ML19121A505

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Issuance of Amendments to Renewed Facility Operating Licenses Removal of Operating Mode Restrictions for Performing Surveillance Testing of the Division 3 Battery and High Pressure Core Spray Diesel Generator
ML19121A505
Person / Time
Site: LaSalle  Constellation icon.png
Issue date: 06/24/2019
From: Bhalchandra Vaidya
Plant Licensing Branch III
To: Bryan Hanson
Exelon Generation Co, Exelon Nuclear
Vaidya B 415-3308
References
EPID L-2018-LLA-0162
Download: ML19121A505 (31)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON , .D.C. 20555-0001 Mr. Bryan C. Hanson Senior Vice President Exelon Generation Company, LLC President and Chief Nuclear Officer Exelon Nuclear LaSalle County Station 4300 Winfield Road Warrenville, IL 60555 June 24, 2019

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2-ISSUANCE OF AMENDMENTS TO RENEWED FACILITY OPERATING LICENSES RE: REMOVAL OF OPERATING MODE RESTRICTIONS FOR PERFORMING SURVEILLANCE TESTING OF THE DIVISION 3 BATTERY AND PRESSURE CORE SPRAY DIESEL GENERATOR (EPID L-2018-LLA-0162)

Dear Mr. Hanson:

The U.S. Nuclear Regulatory Commission (NRC or Commission) has issued the enclosed Amendment No. 237 to Renewed Facility Operating License No. NPF-11 and Amendment No. 223 to Renewed Facility Operating License No. NPF-18 for the LaSalle County Station, Units 1 and 2, respectively.

The amendments revise the relevant portions of the technical specification and license pages in response to your application dated April 19, 2018, as supplemented by letters dated April 12, April 24, and May 23, 2019. The amendments revised the licenses and the technical specifications (TSs) as follows: (1) Division 3 Battery Surveillance Testing The amendments revised TSs 3.8.4, "DC Sources-Operating," and TS 3.8.6, "Battery Parameters," by removing the Mode restrictions for performance of TS surveillance requirements (SRs) 3.8.4.3 and 3.8.6.6 for the Division 3 direct current (DC) electrical power subsystem battery. The Division 3 DC electrical power subsystem feeds emergency DC loads associated with the high-pressure core spray (HPCS) system. SR 3.8.4.3 verifies that the battery capacity is adequate for the battery to perform its required functions.

SR 3.8.6.6 verifies battery capacity is 80 percent of the manufacturer's rating when subjected to a performance discharge test (or a modified performance discharge test). The amendments removed these mode restrictions for the Division 3 battery, allowing performance of SR 3.8.4.3 and SR 3.8.6.6 for the Division 3 battery during Mode 1 or 2, potentially minimizing impact on HPCS unavailability.

Eliminating the requirement to perform SR 3.8.4.3 and SR 3.8.6.6 only during Mode 3, 4, or 5 (hot shutdown, cold shutdown, or refueling conditions) will provide greater flexibility in scheduling Division 3 battery testing activities by allowing the testing to be performed during non-outage times.

B. Hanson (2) High-Pressure Core Spray Diesel Generator Surveillance Testing The amendments revised TS 3.8.1, "AC Sources-Operating," by revising certain SRs pertaining

  • to the Division 3 diesel generator (DG). The Division 3 DG is an independent source of onsite alternating current (AC) power dedicated to the HPCS system. The TSs currently prohibit performing the testing required by SRs 3.8.1.9, 3.8.1.10, 3.8.1.11, 3.8.1.12, 3.8.1.13, 3.8.1.16, 3.8.1.17, and 3: 8.1.19, in Modes 1 or 2. The amendments removed these Mode restrictions and allow all eight of the identified SRs to be performed in any operating Mode for the Division 3 DG. The mode restrictions will remain applicable to the other two safety-related (Division 1 and Division 2) DGs. The change will provide greater flexibility in scheduling Division 3 DG testing activities by allowing the testing to be performed during non-outage times. Having a completely tested Division 3 DG available for the duration of a refueling outage will reduce the number of system re-alignments and operator workload during an outage. A copy of the Safety Evaluation is also enclosed.

A Notice of Issuance will be included in the Commission's biweekly Federal Register notice. Docket Nos. 50-373 and 50-37 4

Enclosures:

1. Amendment No. 237 to NPF-11 2. Amendment No. 223 to NPF-18 3. Safety Evaluation cc: Listserv Sincerely, Bhalchandra K. Vaidya, Project Manager Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON , D.C. 20555-0001 EXELON GENERATION COMPANY, LLC DOCKET NO. 50-373 LASALLE COUNTY STATION, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 237 Renewed License No. NPF-11 1. The U.S. Nuclear Regulatory Commission (the Commission) has found that: A. The application for amendment filed by the Exelon Generation Company, LLC (the licensee), dated April 19, 2018, as supplemented by letters dated April 12, April 24, and May 23, 2019, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's 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 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 set forth in 10 CFR Chapter I; 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. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 2.C.(2) of the Renewed Facility Operating License No. NPF-11 is hereby amended to read as follows: (2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 237, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. 3. This license amendment is effective as of the date of its issuance and shall be implemented within 90 days from the date of issuance. is M. Regner , Chief (A) Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance:

June 24, 2,)1 9

Attachment:

Revised License and Technical Specification Pages UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON , O.C. 20555-0001 EXELON GENERATION COMPANY, LLC DOCKET NO. 50-37 4 LASALLE COUNTY STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 223 Renewed License No. NPF-18 1. The U.S. Nuclear Regulatory Commission (the Commission) has found that: A. The application for amendment filed by the Exelon Generation Company, LLC (the licensee), dated April 19, 2018, as supplemented by letters dated April 12, April 24, and May 23, 2019, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's 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 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 set forth in 10 CFR Chapter I; 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 2 2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 2.C.(2) of the Renewed Facility Operating License No. NPF-18 is hereby amended to read as follows: (2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 223, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. 3. This license amendment is effective as of the date of its issuance and shall be implemented within 90 days from the date of issuance.

isa M. Regner, Chief (A) Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance: , June 2 4 , 2 v 1 9

Attachment:

Revised License and Technical Specification Pages ATIACHMENT TO LICENSE AMENDMENT NOS. 237 AND 223 RENEWED FACILITY OPERATING LICENSE NOS. NPF-11 AND NPF-18 LASALLE COUNTY STATION, UNITS 1 AND 2 DOCKET NOS. 50-373 AND 50-37 4 Replace the following pages of the Renewed Facility Operating Licenses and 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 License NPF-11, Page 3 NPF-18, Page 3 TSs 3.8.1-10 3.8.1-11 3.8.1-12 3.8.1-13 3.8.1-16 3.8.1-17 3.8.1-18 3.8.4-5 3.8.6-5 INSERT License NPF-11, Page 3 NPF-18, Page 3 TSs 3.8.1-10 3.8.1-11 3.8.1-12 3.8.1-13 3.8.1-16 3.8.1-17 3.8.1-18 3.8.4-5 3.8.6-5 Am.146 01/12/01 Am. 202 07/21/11 Am. 198 09/16/10 Renewed License No. NPF-11 (3) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (4) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 30, 40, and 70, 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 (5)

  • Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of LaSalle County Station, Units 1 and 2, and such Class B and Class C low-level radioactive waste as may be produced by the operation of Braidwood Station, Units 1 and 2, Byron Station, Units 1 and 2, and Clinton Power Station, Unit 1. C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I 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 or incorporated below: (1) Maximum Power Level The licensee is authoriZed to operate the facility at reactor core power levels not in excess of full power (3546 megawatts thermal). Am.237 06/ /19 (2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 237, and the Environmental Protection Plan contained in Appendix 8, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. Am. 194 (3) DELETED 08/28/09 Am.194 (4) DELETED 08/28/09 Am. 194 (5) DELETED 08/28/09 Amendment No. 237 Am. 189 07/21/11 Am.185 09/ 16/10 Renewed License No. NPF-18 (2)
  • Pursuant to the Act and 10 CFR Part 70, to receive, possess and use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended; (3) Pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (4) Pursuant to the Act and 10 CFR Parts 30, 40, and 70, 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 (5) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of LaSalle County Station, Units 1 and 2, and such Class Band Class Clow-level radioactive waste as may be produced by the operation of Braidwood
  • Station, Units 1 and 2, Byron Station, Units 1 and 2, and Clinton Power Station, Unit 1. C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I 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 or incorporated below: (1) Maximum Power Level The licensee is authorized to operate the facility at reactor core power levels not in excess of full power (3546 megawatts thermal).

Items in Attachment 1 shall be completed as specified.

Attachment 1 is hereby incorporated into this license. Am.223 06/ /19 (2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 223, and the Environmental Protection Plan contained in Appendix 8, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. Amendment No. 223 AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.9 SR 3.8.1.10 LaSalle 1 and 2 SURVEILLANCE

NOTES--------------------

1. This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3 DG). However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. 2. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units. Verify each required DG-rejects a load greater than or equal to its associated single largest post-accident load and following load rejection, the frequency is 66.7 Hz. -----------------NOTES---------------------1. This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3 DG). However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. 2. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units. Verify each required DG does not trip and voltage is maintained~

5000 V during and following a load rejection of a load 2600 kW. FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program (continued) 3.8.1-10 Amendment No. 237/223 AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.11 LaSalle 1 and 2 SURVEILLANCE -------------------

NOTES-------------

1. All DG starts may be preceded by. an engine prelube period. 2. This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3 DG). However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. Verify on an actual or simulated loss of offs ite power signal : a. De-energization of emergency buses; b. Load shedding from emergency buses for Divisions 1 and 2 only; and c. DG auto-starts from standby condition and: 1. energizes permanently connected loads in~ 13 seconds, 2. energizes auto-connected shutdown loads, 3. maintains steady state voltage 4010 V and~ 4310 V, 4. maintains steady state frequency 58.8 Hz and~ 61.2 Hz, and 5. supplies permanently connected and auto-connected shutdown loads for 5 minutes. FREQUENCY In accordance with the Surveillance Frequency Control Program (continued) 3.8.1-11 Amendment No. 237/223 AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.12 LaSalle 1 and 2 SURVEILLANCE

NOTES-------------------1. A 11 DG starts may be preceded by an engine prelube period. 2. This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3 DG). However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. Verify on an actual or simulated Emergency Core Cooling System (ECCS) initiation s ignal each required DG auto-starts from standby condition and: a. In~ 13 seconds after auto-start, achieves voltage~ 4010 V and frequency~

58.8 Hz; b. Achieves steady state voltage~ 4010 V and~ 4310 V and frequency~

58.8 Hz and~ 61.2 Hz; and c. Operates for~ 5 minutes. FREQUENCY In accordance with the Surveillance Frequency Control Program (continued) 3.8.1-12 Amendment No. 237/223 AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.13 LaSalle 1 and 2 SURVEILLANCE

NOTE--------------------This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3 DG). However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. Verify each required DG's automatic trips are bypassed on an actual or simulated ECCS initiation signal except: a. Engine overspeed; and b. Generator differential current. FREQUENCY In accordance with the Surveillance Frequency Control Program (continued) 3.8.1-13 Amendment No. 237/223 AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.16 LaSalle 1 and 2 SURVEILLANCE -------------------NOTE--------------------

This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3 DG). However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. Verify each required DG: a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power; b. Transfers loads to offsite power source; and c. Returns to ready-to-load operation.

FREQUENCY In accordance with the Surveillance Frequency Control Program (continued) 3.8.1-16 Amendment No. 237/223 AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.17 SR 3.8.1.18 LaSalle 1 and 2 SURVEILLANCE -------------------NOTE--------------------This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3 DG). However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. Verify, with a required DG operating in test mode and connected to its bus: a. For Division 1 and 2 DGs, an actual or simulated ECCS initiation signal overrides the test mode by returning DG to re~dy-to-load operation; and b. For Division 3 DG, an actual or simu lated DG overcurrent trip signal automatically disconnects the offsite power source while the DG continues to supply normal loads. -------------------NOTE--------------------Thi s Surveillance sha ll not normally be performed in MODE 1 or 2. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. Verify interval between each sequenced load block, for Division 1 and 2 DGs only, is 90% of the design interval for each time delay relay. FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program (continued) 3.8.1-17 Amendment No. 237/223 AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.19 LaSalle 1 and 2 SURVEILLANCE -------------------NOTES-------------------1. A 11 DG starts may be preceded by an engine prelube period. 2. This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3 DG). However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. Verify, on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ECCS initiation signal: a. De-energization of emergency buses; b. Load shedding from emergency buses for Divisions 1 and 2 only; and c. DG auto-starts from standby condition and: 1. energizes permanently connected loads in~ 13 seconds, 2. energizes auto-connected emergency loads including through time delay relays, where applicable, 3. maintains steady state voltage 4010 V and~ 4310 V, 4. maintains steady state frequency 58.8 Hz and~ 61.2 Hz, and 5. supplies permanently connected and auto~connected emergency loads for 5 minutes. FREQUENCY In accordance with the Surveillance Frequency Control Program (continued) 3.8.1-18 Amendment No. 237/223 DC Sources-Operating 3*.8 .4 SURVEILLANCE REQUIREMENTS SR 3.8.4.3 SR 3.8.4.4 LaSalle 1 and 2 SURVEILLANCE -------------------NOTES-------------------1. The modified performance discharge test in SR 3.8.6.6 may be performed in lieu of SR 3.8.4.3. 2. This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3) for the 125 voe batteries.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. Verify battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test. ------------------NOTE-----------

When the opposite unit is in MODE 4 or 5, or moving irradiated fuel in the secondary containment, the following opposite unit SRs are not required to be performed:

SR 3.8.4.2 and SR 3.8.4.3. For the opposite unit Division 2 DC electrical power subsystem, the SRs of the opposite unit Specification 3.8.4 are applicable.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with applicable SRs 3.8.4-5 Amendment No. 237/223 SURVEILLANCE REQUIREMENTS SR 3.8.6.6 SURVEILLANCE

NOTES

1. This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to Division 3) for the 125 VDC batteries.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Credit may be taken for unplanned events that satisfy this SR. 2. In MODE 1, 2 or 3, and the opposite unit in MODE 4 or 5, or moving irradiated fuel in the secondary containment, this Surveillance is not required to be performed for the opposite unit Division 2 DC electrical power subsystem.

3. In MODE 4, 5 or during movement of irradiated fuel in the secondary containment in Mode 4, 5 or defueled, this Surveillance is not required to be performed.

Verif y battery capacity is~ 80% of the manufacturer's rating when subjected to a performance discharge test or a modified performance discharge test. Battery Parameters 3.8.6 FREQUENCY In accordance with the Surveillance Frequency Control Program 12 months when battery shows degradation or has reached 85% of expected life with capacity < 100% of manufacturer's rating 24 months when battery has reached 85% of the expected life with capacity 100% of manufacturer's rating LaSalle 1 and 2 3.8.6-5 Amendment No. 237/223 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON , D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 237 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-11 AND AMENDMENT NO. 223 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-18 EXELON GENERATION COMPANY, LLC LASALLE COUNTY STATION, UNITS 1 AND 2 DOCKET NOS. 50-373 AND 50-37 4

1.0 INTRODUCTION

By application dated April 19, 2018, as supplemented by letters dated April 12, April 24, and May 23, 2019 (Agencywide Documents Access and Management System (ADAMS) Accession Nos. ML18157A123, ML19102A336, ML19114A420 , and ML19144A168, respectively), Exelon Generation Company, LLC (EGC or the licensee), requested amendments to the Renewed Facility Operating License Nos. NPF-11 and NPF-18 for the LaSalle County Station (LaSalle), Units 1 and 2, respectively. The proposed amendment would revise Technical Specification (TS) 3.8.1, "AC [alternating current] Sources-Operating," TS 3.8.4, "DC [direct current] Sources-Operating," and TS 3.8.6, "Battery Parameters." Specifically, the proposed change would remove operating mode restrictions on performing TS surveillance requirements (SRs) pertaining to Division 3 battery and high-pressure core spray (HPCS) diesel generator (DG) as follows: Division 3 Battery Surveillance Testing The proposed amendments would revise TSs 3.8.4, "DC Sources-Operating," and TS 3.8.6, "Battery Parameters," by removing the mode restrictions for performance of TS SRs 3.8.4.3 and 3.8.6.6 for the Division 3 DC electrical power subsystem battery. The Division 3 DC electrical power subsystem feeds emergency DC loads associated with the HPCS system. SR 3.8.4.3 verifies that the battery capacity is adequate for the battery to perform its required functions.

SR 3.8.6.6 verifies battery capacity is 80 percent of the manufacturer's rating when subjected to a performance discharge test (or a modified performance discharge test). The proposed amendments would remove these mode restrictions for the Division 3 battery, allowing performance of SR 3.8.4.3 and SR 3.8.6.6 for the Division 3 battery during Mode 1 or 2, potentially minimizing impact on HPCS unavailability. Eliminating the requirement to perform SR 3.8.4.3 and SR 3.8.6.6 only during Modes 3, 4, or 5 (hot shutdown , cold shutdown, or refueling conditions) will provide greater flexibility in scheduling Division 3 battery testing activities by allowing the testing to be performed during nonoutage times. Enclosure 3 HPCS -DG Surveillance Testing The proposed amendments would revise TS 3.8.1, "AC Sources-Operating," by revising certain SRs pertaining to the Division 3 DG. The Division 3 DG is an independent source of onsite AC power dedicated to the HPCS system. The TSs currently prohibit performing the testing required by SRs 3.8.1.9, 3.8.1.10, 3.8.1.11, 3.8.1.12, 3.8.1.13, 3.8.1.16, 3.8.1.17, and 3.8.1.19, in Modes 1 or 2. The proposed amendments would remove these mode restrictions and allow all eight of the identified SRs to be performed in any operating mode for the Division 3 DG. These restrictions will remain applicable to the other two safety-related (Division 1 and Division 2) DGs. The change will provide greater flexibility in scheduling Division 3 DG testing activities by allowing the testing to be performed during nonoutage times. Having a completely tested Division 3 DG available for the duration of a refueling outage will reduce the number of system re-alignments and operator workload during an outage. The supplemental letters dated April 12, April 24, 2019, and May 23, 2019, provided additional information that clarified the application but did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC or Commission) staffs original proposed no significant hazards consideration determination as published in the Federal Register on August 14, 2018 (83 FR 40348).

2.0 REGULATORY EVALUATION

2.1 Description of Affected Systems 2.1.1 Division 3 Battery According to Section 8.3.2, "D-C Power Systems," of the Updated Final Safety Analysis Report (UFSAR), the DC power distribution system and batteries are designed to provide control power for switchgear groups, DGs, relays, solenoid valves, and other electric devices and components.

Batteries are provided as a source of power for vital loads in case of emergencies such as loss of AC power. The DC system and batteries are designed to provide control power for both normal and emergency operation of plant equipment and to provide power for automatic operation of the engineered safety features (ESF) protection systems during abnormal and of-coolant accident (LOCA) conditions.

Each unit has one 250-volt (V) power battery and three 125-V control batteries.

The 250-V battery supplies its loads until AC power sources to redundant loads are restored.

Each 125-V battery supplies control power requirements of the switchgear and logic circuitry of one of the three ESF divisions (Divisions 1, 2, and 3). Each battery has its own charger with a capacity for restoring it to full charge under normal load. Each Division 1 and 2 125-V DC (VDC) battery has two fully redundant battery chargers capable of supplying at least 200 amperes at a minimum of 130 V for at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The Division 3 battery charger will supply at least 50 amperes at a minimum of 130 V for at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Battery chargers are powered from AC sources, and in case of loss of normal AC power from both on-site and off-site sources, can be supplied from the standby DGs associated with their respective engineered safeguards divisions. 2.1.2 Division 3 HPCS DG The electrical power AC sources consist of the offsite power sources and the onsite power sources. UFSAR Section 8.1.2.2, "Unit Class 1 E A-C Power System," provides a description of the Class 1 E AC power system as summarized below. For each unit, the Class 1 E AC power system is divided into three divisions (Divisions 1, 2, and 3). Each division is powered from a Class 1 E 4.16 kilovolts (kV) bus. Divisions 2 and 3 are supplied standby power from the dedicated DGs. Division 1 obtains its standby power from a common DG which serves either of the corresponding switch groups in each unit. In the event of loss of offsite power supplies to a Class 1 E 4.16 kV switch group, there are provisions for automatic tripping of offsite supply circuit breakers, automatic shedding of certain non-ESF loads, automatic starting of the DG, and automatic closing of the DG supply circuit breaker. Provisions are also made for sequential starting of certain ESF loads to prevent excessive overload of the DGs during their starting periods. 2.2 Description of Proposed Change The current TS prohibits the performance of testing required by SR 3.8.1.9, SR 3.8.1.10, SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.16, SR 3.8.1.17, SR 3.8.1.19, SR 3.8.4.3, and SR 3.8.6.6 in Operating Mode 1 or 2. The proposed amendment would revise TS 3.8.1, TS 3.8.4, and TS 3.8.6 to remove the mode restriction from the above SRs and to allow testing pertaining to the Division 3 battery and HPCS DG to be performed in any operating mode. The restriction would remain applicable to the other two divisions (Division 1 and Division 2) batteries and HPCS DGs. 2.3 Description of Regulatory Requirements and Guidance The regulatory requirements applicable to LaSalle, which the NRC staff applied in its review of the application , include the following:

  • Title 10 of the Code of Federal Regulations (10 CFR) 50.36, "Technical Specifications," requires in part, that the operating license of a nuclear production facility include TSs. Paragraph 50.36(c)(2) of 10 CFR requires that the TSs include limiting conditions for operation (LCOs), which are the lowest functional capability or performance levels of equipment required for safe operation of the facility, and Paragraph 50.36(c)(3) requires that the TSs include SRs, which are requirements relating to rest, calibration, or inspection to assure that the necessary quality of systems and components is maintained, the facility operation will be within safety limits, and that the LCOs of operations are met. When an LCO of a nuclear reactor is not met, Paragraph 50.36(c)(2) requires that the licensee shall shut down the reactor or follow any remedial action permitted by the TSs until the condition can be met. The following general design criteria (GDC) are applicable to the LaSalle electrical power systems.
  • Appendix A to 10 CFR Part 50, 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.

The NRC staff applied the following regulatory guidance to the license amendment request (LAR) evaluation.

  • NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR Edition -Electric Power ," states, in part , that in reviewing the mode of operation where both power systems are being operated in parallel, the interlock scheme , including electrical protective relay coordination and settings, is closely examined to verify that the independence of the necessary redundant portions of the onsite power system is established upon a failure in the offsite power system. The event of concern under this mode of operation is an accident concurrent with a loss of offsite power (LOOP) and a single failure preventing the opening of the feeder-isolation breaker through which the paralleling of the power systems was being accomplished.

Because the signal to start the DG sets is normally derived from under-voltage relays, and under this situation the voltage is maintained above the trip relay settings by the DG under test, the remaining redundant DGs will not be commanded to start running. Consequently, the added capacity resulting from the connection of nonsafety-related loads to the DG under test will cause the tripping of this diesel due to overload or under-frequency.

The end result could be the total loss of power to the safety buses. 3.0 TECHNICAL EVALUATION The NRC staffs evaluation of the proposed change considered several potential plant conditions that could be encountered while performing online testing required by surveillance requirements.

The NRC staff reviewed information in the application pertaining to the electrical power systems, the UFSAR, and applicable TS LCO to verify the capability of the affected electrical power systems to perform their safety functions (assuming no additional failures of electrical components) is maintained.

The staff's evaluation of the proposed change is provided below. 3.1 Evaluation of Impact on Safe Operation of the Plant In the LAR and its supplements, the licensee stated that the HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system. The Division 3 battery and HPCS DG are dedicated to the HPCS system, thus testing on the Division 3 battery and DG only impacts the HPCS system. The licensee further stated that the Division 3 battery and HPCS DG surveillance testing will only be performed when the HPCS system is out of service (OOS) during a scheduled maintenance outage. According to TS 3.5.1 Bases, when the HPCS system is inoperable and the reactor core isolation cooling (RCIC) system is verified operable, adequate core cooling is ensured by the operability of the redundant and diverse low-pressure emergency core cooling system (ECCS) injection/spray subsystems in conjunction with the automatic depressurization system. The RCIC system will automatically provide makeup water at most reactor operating pressures.

Regarding the surveillance testing duration in the LAR and its supplements, the licensee stated that the time needed to perform either battery testing (i.e., SR 3.8.4.3) or discharge testing (i.e., SR 3.8.6.6) is approximately 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (3 days). The Division 3 battery is therefore expected to be unavailable to support the HPCS system for approximately 6 days for both SR tests. The total time needed to perform the HPCS DG SR tests is approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. The NRC staff notes that the current TS allows the HPCS system to be removed from service to perform the scheduled maintenance while in Mode 1, 2, or 3. Specifically, TS 3.5.1 Condition B -HPCS system inoperable

-allows the HPCS system to be inoperable up to 14 days if the RCIC system is operable.

The NRC staff notes that the durations of the Division 3 battery unavailable (6 days) and the Division 3 DG unavailable (48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />) due to testing are within the HPCS outage window allowed by the current TS (14 days). The NRC staff finds, with reasonable assurance, that performing surveillance testing for the Division 3 battery and HPCS DG in Mode 1 or 2 would have minimal impact on the safe operation of the plant because:

  • These SRs will be performed when the RCIC system is verified operable.

Thus, adequate core cooling would be ensured.

  • These SRs on the equipment dedicated to the HPCS system will be performed only when the HPCS system is already OOS during the system's scheduled maintenance outage.
  • The Division 3 battery and DG are physically and electrically independent of other divisions' batteries and DGs and have no connection with any other equipment that is required to be operable.

Thus, testing on the Division 3 battery and DG would not challenge any other plant's SSCs.

  • The time that the Division 3 battery and DG are unavailable due to testing is within the HPCS system outage window allowed by the current TS. 3.2 Evaluation of Effects on Electrical Distribution System SR 3.8.4.3 and SR 3.8.6.6 TS 3.8.4 specifies requirements for the Divisions 1, 2 , 3, and the opposite unit Division 2 125-VDC electrical power subsystems.

These subsystems are required to be operable in plant Modes 1, 2, and 3. SR 3.8.4.3 requires verification that the battery is operable and its capacity is adequate to supply the required emergency loads for the design duty cycle when subjected to a battery service test. TS 3.8.6 specifies requirements for the Divisions 1, 2, 3, and opposite unit Division 2 batteries. The parameters for these batteries are required to be within the limits when the associated DC electrical power subsystems are required to be operable.

SR 3.8.6.6 requires verification that the battery capacity is greater than or equal to 80 percent of the manufacturer's rating when subjected to a performance discharge test or a modified performance discharge test. According to TS 3.8.4 and TS 3.8.6 Bases , the reason for the mode restriction for both SRs 3.8.4.3 and SR 3.8.6.6 is that performing the surveillance would remove a 125-VDC electrical power subsystem from service, perturb the electrical distribution system, and challenge safety systems. In the LAR , the licensee stated that the HPCS system is a stand-alone system with a dedicated DG and independent distribution system. The Division 3 DC electrical power subsystem feeds emergency DC loads associated with the HPCS system. The Division 3 battery and battery chargers are physically separated from and electrically independent of all other divisional batteries and battery chargers. Interconnection with the battery and battery chargers or the emergency DC load groups of any other division is not permitted under any condition of plant operation.

The Division 3 battery is disconnected from the battery chargers during the surveillance tests and has no connection with any other equipment that is required to be operable.

The licensee further stated that the Division 3 battery testing is limited to only one electrical division of equipment at a time to ensure that design basis requirements are met. If a fault occurs while testing the Division __ 3 battery, the other two divisional DC electrical power subsystems and their associated emergency loads would be available to provide the minimum safety functions necessary to shut down the unit and maintain it in a safety shutdown condition.

  • The NRC staff finds with reasonable assurance, that performing surveillance testing required by SR 3.8.4.3 and SR 3.8.6.6 in Mode 1 or 2 would have minimal impact on the plant electrical distribution system because the HPCS system is a stand-alone system with an independent electrical distribution system. Thus , performing surveillance testing on the Division 3 battery would only impact the HPCS electrical distribution system , which is already OOS during the system's scheduled maintenance outage. SR 3.8.1.12 and SR 3.8.1.13 SR 3.8.1.12 requires verification that upon the presence of an ECCS initiation signal, the DG automatically starts within a specified time limit and the DG's parameters will achieve the specified limits. As described in the LAR , the simulated ECCS initiation signal is generated only in the HPCS logic and does not affect the other two safety-related divisions (Divisions 1 and 2). Thus, performing testing required by SR 3.8.1.12 affects only the HPCS system. In addition , since this test is conducted with the Division 3 DG unloaded and isolated from its emergency bus, there is no impact to the electrical distribution system , and no mechanism for challenging continued steady state operation. SR 3.8.1.13 requires verification that upon the presence of an ECCS initiation signal , the DG's automatic trip function is bypassed except engine overspeed and generator differential.

As described in the LAR , the test requ i red by SR 3.8.1.13 is performed with the DG not paralleled to offsite power. This surveillance requires verification that the Division 3 DG automatically trips on engine overspeed and generator differential current is performed with the Division 3 DG operating unloaded and isolated from its 4.16 kV emergency bus. The NRC staff finds w i th reasonable assurance, that performing testing required by SR 3.8.1.12 and SR 3.8.1.13 during operating Mode 1 or 2 would have minimal impact on the plant electrical distribution system because the test will be conducted with the Division 3 DG unloaded and isolated from the associated emergency bus. SR 3.8.1.17 The surveillance of SR 3.8.1.17 requires, in part, verification that, with the Division 3 DG operating in the test mode and connected to its bus, a DG overcurrent trip signal automatically

  • disconnects the offsite power source while the DG continues to supply normal loads. As described in the LAR supplement dated May 23, 2019, the test required by SR 3.8.1.17 is performed by paralleling the DG with offsite power. This test demonstrates the ability of the Division 3 DG to remain connected to the emergency bus and supplying necessary loads following a trip of the system auxiliary transformer feeder breaker. With the DG manually started in test mode and paralleled to its emergency bus, a simulated DG overcurrent trip signal is inserted. This causes the offsite power source to automatically disconnect while the DG continues to supply normal loads. The power system loading for this test is within the rating of the affected transformers, switchgear, and breakers.

SR 3.8.1.17 is performed when HPCS is . out of service and declared inoperable.

Division 3 AC electrical power sources are not required to be operable when HPCS is inoperable.

The NRC staff finds, with reasonable assurance, that performing testing required by SR 3.8.1.17 during operating Mode 1 or 2 would have minimal impact on the electrical distribution system because the HPCS system is a stand-alone system with an independent electrical distribution system. Thus, performing surveillance testing on the Divislon 3 DG would only impact the HPCS electrical distribution system, which is already OOS during the system's scheduled maintenance outage. 3.3 Evaluation of Effects on Grid Stability Grid stability is a function of the overall grid configuration with all electrical power lines and equipment connected or synchronized, and the balance of the generation compared to the grid loading. When the DG voltage has been synchronized with the grid voltage, the paralleling circuit breaker can be closed. Once the paralleling circuit breaker has closed, the generator set and grid supplies are "paralleled

." At this stage , the generator set output is normally zero. SR 3.8.1.9 and SR 3.8.1.10 SR 3.8.1.9 requires verification that the DG's frequency is within a specified limit following a rejection of a load greater than or equal to its associated single largest post-accident load. The surveillance of SR 3.8.1.10 requires verification that the DG does not trip and the voltage is maintained within specified limits following a load rejection.

As described in the LAR, testing required by SR 3.8.1.9 and SR 3.8.1.10 is performed by paralleling the Division 3 DG with offsite power and then testing the load rejection by loading the Division 3 DG output breaker. Opening the DG output breaker separates the DG from its associated emergency bus and allows the offsite power source to continue to supply the bus. During normal plant operation, the 4.16 kV emergency buses are aligned to the system auxiliary transformer, which is fed from a 345 kV offsite system. This is the same configuration maintained during plant shutdown when the load rejection testing is currently conducted.

According to the licensee, the protective relay would be available to protect the DG while it is connected to the offsite power source. In addition, the protective instrumentation for sustained offsite power low-voltage conditions, required to be operable per TS 3.3.8.1, " Loss of Power (LOP) Instrumentation

," would be available to respond to such a condition. In the LAR, the licensee further stated that historical voltage data from SR 3.8.1.9 and SR 3.8.1.1 O testing show that the DG voltage change during the transient is approximately 365 V, which is 9 percent of the 4.16 kV rated voltage , with voltage recovery within approximately 3 seconds. Thus, the voltage transient experienced by loads on the bus is minor and would not challenge the loss-of-voltage relay (LVR) or degraded-voltage relay (DVRr The licensee also noted in the LAR that starting the HPCS pump motor is a more limiting transient than a Division 3 full load rejection due to the presence of the pump motor starting transient.

HPCS pump starts are routinely performed online, with offsite power supplying the Division 3 emergency bus, and these tests have not disturbed plant operation.

The NRC staff finds, with reasonable assurance, that performing testing required by SR 3.8.1.9 and SR 3.8.1.10 during operating Mode 1 or 2 would have minimal impact on the grid stability because:

  • The DG's protective relay would be able to protect the DG if a grid disturbance occurs during these tests while the DG paralleled with the grid.
  • The voltage transient resulting from the load rejection test would be considered not . significant to challenge the LVR and DVR , which provide critical protective function for the electrical power systems.
  • When the DG is separated from the emergency bus during testing, performing a DG load rejection test would not cause perturbations to the electrical distribution systems. 3.4 Evaluation of Effects on Offsite Power SR 3.8.1.11, SR 3.8.1.16, and SR 3.8.1.19 SR 3.8.1.11 requires , in part, verification , on an actual or simulated LOOP, auto start of the DG with specified actions and DG's parameter limits. SR 3.8.1.16 requires verification that the DG can be synchronized with the offsite power source while loaded with emergency loads, and upon the restoration of the offsite power, all loads are transferred to offsite power and the DG returns to ready-to-load operation. SR 3.8.1.19 requires, in part, verification that upon the presence of a LOOP signal in conjunction with an ECCS initiation signal, the DG achieves the required voltage and frequency within the specified time, and the DG supplies permanently connected loads for a specified time. As described in the LAR, the test required by SR 3.8.1.11 does not involve an ECCS initiation signal and the HPCS pump will not automatically start. The simulated LOOP signal is generated only at the Division 3 switchgear and does not affect the other two safety-related electrical divisions.

Additionally , due to the relative size of the loads associated with the HPCS system (i.e., 2540 kW), there is minimal potential for this testing to create an offsite power supply perturbation when the Division-3 4.16 kV emergency bus is de-energized.

As described in the LAR , the period of time that the offsite power to the Division 3 emergency bus is disconnected during the test required by SR 3.8.1.16 is small. Additionally, the relative size of the loads associated with the HPCS system (2540 kW) presents minimal potential for creating an offsite power supply perturbation when shifting the load between the Division 3 DG and the offsite power source. As described in the LAR, during performance of the test required by SR.3.8.1.19, the simulated LOOP and ECCS initiation

~ignals affect only the HPCS system and do not affect the other two safety-related electrical divisions.

The period of time that the offsite power source is disconnected from Division 3 emergency bus is minimal. Due to the relative size of the loads associated with the HPCS system, the potential for this testing to create an offsite power supply perturbation when the Division 3 electrical bus is deenergized is minimal. Additionally, HPCS pump starts are routinely performed online to satisfy quarterly inservice testing requirements , without disturbing plant operation The NRC staff finds, with reasonable assurance, that performing testing required by SR 3.8.1.11, SR 3.8.1.16, and SR 3.8.1.19 during operating Mode 1 or 2 would have minimal impact on offsite power because:

  • The potential of offsite power perturbation caused by this testing would be minimal due to small loads associated with the HPCS system.
  • The duration of disconnecting the offsite power from Division 3 emergency bus would be small. 3.5 Evaluation of Division 3 DG Response to LOOP and/or LOCA In the LAR supplement dated April 24, 2019, the licensee described the response oUhe Division 3 DG should a LOOP and/or LOCA occur during the online load rejection testing (SR 3.8.1.9, SR 3.8.1.10, and SR 3.8.1.17) as follows. The licensee's statements have been reordered and headings added in the quotations below. LOOP Per UFSAR Section 8.1.2.2, "In the event of loss of offsite power supplies to an ESF 4160V switch group, there are provisions for automatic tripping of offsite supply circuit breakers, automatic shedding of certain non-ESF loads, automatic starting of the diesel generator, and automatic closing of the DG supply circuit breaker." UFSAR Section 8.3.1.1.2 further states "Division 3 loads are not shed following a loss of bus voltage, since the total connected bus load is within the capacity of the diesel-generator set." As such, if a LOOP were experienced during Division 3 DG online load rejection testing, with the DG is paralleled with offsite power, the Division 3 electrical loads are not tripped. If a LOOP was experienced while the Division 3 DG was operating unloaded (i.e., output breaker open) during online load rejection testing, the Division 3 DG output breaker would automatically close and the DG would supply the Division 3 bus. Per procedure, operators would take action to remove testing leads and set the governor speed droop appropriately.

If a LOCA were experienced while the Division 3 DG was paralleled with offsite power during online load rejection testing, the Division 3 DG would remain running and supplying the bus and all trips, except for the DG differential overcurrent and engine overspeed, would be bypassed.

If a LOCA was experienced while the Division 3 DG was operating unloaded during online load rejection testing, the Division 3 DG would continue to operate unloaded. All trips, except for the DG differential overcurrent and engine overspeed, would be bypassed.

Per procedure, operators would take the action to remove testing leads and set the governor speed droop appropriately. LOOP and LOCA If a LOOP and LOCA were experienced while the Division 3 DG was paralleled with offsite power during online load rejection testing, the Division 3 DG would likewise remain running and supplying the bus and all trips, except for the DG differential overcurrent and engine overspeed, would be bypassed.

If a LOOP and LOCA were experienced while the Division 3 DG was operating unloaded during online load rejection testing, the Division 3 DG output breaker would auto close and the DG would supply the Division 3 bus. All trips, except for the DG differential overcurrent and engine overspeed, would be bypassed.

Per procedure, operators would take action to remove testing leads and set the governor speed droop appropriately. LOOP Followed by Failure of Feeder Breaker In the event of a LOOP without a LOCA, followed by a failure of the feeder breaker from the offsite power source to the Division 3 bus, to open during online load rejection testing, the Division 3 DG would respond in the same manner as it would if the condition were to occur during the monthly operability runs. An overcurrent condition would send a signal to trip the feeder breaker from the offsite power source followed by a trip of the Division 3 DG if the overcurrent condition still existed. The Division 1 and Division 2 emergency buses would automatically isolate from all supply sources. LOOP and LOCA Followed by Failure of Feeder Breaker In the event of a LOOP and LOCA, followed by a failure of the feeder breaker from the offsite power source to the Division 3 bus to open during online load rejection testing, the Division 3 DG would respond in the same manner as it would if the condition were to occur during the monthly operability runs. The Division 3 DG would continue to operate and supply the associated bus. An overcurrent condition would bring in a control room alarm and operators would be required per procedure to reduce DG load. The Division 1 and Division 2 emergency buses would automatically isolate from all supply sources. LOOP While the DG Operating Unloaded The licensee further states that in all above scenarios, the equipment response of the Division 1 and Division 2 safety-related equipment would not be impacted during Division 3 online load rejection testing. In the LAR, the licensee also stated that the testing is limited to only one DG at a time and that if a fault occurs while testing the Division 3 DG, the other two divisional DGs and associated emergency loads would be available to provide the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition.

The NRC staff finds, with reasonable assurance, that in the event of LOOP and/or LOCA with or without failure of the feeder breaker during the online DG surveillance testing, the DG would remain capable of performing its safety function.

3.6 Conclusion

-Technical Evaluation The NRC staff reviewed the licensee's proposed changes to TS 3.8.1, TS 3.8.4, and TS 3.8.6. The amendment would remove the mode restriction on SRs pertaining to Division 3 battery and HPCS DG. These SRs are currently prohibited from being performed in Mode 1 or 2. By removing the mode restrictions, the proposed amendment would allow the above SR to be performed in all modes of operation.

Based on the above evaluations, the staff concludes that the proposed TS changes would have minimal impact on the licensee's ability to continue to meet the intent of GDCs 17 and 18 concerning the availability, capacity, and capability of the electrical power systems. The staff has determined that the proposed change is consistent with 10 CFR 50.36(c)(3) because the revised surveillance requirements 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 LCOs will be met. Therefore, the NRC staff considers the proposed change in the LAR acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Illinois State official was notified of the proposed issuance of the amendment on May 1, 2019. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION The amendments change requirements with respect to installation or use of a facility component located within the restricted area as defined in 1 O CFR, Part 20, and changes SRs. 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 that the amendment involves no significant hazards consideration, and there has been no public comment on such finding (August 14, 2018 (83 FR 40348)). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Pursuantto 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

6.0 CONCLUSION

The Commission hcis concluded, based on the considerations discussed above, 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 Contributor:

K. Nguyen, NRR/EEOB Date of Issuance:

Jun ,= 2 4 , 2 O 1 9 B. Hanson

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2-ISSUANCE OF AMENDMENTS TO RENEWED FACILITY OPERATING LICENSES RE: REMOVAL OF OPERATING MODE RESTRICTIONS FOR PERFORMING SURVEILLANCE TESTING OF THE DIVISION 3 BATTERY AND PRESSURE CORE SPRAY DIESEL GENERATOR (EPID L-2018-LLA-0162)

DATED JUNE 24 , 2019 DISTRIBUTION:

PUBLIC PM File Copy RidsACRS_MailCTR Resource RidsNrrDorlLpl3 Resource RidsNrrDssStsb Resource RidsNrrLASRohrer Resource RidsNrrPMLaSalle Resource RidsRgn3MailCenter Resource RidsNrrDeEeob Resource P. Snyder, NRR/STSB K. Nguyen , NRR/EEOB ADAMS Accession No.: ML19121A505

(*) by e-mail or memo OFFICE NRR/DORL/LPL3/PM NRR/DORL/LPL3/LA NRR/DSS/STSB/BC NRR.DE/EEOB/BC NAME BVaidya SRohrer VCusumano (AProffitt)

DWilliams DATE 05/29/2019 05/02/2019 06/05/19 05/29/2019 OFFICE OGC NRR/DORL/LPL3/BC(A)

NRR/DORL/LPL3/PM NAME KGam i n LRegner BVaidya DATE 06/18/19 06/24/19 06/24/19 OFFICIAL RECORD COPY

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