Text

License Amendment Request to Revise Technical Specifications and Exemption Request from Requirements of 10CFR50.62 ATWS Rule to Support the Digital Modernization Project Installation
	ML23052A023
Person / Time
Site:	Limerick
Issue date:	02/17/2023
From:	David Helker; Constellation Energy Generation
To:	; Office of Nuclear Reactor Regulation, Document Control Desk
Shared Package
ML23052A022	List: ML23052A023;
References
	Download: ML23052A023 (1)
	v • d • e

200 Exelon Way Kennett Square, PA 19348 www.ConstellationEnergy.com ATTACHMENT 4 TRANSMITTED HEREWITH CONTAINS PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 10 CFR 50.90 10 CFR 50.12 February 17, 2023 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 ATTN: Document Control Desk Limerick Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 NRC Docket Nos. 50-352 and 50-353

Subject:

License Amendment Request to Revise Technical Specifications and Exemption Request from Requirements of 10CFR50.62 ATWS Rule to Support the Digital Modernization Project Installation

References:

1. Constellation Energy Generation, LLC (CEG) letter to the U.S. Nuclear Regulatory Commission (NRC), "License Amendment Request to Revise the Licensing and Design Basis to Incorporate the Replacement of Existing Safety-Related Analog Control Systems with a Single Digital Plant Protection System (PPS)," dated September 26, 2022 (NRC Agencywide Documents Access and Management System (ADAMS) Accession No. ML22269A5690).

2. CEG Presentation Slides, "Non-Proprietary Presentation for March 31, 2022 Pre-Submittal Meeting with Constellation Energy Generation, LLC Regarding Planned Digital Modernization License Amendment Request for Limerick Generating Station, Units 1 and 2," dated March 21, 2022 (ADAMS Accession No. ML22080A152),

3. CEG Presentation Slides, "Non-Proprietary Presentation for June 9, 2022 Pre-Submittal Meeting with Constellation Energy Generation, LLC Regarding Planned Digital Modernization License Amendment Request for Limerick Generating Station, Units 1 and 2," dated June 9, 2022 (ADAMS Accession No. ML22153A360).

4. CEG Presentation Slides, Limerick Generating Station Digital Modernization LAR Pre-submittal Meeting, dated September 8, 2022 (ADAMS Accession No. ML22249A097).

ATTACHMENT 4 TRANSMITTED HEREWITH CONTAINS PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390. When separated from Attachment 4, this submittal is decontrolled.

License Amendment Request Docket Nos. 50-352 and 50-353 February 17, 2023 Page 2 ATTACHMENT 4 TRANSMITTED HEREWITH CONTAINS PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390

5. CEG Presentation Slides, Limerick Generating Station Digital Modernization (DMP) Installation Support LAR and Exemption Request, dated January 10, 2023 (ML23006A257)

In accordance with 10 CFR 50.90, Constellation Energy Generation, LLC (CEG) requests an amendment to Appendix A, "Technical Specifications" (TS) of Renewed Facility Operating License Nos. NPF-39 and NPF-85 for Limerick Generating Station (LGS), Units 1 and 2, respectively. The proposed changes will revise the LGS Technical Specifications (TS) to adopt features from NUREG-1433, Revision 5, "Standard Technical Specifications for General Electric BWR/4 Plants."

In addition, the proposed changes will revise the "Applicability" of TS 3/4.3.4, "ATWS (Anticipated Transient Without Scram) Recirculation Pump Trip (RPT) Actuation Instrumentation," to add a note stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the LCO is not applicable if specified conditions are met. A table with these conditions is included as part of the note. Supporting changes are also proposed to add a corresponding footnote to Surveillance Requirement (SR) 4.1.5, "Standby Liquid Control System," TS Table 3.3.2-1, "Isolation Instrumentation," Trip Function 3.d, "SLCS Initiation," and SR Table 4.3.2.1-1, "Isolation Actuation Instrumentation Surveillance Requirements," Trip Function 3.d, "SLCS Initiation."

The proposed TS changes will support the installation of a digital modification at LGS Unit 1 and Unit 2 during upcoming refueling outages. CEG has submitted a separate license amendment request (LAR) for NRC review and approval of the Digital Modernization Project (DMP) Plant Protection System (PPS) (Reference 1). This LAR is not linked to the LAR for the digital modification but is required to support the installation of the PPS plant modifications within the current refueling outage constraints.

CEG discussed these proposed changes with the NRC as part of pre-submittal meetings for the DMP on March 31, 2022 (Reference 2), June 9, 2022 (Reference 3), September 8, 2022 (Reference 4), and January 10, 2023 (Reference 5). to this letter provides an evaluation of the proposed TS changes. Attachment 2 provides a markup of current TS pages with the proposed changes. Attachment 3 provides the existing TS Bases pages marked to show revised text associated with the proposed TS changes and is provided for information only. Attachments 4 and 5 provide proprietary and non-proprietary versions (respectively) of a deterministic ATWS sensitivity analysis that supports the proposed One-Time TS LCO 3.3.4.1 Applicability Change for ATWS Recirculation Pump Trip Actuation (ATWS-RPT) Instrumentation. Attachment 6 provides an Affidavit in support of Attachment 4. includes an affidavit signed by Global Nuclear Fuels, LLC (GNF), the owner of the proprietary information. The affidavit sets forth the basis upon which the information may be withheld from public disclosure by the NRC, and it addresses with specificity the

License Amendment Request Docket Nos. 50-352 and 50-353 February 17, 2023 Page 3 ATTACHMENT 4 TRANSMITTED HEREWITH CONTAINS PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 considerations listed in paragraph (b)(4) of 10 CFR 2.390 of the NRCs regulations. GNF requests that the GNF proprietary information in Attachment 4 be withheld from public disclosure in accordance with 10 CFR 2.390. Future correspondence with respect to the proprietary aspects of the application for withholding related to the GNF proprietary information or the GNF affidavit provided in Attachment 6 should reference this request letter.

In accordance with 10 CFR 50.12, "Specific exemptions," this submittal also includes a request for temporary exemption from 10 CFR 50.62, "Requirements for reduction of risk from anticipated transients without scram (ATWS) events for light-water-cooled nuclear power plants," Paragraphs (c)(3), (4), and (5). The exemption is required to implement the proposed One-Time TS LCO 3.3.4.1 Applicability Change for ATWS Recirculation Pump Trip Actuation (ATWS-RPT) Instrumentation when both divisions of the ATWS-RPT System Instrumentation are inoperable. The temporary exemption request is provided in .

This amendment request contains no regulatory commitments.

CEG plans to implement the proposed TS changes prior to the LGS Unit 1 20th refueling outage (Li1R20), currently scheduled to commence in April 2024. As such, CEG requests approval of the proposed license amendment by February 17, 2024.

In accordance with 10 CFR 50.91, "Notice for public comment; State consultation,"

paragraph (b), CEG is notifying the Commonwealth of Pennsylvania of this license amendment request supplement by transmitting a copy of this letter to the designated State Official.

If you have any questions regarding this submittal, then please contact Frank Mascitelli at Francis.Mascitelli@constellation.com.

I declare under penalty of perjury that the foregoing is true and correct. Executed on this 17th day of February 2023.

Respectfully, David P. Helker Sr. Manager - Licensing Constellation Energy Generation, LLC Attachments: 1. Evaluation of Proposed Changes

License Amendment Request Docket Nos. 50-352 and 50-353 February 17, 2023 Page 4 ATTACHMENT 4 TRANSMITTED HEREWITH CONTAINS PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390

2. Technical Specification Page Markups

3. Technical Specification Bases Page Markups (Provided for Information Only)

4. GNF 007N5226P, Revision 0, Limerick ATWS Analysis Without Automatic RRCS Functions and Manual SLCS Injection (Proprietary)

5. GNF 007N5226NP, Revision 0, Limerick ATWS Analysis Without Automatic RRCS Functions and Manual SLCS Injection (Non-Proprietary)

6. Affidavit for GNF 007N5226P Limerick ATWS Supplemental Analysis

7. Temporary Exemption Request for ATWS Rule 10CFR50.62, Paragraphs (c)(3), (4), and (5) cc: USNRC Region I, Regional Administrator w/ attachments USNRC Project Manager, LGS "

USNRC Senior Resident Inspector, LGS "

Director, Bureau of Radiation Protection - Pennsylvania Department of Environmental Protection w/attachments 1, 2, 3, 5, 6, and 7

ATTACHMENT 1 License Amendment Request Limerick Generating Station, Units 1 and 2 NRC Docket Nos. 50-352 and 50-353 Evaluation of Proposed Changes 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION 2.1 Current TS Requirements 2.2 Reason for the Proposed TS Changes 2.3 Description of Proposed TS Changes

3.0 TECHNICAL EVALUATION

3.1 Revise TS 3.5.1, RPV WIC, Action a 3.2 Incorporation of TSTF-582 and TSTF-583-T 3.3 Revise Reactor Mode Switch and Manual Scram OPCON 5 Applicability 3.4 Revise Reactor Mode Switch Requirements During Refueling 3.5 One-Time LCO 3.3.4.1 Applicability Change for ATWS Recirculation Pump Trip Actuation Instrumentation

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria 4.2 No Significant Hazards Consideration Analysis 4.3 Conclusion

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 1 of 29 1.0

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, Constellation Energy Generation, LLC (CEG) requests an amendment to Appendix A, "Technical Specifications" (TS) of Renewed Facility Operating License Nos. NPF-39 and NPF-85 for Limerick Generating Station (LGS), Units 1 and 2, respectively. The proposed changes will revise the LGS Technical Specifications (TS) to adopt features from NUREG 1433, Revision 5, "Standard Technical Specifications for General Electric BWR/4 Plants" (herein referred to as the STS) and revise instrumentation requirements that will support the installation of a digital modification at LGS Unit 1 and Unit 2 during upcoming refueling outages. CEG has submitted a separate license amendment request (LAR) for NRC review and approval of the digital modification (Reference 1). This LAR is not linked to the Reference 1 LAR but is required to support the installation of the digital modification within current refueling outage constraints. CEG discussed these proposed changes with the NRC as part of pre-submittal meetings for the DMP PPS LAR (Reference 1) on March 31, 2022 (Reference 2), June 9, 2022 (Reference 3), September 8, 2022 (Reference 4) and January 10, 2023 (Reference 5).

Specifically, the proposed changes will:

1. Incorporate additional TS changes associated with TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control," (Reference 6) and TSTF-582, Revision 0, "RPV WIC Enhancements," (Reference 10) which were previously adopted into the LGS TS (References 9 and 13, respectively):

a. Revise TS 3.5.2, Action a. to delete the requirement to suspend Core Alterations when the required low pressure Emergency Core Cooling System (ECCS) subsystem is inoperable.

b. Revise TS 3.3.3, "Emergency Core Cooling System Actuation Instrumentation,"

and TS 3.8.1.2, "A.C. Sources - Shutdown," to not require automatic start and loading of a diesel generator (DG) and sequenced loading of the emergency electrical busses in OPCON 4 and 5.

2. Revise TS 3.3.1, "Reactor Protection System Instrumentation," OPCON 5 applicability for the "Reactor Mode Switch - Shutdown Position" and "Manual Scram" instrumentation functions to not require these functions to be operable unless any control rods are withdrawn from a core cell containing one or more fuel assemblies, which is consistent with the STS requirements. The TS Actions applicable when these functions are not operable in OPCON 5 are revised to be consistent with the STS requirements.

3. Revise TS 3.9.1, "Reactor Mode Switch," to eliminate references to the "Shutdown" position of the reactor mode switch and make complimentary changes to TS 3.9.10.2, "Multiple Control Rod Removal," to be consistent with the LGS design and the STS requirements.

4. Revise the "Applicability" of TS 3/4.3.4, "ATWS (Anticipated Transient Without Scram)

Recirculation Pump Trip (RPT) Actuation Instrumentation," to add a note stating that for a

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 2 of 29 period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the LCO is not applicable if specified conditions are met. A table with these conditions is included as part of the note.

5. Revise SR 4.1.5, "Standby Liquid Control System" to add a footnote stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), no pumps are required to start automatically.

6. Revise TS Table 3.3.2-1, "Isolation Instrumentation," Trip Function 3.d, "SLCS Initiation,"

to add a footnote stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

7. Revise SR Table 4.3.2.1-1, "Isolation Actuation Instrumentation Surveillance Requirements," Trip Function 3.d, "SLCS Initiation," to add a note stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

CEG discussed several of these proposed changes (Items 1 through 4) with the NRC as part of pre-submittal meetings for the digital modification on March 31, 2022, June 9, 2022, September 8, 2022, and January 10, 2023.

2.0 DETAILED DESCRIPTION 2.1 Current TS Requirements The LGS TS are based on an earlier version of the STS. The LGS TS use the defined term "OPERATIONAL CONDITION (OPCON) instead of the STS defined term "MODE,"

but the definitions of the Operational Conditions and Modes are consistent.

TS 3.5.2, "Reactor Pressure Vessel (RPV) Water Inventory Control (WIC)," Action a, states that with the required low pressure ECCS subsystem inoperable, immediately suspend Core Alterations and restore at least one subsystem to operable status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

TS Table 3.3.3-1, "Emergency Core Cooling System Actuation Instrumentation," Function 5.1, "4.16 kV Emergency Bus Under-Voltage (Loss of Voltage)," and Function 5.2, "4.16 kV Emergency Bus Under-voltage (Degraded Voltage)," are required to be operable in OPCON 1, 2, 3, 4, and 5. The applicable operational condition for these functions includes note *** for OPCON 4 and 5, which states that the functions are only required to be operable when the associated Engineered Safety Features (ESF) equipment is

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 3 of 29 required to be operable. SR Table 4.3.3.1-1, "Emergency Core Cooling System Actuation Instrumentation Surveillance Requirements," includes an equivalent note to the applicable operational conditions for functions 5.1 and 5.2.

TS 3.8.1.2, "A.C. Sources - Shutdown," is applicable in OPCON 4 and 5, and when handling irradiated fuel in the secondary containment. Surveillance Requirement (SR) 4.8.1.2 requires all Surveillance Requirements in TS 3.8.1.1, "A.C. Sources - Operating, "

to be met. The TS 3.8.1.1 SRs required to be met by SR 4.8.1.2 include tests to verify that a required diesel generator will automatically start and achieve the required voltage and frequency within a specified time on receipt of a loss of power signal or an ESF signal, and to verify that loads will be sequenced onto the corresponding bus.

TS Table 3.3.1-1, "Reactor Protection System Instrumentation," Functional Unit 11, "Reactor Mode Switch Shutdown Position," and Functional Unit 12, "Manual Scram," are applicable in OPCONs 1, 2, 3, 4, and 5. SR Table 4.3.1.1-1 includes the same applicability for the two functions.

TS 3.9.1, "Reactor Mode Switch," requires the reactor mode switch to be operable and locked in the Shutdown or Refuel position. The Applicability is OPCON 5, and OPCONs 3 and 4 when the reactor mode switch is in the Refuel position. Actions a and b and Surveillance 4.9.1.1 refer to the reactor mode switch being locked in the Shutdown or Refuel position.

TS 3.9.10.2, "Multiple Control Rod Removal," and Surveillance 4.9.10.2.1 refer to the reactor mode switch being locked in the Shutdown or Refuel position in accordance with Specification 3.9.1.

TS 3/4.3.4.1, "ATWS Recirculation Pump Trip Actuation Instrumentation," provides the LCOs, Actions, SRs, trip setpoints and response times for the ATWS-RPT system instrumentation applicable in OPCON 1. The ATWS-RPT system establishes a means of limiting the consequences of the unlikely occurrence of a failure to scram during an anticipated transient.

TS 3/4.1.5, "Standby Liquid Control System" provides the LCOs, Actions, and SRs for the Standby Liquid Control System (SLCS). The SLCS provides a backup capability for bringing the reactor from full power to a cold, Xenon-free shutdown, assuming that the withdrawn control rods remain fixed in the rated power pattern. The TS is applicable in OPCON 1.

TS Table 3.3.2-1, "Isolation Instrumentation," Trip Function 3.d, "SLCS Initiation," specifies that the trip function is applicable in OPCONs 1, 2, and 3.

SR Table 4.3.2.1-1, "Isolation Actuation Instrumentation Surveillance Requirements," Trip Function 3.d, "SLCS Initiation," specifies that surveillances for the trip function are required in OPCONs 1, 2, and 3. This table includes a note stating that SR frequencies are specified in the Surveillance Frequency Control Program.

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 4 of 29 2.2 Reason for the Proposed Changes In Reference 9, the NRC approved Amendments 227/190 to the LGS TS, which adopted TSTF-542. Prior to the approval of Amendments 227/190, LGS TS 3.5.2, "ECCS -

Shutdown," Actions included a requirement to suspend Core Alterations when an ECCS division is inoperable. Earlier standard TS for boiling water reactor (BWR) plants included a similar action, which was removed during the development of the BWR STS (i.e.,

NUREG-1433). As a result, this action does not appear in the STS and its removal was neither addressed nor justified in TSTF-542. The LGS LAR to implement TSTF 542 (Reference 7) included a request to eliminate the requirement to suspend Core Alteration, consistent with NUREG 1433. In a response to a request for additional information (Reference 8), Exelon Generation Company, LLC (EGC) (i.e., the LGS licensee at that time) rescinded the requested elimination based, in part, on the refueling outage schedule relative to the expected completion of NRC review. As a result, the requirement was retained in the LGS TS. However, suspension of Core Alterations has no effect on RPV water inventory control and the action is unrelated to the safety function of TS 3.5.2.

Therefore, the LGS TS 3.5.2 Actions are being revised to eliminate the requirement to suspend Core Alterations, consistent with both NUREG-1433 and the intent of TSTF-542.

In Reference 12, CEG requested adoption of TSTF-582 into the LGS TS. At that time, CEG did not include all the TS changes that are specified in TSTF-582 into the LGS license amendment request (LAR). In Reference 13, the NRC approved Amendments 252/214 to the LGS TS to adopt the requested portions of TSTF-582. Subsequent to the LGS submittal to adopt TSTF-582, the industry developed additional revisions that could be incorporated into an amendment to adopt TSTF-582 related to automatic starting of diesel generators. That variation was documented in a TSTF T-Traveler which is labeled TSTF-583-T, "TSTF-582 Diesel Generator Variations," was accepted by the NRC in Reference 11, and incorporated into Revision 5 of the STS. The proposed change incorporates the previously unadopted portions of TSTF-582, and the TSTF-583-T TS changes into the LGS TS, and other changes to be consistent with the STS requirements equivalent to SR 4.8.1.2.

The TSFT-582 and TSTF-583-T proposed changes will facilitate outage installation of the DMP PPS digital LAR when ECCS logic is out of service and complying with current TS requirements for Loss of Power (LOP) Instrumentation or Emergency Diesel Generator (EDG) auto start operability/SR performance during outage will become problematic.

There are no accidents or transients analyzed in Mode 4 Cold Shutdown or Mode 5 Refueling which require the automatic start of a diesel generator. Therefore, the supporting instrumentation for the automatic start is not required in those modes of operation and the ability to manually start the diesel is the function which is maintained OPERABLE as a result of the proposed changes.

LGS TS Table 3.3.1-1, "Reactor Protection System Instrumentation," Function 11, "Reactor Mode Switch Shutdown Position," and Function 12, "Manual Scram," requires these Functional Units to be operable in OPCON 5. In the STS, these functions must be operable in Mode 5 only when any control rod is withdrawn from a core cell containing one or more fuel assemblies. The STS Actions applicable when these functions are inoperable are consistent with the STS Applicability. The proposed change incorporates the STS

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 5 of 29 Applicability and Actions for these functions into the LGS TS to provide additional flexibility during a refueling outage.

The TS Table 3.3.1-1 proposed changes for TS Table 3.3.1-1 Functions 11 and 12 will facilitate outage installation of the DMP PPS since during the disassembly of the PPS system the Mode Switch and Manual Pushbuttons will be made inoperable for the RPS functions that they support. In order to continue other refueling activities which do not depend on the RPS function this change is proposed. Specifically, this allows for fuel movement to continue while these RPS features are inoperable. However, since the ability to insert control rods only serves a mitigative function when the control rod is withdrawn in a fuel cell which is still surrounded by fuel, the function has been modified to no longer be required unless a control rod is withdrawn in a fueled cell.

The LGS TS 3.9.1, "Reactor Mode Switch," serves the same purpose as STS 3.9.1, "Refueling Equipment Interlocks," which is to prevent inadvertent criticality during refueling by ensuring the refueling equipment interlocks are operable. In some BWR designs, the refueling equipment interlocks are engaged in both the Shutdown and Refuel reactor mode switch positions, and that design was reflected in the standard TS on which the LGS TS are based (NUREG-0123). The STS revised the specification to only be applicable when the refueling equipment interlocks are required. In the LGS design, the refueling equipment interlocks are only engaged when the reactor mode switch is in the Refuel position. LGS TS 3.9.1 is revised to eliminate references to the Shutdown reactor mode switch position in order to be consistent with the LGS design and the equivalent STS requirements.

The TS 3.9.1 proposed changes will facilitate outage installation of the DMP PPS when the Mode Switch is made inoperable for its RPS function during the refueling outage. This TS has been modified to remove references to placing the Mode Switch in the Shutdown position as a mitigative action for refueling interlocks not being OPERABLE. This allows other refuel outage related activities, primarily related to the movement of fuel, to continue without unnecessary restrictions on the ACTIONS to be taken with the Mode Switch RPS function inoperable. This limits the remaining actions to those which have a direct impact on refueling operations and is in alignment with the STS.

Revise TS 3.9.10.2, "Multiple Control Rod Removal," and SR 4.9.10.2.1 will remove references to the reactor mode switch being locked in the Shutdown position in accordance with Specification 3.9.1. This is required to facilitate the PPS outage installation when the Reactor Mode Switch logic for shutdown will be inoperable.

TS 3.4 The Redundant Reactivity Control System (RRCS) determines that an Anticipated Transient Without Scram (ATWS) mitigation is needed, and automatically activates the Alternate Rod Insertion (ARI), Recirculation Pump Trip (RPT), Standby Liquid Control System (SLCS) injection and Reactor Water Cleanup (RWCU) isolation, and feedwater runback (FWRB) functions. The ATWS-RPT, SLCS actuation and RWCU isolation have TS requirements. The RRCS is being replaced as part of the digital upgrade described in Reference 1. To install the digital upgrade safely and efficiently, CEG plans to dismantle both divisions of the RRCS actuation instrumentation thirty days prior to the beginning of the installation outage for each unit, rendering ARI, ATWS-RPT, SLCS automatic initiation

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 6 of 29 and RWCU isolation, and feedwater runback systems inoperable. During this time, additional ATWS mitigation strategies listed in Section 3.5.2 will be in place for ATWS mitigation to provide the same level of ATWS protection.

Regarding the proposed changes to TS 3.3.4.1, "ATWS Recirculation Pump Trip Actuation Instrumentation," a change to Applicability requirements of the LCO will be made. This LCO provides the Actions, SRs, trip setpoints and response times for the ATWS-RPT system instrumentation applicable in OPCON 1. The ATWS-RPT system establishes a means of limiting the consequences of the unlikely occurrence of a failure to scram during an anticipated transient without scram. To install the digital upgrade safely and efficiently, CEG plans to dismantle both divisions of the RRCS actuation instrumentation thirty days prior to the beginning of the installation outage for each unit, rendering ARI, ATWS-RPT, SLCS automatic initiation and RWCU isolation, and feedwater runback systems inoperable. Therefore, a Note will be added to the LCO 3.3.4.1 that it is not applicable 30 days prior to 2024 (for Unit 1) and 2025 for Unit 2 Refuel Outages, when additional operational restraints summarized in the subsequent Table are in effect, as described in Section 3.5 of this LAR. These operational restraints include: limiting reactor thermal power; crediting a non safety-related reactor recirculation pump runback; requiring additional number of Main Steam Relief Valves (MSRVs) to be operable; manually initiating SLCS within 5 minutes; and raising suppression pool water level limits.

Additionally, the following TS sections are being modified to support the demolition of RRCS under the TS LCO 3.3.4.1, Applicability changes described in the previous paragraph:

TS 3/4.1.5, "Standby Liquid Control System" provides the LCOs, Actions, and SRs for the Standby Liquid Control System (SLCS). The SLCS provides a backup capability for bringing the reactor from full power to a cold, Xenon-free shutdown, assuming that the withdrawn control rods remain fixed in the rated power pattern. The TS is applicable in OPCON 1.

TS Table 3.3.2-1, "Isolation Instrumentation," Trip Function 3.d, "SLCS Initiation," specifies that the trip function is applicable in OPCONs 1, 2, and 3.

SR Table 4.3.2.1-1, "Isolation Actuation Instrumentation Surveillance Requirements," Trip Function 3.d, "SLCS Initiation," specifies that surveillances for the trip function are required in OPCONs 1, 2, and 3. This table includes a note stating that SR frequencies are specified in the Surveillance Frequency Control Program.

2.3 Description of the Proposed TS Changes TS 3.5.2, "RPV WIC," Action a, is revised to eliminate the requirement to immediately suspend Core Alterations. The revised Action states, "With none of the above required subsystems OPERABLE, restore at least one subsystem to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Otherwise, initiate action to establish a method of water injection capable of operating without offsite electrical power.

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 7 of 29 TS 3.3.3-1, "Emergency Core cooling System Actuation Instrumentation," Table 3.3.3-1 Function 5.1, "4.16 kV Emergency Bus Under-Voltage (Loss of Voltage)," and Function 5.2, "4.1.6 kV Emergency Bus Under-voltage (Degraded Voltage)," are revised to eliminate the requirement for the functions to be operable in Operational Conditions 4 and

5. The applicability of OPCON 1, 2, and 3 is retained. Table 3.3.3-1 Note **, which states, "Required when ESF equipment is required to be OPERABLE," and only applies to Functions 5.1 and 5.2 in OPCONs 4 and 5, is deleted.

TS Table 3.3.3-1, Actions 36 and 37, both state, "... and take the ACTION required by Specification 3.8.1.1 or 3.8.1.2, as appropriate." The phrase is revised to state, "... and take the ACTION required by Specification 3.8.1.1." Table 4.3.3.1-1 labels these functions as 5.a and 5.b and is also revised to eliminate the requirement for the functions to be operable in OPCONs 4 and 5. Table 4.3.3.1-1, Note **, which states, "Required OPERABLE when ESF equipment is required to be OPERABLE," and which only applies to Functions 5.a and 5.b in OPCONs 4 and 5, is deleted.

SR 4.8.1.2, which states, "At least the above required A.C. electrical power sources shall be demonstrated OPERABLE per Surveillance Requirements 4.8.1.1.1 and 4.8.1.1.2," is modified by adding "except for 4.8.1.1.1.b, 4.8.1.1.2.e.4, 4.8.1.1.2.e.5, 4.8.1.1.2.e.6, 4.8.1.1.2.e.7, 4.8.1.1.2.e.8.b, 4.8.1.1.2.e.11, 4.8.1.1.2.e.12, 4.8.1.1.2.f, and 4.8.1.1.2.h."

TS 3.3.1.1, "Reactor Protection System Instrumentation," Table 3.3.1-1 and Table 4.3.1.1-1, Functional Unit 11, "Reactor Mode Switch Shutdown Position," and Functional Unit 12, "Manual Scram," OPCON 5, are modified by a new note "q" which states, "With any control rod withdrawn from a core cell containing one or more fuel assemblies."

TS 3.9.1, which states, "The reactor mode switch shall be OPERABLE and locked in the Shutdown or Refuel Position," is revised to state, "The reactor mode switch shall be OPERABLE and locked in the Refuel Position." The TS 3.9.1 Applicability is OPCON 5 (as modified by footnotes

and **) and OPCONs 3 and 4 when the reactor mode switch is in the Refuel Position. It is revised to be applicable in OPCON 5 (as modified by footnotes

and **) and OPCONs 3 and 4. TS 3.9.1, Actions a and b, and SR 4.9.1.1 are revised to eliminate references to the reactor mode switch in the Shutdown position.

TS 3.9.10.2, "Multiple Control Rod Removal," and associated SR 4.9.10.2.1 refer to the reactor mode switch being locked in the Shutdown or Refuel position in accordance with Specification 3.9.1. References to the reactor mode switch being in the Shutdown position are removed.

The proposed change to TS 3.9.1 affects the LGS TS Bases. The regulation at Title 10 of the Code of Federal Regulations (10 CFR), Part 50.36, states, "A summary statement of the bases or reasons for such specifications, other than those covering administrative controls, shall also be included in the application, but shall not become part of the technical specifications." CEG may make changes to the TS Bases without prior NRC review and approval in accordance with the Technical Specifications Bases Control Program. The proposed TS Bases changes are consistent with the proposed TS changes.

Therefore, the Bases changes are provided for information only and approval of the Bases is not requested.

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 8 of 29 TS 3.3.4.1, "ATWS Recirculation Pump Trip Actuation Instrumentation," "Applicability" is revised to add a note stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the LCO is not applicable if specified conditions are met. A table with these conditions is included as part of the note.

SR 4.1.5.b.4 (i.e., "Standby Liquid Control System") is revised to add footnote (***) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), no pumps are required to start automatically.

TS Table 3.3.2-1, "Isolation Instrumentation," Trip Function 3.d, "SLCS Initiation," is revised to add footnote (h) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

SR Table 4.3.2.1-1, "Isolation Actuation Instrumentation Surveillance Requirements," Trip Function 3.d, "SLCS Initiation," is revised to add footnote (b) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the Reactor Water Cleanup (RWCU)

System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

In Attachment 2 several TS pages have been included that are not being changed. They are annotated as For Information Only. No Changes Proposed. They have been included to help facilitate NRC review.

3.0 TECHNICAL EVALUATION

3.1 Revise TS 3.5.2, "RPV WIC" Action a TS 3.5.2, "RPV WIC," requires at least one Core Spray System subsystem or Low Pressure Coolant Injection System subsystem to be operable to provide defense-in-depth should an unexpected draining event occur. The LGS TS Bases state that the purpose of LCO 3.5.2 is to ensure that if an unexpected draining event should occur, the reactor coolant water level remains above the top of the active irradiated fuel. Action a states that with none of the required subsystems being operable, immediate action must be taken to suspend Core Alterations, at least one subsystem must be restored within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , or an alternate method of water injection must be established. The Bases state that the actions are based on engineering judgment that considers the LCO controls on Drain Time and the low probability of an unexpected draining event that would result in loss of RPV water inventory.

The LGS TS definition of Core Alterations in the LGS TS states:

1.7 CORE ALTERATION shall be the movement of any fuel, sources, or reactivity control components within the reactor vessel with the vessel

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 9 of 29 head removed and fuel in the vessel. The following exceptions are not considered to be CORE ALTERATIONS:

a) Movement of source range monitors, local power range monitors, intermediate range monitors, traversing incore probes, or special moveable detectors (including under vessel replacement); and b) Control rod movement, provided there are no fuel assemblies in the associated core cell.

Suspension of CORE ALTERATIONS shall not preclude completion of movement of a component to a safe position.

Suspension of Core Alterations would have no effect on the initiation of a draining event or the ability to respond to a draining event. All requirements necessary to maintain the RPV water level above the TAF are established with the combination of a new TS definition for "Drain Time," a revised and renamed TS 3.5.2, "Reactor Pressure Vessel (RPV) Water Inventory Control, " and a new instrumentation TS 3.3.5.2, "Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation." Therefore, the proposed elimination of the requirement to suspend Core Alterations does not affect the prevention or mitigation of an unplanned RPV draining event. In the Safety Evaluation that approved TSTF-542 (Reference 6), the NRC confirmed this by stating:

"The revised STS LCO 3.5.2 contains requirements for operability of one ECCS subsystem along with requirements to maintain a sufficiently long drain time that plant operators would have time to diagnose and mitigate an unplanned draining event. The NRC staff has determined that the LCO 3.5.2 and 3.3.5.2 provide alternatives for the lowest functional capability or performance levels of equipment required for safe operation of the facility."

3.2 Incorporation of TSTF-582 and TSTF-583-T The LGS TS amendments to adopt TSTF-542 and TSTF-582 eliminated the requirements for automatic actuation of the required ECCS subsystem in OPCONs 4 and 5. The low pressure ECCS subsystem required to be operable by TS 3.5.2 must be capable of being manually started as a defense-in-depth against an unexpected draining event, but there is no assumption of a concurrent loss of offsite power. None of the accidents postulated to occur in OPCONs 4 or 5 that are analyzed in the Updated Final Safety Analysis Report assume a concurrent loss of offsite power (e.g., fuel handling accident involving irradiated fuel). There is no assumption in the accident analyses that the DGs will start and reach the required frequency and voltage within a specific time in OPCONs 4 and 5. There is also no assumption that electrical loads will be shed and loaded in sequence in OPCONs 4 and 5.

The LGS electrical design includes four independent emergency busses, each with its own DG. In OPCONs 1, 2, and 3, TS 3.8.1 requires four DGs to be operable. In Operational Conditions 4 and 5, TS 3.8.2 requires two DGs to be operable instead of the one DG

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 10 of 29 required in the STS. This design difference does not affect the applicability of the proposed change.

TSTF-582 revised STS SR 3.8.2.1, which is similar to LGS SR 4.8.1.2, to eliminate the requirement to meet SRs related to automatic start and loading of the required DG within a specific time on a loss of power signal or ECCS initiation signal, and eliminated the requirement to meet SRs related to load shedding and sequenced loading of the electrical busses in Modes 4 and 5. However, the LGS amendment request to adopt TSTF-582 did not include these changes.

TSTF-583-T expanded on the changes in TSTF-582 by eliminating the requirement for loss of voltage and degraded voltage signals be operable in Modes 4 and 5 as automatic DG start on loss of power was not required. TSTF-583-T also identified additional SRs that should have been excluded from SR 3.8.2.1.

The proposed amendment incorporates the TSTF-582 and TSTF-583-T changes into the LGS TS, as well as other STS SR 3.8.2.1 allowances.

Surveillance Requirements Not Applicable in Operational Conditions 4 and 5 The following table compares the LGS TS 3.8.1 SRs to the equivalent STS 3.8.1 SRs and their disposition in the STS following incorporation of TSTF-582 and TSTF-583-T.

Table 1 Comparison of LGS and STS AC Sources SRs LGS SR STS Required to be Met Proposed Exception Equivalent SR by STS SR 3.8.2.1? to LGS SR 4.8.1.2?

4.8.1.1.1.a 3.8.1.1 Yes No 4.8.1.1.1.b 3.8.1.8 No Yes 4.8.1.1.2.a.1 3.8.1.4 Yes No 4.8.1.1.2.a.2 3.8.3.1 N/A No 4.8.1.1.2.a.3 3.8.1.6 Yes No 4.8.1.1.2.a.4 3.8.1.2 Yes No 4.8.1.1.2.a.5 3.8.1.3 Yes No 4.8.1.1.2.a.6 None N/A No 4.8.1.1.2.a.7 3.8.3.4 N/A No 4.8.1.1.2.b.1 3.8.1.5 Yes No 4.8.1.1.2.b.2 3.8.3.5 N/A No 4.8.1.1.2.c 3.8.3.3 N/A No 4.8.1.1.2.d 3.8.3.3 N/A No 4.8.1.1.2.e.1 (deleted) N/A N/A N/A 4.8.1.1.2.e.2 3.8.1.9 Yes No 4.8.1.1.2.e.3 3.8.1.10 Yes No 4.8.1.1.2.e.4 3.8.1.11 No Yes 4.8.1.1.2.e.5 3.8.1.12 No Yes 4.8.1.1.2.e.6 3.8.1.19 No Yes 4.8.1.1.2.e.7 3.8.1.13 No Yes 4.8.1.1.2.e.8.a 3.8.1.14 Yes No

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 11 of 29 LGS SR STS Required to be Met Proposed Exception Equivalent SR by STS SR 3.8.2.1? to LGS SR 4.8.1.2?

4.8.1.1.2.e.8.b 3.8.1.15 No Yes 4.8.1.1.2.e.9 None N/A No 4.8.1.1.2.e.10 3.8.1.16 Yes No 4.8.1.1.2.e.11 3.8.1.17 No Yes 4.8.1.1.2.e.12 3.8.1.8 No Yes 4.8.1.1.2.e.13 None N/A No 4.8.1.1.2.f 3.8.1.20 No Yes 4.8.1.1.2.g None N/A No 4.8.1.1.2.h 3.8.1.7 No Yes 3.8.1.11 3.8.1.12 3.8.1.19 4.8.1.1.3 (deleted) N/A N/A N/A Each of the proposed exceptions to SR 4.8.1.2 is discussed below.

4.8.1.1.1.b This SR requires demonstration of manually and automatically transferring the unit power supply between the offsite transmission network and the onsite Class 1E distribution system from the normal circuit to the alternate circuit. LCO 3.8.1.2 only requires one circuit between the offsite transmission network and the onsite Class 1E distribution system to be operable in OPCONs 4 and 5. The STS SR 3.8.2.1 did not require this SR to be performed prior to incorporation of TSTF-582 and TSTF-583-T because only one offsite circuit is required to be operable in Modes 4 and 5. Therefore, this SR should not be required to be met by SR 4.8.1.2.

4.8.1.1.2.e.4 This SR simulates a loss of offsite power by deenergizing and load shedding the emergency busses, and verification that the DG automatically starts and reaches the required voltage and frequency within 10 seconds and runs for 5 minutes, as well as verifying auto connection of loads. DG start and loading on a loss of offsite power within a specified time and automatic load shedding and load connection, are not assumed in OPCONs 4 and 5. In these OPCONs, an operator can manually start a DG and connect the required loads in order to avoid immediate difficulty. Therefore, this SR should not be required to be met by SR 4.8.1.2.

4.8.1.1.2.e.5 This SR verifies that on an ECCS actuation signal the DG starts and reaches the required voltage and frequency within 10 seconds and auto connection of the appropriate loads, and runs for at least 5 minutes. The ECCS actuation signal is not required to be operable in OPCONs 4 and 5 (other than Loss of Power, which is discussed below). Therefore, this SR should not be required to be met by SR 4.8.1.2.

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 12 of 29 4.8.1.1.2.e.6 This SR simulates a loss of offsite power and an ECCS actuation signal by deenergizing and load shedding the emergency busses, and verification that the DG automatically starts and reaches the required voltage and frequency within 10 seconds and runs for 5 minutes, as well as verifying auto connection of loads. Automatic load shedding and load connection, and DG start and loading on a loss of offsite power is not assumed in OPCONs 4 and 5. In these OPCONs, an operator can manually start a DG and connect the required loads in order to avoid immediate difficulty. The ECCS actuation signal is not required to be operable in OPCONs 4 and 5 (other than Loss of Power, which is discussed below). Therefore, this SR should not be required to be met by SR 4.8.1.2.

4.8.1.1.2.e.7 This SR verifies that all automatic DG trips, except for critical trips, are bypassed on an ECCS actuation signal. The ECCS actuation signal is not required to be operable in OPCONs 4 and 5 (other than Loss of Power, which is discussed below). Therefore, this SR should not be required to be met by SR 4.8.1.2.

4.8.1.1.2.e.8.b This SR verifies that within 5 minutes of shutdown of the DG after operating at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months the DG will start and achieve the required voltage and frequency within 10 seconds. There are no accidents evaluated in OPCONs 4 and 5 that assume the DG starts and achieves the required voltage and frequency within 10 seconds. Therefore, this SR should not be required to be met by SR 4.8.1.2.

4.8.1.1.2.e.11 This SR verifies that with the DG operating in test mode and connected to the bus, an ECCS actuation signal will override the test mode, return the DG to standby condition, and automatically connect emergency loads to offsite power. The STS SR 3.8.2.1 did not require this SR to be performed prior to incorporation of TSTF-582 and TSTF-583-T because the required DGs are not required to undergo periods of being synchronized to the offsite circuit in OPCONs 4 and 5. In addition, the ECCS actuation signal is not required to be operable in OPCONs 4 and 5 (other than Loss of Power, which is discussed below). Therefore, this SR should not be required to be met by SR 4.8.1.2.

4.8.1.1.2.e.12 This SR verifies that the automatic load sequence timers are operable.

There are no accidents evaluated in OPCONs 4 and 5 that assume a loss of offsite power and the automatic sequencing of required loads on the emergency bus. In these OPCONs, an operator can manually start a DG and connect the required loads in order to avoid immediate difficulty.

Therefore, this SR should not be required to be met by SR 4.8.1.2.

4.8.1.1.2.f This SR requires starting all four DGs simultaneously and verifying they accelerate to the required speed within 10 seconds. Only two DGs are required to be operable in OPCONs 4 and 5 and there are no accidents evaluated in OPCONs 4 and 5 that assume the DG achieves the required

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 13 of 29 speed within 10 seconds. The STS SR 3.8.2.1 did not require this SR to be performed prior to incorporation of TSTF-582 and TSTF-583-T because starting independence is not required with the DGs that are not required to be operable. Therefore, this SR should not be required to be met by SR 4.8.1.2.

4.8.1.1.2.h This SR verifies that the DG starts and achieves the required voltage and frequency within 10 seconds based on a manual start, a simulated loss of offsite power, an ECCS actuation test signal, or both a simulated loss of offsite power and an ECCS actuation test signal. There are no accidents evaluated in OPCONs 4 and 5 that assume the DG starts and achieves the required voltage and frequency within 10 seconds. SR 4.8.1.1.2.a.4 verifies the manual starting of the DG and continues to be required to be met. Automatic load shedding and load connection, and DG start and loading on a loss of offsite power is not assumed in OPCONs 4 and 5. In these OPCONs, an operator can manually start a DG and connect the required loads. The ECCS actuation signal is not required to be operable in OPCONs 4 and 5 (other than Loss of Power, which is discussed below). Therefore, this SR should not be required to be met by SR 4.8.1.2.

In summary, SR 4.8.1.2 is revised to only verify the capabilities that are assumed to be operable in OPCONs 4 and 5.

Revise Applicability of Loss of Voltage and Degraded Voltage Functions TS 3.3.3-1, "Emergency Core cooling System Actuation Instrumentation," Table 3.3.3-1 Function 5.1, "4.16 kV Emergency Bus Under-Voltage (Loss of Voltage)," and Function 5.2, "4.1.6 kV Emergency Bus Under-voltage (Degraded Voltage)," are required to be operable in OPCONs 4 and 5. There are no accidents or transients postulated to occur in OPCONs 4 and 5 that assume a concurrent loss of offsite power and the automatic start of a DG. TSTF-583-T revised the Applicability of these functions to not be applicable in Modes 4 and 5 because there is no assumption that the DG will automatically start on a loss of power in these modes. This logic is equally applicable to LGS in OPCONs 4 and 5.

In these OPCONs, an operator can manually start a DG and connect the required loads assuming either a loss of all offsite power or a loss of all onsite DG power. Therefore, these functions should not be required to be operable in these OPCONs.

The change in the Applicability of Table 3.3.3-1 Functional Units 5.1 and 5.2 results in additional changes. Table 3.3.3-1 Note ***, which states, "The Minimum OPERABLE Channels per Trip Function is per subsystem," and which only applies to Functions 5.1 and 5.2 in OPCONs 4 and 5, is deleted as it is no longer referenced. Table 3.3.3-1, Actions 36 and 37, which are referenced only by Functional Units 5.1 and 5.2, both state

"... and take the ACTION required by Specification 3.8.1.1 or 3.8.1.2, as appropriate." As these functional units no longer share the same applicability as TS 3.8.1.2, the phrase is revised to state, "... and take the ACTION required by Specification 3.8.1.1." Table 4.3.3.1-1, Note **, which states, "Required OPERABLE when ESF equipment is required to be OPERABLE," and which only applies to Functions 5.a and 5.b in OPCONs 4 and 5

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 14 of 29 (the equivalent of Table 3.3.3-1 Functions 5.1 and 5.2) is deleted as it is no longer referenced. These changes are acceptable because they provide consistency within the TS.

3.3 Revise Reactor Mode Switch and Manual Scram OPCON 5 Applicability The purpose of the Functional Unit 11, "Reactor Mode Switch - Shutdown," and Functional Unit 12, "Manual Scram," in OPCON 5 is to provide a means for the reactor operator to rapidly insert all control rods into the reactor core. However, if all control rods are already inserted in all core cells that contain fuel assemblies, this function is not necessary. In the STS, these functions must be operable in Mode 5 only when any control rod is withdrawn from a core cell containing one or more fuel assemblies. The proposed change incorporates this STS allowance into the LGS TS to provide additional flexibility during a refueling outage.

In the LGS TS, if the "Reactor Mode Switch - Shutdown" Function is inoperable in OPCON 5, the Actions require suspending all operations involving Core Alterations and inserting all insertable control rods within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . If the "Manual Scram" Function is inoperable in OPCON 5, the Actions require suspending all operations involving Core Alterations, inserting all insertable control rods, and locking the reactor mode switch in the Shutdown position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The STS Action for either of these functions being inoperable is to immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies, which is consistent with the Applicability. Inserting control rods in core cells that do not contain fuel assemblies does not improve safety. Many actions to suspend Core Alterations were removed during the development of the STS, including the equivalent of the LGS TS Action when the Reactor Mode Switch or Manual Scram Functions are inoperable. The justification was that the refueling TS provide requirements to ensure safe operation during Core Alterations, including the required water level above the RPV flange. Inoperability of these functions does not affect safe performance of Core Alterations and prohibiting Core Alterations is not needed. The requirement to lock the reactor mode switch was also removed during development of the STS based on the justification that moving the reactor mode switch, and therefore any requirement to "lock" the switch, is controlled by plant procedures.

3.4 Revise Reactor Mode Switch Requirements During Refueling The purpose of LGS TS 3.9.1, "Reactor Mode Switch," is to require the refueling equipment interlocks are operable, which ensures that the restrictions on control rod withdrawal and refueling platform movement during the refueling operations are properly activated. These conditions reinforce the refueling procedures and reduce the probability of inadvertent criticality, damage to reactor internals or fuel assemblies, and exposure of personnel to excessive radioactivity. TS 3.9.1 requires the reactor mode switch to be locked in the Shutdown or Refuel positions, which is consistent with the standard TS on which the LGS TS are based (NUREG-0123). However, the LGS design only engages the refueling equipment interlocks when the reactor mode switch is in the Refuel position, and not in the Shutdown position. Locking the reactor mode switch in Shutdown does not satisfy the purpose of the TS.

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 15 of 29 The proposed change eliminates references to the reactor mode switch Shutdown position from the LCO, Applicability, Actions, and Surveillances in TS 3.9.1. This makes the requirements consistent with the LGS design.

This change is also consistent with the intent of the STS 3.9.1, "Refueling Equipment Interlocks." The STS specification is structured differently than the LGS TS, but the purpose of both is to ensure the refueling equipment interlocks are operable when required.

TS 3.9.10.2, "Multiple Control Rod Removal," and Surveillance 4.9.10.2.1 refer to the reactor mode switch being locked in the Shutdown or Refuel position in accordance with Specification 3.9.1. References to the reactor mode switch being in the Shutdown position are removed to be consistent with the proposed changes to TS 3.9.1.

3.5 One-Time LCO 3.3.4.1 Applicability Change for ATWS Recirculation Pump Trip Actuation Instrumentation,"

CEG plans to remove both divisions of LGS Unit 1 and Unit 2 RRCS from service 30 days prior to the start of the Unit 1 and Unit 2 refueling outages in 2024 and 2025, respectively (i.e., just prior to the digital modernization project installation).

RRCS is credited for ATWS mitigation within the approved LGS design and licensing basis. During the Applicability Change period, the RRCS digital logic system in the Auxiliary Equipment Room will be removed and space will be made to install new Plant Protection System equipment panels. The RRCS digital logic system will not be restored prior to entering the respective refueling outages. Removal of the RRCS digital logic system will result in the loss of the RRCS-initiated automatic functions for SLCS injection and associated RWCU isolation, ARI system actuation, ATWS-RPT actuation, and FWRB actuation. With the exception of the RRCS-initiated FWRB automatic actuation function, the loss of RRCS-initiated functions is governed by the LGS TS. Therefore, to enable this activity, CEG is proposing to revise the following TS:

TS 3.3.4.1, "ATWS Recirculation Pump Trip Actuation Instrumentation,"

"Applicability" to add a note stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the LCO is not applicable if specified conditions are met. A table with these conditions is included as part of the note.

SR 4.1.5.b.4 (i.e., "Standby Liquid Control System") to add footnote (***) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), no pumps are required to start automatically.

TS Table 3.3.2-1, "Isolation Instrumentation," Trip Function 3.d, "SLCS Initiation," to add footnote (h) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the Reactor Water Cleanup System Isolation on

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 16 of 29 SLCS Initiation Trip Function is not required to be OPERABLE.

SR Table 4.3.2.1-1, "Isolation Actuation Instrumentation Surveillance Requirements,"

Trip Function 3.d, "SLCS Initiation," to add footnote (b) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

The purpose of requesting these proposed one-time TS changes is to reduce the scope of scheduled work during the refueling outage that will be required during installation of the digital modernization project, which is described in Reference 1. It is estimated that at least an additional 8 days would be added to the refuel outage length if the RRCS demolition could not take place on-line prior to the start of the refuel outage.

Although the evolution requiring the TS changes will result in loss of automatic RRCS-initiated functions that are credited for ATWS mitigation, and in addition to the power and operational flexibility restrictions listed in Section 3.5.2, the following automatic and manual functions will be available to supplant those functions that are lost during the extended AOT, and therefore would be available to mitigate an ATWS event:

A non-safety related automatic reactor recirculation pump (RRP) runback on low reactor water Level 3 with more than the minimum analyzed 12 operable Main Steam Relief Valves (MSRVs) operable. This will supplant the ATWS-RPT trip function.

The Manual start of the SLCS pumps from the main control room no later than 5 minutes post-event, which will supplant the automatic SLCS initiation function.

A redundant RWCU automatic isolation signal on low reactor water Level 2 which will supplant the RRCS-initiated RWCU isolation function. In addition, RWCU isolation on manual SLCS initiation also will still function. When SLCS is manually initiated by the operator the RWCU isolation valves also will close as the isolation logic is directly in the pump breaker logic and is not impacted by RRCS being out of service and insures under SLCS manual initiation the boron is not removed by the RWCU demineralizers.

3.5.1. ATWS Deterministic Supplemental Analysis The current ATWS analysis-of-record (AOR) for Limerick (LGS) is the Thermal Power Optimization (TPO) ATWS analysis (0000-0097-1195). CEG has performed a deterministic supplemental Limerick ATWS analysis to demonstrate compliance with ATWS acceptance criteria without RRCS. The purpose of the supplemental analysis is to deterministically justify removal of both divisions of RRCS from service while still satisfying all of the ATWS analysis acceptance criteria and identify any operating restrictions during end of cycle operation. The automatic initiation of SLCS, automatic trip of the Recirculation Pumps, automatic feedwater runback (FWRB) actuation, automatic Alternate Rod Injection (ARI) actuation and automatic isolation of RWCU PCIVs provided by RRCS are unavailable during this proposed evolution. For the ARI and FWRB functions, neither are credited in the supplemental analysis. Successful automatic ARI actuation has never

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 17 of 29 been credited in any LGS ATWS analyses, since if functional, ATWS mitigation would not need SLCS injection. While the FWRB function is modeled in the LGS ATWS AOR, later supplemental analyses demonstrated that modeling this system does not impact the analysis conclusions. Therefore, consistent with the most recent LGS ATWS analysis basis, ARI and FWRB actuation were not included in the supplemental deterministic evaluation to provide bounding results.

The TPO ATWS supplemental analysis is provided in Attachment 4 (proprietary version) and Attachment 5 (non-proprietary version). This supplemental analysis assumed that all automatic RRCS functions were not available during the 30 day-RRCS demolition period.

The ATWS AOR assumed two safety relief valves out of service (SRVOOS). To mitigate the anticipated peak vessel pressure increase due to lack of RRCS ATWS RPT high pressure trip function and the suppression pool temperature increase due to delayed SLCS injection, sensitivity studies were performed with 1 and 0 SRVOOS and at lower plant power levels to support this evolution during end-of-cycle operation. In addition, the sensitivity analysis utilized the following parameters:

1. The SLCS manual initiation timing was extended to 5 minutes post-event to provide adequate time to implement this operator manual action.

2. The suppression pool temperature limit assumed in the analysis was increased from 190°F to 200°F to remain within the bounds of the LGS Design Basis Accident (DBA) Loss of Coolant (LOCA) containment analysis.

3. The non-safety related automatic RRP runback on low reactor water Level 3 is functional.

4. The Residual Heat Removal (RHR) system heat removal effectiveness value (K) was increased from 289 to 305 BTU/sec-F to establish consistency with the LGS DBA LOCA containment analysis.

3.5.2. ATWS Sensitivity Analysis Results The Supplemental ATWS Analysis (i.e., Attachments 4 and 5) considered all potentially limiting ATWS scenarios from the LGS ATWS AOR for End-of-Cycle (EOC) operation due to planned duration of the proposed change just before the outage. These limiting events are the Main Steam Isolation Valve Closure (MSIVC), Pressure Regulator Failure (PRFO),

and Loss of Offsite Power (LOOP) events. These were reanalyzed, consistent with the ATWS AOR parameters, the additional inputs, and the constraints described above. The Supplemental ATWS Analysis documents the results for these scenarios with the required thermal power set down and the SRVOOS flexibility assumed in the analysis (0 or 1 SRVOOS) to meet the 10CFR50.62 acceptance criteria (Tables 1, 2, and 3 of Attachment 4). The same report also documents the results from the ATWS AOR and their reruns with the most up to date code version for these scenarios.

This Supplemental Analysis demonstrates that, with additional constraints imposed on operation, the station can mitigate an ATWS event and demonstrates compliance with the acceptance criteria, i.e., the operational constraints listed in this analysis eliminates the

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 18 of 29 need for the RRCS automatic functionality. Analysis Summary - Table 1 summarizes conclusions of this Supplemental Analysis:

Analysis Summary - Table 1: Required Operational Constraints Supported Reactor # of OOS Manual initiation Suppression Pool Additional system Thermal Power SRVs time for SBLC Water Level credited 87 % 0 5 minutes 22 feet RRB on L3 84 % 1 5 minutes 22 feet RRB on L3 90 % 0 5 minutes 23 feet RRB on L3 For the listed conditions in the Analysis Summary - Table 1, as long as the reactor thermal power level is less than or equal to the corresponding listed power level, the credited automatic Recirculation Runback (RRB) function on reactor water level (L3) is operational, and manual SLCS injection is started in 5 minutes, the station can mitigate an ATWS event and demonstrate compliance with the acceptance criteria with RRCS out of service.

For the case with no SRVOOS, the limiting PRFO event is limited by the suppression pool temperature. At 87% power, all acceptance criteria, including suppression pool temperature, are met. At 88% power, not shown, the suppression pool limit of 200°F is exceeded.

For the case with 1 SRVOOS, the limiting PRFO event was limited by both peak vessel pressure and suppression pool temperature. At 84% power, all acceptance criteria are met. At 85% power, not shown, both the peak vessel pressure and suppression pool limits are exceeded. The same analysis also documents that if suppression pool level is maintained at or above 23 feet (i.e., mid-permissible TS operating band) instead of the assumed TS minimum level of 22 feet, a reactor thermal power level of 90% is justified with all 14 MSRVs operable.

The results of the ATWS Supplemental Analysis are applicable to either LGS Unit 1 or Unit 2 at the reactor power level with cores of fresh GNF3 fuel including mixed cores with GNF2 fuel, for the end-of-cycle operation only. These results are intended to apply during the time of when RRCS is out of service, assuming no major plant changes. The results of this supporting ATWS analysis do not replace the current LGS ATWS AOR.

3.5.3. SRV Performance History Target Rock Stage 3 SRVs are installed at LGS. Regarding any potential for SRVs not operating within their setpoint bands, the GEHs ATWS methodology results in conservative modeling of the SRV setpoints (by modeling the opening setpoint at a

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 19 of 29 conservative upper analytical limit). The treatment of the SRVs within the ODYN model is also plant specific. For Limerick, the SRV setpoints within the analysis model are statistically spread about the upper analytical limit setpoints, which accounts for variation in plant SRV functionality as well as instrument drift.

This statistical treatment of SRV setpoints is approved in NEDC-24154P-A, Revision 1, (Supplement 1 - Volume 4), Qualification of the One-Dimensional Core Transient Model (ODYN) for Boiling Water Reactors, February 2000. The input selection, uncertainty in inputs, and direction of conservatism are all taken care of within the approval basis of the applied methodology and captured in GE design procedures for ATWS. In addition, when SRVs are taken out-of-service, the lowest opening setpoints are conservatively selected first for added conservatism in the applied methodology.

Limerick installed 3 stage SRVs and they do not have setpoint drift issues outside their prescribed set point tolerances.

3.5.4. Operator Actions during ATWS Conditions Symptom-based Emergency Operating Procedures (EOPs), titled Transient Response Implementation Procedures (TRIPs) at LGS, provide appropriate response to an ATWS condition. One of the entry conditions to LGS EOP T-101, "RPV Control" (Reference 17) is a reactor scram condition with power not downscale. The first action step in T-101 directs operators to manually scram the reactor if a scram has not occurred using all available means from the reactor control console. If reactor power remains above the downscale setpoint, manual ATWS mitigating actions are directed by the next T-101 step which include rapidly lowering RPV water level manually and ensuring SLCS injection and RWCU isolation. While the Recirculation pumps will not trip automatically, a low-speed runback will still automatically occur when RPV water level decreases below +12.5 inches which will reduce core flow and limit reactor power until subsequent EOP steps which direct ensuring the Reactor Recirculation Pumps are tripped.

Once initial ATWS actions are performed per T-101, operators are directed to enter T-117, "ATWS RPV Control," (Reference 18) where additional guidance for inadequate automatic system operation is provided with the phrase: "Ensure as appropriate." The phrase "Ensure as appropriate" encompasses failure of automatic actions that should have occurred including ensuring the Reactor Recirculation pumps are tripped. During the 30-day demolition period where RRCS is inoperable there exists alternative manual operator actions, independent of RRCS, to trip the Recirculation Pumps, initiate SLCS and isolate RWCU, and manually lowering RPV water level. In addition, credit has been given in the supporting ATWS Analysis for the Recirculation Pump runback which will occur on reactor level 3, (+ 12.5 inches). Operations personnel will be briefed daily during the 30-day RRCS demolition period on T-101 and T-117 ATWS actions and the required manual operator actions that would be required, in lieu of RRCS automatic action, to trip the Recirculation Pumps, initiate SLCS and RWCU isolation, and to manually lower RPV water level.

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 20 of 29 Regarding the SLCS manual operator initiation extension to 5 minutes, there is currently not a credited manual operator action for manual initiation of SLCS in an ATWS condition in the LGS Operator Response Time Program per OP-AA-102-106. Operators are trained to manually initiate SLCS during initial and continuing training per the EOPs, but since it is not currently a credited manual action no formal times were documented historically per the Operator Response Time Program. The LGS Operators Response Time Program defines a "Time Critical Action" (TCA) as "time-constrained manual actions which are credited in the safety analyses as part of the primary success path for mitigating design basis accidents." Since the supplemental analysis performed to support the safety case of removing RRCS from service prior to the installation outage assumes that SLCS is manually initiated within 5 minutes of the event as a TCA (as defined in the LGS Operator Response Time Program), this manual action will be added to the LGS Operator Response Time Program per OP-AA-102-106 (Reference 16). Initial validation with an operating crew in the simulator showed that operators can reliably initiate SLCS within 5 minutes of the occurrence of an ATWS condition. Full validation of this new TCA will be completed per OP-AA-102-106 by May 31, 2023.

3.5.5. Risk Insights:

This license amendment request is not a risk-informed request and, therefore, a risk evaluation is not required. However, to provide additional information, CEG is providing risk insights related to the proposed change.

Although this proposed one-time TS 3.3.4.1 LCO Applicability Note condition for a 30-day period extension is based on a deterministic sensitivity analysis, CEG conducted a risk analysis (Reference 15). This analysis evaluated the acceptability, from a risk perspective, of a change to the LGS Unit 1 and Unit 2 TS to allow for removal of RRCS Logic Controllers prior to the refueling outage. The removal of the RRCS Logic Controllers does remove the RRCS initiated Standby Liquid Control (SLC) injection but does not affect manual SLC injection; therefore, SLC remains operable.

The risk analysis demonstrated with reasonable assurance that the proposed TS changes are within the current risk acceptance guidelines in RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications," Revision 2, January 2021, for one-time changes. This ensures that the TS change meets the intent of the incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP) acceptance guidelines of 1.0E-05 (actual 2E-08 for Unit 1 and 2E-08 for Unit 2) and 1.0E-06 (actual 2E-09 for Unit 1 and 2E-09 for Unit 2) established for compatibility with the ICCDP and ICLERP limits of RG 1.177. This acceptance guideline is applicable for configuration changes that require normal work controls.

Additional insights from PRA modeling of three specific operator actions indicate that 5-minute operator action response time is within the bounds of existing scenarios. The following three scenarios (early, later (non-isolation), later) modeled are listed below with the required time frames for manual operator action to initiate SLCS depending on the accident type:

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 21 of 29 Early - 6 minutes before irreversible damage state Later (non-isolation events) - 40 minutes before irreversible damage state Later- 16 minutes before irreversible damage state

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria 10 CFR 50.36, "Technical Specifications," paragraph (b) requires:

"Each license authorizing operation of a utilization facility will include technical specifications. The technical specifications will be derived from the analyses and evaluation included in the safety analysis report, and amendments thereto, submitted pursuant to [10 CFR] 50.34 ["Contents of applications; technical information"]. The Commission may include such additional technical specifications as the Commission finds appropriate."

10 CFR 50.62, "Requirements for reduction of risk from anticipated transients without scram (ATWS) events for light-water-cooled nuclear power plants," requires, in part, that each boiling water reactor:

Must have an alternate rod injection (ARI) system that is diverse (from the reactor trip system) from sensor output to the final actuation device.

Must have a standby liquid control system (SLCS) with the capability of injecting into the reactor pressure vessel a borated water solution at such a flow rate, level of boron concentration and boron-10 isotope enrichment, and accounting for reactor pressure vessel volume, that the resulting reactivity control is at least equivalent to that resulting from injection of 86 gallons per minute of 13 weight percent sodium pentaborate decahydrate solution. The SLCS initiation must be automatic and must be designed to perform its function in a reliable manner Must have equipment to trip the reactor coolant recirculating pumps automatically under conditions indicative of an ATWS. This equipment must be designed to perform its function in a reliable manner.

LAR Attachment 7 provides a justification for a temporary exemption for above requirements for a period of 30 days prior to the start of the refuel outage in which the DMP PPS will be installed. A GNF Supplemental ATWS Analysis has shown that additional specific operational constraints and additional manual operator action guidelines imposed prior to removing the RRCS will ensure during the requested exemption period the consequences, should an ATWS occur, will remain within the acceptance criteria of the current analysis ATWS Analysis of Record.

10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," requires that whenever a holder of a license desires to amend the license,

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 22 of 29 application for an amendment must be filed with the Commission, fully describing the changes desired, and following as far as applicable, the form prescribed for original applications. The proposed changes do not affect LGSs compliance with the intent of 10 CFR 50.90.

10 CFR 50.92, "Issuance of amendment," paragraph (a) states that when determining whether an amendment to a license will be issued to the applicant, the Commission will be guided by the considerations which govern the issuance of initial licenses to the extent applicable and appropriate. The proposed changes do not affect LGSs compliance with the intent of 10 CFR 50.92.

Section IV, "The Commission Policy," of the "Final Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors" (58 FR 39132), dated July 22, 1993, states in part that improved Standard Technical Specifications (STS) have been developed and will be maintained for each Nuclear Steam Supply System owners group.

The Commission Policy encourages licensees to use the improved STS as the basis for plant-specific Technical Specifications.

The industry's proposal of Technical Specifications Task Force (TSTF) travelers and the NRC's approval of travelers is the method used to maintain the improved STS as described in the Commission's Policy. Following NRC approval, licensees adopt STS features into their plant-specific technical specifications following the requirements of 10 CFR 50.90. Therefore, the STS and the traveler process facilitate the Commission's policy while satisfying the requirements of the applicable regulations.

The regulation at 10 CFR 50.36(a)(1) also requires the application to include a "summary statement of the bases or reasons for such specifications, other than those covering administrative controls. The proposed changes do not affect LGSs compliance with the intent of the Final Policy Statement on Technical Specification Improvements for Nuclear Power Reactors.

4.2 No Significant Hazards Consideration Analysis In accordance with 10 CFR 50.90, Constellation Energy Generation, LLC (CEG) requests an amendment to Appendix A, "Technical Specifications" (TS) of Renewed Facility Operating License Nos. NPF-39 and NPF-85 for Limerick Generating Station (LGS), Units 1 and 2, respectively. The proposed TS changes will establish consistency with the LGS accident analysis and the plant design and support the installation of a digital modification at LGS Unit1 and Unit 2 during upcoming refueling outages.

The proposed LGS Unit 1 and Unit 2 TS changes will:

1. Revise TS 3.5.2, "RPV WIC," Action a to eliminate the requirement to immediately suspend Core Alterations. The revised Action states, "With none of the above required subsystems OPERABLE, restore at least one subsystem to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Otherwise, initiate action to establish a method of water injection capable of operating without offsite electrical power.

2. Revise TS 3.3.3-1, "Emergency Core cooling System Actuation Instrumentation,"

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 23 of 29 Table 3.3.3-1 Function 5.1, "4.16 kV Emergency Bus Under-Voltage (Loss of Voltage)," and Function 5.2, "4.1.6 kV Emergency Bus Under-voltage (Degraded Voltage)," to eliminate the requirement for the functions to be operable in Operational Conditions 4 and 5. The applicability of OPCON 1, 2, and 3 is retained. Table 3.3.3-1 Note **, which states, "Required when ESF equipment is required to be OPERABLE," and only applies to Functions 5.1 and 5.2 in OPCONs 4 and 5, is deleted.

3. Revise TS Table 3.3.3-1, Actions 36 and 37, to state, "... and take the ACTION required by Specification 3.8.1.1." Table 4.3.3.1-1 labels these functions as 5.a and 5.b and is also revised to eliminate the requirement for the functions to be operable in OPCONs 4 and 5. Table 4.3.3.1-1, Note **, which states, "Required OPERABLE when ESF equipment is required to be OPERABLE," and which only applies to Functions 5.a and 5.b in OPCONs 4 and 5, is deleted.

4. Modify Surveillance Requirement (SR) 4.8.1.2, which states, "At least the above required A.C. electrical power sources shall be demonstrated OPERABLE per Surveillance Requirements 4.8.1.1.1 and 4.8.1.1.2," by adding ,"except for 4.8.1.1.1.b, 4.8.1.1.2.e.4, 4.8.1.1.2.e.5, 4.8.1.1.2.e.6, 4.8.1.1.2.e.7, 4.8.1.1.2.e.8.b, 4.8.1.1.2.e.11, 4.8.1.1.2.e.12, 4.8.1.1.2.f, and 4.8.1.1.2.h."

5. Modify TS 3.3.1.1, "Reactor Protection System Instrumentation," Table 3.3.1-1 and Table 4.3.1.1-1, Functional Unit 11, "Reactor Mode Switch Shutdown Position," and Functional Unit 12, "Manual Scram," OPCON 5, with a new note "q" which states, "With any control rod withdrawn from a core cell containing one or more fuel assemblies."

6. Revise TS 3.9.1, Limiting Condition for Operation (LCO) to state, "The reactor mode switch shall be OPERABLE and locked in the Refuel Position." The TS 3.9.1 Applicability is OPCON 5 (as modified by footnotes

and **) and OPCONs 3 and 4 when the reactor mode switch is in the Refuel Position. It is revised to be applicable in OPCON 5 (as modified by footnotes

and **) and OPCONs 3 and 4. TS 3.9.1, Actions a and b, and SR 4.9.1.1 are revised to eliminate references to the reactor mode switch in the Shutdown position.

7. Revise TS 3.9.10.2, "Multiple Control Rod Removal," and SR 4.9.10.2.1 to remove references to the reactor mode switch being locked in the Shutdown position in accordance with Specification 3.9.1.

8. Revise TS 3/4.3.4.1, "ATWS Recirculation Pump Trip Actuation Instrumentation,"

"Applicability" to add a note stating that for a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the LCO is not applicable if specified conditions are met. A table with these conditions is included as part of the note.

9. Revise SR 4.1.5.b.4 (i.e., "Standby Liquid Control System") to add footnote (***)

stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2),

no pumps are required to start automatically.

10. Revise TS Table 3.3.2-1, "Isolation Instrumentation," Trip Function 3.d, "SLCS Initiation," to add footnote (h) stating that for a period of 30 days preceding exit from

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 24 of 29 OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

11. Revise SR Table 4.3.2.1-1, "Isolation Actuation Instrumentation Surveillance Requirements," Trip Function 3.d, "SLCS Initiation," to add footnote (b) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage (Unit 1) and 2025 refueling outage (Unit 2), the Reactor Water Cleanup (RWCU) System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

CEG has evaluated whether a significant hazards consideration is involved with the proposed amendment by focusing on the three conditions set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

Change Numbers 1 through 7 The proposed changes revise TS requirements, actions, and testing during cold shutdown and refueling to be consistent with the accident analysis and the plant design.

The proposed changes do not change any of the previously evaluated accidents in the Updated Final Safety Analysis Report (UFSAR). None of the accidents previously evaluated in OPCON 4 or 5 assume a concurrent loss of offsite power or automatic ECCS initiation. None of the accidents previously evaluated in OPCONs 4 and 5 assume automatic starting of a diesel generator or automatic sequencing of loads on the emergency busses. None of the accidents previously evaluated in OPCON 4 or 5 assume a manual reactor scram during refueling. None of the accidents previously evaluated assume the reactor equipment interlocks are engaged with the reactor mode switch in Shutdown. Therefore, elimination of these requirements from the TS will have no effect on the likelihood of an accident previously evaluated nor their mitigation.

Elimination of the requirement to suspend core alterations with no operable ECCS subsystem in OPCON 4 or 5 will not affect the initiation of a draining event nor its mitigation.

Therefore, proposed change numbers 1 through 7 do not involve a significant increase in the probability or consequences of an accident previously evaluated.

Change Numbers 8 through 11 The proposed changes establish a one-time Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) LCO Applicability condition where ATWS-RPT is not required for 30 days under certain plant operational constraints for both channels of ATWS-RPT instrumentation, as well as the applicability and surveillance requirements for the associated Standby Liquid Control System (SLCS) and the Reactor Water Cleanup (RWCU) isolation instrumentation. The ATWS-RPT instrumentation, the SLCS,

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 25 of 29 and RWCU instrumentation are mitigative systems and components. As such, the proposed changes do not impact any accident or event precursors. The probability of an ATWS event occurring does not increase due to this proposed change.

Therefore, proposed change numbers 8 through 11 do not involve a significant increase in the probability of an accident previously evaluated.

The consequences of the ATWS are not increased since the plant will be operating at a reduced power level during the 30 days when ATWS-RPT system is inoperable. The most severe/limiting ATWS events are initiated by a pressurization transient. With SCRAM failure, a pressurization transient can result in a large power spike which may be significantly higher than rated power. The large increase in power exacerbates vessel pressurization.

CEG performed a deterministic sensitivity analysis of the LGS Thermal Power Optimization (TPO) ATWS analysis-of-record (AOR) at a reduced power level to demonstrate compliance with ATWS acceptance criteria. This sensitivity analysis assumed that the capability for automatic initiation of SLCS, automatic trip of the Recirculation Pumps, and automatic feedwater runback (FWRB) actuation was unavailable. In addition, because of the low likelihood that acceptable peak vessel pressure results will occur without the ATWS-RPT high pressure trip function, the sensitivity analysis studies were performed with one and zero safety relief valves out of service (SRVOOS), as opposed to the ATWS AOR assumption of two SRVOOS. In addition, the sensitivity analysis utilized the following assumptions:

1. Manual initiation of SLCS post-ATWS event

2. Increased suppression pool temperature limit

3. Operability of the non-safety related automatic reactor recirculation pump (RRP) runback on low reactor water Level 3

4. Increased Residual Heat Removal (RHR) system heat removal effectiveness value (K).

The deterministic ATWS sensitivity analysis at a reduced reactor power level demonstrates that all ATWS criteria are satisfied during the proposed one-time ATWS-RPT LCO Applicability condition when the existing designed automatic ATWS-RPT system is out of service.

Therefore, proposed change numbers 8 through 11 do not involve a significant increase in the consequences of an accident previously evaluated.

2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

Change Numbers 1 through 7

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 26 of 29 The proposed changes revise TS requirements, actions, and testing during cold shutdown and refueling to establish consistency with the accident analysis and the plant design. The proposed changes do not change the assumed design functions of the affected systems in the applicable OPCONs. The proposed changes do not create any credible new accidents as the associated initiating events, such as loss of power and a draining event, are already considered in the licensing basis.

Change Numbers 8 through 11 The proposed changes establish a one-time ATWS-RPT LCO Applicability condition where ATWS-RPT is not required for 30 days under certain plant operational constraints for both channels of ATWS-RPT instrumentation, as well as the applicability and surveillance requirements for the associated SLCS and the RWCU isolation instrumentation. These changes impact a mitigating system for an existing transient. As such, the unavailability of this mitigation system would not be considered an initiator of a new or different kind of accident.

Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.

3. Does the proposed amendment involve a significant reduction in a margin of safety?

Response: No.

Change Numbers 1 through 7 The proposed changes revise TS requirements, actions, and testing during cold shutdown and refueling to be consistent with the accident analysis. The proposed changes do not affect the analysis of any accident or event in the plants licensing basis.

The proposed changes do not alter any design basis or safety limit, or any controlling numerical values for parameters established in the UFSAR or the license.

Change Numbers 8 through 11 Based on a deterministic sensitivity analysis of the ATWS AOR, the proposed changes will not cause a significant reduction in the margin of safety provided that the plant is operated at a reduced thermal power level.

The use of available safety related and non-safety related equipment during the 30-day RRCS demolition period, at a reduced power level, will continue to protect the fuel, reactor, and containment from failure during a postulated ATWS event. The fuel cladding barrier is protected via adequate cooling and SLCS injection. The reactor coolant system boundary is protected by ensuring compliance with the ASME emergency class pressure limit of 120% of design pressure. The containment is protected by ensuring the suppression pool pressure and temperature limits are met.

Thus, there is no need for any reduction in the margin of safety established in the LGS design and licensing basis for the primary fission product barriers.

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 27 of 29 Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above, CEG concludes that the proposed amendments do not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.

4.3 Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

The proposed changes would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR Part 20, and would change an inspection or surveillance requirement. However, the proposed changes do not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed changes meet the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed changes.

6.0 REFERENCES

1. Constellation Energy Generation, LLC (CEG) letter to the U.S. Nuclear Regulatory Commission (NRC), "License Amendment Request to Revise the Licensing and Design Basis to Incorporate the Replacement of Existing Safety-Related Analog Control Systems with a Single Digital Plant Protection System (PPS)," dated September 26, 2022 (NRC Agencywide Documents Access and Management System (ADAMS)

Accession No. ML22269A5690)

2. CEG Presentation Slides, "Non-Proprietary Presentation for March 31, 2022 Pre-submittal Meeting with Constellation Energy Generation, LLC Regarding Planned Digital Modernization License Amendment Request for Limerick Generating Station, Units 1 and 2," dated March 21, 2022 (ADAMS Accession No. ML22080A152)

3. CEG Presentation Slides, "Non-Proprietary Presentation for June 9, 2022 Pre-Submittal Meeting with Constellation Energy Generation, LLC Regarding Planned Digital Modernization License Amendment Request for Limerick Generating Station, Units 1 and 2," dated June 9, 2022 (ADAMS Accession No. ML22153A360)

4. CEG Presentation Slides, Limerick Generating Station Digital Modernization LAR Pre-submittal Meeting, dated September 8, 2022 (ADAMS Accession No. ML22249A097)

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 28 of 29

5. CEG Presentation Slides, Limerick Generating Station Digital Modernization (DMP)

Installation Support LAR and Exemption Request, dated January 10, 2023 (ADAMS Accession No. ML23006A257)

6. Letter from Alexander R. Klein (NRC) to the Technical Specifications Task Force, "Final Safety Evaluation of Technical Specifications Task Force Traveler TSTF-542, Revision 2, 'Reactor Pressure Vessel Water Inventory Control (TAC No. MF3487),

dated December 20, 2016 (ADAMS Accession No. ML16343B066)

7. Letter from J. Barstow (Exelon Generation Company, LLC (EGC)) to NRC Document Control Desk, "Application to Revise Technical Specifications to Adopt TSTF-542,

'Reactor Pressure Vessel Water Inventory Control,' Revision 2," dated July 19, 2017 (ADAMS Accession No. ML17200D096)

8. Letter from D.P. Helker (EGC) to NRC Document Control Desk, "Response to Request for Additional Information, "Application to Revise Technical Specifications to Adopt TSTF-542, 'Reactor Pressure Vessel Water Inventory Control,' Revision 2," dated December 6, 2017 (ADAMS Accession No. ML18017A201)

9. Letter from V. Sreenivas (NRC) to Bryan C. Hanson (EGC), "Limerick Generating Station, Units 1 and 2 - Issuance of Amendment Nos. 227 and 190 Revising Technical Specifications to Adopt TSTF-542, Revision 2, 'Reactor Pressure Vessel Water Inventory Control' (CAC Nos. MF9967 and MF9968; EPID L-2017-LLA-0260)," (ADAMS Accession No. ML18017A201), dated February 27,2018

10. Letter from Victor G. Cusumano (NRC) to the Technical Specifications Task Force, "Final Safety Evaluation of Technical Specifications Task Force Traveler TSTF-582, Revision 0, RPV WIC Enhancements' Using the Consolidated Line Item Improvement Process (EPID L-2019-PMP-0199)," dated August 13, 2020 (ADAMS Accession No. ML20223A000)

11. Letter from Victor Cusumano (NRC) to the Technical Specifications Task Force, "Model Safety Evaluation of Technical Specifications Task Force Traveler TSTF-582, Revision 0, 'RPV WIC Enhancements' and TSTF-583-T, Revision 0, 'TSTF-582 Diesel Generator Variation,' Using the Consolidated Line Item Improvement Process," dated October 9 2020 (ADAMS Accession No. ML20266G291)

12. Letter from David P. Helker (EGC) to NRC Document Control Desk, "Application to Revise Technical Specifications to Adopt TSTF-582, Revision 0 'Reactor Pressure Vessel Water Inventory Control (RPV WIC) Enhancements' ", dated September 3, 2020 (ADAMS Accession No. ML20247J372)

13. Letter from V. Sreenivas (NRC) to David P. Rhoades (EGC), "Limerick Generating Station, Units 1 and 2 Issuance of Amendment Nos. 252 and 214 Re: Technical Specification Changes Related to Adopt Technical Specifications Task Force Traveler TSTF-582, Revision 0, 'RPV WIC Enhancements' (EPID L-2020-LLA-0199)," (ADAMS Accession No. ML21032A270), dated February 22, 2021

14. NEDC-31681, "Improved BWR Technical Specifications," Volume 4, April 1989

15. LG-LAR-031, "Risk Assessment Input for the Limerick One-Time Technical Specification Change for the RRCS Pre-Outage Removal," Rev 0, dated July 19, 2022

License Amendment Request Limerick Generating Station, Units 1 and 2 Page 29 of 29

16. CEG Procedure, OP-AA-102-106, "Operator Response Time Program," Revision 8 CEG Procedure, OP-LG-102-106. "Operator Response Time Program at Limerick Station," Revision 13

17. CEG Procedure, T-101, "RPV Control," Revision 28

18. CEG Procedure, T-117, "ATWS RPV Control," Revision 23

Attachment 2 License Amendment Request Limerick Generating Station, Units 1 and 2 Docket Nos. 50-352 and 50-353 Technical Specification Page Markups TS Pages, Unit 1 3/4 1-19 (For Information Only) 3/4 3-36a 3/4 1-20 3/4 3-41 3/4 1-21 (For Information Only) 3/4 3-42 3/4 3-3 3/4 3-43 (For Information Only) 3/4 3-4 3/4 3-44 (For Information Only) 3/4 3-5 3/4 5-6 3/4 3-8 3/4 8-3 (For Information Only) 3/4 3-8a 3/4 8-4 (For Information Only) 3/4 3-9 (For Information Only) 3/4 8-5 (For Information Only) 3/4 3-10 (For Information Only) 3/4 8-6 (For Information Only) 3/4 3-12 3/4 8-7 (For Information Only) 3/4 3-16 (For Information Only) 3/4 8-7a (For Information Only) 3/4 3-17 3/4 8-9 3/4 3-28 3/4 9-1 3/4 3-31 3/4 9-2 3/4 3-34 3/4 9-15 3/4 3-35 3/4 9-16 3/4 3-36 TS Pages, Unit 2 3/4 1-19 (For Information Only) 3/4 3-36a 3/4 1-20 3/4 3-41 3/4 1-21 (For Information Only) 3/4 3-42 3/4 3-3 3/4 3-43 (For Information Only) 3/4 3-4 3/4 3-44 (For Information Only) 3/4 3-5 3/4 5-6 3/4 3-8 3/4 8-3 (For Information Only) 3/4 3-8a 3/4 8-4 (For Information Only) 3/4 3-9 (For Information Only) 3/4 8-5 (For Information Only) 3/4 3-10 (For Information Only) 3/4 8-6 (For Information Only) 3/4 3-12 3/4 8-7 (For Information Only) 3/4 3-16 (For Information Only) 3/4 8-7a (For Information Only) 3/4 3-17 3/4 8-9 3/4 3-28 3/4 9-1 3/4 3-31 3/4 9-2 3/4 3-34 3/4 9-15 3/4 3-35 3/4 9-16 3/4 3-36

For Information Only. No Changes Proposed.

REACTIVITY CONTROL SYSTEMS 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.1.5 The standby liquid control system shall be OPERABLE and consist of the following:

a. In OPERATIONAL CONDITIONS 1 and 2, two pumps and corresponding flow paths,

b. In OPERATIONAL CONDITION 3, a minimum of one pump and corresponding flow path.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3 ACTION:

a. With only one pump and corresponding explosive valve OPERABLE, in OPERATIONAL CONDITION 1 or 2, restore one inoperable pump and corresponding explosive valve to OPERABLE status within 7 days or in accordance with the Risk Informed Completion Time Program, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With standby liquid control system otherwise inoperable, in OPERATIONAL CONDITION 1, 2, or 3, restore the system to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.5 The standby liquid control system shall be demonstrated OPERABLE:

a. In accordance with the Surveillance Frequency Control Program by verifying that:

1. The temperature of the sodium pentaborate solution is within the limits of Figure 3.1.5-1.

2. The available volume of sodium pentaborate solution is at least 3160 gallons.

3. The temperature of the pump suction piping is within the limits of Figure 3.1.5-1 for the most recent concentration analysis.

LIMERICK - UNIT 1 3/4 1-19 Amendment No. 59,66,87,185,186, 201, 240

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. In accordance with the Surveillance Frequency Control Program by:

1. Verifying the continuity of the explosive charge.

2. Determining by chemical analysis and calculation* that the available weight of Boron-10 is greater than or equal to 185 lbs; the concentration of sodium pentaborate in solution is less than or equal to 13.8% and within the limits of Figure 3.1.5-1 and; the following equation is satisfied:

C x E x Q 1 13% wt. 29 atom % 86 gpm where C = Sodium pentaborate solution (% by weight)

Q = Two pump flowrate, as determined per surveillance requirement 4.1.5.c.

E = Boron 10 enrichment (atom % Boron 10)

3. Verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

4. Verifying that no more than two pumps are aligned for automatic operation.***

c. Demonstrating that, when tested pursuant to Specification 4.0.5, the minimum flow requirement of 37.0 gpm per pump at a pressure of greater than or equal to 1230 +/- 25 psig is met.

d. In accordance with the Surveillance Frequency Control Program by:

1. Initiating at least one of the standby liquid control system loops, including an explosive valve, and verifying that a flow path from the pumps to the reactor pressure vessel is available by pumping demineralized water into the reactor vessel. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch which has been certified by having one of the batch success-fully fired. All injection loops shall be tested in 3 operating cycles.

2. Verify all heat-treated piping between storage tank and pump suction is unblocked.**

e. Prior to addition of Boron to storage tank verify sodium pentaborate enrichment to be added is 49 atom % Boron 10.

This test shall also be performed anytime water or boron is added to the solu-tion or when the solution temperature drops below the limits of Figure 3.1.5-1 for the most recent concentration analysis, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after water or boron addition or solution temperature is restored.

- This test shall also be performed whenever suction piping temperature drops below the limits of Figure 3.1.5-1 for the most recent concentration analysis, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after solution temperature is restored.

- - For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage, no pumps are required to start automatically.

LIMERICK - UNIT 1 3/4 1-20 Amendment No. 59,61,66,91,106,185, 186, 201, 232

For Information Only. No Changes Proposed.

SODIUM PENTABORATE SOLUTION TEMPERATURE/CONCENTRATION REQUIREMENTS FIGURE 3.1.5-1 LIMERICK - UNIT 1 3/4 1-21 Amendment No. 22, 232

C TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION

6. DELETED DELETED DELETED DELETED I

7. Drywell Pressure - High 1, 2(h) 2

8. Scram Discharge Volume Water Level - High

a. Level Transmitter 1, 2 2 5(i) 2

b. Float Switch 1, 2 2 5(i) 2

9. Turbine Stop Valve - Closure 1(j) 4(k)

10. Turbine Control Valve Fast Closure, Trip Oil Pressure - Low 1(j) 2(k)

11. Reactor Mode Switch Shutdown Position 1, 2 2 3, 4 2 5 2 (q)

12. Manual Scram 1, 2 2 3, 4 2 5 2

TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION ACTION STATEMENTS ACTION 1 Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 2 Verify all insertable control rods to be inserted in the core and lock the reactor mode switch in the Shutdown position with; n 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 3 Suspend all operations involving CORE ALTERATIONS a insert all insertable control rods within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 4 Be in at least STARTUP within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 5 Be in STARTUP with the main steam line isolation valves closed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 6 Initiate a reduction in THERMAL POWER within 15 minutes and reduce turbine first stage pressure until the function is automatically bypassed, within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

ACTION 7 Verify all insertable control rods to be inserted within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 8 Lock the reactor mode switch in the Shutdown position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 9 Suspend all operations involving CORE ALTERATIONS, and insert all insertable control rods and lock the reactor mode switch in the Shutdown position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 10 a. the condition exists due to a common-mode OPRM deficiency*, then initiate alternate method to detect and suppress thermal-hydraulic instability oscillations within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND restore required channels to OPERABLE status within 120 days,

b. Reduce THERMAL POWER to < 25% RATED THERMAL POWER within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Unanticipated characteristic of the instability detection algorithm or equipment that renders all OPRM channels inoperable at once.

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

LIMERICK - UNIT 1 3/4 3-4 Amendment No. +4l,+49,~,200

TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE NOTATIONS (a) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for required surveillance without plaCing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) This function shall be automatically bypassed when the reactor mode switch is in the Run pOSition.

(c) DELETED (d) The noncoincident NMS reactor trip function logic is such that all channels go to both trip systems. Therefore, when the "shorting links" are removed, the Minimum OPERABLE Channels Per Trip System is 6 IRMs.

(e) An APRM channel is inoperable if there are less than 3 LPRM inputs per level or less than 20 LPRM inputs to an APRM channel, or if more than 9 LPRM inputs to the APRM channel have been bypassed since the last APRM calibration (weekly gain calibration).

(f) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1.

(g) This function shall be automatically bypassed when the reactor mode switch is not in the Run position.

(h) This function is not required to be OPERABLE when PRIMARY CONTAINMENT INTEGRITY is not required.

(i) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

(j) This function shall be automatically bypassed when turbine first stage pressure is equivalent to a THERMAL POWER of less than 29.5% of RATED THERMAL POWER.

(k) Also actuates the EOC RPT system.

(1) DELETED (m) Each APRM channel provides inputs to both trip systems.

(n) DELETED (0) With THERMAL POWER ~ 25% RATED THERMAL POWER. The OPRM Upscale trip output shall be automatically enabled (not bypassed) when APRM Simulated Thermal Power is ~ 29.5% and recirculation drive flow is < 60%. The OPRM trip output may be automatically bypassed when APRM Simulated Thermal Power is

< 29.5% or recirculation drive flow is ~ 60%.

(p) A minimum of 23 cells, each with a minimum of 2 OPERABLE LPRMs, must OPERABLE for an OPRM channel to be OPERABLE.

(q) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

LIMERICK - UNIT 1 3/4 3 5 Amendment No. 4+/-,~,+4+ ,201

TABLE 4.3.1.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH FUNCTIONAL UN IT CHECK(n) TEST(n) CALIBRATION(a)(n) SURVEILLANCE REQUIRED

9. Turbine Stop Valve - Closure N.A. 1

10. Turbine Control Valve Fast Closure, Trip Oil Pressure - Low N.A. 1

11. Reactor Mode Switch Shutdown Position N.A. N.A. 1, 2, 3, 4, 5 (q)

12. Manual Scram N.A. N.A. 1, 2, 3, 4, 5 (a) Neutron detectors may be excluded from CHANNEL CALIBRATION.

(b) The IRM and SRM channels shall be determined to overlap for at least 1/2 decades during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be determined to overlap for at least 1/2 decades during each controlled shutdown, if not performed within the previous 7 days.

(c) Calibration includes verification that the OPRM Upscale trip auto-enable (not-bypass) setpoint for APRM Simulated Thermal Power is~ 29.5% and for recirculation drive flow is< 60%.

(d) The more frequent calibration shall consist of the adjustment of the APRM channel to conform to the power values calculated by a heat balance during OPERATIONAL CONDITION 1 when THERMAL POWER ~25% of RATED THERMAL POWER.

Verify the calculated power does not exceed the APRM channels by greater than 2% of RATED THERMAL POWER.

(e) CHANNEL FUNCTIONAL TEST shall include the flow input function, excluding the flow transmitter.

(f) The LPRMs shall be calibrated at least once per 2000 effective full power hours (EFPH).

(g) The less frequent calibration includes the flow input function.

(h) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1.

(i) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

(j) If the RPS shorting links are required to be removed per Specification 3.9.2, they may be reinstalled for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for required surveillance. During this time, CORE ALTERATIONS shall be suspended, and no control rod shall be moved from its existing position.

( k) DELETED (1) Not required to be performed when entering OPERATIONAL CONDITION 2 from OPERATIONAL CONDITION 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering OPERATIONAL CONDITION 2.

(m) With THERMAL POWER~ 25% of RATED THERMAL POWER.

(n) Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

LIMERICK - UNIT 1 3/4 3-8 Amendment77 I°igi:iQs . 2Ql.233 N 29 H 53 '66' ll~all7.l~lzl41,l

TABLE 4.3.1.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS (0) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(p) The instrument channel setpoint 11 be reset to a value that is within the as-left tolerance around the Trip Setpoint at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the Trip Setpoint are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the associated Technical Specifications Bases.

(q) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

LIMERICK - UNIT 1 3/4 3-8a Amendment No .201

For Information Only. No Changes Proposed.

INSTRUMENTATION 3/4.3.2. ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2 The isolation actuation instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.2.-2 and with ISOLATION SYSTEM RESPONSE TIME as shown in Table 3.3.2-3.

APPLICABILITY: As shown in Table 3.3.2-1.

ACTION:

a) With an isolation actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.

b) With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirements for one trip system:

1. If placing the inoperable channel(s) in the tripped condition would cause an isolation, the inoperable channel(s) shall be restored to OPERABLE status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or in accordance with the Risk Informed Completion Time Program**#. If this cannot be accomplished, the ACTION required by Table 3.3.2-1 for the affected trip function shall be taken, or the channel shall be placed in the tripped condition.

or

2. If placing the inoperable channel(s) in the tripped condition would not cause an isolation, the inoperable channel(s) and/or that trip system shall be placed in the tripped condition within:

a) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months or in accordance with the Risk Informed Completion Time Program**# for trip functions common* to RPS Instrumentation.

b) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program**# for trip functions not common* to RPS Instrumentation.

Trip functions common to RPS Actuation Instrumentation are shown in Table 4.3.2.1-1.

- Not applicable when trip capability is not maintained.

Not applicable for Function 7, Secondary Containment Isolation.

LIMERICK - UNIT 1 3/4 3-9 Amendment No. 53,69,169, 240

For Information Only. No Changes Proposed.

INSTRUMENTATION LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

c. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system** in the tripped condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and take the ACTION required by Table 3.3.2-1.

SURVEILLANCE REQUIREMENTS 4.3.2.1 Each isolation actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS shown in Table 4.3.2.1-1 and at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.3.2.1-1.

4.3.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operations of all channels shall be performed in accordance with the Surveillance Frequency Control Program.

4.3.2.3 The ISOLATION SYSTEM RESPONSE TIME of each isolation trip function shown in Table 3.3.2-3 shall be demonstrated to be within its limit in accordance with the Surveillance Frequency Control Program. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times the frequency specified in accordance with the Surveillance Frequency Control Program, where N is the total number of redundant channels in a specific isolation trip system.

- The trip system need not be placed in the tripped condition if this would cause the Trip Function to occur. When a trip system can be placed in the tripped condition without causing the Trip Function to occur, place the trip system with the most inoperable channels in the tripped condition; if both systems have the same number of inoperable channels, place either trip system in the tripped condition.

LIMERICK - UNIT 1 3/4 3-10 Amendment No. 53, 71, 186

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION MINIMUM APPLICABLE ISOLATION OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b) CONDITION ACTION

3. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCS Flow - High J 1 1, 2, 3 23

b. RWCS Area Temperature - High J 6 1, 2, 3 23

c. RWCS Area Ventilation Temperature - High J 6 1, 2, 3 23

d. SLCS Initiation (h) Y(d) NA 1, 2, 3 23

e. Reactor Vessel Water Level -

Low, Low - Level 2 B 2 1, 2, 3 23

f. Manual Initiation NA 1 1, 2, 3 24

4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line Pressure - High L 1 1, 2, 3 23

b. HPCI Steam Supply Pressure - Low LA 2 1, 2, 3 23

c. HPCI Turbine Exhaust Diaphragm Pressure - High L 2 1, 2, 3 23

d. HPCI Equipment Room Temperature - High L 1 1, 2, 3 23

e. HPCI Equipment Room Temperature - High L 1 1, 2, 3 23 LIMERICK - UNIT 1 3/4 3-12

For Information Only. No Changes Proposed.

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION ACTION STATEMENTS ACTION 20 - Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24-hours.

ACTION 21 - Be in at least STARTUP with the associated penetration flow path(s) isolated by use of one deactivated automatic valve secured in the isolated position, or one closed manual valve or blind flange*** within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 22 - Be in at least STARTUP within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 23 - In OPERATIONAL CONDITION 1 or 2, verify the affected penetration flow path(s) are isolated by use of one deactivated automatic valve secured in the isolated position, or one closed manual valve or blind flange*** within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and declare the affected system inoperable. In OPERATIONAL CONDITION 3, be in at least COLD SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 24 - Restore the manual initiation function to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or isolate the affected penetration flow path(s) by use of one deactivated automatic valve secured in the isolated position, or one closed manual valve or blind flange*** within the next hour and declare the affected system inoperable or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 25 - Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 26 - Isolate the affected penetration flow path(s) by use of one deactivated automatic valve secured in the isolated position, or one closed manual valve or blind flange*** within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 27 - Restore the manual initiation function to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

TABLE NOTATIONS

Required when handling RECENTLY IRRADIATED FUEL in the secondary containment.

- May be bypassed under administrative control, with all turbine stop valves closed.

- - Isolation valves closed to satisfy these requirements may be reopened on an intermittent basis under administrative control.

During operation of the associated Unit 1 or Unit 2 ventilation exhaust system.

(a) DELETED (b) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter. Trip functions common to RPS Actuation Instrumentation are shown in Table 4.3.2.1-1. In addition, for the HPCI system and RCIC system isolation, provided that the redundant isolation valve, inboard or outboard, as applicable, in each line is OPERABLE and all required actuation instrumentation for that valve is OPERABLE, one channel may be placed in an inoperable status for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for required surveillance without placing the channel or trip system in the tripped condition.

LIMERICK - UNIT 1 3/4 3-16 Amendment No. 23,40,53,69,146, 185, 227, 237

TABLE 3.3.2-1 (Continued)

TABLE NOTATIONS (c) Actuates secondary containment isolation valve. Signals B, H, S, and R also start the standby gas treatment system.

(d) RWCU system inlet outboard isolation valve closes on SLCS "B" initiation.

RWCU system inlet inboard isolation valve closes on SLCS "A" or SLCS "C" initiation.

(e) Manual initiation isolates the steam supply line outboard isolation valve and only following manual or automatic initiation of the system.

(f) In the event of a loss of ventilation the temperature - high setpoint may be raised by 50°F for a period not to exceed 30 minutes to permit restoration of the ventilation flow without a spurious trip. During the 30 minute period, an operator, or other qualified member of the technical staff, shall observe the temperature indications continuously, so that, in the event of rapid increases in temperature, the main steam lines shall be manually isolated.

(g) Wide range accident monitor per Specification 3.3.7.5.

(h) For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage, the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

LIMERICK - UNIT 1 3/4 3-17 Amendment No. 28, 53, 112, 146

TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK(a) TEST(a) CALIBRATION(a) SURVEILLANCE REQUIRED

3. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCS Flow - High 1, 2, 3

b. RWCS Area Temperature - High 1, 2, 3

c. RWCS Area Ventilation Temperature - High 1, 2, 3

d. SLCS Initiation (b) N.A. N.A. 1, 2, 3

e. Reactor Vessel Water Level Low, Low, - Level 2 1, 2, 3

f. Manual Initiation N.A. N.A. 1, 2, 3

4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line Pressure - High 1, 2, 3

b. HPCI Steam Supply Pressure, Low 1, 2, 3

c. HPCI Turbine Exhaust Diaphragm Pressure - High 1, 2, 3

d. HPCI Equipment Room Temperature - High 1, 2, 3

e. HPCI Equipment Room Temperature - High 1, 2, 3

f. HPCI Pipe Routing Area Temperature - High 1, 2, 3

g. Manual Initiation N.A. N.A. 1, 2, 3

h. HPCI Steam Line Pressure Timer N.A. 1, 2, 3 LIMERICK - UNIT 1 3/4 3-28 Amendment No. 53, 69, 186

TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK (a) TEST (a) CALIBRATION(a) SURVEILLANCE REQUIRED

7. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level Low, Low - Level 2 1, 2, 3

b. Drywell Pressure## - High 1, 2, 3 c.1. Refueling Area Unit 1 Ventilation Exhaust Duct Radiation - High *#

2. Refueling Area Unit 2 Ventilation Exhaust Duct Radiation - High *#

d. Reactor Enclosure Ventilation Exhaust Duct Radiation - High 1, 2, 3

e. Deleted

f. Deleted

g. Reactor Enclosure Manual Initiation N.A. N.A. 1, 2, 3

h. Refueling Area Manual Initiation N.A. N.A. *

(a) Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

Required when handling RECENTLY IRRADIATED FUEL in the secondary containment.

- When not administratively bypassed and/or when any turbine stop valve is open.

During operation of the associated Unit 1 or Unit 2 ventilation exhaust system.

1. These trip functions (2a, 6b, and 7b) are common to the RPS actuation trip function.

LIMERICK - UNIT 1 3/4 3-31 Amendment No. 23, 40, 53, 69, 89, 112, 185, 186, 227 (b) For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage, the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

. I TABLE 3.3.3-1 (Continued) m

' -4 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION so C-6-4 ,, -MINII MUM OPERABLE CHjkNNELS PER APPLICABLE 1

TRIP OPERATIONAL TRIP FUNCTION FUI NCTION a CONDITIONS ACTION

4. AUTOMATIC DEPRESSURIZATION SYSTEM#***

N. a. Reactor Vessel Water Level - Low Low Low, Level 1 2 1, 2, 3 30

b. Drywell Pressure - High 2 1, 2, 3 30 r-J c. ADS Timer 1 1, 2, 3 31

d. Core Spray Pump Discharge Pressure - High (Permissive) 2 1, 2, 3 31

e. RHR LPCI Mode Pump Discharge Pressure High (Permissive) 4 1, 2, 3 31

f. Reactor Vessel Water Level - Low, Level 3 (Permissive) 1 1, 2, 3 31 (A)

g. Manual Initiation 2 1, 2, 3 33

h. ADS Drywell Pressure Bypass Timer. 2 1, 2, 3 31 4>1 MINIMUM APPLICABLE TOTAL NO. CHANNELS CHANNELS OPERATIONAL OF CHANNELS(f) TO TRIP OPERABLE CONDITIONS ACTION

5. LOSS OF POWER

1. 4.16 kV Emergency Bus Under-voltage (Loss of Voltage) 1/bus 1/bus 1/bus 1,2,3,4**,5** 36

2. 4.16 kV Emergency Bus Under-voltage (Degraded Voltage) 1/source/ 1/source/ 1/source/ 1,2,3,4**,5** 37 bus bus bus

.3 0-.

=3 0

CLA rta

- - The Minimum OPERABLE Channels Per Trip Function is per subsystem.

(7' ' , ' '( (.

TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION TABLE NOTATIONS (a) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) Also provides input to actuation logic for the associated emergency diesel generators.

(c) One trip system. Provides signal to HPCI pump suction valves only.

(d) On 1 out of 2 taken twice logic, provides a signal to trip the HPCI pump turbine only.

(e) The manual initiation push buttons start the respective core spray pump and diesel generator. The "A" and "B" logic manual push buttons also actuate an initiation permissive in the injection valve opening logic.

(f) A channel as used here is defined as the 127 bus relay for Item 1 and the 127, 127Y, and 127Z feeder relays with their associated time delay relays taken together for Item 2.

DELETED

Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

- Required when ESF equipment is required to be OPERABLE.

1. Not required to be OPERABLE when reactor steam dome pressure is 1ess than or equal to 200 psig.

1. 1. The injection functions of Drywell Pressure - High and Manual Initiation are not required to be OPERABLE with reactor steam dome pressure less than 550 psig.

LIMERICK - UNIT 1 3/4 3-35 Amendment No. -eJ,-l24, 227

TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION STATEMENTS ACTION 30 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. With one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program, or declare the associated system inoperable.

b. With more than one channel inoperable, declare the associated system inoperable.

ACTION 31 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, declare the associated ECCS inoperable within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 32 - DELETED ACTION 33 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program*, or declare the associated ECCS inoperable.

ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. For one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program, or declare the HPCI system inoperable.

b. With more than one channel inoperable, declare the HPCI system inoperable.

ACTION 35 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program*, or declare the HPCI system inoperable.

ACTION 36 - With the number of OPERABLE channels less than the Total Number of Channels, declare the associated emergency diesel generator and the associated offsite source breaker that is not supplying the bus inoperable and take the ACTION required by Specification 3.8.1.1 or 3.8.1.2, as appropriate.

Not applicable when trip capability is not maintained.

LIMERICK - UNIT 1 3/4 3-36 Amendment No. +l,~.~.~. 240

TABLE 3.3.3-1 (Continued)

E1-'RGEN7Y CORE COSING SYST2' A_-TUATo:: -.. 7u_.!: - ATSON ACT IO'N S T.-T V£E7S ACTION 37 - With the number of OPERABLE channels one less than the Total Number of Channels, place the inoperable device in the bypassed condition subject to the following conditions:

Inoperable Device Condition 127-l1XOX 127Y-llXOX and 127Z-llXOX operable 127Y-1lXOX 127-l1XOX and 127Z-llXOX operable 127Z-llXOX 127-llXOX and 127Y-llXOX operable.

127Z-llYOY operable for the other 3 breakers monitoring that source, offsite source grid voltage for that source is maintained at or above 230kV (for the 101 Safeguard Bus Source) or 525kV (for the 201 Safeguard Bus Source),

Load Tap Changer for that source is in service and in automatic operation, and the electrical buses and breaker alignments are maintained within bounds of approved plant procedures.

or, place the inoperable channel in the tripped condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and take the Action required by Specification 3.8.1.1 or 3.8.1.2, as appropriate.

Operation may then continue until perfo mance of the next required CHANNEL FUNCTIONAL TEST.

LI.-1ERIi - U>NIT 1 3/4 3-36a Amendment No. 158 I AR 2 0 2WJ2

TABLE 4.3.3.1-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHE..G.KW TEST( a) CALIBRATION(a) SURVEILLANCE REQUIRED

4. AUTOMATIC DEPRESSURIZATION SYSTEM#

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1, 2, 3

b. Drywel l Pressure - High 1, 2, 3 C. ADS Timer N.A. 1, 2, 3

d. Core Spray Pump Discharge Pressure - High 1, 2, 3

e. RHR LPCI Mode Pump Discharge Pressure - High 1, 2, 3

f. Reactor Vessel Water Level - Low, Level 3 1, 2, 3

g. Manual Initiation N.A. N.A. 1, 2, 3

h. ADS Drywell Pressure Bypass Timer N. A. 1, 2, 3

5. LOSS OF POWER

a. 4.16 kV Emergency Bus Under-voltage (Loss of Voltage)~ N.A. N.A. 1, 2, 3, 4**, 5**

b. 4.16 kV Emergency Bus Under -

voltage (Degraded Voltage) 1, 2, 3, 4**, 5**

(a) Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

DELETED

- Required OPERABLE when ESF equipment is required to be OPERABLE.

- - Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.

Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

1. Loss of Voltage Relay 127-llX is not field setable.

LIMERICK - UN IT 1 3/4 3-41 Amendment No. -&J, ~ . 227

INSTRUMENTATION 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram recirculation pump trip (ATWS-RPT) system instrumentation channels shown in Table 3.3.4.1-1 shall be OPERABLE with their trip setpoints set consistent with values shown in the Trip Setpoint column of Table 3.3.4.1-2.

APPLICABILITY: OPERATIONAL CONDITION 1.

Insert 1 ACTION:

a. With an ATWS recirculation pump trip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.1-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel trip setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels per Trip System requirement for one or both trip systems, place the inoperable channel(s) in the tripped condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program*.

c. With the number of OPERABLE channels two or more less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system and:

1. If the inoperable channels consist of one reactor vessel water level channel and one reactor vessel pressure channel, place both inoperable channels in the tripped condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program, or if this action will initiate a pump trip, declare the trip system inoperable.

2. If the inoperable channels include two reactor vessel water level channels or two reactor vessel pressure channels, declare the trip system inoperable.

d. With one trip system inoperable, restore the inoperable trip system to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or in accordance with the Risk Informed Completion Time Program, or be in at least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

e. With both trip systems inoperable, restore at least one trip system to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in at least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.3.4.1.1 Each of the required ATWS recirculation pump trip system instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies specified in the Surveillance Frequency Control Program.

4.3.4.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed in accordance with the Surveillance Frequency Control Program.

Not applicable when trip capability is not maintained.

LIMERICK - UNIT 1 3/4 3-42 Amendment No. 70,71,186, 240

Insert 1 Note: For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2024 refueling outage, the LCO is not applicable when the following conditions are met:

Maximum Maximum Inoperable Minimum Suppression THERMAL POWER Safety/Relief Valves Pool Water Level 90% RTP 0 of 14 23 feet 87% RTP 0 of 14 22 feet 84% RTP 1 of 14 22 feet Recirc Runback on Level 3 Function is Available and not in Bypass.

For Information Only. No Changes Proposed.

TABLE 3.3.4.1-1 ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION MINIMUM OPERABLE CHANNELS PER TRIP FUNCTION TRIP SYSTEM *

1. Reactor Vessel Water Level -

Low Low, Level 2 2

2. Reactor Vessel Pressure - High 2

One channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for required surveillance provided the other channel is OPERABLE.

LIMERICK - UNIT 1 3/4 3-43 Amendment No. 70

For Information Only. No Changes Proposed.

TABLE 3.3.4.1-2 ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION SETPOINTS TRIP ALLOWABLE TRIP FUNCTION SETPOINT VALUE

1. Reactor Vessel, Water Level -

Low Low, Level 2 -38 inches* -45 inches

2. Reactor Vessel Pressure - High 1149 psig 1156 psig

See Bases Figure B3/4 3-1.

LIMERICK - UNIT 1 3/4 3-44 Amendment No. 106

EMERGENCY CORE COOLING SYSTEMS 3/4.5.2 REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)

LIMITING CONDITION FOR OPERATION 3.5.2 DRAIN TIME of RPV water inventory to the top of active fuel (TAF) shall be~ 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months At least one of the following shall be OPERABLE:

a. Core spray system (CSS) subsystem comprised of:

1. Two OPERABLE CSS pumps, and

2. An OPERABLE flow path capable of taking suction from at least one of the following water sources and transferring the water through the spray sparger to the reactor vessel:

a) From the suppression chamber, or b) When the suppression chamber water level is less than the limit or is drained, from the condensate storage tank containing at least 135,000 available gallons of water, equivalent to a level of 29 feet.

b. Low pressure coolant injection (LPCI) system subsystem comprised of:

1. One OPERABLE LPCI pump, and

2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water to the reactor vessel.**

APPLICABILITY: OPERATIONAL CONDITIONS 4 and 5.

ACTION:

a. With none of the above required subsystems OPERABLE, immediately suspend CORE ALTERATIONS. Restore at least one subsystem to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Otherwise, initiate action to establish a method of water injection capable of operating without offsite electrical power.

b. DELETED

- One LPCI subsystem may be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned and not otherwise inoperable.

LIMERICK - UNIT 1 3/4 5-6 Amendment No. ~.227

For Information Only. No Changes Proposed.

F1 FflTRTC.AI PnWFR SYSTFMSý

.SURVEILLANCE REOUIREMENTS 4.8.1.1.1 Each of the above required independent circuits between the offsite transmission network and the onsite Class 1E distribution system shall be:

a. Determined OPERABLE in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignments and indicated power availability, and.

b. Demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by transferring, manually and automatically, unit power supply from the normal circuit to the alternate circuit.

4.8.1.1.2 Each of the above required diesel generators shall be demonstrated OPERABLE:

a. In accordance with the Surveillance Frequency Control Program on a STAGGERED TEST BASIS by:

1. Verifying the fuel level in the day fuel tank.

2. Verifying the fuel level in the fuel storage tank.

3. Verifying the fuel transfer pump starts and transfers fuel from the storage system to the day fuel tank.

4. Verify that the diesel can start* and gradually accelerate to synchronous speed with generator voltage and frequency at 4280 +/- 120 volts and 60 +/- 1.2 HZ.

5. Verify diesel is synchronized, gradually loaded* to an indicated 2700-2800 KW** and operates with this load for at least 60 minutes.

6. Verifying the diesel generator is aligned to provide standby power to the associated emergency busses.

7. Verifying the pressure in all diesel generator air start receivers to be greater than or equal to 225 psig.

This test shall be conducted in accordance with the manufacturer's recommendations regarding engine pre-lube and.warmup procedures, and as applicable regarding loading and shutdown recommendations.

- This band is meant as guidance to avoid routine overloading of the engine.

Loads in excess of this band for special testing under direct monitoring by the manufacturer or momentary variations due to changing bus loads shall not invalidate the test.

LIMERICK - UNIT I 3/4 8-3 Amendment No. *,-7,4-O,48.,189

For Information Only. No Changes Proposed.

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. By removing accumulated water:

1) From the day tank in accordance with the Surveillance Frequency Control Program and after each occasion when the diesel is operated for greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , and

2) From the storage tank in accordance with the Surveillance Frequency Control Program.

c. By sampling new fuel oil in accordance with ASTM D4057-81 prior to addition to the storage tanks and:

1) By verifying in accordance with the tests specified in ASTM D975-81 prior to addition to the storage tanks that the sample has:

a) An API Gravity of within 0.3 degrees at 60'F or a specific gravity of within 0.0016 at 60/60 0 F, when compared to the supplier's certificate or an absolute specific gravity at 60/60'F of greater than or equal to 0.83 but less than or equal to 0.89 or an API gravity at 60'F of greater than or equal to 27 degrees but less than or equal to 39 degrees.

b) A kinematic viscosity at 40 0 C of greater than or equal to 1.9 centistokes, but less, than or equal to 4.1 centistokes, if gravity was not determined by comparison with the supplier's certification.

c) A flash point equal to or greater than 125°F, and d) A clear and bright appearance with proper color when tested in accordance with ASTM D4176-82.

2) By verifyihg within 31 days of obtaining the sample that the other properties specified in Table 1 of ASTM D975-81 are met when tested in accordance with ASTM D975-81 except that the analysis for sulfur may be performed in accordance with ASTM D1552-79 or ASTM D2622-82.

d. In accordance with the Surveillance Frequency Control Program by obtaining a sample of fuel oil from the storage tanks in accordance with ASTM D2276-78, and verifying that total particulate contamination is less than 10 mg/liter when checked in accordance with ASTM D2276-78, Method A, except that the filters specified in ASTM D2276-78, Sections 5.1.6 and 5.1.7, may have a nominal pore size of up to three (3) microns.

e. In accordance with the Surveillance Frequency Control Program by:

1. Deleted

2. Verifying each diesel generator's capability to reject a load of greater than or equal to that of its single largest post-accident load, and:

I a) Following load rejection, the frequency is

66.5 Hz; b) Within 1.8 seconds following the load rejection, voltage is 4285

+/- 420 volts, and frequency is 60 +/- 1.2 Hz; and c) After steady-state conditions are reached, voltage is maintained at 4280 +/- 120 volts.

LIMERICK - UNIT 1 3/4 8-4 Amendment No. 21-,4,4-44,-1-24-,

4,4--3,4-,8, 189

For Information Only. No Changes Proposed.

ELECTRICAL POWER SYSTEMS SURVEILLANCE REOUIREMENTS (Continued)

3. Verifying the diesel generator capability to reject a load of 2850 kW without tripping. The generator voltage shall not exceed 4784 volts during and following the load rejection.

4. Simulating a loss-of-offsite power by itself, and:

a) Verifying deenergization of the emergency busses and load shedding from the emergency busses.

b) Verifying the diesel generator starts* on the auto-start signal, energizes the emergency busses within 10 seconds, energizes the auto-connected loads through the individual load timers and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4280 +/- 120 volts and 60 +/- 1.2 Hz during this test.

5. Verifying that on an ECCS actuation test signal, without loss-of-offsite power, the diesel generator starts* on the auto-start signal and operates on standby for greater than or equal to 5 minutes. The generator voltage and frequency shall reach 4280 +/- 120 volts and 60 +/- 1.2 Hz within 10 seconds after the auto-start signal; the steady state generator voltage and frequency shall be maintained within these limits during this test.

6. Simulating a loss-of-offsite power in conjunction with an ECCS actuation test signal, and:

a) Verifying deenergization of the emergency busses and load shedding from the emergency busses.

b) Verifying the diesel generator starts* on the auto-start signal, energizes the emergency busses within 10 seconds, energizes the auto-connected shutdown loads through the individual load timers and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4280 +/- 120 volts and 60 +/- 1.2 Hz during this test.

7. Verifying that all automatic diesel generator trips, except engine overspeed and generator differential over-current are automatically bypassed upon an ECCS actuation signal.

This test shall be conducted in accordance with the manufacturer's recommendations regarding engine prelube and warm-up procedures, and as applicable regarding loading and shutdown recommendations.

LIMERICK - UNIT I 3/4 8-5 Amendment No. -, W-4, 4-04*,186

For Information Only. No Changes Proposed.

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

8. a) Verifying the diesel generator operates* for at least 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

During the first 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of this test, the diesel generator shall be loaded to an indicated 2950-3050 kW** and during the remaining 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months of this test, the diesel generator shall be loaded to an indicated 2700-2800 kW**.

b) Verifying that, within 5 minutes of shutting down the diesel generator after the diesel generator has operated* for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months at an indicated 2700-2800 kW**, the diesel generator starts*.

The generator voltage and frequency shall reach 4280 +/- 120 volts and 60 +/- 1.2 Hz within 10 seconds after the start signal.

9. Verifying that the auto-connected loads to each diesel generator do not exceed the 2000-hour rating of 3100 kW.

10. Verifying the diesel generator's capability to:

a) Synchronize with the offsite power source while the generator is loaded with its emergency loads upon a simulated restoration of offsite power, b) Transfer its loads to the offsite power source, and c) Be restored to its standby status.

11. Verifying that with the diesel generator operating in a test mode and connected to its bus, a simulated ECCS actuation signal overrides the test mode by (1) returning the diesel generator to standby operation, and (2) automatically energizes the emergency loads with offsite power.

12. Verifying that the automatic load sequence timers are OPERABLE with the interval between each load block within +/- 10% of its design interval.

This test shall be conducted in accordance with the manufacturer's recommendations regarding engine prelube and warmup procedures, and as applicable regarding loading and shutdown recommendations.

- This band is meant as guidance to avoid routine overloading of the engine.

Loads in excess of this band for special testing under direct monitoring by the manufacturer or momentary variations due to changing bus loads shall not invalidate the test.

LIMERICK - UNIT 1 3/4 8-6 Amendment No. 3, -74, 4-a, 4-04, 4-36, 186

For Information Only. No Changes Proposed.

ELECTRICAL POWER SYSTEMS SURVEILLANCE REOUIREMENTS (Continued)

13. Verifying that the following diesel generator lockout I features prevent diesel generator starting only when required:

a) Control Room Switch In Pull-To-Lock (With Local/Remote Switch in Remote) b) Local/Remote Switch in Local c) Emergency Stop

f. In accordance with the Surveillance Frequency Control Program or I after any modifications which could affect diesel generator interdependence by starting* all four diesel generators simultaneously, during shutdown, and verifying that all four diesel generators accelerate to at least 882 rpm in less than or equal to 10 seconds.

g. In accordance with the Surveillance Frequency Control Program by: I

1. Draining each fuel oil storage tank, removing the accumulated sediment and cleaning the tank using a sodium hypochlorite or equivalent solution, and

2. Performing a pressure test of those portions of the diesel fuel oil system designed to Section III, subsection ND of the ASME Code in accordance with ASME Code Section XI Article IWD-5000.

This test shall be conducted in accordance with the manufacturer's recommendations regarding engine prelube and warmup procedures, and as applicable regarding loading and shutdown recommendations.

LIMERICK - UNIT 1 3/4 8- 7 Amendment No. 4, ;74, 186

For Information Only. No Changes Proposed.

T(-

-L-CT-,CA -

E SY!STEMS1F-A SURVEILLANCE REOUIREMENTS (Continued)

h. In accordance with the Surveillance Frequency Control Program the diesel generator shall be started* and verified to accelerate to synchronous speed in less than or equal to 10 seconds. The generator voltage and frequency shall reach 4280 +/- 120 volts and 60 +/- 1.2 Hz within 10 seconds after the start signal. The diesel generator shall be started for this test by using one of the following signals:

a) Manual***

b) Simulated loss-of-offsite power by itself.

c) Simulated loss-of-offsite power in conjunction with an ECCS actuation test signal.

d) An ECCS actuation test signal by itself.

The generator shall be manually synchronized to its appropriate emergency bus, loaded to an indicated 2700-2800 KW** and operate for at least 60 minutes. This test, if it is perfori,,ed so iL coincides with the testing required by Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5, may also serve to concurrently meet those requirements as well.

4.8.1.1.3 Deleted

This test shall be conducted in accordance with the manufacturer's

... J.mm)i ... - .. i.. ...1/4 .. prellube and .,rmup pr e, , and as applicable regarding loading and shutdown recommendations.

- This band is meant as guidance to avoid routine overloading of the engine. Loads in excess of this band for special testingkunder dire'ct monitoring by the manufacturer or momentary variations due to changing bus loads shall not invalidate the test.

- - If diesel generator started manually from the control room, 10 seconds after the automatic prelube period.

`MýýDTýV - INTT I 3/4 8- 7a Amendment No. -a, , go,189

ELECTRICAL POWER SYSTEMS A.C. SOURCES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.1.2 As a minimum, the following A.C. electrical power sources shall be OPERABLE:

a. One circuit between the offsite transmission network and the onsite Class lE distribution system, and

b. Two diesel generators each with:

1. A day fuel tank containing a minimum of 250 gallons of fuel.

2. A fuel storage system containing a minimum of 33,500 gallons of fuel.

3. A fuel transfer pump.

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5, and*

ACTION:

a. With less than the above required A.C. electrical power sources OPERABLE, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment, and crane operations over the spent fuel storage pool when fuel assemblies are stored therein. In addition, when in OPERATIONAL CONDITION 5 with the water level less than 22 feet above the reactor pressure vessel flange, immediately initiate corrective action to restore the required power sources to OPERABLE status as soon as practical.

b. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.1.2 At least the above required A.C. electrical power sources shall be demonstrated OPERABLE per Surveillance Requirements 4.8.1.1.1 and 4.8.1.1.2.

, except for 4.8.1.1.1.b, 4.8.1.1.2.e.4, 4.8.1.1.2.e.5, 4.8.1.1.2.e.6, 4.8.1.1.2.e.7, 4.8.1.1.2.e.8.b, 4.8.1.1.2.e.11, 4.8.1.1.2.e.12, 4.8.1.1.2.f, and 4.8.1.1.2.h.

When handling irradiated fuel in the secondary containment.

LIMERICK - UNIT 1 3/4 8-9 Amendment No. Ji, -+/---9--i, -+/---9-J, 227

3.4.9 REFUELING OPERATIONS 3/4.9.1 REACTOR MODE SWITCH IiMLTINM CDNDIThQN EORItAlNO R

3.9.1 The reactor mode switch shall be OPERABLE and locked in the Shutdown or Refuel position. When the reactor mode switch is locked in the Refuel position:

a. The Refuel position one-rod-out interlock shall be OPERABLE.

b. The following Refuel position interlocks shall be OPERABLE:

1. All rods in.

2. Refuel Platform (over-core) position.

3. Refuel Platform hoists fuel-loaded.

4. Service Platform hoist fuel-loaded (with Service Platform installed).

APPLICABILITY: OPERATIONAL CONDITION 5* **, OPERATIONAL CONDITIONS 3 AND 4 when the reactor mode switch is in the Refuel position.

ACTION:

a. With the reactor mode switch not locked in the Shutdown or Refuel position as specified, suspend CORE ALTERATIONS and lock the reactor mode switch in the Shutdown or Refuel position.

b. With the one-rod-out interlock inoperable, verify all control rods are fully inserted and disable withdraw capabilities of all control rods

or lock the reactor mode switch in the Shutdown position.

c. With any of the above required Refuel Platform Refuel position interlocks inoperable, take one of the ACTIONS listed below, or suspend CORE ALTERATIONS.

1. Verify control rods are fully inserted and disable withdraw capabilities of all control rods***, or

2. Verify Refuel Platform is not over-core (limit switches not reached) and disable Refuel Platform travel over-core, or

3. Verify that no Refuel Platform hoist is loaded and disable all Refuel Platform hoists from picking up (grappling) a load.

d. With the Service Platform installed over the vessel and any of the above required Service Platform Refuel position interlocks inoperable, take one of the ACTIONS listed below, or suspend CORE ALTERATIONS.

1. Verify all control rods are fully inserted and disable withdraw capabilities of all control rods***, or

2. Verify Service Platform hoist is not loaded and disable Service Platform hoist from picking up (grappling) a load.

See Special Test Exceptions 3.10.1 and 3.10.3.

- The reactor shall be maintained in OPERATIONAL CONDITION 5 whenever fuel is in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.

- Except control rods removed per Specification 3.9.10.1 or 3.9.10.2.

LIMERICK - UNIT 1 3/4 9-1 Amendment No. -it?7 149 APR 0 5 20-3

REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS 4.9.1.1 The reactor mode switch shall be verified to be locked in the Shutdown or Refuel position as specified, in accordance with the Surveillance Frequency Control Program.

4.9.1.2 Each of the above required reactor mode switch Refuel position interlocks* shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST in accordance with the Surveillance Frequency Control Program during control rod withdrawal or CORE ALTERATIONS, as applicable.

4.9.1.3 Each of the above required reactor mode switch Refuel position interlocks* that is affected shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST prior to resuming control rod withdrawal or CORE ALTERATIONS, as applicable, following repair, maintenance or replacement of any component that could affect the Refuel position interlock.

The reactor mode switch may be placed in the Run or Startup/Hot Standby position to test the switch interlock functions provided that all control rods are verified to remain fully inserted by a second licensed operator or other technically qualified member of the unit technical staff.

LIMERICK - UNIT 1 3/4 9-2 Amendment No. 4--, 186

REFUELING OPERATIONS MULTIPLE CONTROL ROD REMOVAL LIMITING CONDITION FOR OPERATION 3.9.10.2 Any number of control rods and/or control rod drive'mechanisms may be removed from the core and/or reactor pressure vessel provided that at least the following requirements are satisfied until all control rods and control rod drive mechanisms are reinstalled and all control rods are inserted in the core.

a. The reactor mode switch is OPERABLE and locked in'the Shutdown position or in the Refuel position per Specification 3.9.1, except that the Refuel position "one-rod-out" interlock may be bypassed, as required, for those control rods and/or control rod drive mechanisms to be removed, after'the fuel'assemblies have been removed as specified below.

b. The source range monitors'(SRM) are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN'MARGIN requirements'of Specification-3.1.1 are satisfied.

d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.

e. The four fuel assemblies'surrounding each control rod or control rod

-drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.

APPLICABILITY: OPERATIONAL CONDITION 5.

ACTION:

With the requirements of the above specification not satisfied, suspend removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and initiate action to satisfy the above requirements.

LIMERICK - UNIT 1 3/4 9-15

REFUELING OPERATIONS SURVEILLANCE REOUIREMENTS 4.9.10.2.1 Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to the start of removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and in accordance with the Surveillance Frequency Control Program thereafter until all control rods and control rod drive mechanisms are reinstalled and all control rods are inserted in the core, verify that:

a. The reactor mode switch is OPERABLE per Surveillance Requirement 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Shutdown position or in the Refuel position per Specification 3.9.1.

b. The SRM channels are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.

d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.

e. The four fuel assemblies surrounding each control rod and/or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.

4.9.10.2.2 Following replacement of all control rods and/or control rod drive mechanisms removed in accordance with this specification, perform a functional test of the "one-rod-out" Refuel position interlock, if this function had been bypassed.

LIMERICK - UNIT 1 3/4 9-16 Amendment No. 186

For Information Only. No Changes Proposed.

REACTIVITY CONTROL SYSTEMS 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.1.5 The standby liquid control system shall be OPERABLE and consist of the following:

a. In OPERATIONAL CONDITIONS 1 and 2, two pumps and corresponding flow paths,

b. In OPERATIONAL CONDITION 3, a minimum of one pump and corresponding flow path.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3 ACTION:

a. With only one pump and corresponding explosive valve OPERABLE, in OPERATIONAL CONDITION 1 or 2, restore one inoperable pump and corresponding explosive valve to OPERABLE status within 7 days or in accordance with the Risk Informed Completion Time Program, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With standby liquid control system otherwise inoperable, in OPERATIONAL CONDITION 1, 2, or 3, restore the system to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.5 The standby liquid control system shall be demonstrated OPERABLE:

a. In accordance with the Surveillance Frequency Control Program by verifying that:

1. The temperature of the sodium pentaborate solution is within the limits of Figure 3.1.5-1.

2. The available volume of sodium pentaborate solution is at least 3160 gallons.

3. The temperature of the pump suction piping is within the limits of Figure 3.1.5-1 for the most recent concentration analysis.

LIMERICK - UNIT 2 3/4 1-19 Amendment No. 24,48,49,146,147, 163, 203

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. In accordance with the Surveillance Frequency Control Program by:

1. Verifying the continuity of the explosive charge.

2. Determining by chemical analysis and calculation* that the available weight of Boron-10 is greater than or equal to 185 lbs; the concentration of sodium pentaborate in solution is less than or equal to 13.8% and within the limits of Figure 3.1.5-1 and; the following equation is satisfied:

C x E x Q 1 13% wt. 29 atom % 86 gpm where C = Sodium pentaborate solution (% by weight)

Q = Two pump flowrate, as determined per surveillance requirement 4.1.5.c.

E = Boron 10 enrichment (atom % Boron 10)

3. Verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

4. Verifying that no more than two pumps are aligned for automatic operation. ***

c.Demonstrating that, when tested pursuant to Specification 4.0.5, the minimum flow requirement of 37.0 gpm per pump at a pressure of greater than or equal to 1230+/-25 psig is met.

d. In accordance with the Surveillance Frequency Control Program by:

1. Initiating at least one of the standby liquid control system loops, including an explosive valve, and verifying that a flow path from the pumps to the reactor pressure vessel is available by pumping demineralized water into the reactor vessel. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch which has been certified by having one of the batch success-fully fired. All injection loops shall be tested in 3 operating cycles.

2. Verify all heat-treated piping between storage tank and pump suction is unblocked.**

e. Prior to addition of Boron to storage tank verify sodium pentaborate enrichment to be added is 49 atom % Boron 10.

This test shall also be performed anytime water or boron is added to the solu-tion or when the solution temperature drops below the limits of Figure 3.1.5-1 for the most recent concentration analysis, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after water or boron addition or solution temperature is restored.

- This test shall also be performed whenever suction piping temperature drops below the limits of Figure 3.1.5-1 for the most recent concentration analysis, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after solution temperature is restored.

- - For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2025 refueling outage, no pumps are required to start automatically.

LIMERICK - UNIT 2 3/4 1-20 Amendment No. 24,26,34,48,51,146,147, 163, 195

For Information Only. No Changes Proposed.

SODIUM PENTABORATE SOLUTION TEMPERATURE/CONCENTRATION REQUIREMENTS FIGURE 3.1.5-1 LIMERICK - UNIT 2 3/4 1-21 Amendment No. 195

5 K

TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION

6. DELETED DELETED DELETED DELETED I

7. Drywell Pressure - High 1, 2(h) 2

8. Scram Discharge Volume Water Level - High

a. Level Transmitter 1, 2 2 5(i) 2

b. Float Switch 1, 2 2 5(i) 2

9. Turbine Stop Valve - Closure l(j) 4(k)

10. Turbine Control Valve Fast Closure, Trip Oil Pressure - Low l(j) 2(k)

11. Reactor Mode Switch Shutdown Position 1, 2 2 3, 4 2 5 (q) 2 len 12. Manual Scram 1, 2 2 3, 4 2 e.n 5 2

(Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION ACTION STATEMENTS ACTION 1 Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 2 Veri fy all i nsertabl e control rods to be inserted in the core and lock the reactor mode switch in the Shutdown position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 3 Suspend all operations involving CORE ALTERATIONS and insert all insertable control rods within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 4 Be in at least STARTUP within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 5 Be in STARTUP with the main steam line isolation valves closed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 6 Initiate a reduction in THERMAL POWER within 15 minutes and reduce turbine first stage pressure until the function is automatically bypassed, within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

ACTION 7 Verify all insertable control rods to be inserted within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 8 Lock the reactor mode switch in the Shutdown position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 9 Suspend all operations involving CORE ALTERATIONS, and insert all i nsertabl e control rods and lock the reactor mode switch in the Shutdown position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 10 a. If the condition exists due to a common-mode OPRM deficiency*,

then initiate alternate method to detect and suppress thermal-hydraulic instability oscillations within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND restore required channels to OPERABLE status within 120 days,

b. Reduce THERMAL POWER to < 25% RATED THERMAL POWER within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Unanticipated characteristic of the instability detection algorithm or equipment that renders all OPRM channels inoperable at once.

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

LIMERICK UNIT 2 3/4 3-4 Amendment No. +/-Q9,~,~,161

..w..l.1"'-'=-"~~,---,"----""" (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE NOTATIONS (a) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for required surveillance without placing the trip in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) This function shall automatically be bypassed when the reactor mode switch is in the Run position.

(c) DELETED (d) The noncoincident NMS reactor trip function logic is such that all channels go to both trip systems. Therefore, when the "shorting links" are removed, the Minimum OPERABLE Channels Per Trip System is 6 IRMs.

(e) An APRM channel is inoperable if there are less than 3 LPRM inputs per level or 1ess than 20 LPRM inputs to an APRM channel, or if more than 9 LPRM inputs to the APRM channel have been bypassed since the last APRM calibration (weekly gain calibration).

(f) This function is not required to be OPERAB when the reactor pressure vessel head is removed per Specification 3.10.1.

(g) This function shall automatically bypassed when the reactor mode switch is not in the Run position.

(h) This function is not required to be OPERABLE when PRIMARY CONTAINMENT INTEGRITY is not required.

(i) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

(j) This function shall automatically bypassed when turbine first stage pressure is equivalent to a THERMAL POWER of less than 29.5% of RATED THERMAL POWER.

(k) Also actuates the EOC RPT system.

(1 ) DELETED (m) Each APRM channel provides inputs to both trip systems.

(n) DELETED (0) With THERMAL POWER ~ 25% RATED THERMAL POWER. The OPRM Upscale trip output shall be automatically enabled (not bypassed) when APRM Simulated Thermal Power is ~ 29.5% and recircul on drive flow is < 60%. The OPRM trip output may be automatically bypassed when APRM Simulated Thermal Power is < 29.5% or recirculation drive flow is ~ 60%.

(p) A minimum of 23 cells, each with a mlnlmum of 2 OPERABLE LPRMs. must be OPERABLE for an OPRM channel to be OPERABLE.

(q) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

LIMERICK - UNIT 2 3/4 3 5 Amendment No. + .~,~,163

TABLE 4.3.1.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH FUN CTI ONA L UN IT CHECK Cn) TEST Cn) CALIBRATIONCa)Cn) SURVEILLANCE REQUIRED

9. Turbine Stop Valve - Closure N.A. 1

10. Turbine Control Valve Fast Closure, Trip Oil Pressure - Low N.A. 1

11. Reactor Mode Switch Shutdown Position N.A. N.A. l, 2, 3, 4, 5 (q)

12. Manual Scram N.A. N.A. 1, 2, 3, 4, 5 (a) Neutron detectors may be excluded from CHANNEL CALIBRATION.

(b) The IRM and SRM channels shall be determined to overlap for at least 1/2 decades during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be determined to overlap for a least 1/2 decades during each controlled shutdown, if not performed within the previous 7 days.

( C) Calibration includes verification that the OPRM Upscale trip auto-enable (not-bypass) setpoint for APRM Simulated Thermal Power is~ 29.5% and for recirculation drive flow is< 60%.

(d) The more frequent calibration shall consist of the adjustment of the APRM channel to conform to the power values calculated by a heat balance during OPERATIONAL CONDITION 1 when THERMAL POWER~ 25% of RATED THERMAL POWER.

Verify the calculated power does not exceed the APRM channels by greater than 2% of RATED THERMAL POWER.

(e) CHANNEL FUNCTIONAL TEST shall include the flow input function, excluding the flow transmitter.

(f) The LPRMs shall be calibrated at least once per 2000 effective full power hours (EFPH).

(g) The less frequent calibration includes the flow input function.

( h) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1.

(i ) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

( j) If the RPS shorting links are required to be removed per Specification 3.9.2, they may be reinstalled for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for required surveillance. During this time, CORE ALTERATIONS shall be suspended, and no control rod shall be moved from its existing position.

( k) DELETED (l ) Not required to be performed when entering OPERATIONAL CONDITION 2 from OPERATIONAL CONDITION 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering OPERATIONAL CONDITION 2.

(m) With THERMAL POWER~ 25% of RATED THERMAL POWER.

( n) Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

LIMERICK - UNIT 2 3/4 3-8 Amendment No. 7,17,4g,J5,79,92,1Q9,1~9.147,15e,le~.196

TABLE 4.3.1.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS (0) If the as-found channel setpoint is outside its predefined as found tolerance, then the channel shall be evaluated to veri that it is functioning as required before returning the channel to service.

(p) The instrument channel setpoint shall be reset to a value that is within the as left tolerance around the Trip Setpoint at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the Trip Setpoint are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as found and the as-left tolerances are specified in the associated Technical Specifications Bases.

(q) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

LIMERICK - UNIT 2 3/4 3-8a Amendment No .163

For Information Only. No Changes Proposed.

INSTRUMENTATION 3/4.3.2. ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2 The isolation actuation instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.2.-2 and with ISOLATION SYSTEM RESPONSE TIME as shown in Table 3.3.2-3.

APPLICABILITY: As shown in Table 3.3.2-1.

ACTION:

a) With an isolation actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.

b) With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirements for one trip system:

1. If placing the inoperable channel(s) in the tripped condition would cause an isolation, the inoperable channel(s) shall be restored to OPERABLE status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or in accordance with the Risk Informed Completion Time Program**#. If this cannot be accomplished, the ACTION required by Table 3.3.2-1 for the affected trip function shall be taken, or the channel shall be placed in the tripped condition.

or

2. If placing the inoperable channel(s) in the tripped condition would not cause an isolation, the inoperable channel(s) and/or that trip system shall be placed in the tripped condition within:

a) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months or in accordance with the Risk Informed Completion Time Program**# for trip functions common* to RPS Instrumentation, b) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program**# for trip functions not common* to RPS Instrumentation.

Trip functions common to RPS Actuation Instrumentation are shown in Table 4.3.2.1-1.

- Not applicable when trip capability is not maintained.

Not applicable for Function 7, Secondary Containment Isolation.

LIMERICK - UNIT 2 3/4 3-9 Amendment No. 17,32,132, 203

For Information Only. No Changes Proposed.

INSTRUMENTATION LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

c. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system** in the tripped condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and take the ACTION required by Table 3.3.2-1.

SURVEILLANCE REQUIREMENTS 4.3.2.1 Each isolation actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS shown in Table 4.3.2.1-1 and at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.3.2.1-1.

4.3.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operations of all channels shall be performed in accordance with the Surveillance Frequency Control Program.

4.3.2.3 The ISOLATION SYSTEM RESPONSE TIME of each isolation trip function shown in Table 3.3.2-3 shall be demonstrated to be within its limit in accordance with the Surveillance Frequency Control Program. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times the frequency specified in accordance with the Surveillance Frequency Control Program, where N is the total number of redundant channels in a specific isolation trip system.

- The trip system need not be placed in the tripped condition if this would cause the Trip Function to occur. When a trip system can be placed in the tripped condition without causing the Trip Function to occur, place the trip system with the most inoperable channels in the tripped condition; if both systems have the same number of inoperable channels, place either trip system in the tripped condition.

LIMERICK - UNIT 2 3/4 3-10 Amendment No. 17, 34, 147

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION MINIMUM APPLICABLE ISOLATION OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b) CONDITION ACTION 3 REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCS Flow - High J 1 1, 2, 3 23

b. RWCS Area Temperature - High J 6 1, 2, 3 23

c. RWCS Area Ventilation Temperature - High J 6 1, 2, 3 23

d. SLCS Initiation (h) Y(d) NA 1, 2, 3 23

e. Reactor Vessel Water Level -

Low, Low - Level 2 B 2 1, 2, 3 23

f. Manual Initiation NA 1 1, 2, 3 24

4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line Pressure - High L 1 1, 2, 3 23

b. HPCI Steam Supply Pressure - Low LA 2 1, 2, 3 23

c. HPCI Turbine Exhaust Diaphragm Pressure - High L 2 1, 2, 3 23

d. HPCI Equipment Room Temperature - High L 1 1, 2, 3 23

e. HPCI Equipment Room Temperature - High L 1 1, 2, 3 23 LIMERICK - UNIT 2 3/4 3-12

For Information Only. No Changes Proposed.

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION ACTION STATEMENTS ACTION 20 - Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 21 - Be in at least STARTUP with the associated penetration flow path(s) isolated by use of one deactivated automatic valve secured in the isolated position, or one closed manual valve or blind flange*** within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 22 - Be in at least STARTUP within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 23 - In OPERATIONAL CONDITION 1 or 2, verify the affected penetration flow path(s) are isolated by use of one deactivated automatic valve secured in the isolated position, or one closed manual valve or blind flange*** within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and declare the affected system inoperable. In OPERATIONAL CONDITION 3, be in at least COLD SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 24 - Restore the manual initiation function to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or isolate the affected penetration flow path(s) by use of one deactivated automatic valve secured in the isolated position, or one closed manual valve or blind flange*** within the next hour and declare the affected system inoperable or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 25 - Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 26 - Isolate the affected penetration flow path(s) by use of one deactivated automatic valve secured in the isolated position, or one closed manual valve or blind flange*** within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 27 - Restore the manual initiation function to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

TABLE NOTATIONS

Required when handling RECENTLY IRRADIATED FUEL in the secondary containment.

- May be bypassed under administrative control, with all turbine stop valves closed.

- - Isolation valves closed to satisfy these requirements may be reopened on an intermittent basis under administrative control.

During operation of the associated Unit 1 or Unit 2 ventilation exhaust system.

(a) DELETED (b) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter. Trip functions common to RPS Actuation Instrumentation are shown in Table 4.3.2.1-1. In addition, for the HPCI system and RCIC system isolation, provided that the redundant isolation valve, inboard or outboard, as applicable, in each line is OPERABLE and all required actuation instrumentation for that valve is OPERABLE, one channel may be placed in an inoperable status for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for required surveillance without placing the channel or trip system in the tripped condition.

LIMERICK - UNIT 2 3/4 3-16 Amendment No. 17, 32, 107, 146, 190, 200

TABLE 3.3.2-1 (Continued)

TABLE NOTATIONS (c) Actuates secondary containment isolation valves. Signal B, H, S, and R also start the standby gas treatment system.

(d) RWCU system inlet outboard isolation valve closes on SLCS "B" initiation.

RWCU system inlet inboard isolation valve closes on SLCS "A" or SLCS "C" initiation.

(e) Manual initiation isolates the steam supply line outboard isolation valve and only following manual or automatic initiation of the system.

(f) In the event of a loss of ventilation the temperature - high setpoint may be raised by 50°F for a period not to exceed 30 minutes to permit restoration of the ventilation flow without a spurious trip. During the 30 minute period, an operator, or other qualified member of the technical staff, shall observe the temperature indications continuously, so that, in the event of rapid increases in temperature, the main steam lines shall be manually isolated.

(g) Wide range accident monitor per Specification 3.3.7.5.

(h) For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2025 refueling outage, the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

LIMERICK - UNIT 2 3/4 3-17 Amendment No. 17, 74, 107

TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK (a) TEST (a) CALIBRATION(a) SURVEILLANCE REQUIRED

3. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCS Flow - High 1, 2, 3

b. RWCS Area Temperature - High 1, 2, 3

c. RWCS Area Ventilation Temperature - High 1, 2, 3

d. SLCS Initiation (b) N.A. N.A. 1, 2, 3

e. Reactor Vessel Water Level Low, Low, - Level 2 1, 2, 3

f. Manual Initiation N.A. N.A. 1, 2, 3

4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line Pressure - High 1, 2, 3

b. HPCI Steam Supply Pressure, Low 1, 2, 3

c. HPCI Turbine Exhaust Diaphragm Pressure - High 1, 2, 3

d. HPCI Equipment Room Temperature - High 1, 2, 3

e. HPCI Equipment Room Temperature - High 1, 2, 3

f. HPCI Pipe Routing Area Temperature - High 1, 2, 3

g. Manual Initiation N.A. N.A. 1, 2, 3

h. HPCI Steam Line Pressure Timer N.A. 1, 2, 3 LIMERICK - UNIT 2 3/4 3-28 Amendment No. 17, 32, 147

TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK(a) TEST(a) CALIBRATION(a) SURVEILLANCE REQUIRED

7. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level Low, Low - Level 2 1, 2, 3

b. Drywell Pressure## - High 1, 2, 3 c.1. Refueling Area Unit 1 Ventilation Exhaust Duct Radiation - High *#

2. Refueling Area Unit 2 Ventilation Exhaust Duct Radiation - High *#

d. Reactor Enclosure Ventilation Exhaust Duct Radiation - High 1, 2, 3

e. Deleted

f. Deleted

g. Reactor Enclosure Manual Initiation N.A. N.A. 1, 2, 3

h. Refueling Area Manual Initiation N.A. N.A. *

(a) Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

Required when handling RECENTLY IRRADIATED FUEL in the secondary containment.

- When not administratively bypassed and/or when any turbine stop valve is open.

During operation of the associated Unit 1 or Unit 2 ventilation exhaust system.

1. These trip functions (2a, 6b, and 7b) are common to the RPS actuation trip function.

(b) For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2025 refueling outage, the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

LIMERICK - UNIT 2 3/4 3-31 Amendment No. 17, 32, 52, 74, 146, 147, 190

I-TABLE 3.3.3-1 (Continued) b-4 m EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION

'-4 MINIMUM OPERABLE CHANNELS PER APPLICABLE C= TRIP (a) OPERATIONAL

-4 TRIP FUNCTION FUNCTION CONDITIONS ACTION

4. AUTOMATIC DEPRESSURIZATION SYSTEM#*%*

a. Reactor Vessel Water Level - Low Low Low, Level 1 2 1, 2, 3 30

b. Dr3well Pressure - High 2 1, 2, 3 30

c. ADS Timer 1 1, 2, 3 31

d. Core Spray Pump Discharge Pressure - High (Permissive) 2 1, 2, 3 31

e. RHR LPCI Mode Pump Discharge Pressure High (Permissive) 4 1, 2, 3 31

f. Reactor Vessel Water Level - Low, Level 3 (Permissive) 1 1, 2, 3 31 SP..

g. Manual Initiation 2 1, 2, 3 33

h. ADS Drywell Pressure Bypass Timer 2 1, 2, 3 31 WA MINIMUM APPLICABLE TOTAL NO. CHANNELS CHANNELS OPERATIONAL OF CHANNELS(f) TO TRIP OPERABLE CONDITIONS ACTION

5. LOSS OF POWER

1. 4.16 kV IEmergency Bus Under-voltage I(Loss of Voltage) 1/bus 1/bus 1/bus 1, 2, 3, 4 **, 5**

36

2. 4.16 kV IEmergency Bus Under-voltage i(Degraded Voltage) 1/source/ 1/source/ 1/source/ 1, 2, 3, 4**, 5** 37 bus bus bus

- - The Minimum OPERABLE Channels Per Trip Function is per subsystem.

(_w

TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION TABLE NOTATIONS (a) A channel may be pl aced in an inoperable status for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) Also provides input to actuation logic for the associated emergency diesel generators.

(c) One trip system. Provides signal to HPCI pump suction valves only.

(d) On 1 out of 2 taken twice logic, provides a signal to trip the HPCI pump turbine only.

(e) The manual initiation push buttons start the respective core spray pump and diesel generator. The "A" and "B" logic manual push buttons al so actuate an initiation permissive in the injection valve opening logic.

(f) A channel as used here is defined as the 127 bus relay for Item 1 and the 127, 127Y, and 127Z feeder relays with their associated time delay relays taken together for Item 2.

DELETED

Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

- Required when ESF equipment is required to be OPERABLE.

1. Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.

1. 1. The injection functions of Drywell Pressure - High and Manual Initiation are not required to be OPERABLE with reactor steam dome pressure less than 550 psig.

LIMERICK - UNIT 2 3/4 3-35 Amendment No. J+, ~ . 190

TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION STATEMENTS ACTION 30 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. With one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program, or declare the associated system inoperable.

b. With more than one channel inoperable, declare the associated system inoperable.

ACTION 31 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, declare the associated ECCS inoperable within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 32 - DELETED ACTION 33 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program*, or declare the associated ECCS inoperable.

ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. For one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program, or declare the HPCI system inoperable.

b. With more than one channel inoperable, declare the HPCI system inoperable.

ACTION 35 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program*, or declare the HPCI system inoperable.

ACTION 36 - With the number of OPERABLE channels less than the Total Number of Channels, declare the associated emergency diesel generator and the associated offsite source breaker that is not supplying the bus inoperable and take the ACTION required by Specification 3.8.1.1 or 3.8.1.2, as appropriate.

Not applicable when trip capability is not maintained.

LIMERICK - UNIT 2 3/4 3-36 Amendment No. -l+,~,-+/--9-0. 203

Ti'eE 3...3-1 (c:inue )

E:*:ERS-'-Y CCRE CX LANG SYSTEN'; ACTUATION :-:ET;.Tw:

ACTION STATEDT'S ACTION 37 - With the number of OPERABLE channels one less than the Total Number of Channels, place the inoperable device in the bypassed condition subject to the following conditions:

Inonerable Device Condition 127-a1XOX 127Y-11XOX and 127Z-1lXOX operable 127Y-llXOX 127-l1XOX and 127Z-llXOX operable 127Z-llXOX 127-llXOX and 127Y-1lXOX operable.

127Z-llYOY operable for the other 3 breakers monitoring that source, offsite source grid voltage for that source is maintained at or above 230kV (for the 101 Safeguard Bus Source) or 525kV (for the 201 Safeguard Bus Source),

Load Tap Changer for that source is in service and in automatic operation, and the electrical buses and breaker alignments are maintained within bounds of approved plant procedures.

or, place the inoperable channel in the tripped condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and take the Action required by Specification 3.8.1.1 or 3.8.1.2, as appropriate Operation may then continue until performance of the next required CHANNEL FUNCTIONAL TEST.

Amendment No. 120 I MAR 2 0 aii1 LIi1ER.ICK - UNIT 2 3/4 3-36a

TABLE 4.3.3.1-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK (a) TEST (a) CALIBRATION(a) SURVEILLANCE REQUIRED

4. AUTOMATIC DEPRESSURIZATION SYSTEM#

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1, 2, 3

b. Drywel l Pressure - High 1, 2, 3 C. ADS Timer N.A. 1, 2, 3

d. Core Spray Pump Discharge Pressure - High 1, 2, 3

e. RHR LPCI Mode Pump Discharge Pressure - High 1, 2, 3

f. Reactor Vessel Water Level - Low, Level 3 1, 2, 3

g. Manual Initiation N.A. N.A. 1, 2, 3

h. ADS Drywel l Pressure Bypass Timer N.A. 1, 2, 3

5. LOSS OF POWER

a. 4.16 kV Emergency Bus Under voltage (Loss of Voltage)## N.A. N.A. 1, 2, 3, 4**, 5**

b. 4.16 kV Emergency Bus Under-voltage (Degraded Voltage) 1, 2, 3, 4**, 5**

(a) Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

DELETED

- Required OPERABLE when ESF equipment is required to be OPERABLE.

- - Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.

Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

1. Loss of Voltage Relay 127-llX is not field setable.

LIMERICK - UNIT 2 3/4 3-41 Amendment No . .W:., +4+, 190

INSTRUMENTATION 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram recirculation pump trip (ATWS-RPT) system instrumentation channels shown in Table 3.3.4.1-1 shall be OPERABLE with their trip setpoints set consistent with values shown in the Trip Setpoint column of Table 3.3.4.1-2.

APPLICABILITY: OPERATIONAL CONDITION 1.

Insert 2 ACTION: