Text

License Amendment Request 279, Extend Surveillance Test Intervals in Support of Transition to 24 Month Fuel Cycles
	ML25062A213
Person / Time
Site:	Turkey Point ; (DPR-031, DPR-041)
Issue date:	03/03/2025
From:	Mack K; Florida Power & Light Co
To:	; Office of Nuclear Reactor Regulation, Document Control Desk
References
	L-2025-020
	Download: ML25062A213 (1)
	v • d • e

l=PL..

U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington DC 20555-0001 RE:

Turkey Point Nuclear Generating Station, Unit 3 and 4 Docket Nos. 50-250 and 50-251 Renewed Facility Operating Licenses DPR-31 and DPR-41 March 3, 2025 L-2025-020 10 CFR 50.90 License Amendment Request 279, Extend Surveillance Test Intervals in Support of Transition to 24 Month Fuel Cycles

References:

1.

Florida Power & Light Company letter L-2023-078, License Amendment Request 278, Incorporate Advanced Fuel Products, Extend Surveillance Intervals and 10 CFR 50.46 Exemption Request to Facilitate Transition to 24-Month Fuel Cycles, November 15, 2023 (ADAMS Accession Nos. ML23320A028 and ML23320A029)

2.

Nuclear Regulatory Commission (NRC) Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," April 2, 1991, (ADAMS Accession No. ML031140501).

Pursuant to 10 CFR Part 50.90, Florida Power & Light Company (FPL) hereby requests amendments to Subsequent Renewed Facility Operating Licenses (SRFOLs) DPR-31 and DPR-41 for Turkey Point Nuclear Generating Station, Units 3 and 4 (Turkey Point), respectively. The proposed license amendments modify the Turkey Point Surveillance Frequency Control Program (SFCP) by extending Technical Specification (TS) Surveillance Requirement (SR) performance intervals from a 36-month frequency to a 48-month frequency, and from a 36-month staggered test basis (STB) frequency to a 48-month STB frequency, as applicable. The proposed change is necessary to facilitate a Turkey Point transition to 24-month fuel cycles.

In Reference 1, FPL requested SR interval extensions from 18-months to 24-months along with other proposed changes to the Turkey Point licensing basis in support of the 24-month fuel cycle transition. As in Reference 1, justifications supporting the requested 36-month and 36-month STB surveillance interval extensions are based on the regulatory guidance of Generic Letter 91-04 (Reference 2).

The enclosure to this letter provides FPL's evaluation of the proposed change. to the enclosure identifies the 36-month and 36-month STB SRs proposed for surveillance interval extensions. to the enclosure provides the supporting evaluations for the requested 36-month and 36-month STB surveillance interval extensions. Because the applicable SRs are subject to the SFCP, no changes are proposed to the Turkey Point TS or to the TS Bases. Only the surveillance frequencies specified in the SFCP listing of surveillance test intervals (STI) are affected by this amendment request.

FPL has determined that the proposed changes do not involve a significant hazards consideration pursuant to 10 CFR 50.92(c), and there are no significant environmental impacts associated with the proposed change. The Turkey Point Onsite Review Group has reviewed the proposed license amendments.

In accordance with 10 CFR 50.91 (b)(1 ), a copy of the proposed license amendments is being forwarded to the State designee for the State of Florida.

FPL requests that the proposed change is processed as a normal license amendment request with approval within one year of submittal. Once approved, the amendments shall be implemented on a forward fit basis by no later than the next Unit 3 and Unit 4 spring reload campaigns, respectively.

This letter contains no new or revised regulatory commitments.

Florida Power & Light Company 9760 SW 344th Street, Homestead, FL 33035

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 L-2025-020 Page 2 of 2 Should you have any questions regarding this submission, please contact Ms. Maribel Valdez, Fleet Licensing Manager, at 561-904-5164.

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

Executed on the 3rd day of March 2025.

Kenneth A Mack Director, Licensing and Regulatory Compliance Florida Power & Light Company cc:

USNRC Regional Administrator, Region II USNRC Project Manager, Turkey Point Nuclear Plant USNRC Senior Resident Inspector, Turkey Point Nuclear Plant Mr. Clark Eldredge, Florida Department of Health Enclosure (1)

Attachments (2)

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 Turkey Point Nuclear Plant Unit 3 and Unit 4 L-2025-020 Enclosure Page 1 of 8 License Amendment Request 279, Extend 36-Month Surveillance Interval Frequencies in Support of Transition to 24 Month Fuel Cycles 1.0

SUMMARY

DESCRIPTION............................................................................................................. 2 2.0 DETAILED DESCRIPTION.............................................................................................................. 2 2.1 Background......................................................................................................................... 2 2.2 Current Requirements/ Description of the Proposed Change........................................... 3 2.3 Reason for the Proposed Change...................................................................................... 3

3.0 TECHNICAL EVALUATION

............................................................................................................ 3 4.0 REGULA TORY EVALUATION....................................................................................................... 4 4.1 Applicable Regulatory Requirements/Criteria..................................................................... 4 4.2 Precedent............................................................................................................................ 5 4.3 No Significant Hazards Consideration................................................................................ 6 4.4 Conclusion.......................................................................................................................... 7 5.0 ENVIRONMENT AL CONSIDERATION.......................................................................................... 7

6.0 REFERENCES

................................................................................................................................. 7 ATTACHMENTS

1.

Surveillance Requirements (SRs) Proposed for Surveillance Interval Extensions

2.

Turkey Point Units 3 and 4 GL 91-04, Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 1.0

SUMMARY

DESCRIPTION L-2025-020 Enclosure Page 2 of 8 Florida Power & Light Company (FPL) requests amendments to Subsequent Renewed Facility Operating Licenses (SRFOLs) DPR-31 and DPR-41 for Turkey Point Nuclear Generating Station, Units 3 and 4 (Turkey Point), respectively. The proposed license amendments modify the Turkey Point Surveillance Frequency Control Program (SFCP) by extending Technical Specification (TS) Surveillance Requirement (SR) performance intervals from a 36-month frequency to a 48-month frequency, and from a 36-month staggered test basis (STB) frequency to a 48-month STB frequency, as applicable. The proposed change is necessary to facilitate a Turkey Point transition to 24-month fuel cycles. In Reference 6.1, FPL requested SR interval extensions from 18-months to 24-months along with other proposed changes to the Turkey Point licensing basis in support of the 24-month fuel cycle transition. As in Reference 6.1, justifications supporting the requested 36-month and 36-month STB surveillance interval extensions are based on the regulatory guidance of Generic Letter 91-04 (Reference 6.2).

2.0 DETAILED DESCRIPTION

2.1 Background

In Reference 6.3, as supplemented by Reference 6.4, Amendments 263 and 258 were issued revising the Turkey Point TS by relocating specific SR frequencies to the Turkey Point SFCP, a licensee-controlled program. The SFCP requires changes to the SR surveillance intervals be conducted in accordance with Nuclear Energy Institute (NEI) 04-10, "Risk-Informed Technical Specification Initiative Sb, Risk Informed Method for Control of Surveillance Frequencies" Reference 6.5). The changes are consistent with NRC-approved Technical Specification Task Force (TSTF) Standard Technical Specifications change TSTF-425, "Relocate Surveillance Frequencies to Licensee Control - Risk Informed Technical Specifications Task Force (RITSTF) Initiative 5b," Revision 3 (Reference 6.6). However, the rigorous, risk-informed evaluation that is required to support a surveillance interval extension in accordance with NEI 04-10 was not intended for SR extensions en-masse, such as would be encountered with a transition from 18-month to 24-month fuel cycles. SR extensions from 18 months to 24 months, and from 36 months to 48 months, are necessary to avoid mid-cycle shutdowns for the sole purpose of performing surveillances that cannot be performed on line without elevated risk. Using deterministic methods, Generic Letter (GL) 91-04 provides guidance for extending SR intervals from 18 months to 24 months for licensees transitioning to 24-month fuel cycles.

In this amendment request, the deterministic principles of GL 91-04 are similarly applied to extending SR intervals from 36-months to 48-months, and from 36-months on a staggered test basis (STB) to 48-months STB.

These TS SRs are subject to the administrative controls of the SFCP and their frequencies are documented in the Turkey Point SFCP Surveillance Test Interval (STI) listing. The subject surveillance frequencies are either every 36 months or every 36 months STB. SRs on a 36 month STB frequency are tested every 18 months such that both system trains (e.g., Train A and 8) are surveilled within 36 months.

In accordance with Turkey Point administrative procedure O-ADM-235, Technical Specification Surveillance Frequency Control Program, a Staggered Test Basis shall consist of:

A A test schedule for 'n' systems, subsystems, trains, or other designated components obtained by dividing the specified test interval into 'n' equal subintervals, and B. The testing of one system, subsystem, train, or other designated component at the beginning of each subinterval.

The procedure further defines 36 months on a staggered test basis as a "surveillance to be performed every 36 months. i.e. only 1 (A or B) train of applicable surveillance will be performed each refueling outage."

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 2.2 Current Requirements / Description of the Proposed Change L-2025-020 Enclosure Page 3 of 8 The Turkey Point TS specify the applicable SRs for this amendment request. The SR performance frequencies are identified in the Turkey Point SFCP as either on a 36-month or a 36-month STB frequency.

As indicated in the Attachment 1, the proposed change extends the performance frequencies of these SRs to either 48-months or 48-months STB, as appropriate. The table includes a listing of the associated equipment, system or instrumentation functional unit (FU) and the corresponding surveillance requirement.

The 'SR type' column aligns with the three surveillance type evaluations described in GL 91-04.

2.3 Reason for the Proposed Change The proposed change is necessary to facilitate a Turkey Point transition to 24-month fuel cycles, as described in Reference 6.1. Specifically, extending the existing 36-month and 36-month STB surveillance intervals is necessary to avoid mid-cycle shutdowns in order to complete TS surveillances that place the affected unit at an elevated risk if performed online. Extending these surveillance frequencies to align with 24-month fuel cycles would provide for orderly, uninterrupted operation throughout the intended fuel cycle.

3.0 TECHNICAL EVALUATION

GL 91-04 Evaluation Methods GL 91-04 (Reference 6.2) provides the NRC Staff's guidance on the types of information that must be addressed when proposing SR interval extensions from 18 to 24-months. The GL broadly categorizes the surveillances into the following 3 categories:

A Non-calibration SRs B. Calibration SRs without setpoints (no TS Allowable Values)

C. Calibration SRs with setpoints (TS Allowable Values)

As described above, this document identifies the 36-month and 36-month STB SRs where surveillance interval extensions to 48-months and 48-month STB, as applicable, are necessary to accommodate a proposed Turkey Point transition to 24 month fuel cycles. Of the requested surveillance extensions associated with this amendment request, none involve calibration SRs with setpoints, which were evaluated in the previous amendment request of Reference 6.1. Additionally, FPL recognizes that GL 91-04 does not explicitly address SR interval extensions beyond 24 months. However, the same evaluation process which supports the conclusion that the effect of the 18-month to 24-month SR extensions on plant safety is small can be applied to the 36 month and 36 month STB SR extension evaluations with the expectation that any safety impact would become evident as a result of the evaluation process. The GL-91-04 evaluations in this amendment request are consistent with precedents referenced in Section 4.2 of this amendment request for extending 36-month and 36-month STB SR intervals using the GL 91-04 regulatory guidance.

For the non-calibration SRs and the calibration SRs without setpoints having a surveillance test interval of 36 months and 36 month STB, GL-91-04 identifies three considerations that must be evaluated to support the conclusion that the effect of the SR extensions on plant safety is small, as indicated below:

Step 1.

Evaluate the effect on safety of the change in surveillance intervals to accommodate a 24-month fuel cycle. This evaluation should support the conclusion that the effect on safety is small.

Step 2.

Confirm that the historical maintenance and surveillance data does not invalidate this conclusion.

Step 3.

Confirm that the performance of surveillances at the bounding surveillance interval limit provided to accommodate a 24-month fuel cycle would not invalidate any assumption in the plant licensing basis.

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 L-2025-020 Enclosure Page 4 of 8 to this enclosure provides the detailed evaluations for each of the SRs identified in Attachment 1, as described in Section 2.2 of this amendment request, using the three-step process described above.

Applying the Turkey Point TS SR 3.0.2 allowance of a 25% extension to the surveillance interval, and with the proposed maximum SR interval extended from 36 to 48 months, and from 36-months STB to 48-months STB, the SR interval extensions were evaluated for up to 60 months and for 60 months STB. Each included a review of the associated component's function and features to determine the impact on safety with consideration for more frequent testing by other plant requirements, system/component redundancy and single failure tolerance, and overall system/component reliability. For each of the subject SRs, surveillance failure analyses were performed based on historical surveillance data and maintenance records over the previous 5 cycles to the extent possible. These analyses examined both performance and failure history, as well as potential common failures of similar components tested by different SRs to identify evidence of repetitive failures among similar plant components. Consistent the precedents identified in Sections 4.2 of this amendment request, excluded from the surveillance failures evaluations were failures that were not related to potential unavailability as a result of an SR extension. These exclusions included failures that did not impact TS operability, were detectable by more frequent testing requirements, or were attributed to certain other activities detailed in Attachment 2. Lastly, the Turkey Point licensing basis was reviewed, including the UFSAR-specified accident analyses, TS license conditions, and regulatory commitments, to confirm that the licensing basis assumptions associated with the Turkey Point nuclear units are not affected by the requested surveillance interval extensions. Applying the Turkey Point TS SR 3.0.2 allowance of a 25% extension of the surveillance interval, and with the proposed maximum SR interval extended from 36 to 48 months, and from 36-months STB to 48-months STB, the SR interval extensions were evaluated for up to 60 months and for 60 months STB. The results of the GL 91-04 evaluations for the requested 36-month and 36-month STB surveillance interval extensions support the conclusion that the effect on plant safety, if any, is small and the extensions would not invalidate any licensing basis assumptions. Moreover, the evaluations demonstrated that overall system reliability would be maintained.

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria

1.

Title 10 of the Code of Federal Regulations, Section 50.36(c)(3), "Surveillance requirements," states that surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met.

2.

10 CFR 50, Appendix A, GDC 17, Electric power systems, states in part, that an onsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety.

The onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure.

3.

10 CFR 50, Appendix A, GDC 18, Inspection and Testing of Electric Power Systems, states in part, that electric power systems that are important to safety must be designed to permit appropriate periodic inspection and testing.

4.

1 O CFR 50, Appendix A, GDC 19, Control Room, states in part, that a control room shall be provided from which actions can be taken to operate the nuclear power unit safely under normal conditions and to maintain it in a safe condition under accident conditions, including loss-of-coolant accidents.

Adequate radiation protection shall be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident.

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 L-2025-020 Enclosure Page 5 of 8 (Note: The General Design Criterion (GDC) used during the licensing of Turkey Point were based on the 1967 Atomic Energy Commission Proposed General Design Criterion (1967 Proposed GDC) as published in Federal Register 32 FR 10213 and predate 10 CFR Part 50, Appendix A)

5.

1967 Proposed GDC 19, Protection System Reliability, states that protection system shall be designed for high functional reliability and in-service testability necessary to avoid undue risk to the health and safety of the public ('67 GDC 19 and 20)

6.

1967 Proposed GDC 20, Protection Systems Redundancy and Independence, states that redundancy and independence designed into protection systems shall be sufficient to assure that no single failure on removal from service of any component or channel of such a system will result in loss of the protection function. The redundancy provided shall include, as a minimum, two channels of protection for each protection function to be served.

7.

1967 Proposed GDC 46, Testing of Emergency Core Cooling System Components, states that '

Design provisions shall be made so that components of the Emergency Core Cooling System can be tested periodically for operability and functional performance.

8.

1967 Proposed GDC 47, Testing of Emergency Core Cooling System, states that capability shall be provided to test periodically the operability of the Emergency Core Cooling System up to a location as close to the core as is practical.

9.

1967 Proposed GDC 59, Testing of Containment Pressure-Reducing Systems Components, states that the containment pressure-reducing systems shall be designed to the extent practical so that components, such as pumps and valves, can be tested periodically for operability and required functional performance.

10.

1967 Proposed GDC 60, Testing of Containment Spray Systems, states that a capability shall be provided to the extent practical to test periodically the delivery capability of the containment spray system at a position as close to the spray nozzles as is practical.

The proposed license amendments comply with the requirements of 10 CFR 50.36(c)(3), GDCs 17, 18, and 19 of 10 CFR 50, Appendix A, and 1967 Proposed GDCs 19, 20, 46, 47, 59 and 60, consistent with the applicable regulatory requirements and the Turkey Point current licensing basis. All requirements will continue to be satisfied as a result of the proposed change.

4.2 Precedent In Reference 6.7, the NRC issued Amendment 218 to the Fermi 2 Nuclear Operations Facility which increased increase certain surveillance requirement intervals from 18 months to 24 months to accommodate a 24-month fuel cycle based. Similar to this amendment request, the amendment was based, in part, on the satisfactory application of the GL 91-04 principles to the non-calibration and calibration without setpoint surveillance requirements.

In Reference 6.8, the NRC issued Amendments 239 and 227 for Prairie Island Nuclear Generating Plant, Units 1 and 2, respectively, which increased certain surveillance requirement intervals up to 30 months to accommodate a 24-month fuel cycle based. Similar to this amendment request, the amendment was based, in part, on the satisfactory application of the GL 91-04 principles to the non-calibration and calibration without setpoint surveillance requirements.

In Reference 6.9, PSEG, LLC, requested for the Hope Creek Generating Station, a license amendment extending selected TS SR performance intervals based on the regulatory principles of GL 91.04 in support of their transition to 24 month fuel cycles. Included within was a proposed extension of a SR interval from 36-months to 48-months. Though the PSEG application was currently

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 L-2025-020 Enclosure Page 6 of 8 under NRC review at the time of this amendment request, the application of GL 91-04 to 36-month to 48-month surveillance extensions was not challenged in the NRC staffs RAls of Reference 6.10.

4.3 No Significant Hazards Consideration Florida Power & Light Company (FPL) requests amendments to Subsequent Renewed Facility Operating Licenses (SRFOLs) DPR-31 and DPR-41 for Turkey Point Nuclear Generating Station, Units 3 and 4 (Turkey Point), respectively. The proposed license amendments modify the Turkey Point Surveillance Frequency Control Program (SFCP) by extending Technical Specification (TS) Surveillance Requirement (SR) performance intervals from a 36-month frequency to a 48-month frequency, and from a 36-month on a staggered test basis (STB) frequency to a 48-month STB frequency, as applicable. The proposed change is necessary to facilitate a Turkey Point transition to 24-month fuel cycles. In Reference 1, FPL requested SR interval extensions from 18-months to 24-months along with other proposed changes to the Turkey Point licensing basis in support of the 24-month fuel cycle transition. As in Reference 6.1, justifications supporting the requested 36-month and 36-month STB surveillance interval extensions are based on the regulatory guidance of Generic Letter 91-04 (Reference 6.2).

As required by 10 CFR 50.91(a), FPL has evaluated the proposed change using the criteria in 10 CFR 50.92 and has determined that the proposed change does not involve a significant hazards consideration.

An analysis of the issue of no significant hazards consideration is presented below:

(1)

Do the proposed amendments involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No The proposed change involves a change in the surveillance test intervals specified in the Turkey Point Surveillance Frequency Control Program (SFCP) to facilitate a Turkey Point transition to 24 month fuel cycles. The proposed change to the surveillance test intervals do not physically impact the physical plant, or degrade the performance of, or increase the challenges to, any safety systems credited in the plant safety analyses. The proposed TS changes do not impact the surveillance requirements in evaluating the operability of required systems and components, or the way in which the surveillances are performed, and the frequency of surveillance testing is not an event initiator of any analyzed accident. Moreover, evaluation of the proposed change, including the historical testing and failure history of the affected surveillances demonstrate that the reliability of the equipment and the availability of redundant systems and equipment will be maintained.

Therefore, the proposed amendment does not involve a significant increase in the probability or consequences of an accident previously evaluated.

(2)

Do the proposed amendments create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No The proposed change involves a change in the surveillance test intervals specified in the Turkey Point SFCP to facilitate a Turkey Point transition to 24 month fuel cycles. No physical, operational or design changes are associated with the proposed change. Thereby, no new or modified event initiators can result, and new or modified failure modes can be introduced as a result of the proposed change. The existing surveillances will continue to be performed in a manner which assures the necessary quality of systems and components is maintained, facility operation will be within safety limits, and the limiting conditions for operation will be met.

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

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 (3)

Do the proposed amendments involve a significant reduction in a margin of safety?

Response: No L-2025-020 Enclosure Page 7 of 8 The proposed change involves a change in the surveillance test intervals specified in the Turkey Point SFCP to facilitate a Turkey Point transition to 24 month fuel cycles. The proposed change does not alter the approach to any safety limits, limiting safety system settings, or safety analysis assumptions or inputs, and thereby cannot affect plant operating margins. The proposed change does not modify the design and capability of equipment credited in safety analyses, or introduce new energy sources, and thereby cannot affect the integrity of any radiological barrier.

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

Based upon the above analysis, FPL concludes that the proposed license amendment does not involve a significant hazards consideration, under the standards set forth in 1 O CFR 50.92, "Issuance of Amendment,"

and accordingly, a finding of "no significant hazards consideration" is justified.

4.4 Conclusion Based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

Florida Power & Light Company (FPL) has evaluated the proposed amendments for environmental considerations and determined that the proposed amendments 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, or would change an inspection or surveillance requirement. However, the proposed amendments do not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendments meet the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 1 O CFR 51.22(b),

no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendments.

6.0 REFERENCES

6.1 Florida Power & Light Company letter L-2023-078, License Amendment Request 278, Incorporate Advanced Fuel Products, Extend Surveillance Intervals and 10 CFR 50.46 Exemption Request to Facilitate Transition to 24-Month Fuel Cycles, November 15, 2023 (ADAMS Accession No.

ML23320A028, ML23320A029) 6.2 Nuclear Regulatory Commission Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," April 2, 1991, (ADAMS Accession No. ML031140501).

6.3 U.S. Nuclear Regulatory Commission to Florida Power & Light Company, Turkey Point Nuclear Generating Unit Nos: 3 and 4 - Issuance of Amendments Regarding Risk-Informed Justifications for the Relocation of Specific Surveillance Frequency Requirements to a Licensee-Controlled Program (TAC NOS. MF3931 AND MF3932), July 16, 2015 (ADAMS Accession No. ML15166A320)

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 L-2025-020 Enclosure Page 8 of 8 6.4 U.S. Nuclear Regulatory Commission to Florida Power & Light Company, Turkey Point Nuclear Generating Unit Nos: 3 and 4 - Corrections to Amendments Nos. 263 and 258 (TAC Nos. Mf6560 and MF6561), August 28, 2015 (ADAMS Accession No. ML15225A305) 6.5 Nuclear Energy Institute (NEI) 04-10, Revision 1, "Risk-Informed Method for Control of Surveillance Frequencies," April 2007 (ADAMS Accession No. ML071360456) 6.6 Technical Specification Task Force (TSTF)-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5b," March 18, 2009 (ADAMS Accession No. ML090850642)

6. 7 US Nuclear Regulatory Commission to DTE Electric Company, FERMI 2 - Issuance of Amendment No. 218 -

Revision to Technical Specifications to Change Certain Surveillance Intervals to Accommodate a 24-Month Fuel Cycle (EPID L-2019-LLA-0249), February 24, 2021 (ADAM Accession No. M L20358A 155) 6.8 US Nuclear Regulatory Commission to Northern States Power Company - Minnesota, Prairie Island Nuclear Generating Plant, Units 1 and 2 - Issuance of Amendments 239 and 227 RE: 24-Month Operating Cycle (EPID L-2021-LLA-0146), July 28, 2022 (ADAMS Accession No. ML22166A389) 6.9 PSEG Nuclear, LLC letter to US Nuclear Regulatory Commission, License Amendment Request -

Revise Hope Creek Generating Station Technical Specification to Change Surveillance Intervals to Accommodate a 24-Month Fuel Cycle, May 20, 2024 (ADAMS Accession No. ML24141A136) 6.1 O US Nuclear Regulatory Commission electronic memorandum to PSEG, "Hope Creek - Final EEEB RAI regarding Amendment to Revise TS to Change Surveillance Interval to Accommodate 24-Month Fuel Cycle (EPID: L-2024-LLA-0065)," September 9, 2024 (ADAMS Accession No. ML24253A194)

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 Surveillance Requirements (SRs) Proposed for Surveillance Interval Extensions SR#

Equipment System /

Surveillance Requirement SR Type Instrument Functional Unit (FU)

SR Table 3.3.1-1, FU-1 Perform Trip Actuating Device Operational Test (TADOT)

Non-3.3.1.12 Manual Rx Trip Calibration SR Table3.3.1-1, FU-16 Perform T ADOT Non-3.3.1.12 SI on ESF Calibration SR Table3.3.1-1, FU-18a Perform T ADOT Non-3.3.1.12 RCP Breaker Position - Single Loop Calibration SR Table 3.3.1-1, FU-18b Perform T ADOT Non-3.3.1.12 RCP Breaker Position - Two Loops Calibration SR Table 3.3.2-1, FU-5a Non-3.3.2.2 Feedwater Isolation, Automatic Perform Actuation Logic Test Calibration Actuation Logic and Relays SR Table 3.3.2-1, FU-6a Non-3.3.2.2 Auxiliary Feedwater, Automatic Perform Actuation Logic Test Calibration Actuation Logic and Relays TS Table 3.3.2-1, FU-2b SR Containment Spray, Containment Perform T ADOT Non-3.3.2.4 Pressure - High, High; Coincident Calibration with Containment Pressure - High TS Table 3.3.2-1, FU-3b3 SR Containment Isolation, Containment Perform T ADOT Non-3.3.2.4 Pressure - High, High; Coincident Calibration with Containment Pressure - High TS Table 3.3.2-1, FU-4c SR Steam Line Isolation, Containment Perform T ADOT Non-3.3.2.4 Pressure - High, High; Coincident Calibration with Containment Pressure - High Current SR Frequency 36 months STB*

36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB L-2025-020 Page 1 of 7 Proposed SR Frequency 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 Surveillance Requirements (SRs) Proposed for Surveillance Interval Extensions SR#

Equipment System /

Surveillance Requirement SR Type Instrument Functional Unit (FU)

SR TS Table 3.3.2-1, FU-6d Perform T ADOT Non-3.3.2.4 Auxiliary Feedwater, Bus Stripping Calibration SR TS Table 3.3.2-1, FU-6e Non-3.3.2.4 Auxiliary Feedwater, Trip of all MFP Perform T ADOT Calibration Breakers SR TS Table 3.3.2-1, FU-1a Perform T ADOT Non-3.3.2.5 Safety Injection, Manual Initiation Calibration SR TS Table 3.3.2-1, FU-3a(1)

Non-3.3.2.5 Containment Isolation, Phase A Perform T ADOT Calibration Isolation, Manual Initiation SR TS Table 3.3.2-1, FU-3b(1)

Non-3.3.2.5 Containment Isolation, Phase B Perform T ADOT Calibration Isolation, Manual Initiation SR TS Table 3.3.2-1, FU-4a Non-3.3.2.5 Steam Line Isolation, Manual Perform T ADOT Calibration Initiation SR Table 3.3.5-1, FU-1 a Non-3.3.5.2

4. 16 kV Busses A and B (Loss of Perform T ADOT Calibration Voltage) Bus Undervoltage SR Table 3.3.5-1, FU-2a Calibration 3.3.5.3 480V Load Centers (Undervoltage),

Perform Channel Calibration w/o Bus Undervoltage setpoints SR Table 3.3.5-1, FU-2b Calibration 3.3.5.3 480V Load Centers (Undervoltage),

Perform Channel Calibration w/o Time Delay setpoints SR Table 3.3.5-1, FU-3a Calibration 3.3.5.3 480V Load Centers (Degraded Perform Channel Calibration w/o Voltage), Bus Undervoltage setpoints SR Table 3.3.5-1, FU-3b Calibration 3.3.5.3 480V Load Centers (Degraded Perform Channel Calibration w/o Voltage), Time Delay setpoints Current SR Frequency 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months 36 months 36 months 36 months L-2025-020 Page 2 of 7 Proposed SR Frequency 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months 48 months 48 months 48 months

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 Surveillance Requirements (SRs) Proposed for Surveillance Interval Extensions SR#

Equipment System /

Surveillance Requirement SR Type Instrument Functional Unit (FU)

Verify each ECCS automatic valve in the flow path that is SR ECCS - Operating not locked, sealed, or otherwise secured in position, Non-3.5.2.5 actuates to the correct position on an actual or simulated Calibration actuation signal.

SR ECCS - Operating Verify each ECCS pump starts automatically on an actual Non-3.5.2.6 or simulated actuation signal.

Calibration Verify each automatic containment isolation valve that is SR Containment Isolation Valves not locked, sealed or otherwise secured in position, Non-3.6.3.6 actuates to the isolation position on an actual or simulated Calibration actuation signal Verify each automatic containment spray valve in the flow SR Containment Spray and Cooling path that is not locked, sealed, or otherwise secured in Non-3.6.6.6 Systems position, actuates to the correct position on an actual or Calibration simulated actuation signal.

SR Containment Spray and Cooling Verify each containment spray pump starts automatically Non-3.6.6.7 Systems on an actual or simulated actuation signal.

Calibration SR Containment Spray and Cooling Verify each emergency containment cooling unit starts Non-3.6.6.8 Systems automatically on an actual or simulated actuation signal Calibration SR Feedwater Isolation Valves (FIVs)

Verify each FIV, FCV, and associated bypass valves Non-3.7.3.2 Feedwater Control Valves (FCVs) actuates to the isolation position on an actual or simulated Calibration and Associated Bypass Valves actuation signal.

Verify each CCW automatic valve in the flow path that is SR Component Cooling Water System not locked, sealed, or otherwise secured in position, Non-3.7.7.2 actuates to the correct position on an actual or simulated Calibration actuation signal.

SR Component Cooling Water System Verify each CCW pump starts automatically on an actual Non-3.7.7.3 or simulated actuation signal.

Calibration Current SR Frequency 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB L-2025-020 Page 3 of 7 Proposed SR Frequency 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 SuNeillance Requirements (SRs) Proposed for SuNeillance lnteNal Extensions SR#

Equipment System /

Surveillance Requirement SR Type Instrument Functional Unit (FU)

Verify each ICW automatic valve in the flow path that is SR Intake Cooling Water System not locked, sealed, or otherwise secured in position, Non-3.7.8.2 actuates to the correct position on an actual or simulated Calibration actuation signal.

SR Intake Cooling Water System Verify each ICW pump starts automatically on an actual or Non-3.7.8.3 simulated actuation signal.

Calibration Verify each CREVS train actuates on an actual or SR Control Room Emergency simulated actuation signal, except for dampers and valves Non-3.7.10.3 Ventilation System that are locked, sealed, or otherwise secured in the Calibration actuated position.

Verify each EOG rejects a load greater than or equal to its associated single largest post-accident load, and:

SR

a. Following load rejection, the frequency is :5 66.25 Hz, Non-3.8.1.9 AC Sources - Operating

b. Within 2 seconds following load rejection, the voltage Calibration is ~ 3950 V and :;; 4350 V, and

c. Within 2 seconds following load rejection, the frequency is ~ 59.4 Hz and :5 60.6 Hz.

SR Verify each EOG does not trip and voltage returns to :5 Non-3.8.1.10 AC Sources - Operating 4784 V within 2 seconds following a load rejection of Calibration

~ 2500 kW (Unit 3), ~ 2874 kW (Unit 4).

Current SR Frequency 36 months STB 36 months STB 36 months STB 36 months STB 36 months STB L-2025-020 Page 4 of 7 Proposed SR Frequency 48 months STB 48 months STB 48 months STB 48 months STB 48 months STB

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 Surveillance Requirements (SRs) Proposed for Surveillance Interval Extensions SR#

Equipment System /

Surveillance Requirement SR Type Instrument Functional Unit (FU)

Verify on an actual or simulated loss of offsite power signal:

a. De-energization of emergency buses,

b. Load shedding from emergency buses,

c. EDG auto-starts from standby condition and:

1. Energizes permanently connected loads in :;; 15 SR

seconds, Non-3.8.1.11 AC Sources - Operating

2. Energizes auto-connected shutdown loads through Calibration automatic load sequencer,

3. Maintains steady state voltage

3950 V and

;; 4350 V,

4. Maintains steady state frequency ;;:: 59.4 Hz and :;;

60.6 Hz, and

5. Supplies permanently connected and auto-connected shutdown loads for;;:: 5 minutes.

Verify on an actual or simulated Engineered Safety Feature (ESF) actuation signal each EDG autostarts from standby condition and:

a. In:;; 15 seconds after auto-start and during tests, achieves voltage ;;:: 3950 V and frequency ;;:: 59.4 Hz, SR

b. Achieves steady state voltage ;;:: 3950 V and :;; 4350 V Non-3.8.1.12 AC Sources - Operating and frequency ;;:: 59.4 Hz and :;; 60.6 Hz, Calibration

c. Operates for;;:: 5 minutes,

d. Permanently connected loads remain energized from the offsite power system, and

e. Emergency loads are energized or autoconnected through the automatic load sequencer from the offsite power system.

Verify EDG trips made OPERABLE during the test mode SR AC Sources - Operating of EDG operation are inoperable on actual or simulated Non-3.8.1.13 loss of voltage signal on the emergency bus concurrent Calibration with an actual or simulated ESF actuation signal.

Current SR Frequency 36 months STB 36 months STB 36 months STB L-2025-020 Page 5 of 7 Proposed SR Frequency 48 months STB 48 months STB 48 months STB

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 Surveillance Requirements (SRs) Proposed for Surveillance Interval Extensions SR#

Equipment System /

Surveillance Requirement SR Type Instrument Functional Unit (FU)

Verify each EOG:

a. Synchronizes with offsite power source while loaded SR AC Sources - Operating with emergency loads upon a simulated restoration of Non-3.8.1.16 offsite power, Calibration

b. Transfers loads to offsite power source, and

c. Returns to ready-to-load operation.

Verify, with a EOG operating in test mode and connected to its bus, an actual or simulated ESF actuation signal SR AC Sources - Operating overrides the test mode by:

Non-3.8.1.17

a. Returning EOG to ready-to-load operation and Calibration

b. Automatically energizing the emergency load from offsite power.

SR Verify interval between each sequenced load block is Non-3.8.1.18 AC Sources - Operating within +/- 10% of design interval for each emergency load Calibration sequencer.

Verify on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ESF actuation signal:

a. De-energization of emergency buses,

b. Load shedding from emergency buses, and

c. EOG auto-starts from standby condition and:

1. Energizes permanently connected loads in s; 15 SR AC Sources - Operating

seconds, Non-3.8.1.19

2. Energizes auto-connected emergency loads Calibration through load sequencer,

3. Achieves steady state voltage

3950 V ands; 4350 V,

4. Achieves steady state frequency

59.4 Hz and s; 60.6 Hz, and

5. Supplies permanently connected and autoconnected emergency loads for:::: 5 minutes.

Current SR Frequency 36 months STB 36 months STB 36 months STB 36 months STB L-2025-020 Page 6 of 7 Proposed SR Frequency 48 months STB 48 months STB 48 months STB 48 months STB

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 Surveillance Requirements (SRs) Proposed for Surveillance Interval Extensions SR#

Equipment System /

Surveillance Requirement SR Type Instrument Functional Unit (FU)

Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation with SR Control Room Envelope (CRE) one CREVS train operating at the flow rate required by Non-5.5.15.d Habitability Program the VFTP, at a Frequency in accordance with the Calibration Surveillance Frequency Control Program. The results shall be trended and used as part of the assessment of the CRE boundary.

Current SR Frequency 36 months STB L-2025-020 Page 7 of 7 Proposed SR Frequency 48 months STB

Turkey Point Nuclear Plant Docket Nos. 50-250 and 50-251 Westinghouse Non-Proprietary Class 3 Generic Letter (GL) 91-04 L-2025-020 Non-Calibration and Calibration Without Setpoints Surveillance Failure Analyses In Support of 36 Month and 36 Month (Staggered Test Basis) Extensions (35 pages follow)

1.

Westinghouse Non-Proprietary Class 3 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis BACKGROUND Next Era plans to transition Turkey Point units 3 and 4 from the current 18-month operating cycle to a 24 Month Fuel Cycle (24 MFC). Technical Specification (TS) Surveillance Requirement (SR) interval changes are required to accommodate a 24 MFC for Turkey Point 3 and 4. The proposed TS SR interval changes were evaluated in accordance with the guidance provided in Nuclear Regulatory Commission (NRC) Generic Letter (GL) 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991. GL 91-04 provides the NRC Staff guidance that identifies the types of information that must be addressed when proposing extension of a SR interval from 18 to 24 months.

This document identifies the 36 month and 36 month (staggered test basis) Non-Calibration and Calibration Without Setpoints SRs where frequency changes are necessary to accommodate a proposed 24 MFC.

Performance data and failure history associated with the affected TS SRs has been evaluated. The evaluations support the conclusion that the effect of the proposed changes on plant safety, reliability and availability of the systems, components, and functions, if any, is small.

Turkey Point 3 and 4 historical SR performance data and associated maintenance records were reviewed to evaluate the effect of these changes on safety. The Surveillance Failure Analysis (SFA) presented in this document addresses Non-Calibration and Calibration Without Setpoints SRs. These evaluations and results are described below.

The SFA identified no SR failures that would call into question the acceptability of the proposed extension of SR intervals.

In addition, a review of the Turkey Point 3 and 4 licensing basis (UFSAR and commitments) confirmed that plant-licensing basis assumptions are not affected by the proposed SR interval changes.

(Reference FPLM-TSPS-TM-L9-000001.)

In summary, these reviews support the conclusion that the effect on plant safety associated with the proposed SR interval extension from 36 months to 48 months or 36 months (staggered test basis) to 48 months (staggered test basis), if any, is small.

Westinghouse Non-Proprietary Class 3 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis

2.

EVALUATION This submittal discusses each step outlined by the NRC in GL 91-04 and provides a description of the methodology used to complete the evaluation for each applicable Non-Calibration and Calibration Without Setpoints SR.

Ideally, approximately eight years of performance data was obtained for each Non-Calibration and Calibration Without Setpoints SR proposed for extension to 48 months. This provides sufficient data to identify repetitive issues.

Surveillance Failure Analysis Surveillance Failure Analysis presented in Section A of this document includes Non-Calibration SR interval changes associated with:

TRIP ACTUATING DEVICE OPERATIONAL TEST (TADOT),

ACTUATION LOGIC TEST, and Other specific surveillance requirements.

Surveillance Failure Analysis presented in Section B of this document includes Calibration Without Setpoints SR interval changes associated with:

TS 3.3.5 Loss of Power (LOP) Emergency Diesel Generator (EDG) Start Instrumentation CHANNEL CALIBRATIONS The SFA is concerned with failures that could result in the loss of the associated safety function during the operating cycle that would only be detected by the performance of the 36 month or 36 month (staggered test basis) SR, and whether the proposed increase in the SR interval might result in a decrease in availability of the associated function. Additionally, the SFA reviews potential common failures of similar components tested by different SRs. This additional evaluation determines whether there is evidence of repetitive failures among similar plant components.

The SR failures described in this enclosure exclude failures that:

a.

Did not impact a TS safety function or TS operability;

b. Are detectable by required testing performed more frequently than the 18-month SR being extended; or

c. The cause can be attributed to an associated event such as a preventative maintenance task, human error, previous modification, or previously existing design deficiency; or that were subsequently re-performed successfully with no intervening corrective maintenance (e.g., plant conditions or malfunctioning measurement and test equipment may have caused aborting the test performance).

These types of failures are not related to potential unavailability of the associated function due to testing interval extension and are therefore not listed or further evaluated in this submittal.

The following sections summarize the results of the Non-Calibration and Calibration Without Setpoints SR failure analysis evaluations. The evaluations confirm that the impact on availability of the associated function due to extending the SR intervals to 48 months or 48 months (staggered test basis), if any, is small.

Westinghouse Non-Proprietary Class 3 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis A.

Non-Calibration SR Changes For the non-calibration 36-month or 36-month (staggered test basis) surveillances, GL 91-04 requires the following information to support conversion to a 48-month or 48-month (staggered test basis) surveillance interval:

1)

Licensees should evaluate the effect on safety of an increase in 36-month or36-month (staggered test basis) surveillance interva Is to accommodate a 24-month fuel cycle. This evaluation should support a conclusion that the effect on safety is small.

2)

Licensees should confirm that historical plant maintenance and surveillance support this conclusion.

3)

Licensees should confirm that the assumptions in the plant licensing basis would not be invalidated as a result of performing any surveillance at the bounding surveillance interval limit provided to accommodate a 24-month fuel cycle.

GL 91-04 states that licensees need not quantify the effect of the change in surveillance intervals on the availability of individual systems or components.

The proposed changes increase the SR interval from 36 to 48 months (a maximum of 60 months including the 25% extension afforded by TS SR 3.0.2 where applicable) for the non-calibration SRs discussed below.

The evaluations provided for each of these changes, support the conclusion that:

the effect of these changes on plant safety, if any is small; that the impact, if any, on system availability is minimal, and that the changes do not invalidate any assumption in the plant licensing basis.

The SFA review of Turkey Point 3 and 4 SR performance history that supports this conclusion is summarized for each SR discussed below.

TS 3.3.1 SR 3.3.1.12 Westinghouse Non-Proprietary Class 3 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Reactor Trip System (RTS) Instrumentation Perform TRIP ACTUATING DEVICE OPERATIONAL TEST (TADOT)-

(NOTE: Verification of setpoint is not required)

Table 3.3.1-1 Function 1 Manual Reactor Trip The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The Manual Reactor Trip ensures that the control room operator can initiate a reactor trip at any time by using either of two reactor trip switches in the control room. A Manual Reactor Trip accomplishes the same results as any one of the automatic trip Functions. It is used by the reactor operator to shut down the reactor whenever any parameter is rapidly trending toward its Trip Setpoint.

The manual actuating devices are independent of the automatic trip circuitry and are not subject to failures which make the automatic circuitry inoperable.

This surveillance is the performance of a TADOT of the Manual Reactor Trip. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

The test shall independently verify the OPERABILITY of the undervoltage and shunt trip mechanisms for the Manual Reactor Trip Function for the Reactor Trip Breakers and Reactor Trip Bypass Breakers.

The SR is modified by a Note that excludes verification of setpoints from the TADOT. The Functions affected have no setpoints associated with them.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.3.1 SR 3.3.1.12 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Reactor Trip System (RTS) Instrumentation Perform TRIP ACTUATING DEVICE OPERATIONAL TEST (TADOT) -

(NOTE: Verification of setpoint is not required)

Table 3.3.1-1 Function 16 Safety Injection (SI) Input from Engineered Safety Feature Actuation The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The SI Input from ES FAS ensures that if a reactor trip has not already been generated by the RTS, the ESFAS automatic actuation logic will initiate a reactor trip upon any signal that initiates SI. This is a condition of acceptability for the LOCA. However, other transients and accidents take credit for varying levels of ESF performance and rely upon rod insertion, except for the most reactive rod that is assumed to be fully withdrawn, to ensure reactor shutdown. Therefore, a reactor trip is initiated every time an SI signal is present.

Trip Setpoint and Allowable Values are not applicable to this Function. The SI Input is provided by relay in the ESFAS. Therefore, there is no measurement signal with which to associate an LSSS.

This surveillance is the performance of a TADOT of the SI Input from ESFAS. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

The SR is modified by a Note that excludes verification of setpoints from the TADOT. The Functions affected have no setpoints associated with them.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.3.1 SR 3.3.1.12 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Reactor Trip System (RTS) Instrumentation Perform TRIP ACTUATING DEVICE OPERATIONAL TEST (TADOT) -

(NOTE: Verification of setpoint is not required)

Table 3.3.1-1 Function 18 Reactor Coolant Pump (RCP) Breaker Position

a. Single Loop

b. Two Loops The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis)i for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

Both RCP Breaker Position trip Functions operate together on two sets of auxiliary contacts, with one set on each RCP breaker. These Functions anticipate the Reactor Coolant Flow - Low trips to avoid RCS heatup that would occur before the low flow trip actuates.

The RCP Breaker Position (Single Loop) trip Function ensures that protection is provided against violating the DNBR limit due to a loss of flow in one RCS loop. The position of each RCP breaker is monitored. If one RCP breaker is open above the P-8 setpoint, a reactor trip is initiated. This trip Function will generate a reactor trip before the Reactor Coolant Flow - Low (Single Loop) Trip Setpoint is reached.

The RCP Breaker Position (Two Loops) trip Function ensures that protection is provided against violating the DNBR limit due to a loss of flow in two or more RCS loops. The position of each RCP breaker is monitored. Above the P-7 setpoint and below the P-8 setpoint, a loss of flow in two or more loops will initiate a reactor trip. This trip Function will generate a reactor trip before the Reactor Coolant Flow - Low (Two Loops) Trip Setpoint is reached.

This Function measures only the discrete position (open or closed) of the RCP breaker, using a position switch. Therefore, the Function has no adjustable trip setpoint with which to associate an LSSS.

This surveillance is the performance of a TADOT of the RCP Breaker Position. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

The SR is modified by a Note that excludes verification of setpoints from the TADOT. The Functions affected have no setpoints associated with them.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.3.2 SR 3.3.2.2 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Engineered Safety Features Actuation System (ESFAS) Instrumentation Perform ACTUATION LOGIC TEST-Table 3.3.2-1 Functions:

5.a: Feedwater Isolation - Automatic Actuation Logic and Actuation Relays 6.a: Auxiliary Feedwater - Automatic Actuation Logic and Actuation Relays The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The primary functions of the Feedwater Isolation signals are to prevent damage to the turbine due to water in the steam lines, and to stop the excessive flow of feedwater into the SGs. These Functions are necessary to mitigate the effects of a high water level in the SGs, which could result in carryover of water into the steam lines and excessive cool down of the primary system.

Feedwater Isolation is actuated by a Safety Injection signal or when the level in any SG exceeds the high high setpoint, and performs the following functions:

Trips the main turbine, Trips the MFW pumps, Initiates feedwater isolation, and Shuts the MFW regulating valves and the bypass feedwater regulating valves.

The Auxiliary Feedwater (AFW) System is designed to provide a secondary side heat sink for the reactor in the event that the MFW System is not available. The system has three turbine driven pumps, making them available during normal unit operation, during a loss of AC power, a loss of MFW, and during a Feedwater System pipe break. The normal source of water for the AFW System is the condensate storage tank (CST). The AFW System is aligned so that upon a pump start, flow is initiated to the respective SGs immediately.

All AFW pumps automatically start from any of the following signals:

SG Low-Low Level, Safety Injection signal, Loss of Off site Power - Service Bus Low Voltage, Trip of All Main Feedwater Pump Breakers This surveillance is the performance of an ACTUATION LOGIC TEST using the semiautomatic tester.

The train being tested is placed in the bypass condition, thus preventing inadvertent actuation.

Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. In addition, the master relay coil is pulse tested for continuity. This verifies that the logic modules are OPERABLE and that there is an intact voltage signal path to the master relay coils.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.3.2 SR 3.3.2.4 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Engineered Safety Features Actuation System (ESFAS) Instrumentation Perform TRIP ACTUATING DEVICE OPERATIONAL TEST (TADOT} -

{NOTE: Verification of setpoint is not required)

Table 3.3.2-1 Functions:

2.b: Containment Spray-Containment Pressure -High High Coincident with Containment Pressure - High 3.b.3: Containment Isolation - PHASE B: Containment Pressure -High High Coincident with Containment Pressure - High 4.c: Steam Line Isolation - Containment Pressure -High High Coincident with Containment Pressure - High 6.d: Auxiliary Feedwater - Bus Stripping 6.e : Auxiliary Feedwater - Trip of All Main Feedwater Pump Breakers The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

Containment Spray provides protection against a LOCA or a SLB inside containment.

Containment Isolation provides isolation of the containment atmosphere, and all process systems that penetrate containment, from the environment. This Function is necessary to prevent or limit the release of radioactivity to the environment in the event of a large break LOCA.

Steam Line Isolation provides protection in the event of a SLB inside or outside containment. Rapid isolation of the steam lines will limit the steam break accident to the blowdown from one SG, at most.

Auxiliary Feedwater is designed to provide a secondary side heat sink for the reactor in the event that the MFW System is not available. The system has three turbine driven pumps, making them available during normal unit operation, during a loss of AC power, a loss of MFW, and during a Feedwater System pipe break This surveillance is a TADOT. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

The SR is modified by a Note that excludes verification of setpoints for relays. Relay setpoints require elaborate bench calibration and are verified during CHANNEL CALIBRATION.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.3.2 SR 3.3.2.5 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Engineered Safety Features Actuation System (ESFAS) Instrumentation Perform TRIP ACTUATING DEVICE OPERATIONAL TEST {TADOT}-

{NOTE: Verification of setpoint not required for manual initiation functions.)

Table 3.3.2-1 Function:

4.a Steam Line Isolation - Manual Initiation The SR interval for this SR is being increased from 36 months {staggered test basis) to 48 months {staggered test basis}, for a maximum interval of 60 months {staggered test basis}, including the 25% extension afforded by TS SR 3.0.2.

Isolation of the main steam lines provides protection in the event of a SLB inside or outside containment. Rapid isolation of the steam lines will limit the steam break accident to the blowdown from one SG, at most.

Manual initiation of Steam Line Isolation can be accomplished from the control room. There are three pushbuttons in the control room and each pushbutton initiates action to immediately close its associated MSIV.

This surveillance is a check of the Steam Line Isolation Manual Actuation Functions. Each Manual Actuation Function is tested up to, and including, the master relay coils. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.).

The SR is modified by a Note that excludes verification of setpoints during the TADOT for Manual Initiation Functions. The manual initiation Functions have no associated setpoints.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.3.2 SR 3.3.2.5 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Engineered Safety Features Actuation System (ESFAS) Instrumentation Perform TRIP ACTUATING DEVICE OPERATIONAL TEST (TADOT)-

(NOTE: Verification of setpoint not required for manual initiation functions.)

Table 3.3.2-1 Functions:

1.a: Safety Injection - Manual Initiation 3.a.1: Containment Isolation - Phase A Manual Initiation 3.b.1: Containment Isolation - Phase A Manual Initiation The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

Safety Injection (SI) provides two primary functions 1) Primary side water addition to ensure maintenance or recovery of reactor vessel water level (coverage of the active fuel for heat removal, clad integrity, and for limiting peak clad temperature to< 2200°F), and 2} Boration to ensure recovery and maintenance of SDM (keff < 1.0).

The operator can initiate SI at any time by using either of two pushbuttons in the control room. This action will cause actuation of all components in the same manner as any of the automatic actuation signals.

Containment Isolation provides isolation of the containment atmosphere, and all process systems that penetrate containment, from the environment. This Function is necessary to prevent or limit the release of radioactivity to the environment in the event of a large break LOCA.

Manual Phase A Containment Isolation is accomplished by either of two switches in the control room.

Either switch actuates both trains. Note that manual actuation of Phase A Containment Isolation also actuates Containment Purge and Exhaust Isolation.

Manual Phase B Containment Isolation is actuated for both trains when the two pushbuttons are pushed simultaneously.

This surveillance is a check of the Safety Injection Manual Actuation Function and Containment Isolation Manual Actuation Functions for Phase A and Phase B isolation. Each Manual Actuation Function is tested up to, and including, the master relay coils. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.).

The SR is modified by a Note that excludes verification of setpoints during the TADOT for Manual Initiation Functions. The manual initiation Functions have no associated setpoints.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.3.5 SR 3.3.5.2 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Loss of Power (LOP) Emergency Diesel Generator (EOG) Start Instrumentation Perform TRIP ACTUATING DEVICE OPERATIONAL TEST {TADOT} -

Table 3.3.5-1 Function:

1.a: 4.16 kV Susses A and B (Loss of Voltage)- Bus Undervoltage The SR interval for this SR is being increased from 36 months {staggered test basis) to 48 months {staggered test basis), for a maximum interval of 60 months (staggered test basis}, including the 25% extension afforded by TS SR 3.0.2.

The EDGs provide a source of emergency power when offsite power is either unavailable or is insufficiently stable to allow safe unit operation. Undervoltage protection will generate a LOP start if a loss of voltage occurs on 4.16 kV Bus A or B, an undervoltage condition occurs on safety related load centers, or a degraded voltage occurs on the safety related load centers. There are three LOP start signals for each 4.16 kV vital bus.

The relaying scheme for Bus A is independent of that for Bus B. Load shedding, EOG start, and sequencing will occur for both buses only upon a concurrent loss of voltage on each bus. To provide reliability, the two instantaneous undervoltage relays are connected across two secondaries of the potential transformer for each bus. Thus, failure of a single relay or voltage source would not cause a spurious transfer. Therefore, undervoltage on one bus alone is sufficient for the separation of that system from offsite sources, while the other bus, if not disturbed, would still be fed from offsite sources.

This surveillance is performance of a TADOT. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The test checks trip devices that provide actuation signals directly, bypassing the analog process control equipment. For these tests, the relay trip setpoints are verified and adjusted as necessary. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.5.2 SR 3.5.2.5 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Emergency Core Cooling Systems (ECCS) - Operating Verify each ECCS automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The function of the ECCS is to provide core cooling and negative reactivity to ensure that the reactor core is protected after any of the following accidents:

a.

Loss of coolant accident (LOCA), coolant leakage greater than the capability of the normal charging

system,

b.

Rod ejection accident,

c.

Loss of secondary coolant accident, including uncontrolled steam release or loss of feedwater, and

d.

Steam generator tube rupture (SGTR).

The addition of negative reactivity is designed primarily for the loss of secondary coolant accident where primary cooldown could add enough positive reactivity to achieve criticality and return to significant power.

The ECCS components and flowpaths ensure sufficient emergency core cooling capability will be available in the event of a LOCA assuming any single active failure. In addition, the ECCS provides long term core cooling capability in the recirculation mode during the accident recovery period.

Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation.

This surveillance demonstrates that each automatic ECCS valve actuates to the required position on an actual or simulated SI signal. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. In addition, SR 3.5.2.5 also verifies the correct interlock action to ensure that the RWST is isolated from the RHR System during RHR System operation and to ensure that the RHR System cannot be pressurized from the Reactor Coolant System unless the above RWST isolation valves are closed.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.5.2 SR 3.5.2.6 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Emergency Core Cooling Systems (ECCS) - Operating Verify each ECCS pump starts automatically on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The function of the ECCS is to provide core cooling and negative reactivity to ensure that the reactor core is protected after any of the following accidents:

a.

Loss of coolant accident (LOCA), coolant leakage greater than the capability of the normal charging

system,

b.

Rod ejection accident,

c.

Loss of secondary coolant accident, including uncontrolled steam release or loss of feedwater, and

d.

Steam generator tube rupture (SGTR).

The addition of negative reactivity is designed primarily for the loss of secondary coolant accident where primary cooldown could add enough positive reactivity to achieve criticality and return to significant power.

The ECCS components and flowpaths ensure sufficient emergency core cooling capability will be available in the event of a LOCA assuming any single active failure. In addition, the ECCS provides long term core cooling capability in the recirculation mode during the accident recovery period.

This surveillance demonstrates that each ECCS pump (RHR and HHSI) starts on receipt of an actual or simulated SI signal.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.6.3 SR 3.6.3.6 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Containment Isolation Valves Verify each automatic containment isolation valve that is not locked, sealed or otherwise secured in position, actuates to the isolation position on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The containment isolation valves form part of the containment pressure boundary and provide a means for fluid penetrations not serving accident consequence limiting systems to be provided with two isolation barriers that are closed on a containment isolation signal. These isolation devices are either passive or active (automatic). Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured), blind flanges, and closed systems are considered passive devices.

Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. One of these barriers may be a closed system. These barriers (typically containment isolation valves) make up the Containment Isolation System.

Automatic containment isolation valves close on a containment isolation signal to prevent leakage of radioactive material from containment following a DBA. This SR ensures that each automatic containment isolation valve will actuate to its isolation position on a containment isolation signal. This surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.6.6 SR 3.6.6.6 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Containment Spray and Cooling Systems Verify each automatic containment spray valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The Containment Spray System consists of two separate trains of equal capacity. Each train includes a containment spray pump, spray headers, nozzles, valves, and piping. Each train is powered from a separate ESF bus. The refueling water storage tank (RWST) supplies borated water to the Containment Spray System during the injection phase of operation. In the recirculation mode of operation, containment spray pump suction is transferred from the RWST to the containment sump(s) via the Residual Heat Removal (RHR)

System.

The Containment Spray System provides a spray of cold borated water into the upper regions of containment to reduce the containment pressure and temperature and to reduce fission products from the containment atmosphere during a DBA. The RWST solution temperature is an important factor in determining the heat removal capability of the Containment Spray System during the injection phase. In the recirculation mode of operation, heat is removed from the containment sump water by the residual heat removal coolers.

The Containment Spray System is actuated automatically by a containment High-High pressure signal coincident with a containment High pressure signal. An automatic actuation opens the containment spray pump discharge valves, starts the two containment spray pumps, and begins the injection phase.

This surveillance verifies that each automatic containment spray valve actuates to its correct position upon receipt of an actual or simulated actuation of a containment High-High pressure signal. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. Surveillance of the containment sump isolation valves is also required. A single surveillance may be used to satisfy both requirements.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.6.6 SR 3.6.6.7 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Containment Spray and Cooling Systems Verify each containment spray pump starts automatically on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The Containment Spray System consists of two separate trains of equal capacity. Each train includes a containment spray pump, spray headers, nozzles, valves, and piping. Each train is powered from a separate ESF bus. The refueling water storage tank (RWST) supplies borated water to the Containment Spray System during the injection phase of operation. In the recirculation mode of operation, containment spray pump suction is transferred from the RWST to the containment sump(s) via the Residual Heat Removal (RHR)

System.

The Containment Spray System provides a spray of cold borated water into the upper regions of containment to reduce the containment pressure and temperature and to reduce fission products from the containment atmosphere during a DBA. The RWST solution temperature is an important factor in determining the heat removal capability of the Containment Spray System during the injection phase. In the recirculation mode of operation, heat is removed from the containment sump water by the residual heat removal coolers.

The Containment Spray System is actuated automatically by a containment High-High pressure signal coincident with a containment High pressure signal. An automatic actuation opens the containment spray pump discharge valves, starts the two containment spray pumps, and begins the injection phase.

This surveillance verifies that each containment spray pump starts upon receipt of an actual or simulated actuation of a containment High-High pressure signal. The manual isolation valves in the spray lines at the containment shall be locked closed for the performance of the containment spray pump automatic start tests.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.6.6 SR 3.6.6.8 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Containment Spray and Cooling Systems Verify each emergency containment cooling unit starts automatically on an actual or simulated actuation signal..

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

Three units of emergency containment cooling are provided. Each fan unit is supplied with cooling water from a train of component cooling water (CCW). Air is drawn into the coolers through the fan and discharged to the upper areas of containment.

In post-accident operation following an actuation signal, two Emergency Containment Cooling System fans are designed to start automatically if not already running. Only two of the three emergency containment fans start on a safety injection signal (Containment High-1 pressure setpoint). The third emergency containment fan is required to be available and will automatically start if there is a failure of one of the other units. The temperature of the CCW is an important factor in the heat removal capability of the fan units.

This surveillance verifies that each emergency containment cooling unit actuates upon receipt of an actual or simulated safety injection signal.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.7.3 SR 3.7.3.2 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Feedwater Isolation Valves (FIVs) and Feedwater Control Valves (FCVs) and Associated Bypass Valves Verify each FIV, FCV, and associated bypass valves actuates to the isolation position on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The FCVs isolate main feedwater (MFW) flow to the secondary side of the steam generators following a high energy line break (HELB). The function of the FIVs is to provide the second isolation of MFW flow to the secondary side of the steam generators following an HELB. The LCO requires three FCVs, three FIVs, three bypass line control valves, and three bypass line isolation valves to be OPERABLE.

The FIVs and associated bypass valves, or FCVs and associated bypass valves, isolate the nonsafety related portions from the safety related portions ofthe system. In the event of a secondary side pipe rupture inside containment, the valves limit the quantity of high energy fluid that enters containment through the break and provide a pressure boundary for the controlled addition of auxiliary feedwater (AFW) to the intact loops.

One FIV and associated bypass valves, and one FCV and its associated bypass valve, are located on each MFW line, outside but close to containment. The FIVs and FCVs are located upstream of the AFW injection point so that AFW may be supplied to the steam generators following FIV or FCV closure. The piping volume from these valves to the steam generators must be accounted for in calculating mass and energy releases and refilled prior to AFW reaching the steam generator following either an SLB or FWLB.

This surveillance verifies that each FIV, FCV, and associated bypass valves can close on an actual or simulated actuation signal. This Surveillance is normally performed upon returning the plant to operation following a refueling outage.

This SR is modified by a Note that allows entry into and operation in MODE 3 prior to the surveillance being performed. This allows a delay of testing until MODE 3, to establish conditions consistent with those under which the acceptance criterion was generated.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.7.7 SR 3.7.7.2 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Component Cooling Water (CCW) System Verify each CCW automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The CCW System provides a heat sink for the removal of process and operating heat from safety related components during a Design Basis Accident (OBA) or transient.

The CCW System is arranged as two independent cooling loops and has isolatable nonsafety related components. Each safety related train includes a full capacity pump, surge tank, piping, valves, and instrumentation. The CCW System design also includes three heat exchangers that are common to both cooling loops. Each safety related train is powered from a separate bus. An open surge tank in the system provides pump trip protective functions to ensure that sufficient net positive suction head is available. The pump in each train is automatically started on receipt of a safety injection signal, and all nonessential components are isolated.

In addition, the CCW System design includes an additional CCW pump that can swing from one train to the other, with interlocks to ensure the swing pump can serve as a backup to either CCW train. Each of the two standby pumps provides 100% backup, during normal operation. The CCW pumps and heat exchangers are arranged such that any combination of pumps and heat exchangers can supply either CCW cooling loop. The CCW trains are normally cross tied at common suction and discharge headers and can be separated by closing crosstie valves between headers.

This surveillance verifies proper automatic operation of the CCW valves on an actual or simulated actuation signal. The CCW System is a normally operating system that cannot be fully actuated as part of routine testing during normal operation. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.7.7 SR 3.7.7.3 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Component Cooling Water (CCW) System Verify each CCW pump starts automatically on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The CCW System provides a heat sink for the removal of process and operating heat from safety related components during a Design Basis Accident (DBA) or transient.

The CCW System is arranged as two independent cooling loops and has isolatable nonsafety related components. Each safety related train includes a full capacity pump, surge tank, piping, valves, and instrumentation. The CCW System design also includes three heat exchangers that are common to both cooling loops. Each safety related train is powered from a separate bus. An open surge tank in the system provides pump trip protective functions to ensure that sufficient net positive suction head is available. The pump in each train is automatically started on receipt of a safety injection signal, and all nonessential components are isolated.

In addition, the CCW System design includes an additional CCW pump that can swing from one train to the other, with interlocks to ensure the swing pump can serve as a backup to either CCW train. Each of the two standby pumps provides 100% backup, during normal operation. The CCW pumps and heat exchangers are arranged such that any combination of pumps and heat exchangers can supply either CCW cooling loop. The CCW trains are normally cross tied at common suction and discharge headers and can be separated by closing crosstie valves between headers.

Each pump is automatically started on receipt of a start signal from the emergency bus load sequencer, and all nonessential components are isolated. The emergency bus load sequencer is actuated by a loss of offsite power (LOOP), a safety injection (SI) signal on its associated unit, a SI from the opposite unit, or a combination LOOP/LOCA.

This surveillance verifies proper automatic operation of the CCW pumps on an actual or simulated actuation signal. The CCW System is a normally operating system that cannot be fully actuated as part of routine testing during normal operation.

The CCW swing pump (C pump) is interlocked to prevent starting if CCW pumps A and Bare aligned for starting. For a start signal to initiate starting the swing pump on a LOOP or SI signal, the supply breaker for the CCW pump, associated with the AC electrical power distribution train to which it is aligned, must be open and racked out. Testing the automatic starting ofthe swing CCW pump includes testing this interlock.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.7.8 SR 3.7.8.2 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Intake Cooling Water (ICW) System Verify each ICW automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The ICW System provides a heat sink for the removal of process and operating heat from safety related components during a Design Basis Accident (DBA) or transient.

The ICW System consists of two separate, 100% capacity, safety related, cooling water trains. Each train consists of one 100% capacity pump. In addition, the ICW System design includes an additional ICW pump that can swing from one train to the other, with interlocks to ensure the swing pump can serve as a backup to either ICW train.

The ICW System supplies salt water to the tube side of the component cooling water {CCW) heat exchangers and to cold side of the turbine area cooling water heat exchangers. The redundant header system is provided with isolation valves that can be shut so that failure of one loop does not require immediate shutdown of the unit. The supply headers are redundant while the return merges to a discharge header that returns water to the discharge canal.

The ICW System provides sufficient redundancy so that at least one ICW pump will continue to operate to handle heat loads from DBAs following a postulated single active failure. A single ICW pump, however, is limited in its ability to supply the required cooling water to the CCW water heat exchangers during an accident when flow is also allowed to continue through the turbine plant cooling water (TPCW) heat exchangers. OPERABILITY of the ICW header during an accident is maintained by isolation of the TPCW.

This surveillance verifies proper automatic operation of the ICW System valves on an actual or simulated actuation signal. The ICW System is a normally operating system that cannot be fully actuated as part of power operation testing. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.7.8 SR 3.7.8.3 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Intake Cooling Water (ICW) System Verify each ICW pump starts automatically on an actual or simulated actuation signal.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The ICW System provides a heat sink for the removal of process and operating heat from safety related components during a Design Basis Accident (DBA) or transient.

The ICW System consists of two separate, 100% capacity, safety related, cooling water trains. Each train consists of one 100% capacity pump. In addition, the ICW System design includes an additional ICW pump that can swing from one train to the other, with interlocks to ensure the swing pump can serve as a backup to either ICW train.

The ICW System supplies salt water to the tube side of the component cooling water (CCW) heat exchangers and to cold side of the turbine area cooling water heat exchangers. The redundant header system is provided with isolation valves that can be shut so that failure of one loop does not require immediate shutdown of the unit. The supply headers are redundant while the return merges to a discharge header that returns water to the discharge canal.

Three ICW pumps are provided for each unit. Only one pump is required following a maximum hypothetical accident (MHA). The A and B ICW pumps are powered by 4.16 kV buses A or B, which can be powered by each train's associated emergency diesel generator (EDG). A swing 4.16 kV emergency bus provides power to the swing ICW pump C and can be manually aligned to either the A or B train 4.16 kV bus. ICW pump C is interlocked, such that, it can only start on a loss of offsite power (LOOP) or safety injection (SI) signal if the supply breaker for the A or B ICW pump associated with train to which it is aligned is open and racked out.

The ICW swing pump (C pump) is interlocked to prevent starting if ICW pumps A and Bare aligned for starting. For a start signal to initiate starting the swing pump on a LOOP or SI signal, the supply breaker for the ICW pump, associated with the AC electrical power distribution train to which it is aligned, must be open and racked out. Testing the automatic starting of the swing ICW pump includes testing this interlock.

This surveillance verifies proper automatic operation of the ICW System pumps on an actual or simulated actuation signal. The ICW System is a normally operating system that cannot be fully actuated as part of normal testing during normal power operation.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.7.10 SR 3.7.10.3 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Control Room Emergency Ventilation System (CREVS)

Verify each CREVS train actuates on an actual or simulated actuation signal, except for dampers and valves that are locked, sealed, or otherwise secured in the actuated position.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25% extension afforded by TS SR 3.0.2.

The CREVS provides a protected environment from which occupants can control the unit following an uncontrolled release of radioactivity, hazardous chemicals, or smoke.

The CREVS is a subsystem of the Control Building Ventilation System and consists of the following components:

a.

Air handling units (AH Us),

b.

Recirculation fans,

c.

Recirculation dampers,

d.

Recirculation filter unit,

e.

Normal outside air intake dampers, and

f.

Emergency outside air intake dampers.

During normal operation, fresh makeup air is admitted to this system through an intake louver and two dampers in series located in the west wall of the control building. This system maintains a positive pressure in the CRS greater than that in the cable spreading room in order to prevent smoke from a hypothesized fire in the cable spreading room from entering the control room.

The control room recirculation mode is initiated by a containment Phase A signal, a high radiation signal from the containment air radiation monitors (R-11 and R-12), the manual initiation from a test switch, or a high radiation signal from the redundant monitors in the control room normal air intake. Following initiation, all exhaust fans shut off, and the redundant series exhaust isolation dampers close. Redundant normal air intake isolation dampers in series close. Redundant parallel emergency air intake dampers open. Likewise, the recirculation air path opens. A single air supply fan is energized to move the appropriate mixture of recirculation control room air and fresh outdoor air through the high efficiency particulate air (HEPA) and charcoal filter system.

This surveillance verifies that each CREVS train starts and operates on an actual or simulated actuation signal.

The SR excludes automatic dampers and valves that are locked, sealed, or otherwise secured in the actuated position. Placing an automatic valve or damper in a locked, sealed, or otherwise secured position requires an assessment of the OPERABILITY of the system or any supported systems, including whether it is necessary for the valve or damper to be repositioned to the non-actuated position to support the accident analysis.

Restoration of an automatic valve or damper to the non-actuated position requires verification that the SR has been met within its required Frequency.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.8.1 SR 3.8.1.9 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis AC Sources - Operating Verify each EDG rejects a load greater than or equal to its associated single largest post-accident load, and:

a.

Following load rejection, the frequency is s:: 66.25 Hz,

b.

Within 2 seconds following load rejection, the voltage is~ 3950 V and s:: 4350 V, and

c.

Within 2 seconds following load rejection, the frequency is~ 59.4 Hz and S:: 60.6 Hz.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated EOG. Two EOGs provide onsite emergency AC power for each unit. EOGs 3A and 38 provide Unit 3 A train, and B train emergency power, respectively. EOGs 4A and 48 provide Unit 4 A train and B train emergency power, respectively. A EOG starts automatically on a safety injection (SI} signal, or on an ESF bus degraded voltage or undervoltage signal. After the EOG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The EOGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips non permanent loads from the ESF bus. When the EOG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the EOG by automatic load application.

The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 recommendations for response during load sequence intervals. The 2 seconds specified is less than 60% of a typical 5 second load sequence interval associated with sequencing of the largest load. The voltage and frequency specified are consistent with the design range of the equipment powered by the EOG.

This Surveillance demonstrates the EOG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining margin to the overspeed trip. For this unit, the single load for each EOG is the component cooling water pump having an equivalent kW rating of 380 kW. To compensate for a worst-case EOG over-frequency of 1% the minimum rejection load specified is increased to 392 kW.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.8.1 SR 3.8.1.10 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis AC Sources - Operating Verify each EDG does not trip and voltage returns to:,; 4784 V within 2 seconds following a load rejection of;::: 2500 kW (Unit 3),;::: 2874 kW (Unit 4).

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated EDG. Two EDGs provide onsite emergency AC power for each unit. EDGs 3A and 38 provide Unit 3 A train, and 8 train emergency power, respectively. EDGs 4A and 48 provide Unit 4 A train and 8 train emergency power, respectively. A EDG starts automatically on a safety injection {SI) signal, or on an ESF bus degraded voltage or undervoltage signal. After the EDG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The EDGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips nonpermanent loads from the ESF bus. When the EDG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the EDG by automatic load application.

This Surveillance demonstrates the EDG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. The EDG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the EDG experiences following a full load rejection and verifies that the EDG does not trip upon loss of the load. These acceptance criteria provide for EDG damage protection. While the EDG is not expected to experience this transient during an event and continues to be available, this response ensures that the EDG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.8.1 SR 3.8.1.11 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis AC Sources - Operating Verify each EDG rejects a load greater than or equal to its associated single largest post-accident load, and:

a.

De-energization of emergency buses,

b.

Load shedding from emergency buses,

c.

EDG auto-starts from standby condition and:

1.

Energizes permanently connected loads in:::; 15 seconds,

2.

Energizes auto-connected shutdown loads through automatic load sequencer,

3.

Maintains steady state voltage~ 3950 V and:::; 4350 V,

4.

Maintains steady state frequency~ 59.4 Hz and:::; 60.6 Hz, and

5. Supplies permanently connected and auto-connected shutdown loads for

~ 5 minutes The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated EDG. Two EDGs provide onsite emergency AC power for each unit. EDGs 3A and 3B provide Unit 3 A train, and B train emergency power, respectively. EDGs 4A and 4B provide Unit 4 A train and B train emergency power, respectively. A EDG starts automatically on a safety injection (SI) signal, or on an ESF bus degraded voltage or undervoltage signal. After the EDG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The EDGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips non permanent loads from the ESF bus. When the EDG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the EDG by automatic load application.

This Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the LOOP, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the EDG. It further demonstrates the capability of the EDG to automatically achieve the required voltage and frequency within the specified time.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.8.1 SR 3.8.1.12 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis AC Sources - Operating Verify on an actual or simulated Engineered Safety Feature (ESF) actuation signal each EOG autostarts from standby condition and:*

a.

In :::; 15 seconds after auto-start and during tests, achieves voltage;::: 3950 V and frequency;::: 59.4 Hz,

b.

Achieves steady state voltage;::: 3950 V and:::; 4350 V and frequency;::: 59.4 Hz and :::; 60.6 Hz,

c.

Operates for;::: 5 minutes,

d.

Permanently connected loads remain energized from the offsite power system, and

e.

Emergency loads are energized or auto-connected through the automatic load sequencer from the offsite power system.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated EOG. Two EOGs provide onsite emergency AC power for each unit. EOGs 3A and 3B provide Unit 3 A train, and B train emergency power, respectively. EOGs 4A and 4B provide Unit 4 A train and B train emergency power, respectively. A EOG starts automatically on a safety injection (SI) signal, or on an ESF bus degraded voltage or undervoltage signal. After the EOG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The EOGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips nonpermanent loads from the ESF bus. When the EOG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the EOG by automatic load application.

This Surveillance demonstrates that the EOG automatically starts and achieves the required voltage and frequency within the specified time (15 seconds) from the design basis actuation signal (LOCA signal) and operates for;::: 5 minutes. The 5 minute period provides sufficient time to demonstrate stability.

SR 3.8.1.12.d and SR 3.8.1.12.e ensure that permanently connected loads and emergency loads are energized from the offsite electrical power system on an ESF signal without LOOP.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.8.1 SR 3.8.1.13 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis AC Sources - Operating Verify EDG trips made OPERABLE during the test mode of EDG operation are inoperable on actual or simulated loss of voltage signal on the emergency bus concurrent with an actual or simulated ESF actuation signal.

The SR interval for this SR is being increased from 36 months {staggered test basis) to 48 months

{staggered test basis), for a maximum interval of 60 months {staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated EOG. Two EOGs provide onsite emergency AC power for each unit. EOGs 3A and 38 provide Unit 3 A train, and 8 train emergency power, respectively. EOGs 4A and 48 provide Unit 4 A train and 8 train emergency power, respectively. A EDG starts automatically on a safety injection {SI) signal, or on an ESF bus degraded voltage or undervoltage signal. After the EOG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The EOGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips nonpermanent loads from the ESF bus. When the EOG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the EOG by automatic load application.

This Surveillance demonstrates that EOG noncritical protective functions {e.g., high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ESF actuation test signal.

Noncritical automatic trips are all automatic trips except:

a.

Engine overspeed; and

b.

Generator differential current.

The noncritical trips are bypassed during 08As and provide an alarm on an abnormal engine condition.

This alarm provides the operator with sufficient time to react appropriately. The EOG availability to mitigate the OBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the EOG.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.8.1 SR 3.8.1.16 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis AC Sources - Operating Verify each EDG:

a.

Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power,

b.

Transfers loads to offsite power source, and

c.

Returns to ready-to-load operation.

The SR interval for this SR is being increased from 36 months (staggered test basis} to 48 months (staggered test basis}, for a maximum interval of 60 months (staggered test basis}, including the 25%

extension afforded by TS SR 3.0.2.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated EDG. Two EDGs provide onsite emergency AC power for each unit. EDGs 3A and 38 provide Unit 3 A train, and B train emergency power, respectively. EDGs 4A and 48 provide Unit 4 A train and B train emergency power, respectively. A EDG starts automatically on a safety injection {SI} signal, or on an ESF bus degraded voltage or undervoltage signal. After the EDG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The EDGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips non permanent loads from the ESF bus. When the EDG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the EDG by automatic load application.

This Surveillance ensures that the manual synchronization and automatic load transfer from the EDG to the offsite source can be made and the EDG can be returned to ready to load status when offsite power is restored. It also ensures that the autostart logic is reset to allow the EDG to reload if a subsequent LOOP occurs. The EDG is considered to be in ready to load status when the EDG is at rated speed and voltage, the output breaker is open and can receive an autoclose signal on bus undervoltage, and the load sequence timers are reset.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis} SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.8.1 SR 3.8.1.17 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis AC Sources - Operating Verify, with a EOG operating in test mode and connected to its bus, an actual or simulated ESF actuation signal overrides the test mode by:

a.

Returning EOG to ready-to-load operation and

b.

Automatically energizing the emergency load from offsite power.

The SR interval for this SR is being increased from 36 months (staggered test basis} to 48 months (staggered test basis}, for a maximum interval of 60 months (staggered test basis}, including the 25%

extension afforded by TS SR 3.0.2.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated EDG. Two EDGs provide onsite emergency AC power for each unit. EDGs 3A and 3B provide Unit 3 A train, and B train emergency power, respectively. EDGs 4A and 4B provide Unit 4 A train and B train emergency power, respectively. A EDG starts automatically on a safety injection (SI} signal, or on an ESF bus degraded voltage or undervoltage signal. After the EDG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The EDGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips non permanent loads from the ESF bus. When the EDG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the EDG by automatic load application.

This Surveillance demonstrates the test mode override to ensure that the EOG availability under accident conditions will not be compromised as the result of testing and the EOG will automatically reset to ready to load operation if a LOCA actuation signal is received during operation in the test mode. Ready to load operation is defined as the EOG running at rated speed and voltage with the EDG output breaker open.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis} SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.8.1 SR 3.8.1.18 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis AC Sources - Operating Verify interval between each sequenced load block is within+/- 10% of design interval for each emergency load sequencer.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated EDG. Two EDGs provide onsite emergency AC power for each unit. EDGs 3A and 3B provide Unit 3 A train, and B train emergency power, respectively. EDGs 4A and 4B provide Unit 4 A train and B train emergency power, respectively. A EDG starts automatically on a safety injection (SI) signal, or on an ESF bus degraded voltage or undervoltage signal. After the EDG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The EDGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips non permanent loads from the ESF bus. When the EDG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the EDG by automatic load application.

This Surveillance demonstrates that under accident and loss of offsite power conditions loads are sequentially connected to the bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the EDGs due to high motor starting currents. The 10% load sequence time interval tolerance ensures that sufficient time exists for the EDG to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.8.1 SR 3.8.1.19 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis AC Sources - Operating Verify on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ESF actuation signal:

a.

De-energization of emergency buses,

b.

Load shedding from emergency buses,

c.

EDG auto-starts from standby condition and:

1.

Energizes permanently connected loads in::::; 15 seconds,

2.

Energizes auto-connected shutdown loads through load sequencer,

3.

Achieves steady state voltage~ 3950 V and::::; 4350 V,

4.

Achieves steady state frequency~ 59.4 Hz and ::::; 60.6 Hz, and

5.

Supplies permanently connected and auto-connected emergency loads for

~ 5 minutes.

The SR interval for this SR is being increased from 36 months (staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months (staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated EDG. Two EDGs provide onsite emergency AC power for each unit. EDGs 3A and 3B provide Unit 3 A train, and B train emergency power, respectively. EDGs 4A and 48 provide Unit 4 A train and B train emergency power, respectively. A EDG starts automatically on a safety injection (SI) signal, or on an ESF bus degraded voltage or undervoltage signal. After the EDG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The EDGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips nonpermanent loads from the ESF bus. When the EDG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the EDG by automatic load application.

This Surveillance demonstrates the EDG operation, as discussed in the Bases for SR 3.8.1.11, during a LOOP actuation test signal in conjunction with an ESF actuation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the EDG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 5.5.15 SR 5.5.15.d Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis Control Room Envelope (CRE) Habitability Program Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation with one CREVS train operating at the flow rate required by the VFTP, at a Frequency in accordance with the Surveillance Frequency Control Program. The results shall be trended and used as part of the assessment of the CRE boundary.

The SR interval for this SR is being increased from 36 months {staggered test basis) to 48 months (staggered test basis), for a maximum interval of 60 months {staggered test basis), including the 25%

extension afforded by TS SR 3.0.2.

A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Ventilation System (CREVS}, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month (staggered test basis) SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month (Staggered Test Basis) Surveillance Failure Analysis B. Calibration Changes Without Setpoints TS 3.3.5 SR 3.3.5.3 Loss of Power (LOP) Emergency Diesel Generator (EOG) Start Instrumentation Perform CHANNEL CALIBRATION Table 3.3.5-1 Function:

1.a: 4.16 kV Susses A and B (Loss of Voltage) - Bus Undervoltage The SR interval for this SR is being increased from 36 months to 48 months, for a maximum interval of 60 months, including the 25% extension afforded by TS SR 3.0.2.

The EDGs provide a source of emergency power when offsite power is either unavailable or is insufficiently stable to allow safe unit operation. Undervoltage protection will generate a LOP start if a loss of voltage occurs on 4.16 kV Bus A or B, an undervoltage condition occurs on safety related load centers, or a degraded voltage occurs on the safety related load centers. There are three LOP start signals for each 4.16 kV vital bus.

The relaying scheme for Bus A is independent of that for Bus B. Load shedding, EOG start, and sequencing will occur for both buses only upon a concurrent loss of voltage on each bus. To provide reliability, the two instantaneous undervoltage relays are connected across two secondaries of the potential transformer for each bus. Thus, failure of a single relay or voltage source would not cause a spurious transfer. Therefore, undervoltage on one bus alone is sufficient for the separation of that system from offsite sources, while the other bus, if not disturbed, would still be fed from offsite sources.

This surveillance is the performance of a CHANNEL CALIBRATION.

The setpoints, as well as the response to a loss of voltage and a degraded voltage test, shall include a single point verification that the trip occurs within the required time delay.

CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

TS 3.3.5 SR 3.3.5.3 Turkey Point 3 and 4 GL 91-04 Non-Calibration and Calibration Without Setpoints 36 Month and 36 Month {Staggered Test Basis) Surveillance Failure Analysis Loss of Power (LOP) Emergency Diesel Generator (EDG) Start Instrumentation Perform CHANNEL CALIBRATION Table 3.3.5-1 Function:

2a: 480V Load Centers (Undervoltage) - Bus Undervoltage 2.b: 480V Load Centers (Undervoltage) - Time Delay 3a: 480V Load Centers (Degraded Voltage) - Bus Undervoltage 3.b: 480V Load Centers (Degraded Voltage) - Time Delay The SR interval for this SR is being increased from 36 months to 48 months, for a maximum interval of 60 months, including the 25% extension afforded by TS SR 3.0.2.

The EDGs provide a source of emergency power when offsite power is either unavailable or is insufficiently stable to allow safe unit operation. Undervoltage protection will generate a LOP start if a loss of voltage occurs on 4.16 kV Bus A or B, an undervoltage condition occurs on safety related load centers, or a degraded voltage occurs on the safety related load centers. There are three LOP start signals for each 4.16 kV vital bus.

The relaying scheme for Bus A is independent of that for Bus B. Load shedding, EDG start, and sequencing will occur for both buses only upon a concurrent loss of voltage on each bus. To provide reliability, the two instantaneous undervoltage relays are connected across two secondaries of the potential transformer for each bus. Thus, failure of a single relay or voltage source would not cause a spurious transfer. Therefore, undervoltage on one bus alone is sufficient for the separation of that system from offsite sources, while the other bus, if not disturbed, would still be fed from offsite sources.

This surveillance is the performance of a CHANNEL CALIBRATION.

The setpoints, as well as the response to a loss of voltage and a degraded voltage test, shall include a single point verification that the trip occurs within the required time delay.

CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology.

A review of SR test history identified no failures of the TS functions that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 60-month SR interval. Based on the history of system performance, the impact of this change on safety, if any, is small.

v t e Letter Sequence Request
EPID:L-2025-LLA-0045, (Open)
Initiation Request Acceptance Administration Questions Answers Results Approval... Other:
MONTHYEAR2025-03-03 [Table View]

L-2025-020, License Amendment Request 279, Extend Surveillance Test Intervals in Support of Transition to 24 Month Fuel Cycles

Text

References:

SUMMARY

3.0 TECHNICAL EVALUATION

6.0 REFERENCES

SUMMARY

2.1 Background

3.0 TECHNICAL EVALUATION

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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Person / Time
ML25062A213
Site:	Turkey Point (DPR-031, DPR-041)
Issue date:	03/03/2025
From:	Mack K Florida Power & Light Co
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
L-2025-020
Download: ML25062A213 (1)
v • d • e

L-2025-020, License Amendment Request 279, Extend Surveillance Test Intervals in Support of Transition to 24 Month Fuel Cycles

Text

References:

SUMMARY

3.0 TECHNICAL EVALUATION

6.0 REFERENCES

SUMMARY

2.1 Background

3.0 TECHNICAL EVALUATION

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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