Text

Issuance of Exigent Amendment No. 248 Technical Specification 3/4.8.1 Change to Allow for a One-Time Extension of the Allowed Outage Time for One Emergency Diesel Generator
	ML19203A166
Person / Time
Site:	Saint Lucie
Issue date:	07/26/2019
From:	Michael Wentzel; Plant Licensing Branch II
To:	Moul D; Florida Power & Light Co
	Wentzel,Michael, NRR/DORL/LPL2-2
References
	EPID L-2019-LLA-0152
	Download: ML19203A166 (32)
	v • d • e

UNITED STATES WASHINGTON, D.C. 20555.0001 July 26, 2019 Mr. Don Moul Vice President, Nuclear Division and Chief Nuclear Officer Florida Power & Light Company Mail Stop: NT3/JW 15430 Endeavor Drive Jupiter, FL 33478

SUBJECT:

ST. LUCIE PLANT, UNIT NO. 1 - ISSUANCE OF EXIGENT AMENDMENT NO. 248 REGARDING TECHNICAL SPECIFICATIONS CHANGE TO ALLOW A ONE-TIME EXTENSION OF THE ALLOWED OUTAGE TIME FOR ONE INOPERABLE EMERGENCY DIESEL GENERATOR (EPID L-2019-LLA-0152)

Dear Mr. Moul:

The U.S. Nuclear Regulatory Commission (NRC or the Commission) has issued the enclosed Amendment No. 248 to Renewed Facility Operating License No. DPR-67 for St. Lucie Plant, Unit No. 1. The amendment changes the Technical Specifications in response to the application from Florida Power & Light Company dated July 19, 2019, as supplemented by letters dated July 24, 2019, and July 25, 2019.

The amendment revises the Technical Specifications to allow for a one-time extension of the allowed outage time for one inoperable emergency diesel generator from 14 days to 30 days.

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

Sincerely, Michae;~~~~ect Manager Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-335

Enclosures:

1. Amendment No. 248 to DPR-67

2. Safety Evaluation cc: Listserv

UNITED STATES FLORIDA POWER & LIGHT COMPANY DOCKET NO. 50-335 ST. LUCIE PLANT UNIT NO. 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 248 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 (FPL, the licensee), dated July 19, 2019, as supplemented by letters dated July 24, 2019, and July 25, 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.

Enclosure 1

2.

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.B to read as follows:

B. Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 248, 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 immediately.

FOR THE NUCLEAR REGULATORY COMMISSION Undine Shoop, Chief Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications Date of Issuance: July 2 6, 2 O1 9

ATTACHMENT TO LICENSE AMENDMENT NO. 248 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-67 ST. LUCIE PLANT, UNIT NO. 1 DOCKET NO. 50-335 Replace page 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 page of the Appendix A Technical Specifications with the attached page.

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

Remove Insert 3/4 8-1 3/4 8-1

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 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 B, as revised through Amendment No. 248, 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.

C. 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 10 CFR 50.59 and otherwise complies with the requirements in that section.

D. 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. 248

3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES OPERATING LIMITING CONDITION FOR OPERATION 3.8.1.1 As a minimum, the following A.C. electrical power sources shall be OPERABLE:

a. Two physically independent circuits between the offsite transmission network and the onsite Class 1E distribution system, and

b. Two separate and independent diesel generator sets each with:

1. Engine-mounted fuel tanks containing a minimum of 152 gallons of fuel,

2. A separate fuel storage system containing a minimum of 19,000 gallons of fuel, and

3. A separate fuel transfer pump ..

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

a. With one offsite circuit of 3.8.1.1.a inoperable, except as provided in Action f.

below, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and at least once

per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter. Restore the offsite circuit to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or in accordance with the Risk Informed Completion Time Program, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . LCO 3.0.4.a is not applicable when entering HOT SHUTDOWN.

NOTE If the absence of any common-cause failure cannot be confirmed, Surveillance Requirement 4.8.1.1.2.a.4 shall be completed regardless of when the inoperable EOG is restored to OPERABILITY.

b. With one diesel generator of 3.8.1.1.b inoperable, demonstrate the OPERABILITY of the A.C. sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter; and if the EOG became inoperable due to any cause other than an inoperable support system, an independently testable component, or preplanned preventative maintenance or testing, demonstrate the OPERABILITY of the remaining OPERABLE EOG by performing Surveillance Requirement 4.8.1.1.2.a.4 within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , unless it can be confirmed that the cause of the inoperable EDG does not exist on the remaining EOG; restore the diesel generator to OPERABLE status within 14 days* or in accordance with the Risk Informed Completion Time Program, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Additionally, within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from the discovery of concurrent inoperability of required redundant feature(s) (including the steam driven auxiliary feed pump in MODE 1, 2, and 3), declare required feature(s) supported by the inoperable EDG inoperable if its redundant required feature(s) is inoperable.

A one-time AOT extension for the inoperable 1B EOG allows 30 days to restore the EOG to OPERABLE status. Compensatory Measure within FPL Letter L-2019-153 dated July 25, 2019 will remain in effect during the extended AOT period. This extension expires on August 14, 2019 at 0736 hours0.00852 days 0.204 hours 0.00122 weeks 2.80048e-4 months EDT.

ST. LUCIE - UNIT 1 3/4 8-1 Amendment No. 4-03, ~ . ~ . 4+0,

.:t-SG.~.234.247,248

UNITED STATES SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 248 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-67 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT, UNIT NO. 1 DOCKET NO. 50-335

1.0 INTRODUCTION

By application dated July 19, 2019 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML19200A283), as supplemented by letters dated July 24, 2019, and July 25, 2019 (ADAMS Accession Nos. ML19205A407 and ML19206A658, respectively),

Florida Power & Light Company (the licensee) requested changes to the Technical Specifications (TSs) for St. Lucie Plant, Unit No. 1 (St. Lucie 1), which are contained in Appendix A of Renewed Facility Operating License No. DPR-67. The licensee proposed to revise TS 3/4.8.1, "AC. [Alternating Current] Sources," to allow for a one-time extension of the allowed outage time (AOT) for one inoperable emergency diesel generator (EOG) from 14 days to 30 days.

The licensee submitted this request under exigent circumstances to avoid unnecessary operational transients, consistent with the requirements in Title 10 of the Code of Federal Regulations (10 CFR) Section 50.91(a)(6), which states that exigent circumstances exist when a licensee and the U.S. Nuclear Regulatory Commission (NRC or the Commission) must act quickly, and time does not permit the NRC to publish a Federal Register notice allowing 30 days for prior public comment.

2.0 REGULATORY EVALUATION

2.1. System Description The following description of the St. Lucie 1 AC power system is reproduced from the licensee's July 19, 2019, license amendment request (LAR):

The normal source of auxiliary AC power for plant start-up or shutdown is from the incoming off-site transmission lines through the plant switchyard and start-up transformers. The start-up transformers step down the 230 kV [kilovolt] incoming line voltage to 6.9 kV and 4.16 kV for auxiliary system use. During normal plant operation, AC power is provided from the main generator through the unit Enclosure 2

auxiliary transformers. The unit auxiliary transformers step down the main generator output voltage from 22 kV to 6.9 kV and 4.16 kV.

In the event of a complete loss of the normal offsite AC power sources, i.e. Loss of Offsite Power (LOOP), station on-site emergency AC power system will be supplied by the on-site EDGs and station batteries.

The 4.16 kV system consists of normal and emergency buses. Normal buses provide power to loads which are non-safety related. All safety related loads are powered from the emergency buses. There are two normal buses (1A2 and 182) which receive power directly from the unit auxiliary or start-up transformers.

The emergency portion of the 4.16 kV system is arranged into two redundant load groups (A and B). Each of these load groups consists of the complement of safety related equipment needed to achieve safe plant shutdown and/or to mitigate the consequences of a design basis accident. Additional safety related equipment (e.g., the third component cooling and intake cooling water pumps) is arranged as a "third service" or "swing" load group AB. This load group consists of equipment which can be used as back-up or replacement to the equipment in either of the main redundant load groups A or B. Load group A is powered from the emergency bus 1A3 and load group B from the emergency bus 183.

Emergency bus 1AB serves load group AB. Additionally, the two safety related "swing" 4.16 kV busses 1AB and 2AB can be inter-connected between Units 1 and 2 via the SBO [station blackout] crosstie connection.

Whenever the normal power sources are available, power is supplied directly to the 4.16 kV system through the two normal buses, each of which is tied to one of the redundant emergency buses. Emergency bus 1AB is normally tied to either (but never both) emergency bus 1A3 or 183. The tie breakers of bus 1AB are interlocked electrically to prevent this bus from being simultaneously connected to both buses 1A3 and 183.

Upon a loss of the normal power sources, the crosstie breakers between the normal and emergency buses will automatically open and the EDGs will automatically start and begin supplying power directly to the emergency buses.

The standby AC power source consists of two redundant EDGs, their attendant air starting and fuel supply system, and automatic control circuitry. The EDGs supply power to those electrical loads which are needed to achieve safe shutdown of the plant or to mitigate the consequences of a loss of coolant accident (LOCA) in the event of a coincident LOOP.

Each diesel generator consists of two diesel engines mounted in tandem with a 3500 kw [kilowatt] generator coupled directly between the engines. Each engine in each diesel generator set has a self-contained cooling system which consists of a forced circulation cooling water system which cools the engine directly and an air cooled radiator system which removes the heat from the cooling water.

The cooling water pump and radiator fan are driven directly from the engine crankshaft. After starting, the diesel generator set cooling system requires no external source of power and does not depend on any plant cooling system.

2.2 Licensee's Proposed Changes By letter dated July 24, 2019, the licensee supplemented its July 19, 2019, LAR to request the deferral of certain surveillance requirements on the remaining EDGs until after the completion of the proposed extended AOT. By letter dated July 25, 2019, the licensee withdrew its request to defer performance of the surveillance requirements based on the current repair schedule for the 1B EDG. The licensee stated that its July 25, 2019, letter replaced the July 24, 2019, letter in its entirety. As a result, the NRC staff only reviewed the changes requested in the licensee's July 19, 2019, LAR, as supplemented by the licensee's letter dated July 25, 2019.

The licensee proposed to revise TS Limiting Condition for Operation (LCO) 3.8.1.1, ACTION b, as follows (additional text shown underlined):

b. With one diesel generator of 3.8.1.1.b inoperable, demonstrate the OPERABILITY of the AC. sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter; and if the EDG became inoperable due to any cause other than an inoperable support system, an independently testable component, or preplanned preventative maintenance or testing, demonstrate the OPERABILITY of the remaining OPERABLE EDG by performing Surveillance Requirement 4.8.1.1.2.a.4 within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , unless it can be confirmed that the cause of the inoperable EDG does not exist on the remaining EDG; restore the diesel generator to OPERABLE status within 14 days~ or in accordance with the Risk Informed Completion Time Program, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Additionally, within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from the discovery of concurrent inoperability of required redundant feature(s) (including the steam driven auxiliary feed pump in MODE 1, 2, and 3), declare required feature(s) supported by the inoperable EDG inoperable if its redundant required feature(s) is inoperable.

A one-time AOT extension for the inoperable 1B EDG allows 30 days to restore the EDG to OPERABLE status. Compensatory Measure within FPL Letter L-2019-153 dated July 25, 2019 will remain in effect during the extended AOT period. This extension expires on August 14, 2019 at 0736 hours0.00852 days 0.204 hours 0.00122 weeks 2.80048e-4 months EDT.

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 amendment 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.

The regulations at 10 CFR 50.36(a)(1) state, 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." Paragraph 50.36(c) of 10 CFR requires that the TSs include items in the following categories related to station operation: (1) safety limits, limiting

safety system settings, and limiting control settings; (2) LCOs; (3) surveillance requirements; (4) design features; and (5) administrative controls. Paragraph 50.36(c)(2) of 10 CFR states, in part, that when an LCO is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the TSs until the condition can be met.

The regulations at 10 CFR 50.63, "Loss of all alternating current power," require, in part, that a nuclear power plant shall be able to withstand for a specified duration and recover from a complete loss of offsite and onsite AC sources (i.e., a station blackout (SBO)).

The regulations at 10 CFR 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," require, in part, that performing maintenance activities shall not reduce the overall availability of the systems, structures, and components, which are important to safety.

The construction permit for St. Lucie 1 was issued prior to the 1971 publication of Appendix A, "General Design Criteria (GDC) for Nuclear Power Plants," to 10 CFR Part 50. As such, St. Lucie 1 is not licensed to the current GDC. Although not licensed to the GDC, Section 8.1.2.2 of the St. Lucie 1 Updated Final Safety Analysis Report (UFSAR) states that the St. Lucie 1 onsite electrical power systems meet the requirements of GDC 17, "Electric Power Systems." GDC 17 provides, in part, that an onsite electric power system and an offsite electric power system shall 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 electrical power sources, including the batteries, and the onsite electrical distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure.

Regulatory Guide (RG) 1.93, "Availability of Electric Power Sources" (ADAMS Accession No. ML090550693), provides guidance with respect to operating restrictions or completion time (CT) (referred to as AOT in this evaluation) if the number of available AC sources is less than that required by the TS LCO. In particular, this guide recommends a maximum CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for an inoperable onsite or offsite AC source.

RG 1.155, "Station Blackout" (ADAMS Accession No. ML003740034 ), provides guidance for complying with the requirements of 10 CFR 50.63, which require nuclear power plants to be capable of coping with an SBO event for a specified duration.

RG 1.174, Revision 3, "An Approach for Using Probabilistic .Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" (ADAMS Accession No. ML17317A256), describes a risk-informed approach acceptable to the NRC for assessing the nature and impact of proposed licensing-basis changes by considering engineering issues and applying risk insights. This RG also provides risk acceptance guidelines for evaluating the results of such evaluations.

RG 1.177, Revision 1, "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications" (ADAMS Accession No. ML100910008), describes an acceptable risk-informed approach specifically for assessing proposed one-time TS changes in CTs. This

RG also provides risk acceptance guidelines for evaluating the results of such assessments and contains five key principles that TS changes should meet. They are: ( 1) the proposed change meets the current regulations unless it is explicitly related to a requested exemption or rule change; (2) the proposed change is consistent with the defense-in-depth philosophy; (3) the proposed change maintains sufficient safety margins; ( 4) when proposed changes result in an increase in core-damage frequency or risk, the increases should be small and consistent with the intent of the Commission's Safety Goal Policy Statement; and (5) the impact of the proposed change should be monitored using performance measurement strategies.

RG 1.177 provides the following three-tiered TS acceptance guidelines specific to one-time only CT changes for evaluating the risk associated with the revised CT:

1. The licensee has demonstrated that implementation of the one-time only TS CT change impact on plant risk is acceptable (Tier 1):

ICCDP [incremental conditional core damage probability of less than 1.0x10-6 and an incremental ICLERP [incremental conditional large early release probability] of less than 1.0x10-7 , or

ICCDP of less than 1.0x10*5 and an ICLERP of less than 1.0x10-6 with effective compensatory measures implemented to reduce the sources of increased risk.

2. The licensee has demonstrated that there are appropriate restrictions on dominant risk-significant configurations associated with the change (Tier 2).

3. The licensee has implemented a risk-informed plant configuration control program. The licensee has implemented procedures to utilize, maintain, and control such a program (Tier 3).

RG 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (ADAMS Accession No. ML090410014),

describes an acceptable approach for determining whether the quality of the probabilistic risk assessment (PRA) models, in total, or the parts that are used to support an application, is sufficient to provide confidence in the results such that the PRA models can be used in regulatory decision-making for light-water reactors.

NUREG-0800, "Standard Review Plan [SRP] for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR Edition," Chapter 16.1, Revision 1, "Risk-Informed Decision Making: Technical Specifications" (ADAMS Accession No. ML070380228), states that licensees submitting risk information should address each of the principles of risk-informed regulation addressed in RG 1.177.

SRP Chapter 19, Section 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance" (ADAMS Accession No. ML071700658), provides general guidance for evaluating the technical basis for proposed risk-informed changes that envelop one-time changes. Guidance on evaluating PRA technical adequacy is provided in Section 19.1, "Determining the Technical Adequacy of Probabilistic Risk Assessment for Risk-Informed License Amendment Requests After Initial Fuel Load" (ADAMS Accession No. ML12193A107).

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 (SE).

3.1 Method of Staff Review An acceptable approach for making risk-informed decisions about proposed TS changes, including both permanent and temporary changes, is to show that the proposed changes meet the five key principles stated in RG 1.174, Section 2, and RG 1.177, Section B. These key principles are:

Principle (1 ): The proposed change meets the current regulations unless it is explicitly related to a requested exemption.

Principle (2): The proposed change is consistent with the defense-in-depth philosophy.

Principle (3): The proposed change maintains sufficient safety margins.

Principle (4 ): When the proposed change results in an increase in core damage frequency (CDF) and/or large early release frequency (LERF), the increase should be small and consistent with the intent of the Commission's Safety Goal Policy statement.

Principle (5): The impact of the proposed change should be monitored by using performance measures strategies.

The key information used in the NRC staff's review of the licensee's risk evaluation is contained in Section 3.2 of the LAR dated July 19, 2019, as supplemented by the licensee's letters dated July 24, 2019, and July 25, 2019. To support the assessment of the licensee's PRA capability for use in the risk evaluation, the NRC staff also reviewed the SEs in support of the NRC staff's approval of both the licensee's request to adopt risk-informed completion times (RICTs) in the St. Lucie 1 and 2 TSs, dated July 2, 2019 (RICT Amendments; ADAMS Accession No. ML19113A099), and the licensee's request to transition to a National Fire Protection Association Standard 805 (NFPA 805)-based fire-protection program (NFPA 805 Amendments, dated March 31, 2016; ADAMS Accession No. ML15344A346).

3.2 Key Principle 1: The Proposed Change Meets Current Regulations The regulations at 10 CFR 50.36(c) specify the requirements for TSs. The licensee's proposed one-time change to TS LCO 3.8.1.1, Action b, to increase the AOT for one inoperable EOG affects the maximum allowed time to have only one EOG OPERABLE without shutting down the reactor. The licensee's request does not deviate from the requirements to comply with this regulation nor any other regulation. Therefore, the NRC staff concludes that the licensee's proposed change is in compliance with existing regulations.

3.3 Key Principle 2: The Proposed Change is Consistent with Defense-in-Depth Philosophy The proposed LAR requests a one-time extension of TS LCO 3.8.1.1, Action b AOT for an inoperable EOG from 14 days to 30 days. During the proposed AOT extension, Units 1 and 2 will be in Mode 1.

The purpose of the proposed one-time change to TS LCO 3.8.1.1, Action b, is to extend the EOG AOT from the current 14 days to 30 days to allow the licensee to perform repair and maintenance activities on EOG 1B. The longer AOT would help the licensee avert potential unplanned shutdown by providing margin for the performance of corrective activities that are needed to restore EOG 1B to an OPERABLE status.

The NRC staff evaluated the licensee's request to extend the AOT for EOG 1B to determine whether the decrease in severe accident risk achieved with the implementation of the SBO requirements in 10 CFR 50.63 would be eroded. The request was also evaluated to ensure that the overall availability of onsite and offsite power systems will not be adversely impacted to significantly reduce safe shutdown capability of Units 1 and 2 because of the extended AOT required to conduct the maintenance activities.

In the LAR, the licensee stated:

EOG capacity is such that any three of the four diesels can supply all required loads for the safe shutdown of both units without offsite power. Each of the four EDGs can supply one of the four separate Class 1E emergency busses. Each is started automatically on a loss of offsite power (LOOP) or Loss of Coolant Accident (LOCA). The EOG arrangement provides adequate capacity to supply the ESF [engineered safety feature] loads for the Design Basis Accident, assuming the failure of a single active component in the system.

The design and licensing basis of St Lucie 1 states that each of the load groups (A or B) on each unit has a complete set of safety-related equipment needed to achieve safe plant shutdown and/or to mitigate the consequences of a design-basis accident.

During the AOT entry for TS LCO 3.8.1.1, the LCO is not met due to the inoperable EOG, and the redundancy required by the TS LCO (in operating modes) as specified by GDC 17 will not be maintained. The regulations at 10 CFR 50.36(c)(2) permit a limited period of time to restore the inoperable train to OPERABLE status and/or take other remedial measures when the necessary redundancy is not maintained (e.g., one train in a redundant train system is inoperable). If these actions are not completed within the AOT, the TSs normally require that the plant exit the mode of applicability for the LCO. For St. Lucie 1, with train 1B of a two-train onsite power system inoperable, the TS safety function is accomplished by the remaining 1A OPERABLE train. In the current TSs, the specified AOT is a maximum time of 14 days to restore train 1B to OPERABLE status. The extension of the AOT to 30 days is beyond the guidance provided in RG 1.93 and reduces the defense-in-depth incorporated in the design of the plant for 30 days. However, the safe shutdown capability for postulated accident conditions and abnormal operational occurrences is retained. The compensatory actions implemented by the licensee provide reasonable assurance that two offsite sources and three EDGs (two on Unit 2 and one on Unit 1) will be available during normal operation and mitigating the consequences of an accident at one unit while supporting safe shutdown of the other unit. In

the remote event of a dual-unit LOOP coupled with accident conditions in one unit, at least one EDG will be available at each unit to support safe shutdown of the units.

The LAR also states:

St. Lucie's coping time during SBO is not affected by the proposed change. The coping time is calculated based on guidance provided in Nuclear Utility Management and Resource Council (NUMARC) 87-00, Guidelines and Technical Bases for NU MARC Initiatives Addressing Station Blackout at Light Water Reactors, Revision 1, August 1991 [ADAMS Accession No. ML102710587].

During a SBO, the most significant requirement is to quickly restore AC power.

RG 1.155 provides a method for demonstrating conformance to the SBO rule promulgated in 10 CFR 50.63. RG 1.155 also endorses NUMARC 87-00 guidelines as an acceptable method for conforming to the SBO regulation. As stated in the St. Lucie 1 UFSAR, in the unlikely event of a total loss of AC power, both onsite and offsite (SBO) and a loss of one EDG on St. Lucie 1, power can be provided to one of the Unit 2 Class 1E redundant divisions from the only available site EDG set. The power will be transferred via a crosstie connecting the safety-related swing switchgear (1AB and 2AB) of the two units.

By letter dated July 25, 2019, the licensee provided clarification on SBO coping duration for the two Units:

Section 15.10 of the Unit 2 UFSAR contains the SBO analysis. This analysis shows that St. Lucie Unit 2 can successfully endure a complete loss of AC power for at least 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . However, it is expected that AC power would be restored within 30 minutes to one hour as a result of either one of the following corrective actions:

a. Offsite power is restored;

b. One or both of the St. Lucie Unit 2 diesel generators are started.

No credit is given for Unit 1 EDGs, but the DC [direct current] coping capability is further enhanced by the ability to provide power to the one division of the Class 1E distribution system from the available Unit 1 EDG. Even though the amount of power available to Unit 2 loads under a Station Blackout scenario (only one EDG operation on Unit 1) is limited by plant procedures as not to affect Unit 1 safe shutdown, it can be used to power selected loads, i.e., battery chargers, UPS [uninterruptable power supply], certain fans, etc.

Section 15.2.13 of the Unit 1 UFSAR contains the SBO analysis. As stated, Unit 1 is a four-hour SBO coping plant. At 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , The DC coping period is assumed to end when the Unit 1 4160V 1AB bus and Unit 2 4160V 2AB bus are manually connected and AC power is available to Unit 1, based on excess Unit 2 EOG capacity. After 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , either offsite power is restored or one or both St. Lucie 1 EDGs are started, thus terminating the event.

Based on the information provided by the licensee, the NRC staff agrees that accident mitigating capabilities and SBO coping capability at St. Lucie can be managed during the

proposed AOT. The NRC staff determined that 30-day AOT is acceptable as it allows sufficient time to restore EOG 1B to OPERABLE status and avoids a plant transient.

Pursuant to the requirements of 10 CFR 50.65, the licensee has implemented a program for monitoring the effectiveness of maintenance at St. Lucie. The program requires, in part, that performing maintenance activities shall not reduce the overall availability of the systems, structures, and components, which are important to safety. This program also ensures that EOG reliability is maintained at or above the SBO target level, and the effectiveness of maintenance on the EDGs and support systems is monitored. Although the licensee is requesting a 30-day AOT, the licensee plans to restore the 1B EOG to an OPERABLE status as soon as possible to minimize plant risk and minimize the impact on reliability factors monitored under the 10 CFR 50.65 program.

3.3.1 Use of Compensatory Measures to Retain Defense-in-Depth During the implementation of extended AOT, the licensee will implement compensatory actions for various plant maintenance configurations to maintain and manage acceptable risk levels.

The intent of the compensatory measures is to reduce the duration of risk-sensitive activities and avoid high-risk sensitive equipment outages or maintenance states that result in high-risk plant configurations.

By letter dated July 25, 2019, the licensee updated the planned compensatory actions provided in the LAR and denoted in the TSs for the duration of extended AOT requested for EOG 1B:

1. The availability of alternate AC (AAC) power sources shall be checked every 8-12 hours (once per shift). If an AAC power source (e.g., a Unit 2 emergency diesel generator (EOG)) becomes unavailable at any time during extended AOT, the unavailable ACC unit will be returned to service in the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , or Unit 1 will enter Mode 3 in the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

2. No elective load threatening tests or maintenance activities will be allowed (e.g.,

component testing or maintenance of safety systems and important nonsafety equipment in the offsite power systems which can increase the likelihood of a plant transient (unit trip or loss of offsite power (LOOP)).

3. Any other preplanned maintenance will be rescheduled if severe weather conditions are anticipated.

4. The system load dispatcher will be contacted once per day to ensure no significant grid perturbations (high grid loading unable to withstand a single contingency of line or generation outage) are expected during the extended AOT.

The licensee has developed procedure ADM-17 .16 related to implementation of the Configuration Risk Management Program. In accordance with this procedure, the following risk management actions will be implemented while in the extended AOT:

Conduct a plant fire protection walkdown of the areas that could impact EOG availability, offsite power availability, or the ability to use the SBO crosstie prior to entering the extended AOT.

Perform a thermographic examination of high-risk potential ignition sources in the Cable Spreading Room and the Control Room prior to entering the extended AOT.

Restrict planned hot work in the Cable Spreading Room and Control Room during the extended AOT.

Establish a continuous fire watch in the Cable Spreading Room when in the extended AOT.

A Unit 2 EDG or the SBO crosstie shall only be removed from service for corrective maintenance required to ensure or restore operability of the equipment.

Ensure that the relevant Guarded Equipment protected train measures have been taken.

Validate availability of the minimum required fire detection and/or functional suppression systems in the identified important Fire Zones to be protected per plant procedures. If not met, then initiate fire watches in the affected zones in accordance with the Fire Protection Plan.

Brief operators and fire team members on the significance of a fire in the identified important fire zones to be protected.

In addition to the above compensatory measures, the licensee has stated that existing plant procedures address monitoring weather conditions and ensuring that actions are taken in the event adverse conditions are expected on-site. Specifically, the licensee stated:

These actions, relevant during Hurricane Season, include housekeeping, flooding, and high wind preparation considerations. Also, the procedure places the unit outside the EDG limiting condition of operation (LCO) applicability for operating units (i.e., MODES 1 or 2) by directing a shutdown based on the hurricane category.

Upon issuance of a watch or warning which impacts the site, the following actions will be executed as required by the procedures for the watch or warning in effect:

Perform site walk-downs and eliminate or secure missile hazards.

Secure exterior cranes.

Ensure Unit 1 and Unit 2 Reactor Auxiliary Building (RAB) exterior doors are closed.

Ensure storm drain system capacity and the basin influent and discharge are clear of blockages.

Pump down yard sumps, Unit 1 RAB sumps and Unit 2 RAB sumps.

Verify RAB storage tanks have capacity for storm drainage.

Deploy the portable diesel fire pump for dewatering.

Perform a shiftly tail board with Operations Fire Team members to discuss the location of the fire equipment that has been relocated per plant procedures.

Obtain meteorological forecasts and data from the National Hurricane Center in Miami, Florida at least once per six hours during either a Hurricane Watch or a Hurricane Warning and enter in the narrative log.

Shutdown to at least HOT STANDBY (for Category 1, 2, or 3 hurricanes) or COLD SHUTDOWN (for Category 4 or 5 hurricanes) at least two hours prior to the onset of hurricane force winds at the site.

The NRC staff finds the proposed compensatory actions reasonable to reduce risk of complete loss of AC power required for safe shutdown of dual units. The NRC staff also finds the proposed actions to shutdown to at least HOT STANDBY prior to onset of hurricane force winds at the site reasonable to mitigate the risk from hurricanes.

3.3.2 Diverse and Flexible Mitigation Capability (FLEX) to Provide Defense-in-Depth On March 12, 2012, the NRC issued Order EA-12-049, "Issuance of Order to Modify Licenses with Regard to Requirements for Mitigation Strategies for Beyond-Design-Basis External Events" (ADAMS Accession No. ML12054A735). This order directed licensees to develop, implement, and maintain guidance and strategies to maintain or restore core cooling, containment and spent fuel pool cooling capabilities in the event of a beyond-design-basis external event. By letters dated May 12, 2015 (ADAMS Accession No. ML15140A393), and December 10, 2015 (ADAMS Accession No. ML15350A394), the licensee submitted compliance letters to Order EA-12-051 for Units 1 and 2, respectively. In addition, as stated above, the December 10, 2015, letter, as supplemented by letter dated March 21, 2016 (ADAMS Accession No. ML16096A338), provided the St. Lucie Final Integrated Plan in response to the order. The compliance letters stated that the licensee had achieved full compliance with Order EA-12-051. The results of the NRC staff's review of the licensee's strategies for St. Lucie are documented in a letter dated July 5, 2016 (ADAMS Accession No. ML16167A473).

In the July 5, 2016, letter, the NRC staff determined that the licensee's actions during an extended loss of all AC power (should it occur), including use of portable generators, provides additional defense-in-depth measures. The FLEX strategies provide reasonable assurance that in the event of an extended SBO during the proposed AOT, the long-term core cooling and spent fuel pool cooling will be managed until external resources are available.

3.3.3 EOG Failure Cause Determination In the LAR, the licensee stated that the apparent cause of this event is the failure of the radiator fan accessory drive coupling from a fatigue mechanism. The licensee's visual assessment indicates that the driving loads were a combination of both torsional and cyclic bending stresses. The licensee has identified numerous conditions that could result in high torsional or cyclic bending loads on the crankshaft, such as a nonfunctioning crankshaft vibration damper, misalignment of the fan power takeoff hollow shaft to the crankshaft coupling, bearing issues, or alignment of the power takeoff bearing pedestal.

The licensee stated that the 182 engine fan idler pulley shaft failed in 1988 and 1991 and that these failures may have caused some loading on the drive shaft, ultimately contributing to the high torsional loads on the crankshaft. There have been no similar failures on the other EDGs that may have contributed to stress concentrations in the radiator coupling. Also, the licensee barred over the 1A EOG, which has had successful surveillances in the past, and the radiator couplings were intact. As such, the licensee concluded that there is no similar degraded condition of the 1A EOG fan accessory drive coupling and no common cause exists.

The NRC staff has reviewed the licensee's failure cause determination, which states that the failure of the radiator fan accessory drive coupling was apparently caused by a fatigue mechanism, which was possibly caused by two fan idler pulley shaft failures in 1988 and 1991.

The NRC staff finds the licensee's assessment to be reasonable. The NRC assessment is based on the information provided by the licensee that the two fan idler pulley shaft failures may have contributed to the high torsional or cyclic bending loads on the crankshaft, which eventually led to a fatigue failure of the radiator coupling. The NRC staff also finds that the other EDGs are not susceptible to the same type of failure mechanism based on the information

provided by the licensee that they have not had any failures that would lead to high torsional or cyclic bending loads on the crankshafts of the other EDGs.

3.3.4 Defense-in-Depth Conclusion The NRC staff concludes that the LAR meets the guidance of RG 1.177, Section 2.2.1. The staff concludes that the licensee's request to revise TS LCO 3.8.1.1 to extend the AOT of an inoperable EOG 1B to OPERABLE status from the current 14 days to 30 days is acceptable from a defense-in-depth perspective. The NRC staff finds the proposed TS change will have no or minimal adverse impact on the licensee's compliance with 10 CFR Part 50, Appendix A, GDC 17; 10 CFR 50.36; 10 CFR 50.65; and 10 CFR 50.63.

3.4 Key Principle 3: The Proposed Change Maintains Sufficient Safety Margins The licensee will continue to meet the accident analysis requirements (considering no additional failure in safety-related equipment in any other train except those impacted by the 1B EOG outage). The NRC staff finds that there will be no or minimal reduction in safety margin.

3.5 Key Principle 4: Change in Risk is Consistent with the Safety Goal Policy Statement The evaluation below addresses the NRC staff's philosophy of risk-informed decision-making that when the proposed changes result in a change in risk, the increase should be small and consistent with the intent of the Commission's Safety Goal Policy Statement. The NRC staff's evaluation of Key Principle 4 for the proposed one-time TS change is described below.

3.5.1 Tier 1: PRA Capability and Insights The first tier evaluates the impact of the proposed change on plant operational risk. The Tier 1 review involves two aspects: ( 1) evaluation of the technical acceptability of the St. Lucie 1 PRA models and its application to the proposed change, and (2) evaluation of the PRA results and insights based on the licensee's proposed change.

Previous NRC Evaluation of St. Lucie 1 PRA Model Quality The NRC has previously reviewed the St. Lucie 1 internal events, internal flooding, and fire PRAs. (IEPRA, IFPRA, and FPRA, respectively) for determining their acceptability to support the licensee's RICT Amendments and NFPA 805 Amendments. To the extent applicable, the NRC staff used its previous PRA model acceptability evaluations in its review of PRA model acceptability for the risk analysis that supports this LAR.

3.5.1.1 Evaluation of PRA Acceptability RG 1.174 states that, "[t]he PRA scope and level of detail, should be commensurate with that required for a given activity as discussed in Sections C.2.3.1 and C.2.3.3 of this RG, respectively." The acceptability of the PRA must be compatible with the safety implications of the TS change being requested and the role that the PRA plays in justifying that change. That is, the more the potential change in risk or the greater the uncertainty in that risk from the requested TS change, or both, the more rigor that must go into ensuring the acceptability of the PRA. This applies to Tier 1, and it also applies to Tier 2 and Tier 3 to the extent that a PRA model is used.

RG 1.200, Revision 2, describes one acceptable approach for determining whether the technical elements of the PRA, in total, or the parts that are used to support an application, is sufficient to provide confidence in the results such that the PRA can be used in regulatory decision-making for light-water reactors. RG 1.200, Revision 2, endorses, with comments and qualifications, the use of: (1) the American Society of Mechanical Engineers/American Nuclear Society (ASME/ANS) PRA standard ASME/ANS RA-Sa-2009, "Addenda to ASME/ANS RA-S-2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications"; (2) Nuclear Energy Institute (NEI) 00-02, Revision 1, "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance" (ADAMS Accession No. ML061510619); and (3) NEI 05-04, Revision 2, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard" (ADAMS Accession No. ML083430462).

The ASME/ANS PRA standard provides technical supporting requirements in terms of three Capability Categories (CCs). The intent of the delineation of the Capability Categories within the supporting requirements is generally that the degree of scope and level of detail, the degree of plant specificity, and the degree of realism increase from CC I to CC Ill. In general, the staff anticipates that current good practice (i.e., CC II of the ASME/ANS standard) is adequate for the majority of applications.

On May 3, 2017, the NRC staff transmitted its review results of Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13, "Close-out of Facts and Observations" (F&Os) (ADAMS Accession No. ML17079A427). The NRC accepted Appendix X for use by licensees to close F&Os that were generated during a peer review process.

LAR Attachment 3, Section 2.0, states that the licensee employed the F&O closure process for F&Os associated with internal events, internal floods, and fire models. The close-out reviews were conducted in September 2017 and May 2019.

In its letter dated July 25, 2019, the licensee explained that FLEX equipment is not credited in the PRA evaluations for this application.

3.5.1.1.2 Internal Events and Internal Flooding The full-power IEPRA and IFPRA for St. Lucie 1 addressed both CDF and LERF. The licensee used RG 1.200, Revision 2, to address the technical acceptability of the IEPRA and IFPRA to assure these PRAs are capable of accurately characterizing the risk impact from internal events (including flooding) associated with the TS AOT extension for EOG 1B. Consistent with the guidance of RG 1.177 and RG 1.200, CC II of ASME/ANS RA-Sa-2009 was applied, and any identified deficiencies to those requirements (i.e., if either a supporting requirement was not met or met at CC I) were assessed further to determine any impacts to the risk evaluation.

As discussed in both the LAR and the RICT Amendments SE, the St. Lucie 1 IEPRA full scope peer review was performed in July 2002 by the Combustion Engineering Owners Group using NEI 00-02, Revision A.3, "Probabilistic Risk Assessment (PRA) Peer Review Guidance" (ADAMS Accession No. ML003728023), which pre-dated the ASME/ANS PRA standard and RG 1.200. A focused-scope peer review associated with LERF was performed by the Pressurized Water Reactor Owner's Group in July 2009 using the combined PRA standard, ASME/ANS-RA-Sb-2005, "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications," as clarified by RG 1.200, Revision 1 (ADAMS Accession No. ML070240001 ).

Focused-scope peer reviews were performed in August 2009 for the common cause failure

(CCF) methodology on April 2011 for the human reliability analysis, data, and internal flood (IF) technical elements, and in December 2013 for the interfacing system loss-of-coolant accident (ISLOCA) methodology and data using the combined PRA standard, ASME/ANS-RA-Sa-2009, as clarified by RG 1.200, Revision 2. Further, a few self-assessments were completed in October 2007 and March 2014 to identify potential gaps between the peer reviews and self-assessments performed using earlier revisions of the PRA standard and the current PRA ASME standard, ASME/ANS RA-Sa-2009, as clarified by RG 1.200, Revision 2. The licensee's assessment provided to support the RICT Amendments concluded that no gaps were identified relative to ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, Revision 2, except those associated with the December 2013 ISLOCA focused-scope peer review.

The NRC staff approval of the RICT Amendments included implementation items to address the resolutions of five F&Os related to the internal events PRA model. As stated in the LAR, the licensee recently conducted an Appendix X F&O closure in May 2019, and it noted that all of the internal events F&Os have been closed. Due to the limited time to audit this information as a part of the exigent amendment, the NRC staff did not consider whether the F&O closure was consistent with NRG-accepted guidance. Nevertheless, the NRC staff reviewed each peer review F&O resolution provided in support of the RICT Amendments and concluded that the resolutions did not significantly impact the exigent application.

Based on the previous NRC staff's review of the licensee's disposition of the F&Os in support of the RICT Amendments and the licensee's statement that all F&Os were closed using the NRG-accepted Appendix X F&O closure process, the NRC staff concludes that the IEPRA and IFPRA F&Os were adequately dispositioned to support the internal events and internal flooding PRA acceptability for the proposed one-time AOT extension. Also, as described later under the subheading "PRA Results and Insights" in Section 3.5.1.1.4 of this SE, the LAR's risk results (i.e., ICCDP and ICLERP for the proposed one-time AOT extension) for internal events and internal flooding met the RG 1.177 risk acceptance guidelines by a large margin, which provides additional confidence that any uncertainties associated with the IEPRA and IFPRA are not expected to change the conclusions of this assessment.

3.5.1.1.3 Internal Fire The St. Lucie 1 internal FPRA addressed both CDF and LERF. The licensee used RG 1.200, Revision 2, to address the acceptability of the FPRA to assure the PRA is capable of accurately characterizing the risk impact from internal fire associated with the TS LCO 3.8.1.1 AOT extension for the inoperable EOG 1B. Consistent with the guidance of RG 1.177 and RG 1.200, CC II of ASME/ANS RA-Sa-2009 was applied as the standard, and any identified deficiencies to those requirements (i.e., if either a supporting requirement was not met or met at CC I) were assessed further to determine any impacts to the risk evaluation.

As discussed in both the LAR and the RICT Amendments SE, the licensee evaluated the technical adequacy of the St. Lucie FPRA model by conducting a full-scope peer review using NEI 07-12, Revision 1, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines" (ADAMS Accession No. ML102230070), peer review process and Part 4 {fire PRA) of the current PRA ASME standard, ASME/ANS RA-Sa-2009, as clarified by RG 1.200 Revision 2. Furthermore, focused-scope peer reviews were performed in May 2013 for the Fire Scenario Selection and Analysis elements, and in June 2013 for the Fire Risk Quantification elements. The NRC staff's review of the technical adequacy of the FPRA was performed during its review of the RICT Amendments. At the end of that review, the NRC staff concluded that the

St. Lucie FPRA possessed sufficient technical adequacy and that its quantitative results can be used to demonstrate that the change in risk due to the RICT program meets the acceptance guidelines in RG 1.174. Since the review of the NFPA 805 and RICT Amendments, the licensee's fire PRA has undergone many refinements, which have allowed for the risk contribution due to fires to decrease. In support of the RICT Amendments, the licensee estimated the maximum EOG outage to 14 days; however, the updated fire risk analysis has increased the amount of time estimated for EOG outages by the current PRA.

In its letter dated July 25, 2019, the licensee provided three F&Os that remained open at the time of this LAR. The NRC staff's review of these F&Os is described below.

1. CS-A3-01: The peer review team identified that the licensee's Fire PRA Plant Response model and other fire PRA support tasks are adversely affected because the 4kV power and 125-volt control cables required to support the operation of the Containment Spray Pump were not identified. In resolution, the licensee stated that it added to the Component and Cable Selection Report a list of cables required to support the proper operation of the credited equipment and further added documentation to show the function of the selected cables and of a thorough review of the existing cable selection.

The licensee further stated that this issue is related to documentation. Because the licensee completed the documentation, and because the documentation is not expected to impact the risk calculation for this application, the NRC staff finds the resolution of this F&O acceptable for this application.

2. CS-B 1-01: The peer review team identified that the absence of an evaluation to verify that the overcurrent coordination analysis bounds new components and cables adversely affects the licensee's FPRA model. In resolution, the licensee stated that it performed a coordination analysis of FPRA components and added breaker coordination evaluations to the Component and Cable Selection Report. The NRC staff finds this F&O resolution does not impact this application since the licensee had already performed the coordination analysis and only required verification of the existing analysis.

3. SF-A 1-03: The peer review team identified that the licensee's documented assessment/review of fire induced by seismic event failed to address common cause failures, review of plant seismic response procedures, review of fire brigade training, associated equipment storage and routes, and the impact a seismic event would have on them. The licensee performed an analysis and determined that St. Lucie has a low seismic hazard and there are no seismic vulnerabilities to potential severe accidents for this configuration. As described in the External Hazards section of this SE, the bounding seismic value was added to the one-time risk values and did not significantly impact the results. Therefore, due to the low probability of a seismic event occurring, this F&O is found not to significantly impact this application.

The licensee stated in its July 25, 2019, letter that the Very Early Warning Fire Detection System is not credited in the St. Lucie 1 FPRA, and therefore, has no impact on this application.

In its July 25, 2019, letter, the licensee explained that its fire LERF presented in the LAR as three orders of magnitude below the CDF, which appeared unexpectedly low to the staff, was obtained from cutsets quantifying scenarios at a high truncation value. The licensee provided in its supplemental letter updated results for fire LERF and delta LERF using an appropriate

truncation value. Applying the appropriate truncation made the ICLERP consistent with the ICCOP by an order of magnitude.

In summary, the NRC staff evaluated the licensee's disposition of the open F&Os associated with the FPRA and concludes these F&Os were adequately addressed to support the FPRA acceptability for the proposed one-time AOT extension or the F&Os did not apply to the application of the one-time EOG CT extension. Also, as described later in the "PRA Results and Insights" section of this SE, the LAR's risk results (i.e., ICCOP and ICLERP for the proposed one-time AOT extension) for fire meet the RG 1.177 risk acceptance guidelines by a significant margin, which provides additional confidence that any uncertainties associated with the FPRA are not expected to change the conclusions of this SE.

3.5.1.1.4 Seismic and Other External Hazards St. Lucie 1 does not have PRA models for external flooding, extreme winds and tornadoes, and seismic hazards; therefore, these hazards are addressed qualitatively or using bounding analyses.

In support of the RICT Amendments, the licensee described an external events hazard evaluation based on an Individual Plant Examination of External Events study updated with the latest information for each hazard for the site. In the RICT Amendments SE, the NRC staff concluded that no unique PRA model for external flooding to support the St Lucie RICT calculation is necessary because the licensee's description of the site's physical characteristics, the evaluation of the flooding risk, and the statement to examine the applicability of the screening criteria on a case-by-case basis for RICT calculations indicate that the risk contribution from flooding is low and any configuration for which the risk might not be low will be identified. Furthermore, in the supplement dated July 25, 2019, the licensee stated that the "maximum storm surge water level associated with hurricanes was determined to be[ ... ] below the level for Unit 1 and Unit 2 EOG buildings and equipment." As indicated in the LAR, the licensee's response to hurricanes includes a compensatory measure to shut down at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months prior to the onset of hurricane force winds on the site. The licensee also stated that, based on the reevaluation performed for local intense precipitation events submitted to the NRC by letter dated February 18, 2016, it was found that the local flood levels remain below the Unit 1 and Unit 2 EOG operating floor and door levels. The NRC staff finds this qualitative analysis consistent with the criteria in RG 1.177 and the compensatory measures are appropriate for this outage. Therefore, external flooding is not a significant contributor to risk for this one-time outage.

With respect to extreme winds, in the July 25, 2019, letter, the licensee stated that procedures at St. Lucie include obtaining meteorological forecasts and data from the National Hurricane Center in Miami, Florida, at least once per 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months during a Hurricane Watch or a Hurricane Warning. These procedures also require controlled shutdown to be at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months prior to the onset of hurricane force winds at the site. The NRC staff concludes that the compensatory measures of obtaining forecasts every 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and shutting down prior to the onset of hurricane force winds provide adequate confidence to minimize risk from the hazard. Further, in support of the RICT Amendments, the NRC staff evaluated the tornado risk and concluded that no unique PRA model for extreme winds and tornadoes is necessary to assess configuration risk for the RICT program, and therefore, is not expected to affect this one-time AOT extension.

In support of the RICT Amendments, the licensee stated it will add the total seismic risk to the risk increase in every RICT calculation as a generally conservative estimate of the risk increase.

The total bounding seismic risk reported in the July 25, 2019, letter was 3.49E-06 for CDF and 3.49E-07 for LERF. The NRC staff included the seismic risk bounding estimates in the quantification for this configuration. The NRC staff finds that the bounding seismic risk increase is small and using the total seismic risk as the risk increase is a conservative assumption and does not change the conclusion regarding the acceptability of the 30-day outage. Also, as described previously in this section of the SE, and later in the "PRA Results and Insights" section, the LAR's risk results (i.e., ICCDP and ICLERP for the proposed one-time AOT extension) for all hazards met the RG 1.177 risk acceptance guidelines by a significant margin, which provides additional confidence that any uncertainties associated with the seismic risk would not change the conclusions of this assessment.

The NRC staff finds that the licensee followed RG 1.177 by performing quantitative or qualitative bounding analyses of other external hazards and determining that those hazards do not adversely impact the decision regarding this LAR. In addition, the proposed compensatory actions listed in the LAR would reduce any risk associated with these external hazards.

Plant Representation RG 1.174 states that, "[t]he PRA results used to support an application are derived from a PRA model that represents the as-built and as-operated plant to the extent needed to support the application." That is, at the time of the application, the PRA should realistically reflect the risk associated with the plant.

As discussed in the NRC staff's RICT Amendments SE, changes to the as-built, as-operated, and maintained plant to reflect the operating experience at the plant are summarized in the RICT LAR (ADAMS Accession No. ML16193A659) and request for additional information responses (ADAMS Accession No. ML18316A030). The licensee provided a list of information sources that are monitored for changes that could impact the PRA such as changes in design, maintenance policies, procedure changes, and plant and system operating experience. Each change is entered into a model change database along with an estimate of the total and cumulative risk impacts for that change. If the impact is considered minor, then it will be incorporated into the PRA models during the next scheduled model update, but if it constitutes a major impact, then a model change is "conducted promptly."

Based on the description of the PRA model update process, the NRC staff concluded that the licensee's PRA maintenance and change process ensured that the PRA model would be updated as necessary to reflect the as-built and as-operated plant.

PRA Results and Insights The NRC staff identified that the fire ICLERP reported in the LAR was significantly lower than the ICCDP. The licensee's July 25, 2019, supplement clarified that a combination of higher truncation quantification limit and fewer scenarios involving EOG unavailability have led to unusual disparity in comparing CDF and LERF values in fire risk. The licensee provided updated risk values in its supplement that were obtained with an appropriate truncation value.

The licensee evaluated the impact of the proposed change on plant risk using the internal events, internal flooding, internal fire, and high winds PRA models. This risk evaluation is

specific to the St. Lucie 1 EOG 18 outage with all relevant configurations represented in the PRA models, including:

EOG 18 failure to start failure mode was set to a failure probability of 1.0 to reflect the diesel generator being out of service during the 30-day extended AOT.

The 1A, 2A, and 28 diesel generators, as well as two methods of S80 crossties to the other units assumed to be protected during the extended CT.

All analyzed models were evaluated for the at-power (Mode 1) condition to determine CDF and LERF significance.

Common cause failures associated with common cause failure group EDGs 1A, 18, 2A, and 28 were assumed with nominal values.

The licensee calculated total ICCDP and ICLERP based on the 30-day AOT for the 1B EOG.

As provided in its supplement dated July 25, 2019, the licensee calculated ICCDP of 2.32E-6 and ICLERP of 5.43E-7. If the seismic contribution reported by the licensee of 3.49E-6 CDF and 3.49E-7 LERF is added to the delta CDF and delta LERF and then converted to ICCDP and ICLERP, the following final risk values, which include the seismic contribution, were estimated by the NRC staff:

ICCDP = 2.61 x 1Q-6 (RG 1.177 Acceptance Guideline: < 1 x 10-5 with effective compensatory measures implemented to reduce the sources of increased risk)

ICLERP = 5. 71 x 10-7 (RG 1.177 Acceptance Guideline: < 1 x 1Q-6 with effective compensatory measures implemented to reduce the sources of increased risk)

The NRC staff finds that the licensee met the appropriate risk measures specific to one-time only AOT changes provided that the compensatory measures discussed later in this SE are established, and the AOT changes are, therefore, considered acceptable.

3.5.1.2 PRA Modeling Regulatory Position 2.3.5 of RG 1.177 states that the risk resulting from TS CT changes is often relatively insensitive to uncertainties because uncertainties associated with CT changes tend to similarly affect the base case and the change case.

In support of the RICT Amendments, the licensee identified model uncertainties and related assumptions for the St. Lucie 1 PRA model using guidance in NUREG-1855, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making" (ADAMS Accession No. ML090970525), and EPRI TR-1016737, "Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments." Three types of uncertainty were evaluated:

parameter uncertainty, model uncertainty, and completeness uncertainty. The licensee evaluated uncertainties associated with internal events, internal floods, and fire models using a bounding analysis to assess the impact of the unavailability on the delta CDF and delta LERF in of the LAR.

The licensee may need to perform the Unit 2 diesel surveillance that is due within the outage window. The NRC staff compared the risk insights using the Standardized Plant Analysis Risk tool for the additional 24-hour surveillance window with the diesel, including the affected crosstie set to fail, and concluded that the risk increase due to the 24-hour surveillance is insignificant for this application.

Based on the margin by which the risk metrics met the RG 1.177 risk acceptance guidelines and the multiple compensatory measures that will be taken by the licensee during this extended CT, the NRC staff concludes that PRA model uncertainties are not expected to change the conclusions of this SE. Because the licensee does not propose new equipment to be installed or failure modes introduced by the proposed change, the PRA models were able to adequately predict the change in CDF and LERF for the one-time AOT extension. Based on the discussion above, the NRC staff finds that the licensee's assessment of sensitivity and uncertainty meets the guidance in RG 1.177.

3.5.2 Tier 2: Avoidance of Risk-Significant Plant Configurations Under the Tier 2 acceptance guideline in RG 1.177, the licensee should provide reasonable assurance that risk-significant plant equipment outage configurations would not occur when specific plant equipment is taken out of service in accordance with the proposed TS change.

Based on configuration-specific risk insights provided by the St. Lucie 1 IEPRA, IFPRA, FPRA, and seismic and high winds hazard analysis, the licensee identified risk-significant combinations of equipment that if out-of-service during the 1B EDG outage, would significantly increase risk.

Next, the licensee identified in its letter dated July 25, 2019, further compensatory actions and restrictions to avoid these high-risk equipment outage combinations. Section 3.3 of the LAR describes these compensatory measures that will be incorporated into the TSs and implemented during the 1B EDG outage to ensure the risk impacts are acceptably low.

As discussed in Section 3.3.1 of this SE, the licensee identified various compensatory measures, which will be incorporated into its TSs as a result of the proposed EOG AOT extension.

Top Dominant Cutsets in Delta CDF in Internal Events:

In its July 25, 2019, letter, the licensee provided the following list of dominant cutsets for internal events:

SMALL LOCA IE, A-train MOV to containment sump (source for 1A HPSI injection 1 during long term) fails to open, AC breaker from 1B startup transformer to 4KV 182 bus fails to close, EDG 1B OOS in TM.

Stuck open SRV initiator occurred (similar to SLOCA), A-train MOV to containment sump (source for 1A HPSI injection during long term) fails to open, 2

AC breaker from 1B startup transformer to 4KV 182 bus fails to close, EDG 1B OOS in TM.

LOSS OFF-SITE POWER (PLANT-CENTERED), EDG 1A FTR, EOG 18 OOS in TM, OPERATOR FAILS TO ALIGN BLACKOUT XTIE TO POWER UNIT 1 FROM 3 UNIT 2, OPERATOR FAILS TO ALIGN NSR 4KV BUSES XTIE TO POWER UNIT 1 FROM UNIT 2, and OPERATOR FAILS TO CONTROL TD AFW PUMP DURING SBO & LODC.

LOSS OFF-SITE POWER (PLANT-CENTERED), EOG FO PUMP 1A FAILS TO START, EOG 18 OOS in TM, OPERATOR FAILS TO ALIGN BLACKOUT XTIE 4 TO POWER UNIT 1 FROM UNIT 2, OPERATOR FAILS TO ALIGN NSR 4KV BUSES XTIE TO POWER UNIT 1 FROM UNIT 2, and OPERATOR FAILS TO CONTROL TD AFW PUMP DURING SBO & LODC.

LOSS OFF-SITE POWER (PLANT-CENTERED), EOG 1A FTS, EOG 18 OOS in TM, OPERATOR FAILS TO ALIGN BLACKOUT XTIE TO POWER UNIT 1 FROM 5 UNIT 2, OPERATOR FAILS TO ALIGN NSR 4KV BUSES XTIE TO POWER UNIT 1 FROM UNIT 2, and OPERATOR FAILS TO CONTROL TD AFW PUMP DURING SBO & LODC.

LOSS OF 4KV BUS 182 IE, 4 KV SWGR BUS 182 FAULT (1 YR EXPOSURE),

EOG 18 OOS in TM, OPERATOR FAILS TO PROVIDE LONG TERM MAKEUP TO CST VIA TWST, OPERATOR FAILS TO PROVIDE SUCTION TO U1 AFW 6

FROM U2 CST, OPERATOR FAILS TO USE THE DIESEL-DRIVEN FIRE PUMP TO REFILL THE CST, OPERATOR FAILS TO INITIATE ONCE-THROUGH-COOLING (OTC) using 2 PORVs.

LOSS OFF-SITE POWER (PLANT-CENTERED), EOG 1A FTR, EOG 18 OOS in TM, OPERATOR FAILS TO ALIGN BLACKOUT XTIE TO POWER UNIT 1 FROM 7

UNIT 2, OPERATOR FAILS TO ALIGN NSR 4KV BUSES XTIE TO POWER UNIT 1 FROM UNIT 2, and TURBINE-DRIVEN AFW PUMP 1C FAILS TO RUN.

LOSS OFF-SITE POWER (PLANT-CENTERED), EOG 1A FTR, EDG 18 OOS in TM, OPERATOR FAILS TO ALIGN BLACKOUT XTIE TO POWER UNIT 1 FROM 8 UNIT 2, OPERATOR FAILS TO ALIGN NSR 4KV BUSES XTIE TO POWER UNIT 1 FROM UNIT 2, and AFW PUMP 1C TRAIN UNAVAILABLE DUE TO TEST/MAINTENANCE.

LOSS OF 4KV BUS 182 IE, 4 KV SWGR BUS 182 FAULT (1 YR EXPOSURE),

9 EOG 1B OOS in TM, CCF 20% OR MORE CRD/RODS FAIL TO INSERT.

SMALL LOCA IE, AC breaker from 1B startup transformer to 4KV 182 bus fails to 10 close, EOG 1BOOS in TM, HPSI PUMP 1A FAILS TO RUN DURING INJECTION.

The cutsets shown above confirm the compensatory measures are valid and the risk values are consistent with established practices. Based on these cutsets, the licensee has adequately evaluated the configuration risk based on RG 1.177 and will implement these measures in an appropriate manner to mitigate further risk increase during the EOG 1B outage.

The NRC staff finds that the licensee provided an acceptable (i.e., consistent with RG 1.177)

Tier 2 analysis of potential risk-significant configurations that could occur during the EOG 1B outage and used these risk insights to identify compensatory measures to preclude their occurrence. The staff notes that the licensee performed this Tier 2 analysis using PRA models of the appropriate scope, level of detail, and technical elements as discussed under the "PRA Quality" section of this SE. The licensee used an approach consistent with RG 1.177, which provides reasonable assurance that risk-significant plant equipment outage configurations will not occur during the EOG 1B outage based on the aforementioned compensatory measures provided by the licensee and incorporated into the TSs.

3.5.3 Tier 3: Risk-Informed Configuration Risk Management RG 1. 177 states that Tier 3 is the establishment of an overall configuration risk management program to ensure that other potentially lower probability, but nonetheless risk-significant configurations resulting from maintenance and other operational activities are identified and managed. RG i. 177 further states that the licensee's program for compliance with 10 CFR 50.65(a)(4) ensures that the risk impact of out-of-service equipment is appropriately assessed and managed.

The licensee stated that it considers weather-related events (i.e., hurricanes) in applicable plant emergency and response procedures.

Based on the above, the staff finds the licensee's Tier 3 program for complying with 10 CFR 50.65(a)(4) is consistent with the guidance of Section 16.1 of the SRP and RG 1.177 and, thus, is acceptable.

3.5.4 PRA Acceptability Conclusion The licensee has demonstrated that the scope, level of detail, and technical adequacy of its PRA models are sufficient to support the proposed one-time AOT change to TS LCO 3.8. 1. 1.

The risk metrics used to support the LAR are consistent with RG 1. 177. The NRC staff finds that the licensee has followed the three-tiered approach outlined in RG 1.177 to evaluate the risk associated with the proposed change, and therefore, the proposed change satisfies the fourth key safety principle of RG 1.177.

3.6 Key Principle 5: Monitor the Impact of the Proposed Change RG 1. 174 and RG 1.177 establish the need for an implementation and monitoring program to ensure that no adverse safety degradation occurs because of the changes to the TSs. An implementation and monitoring program is intended to ensure that the impact of the proposed TS change continues to reflect the reliability and availability of structures, systems, and components impacted by the change.

RG 1. 177 states that the licensee is to use a three-tiered approach in implementing the proposed TS CT change. Application of the three-tiered approach is in keeping with the fundamental principle that the proposed change is consistent with the defense-in-depth philosophy. Application of the three-tiered approach provides assurance that defense-in-depth will not be significantly impacted by the proposed change. Furthermore, RG 1. 177 states that to ensure that extension of a TS CT does not degrade operational safety over time, the licensee should ensure, as part of its Maintenance Rule program (10 CFR 50.65), that when equipment

. does not meet its performance criteria, the evaluation required under the Maintenance Rule includes prior related TS changes in its scope.

The staff concludes that implementation and monitoring in accordance with the licensee's Maintenance Rule program for the proposed TS change satisfies the fifth key safety principle of RG 1. 177.

3.7 Technical Conclusion As discussed in Section 3.1 of this SE, an acceptable approach for making risk-informed decisions about proposed TS changes, including both permanent and temporary changes, is to show that the proposed changes meet the five key principles stated in RG 1.174, Section 2, and RG 1.177, Section 8. The NRC staff determined in Sections 3.2 through 3.6 of this SE that the licensee's proposed one-time extension of the AOT for one inoperable EOG from 14 days to 30 days meets the five key principles.

The NRC staff finds that the risk impact of the licensee's request for a one-time extension of the AOT of TS LCO 3.8.1.1 from 14 days to 30 days, as estimated by ICCOP and ICLERP, is consistent with the acceptance guidelines specified in RG 1.177 and the staff guidance outlined in Sections 19.1 and 16.1 of NUREG-0800, provided that the licensee complies with compensatory measures detailed in the licensee's supplement. The licensee's methodology for assessing the risk impact is accomplished using PRA models of sufficient scope and technical adequacy. For external hazards not explicitly modeled by PRA, the licensee used qualitative or bounding analyses. The NRC staff finds that the licensee has followed the approach and performance monitoring programs outlined in RG 1.177.

As a result, the NRC staff finds that the proposed change to TS LCO 3.8.1.1 is consistent with the requirements of 10 CFR 50.36(c)(2) and is acceptable.

4.0 EXIGENT CIRCUMSTANCES

The NRC's regulations contain provisions for issuance of amendments when the usual 30-day public comment period cannot be met. These provisions are applicable when both exigent circumstances exist and the amendment involves no significant hazards consideration.

Consistent with the requirements in 10 CFR 50.91(a)(6), exigent circumstances exist when a licensee and the NRC must act quickly and time does not permit the NRC to publish a Federal Register notice allowing 30 days for prior public comment. As discussed in the licensee's application, the licensee requested that the proposed amendment be processed by the NRC on an exigent basis.

Under the provisions in 10 CFR 50.91(a)(6), the NRC notifies the public in one of two ways:

(1) by issuing a Federal Register notice providing an opportunity for hearing and allowing at least 2 weeks from the date of the notice for prior public comments or (2) by using local media to provide reasonable notice to the public in the area surrounding the licensee's facility. In this case, the NRC staff published a notice in the Treasure Coast Newspapers on July 23, 2019, and July 24, 2019, requesting public comments by July 25, 2019.

The licensee provided the following information to support its need for this exigent LAR. On July 15, 2019, at 0736 hours0.00852 days 0.204 hours 0.00122 weeks 2.80048e-4 months , the 18 EOG was declared out of service to support its monthly testing. At 0919 hours0.0106 days 0.255 hours 0.00152 weeks 3.496795e-4 months , while performing the testing, the 18 EOG unexpectedly tripped on high water temperature. Subsequent troubleshooting revealed that the 182 engine radiator fan was not rotating because the coupling between the crank shaft and stub shaft that drives the radiator fan failed from a fatigue mechanism. Furthermore, the licensee determined that the EOG repairs require an extensive disassembly and refurbishment of the 182 EOG engine and will challenge the current allowed outage time of 14 days and provide little margin for contingencies.

Further, the licensee stated that a forced outage to repair the 182 EOG engine would result in an unnecessary transient to St. Lucie 1.

The licensee stated that failure of the 1B2 EOG could not have reasonably been anticipated because there had been no adverse maintenance history associated with the failed component.

To support this statement, the licensee provided a table listing surveillance testing successfully completed within the previous 12-months.

NRC Staff Conclusion Based on the above circumstances, the NRC staff finds that the licensee made a timely application for the proposed amendment following identification of the issue. In addition, the NRC staff finds that the licensee could not avoid the exigency because failure of the EDG could not be anticipated, and the licensee acted quickly upon discovery of the condition. Based on these findings and the determination that the amendment involves no significant hazards consideration as discussed in Section 5.0 below, the NRC staff has determined that a valid need exists for issuance of the license amendment using the exigent provisions of 10 CFR 50.91(a)(6).

5.0 FINAL NO SIGNIFICANT HAZARDS CONSIDERATION

The NRC's regulation in 10 CFR 50.92(c) states that the NRC may make a final determination, under the procedures in 10 CFR 50.91, that a license amendment involves no significant hazards consideration if operation of the facility, in accordance with the amendment, would not:

( 1) involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) involve a significant reduction in a margin of safety.

The licensee's determination of no significant hazards consideration is presented below:

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

Response: No.

The proposed license amendment provides a one-time 30 day AOT allowance in TS 3/4.8.1, Action b for one EOG. This change will have no effect on accident probabilities since the EDGs are not considered accident initiators. The proposed AOT extension does not require any physical plant modifications. Since no individual precursors of an accident are affected, the proposed amendment does not increase the probability of a previously analyzed event.

The consequences of an evaluated accident are determined by the operability of plant systems designed to mitigate those consequences. The EDGs are backup power to components that mitigate the consequences of accidents. The current TSs normally permit a single EOG to be inoperable for up to 14 days. The proposed license amendment extends the current AOT for the 1B EOG on a one-time basis, to no more than a total of 30 days.

The proposed change does not affect any of the assumptions used in deterministic safety analysis. Granting the proposed change will not adversely affect the consequences of an accident previously evaluated.

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

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

Response: No.

Creation of the possibility of a new or different kind of accident requires creating one or more new accident precursors. New accident precursors may be created by modifications of plant configuration, including changes in allowable modes of operation.

The proposed amendment provides a one-time allowance of a 30 day AOT for TS 3/4.8.1, Action b. This change does not involve a modification or the physical configuration of the plant (i.e., no new equipment will be installed),

create any new failure modes for existing equipment, or create any new limiting single failures. The plant equipment considered available when evaluating the existing AOT remains unchanged. The extended AOT will permit completion of repair activities without incurring transient risks associated with performing a unit shutdown with the EOG unavailable.

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

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

Response: No.

The proposed license amendment provides a risk-informed, one-time allowance of a 30 day AOT for TS 3/4.8.1, Action b. A deterministic evaluation of the proposed AOT demonstrates there is sufficient margin to safety during the extended EOG AOT period. During the extended AOT times, sufficient compensatory measures will be established to maintain the defense-in-depth design philosophy to ensure the electrical power system meets its design safety function.

Therefore, the proposed amendment does not result in a significant reduction in the margin of safety.

Based on the above evaluation, the NRC staff concludes that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff has made a final determination that no significant hazards consideration is involved for the proposed amendment and that the amendment should be issued as allowed by the criteria contained in 10 CFR 50.91.

6.0 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 July 23, 2019, of the proposed issuance of the amendment. The State official had no comments.

7.0 ENVIRONMENTAL CONSIDERATION

The amendment changes requirements with respect to the use of facility components located within the restricted area as defined in 10 CFR Part 20 or a surveillance requirement. The NRC staff has determined that the amendment involves 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 Treasure Coast Newspapers on July 23, 2019, and July 24, 2019, that the amendment involves NSHC, and there has been no public comment on such finding. Accordingly, the amendment meets 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 amendment.

8.0 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 amendment will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors: Jonathan Evans Gurcharan Matharu Alexis Nelson Cassandra Smith Robert Wolfgang Date: July 26, 2019

D.Moul

SUBJECT:

ST. LUCIE PLANT, UNIT NO. 1 - ISSUANCE OF EXIGENT AMENDMENT NO. 248 REGARDING TECHNICAL SPECIFICATIONS CHANGE TO ALLOW A ONE-TIME EXTENSION OF THE ALLOWED OUTAGE TIME FOR ONE INOPERABLE EMERGENCY DIESEL GENERATOR (EPID L-2019-LLA-0152)

DATED JULY 26, 2019 DISTRIBUTION:

PUBLIC RidsACRS_MailCTR PM File Copy RidsNrrPMStLucie RidsNrrLALRonewicz RidsRgn2MailCenter RidsNrrDorlLpl2-2 RidsNrrDeEeob RidsNrrDmlrEmib RidsNrrDraApla RidsN rrDssScpb RidsNrrDssStsb GCurran, NRR GMatharu, NRR JEvans, NRR ANelson, NRR CSmith, NRR RWolfgang NRR ADAMS Access1on No.: ML19203A166 *b>V e-ma1 OFFICE NRR/DORL/LPL2-2/PM NRR/DORL/LPL2-2/LA NRR/DE/EEOB/BC*

NAME MWentzel LRonewicz DWilliams (RMathew for)

DATE 07/26/2019 07/26/2019 07/25/2019 OFFICE NRR/DMLR/EMIB/BC* NRR/DRA/APLA/BC* NRR/DSS/STSB/BC*

NAME SBailey SRosenberg PSnyder DATE 07/24/2019 07/25/2019 07/26/2019 OFFICE OGC (NLO) w/edits* NRR/DORL/LPL2-2/BC NRR/DORL/LPL2-2/PM NAME KGamin UShoop (DGalvin for) MWentzel DATE 07/26/2019 07/26/2019 07/26/2019 OFFICIAL RECORD COPY

v t e Letter Sequence Approval
EPID:L-2019-LLA-0152, (Approved, Closed)
Initiation Acceptance... Supplement, Supplement Administration Questions Answers Results Approval Other: L-2019-147, Exigent Technical Specification Amendment Request One-Time Allowed Outage Time Extension for Inoperable EDG, L-2019-149, Exigent Technical Specification Amendment Request RAI Reply One-Time Allowed Outage Time Extension for Inoperable EDG, ML19203A016, ML19203A018
MONTHYEAR2019-07-22 [Table View]

ML19203A166

Text

SUBJECT:

Dear Mr. Moul:

Enclosures:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

4.0 EXIGENT CIRCUMSTANCES

5.0 FINAL NO SIGNIFICANT HAZARDS CONSIDERATION

6.0 STATE CONSULTATION

7.0 ENVIRONMENTAL CONSIDERATION

8.0 CONCLUSION

SUBJECT:

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