Text

Draft LAR for TS 3.8.3 Inverters Operating Completion Time Extension
	ML22307A007
Person / Time
Site:	Vogtle
Issue date:	11/02/2022
From:	Dorsey K; Southern Nuclear Operating Co
To:	Cayetano Santos; NRC/NRR/VPOB
References
	Download: ML22307A007 (1)
	v • d • e

Cayetano Santos

From: Dorsey, Keith A. <kadorsey@southernco.com>

Sent: Wednesday, November 02, 2022 4:02 PM To: Cayetano Santos Cc: Billy Gleaves; Williamson, Daniel W.; Gilbreath, Jeremiah A.; Chamberlain, Amy Christine; Leighty, Steven; Garrett, William; Coleman, Jamie Marquess

Subject:

[External_Sender] Public Copy - License Amendment Request for Technical Specification 3.8.3, Inverters - Operating (Non-Proprietary)

Attachments: ND-22-XyXy_Inverter CT LAR [DRAFT-PSM].pdf

Mr.Santos:

AttachedyouwillfindaNonProprietarydraftcopyofaLicenseAmendmentRequestforTechnicalSpecification3.8.3, Inverters-OperatingforNRCreviewpriortothepresubmittalmeetingscheduledfornextThursday(11/10).

Thiscopymaybemadeavailabletothepublic.

Thanks, KeithDorseyP.E.

LeadEngineer NuclearDevelopment RegulatoryAffairs

BinN226EC 3535ColonnadeParkway Birmingham,Al35243 2059927480

1 B. H. Whitley Southern Nuclear Director Operating Company, Inc.

Regulatory Affairs 3535 Colonnade Parkway Birmingham, AL 35243 Tel 205.992.7079

Month dd, 2022 ND-22-xxxx 10 CFR 50.90

U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Vogtle Electric Generating Plant Units 3 and 4 Docket Nos.: 52-025 & 52-026

Subject:

License Amendment Request for Technical S pecification 3.8.3, Inverters - Operating, Completion Time Extension

Ladies and Gentlemen:

Pursuant to 10 CFR 52.98(c) and in accordance with 10 CFR 50.90, Southern Nuclear Operating Company (SNC) requests an amendment to the combined licenses (COLs) for Vogtle Electric Generating Plant (VEGP) Units 3 and 4 (License Numb ers NPF-91 and NPF-92, respectively).

The requested amendment proposes changes to COL App endix A, Technical Specifications (TS) 3.8.3, Inverters - Operating, to extend the Co mpletion time for Required Action A.1.

These changes were previously discussed with the NR C Staff at a public presubmittal conference call on November 10, 2022 (ADAMS Accession Number M Lxxx).

The Enclosure provides the description, technical e valuation, regulatory evaluation (including the Significant Hazards Consideration Determination) an d environmental considerations for the proposed changes.

Attachments 1 and 2 provide markups depicting the r equested changes and final typed changes, respectively, to the VEGP Units 3 and 4 TS.

provides the information-only changes to the VEGP Units 3 and 4 TS Bases document.

This letter contains no regulatory commitments. Th is letter has been reviewed and determined not to contain security-related information.

SNC requests NRC staff review and approval of this LAR no later than 12 months from acceptance. Delayed approval of this license amend ment could put the plant at increased risk of a TS required shutdown upon discovery of an inopera ble inverter. SNC expects to implement the proposed amendment within 30 days of approval of th e LAR.

U.S. Nuclear Regulatory Commission ND-22-xxxx Page 2 of 2

In accordance with 10 CFR 50.91, SNC is notifying t he State of Georgia by transmitting a copy of this letter and its enclosure to the designated Sta te Official.

Should you have any questions, please contact Amy C hamberlain at (205) 992-6361.

I declare under penalty of perjury that the foregoi ng is true and correct. Executed on the xx th of Month 2022.

Respectfully submitted,

B. H. Whitley Regulatory Affairs Director Southern Nuclear Operating Company

Enclosure:

Vogtle Electric Generating Plant (VEGP) Units 3 and 4 - Request for License Amendment: Technical Specification 3.8.3, Inverter s - Operating, Completion Time Extension

Attachments:

1. Technical Specification Marked-up Pages

2. Revised Technical Specification Pages

3. Technical Specification Bases Marked-up Pages (f or information only)

cc:

Regional Administrator, Region ll VPO Project Manager Senior Resident Inspector - Vogtle 3 & 4 Director, Environmental Protection Division - State of Georgia Document Services RTYPE: VND.LI.L00 File AR.01.02.06

Vogtle Electric Generating Plant (VEGP) Units 3 and 4

License Amendment Request for Technical Specificati on 3.8.3, Inverters - Operating, Completion Time Extension

Enclosure

Basis for Proposed Change

1.

SUMMARY

DESCRIPTION

2. DETAILED DESCRIPTION

2.1 System Design and Operation 2.2 Current Technical Specifications Requirements 2.3 Reason for the Proposed Change 2.4 Description of the Proposed Change

3. TECHNICAL EVALUATION

4. REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedents 4.3 Significant Hazards Consideration 4.4 Conclusions

5. ENVIRONMENTAL CONSIDERATIONS

6. REFERENCES

ATTACHMENTS:

1. Technical Specification Page Markups

2. Retyped Technical Specification Pages

3. Bases Page Markups (for information only)

ND-22-xxxx Enclosure Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

1

SUMMARY

DESCRIPTION Pursuant to 10 CFR 52.98(c) and in accordance with 10 CFR 50.90, Southern Nuclear Operating Company (SNC) hereby requests an amendment to Combi ned License (COL) Nos. NPF-91 and NPF-92 for Vogtle Electric Generating Plant (VEGP) Units 3 and 4, respectively.

The proposed change would revise COL Appendix A, Te chnical Specifications (TS) 3.8.3, Inverters - Operating, to extend the Completion tim e for Required Action A.1 from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days.

Additionally, TS 3.3.9, Engineered Safety Feature A ctuation System (ESFAS) Manual Initiation, Condition C proposed change would replace misspelle d Requried with Required.

2 DETAILED DESCRIPTION 2.1 System Design and Operation The Class 1E 250 VDC and Uninterruptable Power Supp ly System (IDS) consists of the Class 1E 250 DC subsystem and the Uninterruptable P ower Supply (UPS) subsystem.

The Class 1E 250 VDC subsystem is divided into four independent Divisions (A, B, C, and D). Each of these divisions is supplied from d edicated batteries and battery chargers. Divisions A and D battery banks and one of the battery banks in Divisions B and C are designated as 24-hour battery banks (two 60-cell strings in series) and provide power to the loads required for the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months following a loss of all AC power event or a design basis accident (DBA). The second batte ry bank in Divisions B and C, designated as the 72-hour battery bank (two 60-cell strings in series), is used for those loads requiring power for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months following the sa me event. A single spare battery bank with spare battery charger is provided for the Clas s 1E 250 VDC subsystem.

The Class 1E UPS subsystem provides power at 208 Y/ 120 VAC to four independent divisions of Class 1E instrument and control power buses. Divisions A and D each consist of one Class 1E inverter associated with an instrument and control distribution panel and a backup voltage regulating transformer w ith a distribution panel. The inverter is powered from the respective 24-hour battery bank switchboard. Divisions B and C each consist of two inverters, two instrument and c ontrol distribution panels, and a voltage regulating transformer (which can be suppli ed by an ancillary diesel generator) with a distribution panel. One inverter is powered by the 24-hour battery bank switchboard and the other, by the 72-hour battery b ank switchboard.

The four divisions are independent, located in sepa rate rooms, cannot be interconnected, and their circuits are routed in de dicated, physically separated raceways.

This level of electrical and physical separation pr events the failure or unavailability of a single battery, battery charger, or inverter from a dversely affecting a redundant division.

An IDS spare battery bank (IDSS-DB-1A and IDSS-DB-1 B) with a spare charger (IDSS-DC-1) is provided for the Class 1E battery sy stem. In order to preserve independence of each Class 1E DC system division, p lug-in locking type disconnects are permanently installed to prevent connection of more than one battery bank to the spare. In addition, kirk-key interlock switches ar e provided to prevent transfer operation of more than one switchboard at a time. The spare battery bank is located in a separate

Page 2 of 27 ND-22-xxxx Enclosure Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

room and is capable of supplying power to the requi red loads on any battery being temporarily replaced with the spare.

The inverters are the preferred source of power for the Class 1E AC instrument and control buses because of the stability and reliabil ity they achieve. Divisions A and D, each consist of one Class 1E inverter. Divisions B and C, each consist of two inverters.

The function of the inverter is to convert Class 1E DC electrical power to AC electrical power, thus providing an uninterruptible power sour ce for the instrumentation and controls for the Protection and Safety Monitoring S ystem (PMS). The inverters are powered from the Class 1E 250 VDC battery sources.

Under normal operation, a Class 1E inverter supplie s power to the Class 1E AC instrument and control bus. If the inverter is ino perable or the Class 1E 250 VDC input to the inverter is unavailable, the Class 1E AC ins trument and control bus is powered from the backup source associated with the same div ision via a static transfer switch featuring a make-before-break contact arrangement. In addition, a manual mechanical bypass switch can be used to provide power from the backup source to the Class 1E AC instrument and control bus when the inverter is rem oved from service. The backup source is a Class 1E 480-208/120 volt voltage regul ating transformer providing a regulated output to the Class 1E AC instrument and control bus through a static transfer switch or a manual bypass switch. This backup sour ce can be supplied by the standby diesel generator during a loss of offsite power (LO OP). Additionally, for Divisions B and C the ancillary diesel generator can also provide a source of backup power.

2.2 Current Technical Specifications Requirements TS 3.8.3, Inverters - Operating, Condition A is for One or two inverter(s) within one division inoperable. The associated Required Acti on A.1 requires Restore inverter(s) to OPERABLE status within a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

TS 3.8.3 Required Action A.1 also is provided a Not e stating: Enter applicable Conditions and Required Actions of LCO 3.8.5 Distr ibution Systems - Operating with any instrument and control bus de-energized. With any instrument and control bus de-energized, TS 3.8.5 Required Action A.1 requires re storing power to the instrument and control bus within a Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

TS 3.3.9, Engineered Safety Feature Actuation Syste m (ESFAS) Manual Initiation, Condition C has a misspelling Requried instead of Required.

2.3 Reason for the Proposed Change The TS 3.8.3 Required Action A.1 24-hour Completion Time is based upon engineering judgement, taking into consideration the time requi red to repair an inverter and the additional risk to which the unit is exposed becaus e of the inverter inoperability. The proposed change provides greater operational flexib ility for online repair or replacement of an inoperable inverter. The proposed change wou ld avert an unplanned shutdown of the unit if an inverter were inoperable for longer than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and a repair or replacement and retest of the inoperable inverter c ould not be completed during this time.

Page 3 of 27 ND-22-xxxx Enclosure Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

Extending the Completion Time for an inoperable inv erter to 14 days provides the following potential benefits:

Provide additional time to complete repairs and ne cessary retesting when components fail with the unit in the Applicability of TS 3.8.3 (i.e., Modes 1, 2, 3 and 4) thereby avoiding an unnecessary unplanned sh utdown of the unit, which could challenge safety systems.

Reducing the potential administrative burden of re questing a notice of enforcement discretion or emergency license amendme nt.

Provide additional time to troubleshoot and comple te inverter repair in a more controlled environment, which will enhance equipmen t and personnel safety.

Correcting misspelling in TS 3.3.9 Condition C is a n editorial enhancement.

2.4 Description of the Proposed Change TS 3.8.3, Inverters - Operating, Required Action A. 1 Completion Time is proposed to be revised to 14 days.

TS 3.3.9 Condition C is proposed to replace Requri ed with Required.

3 TECHNICAL EVALUATION The proposed change to TS 3.3.9 Condition C to repl ace Requried with Required is an editorial correction with no technical impact. The remainder of the Technical Evaluation will address the proposed TS 3.8.3 Completion Time change.

Regulatory Guide (RG) 1.177, Revision 2, An Approa ch for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications, identifi es that evaluations should consider integrated decision making consistent with RG 1.174, Revision 3, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Spec ific Changes to the Licensing Basis. As described in RG 1.174, Revision 3, decisions concer ning proposed changes are expected to be reached in an integrated fashion, considering tradi tional engineering and risk information, and may be based on qualitative factors as well as quan titative analyses and information. Therefore, a deterministic evaluation and a probabilistic risk assessment (PRA) have been included to support the proposed changes.

The deterministic evaluation discusses the design o f the Class 1E 250 VDC and UPS System (IDS) and the associated defense-in-depth (DID) des ign features, the function of the inverters within the IDS during normal operation, accident mi tigating steps included in the abnormal operating procedures related to the inverters, an a ssessment of continued compliance with applicable safety analyses, and risk management mea sures to be taken during the extended Completion Time. The PRA subsection discusses the quantitative analyses and risk information.

Page 4 of 27 ND-22-xxxx Enclosure Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

Deterministic Evaluation

Electrical System Design and Defense-in-Depth Featu res

The Vogtle Electric Generating Plant (VEGP) Units 3 &4 plant design provides appropriate electrical systems and DID to permit functioning of plant structures, systems, and components (SSCs) during all plant states. These systems incl ude:

Normal power supply system o Normal source (AC power from Turbine Generator)

The normal ac power supply to the main ac power sy stem is provided from the station main generator.

Off-site power supply system o Preferred source (AC power from grid)

When the main generator is not available, plant au xiliary power is provided from the switchyard by backfeeding through the main stepup and unit auxiliary transformers.

o Secondary/Maintenance source (AC Power from grid)

When neither the normal or the preferred power sou rce is available due to an electrical fault, fast bus transfer is initiated to transfer the loads to the reserve auxiliary transformers powered by maintenan ce/secondary source.

Emergency electric power system o Battery source, from Class 1E DC and UPS power sys tems.

VEGP also has the following additional power source s: non-Class 1E DC and UPS power system, non-Class 1E onsite standby diesel generator system, and the non-Class 1E ancillary diesel generator.

The emergency electric supply design incorporates a dditional levels of DID:

The Class 1E DC and UPS system has sufficient capa city to achieve and maintain safe shutdown of the plant for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months following a comp lete loss of all AC power sources without requiring load shedding for the first 24 ho urs.

The Class 1E DC and UPS system is divided into fou r independent divisions. Any three out of four divisions can shut down the plant safel y and maintain it in a safe shutdown condition.

Each Class 1E division includes a voltage regulati ng transformer with a distribution panel capable of providing a regulated output to the Clas s 1E AC instrument and control bus through a static transfer switch or a manual bypass switch in the event of an inverter failure.

Two ancillary diesel generators provide AC power f or Class 1E post-accident monitoring, MCR lighting, MCR and instrumentation and control ( I&C) room ventilation, and power to refill the passive containment cooling water storag e tank and spent fuel pool if no other sources of power are available to Divisions B and C.

Page 5 of 27 ND-22-xxxx Enclosure Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

The onsite standby power system supplies ac power to the selected permanent nonsafety loads in the event of a main generator trip concurr ent with the loss of preferred power source and maintenance power source when under fast bus transfer conditions. The onsite standby diesel generators are automatically connected to the associated 6.9 kV buses upon loss of bus voltage only after the gener ator rated voltage and frequency is established.

Extending IDS Inverter Completion Time from 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s to 14 days does not impact the layers of DID inherent to the VEGP Units 3&4 electrical syste ms or the IDS. There are no changes to the offsite and normal power supplies. There are no ch anges to the diesel generator backed Class 1E voltage regulating transformer. There are no ch anges to the redundancy inherent in the IDS design. The safety-related IDS batteries continue to provide necessary electrical power for the safety-related valves and instrumentation credited for design basis events. Therefore, the VEGP Units 3&4 design provides reasonable assurance of t he continued availability of the required power to shut down the reactor and to maintain the reactor in a safe condition after an anticipated operational occurrence or a postulated design-basis accident.

Normal Operation

The Main AC Power System (ECS) system is part of a three tier design supporting normal operation. The first tier consists of the AC power distribution systems feeding non-safety loads required exclusively for unit operation. The secon d tier includes the AC and DC power distribution systems supplying power to permanent n on-safety loads. These are non-safety loads that, due to their specific functions, are ge nerally required to remain operational at all times including when the unit is shut down. The th ird tier consists of the redundant Class 1E DC and Uninterruptible Power Supply (UPS) power dis tribution systems feeding safety related loads.

To provide normal power to the plant auxiliary and service loads during normal operation, the station generated power is transmitted to the offsi te transmission system and includes a tap to the two Unit Auxiliary Transformers (UATs). A seco nd AC power supply from the utility grid is provided through the two Reserve Auxiliary Transfor mers (RATs) supplied by two overhead lines from a 230 kV switchyard with a ring bus configurat ion. The capacity and the secondary voltage ratings of the UATs and the RATs are identical.

When AC power is available at the plant from the on -site or off-site sources, the IDS provides Class 1E 250 VDC and Class 1E 208Y/120V AC UPS powe r for distribution through the Class 1E battery chargers. The Class 1E battery chargers re ceive 480 VAC input power from the on-site standby diesel generator backed MCCs and supply 250 VDC output power to the DC buses and to the associated Class 1E inverters as input power. The Class 1E inverter supplies 208Y/120V AC UPS output power to the instrument and control b uses. The spare battery charger supplies 250 VDC output power to the spare fused transfer sw itch box bus and the spare termination box.

Page 6 of 27 ND-22-xxxx Enclosure Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

Abnormal Operation

An abnormal system condition may occur as a result of component failures within the IDS or as the result of a fire. Potential component failures and sources of component unavailability include battery charger failure, battery failure, off-line battery recharging, inverter failure, inverter maintenance, I&C room fires, and electrical equipme nt room fires. In each case, operator responses and actions have been developed and inclu ded in advanced operating procedures.

If an inverter is inoperable or the Class 1E 250 VD C input to the inverter is unavailable, the power is transferred automatically to the backup AC sourc e by a static transfer switch featuring a make-before-break contact arrangement. The backup power is received from the diesel generator backed non-Class 1E 480 VAC bus through the Class 1 E voltage-regulating transformer.

Additionally, two ancillary diesel generators provi de another source of backup AC power for Divisions B and C.

Upon the unlikely failure of the DC bus or the inve rter and the backup AC power supply (voltage regulating transformer, or upstream equipment / sou rce), the associated instrument and control power bus(es) will de-energize. TS 3.8.3 Required Action A.1 includes a Note providing more limiting actions in the event the instrument and co ntrol bus is de-energized by requiring the entry into the applicable Conditions and Required Actions of LCO 3.8.5, Distribution Systems -

Operating. These Required Actions required that ea ch affected instrument and control bus is promptly re-energized (i.e., within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ) as req uired by LCO 3.8.5 Required Action A.1.

Applicable Safety Analyses and Safety Margin Evalua tion

The initial conditions of DBA and transient analyse s in UFSAR Chapter 6 and UFSAR Chapter 15, assume engineered safety features are OPERABLE. Th e inverters are designed to provide the required capacity, capability, redundancy, and reli ability to maintain the availability of necessary power to the PMS instrumentation and controls so th at the fuel, reactor coolant system (RCS),

and containment design limits are not exceeded. Th ese limits are discussed in more detail in the Bases for Technical Specifications 3.2 (Power Distr ibution Limits), 3.4 (Reactor Coolant System),

and 3.6 (Containment Systems).

The operability of the inverters is consistent with the initial assumptions of the accident analyses and is based on meeting the design basis of the uni t. This includes maintaining at least three of the four Divisions of AC instrument and control bus es operable during accident conditions in the event of:

a) An assumed loss of all offsite and onsite AC pow er source; and b) A worst case single failure.

During operation with an inoperable inverter divisi on governed by the associated TS 3.8.3 Action Completion Time, and additional single failure is n ot assumed. In this condition the minimum required UPS divisions are operable to support the assumption of the safety analysis. As such, with one of the required Class 1E UPS divisions bei ng powered from the voltage regulating transformer, which is backed up by a diesel generat or, there is no significant reduction in the margin of safety.

Page 7 of 27 ND-22-xxxx Enclosure Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

In the event of a LOOP with an IDS division aligned to the backup power source, the power is received from a standby diesel generator backed non -Class 1E 480 VAC bus through the voltage regulating transformer. For divisions B and C, th e voltage-regulating transformers can also be connected to the ancillary AC diesel generator. The simultaneous failure of an inverter, or inverter removed from service for maintenance, followed by a standby diesel generator failure (and for Division B or C an ancillary diesel generator follo wed by a standby diesel generator failure (and for Division B or C an ancillary diesel generator f ailure) concurrent with a LOOP is extremely unlikely. Nonetheless, a failure of an IDS divisio n following a LOOP has no impact on the ability on safety-related functions since any three out of four divisions can shut down the plant safely and maintain it in a safe shutdown condition. Furt hermore, TS 3.8.5 limits the time for this deenergized bus to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

Industry Experience Related to Inverter Maintenance

VEGP Units 3&4 do not currently have direct operati ng experience related to maintenance on the specific VEGP inverter. The Class 1E Inverters are Gutor system type WDW 3015-250/208-EAN, which utilize components similar to components typi cally used in other Nuclear Power Plant applications. The exact model of inverter however does not currently have industry operating experience available.

Despite not having direct operating experience, gen eral industry operating experience for inverter maintenance supports the proposed extension of the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowed outage time. Previous license amendment requests for Vital AC inverter al lowed outage time were submitted by Palo Verde Nuclear Generating Station, North Anna Power Station, Clinton Power Station, and Byron and Braidwood Stations. Each request identified in verter maintenance scenarios exceeding the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time. More recent industry oper ating experience is also available demonstrating instances when 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (and in some case 7 days) was insufficient to complete inverter maintenance. Table 1 provides examples of industry operating experience supporting extension of the Completion Time from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Un availability of personnel or replacement equipment to support the repairs could extend these completion times.

Table 1: Industry Operating Experience Supporting C ompletion Time Extension Location Inverter Maintenance Description Reference North Anna Once every refueling outage the inverter s at North Anna Power ADAMS Station, Units 1 and 2, have been out of service fo r Accession No.

approximately 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for maintenance activities ML041380438 North Anna The normal preventative maintenance that occurs every six ADAMS refueling outages can typically be performed within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Accession No. ML041380438 North Anna During power operation the replacement o f a failed constant ADAMS voltage transformer, which is a component of the in verter, would Accession No.

take 5 to 7 days. ML041380438 Clinton Inverters have had an extensive history of maintenance and ADAMS operational issues since they were installed in 198 6. A review of Accession No.

the corrective maintenance and elective maintenance records ML061160181 was performed to identify work performed on Divisio n 1, 2, 3, and 4 NSPS inverters. This review indicated that 37 emergent

Page 8 of 27 ND-22-xxxx Enclosure Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

Location Inverter Maintenance Description Reference work activities have been completed since installat ion of the CPS NSPS inverters. The most significant failures o ccurred during refueling outages, when no generation capabi lity was lost. Of these failures, the longest duration to re pair an inverter was 174 hours0.00201 days 0.0483 hours 2.876984e-4 weeks 6.6207e-5 months (7.25 days). This occurred in August 1998 during CPS's extended sixth refueling outage.

Clinton There have been 7 emergent work activities completed on the ADAMS regulating transformers since they were installed b ut none of the Accession No.

failures occurred during power operation. The longe st repair ML061160181 duration was 3 days, which occurred in 1997.

Byron/Braidwood The inverters have been out-of-serv ice for approximately 2 to 3 ADAMS days during outages for maintenance activities. Accession No. ML032830455 Byron/Braidwood It is expected that additional main tenance activities will be ADAMS needed, with major rebuilds of each inverter that w ould take a Accession No.

maximum of 4 to 7 days to perform corrective mainte nance. ML032830455 Palo Verde In response to request for information, Palo Verde Nuclear ADAMS Station provided typical inverter corrective mainte nance Accession No.

schedule information which details a hypothetical i nverter ML102720481 corrective maintenance scenario and provides a post ulated timeline. The postulated timeline found that it ma y take between 5.5 days and 7.5 days to reenergize an inverter.

Millstone Unit 3 On May 4, 2019, while Millstone Unit 3 was in Mode 6 Refueling INPO IRIS Shutdown, operators received intermittent alarms co ncurrent Report No.

with a loss of Safety Related 120 Volts AC distribu tion panel 460389 (Vital Inverter AC 4 or VIAC 4). VIAC 4 swapped to its alternate source and then back to its normal alignment multip le times and was declared inoperable. Troubleshooting identified visible degradation and measured a temperature gradient on a fuse block for the main fuses of the distribution panel on the output of the inverter. The distribution panel was de-energi zed and the degraded fuse block and associated fuses were repla ced. The affected distribution panel was restored and the in verter was restored to operable on May 6, 2019. There was no impact to the outage schedule Salem Unit 2 On April 02, 2018, the Control Room received an Ove r Head INPO IRIS alarm identifying the Vital Instrument Bus Inverter Failure. A Report No.

walkdown discovered that the inverter temporarily s wapped from 436327 primary to alternate source (unlatched transfer) wi th no abnormal conditions noted. Operators manually tran sferred the load to the AC Line Regulator. Maintenance entered complex troubleshooting and upon adjustment of a tuning pot entiometer, a fuse was identified to be blown, which is charact eristic of a faulty Modulation Index Control (MIC) card. The MI C card was replaced and the inverter was restored on April 04, 2018.

Page 9 of 27 ND-22-xxxx Enclosure Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

Risk Management Measures

The VEGP Units 3&4 Maintenance Rule program monitor s the reliability and availability of the IDS inverters and confirms that appropriate managem ent attention and goal setting are applied based on pre-established performance criteria. The VEGP Units 3&4 configuration risk management program (CRMP) is consistent with 10 CFR 50.64(a)(4) (Maintenance Rule) and is managed to prevent entering risk-significant plant configurations for planned maintenance activities, and to take appropriate actions should unforeseen events place the plant in a risk-significant configuration during the IDS inverter C ompletion Time.

Planned maintenance is screened for impacts related to nuclear safety. Examples include consideration of maintenance that results in entry into Technical Specifications Required Action Statements, inability to control a critical safety function (e.g., power to Class 1E instrument and control power buses), and inability to perform an E mergency Operating Procedure. Planned maintenance also bundles work to minimize plant ris k and to minimize out of service time.

Operations is the final authority for determining i f work is done on-line or in an outage.

Operational Risk Awareness procedures also screen e mergent, as well as planned maintenance.

These activities are classified as either medium or high risk. The associated risk management plans identify work activities that pose risk to pe rsonnel, plant equipment, or the environment are clearly identified, and an appropriate mitigation p lan(s) developed to minimize or eliminate the likelihood of an unacceptable event.

10 CFR 50.65 requires that preventive maintenance a ctivities must be sufficient to provide reasonable assurance that SSCs are capable of fulfi lling their intended functions. As it pertains to the proposed IDS inverter Completion Time extens ion, 10 CFR 50.65(a)(4) requires the assessment and management of the increase in risk t hat result from proposed maintenance activities. The VEGP Units 3&4 Maintenance Rule pr ogram monitors the reliability and availability of the IDS inverters and confirms that appropriate management attention and goal setting are applied based on pre-established performance criter ia. The VEGP Units 3&4 configuration risk management program (CRMP) is consistent with 10 CFR 50.64(a)(4) (Maintenance Rule) and is managed to prevent entering risk-significant plant configurations for planned maintenance activities, and to take appropriate actions should unforeseen events place the plant in a risk-significant configuration during the extended IDS i nverter Completion Time. Therefore, the proposed extension of the vital AC inverter Complet ion Time from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days, and the planned vital AC inverter on-line maintenance that this extension will permit, are not anticipated to result in exceeding the current established Main tenance Rule criteria for the IDS inverters.

Probabilistic Risk Assessment

Regulatory Guide 1.177 provides guidance for both p ermanent and one-time only Completion Time changes to Technical Specifications. This gui dance was used to assess the impact of a permanent Completion Time extension from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months t o 14 days.

Based on Guidance from Regulatory Guide 1.177, an I ncremental Conditional Core Damage Probability (ICCDP) of less than 1.0E-06 is conside red a small quantitative impact on plant risk.

An Incremental Conditional Large Early Release Prob ability (ICLERP) of less than 1.0E-07 is also considered a small quantitative impact on plant ris k. Plant risk assuming a single IDS inverter is

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inoperable and assuming both IDS inverters in the s ame division are unavailable (limited to Division B and C) for 14 days has been estimated to demonstrate that the quantitative impact is small, based on the Regulatory Guide 1.177 threshol ds.

Table 2 outlines the basic events associated with t he IDS inverters that are explicitly addressed within the PRA Model. Note that the PRA only addres ses failures of the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months battery banks to support the indication and control function of the IDS batteries. The 72-hour battery banks provide longer term indications (e.g., PAMS) and other supp ort functions. The PAMS function is not explicitly addressed or credited to mitigate CDF or LERF in the PRA model. The 72-hour battery banks have limited credit in the PRA. This includes power supports for the 120 VAC UPS distribution panel IDSB-EA-3 (supported by inverter APP-IDSB-DU-2) and the AC UPS distribution panel IDSC-EA-3 (supported by inverter APP-IDSC-DU-2) electric power dependencies are included in the PRA if the identif ied PRA equipment requires power for the given PRA function. The electric power dependency is then addressed in the model based on the associated distribution panel/bus identified by the electrical load list.

The IDS inverters static switch is an important com ponent that adds to the reliability of the UPS and, as such, is modeled separately from the invert er. If an inverter is inoperable or the Class 1E 250 VDC input to the inverter is unavailable (i.e., the TS 3.8.3 Actions entered), the power is transferred automatically to the backup AC source b y a static transfer switch featuring a make-before-break contact arrangement. The backup power is received from normal non-Class 1E 480V AC bus through the Class 1E voltage-regulating transformer. The impact of an inoperable inverter is only explicitly addressed in the unavai lability of the inverter function. Unavailability of the inverter function is not a direct loss of I&C l oads (e.g., IDSA-EA-1). That would only occur if it was coupled with a failure of the transfer switc h or AC power supply. In the event that backup power is not supplying the instrument and control p ower bus, the TS 3.8.5 Action A applies limiting continued operation to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

Table 2: IDS Inverter Associated Basic Events Bus Component Tag Related Basic Event(s)

IDSA Inverter APP-IDSA-DU-1 IDS-INV-FOP-DU1/A Transfer Switch APP-IDSA-DU-1 IDS-ABT-FOP-DU1STS/A

Inverter APP -IDSB -DU -1 IDS -INV -FOP -DU1/B IDSB Inverter APP-IDSB-DU-2 IDS-INV-FOP-DU2/B Transfer Switch APP-IDSB-DU-1 IDS-ABT-FOP-DU1STS/B Transfer Switch APP-IDSB-DU-2 IDS-ABT-FOP-DU2STS/B Inverter APP-IDSC-DU-1 DS-INV-FOP-DU1/C IDSC Inverter APP-IDSC-DU-2 IDS-INV-FOP-DU2/C Transfer Switch APP-IDSC-DU-1 IDS-ABT-FOP-DU1STS/C Transfer Switch APP-IDSC-DU-2 IDS-ABT-FOP-DU2STS/C IDSD Inverter APP-IDSD-DU-1 IDS-INV-FOP-DU1/D Transfer Switch APP-IDSD-DU-1 IDS-ABT-FOP-DU1STS/D

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The estimated risk impacts are generated by setting the representative events to true in the associated internal events or hazards baseline resu lts cutset file post-processing. Table 3 outlines the baseline cutset files and associated b aseline frequencies for the at-power Vogtle Units 3 and 4 PRA.

Table 3 : Baseline CDF and LERF Results Hazards Result Baseline CDF & LERF Cutset File Freq uency (per reactor year)

Internal CDF CDF-ALL.CUT 3.94E-07 Events LERF L2 -ALL -LERF.CUT 3.83E -08 Internal CDF CDF-ALL_E-14.CUT 2.17E-07 Flooding LERF L2 -ALL -LERF_E -14.CUT 8.40E -08

Internal Fire CDF CDF_1E-14.GROUP.CUT 8.54E-07 LERF LERF_5E-15.GROUP.CUT 3.37E-07(1)

Seismic CDF ALL-SCENARIOS-CDF.CUT 9.30E-08 (2) LERF ALL-SCENARIOS-LERF.CUT 5.16E-08(2)

Notes:

(1) Result based on the FRANX results for truncation le vel of 1E-15. The grouped cutset file for Internal Fire LERF was limited to 5E-15 truncation due to computing limitation. The Fire LERF value of 3.37E-07/reactor year is used for this ass essment based on the 5E-15 truncation results. Given the small difference between the 1E-15 and 5E -15 LERF values (~5E-09) this small difference is not anticipated to have any not able impact the ICLERP assessment results.

(2) All results are based on the CAFTA Minimal Cutset U pper Bound (MCUB) results and not the ACUBE post processing results.

Based on the results in Table 3, the total baseline CDF is 1.56E-06 and the total baseline LERF is 5.11E-07. The baseline cutset files outlined in Table 3 are used to support the conditional CDF and LERF values for each of the inverter basic even ts presented in Table 2. The results of this evaluation are outlined in Table 4. Each inverter basic event identified in the representative event column was set to true to obtain the corresponding conditional CDF and LERF. Conditional values were obtained for each inverter individually and tw o cases were assessed with both inverters in the same division set to true at the same time (lim ited to Division B and C.)

The estimated risk impacts are generated by setting the representative events to true in the associated hazards baseline results cutset file pos t-processing, utilizing the baseline truncation values. This was selected over re-quantification d ue to the computing limitation associated with FRANX (used to quantify fire and seismic) and the l arge cutset file generated to support the LERF results. The impact of the representative basic ev ent(s) set to true was observed in each of the total conditional CDF and LERF resulting values whe n compared to individual hazard results where impact may not be observed due to the represe ntative basic event(s) not being in the baseline cutset file (below truncation). These sub set of cases with the representative basic event(s) not in the baseline cutset file (below tru ncation) are identified in bold text in Table 4. T his

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treatment is deemed sufficient, and impact is antic ipated to be negligible since impact is observed in the total conditional CDF and LERF values for ea ch inverter case and representative basic event(s) not in the baseline cutset file (below tru ncation) is an indication of lower importance to CDF and LERF.

Table 5 utilizes the conditional CDF and LERF value s from Table 4 to assess the impact of different Completion Times. The resulting ICCDP an d ICLERP are calculated on a per entry basis, with the TS entry duration being the full pr oposed duration of the allowed Completion Time identified for each column.

The final baseline seismic CDF and LERF results wer e based on the ACUBE post-processing results over the CAFTA MCUB results utilized for th e conditional CDF and LERF values and baseline values in Tables 4 and 3. Utilizing the M CUB results over the ACUBE results is anticipated to have no meaningful impact on the res ulting ICCDP and ICLERP values since the delta from the condition CDF and LERF values to the baseline values CDF and LERF values are small (less than 6E-8/year for CDF and less than 5E -9/year for LERF) when compared to the other hazard groups.

Risk impact was assessed using the VEGP 3&4 specifi c PRA. Impacts on other external hazards and low power or shutdown operation were qualitativ ely assessed and described in further detail below. There is a small quantitative impact on pla nt risk due to the extension of the IDS Inverter extended Completion Time as shown above in Table 5. Note that, the 30-day Completion Time results shown above in Table 5 also indicate a smal l quantitative impact on plant risk providing additional confidence in the minimal impact at a 14 -day Completion Time. Therefore, it is concluded that increasing the Completion Time for a n IDS inverter from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days meets the acceptance guidelines of RG 1.177.

Consideration of Impact on External Hazards

Based on the conclusions of the at-power External H azards Assessment, the identified external hazards (excluding Internal Flooding, Seismic, and Internal Fire) were screened out. Qualitative and quantitative screening of external hazards was performed consistent with the requirements of ASME/ANS-RA-Sa 2009, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Application s for this external events analysis. These assessments conclude that other external hazards ar e individually screened with CDFs between 1E-09 per year to approximately 1E-14 per year. Ex tension of the IDS TS Completion Time from the current 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days increases the singl e component outage risk associated CDP due to other (i.e., screened external hazards) to the range of 2E-11 to 2E-16 per entry. Given the low probability (contribution) of other external hazards they may be screened from the impact for this test Interval extension. These contributi ons are insignificant, particularly when compared to the impact on Internal Events, Internal Flooding, Internal Fire and Seismic.

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ND-22-xxxx Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

Consideration of Impact During Low Power and Shutdo wn

TS 3.8.3 Action A is applicable from Mode 1 through Mode 4. As the plant configuration is the same for Modes 1 through 3 with minor exceptions, t he insights from at-power PRA are applicable for Modes 1, 2 and 3. The primary differences amon g these modes from at-power operation (Mode 1) is that Mode 2 limits power operation to 5% and that the Mode 3 configuration has control rods inserted with potentially lower plant temperatures/pressures. Therefore, Mode 3 is not subject to anticipated transients without scram (ATWS) and would likely have lower loss of coolant accident (LOCA) frequencies and lower decay heat conditions. As a result, should an initiating event occur, the initial conditions of l ower power and decay heat in Mode 2 and Mode 3 that result in initiating events that provide more time for operator responses.

Mode 4 maintains the plant in hot shutdown with an intact RCS. During Mode 4 operation, prior to placing Normal Residual Heat Removal System (RNS ) in service, the plant decay heat removal defenses are not reduced when compared to the at-po wer level of defenses. For example, steam generators (SGs), passive residual heat removal and in-containment refueling water storage tank (injection and passive recirculation cooling method s are available to support decay heat removal.

Therefore, in lieu of developing quantitative impac ts, it is conservative to use the at-power PRA model to bound the risk impact of Mode 4 operation prior to placing RNS in service.

During Mode 4 operation with RNS in service, the pl ant has the same safety-related decay heat removal defense as Mode 1, as well as the non-safet y related steam generators providing decay heat removal. Core Makeup Tanks (CMTs), Passive Re sidual Heat Removal Heat Exchanger (PRHR HX), and In-Containment Refueling Water Stora ge Tank (IRWST) injection/passive recirculation cooling methods continue to be availa ble during Mode 4 regardless of RNS providing decay heat removal.

In the event that RNS is lost during Mode 4 operati on with RNS in service, the operators utilize the Loss of Normal Residual Heat Removal procedure to address the cause with the intent of restoring RNS for decay heat removal. If RNS canno t be restored, operators establish cooling using a secondary heat sink consisting of at least one intact SG, a means to add feedwater (main or startup feedwater pumps), and a means to dump st eam in a controlled manner. If a secondary heat sink cannot be established, then PRHR HX cooli ng is initiated. If no means of RCS cooling can be established, then passive feed and bleed is established by actuation of Safeguards and transitioning to the Emergency Operation Procedures. Unless a heat sink is established that directs reactor decay heat outside containment usin g the RNS system or a SG, the PRHR HX is used to transfer heat to the IRWST. Heat is then t ransferred to the containment atmosphere by allowing the IRWST to heat up and boil. The IRWST can be cooled by the spent fuel pool cooling system if available. Potential actions to cool the containment atmosphere include operation of the containment fan coolers.

Additionally, lines of defense that are independent from IDS are available. This includes DAS actuation of PRHR and IRWST injection/passive recir culation cooling. RNS operation is also independent from IDS after RNS is placed in service.

Also, as discussed in UFSAR Section 17.4 risk signi ficant non-safety systems, structures, and components (including RNS as shown in UFSAR Table 1 7.4-1) are included in the Operational

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Phase Reliability Assurance Activities. These reli ability assurance and investment protection programs include:

Maintenance Rule Program Quality Assurance Program Inservice Testing Program Inservice Inspection Programs Investment Protection Short Term Availability Cont rol Site Maintenance Program

There is no change to the Regulatory Treatment of N on-Safety Systems evaluation as a result of the risk impact estimates for the proposed changes to TS 3.8.3.

Safety-related normal decay heat removal is provide d by the Passive Core Cooling System (PXS).

The requirements for Mode 4 operation of the PXS ar e provided in TS Section 3.5, Passive Core Cooling System. Specifically, TS 3.5.3, CMTs - Sh utdown, RCS Intact, and TS 3.5.5, PRHR HX - Shutdown, RCS Intact, address the PXS compone nt operability required when in Mode 4 with the RCS cooling provided by the RNS to provide the availability of safety-related decay heat removal in the event RNS is lost. TS 3.5.6, IRWST - Operating, addresses the operability requirements for the IRWST in Mode 4.

The multiple lines of defense that are independent from IDS and the longer time window available for recovery typically observed during lower mode o peration, the contribution of the lower power and shutdown modes are judged to be very small comp ared to the at-power PRA risks and does not impact the assessment of overall risk insights.

Status of Vogtle AP1000 Plant PRA

VEGP Unit 3&4 COL condition 2.D(12)(g)6 requires a review of the differences between the as-built plant and the design used as the basis for th e AP1000 seismic margin analysis, including verification walkdowns, evaluation of differences, seismic margin analysis, and high confidence, low probability of failures (HCLPFs) evaluations. VEGP Units 3&4 COL condition 2.D(12)(g)8 requires a review of the differences between the as -built plant and the design used as the basis for the AP1000 internal fire and internal flood ana lysis. The differences between the plant-specific PRA-based insights and the design for internal fire and internal flood have been evaluated.

Each of these activities is complete and satisfied based on the as-built activities for VEGP Unit 3 and assumed to be representative of VEGP Unit 4 sin ce each activity must also be complete for Vogtle Unit 4 to satisfy the COL Conditions. Any s ignificant deviations at that time must be reconciled to complete the COL Conditions for Unit 4.

The plant specific PRA model has been modified as n ecessary to account for the plant-specific design and any design changes or departures from th e design certified in Revision 19 of the AP1000 Design Certification Document. None of the plant-specific differences identified during performance of walkdowns or model changes as a resu lt of design changes resulted in changes to the risk insights from the VEGP Unit 3 PRA. No model changes as a result of design changes have resulted in changes to risk insights from the VEGP Unit 4 PRA.

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The CDF and LERF are calculated for internal events. Selected internal hazard events are also quantitatively assessed to derive plant insights an d plant risk conclusions. Seismic events are assessed using a detailed site-specific PRA approac h. Other external hazards are evaluated with a qualitative approach.

The models have been updated to reflect plant-speci fic design and as-built conditions following standards and methodologies applicable to preparing a PRA model for operations including:

ASME/ANS-RA-Sa 2009, Standard for Level 1/Large E arly Release Frequency Probabilistic Risk Assessment for Nuclear Power Pla nt Applications, American Society of Mechanical Engineers.

US NRC Regulatory Guide 1.200, An Approach for De termining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk I nformed Activities, Revision 2.

NUREG/CR-6928, Industry-Average Performance for C omponents and Initiating Events at U.S. Commercial Nuclear Power Plants.

EPRI 1019194, Guidelines for Performance of Inter nal Flooding Probabilistic Risk Assessment, Electric Power Research Institute.

US NRC NUREG/CR-6850, EPRI/NRC-RES Fire PRA Metho dology for Nuclear Power Facilities.

ANSI/ANS 58.21-2007, External Events PRA Methodol ogy.

The models have been peer reviewed following approp riate guidance including:

NEI 00-02, Probabilistic Risk Assessment (PRA) Pee r Review Process Guidance.

NEI 05-04, Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard.

NEI 07-12, Fire Probabilistic Risk Assessment (FPR A) Peer Review Process Guidelines.

NEI 12-13, External Hazards PRA Peer Review Proce ss Guidelines.

EPRI 3002012994, Seismic Fragility and Seismic Ma rgin Guidance for Seismic Probabilistic Risk Assessment, September 2018

Therefore, the technical adequacy of the VEGP site-specific PRA, and the risk evaluations performed to support this proposed change, are suff icient to provide confidence in the results such that the PRA can be used in regulatory decisio n-making.

Status of Unit 3 Walkdown

Walkdowns have been performed that confirm the assu mptions used in the PRA represent the Vogtle Unit 3 as-built plant conditions. The walkd own teams followed industry guidance outlined in walkdown notebooks. Walkdowns of the plant were conducted in the August 2020 to April 2021 timeframe when the plant construction was approxima tely 98% complete. Results of these walkdowns, including as-built observations, are doc umented in walkdown notebooks. Since the plant construction was not complete at the time of the walkdowns, as-found conditions were evaluated for potential risk-significance and deter mination of if necessary for incorporation into the models. Results of the as-built walkdown evalu ations and observations were incorporated into the plant-specific PRA models as necessary. O bservations identified with potential risk-significant impact to the PRA were incorporated int o the model, while observations and as-found

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conditions identified with low impact (not risk sig nificant) were dispositioned and are tracked via the model maintenance process for future incorporat ion.

None of the plant-specific differences identified d uring performance of walkdowns or model changes as a result of design changes resulted in c hanges to the risk insights from the Vogtle Unit 3 PRA or a risk-significant impact to the Vogt le Unit 3 PRA. The walkdown observations and walkdown open items were reviewed. No walkdown obs ervations or walkdown open items were identified for possible impact to this application.

PRA Maintenance and Update Procedure

The Vogtle Units 3&4 PRA model reflects the design reference point of August 2018 (model freeze date). The changes to the design up to the model freeze date for the Vogtle Unit 3 have been incorporated in the PRA model. For the design changes or departures from the certified design that would have occurred after August 2018, a model maintenance process was used to identify, collect, and screen them for any necessar y model update. Subsequent design changes were reviewed for possible impact on this applicati on. No design changes were identified for possible impact to this application.

Review of Self-Assessment

A self-assessment was performed against Part 2 of A SME/ANS RA-Sa-2009 for Internal Events, Internal Flooding, Internal Fire, Seismic, and Exte rnal Events. Due to the pre-operational /

construction stage of the plant at the time of the self-assessment, some of the Supporting Requirements (SRs) were marked as Met Intent, Not Achievable. No internal events SR is identified for possible impact to this application.

LOOP Sensitivity

LOOP was identified as a potential source of uncert ainty impacting this application. A sensitivity study was performed by reducing the LOOP frequency in the base and condition cases for internal events.

The VEGP Units 3&4 Internal Events PRA conservative ly assumes no recovery from LOOP. A sensitivity was performed by decreasing the LOOP in itiating event frequency by 50%. The baseline values (CDF and LERF) and conditional CDF and LERF values for IDS-INV-FOP-DU1/B

& IDS-INV-FOP-DU2/B were generated to assess the im pact of this assumption for this application. This sensitivity is limited to intern al events since no credit or limited credit for LOO P recovery would be expected during an internal flood, internal fire or seismic events. For example, no credit for equipment recovery is included for fi re-induced and flood-induced loss of Electric Power Distribution System equipment leading to a LO OP. Conditional CDF and LERF values for IDS-INV-FOP-DU1/B & IDS-INV-FOP-DU2/B were selected for the sensitivity since they have the largest delta risk from Table 4.

The loss of offsite power initiating event frequenc y is currently 3.59E-02/per reactor year. To estimate the potential impact of crediting loss of offsite power recovery the offsite power initiating event frequency was reduced by 50% resulting in an updated LOOP frequency of 1.80E-02/per

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reactor year. LOOP frequency was updated from its baseline frequency 3.59E-02 to the revised sensitivity value of 1.80E-02.

The baseline CDF and LERF values in Table 6 are d irectly from Table 3. The Baseline + LOOP Update results utilized the baseline cutset files CDF-ALL.CUT and L2-ALL-LERF.CUT from Table 3. The LOOP frequency (%LOOP) was then update d to 1.80E-02/per reactor operating state year in the cutset file. The updated CDF and LERF results are then presented in Table 6.

As expected, a small decrease in CDF and LERF resul ts is observed.

Table 6: Internal Events Baseline Cases

Baseline Case CDF LERF

Baseline (From Table 3) 3.94E-07 3.83E-08

Baseline + LOOP Update 3.83E-07 3.59E-08

The IDS-INV-FOP-DU1/B & IDS-INV-FOP-DU2/B Baseline (from Table 4) Conditional CDF and LERF values in Table 7 below are directly from Tabl e 4. The IDS-INV-FOP-DU1/B & IDS-INV-FOP-DU2/B + LOOP Update results utilized the cutse t files CDF-ALL-IDS-INV-FOP-DU1_B_and_IDS-INV-FOP-DU2_B - LOOP.cut and L2-ALL-L ERF-IDS-INV-FOP-DU2_B -

LOOP.CUT that support the conditional results in Ta ble 4. The LOOP frequency was then updated to 1.80E-02 per reactor operating state year in eac h cutset file. The updated conditional CDF and LERF results are presented in Table 7. The CCDF and CLERF values were calculated by subtracting the baseline value (Table 6) from the c orresponding conditional value. The resulting CCDF and CLERF values in Table 7 demonstrate that t his assumption is conservative for this application.

Table 7: Conditional CDF and LERF Results for At-Po wer Internal Events and Hazards

Internal Events CCDF and CLERF

Sensitivity Conditional Conditional Conditional CCDF CLERF Case CDF LERF (Conditional (Conditional

-Baseline) - Baseline)

IDS-INV-FOP-DU1/B &

IDS-INV-FOP-DU2/B Baseline (from Table 4) 1.33E-06 1.10E-07 9.36E-07 7.17E-08

IDS-INV-FOP-DU1/B &

IDS-INV-FOP-DU2/B +

LOOP Update 9.35E-07 7.49E-08 5.52E-07 3.90E-08

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The results indicate that the current treatment of LOOP recovery in the PRA model is conservative for this application.

RAW Value of Unavailability Basic Events Comparison

A review of the unavailable basic events with risk assessment worth (RAW) for the conditional internal events CDF and LERF results. They are the n compared to the baseline results RAW values. The risk-significant unavailable basic eve nts with a notable increase in RAW, identified during this review, each support the backup sources to the Class 1E AC instrument and control buses. Cutset reviews were performed for the cutse ts containing the identified risk-significant unavailable basic events with a notable increase in RAW. The cutset reviews of the unavailable basic events with a notable RAW increase all includ ed an initiating event independent from one inverter division being unavailable, coupled with a system failure independent from IDS or two systems independent from IDS and each other. This demonstrates that DID is maintained for events with one inverter division being unavailable, and therefore demonstrates that no additional compensatory measures (beyond the current procedura lly controlled risk management plans and Maintenance Rule program) are necessary.

4 REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria A review of the pertinent regulations and industry guidance was performed and found that compliance with 10 CFR Sections 50.36, 50.63, 50.65, Part 50 Appendix A General Design Criteria (GDC) 17, 18, and Regulatory Guides (RGs) 1.174 and 1.177 is maintained by extending the IDS Inverter Completion Time from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days. A description of the pertinent requirements and guida nce as well as a disposition for continued compliance are provided below.

10 CFR Section 50.36, Technical Specifications 10 CFR 50.36 requires that operating licenses for n uclear reactors must include TS that specify LCOs for equipment required for safe operat ion. The proposed change in the IDS Inverter Completion Time has no impact on the c ontinued conformance with the requirements of 10 CFR 50.36. Specifically, the in verters are part of the electrical power distribution systems, and as such, satisfy criterio n 3 of 10 CFR 50.36(c)(2)(ii). The distribution system for which the inverters are inc luded, are a primary success path, and function or actuate to mitigate a design basis acci dent or transient that either assumes the failure of or presents a challenge to the integ rity of a fission product barrier and continues to perform as intended and consistent wit h the accident analyses.

10 CFR 50, Appendix A, GDC 17 - Electrical Power S ystems GDC 17 requires, in part, that nuclear power plants have onsite and offsite electric power systems to permit the functions of SSCs that are im portant to safety. The onsite system must have sufficient independence, redundancy, and testability to perform its safety function, assuming a single failure. The offsite p ower system must be supplied by two

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physically independent circuits that are designed a nd located so as to minimize, to the extent practical the likelihood of their simultaneo us failure under operating and postulated accident and environmental conditions. In addition, this criterion requires provisions to minimize the probability of losing el ectric power from the remaining electric power supplies as a result of a loss of power from the unit, the offsite transmission network, or the onsite power supplies. The propose d change continues to provide sufficient independence, redundancy, and testabilit y, and minimizes the probability of losing power as a result of a loss of power from th e unit, the offsite transmission network, or the onsite power supplies.

The VEGP Units 3&4 plant design continues to provid e appropriate electrical systems and Defense-in-Depth (DID) to permit functioning of plant SSCs during all plant states.

These systems include:

o Normal power supply system Normal source (AC power from Turbine Generator)

The normal ac power supply to the main ac power sy stem is provided from the station main generator.

o Off-site power supply system Preferred source (AC power from grid)

When the main generator is not available, plant au xiliary power is provided from the switchyard by backfeeding through the main stepup and unit auxiliary transformers.

Secondary/Maintenance source (AC Power from grid)

When neither the normal or the preferred power sup ply is available due to an electrical fault, fast bus transfer is initiated to transfer the loads to the reserve auxiliary transformers powered by maintenan ce sources of power o Emergency electric power system Battery source, from Class 1E DC and UPS power sys tems.

The VEGP Units 3&4 plants also have the following a dditional power sources: non-Class 1E DC and UPS power system, non-Class 1E onsite sta ndby diesel generator system, and the non-Class 1E ancillary diesel generator.

The safety-related IDS batteries continue to provid e the necessary electrical power for the safety-related valves and instrumentation credi ted for design basis events. There are no changes to other plant electrical systems or the DID design. Therefore, implementation of the proposed Completion Time exte nsion will have no impact on the VEGP Units 3&4 GDC 17 licensing basis.

10 CFR 50, Appendix A, GDC 18, Inspection and Test ing of Electric Power Systems, GDC 18 requires that electric power systems that ar e important to safety must be designed to permit appropriate periodic inspection and testing. The extended IDS Inverter Completion Time from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days d oes not impact the testing or inspection of the inverters. Therefore, implementa tion of the proposed Completion Time extension will have no impact on the VEGP Units 3&4 GDC 18 licensing basis.

Page 21 of 27 ND-22-xxxx Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

10 CFR Section 50.63, Loss of All Alternating Curr ent Power 10 CFR Section 50.63 requires that nuclear power pl ants must be able to withstand a loss of all AC power for an established period of t ime and recover from a station blackout.

During a loss of all AC power sources including the on-site standby diesel generators, the IDS provides power from the IDS batteries witho ut interruption for a period of 24 and 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to the required safety-related loads.

Divisions A and D battery banks and one of the batt ery banks in Divisions B and C are designated as 24-hour battery banks (two 60-cell st rings in series) and provide power to the loads required for the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months following a loss of all AC power event or a DBA.

The second battery bank in Divisions B and C, desig nated as the 72-hour battery bank (two 60-cell strings in series) is used for those l oads requiring power for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months following the same event. A spare battery bank wit h spare battery charger is provided for the Class 1E DC and UPS system. The voltage-re gulating transformers provide the availability of AC power to the UPS loads in case o f failure or unavailability of the inverters.

Including the extended IDS Inverter Completion Time from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days, the IDS continues to provide sufficient levels of redundanc y and DID to provide the necessary electrical power for the safety-related valves and instrumentation credited for design basis events. Therefore, the proposed extension of the IDS Inverter Completion time from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days has no significant impact on the ability to withstand a loss of all AC power and recover from a station blackout.

10 CFR 50.65, Requirements for monitoring the effec tiveness of maintenance at nuclear power plants 10 CFR 50.65 requires that preventive maintenance a ctivities must be sufficient to provide reasonable assurance that SSCs are capable of fulfilling their intended functions.

As it pertains to the proposed IDS inverter Complet ion Time extension, 10 CFR 50.65(a)(4) requires the assessment and management of the increase in risk that result from proposed maintenance activities. The VEGP Uni ts 3&4 Maintenance Rule program monitors the reliability and availability of the ID S inverters and confirms that appropriate management attention and goal setting are applied b ased on pre-established performance criteria. The VEGP Units 3&4 configura tion risk management program (CRMP) is consistent with 10 CFR 50.64(a)(4) (Maint enance Rule) and is managed to prevent entering risk-significant plant configurati ons for planned maintenance activities, and to take appropriate actions should unforeseen e vents place the plant in a risk-significant configuration during the extended IDS i nverter Completion Time. Therefore, the proposed extension of the vital AC inverter Com pletion Time from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days, and the planned vital AC inverter on-line maintenance that this extension will permit, are not anticipated to result in exceeding the current established Maintenance Rule criteria for the IDS inverters.

Page 22 of 27 ND-22-xxxx Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

Regulatory Guides (RG)

RG 1.177states that a risk-informed application sho uld be evaluated to confirm that the proposed change meet the following five key princip les:

1) The proposed change meets the current regulation s unless it is explicitly related to a requested exemption, i.e., a "specific exemption" under 10 CFR 50.12.

2) The proposed change is consistent with the DID p hilosophy.

3) The proposed change maintains sufficient safety margins.

4) When proposed changes result in an increase in C DF or risk, the increases should be small and consistent with the intent of the Comm issions Safety Goal Policy Statement.

5) The impact of the proposed change should be moni tored using performance measurement strategies.

The NRCs safety Goal Policy Statement and PRA Poli cy Statement are implemented in part via RG 1.174, An Approach for Using Probabili stic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis and RG 1.177, "An Approach for Plant-Specific, Risk-Informed Deci sionmaking: Technical Specifications". RG 1.174 describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed lic ensing basis changes by considering engineering issues and applying risk insights. RG 1.177 identifies an acceptable risk-informed approach, including additional guidance ge ared toward the assessment of proposed TS Completion Time changes.

RG 1.200, "An Approach For Determining The Technica l Adequacy Of Probabilistic Risk Assessment Results For Risk-Informed Activities," R evision 2, provide guidance to licensees for use in determining the technical adeq uacy of the base PRA used in a risk-informed regulatory activity. RG 1.200 endorses st andards and industry guidance that address risk-informed activities and is a supportin g document to other NRC regulatory guides that address risk-informed activities, inclu ding RG 1.174 and RG 1.177 described above. The VEGP Units 3&4 Probabilistic Risk Asses sment has been developed in accordance with Regulatory Guide 1.200 Revision 2 a nd the endorsed standards and industry guidance, and therefore is adequate for us e in risk-informed regulatory activity.

The VEGP Units 3&4 assessment of potential risk imp acts associated with the IDS Inverter Completion Time extension from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days was performed in a manner consistent with the guidance and criteria described above. This assessment confirms that applicable regulatory requirements continue to be met, adequate DID is maintained, sufficient safety margins are maintained, and any i ncrease in risk is small and consistent with the NRC's Safety Goal Policy Statement. The I CCDP and ICLERP for each IDS Inverter meet the regulatory guidelines such that t he impact on plant risk is considered small.

Page 23 of 27 ND-22-xxxx Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

The risk impact of the extended IDS Inverter Comple tion Time from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 14 days as estimated by ICCDP and ICLERP, is consistent wit h the acceptance guidelines specified in RG 1.174 and RG 1.177.

4.2 Precedents Byron & Braidwood, Units 1 and 2, Package, Re Comp letion Time from 24 Hours to 7 Days for One Inoperable Instrument Bus Inverter, dated November 19, 2003

[ML032830455]

North Anna, Units 1 and 2, License Amendments 235 & 217 regarding Extended Inverter Allowed Outage Time, dated May 12, 2004 [M L041380438]

Clinton, License Amendment, TS Change to Extend Co mpletion Time for Nuclear System Protection System Inverters, dated May 26, 2 006 [ML061160181]

Palo Verde, Units 1, 2, and 3 - Issuance of Amendm ent Nos. 180, 180, and 180, Revise TS 3.8.7, "Inverters - Operating," to Extend Completion Time for Restoration of an Inoperable Inverter (TAC Nos. ME2337, ME2338, and ME2339), dated September 29, 2010 [ML102670352]

4.3 Significant Hazards Consideration Southern Nuclear Operating Company (SNC) is request ing an amendment to Combined License (COL) Nos. NPF-91 and NPF-92 for Vogtle Ele ctric Generating Plant (VEGP)

Units 3 and 4, respectively. The license amendment request (LAR) proposes changes to COL Appendix A, Technical Specifications (TS) 3. 8.3, Inverters - Operating, to extend the Completion time for restoring the inoperability of one or two inverters one division to 14 days. An additional editorial change corrects t he spelling of Required in TS 3.3.9, Engineered Safety Feature Actuation System (ESFAS) Manual Initiation, Condition C.

4.3.1 Does the proposed amendment involve a signifi cant increase in the probability or consequences of an accident previous ly evaluated?

Response: No.

The proposed changes do not adversely affect the op eration of any structures, systems, or components (SSCs) associated with an ac cident initiator or initiating sequence of events. The proposed change does not a ffect the design of the vital AC inverters, the operational characteristics or fu nction of the inverters, the interfaces between the inverters and other plant sy stems, or the reliability of the inverters. An inoperable vital AC inverter is not considered an initiator of an analyzed event. In addition, Required Actions and the associated Completion Times are not initiators of previously evaluated ac cidents. Extending the Completion Time for an inoperable vital AC inverter would not have a significant impact on the frequency of occurrence of an acciden t previously evaluated.

The proposed changes continue to maintain the initi al conditions and operating limits assumed during normal operation, assumed by the accident analysis, and assumed in anticipated operational occurrences. Th erefore, the proposed changes do not result in any increase in probabilit y of an analyzed accident occurring.

Page 24 of 27 ND-22-xxxx Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

The proposed changes do not involve a change to any mitigation sequence or the predicted radiological releases due to postulated a ccident conditions. Thus, the consequences of the accidents previously evaluated are not adversely affected.

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

4.3.2 Does the proposed amendment create the possib ility of a new or different kind of accident from any accident previously evalu ated?

Response: No.

The proposed changes do not involve physical altera tion, and do not impact the required functional capability of the safety system s for previously evaluated accidents and anticipated operational occurrences. No new equipment is being introduced, and installed equipment is not being op erated in a new or different manner. The proposed revisions do not change the f unction of the related systems, and thus, the changes do not introduce a n ew failure mode, malfunction or sequence of events that could adversely affect s afety or safety-related equipment.

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

4.3.3 Does the proposed amendment involve a signifi cant reduction in a margin of safety?

Response: No.

Margins of safety are established in the design of components, the configuration of components to meet certain performance parameter s, and in the establishment of setpoints to initiate alarms or actions. The pr oposed amendment does not alter the design or configuration of the vital AC inverte rs. The proposed changes continue to provide the required functional capabil ity of the safety systems for previously evaluated accidents and anticipated oper ational occurrences. The proposed changes do not change the function of the related systems nor significantly affect the margins provided by the sy stems. No safety analysis or design basis acceptance limit/criterion is challeng ed or exceeded by the requested changes. Applicable regulatory requirements will c ontinue to be met, adequate defense-in-depth will be maintained, sufficient saf ety margins will be maintained, and any increases in risk are consistent with the N RC Safety Goals.

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

Based on the above, it is concluded that the propos ed amendment does not involve a significant hazards consideration under the standar ds set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards c onsideration is justified.

Page 25 of 27 ND-22-xxxx Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

4.4 Conclusions Based on the considerations discussed above, (1) th ere is reasonable assurance that the health and safety of the public will not be end angered by operation in the proposed manner, (2) such activities will be conducted in co mpliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public. Therefore, it is concluded that the requested amendment does not involve a sig nificant hazards consideration under the standards set forth in 10 CFR 50.92(c), a nd, accordingly, a finding of no significant hazards consideration is justified.

5 ENVIRONMENTAL CONSIDERATIONS The proposed changes to the Technical Specification s (TS) are described in Section 2.4 of this Enclosure.

A review has determined that the proposed changes r equire an amendment to the COL. A review of the anticipated construction and operational eff ects of the requested amendment has determined that the requested amendment meets the e ligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9), in that:

(i) There is no significant hazards consideration.

As documented in Section 4.3, Significant Hazards C onsideration, of this license amendment request, an evaluation was completed to d etermine whether or not a significant hazards consideration is involved by fo cusing on the three standards set forth in 10 CFR 50.92, Issuance of amendment. The Sign ificant Hazards Consideration evaluation determined that (1) the proposed amendme nt does not involve a significant increase in the probability or consequences of an a ccident previously evaluated; (2) the proposed amendment does not create the possibility of a new or different kind of accident from any accident previously evaluated; and (3) the proposed amendment does not involve a significant reduction in a margin of safe ty. Therefore, it is concluded that the proposed amendment does not involve a significant h azards consideration under the standards set forth in 10 CFR 50.92(c), and accordi ngly, a finding of no significant hazards consideration is justified.

(ii) There is no significant change in the types or significant increase in the amounts of any effluents that may be released offsite.

The proposed changes are unrelated to any aspect of plant construction or operation that would introduce any change to effluent types (e.g., effluents containing chemicals or biocides, sanitary system effluents, and other effl uents) or affect any plant radiological or non-radiological effluent release quantities. Furt hermore, the proposed changes do not affect any effluent release path or diminish the fu nctionality of any design or operational features that are credited with controlling the rel ease of effluents during plant operation.

Therefore, it is concluded that the proposed amendm ent does not involve a significant change in the types or a significant increase in th e amounts of any effluents that may be released offsite.

Page 26 of 27 ND-22-xxxx Request for License Amendment: Technical Specifica tion 3.8.3, Inverters - Operating, Completion Time Extension

(iii) There is no significant increase in individua l or cumulative occupational radiation exposure.

The proposed change in the requested amendment does not affect the shielding capability of, or alter any walls, floors, or other structures that provide shielding. Plant radiation zones and controls under 10 CFR 20 preclude a signi ficant increase in occupational radiation exposure. Therefore, the proposed amendm ent does not involve a significant increase in individual or cumulative occupational r adiation exposure.

Based on the above review of the proposed amendment, it has been determined that anticipated construction and operational effects of the propose d amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or ( iii) a significant increase in the individual or cumulative occupational radiation exposure. Accord ingly, the proposed amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant t o 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6 REFERENCES None.

Page 27 of 27 Vogtle Electric Generating Plant (VEGP) Units 3 and 4

License Amendment Request for Technical Specificati on 3.8.3, Inverters - Operating, Completion Time Extension

Attachment 1

Technical Specification Marked Up Pages

Insertions Denoted by Blue Underline and Deletions by Red Strikethrough Omitted text is identified by three asterisks ( * * * )

(Attachment 1 consists of three pages, including th is cover page.)

ND-22-xxxx Technical Specification Marked Up Pages

Technical Specification 3.8.3, Inverters - Operating :

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

A. One or two inverter(s) A.1 ------------------------------------

within one division - NOTE -

inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.5 Distribution Systems -

Operating with any instrument and control bus de-energized.

Restore inverter(s) to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 14 days OPERABLE status.

B. * * * * *

Page 2 of 3 ND-22-xxxx Technical Specification Marked Up Pages

Technical Specification 3.3.9, Engineered Safety Fe ature Actuation System (ESFAS)

Manual Initiation:

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

C. Requried Required * *

Action and associated Completion Time of Condition A or B not met.

OR One or more Functions with two channels inoperable.

Page 3 of 3 Vogtle Electric Generating Plant (VEGP) Units 3 and 4

License Amendment Request for Technical Specificati on 3.8.3, Inverters - Operating, Completion Time Extension

Attachment 2

Technical Specification Revised Pages

(Attachment 2 consists of three pages, including th is cover page.)

Technical Specifications ESFAS Manual Initiation 3.3.9

ACTI ONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

C. Required Action and C.1 Enter the Condition Immediately associated Completion referenced in Table 3.3.9-1 Time of Condition A or for the channel(s).

B not met.

OR

One or more Functions with two channels inoperable.

D. As required by D.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action C.1 and referenced in AND Table 3.3.9-1. D.2 Be in MODE 4 with the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

Reactor Coolant System (RCS) cooling provided by the Normal Residual Heat Removal System (RNS).

E. As required by E.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action C.1 and referenced in AND Table 3.3.9-1.

E.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

F. As required by F.1 Declare affected isolation Immediately Required Action C.1 valve(s) inoperable.

and referenced in Table 3.3.9-1.

G. As required by G.1 Be in MODE 5. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Required Action C.1 and referenced in AND Table 3.3.9-1.

G.2 Initiate action to establish 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months RCS VENTED.

VEGP Units 3 and 4 3.3.9 - 2 Amendment No. ___ (Uni t 3)

Amendment No. ___ (Unit 4)

Technical Specifications Inverters - Operating 3.8.3

3.8 ELECTRICAL POWER SYSTEMS

3.8.3 Inverters - Operating

LCO 3.8.3 The Division A, B, C, and D inverters sh all be OPERABLE.

- NOTES -

One inverter may be disconnected from its associate d DC bus for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to perform an equalizing charge on its a ssociated battery, providing:

1. The associated instrument and control bus is ene rgized from its Class 1E voltage regulating transformer; and

2. All other AC instrument and control buses are en ergized from their

----------------------------------------------- associated OPERABLE inverters.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

A. One or two inverter(s) A.1 ------------------------------------

within one division - NOTE -

inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.5 Distribution Systems -

Operating with any instrument and control bus de-energized.

Restore inverter(s) to 14 days OPERABLE status.

B. Required Action B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and associated Completion Time AND not met. B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

VEGP Units 3 and 4 3.8.3 - 1 Amendment No. ___ (Uni t 3)

Amendment No. ___ (Unit 4)

Vogtle Electric Generating Plant (VEGP) Units 3 and 4

License Amendment Request for Technical Specificati on 3.8.3, Inverters - Operating, Completion Time Extension

Attachment 3

Technical Specification Bases Marked Up Pages (For Information Only)

Insertions Denoted by Blue Underline and Deletions by Red Strikethrough Omitted text is identified by three asterisks ( * * * )

(Attachment 3 consists of two pages, including this cover page.)

ND-22-xxxx Technical Specifications Bases Marked Up Pages (For Information Only)

Technical Specifications Bases B 3.8.3, Inverters - Operating BASES

ACTIONS A.1

Required Action A.1 allows 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 14 days to fix each inoperable inverter and return it to service. The 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 14 day time limit is based on engineering judgment a risk-informed Completion Time based on site-specific risk analysis, taking into consideration the time required to re pair an inverter and the additional risk to which the un it is exposed because of the inverter inoperability. This has to be balance d against the risk of an immediate shutdown, along with the potential challe nges to safety systems such a shutdown might entail. When the AC instrument and control bus is powered from its voltage regulating transformer, it is relying upon interruptible AC electrical power sources (off site and onsite). The uninterruptible inverter source to the AC instrumen t and control buses is the preferred source for powering instrumentation t rip setpoint devices.

Page 2 of 2

ML22307A007

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