3.5.3 Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation BASES BACKGROUND FERMI - UNIT 2 The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF. If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

Technical Specifications are required by 10 CFR 50.36 to include limiting safety system settings (LSSS) for variables that have significant safety functions.

LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded."

The Analytical Limit is the limit of the process variable at which a safety action is initiated to ensure that a SL is not exceeded.

Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded.

However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.

The actual settings for the automatic isolation channels are the same as those established for the same functions in MODES 1, 2, and 3 in LCO 3.3.6.1, "Primary Containment Isolation Instrumentation."

With the unit in MODE 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses.

RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur.

Under the definition of DRAIN TIME, some penetration flow paths may be excluded from t he DRAIN TIME calculation if they will be isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to B 3.3.5.3-1 Revision 94 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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BASES Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control Instrumentation B 3.3.

5.3 BACKGROUND

(continued)

APPLICABLE SAFETY ANALYSES,

LCD, and APPLICABILITY FERMI - UNIT 2 the TAF when actuated by RPV water level isolation instrumentation.

The purpose of the RPV Water Inventory Control Instrumentation is to support the requirements of LCD 3.5.2, "Reactor Pressure Vessel (RPV) Water Inventory Control," and the definition of DRAIN TIME.

There are functions that support automatic isolation of Residual Heat Removal subsystem and Reactor Water Cleanup system penetration flow path(s) on low RPV water level.

With the unit in MODE 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses. RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure.

It is assumed, based on engineering judgment, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can be manually initiated to maintain adequate reactor vessel water level.

As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety. Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

Permissive and interlock setpoints are generally considered as nominal values without regard to measurement accuracy.

B 3.3.5.3-2 Revision 94 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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BASES Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control Instrumentation B 3.3.5.3 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

FERMI - UNIT 2 The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

RHR System Isolation l.a - Reactor Vessel Water Level - Low, Level 3 The definition of Drain Time allows crediting the closing of penetration flow paths that are capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation. The Reactor Vessel Water Level - Low, Level 3 Function associated with RHR System isolation may be credited for automatic isolation of penetration flow paths associated with the RHR System.

Reactor Vessel Water Level - Low. Level 3 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low. Level 3 Function are available, only two channels (both in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low. Level 3 Allowable Value was chosen to be the same as the Primary Containment Isolation Instrumentation Reactor Vessel Water Level - Low.

Level 3 Allowable Value (LCO 3.3.6.1). since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME (i.e.. this Function must be OPERABLE if the DRAIN TIME calculation assumes the RHR System would be automatically isolated).

This Function isolates the Group 4 valves.

B 3.3.5.3-3 Revision 94 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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BASES Security-Related Information - Withhold nder 10 CFR 2.390 RPV Water Inventory Control Instrumentation B 3.3.5.3 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

FERMI - UNIT 2 in MODES 4 and 5 when the associated ECCS subsystems are required to be OPERABLE per LCO 3.5.2.

RHR System Isolation 3.a - Reactor Vessel Water Level - Low, Level 3 The definition of Drain Time allows crediting the closing of penetration flow paths that are capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation.

The Reactor Vessel Water Level - Low, Level 3 Function associated with RHR System isolation may be credited for automatic isolation of penetration flow paths associated with the RHR System.

Reactor Vessel Water Level - Low, Level 3 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Level 3 Function are available, only two channels (both in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the Primary Containment Isolation Instrumentation Reactor Vessel Water Level - Low, Level 3 Allowable Value (LCO 3.3.6.1). since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME (i.e., this Function must be OPERABLE if the DRAIN TIME calculation assumes the RHR System would be automatically isolated).

This Function isolates the Group 4 valves.

B 3.3.5.3 - 4 Revision 92 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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BASES Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control Instrumentation B 3.3.5.3 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Reactor Water Cleanup (RWCU) System Isolation FERMI - UNIT 2 2.a - Reactor Vessel Water level - Low Low, Level 2 The definition of Drain Time allows crediting the closing of penetration flow paths that are capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation. The Reactor Vessel Water Level - Low Low, Level 2 Function associated with RWCU System isolation may be credited for automatic isolation of penetration flow paths associated with the RWCU System.

Reactor Vessel Water Level - Low Low. Level 2 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low Low, Level 2 Function are available. only two channels (both in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low Low. Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low Low, Level 2 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME (i.e., this Function must be OPERABLE if the DRAIN TIME calculation assumes the RWCU System would be automatically isolated).

This Function isolates the Group 10 and 11 valves.

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BASES ACTIONS FERMI - UNIT 2 Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control Instrumentation B 3.3.5.3 A Note has been provided to modify the ACTIONS related to RPV Water Inventory Control instrumentation channels.

Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition.

Section 1.3 also specifies that Required Actions continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.

However, the Required Actions for inoperable RPV Water Inventory Control instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable RPV Water Inventory Control instrumentation channel.

A.1, A.2.1 and A.2.2 RHR System Isolation, Reactor Vessel Water Level - Low Level 3, and Reactor Water Cleanup System, Reactor Vessel Water Level - Low Low, Level 2 functions are applicable when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.

If the instrumentation is inoperable, Required Action A.1 directs immediate action to place the channel in trip. With the inoperable channel in the tripped condition, the remaining channel will isolate the penetration flow path on low water level. If both channels are inoperable and placed in trip, the penetration flow path will be isolated. Alternatively, Required Action A.2.1 requires the associated penetration flow path(s) to be immediately declared incapable of automatic isolation. Required Action A.2.2 directs initiating action to calculate DRAIN TIME.

The calculation cannot credit automatic isolation of the affected penetration flow paths.

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BASES SURVEILLANCE REQUIREMENTS FERMI - UNIT 2 Security-Related Information - Withhold nder 10 CFR 2.390 RPV Water Inventory Control Instrumentation B 3.3.5.3 The following SRs apply to each RPV Water Inventory Control instrument Function in Table 3.3.5.3-1.

SR 3.3.5.3.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels.

It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK guarantees that undetected outright channel failure is limited; thus. it is key to verifying the instrumentation continues to operate properly between each CHANNEL FUNCTIONAL TEST.

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

including indication and readability.

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

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The CHANNEL CHECK supplements less formal. but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

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BASES Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control Instrumentation B 3.3.5.3 SURVEILLANCE REQUIREMENTS (continued)

FERMI - UNIT 2 SR 3.3.5.3.2 and SR 3.3.5.3.3 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non -Technical Specifications tests.

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

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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BASES REFERENCES FERMI - UNIT 2 Security-Related Information - Withhold nder 10 CFR 2.390

1.

RPV Water Inventory Control Instrumentation B 3.3.5.3 Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup," November 1984.

2.

Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves,"

August 1986.

3.

Generic Letter 92 -04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(F)," August 1992.

4.

NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs,"

May 1993.

5.

Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone l, "

July 1994.

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BASES LCD APPLICABILITY ACTIONS FERMI - UNIT 2 Security-Related Information - Withhold Under 10 CFR 2.390 Primary Containment Oxygen Concentration B 3.6.3.1 The primary containment (both drywell and suppression chamber) oxygen concentration is maintained< 4.0 v/o to ensure that an event that produces any amount of hydrogen does not result in a combustible mixture inside primary containment.

The primary containment oxygen concentration must be within the specified limit when primary containment is inerted.

The primary containment must be inert in MODE 1 and 2. since this is the condition with the highest probability of an event that could produce hydrogen.

A.1 If oxygen concentration is~ 4.0 v/o while operating in MODE 1 and 2, oxygen concentration must be restored to

< 4.0 v/o within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is allowed when oxygen concentration is~ 4.0 v/o because of the low probability and long duration of an event that would generate significant amounts of hydrogen occurring during this period.

A Note permits the use of the provisions of LCD 3.0.4.c.

This allowance permits entry into the applicable MODE(S) while relying on the ACTIONS. This allowance is acceptable because inerting the primary containment prevents containment access without an appropriate breathing apparatus. Therefore. the primary containment is inerted as late as possible in t he plant startup, after entering MODES 1 and 2, and de-inerted as soon as possible in the plant shutdown. It is acceptable to intentionally enter Required Action A.1 prior to a shutdown in order to begin de-inerting the primary containment prior to exiting the Applicability.

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BASES Security-Related Information - Withhold Under JO CFR 2.390 Primary Containment Oxygen Concentration B 3.6.3.1 ACTIONS (continued)

B.1 SURVEILLANCE REQUIREMENTS REFERENCES FERMI - UNIT 2 If oxygen concentration cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, power must be reduced to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

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 reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.

SR 3. 6. 3. 1. 1 The primary containment must be determined to be inert by verifying that oxygen concentration is< 4.0 v/o.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

1.

UFSAR, Section 6.2.5.

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BASES Security-Related Information - Withhold Under 10 CFR 2.390 Primary Containment Isolation Instrumentation B 3.3.6.1 ACTIONS (continued)

SURVEILLANCE REQUIREMENTS FERMI - UNIT 2 The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes risk while allowing sufficient time for personnel to isolate the RWCU System.

J.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated penetration flow path should be closed.

However. if the shutdown colling function is needed to provide core cooling, the Required Action allows the penetration flow path to remain unisolated provided action is immediately initiated to restore the channel to OPERABLE status. Actions must continue until the channel is restored to OPERABLE status.

As noted at the beginning of the SRs. the SRs for each Primary Containment Isolation instrumentation Function are found in the SRs column of Table 3.3.6.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances. entry into associated Conditions and Required Actions may be delayed.

Upon completion of the Surveillance, or expiration of the allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 5 and 6) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the testing allowance does not significantly reduce the probability that the PCIVs will isolate the penetration flow path(s) when necessary.

Note 2.b clarifies that the isolation function is maintained for Function 5.c, RWCU Area Differential Temperature-High, provided Function 5.b. RWCU Area Temperature-High is OPERABLE in the affected area.

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BASES ecurity-Related Information - Withhold nder 10 CFR 2.390 LOP Instrumentation B 3.3.8.1 APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY (continued)

FERMI - UNIT 2

1.

4.16 kV Emergency Bus Undervoltage (Loss of Voltage)

Loss of voltage on a 4.16 kV emergency bus indicates that offsite power may be completely lost to the respective emergency bus and is unable to supply sufficient power for proper operation of t he applicable equipment. Therefore.

the power supply to the bus is transferred from offsite power to EOG power when the voltage on the bus drops below the Loss of Voltage Function Allowable Values (loss of voltage with a short time delay). This ensures that adequate power will be available to the required equipment.

The Bus Undervoltage Allowable Values are low enough to prevent inadvertent power supply transfer. but high enough to ensure that power is available to the required equipment.

The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that power is available to the required equipment.

Four channels of 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) Function per associated emergency bus are only required to be OPERABLE when the associated EOG is required to be OPERABLE to ensure that no single instrument failure can preclude the EOG function.

Refer to LCD 3.8.1, "AC Sources-Operating" for Applicability Bases for the EDGs.

2.

4.16 kV Emergency Bus Undervoltage (Degraded Voltage)

A reduced voltage condition on a 4.16 kV emergency bus indicates that, while offsite power may not be completely lost to the respective emergency bus, available power may be insufficient for starting large ECCS motors without risking damage to the motors that could disable the ECCS function.

Therefore, power supply to the bus is transferred from offsite power to onsite EOG power when the voltage on the bus drops below the Degraded Voltage Function Allowable Values (degraded voltage with a time delay). This ensures that adequate power will be available to the required equipment.

The Bus Undervoltage Allowable Values are low enough to prevent inadvertent power supply transfer. but high enough to ensure that sufficient power is available to the required equipment.

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BASES Security-Related Information - Withhold Under 10 CFR 2.390 LOP Instrumentation B 3.3.8.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

ACTIONS FERMI - UNIT 2 to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that sufficient power is available to the required equipment.

An additional time delay logic for degraded voltage (with LOCA) ensures a more rapid transfer of power from the offsite power system to the onsite power system if a LOCA condition is sensed during sustained degraded voltage. This additional logic ensures that the timing requirements in the accident analysis will be met under degraded voltage conditions.

Four channels of 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) Function per associated bus are only required to be OPERABLE when the associated EOG is required to be OPERABLE to ensure that no single instrument failure can preclude the EOG function.

Refer to LCO 3.8.1 for Applicability Bases for the EDGs.

A Note has been provided to modify the ACTIONS related to LOP instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.

However, the Required Actions for inoperable LOP instrumentation channels provide appropriate compensatory measures for separate inoperable channels.

As such, a Note has been provided that allows separate Condition entry for each inoperable LOP instrumentation channel.

A.1 With one or more channels of a Function inoperable, the Function may not be capable of performing the intended function (if LOP trip capability is lost, Condition Bis also required to be entered). Therefore, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months are allowed to restore the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition B must be entered and its Required Action taken.

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BASES Security-Related Information - Withhold nder 10 CFR 2.390 LOP Instrumentation B 3.3.8.1 ACTIONS (continued)

SURVEILLANCE REQUIREMENTS FERMI - UNIT 2 The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is acceptable because it minimizes risk while allowing time for restoration of channels.

B.l If Required Action A.land associated Completion Time is not met. or the associated Function is not capable of performing the intended function, the associated EDG(s) is declared inoperable immediately. This requires entry into applicable Conditions and Required Actions of LCO 3.8.1 which provides appropriate actions for the inoperable EDG(s).

As noted at the beginning of the SRs, the SRs for each LOP instrumentation Function are located in the SRs column of Table 3.3.8.1-1.

SR 3. 3. 8. 1. 1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

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

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3. 3. 8. 1. 2 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint B 3.3.8.1-6 Revision 94 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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REFERENCES FERMI - UNIT 2 methodology.

This SR also ensures the sum of the degraded voltage time delay and the longest time delay of the four associated bus undervoltage relays remains consistent with the plant specific setpoint methodology.

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

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3. 3. 8. 1. 3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a ~pecific channel.

The system functional testing performed 1n LCO 3.8.1 overlaps this Surveillance to provide complete testing of the assumed safety functions.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

1.

UFSAR. Figure 8.3-8.

2.

UFSAR, Section 3.6.

3.

UFSAR, Section 6.3.

4.

UFSAR, Chapter 15.

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Security-Related Information - Withhold nder 10 CFR 2.390 BASES RCS PIV Leakage B 3.4.5 ACTIONS (continued)

FERMI - UNIT 2 leakage limits exceeded provide appropriate compensatory measures for separate affected RCS PIV flow paths.

As such, a Note has been provided that allows separate Condition entry for each affected RCS PIV flow path.

Note 2 requires an evaluation of affected systems if a PIV is inoperable.

The leakage may have affected system OPERABILITY, or isolation of a leaking flow path with an alternate valve may have degraded the ability of the interconnected system to perform its safety function.

As a result, the applicable Conditions and Required Actions for systems made inoperable by PIVs must be entered. This ensures appropriate remedial actions are taken, if necessary, for the affected systems.

A.1 If leakage from one or more RCS PIVs is not within limit,

the flow path must be isolated by at least one closed manual, deactivated automatic, or check valve within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Required Action A.l is modified by a Note stating that valves used for isolation must meet the same leakage requirements as the PIVs (i.e., meet SR 3.4.5.1).

Furthermore, the leakage must have been verified at the last refueling outage or after the last time the valve was disturbed (i.e., maintenance activities that could affect the leak tightness of the valve), whichever is more recent.

Four hours provides time to reduce leakage in excess of the allowable limit and to isolate the flow path if leakage cannot be reduced while corrective actions to reseat the leaking PIVs are taken.

The 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months allows time for these actions and restricts the time of operation with leaking valves.

B.1 and B.2 If leakage cannot be reduced or the system isolated, 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 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 . This action may reduce the leakage and also reduces the potential for a LOCA outside the containment.

The Completion Times are reasonable, based on operating experience, to achieve the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

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Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control BASES BACKGROUND The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF.

If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

APPLICABLE With the unit in MODE 4 or 5, RPV water inventory control is SAFETY ANALYSES not required to mitigate any events or accidents evaluated FERMI - UNIT 2 in the safety analyses.

RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material to the environment should an unexpected draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems.

Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate. or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure (an event that creates a drain path through multiple vessel penetrations located below top of active fuel, such as loss of normal power. or a single human error). It is assumed, based on engineering judgment, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level.

As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety. Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

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LCO FERMI - UNIT 2 Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control B 3.5.2 The RPV water level must be controlled in MODES 4 and 5 to ensure that if an unexpected draining event should occur, the reactor coolant water level remains above the top of the active irradiated fuel as required by Safety Limit 2.1.1.3.

The Limiting Condition for Operation (LCO) requires the DRAIN TIME of RPV water inventory to the TAF to be~ 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . A DRAIN TIME of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months is considered reasonable to identify and initiate action to mitigate unexpected draining of reactor coolant.

An event that could cause loss of RPV water inventory and result in the RPV water level reaching the TAF in greater than 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.

One low pressure ECCS injection/spray subsystem is required to be OPERABLE and capable of being manually aligned and started from the control room to provide defense-in-depth should an unexpected draining event occur.

OPERABILITY of the ECCS injection/spray subsystem includes any necessary valves, instrumentation, or controls needed to manually align and start the subsystem from the control room.

A low pressure ECCS injection/spray subsystem consists of either one Core Spray (CS) subsystem or one Low Pressure Coolant Injection (LPCI) subsystem.

Each CS subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool or condensate storage tank (CST) to the RPV.

Each LPCI subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV.

In MODES 4 and 5, the RHR System cross tie valve is not required to be closed.

Management of gas voids is important to ECCS injection/spray subsystem OPERABILITY.

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BASES APPLICABILITY ACTIONS FERMI - UNIT 2 Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control B 3.5.2 RPV water inventory control is required in MODES 4 and 5.

Requirements on water inventory control in other MODES are contained in LCOs in Section 3.3, "Instrumentation," and other LCOs in Section 3.5, "ECCS, RPV Water Inventory Control, and RCIC System."

RPV water inventory control is required to protect Safety Limit 2.1.1.3 which is applicable whenever irradiated fuel is in the reactor vessel.

A.1 and B.1 If the required low pressure ECCS injection/spray subsystem 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 .

In this Condition, the LCO controls on DRAIN TIME minimize the possibility that an unexpected draining event could necessitate the use of the ECCS injection/spray subsystem, however the defense-in-depth provided by the ECCS injection/spray subsystem is lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time for restoring the required low pressure ECCS injection/spray subsystem to OPERABLE status is based on engineering judgment that considers the LCO controls on DRAIN TIME and the low probability of an unexpected draining event that would result in loss of RPV water inventory.

If the inoperable ECCS injection/spray subsystem is not restored to OPERABLE status within the required Completion Time, action must be initiated immediately to establish a method of water injection capable of operating without offsite electrical power.

The method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur.

The method of water injection may be manually initiated and may consist of one or more systems or subsystems, and must be able to access water inventory capable of maintaining the RPV water level above the TAF for

~ 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

If recirculation of injected water would occur, it may be credited in determining the necessary water volume.

C.1, C.2, and C3 With the DRAIN TIME less than 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months but greater than or equal to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , compensatory measures should be taken to ensure the ability to implement mitigating actions should an unexpected draining event occur.

Should a draining event lower the reactor coolant level to below the TAF, there is B 3.5.2-3 Revision 94 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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FERMI - UNIT 2 flange, the realistic cross-sectional area is based on the control rod blade seated in the control rod guide tube.

If the control rod blade will be raised from the penetration to adjust or verify seating of the blade, the exposed cross-sectional area of the RPV penetration flow path is used.

The definition of DRAIN TIME excludes from the calculation those penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are closed and administratively controlled, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths. A blank flange or other bolted device must be connected with a sufficient number of bolts to prevent draining.

Normal or expected leakage from closed systems or past isolation devices is permitted.

Determination that a system is intact and closed or isolated must consider the status of branch lines.

The Residual Heat Removal (RHR) Shutdown Cooling System is only considered an intact closed system when misalignment issues (Reference 6) have been precluded by functional valve interlocks or by isolation devices, such that redirection of RPV water out of an RHR subsystem is precluded.

Further, RHR Shutdown Cooling System is only considered an intact closed system if its controls have not been transferred to Remote Shutdown, which disables the interlocks and isolation signals.

The exclusion of a single penetration flow path, or multiple penetration flow paths susceptible to a common mode failure, from the determination of DRAIN TIME should consider the effects of temporary alterations in support of maintenance (rigging, scaffolding, temporary shielding, piping plugs, freeze seals, etc.). If reasonable controls are implemented to prevent such temporary alterations from causing a draining event from a closed system, or between the RPV and the isolation device, the effect of the temporary alterations on DRAIN TIME need not be considered.

Reasonable controls include, but are not limited to, controls consistent with the guidance in MUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Revision 4, NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management," or commitments to NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants."

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BASES Security-Related Information - Withhold Under 10 CFR 2.390 RPV Water Inventory Control B 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

FERMI - UNIT 2 Surveillance Requirement 3.0.1 requires SRs to be met between performances. Therefore, any changes in plant conditions that would change the DRAIN TIME requires that a new DRAIN TIME be determined.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.2 and SR 3.5.2.3 The minimum water level of -66 inches (9 ft O inches actual level) required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the CS subsystem or LPCI subsystem pump, recirculation volume, and vortex prevention.

With the suppression pool water level less than the required limit, the required ECCS injection/spray subsystem is inoperable unless aligned to an OPERABLE CST.

When the suppression pool level is< -66 inches, the required CS System is OPERABLE only if it can take suction from the CST, and the CST water level is sufficient to provide the required NPSH for the CS pump.

Therefore, a verification that either the suppression pool water level is

~ -66 inches or that a required CS subsystem is aligned to take suction from the CST and the CST contains~ 300,000 gallons of water, equivalent to 19 ft, ensures that the CS subsystem can supply at least 150,000 gallons of makeup water to the RPV.

The CS suction is uncovered at the 150,000 gallon level.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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FERMI - UNIT 2 SR 3.5.2.4 The LPCI System injection valves and recirculation pump discharge valves are powered from the LPCI swing bus, which must remain energized to support OPERABILITY of any required LPCI subsystem. Therefore, verification of proper voltage and correct breaker alignment to the swing bus is required.

The correct breaker alignment ensures the appropriate electrical power sources are available, and the appropriate voltage is available to the swing bus, including verification that the swing bus is energized. The verification of proper voltage availability ensures that the required voltage is readily available for critical system loads connected to this bus.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.5 The Bases provided for SR 3.5.1.3 is applicable to SR 3.5.2.5.

SR 3.5.2.6 Verifying that the required ECCS injection/spray subsystem can be manually aligned, and the pump started and operated for at least 10 minutes demonstrates that the subsystem is available to mitigate a draining event. This SR is modified by two Notes. Note 1 states that testing the ECCS injection/spray subsystem may be done through the test return line to avoid overfilling the refueling cavity.

Note 2 states that credit for meeting the SR may be taken for normal system operation that satisfies the SR, such as using the shutdown cooling mode of RHR for~ 10 minutes.

The minimum operating time of 10 minutes was based on engineering judgement.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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BASES Security-Related ]nformation - Withhold Under 10 CFR 2.390 RPV Water Inventory Control B 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.

2.7 REFERENCES

FERMI - UNIT 2 Verifying that each valve credited for automatically isolating a penetration flow path actuates to the isolation position on an actual or simulated RPV water level isolation signal is required to prevent RPV water inventory from dropping below the TAF should an unexpected draining event occur.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.8 This Surveillance verifies that a required CS subsystem or LPCI subsystem can be manually aligned and started from the control room, including any necessary valve alignment, instrumentation, or controls, to transfer water from the suppression pool or CST to the RPV.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.

1.

Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup," November 1984.

2.

Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves,"

August 1986.

3.

Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(f)," August 1992.

4.

NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs,"

May 1993.

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BASES LCD (continued)

APPLICABILITY ACTIONS FERMI - UNIT 2 Security-Related Information - Withhold Under 10 CFR 2.390 PCIVs B 3.6.1.3 or open under administrative controls.

Normally closed automatic PCIVs, are required to have isolation times within limits and actuate on an automatic isolation signal. These passive isolation valves and devices are those listed in Reference 2.

Purge valves with resilient seals. secondary containment bypass valves, MSIVs, and hydrostatically tested valves must meet leakage rate requirements in addition to the other PCIV leakage rates which are addressed by LCD 3.6.1.1. "Primary Containment," as Type B or C testing.

This LCD provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the primary containment boundary during accidents.

In MODES 1, 2, and 3, a OBA 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, PCIVs are not required to be OPERABLE in MODES 4 and 5.

The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room.

In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

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Security-Related Information - Withhold Under 10 CFR 2.390 BASES PCIVs B 3.6.1.3 ACTIONS (continued)

FERMI - UNIT 2 leaking PCIV(s) remain inoperable due to leakage and Condition D remains applicable. Required Action D.2 must also be performed to verify the penetration is isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident are isolated. The Completion Time of "once per 31 days for isolation devices outside primary containment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low.

For the devices inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the devices and other administrative controls ensuring that device misalignment is an unlikely possibility.

Required Action D.2 is modified by three Notes.

Note 1 applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative means.

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

Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by use of administrative means.

Allowing verification by administrative means is considered acceptable since the function of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned.

Note 3 states that verification that the penetration is isolated applies only to penetration flow paths isolated to restore leakage within limits.

E.l and E.2 If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 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 B 3.6.1.3-10 Revision 94 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 BASES PCIVs B 3.6.1.3 ACTIONS (continued)

SURVEILLANCE REQUIREMENTS FERMI - UNIT 2 power conditions in an orderly manner and without challenging plant systems.

SR 3. 6. 1. 3. 1 This SR ensures that the drywell and suppression chamber purge system isolation valves (6 inch, 10 inch, 20 inch, and 24 inch) and the containment pressure control valves (1 inch) are closed as required or, if open, open for an allowable reason.

If a purge or containment pressure control valve is open in violation of this SR, the valve is considered inoperable. If the inoperable valve is not otherwise known to have excessive leakage when closed, it is not considered to have leakage outside of limits. Primary containment purge and containment pressure control valves are only required to be closed in MODES 1, 2, and 3 (i.e.,

no isolation instrumentation functions of LCO 3.3.6.1 are required to be OPERABLE for isolation of these valves outside of MODES 1, 2, and 3). If a LOCA inside primary containment occurs in these MODES, the purge valves may not be capable of closing before the pressure pulse affects systems downstream of the purge valves.

At other times (e.g., during handling of irradiated fuel), pressurization concerns are not present and the purge and containment pressure control valves are allowed to be open.

The SR is modified by a Note stating that the SR is not required to be met when the purge or containment pressure control valves are open for the stated reasons.

The Note states that these B 3.6.1.3-11 Revision 94 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under JO CFR 2.390 BASES PCIVs B 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)

FERMI - UNIT 2 Containment Leakage Rate Testing Program.

This SR simply imposes additional acceptance criteria. Additionally, some secondary containment bypass paths (refer to UFSAR 6.2.1.2.2.3) use non-PCIVs and therefore are not addressed by the testing Frequency of 10 CFR 50, Appendix J, testing.

To address the testing for these valves, the Frequency also includes a requirement to be in accordance with the INSERVICE TESTING PROGRAM.

Secondary containment bypass leakage is also considered part of La.

SR 3. 6. 1. 3. 12 The analyses in References 1 and 4 are based on leakage that is less than the specified leakage rate.

Leakage through all four main steam lines must be~ 250 scfh, and

~ 100 scfh for any one steam line, when tested at~ Pt (25 psig). This leakage test is performed in lieu of 10 CFR 50, Appendix J, Type C test requirements, based on an exemption to 10 CFR 50, Appendix J.

MSIVs have separate leakage limits, and the dose consequence of this leakage path is evaluated separately and added to those calculated from primary containment La leakage, including secondary containment bypass leakage.

As such, this leakage is not combined with the Type Band C leakage rate totals. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

SR 3. 6. 1. 3. 13 Surveillance of hydrostatically tested lines provides assurance that the calculation assumptions of Reference 4 are met.

The acceptance criteria for the combined leakage of all hydrostatically tested lines is 1 gpm times the number of valves per penetration, not to exceed 3 gpm, when tested at 1.1 Pa (~ 62.2 psig). Additionally, a combined leakage rate limit of~ 5 gpm when tested at 1.1 Pa

(~ 62.2 psig) is applied for all hydrostatically tested PCIVs that penetrate containment.

The combined leakage rates must be demonstrated in accordance with the leakage rate test Frequency required by Primary Containment Leakage Rate Testing Program.

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BASES REFERENCES FERMI - UNIT 2 Security-Related Information - Withhold Under 10 CFR 2.390

1.

UFSAR, Chapter 15.

2.

UFSAR, Table 6.2-2.

3.

10 CFR 50. Appendix J, Option B.

4.

UFSAR, Section 6.2.

5.

UFSAR, Section 15.6.2.

PCIVs B 3.6.1.3

6.

GE BWROG B21-00658-01, "Excess Flow Check Valve Testing Relaxation." dated November 1998.

7.

Technical Requirements Manual. Section TR 3.6.3 B 3.6.1.3-18 Revision 94 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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BASES Security-Related Jnformation - Withhold Under 10 CFR 2.390 AC Sources-Operating B 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

FERMI - UNIT 2 This value is also bounding for Division II and ensures that adequate voltage is available to the equipment supported by Division I and II of the EDGs.

The specified maximum steady state output voltages of 4314 V for Division I EDGs and 4400 V for Division II EDGs are equal to the maximum operating voltage in plant-specific analyses. This ensures that for a lightly loaded distribution system, the voltage at the terminal of the 460 V motors is no more than 110% of rated voltage.

The specified minimum and maximum frequencies of the EOG are 59.5 Hz and 60.5 Hz, respectively. These values are equal to the frequency limits in the plant-specific analyses to meet recommendations found in Regulatory Guide 1.9 (Ref. 3).

SR 3.8.1.1 The SR ensures correct breaker alignment for each required offsite circuit to ensure that distribution buses and loads are connected to their preferred power source, and that appropriate independence of offsite circuits is maintained.

The SR also verifies the indicated availability of three-phase AC electrical power from each required offsite circuit to the onsite distribution network.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition.

To minimize the mechanical stress and wear on moving parts that do not get lubricated when the engine is not running, these SRs have been modified by a Note (Note 1 for SR 3.8.1.2 and the Note for SR 3.8.1.7) to indicate that all EOG starts for these Surveillances may be preceded by an engine prelube period and followed by a warmup prior to loading.

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BASES LCO FERMI - UNIT 2 Security-Related Information - Withhold Unde,* 10 CFR 2.390 AC Sources-Shutdown B 3.8.2 One offsite circuit capable of supplying the onsite Class lE power distribution subsystem(s) of LCO 3.8.8, "Distribution Systems-Shutdown." ensures that all required loads are capable of being powered from offsite power.

An OPERABLE Division of onsite power. consisting of two EDGs associated with Distribution System Engineered Safety Feature (ESF) buses required OPERABLE by LCO 3.8.8, ensures that a diverse power source is available for providing electrical power support assuming a loss of the offsite circuit. Together, OPERABILITY of the required offsite circuit and the ability to manually start EDGs ensures the availability of sufficient AC sources to operate the plant in a safe manner and to mitigate the consequences of postulated events during shutdown (e.g., fuel handling accidents involving recently irradiated fuel).

The qualified offsite circuit(s) must be capable of providing three phases of AC power, maintaining rated frequency and voltage while connected to their respective ESF bus(es). and of accepting required loads during an accident. Qualified offsite circuits are those that are described in the UFSAR and are part of the licensing basis for the unit.

The offsite circuit consists of incoming breakers and disconnect to the station service 64 or 65 transformer. and the respective circuit path including feeder breakers to all 4.16 kV ESF buses required by LCO 3.8.8.

The required EDGs must be capable of being manually started, accelerating to rated speed and voltage, connecting to their respective ESF buses. and accepting required loads.

It is acceptable for divisions to be cross tied during shutdown conditions. permitting a single offsite power circuit to supply all required divisions.

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BASES Security-Related lnformation - Withhold Under 10 CFR 2.390 AC Sources - Shutdown B 3.8.2 ACTIONS (Continued)

SURVEILLANCE REQUIREMENTS immediately entered. This Note allows Condition A to provide requirements for the loss of the offsite circuit whether or not a division is de-energized.

LCO 3.8.8 provides the appropriate restrictions for the situation involving a de-energized division.

SR 3.8.2.1 SR 3.8.2.1 requires the SRs from LCO 3.8.1 that are necessary for ensuring the OPERABILITY of the AC sources in other than MODES 1, 2, and 3.

SR 3.8.1.7. SR 3.8.1.10, SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.14. SR 3.8.1.16, and SR 3.8.1.17 are not required to be met because EOG start and load within a specified time and response on an offsite power or ECCS initiation signal is not required. SR 3.8.1.18 is excepted because starting independence is not required with the EDGs that are not required to be OPERABLE.

Refer to the corresponding Bases for LCD 3.8.1 for a discussion of each SR.

This SR is modified by a Note which precludes requiring the OPERABLE EDGs from being paralleled with the offsite power network or otherwise rendered inoperable during the performance of SRs, and to preclude deenergizing a required 4160 V ESF bus or disconnecting a required offsite circuit during performance of SRs.

With limited AC sources available, a single event could compromise both the required circuit and a required EOG.

It is the intent that these SRs must still be capable of being met. but actual performance is not required during periods when the EDGs and offsite circuit are required to be OPERABLE.

REFERENCES None.

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Security-Related Information - Withhold Under 10 CFR 2.390 ATTACHMENT 5 TO NRC-24-0056 Summary of Excessive Detail Removed from the Fermi 2 UFSAR contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 to NRC-24-0056 Page 1 Summary Report of Excessive Detail Removal The following is a summary report of exce ive detail that has been removed in Revision 25 to the Fermi 2 UFSAR. These changes are consistent with uclear nergy Institute (NEI) 98-03, "Guidelines for Updating Final Safety Analysis Reports" Revision I, June 1999, as endorsed by the RC. The Fermi 2 UFSAR continues to adequately describe the de ign bases, plant safety analyses, and design and operation of structures, system, and components (S Cs).

There was no removal of excessive detail in Revision 25 of the Fermi 2 UFSAR. contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 ATTACHMENT 6 TO NRC-24-0056 10 CFR 72.48 Evaluation Summary Report contains Security-Related Information - Withhold Under 10 CFR 2.390.

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to NRC-24-0056 Page 1 Security-Related Information - Withhold Under 10 CFR 2.390 10 CFR 72.48 Evaluation Summary Report The following is an Evaluation Summary Report of l 0 CPR 72.48 Evaluations performed in accordance with the general licen e under docket number 72-71 since the previous report submitted with UPSAR Revision 24. This report is being submitted in accordance with the requirements of 10 CPR 72.48(d)(2).

There were no 10 CFR 72.48 Evaluations performed since the previous report submitted with UFSAR Revision 24. contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 ATTACHMENT 7 TO RC-24-0056 LICE SE RE EW AL REQUIREME TS FOR 10 CFR 54.37 contains Security-Related Information - Withhold Under 10 CFR 2.390.

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Security-Related Information - Withhold Under 10 CFR 2.390 to NRC-24-0056 Page I LICENSE RENEW AL REQUIREMENTS FOR 10 CFR 54.37 In accordance with 10 CFR 54.37(b) and the guidance specified in Regulatory Is ue Summary 2007-16, Revision 1, "Implementation of the Requirements of the 10 CFR 54.37(b) for Holders of Renewed Licenses," the UFSAR update required by 10 CFR 50.71 (e) must include any structures, systems, or components (SSCs) newly identified that would have been subject to an aging management review or evaluation of time-limited aging analyses in accordance with 10 CFR 54.21. This UFSAR update must describe how the effects of aging will be managed such that the intended function(s) in 10 CFR 54.4(b) wi ll be effectively maintained during the period of extended operation. DTE conducted reviews and detennined that there are no newly identified SSCs that would have been subject to an aging management review or evaluation as a time-limited aging analysis (TLAA). contains Security-Related Information - Withhold Under 10 CFR 2.390.

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ML24318C477

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5.3 BACKGROUND

2.7 REFERENCES

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5.3 BACKGROUND

2.7 REFERENCES

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