ML18311A265

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Issuance of Amendments Nos. 233 and 219 to Renewed Facility Operating Licenses License Amendment Request for Temporary Extensions to Technical Specifications
ML18311A265
Person / Time
Site: LaSalle  Constellation icon.png
Issue date: 01/02/2019
From: Bhalchandra Vaidya
Plant Licensing Branch III
To: Bryan Hanson
Exelon Nuclear
Vaidya B, 415-3308
References
EPID L-2018-LLA-0012
Download: ML18311A265 (31)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 January 2, 2019 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

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2- ISSUANCE OF AMENDMENT NOS. 233 AND 219 TO RENEWED FACILITY OPERATING LICENSES RE:

LICENSE AMENDMENT REQUEST FOR TEMPORARY EXTENSIONS TO TECHNICAL SPECIFICATIONS SUPPORTING MAINTENANCE ON PORTIONS OF THE CORE STANDBY COOLING SYSTEM (EPID L-2018-LLA-0012)

Dear Mr. Hanson:

The U.S. Nuclear Regulatory Commission (NRC or Commission) has issued the enclosed Amendment No. 233 to Renewed Facility Operating License No. NPF-11 and Amendment No. 219 to Renewed Facility Operating License No. NPF-18 for the LaSalle County Station (LSCS), Units 1 and 2, respectively. The amendments revise the relevant portions of the technical specification and license pages in response to your application dated January 24, 2018, as supplemented by letters dated June 11, 2018, and July 16, 2018.

The amendments revised the LSCS Technical Specifications (TSs) 3.7.2, "Diesel Generator Cooling Water (DGCW) System," and 3.8.1, "AC Sources-Operating," to allow an extended period to install isolation valves to support replacing degraded core standby cooling system piping.

The changes modify TS 3.7.2 to include a 7-day Completion Time (CT} when one or more required DGCW subsystem(s) are inoperable. The changes to TS 3.8.1 include a 7-day CT when a Division 2 diesel generator (DG) and the required opposite unit Division 2 DG are inoperable. The changes will only be used during four refueling outages, two for Unit 1 prior to July 1, 2024, and two for Unit 2 prior to July 1, 2023. The current planned schedule for the refueling outages, subject to change, is L2R17 (2019), L 1R18 (2020), L2R18 (2021 ), and L 1R19 (2022).

B. Hanson A copy of the Safety Evaluation is also enclosed. A Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely, r(w,~/W--'- fir-Bhalchandra K. Vaidya, Project Manager Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-373 and 50-37 4

Enclosures:

1. Amendment No. 233 to NPF-11
2. Amendment No. 219 to NPF-18
3. Safety Evaluation cc: Listserv

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. 233 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 January 24, 2018, as supplemented by letters dated June 11, 2018, and July 16, 2018, 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. 233, 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.

3. This license amendment is effective as of the date of its issuance and shall be implemented within 30 days from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION c)J oV____

David J. Wrona, 6i~ef Plant Licensing Branch 111 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance: January 2, 2019

Attachment:

Revised License and Technical Specification Pages

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 EXELON GENERATION COMPANY, LLC DOCKET NO. 50-374 LASALLE COUNTY STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 219 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 January 24, 2018, as supplemented by letters dated June 11, 2018, and July 16, 2018, 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. 219, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed 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 30 days from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

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Plant Licensing Branch Ill Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance: January 2, 2019

Attachment:

Revised License and Technical Specification Pages

ATTACHMENT TO LICENSE AMENDMENT NOS. 233 AND 219 RENEWED FACILITY OPERATING LICENSE NOS. NPF-11 AND NPF-18 LASALLE COUNTY STATION, UNITS 1 AND 2 DOCKET NOS. 50-373 AND 50-374 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 INSERT License License NPF-11, Page 3 NPF-11, Page 3 NPF-18, Page 3 NPF-18, Page 3 TS 3.7.2-1 TS 3.7.2-1 TS 3.7.2-2 TS 3.7.2-2 TS 3.7.2-3 TS 3.7.2-3 TS 3.7.2-4 TS 3.7.2-4 TS 3.8.1-4 TS 3.8.1-4 TS 3.8.1-6 TS 3.8.1-6 TS 3.8.1-6a

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; Am. 146 (4) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 01/12/01 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 Am. 202 (5) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 07/21/11 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:

Am. 198 (1) Maximum Power Level 09/16/10 The licensee is authorized to operate the facility at reactor core power levels not in excess of full power (3546 megawatts thermal).

Am. 233 (2) Technical Specifications and Environmental Protection Plan 01/02/19 The Technical Specifications contained in Appendix A, as revised through Amendment No. 233, and the Environmental Protection Plan contained in Appendix B, 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. 233

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 Am. 189 (5) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 07/21/11 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:

Am. 185 (1) Maximum Power Level 09/16/10 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. 219 (2) Technical Specifications and Environmental Protection Plan 01/02/19 The Technical Specifications contained in Appendix A, as revised through Amendment No. 219, and the Environmental Protection Plan contained in Appendix B, 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. 219

DGCW System 3.7.2 3.7 PLANT SYSTEMS 3.7.2 Diesel Generator Cooling Water (DGCW) System LCO 3.7.2 The following DGCW subsystems shall be OPERABLE:

a. Three DGCW subsystems; and
b. The opposite unit Division 2 DGCW subsystem.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

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

Separate Condition entry is allowed for each DGCW subsystem.

LaSalle 1 and 2 3.7.2-1 Amendment No. 233/219

DGCW System 3.7.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. --------NOTES-------- A.l Declare supported Immediately

1. Not applicable to component Cs)

Division 1 during inoperable.

installation of the Division 1 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4,5, or defueled.

2. Not applicable to Division 2 during installation of the Division 2 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4,5, or defueled.

One or more DGCW subsystems inoperable.

(continued)

LaSalle 1 and 2 3.7.2-2 Amendment No. 233/219

DGCW System 3.7.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. --------NOTES-------- B.l Restore DGCW 7 days

1. Only applicable to subsystem to OPERABLE Division 1 during status.

installation of the Division 1 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4,5, or defueled.

2. Only applicable to Division 2 during installation of the Division 2 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4,5, or defueled.

One or more DGCW subsystems inoperable.

(continued)

LaSalle 1 and 2 3.7.2-3 Amendment No. 233/219

DGCW System 3.7.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C. 1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time of Condition B AND not met.

C.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.2.1 Verify each DGCW subsystem manual, power In accordance operated, and automatic valve in the flow with the path, that is not locked, sealed, or Surveillance otherwise secured in position, is in the Frequency correct position. Control Program SR 3.7.2.2 Verify each DGCW pump starts automatically In accordance on each required actual or simulated with the initiation signal. Surveillance Frequency Control Program LaSalle 1 and 2 3.7.2-4 Amendment No. 233/219

AC Sources-Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. --------NOTE--------- C.l Perform SR 3.8.1.1 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />

1. Not applicable to for OPERABLE required the Division 2 DG offsite circuit(s). AND and the opposite unit Division 2 DG Once per during installation 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of Division 2 CSCS thereafter isolation valves during a single AND Unit 1 Refueling Outage completed C.2 Declare required 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from prior to July 1, feature(s), supported discovery of 2024, and during a by the inoperable Condition C single Unit 2 DG(s), inoperable concurrent with Refueling Outage when the redundant inoperability completed prior to required feature(s) of redundant July 1, 2023, while are inoperable. required the outage unit is feature(s) in MODE 4,5, or defueled. AND C.3.1 Determine OPERABLE 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Required Division 3 DG DG(s) are not inoperable. inoperable due to common cause failure.

One required Division 1, 2, or 3 DG C.3.2 Perform SR 3.8.1.2 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> inoperable and the for OPERABLE DG(s).

required opposite unit Division 2 DG AND inoperable.

C.4 Restore required 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> DG(s) to OPERABLE status.

17 days from discovery of failure to meet LCO 3. 8. 1. a orb (continued)

LaSalle 1 and 2 3.8.1-4 Amendment No. 233/219

AC Sources-Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. --------NOTE--------- F.l Restore one required 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />

1. Not applicable DG to OPERABLE during installation status.

of the Division 2 CSCS isolation 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if valves during a Division 3 DG single Unit 1 is inoperable Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July l, 2023, while the outage unit is in MODE 4,5, or defueled.

Two required Division 1, 2, or 3 DGs inoperable.

Division 2 DG and the required opposite unit Division 2 DG inoperable.

(continued)

LaSalle 1 and 2 3.8.1-6 Amendment No. 233/219

AC Sources-Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G. --------NOTE---------- G.1 Restore required 7 days

1. Only applicable Division 2 DG to during installation OPERABLE status.

of Division 2 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4,5, or defueled.

Division 2 DG and the required opposite unit Division 2 DG inoperable.

H. Required Action and H.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time of Condition A, B, C, D, E, F or G not met.

I. Three or more required I .1 Enter LCO 3.0.3. Immediately AC sources inoperable.

LaSalle 1 and 2 3.8.l-6a Amendment No. 233/219

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 233 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-11 AND AMENDMENT NO. 219 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-18 EXELON GENERATION COMPANY, LLC LASALLE COUNTY STATION, UNITS 1 AND 2 DOCKET NOS. 50-373 AND 50-374

1.0 INTRODUCTION

By application dated January 24, 2018, as supplemented by letters dated June 11, 2018, and July 16, 2018 (Agencywide Documents Access and Management System (ADAMS) Accession Nos. ML18024A275, ML18163A146, and ML18197A325, 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 (LSCS}, Units 1 and 2, respectively.

The proposed amendments would revise the LSCS Technical Specifications (TSs) 3.7.2, "Diesel Generator Cooling Water (DGCW) System," and 3.8.1, "AC [alternating current]

Sources-Operating," to allow an extended period to install isolation valves to support replacing degraded core standby cooling system (CSCS) piping.

Specifically, the proposed changes would modify TS 3.7.2 to include a 7-day Completion Time (CT) when one or more required DGCW subsystem(s) are inoperable. The proposed changes to TS 3.8.1 include a 7-day CT when a Division 2 diesel generator (DG) and the required opposite unit Division 2 DG are inoperable. The proposed changes will only be used during four refueling outages, two for Unit 1 prior to July 1, 2024, and two for Unit 2 prior to July 1, 2023.

The current planned schedule, subject to change, is L2R17 (2019), L 1R18 (2020), L2R18 (2021 ), and L 1R19 (2022).

The supplemental letters dated June 11, 2018, and July 16, 2018, provided additional information that clarified the application, did not expand the scope of the application as originally noticed (March 13, 2018 (83 FR 10919)), and did not change the staffs original proposed no significant hazards consideration determination as published in the Federal Register.

Enclosure 3

2.0 REGULATORY EVALUATION

2.1 System Description The function of the CSCS is to circulate lake water from the ultimate heat sink for cooling of the residual heat removal (RHR) heat exchangers, DG coolers, CSCS cubicle area cooling coils, RHR pump seal coolers, and low-pressure core spray (LPCS) pump motor cooling coils. This system also provides a source of emergency makeup water for fuel pool cooling and provides containment flooding water for post-accident recovery.

The CSCS for each unit consists of three independent piping subsystems corresponding to the three essential electrical power supply divisions for each unit.

Division 1 of each unit includes two RHR service water (RHRSW) pumps which supply cooling water to the Division 1 RHR heat exchanger and pump seal cooler. The fuel pool emergency makeup pump in Division 1 of each unit supplies a source of emergency makeup water to the spent fuel pool (SFP). Also included in Division 1 of Unit 1 is a diesel generator cooling water (DGCW) pump which supplies cooling water to the Division 1 DG, Units 1 and 2 LPCS pump motor coolers, and Units 1 and 2 Division 1 CSCS area coolers. Electrical power for operation of these pumps is supplied from Division 1 essential power.

Two RHRSW pumps are also provided in Division 2 of each unit to supply cooling water to the Division 2 RHR heat exchanger and the two Division 2 RHR pump seal coolers. The DGCW pump in Division 2 of each unit supplies cooling water to the Division 2 DG and to the Division 2 CSCS area cooler. The Division 2 fuel pool emergency makeup pump provides a redundant source of emergency makeup water to the SFP and provides a source of containment flooding water to the RHR system for post-accident recovery. Electrical power for these pumps is supplied from Division 2 essential power.

Each of the six CSCS divisions across the two units is configured with a separate suction pipe from the service water tunnel. The CSCS discharge pipes are combined into a common discharge for identical divisions of both Units 1 and 2. The discharge pipe outlets at the CSCS cooling pond are located above the normal cooling lake level.

Redundancy is provided by designing the CSCS system as multiple independent subsystems.

Separation between subsystems assures that no single failure can affect more than one subsystem. Therefore, assuming a single failure in any subsystem including the subsystem shared between units, two subsystems in each unit will remain unaffected. These two subsystems can supply the minimum required cooling water for safe shutdown of a unit or mitigate the consequences of an accident.

Each engineered safety features (ESFs) division has a DG that serves as an independent onsite power source in the event of the simultaneous occurrence of a total loss of offsite power (LOOP) and a loss of the unit auxiliary power system. The DGs have ample capacity to supply all power required for the safe shutdown of both units in the event of a LOOP, a loss-of-coolant accident (LOCA) on one unit concurrent with the shutdown of a unit without a LOCA, or a concurrent shutdown of both units without LOCAs.

The RHR system has three functional modes, each of which contributes towards satisfying the design basis of the system. The different modes of operation include:

  • Low-pressure coolant injection (LPCI) mode

The low-pressure core spray (LPCS) system's primary function is to provide low-pressure core spray to mitigate the effects of an intermediate and large break LOCAs.

2.1.1 Description of the Electrical Power System The LSCS, Units 1 and 2, has five emergency diesel generators (EDGs). Two EDGs are assigned to each unit (1A, 1B, 2A, and 28) with the fifth EDG (0) capable of being lined up to either unit to provide power to the Divisions 1, 2, and 3 emergency power busses. Division 1 for each unit is powered by one swing EOG (i.e., EOG 0). Division 2 for each unit is powered by its specific Division 2 EDGs (i.e., EDGs 1A and 2A).

  • Division 2 powers equipment that is common between both units. Therefore, both Division 2 EDGs are required to be operable to satisfy Division 2 TS operability requirements. Division 3 is powered by two independent EDGs (i.e.,

EDGs 1B and 28) which are also known as high pressure core spray (HPCS) diesels and can be dedicated to supply the HPCS motor for the associated unit. Therefore, the continued operation of each unit is based on the operability of its associated Divisions 1, 2, and 3 EDGs and the opposite unit's Division 2 EOG. The ESFs systems powered by any two of the three divisions provide the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition.

Offsite power is supplied to the switchyard from four 345 kilo Volt (kV) transmission lines. Two of the transmission lines are in service for Unit 1 and the other two lines service Unit 2. From the switchyard, two electrically and physically separate circuits provide AC power for each unit via the unit's assigned station auxiliary transformer (SAT) and via the SAT from the other unit by cross-tie between the two units. The unit SAT provides the normal source of power to the respective unit's Divisions 1, 2, and 3 emergency buses. In the event of a loss of a unit SAT, the Division 1 and 2 emergency buses fast transfer to the unit auxiliary transformer (UAT) which is connected to the main generator output. The Division 3 emergency bus has no second offsite power source, and will automatically be supplied by the Division 3 EOG after the bus is de-energized. The Divisions 1 and 2 emergency buses can be manually transferred to the UAT through the unit ties on a dead bus transfer or a live bus transfer if the EOG is supplying power to the bus.

2.1.2 Relationship between the Core Standby Cooling System and Diesel Generator System The CSCS circulates lake water from the ultimate heat sink for cooling of loads such as the RHR heat exchangers and pump seal coolers, EDG coolers, CSCS cubicle area cooling coils, and RHR and LPCS pump motor cooling coils. The CSCS for each unit consists of three independent piping subsystems corresponding to the three essential electrical power supply divisions for each unit. Division 1 of Unit 1 has a DGCW pump which supplies cooling water to the Division 1 EOG, Unit 1 and 2 LPCS pump motor coolers, and Units 1 and 2 Division 1 CSCS area coolers. Electrical power for operation of these pumps is supplied from Division 1 essential power. Similarly, the DGCW pump in Division 2 of each unit supplies cooling water to the Division 2 EOG and to the Division 2 CSCS area cooler. Electrical power for these pumps is supplied from Division 2 essential power. The HPCS DG and the Division 3 CSCS area cooler

are supplied with cooling water by the Division 3 HPCS DGCW pump. Electrical power for this pump is supplied from Division 3 essential power.

The CSCS provides cooling water to the associated EDGs in each safety-related division required for safe shutdown of the plant.

2.2 Description of Proposed Changes The following changes are proposed by the licensee:

  • The existing Condition A for TS 3.7.2 is modified by notes which state:
1. Not applicable to Division 1 during installation of the Division 1 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4, 5, or defueled.
2. Not applicable to Division 2 during installation of the Division 2 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4, 5, or defueled.
  • A new Condition B for TS 3. 7.2 is added. The Condition states, "One or more DGCW subsystems inoperable." The new Condition Bis modified by notes which state:
1. Only applicable to Division 1 during installation of the Division 1 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4, 5, or defueled.
2. Only applicable to Division 2 during installation of the Division 2 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4, 5, or defueled.

Required Action B.1 requires restoring DGCW subsystem to Operable status with a 7-day CT.

  • A new Condition C for TS 3.7.2 is added. The Condition states, "Required Action and associated Completion Time of Condition B not met." Required Action C.1 requires being in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Required Action C.2 requires being in Mode 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

The two Required Actions are linked with the logical connector"AND."

  • The existing Condition C for TS 3.8.1 is modified by a note which states:
1. Not applicable to the Division 2 DG and the opposite unit Division 2 DG during installation of the Division 2 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4, 5, or defueled.
  • The existing Condition F for TS 3.8.1 is modified by a note which states:
1. Not applicable during installation of the Division 2 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4, 5, or defueled.
  • A new Condition G for TS 3.8.1 is added. The Condition states, "Division 2 DG and the required opposite unit Division 2 DG inoperable." The new Condition G is modified by a note which states:
1. Only applicable during installation of the Division 2 CSCS isolation valves during a single Unit 1 Refueling Outage completed prior to July 1, 2024, and during a single Unit 2 Refueling Outage completed prior to July 1, 2023, while the outage unit is in MODE 4, 5, or defueled.

Required Action G.1 requires restoring required Division 2 DG to Operable status with a 7-day CT.

  • The current Condition G is modified to Condition H and now states, "Required Action and associated Completion Time of Condition A, B, C, D, E, F, or G not met." The corresponding Required Action G.1 is modified to H.1.
  • The current Condition H is modified to Condition I. The corresponding Required Action H.1 is modified to 1.1.

2.3 Regulatory Evaluation The following U.S. Nuclear Regulatory Commission (NRC or Commission) requirements and guidance documents were applied during the NRC staff's review of the application.

Title 10 of the Code of Federal Regulations ( 10 CFR), Part 50, Appendix A, "General Design Criteria for Nuclear Power Plants," General Design Criterion (GDC) 5, "Sharing of structures, systems, and components," states, in part, that structures, systems, and components important to safety shall not be shared among nuclear power units unless it can be shown that such sharing will not significantly impair their ability to perform their safety functions including, in the event of an accident in one unit, an orderly shutdown and cooldown of the remaining units.

The GDC 17, "Electric power systems," states, in part, that nuclear power plants shall have onsite and offsite electric power systems to permit the functioning of structures, systems, and components that are important to safety. The onsite system is required to have sufficient independence, redundancy, and testability to perform its safety function, assuming a single failure. The offsite power system is required to be supplied by two physically independent circuits that are designed and located so as to minimize, to the extent practical, the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. In addition, this criterion requires provisions to minimize the probability of losing electric power from the remaining electric power supplies as a result of loss of power from the unit, the offsite transmission network, or the onsite power supplies.

The regulation at 10 CFR 50.36(a)(1) states: "A summary statement of the bases or reasons for such specifications ... shall also be included in the application, but shall not become part of the technical specifications."

The regulation at 10 CFR 50.36(c) contains the requirements related to the content of TSs.

Pursuant to 10 CFR 50.36, TSs are required to include items in the following categories:

(1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation (LCOs); (3) surveillance requirements (SRs); (4) design features; and (5) administrative controls. The regulation does not specify the particular requirements to be included in a plant's TSs.

Requirement 10 CFR 50.36(b) also requires the TSs to be derived from the analyses and evaluation included in the safety analysis report and amendments thereto.

As discussed in 10 CFR 50.36(c)(2)(ii), LCOs are the lowest functional capability or performance level of equipment required for safe operation of the facility. When LCOs are not met, the licensee shall shut down the reactor or follow any remedial action permitted by the TSs until the LCOs can be met. The ACTIONs in TSs describe the remedial actions permitted when LCOs are not met.

Paragraph 10 CFR 50.57(a) states that an operating license may be issued upon finding, among other things, that:

(3) There is reasonable assurance (i) that the activities authorized by the operating license can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the regulations in this chapter.

Regulation 10 CFR 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," requires that preventing failures of structures, systems, and components through maintenance is appropriately balanced against the objective of minimizing unavailability of structures, systems, and components due to monitoring or preventive maintenance.

Regulation 10 CFR 50.63, "Loss of all alternating current power," requires a nuclear power plant to be able to withstand for a specified duration and recover from a complete loss of offsite and onsite AC sources.

The NRC staff also considered the following guidance documents to evaluate the license amendment request (LAR):

Regulatory Guide 1.93, "Availability of Electric Power Sources," provides guidance with respect to operating restrictions or CT if the number of available AC sources is less than that required by the TS LCO. In particular, this guide prescribes a maximum CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for an inoperable onsite or offsite AC source.

NRC Branch Technical Position (BTP) 8-8, "Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions," February 2012, provides guidance to NRC staff for the evaluation of allowed outage time extension requests for onsite and offsite power sources to allow on-line maintenance of on EDGs that would normally be performed during refueling outages, or maintenance of offsite power sources.

The NRC's guidance for the format and content of licensee's TSs can be found in the Standard Technical Specifications (STS) for boiling-water reactors (BWRs) in NUREG-1433, "Standard Technical Specifications General Electric Plants BWR/4" and NUREG-1434, "Standard Technical Specifications General Electric Plants, BWR/6."

3.0 TECHNICAL EVALUATION

3.1 Background In its application for the LAR dated January 24, 2018, the licensee stated that in an attempt to enhance the reliability of the Unit 1 and Unit 2 CSCS, the licensee would like to replace the portion of DGCW return piping directly connected to the lake and below normal cooling lake level. This maintenance will require isolation by hot tapping, installing temporary line stops (stopples), and then installing new isolation valves. The licensee further stated that installation of new isolation valves for a Division of CSCS cannot be assured within the existing CTs for applicable TS. The licensee stated that CTs of 7 days will allow sufficient time to complete the installation of new isolation valves.

3.1 Staff Evaluation 3.1.1 Containment and Plant Systems The licensee in its application has proposed four separate DGCW configurations to replace two lines in Division 1 and two lines in Division 2 of the DGCW system and install an isolation valve in each replacement line. The piping to be replaced will be in DGCW piping of an outage unit, but each piping replacement will affect the TSs of the operating unit. The piping to be replaced will be isolated from the operating DGCW system by a non-code (non-ASME (American Society of Mechanical Engineers), Section Ill) line stops/stopples which will be installed online using hot tap procedures. The stopples would provide a pressure boundary to allow piping replacement and valve installation. The use of stopples in the licensee's proposal would allow one unit to remain in Modes 1-3 while the other unit is in Mode 4, 5, or defueled. Using stopples provides a pressure boundary and makes the affected DGCW subsystems and RHRSW trains inoperable but available. The cooling loads immediately upstream of the piping to be replaced will be inoperable and unavailable.

Two lines are downstream of the emergency core cooling system (ECCS) room coolers and LPCS pump cooler for each unit which connect to a common discharge header in Division 1.

Two other lines are downstream of the A and B RHR seal coolers and its associated room cooler for each unit which connect to a common discharge header in Division 2. The lines are shown in Attachment 2, Figures 1 through 4, in the LAR and listed below:

  • 2DG06A-4" adjacent to line 2RH83BB-24" The lines will be replaced in four separate outages, two outages per unit. The licensee has stated that the existing CTs for TSs 3.7.2 and 3.8.1 will not allow sufficient time to complete each installation and is requesting CTs of 7 days to complete each installation.

The NRC staff noted that the stopples may leak or fail during the line replacement and questioned the added weight and moment and the potential adverse seismic response caused by the hot tap equipment. Therefore, in an email request for additional information (RAI) dated June 14, 2018 (ADAMS Accession No. ML18166A187), the staff requested the licensee provide the following information:

(a) Identify and discuss the possible impact on plant safety caused by expected leakage past the line stops.

(b) What precautions will be needed and implemented to mitigate the effects of leakage?

(c) Considering the added weight and moment of the hot tap hardware, what actions will be taken or analysis will be performed to ensure plant safety during a seismic event, including a seismic induced loss of offsite power?

(d) Since the pipes to be replaced are not isolable and below lake level, what contingency plans are there to combat flooding caused by possible gross failure of line stops or pipe?

The licensee responded in a letter dated July 16, 2018 (ADAMS Accession No. ML18197A325),

noting the CSCS system is a low-pressure system with a maximum expected pressure at the stopples of 16 pounds per square inch gauge (psig), that stopples are qualified for the maximum expected pressure and seismic load, that adequate flood protection measures will be at the stopple locations, that leakage control material including damage control plugs will be pre-staged, and that the hot tap hardware will be seismically analyzed and supported to withstand a design basis seismic event. The NRC staff was satisfied that the licensee satisfactorily considered possible leakage, the added weight and seismic concerns of the hot tap equipment, and possible gross failure with flooding.

The pipe line replacement will be only in an outage unit. Each line will be isolated from the main discharge header with a non-code line stop/stopple. The isolation will be performed with the system pressurized and in operation by using a hot tap tool. When each line is being replaced, the DGCW and RHRSW cooling loads in the associated division (either Division 1 or 2) will become inoperable for both units because of the non-code line stop acting as an isolation barrier. The cooling loads (associated with the outage unit) that are upstream of the replacement line will be inoperable and unavailable because of no DGCW or RHRSW flow. The other loads for both units in the associated division have flow and are inoperable because of the non-code stopple, but are available because they have full DGCW or RHRSW flow. The other divisions (either Division 1 or 2 and 3) where no work is being performed will be operable.

When replacing line 2DG23B-6" in Division 1 of Unit 2 or line 1DG23B-6" in Division 1 of Unit 1, as shown in Figures 1 and 2, Attachment 2, of the LAR, the following components become inoperable in both units. LPCS pump coolers, an RHR pump and pump room cooler, LPCS and RCIC (reactor core isolation coolant) pump room coolers, a RHR heat exchanger, and the OA DG. These cooling loads in the outage unit (except the OA DG which is inoperable but available) are loads inoperable and unavailable. The same loads in the operating unit become inoperable but available because they have DGCW and RHRSW flow. Figures 1 and 2 of of the LAR show the inoperable/available and inoperable/unavailable components. In the operating unit, one subsystem of DGCW and one train of RHRSW and the OA DG become inoperable. This would currently cause entry into TS 3. 7 .1, Condition A, and TS 3.7.2, Condition A. TSs for DGCW supported systems would also be entered. Supported system TSs are TS 3.5.1, "ECCS-Operating," TS 3.5.3, "RCIC System," TS 3.6.2.3, "Residual

Heat Removal (RHR) Suppression Pool Cooling," and TS 3.6.2.4, "Residual Heat Removal (RHR) Suppression Pool Spray." However, the licensee proposed adding Note 1 to TS 3.7.2 Condition A and new Condition B which would allow a 7-day CT to restore inoperable DGCW subsystems. The licensee also added new Condition C to TS 3. 7.2 to account for when the CT of new Condition Bis not met. The new Note 1 to 3.7.2 Condition A would allow the licensee to not enter supported system TS by utilizing the provisions of TS 3.0.6.

When replacing line 1DG06A-4" in Division 2 of Unit 1 or line 2DG06A-4" in Division 2 of Unit 2, as shown in Figures 3 and 4 of Attachment 2 of the LAR, the following components become inoperable in both units: B and C RHR pumps and pump room cooler, B RHR heat exchanger, and the 1A and 2A DGs. The Band C RHR pumps and pump room cooler in the outage unit are inoperable and unavailable. The same loads in the operating unit become inoperable, but available because they have DGCW and RHRSW flow. Figures 3 and 4 of Attachment 2 of the LAR show the inoperable/available and inoperable/unavailable components. In the operating unit, one subsystem of DGCW and one train of RHRSW and the unit specific DG become inoperable/available. This would currently cause entry into TS 3.7.1 Condition A, TS 3.7.2 Condition A, and TS 3.8.1 Conditions C and F. TS for DGCW supported systems TS would also be entered. Supported system TSs are TS 3.5.1, "ECCS-Operating," TS 3.6.2.3, "Residual Heat Removal (RHR) Suppression Pool Cooling," and TS 3.6.2.4, "Residual Heat Removal (RHR) Suppression Pool Spray." However, the licensee proposed adding Note 2 to TS 3.7.2 Condition A and new Condition B, which would allow a 7 day CT to restore inoperable DGCW subsystems to operable status. New Condition C to TS 3. 7 .2 is added to shutdown the unit if the CT for new Condition Bis not met. The new Note 2 to 3.7.2 Condition A would allow the licensee to not enter supported system TS by utilizing the provisions of TS 3.0.6. The licensee has also proposed adding Note 1 to TS 3.8.1 Conditions C and F and new Condition G, which would allow a 7-day CT to restore the required Division 2 DGs to operable status.

The licensee's proposed TS change would increase the CT of one or more inoperable DGCW subsystems (TS 3. 7.2) and two inoperable ECCS subsystems (TS 3.5.1) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days. TS 3.7.1 and the other supported system TSs have CTs that are not challenged by the requested CT extension of TS 3.7.2. The licensee's proposed TS change would also increase the CT of one inoperable required Division 2 DG and the inoperable required opposite unit Division 2 DG from 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to 7 days.

Based on the above, the following facts are established:

(a) During the planned line replacements, the remaining DGCW subsystems in the other divisions (Division 1 or 2 and Division 3) are operable.

(b) The licensee has a Configuration Risk Management Program (CRMP), which programmatically manages risk by identifying equipment lineups that increase risk.

(c) The licensee's proposed changes to TSs 3.7.2 and 3.8.1 will be limited to four occurrences in four separate outages.

Additionally, the NRC staff concludes the following:

(a) The inoperable DGCW subsystem(s) in the operating unit are available with full DGCW flow and would perform its safety functions if needed.

(b) The likelihood of line stop (stopple) failure is very low since it is seismically qualified and qualified for full system pressure in a low pressure system.

(c) The licensee satisfactorily addressed possible leakage, the added weight and seismic concerns of the hot tap equipment, and possible gross failure with flooding.

(d) The DGCW and RHRSW systems are only needed during a design basis accident (OBA) and the likelihood of a OBA and stopple failure is very low during the CT extension from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days.

(e) The added risk to public safety is very low for a concurrent OBA and line stopple failure when extending the CTs in TS 3.7.2 and TS 3.8.1 (requires NRC approval) as proposed in this LAR.

The CRMP includes a protective equipment program to minimize risk to both the online and outage units. This program administers and controls (restricts) access to and work performed on protected equipment. Access to other equipment considered important to managing overall plant risk will also be controlled.

3.1.2 Electrical Engineering Systems In accordance with TS LCO 3.0.1, the components supported by inoperable DGCW subsystems will be declared inoperable. In this case, the EDGs will be declared inoperable for the duration that the DGCW is inoperable. Though the piping upgrade will be implemented during the separately planned refueling outages for Unit 1 and Unit 2, Condition C of TS 3.8.1 currently requires both units' Division 2 EDGs to be inoperable with a CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and Condition F currently requires both units' Division 2 EDGs to be inoperable with a CT of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The licensee has concluded that the installation of new isolation valves for a Division of CSCS cannot be assured with the existing CTs for applicable TS. The requested CTs of 7 days will allow sufficient time to complete the installation of new isolation valves. After installing and testing the isolation valves, the pressure boundary will be conforming and EOG operability will be restored, after which the DGCW return piping replacement will continue upstream of the new isolation valves.

The NRC staff evaluated the licensee's request to extend the CT for EDGs to determine whether the station blackout (SBO) requirement in 10 CFR 50.63 would be eroded by the proposed changes and whether the overall availability of the EDGs would be reduced significantly as a result of maintenance activities associated with the operating unit.

The NRC staff has developed guidance in BTP 8-8, "Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions," for evaluating requests by licensee's for allowed outage time (AOT) extensions to perform online maintenance. The BTP specifically discusses aspects of onsite and offsite power sources from a deterministic perspective and recommends that a supplemental power source should be available as a backup to the inoperable EOG or offsite power source, to maintain the defense-in-depth design philosophy of the electrical system to meet its intended safety function. The licensee has stated that the BTP is not applicable to this LAR due to the following:

  • The EDGs or offsite power source are not in the scope of planned maintenance.
  • Though EDGs will be declared inoperable, they will remain available and fully capable of supplying their design electrical loads.
  • There will be no increase in the EOG electrical loading.
  • The EOG control circuitry and automatic start logic will not be changed.
  • All EOG support systems will remain available for EOG operation. No additional operator action will be required for operation of the EDGs.
  • The planned maintenance will not affect how the DGs are operated or controlled.
  • Other than the portion of the DGCW return piping, which will be replaced on the outage unit, the DGCW subsystems, EDGs, and offsite power sources will remain available and fully capable of performing their design functions.

The attachments to the LAR include sketches depicting DGCW systems and the association with the degraded piping. The NRC staff noted that work will be performed on portions of the CSCS that are also supplied by the DGCW pumps and a non-code valve will be installed on the discharge side of the EDG cooling system. Since the DGCW pump can start at any time that an EDG gets an emergency start signal, by letter dated May 10, 2018, the staff requested clarification on availability of EDG during the process of securing portions of CSCS for planned maintenance. In its letter dated June 11, 2018, the licensee stated, "During all phases of the work requiring entry into the proposed Technical Specifications the DG CWP [cooling water pump] for the affected Division will remain unisolated and available to support any start of the affected Diesel Generator."

The NRC staff also requested clarification on consequences of a postulated failure of the temporary non-code stopple valve and the impact on the performance capabilities of the associated EDG cooling system if the available EDGs are required to power safety-related loads. In response, the licensee stated that:

  • Leakage control materials will be pre-staged at each valve location in the unlikely event the mechanical line stops were to begin leaking during maintenance evolutions while the line is breached.
  • Any leakage that is incurred will be on the outage unit and will not be exposed to LOCA conditions on the operating unit, thereby allowing access for compensatory actions should leakage from the line stop occur.
  • Since the work is being performed downstream of EDG coolers, the DGCW pump will continue to supply the EDG coolers without limitation.
  • Significant leakage is not anticipated as the mechanical line stop is installed in an open-ended return line with a maximum estimated pressure of 16 psig.

Based on the information provided in the LAR and responses to RAls, the NRC staff has concluded that the offsite power and onsite power sources, though not operable, will remain available and fully capable of performing their design functions during the planned upgrade of CSCS piping and entry into the 7-day CT for TS 3.8.1.

In the LAR, the licensee has provided details on CRMP that is used for planning work activities and managing emerging conditions to ensure that defense-in-depth is maintained. The licensee has stated that the LSCS CRMP includes a protective equipment program to minimize risk to both the on line and outage units. Some of the contingencies that the licensee identified include programmatic activities, such as controlling access to other equipment considered important to managing overall plant risk and deferring, to the extent possible, the performance of any maintenance or testing related to the operable train of equipment. The licensee has identified the following electrical systems for restricted access during the planned CSCS maintenance work:

  • Division 1 and Division 2 Switchgear for online unit
  • Division 1 and Division 2 Switchgear for outage unit
  • Division 1 and Division 2 DG for both units
  • Division 3 Switchgear for operating unit
  • Division 3 DG for operating unit
  • Support equipment for DGs such as Divisions 1, 2, and 3 CSCS Based on the CT extension being applicable for a limited duration, the NRC staff considers the programmatic activities to be appropriate and adequate for maintaining defense-in-depth.

The NRC staff evaluated the licensee's request to extend the CTs associated with the EOG system during the implementation of piping modifications for DGCW system from a deterministic perspective. The staff's deterministic evaluation supports the proposed extension of the CT for the EOG systems to 7 days as related to TS LCO 3.8.1, Condition C and Condition F. This proposed CT of 7 days will only be applicable during a single Unit 1 Refueling Outage prior to July 1, 2024, and a single Unit 2 Refueling Outage prior to July 1, 2023.

The NRC staff also concludes that entries into TS 3.8.1 will be adequately controlled by the licensee's configuration risk management programs. The licensee will implement compensatory measures that will prohibit discretionary maintenance and testing on redundant equipment as detailed in the LAR.

3.1.3 Detailed Discussion of Technical Specification Changes The licensee provided an evaluation of the proposed TS changes in Section 2.3 of the LAR. A portion of the justification for the proposed CTs is contained in Section 3.0 of the LAR.

3.1.3.1 Changes to TS 3.7.2 As described in Section 2.2 of this safety evaluation (SE), the licensee proposed adding two NOTEs to Condition A, a new Condition B for the situation when one or more DGCW subsystems is inoperable, and a new Condition C for the situation when the Required Action and associated CT of Condition B is not met.

The licensee's evaluation and justification for the proposed changes, which can be found in Section 2.3 of the LAR, states:

The two notes added to TS 3.7.2 Condition A and the proposed Condition B restrict the applicability and use of the extended CT requested to install CSCS isolation valves. The period of applicability is only during the refueling outages prior to identified cutoff dates, to be used once for each division on each unit (four times in total), and is during the periods when the DGCW is inoperable due to use of a nonconforming line stop. The two notes added to TS 3.7.2 Condition A and proposed Condition B are not intended for use when any DGCW subsystem is inoperable for any other reason.

The licensee further justified the changes in its evaluation in Section 2.3 of the LAR by stating:

In accordance with TS LCO 3.0.1 the components supported by inoperable DGCW subsystems will be declared inoperable; however, the CTs of the LCO Required Actions of the supported systems are not of sufficient duration to allow completion of the work evolution. TS LCO 3.0.6 requires entry into the supported system Conditions and Required Actions pursuant to TS LCO 3.0.2 when the

support system's Required Actions direct the supported system to be declared inoperable. By adding the proposed 7 day CT for one or more inoperable DGCW subsystems, the allowances of TS LCO 3.0.6 can be utilized to defer entry into the supported system Conditions and Required Actions and the duration of the inoperability will be controlled by the support system LCO Actions. The proposed Condition B and C added to TS 3. 7 .2 supplements the CT by adding an end state for the proposed Required Action CTs.

The NRC staff reviewed the proposed changes to TS 3.7.2 as well as the licensee's evaluation of the changes. The staff determined that the proposed NOTEs appropriately modify and limit when the associated Conditions apply. As discussed in 3.1.1 of this SE, the staff determined that the proposed CT of 7 days for new Condition B is acceptable during installation of each CSCS isolation valve so long as the maintenance is performed in a manner which maintains availability of the CSCS system and DGCW subsystem for the online Unit, as described in Section 3.0 of the LAR. The staff determined that the licensee's evaluation justifies the changes and that the regulatory requirements of 10 CFR 50.36(b) are met for the proposed changes to TS 3. 7.2. Therefore, the staff finds the proposed changes are acceptable.

3.1.3.2 Changes to TS 3.8.1 As described in Section 2.2 of this SE, the licensee proposed adding a NOTE to Conditions C and F, a new Condition G for the situation when the Division 2 DG and the required opposite unit Division 2 DG are inoperable, and editorial changes to existing Conditions G and H.

The licensee's evaluation and justification for the proposed changes, which can be found in Section 2.3 of the LAR, states:

The two notes added to TS 3.8.1 Conditions C and F, and proposed new Condition G restrict the applicability and use of the extended CT requested to install CSCS isolation valves. The period of applicability is only during the refueling outages prior to identified cutoff dates, to be used one-time for each unit, and is during the periods when the Division 2 DGs are inoperable due to use of a nonconforming line stop. The two notes added to TS 3.8.1 Conditions C and F, and proposed new Condition Gare not intended for use when both Division 2 DGs are inoperable for any other reason.

As discussed in Section 3.1.2 of this SE, the NRC staff reviewed the proposed changes to TS 3.8.1 as well as the licensee's evaluation of the changes. The staff determined that the proposed NOTEs appropriately modify and limit when the associated conditions apply. The staff determined that the proposed CT of 7 days for New Condition G is acceptable during installation of each CSCS isolation valve so long as the maintenance is performed in a manner which maintains availability of the CSCS system and DGCW subsystem for the online unit, as described in Section 3.0 of the LAR. The staff determined that the licensee's evaluation justifies the changes and that the regulatory requirements of 10 CFR 50.36(b) are met for the proposed changes to TS 3.8.1.

Therefore, the staff finds the proposed changes are 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 November 7, 2018. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. 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 (March 13, 2018 (83 FR 10919)). 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.

6.0 CONCLUSION

The Commission has 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 Contributors: G. Purciarello, NRR/DSS/SCPB G. Matharu, NRR/DE/EEOB M. Hamm, NRR/DSS/STSB Date of Issuance: January 2, 2019

B. Hanson

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2 - ISSUANCE OF AMENDMENT NOS. 233 AND 219 TO RENEWED FACILITY OPERATING LICENSES RE:

LICENSE AMENDMENT REQUEST FOR TEMPORARY EXTENSIONS TO TECHNICAL SPECIFICATIONS SUPPORTING MAINTENANCE ON PORTIONS OF THE CORE STANDBY COOLING SYSTEM (EPID L-2018-LLA-0012) DATED JANUARY 2, 2019 DISTRIBUTION:

PUBLIC PM File Copy RidsACRS_MailCTR Resource RidsNrrDorlLpl3 Resource RidsNrrLASRohrer Resource RidsNrrPMLaSalle Resource RidsRgn3MailCenter Resource RidsNrrDssStsb Resource RidsDeEeob Resource RidsNrrDssScpb Resource G. Purciarello, NRR/SCPB M. Hamm, NRR/STSB G. Matharu, NRR/EEOB ADAMS A ccess1on N o.: ML18311A265 (*) b>Y e-ma1*1 or memo OFFICE NRR/DORL/LPL3/PM NRR/DORL/LPL3/LA NRR/DSS/STSB/BC(*) NRR/DE/EEOB/BC(*)

NAME BVaidya (KGreen for) SRohrer VCusumano JQuichocho DATE 12/6/18 11/3/18 08/17/2018 08/15/2018 OFFICE NRR/DSS/SCPB/BC(*) OGC* NRR/DORL/LP L3/BC NRR/DORL/LPL3/PM NAME SAnderson KGamin (NLO) DWrona BVaidya (KGreen for)

DATE 11/6/2018 11/29/18 01/02/19 01/02/19 OFFICIAL RECORD COPY

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