ML21055A068

Submittal of Revision 23 to Updated Final Safety Analysis Report, 10CFR50.59 & 10CFR72.48 Evaluation Summary Reports, Commitment Management Report, Revisions to Technical Requirements Manual & Tech Specifications Bases

ML21055A068
Person / Time
Site:	Fermi, 07200071
Issue date:	02/02/2021
From:	Peter Dietrich DTE Electric Company
To:	Document Control Desk, Office of Nuclear Material Safety and Safeguards, Office of Nuclear Reactor Regulation
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References
NRC-21-0002
Download: ML21055A068 (98)

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{{#Wiki_filter:.J Peter Dietrich Senior Vice President and Chief Nuclear Officer DTE Electric Company 6400 N. Dine Highway, Newport, MI 48166 Tel: 734.586.4153 Fu:: 734.586.1431 Email: peter.dietrich@dteenergy.com DTE Security-Related Information - Withhold Under 10 CFR 2.390 February 2, 2021 NRC-21-0002 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 10 CFR 50.71(e) 10 CFR 50.54(a)(3) 10 CFR 50.4(b)(6) 10 CFR 50.59(d)(2) 10 CFR 54.37(b) 10 CFR 72.48( d)(2) Subject Submittal of Revision 23 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 Specifications Bases, and a Summary of the Excessive Detail Removed from the UFSAR Pursuant to 10 CER 50.71(e) and 10 CFR 50.4(b)(6), DTE Electric Company (DTE) hereby submits an electronic version on Compact Discs (CDs) of Revision 23 to the Fermi 2 Updated Final Safety Analysis Report (UFSAR). In accordance with 10 CFR 50.7l(e), Revision 23 of the UFSARreflects changes made as a result of license amendments and other changes made under the provision of 10 CFR 50.59. Revision 23 includes plant configuration changes made through the end of the twentie.th refueling outage which concluded on August 5, 2020. Sections, Tables, and Figures that have been changed in Revision 23 are marked REV 23 02/21" in the lower right hand comer of. each page and are annotated by revision bars in the appropriate margin. }i-b63 fl)H~S7-(p Afl!-~ '\\t:

• r----En-c-losed--CD-2_co_n_ta_in_s_S_ec_uri_ty ___ R_ela_ted_Infi_orm_a_ti_on---W-ith_h_ol-,d-U_n_d-er_l_O_C_FR_2_.-390-. ----. /JM 55

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. When se rated from CD 2, this document Is decontrolled. ..,,.... -:_;'*\\ '

I,- USNRC NRC-21-0002 Page2 In a previous UFSAR revision, numerous UFSAR figures that are based on con.trolled plant drawings were removed from the UFSAR and replaced with references to the controlled plant drawings. The current revisions of the associated controlled plant drawings are being provided electronically on the enclosed CDs. Based on NRC Regulatory Issue Summary (RIS) 2015-17, Review and Submission of Updates to Final Safety Analysis Reports, Emergency Preparedness Documents, and Fire Protection Documents," DTE has reviewed Revision 23 of the UFSAR, and the associated controlled plant drawings being provided, for security-related information (SRI). Consequently, two CDs are being provided. CD 1 contains the entire UFSAR Revision 23 and most of the controlled plant drawings associated with UFSAR figures. CD 1 does not contain any SRI and is suitable for public disclosure. CD 2 contains the remainder of the controlled plant drawings associated with UFSAR figures. CD 2 does contain SRI and should be withheld from public disclosure under 10 CFR 2.3 90. The information that is SRI is designated by the statement "Security-Related Information - Withhold Under 10 CFR 2.390" at the top of the page. This submittal also includes seven enclosures as described below: provides the 10 CFR 50.59 Evaluation Summary Report including brief descriptions of 10 CFR 50.59 Evaluations performed since the previous report submitted with UFSAR Revision 22. 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 summaries of commitments that have been deleted or changed since the previous report submitted with UFSARRevision 22. DTE's 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. provides revised pages of Volume I of the Technical Requirements Manual (TRM) issued since the previous report submitted with UFSAR Revision 22. The TRM is incorporated by reference in the UFSAR; therefore, these pages are being submitted in accordance with 10 CFR 50.7l(e). provides revised pages of the Technical Specifications Bases (TSB) issued since the previous report submitted with UFSAR Revision 22. These pages are being submitted in accordance with the TSB control program in Technical Specification Section 5.5.10. 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.

USNRC NRC-21-0002 Page3 provides the 10 CFR 72.48 Evaluation Summary Report including brief descriptions of 10 CFR 72.48 Evaluations performed in accordance with the general license under docket number 72-71 since the previous report submitted with UFSAR Revision 22. This report is being submitted in accordance with the requirements of 10 CFR 72.48(d)(2). provides the results of the aging management review in accordance with the requirements of 10 CFR 54.37(b) for the Fermi 2 renewed license. Should you have any questions or require additional information, please contact Ms. Margaret Offerle, Manager-Nuclear Licensing, at (734) 586-5076. I declare under penalty of perjury that the foregoing is true and correct. Executed on February 2, 2021 ?-;;12{) Peter Dietrich Senior Vice President and Chief Nuclear Officer Enclosed CDs:

1. Fermi 2 UFSAR Revision 23 and Drawings Associated with UFSAR Revision 23 Figures (For Public Use)

2. Additional Drawings Associated with UFSAR Revision 23 Figures (Contains SRI, Not For Public Use)

Additional

Enclosures:

1. 10 CFR 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 54.3 7 cc:

NRC Project Manager NRC Resident Office Regional Administrator, Region ill

CDl Fermi 2 UFSAR Revision 23 and Drawings Associated with UFSAR Revision 23 Figures (For Public Use)

Security-Related Information - Withhold Under 10 CFR 2.390 CD2 Additional Drawings Associated with UFSAR Revision 23 Figures (Contains SRI, Not For Public Use) CD 2 contains Security-Related Information - Withhold Under 10 CFR 2.390. When separated from CD 2, this cover sheet is decontrolled.

ENCLOSURE 1 TO NRC-21-0002 10 CFR 50.59 Evaluation Summary Report to NRC-21-0002 Page 1 50.59 EVALUATION

SUMMARY

50.59 Evaluation No: 17-0099 Rev. 0 UFSAR Revision No. 23 Reference Document: EDP 37537 Section(s) 7.1.2.1.15.1, 7.6.1.9, 7.6.1.13.8.1, & 7.6.2.13.6.1 Title of Change: LCR 17-032-UFS Table(s) NIA Figure Change D Yes

• [!] No Traversing In-Core Probe (TIP) Control System Replacement Engineering Design Package (EDP) 37537 replaces the control components of the TIP System in response to obsolescence and also reconfigures the data path for direct interface with the 3D Monicore (3DM) computer instead of through the Integrated Plant Computer System (IPCS).

The existing analog Drive Control Units (DCU) are replaced with digital based Automatic TIP Control Units (ATCU) which monitor and control path selection, position, and traverse speed of the TIP fission chambers (detectors). In addition, the existing mechanical Veeder Root counters on all five drive mechanisms are replaced with absolute encoders to identify the TIP detector positions. The proposed replacement of the existing analog components of the TIP control system with digital equivalents will not reduce the margin of safety as defined in the Technical Specification, Safety Evaluation Report (SER) or UFSAR. Evaluation of the effects of the proposed change indicates that all design standards and applicable safety criteria are met. The replacement Automatic TIP Control Units perform the same important-to-safety function as the existing analog Drive Control Units by transmitting a permissive to the TIP guide tube isolation ball valves. Failure of the new digital component is no different than failure of an existing analog component where isolation of the affected TIP guide tube is subsequently established by actuation of the redundant shear valve. This holds true also for removal of the IPCS from data handling between the TIP system and the 3DM system. There are no more than minimal impacts on likelihoods or consequences of previously evaluated accidents or malfunctions, no potential for the creation of a new type of event or malfunction with a different result, no adverse impacts to design basis limits for fission product barriers, and no impact to evaluation methodologies as described in the UFSAR. Therefore, prior NRC approval of this change is not required. to NRC-21-0002 Page2 50.59 EVALUATION

SUMMARY

50.59 Evaluation No: 19-0026 Rev. 0 Reference Document: TSR 38095 LCR 19-059-UFS LCR 19-065-UFS LCR 20-006-UFS UFSAR Revision No. 23 Section(s) Numerous Table(s) Numerous Figure Change IE] Yes Title of Change: Technical Service Request (TSR) 38095 GNF3 New Fuel Introduction Fermi 2 has initiated the transition from the current GE14 (lOxl0) fuel design to the more advanced GNF3 (lOxlO) fuel design in accordance with the Fermi 2 reload process. Towards this end, 176 assemblies of GNF3 introduced into the core during Refueling Outage (RF) 20 will support plant operation during Cycle 21. Additional GNF3 assemblies will be inserted during later operating cycles until the core is comprised entirely of GNF3 fuel. The evaluation of design impacts associated with GNF3 new fuel receipt and placement in the spent fuel pool prior to RF20 have already been addressed under TSR 38170 and its associated 50*.59 Evaluation, 19-0208. In contrast, TSR 38095, addresses design impacts to the fuel design basis configuration documentation due to the introduction of the GNF3 fuel type into the operating reactor. The transition to a GNF3 based fuel cycle is intended to support the near-term future transition to a 24-month Fermi 2 fuel cycle. Note, however, that while much of the design supporting the current transition to GNF3 fuel has been performed conservatively based on a 24-month operating cycle, actual transition to a 24-month operating cycle will be conducted later under a license amendment re'quest The following changes have been determined to screen in and, therefore, require full evaluation under 50.59: The effects of increased core decay heat on maximum local suppression pool temperature, post-accident ultimate heat sink temperature and makeup requirements, and station blackout containment response (temperature and pressure) and condensate storage tank (CST) demand. The effects of an additional standby liquid control (SLC) injection delay associated with initial flushing of the SLC injection piping on post-anticipated transient without scram (A TWS) containment temperature and pressure. The effects of an increased core source term on post-accident dose consequences and Environmental Program component dose qualification margins. Several UFSAR described methods are replaced or altered, specifically: o A correction was applied to the decay heat model used to evaluate spent fuel pool design heat loads. to NRC-21-0002 Page3 o The ODYN analysis of the full-power ATWS overpressure is replaced by one performed using TRACG-A1WS overpressure (see separate 50.59 evaluation 19-0264 in this Enclosure). o The current ORIGEN-S based core source term is replaced with a core source term obtained using ORIGEN2 2.1. o The GEH determination of the TPOOL calculation of maximum local suppression pool temperature due to the change in core decay heat is based on an assessment of the expected response and not on an explicit rerunning of the code. o The determination of maximum local spent fuel pool temperature, previously using the FLUENT/UNS Version 42.8 fluid dynamics code, is updated to use the newer FLUENT Version 18.l code. GNF3 fuel bundles are designed and manufactured by Global Nuclear Fuel (GNF) to have the same form, fit, and function as earlier fuel designs used for Fermi 2, and also manufactured by GNF. All of the licensing criteria for fuel, as specified by GESTAR-II have been demonstrated (including the cycle-specific analyses performed for each reload), therefore ensuring that the design functions of the fuel and reactor core, containment, and emergency core cooling systems are maintained. Since a GNF3 fuel assembly has physical characteristics ( external dimensions, weight, material composition, etc.) that are fully compatible with the existing plant equipment, will be handled in the same manner, and weighs less than the initial core fuel assemblies, the frequency of occurrence of the fuel handling accident will not be increased. Since all other accidents described in the UFSAR are initiated by operator error or equipment failure or malfunction outside the fuel and core, use of a new fuel bundle design, which meets all applicable design and licensing requirements for fuel, does not have any effect on the frequency of occurrence of those accidents or the malfunction of other SSCs. The general increase in the GNF3 source term compared to the base GE14 source term required re-evaluation of the consequences of accidents involving fuel failure. The dose increases associated with the revised radiological consequences remain no more than minimal. The introduction of GNF3 does not introduce any new component or system level failure modes such that the consequences of a malfunction of equipment important to safety are made worse. Furthermore, there are no new failure modes that in and of themselves affect the magnitude of a release or redundancy of any mitigating equipment to be less than currently evaluated. GNF3 fuel bundles have physical characteristics ( external dimensions, weight, material composition, etc.) which are fully compatible with the existing plant equipment and systems and will be handled in the same manner. The behavior of GNF3 fuel in the core has been properly evaluated. Therefore, use of GNF3 fuel bundles does not increase the possibility of an accident of a different type or result in a malfunction of an SSC important to safety with a different result Loss-of-coolant accident (LOCA) analysis results for GNF3 showed an increase in the maximum local cladding oxidation, however, the results remain within the design basis limits. The increased GNF3 core decay heat was explicitly evaluated relative to impacts to containment and the results show that allowable design basis limits are not exceeded or altered for GNF3 introduction. Prior to each reload, cycle-specific power distribution limits for each fuel type in the core are established to assure that the margin of safety for fuel cladding integrity will not be

\\.

• Enclosure 1 to NRC-21-0002 Page4 reduced. In addition, cycle specific analyses confirm that overpressure protection criteria will not be exceeded during the limiting pressurization event Therefore, the use of the GNF3 fuel design does not have an impact on the integrity of the fuel cladding, reactor coolant pressure boundary,orcontainment Regarding methods of evaluation, the generation of the GNF3 source term is based using the GEH controlled version ofORJGEN2 (vs the previously employed ORJGEN-S based analysis) is consistent with the effective NRC endorsement of both codes in Regulatory Guide 1.183 Rev 0. '

The correction of the ASB 9-2 Brach Technical Position model of decay heat, which was previously licensed for use by Fermi 2 in evaluating spent fuel pool heatup, has been reviewed and approved for the Waterford plant Accordingly, this change which removes a significant over-conservatism is not a departure from the current licensed methodology. The determination of the change in maximum post-LOCA local suppression pool temperature, originally made using the TPOOL code has been assessed using the calculated change in bulk suppression pool temperature for the evaluated increase in integrated nominal core decay heat Because the differential between bulk and local temperature tends to decrease with increasing bulk temperature, this method for calculating the change in local suppression pool temperature is more conservative than would be obtained using TPOOL; therefore, the applied approach is not a departure from an NRC approved method. The replacement of the original spent fuel pool local heating evaluation performed using FLUENT/UNS Version 42.8 with a new GNF3 based analysis performed FLUENT Version 18.1 was determined to not be a departure from an NRC-approved method on the basis that the new version of FLUENT produces essentially the same result when benchmarked against the original analysis. Therefore, prior NRC approval of this change is not required. \\ to NRC-21-0002 Page5 50.59 EVALUATION

SUMMARY

50.59 Evaluation No: 19-0208 Rev. 0 Reference Document: TSR 38170 LCR 19-049-UFS UFSAR Revision No. 23 Section(s) 3.13.3.17.7, 9.1.2.1, 9.1.2.3, & 9.1 References Table(s) NIA Figure Change D Yes Title of Change: Tec~nical Service Request (fSR) 38170 GNF3 New Fuel Introduction TSR 38170 addresses Fermi 2 design impacts required to support GNF3 new fuel receipt and placement in the spent fuel pool (SFP) prior to its introduction into the Fermi 2 core in Cycle 21. The SFP criticality analyses that currently demonstrate the adequacy of the in-rack criticality control for the GEl 4 fuel type have accordingly been re-performed for the new GNF3 fuel type. Whereas the current GE14 analyses were prepared using Version 0lA of the GEH controlled version of the Los Alamos neutral particle transport Monte Carlo simulation code, MCNP Version 04, the new GNF3 analyses utilizes MCNP Version 05P, the GNF controlled version of MCNP Version 05. The 50.59 screen prepared in support ofTSR 38170 has determined that the change in MCNP versions affects a described method of analysis used in a plant safety analysis for which a 50.59 evaluation must be performed. The criticality calculation subroutines in MCNP Versions 4 and 5 are identical. The only substantive difference relative to MCNP criticality calculations is a modification of the random number generator (RNG). Both RNG versions implement Lermer's linear congruential scheme; however, the Version 5 model allows the user to extend the Version 4 48-bit RNG to a 63-bit implementation. The 63-bit version simply expands the period of generation - i.e., increases the pool of available random numbers. Version 5 maintains the original 48-bit RGN as the default RNG. The criticality analyses performed in support of GNF3 new fuel receipt to be issued with TSR 38170 were performed using the default Version 5 RNG - i.e., they used the 48-bit version 4 RNG. On these bases, the change in MCNP Version from 4 to 5 in performing the criticality calculations does not depart from the previously approved methods of evaluation. Therefore, prior NRC approval of this change is not required. to NRC-21-0002 Page6 50.59 EVALUATION

SUMMARY

? 50.59 Evaluation No: 19-0264 Rev. 0 UFSAR Revision No. NIA Reference Do~nment: TSR 38095 Section(s) _N_I_A _______ _ Title of Change: Table(s) NIA Figure Change_ D Yes Implementation ofTRACG Methodology for Calculation of Peak Pressure for the Anticipated Transient Without Scram (ATWS) Event As part of the GNF3 New Fuel Introduction Project, TRACG is applied to the ATWS analysis. TRACG code is a thermal-hydraulic analysis code intended to be used as a realistic analysis 1-1 model. The NRC staff approved TRACG for ATWS events on August 18, 2003. The TRACG methodology replaces the ODYN methodology for the determination of peak pressure only. TRACG for A TWS can be used prior to the time of signal initiation for the Standby Liquid Control System pump injection of boron. TRACG for ATWS is generically NRC approved for licensees to adopt provided methodology conditions and limitations are met. The TRACG ATWS Licensing Topical Report justifies the use of TRACG for modeling the A TWS event up to Standby Liquid Control System initiation. The GEH TRACG code model description, qualification, appµcation was previously approved for use at Fermi 2 with 50.59 "Evaluation 12-0082 (summarized in UFSAR Revision 19 submittal in 2014). The NRC approved TRACG for ATWS events on August 18, 2003 and updated in 2010. Fermi 2 has complied with all implementation requirements such that the TRACG ATWS methodology is approved for use at Fermi 2. Therefore, prior NRC approval of this change is not required. to NRC-21-0002 Page7 50.59 EVALUATION

SUMMARY

50.59 Evaluation No: 20-0023 Rev. 0 Reference Document: TM 20-0003 UFSAR Revision No. Section(s) Table(s) NIA NIA Figure Change D Yes NIA Title of Change: Temporary Modification (fM) 20-0003 to Gag Reactor Water Cleanup (RWCU) Thermal Relief Valve The RWCU Filter/Demineralizer (F/D) B" Thermal Expansion Relief Valve G3300F062B is lifting and not re-seating when placing the B" F/D G3305D001B in service. Flow through the degraded valve results in decreased margin to RWCU isolation on high differential flow. The relief valve will be gagged closed by,TM 20-0003 to prevent it from opening during startup pressure perturbations. The TM will be installed until a new relief valve is procured and/or maintenance can be performed. The valve provides protection to RWCU B" F/D and piping against temperature induced pressure fluctuations caused by running the RWCU hold pump G3305C003B while the F/D is isolated. Manual operator action to shut off the hold pump is being proposed as a replacement to the valve's automatic relief function during the backwash/precoat operation and restoration ofRWCU B" F/D. The relief function is only applicable when the hold pump is on and the F/D is isolated, and therefore, the relief *function is not required when RWCU B"'F/D is running in normal operation. The installation of Temp Mod TM-20-0003 does not require prior NRC approval. The so_urce of internal heat, hold pump*G3305C003B, will be removed while the F/D is in service and compensatory actions will be taken to secure the hold pump prior to the *line reaching 1275 psig if the F/D is isolated and the hold pump is running during manual operation. Gagging the relief valve does not result in more than a minimal increase in frequency, likelihood, or consequences of an accident or malfunction as evaluated in the UFSAR. There are also no possibilities for new accidents or malfunctions di:ffe~t than evaluated in the UFSAR, no impact to fission product barriers, and no impact to evaluation methods as descnbed in the UFSAR. Therefore, prior NRC approval of this change is not required. [Note that the temporary modification descnbed in this evaluation has since been removed and eancelled due to subsequent repair of the relevant equipment.] to NRC-21-0002 Page 8 50.59 EVALUATION

SUMMARY

50.59 Evaluation No: 20-0027 Rev. A Reference Document: EDP 80131 LCR 20-007-UFS UFSAR Revision No. Section(s) Table(s) 6.2.1.6 & A.1.54 6.2-8 Figure Change D Yes 23 Title of Change: EDP 80131 and LCR 20-007-UFS Torus Coating Modification The existing Plasite 7155H coating in the Fermi 2 Torus is removed and replaced with Carboguard 6250 N coating for the submerged portion of the Torus up to approximately 14" into the vapor region (approximately Elevation 558'-2") in response to NRC Confirmatory Action Letter EA-19-097. The partial re-coat of the Torus requires an overlap between the new and existing coatings at the transition line (it is not possible to abut the coatings up to each other without potentially creating a coating gap). At the top of the new coating (Elevation 558'-2"), there will be a band of the Carbo guard coating that overlaps the Plasite coating Oess than 1/2" wide) which will be considered "unqualified." The Torus coatings are currently described as fully qualified (per Regulatory Guide 1.54, 1973, also referred to as Rev. 0, and American National Standards Institute (ANSI) NlOl.4 requirements) in the UFSAR. Per the associated 50.59 screening, the addition of the unqualified Torus coating is considered adverse and requires evaluation under 10 CFR 50.59. Additionally, the proposed exceptions to the application of coating qualification standards for the new Carboguard 6250 N coating (i.e., the exceptions to the recommendations of Regulatory Guide 1.54 Rev, 0 / ANSIN101.4 identified in EDP 80131) require evaluation under 10 CFR 50.59. This evaluation determines that the addition of unqualified Torus coating to the Fermi 2 containment and the changes to the standards used for the qualification of the new Torus coating as a result of the Torus recoat described above do not require prior NRC approval. This conclusion is based on the establishment that, while this unqualified coating is postulated to fail in design basis accident (DBA) conditions, the resulting additional load on the Emergency Core Cooling System (ECCS) strainers does not impact the ability of the associated ECCS pumps to meet their flow rate requirements, similar to existing unqualified containment coatings. Also, it is concluded that the use of the alternative qualification standards endorsed in RG 1.54 Rev. 2 provide an acceptable qualification basis for the Carboguard 6250 N coating at Fermi. The proposed activity does not result in more than a minimal increase in the frequency of 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 an SSC important to safety nor the consequences of such a malfunction previously evaluated in the UFSAR. The proposed activity does not create a possibility 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 to NRC-21-0002 Page 9 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. to NRC-21-0002 Page 10 50.59 EVALUATION

SUMMARY

50.59 Evaluation No: 20-0074 Rev. 0 UFSAR Revision No. NIA Reference Document: EPGISAG Rev. 4 Section(s) _N_I_A _______ _ Title of Change: Table(s) NIA Figure Change D Yes EOPISAG/fSG Update to BWROG EPG/SAG Revision 4 Vol I to VI, Appendix A, B, C and TSG Revision 1 The Boiling Water Reactor Owner's Group (BWROG) has issued the Emergency Procedure and Severe Accident Guidelines (EPGs/SAGs) Revision 4 and Technical Support Guidance (TSG) Revision 1. This change has several generic changes that are being evaluated here:

1. Modify Emergency Depressuriz.ation (ED) guidance by moving ATWS ED into contingencies 4 & 5.

2. Adding additional operation guidance to tables and isolation/interlock defeats.

3. Changes to the ATWS strategy.

BWROG has updated the Emergency Operating Procedure (EOP)ISAG source documents. This evaluation shows that the changes resulting from the BWROG generic guidelines do not require prior approval to be implemented into Fermi 2 EOPISAG program documents. These changes have no more than minimal or no impacts on fission product barriers, or the consequences of any previously evaluated events, no change in :frequency of occurrence of events or malfunction, no potential for creation of a new type of event and no change to methods. Implementation of EPGs/SAGs Revision 4 into the EOP program may be performed without prior regulatory approval. Therefore, prior NRC approval of this change is not required. L

ENCLOSURE 2 TO NRC-21-0002 Commitment Management Report to NRC-21-0002 Page 1 I 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 50.71(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 1: 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 of recurring regulatory actions such as routine submittals. Changes to these types of RACTS items are not identified in Table 1 or Table 2 because the items were never regulatory commitments per the NEI 99-04 definition. to NRC-21-0002 Page2 Table 1 Regulatory Commitments Deleted From the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DELETION NO. DATE DOCUMENT 00999 09/15/1983 DTE Letter The commitment was to remove 50% of the The commitment was changed to one-time EF2-65232 safety relief valves (SRV) from service for closed. The commitment is obsolete. testing in a refueling outage and the Required testing and surveillances are remaining 50% in the next refueling outage. performed per 10 CFR 50.55a and the applicable ASME OM code according to the Fermi 2Jnservice Testing (1ST) Program, including any current NRC-aooroved reliefreauests. 08025 10/10/1985 DTE Letter Based on operational occurrences, actions The,commitment was changed to one-time VP-85-0198 were to be taken to provide training on the closed. The training was completed in importance of logging activities, shift 1985. Fermi 2 now utilizes the industry turnover, system startup, and transient standard systematic approach tp training initiation. (SAT). The commitment is no longer laoolicable. 07340 03/05/1986 NRC Inspection The commitment was to observe valve The commitment was chaµged to one-time Report 86-007 remote position indicators every 2 years to closed. The commitment is obsolete. verify accuracy of the indication, including Required testing and surveillances are at plant remote shutdown panels. performed per 10 CFR 50.55a and the applicable ASME OM code according to the Fermi 2 IST Program, including any current NRC-aooroved relief reauests. to NRC-21-0002 Page 3 Table 1 Regulatory Commitments Deleted From the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DELETION NO. DATE DOCUMENT 07778 10/01/1986 DTE Letter The commitment was to incorporate the The commitment was changed to one-time VP-86-0135 requirement for a Shift Technical Advisor closed. The STA educational requirements (STA) to have a bachelor's degree in a are captured in the Fermi 2 Technical scientific or engineering discipline or Specifications (5.2.2) and UFSAR Section equivalent into training documentation. 13.1.2. The commitment is no longer aoolicable. 87136 05/01/1987 DTE Letter As a result of Licensee Event Report (LER) The commitment was changed to one-time NRC-87-0015 87-010, an audit of operator training records closed. The audit was previously was to be performed to verify required completed in 1987. Fermi 2 now utilizes training was completed. the industry standard systematic approach to training (SAT). The commitment is no lomrer aoolicable. 87395 09/22/1987 NRC Letter to DTE The commitment was to update the 1ST The commitment was changed to one-time program and surveillances to comply with closed. The commitment is obsolete. NRC letters regarding entry into Technical Required testing and surveillances are Specification Limiting Conditions for performed per 10 CFR 50.55a and the Operation based on 1ST surveillance results. applicable AS:tvffi OM code according to the Fermi 2 Inservice Testing (1ST) Program, including any current NRC-aooroved relief reouests. to NRC-21-0002 Page4 Table 1 Regulatory Commitments Deleted From the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DELETION NO. DATE DOCUMENT 87505 10/22/1987 DTE Letter The commitment was to update the IST to The commitment was changed to one-time NRC-87-0209 add specific valves and ensure surveillances closed. The commitment is obsolete. reflect the 1ST requirements. Required testing and surveillances are performed per 10 CFR 50.55a and the applicable ASME OM code according to the Fermi 2 Inservice Testing (1ST) Program, including any current NRC-approved relief requests. 88028 01/12/1988 DTE Letter In response to a Notice of Violation (NOV), The commitment was changed to one-time NRC-87-0232 actions were to be taken to revise closed. The procedure revisions were surveillance procedures to verify the contact previously performed in 1988. Current continuity in the circuits. surveillance procedure methodology inherently tests contact continuity. The commitment is no lon1Zer applicable. 88086 02/19/1988 DTE Letter The commitment was to modify The commitment was changed to one-time NRC-88-0044 administrative controls for the 1ST program closed. The commitment is obsolete. to replace valve leakage limits. Required testing and surveillances are performed per 10 CFR 50.55a and the applicable ASME OM code according to the Fermi 2 Inservice Testing (1ST) Program, including any current NRC-approved relief requests. to NRC-21-0002 Page5 Table 1 Regulatory Commitments Deleted From the Regulatory Commitment Tracking System (RACTS) RACTS ORJG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DELETION NO. DATE DOCUMENT 88364 / 07/15/1988 DTE Letter In response to an NOV regarding the non-The commitments were changed to one-88366 / NRC-88-0175 interruptible air supply (NIAS) system, time closed. The operability guidelines and 88414 actions were to be taken to develop reference documents were previously 08/17/1988 DTE Letter guidelines for operability and a support prepared in 1988/1989. Current operability NRC-88-0198 system reference document. The guidelines are now in accordance with commitment regarding operability standard industry practice based on NEI guidelines, especially with respect to support 18-03 guidance. The commitments are no systems, was later reiterated in a response to longer applicable. an NRC SALP 9 Board Report. 89572 10/31/1989 DTE Letter In response to the NRC evaluation of the The commitment was changed to one-time NRC-89-0221 Fermi 2 compliance with NUREG-0737, the closed. The training was completed in plant licensed and non-licensed operations 1989. Fermi 2 now utilizes the industry

• personnel were to be given formal training standard systematic approach to training on the importance of the SGTS sample lines (SA1). The commitment is no longer heat tracing in assuring a reliable accident applicable.

range effluent monitorinJ;!; system sample. 89595 I 11/15/1989 DTE Letter As part ofIST reliefrequests,*commitments The commitment was changed to one-time 89596 NRC-89-0232 were made to (1) test a specific valve closed. The commitment is obsolete. individually during future tests and (2) Required testing and surveillances are establish administrative limits in performed per 10 CFR 50.55a and the consideration of all valves in a pen~tration applicable ASME OM code according to group rather than the simple sum of the Fermi 2 Inservice Testing (1S1) individual limits for each of the valves in the Program, including any current NRC-group based on size. approved relief requests. to NRC-21-0002 Page 6 Table 1 Regulatory Commitments Deleted From the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DELETION NO; DATE DOCUMENT 90059 01/02/1990 NRC Inspection In response to an NRC Inspection Report, The commitment was changed to one-time Report 89-030 actions were to be taken to address concerns closed. The UFSAR was previously with the design of the control center heating, updated in 1989/1990 to identify the ventilation, and cooling (CCHV AC) and licensed configuration and associated control room emergency filtration (CREF) regulatory requirements with the CCHV AC ,systems. and CREF systems. 90093 01/26/1990 DTE Letter In response to Generic Letter (GL) 89-13, The commitment was changed to one-time NRC-90-0012 maintenance practices, operating and closed. The further review was previously emergency procedures, and training completed prior to 1991 and no subsequent programs related to the service water review was required. The commitment is systems had been established to ensure that no longer applicable. the systems will perform their intended design and safety functions, and the operators would also perform effectively in operating the systems. These programs and procedures were to be further reviewed to assure the requested confirmation. 90214 03/23/1990 NRC Inspection As a result ofLER 89-019, corrective The commitment was changed to one-time Report 90-002 actions were to be taken to evaluate the closed. The evaluation was previously potential for bearing failure on CCHV AC performed in 1990 and no further actions fans. were required. The commitment is no longer applicable. to NRC-21-0002. Page 7 Table 1 Regulatory Commitments Deleted From the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMl\\fiTMENT BASIS FOR DELETION NO. DATE DOCUMENT 90342 I 07/18/1990 DTE Letter In response to NRC Bylletin 90-01, specific The commitments were changed to one- - 90343 NRC-90-0128 Rosemount transmitters were to be trended time closed. The specific Rosemount to monitor for any degraded or degrading transmitters in question have since been condition. replaced. The commitments are no longer applicable. 94175 09/01/1992 DTE Letter The commitment was to test specific The commitment was changed to one-time NRC-92-0099 pressure boundary valves identified in an closed. The commitment is obsolete. IST relief request only during cold shutdown Required testing and surveillances are or refueling. performed per 10 CFR 50.55a and the applicable ASME OM code according to l the Fermi 2 Inservice Testing (IST) Program, including any current NRC-approved relief requests. 93225 07/30/1993 DTE Letter As part of an exemption request regarding The commitment was changed to one-time NRC-93-0122 Fermi 1, training of personnel who perform closed. All training on site is performed work at Fermi 1 was to be performed under under the Fermi 2 training program, which the Fermi 2 training program. utilizes the industry standard systematic approach to training (SAT). The commitment is not required. 9406-9 01/14/1994 DTE Letter In response to an emergency diesel The commitment was changed to one-time NRC-93-0153 generator (EDG) failure, actions were to be closed. The maintenance work was taken to install locknuts to preclude bolts previously performed in 1994. The from backing out and potentially becoming commitment is no longer applicable. disconnected from the output shaft. to NRC-21-0002 Page 8 Table 1 Regulatory Commitments Deleted-From the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DELETION NO. DATE DOCUMENT 94264 07/12/1994 NRC Inspection In response to an NRC Inspection Report, The commitment was changed to one-time Report 94-008 actions were to be taken to address closed. Following additional training, inconsistent implementation of simulator review of operations and staff crew training between operations and staff crews. performance during requalification exams in 1994/1995 identified no further inconsistencies. Fermi 2 now utilizes the industry standard systematic approach to training (SAT). The commitment is no lon12:er applicable. 95001 12/21/1994 NRC Inspection In response to an NRC Inspection Report, The commitment was changed to one-time Report 94-018 actions were to be taken to ensure that closed. The forms used to track training operator requali:fication training attendance attendance were previously revised in records were complete and accurate. 1994/1995. Fermi 2 now utilizes the industry standard systematic approach to training (SAT). The commitment is no longer applicable. 97199 10/23/1997 DTE Letter In response to an NOV involving inadequate The commitment was changed to one-time NRC-97-0097 lubrication of motor control center (MCC) closed. The monitoring period ended in switches, a control group of disconnect 2000 and no further monitoring was switches was identified to be monitored for a required. The commitment is no longer period for effectiveness of cleaning and applicable. ~ lubrication and to detect any potential switch de~a.dation. to NRC-21-0002 Page9 Table 1 Regulatory Commitments Deleted From the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR DELETION NO. DATE DOCUMENT 20085 06/26/2002 DTE Letter In response to LER 02-002, corrective The commitment was changed to one-time NRC-02-0056 actions were to be taken to train operators on closed. The training was completed in the basis for manual actions associated with 2002: Fermi 2 now utilizes the industry the Appendix R fire scenario. standard systematic approach to training (SAT). The commitment is no longer aoolicable. 20167 06/04/2004 DTE Letter In response to a Request for Additional The commitment was changed to one-time NRC-04-0037 Information (RAI) regarding a license closed. The training update was completed amendment request, a commitment was in 2004. Fermi 2 now utilizes the industry made to update operator training to reflect standard systematic approach to training the pH control function of the standby liquid (SAT). The commitment is no longer control (SLC) system. annlicable. 20206 01/19/2006 DTE Letter In response to a Demand for Information, a The commitment was changed to one-time NRC-06-0002 commitment was made regarding training closed. The training update was completed for operations personnel on security-related in 2006/2007. Fermi 2 now utilizes the events. industry standard systematic approach to training (SAT). The commitment is no Ionizer aoolicable. to NRC-21-0002 Page 10 Table 2 Regulatory Commitments Revised in the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR COMMITMENT NO. DATE DOCUMENT CHANGE 96092 05/10/1996 D'IELetter In response to NRC Bulletin 96-02, D'IE The commitment used dated terminology NRC-96-0051 committed to revise the procedures for describing the 10 CFR 50.59 process. associated with movement of heavy loads The commitment wording was revised to to clarify that heavy load movement use the appropriate language and activities not bounded by the Fermi 2 terminology consistent with the current licensing basis will be considered "changes 10 CFR 50.59 rule. to procedures described in the safety analysis report and subject to a safety evaluation in accordance with 10 CFR 50.59. The commitment also identified that if an unreviewed safety question" is identified, a license amendment will be requested in advance. 97009 12/19/1996 D'IELetter As a result ofLER 96-019, corrective The specific CST level identified in the NRC-96-0106 actions were to be taken to maintain the commitment has been revised based on required volume of water in the CST subsequent engineering evaluations. The greater than 22 feet. commitment was revised to reflect the appropriate CST level required to support systems that utilize the CST inventory. to NRC-21-0002 Page 11 Table 2 Regulatory Commitments Revised in the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMI\\1ITMENT BASIS FOR COMMITMENT NO. DATE DOCUMENT CHANGE 20361 01/30/2014 DTE Letter In response to NRC Bulletin 12-01, DTE Per ML19163Al 76, the NEI OPC NRC-14-0007 committed to the schedule provided in the Initiative Revision 3, a risk evaluation NEI Open Phase Condition (OPC) may be perf onned as an alternative to Initiative letter to the NRC enabling active features that respond to an (ML13333Al47) and to follow the NEI OPC. The commitment was revised to deviation process as necessary. reflect the use of the risk evaluation as an alternative to the original NEI schedule for enabling the active features. Note that the risk evaluation was subsequently completed. 20319 04/24/2014 License Renewal The commitment is a License Renewal The commitment is revised to eliminate Application commitment for the Aboveground Metallic inspections of the CTG fuel oil tank. The Tanks Program. The commitment is to inspections committed to for the CTG fuel 01/20/2015 DTE Letter implement the new Aboveground Metallic oil tank were based on the intent of NRC-15-0005 Tanks Program to manage loss of material utilizing the existing tank beyond the and cracking for outdoor tanks within the original 40-year license period. 04/10/2015 DTE Letter scope of license renewal that are sited on Inspection of the CTG fuel oil tank is no NRC-15-0031 soil or concrete. The program is to include longer required as the existing tank has inspections of the condensate storage tank recently been replaced with an entirely (CST) and the combustion turbine new tank. generator (CTG) fuel oil tank. The program is also to manage the bottom surfaces of both in-scope aboveground metallic tanks. to NRC-21-0002 Page 12 Table 2 Regulatory Commitments Revised in the Regulatory Commitment Tracking System (RACTS) RACTS ORIG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR COMJ.\\1ITMENT NO. DATE DOCUMENT CHANGE 20327 04/24/2014 License Renewal The commitment is a License Renewal The commitment is revised to eliminate Application commitment for the Diesel Fuel inspections of the CTG fuel oil tank. The Monitoring Program. The commitment is inspections committed to for the CTG fuel 05/19/2015 DTE Letter to revise Diesel Fuel Monitoring Program oil tank were based on the intent of NRC-15-0056 procedures to monitor and trend parameters utilizing the existing tank beyond the in the EDG fuel oil storage tanks, EDG original 40-year license period. fuel oil day tanks, diesel fire pump fuel oil Inspection of the CTG fuel oil tank is no tank, and CTG fuel oil tank quarterly. In longer required as the existing tank has addition, the commitment is to revise the recently been replaced with an entirely Diesel Fuel Monitoring Program new tank. procedures to include a 10-year periodic cleaning and internal visual inspection of the EDG fuel oil storage tanks, EDG fuel oil day tanks, diesel fire pump fuel oil tank, and CTG fuel oil tank. to NRC-21-0002 Page 13 Table 2 Regulatory Commitments Revised in the Regulatory Commitment Tracking System (RACTS) RACfS ORIG. REFERENCE DESCRIPTION OF COMMITMENT BASIS FOR COMMITMENT NO. DATE DOCUMENT CHANGE 20378 12/02/2015 DTE Letter DTE committed to update the site SAMGs Per the SAMG Industry Initiative, NRC-15-0101 to future revisions of the BWROG generic _ Revision 1, the commitment was revised SAMGs, to integrate the SAMGs with to remove the reference to NEI 14-01. other emergency response guideline sets The NEI 14-01 reference is not required and symptom-based Efl?.ergency Operating since the Mitigation of Beyond Design Procedures, and to validate the SAMGs Basis'Events Rule does not reference NEI using the guidance in NEI 14-01, 14-01 and the document will not be Emergency Response Procedures and endorsed by the NRC. In addition, Guidelines for Beyond Design Basis PWROG and BWROG technical guidance Events and Severe Accidents. is sufficient to support integration and validation of site-specific SAMGs.

ENCLOSURE 3 TO NRC-21-0002 Summary of Revisions to Technical Requirements Manual, Volume I, and Revised Pages to NRC-21-0002 Page 1 Revision 119 05/02/2019 Revision 120 12/20/2019 Revision 121 12/27/2019 Revision 122 04/16/2020 Revision 123 07/13/2020 Summary of the Technical Requirements Manual (TRM) Volume I Changes* Revised TR 5.1.1 description oflnservice Inspection and Testing Program for Snubbers to implement ASME OM Code, 2012 Edition, for the fourth ten-year interval. Revised Table TR3.3.l.l-1 setpoints for the OPRM-Upscale confirmation count and amplitude. Revised Table TR3.7.7-1 to correct an Appendix R alternative shutdown control circuit label. Revised Core Operating Limits Report (COLR) for Cycle 20, Revision 1.* Revised TRSR 3.7.7.6 frequency on a one-time basis to re-align the performance of the TRSR for certain alternative shutdown system control circuit functions with plant cold conditions (i.e., during a refueling outage). Revised COLR for Cycle 21, Revision O.* Revised Tables TR3.6.3-l and TR3.8.4-1 to reflect de-energized and locked-closed status of certain combustible gas control system valves. The following pages are information only copies of the revised TRM pages for the above revisions.

• Pages of the COLR from Revisions 120 and 122 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.

TR 5.0 TR 5.1 TR 5.1.1 TRM Vol. I ADMINISTRATIVE CONTROLS Programs Inservice Inspection and Testing Program for Snubbers Programs TR 5.1 The Snubber Program Plan for the Preservice and Inservice Examination and Testing of Snubbers (Snubber Program) implements the requirements of the ASME OM Code, Subsections ISTA and ISTD, 2012 Edition, as required by ldCFR50.55a(b) (3) (v) (B) for the preservice and inservice examination and testing requirements of snubbers when using the 2006 Add~nda and later editions and addenda of Section XI of the ASME BPV Code. TRM 5.0-1 REV 119 05/19

TR 3.3 INSTRUMENTATION TR 3.3.1.1 Reactor Protection System (RPS) Instrumentation RPS Instrumentation TR 3. 3.1.1 The RPS instrumentation trip setpoints and response times are listed in Table TR3. 3.1.1-1. TABLE TR3.3.1.l-1 (Page 1 of 2) Reactor Protection System Instrumentation FUNCTION

1.

Intermediate Range Monitors

a.

Neutron Flux - High

b.

Inop

2.

Average Power Range Mani tors I*>

a.

Neutron Flux-Upscale (Setdown)

b. Simulated Thermal Power - Upscale

1. Fl.ow Biased (9)

,2. High Flow Clamped

c. Neutron Flux - Upscale

d.

Inop

e. 2-out-of-4 Voters

f.

OPRM-Upacale

1.

Confi=a.tion Count and

2.

Amplitude

3.

Growth

4.

Amplitude TRIP SETPOINT RESPONSE TIME (secondll) ~ 120/125 divisi= of full scale NA NA NA S 15% RTP S 0.62 (W-b.W)~> + 60.2%, with a maxlumm ot < 113.5% of RTP < 118% Rl'P NA NA 16 1.15 1.3 1.3 NA HA NA NA s o. os<*> NA ( continued) (a) Neutron detectors, APBM channel, and 2-out-of-4 Trip Voter digital electronics are exempt from reaponl5e tim.e testing. Response time shall be mea.Bured from activation ot the 2-out-of-4 Trip Voter output relay. (b) b.W 0 0% for two loop operation. ti.w - 8% for single loop operation. TRM Vol. I TRM 3.3-1 REV 120 12/19 i ~

• I i

Appendix R Alternative Shutdown Auxiliary Systems TR 3.7.7 TABLE TR3.7.7-l (Page 4 of 4) Appendix R Alternative Shutdown Control Circuits FUNCTION

82.

43S-2C Tranafer SWitch Valve Ell50-F015A

83.

43S-3A Transrer SWitch Valve El150-F017A

84.

Recirculation PUIIIP A Discharge Valve B31-F031A

85.

Cross-Tie Header Valve Ell-FOlO

86.

RHR to Recirculation Inboard Isolation Valve Ell-j'()lSA

87.

RHR Recirculation Outboard Isolation Valve Ell-F017A

88.

43B-4B Tranarer Switch Valve P44-F616

89.

KECW from Drywall Inboard Isolation P44-F616

90.

Dedicated Shutdown system

91.

43B-4CR Transfer Switch Valve P44-F607A

92.

EECW fiom Drywall Outboard Isolation P44-F607A

93.

Alternate QA IM (BOP) power to 72F-4A position 4C-R, throwover switch valve P44-F607A

94.

72M-3B position SBR transfer switch BOP Battery Charger 2C-1

95.

72S-2A position SC transrer switch BOP Battery Charger 2Cl-2 TRM Vol. I TRM 3.7-18 CONTROL CIRCUIT Transfer Transrer PuBh-button Push-button Push-button Push-button Transrer Selector Push-button Transfer Pushbutton Transfer Transfer Transfer SWITCH LOCATION H21-P627 H21-P627 H2l-P627 H21-P627 H21-P627 H21-P627 H21-P628 H21-P628 Hll-PBll H21-P632 H21-P632 Rl600Sl48 Rl600S011D Rl600S015A REV 120 12/19

Appendix R Alternative Shutdown Auxiliary Systems TR 3.7.7 SURVEILLANCE REQUIREMENTS TRSR 3.7.7.1 TRSR 3.7.7.2 TRSR 3.7.7.3 TRSR 3.7.7.4 TRSR 3.7.7.5 TRSR 3.7.7.6 SURVEILLANCE FREQUENCY For the SBFW system, verify by venting at 31 days the high point vents that the system piping from the pump discharge to the system isolation valves is filled with water. For the SBFW system, verify that each valve 31 days (manual, power-operated or automatic} in the flow path that is not locked, sealed, or otherwise secured in position, is in the correct position. For CTG 11 Unit 1, start and' supply load of' at least 10 MW to the Peaker Bus. Verify that each SBFW pump develops a flow of~ 600 gpm in a test flow path with a system head corresponding to the reactor vessel operating pressure including injection line losses. For the drywell cooling units, operate the unit for 72 hours with the fan in "HIGH" speed. Verify each required alternative shutdown system control circuit in Table TR3.7.7-1 is capable of performing its intended function(s}. 31 days 46 days on a STAGGERED TEST BASIS 46 days on a STAGGERED TEST BASIS 18 months*

• A one-time change extended the FREQUENCY from 18 months to 26 months for Table TR3.7.7-1 Functions 1 through 17 and 90 tested by 24.321.06.

This one-time FREQUENCY change is applicable for the duration of Cycle 20. See LCR 19-064-TRM. TRM Vol. I TRM 3. 7-14 REV 121 12/19

TR 3.6 TR 3.6.3 CONTAINMENT SYSTEMS Primary Containment Isolation Valves (PCIVs) PCIVs TR 3.6.3

1. The PCIVs and associated maximum isolation times for the automatic valves are listed in Table TR3.6.3-l.

2. The PCIVs and Primary Containment Flanges located in Locked High Radiation Areas are listed in Table TR3.6.3-2.

TABLE TR.3.6.3-1 {Page 1 of 23) Primary Containment !solation Valves FUNCTION

1.

Automatic Isolation Valves <*I

a.

Group 1 - Main Steam System Main Steam Isolation Valvee {MSIVs) Inboard Line A: B2103-F022A Line B: B2103-F022B Line C: B2103-F022C Line D: B2103-F022D Outboard Line A: B2103-F028A Line B: B2103-F028B Line C: B2103-F028C Line D: B2103-F028D Main Steam Line Drains Isolation Valves Inboard: B2103-F016 outboard: B2103-FD19

b.

Group 2 - Reactor Water Sample System Reactor Water Sample Line Ieolation Valves Inboard: B3100-F019 outboard: B3100-F020 TRM Vol. I TRM 3.6-3 MAXIMUM ISOLATION TIME {second.a) <uJ 5 5 5 5 5 5 5 5 23 23 15 15 {continued) REV 123 07/20

TABLE TR3.6.3-l (Page 2 of 23) Primary Containment Isolation Valve~ FUNCTION

1.

Automatic Isolation Valves<*> (continued)

c.

Group 3 - Residual Heat Removal (RHR) System RRR Drywall Spray Isolation Valves Loop A: E1150-F016A El150-F021A Loop B: E1150-F016B E1150-F021B RHR Containment Cooling/Teat Isolation Valves Loop A: Ell50-F024A Loop B: El150-F024B RHR Suppression Pool Spray Isolation Valves Loop A: Ell50-F027A Loop B: Ell50-F027B RHR Suppression Pool Spray/Teat I~olation Valves Loop A: Ell50-FD28A Loop B: Ell50-F028B

d.

Group 4 - Residual Heat Removal Shutdown Cooling and Head Spray RHR Shutdown Cooling Suction Isolation Valves Inboard: Ell50-F009 Outboard: E1150-F008 RHR Reactor Pressure Vessel Head Spray Isolation Valves Inboard: Ell50-F022 Outboard: Ell50-F023

e.

Group 5 - Core Spray System Core Spray Pump Flow Te~t Valves<*> Loop A: E2150-F015A Loop B: E2150-F015B

• To ensure LPCI response time of 72 seconds per OPL-4.

TRM Vol. I TRM 3.6-4 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (seconds) 150 60 150 60 45* 45* 60 60 45* 45* 51 51 36 120 108 108 (continued) REV 123 07/20

TABLE TR3.6.3-1 (Page 3 of 23) Prilllary Containment Isolation Valvea FUNCTION

1.

Automatic Isolation Valves 1*> (continued)

f.

Group 6 - High Preaaure Coolant Injection (HPCI) System HPCI Turbine Steam Supply Isolation Valves Inboard: E4150-F002 Outboard: E4150-F003 HPCI Turbine Steam Supply Outboard Iaolation Bypass Valve E4150-F600 HPCI Booster Pump Suction from Suppression Chamber Isolation Valve 1*l E4150-F042

g.

Group 7 - High Pressure Coolant Injection (HPCI) Vacuum Breakers HPCI Turbl.Jle Exhaust Line Vacuum Breaker Isolation Valves E4150-F07 5 E4150-F079

h.

Group 8 - Reactor Core Isolation Cooling (RCIC) System RCIC Steam Line Isolation Valves Inboard: Outboard E5150-F007 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 TildE (seconds) Ill) 15 45*

15 60 60 60 15 15 60 60 (continued)

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

TRM Vol. I TRM 3.6-5 REV 123 07/20

TABLE TR3.6.3-l (Page 4 of 23) Primary Containment Isolation Valves FUNCTION

1.

Automatic I11olation Valveal*I (continued)

j. Group 10 - Reactor Water Cleanup (RWCU) Sy11tem (Inboard)

Inboard: G3352-F001

k.

Group 11 - Reactor Water Cleanup (RWCU) System (Outboard) Outboard: G3352-F004 Outboard: G3352-F220

1.

Group 12 - To= Water Management System (TWMS) TWMS to RHR Line Isolation Valves Cbl 1°1 G5100-F605 G5100-F604 T'ifMS to CSS Te11t Line Isolation Valves Cb> le> G5100-F607 G5100-F606 Torus Drain Isolation Valveslbl 1°1 G5100-F600 G5100-F602 G5100-F601 G5100-F603

m.

Group 13-Drywell Sumps Drywell Floor Drain Sump Pump Discharge Isolation Valves Gll54-F600 Gll00-F003 Drywell Equipment Drain Sump Pump Discharge I11olation Valves TRM Vol. I Gll54-F018 Gll00-F019 TRM 3.6-6 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (aecond8) luJ 12 12 20 60 60 60 60 60 60 60 60 60 60 60 60 (continued) REV 123 07/20

TABLE TR3.6.3-l (Page 5 of 23) Primary Containment Ieolation Valves FUNCTION

1.

Automatic Isolation Valves<*> (continued)

n.

Group 14 - Drywall and Suppreesion Pool Ventilation Sy~tem Drywall Exhaust Isolation Valves T4803-E'602 T4600-F411 T4600-F402 Drywell N2 and Air Purge Inlet Isolation Valves T4803-F601 T4800-E'408 T4800-F407 Suppression Pool Exhaust Air Purge to Standby Gas Treatment Syetem and N2 Inlet Isolation Valvee T4600-F400 T4800-F410 T4600-E'401 T4600-F412 Suppreeeion Pool N2 and Air Purge Inlet Isolation Valves T4800-E"404 T4800-F405 T4800-F409

o. Not used

p.

Group 15 - Traversing In-core Probe (TIP) System TIP System Ball Valves C5100-F002 A, B, C, D, and E TRM Vol. I TRM 3.6-7 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (eeconciB) 5 5 5 5 5 5 5 5 5 5 5 5 5 NA (continued) REV 123 07/20

TABLE TR3.6.3-l (Page 6 of 23) Primary Containment Isolation Valves FUNCTION

1.

Automatic Isolation Valve!'!<*> (continued)

q.

Group 16 - Nitrogen Inerting System N2 Pressure Control Isolation Valve!'! Inboard: Outboard: T4800-E'455 T4800-F453 T4800-F454 T4800-F456 T4800-F457 T4800-E'458

r.

Group 17 - Recirculation Pump System and Primary Containment Radiation Monitoring System Recirculation Pumps Seal Purge Isolation Valve!'! Inboard: Outboard: B3100-F014A B3100-F014B B3100-F016A B3100-E'0l6B Primary Containment Gaseo= Radioactivity Monitor Isolation Valves Inboard: Outboard: T50-F450 T50-F451 T5000-E'455 T5000-F456

s.

Group 18 - Primary Containment Pneumatic Supply System N2 to Drywell Isolation Valves Inboard: Outboard: TRM Vol. I T4901-F601 T4901-F602 T4901-F465 T4901-F468 TRM 3.6-8 PCIVs TR 3.6.3 MAXIMOM ISOLATION TIME ( second.8) lul 60 60 60 60 60 60 5 5 5 5 60 60 60 60 60 60 60 60 (continued) REV 123 07/20

TABLE TR3.6.3-l (Page 7 of 23) Primary Containment Isolation Valves FUNCTION

2.

Remote-Manual I!!olation Valves ldJ

a.

Deleted

b.

RRR Shutdown Cooling Suction Inboard Isolation Valve Bypass Valve IP) Ell50-F608

c.

LPCI Inboard Isolation Valves l*I lrJ Loop A: Ell50-F015A Loop B: Ell50-F015B

d.

RHR Pumps Recirculation Motor Operated Valvesltll*l Pumps A/C: E1150-F007A Pumps B/D: Bll50-F007B

e.

Warm up and Flush Line I!!olation Valvel*Jltl Bll50-F026B

f.

Reactor Protection System In!!trumentation I~olation Valves Divi!!ion I: Ell-F414 Ell-F415 Division II: Ell-F412 Ell-E'413

g.

RHR Pump Torus Suction Isolation Valve~ 1,1 Pump A: Bll50-F004A Pump B: Ell50-F004B Pump C: Ell50-F004C Pump D: Ell50-F004D

h.

Core Spray Loop Inboard Isolation Valves ' Loop A: E2150-F005A Loop B: B2150-F005B TRM Vol. I TRM 3.6-9 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (seconds) Cul NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-l (Page 8 of 23) Prilnary Containment Isolation Valvee FUNCTION

2.

Remote-Manual Isolation Valves<d> (continued)

i. Core Spray Loop Minimum Recirculation Ieolation Valves !gl <*>

Loop A: Loop B: E2150-F031A E2150-F031B

j. Core Spray Loop Suction from Suppresi,ion Chamber Valves!*>

Loop A: E2150-F036A Loop B: E2150-F036B

k.

HPCI Pump Discharge to Reactor Feedwater Header Valve<h> E4150-F006

1.

HPCI Pump Minimum Flow Valve<1> <*l E4150-F012

m.

RCIC Pump Discharge to Feedwater Header Isolation Valve<1l E5150-F013

n.

RCIC Pump Ml.Iumum Flow Valve !kl<*> E5150-F019

o.

RCIC Pump Suction from Suppression Chamber Isolation Valvee<*> Inboard: E5150-F031

p.

Deleted TRM Vol. I TRM 3. 6-10 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (eeconds) NA NA NA NA NA NA NA NA NA continued REV 123 07/20

TABLE TR3.6.3-l (Page 9 of 23) Prilllary Containment Isolation Valves FUNCTION

2.

Remote-Manual Isolation Valves<dJ (continued)

q.

Deleted

r.

Prilllary Containment Monitoring System Torus Return I!!olation Valves Division I: T5000-F408A Division II: T5000-F408B

s.

Primary Containment Monitoring Sy~tem TorUB Suction Isolation Valves Division I: T5000-F407A Division II: T5000-F407B

t.

Drywell Atmosphere Sample Isolation Valves Division I: T5000-F401A T5000-F402A T5000-F403A T5000-F404A T5000-F405A Division II: T5000-F401B TRM Vol. I T5000-F402B T5000-F403B T5000-F404B T5000-F405B TRM 3.6-11 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (seconds) <uJ NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-1 (Page 10 of 23) Primary Containment Isolation Valve~ FUNCTION

2.

Remote-Manual Isolation Valvesldl (continued)

u.

Drywell to Suppression Chamber Vacuum Brea.leers N2 Supply Isolation Valves T4800-F416 T4800-F417 T4800-F418 T4800-F419 T4800-F420 T4800-F421 T4800-F422 T4800-F423 T4800-F424 T4800-F425 T4800-F426 T4800-F427

v.

Drywell Pressure Instrumentation Isolation Valve~ Divi~ion I: T5000-F420A Division II: T5000-F420B

w.

Suppres~ion Pool Level In~trumentation Isolation Valves Division I: E41-F40llbl T50-F412A!bl E41-F400 Division II: E41-E'403Cbl T50-F412Blbl E41-F402

x.

EECW Supply to Drywell Equipment Isolation Valves Division I: P4400-F606A Divi~ion II: P4400-F606B TRM Vol. I TRM 3.6-12 PCIVs TR 3.6.3 MAXIMOM ISOLATION TIME (seconda) Cul NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-l (Page 11 of 23) Primary Containment Isolation Valves FUNCTION

2.

Remote-Manual Isolation Valves 1dl (continued)

y.

EECW Return from Drywall Equipment Isolation Valve!!! Division I: P4400-F607A P4400-F616 Division II: P4400-F607B P4400-F615

z.

Deleted aa. TIP System Shear Valves Ill IQ) C5100-F001A C5100-F001B C5100-F001C C5100-F001D C5100-F001E ab. Post Accident Sampling Il!lolation Valves

1.

Drywall Atmol!lphere Sample Suction Valves Division I: P34-F404B P34-F403B Division II: P34-F403A P34-F404A

2.

Suppression Pool Atmosphere Sample Suction Valves Division I: P34-F405B P34-F406B Division II: P34-F405A P34-F406A TRM Vol. I TRM 3.6-13 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (second!!!) lul NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-l (Page 12 of 23) Primary Containment I~olation Valves FUNCTION

2.

Remote-Manual Isolation Valves ta> (continued) ab. Post Accident Sampling Isolation Valves (continued)

3.

Gaseou~ Sample Return Valves P34-F408 P34-F410

4. Pressurized Reactor Coolant Sample Suction Valves P34-H'401A P34-F401B

5. Liquid Sample Return Valves (bl P34-F407 P34-F409 ac. Torus to Secondary Containment Vacuum Breaker Isolation Valves T2300-F410 T2300-F409 ad. Primary Containment Water Level Instrumentation Isolation Valves T50-F458

3.

Manual Isolation Valves

a.

Drywell Condensate Supply Header Inboard Isolation ValvetPl Pl100-Fl26

b.

Drywell Control Air and N2 outboard Isolation Bypass ValvetPl T4901-F007

c.

N2 to Drywell outboard Isolation Bypass ValvetP> T4901-F016

d.

Combu~tible Gas Control System Suction Isolation Valves~> Inboard Torus: Division I: T4804-F602A Division II: T4804-F602B TRM Vol. I TRM 3.6-14 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (seconda) tuJ NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-l (Page 13 of 23) Primary Containment Isolation Valves FUNCTION

3.

Manual Isolation Valve11 (continued) PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (second8) (u)

d.

Combustible Gas Control System Suction I11olation Valvestp> (continued) Drywell: Di vision Divi11ion Outboard Torus: Division Division Drywall: Division Division I: II: I: II: I: II: T4804-F603A T4804-F603B T4804-F60 6A T4804-F606B T4804-F605A T4804-F605B

e. Combustible Gas Control System Return Isolation Valves 1P>

Inboard: Division I: T4804-F60lA Division II: T4804-F601B Outboard: Division I: T4804-F604A Division II: T4804-F604B TRM Vol. I TRM 3.6-14a NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

4.

Other Isolation Valves TABLE TR3.6.3-1 (Page 14 of 23) Primary Containment Isolation Valves FUNCTION

a. Main Feedvater Reverse Flow Check Valves B2100-F010A B2100-F010B B2100-F076A B2100-F076B

b.

RHR Heat Exchanger Relief ValvesC*I E:1100-FO0lA El100-F001B

c.

RHR Heat Exchanger outlet Line Relief Valvesl 0 1C*l El100-F025A El100-F025B

d.

RHR Pump Suction from Recirc Piping Reverse Flow Check Valve El100-F408

e.

RHR Shutdown Cooling Suction Relief Valve lo> C*l El100-F029

f.

RHR PUIIlp Torus Suction Relief Valves lol l*l E1100-F030A El100-F030B E1100-F030C El100-F030D

g.

Core Spray Loop Containment Reverse Flow Check Valves E2100-F006A E2100-F006B TRM Vol. I TRM 3.6-15 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (seconds) Cul NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-1 (Page 15 of 23) Primary Contai=ent Isolation Valves FUNCTION

4.

Other Isolation Valves (continued)

h.

Core Spray Loop Pump Suction Relief Valvesl 0> I*> E2100-E'032A E2100-F032B

i. Core Spray Loop Pump Diecharge Pressure Relief Valves 1*>

E2100-F011A E2100-F012A E2100-F011B E2100-F012B

j. Excese Flow Check Valves lq>

1. Jet Pump Instrumentation TRM Vol. I B21-F513A B21-E'513B B21-F513C B21-F513D B21-F514A B21-F514B B21-F514C B21-F514D B21-F515A B21-F515B B21-F515C B21-F515D B21-F515E B21-E'515F B21-F515G B21-F515H B21-E'515L TRM 3.6-16 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (eeconds) luJ NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued)

REV 123 07/20

TABLE TR3.6.3-l (Page 16 of 23) Primary Containment Isolation Valves FUNCTION

4.

Other Isolation Valves (continued)

j. Exce1'1s Flow Check Valves<ol (continued)

1. Jet Pump Instrumentation (continued)

B21-F515M B21-F515N B21-F515P B21-F515R B2l-F515S B21-F515T B21-F515U

2.

RPV Instrumentation TRM Vol. I a) Level: B21-F507 B21-F508 B21-F509 B21-F510 B21-F511 B21-F512 b) Pre1'!sure: B21-F506 B21-F508 B21-F516A B21-F516B B21-F516C B21-F517A B21-F517B B21-F517C B21-E'517D TRM 3.6-17 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME ( s econdtl) <uJ NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-l (Page 17 of 23) Primary Containment Isolation Valves FUNCTION

4.

other Isolation Valves (continued)

j. Excese Flow Check Valvee 141 (continued)

2.

RPV Iru!trumentation (continued)

3.

4.

5.

b) Pressure: (continued) N21-F539A N21-Ji'539B G33-F583 Core Spray instrumentation 11:21-FS00A E21-F500B HPCI Instrumentation E41-F500 E41-F501 E41-F502 E41-F503 RCIC Instrumentation E51-F503 E51-F504 E51-Ji'505 E51-F506

6. Recirculation Pump Instrumentation TRM Vol. I a)

Flow Loop A: B31-F503A B31-F504A B31-F505A B31-F506A TRM 3.6-18 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (seconds) C*l NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-1 (Page 18 of 23) Primary Containment Ieolation Valves FUNCTION

4.

other Ieolation Valvea (continued)

j. Exceas Flow Check Valves tq> (continued)

6. Recirculation Pump Instrumentation (continued)

TRM Vol. I a) Flow (continued) Loop B: B31-F503B B31-F504B B31-F505B B31-F506B b) Inlet Differential Pressure B31-F501A B31-F501B B31-F501C B31-F501D B31-F502A B31-F502B B31-F502C B31-F502D c) Pump Differential Pressure Pump A: B31-F510A B31-F511A Pump B: B31-F510B B31-F511B d) Seal Cavity Pressure Pump A, i1 Seal: B31-F516A Pump A, !2 Seal: B31-F515A Pump B, u Seal: B31-F516B Pump B, i2 Seal: B31-F515B TRM 3.6-19 PCIVs TR 3.6.3 \\ MAXIMUM ISOLATION TIME (seconds) tu> NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07 /20

TABLE TR3.6.3-1 (Page 19 of 23) Prilnary Containment Isolation Valves E'UNCTION

4.

other Isolation Valves (continued)

j. Excess Flow Check Valves 1V(continued)

6. Recirculation Pump InBtrumentation (continued) e)

Pumps A and B Suction Pressure B31-F512A B31-F512B

7.

Main Steam Flow Instrumentation TRM Vol. I Line A: B21-F501A B21-F502A B21-F503A B21-F504A Line B: B21-F501B B21-F502B B21-F503B B21-F504B Line C: B21-F501C B21-F502C B21-F503C B21-F504C Line D: B21-F501D B21-F502D B21-F503D B21-F504D TRM 3.6-20 PCIVs TR 3.6.3 MAXIMOM ISOLATION TIME (seconds) lul NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-1 (Page 20 of 23) Primary Containment Isolation Valves FUNCTION

4.

Other Isolation Valves (continued)

k.

HPCI Turbine Exhaust Drain Pot Drain to Suppres11ion Chamber Rever11e Stop Check ValvelaJ <*> E4150-F022

l. RCIC Turbine Exhaust Line Isolation Check Valvelal l*l E5150-F001

m.

HPCI Turbine Exhaust line Isolation Valve<*><*> E4150-E'021

n.

RCIC Barometric Condenser Vacuum Pump Diiicharge Stop Check Valve lml <*> E5150-F002

o.

Combustible Gas Control System Return Line Relief Valves Division I: T4804-F016A Division II: T4804-F016B

p.

Suppression Pool to Reactor Building Check Valves T2300-F450A T2300-F450B

q.

CRD Insert and Withdrawal Valves lnl lql The following valve identifiers are common to all HCUs and are sub-components under each HCU PIS number. HCU PIS numbers are Cl103-D001 through C1103-D185. Cll-F120 Cll-F121 Cll-F122 Cll-F123

r.

Standby Liquid Control Reverse Flow Check Valves Inboard: C4100-F007 Outboard: C4100-F006 TRM Vol. I TRM 3.6-21 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (seconds) Cul NA NA NA NA NA NA NA NA NA NA NA NA NA NA (continued) REV 123 07/20

TABLE TR3.6.3-l (Page 21 of 23) Primary Containment Isolation Valves FUNCTION

4.

Other IBolation Valves (continued)

s.

EECW Supply to Drywell Rquipment Check ValveB Divieion I: P4400-F282A Division II: P4400-F282B

t. Control Rod Drive System Insert and Withdrawal Lineslql The following valve identifiers are common to all HCUs and sub-components under each HCU PIS number.

HCU PIS numbers are C1103-D001 through Cll03-D185. Cll-FllS Cll-Fl38

u. Control Rod Drive Scram Diecharge Volume C1100-F010 Cll00-F0ll Cl100-F180 C1100-F181 PCIVs TR 3.6.3 MAXIMUM ISOLATION TIME (seconds) (ul NA NA NA NA NA NA NA NA (a)

The following is a summary of the parameters which will automatically actuate the Primary Containment Isolation Valve Groups. The instrumentation aseociated with these parameters is described in Technical Specification LCO 3.3.6.1.

1.

Group 1 - Main Steam System Reactor Veesel Low Water Level - Level 1 Main Steam Line Flow - High Main Steam Line Tunnel Temperature - High Main Steam Line Preesure - Low Condenser Pressure - High Turbine Building Area Temperature - High

2.

Group 2 - Reactor Water Sample System Reactor Veseel Low Water Level - Level 2 Drywell Pressure - High Main Steam Line Radiation - High

3.

Group 3 - Residual Heat Removal (RHR) System Reactor Veeeel Low Water Level - Level 1 Drywell Pressure - High

4.

Group 4 - Reeidual Heat Removal Shutdown Cooling: Reactor Vessel Low Water Level - Level 3 Reactor Veesel Pressure - High, Shutdown Cooling TRM Vol. I TRM 3.6-22 and Head Spray Interlock (continued) REV 123 07/20

TABLE TR3.6.3-1 (Page 22 of 23) Primary Containment Isolation Valves

5.

Group 5 - Core Spray System Reactor Veesel Low Water Level - Level 1 Drywell Pressure - High

6.

Group 6 - High Pressure Coolant Injection (HPCI) System

7.

8.

9.

HPCI Steam Line Flow - High HPCI Steam Supply Pressure - Low HPCI Turbine Exhaust Diaphragm Preesure - High HPCI Equipment Room Temperature - High Group 7 - High Pressure Coolant Injection (HPCI) Vacuum Breakers Drywell Pressure - High with simultaneous HPCI Steam Supply Pressure - Low Group 8 - Reactor Core Isolation Cooling (RCIC) System RCIC Steam Line Flow - High RCIC Steam Supply Pressure - Low RCIC Turbine Exhauet Diaphragm Pressure - High RCIC Equipment Room Temperature - High Group 9 - Reactor Core Ieolation Cooling (RCIC) Vacuum Breakers Drywall Pressure - High with simultaneous RCIC Steam Supply Pressure - Low

10. Group 10 - Reactor Water Cleanup (RWCU) System (Inboard)

RWCU Differential Flow - High RWCU Area Temperature - High RWCU Area Ventilation Differential Temperature - High Reactor Vessel Low Water Level - Level 2

11. Group 11-Reactor Water Cleanup (RWCU) System (outboard)

SLCS Initiation (not a containment isolation eignal) RWCU Differential Flow - High RWCU Area Temperature - High RWCU Area Ventilation Differential Temperature - High Reactor Vessel Low Water Level - Level 2

12. Group 12 - Torus Water Management System (TWMS)

Reactor Vessel Low Water Level - Level 2 Drywell Pressure - High 13. Group 13 - Drywall Sumps Reactor Vessel Low Water Level - Level 3 Drywell Pressure - High

14. Group 14 - Drywall and Suppression Pool Ventilation System Reactor Vessel Low Water Level - Level 2 Drywell Preesure - High

15. Group 15 - Transversing In-Core (TIP) Syetem PCIVs TR 3.6.3 NOTE:

Either of these signals initiate TIP withdrawal which resulte in automatic closure of the TIP Ball Valves when the TIP probe has entered the shield cask. Reactor Vessel Low Water Level - Level 3 Drywell Preseure - High

16. Group 16 - Nitrogen Inerting System Reactor Vessel Low Water Level - Level 2 Drywall Preeeure - High TRM Vol. I TRM 3.6-23 (continued)

REV 123 07 /20

TABLE TR3.6.3-1 (Page 23 of 23) Primary Containment Isolation Valves PCIVs TR 3.6.3

17. Group 17 - Recirculation Pump Syatem and Primary Containment Radiation Monitoring System Reactor Vessel Low Water Level - Level 2 Drywell Pressure - High

18. Group 18 - Primary Containment Pneumatic Supply System Reactor Vessel Low Water Level - Level 2 Drywall Pre~sure - High (b)

These valves are hydrostatically leak tested. (c) Also closes automatically as a result of ToruB Room Floor Drain Sump Level - High - High and Drywall Floor Drain Sump Level - High - High. (d) These valves may be closed remotely from one of the following locations:

1) control room.

2) their respective local panels.

(e) Will automatically reposition as a result of the actuation of the LPCI Loop Selection Logic. (f) Will automatically close when the correaponding RHR loop flow is greater than approxilllately 5900 gpm. (g) Will automatically close when the corresponding core spray loop flow is greater than approximately 2200 gpm. (h) Will automatically close when a) HPCI Turbine Steam Stop Valve E4100-F067 close~ or b) HPCI Turbine Steam Supply Iaolation Valve E4150-F00l_closes. {i) Will automatically close as a result of the condition li~ted in Note (h), above, as well aa when HPCI flow is greater than 1200 gpm. (j) Will automatically close when a) RCIC Turbine Steam Stop Valve E5150-F045 closes orb) RCIC Turbine Governor Trip and Throttle Valve E5150-F059 closes. (k) Will automatically close as a result of the conditions listed in Note (j) above, as well as when RCIC flow is greater than 130 gpm. (1) These valves are actuated by remote manual key-locked switche~ and will cut the TIP cable and aeal off the TIP guide tube when actuated. These valve~ are aquib-fired. (m) May be closed remotely as a secondary actuation mode to reverse flow. (n) Valves realign automatically on a reactor scram aignal. (o) Thermal relief valves. (p) Locked closed. (q) Not subject to Type C leakage tests. (r) Hydrostatically tested in accordance with Technical Specification SR 3.4.5.1 in lieu of the requirements of Technical Specifications 3.6.1.1 and 3.6.1.3. (s) These Containment Isolation Valve(s) are not Type C tested. Containment by-pass leakage is prevented since the line terminatea below the minimum water level in the suppression chamber and the system is a closed syatem outside Primary Containment. (t) Valve closea on low reactor water level signal (Level 1) or high drywell pressure signal. (u) Includes valve stroke time only. License Amendment No. 143, approved by the NRC on July 12, 2001, reviaed the Licenaing Baais to allow a 121-second delay in the timing of the release of fission products ~allowing a design-basis accident. Therefore, most Class B valves' maximum isolation time may be changed to 108 seconda using the 10 CFR 50.59 process. See letter NRC-00-0066 and Amendment No. 143 for more details. TRM Vol. I TRM 3.6-24 REV 123 07/20

Electrical Equipment Protective Devices Motor-Operated Valves Thermal Overload Protection TR 3.8.4 TABLE TR3.8.4-l (Page 6 of 6) Motor-Operated Valves Thermal Overload Protection SYSTEM AFFECTED

14.

Containment Atmosphere Control System

15.

Primary Containment Pneumatic Supply System TRM Vol. I TRM 3. 8-11 VALVE NUMBER T4803-F601 T4803-F602 T4901-F601 T4901-F602 REV 123 07/20

ENCLOSURE 4 TO NRC-21-0002 Summary of Revisions to Technical Specifications Bases and Revised Pages to NRC-21-0002 Page 1 Revision 80 11/13/2019 Revision 81 12/20/2019 Revision 82 01/03/2020 Revision 83 0'JJ0?/2020 Revision 84 04/13/2020 Summary of Technical Specification Bases (TSB) Changes Revised Section B 3.3.1.1 to implement the Technical Specifications Task Force (TSTF) TSTF-573-T clarification of Reactor Protection System logic description of main steam isolation valve and turbine stop valve closure functions. Revised Section B 3.3.1.1 references to include the current GE Simplified Stability Solution licensing topical report. Revised Sections B 2.1.1, B 2.1.1.2, and B 3.2.2 to implement License Amendment 214 to Revise Technical Specifications to Adopt TSTF-564, "Safety Limit MCPR." Revised Section B 3.5.1 references to reflect newer design calculations. Revised Section B 3.3.5.3 to implement License Amendment 215 to Revise Technical Specification 3.3.5.3, Reactor Pressure Vessel Water Inventory Control Instrumentation. Revised Section B 3.3.5.1 to correct an error in the description of the number of channels that results in loss of function for riser differential pressure - high. Revised Section B 3.3.6.1 to clarify the Traversing In-Core Probe system isolation logic. Revised Sections B 32.1, B 3.3.5.1, and B 3.4.1 to replace outdated references with newer references applicable to GNF3 fuel. Revised Section B 3.8.4 references to correct the year of an applicable IEEE standard. The following pages are information only copies of the revised TSB pages for the above revisions.

BASES RPS Instrwnentation B 3.3.1.1 APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

5. Hain Steam Isolation Valve-Closure FERMI - UNIT 2 MSIV closure results in loss of the main turbine and the*

condenser as a heat sink for the nuclear steam supply system and indicates a need to shut down the reactor to reduce heat generation. Therefore, a reactor scram is initiated on a Main Steam Isolation Valve-Closure signal before the MSIVs are COJTl)letely closed in anticipation of the complete loss of the nonnal heat sink and subsequent overpressurization transient. However, for the overpressurization protection analysis of Reference 4, the Average Power Range Monitor Neutron Flux-Upscale Function, along with the SRVs. limits the peak RPV pressure to less than the ASHE Code limits. That is, the direct scram on position switches for MSIV closure events is not assU11ed in the overpressurization analysis. The reactor scram reduces the aroount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. MSIV closure signals are initiated from position switches located on each of the eight MSIVs. Each HSIV has one position switch that provides the originating sensor for two separate channels; one inputs to RPS trip system A while the other inputs to RPS trip system B. Each inboard and outboard MSIV inputs to a main steam line channel in each trip system, and each of the two trip logics within each RPS trip system receive parallel inputs from two of the four main steam lines. Thus. each RPS trip system receives an input from eight Main Steam Isolation Valve-Closure channels, each channel consisting of one position switch, which is shared with one other channel. The logic for the Hain Steam Isolation Valve-Closure Function is arranged such that either the inboard or outboard valve on both of the main steam lines i.n one of the two trip 1 ogi cs in. each RPS trip system must close in order for a scram to occur. The Main Steam Isolation Valve-Closure Allowable Value*is specified to ens_ure that a scram occurs prior to a significant reduction in steam flow, thereby reducing the 'severity of the subsequent pressure.transient. Sixteen channels of the Hain-Steam Isolation Valve-Closure Function, with eight channels. in.each trip system, are required to be OPERABLE to ensure that no single instrument B 3.3.1.1-14 Revision 80

BASES RPS Instrumentation 83.3.1.1 APPLICABLE SAFm ANALYSIS, LCO, and APPLICABILilY (continued) FERMI - UNIT 2 failure will preclude the scram from this Function on a valid signal. This Function is only required in MODE 1 since, with the HSIVs open and the heat generation rate high, a pressurization transient can occur if the HSIVs close. In MODE 2. the MSIV closure trip is automatically bypassed, and the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection.

6. Deleted B 3. 3.1. 1-15 Revision 80

BASES RPS Instrumentation B 3.3.1.1 APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued) FERMI - UNIT 2 signal from a level switch and a level transmitter to each RPS logic channel. The level measurement instrumentation satisfies the recommendations of Reference 8. The Allowable Value is chosen low enough to ensure that there is sufficient volume in the SDV to accomnxxfate the water from a full scram. Four channels of each type of Scram Discharge Volume Water Level--Higr Function, with two channels of each type in each trip system, arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from these Functions on a valid signal. These Functions are required in MODES 1 and 2, and in MODE 5 with any control rod withdrawn-from a core cell :containing one or more fuel assemblies. since these are the MODES and other specified conditions when control' rods are withdrawn. At all other times, this Function may be bypassed.

9. Turbine Stop Valve-Closure Closure of the TSVs results in the loss of a heat sink that produces reactor pressure, neutron flux. and heat flux transients that must be limited. Therefore,. a reactor scram is initiated at the start of TSV closure in anticipation of the transients that would result from the closure of these valves.

The Turbine Stop Valve-Closure Function is the primary scram signal for the turbine trip event analyzed in Reference 7. For this event, the reactor scram reduces the a100unt of energy required to be absorbed and ensures that the MCPR SL is not exceeded. Turbine Stop Valve-Closure signals are initiated from position switches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of the two switches provides input to RPS trip system A; the other, to RPS trip system B. Each of the two trip-logics within each RPS trip system receives parallel inputs from two of the four turbine stop valves. Thus, each RPS trip system receives an input.from four Turbin~ Stop Valve-Closure channels, each consisting of one pos*ition switch. The logic for the Turbine Stop Valve-Closure Function is such that two TSVs in one of the two trip logics in each RPS trip system must close to produce a scram. This Function must be enabled at THERMAL POWER~ 29.53/4 RTP. r B 3.3.1.1-17 Revision 80 I*

BASES RPS Instrumentation B 3.3.1.1 APPLICABLE*SAFETY ANALYSIS. LCO, and APPLICABILITY (continued) FERMI - UNIT 2 This is oormally accomplished automatically by pressure transmitters sensing turbine first stage pressure of~ 161.9 psig. If the turbine bypass valves are open' with THERMAL PMR ~ 29.5.t RTP, turbine first stage pressure 111.1st be sufficient to _ensure the Function is enabled. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If the bypass' channel is placed in the nonbypass condition, the.Turbine Stop Valve-Closure Function is considered OPERABLE. The Turbine Stop Valve-Closure Allowable Value is selected to be high enough to detect iJ11J1inent TSV closure, thereby reducing the severity of the subsequent pressure transient. Eight channels of Turbine Stop Valve-Closure Function. with four channels.in each trip system, are required to be OPERABLE to ensure that no single instrwnent failure will preclude a scram from this Function on a valid signal., This Function is required, consistent with analysis assunptions, whenever THERMAL POWER is ~ 29. 5.t RTP. This Funct-i on is not required when THERMAL POWER is< 29.5.t RTP since the 1Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor Neutron Flux-Upscale Functions are adequate to maintain the necessary safety,margins.

10. Turbine Control Valve Fast Closure Fast closure of the TCVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure Function is the primary scram signal for the generator load rejection event analyzed in Reference 7.

For this event, the*reactor scram reduces the amount of energy req1,.1i.red to be absorbed and ensures that the HCPR SL is not exceeded. 1 Turbine Control Valve Fast Closure signals are -initiated by the de-energization of the solenoid dump valv~ at each control valve. Redundant relay signals are provided to each RPS logic channel such that fast closure of one control valve in each RPS trip system will initiate a scram. This Function must be enabled at THERMAL POWER~ 29.5.t RTP. This is normally accomplished automatically by pressure transmitters sensing turbine-first stage pressure of ~ 161.9 psig. If the turbine bypass valves are open with B 3.3.1.1-18 Revision 80 I*

BASES RPS Instrwnentation B 3.3.1.1 ACTIONS (continued) FERMI - UNIT-2 Alternately, 'if it is not desired to place the inoperable channels (or one trip system) in trip (e.g., as in the case where placing the inoperable channel or associated trip system in trip would result in a scram), Condition D must be entered and its Required Action taken. As noted, Condition Bis not applicable.for APRH Functions 2.a, 2.b, 2.c, 2.d, and 2.f. Inoperab1lity of an APRM channel affects both trip systems and is not associated with a specific trip system, as are the APRH 2-out-of-4 voter and other non~APRM channels for whic~ Condition B applies. For an inoperable APRM channel, Required Action A.1 must be satisfied, and is the only action (other than restoring OPERABILITY) that will restore capability to accoounodate a single failure. Inoperability of a Function in more than one required APRH channel results in loss of trip capability for that function and entry into Condition C, as well as entry into Condition A for each channel. Because.Conditions A and C provide Required Actions that are appropriate for the inoperability of APRH Functions 2.a, 2.b, 2.c, 2.d, and 2.f, and these Functions are not associated with specific trip systems as are the APRM 2-out-of-4 voter and other non-APRH channels, Condition B does not apply. I C.l Required Action C.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same trip system for the same Function result in the Function not maintaining RPS trip capability. A Function is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (or the associated trip system is in trip),,such that both trip systems will generate a trip signal from the given Function on a valid signal. For the typical Function with one-out-of-two taken twice logic and the IRH and APRM Functions, this would require both trip systems to have one -channel OPERABLE or in trip (or the associated trip system in trip). for Function 5 (Main Steam Isolation Valve--{;losure), maintaining RPS trip capability would require at least one trip system logic in both trip systems to have each channel associated with the HSIVs in two main steam lines (at least three different main steam lines total for both trip systems) OPERABLE or in trip (or the associatecl trip systan in trip). B 3.3.1.1-23 Rev,sion 80

BASES RPS InstrU111entation B3.3.1.1 ACTIONS (continued) FERMI - UNIT 2 For Function 9 (Turbine Stop Valve-Closure), maintaining RPS trip capability would require at least one trip system

• logic in both trip systems to have two channels (at least three different turbine stop valves total for both trip systems) OPERABLE or in trip (or the associated trip system in trip).

The Completion Time is intended to allow the operator time to evaluate, and repair or place in trip any discovered inoperabilities that result in a loss of RPS trip OPERABILITY. The 1 hour Completion Time is acceptable. because it minimizes risk while allowing time for restoration or tripping of channels. D.1 Required Action D.1 directs entry into the appropriate Condition referenced in Table 3.3.1.1-1. The applicable Condition specified in the Table is Function and MODE or other specified condition dependent and may change as the. Required Action of a previous Condition is completed. Each time an inoperable channel has not met any Required Action o*f Condition A, B, or C and the associated Completion Time has expired, Condition D will be entered for that channel and provides for transfer to the appropriate subsequent Condition. E.l, F.l, G.l, H.1, H.2, and K.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MOOE or other specified condition in which the LCO does not apply. Alternately, for Condition H, the MSLs may be isolated (Required Action H.1), and, if allowed (i.e., plant safety analysis and minimal steam flow in MODE 2 allows operation with the MSLs isolated), operation with the MSLs isolated may continue. Isolating the HSLs conservatively accomplishes the safety function of the inoperable channel. The allowe<;I Completion Times are reasonable, based on operating experience, to reach the specified condition from full power conditions in an orderly manner and without challenging plant systems. In addition,* the Completion Time of Required Actions E.1 and K.1 are consistent with the Completion Time provided in LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)." B 3.3.1.1-24 Revision 80

BASES REFERENCES (continued)

16.

17.

18.

19.

20.

21.

FERMI - UNIT 2 RPS Instrwnentation B 3.3.1.1 NEDE-33766P-A, "GEH Simplified Stability Solution (GS3)," Revision 1, March 2015. NEDC-32410P-A, Supplement 1, NNuclear Measurement* Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function." November 1997. Letter, L.A. England (BWROG) to M. J. Virgilio, "BWR Owners' Group Guidelines for Stability Interim Corrective Action," June 6, 1994. NRC Generic Letter 94-02, "Long-Term Solutions and Upgrade of Interim Operating Recommendations for Thenual Hydraulic Instabilities in Boiling Water Reactors," July 1994. BWROG Letter 96113, Kevin P. Donovan (BWRffi) to L. E. Phillips (NRC), "Guidelines for Stability Option III 'Enable Region' (TAC M92882)," dated September 17, 1996. NED0-32291-A Supplement 1, "System Analysis for the Elimination of Selected Response Time Testing Requirements," dated October 1999. B 3.3.1.1-37 Revision 80

Reactor Core SLs B 2.1.1 B 2.0 SAFE1Y LIMITS (SLs) B 2.1.1 Reactor Core SLs BASES BACKGROUND FERMI - UNIT 2 GOC 10 (Ref. 1) requires, and SLs ensure, that specified acceptable fuel design limits are not exceeded during normal operation, including the effects of anticipated operational occurrences (AOOs). The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated. Because fuel damage is not directly observable, a stepback approach is used to establish an SL, such that the MCPR is not less than the limit specified in Specification 2.1.1.2. HCPR greater than the specifiep limit represents a conservative margin relative to the conditions required to maintain fuel cladding integrity. The fuel cladding is one of the physical barriers that separate the radioactive materials from the environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking. Although some corrosion or use related cracking may occur during the life of the cladding, fission product migration from this source is incrementally ClWlative and continuously measurable. Fuel cladding perforations, however, can result from therma 1 stresses, which occur from reactor opera ti on significantly above design conditions. While fission product migration from cladding-perforation is just as measurable as that from use related cracking, the thermally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross, rather than incremental, cladding deterioration. Therefore, the fuel cladding SL is defined with a margin to the conditions that would produce onset of transition boiling (i.e., MCPR = 1.00). These conditions represent a significant depart~re from the condition intended by design for planned operation. This is accomplished by having a Safety Limit MinimllB Critical Power Ratio (SLMCPR) design basis, referred to as SLMCPR9s!9s, which corresponds to a 95% probability at a 95l confidence level (the 95/95 HCPR criterion) that transition boiling will not occur. Operation above the boundary of the nucleate boiling regime could result in excessive cladding temperature because of the onset of transition boiling and the resultant sharp B 2.1.1-1 Revision 81

BASES Reactor Core Sls B 2.

1.1 BACKGROUND

(continued) reduction in heat transfer coefficient. Inside the steam film, high cladding temperatures are reached, and a cladding-water (zirconium-water) reaction may take place. This chemical reaction results in oxidation of the fuel cladding to a structurally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled release of activity to the reactor coolant. APPLICABLE The fuel cladding must not sustain damage as a result of SAFETY ANALYSES normal operation and AOOs. The Technical Specification SL is set generically on a fuel product HCPR correlation basis as the MCPR which corresponds to a 95% probability at a 95% confidence level that transition boiling will not occur, FERMI

• UNIT 2 referred to as SLMCP~.

The Reactor Protection System setpoi nts ( LCO 3. 3.1.1, "Reactor Protection System (RPS) Instrumentation"), in combination with the other LCOs, are designed to prevent any anticipated combination of transient conditions for Reactor Coolant System water level, pressure, and THERMAL POWER level that would result in reaching the MCPR safety limit. 2.1.1_.1 Fuel Cladding Integrity General Electric Company (GE) critical power correlations are applicable for all critical power calculations at-pressures ~ 785 psi g and core flows ~ 10.%' of rated fl ow. For operation at low pressures or low flows, another basis is used, as follows: Since the pressure drop in the bypass region is essentially all elevation head, the core pressure drop at low power and flows will always be> 4.5 psi. Analyses (Ref. 2) show that with a bundle flow of 28 x 103 lb/hr, bundle pressure drop is nearly independent of bundle power and has a value of 3.5 psi. Thus, the bundle flow with a 4.5 psi driving head will be > 28 x 103 lb/hr. Full seal e All.AS test data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly critical power at this flow is approximately 3.35 MWt. With the design peaking factors, this corresponds to a TI--lERMAL POWER> 501/4 RTP. Thus, a THERMAL POWER limit of 25.%' RTP for reactor pressure< 785 psig is conservative~ B 2.1.1-2 Revision 81

BASES Reactor Core Sls B2.1.1 APPLICABLE SAFETY ANALYSIS (continued) 2.Ll.2 HCPR FERMI - UNIT 2 The MCPR SL is set such that no significant fuel damage is calculated to occur if the limit is not violatE!d. Since the parameters that result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions that result in the onset of transition boiling have been used to 11ark the beginning of the region in which fuel damage could occur. Although it is recognized that the onset of transition boiling would not result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. The Technical Specification SL value is dependent on the fuel product line and the corresponding MCPR correlation, which is cycle independent. The value is 'based on the Critical Power Ratio (CPR) data statistics and a 95% probability with 953/4 confidence that rods are not susceptible to boiling transition, referred to as MCPR9s~s. ~ \\ The SL is based on GNF3 fuel. For cores with a single fuel product line, the Sl..HCPR95t95 is the MCPR95195 for the fuel type. For cores loaded with a mix of applicable fuel types, the SLMCPR9sm is based on the largest (1.e., most limiting) of the, MCPR values for the fuel product lines that are fresh or once-burnt at the start of the cycle. 2.1.1.3 Reactor Vessel Water Level During MODES 1 and 2 the reactor vessel water level is required to be above the top of the active fuel to provide core coo 1 i ng capability. With fuel in the reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due to the effect of decay heat. If the water level should drop below the top of the active irradiated fuel during this period, the ability to reoove decay heat is reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the B 2.1.1-3 Revision 81 _j

MCPR B 3.2.2 B 3.2 POWER DISJRIBUTION LIMITS B 3.2.2 MINIMUM CRITICAL POWER RATIO (HCPR) BASES BACKGROUND APPLICABl£ SAFffi ANALYSES FERMI - UNIT 2 MCPR is a ratio of the fuel assembly power that would result in the onset of boiling transition to the actual fuel assembly power. The operating limit MCPR is established to ensure that no fuel damage results during anticipated operational occurren~s (AOOs), and that 99.93/4 of the fuel rods are not susceptible to boiling transition if the limit is not violated. Although fuel damage does not necessarily occur if a fuel rod actually experienced lx>iling transition (Ref. 1), the critical power at which lx>iling transition is calculated to occur has been adopted as a fuel design criterion. The onset of transition lx>iling is a phenomenon that is readily detected during the testing of variou~ fuel bundle designs. Based on these experimental data, correlations have been developed, to predict critical bundle power (i.e., the bundle power level at the onset of transitioD lx>iling) for a given set of plant parameters (e.g., reactor vessel pressure, flow, and subcooling). Because plant operating conditions and bundle power levels are monitored and determined relatively easily, 100nitoring the MCPR is a convenient way of ensuring that fuel failures due to inadequate cooling do not occur. The analytical methods and asslmlptions used in evaluating the AOOs to establish the operating limit MCPR are presented in References 2, 3, 4, 5, 6, 7, and 8. To ensure that the MCPR Safety Limit (SL) is not exceeded during any transient event that occurs with moderate frequency, limiting transients have been analyzed to determine the largest reduction in critical power ratio (CPR). The types of _ transients evaluated are loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the. largest change in CPR (ACPR). When the largest.A.CPR is combined with the SLHCPR99.9.l, the required operating limit MCPR i s obtained. MCPR99.9% is detennined to ensure 100re than 99.9% of the fuel rods in the core are not susceptible to lx>iling transition using a statistical toodel that combines all the uncertainties in operating parameters and the procedures used to calculate critical power. The probability of the B 3.2.2-1 Revision 81

BASES HCPR B 3.2.2 APPLICABLE SAFETY ANALYSES (continued) LCO FERMI - UNIT 2 occurrence of boiling transition is determined using the approved Critical Power correlations. Details of the MCPR99.9t calculation are given in Reference 2. Reference 2 also includes a tabulation of the uncertainties and the nominal values of the parameters used in the MCPR99.9t statistical analysis. The HCPR operating limits are derived from the HCP!w.9% value j ~ and the transient analysis, and are dependent on the operating core flow and power state (MCPRf and MCPRp, respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency (Refs. 6, 7, and 8). Flow dependent MCPR limits are detennined by steady state thermal hydraulic methods with key physics response inputs benchmarked using the three dimensional BWR simulator code (Ref. 9) to analyze slow flow runout transients. The operating limit is dependent on the rnaxinnnn recirculation scoop tube mechanical stop setting in the Recirculation Flow Control System. Power dependent MCPR limits (MCPRp) are detennined by approved transient analysis models (Refs. 10 and 11). Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which the turbine stop valve closure and turbine control valve fast closure scrams are bypassed, high and low fl ow MCPRo operating limits are provided for operating between 25% RTP and the previously mentioned bypass power level. Transients involving increase in pressure and power are sensitive to the size of the steam volume and the availability of this steam volume to aceornmodate the reactor steam production. Larger steam volumes and longer or earlier availability result in less severe pressure transients. Thus operation of the turbine generator bypass valves and the availability of the moisture separator reheater have an effect on the transient results. For this reason the COLR contains MCPR limits for when the turbine bypass valves and/or moisture separator reheater are out-of-service (refer to LCO 3.7.6, nThe Hain Turbine Bypass System and Moisture Separator Reheater*). The MCPR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). The MCPR operating limits specified in the COLR (MCPR99.9t value, MCPRt values, and MCPRi, values) are the result of the design basis transient analysis. The operating limit MCPR B 3.2.2-2 Revision 81

BASES LCO (continued) FERMI - UNIT 2 MCPR B 3.2.2 is determined by the larger of the MCPRt, and HCPRp limits, which are based on the MCPR99.!lt limit specified in the COLR. B 3.2.2-2a Revision 81

BASES RPV Water Inventory Control Instrumentation B 3.3.5.3 ACTIONS (continued) operator can take manual control o.f the plDIJJ) and the

• injection valve to inject water into the RPV.

Th~ C01J1Pletion Time of 1 hoµr is intend~ to allow tne operator time to evaluate any discovered inoperabilities and to place the channel in trip. D.1 If a manual initiation function is inoperable, the associated low pressure ECCS injection/spray subsystem may be incapable of performing the intended function, and must be declared inoperable innediately. With the Required Action and associated Completion Time of Condition C not met, the associated low pressure ECCS injection/spray subsystem may be incapable of performing the intended function, and must be declared inoperable ~innnediately;* ---- - SURVEILLANCE As noted in the beginning of the SRs, t~ SRs for each RPV ..:.REQUIREMOOS- _ -

• _water-: Inventor_y-Control -instrument. Ftmction are-*found in *the - -

SRs-collBilll of Table 3.3.5.3-1. FERMI,_

• UNIT 2

-The Surveillances are-modified by a Note-to indicate that when a channel is placed in an inoperable status solely for performance o"f required Survei 11 ances. entry into associated Conditions and Required Actions may be delayed for up to*6 hoµrs for F~nctions l.a and 2.a provided tn~ associated Function maintains ECCS initiation capability. Upon ~letion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to -OPERABLE status or*the applicable Coridit1on entered *and Required Actions

• taken. This Note is based on the reliability analysis (Ref.

6) *assumption of the average time required to perform channel surveillance. The analysis demonstrat~ that the 6 hour testing allowance does not significantly reduce the probability that the ECCS will init~ate when necessary.

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 -nonnally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is B 3'.3.5.3-7 Revision 82

BASES RPV Water Inventory Control Instrumentation B 3.3.5.3 SURVEILLANCE REQUIREMENTS (continued) FERMI - UNIT 2 based on the assumption that instrument channels monitoring the same*parameter should read approximately the same value. Significant deviations between the instrLDUent channels could be an indication of excessive*instrwnent 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 detennined by the plant staff, based on a conbination of the channel instrLUDeTit 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 fr~~nt, c~~ks of channels d4ring nonnal operattonal use of the displays associated with the channels required by the LCO. SR - 3::t 5.3:2°* and SR 3. 3-.5.3-.3 A CHANNEL FUNCTIONAL TEST is perfonned 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 perfonned by the verification of the change of state of a single contact of the re1ay. This clarifies what is an acceptable CHANNEL FlJNcrioNAL TEST of a relay. This is acceptable because a 11 of the other required contacts of the relay are verified by -- other Technical Specifications and non-Technical Specifi~ations*tests. - Any setpoint adjustment shall be consistent with the asslBllptions of the current plant specific setpoint methodology. The Surveillance*Frequency is controlled under the __ Surveillance F~q_~ency Control Progr~m. B 3.3.5.3-8 Revision 82

BASES REFERENCES FERMI - UNIT 2 RPV Water Inventory Control Instrumentation B 3.3.5.3

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 Hisaligrnnent 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.

NRG Bulletin 93-03; "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.

5.

Infonnation Notice 94-52, "Inadvertent Contairvnent Spray and Reactor Vessel Draindown at Millstone 1," July 1994. 6; NEDC--30936-P-A,-~BWR Owners' Group-Technical Specification Improvement Analyses for EGGS Actuation Instrumentation, Pc;irt 2," December 19eB. B 3.3.5.3-9 Revision 82

BASES EGGS-Operating B 3.5.1_ SURVEILLANCE REQUIREMENTS (continued) FERMI - UNIT 2 SR 3.5.1.8, SR 3.5.1.9, and SR 3.5.1.10 The perfonnance requirements of the low pressure EGGS pumps are determined through application of the 10 GFR 50, Appendix K criteria (Ref. 8). This periodic Surveillanc;e is perfonned (in accordance with the ASME Code, Section XI, requirements for the EGGS pumps) to verify that the ECCS pumps will develop the flow rates required by the respective analyses. The low pressure EGGS pLHTip flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of Reference 10. The pump flow rates (for Core Spray, 2 pumps in parallel operation) are verified against a system head equivalent to the RPV pressure expected during a LOCA. The total system pllJll) outlet pressure is adequate to overcome the elevation head pr~sure between the pump suction and the vessel discharge, the piping friction losses, and RPV pressure present during a LOCA. These values may be established during preoperational testing. Actual testing is performed via the test flow path against test line pressures established in References 18 and 19. The fl ow tests for the HPCI System are performed at two different pressure ranges such that system capability to provide rat~. flow is tested at both the higher and_ lower operating ranges of the system. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPGI System diverts steam flow. Reactor steam pressure must be~ 945 psig to perform SR 3.5.1.9 and ~ 165 psi g to perform SR 3. 5.1.10. Adequate steam fl ow is represented by main turbine generator on line or turbine bypass valves open at least 153/4 in auto-pressure control. Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these tests. Reactor startup is allowed prior to performing the low pressure Surveillance test because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance test is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure test has been satisfactorily completed and there is no indication or reason to believe that HPGI is inoperable. B 3.5.1-16 Revision 82

BASES REFERENCES FERMI

• UNIT 2

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

UFSAR, Section 6.3.2.2.3. UFSAR, Section 6.3.2.2.4. UFSAR, Section 6.3.2.2.1. UFSAR, Section 6.3.2.2.2. UFSAR, Section 15.2.7. UFSAA, Section 15.6.4. UFSAR, Section 15.6.5. 10 CFR 50, Appendix K. UFSAR, Section 6.3.3. 10 CFR 50.46. UFSAR, Section 6.3.3.3. ECCS-Operating B 3.5.1

12.

Memorandum from R.L. Baer (NRC) to V. Stello, Jr. (NRC), "Recormnended Interim Revisions to LCOs for ECCS Components," December 1, 1975.

13.

NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Infonned Modification to Selected Required End States for BWR Plants, Decerrver 2002.

14.

UFSAR, Table 6.3-6.

15.

UFSAR, Section 5.2.2.2.3.

16.

Technical Require11ents Manual.

17.

NED0-32291, "System Analyses for Elimination of Selected Response Time Testing Requirements, a January 1994; and Fenni-2 SER for Amendment 111, dated April 18, 1997.

18.

DC-0230 Vol I, Hydraulic Calculations for the Core Spray System.

19.

DC-0367 Vol I, Hydraulic Calculations for the RHR System. B 3.5.1-21 Revis1on 82

BASES ECCS Instrumentation B 3.3.5.1 ACTIONS (continued) FERMI - UNIT 2 for the inoperability, restore capability to acco111Tiodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition G must be entered and its Required Action taken. C.l and C.2 Required Action C.l is intended to ensure that appropriate actions are taken if multiple, inoperable channels within the same Function result in redundant automatic initiation capability being lost for the feature(s). Required Action C.l features would be those that are initiated by Functions 1.c, 2.c, 2.e, and 2.f (i.e., low pressure ECCS). Redundant automatic initiation capability is lost if either (a) two Function 1.c channels are inoperable in the same trip system, (b) two Function 2.c channels are inoperable in the same trip system, (c) two Function 2.e channels are inoperable in the same trip system, or (d) two Function 2.f channels are inoperable in the same trip system. In this situation (loss of redundant automatic initiation capability), the 24 hour allowance of Required Action C.2 is not appropriate and the feature(s) associated with the inoperable channels must be declared inoperable within 1 hour. Since each inoperable channel would have Required Action C.l applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system to be declared inoperable. However, since channels for both low pressure ECCS subsystems are inoperable (e.g., both CS subsystems), and the Completion Times started concurrently for the channels in both subsystems, this results in the affected portions in both subsystems being concurrently declared inoperable. For Functions 1.c, 2.c, 2.e, and 2.f, the affected portions are the associated low pressure ECCS pumps. B 3.3.5.1-25 Revision 83

BASES REFERENCES FERMI - UNIT 2 ~~ffi B 3.2.1

1.

NED0-24011-P-A nGeneral Electric Standard Application for Reactor Fuel* (latest approved version).

2.

UFSAR, Chapter 4.

3.

UFSAR, Chapter 6.

4.

UFSAR, Chapter 15.

5.

MDE-56-0386, "Fermi 2 Single Loop Operation Analysis, a April 1987, and NEDC-32313-P, "Enrico Fenni Energy Center Unit 2 Single Loop Operation," September 1994.

6.

NEDC-31515, Rev. 1, *Maximum Extended Load Line Limit and Feedwater Heater Out-of-Service Analysis for Enrico Fenni Atomic Power Plant Unit 2," August 1989.

7.

NEDC-31843, aMaximlDll Extended Operating Domain Analysis for Detroit Edison Company Enrico Fenni Energy Center Unit 2," July 1990.

8.

NE00-30130-A, "Steady State Nuclear Methods," May 1985.

9.

TRACG Application for Anticipated Operational Occurrences (ADO) Transient Analyses, NEDE-32906P-A, Revision 3, September 2006.

10.

TRVEND NEDC 33919P, "Fermi 2 TRACG ECCS, Loss-of-Coolant Accident (LOCA) Analysis," January 2020.

11.

Migration to TRACG04 / PANACll from TRACG02 / PANAClO for TRACG /JOO and ATWS Overpressure Transients, NEDE-32906P Supplement 3-A, Rev.. 1, April 2010. B 3.2.1-4 Revision 84

BASES ECCS Instr1.UJ1entation B 3.3.5.1 SURVEILLANCE REQUIREMEITTS (continued) SR 3.3.5.

1.4 REFERENCES

FERMI - UNIT 2 A CHANNEL CALIBRATION is a complete check of the instr1.UJ1ent 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 instr1.UJ1ent drifts between successive calibrations consistent with the plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.5.1.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing perfonned in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to complete testing of the assumed safety functioo. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

1.

UFSAR, Section 6.3.

2.

UFSAR, Chapter 15.

3.

TRVEND NEDC 33919P, "Fermi 2 TRACG ECCS, Loss-of-Coolant Accident (LOCA) Analysis," January 2020.

4.

NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988. B 3.3.5.1-33 Revision 84

\\. BASES Primary Containment Isolation Instrumentation B 3.3.

6.1 BACKGROUND

(continued) APPLICABLE SAFffi ANALYSES, LCO, and APPLICABILITY FERMI - UNIT 2

6. Shutdown Cooling System Isolation The Reactor Vessel Water Level-Low, Level 3 Function receives input from four rea~tor vessel water level channels. The outputs from the reactor vessel water level channels are connected to two two-out-of-two trip systems.

The Reactor Vessel Pressure-High Function receives input from two channels, with each channel in one trip system using a one-out-of-one logic. Each of the two trip systems is connected to one of the two valves on each shutdown cooling penetration. Shutdown Cooling System Isolation Functions isolate the shutdown cooling isolation valves.

7. Traversing Incore Probe System Isolation The _Reactor Vessel Water Level -Low, Level 3 Function receives input from two reactor vessel water level channels.

The outputs from the reactor vessel water.level channels are connected into one two-out-of-two logic trip system. The Drywell Pressure-High Isolation Function receives input from two drywell pressure channels. The outputs from the drywell pressure channels are connected into one two-out-of-two logic trip system. The outputs from the reactor vessel water level channels are in series with the drywell pressure channels such that the Functions collectively act as a one-out-of-two taken twice ~ogic trip system. When either Isolation Function actuates, or a combination of 1* both Isolation Functions results in actuation, the TIP drive mechanisms will withdraw the TIPs, if inserted, and close the inboard TIP System isolation ball valves when the TIPs are fully withdrawn. The outboard TIP System isolation valves are manual shear valves. TIP System Isolation Functions isolate the TIP inboard isolation ball valves. The isolation signals generated by the primary containment i'solation instrumentation are implicitly assumed in the safety analyses o.f References 1 and 2 to initiate closure of valves to limit offsite doses. Refer to LCO 3.6.1.3, APrimary Containment Isolation Valves (PCIVs)," Applicable B 3.3.6.1-5 Revision 84

BASES Primary Containment Isolation Instrumentation B 3.3.6.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLI~ILITY (continued) FERMI - UNIT 2 Safety Analyses Bases for more detail of the safety analyses. Primary containment isolation instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion. The OPERABILITY of the primary containment instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.6.1-1. Each Function must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibr,ated consistent with applicable setpoint methodology assumptions. Each channel must also respond within its assumed response time, where appropriate. Allowable Values are specified for each Primary Containment Isolation Function specified in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS or between successive verifications of trip unit setpoints. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. Trip setpoints are those predetennined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from* the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoi nts are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for. B 3.3.6.1-6 Revision 84

BASES Primary Containment Isolation Instrumentation B 3.3.6.1 ACTIONS (continued) FERMI - UNIT 2 channels within the same Function result in redundant automatic isolation capability being lost for the associated penetration flow path(s). The HSL Isolation Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that both trip systems will generate a trip signal from the given Function on a valid signal. The other isolation functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two PCIVs in the associated penetration flow path can receive an isolation signal from the given Function. For Functions 1.a, 1.b, and l.d, this would require both trip systems to have one channel OPERABLE or in trip. For Function 1.c, this would require both trip systems to have one channel, associated with each HSL, OPERABLE or in trip. For Functions 1.e and l.g, each Function consists of channels that monitor several locations within a given area (e.g., different locations within the main steam tunnel area). Therefore, this would require both trip systems to have one channel per location OPERABLE or in trip. For Functions 2.a, 2.b, 2.c, 2.d, 3.b, 3.c, 4.b, 4.c, 5.e, and 6.b, this would require one trip system to have two channels, each OPERABLE or in trip. For Functions 3.a, 3.d, 4.a, 4.d, 5.a, 5.d, and 6.a, this would require one trip system to have one channel OPERABLE or in trip. For Functions 5.b and 5.c, each Function consists of channels that monitor several different rooms or areas. Therefore, this would require one channel per room or area to be OPERABLE (the channels are not required to be in the same trip system). As noted, with a Table 3.3.6.1-1 Function 5.c channel inoperable, isolation capability is considered maintained provided Function 5.b is OPERABLE in the affected room. There is diversity in the RWCU temperature isolation instrumentation in that Area Ventilation Differential Temperature-High and the Area Temperature-High monitor for a sma 11 leak in the same rooms. The rel i abi l i ty of the RWCU system isolation function remains high even in the presence of single or multiple failures of differential temperature channels because a steam leak will cause a coincident trip of both the Area Ventilation Differential Temperature-High and the Area Temperature-High channels in RWCU A Pump Room, RWCU B Pump room, RWCU Phase Separator Room, and RWCU Heat Exchanger Room. There is no diversity for the RWCU Open B 3.3.6.1-27 Revision 84

BASES Primary Containment Isolation Instrumentation B 3.3.6.1 ACTIONS (continued) FERMI - UNIT 2 Trench Above Pump room and RWCU Torus Room areas. The Condition does not include the Manual Initiation Functions (Functions l.h, 2.e, 3.f, 4.f, 5.f, and 6.c), since they are not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours (as allowed by Required Action A.1) is allowed. For Functions 7.a and 7.b, the logic is arranged in one trip system and the isolation function is ensured by the manual shear valve in each penetration. Therefore, this would require both channels to be OPERABLE or in trip, or the manual shear valves to be OPERABLE. The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. C.1 Required Action C.1 directs entry into the appropriate Condition referenced in Table 3.3.6.1-1. The applicable Condition specified in Table 3.3.6.1-1 is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed. Each time an inoperable channel has not met any Required Action of Condition A or Band the associated Completion Time has expired, Condition C will be entered for that channel and provides for transfer to the appropriate subsequent Condition. D.1, D.2.1, and D.2.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by placing the plant in at least MODE 3 within 12 hours and in MOOE 4 within 36 hours (Required Actions D.2.1 and D.2.2). Alternately, the associated MSLs may be isolated (Required Action D.1), and, if allowed (i.e., plant safety analysis allows operation with an MSL isolated), operation with that HSL isolated may continue. Isolating the affected MSL accomplishes the safety function of the inoperable channel. The Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. B 3.3.6.1-28 Revision 84

BASES Recirculation Loops Operating B 3.4.1 APPLICABLE The operation of the Reactor Coolant Recirculation System is SAFETY ANALYSES an initial condition assumed in the design basis loss of FERMI - UNIT 2 , coolant accident (LOCA) (Ref. 1). During a LOCA caused by a recirculation loop pipe break, the intact loop is assumed to provide coolant flow during the first few seconds of the accident. The initial core flow decrease is rapid because the recirculation pump in the broken loop ceases to pump reactor coolant to the vessel almost immediately. The pump in the intact loop coasts down relatively slowly. ll]is pump coastdown governs the core flow response for the next several seconds until the jet pump suction is uncovered. The analyses assume that both loops are operating at the same flow prior to the accident. However, the LOCA analysis was reviewed for the case with a flow mismatch between the two loops, with the pipe break assumed to be in the loop with the higher flow. While the flow coastdown and core response are potentially more severe in this assumed case (since the intact loop starts at a lower flow rate and the core response is the same as if both loops were operating at a lower flow rate), a small mismatch has been detennined to be acceptable based on engineering judgement. The recirculation system is also assumed to have sufficient flow coastdown characteristics to maintain fuel thennal margins during abnormal operational transients (Ref. 2), which are analyzed in Chapter 15 of the UFSAR. A plant specific LOCA analysis has been performed assuming only one operating recirculation loop. This analysis has demonstrated that, in the event of a LOCA caused by a pipe break in the operating recirculation loop, the Emergency Core Cooling System response will provide adequate core cooling provided the APLHGR requirements are modified accordingly (Ref. 3). The transient analyses of Chapter 15 of the UFSAR have also been performed for single recirculation loop operation (Refs. 4 and 5) and demonstrate sufficient flow coastdown characteristics to maintain fuel thennal margins during the abnonnal operational transients analyzed provided the MCPR requirements are modified. During single recirculation loop operation, modification to the Reactor Protection System (RPS) average power range monitor (APRM) instrwnent setpoints is also required to account for the different relationships between recirculation drive flow and reactor B 3.4.1-3 Revision 84

BASES REFERENCES FERMI - UNIT 2

1.

UFSAR, Section 6.3.3. Recirculation Loops Operating B 3.4.1

2.

NEDE-33005P-A, Revision 2, Licensing Topical Report "TRACG Application for Emergency Core Cooling Systems/ Loss-of-Coolant-Accident Analyses for BWR/2-6," May 2018.

3.

NEDC-32313-P, "Enrico Fermi Energy Center Unit 2 Single-Loop Operation," September 1994.

4.

TRVEND NEDC 33919P, "Fermi 2 TRACG ECCS, Loss-of-Coolant Accident (LOCA) Analysis," January 2020.

5.

Cycle-Specific Supplemental Reload Licensing Report. B 3.4.1-9 Revision 84

BASES REFERENCES ) FERMI - UNIT 2

1.

10 CFR 50, Appendix A, GOG 17.

2.

Regulatory Guide 1.6.

3.

IEEE Standard 308, 1971.

4.

UFSAA, Chapter 6.

5.

UFSAR, Chapter 15.

6.

Regulatory Guide 1.93.

7.

IEEE Standard 450. DC Sources-O~rating B 3.8.4

8.

NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Infonned Modification to Selected - Required End States for BWR Plants, December 2002.

9.

Regulatory Guide 1.32, February 1977.

10.

IEEE Standard 485, 1983.

11.

UFSAA, Section 8.3.2. B 3.8.4-9 Revision 84

ENCLOSURE 5 TO NRC-21-0002 Summary of Excessive Detail Removed from the Fermi 2 UFSAR to NRC-21-0002 Page 1 Summary Report of Excessive Detail Removal The following is a summary report of excessive detail that has been removed in Revision 23 to the Fermi 2 UFSAR These changes are consistent with Nuclear Energy Institute (NEI) 98-03, "Guidelines for Updating Final Safety Analysis Reports", Revision 1, June 1999, as endorsed by the NRC. The Fermi 2 UFSAR continues to adequately describe the design bases, plant safety analyses, and design and operation of structures, systems, and components (SSCs). LCRNo. Excessive Detail Removed Basis for Removal 19-027-UFS Deleted the specific position title The UFSAR section retains the that fire protection personnel necessary description of the report to within the operations reporting structure of the fire department in UFSAR Section protection personnel within the 13.1. department. The specific position title is not reauired. 20-015-UFS Deleted obsolete discussions of the The CGCS has been retired in abandoned Combustible Gas place due to revised 10 CFR Control System (CGCS) in 50.44, issued License Amendment UFSAR Sections 6.2.5, 7.3.8, and 159, and updated guidance of others. Regulatory Guide 1. 7. The UFSAR retains the discussion of CGCS components that remain in place and their current status and function. 20-030-UFS Deleted the discussion of a one-The deferral took place in the past time deferral of a turbine and is no longer applicable. The inspection in UFSAR Section UFSAR section retains the 10.2.3. discussion of the inspection recommendations.

ENCLOSURE 6 TO NRC-21-0002 10 CFR 72.48 Evaluation Summary Report to NRC-21-0002 Page 1 72.48 EVALUATION

SUMMARY

72.48 Evaluation No: 19-0001 Rev. 0 212 Report Rev. No. 2 Reference Document: ECO 1021 141 ECO 5014 270 Section(s) NIA Title of Change: 35.710.043 Table(s) NIA Figure Change D Yes Revise Holtec Drawing 3923R36 & Cask FSAR Section 8.1.5 via ECO 1021141 and ECO 5014 270 Engineering Change Order (ECO) 1021141: Add the Note PRIOR TO WELDING, ENSURE PORT COVER PLATE SET SCREWS ARE RECESSED AT LEAST 118" INTO PORT COVER PLATE." ECO 5014 270: Revise Cask FSAR Section 8.1.5, Step 9.b. to read, "Flush the cavity with helium to remove the air and immediately install the set screws recessed below flush with the top of the cover plate." Fermi 2 procedure 35.710.043 is revised to add this requirement. The proposed activity does not result in a more than minimal increase in the frequency of occurrence of an accident, the likelihood of occurrence of a malfunction of an SSC important to safety, the consequences of an accident, or the consequences of a malfunction of an SSC; does not create a possibility for an accident of a different type or a malfimction of an SSC important to safety with a different result than any previously evaluated in the cask FSAR; does not result in a design basis limit for a fission product barrier as described in the cask FSAR; and does not involve a departure from a method of evaluation described in the cask FSAR Therefore, prior NRC approval of this change is not required. to NRC-21-0002 Page2 72.48 EVALUATION

SUMMARY

72.48 Evaluation No: 19-0010 Rev. 0 212 Report Rev. No. 2 Reference Document: ECO 5014 266 Section(s) _N_/_A _______ _ Title of Change: Table(s) NIA Figure Change D Yes ECO 5014 266 Revision 1 - Proposed Changes to ID-STORM 100 FSAR (ID-2002444) Revision 14 Holtec ECO 5014 266 Rev. 1 was issued to revise HI-STORM 100 FSAR.Rev. 14, Table 1.D.l, Table 2.2.3, Table 2.1.8, Table 4.1.5, Table 4.1.6, Table 4.1.8, and Table 4.1.9 to reflect a decrease in the local temperature limit of HI-STORM plain concrete under short term, off-normal, and accident conditions. Additionally, the cask FSAR Tables are updated to reflect a decrease in credited concrete compressive strength when the HI-STORM canister concrete is exposed to elevated local temperature conditions. Changes are made to Subsection 3.4.8 and Table 3.4.9 to reflect changes from calculations that are updated to reflect the reduced credited concrete compressive strength. The Holtec ECO also deleted Note 1 of Table l.D.1 to resolve an inconsistency with the governing ACI Code. There are no malfunctions associated with the HI-STORM system due to the proposed activity and so, no malfunction likelihood, consequences, or results can be increased. The MPC confinement boundary and MPC basket flow holes remain unchanged, so no accident consequences can be increased. Methods of handling and operating the cask system are not affected, so no new accidents can be created. Cask system temperatures, including fuel cladding, are not increased beyond acceptable limits and MPC internal pressures are not increased, so no fission product boundary limit is exceeded. There is no departure from an evaluation method with this proposed activity. Therefore, prior NRC approval of this change is not required. to NRC-21-0002 Page3 72.48 EVALUATION

SUMMARY

72.48 Evaluation No: 19-0011 Rev. 0 Referenc_e Document: ECO 1021137 2U Report Rev. No. Section(s) Table(s) NIA NIA Figure Change D Yes (!]No* Title of Change: ECO 1021 137 - Proposed Changes to MPC-68M Fuel Basket Licensing Dr.awing (7195Rl3) Various changes to Holtec licensing drawing 7195R13 are proposed in ECO 1021137. The one drawing change that screened in under 72.48 Screen Question 1 (Change to an SSC that adversely affects a cask FSAR described design function) was a proposed change to allow for increased clearance between the MPC internal cavity and fuel basket The maximum allowable height difference between the fuel basket and the multi-purpose canister (MPC) internal cavity is increased from 4.25" to 5. 75". This change is being made to allow for the fuel basket to be shortened, thereby improving clearance between the fuel handling tool and the basket during fuel assembly installation. There are no malfimctions associated with the HI-STORM system due to the proposed activity and so, no malfunction likelihood, consequences or results can be increased. The confinement boundary and MPC basket flow holes remain unchanged, so no accident consequences can be increased. Methods of handling and operating the cask system are not affected, so no new accidents can be created. cask system temperatures, including fuel cladding, are not increased beyond acceptable limits and MPC internal pressures are not increased, so no fission product boundary limit is exceeded. No new evaluation methods are used. As the response to each of the eight of the Evaluation Questions is 'No,' the proposed activity may be implemented without obtaining an amendment to the license or Certificate of Compliance. Therefore, prior NRC approval of this change is not required.

ENCLOSURE 7 TO NRC-21-0002 License Renewal Requirements for 10 CFR 54.37 to NRC-21-0002 Page 1 LICENSE RENEW AL REQUIREMENTS FOR 10 CFR 54.37 In accordance with 10 CFR 54.37(b) and the guidance specified in Regulatory Issue Summary 2007-16, Revision I, 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 CPR 5421. This UFSAR update must describe how the effects of aging will be managed such that the intended function(s) in 10 CPR 54.4(b) will be effectively maintained during the period of extended operation. DIB conducted reviews and determined 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).}}