ML17200D096

Application to Revise Technical Specifications to Adopt TSTF-542, Reactor Pressure Vessel Water Inventory Control, Rev. 2.

ML17200D096
Person / Time
Site:	Limerick
Issue date:	07/19/2017
From:	Jim Barstow Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML17200D096 (120)

Text

200 Exelon Way Kennett Square, PA 19348 www.exeloncorp.com 10 CFR 50.90 July 19, 2017 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 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:

Application to Revise Technical Specifications to Adopt TSTF-542, "Reactor Pressure Vessel Water Inventory Control," Revision 2 In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (Exelon) requests an amendment to the Technical Specifications (TS), Appendix A of Renewed Facility Operating License Nos. NFP-39 and NPF-85 for Limerick Generating Station (LGS), Units 1 and 2, respectively.

The proposed changes replace existing TS requirements related to "operations with a potential for draining the reactor vessel" (OPDRVs) with new requirements on Reactor Pressure Vessel Water Inventory Control (RPV WIC) to protect Safety Limit 2.1.4. Safety Limit 2.1.4 requires reactor vessel water level to be greater than the top of active irradiated fuel.

The proposed amendment has been reviewed by the LGS Plant Operations Review Committee in accordance with the requirements of the Exelon Quality Assurance Program.

This amendment request contains no regulatory commitments. provides a description and assessment of the proposed changes. Attachment 2 provides the existing TS pages marked up to show the proposed changes. Attachment 3 provides the existing TS Bases pages marked up to show the proposed changes (information only).

Exelon requests approval of the proposed amendment by February 28, 2018 in support of the Spring 2018 Unit 1 refueling outage. Once approved, the amendments shall be implemented within 90 days.

U.S. Nuclear Regulatory Commission Application to Revise TS to Adopt TSTF-542 Docket Nos. 50-352 and 50-353 July 19, 2017 Page 2 In accordance with 10 CFR 50.91, "Notice for public comment; State consultation,"

paragraph (b), Exelon is notifying the Commonwealth of Pennsylvania of this application for license amendment by transmitting a copy of this letter and its attachments to the designated State Official.

If you have any questions or require additional information, please contact Glenn Stewart at (610) 765-5529.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 191h day of July 2017.

Respectfully, James Barstow Director, Licensing and Regulatory Affairs Exelon Generation Company, LLC Attachments: 1. Description and Assessment

2. Markup of Technical Specifications Pages

3. Markup of Technical Specifications Bases Pages (For Information Only) cc: USNRC Region I, Regional Administrator wl attachments USNRC Senior Resident Inspector, LGS II USNRC Project Manager, LGS II R. R. Janati, Pennsylvania Bureau of Radiation Protection II

ATTACHMENT 1 Limerick Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 Docket Nos. 50-352 and 50-353 Application to Revise Technical Specifications to Adopt TSTF-542, "Reactor Pressure Vessel Water Inventory Control," Revision 2 Description and Assessment

License Amendment Request Attachment 1 Application to Revise TS to Adopt TSTF-542 Page 1 of 6 Docket Nos. 50-352 and 50-353 Description and Assessment

1.0 DESCRIPTION

Exelon Generation Company, LLC (Exelon), requests an amendment to the Technical Specifications (TS), Appendix A of Renewed Facility Operating License Nos. NPF-39 and NPF-85 for Limerick Generating Station (LGS), Units 1 and 2, respectively.

The proposed changes replace existing TS requirements related to "operations with a potential for draining the reactor vessel" (OPDRVs) with new requirements on Reactor Pressure Vessel (RPV) Water Inventory Control (WIC) to protect Safety Limit 2.1.4. Safety Limit 2.1.4 requires reactor vessel water level to be greater than the top of active irradiated fuel.

2.0 ASSESSMENT 2.1 Applicability of Published Safety Evaluation Exelon has reviewed the safety evaluation provided to the Technical Specifications Task Force on December 20, 2016 (Reference 1), as well as the information provided in TSTF-542 (Reference 2). Exelon has concluded that the justifications presented in TSTF-542 and the safety evaluation prepared by the Nuclear Regulatory Commission (NRC) staff are applicable to LGS, Units 1 and 2, and justify this amendment for the incorporation of the changes to the LGS TS.

The following LGS TS reference or are related to OPDRVs and are affected by the proposed changes:

1.0 Definitions 3.3.2 Isolation Actuation Instrumentation 3.3.3 Emergency Core Cooling System Actuation Instrumentation 3.3.7 Radiation Monitoring Instrumentation 3.5.2 ECCS - Shutdown 3.5.3 Suppression Chamber 3.6.5.1.2 Refueling Area Secondary Containment Integrity 3.6.5.2.2 Refueling Area Secondary Containment Automatic Isolation Valves 3.6.5.3 Standby Gas Treatment System - Common System 3.7.2 Control Room Emergency Fresh Air Supply System - Common System 3.8.1.2 A.C. Sources - Shutdown 3.8.2.2 D.C. Sources - Shutdown 3.8.3.2 Distribution - Shutdown 2.2 Variations Exelon is proposing the following variations from the TS changes described in TSTF-542.

These variations do not affect the applicability of TSTF-542 or the NRC staff's safety evaluation to the proposed license amendment.

LGS TS are based on the previous version of the NRC's Standard TS (NUREG-0123, Revision

2) (Reference 3) and, therefore, the wording and format varies slightly from the NRC Improved Standard Technical Specifications (NUREG-1433) shown in TSTF-542, Revision 2, and the applicable parts of the NRC's safety evaluation. This minor variation is administrative in nature and does not affect the applicability of TSTF-542 to the LGS TS.

License Amendment Request Attachment 1 Application to Revise TS to Adopt TSTF-542 Page 2 of 6 Docket Nos. 50-352 and 50-353 Description and Assessment In alignment with TSTF-542, Rev. 2, Proposed Safety Basis (Section 3.1.2), the existing LGS TS 3.5.2 requirement to suspend core alterations as an action for Emergency Core Cooling System (ECCS) inoperability is no longer warranted since there are no postulated events associated with core alterations that are prevented or mitigated by the proposed RPV water inventory control requirements. In addition, loss of RPV inventory events are not initiated by core alteration operations. Refueling Limiting Conditions for Operation (LCOs) provide requirements to ensure safe operation during core alterations, including required water level above the RPV flange. Therefore, LGS proposes to delete TS 3.5.2, Action 'b' in its entirety, including the action relating to core alterations.

In alignment with NUREG-1433, Rev. 4, and consistent with TSTF-542, Rev. 2, LGS proposes to revise TS 3.5.3, "Suppression Chamber," to remove TS requirements associated with OPERATIONAL CONDITIONS (OPCONs) 4 and 5 since they are redundant to the requirements and intent of the newly proposed TS Section 3.5.2, "Reactor Pressure Vessel (RPV) Water Inventory Control (WIC)." For example, the existing LGS TS LCO 3.5.3.b contains conditions that allow the suppression chamber level to be less than the required 16 feet 0 inches in OPCONs 4 and 5 if the conditions are met, such as maintaining an operable flow path for the Core Spray System to take suction from the Condensate Storage Tank (CST) and ensuring there is sufficient level (29 feet) in the CST. These conditions are satisfied by the proposed LCO 3.5.2.a.2.b). In addition, existing LGS Surveillance Requirement (SR) 4.5.3.1.b requires verifying that the suppression chamber water level is 16 feet 0 inches. This is satisfied by proposed SRs 4.5.2.2 and 4.5.2.3.

Because LGS, Unit 1 and Unit 2 TS are based on NUREG-0123, Revision 2, the current LGS TS in Table 3.3.3-1, "Emergency Core Cooling System Actuation Instrumentation," do not include requirements for the following functions that are listed in TSTF-542: "1b - Core Spray Pump Discharge Flow-Low (Bypass)" and "2b - Low Pressure Coolant Injection Pump Discharge Flow-Low (Bypass)." Therefore, to align with current LGS instrumentation TS, no requirements were added for these functions as part of the newly proposed TS Table 3.3.3.A-1.

TSTF-542, Table 3.3.5.2-1, "RPV Water Inventory Control Instrumentation," contains Function 2.a, Reactor Steam Dome Pressure - Low (Injection Permissive)," as a permissive for the injection function of the Low Pressure Coolant Injection (LPCI) system in Modes 4 and 5. The current LGS TS Table 3.3.3-1, "Emergency Core Cooling System Actuation Instrumentation,"

contains a similar Function 2.c, Reactor Vessel Pressure - Low; however, for LGS, this function is only required in OPCONs 1, 2, and 3, and is combined with the Drywell Pressure - High function to provide an automatic initiation signal for LPCI, which is separate from the injection logic. For LGS, the permissive for the injection function of LPCI in OPCONs 4 and 5 from TS Table 3.3.3-1 is Function 2.d, Injection Valve Differential Pressure - Low. This interlock, as determined by monitoring the differential pressure across the injection valve, is to prevent opening the injection valve if reactor pressure is greater than the Residual Heat Removal (RHR) system piping design maximum pressure. Therefore, the new proposed TS Table 3.3.3.A-1, "RPV Water Inventory Control (WIC) Instrumentation," for LGS will include Function 2.a, Injection Valve Differential Pressure - Low (Permissive), for the injection function of the LPCI mode of the RHR system rather than the Reactor Vessel Pressure - Low [Reactor Steam Dome Pressure - Low] function specified in TSTF-542. This variation is consistent with the current LGS TS and operation of the plant, and does not affect the applicability of TSTF-542 to the LGS TS.

License Amendment Request Attachment 1 Application to Revise TS to Adopt TSTF-542 Page 3 of 6 Docket Nos. 50-352 and 50-353 Description and Assessment LGS TS include Amendment Nos. 216 for Unit 1 and 178 for Unit 2 (Reference 4) for TSTF-523, "Generic Letter 2008-01, Managing Gas Accumulation." As discussed in the Technical Evaluation of TSTF-542, Rev. 2, the changes in TSTF-523 are also applicable to the proposed SRs 4.5.2.4 and 4.5.2.5. Therefore, the following changes are being made to the proposed SRs 4.5.2.4 and 4.5.2.5 based on the changes made to the corresponding LGS SRs in the above referenced amendments that adopted TSTF-523. The following changes have no effect on the adoption of the TSTF-542 and are an acceptable variation in accordance with Section 3.2.4.4 of TSTF-542:

• SR 4.5.2.4 has been modified from "Verify, for the required ECCS injection/spray subsystem, the piping is filled with water from the pump discharge valve to the injection valve," to "Verify, for the required ECCS injection/spray subsystem, locations susceptible to gas accumulation are sufficiently filled with water."

• SR 4.5.2.5 has been modified to retain the note: "Not required to be met for system vent flow paths opened under administrative control."

During the development of this LAR to adopt TSTF-542, Rev.2, an administrative error was identified within the LGS Index. As part of LGS Amendment Nos. 174 for Unit 1 and 136 for Unit 2 (ADAMS Accession No. ML043220090), the 'E-AVERAGE DISINTEGRATION ENERGY '

definition was deleted. The LGS TS Index is being revised to reflect this deletion. This change is administrative in nature and does not affect the applicability of TSTF-542 to the LGS TS.

The model application provided in TSTF-542 includes an attachment for typed, camera-ready (revised) TS pages reflecting the proposed changes. LGS is not including such an attachment due to the number of TS pages included in this submittal that have the potential to be affected by other unrelated license amendment requests. Providing only mark-ups of the proposed TS changes satisfies the requirements of 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," in that the mark-ups fully describe the changes desired. This is administrative in nature and does not affect the applicability of TSTF-542 or the NRC's safety evaluation to the proposed license amendment.

The LGS TS contain a Surveillance Frequency Control Program (SFCP). Therefore, the SR frequencies for proposed TS 3.5.2 are "in accordance with the Surveillance Frequency Control Program," and the SR frequencies specified in TSTF-542 will be incorporated into the LGS SFCP upon implementation of the proposed amendment.

LGS TS pages 3/4 3-15, 3/4 3-64, and 3/4 3-66 are provided for information only since the table notations where the reference to operations with the potential for draining the reactor vessel are proposed to be deleted refer to the tables on these pages.

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration Exelon Generation Company, LLC (Exelon), requests an amendment to the Technical Specifications (TS), Appendix A of Renewed Facility Operating License Nos. NPF-39 and NPF-85 for Limerick Generating Station (LGS), Units 1 and 2, respectively.

License Amendment Request Attachment 1 Application to Revise TS to Adopt TSTF-542 Page 4 of 6 Docket Nos. 50-352 and 50-353 Description and Assessment Exelon requests adoption of TSTF-542, "Reactor Pressure Vessel Water Inventory Control,"

which is an approved change to the Standard Technical Specifications (STS), into the LGS TS.

The proposed amendment replaces the existing requirements in the TS related to "operations with a potential for draining the reactor vessel" (OPDRVs) with new requirements on Reactor Pressure Vessel Water (RPV) Inventory Control (WIC) to protect Safety Limit 2.1.4. Safety Limit 2.1.4 requires reactor vessel water level to be greater than the top of active irradiated fuel.

Exelon has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards 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.

The proposed changes replace existing TS requirements related to OPDRVs with new requirements on RPV WIC that will protect Safety Limit 2.1.4. Draining of RPV water inventory in OPERATIONAL CONDITION 4 (i.e., cold shutdown) and OPERATIONAL CONDITION 5 (i.e., refueling), is not an accident previously evaluated and, therefore, replacing the existing TS controls to prevent or mitigate such an event with a new set of controls has no effect on any accident previously evaluated. RPV water inventory control in OPERATIONAL CONDITION 4 or 5 is not an initiator of any accident previously evaluated. The existing OPDRV controls or the proposed RPV WIC controls are not mitigating actions assumed in any accident previously evaluated.

The proposed changes reduce the probability of an unexpected draining event (which is not a previously evaluated accident) by imposing new requirements on the limiting time in which an unexpected draining event could result in the reactor vessel water level dropping to the top of the active fuel (TAF). These controls require cognizance of the plant configuration and control of configurations with unacceptably short drain times.

These requirements reduce the probability of an unexpected draining event. The current TS requirements are only mitigating actions and impose no requirements that reduce the probability of an unexpected draining event.

The proposed changes reduce the consequences of an unexpected draining event (which is not a previously evaluated accident) by requiring an Emergency Core Cooling System (ECCS) subsystem to be operable at all times in OPERATIONAL CONDITIONS 4 and 5. The current TS requirements do not require any water injection systems, ECCS or otherwise, to be Operable in certain conditions in OPERATIONAL CONDITION 5.

The change in requirement from two ECCS subsystems to one ECCS subsystem in OPERATIONAL CONDITIONS 4 and 5 does not significantly affect the consequences of an unexpected draining event because the proposed Actions ensure equipment is available within the limiting drain time that is as capable of mitigating the event as the current requirements. The proposed controls provide escalating compensatory measures to be established as calculated drain times decrease, such as verification of a second method of water injection and additional confirmations that containment and/or filtration would be available if needed.

License Amendment Request Attachment 1 Application to Revise TS to Adopt TSTF-542 Page 5 of 6 Docket Nos. 50-352 and 50-353 Description and Assessment The proposed changes reduce or eliminate some requirements that were determined to be unnecessary to manage the consequences of an unexpected draining event, such as automatic initiation of an ECCS subsystem and control room ventilation. These changes do not affect the consequences of any accident previously evaluated since a draining event in OPERATIONAL CONDITIONS 4 and 5 is not a previously evaluated accident and the requirements are not needed to adequately respond to a draining event.

Therefore, the proposed changes do not involve a significant increase in the probability or 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.

The proposed changes replace existing TS requirements related to OPDRVs with new requirements on RPV WIC that will protect Safety Limit 2.1.4. The proposed changes will not alter the design function of the equipment involved. Under the proposed changes, some systems that are currently required to be operable during OPDRVs would be required to be available within the limiting drain time or to be in service depending on the limiting drain time. Should those systems be unable to be placed into service, the consequences are no different than if those systems were unable to perform their function under the current TS requirements.

The event of concern under the current requirements and the proposed changes is an unexpected draining event. The proposed changes do not create new failure mechanisms, malfunctions, or accident initiators that would cause a draining event or a new or different kind of accident not previously evaluated or included in the design and licensing bases.

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.

The proposed changes replace existing TS requirements related to OPDRVs with new requirements on RPV WIC. The current requirements do not have a stated safety basis and no margin of safety is established in the licensing basis. The safety basis for the new requirements is to protect Safety Limit 2.1.4. New requirements are added to determine the limiting time in which the RPV water inventory could drain to the TAF in the reactor vessel should an unexpected draining event occur. Plant configurations that could result in lowering the RPV water level to the TAF within one hour are now prohibited. New escalating compensatory measures based on the limiting drain time replace the current controls. The proposed TS establish a safety margin by providing defense-in-depth to ensure that the Safety Limit is protected and to protect the public health and safety. While some less restrictive requirements are proposed for plant

License Amendment Request Attachment 1 Application to Revise TS to Adopt TSTF-542 Page 6 of 6 Docket Nos. 50-352 and 50-353 Description and Assessment configurations with long calculated drain times, the overall effect of the change is to improve plant safety and to add safety margin.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above, Exelon concludes that the proposed amendment presents no 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.

4.0 ENVIRONMENTAL CONSIDERATION

Exelon has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, "Standards for Protection Against Radiation," or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets 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 amendment.

5.0 REFERENCES

1. Final Safety Evaluation of Technical Specifications Task Force Traveler TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control," dated December 20, 2016 (TAC No. MF3487). ADAMS Accession No. ML16343B008.

2. TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control," dated March 14, 2016. ADAMS Accession No. ML16074A448.

3. NUREG-0123, Revision 2, "Standard Technical Specifications General Electric Boiling Water Reactors (GE-STS)," dated August 1979.

4. Letter from U.S. NRC (R. B. Ennis) to Exelon (B. Hanson), "Limerick Generating Station, Units 1 and 2 - Issuance of Amendments Re: Adoption of Technical Specification Task Force (TSTF) Traveler TSTF-523, 'Generic Letter 2008-01, Managing Gas Accumulation' (TAC Nos. MF4412 and MF4413)," dated May 11, 2015. ADAMS Accession No. ML15083A403.

ATTACHMENT 2 Proposed Technical Specifications Changes (Mark-ups)

Limerick Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 Docket Nos. 50-352 and 50-353 Application to Revise Technical Specifications to Adopt TSTF-542, "Reactor Pressure Vessel Water Inventory Control," Revision 2 Revised Proposed Technical Specifications Pages Unit 1 TS Pages i 3/4 3-40 3/4 5-7 vii 3/4 3-41 3/4 5-8 xii 3/4 3-41a* 3/4 5-9 xviii 3/4 3-41b* 3/4 6-47 xx 3/4 3-41c* 3/4 6-50 1-2 3/4 3-41d* 3/4 6-52 1-2a* 3/4 3-41e* 3/4 7-6 3/4 3-15 ** 3/4 3-64** 3/4 7-7 3/4 3-16 3/4 3-65 3/4 8-9 3/4 3-31 3/4 3-66** 3/4 8-14a 3/4 3-33 3/4 3-67 3/4 8-20 3/4 3-35 3/4 5-6 3/4 3-36 3/4 5-6a*

Unit 2 TS Pages i 3/4 3-40 3/4 5-7 vii 3/4 3-41 3/4 5-8 xii 3/4 3-41a* 3/4 5-9 xviii 3/4 3-41b* 3/4 6-47 xx 3/4 3-41c* 3/4 6-50 1-2 3/4 3-41d* 3/4 6-52 1-2a* 3/4 3-41e* 3/4 7-6 3/4 3-15** 3/4 3-64** 3/4 7-6a 3/4 3-16 3/4 3-65 3/4 8-9 3/4 3-31 3/4 3-66** 3/4 8-14a 3/4 3-33 3/4 3-67 3/4 8-19 3/4 3-35 3/4 5-6 3/4 8-20 3/4 3-36 3/4 5-6a*

• New TS Page

• • Information Only TS Page

INDEX DEFINITIONS SECTION 1.0 DEFINITIONS PAGE 1.1 ACTION ....................................................... 1-1 1.2 AVERAGE PLANAR EXPOSURE ...................................... 1-1 1.3 AVERAGE PLANAR LINEAR HEAT GENERATION RATE ................... 1-1 1.4 CHANNEL CALIBRATION .......................................... 1-1 1.5 CHANNEL CHECK ................................................ 1-1 1.6 CHANNEL FUNCTIONAL TEST ...................................... 1-1 1.7 CORE ALTERATION .............................................. 1-2 1.7A CORE OPERATING LIMITS REPORT ................................. 1-2 1.8 CRITICAL POWER RATIO ......................................... 1-2 1.9 DOSE EQUIVALENT I-131 ........................................ 1-2 1.9a DOWNSCALE TRIP SETPOINT (DTSP) ............................... 1-2 1.9b DRAIN TIME ................................................... 1-2 1.10 E-AVERAGE DISINTEGRATION ENERGY(DELETED) ..................... 1-2a 1.11 EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME ........... 1-2a 1.12 END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME .... 1-3 1.13 (DELETED) .................................................... 1-3 1.14 (DELETED) .................................................... 1-3 1.15 FREQUENCY NOTATION ........................................... 1-3 1.15a HIGH (POWER) TRIP SETPOINT (HTSP) ............................ 1-3 1.16 IDENTIFIED LEAKAGE ........................................... 1-3 1.16a INTERMEDIATE (POWER) TRIP SETPOINT (ITSP) .................... 1-3 1.17 ISOLATION SYSTEM RESPONSE TIME ............................... 1-3 1.18 LIMITING CONTROL ROD PATTERN ................................. 1-3 1.19 LINEAR HEAT GENERATION RATE .................................. 1-3 1.20 LOGIC SYSTEM FUNCTIONAL TEST ................................. 1-4 LIMERICK - UNIT 1 i Amendment No. 33, 37, 66

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE INSTRUMENTATION (Continued) 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION .......................... 3/4 3-9 Table 3.3.2-1 Isolation Actuation Instrumentation.......................... 3/4 3-11 Table 3.3.2-2 Isolation Actuation Instrumentation Setpoints................ 3/4 3-18 Table 3.3.2-3 Isolation System Instrumen-tation Response Time..................... 3/4 3-23 Table 4.3.2.1-1 Isolation Actuation Instrumen-tation Surveillance Requirements ........................... 3/4 3-27 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION .............................................. 3/4 3-32 Table 3.3.3-1 Emergency Core Cooling System Actuation Instrumentation................ 3/4 3-33 Table 3.3.3-2 Emergency Core Cooling System Actuation Instrumentation Setpoints................................ 3/4 3-37 Table 3.3.3-3 Emergency Core Cooling System Response Times........................... 3/4 3-39 Table 4.3.3.1-1 Emergency Core Cooling System Actuation Instrumentation Surveillance Requirements .............. 3/4 3-40 3/4.3.3.A REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)

INSTRUMENTATION.............................................. 3/4 3-41a Table 3.3.3.A-1 RPV Water Inventory Control (WIC)

Instrumentation ......................... 3/4 3-41b Table 3.3.3.A-2 RPV Water Inventory Control (WIC)

Instrumentation Setpoints ............... 3/4 3-41d Table 4.3.3.A-1 RPV Water Inventory Control (WIC)

Instrumentation Surveillance Requirements 3/4 3-41e 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS Recirculation Pump Trip System Instrumentation .......... 3/4 3-42 Table 3.3.4.1-1 ATWS Recirculation Pump Trip System Instrumentation ................. 3/4 3-43 Table 3.3.4.1-2 ATWS Recirculation Pump Trip System Instrumentation Setpoints .............................. 3/4 3-44 Table 4.3.4.1-1 (Deleted) .............................. 3/4 3-45 End-of-Cycle Recirculation Pump Trip System Instrumentation .............................................. 3/4 3-46 LIMERICK - UNIT 1 vii Amendment No. 33, 186

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE REACTOR COOLANT SYSTEM (Continued) 3/4.4.9 RESIDUAL HEAT REMOVAL Hot Shutdown ............................................... 3/4 4-25 Cold Shutdown .............................................. 3/4 4-26 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ECCS - OPERATING ........................................... 3/4 5-1 3/4.5.2 ECCS --- SHUTDOWNREACTOR PRESSURE VESSEL (RPV)

WATER INVENTORY CONTROL (WIC) ............................. 3/4 5-6 3/4.5.3 SUPPRESSION CHAMBER ........................................ 3/4 5-8 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity .............................. 3/4 6-1 Primary Containment Leakage ................................ 3/4 6-2 Primary Containment Air Lock ............................... 3/4 6-5 MSIV Leakage Alternate Drain Pathway ....................... 3/4 6-7 Primary Containment Structural Integrity ................... 3/4 6-8 Drywell and Suppression Chamber Internal Pressure .......... 3/4 6-9 Drywell Average Air Temperature ............................ 3/4 6-10 Drywell and Suppression Chamber Purge System ............... 3/4 6-11 3/4.6.2 DEPRESSURIZATION SYSTEMS Suppression Chamber ........................................ 3/4 6-12 Suppression Pool Spray ..................................... 3/4 6-15 Suppression Pool Cooling ................................... 3/4 6-16 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES ....................... 3/4 6-17 LIMERICK - UNIT 1 xii Amendment No. 33, 107, 146

INDEX BASES SECTION PAGE 3/4.0 APPLICABILITY .................................................... B 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN............................................. B 3/4 1-1 3/4.1.2 REACTIVITY ANOMALIES........................................ B 3/4 1-1 3/4.1.3 CONTROL RODS................................................ B 3/4 1-2 3/4.1.4 CONTROL ROD PROGRAM CONTROLS................................ B 3/4 1-3 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM............................... B 3/4 1-4 3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE........................................................ B 3/4 2-1 3/4.2.2 (DELETED)................................................... B 3/4 2-2 LEFT INTENTIONALLY BLANK ............................................... B 3/4 2-3 3/4.2.3 MINIMUM CRITICAL POWER RATIO................................ B 3/4 2-4 3/4.2.4 LINEAR HEAT GENERATION RATE................................. B 3/4 2-5 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION................... B 3/4 3-1 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION......................... B 3/4 3-2 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION............................................. B 3/4 3-2 3/4.3.3.A REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC) INSTRUMENTATION ............................ B 3/4 3-2a 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION........... B 3/4 3-3 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION............................................. B 3/4 3-4 3/4.3.6 CONTROL ROD BLOCK INSTRUMENTATION........................... B 3/4 3-4 3/4.3.7 MONITORING INSTRUMENTATION Radiation Monitoring Instrumentation ..................... B 3/4 3-5 LIMERICK - UNIT 1 xviii Amendment No. 7, 33, 66, 69

INDEX BASES SECTION PAGE REACTOR COOLANT SYSTEM (Continued) 3/4.4.5 SPECIFIC ACTIVITY ............................................ B 3/4 4-4 3/4.4.6 PRESSURE/TEMPERATURE LIMITS .................................. B 3/4 4-4 Bases Table B 3/4.4.6-1 Reactor Vessel Toughness ..................... B 3/4 4-7 Bases Figure B 3/4.4.6-1 Fast Neutron Fluence (E>1 MeV) At 1/4 T As A Function of Service Life .......................... B 3/4 4-8 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES ............................. B 3/4 4-6 3/4.4.8 (DELETED) .................................................... B 3/4 4-6 3/4.4.9 RESIDUAL HEAT REMOVAL ........................................ B 3/4 4-6 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUTDOWN.................... B 3/4 5-1 3/4.5.2 REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)................................................ B 3/4 5-3a 3/4.5.3 SUPPRESSION CHAMBER .......................................... B 3/4 5-4 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity ................................ B 3/4 6-1 Primary Containment Leakage .................................. B 3/4 6-1 Primary Containment Air Lock ................................. B 3/4 6-1 MSIV Leakage Control System .................................. B 3/4 6-1 Primary Containment Structural Integrity ..................... B 3/4 6-2 Drywell and Suppression Chamber Internal Pressure................................................... B 3/4 6-2 Drywell Average Air Temperature .............................. B 3/4 6-2 Drywell and Suppression Chamber Purge System ................. B 3/4 6-2 3/4.6.2 DEPRESSURIZATION SYSTEMS ..................................... B 3/4 6-3 LIMERICK - UNIT 1 xx Amendment No. 33, 199 Associated with Amendment 216

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

CORE OPERATING LIMITS REPORT 1.7a The CORE OPERATING LIMITS REPORT (COLR) is the unit-specific document that provides the core operating limits for the current operating reload cycle. These cycle-specific core operating limits shall be determined for each reload cycle in accordance with Specifications 6.9.1.9 thru 6.9.1.12. Plant operation within these limits is addressed in individual specifications.

CRITICAL POWER RATIO 1.8 The CRITICAL POWER RATIO (CPR) shall be the ratio of that power in the assembly which is calculated by application of the (GEXL) correlation to cause some point in the assembly to experience boiling transition, divided by the actual assembly operating power.

DOSE EQUIVALENT I-131 1.9 DOSE EQUIVALENT I-131 shall be that concentration of I-131, microcuries per gram, which alone would produce the same inhalation committed effective dose equivalent (CEDE) as the quantity and isotopic mixture of I-131, I-132, I-133, I-134, and I-135 actually present. The inhalation committed effective dose equivalent (CEDE) conversion factors used for this calculation shall be those listed in Table 2.1 of Federal Guidelines Report 11, Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion, ORNL, 1989, as described in Regulatory Guide 1.183. The factors in the column headed effective yield doses corresponding to the CEDE.

DOWNSCALE TRIP SETPOINT (DTSP) 1.9a The downscale trip setpoint associated with the Rod Block Monitor (RBM) rod block trip setting.

DRAIN TIME 1.9b The DRAIN TIME is the time it would take for the water inventory in and above the Reactor Pressure Vessel (RPV) to drain to the top of the active fuel (TAF) seated in the RPV assuming:

a) The water inventory above the TAF is divided by the limiting drain rate; b) The limiting drain rate is the larger of the drain rate through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths LIMERICK - UNIT 1 1-2 Amendment No. 37, 66, 87, 174, 185

DEFINITIONS DRAIN TIME (Continued) susceptible to a common mode failure (e.g., seismic event, loss of normal power, single human error), for all penetration flow paths below the TAF except:

1. Penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are locked, sealed, or otherwise secured in the closed position, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths;

2. Penetration flow paths capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation; or

3. Penetration flow paths with isolation devices that can be closed prior to the RPV water level being equal to the TAF by a dedicated operator trained in the task, who is in continuous communication with the control room, is stationed at the controls, and is capable of closing the penetration flow path isolation device without offsite power.

c) The penetration flow paths required to be evaluated per paragraph b) are assumed to open instantaneously and are not subsequently isolated, and no water is assumed to be subsequently added to the RPV water inventory; d) No additional draining events occur; and e) Realistic cross-sectional areas and drain rates are used.

A bounding DRAIN TIME may be used in lieu of a calculated value.

1.10 (Deleted)

EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME 1.11 The EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ECCS actuation set-point at the channel sensor until the ECCS equipment is capable of performing its safety function, i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc. Times shall include diesel generator starting and sequence loading delays where applicable. The response time may be measured by any series of sequential, overlapping or total steps such that the entire response time is measured.

LIMERICK - UNIT 1 1-2a Amendment No. 37, 66, 87, 174, 185

TABLE 3.3.2-1 (Continued)

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

7. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level Low, Low - Level 2 B 2 1, 2, 3 25

b. Drywell Pressure - High H 2 1, 2, 3 25 c.1. Refueling Area Unit 1 Ventilation Exhaust Duct Radiation - High R 2 *# 25

2. Refueling Area Unit 2 Ventilation Exhaust Duct Radiation - High R 2 *# 25

d. Reactor Enclosure Ventilation Exhaust Information Only Duct Radiation - High S 2 1, 2, 3 25

e. Deleted

f. Deleted

g. Reactor Enclosure Manual Initiation NA 1 1, 2, 3 24

h. Refueling Area Manual Initiation NA 1

• 25 LIMERICK - UNIT 1 3/4 3-15 Amendment No. 6, 23, 33, 40, 112

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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24-hours.

ACTION 21 - Be in at least STARTUP with the associated isolation valves closed within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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

ACTION 23 - In OPERATIONAL CONDITION 1 or 2, verify the affected system isolation valves are closed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and declare the affected system inoperable. In OPERATIONAL CONDITION 3, be in at least COLD SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

ACTION 24 - Restore the manual initiation function to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or close the affected system isolation valves 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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

ACTION 26 - Close the affected system isolation valves within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

TABLE NOTATIONS

• Required when (1) handling RECENTLY IRRADIATED FUEL in the secondary containment, or (2) during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

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

1. 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 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

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 (1) handling RECENTLY IRRADIATED FUEL in the secondary containment, or (2) during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

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

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

1. 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

TABLE 3.3.3-1 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION MINIMUM OPERABLE CHANNELS PER APPLICABLE TRIP OPERATIONAL TRIP FUNCTION FUNCTION(a) CONDITIONS ACTION

1. CORE SPRAY SYSTEM***

a. Reactor Vessel Water Level - Low Low Low, Level 1 2/pump(b) 1, 2, 3, 4*, 5* 30

b. Drywell Pressure - High 2/pump(b) 1, 2, 3 30

c. Reactor Vessel Pressure - Low (Permissive) 6(b) 1, 2, 3 31 4*, 5* 32

d. Manual Initiation 2(e) 1, 2, 3, 4*, 5* 33

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM***

a. Reactor Vessel Water Level - Low Low Low, Level 1 2 1, 2, 3, 4*, 5* 30

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

c. Reactor Vessel Pressure - Low (Permissive) 2 1, 2, 3 31

d. Injection Valve Differential Pressure-Low 1/valve 1, 2, 3, 4*, 5* 31 (Permissive)

e. Manual Initiation 1 1, 2, 3, 4*, 5* 33

3. HIGH PRESSURE COOLANT INJECTION SYSTEM##

a. Reactor Vessel Water Level - Low Low Level 2 4 1, 2, 3 34

b. Drywell Pressure - High### 4 1, 2, 3 34

c. condensate Storage Tank Level - Low 2(c) 1, 2, 3 35

d. Suppression Pool Water Level - High 2 1, 2, 3 35

e. Reactor Vessel Water Level - High, Level 8 4(d) 1, 2, 3 31

f. Manual Initiation### 1/system 1, 2, 3 33 LIMERICK - UNIT 1 3/4 3-33 Amendment No. 224

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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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.

• When the system is required to be OPERABLE per Specification 3.5.2.DELETED

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

1. 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. 53, 224

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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 32 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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.

LIMERICK - UNIT 1 3/4 3-36 Amendment No. 11, 53, 158

TABLE 4.3.3.1-1 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

1. CORE SPRAY SYSTEM

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1, 2, 3, 4*, 5*

b. Drywell Pressure - High 1, 2, 3

c. Reactor Vessel Pressure - Low 1, 2, 3, 4*, 5*

d. Manual Initiation N.A. N.A. 1, 2, 3, 4*, 5*

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1, 2, 3, 4*, 5*

b. Drywell Pressure - High 1, 2, 3

c. Reactor Vessel Pressure - Low 1, 2, 3

d. Injection Valve Differential Pressure - Low (Permissive) 1, 2, 3, 4*, 5*

e. Manual Initiation N.A. N.A. 1, 2, 3, 4*, 5*

3. HIGH PRESSURE COOLANT INJECTION SYSTEM***

a. Reactor Vessel Water Level -

Low Low, Level 2 1, 2, 3

b. Drywell Pressure - High 1, 2, 3

c. Condensate Storage Tank Level -

Low 1, 2, 3

d. Suppression Pool Water Level -

High 1, 2, 3

e. Reactor Vessel Water Level -

High, Level 8 1, 2, 3

f. Manual Initiation N.A. N.A. 1, 2, 3 LIMERICK - UNIT 1 3/4 3-40 Amendment No. 53, 71, 186

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. Drywell 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.

• When the system is required to be OPERABLE per Specification 3.5.2.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.

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

1. 1. Loss of Voltage Relay 127-11X is not field setable.

LIMERICK - UNIT 1 3/4 3-41 Amendment No. 53, 186

INSTRUMENTATION 3/4.3.3.A REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)

INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.A The RPV Water Inventory Control (WIC) instrumentation channels shown in Table 3.3.3.A-1 shall be OPERABLE.

APPLICABILITY: As shown in Table 3.3.3.A-1 ACTION:

a. With one or more channels inoperable in a trip system, take the ACTION referenced in Table 3.3.3.A-1 for the trip system.

SURVEILLANCE REQUIREMENTS 4.3.3.1.A Each RPV Water Inventory Control (WIC) instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and LOGIC SYSTEM FUNCTIONAL TEST as shown in Table 4.3.3.A-1 and at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.3.3.A-1.

LIMERICK - UNIT 1 3/4 3-41a Amendment No.

TABLE 3.3.3.A-1 RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION MINIMUM OPERABLE CHANNELS PER APPLICABLE TRIP OPERATIONAL TRIP FUNCTION FUNCTION CONDITIONS ACTION

1. CORE SPRAY SYSTEM

a. Reactor Vessel Pressure - Low (Permissive) 6(a) 4, 5 39

b. Manual Initiation 2(a) 4, 5 40

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Injection Valve Differential Pressure - Low (Permissive) 1/valve(a) 4, 5 39

b. Manual Initiation 1(a) 4, 5 40

3. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level -

Low - Level 3 2 in one (b) 38 trip system

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. Reactor Vessel Water Level -

Low, Low - Level 2 2 in one (b) 38 trip system (a) Associated with an ECCS subsystem required to be OPERABLE by LCO 3.5.2, "REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)."

(b) When automatic isolation of the associated penetration flow path(s) is credited in calculating DRAIN TIME.

LIMERICK - UNIT 1 3/4 3-41b Amendment No.

TABLE 3.3.3.A-1 (Continued)

RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION ACTION STATEMENTS ACTION 38 - Declare the associated trip system for the penetration flow path(s) incapable of automatic isolation and calculate DRAIN TIME.

ACTION 39 - Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, place channel in trip. Otherwise, declare associated low pressure ECCS injection/spray subsystem inoperable.

ACTION 40 - Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, restore channel to OPERABLE status. Otherwise, declare associated low pressure ECCS injection/spray subsystem inoperable.

LIMERICK - UNIT 1 3/4 3-41c Amendment No.

TABLE 3.3.3.A-2 RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION SETPOINTS ALLOWABLE TRIP FUNCTION VALUE

1. CORE SPRAY SYSTEM

a. Reactor Vessel Pressure - Low (Permissive) > 435 psig (decreasing)

b. Manual Initiation N.A.

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Injection Valve Differential Pressure - Low (Permissive) < 84 psid

b. Manual Initiation N.A.

3. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level -

Low - Level 3 11.0 inches

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. Reactor Vessel Water Level -

Low, Low - Level 2 -45 inches LIMERICK - UNIT 1 3/4 3-41d Amendment No.

TABLE 4.3.3.A-1 RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL LOGIC SYSTEM OPERATIONAL CHANNEL FUNCTIONAL FUNCTIONAL CONDITIONS FOR WHICH TRIP FUNCTION CHECK(a) TEST(a) TEST(a) SURVEILLANCE REQUIRED

1. CORE SPRAY SYSTEM

a. Reactor Vessel Pressure - Low (Permissive) N.A. 4, 5

b. Manual Initiation N.A. N.A. 4, 5

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Injection Valve Differential Pressure - Low (Permissive) N.A. 4, 5

b. Manual Initiation N.A. N.A. 4, 5

3. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level -

Low - Level 3 N.A. (b)

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. Reactor Vessel Water Level -

Low, Low - Level 2 N.A. (b)

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

(b) When automatic isolation of the associated penetration flow path(s) is credited in calculating DRAIN TIME.

LIMERICK - UNIT 1 3/4 3-41e Amendment No.

TABLE 3.3.7.1-1 RADIATION MONITORING INSTRUMENTATION MINIMUM CHANNELS APPLICABLE ALARM/TRIP INSTRUMENTATION OPERABLE CONDITIONS SETPOINT ACTION

1. Main Control Room Normal 4 1,2,3, 1 x 10-5 Ci/cc 70 Fresh Air Supply Radiation and

• Monitor

2. Area Monitors

a. Criticality Monitors

1) Spent Fuel 2 (a) 5 mR/h and 20mR/h(b) 71 Storage Pool

b. Control Room Direct1 At All Times N.A.(b) 73 Radiation Monitor Information Only

3. Reactor Enclosure Cooling Water Radiation Monitor 1 At All Times 3 x Background(b) 72 LIMERICK - UNIT 1 3/4 3-64 Amendment No. 185

TABLE 3.3.7.1-1 (Continued)

RADIATION MONITORING INSTRUMENTATION TABLE NOTATIONS

• When RECENTLY IRRADIATED FUEL is being handled in the secondary containment or during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

(a) With fuel in the spent fuel storage pool.

(b) Alarm only.

ACTION STATEMENTS ACTION 70 - With one monitor inoperable, restore the inoperable monitor to the OPERABLE status within 7 days or, within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, initiate and maintain operation of the control room emergency filtration system in the radiation isolation mode of operation.

With two or more of the monitors inoperable, within one hour, initiate and maintain operation of the control room emergency filtration system in the radiation mode of operation.

ACTION 71 - With one of the required monitor inoperable, assure a portable continuous monitor with the same alarm setpoint is OPERABLE in the vicinity of the installed monitor during any fuel movement.

If no fuel movement is being made, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 72 - With the required monitor inoperable, obtain and analyze at least one grab sample of the monitored parameter at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 73 - With the required monitor inoperable, assure a portable alarming monitor is OPERABLE in the vicinity of the installed monitor or perform area surveys of the monitored area with portable monitor-ing instrumentation at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

LIMERICK - UNIT 1 3/4 3-65 Amendment No. 185

TABLE 4.3.7.1-1 RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS OPERATIONAL CHANNEL CONDITIONS FOR CHANNEL FUNCTIONAL CHANNEL WHICH SURVEILLANCE INSTRUMENTATION CHECK(c) TEST (c) CALIBRATION(c) IS REQUIRED

1. Main Control Room Normal Fresh Air Supply Radiation Monitor 1, 2, 3, and *

2. Area Monitors

a. Criticality Monitors

1) Spent Fuel Storage (a)

Pool

b. Control Room Direct At All Times Information Only Radiation Monitor

3. Reactor Enclosure Cooling Water Radiation Monitor (b) At All Times LIMERICK - UNIT 1 3/4 3-66 Amendment No. 70, 185, 186

TABLE 4.3.7.1-1 (Continued)

RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS TABLE NOTATIONS

• When RECENTLY IRRADIATED FUEL is being handled in the secondary containment or during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

(a) With fuel in the spent fuel storage pool.

(b) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards (NBS) or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used.

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

LIMERICK - UNIT 1 3/4 3-67 Amendment No. 185, 186

EMERGENCY CORE COOLING SYSTEMS 3/4 5.2 ECCS -- SHUTDOWN 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 <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> AND At least two one of the following shall be OPERABLE:

a. Core spray system (CSS) subsystems with a 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 subsystems with a 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 one none of the above required subsystems inoperableOPERABLE, restore at least twoone subsystems to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Otherwise, initiate action to establish a method of water injection capable of operating without offsite electrical power or suspend all operations with a potential for draining the reactor vessel.

b. With both of the above required subsystems inoperable, suspend CORE ALTERATIONS and all operations with a potential for draining the reactor vessel. Restore at least one subsystem to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or establish SECONDARY CONTAINMENT INTEGRITY within the next 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> DELETED.

• The ECCS is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded, the spent fuel pool gates are removed, and water level is maintained within the limits of Specifications 3.9.8 and 3.9.9.

• • 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. 95

EMERGENCY CORE COOLING SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION:

c. With DRAIN TIME less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> and greater than or equal to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, within 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />s:

1. Verify SECONDARY CONTAINMENT INTEGRITY is capable of being established in less than the DRAIN TIME,

2. Verify each secondary containment penetration flow path is capable of being isolated in less than the DRAIN TIME, and

3. Verify one standby gas treatment subsystem is capable of being placed in operation in less than the DRAIN TIME.

d. With DRAIN TIME less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, immediately:

1. Initiate action to establish an additional method of water injection with water sources capable of maintaining RPV water level greater than TAF for greater than or equal to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />,***

2. Initiate action to establish SECONDARY CONTAINMENT INTEGRITY,

3. Initiate action to isolate each secondary containment penetration flow path or verify it can be manually isolated from the control room, and

4. Initiate action to verify one standby gas treatment subsystem is capable of being placed in operation.

e. With required ACTION and associated allowed outage time for ACTIONs c. or d. not met, or DRAIN TIME less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, initiate action to restore DRAIN TIME to greater than or equal to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

• • • The required injection/spray subsystem or an additional method of water injection shall be capable of operating without offsite electrical power.

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

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.2.1 Verify DRAIN TIME is greater than or equal to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> in accordance with the Surveillance Frequency Control Program At least the above required ECCS shall be demonstrated OPERABLE per Surveillance Requirement 4.5.1.*

4.5.2.2 Verify, for a required LPCI subsystem, the suppression pool water level is greater than or equal to 16 feet 0 inches in accordance with the Surveillance Frequency Control Program The core spray system shall be determined OPERABLE in accordance with the Surveillance Frequency Control Program by verifying the condensate storage tank required volume when the condensate storage tank is required to be OPERABLE per Specification 3.5.2a.2.b).

4.5.2.3 Verify, for a required CSS subsystem, that the suppression pool water level is greater than or equal to 16 feet 0 inches or the condensate storage tank water level is greater than or equal to 29 feet 0 inches in accordance with the Surveillance Frequency Control Program.

4.5.2.4 Verify, for the required ECCS injection/spray subsystem, locations susceptible to gas accumulation are sufficiently filled with water.

4.5.2.5 Verify, for the required ECCS injection/spray subsystem, each manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position in accordance with the Surveillance Frequency Control Program.#^

4.5.2.6 Operate the required ECCS injection/spray subsystem through the recirculation line for greater than or equal to 10 minutes in accordance with the Surveillance Frequency Control Program.

4.5.2.7 Verify each valve credited for automatically isolating a penetration flow path actuates to the isolation position on an actual or simulated isolation signal in accordance with the Surveillance Frequency Control Program.

4.5.2.8 Verify the required ECCS injection/spray subsystem actuates on a manual initiation signal in accordance with the Surveillance Frequency Control Program.##

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

1. Not required to be met for system vent flow paths open under administrative control.

^Except that an automatic valve capable of automatic return to its ECCS position when an ECCS signal is present may be in position for another mode of operation.

1. 1. Vessel injection/spray may be excluded.

LIMERICK - UNIT 1 3/4 5-7 Amendment No. 95, 186

EMERGENCY CORE COOLING SYSTEMS 3/4.5.3 SUPPRESSION CHAMBER LIMITING CONDITION FOR OPERATION 3.5.3 The suppression chamber shall be OPERABLE:

a. In OPERATIONAL CONDITIONS 1, 2, and 3 with a contained water volume of at least 122,120 ft3, equivalent to a level of 22'0".

b. DELETEDIn OPERATIONAL CONDITION 4 and 5* with a contained water volume of at least 88,825 ft3, equivalent to a level of 16'0", except that the suppression chamber level may be less than the limit or may be drained provided that:

1. No operations are performed that have a potential for draining the reactor vessel,

2. The reactor mode switch is locked in the Shutdown or Refuel position,

3. The condensate storage tank contains at least 135,000 available gallons of water, equivalent to a level of 29 feet, and

4. The core spray system is OPERABLE per Specification 3.5.2 with an OPERABLE flow path capable of taking suction from the condensate storage tank and transferring the water through the spray sparger to the reactor vessel.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3, 4, and 5*.

ACTION:

a. In OPERATIONAL CONDITION 1, 2 or 3 with the suppression chamber water level less than the above limit, restore the water level to within the limit within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. DELETEDIn OPERATIONAL CONDITION 4 or 5* with the suppression chamber water level less than the above limit or drained and the above required conditions not satisfied, suspend CORE ALTERATIONS and all operations that have a potential for draining the reactor vessel and lock the reactor mode switch in the Shutdown position. Establish SECONDARY CONTAINMENT INTEGRITY within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

• The suppression chamber is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded or being flooded from the suppression pool, the spent fuel pool gates are removed when the cavity is flooded, and the water level is maintained within the limits of Specifications 3.9.8 and 3.9.9.

LIMERICK - UNIT 1 3/4 5-8 Amendment No.

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.3.1 The suppression chamber shall be determined OPERABLE by verifying the water level to be greater than or equal to, as applicable:

a. 22'0" in accordance with the Surveillance Frequency Control Program.

b. DELETED16'0" in accordance with the Surveillance Frequency Control Program.

4.5.3.2 DELETEDWith the suppression chamber level less than the above limit or drained in OPERATIONAL CONDITION 4 or 5*, in accordance with the Surveillance Frequency Control Program:

a. Verify the required conditions of Specification 3.5.3b. to be satisfied, or

b. Verify footnote conditions

• to be satisfied.

• The suppression chamber is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded or being flooded from the suppression pool, the spent fuel pool gates are removed when the cavity is flooded, and the water level is maintained within the limits of Specifications 3.9.8 and 3.9.9.

LIMERICK - UNIT 1 3/4 5-9 Amendment No. 186

CONTAINMENT SYSTEMS 3/4.6.5 SECONDARY CONTAINMENT REFUELING AREA SECONDARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.5.1.2 REFUELING AREA SECONDARY CONTAINMENT INTEGRITY shall be maintained.

APPLICABILITY: When RECENTLY IRRADIATED FUEL is being handled in the secondary containment, or during operations with a potential for draining the reactor vessel, with the vessel head removed and fuel in the vessel.

ACTION:

Without REFUELING AREA SECONDARY CONTAINMENT INTEGRITY, suspend handling of RECENTLY IRRADIATED FUEL in the secondary containment and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.1.2 REFUELING AREA SECONDARY CONTAINMENT INTEGRITY shall be demonstrated by:

a. Verifying in accordance with the Surveillance Frequency Control Program that the pressure within the refueling area secondary containment is greater than or equal to 0.25 inch of vacuum water gauge.

b. Verifying in accordance with the Surveillance Frequency Control Program that:

1. All refueling area secondary containment equipment hatches and blowout panels are closed and sealed.

2. At least one door in each access to the refueling area secondary containment is closed, except when the access opening is being used for entry and exit.

3. All refueling area secondary containment penetrations not capable of being closed by OPERABLE secondary containment automatic iso-lation dampers/valves and required to be closed during accident conditions are closed by valves, blind flanges, slide gate dampers or deactivated automatic dampers/valves secured in position.

c. In accordance with the Surveillance Frequency Control Program:

Operating one standby gas treatment subsystem for one hour and main-taining greater than or equal to 0.25 inch of vacuum water gauge in the refueling area secondary containment at a flow rate not exceeding 764 cfm.

LIMERICK - UNIT 1 3/4 6-47 Amendment No. 29,71,185,186, 220

CONTAINMENT SYSTEMS REFUELING AREA SECONDARY CONTAINMENT AUTOMATIC ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.5.2.2 The refueling area secondary containment ventilation system automatic isolation valves shall be OPERABLE.

APPLICABILITY: When RECENTLY IRRADIATED FUEL is being handled in the secondary containment, or during operations with a potential for draining the reactor vessel, with the vessel head removed and fuel in the vessel.

ACTION:

With one or more of the refueling area secondary containment ventilation system automatic isolation valves inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> either:

a. Restore the inoperable valves to OPERABLE status, or

b. Isolate each affected penetration by use of at least one deactivated valve secured in the isolation position, or

c. Isolate each affected penetration by use of at least one closed manual valve, blind flange or slide gate damper.

Otherwise, suspend handling of RECENTLY IRRADIATED FUEL in the refueling area secondary containment, and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.2.2 Each refueling area secondary containment ventilation system auto-matic isolation valve shall be demonstrated OPERABLE:

a. Prior to returning the valve to service after maintenance, repair or replacement work is performed on the valve or its associated actuator, control or power circuit by cycling the valve through at least one complete cycle of full travel and verifying the specified isolation time.

b. In accordance with the Surveillance Frequency Control Program by verifying that on a containment isolation test signal each isolation valve actuates to its isolation position.

c. By verifying the isolation time to be within its limit in accordance with the Surveillance Frequency Control Program.

LIMERICK - UNIT 1 3/4 6-50 Amendment No. 6,40,71,105,185, 186

CONTAINMENT SYSTEMS STANDBY GAS TREATMENT SYSTEM - COMMON SYSTEM LIMITING CONDITION FOR OPERATION 3.6.5.3 Two independent standby gas treatment subsystems shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, and when (1) irradiated fuel is being handled in the refueling area secondary containment, or (2) during CORE ALTERATIONS, or (3) during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

ACTION:

a. In OPERATIONAL CONDITION 1, 2, or 3:

1. With one standby gas treatment subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. When (1) irradiated fuel is being handled in the refueling area secondary containment, or (2) during CORE ALTERATIONS, or (3) during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel:

1. With one standby gas treatment subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days, or suspend handling of irradiated fuel in the secondary containment, and CORE ALTERATIONS and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

2. With both standby gas treatment subsystems inoperable, if in progress, suspend handling of irradiated fuel in the secondary containment and, CORE ALTERATIONS or operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3. are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.3 Each standby gas treatment subsystem shall be demonstrated OPERABLE:

a. In accordance with the Surveillance Frequency Control Program by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates with the heaters OPERABLE.

LIMERICK - UNIT 1 3/4 6-52 Amendment No. 29,40,185,186, 200

PLANT SYSTEMS 3/4.7.2 CONTROL ROOM EMERGENCY FRESH AIR SUPPLY SYSTEM - COMMON SYSTEM LIMITING CONDITION FOR OPERATION 3.7.2 Two independent control room emergency fresh air supply system subsystems shall be OPERABLE.

NOTE: The main control room envelope (CRE) boundary may be opened intermittently under administrative control APPLICABILITY: All OPERATIONAL CONDITIONS and when RECENTLY IRRADIATED FUEL is being handled in the secondary containment, or during operations with a potential for draining the reactor vessel.

ACTION:

a. In OPERATIONAL CONDITION 1, 2, or 3:

1. With one control room emergency fresh air supply subsystem inoperable for reasons other than Condition a.2, restore the inoperable subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. With one or more control room emergency fresh air supply subsystems inoperable due to an inoperable CRE boundary,

a. Initiate action to implement mitigating actions immediately or be in HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and

b. Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, verify mitigating actions ensure CRE occupant exposures to radiological and chemical hazards will not exceed limits and actions to mitigate exposure to smoke hazards are taken or be in HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and

c. Restore CRE boundary to operable status within 90 days or be in HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. In OPERATIONAL CONDITION 4, 5, or when RECENTLY IRRADIATED FUEL is being handled in the secondary containment, or during operations with a potential for draining the reactor vessel:

1. With one control room emergency fresh air supply subsystems inoperable for reasons other than Condition b.3, restore the inoperable subsystem to OPERABLE status within 7 days or initiate and maintain operation of the OPERABLE subsystem in the radiation isolation mode of operation.

2. With both control room emergency fresh air supply subsystems inoperable for reasons other than Condition b.3, immediately suspend handling of RECENTLY IRRADIATED FUEL in the secondary containment and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

LIMERICK - UNIT 1 3/4 7-6 Amendment No. 40,71,185,186, 188

PLANT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

3. With one or more control room emergency fresh air subsystems inoperable due to an inoperable CRE boundary, immediately suspend handling of RECENTLY IRRADIATED FUEL in the secondary containment and operations with a potential for draining the reactor vessel.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.7.2.1 Each control room emergency fresh air supply subsystem shall be demonstrated OPERABLE:

a. In accordance with the Surveillance Frequency Control Program by verifying the control room air temperature to be less than or equal to 85°F effective temperature.

b. In accordance with the Surveillance Frequency Control Program on a STAGGERED TEST BASIS by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates with the heaters OPERABLE.

c. In accordance with the Surveillance Frequency Control Program or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire, or chemical release in any ventilation zone communicating with the subsystem by:

1. Verifying that the subsystem satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.5.a, C.5.c, and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 3000 cfm +/- 10%.

2. Verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, shows the methyl iodide penetration of less than 2.5%

when tested in accordance with ASTM D3803-1989 at a temperature of 30°C (86°F) and a relative humidity of 70%.

3. Verifying a subsystem flow rate of 3000 cfm +/- 10% during subsystem operation when tested in accordance with ANSI N510-1980.

d. After every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of charcoal adsorber operation by verifying within 31 days after removal that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, shows the methyl iodide penetration of less than 2.5%

when tested in accordance with ASTM D3803-1989 at a temperature of 30°C (86°F) and a relative humidity of 70%.

LIMERICK - UNIT 1 3/4 7-7 Amendment No. 5,40,71,144,185, 186, 188

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 1E 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, operations with a potential for draining the reactor vessel 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.

• When handling irradiated fuel in the secondary containment.

LIMERICK - UNIT 1 3/4 8-9 Amendment No. 32, 192, 193

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

2. Division 1 or 2 with float current > 2 amps, or with Division 3 or 4 with float current > 1 amp, perform 4.8.2.1.a.2 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for affected battery(s) and restore battery float current to within limits within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.

3. One or two batteries on one division with one or more cells electrolyte level less than minimum established design limits, if electrolyte level was below the top of the plates restore electrolyte level to above top of plates within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and verify no evidence of leakage(*) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In all cases, restore electrolyte level to greater than or equal to minimum established design limits within 31 days.

4. One or two batteries on one division with pilot cell electrolyte temperature less than minimum established design limits, restore battery pilot cell temperature to greater than or equal to minimum established design limits within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

5. Batteries in more than one division affected, restore battery parameters for all batteries in one division to within limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

6. (i) Any battery having both (Action b.1) one or more battery cells float voltage < 2.07 volts and (Action b.2) float current not within limits, and/or (ii) Any battery not meeting any Action b.1 through b.5, Restore the battery parameters to within limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

c. 1. With the requirements of Action a. and/or Action b. not met, or

2. With less than two divisions of the above required D.C. electrical power sources OPERABLE for reasons other than Actions a. and/or b.,

Suspend CORE ALTERATIONS and, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

d. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.2.2 At least the above required battery and charger shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.1.

(*) Contrary to the provisions of Specification 3.0.2, if electrolyte level was below the top of the plates, the verification that there is no evidence of leakage is required to be completed regardless of when electrolyte level is restored.

LIMERICK - UNIT 1 3/4 8-14a Amendment No. 164

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5, and *.

ACTION:

a. With less than two divisions of the above required Unit 1 A.C. dis-tribution systems energized, suspend CORE ALTERATIONS and, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

b. With less than two divisions of the above required Unit 1 D.C. dis-tribution systems energized, suspend CORE ALTERATIONS and, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

c. With any of the above required Unit 2 and common AC and/or DC distribution system divisions not energized, declare the associated common equipment inoperable, and take the appropriate ACTION for that system.

d. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.3.2 At least the above required power distribution system divisions shall be determined energized in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and voltage on the busses/MCCs/panels.

• When handling irradiated fuel in the secondary containment.

LIMERICK - UNIT 1 3/4 8-20 Amendment No. 24, 186

INDEX DEFINITIONS SECTION 1.0 DEFINITIONS PAGE 1.1 ACTION ....................................................... 1-1 1.2 AVERAGE PLANAR EXPOSURE ...................................... 1-1 1.3 AVERAGE PLANAR LINEAR HEAT GENERATION RATE ................... 1-1 1.4 CHANNEL CALIBRATION .......................................... 1-1 1.5 CHANNEL CHECK ................................................ 1-1 1.6 CHANNEL FUNCTIONAL TEST ...................................... 1-1 1.7 CORE ALTERATION .............................................. 1-2 1.7A CORE OPERATING LIMITS REPORT ................................. 1-2 1.8 CRITICAL POWER RATIO ......................................... 1-2 1.9 DOSE EQUIVALENT I-131 ........................................ 1-2 1.9a DOWNSCALE TRIP SETPOINT (DTSP) ............................... 1-2 1.9b DRAIN TIME ................................................... 1-2 1.10 E -AVERAGE DISINTEGRATION ENERGY (DELETED) ................... 1-2a 1.11 EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME ........... 1-2a 1.12 END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME .... 1-3 1.13 (DELETED) .................................................... 1-3 1.14 (DELETED) .................................................... 1-3 1.15 FREQUENCY NOTATION ........................................... 1-3 1.15a HIGH (POWER) TRIP SETPOINT (HTSP) ............................ 1-3 1.16 IDENTIFIED LEAKAGE ........................................... 1-3 1.16a INTERMEDIATE (POWER) TRIP SETPOINT (ITSP) .................... 1-3 1.17 ISOLATION SYSTEM RESPONSE TIME ............................... 1-3 1.18 LIMITING CONTROL ROD PATTERN ................................. 1-3 1.19 LINEAR HEAT GENERATION RATE .................................. 1-3 1.20 LOGIC SYSTEM FUNCTIONAL TEST ................................. 1-4 LIMERICK - UNIT 2 i Amendment No. 4, 48

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE INSTRUMENTATION (Continued) 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION .......................... 3/4 3-9 Table 3.3.2-1 Isolation Actuation Instrumentation...... 3/4 3-11 Table 3.3.2-2 Isolation Actuation Instrumentation Setpoints................ 3/4 3-18 Table 3.3.2-3 Isolation System Instrumentation Response Time............................ 3/4 3-23 Table 4.3.2.1-1 Isolation Actuation Instrumentation Surveillance Requirements .............. 3/4 3-27 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION .............................................. 3/4 3-32 Table 3.3.3-1 Emergency Core Cooling System Actuation Instrumentation................ 3/4 3-33 Table 3.3.3-2 Emergency Core Cooling System Actuation Instrumentation Setpoints...... 3/4 3-37 Table 3.3.3-3 Emergency Core Cooling System Response Times........................... 3/4 3-39 Table 4.3.3.1-1 Emergency Core Cooling System Actuation Instrumentation Surveillance Requirements .............. 3/4 3-40 3/4.3.3.A REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)

INSTRUMENTATION.............................................. 3/4 3-41a Table 3.3.3.A-1 RPV Water Inventory Control (WIC)

Instrumentation ......................... 3/4 3-41b Table 3.3.3.A-2 RPV Water Inventory Control (WIC)

Instrumentation Setpoints ............... 3/4 3-41d Table 4.3.3.A-1 RPV Water Inventory Control (WIC)

Instrumentation Surveillance Requirements 3/4 3-41e 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS Recirculation Pump Trip System Instrumentation .......... 3/4 3-42 Table 3.3.4.1-1 ATWS Recirculation Pump Trip System Instrumentation ................. 3/4 3-43 Table 3.3.4.1-2 ATWS Recirculation Pump Trip System Instrumentation Setpoints .............................. 3/4 3-44 Table 4.3.4.1-1 (Deleted) .............................. 3/4 3-45 End-of-Cycle Recirculation Pump Trip System Instrumentation .............................................. 3/4 3-46 LIMERICK - UNIT 2 vii Amendment No. 147

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE REACTOR COOLANT SYSTEM (Continued) 3/4.4.9 RESIDUAL HEAT REMOVAL Hot Shutdown ............................................... 3/4 4-25 Cold Shutdown .............................................. 3/4 4-26 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ECCS - OPERATING ........................................... 3/4 5-1 3/4.5.2 ECCS --- SHUTDOWNREACTOR PRESSURE VESSEL (RPV)

WATER INVENTORY CONTROL (WIC) .............................. 3/4 5-6 3/4.5.3 SUPPRESSION CHAMBER ........................................ 3/4 5-8 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity .............................. 3/4 6-1 Primary Containment Leakage ................................ 3/4 6-2 Primary Containment Air Lock ............................... 3/4 6-5 MSIV Leakage Alternate Drain Pathway ....................... 3/4 6-7 Primary Containment Structural Integrity ................... 3/4 6-8 Drywell and Suppression Chamber Internal Pressure .......... 3/4 6-9 Drywell Average Air Temperature ............................ 3/4 6-10 Drywell and Suppression Chamber Purge System ............... 3/4 6-11 3/4.6.2 DEPRESSURIZATION SYSTEMS Suppression Chamber ........................................ 3/4 6-12 Suppression Pool Spray ..................................... 3/4 6-15 Suppression Pool Cooling ................................... 3/4 6-16 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES ....................... 3/4 6-17 LIMERICK - UNIT 2 xii Amendment No. 53, 107

INDEX BASES SECTION PAGE 3/4.0 APPLICABILITY .................................................... B 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN .............................................. B 3/4 1-1 3/4.1.2 REACTIVITY ANOMALIES ......................................... B 3/4 1-1 3/4.1.3 CONTROL RODS................................................. B 3/4 1-2 3/4.1.4 CONTROL ROD PROGRAM CONTROLS ................................. B 3/4 1-3 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM ................................ B 3/4 1-4 3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE......................................................... B 3/4 2-1 3/4.2.2 (DELETED).................................................... B 3/4 2-2 LEFT INTENTIONALLY BLANK ............................................... B 3/4 2-3 3/4.2.3 MINIMUM CRITICAL POWER RATIO ................................. B 3/4 2-4 3/4.2.4 LINEAR HEAT GENERATION RATE .................................. B 3/4 2-5 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION .................... B 3/4 3-1 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION .......................... B 3/4 3-2 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION.............................................. B 3/4 3-2 3/4.3.3.A REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC) INSTRUMENTATION ............................ B 3/4 3-2a 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ............ B 3/4 3-3 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION.............................................. B 3/4 3-4 3/4.3.6 CONTROL ROD BLOCK INSTRUMENTATION ............................ B 3/4 3-4 3/4.3.7 MONITORING INSTRUMENTATION Radiation Monitoring Instrumentation ......................... B 3/4 3-5 LIMERICK - UNIT 2 xviii Amendment No. 4, 32, 48

INDEX BASES SECTION PAGE REACTOR COOLANT SYSTEM (Continued) 3/4.4.5 SPECIFIC ACTIVITY ............................................ B 3/4 4-4 3/4.4.6 PRESSURE/TEMPERATURE LIMITS .................................. B 3/4 4-4 Bases Table B 3/4.4.6-1 Reactor Vessel Toughness ..................... B 3/4 4-7 Bases Figure B 3/4.4.6-1 Fast Neutron Fluence (E>1 MeV) At 1/4 T As A Function of Service Life .......................... B 3/4 4-8 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES ............................. B 3/4 4-6 3/4.4.8 (DELETED) .................................................... B 3/4 4-6 3/4.4.9 RESIDUAL HEAT REMOVAL ........................................ B 3/4 4-6 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUTDOWN.................... B 3/4 5-1 3/4.5.2 REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)................................................ B 3/4 5-3a 3/4.5.3 SUPPRESSION CHAMBER .......................................... B 3/4 5-4 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity ............................. B 3/4 6-1 Primary Containment Leakage ............................... B 3/4 6-1 Primary Containment Air Lock .............................. B 3/4 6-1 MSIV Leakage Control System ............................... B 3/4 6-1 Primary Containment Structural Integrity .................. B 3/4 6-2 Drywell and Suppression Chamber Internal Pressure ................................................ B 3/4 6-2 Drywell Average Air Temperature ........................... B 3/4 6-2 Drywell and Suppression Chamber Purge System .............. B 3/4 6-2 3/4.6.2 DEPRESSURIZATION SYSTEMS ..................................... B 3/4 6-3 LIMERICK - UNIT 2 xx Amendment No. 160 Associated with Amendment 178

DEFINITIONS _

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

CORE OPERATING LIMITS REPORT 1.7a The CORE OPERATING LIMITS REPORT (COLR) is the unit-specific document that provides the core operating limits for the current operating reload cycle. These cycle-specific core operating limits shall be determined for each reload cycle in accordance with Specifications 6.9.1.9 thru 6.9.12. Plant operation within these limits is addressed in individual specifications.

CRITICAL POWER RATIO 1.8 The CRITICAL POWER RATIO (CPR) shall be the ratio of that power in the assembly which is calculated by application of the (GEXL) correlation to cause some point in the assembly to experience boiling transition, divided by the actual assembly operating power.

DOSE EQUIVALENT I-131 1.9 DOSE EQUIVALENT I-131 shall be that concentration of I-131, microcuries per gram, which alone would produce the same inhalation committed effective dose equivalent (CEDE) as the quantity and isotopic mixture of I-131, I-132, I-133, I-134, and I-135 actually present. The inhalation committed effective dose equivalent (CEDE) conversion factors used for this calculation shall be those listed in Table 2.1 of Federal Guidelines Report 11, Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion, ORNL, 1989, as described in Regulatory Guide 1.183. The factors in the column headed effective yield doses corresponding to the CEDE.

DOWNSCALE TRIP SETPOINT (DTSP) 1.9a The downscale trip setpoint associated with the Rod Block Monitor (RBM) rod block trip setting.

DRAIN TIME 1.9b The DRAIN TIME is the time it would take for the water inventory in and above the Reactor Pressure Vessel (RPV) to drain to the top of the active fuel (TAF) seated in the RPV assuming:

a) The water inventory above the TAF is divided by the limiting drain rate; b) The limiting drain rate is the larger of the drain rate through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths LIMERICK - UNIT 2 1-2 Amendment No. 4, 48, 49, 136, 146

DEFINITIONS DRAIN TIME (Continued) susceptible to a common mode failure (e.g., seismic event, loss of normal power, single human error), for all penetration flow paths below the TAF except:

1. Penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are locked, sealed, or otherwise secured in the closed position, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths;

2. Penetration flow paths capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation; or

3. Penetration flow paths with isolation devices that can be closed prior to the RPV water level being equal to the TAF by a dedicated operator trained in the task, who is in continuous communication with the control room, is stationed at the controls, and is capable of closing the penetration flow path isolation device without offsite power.

c) The penetration flow paths required to be evaluated per paragraph b) are assumed to open instantaneously and are not subsequently isolated, and no water is assumed to be subsequently added to the RPV water inventory; d) No additional draining events occur; and e) Realistic cross-sectional areas and drain rates are used.

A bounding DRAIN TIME may be used in lieu of a calculated value.

1.10 (Deleted)

EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME 1.11 The EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ECCS actuation set-point at the channel sensor until the ECCS equipment is capable of performing its safety function, i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.

Times shall include diesel generator starting and sequence loading delays where applicable. The response time may be measured by any series of sequential, overlapping or total steps such that the entire response time is measured.

LIMERICK - UNIT 2 1-2a Amendment No. 4, 48, 49, 136, 146

TABLE 3.3.2-1 (Continued)

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

7. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level Low, Low - Level 2 B 2 1, 2, 3 25

b. Drywell Pressure - High H 2 1, 2, 3 25 c.1. Refueling Area Unit 1 Ventilation Exhaust Duct Radiation - High R 2 *# 25

2. Refueling Area Unit 2 Ventilation Exhaust Duct Radiation - High R 2 *# 25

d. Reactor Enclosure Ventilation Exhaust Information Only Duct Radiation - High S 2 1, 2, 3 25

e. Deleted

f. Deleted

g. Reactor Enclosure Manual Initiation NA 1 1, 2, 3 24

h. Refueling Area Manual Initiation NA 1

• 25 LIMERICK - UNIT 2 3/4 3-15 Amendment No. 74

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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 21 - Be in at least STARTUP with the associated isolation valves closed within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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

ACTION 23 - In OPERATIONAL CONDITION 1 or 2, verify the affected system isolation valves are closed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and declare the affected system inoperable. In OPERATIONAL CONDITION 3, be in at least COLD SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

ACTION 24 - Restore the manual initiation function to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or close the affected system isolation valves 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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

ACTION 26 - Close the affected system isolation valves within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

TABLE NOTATIONS

• Required when (1) handling RECENTLY IRRADIATED FUEL in the secondary containment, or (2) during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

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

1. 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 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

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 (1) handling RECENTLY IRRADIATED FUEL in the secondary containment, or (2) during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

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

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

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

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

TABLE 3.3.3-1 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION MINIMUM OPERABLE CHANNELS PER APPLICABLE TRIP OPERATIONAL TRIP FUNCTION FUNCTION(a) CONDITIONS ACTION

1. CORE SPRAY SYSTEM***

a. Reactor Vessel Water Level - Low Low Low, Level 1 2/pump(b) 1, 2, 3, 4*, 5* 30

b. Drywell Pressure - High 2/pump(b) 1, 2, 3, 30

c. Reactor Vessel Pressure - Low (Permissive) 6(b) 1, 2, 3 31 4*, 5* 32

d. Manual Initiation 2(e) 1, 2, 3, 4*, 5* 33

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM***

a. Reactor Vessel Water Level - Low Low Low, Level 1 2 1, 2, 3, 4*, 5* 30

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

c. Reactor Vessel Pressure - Low (Permissive) 2 1, 2, 3 31

d. Injection Valve Differential Pressure-Low 1/valve 1, 2, 3, 4*, 5* 31 (Permissive)

e. Manual Initiation 1 1, 2, 3, 4*, 5* 33

3. HIGH PRESSURE COOLANT INJECTION SYSTEM##

a. Reactor Vessel Water Level - Low Low, Level 2 4 1, 2, 3 34

b. Drywell Pressure - High### 4 1, 2, 3 34

c. Condensate Storage Tank Level - Low 2(c) 1, 2, 3 35

d. Suppression Pool Water Level - High 2 1, 2, 3 35

e. Reactor Vessel Water Level - High, Level 8 4(d) 1, 2, 3 31

f. Manual Initiation### 1/system 1, 2, 3 33 LIMERICK - UNIT 2 3/4 3-33 Amendment No. 185

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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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.

• When the system is required to be OPERABLE per Specification 3.5.2.DELETED

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

1. 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. 17, 185

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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 32 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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.

LIMERICK - UNIT 2 3/4 3-36 Amendment No. 17, 120

TABLE 4.3.3.1-1 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

1. CORE SPRAY SYSTEM

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1, 2, 3, 4*, 5*

b. Drywell Pressure - High 1, 2, 3

c. Reactor Vessel Pressure - Low 1, 2, 3, 4*, 5*

d. Manual Initiation N.A. N.A. 1, 2, 3, 4*, 5*

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1, 2, 3, 4*, 5*

b. Drywell Pressure - High 1, 2, 3

c. Reactor Vessel Pressure - Low 1, 2, 3

d. Injection Valve Differential Pressure - Low (Permissive) 1, 2, 3, 4*, 5*

e. Manual Initiation N.A. N.A. 1, 2, 3, 4*, 5*

3. HIGH PRESSURE COOLANT INJECTION SYSTEM***

a. Reactor Vessel Water Level -

Low Low, Level 2 1, 2, 3

b. Drywell Pressure - High 1, 2, 3

c. Condensate Storage Tank Level -

Low 1, 2, 3

d. Suppression Pool Water Level -

High 1, 2, 3

e. Reactor Vessel Water Level -

High, Level 8 1, 2, 3

f. Manual Initiation N.A. N.A. 1, 2, 3 LIMERICK - UNIT 2 3/4 3-40 Amendment No. 17, 34, 147

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. Drywell 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.

• When the system is required to be OPERABLE per Specification 3.5.2.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.

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

1. 1. Loss of Voltage Relay 127-11X is not field setable.

LIMERICK - UNIT 2 3/4 3-41 Amendment No. 17, 147

INSTRUMENTATION 3/4.3.3.A REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)

INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.A The RPV Water Inventory Control (WIC) instrumentation channels shown in Table 3.3.3.A-1 shall be OPERABLE.

APPLICABILITY: As shown in Table 3.3.3.A-1 ACTION:

a. With one or more channels inoperable in a trip system, take the ACTION referenced in Table 3.3.3.A-1 for the trip system.

SURVEILLANCE REQUIREMENTS 4.3.3.1.A Each RPV Water Inventory Control (WIC) instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and LOGIC SYSTEM FUNCTIONAL TEST as shown in Table 4.3.3.A-1 and at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.3.3.A-1.

LIMERICK - UNIT 2 3/4 3-41a Amendment No.

TABLE 3.3.3.A-1 RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION MINIMUM OPERABLE CHANNELS PER APPLICABLE TRIP OPERATIONAL TRIP FUNCTION FUNCTION CONDITIONS ACTION

1. CORE SPRAY SYSTEM

a. Reactor Vessel Pressure - Low (Permissive) 6(a) 4, 5 39

b. Manual Initiation 2(a) 4, 5 40

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Injection Valve Differential Pressure - Low (Permissive) 1/valve(a) 4, 5 39

b. Manual Initiation 1(a) 4, 5 40

3. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level Low - Level 3 2 in one (b) 38 trip system

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. Reactor Vessel Water Level -

Low, Low - Level 2 2 in one (b) 38 trip system (a) Associated with an ECCS subsystem required to be OPERABLE by LCO 3.5.2, "REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)."

(b) When automatic isolation of the associated penetration flow path(s) is credited in calculating DRAIN TIME.

LIMERICK - UNIT 2 3/4 3-41b Amendment No.

TABLE 3.3.3.A-1 (Continued)

RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION ACTION STATEMENTS ACTION 38 - Declare the associated trip system for the penetration flow path(s) incapable of automatic isolation and calculate DRAIN TIME.

ACTION 39 - Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, place channel in trip. Otherwise, declare associated low pressure ECCS injection/spray subsystem inoperable.

ACTION 40 - Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, restore channel to OPERABLE status. Otherwise, declare associated low pressure ECCS injection/spray subsystem inoperable.

LIMERICK - UNIT 2 3/4 3-41c Amendment No.

TABLE 3.3.3.A-2 RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION SETPOINTS ALLOWABLE TRIP FUNCTION VALUE

1. CORE SPRAY SYSTEM a Reactor Vessel Pressure - Low (Permissive) > 435 psig (decreasing)

b. Manual Initiation N.A.

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Injection Valve Differential Pressure - Low (Permissive) < 84 psid

b. Manual Initiation N.A.

3. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level -

Low - Level 3 11.0 inches

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. Reactor Vessel Water Level -

Low, Low - Level 2 -45 inches LIMERICK - UNIT 2 3/4 3-41d Amendment No.

TABLE 4.3.3.A-1 RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL LOGIC SYSTEM OPERATIONAL CHANNEL FUNCTIONAL FUNCTIONAL CONDITIONS FOR WHICH TRIP FUNCTION CHECK(a) TEST(a) TEST(a) SURVEILLANCE REQUIRED

1. CORE SPRAY SYSTEM

a. Reactor Vessel Pressure - Low (Permissive) N.A. 4, 5

b. Manual Initiation N.A. N.A. 4, 5

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Injection Valve Differential Pressure Low (Permissive) N.A. 4, 5

b. Manual Initiation N.A. N.A. 4, 5

3. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level Low - Level 3 N.A. (b)

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. Reactor Vessel Water Level -

Low, Low - Level 2 N.A. (b)

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

(b) When automatic isolation of the associated penetration flow path(s) is credited in calculating DRAIN TIME.

LIMERICK - UNIT 2 3/4 3-41e Amendment No.

TABLE 3.3.7.1-1 RADIATION MONITORING INSTRUMENTATION MINIMUM CHANNELS APPLICABLE ALARM/TRIP INSTRUMENTATION OPERABLE CONDITIONS SETPOINT ACTION

1. Main Control Room Normal 4 1,2,3, 1 x 10-5 Ci/cc 70 Fresh Air Supply Radiation and

• Monitor

2. Area Monitors

a. Criticality Monitors

1) Spent Fuel 2 (a) 5 mR/h and 20mR/h(b) 71 Storage Pool

b. Control Room Direct 1 At All Times N.A.(b) 73 Radiation Monitor 3.

Information Only Reactor Enclosure Cooling Water Radiation Monitor 1 At All Times 3 x Background(b) 72 LIMERICK - UNIT 2 3/4 3-64 Amendment No. 146

TABLE 3.3.7.1-1 (Continued)

RADIATION MONITORING INSTRUMENTATION TABLE NOTATIONS

• When RECENTLY IRRADIATED FUEL is being handled in the secondary containment or during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

(a) With fuel in the spent fuel storage pool.

(b) Alarm only.

ACTION STATEMENTS ACTION 70 - With one monitor inoperable, restore the inoperable monitor to the OPERABLE status within 7 days or, within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, initiate and maintain operation of the control room emergency filtration system in the radiation isolation mode of operation.

With two or more of the monitors inoperable, within one hour, initiate and maintain operation of the control room emergency filtration system in the radiation mode of operation.

ACTION 71 - With one of the required monitor inoperable, assure a portable continuous monitor with the same alarm setpoint is OPERABLE in the vicinity of the installed monitor during any fuel movement.

If no fuel movement is being made, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 72 - With the required monitor inoperable, obtain and analyze at least one grab sample of the monitored parameter at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 73 - With the required monitor inoperable, assure a portable alarming monitor is OPERABLE in the vicinity of the installed monitor or perform area surveys of the monitored area with portable monitor-ing instrumentation at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

LIMERICK - UNIT 2 3/4 3-65 Amendment No. 146

TABLE 4.3.7.1-1 RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS OPERATIONAL CHANNEL CONDITIONS FOR CHANNEL FUNCTIONAL CHANNEL WHICH SURVEILLANCE INSTRUMENTATION CHECK(c) TEST(c) CALIBRATION(c) IS REQUIRED

1. Main Control Room Normal Fresh Air Supply Radiation Monitor 1, 2, 3, and *

2. Area Monitors

a. Criticality Monitors

1) Spent Fuel Storage (a)

Pool

b. Control Room Direct At All Times Information Only Radiation Monitor

3. Reactor Enclosure Cooling Water Radiation Monitor (b) At All Times LIMERICK UNIT 2 3/4 3-66 Amendment No. 33, 146, 147

TABLE 4.3.7.1-1 (Continued)

RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS TABLE NOTATIONS

• When RECENTLY IRRADIATED FUEL is being handled in the secondary containment or during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

(a) With fuel in the spent fuel storage pool.

(b) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards (NBS) or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used.

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

LIMERICK - UNIT 2 3/4 3-67 Amendment No. 146, 147

EMERGENCY CORE COOLING SYSTEMS 3/4 5.2 ECCS --- SHUTDOWNREACTOR 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 <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> AND At least two one of the following shall be OPERABLE:

a. Core spray system (CSS) subsystems with a 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 subsystems with a 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 one none of the above required subsystems inoperableOPERABLE, restore at least twoone subsystems to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Otherwise, initiate action to establish a method of water injection capable of operating without offsite electrical powerall operations with a potential for draining the reactor vessel.

b. With both of the above required subsystems inoperable, suspend CORE ALTERATIONS and all operations with a potential for draining the reactor vessel. Restore at least one subsystem to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or establish SECONDARY CONTAINMENT INTEGRITY within the next 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />sDELETED.

• The ECCS is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded, the spent fuel pool gates are removed, and water level is maintained within the limits of Specifications 3.9.8 and 3.9.9.

• • 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 2 3/4 5-6 Amendment No. 59

EMERGENCY CORE COOLING SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION:

c. With DRAIN TIME less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> and greater than or equal to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, within 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />s:

1. Verify SECONDARY CONTAINMENT INTEGRITY is capable of being established in less than the DRAIN TIME,

2. Verify each secondary containment penetration flow path is capable of being isolated in less than the DRAIN TIME, and

3. Verify one standby gas treatment subsystem is capable of being placed in operation in less than the DRAIN TIME.

d. With DRAIN TIME less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, immediately:

1. Initiate action to establish an additional method of water injection with water sources capable of maintaining RPV water level greater than TAF for greater than or equal to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />,***

2. Initiate action to establish SECONDARY CONTAINMENT INTEGRITY,

3. Initiate action to isolate each secondary containment penetration flow path or verify it can be manually isolated from the control room, and

4. Initiate action to verify one standby gas treatment subsystem is capable of being placed in operation.

e. With required ACTION and associated allowed outage time for ACTIONS c. or d. not met, or DRAIN TIME less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, initiate action to restore DRAIN TIME to greater than or equal to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

• • • The required injection/spray subsystem or an additional method of water injection shall be capable of operating without offsite electrical power.

LIMERICK - UNIT 2 3/4 5-6a Amendment No.

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.2.1 Verify DRAIN TIME is greater than or equal to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> in accordance with the Surveillance Frequency Control ProgramAt least the above required ECCS shall be demonstrated OPERABLE per Surveillance Requirement 4.5.1.*

4.5.2.2 Verify, for a required LPCI subsystem, the suppression pool water level is greater than or equal to 16 feet 0 inches in accordance with the Surveillance Frequency Control Program.he core spray system shall be determined OPERABLE in accordance with the Surveillance Frequency Control Program by verifying the condensate storage tank required volume when the condensate storage tank is required to be OPERABLE per Specification 3.5.2a.2.b).

4.5.2.3 Verify, for a required CSS subsystem, that the suppression pool water level is greater than or equal to 16 feet 0 inches or the condensate storage tank water level is greater than or equal to 29 feet 0 inches in accordance with the Surveillance Frequency Control Program.

4.5.2.4 Verify, for the required ECCS injection/spray subsystem, locations susceptible to gas accumulation are sufficiently filled with water.

4.5.2.5 Verify, for the required ECCS injection/spray subsystem, each manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position in accordance with the Surveillance Frequency Control Program.#^

4.5.2.6 Operate the required ECCS injection/spray subsystem through the recirculation line for greater than or equal to 10 minutes in accordance with the Surveillance Frequency Control Program.

4.5.2.7 Verify each valve credited for automatically isolating a penetration flow path actuates to the isolation position on an actual or simulated isolation signal in accordance with the Surveillance Frequency Control Program.

4.5.2.8 Verify the required ECCS injection/spray subsystem actuates on a manual initiation signal in accordance with the Surveillance Frequency Control Program.##

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

1. Not required to be met for system vent flow paths open under administrative control.

^Except that an automatic valve capable of automatic return to its ECCS position when an ECCS signal is present may be in position for another mode of operation.

1. 1. Vessel injection/spray may be excluded.

LIMERICK - UNIT 2 3/4 5-7 Amendment No. 59, 147

EMERGENCY CORE COOLING SYSTEMS 3/4.5.3 SUPPRESSION CHAMBER LIMITING CONDITION FOR OPERATION 3.5.3 The suppression chamber shall be OPERABLE:

a. In OPERATIONAL CONDITIONS 1, 2, and 3 with a contained water volume of at least 122,120 ft3, equivalent to a level of 22'0".

b. DELETEDIn OPERATIONAL CONDITION 4 and 5* with a contained water volume of at least 88,815 ft3, equivalent to a level of 16'0", except that the suppression chamber level may be less than the limit or may be drained provided that:

1. No operations are performed that have a potential for draining the reactor vessel,

2. The reactor mode switch is locked in the Shutdown or Refuel position,

3. The condensate storage tank contains at least 135,000 available gallons of water, equivalent to a level of 29 feet, and

4. The core spray system is OPERABLE per Specification 3.5.2 with an OPERABLE flow path capable of taking suction from the condensate storage tank and transferring the water through the spray sparger to the reactor vessel.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3, 4, and 5*.

ACTION:

a. In OPERATIONAL CONDITION 1, 2 or 3 with the suppression chamber water level less than the above limit, restore the water level to within the limit within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. In OPERATIONAL CONDITION 4 or 5* with the suppression chamber water level less than the above limit or drained and the above required conditions not satisfied, suspend CORE ALTERATIONS and all operations that have a potential for draining the reactor vessel and lock the reactor mode switch in the Shutdown position. Establish SECONDARY CONTAINMENT INTEGRITY within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. DELETED

• The suppression chamber is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded or being flooded from the suppression pool, the spent fuel pool gates are removed when the cavity is flooded, and the water level is maintained within the limits of Specifications 3.9.8 and 3.9.9.

LIMERICK - UNIT 2 3/4 5-8 Amendment No.

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.3.1 The suppression chamber shall be determined OPERABLE by verifying the water level to be greater than or equal to, as applicable:

a. 22'0" in accordance with the Surveillance Frequency Control Program.

b. DELETED16'0" in accordance with the Surveillance Frequency Control Program.

4.5.3.2 DELETEDWith the suppression chamber level less than the above limit or drained in OPERATIONAL CONDITION 4 or 5*, in accordance with the Surveillance Frequency Control Program:

a. Verify the required conditions of Specification 3.5.3b. to be satisfied, or

b. Verify footnote conditions

• to be satisfied.

• The suppression chamber is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded or being flooded from the suppression pool, the spent fuel pool gates are removed when the cavity is flooded, and the water level is maintained within the limits of Specifications 3.9.8 and 3.9.9.

LIMERICK - UNIT 2 3/4 5-9 Amendment No. 147

CONTAINMENT SYSTEMS 3/4.6.5 SECONDARY CONTAINMENT REFUELING AREA SECONDARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.5.1.2 REFUELING AREA SECONDARY CONTAINMENT INTEGRITY shall be maintained.

APPLICABILITY: When RECENTLY IRRADIATED FUEL is being handled in the secondary containment, or during operations with a potential for draining the reactor vessel, with the vessel head removed and fuel in the vessel.

ACTION:

Without REFUELING AREA SECONDARY CONTAINMENT INTEGRITY, suspend handling of RECENTLY IRRADIATED FUEL in the secondary containment, and operations with a potential for draining the reactor vessel. The provisions of Specifica-tion 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.1.2 REFUELING AREA SECONDARY CONTAINMENT INTEGRITY shall be demonstrated by:

a. Verifying in accordance with the Surveillance Frequency Control Program that the pressure within the refueling area secondary containment is greater than or equal to 0.25 inch of vacuum water gauge.

b. Verifying in accordance with the Surveillance Frequency Control Program that:

1. All refueling area secondary containment equipment hatches and blowout panels are closed and sealed.

2. At least one door in each access to the refueling area secondary containment is closed, except when the access opening is being used for entry and exit.

3. All refueling area secondary containment penetrations not capable of being closed by OPERABLE secondary containment automatic iso-lation dampers/valves and required to be closed during accident conditions are closed by valves, blind flanges, slide gate dampers or deactivated automatic dampers/valves secured in position.

c. In accordance with the Surveillance Frequency Control Program:

Operating one standby gas treatment subsystem for one hour and main-taining greater than or equal to 0.25 inch of vacuum water gauge in the refueling area secondary containment at a flow rate not exceeding 764 cfm.

LIMERICK - UNIT 2 3/4 6-47 Amendment No. 34,146,147, 182

CONTAINMENT SYSTEMS REFUELING AREA SECONDARY CONTAINMENT AUTOMATIC ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.5.2.2 The refueling area secondary containment ventilation system automatic isolation valves shall be OPERABLE.

APPLICABILITY: When RECENTLY IRRADIATED FUEL is being handled in the secondary containment, or during operations with a potential for draining the reactor vessel, with the vessel head removed and fuel in the vessel.

ACTION:

With one or more of the refueling area secondary containment ventilation system automatic isolation valves inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> either:

a. Restore the inoperable valves to OPERABLE status, or

b. Isolate each affected penetration by use of at least one deactivated valve secured in the isolation position, or

c. Isolate each affected penetration by use of at least one closed manual valve, blind flange or slide gate damper.

Otherwise, suspend handling of RECENTLY IRRADIATED FUEL in the refueling area secondary containment, and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.2.2 Each refueling area secondary containment ventilation system auto-matic isolation valve shall be demonstrated OPERABLE:

a. Prior to returning the valve to service after maintenance, repair or replacement work is performed on the valve or its associated actuator, control or power circuit by cycling the valve through at least one complete cycle of full travel and verifying the specified isolation time.

b. In accordance with the Surveillance Frequency Control Program by verifying that on a containment isolation test signal each isolation valve actuates to its isolation position.

c. By verifying the isolation time to be within its limit in accordance with the Surveillance Frequency Control Program.

LIMERICK - UNIT 2 3/4 6-50 Amendment No. 34, 69, 146, 147

CONTAINMENT SYSTEMS STANDBY GAS TREATMENT SYSTEM - COMMON SYSTEM LIMITING CONDITION FOR OPERATION 3.6.5.3 Two independent standby gas treatment subsystems shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, and when (1) irradiated fuel is being handled in the refueling area secondary containment, or (2) during CORE ALTERATIONS, or (3) during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.

ACTION:

a. In OPERATIONAL CONDITION 1, 2, or 3:

1. With the Unit 1 diesel generator for one standby gas treatment subsystem inoperable for more than 30 days, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. With one standby gas treatment subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3. With one standby gas treatment subsystem inoperable and the other standby gas treatment subsystem with an inoperable Unit 1 diesel generator, restore the inoperable subsystem to OPERABLE status or restore the inoperable Unit 1 diesel generator to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. With the Unit 1 diesel generators for both standby gas treatment system subsystems inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. When (1) irradiated fuel is being handled in the refueling area secondary containment, or (2) during CORE ALTERATIONS, or (3) during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel.:

1. With one standby gas treatment subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days, or suspend handling of irradiated fuel in the secondary containment, CORE ALTERATIONS, and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

2. With both standby gas treatment subsystems inoperable, if in progress, suspend handling of irradiated fuel in the secondary containment and, CORE ALTERATIONS, and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

LIMERICK - UNIT 2 3/4 6-52 Amendment No. 132, 146

PLANT SYSTEMS 3/4.7.2 CONTROL ROOM EMERGENCY FRESH AIR SUPPLY SYSTEM - COMMON SYSTEM LIMITING CONDITION FOR OPERATION 3.7.2 Two independent control room emergency fresh air supply system subsystems shall be OPERABLE.

NOTE: The main control room envelope (CRE) boundary may be opened intermittently under administrative control.

APPLICABILITY: All OPERATIONAL CONDITIONS and when RECENTLY IRRADIATED FUEL is being handled in the secondary containment, or during operations with a potential for draining the reactor vessel.

ACTION:

a. In OPERATIONAL CONDITION 1, 2, or 3:

1. With the Unit 1 diesel generator for one control room emergency fresh air supply subsystem inoperable for more than 30 days, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. With one control room emergency fresh air supply subsystem inoperable for reasons other than Condition a.5, restore the inoperable subsystem to OPERABLE status within 7 days, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3. With one control room emergency fresh air supply subsystem inoperable for reasons other than Condition a.5, and the other control room emergency fresh air supply subsystem with an inoperable Unit 1 diesel generator, restore the inoperable subsystem to OPERABLE status or restore the Unit 1 diesel generator to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. With the Unit 1 diesel generators for both control room emergency fresh air supply subsystems inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

5. With one or more control room emergency fresh air supply subsystems inoperable due to an inoperable CRE boundary,

a. Initiate action to implement mitigating actions immediately or be in HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and

b. Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, verify mitigating actions ensure CRE occupant exposures to radiological and chemical hazards will not exceed limits and actions to mitigate exposure to smoke hazards are taken or be in HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and LIMERICK - UNIT 2 3/4 7-6 Amendment No. 132, 146, 149

PLANT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

c. Restore CRE boundary to operable status within 90 days or be in HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. In OPERATIONAL CONDITION 4, 5 or when RECENTLY IRRADIATED FUEL is being handled in the secondary containment, or during operations with a potential for draining the reactor vessel:

1. With one control room emergency fresh air supply subsystem inoperable for reasons other than Condition b.3, restore the inoperable subsystem to OPERABLE status within 7 days, or initiate and maintain operation of the OPERABLE subsystem in the radiation isolation mode of operation.

2. With both control room emergency fresh air supply subsystem inoperable for reasons other than Condition b.3, immediately suspend handling of RECENTLY IRRADIATED FUEL in the secondary containment and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

3. With one or more control room emergency fresh air subsystems inoperable due to an inoperable CRE boundary, immediately suspend handling of RECENTLY IRRADIATED FUEL in the secondary containment and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.7.2.1 Each control room emergency fresh air supply subsystem shall be demonstrated OPERABLE:

a. In accordance with the Surveillance Frequency Control Program by verifying the control room air temperature to be less than or equal to 85°F effective temperature.

b. In accordance with the Surveillance Frequency Control Program on a STAGGERED TEST BASIS by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates with the heaters OPERABLE.

c. In accordance with the Surveillance Frequency Control Program or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire, or chemical release in any ventilation zone communicating with the subsystem by:

1. Verifying that the subsystem satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.5.a, C.5.c, and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 3000 cfm +/- 10%.

LIMERICK - UNIT 2 3/4 7-6a Amendment No. 34, 147, 149, 153

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 1E 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, operations with a potential for draining the reactor vessel 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.

• When handling irradiated fuel in the secondary containment.

LIMERICK - UNIT 2 3/4 8-9 Amendment No. 153, 154

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION ACTION: (Continued)

2. Division 1 or 2 with float current > 2 amps, or with Division 3 or 4 with float current > 1 amp, perform 4.8.2.1.a.2 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for affected battery(s) and restore battery float current to within limits within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.

3. One or two batteries on one division with one or more cells electrolyte level less than minimum established design limits, if electrolyte level was below the top of the plates restore electrolyte level to above top of plates within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and verify no evidence of leakage(*) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In all cases, restore electrolyte level to greater than or equal to minimum established design limits within 31 days.

4. One or two batteries on one division with pilot cell electrolyte temperature less than minimum established design limits, restore battery pilot cell temperature to greater than or equal to minimum established design limits within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

5. Batteries in more than one division affected, restore battery parameters for all batteries in one division to within limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

6. (i) Any battery having both (Action b.1) one or more battery cells float voltage < 2.07 volts and (Action b.2) float current not within limits, and/or (ii) Any battery not meeting any Action b.1 through b.5, Restore the battery parameters to within limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

c. 1. With the requirements of Action a. and/or Action b. not met, or

2. With less than two divisions of the above required D.C. electrical power sources OPERABLE for reasons other than Actions a. and/or b.,

Suspend CORE ALTERATIONS and, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

d. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.2.2 At least the above required batteries and chargers shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.1.

(*) Contrary to the provisions of Specification 3.0.2, if electrolyte level was below the top of the plates, the verification that there is no evidence of leakage is required to be completed regardless of when electrolyte level is restored.

LIMERICK - UNIT 2 3/4 8-14a Amendment No. 126

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) c) 125-V DC Distribution Panels: 2PPA1 (2AD102) 2PPA2 (2AD501) 2PPA3 (2AD162)

2. Unit 2 Division 2, Consisting of:

a) 250-V DC Fuse Box: 2FB (2BD105) b) 250-V DC Motor Control Centers: 2DB-1 (20D202) 2DB-2 (20D203) c) 125-V DC Distribution Panels: 2PPB1 (2BD102) 2PPB2 (2BD501) 2PPB3 (2BD162)

3. Unit 2 Division 3, Consisting of:

a) 125-V DC Fuse Box: 2FC (2CD105) b) 125-V DC Distribution Panels: 2PPC1 (2CD102) 2PPC2 (2CD501) 2PPC3 (2CD162)

4. Unit 2 Division 4, Consisting of:

a) 125-V DC Fuse Box: 2FD (2DD105) b) 125-V DC Distribution Panels: 2PPD1 (2DD102) 2PPD2 (2DD501) 2PPD3 (2DD162)

5. Unit 1 and Common Division 1, Consisting of:

a) 250-V DC Fuse Box: 1FA (1AD105) b) 125-V DC Distribution Panels: 1PPA1 (1AD102) 1PPA2 (1AD501)

6. Unit 1 and Common Division 2, Consisting of:

a) 250-V DC Fuse Box: 1FB (1BD105) b) 125-V DC Distribution Panels: 1PPB1 (1BD102) 1PPB2 (1BD501)

7. Unit 1 and Common Division 3, Consisting of:

a) 125-V DC Fuse Box: 1FC (1CD105) b) 125-V DC Distribution Panels: 1PPC1 (1CD102) 1PPC2 (1CD501)

8. Unit 1 and Common Division 4, Consisting of:

a) 125-V DC Fuse Box: 1FD (1DD105) b) 125-V DC Distribution Panels: 1PPD1 (1DD102) 1PPD2 (1DD501)

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5, and *.

ACTION:

a. With less than two divisions of the above required Unit 2 A.C.

distribution systems energized, suspend CORE ALTERATIONS and, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

• When handling irradiated fuel in the secondary containment.

LIMERICK - UNIT 2 3/4 8-19 Amendment No. 102

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

b. With less than two divisions of the above required Unit 2 D.C.

distribution systems energized, suspend CORE ALTERATIONS, and handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

c. With any of the above required Unit 1 and common AC and/or DC distribution system divisions not energized, declare the associated common equipment inoperable, and take the appropriate ACTION for that system.

d. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.3.2 At least the above required power distribution system divisions shall be determined energized in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and voltage on the busses/MCCs/panels.

LIMERICK - UNIT 2 3/4 8-20 Amendment No. 147

ATTACHMENT 3 Proposed Technical Specifications Bases Changes (Mark-ups)

(For Information Only)

Limerick Generating Station Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 Docket Nos. 50-352 and 50-353 Application to Revise Technical Specifications to Adopt TSTF-542, "Reactor Pressure Vessel Water Inventory Control," Revision 2 Revised Proposed Technical Specifications Bases Pages Unit 1 TS Bases Page B 3/4 3-2a* B 3/4 5-3b*

B 3/4 3-2b* B 3/4 5-3c*

B 3/4 3-2c* B 3/4 5-3d*

B 3/4 3-2d* B 3/4 5-3e*

B 3/4 3-3 B 3/4 5-3f*

B 3/4 5-1 B 3/4 5-4 B 3/4 5-2 B 3/4 6-5 B 3/4 5-3 B 3/4 10-2 B 3/4 5-3a*

Unit 2 TS Bases Page B 3/4 3-2a* B 3/4 5-3b*

B 3/4 3-2b* B 3/4 5-3c*

B 3/4 3-2c* B 3/4 5-3d*

B 3/4 3-2d* B 3/4 5-3e*

B 3/4 3-3 B 3/4 5-3f*

B 3/4 5-1 B 3/4 5-4 B 3/4 5-2 B 3/4 6-5 B 3/4 5-3 B 3/4 10-2 B 3/4 5-3a*

• New TS Bases Page

INSTRUMENTATION BASES 3/4.3.3 EMERGENCY CORE COOLING ACTUATION INSTRUMENTATION (Continued)

Surveillance intervals are determined in accordance with the Surveillance Frequency Control Program and maintenance outage times have been determined in accordance with NEDC-30936P, Parts 1 and 2, "Technical Specification Improvement Methodology (with Demonstration for BWR ECCS Actuation Instrumentation)," as approved by the NRC and documented in the SER (letter to D. N. Grace from A. C.

Thadani dated December 9, 1988 (Part 1) and letter to D. N. Grace from C. E.

Rossi dated December 9, 1988 (Part 2)).

Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power for energizing various components such as pump motors, motor operated valves, and the associated control components. If the loss of power instrumentation detects that voltage levels are too low, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources. The loss of power relays in each channel have sufficient overlapping detection characteristics and functionality to permit operation subject to the conditions in Action Statement 37. Bases 3/4.8.1, 3/4.8.2, and 3/4.8.3 provide discussion regarding parametric bounds for determining operability of the offsite sources.

Those Bases assume that the loss of power relays are operable. With an inoperable 127Z-11X0X relay, the grid voltage is monitored to 230kV (for the 101 Safeguard Bus Source) or 525kV (for the 201 Safeguard Bus Source) to increase the margin for the operation of the 127Z-11X0X relay.

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses.

3/4.3.3.A REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC) INSTRUMENTATION The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF. If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation.

Safety Limit 2.1.4 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

Technical Specifications are required by 10 CFR 50.36 to include limiting safety system settings (LSSS) for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated to ensure that a SL is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur. The actual settings for the automatic isolation channels are the same as those established for the same functions in OPERATIONAL CONDITIONS 1, 2, and 3 in TABLE 3.3.2-2, "ISOLATION ACTUATION INSTRUMENTATION SETPOINTS."

With the unit in OPERATIONAL CONDITION 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses. RPV water inventory control is required in OPERATIONAL CONDITIONS 4 and 5 to protect Safety Limit 2.1.4 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur. Under the definition of DRAIN TIME, some penetration flow paths may be excluded from the DRAIN TIME calculation if they will be isolated by valves that will close LIMERICK - UNIT 1 B 3/4 3-2a Amendment No.52, 69, 70, 158, 186

INSTRUMENTATION BASES 3/4.3.3.A RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION (Continued) automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation.

The purpose of the RPV Water Inventory Control Instrumentation is to support the requirements of LCO 3.5.2, Reactor Pressure Vessel (RPV) Water Inventory Control (WIC), and the definition of DRAIN TIME. There are functions that are required for manual initiation or operation of the ECCS injection/spray subsystem required to be OPERABLE by LCO 3.5.2 and other functions that support automatic isolation of Residual Heat Removal (RHR) subsystem and Reactor Water Cleanup (RWCU) system penetration flow path(s) on low RPV water level.

The RPV Water Inventory Control Instrumentation supports operation of the Core Spray System (CSS) and the Low Pressure Coolant Injection (LPCI) system. The equipment involved with each of these systems is described in the Bases for LCO 3.5.2.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not postulated in OPERATIONAL CONDITIONS 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is postulated in which a single operator error or initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure, e.g., seismic event, loss of normal power, or single human error. It is assumed, based on engineering judgment, that while in OPERATIONAL CONDITIONS 4 and 5, one low pressure ECCS injection/spray subsystem can be manually initiated to maintain adequate reactor vessel water level.

As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.

Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

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

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

Core Spray System - Reactor Vessel Pressure - Low (Permissive) and Low Pressure Coolant Injection Mode of RHR System - Injection Valve Differential Pressure - Low (Permissive)

The low reactor vessel pressure signal for Core Spray and the injection valve low differential pressure signal for LPCI are used as permissives for the low pressure ECCS injection/spray subsystem manual injection functions. These functions ensure that, prior to opening the injection valves of the low pressure ECCS subsystems, the reactor pressure has fallen to a value below these subsystems' maximum design pressure. While it is assured during OPERATIONAL CONDITIONS 4 and 5 that the reactor vessel pressure will be below the ECCS maximum design pressure, the Reactor Vessel Pressure - Low signal and the Injection Valve Differential Pressure - Low signal are assumed to be OPERABLE and capable of permitting initiation of the ECCS.

The Reactor Vessel Pressure - Low signals are initiated from four pressure transmitters that sense the reactor vessel pressure. The transmitters are connected to four trip units. The outputs of the trip units are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.

LIMERICK - UNIT 1 B 3/4 3-2b Amendment No.

INSTRUMENTATION BASES 3/4.3.3.A RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION (Continued)

The Injection Valve Differential Pressure - Low signals are initiated from four differential pressure transmitters (one per valve) that monitor the differential pressure across each LPCI injection valve.

The Allowable Values are low enough to prevent overpressuring the equipment in the low pressure ECCS. The instrument channels of the Reactor Vessel Pressure

- Low and Injection Valve Differential Pressure - Low Functions are required to be OPERABLE in OPERATIONAL CONDITIONS 4 and 5 when ECCS manual initiation is required to be OPERABLE by LCO 3.5.2.

Manual Initiation The Manual Initiation push button channels introduce signals into the appropriate ECCS logic to provide manual initiation capability. There is one push button for each of the CSS and LPCI subsystems (i.e., four for CSS and four for LPCI).

There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons. A channel of the Manual Initiation Function (one channel per subsystem) is required to be OPERABLE in OPERATIONAL CONDITIONS 4 and 5 when the associated ECCS subsystems are required to be OPERABLE per LCO 3.5.2.

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

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

The Reactor Vessel Water Level Low - Level 3 Allowable Value was chosen to be the same as the Primary Containment Isolation Instrumentation Reactor Vessel Water Level Low - Level 3 Allowable Value (TABLE 3.3.2-2), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level Low - Level 3 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME. This Function isolates the Group 2 valves.

Reactor Water Cleanup (RWCU) System Isolation - Reactor Vessel Water Level -

Low, Low - Level 2 The definition of DRAIN TIME allows crediting the closing of penetration flow paths that are capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation. The Reactor LIMERICK - UNIT 1 B 3/4 3-2c Amendment No.

INSTRUMENTATION BASES 3/4.3.3.A RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION (Continued)

Vessel Water Level - Low, Low - Level 2 Function associated with RWCU System isolation may be credited for automatic isolation of penetration flow paths associated with the RWCU System. Reactor Vessel Water Level - Low, Low - Level 2 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Low - Level 2 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low, Low - Level 2 Allowable Value was chosen to be the same as the Primary Containment Isolation Instrumentation Reactor Vessel Water Level - Low, Low Level 2 Allowable Value (TABLE 3.3.2-2), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low, Low Level 2 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME. This Function isolates the Group 3 valves.

Actions A note has been provided to modify the ACTIONs related to RPV Water Inventory Control instrumentation channels. The ACTIONs for inoperable RPV Water Inventory Control instrumentation channels provide appropriate compensatory measures for each inoperable RPV Water Inventory Control instrumentation channel.

ACTION a. directs taking the appropriate ACTION referenced in Table 3.3.3.A-

1. The applicable ACTION referenced in the Table is Function dependent.

RHR System Shutdown Cooling Mode Isolation, Reactor Vessel Water Level Low

- Level 3, and Reactor Water Cleanup System Isolation, Reactor Vessel Water Level

- Low, Low - Level 2 functions are applicable when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME. If the instrumentation is inoperable, ACTION 38 directs an immediate declaration that the associated penetration flow path(s) are incapable of automatic isolation and calculation of DRAIN TIME. The calculation cannot credit automatic isolation of the affected penetration flow paths.

Low reactor vessel pressure signals are used as permissives for the low pressure ECCS injection/spray subsystem manual injection functions. If the permissive is inoperable, manual initiation of ECCS is prohibited. Therefore, the permissive must be placed in the trip condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. With the permissive in the trip condition, manual initiation may be performed. Prior to placing the permissive in the tripped condition, the operator can take manual control of the pump and the injection valve to inject water into the RPV.

The allowed outage time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is intended to allow the operator time to evaluate any discovered inoperabilities and to place the channel in trip.

The 24-hour allowed outage time was chosen to allow time for the operator to evaluate and repair any discovered inoperabilities. The allowed outage time is appropriate given the ability to manually start the ECCS pumps and open the injection valves and to manually ensure the pump does not overheat.

With the ACTION and associated allowed outage time of ACTION 39 or 40 not met, the associated low pressure ECCS injection/spray subsystem may be incapable of performing the intended function, and must be declared inoperable immediately.

LIMERICK - UNIT 1 B 3/4 3-2d Amendment No.

INSTRUMENTATION BASES 3/4.3.3.A RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION (Continued)

REFERENCES

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

2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

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

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

5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION The anticipated transient without scram (ATWS) recirculation pump trip system provides a means of limiting the consequences of the unlikely occurrence of a failure to scram during an anticipated transient. The response of the plant to this postulated event falls within the envelope of study events in General Electric Company Topical Report NEDO-10349, dated March 1971, NEDO-24222, dated December 1979, and Section 15.8 of the FSAR.

The end-of-cycle recirculation pump trip (EOC-RPT) system is a supplement to the reactor trip. During turbine trip and generator load rejection events, the EOC-RPT will reduce the likelihood of reactor vessel level decreasing to level

2. Each EOC-RPT system trips both recirculation pumps, reducing coolant flow in order to reduce the void collapse in the core during two of the most limiting pressurization events. The two events for which the EOC-RPT protective feature will function are closure of the turbine stop valves and fast closure of the turbine control valves.

A fast closure sensor from each of two turbine control valves provides input to the EOC-RPT system; a fast closure sensor from each of the other two turbine control valves provides input to the second EOC-RPT system. Similarly, a position switch for each of two turbine stop valves provides input to one EOC-RPT system; a position switch from each of the other two stop valves provides input to the other EOC-RPT system. For each EOC-RPT system, the sensor relay contacts are arranged to form a 2-out-of-2 logic for the fast closure of turbine control valves and a 2-out-of-2 logic for the turbine stop valves. The operation of either logic will actuate the EOC-RPT system and trip both recirculation pumps.

LIMERICK - UNIT 1 B 3/4 3-3 Amendment No. 53, 69, 70, 158, 186

3/4.5 EMERGENCY CORE COOLING SYSTEM BASES 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUTDOWN The core spray system (CSS), together with the LPCI mode of the RHR system, is provided to assure that the core is adequately cooled following a loss-of-coolant accident and provides adequate core cooling capacity for all break sizes up to and including the double-ended reactor recirculation line break, and for smaller breaks following depressurization by the ADS. Management of gas voids is important to ECCS injection/spray subsystem OPERABILITY.

The CSS is a primary source of emergency core cooling after the reactor vessel is depressurized and a source for flooding of the core in case of accidental draining.

The surveillance requirements provide adequate assurance that the CSS will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown.

The low pressure coolant injection (LPCI) mode of the RHR system is provided to assure that the core is adequately cooled following a loss-of-coolant accident. Four subsystems, each with one pump, provide adequate core flooding for all break sizes up to and including the double-ended reactor recirculation line break, and for small breaks following depressurization by the ADS.

The surveillance requirements provide adequate assurance that the LPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown.

The high pressure coolant injection (HPCI) system is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the reactor coolant system and loss of coolant which does not result in rapid depressurization of the reactor vessel. The HPCI system permits the reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel is depressurized. The HCPI system continues to operate until reactor vessel pressure is below the pressure at which CSS operation or LPCI mode of the RHR system operation maintains core cooling.

The capacity of the system is selected to provide the required core cooling.

The HPCI pump is designed to deliver greater than or equal to 5600 gpm at reactor pressures between 1182 and 200 psig and is capable of delivering at least 5000 gpm between 1182 and 1205 psig. In the systems normal alignment, water from the condensate storage tank is used instead of injecting water from the suppression pool into the reactor, but no credit is taken in the safety analyses for the condensate storage tank water.

LIMERICK - UNIT 1 B 3/4 5-1 Amendment No. 106, 137 ECR 00-00177, Associated with Amendment 216

EMERGENCY CORE COOLING SYSTEM BASES ECCS - OPERATING and SHUTDOWN (Continued)

With the HPCI system inoperable, adequate core cooling is assured by the OPERABILITY of the redundant and diversified automatic depressurization system and both the CS and LPCI systems. In addition, the reactor core isolation cooling (RCIC) system, a system for which no credit is taken in the safety analysis, will automatically provide makeup at reactor operating pressures on a reactor low water level condition. The HPCI out-of-service period of 14 days is based on the demonstrated OPERABILITY of redundant and diversified low pressure core cooling systems and the RCIC system. The HPCI system, and one LPCI subsystem, and/or one CSS subsystem out-of-service period of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> ensures that sufficient ECCS, comprised of a minimum of one CSS subsystem, three LPCI subsystems, and all of the ADS will be available to 1) provide for safe shutdown of the facility, and 2) mitigate and control accident conditions within the facility.

A Note prohibits the application of Specification 3.0.4.b to an inoperable HPCI subsystem. There is an increased risk associated with entering an OPERATIONAL CONDITION or other specified condition in the Applicability with an inoperable HPCI subsystem and the provisions of Specification 3.0.4.b, which allow entry into an OPERATIONAL CONDITION or other specified condition in the Applicability with the Limiting Condition for Operation not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The surveillance requirements provide adequate assurance that the HPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test with reactor vessel injection requires reactor shutdown.

The ECCS injection/spray subsystem flow path piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the ECCS injection/spray subsystems and may also prevent a water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of ECCS injection/spray subsystem locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The ECCS injection/spray subsystem is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. Accumulated gas should be eliminated or brought within the acceptance criteria limits. ECCS injection/spray LIMERICK - UNIT 1 B 3/4 5-2 Amendment No. 8/10/94 Ltr,94,152,169, 186, Associated with Amendment 216

EMERGENCY CORE COOLING SYSTEM BASES ECCS - OPERATING and SHUTDOWN (Continued) subsystem locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location.

Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g.,

operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

Surveillance 4.5.1.a.1.b is modified by a Note which exempts system vent flow paths opened under administrative control. The administrative control should be proceduralized and include stationing a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed.

Upon failure of the HPCI system to function properly after a small break loss-of-coolant accident, the automatic depressurization system (ADS) automa-tically causes selected safety/relief valves to open, depressurizing the reactor so that flow from the low pressure core cooling systems can enter the core in time to limit fuel cladding temperature to less than 2200°F. ADS is conserva-tively required to be OPERABLE whenever reactor vessel pressure exceeds 100 psig. This pressure is substantially below that for which the low pressure core cool-ing systems can provide adequate core cooling for events requiring ADS.

ADS automatically controls five selected safety-relief valves. The safety analysis assumes all five are operable. The allowed out-of-service time for one valve for up to fourteen days is determined in a similar manner to other ECCS sub-system out-of-service time allowances.

Verification that ADS accumulator gas supply header pressure is 90 psig ensures adequate gas pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The design pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator at least two valve actuations can occur with the drywell at 70% of design pressure. The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure of 90 psig is provided by the PCIG supply.

LIMERICK - UNIT 1 B 3/4 5-3 Amendment No. 8/10/94 Ltr,94,152,169, 186, Associated with Amendment 216

EMERGENCY CORE COOLING SYSTEM BASES 3/4 5.2 - REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)

Background:

The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF. If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.4 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

Applicable Safety Analysis:

With the unit in OPERATIONAL CONDITION 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses. RPV water inventory control is required in OPERATIONAL CONDITIONS 4 and 5 to protect Safety Limit 2.1.4 and the fuel cladding barrier to prevent the release of radioactive material to the environment should an unexpected draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not postulated in OPERATIONAL CONDITIONS 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which single operator error or initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure, e.g., seismic event (except when risk is assessed and managed in accordance with LCO 3.7.4), loss of normal power, or single human error. It is assumed, based on engineering judgement, that while in OPERATIONAL CONDITIONS 4 and 5, one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level.

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

Limiting Condition for Operation:

The RPV water level must be controlled in OPERATIONAL CONDITIONS 4 and 5 to ensure that if an unexpected draining event should occur, the reactor coolant water level remains above the top of the active irradiated fuel as required by Safety Limit 2.1.4.

The Limiting Condition for Operation (LCO) requires the DRAIN TIME of RPV water inventory to the TAF to be 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. A DRAIN TIME of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> is considered reasonable to identify and initiate action to mitigate unexpected draining of reactor coolant. An event that could cause loss of RPV water inventory and result in the RPV water level reaching the TAF in greater than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> does not represent a significant challenge to Safety Limit 2.1.4 and can be managed as part of normal plant operation.

One low pressure ECCS injection/spray subsystem is required to be OPERABLE and capable of being manually started to provide defense-in-depth should an unexpected draining event occur. A low pressure ECCS injection/spray subsystem consists of either one Core Spray System (CSS) subsystem or one Low Pressure Coolant Injection (LPCI) subsystem. Each CSS subsystem consists of two motor driven pumps, piping, and valves to transfer water from the suppression pool or condensate storage tank (CST) to the RPV.

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

LIMERICK - UNIT 1 B 3/4 5-3a Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

The LCO is modified by a note which allows a required LPCI subsystem to be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned (remote or local) to the LPCI mode and is not otherwise inoperable. Alignment and operation for decay heat removal includes when the required RHR pump is not operating or when the system is realigned from or to the RHR shutdown cooling mode. This allowance is necessary since the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Because of the restrictions on DRAIN TIME, sufficient time will be available following an unexpected draining event to manually align and initiate LPCI subsystem operation to maintain RPV water inventory prior to the RPV water level reaching the TAF.

Applicability:

RPV water inventory control is required in OPERATIONAL CONDITIONS 4 and 5.

Requirements on water inventory control are contained in LCO 3.3.3.A, REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC) INSTRUMENTATION, and LCO 3.5.2, REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC). RPV water inventory control is required to protect Safety Limit 2.1.4 which is applicable whenever irradiated fuel is in the reactor vessel.

Actions:

Action a. - If none of the required low pressure ECCS injection/spray subsystems are OPERABLE, one subsystem must be restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. In this condition, the LCO controls on DRAIN TIME minimize the possibility that an unexpected draining event could necessitate the use of the ECCS injection/spray subsystem; however, the defense-in-depth provided by the ECCS injection/spray subsystem is lost.

The 4-hour allowed outage time for restoring the required low pressure ECCS injection/spray subsystem to OPERABLE status is based on engineering judgment that considers the LCO controls on DRAIN TIME and the low probability of an unexpected draining event that would result in loss of RPV water inventory.

If the inoperable ECCS injection/spray subsystem is not restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, action must be initiated immediately to establish a method of water injection capable of operating without offsite electrical power. The method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The method of water injection may be manually initiated and may consist of one or more systems or subsystems, and must be able to access water inventory capable of maintaining the RPV water level above the TAF for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. If recirculation of injected water would occur, it may be credited in determining the necessary water volume.

Action b. - Deleted Action c. - With the DRAIN TIME less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> but greater than or equal to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, compensatory measures should be taken to ensure the ability to implement mitigating actions should an unexpected draining event occur. Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environment.

LIMERICK - UNIT 1 B 3/4 5-3b Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

The secondary containment provides a controlled volume in which fission products can be contained, diluted, and processed prior to release to the environment.

Verification of the capability to establish SECONDARY CONTAINMENT INTEGRITY in less than the DRAIN TIME is required. The required verification confirms actions to establish SECONDARY CONTAINMENT INTEGRITY are preplanned and necessary materials are available. SECONDARY CONTAINMENT INTEGRITY is considered established when one Standby Gas Treatment (SGT) subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment. Verification that SECONDARY CONTAINMENT INTEGRITY can be established must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment.

Secondary containment penetration flow paths form a part of SECONDARY CONTAINMENT INTEGRITY. Verification of the capability to isolate each secondary containment penetration flow path in less than the DRAIN TIME is required. The required verification confirms actions to isolate secondary containment penetration flow paths are preplanned and necessary materials are available. Power operated valves are not required to receive automatic isolation signals if they can be closed manually within the required time. Verification that secondary containment penetration flow paths can be isolated must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment.

One SGT subsystem is capable of maintaining the secondary containment at a negative pressure with respect to the environment and filter gaseous releases.

Verification of the capability to place one SGT subsystem in operation in less than the DRAIN TIME is required. The required verification confirms actions to place a SGT subsystem in operation are preplanned and necessary materials are available.

Verification that a SGT subsystem can be placed in operation must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment.

Action d. - With the DRAIN TIME less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, mitigating actions are implemented in case an unexpected draining event should occur. Note that if the DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the required Action e. to restore DRAIN TIME to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> or greater is also applicable.

Immediate action to establish an additional method of water injection augmenting the ECCS injection/spray subsystem required by the LCO is required. The additional method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The note states that either the ECCS injection/

spray subsystem or the additional method of water injection must be capable of operating without offsite electrical power. The additional method of water injection may be manually initiated and may consist of one or more systems or subsystems. The additional method of water injection must be able to access water inventory capable of being injected to maintain the RPV water level above the TAF for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The additional method of water injection and the ECCS injection/spray subsystem may share all or part of the same water sources. If recirculation of injected water would occur, it may be credited in determining the required water volume.

Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environment.

LIMERICK - UNIT 1 B 3/4 5-3c Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

The secondary containment provides a control volume into which fission products can be contained, diluted, and processed prior to release to the environment. Actions to immediately establish SECONDARY CONTAINMENT INTEGRITY are required. With SECONDARY CONTAINMENT INTEGRITY established, one SGT subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment.

The secondary containment penetrations form a part of SECONDARY CONTAINMENT INTEGRITY. Actions to immediately verify that each secondary containment penetration flow path is isolated or to verify that it can be manually isolated from the control room are required.

One SGT subsystem is capable of maintaining the secondary containment at a negative pressure with respect to the environment and filter gaseous releases. Actions to immediately verify that at least one SGT subsystem is capable of being placed in operation are required. The required verification is an administrative activity and does not require manipulation or testing of equipment.

Action e. - If the ACTIONs and associated allowed outage times are not met or if the DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, actions must be initiated immediately to restore the DRAIN TIME to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. In this condition, there may be insufficient time to respond to an unexpected draining event to prevent the RPV water inventory from reaching the TAF. Note that ACTIONs are also applicable when DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

Surveillance Requirement (SR) 4.5.2.1 verifies that the DRAIN TIME of RPV water inventory to the TAF is 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The period of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> is considered reasonable to identify and initiate action to mitigate draining of reactor coolant. Loss of RPV water inventory that would result in the RPV water level reaching the TAF in greater than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> does not represent a significant challenge to Safety Limit 2.1.4 and can be managed as part of normal plant operation.

The definition of DRAIN TIME states that realistic cross-sectional areas and drain rates are used in the calculation. A realistic drain rate may be determined using a single, step-wise, or integrated calculation considering the changing RPV water level during a draining event. For a control rod RPV penetration flow path with the control rod drive mechanism removed and not replaced with a blank flange, the realistic cross-sectional area is based on the control rod blade seated in the control rod guide tube.

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

The definition of DRAIN TIME excludes from the calculation those penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are locked, sealed, or otherwise secured in the closed position, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths.

A blank flange or other bolted device must be connected with a sufficient number of bolts to prevent draining in the event of an Operating Basis Earthquake. Normal or expected leakage from closed systems or past isolation devices is permitted.

Determination that a system is intact and closed or isolated must consider the status of branch lines and ongoing plant maintenance and testing activities.

The Residual Heat Removal (RHR) Shutdown Cooling System is only considered an intact closed system when misalignment issues (Reference 6) have been precluded by functional valve interlocks or by isolation devices, such that redirection of RPV water out of an RHR subsystem is precluded. Further, the RHR Shutdown Cooling System is only considered an intact closed system if its controls have not been transferred to Remote Shutdown, which disables the interlocks and isolation signals.

LIMERICK - UNIT 1 B 3/4 5-3d Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

The exclusion of penetration flow paths from the determination of DRAIN TIME must consider the potential effects of a single operator error or initiating event on items supporting maintenance and testing (rigging, scaffolding, temporary shielding, piping plugs, snubber removal, freeze seals, etc.). If failure of such items could result and would cause a draining event from a closed system or between the RPV and the isolation device, the penetration flow path may not be excluded from the DRAIN TIME calculation.

TS 4.0.1 requires SRs to be met between performances. Therefore, any changes in plant conditions that would change the DRAIN TIME requires that a new DRAIN TIME be determined.

SRs 4.5.2.2 and 4.5.2.3 - The minimum water level of 16 feet required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the CSS subsystem or LPCI subsystem pumps, recirculation volume, and vortex prevention. With the suppression pool water level less than the required limit, the required ECCS injection/spray subsystem is inoperable unless aligned to an OPERABLE CST.

The required CSS subsystem is OPERABLE if it can take suction from the CST, and the CST water level is sufficient to provide the required NPSH for the CSS pumps.

Therefore, a verification that either the suppression pool water level is greater than or equal to 16 feet 0 inches or that a CSS subsystem is aligned to take suction from the CST and the CST contains greater than or equal to 135,000 available gallons of water, equivalent to a level of 29 feet 0 inches, ensures that the CSS subsystem can supply the required makeup water to the RPV.

SR 4.5.2.4 - The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge lines of the required ECCS injection/spray subsystems full of water ensures that the ECCS subsystem will perform properly. This may also prevent a water hammer following an ECCS initiation signal. One acceptable method of ensuring that the lines are full is to vent at the high points.

SR 4.5.2.5 - Verifying the correct alignment for manual, power operated, and automatic valves in the required ECCS subsystem flow paths provides assurance that the proper flow path will be available for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

SR 4.5.2.6 - Verifying that the required ECCS injection/spray subsystem can be manually started and operate for at least 10 minutes demonstrates that the subsystem is available to mitigate a draining event. Testing the ECCS injection/spray subsystem through the recirculation full flow test line is necessary to avoid overfilling the refueling cavity. The minimum operating time of 10 minutes was based on engineering judgement.

SR 4.5.2.7 - Verifying that each valve credited for automatically isolating a penetration flow path actuates to the isolation position on an actual or simulated RPV water level isolation signal is required to prevent RPV water inventory from dropping below the TAF should an unexpected draining event occur.

LIMERICK - UNIT 1 B 3/4 5-3e Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

SR 4.5.2.8 - The required ECCS subsystem is required to actuate on a manual initiation signal. This surveillance verifies that a manual initiation signal will cause the required CSS subsystem or LPCI subsystem to start and operate as designed, including pump startup and actuation of all automatic valves to their required positions. This SR is modified by a note that excludes vessel injection/spray during the surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the surveillance.

The Surveillance Frequencies in the above SRs are controlled under the Surveillance Frequency Controlled Program.

REFERENCES

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

2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

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

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

5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

6. General Electric Service Information Letter No. 388, "RHR Valve Misalignment During Shutdown Cooling Operation for BWR 3/4/5/6," February 1983.

LIMERICK - UNIT 1 B 3/4 5-3f Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES ECCS - OPERATING and SHUTDOWN (Continued) 3/4.5.3 SUPPRESSION CHAMBER The suppression chamber is required to be OPERABLE as part of the ECCS to ensure that a sufficient supply of water is available to the HPCI, CS and LPCI systems in the event of a LOCA. This limit on suppression chamber minimum water volume ensures that sufficient water is available to permit recirculation cooling flow to the core. The OPERABILITY of the suppression chamber in OPERATIONAL CONDITION 1, 2, or 3 is also required by Specification 3.6.2.1.

Repair work might require making the suppression chamber inoperable. This specification will permit those repairs to be made and at the same time give assurance that the irradiated fuel has an adequate cooling water supply when the suppression chamber must be made inoperable, including draining, in OPERATIONAL CONDITION 4 or 5.

In OPERATIONAL CONDITION 4 and 5 the suppression chamber minimum required water volume is reduced because the reactor coolant is maintained at or below 200°F. Since pressure suppression is not required below 212°F, the minimum water volume is based on NPSH, recirculation volume and vortex prevention plus a safety margin for conservatism.

LIMERICK - UNIT 1 B 3/4 5-4 Amendment No. 152 Associated with Amendment 216

CONTAINMENT SYSTEMS BASES 3/4.6.5 SECONDARY CONTAINMENT Secondary containment is designed to minimize any ground level release of radioactive material which may result from an accident. The Reactor Enclosure and associated structures provide secondary containment during normal operation when the drywell is sealed and in service. At other times the drywell may be open and, when required, secondary containment integrity is specified.

Establishing and maintaining a vacuum in the reactor enclosure secondary containment with the standby gas treatment system in accordance with the Surveillance Frequency Control Program, along with the surveillance of the doors, hatches, dampers and valves, is adequate to ensure that there are no violations of the integrity of the secondary containment.

The OPERABILITY of the reactor enclosure recirculation system and the standby gas treatment systems ensures that sufficient iodine removal capability will be available in the event of a LOCA. The reduction in containment iodine inventory reduces the resulting SITE BOUNDARY and Control Room radiation doses associated with containment leakage. The operation of these systems and resultant iodine removal capacity are consistent with the assumptions used in the LOCA analysis. Provisions have been made to continuously purge the filter plenums with instrument air when the filters are not in use to prevent buildup of moisture on the adsorbers and the HEPA filters.

As a result of the Alternative Source Term (AST) project, secondary containment integrity of the refueling area is not required during certain conditions when handling irradiated fuel or during CORE ALTERATIONS and alignment of the Standby Gas Treatment System to the refueling area is not required. The control room dose analysis for the Fuel Handling Accident (FHA) is based on unfiltered releases from the South Stack and therefore, does not require the Standby Gas Treatment System to be aligned to the refueling area.

However, when handling RECENTLY IRRADIATED FUEL or during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel, secondary containment integrity of the refueling area is required and alignment of the Standby Gas Treatment System to the refueling area is required. The AST fuel handling analysis does not include an accident involving RECENTLY IRRADIATED FUEL or an accident involving draining the reactor vessel.

The Standby Gas Treatment System is required to be OPERABLE when handling irradiated fuel, handling RECENTLY IRRADIATED FUEL and, during CORE ALTERATIONS and during operations with a potential to drain the vessel with the vessel head removed and fuel in the vessel. Fuel Handling Accident releases from the North Stack must be filtered through the Standby Gas Treatment System to maintain control room doses within regulatory limits. The OPERABILITY of the Standby Gas Treatment System assures that releases, if made through the North Stack, are filtered prior to release.

LIMERICK - UNIT 1 B 3/4 6-5 Amendment No. 6,40,71,106,122, 185,186, ECR LG 09-00052

3/4.10 SPECIAL TEST EXCEPTIONS BASES 3/4.10.8 INSERVICE LEAK AND HYDROSTATIC TESTING This special test exception permits certain reactor coolant pressure tests to be performed in OPERATIONAL CONDITION 4 when the metallurgical characteristics of the reactor pressure vessel (RPV) or plant temperature control capabilities during these tests require the pressure testing at temperatures greater than 200°F and less than or equal to 212°F (normally corresponding to OPERATIONAL CONDITION 3). The additionally imposed OPERATIONAL CONDITION 3 requirements for SECONDARY CONTAINMENT INTEGRITY provide conservatism in response to an operational event.

Invoking the requirement for Refueling Area Secondary Containment Integrity along with the requirement for Reactor Enclosure Secondary Containment Integrity applies the requirements for Reactor Enclosure Secondary Containment Integrity to an extended area encompassing Zones 1 and 3. Operations with the Potential for Draining the Vessel, Core alterations, and fuel handling are prohibited in this secondary containment configuration. Drawdown and inleakage testing performed for the combined zone system alignment shall be considered adequate to demonstrate integrity of the combined zones.

Inservice hydrostatic testing and inservice leak pressure tests required by Section XI of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code are performed prior to the reactor going critical after a refueling outage. The minimum temperatures (at the required pressures) allowed for these tests are determined from the RPV pressure and temperature (P/T) limits required by LCO 3.4.6, Reactor Coolant System Pressure/Temperature Limits. These limits are conservatively based on the fracture toughness of the reactor vessel, taking into account anticipated vessel neutron fluence. With increased reactor fluence over time, the minimum allowable vessel temperature increases at a given pressure.

LIMERICK - UNIT 1 B 3/4 10-2 Amendment No. 133 ECR 99-00864, 167

INSTRUMENTATION BASES 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION (Continued)

Surveillance intervals are determined in accordance with the Surveillance Frequency Control Program and maintenance outage times have been determined in accordance with NEDC-30936P, Parts 1 and 2, "Technical Specification Improvement Methodology (with Demonstration for BWR ECCS Actuation Instrumentation)," as approved by the NRC and documented in the SER (letter to D. N. Grace from A. C.

Thadani dated December 9, 1988 (Part 1) and letter to D. N. Grace from C. E. Rossi dated December 9, 1988 (Part 2)).

Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power for energizing various components such as pump motors, motor operated valves, and the associated control components. If the loss of power instrumentation detects that voltage levels are too low, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources. The loss of power relays in each channel have sufficient overlapping detection characteristics and functionality to permit operation subject to the conditions in Action Statement 37.

Bases 3/4.8.1, 3/4.8.2, and 3/4.8.3 provide discussion regarding parametric bounds for determining operability of the offsite sources. Those Bases assume that the loss of power relays are operable. With an inoperable 127Z-11X0X relay, the grid voltage is monitored to 230kV (for the 101 Safeguard Bus Source) or 525kV (for the 201 Safeguard Bus Source) to increase the margin for the operation of the 127Z-11X0X relay.

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses.

3/4.3.3.A REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC) INSTRUMENTATION The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF. If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation.

Safety Limit 2.1.4 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

Technical Specifications are required by 10 CFR 50.36 to include limiting safety system settings (LSSS) for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated to ensure that a SL is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur. The actual settings for the automatic isolation channels are the same as those established for the same functions in OPERATIONAL CONDITIONS 1, 2, and 3 in TABLE 3.3.2-2, "ISOLATION ACTUATION INSTRUMENTATION SETPOINTS."

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

RPV water inventory control is required in OPERATIONAL CONDITIONS 4 and 5 to protect Safety Limit 2.1.4 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur. Under the definition of DRAIN TIME, some penetration flow paths may be excluded from the DRAIN TIME calculation LIMERICK - UNIT 2 B 3/4 3-2a Amendment No. 17, 32, 33, 120, 147

INSTRUMENTATION BASES 3/4.3.3.A RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION (Continued) if they will be isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation.

The purpose of the RPV Water Inventory Control Instrumentation is to support the requirements of LCO 3.5.2, Reactor Pressure Vessel (RPV) Water Inventory Control (WIC), and the definition of DRAIN TIME. There are functions that are required for manual initiation or operation of the ECCS injection/spray subsystem required to be OPERABLE by LCO 3.5.2 and other functions that support automatic isolation of Residual Heat Removal (RHR) subsystem and Reactor Water Cleanup (RWCU) system penetration flow path(s) on low RPV water level.

The RPV Water Inventory Control Instrumentation supports operation of the Core Spray System (CSS) and the Low Pressure Coolant Injection (LPCI) system. The equipment involved with each of these systems is described in the Bases for LCO 3.5.2.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not postulated in OPERATIONAL CONDITIONS 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is postulated in which a single operator error or initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure, e.g., seismic event, loss of normal power, or single human error. It is assumed, based on engineering judgment, that while in OPERATIONAL CONDITIONS 4 and 5, one low pressure ECCS injection/spray subsystem can be manually initiated to maintain adequate reactor vessel water level.

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

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

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

Core Spray Systems - Reactor Vessel Pressure - Low (Permissive) and Low Pressure Coolant Injection Mode of RHR System - Injection Valve Differential Pressure -

Low (Permissive)

The low reactor vessel pressure signal for Core Spray and the injection valve low differential pressure signal for LPCI are used as permissives for the low pressure ECCS injection/spray subsystem manual injection functions. These functions ensure that, prior to opening the injection valves of the low pressure ECCS subsystems, the reactor pressure has fallen to a value below these subsystems' maximum design pressure. While it is assured during OPERATIONAL CONDITIONS 4 and 5 that the reactor vessel pressure will be below the ECCS maximum design pressure, the Reactor Vessel Pressure - Low signal and the Injection Valve Differential Pressure - Low signal are assumed to be OPERABLE and capable of permitting initiation of the ECCS.

The Reactor Vessel Pressure - Low signals are initiated from four pressure transmitters that sense the reactor vessel pressure. The transmitters are connected to four trip units. The outputs of the trip units are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.

LIMERICK - UNIT 2 B 3/4 3-2b Amendment No.

INSTRUMENTATION BASES 3/4.3.3.A RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION (Continued)

The Injection Valve Differential Pressure - Low signals are initiated from four differential pressure transmitters (one per valve) that monitor the differential pressure across each LPCI injection valve.

The Allowable Values are low enough to prevent overpressuring the equipment in the low pressure ECCS. The instrument channels of the Reactor Vessel Pressure -

Low and Injection Valve Differential Pressure - Low Functions are required to be OPERABLE in OPERATIONAL CONDITIONS 4 and 5 when ECCS manual initiation is required to be OPERABLE by LCO 3.5.2.

Manual Initiation The Manual Initiation push button channels introduce signals into the appropriate ECCS logic to provide manual initiation capability. There is one push button for each of the CSS and LPCI subsystems (i.e., four for CSS and four for LPCI).

There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons. A channel of the Manual Initiation Function (one channel per subsystem) is required to be OPERABLE in OPERATIONAL CONDITIONS 4 and 5 when the associated ECCS subsystems are required to be OPERABLE per LCO 3.5.2.

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

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

The Reactor Vessel Water Level Low - Level 3 Allowable Value was chosen to be the same as the Primary Containment Isolation Instrumentation Reactor Vessel Water Level Low - Level 3 Allowable Value (TABLE 3.3.2-2), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level Low - Level 3 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME. This Function isolates the Group 2 valves.

Reactor Water Cleanup (RWCU) System Isolation - Reactor Vessel Water Level -

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

LIMERICK - UNIT 2 B 3/4 3-2c Amendment No.

INSTRUMENTATION BASES 3/4.3.3.A RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION (Continued)

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

The Reactor Vessel Water Level - Low, Low - Level 2 Allowable Value was chosen to be the same as the Primary Containment Isolation Instrumentation Reactor Vessel Water Level - Low, Low Level 2 Allowable Value (TABLE 3.3.2-2), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low, Low - Level 2 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME. This Function isolates the Group 3 valves.

Actions A note has been provided to modify the ACTIONs related to RPV Water Inventory Control instrumentation channels. The ACTIONs for inoperable RPV Water Inventory Control instrumentation channels provide appropriate compensatory measures for each inoperable RPV Water Inventory Control instrumentation channel.

ACTION a. directs taking the appropriate ACTION referenced in Table 3.3.3.A-1.

The applicable ACTION referenced in the Table is Function dependent.

RHR System Shutdown Cooling Mode Isolation, Reactor Vessel Water Level Low -

Level 3, and Reactor Water Cleanup System Isolation, Reactor Vessel Water Level -

Low, Low - Level 2 functions are applicable when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME. If the instrumentation is inoperable, ACTION 38 directs an immediate declaration that the associated penetration flow path(s) are incapable of automatic isolation and calculation of DRAIN TIME. The calculation cannot credit automatic isolation of the affected penetration flow paths.

Low reactor vessel pressure signals are used as permissives for the low pressure ECCS injection/spray subsystem manual injection functions. If the permissive is inoperable, manual initiation of ECCS is prohibited. Therefore, the permissive must be placed in the trip condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. With the permissive in the trip condition, manual initiation may be performed. Prior to placing the permissive in the tripped condition, the operator can take manual control of the pump and the injection valve to inject water into the RPV.

The allowed outage time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is intended to allow the operator time to evaluate any discovered inoperabilities and to place the channel in trip.

The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed outage time was chosen to allow time for the operator to evaluate and repair any discovered inoperabilities. The allowed outage time is appropriate given the ability to manually start the ECCS pumps and open the injection valves and to manually ensure the pump does not overheat.

With the ACTION and associated allowed outage time of ACTION 39 or 40 not met, the associated low pressure ECCS injection/spray subsystem may be incapable of performing the intended function, and must be declared inoperable immediately.

LIMERICK - UNIT 2 B 3/4 3-2d Amendment No.

INSTRUMENTATION BASES 3/4.3.3.A RPV WATER INVENTORY CONTROL (WIC) INSTRUMENTATION (Continued)

REFERENCES

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

2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

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

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

5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION The anticipated transient without scram (ATWS) recirculation pump trip system provides a means of limiting the consequences of the unlikely occurrence of a failure to scram during an anticipated transient. The response of the plant to this postulated event falls within the envelope of study events in General Electric Company Topical Report NEDO-10349, dated March 1971, NEDO-24222, dated December 1979, and Section 15.8 of the FSAR.

The end-of-cycle recirculation pump trip (EOC-RPT) system is a supplement to the reactor trip. During turbine trip and generator load rejection events, the EOC-RPT will reduce the likelihood of reactor vessel level decreasing to level 2. Each EOC-RPT system trips both recirculation pumps, reducing coolant flow in order to reduce the void collapse in the core during two of the most limiting pressurization events.

The two events for which the EOC-RPT protective feature will function are closure of the turbine stop valves and fast closure of the turbine control valves.

A fast closure sensor from each of two turbine control valves provides input to the EOC-RPT system; a fast closure sensor from each of the other two turbine control valves provides input to the second EOC-RPT system. Similarly, a position switch for each of two turbine stop valves provides input to one EOC-RPT system; a position switch from each of the other two stop valves provides input to the other EOC-RPT system. For each EOC-RPT system, the sensor relay contacts are arranged to form a 2-out-of-2 logic for the fast closure of turbine control valves and a 2-out-of-2 logic for the turbine stop valves. The operation of either logic will actuate the EOC-RPT system and trip both recirculation pumps.

LIMERICK - UNIT 2 B 3/4 3-3 Amendment No. 17,32,33,120, 147

3/4.5 EMERGENCY CORE COOLING SYSTEM BASES 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUTDOWN The core spray system (CSS), together with the LPCI mode of the RHR system, is provided to assure that the core is adequately cooled following a loss-of-coolant accident and provides adequate core cooling capacity for all break sizes up to and including the double-ended reactor recirculation line break, and for smaller breaks following depressurization by the ADS. Management of gas voids is important to ECCS injection/spray subsystem OPERABILITY.

The CSS is a primary source of emergency core cooling after the reactor vessel is depressurized and a source for flooding of the core in case of accidental draining.

The surveillance requirements provide adequate assurance that the CSS will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown.

The low pressure coolant injection (LPCI) mode of the RHR system is provided to assure that the core is adequately cooled following a loss-of-coolant accident. Four subsystems, each with one pump, provide adequate core flooding for all break sizes up to and including the double-ended reactor recirculation line break, and for small breaks following depressurization by the ADS.

The surveillance requirements provide adequate assurance that the LPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown.

The high pressure coolant injection (HPCI) system is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the reactor coolant system and loss of coolant which does not result in rapid depressurization of the reactor vessel. The HPCI system permits the reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel is depressurized. The HCPI system continues to operate until reactor vessel pressure is below the pressure at which CSS operation or LPCI mode of the RHR system operation maintains core cooling.

The capacity of the system is selected to provide the required core cooling.

The HPCI pump is designed to deliver greater than or equal to 5600 gpm at reactor pressures between 1182 and 200 psig and is capable of delivering at least 5000 gpm between 1182 and 1205 psig. In the systems normal alignment, water from the condensate storage tank is used instead of injecting water from the suppression pool into the reactor, but no credit is taken in the safety analyses for the condensate storage tank water.

LIMERICK - UNIT 2 B 3/4 5-1 Amendment No. 51,98, ECR 00-00177, Associated with Amendment 178

EMERGENCY CORE COOLING SYSTEM BASES ECCS - OPERATING and SHUTDOWN (Continued)

With the HPCI system inoperable, adequate core cooling is assured by the OPERABILITY of the redundant and diversified automatic depressurization system and both the CS and LPCI systems. In addition, the reactor core isolation cooling (RCIC) system, a system for which no credit is taken in the safety analysis, will automatically provide makeup at reactor operating pressures on a reactor low water level condition. The HPCI out-of-service period of 14 days is based on the demonstrated OPERABILITY of redundant and diversified low pressure core cooling systems and the RCIC system. The HPCI system, and one LPCI subsystem, and/or one CSS subsystem out-of-service period of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> ensures that sufficient ECCS, comprised of a minimum of one CSS subsystem, three LPCI subsystems, and all of the ADS will be available to 1) provide for safe shutdown of the facility, and 2) mitigate and control accident conditions within the facility. A Note prohibits the application of Specification 3.0.4.b to an inoperable HPCI subsystem. There is an increased risk associated with entering an OPERATIONAL CONDITION or other specified condition in the Applicability with an inoperable HPCI subsystem and the provisions of Specification 3.0.4.b, which allow entry into an OPERATIONAL CONDITION or other specified condition in the Applicability with the Limiting Condition for Operation not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The surveillance requirements provide adequate assurance that the HPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test with reactor vessel injection requires reactor shutdown.

The ECCS injection/spray subsystem flow path piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the ECCS injection/spray subsystems and may also prevent a water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of ECCS injection/spray subsystem locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The ECCS injection/spray subsystem is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.

LIMERICK - UNIT 2 B 3/4 5-2 Amendment No. 8/10/94 Ltr, 58, 116, 132, 147, Associated with Amendment No. 178

EMERGENCY CORE COOLING SYSTEM BASES ECCS - OPERATING and SHUTDOWN (Continued)

ECCS injection/spray subsystem locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g.,

operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

Surveillance 4.5.1.a.1.b is modified by a Note which exempts system vent flow paths opened under administrative control. The administrative control should be proceduralized and include stationing a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed.

Upon failure of the HPCI system to function properly after a small break loss-of-coolant accident, the automatic depressurization system (ADS) automa-tically causes selected safety/relief valves to open, depressurizing the reactor so that flow from the low pressure core cooling systems can enter the core in time to limit fuel cladding temperature to less than 2200°F. ADS is conserva-tively required to be OPERABLE whenever reactor vessel pressure exceeds 100 psig.

This pressure is substantially below that for which the low pressure core cool-ing systems can provide adequate core cooling for events requiring ADS.

ADS automatically controls five selected safety-relief valves. The safety analysis assumes all five are operable. The allowed out-of-service time for one valve for up to fourteen days is determined in a similar manner to other ECCS sub-system out-of-service time allowances.

Verification that ADS accumulator gas supply header pressure is 90 psig ensures adequate gas pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The design pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator at least two valve actuations can occur with the drywell at 70%

of design pressure. The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS.

This minimum required pressure of 90 psig is provided by the PCIG supply.

LIMERICK - UNIT 2 B 3/4 5-3 Amendment No. 8/10/94 Ltr, 58, 116, 132, 147, Associated with Amendment No. 178

EMERGENCY CORE COOLING SYSTEM BASES 3/4 5.2 - REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)

Background:

The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF. If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.4 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

Applicable Safety Analysis:

With the unit in OPERATIONAL CONDITION 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses. RPV water inventory control is required in OPERATIONAL CONDITIONS 4 and 5 to protect Safety Limit 2.1.4 and the fuel cladding barrier to prevent the release of radioactive material to the environment should an unexpected draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not postulated in OPERATIONAL CONDITIONS 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which single operator error or initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure, e.g., seismic event (except when risk is assessed and managed in accordance with LCO 3.7.4), loss of normal power, or single human error. It is assumed, based on engineering judgement, that while in OPERATIONAL CONDITIONS 4 and 5, one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level.

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

Limiting Condition for Operation:

The RPV water level must be controlled in OPERATIONAL CONDITIONS 4 and 5 to ensure that if an unexpected draining event should occur, the reactor coolant water level remains above the top of the active irradiated fuel as required by Safety Limit 2.1.4.

The Limiting Condition for Operation (LCO) requires the DRAIN TIME of RPV water inventory to the TAF to be 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. A DRAIN TIME of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> is considered reasonable to identify and initiate action to mitigate unexpected draining of reactor coolant. An event that could cause loss of RPV water inventory and result in the RPV water level reaching the TAF in greater than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> does not represent a significant challenge to Safety Limit 2.1.4 and can be managed as part of normal plant operation.

One low pressure ECCS injection/spray subsystem is required to be OPERABLE and capable of being manually started to provide defense-in-depth should an unexpected draining event occur. A low pressure ECCS injection/spray subsystem consists of either one Core Spray System (CSS) subsystem or one Low Pressure Coolant Injection (LPCI) subsystem. Each CSS subsystem consists of two motor driven pumps, piping, and valves to transfer water from the suppression pool or condensate storage tank (CST) to the RPV. Each LPCI subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV.

LIMERICK - UNIT 2 B 3/4 5-3a Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

The LCO is modified by a note which allows a required LPCI subsystem to be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned (remote or local) to the LPCI mode and is not otherwise inoperable. Alignment and operation for decay heat removal includes when the required RHR pump is not operating or when the system is realigned from or to the RHR shutdown cooling mode. This allowance is necessary since the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Because of the restrictions on DRAIN TIME, sufficient time will be available following an unexpected draining event to manually align and initiate LPCI subsystem operation to maintain RPV water inventory prior to the RPV water level reaching the TAF.

Applicability:

RPV water inventory control is required in OPERATIONAL CONDITIONS 4 and 5.

Requirements on water inventory control are contained in LCO 3.3.3.A, REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC) INSTRUMENTATION, and LCO 3.5.2, REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC). RPV water inventory control is required to protect Safety Limit 2.1.4 which is applicable whenever irradiated fuel is in the reactor vessel.

Actions:

Action a. - If none of the required low pressure ECCS injection/spray subsystems are OPERABLE, one subsystem must be restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. In this condition, the LCO controls on DRAIN TIME minimize the possibility that an unexpected draining event could necessitate the use of the ECCS injection/spray subsystem; however, the defense-in-depth provided by the ECCS injection/spray subsystem is lost. The 4-hour allowed outage time for restoring the required low pressure ECCS injection/spray subsystem to OPERABLE status is based on engineering judgment that considers the LCO controls on DRAIN TIME and the low probability of an unexpected draining event that would result in loss of RPV water inventory.

If the inoperable ECCS injection/spray subsystem is not restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, action must be initiated immediately to establish a method of water injection capable of operating without offsite electrical power. The method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The method of water injection may be manually initiated and may consist of one or more systems or subsystems, and must be able to access water inventory capable of maintaining the RPV water level above the TAF for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. If recirculation of injected water would occur, it may be credited in determining the necessary water volume.

Action b. - Deleted Action c. - With the DRAIN TIME less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> but greater than or equal to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, compensatory measures should be taken to ensure the ability to implement mitigating actions should an unexpected draining event occur. Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environment.

LIMERICK - UNIT 2 B 3/4 5-3b Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

The secondary containment provides a controlled volume in which fission products can be contained, diluted, and processed prior to release to the environment.

Verification of the capability to establish SECONDARY CONTAINMENT INTEGRITY in less than the DRAIN TIME is required. The required verification confirms actions to establish SECONDARY CONTAINMENT INTEGRITY are preplanned and necessary materials are available. SECONDARY CONTAINMENT INTEGRITY is considered established when one Standby Gas Treatment (SGT) subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment. Verification that SECONDARY CONTAINMENT INTEGRITY can be established must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment.

Secondary containment penetration flow paths form a part of SECONDARY CONTAINMENT INTEGRITY. Verification of the capability to isolate each secondary containment penetration flow path in less than the DRAIN TIME is required. The required verification confirms actions to isolate secondary containment penetration flow paths are preplanned and necessary materials are available. Power operated valves are not required to receive automatic isolation signals if they can be closed manually within the required time. Verification that secondary containment penetration flow paths can be isolated must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment.

One SGT subsystem is capable of maintaining the secondary containment at a negative pressure with respect to the environment and filter gaseous releases.

Verification of the capability to place one SGT subsystem in operation in less than the DRAIN TIME is required. The required verification confirms actions to place a SGT subsystem in operation are preplanned and necessary materials are available.

Verification that a SGT subsystem can be placed in operation must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment.

Action d. - With the DRAIN TIME less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, mitigating actions are implemented in case an unexpected draining event should occur. Note that if the DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the required Action e. to restore DRAIN TIME to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> or greater is also applicable.

Immediate action to establish an additional method of water injection augmenting the ECCS injection/spray subsystem required by the LCO is required. The additional method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The note states that either the ECCS injection/spray subsystem or the additional method of water injection must be capable of operating without offsite electrical power. The additional method of water injection may be manually initiated and may consist of one or more systems or subsystems. The additional method of water injection must be able to access water inventory capable of being injected to maintain the RPV water level above the TAF for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The additional method of water injection and the ECCS injection/spray subsystem may share all or part of the same water sources. If recirculation of injected water would occur, it may be credited in determining the required water volume.

Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environment.

LIMERICK - UNIT 2 B 3/4 5-3c Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

The secondary containment provides a control volume into which fission products can be contained, diluted, and processed prior to release to the environment. Actions to immediately establish SECONDARY CONTAINMENT INTEGRITY are required. With SECONDARY CONTAINMENT INTEGRITY established, one SGT subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment.

The secondary containment penetrations form a part of SECONDARY CONTAINMENT INTEGRITY. Actions to immediately verify that each secondary containment penetration flow path is isolated or to verify that it can be manually isolated from the control room are required.

One SGT subsystem is capable of maintaining the secondary containment at a negative pressure with respect to the environment and filter gaseous releases. Actions to immediately verify that at least one SGT subsystem is capable of being placed in operation are required. The required verification is an administrative activity and does not require manipulation or testing of equipment.

Action e. - If the ACTIONs and associated allowed outage times are not met or if the DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, actions must be initiated immediately to restore the DRAIN TIME to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. In this condition, there may be insufficient time to respond to an unexpected draining event to prevent the RPV water inventory from reaching the TAF. Note that ACTIONs are also applicable when DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

Surveillance Requirement (SR) 4.5.2.1 verifies that the DRAIN TIME of RPV water inventory to the TAF is 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The period of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> is considered reasonable to identify and initiate action to mitigate draining of reactor coolant. Loss of RPV water inventory that would result in the RPV water level reaching the TAF in greater than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> does not represent a significant challenge to Safety Limit 2.1.4 and can be managed as part of normal plant operation.

The definition of DRAIN TIME states that realistic cross-sectional areas and drain rates are used in the calculation. A realistic drain rate may be determined using a single, step-wise, or integrated calculation considering the changing RPV water level during a draining event. For a control rod RPV penetration flow path with the control rod drive mechanism removed and not replaced with a blank flange, the realistic cross-sectional area is based on the control rod blade seated in the control rod guide tube. If the control rod blade will be raised from the penetration to adjust or verify seating of the blade, the exposed cross-sectional area of the RPV penetration flow path is used.

The definition of DRAIN TIME excludes from the calculation those penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are locked, sealed, or otherwise secured in the closed position, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths. A blank flange or other bolted device must be connected with a sufficient number of bolts to prevent draining in the event of an Operating Basis Earthquake.

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

Determination that a system is intact and closed or isolated must consider the status of branch lines and ongoing plant maintenance and testing activities.

The Residual Heat Removal (RHR) Shutdown Cooling System is only considered an intact closed system when misalignment issues (Reference 6) have been precluded by functional valve interlocks or by isolation devices, such that redirection of RPV water out of an RHR subsystem is precluded. Further, the RHR Shutdown Cooling System is only considered an intact closed system if its controls have not been transferred to Remote Shutdown, which disables the interlocks and isolation signals.

LIMERICK - UNIT 2 B 3/4 5-3d Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

The exclusion of penetration flow paths from the determination of DRAIN TIME must consider the potential effects of a single operator error or initiating event on items supporting maintenance and testing (rigging, scaffolding, temporary shielding, piping plugs, snubber removal, freeze seals, etc.). If failure of such items could result and would cause a draining event from a closed system or between the RPV and the isolation device, the penetration flow path may not be excluded from the DRAIN TIME calculation.

TS 4.0.1 requires SRs to be met between performances. Therefore, any changes in plant conditions that would change the DRAIN TIME requires that a new DRAIN TIME be determined.

SRs 4.5.2.2 and 4.5.2.3 - The minimum water level of 16 feet required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the CSS subsystem or LPCI subsystem pumps, recirculation volume, and vortex prevention. With the suppression pool water level less than the required limit, the required ECCS injection/spray subsystem is inoperable unless aligned to an OPERABLE CST.

The required CSS subsystem is OPERABLE if it can take suction from the CST, and the CST water level is sufficient to provide the required NPSH for the CSS pumps.

Therefore, a verification that either the suppression pool water level is greater than or equal to 16 feet 0 inches or that a CSS subsystem is aligned to take suction from the CST and the CST contains greater than or equal to 135,000 available gallons of water, equivalent to a level of 29 feet 0 inches, ensures that the CSS subsystem can supply the required makeup water to the RPV.

SR 4.5.2.4 - The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge lines of the required ECCS injection/spray subsystems full of water ensures that the ECCS subsystem will perform properly. This may also prevent a water hammer following an ECCS initiation signal.

One acceptable method of ensuring that the lines are full is to vent at the high points.

SR 4.5.2.5 - Verifying the correct alignment for manual, power operated, and automatic valves in the required ECCS subsystem flow paths provides assurance that the proper flow path will be available for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

SR 4.5.2.6 - Verifying that the required ECCS injection/spray subsystem can be manually started and operate for at least 10 minutes demonstrates that the subsystem is available to mitigate a draining event. Testing the ECCS injection/spray subsystem through the recirculation full flow test line is necessary to avoid overfilling the refueling cavity. The minimum operating time of 10 minutes was based on engineering judgement.

SR 4.5.2.7 - Verifying that each valve credited for automatically isolating a penetration flow path actuates to the isolation position on an actual or simulated RPV water level isolation signal is required to prevent RPV water inventory from dropping below the TAF should an unexpected draining event occur.

LIMERICK - UNIT 2 B 3/4 5-3e Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES RPV WATER INVENTORY CONTROL (WIC) (Continued)

SR 4.5.2.8 - The required ECCS subsystem is required to actuate on a manual initiation signal. This surveillance verifies that a manual initiation signal will cause the required CSS subsystem or LPCI subsystem to start and operate as designed, including pump startup and actuation of all automatic valves to their required positions. This SR is modified by a note that excludes vessel injection/spray during the surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the surveillance.

The Surveillance Frequencies in the above SRs are controlled under the Surveillance Frequency Controlled Program.

REFERENCES

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

2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

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

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

5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

6. General Electric Service Information Letter No. 388, "RHR Valve Misalignment During Shutdown Cooling Operation for BWR 3/4/5/6," February 1983.

LIMERICK - UNIT 2 B 3/4 5-3f Amendment No.

EMERGENCY CORE COOLING SYSTEM BASES ECCS - OPERATING and SHUTDOWN (Continued) 3/4.5.3 SUPPRESSION CHAMBER The suppression chamber is required to be OPERABLE as part of the ECCS to ensure that a sufficient supply of water is available to the HPCI, CS and LPCI systems in the event of a LOCA. This limit on suppression chamber minimum water volume ensures that sufficient water is available to permit recirculation cooling flow to the core. The OPERABILITY of the suppression chamber in OPERATIONAL CONDITION 1, 2, or 3 is also required by Specification 3.6.2.1.

Repair work might require making the suppression chamber inoperable. This specification will permit those repairs to be made and at the same time give assurance that the irradiated fuel has an adequate cooling water supply when the suppression chamber must be made inoperable, including draining, in OPERATIONAL CONDITION 4 or 5.

In OPERATIONAL CONDITION 4 and 5 the suppression chamber minimum required water volume is reduced because the reactor coolant is maintained at or below 200°F. Since pressure suppression is not required below 212°F, the minimum water volume is based on NPSH, recirculation volume and vortex prevention plus a safety margin for conservatism.

LIMERICK - UNIT 2 B 3/4 5-4 Amendment No. 116, Associated with Amendment No. 178

CONTAINMENT SYSTEMS BASES 3/4.6.5 SECONDARY CONTAINMENT Secondary containment is designed to minimize any ground level release of radioactive material which may result from an accident. The Reactor Enclosure and associated structures provide secondary containment during normal operation when the drywell is sealed and in service. At other times the drywell may be open and, when required, secondary containment integrity is specified.

Establishing and maintaining a vacuum in the reactor enclosure secondary containment with the standby gas treatment system in accordance with the Surveillance Frequency Control Program, along with the surveillance of the doors, hatches, dampers and valves, is adequate to ensure that there are no violations of the integrity of the secondary containment.

The OPERABILITY of the reactor enclosure recirculation system and the standby gas treatment systems ensures that sufficient iodine removal capability will be available in the event of a LOCA. The reduction in containment iodine inventory reduces the resulting SITE BOUNDARY and Control Room radiation doses associated with containment leakage. The operation of these systems and resultant iodine removal capacity are consistent with the assumptions used in the LOCA analysis. Provisions have been made to continuously purge the filter plenums with instrument air when the filters are not in use to prevent buildup of moisture on the adsorbers and the HEPA filters.

As a result of the Alternative Source Term (AST) project, secondary containment integrity of the refueling area is not required during certain conditions when handling irradiated fuel or during CORE ALTERATIONS and alignment of the Standby Gas Treatment System to the refueling area is not required. The control room dose analysis for the Fuel Handling Accident (FHA) is based on unfiltered releases from the South Stack and therefore, does not require the Standby Gas Treatment System to be aligned to the refueling area.

However, when handling RECENTLY IRRADIATED FUEL or during operations with a potential for draining the reactor vessel with the vessel head removed and fuel in the vessel, secondary containment integrity of the refueling area is required and alignment of the Standby Gas Treatment System to the refueling area is required.

The AST fuel handling analysis does not include an accident involving RECENTLY IRRADIATED FUEL or an accident involving draining the reactor vessel.

The Standby Gas Treatment System is required to be OPERABLE when handling irradiated fuel, handling RECENTLY IRRADIATED FUEL and, during CORE ALTERATIONS and during operations with a potential to drain the vessel with the vessel head removed and fuel in the vessel. Fuel Handling Accident releases from the North Stack must be filtered through the Standby Gas Treatment System to maintain control room doses within regulatory limits. The OPERABILITY of the Standby Gas Treatment System assures that releases, if made through the North Stack, are filtered prior to release.

LIMERICK - UNIT 2 B 3/4 6-5 Amendment No. 34,51,86,146,147, ECR LG 09-00052

3/4.10 SPECIAL TEST EXCEPTIONS BASES 3/4.10.8 INSERVICE LEAK AND HYDROSTATIC TESTING This special test exception permits certain reactor coolant pressure tests to be performed in OPERATIONAL CONDITION 4 when the metallurgical characteristics of the reactor pressure vessel (RPV) or plant temperature control capabilities during these tests require the pressure testing at temperatures greater than 200°F and less than or equal to 212°F (normally corresponding to OPERATIONAL CONDITION 3). The additionally imposed OPERATIONAL CONDITION 3 requirements for SECONDARY CONTAINMENT INTEGRITY provide conservatism in response to an operational event.

Invoking the requirement for Refueling Area Secondary Containment Integrity along with the requirement for Reactor Enclosure Secondary Containment Integrity applies the requirements for Reactor Enclosure Secondary Containment Integrity to an extended area encompassing Zones 2 and 3. Operations with the Potential for Draining the Vessel, Core alterations, and fuel handling are prohibited in this secondary containment configuration. Drawdown and inleakage testing performed for the combined zone system alignment shall be considered adequate to demonstrate integrity of the combined zones.

Inservice hydrostatic testing and inservice leak pressure tests required by Section XI of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code are performed prior to the reactor going critical after a refueling outage. The minimum temperatures (at the required pressures) allowed for these tests are determined from the RPV pressure and temperature (P/T) limits required by LCO 3.4.6, Reactor Coolant System Pressure/Temperature Limits. These limits are conservatively based on the fracture toughness of the reactor vessel, taking into account anticipated vessel neutron fluence. With increased reactor fluence over time, the minimum allowable vessel temperature increases at a given pressure.

LIMERICK - UNIT 2 B 3/4 10-2 Amendment No. 95 ECR 99-00864, 130