ML19312A098
| ML19312A098 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 12/03/2019 |
| From: | John Lamb Plant Licensing Branch II |
| To: | Gayheart C Southern Nuclear Operating Co |
| Lamb J | |
| References | |
| EPID L-2019-LLA-0108 | |
| Download: ML19312A098 (38) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 Ms. Cheryl A. Gayheart Regulatory Affairs Director Southern Nuclear Operating Co., Inc.
3535 Colonnade Parkway Birmingham, AL 35243 December 3, 2019
SUBJECT:
EDWIN I. HATCH NUCLEAR PLANT, UNIT NOS. 1 AND 2, ISSUANCE OF AMENDMENTS REGARDING LICENSE AMENDMENT REQUEST FOR TECHNICAL SPECIFICATIONS 3.3.8.1 AND 3.8.1 REGARDING UNIT 1 DEGRADED VOLTAGE PROTECTION (EPID L-2019-LLA-0108)
Dear Ms. Gayheart:
The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 302 to Renewed Facility Operating License No. DPR-57 and Amendment No. 247 to Renewed Facility Operating License No. NPF-5 for the Edwin I. Hatch Nuclear Plant (HNP), Unit Nos. 1 and 2, respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated April 30, 2019, as supplemented by letters dated August 28, and October 17, 2019.
The amendments revise HNP, Unit 1, and HNP, Unit 2, TS 3.3.8.1, "Loss of Power (LOP)
Instrumentation," to modify the instrument allowable values for the 4.16 kilovolt (kV) emergency bus degraded voltage instrumentation for HNP Unit1, and delete the annunciation requirements for the 4.16 kV emergency bus undervoltage instrumentation for HNP Unit 1, including associated TS actions. These proposed amendments would also delete HNP, Unit 1 License Condition 2.C(11) and HNP, Unit 2 License Condition 2.C(3)(i). Additionally, the proposed amendments would revise surveillance requirement (SR) 3.8.1.8 in TS 3.8.1, "AC Sources -
Operating," to increase the voltage limit in the emergency diesel generator (EDG) full load rejection test for the HNP, Unit 1 EDGs.
C. A copy of the related Safety Evaluation is also enclosed. A Notice of Issuance will be included in the Commission's biweekly Federal Register notice.
Docket Nos. 50-321 and 50-366
Enclosures:
- 1. Amendment No. 302 to DPR-57
- 2. Amendment No. 247 to NPF-5
- 3. Safety Evaluation cc: Listserv Sincerely, John. Lamb, S! ~~
Plant icensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SOUTHERN NUCLEAR OPERATING COMPANY, INC.
GEORGIA POWER COMPANY OGLETHORPE POWER CORPORATION MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA CITY OF DAL TON, GEORGIA DOCKET NO. 50-321 EDWIN I. HATCH NUCLEAR PLANT, UNIT NO. 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 302 Renewed License No. DPR-57
- 1.
The Nuclear Regulatory Commission (the Commission) has found that:
A.
The application for amendment to the Edwin I. Hatch Nuclear Plant, Unit No. 1 (the facility) Renewed Facility Operating License No. DPR-57 filed by Southern Nuclear Operating Company, Inc. (the licensee), acting for itself, Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and City of Dalton, Georgia (the owners), dated April 30, 2019, as supplemented August 28, and October 17, 2019, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I;
- 8.
The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.
There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations 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.
- 2.
Accordingly, the license is hereby amended by page 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-57 is hereby amended to read as follows:
(2)
Technical Specifications The Technical Specifications (Appendix A) and the Environmental Protection Plan (Appendix 8), as revised through Amendment No. 302, are hereby incorporated in the renewed license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
- 3.
This license amendment is effective as of its date of issuance and shall be implemented after the installation of the Degraded Voltage modifications, and prior to start-up from the HNP, Unit 1, spring 2020 refueling outage.
Attachment:
Changes to Renewed Facility Operating License No. DPR-57 and Technical Specifications FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance:
December 3, 2019
ATTACHMENT TO LICENSE AMENDMENT NO. 302 EDWIN I. HATCH NUCLEAR PLANT, UNIT NO. 1 RENEWED FACILITY OPERATING LICENSE NO. DPR-57 DOCKET NO. 50-321 Replace the following pages of the License and the Appendix A Technical Specifications (TSs) with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.
Remove Pages Insert Pages License License 4
4 8
8 TSs TSs 3.3-70 3.3-70 3.3-71 3.3-71 3.3-72 3.3-72 3.8-11 3.8-11 for sample analysis or instrumentation calibration, or associated with radioactive apparatus or components (6)
Southern Nuclear, pursuant to the Act and 10 CFR Parts 30 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.
(C)
This renewed license shall be deemed to contain, and is subject to, the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Section 50.54 of Part 50, and Section 70.32 of Part 70; all applicable provisions of the Act and the rules, regulations, and orders of the Commission now or hereafter in effect; and the additional conditions2 specified or incorporated below:
(1)
Maximum Power Level Southern Nuclear is authorized to operate the facility at steady state reactor core power levels not in excess of 2804 megawatts thermal.
(2)
Technical Specifications (3)
The Technical Specifications (Appendix A) and the Environmental Protection Plan (Appendix B); as revised through Amendment No. 302 are hereby incorporated in the renewed license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
The Surveillance Requirement (SR) contained in the Technical Specifications and listed below, is not required to be performed immediately upon implementation of Amendment No. 195. The SR listed below shall be successfully demonstrated before the time and condition specified:
SR 3.8.1.18 shall be successfully demonstrated at its next regularly scheduled performance.
Fire Protection Southern Nuclear shall implement and maintain in effect all provisions of the fire protection program, which is referenced in the Updated Final Safety Analysis Report for the facility, as contained in the updated Fire Hazards Analysis and Fire Protection Program for the Edwin I. Hatch Nuclear Plant, Units 1 and 2, which was originally submitted by letter dated July 22, 1986. Southern Nuclear may make changes to the fire protection program without prior Commission approval only if the changes Renewed License No. DPR-57 Amendment No. 302
- c.
The first performance of the periodic measurement of CRE pressure, Specification 5.5.14.d, shall be within 24 months, plus the 6 months allowed by SR 3.0.2, from the date of the most recent successful pressure measurement test.
D.
Southern Nuclear shall not market or broker power or energy from Edwin I. Hatch Nuclear Plant, Unit 1.
- 3.
This renewed license is effective as of the date of issuance and shall expire at midnight, August 6, 2034.
FOR THE U.S. NUCLEAR REGULATORY COMMISSION
~irector Office of Nuclear Reactor Regulation Attachments:
Appendix A-Technical Specifications Appendix B - Environmental Protection Plan Date of Issuance: January 15, 2002 Renewed License No. DPR-57 Amendment No. 302
3.3 INSTRUMENTATION 3.3.8.1 Loss of Power (LOP) Instrumentation LOP Instrumentation 3.3.8.1 LCO 3.3.8.1 The LOP instrumentation for each Function in Table 3.3.8.1-1 shall be OPERABLE for each diesel generator (DG) required by LCO 3.8.1, "AC Sources - Operating," and LCO 3.8.2, "AC Sources - Shutdown."
APPLICABILITY:
When associated DG is required to be OPERABLE.
ACTIONS
NOTE---------------------------------------------------------
Separate Condition entry is allowed for each channel.
CONDITION REQUIRED ACTION COMPLETION TIME A.
One or more required A.1 Restore channel to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> channels inoperable.
OPERABLE status.
B.
Required Action and 8.1 Declare associated DG Immediately associated Completion inoperable.
Time not met.
HATCH UNIT 1 3.3-70 Amendment No. 302
SURVEILLANCE REQUIREMENTS LOP Instrumentation 3.3.8.1
NOTES---------------------------------------------------
- 1.
These SRs apply to each Function in Table 3.3.8.1-1.
- 2.
When a 4.16 kV Emergency Bus Undervoltage channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains initiation capability.
SURVEILLANCE SR 3.3.8.1.1 Deleted.
SR 3.3.8.1.2 Perform CHANNEL FUNCTIONAL TEST.
SR 3.3.8.1.3 Perform CHANNEL CALIBRATION.
SR 3.3.8.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.
HATCH UNIT 1 3.3-71 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendment No. 302
- 1.
- 2.
HATCH UNIT 1 FUNCTION Table 3.3.8.1-1 (page 1 of 1)
Loss of Power Instrumentation REQUIRED CHANNELS PER BUS 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)
- a.
Bus Undervoltage 2
- b.
Time Delay 2
4.16 kV Emergency Bus Undervoltage (Degraded Voltage)
- a.
Bus Undervoltage 2
- 1) Bus 1E
- 2) Bus 1F
- 3) Bus 1G
- 4) Bus2E
- 5) Bus2G
- b.
Time Delay 2
- 1) Unit 1 Buses
- 2) Unit 2 Buses 3.3-72 LOP Instrumentation 3.3.8.1 ALLOWABLE VALUE
~ 2800V s 6.5 seconds
~ 3990V
~ 3861 V
~ 3885 V
~ 3952V
~ 3892V s 11.3 seconds s 9.8 seconds Amendment No. 302
AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SR 3.8.1.8 HATCH UNIT 1 SURVEILLANCE
NOTES------------------------------
- 1.
This Surveillance shall not normally be performed in MODE 1 or 2, except for the swing DG. However, this surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. For the swing DG, this Surveillance shall not be performed in MODE 1 or 2 using the Unit 1 controls.
Credit may be taken for unplanned events that satisfy this SR.
- 2.
If grid conditions do not permit, the power factor limit is not required to be met. Under this condition, the power factor shall be maintained as close to the limit as practicable.
- 3.
For the swing DG, a single test at the specified Frequency will satisfy this Surveillance for both units.
Verify each DG operating at a power factor s 0.88 does not trip and voltage is maintained s 5200 V during and following a load rejection of ~ 2775 kW.
3.8-11 FREQUENCY In accordance with the Surveillance Frequency Control Program (continued)
Amendment No. 302
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SOUTHERN NUCLEAR OPERA TING COMPANY, INC.
GEORGIA POWER COMPANY OGLETHORPE POWER CORPORATION MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA CITY OF DAL TON. GEORGIA DOCKET NO. 50-366 EDWIN I. HATCH NUCLEAR PLANT, UNIT NO. 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 247 Renewed License No. NPF-5
- 1.
The Nuclear Regulatory Commission (the Commission) has found that:
A.
The application for amendment to the Edwin I. Hatch Nuclear Plant, Unit No. 2 (the facility) Renewed Facility Operating License No. NPF-5 filed by Southern Nuclear Operating Company, Inc. (the licensee), acting for itself, Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and City of Dalton, Georgia (the owners), dated April 30, 2019, as supplemented August 28, and October 17, 2019, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I; B.
The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.
There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations 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.
- 2.
Accordingly, the license is hereby amended by page 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-5 is hereby amended to read as follows:
(2)
Technical Specifications The Technical Specifications (Appendix A) and the Environmental Protection Plan (Appendix 8), as revised through Amendment No. 247 are hereby incorporated in the renewed license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
- 3.
This license amendment is effective as of its date of issuance and shall be implemented after the installation of the Degraded Voltage modifications, and prior to start-up from the HNP, Unit 1, spring 2020 refueling outage.
Attachment:
Changes to Renewed Facility Operating License No. NPF-5 and Technical Specifications FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance:
December 3, 2019
ATTACHMENT TO LICENSE AMENDMENT NO. 247 EDWIN I. HATCH NUCLEAR PLANT, UNIT NO. 2 RENEWED FACILITY OPERATING LICENSE NO. NPF-5 DOCKET NO. 50-366 Replace the following pages of the License and the Appendix A Technical Specifications (TSs) with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.
Remove Pages Insert Pages License License 4
4 6b 6b TSs TSs 3.3-70 3.3-70 3.3-71 3.3-71 3.3-72 3.3-72 3.8-11 3.8-11 (6)
Southern Nuclear, pursuant to the Act and 10 CFR Parts 30 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.
(C)
This renewed license shall be deemed to contain, and is subject to, the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Section 50.54 of Part 50, and Section 70.32 of Part 70; all applicable provisions of the Act and the rules, regulations, and orders of the Commission now or hereafter in effect; and the additional conditions2 specified or incorporated below:
( 1)
Maximum Power Level Southern Nuclear is authorized to operate the facility at steady sate reactor core power levels not in excess of 2,804 megawatts thermal, in accordance with the conditions specified herein.
(2)
Technical Specifications The Technical Specifications (Appendix A) and the Environmental Protection Plan (Appendix B); as revised through Amendment No. 247 are hereby incorporated in the renewed license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
(3)
Additional Conditions The matters specified in the following conditions shall be completed to the satisfaction of the Commission within the stated time periods following the issuance of the renewed license or within the operational restrictions indicated. The removal of these conditions shall be made by an amendment to the license supported by a favorable evaluation by the Commission.
(a)
Fire Protection Southern Nuclear shall implement and maintain in effect all provisions of the fire protection program, which is referenced in the Updated Final Safety Analysis Report for the facility, as contained 2 The original licensee authorized to possess, use, and operate the facility with Georgia Power Company (GPC). Consequently, certain historical references to GPC remain in certain license conditions.
Renewed License No. NPF-5 Amendment No. 247
(h)
- 6b -
TSTF-448 Control Room Habitability Upon implementation of the Amendments adopting TSTF-448, Revision 3, the determination of control room envelope (CRE) unfiltered air inleakage as required by SR 3.7.4.4, in accordance with TS 5.5.14.c.(i), the assessment of CRE habitability as required by Specification 5.5.14.c.(ii), and the measurement of CRE pressure as required by Specification 5.5.14.d, shall be considered met. following implementation:
i)
The first performance of SR 3.7.4.4, in accordance with Specification 5.5.14.c.(i), shall be within the next 18 months.
ii)
The first performance of the periodic assessment of CRE habitability, Specification 5.5.14.c.(ii), shall be within 3 years, plus the 9-month allowance of SR 3.0.2, of the next successful tracer gas test.
iii)
The first performance of the periodic measurement of CRE pressure, Specification 5.5.14.d, shall be within 24 months, plus the 6 months allowed by SR 3.0.2, from the date of the most recent successful pressure measurement test.
D.
This renewed license is subject to the following antitrust conditions:
(1)
As used herein:
(a)
"Entity" means any financially responsible person, private or public corporation, municipality, county, cooperative, association, joint stock association or business trust, owning, operating or proposing to own or operate equipment or facilities within the state of Georgia (other than Chatham, Effingham, Fannin, Towns and Union Counties) for Renewed License No. NPF-5 Amendment No. 247
3.3 INSTRUMENTATION 3.3.8.1 Loss of Power (LOP) Instrumentation LOP Instrumentation 3.3.8.1 LCO 3.3.8.1 The LOP instrumentation for each Function in Table 3.3.8.1-1 shall be OPERABLE for each diesel generator (DG) required by LCO 3.8.1, "AC Sources - Operating," and LCO 3.8.2, "AC Sources - Shutdown."
APPLICABILITY:
When associated DG is required to be OPERABLE.
ACTIONS
NOTE------------------------------------------------------------
Separate Condition entry is allowed for each channel.
CONDITION REQUIRED ACTION COMPLETION TIME A.
One or more required A.1 Restore channel to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> channels inoperable.
OPERABLE status.
B.
Required Action and B.1 Declare associated DG Immediately associated Completion inoperable.
Time not met.
HATCH UNIT 2 3.3-70 Amendment No. 247
SURVEILLANCE REQUIREMENTS LOP Instrumentation 3.3.8.1
NOTES----------------------------------------------------------
- 1.
These SRs apply to each Function in Table 3.3.8.1-1.
- 2.
When a 4.16 kV Emergency Bus Undervoltage channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains initiation capability.
SURVEILLANCE SR 3.3.8.1.1 Deleted.
SR 3.3.8.1.2 Perform CHANNEL FUNCTIONAL TEST.
SR 3.3.8.1.3 Perform CHANNEL CALIBRATION.
SR 3.3.8.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.
HATCH UNIT 2 3.3-71 FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program Amendment No. 247
- 1.
- 2.
HATCH UNIT2 FUNCTION Table 3.3.8.1-1 (page 1 of 1)
Loss of Power Instrumentation REQUIRED CHANNELS PER BUS 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)
- a.
Bus Undervoltage 2
- b.
Time Delay 2
4.16 kV Emergency Bus Undervoltage (Degraded Voltage)
- a.
Bus Undervoltage 2
- 1) Bus 2E
- 2) Bus 2F
- 3) Bus 2G
- 4) Bus 1E
- 5) Bus 1G
- b.
Time Delay 2
- 1) Unit 2 Buses
- 2) Unit 1 Buses 3.3-72 LOP Instrumentation 3.3.8.1 ALLOWABLE VALUE
~ 2800V s 6.5 seconds
~ 3952V
~ 3892V
~ 3892V
~ 3990V
~ 3885 V s 9.8 seconds s 11.3 seconds Amendment No. 247
AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SR 3.8.1.8 HATCH UNIT 2 SURVEILLANCE
* --------------------NO TES---------------------------
- 1.
This Surveillance shall not normally be performed in MODE 1 or 2, except for the swing DG. However, this surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. For the swing DG, this Surveillance shall not be performed in MODE 1 or 2 using the Unit 2 controls.
Credit may be taken for unplanned events that satisfy this SR.
- 2.
If grid conditions do not permit, the power factor limit is not required to be met. Under this condition, the power factor shall be maintained as close to the limit as practicable.
- 3.
For the swing DG, a single test at the specified Frequency will satisfy this Surveillance for both units.
Verify each DG operating at a power factors 0.88 does not trip and voltage is maintained s 5200 V during and following a load rejection of.:: 2775 kW.
3.8-11 FREQUENCY In accordance with the Surveillance Frequency Control Program (continued)
Amendment No. 247
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 302 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-57 AND AMENDMENT NO. 247 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-5 SOUTHERN NUCLEAR OPERATING COMPANY, INC.
EDWIN I. HATCH NUCLEAR PLANT, UNIT NOS. 1 AND 2 DOCKET NOS. 50-321 AND 50-366
1.0 INTRODUCTION
By application dated April 30, 2019 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML19123A101), as supplemented by letters dated August 28 and October 17, 2019 (ADAMS Accession Nos. ML19240B751 and ML19290H599, respectively),
Southern Nuclear Operating Company, Inc. (SNC, the licensee), requested changes to the Technical Specifications (TSs) for the Edwin I. Hatch Nuclear Plant (HNP), Unit Nos. 1 and 2.
The proposed amendments would revise HNP, Unit 1, and HNP, Unit 2, TS 3.3.8.1, "Loss of Power (LOP) Instrumentation," to modify the instrument allowable values for the 4.16 kilovolt (kV) emergency bus degraded voltage instrumentation HNP, Unit 1, and delete the annunciation requirements for the 4.16 kV emergency bus undervoltage instrumentation for HNP, Unit 1, including associated TS actions. These proposed amendments would also delete HNP, Unit 1 License Condition 2.C(11) and HNP, Unit 2 License Condition 2.C(3)(i). Additionally, the proposed amendments would revise surveillance requirement (SR) 3.8.1.8 in TS 3.8.1, "AC Sources - Operating," to increase the voltage limit in the emergency diesel generator (DG) full load rejection test for the HNP, Unit 1 DGs. These changes assure adequate voltage to safety-related equipment during design-basis grid voltage events and delete the annunciation requirements for the 4.16 kV Emergency Bus Undervoltage (Annunciation) instrumentation for HNP, Unit 1. This modification addressed the items specified in the U.S. Nuclear Regulatory Commission (NRC) Generic Letter (GL) 79-36, as supplemented in the NRC Regulatory Issue Summary (RIS) 2011-12, "Adequacy of Station Electric Distribution System Voltages," to revise a Unit 1 license condition to more accurately reflect its intent.
The supplements dated August 28 and October 17, 2019, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S Nuclear Regulatory Commission (NRC or the Commission) staff's original proposed no significant hazards consideration determination as published the Federal Register on July 16, 2019 (84 FR 33988).
2.0
2.1 REGULATORY EVALUATION
Electrical System Design Overview The 4.16 kV Emergency Buses of HNP, Units 1 and 2, provide electrical power to safety-related equipment such as pump motors, motor operated valves and associated control components.
The preferred source of power for 4.16 kV Emergency Buses for the required equipment is offsite power. The LOP protection instrumentation monitors the voltage on the 4.16 kV Emergency Buses E, F, and G of each HNP unit. Each electrical train has independent LOP instrumentation and relay actuation logic to detect the degraded grid or loss of voltage conditions. The LOP Diesel Generators (DGs) start signal is actuated when offsite power is either unavailable or is insufficiently stable to allow safe unit operation.
Before spring of 2019, each 4.16 kV Emergency Bus of HNP, Units 1 and 2, was provided with two sets of undervoltage (UV) protection-- one called Loss of Voltage Relay (LVR), and the other known as Degraded Voltage Relay (DVR). The UV relays protect the Class 1 E loads connected to the emergency buses from excessively low voltages indicative of complete loss of voltage or serious degradation of the offsite power source.
The Loss of Voltage condition for each 4.16 kV Emergency Buses is monitored by two L VRs.
These two relays are combined in two-out-of-two logic configuration on the same bus to generate an LOP signal if the voltage is below the nominal setpoints and remains below this value for a specified amount of time. The LOP signal results in an automatic trip of the applicable 4.16 kV preferred power supply breakers, disconnecting the 4.16 kV bus from its preferred offsite power source. Then, that undervoltage bus is transferred to receive power from a DG, an alternate power source. The DG start logic is arranged in a one-out-of-two configuration. These two L VRs also provided the low voltage annunciator to each 4.16 kV emergency bus.
The Degraded Voltage scheme has the same function of Loss of Voltage scheme that causes the bus transfers and disconnects. The degraded voltage protection is separate from the loss of voltage relays, with different voltage setting and time delay and relies upon administrative controls and the automatic portion of the degraded voltage protection scheme to ensure bus availability.
By letter dated March 9, 2018, (ADAMS Accession No. ML18071A363), the licensee submitted a license amendment request (LAR) to modify the 4.16 kV emergency bus degraded voltage instrumentation for HNP, Unit 2 and delete the annunciation and manual action requirements for the 4.16 kV emergency bus undervoltage instrumentation for HNP, Unit 2. That LAR was approved by the NRC staff on January 28, 2019 (ADAMS Accession No. ML19010A009) and the work to implement the revised LOP and DVR scheme was performed and completed by the licensee in Spring 2019, per the requirement of the HNP, Unit 2, License Condition 2.C(3)(i).
In this LAR, the licensee proposes a similar modification to the degraded voltage protection scheme for HNP, Unit 1, and proposes to complete the implementation in spring 2020, as a requirement of HNP Unit 1 License Condition 2.C(11 ).
In HNP, Unit 1, three proposed solid-state UV relays monitor the degraded voltage of each bus (Buses 1 E, 1 F, and 1 G) and their outputs are arranged in a two-out-of-three logic configuration and Unit 1 DGs are arranged in a one-out-of-three configuration. The three relays are combined in two-out-of-three logic on the same bus to generate a LOP signal if the voltage is below the nominal setpoints and remains below this value for a specified amount of time. The LOP signal results in an automatic trip of the applicable 4.16 kV preferred power supply breakers, disconnecting the undervoltage bus from its preferred offsite power source. Then that undervoltage bus is transferred to receive power from a DG, an alternate power source. This change will eliminate the manual actions that are a part of the current HNP, Unit 1, degraded voltage protection scheme.
2.2 Regulatory Requirements and Guidance:
The construction permits of HNP, Unit No. 1 and Unit No. 2, were issued on September 30, 1969, and on December 27, 1972, respectively. Consequently, HNP, Unit No. 2, is licensed in conformance with 10 CFR Part 50, Appendix A, "General Design Criteria." HNP, Unit No. 1, is licensed in conformance with the 1967 version of 10 CFR Part 50, Appendix A, "General Design Criteria for Nuclear Power Plant Construction Permits" (ADAMS Accession No. ML043310029).
HNP, Unit No.1 Final Safety Analysis Report (FSAR), Appendix F, "Conformance To Atomic Energy Commission (AEC) Criteria," describes the relevant licensing bases for HNP, Unit No. 1, as follows:
Section F.2 of this appendix contains an evaluation of the design bases of Hatch Nuclear Plant-Unit No. 1 (HNP-1) based on the current understanding of the intent
- of the "General Design Criteria for Nuclear Power Plant Construction," issued for comment in July 1967.
Section F.3 contains an evaluation of the design bases of HNP-1 based on the current understanding of the intent of the "General Design Criteria for Nuclear Power Plants," effective May 21, 1971, and subsequently amended July 7, 1971.
Each of the AEC criteria is followed by a discussion of the plant design.
Applicable references are made to facilitate comparisons.
The HNP-1 construction permit was received under the 70 general design criteria discussed in section F.2. The HNP-1 design bases were not, therefore, developed in consideration of the 64 new general design criteria discussed in section F.3. The applicant has, however, evaluated the HNP-1 design bases against the new criteria.
the NRC staff considered the following requirements in its review of the LAR:
Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Section 36 (50.36), "Technical specifications," requires that TSs shall be included in applications for a license authorizing operation of a production or utilization facility.
10 CFR 50.36(c) requires that TSs include items in five specific categories related to station operation. These categories are: (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 proposed changes discussed in this safety evaluation include changes to LCOs and SRs.
10 CFR 50.36(c)(3) requires that surveillance requirements relating to test, calibration, or inspection are to assure that the necessary quality of systems and components is maintained.
10 CFR 50 Appendix A, General Design Criterion (GDC) 13, "Instrumentation and control,"
states in part, that instrumentation shall be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, 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 controls shall be provided to maintain these variables and systems within prescribed operating ranges.
GDC 17, "Electric power systems," requires, in part, that an onsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety.
The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. The onsite electric power supplies and the onsite electric distribution system shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure. In addition, this criterion requires provisions to minimize the probability of losing electric power from any of the remaining supplies as a result of the loss of power from the unit, the transmission network, or the onsite electric power supplies.
HNP Unit No. 2 FSAR Section 8.3.1.2.1 states that the offsite power system and the onsite power systems conform to GDC 17, as discussed in Section 3.1 of the FSAR.
HNP Unit No. 1 FSAR Appendix F, Section F.2 discusses compliance with AEC GDC 39, "Emergency Power for Engineered Safety Features (ESF)," and states:
Sufficient offsite and standby (redundant, independent, and testable) auxiliary sources of electrical power are provided to attain prompt shutdown and continued maintenance of the plant in a safe condition. The capacity of the offsite and onsite power sources are independently adequate to accomplish the required ESF functions, assuming a failure of a single active component in each power system.
10 CFR 50.55a(h)(2), "Protection systems," requires nuclear power plants with construction permits issued after January 1, 1971, but before May 13, 1999, to have protection systems that meet the requirements stated in either Institute of Electrical and Electronics Engineers (IEEE)
Standard 279, "Criteria for Protection Systems for Nuclear Power Generating Stations," or IEEE Standard 603-1991, "Criteria for Safety Systems for Nuclear Power Generating Stations," and the correction sheet dated January 30, 1995. The construction permit for HNP Unit No. 2 was issued on December 27, 1972.
The NRC staff also considered the following guidance documents in its review of the LAR:
NRC Regulatory Guide (RG) 1.32, "Criteria for Safety-Related Electric Power Systems for Nuclear Power Plants," describes a method acceptable to the NRC staff for complying with the NRC's regulations with regard to design, operation, and testing of electric power systems in nuclear power plants.
RG 1.105, Revision 3, "Setpoints for Safety-Related Instrumentation," dated December 1999, (ADAMS Accession No. ML993560062) describes a method acceptable to the NRC staff for complying with the NRC's regulations for ensuring that setpoints for safety-related instrumentation are initially within and remain within the TS limits. The RG 1.105 endorses Part I of Instrument Society of America (ISA) Standard 67.04-1994, "Setpoints for Nuclear Safety-Related Instrumentation." The staff used this guide to establish the adequacy of the licensee's setpoint calculation methodologies and the related plant surveillance procedures.
NRC Standard Review Plan (NUREG-0800), Revision 2, "Standard Review Plan for the Review of Safety Analysis Reports for-Nuclear Power Plants: LWR [Light-Water Reactor] Edition,"
Appendix 8-A, July 1981, Branch Technical Position (PSB)-1, Position 8.1 (ADAMS Accession No. ML052350520). In addition to the undervoltage scheme provided to detect loss of offsite power at the Class 1 E buses, a second level of undervoltage protection with time delay should also be provided to protect the Class 1 E equipment.
NUREG-0800, Branch Technical Position (BTP) 8-6, "Adequacy of Station Electric Distribution System Voltages," Revision 3 (ADAMS Accession No. ML070710478), outlines the purpose of the DVRs to protect Class 1 E safety-related buses from sustained degraded voltage conditions on the offsite power system under accident and non-accident conditions.
Regulatory Issue Summary (RIS) 2011-12, Revision 1, "Adequacy of Station Electric Distribution System Voltages," Revision 1, dated December 29, 2011 (ADAMS Accession No. ML113050583).
IEEE Standard 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations."
NRC Generic Letter 79-36, "Adequacy of Station Electric Distribution Systems Voltages," dated August 8, 1979.
NUREG-1433, "Standard Technical Specifications General Electric BWR/4 Plants," Volume 1 -
Specifications, Revision 4.0 (ADAMS Accession No. ML12104A192).
NRC Information Notice 95-05, "Undervoltage Protection Relay Settings Out of Tolerance Due to Test Equipment Harmonics," dated January 20, 1995 (ADAMS Accession No. ML031060397).
1SA-RP67.04.02-2000, "Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation." This guidance is an unendorsed supplement to ANSI/ISA-S67.04, Part 1, 1994. In some areas, e.g., methodologies including sample equations to calculate total channel uncertainty; common assumption and practices in instrument uncertainty calculations; and application of instrument channel uncertainty in setpoint determinations, the information in RP67.04.02 is useful in interpreting ISA Standard 67.04-1994.
part of the HNP degraded voltage protection scheme. Revision of the voltage limit requirement in SR 3.8.1.8 for the Unit 1 DGs is required as a result of the higher operating voltage on the 1 E and 1 G 4.16 kV emergency buses.
The Unit 2 portion of the electrical power system modification, including the installation of the new degraded voltage instrumentation, was installed in the 2019 spring refueling outage. The final portion of the electrical power system modification will be installed for the Unit 1 4.16 kV emergency buses during the 2020 spring refueling outage. SNC has evaluated the modification against the criteria of 10 CFR 50.59(c) and determined the facility modification does not require a license amendment pursuant to 1 O CFR 50.90. However, a change to TS 3.3.8.1 and TS 3.8.1 is required as part of the implementation of that plant modification for Unit 1.
3.3 Description of Proposed Change The proposed amendment would delete Unit 1 License Condition 2.C(11) and Unit 2 License Condition 2.C(3)(i), and would revise Unit 1 and Unit 2, TS 3.3.8.1 and TS 3.8.1 as follows (deleted text in strikeout and added text in italics):
TS 3.3.8.1 Changes Condition A is revised to state "One or more required channels inoperable." far Funstions 1 and 2."
Condition Bis deleted, and Condition C is renumbered as Condition 8.
Surveillance Requirement Note 1 is revised to state "Ref.er to These SRs apply to each Function in Table 3.3.8.1-1." to determine whish SRs apply f.or eash LOP Funstion."
Surveillance Requirement Note 2 is revised to state "When a 4.16 kV Emergency Bus Undervoltage channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains initiation capability." (f.or Funstions 1 and 2) and annunsiation sapability (f.or Funstion 3)."
SR 3.3.8.1.1 is removed, and the remaining SRs are renumbered accordingly.
The Unit 1 AVs associated with Table 3.3.8.1-1 Functions 2.a, "Bus Undervoltage" and 2.b, "Time Delay," are revised with new calculated values individually specifying the bus undervoltage AV for each required 4.16 kV emergency bus.
Table 3.3.8.1-1 Function 3 is removed.
Table 3.3.8.1-1 Surveillance Requirements column is removed.
TS 3.8.1 Change SR 3.8.1.8 is revised to state:
Verify each DG operating at a power factors~ 0.88 does not trip and voltage is the f.ollmving voltages are maintained ~ 5200 V during and following a load rejection of~ 2775 kW~
fa. For DGs 1A and 1G, < 4800 V; and
- b. For DGs 2A, 2G, and 1 B, < 5200 V].
(Unit 1) fa. For DGs 2/1., 2G, and 1 B, < 5200 V; and
- b. For DGs 1/1. and 1G, < 4800 V].
(Unit 2)
The proposed changes are shown in the marked-up and clean typed Unit 1 and Unit 2 facility operating license pages and TS pages provided in Attachments 1 and 2 [of the letter dated April 30, 2019.] In addition, Attachment 3 of the letter dated April 30, 2019, provides, for information only, mark-ups of anticipated corresponding changes to affected TS Bases pages.
3.4 Technical Staff Evaluation 3.4.1 Diesel Generators According to the HNP, TS Bases, SR 3.8.1.8 demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This SR ensures proper engine generator load response under the simulated test conditions. The test under this SR simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. The SR acceptance criteria (i.e., power factor and maximum voltage) provide damage protection for the DG. While the DG is not expected to experience this transient during an event, and continues to be available, the test response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.
In the LAR, the licensee provided an analysis of the effect of an increased voltage limit on the components that are subjected to the transient voltages. The NRC staff evaluated the licensee's analysis as discussed below~
3.4.1.1 Effects on DGs As described in the LAR and its supplement, the HNP DGs are manufactured by Fairbanks Morse. DGs 1 A, 1 B and 1 C have a continuous rating of 2850 kilowatt (kW), 30-minute rating of 3500 kW, 1000-hour rating of 2850 kW, and 168-hour rating of 3250 kW. These DGs are rated at 4160 volt (V), three-phase, 60 Hertz (Hz), and are capable of attaining rated frequency and voltage within 12 seconds after receipt of a start signal.
- a. DG Voltage Rating As described in the LAR:
Fairbanks Morse identified that alternator high potential (hi-pot) factory testing on the generators is conducted for one minute at twice the rated voltage plus 1000 V; 9320 V).
Therefore, according to the licensee and the manufacturer, the DGs can withstand significantly higher voltages than the proposed voltage limit during DG full load rejection testing.
The NRC staff notes that the proposed SR voltage limit acceptance criterion of 5200 Vis bounded by the HNP DGs' test voltage rating of 9320 V.
- b. DG Speed Limit As described in the LAR:
The Fairbanks Morse vendor manual states that the generator is protected with an overspeed setting of 112% to 115% of rated speed. The overspeed trip setting will sense an overspeed and shut down the engine. The vendor indicates that the overspeed of the alternator is rated for 125%. HNP DGs 2A, 1 B, and 2C did not experience an overspeed trip during the full load rejection surveillance test performed during the spring 2019 refueling outage.
Based on the licensee's information, the NRC staff finds there is reasonable assurance that the proposed increased voltage limit for SR 3.8.1.8 would not adversely impact the DG's intended safety function. The DG damage protection would be maintained, and the DG would not be degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.
3.4.1.2 Effects on Engineered Safety Feature (ESF) Buses The NRC staff evaluated the effects of an increased voltage limit for SR 3.8.1.8 on the ESF bus as the result of the HNP, Unit 2 electrical power system modifications. In its letter dated February 20, 2019 (ADAMS Accession No. ML19051A145), the licensee stated, in part, that the increased ESF bus operating voltage was calculated for the degraded voltage protection modification using ETAP, Version 12.6.0N. The calculated bus operating voltage values were confirmed during the post-modification testing performed for ESF Bus 2F.
Based on the licensee's information, NRC staff finds, with reasonable assurance, that by confirming the calculated ESF bus operating voltage increase for bus modification testing, the proposed increased voltage limit for SR 3.8.1.8 would not adversely impact the ESF buses.
3.4.1.3 Effects on Cables
- a. Power Cables As described in the LAR and its supplement:
[The] power cables used in the 4.16 kV system at HNP from the breaker to the DG are 3/C 500 MCM [thousands of a circular mils or 0.5067 square millimeters], triplex, EPR [ethylene propylene rubber] insulated cables and rated for 15 kV. Thus, the voltage rating of the power cables exceeds the proposed voltage limit during a DG full load rejection test [by a substantial margin, and the power cables will not experience detrimental effects due to transient voltages up to 5200 V.]
- b. Control Cables As described in the LAR and its supplement:
The DG control cables have a rating of 600 V. [For an evaluated transient voltage of 9320 V, the associated maximum voltage the control cables would experience is 269 V.]
Therefore, the power and control cables would not experience detrimental effects due to transient voltages up to 5200 V.
Based on the licensee's information, the NRC staff finds, with reasonable assurance, that the power and control cable ratings bound the calculated transient voltages the cables would experience during the full load rejection testing, and therefore the proposed increased voltage limit for SR 3.8.1.8 would not adversely impact these cables.
3.4.1.4 Effects on Switchgear As described in the LAR and its supplement:
The vendor manual for the Westinghouse DHP switchgear states that the switchgear is designed to withstand an impulse test of 60 kV, and a factory production test of 19 kV at 60 Hz for one minute was performed.... The switchgear is designed for elevated voltage, and thus... there would be no adverse effect on the ability of the switchgear to operate following a voltage transient of 5200 volts for a short duration.
Based on the licensee's information, the NRC staff finds, with reasonable assurance, that the switchgear was tested at a voltage much higher than 5200 V, and, therefore, the proposed increased voltage limit for SR 3.8.1.8 would not adversely impact the switchgear.
3.4.1.5 Effects on DG Control Components As described in the LAR and its supplement:
The HNP DG voltage regulators are MPR/Basler Electric automatic voltage regulators (AVRs). The exciter portion of the excitation system consists of power current transformers, saturable transformers, linear reactors, and the AVR power supply transformer. These transformers are connected to the output of the DG via their primary windings and are isolated from the exciter output. The voltage regulator portion of the excitation system includes the AVR, which obtains voltage sensing from potential transformers. These transformers are connected to the output of the generator via their primary windings. The Basler design employs a 12 kV dielectric withstand rating for the primary windings of these transformers. Therefore, a DG peak transient voltage of 5200 V is well within the ratings of the exciter and AVR.
Based on the licensee's information, the NRG staff finds, with reasonable assurance, that the primary windings of the potential transformers are rated at a voltage much higher than 5200 V, and therefore the proposed increased voltage limit for SR 3.8.1.8 would not adversely impact the DG voltage regulators.
3.4.1.6 Effects on Grid Stability Grid stability is a function of the overall grid configuration with all electrical power lines and equipment connected or synchronized, and the balance of the generation compared to the grid loading. When the DG voltage has been synchronized with the grid voltage, the paralleling circuit breaker can be closed. Once the paralleling circuit breaker has closed, the generator set, and grid supplies are "paralleled". At this stage, the generator set output is normally zero, so it is contributing no power to the paralleled system.
As described in the LAR and its supplement:
The resulting transient voltage on the DG is due to performing the full load rejection test while in parallel with the offsite power grid. This is a simulated test of actual DG loading conditions during an accident with no offsite power. To simulate a full load rejection, the 4160 V feeder breaker at the safety-related bus is opened. At the time after the breaker has opened, the 4160 V bus does not experience the peak transient voltage that occurs at the DG.
Based on the licensee's information, the NRG staff finds, with reasonable assurance, that the proposed increased voltage limit for SR 3.8.1.8 would not adversely impact the grid stability.
3.4.2 TS 3.3.8.1 The AVs for the automatic DVRs in TS Table 3.3.8.1-1 for function 2, are revised to assure adequate voltage to safety-related equipment during design basis events, thus eliminating reliance on manual actions. The proposed change to revise the degraded voltage instrumentation (i.e., function 2 of TS Table 3.3.8.1-1) A Vs for the HNP, Unit 1 buses does not involve a physical change to the LOP instrumentation, nor does it change the safety function of the LOP instrumentation or the equipment supported by the LOP instrumentation. The AVs for function 2 include new calculated values individually specified for each required HNP, Unit 1 4.16 kV emergency bus and are more restrictive than the current requirements. These more restrictive requirements continue to ensure process variables, structures, systems, and components are maintained consistent with the safety analyses and licensing basis. The NRG staff finds that there is reasonable assurance that 10 GFR 50.36(b) will be met because TS A Vs are derived from the analyses and evaluation included in the safety analysis report and amendments thereto. Therefore, the revised AVs for TS Table 3.3.8.1-1 Function 2 are acceptable. This change provides clarification of the LOP instrumentation requirements for specific 4.16 kV emergency buses and reflects the fact that revised AVs are associated with each emergency bus modified as part of the HNP electrical power system upgrades.
The licensee applied the definitions of the Analytical Limit (AL), Allowable Value (AV), Nominal Trip Setpoint (NTSP), and margin in Sections 3 (Definitions) and 4 (Establishment of Setpoints),
of the (ANSl)/ISA-67.04.01-1994 to define:
NTSP Margin is an allowance provided between the NTSP and the AL.
AV Margin is an allowance provided between the Maximum AV and the AL, which is dependent on the process measurement uncertainties, the instrument accuracies and the calibration errors, but does not include error due to instrument drift.
The licensee calculated the AV Margins and NTSP Margins by subtracting or adding the AL from AV and NSTP as shown below:
For increasing setpoint AV= AL-AV Margin Minimum NTSP = AL - NTSP Margin For decreasing setpoint AV= AL+ AV Margin Maximum NTSP = AL + NTSP Margin (Equation 1)
(Equation 2)
The NRC staff review is based on the RG 1.105, Revision 3, which presents acceptable methods for combining uncertainties in determining a trip setpoint and its allowable values and Section 4, "Establishment of Setpoints," of the American National Standards Institute (ANSI)/
ISA-S67.04.01-1994. This standard, ISA-S67.04.01-1994, is endorsed within RG 1.105, to independently calculate the Total Loop Uncertainty (TLU) for a process parameter that is increasing, using the following equations:
=
TLU (A)
=
Margin (B)
=
Margin%
=
AL - TLU; thus, AL-NTSP AL-AV (B / A) x 100 %
(Equation 3)
(Equation 4)
(Equation 5)
The TLU is total amount by which an instrument channel's output is in doubt ( or the allowance made for such doubt) due to possible errors, either random or systematic. The uncertainty is generally identified within a probability and confidence level. Random error is described as a variable whose value at a particular future instant cannot be predicted exactly but can only be estimated by a probability distribution function. Bias is an uncertainty component that consistently has the same algebraic sign and is expressed as an estimated limit of error.
The NRC staff independently compared the licensee's equations (1) and (2) (Minimum NTSP and AV Margin for increasing setpoint) with the equations (3) to (5) and verified that the general HNP setpoint methodology is consistent with the performance criteria of RG 1.105 and the method to determine the trip setpoint and AV of ISA-S67.04.
In addition, the methodology was used to establish the setpoints for the DVRs in HNP, Unit 2, that were found to be acceptable by the NRC staff in the letter dated January 28, 2019 (ADAMS Accession No. ML 1901 OA009). Therefore, the NRC staff finds that these methodologies to establish the setpoints for the proposed DVRs in HNP, Unit 1, are acceptable as well.
The NRC staff evaluated the calculated setpoint values for the 4.16 kV Emergency Buses 1 E, 1 F, and 1 G for HNP, Unit 1 in Attachment 4 of the LAR, as shown below:
Table 2.1-1 of Attachment 4 provided the minimum required voltage (MRVs) and maximum expected voltage (MEVs for 4.16 kV safety-related emergency buses for HNP, Unit 1. Table 2.2-1 provided the undervoltage Leave-Alone Tolerances (LAT i.e.,+/- 7.0 VAC, +/- 0.1-percent for the primary voltage and+/- 0.2 VAC, +/- 0.1-percent for the secondary voltage). Table 2.2-2 provided the AVs and NTSPs for the bus degraded voltage functions.
The NRC staff reviewed the information in Table 2.2-2, "Allowable Values and Nominal Setpoints (Bus Undervoltage Function," in Attachment 4 of the LAR and summarized it in Figure 1 below:
Bus Degraded Voltage -
1E 1F 1G Undervoltage Trip Primary Secondar Primary Secondar Primary Secondar 0/AC)
Voltage y Voltage Voltage yVoltage Voltage y Voltage MEV/%
4145.4 118.4 99.65 4152.9 118.7 99.83 4146.2 118.5 Upper Operating 4093.4 116.9 98.40 3962.4 113.2 95.25 3988.1 113.9 AV Reset 4049.5 115.7 3920.0 112.0 3944.5 112.7 NTSP Reset 4042.5 115.5 3913.0 111.8 3937.5 112.5 NTSP (Trip) 4021.5 114.9 3892.0 111.2 3916.5 111.9 Lower AV 3990 114.0 3861 110.3 3885 111.0 Lower AL 3937.9 112.6 94.66 3808.1 108.9 91.54 3833.5 109.6 MRV/%
3854.7 110.1 92.66 3752.3 107.2 90.20 3758.6 107.4 Figure 1: NRC Safety Evaluation Summary of Proposed Degraded Voltage for HNP, Unit 1 99.67 95.87 92.15 90.35 Based on the summary of the proposed degraded voltage for HNP Unit 1, the NRC staff finds that:
The proposed A Vs and NTSPs of 4.16 kV Emergency Buses 1 E, 1 F, and 1 G for the new DVRs are less than their MEVs but remain above their MRVs to ensure that the voltages at safety-related equipment powered downstream from each respective safety-related 4.16 kV buses remain above their minimum level during steady-state and motor starting conditions.
The proposed NTSPs of Buses 1 E, 1 F, and 1 G will be set to reset to within their minimum reset value of 0.5% of settings as indicated in the calculation assumption in Section 2.3, "4.16 kV Emergency Bus Degraded Voltage -Time Delay Function," of of LAR. The NRC staff verified the licensee's settings assumption by the calculation below:
Bus 1E: 114.9 VAC + (114.9 x 0.5%) = 115.5 VAC Bus 1F: 111.2VAC+(111.2x0.5%)= 111.8VAC Bus 1G: 111.9VAC+(111.9x0.5%)= 112.5VAC The calculation results show the NTSPs Set and Reset values are consistent with the values in Table 2.2-1 of Attachment 4 of LAR. In addition, the 0.5-percent difference between Set and Reset values are consistent with the ABB Instruction Manual data (the allowed difference between pickup and dropout voltage may be set as low as 0.5-percent of setting).
The NRC staff subsequently used the guidance in RG 1.105, Revision 3, to independently confirm whether there are adequate margins for instrument channel performance uncertainty between the Als and NTSPs and associated AVs (for Function 2.a in HNP, Unit 1, TS Table 3.3.8.1-1) to satisfy the requirements of 10 CFR 50.36(c)(1 )(ii)(A).
The NRC staff used Equations (3) to (5) above to independently calculate the margin percentages(%) between AV Margins and NTSP Margins (applicable to Unit 1 4.16 kV Emergency Buses, Degraded Voltage), and the calculation results are shown in Figure 2 below:
HNP Unit 1 DVR Allowable Value & Nominal Trip Setpoints Relationships Minimum Expected Voltage AV (Reset)
NTSP (Reset)
Lower NTSP LAT+
Nominal Trip Setpoint (NTSP)
Lower NTSP LAT-A TLU (NTSP Margin)
Lower Allowable Value (AV)
B Margin (AV Margin)
Lower Analytical Limit (AL)
Minimum Required Voltage (Safety/Design Limit)
Lower AV/ NTSP Margins Calculation Bus Degraded Voltage Secondarv Vott,.,,e 11:
1F 1G (Undervoltage Trip)
(VAC)
(VAC)
NAC) 1 MEV/%
118.4 118.7 118.5 Upper Operating 116.9 113.2 113.9 2
Limit/%
3 AV Reset 115.7 112.0 112.7 4
NTSP Reset 115.5 111.8 112.5 5
LAT 0.20 0.20 0.20 6
NTSP+ LAT 115.1 111.4 112.1 7
NTSPITrlD) 114.9 111.2 111.9 8
NTSP-LAT 114.7 111.0 111.7 9
LowerAV 114.0 110.3 111.0 10 Lower AL 112.6 108.9 109.6 11 MRV/%
110.18 105.93 108.4 12 AV Maraln (8) 1.40 1.40 1.40 13 NTSP Margln(A) 2.50 2.50 2.50 Margin%=
14 B/A)*100 %
56.00 56.00 56.00 Figure 2: NRC Independent Calculation of AV Margin and NTSP Degraded Voltage Margin for Proposed DVR Buses As summarized in Figure 2 above, the NRC staff has determined the following, with respect to the proposed AVs of the 4.16 kV Emergency Buses 1 E, 1 F, and 1G for HNP, Unit 1 for the TS Table 3.3.8.1-1 Function 2.a:
The margin percentages between the NTSP and AV margins are greater than 56% and are adequate. These margins ensure that the trip setpoints have been chosen to assure that a trip or safety actuation will occur significantly before the measured process reaches the Lower Analytical Limit.
The resulting Lower ALs are higher than the MRVs values (as indicated in Rows 10 and 11 of Figure 2) and are adequate. The MRVs are calculated from the Electrical Transient Analyzer Program (ETAP) simulation for each Unit 1 4.16 kV Emergency Bus and assumed the worst case loading conditions, which assures the ALs will not exceed the HNP analysis values.
The NTSPs, inclusive of their respective LATs, are higher values than the Lower AV to assure that the trip signals will be initiated before they reach the AV value and are acceptable.
Although the proposed AL, AV, and NTSP settings for the Buses 1 E, 1 F, and 1 G are different, their A Vs Margins and NTSP Margins for each Bus are consistent and acceptable.
Furthermore, the proposed A Vs for the 4.16 kV Emergency Buses 1 E, 1 F, and 1 G for HNP, Unit 1, (proposed HNP, Unit 1, TS Table 3.3.8.1-1 Function 2.a) are greater than the AVs of the existing Function 3.a, TS 4.16 kV Emergency Buses Annunciation for HNP, Unit 1, (AVs of Function 3.a in TS Table 3.3.8.1-1, which are.:: 3825 V (primary voltage) or.:: 109.29 V (secondary voltage)). Therefore, the proposed AVs of Function 2.a will enable the existing Function 3.a (Unit 1) to be not needed and justifies the proposed deletion of Function 3.a from HNP, Unit 1, TS Table 3.3.8.1-1. The proposed deletion of Function 3.a, as described in Section 2.2.2 (2) above and discussed in Section 3.2.2 (2) of this SE, will eliminate the need for the current manual actions as part of the HNP, Unit 1, degraded voltage protection scheme.
The NRC staff determined that the proposed AVs of Function 2.a in TS Table 3.3.8.1-1 have been chosen so that automatic protective action will prevent a safety limit from being exceeded.
These proposed settings are consistent with RG 1.105, satisfy the requirements of 1 O CFR 50.36(c)(1 )(ii)(A), 10 CFR 50.36(c)(2)(ii)(C), Criterion 3, and GDC 13, and are acceptable.
TS Table 3.3.8.1-1 function 3 and its associated required channels, SRs, and AVs are deleted.
Function 3 the 4.16 kV Emergency Bus Undervoltage (Annunciation) for HNP, Unit 1 and its associated requirements are deleted, because upon completion of the electrical power system modifications for HNP, Unit 1, operators no longer need to manually transfer electrical power sources during a degraded voltage condition to assure adequate voltage is supplied to safety-related equipment during design basis events. The electrical power system modifications allow the HNP degraded voltage protection design to automatically actuate from the DVRs without crediting manual operator actions. Following an automatic degraded voltage actuation, the DVRs will automatically transfer the electrical power sources and the low voltage alarm annunciator will direct the operator to verify auto DG start, auto bus transfer to the DG, and verification of power available to the bus and associated loads. Because the HNP DVRs provide automatic protection, the NRC staff finds that the low voltage alarm annunciator is no longer required to be in TS Table 3.3.8.1-1 as function 3. Function 3 and its associated requirements do not meet the requirements to be included in TSs as stated in 10 CFR 50.36(c).
Therefore, the NRC staff finds the deletion offunction 3 in TS Table 3.8.1.1-1 to be acceptable.
The following proposed changes are based on the deletion of TS Table 3.3.8.1-1 function 3.
Deletion of the phrase "for Functions 1 and 2," in Condition A Deletion of Condition B and corresponding re-lettering of Condition C.
Revision of SR Note 1 and Note 2.
Deletion of SR 3.3.8.1.1 and the corresponding renumbering of the remaining SRs.
Deletion of TS Table 3.3.8.1-1 Surveillance Requirements column.
Since TS Table 3.3.8.1-1 will only include functions 1 and 2, the phrase "for Functions 1 and 2" is no longer necessary as Condition A will apply to both remaining functions. Condition B "One or more channels inoperable for Function 3," is only applicable to TS Table 3.3.8.1-1 function 3 and is no longer necessary; therefore, Condition C is re-lettered Condition B. The SR 3.3.8.1.1 applies to function 3, the remaining functions 1 and 2 do not require performance of SR 3.3.8.1.1; therefore, SR 3.3.8.1.1 is no longer needed for TS 3.3.8.1. The remaining SRs apply to remaining functions 1 and 2 and are renumbered SR 3.3.8.1.1, SR 3.3.8.1.2, and SR 3.3.8.1.3, respectively. Because all the SRs apply to the remaining functions 1 and 2, the SRs column in TS Table 3.3.8.1-1 is no longer necessary and is deleted.
In addition, clarity is added by revising SR Note 1 to reflect that the remaining SRs apply to remaining functions 1 and 2. The SR Note 2 contains a clarification that initiation capability is provided by functions 1 and 2 and annunciation capability is provided by function 3. This clarification is no longer necessary, since function 3 is deleted. The NRC staff determined that these proposed changes are administrative changes, which provide clarification and do not change the TSs requirements since TS Table 3.3.8.1-1 function 3 is deleted. The NRC staff finds there is reasonable assurance that 10 CFR 50.36(b), 10 CFR 50.36(c),
10 CFR 50.36(c)(2)(i), and 10 CFR 50.36(c)(3) will be met, because TS AVs are derived from the analyses and evaluation included in the safety analysis report and amendments thereto, TSs include the lowest functional capability or performance levels of equipment required for safe operation of the facility, the SRs relate to test, calibration, or inspection and assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the LCOs will be met. Therefore, the proposed changes are acceptable.
3.4.3 TS 3.8.1 The purpose of a full load rejection test as performed under SR 3.8.1.8 is to demonstrate that the DG can reject a full load without overspeed tripping or exceeding the predetermined voltage limits. This SR ensures proper DG load response under simulated test conditions. This SR simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. While the DG is not expected to experience this transient during the event, the SR requirement ensures that the DG is not degraded for future operation, including re-connection to the bus if the trip initiator can be corrected or isolated. The existing 4800 V limit for DGs 1A and 1 C in SR 3.8.1.8 is based on the pre-modification engineered safety feature bus voltages. The engineered safety feature bus operating voltages will increase as a result of the electrical power system modification, which will increase the maximum DG voltage experienced during the performance of this SR. The increased limit provides a new acceptance criterion for the performance of this SR, is based on the increased post-modification operating voltage on the 1 E and 1 G 4.16 kV emergency buses and will not result in damage to the DGs or the other components subjected to the transient voltages.
The regulation 10 CFR 50.36(c)(3), requires TSs to include items in the category of SRs, which are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the LCOs will be met. The proposed TS SR is acceptable because there is reasonable assurance that the SR continues to assure the necessary quality of the systems and components are maintained and that facility operation will be within safety limits, and that the LCO will continue to be met. Therefore, the NRC staff finds that 1 O CFR 50.36(c)(3) will continue to be met and the revised SR is acceptable.
3.4.4 License Conditions The licensee proposes to delete HNP, Unit 1 License Condition 2.C(11) and HNP, Unit 2 License Condition 2.C(3)(i). The HNP, Unit 2 portion of the electrical power system modification, including the installation of the new degraded voltage instrumentation, was installed in the 2019 spring refueling outage (RFO). The final portion of the electrical power system modification will be installed for the 4.16 kV emergency buses for HNP, Unit 1 during the 2020 spring RFO. The licensee evaluated the modification and determined that a change to TS 3.3.8.1 and TS 3.8.1 is required as part of the implementation of the plant modification for HNP, Unit 1, because it will result in a higher operating voltage on the 1 E and 1 G 4.16 kV emergency buses.
Since (1) the license conditions are satisfied upon completion of the electrical power system modifications, which eliminate the use of manual actions as part of the HNP degraded voltage protection scheme; thereby, making these license conditions unnecessary, and (2) based on
. Section 3.4.1 and 3.4.2 above, there is reasonable assurance that TS 3.3.8.1 and TS 3.8.1 assure adequate voltage to safety-related equipment during design basis events for HNP, Unit 1 and HNP, Unit 2 and the requirements of 10 CFR 50.36 continue to be met, therefore, the NRC staff finds that the proposed deletion of HNP, Unit 1 License Condition 2.C{11) and HNP, Unit 2 License Condition 2.C{3)(i) is acceptable.
3.4.5 TS Bases In accordance with 10 CFR 50.36(a)(1), the licensee submitted TS Bases changes that correspond to the proposed TS changes for information only. The licensee will make supporting changes to the TS Bases in accordance with TS 5.5.11, "Technical Specifications (TS) Bases Control Program."
3.4.6 Technical Staff Evaluation Conclusion The NRC staff reviewed the proposed TSs changes and determined that they meet the requirements for TSs in 10 CFR 50.36(b ), because they are derived from the analyses and evaluations included in the safety analysis report, and this amendment thereto. Additionally, the changes to the TSs were reviewed for technical clarity and consistency with customary terminology and format in accordance with Standard Review Plan Chapter 16.0. The NRC staff reviewed the proposed TSs changes against the regulations and concludes that they meet the requirements of 10 CFR 50.36(a){1), 10 CFR 50.36(b), 10 CFR 50.36(c),
10 CFR 50.36(c)(2){i), 10 CFR 50.36{c)(3), for the reasons discussed above, and thus provide reasonable assurance that the TSs will have the requisite requirements and controls to operate safely. Therefore, the NRC staff concludes that the proposed TSs changes are acceptable.
4.0 STATE CONSULTATION
In accordance with the Commission's regulations, the Georgia State official was notified of the proposed issuance of the amendments on September 23, 2019. The State official had no comments.
5.0 ENVIRONMENTAL CONSIDERATION
The amendments change a requirement with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20 and change surveillance requirements. 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 amendments involve no significant hazards consideration, and there has been no public comment on such finding, issued on July 16, 2019 (84 FR 33988). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22{c)(9).
Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.
6.0 CONCLUSION
The Commission has concluded, based on the 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 amendments will not be inimical to the common defense and security or to the health and safety of the public.
Principal Contributors: Hang Vu, DE/EICB Date:
Khoi Nguyen, DE/EEOB Kristy Bucholtz, DSS/STSB.
December 3, 2019
ML19312A098 via email OFFICE NRR/LPL2-1/PM NRR/LPL2-1/LA DE/EEOB/BC(A)
DE/ES EB/BC NAME JLamb KGoldstein DWilliams*
MWaters*
DATE 10/9/19 11/21/19 10/9/19 11/7/19 OFFICE DSS/STSB/BC OGC-NLO NRR/LPL2-1/BC NRR/LPL2-1/PM NAME VCusumano*
KGamin*
MMarkley JLamb DATE 8/30/19 11/21/19 12/3/19 12/3/19