ML22222A086

Issuance of Amendment Nos. 317 and 208 Revise Technical Specification 3.3.5, Loss of Power (LOP) Diesel Generator (DG) Start and Bus Separation Instrumentation

ML22222A086
Person / Time
Site:	Beaver Valley
Issue date:	09/01/2022
From:	Ballard B Plant Licensing Branch 1
To:	Grabnar J Energy Harbor Nuclear Corp
Ballard B, NRR/DORL
References
EPID L-2021-LLA-0156
Download: ML22222A086 (37)

Text

September 1, 2022

Mr. John J. Grabnar Site Vice President Energy Harbor Nuclear Corp.

Beaver Valley Power Station Mail Stop P-BV-SSEB P.O. Box 4, Route 168 Shippingport, PA 15077-0004

SUBJECT:

BEAVER VALLEY POWER STATION, UNITS 1 AND 2 - ISSUANCE OF AMENDMENT NOS. 317 AND 208 RE: REVISE TECHNICAL SPECIFICATION 3.3.5, LOSS OF POWER (LOP) DIESEL GENERATOR (DG) START AND BUS SEPARATION INSTRUMENTATIO N (EPID L-2021-LLA-0156)

Dear Mr. Grabnar:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 317 to Renewed Facility Operating License No. DPR-66 for the Beaver Valley Power Station, Unit 1, and Amendment No. 208 to Renewed Facility Operating License No. NPF-73 for the Beaver Valley Power Station, Unit 2. The amendments consist of changes to the technical specifications in response to your application dated August 29, 2021 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML21242A125), as supplemented by letters dated April 4, 2022, and August 2, 2022 (ML22094A115 and ML22214B739, respectively).

The amendments add notes to required actions C.1 and D.1 of Technical Specification 3.3.5, and revise Table 3.3.5-1, Loss of Power Diesel Generator Start and Bus Separation Instrumentation.

J. Grabnar

A copy of the related safety evaluation is also enclosed. Notic e of Issuance will be included in the Commissions monthly Federal Register notice.

Sincerely,

/RA/

Brent T. Ballard, Project Manager Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Docket Nos. 50-334 and 50-412

Enclosures:

1. Amendment No. 317 to DPR-66

2. Amendment No. 208 to NPF-73

3. Safety Evaluation

cc: Listserv ENERGY HARBOR NUCLEAR CORP.

ENERGY HARBOR NUCLEAR GENERATION LLC

DOCKET NO. 50-334

BEAVER VALLEY POWER STATION, UNIT NO. 1

AMENDMENT TO RENEWED FACILITY OPERATING LICENSE

Amendment No. 317 Renewed License No. DPR-66

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

A. The application for amendment by Energy Harbor Nuclear Corp., acting on its own behalf and as agent for Energy Harbor Nuclear Generation LLC* ( the licensees),

dated August 29, 2021, as supplemented by letter dated April 4, 2022, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations s et forth in 10 CFR Chapter I.

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

C. There is reasonable assurance (i) that the activities author ized by this amendment can be conducted without endangering the health and safety of t he public, and (ii) that such activities will be conducted in compliance with the Commissions regulations;

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

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

• Energy Harbor Nuclear Corp. is authorized to act as agent for Energy Harbor Nuclear Generation LLC and has exclusive responsibility and control over the physical construction, operation, and maintenance of the facility.

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 Renewed Facility Operating License No. DPR-66 is hereby amended to read as follows:

(2) Technical Specifications

The Technical Specifications contained in Appendix A, as revised through Amendment No. 317, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications.

3. This license amendment is effective as of its date of issuan ce and shall be implemented within 60 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

Hipólito J. González, Chief Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications

Date of Issuance: September 1, 2022

ENERGY HARBOR NUCLEAR CORP.

ENERGY HARBOR NUCLEAR GENERATION LLC

DOCKET NO. 50-412

BEAVER VALLEY POWER STATION, UNIT 2

AMENDMENT TO RENEWED FACILITY OPERATING LICENSE

Amendment No. 208 Renewed License No. NPF-73

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

A. The application for amendment by Energy Harbor Nuclear Corp., acting on its own behalf and as agent for Energy Harbor Nuclear Generation LL C* (the licensees), dated August 29, 2021, as supplemented by letter da ted April 4, 2022, complies with the standards and requirements of the Atomi c Energy Act of 1954, as amended (the Act), and the Commissions rules and regu lations set forth in 10 CFR Chapter I.

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

C. There is reasonable assurance (i) that the activities author ized by this amendment can be conducted without endangering the health and s afety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations;

D. The issuance of this amendment will not be inimical to the c ommon 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 Commissions regulations and all applicable requirements have been satisfied.

• Energy Harbor Nuclear Corp. is authorized to act as agent for Energy Harbor Nuclear Generation LLC and has exclusive responsibility and control over the physical construction, operation, and maintenance of the facility.

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 Renewed Facility Operating License No. NPF-73 is hereby amended to read as follows:

(2) Technical Specifications

The Technical Specifications contained in Appendix A, as revised through Amendment No. 208, and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto and hereby incorporated in the license. FENOC shall operate th e facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. This license amendment is effective as of its date of issuan ce and shall be implemented within 60 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

Hipólito J. González, Chief Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

September 1, 2022 Changes to the Renewed Facility Operating License and Technical Specifications

Date of Issuance: September 1, 2022

ATTACHMENT TO LICENSE AMENDMENT NOS. 317 AND 208

BEAVER VALLEY POWER STATION, UNITS 1 AND 2

RENEWED FACILITY OPERATING LICENSE NOS. DPR-66 AND NPF-73

DOCKET NO. 50-334 and 50-412

Replace the following pages of the Renewed Facility Operating L icenses with the attached revised pages. The revised pages are identified by amendment n umber and contain marginal lines indicating the area of change.

Renewed Facility Operating License No. DPR-66

Remove Insert P age 3 P age 3

Renewed Facility Operating License No. NPF-73

Remove Insert P age 4 P age 4

Replace the following pages of the Appendix A, Technical Specif ications, with the attached revised pages. The revised pages are identified by amendment n umber and contain marginal lines indicating the areas of change.

Appendix A, Technical Specifications

Remove Insert 3.3.5 - 1 3.3.5 - 1 3.3.5 - 2 3.3.5 - 2 3.3.5 - 3 3.3.5 - 3

---

3.3.5-3a

(3) Energy Harbor Nuclear Corp., 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 monito ring equipment calibration, and as fission detectors in amounts as required;

(4) Energy Harbor Nuclear Corp., 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 chem ical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components;

(5) Energy Harbor Nuclear Corp., pursuant to the Act and 10 CFR Parts 30, 40, and 70, to possess, but not separate, such byproduct and specia l nuclear materials as may be produced by the operation of the facility.

C. This renewed operating license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter 1:

Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Se ctions 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional condit ions specified or incorporated below:

(1) Maximum Power Level

Energy Harbor Nuclear Corp. is authorized to operate the facili ty at a steady state reactor core power level of 2900 megawatts thermal.

(2) Technical Specifications

The Technical Specifications contained in Appendix A, as revise d through Amendment No. 317, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Spe cifications.

(3) Auxiliary River Water System

(Deleted by Amendment No. 8)

Amend ment No. 317 BeaverValleyUnit1R enewed Operating License DPR-66

C. This renewed operating license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations set forth in 10 CFR Chapter 1 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 condition s specified or incorporated below:

(1) Maximum Power Level

Energy Harbor Nuclear Corp. is authorized to operate the facility at a steady state reactor core power level of 2900 megawatts thermal.

(2) Technical Specifications

The Technical Specifications contained in Appendix A, as revised through Amendment No. 208, and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto are hereby incorporated in the license. Energy Harbor Nuclear Corp. shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Amend ment No. 208 BeaverValleyUnit2R enewed Operating License NPF-73

LOP DG Start and Bus Separation Instrumentation 3.3.5

3.3 INSTRUMENTATION

3.3.5 Loss of Power (LOP) Diesel Generator (DG) Start and Bus Separation Instrumentation

LCO 3.3.5 The DG Start and Bus Separation instrumentation specified in Table 3.3.5-1 shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4, When associated DG is required to be OPERABLE by LCO 3.8.2, "AC Sources - Shutdown."

ACTIONS

-NOTE -

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more Functions A.1 Enter the applicable Immediately with one or more required Condition(s) referenced in channels inoperable. Table 3.3.5-1 for the affected channel(s).

B. One or more Functions ------------------------------------------------

with one channel per bus -NOTE -

inoperable. The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for surveillance testing of other channels provided the corresponding instrument channels, electrical bus, and DG in the other train are OPERABLE.

B.1 Place channel in trip. 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />

C. One or more Functions ------------------------------------------------

with two channels per bus -NOTE -

inoperable. Functions 1 and 2 may be bypassed for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> while starting the A RCP provided the corresponding instrument channels, electrical bus, and DG in the other train are OPERABLE.

C.1 Restore one channel per 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> bus to OPERABLE status.

Beaver Valley Units 1 and 2 3.3.5 - 1 Amendments 317 / 208 LOP DG Start and Bus Separation Instrumentation 3.3.5

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

D. One or more Functions ------------------------------------------------

with one channel per bus -NOTE -

inoperable. Functions 1 and 2 may be bypassed for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> while starting the A RCP provided the corresponding instrument channels, electrical bus, and DG in the other train are OPERABLE.

D.1 Restore inoperable 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> channel to OPERABLE status.

E. Required Action and E.1 Enter applicable Immediately associated Completion Condition(s) and Required Time not met. Action(s) for the associated DG made inoperable by LOP DG start or Bus Separation instrumentation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY

SR 3.3.5.1 -------------------------------------------------------------------------

-NOTE -

Verification of setpoint is not required.

Perform TADOT. In accordance with the Surveillance Frequency Control Program

SR 3.3.5.2 Perform CHANNEL CALIBRATION. In accordance with the Surveillance Frequency Control Program

SR 3.3.5.3 Verify ESF RESPONSE TIMES are within limit. In accordance with the Surveillance Frequency Control Program

Beaver Valley Units 1 and 2 3.3.5 - 2 Amendments 317 / 208 LOP DG Start and Bus Separation Instrumentation Before Degraded Voltage Relay Reduced Time Delay Modifications 3.3.5

Table 3.3.5-1 (page 1 of 1)

Loss of Power Diesel Generator Start and Bus Separation Instrumentation

REQUIRED UNIT 1 UNIT 2 CHANNELS ALLOWABLE ALLOWABLE FUNCTION PER BUS CONDITIONS VALUE VALUE

Loss of Voltage

1. 4160 V Emergency 1 D, E 2962 V with a 2962 V with a time Bus DG start time delay of delay of 0.33 0.03

< 0.9 seconds seconds

2. 4160 V Emergency 1 (Unit 1) D,E (Unit 1) 2962 V with a 2962 V with a time Bus Bus Separation 2 (Unit 2) B,C,E (Unit 2) time delay of 1.0 delay of 1.0 0.1 0.1 seconds seconds

Degraded Voltage

3. 4160 V Emergency 2 B,C,E 3885.4 V with a 3873 V with a time Bus Bus Separation time delay of 90 delay of 90 5.0 5.0 seconds seconds

4. 480 V Emergency Bus 2 B,C,E 448.3 V with a 446.9 V with a time Bus Separation time delay of 90 delay of 90 5.0 5.0 seconds seconds

Beaver Valley Units 1 and 2 3.3.5 - 3 Amendments 317 / 208 LOP DG Start and Bus Separation Instrumentation After Degraded Voltage Relay Reduced Time Delay Modifications 3.3.5

Table 3.3.5-1 (page 1 of 1)

Loss of Power Diesel Generator Start and Bus Separation Instrumentation

REQUIRED UNIT 1 UNIT 2 CHANNELS ALLOWABLE ALLOWABLE FUNCTION PER BUS CONDITIONS VALUE VALUE

Loss of Voltage

1. 4160 V Emergency 1 D, E 3224 V with a 3328 V with a time Bus DG start time delay of delay of 0.33 0.03

< 0.9 seconds seconds

2. 4160 V Emergency 1 (Unit 1) D,E (Unit 1) 3224 V with a 3328 V with a time Bus Bus Separation 2 (Unit 2) B,C,E (Unit 2) time delay of 1.0 delay of 1.0 0.1 0.1 seconds seconds

Degraded Voltage (without safety injection signal)

3. 4160 V Emergency 2 B,C,E 3885.4 V with a 3873 V with a time Bus Bus Separation time delay of 90 delay of 90 5.0 5.0 seconds seconds

4. 480 V Emergency Bus 2 B,C,E 448.3 V with a 446.9 V with a time Bus Separation time delay of 90 delay of 90 5.0 5.0 seconds seconds

Degraded Voltage (with safety injection signal)

5. 4160 V Emergency 2 B,C,E 3885.4 V with a 3873 V with a time Bus Bus Separation time delay of 4.00 delay of 4.00 0.18 0.18 seconds seconds

6. 480 V Emergency Bus 2 B,C,E 448.3 V with a 446.9 V with a time Bus Separation time delay of 4.00 delay of 4.00 0.18 0.18 seconds seconds

Beaver Valley Units 1 and 2 3.3.5 - 3a Amendments 317 / 208 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION

RELATED TO AMENDMENT NOS. 317 AND 208 TO RENEWED

FACILITY OPERATING LICENS ES NOS. DPR-66 AND NPF-73

ENERGY HARBOR NUCLEAR CORP.

ENERGY HARBOR NUCLEAR GENERATION LLC

BEAVER VALLEY POWER STATION, UNITS 1 AND 2

DOCKET NOS. 50-334 AND 50-412

1.0 INTRODUCTION

1.1 Background

By application dated August 29, 2021 (Agencywide Documents Acce ss and Management System (ADAMS) Accession No. ML21242A125), as supplemented by letters dated April 4, 2022, and August 2, 2022 (ML22094A115 and ML22214B739, respecti vely), Energy Harbor Nuclear Corp. (the licensee), requested changes to the technica l specifications (TSs) for Beaver Valley Power Station (Beaver Valley), Units 1 and 2.

The proposed changes would revise TS 3.3.5, Loss of Power (LOP ) Diesel Generator (DG)

Start and Bus Separation Instrumentation. Specifically, the proposed changes would add notes to Required Actions C.1 and D.1 to facilitate temporary bypassing of the loss of voltage functions while starting a reactor coolant pump. Additionally, in Table 3.3.5-1, Loss of Power Diesel Generator Start and Bus Separation Instrumentation, vol tage allowable values would be increased for relays that provide signals for emergency diesel generators to start and 4160-volt (V) emergency buses to separate from the non-safety buses under loss of voltage conditions.

New voltage and time delay allowable values would be added for new relays that have a reduced time delay and would be installed to provide signals for 4160-volt and 480-volt emergency buses to separate from the non-safety buses under deg raded voltage conditions when a safety injection signal is present. The existing voltage and time delay allowable values under degraded voltage conditions will be used when a safety in jection signal is not present.

The U.S. Nuclear Regulatory Commission (NRC) staff audited various licensee documents to support the licensing review. The NRC staff issued its audit pl an on December 15, 2021 (ML21347A883), and conducted the audit using an internet-based portal provided by the licensee. The staff issued its audit summary report on May 2,2 022 (ML22108A292). The NRC requested additional information from the licensee on March 9, 2022 (ML22068A182). The licensee responded to the NRCs request by letter dated April 4,2022.

Enclosure 3

The supplemental letters dated April 4, 2022, and August 2, 202 2, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staffs original proposed n o significant hazards consideration determination as published in the Federal Register on January 25, 2022 (87 FR 3847).

1.2 System Description - LOP DG Start and Bus Separation Instru mentation

In the license amendment request (LAR), the licensee provided t he following description:

As shown in the BVPS-1 [Beaver Valley Power Station, Unit 1] Up dated Final Safety Analysis Report (UFSAR) Figure 8.1-1, Sheet 1 of 2, Electrical One Line Diagram, and BVPS-2 [Beaver Valley Power Station, Unit 2] UFSAR Figure 8.3-1, Sheet 1 of 2, Main One Line Diagram, at each BVPS [Beaver Valley Power Station] u nit, two independent Class 1E emergency 4160 V buses (1AE and 1DF at BVPS-1, and 2AE and 2DF at BVPS-2) and switchgear are provided. Each emergency bus is supp lied from a normal 4160 V station service switchgear bus (1A, 1D, 2A, and 2D, resp ectively) which, in turn, is supplied from a selected preferred source unit station servi ce transformer (main generator source) or system station service transformer (offsite source) with provisions for automatic transfer from the selected source to the remainin g source should the selected source fail.

The normal 4160 V buses 1A, 1D, 2A, and 2D each supply power to the corresponding emergency bus through two series connected air circuit breakers (ACBs). Each series connected ACB receives a trip signal under loss of voltage or d egraded voltage conditions, thus separating the respective emergency bus, which can then be energized from its DG.

The DGs provide a source of emergency power when offsite power is either unavailable or is insufficiently stable to allow safe unit operation. Loss of power instrumentation ensures a reliable source of emergency power by providing the f ollowing functions: 1) An automatic DG start on emergency bus undervoltage, and 2) Separation of the emergency buses on undervoltage or degraded voltage conditions.

BVPS-1 Loss of Voltage Protection

BVPS-1 loss of voltage protection consists of two LVRs [Loss of Voltage Relays] for each 4160 V emergency bus. One LVR actuates to open the normal supply breakers for the associated emergency bus (bus separation). The other LVR pr ovides a start signal for the DG associated with the bus. Both LVRs have the same NTS [Nominal Trip Setpoint] and allowable value (with different time delays).

BVPS-2 Loss of Voltage Protection

BVPS-2 loss of voltage protection consists of three LVRs for each 4160 V emergency bus. Two relays on each bus actuate to open the normal supply b reakers for the associated emergency bus (with a two-out-of-two logic per bus) to provide the bus separation function. The other LVR provides a start signal for the associated DG. All three LVRs have the same NTS and allowable value (with different time delays).

Degraded Voltage Protection

Degraded voltage protection for BVPS-1 and BVPS-2 is provided by two DVRs

[Degraded Voltage Relays] (in a two-out-of-two logic per bus) on each 4160 V and associated 480 V emergency bus. The DVRs on either the 4160 V o r 480 V bus initiate a common time delay relay that actuates if the degraded voltage c ondition persists for the entire delay period. The supply breakers for the affected 4160 V emergency bus open and separate the bus from the degraded voltage supply if the ti me delay is exceeded.

The two-out-of-two logic defends against a spurious DVR actuati on causing bus separation.

Allowable Values

Allowable Values are specified for each function in TS Table 3. 3.5-1. Nominal trip setpoints are specified in the BVPS-1 and BVPS-2 Licensing Requ irements Manuals.

The nominal trip setpoints are selected to ensure the setpoints measured by the surveillance procedures are not less than the minimum allowable values if the relays are performing as required.

1.3 Proposed Change

1.3.1 Current Technical Specification Requirements

As stated in the LAR, TS 3.3.5 is provided to ensure Beaver Val ley, Units 1 and 2, DG start and bus separation instrumentation specified in TS Table 3.3.5-1 is operable.

Beaver Valley, Units 1 and 2, TS Table 3.3.5-1, Loss of Power Diesel Generator Start and Bus Separation Instrumentation, currently contains two loss of vol tage protections and two degraded voltage protections, as described above in section 1.2.

Loss of Voltage (LOV) Protections:

Function 1, 4160 V Emergency Bus DG start, LVRs provide a start signal for the DG associated with the bus.

Function 2, 4160 V Emergency Bus Bus Separation, LVRs actuate to open the normal supply breakers for the associated emergency bus (bus separatio n).

Degraded Voltage (DV) Protections:

Function 3, 4160 V Emergency Bus Bus Separation, and Function 4, 480 V Emergency Bus Bus Separation, specify allowable voltages and a time delay after which DVRs provide signals to open the normal supply breaker for the affected emergency bus to separate the bus from the degraded voltage sup ply.

1.3.2 Reason for Proposed Change

The licensee proposed to increase the NTSs of LVRs Functions 1 and 2 to ensure that running safety-related motors do not stall and trip on overcurrent during a sustained DV condition. The allowable value (AV) revision for Functions 1 and 2 is based on updating operability criteria for the LVRs to support the NTS changes.

An issue was identified in an NRC unresolved item (2011 Compone nt Design Basis Inspection, ML112130443), that observed the existing DVR time delay of 90+/-5 seconds (secs) did not appear to be consistent with the assumption in the UFSAR accident analysis for safety injection flow.

Beaver Valley, Unit 1 UFSAR shows a time delay of less than or equal () to 17 secs for injection flow with offsite power, and to 27 secs with a loss -of-coolant accident coincident with a loss-of-offsite power (LOOP). Beaver Valley, Unit 2 design and accident analysis assumptions are similar to Unit 1.

To resolve this concern, an additional DV timing relay will be installed for each 4160 V emergency bus at each unit. The new relays will be installed in parallel with the existing DV time-delay relays but will have a reduced time delay setting that complies with the existing inputs to accident analyses. As with the existing relays, actuation of the new relays causes the associated emergency bus to separate from the non-Class 1E powe r source so that the DGs can assume the load, except that the new relay output will be i nhibited unless a safety injection signal exists.

New degraded voltage Function 5, 4160 V Emergency Bus Bus Sepa ration, and Function 6, 480 V Emergency Bus Bus Separation, would be added to Table 3.3.5-1. The new functions would be the same as existing Functions 3 and 4 but would apply when a safety injection signal is present and would have a reduced time delay. The existing Fu nctions 3 and 4 would apply when a safety injection signal is not present.

1.3.3 Description of Proposed Changes

In the LAR, the licensee proposed the following changes:

1. Revise AVs of LOV Functions 1 and 2 in TS Table 3.3.5-1, Loss of Power Diesel Generator Start and Bus Separation Instrumentation. There is no change to the associated time delays.

Loss of Voltage Unit 1 Unit 2 Function Existing AV Proposed AV Existing AV Proposed AV

1. 4160 V 2962 V 3224 V 2962 V 3328 V with a Emergency with a time with a time with a time time delay of 0.33 Bus DG start delay of delay of delay of +/- 0.03 seconds

< 0.9 < 0.9 0.33 +/- 0.03 seconds seconds seconds

2. 4160 V 2962 V 3224 V 2962 V 3328 V with a Emergency with a time with a time with a time time delay of 1.0 Bus Bus delay of 1.0 delay of 1.0 delay of 1.0 +/- 0.1 seconds Separation +/- 0.1 +/- 0.1 +/- 0.1 seconds seconds seconds

2. In the LAR, the licensee stated that the increased allowable voltage for Functions 1 and 2 could increase the possibility that the voltage dip caused by starting a reactor coolant pump (RCP) [6000 horsepower] would cause an LVR actuation. Ther efore, as a

precaution to prevent spurious actuation, Functions 1 and 2 sho uld be temporarily bypassed. The licensee proposed the following NOTE to be inserted in TS 3.3.5 above Required Action C.1 for Condition C (One or more Functions with two channels per bus inoperable) and Required Action D.1 for Condition D (One or mor e Functions with one channel per bus inoperable) to facilitate temporary bypassing o f loss of voltage functions 1 and 2 while starting a reactor coolant pump.

NOTE: Functions 1 and 2 may be bypassed for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> while starting the "A" reactor coolant pump provided that the corresponding instrument channels, electrical bus, and DG in the other train are OPERABLE.

In the LAR, the licensee stated that intentional entry into Condition C or Condition D is already permissible within the duration of the existing 1-hour completion times stated for these required actions. Only the "A" reactor coolant pumps at B eaver Valley, Units 1 and 2, are powered from a non-Class 1E 4160 V bus (Bus 1A at Unit 1, and Bus 2A at Unit

2) that also provides the normal power to the downstream Class 1E [emergency] 4160 V bus (1AE at Unit 1 and Bus 2AE at Unit 2].

3. TS Table 3.3.5-1 currently contains two degraded voltage functions. Function 3 (4160 V Emergency Bus, Bus Separation) and Function 4 (480 V Emergency Bus, Bus Separation). These functions specify allowable voltages and a t ime delay after which the 4160 V emergency bus separates from the normal supply bus. The licensee proposed to modify these functions such that exiting Functions 3 and 4 appl y when no safety injection signal is present. Functions 3 and 4 are annotated to indicate that they apply when no safety injection signal is present. The section title i s revised to Degraded Voltage (without safety injection signal).

4. Add section Degraded Voltage (with safety injection signal) with Functions 5 and 6, as shown below:

Degraded Voltage (with safety injection signal)

Required Unit 1 Unit 2 Function Channels Per Conditions Allowable Allowable Bus Value Value

5. 4160 V 2 B,C,E 3885.4 V 3873 V Emergency with a time with a time Bus Bus delay of 4.0 +/- delay of 4.0 Separation 0.18 seconds +/- 0.18 seconds

6. 480 V 2 B,C,E 448.3 V with 446.9 V Emergency a time delay with a time Bus Bus of 4.0 +/- 0.18 delay of 4.0 Separation seconds +/- 0.18 seconds

The proposed Functions 5 and 6 apply when a safety injection signal is present.

Functions 5 and 6 have a shorter time delay to support safety injection timing assumptions in the accident analyses. The functions require plant modifications at each unit to install an additional degraded voltage time delay relay in parallel with each existing 90-second nominal time delay relay. The new time delay relay will start timing

and execute the same output function as the existing 90-second timer but has a reduced nominal time delay of 4 seconds. The output of the new relay is enabled only concurrently with a safety injection signal. The reduced time d elay achieves consistency between the TS and the time delays assumed in accident analyses.

5. By letter dated August 2, 2022, the licensee addressed a pot ential configuration control issue during the implementation period for the TS pages, which will be effective on the license amendment issuance date. The current TS Table 3.3.5-1 o n TS page 3.3.5-3 is retained with a proposed note added to the page header to indicate that it is applicable Before Degraded Voltage Relay Reduced Time Delay Modifications. Similarly, proposed new TS Table 3.3.5-1 on TS page 3.3.5-3a has a header note to indicate it is applicable After Degraded Voltage Relay Reduced Time Delay Mod ifications. Since the staggered plant modifications are anticipated to be completed in 2024 for Unit 2 and 2027 for Unit 1, the TS pages will be effective as appropriate to each units modification status.

2.0 REGULATORY EVALUATION

2.1 Regulatory Requirements

Title 10 of the Code of Federal Regulations (10 CFR) Part 50.36, Technical Specifications, established its regulatory 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 co nditions for operations (LCOs); (3) surveillance requirements (SRs); (4) design features; and (5) a dministrative controls. The proposed changes fall in the LCOs category.

The regulations in 10 CFR 50.36(c)(1)(ii)(A) require, in part, Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded. If, during operation, it is determined that the autom atic safety system does not function as required, the licensee shall take appropriate action, which may include shutting down the reactor.

The regulations in 10 CFR 50.36(c)(2)(i) require, in part, that [w]hen a limiting condition for operation of a nuclear reactor is not met, the licensee shall s hut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.

The regulations in 10 CFR Part 50, Domestic Licensing of Produ ction and Utilization Facilities, specifically, Appendix A, General Design Criteria (GDC) for Nuclear Power Plants, to 10 CFR Part 50, provides the minimum necessary design, fabrication, construction, testing, and performance requirements for structures, systems, and component s important to safety.

The regulations in 10 CFR 50 Appendix A, GDC 13, Instrumentati on and Control, state, in part, Instrumentation shall be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurr ences, and for accident conditions as appropriate to assure adequate safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems. Appropriate control s shall be provided to maintain these variables and systems within prescribed operating ranges. "

The regulations in 10 CFR 50, Appendix A, GDC 17, Electric powe r systems, states in part, that nuclear power plants have onsite and offsite electric power sys tems, to permit the functioning of structures, systems, and components that are important to sa fety. The safety function for each system (assuming the other system is not functioning) shal l 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 NRC staff notes that the construction permit (CP) of Beaver Valley, Unit 1, was issued in June 1970 and the CP of Beaver Valley, Unit 2, was issued in Ma y 1974. Therefore, Unit 1 has been designed and constructed to comply with the "General Desig n Criteria for Nuclear Power Plant Construction" published in July 1967 by the Atomic Energy Commission (AEC). Appendix 1A, 1971 AEC General Design Criteria Conformance, of the Beav er Valley, Unit 1, Final Safety Analysis Report (FSAR) provides a discussion of the degree of c onformance to the AEC GDC published as Appendix A to 10 CFR 50 in 1971. In the FSAR, Appendix 1A the Criterion 1A.13 and Criterion 1A.17 are equivalent to Criterion 13 and Criterion 17 of the 10 CFR 50 Appendix A. The NRC staff applied the Criterion 13 and Criterion 17, as shown above, to evaluate this LAR for both Units 1 and 2.

2.2 Regulatory Guidance

Regulatory Guide (RG) 1.105, Revision 4, Setpoints for Safety-Related Instrumentation, dated February 2021 (ML20330A329), describes a method acceptable to t he NRC staff for complying with the NRCs regulations for ensuring that setpoints for safe ty-related instrumentation are initially within and remain within the TS limits. RG 1.105 Revi sion 4 endorses American National Standards Institute International Society of Automation (ANSI/I SA) Standard 67.04.01-2018, Setpoints for Nuclear Safety-Related Instrumentation. The NRC staff used this guide to establish the adequacy of the licensees setpoint calculation methodologies and the related plant surveillance procedures.

Regulatory Issue Summary (RIS) 2011-12, Revision 1, Adequacy of Station Electric Distribution System Voltages," Revision 1, dated December 29, 2011 ( ML11305 0583) clarifies voltage studies necessary for DVR (second level undervoltage protection ) setting bases and transmission network/offsite/station electric power system desi gn bases for meeting the regulatory requirements specified in GDC 17, Electric Power Systems, of Appendix A to 10 CFR Part 50. The RIS states, in part, Licensee voltage calc ulations should provide the basis for their DVR settings, ensuring safety-related equipment is su pplied with adequate voltage (dependent on equipment manufacturers design requirements), based on bounding conditions for the most limiting safety-related load (in terms of voltage) in the plant. Regarding the time delay setting of DVRs, the RIS states:

(1) The allowable time delay, including margin, shall not excee d the maximum time delay that is assumed in the FSAR accident analyses.

Note: Time delay condition (1) indicates that the DVR circuits should be designed assuming coincident sustained degraded grid voltage and acciden t events. Upon the onset of the coincident accident and degraded grid event, the t ime delay for the DVR circuit should allow for separation of the 1E buses from the of fsite circuit(s) and connection to the 1E onsite supplies in time to support safety system functions to mitigate the accident in accordance with the FSAR accident anal yses.

(2) The time delay shall override the effect of expected short duration grid disturbances, preserving availability of the offsite power source(s); and (3) The allowable time duration of a degraded voltage condition at all distribution system levels shall not result in failure of safety-related systems or components.

Guidance in RIS 2006-17, NRC Staff Position on the Requirements of 10 CFR 50.36, Technical Specifications, Regarding Limiting Safety System Se ttings During Periodic Testing and Calibration of Instrument Channels, dated August 24, 2006 (ML051810077), discusses issues that could occur during testing of limiting safety system settings and therefore may have an adverse effect on equipment operability. The RIS also repres ents an approach that is acceptable to the NRC staff for addressing these issues for use in licensing actions.

The NRC staffs review guidance contained in the Standard Revie w Plan for the Review of Safety Analysis Reports for Nuclear Power Plants (NUREG-0800) B ranch Technical Position (BTP) 8-6, March 2007 (like the previous BTP PSB-1, July 1981) Adequacy of Station Electric Distribution System Voltages states that the TS should include limiting conditions for operations, surveillance requirements, trip setpoints, and maxi mum and minimum allowable values for the first level of undervoltage protection (loss of offsite power) relays and the second level (degraded voltage) protection sensors and associated time delay devices.

Institute of Electrical and Electronics Engineers Standard (IEE E) Std. 741-2017, IEEE Standard for Criteria for the Protection of Class 1E Power Systems and Equipment in Nuclear Power Generating Stations, Annex A, provides guidance for the following: (1) Protection of Class 1E equipment for loss of voltage or degraded voltage conditions; a nd (2) One method for the determination of the proper settings for loss of voltage and degraded voltage protection systems

[relays] and their associated time delays.

3.0 TECHNICAL EVALUATION

In determining whether an amendment to a license will be issued, the NRC is guided by the considerations that govern the issuance of initial licenses to the extent applicable and appropriate. The NRC staff evaluated the licensees LAR to determine whether the proposed change is consistent with the regulations and licensing basis discussed in Section2.0 of this safety evaluation (SE). The NRC staff reviewed the proposed TS changes to determine whether they meet the requirements of 10CFR50.36 and provide reasonab le assurance of health and safety of the public.

To support TS 3.3.5 changes, the licensee performed various ele ctrical power system calculations. During the months of January and February 2022, the NRC staff conducted a virtual regulatory audit with regards to the proposed revision to TS 3.3.5 of Beaver Valley, Units 1 and 2, based on an audit plan issued on December 15, 2021. Following the audit, the NRC staff issued requests for additional information (RAIs) on March 9, 2022. The licensee responded to the RAI in its supplemental letter dated April 4, 2022.

For this SE, the following terms are used:

Analytical Limit (AL) - Limit of a measure or calculated varia ble established by the safety analysis to ensure that a safety limit is not exceeded.

Allowable Value (AV) - A limiting value that the trip setpoint may have when tested periodically, beyond which appropriate action shall be taken.

Nominal Trip Setpoint (NTS) - A predetermined value for actuat ion of the final setpoint

device to initiate a protective action.

Trip Margin - an allowance provided between the trip setpoint and the analytical limit to ensure a trip before the analytical limit is reached.

NTS Margin (MarginNTS) - An allowance provided between the NTS and the AL (Region (A + B) in Figure 1 of ANSI/ISA) Standard 67.04.01-2018).

AV Margin (MarginAV) - The margin between the AV and the AL that is observable dur ing TS surveillances where the channel may be determined inoperable (Region C in Figure1 of ANSI/ISA) Standard 67.04.01-2018).

The NRC staff performed an independent confirmatory evaluation to verify that the licensees setpoint calculation values and methodologies are adequate to a ssure, with a high confidence level, that required protective actions are initiated before th e associated plant process parameters exceed their analytical limits. The staff evaluated the proposed amendment by using guidance of RG 1.105, Revision 4, and ANSI/ISA 67.04.01-2018. I n addition, the NRC staff evaluated the proposed changes in conformance with RIS 2011-12 and RIS 2006-17 regarding whether the licensee properly used the NRC guidance in establishing AVs to be applied to the LOV Functions 1 and 2 and proposed new DV Functions 5 and 6 in TS Table 3.3.5-1.

3.1 Summary of Licensee Methodology for Proposed Settings to be Applied to the LOV Functions 1 and 2 and Proposed New DV Functions 5 and 6

In the LAR, the licensee stated that setpoint uncertainty or ch annel statistical allowance (CSA) is calculated by a square root of the sum of the squares (SRSS) of relevant uncertainty terms in accordance with the setpoint methodology defined in the Westinghouse Topical Reports WCAP-11419, Revision 6 and WCAP-11366, Revision 7.

The NRC staff reviewed these Westinghouse Topical Reports and t he calculations in the Supplement, as listed above, to verify that:

Equations used in the Westinghouse Topical Reports and the calculations to calculate the total allowances (TAs), Margins, CSA, and AVs are consistent with the guidance in RG 1.105.

CSA and CSA time-delay (CSATD) uncertainties were calculated using the SRSS plus algebraic approaches.

The NRC staff determined that the methodology used to determine instrument uncertainties was the SRSS, as the means of combining normally distributed and independent uncertainty terms and algebraic summation as the means of combining uncertainty t erms that are not random, not normally distributed, or are dependent, to assure that control and monitoring setpoints are established and maintained in a manner consistent with plant safety function requirements.

3.2 Evaluation of Proposed Changes

3.2.1 LVR Settings (TS Table 3.3.5, Functions 1 and 2)

The licensee has proposed to increase the allowable voltage values specified in TS Table 3.3.5-1 for the loss of voltage Function 1 (at which the DGs start) and Function 2 (at which a 4160 V emergency bus separates from offsite power source and is then powered from DG) from 2962 V to 3224 V at BVPS-1, and from 2962 V to 3328 V a t BVPS-2.

3.2.1.1 LVR Minimum Analytical Voltage Limits

In the LAR, Section 3.1, the licensee provided the minimum volt age analytical limit for 4160 V emergency buses for Beaver Valley, Unit 1as 3141 V, and for Beaver Valley, Unit 2 as 3253 V.

In the LAR, Section 3.1.1, the licensee stated that these minimum analytical voltage limits were derived from the load flow studies/calculations corresponding t o steady-state, maximum load conditions during normal operation. The load flow studies were used to determine the voltages at motors and motor control centers (MCCs). These voltages were then compared to the motor stall voltages and minimum allowable MCC voltages. The minimum acceptable voltage for each MCC ensures adequate voltage at the limiting motor. The analytical limits for LVR voltage prevent normally running safety-related motors from stalling du ring severely degraded voltage conditions. In supplement dated April 4, 2022, the licensee provided summaries of the following calculations which included the determination of the LVR Minimu m Analytical Limits:

Calculation No. 8700-E-345, Rev. 1 for BVPS-1, Voltage and Time Delays Analysis for Unit 1 Undervoltage Protection Scheme (Enclosure A in the supp lement).

Calculation No. 10080-E-346, Rev. 1 for BVPS-2, Voltage and Time Delays Analysis for Unit 2 Undervoltage Protection Scheme (Enclosure C in the supp lement).

In the summaries of the above calculations (under heading Mini mum Voltage Limit for LVRs),

the following is stated: The minimum voltage limit for the loss of voltage relays should be high enough to preclude normally-running safety-related motors from stalling. Based on the conclusions section of the above calculations, the analytical m inimum voltage limit of LVRs for the safety-related Beaver Valley, Unit 1 4160 V buses is 3141 V (75.5 percent ), and for Beaver Valley, Unit 2 4160 V buses is 3230 V (77.65 percent).

The staff performed an audit on the above calculations, as mentioned in the audit report summary dated May 2, 2022. The staff finds the methodology of c alculations performed by the licensee is consistent with the IEEE Std 741-2017, Annex A, Sec tion A.4.5, Confirmation LVR prevents motor stalling. Therefore, the staff finds that the m inimum voltage analytical limits for 4160 V emergency buses for Beaver Valley, Unit 1 as 3141 V, and for Beaver Valley, Unit 2 as 3253 V, are reasonable and acceptable.

3.2.1.2 Proposed LOV AVMin of Functions 1 and 2

In the LAR, the licensee stated that operability criteria for t he loss of voltage relays (LVRs) was updated to support the NTS change.

In the supplement dated April 4, 2022, the licensee provided su mmaries of the following calculations which included the determination of the LOV Minimu m AV:

Calculation No. 8700-DEC-0212, Revision 2, "Beaver Valley Unit 1, 4.1 kV Emergency Bus Undervoltage: Trip Feed and Start Diesel Uncertainty Calculations" (Enclosure H of the Supplement).

Calculation No. 10080-DEC-0215, Revision 2, "Beaver Valley Unit 2, 4.1 kV Emergency Bus Undervoltage: Trip Feed and Start Diesel Uncertainty Calculations" (Enclosure I of the Supplement).

In the Calculation Nos. 8700-DEC-0212 and 10080-DEC-0215, the l icensee calculated the proposed setpoints for the Functions 1 and 2. The NRC staff sum marized the results of these calculations in Table 1.

Table 1: Summary of the Calculations Results Items / Terms and Equations Unit 1 Unit 2 PT Turns Potential transformer (PT) turns: 4200/120 = 35 35 35 Nominal At primary side (Vac Bus) 4160 Vac Bus 4160 Vac Bus Voltage of At secondary side (sec-side) 4200V = Nominal voltage at primary 119 volts 119 volts side (Vac Bus) / 35 Nominal Trip Setpoint (NTS) 78.5% (Unit 1) and 81% (Unit 3266 Vac Bus 3370 NTS 2) of nominal voltage of 4160 Vac Bus volts NTS at sec-side voltage: NTS Vac Bus / 35 93.3 volts 96.3 volts As-Found Tolerance (AFT) at AFT* primary side: AFT at sec-side +/- 17.5 V +/- 17.5 V x 35 AFT at sec-side in Table 3.1.2-1 of LAR +/- 0.5 volts +/- 0.5 volts Minimum analytical limit (ALMin) at primary side: 75.5% 3141 Vac Bus 3253 Vac Bus ALMin (Unit 1) & 78.2% (Unit 2) of nominal 4160 volts ALMin sec-side = (ALMin at primary side, Vac Bus) / 35 89.74 volts 92.94 volts CSA** CSA of 4160 Vac Bus = CSA 105 105 sec-side x 35 Vac Bus Vac Bus CSA of sec-side 3 volts 3 volts Total Allowance (TA) of 124.8 Vac 116.5 Vac TA nominal 4160 volts: TA = Bus Bus lALMin - NTSl TA sec-side = TA at Vac Bus

/ 35 3.57 volts 3.33 volts Margin of 4160 Vac Bus = 19.8 11.5 Margin TA-CSA Vac Bus Vac Bus Margin sec-side = Margin of 4160 Vac Bus / 35 0.57 volts 0.33 volts Minimum AV at 4160 Vac 3328 Bus = NTS - RD (RD: 1% of 3224 Vac Bus Vac Bus AVMin () nominal 4160 volts)

AV at sec-side = AV at 4160 Vac Bus / 35 92.1 volts 95.1 volts

• As-Found Tolerance (AFT) and As-Left Tolerance (ALT):

In the LAR, the licensee provided Table 3.1.2-1, Loss of Voltag e Relay Calibration Tolerances of functions (1) 4160 V Emergency Bus, Bus Separation Relays and (2)

4160 V Emergency Bus, DG Start Relays. In addition, the licen see noted that in both Beaver Valley units, (1) the AFT and ALT are identical, (2) The pickup tolerances are based on the assumption that the pickup tolerances are +/- 2 perc ent of the pickup voltage setting, and (3) the dropout tolerances are to be maintained at +/- 0.5 V that are consistent with the supporting uncertainty calculations.

• • CSA was calculated by the following equations:

CSA = [PEA12 + PEA22 + RRA2 + (RMTE + RCA)2 + (RMTE + RD)2 + RTE2]1/2

Where the instrument uncertainties:

PEA1: Primary Element Accuracy (potential transformer accuracy)

PEA2: Primary Element Accuracy (variation in dropout voltage vs. DC control)

RRA: Relay Repeatability (sec-side)

RCA: Relay calibration Accuracy (sec-side)

RMTE: Relay Temperature Effect (over -20 to +55ºC)

RD: Relay Drift

In the LAR, the licensee stated that the relay drift was also proposed to be revised from 3.79%

to 1% at both Beaver Valley units. The licensee stated: The 1% drift value reflects the upper bound of a 95 percent confidence interval based on site-specific performance history gathered from calibrations and surveillances.

The NRC staff compared the margins between the existing NTS and AV Min to the margins between the proposed NTS and AV Min. The results in Table 2 of this SE, as shown below, showed that the margin between NTS and AV (Margin NTS-AV) of the proposed settings will be less than the existing settings. These results reflected that the proposed settings would have stricter criteria for the operation.

Table 2: Margin between NTS and AV comparison Primary side Unit 1 Unit 2 (Vac Bus) Existing Proposed Existing Proposed NTS 3120 3266 3120 3370 AVMin 2962 3224 2962 3328 MarginNTS-AV 158 42 158 42

The NRC staff calculated the existing 3.79 percent drift at 100 percent of span ((3.79 percent*100) / 75 = 5.03 percent) and the proposed 1 percent drift at 100 percent of span (1 percent *100/75 = 1.33 percent) to verify that the existing drift was extrapolated from 5 percent at full span.

The NRC staff used the information in the LAR and results of th e calculations in the supplement (reflected in Table 1 of this SE) to establish the relationship s between the LOV ALMin, NTS and associated AVMin of Functions 1 and 2 in Figure 1.

Figure 1: ALMin, NTS with associated AV Min relationships

Based on the review that was summarized in Table 1 and Figure 1 above, with respect to the proposed AVMin for the LOV in TS Table 3.3.5-1 of Beaver Valley, Units 1 and 2, the NRC staff has determined the following:

The NTSs of LOV inclusive of their (-) AFTs (Row 1) are greater than their minimum AVs, and therefore, would assure that the trip signals from the LOV circuit will be initiated prior to exceeding their AV values. The proposed AFT values associated with the setpoint changes were determined in a manner consistent wit h RIS 2006-17 in establishing the As-Left and As-Found tolerances.

The Margin NTS (TAMin)(Row 3) are greater than CSA. This indicates that there is res erve margin beyond the CSA. The Margin values are illustrated in Tab le 1 of this SE. In addition, the AV Min values are greater than (NTS - CSA) (Row 2). This indicates th at maintaining the actuation setpoint above the AV will ensure tha t the AL will not be exceeded. Therefore, the minimum relay setting ensures that run ning safety-related motors do not stall and trip on overcurrent during sustained degraded voltage conditions.

The ratios between the NTS and AV margins (Row 5) are adequate. These margins ensure that the trip setpoints have been chosen to assure that a trip or safety actuation will occur well before the measured process reaches the Lower A Ls (Minimum Equipment Acceptable Voltage). Therefore, the proposed AV settings support an automatic protective action before a safety limit is exceeded.

In the LAR, the licensee stated that the proposed 1 percent drift value reflects the upper bound of a 95 percent confidence interval based on site-specific performance history gathered from calibrations and surveillances. The licensee claims this proposed drift will correct the existing non-conservative issue (drift 3.79 percent at 75 percent of span that was extrapolated from 5 percent at full span to the NTS).

The NRC staff finds that the proposed LVR AVs for LOV Functions 1 and 2 in TS Table 3.3.5-1 provide sufficient margins to continue to satisfy the requireme nts of 10 CFR 50.36(c)(1)(ii)(A)

and 10 CFR 50, Appendix A, GDC 13 and were established in confo rmance with RIS 2011-12 and RIS 2006-17. Therefore, the staff finds that these proposed AVs are acceptable.

3.2.2 Proposed Note for TS 3.3.5 Required Actions C.1 and D.1

In the LAR, the licensee has proposed to insert a Note in TS 3.3.5 required actions C.1 and D.1 associated with Condition C, One or more Functions with two channels per bus inoperable, and Condition D, One or more Functions with one c hannel per bus inoperable, respectively.

The Note would state, Functions 1 and 2 may be bypassed for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> while starting the "A" RCP provided the corresponding instrument channels, electrical bus, and DG in the other train are OPERABLE.

The licensee stated that starting the A reactor coolant pump at Beaver Valley, Units 1 or 2, can cause voltage dips at the 1AE or 2AE emergency 4160 V buses, re spectively. Starting the B or C reactor coolant pump at either unit does not significantly affect the voltages at the emergency 4160 V buses.

In the supplement dated April 4, 2022, the licensee provided su mmaries of the following calculations:

Calculation No. 8700-E-271, Rev. 3, Addendum 4 for BVPS-1, Sta tion Service System Dynamic Stability Study (Enclosure E in the supplement).

Calculation No. 10080-E-271, Rev. 1, Addendum 6, and Addendum 7 for BVPS-2, Transient Stability Analysis (Enclosures F and G in the suppl ement).

One of the study cases in each of above calculations evaluated the starting of A RCP with minimum 138 kV switchyard voltage when the 4160 V buses are fed from station service transformers, under normal non-accident loading conditions. The A RCP pump was selected because it is upstream of the safety-related bus. The other RCP s are connected upstream of non-safety-related buses. In this study, the licensee determined that it was necessary to manually change the upstream station service transformer (138 kV-4.36 kV-4.36 kV) taps before starting A RCP so that minimum voltage observed at the safety-related 4160 V buses during reactor coolant pump starts remains above the maximum al lowable dropout voltage for LVRs.

In the supplement dated April 4, 2022, the licensee confirmed t hat the proposed Note will help avoid manually adjusting the station service transformer (138 k V-4.36 kV-4.36 kV) taps before starting A RCP. The licensee also stated as follows:

The option to temporarily bypass the loss-of-voltage functions is a precaution to prevent unnecessarily exercising safety-related equipment. If voltages on the emergency 4160 volt buses drop too low while starting the "A" reactor coolant pump at both Unit Nos. 1 and 2, the loss-of-voltage relays drop out and safety-related equipment is separated from the preferred power source and transferred to the emergency diesel generator.

Provided certain conditions are met, the option to temporarily bypass the loss-of-voltage functions for up to one hour while starting these pumps is a de fense-in-depth measure.

Based on reactor operating practice, the starting of an RCP (a non-safety related load) is required only during the non-accident conditions. Based on discussion above, the staff finds the above proposed Note to be inserted in TS 3.3.5 Required Actions C.1 and D.1 reasonable and acceptable; and therefore, it continues to satisfy the requirem ents of 10 CFR 50.36(c)(2)(i).

3.2.3 DVR Time Delay Settings Without Safety Injection Signal (TS Table 3.3.5-1, Functions 3 and 4)

In the LAR, the licensee stated that the proposed amendment would divide existing Table 3.3.5-1 degraded voltage functions into two subsets: Those that apply when no safety injection signal is present, and those that apply when a safety injection signal is present. The existing Functions 3 and 4 having a 90-second time delay would be duplicated by new Functions 5 and 6, but with a reduced 4-second time delay applicable only with a concurrent safety injection signal. The existing Functions 3 and 4 would be unchanged, exce pt that they would be identified as applicable when no safety injection signal is present.

The staff finds that according to NUREG-0800, BTP 8-6, two time delays associated with DVRs are recommended - one time delay (shorter duration to allow motor-starting transients) for accident condition, and second time delay (longer duration) for non-accident conditions to prevent damage to the permanently connected Class 1E loads. The refore, the proposed division of existing Table 3.3.5-1 degraded voltage functions into two s ubsets: those that apply when no safety injection signal is present, and those that apply when a safety injection signal is present, is in accordance with BTP 8-6, and therefore acceptable.

In the supplement dated April 4, 2022, the licensee provided su mmaries of the following calculations which included the determination of the adequacy o f existing DVR time delay for non-accident conditions:

Calculation No. 8700-E-345, Rev. 1, and Addendum 1, for BVPS-1, Voltage and Time Delays Analysis for Unit 1 Undervoltage Protection Scheme (Enclosures A and B in the supplement).

Calculation No. 10080-E-346, Rev. 1, and Addendum 1, for BVPS-2, Voltage and Time Delays Analysis for Unit 2 Undervoltage Protection Scheme (Enc losures C and D in the supplement).

In the above calculations, under the Results heading, the lic ensee stated:

The degraded voltage relay time delay is 90 +/- 5.0 seconds for n on-accident conditions.

For steady-state, non-accident conditions, bus trip times are g reater than 95 seconds.

Most running, safety-related motors can ride-through a 95 secon d degraded voltage condition without tripping on overcurrent. Possible exceptions are 4160 volt motors for which overcurrent trip times are undefined.

Regulatory Issue Summary 2011-12 states that "the [DVR] time de lay chosen should be optimized to ensure that permanently connected Class 1E loads a re not damaged under sustained degraded voltage conditions (such as a sustained degraded voltage below the DVR voltage setting(s) for the duration of the time delay setti ng)." The degraded voltage relays time out before the motor thermal limits are challenged. For accident conditions, the reduced degraded voltage relay time delay ensures that equipment is available to perform its accident mitigation function in time to support the UFSAR accident analyses.

For non-accident conditions, the existing 90 +/- 5.0 seconds prev ents equipment damage due to prolonged operation at degraded voltages. The time delay is acceptable.

The possible exception mentioned above regarding some 4160 V mo tors is acceptable, because: (1) even if a motor is tripped in non-accident condition, it can be reset within a reasonable time without endangering the safety of plant, and (2 ) a motor voltage is likely to improve in approximately 90 seconds due to upstream voltage reg ulating devices (such as load taps on upstream transformers) which would save the motor from tripping on overcurrent. For non-accident conditions, the DVR time setting is not considered critical. No specific requirement of time delay of DVR is required as per NUREG-0800 BTP 8-6, and RIS 2011-12 for non-accident conditions. Therefore, for non-accident conditions, th e staff finds the existing 90 +/- 5.0 seconds time delay settings of DVRs as acceptable.

3.2.4 DVR Time Delay Settings with Safety Injection Signal (TS Table 3.3.5-1, Functions 5 and 6)

The licensee has proposed new Functions 5 and 6 which would be applicable when a degraded voltage condition is detected coincident with a safety injection signal. Functions 5 and 6 allowable voltages remain the same as functions 3 and 4. A plant modification would install an additional degraded voltage time delay relay in parallel with t he existing 90-second time delay relay. The new time delay relay for Function 5 and 6 would be initiated by the same DVR signal.

Only the time delay would differ.

3.2.4.1 DVR Analytical Maximum Time Delay with Safety Injection Signal

In the LAR, the licensee stated that the analytical maximum tim e delays during accident conditions were determined to be 4.4 seconds at Beaver Valley, Unit 1, and 4.7 seconds at Beaver Valley, Unit 2. The maximum time delays were selected to preclude overcurrent protective devices from tripping during degraded voltage conditions before the degraded voltage time delay is reached and to be within the 10-second assumption in accident analyses for the DGs to start and be capable of accepting loads following a safe ty injection signal.

In the LAR, the licensee stated:

Under degraded voltage conditions, the motors are not guarantee d to have adequate starting voltage and are therefore assumed to stall. A stalled motor draws significantly more current than a running motor, which results in stalled mot ors tripping more quickly than running motors. Stall currents were calculated for the relevant motors. For motors powered directly from 4160 V buses and 480 V unit substations, the minimum trip time at the stall current for each motor was determined using time-curr ent curves for the associated overcurrent protective devices. The minimum of all t he trip times (excluding non-safety-related equipment) was used to establish a maximum D VR time delay limit for accident conditions. The minimum trip time of 4160 V motors was determined to be more limiting than for 480 V motors.

For motors powered from 480 V MCCs, time-current curves for eac h breaker or overload heater were used to determine the minimum trip current that cor responds to six seconds.

Six seconds exceeds the minimum trip times of the motors powere d directly from the 4160 V buses and 480 V unit substations. For each motor, the tr ip current value that corresponds to a six-second trip time was then confirmed to be greater than the stall current for that motor. Therefore, the stall current is not gre at enough to result in a trip

time that is less than six seconds. Therefore, proposed maximum time delay analytical limits at both BVPS units are conservative.

In the supplement dated April 4, 2022, the licensee provided su mmaries of the following calculations which included the determination of the DVR Analyt ical Maximum Time Delay Limit:

Calculation No. 8700-E-345, Rev. 1, and Addendum 1, for BVPS-1, Voltage and Time Delays Analysis for Unit 1 Undervoltage Protection Scheme (Enclosures A and B in the supplement).

Calculation No. 10080-E-346, Rev. 1, and Addendum 1, for BVPS-2, Voltage and Time Delays Analysis for Unit 2 Undervoltage Protection Scheme (Enc losures C and D in the supplement).

Regarding the maximum time delay for DVRs, the above calculatio ns state, The maximum time delay limit is selected to prevent motors from tripping on overcurrent before the degraded voltage relays time-out. This ensures that the equipment requir ed to mitigate a design basis accident is available to be transferred to the emergency diesel generators.

In the above calculations, the licensee explained the methodolo gy adopted to determine the maximum time delay for DVRs under accident conditions so that safety-related motors do not trip under degraded voltage conditions during starting or runni ng conditions. The licensee determined the maximum analytic limit of time delay as 4.4 seconds at Beaver Valley, Unit 1, and 4.7 seconds at Beaver Valley, Unit 2, provided certain over current relay settings are revised as detailed in the recommendations section of above calculation s.

The NRC staff finds the methodology of calculations performed b y the licensee is consistent with the IEEE Std 741-2017, Annex A, Section A.4.3, Establishment of DVR first level time delay (with accident signal). Based on conclusions made in above calculations, analytical maximum time delays during accident conditions as 4.4 seconds at Beaver Valley, Unit 1, and 4.7 seconds at Beaver Valley, Unit 2 are acceptable provided ce rtain overcurrent relay replacements and settings changes are implemented. According to the supplement dated April 4, 2022 (response to RAI EEB-2), these changes will be implemen ted by timeline for Unit 2 refueling outage (fall of 2024), and Unit 1 refueling outage (spring of 2027).

Beaver Valley, Unit 1, UFSAR Table 14.3.2-8 shows a time delay of 17 seconds for safety injection flow (after the safety injection signal) with offsite power. Beaver Valley, Unit 2, UFSAR Table 15.6-8e also shows a time delay of 17 seconds for safety injection flow (after the safety injection signal) with offsite power. Therefore, the analytical maximum time delays during accident conditions determined to be 4.4 seconds at Beaver Vall ey, Unit 1, and 4.7 seconds at Beaver Valley, Unit 2, meet the requirement of timely safety in jection flow to support the UFSAR accident analyses and meet the intent of RIS 2011-12.

3.2.4.2 DVR Minimum Time Delay Analytical Limit with Safety Inj ection Signal

In the LAR, the licensee stated that the analytical minimum tim e delays during accident conditions were determined to be 2.5 seconds at Beaver Valley, Unit 1, and 2.2 seconds at Beaver Valley, Unit 2. The minimum time delays were selected to provide adequate time for bus voltages to recover and DVRs to reset following fast bus transf ers and are longer than the voltage transients associated with block starting safety-inject ion equipment.

According to the LAR, the licensee adopted the following method ology to establish that the analytical minimum time delays during accident conditions:

To establish the analytical minimum time delays during accident conditions, an analysis for each unit was performed using a model of the electrical dis tribution system. The model was used to simulate electrical transients caused by fast bus transfers and motor starts and to produce plots of voltage versus time for various study cases. The results of these simulations were reviewed to confirm that the minimum tim e delays would exceed the durations of voltage transients caused by block starting sa fety-injection equipment or by fast bus transfers, whichever is more limiting. Voltage tran sients associated with block-starting safety injection equipment subside within 2.5 se conds for BVPS-1 and 2.2 seconds for BVPS-2, thus defining the analytical minimum time d elays.

In the supplement dated April 4, 2022, the licensee provided su mmaries of the following calculations:

Calculation No. 8700-E-271, Rev. 3, Addendum 4 for BVPS-1, Sta tion Service System Dynamic Stability Study (Enclosure E in the supplement)

Calculation No. 10080-E-271, Rev. 1, Addendum 6, and Addendum 7 for BVPS-2, Transient Stability Analysis (Enclosures F and G in the suppl ement).

In the above calculations, under the Conclusions heading, the licensee stated:

For accident conditions, the degraded voltage relay time delay shall be greater than 2.5 [2.2] seconds [2.5 seconds for Beaver Valley, Unit 1 ( Enclosure E), and 2.2 seconds for Beaver Valley, Unit 2 (Enclosure F)]. This prov ides adequate time for bus voltages to recover following fast bus transfers and is longer than the voltage transients associated with block starting safety-inject ion equipment. To minimize the potential for inadvertent relay actuation and to preserve operating margin, the time delay should be as long as permissible.

Based on the excerpts of above analyses, the staff finds that a nalytical minimum time delays of DVRs during accident conditions as 2.5 seconds at Beaver Valley, Unit 1, and 2.2 seconds at Beaver Valley, Unit 2, are reasonable and meets the intent of RIS 2011-12.

3.2.4.3 Proposed AVs of DV Time-Delay (AV Max-TD and AVMin-TD) of Functions 5 and 6

In the LAR, the licensee stated, in part, that:

The new degraded voltage time delay relay is an ABB solid state timing relay, Type 62T with a range of 0.01 to 9.99 seconds. Since the time delay rela y setpoints should be as long as permissible to minimize the potential for inadvertent relay actuation and to preserve operating margin, an NTS of 4.00 seconds has been chosen.

BVPS does not have calibration data for the ABB 62T, and ABB datasheet does not publish drift values for the ABB 62T series of relays. In the absence of vendor supplied drift values and plant operating data for the new time delay re lays, a 1.8% drift value was applied. Based on the full range (9.99 seconds) of the time delay relay, drift would be +/-

0.18 seconds over a 54-month calibration period. The proposed m inimum allowable values reflect this value.

In the supplement dated April 4, 2022, the licensee provided su mmaries of the Calculation No.

E-529, Revision 1, "Beaver Valley Units 1 and 2, Degraded Volta ge Relay (DVR) Time Delay Relay Instrument Uncertainty" (Enclosure J of the Supplement ).

In calculation No. E-529 of the supplement, the licensee used the Maintenance Measured Database (MMD) to calculate the device drift for each equipment calibration and surveillance based on as-Left and as-Found data. In this calculation, th e licensee also stated, in part, Should the As-Found 4.1kV Emergency Bus DVR relay drift exceed the Maintenance Measured Database (MMD) values during any calibration frequency, a Condition Report (CR) is to be initiated, as is the practice in MMD excessive drift.

Therefore, the AV term is calculated based on the relay drift t ime-delay (RDTD):

AV = NTS +/- RDTD

= 4 sec. +/- 0.18 sec = 4.18 sec. (AV Max) and 3.82 sec (AVMin).

The NRC staff reviewed vendor instruction manual of the Solid-Stated Timing Relay, Type 62T, Model number 417T2170 (ABB IB 7.7.1.7-6, Issue D), to veri fy that (1) the time range of this model is 0.01 - 9.99 seconds, and (2) the repeatability of delay setting range is +/- 0.5 percent of the delay time setting or +/- 15 milliseconds (ms), o r +/-1 digit (10ms), which is greater.

The licensee calculated the Rack or Component Calibration Accuracy (RCA) for NTS : 0.5 percent x 4.0 sec = 0.02 sec (for both Beaver Valley, Units 1 and 2). Therefore, the proposed RCA 0.02 sec for NTS is consistent with the vendor instructio n manual.

In this calculation, the licensee calculated the proposed time-delays for the proposed Functions 5 and 6. The NRC staff summarized the results, that are reflect ed in Table 3.

Table 3: Summary of the Proposed Time-Delay Relays Calculations Results Items /Terms and Equations Unit 1 Unit 2 Second (sec) Second (sec)

ALMax Maximum Analytical Limit (ALMax) 4.4 sec 4.7 sec

TAMax Maximum Total Allowance (TAMax) = lALMax - NTSl 0.4 sec 0.7 sec

TAMin Minimum Total Allowance (TAMin) = lALMin - NTSl 1.5 sec 1.8 sec CSATD (+/-)* Channel Statistical Allowance of +0.33 sec and +0.33 sec and time-delay (CSATD+ and CSATD-) -0.21 sec -0.21 sec RDTD or Rack or Component Drift or As-AFT Found Tolerance 0.18 sec 0.18 sec AVMax Maximum Allowable Value (AVMax) = NTS + RDTD 4.18 sec 4.18 sec

NTS Nominal Trip Setpoint (NTS) has been chosen 4.0 sec 4.0 sec

AVMin Minimum Allowable Value (AVMin) = NTS - RDTD 3.82 sec 3.82 sec ALMin Minimum Analytical Limit (AL Min) 2.5 sec 2.2 sec MarginMax Maximum margin (MarginMax) = TAMax - lCSATD+l 0.07 sec 0.37 sec

MarginMin Minimum margin (MarginMin) = TAMin - lCSATD-l 1.29 sec 1.59 sec

• CSATD was calculated by the following equation:

CSATD = +/- [(RCATD + RMTETD)2 + (RDTD + RMTETD)2 + RTETD2 + RMETD2]1/2 + RFDTD

+ PMATD

Where the instrument uncertainties:

RCATD: Rack or Component Calibration Accuracy time-delay RMTETD: Rack or Component Calibration Accuracy RDTD: Rack or Component Drift or Stability RTETD: Rack or Component Ambient Temperature Effects RMETD: Rack or Component Miscellaneous Effects RFDTD: Rack or Component Relay Fixed De lay Effects (Positive Bias)

PMATD: Rack or Component Process Measurement Allowance Effects (Posi tive Bias)

The licensee noted that the positive bias terms RFD TD and PMATD will only be applied to the ALMax side of the NTS. Therefore, CSATD+ and CSATD-are different.

The licensee stated (in the Calculation No. E-529) that the tim e-delay of 90 +/- 5 seconds, for the existing DVRs of the Functions 3 and 4, exceeded the 17 seconds required by the Beaver Valley UFSAR for safety injection concurrent with the offsite power condition which is described in the accident analysis. Therefore, the new time-delay of the proposed DVRs of Functions 5 and 6 will correct this condition.

The NRC staff reviewed the UFSAR of Beaver Valley, Unit 1, Table 14.3.2-1, to verify that the analyzed value or range of the parameter 3.c, Safety injection delay, should be 17 seconds (with offsite power) 27 seconds (with LOOP). Therefore, the exi sting time-delay of 90 +/- 5 secs exceeded the Beaver Valley, Unit 1, UFSAR time limit for safety injection concurrent with the offsite power condition.

The licensee is proposing to set the time-delay of 4.0 +/- 0.18 s econds for the AV time-delays of Functions 5 and 6 in TS Table 3.3.5-1.

The NRC staff used the results of the Calculation No. E-529 (th e summary is shown in Table 3 of this SE) to establish the relationships between the time-delay settings (ALs, NTS and associated AVs) of DV Functions 5 and 6. These relationships are reflected in Figure 2.

Figure 2: Time-Delay Settings of Functions 5 and 6 Relationship s

Based on the information in Table 3 and Figure 2 above, with re spect to the proposed AV Max and AVMin for the DVRs of Functions 5 and 6 in TS Table 3.3.5-1 of Beave r Valley, Units 1 and 2, the NRC staff has determined the following:

The margin ratio percentage between the NTS and AV margins (Rows 7 and 8) are adequate. These margins ensure that the trip setpoint has been chosen to assure that a trip or safety actuation will occur significantly before the me asured process reaches the ALMax and ALMin. The proposed AV settings support an automatic protective action that will correct the abnormal situation before a safety limit is ex ceeded.

The AV term is calculated based on the relay drift time-delay (RDTD) and NTS is consistent with the definition of AV in the (ANSI/ISA) Standard 67.04.01-2018. This stated, for those plants that include AV values in their technical specifications, the AV is

established as the least conservative value of the as-found setpoint that a channel can have during a periodic technical specification required channel calibration, channel operational test,. Therefore, NTS inclusive (+/-) of their AFT s (RDTD) are in the range of AVMax and AVMin. That would assure that the trip signals will be initiated bef ore or when NTS exceeds the AV values. The proposed AFT values associa ted with the setpoint changes were determined in a manner consistent with RIS 2006-17 in establishing the As-Left and As-Found tolerances.

The Margin NTSMax (TAMax)(Row 3) are greater than CSATD+ and Margin NTSMin (TAMin)(Row 5) are greater than absolute values of CSA TD-. This indicates that there is reserve margin beyond CSA. The Margin Max and MarginMin values are illustrated in Table 3 of this SE.

In addition, the values of AV Max are less than (NTS + CSATD+) (Row 1) and AVMin are greater than (NTS + CSATD-) (Row 2) that specify: the proposed maximum and minimum AVs will be not exceeded the TA Max and TAMin (before margins included).

Therefore, the allowable time duration of a degraded voltage co ndition at all distribution system levels shall not result in failure of safety related sys tems or components

The proposed maximum/minimum TS AVs are within the time delay setting range of 3.82 sec to 4.18 sec to resolve the existing DVR time delay (of 90+/-5 secs) that was not consistent with the assumption in the UFSAR accident analysis f or safety injection flow.

Moreover, this proposed time delay setting is consistent with the timing range of 0.01 to 9.99 secs of the ABB vendor manual for Type 62T, Solid-State Ti ming Relay, would maintain the associated variables and systems within prescribed operating ranges.

The NRC staff finds that the proposed DVR settings for new DV F unctions 5 and 6 in TS Table 3.3.5-1 provided sufficient margins to continue to satisfy the requirements of 10 CFR 50.36(c)(1)(ii)(A) and 10 CFR 50, Appendix A, GDC 13 and were e stablished in conformance with RIS 2011-12 and RIS 2006-17. Therefore, the staff finds that these proposed AVs are acceptable.

3.2.5 TS Table 3.3.5-1 Implementation Notes

The August 2, 2022, supplement addressed a potential configuration control issue during the implementation period for TS Table 3.3.5-1 to indicate when eac h version of it would be applicable before and after the system modifications anticipate d in 2024 for Unit 2 and 2027 for Unit 1. Since both versions of TS Table 3.3.5-1 on TS pages 3.3.5-3 and 3.3.5-3a are effective at the same time, the licensee proposed to add notes to these p ages in the headers. The NRC staff finds this proposed administrative change acceptable because it provides clarity to the requirements as to when each version would be applicable according to their modification status.

3.3 Technical Conclusion

Based on the technical evaluation in Section 3.0, the staff fin ds that the changes proposed in TS 3.3.5 are acceptable. The methodology of calculations/analyses performed by the licensee meet the intent of NUREG-0800 BTP 8-6, RIS 2011-12, RIS 2006-17, and IEEE Std. 741-2017. The changes meet the requirements of 10 CFR 50.36(c). The proposed TS changes would ensure that the intent of 10 CFR 50, Appendix A, GDC 17, relating to the adequacy of offsite power

source (which includes adequate voltage requirements of safety-related loads), continues to be met and ensures sufficient margins are provided to continue to satisfy the requirements of 10 CFR 50.36(c)(1)(ii)(A) and 10 CFR 50, Appendix A, GDC 13. Addit ionally, as described in Section 3.1 of this SE, the licensee used an acceptable SRSS co mbinatorial method to calculate the proposed settings. The staff finds that this methodology provides a reasonable assurance that control and monitoring setpoints are established and maintained in a manner consistent with plant safety function requirements and consistent with RG 1.105 Revision 4.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Pennsylvan ia State official was notified of the proposed issuance of the amendments on May 26, 2022. The St ate official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to installatio n 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 amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the am endments involve no significant hazards consideration, and there has been no public comment on such finding (87 FR 3847; January 25, 2022). Accordingly, the amendments mee t the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

6.0 CONCLUSION

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

Principal Contributors: V. Goel, NRR H. Vu, NRR K. West, NRR

Date: September 1, 2022

ML22222A086 OFFICE NRR/DORL/LPL1/PM NRR/DORL/LPL1/LA NRR/DEX/EEEB/BC NRR/DEX/ECIB/BC NAME BBallard KZeleznock (SLent for) WMorton MWaters DATE 08/09/2022 8/11/22 05/13/2022 05/11/2022 OFFICE NRR/DSS/STSB/BC OGC - NLO NRR/DORL/LPL1/BC NRR/DORL/LPL1/PM NAME VCusumano MCarpentier HGonzález BBallard DATE 08/09/2022 08/25/2022 09/01/2022 09/01/2022