Text

Emergency Plan Implementing Procedures Manual, Volume C, Revision 2014-003
	ML14037A081
Person / Time
Site:	Oconee
Issue date:	02/04/2014
From:	Batson S; Duke Energy Corp
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	ONS-2014-007, FOIA/PA-2016-0071
	Download: ML14037A081 (106)
	v • d • e

Scott L.Batson Vice President

@ENERGY. Oconee Nuclear Stabon Duke Energy ONOIVP 17800 Rochester wy Seneca, SC 29672 ONS-2014-007 o: 864.873.3274 864.873. 4208 ScottBatson@duke-enefgy.com February 4, 2014 10 CFR 50.54(q)

Attn: Document Control Desk U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville, Maryland 20852-2746

Subject:

Duke Energy Carolinas, LLC Oconee Nuclear"Station, Units 1, 2, and 3 Docket Nos. 50-269, -270, and -287 Emergency Plan Implementing Procedures Manual Volume C, Revision 2014-003

Please find attached for your use and review copies of the revision to the Oconee Nuclear Station Emergency Plan, Implementing Procedures along with the associated revision instructions and 10 CFR 50.54(q) evaluation.

This revision is being submitted in accordance with 10 CFR 50.54(q) and does not reduce the effectiveness of the Emergency Plan or the Emergency Plan Implementing Procedures. Ifthere are any questions or concerns pertaining to this revision please call Pat Street, Emergency Planning Manager, at 864-873-3124.

By copy of this letter, two copies of this revision are being provided to the NRC, Region II, Atlanta, Georgia.

Sincerely, Scott L. Batson Vice President Oconee Nuclear Station Attachments:

Revision Instructions

EPIP Volume C - Revision 2014-007 10 CFR 50.54(q) Evaluation(s) www.duke-energy.com

U. S. Nuclear Regulatory Commission February 4, 2014 xc: w/2 copies of attachments Mr. Victor McCree, Regional Administrator U.S. Nuclear Regulatory Commission - Region II Marquis One Tower 245 Peachtree Center Ave., NE, Suite 1200 Atlanta, GA 30303-1257 w/copy of attachments Mr. Richard Guzman, Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mailstop O-8C2 11555 Rockville Pike Rockville, MD 20852-2738 (send via E-mail) w/o attachments Mr. Eddy Crowe NRC Senior Resident Inspector Oconee Nuclear Station ELL EC2ZF

February 4, 2014 OCONEE NUCLEAR STATION

SUBJECT:

Emergency Plan Implementing Procedures Volume C Revision 2014-003 Please make the following changes to the Emergency Plan Implementing Procedures, Volume C:

REMOVE INSERT Cover Sheet Rev. 2013-15 Cover Sheet Rev. 2014-1 Table of Contents" Table of Contents Pages 1, 2, & 3 Pages 1, 2, & 3 Engineering Manual 5.1 - Rev 030 Engineering Manual 5.1 - Rev 032 Engineering Manual 5.1 Revision 032 replaces revision 030. Revision 031 and Revision 032 did have the appropriate 50.54(q) however the EPlan was not revised until Revision 032 was received. Refer to PIP 0-14-00670.

Pat Street ONS Emergency Planning Manager

~DU ENERGY. KE OCONEE NUCLEAR STATION EMERGENCY PLAN IMPLEMENTING PROCEDURES VOLUME C

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APPROVED:

Terry I(. atterson Organizational Effectiveness Director Date Approved VOLUME C REVISION 2014-003 February 2014

VOLUME C TABLE OF CONTENTS SHIO/B/2005/001 Emergency Response Offsite Dose Projections Rev. 006 SHIO/B/2005/002 Protocol for the Field Monitoring Coordinator Rev. 005 During Emergency Conditions H PO/B/I1009/018 Off-Site Dose Projections Rev. 023 H PIO/B/1 009/020 Estimating Food Chain Doses Under Post- Rev. 005 Accident Conditions HP0/IBI1 009/022 On-Shift Off-Site Dose Projections Rev. 013 H P/O/B/I1009/023 Radiation Protection Emergency Response Rev. 000 HPO/B/I1009/026 Environmental Monitoring For Emergency Rev. 000 Conditions RP/O1A/1000/001 Emergency Classification Rev. 000 O RP/O/A/1000/002 Control Room Emergency Coordinator Procedure Rev. 001 RP/0/B/1 000/002 Control Room Emergency Coordinator Procedure Rev. 025 RP/0/B/1 000/003 A ERDS Operation Rev. 011 RP/0/A/1000/009 Procedure For Site' Assembly Rev. 002 Procedure For Emergency RP/0/A/1000/010 Rev. 001 Evacuation/Relocation Of Site Personnel RPI0/A/1000/015 A Offsite Communications From The Control Room Rev. 001 RP/0/A/1000/015 B Offsite Communications From The Technical Rev. 000 Support Center RP/O/B/1000/016 MERT Activation Procedure For Medical, Rev. 018 Confined Space, and High Angle Rescue Emergencies RP/0/A/1 000/017 Spill Response Rev. 001 RP/O/B/1000/018 Core Damage Assessment Rev. 005 O RP/0/A/1000/019 Technical Support Center Emergency Rev. 003 Coordinator Procedure I Revision 2014-003 January 2014

VOLUME C TABLE OF CONTENTS RPIOIBI1 000/022 Procedure For Major Site Damage Assessment Rev. 014 And Repair RP/O/A/1000/024 Protective Action Recommendations Rev. 001 RPIO/B/1 000/027 Re-Entry Recovery Procedure Rev. 003 RP/01A/1000/028 Nuclear Communications Emergency Response Rev. 000 Plan RP/0/BI1 000/029 Fire Brigade Response Rev. 017 RP/O/B/1000/031 Joint Information Center Emergency Response Rev. 006 Plan RP/OIB/1 000/035 Severe Weather Preparations Rev. 009 SR/OIB/2000/001 Standard Procedure For Corporate Rev. 012 Communications Response To The Emergency Operations Facility

. SR/0/B12000/002 Standard Procedure for EOF Services Rev. 006 SR/OIAI2000/003 Activation of the Emergency Operations Facility Rev. 000 SR/O/A/2000/004 Notification to States and Counties from the Rev. 000 Emergency Operations Facility for Catawba, McGuire, and Oconee Business Business Management Emergency Plan Rev. 012 Management SSG Functional SSG Emergency Response Plan - ONS Specific Rev. 008 Area Directive 102 SCD -110 Supply Chain Directive 110 - SCO Emergency Rev. 004 Response Plan Engineering Engineering Emergency Response Plan Rev. 032 Manual 5.1 Human Resources ONS Human Resources Emergency Plan 10/13/2004 Procedure Radiation Off-Site Dose Assessment And Data Evaluation Rev. 001 Protection Section Manual 11.3 2 Revision 2014-003 January 2014

VOLUME C TABLE OF CONTENTS Safety Assurance Emergency Response Organization Rev. 007 Directive 6.1 Safety Assurance Emergency Contingency Plan Rev. 006 Directive 6.2 Training Division Oconee Training Division Training Standard Rev. 018 DTS-007 3 Revision 2014-003 January 2014

Form 703-1. Procedure Process Record (PPR)

(R0O810) Duke Energy (I)IDNo. EM 5.1

PROCEDURE PROCESS RECORD Revision No. 32 _

PREPARATION (2) Station OCONEE NUCLEAR STATION (3) Procedure Title - Engineering Emergency P nse P (4) Prepared By* John Kaminski (Signature) Date 12/4/2013 (5) Requires NSD 228 Applicability Determinatio

[ Yes (New procedure or revision with major changes) - Att ch NS0228 documentation.

El No (Revision with minor changes)

(6) Reviewed By* '*i&J.AxV*o I C_* 'J , Date _________

Cross-Disciplinary Review By* FT' _-_ -- .(QR)(KI) NA.Ikate 0/*4..t' Reactivity Mgmt Review By* .(QR) NAbA"ate I, A r Mgmt Involvement Review By* (Ops. Supt.) NAbledate 4A! /,,.

(7) Additional Reviews Reviewed By* Date Reviewed By* Date Approved By* 'AIVý Datee PERFORMANCE (Compare with control copy 4ery4 calenda aysw lie work is beingperformeSt)

(9) Compared with Control Copy* Date Compared with Control Copy* Date Compared with Control Copy* Date (10) Date(s) Performed Work Order Number (WO#)

COMPLETION (11) Procedure Completion Verification:

o Unit 0 0 Unit 1 El Unit 2 0 Unit 3 Procedure performed on what unit?

o Yes 0 NA Check lists and/or blanks initialed, signed, dated, or filled in NA, as appropriate?

O Yes 0 NA Required enclosures attached?

O Yes 0 NA Charts, graphs, data sheets, etc. attached, dated, identified, and marked?

o1 Yes 0 NA Calibrated Test Equipment, if used, checked out/in and referenced to this procedure?

O Yes 0 NA Procedure requirements met?

Verified By* Date (12) Procedure Completion Approved Date (13) Remarks (Attach additionalpages, ifnecessary) 0

PrintedName and Signature

ENERGY.

SDUKE Oconee EngineeringNuclear Site Manual Section

Title:

EM &5 - Engineering Emergency Response Plan Revision No.: 32

Reference:

Approved By: J. Ed Burchfield Jr. Approved Date: 12/05/13 Revised By: Carl D. Fago Revised Date: 12/05/13 Reviewed By: David Wilson Original Date: 05/27/92 Effective Date: 12/05/13 Reviewed By: (EP) Pat.M. Street Review Date: 12/05/13 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Document Revision Description REVISION NO. PAGES or SECTIONS REVISED AND DESCRIPTION 1 3.1, 3.2,4.1,4.3,4.4,4.5, 5.1.3, 5.2.2, 5.2.4, 5.2.5, 5.2.6, 6.3, 6.7 7.3.1, 8.3 - General update - Added EOF facility into several steps, clarified Evacuation Coordinator duties, added TSC/OSC Liaison duties, revised site assembly reporting locations, changed "Security Shift Lieutenant" to "Security Shift Supervisor", clarified duties of TSC Offsite Dose Liaison.

2 5.1.2, 5.1.3 - Inserted instructions for swiping badge when assembly inside Protected Area is required.

5.1.3 - 5.1.8 - Renumbered because 5.1.2 was inserted.

3 1.0 - Changed 3 working days to 7 working days 2.0 - Added NSD 117 as a reference 4 - Deleted 4.3 Engineering Section Manager 4.5 - Changed "impassable" to "damaged: use caution" Added requirement to stay within response time.

5.2.2 - Changed title to TSC Eng. Mgr. from MSE Mgr.

6.2 - Changed MSE to MCE 6.5.1,6.5.2 - Changed Nuclear Eng to Reactor Systems Eng 6.6.1,6.6.2, and 6.6.3 - Changed title to TSC Engineering Manager and MSE To MCE 6.6.2 - Added electrical to the support required 6.8 - Added section Primary and BOP Systems Eng duties.

7.3.1, 7.3.2 - Changed CEN to RES General - Changed MG to ED in 3 locations 4 Add Enclosure 9.1 for TSC Guidance Document 5 Minor editorial changes, added Section M and revised 6.8 to only require one engineer.

6 Minor editorial changes, added Section N.

7 Add Section 0 to TSC Guidance Document 8 Editorial changes to Section 0 9 Enclosure 9.1 Section F - Added background information and instructions concerning recovery from a boiling spent fuel pool 10 Revise Section 0 to incorporate PIP 00-2707 CA# 7 11 Editorial Changes Only 12 Added Section P for guidance on depressurizing the reactor building after a loss of DHR event during MODES 5 and 6.

13 Added Section Q for guidance on actions to reduce the effects of RBES screen blockage by debris.

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EM 5.1 14 Revised to insert changes required by PIP 01-2667 for Sections C and N.

Enclosure 9.1, Section C, 3.3 - Reference to AP/1/A/1700/010, Encl. 6.1 replaced by EP/1,2,3/A/1800/001 Encl. 5.31 (T1emporarily Charging the -PSW System).

Enclosure 9.1, Section F, 3.3 - Added "Pool" to the end of "Emergency Plan for Refilling Spent Fuel". MP/O/A/3009/012A replaced by AM/O/A/3009/012A.

Enclosure 9.1, Section G, 3.3 - MP/0/A/13001059 replaced by AM/O/A/1300/059.

Enclosure 9.1, Section H, 3.3 - Reference to EP/I1,2,3/A/1800/001, Section 502 replaced by EP/1,2,3/A/1800/001, Turbine Building Flood Tab.

Enclosure 9.1, Section K, 3.3 - IP/0/A/0050/001 replaced by EMIO/A/0050/001.

15 Enclosure 9.1 Added Section R for guidance on establishing PZR bubble without PZR temperature indication 16 Enclosure 9.1, Added Section S- Alternate HPI Termination Criteria When Operating From the RB Sump 17 Enclosure 9.1, Added Section T - Alternate Water Source for Post-Accident BWST Refill 18 Enclosure 9.1, Revised Table of Contents for section M, changed "CCW Dam" to "Dam/Dike" Enclosure 9.1, Revised Section 2.0 changed "CCW Dam" to "Dam/Dike" and added sections 0 through T.

Enclosure 9.1, Revised Section M - Changed "CCW Dam" to "Dam/Dike". NSM 23107 modified the piping supplying the RBACs; therefore, the list of available LPSW loads was revised (PIP 04-5836).

Enclosure 9.1, Section S -made editorial corrections (PIP 04-5836).

Section 4.4, Updated pager codes.

Section 6.1, Changed sentence to designate Unit 2 Control instead of Unit I or Unit 2.

Section 8.4, Added State/County EOC Liaison position.

19 Enclosure 9.1, Section U - added guidance for mitigating a loss of spent fuel pool level event 20 Enclosure 9.1, added Section V for controlling MS pressure with MS atmospheric dump valves in an SSF event.

Corrected editorial omissions on pages 10 and 12 from revisions 18 and 19.

21 Enclosure 9.1, Section V, Operating Atmospheric Dump Valves during an Accident that Requires Operation of the SSF, was revised to require the affected ADV flow paths to be isolated if the ADVs are being used to control main steam system pressure during an SSF Event and pressure cannot be maintained > = 900 psig. This change is needed because the minimum controllable flow rate for the ADV control valves may be higher than the flow rate needed to control main steam system pressure at low RCS decay heat loads. (Ref. PIP 06-3342)

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EM 5.1 22 Enclosure 9.1, Section V, Operating Atmospheric Dump Valves during an Accident that Requires Operation of the SSF, was revised to include guidance for using permanent pressure gauges 1,2,3MSPG1000 & 1,2,3MSPG1001 that were installed at the ADVs per OD-100713, OD-200714, & OD-300715. Changed Main Steam Safety Valve (MSSV) to Main Steam Relief Valve (MSRV) to be consistent with established nomenclature for these valves.

23 Enclosure 9.1, Section V, Operating Atmospheric Dump Valves during an Accident that Requires Operation of the SSF, was reworked to eliminate use of 10 CFR 50.54x and to utilize new small ADV bypass valves 1,2,3MS-237 & 238 24 Editorial Changes:

- Section 3.2 of Part A (3d Paragraph), changed from "$5 of Reactivity" to "5% of reactivity"

- Section 3.0 of Part H, changed to remove highlight from RB

- Section 4.4, added "pager or", added "ONS Drill (or emergency) followed by security event in progress"

- Section 5.2, added "via E-mail" and "E-mails"

- Section 6.1, added "south entrance of'

- Section 6.4, added "ERO pager and/or" and "after normal working hours"

- Section 7.0, added "south entrance of"

- Section 8.0, changed name of section to "Joint Information Center", replaced "EOF" with "JIC" accordingly in following subsections

- Section 8.2, removed "Offsite Dose Assessment" and renumbered sections accordingly

- Section 8.3, replaced "EOF communications manager" with "JIC Government Agency Liason"

- Section 8.3, added "sign in on board, obtain response bag, and report to applicable state/county EOC"

- Section 3.3 of Part F, changed OP/3/A/1 104/006/E to OP/3/A/I 104/006/C Technical Changes:

- Section 3.2 of Part F, added information concerning mitigating activities during an SFP boiling event as per PIP-O-00-4075 CA #16.

- Added Section 3.1.2 of Part U "Control of Steam Condensation"

- Section 3.2 of Part P, deleted "core alterations or" and added information concerning recently irradiated fuel.

25 Added Part W: GUIDANCE FOR SECURING REACTOR BUILDING SPRAY PUMPS FOLLOWING A LOCA 26 Added Part X: GUIDANCE FOR POTENTIAL LPJ/BS/HPI SEAL FAILURE OR 3A HPI PUMP INTERNAL WEAR FOLLOWING A LOCA.

27 Editorial changes in Sections 4.4, 5.2.1, 5.2.2, 6.4.1, 6.5.2, 8.3.1, (8.3.2 deleted -

information included in 8.3.1) and Enclosure 9.1 as requested by Emergency Response organization.

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EM 5.1 28 Per PIP G-08-15, CA#40, changed TSC guideline part G: Makeup and Monitoring of CCW Inlet Pipe Inventory Per PIP 0-08-5362, CA#1, change TSC guideline part 0: Opening the Alternate Post-LOCA Boron Dilution Flowpath to include guidance concerning Generic Letter 2008-01.

29 Per PIP 0-10-09285 CA # 13 and 18 revise E.M. 5.1 to reflect the responsible group in the new Engineering organization (See Sections 6.2.1, 6.4.1, 6.5.1, 6.5.2, 7.3.1. and 7.3.2) and the change of ownership of the Technical Support Guideline documents (Encl. 9. 1)

Section Q had all references to the old LPI design (Pre LPI Cross Tie mod) removed.

This was in response to PIP 04-05280, CA #3.

Section E was changed to address AREVA document 51-1232710-00 (Referenced in the ONS RCS P/T analyses). This was in response to PIP 09-02545 where it was noted that LPI initiation with no RCP in operation (Natural Circulation) would require a RCS P/T analysis prior to startup.

Enclosure X (GL 04-02 HPI/LPI/BS seal failure or 3A HPI pump wear) was deleted due to completed cyclone separator and HPI pump replacement to support GL 04-02 commitments.

Enclosure J (LPI Pump Interaction) was changed to incorporate LPI and BS flow un-certainty changes. Guidance to throttle BS flow was removed.

Enclosure U (Loss of Spent Fuel Pool Level) step 3.1.3 was changed to note 'doors' instead of a single door (PIP 11-02927) and step 3.1.2 provide the correct location for closing damper (SFP Ventilation Fans) (PIP 11-02928) CA # 32..

30 Per PIP 0-10-2039 CA# 108 revise EM-5.1 (Encl. 9.1 Section E remove reference to Appendix R) to implement NFPA-805.

31 Added Section Y. PIP 12-10969 CA# 59 determine action(s) necessary to support restoration of Spent Fuel Cooling at least when one Unit is in MODE 5, 6 or No Mode.

32 Added Enclosure X, GUIDANCE FOR OBTAINING REACTOR BUILDING HYDROGEN SAMPLE, per PIP 13-14426 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Table of Contents 1.0 PU RPO SE ............................................................................................................................................................ 1 2.0 REFEREN CES ............................................................ ........................................................................................ 1 3.0 D EFINITION S ...................................................................................................................................................... 1 4.0 RESPO N SIBILITIES ........................................................................................................................................... I 5.0 SITE ASSEMBLY AND EVACUATION ...................................................................................................... 2 6.0 TECH NICA L SUPPO RT CEN TER ................................................................................................................... 4 7.0 O PERA TIO NAL SUPPORT CENTER ........................................................................................................ 6 8.0 JOINT INFO RMATION CENTER: .................................................................................................................... 7 9.0 EN CLOSU RES .................................................................................................................................................... 8 Enclosure 9.1 - Oconee Technical Support Center Guideline.......................................................................... 9 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page I of 89 1.0 Purpose The purpose of this directive is to identify The Engineering Division responsibilities during an emergency at Oconee Nuclear Station. This directive is an implementation directive to the site emergency plan.

Upon revision, a copy of this directive must be forwarded to Emergency Planning within seven (7) working days of its approval.

2.0 References

1. Oconee Nuclear Site Emergency Response Plan

2. NSD 117 Emergency Response Organization, Training, and Responsibilities 3.0 Definitions 3.1 Essential Personnel Personnel needed to mitigate the emergency as determined by the EOF, TSC, or OSC.

3.2 Engineering Emergency Response Person Engineering personnel assigned to those positions in the EOF, TSC, or OSC listed in Sections 6.0 and 7.0 of this directive.

4.0 Responsibilities 4.1 Engineering Division Manager The Engineering Division Manager shall be responsible for the implementation of this directive. During a site assembly he/she shall be responsible to account for all engineering personnel to the Security Shift Supervisor or designee.

4.2 Engineering Group Manager During a site assembly each Engineering Group Manager shall be responsible to account for each person in his/her Group to the Engineering Division Manager or designee.

4.3 Engineering Supervisor During a site assembly each Engineering Supervisor shall be responsible to account for each person on his/her team to his/her Engineering Group Manager or designee.

4.4 Engineering Emergency Response Person When notified of EOF/TSC/OSC activation, the engineering emergency response persons will report to their assigned position in the EOF, TSC, or OSC. Notification during normally scheduled work hours will be by pager or an announcement on the station PA system. Notification during unscheduled work hours will be by pager or Nuclear Call Out system using the following:

PAGER CODES:

" ONS Drill - EOF/TSC/OSC activated for a drill.

" ONS Emergency - EOF/TSC/OSC activated for an emergency.

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EM 5.1 Revision No.: 32 Page 2 of 89 jNote: During flooding/dam failure/earthquake conditions assume bridges may be damaged; use caution.

ONS Drill Bridges - Pager message used when bridges may be damaged and EOF/TSC/OSC activation is needed. Use caution.

ONS Emergency Bridges - Pager message used when EOF/TSC/OSC activated for an emergency and the bridges may be damaged; use caution.

ONS Drill (or Emergency) followed by "Security Event in Progress" - All ERO members report to the JIC (In-Processing Center) on Issaqueena Trail in Clemson and await further instructions from the Emergency Coordinator.

Each engineering emergency response person will carry a pager which will be turned on when leaving the station and left on at all times. He/she will remain fit for duty at all times while serving duty as an engineering emergency response person, and will stay within required response times for his/her facility.

For specifics, see NSD 117.

4.5 Employee During a site assembly each employee will proceed to his/her site assembly location (generally the person's work area) and report to his/her supervisor within the specified time.

5.0 SITE ASSEMBLY AND EVACUATION 5.1 Site Assembly 5.1.1 When a site assembly is commenced, a warbling tone will be broadcast over the Station PA system and the outdoor Site Assembly Horn will sound. All Engineering personnel shall immediately proceed to their site assembly location and report to his/her supervisor. Any person who cannot report to his/her designated area within eight (8) minutes of the commencement of the site assembly shall contact his/her supervisor by telephone for assembling instructions.

5.1.2 Personnel inside the Protected Area (PA) who must assemble at a location inside the PA or who cannot make it to their assembly point outside the PA shall card in at the nearest card reader, notify their supervisor of their location, and wait for further instructions.

5.1.3 Personnel working in an RCZ in protective clothing should leave the work area and go to the appropriate Change Room. Once in the Change Room area, they should card in (swipe their security badge) and contact their supervisor for accountability. Personnel should then follow the instructions of the RP personnel' in the Change Room or RCZ.

5.1.4 Each Engineering Section Manager/Supervisor shall account for all personnel in his/her Section/Team and report the result to his/her Engineering Group Manager or designee. Unaccounted for personnel shall be reported by name. This report should be made within 10 minutes of the commencement of the site assembly. Do NOT leave phone mail messages when reporting.

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EM 5.1 Revision No.: 32 Page 3 of 89 5.1.5 Each Engineering Group Manager shall account for all personnel in his/her Group and report the result to the Engineering Division Manager or designee. Unaccounted for personnel shall report by name. This report should be made within 15 minutes of the commencement of the site assembly. Do NOT leave phone mail messages when reporting.

5.1.6 The Engineering Division Manager or designee shall account for all Engineering personnel and report the result to the Security Shift Supervisor or designee. Donnt report unaccounted for personnel by name at this time. This report shall be made within 20 minutes of the commencement of the site assembly.

5.1.7 During unscheduled work hours, each employee on site shall report to his/her assigned assembly area. If a Supervisor is present, the supervisor will call directly to the Security Shift Supervisor and report accountability within 15 minutes. If no Supervisor is present, the senior employee (or lone employee) will call the Security Shift Supervisor directly and report accountability. If working in an RCZ in protective clothing, proceed to the appropriate Change Room. Report to the individual in charge of the change room. If no one is in charge of the change room, call the Security Shift Supervisor directly and report accountability.

5.2 Site Evacuation Instructions Initial Notification:

5.2.1 Site evacuation will be activated only after a site assembly. When it has been deemed necessary to evacuate the site, an announcement will be made on the PA system and evacuation instructions will be placed in the Evacuation Plan via DAE or EP Web Sharepoint.

5.2.2 The Engineering Evacuation Coordinator will access the Evacuation Plan via DAE or EP Web Sharepoint, retrieve evacuation information, pass evacuation information on to Engineering groups, and get acknowledgement back that the information has been received.

The Evacuation Coordinator also lets Engineering Managers know that they need to provide 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months coverage for their areas during the emergency, gets that information from the managers, and relays it to the TSC Engineering manager in the TSC.

5.2.3 The Engineering Section Manager/Supervisors will determine which, if any, essential personnel should not evacuate. This will be based on the needs communicated from the TSC or OSC.

5.2.4 The Engineering Section Managers/Supervisors, based on needs communicated from the TSC or OSC, will establish shift lead persons and a continuous 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months staffing schedule, and communicate this schedule to all personnel in their section/team.

5.2.5 The Engineering Section Managers/Supervisors will give evacuation instructions to all personnel in their sections/teams and implement the evacuation plan.

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EM 5.1 Revision No.: 32 Page 4 of 89 Accountability Notification:

5.2.6 The Engineering Section Managers/Supervisors will report to their respective Engineering Group Manager or designee if transportation assistance is needed. They will report which personnel, if any, have been deemed essential and their location along with their shift lead persons and continuous 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months staffing schedule to the Engineering Evacuation Coordinator and their respective Group Manager.

&2.7 The Engineering Sections Managers/Supervisors or designee will report the status of their sections/teams to the Group Evacuation Coordinator.

NOTE: Subsequent Evacuations will be coordinated from the designated relocation area(s) per NSD 114.

6.0 Technical Support Center 6.1 The Technical Support Center (TSC) is located on the Unit 2 side of the Units 1&2 control room. When reporting to the TSC, pick up ED and TLD, go to the south entrance of Unit 2 Control Room Lobby, and frisk for possible contamination before entering the Control Room.

EMERGENCY RESPONSE RWP NUMBER. 33 (For drills and emergency response)

If evacuation from the TSC becomes necessary, report to the alternate TSC on the third floor, room 316, of the Oconee Office Building. Assume the same duties as in the Primary TSC.

6.2 Technical Assistant to Emergency Coordinator 6.2.1 The Technical Assistant to Emergency Coordinator will report to the Emergency Coordinator. This position is staffed by the Systems and Programs/Component Engineering Section. This position should be staffed within 75 minutes of the emergency declaration.

6.2.2 The Technical Assistant to Emergency Coordinator's main duty will be to maintain a log of activities in the TSC. This log will include systems and components status, decisions, and announcements made in the TSC. The Technical Assistant to Emergency Coordinator will also perform any other duties assigned by the Emergency Coordinator.

6.3 TSCIOSC Liaison 6.3.1 The TSC/OSC Liaison will report to the Emergency Coordinator. This position is staffed by Engineering within 75 minutes.

6.3.2 The TSC/OSC Liaison is responsible for communicating task priority and status information between the TSC and OSC.

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EM 5.1 Revision No.: 32 Pap 5 of 89 6.4 Technical Assistant to TSCIOSC Liaison:

6.4.1 The Technical Assistant to TSC/OSC Liaison will report to the TSC/OSC Liaison. This position is staffed by Design Engineering. Individuals staffing this position will be contacted by ERO pager and/or using the Nuclear Call Out system after normal work hours.

6.4.2 The Technical Assistant to TSC/OSC Liaison will maintain the Plant status board or WEB EOC in the TSC. The Technical Assistant to TSC/OSC Liaison will perform any other duties as assigned by the TSC/OSC Liaison.

6.5 Nuclear Engineer 6.5.1 Reactor Engineering will provide personnel for this position. This position is required by regulation with the person being available in the TSC within 75 minutes of the emergency declaration. This person is required to be in place prior to Control Room turnover to the TSC. The Nuclear Engineer will report to the TSC Engineering Manager in the TSC.

6.5.2 A second person from Reactor Engineering will be called by the Nuclear Call Out system.

6.5.3 The Nuclear Engineer(s) will provide engineering support and recommendations in the following areas:

1. Reactor core physics

2. Shutdown margin calculations

3. Transient assessment flnctions via the transient monitors

4. Safety review fumction

5. Core damage assessment.

6.6 TSC Engineering Manager:

6.6.1 The TSC Engineering Manager should report to the TSC within 75 Minutes of emergency declaration and report to the Emergency Coordinator. The MCE Section is responsible for assuring this position is filled.

6.6.2 The TSC Engineering Manager will be responsible for providing engineering support required by the TSC. He/she will be responsible for resolving engineering problems. Also he/she will assure that any needed mechanical or electrical systems engineering personnel are contacted and given instruction on the necessary actions to be taken.

6.6.3 The TSC Engineering Manager will be responsible for making contact with the Accident Assessment Team in the Corporate Office to provide additional assessment expertise to the Technical Support Center.

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EM 5.1 Revision No.: 32 Page 6 of 89 6.7 Offaite Dose Assessment 6.7.1 The TSC Dose Assessment Liaison will report to the Emergency Coordinator in the TSC. He/she will be responsible for providing offsite Dose Assessment as needed and is to report within 45 minutes of the emergency classificatlon.

6.7.2 The Offsite Dose Assessors report to the TSC Dose Assessment Liaison within 75 minutes of the emergency classification and provide dose assessment as needed.

6.8 Engineering Manager Assistant 6.8.1 This individual should report to the TSC within 75 minutes of emergency declaration and report to the TSC Engineering Manager.

6.8.2 The Engineering Manager Assistant will be responsible for providing Primary and BOP systems support required by the TSC and will report to the TSC Engineering Manager.

7.0 Operational Support Center 7.1 The Operational Support Center (OSC) is located at the back of the Unit 3 Control Room. When reporting to the OSC, carry ED and TLD, go to the south entrance of Unit 3 Control Room Elevator Lobby, and frisk for possible contamination before entering the Control Room.

EMERGENCY RESPONSE RWP NUMBER. 33 (For drills and emergencies) 7.2 If evacuation from the OSC becomes necessary, report to the alternate OSC located on the third floor, room 316A, of the Oconee Office Building. Assume the same duties as in the Primary OSC.

7.3 Equipment Engineering Support for OSC 7.3.1 The Engineering Support duty person is required to report to the OSC within 75 minutes of emergency declaration. This position will report to the OSC Manager.

7.3.2 Engineering Support will be responsible for providing Electrical Engineering support for any work performed by the OSC. Should any Mechanical/Civil Engineering needs arise from the OSC, this person will inform the appropriate party.

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EM 5.1 Revision No.: 32 Page 7 of 89 7.4 Engineering Support 7.4.1 Personnel filling the Engineering Support role may also have a primary ERO responsibility which must be addressed prior to responding as Engineering Support (ex: The Engineering Manager Assistant gn

&-Uwill respond to the TSC to satisfy that requirement).

7.4.2 Engineering Support personnel are required to report to the site within 75 minutes of an emergency declaration. ERO personnel filling this role will report to their normal office/work area to be available as an Engineering resource if needed. Upon arrival, contact the Engineering Manager in the TSC to report availability and obtain additional direction if needed.

8.0 Joint Information Center:

8.1 The Joint Information Center (JIC) is located in Clemson on Issaqueena Trail (In-Processing Center).

TLDs and EDs are not required for this facility.

8.2 Technical Briefers:

8.2.1 The Technical Briefers will be notified as needed by the Joint Information Center (located at the JIC).

They will report to the Technical Briefers Section Head in the Joint Information Center.

8.2.2 The Technical Briefers will be responsible for reading news releases or predeveloped messages for technical accuracy and responding to calls by following the rumor control procedure.

8.2.3 The Technical Briefers will keep the Technical Briefer Section Head informed of calls being received and assist in coordinating activities as needed The Technical Briefer position is filled by persons from across the organization who possesses the skills needed.

8.3 State/County EOC Liaison 8.3.1 State/County EOC Liaisons should report directly to their assigned EOC location at Pickens or Oconee counties and the State Emergency Operations Center as indicated on their duty roster. The response bag is located at the respective EOC location.

IF this is an actual emergency (not a drill) THEN the duty person assigned the following week will also immediately report to the assigned EOC to establish 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months coverage.

Consult with the Drill Director for guidance on drill participation and locations.

Engineering will staff this position.

Responsibilities for this position are as follows:

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EM 5.1 Revision No.: 32 Page 8 of 89

1) Answer questions in a non-technical manner about systems affected by the emergency at the plant and be knowledgeable of overall system functions.

2) Be able to interpret information found on the emergency notification form.

3) Be able to clarify information and provide interpretation as needed.

4) Provide an honest assessment of plant conditions.

5) Understand the emergency plans and classifications procedures.

6) Provide objective information to decisions makers in the EOC.

7) Be comfortable/adept in providing "Duke update" as part of the EOC update.

8) Have the ability to get answers to questions asked by state/county officials.

9) Assist with rumor control, if needed.

10) Forward state/county issues concerning Duke to the EOF staff.

9.0 Enclosures 9.1 Oconee Technical Support Center Guideline VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 9 of 89 .1 - Oconee Technical Support Center Guideline Eric Hensaw 8/6/01 TSCO Section A Date Eric Henshaw 11160 TSCO Section B Date Ron Haub 8/9/01 TSCO Section C Date Eric Herahaw 816(01 TSCO Section D Due Eric Hendaw 8/6/01 TSWO Section B Date Ken Grayson 8/1/01 T OSCSection F Date Ron Harrhi 8/9/01 TSCO Section 0 Date Eric Hensmhw 8/6001 TSCO Section H Data Eric Hecnabw 8/6/01 TSCO Section I Date Beau Abellam 899/01 TSCO Section J Date Courtney Brown 81/901 TWO Section K Date Paul Mabry 8/9/01 TSCWSection L Date Beau Abellam 3/W/02 TSCO Secon M Date VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 10 of 89 Ron Hari 5/21/02 TSCO Sectiot N Date Eti Henahaw 7112,0 TWO Section 0 Date Dave Wilson 9/17/03 TW Section P Dau Paul Mabry 10/I03 TWO Sec*t*, Q Date Beau Abaliana 12/3103 TSCO - Section R Date Paul Mabsy 6/2804 TSCO Section S Date Paul Mabry (EM .1 re 17,18)

TWCO Sectioa T Datg David Wilson 82./03 TSCO Section U Dat W. K. lraysan 4/17/06 TWO Sectiom V Dat David Wilsa 9/21/07 TSCO Section W Date Carl D. Pap 12/3/13 TSCG Section X Date Beau Abellana 10/10/13 TSCO Section Y Date VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page I I of 89 TABLE OF CONTENTS A. STARTING OR BUMPING A RCP FOLLOWING LOSS OF SCM ......................................................... 14 B. STEAMING A STEAM GENERATOR WITH WATER IN THE STEAM LINE ...................................... 20 C. REFILL THE EW ST .......................................................................................................................................... 22 D. EVALUATE OUTSIDE AIR BOOSTER FAN OPERATION ................................................................... 24 E. NATURAL CIRCULATION COOLDOWN CONSIDERATIONS ........................................................... 25 F. MAKEUP AND MONITORING OF THE SFP AND RECOVERY FROM A BOILING CONDITION ........ 29 G. MAKEUP AND MONITORING OF CCW INLET PIPE INVENTORY .................................................... 32 H. CONSERVE BWST INVENTORY ............................................................................................................... 34 I. CFF CORE COOLING FOLLOWING LOSS OF DECAY HEAT REMOVAL ........................................ 36 J. MITIGATE LPI PUMP INTERACTION AND LPI PUMP RESTART ............................. 38 K. ENERGIZE THE ASW SWITCHGEAR FROM AN OPERATING OCONEE UNIT ................................. 41 L. LIMITATIONS ON ALIGNING HPI SUCTION FROM THE SFP ............................................................ 43 M. ENSURE TOTAL LPSW RECIRCULATION FLOW IS <9000 GPM DURING DAM/DIKE FAILURE ..... 46 N. MANAGE KEOWEE LAKE LEVEL DURING A LOOP ......................................................................... 48

0. OPENING THE ALTERNATE POST-LOCA BORON DILUTION FLOWPATH ................................... 51 P. DEPRESSURIZING THE REACTOR BUILDING AFTER A LOSS OF DHR EVENT DURING MODES 5 A N D 6 ................................................................................................................................................................. 55 Q. ACTIONS TO REDUCE EFFECTS OF RBES SCREEN BLOCKAGE BY DEBRIS ................................. 58 R. GUIDANCE FOR ESTABLISHING PZR BUBBLE WITHOUT PZR TEMPERATURE INDICATION ...... 62 S. ALTERNATE HPI TERMINATION CRITERIA WHEN OPERATING FROM THE RB SUMP ............. 63 T. ALTERNATE WATER SOURCE FOR POST-ACCIDENT BWST REFILL ............................................. 66 U. LOSS OF SPENT FUEL POOL LEVEL ...................................................................................................... 69 V. OPERATING ATMOSPHERIC DUMP VALVES DURING AN ACCIDENT THAT REQUIRES OPERATION OF THE SSF ............................................................................................................................... 77 W. GUIDANCE FOR SECURING REACTOR BUILDING SPRAY PUMPS FOLLOWING A LOCA ...... 83 X. GUIDANCE FOR OBTAINING REACTOR BUILDING HYDROGEN SAMPLE .................................... 84 Y. ENERGIZING DESIRED LOADS ONTO THE EMERGENCY POWER SOURCES IN SUPPORT OF AP/lI ................................................................................................................................................................... 86 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 12 of 89

1.0 INTRODUCTION

The purpose of the Technical Support Center Guideline (TSCG) is to present accident mitigation guidance and facilitate ad hoc accident evaluation and decision making. The guidance contained herein provides the TSC with pertinent background information and candidate actions. Alternate methods not discussed herein may be used at the discretion of the TSC.

2.0 DIAGNOSIS AND MITIGATION The TSCG consists of individual sections linked to specific TSC requested actions. Each requested action is linked to specific EOPs and/or AOPs. The sections are:

A. Starting or bumping a RCP following loss of SCM B. Steaming a steam generator with water in the steam line C. Refill the EWST D. Evaluate outside air booster fan operation E. Natural circulation cooldown considerations F. Makeup and monitoring of the SFP G. Makeup and monitoring of CCW intake pipe inventory H. Conserve BWST inventory I. CFT core cooling following loss of decay heat removal J. Mitigate LPI pump interaction and LPI pump restart K. Energize the ASW switchgear from an operating Oconee unit L. Limitations on aligning HPI suction from the SFP M. Ensure total LPSW recirculation flow is <9000 GPM during dam/dike failure N. Manage Keowee Lake Level During a LOOP

0. Opening the alternate Post-LOCA boron dilution flowpath P. Depressurizing the reactor building after a loss of DHR event during modes 5 and 6 Q. Actions to reduce effects of RBES screen blockage by debris R. Guidance for establishing Pressurizer bubble without Pressurizer temperature indication S. Alternate HPI termination criteria when operating from the RB sump T. Alternate water source for Post-Accident BWST refill U. Loss of Spent Fuel Pool Level V. Operating Atmospheric Dump Valves during an Accident that Requires Operation of the SSF W. Guidance for securing reactor building spray pumps following a LOCA X. Guidance For Obtaining Reactor Building Hydrogen Sample Y. Energizing desired loads onto the emergency power sources in support of AP/I I VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 13 of 89 Each section contains the following subsections:

1.0 SAFETY CONCERN A brief statement highlighting the requested action or safety issue requiring TSC consideration.

2.0 PROCEDURE ENTRY CONDITIONS This section lists the plant conditions, consistent with the procedure entry conditions, that are considered in development of the guidance. These bulleted items highlight these applicable plant conditions and/or initiating events.

3.0 REQUESTED ACTION 3.1 Requested Action Summary This section summarizes the requested actions and their purpose.

3.2 Background This section provides technical background and information pertaining to plant conditions and the requested actions. Information considered common knowledge is typically not included, unless necessary to characterize or support potential actions.

3.3 Implementation This section details the requested actions. It contains information such as applicable procedures, system and component details and requirements, observations and system expert opinion.

3.4 Expected Plant Response This section summarizes plant response to implementation of the requested action.

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EM 5.1 Revision No.: 32 Page 14 of 89 A. STARTING OR BUMPING A RCP FOLLOWING LOSS OF SCM 1.0 SAFETY CONCERN Bumping or restarting a RCP may result in transferring unborated or underborated primary coolant to the core that may result in a critical condition.

2.0 PROCEDURE ENTRY CONDITIONS EOP guidance exists to bump/restart a RCP given the following plant conditions:

Evidence of a loss of coolant and/or SG tube leak.

Loss of heat transfer.

Loss of or degraded natural circulation cooling.

BHPI cooling.

Following recovery of subcooled margin (SCM)

Evidence of hot leg voiding

Evidence of boiler-condenser mode (BCM) cooling

No RCPs on or large void in loop opposite with one RCP on The above conditions were considered in preparation of the following guidance.

3.0 Requested Action 3.1 Requested Action Summary Bump or restart a RCP in an idle loop.

The purpose of restarting or bumping a RCP in an idle loop is to promote primary-to-secondary heat transfer by either establishing forced circulation cooling or assisting natural circulation cooling.

3.2 Background Restarting or bumping a RCP following loss of SCM risks introducing excessive positive reactivity by pumping unborated or underborated coolant to the core. An RCP bump consists of a pump restart of sufficient duration to allow pump motor amps to stabilize (approximately 10 seconds) followed by an immediate trip of the pump.

For a range of SBLOCA break sizes that exceed the capacity of the HPI system, yet require steam generator heat transfer to cooldown and depressurize, the RCS may experience BCM cooling. With the RCS in a saturated condition, core decay heat causes boiling to occur and steam to be transferred to the hot legs. BCM mode develops when the steam void that initially forms in the top of the hot leg expands down into the steam generator tubes where it is condensed. The primary coolant is condensed by EFW or MFW delivered through the auxiliary header when the steam void expands below the elevation of the auxiliary header nozzles. This is referred to as EFW-BCM. When the steam void expands below the secondary pool level in the steam generator, primary coolant will condense due to pool-BCM. Both EFW-BCM and pool-BCM are effective forms of heat transfer, and are either cyclic or stable in nature.

However, both forms of BCM can cause underborated water to accumulate in the steam generator tubes, lower steam generator head and cold leg up to the RCP spillover. This occurs because only a small percentage of the boron is transported with the steam that is condensed during BCM cooling. The volume VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 15 of 89 of this underborated RCS condensate would be swept into the core upon bumping a RCP. The consequences of a RCP restart could introduce greater than 5% of reactivity and be as severe as a rapid power excursion with the potential for significant fuel damage and RCS pressure boundary damage.

The most likely indication of boron maldistribution is inconsistent boron sample results. However, the capability to quantify the size of a region of unborated or underborated water is limited. If BCM has occurred the volume of condensed RCS coolant consisting of unborated or underborated water should be assumed large.

The potential for a rapid boron dilution event decreases as the RCS boron concentration decreases with cycle burnup. Towards the end-of-cycle when the boron concentration is lower, RCS conditions exist which permit safely bumping or restarting a RCP in a formerly idle loop assumed to have undergone some boiler condenser heat transfer.

If hot leg level remains above the elevation of the auxiliary header, it can be concluded BCM cooling has not occurred. In other words, primary coolant level greater than the auxiliary header elevation precludes significant accumulation of unborated or underborated primary coolant Likewise, if no feedwater has been supplied to a steam generator it can be concluded that BCM has not occurred.

Insufficient boron mixing in the RCS can also exist for the following conditions. With a single RCP in operation and a large void indicated in the opposite loop, no mixing in the idle loop should be assumed.

The void may prevent reverse flow, and an underborated region may therefore exist in the idle loop. An RCP bump or restart must not be attempted in this plant configuration without careful consideration of the potential for a reactivity insertion event.

3.3 Implementation Three sets of guidance are provided. The first considers a loss of SCM and a void in the hot leg, but is subject to one of the following conditions: 1) the void is not large enough to result in unborated/underborated primary condensate or 2) the void extends into the tube region, but the SG has not been fed. The second set of guidance considers adequate mixing of the primary coolant during natural circulation to allow for a pump bump or restart. Lastly, guidance is provided for time in core life where boron concentration is less due to burnup. For certain conditions RCP restart can be performed since a significant boron dilution event cannot occur. A combination of RCP cold leg temperature or So pressure, pre-accident boron concentration, and elapsed time are used to determine when bumping or restarting a RCP is recommended.

No Boiler Condenser Mode Confirmed

A RCP may be bumped or restarted if one of the following is true:

a. Hot leg level remained > 389 inches (value includes allowances for instrument uncertainty)

The primary coolant level has remained at an elevation greater than the EFW upper header. This value reflects an elevation at the secondary face of the upper tube sheet It can be concluded that a significant volume of unborated/underborated condensate has not accumulated in the tubes if the hot leg void has not penetrated the SG tube region.

b. If during HPI forced cooling neither SG has been fed while the RCPs were off and adequate core exit subcooling has been restored, a RCP may be restarted. Without feedwater being delivered BCM cannot occur and there is no concern.

Adeauate Natural Circulation Mixing Confirmed

A RCP may be restarted if all of the following conditions are satisfied.

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EM 5.1 Revision No.: 32 Page 16 of 89

1. Subcooled natural circulation has existed in both loops for > 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , and,

2. There is no indication of increasing reactivity during natural circulation on available nuclear instrumentation.

If the above conditions are satisfied adequate boron mixing in each loop exists and a region of unborated or underborated primary coolant does not exist.

Criteria for RCP Bum /Restart Due to Low Initial Boron Concentration One of two figures may be used to determine if bumping or restarting a RCP is advisable following BCM coolin& The first figure is a function of RCS cold leg temperature and elapsed time. The second figure is a function of SO pressure and elapsed time since reactor trip. If cold leg temperature indication is available in the loop with a pump to be bumped/restarted Figure I should be used. If cold leg temperature indication is unavailable, but SO pressure indication is available then Figure 2 should be used. The following criteria must be satisfied prior to using either Figure.

" Verify all control rods are fully inserted

" Verify reactor power was a 70% prior to reactor trip

" Verify time since reactor trip is within analyzed limits (< 48 h)

Figure 1 uses RCS cold leg temperature as a function of elapsed time since reactor trip for various RCS boron concentration pre-conditions. Figure 2 uses SO pressure as a function of elapsed time since reactor trip for various RCS boron concentration pre-conditions. The figures are generated assuming the following:

" All control rods are fully inserted

Assumes 70% full power equilibrium xenon.

" Includes 50 ppmB concentration measurement uncertainty in initial RCS concentration (prior to accident)

" In Figure 1, a 9 *F uncertainty allowance for RCS temperature indication. In Figure 2, a 110 psi uncertainty allowance for SO pressure indication.

To use either Figure I or Figure 2, determine:

1. For Figure I determine the lowest indicated cold leg temperature.

For Figure 2, determine the lowest indicated SG pressure during the accident.

2. The pre-accident RCS boron concentration, and

3. The elapsed time since reactor trip.

4. Given the above considerations, if the lowest indicated RCS cold leg temperature or SO pressure is greater than the line corresponding to the pre-accident RCS boron concentration, a RCP may be bumped or restarted per the EOP.

If any of the above conditions are not met, evaluation by site and G.O. nuclear engineering can be requested.

3.4 Expected Plant Response Plant response to bumping or restarting a RCP will depend upon the plant conditions prior to a bump/restart. When a RCP is bumped or restarted with a hot leg void, expect the void to collapse as it is quenched in the SO. If the RCP is bumped, RCS pressure will decrease rapidly as a result One RCP at a VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 17 of 89 time should be bumped for a period of time sufficient to allow the pump motor amps to stabilize (approximately 10 seconds). If plant conditions do not indicate the presence of natural circulation cooling following the pump bump, the other RCPs may each be bumped one time. If bumping the RCPs does not start natural circulation cooling, then refer to: E. Natural Circulation Cooldown Considerations.

If the RCP is restarted, RCS pressure will decrease. A loss of SCM may occur with the initial decrease in system pressure and require the RCP to be tripped shortly after it is restarted. If adequate SCM remains, plant response should then be consistent with forced circulation cooling. However, if a large void exists in the loop opposite the operating RCP, forced circulation cooling may be prevented.

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EM 5.1 Revision No.: 32 Page I of 89 FIgure 1: RCP BumplRestart Criteria 550.0 500.0 I

E 450.0 I 400.0 350.0 300.0

-850 ppmB Pre-Accident 250.0 .... 550 ppmB Pre-Accident 3-450 ppmB Pre-Accident

- .-350 ppmB Pre-Accident 250 ppmB Pro-Accident ....

150 ppmB Pro-Accident

50 pprmB Pro-Accident 200.0 0 4 8 12 16 20 24 28 32 36 40 44 48 Elapsed Time Since Reactor Trip (hours)

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EM 5.1 Revision No.: 32 Page 19 of 89 Figure 2: RCP Bump/Restart Criteria 1050.0 ' I Acceptable *__

pera on F--

980.0 w.0po I

5___j-50 ppmS ProAcdn ppmB Pro-Accident 6-450 Boo. .- 350 ppmB Pro-Accident

...... 250 ppmB Pro-Accident 70.0 150 ppmB Pr-Accident 00.0 - .--- 50

< ppmB Pro-Accident

°60.

No. I _,__-

J - C. ....

500.0r 41W.0 ;

0 4 8 12 16 20 24 28 32. 38 40 44 48 Elapsed Time Since Reactor Trip (hours)

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EM 5.1 Revision No.: 32 Page 20 of 89 B. STEAMING A STEAM GENERATOR WITH WATER IN THE STEAM LINE 1.0 SAFETY CONCERN Potential loss of secondary pressure control due to waterhammer causing steam line rupture and/or loss of turbine-driven pump steam supply.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" Evidence of a SO tube leak.

SG level of 96 %OR or greater.

" Inadequate core cooling.

" HPI cooling cooldown.

3.0 REQUESTED ACTION 3.1 Requested action Summary

Steam a SO with indication of water in the steam line.

3.2 Background Opening a valve to reduce secondary pressure and cooldown the primary system with water in the steam line risks: 1) waterhammer, 2) losing steam supply to pump turbines, and/or 3) transferring water to pump turbines. A waterhammer event could ultimately result in loss of secondary pressure control due to pipe break or failure of a valve to reseat.

At SG levels of 96 %OR and greater it is possible that water has leaked-by the outlet annulus via a SO level instrument tap near the top of the baffle. The water will pool in the outlet annulus until it spills into the steam line. The steam line exits the steam generator horizontally for -10 feet before turning and increasing in elevation 10 feet or greater. The water level in this section of the pipe will be approximately the same as in the steam generator. When steam generator level drops below the upper tap location, water will begin to drain back into the steam generator. Consideration should be given to some water remaining in the steam line immediately exiting the SO despite a reduction in SO level.

Expect condensation to occur over the length of the steam lines under low flow or stagnant conditions.

The steam lines are horizontal or downward sloping the entire length of the run to the turbine after the initial rise in elevation at the steam generator exit. Therefore, the condensate will not accumulate in a "water catch" piping arrangement other than at the SO exit.

With water leaking by the instrument tap, the water will pool in the length of pipe exiting the SO. The level in this pipe will be approximately the same as the level indicated in the SO. With a level established in the pipe, high steam velocity is then necessary to form a plug of water. High steam velocity is also required to entrain liquid in a partially liquid filled pipe. A controlled cooldown using the ADVs or the Turbine Bypass System does not typically generate steam velocities large enough to entrain liquid or form a plug in a steam line with a residual level of water (in cases where indicated SO level has decreased below 96 %O6R). The velocity necessary to do so depends upon the liquid level in the steam line as well, but once the line has been drained steaming the SO is allowable as very high steam velocities are required with lower levels.

If there is indication of SO levels approaching 120 inches above the instrument tap elevation, then water has spilled into the steam line above the exit. Full range indication is uncompensated and unreliable in VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 21 of 89 this condition of operation. However when full range SG level indicates an increasing trend in SO level, well above the instrument tap elevation (500 inches or greater), it can be assumed water has spilled into the length of pipe rising above the exit (approximately 10 feet). The SO should not be steamed at all in this instance, even if the OR level decreases below 96 %OR.

If neither steam line is available, HPI cooling should be used to cool down the unit.

3.3 Implementation If SO level is greater than 96% OR (or equivalent temperature compensated XSUR level) do not steam the SG.

If full range indication does not indicate SO levels continued to increase above the instrument tap level to a level greater than 450 inches (69 %FR), and SG level has reduced to a level less than 96 %OR, the SG may then be steamed.

Otherwise, HPI cooling should be used to cooldown the unit if water is suspected in both steam lines.

3.4 Expected Plant Response Secondary pressure control should not be lost if the guidance is followed during RCS cooldown.

Controlling to the prescribed cooldown rate precludes liquid entrainment and/or plug formation in the steam line piping exiting the SO.

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EM 5.1 Revision No.: 32 Page 22 of 89 C. REFILL THE EWST 1.0 SAFETY CONCERN Loss of HPSW resulting in loss of backup cooling water to IBPI pump motor coolers, cooling water to the TDEFW pump, and/or loss of fire suppression capability.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" Loss of offsite power.

" Station blackout.

" Turbine Building flooding.

" Loss of LPSW

" EWST level low.

3.0 REQUESTED ACTION 3.1 Requested Action Summary

" Provide power to a HPSW pump.

" Refill EWST using offsite fire department engine.

" Use Keowee Hydro Station portable backup jockey pump on the discharge structure.

3.2

Background:

The EWST provides the following functions:

" The EWST is capable of delivering the demands of each fire suppression system individually. This constitutes a significant demand on the EWST, which cannot be sustained for very long.

" During loss of all AC power (station blackout), HPSW could provide cooling water to the turbine driven EFW pump.

" During loss of normal LPSW supply to the HPI pump motor coolers due to a Turbine Building flood or other condition: HPSW should provide cooling water to the BPI pump motor coolers. (Station ASW may also be capable of supplying the HPI pump motor coolers.)

" Upon CCW pump restart after loss of LPSW, HPSW is needed to supply water via SSW piping to the CCW pumps for bearing lubrication and motor cooling.

Replenishing the EWST is a risk-significant operation. Failure to replenish the EWST increases the core damage frequency.

3.3 Implementation Refill the EWST through a method delineated in:

EP/1,2,3/A/1800/001, Enclosure 5.31 (Temporarily Charging the HPSW System)

Two methods are presented in the Enclosure. Consider the following when choosing a method (ref. OSC-7966):

Option 1: Use offsite fire department engine on the intake structure.

Location on the intake near 2C CCW pump available for fire department engine.

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EM 5.1 Revision No.: 32 Page 23 of 89

" Fire department has length of hard pipe suction hose to reach.below water surface if lake level > 796 feet.

" Fire hydrant HY-26 available. (OFD-124C-1.4)

" Must use 5. inch diameter hose to connect to fire hydrant to avoid excessive pressure drop.

Option 2: Use offsite fire department engine on the discharge structure.

" Location on the CCW discharge available for fire department engine.

" Fire department has length of hard pipe suction hose to reach below water surface if lake level > 790 feet.

" Fire hydrant HY-7 available. (OFD-124C-1.5)

" Must use 5 inch diameter hose to connect to fire hydrant to avoid excessive pressure drop.

To extend the available EWST inventory, isolate any non-essential demands on -PSW as follows:

Close BPSW-901 to isolate HPSW supply to SSW. (ref. OFD-124C- 1.1)

" Isolate HPSW supply to primary Instrument Air compressor by performing Backup IA Compressor Startup/Primary IA Compressor Shutdown per OP/0/A/1 106/027 (Compressed Air System).

" If operating, shutdown Breathing Air Systems per OP/0/B/1 106/032 (Breathing Air System).

" If TDEFW pumps are not needed, isolate HPSW supply to TDEFW pumps, including cooling jackets and oil coolers.

3.4 Expected Plant Response EWST level will be maintained or increased.

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EM 5.1 Revision No.: 32 Page 24 of 89 D. EVALUATE OUTSIDE AIR BOOSTER FAN OPERATION 1.0 SAFETY CONCERN Control Room habitability.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

1/2/3RIA-39 CNTRL RM Gas Alarm actuated

Outside air booster fans are operating 3.0 REQUESTED ACTION 3.1 Requested Action Summary

" Terminate outside air booster fan operation

" Continue outside air booster fan operation 3.2

Background:

The outside air booster fans are operated when a control room air handling unit return air radiation monitor (1I/3RIA-39 (CNTL RM Gas)) alarms. The outside air booster fans provide filtered air to positively pressurize the control room.

The outside air booster fans should not be disabled prior to terminating the radiation release. The in-line filters should remain operable for greater than 20 days. Therefore if radiation protection or available radiation monitoring indicates the event has not been terminated it is prudent to maintain the outside air booster fans operable.

The location of the source term is important to the decision. If release is a result of component or penetration failure in the Auxiliary Building, continued operation of the outside are booster fans is prudent. Bypassing the Auxiliary Building via the emergency or equipment hatches could result in a release effecting the booster fan suction source. If RIA-39 counts do not stabilize or reduce with booster fan operation, consideration should be given to isolating the outside air booster fans.

In addition, chlorine release or smoke near the fan suction could prompt isolating the fans depending on the magnitude of the source term.

3.3 Implementation Determine location of source. If source is such that operation of the outside air booster fans result in continued and increasing 1/2/3RIA-39 CNTRL RM gas alarm counts, it may be prudent to terminate operation of the fans.

Consider extenuating circumstances which may effect Control Room habitability, such as fire or noxious gas, to evaluate continued operation of the outside air booster fans.

3.4 Expected Plant Response Operation of the control room air booster fans should result in reducing counts on or stopping the 1/2/3RIA-30 CNTRL RM gas alarm.

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EM 5.1 Revision No.: 32 Page 25 of 89 E. NATURAL CIRCULATION COOLDOWN CONSIDERATIONS 1.0 SAFETY CONCERN Loss of or degraded natural circulation.

LPI initiation during natural circulation.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" Loss of CCW intake canal.

" Loss of equipment in a fire area due to fire.

" Station blackout.

" Loss of all equipment (except cabling) in non-vital areas due to sabotage.

" Loss of equipment in the Turbine and Auxiliary Buildings due to a flood resulting from CCW System ruptures.

Loss of equipment in the Turbine and Auxiliary Buildings due to a tornado missile event.

" Indication of loose parts alarms or sustained large magnitude noise in the RCS.

Loss of subcooling margin.

3.0 REQUESTED ACTION 3.1 Requested Action Summary

Evaluate natural circulation cooldown conditions.

3.2

Background:

The following summarizes various natural circulation cooldown scenarios and provides plant conditions and expected response to operator intervention. The guidance considers thermally coupled primary and secondary systems as a function of RCS SCM, loop asymmetry during natural circulation, phenomena which will interrupt natural circulation, and what is necessary to enhance or restart natural circulation.

Primary/Secondary Cou led - RCS is Subcooled Subcooled natural circulation is indicated by:

1. Tcu coupled to the saturation temperature at the SG pressure,

2. Incore T/C temperature indication should track Ttt within approximately 10 OF, and

3. Tho and Tco temperature difference should be between 30 to 50 OF.

4. SG level at 50 %OR, 240 in XSUR.

The AT between T*,t and T.1d is expected to be 50 OF or less. The magnitude of the flow rate will decrease as the AT decreases and as core decay heat decreases.

Primarg/Secondary Coupled - RCS is Saturated Saturated natural circulation is indicated by:

1. T,*d coupled to the saturation temperature at the SG pressure.

2. Loss of SCM SG level VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 26 of 89 With the RCS saturated, incore T/C temperature will track T. whether natural circulation flow exists or not. The AT between Tht and T,.I, will vary between 50 *F and 0 TF, depending upon how much of the core heat is transferred to the primary coolant as latent heat of vaporization. The magnitude of the flow rate will decrease as the AT decreases as core decay heat decreases.

Primary/Secondary Coupled - One SG Operable. Subcooled or Saturated If only one SG is operating during natural circulation only Thw in the operating loop will indicate core outlet temperature. Tm on the operating SQ will be approximately equal to T.1 in the operating SG.

T~m in the isolated SQ may not be equal to T1 t in the isolated SG. It will probably be colder due to ambient losses and due to cooler injection water (seal injection, MU, HPI). AT on the operating SQ may be 10 OF higher than the 50 TF expected with two operating SGs. The loop with the idle SG may prevent primary depressurization.

Interuption of Natural Circulation Natural circulation can be challenged and lost by three causes. Inadequate steam generator level and/or loss of steam generator steaming capability (including overfilling the SG) will result in degraded or loss of natural circulation. Hot leg voids collecting in the top of the hot leg will degrade or stop natural circulation. Generally, the benefits of maintaining or restoring primary-to-secondary heat transfer warrants operator action to do so.

Two sets of symptoms indicate whether natural circulation will be interrupted due to hot leg void formation. The first set are identified by a diagnosis of plant conditions that could result in void formation:

" Loss of RCS inventory

" Loss of subcooled margin that might result in water flashing to steam

" Contraction of the RCS inventory due to an overcooling event

" Cooldown and depressurization with an idle loop

" An outsurge of hot water from the pressurizer

" Accumulation of noncondensible gases following ICC or from any other source The second set of symptoms include indications that heat transfer has been interrupted:

" Hot leg level < 537 inches (void large enough to interrupt natural circulation)

" RCS temperatures increasing, with CETC temperature diverging from hot leg RTDs

" Pressurizer level increasing due to void growth or thermal expansion (primarily if subcooled)

Steam generator pressure decreasing due to injection of feedwater

" RCS temperature and pressure increasing along the saturation curve (if subcooling lost)

The first set of symptoms will likely lead to the second, with natural circulation being lost due to a hot leg void forming. As the void in the hot leg continues to expand into the steam generator tube region, boiler-condenser mode heat transfer will occur. Natural circulation can be regained after it has been lost, and the cooldown could be expected to occur in a cyclic manner.

Enhancing/Stimulating Natural Circulation

Increase AT between primary and secondary

" Open hot leg high point vents if a void is indicated VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 27 of 89

Bump or restart a RCP Increasing the temperature difference between the primary and secondary increases the density differences between the hot legs and the SGs. This is accomplished by raising SO levels and/or steaming the SGs.

The optimum cooldown method includes balanced steaming of both steam generators in order to maintain a symmetric coolant temperature distribution.

Natural circulation will become intermittent and then will be lost as a hot leg void increases. The void can be vented to mitigate the cause and duration of the loss of natural circulation. This is effective in scenarios where a primary system break cannot provide sufficient cooling. The operator is instructed to open a high point vent if subcooled margin is lost and RCS pressure is increasing due to RCS heatup. If RCS pressurization persists, the pressurizer PORV is also opened to assist in removing decay energy and increasing HPI flow by decreasing RCS pressure.

If a hot leg void exists and SCM has not been lost, then once-through cooling is adequately removing decay heat and the primary may be thermally decoupled from the secondary. In this case, venting a hot leg void is not necessary. However, the void may be vented to restore natural circulation.

Bumping or restarting a RCP may also be utilized to mitigate voiding in the RCS. A RCP bump consists of a pump restart of sufficient duration to allow pump motor amps to stabilize (approximately 10 seconds) followed by an immediate trip of the pump. Bumping or restarting a RCP sweeps the void into the steam generator tubes where it condenses. RCS pressure decreases as the void is condensed and more of the RCS is exposed to the steam generator. Refer to TSCG Section A.

LOI Initiation during a Natural Circulation Cooldown B&W document 51-1232710-00 (Decay Heat Removal System Initiated Pressure/temperature analysis) addresses RCS overcooling issues due to LPI initiation. As long as any RCP is in operation and the RCS cooldown limits are observed, there are no RCS overcooling concerns. However, if there is no RCP in operation when LPI is placed into service (LPI pump started), then there is no current bounding analysis that addresses RCS overcooling concerns. For this reason, it is not desired to initiate the LPI system with no RCPs operating. However, if it is necessary to initiate LPI during a natural circulation cooldown, then ensure a thermal overcooling analysis is performed prior to re-start of the unit. Issue a PIP that is mode coded to prevent startup until after the overcooling event is evaluated.

3.3 Implementation Enhancing Natural Circulation Evaluate the following actions that enhance natural circulation.

" SG levels may be raised up to 96 %OR.

" Steam SGs to increase AT between the primary and secondary.

Maintain makeup to the RCS for losses and shrink (preserve loop thermal communication).

Restarting Natural Circulation Evaluate the following actions, which may aid in restarting natural circulation:

e Maintain makeup to the RCS for losses and shrink (preserve loop thermal communication by minimizing hot leg void growth). This is necessary to restart natural circulation if the plant is in intermittent natural circulation or BCM cooling.

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EM 5.1 Revision No.: 32 Page 28 of 89

" Open hot leg high point vents to aid thermal connection between the hot legs and the steam generators if a hot leg void indicated.

" Bump or restart a RCP (refer to TSCG Section A).

3.4 Expected Plant Response The plant will generally respond in a sluggish manner to operator intervention when in natural circulation cooling. However, if the plant is in BCM cooling, the plant can respond quickly to operator intervention.

When natural circulation exists, it can be enhanced by increasing the thermal center (raising SG level) or increasing AT between the primary and secondary (steaming the SG). Consideration should be given to raising SG levels above target setpoints but less than 96 %OR.

When natural circulation is degraded or intermittent, verify SG level and ensure steaming capacity is available. Makeup should be increased to enhance thermal coupling between the primary and the secondary. Intermittent natural circulation may exist initially or may follow natural circulation. It precedes BCM cooling if makeup is insufficient to match system losses and shrink If natural circulation has ceased, verify adequate RCS makeup and try to vent the RCS hot leg void. The plant may be in BCM cooling if the SGs remain operable and the primary and secondary systems are coupled. BCM cooling is an excellent mode of heat transfer, however a large region of underborated/unborated primary fluid may accumulate. As makeup matches break flow and system shrink (or the hot leg void is vented) the system will transition back to natural circulation though intermittent natural circulation.

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EM 5.1 Revision No.: 32 Page 29 of 89 F. MAKEUP AND MONITORING OF THE SFP AND RECOVERY FROM A BOILING CONDITION 1.0 SAFETY CONCERN Maintain and/or recover SFP inventory, boron concentration, and normal mode of cooling.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" Loss of spent fuel pool cooling.

" Tornado accident.

" SSF RC makeup required.

Boiling SFP 3.0 REQUESTED ACTION 3.1 Requested Action Summary Makeup and/or monitoring the spent fuel pools 3.2

Background:

Maintaining SFP level is important for radiological, fuel integrity, reactivity management, and accident mitigation reasons. The SFP is designed for boiling heat transfer, however makeup for boil-off needs to be assured for radiological and fuel integrity concerns. In addition, makeup to the SFP may be required to make up for SSF demands. Makeup may be from a borated or unborated/underborated source. This will affect reactivity management and accident mitigation when the SFP is used as a source for SSF demands.

Monitors IRIA-6 (Spent Fuel Pool) and 1RIA-41 (Spent Fuel Pool Bldg Gas Mon) should be monitored for an increase in radiation level inside the Units 1 and 2 SFP area. Monitor 3RIA-6 (Spent Fuel Pool) and 3RIA-41 (Spent Fuel Bldg Gas Mon) for an increase in radiation level inside the Unit 3 SFP area.

SFP heat load and SSF demands determine the urgency of monitoring and necessity for makeup. For example, following an outage, and at an initial 150 *F, the spent fuel pool time to boil is approximately 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months after loss of SFP cooling. If the SFP is verified intact (e.g. following a tornado or seismic event) sufficient time exists to provide makeup to the spent fuel pool.

If for some reason normal SFP cooling is lost and cannot be established within the time to boil, special actions must be taken to recover the normal cooling mode. As the spent fuel pool temperature rises it will approach the saturation temperature. At or near saturation temperature, normal cooling can no longer be used due to the lack of NPSH. As the pumps try to draw the boiling water up, out of the pool, the decrease in pressure inside the pipe will cause the water to flash to steam and the SFP water cannot be made to flow to the SF coolers. The bulk temperature of the SFP must be lowered to at least 180 *F before normal cooling can be reestablished. This can be accomplished by allowing the pool to first boil down and then adding cooling water to it at a sufficiently high rate to cool the pool down before it over fills. This rate is dependent on the heat load in the pool.

Normal makeup is available from the BHUT, CBAST, BAMT and DW. Emergency makeup is available using offsite fire department equipment. Makeup to recover from a boiling condition is available from the BWST.

During a SFP boiling event, the potential for a significant amount of steam generation within the SFP area exists. It is not desirable to have the steam enter and condense in the SFP ventilation ductwork.

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EM 5.1 Revision No.: 32 Page 30 of 89 Condensing steam in the ductwork could leak onto the floor of the Ventilation Equipment Room and/or Purge Exhaust Equipment Room. From these rooms, the water could leak into the Control Room and/or the Penetration Rooms potentially affecting safety related equipment. With ONS adopting the alternate source term methodology for determining the dose consequences of accidents, the SFP Ventilation System is no longer credited with maintaining 10CFR100 or 10CFR20 doses within limits. To prevent the potential for condensation from affecting safety related equipment, reference section U, "Loss of Spent Fuel Pool Level."

3.3 Implementation Monitor SFP Level Locally Monitor Hourly if:

" Level indication is not available, and no demand on SFP inventory (SSF RC makeup or HPI suction) in the first 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months following loss of SFP cooling.

" Level indication is available, and SFP inventory is a suction source for SSF or BPI with borated makeup established.

Monitor Continuously if (or as allowed considering radiological and environmental conditions):

Level indication not available, and no demand on SFP inventory (not a SSF or HPI suction source),

and greater than 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months (or within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months of SFP calculated time-to-boil and no makeup source aligned) following loss of SFP cooling.

Level indication is not available and SFP inventory is a suction source for HPI or the SSF with borated makeup established.

Changing the makeup or SFP cooling alignments.

Normal Makeup Sources:

Procedures OP/l&2/A/1 104/006/C and OP/3/A/1 104/006/C are used when making up to the SFP from:

" RC BHUT 1,2,3A/B

" CBAST (Units 1,2,3)

" BAMT (Unitsl&2,3)

" DW Emergency Plan for Refilling Spent Fuel Pool:

Procedure AM/O/A/3009/012A details makeup to the spent fuel pool using the offsite fire department.

Emergency Plan for Recovering from a Boiling SFP:

In order to recover from a boiling SFP, water must be drawn from the BWST. T.S. 3.5.4 SR 3.5.4.2 states that the BWST must have more than 350,000 gallons available with 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months required action time.

Recovery could potentially use up to 2/3 of the BWST inventory. If BWST inventory can't be made up within the required action time, the unit will have to be shut down. Additionally, the SSF RCMU Pump is inoperable when the SFP temperature reaches 141 *F per OSS-0254.00-00-1004, Design Basis Specification for the SSF RC Makeup System. T.S. 3.10.1 states that the RCMU system must be operable with a 7 day required action time. If SFP temperature can't be reduced to less than 141 IF within 7 days the unit(s) will have to be shut down. During recovery of the SFP, provisions should be made to reserve enough water in the BWST to shut down the unit(s). Recovery of the SFP may require as much as 220,000 gallons of water.

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EM 5.1 Revision No.: 32 Page 31 of 89 Makeup to the SFP to recover from a boiling condition will require the use of the A and B SF cooling pumps. These pumps can achieve a combined flow rate of about 1600 gpm. This is adequate flow to lower the spent fuel pool bulk temperature to 180 *F even at the abnormal maximum heat load. (See Calculation OSC-8079 - Recovery of SFP from a Boiling Condition) To lower the temperature of the pool sufficiently, large quantities of cool water must be added at a high flow rate. In order to align the Unit l&2 SFP to the BWST through the SFP Cooler Pumps, SF-53 and either SF-55 (for Unit 1 BWST) or SF-56 (for Unit 2 BWST) should be opened and SF-5 should be closed. For Unit 3 SFP, 3SF-53 and 3SF-55 should be opened and 3SF-5 should be closed. In order to have room to add this make-up water, make-up for the boil off must be stopped and the pool must be allowed to boil down to no less than 9 ft over the fuel racks. 9 ft over the fuel racks is considered the minimum allowable level due to ALARA. A note about boron concentration; Boiling off a large amount of water will have a concentrating effect on the boron in the pool as a large volume of water is removed while most of the boron remains. Worst case boron concentration after boil off and make up from the BWST is about 1300 ppmB above the procedural limit set for the SFP. Once normal cooling has been reestablished the SFP boron concentration should then be placed back within procedural limits.

Boil off times depend on the heat load in the pool and range from -35.5 days at minimum heat load to

-50 hours at maximum heat load for the Unit l&2 SFP and -25 days at minimum heat load to -38.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months at maximum heat load for the Unit 3 SFP. Once the required minimum pool level has been reached, make-up water, from the BWST through the SF cooling pumps, can then be added. The required flow rates for this make-up water (assuming pool is boiled down to 9 ft above the SF racks), based on heat load, can be determined with the following formulas:

Unit l&2 To fill the pool to normal level P'= 53.4XQL -5.73 To fill the pool to maximum level J7 = 42.7X QL -5.14 Unit 3 To fill the pool to normal level V7 = 53.7 X QL - 6.45 To fill the pool to maximum level P = 43.lXQ, -3.23 Note: Heat load values, QL , are in millions of Btu/hr and flow rate, V, is in gpm If heat loads in the SFP are less than the abnormal maximum, Calculation OSC-8079 includes an Excel Spreadsheet that will determine the minimum required boil down level given the actual pool heat load and actual BWST temperature.

3.4 Expected Plant Response SFP level increases or is maintained. Radiation levels in the SFP area are constant or decreasing. Verify boron concentration in the SFP continues to satisfy shutdown margin.

For SFP boiling, SFP temperature decreases. SFP level is kept below maximum elevation of 844'.

Radiation levels in the SFP are constant or decreasing. Verify boron concentration in the SFP continues to satisfy shutdown margin. Normal SF cooling is reestablished.

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EM 5.1 Revision No.: 32 Page 32 of 89 G. MAKEUP AND MONITORING OF CCW INLET PIPE INVENTORY 1.0 SAFETY CONCERN Preservation of SSF ASW pump and/or ASW pump suction supply.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" Tornado or loss of Lake Keowee event (SSF ASW, ASW).

" Fire, flood, or sabotage event (SSF ASW, ASW (potentially w/flood)).

" Station blackout. (SSF ASW)

" Significant blockage of CCW intake screens preventing normal operation of multiple CCW pumps.

3.0 REQUESTED ACTION 3.1 Requested Action Summary

1. Monitor Unit 2 CCW piping inventory, using SSF ASW/ASW pump suction pressure gauges.

2. If the Unit 2 CCW piping is intact, then makeup should be supplied by one or a combination of the following:

" Running a Unit 2 CCW pump, if available

" Gravity flow from CCW discharge

" Dedicated portable submersible pump

" Cross connect the Unit 1 and Unit 3 CCW intake/discharge piping and Unit 2 CCW discharge piping to the Unit 2 inlet piping.

If the Unit CCW pipe integrity is questionable or if CCW intake screens are blocked with debris, then the method of making up will need to fit the system conditions.

3.2

Background:

The Unit 2 CCW inlet is the assured source of water satisfying the unit ultimate heat sink requirements.

This mission is accomplished by serving as a source of supply water for SSF ASW or station ASW demands. Worst case required ASW inventory to remove core decay is approximately 37 days if Units 1, 2, and 3 intake and discharge piping volumes are available (inventory available below 791 feet). Action may be required in as little as 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

With Unit 2 and either Unit 1 or 3 intake and discharge piping, core decay heat can be removed from 2 Units for 37 days. Action may be required in as little as 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

3.3 Implementation

Monitor Unit 2 CCW intake pipe inventory For loss of lake, loss of intake canal, tornado or other events requiring SSF ASW or station ASW operation, evaluating CCW intake pipe inventory requires removing high point manways and using direct observation of level following loss of siphon. Prior to losing the siphon, use the SSF ASW pump suction gauge. The structural integrity of the pipe should be considered when obtaining the level observation/measurement.

Makeup to Unit 2 CCW intake pipe inventory VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 33 of 89 The methods to provide makeup to the Unit 2 CCW intake are:

1. Running a Unit2 CCW pump

-FOREBAY ELEV is above 67 feet (i.e. CCW intake level > 767 feet MSL)

-SSW (HPSW) supply to CCW pump

-Power to CCW pump discharge valve

-CCW cross-over aligned to other units (as necessary)

2. Gravity flow from CCW discharge

3. Dedicated portable submersible pump AM/0/A/1300/059

4. Cross connected with another unit and available water supply 3 Units intake and discharge pipes available:

Where the SSF ASW pump is in service and the station ASW pump is off, action must be taken within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of reactor trip to cross-connect the Unit's CCW intake and discharge unwatering pipes. This will assure 37 days of inventory where the SSF ASW pump is initially providing core decay heat removal.

Where the station ASW pump is in service with the SSF ASW pump off, action must be taken in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months of reactor trip to cross-connect the Unit's CCW intake and discharge unwatering pipes. This will assure 37 days of inventory where the station ASW pump is initially providing core decay heat and the SSF diesel engine service water is muted to the yard drain.

Unit 2 and either Unit I or 3 CCW intake and discharge pines available:

Where the SSF ASW pump is in service and the station ASW pump is off, action must be taken in 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months of reactor trip to cross-connect the available (not unwatered) Units' CCW intake and discharge unwatering pipes and to open or verify open 2CCW-75, 2CCW-78, 2CCW-79, 2CCW-86 and 2CCW-87 (if Unit 1 CCW intake pipe is unwatered). This will assure 37 days of inventory where the SSW ASW pump is initially providing core decay heat removal.

Where the station ASW pump is in service with the SSF ASW pump off, action must be taken within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months of reactor trip to cross-connect the available (not unwatered) Units' CCW intake and discharge unwatering pipes and open or verify open 2CCW-75, 2CCW-78, 2CCW-79, 2CCW-86 and 2CCW-87 (if Unit 1 CCW intake pipe is unwatered). This will assure 37 days of inventory where the station ASW pump is initially providing core decay heat and the SSF diesel engine service water is routed to the yard drain.

5. Supply CCW intake from CCW discharge 3.4 Expected Plant Response Unit 2 CCW intake pipe inventory is maintained to accommodate demands due to SSF or station ASW operation and/or possible losses due to leakage from the system.

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EM 5.1 Revision No.: 32 Page 34 of 89 H. CONSERVE BWST INVENTORY 1.0 SAFETY CONCERN

Loss of LPSW and BWST inventory depletion.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" Uncontrollable flooding of the Turbine Building.

" Loss of primary to secondary heat transfer control from Unit Control Rooms and aux shutdown panels.

" SSF ASW system and station ASW System unavailable.

Using forced HPI cooling.

3.0 REQUESTED ACTIONS 3.1 Requested Action Summary

Provide guidance to conserve BWST inventory to extend BPI cooling, considering the following potential actions:

- Throttle HPI flow to balance decay heat.

- Secure RBS system.

- Vent the RB.

3.2 Background BWST inventory constitutes the ultimate heat sink when primary-to-secondary heat transfer is lost and LPSW is unavailable. Forced HPI cooling is used to remove core decay heat when primary-to-secondary heat transfer is lost. Therefore, conserving BWST inventory by limiting what systems place demands on it extends the time available for forced BPI cooling. Aligning makeup to and replenishing the BWST inventory should be pursued while attempting to conserve the inventory.

BPI forced cooling is initiated by manually establishing BPI flow in the injection mode and latching open the PORV to create a relief flowpath. With subcooling margin all but one RCP is tripped to minimize the heat load on the system and maintain good circulation and mixing of injection flow.

HPI forced cooling results in energy relief to the RB. Without LPSW the RB structure and internal structures are the only heat sinks available to remove the energy from core decay heat, RCS metal, and secondary metal released by venting the RCS via the PORV. The controlled release of primary fluid to the building via the pressurizer PORV, safety valves or the hot leg high point vents via quench tank relief will result in increasing containment temperature and pressure. If there is no evidence of a high energy line break, and LPSW is unavailable, operation of the RBS system will only be marginally effective in removing energy from the atmosphere to containment structures. The RBS system should be isolated to minimize BWST drawdown rate.

Venting the RB removes energy primarily from the RB atmosphere. The RB purge system is not designed to operate under the differential pressure expected during HPI forced cooling. Venting would endanger the in-line filter package given environmental conditions present in the RB during HPI forced cooling. Likewise, venting RB may challenge the isolation valves ability to reseat. Lastly, removing air from the RB without replenishing it may complicate restarting RBS if required. If the air is removed and the atmosphere is predominantly saturated steam, spraying down containment could result in a differential VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 35 of 89 pressure greater than design. Given these concerns it is not recommended the RB be vented prior to establishing LPSW flow. If venting containment, purged air should be replenished with fresh air.

3.3 Implementation Minimize BWST Drawdown RBS should be isolated if there is no evidence of a HELB. Indication of a HELB would include: rapidly changing RB pressure and temperature, rapidly increasing RB sump level, and possibly increasing radiation levels in the building. If RB pressure remains less than 40 psig, RBS should remain isolated.

HPI cooling, without a large HELB, will only produce a gradual worsening of Reactor Building conditions.

Depending on the predicted time to recover LPSW or acquire a makeup source for the BWST, consideration should be given to minimizing HPI flow. This can be done by matching HPI forced cooling flow with the core decay heat demand. This will result in losing SCM, but would further extend the BWST inventory. Refer to EP/1,2,3/A/1800/001, Turbine Building Flood Tab.

Venting the Reactor Building Venting the RB risks subsequent loss of the ability to isolate, filter, and monitor any radiological release.

As Reactor Building ultimate design pressure is near 144 psig, venting the Reactor Building should not be considered unless failure is deemed imminent.

3A. Expected Plant Response The energy storage and conduction capacity of the RB during BPI cooling is sufficient to preserve Reactor Building integrity. As such, neither RBS or venting the Reactor Building should be necessary.

Therefore, BWST inventory can be conserved by minimizing demand, or isolating RBS.

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EM 5.1 Revision No.: 32 Page 36 of 89 I. CFT CORE COOLING FOLLOWING LOSS OF DECAY HEAT REMOVAL 1.0 SAFETY CONCERN Use of CFTs to remove decay heat.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" Loss of decay heat removal.

" BWST inventory approaching depletion.

" BWST aligned for gravity flow to RCS.

3.0 REQUESTED ACTIONS:

3.1 Requested action Summary 9 Drain CFTs to RCS to remove decay heat/makeup for boil off (when the BWST is unavailable).

3.2 Background A CFT contains 1040 +/- 30 cu-ft of borated water. In a shutdown condition one or more CFTs may not be available. CFTs may be at Reactor Building atmospheric conditions or have a nitrogen overpressure of 50 psi or greater (OP/l(2,3)/A/I 104/001, Core Flooding System).

The location of the RCS vent, the presence of steam generator nozzle dams, and RCS level should be considered when pressurizing and discharging the CFTs in a shutdown condition. If the RCS vent is in the upper SG, completely discharging a CFT with a pressurizer level of 360 inches could result in inventory loss out the vent. If SG nozzle dams are installed the CFTs must not be discharged.

The CFTs can be pressurized as necessary to discharge liquid volume for makeup. Each CFT should be discharged separately to maximize the liquid available to remove decay heat.

3.3 Implementation CFT Discharge for Decay Heat Removal:

Refer to OP/1(2,3)/A/1 104/001, Enclosure 4.14, for details regarding discharging the CFTs to the RCS.

Equipment required/considerations:

Inventory in the CFT.

Nitrogen high pressure header available.

Power supply to valves, 1/2/3CF-I and/or 1/2/3CF-2.

The valves CF-I and CF-2 can be operated locally. However, Reactor Building radiological and environmental conditions may preclude local operation.

The flow rate necessary to remove decay heat 1 day after shutdown from full power operation is 108 gpm and at 5 days the required flow rate is 62 gpm. Controlling CFT discharge to match decay heat will be difficult. CFT inventory should be discharged to preserve RCS level, but flow rates much greater than required to remove decay heat and maintain RCS level is likely. With the RV head removed, the difference in head generated by the initial CFT and RCS levels will produce CFT flows of several thousand GPM even if the CFT were vented to RB atmosphere.

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EM 5.1 Revision No.: 32 Page 37 of 89 CFT nitrogen pressure should be reduced to minimize rate of discharge prior to opening the discharge valves. Consideration of the RCS vent location will affect how the CFls are discharged as well. If the RV head is removed, inventory will spill from the RV given coarse flow control from the CFT. However, if the RCS vent is in the pressurizer or the upper SG head, CFT discharge should be controlled to a level several hundred inches below the vent location. The flow rate from a single CFT is sufficient to match decay heat at I day of shutdown, therefore the CFTs should be discharged one at a time.

A CFT must not be discharged if SG nozzle dams are installed.

3.4 Expected Plant Response CFT inventory can be used to makeup for boil-off following loss of DHR. Control of the injection rate will not be precise and a flow rate of less than 100 gpm is only required to makeup for decay heat. The CFTs should be discharged by pressurizing with nitrogen and pushing water through the injection lines as needed to maintain RCS level. The amount of fluid discharged will depend upon the location of the RCS vent. Do not attempt to discharge the CFTs if the nozzle dams are installed.

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EM 5.1 Revision No.: 32 Page 38 of 89 J. MITIGATE LPI PUMP INTERACTION AND LPI PUMP RESTART 1.0 SAFETY CONCERN Protect LPI pumps during low flow operation.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

Two LPI pumps in operation and BWST inventory decreasing, requiring LPI/HPI "piggyback" operation to provide BPI suction from the RBES and restart of an LPI pump following deadhead operation

SBLOCA B-PI forced cooling

SGTR 3.0 REQUESTED ACTION 3.1 Requested Action Summary Evaluate restarting an LPI pump following a low flow condition or continued operation of LPI pumps at low flow conditions.

EOP cautions the operator and informs station management if LPI pumps are operated below minimum flow values:

" Any LPI pump operated at <100 gpm.

Two LPI pumps operating in piggyback with NO LPI header flow and total indicated HPI flow <500 gpm.

Turn off an LPI pump.

3.2

Background:

The manufacturer's recommended minimum flows: (recommended for accident condition only to minimize undue stresses)

" LPI flow > 100 gpm (5 continuous days)

" LPI flow > 200 gpm (one year continuous)

For some SBLOCAs, HPI cooling, or SGTR events, an interaction between the LPI pumps can occur during LPI/HPI-piggyback operation. In particular, under low flow conditions a weak-pump strong-pump interaction is established. The acceptability of the LPI/HPI piggyback alignment with two trains of LPI supplying suction to two BPI pumps through both LP-15 and LP-16 is a function of total HPI injection flow assuming no LPI flow injecting into the RCS. Analysis has been performed modeling the weak pump/strong pump interaction with both trains at a combined flowrate of 500 gpm. The analysis shows if pumps differ by as much as 7% in developed head that flow from the weaker pump will be limited.

Periodic testing verifies that the "A" & "B" LPI pumps are within this 7% assumption. If two LPI pumps are operating in piggyback with no LPI header flow and total indicated HPI flow < 500 gpm, it is recommended that one LPI pump be secured. A single LPI pump can provide sufficient flow for 2 HPI pumps.

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EM 5.1 Revision No.: 32 Page 39 of 89 Operating the LPI pumps below minimum flow will cause hydraulic instabilities. Operating the LPI pump for an extended period (@ <100 gpm) can lead to fluid flashing in the casing that can lead to cavitation and seal failure. This can be catastrophic.

Vendor recommendation is based on a similar pump that was operated at approximately 100 gpm for one month. This test showed no degradation in pump performance or component damage. To minimize undue pump stress, this manufacturer's recommendation must be adhered to.

3.3 Implementation Re-energizing an LPI pump after it has been secured because it was deadheaded or if two LPI pumps operating in piggyback with no LPI header flow and total indicated HPI flow <500 gpm requires an evaluation.

" Depending on RCS conditions, specifically RCS pressure and the rate it is decreasing, it may be advisable to secure an LPI pump in support of piggyback. A single LPI pump can provide sufficient flow for 2 HPI pumps. If acceptable increase total indicated HPI flow to >500 gpm to maintain two LPI pumps in operation.

" The temperature of the fluid in the LPI pump is a function of the length of time the LPI pump has been operating at deadhead condition. It is advisable to restart the LPI pump when it can be assured that RCS pressure has decreased that will allow LPI injection. An LPI pump can develop approximately 180 psi of developed head.

" When restarting an LPI pump for piggyback operation after it has been secured due to deadhead operation, consideration must be given to the fact that the LPI pump may only have minimum recirc flow until LP-15 & 16 are opened. Minimize the time between pump restart and opening LP-15 or LP-16.

Approximate LPI Flow Rate Calculation

The indicated LPI flow is inaccurate at low flowrates. For example the indicated flow can vary between 0.0 gpm.to 500 gpm if actual flow is <850 gpm. Based on LPI performance, it is expected that LPI flow should rapidly increase to >1000 gpm as RCS pressure decreases below shut off head (approximately 180 psig). LPI flow can be estimated based on the BWST draindown rate as follows (assuming a relatively constant rate of BWST level decrease):

- The volume of the BWST is - 7613 gals/ft.

- LPI flow = [((initial level - current level)/time) (7613)] - (sum of HPI and RBS flow)

- The instrument uncertainty analysis (worst case) are:

If RBS is operating, the flowrate uncertainty is approximately +/-40gpm.

HPI flow uncertainty is approximately 25 gpm if flow >500 gpm. For indicated HPI flow below 125 gpm, actual flow can be 0.0 gpm or > 189 gpm

- Comparison of header flows allows one to diagnose the validity of the indicated flow.

- Analysis shows that two HPI pumps can deliver approximately 550 gpm & 650 gpm @ RCS pressures of 1500 psig and 1200 psig respectively. This is assuming the HPI pumps developed head have degraded 10%.

- RB pressure can influence LPI total developed head when aligned to the BWST.

- RCS pressure must be considered in the evaluation.

3.4 Expected Plant Response VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 40 of 89 The guidance assures the minimum required flow for LPI pump during long term cooling. In addition, the guidance assures successful operation following restart of a pump after deadhead operation.

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EM 5.1 Revision No.: 32 Page 41 of 89 K. ENERGIZE THE ASW SWITCHGEAR FROM AN OPERATING OCONEE UNIT 1.0 SAFETY CONCERN Restore power supply to the HPI and ASW pumps from Oconee unit not experiencing SBO.

2.0 PROCEDURE ENTRY CONDITIONS Evaluate continued operation of LPI pumps at low flow conditions.

" An Oconee unit has tripped and is experiencing a station blackout (SBO)

The main feeder bus cannot be energized through the startup transformer and the standby bus cannot be energized from either Keowee or CT-5

" Another Oconee Unit is generating and is energizing both its MFBs.

3.0 REQUESTED ACTION 3.1 Requested action Summary:

Close the operating Oconee unit's standby breaker I (S1) to energize standby bus I (SB 1) and power the auxiliary service water switchgear (ASWS) from the operating Oconee generator.

" Connect a HPI pump (HPIP), from the Oconee unit experiencing the SBO, to the ASWS.

" This would allow HPI forced cooling of the core, while power is being restored. Also the auxiliary service water pump (ASWP) would be available to provide inventory to the steam generators if needed for cooling.

3.2

Background:

During a loss of switchgear event, the underground emergency power path or a Lee combustion turbine can supply one HPIP and the ASWP through SB1 and the ASWS. The HPIP can maintain water on the core and the ASWP can supply water to the steam generators providing a heat sink for the reactor coolant system. If the underground emergency power path or a Lee combustion turbine can not energize the standby bus, the HPIP and the ASWP would not be available. If another Oconee unit were generating, that unit could energize SBI by closing its SI breaker. The SI breaker close logic will allow the breaker to close as long as the standby bus is not energized. The ASWS could then be energized to provide power to a HPIP and the ASWP.

The typical load for a running Oconee Unit is 12-15MW. The auxiliary and startup transformers are rated at 33.6MVA. The addition load of one HPIP and an ASWP is < 1MVA or 137 amps. With both main feeder buses in service, the load on main feeder bus 1 would be within its limits. UFSAR 8.2.1 3 states that each unit's auxiliary startup transformer is sized to carry full load auxiliaries for one nuclear generating unit plus the engineered safeguards equipment of another unit. The operating load of a HPIP and an ASWP is considerably less than a unit's engineered safeguards load, thus there would be sufficient power available should the operating unit trip.

3.3 Implementation

1. Verify SBI is not energized.

2. Ensure all breakers for SB 1 are open.

3. Place CT4 BUS 1 "AUTO/MAN" transfer switch in "MANUAL".

4. Place Standby Bus I "AUTO/MANUAL" transfer switches in "MANUAL".

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EM 5.1 Revision No.: 32 Page 42 of 89

5. Close Breaker Si.

6. Have I&E perform procedure EM/O/A/0050/001, Procedure To Provide Emergency Power To An HPI Pump Motor From The ASW Switchgear.

3.4 Expected Plant Response ASW Switchgear will be energized from an operating Oconee Unit One HPI pump and the ASW pump can be operated as desired.

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EM 5.1 Revision No.: 32 Page 43 of 89 L. LIMITATIONS ON ALIGNING BPI SUCTION FROM THE SFP 1.0 SAFETY CONCERN Loss of suction source to the HPI pumps when aligned to the SFP.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" An Oconee unit has tripped and is experiencing a station blackout (SBO)

" SSF RC makeup pump is not available

" An HPI pump can be powered from the ASW switchgear

" The BWST and LDST are not available as suction sources to the BPI pumps

" The SFP can be aligned as a suction source for the HPI pumps 3.0 REQUESTED ACTION 3.1 Requested action Summary:

" Provide guidance to monitor the SFP and ensure suction remains available to the HPI pumps based on limitations on the following parameters:

" SFP level SHBPI flow rate

SFP temperature 3.2

Background:

If the BWST and LDST are not available as a suction source for the HPI pumps, it is possible to align the suction of an BPI pump to the SFP. Conditions in the SFP need to be monitored to ensure suction to the HPI pumps is not interrupted. Design calculations demonstrate that an HPI pump will have adequate NPSH when aligned to the SFP. However, suction could be interrupted based on the following two concerns:

Siphon break at elevation 822 feet in the SFP:

The suction line as a siphon break at 822 feet. This consists of two 1/2 inch holes. If the SFP level decreases to 822 feet, suction to the HPI pumps will be interrupted. Thus, this is one limit that the TSC must consider.

Flashing in the high point of the SFP suction line:

HPI flow can be interrupted if the pressure in the high point of the suction line from the SFP equals the vapor pressure based on SFP temperature. This is the primary concern when aligning HPI to the SFP.

The factors that influence flashing are:

SFP temperature - If SFP cooling is lost, SFP temperature will increase. The higher the temperature, the less margin to flashing in the high point. The factor that influences SFP temperature is the decay heat load in the SEP.

SEP level - SFP level impacts flashing in that a lower SFP level results in lower elevation head and a lower pressure in the high point of the suction line. SEP level will decrease based on the HPI flow rate.

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EM 5.1 Revision No.: 32 Page 44 of 89 HPI flow rate - HPI flow rate impacts margin to flashing by its effect on the pressure in the high point of the SFP suction line. As HPI flow rate increases, the frictional losses in the suction pipe increase.

Increased frictional losses decrease the pressure in the high point of the line, thus reducing the margin to the vapor pressure. The frictional losses due to the flow rate are a second order effect when compared to SFP level and temperature. Thus, the primary issue with SFP flow rate is its impact on SFP level.

3.3 Implementation Siphon Break If an HPI pump is aligned to the SFP, the pump should be secured prior to SFP level decreasing below 824 feet. The 824 feet criterion is selected to provide margin to the elevation of the siphon break (siphon break is at a SFP level of 822 feet).

Flashing at SFP Suction High Point Flashing in the high point of the SFP suction line depends on SFP temperature, SFP level, and the HPI flow rate. Calculation OSC-3873, Rev. 4, provides data on the SFP as a suction source for the BPI pumps. The analyses in this calculation demonstrate that the frictional losses associated with the HPI flow rate are small. Thus, the conditions at which flashing occurs can be directly determined based on only SFP level and temperature. Also, for a given SFP level and temperature, the differences between the Units 1 and 2 SFP and the Unit 3 SFP are negligible. Thus, the same data to determine the flashing point can be used for both SFPs.

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EM 5.1 Revision No.: 32 Page 45 of 89 The following figure provides the flashing curve as a function of SFP temperature and SFP level. For a given SFP temperature, the level must be maintained greater than the level in the following curve.

840 am I z 1 - IJ] z-I

- *I Acceptable Oueration II111 ilUacetbe prto I II II I II ý- - II *-

IIIIg HI IHI am - IIII II1 11 LIIII -Lll 1W 1I5 1W 165 170 175 18D 185 1W0 15 . 2D 205 210

" Monitor SFP level and temperature initially on a one half hour frequency and project changes in temperature and level to ensure continued suction remains to the HPI pumps. Adjust monitoring frequency based on projections of SFP temperature and level.

" BPI flow rate should be adjusted based on RCS requirements taking into consideration the impact of changing flow rates on SFP level.

3.4 Expected Plant Response HPI flow is successfully established from the SFP. Monitoring is in place to determine when HPI flow from the SFP should be terminated.

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EM 5.1 Revision No.: 32 Page 46 of 89 M. ENSURE TOTAL LPSW RECIRCULATION FLOW IS *59000 GPM DURING DAM/DIKE FAILURE 1.0 SAFETY CONCERN Total LPSW flow is maintained <9000 gpm during dam/dike failure scenario. Flow to various LPSW loads may require throttling to achieve desired flow rate.

2.0 PROCEDURE ENTRY CONDITIONS This guidance is used during AP/l/A/1700/013 involving dam/dike failure without loss of CCW intake canal. The Symptoms for entering AP/1/A/1700/013 are:

Visual observation of decreasing lake level or dam failure

" Telephone communication of a Keowee or Little River dam failure

" "CCW LAKE LEVEL LOW" statalarm (lSA-09/B-10)

" "FOREBAY ELEV" decreasing toward 70 feet 3.0 REQUESTED ACTION Determine which LPSW loads should be throttled to ensure total LPSW recirculation flow is

<9000 gpm.

3.1

Background:

In the event of a Loss of Lake Keowee, the preferred method of decay heat removal is via the CCW System recirculation mode. In this alignment, the Unit l&2 and Unit 3 LPSW systems are cross-connected and one LPSW pump operated to supply the required loads for all three units.

The LPSW System is aligned so that the normal discharge paths are isolated such that flow is forced in the reverse direction through the Unit I RCW coolers and back to the CCW crossover.

Per OSC-5739, total LPSW flow is limited to 9000 gpm to ensure excessive velocities are not generated in the tubes of the RCW Coolers and to reduce the likelihood of undesirable internal LPSW recirculation in certain system configurations.

3.2 Implementation

Since total LPSW flow is limited to 9000 gpm and only one LPSW pump is operating, each unit is allowed 3000 gpm of LPSW flow. LPSW loads and associated throttle valves are listed below.

"B" RBCU - I/2/3LPSW-21

"A" LPI Cooler - I/2/3LPSW-4 or I/2/3LPSW-251

"B" LPI Cooler - 1/2/3LPSW-5 or I/2/3LPSW-252

Unit 2 RBACs - 2LPSW-1061 or 2LPSW-1062. Note - RBAC flow is not required.

The above loads must be throttled as required on each unit to maintain total LPSW pump flow

9000 gpm.

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EM 5.1 Revision No.: 32 Page 47 of 89 3.3 Expected Plant Response Total LPSW flow as indicated on the operating LPSW Pump's discharge flow gauge should indicate <9000 gpm.

S S

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EM 5.1 Revision No.: 32 Page 48 of 89 N. MANAGE KEOWEE LAKE LEVEL DURING A LOOP 1.0 SAFETY CONCERN During any event involving a loss of off-site power (LOOP) and operation of Keowee Hydro Station, the lake level will decrease significantly. Decreasing lake level can adversely affect the operability of several plant systems and equipment.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" Loss of off-site power.

" Keowee Hydro Station in operation.

3.0 REQUESTED ACTION 3.1 Requested Action Summary

" Minimize usage of Lake Keowee inventory.

" Supplement Lake Keowee inventory from Lake Jocassee.

" Take actions to mitigate effects of decreasing lake level on Oconee systems/equipment as follows:

1. Minimize LPSW System demand to reduce NPSH required.

2. Align LPSW supply to Chiller Condenser Service Water Pump suction to increase NPSH available.

3. Place HPSW pumps in OFF position to increase NPSH available for LPSW pumps.

4. Isolate RWF Equipment Cooling supply and return lines from ECCW siphon headers to maintain operability of ECCW first siphon.

5. Restart two CCW pumps (one each on two separate Oconee units) to eliminate reliance on ECCW first siphon.

3.2

Background:

SLC 16.9.7 provides operability requirements for Oconee systems and equipment based on Keowee lake level. As an event progresses and lake level decreases, various actions are necessary to ensure systems and equipment remain capable of performing their functions.

The Oconee licensing basis does not provide a duration for a LOOP, but a reasonable duration for Keowee operation is 7 days (ref. PIP 0-02-136). Assuming an event begins with the lake level at 791 feet and both Keowee units are operating, the lake level would be 783.6 feet after 7 days (ref. OSC-3528).

This assumes no water transferred to Lake Keowee from Lake Jocassee.

Section 3.3 contains several estimates of the time available based on an initial lake level of 791 feet. If an event begins at some lake level above 791 feet, add about 1 day for each foot above 791 feet. For example, if an event begins at 794 feet, add three days.

3.3 Implementation 3.3.1 Minimize usage of Lake Keowee Inventory If all plant loads are being supplied by one unit at Keowee Hydro and the other Keowee unit is running at speed no-load, consider stopping the unloaded unit to conserve inventory. Operation of a Keowee unit VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 49 of 89 with no load uses almost as much water as operation fully loaded to the maximum emergency loads.

Therefore, stopping one Keowee unit would reduce water usage by more than 40% (ref. OSC-3528).

If both Keowee units are carrying some load, procedures do not exist to manually transfer plant loads from one Keowee unit to another in order to stop one Keowee unit. However, this action should be considered by the TSC if the event is expected to last significantly beyond 7 days. Differences in reliability and the potential for inducing an undesirable transient (i.e., loss of all AC power) should be considered before taking this action.

Operation and loading of combustion turbines at Lee Steam Station may allow stopping both Keowee units, thus conserving water in Lake Keowee. However, differences in reliability and the potential for inducing an undesirable transient (i.e., loss of all AC power) should be considered before taking this action.

If Jocassee Hydro is capable of starting and generating to the grid, evaluate the possibility of energizing the Oconee switchyard from Jocassee and providing power to the LOOP units from the switchyard. This would allow both Keowee units to be shutdown for some period of time to conserve water. However, differences in reliability and the potential for inducing an undesirable transient (i.e., loss of all AC power) should be considered before taking this action.

The ECCW second siphon discharge at CCW-8 transfers a small amount of flow (-30,000 gpm) from Lake Keowee to Lake Hartwell. If the second siphon is not needed, this discharge can be eliminated by closing CCW-8 per OP/I,2,3/A/1 104/012 (CCW System).

3.3.2 Transfer water from Lake Jocassee to Lake Keowee The System Operating Center (SOC) should be contacted to request transfer of water from Lake Jocassee to Lake Keowee. In order to transfer water from Lake Jocassee at the same rate that two Keowee units would use, at least one unit at Jocassee Hydro Station would have to be generating to the grid. However, water can be transferred at a slower rate by operating Jocassee units at speed no-load or by opening the spillway gates. This would at least reduce the rate of decrease of the Keowee lake level. Depending upon the Jocassee lake level, operation at speed no-load plus opening the spillway gates may supply adequate flow rate to match two units at Keowee Hydro.

3.3.3 Minimize LPSW System Demand If a loss of Instrument Air (IA) has occurred, maximum LPSW flow will be supplied to each LPI cooler.

LPSW flow to LPI coolers must be throttled on any non-ES unit to <6000 gpm (total flow for both coolers). There would be >9 hours before LPSW flow to LPI coolers must be throttled to maintain adequate NPSH for LPSW pumps (based on 790.6 feet actual limit per calculation). Operations estimated that this action would be completed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months using existing procedures. After throttling, the LPSW NPSH limit would become 781.6 feet (ref. OSC-2280).

The LPSW pump NPSH limits discussed above assume administrative controls are in place to ensure the A HPSW pump is not operating. This means that the A HPSW pump should be in "standby" with the B HPSW pump in "base" (i.e., the normal alignment) or place the A HPSW pump in "off' to prevent it from operating.

3.3.4 Align LPSW Supply to Chiller Condenser Service Water Pump Suction There would be >23 hours before we would reach the 790 ft. limit for the Chiller Condenser Service Water Pump. AP/I,2,3/A/1700/011 (Recovery from Loss of Power) contains steps to prevent air binding and ensure adequate NPSH at lower lake levels. These steps include starting additional CCW pumps or aligning the LPSW supply to the Chiller Condenser Service Water Pump (ref. OFD-124A-1.2).

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EM 5.1 Revision No.: 32 Page 50 of 89 3.3.5 Place HPSW Pumps In OFF Position The A HPSW pump may have inadequate NPSH below 791 feet. The B HPSW pump may have inadequate NPSH below 789 feet. To ensure protection of the pumps, consider placing the pumps in the OFF position to prevent automatic start. If available, use the Jockey pump to maintain EWST level instead of the A or B HPSW pumps. Also, consider temporary charging of the HPSW system using the off-site fire department per the emergency operating procedure. If short-term operation of the A or B HPSW pump is required to maintain EWST level, this should be performed manually and the duration should be minimized to avoid pump damage due to inadequate NPSH.

3.3.6 Isolate RWF Equipment Cooling Supply and Return Lines from ECCW Siphon Headers Lake level must be above 787 feet to prevent a postulated pipe break at normally open seismic boundary valves 1,2,3CCW-319 and 1,2,3CCW-320 from potentially affecting the ECCW first siphon via air in-leakage. If lake level approaches 787 feet, these valves should be closed. There would be >3.9 days before the lake level would reach 787 feet.

If enough ECCW siphon headers are operable, it may be desirable to leave the valves open on one Oconee unit to continue supplying the RWF. However, this would make the ECCW siphon headers inoperable on that unit.

As an alternative, restart of CCW pumps may be performed as discussed below instead of closing the valves.

3.3.7 Restart Two CCW Pumps Lake level must be above 786 feet to meet operability requirements for the ECCW first siphon, since the ECCW test acceptance criteria assumes a minimum lake level of 786 feet. There would be >4.8 days before the lake level would decrease to 786 feet. This is enough time for operators to restart two CCW pumps, one each on two separate Oconee units, using existing procedures (AP/l,2,3/A/1700/0l1). The CCW pumps would be able to supply suction to LPSW pumps without relying on the first siphon.

If necessary, the ECCW first siphon would continue to supply adequate suction to LPSW pumps down to 782 feet or lower. The 786 feet requirement is conservatively based on maintaining the ECCW header full. Engineering calculations have determined that adequate flow can be supplied to LPSW pumps with the water level inside the pipe about 4 feet (or less) below the top of the pipe, depending upon the number of open CCW pump discharge valves (ref. OSC-5349). Also, the actual ECCW test results may be better than the minimum acceptable results, thus providing additional margin.

If lake level is less than 786 feet and CCW pumps are not running, periodically monitor the following pumps that take suction from the CCW crossover for evidence of inadequate suction (i.e., amps fluctuating, cavitation noise at pumps):

" LPSW pumps

Chiller Condenser Service Water pumps for A, B, C, and D chillers

" HPSW Jockey pump

" CCW Booster pump 3.4 Expected Plant Response By taking actions as recommended above, the important plant systems and equipment needed for accident mitigation will remain capable of performing their functions for >7 days during a LOOP.

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EM 5.1 Revision No.: 32 Page 51 of 89

0. OPENING THE ALTERNATE POST-LOCA BORON DILUTION FLOWPATH 1.0 Safety Concern Opening the alternate post-LOCA boron dilution flowpath at elevated RCS pressure may damage the RB sump screen or supply two-phase water to the suction of the LPI pumps.

2.0 Procedure Entry Conditions.

EOP Section LOCA Cooldown/HPI Cooldown, Response Not Obtained

An Oconee unit is experiencing a LOCA.

9 The primary boron dilution flowpath cannot be opened.

9 The alternate post-LOCA boron dilution flowpath is to be opened.

3.0 Requested Action 3.1 Requested Action Summary:

Open the alternate post-LOCA boron dilution flowpath.

3.2

Background:

An LPI boron dilution flowpath is opened to prevent excessive boron concentrations in the reactor vessel due to extended operation in the "boiling pot mode" following LOCAs. In the boiling pot mode the reactor vessel functions as an evaporator and concentrates the boric acid. The guidance is in EOP LOCA and HPI Cooldown Sections. Excessive boron concentrations can result in precipitation of boric acid crystals that can lead to obstructing long-term cooling of the core. Calculations have shown that opening an LPI boron dilution flowpath is required no earlier than 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months following a large cold leg break LOCA, which is the limiting break size and location for this issue. The EOP does not include the 9 hour1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months requirement, with the expectation that this action will occur prior to 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months . The EOP does not require this action unless the core exit thermocouple temperatures are less than 400*F, and the subcooled margin does not exist. Also, RCS pressure must be less than 320 psig, to support operation of valves LP-103 and LP-104. These criteria are based on the higher solubility of the boric acid at temperatures of 400°F and higher, and that the boiling pot mode does not exist if the core exit thermocouple temperatures indicate subcooled conditions.

There is a good likelihood that gaps in the reactor vessel internals where the hot legs nozzles match up with the upper internals will provide a leakage path that will serve to prevent the concentration of boric acid in the core region. The B&WOG has analyzed these gaps and have concluded that they will function to prevent excessive boric acid concentration buildup. One drawback to crediting these gaps exists, and that is the possibility that the gaps will be plugged by debris circulated by the LPI System while drawing water from the RB sump. This possibility has been recognized by the industry and by the NRC, and so reliance on the gaps, while likely, should not be the sole method of preventing post-LOCA boric acid precipitation.

Opening the primary boron dilution flowpath through LP-103 and LP-104 does not involve any additional considerations, and is not the subject of this TSC Guideline.

Opening the alternate post-LOCA boron dilution flowpath through LP-1, LP-2, and LP-105 (Unit 1), and through LP-1, LP-2, and LP-3 (Units 2 and 3), does involve additional considerations, and that is the subject of this TSC Guideline.

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EM 5.1 Revision No.: 32 Page 52 of 89 The first consideration is that opening the alternate post-LOCA boron dilution flowpath can result in a high velocity discharge that can impinge on the emergency sump screen. This high velocity can result from the RCS being at a higher pressure than the emergency sump, and opening the alternate flowpath will then accelerate water through the pipe and towards the sump and sump screen. The second consideration is that opening the alternate post-LOCA boron dilution flowpath can result in two-phase conditions at the suction of the A LPI pump. This is possible due to the depressurization of the RCS (if the RCS pressure is higher than the RB pressure) and the possibility that water flowing through the LPI piping will flash. This situation must not be allowed since continued stable operation of the LPI pumps must be maintained.

For large break LOCAs the RCS and the RB will have equalized in pressure, and there is no adverse consequence of opening the alternate post-LOCA boron dilution flowpath. The objectives of this TSC guidance is therefore to ensure 1) that opening the alternate post-LOCA boron dilution flowpath is necessary, 2) that for SBLOCAs that the RCS and RB pressures have equalized prior to opening the alternate post-LOCA boron dilution flowpath, and 3) if pressure equalization cannot be confirmed, then the alternate post-LOCA boron dilution flowpath must not be opened.

3.3 Implementation Step 1: Determine if the boiling Rot mode exists: If the core exit thermocouple temperature indicates that the water exiting the core is subcooled, then the boiling pot mode cannot exist, and there is no requirement for opening the alternate post-LOCA boron dilution flowpath. The actual core exit thermocouple temperatures should be considered in this determination, rather than relying on the ICCM subcooled margin, since the worst-case instrument uncertainty is included in the ICCM software.

Similarly, the available RCS and RB pressure instrumentation should be used rather than just relying on the ICCM subcooled margin. LPI System flow can also be used to confirm the RCS pressure. Trends of these temperature and pressure indications should be considered since for all LOCAs the pressures and temperatures will steadily decrease in the long-term as decay heat decreases.

Step 2: Determine if the RCS level is high enough to spill borated water out the break: The reactor vessel and hot leg level indications can be used to determine if the water level is high enough in the reactor vessel to provide flow from the core outlet, through the reactor vessel internal vent valves, into the vessel upper downcomer, and then towards the cold leg break location. If this flowpath exists, then the core boron concentration cannot increase to an unacceptable value. A vessel level of 120 inches, and a hot leg level of 120 inches is sufficient for confirming that this flowpath exists, and that the alternate post-LOCA boron dilution line does not need to be opened.

Step 3: Determine if the RCS boron concentration is increasing by sampling the RB suma boron concentration: Concentration of boric acid in the reactor vessel can be evaluated by periodic sampling of the boron concentration in the RB sump. If the RB sump boron concentration is not decreasing, then the reactor vessel boron concentration cannot be increasing. An absence of a decreasing trend in the RB boron sump concentration precludes the need to open the boron dilution flowpath.

Step 4: Determine how much time is available to make this decision: A conservative earliest time requirement for opening a boron dilution flowpath is 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months . This value is the result of a conservative calculation and includes many worst-case assumptions, including a large cold leg break LOCA. For SBLOCAs a significantly longer period of time is available, since the boiling pot mode starts later, there may be a period of natural circulation, etc. For SBLOCA, boron precipitation is a concern when the RCS is saturated with CETC temperature less than 305°F (saturated pressure of 72 psia). If the core is above 72 psia no boron precipitation can occur (reference FTI Doc. 51-1266113-00 Post LOCA Boron Concentration Management). If additional determination is required, the G. 0. Safety Analysis Section VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 53 of 89 will be available to support Oconee Engineering and Operations following any station event, this determination will be their responsibility. The associated calculations can be performed in a short period of time and within the time available. The purpose of extending the time for making the decision to open the alternate post-LOCA boron dilution flowpath is to allow the RCS and RB pressures more time to equalize, or to allow the boiling pot mode to cease. Both of these situations are more likely as decay heat diminishes over time.

Step 5: Continue efforts to recover the primary boron dilution flownath: Since there are no adverse consequences associated with the primary boron dilution flowpath, it is the preferred mitigation method.

Recovery of the use of the primary boron dilution flowpath should be a priority.

Step 6: Confirm equalization of RCS and RB pressures: During the time period available (9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months plus the additional hours resulting from the Step 4 analysis), evaluate the available data to determine if RCS and RB pressures have equalized. Engineering should be consulted to obtain information on the uncertainty in the process data, so that the possible adverse effect of instrument uncertainty is considered.

Since some uncertainty in the process data will exist, confirming that RCS and RB pressure have equalized will involve some degree of judgment. Management concurrence with a decision to open the alternate post-LOCA boron dilution flowpath is required.

Step 7: Open the alternate post-LOCA boron dilution flowpath and monitor the LPI pumps: If Steps 1-6 have been performed and opening the alternate post-LOCA boron dilution flowpath is still necessary, and the allowable time determined in Step 4 has expired, and management concurs, then the alternate post-LOCA boron dilution flowpath is opened. Note that opening the alternate path is not recommended unless

RCS is saturated with CETC temperature less than 305°F (saturated pressure of 72 psia). Align alternate boron dilution flow path as follows:

Note: The minimum system design (pressure & temp. rating) for both LPI & RBS in all units is 200 psig

/300F.

Note: Unit 1 alternate post-LOCA boron dilution flowpath has potential for gas intrusion into the ECCS system (Generic Letter 2008-01). The guidance provided in the steps below is intended to eliminate this potential for introducing air into the ECCS piping or components.

1. Ensure LP-6, LP-9, LP-21 are closed

2. Ensure B or C LPI pump providing HPI piggy back through LP-16

3. Secure A BS pump and close BS-1

4. Secure A LPI pump

5. Close LP-19

6. Open LP-3, LP-2, LP-1

7. Throttle open BS-I to obtain flow indication (nominally 100 gpm). Note this action could potentially wind mill the RBS pump

8. When RCS pressure decays flow and thru BS-I will diminish, close BS-I.

9. For Unit 1 Only, when RCS pressure minus Reactor Building Pressure is less than or equal to 10 psid, open LP-105. (Based on RCS low range pressure indication and building pressure)

Note: For Unit 1 Only: In order to drive non condensables out from the line, it is recommended to wait 10 minutes after opening LP-105 before proceeding to Step 10.

10. OpenLP-19 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 54 of 89

11. Align A LPI back to Emergency sump SteR 8: Report to management on the plant response to onening the alternate vost-LOCA boron dilution flowath.

3.4 Expected Plant Response No observable change in RCS conditions is expected.

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EM 5.1 Revision No.: 32 Page 55 of 89 P. DEPRESSURIZING THE REACTOR BUILDING AFTER A LOSS OF DHR EVENT DURING MODES 5 AND 6 1.0 SAFETY CONCERN Depressurize the reactor building when building pressure reaches I psig to maintain containment closure during MODES 5 and 6. This guidance is mainly applicable to the steam generator replacement outage when building tendons will be detensioned and concrete will be removed beginning in MODE 5, but could be applied generically.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of this guidance.

" Loss of offsite power during MODES 5 and 6

" Loss of DHR during MODES 5 and 6 3.0 REQUESTED ACTION 3.1 Requested Action Summary Depressurize the reactor building when pressure reaches 1 psig and maintain pressure below 8 psig via the reactor building purge pathway during MODES 5 and 6.

3.2

Background:

During movement of recently irradiated fuel assemblies within containment, a release of fission product radioactivity within containment is restricted from escaping to the environment. Recently irradiated fuel is fuel that has occupied part of a critical reactor core within the previous 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In MODES 1, 2, 3, and 4, this is accomplished by maintaining containment OPERABLE as described in ITS LCO 3.6.1, "Containment." In MODES 5 and 6, the potential for containment pressurization as a result of an accident is not likely; therefore, requirements to isolate the containment from the outside atmosphere can be less stringent In order to make this distinction, the penetration requirements are referred to as "containment closure" rather than "containment OPERABILITY." Containment closure means that specified escape paths are closed or capable of being closed. During movement of recently irradiated fuel assemblies within containment, the specified escaped paths that are controlled by LCO 3.9.3 are the equipment hatch, the air locks, and the penetrations which provide direct access from the containment atmosphere to the outside atmosphere. Since there is no significant potential for containment pressurization, the Appendix J leakage criteria and tests are not required.

The requirements on containment penetration closure ensure that a release of fission product radioactivity within containment will be restricted from escaping to the environment. The closure restrictions are sufficient to restrict fission product radioactivity release from containment due to a fuel handling accident during refueling. However, to ensure containment closure is maintained during a loss of DHR event that causes building pressure to escalate, additional guidance will be presented in this section to depressurize the reactor building through the purge release pathway via opening valves PR-l, -2, -3 and starting the purge fan. This pathway will filter the building air using the purge exhaust filter, monitor the air using the Unit Vent Radiation Monitor (1,2,3 RIA-45), and exhaust the air to the vent stack. There will be guidance provide for 1) a loss of DHR event caused from the loss of power and 2) a loss of DHR event NOT caused from a loss of power. It should be noted that this guidance is specific to the steam generator replacement outage when building tendons will be detensioned and concrete will be removed beginning in MODE 5, but could be applied generically.

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EM 5.1 Revision No.: 32 Page 56 of 89 The Reactor Building Purge System includes a supply penetration and exhaust penetration. During MODES 1, 2, 3, and 4, two valves in each of the supply and exhaust penetrations are secured in the closed position. The system is not subject to a Specification in MODE 5. In MODE 6, large air exchanges are necessary to support refueling operations. The purge system is used for this purpose, and two valves in each penetration flow path may be closed on a unit vent high radiation signal. The Unit Vent Radiation Monitor (1,2,3 RIA-45) closes the four outboard isolation valves (1,2,3 PR-2, -3, -4, -5) associated with R.B. Purge Penetrations (19 and 20). The capability of RIA-45 to close the valves is verified immediately prior to movement of recently irradiated fuel. If a loss of DHR event occurs, AP/1,2,3/A/1700/026 secures RB purge and closes 1,2,3 PR-i, -2, -3, -4, -5, and -6. However, if during this event the building begins to pressurize and jeopardize containment closure during MODES 5 or 6, purge will be restarted per this guidance document.

It should again be noted that this guidance is specific to the steam generator replacement outage when building tendons will be detensioned and concrete will be removed beginning in MODE 5, but could be applied generically. In addition, with respect to accident analyses, there is no credit taken for any containment boundary in limiting releases during MODES 5 or 6. However, as a defensive measure, containment closure is maintained per Technical Specifications.

3.3 Implementation 3.3.1 Loss of DiR Event Caused from a Loss of Power Event Monitor Reactor Building Pressure During the steam generator replacement outages, if a loss of DHR event occurs, reactor building pressure should be continuously monitored and should not exceed 8 psig, as this is the limiting pressure the liner plate can withstand without buckling or rupturing. Action will be taken to depressurize the building when pressure reaches I psig.

Denressurize Reactor Building Upon a loss of DHR event that causes reactor building pressure to escalate, the following steps should be taken when building pressure reaches I psig:

I. Upon loss of power, wait until power is restored (estimated at approximately 23 seconds).

2. Restore reactor building purge via OP/1,2,3/A/1 102/014 Enclosure "RB Purge Release." Ensure purge flow rate does not exceed 50,000 cfm.

3. If the purge filter high dP alarm is received, slow the release by throttling PR-3 until alarm is silenced.

4. If core damage is indicated, terminate the purge by closing PR-I, -2, and -3. Indication can include, but is not limited to, reactor engineering recommendation, RP offsite sampling, or RIA response.

3.3.2 Loss of DHR Event NOT Caused from a Loss of Power Event Monitor Reactor Building Pressure During the steam generator replacement outages, if a loss of DHR event occurs, reactor building pressure should be continuously monitored and should not exceed 8 psig, as this is the limiting pressure the liner plate can withstand without buckling or rupturing. Action will be taken to depressurize the building when pressure reaches I psig.

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EM 5.1 Revision No.: 32 Page 57 of 89 Depressurize Reactor Building Upon a loss of DHR event that causes reactor building pressure to escalate, the following steps should be taken when building pressure reaches I psig:

1. Restore reactor building purge via OP/l,2,3/A/1 102/014 Enclosure "RB Purge Release." Ensure purge flow rate does not exceed 50,000 cfm.

2. If the purge filter high dP alarm is received, slow the release by throttling PR-3 until alarm is silenced.

3. If core damage is indicated, terminate the purge by closing PR-i, -2, and -3. Indication can include, but is not limited to, reactor engineering recommendation, RP offsite sampling, or RIA response.

3.4 Expected Plant Response It is expected that the reactor building pressure will decrease and the air being released via the purge pathway will be filtered adequately.

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EM 5.1 Revision No.: 32 Page 58 of 89 Q. ACTIONS TO REDUCE EFFECTS OF RBES SCREEN BLOCKAGE BY DEBRIS 1.0 SAFETY CONCERN Debris that may be generated by a RCS break can be transported to the RB Emergency Sump and partially block the sump screen. Accumulation of debris on the sump screen can increase pressure loss to the point that NPSH. for the LPI pumps may be lost 2.0 PROCEDURE ENTRY CONDITIONS A LOCA has occurred and the BWST has been depleted which required aligning the ECCS for recirculating water from the RB Emergency Sump.

3.0 REQUESTED ACTION 3.1 Requested action Summary 3.1.1 Symptoms If valid symptoms of sump blockage are observed proceed with the actions listed in Section 3.1.2.

Valid symptoms of sump blockage include:

" Both LPI header flow rates decreasing with steady RCS pressure, and/or not increasing as RCS pressure decreases. If only one LPI pump is operating, start the idle pump (assuming it wasn't lost due to single failure) to verify that the flow loss is not a mechanical or electrical degradation effect (note that the flow reduction [per pump] when going from one operating pump to two operating pumps may reduce the pump NPSH. sufficiently to eliminate cavitation, at least for a while).

We don't want to enter this procedure if a flow rate is dropping due to degradation of one LPI pump or other similar "single failure" type of events.

Although this symptom could also be caused by flow blockage downstream of the sump screens possibly in valves LP-12 and LP-14 or in the LPI cross tie flow elements (LPIFE0006&0007) rather than pump cavitation, this would have the same effect on availability.

" Pump low AP alarm is received and actual (not instrument adjusted) LPI pump flow rate is known to be less than about 3700 gpm (this includes both LPI header flow and any piggyback flow to HPI). Again, if only one LPI pump is operating, start the idle pump to verify the problem isn't caused by a "single failure".

" Pump motor amps low and/or cycling on both LPI pumps

This likely won't be seen until there is severe cavitation occurring. The other symptoms are expected to appear first. Again, if only one LPI pump is operating, start the idle pump to verify the problem isn't caused by a "single failure".

HPI may have been secured due to meeting HPI termination criteria, or HPI may still be in service.

3.1.2 Actions

1. Insure that BWST inventory recovery is in progress and is proceeding as rapidly as possible (this is of highest priority since the BWST may become the only source of ECCS water if sump screen clogging becomes severe).

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EM 5.1 Revision No.: 32 Page 59 of 89

Alternatives such as makeup from a spent fuel pool or from another unit's BWST (not possible for Unit 3 due to piping differences) must be considered since HPI flow rates will be higher than normal makeup sources

2. If both BS trains are in operation, reduce to one operating pump. BS valves should remain open.

" (BS-I & BS-2 and BS-3 & -4, and BS-12, & 17 should NOT be isolated if LP-9 and LP-10 are open since LPI suction pressurization is prevented via BS pump & open BS header isolation valve).

" If there are signs of BS or LPI pump caviation, then consider securing all RB spray flow if containment isolation is complete (per ES checklist) and there are no signs of a containment breach.

3. Do not throttle LPI flow rate

4. Continue to run LPI pumps as long as pump flow rates are above pump min flow requirements, and other parameters appear relatively stable (motor amps, bearing temps, etc.,

as available).

If operating with LPI discharge headers cross connected (LP-9 & LP10 open to mitigate a single failure), and pump minimum flow requirements can be met, there is some benefit to running two LPI pumps since each wiln be operating at a lower flow rate and NPS-I will be less than if only one pump is supplying the total flow.

5. If LPI flow is reduced to the point that either the core is superheated or indicated vessel level is < 0",

> Align HPI pumps to the BWST (note that valve LP-28 must be reopened since it is closed as a part of the swap from the BWST to the sump).

> Initiate/Verify full HPI flow and throttle to _<475 gpm/pump until core is no longer superheated.

Full HPI flow is initially established to reestablish liquid level as quickly as possible. Note that a Reactor Vessel RVLIS indicated level of > 11.2" assures that vessel level has increased to at least the bottom of the hot leg piping. It will not be possible to achieve this indication for all postulated breaks due to liquid spilling from some breaks.

> If indication of being saturated is detected, HPI flow can be throttled to the values in the table below

Degraded LPI flow rate augmented by the throttled HPI flow rate should be sufficient to maintain core coverage. Reducing HPI flow by the maximum amount possible is important to extend the limited supply of fluid in the BWST

> Throttling LPI should only be performed to ensure adequate NPSH for HPI in piggyback. It is acceptable to throttle/terminate direct LPI injection if adequate HPI flow is available and the objective is reducing total LPI flow to ensure adequate LPI pump NPSH.

> If at any time the RCS is subcooled, throttle HPI flow while maintaining RCS subcooling >0SF.

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EM 5.1 Revision No.: 32 Page 60 of 89 Minimum HPI Flow with Subcooling < 0*F Time after Minimum indicated HPI Minimum indicated shutdown flow (gpm) HPI flow (gpm)

(hr) (2 headers) (1 header)

<1 660 (330 per header) 630*

1 580 (290 per header) 535*

2 500 (250 per header) 440 3 460 (230 per header) 390 4 430 (215 per header) 350 5 410 (205 per header) 320 6 390 (195 per header) 290 8 370 (185 per header) 270 12 350 (175 per header) 250 24 340 (170 per header) 220 36 340 (170 per header) 210 48 340 (170 per header) 205

exceeds recommended flow from one pump 3.2 Background

" Throttling LPI flow is NOT recommended. If break is core flood line break, with 2200 gpm of actual flow, the adverse flow split may be as low as 0 gpm to the core.

" Reducing flow rate from the RBES will minimize flow velocities in and around the sump. This has two effects:

o Reduced velocity reduces debris transport to the sump o Reduced velocity through the sump screen (and any accumulated debris "mat") will reduce the head loss across the sump screen and increase NPSH. for the LPI and BS pumps o Throttling LPI header flow rate and/or realigning HPI pumps back to a refilled BWST reduces the flow rate of the operating LPI pumps which decreases the pump's NPS-I.

Debris generation is, in general, a function of break size and proximity of targets that can generate debris o Larger breaks increase break flow rates and volume affected by jet spray. Although the blowdown jet flow duration is shorter than for smaller breaks, it is expected that larger breaks will generate more debris than a smaller break (at the same location).

o Larger breaks result in higher flow rates both from the RB Emergency Sump and from the BWST (this minimizes the amount of time for "settling" of debris between end of blowdown and start of recirculation)

" Oconee is a relatively "clean" unit (based on building walkdowns/cleaning, amount of fibrous insulation that can be a target of a LOCA break). These compensatory actions are not expected to be implemented, but are in response to NRC Bulletin 2003-01.

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EM 5.1 Revision No.: 32 Page 61 of 89 3.3 Implementation The requested actions are intended to address beyond current licensing basis concerns that debris may accumulate on the emergency sump screen and increase pressure drop to the point that LPI pump performance is degraded due to cavitation. Performing these steps will reduce the potential for pump damage that could result in less flow being provided to the reactor vessel following a LOCA.

3.4 Expected Plant Response The actions identified in this guide are intended to prolong the period of time that ECCS can be provided to the core if sump blockage occurs. The postulation of significant sump blockage is beyond current licensing basis and is considered to be very unlikely. These actions are intended to be an interim step to reduce the consequences of some, but not all scenarios that can be postulated.

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EM 5.1 Revision No.: 32 Page 62 of 89 R. GUIDANCE FOR ESTABLISHING PZR BUBBLE WITHOUT PZR TEMPERATURE INDICATION 1.0 SAFETY CONCERN The EOP does not address how to determine when PZR bubble has been formed if the PZR RTD's are lost.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

" HPI Cooldown

" Forced Cooldown 3.0 REQUESTED ACTION 3.1 Requested Action Summary The EOP instructs the Operator to reduce PZR level to 300" when PZR temperature is equal to PZR saturation temperature. However, if the PZR RTDs fails, the action cannot be performed as instructed.

An OPS guide will direct operations to consult the TSC for guidance.

3.2

Background:

By procedure, the actions in the EOP will have placed the RCS in stable condition when this action is requested. The Operator has been controlling the RCS pressure by controlling the feedwater and TBV.

The RCS is water solid and subcooled. The procedure will have instructed the Operator to energize the PZR heaters. En route to reaching this step in the procedure, the Operator would have realized that the RCS pressure is sensitive to the feedwater flow. It was also expected that the Operator would have maintained RCS pressure greater than 1600 but less than 2300 psig. The pressure band was selected to prevent ES actuation on low RCS pressure and prevent lifting the PORV on high RCS pressure.

3.3 Implementation

" If the surge line temperature indication is available, the indication can be used in placed of the PZR RTD. This indication can be used to determine if the saturation temperature in the PZR has been reached via RCS wide range pressure indication. Re-energizing the PZR heaters when the RCS is water solid and stable condition will hydraulically cause the stagnant fluid in the surge line to migrate to the hotleg due the thermal expansion. This has been verified in the simulator. Note, the surge line thermocouple is NON-safety and NON EQ. The surge line temperature will lag the actual PZR temperature.

Actual times to form PZR bubble may vary depending on plant conditions and available equipment.

PZR bubble can be verified to have formed when the RCS pressure becomes less sensitive to increases in letdown flow while feedwater flow was maintained constant. Note, when verifying the bubble has formed letdown must be increased slowly while observing the RC pressure. If RC pressure drops below 1700 psig reduce letdown to match makeup. It is important not to decrease RC pressure below 1600 psig to avoid ES actuation.

3.4 Expected Plant Response The guidance assures that PZR bubble has been formed and controlled shutdown to DHR operation can 0 later be established.

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EM 5.1 Revision No.: 32 Page 63 of 89 S. ALTERNATE HPI TERMINATION CRITERIA WHEN OPERATING FROM THE RB SUMP 1.0 SAFETY CONCERN The HPI Termination Criteria contained in the EOP is conservatively based on maximum decay heat at reactor trip. As core decay heat drops, the amount of water required for decay heat removal is reduced and the indicated LPI flow rate that is required to assure this amount of water is delivered to the vessel can be reduced. Taking credit for this reduction will enable termination of HPI Piggyback earlier than using the conservative criteria employed in the EOP. The Alternate HPI Termination Criteria have been established in OSC-2820 for those units that have implemented the LPI Cross Tie Modification.

2.0 PROCEDURE ENTRY CONDITIONS A LOCA has occurred, HPI operation has not been secured via criteria in the EOP, and the LPI pumps are taking suction from the RB Emergency Sump.

Note that "Alternate HPI Termination Criteria" have only been established for Units that have the LPI Cross Tie Modification installed.

3.0 REQUESTED ACTION 3.1 Requested action Summary 3.1.1 Symptoms When operating the ECCS in piggyback mode, BPI operation may be terminated if indicated LPI flow rates are high enough. This can be determined using the following steps:

1. Determine:

" the time from reactor trip and

" the number of operating LPI pumps (note that these criteria are not valid if LPI Pump IC or 2C is in operation).

2. Using the time from reactor trip and the number of operating LPI pumps, enter the appropriate column to determine the minimum total LPI flow rate that will permit securing the HPI pumps and exiting "HPI piggyback" operation.

" For Unit 1 use Table 3.1.

" For Unit 2 use Table 3.2.

3. If only one LPI pump is operating and the indicated LPI header flow rate exceeds the flow rate required, then it is recommended that the TSC inform the control room that Alternate HPI Termination Criteria have been met and recommend that appropriate steps be taken to secure from HPI Piggyback Operation.

4. If two LPI pumps are operating and the sum of the indicated LPI header flow rates exceeds the flow rate required from the appropriate Table, then it is recommended that the TSC inform the control room that Alternate HPI Termination Criteria have been met and that appropriate steps be taken to secure from HPI Piggyback Operation.

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EM 5.1 Revision No.: 32 Page 64 of 89 Table 3.1 Table 3.2 Unit I Alternate HPI Termination Unit 2 Alternate HPI Termination Criteria Criteria Time Either LPI Both LPI Time Either LPI Both LPI after Pump IA Pump IA after Pump 2A Pump 2A Reactor or 1B is and 1B Reactor or 2B is znd 2B Trip Operating are Trip Operating are Operating Operating

2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 2700 gpm 3200 gpm I hour 2700 gpm 3100 gpm 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 2650 gpm 3100gpm 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 2600 gpm 3000 gpm 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months 2600 gpm 3070 gpm 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months 2575 gpm 2950 gpm 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 2575 gpm 3050 gpm 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 2550 gpm 2910 gpm 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months 2560 gpm 3040 gpm 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months 2520 gpm 2900 gpm 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 2550 gpm 3030 gpm 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 2510 gpm 2880 gpm 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months 2530 gpm 3000 gpm 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months 2490 gpm 2860 gpm 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 2500 gpm 2980 gpm 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 2460 gpm 2830 gpm 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months 2480 gpm 2950 gpm 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months 2440 gpm 2800 gpm 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 2440 gpm 2910 gpm 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 2400 gpm 2760 gpm 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 2430 gpm 2900 gpm 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 2390 gpm 2750 gpm 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months 2420 gpm 2890 gpm 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months 2380 gpm 2740 gpm These criteria are not applicable if These criteria are not applicable if LPI Pump IC is operating. LPI Pump 2C is operating.

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EM 5.1 Revision No.: 32 Page 65 of 89 3.2 Background

" Depending on break size and location, it may be difficult to achieve the conservative HPI Termination Criteria contained in the EOP. The LPI flows required for HPI Termination in the EOP are based on decay heat immediately after reactor trip and ensure that approximately 600 gpm of LPI flow is delivered to the Reactor Vessel (after accounting for the worst case break location [Core Flood Line Break], amount of LPI flow that can be directed spilled to the RB, flow instrument uncertainty, strongest LPI pumps, maximum Keowee frequency, etc.).

BPI Termination is an important milestone in mitigating a Small Break LOCA.

" As core decay heat drops following Reactor Trip, the flow rate that must be delivered to the RV to makeup for boil-off decreases. As a result, the required indicated LPI flow rates can be reduced as a function of time as shown in these tables. The tables are from calculation OSC-2820, Appendices F and G (Unit 1 and Unit 2 respectively).

3.3 Implementation The requested actions are intended to allow HPI Termination earlier than may otherwise occur if the criteria in the EOP are used. Earlier termination is desirable since it reduces the amount of equipment that needs to operate to mitigate a LOCA. Also earlier termination of HPI is desirable since it is not considered to be required to operate in the "long term". Securing HPI will also reduce the flow rate of the operating LPI pumps which is desirable since it will reduce pump NPS-I and increases NPSHB.

3.4 Expected Plant Response The actions identified in this guide are intended to reduce the period of time that HPI is required to operate to mitigate certain LOCAs. This is consistent with the HPI system not being required to operate in the "long term" following a LOCA. The capability of securing HPI sooner also reduces the flow rate withdrawn from the RB Emergency Sump which helps to reduce the chance of debris transport and fouling of the sump screen.

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EM 5.1 Revision No.: 32 Page 66 of 89 T. ALTERNATE WATER SOURCE FOR POST-ACCIDENT BWST REFILL 1.0 SAFETY CONCERN 1.1 LOCA Mitigation If significant sump screen blockage occurs, additional BWST inventory is desired to support ECCS and BS pump NPSH in sump recirculation alignment. Re-establishing inventory in the BWST would allow its use as a suction source for the pumps and would increase level in the Reactor Building Emergency Sump if used. The additional RBES level would increase NPSHa to the pumps. NRC bulletin 2003-01 requested licensees to identify alternate sources of water to support post-LOCA BWST refill in the event of degraded sump performance.

1.2 SGTR Mitigation In the event of a Steam Generator Tube Rupture, OSC-2820 states that a BWST level of 35 feet should be maintained to ensure that sufficient inventory will be available during a prolonged cooldown. Alternate water sources for BWST refill are desired for satisfying this requirement 2.0 PROCEDURE ENTRY CONDITIONS One of the following scenarios has occurred:

2.1 Loss Of Coolant Accident

A LOCA has occurred and ES has actuated at least one train of BS and LPI systems.

BWST inventory has been depleted and transfer of LPI/BS pump suction to RBES has been performed per EOP guidance.

Symptoms of RBES blockage are observed, specifically signs of LPI or BS pump distress or inadequate flow rates from these pumps.

" Normal BWST refill actions provided in the EOP have been performed and additional inventory is desired.

2.2 Steam Generator Tube Rupture

A SGTR has occurred and BWST level has fallen below 35 feet.

Normal BWST refill actions provided in the EOP have been performed and additional inventory is desired.

3.0 REQUESTED ACTION 3.1 Requested Action Summary It is desired to align the Spent Fuel Pool to the BWST of the affected unit. Alignment is accomplished by manual manipulation of various valves in the SF system and LP-28 in the LPI system. Flow path is from SF suction piping to BWST outlet piping.

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EM 5.1 Revision No.: 32 Page 67 of 89 3.2 Background Around 1998, the NRC identified a safety issue, known as Generic Safety Issue 191 (GSI-191), which involves the potential blockage of the Reactor Building Emergency Sump screens with debris generated from a LOCA jet, combined with resident (pre-existing) containment debris which could transport to the sump screens. This debris could create excessive head loss across the screens, reducing Net Positive Suction Head (NPSH) available to the LPI and BS pumps in the post-LOCA sump recirculation mode of operation below that required for acceptable pump operation. Reduced NPSH could cause pumps to cavitate, resulting in a number of adverse consequences such as excessive pump vibration, flow instability, loss of flow, or reduction of flow rates to unacceptable levels.

In June of 2003, the NRC issued Bulletin 2003-01 on this same issue. The focus of the bulletin was to identify compensatory measures which could be taken to reduce risk of core melt in the event of a LOCA.

One such compensatory measure was to identify alternate water sources that could be used to support post-LOCA sump recirculation. The purpose of this TSC guidance is to identify one of those alternate water sources. Additional water sources are identified in the EOP. This guideline should be used with discretion if and when the existing EOP guidance for usage of alternate water sources for BWST refill has been utilized and found to be insufficient.

This guide was recognized to have applicability to the SGTR event as well as the LOCA, although for different reasons. The emphasis for the SGTR event is maintaining sufficient inventory for prolonged injection versus the LOCA scenario which involves re-establishing injection after swapover to BWST and experiencing symptoms of blockage of the Reactor Building Emergency Sump screen.

3.3 Implementation To add inventory to the BWST from the Spent Fuel Pool, perform the following:

1. Secure all SF pumps.

2. Ensure *LP-21 AND *LP-22 closed.

3. Open *SF-53.

4. Open *SF-55 (Unit I or 3) or *SF-56 (Unit 2)

5. Ensure open *LP-28

6. Monitor level and temperature in SFP.

7. If SFP level drops to -3 ft, secure gravity drain and re-establish SF Cooling.

8. If SFP temperature exceeds 130 F, secure gravity drain and re-establish SF Cooling.

9. When draining complete, secure gravity drain.

10. For LOCA mitigation, align BWST to HPI or LPI suction and inject into RCS.

II. If desired, re-establish sump recirculation with LPI.

12. Initiate actions to raise level in SFP.

13. Re-establish cooling to the SEP.

3.4 Expected Plant Response VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 68 of 89

Spent Fuel Pool Level will decrease.

BWST Level will increase.

Signs of pump distress should improve when sump recirculation is re-established.

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EM 5.1 Revision No.: 32 Page 69 of 89 U. LOSS OF SPENT FUEL POOL LEVEL 1.0 SAFETY CONCERN Loss of SFP inventory can cause fuel to become uncovered.

2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance:

Entry into AP/1&2/A/1700/035 has occurred.

Entry into AP/3/A/1700/035 has occurred.

3.0 REQUESTED ACTIONS 3.1 Requested Action Summary NOTE: All actions should be coordinated with Security and RP 3.1.1 Provide Makeup to the Spent Fuel Pool The table on the following pages provides information on the SFP makeup options along with the associated procedure, inventory volume, expected pump flow rates, location of pumps, and from where the pumps are controlled.

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EM 5.1 Revision No.: 32 Page 70 of 89 Table U.I. Available Makeup Flow Paths to the SFP Suction Procedure or Volume of Inventory Expected Flow Equipment ID of Location of MCC and from Where Controlled Source Document that Makes Rate Pump(s) Pump(s)

Alignment BHUT (Bleed OP/1&2,3/A/I104/006C - 'A'BHUT, 1000fl3 -150 gpm 9 IA/2A/3A BTP: Ul: AB 107

IABTP: IXL-ID, UI Control Transfer AP/1&2,3/A/1700/035 or 82280 gal 1/2/3 CSPU0003 U2: AB 125 Room and Waste Disposal PUMP) "'B' BHUT, 11000 ft3 e IB/2B/3B BTP: Control Panel or 82280 gal 1/2/3 CSPUO U3: AB 161 e IB BTP: IXN-lB, U1 Control Room and Waste Disposal Control Panel a 2A BTP: 2XL-2D, U2 Control Room and Waste Disposal Control Panel

2B BTP: 2XN-IB, U2 Control Room and Waste Disposal Control Panel

3A BTP: 3XL-ID, U3 Control Room and Waste Disposal Control Panel

3B BTP: 3XN-IB, U3 Control Room and Waste Disposal Control Panel VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 71 of 89 Suction Procedure or Volume of Inventory Expected Flow Equipment ID of Location of MCC and from Where Controlled Source Document that Makes Rate Pump(s) Pump(s)

Alignment CBAST OP/I&2,3/A/I104/006C 3000 fl or 22440 gal -100gpm 1/2/3 CBAST Pump: UhL.AB 106 e Unit 1 CBASTPump: 1XN-2E, (CBAST 1/2/3 CSPU0005 UI Control Room and Waste Pump). U2: AB 124 Disposal Control Panel U3: AB 166

Unit 2 CBAST Pump: 2XUB-21, U2 Control Room and Waste Disposal Control Panel e Unit 3 CBAST Pump: 3XL-4D, U3 Control Room and Waste Disposal Control Panel BAMT(LP OP/I&2,3/A/I104/006C 500 fi or 3740 gal 10gpm

A/3ALPBAMT UO: AB 111 * 'A'LPBAMTPump: IXL-6A, BAMT Pump) Pump: 0/3 U3: AB 150 UI Control Room and Chemical CAPU0002 Addition Control Panel

B/3B LP BAMT * 'B' LP BAMT Pump: IXN-6B, Pump: 0/3 U2 Control Room and Chemical CAPU0003 Addition Control Panel e 3A LP BAMT Pump: 3XL-6A, U3 Control Room and Chemical Addition Control Panel

3B LP BAMT Pump: 3XN-6B, U3 Control Room and Chemical Addition Control Panel VERIFY PRINTED COPY AGAINST ELECIRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 72 of 89 Suction Procedure or Volume of Inventory Expected Flow Equipment ID of Location of MCC and from Where Controlled Source Document that Makes Rate Pump(s) Pump(s)

Alignment Demin Water OP/l&2,3/A/I104/006C e 'A' Filtered Water e single pass RO, e 'A' permeate pump:

permeate and e 'A'permeate pump: XWT-IB, AP/I&2,3/A/1700/035 Tank, 45000 gal 2 permeate ODWPUOO1OA multimedia RO Skid

" 'B' Filtered Water pumps - 300 e 'B' permeate pump: filter Service * 'B' permeate pump: XWT-4D, Tank, 45000 gal gpm ODWPU00lO0B Bldg. Column RO Skid

" Permeate Storage

dual pass RO, I e 'A' booster pump: AA9 * 'A' booster pump: XWT-2C, RO Tank, 45000 gal permeate pump - ODWPU00O1

booster. water Skid 200 gpm e 'B' booster pump treatment room * 'B' booster pump: XWT-2D, RO bypass RO, 2 ODWPU0002 Skid booster pumps - * 'A' multimedia e 'A' multimedia filter pump:

450 gpm filter pump: XWT-4BB, Water Treatment OFWPU0016 Main Control Panel 0 'B' multimedia * 'B' multimedia filter pump:

filter pump: XWT-4CT, Water Treatment OFWPU0017 Main Control Panel BWST(SFC EM5.l, Engineering max: 390,000gal 1600 gpmusing2

A/3ASFCPump: U1/2: AB218 * 'A' SFCPump: lXL-2C, U2 Pumps) Emergency Response Plan credited: 355,000 gal SFC pumps 0/3 SFPU0001 U3: AB 255 Control Room

B/3B SFC Pump * 'B' SFC Pump: IXN-3C, U2 SFPU0002 Control Room

'C' SFC Pump * 'C' SFC Pump: 2XL-2BB, U2 SFPU0006 Control Room e 3C SFC Pump: e 3A SFC Pump: 3XL-2C, U3 3SFPU0003 Control Room

3B SFC Pump: 3XN-3C, U3 Control Room a 3C SFC Pump: 3XF-4C, U3 Control Room VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 73 of 89 Suction Procedure or Volume of Inventory Expected Flow Equipment ID of Location of MCC and from Where Controlled Source Document that Makes Rate Pump(s) Pump(s)

Alignment BWST AP/1&2,3/A/1700/035 max: 390,000 gal -100 wpm Unit 0/3 BWST Recirc U1/2: AB 218 (BWST Reci credited: 355,000 gal Pump: 0/3 SFPU0004 U3: AB 255 Pump)

Lake (via fire AM/0/A/3009/012A unlimited Unit 1,150 gpm N/A fire truck N/A trucks through Unit 3, 100 gpm SSF hard pipe)

- - higher flow rate could be achieved if different assumptions are used VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 74 of 89 3.1.2 Control of Steam Condensation

1. To prevent the potential for condensation dripping on safety related equipment, perform the following actions:

" Ensure SFP Ventilation System Fans are not operating.

" Manually close damper D-1 (AB-6 in ceiling north of column 73 and east of column T for Unit I)(AB-6 in ceiling at column T-89 Room 650 and SFP for Unit 3) by disconnecting the actuator and securing. Ladders are available. A 10' ladder for each damper, 1/4" x 6' 1g. rope and 2ea 12" adjustable wrenches.

3.1.3 Enhance SFP Air Circulation

1. To promote forced. filtered air flow, perform the following actions:

Ensure SFP Filtered Exhaust Fan F-i or F-2 is operating to promote forced air circulation and filtered exhaust (AB6/entry into SFP).

2. If SFP Filtered Exhaust system is not available and fuel has been uncovered or it is anticipated that fuel may become uncovered, consider the following methods to enhance air circulation in the SFP area:

To promote forced. unfiltered air flow, perform the following actions:

NOTE: If this action is taken, damper D-1 must be unsecured. The potential exists for condensation to drip on safety related equipment as discussed in section F, "Makeup and Monitoring of the SFP and Recovery From a Boiling Condition."

" For Units 1 & 2, ensure AHU-9 is operating Ensure exhaust fans EF 19/20/21 (two of the three) are operating.

For Unit 3, ensure AHU 3-10 is operating. Ensure exhaust fans EF 3-4/3-5/3-6(two of the three) are operating.

For Units 1&2, ensure exhaust fans EF 19/20/21 (two of the three) are operating.

Open fuel bay roil-up door as required to draw air through SFP area.

For Unit 3, ensure exhaust fans EF3-4/3-5/3-6 (two of the three) are operating.

Open fuel bay roll-up door as required to draw air through SFP area.

To promote natural, unfiltered air flow, perform the following actions:

" Open fuel bay roll-up door as required. Open the door(s) between the SFP and the Purge Inlet Room(s) and the door(s) between the Purge Inlet Room(s) and the outside.

Open fuel bay roll-up door as required. Ensure open SFP Ventilation system damper D-l (Units l&2 - AB6/Ceiling outside SFP)(Unit 3 -- AB6/AHU Room 650). NOTE: If this action is taken, damper D-1 must be unsecured.

3.1.4 Provide For Scrubbing of SFP Environment VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 75 of 89

1. If fuel has been uncovered, or it is anticipated that fuel will become uncovered, implement water spray for scrubbing radioactive materials from the air above the Spent Fuel Pool (SFP). Request the Fire Brigade to perform the following actions:

Coordinate actions with RP and Security

" Retrieve stationary hose monitors (BlitzFire Monitors) from the following locations: Hose Houses on the east and south sides of the Turbine Building, Fire Brigade Equipment Trailer on the north side of the Radwaste Building, and/or the Fire/Rescue Truck.

Retrieve 2.5" fire hose from the following locations: Fire Brigade Equipment Trailers on the north side of the Radwaste Building or on the south side of the Oconee Office Building. Additional hose can be located in red Hose Houses around the site.

Place the stationary hose monitors where the hose stream will reach the atmosphere above the SFP. This could be in personnel doorways or by partially opening the Fuel Receiving Bay rollup door. Connect the monitors with 2.5" fire hose to the HPSW system.

Security and/or RP support may be required

" Adjust the nozzle on the hose monitor to as wide a fog pattern as practical to help entrain the radioactive materials in the water droplets.

Additional equipment (fire engines, master stream devices, aerial trucks for elevated hose streams, etc.) may be requested through the offsite fire departments to supplement onsite equipment.

3.2 Background

To prevent uncovering the fuel in the SFP, various methods to makeup to the SFP are provided. These methods include normal makeup flow paths and emergency makeup flow paths. Table U. I provides the various available normal and abnormal makeup flow paths, inventory volume, expected pump flow rates, location of pumps, and from where the pumps are controlled. This table should be used as a guide during a loss of SFP level event to determine the most appropriate suction source to refill the pool.

There are several methods by which air movement in the SFP area can be achieved.

Performing one of the specified actions will assist in lowering area temperatures in the event of a reduction or complete loss of SFP inventory. There are three ways to enhance air flow in the spent fuel pool area:

1) forced, filtered air flow

2) forced, unfiltered air flow

3) natural, unfiltered air flow If an event has occurred in which radioactive releases are occurring, the SFP filtered exhaust fans are designed to draw air from the SEP area and provide filtering capability by way of the RB Purge filter bank prior to release to the atmosphere. If this system is not available, unfiltered air flow paths must be used. The SFP Ventilation system is divided into a supply section and an exhaust section. If AHU-9 (Units 1 & 2) or AHU 3-10 (Unit

3) are available, they can be used in conjunction with the exhaust fans to promote forced, unfiltered air flow. If only the exhaust portion is available, the fuel bay roll up door can VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 76 of 89 be opened to aid in providing a source of cooler air to the SFP area. If no forced ventilation is available, opening the fuel bay roll-up door in conjunction with the doors in the Purge Inlet room will provide a natural, unfiltered air flow path to the outside.

Finally, SFP Ventilation system damper D-1 can be opened in conjunction with the fuel bay roll-up door to provide another natural, unfiltered air flow path to the outside by way of the unit vent stack.

One method of limiting the release of airborne radioactive materials being emitted from damaged fuel is by spraying the air above the fuel with a fine water spray. This action will entrain some of the radioactive material in the water droplets. Fire Brigade equipment is readily available onsite and is stored in various areas inside the protected area which increases the chances for it being available during an incident. Fire Brigade members are trained on the set up of this equipment and practice using it during quarterly Fire Brigade drills. This action must be completed early in the incident to ensure that it is set prior to dose rates in the area increasing to the level which prohibits entry into the SFP area. This action may also provide additional makeup to the SFP following a loss of SFP level. The water spray may also provide cooling to uncovered spent fuel assemblies should SFP level decrease to below fuel level.

3.3 Implementation Fire Brigade equipment must be deployed early in the incident before dose rates increase to levels prohibiting personnel access. Determine the cause of the loss of SFP inventory.

Promote cooling air flow in the SFP area by one of the listed means for promoting air flow. RP should determine the stay times to perform the actions stated herein.

3.4 Expected Plant Response Water spray above the SFP will reduce the levels of radioactive materials being released into the air following a SFP accident, may provide additional makeup to the SFP and/or provide some cooling to exposed spent fuel following a loss of SFP level. Promoting forced or natural circulation of air in the SFP area during a loss of SFP inventory event will assist in lowering area temperatures.

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EM 5.1 Revision No.: 32 Page 77 of 89 V. OPERATING ATMOSPHERIC DUMP VALVES DURING AN ACCIDENT THAT REQUIRES OPERATION OF THE SSF 1.0 Safety Concern During an accident that requires operation of the SSF ASW System, the main steam relief valve (MSRV) with the lowest set point (1050 psig) on each main steam header will lift and reseat as needed to provide a flow path from the steam generators for decay heat removal from the RCS.

Should failure of an MSRV be observed (e.g., failure to reseat), control of MS pressure should be taken with the MS Atmospheric Dump Valves (ADVs). (Reference PIP 0-5-3770 Corrective Action 5; PIP 0-7-1445 Corrective Action 4).

(This guidance is not applicable to other uses of ADVs specifically directed in the SSF Emergency Operating Procedure, such as use of ADVs to prevent overly rapid increase in MS pressure during isolation of MS branch lines, and use of ADVs for post-fire cooldown) 2.0 Procedure Entry Conditions Any accident condition that requires operation of the SSF (and SSF ASW System) where a failed or failing MSRV(s) is observed.

3.0 Requested Action 3.1 Requested Action Summary Decrease Main Steam header pressure below the MSRV set pressure to reseat affected MSRV(s),

reduce the number of times that affected MSRV(s) must lift and reseat, or prevent further cycling of affected MSRV(s).

3.2 Background

MSRVs are credited for control of MS pressure at setpoint in SSF events without operator action, and no other equipment (e.g., ADVs) is licensed for the purpose of regulating MS pressure at setpoint in SSF events. However, the SSF is not required to withstand a single failure, so that failure of an MSRV during an SSF event would constitute a beyond-design-basis condition. In a beyond-design-basis condition actions are to be taken as necessary for safe plant control. Thus use of ADVs to control MS pressure in an SSF event is allowed if MSRV(s) failure is observed to have occurred or be occurring. Evaluations of potential MSRV failure modes and acceptable MSRV leakage rates were performed in 2005 and 2006 (reference PIP 0-5-3770 CAs 2,4 & 212; PIP 0-6-7655 (Operability Evaluation). These evaluations provide a basis for determining through observation of MSRVs whether a failure of an MSRV has occurred or is occurring.

ADV control of MS pressure in the conditions described could prevent loss of MS pressure control and thereby prevent over cooling of the reactor coolant system (RCS) and potential loss of pressurizer level / RCS voiding, which is the purpose of this guidance. Limits on system VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 78 of 89 conditions are provided, along with directions for setting up local MS pressure indications and establishing of direct communication from the SSF Control Room to operators at the ADVs.

MS pressure shall not be reduced below 900 psig to prevent voiding In the RCS that could Interrupt RCS natural circulation flow.

3.3 Implementation 3.3.1 Prerequisite Conditions Complete 3.3.1A, 3.3.1B and 3.3.1C prior to using the ADVs to control MS pressure:

A. Observation to Identify MSRV Failure: TSC Engineering Manager

1. Direct Engineering personnel to observe MSRVs and evaluate whether MSRV(s) failure has occurred or is occurring with respect to MS pressure control in an SSF event, using the following considerations:

" Failure of MSRV(s) to reseat properly, or a simmering condition, could cause leakage in excess of that assumed in calculations applicable to latter portions of an SSF event.

(Reference OSC 9030 /RETRAN).

MSRV response during cycling, if different than expected, could indicate a pending failure or setpoint drift which would adversely affect SSF event mitigation.

" The following information is provided to aid in assessment of MSRV response and need for use of ADVs.

I. Without any specific mechanical problems, MSRV performance In an SSF event could range from discrete cycling to simmering to wisping.

a. Discrete cydes will occur when decay heat rate Is high and the MS system pressurization rate is high. Discrete cycling Is characterized by well defined periods of high flow blowdown followed by low leakage after the valve reseats.

b. Simmering will tend to occur when the MS system pressurization rate Is low (decay low and/or other MS leakage high). Simmering may look like continuous leakage. There may be rapid, cyclic contact between the disk and seat during simmering. Because this contact Isof low impact energy (very little separation between disk and seat) and because the disk and seat are of erosion resistant materials, simmering should not promote Impact related damage or erosion/wire-drawing damage that creates a leak path. Whether simmering (rapid tapping sound) can be audibly detected so as to distinguish between simmering and gross leakage due to failure Is not known.

i. Unlike discrete cycles or wisping, simmering could affect SSF accident mitigation and therefore indicate that use of ADVs is needed.

c. Wisping is characterized as a small amounts of steam emanating from the MSRVs when seated, as may occur during normal operation.

II. Normal MSRV reseating during cycling does not Imply zero leakage. Failure to reseat implies gross leakage due to the following:

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EM 5.1 Revision No.: 32 Page 79 of 89

a. The spring does not bring the disk to the seat with normal force.

b. The disk Is not in continuous contact with the seat, i.e. cocked.

c. The valve has suffered a mechanical failure, such as a broken spring.

111. How to evaluate MSRV performance during an SSF event

a. Available Information:

I. MS pressure trend showing lift and reseat pressures.

iI. Comparison to MSRV on opposite header, visually and using data trends ill. RCS data trends on each loop

b. Decreasing MS pressure with MSRVs not cycling Indicates that total MS system leakage Is excessive.

1. If the MSRVs are simmering or otherwise appear to not be reseated properly during cycling, use the ADVs to force the disk to the seat to reduce MSRV steam flow. (This will confirm gross leakage is not occurring due to some mechanical failure. It will also aid In determining if additional MS isolation Is needed.)

II. If the MSRVs are only wisping, use of the ADVs may not have much benefit. (Need for additional MS Isolation may be Indicated.)

c. Decreasing or Increasing overall trend In MS pressure with MSRV(s) continuing to cyde implies MSRV setpoint drift. Use the ADVs to stop MSRV cycling and to control pressure In the required range.

d. A stable MS pressure trend Implies that overall MS Isolation Is effective.

i. If the MSRVs are simmering or otherwise not reseating properly, use the ADVs to stop cydlng/simmering and force the disk to the seat to reduce the potential for MSRV damage.

II. If the MSRVs are only wisping, use of the ADVs may not have much benefit.

e. MSRVs on each of a unit's MS headers should be behaving simllariy, i.e. cycling at approximately the same rate and MS pressure. If they are not similar, investigate to determine the cause. Use the guidance above based on MS pressure, RCS data and visual observation to determine IfADVs should be used.

I. The MS loop with better MS Isolation will be more likely to exhibit discrete cydes at a higher rate and have higher MS pressure.

ii. If one MSRV is cycling and the other simmering, the difference In behavior could be due to normal physical differences between valves.

A.2 If an MSRV failure with respect to SSF event mitigation capability is determined to have occurred or be occurring, and use of ADVs could prevent fiuther degradation, recommend to the TSC Emergency Coordinator that the remaining steps in this guide be performed.

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EM 5.1 Revision No.: 32 Page 80 of 89 B. Local Pressure Gauges at ADVs - Operations and (If necessary) Maintenance Align local ADV pressure gauges and determine if pressure gauges are functioning properly.

Local pressure gauges are provided at the ADVs. The following guidance is provided to align the required pressure gauges and to verify that the pressure gauges are functioning properly:

1. On each affected unit, verify closed the following valves:

" 1,2,3MS-233

1,2,3MS-234

" 1,2,3MS IV0441

" 1,2,3MS IV0445

2. On each affected unit, open or verify open the following valves:

1,2,3MS IV0440

1,2,3MS-222

" 1,2,3MS-223

" 1,2,3MS IV0444

" 1,2,3MS-225

" 1,2,3MS-226

3. If indicated pressure for 1,2,3MSPG1000 (MS header A pressure) and 1,2,3MSPGI001(MS header B pressure) on each affected unit is outside the expected pressure range (< 900 psig or

> 1100 psig or alternate pressure range provided by TSC), install a local pressure gauge in parallel to the affected instrument (l,2,3MSPG1000 and 1,2,3MSPG1001) per guidance provided in AM/O/A/0270/0O1, Main Steam Atmospheric Dump Valves (ADV) Connection and Removal of Temporary Pressure Gauges.

C. Establishment/Verification of Initial Plant Conditions - Operations

" Establish a SG level between 240" and 260" in each affected unit's steam generators per guidance contained in AP/0/A/1700/25.

" Once SG level has been established, ensure pressurizer level is> 200". Pressurizer level can be increased by isolating the SSF RC makeup system letdown flow path. Maintaining RCS pressure within AP/0/A/1700/25 limits, while raising pressurizer level, is accomplished by cycling pressurizer heaters and SSF RC makeup system letdown flow.

" Ensure that Enclosure 5.3A (Unit 1 Plant Actions), Enclosure 5.3B (Unit 2 Plant Actions),

and Enclosure 5.3C (Unit 3 Plant Actions) of AP/0/A/1700/25 have been performed on affected units.

3.3.2 Control of MS Pressure using the ADVs Direct communication shall be maintained between the operator at the ADV(s), the person observing the MSRVs, and the SSF Control Room Operator. The Operator at each ADV will control flow based on direction from the SSF Control Room Operator and guidance contained in the EOP (Ref EP/*/A/1800/001, Enclosure 5.24) for throttling flow through the ADVs. If the ADVs are opened too quickly, the resulting MS depressurization could cause overcooling of the VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 81 of 89 RCS that could lead to a loss of pressurizer level, a loss of pressurizer heater control, and potential voiding in the hot legs.

The SSF Control Room Operator shall direct control of the ADVs for each affected unit based on the following information:

a. Operation of a MS line's ADV(s) is not required if the corresponding MSRV is not lifting.

b. During use of the ADVs, control MS pressure so that the following limits are met:

" All limits stated in AP/0/A/1700/25 still apply.

" Control MS pressure using the local pressure gauges that are installed near the ADVs. If the local pressure gauges are not available or are inoperable, obtain TSC guidance for determining MS pressure.

" Initial pressurizer level is > 200". After ADV flow is established, ensure pressurizer level remains > 125".

" Ensure MS pressure is maintained > 900 psig at all times.

Note: If the small bypass ADVs 1,2,3MS-237 and 1,2,3MS-238 are installed they will be used for steps 3.3.2c and 3.3.2d. On Unit 1 only, the respective upstream block valves IMS-235 and IMS-236 must first be opened.

c. Perform the following to reduce the actuation frequency of the MSRVs.

" Slowly throttle open the ADVs, starting with small bypass ADVs 1,2,3MS-237 and 1,2,3MS-238 (if installed on the affected units).

" If necessary, slowly throttle open 1,2,3MS-162 and 123MS-164 (a maximum of 1/4 turn open each time valve is operated) and allow time (at least 20 minutes or as directed by TSC) for the RCS to respond.

d. If directed by the TSC, perform the following to close the MSRVs.

" Continue to slowly throttle open the ADVs, starting with small ADVs 1,2,3MS-237 and 1,2,3MS-238 (if installed on the affected units).

" If necessary, slowly throttle open 1,2,3MS-162 and 1,2,3MS-164 (a maximum of 1/4 turn open each time valve is operated) and allow time (at least 20 minutes or as directed by TSC) for the RCS to respond.

Prevent MSRVs from re-opening by maintaining MS pressure below 1000 psig.

The MSRVs are expected to reseat at -1015 psig. If a MSRV does not fully reseat (seat leakage),

leakage is expected to stop at -970 psig based on operating experience. Once the MSRV has fully reseated, the 900 psig - 1000 psig control band still applies.

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EM 5.1 Revision No.: 32 Page 82 of 89

e. As RCS decay heat load decreases, throttle the ADVs to maintain MS pressure above 900 psig.

Ensure that main steam system pressure does not exceed 1000 psig.

f. If MS pressure cannot be maintained > 900 psig by throttling closed the ADVs, isolate the corresponding ADV flow path to return MS pressure control to the MSRVs.

3.4 Expected Plant Response The MSRV lift frequency has significantly decreased or the MSRVs are not lifting because MS header pressure is being maintained below MSRV set pressure. MS header pressure is maintained between 900 psig and 1000 psig. Pressurizer level is maintained > 125". The flow path for removing decay heat from the steam generators is through the ADVs.

If MS pressure cannot be controlled within the required pressure band using the ADVs, the corresponding ADV flow path is isolated to return MS pressure control to the MSRVs.

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EM 5.1 Revision No.: 32 Page 83 of 89 W. GUIDANCE FOR SECURING REACTOR BUILDING SPRAY PUMPS FOLLOWING A LOCA 1.0 SAFETY CONCERN Potential to block Reactor Building Emergency Sump strainer due to chemical precipitants formed during a LOCA 2.0 PROCEDURE ENTRY CONDITIONS The following conditions are considered in preparation of the following guidance.

9 Loss of Coolant Accident with Reactor Building Spray in operation.

3.0 REQUIRED ACTIONS 3.1 Requested Action Summary

. Secure RBS pumps when radiological conditions allow.

3.2 Background The operation of RBS post-LOCA acts to reduce RB pressure and temperature and remove iodine from the RB atmosphere that can potentially leak out and cause radiological consequences. If; however, the system is operated longer than necessary then negative effects can take place including instrument failure or degradation, Auxiliary Building room heatup, and potential RBES blockage due to chemical particulate produced by spraying aluminum. The room heatup analysis is contained within OSC-6667 and assumes the RBS pumps will be secured within 7 days of the accident. The effect of RBES blockage was analyzed as part of the Generic Letter 04-02 resolution and also assumes that the RBS pumps are secured within 7 days.

The dose analysis is documented in OSC-7734 and assumes that RBS is in operation for a minimum of 4.7 days after the accident. The analysis is based on Maximum Hypothetical conditions including 100% failed fuel. The 4.7 day duration is not required if there is no failed fuel.

3.3 Implementation RBS should be secured as soon as radiological conditions permit.

3.4 Expected Plant Response RBS is secured with no adverse effects on dose values to the general public and control room personnel.

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EM 5.1 Revision No.: 32 Page 84 of 89 X. GUIDANCE FOR OBTAINING REACTOR BUILDING HYDROGEN SAMPLE 1.0 SAFETY CONCERN Potential unavailability of reactor building (RB) hydrogen concentration during non-functionality of reactor building hydrogen analyzers 2.0 PROCEDURE ENTRY CONDITIONS Any event which warrants obtaining RB hydrogen concentration during non-functionality of installed RB hydrogen analyzers.

3.0 REQUIRED ACTIONS 3.1 Requested Action Summary Initiate a task to the OSC for RP and Chemistry to obtain a RB atmospheric sample and analyze for volume percent hydrogen.

3.2 Background RB hydrogen concentrations are normally provided by the "A" and "B" RB hydrogen analyzers which, once placed in service by Operations per the EOP, provide continuous indication of RB hydrogen in the range of 0 to 10%. In the case that one or more unit's RB hydrogen analyzers are out of service, discrete sampling by RP and analysis by Chemistry can provide RB hydrogen concentration information.

This method may also be credited as a preplanned alternate method of monitoring per SLC 16.7.4 Condition C required action.

The RB hydrogen concentration may be needed:

" to support emergency classification per RP/O/A/1000/001, Emergency Classification, Enclosure 4.1 Fission Product Barrier Matrix, Containment Barriers (BD 10-13),

" to evaluate the potential and severity of core damage per RP/O/B/1000/018, Core Damage Assessment, and

" during severe accident management diagnosis and mitigation of plant damage conditions (PDCs) (ref. Oconee Severe Accident Guidelines, OSAG)

The RP sample point is via the RIA47,48,49 sample line at the Auxiliary Sample Station in the Auxiliary Building Filter Room. If ES actuation has occurred, applicable containment isolation valves would have to be restored to allow the sample to be taken.

The Chemistry analysis will support the full range of hydrogen concentrations, 0 to 100%.

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EM 5.1 Revision No.: 32 Page 85 of 89 Periodicity of sampling is determined by the TSC based on other inputs such as expected core damage from other indications, dose rates at the sample point, data needed for specific decisions (e.g. EAL determinations), etc.

3.3 Implementation Initiate a task to the OSC using the appropriate unit designator:

1. Operations ensure *PR-7, 8, 9 & 10 are open to allow sampling.

2. RP to obtain a Unit

reactor building hydrogen sample at the Auxiliary Sample Station using HP/0/B/1000/060B, Reactor Containment Building Sampling And Release Rate Determination For Gaseous Purge and supply the sample to Chemistry for analysis.

3. Chemistry to analyze the sample using LM/O/P937 Hydrogen Analysis by SRI Gas Chromatograph. The sample may need to be analyzed twice. First using the high range analysis (1-100%) and second, if the results are less than 15%, using the low range analysis. Report the results to the TSC.

3.4 Expected Plant Response Desired RB hydrogen analysis obtained.

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EM 5.1 Revision No.: 32 Page 86 of 89 Y. ENERGIZING DESIRED LOADS ONTO THE EMERGENCY POWER SOURCES IN SUPPORT OF AP/II 1.0 SAFETY CONCERN Existing plant procedure(s) may not provide a clear path for how to restore desired loads such as SFP cooling and supporting systems during non-power operation or shutdown conditions.

Actions outlined in the emergency procedures are based on a conservative course of action(s) to be followed. Procedures however, cannot address all contingencies and, therefore, must contain a degree of flexibility since emergency situations may not follow an anticipated sequence.

PIP 0-12-10969 identified significant issues relating to the ability of the ventilation systems in the Unit l&2 Blockhouse to maintain building ambient temperatures within equipment rating limits during design basis accident scenarios. As a result, Standby Bus electrical load limits were put in place. These load limits were in the form of a prescribed list of loads that Operations is allowed to restore for any Oconee Unit that has experienced a Loss of Oftsite Power (LOOP) and is subsequently being powered from the Standby Bus. Due to ventilation and cooling system capability reductions caused by certain design basis single failure assumptions, allowable Standby Bus loading did not contain sufficient margin to include Spent Fuel Cooling-related loads to be restored.

CT-5 and CT-4 Transformers, Unit-I and -2 Switchgear Blockhouse breaker(s) and Unit-3 Switchgear Blockhouse breaker(s) have temperature limits that could be challenged due to electrical loads and environmental conditions (induced by high ambient temperature). The combination of limiting the electrical load and ensuring support equipment (such as the CT-4 and Ul/2 Switchgear Blockhouse ventilation fans, CT-4 & -5 transformer fans, evaporative cooling system and supports) are available and can operate when required ensures the design function to provide emergency power to safety related equipment is maintained.

Items to be considered (not all inclusive):

During refueling operation a single unit event is vulnerable to a loss of SFP cooling (due to high SFP heat load from freshly unloaded fuel). The scenario where Unit-I experiences a LOOP is worse than if Unit-2 experiences a LOOP. If Unit-I experiences the LOOP two Spent Fuel Cooling pumps will be lost whereas if Unit-2 experiences the LOOP only one SFC pump is lost.

" There is also a vulnerability for a Unit-i and -2 event when a portion of the CT4/Switchgear fans, doors, and/or the evaporative cooling system are out of service.

2.0 PROCEDURE ENTRY CONDITIONS Recognizing that actual plant events will likely not result in the ventilation capacity reductions, maximum electrical load, or conservative environmental condition postulated in the Prompt Determination of Operability (PDO) documented in PIP 0-12-10969, this guidance is provided when desired loads, such as the Spent Fuel Pool cooling and related loads (for any unit receiving power from the Standby Bus) can be energized. The technical basis for these recommendations was derived from the analysis results presented in the PDO revisions for PIP 0-12-10969.

The following conditions are considered in preparation of this guidance.

Loss of offsite power during a non-power operation

" Loss of SFP Cooling VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 87 of 89 3.0 REQUESTED ACTION 3.1 Requested Action Summary Recovery of desired station loads such as the Spent Fuel Pool cooling and supporting systems (CCW, RCW, CCW booster pump).

3.2 Background The licensing basis electrical load is in UFSAR Table 8-1. The table lists engineering safeguards and vital equipment power requirements based on component ratings. The electrical loads that can be powered by CT4 and CT-5 include the UFSAR Table 8-1 required loads, Auto-Start ES loads (including MDEFWPs), loads that will run due to not being load-shed and other loads that the station may desire.

The limiting condition for thermal environment with ventilation fans in service in the CT-4 and U1/2 Switchgear Blockhouse is a LOCA on Unit 3 and Unit-l&2 are operating. For a LOCA on Unit 3, Units I and 2 Main Step-up Transformers (MSU) will remain in service which will tend to heat the air entering the slanted air intake holes on the north and south walls of the blockhouse.

These holes face the Unit I and 2 MSU. With blockhouse ventilation in service, this will result in taking in air that has been heated by the transformers above the ambient air temperature.

CT4 and CT-5 TRANSFORMER rating:

CT-5 (name plate rating) is an outdoor oil-filled transformer rated for a maximum of 22.4MVA with the oil cooler fans in service in a (300 C) 86°F daily average ambient temperature environment for 20 continuous years of service. Note: CT-5 electrical load may be limited due to cable rating that is susceptible to environmental condition(s).

a. 13.44MVA with no forced ventilation through the two transformer heat exchanger fin banks.

b. 17.92 MVA with forced ventilation in service on one of two banks of transformer heat exchanger radiators.

c. 22.4 MVA with forced ventilation in service on two of two banks of transformer heat exchanger radiator.

The above rating is applicable to CT-4 but would have added limitation because the transformer is housed in a concrete structure.

3.3 Implementation Procedure limits are always applicable (e.g. oil and winding temperature limits). Parameters and conditions articulated here are for the Technical Support Center (TSC) staff to use. The information presented will aid in providing the technical basis for making recommendation for when it is acceptable to energize the desired station loads (e.g. SFP cooling and supporting systems) in addition to the required safety loads. All limits must be met in order to recommend desired loads can be added.

" Request Operational Support Center (OSC) to verify (with an appropriate instrument) the temperatures in the specified areas are within limits.

" Loading of desired load must be performed at a gradual and cautious pace to allow for temperature monitoring and potentially securing loads if limits are being approached.

" It is recommended that the SFP cooling system and the supporting systems have priority.

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EM 5.1 Revision No.: 32 Page 88 of 89 Switchaear Room:

Switchgear room must be < 60*C (140*F). Room temperature limit is applicable regardless of the power source(s) CT-4 or CT-5. The indication that can be used locally to verify the temperature is at the exhaust fan controls (NW corner of the blockhouse).

CT-4 to Standby bus:

CT4/Keowee Underground Path and Switchgear Room equipment is capable (with regards to room temperatures in the Unit l&2 Blockhouse) of supplying up to 22.4 MVA provided the ambient temperature inside CT-4 room is <555C (131*F) and Switchgear room is <60*C (140°F).

Above these temperatures the transformer fans and switchgear breakers will trip. The indication that can be used locally to verify the temperature is at the exhaust fan controls (NE corner of the blockhouse) and west wall.

Event mitigation analysis with CT-4 carrying 22.4 MVA with an outdoor temperature of 100*F or less does not credit the Evaporative Cooling System. Event mitigation at outdoor temperatures above 100*F and up to I 10°F (the max temperature analyzed) requires crediting the evaporative cooling system to ensure operability of CT4.

CT-5 to Standby bus:

Load limits for the CT-5 power source are described and tabulated below. For other ambient temperatures the power limit may be determined using the formulas in Calculation OSC-10864.

The existing procedure (loss of power) using CT-5 as the power source is based on a maximum ambient temperature of IlOF (which limits the load to 17.5 MVA or 20.1 MVA for 100 his or less).

Additional loads can be added:

IF the ambient temperature (in the cable trench and in the Unit-2 TB basement {in the vicinity > 1 ft away from the cable)) for the entire length of the cable can be verified to be < 970 F, the CT-5 limit is 22.4 MVA or 133 amps on high side of Transformer CT-5.

IF the ambient temperature (in the cable trench and in the Unit-2 TB basement {in the vicinity >

1 ft away from the cable)) for the entire length of the cable can be verified to be 0.0278 hours 1.653439e-4 weeks 3.805e-5 months .

The most limiting temperature area will dictate the CT-S MVA limit:

Ambient Temperature CT5 High Side along the cable route(in Amps (Unit-2 the vicinity > 1 ft. away Cable CR gauge Cable Section from the cable) Temperature Available MVA preferred)

Cable Trench and Turbine Building 970F/36.06C 194°F/90 0 C 22.4 133 Cable Trench and Turbine Building 11 70F/47. 1C 194 0F/90 0 C 20.1 119 Cable Trench and Turbine Building 132°F/56.4°C 230°F/110 0C 22.4 ( for 100 His) 133 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 32 Page 89 of 89 The cable routing has been analyzed and broken up into three sections. Section one is the trench from Transformer CT5 to the entrance into the Auxiliary Building at Elevation 796. Section two is from the entrance into the Auxiliary Building through the Turbine Building Basement to the entrance into the Unit 1 and 2 Switchgear Blockhouse. Section three is the Unit 1 and 2 Switchgear Blockhouse (bounded by Switchgear room temperature limit).

3.4 Expected Plant Response Observing the temperature limits prescribed above will allow the emergency transformers to carry the stated UFSAR Table 8-1, Section MI, loads {for the design basis LOCA/LOOP on one unit with LOOPs on the remaining non-LOCA units are 15.971 MVA (starting) and 12.79 MVA (running)) and provide power for additional loads as desired to assist in event mitigation.

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3.10 10CFR 50.54(q) Evaluations Emergency Planning Functional Area Manual Attachment 3.10.7.2

§50.54(q) Screening Evaluation Form 1145.k~

Activity Description and

References:

Engineering Emergency Response Plan, rev 32 Added alternate hydrogen sampling appendix Activity Scope:

0 The activity is a change to the emergency plan El The activity is not a change to the emergency plan Change Type: Change Type:

[] The change is editorial or typographical El The change does conform to an activity that has 0 The change is not editorial or typographical prior approval

[ The change does not conform to an activity that has prior approval Planning Standard Impact Determination:

[I §50.47(b)(1) - Assignment of Responsibility (Organization Control)

El §50.47(b)(2) - Onsite Emergency Organization El §50.47(b)(3) - Emergency Response Support and Resources 0 §50.47(b)(4) - Emergency Classification System*

El §50.47(b)(5) - Notification Methods and Procedures*

§50.47(b)(6) - Emergency Communications

§50.47(b)(7) - Public Education and Information El §50.47(b)(8) - Emergency Facility and Equipment 0 §50.47(b)(9) - Accident Assessment*

El §50.47(b)(10) - Protective Response*

[E §50.47(b)(1 1) - Radiological Exposure Control El §50.47(b)(12) - Medical and Public Health Support El §50.47(b)(1 3) - Recovery Planning and Post-accident Operations

[E §50.47(b)(14) - Drills and Exercises El §50.47(b)(15) - Emergency Responder Training El §50.47(b)(16) - Emergency Plan Maintenance

Risk Significant Planning Standards El The proposed activity does not impact a Planning Standard Commitment Impact Determination:

El The activity does involve a site specific EP commitment Record the commitment or commitment reference:

0 The activity does not involve a site specific EP commitment Results: U UI The activity can be implemented without performing a §50.54(q) effectiveness evaluation 0 The activity cannot be implemented without performing a §50.54(q) effectiveness evaluation Kreparer Name: Pr-* Signa3are,/ Date: .

ohn Kaminskdi JA'4. ) -4.3_21i1 Reviewer Name: I/.e rSi e/Date:

Don Crowl V1,4~3 /~ 5/s ':7 j-/ - F_'%

Revision 12 10 10CFR 50.54(q) Evaluations Emergency Planning Functional Area Manual Attachment 3.10.7.3

§50.54(q) Effectiveness Evaluation Form a ,

Activity Description and

References:

Engineering Emergency Response Plan, rev 32 Activity Type:

0 The activity is a change to the emergency plan EJ The activity affects implementation of the emergency plan, but is not a change to the emergency plan Impact and Licensing Basis Determination:

Licensing Basis:

1. 10CFR50.47b(4) A standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters, is in use by the nuclear facility licensee, and State and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial offsite response measures.

2. 10CFR50.47b (9) Adequate methods, systems, and equipment for assessing and monitoring actual or potential offsite consequences of a radiological emergency condition are in use.

3.10CFR50 Appendix E.IV.B1. The means to be used for determining the magnitude of, and for continually assessing the impact of, the release of radioactive materials shall be described, including emergency action avels that are to be used as criteria for determining the need for notification and participation of local and ate agencies, the Commission, and other Federal agencies, and the emergency action levels that are to be used for determining when and what type of protective measures should be considered within and outside the site boundary to protect health and safety. The emergency action levels shall be based on in-plant conditions and instrumentation in addition to onsite and offsite monitoring.

4. ONS E Plan Volume A, Section D Enclosure 4.1, A containment hydrogen concentration greater than 9 percent volume is sufficient to expect that any ignition would result in complete combustion of the hydrogen in containment and a significant pressure rise. At hydrogen concentrations near 9 percent volume no challenge to containment integrity would be expected. At levels somewhat higher the possibility of a deflagration to detonation transition raises the uncertainty as to the actual response of the containment. Therefore, it is prudent that this level of hydrogen in the containment be considered a potential loss of containment integrity.

5. ONS E Plan Volume A Section 1.2, Post Accident Sampling -The NRC issued Amendments No. 346 (Renewed License No. DPR-38), No.348 (Renewed License No. DPR-47), and No. 347 (Renewed License No.DPR-55) on 07/12/05. These amendments, effective 01/08/06, delete Technical Specification Section 5.5.4, Post Accident Sampling for Oconee Nuclear Site Units 1, 2, and 3 and thereby eliminate the requirements to have and maintain Post Accident Sampling Systems - PASS (PALS/PAGS). Consistent with the requirements of the NRC safety evaluation, contingency plans for obtaining samples have been developed. Procedures have been developed for taking and analyzing post accident reactor coolant samples using either the normal sample points or the existing PALS sample panels. Containment atmosphere samples are no longer required; however, procedures are in place for surveying the containment building wall as well as sampling the environment and using these values to develop off site dose projections and provide appropriate protective action recommendations for the public.

~m.

0

Compliance Evaluation and

Conclusion:

Evaluation:

A standard EAL classification scheme remains in effect at ONS, there has been no change to the EALs or their set point. Monitoring of Hydrogen in the Reactor Building via an alternate sample path outlined in Appendix X, of EM 5.1 rev 32 would continue to provide for the identification of the EAL condition as well as providing a means to evaluate /assess core damage and potential offsite consequences of a radiological release. The value expressed in the EAL for the hydrogen concentration has not changed, the proposed revision provides for an alternate means to obtain that value. Therefore this proposed revision continues to comply with all requirements.

Conclusion:

The proposed activity Z do / F1 does not continue to comply with the requirements.

Reduction in Effectiveness (RIE) Evaluation and

Conclusion:

1. Evaluation:

The proposed revision does not change the EAL (RB Hydrogen) and associated set-point (5) for a potential loss of containment. The proposed revision provides for an alternate sample path (provides for the means and methods) with which to first obtain and then to analyze the Reactor Building hydrogen concentration when the continuous hydrogen monitors are out of service. Sampling of the Reactor Building environment may be undertaken whenever TSC engineering teams deem it necessary as indicated in the proposed revision. As such, although continuous monitoring may not be possible, frequent sampling can be undertaken to enable tracking and trending of the hydrogen concentration, such that should the hydrogen concentration begin to rise it could be trended to ascertain in a timely manner when the value of 9% would be reached. Therefore the function of monitoring for hydrogen concentration in the Reactor Building has not changed. The timing and timeliness aspects for identifying a partial loss of containment due to hydrogen concentration at 9% has not been impacted as frequent sampling will provide for trending as well as using the value obtained for the determination of the amount of core damage.

As indicated in the proposed change the values obtained can be used to support emergency classification, support core damage assessment and can be used during severe accident monitoring. The proposed change provides for the means and methods to be employed to obtain the samples and directs that the samples be analyzed by chemistry. Therefore there has been no reduction in the function to be provided, and the timing and timeliness of performing the function has not been impacted

Conclusion:

The proposed activity Ml does / [ does not constitute a RIE.

Effectiveness Evaluation Results

[] The activity does continue to comply with the requirements of §50.47(b) and §50 Appendix E and the activity does not constitute a reduction in effectiveness. Therefore, the activity can be implemented without prior approval.

El The activity does not continue to comply with the requirements of §50.47(b) and §50 Appendix E or the activity does constitute a reduction in effectiveness. Therefore, the activity cannot be implemented without prior approval.

"I,-Ir'M Preparer Name: Date* '07 7116-John Kaminski P& ig 07'.

Y-'

DonCrowl StreetýN i

PP e Name": .p Z e Reiwer Name: .. .

R'... r eDate: 1 -* -

IDDate.-:

t' Z-15 lyprver

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ONS-2014-007, Emergency Plan Implementing Procedures Manual, Volume C, Revision 2014-003

Contents

Text

Subject:

SUBJECT:

Title:

Reference:

1.0 INTRODUCTION

Background:

Background:

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Background:

3.2 Implementation

Background:

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3.2 Background

3.2 Background

References:

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Conclusion:

Conclusion:

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ONS-2014-007, Emergency Plan Implementing Procedures Manual, Volume C, Revision 2014-003

Text

Subject:

SUBJECT:

Title:

Reference:

1.0 INTRODUCTION

Background:

Background:

Background:

Background:

Background:

Background:

Background:

Background:

Background:

3.2 Implementation

Background:

Background:

Background:

Background:

3.2 Background

3.2 Background

References:

References:

Conclusion:

Conclusion:

Conclusion:

Conclusion:

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