Text

Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for High Energy Line Breaks Outside of the Containment Building
	ML19240A814
Person / Time
Site:	Oconee
Issue date:	08/28/2019
From:	Burchfield J; Duke Energy Carolinas
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML19240A925	List: ML19242C700; ML19242C728; RA-19-0253, Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for High Energy Line Breaks Outside of the Containment Building;
References
	RA-19-0253
	Download: ML19240A814 (70)
	v • d • e

J. Ed Burchfield, Jr.

Vice President Oconee Nuclear Station Duke Energy ON01VP l 7800 Rochester Hwy Seneca, SC 29672 o: 864.873.3478 f: 864.873.4208 Ed.Burchfield@duke-energy.com RA-19-0253 10 CFR 50.90 August 28, 2019 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

Subject:

Duke Energy Carolinas, LLC Oconee Nuclear Station Renewed Facility Operating License Numbers DPR-38, DPR-47, and DPR-55 Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for High Energy Line Breaks Outside of the Containment Building.

References:

1. Letter from A. Giambusso (Atomic Energy Commission) to A. C. Thies (Duke Power Company), General Information Required for Consideration of the Effects of a Piping System Break Outside Containment, dated December 15, 1972.

2. Letter from A. Schwencer (Atomic Energy Commission) to A. C. Thies (Duke Power Company), General Information Required for Consideration of the Effects of a Piping System Break Outside Containment, Clarification Letter, dated January 17, 1973.

3. MDS Report No. OS-73.2, Analysis of Effects Resulting from Postulated Piping Breaks Outside Containment for Oconee Nuclear Station, Units 1, 2, & 3, prepared by Duke Power Company, dated April 25, 1973.

4. MDS Report No. OS-73.2, Supplement 1, Analysis of Effects Resulting from Postulated Piping Breaks Outside Containment for Oconee Nuclear Station, Units 1, 2, & 3, prepared by Duke Power Company, dated June 22, 1973.

5. MDS Report No. OS-73.2, Supplement 2, Analysis of Effects Resulting from Postulated Piping Breaks Outside Containment for Oconee Nuclear Station, Units 1, 2, & 3, prepared by Duke Power Company, dated March 12, 1974.

6. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for HELB Events Outside of the Containment Buildings; License Amendment Request No. 2008-005, dated June 26, 2008.

Attachment 4 of this letter contains proprietary information. Withhold from Public Disclosure Under 10 CFR 2.390. Upon removal of Attachment 4, this letter is uncontrolled.

U.S. Nuclear Regulatory Commission August 28, 2019 Page 2

7. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for HELB Events Outside of the Containment Building - Unit 2; License Amendment Request No. 2008-006, dated December 22,2008.

8. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for HELB Events Outside of the Containment Building; License Amendment Request No. 2008-007, dated June 29, 2009.

9. Letter to the U.S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, Tornado and High Energy Line Break (HELB) Mitigation License Amendment Requests (LARs) - Responses to Request for Additional Information, dated December 16, 2011.

10. Letter to the U. S. Nuclear Regulatory Commission from Thomas Ray, Vice President, Oconee Nuclear Station, Duke Energy Carolinas, LLC, Revision to Tornado/HELB Mitigation Strategies and Regulatory Commitments, dated November 15, 2017.

In accordance with 10 CFR 50.90, Duke Energy Carolinas, LLC (Duke Energy) proposes to amend Renewed Facility Operating License Numbers DPR-38, DPR-47, and DPR-55 to revise the Oconee Nuclear Station (ONS) current licensing basis (CLB) with regard to High Energy Line Breaks (HELBs) outside of the containment building. The license amendment request (LAR) includes revisions to the Updated Final Safety Analysis Report (UFSAR) in support of the revised HELB licensing basis (LB).

The purpose of this LAR is to establish normal plant systems, protected service water (PSW),

and/or the standby shutdown facility (SSF) as the assured mitigation path following a HELB.

Nuclear Regulatory Commission (NRC) approval is requested for specific details of the new strategy discussed in section 2.4 and evaluated in section 3 including associated attachments.

In parallel with the review and approval of this LAR, ONS is implementing a number of conforming modifications to the plant under 10 CFR 50.59. A description of these changes is included in Attachment 1 and provided for your information. These modifications either enhance the ability of structures, systems, or components (SSC) to withstand the effects of the HELB or improves the response of the mitigating systems in responding to a HELB. The descriptions and conclusions provided in this LAR credit these modifications. These modifications will be completed prior to implementation of the LAR.

The analysis of the dynamic effects resulting from postulated piping breaks outside of the containment building was originally documented in Duke Energy mechanical design study (MDS) Report No. OS-73.2 (reference 3) and corresponding supplements (references 4 and 5).

The existing HELB report (references 3, 4, and 5) will remain as the HELB LB pending the approval and implementation of this LAR.

This LAR and supporting attachments provide a re-evaluation of postulated HELBs and describes the as modified station configuration for the identified HELBs. This LAR is a LB reconstitution effort that reflects extensive analysis. The proposed changes, once approved by the NRC staff, will supersede the existing HELB LB documentation, MDS Report No. OS-73.2 (reference 3) and corresponding supplements (reference 4 and 5).

U.S. Nuclear Regulatory Commission August28,2019 Page3 The enclosure to this LAA provides a description and assessment of the proposed change.

Attachment 1 contains the list of conforming modifications to be installed as a result of this LAA.

Attachments 2 and 3 contain the UFSAR red marked changes and retypes, respectively.

Attachments 4 and 5 describe the Thermal Hydraulic (T-H) models used to perform analysis of mitigated HELB scenarios in support of this LAA. Within Attachment 4, proprietary information is identified by brackets. In accordance with 10 CFR 2.390, Duke Energy requests that this information be withheld from public disclosure. Attachment 5 contains the non-proprietary (redacted) version of this content. Attachments 7 and 8 contain affidavits attesting to the proprietary nature of the information in Attachment 4. The proprietary information that is owned by Duke Energy and Framatome is annotated, respectively. The annotated information has substantial commercial value that provides a competitive advantage. Attachment 6 contains the T-H Transient Analyses performed to evaluate HELB effects. Attachment 9 provides how ONS meets the regulatory requirements from the Giambusso/Schwencer letters with exclusions and deviations (references 1 and 2). Attachment 1Oprovides HELB definitions. Attachments 11 and 12 provide the time critical operator actions and feasibility assessment associated with the prescribed HELB mitigation strategies, respectively.

In accordance with Duke Energy administrative procedures that implement the Quality Assurance Program Topical Report, these proposed changes have been reviewed and approved by the On-Site Review Committee. A copy of this LAA is being sent to the State of South Carolina in accordance with 10 CFR 50.91 requirements.

Duke Energy requests approval of this amendment request by August 2021 with an implementation period in accordance with completion dates identified in Attachment 1. Note that Duke Energy plans to implement the revised HELB licensing basis in a staggered fashion on a per unit basis. The UFSAR changes will also be issued on a per unit basis. For the intent of this LAA and sake of review, the proposed changes are treated like all modifications have been completed for all three units. Inquiries on this proposed amendment request should be directed to Timothy D. Brown of the ONS Regulatory Projects Group at (864) 873-3952 I declare under penalty of perjury that the foregoing is true and correct. Executed on August 28, 2019.

Sincerely, J. Ed Burchfield, Jr.

Vice President Oconee Nuclear Station

U.S. Nuclear Regulatory Commission August 28, 2019 Page 4

Enclosure:

Evaluation of Proposed Changes Conforming Actions UFSAR Red-Marked Changes UFSAR Retyped Changes Thermal-Hydraulic Models for High Energy Line Break Transient Analysis

[Proprietary] Thermal-Hydraulic Models for High Energy Line Break Transient Analysis [Non-Proprietary] Thermal-Hydraulic Transient Analysis for Evaluation of High Energy Line Breaks Duke Energy Affidavit Framatome Affidavit Regulatory Requirements 0 Definitions 1 Time Critical Operator Actions 2 Feasibility Assessment for New Proposed Time Critical Operator Actions cc w/enclosure and attachments:

Ms. Laura A. Dudes, Administrator, Region II U.S. Nuclear Regulatory Commission Marquis One Tower 245 Peachtree Center Ave., NE, Suite 1200 Atlanta, GA 30303-1257 Ms. Audrey Klett, Project Manager (by electronic mail only)

Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Mr. Adam Ruh Acting NRC Senior Resident Inspector Oconee Nuclear Station Ms. Anuradha Nair-Gimmi, (by electronic mail only: naira@dhec.sc.gov)

Bureau of Environmental Health Services Department of Health & Environmental Control 2600 Bull Street Columbia, SC 29201

ENCLOSURE EVALUATION OF PROPOSED CHANGES LICENSE AMENDMENT REQUEST

Subject:

Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for High Energy Line Breaks Outside of the Containment Building.

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 2.5 UFSAR Changes

3. TECHNICAL EVALUATION 3.1 Purpose and Methodology 3.2 HELB Strategy 3.3 Regulatory Requirements 3.4 Arbitrary Intermediate Breaks and Critical Cracks 3.5 Excluded Systems 3.6 Operations Response, Training and Procedures 3.7 Thermal Hydraulic Analysis

4. REGULATORY EVALUATION 4.1 Applicable UFSAR 4.2 Precedent 4.3 Significant Hazards Consideration

5. ENVIRONMENTAL CONSIDERATION

6. REFERENCES

7. ACRONYMS

License Amendment Request August 28, 2019

1.

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, Duke Energy Carolinas, LLC (Duke Energy) proposes to amend Renewed Facility Operating License Numbers DPR-38, DPR-47, and DPR-55 to revise the Oconee Nuclear Station (ONS) current licensing basis (CLB) with regard to high energy line breaks (HELBs) outside of the containment building. The license amendment request (LAR) includes revisions to the Updated Final Safety Analysis Report (UFSAR) in support of the revised HELB licensing basis (LB).

The purpose of this LAR is to establish normal plant systems, protected service water (PSW),

and/or the standby shutdown facility (SSF) as the assured mitigation path following a HELB.

Nuclear Regulatory Commission (NRC) approval is requested for specific details of the new strategy discussed in section 2.4 and evaluated in section 3 including associated attachments.

The LAR also proposes to credit a number of plant modifications to enhance the stations capability to withstand the dynamic effects of a damaging HELB. Implementation of the proposed HELB LB and the related activities will clarify and, in some cases, revise the stations LB to collectively enhance the overall design and safety margin. Note that the modifications are being performed under 10 CFR 50.59 and their approval is not a part of this LAR even though they are discussed.

The analysis of the dynamic effects resulting from postulated piping breaks outside of the containment building was originally documented in Duke Energy mechanical design study (MDS) Report No. OS-73.2 (reference 3) and corresponding supplements (references 4 and 5).

The existing HELB report (references 3, 4, and 5) will remain as the HELB LB pending the approval and implementation of this LAR.

This LAR and supporting attachments provide a re-evaluation of postulated HELBs and describes the as modified station configuration for the identified HELBs. This LAR is an HELB LB reconstitution effort that reflects extensive analysis. The proposed changes, once approved by the NRC, will supersede the existing HELB LB documentation, MDS Report No. OS-73.2 (reference 3) and corresponding supplements (reference 4 and 5).

The current commitments for HELB can be found in the letter dated November 15, 2017 (reference 39). HELB commitment 24H addresses submittal of the subject LAR and is considered met with submittal of this LAR. Commitments 31H and 32H have been addressed by the HELB re-analysis and are considered met and closed. The remaining commitments specific to HELB are incorporated into this LAR as conforming actions within Attachment 1 to be completed and tracked accordingly.

This LAR will supersede, in its entirety, previous HELB documentation and responses to request for additional information (RAI). These were provided in letters to the NRC dated November 30, 2006 (reference 8), June 26, 2008 (reference 14), December 22, 2008 (reference 15),

September 2, 2009 (HELB related RAI 10) (reference 33), June 29, 2009 (reference 16),

October 23, 2009 (reference 26), June 24, 2010 (HELB related RAIs 2-37 and 2-38) (reference 27), August 31, 2010 (HELB related RAI 2-36) (reference 28), December 7, 2010 (reference 29), December 16, 2011 (reference 30), January 20, 2012 (reference 31), and March 1, 2012 (reference 32).

This enclosure provides a description and assessment of the proposed change. Attachment 1 contains the list of conforming actions to be implemented as a result of this LAR. Attachments 2 and 3 contain the UFSAR red marked changes and retypes, respectively. Attachments 4 and 5 describe the Thermal Hydraulic (T-H) models used to perform analysis of mitigated HELB scenarios in support of this LAR. Within Attachment 4, proprietary information is identified by brackets. In accordance with 10 CFR 2.390, Duke Energy requests that this information be 1

License Amendment Request August 28, 2019 withheld from public disclosure. Attachment 5 contains the non-proprietary (redacted) version of this content. Attachments 7 and 8 contain affidavits attesting to the proprietary nature of the information in Attachment 4. The proprietary information that is owned by Duke Energy and Framatome is annotated, respectively. The annotated information has substantial commercial value that provides a competitive advantage. Attachment 6 contains the T-H Transient Analyses performed to evaluate HELB effects. Attachment 9 provides how ONS meets the regulatory requirements from the Giambusso/Schwencer letters with exclusions and deviations (references 1 and 2). Attachment 10 provides HELB definitions. Attachments 11 and 12 provide the time critical operator actions and feasibility assessment associated with the prescribed HELB mitigation strategies, respectively. Note that references and acronyms provided in sections 6 and 7 of this enclosure are used throughout the attachments.

Each step of this HELB LB reconstitution process and the results have been documented in station calculations. These documents are controlled and owned by the station, and they form the basis of the information contained in this document. They will be posted to a designated sharepoint upon request to support NRC review and approval of this LAR.

2. DETAILED DESCRIPTION 2.1 System Design and Operation 2.1.1 Protected Service Water System The PSW system is designed as a standby system for use under emergency conditions. The PSW system provides added defense-in-depth protection by serving as a backup to existing safety systems and as such, the system is not required to comply with single failure criteria. The PSW system is provided as an alternate means to achieve and maintain safe shutdown (SSD) conditions for one, two, or three units following postulated scenarios that damage essential systems and components normally used for SSD. The PSW System requires manual activation and can be activated if normal emergency systems are unavailable.

The function of the PSW System is to provide a diverse means to achieve and maintain SSD by providing secondary side decay heat removal (DHR), reactor coolant system (RCS) pump seal cooling, RCS primary inventory control, and RCS boration for reactivity management following plant scenarios that disable the 4160 volts alternating current (VAC) essential electrical power distribution system. The PSW System is not an Engineered Safety Feature Actuation System and is not credited to mitigate design basis events (DBEs) as analyzed in UFSAR Chapters 6 and 15. No credit is taken in the safety analyses for PSW system operation following DBEs.

The PSW pumping system utilizes the inventory of lake water contained in the Unit 2 Condenser Circulating Water (CCW) piping. The PSW primary and booster pumps are located in the auxiliary building (AB) at elevation 771 and take suction from the Unit 2 CCW piping and discharge into the steam generators (SGs) of each unit via the emergency feedwater (EFW) system headers. The raw water is vaporized in the SGs, removing residual heat, and is dumped to atmosphere via the Main Steam Relief Valves (MSRVs) or Atmospheric Dump Valves (ADVs). For extended operation, the PSW portable pump with a flow path capable of taking suction from the intake canal and discharging into the Unit 2 CCW piping is designed to provide a backup supply of water to the PSW system in the event of loss of CCW and subsequent loss of CCW siphon flow. The PSW portable pump is stored onsite.

The PSW system is designed to support cool down of the RCS and maintain SSD conditions.

The PSW system is designed to promote natural circulation DHR using the SGs for an extended period of time during which time other plant systems required to cool the RCS to Mode 5 conditions will be restored and brought into service. In addition, the PSW system, in 2

License Amendment Request August 28, 2019 combination with the high pressure injection (HPI) system, provides borated water for reactor coolant pump (RCP) seal cooling, RCS makeup, and reactivity management.

The mechanical portion of the PSW system provides DHR by feeding Lake Keowee water to the secondary side of the SGs. In addition, the PSW pumping system supplies Keowee lake water to the HPI pump motor coolers. The PSW pumping system consists of a booster pump, a primary pump, and a portable pump.

The PSW primary and booster pumps, motor operated valves, and solenoid valves required to bring the system into service, are controlled from the main control rooms (CRs). Check valves and manual handwheel operated valves are used to prevent back-flow, accommodate testing, or are used for system isolation.

The PSW electrical system is designed to provide power to PSW mechanical and electrical components as well as other system components (i.e., RCS vent valves, select groups of pressurizer heaters, one HPI pump, etc.) needed to establish and maintain an SSD condition.

Normal power is provided by a transformer connected to a 100 kilovolt (kV) overhead transmission line that receives power from the Central Tie Switchyard located approximately eight (8) miles from the plant. Standby power is provided from the Keowee Hydroelectric Station via an underground path. The Keowee Hydro Unit (KHU) aligned to the overhead emergency power path can automatically provide power to Keowee Hydroelectric Station in-house loads.

These external power sources provide power to transformers, switchgear, breakers, load centers (LCs), batteries, and battery chargers located in the PSW electrical equipment structure.

There are two (2) batteries inside the PSW building. Either battery is sized to supply PSW direct current (DC) loads. The battery banks are located in different rooms separated by fire rated walls. A separate room within the PSW building is provided for major PSW electrical equipment.

PSW building heating, ventilation, and air conditioning (HVAC) is designed to maintain transformer and battery rooms within their design temperature range. The HVAC system consists of two (2) systems; a non-QA-1/non-credited system designed to maintain the PSW transformer and battery rooms environmental profile and a QA-1/credited system designed to actuate whenever the non-QA-1 system is not able to meet its design function.

2.1.2 Standby Shutdown Facility The SSF is designed as a standby system for use under certain emergency conditions. The system provides additional defense-in-depth protection for the health and safety of the public by serving as a backup to existing safety systems. It provides an alternate means to achieve and maintain the unit(s) in Mode 3 with average RCS temperature 525oF (unless the initiating event causes the unit(s) to be driven to a lower temperature) following a fire, turbine building (TB) flood, and station blackout (SBO) events. The SSF is designed for the criteria associated with these events. The SSF Auxiliary Service Water (ASW) system is credited as a backup to EFW to address EFW system equipment vulnerabilities associated with single failures, tornado missiles, and seismic design. The SSF may also be activated as necessary in response to events associated with plant security. The single failure criterion is not required. Failures in the SSF system will not cause failures or inadvertent operations in other plant systems. The SSF requires manual activation and can be activated if emergency systems are not available.

The SSF is designed to maintain the reactor(s) in an SSD condition for a period of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months following a fire or TB flood, and for a period of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months following an SBO. The capability of the SSF to maintain the reactor(s) in an SSD condition is also credited for certain security related events. The design criteria associated with each of these events is described in UFSAR Section 9.6.2. The main components of the SSF are the SSF ASW system, SSF Portable Pumping 3

License Amendment Request August 28, 2019 system, SSF Reactor Coolant Makeup (RCMU) system, SSF Power system, and SSF instrumentation.

The SSF ASW system is a high head, high volume system designed to provide sufficient SG inventory for adequate DHR for three units during a loss of normal alternating current power in conjunction with the loss of the Main Feedwater (MFDW) and EFW systems. One motor driven SSF ASW pump, located in the SSF, serves all three units. The SSF ASW pump utilizes a suction supply of lake water from the embedded Unit 2 CCW piping.

The SSF ASW system is used to provide adequate cooling to maintain single phase RCS natural circulation flow in Mode 3 with an average RCS temperature 525oF (unless the initiating event causes the unit(s) to be driven to a lower temperature). In order to maintain single phase RCS natural circulation flow, an adequate number of Bank 2, Group B and C pressurizer heaters are needed to compensate for ambient heat loss from the pressurizer. As long as the temperature in the pressurizer is maintained, RCS pressure will also be maintained.

This will preclude hot leg voiding and ensure adequate natural circulation cooling.

Portions of the SSF ASW system are credited to meet the Extensive Damage Mitigation Strategies commitments per Nuclear Energy Institute (NEI) 06-12 (B.5.b) and the SSF is fully credited to meet the Extensive Damage Mitigation Strategies commitments per NEI 12-06 (FLEX).

The SSF Portable Pumping system, which includes a submersible pump and a flow path capable of taking suction from the intake canal and discharging into the Unit 2 CCW line, is designed to provide a backup supply of water to the SSF in the event of loss of CCW and subsequent loss of CCW siphon flow. The SSF Portable Pumping system is installed manually in accordance with procedures.

The SSF RCMU system is designed to supply makeup to the RCS and RCP seal cooling in the event that normal makeup systems are unavailable. An SSF RCMU pump located in the reactor building (RB) of each unit supplies makeup to the RCS should the normal makeup system flow and seal cooling become unavailable. The system is designed to ensure that sufficient borated water is provided from the spent fuel pool (SFP) to allow the SSF to maintain all three units in Mode 3 with average RCS temperature 525oF (unless the initiating event causes the unit(s) to be driven to a lower temperature) for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . An SSF RCMU pump is capable of delivering borated water from the SFP to the RCP seal injection lines. A portion of this seal injection flow is used to makeup for RCP seal leakage while the remainder flows into the RCS to makeup for other normal RCS leakage.

When normal and emergency systems are not available, RCS inventory and reactor shutdown margin are maintained from the SSF CR by the SSF RCMU pump taking suction from the SFP.

Primary system pressure can be maintained by the pressurizer heaters or by use of charging combined with letdown. The SSF reactor coolant (RC) letdown is also used to maintain the desired level in the pressurizer if the seal injection flow exceeds the RCP seal leakage plus other RCS leakage once adequate makeup flow has been provided for allowable RCS volume shrinkage.

The SSF Power system includes 4160 VAC, 600 VAC, 208 VAC, 120 VAC and 125 volts direct current (VDC) power. It consists of switchgear, a LC, motor control centers (MCCs),

panelboards, remote starters, batteries, battery chargers, inverters, a diesel generator (DG),

relays, control devices, and interconnecting cable supplying the appropriate loads. The SSF Power system provides electrical isolation of SSF equipment from non-SSF equipment. The SSF 125 VDC Power system provides a reliable source of power for DC loads needed to black start the DG. The DC power system consists of two 125 VDC batteries and associated 4

License Amendment Request August 28, 2019 chargers, two 125 VDC distribution centers (DCSF, DCSF-1), and a DC power panelboard (DCSF). The SSF Power system is provided with standby power from a dedicated DG. The SSF DG and support systems consist of the DG, fuel oil transfer system, air start system, diesel engine service water system, as well as associated controls and instrumentation. This SSF DG is rated for continuous operation at 3500 kilowatt, 0.8 power factor, and 4160 VAC. The SSF electrical design load does not exceed the continuous rating of the DG. The auxiliaries required to assure proper operation of the SSF DG are supplied entirely from the SSF Power system.

The SSF DG is provided with manual start capability from the SSF only. It uses a compressed air starting system with four air storage tanks. An independent fuel system, complete with a separate underground storage tank, duplex filter arrangement, a fuel oil transfer pump, and a day tank, is supplied for the DG.

The SSF air conditioning, which includes the HVAC service water system and air conditioning equipment (fan motors, compressors, condensers, and coils), must be operable to support the SSF power system operability.

2.1.3 Normal Plant Systems Normal plant systems and related support systems may remain available for HELB mitigation.

These systems can be used for plant cooldown and the establishment of cold shutdown (CSD).

For conciseness, only the HPI and EFW systems are discussed below based on their significance to the safety analysis performed for HELB mitigation scenarios.

2.1.3.1 High Pressure Injection The HPI system consists of two independent trains, each of which splits to discharge into two RCS cold legs, so that there is a total of four HPI injection lines. Each train takes suction from the borated water storage tank (BWST) and has an automatic suction valve and discharge valve which open upon receipt of an Engineered Safeguards (ES) Protective System (ESPS) signal.

The two HPI trains are designed and aligned such that they are not both susceptible to any single active failure (SAF) including the failure of any power operating component to operate or any single failure of electrical equipment.

There are three ESPS actuated HPI pumps; the discharge flow paths for two of the pumps are normally aligned to automatically support HPI train A and the discharge flow path for the third pump is normally aligned to automatically support HPI train B. The discharge flow paths can be manually aligned such that each of the HPI pumps can provide flow to either train. At least one pump is normally running to provide RCS makeup and seal injection to the RCPs. Suction header cross-connect valves are normally open, cross-connecting the HPI suction headers during normal operation. The discharge crossover valves (HP-409 and HP-410) are normally closed; these valves can be used to bypass the normal discharge valves and assure the ability to feed either trains injection lines via HPI pump B. For each discharge valve and discharge crossover valve, a safety grade flow indication is provided to enable the operator to throttle flow to assure that runout limits are not exceeded.

A suction header supplies water from the BWST to the HPI pumps. HPI discharges into each of the four RCS cold legs between the RCP and the reactor vessel (RV). There is one flow limiting orifice in each of the four injection headers that connect to the RCS cold legs. If a pipe break were to occur in an HPI line between the last check valve and the RCS, the orifice in the broken line would limit HPI flow lost through the break and maximize the flow supplied to the RV via the other line supplied by the HPI header. The HPI pumps are capable of discharging to the RCS at an RCS pressure above the operating setpoint of the pressurizer safety valves (PSVs). The HPI system also functions to supply borated water to the reactor core following increased heat removal events, such as main steam line breaks (MSLBs).

5

License Amendment Request August 28, 2019 2.1.3.2 Emergency Feedwater The EFW System automatically supplies feedwater (FDW) to the SGs to remove decay heat from the RCS upon the loss of normal FDW supply. The EFW pumps take suction through suction lines from the upper surge tank (UST) and condenser hotwell and pump to the SG secondary side through the EFW nozzles. The SGs function as a heat sink for core decay heat.

The heat load is dissipated by releasing steam to the atmosphere from the SGs via the MSRVs or ADVs. If the main condenser is available, steam may be released via the turbine bypass system and recirculated to the condenser hotwell.

The EFW System consists of two motor-driven EFW pumps and one turbine-driven EFW pump, any one of which can provide the required heat removal capability. Thus, the requirements for diversity in motive power sources for the EFW System are met. The steam turbine driven EFW pump receives steam from either of the two main steam (MS) headers, upstream of the main turbine stop valves, or from the auxiliary steam system which can be supplied from the other two units MS system. The EFW System supplies a common header capable of feeding either or both SGs. The EFW System normally receives a supply of water from the UST. The EFW system can also be aligned to the condenser hotwell.

The EFW System is capable of supplying FDW to the SGs during normal unit startup, shutdown, and hot standby conditions. The discharge header of each EFW system can be cross-connected making each system capable of supplying any unit.

The three EFW pumps are started automatically upon a loss of both MFDW pumps or a signal from the anticipated transient without scram mitigation system actuation circuitry. The two motor driven EFW pumps are also started automatically upon a low SG level that exists for at least 30 seconds.

2.2 Current Technical Specifications Requirements There are no technical specification (TS) requirements for HELB.

2.3 Reason for the Proposed Change In December 1972, the Atomic Energy Commission (AEC) sent to Duke Power Company a request for information (references 1 and 2) concerning postulated piping breaks on high energy (HE) lines outside of the containment building at ONS. It was issued by A. Giambusso, the Deputy Director for Reactor Projects Directorate of Licensing, and is referred to as the Giambusso Letter (reference 1) throughout this LAR. The Giambusso Letter was amended by an errata sheet provided in a letter from A. Schwencer (AEC), Chief Pressurized Water Reactors Branch No. 4 Directorate of Licensing in January 1973 (reference 2). In response to the Giambusso Letter, a summary of the analysis of the HE line configuration was provided to the AEC. This analysis was documented in MDS Report No. OS-73.2 (reference 3) and supplements 1 and 2 (references 4 and 5). The 1973 document included the HELB criteria, station design methodologies, and protection requirements for mitigating postulated HELBs outside of the containment building. Based upon the information provided in the 1973 document and the supplements, an ONS Unit 2 and 3 Safety Evaluation Report (SER) was received from the AEC on July 6, 1973, in which the AEC evaluated the assessment performed by Duke Power Company and concluded that ONS had been analyzed in a manner consistent with the intent of the criteria and guidelines provided by the AEC (reference 6).

The MDS report was incorporated into the ONS license application by reference. SER Section 7.1.11 High-energy Line Rupture External to the Reactor Building addressed the MDS report, and Attachment E of the SER repeated the NRC HELB criteria, as amended by the Schwencer letter (reference 2). The basic criteria require that:

6

License Amendment Request August 28, 2019

1. Protection be provided for equipment necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming a concurrent and unrelated single active failure of protected equipment, from all effects resulting from ruptures in pipes carrying high-energy fluid, up to and including a double-ended rupture of such pipes, where the temperature and pressure conditions of the fluid exceed 200oF and 275 psig. Breaks should be assumed to occur in those locations specified in the pipe whip criteria. The rupture effects on equipment to be considered include pipe whip, structural (including the effects of jet impingement) and environmental.

2. Protection be provided for equipment necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming a concurrent and unrelated single active failure of protected equipment, from the environmental and structural effects (including the effects of jet impingement) resulting from a single open crack at the most adverse location in pipes carrying high-energy fluid routed in the vicinity of this equipment, where the temperature and pressure conditions of the fluid exceed 200oF and 275 psig. The size of the cracks should be assumed to be 1/2 the pipe diameter in length and 1/2 the wall thickness in width.

Staff Evaluation and Conclusion The staff has evaluated the assessment performed by the applicant and has concluded that the applicant has analyzed the facilities in a manner consistent with the intent of the criteria and guidelines provided by the staff. The staff agrees with the applicants selection of pipe failure locations and concludes that all required accident situations have been addressed appropriately by the applicant.

Furthermore the staff has evaluated the analytical methods and assumptions used in the applicants analyses and find them acceptable and concurs with the proposed plant modifications and the criteria to be used in their designs.

Many years after approval of the MDS report and initial licensing of ONS, the SSF was built.

The SSF provides additional defense-in-depth protection to achieve and maintain Mode 3 with an average RCS temperature 525oF (unless the initiating event causes the unit(s) to be driven to a lower temperature) following postulated fire, sabotage, SBOs, or flooding events.

The SSF RCMU system is the SSF sub-system designed and credited to supply RCP seal injection flow in the event that the HPI, the normal makeup system, becomes unavailable when a Units RCS temperature is > 250oF during Modes 1, 2, and 3. It can recover RCS volume shrinkage caused by cooling the RCS to Mode 3 with an average RC temperature 525oF (unless the initiating event causes the unit(s) to be driven to a lower temperature). However, the SSF RCMU System is not credited for UFSAR Chapter 6 and 15 events, such as Loss of Coolant Accident (LOCA), which result in significant loss of RCS inventory. The SSF ASW system is the SSF sub-system credited as the backup to the FDW and EFW systems.

In 1998, Duke Energy performed an assessment (reference 7) that identified gaps in documentation with the original HELB analysis performed in 1973. As a result, Duke Energy initiated a project to update the original HELB work. This initiative was communicated to the NRC Region II management during a January 26, 1999 management meeting. The primary objective of this initiative was to revalidate and update the original HELB design basis for the present station configuration.

To further reduce plant risk and improve the quality of ONS LB documentation, Duke Energy initiated a risk reduction initiative in 2004. The goal of this initiative was to further clarify the LB and produce a set of design, program, and procedure changes that would reduce SSF 7

License Amendment Request August 28, 2019 vulnerability concerns. Duke Energy believed that this integrated approach was more beneficial than recommending changes that targeted individual design issues.

The risk reduction initiative report was completed in May 2005 and recommended a number of modifications to resolve old design issues that included HELB. The proposed modifications would result in a significant improvement in overall core damage frequency.

In light of the risk reduction teams recommendations and as a result of continued communications with the NRC regarding resolution of HELB outstanding issues, a combined tornado and HELB mitigation strategies letter was submitted on November 30, 2006 (reference 8). The submittal contained a number of regulatory commitments as well as responses to key issues identified by the NRC related to the HELB LB.

In 2007, there were additional communications between Duke Energy and the NRC regarding the mitigation strategies in the November 2006 submittal (reference 8). The result of this effort is documented in an NRC letter to Duke Energy dated March 28, 2007 (reference 9). Finally, as concluded in a May 15, 2007 NRC letter (reference 10) to Duke Energy, as a result of the extensive dialogue that we have had concerning your proposed modifications and mitigation strategies, we believe that the future LARs based on this approach could be found acceptable.

Duke Energy submitted follow-up letters (references 11 and 12) to refine and adjust implementation schedules of several of the commitments made in the November 30, 2006, letter (reference 8).

Supplemental letters dated September 2 (reference 33), October 23, 2009 (reference 26); June 10 (reference 40), June 24 (reference 27), August 31 (reference 28), and December 7, 2010 (reference 29) were provided to address requests for additional information (RAI). RAIs dated December 16, 2011 (reference 30); January 20 (reference 31), March 1 (reference 32), March 16 (reference 41), June 11 (reference 42), July 20 (reference 43), August 31 (reference 60),

November 2, 2012 (reference 44); April 5 (reference 23), June 28 (reference 45), August 7 (reference 46), December 18, 2013 (reference 47); February 14 (reference 17), April 3 (reference 61), April 11 (reference 25), and July 24, 2014 (reference 24) were credited for PSW review and approval, but also had information regarding HELB.

During this timeframe, PSW was also being implemented and reviewed as part of the National Fire Protection Association 805 and HELB LB reconstitution work. Each LAR credited PSW for varying types of mitigation. The NRC realized that PSW required final approval before they could continue review of HELB. As a result, the NRC suspended their review of the HELB LARs and separated the PSW review from it as stated in the issuance of PSW License Amendments 386, 388, and 387 dated August 13, 2014 (reference 13).

This document is the result of the initiatives and history provided above. It provides the completed analysis for HELBs at ONS. Included in the document are the descriptions of the station modifications that have been made or will be made as a result of performing this comprehensive HELB analysis. It will be used as the HELB LB for ONS and will supersede the configuration and strategy provided in the 1973 ONS HELB Report, OS-73.2 (references 3, 4, and 5) and more recent HELB LARs submitted in 2008 and 2009 (references 14, 15, and 16) and later combined in 2011 (reference 30) along with supporting documentation.

2.4 Description of the Proposed Change The purpose of this LAR is to establish normal plant systems, PSW, and/or SSF as the assured mitigation path following a HELB. Specifically, NRC approval is requested for:

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License Amendment Request August 28, 2019

1. Crediting the PSW system or SSF for HELB mitigation when a HELB results in the loss of plant systems needed for SSD inside the TB.

2. Crediting normal plant systems (i.e., HPI and EFW) or the SSF for HELB mitigation when a HELB results in the loss of plant systems needed for SSD inside the AB.

3. Crediting normal plant systems for HELB mitigation when a HELB occurs outside of the TB and AB.

4. UFSAR revisions that will incorporate the HELB strategy into the LB.

5. Time critical operator actions (TCAs) associated with the prescribed HELB mitigation strategies.

6. Exclusion of systems whose operating time at high energy (HE) conditions is less than 1% of the total unit operating time.

7. Exclusion of systems whose operating time at HE conditions is less than approximately 2% of the total system operating time.

8. Elimination of arbitrary intermediate breaks in ASME B & PV Section III-Class 2 and Class 3 equivalent piping. Intermediate breaks are postulated where calculated longitudinal stress for the applicable load cases (internal pressure, dead weight (gravity),

thermal, and seismic (OBE) conditions) exceed 0.8(Sa + Sh).

9. Intermediate breaks in non-rigorously analyzed piping are postulated in accordance with Branch Technical Position (BTP) Mechanical Engineering Branch (MEB) 3-1, Section B.1.c(2)(b)(i).

10. Elimination of critical cracks at the most adverse location in ASME Boiler and Pressure Vessel (B&PV) Section III-Class 2 and Class 3 equivalent piping. Critical cracks are postulated at axial locations where the calculated stress for the applicable load cases (internal pressure, dead weight (gravity), thermal, and seismic (OBE) conditions) exceed 0.4(Sa + Sh). Critical cracks are not postulated at locations of terminal ends.

11. The effects of the postulated intermediate breaks bound the effects from critical cracks; therefore, critical cracks are eliminated from evaluation in non-rigorously analyzed piping.

12. Determination of the effective length of jets from a break or critical crack in accordance with NUREG/CR-2913.

13. Strategies to achieve and maintain CSD conditions.

14. Elimination of the TCA to cross-connect EFW.

15. Elimination of the TCA to manually start the turbine driven EFW pump locally.

16. RCS Acceptance criteria as specified in Attachment 6.

Implementation of the proposed HELB LB and the conforming actions will clarify and, in some cases, revise the stations CLB to collectively enhance the overall design and safety margin.

The LAR describes plant modifications to enhance the stations capability to withstand effects of a HELB. These modifications, included in Attachment 1, are being performed under 10 CFR 50.59 and their approval for installation is not part of this LAR even though they are discussed.

2.5 UFSAR Changes Duke Energy proposes to modify the UFSAR, as follows below, to describe the ONS HELB mitigation strategy and update other applicable sections to reflect normal plant systems, PSW, and/or the SSF as the HELB mitigation strategy. Duke Energy plans to implement the UFSAR on a per unit basis. When all modifications are complete on a unit, the proposed changes described below will be issued for that unit through normal station processes. For the intent of this LAR and sake of review, the proposed changes are treated like all modifications have been completed for all three units. The UFSAR marked-up and retyped pages are provided in Attachments 2 and 3, respectively.

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License Amendment Request August 28, 2019 Currently, the analysis of effects resulting from postulated piping breaks outside of the containment building is contained in Duke Energys MDS Report No. OS-73.2 dated April 25, 1973 including revisions through supplement 2 (references 3 - 6) and incorporated by reference in UFSAR section 3.6.1.4. UFSAR Section 3.6.1.3 will be deleted and new section 3.6.2, Postulated Piping Failures in Fluid Systems Outside Containment, will be added to generally describe the revised HELB methodology and results. Section 3.6.2 will contain the following:

The purpose and methodology associated with evaluating HELBs outside of the containment building to include the following:

Identification of HE lines.

HELB location methodology.

Identification of HELB types.

Shutdown sequence evaluation criteria.

Interaction evaluation criteria.

Determination of SSD systems to include the following:

HELB mitigation strategy.

Shutdown objectives.

Functions to meet SSD objectives.

Also, section 3.6.1.4 will become section 3.6.3 and will reflect the HELB safety analysis performed in support of the LAR. References will be renumbered from 3.6.3 to 3.6.4. UFSAR Sections 5.1.2.4, Natural Circulation, 9.6, SSF and 9.7, PSW will be revised to reflect the HELB mitigation strategies. UFSAR Section 10.4.7.3.2, EFW Response Following a HELB, will be revised to reference the new HELB strategy.

3. TECHNICAL EVALUATION 3.1 Purpose and Methodology The purpose of this LAR and the descriptions of the evaluations and analyses contained within are to document the HELB configuration for ONS and to provide a comprehensive, updated strategy for mitigating the potential adverse interactions caused by these postulated HELBs.

Since this document provides a re-evaluation of the postulated HELBs in ONS and credits the as-modified ONS configuration for the identified HELBs, it supersedes the analysis provided in the original 1973 ONS HELB analysis (references 3, 4, and 5) and establishes a new basis for future HELB considerations. The original HELB report, OS-73.2 (references 3, 4, and 5) will still be used as a reference for definitions and historical information.

The analyses in this evaluation have been accomplished by using a systematic, step-by-step program of identification, evaluation, and documentation. The steps in the HELB program for ONS are as follows:

1. Identification of the HE systems, the HE lines, and the boundaries of the HE lines on each of those systems.

2. Identification of the postulated HELB locations and break types on each of the HE lines.

3. Determination of the equipment and systems in the ONS units, which could be utilized to mitigate the postulated HELBs.

4. Identification of the targets (structures, systems, or components (SSCs)) of each postulated HELB based upon the results of field inspections.

5. Determination of the shutdown equipment that is undamaged by the postulated HELB and can be used for the HELB mitigation and the shutdown of the station. This step is based upon the identification of the targets and the impact of the postulated HELBs on those targets.

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License Amendment Request August 28, 2019

6. Identification and recommendation of station physical and/or procedural changes to support the HELB mitigation strategy.

The details for the methodology have been documented in Attachment 9.

3.2 HELB Strategy The revised HELB Mitigation Strategy addresses the level of protection provided to SSCs necessary to reach SSD from the direct effects (pipe whip and jet impingement) and indirect effects (environmental and flooding) of a given HELB outside of the containment building. The major points of the updated strategy are as follows:

Required SSCs located in the TB are not impacted by HELBs postulated to occur in the AB or in the yard.

Required SSCs located in the AB are not impacted by HELBs postulated to occur in the TB.

SAFs are imposed for those components required for initial mitigation.

SAFs are not imposed for those components required to initiate a cooldown of the plant.

HELBs resulting in the loss of plant systems inside the TB needed for SSD are mitigated by the PSW system.

Should the PSW system be unavailable, the SSF is credited as an alternate means of achieving and maintaining SSD following HELBs that disable plant systems inside the TB.

HELBs resulting in the loss of plant systems inside the AB needed for SSD are mitigated by normal plant systems or the SSF.

As applicable, NUREG/CR-2913 is used for the determination of jet impingement effects following breaks and critical cracks.

Exclusion of systems whose operating time at HE conditions is less than 1% of the total unit operating time.

Exclusion of systems whose operating time at HE conditions is less than approximately 2% of the total system operating time.

Elimination of arbitrary intermediate breaks in ASME B & PV Section III-Class 2 and Class 3 equivalent piping. Intermediate breaks are postulated where calculated longitudinal stress for the applicable load cases (internal pressure, dead weight (gravity),

thermal, and seismic (OBE) conditions) exceed 0.8(Sa + Sh).

Intermediate breaks in non-rigorously analyzed piping are postulated in accordance with BTP MEB 3-1, Section B.1.c(2)(b)(i).

Elimination of critical cracks at the most adverse location in ASME B&PV Section III-Class 2 and Class 3 equivalent piping. Critical cracks are postulated at axial locations where the calculated stress for the applicable load cases (internal pressure, dead weight (gravity), thermal, and seismic (OBE) conditions) exceed 0.4(Sa + Sh). Critical cracks are not postulated at locations of terminal ends.

The effects of the postulated intermediate breaks bound the effects from critical cracks; therefore, critical cracks are eliminated from evaluation in non-rigorously analyzed piping.

HELBs occurring outside of the TB and AB are mitigated by normal plant systems.

Repairs are made to any system/components required for CSD.

Elimination of the TCA to cross-connect EFW.

Elimination of the TCA to manually start the turbine driven EFW pump locally.

RCS Acceptance criteria as specified in Attachment 6.

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License Amendment Request August 28, 2019 3.3 Regulatory Requirements The regulatory requirements for ONS are defined in the Implementation Section of the Standard Review Plan (SRP) 3.6.2, revision 1 (reference 18). Specific guidance is provided in Section B.4 of the BTP Auxiliary Systems Branch (ASB) 3-1, in which it is stated that for plants with operating licenses issued before July 1, 1975, the requirements of the Giambusso/Schwencer Letters (references 1 and 2) applied. The ONS Units were licensed to operate before the July 1, 1975 date, and the Unit 2 and 3 SER was issued on July 6, 1973 (reference 6). Hence the regulatory requirements for the ONS are contained within the Giambusso/Schwencer Letters (references 1 and 2).

The HELB requirements can be summarized as follows:

1. The reactor can be shut down and maintained in an SSD condition and subsequently cooled to the CSD condition in the event of a postulated rupture, outside of the containment building, of a pipe containing a HE fluid, including the double ended rupture of the largest pipe in the MS and FDW systems.

2. Plant SSCs required to safely shutdown the reactor and maintain it in an SSD condition should be protected or designed to withstand the effects of such a postulated pipe failure.

In addition to the Giambusso/Schwencer Letters (references 1 and 2), SRP 3.6.2 (reference 18) is used to provide guidance by supplementing and clarifying the requirements in the Giambusso/Schwencer letters. This includes adopting portions of Generic Letter (GL) 87-11 (reference 19). In that GL, those portions that eliminated the arbitrary intermediate breaks and critical cracks are used for establishing pipe break and critical crack locations on the seismically analyzed HE piping lines in the station. Specific mitigation strategies, regulatory commitments, and responses were provided to the NRC in the November 30, 2006 letter (reference 8) and the January 25, 2008 letter (reference 12) from Duke Energy, and the information in these letters form the basis for this document. provides the detailed information pertaining to how ONS meets the Giambusso/

Schwencer requirements (references 1 and 2).

3.4 Arbitrary Intermediate Breaks and Critical Cracks There are two areas where BTP MEB 3-1 (reference 19) provides more clarity than given by the Giambusso/Schwencer letters: (1) Relaxation in Arbitrary Intermediate Pipe Rupture Requirements; and (2) Postulation of Critical Cracks. In general, these are the two subjects where a deviation to the Giambusso/Schwencer requirements are sought. These topics are addressed below.

3.4.1 Arbitrary Intermediate HELBs Giambusso/Schwencer required for American Society of Mechanical Engineers (ASME) Code Class 2 and 3 equivalent piping that intermediate break locations should be postulated as follows:

1) At any intermediate locations between terminal ends where either the circumferential or longitudinal stresses derived on an elastically calculated basis under the loadings associated with seismic events and operational plant conditions exceed .8 x (SH + SA) or the expansion stresses exceed .8 SA.

2) Intermediate locations in addition to those determined by (1) above, selected on a reasonable basis as necessary to provide protection. At a minimum, there should be two intermediate locations for each piping run or branch run.

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License Amendment Request August 28, 2019 GL 87-11 allowed licensees to eliminate postulated arbitrary intermediate pipe breaks in Class 1 piping and Class 2 and 3 equivalent piping in areas of the plant outside the containment penetration areas without prior NRC approval insofar as the change did not conflict with the plants license or the TSs. The GL implemented the relaxation by revising portions of the BTP MEB 3-1, Postulated Rupture Locations in Fluid System Piping Inside and Outside Containment (reference 19).

ONS proposes to adopt this provision to use stress criteria to postulate intermediate break locations for Class 2 and 3 equivalent piping and eliminate arbitrary intermediate breaks.

Intermediate break locations would be determined based on the calculated circumferential or longitudinal stresses derived on an elastically calculated basis using the loadings associated with seismic events and operational plant conditions that exceed 0.8 x (SH + Sa). Intermediate break locations would not be postulated where the expansion stress exceeds 0.8 Sa. Thermal stresses are classified as secondary, and taken in absence of other stresses, do not cause ruptures in pipes. Actual stresses used for comparison to the break thresholds are calculated in accordance with the ONS piping code of record, USAS B31.1.0 (reference 48). Allowable stress values Sa and SH shall be determined in accordance with the USAS B31.1.0 code or the USAS B31.7 code (reference 49). The scope of piping effected by this proposal is seismically analyzed lines within the TB and AB including the containment penetration rooms.

This approach was first communicated in a letter to the NRC dated July 3, 2002 (reference 52).

This provision is similar to that given in the BTP MEB 3-1 Rev. 2 Section B.1.c (2) (reference 19). The approach to eliminate arbitrary intermediate breaks by the adoption of GL 87-11, and by reference BTP MEB 3-1 Revision 2 Section B.1.c (2) (reference 19) has been previously approved for portions of the low pressure injection (LPI) system at ONS as part of the Passive LPI Cross Connection Modifications (reference 50).

Although adoption of GL 87-11 implies a reduction in the number of break locations, the re-evaluation and inclusion of the proposed portions of BTP MEB 3-1 revision 2 in the ONS HELB design and LB results in an actual increase in the number of postulated HELB locations outside of the containment building when compared to the number postulated in the original HELB MDS OS-73.2 report. Each of these new locations require that ONS formulate a mitigation strategy.

These actions enhance the ability of the plant to mitigate any break that could possibly occur. In doing this, the overall safety of the plant is improved.

As noted above, ONS plans to adopt the provisions of BTP MEB 3-1 regarding the elimination of arbitrary intermediate breaks for analyzed lines that include seismic loading. Adoption of this provision allows ONS to focus attention to those high stress areas that have a higher potential for catastrophic pipe failure. Breaks for analyzed lines that do not contain seismic loading and breaks for non-analyzed lines are postulated at every piping weld and fitting. The inclusion of this approach provides a comprehensive break scenario for which mitigation strategies are determined. These actions enhance the overall safety of the plant.

3.4.2 Determination of Jet Impingement Effects NUREG/CR-2913 describes the method for determination of jet impingement effects following a HELB. However, Duke Energy requests NRC approval to use the NUREG for determination of the effects from breaks and critical cracks.

Giambusso/Schwencer does not provide any direction on the methodology to be used to determine potential impingement effects from critical cracks. The NUREG provides an analytical model for predicting two-phase, water jet loadings on axisymmetric targets. Input to the model includes the initial system pressure, temperature (or alternatively steam quality), diameter of the break opening, distance to the target, and radius from the centerline of the target. The model 13

License Amendment Request August 28, 2019 ranges in application from 60 bars (870 psi) to 170 bars (2465 psig) pressure and 70 degrees Centigrade (158 degrees Fahrenheit) subcooled liquid to 0.75 (or greater) steam quality.

Since no guidance for the determination of the zone of influence (ZOI) for critical cracks was promulgated in Giambusso/Schwencer and there is no description of the methodology used for the determination of the ZOI for critical cracks in the original HELB report MDS OS-73.2, the use of the NUREG in the manner described represents a change to the ONS LB for HELB. In absence of definitive studies of the ZOI for critical cracks, the NUREG provides a reasonable methodology that can be adapted for critical cracks.

The MS and MFDW systems are the only two HE systems which had calculated stresses that exceeded the crack threshold, and thus are the only two systems in which critical cracks are postulated. For the MS system the locations where the stresses exceeded the crack threshold are limited to the TB of all three units. For the MFDW system the locations where the stresses exceeded the crack threshold are in both the TB and the EPR of the AB of all three units. The operating pressure and temperatures for the MS and MFDW systems fall within the pressure and temperature ranges described in the NUREG/CR-2913.

3.4.3 Postulation of Critical Cracks Giambusso/Schwencer defines critical cracks as 1/2 the pipe diameter in length and 1/2 the wall thickness in width. Giambusso/Schwencer notes that the critical crack needs to be postulated at the most adverse location. ONS seeks to modify this requirement by incorporating the stress criteria from MEB BTP 3-1 1.e(2) for postulation of leakage cracks for piping that is seismically analyzed (i.e., stress analysis information is available, and the analysis includes seismic loading). Critical cracks would be postulated in Class 2 and Class 3 equivalent piping at axial locations where the calculated stress for the applicable load cases exceed 0.4(Sa + Sh).

Applicable load cases include internal pressure, dead weight (gravity), thermal, and seismic (defined as Operational Basis Earthquake (OBE)). Critical cracks are not postulated at locations of terminal ends. For non-seismically analyzed piping, critical cracks are not postulated, since breaks are postulated at each weld location, which would bound the effect from a critical crack.

3.5 Excluded Systems ONS has excluded some systems from HELB consideration due to the short time these systems operate at HE conditions. No HELB protection is provided if the operating time of a system at HE conditions is less than 1% of the total unit operating time (e.g. EFW, RB spray). For systems meeting this limitation, no breaks or cracks are postulated. This is justified based on the very low probability of a HELB occurring during the limited operating time of these systems at HE conditions.

In addition, ONS has excluded some systems from HELB consideration if the operating time of a system at HE conditions is less than approximately 2% of the total system operating time (e.g.

LPI). This is justified based on the very low probability of a HELB occurring during the limited operating time of these systems at HE conditions.

The 1% or 2% criterion is not contained in Giambusso/Schwencer or the SRP. The proposal to exclude consideration of breaks in HE systems or subsystems that operate for short periods of time at HE conditions is based on the probability of a pipe break actually occurring during this short operational period and precedent established in other licensee submittals. This issue was previously discussed in the March 5, 2007 meeting between Duke Energy and the NRC and a common understanding reached (reference 9: Matrix item H3) (ADAMS Accession Nos.

ML070670206 and ML070670203).

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License Amendment Request August 28, 2019 An example in this regard is located in a SER dated January 4, 1991 (section 4.2.2 of this enclosure) for Tennessee Valley Authoritys Watts Bar Nuclear Plant. The NRC reviewed and approved Appendix 3.6A Definition 6 which notes in part:

Systems may be classified as moderate energy if the total time that the above conditions are exceeded is less than either of the following:

a. One percent of the normal operating life span of the plant

b. Two percent of the time period required for the system to accomplish its design function.

In addition, gas systems (e.g. Nitrogen) and oil systems (e.g. Electrohydraulic Control) have been excluded, since these systems possess limited energy (reference 51).

3.6 Operations Response, Training and Procedures All of the postulated HELBs outside of the containment building are described in calculation entitled, Analysis of Postulated HELBs Outside of Containment.

HELB mitigation is dependent on the location and magnitude of the HELB as well as its interactions with SSD equipment. The consequences of the HELB interactions were reviewed to determine if one HELB could be found that was bounding with respect to operator actions, necessary repairs, manpower requirements and the associated time limits for performing these actions. It was found that HELBs occurring inside the TB have the potential to create the most bounding scenario involving required operator actions, manpower requirements and damage repairs.

The expected actions are described in the discussion below and are based on approval of the revised HELB mitigation strategy, subsequent completion of committed modifications, and revisions to the mitigation and recovery procedures.

3.6.1 Overheating Scenarios 3.6.1.1 FDW HELBs in the TB FDW HELBs that can cause a loss of AC power to all three units coupled with failures to CCW piping resulting in TB flooding will create the bounding overheating scenario for activities necessary to place the units in Mode 5. Such HELBs result in a loss of MFDW and EFW on all three units. No un-isolable breaks occur in either of the MS lines for these HELBs. The plant transient and acceptance criteria are described in section 3.7 of this enclosure and Attachment 6.

Mitigation of these postulated HELBs is divided into four distinct phases. Phase 1 is reactor shutdown and the stabilization of the affected unit(s) in Mode 3 with RC average temperature 525°F. Phase 2 is the plant cooldown from Mode 3 to Mode 4 (< 250oF). Phase 3 is the assessment and repair of SSCs required to transition the unit from Mode 4 (< 250oF) to Mode 5

(< 200oF). Phase 4 is the plant cooldown to Mode 5 (< 200oF).

Phase 1: Reactor Shutdown The postulated MFDW HELB leads to an overheating condition for the RCS. The reactor protective system (RPS) will trip the reactor on the loss of MFDW pumps or on high RCS pressure. The pressurizer code safety valves are credited to relieve pressure to maintain RCS pressure below the acceptance limits. The MSRVs are the only credited means of steam release for DHR during this phase.

Operator actions are needed to restore secondary side DHR and RCP seal cooling to establish a SSD Condition. The SSF and the PSW systems would remain available to establish and 15

License Amendment Request August 28, 2019 maintain SSD for these MFDW HELBs. Emergency procedures direct the operators to initiate both pathways in parallel. The actions taken by the operators have been segregated by the different pathways in which SSD would be achieved and maintained.

Pathway 1: SSD Using PSW Systems

1. The offsite or onsite power source is aligned to the PSW electrical system.

2. The PSW pumps are started and aligned to the affected unit.

3. PSW power is aligned to the A train of HPI and the RCS vent valves.

4. PSW is established to the SGs. This is a new TCA that must be completed within 14 minutes.

5. A PSW powered HPI pump is started and aligned to provide RCP seal cooling. This is an existing TCA that must be completed within 20 minutes.

6. RCS vent valves are opened to establish RCS letdown as required to maintain pressurizer level.

7. RCS boundary valves are closed to isolate potential diversion flow paths (e.g., RCP seal return and normal RCS letdown). These are existing TCAs that must be completed within 15 minutes for RCP seal return isolation and 20 minutes for RCS letdown.

8. PSW power is locally aligned to selected pressurizer heaters and the pressurizer heaters are cycled as required to control RCS pressure.

9. Local actions are taken to prevent flooding of the HPI pump room due to boiloff from the SFP. This is an existing TCA that must be completed between 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months depending upon the amount of decay heat present in the SFP.

10. Control complex and AB cooling is locally restored via the PSW powered alternate chilled water (AWC) system. This is an existing TCA that must be completed between 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months depending upon the area(s) requiring cooling.

11. RBC is locally restored via a diesel powered Alternate RBC pump and a PSW powered RBC unit. This is an existing TCA that must be completed within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

12. The unit is placed in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This is an existing TCA.

Pathway 2: SSD Using SSF Systems

1. Operators are dispatched to the SSF upon recognition of the loss of RCP seal cooling.

2. A breaker transfer is performed at the SSF 600 VAC MCCs to transfer control of selected RCS boundary isolation valves, selected pressurizer heaters and selected RCS instrumentation from the main CR to the SSF.

3. The SSF DG is emergency started and aligned to the SSF electrical system, and the SSF ASW pump is started.

4. The SSF RCMU pump is started to restore RCP seal cooling. This is an existing TCA that must be completed within 20 minutes.

5. RCS boundary valves are closed to isolate potential diversion flow paths (e.g., normal RCS letdown and RCP seal return). These are existing TCAs that must be completed within 15 minutes for RCP seal return isolation and 20 minutes for other RCS isolations.

6. SSF ASW is established to the SGs. This is an existing TCA that must be completed within 14 minutes.

7. Sufficient SSF ASW flow is provided to the SGs to reduce and maintain RCS pressure 2250 psig. This is an existing TCA that must be completed within 20 minutes.

8. SSF powered pressurizer heaters are energized. This is an existing TCA that must be completed within 20 minutes. Once the pressurizer is saturated, the heaters are cycled as required to control RCS pressure.

9. RCS letdown to the SFP is established to control pressurizer level.

16

License Amendment Request August 28, 2019 While the operators are placing the affected unit(s) in Mode 3 with an RC temperature of 525oF, the Operations Shift Manager initiates the Emergency Plan and activates the Technical Support Center and the Operations Support Center. Emergency Preparedness implementing procedures provide guidance to augment staff resources and initiate site damage assessment/repair procedures.

Operators will terminate the TB flooding by tripping all four CCW pumps on all three units within 45 minutes. This action reduces the rate of TB flooding to a flow rate that can be accommodated by the TB drain. This is a new TCA that will be added to the TB HELB mitigation procedure.

Operators monitor the water temperature and water level in the SFP due to the loss of spent fuel cooling as directed by existing emergency procedures. Refill of the SFP is performed using existing site damage repair procedures.

A SSD condition can be maintained from either the Main CR using the PSW and HPI Systems or from the SSF CR using the SSF ASW and SSF RCMU Systems. There are no required repairs from these postulated HELBs to achieve SSD using either the PSW or SSF systems.

However, if makeup to the CCW piping from the CCW intake or discharge via gravity induced flow is not available, a portable pump would need to be installed at the CCW intake to provide replenishment of the water being used by the PSW or SSF systems. Electrical power can be supplied from either the PSW electrical system or the SSF electrical system. Placement of the portable pump in operation must be completed within 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months and 20 minutes of a loss of forced and gravity CCW system flow. This is an existing TCA.

Phase 2: Plant Cooldown to Mode 4 (< 250oF)

Plant cooldown requires one PSW powered HPI pump to provide sufficient makeup capability.

PSW is used to feed the SGs during the plant cooldown. A natural circulation cooldown would be required.

If the unit is being maintained in a SSD condition from the SSF, the RCS inventory control, RCP seal cooling and SG feed functions are transferred from the SSF to the PSW system prior to initiating a cooldown.

Plant Cooldown Sequence to Mode 4:

1. The RV head vents are opened and the RCS loop high point vents are cycled as necessary.

2. The manually operated ADVs are throttled open to establish a cooldown to Mode 4

(< 250oF).

3. PSW flow to the SGs is throttled as required to control SG levels.

4. The A train HPI header discharge valve is throttled open as required to control pressurizer level.

5. The pressurizer power operated relief valve (PORV) is cycled as required to decrease RCS pressure while maintaining RCS subcooling margin during plant cooldown.

6. When RCS pressure is approximately 700 psig, the core flood tank isolation valves are remotely closed from the portable valve control panel. The actions taken to restore power to the CFT isolation valves is contained in the site damage repair procedures.

7. RCS pressure is stabilized at approximately 300 psig by cycling the pressurizer heaters with RCS temperature maintained < 250°F.

8. The RV head vent valves and RCS loop high point vents are closed, and the operating HPI pump is secured as RCP seal cooling is no longer required.

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License Amendment Request August 28, 2019 In this configuration long term subcooled natural circulation DHR conditions are maintained with RC pressure being controlled by the cycling of the pressurizer heaters and RC temperature being maintained < 250°F by natural circulation.

Phase 3: Damage Assessment and Repairs Required to Achieve Mode 5 (< 200oF)

HELB damage assessment is initiated to assess, and repair systems needed to allow plant cooldown from Mode 4 (< 250oF) to Mode 5 (< 200oF). Although the assessment may begin in Phase 1, the systems needed to achieve CSD are not required to be repaired prior to initiating a cooldown of the RCS from Mode 4 to Mode 5. The scope of the assessment determines the availability of the CCW system, the LPSW system, the LPI system, and the associated electrical power to these systems.

The postulated loss of AC power to all three units would require restoring power to one CCW pump motor, two LPSW pump motors (one shared by Units 1 and 2, and one for Unit 3), three LPI pump motors (one for each unit), and the decay heat drop line isolation valves for each unit.

The actions taken to restore power to the pump motors and valves needed for CSD are contained in the site damage repair procedures. The necessary electrical equipment has been identified in these procedures and is available to enable the restoration of power to these motors. Power to the pump motors is provided by 4160 VAC breakers mounted on a portable trailer. Power to the 4160 VAC breaker trailer is provided by a KHU via the CT4 transformer. In addition, two LPSW pump motors would need to be replaced due to the effects of TB Flooding.

There are two spare LPSW pump motors that can be installed using existing station procedures.

The manpower requirements to execute the repairs have been defined in the procedures.

Phase 4: Plant Cooldown to Mode 5 (< 200oF)

Following assessment and repair, the following sequence is used to achieve Mode 5:

1. The CCW system, LPSW systems and LPI systems are locally aligned for operation.

2. One CCW pump is locally started at the 4160 VAC breaker trailer to supply suction to the LPSW pumps.

3. The two LPSW pumps are locally started at the 4160 VAC breaker trailer to provide cooling water to the Unit 1, Unit 2, and Unit 3 LPI coolers.

4. The decay heat drop line valves are remotely opened from the portable valve control panel.

The actions taken to restore power to the drop line valves is contained in the site damage repair procedures.

5. One LPI pump is locally started at the 4160 VAC breaker trailer for each unit.

6. LPSW flow is locally throttled to the LPI coolers to establish the desired cooldown rate.

The guidance to cooldown the plant to Mode 5 is contained in site operating procedures.

3.6.1.2 FDW HELB in the EPR The postulated FDW HELB occurs downstream of the check valve in the EPR of the AB. The station electrical system is not affected by the HELB, and normal plant equipment is used for mitigation. The RPS will trip the reactor on high RCS pressure. The affected SG will completely depressurize following reactor trip resulting in an automatic feedwater isolation system (AFIS) actuation which trips the MFDW pumps and isolates main and emergency FDW to the affected SG. The motor driven EFW pump aligned to the intact SG will auto start on the loss of both MFDW pumps. The transient evolves rapidly to an overheating scenario with one motor driven EFW pump supplying the unaffected SG and all 4 RCPs operating. The bounding scenario assumes that the pressurizer PORV is unavailable to provide RCS pressure control.

The plant transient and acceptance criteria are described in section 3.7 of this enclosure and .

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License Amendment Request August 28, 2019 The guidance to place the affected unit in a SSD condition following a FDW HELB in the EPR is contained in existing emergency procedures. However, the procedures will need to be revised to utilize the RCS high point vent valves, e.g.:

1. Proper actuation of AFIS is verified.

2. Proper operation of the EFW system is verified.

3. One RCP per SG is secured to limit heat input into the RCS. This is an existing procedural action, but is now a new TCA that must be completed within 15 minutes.

4. One set of RCS high point vent valves is cycled as required to maintain an alternate RCS letdown flow path. This is a new procedural action and a new TCA that must be completed within 30 minutes.

Once the affected unit has restored a steam bubble in the pressurizer and RC letdown has been restored, the RCS high point vent valves are closed, and the unit is cooled down to Mode 5 using normal plant systems and procedures.

FDW will collect on the floor of the EPR and when the level exceeds the top of the curb around the flood outlet device, the water will flow out of the AB to the west yard.

If a SAF prevents the HPI system from providing RCP seal cooling, the SSF RCMU system is used to provide RCP seal cooling and RCS inventory control. If a SAF prevents the EFW system from supplying the unaffected SG, HPI forced cooling (e.g., HPI feed and bleed) is utilized to provide core cooling until SSF ASW feed is established to the unaffected SG. If a SAF results in a failure of the control complex (CR, cable spreading room (CSR), equipment room) cooling, the affected unit is maintained in an SSD condition using the SSF RCMU system and the SSF ASW system.

3.6.2 Overcooling Scenarios The bounding scenario is a double MS HELB in the TB resulting in a loss of all AC power and reactor trip (Note: If scenario does not result in a loss of all AC power, the RPS will trip the reactor on a low or variable low RCS pressure). The postulated double MS HELB leads to an overcooling condition for the RCS. The affected unit is stabilized in Mode 3 with RC temperature of approximately 325°F - 350°F.

Mitigation of these postulated overcooling HELBs is also divided into the same four distinct phases as described in section 3.6.1. However, the sequence and timing of certain actions differs due to overcooling and shrinkage of the RCS.

The plant transient and acceptance criteria are described in section 3.7 of this enclosure and .

Phase 1: Reactor Shutdown Operator actions are needed to restore secondary side DHR and RCP seal cooling to establish a SSD Condition. The SSF and the PSW systems would remain available to establish and maintain SSD for these double MS HELBs. Emergency procedures direct the operators to initiate both pathways in parallel. The actions taken by the operators have been segregated by the different pathways in which SSD would be achieved and maintained. Note that the scenario progression times are approximate based on the analyses described in section 3.7 of this enclosure.

Pathway 1: SSD Using PSW Systems

1. The offsite or onsite power source is aligned to the PSW electrical system.

2. The PSW pumps are started and aligned to the affected unit.

3. PSW power is aligned to the A train of HPI and the RCS vent valves.

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License Amendment Request August 28, 2019

4. A PSW powered HPI pump is started and aligned to provide RCP seal cooling. This is an existing TCA that must be completed within 20 minutes

5. Flow is established in the A train HPI header to refill the RCS, restore SCM and recover pressurizer level to 100 inches. This occurs approximately 28 minutes following start of the HPI pump.

6. RCS boundary valves are closed to isolate potential diversion flow paths (e.g., normal RCS letdown and RCP seal return). These are existing TCAs that must be completed within 15 minutes for RCP seal return isolation and 20 minutes for RCS letdown.

7. PSW power is locally aligned to selected pressurizer heaters and the pressurizer heaters are energized as required to establish and maintain RCS pressure at approximately 700 psig. It may take approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to establish saturated conditions in the pressurizer and increase RCS pressure to 700 psig.

8. RCS vent valves are opened to establish RCS letdown as required to control pressurizer level.

9. Once the overcooling has been terminated and the RCS has refilled, PSW is established to the SGs to control RCS temperature at approximately 350°F. This activity may not be initiated until approximately 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months into the scenario.

10. Local actions are taken to prevent flooding of the HPI pump room due to boiloff from the SFP. This is an existing TCA that must be completed between 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months depending upon the amount of decay heat present in the SFP.

11. Control complex and AB cooling is locally restored via the PSW powered AWC system. This is an existing TCA that must be completed between 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months depending upon the area(s) requiring cooling.

12. RBC is locally restored via the PSW powered Alternate RBC system. This is an existing TCA that must be completed within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

13. The unit is placed in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This is an existing TCA.

Pathway 2: SSD Using SSF Systems

1. Operators are dispatched to the SSF upon recognition of the loss of RCP seal cooling.

2. A breaker transfer is performed at the SSF 600 VAC MCCs to transfer control of selected RCS boundary isolation valves, selected pressurizer heaters and selected RCS instrumentation from the main CR to the SSF.

3. The SSF DG is emergency started and aligned to the SSF electrical system, and the SSF ASW pump is started.

4. The SSF RCMU pump is started to restore RCP seal cooling. This is an existing TCA that must be completed within 20 minutes.

5. RCS boundary valves are closed to isolate potential diversion flow paths (e.g., normal RCS letdown and RCP seal return). These are existing TCAs that must be completed within 15 minutes for RCP seal return isolation and 20 minutes for other RCS isolations.

6. The SSF pressurizer heaters are energized to establish and maintain a 100°F subcooling margin. It may take approximately 3.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months for saturated conditions to be established in the pressurizer and approximately 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months for 100°F subcooling margin to be established.

7. Once the overcooling has been terminated and the RCS has refilled, SSF ASW is established to the SGs at a rate necessary to maintain a stable pressurizer level. This activity may not be initiated until approximately 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months into the scenario.

8. Once ASW flow has been throttled to maintain an RCS temperature of approximately 300°F, pressurizer level will continue to increase due to RCP seal injection. RCS letdown to the SFP is established to control pressurizer level. This activity may not be initiated until approximately 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months into the scenario.

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License Amendment Request August 28, 2019 The activities required to cooldown the plant to Mode 4 (< 250oF), perform damage assessment and repairs required to achieve Mode 5 (< 200oF), and cooldown the plant to Mode 5 (< 200oF) are the same as those previously described in section 3.6.1 for the overheating scenario.

3.6.3 Letdown Line Break There is a postulated terminal end break at the letdown line containment penetration #6 in the EPR. This break does not interact with any other SSD equipment but the detection and isolation of the letdown line is important since the isolation of the letdown line terminates the loss of RCS inventory.

The letdown line break results in depressurization of the RCS as primary inventory is lost through the break and a reactor trip is initiated on either the low RCS pressure or on variable low pressure trip function. Continued RCS depressurization results in the RCS pressure decreasing to the ES actuation point. The ES system actuation isolates the break by closing valves HP-3 (A letdown cooler outlet and containment isolation valve) and HP-4 (B letdown cooler outlet and containment isolation valve). If a SAF of either HP-3 or HP-4 occurs (failure to close), procedural guidance directs the operators to close HP-1 (A letdown cooler inlet isolation valve) or HP-2 (B letdown cooler inlet isolation valve) to isolate the break. The HPI system has adequate capacity to compensate for the leak rate as RCS pressure and pressurizer level recover, RCS subcooling is not lost and the RCPs remain in operation. Following the isolation of the letdown line, unit shutdown would be conducted using the normal shutdown systems.

The following TCAs are identified for timely isolation of primary leakage outside of the containment building, with consideration for providing margin to potential radiological effluent release:

1. Isolate the letdown line break within 20 minutes following ES actuation. This is a new TCA.

2. Start the control room ventilation system (CRVS) Booster Fans within 30 minutes of ES actuation. This is an existing TCA.

3.6.4 HPI Pump Discharge Line Break The postulated terminal end break at the discharge nozzle of the 1,2,3A or 1,2,3B HPI pump will result in flooding of the HPI pump room if not isolated.

The HPI pump provides RCS makeup and RCP seal cooling. A HELB at the discharge nozzle of an operating HPI pump can be quickly diagnosed and isolated. The CR operator will immediately receive the HPI pump discharge pressure low annunciator and the RCP seal header flow low annunciator, the standby HPI pump will auto start, and LDST level will rapidly decrease. Once the break location has been identified, the affected HPI pump will be tripped by the CR operator. A non-licensed operator than locally isolates the leak by closing the remote-operated manual suction valve on the affected HPI pump. Operation of the isolation valve does not require entry into the HPI pump room.

This scenario identified the need for the following TCA:

1. Isolate HPI pump discharge nozzle break within 39 minutes. This is a new TCA.

3.6.5 HPI HELBs in the Penetration Rooms 3.6.5.1 HPI HELBs in the EPR In addition to the RCS letdown line break described above, there are three (3) additional postulated HPI HELBs in the EPR:

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License Amendment Request August 28, 2019

1. A terminal end break on the train A HPI line at containment penetration #9.

2. A terminal end break on the RCP seal injection line at containment penetration #23A.

3. A terminal end break on the RCP seal injection line at containment penetration #23B.

If either one or both seal injection lines break, the operators in the CR will be alerted to the break by RCP seal flow annunciators. The break(s) will then be isolated by closing HP-31 (RCP seal flow control valve) from the CR. If HP-31 fails to close, operators can isolate the break by closing manually operated valves, which are located outside of the break area.

The component cooling (CC) system remains available and RCP seal cooling will not be lost. If the CC system fails due to a SAF, RCP seal cooling will be restored by the SSF RCMU system. If this leak is not isolated within approximately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and 40 minutes, the flood level will exceed the top of the curb around the flood outlet device and the water will flow out of the AB to the west yard. The radiological consequences of the flooding will be insignificant as the water being released to the EPR is from the BWST/LDST. Unit shutdown to the CSD condition would be performed using normal plant systems.

If a break occurs on the train A HPI line, the operators in the CR will be alerted to the break by decreasing LDST level, decreasing pressurizer level, and low HPI header discharge pressure. The break will then be isolated by closing HP-120 (RC volume control valve) from the CR. If HP-120 fails to close, the operator will align RC makeup to the train B HPI line from the CR. An operator can then isolate the break by closing a manually operated valve on the train A HPI line upstream of the break. The break on the injection line can also whip into the two (2) RCP seal injection lines in the EPR and rupture both lines. The CC system remains available and RCP seal cooling will not be lost. Isolation of these breaks is described above. If the CC system fails due to a SAF, RCP seal cooling will be restored by the SSF RCMU system as described above. If this leak is not isolated in approximately 10 minutes, the flood level will exceed the top of the curb around the flood outlet device and the water will flow out of the AB to the west yard. The radiological consequences of the flooding will be insignificant as the water being released to the EPR is from the BWST/LDST. Unit shutdown to the CSD condition would be performed using normal plant systems. No T-H analyses were performed for these breaks in the EPR.

3.6.5.2 HPI HELBs in the West Penetration Room There are two (2) postulated HPI HELBs in the west penetration room (WPR):

1. A terminal end break on the RCP seal injection line at containment penetration #10A.

2. A terminal end break on the RCP seal injection line at containment penetration #10B.

These breaks would be isolated as described above for the seal injection line breaks in the EPR. The CC system remains available and RCP seal cooling will not be lost. If the CC system fails due to a SAF, RCP seal cooling will be restored by the SSF RCMU system. If this leak is not isolated within approximately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and 4 minutes, the flood level will exceed the top of the flood barrier located in front of the exit door from the WPR to the west yard and the water will flow out of the AB to the west yard. The radiological consequences of the flooding will be insignificant as the water being released to the WPR is from the 22

License Amendment Request August 28, 2019 BWST/LDST. Unit shutdown to the CSD condition would be performed using normal plant systems. No T-H analyses were performed for these breaks in the WPR.

3.6.6 Training Operators receive classroom, simulator (including the SSF simulator) and on-the-job training for the emergency procedures and abnormal procedures (APs) during the initial licensed operator training program. Licensed operators maintain their proficiency with these procedures and their skill in placing the plant in a SSD condition using the simulator through participation in the licensed operator continuing training program. Non-licensed operators receive training on their emergency procedure and AP related tasks through participation in the non-licensed operator initial and continuing training programs. Also, licensed and non-licensed operators may be evaluated on SSF time critical tasks using job performance measures during their annual operating exam that is part of the operator requalification program.

For implementation of this LAR, both shift licensed operators and non-licensed operators will receive applicable training on the modifications associated with the new HELB strategy.

Emergency procedures and APs will be revised to reflect the change in HELB mitigation strategy. Licensed operators and non-licensed operators will be trained on the revised procedures. These changes and training will be completed as part of implementation of this license amendment.

3.6.7 Procedures and Verification The emergency procedures will be revised to provide the guidance required to place the HELB affected unit in an SSD condition.

All ONS emergency operating procedures (EOPs) and APs changes go through a rigorous verification and validation process governed by operations administrative procedures. The purpose of the verification and validation process is to ensure that the procedures used to mitigate, and correct abnormal and emergency conditions meet certain criteria. These criteria include written correctness, accurate technical content, usability, and operational correctness.

Procedure validation provides assurance that the procedure contains sufficient and understandable operator information and is compatible with plant response, equipment accessibility, plant hardware, and shift manpower. Procedures are validated using a table top setting, in the field, and/or on the training simulator, including the SSF simulator for the SSF procedure. Procedure validation also ensures that TCAs can be completed within the required time.

The new proposed TCAs included in Attachment 11 to this LAR have been reviewed by the SRO responsible for managing the operations TCA program and the previously licensed SRO responsible for maintaining the APs and EOPs. This qualitative assessment included a review of the impact of the TCA to the applicable operating procedure, the time available before the action is required, the time required to complete the action, the required staffing, the complexity/feasibility of the action, the plant condition at the time the action is required, and the adequacy of existing operator skill and knowledge to perform the TCA. These reviews provide additional assurance that these TCAs can be successfully performed within the prescribed times. The assessment of these new proposed TCAs is provided in Attachment 12.

Approved TCAs are managed in accordance with an administrative procedure that provides guidance on how to identify TCAs and control these actions to assure the required times can be met. TCAs without excess margin are re-validated approximately every five years to verify the ability to accomplish the actions with margin.

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License Amendment Request August 28, 2019 Unless noted, all TCAs described in this section are existing TCAs that have been previously reviewed and approved as documented in OSS 0254.00-00-4005, Design Basis Specification for the DBEs. The HELB credited TCAs are summarized in Attachment 11.

3.7 Thermal Hydraulic Analysis The analyses assess the new LB of the PSW system, the SSF, and normal plant systems as the assured mitigation paths following a HELB outside of the containment building. The HELBs considered in these analyses are MS HELBs and FDW HELBs outside of the containment building.

Direct effects from some HELBs inside the TB can impact the electrical distribution system that provides power to both safety related and non-safety related equipment. In addition, some HELBs can result in the loss of secondary systems needed for continued plant operation. The effects can result in any combination of the following:

Loss of the 230 kV red and yellow buses (similar to a loss of offsite power (LOOP))

Loss of the standby buses

Loss of the 4160 VAC main feeder buses

Loss of the 6900 VAC buses

Loss of condensate/MFDW system Any interaction on the above equipment due to consequential effects from postulated HELBs is assumed to result in its immediate loss at the time of the break. If there are no consequential effects on the above equipment, the equipment is assumed to remain in operation during the transient analyses.

The HELB analyses consider the possibility that either the condensate, MFDW or MS piping located outside of the containment building in either the TB or EPR could be faulted. The overheating analysis considers a faulted MFDW line while assuming the MS lines remain intact to maximize the overheating. The overcooling analysis considers a faulted MS line while assuming the MFDW lines remain intact to maximize the overcooling. Both the overheating and overcooling analyses consider the possibility that the HELB causes damage that may result in the loss of onsite emergency power sources.

The RCS T-H analyses evaluate the ability to mitigate HELBs in the TB for the ONS using normal plant equipment, SSF, and PSW mitigation. The initiating event for the HELB scenario is either a MS HELB or FDW HELB in the TB that causes an immediate loss of 4160 VAC power, resulting in an immediate reactor trip and turbine trip. The RCPs continue to operate until operator action is taken to trip them either 2 minutes after a loss of indicated subcooled margin, 3 minutes after a loss of RCP seal cooling, or through established procedural guidance. Offsite power or Keowee may be available for this scenario, enabling PSW equipment to be available to mitigate the plant transient.

The RCS T-H analyses also evaluates the ability to mitigate HELBs in the EPR for the ONS using normal plant equipment mitigation. The initiating event for these HELB scenarios does not cause an immediate loss of 4160 VAC power. The RCPs continue to operate until operator action is taken to trip them either 2 minutes after a loss of indicated subcooled margin, 3 minutes after loss of RCP seal cooling, or through established procedural guidance.

The T-H analyses are performed using either Duke Energys RELAP5/MOD2-B&W ONS T-H model or Duke Energys RETRAN-3D ONS model. The ONS RETRAN-3D model has previously been approved for use in the ONS UFSAR Chapter 6 and Chapter 15 accident analyses. Duke Energys RELAP5/MOD2-B&W model has previously been approved for use in the ONS UFSAR Chapter 6 LOCA mass and energy release analyses.

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License Amendment Request August 28, 2019 The ONS RETRAN-3D model and analysis methods are described in Duke Energys NRC approved methodology reports DPC-NE-3000-PA (reference 21), DPC-NE-3003-PA (reference 22), and DPC-NE-3005-PA (reference 53), and have been modified as described in Attachment 4, to include additional detail and features required to perform these analyses.

The ONS RELAP5/MOD2-B&W model and analysis methods are described in Duke Energys NRC approved methodology report DPC-NE-3003-PA (reference 22) and have been modified, as described in Attachment 4, to include additional detail and features required to perform these analyses.

3.7.1 HELB Mitigation - Acceptance Criteria.

The acceptance criteria are as follows:

Successful mitigation of a HELB condition at ONS shall be defined as meeting the following criteria to ensure that the integrity of the fuel and RCS remains unchallenged.

The following criteria are validated for the overheating analyses to demonstrate acceptable results.

The core must remain intact and in a coolable core geometry.

Minimum Departure from Nucleate Boiling Ratio (DNBR) meets specified acceptable fuel design limits.

RCS pressure must not exceed 2750 psig (110% of design).

In addition to the criteria specified above, the following criteria are validated for the most limiting overcooling analyses to demonstrate acceptable results.

The SG tubes remain intact.

RCS remains within acceptable pressure and temperature limits.

The two additional criteria validated in the overcooling analysis recognize the thermal stress induced on the RCS and SG materials during the transient evolution. These criteria ensure the thermal stress induced on the RCS materials during the transient evolution does not challenge the integrity of the RCS pressure boundary. The first criteria is required by the OTSG design. The second criteria is validated to ensure the transient response remains within analyzed limits.

3.7.2 HELB Mitigation - Overheating Analysis The postulated condensate and MFDW system piping failures are analyzed for their effects on the ability to achieve and maintain SSD of the affected unit following a HELB. It is assumed that a loss of 4160 VAC power to the affected unit may occur as a result of a HELB located in the TB.

Three sets of overheating analyses scenarios are evaluated for establishing SG heat removal to the unit experiencing the FDW HELB; one with 4160 VAC power available, and two where 4160 VAC power is lost. EFW is credited for cases where 4160 VAC power remains available. For scenarios where 4160 VAC power is lost, two alternatives are evaluated for mitigation strategies using either PSW or SSF equipment.

Analyses have been performed for each of these scenarios, using normal plant, SSF and PSW equipment to evaluate the ONS RCS response to a FDW HELB. The primary objective of the analyses is to demonstrate that the credited systems are capable of meeting the proposed HELB mitigation acceptance criteria for an overheating scenario. The results of the analyses met the acceptance criteria. Details of the overheating analyses are contained in Attachment 6.

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License Amendment Request August 28, 2019 3.7.3 HELB Mitigation - Overcooling Analysis The postulated MS system piping failures are analyzed for their effects on the ability to achieve and maintain SSD of the affected unit following a HELB. It is assumed that a loss of 4160 VAC power to the affected unit may occur as a result of a HELB located in the TB.

Three sets of overcooling analyses scenarios are evaluated for establishing SG heat removal to the unit experiencing the MS HELB; one with 4160 VAC power available, and two where 4160 VAC power is lost. EFW is credited for cases where 4160 VAC power remains available. For scenarios where 4160 VAC power is affected by the HELB, two alternatives are evaluated for mitigation strategies using either PSW or SSF equipment.

One objective of the overcooling analysis is to demonstrate adequate core cooling and establish a basis for mitigation strategies for establishing and maintaining SSD conditions following a MS HELB in the TB or EPR.

A second objective of the overcooling analysis is to demonstrate the SG tubes remain intact and the RCS remains within acceptable pressure and temperature limits.

Analyses have been performed for each of these scenarios using normal plant, SSF and PSW equipment to evaluate the ONS RCS response to a MS HELB. The primary objective of the analyses is to demonstrate that the credited systems are capable of meeting the proposed HELB mitigation acceptance criteria for an overcooling scenario. The results of the analyses met the acceptance criteria. Details of the overcooling analyses are contained in attachment 6.

4 REGULATORY EVALUATION 4.1 Applicable UFSAR UFSAR Section 3.6.1 (Postulated Piping Failures in Fluid Systems Inside and Outside Containment), denotes that the analysis of effects resulting from postulated piping breaks outside of the containment building is contained in Duke Power MDS Report No. OS-73.2 dated April 25, 1973 including revision through Supplement 2. The proposed changes specified in Section 2.5 of the LAR will revise this section of the UFSAR. The proposed changes reflect a revised licensing strategy that credits normal plant equipment, the SSF, and the PSW system as assured SSD pathways for HELB mitigation.

UFSAR 3.11.1.2 (Environmental Conditions) - The postulated harsh environmental conditions resulting from a LOCA or HELB inside the RB and a HELB outside the RB are identified and discussed in the ONS Environmental Qualification Criteria Manual. The proposed changes will not affect this section of the UFSAR.

UFSAR 5.1.2.4 (Natural Circulation) - Natural circulation provides an acceptable method of energy removal from the core with transfer of energy to the secondary system through the SGs.

The proposed changes will clarify that minor reductions in temperature to stabilize the plant do not constitute a natural circulation cooldown requiring the RCS head vents to be open.

UFSAR 5.4.8.6.1 (Replacement Steam Generator LOCA Analysis) - For the replacement SG RCS structural analysis, ten HELBs are identified and considered. The proposed changes will not affect this section of the UFSAR.

UFSAR 9.6, (Standby Shutdown Facility) - SSF houses stand-alone systems that are designed to maintain the plant in a safe and stable condition following postulated emergency events that are distinct from the design basis accidents and DBEs for which the plant systems were originally designed. The system provides additional "defense in-depth" protection for the health and safety of the public by serving as a backup to existing safety systems. The proposed changes will revise this section of the UFSAR as specified in Section 2.5 of the LAR. The 26

License Amendment Request August 28, 2019 proposed changes reflect a revised licensing strategy that credits the SSF as an assured SSD path for HELB mitigation.

UFSAR 9.7, (Protected Service Water) - PSW is designed as a standby system for use under emergency conditions. The PSW System provides added "defense-in-depth" protection by serving as a backup to existing safety systems and as such, the system is not required to comply with single failure criteria. The PSW System is provided as an alternate means to achieve and maintain SSD conditions for one, two or three units following certain postulated scenarios. The proposed changes will revise this section of the UFSAR as specified in Section 2.5 of the LAR. The proposed changes reflect a revised licensing strategy that credits the PSW system as an assured SSD path for HELB mitigation.

UFSAR 10.4.7.1 (EFW Design Bases) states that the effects of HELBs have been analyzed as addressed in UFSAR Section 3.6.1.3. The proposed change is editorial.

UFSAR 10.4.7.2.1 (Motor Driven EFW Pumps) states that the Motor Driven EFW Pumps are powered from the 4160 VAC switchgear TD and TE. The switchgear are located side by side on the ground floor of the TB and are not protected from HELBs. The proposed changes will not affect this section of the UFSAR.

UFSAR 10.4.7.3.2 (EFW Response Following a HELB) describes the mitigation strategies for HELBs resulting in a loss of TC, TD, and TE switchgear, FDW/MSLBs causing loss of SG pressure boundary, and other Condensate/FDW line breaks that result in a loss of condenser hotwell inventory. The proposed changes will revise this section of the UFSAR as specified in Section 2.5 of the LAR. The proposed changes reflect a revised licensing strategy that credits normal plant equipment, the SSF, and the PSW system as assured SSD pathways for HELB mitigation.

4.2 Precedent The NRC has previously approved changes similar to the proposed changes in this LAR. The following plants submitted HELB methodology related LARs that have been reviewed and approved:

4.2.1 Donald C. Cook Units 1 and 2: Application dated April 6, 2000 (ADAMS Accession No. ML003702066); NRC Safety Evaluation dated November 21, 2000 (ADAMS Accession No. ML003770373).

4.2.2 Tennessee Valley Authority, Watts Bar Nuclear Plant, Units 1 and 2, Safety Evaluation Report Supplement 6 (SSER 6), Section 6, Protection Against Dynamic Effects Associated with the Postulated Rupture of Piping, dated April 1991.

4.2.3 Florida Power Corporation (Now Duke Energy), submittal for Crystal River Unit 3, dated December 18, 1989. The submittal was approved by the NRC on April 11, 1990.

4.3 Significant Hazards Consideration Duke Energy has evaluated whether a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, Issuance of Amendment, as discussed below:

1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

Justification: A High Energy Line Break (HELB) does not constitute a previously-evaluated accident. HELB is a design criterion that is required to be considered in the 27

License Amendment Request August 28, 2019 design of structures, systems, or components and is not a design basis accident or design basis event. The possibility of HELBs is appropriately considered in the UFSAR and Duke Energy has concluded that the proposed changes do not increase the possibility that a HELB will occur or increase the consequences from a HELB. This LAR provides an overview of HELB reanalysis, descriptions of station modifications that will be made as a result of the HELB reanalysis, and the proposed mitigation strategies which now includes normal plant equipment, the protected service water (PSW) system, and the standby shutdown facility (SSF). The PSW and SSF Systems are designed as standby systems for use under emergency conditions. With the exception of testing, the systems are not normally pressurized. The duration of the test configuration is short as compared to the total plant (unit) operating time. Due to the combination of the infrequent testing and short duration of the test, pipe ruptures are not postulated or evaluated for these systems.

Other systems have also been excluded based on the infrequency of those systems operating at high energy conditions. Consideration of HELBs is excluded (both breaks and cracks) if a high energy system operates for less than 1% of total unit operating time such as emergency feedwater or reactor building spray or if the operating time of a system at high energy conditions is less than approximately 2% of total system operating time such as low pressure injection. This is acceptable based on the very low probability of a HELB occurring during the limited operating time of these systems at high energy conditions. Gas and oil systems have been excluded, since these systems also possess limited energy.

The modifications associated with the HELB licensing basis will be designed and installed in accordance with applicable quality standards to ensure that no new failure mechanisms, malfunctions, or accident initiators not already considered in the design and licensing basis are introduced. For Turbine Building HELBs that could adversely affect equipment needed to stabilize and cooldown the units, the PSW System or SSF provides assurance that safe shutdown can be established and maintained. For Auxiliary Building HELBs, normal plant systems or the SSF provides assurance that safe shutdown can be established and maintained.

As noted in Section 3.4, Oconee Nuclear Station plans to adopt the provisions of Branch Technical Position (BTP) Mechanical Engineering Branch (MEB) 3-1 regarding the elimination of arbitrary intermediate breaks for analyzed lines that include seismic loading. Guidance in the BTP MEB 3-1 is used to define crack locations in analyzed lines that include seismic loading. Adoption of this provision allows Oconee Nuclear Station to focus attention to those high stress areas that have a higher potential for catastrophic pipe failure. In absence of additional guidance, Duke Energy uses NUREG/CR-2913 to define the zone of influence for breaks and critical cracks that meet the range of operating parameters listed in NUREG/CR-2913. NUREG/CR-2913 provides an analytical model for predicting two-phase, water jet loadings on axisymmetric targets that did not exist prior in the Giambusso/Schwencer requirements.

In conclusion, the changes proposed will increase assurance that safe shutdown can be achieved following a HELB. The changes will also collectively enhance the stations overall design, safety, and risk margin; therefore, the proposed change does not involve a significant increase in the probability or consequence of an accident previously evaluated.

2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

28

License Amendment Request August 28, 2019 Response: No.

Justification: A HELB does not constitute a previously-evaluated accident. HELB is a design criterion that is required to be considered in the design of structures, systems, or components and is not a design basis accident or design basis event. The possibility of HELBs is appropriately considered in the UFSAR and Duke Energy has concluded that the proposed changes do not increase the possibility that a HELB will create a new or different kind of accident. This LAR provides an overview of HELB analysis, descriptions of station modifications that will be made as a result of the HELB reanalysis, and the proposed mitigation strategies which now include normal plant equipment, the PSW system, and the SSF.

In conclusion, the changes proposed will increase assurance that safe shutdown can be achieved following a HELB. The changes will also collectively enhance the stations overall design, safety, and risk margin; therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does the proposed amendment involve a significant reduction in a margin of safety?

Response: No.

Justification: A HELB does not constitute a previously-evaluated accident. HELB is a design criterion that is required to be considered in design of structures, systems, or components and is not a design basis accident or design basis event. The possibility of HELBs is appropriately considered in the UFSAR and Duke Energy has concluded that the proposed changes do not involve a reduction in the margin of safety. This LAR provides an overview of HELB analysis, descriptions of station modifications that will be made as a result of the HELB reanalysis, and the proposed mitigation strategies which now include normal plant equipment, the PSW system, and the SSF.

The changes described above provide a HELB licensing basis and have no effect on the plant safety margins that have been established through limiting conditions for operation, limiting safety system settings, and safety limits specified in the technical specifications.

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

Based on the above, Duke Energy concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significance hazards consideration is justified.

Conclusion Based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by the proposed revision to the wording in the UFSAR and operation of the unit in the proposed manner, (2) the proposed revision will be implemented in a manner consistent with the commissions regulations, and (3) the issuance of the amendment will not be adverse to the common defense and security or to the health and safety of the public.

5 ENVIRONMENTAL CONSIDERATION Duke Energy has evaluated this LAR against the criteria for identification of licensing and regulatory actions requiring environmental assessment in accordance with 10 CFR 51.21. Duke Energy has determined that this LAR meets the criteria for a categorical exclusion as set forth in 10 CFR 51.22(c)(9). This determination is based on the fact that this change is being proposed as an amendment to a license issued pursuant to 10 CFR 50 that changes a requirement with 29

License Amendment Request August 28, 2019 respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or that changes an inspection or a surveillance requirement, and the amendment meets the following specific criteria:

(i) The amendment involves no significant hazards consideration.

As demonstrated in Section 4.3, this proposed amendment does not involve a significant hazards consideration.

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

The change proposed in this amendment request will enhance and clarify the overall HELB LB. Since the principal barriers to the release of radioactive materials are not modified or affected by this change, no significant increases in the amounts of any effluent that could be released offsite will occur as a result of this proposed change.

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

Because the principal barriers to the release of radioactive materials are not modified or affected by this change, there is no significant increase in individual or cumulative occupational radiation exposure resulting from this change.

Therefore, no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment pursuant to 10 CFR 51.22(b).

6 REFERENCES

1. Letter from A. Giambusso (AEC) to A. C. Thies (Duke Power Company), General Information Required for Consideration of the Effects of a Piping System Break Outside Containment, dated December 15, 1972.

2. Clarification Letter from A. Schwencer (AEC) to A. C. Thies (Duke Power Company),

Clarification Letter, dated January 17, 1973.

3. Letter from Duke Power Company to the AEC, MDS Report No. OS-73.2, Analysis of Effects Resulting from Postulated Piping Breaks Outside Containment for Oconee Nuclear Station, Units 1, 2, & 3, dated April 25, 1973.

4. Letter from Duke Power Company to the AEC, MDS Report No. OS-73.2, Supplement 1, Analysis of Effects Resulting from Postulated Piping Breaks Outside Containment for Oconee Nuclear Station, Units 1, 2, & 3, dated June 22, 1973.

5. Letter from Duke Power Company to the AEC, MDS Report No. OS-73.2, Supplement 2, Analysis of Effects Resulting from Postulated Piping Breaks Outside Containment for Oconee Nuclear Station, Units 1, 2, & 3, dated March 12, 1974.

6. Letter from AEC to Duke Power Company, Safety Evaluation Report for Oconee Units 2 &

3, dated July 6, 1973.

7. Problem Investigation Process, Oconee Nuclear Station, O-98-03902 (NCR 1884166),

Investigation of Pipe Rupture Design Basis at the Oconee Nuclear Site (PIP is based upon the CEN Self Assessment O-CEN-013-98).

8. Letter to Mr. James Dyer, Director, Office of Nuclear Reactor Regulation, from Henry B.

Barron, Group Vice President and Chief Nuclear Officer, Nuclear Generation, Duke Energy Corporation, "Tornado/HELB Mitigation Strategies and Regulatory Commitments," dated November 30, 2006.

9. Letter from Leonard N. Olshan, Project Manager, Plant Licensing Branch II-1, Division of Operating Reactor Licensing, USNRC Office of Nuclear Reactor Regulation, to Duke Power 30

License Amendment Request August 28, 2019 Company LLC, Summary of March 5, 2007, Meeting to Discuss the November 30, 2006, Letter Regarding Oconee High-Energy Line Break (HELB) and Tornado Mitigation Strategies, dated March 28, 2007.

10. Letter from Timothy J. McGinty, Deputy Director, Division of Operating Reactor Licensing, USNRC Office of Nuclear Reactor Regulation, to Bruce H. Hamilton, Oconee Nuclear Station, Units 1, 2, and 3 (Oconee) - Tornado and High-Energy Line Break (HELB) Mitigation Strategies, dated May 15, 2007.

11. Letter to the U. S. Nuclear Regulatory Commission from Bruce H. Hamilton, Vice President, Oconee Site, "Revision to Tornado/HELB Mitigation Strategies and Regulatory Commitments," dated June 28, 2007.

12. Letter to the U. S. Nuclear Regulatory Commission from Henry B. Barron, Group Vice President and Chief Nuclear Officer, Nuclear Generation, Duke Energy Corporation, "Revision to Tornado/HELB Mitigation Strategies and Regulatory Commitments," dated January 25, 2008.

13. Safety Evaluation by the Office of Nuclear Reactor Regulation Related to Amendment Nos.

386, 388, and 387, Implementation of the Protected Service Water System, dated August 13, 2014 (Accession Number ML14206A790).

14. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for HELB Events Outside of the Containment Buildings; License Amendment Request No. 2008-005, dated June 26, 2008.

15. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for HELB Events Outside of the Containment Building - Unit 2; License Amendment Request No. 2008-006, dated December 22, 2008.

16. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for HELB Events Outside of the Containment Building; License Amendment Request No. 2008-007, dated June 29, 2009.

17. Letter to the U.S. Nuclear Regulatory Commission from Scott Batson, Vice President, Oconee Site, licensing Basis for the Protected Service Water System - Response to Request for Additional information (RAI) No. 190; Revised Responses to RAI Nos. 134 and 165; License Amendment Request (LAR) 2008 Supplement 8, dated February 14, 2014.

18. Standard Review Plan (SRP) 3.6.2 - Determination of Rupture Locations and Dynamic Effects Associated with the Postulated Rupture of Piping, Rev. 1 - July 1981.

19. NRC Generic Letter 87-11, Relaxation in Arbitrary Intermediate Pipe Rupture Requirements (Rev. 2 of BTP MEB 3-1), June 19, 1987.

20. Letter from U.S. Nuclear Regulatory Commission to Ronald A. Jones, Vice President, Oconee Nuclear Station, Oconee Nuclear Station, Units 1, 2, and 3 Re: Issuance of Amendments, dated June 1, 2004.

21. Duke Energy Methodology Report DPC-NE-3000-PA, Oconee Nuclear Station, McGuire Nuclear Station, Catawba Nuclear Station, Thermal-Hydraulic Transient Analysis Methodology, Revision 5. (Safety Evaluations for Oconee Nuclear Station dated August 8, 1994 (Accession Number ML16293A840); October 14, 1998 (Accession Number ML9810190223); September 24, 2003 (Accession Number ML032670816); October 29, 2008 (Accession Number ML082800408); and July 21, 2011 (Accession Number ML11137A150)).

22. Duke Energy Methodology Report DPC-NE-3003-PA, Oconee Nuclear Station, Mass and Energy Release and Containment Response Methodology, Revision 1. (Safety Evaluations dated March 15, 1995; September 24, 2003 (Accession Number ML032670816)).

31

License Amendment Request August 28, 2019

23. Letter to the U.S. Nuclear Regulatory Commission from Scott Batson, Vice President, Oconee Site, Licensing Basis for the Protected Service Water System - Responses to Request for Additional Information - Supplement 4, dated April 5, 2013.

24. Letter to the U. S. Nuclear Regulatory Commission from Scott Batson, Vice President, Oconee Site, " Response to Requests for Additional Information Regarding PSW Cabling Aging Management Program and FANT Line Supply to PSW Degraded Voltage Protection; License Amendment Request (LAR) 2008 Supplement 11, dated July 24, 2014.

25. Letter to the U. S. Nuclear Regulatory Commission from Scott Batson, Vice President, Oconee Site, " License Condition for the Unit 3 High Energy Line Break (HELB); License Amendment Request (LAR) 2008-07; Supplement 10, dated April 11, 2014.

26. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Responses to Request for Additional Information for the License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for High Energy Line Break Events Outside of the Containment Building; License Amendment Request No. 2008-007, dated October 23, 2009.

27. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Tornado Mitigation License Amendment Request - Response to Request for Additional Information, dated June 24, 2010.

28. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Tornado Mitigation License Amendment Request - Response to Request for Additional Information, dated August 31, 2010.

29. Letter to the U.S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, High Energy Line Break License Amendment Request - Response to Request for Additional Information, dated December 7, 2010.

30. Letter to the U.S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, Tornado and High Energy Line Break (HELB) Mitigation License Amendment Requests (LARs) - Responses to Request for Additional Information, dated December 16, 2011.

31. Letter to the U.S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, Tornado and High Energy Line Break (HELB) License Amendment Requests (LARs) - Supplemental Responses to Request for Additional Information (RAI)

Nos. 61, 62, and 107, dated January 20, 2012.

32. Letter to the U.S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, Tornado and High Energy Line Break License Amendment Requests - Supplemental Responses to Request for Additional Information Nos. 70, 76, and 106, dated March 1, 2012.

33. Letter to the U.S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Responses to Request for Additional Information for the License Amendment Requests to Revise Portions of the Updated Final Safety Analysis Report Related to the Tornado Licensing Basis, dated September 2, 2009.

34. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, "Revision to Tornado/HELB Mitigation Strategies and Regulatory Commitments," dated November 18, 2008.

35. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, "Revision to Tornado/HELB Mitigation Strategies and Regulatory Commitments," dated May 18, 2010.

36. Letter to the U. S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, "Revision to Tornado/HELB Mitigation Strategies Regulatory Commitments," dated July 29, 2011.

32

License Amendment Request August 28, 2019

37. Letter to the U. S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, "Revision to Tornado/HELB Mitigation Strategies and Regulatory Commitments," dated February 21, 2012.

38. Letter to the U. S. Nuclear Regulatory Commission from Scott Batson, Vice President, Oconee Site, "Revision to Tornado/HELB Mitigation Strategies and Regulatory Commitments 8T, 10T, 17T, and 25H," dated December 19, 2013.

39. Letter to the U. S. Nuclear Regulatory Commission from Thomas Ray, Vice President, Oconee Site, "Revision to Tornado/HELB Mitigation Strategies and Regulatory Commitments," dated November 15, 2017.

40. Letter to the U. S. Nuclear Regulatory Commission from Dave Baxter, Vice President, Oconee Site, Request for Additional Information (RAI) Regarding the Licensee Amendment Request for Upgrading the Licensing Basis for Tornado Mitigation, dated June 10, 2010.

41. Letter to the U. S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, Tornado and High Energy Line Break Mitigation License Amendment Requests - Response to Request for Additional Information for Item No. 109, dated March 16, 2012.

42. Letter to the U. S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, "Request for Additional Information (RAI) Regarding the License Amendment Requests (LARs) for the Licensing Basis for the Protected Service Water System, dated June 11, 2012.

43. Letter to the U. S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, " Licensing Basis for the Protected Service Water System -

Responses to Request for Additional Information - Supplement 1, dated July 20, 2012.

44. Letter to the U. S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, " Licensing Basis for the Protected Service Water System -

Responses to Request for Additional Information - Supplement 3, dated November 2, 2012.

45. Letter to the U. S. Nuclear Regulatory Commission from Scott Batson, Vice President, Oconee Site, " Licensing Basis for the Protected Service Water System - Responses to Request for Additional Information - Supplement 5, dated June 28, 2013.

46. Letter to the U. S. Nuclear Regulatory Commission from Scott Batson, Vice President, Oconee Site, " Licensing Basis for the Protected Service Water System - Updated Responses to Request for Additional Information Item Nos. 107, 109(a), and 109(b) -

Supplement 6, dated August 7, 2013.

47. Letter to the U. S. Nuclear Regulatory Commission from Scott Batson, Vice President, Oconee Site, " Licensing Basis for the Protected Service Water System - Responses to Request for Additional Information Item Nos. 172 through 189 - Supplement 7, dated December 18, 2013.

48. USAS B31.1.0, 1967 Edition, Power Piping

49. USAS B31.7, February 1968 Edition including Errata of June 1968, Code for Pressure Boundary Piping, Nuclear Power Piping.

50. Letter from U.S. Nuclear Regulatory Commission to Ronald A. Jones, Vice President, Oconee Nuclear Station, Oconee Nuclear Station, Units 1, 2, and 3 Re: Issuance of Amendments, dated September 29, 2003.

51. OSC-8385, Normal Operating Conditions for High Energy Line Break (HELB) Analysis (ONS Units 1, 2, & 3).

52. Letter to the U. S. Nuclear Regulatory Commission from W. R. McCollum, Jr., Vice President, Oconee Site, High-Energy Line Break Outside Reactor Building Methodology, dated July 3, 2002.

53. Duke Energy Methodology Report DPC-NE-3005-PA, Oconee Nuclear Station, UFSAR Chapter 15 Transient Analysis Methodology, Revision 5. (Safety Evaluations dated October 33

License Amendment Request August 28, 2019 1, 1998; May 25, 1999; September 24, 2003; October 29, 2008; July 21, 2011 (Accession Number ML11137A150); and April 29, 2016 (Accession Number ML16088A330)).

54. BAW-10164P-A, Revision 4, "RELAP5/MOD2-B&W - An Advanced Computer Program for Light-Water Reactor LOCA and Non-LOCA Transient Analysis", Framatome ANP, November 2002.

55. Letter J. F. Stolz (NRC) to H. B. Tucker (Duke),

Subject:

NUREG-0737 ITEM II.K.3.30, SMALL BREAK LOCA METHODS, Re: Oconee Nuclear Station, Units 1, 2 and 3, Dated:

July 29, 1985. (Safety Evaluation Report for the BABCOCK AND WILCOX OWNERS GROUP SMALL BREAK LOSS-OF-COOLANT ACCIDENT EVALUATION MODEL, CRAFT2 (REV. 3) (BAW-10092P, REV. 3 AND BAW-10154)).

56. Evaluation of SBLOCA Operating Procedures and Effectiveness of Emergency Feedwater Spray for B&W-Designed Operating NSSS, Document No. 77-1141270-00, Babcock &

Wilcox, Lynchburg, Virginia, February 1983.

57. ONS Reload Design Methodology, NFS-1001-A, Duke Energy, Safety Evaluation dated July 21, 2011.

58. Letter, S. A. Richards (NRC) to G. L. Vine (EPRI), Safety Evaluation Report on EPRI Topical Report NP-7450(P), Revision 4, RETRAN-3D - A Program for Transient Thermal-Hydraulic Analysis of Complex Fluid Flow Systems, January 25, 2001.

59. Oconee Nuclear Design Methodology Using CASMO-4 / SIMULATE-3, DPC-NE-1006-PA, Duke Energy, Safety Evaluation dated August 2, 2011.

60. Letter to the U. S. Nuclear Regulatory Commission from T. Preston Gillespie, Jr., Vice President, Oconee Site, Licensing Basis for the Protected Service Water System -

Responses to Request for Additional Information - Supplement 2, dated August 31, 2012.

61. Letter to the U. S. Nuclear Regulatory Commission from Scott Batson, Vice President, Oconee Site, " Licensing Basis for the Protected Service Water (PSW) System - Response to Request for Additional Information (RAI) Nos. 191-194; License Amendment Request (LAR) 2008 Supplement 9, dated April 3, 2014.

7 ACRONYMS AB Auxiliary Building ADV Atmospheric Dump Valve AEC Atomic Energy Commission AFIS Automatic Feedwater Isolation System AP Abnormal Procedure ASB Auxiliary Systems Branch ASME American Society of Mechanical Engineers ASW Auxiliary Service Water AWC Alternate Chilled Water B&PV Boiler and Pressure Vessel BTP Branch Technical Position BWST Borated Water Storage Tank CC Component Cooling CCW Condenser Circulating Water CET Core Exit Temperatures 34

License Amendment Request August 28, 2019 CLB Current Licensing Basis CR Control Room CRD Control Rod Drive CRVS Control Room Ventilation System CSD Cold Shutdown CSR Cable Spreading Room DBE Design Basis Event DC Direct Current DG Diesel Generator DHR Decay Heat Removal DNB Departure from Nucleate Boiling DNBR Departure from Nucleate Boiling Ratio Duke Energy Duke Energy Carolinas, LLC EFW Emergency Feedwater EPR East Penetration Room ES Engineered Safeguards ESPS Engineered Safeguards Protective System FAC Flow Accelerated Corrosion FDW Feedwater GL Generic Letter HE High Energy HELB High Energy Line Break HFP Hot Full Power HPI High Pressure Injection HVAC Heating, Ventilation, and Air Conditioning IA Instrument Air ICS Integrated Control System KHU Keowee Hydro Unit kV Kilovolt LAR License Amendment Request LB Licensing Basis LC Load Center LDST Letdown Storage Tank LOCA Loss of Coolant Accident 35

License Amendment Request August 28, 2019 LOOP Loss of Offsite Power LPI Low Pressure Injection LPSW Low Pressure Service Water MCC Motor Control Center MDS Mechanical Design Study MEB Mechanical Engineering Branch MFDW Main Feedwater MS Main Steam MSLB Main Steam Line Break MSRV Main Steam Relief Valve MT Magnetic Particle Testing NEI Nuclear Energy Institute NRC Nuclear Regulatory Commission OAC Operator Aid Computer OBE Operational Basis Earthquake OD Outer Diameter ONS Oconee Nuclear Station OTSG Once Through Steam Generator PH Plant Heating PORV Power Operated Relief Valve PSV Pressurizer Safety Valve PSW Protected Service Water PT Penetrant Testing RAI Request for Additional Information RB Reactor Building RBC Reactor Building Cooling RC Reactor Coolant RCMU Reactor Coolant Makeup RCP Reactor Coolant Pump RCS Reactor Coolant System RPS Reactor Protective System RV Reactor Vessel SAF Single Active Failure SBO Station Blackout 36

License Amendment Request August 28, 2019 SER Safety Evaluation Report SFP Spent Fuel Pool SG Steam Generator SRP Standard Review Plan SSC Structure, System, or Component SSD Safe Shutdown SSF Standby Shutdown Facility T-H Thermal Hydraulic TB Turbine Building TBV Turbine Bypass Valves TCA Time Critical Operator Action TS Technical Specification UFSAR Updated Final Safety Analysis Report UST Upper Surge Tank UT Ultrasonic Testing VAC Volts Alternating Current VDC Volts Direct Current WPR West Penetration Room ZOI Zone of Influence 37

ATTACHMENT 1 CONFORMING ACTIONS

License Amendment Request Attachment 1 Conforming Actions The following table identifies the conforming actions (previously commitments) that Duke Energy will take in implementing HELB. Any other statements in this submittal are provided for information purposes and are not considered to be conforming actions. Please direct questions regarding these conforming actions to Timothy Brown, ONS Regulatory Projects Group, at (864) 873-3952.

Previous Commitment Action Completion Date 26H In order to mitigate the postulated HELB on the letdown line, Two refueling the inlet isolation valves to the Unit 1 letdown coolers on the outages after letdown line (1HP-1 & 1HP-2) will be upgraded to permit their issuance of the use following a postulated HELB on the letdown line at SER.

containment penetration #6. With these valves upgraded, the letdown flow path could be isolated if either of the inboard containment isolation valves (1HP-3 & 1HP-4) fail to close.

27H The Unit 1 control complex cooling is being upgraded to *Three refueling address the potential propagation of the HELB generated outages after environment in the EPR to the Unit 1 control complex. issuance of the SER.

30H TB structural support columns D-24 (Unit 1), D-26 (Unit 1), *Three refueling 44H and M-20 (Unit 1), will be modified to prevent potential failure outages after of the column, when subjected to a pipe whip load. Upgrade issuance of the of columns D-24 and D-26 prevent the loss of the routing to SER.

get temporary cabling to the LPI and LPSW pump motors.

35H The Unit 2 control complex cooling is being upgraded to *Three refueling address the potential propagation of the HELB generated outages after environment in the EPR to the Unit 2 control complex. issuance of the SER.

36H The valves (2HP-103 & 2HP-107) on the individual suction Two refueling lines to the Unit 2 "A" & "B" HPI pumps are being upgraded to outages after allow the remote operation (operated outside the HPI pump issuance of the room) of these valves. The remote operation of these valves SER.

allows the isolation of postulated HELBs on the discharge side of the HPI pumps without compromising the availability of the other HPI Pumps and the need to maintain the LDST aligned to the HPI pump suction piping. For a SAF of either valve 2HP-103 or 2HP-107 to close, a redundant, remotely operated valve is provided on each of the HPI Pumps "A" and "B" to assure HELB mitigation.

38H TB structural support column D-29 (Unit 2), D-31 (Unit 2), and *Three refueling 44H M-35 (Unit 2), will be modified to prevent potential failure of outages after the column, when subjected to a pipe whip load. issuance of the SER.

1

License Amendment Request Previous Commitment Action Completion Date 41H The Unit 3 control complex cooling is being upgraded to *Three refueling address the potential propagation of the HELB generated outages after environment in the EPR to the Unit 3 control complex. issuance of the SER.

44H TB structural support columns D-43 and D-45 (Unit 3), M-49 *Three refueling (Unit 3), and L-47 (Unit 3) will be modified to prevent potential outages after failure of the column(s), when subjected to a pipe whip load. issuance of the SER.

New Install new QA-1 instrumentation or upgrade existing Three refueling instrumentation in the SSF CR for SG pressure, nuclear outages after instrumentation, core exit thermocouples, pressurizer issuance of the temperature, and temperature compensated pressurizer SER.

level. This will provide SSF CR operators with the enhanced ability to monitor and control the plant.

New Eliminate the cross-connection of power from a particular unit Two refueling to another unit for the CRD. This will ensure immediate outages after reactor trip following a postulated MFDW HELB that affects issuance of the the ES switchgear. SER.

New Install a new SSF letdown line in each unit to provide SSF CR Two refueling operators with the ability to control the plant at lower-range outages after RCS pressures. issuance of the SER.

New The SSF related components located in each units AB need Three refueling to be either analyzed or replaced to qualify them for potential outages after harsh environments created by AB HELBs, particularly issuance of the HELBs within the EPR. SER.

New LPSW system valves, 1,2,3LPSW-1119 and 1,2,3LPSW- Three refueling 1120 are vulnerable to damage by certain TB HELBs. A outages after modification is needed to ensure the required LPSW system issuance of the isolations can be made to enable operation of the Alternate SER.

RBC system.

New TCA Validations described in Attachment 12 of this LAR. Three refueling outages after issuance of the SER.

Note that the dates have changed from 2 refueling outages to 3 refueling outages due to the complex nature of the modifications.

2

ATTACHMENT 2 UPDATED FINAL SAFETY ANALYSIS REPORT RED-MARKED CHANGES

License Amendment Request 1

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v t e Letter Sequence Request
EPID:L-2020-LLS-0000, License Amendment Request for Measurement Uncertainty Recapture Power Uprate (Approved, Closed)
Initiation Request, Request Acceptance, Acceptance Supplement Administration Withholding Request Acceptance Questions 10 July 2020 Answers 31 July 2019 Results Approval Other:
MONTHYEAR2020-04-22 [Table View]

RA-19-0253, Proposed License Amendment Request to Revise the Oconee Nuclear Station Current Licensing Basis for High Energy Line Breaks Outside of the Containment Building

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