Text

Issuance of Amendment Nos. 250 and 202 Regarding Technical Specification Changes to Allow the Performance of Selected Emergency Diesel Generator Surveillance Requirements During Power Operation
	ML19266A072
Person / Time
Site:	Saint Lucie
Issue date:	01/27/2020
From:	Natreon Jordan; Plant Licensing Branch II
To:	Moul D; Florida Power & Light Co
	Jordan N
References
	EPID L-2018-LLA-0574
	Download: ML19266A072 (37)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 January 27, 2020

SUBJECT:

ST. LUCIE PLANT, UNIT NOS. 1 AND 2 - ISSUANCE OF AMENDMENT NOS. 250 AND 202 REGARDING TECHNICAL SPECIFICATION CHANGES TO ALLOW THE PERFORMANCE OF SELECTED EMERGENCY DIESEL GENERATOR SURVEILLANCE REQUIREMENTS DURING POWER OPERATION (EPID L-2018-LLA-0574)

Dear Mr. Moul:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment Nos. 250 and 202 to Renewed Facility Operating License Nos. DPR-67 and NPF-16 for the St. Lucie Plant, Unit Nos. 1 and 2, respectively. The amendments change the technical specifications in response to the application from Florida Power & Light Company dated December 20, 2018, as supplemented by letter dated June 28, 2019.

The amendments revise the technical specifications to allow for the performance of selected emergency diesel generator surveillance requirements during power operation and relocate two surveillance requirements, for each unit, to licensee control.

A copy of the related safety evaluation is also enclosed. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Docket Nos. 50-335 and 50-389

Enclosures:

1. Amendment No. 250 to DPR-67

2. Amendment No. 202 to NPF-16

3. Safety Evaluation cc: Listserv Sincerely, Natreon J. Jordan, Project Manager Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 FLORIDA POWER & LIGHT COMPANY DOCKET NO. 50-335 ST. LUCIE PLANT. UNIT NO. 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 250 Renewed License No. DPR-67

1.

The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Florida Power & Light Company, dated December 20, 2018, as supplemented by letter dated June 28, 2019, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I;

8.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2.

Accordingly, Renewed Facility Operating License No. DPR-67 is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and by amending paragraph 3.8 to read as follows:

8.

Technical Specifications The Technical Specifications contained in Appendices A and 8, as revised through Amendment No. 250, are hereby incorporated in the renewed license. FPL shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 90 days of issuance.

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications Date of Issuance: January 27, 2020 FOR THE NUCLEAR REGULATORY COMMISSION ll~Aor Undine Shoop, Chief Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

ATTACHMENT TO LICENSE AMENDMENT NO. 250 ST. LUCIE PLANT. UNIT NO. 1 RENEWED FACILITY OPERATING LICENSE NO. DPR-67 DOCKET NO. 50-335 Replace pages 3 of Renewed Facility Operating License No. DPR-67 with the attached page 3.

The revised page is identified by amendment number and contains a marginal line indicating the area of change.

Replace the following pages of the Appendix A Technical Specifications with the attached pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert 3/4 8-5 3/4 8-5 3/4 8-6 3/4 8-6 3/4 8-6a 3/4 8-6a 3/4 8-6b applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

A.

Maximum Power Level B.

C.

D.

FPL is authorized to operate the facility at steady state reactor core power levels not in excess of 3020 megawatts (thermal).

Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 250, are hereby incorporated in the renewed license.

FPL shall operate the facility in accordance with the Technical Specifications.

Appendix B, the Environmental Protection Plan (Non-Radiological), contains environmental conditions of the renewed license. If significant detrimental effects or evidence of irreversible damage are detected by the monitoring programs required by Appendix B of this license, FPL will provide the Commission with an analysis of the problem and plan of action to be taken subject to Commission approval to eliminate or significantly reduce the detrimental effects or damage.

Updated Final Safety Analysis Report The Updated Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on March 28, 2003, describes certain future activities to be completed before the period of extended operation. FPL shall complete these activities no later than March 1, 2016, and shall notify the NRC in writing when implementation of these activities is complete and can be verified by NRC inspection.

The Updated Final Safety Analysis Report supplement as revised on March 28, 2003, described above, shall be included in the next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50.71(e)(4),

following issuance of this renewed license. Until that update is complete, FPL may make changes to the programs described in such supplement without prior Commission approval, provided that FPL evaluates each such change pursuant to the criteria set forth in 1 O CFR 50.59 and otherwise complies with the requirements in that section.

Sustained Core Uncovery Actions Procedural guidance shall be in place to instruct operators to implement actions that are designed to mitigate a small-break loss-of-coolant accident prior to a calculated time of sustained core uncovery.

Renewed License No. DPR-67 Amendment No. 250

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

c.

Verify fuel oil properties of new and stored fuel oil are tested in accordance with, and maintained within the limits of the Diesel Fuel Oil Testing Program.

d.

DELETED

e.

In accordance with the Surveillance Frequency Control Program by:

1.

DELETED

2.

3.

ST. LUCIE - UNIT 1 NOTE Credit may be taken for unplanned events that satisfy this SR.

Verifying generator capability to reject the single largest post-accident load while maintaining voltage at 4160 !:. 420 volts and frequency at 60 !:.

1.2 Hz.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying that upon an actual or simulated loss of offsite power signal by itself.

a}

Deenergization of the emergency busses and load shedding from the emergency busses.

3/4 8-5 Amendment No. ea, 400, +68, ~.

~.250

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

4.

5.

b)

The diesel starts on the auto-start signal****, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads.

After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160 +/- 210 volts and 60 +/- 0.6 Hz during this test.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying that upon an actual or simiulated ESF actuation signal (without loss-I of-offsite power) the diesel generator starts**** on the auto-start signal, and:

a)

Within 10 seconds, generator voltage and frequency shall be 4160 +/- 420 volts and 60 +/- 1.2 Hz.

b)

Operates on standby for greater than or equal to 5 minutes.

c)

Steady-state generator voltage and frequency shall be 4160 +/- 210 volts and 60 +/- 0.6 Hz and shall be maintained throughout this test.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying that upon an actual or simulated loss-of-offsite power signal in conjunction with an ESF actuation signal:

a)

Deenergization of the emergency busses and load shedding from the emergency busses.

- - - This test may be conducted in accordance with the manufacturer's recommendations concerning engine prelube period.

ST. LUCIE - UNIT 1 3/4 8-6 Amendment No. ea, 4-06, ~. 250

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS {Continued)

6.

b)

The diesel starts on the auto-start signal****, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected emergency (accident) loads through the auto-sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160 +/- 210 volts and 60 +/- 0.6 Hz during this test.

c)

All automatic diesel generator trips, except engine overspeed and generator differential, are automatically bypassed upon loss of voltage on the emergency bus concurrent with a safety injection signal.

NOTE Credit may be taken for unplanned events that satisfy this SR.

Verifying the diesel generator operates for at least 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s****. During the first 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of this test, the diesel generator shall be loaded within a load band of 3800 to 3960 kW# and during the remaining 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months of this test, the diesel generator shall be loaded within a load band of 3300 to 3500 kW#. The generator voltage and frequency shall be 4160 +/- 420 volts and 60 +/- 1.2 Hz within 10 seconds after the start signal; the steady state generator voltage and frequency shall be maintained within these limits during this test.

7.

DELETED

8.

NOTE This Surveillance shall not normally be performed in MODE 1, 2, 3 or 4.

However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying the diesel generator's capability to:

a)

Synchronize with the offsite power source while the generator is loaded with its emergency loads upon actual or simulated restoration of offsite power.

b}

Transfer its load to the offsite power source, and c)

Be restored to its standby status.

This band is meant as guidance to avoid routine overloading of the engine. Variations in load in excess of this band due to changing bus loads shall not invalidate this test.

- - - This test may be conducted in accordance with the manufacturer's recommendations concerning engine prelube period.

ST. LUCIE - UNIT 1 3/4 8-6a Amendment No. ~. ~. 223, 250

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (continued)

9.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying that with the diesel generator operating in a test mode (connected to its bus), an actual or simulated safety injection signal overrides I the test mode by (1) returning the diesel generator to standby operation and (2) automatically energizes.the emergency loads with offsite power.

10.

DELETED

11.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying that the automatic load sequence timers are operable with the interval between each load block within + 1 second of its design interval.

f.

In accordance with the Surveillance Frequency Control Program or after any modification which could affect diesel generator independence by starting****

the diesel generators simultaneously, during shutdown, and verifying that the diesel generators accelerate to approximately 900 rpm in less than or equal to 10 seconds.

g.

In accordance with the Surveillance Frequency Control Program by performing a pressure test of those portions of the diesel fuel oil system designed to USAS 831.7 Class 3 requirements in accordance with the lnservice Inspection Program.

4.8.1.1.3 Reports - (Not Used) 4.8.1.1.4 The Class 1 E underground cable system shall be demonstrated OPERABLE within 30 days after the movement of any loads in excess of 80% of the ground surface design basis load over the cable ducts by pulling a mandrel with a diameter of at least 80% of the duct's inside diameter through a duct exposed to the maximum loading (duct nearest the ground's surface) and verifying that the duct has not been damaged.

This band is meant as guidance to avoid routine overloading of the engine. Variations in load in excess of this band due to changing bus loads shall not invalidate this test.

This test may be conducted in accordance with the manufacturer's recommendations concerning engine prelube period.

ST. LUCIE - UNIT 1 3/4 8-6b Amendment No. 400, ~.

44-S,+lfl.~.223.-233, 250

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, O.C. 20555-0001 FLORIDA POWER & LIGHT COMPANY ORLANDO UTILITIES COMMISSION OF THE CITY OF ORLANDO. FLORIDA AND FLORIDA MUNICIPAL POWER AGENCY DOCKET NO. 50-389 ST. LUCIE PLANT UNIT NO. 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 202 Renewed License No. NPF-16

1.

The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A The application for amendment by Florida Power & Light Company dated December 20, 2018, as supplemented by letter dated June 28, 2019, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2.

Renewed Facility Operating License No. NPF-16 is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and by amending paragraph 3.8 to read as follows:

B.

Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 202, are hereby incorporated in the renewed license. FPL shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 90 days of issuance.

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications Date of Issuance: January 27, 2020 FOR THE NUCLEAR REGULA TORY COMMISSION Undine Shoop, Chief Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

ATTACHMENT TO LICENSE AMENDMENT NO. 202 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-16 ST. LUCIE PLANT, UNIT NO. 2 DOCKET NO. 50-389 Replace page 3 of Renewed Facility Operating License No. NPF-16 with the attached page 3.

The revised page is identified by amendment number and contains a marginal line indicating the area of change.

Replace the following pages of the Appendix A Technical Specifications with the attached page.

The revised page is identified by amendment number and contains marginal lines indicating the area of change.

Remove Insert 3/4 8-5 3/4 8-5 3/4 8-6 3/4 8-6 3/4 8-7 3/4 8-7 3/4 8-7a 3/4 8-7a 3/4 8-7b neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required.

D.

Pursuant to the Act and 10 CFR Parts 30, 40, and 70, FPL to receive, possess, and use in amounts as required any byproduct, source, or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and E.

Pursuant to the Act and 10 CFR Parts 30, 40, and 70, FPL to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

3.

This renewed license shall be deemed to contain and is subject to the conditions specified in the following Commission's regulations: 10 CFR Part 20, Section 30.34 of 10 FR Part 30, Section 40.41 of 10 CFR Part 40, Section 50.54 and 50.59 of 10 CFR Part 50, and Section 70.32 of 10 CFR Part 70; and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified below:

A.

Maximum Power Level FPL is authorized to operate the facility at steady state reactor core power levels not in excess of 3020 megawatts (thermal).

B.

Technical Specifications The Technical Specifications contained in Appendices A and 8, as revised through Amendment No. 202, are hereby incorporated in the renewed license.

FPL shall operate the facility in accordance with the Technical Specifications.

Renewed License No. NPF-16 Amendment No. 202

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS <continued}

c.

Verify fuel oil properties of new and stored fuel oil are tested in accordance with, and maintained within the limits of the Diesel Fuel Oil Testing Program.

d.

DELETED

e.

In accordance with the Surveillance Frequency Control Program by:

1.

DELETED

2.

3.

ST. LUCIE - UNIT 2 NOTE Credit may be taken for unplanned events that satisfy this SR.

Verifying generator capability to reject the single largest post-accident load while maintaining voltage at 4160.+/-. 420 volts and frequency at 60.+/-. 1.2 Hz.

NOTE Credit may be taken for unplanned events that satisfy this SR.

Verifying the generator capability to reject a load of 3685 kW without tripping. The generator voltage shall not exceed 4784 volts during and following the load rejection.

3/4 8-5 Amendment No. afl,-444, 4§§,

473,202

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS <Continued}

4.

5.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying that upon an actual or simulated loss-of-offsite power signal by itself:

a.

Deenergization of the emergency busses and load shedding from the emergency busses.

b.

The diesel starts on the auto-start signal,**** energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads.

After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160 +/- 210 volts and 60 +/- 0.6 Hz during this test.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying that upon an actual or simulated ESF actuation signal (without loss-I of-offsite power) the diesel generator starts**** on the auto-start signal, and:

a)

Within 10 seconds, generator voltage and frequency shall be 4160 +/- 420 volts and 60 +/- 1.2 Hz.

b)

Operates on standby for greater than or equal to 5 minutes.

c)

Steady-state generator voltage and frequency shall be 4160 +/- 210 volts and 60 +/- 0.6 Hz and shall be maintained throughout this test.

- - - This test may be conducted in accordance with the manufacturer's recommendations concerning engine prelube period.

ST. LUCIE - UNIT 2 3/4 8-6 Amendment No. JB, 4-ed, 202

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

6.

7.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying that upon an actual or simulated loss-of-offsite power in conjunction with an ESF actuation signal:

a)

Deenergization of the emergency busses and load shedding from the emergency busses.

b)

The diesel starts on the auto-start signal,**** energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected emergency (accident) loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160.+/-. 21 O volts and 60.+/-. 0.6 Hz during this test.

c)

Verifying that all automatic diesel generator trips, except engine overspeed and generator differential, are automatically bypassed upon loss of voltage on the emergency bus concurrent with a safety injection actuation signal.

NOTE Credit may be taken for unplanned events that satisfy this SR.

Verifying the diesel generator operates for at least 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .**** During the first 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of this test, the diesel generator shall be loaded within a load band of 3800 to 3985 kW and during the remaining 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months of this test, the diesel generator shall be loaded within a load band of 3450 to 3685 kv.J#.

The generator voltage and frequency shall be 4160.+/-. 420 volts and 60.+/-. 1.2 Hz within 10 seconds after the start signal; the steady-state generator voltage and frequency shall be maintained within these limits during this test.

8.

DELETED This band is meant as guidance to avoid routine overloading of the engine. Variations in load in excess of this band due to changing bus loads shall not invalidate this test.

- - - This test may be conducted in accordance with the manufacturer's recommendations concerning engine prelube period.

ST. LUCIE - UNIT 2 3/4 8-7 AmendmentNo.Je,eG,78,89,202

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS <Continued}

9.

10.

NOTE This Surveillance shall not normally be performed in MODE 1, 2, 3 or 4.

However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy th is SR.

Verifying the diesel generator's capability to:

a)

Synchronize with the offsite power source while the generator is loaded with its emergency loads upon actual or simulated restoration of offsite power signal.

b)

Transfer its load to the offsite power source, and c)

Be restored to its standby status.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

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

11.

DELETED

12.

NOTE This Surveillance shall not normally be performed in MODE 1 or 2.

However, the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verifying that the automatic load sequence timers are operable with the interval between each load block within.+/-.1 second of its design interval.

13.

Performing Surveillance Requirement 4.8.1.1.2a.4 within 5 minutes of shutting down the diesel generator after it has operated within a load band of 3450 kW to 3685 kW for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or until operating temperatures have stabilized.

This band is meant as guidance to avoid routine overloading of the engine. Variations in load in excess of this band due to changing bus loads shall not invalidate this test.

ST. LUCIE - UNIT 2 3/4 8-7a Amendment No. 39, -78, 424, 4-+J,483,202

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued}

f.

In accordance with the Surveillance Frequency Control Program or after any modifications which could affect diesel generator interdependence by starting****

the diesel generators simultaneously, during shutdown, and verifying that the diesel generators accelerate to approximately 900 rpm in less than or equal to 1 O seconds.

g.

In accordance with the Surveillance Frequency Control Program by performing a pressure test of those portions of the diesel fuel oil system designed to Section Ill, subsection ND of the ASME Code in accordance with the lnservice Inspection Program.

4.8.1.1.3 Reports - (Not Used).

4.8.1.1.4 The Class 1 E underground cable system shall be demonstrated OPERABLE within 30 days after the movement of any loads in excess of 80% of the ground surface design basis load over the cable ducts by pulling a mandrel with a diameter of at least 80% of the duct's inside diameter through a duct exposed to the maximum loading (duct nearest the ground's surface) and verifying that the duct has not been damaged.

- .... This test may be conducted in accordance with the manufacturer's recommendations concerning engine prelube period.

ST. LUCIE - UNIT 2 3/4 8-7b Amendment No. 202

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NOS. 250 AND 202 TO RENEWED FACILITY OPERATING LICENSE NOS. DPR-67 AND NPF-16 FLORIDA POWER & LIGHT COMPANY. ET AL.

1.0 INTRODUCTION

ST. LUCIE PLANT, UNIT NOS. 1 AND 2 DOCKET NOS. 50-335 AND 50-389 By application dated December 20, 2018 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML18354A901 ), as supplemented by letter dated June 28, 2019 (ADAMS Accession No. ML19179A132), Florida Power & Light Company (the licensee) requested changes to the technical specifications (TSs) for the St. Lucie Plant, Unit Nos. 1 and 2 (St. Lucie 1 and 2), which are contained in Appendix A of Renewed Facility Operating License Nos. DPR-67 and NPF-16. The licensee proposed to modify selected emergency diesel generator (EOG) surveillance requirements (SRs) to allow for their performance during power operations and to relocate two EOG SRs to licensee control.

The supplement dated June 28, 2019, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC or the Commission) staff's original proposed no significant hazards consideration determination as published in the Federal Register on May 21, 2019 (84 FR 23077).

2.0 REGULATORY EVALUATION

2.1.

System Description

2.1.1 Offsite Power System In addition to distributing the electrical power generated by St. Lucie 1 and 2, the offsite transmission system is designed to provide power to one or both of the plants for operation of the plant onsite auxiliary power system during startup, or for plant operation, shutdown, or accident conditions. Two separate 230 kilovolt (kV) transmission circuits connect the St. Lucie switchyard to the system transmission grid at the Midway substation. A third 230 kV circuit connects to the Treasure substation. Each transmission circuit connecting the St. Lucie switchyard and the substations is capable of handling the total plant output of either St. Lucie 1 or 2. A fourth transmission line connected to the St. Lucie switchyard from the Turnpike substation is located underground. The Turnpike line has been sized to meet the same capabilities of each of the three transmission lines connected to the St. Lucie switchyard. A six-bay, 230 kV switchyard provides switching capability for each main generator output, each of the two startup transformers per unit, and the four outgoing transmission lines. Each of the main generators supplies electrical power at 22 kV through an isolated phase bus to the two main transformers and two auxiliary transformers per unit. The main transformer steps up the voltage to 230 kV for transmission to the St. Lucie switchyard. The auxiliary transformers step down the voltage and feed the units' 6.9 kV bus and 4.16 kV bus. Normal transfer of the 6.9 kV or 4.16 kV busses between the auxiliary transformer and the startup transformer is performed by Control Room operators. Emergency transfer from the auxiliary to the startup transformer is automatically initiated by protective relay action. In the event of a complete loss of offsite power (LOOP), station onsite emergency alternating current (AC) power will be supplied by the EDGs and station batteries.

2.1.2 Onsite Power System Each onsite auxiliary power system is designed to supply the functional requirements of all auxiliary loads required for all modes of plant operation. The auxiliary power distribution system distributes the electrical power to plant components through a network of busses, transformers, switches, and related equipment. Plant auxiliary power is distributed throughout each unit by two 6.9 kV busses and five 4.16 kV busses. Each of the 6.9 kV busses supplies two reactor coolant pump motors and one feedwater pump motor. The 4.16 kV distribution system consists of two normal operation power busses that receive power from the auxiliary or startup transformers and three emergency busses. Depending on plant conditions, the three emergency busses receive power from either the normal 4.16 kV busses or the two standby EDGs.

2.1.3 Emergency Diesel Generators The standby AC power source consists of two redundant Class 1 E EOG sets per unit (1A and 1 B for St. Lucie 1 and 2A and 28 for St. Lucie 2). The EDGs are supplied with air starting systems, fuel supply systems, and automatic control circuitry. Each EOG consists of two diesel engines mounted in tandem with a generator coupled directly between the engines. The St. Lucie 1 EDGs are rated at 3,500 kilowatts (kW), each, while the St. Lucie 2 EDGs are rated at 3,800 kW, each. In the event of a loss of preferred AC power supply, the EDGs supply power to those electrical loads needed to achieve safe shutdown of the plant or to mitigate the consequences of a design-basis accident. In such an event, each diesel generator set is automatically started and loaded by controls and circuitry that are independent of the controls and circuitry used to start and load the redundant unit. The EDGs have sufficient capacity to supply the minimum necessary engineered safeguards loads with only one EOG operating.

Local and control room alarms are provided for all conditions causing diesel generator lockout, even if a lockout is overridden. Local and control room annunciation are also provided. The licensee's analyses demonstrate that both St. Lucie 1 and 2 can successfully withstand and recover from a loss of all offsite and onsite AC power, in compliance with the station blackout rule, Title 1 O of the Code of Federal Regulations ( 1 O CFR) Section 50.63.

The capability exists for periodic testing of the EDGs under load when normal bus supply is from the unit auxiliary transformer. If normal AC power is lost during testing, the EOG breaker will open. After attaining normal frequency and voltage, the EOG breaker will close and immediately start all loads belonging to the first block for which "starting required" signals are present from engineered safety features(ESF) actuation signals or from circuit conditions indicating that they were previously running.

2.2 Licensee's Proposed Changes The current TSs prohibit the testing required by SR 4.8.1.1.2.e to be performed in Mode 1 (Power Operation) or Mode 2 (Startup). The proposed amendments would revise TS 3.8.1 to remove the mode restriction from SR 4.8.1.2.e and allow testing pertaining to selected EOG SRs to be performed in any operating mode. The proposed amendments would also revise TS 3.8.1 to relocate two EOG SRs to licensee control. The proposed changes are described below.

2.2.1 Mode Restriction Removal The licensee proposed to remove the mode restriction from SR 4.8.1.1.2.e as indicated below (deletion shown in stricken text):

e.

In accordance with the Surveillance Frequency Control Program ~

shutdown by:

2.2.2 Adding Unplanned Event Credit Note SR 4.8.1.1.2.e.2 and SR 4.8.1.1.2.e.6 (St. Lucie 1)

SR 4.8.1.1.2.e.2, SR 4.8.1.1.2.e.3, and SR 4.8.1.1.2.e. 7 (St. Lucie 2)

The licensee proposed to add a note to the above SRs for EOG partial-load rejection testing, EOG full-load rejection testing, and EOG 24-hour endurance testing, as indicated below:

~---------------~-----NOTE---------------------------------------~---

Credit may be taken for unplanned events that satisfy this SR.

2.2.3 Relocating Single-Load Rejection Testing Numerical Values The licensee proposed to replace the numerical values for the single load rejection testing with the written description of the numerical values. The numerical values will be placed in the TS Bases, as indicated by the deletions shown in stricken text and additions underlined:

SR 4.8.1.1.2.e.2 ( St. Lucie 1)

2.

Verifying generator capability to reject a load of greater than or equal to 600 1:$ the single largest post-accident load while maintaining voltage at 4160 +/-

420 volts and frequency at 60 +/- 1.2 Hz.

SR 4.8.1.1.2.e.2 (St. Lucie 2)

2.

Verifying generator capability to reject a load of greater than or equal to 453 kW the single largest post-accident load while maintaining voltage at 4160 +/-

420 volts and frequency at 60 +/- 1.2 Hz.

The above numerical values would be relocated to the TS Bases and any changes to those values would be subject to the TSs Bases Control Program required by TS 6.8.4.j, which includes provisions to ensure that the Bases are maintained consistent with the Updated Final Safety Analysis Report (UFSAR). The TS Bases will specify the largest post-accident load and the numerical value to be specified in plant test procedures.

2.2.4 Adding Flexibility and Unplanned Event Credit Note for Partial SRs (Mode 1 or 2)

SR 4.8.1.1.2.e.3, SR 4.8.1.1.2.e.4, SR 4.8.1.1.2.e.5, and SR 4.8.1.1.2.e.9 (St. Lucie 1)

SR 4.8.1.1.2.e.4, SR 4.8.1.1.2.e.5, SR 4.8.1.1.2.e.6, and SR 4.8.1.1.2.e.10 (St. Lucie 2)

The licensee proposed to add a note to the above SRs for EOG LOOP testing, EOG ESF actuation testing, EDG ESF actuation coincident with LOOP testing, and EDG test mode override testing, as indicated below:

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

This Surveillance shall not normally be performed in MODE 1 or 2. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

2.2.5 Adding Flexibility and Unplanned Event Credit Note (MODE 1 or 2)

The licensee proposed to add a note to SR 4.8.1.1.2.e.11 (St. Lucie 1) and SR 4.8.1.1.2.e.12 (St. Lucie 2) for EDG load sequence timer testing, as indicated below:

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

This Surveillance shall not normally be performed in MODE 1 or 2. However, the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR.

2.2.6 Adding Flexibility and Unplanned Event Credit Note (MODE 1, 2, 3 or 4)

The licensee proposed to add a note to SR 4.8.1.1.2.e.8 (St. Lucie 1) and SR 4.8.1.1.2.e.9 (St. Lucie 2) for EDG load sequence timer testing, as indicated below:

NOTE--------------------------------------*---------

This Surveillance shall not normally be performed in MODE 1, 2, 3 or 4.

However, the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines that the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

2.2.7 Requiring Verification of EDG Operability Upon Actual or Simulated Signal The licensee proposed to revise its TSs to require verification of EDG operability upon an actual or simulated signal and revise text to relocate the word "verifying," making conforming changes to be consistent with the Combustion Engineering (CE) STS, as indicated below (deletions shown in stricken text and additions underlined). The change would allow either an actual or a simulated signal to be credited.

St. Lucie 1 SR 4.8.1.1.2.e.3

3.

Simulating a Verifying that upon an actual or simulated loss of offsite power signal by itself-aoo:

a)

Verifying dDeenergization of the emergency busses and load shedding from the emergency busses.

b)

Verif},1ing tihe diesel starts on the auto-start signal****, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160 +/- 210 volts and 60 +/- 0.6 Hz during this test.

SR 4.8.1.1.2.e.4

4.

Verifying that upon an actual or simulated GA-aR ESF actuation signal (without loss-of-offsite power) the diesel generator starts**** on the auto-start signal, and:

SR 4.8.1.1.2.e.5

5.

Simulating a Verifying that upon an actual or simulated loss-of-offsite power signal in conjunction with an ESF actuation test-signal,-aoo~

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

b) Verif},1ing tihe diesel starts on the auto-start signal****, energizes the emergency busses with permanently connected loads within 1 O seconds, energizes the auto-connected emergency (accident) loads through the auto-sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160 +/- 210 volts and 60 +/- 0.6 Hz during this test.

c) Verifying that aAII automatic diesel generator trips, except engine overspeed and generator differential, are automatically bypassed upon loss of voltage on the emergency bus concurrent with a safety injection signal.

SR 4.8.1.1.2.e.8

8.

Verifying the diesel generator's capability to:

a) Synchronize with the offsite power source while the generator is loaded with its emergency loads upon a simulated actual or simulated restoration of offsite power.

SR 4.8.1.1.2.e.9

9.

Verifying that with the diesel generator operating in a test mode {connected to its bus}, a an actual or simulated safety injection signal overrides the test mode by {1) returning the diesel generator to standby operation and

{2) automatically energizes the emergency loads with offsite power.

St. Lucie 2 SR 4.8.1.1.2.e.4

4.

Simulating a Verifying that upon an actual or simulated loss-of-offsite power signal by itself,-aREI:

a. Verifying dDeenergization of the emergency busses and load shedding from the emergency busses.

b. Verifying tihe diesel starts on the auto-start signal,**** energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160 +/- 210 volts and 60 +/- 0.6 Hz during this test.

SR 4.8.1.1.2.e.5

5.

Verifying that GR upon an actual or simulated ESF actuation test signal (without loss-of-offsite power) the diesel generator starts**** on the auto-start signal, and:

SR 4.8.1.1.2.e.6

6.

Simulating a Verifying upon a loss-of-offsite power in conjunction with an ESF actuation test signal,-aREI~

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

b) Verifying tihe diesel starts on the auto-start signal,**** energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected emergency (accident) loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160 +/- 210 volts and 60 +/- 0.6 Hz during this test.

SR 4.8.1.1.2.e.9

9.

Verifying the diesel generator's capability to:

a) Synchronize with the offsite power source while the generator is loaded with its emergency loads upon a simulated an actual or simulated restoration of offsite power signal.

SR 4.8.1.1.2.e.10

10. Verifying that with the diesel generator operating in a test mode (connected to its bus), a an actual or simulated safety injection signal overrides the test mode by (1) returning the diesel generator to standby operation and (2) automatically energizes the emergency loads with offsite power.

2.2.8 Relocating EOG 2000-Hour Rating Verification Requirement The licensee proposed to remove the EOG 2000-hour rating verification testing as indicated below (deletions shown in stricken text and additions underlined). Section 3.4.1 of the license amendment request (LAR) indicated that it would be relocated to plant procedural control whereby future changes will be subject to 10 CFR 50.59 requirements:

SR 4.8.1.1.2.e.7 (St. Lucie 1)

7.

Verifying that the auto oonne~ed loads do not exceed the 2000 hour0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months rating of 3730 lw1.DELETED SR 4.8.1.1.2.e.8 (St. Lucie 2)

8.

Verifying that the auto connected loads do not exceed the 2000 hour0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months rating of 3935 Kw.DELETED 2.2.9 Relocating EOG Fuel Oil Transfer Pump Cross-Connection Testing Requirement The proposed change would remove the EOG fuel oil transfer pump cross-connection testing from the above SRs, as indicated below (deletions shown in stricken text and additions underlined) and relocate it to plant procedural control where future changes would be subject to 10 CFR 50.59 requirements:

SR 4.8.1.1.2.10 (St. Lucie 1)

10. Verifying that tho fuel transfer pump transfers f.uol from each f.uol storage tank to the engine mounted tanks of each diesel 'lia the installed cross conne~ion lines.DELETED SR 4.8.1.1.2.11 (St. Lucie 2)

11. Verifying that the fuel transfer pump transfers fuel from each f.uel storage tank to the engine mounted tanks of each diesel *iia the installed cross connection lines. DELETED 2.3 Regulatory Review The NRC staff reviewed the licensee's application to determine whether (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that the activities proposed will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or the health and safety of the public. The NRC staff considered the following regulatory requirements, guidance, and licensing and design-basis information during its review of the proposed changes.

Section 50.36(a)(1) of 10 CFR states, in part, that each applicant for an operating license shall include in the application proposed TSs in accordance with the requirements of 10 CFR 50.36, "Technical specifications." Section 50.36(c) of 10 CFR requires that the TSs include items in the following categories: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation; (3) SRs; (4) design features; and (5) administrative controls. Section 50.36(c)(3) of 10 CFR states that SRs 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.

Section 50.59 of 10 CFR allows a licensee to make changes in the facility described in the UFSAR, make changes in the procedure described in the UFSAR, and conduct tests or experiments not described in the UFSAR without obtaining a license amendment if (1) no TS change is required, and (2) the change, test, or experiment does not meet any of the criteria in 10 CFR 50.59(c)(2). Section 50.59 of 10 CFR also requires that each licensee maintain records of any changes under 10 CFR 50.59(c), including a written evaluation that provides the basis for its determination that the criteria in 10 CFR 50.59(c)(2) are not met.

Appendix A, "General Design Criteria (GDC) for Nuclear Power Plants," to 10 CFR Part 50 establishes the minimum requirements for the principal design criteria for water-cooled nuclear power plants. The following GDC are applicable for this review:

GDC 17, "Electric Power Systems," states, in part, that an onsite electric power system and an offsite electric power system be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences, and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. 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.

GDC 18, "Inspection and Testing of Electric Power Systems," states, in part, that electric power systems important to safety shall be designed to permit appropriate periodic inspection and testing of important areas and features.

NUREG-1432, Volume 1, Revision 4, "Standard Technical Specifications [STSs] - Combustion Engineering Plants" (ADAMS Accession No. ML12102A165), contains the STSs for CE plants.

Although the St. Lucie1 and 2 TSs are not based on the guidance in NUREG-1432, the STS present an acceptable method for licensees of CE plants to meet the NRC's requirements in 10 CFR 50.36.

3.0 TECHNICAL EVALUATION

The NRC staff evaluated the licensee's application to determine if the proposed changes are consistent with the guidance, regulations, and plant-specific design and licensing basis information discussed in Section 2.3 of this safety evaluation.

The NRC staff's evaluation of the proposed changes considered several potential plant conditions that could be encountered while performing testing required by SRs while at power.

The NRC staff reviewed information pertaining to the electrical power systems in the application, the updated final safety analysis report, and applicable TS limiting conditions for operation to verify the capability of the affected electrical power systems to perform their safety functions (assuming no additional failures of electrical components) is maintained. Consequently, the NRC staff reviewed the EDG responses to the most challenging events such as LOOP, loss-of-coolant accident (LOCA), or a LOOP coincident with a LOCA, while the EDG under surveillance testing is at power. The NRC staff's evaluation of the proposed changes is provided below.

3.1 Evaluation of Impact on Safe Operation of the Plant As described in the LAR, and its supplement, the EDG under test is declared inoperable for the test duration. The redundant EDG remains available to respond to any accident or transient. In the event of a unit trip, power to the auxiliary sources is automatically and independently transferred from the "A" and "B" auxiliary transformers to the unit's corresponding "A" and "B" startup transformers. To protect the 4.16 kV safety-related busses from main generator or offsite power fluctuations, each bus is provided with Class 1 E loss of voltage protection relay, degraded-voltage protection relay (DVR), and isolation breakers that are connected to and monitor the 4.16 kV safety-related busses. Upon detection of an undervoltage, the relays will separate the 4.1.6 kV safety-related busses from the offsite power source and transfer the busses to the EDGs. The loss of voltage protection relay and DVR are 100 percent independent between the "A" and "B" electrical trains such that protection of the 4.16 kV safety-related busses is unaffected by upstream interconnections of the auxiliary transformers, startup transformers, main generator, main transformers, and switchyard. Both relays respond in sufficient time to prevent damage to plant equipment. A secondary set of DVRs arms within 1 O seconds of a degraded voltage condition such that upon a subsequent safety injection actuation signal_. the 4.16 kV SR busses automatically separate from offsite power.

Because the EDG under test is declared inoperable for the test duration and the redundant electrical train, including the associated EDG and support systems, remains operable, and would respond to any accident or transient as required, the station would remain within its licensing basis in response to any design-basis event for the duration of the EDG test run while at power. Therefore, the NRC staff finds that performing surveillance testing for the EDG at power would have minimal impact on the safe operation of the plant.

3.2 Evaluation of Effects on Electrical Distribution System The LAR states, in part, that the 24-hour endurance test will not cause electrical perturbations because the testing involves no simulated signal that disrupts connectivity to the electrical distribution system. Administrative controls prevent paralleling the redundant EOG to the offsite grid during the testing in order to prevent any disturbances to the electrical system from affecting the availability of emergency AC power. Historical load rejection testing during plant shutdowns has demonstrated little impact on the plant's electrical system because the voltage perturbation on the bus supplying the loads is not significant, and protective instrumentation and relaying exist that mitigate the effects of any disturbances.

Therefore, because administrative controls prohibit paralleling the redundant EOG to the offsite grid during the testing to prevent disturbances to the electrical system, and because protective instrumentation would be available to protect plant loads in response to any sustained low grid-voltage condition, the NRC staff finds that performing the EOG surveillance testing in Mode 1 or 2 would have minimal impact on the electrical distribution system. In addition, Limiting Condition for Operation (LCO) 3.8.1.1 and TS 6.8.4.s and TS 6.8.4.t, Safety Function Determination Program requirements for Units 1 and 2, respectively, would ensure the opposite train EOG remains capable of performing its safety function. Thus, the change would not significantly impact EOG availability or EOG capability to provide the standby AC power.

3.3 Evaluation of Effects on Grid Stability Grid stability is a function of the overall grid configuration where all electrical power lines and equipment are connected or synchronized, and the balance of the generation is compared to the grid loading. Once the EOG voltage has been synchronized with the grid voltage, the paralleling circuit breaker can be closed. When the paralleling circuit breaker has closed, the generator set and grid supplies are then "paralleled." At this stage the EOG set output is normally zero, so it is contributing no power to the paralleled system. The NRC staff notes that the grid stability could be challenged when the EOG that is under test is paralleled with the offsite power grid. This could be a concern when performing the load rejection test or during the 24-hour endurance test.

In the LAR, the licensee stated, in part, that administrative controls preclude paralleling the redundant EOG to the offsite grid or performing the load rejection testing during periods of grid instability, severe weather, or switchyard maintenance. The online aggregate risk assessment employs the use of the probabilistic safety analysis calculations in support of risk assessments for online maintenance activities, a safety train analysis to ensure adequate separation of out-of-service ESFs equipment, and consideration for environmental factors such as severe weather and other challenges to grid stability.

Administrative controls would preclude either paralleling the redundant EOG to the offsite grid or performing the load rejection testing during periods of grid instability. In addition, the risk assessment supporting at-power testing will consider environmental factors such as severe weather and other challenges to grid stability. This risk assessment is required to be performed in accordance with the licensee's Configuration Risk Management Program (CRMP), which is described in the licensee's administrative procedure that implements the Maintenance Rule pursuant to 10 CFR 50.65. Therefore, the NRC staff finds that performing the EOG surveillance testing at power would have minimal impact on the grid stability. In addition, LCO 3.8.1.1, and TS 6.8.4.s and TS 6.8.4.t, Safety Function Determination Program requirements for Units 1 and 2, respectively, would ensure the opposite train diesel remains in service. Thus, the change would not significantly impact EOG availability or EOG capability to provide the standby AC power.

3.4 Evaluation of Response to LOOP and/or LOCA In the LAR, the licensee described the response of the EOG under test, should a LOOP and/or LOCA occurred during the performance of the load rejection and endurance testing as follows:

LOOP Response In MODES 1 and 2, receipt of a LOOP signal with an EOG operating in parallel with off-site power results in the diesel output breaker not immediately tripping and separating the EDG from off-site power. The closed EOG output breaker blocks the under-voltage protective relays that initiate load shed on the associated emergency bus. As the only source of power for loads connected to the emergency (safety) and normal (non-safety) 4.16 kV busses, the EOG under test will likely trip on over-current protection. Tripping on overcurrent protection generates a lockout signal which causes the EDG to shut down and trip open the output breaker. Once the output breaker opens, the load-shed 4.16 kV under-voltage protective relays automatically unblock, detect the loss of voltage, separate the emergency bus from the normal supply bus, and isolate the emergency bus by stripping its loads. During this time, the EDG is prevented from starting and the output breaker is prevented from closing and supplying power to the emergency bus. However, within minutes, operators stationed in the vicinity of the EDG would manually reset the lockout relay allowing the EOG to restart, and after reaching nominal frequency and voltage, automatically closing the output breaker. The required safe shutdown loads would then be sequenced onto the emergency bus as designed. The redundant EDG and associated emergency loads would be unaffected by the EDG under test and would respond as designed.

LOCA Response In MODES 1 and 2, with an EOG operating in parallel with off-site power, a LOCA would generate an ESF actuation signal which would immediately trip the EDG output breaker as well as the reactor, turbine and main generator. The main turbine trip causes a fast bus transfer from the auxiliary to the startup transformer such that the 6.9 kV and 4.16 kV busses are powered from off-site via the startup transformer. Since no loss of voltage is present on the 4.16 kV emergency bus, load shedding is not initiated and the EDG output breaker remains open with its EOG running in standby mode at rated frequency and voltage. All required safety related loads are subsequently connected to the emergency bus powered from the off-site electrical grid. Failure of the EOG output breaker to open and isolate the EOG from the emergency bus when in test mode would not affect LOCA load sequencing since the LOCA response loads would be connected to the emergency bus with total load shared between the EDG and off-site power. The redundant EDG and engineered safeguards actuation equipment train responds similarly to a LOCA signal by starting its EDG and leaving it disconnected from the emergency bus since off-site power is available.

LOCA Coincident with LOOP Response In MODES 1 and 2, upon receipt of a LOOP preceding a LOCA, the EOG under test responds as addressed in the LOOP discussion above. In MODES 1 and 2, upon receipt of a LOOP following or coincident with a LOCA, there is no impact on proper loading of the EOG under test. The LOCA/LOOP signal with an EOG operating in parallel with off-site power results in the EOG output breaker tripping. Due to the LOCA/LOOP signal, a trip of the reactor, turbine and main generator occurs. Loss of voltage on the 4.16 kV emergency bus causes it to automatically separate from the normal supply bus and trip its loads. With the EOG running at normal frequency and voltage, its output breaker recloses and commences load sequencing of the emergency loads. After the EDG reaches normal frequency and voltage, its output breaker closes and starts all loads belonging to the first load block. Subsequent loads required to mitigate the LOCA are sequenced back onto the bus in a predetermined order to prevent overloading the EOG. The redundant EOG and engineered safeguards actuation equipment train will also respond to a LOCA/LOOP condition by starting its EOG and shedding the emergency bus loads.

In summary, the occurrence of LOCA with or without a LOOP while an EOG under test is operating in parallel with off-site electrical grid would have no effect on the design basis LOCA response. A LOOP event with an EOG operating in parallel with off-site power could delay the EOG from powering its respective safeguards train. However, plant operators would be stationed in close proximity to restore the EOG capability to power its engineered safeguards equipment train in minutes. In addition, the redundant EOG would be available to power its associated safeguards train.

Typically, during the EOG surveillance testing, the under-test EOG will be declared inoperable, and the opposite train EOG, which is not affected by the EOG testing, would be able to provide the safety function. The NRC staff finds that performing EOG surveillance testing while at power would have minimal impact on the response to LOOP and/or LOCA because the remaining EOG is required to remain capable of performing the safety function by LCO 3.8.1.1.

3.5 Evaluation of Surveillance Testing At Power for Satisfying SRs The licensee proposes to perform the following EOG testing at power:

3.5.1 Load Rejection Testing SR 4.8.1.1.2.e.2 (St. Lucie 1 and 2)

SR 4.8.1.1.2.e.3 (St. Lucie 2 only)

The LAR states that the proposed change would allow EOG single-load (both units) and full-load (St. Lucie 2 only) rejection testing during power operation for the purpose of satisfying surveillance testing requirements. Consistent with the CE STS TS 3.8.1, the proposed change adds a note that states that credit may be taken for activities in response to unplanned events, including actual events, that are equivalent to the required SRs. The station would remain within its licensing basis in response to the most challenging design-basis event during the at-power testing. At-power load rejection testing will not adversely affect plant safety systems or cause significant electrical perturbations that challenge plant safety. During at-power load rejection testing, the EOG would be declared inoperable for only a few hours of the 14-day completion time allotted by TS 3.8.1.1, Action (b). Administrative controls preclude paralleling the redundant EOG to the offsite grid or performing the rejection testing during periods of grid instability, severe weather, switchyard maintenance, etc. In addition, LCO 3.8.1.1, and TS 6.8.4.s and TS 6.8.4.t, Safety Function Determination Program requirements for Units 1 and 2, respectively, would ensure the opposite train EOG remains capable of performing its safety function.

The licensee also proposed to replace the numerical values for the single load rejection testing with the written description of the numerical values. The numerical values will be placed in the TS Bases. In the LAR, the licensee stated that relocating the numerical value of the single largest load to the TS Bases alleviates the need for an amendment request in the event that changes to safety analysis assumptions (e.g. pump efficiency) necessitate a change to the required rejection load. The TS Bases will specify the largest post-accident load (intake cooling water pump) and the numerical value to be specified in plant test procedures.

As discussed in Section 3.4 above, the under-test EOG will be declared inoperable, and the other train EOG, which is not affected by the testing, would be able to provide the standby on site power safety function. Therefore, the NRC staff finds that performing load rejection testing in Mode 1 or 2 would have minimal impact on the safe operation of the plant, electrical distribution, grid stability, and response to LOOP and/or LOCA, and is acceptable. The proposed change that adds a note to the SRs identified above allowing credit for unplanned events that satisfy the SRs is acceptable, because the change is consistent with the CE STS, and because actuation of the equipment due to an unplanned event is sufficient to demonstrate operability. The NRC staff also finds that removing the numerical values for the single-load rejection testing is acceptable because a) the proposed change is consistent with SR 3.8.1.9 of CE STS, which refers to the "single largest post-accident load," but does not specify a numerical value for the required rejection load, b) any future changes would be subject to TS 6.8.4.j, which requires that changes to the TS Bases be evaluated under 10 CFR 50.59 and which has provisions to ensure that the Bases are maintained consistent with the UFSAR, and c) the change will have no effect on EOG capacity to perform its safety function.

3.5.2 24-Hour Endurance Testing SR 4.8.1.1.2.e.6 (St. Lucie 1)

SR 4.8.1.1.2.e. 7 (St. Lucie 2)

The LAR states that during the performance of the at-power 24-hour endurance testing, the EOG is electrically configured the same as during the monthly surveillance test required by SR 4.8.1.1.2.a.5, the only difference being the test duration. Administrative controls (e.g., plant procedures) ensure that the 24-hour endurance run would not be scheduled during periods of potential grid or bus disturbances such as severe weather conditions or maintenance activities affecting the electrical busses. The remaining EDGs and their support systems would remain operable, and no more than one EOG is paralleled with the grid at any time.

As discussed in Section 3.4, above, the under-test EOG will be declared inoperable, and the other train EOG, which is not affected by the EOG testing, would be able to provide the safety functions. Therefore, the NRC staff finds that performing 24-hour endurance testing in Mode 1 or 2 would have minimal impact on the safe operation of the plant, electrical distribution, grid stability, and response to LOOP and/or LOCA. Accordingly, the proposed changes are acceptable.

3.5.3 Hot Restart Testing SR 4.8.1.1.2.e.13 (St. Lucie 2 only)

The LAR states that the St. Lucie 2 EDGs are water-cooled and maintained at hot standby conditions by means of heated cooling water and lubricating oil. As such, they are not subject to temperature rise transients upon being tripped, and therefore, are not prone to the restart failures typical of some air-cooled EDGs. Hence, hot restart testing at power is not likely to impact plant equipment or cause unplanned entry into TS actions. The LAR also states that the proposed change is consistent with SR 3.8.1.15 of the CE STS, which does not impose mode restrictions on EOG hot restart testing.

The proposed deletion of the words "during shutdown" in SR 4.8.1.1.e, above, would remove the mode restriction on this testing. The U.S. Nuclear Regulatory Commission (NRC or the Commission) staff finds that performing hot restart testing in Mode 1 or 2 would have minimal impact on the safe operation of the plant because the St. Lucie 2 EDGs are not subject to temperature rise transients upon being tripped. The staff also finds that the proposed change is consistent with CE STS SR 3.8.1.15. Therefore, the proposed change is acceptable.

3.6 Evaluation of Surveillance Testing At Power for Restoring Operability 3.6.1 Surveillance Testing in Mode 1 or 2 The proposed change adds a note indicating that the surveillance shall not normally be performed in Mode 1 or 2, but allowing the performance of load sequence timer testing (SR 4.8.1.1.2.e.11 for St. Lucie 1 and SR 4.8.1.1.2.e.12 for St. Lucie 2) in Mode 1 or 2 for the purpose of restoring operability, provided an assessment determines that the safety of the plant is maintained or enhanced. The note also states that credit may be taken for unplanned events that satisfy the SR.

In the LAR, the licensee also stated that, consistent with the CE STS, the TS Bases would be modified to describe the assessment.

The NRC staff finds that performing load sequence timer testing in Mode 1 or 2 would have minimal impact on the safe operation of the plant because the proposed note would require an assessment to be performed per the maintenance program (i.e., CRMP) to ensure that the safety of the plant is maintained or enhanced prior to conducting the surveillance testing. The NRC staff also finds that the statement in the proposed note that allows credit to be taken for activities in response to unplanned events that are equivalent to the required SRs is consistent with the CE STS SR 3.8.1.18. Therefore, the proposed change is acceptable.

3.6.2 Partial Surveillance Testing in Mode 1 or 2 The proposed change would add a note to allow the performance of portions of the following in Mode 1 or 2 for the purpose of restoring operability:

LOOP testing (SR 4.8.1.1.2.e.3 for St. Lucie 1 and SR 4.8.1.1.2.e.4 for St. Lucie 2)

ESF actuation testing (SR 4.8.1.1.2.e.4 for St. Lucie 1) and SR 4.8.1.1.2.e.5 (St. Lucie 2)

ESF actuation with concurrent LOOP testing (SR 4.8.1.1.2.e.5 for St. Lucie 1 and SR 4.8.1.1.2.e.6 for St. Lucie 2 Test mode override testing (SR 4.8.1.1.2.e.9 for St. Lucie 1 and SR 4.8.1.1.2.e.10 for St. Lucie 2)

The note also states that credit may be taken for unplanned events that satisfy the SR. The LAR states that the reason for partially performing SR testing at power is that performance of the entire SR could, in some cases, adversely impact plant safety. The NRC staff finds that performing partial testing for the above SRs in Mode 1 or 2 would have minimal impact on the safe operation of the plant because an assessment is required per the maintenance program (i.e., CRMP) and as a condition of the NOTE, to be performed to ensure that the safety of the plant is maintained or enhanced prior to conducting the surveillance testing. This is consistent with the CE STS, and staff finds this to be acceptable. The NRC staff also finds that the proposed addition of a note allowing credit to be taken for unplanned event activities that are equivalent to the required SRs and that would satisfy the SRs is acceptable because the change is consistent with the CE STS and because actuation of the equipment due to an unplanned event is sufficient to demonstrate operability.

3.6.3 Surveillance Testing in Mode 1, 2, 3, or 4 The proposed change adds a note that allows the EDG restoration of offsite power testing (SR 4.8.1.1.2.e.8 for St. Lucie 1 and SR 4.8.1.1.2.e.9 for St. Lucie 2) to be performed in Mode 1, 2, 3 (Hot Standby), or 4 (Hot Shutdown) for the purpose of restoring operability. The note also states that credit may be taken for unplanned events that satisfy the SR.

The NRC staff finds that performing testing for the above SRs in Mode 1, 2, 3, or 4 would have minimal impact on the safe operation of the plant because an assessment is required to be performed per the maintenance program (i.e., CRMP) to ensure that the safety of the plant is maintained or enhanced prior to conducting the surveillance testing. The NRC staff also finds that the addition of the note allowing credit to be taken for activities in response to unplanned events that are equivalent to the required SRs is acceptable because the change is consistent with the CE STS and because actuation of the equipment due to an unplanned event is sufficient to demonstrate operability.

3. 7 Evaluation of Requiring Verification of EDG Operability Upon Actual or Simulated Signal SR 4.8.1.1.2.e.3, SR 4.8.1.1.2.e.4, SR 4.8.1.1.2.e.5, SR 4.8.1.1.2.e.8, and SR 4.8.1.1.2.e.9 (St. Lucie 1)

SR 4.8.1.1.2.e.4, SR 4.8.1.1.2.e.5, SR 4.8.1.1.2.e.6, SR 4.8.1.1.2.e.9, and SR 4.8.1.1.2.e.1 O (St. Lucie 2)

The licensee proposed to revise these TSs to require verification of EDG operability upon an actual or simulated signal, and to revise text by relocating the word "verifying" and making conforming changes to be consistent with the CE STS, as indicated below (deletions shown in stricken text and additions underlined). The changes would allow either an actual or a simulated signal to be credited.

The NRC staff finds that the changes that require verification of EDG operability upon an actual or simulated signal and rewording the TSs are consistent with the CE STSs. These changes are reasonable because actuation of the equipment via an actual signal is sufficient to demonstrate operability. Therefore, the proposed changes are acceptable.

3.8 Evaluation of SR Relocation The following SRs are proposed to be relocated to licensee control:

3.8.1 Relocating 2000-Hour Rating Verification Testing SR 4.8.1.1.2.e. 7 (St. Lucie 1) and SR 4.8.1.1.2.e.8 (St. Lucie 2) verify that the auto-connected load to each EOG does not exceed the 2000-hour rating of 3,935 kW.

As described in the LAR, SR 4.8.1.1.2.e. 7 (St. Lucie 1) and SR 4.8.1.1.2.e.8 (St. Lucie 2) derive from Safety Guide 9, "Selection of Diesel Generator Set Capacity for Standby Power Supplies,"

dated August 10, 1971 (ADAMS Accession No. ML12305A251), which states, in part, that at the operating license stage of review, the predicted loads should not exceed the 2,000-hour rating.

The maximum post-accident loading has been historically verified to be less than the 2,000-hours rating during safeguards testing and is not expected to change without a physical change to the station conducted in accordance with the licensee's design-control process. The licensee further stated that since the 2,000-hours rating verification test is an acceptable means to ensure plant safety analyses assumptions will be met, it is unnecessary to demonstrate EOG operability. The licensee, therefore, requested the SR to be relocated to plant procedural control whereby future changes will be subject to the regulatory controls of 10 CFR 50.59.

The NRC staff finds that removing the 2000-hour rating requirement from the TSs is acceptable because a) it is consistent with the CE STS, b) the existing 24-hour endurance testing requirements of SR 4.8.1.1.2.e.6 (Unit 1) and SR 4.8.1.1.2.e. 7 (Unit 2) requires the EOG testing at the loading ranges that bound the 2000-hour test load rating for time periods sufficient to confirm operability, and c) the 2000-hour rating test is being relocated to plant procedural control whereby future changes will be subject to the regulatory controls of 10 CFR 50.59.

3.8.2 Relocating Fuel Oil Transfer Pump Cross-Connection Testing SR 4.8.1.1.2.e.10 (St. Lucie 1)

SR 4.8.1.1.2.e.11 (St. Lucie 2)

The licensee stated that the proposed change would relocate the EOG fuel oil transfer pump cross-connection testing from the above SRs to plant procedural control whereby future changes will be subject to 10 CFR 50.59 requirements. The above SRs require verification of capability of transferring fuel from each fuel storage tank to the engine mounted tank via the cross-connection pipe.

As noted in NUREG-0800, Section 9.5.4, a minimum of a 7-day supply of fuel oil for each diesel generator system should be onsite to meet the engineered safety feature load requirements following a loss of offsite power and a design-basis accident (OBA). For Unit 1, both diesel oil storage tanks (DOSTs) and the associated fuel transfer cross-connection piping are necessary to assure the availability of a 7-day supply of diesel fuel to either EOG. For Unit 1, TS 3.8.1.1 requires that each EOG maintain a separate fuel storage system containing a minimum of 19,000 gallons of fuel and a separate fuel transfer pump. As a result, the licensee retains the availability of a 7-day supply and the capability to transfer fuel from the DOST to the associated EOG day tank.

SR 4.8.1.1.2.a.3 (St. Lucie 1 and 2) requires verification of fuel transfer pump capability to start and transfer fuel from the fuel storage tank to the engine mounted tank via the cross-connection pipe. The NRC staff concludes that performing the testing required by SR 4.8.1.1.2.a.3, including the valve alignment check, would detect deterioration of the fuel transfer capability to either EOG, and therefore, would also satisfy the requirements of SR 4.8.1.1.2.e.10 (St. Lucie 1) and SR 4.8.1.1.2.e.11 (St. Lucie 2). Therefore, the NRC staff finds that relocating the EOG fuel oil transfer pump cross-connection testing from SR 4.8.1.1.2.e.10 (St. Lucie 1) and SR 4.8.1.1.2.e.11 (St. Lucie 2) to licensee control, whereby future changes will be subject to the regulatory controls of 10 CFR 50.59, would have minimal impact on the safe operation of the plant and is acceptable.

3.9 Technical Conclusion The NRC staff reviewed the licensee's proposed changes to TS 3/4.8.1. Specifically, the proposed changes would remove mode restrictions for performance of selected EOG SRs, allow credit for unplanned events, and relocate two EOG SRs to licensee control. These SRs are currently prohibited to be performed in Mode 1 or 2. By removing the mode restrictions, the proposed amendments would allow the above SRs to be performed in all modes of operation.

Based on the above evaluations, the NRC staff concludes that the proposed TS changes will allow the licensee to continue to meet the intent of GDC 17 and GDC 18 concerning the availability, capacity, and capability of the electrical power systems. The NRC staff finds that the proposed changes are consistent with the requirements of 10 CFR 50.36(c)(3) because the revised S_Rs relating to test, calibration, or inspection continue 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. Therefore, the NRC staff considers the proposed changes in the LAR acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the NRC staff notified the.State of Florida official (Ms. Cynthia Becker, M.P.H., Chief of the Bureau of Radiation Control, Florida Department of Health) on October 2, 2019, of the proposed issuance of the amendments. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change requirements with respect to the use of facility components located within the restricted area as defined in 10 CFR Part 20 or SRs. The NRC staff has determined that the amendments involve no significant increase in the amounts and no significant change in the types of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding, which was published in the Federal Register on May 21, 2019 (84 FR 23077), that the amendments involve no significant hazards consideration, and there has been no public comment on such finding. Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b),

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

6.0 CONCLUSION

The Commission has concluded, based on the aforementioned considerations, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributor: K. Nguyen Da~: January 27, 2020

ML19266A072

b memorandum

- b e-mail OFFICE NRR/DORULPL2-2/PM NRR/DORULPL2-2/LA NRR/DE/EEOB/BC*

NAME MWentzel LRonewicz DWilliams DATE 10/01/2019 09/30/2019 08/28/2019 OFFICE NRR/DSS/SCPB/BC(A)

NRR/DSS/STSB/BC OGC (NLO) w/edits**

NAME SJones (NKaripineni for)

VCusumano MYoung DATE 09/27/2019 10/17/2019 01/08/2020 OFFICE NRR/DORULPL2-2/BC NRR/DORULPL2-2/PM NAME UShoop NJordan DATE 01/24/2020 01/27/2020

v t e Letter Sequence Approval
EPID:L-2018-LLA-0574, TSTF-425 (Approved, Closed)
Initiation Request Acceptance Administration Questions 21 May 2019 31 May 2019 Answers 28 June 2019 Results Approval Other:
MONTHYEAR2019-05-21 [Table View]

ML19266A072

Text

SUBJECT:

Dear Mr. Moul:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

System Description

3.0 TECHNICAL EVALUATION

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

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